Text

Insp Repts 50-313/89-40 & 50-368/89-40 on 891001-1115. Violations Noted.Major Areas Inspected:Plant Status,Followup of Events,Operational Safety Verification,Surveillance, Maint & Outage Activities
	ML19353B165
Person / Time
Site:	Arkansas Nuclear
Issue date:	12/04/1989
From:	Chamberlain D; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:	;
Shared Package
ML19353B163	List: ML19353B162; ML19353B164; ML19353B165;
References
	50-313-89-40, 50-368-89-40, GL-87-12, GL-88-17, NUDOCS 8912120079
	Download: ML19353B165 (27)
	v • d • e

ys; ;

.-

.

&

4

s

, . -

?

%

i

.

,

4,

' APPENDIX B

V.S. NUCLEAR REGULATORY COMMISSION

REGION IV

W.-

Inspection Report:- 50-313/89-40_

Licenses: DPR-51

'

'50-368/89-40

NPF-6

' Dockets:

50-313

e

50-368

Licensee: Arkansas Power & Light Company (AP&L)

P.O. Box 551-

. Little Rock,. Arkansas 72203

Facility.Name: _ Arkansas Nuclear One (ANO), Units 1 and 2

Inspection' At: AND Site,'Russellville, Arkansas

'

0

.

LInspection Conducted:

October 1 through November 15, 1989

,

Inspectors:

C. C. Warren, Senior Resident Inspector, Project Section A

' Division of Reactor Projects

R. C. Haag,. Resident Inspector, Project Section A, Division

of Reactor Projects

f

Approved:

/2- 4- @

D. D.6 Chamberlain P' Chief,' Project Section A

Date

Division of Reactor Projects

Inspection Summary

Inspection Conducted October 1 through November 15,1989 (Report 50-313/89-40:

50-368/89-40)

, Areas Inspected:

Routine unannounced inspection including plant status,

-followup of events, operational safety-verification, surveillance, maintenance,

outage activities, and review of licensee action on low minimum flow conditions

for EFW pumps.

Results:

Four apparent violations of NRC requirements were identified:

Failure to

maintain the Technical Specification (TS) required number of logarithmic (LOG)

power monitor channels operable (Section 7.8), failure to properly torque

fasteners on -plant equipment (Section 6.4), failure to maintain appropriate

procedures for maintenance and testing activities (Sections 6.4, 6.5, and 6.6),

and failure to take prompt effective corrective action (Section 8.0).

8912120079 891204

f

PDR

ADOCK 05000313

,

G

PNV

a

.

[ ryhh6 h '"

'

+

,

LiidCF

'

"

'

4

,

907" 4)

",s

N

,

. ;

>

,

-g.:

, ;

-

,

j

e

1

~

!

'

,-

-. .

.

,

-

.

s

' An' unresolved-item was : identified during this -report period.- 'The unresolved-

j

o

Litem:: involved the adequacy of the retest requirements _ for motor operated

i

valves-(Section3.1).-

,

-

1 Strengths:

i

l

>

0ver'all.cooidination,-control',andcommunication'duringtheUnit2'outagehas?

,_

4~

_ been very good.;

j

LConcerns:

.

1.

Timeliness,andLadequacy of. corrective actions' continue to be weak in some

-

instances.

2.

" Personnel errors led -to plant trips.(Section'3.2), personal injuryo

(Section)7.12) and equipment damage (Section 7.11).. While_immediate

ci.,^

? licensee actions appeared appropriate, long-term plans to propagate

management'sI performancer goals,f objectives, rand expectations 'have not been -

established.~ ~

'

-3.

. Whenffaced:with conflicting procedural . requirements,' a Unit 1Eshift

'

_ supervisor deviated. from. procedural requirements -without consulting -

,

management'or; initiating'actionftoresolvethe: procedural-conflict.

'(Section 4);

4

1

- 4.

Another examp'le of a surveillance test scheduling problem occurred.

-

2 Although: licensee management review of.this,issuet is~ underway, the staff:

_

' continues to be concerned with the frequency that surveillances are not-

performedidue to. scheduling-errors at ANO.

!

a

+

r

5

-4

l*

_

>

f

.

4

I

..

i'

'

.

..

.

..

p%+**4

y

3_ . #

+

a w

,

, y

,

.

,

p ,~,

.s ,s 1 7 , g.

e

--

m.m . ,3

g

m

p ' 3(>3

af

r=

x,

.

-

,

,

,

W:4

" <

,

.

,

+ b:

,

'_

rc.

.,y

. , y

J'

? t;.

y'_

o

1

,

4

g

,

-

g

-

_n

-

,g,c

-

,

..

,

-

e+, m+

s -

4t-

i

.

-

o..

~ : 3

o

au

n,.

q-3 ~ t

,

<

-

';

-yc -

~

..

,

.

+t_,--

-

,

ag .

v

- .

. ,

. i ,

,

.

,

> , 3 ~Y w _o

s;

,

o

,

., ,

A

9% . d

.

,

g*f-' f 7 p

i

r

f'

'

.t

'

,'

t

,y

i y ; _.

_

%J_

',;;-w

,

.C

"

,

_

1Tabd30f Cont'ents? ~=' *

K ?. s

. #x

. ,

.

-

<

r

+;

'I'

..

( ,.

c,

-

,

.:

'

,

ie'

I

.

f

+

e

',

f.~

,,

',

.

,

,*

>+

4

,;

Page

..

,a

m-

4

,

-

4

,

.

gg1 ,

,

w

.m

w.

.,

,

_..

_.;..

,

Z

i N 1'.0D Persons; Contacted?.;:;..y. .c.-.

. .~' . . . . .'.;. .c.:.

.

5-

.

. . .

'

,

- ..

.

2.0JPlant; Status-

.

t. s. .

.....:.>.3........

5-

"-

4

-

,

.#

.

,'

. . . . . .

.

-

h

L3.0$Fo11owup ofJ Events?(Un'its 1 and 2)

, .' g .

6-

.

. . .:

. . . . .

+

we.

.. ..

-6:

M*

l 3,1; / Review. of Ret'est Requireinent's

._, , . . . . .., , . . .

7

D b i.t' 1.' T r i p s i . . . . ' . . . . . . . . . . . . . . . . . . . ..

7

j

-

3.2

U

,

~.

.

10, 1989 Trip:~.

7;

j

.

.

x3.2.1 November

g

7

'

.

. .....

.......

>

W~

13.2 ;2 'Novembe r;;-15, 1989tTrip ... . . . . . . . . . . . . .

8-

1

>

L1 b

,,

?3.3.' iWater Leak?Intolthe Instrument Air System

-.8-

'"

lL ~

-

. . . . . ,,. .

7 {!

,,

'

4

i

-

w 4.010perational' Safety Verification (Units 1- and 2) . . . . . . . .

9'

j

"

_

1

'

(

3

,,

.

s

15.0 Monthly Surveillance Observatio_n (Units le and"2). . . . . , .

110

-

s w

.

i

'e

I6[0?MonthlyMaintenanceObservation(Units 1=and2).........

11:

-

.

-

,

n

m

' '

6.1 (Oisassembly andiRep. air of High Pressure Safety

,

g

,4

' Injection (HPSI). Pumpf Discharge' Valve 28I-10B

. . . . . . .11 '

Li

w

..<@

x--

6i2::. Inspection, Maintenance,Cand Cleaning of' Unit 2-

- m

..

,

m' +' , '

~

! Service Water'(SW) Intake: Structure' Gate . . . . . . . . .- 12

a

'

.

4

-

,

'

16.3i(TroubleshootingEFWPumpDischarge-Valve,

'

. . . . . . . .. . . . . .: 12'

"_

H2CV-1037, Failure lto:Close . .

,

.

~

r

s:

a

>

I.4iUse.ofiUniversaljo'ints_DuringTorquingEvolutions....

13<

4

'

6

q

,

w

.. .

_.

<

JB

q

~6'.51 Disassembly of-Refuel Water Tank Discharge

_ . .

~ ~ ,

Check Valve,-2B5-1B. . . . . . . . . . . . . . . . . . . .

14

'

-

.g

1

1 :6~.62 Liner. Assembly 0-Ring Seal Failure On The #1

y

,

4'

LEmergency Diesel Generator (EDG), 2K4A . . . . . . . . . .

14

,

.

. -

5

'

,

' 6;7 : Replacement.of Dowel Pins in Auxiliary Cooling Water

i

.

-

Isolation' Valve 2CV-1425-1.

15

i

.

.. . . . ... . . . .

L

.6~ 8 : Additional Maintenance Activities

16

m

.

. . . . . .. . . .

,

4

9

r

1

!

2

<

2 /.

2

~ *

,

-fl ' ;n .

, . , .

-

Mfis .

._' _. ,

_,

-

m

a.

.

.. , _ . _

.

>

.

ippys _ m ' n

.

.,

-

1

. _

m

.

,

e < .; a . m .n w:

- ..

n;.

,

.

. y,

y,

"-

n n-

. s

.

,

'

r

1 w

>

'q

g

'{ h;.

'

3

.

a

. ,. c.

, . ,

-.

,

.Q 6 7

I4/

5 ('

t +

(

j

N

3-

ll

ppvgg

-

,

-vy

3

,

es

m

su

a,

<

,

.

g,

.3

,

Q-t

.

-:

, m ; y ,,'

w

,,

.t.

-

n

,

<

.

,

s,

e-

n.

-

I

W

t

r,

i

"; 1-

Ql

<y!

p'

't

-)

.

5

.

s

,

k+ -

. . . . ,

, ; -O ;'

m

'r

r

T

K' d

'

i

r

' .

L

-

,

-

.,n

y,..s~,

_

.

Page

,

p..,..h'^

'

&

v

i

a

..%

'

$

' .* . 1[.7.0btInit;2-Outage' Activities....'v.;..,7.m

D-

5.

,. .

. .

. . ..

. fO'

b-

. . c. .. . < -

'.,.t.

18c

.

..

ng

-;

.

T

r-

s

~ +.

n

.....1. ia.c. i. . . . .

.x.

.

18{

!

",

,

7 71h 0'verview. : . . m.-

i . . / .. .

. e

-

l.

3-

,

,. .

-

'

N r .. . , ,

>

'

.

s

m

07:2 Sleeping, Quality Control Inspector ~ ..-... . 3:.

.

J. .~ -18!

!

p; ~f '

.

3

r

.

.=

,

.

'

N

. : 7l.3c ' Reduced: Reactor Coolant System?lnventoryf0peration. .: . ,

19'

i

.

s

a

,

-7,F, FueliAssembly ' Inspection 'and- Reconstitution . . . . , .- .

19-

.

2

"

b, .- -

'm.

4

?: -

'

7 3 xFail'ure of4 Intake: Structure-Sluice Gates to Open. . . . .

'20

y

e

wg#

-

.

f a,6

(7!69: Plant' Design-Change:; 89-8005;. . . . . ... , .-.=, . . . .-

20-

a

,

.

j

--

- -

,

., , .

21:

x

,7.71 Failure ofsRefueling Machine Hoist' Assembly ...:.~... .

_

.

.s '

. .

.

. .

i7.~8 E Required Number of Operable Logarithmic Nuclear

sInstrumentation Channels-Not Available

-

E-

.

22

,

i?O _ ~%'

,1.7. 9EE.ngirieered: Safety' Features (ESF) Actuation

g

-

. . . .. w

22

~

.

sQ',

7jl0.-Control: Room Emergency Ven'tilation. . .:. ... . . . .,. .

23

w,

s=

17.11?tiquid[Sp111s Due tc Weak. Control -of' Equipment Status . '.

.23-

4'

j e-'

3

.

,

.

17.12SafetyjAwarenessStanddown

c.

...:

.253

.

. . .

. . . . . .

, ,

w

'

.

,

.

.. -

. . . . . .

f<

98.0P Licensee Action on. Low Minimum Flow Conditionssfor Emergency. . l26

,

'

Feedwater:(EFW); Pumps 4

fa

'

9.01 Exit--Interview-.'.n . . . .

27

. . . . . . . . , , . . . . . . . .

i

.

4

-

E

.:

t

d

i

i.' -

u ' f.

~

U,

i: '

.

h.~ g

,

.

f ,.

>

_

I

).

.

,

I

e

^3

.

.i

t

-

> ,

_-

.

k

j1

- .

J'

4

.

7

!

,

i . '

i

, ,' --' o s

.

8

Y.[

-

r

"

-[f

__

- - - _ - . -

__

._ .

,

-.

v-

.

-

v:

,.: c:

-5-

!

+

'

DETAILS

-

1.0 Persons Contacted

.

N. Carns, Director, Nuclear Operations

.

K.=Coates, Unit-1 Maintenance Manager

.s

A. Cox,. Unit 1: Operations' Manager

,

R. Eddington, Unit 2 Outage-Manager

E. Ewing, General Manager Technical Support and Assessment

R.'Fenech, Unit 2 Plant Manager

,

J.;Fisicaro, Manager, Licensing-

L.-Gulick,' Unit.2.0perations Manager-

.

c

-

*L. Humphrey, General Manager, Nuclear Quality

1

J.; Jacks, Nuclear Safety and Licensing Specialist

zc

G : Jones, Engineering _ General Manager '

. .

R. King,- Acting-Plant Licensing Supervisor;

J.'Kowalewski,_ Mechanical Engineer

.

R.1 Lane, Engineering Manager

A.:McGregor, Engineering Superintendent

-

t

J.:Mueller,, Central Support Manager.

-

P.'Rehm. Mechanical Maintenance Engineer

"~

-*Je Vandergrift, Unit _1< Plant Manager

~

'J.;Waxenfelter, Unit 2' Maintenance Manager

K. Wire, Manager, Assessment

3

Present-'attexit interview.-

The inspectors-also contacted;other plant personnel, includ'ing

, operators',: engineers, technicians, and administrative personnel.

'

2.01 Plant Status-(Units:1 and 2)

.

-Unit Ic operated ,at 74 -percent power from October 1,1989,- through

November.10, 1989,- with the exception of a_ power reduction to'60 percent

on 0ctober 30-and 31, 1989, due to the repair of= a low pressure feedwater

~

heater. On November-10,11989, at 10:53 p.m., Unit 1 tripped due to'a

<

.feedwater transient which. was' induced by the deenergization of the "B"

reactor; protective system.

The unit was restarted at 11:23 a.m. on-

November 11,-_1989, and operated at power levels up to 74 percent until

.11:22 p.m.-cn November 14, 1989, when the unit-again tripped due to a

feedwater transient. The unit was made critical at 5:46 p.m. on

November. 15, .1989, _and remained at 5 percent power when the inspection

,

period: ended-

The 74 percent power operation is a TS limit because of

'

.

the "D" reactor coolant: pump being secured due to excessive oil leakage.

Unit 2 remained shut down during.the inspection period for the seventh

refueling outage.

-

ey

V. ; 4 ' --,"

, j h.

-

,

rm

-

W, .

,

'

g.

.

t

+

,

.,

$(

~

'

<

J

,

I

Y,

.s.

'

,-

! .. .

T

'

fz)

li[

I

b;/

3.0' Followup of Events-(Units: 1 and 2) (93702)

D

.

..

.

3.1' . Review of Retest' Requirements

-l

,

u.

While reviewing valves on the .100' cycle-limit- use list, the

jj;

_

' inspector. questioned the retest adequacy on High Pressure

s

,

Injection Valve CV-1227 following-its failure to.open during a

,. 1

,.

y,

. surveillance test, AtLthe time ~of.the event,'the licensee

V

determined that the cause.of the failure was poor stem lubrication.

Corrective active-involved cleaning the valve stem and increasing

H"

the frequency of the stem lubrication.

Since the failure in April

1989, the valve.has passed all<of the subsequent surveillances.

'The' inspector's concern involved the retest of the' valve and if.the-

-

surveillance that was performed adequately proved valve

f

'

' operability. The-licensee-had reperformed the monthly surveillance-

~

lafteristem lubrication, and thesvalve operated properly.

However,

>

' this- test 'does .not. ver.ify~ operability. during , flow conditions which

-

would require the valv'e4 to operate against a-differential

"-

pressure (DP). The. licensee'does have surveillances that operate

.

ithe valve under DP conditions,;but theypare only scheduled during

'

plant shutdowns.

.

After the inspector recently raised-these concerns, the licensee

Jreviewed the event and-determined a different failure mechanism.

The .licenseeLnow believes a dirty electrical contact caused the

-

. valve not to open in April 1989, and subsequent manual.and remote

operation of?the valve removed the~ dirt or debris. The' licensee

also maintains.that the large number of successful < operations of .

'the valve after the failure pr. ovide adequate assurance of reliable-

'

H

opera ti on.-

This event indicates a weakness in the retest program

and isaan example of questionable corrective-action by the licensee

,

.in determining failure causes and providing adequate. resolutions,

m

-The: licensee has stated that "MOVATS" testing and surveillance

-

testing with DP conditions will be! performed during the midcycle

outage; starting in November 1989. Additional review of these tests

.

P

will be performed.

In addition, while testing the EFW system in February 1989, the

licensee discovered that flush Valve 2CV-0714 would not fully close-

when the EFW pump was running.

During routine monthly pump

surveillance, the flush valve is only operated when the EFW pump is

idle, however, this test involved operating the valve against a DP.

'

While the flush valve is normally closed, the valve, if open during

an EFW actuation, would receive an automatic closure signal to

ensure sufficient EFW flow to the steam generator.

Due to isolation

constraints, the licensee implemented interim guidelines for valve

operation until repairs were completed during this refueling outage.

'

,

,.L..

i

,. ,

y

. ~

R

y

.

k ,,

.< l .

~

W

-7-?

1

a,,

,

b

. , ,

,

. .

.

g

During review of,this' issue,'the' inspector questi_oned the licensee-

l

~

p

about retest of'the valve:following-repairs. The= initial scope of-

4 .

the valve retest included only,the. normal surveillance, which

-

'

O

--operates the valve'under no flow conditions.

The= inspector

,

'

_ expressed'a concern that this: test would not simulate worst case

1

p

conditionsnin.which the valve previously failed-to operate. The-

p'

flicensee subsequently reviewed the retest issue:and incorporated

,

. instructions in-the_ test procedureffor testing 2CV-0714'during flow-

s

.

h

conditions. -During.the retest the valve satisfactorily stroked

1

t

h

on thelfirst attempt;_however,-the valve would not reclose during the~

Q

next-two attempts.- Currently _the licensee has not initiated any.

addition'al action -to- resolve this issue but interim. guidelines -for.

y~ ~

-valve operation have b'een reestablished. The inspector will

'

E

menitor the licensee sLfinal resolution and testing'of Valve 2CV-0714,

-

,

The: initial retestLeffort-for Valve 2CV-0714 and the corrective

'

. action for . Valve CV-1227. highlight a weakness and lack of thoroughness

,

in the licensee's' program' to: establish appropriate retest criteria.

<

'

Management-attention is:needed to' review the retest program and

. ;

provide the :necessary: guidance to strengthen the program,

t

.

r

The adequacy of the retest. program is an Ur. resolved

i

1

'

Item (UNR)_ 313;368/8940-04 pending further evaluatation by ;he

inspector.

.

3.2'. Unit 1 Trips

3

On'_ two oc'casions, November 10 and 15,1989, Unit 3 underwent

-

feedwater transients'that resulted in reactor-trips on high' reactor

coolant system pressure.

In'both cases, the transients were the

result'of personnel error. The details of these trips are discussed

,'

-

below:

,

-3.2.1

November 10, 1989, Trip _

_;

i

On November--10, 1989, at 10:53 p.m., Unit 1, tripped from

~

.74 percent power =when an instrumentation and control (I&C)

~

technician caused the power supply to the "B" reactor

protective system (RPS) .to trip. _The technician was

verifying. power supply outage -voltage when he inadvertently

shorted the power supply output to ground.

Loss of the'

.

"B" RPS power supply deenergized the reactor power

auctioneering circuit of.the integrated control system (ICS).

With the reactor power auctioning circuit deenergized,

_

.

the reactor power signal to the ICS failed to zero and

the ICS response to the loss of reactor power signal was

-

to reduce-feedwater flow to the steam generators and

-

start pulling control rods to increase power. The

'

reduced feedwater flow caused a decrease in heat transfer

capability, a rise in reactor coolant system (RCS)

temperature and pressure, and a reactor trip on high RCS

pressure. The control room staff quickly recognized the

4-

>

--. . ,

yym ,

-

,

a

-

mc

W

gj f s ,

-

l

+

'

<

,

?

,*

-8-

-L,

.,

.

t

'

!

<

<_ ;

d,

'

r

,

N

'

Jcause of the transient and promptly took nianual' control

lof.feedpumps,l pressurizer. spray, and RCS letdown flow.

,

~

thowever., the' relativelysshort duration of.the transient,-

.g

a

'29 seconds,'made thisLeffort to' terminate;the transient-

q

unsuccessful: f All plant equipment responded as expected' -

g

to-the trip a'nd the unit was stabilized in hot shutdown.

-

9

3 2.2

November 15, 1989. Trip

,

p' ' -

-

,

While cycling:the turbine driven EFW pump suction valve'.

o

'j

'(CV 2802). from the' condensate : storage tank (CST) to

a'

. support MOVATS testing, a, licensed control room reactor

'

operator mistakenly closed the

"A" steam generator

feedwater block' valve (CV-2680). The uni _t response to-

'

thisLaction was identical to that which resulted from the'

trip on November 10, 1989, despite the difference-in

initiators. As'the feedwater block valve went closed,

e

feedwater flow to the "A" steam generator began to

Ldecrease, which reduced heat removal capability causing

4

,

RCS temperature and pressure to rise and eventually reach:

,

the high pressure' trip point.

'

As was:the case on November 10, 1989,- following the unit

~

_

'

trip the unit operations staf_f took timely action to

,

-

mitigate the transient and the unit'was stabilized in hot

q

e;

shutdown.

m -

.l

0

Licensee management has reviewed,both unit trips and has

i

concluded that a lack of attention to detail by both the I&C-

.j

t

,

' technician and the co.ntrol room operator was the root cause

i

' '

of;these events.

In. response to this issue, seniorf plant

j

management-conducted a meeting with key members of the

j

Unit 1 operations staff to ensure that management

1

g;

w

expectations in the area of control of work, attention to

detail,:and personnel conduct were understood prior to

approving unit restart after the_ November 15, 1989, trip.

A

'

3.3 Water Leak Into the Instrument Air System

On 0ctober 16, 1989, operations personnel observed a large

' decrease:in the nonnuclear intermediate cooling water (ICW)

!

expansion tank water level.

Investigation revealed'an ICW

j

-leak into the instrument air system at Instrument Air

l

Compressor C2C. Based on the level decrease in the ICW surge,

)

o -

approximately 610 gallons of water leaked out of the ICW

t

system.

The licensee believed the majority of the water

j

,,

leaked out of C2C and onto the floor,

s

-e

,

d

b

)

.

l

gx

3

g

+

.

V

{-

.g.

t

b

Water was drained out of the air receiver and. filter

downstream of the compressor. A small amount.of water was

also drained out of the filter assembly for the main generator

,

hydrogen gas dryer which is located near 2C2. Operations also

,

sampled for water at three separate points in the instrument-

l

air system which.are located downstream of the tie-in point

'

i

for'C20. No additional water was found at these. locations.

,

Procedure 1304.141, " Instrument Air System Moisture Test,"

gW

which checks for water and' measures the dew point at four

locations in the instrument air system, was also performed.

!

Results from this test confirmed that no water was carried

b

.over into~ the main portion of the instrument air system.

S

Licensee actions for this problem appeared prompt and appropriate

!

'

E

in this instance.

p

4,0 l Operational Safety Verification (Units 1 and 2) (71707)

i

The inspectors routinely toured the facility during normal and backshift-

,

hours to access general plant and equipment conditions, housekeeping,

{

and adherence to fire protection, security, and radiological control

1

measures. Ongoing work activities were monitored to ver.ify that they

were being conducted in accordance with approved administrativ;e and

technical. procedures and that proper communications with the control

room staff had been established. The inspector observed valve,

-instrument, and electrical equipment lineups.in the field to ensure that

they were consistent with system operability, requirements and operating

l

procedures.

'

i

<

During tours of.the control room, the inspectors verified proper

j

staffing, access control, and operator. attentiveness. Adherance to

procedures and limiting conditions.for operations were evaluated.

The

1

inspectors examined equipment lineup and operability, instrument traces,

and. status of control room annunciators.

Various control-room logs and

j

other available licensee documentation were reviewed.

1

,

The inspector observed and reviewed outage, maintenance, and problem

investigation activities to verify compliance with regulations,

procedures, codes, and standards.

Involvement of quality assurance ana

i

quality control, safety tag use, personnel qualifications, fire protection

precautions, retest requirements, and reportability were assessed.

The inspector observed tests to verify performance in accordance with

approved procedures and LCOs, collection and validation of test results,

removal and restoration of equipment, and deficiency review and

- resol ution.

Radiological controls were observed on a routine basis during the

reporting period.

Standard industry radiological work practices,

conformance to radiological control procedures, and 10 CFR Part 20

requirements were observed.

M

' j. ' j ;

,

'

,-

.

F

M

'

q;k 4

j

c

(

,

.L

'3;. / ,

.

~

-10--

!

?-

.

-

,

.

Checks were made to determine whether security conditions met regulatory

frequirements,-_the physica'1' security plan, and approved procedures.

~

Those checks included security staffing, protected and-vital area

'

,

F

~

barriers,' personnel identification, access control, badging, and;

if

compensatory measures when required.

$

v

h

During a tour of the Unit '2 control: room,'the inspector:noted that the

k

power supply;for Motor Control Centers B-55 and 56 was selected to Load

4

'Centar B-5-in lieu of-B-6, as required by-Operating Procedures 1104.29

i

ai

and"1015.15B. The' operators stated that the' electrical lineup was-

deviated--from due to the need to clean-a service water pump strainer and

!

an; additional requirement in 1015.15Brwhich. specifies that B-55/56 be

E

powered from B-5 during the current lineup of the emergency control room

y t

ventilation" system.. The decision to deviate from the procedures was

E

lmadelby the shift supervisor without consultation of mauqement.

No

' temporary changes to the procedures were.made toLresolve the conflict.

The licensee . issued a condition Lreport to evaluate necessary orrective

EL

. , .

actions for: required actions _when conflicting procedure. requirements

,,

U

. exi st... The' inspector will continue to monitor . licensee actions in this

Larea during future' inspections.

No' violations or deviations were idehtified.

-

5.0.LMonthly/Surveillanca Observation (Units l'and 2) -(61726)

,

.

,

~

_The' inspector observed the TS required surveillance' testing.on the

m ,

,

lvarious components. listed be~ low and verified that testing was performed

f

'

-in accordance with adequate procedures,. test instrumentation was

~

_

calibrated,' limiting conditions for operation were-met, removal and

restoration'of the affected components were accomplished, test results

conformed with TS and procedure requirements, test results were reviewed

'

3r

.by' personnel other than the individual directing the test, and any

'

ideficiencies identified dur_ing the testing were properly reviewed and

,

resolved-by appropriate management' personnel.

The NRC' inspector witnessed portions of the following test activities:

-

'

-

Performance-test of 125 V Battery Bank 2D12 (Procedure 2403.025,

-Job Order 797746)

M

.Bi weekly power range linear amplifier calibration during power

'

operations (procedure 1304.032, Job Order 797746)

.,

,

'

Service _ discharge test of 125 Volt Battery Bank 2011

(Procedures 2403.027, 78 and 157)

is

[

Emergency Diesel Generator (EDG) 2K4A 18-month operational test

-

'(Procedure 2104.36, Supplement 3).

The inspector observed the

2850KW load rejection test and the autostart on simulated loss of

offsite power test.

EDG 2K4A instrument calibration

%

_

,

9:a p

-

t

&

s

<

'

.

<

t/ .

4

s

,

Jk

s

'

e .

.

l

,

f

[

'

13_.

s

.

1

.

w

', '

e

.

'

i

E

i

$

'On October 9,1989,Lthe licenseeridentified that a previouslyl scheduled

i

b

calibration of'the Unit:lipower range _ amplifiers had not been performed;

V

pas scheduled. TS 4.1-1' requires calibration of'the power. range amplifiers

,

L

twice:per week.

To accomplish this, the licensee normally'does this-

F ,

calibrationi every Monday and Friday. However, on October 6, 1989, the

F

calibration was not performed. .The licensee did not realize'this until

,

V?

October 9, 1989, when.the Monday calibration was performed.

This event is

'addi_tional example.of the surveillance program weaknesses resulting in .

'

[

'not performing a~ scheduled surveillance.

The' licensee recently informed

'

r

the inspector that the issue of missed surveillances and the entire.

<

,

-

surveillance program is under: management review.

The staff is concerned

with the large number of recently rissed surveillances and the continuing-

!

M

examples of -missed surveillanceL required to verify system operability.

'

s

Additional! review.of this area will be performed during future inspections.

'

4

L

L

K6.

' Monthly Maintenance-Observation (Units 1 and 2) (62703)

i.

Station maintenance activities for the safety-related systems and

4

components listed below were observed to ascertain that they were

-

~

conducted in accordance with approved procedures, regulatory guides,_and

-

i .

industry codesi or standards, and in conformance with the TS.

.

,

The following items were considered during this review:

the limiting

&_ ~

l removed:from service, approvals were obtained prior to initiating the

.conditioris for operation were met while components or. systems were

work,: activities were accomplished using approved procedures and

Linspected as applicable, functional' testing and/or calibrations were

performed prior-to returning. components or systems _to service, quality

. control recoras were. maintained, activities were accomplished by

.

(qualified _ personnel, parts and materials used were properly certified,

'

radiological cont'rols were-implemented, and fire prevention controls

'

Lwere implemented.

,

Work requests were reviewed to determine the status of outstanding jobs

I'

and to ensure that priority.is assigned to safety-related equipment

maintenance which may affect system performance.

The following maintenance activities were observed or reviewed:

,

6.1" Disassembly and repair of HPSI pump discharae stop/ check Valve 251-108

-

(Procedure 2402.139, Job Order 792323).

'

The' valve was disassembled to determine the cause of e previous

failure in which the valve failed to reseat and allowed reverse

~

flow. : Visual inspection revealed deep scratches and gouges in the

s

valve bore and on the mating surf aces of the disc and disc skirt.

The licensee concluded the failure of the valve to reseat was

caused by' galling of the disc skirt in the valve body bore.

The

root cause was a design error resulting in the horizontal positioning

of the valve resulting in gravitational force causing the disc

-skirt. to constantly rub / wear on the valve body bore.

s

f

Ws

k

.,

pwyf: Nf:

,

r

.,

p.._

5

.

l-l'

t

P6.?

.

a

3

['

.

-32-

%

,

' '

[5

,

k

}

$

J

Valve repair' included honing and lapping the valve body bore to

9

= remove the majority of the scratches and gouges, lapping the valve

,

L

seat'and replacing the valve internals. Measurements of the valve

+

body bore revealed several locations where the bore inside-diameter

- t

t,

y

was greater than the! manufacturer's tolerance.

The valve-

'

-

r

. manuf acturer, Anchor-Darling, concurred with the licensee. that 'the

J. '

valve would remain operable for 18 months if the above repairs were

,

p,

1 performed.-

H

.

"

Subsequent disassembly and inspection of Valve 251-10C revealed

'

similar but' shallower scratches and gouges,-while 2SI-10A only had

light scratches in the valve body.

Similar_ repairs were completed

for Valves 2SI-10A and C.

With the above repair of the three_HPSI

'

stop/ check valves, the licensee has completed the proposed

.-P

'"short-term" corrective action.

The licensee has indicated the

'

_

-intent to continue the "long-term" corrective action investig uion

"

and perform the required modification.

This action is necessitated-

4

by the limiting 18-month operability determination for 2SI-10B and-

4

!y

by the horizontal position of 2SI-10B and C which was directly

~"

linked to the previous valve failure. This action will be' tracked

as. an inspector followup . item (IFI) 368/8940-05.

,

- 6.2_ Inspection, maintenance, and cleanina_ of Unit 2 SW intake structure-

-

sluice gates.

!

using' temporary stop logs the -lake. side of the SW intake structure

,

Twas isolated to allow measurement'of_ sluice gate out leakage.

Earlier, the licensee had discovered that leakage past the sluice

,

-gates, in a configuration where the emergency cooling pond would be

,

71n use, had not been specifically measured. This leak test included

'

.

. validation of previous assumptions and comparison with results from

n

ni

the previously performed test .

'

W

' Leakage from "B" and "C" sluice gates was less than 1 gpm while

.

"A" sluice gate leakage was approximately 3 gpm.

Therefore,

<

m

total leakage was significantly less than the maximum allowable

.

"

leakage of 45 gpm for all three sluice-gates.

Repair of "A" sluice

gate reduced leakage to less than 1 gpm.

,

6.3 Troubleshooting of EFW pump discharge Valve 2CV-1037-failure to close

-(Job Order 798953).

During response time testing, 2CV-1037 opened remotely from the

control room but would not reclose. A similar failure of the valve

'

to-reclose had occurred several days earlier.

Corrective action

'

-

for the earlier failure involved manu-ally exercising an auxiliary

"

set of contacts in the valve breaker cubicle that were found stuck,

then remotely operating the valve several times.

During investigation

of the second failure, the licensee identified an auxiliary set of

contacts that were stuck. While some confusion existed about

different contact numbers for the two repair efforts, it appears

,

fPN

.

j

,

k

_

,

4

c

f

,

-13-

-

>

y.

,

i'

' t

h

-

that the same set of contacts were Stuck in each failure. The

'

f

inspector noted that the contacts, when cycled several times, would

"

randomly-stick in the open position.

The licensee has replaced the

'

y

module which includes the faulty set ~ of contacts. The inspector

>;

! considers the licensee actions taken during the previous-

L

< troubleshooting / repair. effort to be inappropriate.

Electrical repair =

and troubleshooting activities will be monitored durit,g future

i

e

E

.

inspections to determine'if.this example is. representative of a

' >

. broader program weakness.

,

6.4 Use~of Universal Joints During Torquing Evaluations

Duri_ng the 18-month maintenance on EDG 2K48, the inspector. observed

the use of a:" universal" joint while torquing the fuel injector

<

collar plate fasteners.

The mechanic stated that difficult access

to the fasteners re' quired the use of the universal joint. When

questioned by'the inspector concerning the correction of the

-

,

applied ~ torque, the mechanic stated that no adjustments had been'

,

applied to the torque wrench reading'

The inspector determined

.

,

that without.the use.of a-correction factor when. using a universal

joint, the licensee was unable to' verify that,the collar fasteners

,

were torqued-to the required value of 37 ft.lbs.

~

Procedure 1025.020,." Bolting and Torquing Guideline," pr_ ovide

requirements for the selectior. and use of torquing devices.

Specifically, paragraph 8.4,2.A.3 allows.the use of universal

joints butI requires the correction 'of the indicated torque per

,

-

' Attachment.4. ' Failure to apply correction factors to the indicated

-

torque when using a universal joint is"an apparent violation-

-(368/8940-01).

'

-

While evaluating the use of the universal joint, the licensee

questioned-the EDG vendor on the affects of potentially

'overtorquing the' fuel injector collar fasteners. 'During the

'

>

<

conversation,-'the vendor stated that the correct torque for the

collar' fasteners'is 20-25 ft.lbs in lieu of the torque value of

.37 ft.lbs. which was given in Step 8.3.10 of Procedure 2306.05,

"18-Month Surveillance on Unit 2 EDG 2K-4."

The vendor also stated

,

that the potential consequences of the overtorquing could cause

damage to the fuel-injector nozzle gaskets and the collar plates.

Subsequent inspections of the overtorqued collar plates revealed

obvious warping of the plates.

Subsequently, both the collar

plates and nozzle gaskets were replaced for all fuel injectors on

both diesel generators.

.

Technical Manual (TM) F010.0120 for EDG 2K-4B provides the correct

torque value for the collar f asteners in the " Torque Limits" table,

however, the incorrect torque valve is given in the text of the TM.

In addition, a service information letter from the vendor in July

1986 discussed the potential damage associated with the higher

torque value and the need to use the 20-25 ft.lbs. torque value.

.

._

i

y p: , ,' '

' +

--

->

tg

"

'

.w;

-

y

'*=

r

8

+

"'

TThe111censee. stated that confusion concerning.the app 1'icable diesel

model number in'the service-information letter may have 'affected

'

-implementation of the letter into the TM.

It should be noted that

.,

,

a,

the-inconsistencies in the 1M and the information service letter

. existed. at. the time ~ of the TM impro'vement program, however, the -

error in the EDG TM was not identified.

.

Failure to maintain consistent torque valves in the TM and

1 appropriate; plant procedure instructions is an apparent violation

-(313;368/8940-03).

s

Inspector' review noted that NRC Inspection Report 50-313/88-25;.

50-368/88-25 also issued a Notice of Violation (368/8825-01) for

'the failure't'o adjust the indicated torque when using an adapter

-

'with aLtorque wrench. The inspector noted that the inspection

y

report documented that, at test time, Attachment 4 to

LProcedure~1025.020 did not provide sufficient instructions for

. adjusting the indicated. torque when using a-universal joint.- The

0

licensee had not corrected Attachment 4 even though the procedure

-had been: revised.- This is another example of the violation (313;

-

368/8940-03) for failure to maintain appropriate procedures.

.

6.5 Disassembly of refuel water tank discharge check valve, 2BS-1B-

>DuringdisassemblyofRefueIWaterTankDischarge-CheckValve2BS-1B,

~]

the licensee discovered.that portions 'f the; instructions in

~

o

'

' Procedure 2402.096, "2BS-1A/B Disassembly,LInspectionfand Reassembly,"

were not, applicable tosthervalve., Further review revealed that

' Instruction Manual A585.0010, which was:used to'deriveJinformation

for Procedure 2402.096, is not;. applicable ~to'this valve =(2BS-1A/B).

l

~

The instruction manual contains only generic inforination for

j

-2BS-1A/B.

The most significant error 4 in the procedure'was the

~

'

torque-value for.the bearing cover stud nutsLwhich<was given as

160'ft.lbs. but is required to be only'38 ft.lbs. -A review of

-

previous work on 2BS-1A/B conducted per Procedure 2402.096 revealed

that only one case of overtorquing'2B5-1B fasteners occurred in

March 1988.

Subsequent corrective action for the overtorquing-

issue involved disassembly and inspection of the' bearing covers and

fasteners for the 285-1B valve.

The failure to maintain correct component information 1'n an

instruction manual and appropriate plant procedure instructions is an

i

y

additional example of an apparent violation (313:368/8940-03).

.{

!

6.6 - Liner Assembly 0-Ring Seal Failure on the No.1 EDG

i

!

While. conducting pressure testing on the No. 1 EDG jacket cooling

!

water system to 37 psig, a vendor representative from

1

Fairbanks-Morse (FMED) questioned the adequacy of the hydrostatic

pressure specified by the test.

A review of the vendor manual

revealed a test pressure requirement of 50 psig, while the ANO

procedure required a test pressure of 30-50 psig.

<

il

u m

-

3' 7

_

.m

a

'

+

yg

'

,

'

1 ,'

~

4

WJ

,

s

V

'

3;

8

,s

'

(G

Q,

l,

,

a

'

<

1

,

.

y,

m4

, , '

F-15-

'

s

3

,

f( '

A:.

j

~

<

fs

y

-

O^

JThe discrepancy between the approved' procedure'and the vendor's-

-

J

! manual is a an additional example of the licensee's failure to'

.

maintainlappropriate procedures (313;368/8940-03).

ly

,

-

k

W

.In response to the vendor's_ concern and. performance data which

,

indicated possible jacket water seal degradation,= the licensee

.

,(

reperformed the jacket' water pressure test at 47:psig. The vendor

., ,

%

representativeL based his! seal degradation concern primarily on-the

['

. age and material of-the cylinder liner 0-rings, 16 year-old Buna-N-

f

"

. material',_ and the 6_ psig pressure oscillations in Jacket water .

'

-

pressure:during engine' runs. The pressure oscillations are indicative

<

b

of cylinder liner seal leakage, while the vendor considers normal-

N

service life of 'Buna-N: seals-to be 10 years.: While no seal leakage

E

occurred during the. pressure test at the'iower pressure, coolant

i

~

-leakage'ct'the No. Il cylinder liner exhaust opening did occur at

'

the 47 'psigl test pressure. , Based on_ the. pressure test results and

-

s

,

the life' expectancy'of-the seals, the licensee chose to replace all

'

b

12 cylinder liners with new liners that have Viton seals.

The new

liners arejof an' improved design that incorporate double Viton

.

r

0-rings with a service life expectancy of 15 years. The replacement

work'and required testing were completed satisfactorily.

I

s

e

Therprocedural discrepancy which led to the testing of the No. 1

,

.

EDG,also called into question the adequacy of the pressure test on

,

.

sthe No.02 EDG-(2K48).

The = licensee has' determined, and the tendor -

concurs, that the-36 psig pressure test on the No. 2 EDG was

'

adequate'. ;The_ factors which led the licensee to. reach-this conclusion

=are listed below:

,

0:'

"

Normal operating pressure on-the No. 2 EDG is 29-30 psig,

'_

-therefore, 36 psig'is approximately 125 percent of normal

'

{m.

pressure. Normal operating-pressure on'the No. 1 EDG is

36-37 psig, therefore, a test pressure of. 50 psig' is

l ",

approximately 135 percent of-normal-pressure. . Based on-the

l

above' figures,-the 1icensee feels that the test on the

>

n

s

No. 2 EDG is representative and meets the intent of the' vendor

>

'

-manual-

,

.

.The No. 2 EDG showed no jacket pressure oscillations more than

3 psig during its 24-hour' surveillance run indicating that

'

seal condition is good.

-

No. 2 EDG was built in 1979 and was supplied with Viton

0-rings vs. Buna-N 0-rings

c

The licensee has revised its diesel maintenance procedure and will

h

conduct all future pressure tests at the vendor recommended test

pressure of 50 psig.

-The NRC staff has reviewed this issue and no concerns with the

-licensee's conclusion on the No. 2 EDG testing were identified.

.

1-^

d

e

v

P'

J

~

'

.-

,

- - , .

_,

,

-

,

,-

-

yn

_

. .

.

,

.

s

-

4

, *

1

i

4,

~

'

'

,

.

es

,

~

u

m

,

-16-

es

,

p

>

,

'

p

.

^

6.7 Replacement-of-dowel pins in Auxiliary Cooling Water Supply

-1 solation Valve 2CV-1425-1; -~While investigating the cause of the-

v'alve;failing-to close, the licensee discovered that one-ofithe-

r

y

dowel ~ pins which maintain' vertical' alignment of the disc was

7'

.

missing and the other pin had " backed out" of the mating hole.

-

p

"/

, Inspection of 2CV-1419-1, a' service; water cross-connect valve also-

e

~ revealed a missing dowel pin, After further review and

c .

inspections, the licensee determined that1the cause of the dowel-

pinLfailures was previous maintenance on the_ valve which drilled

,out the old carbon steel pins ~and-replaced them with-stainless

,

y

O'

steel pins. The licensee believes.that the' drilling out of-the old

pw

~ pins ~ enlarged the-holes and resulted in:an improper fit of the new

'

G

pins;in the. mating hole,'after the failure of 2CV-1425-1,

2CV-1419-1Lnew dowel pins were installed in these valves and the

other six valves with same_ design and maintenance history.

The new.

e

dowel-pins are .tappered and grooved to provide the proper fit in-

<

,

'

the~ mating-holes.

-

,

f

6.8 . Additional Maintenance Activities

r.

Repair of Main Steam Safety Relief Valve 2PSV-'1004

C

(Procedure 2402.049,' Job Order 796840).

Postinstallation testing of local annunciators for "B"

EDG

'

. hich was modified by. Design Change Package (DCP) 86-2113

l

R

w

'

l-

,

. . .

p .

Preventive. maintenance (PM).to clean,-inspect, and megger 4160

-

C'

Volt Bus.2A-4 and calibration of meters-located in the bus

cubicles (Procedure 1412.055). . The inspector observed

increased safety precautions that were implemented during the

bus PM. The increased safety precautions were a result of ~a

recent electrical accident that occurred during PM of a 6900

'

volt bus (see Paragraph 7.12).

.

'

Postmaintenance run of EDG 2K4A (Procedure 2306.005). After

the 18-month maintenance, the. licensee experienced difficulty

in starting the diesel.due to incomplete filling of the fuel

line, then leaks were discovered on two air start valves.

Following these repairs, the diesel satisfactorily ccmpleted-

,

the postmaintenance run and the 18-month operation test.

Portions of Procedure 2403.007, " Emergency Diesel Generator

18-month Month Maintenance." The inspector noted that the

~

journeyman mechanic in charge of this evolution was very

,

knowledgeable of all ongoing activities. The individual

'

, .

displayed a strong sense of ownership and responsibility

toward ensuring that the maintenance was properly completed.

3-

As-left "MOVATS" test of the motor. operator for Service Water

'

Cross-Connect Valve 2CV-1421-1 (Procedure 1403.38, Job Order

754146).

This testing was performed after modification of the

i'

t

r

t.

4

. - .

f;r

"

l

-

<

8

,

'

y&

p

pj

zp

,

g,7

,,

i'.

fst

-17-h

,,, i

p,y

_

l

h.

S'"

l operator ~per Design Change Package (DCP) 88-2066 which changed

~

.i

internal gearing and the spring pack.' The operator was?

.

. modified to provide the required torque to stroke the valve

-

.F

g

'during all design basis conditions;

p

Cleaning ~of the service water suction line from the emergency

'

Q

cooling pond to the service water pump > intake structure

(Special Work Plan 2409.223). During the. service water system ~

'

,

e

flow test, degraded flow capacities were: identified for both~

O

the return and suction lines for the emergency-cooling pond.--

'

'The reduced flow was attributed to silt buildup in the pipe'

-

'

and corrosion of.the. pipe.

Both pipes were mechanically

g

l

cleaned.

Subsequent flow test resulted in acceptable flow-

h.

rates. 'The ' licensee -is using _ the data f rom the flow tests

'

and the pipe cleaning as a factor in the service = water integrity

'

program.

Cable termination at the reactor building penetration'for the

'

-reactor coolant pump vibration monitoring-system (DCP 85-2111,

' Job Order 780376)

,,

3-

'~

PM of 4160 Volt Breaker 2A-301:(Procedure 1412.G08,' Job Order

780376)~

"

=

-As-left MOVATs testing of containment spray-sodium hydroxide

,

-addition tank discharge Valve 2CV-5657. (Procedure 1403.14c Job-

Order 787197).

Previous failures of the valve to open during

t

monthly- surveillance identified.the- need for a' torque switch

bypass during valve opening ~.

Plant. Change 89-8008 installed

o

the torque switch bypass'in the valve Rotork operator for the

first 25' percent off valve movement in the opening direction.

The M0 VATS testing-was performed to verify proper setting-

after completion of the plant change'.

-

Inspection of EFW minimum recirculation Orifice 2F0-0717A.

.

The orifice was verified to be oriented correctly and only a

{

small amount of erosion was noted on one side of the orifice.~

"

The licensee determined that the orifice was acceptable for

(

reinstallation, but stated that the existing orifice is

scheduled for replacement.

See Section 8.0 of this report for

additional details,on this-issue.

-

i

e

"-

Troubleshooting the failure of EFW pump service water suction

l

' supply Valve CV-2806 to remotely close (Job Order 7.97399).

The licensee identified a-loose connection on the torque

switch whichrprevented th~e electrical operator from closing

'

the valve. After tightening the connection, the valve was

,

remotely operated in the open and closed direction several

times.

The licensee was unable to determine' the cause of the

loose connection.

-

~n

- * , ,-

---g

-.

p:: m,y

.

,

.

b ,6

.)

m

_

i

!

<

,

.ry.

-

,

i

'

g

38.-

,

f

.i

.

y

o

,

e;

'Hydrostaticitesting of Loop 2 service water loop after 'the;

a

completion-of outage; maintenance items (Procedure 2409.069)

!

i

'

4

Hydrostatic testing of the mainisteam system to satisfy-

~

.

L

110 year l inservice. inspection (ISI) requirements,

t

4 ,

p

(Procedure 2409.118)

'

j

'

pm

~

1

7~0 Unit-2 Outage Activities

a

.

L

k

7.1 ~0verview

e

,

E

During this inspection period, the licensee successfully completed

the. majority of the work' planned for the-Unit 2 refueling outage,

,

2R7, Major work during_ the outage included:

Replacement of the

y

4

I-

- core protection competers; core offload' and refueling . completion-

1

?

' of the 10 year ISli , eluding-reactor vessel inspection; service

'

water' system piping ed component replacement;' limited cleaning of-

g>

service, water piping;< turbine; overhaul; and diesel _ generator.

~

jp/t

>

'

18-month' maintenance.

The' outage also included three periods of-

~

T

midloop. operation,to allow steam generator tube inspection,

-

"

o

replacement of reactor coolant _ pump seals-(RCP), modification of

.;

RCP seal sensing ~ lines, and numerous reactor coolant tystem valve

'

+

repairs. -Overall, conduct of-the outage has been quite good,

v

Planning',, coordination,-and_ communication between the different

- organizations has been effective.

Licensee management has been-

successful-in anticipating and scheduling immergent work items

throughout the outage. Material management has-generally provided-

the necessary parts and equipmentrin a timely fashion and few parts

. discrepancies have occurred.

-Despite'the overall success _of the outage, there have been some

instances where lack of attention _to detail or failure to exercise

.

' adequate work process control resulted in adverse consequences.

,

.

The . spill of- primary coolant from open steam genterator (SG) manways,

overflowing the steam generators during refill operations,. electrical

shock and flash burns received by a maintenance electrician, and

the failure to maintain operable.the required number of LOG power

monitors are some examples of this problem. Management attention

[

should be' focused on identifying and correcting the root cause(s).

of these events.

.

A

7.2 Quality Control' Inspector-Found Sleeping

f

At approximately 4:30 a.m. on October 22, 1989, a member of the

'

operations staff observed a contract quality control (QC) inspector

M

asleep in the backpanel area of the Unit 2 control room.

The QC

inspector had been. assigned to the control room to provide QC

verification'of electrical drawing walkdowns being conducted by

'

members of the electrical maintenance and plant engineering staffs.

.

The' individual had fallen asleep during a break from his

verification duties and stated that he had not intended on sleeping

n

l

'

's gf -

,

(w

E,

I

'

p

'

<

y

,

-

,

.

'

39

(

,

k',

'

l

when he sat down. The' licensee escorted the-individual:offsite and

R

has terminated his site access.

Subsequent to his removal from the

site, the QC organization _ performed a.100 percent reverification _of

?~

all work performed by the-inspector on the night he:was found to be

[

sl eepi ng .~ Based on the individual's_ excellent'past performance',

.the General Manager,= Quality Assurance has recommended that

'

-

the individual be eligible for rehire;after_a 6-month suspension.

_The inspector reviewed the-licensee's' actions and found them to be

g

appropriate,

y

7.3 Reduced-Reactor Ccolant System Inventory Operation

During:this inspection period, there were three periods when the

-

RCS:was placed in reduced inventory to allow specific maintenance

activities to be performed.

One of these reduced inventory windows

'

'was conducted with the core offloaded-and when vessel water inventory

'

.

control- was.not critical, however, during the other two periods, the

core was loaded.in the reactor? vessel and level control was,

q

therefore,<: critical to ensure reliable decay heat' removal (DHR) system

operation.

'

-The-potential-loss of:DHR while in reduced RCS inventory operation has

been the subject of. concern by the NRC.

Generic Letters (GL) 87-12

and GL.88-17 and NUREG-1269 all address'various aspects of this

>

issue in detail. -In response to the two generic letters, AP&L-

n

committed'to-numerous changes in training, procedures, and equipment

to improve the f acility's performance while 'in reduced -inventory.

4

i

The inspector reviewed Procedure 2103.011, " Draining the Reactor

{

Coolant. System," Procedure 2104.04, " Shutdown Cooling System, and

found them to be satisfactory.

In particular, Procedure 2103.11

q

was found'to address the concerns expressed in the two GLs and the-

procedure was clear, ~ concise, and well laid out. The inspector

j

observed the initial draindown evolution and found that it was well

i

controlled throughout its duration. The licensee staff conducted a

l

thorough preevolution brief which covered procedural guidelines and

restrictions,. equipment requirements, and potential problems. _

l

Discussions with on-shift operations personnel found them to be

a

knowledgeable of plant conditions and procedural requirements. The

i

evolution was conducted in a deliberate, controlled manner'and no

j

'

C

difficulties were encountered.

j

i

The inspector had no further questions.

l

'

7.4 Fuel Assembly Inspection and Reconstitution

'

While the core was removed from the' reactor vessel, an ultrasonic

.'

inspection was performed on the fuel assemblies to identify any

leaking- fuel rods.

Four fuel' assemblies were identified from this

inspection as having suspected degradations in fuel rods.

Fuel

>

%

,

j

t

2W.

r

.

,

cw

w,

,

-

,

,.

e

.

,

.

,

f'

~

s

,

_

_*

~.

.

,

y.

,

f-

.g0. l

'

w _

.

.;

'

reconstitution efforts l involved removing the ' suspected fuel rod

p

from each assembly, performing a detailed eddy current-inspection

.on the removed rods and inserting " dummy" stainless rods in the

!

~

-

~ effected fuel assembly.. The eddy current inspections and visual.

M

inspection identified throughwall defects on two of the four fuel

-

L

rods. ._In addition,_the licensee performed an ultrasonic inspection;

F

.on each control, element-assembly with no defects or irregularities

'

,

'were' identified-by this. inspection. The cause of these defects is

'

h -

being: evaluated by. Combustion Engineering (CE) and the licensee.

'

. -

-

N

s7.5.

Failure of Intake Structure Sluice Gates to Open

b"

During valve. lineups for the Unit'2 SW. system flow test, the lake-

~

side sluice gates for the SW intake structure Bays A and C (Valves

"

1

-.2CV-1470;and 2CV-1474), failed lto open.

Investigation by the

licensee determined that a torque switch bypass for the motor

operator-is needed during initial opening movement to ensure that

-

future failures do'not occur.

Plant Change 89-0047, was developed

to11nstall a. torque switch bypass in the three lakeside sluice

,

,

gates and in the three emergency cooling. pond side sluice. gates.

Accomplishment of-the plant change has been deferred from this

.' refueling outage, with no completion date-currently scheduled..

"

Part of the licensee basis for deferring the work was that the lake-

sluice gates safety actuation function _is from:the open to closed

position.and the recent failure mechanism does not affect this

movement. However, the. pond sluice gates safety actuation function

y

is from the closed to open position. The licensee's current

'

ejustification for delaying installation-of the torque switch bypass

'

ifor the pond- side sluice gates is based on no' previous failures of

-

the' pond sluice gates having been identified and a lack of normal

flow by the pond sluice gates. - The high workload for "MOVATS"

testing during the outage-appeared to influence the licensee's

.

decision to delay the plant change, While no imme'diate safety

concern exists with.the present status of these sluice gates, the

-j

implementation of this design improvement was discussed with

.

licensee management. The Unit 2 plant manager indicated the intent

to proceed with implementation of this design improvement during

the early part of-1989. The inspector will monitor licensee

actions _for this issue as an inspector followup item (IFI)

313;368/8940-05.

7.6 Plant Change 89-8005

-The inspector reviewed Plant Change 89-8005 which installed new

roll ~ pins in safety injection tank discharge check Valves 2SI-158

'

and -D and 2SI-15A, -B, -C, and -D.

The roll pins which maintain

alignment of the disc to the disc shaft were previously found

~

missing from 2SI-15C and one roll pin in 2SI-10A was cracked and

had a loose fit in the mating hole. The metalurgical inspection

results of the cracked roll pin indicated that the failure

mechanism was integranular stress corrosion cracking.

Babcock and

.

e

-

,

t

y

.

Nf<

r ,e

i

g

wm

,

-21-

$

j

'

p'

l

' Wilcox's laboratory, which performed the analysis, recommended -

.

1

that.the 420 series: stainless steel roll pin be replaced with 300

- "

series stainless steel material.

p

'

This plant change removed the old style roll pins and replaced them'

with' grooved solid pins manufactured from 316" stainless steel.

Ins

j

addition,'one end of each pin'was tack welded to the~ disc to ensure

,

!,

.that the' pins'would' remain in place.

Upon completion of.the-

outage, two of the eight valves susceptible to roll-pin failure

will-not'have been modified with the plant change. These two

t

&

valves, 2SI-15A and -C, had new original. style roll pins installed

i

in June 1989. .,The licensee has stated that the modification of.

these valves would be completed prior to, or during, the next

l

refueling outage. On the basis of the failure mechanisms derived

from-inspection results of of the original rollpins, the-

.

'

metallurgical-inspectioniresults of the cracked roll pin, and the

1

recently installed'new roll pins, the licensee has concluded that

the. roll pins,-in 2SI-10A and -C would remain functional during the

next. fuel cycle.

This decision appears appropriate especially

'

since the'only cases of failed roll pins were pins.that had been in

L,

service'for 9 to 10 years.

7.7 Failure of Refueling Machine Fuel Hoist Assembly

While attempting to: remove Fuel Assembly AKG 202 from Core

,

Location L-12> the fuel hoist assembly did-not completely grapple,

n"

s

'

J

.As'a consequence of this failure to' grapple, when an attempt was

made-to lift the fuel assembly, it withdrew from the core

Lapproximately 1,53 inches (maximum calculated value) and then

!!

, dropped off the grapple back to its original position.

The licensee conducted inspection of the fuel hoist assembly based

[i

-on hoist performance and determined that the cause of the failure

to grapple correctly was a failed .1875-inch dowel pin. The dowel

pin.normally maintains correct alignment between the grapple and

actuator assemblies. The grapple extension rod is threaded into

-

the actuator assembly and pinned to maintain alignment. The

actuator assembly, in turn, is connected to the hoist cable.

A gear

>

assembly and drive shaft allow the actuator and grapple to be

rotated remotely, provided that all interlocks are satisfied.

The

!

dowel pin normally transfers the rotational force from the a tuator

.

to the grapple, however., failure of the pin allowed full actuator

rotation with only partial grapple rotation.

Because the grapple

position interlocks are sensed off the actuator drive shaft, all

interlocks for lift were satisfied.

The licensee has replaced the failed pin and retested the fuel

hoi st . assembly satisf actorily. The licensee has also notified

other' facilities with similar refueling machines directly and

through Nuclear Network.

.

q

4

3:

y

,

_

,

{

f(M

,

g

(W*>

-22-

t

.

m

1

Mi

VisualLexamination'of Fuel Assembly AKG202, prior to removal,

[#

' '

showed noLapparent' damage'.

Upon removalmto the spent fuel pool,

i

.the bundle was; inspected by ultrasonic test (UT) and no failed pins.

k'f.

. ere detected.

AKG 202 was not scheduled for reload into fuel

w

. Cycle 8 and no.further testing is planned,

y_

b'

~The~ inspector reviewed the licensee's initial ^and followup response.

,.

F

to this event and found 'them appropriate.

The' inspector had no-

p

further questions.

7.8 Required Number of' Operable Logarithmic Nuclear Instrumentation

Channels

,

^0n October 5, 1989, Unit 2 control room operators discovered thati

q

the number of operable LOG power level instrumentation channels was

less than required.by?TS. TS 3.3.1.1 requiresJthat'at least two of

the four. LOG power level' nuclear instrumentation channels be

,

'

operableMin cold shutdown (Mode 5) for additional reactivity

monitoring for unplanned criticality events. With the reactor. trip

-circuit breakers:(TCBs) open,-over a period of 3 days,.0ctober 2,

3, and 4,-all four channels were sequentially removed from service

to allow.I&C technicians to replace cabling connectors on each

channel.

Although control room personnel conducted periodic

' channel checks of equipment required to be operable by TS, the fact

-that ~ the required number of LOG power' 1evel nuclear instrumental

channels'were~not operable was not detected for approximately 36

hours.

Upon ' discovery of this.. discrepancy, at- 3:35 a.m.

0ctober S o

g

'

1989, licensee' personnel. performed a' shutdown margin calculation

as-required by'TS and returned three. channels to operation by.

7:55 a.m.,:0ctober 5,.1989.

Failure to maintain'the required number of operable' LOG power level

. j

~ instrumentation channels operable is an apparent' violation

,-

,

.(368/8940-02) of TS 3.3.1.1

'While the safety significance of this

-

6

issue is minor because other nuclear instrumentation was available,

L

it-is another example of the failure to adequately control work

activities.

'

7.9- Engineered Safety-Features (ESF) Actuation

'While. performing electrical isolation. activities to support work

,

n

associated with the new core protection calculators, several ESF

j

actuations occurred.

Earlier, "D" channel of the plant protection

'

system-(PPS)'had been deenergized for maintenance.

This condition

placed the-PPS in a one-out-of-three trip logic mode.

When a breaker

on 120 Volt Vital AC Panel 2R52 was opened, the steam generator

i

pressure transmitter associated with PPS Channel "B" was deenergized,

_

resulting in a main steam isolation signal.

The breaker was then

]

'

reclosed, which caused a spike on the containment building pressure

1

transmitter for PPS Channel "B" and resulted in a safety injection,

1

]

containment spray, containment isolation, and containment cooling

l

1a

- -

'E

3

,

, .

,

-

.

,- .

,

i'

Y

23

'

l

' '

' actuation signals.

.

j

3r

.

Starting of EDG 2K4A and the actuation of

several valves were tht only automatic actions of the ESF signals.

.The safety significance of this event was minimal since the core

~

4

was off-loaded from the reactor vessel and the majority of

i

safety-related equipment had been tagged out of service. However.-

'

this event,is another example of inadequate control of work activities

,

by operations personnel when work was allowed to be performed on-

t

two PPS channels simultaneously;

I

7.10 Operability of the Control Room Emergency _ Ventilation System

Units 1 and 2 share a common control room (CR) emergency air

conditioning system which includes Cooler 2VUC-27B and Compressor.

Unit'2VE-1B and comparable "A" train components. While Unit 2 "B"

EDG and Loop 11 of SW were out of service for maintenance, 2VUC-27B

and 2VE-1B were inoperable since Unit 2 supplies normal power and

cooling water. This did not affect Unit 2 since the unit was shut

down, however', Unit 1 TS 3.9.1 requires two independent circuits of

CR emergency air conditioning.- Additionally, TS 3.9.2 and 3.9.4

allows one circuit of CR emergency air conditioning to be inoperable

for 7 ' days, after which the ' Unit I reactor is required to be placed

in a-cold shutdown condition within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The. licensee did nM recognize that 2VUC-27B and 2VE-1B were

inoperable until 6 days after the emergency power supply and

1

cooling water had been taken out service. Actions were then taken

to provide the emergency power supply and cooling' water for

M

2VUC-27B and 2VE-1B from Unit 1.

However, these actions were not

'

completed until approximately 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the 7-day allowance of

TS 3.9.2 had been exceeded.

The licensee did not initiate any

action to place the unit in a cold shutdown condition after the

7-day specification had been exceeded.

This event identified a weakness of the licensee's awareness and

the recognition of the impact of operation of TS systems shared by

g' ~ '

both units. The licensee's failure to initiate actions to place

t

the unit in cold shutdown is not a violation of TS as 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is

.

allowed for the action to be complete, however, the intent of the

"

TS may not have been met.

The inspector discussed with licensee

management that when repairs cannot be made within the allowed time

limit, .it is implicit within the TS intent that action be initiated

uI

at the end of the action statement time interval. This was discussed

I

with licensee management and it was agreed that action should have

F

been initiated earlier and the licensee will provide these

instructions to operating crews.

t

7.11 Liquid spills Due to Weak Equipment Status Controls

p

During the performance of various Unit 2 activities, four spills of

'

significant amounts of water (contaminated and noncontaminated)

n

occurred.-

s

\\

l

. ,

.w,

.

-24-

'

On November 1, 1989, a spill of approximately 600 gallons of

'

primary coolant occurred when 2CV 5063 ("D" safety injection

tank (SIT) isolation valve) was opened.

The water flowed out

of the open SG hot leg manways. The manways had been removed

in anticipation of the planned SG tube eddy current testing.

No personnel injury or contamination occurred as a result of

the spill, but the eddy current testing equipment installed at

,

the "A" SG manway was damaged and a 24-hour delay in testing

resulted.

The "D" SIT tank had previously been drained and

vented on September 29, 1989, and then reisolated.

The

coerations crew on shift at the time did not recognize that a

significant length of piping remained full of water after the

previous draining operation and that a small amount of nitrogen

in-leakage had partially pressurized the isolated SIT. When

CV 5063 was opened, the residual water was forced into the RCS

and out the SG manway.

While refilling the "B" SG after the completion of sludge

lancing operations, an undetermined amount of demineralized

water flowed out of the secondary side manway into the primary

containment. Members of the operations staff were using

2P-7B, the electric EFW pump, to fill the "B" SG from the

condensate storage tank at the time of the spill.

A fill rate

of approximately 500 gpm had been established and the operators

were using a temporary tygon standpipe for level indication.

No level checks of the standpipe had been performed and

licensee investigation after the event showed that the standpipe

indicated approximately 18 feet below actual SG level. As a

consequence of this level error, water was pumped through the

open SG manway for some short period of time prior to discovery.

On October 24, 1989, approximately 200 gallons of SW was

sprayed into the "A" charging pump room when a pipe cap

installed under a hold card was removed from drain valve

25W-1100.

Because 25W-1100 could no* be completely closed,

the pipe cap was needed to prevent leakage past the drain

valve. When operators drained water from the containment

coolers into the leg of piping that contained 25W-1100, which

had been previously drained, water leaked into the charging

pump room for approximately 20 minutes. The operations

staff's close monitor'.ng of this evolution, walking down

service water piping auring draining evolutions, prevented

more water from being spilled.

Component cooling water (CCW) system draindown was in

'

progress to support maintenance on CCW cross connect

Valve 2CV-5230 when a spill partially flooded the 335 foot

elevation auxiliary building hallway. The cause of the spill

was an incorrect valve lineup to support the planned evolution.

n

m;

y.

>-

~25~

While the spil'is in these cases did not affect personnel or-

'

reactor. safety. .in all instances the spillage could possibly have

been prevented by increased diligence on the part of the Unit 2

operations staff.

Operations staff performance.during this outage has generally been

very good, however, these four instances, along with others noted in

this report, point out the need for additional improvement in the

areas of work controls.

7.12 Safety _ Awareness Standdown

In response to an increasing _ trend in personal injury accidents and.

near misses, licensee management conducted offsite safety awareness

training at the beginning of the Unit 2 outage for all employees at

ANO. The' training sessions were conducted at the training center-

and consisted of a management safety philosophy introduction and a

safe work practices session. Attendance at the training was

mandatory for all personnel and the licensee estimates that

approximately-5000 manhours were expended in this effort.

Lic.ensee management perceived a need for this training when the -

number of injuries requiring offsite medical. attention doubled

during the week of October 1,1989 (f rom 5 to 10). - The most

visible of these injuries involved a contractor electrician who

received flash burns on both hands during the performance of PM on

6900 Volt Switchgear 2H-1.

The licensee concluded that this

accident was the result of safety awareness' breakdowns at several

levels. The-scope of the clearance was based on the craftman's

recommendation and the assumption by the operators that he was

aware that portions of the buswork would remain energized. -There

was no verification of bus work condition. af ter clearance was

inadequate and the contract technician had not been adequately

briefed on activity scope and equipment condition, also procedural

guidance was weak and preper safety equipment was not used.

In

response to this event, the licensee stopped all electrical work'

while procedures, training, Lend' practices were reviewed.

The

licensee conducted training of all onsite electrical craftsmen and

provided interim guidelines itr the conduct of electrical work

until_. procedures could'be revised to r'eflect management philosophy.

The licensee's efforts in respon'se to these safety concerns were

timely and effective. There'ha; been a significant drop in the

~

number of injuries requiring offsite treatment,since.the safety

meetings.

The inspector concludes that licensee management has approached this

issue-in an_ aggressive and conscientious manner, and that the results

were effective,

b

T

[e

7

L

-26-

>

n

N

,

n

8.0_ Licensee Action on Low Minimum Flow Conditibns for EFW Pumps

'

[

In response to;NRC: Bulletin 88-04, " Potential Safety Related Pump Loss,"

,

the licensee had requested limiting minimum flow values for the EFW

'.

pumps from the Byron-Jackson Company.

Correspondence received from the

!-

Bryon-Jackson Company on December 14, 1988, established a minimum flow

t

for Unit 2 EFV. Pumps 2P-7A and 2P-78 of 45 gpm., This 45 gpm flowrate

,.

L

stipulated operation of not more than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months annually with

increased monitoring for shaft and bearing wear'being recommended.

j

l-

While performing the monthly _ surveillance test-on 2P-7A, Procedure 2106.06,

'

during December 1988 control' room operators. established that minimum

flow for EP-7A was 24.2 gpm and for 2P-7B was 25.1 gpm.

Review of

.

previously performed surveillance, indicated flowrates of 47.9 gpm for

2P-7A and 47.4 gpm for 2P-78. At this time, the procedural recommendation

,-

for minimum flow was 35 gpm, as the vendor recommendation had not been

-;

incorporated into the procedure. The flow instrument used in this test,

2FI-0798A, had been recalibrated prior to running this test because it

p

had previously been observed to indicate approximately 20 gpm with no

pumps' operating. At.the time.of the test, members of the operations

!

staff documented the' inadequate minimum flow condition in Condition

,

p

Report (CR) 2-89-002 and the pumps were declared operable. based on pump

.

performance and a suspected problem with 2FI-0798A. On Jcnuary 1, 1989,

the 1&C department performed Job Order (J0) No. 00776498 to check the

y

,

i

calibration of 2FI-0798A.

The instrument calibration confirmed the-

!

results and subsequent tests in January 1989 of 2P-7A and 2P-7B indicated

f

minimum flow rates at less than 27 gpm.

The licensee performed a'special work plan on March 30, 1989, to

evaluate 2P-7B performance with minimum flow rates of approximately

!

26 gpm. The pump was run for 90 ninutes while bearing vibration,

bearing temperature, and fluid temperature rise across the pump were

monitored every 10 minutes.

No evidence of pump degradation was noted

during this testing.

[

Even though the minimum flow data was lower than the vendor recommended

minimum flow rate of 45 gpm, the licensee responded to the NRC on June 15,

1989, that " adequate pump flows to prevent pump damage are achieved

during anticipated modes of pump operation." The licensee stated in a

,

letter dated November 13, 1989, that this. statement was based on

" incomplete information," that the preparer of the June 15, 1989, letter

was aware of the pump testing results, which were satisf actory, and that

the flow orifice design for the minimum flow line showed a calculated

~3

flow rate of 50 gpm.

The document preparer ~also believed that the'

. reduced flow indication was due to a problem with 2F1-0798A. There was

'apparently inadequate communication between engineering and operations

on this issue.

,

Subsequent conversations with the vendor on November 9, 1989, have

{

confirmed the licensee's position that the current pump flows are

adequate based on the testing data.

P

1

s

V-

r

i

~27-

Although the licensee has recently addressed this issue in a prompt and

aggressive manner and has focused its attention on the safety implication

of the potential insufficient minimum flow, actions prior to those

recently taken appear to have been slow, not effective in bringing the

issue to resolution, and not focused on the potential safety impact.

Although recent review of pump maintenance history and the testing

previously conducted indicate no apparent pump degradation under the

actual minimum flows, the licensee's initial actions to resolve this

problem appear to have been inadequate and untimely.

The licensee's

failure to promptly resolve this issue appears to be a violation of 10 CFR 50 Appendix B Criterion 16 which states, in part, ". . .that conditions

adverse to quality such as failures malfunctions, deficiencies, deviations,

defective material and equipment are promptly identified and corrected."

This apparent violation will be one of the topics discussed at an

Enforcement Conference scheduled December 8, 1989.

9.0 Exit Interview

The inspectors met with Mr. N. S. Carns, Director, Nuclear Operations

and other members of the AP&L staff at the end of the inspection. At

this meeting, the inspectors summarized the scope of the inspection and

the findings. The licensee did not identify as proprietary any of the

material provided to, or reviewed by, the inspectors during this

inspection.

L

ML19353B165

Text

Navigation menu

Search