IR 05000029/1990012

Insp Rept 50-029/90-12 on 900619-0820.Violations Noted. Major Areas Inspected:Plant Operations,Radiological Controls,Maint & Surveillance,Security,Engineering/Technical Support,Safety Assessment/Quality Verification & Repts

ML20059M534
Person / Time
Site:	Yankee Rowe
Issue date:	09/24/1990
From:	Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20059M532	List: IR 05000029/1990012 ML20059M530
References
50-029-90-12, 50-29-90-12, NUDOCS 9010050027
Download: ML20059M534 (25)

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U.S.-NUCLEAR REGULATORY COMMISSION REGION I.

Report No:

50-29/90-12-i Docket No:

50-29

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Licensee No:

DPR-3 I

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Licensee:

Yankee Atomic Electric Company 580 Main Street Bolton, Massachusetts 01740-1398 Facility Name: Yankee Nuclear Power Station

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Inspection at: Rowe, Massachusetts Inspection Conducted:

June 19 - August 20, 1990 Inspectors:

T. Koshy, Senior Resident Inspector

M. Markley, Resident Inspector i

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L. Prividy, Senior Reactor Engineer, DRS l

H. Kaplan, Senior Rea Engineer, DRS

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Approved By:

MW.

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J(Aogg'e. Chief, React (r/Pf,4jects, Section 3A 0'a te '

Inspect bn Summary: Inspection on June 19 - August 20, 1990-1

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(Report No. 50-29/90-12)

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Areas Inspected:

Routine inspection on daytime and backshifts. in the areas of.

plant operations; radiological controls; maintenance and surveillance; security; engineering /techi.ical support; safety assessment / quality verification, and periodic reports.

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Results:

1.

General Conclusions on Adequacy, Strength or Weakness in Licensee Programs The site and corporate engineering involvement in the outage activities was noteworthy in the resolution of control rod issues, the installation of a safety injection tank, motor operated valve refurbishment, and

ultrasonic examination of the pressurizer and reactor vessel head, Radiation control measures were effective in limiting-exposure. ' Increased l

management attention is appropriate regarding occupational safety during outage activities (Sectien-3.4).

2.

Violations Two non cited violations were identified during this inspection period:

9010050027 900925 ~

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High'radiationMarea'not'conspicbously: posted (Section 5.2);.

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Technical. Specification-required source:Trange monitor.was not-

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. audible-(SectionL4'2)..

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3,1 Unresolved Items-

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Two-unresolved items wereLidentified:

j Contractor fitness-for-duty program determined l unacceptable (Siction I!

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7.1);

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Inadequate': screening 1for.une'corted(accesstothe'protectedare~al

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i EXECUTIVE SUMMARY Plant Operations

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Yankee Nuclear Power Station commenced-the Core XXI refueling outage on June 23, 1990. During a plant load reduction, an operator error resulted itithe automatic start of an emergency diesel generator while. attempting to crosstie

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the main generator power supply to the offsite power supply. On June 23, 1990, two control rods failed to fully insert into the core during control rod drop testing.

Licensee corrective. actions and actions to prevent recurrence were

adequate.

Licensee performance during core-alterations was good.

However,-the control room staff was not attentive to the lack of an audible source range monitor.

This was identified as an NRC non-cited violation ~(Section 4.2).

Radiological Controls

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Noteworthy licensee performance was observed in radiological controls for core alterations, steam generator eddy current testing and tube plugging, control rod cutting, and outage waste handling.

Engineering controls were effective in reducing occupational exposure. A non-cited violation was' identified for a high radiation area which was not conspicuously posted as required (Section-

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5.2).

Maintenance and Surveillanc-

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The licen'see was responsh essing industry concerns regarding pressurizer

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and reactor vessel head crac-The licensee examinations were technically sound.

In response to NRC Gs.acic Letter 89-10, the-licensee initiated a motor-operated valve refurbishment and testing program during this outage.

Licensee oversight of the contractor activities associated with motor-operated valve maintenance was adequate.

Security The licensee identified two deficiencies in the fitness-for-duty (FFD) program.

The licensee had accepted a contractor FFD program which was later determined unacceptable by the corporate auditing staff (Section 7.1).

Also, the licensee did not obtain written suitable inquiry FFD statements from a number of contractor personnel when scraening personnel for unescorted access to the protected _ area.

(Section 7.2).

These items are unresolved pending review by an NRC Region I specialist inspector.

Engineering and Technical Support A high level of engineering and technical support involvement was noted during outage activities.

The overall quality of. technical support was good. However, reactor engineering and maintenance support department personnel worked e'xcessive

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Executive Summary 2.:_

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overtime to: accomplish. assigned responsibilities. 'Althoughino deficiencies ins

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personnel performance were,noted, the need for individuals-to' work excessive

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overtime warrants further managementLattention..

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Safety? Assessment / Quality'Vertfication-

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Licensee quality assurance' audits of engineering and operating expeH ence _

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assessment were effectiveJin: identifying: strengths and. weaknesses. lNo deficiencies were-identified in'the. completion and reporting: of licensee-event reports.'-

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TABLE OF CONTENTS

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

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

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Operational-Safety Verification (IP 71707, 71710, 93001* ).........-.....

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3.1 Plant Operations Review.........................................

3.2 Safety-System Rev1ew............................................

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3.3 Review of Temporary Changes, Switching and Tagging..............

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3.4 Occupational-Safety..............................................

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Plant' Operations (IP 71707,'93702,60710,70313,70323)..............

't 4.1 Emergency Diesel Generator (EDG) Automatic Start Due to Operator Error.........................................................

~4 4.2 Refueling Activities............................................

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4.3 Control Rod Failure to Fully Insert During Drop Rod Tests.......

4.4 Containment Integrated Leak Rate Test (CILRT)...................

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Radiological Controls (IP 71707,83729)..............................

5.1 Radiological Controls for Outage Activities.....................

5.2 High Radiation Area Not Conspicuously Posted....................

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Maintenance / Surveillance (IP 61726,62703,62700)....................

6.1 Ultrasonic Examinations of the Pressurizer and Reactor Vessel'

Head................................................

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6.2 Motor-Operated Valve Jefurb1shment..............................

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6.3 -Inspection of Mechanical Snubbers.............................. '13

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Security (IP 71707)..................................................

7.1 Contractor Fitness-For-Duty (FFD) Program _ Determined

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Unacceptable..................................................

7.2 Inadequate Screening for' Unescorted Access to the Protected Area..........................................................

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Engineering / Technical Support (IP 71707, 37700, 37828)...............

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8.1 Technical Support for Outage Activities.........................

1 8.2 TMI (Three Mile Island) Action Plan Items.......................

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• The NRC Inspection Manual inspection procedure (IP) or temporary instruction

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(TI) or the Region I temporary instruction (RI TI) that was used as inspection

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' guidance is listed for each applicable report section.

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Tabli-of-Contents.

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9.

-Safety Assessment / Quality. Verification (IPf71707,:40500,190712),...-..

9.1.QA Audit 1Y-89-07,; Plant Changes............;4.......:......:.......-.16

9.2' QA Audit Y-89-17, Operating: Experience AssessmentLand Corrective.

d Action....'................'..........................-.-....-.....t:16-

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9.3-.LER 90-502, Unauthorized Person in'the Access Controlled + Area...

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9.4-LER 90-002,. Automatic ESF Actuation Following Loss ofE480lVolt:

. Bus....a.........:.i.......-............:...........-.-.-...-............-

17f 9 5 -LER;90-003, Main Steam Safety Valves Setpoints-Exceeds

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Te chn i c a l Spec i f i ca t i on s.............................. -......... c ~.17 -

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9.6 =LER 90-004', High-Radiation-Area Not Conspicuously Posted..._.....-,17_

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-9.7 'LER 90-007, Pressurizer Safety 1 Valve Exceeds Technicall

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~ S p e c i f i c a t i o n_,............................ s...... '.............. < '17

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Revi ew : o f Pe riodi c Re port s (I P. 90713)......... t...-.......-;.... '......... ? l81 l

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Q ll. Ma na gemen t: Mee t i ng s : ( I P. 30703 ) ;...................... :.S... -.--,.......... -.191

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DETAILS

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1.

, Persons Contacted Yankee Nuclear Power Station-T. Henderson, Plant Superintendent

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R. Mellor, Technical Director

Yankee Atomic Electric Company (YAEC)~

I N. St.-Laurent, Manager of Operations

The inspector interviewed licensec employees during the inspection, including

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members of the operations, radiation protection, chemistry, instrument and control, maintenance, reactor engineering, security, training.. technical services and general office staffs.

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Summary of Facility Activities j

Yankee Nuclear Power Station (YNPS, Yankee or the plant) commenced the

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core XXI refueling and maintenance outage on June 23, 1990.

The projected i

seven week' outage schedule was extended to September 12, 1990, to facilitate

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replacement of the station emergency diesel generators. 10n August 2-27, i

1990, the resident inspectors-conducted a special-inspection of the emergency

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diesel generators (50-29/90-14).

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On July 9-20 and August 6-10, 1990,- a Maintenance Team Inspection (MTI)

i was conducted by NRC Region I personnel, an individualifrom the NRC Office

of Nuclear Reactor Regulation (NRR) and an NRC contractor (50-29/90-80).

l On July 9-13, 1990, two NRC Region I specialist ins'pectors conducted a_

l radiation protection outage inspection (50-29/90-13).

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On July 24-27, 1990, two NRC NRR staff personnel from:theilicense renewal'

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section conducted a structural walkdown of the facility in connection with

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the plant life extension program, j

On July 30 to August 3,1990, one NRC Region I specialist inspector and a

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NRC NRR staff member conducted an inspection of the licensee response actions j

to NRC Generic Letter 88-17., Loss of Decay Hea Removal (50-29/90-17).

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. 0pera t ional Safety Verification j

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'3.1 Plant Operations Review

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The inspector observed plant operations caring regular and backshift tours of the following areas:

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Safe Shutdown System Building

' Primary Auxiliary Building Fence Line (Protected Area)

Diesel Generator Rooms Intake Structure T

Vital Switchgear Room-Turbine Building Cable Tray House Spent Fuel Pit (SFP) Building Safety Injection Building Vapor Container The following items were checked-during daily routine facility tours:

shift staffing, access. control, adherence to procedures and limiting conditions of operation (LCOs), instrumentation, recorder traces,

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protective systems, control room annunciators, area radiation and process' monitors, emergency power source operability,-operabilityLof.

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the Safety Parameter Display System (SPDS),- control room logs, shift supervisor logs', and operating orders.

On a weekly basis, selected Engineered Safety Feature (ESF) trains were verified to be operable..

The condition of plant equipment, radiological controls, security and.

t safety were assessed. On a biweekly frequency, the inspector reviewed safety-related tagouts, chemistry sample results, shif t turnovers, i

portions of the containment isolation valve lineup and the posting of notices.to workers.

Plant housekeeping, fire protection and occupation

safety were also evaluated.

Inspections of the control room were performed on weekends and backshifts as follows: June 20, 22, 23, 25, '27; July 8-13,16-19. 30, 31 and August 14 Deep backshift inspection was performed from 2:00 a.m. to 1:45 p.n.. on June 6,1:00 a.m. to 2:00 p.m, on June 24, 7:00 a.m. to -

10:30 a.m. June 30, 11:00 a.m. to 5:45 p.m. and 11:00 p.m. to 12:00'

a.m. on July 8 and 1:45 p.m. to 5:45 p.m. on July 29, 1990. Operators and shift supervisors were alert, attentive and responded appropriately to annunciators and' plant conditions.

Cognizant shift personnel were knowledgeable of plant conditions and ongoing maintenance and surveillance activities.

Shift turnovers I

were conducted professionally with effective control exercised over control room access.

Shif t documentation adequately characterized

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operatila history and the obsarved off-normal conditions.

Equipment problems were resolved in a timely manner. Operators were cognizant i

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of plant operating requiremercs during the Core XXI refueling outage.

3.2 Safety System Review

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The emergency diesel generators, EDG fuel oil, residual heat removal, and safety injection systems were reviewed to verify proper alignment.

and operational status..The review included verification-that (i) accessible major flow path valves were correctly positioned,

.(ii) power. supplies were energized, (iii) lubrication and component cooling were proper, and (iv) components were operable based on'a visual inspection of equipment for leakage and general conditions.

System walkdowns to assess the material condition of the ECCS HPSI-

.and LPSI and the low pressure safety injection accumulator were

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performed. - Selected accessible: valves;were verified to be in the correct position and locked when required by plant procedures.

Significant activities associated with the-outage replacement of the

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emergency diesel generators were discussed in'NRC Inspection Report 50-29/90-14, 3.3 Review of Temporary Changes, Switching, and Tagging

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Temporary change requests (TCRs),'which were approved in support of implementing lif ted leads and jumper requests and mechanical bypasses, r

were reviewed to verify that: contrc!s. established by AP-0018,

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" Temporary Change Control,".were met; no conflicts with-the. Technical Specifications were created; -the requests werei properly approved prior to installation; and a safety evaluation in accordance with 10 CFR -

50.59 was prepared if required.

Implementation of the requests was reviewed on a sampling basis,

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The switching and tagging log was reviewed and tagging activities

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were inspected to verify plant equipment was controlled in accordance with the requirements of AP 0017, Switching and Tagging of Plant Equipment.

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Licensee administrative control, of off-normal system configurations by the use of TCR and switching _and tagging procedures, as reviewed above, was in compliance with procedural instructions'and was consistent with plant safety.

Lineups for transition to Mode 5 (Cold Shutdown)

were performed as required, No unacceptable conditions were identified.

3.4 Occupational Safety Consistent with October 21, 1988,- Memorandum of Understanding-(MOV)

between the NRC and the Occupational 1 Safety and Health' Administration

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(OSHA), the inspectors reviewed licensee. activities relative-to industry s,andards and the station safety manual.

The observations below were

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nosed during the outage.

On July 2,1990, the. inspector identified an inadequate safety

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barrier around the shield tank cavity (STC) in the vapor container (VC).

Specifically, the barrier was inadequate (approximately.3 ft tall) to protect personnel from a pote'ntial fall to the: bottom L

of the STC (approximately 40-ft.)..The licensee immediately corrected the barrier. However, on July 3,1990, the inspector.

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observed the replacement barrier leaning approximately 2 ft.

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into the STC. The licensee immediately corrected-the condition.

l On July 3,1990, the inspector observed an Lindividual traverse

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l an open-air ladder from :the vapor container refueling floor to the top of the reactor vessel head (approximately 40 f t. above the STC floor).

The individual was wearing a-respirator and not i

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wearing a safety _ belt. The licensee was immediately informed.

Licensee management directed plant supervisors to: caution station personnel to use good safety practices around the STC.

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On July 27, 1990, the inspector observed personne1' climbing an

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unsecured temporary ladder into the pressurizer cubicle.

This ladder was located approximately 5. f t, from=the STC which was

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filled with borated refueling water. 'The_ licensee immediately

removed the ladder when informed by the inspector.

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On July 25, 1990, the inspector observed portions of

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non-radiological diving in the plant intake structure. The inspector requested to review the breathing air certification documents to ensure the divers were being provided with adequate breathing air quality.

The licensee did not evaluate the air compressor or certification documents used_by the~ diving company.

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The diving company, Lane-Robinson Associates of East Lyme, Ct. =

was unable to produce the requested. documents. At the end of the inspection, the licensee had not demonstrated acceptable breathing air quality for the diving evolution.- Mechanical equipment control for this evolution was adequate.

On August 21, 1990, the licensee performed non-radiological diving

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in the fire water storage tank-(FWST). The inspector questioned safety department personnel whether the air supply met the appropriate quality standards.

Th( safety staff was unaware that a diving evolution was scheduled or being performed.

During this discussion, the inspector became aware that the-licensee:

does not have procedures to control diving activities.

Appropriate guidance is similarly absent from-the. Yankee Safety Standards manual._ The licensee used the station breathing air system to

_i fill the diver air tanks.

l In response to the identified concerns, the licensee ' stated that interim

guidance would be provided to control diving activities on a-case-by-case basis pending completion of program upgrades.

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Plant Operations j

u 4.1 Emergency Diesel Generator (EDG) Automatic Start Due to Operator Error At 4:12 a.m. on June 23, 1990, EDG-2 (emergency diesel generator No.

2) automatically started when a control room operator inadvertently

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. turned the wrong circuit breaker control switch while attempting to crosstie the 480 Volt Bus 4-1 power supply from the main transformer.

to the Y-177 offsite power supply.

Specifically, the operator I

L inadvertently opened ACB-424 (air circuit breaker No. 424) when ACB-124

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should have been opened.

At the time, the plant was at'approximai?ly

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30 MWe and personnel were implementing OP-2104, Rev. 35 Major, Plant Shutdown to Mode 2 or 3, for the core XXI refueling outage.

The personnel error was immediately recognized and power was restore? to vital Bus 4-1 by 4:13 a.m.

The licensee notified the NRC Operations Center via the ENS (emergency notification system) at 5:14 a.m.

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The licensee stated that a full human factors evaluation would:be performed.

The licensee issued a Licensee Event Report (LER 90-02)f which indicated the personnel error was due, in part, to the lack of an adequate self-verification by the operator prior to turning the ACB controller, Corrective actions included l requiring all operations personnel to review self-verification principles in procedure AP-2001, Responsibilities and Authorities of Operations Department Personnel, and incorporating the evolution lessons learned into the training program for the site reference simulator scheduled =to be operational in early 1991.

Inspector review noted operator actions following the personnel error were prompt and-effective in establishing the desired electrical.

configuration. All safety. systems performed as described.

However,.

the communications implemented during the operational transition to Mode 2 ~ may have, f acilitated an opportu'nity for-operator error.

Operations shif t supervisory personnel directed the subject operator

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to transfer the power supply using step No. 11 of OP-2104.

If the procedure step had been implemented in the presentation and repeat-back

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method described in AP-2001, the personnel error may have been averted.

Operations management stated ~that the' presentation and repeat-back method is only used for E0Ps (emergency operating procedures) and tagging orders.

The inspector questioned the operational prudence-of

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not implementing AP-2001 described communications for evolutions which may induce plant transients and challenge safety. systems. -While the licensee is evaluating the inspectors observations, the inspectors will continue to monitor the licensee's performance.

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4.2 Refueling Activities At 10:00 p.m. on June 23, 1990, the. licensee commenced a plant load reduction.to begin the core XXI refueling outage. The inspector reviewed selected portions of 'the refueling activities including.

detensioning and movement of the reactor vessel head, refueling seal installation and testing, establishment of-containment integrity, reactor vessel internals removal and replacement, fuel. movement and ultrasonic testing, control rod bow measurements, cutting and replacement.

Licensee performance during core alterations was good. The refueling water was continuously maintained at the required boric acid concentration and water level. Refueling manipulator cranes were-properly load tested prior to core alterations and following maintenance.

i Shutdown cooling controls effectively managed the decay heat load.

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' During a routine control room review on July 16, 1990, the inspector noted the required source range monitor was not-audible.

The operating-shift immediately verified the inspector observation.

Instrumentation

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and. control (I&C)-personnel determined the channel alarm did not function properly.

The audible alarm was switched to another source range

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channel.

The inspector questioned why the operators did not notice

the absence of the audible alarm.

The licensee was unable to determine when the audible alarm became inoperable.

Operations management stated

it had been verified operable during the morning shift change.

The-licensee also stated the Technical Specification (TS) action statement

was satisfied in that no core alterations or' positive reactivity changes i

had occurred.

The inspector questioned the prudency of the alarm

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setpoint being established at 8000 counts.

The inspector observed

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that alarm-setpoint would be achieved and the alarm would become audible approximately every 4-5 minutes.

The licensee reestablished a more-i conservative alarm setpoint at 4000 counts.

The licensee completed corrective actions and actions to prevent-

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recurrence during this inspection. Although'no core alterations or

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positive reactivity changes were in progress, the inattentiveness of the operating shift that did not recognize the absence of an audible source range monitor is of concern. -Inspector review determined it was an isolated incident and not repetitive in nature as set forth in 10 CFR 2, Appendix C, Section V. A. for a non-cited violation of TS 3.9.2 (50-29/90-12-01).

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4.3 Control Rod Failure To Fully Insert Durino Rod Drop Tests At 880 a.m. on June 23, 1990, as-a part'of the plant shutdown activities, the licensee performed the control rod drop test in accordance with-OP-7000.39, Simulsaneous and Individual Rod-Group: Drop-Time Measurement.

All the control-rods except~ rods 17 and 18 dropped within the acceptance criteria.

These two control rods were stuck at' approximately_ Step 39.

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The licensee utilized OP-3118, Mispositioned or Dropped Control Rod (s),

to resolve the stuck rod condition.

The licensee used'the unique design feature of pull down coils, normally not in' service, to drive the rods into the core..The resident inspectors were in.the control room throughout the evolution.

The licensee performed a conservative evaluation on the two stuck rods and determined that a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report was required per-10 CFR 50.72(b)(2).

The licensee notified the NRC Operations Center at 12:40

p.m. via the Emergency Notification System'.

A subsequent licensee evaluation using actual rod positions concluded that a report was not required in that adequate shutdown margin was maintained and bo'th rods collectively were equivalently less than the one stuck rod design-bases.

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=The control rods in use at Yankee are a cruciform design with~a neutron absorbing section and a Zircaloy fo'11ower that is not used at any-other, domestic PWR commercial plant.

The sticking problem experienced ~

_by these rods is apparently due to-differential growth of opposing i

vanes of the Zircaloy followers resulting from fast neutron flux gradients and possible material differences in the follower vanes.

The recent and post-1972 control rod sticking problems have been i

confined to the peripheral, shutdown Group D control rods and have

.not impacted the interior or central _ region control rods.

To address'the control rod sticking' problem, the licensee has had a control rod management-program in place since 1972. This program has been refined over the years and a -formalized control rod management program was issued in April 1990.

Several key aspects of.this program that existed through cycle 20 were as follows:

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' Selected. rods were examined during refueling outages'for

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measurements of control rod bow.

If bow exceeded 0.250 inches,

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the control rod was replaced.

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A 90 rotation of all control rods at each refueling had been

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used as a technique to equalize the environment'thatieach follower

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vane of a rod was exposed to over its lifetime.

Other aspects of the program included measurement of control rod lengths, drop times, drag forces,_ tests and development of a model to predict

control rod bow. Also, as control rods were replaced,-_ emphasis ~ was

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placed on ordering rods with metallurgically matched material in opposite Zircaloy follower vanes, following the event of June 23, 1990, the licensee modified the control

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rod management program to include the examination of all 24 control i

rods in lieu of-just selected control rods.

Control rods 9,'17, 18-and 21 were replaced since they did.not meet the rod. bow criteria of;

0.250 inches. Another significant change in the control rod management

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program concerned the rotation of control. rods at each -refueling.

While a 90 rotation of interior control rods was retained, peripheral-control rods (Group D) not replaced (19, 20, 22,- 23, and 24) were oriented with~ bow away from the center of the core to account for the fast neutron flux gradients -(up to sixty percent) at 'these locations.

This strategy is intended to straighten these rods rather than worsen existing measured bows.

Conference calls were conducted on August 3 and 8, 1990, between the licensee and NRC Region I management to discuss the licensee' plans for assuring proper control rod operation during cycle 21.

Region I'

personnel noted that the licensee was using a linear model to p'redict control rod bow while data from domestic BWR plants indicated a quadratic or exponential function was probably more appropriate.

The licensee noted that a quadratic model of the rod growth data available for 22 l

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rods may provide a better approximation of control: rod growth, The licensee agreed to further validate the bow model with data obtained from domestic BWR plants by mid-cycle 21.

In addition to conducting control rod _ drop tests which are required per TS prior' to restart, the licensee agreed to include the following specific points into their cycle 21 operating plan:

1.

The licensee will conduct control rod drop time measurements whenever the reactor is in Mode 3 and testing has not occurred within 60 days.

Historical plant data indicates the plant enters Mode 3 three to four times per operating cycle,

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Such testing will be conducted per Technical Specification

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requirements where (a):4 main-coolant. pumps are running with coolant Ltemperature of > approximately. 515 Fahrenheit and (b)' drop times are to be less than 2.5 seconds from the all rods out position.

Data will be trended and' compared with.the data from the

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beginning and throughout the cycle.

2.

The licensee will have an independent peer review conducted of the control rod model with a report tn the NRC by the end of

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1990.

The NRC considers the licensee action-to be technically sound in-resolving the current concerns and proposed actions: for the operating cycle are adequate to further verify the licensee's rod prediction-

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models.

4.4 Containment Integrated Leak Rate Test (CILRT)

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l On June 25-29, 1990, the licensee performed the CILRT per OP-1708,

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Rev. 2-Major, Vapor Container Type'A Leakage Test.- The inspector reviewed the CILRT relative to 10 CFR 50, Appendix -J site Technical Specification (TS) 3.6.1.2, ANSI N45.4-1972 and ANSI /ANS 56.8-1987.

The inspector observed selected portions of the system alignment including accessible containment penetration locations. LThe licensee-i

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pressurized the vapor container to 33.4 psig and verified containment.

isolation signals at 4.5 psig.

q Preliminary inspector review determined the licensee completed a

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satisfactory Type A test.

The as-found Type A leak rate was 0.14 weight. percent per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at greater.than 31.6 psig.

The Type A test leak rate was 0.15 weight percent per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The TS-limit is 0.20 weight percent per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

No unacceptable conditions-were identified in the conduct'of the test..The licensee adequately'

satisfied the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> stabilizing period.

Similarly, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> verification test was properly performe...

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Radiological Control's Radiological' controls were reviewed on a routine basis relative to industry radiological standards, administrative and radiological control procedures, and regulatory requirements. Selected work evolutions were observed to

determine the-adequacy of program implementation commensurate with the radiological hazards and importance to safety.

Independent surveys were performed by the inspector to verify the adequacy of radiological controls -

and instructions to workers.

t 5.1 Radiological Controls for Outage Activities'

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~ Radiation protection-(RP) program implementation-for outage activities was generally good.

Radiation work permits-(RWPs), radiological surveys and air sampling adequately characterized the radiological hazards.

Work controls implemented by the PJ staff were effective in providing

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a high level of radiologleal safety.

Noteworthy licensee performance

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was observed in rcdiological controls' for core alterations, steam generator eddy current testing and tube-plugging, control rod cutting and outage related waste handling.

Engineering controls were effective

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in reducing occupational exposure.

During routine plant tours of the RCA (radiological' control area),

the inspector noted examples indicating ~that personnel may have been consuming food and tobacco products in prohibited areas. 'Specifically, candy wrappers were found on top of the safety injection bui.lding and on the ground outside the emergency diesel generator building. The inspector noted used cigarette, remnants and empty matchbooks on'the

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ground around the new safety injection tank.

Although no individuals were observed performing the above~ described' activities, the number of examples identified indicate a need for further attention. _These observations were elevated to management which increased attention ~to preclude recurrence.

No further examples were' identified following management actions.

5.2 High Radiation Area Not Conspicuously Posted

. During a routine plant tour on June 29, 1990, the inspector observed the entrance to a high radiation atea-not conspicuously posted as

required.

Specifically,.the access manhole cover to the-fuel transfer chute was unlocked and removed.

The associated radiological posting,;

" Caution, High Radiation Exclusion Area, Contaminated Area, RWP Required

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for Entry," was similarly. removed. When identified by the inspector,

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the area was barricaded and posted, " Caution, Contaminated Area, RWP Required for Entry." The highest general area dose rate'in the area

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was 300-2000 mrem / hour.

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At the time of identification, an entry into the area was in progress.

A member of the training department staff was restricting personnel access from outside the barricaded area.

The inspector questioned

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cognizant licensee personnel-why the area was not properly posted to

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reflect the. radiological conditions.

The licensee immediately reposted l

the area with the required high radiation area sign.

Licensee corrective action included reporting the incident as LER (licensee event report)-

No.90-004.

Radiation protection (RP). management issued memorandum RP 90-52 requiring RP department and contractor personnel to review posting and control requirements for high radiation areas.

The licensee revised'

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the RWP (Radiation Work Permit) procedure to require special instructions on RWPs.to maintain high radiation areas conspicuously posted.

The licensee attributed the root cause was personnel error on the part of.

the RP technicians who were knowledgeable of the posting requirements but inadvertently positioned.the manhole cover such~that.the previous posting was no longer visible.

Licensee review of personnel training-records and discussions with cognizant ~ personnel verified adequate training and personnel knowledge.

Further the licensee performed an

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evaluation to determine plant needs for secondary and/or permanent postings to assure all areas remain conspicuously posted regardless-of changes in access control devices and ongoing work activities.

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Inspector review noted a strong orientation toward safety in licensee

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actions. Although cognizant RP and training personnel did not-recognize

the posting deficiency in staging the area for access, a high level

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of radiological control was maintained throughout the evolution.

No actual compromise in worker safety occurred.- Licensee corrective actions were completed within the scope of this inspection.

Inspector review determined it was an isolated incident and not repetitive in nature as set forth in 10 CFR 2, Appendix C, Section V.A. for a

non-cited violation of 10 CFR 20.203(C)(1) (50-29/90-12-02).

6.

Maintenance / Surveillance The inspector observed and reviewed maintenance and surveillance activities relative to industry standards, administrative controls, and regulatory requirements.

Selected work evolutions and surveillance tests were observed to verify safety and compliance. Specific areas examined were licensee use of station procedures, codes and standards,: QA/QC involvement,' management oversight, safety tag use, jumper use, equipment alignment and post-maintenance testing (PMT).

In. addition, the inspector evaluated radiological controls for worker protection, fire protection, limiting conditions for operation-(LCOs), deficiency review, resolution and repor. ting per Technical Specification-(TS).

6.1 Ultrasonic Examinations of the Pressurizer and Reactor Vessel Head

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in light of'the pressurizer surface cracking observed at the Haddam

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Neck Nuclear Station, the inspector inquired about the Yankee Rowe pressurizer inspection program.

The licensee stated that the pressurizer inspections were suspended in 1986 when the inspection requirements were, removed from the TS.

The licensee was also aware of the reactor vessel head defect observed at Fitzpatrick Nuclear Station, s

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.To address these potential concerns in.the core XXI refueling outage, the licensee. secured an ultrasonic examination of!the reactor pressure vessel closure head and the upper regions of the pressurizer shell.

These examinations were-conducted to determine.if the cracks within the 304 stainless steel cladding had penetrated into the SA302B alloy steel base material.

o The cladding was applied by a resistance welded process which involved-spot welding a sheet of 304 stainless steel plate to the interior surface of the vessel's shell.

Thus, the clad cracks can only propagate into the base material where-the two materials are joined by the spot a

weld.

'Since 1965, the licensee has been periodically monitoring'the clad-cracking located within the pressurizer and the reactor pressure vessel closurc head.

The clad cracking in their Babcock and Wilcox designed

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pressurizer was discovered by liquid penetrant and' visual examination

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methods. The highest concentration of cracking occurred in the pressuri.er's water phase (22 feet from the manway) and in the steam phase to a lesser. extent.

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During the 1965 investigation, the licensee explored six cracks in:

i the pressurizer cladding by grinding and found no extension into the

base metal.

The cause of the cracks was believed to be intergranular

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stress corrosion because of the occasional high levels of. oxygen.

Another possibility was that they originated initially as weld cracks,

The inspector reviewed the 1990 ultrasonic reports of the pressurizer

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and the reactor vessel head.

The reports indicated that the automated P-Scan system was utilized. for the pressurizer and a manual system

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for the reactor head.

Inspector review of licensee Procedure YA-VT.22, i

Rev. 2 which covered both systems indicated.the examination processes-

met the specifications of ASME Section XI,1983 Edition.

I The areas selected for the examination contained known clad defects.

l The areas were identified as follows.

For the pressurizer, the examination was divided into-three sections.

Section 3-1 extended 15

inches down from the head-to-shell weld.- Section 16-2 extended between

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5 inches and 14 inches down from the outer shell weld.

Section 16-1 I

extended between 14 inches and 29 inches down from the outer shell l

welds.

For the reactor pressure vessel head examination, the area

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extended 18 inches to either side of stud hole No.1 and stud hole No.

13.

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l The inspector determined the licensee evaluation of the ultrasonic data which concluded there was no extension of the previously observed

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cladding cracks into the base metal was technically sound.

The' licensee intends to reinspect these components periodically every five years.

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6.2 Motor-Operated Valve (MOV) Refurbishment In response to Generic Letter 89-10 on Safety Related Motor-Operated Valve Testing and Surveillance, the licensee developed a program to improve MOV operability. On December 27, 1989, the licensee re9onded to the W.iC detailing the proposed course of action. A subsequent letter from NRC on June 11, 1990, requested additional information

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on the refurbishment program, testing, and schedule-for completing the MOV testing and surveillance program.

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The MOV refurLishment program is currently planned.to be completed in i

three stages.

In the current outage, 22 MOVs were selected based on safety significance.

On these valves, engineering review and ~ analysis was performed to generate the switch settings assuming-the maximut..

differer.tial pressure across the. valve. This review also assessed the adequacy of the existing actuator.

The refurbishment activity involved a full tear down _of-the limit-switch compartment and replacement of all degraded parts.

Due to the specialized nature of the work, the licensee utilized the. services of

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an outside contractor for performing this activity. This contrhetor

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is also the supplier of the MOV diagnostic testing equipment and service.

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i The inspector reviewed the various stages of the valve-tear down and assembly.

The inspector verified the use of manufacturer recommended

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grease, MOBIL 28, Beacon 325 at the main gear' case and limit switch

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gear assembly._ The inspector also verified the use of qualified. control wire, Firewall III, through material issue ticket 47699 as well as-l physical inspection.

The licensee has approved this wire for use in i

harsh environments.

]a All the valves serviced in this outage were subjected to diagnostic j

testing.

This testing demonstrated the function of the_ limit and

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torque switches at the required setpoint.

It also measured 1the thrust developed at the valve seat, which represents the thrust-available j

for valve closure under design bases events.

The Generic Letter requires all the safety related valves -be tested-

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with actual differential pressure across the valve to demonstrate j

operational readiness.

Due to certain process system limitations,

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the' licensee has tested only 4 MOVs with differential pressure across a

the valve. Th_e licensee is in the process of preparing a submittal l

to the NRC justifying the setpoints for the other valves.

This response u

is due to.NRC on November 30,1990,

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l l-The licensee control and management of the MOV contractor activity l

was adequate in that it addressed all the significant attributes of f

l the generic letter.

Licensee oversight of the contractor and the testing system was adequate.

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6.3 -Inspection of Mechanical Snubbers The mechanical snubbers used on various plant systems: to control expansion, vibration or shock are periodically inspected in accordance.

with the TS requirements. The licensee used the services of a contractor to performing the inspection and testing,

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A-sample of 6 snubbers were selected to represent 10' percent of.each snubber type. The sample chosen was in agreement with the TS guidance.

Three of the snubbers failed the test for 3 different reasons: namely l

compression, tension and more than 50 percent variance from~the previous demonstrated test ~ data.

The licensee took additional samples and expanded the testing in accordance with the procedure.. The failed snubbers were replaced.

The licensee program for snubber testing was-in compliance'with TS requirements and the results were satisfactory.

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7.

Security Selected aspects of plant physical security were reviewed during regular and backshif t hours to verify that controls were in accordance with the

security plan and approved procedures.

This review included the following

security measures: guard staffing, vital and protected area barrier integrity, maintenance of isolation zones, and implementation of access controls including authorization, badging, escorting, and searches.

Security personnel demonstrated noteworthy professionalism in. conducting their duties-to support outage activities. No inadequacies were identified.

7.1 Contractor Fitness-For-Duty (FFO) Program Determined Unacceptable On June 19, 1990, the licensee informed.the inspectors that the FFD

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program provided by New England Power Service Company-(NEPSCO) had been determined by the licensee's corporate auditing staff-to be unsatisfactory in meeting the requirements of_10 CFR 26. 'The NEPSCO program lacked the procedures and guidance specified in the regulations.

However, a subsequent. licensee audit determined.that the chemical

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testing portion of the program had been performed by a laboratory certified by the National Institute for. Drug Abuse (NIDA) and that the processing chain of custody was acceptable. Therefore,the111censee determined the test results were a valid screening.

Prior to audit identification, the licensee.had taken credit for the FFD program for initial unescorted access requirements for 55 NEPSCO employees.

Due to irregularities in NEPSCO chemical testing documentation, licensee retested all the individuals in.the YNPS FFD program by June 21, 1990.

All individuals tested. satisfactorily in

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the YNPS program.

During the interim prior to retesting, the licensee continued to allow the individuals unescorted access t'o the I

protected area.

10 CFR 26.23 (a) specifies that all contractor ar.d vendor personnel performing activities within the scope of this Part for a licensee must be subject to either the licensee's program

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relating to fitness for duty, or.to a program,' formally reviewed and'

approved by the licensee, which meet the requirements of this part.

This item is unresolved pending review by a NRC Region I specialist'

inspector (50-29/90-12-03).

7.2 Inadequate Screening for Unescorted Access to'the Protected Area

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On August 14, 1990, the licensee informed the inspector that YNPS had improperly screened access authorizations for 33 contractors employed r

by Applied Radiological Controls.

Specifically, the licensee did not i

obtain written FFD suitable inquiry statements frsm thenindividuals r

prior to granting unescorted access to the protected area.

The licensee identified the problem during an~ access-control audit on August 8-10, 1990.

The subject individuals had been accessing the protected and

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vital areas throughout the refueling outage which began June 23, 1990.

The licensee suspended access for the involved individuals on August 10.

Later the same day, following completion of the suitable inquiry

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documents and satisfactory evaluation, the licensee reinstated access authorization.

To prevent recurrence,~the licensee revised station procedures to detail the specific handling-of suitable -inquiry documents prior to-granting unescorted access to the protected area.

10 CFR 26.27(a) requires prior to the initial granting =of unescorted access to a protected area or the assignment to_ activities within the scope of this Part to any person, the licensee shall o_btain a written t

statement from the individual as to'whether activities within'the i

scope of this Part were ever denied the individual.

The licensee shall complete a suitable !.aui"y on a best-efforts basis to determine t

if that person was, in the past, tested positive for drugs or use of alcohol that resulted in on-duty impairment, subject to al plan for treating substance abuse (except for self referral for treatment), or removed from activities within the scope of this Part, or denied unescorted access at any other nuclear power plant in accordance with a fitness-for-duty policy.

This item is unresolved pending review by i

the NRC Region I specialist inspector (50-29/90-12-04).

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8.

Engineering / Technical Support

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8.1 Engineering and Technical Support for Outage Activities Inspector review noted a high level of engineering and technical support involvement for the core XXI refueling outage.

Reactor engineering (RE) was observably involved in core alterations, problem resolution associated with control rod performance and containment integrated leak rate testing (CILRT). Maintenance support department (MS0)

personnel assumed critical roles in the oversight and implementation of a motor-operated valve refurbishment and testing program, construction of the safety injection tank and associated modifications, installation of seismic safe shutdown system modifications, and the testing of

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main coolant system support snubbers. _ Yankee Nuclear Services Division (YNSD) personnel were observably involved in engineering design change request (EOCR) implementation.

l The overall quality of technical support was good.

However, inspector.

observation-of inplant activities and the subsequent review of personnel timesheets indicated that-RE and MSD personnel routinely worked up to-

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90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> per week, Management: had pre-approved the. outage overtime.

The inspector questioned the necessity for the subject individuals to work excessive overtime.

Licensee management stated that the onsite engineering staff worked the hours necessary for the tasks being-performed. Although no deficiencies were noted in personnel performance, the need for individuals, providing' oversight and technical support for critical activities, to routinely work excessive overtime warrants.

further management attention.

8.2 TMI (Three Mile Island) Action Plan Items Selected NUREG-0737, Clarification of TMI Action' Plan Items, were

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reviewed to assess'the status of licensee actions and the implementa; ion of required changes.

The rollowing items were reviewed.

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NUREG-0737, III.D.3.4.3., Control Room Habitability -

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Implementation Modifications

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The NRC NRR (Office of Nuclear Reactor Regulation) reviewed the licensee's proposed installation of the Control' Room Emergency Air. Cleaning System (CREACS) and documented acceptance in the NRC safety evaluation report dated Mayz28, 1982.

Subsequent to the installation,.TS amendment'No.-125 dated October 17, 1989 incorporated the surveillance requirements of the CREACS system.

q The inspector verified the installation and licensee program _forf-j implementing the TS_ surveillance.

This-item is closed.

NUREG-0737, II.E.4.1.2, Oedicated Hydrogen' Penetrations

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Review and Revise Hydrogen Control Procedures On Octcber 30, 1984, the NRC-NRR staff issued the licensee.an exception from the seismic and redundancy requirements of 10 CFR 50.44 (c)(3)(11).for hydrogen recombiner containment penetration

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isolation valves.' Consistent with details in the-supporting technical justification, the licensee issued station procedure j

OP-2658, Rev. 21. Major, Operation of the Post-Accident Vapor

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Container Hydrogen Control System.

Entry instructions.for OP-2658-are adequately detailed in station emergency' operating procedures (EOPs). This item is closed,

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NUREG-0737, II.8.1.l[x Reactor Coolant-System Vents'- Install Vents

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On December 29, 1986, the NRC issued the licensee an exemption from the control operability requirements of 10 CFR 50.44(c)(3)(iii)

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for the reactor coolant system high point vents to be operated

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from the station switchgear room instead of the control. room.

The four vents are powered from emergency. buses. Once power is restored. The valves can be operated remotely from the control

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room.

This item is closed.

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NUREG-0737, I1.B.1.3, Reactor Coolant System Vents - Procedures

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The licensee issued station procedure OP-2671,.Rev. 5, Operation.

of the Main Coolant System Vent System, to detail personnel guidance

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in operation of the vent system.

Entry instructions for OP-2671 are adequately detailed in station emergency operating procedures

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(EOPs).

This item is closed.

9.

Safety' Assessment / Quality Verification The inspector reviewed selected portions of.the licensee's self-assessment program to verify implementation and determine if those programs contribute to the prevention of problems through monitoring and evaluating plant performance, providing assessments and findings, and communicating and

following up on corrective action recommendations.

9.1 QA Audit Y-89-07, Plant Changes Audit Y-89-07 effectively identified deficiencies and observations for consideration by the plant.

It alst Informed licenseeLmanagement

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of,an apparent downward trend in performance based on engineering support limitations.

Specifically, the trend was: attributed to-the-combined workload from engineering support for maintenance, backlog of PDCRS (plant: design change requests),: and response to NRC Bulletins-and letters, The licensee responded to the identified deficiencies and-entered them into corrective action programs.

However, the observed performance trend was not discussed in response documentation reviewed by the inspector.

The licensee informed the inspector that thise13.ue i

was resolved in a separate memorandum within the department.

9.2 QA Audit Y-89-17, Operating Experience Assessment and Corrective Action

' Audit Y-89-17 effectively identified a weakness in licensee LER

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commitment tracking.

It.also identified licensee limitations in assessing 10E (Industry Operating Experience).

The-audit effectively assessed management performance in the application of 10E.

The. audit reflected an objective, critical examination of licensee, techn'ical'

reviews, corrective actions and prioritization of issues relative to.

safety, i

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9.3 LER 90-502, Unauthorized Person-in an Access Controlled Area, addresses the May 7,-1990, incident where an unauthorized individual accessed a controlled-area, due in part, to a malfunctioning access control device.

No deficiencies were identified,in the. licensee response to this incident or in the reporting made to the NRC.

This item was reviewed in Section-7.2 of NRC Region I inspection 50-29/90-07 as a non-cited, licensee identified violation.

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9.4 LER 90-002, Automatic ESF Actuation Following Loss of 400 Volt Bus, addresses the June 23, 1990, automatic: start of the No. 2 emergency.

diesel generator when the control room ope ator inadvertently turned the wrong circuit breaker control switch wh!1c attempting to crosstie:

the 480 Volt Bus 4-1 from the main transformer to the Y-177 offsite power supply. The details of this incident are described-in Section-4.1 of this report, In-addition to evaluating this incident.in accordance with the LER, the licensee performed a human factors

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assessment (HPES 90-02). Although this' assessment was'a good licensee-

initiative, one of the conclusions-was inaccurate based on inspector

observations in the control room and d arussions with~the subject

.1 operator immediately prior. to and followirij the incident..

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Specifically, the HPES attributed one of the causes _to operator.

j fatigue / tiredness.

However, the LER adequately characterized the

incident, root cause and corrective action.

No unacceptable

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conditions were identified in operator response actions or the

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reporting assessment.

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9.5 LER 90-003, Main Steam Safety Valves Setpoints Exceed Technical Specifications, addresses the June 30, 1990, TS surveillance test's on

the main steam line safety valves;where four of the twelve valves j

demonstrated lift settings greater than the=3-percent nameplate set j

pressure tolerance.

The as-found setpoints exceeded the allowable TS range by 0.3 to-8.5 percent.

The licensee determined the root

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cause was setpoint drift.

Subsequent retesting, without valve

adjustment, demonstrated each valve met the TS tolerance.

The licens'ee-

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technical and reporting assessments were' adequate._

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The safety assessment concluded the peak' pressures would remain below-the 110% design pressure for the limiting overpressure event of a j

loss of load from' full power.

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9.6 LER 90-004, High Radiation Area Not Conspicuously Posted, addresses

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the June 29, 1990, NRC identified high radiation area access which l

was not conspicuously posted as required.

Due-to the promptness of

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licensee actions and the strength of access control, this iter, resulted i

in a non-cited violation of 10-CFR 20.203 (c)(1).

Licensae actions-were adequate.

No deficiencies in reporting requirements were identified.

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9.7 LER 90-007, ?ressurizer Safety Valve Exceed Technical Specifications, addresses the July 6,1990, determination that pressurizer code safety valve (PR-SV-181) had exceeded the TS lift setting tolerance within.

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of 3% of nameplate set pressure of 2485 psig.

The as-found set pressure was 2574 psig.

The root cause was determined to be setpoint drift.

Immediate retesting of the safety valve, without adjustment,-

demonstrated a repeatable setpoint within TS limits.. The licensee noted similar occurrences which resulted in LERs 85-04,.87-07 and 88-13.

Each previous incident attributed the root cause, in part, to setpoint drift.

Both pressurizer code safety valves (PR-SV-181 and-

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PR-SV-182) are Dresser Model 31719A valves which were installed in 1984.

The licensee has not resolved problems with setpoint drift outside TS limits.

The as-found values do not, however, constitute l

performance approaching the design limits of 10 percent within the

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nameplate set pressure.

No deficiencies in reporting requirements'

were identified.

10.

Review of Periodic Reports Upon receipt, t',

inspector reviewed periodic reports submitted pursuant to Technical Spi. fications and other internal. licensee reports.

This review verified, w applicable:

(1) that the reported information was.

valid and included the NRC-required _ data: (2) that test results and supporting

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information were consistent with design predictions,and performance specification;. and (3) that planned corrective actions were maquate for resolution of the problem.

The inspector also ascertained hether any j

reported information should be classified as an abnormal c ;urrence.

The following reports were reviewed:

Monthly Statistical Report on plant operations for June and July,

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1990.

Proposed Change No. 235 to TS for changes in Safety Injection Tank

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Minimum Inventory, letter BYR 90-88, June 25,.1990; PORC Subcomnittee Review of Proposed Change No. 227 Reduced Level

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Operation, memorandum RE 90-61, April 9, 1990; EDCR No.89-301, Safe: Shutdown System Piping Modifications Inside the

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Vapor Container-Phase IV, March 12, 1990;

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a EDCR No.89-302, Pressurizer Auxiliary Spray and HPSI Throttle Valve i

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Modifications, February 9,'1990;

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J EDCR No.89-303, Safety' Parameter Display System (SPDS), memorandum

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YRP 1804/89, December 21, 1989; i

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EDCR No.89-306, Motor-Operated. Vah tions, March 12, 1990;

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EDCR No.89-310, Main Coolant Loop Valves; Disc Replacement

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i Phase II, March 28, 1990; j

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Core Operating Limits. Report. for Cycle '21,11etter EiYRJ90-100, July.

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19, 1990;.

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a', Core 21 Performarre. Analysis for the Yarikee Nuclear l Power Station,

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letter: BYR-90-99, July 20,'1990.

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The. inspector concluded that the above reports were acceptable..

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-11. -Management Meetinos:--

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At periodic 3intervalsiduring this inspection,fmeetings:werejheld.with senior!

j plant management.to discuss the'findingst..A: summary ofofindings-Lfor the

report period was also-discussed at the< conclusion of the inspection <and;

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prior to report-issuance.,.No proprie_tarylinformation'was. identified'as<

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beingi. included within the scope: of this'. inspection.

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