ML20234D700

Insp Repts 50-338/87-15 & 50-339/87-15 on 870513-0616. Violations Noted:Failure to Follow Procedure Resulting in Movement of Fuel Assembly While Partially Inserted in Fuel Rack & Violation of Tech Spec 3.6.1.1

ML20234D700
Person / Time
Site:	North Anna
Issue date:	06/26/1987
From:	Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20234D639	List: ML20234D636 ML20234D686 ML20234D700
References
50-338-87-15, 50-339-87-15, NUDOCS 8707070309
Download: ML20234D700 (15)

See also: IR 05000338/1987015

Text

f

UNITED STATES

gj@ MCoq[o ,

NUCLEAR REGULATORY COMMISSION

y -/ n REGION 11

$ j 101 MARIETTA STREET, N.W. l

• 1. ATL ANTA, G EORGI A 30323 i

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Report Nos.: 50-338/87-15 and 50-339/87-15

Licensee: Virginia Electric & Power Company

Richmond, VA 23261

Docket Nos.: 50-338 and 50-339

Facility Name: North Anna 1 and 2

Inspection Conducted: May 13 - June 16, 1987

Inspectors:

J.L.

M@ -

/.

Caldwell, Senio'r es Went Inspector

, [/DateM51gned

A <

L. .P. ' King, Resident IhspWtor

//2-

Oate Signed

Sh

Approved by: Y

F. S'.*Cantrell, Section Chjp

d h2 72

B' ate Si'gned 1

Division of Reactor Projects)'

SUMMARY I

Scope: This routine inspection by the resident inspectors involved the 3

following areas: plant status, licensee action on previous enforcement matters,

licensee event report (LER followup), review of inspector follow-u) items,

monthly maintenance observation, monthly surveillance observation, ESF walk- .

down, operator safety verification, design change modifications, verification j

of containment integrity and plant startup from refuelling. During the perfor- J

mance of this inspection, the resident inspectors conducted reviews of the

licensee's backshift operations on the following days - May 13, 14, 18, 19, 22,

23, 26 and 30 and June 1, 2, 3, 4, 5, 8, 9, 10, 11, 12 and 16.  ;

Results: Two violations were identified: Violation of Technical Specification 3.6.1.1, Containment Integrity; and Failure to follow procedure resulting in  !

movement of a fuel assembly while still partially inserted in a fuel rack (see j

paragraphs 7 and 11, respectively). )

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REPORT DETAILS

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1. Licensee Employees Contacted

• E. W. Harrell, Station Manager.

• R. C. Driscoll, Quality Control (QC) Manager

• G. E. Kane, Assistant Station Manager

• M. L. Bowling, Assistant Station Manager

• R. O. Enfinger, Superintendent, Operations

• M. R. Kansler, Superintendent, Maintenance

• A. H. Stafford, Superintendent, Health Physics

• J. A. Stall,-Superintendent, Technical Services ,

J. L. Downs, Superintendent, Administrative Services 1

J. R. Hayes, Operations Coordinator f

D. A. Heacock, Engineering Supervisor .i

D. E. Thomas, Mechanical Maintenance Supervisor j

G. D. Gordon, Electrical Supervisor l

R. A. Bergguist, Instrument Supervisor l

F. T. Termine11a, QA Supervisor i

J. P. Smith, Superintendent, Engineering j

0. B. Roth, Nuclear Specialist i

J. H..Leberstein, Engineer i

• G. G. Harkness, Licensing Coordinator  !

• D. J. VanDeWalle, Licensing Supervisor (SEC) i

Other licensee employees contacted include technicians, operators, mechanics,

security force members, and office personnel.

• Attended exit interview

2. Exit Interview (30703)

The inspection scope and findings were summarized on June 16, 1987, with

those persons indicated in paragraph 1 above. The licensee acknowledged

the inspectors findings. The licensee did not identify as proprietary any 1

of the material provided to or reviewed by the inspectors during this 1

inspection.

(0 pen) Violation 338,339/87-15-01: Violation of T.S. 3.6.1.1,

Containment Integrity (paragraph 7).

(0 pen)~ Violation 338/87-15-02: Failure to follow procedure resulting

in the movement of a fuel assembly while still partially inserted in

a spent fuel rack (paragraph 11).

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3. Plant Status i

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Unit 1

Unit 1 began the inspection period in day 25 of the refueling outage

with the fuel removed from the core. The unit completed reloading the

core on May 18, 1987, and is presently in Mode 5 day 59 of the refueling

outage,

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Unit 2

Unit 2 began the inspection period operating at approximately 100% power.

On May 21, 1987, the leakoff rate from the #1 seal of "C" Reactor Coolant

Pump (RCP) increased to approximately 5.8 gpm indicating a degradation of

the #1 seal. By May 23, the "C" RCP seal leakoff had increased to approx-

imately 8 gpm, and the decision was made to shut Unit 2 down. Shutdown .l

commenced on May 23,1987, after 217 days of continuous operation.

Shortly after the "C" RCP was secured following the shutdown, the #1

seal failed completely. The seal leakoff was isolated, and the #2 seal j

maintained the reactor coolant pressure boundary until the cooldown and

depressurization could be completed.

The licensee completed the replacement of the seal package on "C" RCP, f

and on June 1,1987, commenced a startup of Unit 2. The unit achieved

100% power on June 4, 1987, and is presently operating at 100% power.

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4. Unresolved Items

Unresolved items were not identified during this inspection.

5. Licensee Action on Previous Enforcement Matters (92702)

(Closed) Violation 338,339/86-28-03: Failure to Document Rubidium 88

Contamination. The licensee has com l

response to the Notice of Violation. pleted the action as stated in their

6. Licensee Event Report (LER) Followup (90712)

The following LERs were reviewed and closed. The inspector verified that

reporting requirements had been met, that causes had been identified

that corrective actions appeared appropriate, that generic applicabili,ty

had been considered, and that the LER forms were complete. Additionally,

the inspectors confirmed that no unreviewed safety questions were involved

and that violations of regulations or Technical Specification (TS) condi-

tions had been identified.

(0 pen) LER 338/85-03: Flooding Potential not Previously Evaluated.

(Reference Inspection Report 338,339/85-12) Corrective action in the LER

stated that long-term action was currently being developed. The turbine

building contains safety related equipment which could be affected by

flooding. A Type I VEPC0 engineering study showed possible options to

prevent this occurrence. To date, the licensee has not taken any long-

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term corrective actions. The insaector requested the licensee provide

a date when corrective action will be taken or submit a supplemental

response to the LER stating that long term action will not be taken and

provide the reasons why.

(Closed) LER 339/86-07: Reactor Trip Caused by Turbine First Stage

Pressure Spike. This item has been corrected by instrumentation.

(Closed K-Line Breaker with Improper Overcurrent Trip

Device.)The 10licensee

CFR 2185-01:

provided the inspector with a memorandum dated

May 19, 1987, stating that the breakers in question have not been

purchased for use at North Anna.

7. ReviewofInspectorFollow-upItems(92701)

(Closed) IFI 338,339/86-20-01: Inconsistencies in Locking .9equirements

for Auxiliary Discharge Valves. 1-0P-31.2A has been revised to lock

valves closed similar to Unit 2 valves and an engineering work request

was submitted to update the drawings.

(Closed) IFI 338/86-20-02: Inadvertent Safety Injection PT 36.1. The'

I&C Department has changed PT 37.1A and PT 36.1B on both units to:

1) Require single action steps

2) Have an operator sign the PT step

3) Only reset the train under test

This should preclude further events of this type.

(Closed) IFI 338,339/86-28-06: Determine Source of CS-138 Which Caused a

Hi-Hi Air Particle Monitor Alarm. The licensee took appropriate action

to determine the cause of the alarm. Air samples were taken and analyzed

but a source determination could not be made.

(Closed) URI 338,339/86-28-04: Verify That Rubidium 88 Did Not Exceed

MPC Limits of 10 CFR 20. The licensee demonstrated to the inspectors

that appropriate action was taken to ensure the 10 CFR 20 limits were not

exceeded.

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(Closed) URI 338,339/86-28-07: Modification of Commitments to NRC Regarding l

Inspector Concerns and a Violation. The licensee has taken steps to

modify the procedure to ensure it is not misinterpreted. J

(Closed) URI 338/85-31-02: Refueling - Fuel Transfer Equipment. The

engineering work request for Unit 1 was completed prior to the refueling )

outage, and the transfer mechanism performed acceptably. '

(Closed)URI 338,339/85-05-03: Battery Inspcction Comments. 'The licensee

changed the technical specification surveillance requirement for the

inspection of diesel fire pump battery cells.

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(Closed) IFI 338,339/84-27-05: Organization of Offsite Review Committee.

This item will be closed until another review can be made of the Offsite

Review Committee. The licensee has responded to all of the inspector's

concerns.

(Closed) URI 338,339/86-18-01: Outstanding Work Requests. This item

will be closed and monitored on a monthly basis. .The licensee made an

initial effort to reduce the amount of safety related work requests.

(Closed) IFI 338,339/86-03-03: Rockwell Edward Valve Failure. Periodic

tests were )repared for Unit 1 and Unit 2 for those valves which experi-

ence high tiermal transients. The licensee performed radiography on the

RTD bypass line valves and made repairs where flow caused the valve to

seat.

(Closed) IFI 339/84-19-01: Drawing Updates and Valve Lineu) Corrections

Required on D/G Support System. The licensee has revised tie drawing by

Engineering Work Request 84-508. All commitments have been completed on

this item.

(Closed)URI 338,339/87-10-02: Review Licensee Actions Following Discovery

of Potential Unreviewed Safety Question. In a memorandum dated May 13,

1987, from R. M. Berryman, VEPC0, to J. A. Stall, VEPCO, North Anna, the

licensee stated that a preliminary analysis on April 16, 1987 indicated

there were enough conservatisms in the current accident analysis to

consider them still bounding. This preliminary analysis was supplied by

Stone and Webster (S&W) and reviewed by the VEPC0 corp, orate Nuclear

Eng'neering Staff on A)ril 16, 1987. S&W completed their final review

on April 22, 1987, anc the conclusions were reported to be consistent

with the preliminary indications.

After discussions with the inspectors, the licensee agreed to perform a

formal 10 CFR 50.59 evaluation of the issue. In a memorandum dated

May 19,1987, from R. M. Berryman, VEPC0 to J. A. Stall, VEPCO, North

Anna, the licensee documented that no unreviewed safety question existed

concerning the use of 24.7 psia instead of 30 psia for the Hi-Hi contain-

ment pressure setpoint. The determination that an unreviewed safety s

cuestion did not exist had been addressed previously but not formally

cocumented.

(Closed) URI 338,339/85-12-01: Proper Description & Testing of Thermal

Hydrogen Recombiner System. In April' of 1985, the inspectors identified

a situation to the licensee where performance cf Technical Specification

(TS) surveillance 4.6.4.2.a on the hydrogen recombiners in Modes 1, 2 3 '

or 4 would cause the licensee to be in violation of TS 3.6.1.1 (Prima,ry,

Containment Integrity). The inspectors also had a concern that the

hydrogen recombiners could not withstand the design bases containment

pressure increase of 45 psig. In April of 1986, the licensee performed an

engineering evaluation, Engineering Work Request (EWR)86-156, which

concluded that the recombiners could withstand the maximum containment

pressure caused by a design based accident. However, a S change allowing

theperformanceofTSsurveillance4.6.4.2.a,whichrequ]iresnon-automatic

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containment isolation to be open for approximately four hours, was net

submitted to the NRC until May 27, 1987. At the time, it was the ins)ec-

tors' understanding that performance of TS 4.6.4.2.a would not be concutted

with the units in Modes 1, 2, 3, or 4 until the licensee received an NRC

approved TS change.

During a recent review of the unresolved item, the inspectors discovered

that the licensee had performed TS 4.6.4.2.a numerous times, beginning in

1985, with the associated unit operat,ing in Mode 1,,2, 3, or 4. The

inspectors had been given the impression that the licensee had not, and

would not, perform this surveillance unless the unit in question was in

Modes 5 or 6. Based on further discussions with the licensee, there

appeared to be a misunderstanding among personnel within the licensee's

staff and with the inspectors. Personnel involved with the performance

of the hydrogen recombiner surveillance felt that since the recombiner

had been demonstrated capable of being an extension of the containment

boundary, and since it would be required to be placed in service following

an accident, then performance of TS 4.6.4.2.a in Modes 1, 2, 3, or 4 was

acceptable. However, the inspectors had made it clear to other licensee

personnel that performance of the hydrogen recombiner surveillance,

opening of non-automatic containment isolation valves for greater than

an hour, with the unit in Modes 1, 2, 3, or'.4 would be a violation of

containment integrity as presently stated in TS 3.6.1.1.

The inspectors reviewed the procedure for performance of the hydrogen

recombiner surveillance and determined there was no mention of shutting

the containment isohtion valves if an accident occurred. In fact, there

was no discussion in the procedure precaution or otherwise which described

these valves as containment isolation valves and what should be done in

case of an accident. The inspectors concluded that the administrative

controls over the oaeration of these containment-isolation valves with the

plent operating in iodes 1, 2, 3, or 4 was inadequate. ,

Based on the fact that this item was identified in April of 1985, the

insaectors indicated to the licensee that performance of the surveillance

in iodes 1, 2, 3, or 4 was a violation of TS 3.6.1.1 the EWR demonstrating

the recombiner could withstand design bases pressur,e was not completed

until a year later in April 1986, the administrative control of the valves

did not address the containment integrity issue and finally, the TS change

was not issued until May 1987, over two years after the.need was identified,

the performance of the hydrogen recombiner surveillance with the unit in i

Modes 1, 2, 3, or 4 will be identified as a violation (338,339/87-15-01)  !

of TS 3.6.1.1. <

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8. Monthly Maintenance (62703) l

Station maintenance activities affecting safety related systems and i

components were observed / reviewed, to ascertain that the activities were

conducted in accordance with approved procedures, regulatory guides and

ir,idustry co&s or standards, and in conformance with Technical Specifica-

tions.

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The licensee informed the inspector that during inspections of several I

Limitorque Motor Operated Valves (MOVs), grease was discovered in the ]

valve spring packs. This grease was also beginning to seoarate into an i

oil-like substance and a wax-like substance. The licensee was concerned l

that the separated grease could inhibit the operation of the spring pack

and consequently prevent the torque switch from stopping the motor.

Based on this discovery, the licensee decided to look at the grease in i

all of the safety related Limitorque MOVs. The licensee also changed i

their preventative maintenance procedures to recbire removal of the spring

pack cover to inspect for excessive grease anc grease separation, and

initiated a p ogram to replace the grease on MOVs in containment with

Exxon NEBULA ..

On May 21, 1987, the inspector observed the disassembly of Limitorque MOV )

1286B, the "B" charging pump discharge valve. This disassembly was being )

performed under maintenance 3rocedure MEMP-C-MOV-1. The inspector observed

the grease separation, and tie location of grease in the spring pack. The

harder portion of the grease was observed to be still pliable with i'he

consistency of axle grease.

On May 22,1987, the inspectors reviewed the Engineering Work Request

(EWR)87-375whichprovidedtheinstructionsforthemodificationofsix

incore flux thimbles. These thimbles were being modified because they

were discovered to have wall thinning greater than'35% (see Inspection

Report 338,339/87-10, paragraph 7). Along with the EWR, the ins 3ectors

reviewed the 10 CFR 50.59 safety evaluation which demonstrated tlat the

repairs did not present an unreviewed safety question and the_ temporary

maintenance procedure TMMP-C-RC-8 which provided the instructions to

perform the modification. The inspectors did not identify any problem

associated with these procedures.

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During this inspection period, the licensee , performed the disassembly,

inspection and repair of the 1J Emergency Diesel Generator (EDG) (see

Inspection Report 338,339/87-10, paragraph 7). The preliminary results

of this inspection indicated one piston pin floating bushing had extruded.

This bushing, from the number 3 upper piston, had extruded to the extent i

that it had become an interference fit in one section of the bushing.

The area of the bushing that had grown showed signs of discoloration,

indicating it had been abnormally heated and showed signs of rubbing

against the fixed bushings. The discovery of this bushing, and the number

10 upper bushing on the 1H EDG, indicates that the floating bushings can  !

become heated and extruded in one section uf the bushing without being

identified as a problem during the six-month piston pin bushing, gap

measurements. The licensee was requested to evaluate this situation and i

provide some discussion and conclusions in their diesel rtport due to be

issued to the NRC in September 1987.

The licensee

the steam has comp

generators SG). (leted the various

The result of this types

testingofindicates

eddy current testing of

numerous

tubes in each of the SGs require plugging. Based on the results of the

sample of tubes required to be inspected by TS, the licensee is required

to get NRC concurrence prior to operation of the SGs.

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the licensee

described their tube pluggi,ng criteria.in a meeting

This criteria bas in Washington with th

of the following: all indications greater than 40% of nominal tube wall

thickness will be plugged which is in complicnce with TS, all distorted

indications which cannot be accurately evaluated will be plugged, and all

tube sheet possible indicaticas will be plugged. Based on this criteria,

the number of tubes requiring plugging in SG "A" is 83; SG "B" is 62; and

SG "C" is 118. The totai

6.17%; SG "B" equals 5.25% percentage

and of tubes

SG "C" equals 7.99%.plugged in SG "A" equals

The licensee

performed a 10 CFR 50.59 evaluation on the effects of plugging SG tubes

and determined that with less than 12% plugged, they were still within

their accident analysis and did not present an unreviewed safety question.

Based on this meeting, the NRC committed to send a letter to North Anna

Power Station stating that it is acceptable to operate the SGs following

the completion of the plugging of the SG tubes as committed to by the

licensee on June 3, 3997.

It came to the inspectors' attention, that during the Unit 2 shutdown on

May 23, 1987 followin the

associated discharge ckeck valve hung 03en.thesecuringofthe"B"MainFeed

Following discussions w

the licensee, the inspector discovered tlat at least on two other occasions,

one in 1985 and one approximately five months earlier, MFP discharge check

valves failed to shut following the securing of the associated MFP.

The licensee has inspected and repaired as necessary all of the Unit 1

and Unit 2 MFP discharge check valves. The one that failed during the

Unit 2 shutdown was discovered to have one dowel pin and one hinge pin

missing. The other past failures could not be determined as to their

cause but the licensee documented replacement of their bushings and

pins. , The recent inspections of Unit 1 and Unit 2 check valves revealed

various problems from degraded wear of the dowel pin, the hinge pins and

the bushings to missing dowel and hinge pins.

Based on these findings, the licensee repaired the check valves as neces- I

sary and is in the process of establishing a preventative maintenance

procedure to , periodically ins 3ect these check valves. One important thing

to note; unlike the MFP disclarge check valves at the Surry Station that

failed during the recent feedwater pipe rupture event, the North Anna-

check valves have their seats welded to valve body and the dowel pins

holding the hinge pin in place were welded. These modifications to the i

check valves were identified to North Anna by Crane through Stone and

Webster in 1978 during construction.

The inspectors observed the following maintenance items during this

inspection period:

EWR 86-054c, installation of hush trim on main feedwater regulating

valves.

The maintenance associated with pulling diesel generator bearing.

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Reactor Coolant Pumps - The inspectors observed the replacement of

the seal package on the "B" pump, and the teardown of the "A" motor

for the five year inspection. The. five year inspection on the "A"

motor showed signs of overheating on the motor windings. i

The recirculation spray heat exchanger diaphragms replacement on the

recirculation spray heat exchangers.

The installation of new Exide batteries for the 1-III battery bank.

The maintenance on 1-SI-MOV-1890D, Low Head Safety Injection Pump

Discharge to the Cold Leg. A work request had been written because  ;

of a body to bonnet leak. The inspectors reviewed the procedure, the <

material certification and the radiation work permit. No problems l

were identified. 1

The replacement of piping and welding of the main feedwater piping. l

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The installation of the new environmentally qualified cable for the

incore thermocouples. This was being done under design change >

package 85-07.

The installation and torquing of the main steam relief valves.

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During the outage, the "B" residual heat removal pump motor showed l

evidence of smoking. The lug terminal connection was burned off. Megger i

readings were taken, the lug replaced, and the motor restarted. .

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New air cylinders and tubing have been installed for the decay heat dump

valve and the steam valves to the Terry turbine for the auxiliary feedwater

pump. -

The service water valve to the recirculation spray heat exchangers 101

A&B are being replaced with refurbished valves.

No violations or deviations were identified.

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9. Monthly Surveillance (61726)

The inspectors observed / reviewed technical specification recuired testing

and verified that testing was performed in accordance wit 1 adequate

procedures, that test instrumentation was calibrated, that limiting

conditions for operation (LCO) were met and that any deficiencies

identified were properly reviewed and resolved. -

The inspectors observed portions of the following surveillance procedures;

2-PT-71.1 " Operation of Auxiliary Feedwater Steam Turbine"

1-PT-213.14 " Valve Stroke Test for Instrument Air Supply, TV-1A-102A

and 1028.

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1-PT-61.2.3 " Containment Type B Equipment Hatch Testing". The "0"

ring seals at the enclosure passed, but the "0" rings for the air

lock failed and were replaced. They were retested and passed.

1-PT-83.4 " Blackout of Emergency Bus for Shutdown Loads" for the IJ

bus portion. The diesel started and picked up the loads.

Type "C" Valve Testing - Approximately 44 valves have to be retested ,

as a result of excessive leakage identified during , Type "C" testing. i

The inspectors reviewed the Type "C" testing requirements outlined  !

in 1-PT-61. 3. The "as found" and "as left" conditions are documented I

on the summary pages of the procedure. A review was made of past

Type"C"andTye'A" tests. There are some valves.that consistently

fall the Type C" test. Theseincludetheairejectordivertcheck

valve in the containment, the recirculation spray heat exchanger

service water valves and the containment purge valves.

The inspectors witnessed the Type "C" testing of 1-RH-36 and 1-RH-37

which were leaking approximately 18 SCFH and the Type "C" testing of

the containment purge inlet valve.

The inspectors made a survey of the containment loop rooms and the

3enetration area to look for valve leaks. No leaks were identified which

lad not been previously identified by the licensee.

No violations or deviations were identified.

10. ESF System Walkdown (71710)

The following selected ESF systems were verified operable by performing a

walkdown of the accessible and essential portions of the systems on

June 16, 1987.

The inspectors verified the valve lineup for the 1H and 2J Emergency

Diesel Generator (EDG) auxiliaries per the following procedures:

1-0P-46.4A - Valve Checkoff - Diesel Air

1-0P-6.3A - Valve Checkoff - 1H Diesel Engine Lube Oil System

1-0P-6.1A - Valve Checkoff - 1H Diesel Engine Cooling Water

200P-6.2A - Valve Checkoff - 2J Diesel Engine Cooling Water

2-0P-6.4A - Valve Checkoff - 2J Diesel Engine Lube Oil System

No violations or deviations were identified.

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11. Operational Safety Verification (71707)

By observations during. the inspection period, the inspectors verified

that' the control room manning requirements were being met. In addition,

the inspectors observed shift turnover to verify that continuity of system

status was maintained. .The inspectors periodically, questioned shif t I

personnel relative to their awareness of plant conditions. l

Through log review and plant tours, the inspectors verified compliance l

with selected Technical Specification (TS) and Limiting Conditions for

Operations.

In the course of the monthly activities, the resident inspectors included

a review of the licensee's physical security arogram. The performance

of various shifts of the security force was o] served in the conduct of

daily activities to include: protected and vital areas access controls,

searching of personnel, packages and vehicles, badge issuance and

retrieval escorting of visitors, patrols and compensatory posts. In i

addition,, the resident inspectors observed protected area lighting,

arotected and vital areas barrier integrity and verified an interface

aetween the security organization and operations-or maintenance.

radiation work permits (RWP) were reviewed and the

On a regular

specific basis,ity was monitored to assure the activities were being

work activ

conducted aer the RWPs. Selected radiation protection instruments were

periodical'y checked and equipment operability and calibration frequency

was verified.

The inspectors kept informed, on a daily basis, of overall status of both

units and of any significant safety matter related to plant operations.

Discussions were held with plant management and various members of the

operations staff on a regular basis. Selected portions of operating logs j

and data sheets were reviewed daily. l

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The inspectors conducted various plant tours and made frequent visits' to I

the control room. Observations included: witnessing work activities in

progress; verifying the status of operating and standby safety systems

and equipment; confirming valve positions, instrument and recorder

readings, annunciator alarms, and housekeeping.

On Mav 18, 1987, the inspector conducted a tour of the Unit 1 containment

building. During this tour, the inspector witnessed the transfer of

several fuel assemblies from the fuel pool into the vessel. The insoector

observed the licensee's performance of loading fuel into the vessel' from

the containment refueling bridge. The operation of.the transfer system, j

up-ender and refueling bridge was performed by Westinghouse contract

personnel. The VEPC0 personnel observin

refueling Senior ' Reactor Operator (SRO)g and the operation

a Quality consisted

Assurance (QA) of the

inspector. The reloading fuel operation began on May 15, 1987, and was

completed cn May 18, 1987.

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On May 23, 1987, the inspector observed portions of Unit 2 reactor shut-

down. The unit was being shutdown due to a degraded "C" RCP #1 seal. i

Following the completion of the control rod insertion, the licensee

secured the "C" RCP. Approximately five minutes after the RCP was

secured, the #1 seal failed completely. The licensee followed 1-AP-33 )

" Reactor Coolant Pump Seal Failure" and. shut the #1 seal leakoff valve. 1

The #2 seal maintained the reactor coolant pressure boundary until the '

unit could be cooled down and depressurized. During the repair, the

inspectors made a containment entry to witness replacement of the seal.

Based

operation onofathe

request

Low HeadfromSafety

the Region,

In jection (LHSI) and Higo Head Safetyth

Injection (HHSI) System transfer from the injection , phase te the recircu-

lation phase. This review determined that the suction of tne LHSI pumps

automatically swaps from the Refueling Water Storage Tank (NST) to the

reactor compartment sump on a low level in the RWST. Not oniv does the

LHSI system change state on a RWST low level, but so does the' valve for

LHSI discharge to the suction of the HHSI pumps. Therefoi . 'A safety

injection system will automatically swap from the injection m, ele taking a

suction from the RWST to the recirculation mode where the LHSI pumps take

a suction from the containment sump and discharges to the reactor vessel

and/or supplies the necessary net positive suction head to the suction of

the HHSI pumps.

Following the recent discovery of deposits of boron on the vessel head at

the Surry Nuclear Station, and the earlier problems at another facility,

the inspector requested the licensee make a determination to see if the

problem exists on either unit at the North Anna Power Station.- At the

time of the request, Unit I was in a refueling outage and Unit 2 had just

shutdown due to a degraded reactor coolant pump seal. The licensee had

already inspected the Unit 1 reactor vessel head and bolts and informed

the inspectors that they did not discover any boron deposits on the vessel

head or the bolts. Unit 2whichhadjustshutdownwasinspectedandthere

did not appear to be any indication of previous leaking or identification

of boron deposits in the vessel head area. The licensee also performed a

review of past leakage problems since the last refueling outage for Unit 2

and did not discover any in the vessel head area.

On Ma"

Mode!I.25,1987, thethis

Following licensee

mode changed modes

change, the on Unitbecame

inspectors 1 from Mode

aware6oftoa  ;

problem associated with the pressurizer code safety that was being taken 1

credit for in TS 3.4.3. This TS requires a minimum of one code safety

to be operable in Modes 4 and 5. This specific code safety was' fully

o J eretional except for a snubber supporting the discharge tail piece

w1ich was inoperable. TS 3.7.10 requires snubbers located in systems

required to be operable in Mode 5 to also be operable. The licensee

evaluated the inoperable snubber and determined that in the condition

-of the unit at the time of the mode change, approximately 90 degrees i

Fahrenheit, the snubber was not required to support the operation of the

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code safety. The licensee also considered in this evaluation that the

pressurizer PORVs were blocked open, the RHR reliefs were on line and the  ;

vessel was partially drained making it unlikely that the safety would be  ;

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required to relieve pressure and then it would be water not steam. j

However, this evaluation did not address all the possible failures of

the snubber and code safety discharge pipe and how they could affect

the operation' of the code safety. One question not addressed, was the

possibility of the failure of the discharge pipe in such a way that -

would restrict flow out of the safety also, even though reactor coolant

temperature was 90 degrees Fahrenheit and the vessel level was partially

lowered, Mode 5 allowc up to 195 degrees Fahrenheit and the unit could be -

filled with a steam bubble in the pressurizer. 4

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Based on the condition of the plant at the time of the mode change, the

failure of the code safety to relieve pressure would not have presented a

safety probiem due to the other relief paths. However, TS 3.0.4 states

in part... entry into an operational mode or other specified applicability

condition shall not be made unless the conditions of the Limiting Condition

for Operation are met without relevance on the provision contained in the

action statements unless otherwise excepted. Since the snubber was

technically required to support the operation of the code safety and the 4

snubber was inoperable also making the code safety technically inoperable, i

then both TS 3.4.2 and 3.7.10 LCOs wer2 in action statements. Even though

the safety significance is minor, the entry into Mode 5 from Mode 6 with a

technically ino,perable code safety was being considered a viciation of TS 3.0.4. Following the identification of the potential violation the i

licensee re-examined the circumstances involved in the mode change. This

re-examination revealed that one of the other relief valves previously

considered inoperable because the valve had not been fully torqued was in

fact torqued enough to be considered operable. The licensee stated that ,

the inlet flange had been torqued to at least 250 ft-lbs and an engineering

calculation demonstrated that the bolts would take the stresses present at l

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pressures up to 2485 psig. The licensee also stated that the inlet flange '

was made up metal to metal and would have prevented leakage at the maximum

pressures experienced in Mode 5. Based on the fact that all three safeties

were installed, the plant conditions at the time of the mode change did

not present a potential for an overpressurization event and the TS

requirement for one operable safety relief was met without the reliance on I

an action statement this event is no longer being considered a violation. I

The inspector will continue monitor the licensee's decision process in

making mode changes and complying with TSs.

On May 16, 1987, while moving fuel in the spent fuel pool in preparation

for transferring the fuel to the Unit 1 containment, a fuel assembly, ,

G-56, was moved'in the lateral direction while still partially inserted

in the spent fuel rack. The fuel handling operator recognized that

something was wrong after moving the spent fuel handling bridge approxi- l

mately 4 to 12 inches and immediatelv returned the fuel handling equipment  !

back directly over the fuel rack. 'The fuel assembly was withdrawn and i

inspected to determine if any damage occurred. The inspection included a  !

visual, with binoculars, and a video tape examination. The licensee

reported that neither examination revealed any damage to the fuel assembly. ,

Following the licensee's investigation into the cause of the event, the  ;

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fuel assembly was transferred to the Unit 1 containment for loading into

the core. The mishandling event resulted in an approximate four and

one-half hour delay in the core reload.

Refueling operations were performed by a contractor (Westinghouse) under

the supervision of a VEPC0 SRO. Just prior to the mishardling event, the

fuel handling equipment operator had been relieved, and the turnover did ,

not include the position of the fuel assembly. The on-coming operator

assumed that the assembly was fully withdrawn and did not h.. at the

assembly to ensure that it was withdrawn. This was further complicated by

the fact that VEPC0 policies require two operators on the bridge; one

handling the fuel assembly tool and the other operating the bridge. At i

the time of the event, there was only one oparator on the bridge

performing both functions.

This policy, along with other VEPC0 : fueling, procedures and policies,

were ex)lained to the contractor personnel prior to any fuel manipula-

tion. iowever, the inspector was informed that on several occasions, the

licensee had to reinform the operators on the correct procedures and ,

methods of operation required to be performed during fuel assembly  !

manipulations.  !

The licensee's investigation into the event revealed several discre-

pancies. The contractor's o)erator failed to follow both the VEPC0

policies ar.d instructions inc the contractor's fuel handling procedure.

The contractor's fuel handling procedure F-5, step 6.2.3, prohibits

lateral movement of the fuel handling hoist while any part of the latched

fuel assembly is inserted into the storage cells, transfer system or

elevator. The VEPC0 policies and instructions, which were explained to

require two operators on

the contractor's

the bridge personnel

during fuel on several

manipulation. Theseoccasions,icies,

pol however, are not

spelled out in the licensee s procedures. The operator failed to conduct

an adequate shift turnover, and the turnover was not performed at an

appropriate point in the fuel handling operation. Finally, the

Westinghouse operators were not following the directions of the refueling

senior reactor operator as demonstrated by the need on several occasions  !

to caution the operators on their fuel handling techniques, l

Technical Specification 6.8.1 requires written procedures be established,

implemented and maintained covering refueling operations. Contrary to

the above, on May 16, 1987, the spent pool refueling bridge operator l

failed to follow the contractor's refueling procedure. F-5 and the

operations which

licensee's policies

resulted in the and instructions

lateral movement for fuel handling,1e

of a fuel assembly wn1 still partially

inserted in the spent fuel rack. This misnandling event could have  ;

resulted in a damaged fuel assembly and is a violation (338/87-15-02).

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12. Design Change Modifications (37700)

The fc: lowing completed design changes were reviewed.

84-59 - Reg. Guide 1.97, Pressurizer Liquid Temperature Modification

83-34 - Class IE RTD, Replacement Safety Related

84-46 - Reg. Guide 1.97, Waste Gas Decay Tunic Instrument Modification

84-005 - Reactor Trip Breaker Shunt Modification. l

The design changes were reviewed to verify that drawings and procedures

had been updated and the testing had been completed. The inspector

verified that the written basis upon which the change was based was 4

technically correct and no unreviewed safety question existed. 1

The inspectors noted that several design changes had been installed but

not completed. In one case, DCP 84-72 " Pressurizer Safety and Relief

Valve Discharge Pipe Support Modification" was not completed because the

pressurizer belly band support was not modified.

A review of other design change packages indicated that too much time

elapses before closing out the design change deficiency reports. This

results in changes being installed, but not completed for long periods of

time.

No violations or deviations were identified.

13. Verification of Containment Integrity (61715) i

Verification was made of integrity of the equipment airlock on June 6,

1987, by witnessing 1-PT-61.2.3.

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The conteinment penetration area inside the containment was inspected to  ;

ensure proper valve lineup. Included in the penetrations checked were

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Penetrations 22, 18, 17, 35, 37, 44, 48 and 54.

The accumulator systems were walked down as part of this module.

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No violations or deviations were identified.

14. Plant Startup from Refueling (71711)

Valve checkoff 1-0P-7.3A was used to verify the position of the accumulator >

valves on "A" Accumulator. The motor operator was removed from the i

accumulator outlet valve as part of the program to change out the grease.

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No violations or deviations were identified.

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