ML20129F418

Forwards marked-up Copy of Insp Repts 50-424/90-19 & 50/425/90-19,Suppl 1,which Documents Insp Teams Review & Conclusions Re Allegations at Time of Insp Exit Meeting on 900817

ML20129F418
Person / Time
Site:	Vogtle
Issue date:	07/23/1991
From:	Reyes L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	Vandenburgh C Office of Nuclear Reactor Regulation
Shared Package
ML20129F106	List: IA-94-208, Partially Released Ltr Re Conversations W/Staff & Ltrs Identifying Allegations Related to Operations & TS Practices at Plant.Review Completed & Findings Documented in Encls ML20129F103 ML20129F113 ML20129F174 ML20129F222 ML20129F230 ML20129F243 ML20129F264 ML20129F418 ML20129F436 ML20129F452 ML20129F511 ML20129F549 ML20129F581 ML20129F593 ML20129F599 ML20129F606 ML20129F613 ML20129F621 ML20129F628 ML20129F638 ML20129F643 ML20129F648 ML20129F663 ML20129F684 ML20129F694 ML20129F724 ML20129F729 ML20129F735 ML20129F865 ML20129F990 ML20129G037
References
FOIA-94-208 NUDOCS 9610040144
Download: ML20129F418 (56)

See also: IR 05000424/1990019

Text

_ __

UNITED STATES

. [pm neo 'o NUCLEAR REGULATCRY COMMISSION

. [ , CE! ION 11

y ,P 101 MARIETTA STREET, N.W.

, s ATLANTA, GEOR0dA 30323

'+,.....

JUL 2 31991

MEMORANN N F0P, Chris A. VanDenburgh, Chief, Reactive Inspection Section 2

Vendor Inspection Branch

Division of Reactor Inspections and Safeguards

FROM: Luis A. Reyes, Director e

Division of Reactor Projects

SUBJECT: V0GTLE SPECIAL TEAM INSPECTION - ALLEGATION FOLLOWUP TEAM

DRAFT INSPECTION REPORT (INSPECTION REPORT NOS. 50-424/90-XX

AND50-425/90-XX)

This memorandum refers to the special inspection conducted on August 6

through 17, 1990, at the Vogtle Electric Generating Plant (VEGP). This

'

inspection involved a review of several allegations regarding the safe

operation of VEGP and the review of operational activities generally related

to the allegations. As discussed in the inspection plan, the inspection was

performed by two separate teams--an operational followup and an allegation

,

followup team.

As decided in a meeting held in Nuclear Regulatory Commission (NRC) head-

quarters on September 26, 1990, the allegation followup team's findings and

conclusions was not included in Inspection Report 50-424/90-19;

50-425/90-19. This information was to be withheld pending the completion of

an Office of Investigation review of the allegations and the inspection

team's conclusions. On January 11, 1991, Inspection Report 50-424,425/90-19

was issued which included the operational followup team findings. The

remaining issues from the allegation followup team were then left in

Inspection Report 90-XX, pending the completion of Ois' review of the

'

allegations.

On July 9,1991, a meeting was held in Region II, with members of Region

II-DRP, 01, and NRR-PD3-2 and Regional management. It was determined to j

,

-

issue the remainder of the 50-424,425/90-19 report, except for the following i

issues: 1) 12.3 Missed Containment Isolation Valve Surveillance; 2) 12.4

Mode Change With Inoperable Source Range Monitor Nuclear Instrument; 3) 1

2.7 Reliability of Emergency Diesel Generators and their corresponding parts

to the Notice of Violations.

This memorandum forwards a marked up copy of Inspection Report 50-424,

425!90-19, Supplement 1, which documents the inspection team's review and

conclusions regarding the allegations as of the time of the inspection exit

meeting on August 17, 1990 The report has already been reviewed by the

'

.

Office of Investigation in Region II for information that clight compromise

their on going investigations. The information that was considered

l

pertinent to these investigations will not be included in the issued report.

-

l \

9610040144 960827 l

PDR FOIA  ;

COLAPIN94-200 PDR i

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..

Chris A. VanDenburgh

.

2 JUL 2 31991 l

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If you have any questions concerning this issue, please contact P. Skinner  !

at Ext.16299 or S. Vias at Ext.15350.  :

'i

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~/ 4 l

'

Luis A. R

!

Enclosures

~1. Draft Notice of Violation i

2. Draft -Inspection Report '

50-424,425/90-19 Supplement I

cc w/encis:  !

L. Robinson 01. i

D. Hood, NRR, PD3-2~ t

s.445

&.%nd

t. %e 5

6. Jul

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, ioi maasts ta sie<tti. n.

4  ;; e anc.mA.etonc A 3o323

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• ' . M%II G;

1

i Docket Nos. 50-424 and 50-425 J

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License Nos. NPF-68 and NPF-81

i

i Georgia Power Company

ATTN: Nr. W. G. Hairston, III i

'

4 Senior Vice President - .

i

j Nuclear operations q L

)

<

P.O. Box 1295 y '

) Birmingham, AL 35201

Gentlemen:

SUBJECT: VOGTLE SPECIAL TEAM INSPECTION AND NOTICE OF VIDIATION

1 (NRC INSPECTION REPORT 3

NOS. 50-424/90-19 AND

50-425/90-1gg SuppleAw

This refers to the inspection conducted by an NRC Special p  !

j

!

Inspection Team

included a

on August 6 through 17, 1990.Jr Tne inspem. ion .Ag'

review of activities authorized for your Vogtle

i

facility. At the conclusion of the inspection, thePffindings were

3

i

i

discussed with those members of your staff identified in the

j

i

enclosed inspection report. }[

Areas examined during the inspection are identified in the report.

! Within these areas, the inspection consisted of selective

examinations of procedures and representative records, interviews

j. with personnel, and observation of activities in progress.

. Based on the results of this inspection, certain of your activities

.

appeared to be in violation of NRC requirements, as specified in

j the enclosed Notice of Violation (Notice). i

i

-1^3 *hatthe inspection concluded that the facility was opera

_

a safe mann..- Q dance with the requirements perating

l license, we are conc =..:f that there e veral operational  !

policies and programs whers we ___ - laantified. As part of i

, your response to the ons identified n sed Notice,

you are a sted to address each of the weaknesses ___A

l ion summary.

!

! You are required to respond to this letter and Notice and should ,

follow the instructions specified in the enclosed Notice when  !

preparing your response to the violations. In your response, you 1

l should document the specific actions taken and any additional

i actions you plan to prevent recurrence. After reviewing your

'

response to this Notice, including your proposed corrective actions

and the results of future inspections, the NRC will determine

whether further NRC enforcement action is necessary to ensure

compliance with NRC regulatory requirements. .

-

.

Q.4 4t g f & LeM-e t % w e.e U An, 491. d* k, & ~?

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coorgio Pov3r CcIpany

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a

E d!*ionally, you should respond to each of the o esses are

(The

weaknessesMfied within the report. ary.) The response

specifically annotated-in .the InspectioMhe s3gnificance of the weaknesses

.

should address your analysis at these operat tices do not ,

and your actions toof non-compliance or reduce the marg n 7:'ev ^

evolve int

p ant.

.

'

In accordance with section 2.790 of the NRC's " Rules of Practice,"

a copy of this letter and its enclosures will be placed in the NRC

Public Document Room. r

The responses directed by this letter and the enclosed

and Budget as required by the Paperwork Reduction Act of 1980,

Pub. L. No. 96. 511.

Should you have any questions concerning this letter, please

4 contact us.

sincerely,

0

>

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>

ne r

' Regional Administrator f

<

,

Region II

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Enclosures:

1. Notice of Violation

2. Inspection Report 50-424/90-191 l

50-425/90-19 % (pl* * d 1

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LIMITED DISTRIBUTION - Not For Public Ralesco h, '

DRAFT - PREDECISIONAL INFORMATION E,N,";,'" ,

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May 9, 1991 P[ %[

-> .

.

,,

MEMO DUM FOR: Luis A. Reyes, Director g:~ y .i

Division of Reactor Projects fq ',* : ~

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Region II .6.'N ', ' '

FROM: Chris A. VanDenburgh, Chief NY '- " '-4'.:..T.1 + '-

Reactive Inspection Section - 2 [5EF.('-j ,y..

Vendor Inspection Branch  ;

Division of Reactor Inspection and i

'

Safeguards

SUIL7ECT: VOGTLE ECIAL TEAM INSPECTION - ALLEG TION FOLLOWUP TEAM  ;

DRAFT SPECTION REPORT (INSPE ION REPORT NOS.  !

50-424/90 x AND 50-425/90-xx) l

This memorandum refer to the special spection conducted on

August 6 through 17, 19 , at the Vogtle lectric Generating Plant .

(VEGP). This inspection nvolved a rev ew of several allegations

regarding the safe operati of VEGP a d the review of operational  ;

i

activities generally relate to the legations. As discussed in

the inspection plan, the ins ction was performed by two separate

teams--an operational followup nd n allegation followup team. At

the conclusion of the inspect , all of the inspection team's ,

conclusions with respect to the erations and allegation followup l

were discussed with the me s GP's staff identified in the

I

enclosed draft inspection re rt.

As decided in a meeting hel in Nuclea egulatory Commission (NRC)

headquarters on September 26, 1990, the llegation followup team's

findings and conclusio have not bee included in Inspection

Report 424/90-19; 50-4 /90-19. This info ation has been withheld

pending the completi of an office of Inve igation review of the

allegations and the spection team's conclus ns. This memorandum ,

'

forwards a draft spection report (50-424/ -xx; 50-425/90-xx)

s

'

which documents e inspection team's revie and conclusions

regarding the a egations as of the time of th inspection exit

meeting on Au t 17, 1990.

. The areas e amined during the inspection are iden fled in the -

inspection eport. As discussed in Inspection Report -424/90-19;

50-425/90 9, the inspection team concluded that the f ility was

, safely rated. However, the inspection identifie several '

i instan s in which the VEGP was not operated in accordance ith the ,

inten of the Technical Specifications. In additio the

insp ction identified several potential weaknesses i the

'

fa lities' operational r licies and practicc..

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DRAFT - PREDECISIONAL INFORMATION

i

Lui A. Reyes -2- '

The ins'pection team's review of the allegations identified severa

additio 1 weaknesses in these operational policies and practice .

These ar identified in the inspection summary of the enci ed ,

'

draft insp ction report.

Based on the t artain

activities app,esults eared toof this inspection

be in violationofof theNRC allegations,

require nts, as

specified in t e enclosed draft Notice of Violation (Notice).

These violations re important because they indicate ( a failure

to implement the r cations and

-

administrative proc,equirements

9 dures, and (2) of the

theTechnical

failure to Speci

pr vide accurate

information to the .

As part of the response to the violations /dentified in the

~

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enclosed notice, VEGP should also be requeste to address each of

the concerns listed in t e inspection summa .

t

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Enclosures:

1. Draft Notice of Violation

2. Draft Inspection Report 50-434/90-xx; 50-425/90-xx

/

cc:

BKGrimes

EWBrach

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DRAFT - PREDECISIONAL INFORMATICN

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NRR/DRIS RII/DRP RII/DRP RII/DRP

JWilcox* RAlello* RStarkey* MBranch*

9/ /90 8/31/9 8/31/90 8/31/90

1

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RII/DRP RII RS NRR/DLPQ RJI/DRS

I4arner* MThomas* NHuneauller* ylore

9/27/90 /31/90 8/31/90 8/ 1/90  ;

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RII/DRP NRR/DRIS i

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RCarroll* CVanDenburgh '

8/31/90 9/ /90 l

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• Se previous concurrences

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LIMITED DISTRIBUTION - Not For Public R31easo

DRAFT - PREDECISIONAL INFORMATION

ENCLOSURE 1  !

,

NOTICE OF VIOIATION

<

l Georgia Power Company Docket Nos. 50-424 and 50-425

Vogtle Electric Generating Plant License Nos. NPF-68 and NPF-81 l

3 Units 1 and 2 l

'

,

l

l During an NRC inspection conducted on August 6 through 17, 1990, ,

violations of NRC requirements were identified. In accordance with l

the " General Statement of Policy and Procedure for NRC Enforcement i

! Actions," 10 CFR Part 2, Appendix C (1990), the violations are l

!

i

listed below. '

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"

A. 10 CFR Part 50.9, " Completeness and Accuracy of Information,"

requires that info mation provided to the NRC by a licensee

shall be complete and accurate in all material respects.

I Contrary to the above, the licensee provided g separate

curate

, information to the inspection team on 4heee

1

occasions. Although the information was provided in unsworn,

1 oral statements, the information provided was significant to

the licensing process. The information was provided by

l licensed operators, supervisors and management concerning

i information which was within their specific responsibilities. 1 i

l The d4ve examples were as follows. (50-424/90-eese-95; 50- l

'

! 90-eas-99) li - I'L l

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IV'2-

1. Containment Isolation Valves: During a Unit 2

surveillance procedure, the unit shift supervisor (USS)

,

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stated, and the operations manager later confirmed, that

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j the containment isolation valves for the hydrogen monitor

3 system were allowed to be opened without entering the

3 limiting condition for operation (Ico) action

requirements for Technical specification (Ts) 3.6.3

because the valves received an automatic isolation

.3 signal. The inspection identified that these containment

] isolation valves were remotely-operated, manual valves

without automatic isolation signals. (Discussed in

Section 2.2.1.1 of Inspection Report 50-424/90-19; 50-

425/90-19)

4 2. Snubber Reduction: The operations manager stated that,

! after the second Unit i refueling outage (1R2), the

!

modifications to tt:e snubbers were done in conjunction  !

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3g personnel Accountabiliev: The operations manager stated that

the shift superintendents (SSs) reported directly to the

operations manager and that he personally prepared their

performance appraisals. The inspection identified that the

sss reported to the unit superintendent (Us), and that the US

1 personally prepared the performance appraisals of the Sss. j

(Discussed ;,n section 2.Af of this inspection report)

O ,

4 y) Ts 3. 0. 3 Actions: The unit superintendent indicated that

there were no Operations Department actions which were i

,2

'

anticipated or required within the first three hours of

entering the action statement of TS 3.0.3. The inspection

identified that the VEGP management policy and stated practice

,

required preparations for a power reduction, including

8

informing the load dispatcher within the first hour.

' (Discussed in section 2.1.1.3 of Inspection Report 50-424/90-

19; 50-425/90-19)

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DRAFT - PREDECISIONAL INFORMATION

1

with preplanned system outages which were required for i

other preventive or corrective maintenance or testing. i

inspection identified that few of the snubber

. <

The

modifications were done jointly with pre-planned system j

,

i outages. (Discussed in Section 2.1.1.4 of Inspection

Report 50-424/90-19; 50-425/90-19)

'

. *=14mhl11tyr vrco j

E== v.nq Diesel-Generater (w)

,

.ncorrectly counted the number of starts and failurgot

1 t DGs and incorrectly represented the EDG re ability i

in a on II presentation on April 9, 199 Although t

I the presen ion was not 'ntended to repr sent a specific ,

number of su ssful valid test s specified in l

,

Regulatory Guide ( 1.108 and T . 8.1.1.2a, but rather

i

,

to describe the EDG ma nan test program and the EDG

reliability status, the was not informed of the i

C asked for it during  !

j incorrect information il th

i

the inspection. he confirmat of action (CAL)

response and L nsee Event Report (LER -006 were also ,

incorrect A cause they were based on t EDG start l

inform fon that was compiled for the VEGP pre ation  !

I

j in e Region II Office. (Discussed in Section 2. f

g[ s inspection report)

I

This is a Severity M vel IV violation (Supplement VII).

2

l B. Technical Specification 6.7.1.a requires that written

j procedures be established or implemented for those activities

' delineated in Appendix A of Regulatory Guide 1.33, Revision 2,

i February 1978.

l Contrary to the above, two examples were identified in which

the licensee failed to establish or implement the procedures I

for these required activities as follows: (50-424/90-ac'M? :

50-425/90-asu-49) 19- G

i

19 - 6

! 1. Administrative Procedure 00150-C, " Deficiency Control,"

i- states that a deficiency card must be written if the

i deficiency involves safety-related components which are

to be dispositioned "use-as-is/ repair," or other

conditions involving safety-related components which

- require engineering support or other technical assistance

to determine if the component is deficient.

d

on August 17, 1990, the NRC identified that a deficiency

card was not written on re'idual heat removal (RHR) pump

'

f1B (a safety-related component) to document the pump's

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DRAFT - PREDECISIONAL INFORMATION

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' degraded conditions which were dispositioned "use-as-is".

(Discussed in Section 2.2 of this inspection report)

i 2. Administrative Procedure 00100-C, " Quality Assurance

Records Administration," Paragraph 4.1.1.8, specifies

that quality assurance (QA) records will exh! bit

necessary and appropriate signatures or initials and

dates.

[

.

On August 17, 1990, the NRC identified that the Unit

i Superintendent incorrectly initialed, dated, and signed

i a QA record which voided Temporary Change Procedure (TCP)

1802-C-7-90-1 to Abnormal Operating Procedure 18028-C,

" Loss of Instrument Air," with the date of June 12, 1990,

i in lieu of the actual date (June 15, 1990) on which the

'

document was signed. (Discussed in Section Jdf of this

i inspection report) g.1b

4

{

This is a Severity Level IV violation (Supplement I).  ;

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C= re. ::, w=n= :. cra.r4 --cI, corr.cu= -

Action," requires measures to be established to ensure tha [

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l-

onditions adverse to quality are promptly identified f d

'

c rected. In the case of significant conditions adve Ne to

! qua , the measures are required to ensure that theguse of

i the co tion is determined and corrective action Jd taken to

i preclude tition. /

, /

ve, two examples were identified in which

Contrary to th

the licensee fa d to determine and adequate

corrective actions preclude repetitl'o/aplement

n as follows: (50-

l 424/90 .ans- et) /  !

i 14 - 14 /

j 1. On August 17,1900, theWC4etermined that the licensee

"

did not identify the foitat and normal use of the 14:0

. status sheet as one oJA.he causes of the event described

in Licensee Event Report (LER) '90,-004, " Failure To comply

j

With Technical Specification 3.0N< occurs on Entry Into

,

Mode 6"; therefore, corrective action was not taken to

preclude repet'ition of the failure to review Ico-required

actions orAremarks which may be on the back side of the

i LCo status sheet. (Discussed in Section '2.4 of this ,

inspect' ion report) i

i

1- 2.

/

(chnical Specifications 4.8.1.1.3 and 6.8.2 require hat

,

all valid or non-valid EDG failures be reported to th

NRC in a special report within 30 days. In addition,

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DRAFT - PREDECISIONAL INFORMATION

. Operations Procedure 55038-C, " Diesel Start Log," Section

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. 0, requires that all EDG failures shall be re or(ed to

t RC in a special report.

l

!

On Augu 17, 1990, the NRC ideptified that the

j corrective a ions taken in response 4o a previous notice

'

of violation e inadequate./ Inspection Report 50-

.

424/s7-57 (dated aber Sj A987) previously identified

l a violation of Tech ' al Specification 4.8.1.1.3, in

! that, all EDG failuresmo not reported to the NRC in a

special report. During a re w of the start records for

i EDG f1B duringA:he period of h 21 through June 14,

i 1990, the NBC' identified that EDG lures had occurred

l which were'not submitted to the NRC in special report.

In a difion, the NRC identified that Opera ns Procedure

.l 5 8-C provided inadequate guidance to i tify and

classify EDG failures. (Discussed in Section 2. this

j inspection report)

This is a Severity I4 vel IV violation (Supplement I).

! Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company

is hereby required to submit a written statement or explanation to

Nuclear Regulatory Commission, ATTN: Document Control

,

i the U.S.

Desk, Washington, DC 20555, with a copy to the Regional

Administrator, Region II, and, if applicable, a copy to the NRC

Resident Inspector within 30 days of the date of the letter i

transmitting this Notice Of Viel: tic . (;5tia) . This reply should

be clearly marked as a " Reply to a Notice of Violation" and should

include for each violation: (1) the reason for the violation, or,

if contested, the basis for disputing the violation, (2) the

corrective steps that have been taken and the results achieved, (3)

the corrective steps that will be taken to avoid further

violations, and (4) the date when full compliance will be achieved.

If an adequate reply is not received within the time specified in

this Notice, an order may be issued to show cause why the license

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should not be modified, suspended, or revoked, or why such other

action as may be proper should not be taken. Where good cause is

shown, consideration will be given to extending the response time.

,

FOR THE NUCLEAR REGULATORY COMMISSION

l

Stuart D. Ebneter

Regional Administrator

Region II

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Dated at Atlanta, Georgia

(s r ov\  !

this day of 199p

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Eid Judu,6 4

Te w ts

Report No.: 50-424/90-N and 50-425/90-N , $u f pleMe aN I

Licensce: Georgia Power company

P.O. Box 1295

Birmingham, AL 35201 .

Docket Nos.: 50-424 and 50-425 License Nos.: NPF-68 and NPF-81

Facility Name: Vogtle Electric Generating Plant, Units 1 and 2

i

Inspection Conducted: August 6-17, 1990

1

Team Members:

Ron Aiello - Resident Inspector, Vogtle

Morris Branch - Senior Resident Inspector, Watts Barr .

'

Robert E. Carroll, Jr. - Project Engineer, DRP, Region II

Larry Garner - Senior Resident Inspector, Robinson

Neal K. Nuneauller - Licensing Examiner, NRR

Larry L. Robinson - Investigator, 01, Region II

Robert D. Starkey - Resident Inspector, Vogtle

Craig T. Tate - Investigator, 01, Region II

Peter A. Taylor - Reactor Inspector, DRS, Region II

McKenzie Thomas - Reactor Inspector, DRS, Region II

' John D. Wilcox, Jr. - Operations Engineer, NRR

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' Team Leader:,. _ _ __. _ _ --

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" Chfis E Va'nDenburgh, SectTon C'hief

Division of Reactor Inspections and Safeguards

! Office of Nuclear Reactor Regulation

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Appeeved by: _ .

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TABLE OF CONTENTS

suf Wf

g 90,

INSPECTION SUMMARY........................................ -t"

1.0 INS PECTION OBJ ECTIVES . . . . . . . . . . . . . . . . . . . . . . . . . ..... T'

2.0 ALLEGATION FOLLOWUP.................................. Ar

2.1 Improper Installation of FAVA System............ 9-

2.2 Operability of Residual Heat Removal Pump....... 41-

2.3 Mi.e.d -Ce..teinsent Isc1; tion '!;1v; Ourveillance. 10

2.4 Msde Cheng; "'ith In:perable Source Rang?

3 -Moni te r Ne:l e r ! n t re :n t . . . . . . . . . . . . . . . . . . . . . . 10-

2 .JF Backdating o f Signatures. . . . . . . . . . . . . . . . . . . . . . . . jkP

2.sr Reportability of Previous Engineered Safety

Y Features Actuation System Load Sequencer

Outages......................................... 24'

3.' Reliability cf Esergency Olcsci Cenereters. . . . . . 2-

2.,r Air Quality of Emergency Diesel Generator

6 Starting Air System............................. 34F

2.F b Reportability of Previous System Outages........ 25'

'2..'7 .240 Intimidation of Plant Review Board Members. . . . . . 33-

2 b L kT Personnel Accountability........................ ,3&-

3.0 EXIT INTERVIEWS...................................... )4P

APPENDIX 1 - LIST OF TRANSCRIBED INTERVIEWS. . . . . . . . . . . . . . . JFr

APPENDIX 2 - PERSONS CONTACT 2D. . . . . . . . . . . . . . . . . . . . . . . . . . . . J1r

APPENDIX 3 - LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,$8

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INSPECTION SUMMARY

Recent activities which have occurred at the Vogtle Electric

Generating Plant (VEGP) have raised concerns within the Nuclear

Regulatory Commission (NRC) as to the ability and the deterinination

of the licensee to operate the facility in a safe and conservative

manner. To address this concern, the NRC performed a special team

inspection to deter 1mine if the licensee operates the facility in

accordance with approved procedures and within the requirements and ,

intent of the facility's operating license. In addition to the  !

occurrence of specific events, NRC concerns regarding the safe

operation of the facility were heightened with the receipt of

several allegations relating to operational activities at VEGP.

The aggregation of the facts and circumstances associated with the

operational events and the allegations was viewed as a possible

indicator of a non-conservative attitude on the part of the

facility's operating staff which warranted the immediate initiation I

of special inspection activities.

Specifically, the inspection objectives were to:

1) Assess the operational philosophy, policy, procedures and I

practices of the f acility's operating staff and management I

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regarding operational safety.

2) Determine the technical validity and safety significance of

d cf the allegations and their impact on the safe and {

conservative operation of the facility.

These inspection objectives were accomplished by the use of two

inspection teams--an operations followup team and an allegations

followup team. The offorts of these two inspection teams were

closely coordinated; however, they independently pursued the

objectives outlined above.

The operations followup team monitored control room activities on

a 24-hour basis in order to: (1) evaluate the operational

philosophy, policies, procedures, and practices of the operating

. staff and management and (2) determine if the plant was being

i operated in a safe and conservative manner in accordance with the

l facilities' operating license.

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The allegations followup team verified the technical validity and

safety significance of each ef the allegations. In addition, with k

the assistance of the OI staff, this team interviewed * members of

4 the plant staff in order to determine (1) their personal

j involvement and knowledge of the specific allegations and (2) their

practice and understanding of the station operational policies.

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! These-interviews were transcribed. Although an OI investigator was l

l assigned to the inspection team to assist during the transcribed  !

1 interviews, this inspection was not an investigation into th g

! intent of the alleaed violations. Nu muesrep.a5 **t M *M }

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w (:iewen. e<mo not iunst.

The inspection substantiated the occurrence of the specific events

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described in the allegations. These events resulted i t

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examples o v, lations of regulatory requirements (50-424/90- D l

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50-425/90- )2' "" G/^; .. ;^ ; and two of the events were .

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! previously identified as non-cited violations (50-424/90-10-03 and d

50-425/90-01-01).  ::: : : , the ine;rrtier did net rubettntirt

-th:t th: : ::t: :' vielstien vere-perfe n f rith the full-

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j L,wledge of 'J::Or ::n:; ::nt. Sie cerclerier See herM rper :

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' ;vice Of the lic:::ee's recorde ^^d the Svern testisery ef the

j pe;ple inv;17;d in th: ev::t;.

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inspection also identified that on several oc

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) naccurate

i respons agers and supervisors verbally su

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information to t e ' tion team durin spection. Although l

the inspection team was a out the accuracy of the i

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J information provided an did n a basis to conclude or l

i suspect th examples were the result o ss disregard ,

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atory requirements or individual wrongdoing. 1

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• - --- m.' ' b observations and conclusions of the inspection tem #g::o )

are detailed in Inspection Report

50-424/90-19; 50-425/90-1C

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addition, the bases for these previous conclusions are summarizedIn ,)#-

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below.

3 Doerational Policies and Practices

i NRC Inspection Report 50-424/90-19; 50-425/90-19 identified several

examples in which the licensee's operational policies and practices

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had the potential to adversely affect the operation of the

i facility. llegation followup team's review of the allegations

identifiedn additional examples in which the licensee's l

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operational policies and practices had the potential to adversely

affect the safe operation of the facility 1 "^r err;1:- {

I 1) The licensee's method of conducting Plant Review Board (PRB)

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meetings had the potential for adversely affecting open

i discussions among the PRB members. This concern was based on

i an example in which a PRB voting member felt intimidated and

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feared retribution during a PRB meeting because of the

presence of the general manager and the absence of dissenting

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opinions in the PRB meeting minutes. Continued licensee

action is necessary to ensure that PRB members freely and

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openly express their technical opinions and safety concerns.

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i 2) The licensee's practice of signing and dating quality

i assurance records was controlled by administrative procedures;

j however, there was a confirmed exasple in which a signature

j was backdated to reflect the actual date of performance. The '

} backdating of TCP 1802-C-7-90-1 was verified and was l

1 identified as Violation 50-424/90- ' ~6; 50-4 25/90-aus-et .

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(Section 24) i

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l 3) The licensee' practice of not initiating a deficiency card

(DC) during troubleshooting activities involving the

questioned operability of the residual heat removal (RHR) pump

prevented a documented engineering evaluation for either the

nuclear service cooling water (NSCW) outlet leak or the

excessive vibration on the RHR motor. The fal' lure to

, implesent this administrative procedure was identified as .4

1 Violation 50-4 2 4/90 .xas-@2. (Section 2.2)

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.. :the ef 59*= 4 = 4 a0 ==d eaaWal l i a; en,a 4 == af

, completed surveillance procedures was not controlled y

inistrative procedures. Based on the confusio hich

i resu d in the missed curveillance of the tainment

j' isolatio alves and a review of this methodo additional

3 atter. tion acessary to ensure that thg procedures are

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appropriately c ntrolled and used. (Sect' ion 2.3)

,9) The licensee's math to denti tive and informational

limiting condition for oper .ns (Iros) on LCO status sheets

allowed continuation o he ~I40 required ac.tions on the

reverse side of the rm. This me , in conjunction with

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the operator's c reed practice of re wing only the front

side of the status sheets, was one of oot causes for

l a non-ci violation (50-424/90-10-03) conc ng a mode

l cha ich occurred with inoperable source ra uclear

i ruments. The failure to identify this additiona oot

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v.u.. ... la.ni.iii.4 es Vicletie.. 50 4 ?/00 :: ^3. (!::t _ _

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fW The licensee's method of appraising the performance of the

licensed operators resulted in a potential disincentive for

identifying items which may result in LERs or violations,

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Accuraev of Information I

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The inspection concluded that during the inspection inaccurate '

' information was received on several occasions, from responsible

managers and operators on topp:s well within the scope of * a ir

specific responsibility. In 4Manstances the initial infor Cisn (

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supplied was clearly incorrect or inadequately researchef th t  :

l inspection team concluded that in each of these example:

licensee officials provided inaccurate, unsworn, oral stat cent s

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concerning information which concerned topics well within ts.24r  :

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responsibilities,

i ho inaccurate information was

the 4ir;t th::: cases, the { l

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significant to the inspection process. Specifically, (1) if the

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' containment isolation valves received an automatic closure signalthe v

' if the snubber modifications had been performed in conjunction with

i other preplanned preventive and corrective maintenance, then the  ;

voluntary entries into LCO 3.7.8 would not have been required, end- I

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p) ii the-WRC-was.. accurately informed .cf.-the-aumber of 15 p ehich 51:::

1 and i.ilorse ;' - th: Ere:gency Diesel Cenerator-No.

uwwuu.a dosinii ts d10 h:: ting, ther additiert! tecting rey hr : j

,.... . .,,. is .4- pries to - th: rele::: .. .... ....... _..... .. ::tden l

1etten The inspection team concluded that the failure to provide  !

accurate information was a violation of the requirements of 10 CFR

50.9 concerning accuracy and completeness of information. The

inspection identified Violation 50-424/90-  ; 50-425/90-Jsw-99 in

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this area and ncted the following examples:

containment Isolation valves: During a Unit 1 surveillance

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procedure, the unit shif t supervisor (USS) stated, and the

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operations manager later confirmed, that the containment

isolation valves for the hydrogen monitor system were allowed

to be opened without entering the 140 action requirements for

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i TS 3.6.3 because the talves received an automatic isolation

i signal. The inspection identified that these containment

i isolation valves were remotely-operated, manual valves without

I auta.tatic isolation signals. (Discussed in Section 2.2.1.1 of '

Inspect Dn Report 50-424/90-19; 50-425/90-19)

2) Snubber Reduction: The operations manager stated that, after

Unit 1 refueling outage IR2, the modifications to the snubbers

were done in conjunction with preplanned system outages which i

were required for other preventive or corrective maintenance

or testing. The inspection identified that few of the snubber

i modifications were done jointly with pre-planned system

' outages. (Discussed in Section 2.1.1.4 of Inspection Report l

50-424/90-19; 50-425/90-19) j

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Emeraenev Diesel cenerator Reliability: The licensee's met

researching information for Region II prese ion

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ng the reliability of the emergency diesel , erators  !

(EDGs) v nadequate in that there was a 1 of specific l

. guidance conc ng the EDG information d red coupled with I

inadequate resear the EDG starti story. This method l

resulted in providing omplete , therefore, inaccurate

info mation to the NRC. inn lon, the licensee's response i

to the NRC's confi nation ac letter (CAL) was based on

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this same inadequate earch. In tion, the subsequent i

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Licensee ' Event rt (LER)90-006 was so inadequately  !

researched. a result of this method of inv ation, the i

NRC was r informed of the correct operability a until j

this pection. (Discussed in section 2.7 of this inspe n

ort)  !

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34t Personnel Accountability: Theoperationsmanagerstatedthatl  !

the shift superintendents (sss) reported directly to the '

operations manager and that he personally prepared their i

performance appraisals. The inspection identified that the  :

SSs reported to the unit superintendent (US), and that the US I

personally prepared the performance appraisals of the SSs.  !

(Discussed in Section 3 A 1 of this inspection report) {

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4pf ts 3. 0. 3 Actione: The unit superintendent indicated that l !

there were no operations Department actions which were

anticipated or required within the first three hours of i

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entering the action statement of TS 3.0.3. The inspection  !

identified that the VEGP management policy and stated practice  !

required preparations for a power reduction, including

i informing the load dispatcher within the first hour.

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j (Discussed in Section 2.1.1.3 of Inspectica Report 50-424/90- i

' its 50-425/90-19)  ;

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In summary, the inspection identified these violations and two\ r

' inspector followup items. The violations involved: (1) a violation i

of 10 CFR 50.9 in that responsible licensee officials provided

inaccurate information to the NRC during the inspectionf4(2) a ,

violation of TS 6.7.1.a in that, two examples were identified of k

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the licensee failing to }mplement actions in accordance with

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W '. 2, 0: iter!:: "Y!, in th:t, tt:0 ::: ;1 : ::: id:nti f'<ed-of  !

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The inspection also identified two inspector followup items ,

involving: (I) an unreviewed safety question concerning the use of  ;

the alternate radwaste building, and (2) the lack of operator

guidance concerning the applicable limiting conditions of operation

during engineered safety features actuation system sequencer  ;

outages.

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INSPECTION DETAILS l

1.0 INSPECTION OIL 7ECTIVES

Recent activities which have occurred at the Vogtle Electric

Generating Plant (VEGP) have raised concerns within the Nuclear

Regulatory Commission (NRC) as to the ability and the determination

of the licensee to operate the facility in a safe and conservative

manner. To address this concern, the NRC performed a special team

inspection to determine if the licensee operates the facility in

accordance with approvad procedures and within the requirements and

intent of the facility's operating license. In addition to the

occurrence of specific events, NRC concerns regarding the safe

operation of the facility were heightened with the receipt of I

several allegations relating to operational activities at VEGP. l

The aggregation of the facts and circumstances associated with the

operational events and the allegations was viewed as a possible

indicator of a non-conservative attitude on the part of the i

facility's operating staff which warranted the immediate initiation '

of special inspection activities.

Because a non-conservative attitude or operating philosophy may j

represent a hazard to the health and safety of the public, a l

special inspection team comprising staff from the Region II Office l

and the Office of Nuclear Reactor Regulation (NRR), assisted by '

staff from the Office of Investigations (OI), was formed to

determine the individual validity and collective impact of these

allegations on the safe operation of the facility. The purpose of l

the inspection was to determine if the licensee operates the j

facility in a conservative and safe manner in accordance with

approved procedures, and the intent and requirements of the

facility's operating license. Specifically, the inspection

objectives were to:

1) kssess the operational philosophy, policy, procedures, and l

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practices of the facility's operating staff and managemenc l

regarding operational safety. )

, 2) Determine the technical validity and safety significance of l

each of the allegations and their impact on the safe and '

, conservative operation of the facility.

l These inspection objectives were accomplished by the use of two

inspection teams--an operations followup team and an allegations

followup team. The efforts of these two inspection teams were

closely coordinated; however, they independently pursued the

obj a::tives outlined above.

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j Theoperationsfollowupteammonitoredcontrolroomactivitieson(

a 24-hour basis in order to: (1) evaluate the operational 8  !

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philosophy, policies, procedures, and practices of the operating 3

3 ' staff . and management and- (2) determine if the plant was being' .

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operated in a safe and conservative manner in accordance with the g  !

facility's operating license. 3  !

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The specific inspection activities of the operations team was  :

described in Inspection Report 50-424/90-19 and 50-425/90-19g e ,.

efforts and conclusions of the allege8 _ti_ ops followup teams are i

described in this inspection report. " In addition, this report } l

identifies several violations 2nd $2;;..;i:1 ;;;%..;;;;; in the l

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licensee's :;;reti;nci pr!!:ler, prr;r-- , and procedures. 9he-  ;

gecificdetails==d h:;i; fe; th; ine;::ti:r trer's r---=ea= are

detailed in the sections that follow and in the Inspection Summary.

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2.0 ALLEGATION FOLIDWUP

The inspection team reviewed several allegations for their

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technical validity and interviewed licensed and non-licensed  !

personnel to determine their personal knowledge and experience  !

regarding these issues. This portion of the inspection was j

performed to determine the validity and significance of the .

allegations. 5:::r:: the elle;stierr errerted *Mt li--- ed '

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:: 5:d vieleted the Techair:1 Sp^cificatiene (??) vith the  !

h.:rl:d;: f lieerrer rare;r rrt, *he inepretien t:22 revier:d th: '

cirrrrrtencer e-d retienele fer i=dividerl retic- . '

The inspection of the allegations included technical reviews of the

licensee's records, logs, and interviews of the personnel involved

in the alleged violations. Although a transcribed record was not

required for every discussion with the licensee's staff, the

inspection team conducted sworn, transcribed interviews with

selected individuals in order to document (1) the individual's

personal knowledge and involvement in the alleged violations and

(2) the circumstances and rationale for their individual actions.

Although an of investigator was assigned to the inspection team to

assist during the transcribed interviews, this inspection was not

an investigation

ewr cos into .the

ar 7w Anap Aur.sers 5 m intent

Amp.rc ofghe h alleaed vi.olations. TwaM

p c. m n Cnc ,ys s,.

The interviews were transcribed after the technical evaluations of

the allegations in order to permit a focused interview and to

minimize the length and scope of the transcribed proceedings.

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transcribed interviews are listed in Appendir 1 in the order they j 4 p

were conducted. The sworn testimony was th? 5;;;6on wnica the

inspection team reached its conclusion on each of the allegations.

These conclusions are prcsented in the material that follows

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(Sections 2.1 through W ). ' '

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2.1 .Imoroner Installation of FAVA System

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An allegation indicated that VEGP installed and operated a radwaste

nicrofiltration system, known as the FAVA system,

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performing an adequate engineering and safety evaluation (i.e.,10

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CFR 50.59). Furthermore, the material configuration, fabrication i

and quality of the system did not meet the guidance of Regulatory

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Guide (RG) 1.143 and the requirements of the American Society of

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Mechanical Engineer's (ASME) Code.

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The FAVA system was temporarily installed for removing Niobium-95.

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The system was later determined to be better suited for as-low-as- ,

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i reasonably-achievable considerations during refueling outage IR2, i

particularly for removing Cobalt-59 and Cobalt-60. VEGP planned to

i replace this temporary modification with a permanent, high-

j; quality, steel system in the future; however, the health and safety l

of the public may be jeopardized if a break in the system i

(resulting in a radioactive release to an unrestricted area)

occurred in the interim. i

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- In February 1988, the VEGP experienced difficulty in removing [

colloidal Niobium-95 following a reactor shutdown for maintenance

work. i

FAVA Control Systems (FAVA) was hired to help rectify this

problem. FAVA was selected because of its experience in filtration

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and domineralization. The situation was corrected by installing  !

i a 0.35-micron filter system downstream of the existing vendor-

supplied pre-filters. t

i generated as the 0.35-micron filters

However, a large volume of radwaste was I

i rapidly exhibited high

differential pressure and were required to be changed frequently.

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The need to change filters frequently also resulted in additional

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radiation exposure to Radwaste Department personnel.

j Upon evaluation of the performance of the 0.35 micron filter

system, the Radwaste Department felt that the best approach to the

problem was a back-flush, pre-coat filter system. However, no

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operational data was available for a system of this type in this

specific application. FAVA supplied a proprietan Ultra Filtration

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System (Model No. SFD/E) for testing purposes in order to evaluate

whether

problem. or not this was a viable and economic solution to the

i The FAVA system was installed before the Unit I refueling

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outage and was operated under Test Procedure T-OPER-8801. The test

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system kept liquid effluent releases well below TS limits. on the

basis of an evaluation of test results by the Radwaste, Chemistry,

and Engineering Departments, a general work order was initiated to

l purchase a permanent system.

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In the early part of 1989, a Quality Assurance (QA) Department  :

audit identified a significant audit finding involving a

programmatic breakdown in the procurement of the FAVA system and  !

i the failure to meet commitments of the Final Safety Analysis Report

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(FSAR).- Because of that finding, the FAVA system was removed from

service. In late 1989, the licensee sought to reinstall the FAVA ,

i system under a temporary modification because colloidal Cobalt-59

i and Cobalt-60 had to be removed. The Plant Review Board (PRB)

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reviewed this temporary modification and several members expressed

] strong objections to it based on the previous QA audit finding.

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i Subsequently, a request for engineering assistance (REA) was  :

i submitted and a 10 CFR ' 50.59 safety evaluation was performed in

i late 1980. This safety evaluation did not properly address the

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guidance of Regulatory Guide (RG) 1.143 regarding the use of

polyvinyl chloride (PVC) piping.' Therefore, another safety

evaluation was p rformed in February 1990 to address this issue--- l

j particularly with respect to radiation degradation.

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The February 1990 safety evaluation specifically stated that the 1

l

FAVA system did not conform to the criteria of RG 1.143. This

! '

deviation was found to be acceptable for the following reasons:

'

1) The design of the FAVA system had been previously evaluated

! and found to be adequate in the response to REA VG-9057 dated

l November 28, 1989 (log SG-8592).

l 2) The location of the FAVA microfiltration system inside a

i

shielded, watertight vault provided adequate assurance that

any system failures will be contained and would not create the

l potential for offsite releases of, radioactivity.

.

l 3) The presence of PVC pipe in the FAVA system, although

l- prohibited by RG 1.143, was acceptable because the radiation

i

exposure to the plastic was within acceptable limits for up to

i 6 months based on the following:

!

a) The amount of PVC piping used was not extensive and was

j contained on the FAVA filter skid.

1

i

b) There were no reported leaks or malfunctions during the

' approximately 6 months that the FAVA system filter was

previously in use,

d

c) Since the FAVA system filter skid was located within the

demineralizar vault, it would be protected from being

damaged.

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I d) On the basis of the assumed' length of time that the PVC .

! piping would be used in a radioactive environment and the

activity levels of the effluent at this stage in the

! liquid radwaste process, the integrated dose to the PVC 'I

piping would be well below the radiation damage threshold  !

! for PVC pipe as reported in Electric Power Research '

i

Institute (EPRI) Report NP-2129, dated November 1981

! (i.e., 6.5 rad over a 6 month period versus the radiation

j: damage threshold of 5.0 x los rad) .

i e) The PVC pipe would not be subjected to excessive pressure  !

i

I

conditions since the maximue. available inlet pressure to i

!

the filter was so to 100 pounds per square inch gauge  !

(psig) which is well below the maximum allowable working

, pressure of 120 psig for the PVC pipe. j

f) The system could be operated at design-basis conditions  !

for 182 days before it would exceed the radiation damage

i

threshold. However, under conditions currently existing

.

at the plant, the expected dose to the PVC piping will

j less than 0.1 percent of the design basis.

i Although the testamony of one of the PRB members indicated that the

,

temperature effects on the use of PVC in the FAVA System were not

i

adequately evaluated before the system was installed, the testimony

! of the corporate system engineer indicated that this was considered

i

prior to installation, although not specifically documented in the

safety evaluation.

1

1

The VEGP general manager subsequently consulted the NRC resident

! inspector to seek an NRC position with regard to placing this

1- system - back in service. This was supplemented by information

{

' documenting reasons why it should not be placed in service. This

package was forwarded to Region II and the office of Nuclear

Reactor Regulation (NRR) for review. In March 1990, following

Region II and NRR concurrence via a telephone conference, the

licensee placed the FAVA system in service with the following NRC

! stipulations:

I

j 1) Procedures for operating the FAVA system required an operator

,

j

to be in attendance for the entire length of time the systra -

'

would be in operation.

i

.

2) All hoses going to and coming from the FAVA syst en required

! verification that they met the requirements of RG 1.143.

1

3) The cover over the FAVA system wa- required to be securely

fastened when the system was in operation to ensure that if a

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!

i spraying leak developed, it would be contained in the concrete

l vault.

i-

4) The design of the . walls of the alternate radwaste building  !

!

(ARB) was required to be evaluated to determine whether or not

i a design modification should be made to reduce the potential  ?

j of wall leakage in the event that a hose leak developed and

j sprayed its contents on the walls.

,

i In June 1990, in response to item 4 (above), the licensee revised

Part G of the safety evaluation for the FAVA system. Part G of the

i safety evaluation addressed the effect that operation of the FAVA 1

! system would have on the probability of occurrence or consequences ,

{ of accidents described in the FSAR. Although there was no l

4

comparable accident analysis in the FSAR that addressed the ARB

accidents or the consequences of accidents in the ARB, the FSAR

I accident analyses (Chapters 15.7.2 and 15.7.3) did describe worst-

case releases of the contents of the recycle holdup tank (HUT) .

l'

The first bounding analysis in Chapter 15.7.2 addressed the release

of the entire gaseous radioactive contents of the HUT to the

i'

environment at ground level and the second bounding analysis {

addressed the release of the entire liquid contents of the HUT-

i through an assumed crack 2n the ARS floor directly into the ground  !

. water supply. In both cases, the 10 CFR Part 100 and 10 CFR Part 1

'

20 limits were not exceeded. These criteria were consistent with

'

j criteria provided in NRC Circular 80-18, "10 CFR 50.59 Safety l

Evaluations for Changes to Radioactive Waste Treatment System." '

However, neither of these analyses addressed the potential for wall

spray down and leakage. through the ARB walls and the subsequent

t release path to the environment. Therefore, the licensee revised

the safety evaluation in June 1990 to address the consequences of

i

a hose break on the FAVA system which would result in wall spray

l

down and potential leakage to the environment.

,

l The inspection team's review of the revised Part G of the safety

i evaluation identified several erroneous assumptions with respect to

the release path and the dilution volumes that could be used in the

,

analysis of a hose break and resultant wall spray down. However,

the inspection team also found that the design of the FAVA system

(i.e., the use of a system cover) would prevent wall spray down and

that the only potential source for wall spray down and subsequent

leakage was from a hose break in another radwaste system in the

ARB. Therefore, the inspection team concluded that the FAVA system

safety evaluation dated June 1990, adequately addressed the

.

temporary modification for the installation of the FAVA system;

j however, the inspection team's review identified an unreviewed

4

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safety question concerning the release paths and consequences of a  !

failure of the other radwaste systems in the ARB.

In' addition, the team noted that in Supplements 3 and 4 of the

Safety Evaluation Report (SER), the NRC staff reviewed and accepted ,

,

the design of the ARB and specifically addressed the consequences

of a hose break on a radwaste system in the ARB. However, the SER

supplements addressed the effects of high airborne activities and

,

puddling and did not address the potential for wall spray down and

leakage. The ARB was installed before the plant was licensed;

t

' therefore, the NRC approved the design and use of the ARB in )

Supplements 3 and 4 of the SER. Thus, there was no requirement to  !

perform another evaluation of the potential effects of hose brcaks

on systems other than the system being installed by the temporary

modification (i.e., the FAVA system).

1

Because the design of the

l

FAVA system effectively prevented a wall spray down, this was not  ;

' a concern that was required to be addressed by the FAVA system '

safety evaluation. Nevertheless, now that it has been identified,

l

l the consequences of a hose break and wall spray down in the other

4

ARB radwaste systems must be resolved. Therefore, this issue will

be followed as an inspector followup item pending further review

and evaluation and is identified as:

' 19 -14 19 - N

IFI 50-424/90.x*-07 and 50-4 2 5/ 9 0-xw-02", 'Dotential Unreviewed

Safety Question Regarding Spray Down of the Alternate Radwaste

Building." .

J

<

Conclusion l

Although the FAVA system was originally installed without an

3

adequate safety evaluation and did not meet the regulatory l

guidance, the inspection team concluded that the subsequent safety i

evaluations were acceptable for the system's use. Serefert, th;

1

' inerrtien tem cen:1 d:d that th; ellgeti;n iter ne* M 1y ) l

r Arte el.i d. (

As a result of QA Department's significant audit finding in early

1989 involving a breakdown in procurement and failure to meet FSAR

commitments, the system was removed from service. Subsequently,  ;

the FAVA system was returned to service following two safety j

,

evaluations which adequately addressed the use of PVC piping with I

respect to radiation degradation and pipe rupture. Therefore,

these safety evaluations justified the use of the FAVA system, even

though the recommendations of RG 1.143 and ASME Code requirements

were not met. Although the safety evaluations did not specifically

address high-temperature effects, the testimony indicated that

these effects had been considered before the system was installed.

i

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Although the safety evaluation performed in June 1990 at the

, request of the NRC Region II Office did not adequately evaluate the

!

effects of a wall spray down and wall leakage to an unrestricted

area, this evaluation was not required because the FAVA system has

a protective cover and the use of hoses and effects of hose breaks

(i.e., airborne activity and puddling) were addressed in SER

J

Supplements 3 and 4.

I

Regardless of whether the safety evaluation was required to address

the effects of a break in the hoses (which could result in wall

spray down or leakage), the inspection team identified a new

concern involving the use of the ARB because the safety evaluation

inadequately addressed the potential effects of wall spray down

l from any other source in the ARB owing to erroneous assumptions

concerning the release path and the dilution volumes. This is a

<

potentially unreviewed safety question concerning the use of the

alternate radwaste building.

2.2 Operability of the Residual Heat Removal Pumo

'

An allegation indicated that during Unit i refueling outage IR2

with residual heat removal (RHR) Train A out of service for

maintenance, the Train B RHR pump experienced excessive vibration

and a nuclear service cooling water (NSCW) motor cooler outlet

i

i

leak. In addition, TS 3.9.8.1, "RHR and coolant Circulation," was

allegedly violated because the operations Department chose not to

, declare RHR pump 15 inoperable in an effort to mitigate the impact

on the critical work path.

Discussion

TS 3.9.8.1 requires at least one RHR train to be operable and in

operation during Mode 6 (refueling) when the water level above the ,

top of the reactor vessel flange is 23 feet or more. Otherwise, '

Suspeed all operations involving an increase in the l

reactor decay heat load or a reduction in boron i

,

concentration of the reactor coolant system (RCS) and j

!

Immediately initiate corrective action to return the '

I

required RHR train to operable and operating status as

soon as possible and close all containment penetrations

'

providing direct access from the containment atmosphere

to the outside atmosphere within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

The inspection team verified that during Unit I refueling outage

IR2 with higher than normal vibration measurements on the RHR pump <

4

1B and a leak on the NSCC outlet of the Rh motor cooler,

Department did

'

operations personnel not declare the pump  ;

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i

i inoperable. This determination was made after consulting with the

on-shift duty engineer from the Engineering Department and was  !

, based on the determination that the pump would fulfill its intended '

j

!,

safety function in Mode 6. Specifically, the RHR pump was capable

of removing decay heat from the partially defueled reactor core.

j The testimony of the individuals involved indicated that this .

. operability determination was based on the fact that the vibration

readings taken at the inservice test (IST) surveillance points did

not reach the IST Alert levels and were therefore acceptable for

continued service. Although the high vibration readings on the top

.

end of the RHR pump were later determined by the vendor

-

(Westinghouse) to be excessive, at the time of the operability i

evaluation, the licensee accepted these values, regardless of their

f

magnitude, because the readings at IST test points were below the

I Alert levels. The testimony also indicated that, even with a leak l

l on the NSCW outlet of the RHR motor cooler, the motor was receiving '

j full cooling water flow and cooling would not have been immediately

i compromised following a complete NSCW discharge pipe break.

l Furthermore, the. testimony indicated that the operations Department

j had : implemented compensatory actions to monitor the vibration

levels and NSCW 1eakage and ensure the continued operability of the

l pump by stationing an operator at the RHR pump to monitor the

vibration levels and notify the control room if the vibration

,

levels increased, thus allowing the control room to implement the

actions of the limiting condition for operations (140).

The inspection team also noted that in event of a catastrophic

!

failure of the RHR pump, all the required actions of TS 3.9.3.I i

I

(i.e., closing all containment penetrations)

'

could have been

$

completed within the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time period of the 140 because

-

'

the Ito for TS 3.9.4, " Containment Building penetrations," was in

effect during this time period. This LCO was implemented due to

,

the movement of irradiated fuel from the core to the spent fuel

j

4

pool. The 140 required that,

The equipment door be closed and held in place by at

least four bolts; at least one door in each airlock be

closed; and each penetration providing direct access from

1,

the containment atmosphere to the outside atmosphere

i shall be either closed by an isolation valve, blind

.

flange, or manual valve, or be capable of being closed by '

an operable automatic containment ventilation isolation

j valve.

4

As a result of the implementation of TS 3.9.4, the only remaining

act' .n for the LCO of 73 3.9.8.1 would have been to close the

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containment purge valve which receives an automatic closure signal *

'

and could have been isolated within the Iro action times.  !

4 During the course of this review, the inspection team found that

the licensee failed to initiate a deficiency card for either the  !

i NSCW 1eak or the excessive vibration as required by operations  !

4 Procedure 00150-C, " Deficiency Control." This procedure requires i

'

i that a deficiency card be written if the deficiency involves

safety-related components which are to be dispositioned "use-as- i

i is/ repair," or other conditions involving safety-related components ,

which require engineering suppolt or other technical assistance to i

determine if the component is deficient. Failure to establish,

,

implement, and maintain adequate operating procedures represents a ,

1 violation of TS 6.7.1.a. This item is identified as:

R-G 6 I

.' VIO 50-424/90_xx=Gt,i..a ;; = /;0 m ;i, " Failure To Establish or

l Implement Procedures for Required Activities."

h conclusion ,

!

!

The inspection team c luded tht t.5e 11-v. tis, n; n;t frily '

i c ertentistrf L;;.;;.3 e operations Department had an adequate i

! engineering basis for accepting the operability of the RHR pump in

j spite of the pump's deficiencies. In addition, the team concluded i

j that declaring the pump inoperable would not have impacted the

! critical work path: the 140 actions would not have been restrictive

'

because containment (excluding ventilation) had been isolated as

,

, required by TS 3.9.4. The LCO actions would not have prev . ,ad the

continuation of refueling activities because the actions to close  !

all containment penetrations providing direct access from the  !

containment atmosphere to the outside atmosphere would only have 1

required closing the containment purge valve which has an automatic

closure signal.

l In addition, the inspection team identified that the licensee

violated the station's administrative procedures by failing to

,

initiate a deficiency card for either the NSCW outlet leak or the

excessive vibration on the RNR motor as required by Operations

'

t

Procedure 00150-C.

,

-?' "!:rrf cert fr ent I:02: tier V:1:: Ourec ill;; ca -

l An allegatio icated that a unit shift isor (USS)

concealed the correc time for a T o prevent a forced

i- shutdown of the unit and to '

CFR 50.72 notification to

the NRC. Furthermore, c ent . ion valves (CIVs) which

'

were missed durin rveillance test sho va been declared

!- inoperabl e immediata actions of the TS LCO s ave been

1 i at the time the missed surveillance was identifie .

1

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ddition, delaying the initiation of the deficiency card (DC) unt 1  :

i.

t surveillance had been re-perfonned allowed the licensee o i

av (d the immediate actions of the LCO and allowed the un to i

) rema'in in operation and avoid the immediate NRC notificatio .

Discus on

! The inspe tion team reviewed the documentation of a missed

j

surveillanc on the containment isolation valves escribed in

a Licensee Eve Report (LER)90-001 for which a non- ted violation  ;

(50-425/90-01- 1) was issued. The LER identified hat during the

i review of mont y Surveillance Procedure 1447 -2, " Containment >

!

'

Integrity Veriff tion-Valves outside Contain nt," the licensee  :

discovered that 3 CIVs had been overlook and had not been

i tested. In additi ,

the valves had not b en tested during the

<

previous two month 1 s surveillances. Up identification, the

j operating shift re-performed the com ete surveillance and

initiated an investigat n which resulte in a deficiency card (DC)

!

for the previously misse surveillance .

i

i

root cause of the violation was

,

8

The LER indicated that t

personnel error in reviewing t e co lated surveillance task sheet. i

In addition, the computer softv which generated the surveillance

l- task sheets (STS) has been a ified so that it is no longer

!

'

possible to inadvertently t n incomplete listing of the

equipment. Even if an error imil to the one which resulted in

.

only two valves being shown n the S were to recur, it could only

result in either all or n e of the e ipment being listed,

i The inspection team v rified that S 3.6.1.1, " Containment

! Integrity," 140 actio statement requi d restoring containment

l integrity within 1 ur or commencing unit shutdown to hot

-

standby within the n t 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. A shutdo required by Technical .

Specifications wou d have required that th NRC be immediately

s

notified in accor ance with 10 CFR 50.72.

!

'

The inspection aan found that the CIV surveillance requirement of

i TS 4. 6.1.1. a ad been completed and approved. The surveillance

, procedure r ired verification every 31 days that al penetrations

i

not capabl4 of being closed by operable containee t automatic

i isolation / valves and required to be closed durin accident

conditi ns be closed by valves, blind flanges, or d etivated

)

'

autom ic valves secured in their normal positions. Du ing the

next shift, the oncoming shift supervisor noted th the

su elllance procedure was only partially performed and that 9 of

'

t CIVs on the surveillance procedure had been marked as ot

pplicable" and had not been performed.

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TS\.0.2.a

witft4n therequires

specifiedthattimeeach

intervalsurveillance requirement be perforud

exten) with a maximum allowa ee

ion not to exceed 25 percent of the surveillance inte

In aditition, Ts 4.0.3 requires that al.

failure to perf

survell

constitut

nee requirement within the specified time interva shalla

LCo. As a failure to meet the operability requirement for an

uch the failure to perform Surveillance R irement

4.6.1.3.a fk a,ll the CIVs within the surveillance pari (i.e.

days plus the 25-percent extension) would have co tituted ,an 31

inoperable con' ition of the CIVs.

The oncoming USS

determine if the stified that he lacked sufficie information to

omplete surveillance had n been performed

within the survalliance frequency because he w

the

circumstances under which the surveillancenot

performed.

familiar with

procedure was

Furthermorg, he lacked sufficient information in the

control

had beenroom to deterni

performed withine if the complete. surveillance procedure

his experience, the CIV su he surveillance ' period. On the basis of

eillance was mormally performed in its

entirety; therefore, the potential existed that another partial

surveillance

CIVs. Although procedure had verified the position of the missed

the control room,previously performed surveillances were filed in

neither controlled these records' era

nor complete. ' for information only and were

'

The USS indicated that the previou stwo monthly surveillances on

the CIVs obtained from this ' file sqre performed incompletely;

however, he did not know whether surveillances on the missed CIVs

had been performed completely under \some other surveillance

procedure.

This was confirmed when tNe team interviewed the

surveillance coordinator! Who indicated that approximately once a

missed surveillances were performed under different tasks. mo

Upon identificatiop/ \

of the potential missed surVtillances the USS

had actually b en missedtoand,

initiated an inveftigation determine whether the surve,illances

concurrently, r -performed the

surveillance

the discove w hin three hours. The inspection tea verified that

time at whi time on the deficiency card correctly flected the

had been p it was verified that the previous two s elllances

formed incompletely.

Cone sion

,

On the basis of the testimony of the USS, the inspection te

neluded that the allegation was not fully substantiated becaus

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USS did not conceal the true discovery time of the sis CIV

surve ces to avoid a unit shutdown. The USS indi that he

'

was not pre ed to keep the plant in operation o prevent NRC

notification. stated that he had er been given any

indication or instruc to do " wha r it takes" to kecp the

unit on line or to avoid N t ation of unusual events. The

USS did not know and co no onfirm if the previous CIV

surveillances had been equately per ed and believed that the

surveillance co re-performed within allowable outage

time; ther , his actions to initiate an invest on into the

4

"

adequ of the previous surveillance and to concur re-

ora the CIV surveillance procedure were appropriate.

: ":f: chance 9fth Inemable source -Jtanae- Monitor Mucien

f Instrument

1

1 An al gation indicated that the operations staff allege

'

knowing violated Technical Specifications (TS) when the uni as

taken fro Mode 5 (cold shutdown) to Mode 6 (refueling) th a

i

source rang monitor (SRM) nuclear instrument inoperable d that

the prohibite operational mode change was made in orde o reduce

the critical pat outage time.

! Discussion

i

'

The inspection team rev ved the documentati of the mode change

' described in Licensee Eva Report (LER) 90 04 for which non-cited

Violation 50-424/90-10-03 s issued. e LER indicated that TS 3.0.4 was violated on March 1990, en Unit 1 entered Mode 6

from Mode 5 with an 140 for Sou e Ra .ge Channel IN31 in effect to

allow performance of an 18-mont 'hannel calibration. The LER

indicated that the root cause to t avant was personnel error by I

the shift superintendent.

The inspection team confir'med that TS 310.4 required that entry

i into an operational mode not be made unlesssthe conditions for the  ;

'

. LCO are met without aeliance on the provisions of the action

requirements. With.one source range monitor inoperable, TS 3.9.2,

" Instrumentation,' could not be satisfied in\ Mode 6 without

reliance on the' action statement.

'

/

Personnel w[re interviewed to (1) confirm the effect on the outage

scheduled /irectly attributed to this TS violation, (2) etermine

whether'it was known at the time of the mode change that mode-

i restraining LCO was in effect, and (3) determine the exte t of

,

phasis on schedule.

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The testimony and a review of the outage schedule confirmed tha (

ere was a reduction in critical path outage time which w  !

d the l

! SRM ectly o anattributed

operable status. to proceeding to Mode 6 before restoring /

i l

. i

l The te isony also indicated that the shift superintendent (SS) and

{ .the uni shift supervisor (USS) did not recognize that 'a mode-

j restrain LCO was in effect at the time of the mode change. Both

!

the SS and SS were aware that there was an active 140 on the SRM,

,

but neither f them had connected the LCO to the mode., restriction.

i

i

contributing ctors to the error were that both th 8 and USS had

directed their attention to a problem with the esting of the  :

) engineered safet features actuation system (ES ) sequencer and i

i that the-work whi had been emphasized to be 1 ding up the mode  !

<

change was the d ontamination of the redctor head. Upon i

j notification that th Health Physics Department had cleared the l

reactor head for work, the SS granted permission to enter Mode 6. i

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i

The testimony also indic

unreasonable emphasis on t

ed that there 'was no indication of an  ;

critical path schedule. Both the SS  ;

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and USS indicated that they had never been given any indication or '

!

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instruction to do "whatever i takes" to stay on schedule. They

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also indicated that they did t , feel undue pressure to stay on

schedule and, particularly, not , f it meant compromising safety.

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The SS admitted that he was initia ly commended for the schedule '

j benefits; however, the violation of he Technical Specifications

'

was not recognized at the time. Thg SS indicated that he had .

initially received some sitive fee ack during the morning

! management briefing for a shift's acco lishments and later in

! the briefing the TS vio ation was recognize and discussed. In the

l SS's opinion the re nition of the TS olation negated all ,

positive feedback.

a

] The inspection t an identified an additional c cern during the

inspection conc ning the format and use of the

'

status sheets.

On the basis interviews with the SS and USS a the review of

the format o the 140 status sheets, the inspection as concluded

i that both a format and normal use of this form co ributed to

this TS v lation.

i

j

The LC status sheet, is a two-sided form; the section for quired

actio a begins on the front and continues on the back, who the

"re rks" section is located. During the testimony, both t

i an USS indicated that their usual practice, notwithstanding a SS

e

anges, was to review only

restorative actions were noted on the back. In this case, the mode

the front of this form because onk

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seestraint

ion. was noted on the back of the form in the " remarks" ,

l

LER 90 4 did not identify the format and use of the LCO st us

sheet, as cause of the violation therefore, corrective ions

,

have not ye een i:aken in this regard. The failure to dentify ,

and implement dequate corrective actions to preclude repetition is

a violation of l'O.CFR 50, Appendix B,

Actions," and as s(uch will be followed as: Criterion XVI/ " Corrective

VIO 50-424/90-xx-03, "F

,

s

ure To Determine and' implement Adequate  !

Corrective Actions." '

!

Conclusion N j

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,

onthebasisofthetranscribed,Jnkerviewsandfromitsreviewof

the outage schedule, )

the i pectionsteam concluded that the

allegation was not fully s stantiated. N.The testimony indicated  ;

'

that the mode change w a critical pathsites. However, the

testimony of the shift

perintendent and the unit shift supervisor

involved indicated that at the time of the mode' change they were

not aware that an'Ir0 was in effect on the SRM a that a mode

change was pro ited.

The ins

the ion team also concluded that the corrective act

failed to identify that the format and use of thns for

140

sta sheets, was one of the causes of the event. Therefore, e

f

ure to implement appropriate corrective actions was found to

,

violation of 10 CFR 50, Appendix. 8, Criterion XVI.

2.b pr Backdatino of sianatures

An allegation indicated that a temporary change to Abnormal

Operating Procedure (AOP) 18028-C, "Ioss of Instrument Air," was

not approved within the 14-day requirement of TS 6.7.3.c; and that

the unit superintendent intentionally incorrectly signed and dated

the

'

,

temporary change to indicate that the TS requirement was

satisfied.

j- Discussion

TS 6.7.3.c requires that temporary changes to AOPs which do not

4

involve changes to the intent of the original procedure be

documented

within 14 days and

of reviewed in accordance with TS 6.7.2 and approved

implementation. TS 6.7.2 requires that changes

to AOPs be reviewed as stated in administrative procedures and

approved

Administrative by theProcedure

Plant Review Board (PRB) and gener11 manager.

00100-C, "Cuality Assurance Records

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j Administration," Paragraphs 4.1.1.4 and 4 .1.1. 8, require ~ that

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i corrections to Quality Assurance records exhibit necessary and

appropriate signatures, initials, and dates.

!

i operations Procedure 18028-C, Revision 7, provided operator actions  :

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in the event of a loss of the instrument air system. A temporary '

j change to the procedure was initiated on May 29, 1990, to delete

i the references to the header isolation at 70 psig and the

i associated actions. This change was processed in accordance with

Administrative Procedure 00052-C, " Temporary Changes to  :

i

Procedures," which allowed the temporary implementation of minor i

j

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changes to procedures as long as the change was approved by the PRB j

and signed by,the general manager within 14 days of the temporary

change. Therefore, Temporary Change Procedure (TCP) 1802-C-7-90-1

was required to be approved by the PRB and signed by the general

,

)

manager by June 12, 1990. '

l

'! The PRB tabled the TCP on June 8, 1990, (PRB meeting 90-81) and i

j assigned action to the Operation's Department to void the TCP or

revise the TCP to incorporate the PRB comments. Revision 8 to

] Operations Procedure 18028-C was developed to modify valve numbers

and descriptions reflected in Temporary Modificatiors 1-90-006 and

i 2-90-002. This revision superseded the changes of the TCP. On

i June 12, 1990, the PRB approved Revision 8 (PRB meeting 90-82) and

!

the TCP was removed from the control room copies of the procedure.

] On June 15, 1990, the unit superintendent lined out the operations

.

manager's previous approval of the TCP and marked the TCP form as

! disapproved by the operations Department. The date entered on the

! form was June 12, 1990.

I

j On June 22, 1990, the PRB secretary initiated Deficiency Card (DC)

1-90-282 which indicated that the unit superintendent incorrectly

i

dated the TCP with the date of June 12, 1990, rather than actual

date of June 15,1990, and DC 1-90-283 which indicated that the TCP

j' was not processed within the required 14 days (i.e., by June 12,

,

1990). The resolution of these DCs, the associated PR8 meeting

i

minutes, and discussions with the operations manager and Nuclear I

Safety and Compliance Department staff indicated that described l

deficiencies were acknowledged and confirmed by the Operations

! Department on July 3,1990, and attributed to personnel error. The

I TCP form was dated with the date on which the Operations Department

l decided to void the TCP and not the date on which the original was

j actually signed. l

As part of the corrective actions for DC 1-90-282, a TCP record

,

correction notice was initiated to correctly indicate the date on '

! which the TCP fo11 was pro..ssed; however, tus TCP record

l,

correction notice could not be produced--one was subsequently

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4 written on August 14, 1990. In addition, the operations manager

- counselled the unit superintendent and assigned him to investigate  !

both DCs because he was the most knowledgeable of the deficiencies  ;

and the assignment served to reinforce the reprimand. '

The

4

subsequent PRB meeting of June 28, 1990, (PRB meeting 90-90)

determined that the 14-day TS violation addressed in DC 1-90-283

. was reportable to the VEGP vice president, but not to the NRC.

1 However, the inspection team found that the report to the VEGP vice

i president was not made.- On August 9, 1990, the PR8 (PRB meeting

}.90-104) confirmed that the report was required. As of August 17,  !

i- 1990, ~ the licensee had not issued the required . cport to the VEGP

j vice president; however, the licensee intended to issue the report. >

,

With respect to the rationale for the unit superintendent's  ;

actions, the inspection team learned (during discussions with the '

}. Technical Support Manager) that the PRB secretary told the unit

i superintendent on June 15, 1990, that the TCP needed to be voided

and 4 DC written for violating the 14-day requirement of TS 6.7.3.

l As discussed in Section 2.11 of this inspection report, Operations

i Department personnel are held personally accountable for violations

'-

and LERs (i.e., there is a direct impact on their bonus pay);  ;

therefore, a reportable occurrence based on this event could have  !

i

adversely impacted the unit superintendent's salary.

l

l The testimony of the unit superintendent indicated that he dated

the TCP with the date (June 12, 1990) on which the PR8 disapproved

I it and not the date on which it was actually signed (June ' 15,

i 1990). Additionally, the unit superintendent had no recollection

l of any discussions on June 15, 1990, regarding violation of the 14-

l day TS requirement. He indicated that he never considered the 14-

day requirement despite his previous knowledge and training

i

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concerning this requirement and the June 12, 1990, expiration date

indicated on the TCP form.

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!

The testimony of the PRB secretary indicted that during a

!

' discussion with the unit superintendent on June 15, 1990, she  ;

identified the need to void the TCP, as well as the need to write '

!. a DC for violating the 14-day TS requirement. Therefore, the

inspection team was concerned about whether the TCP was voided

j' before or after the PRB secretary identified the need to void the

!

'

TCP and initiate a DC. In order to resolve this discrepancy, the

inspection team discussed the discrepancy with the PRB secretary on

,. August 16, 1990. In addition to earlier testimony, the PR8

secretary indicated that during her discussions concerning the TCP

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with the unit. superintendent on June 15, 1990, the unit

superintendent had indicated that the TCP had already been voided

j aar13 : in the day.

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conclusion

i

l On the basis of the testimony, the inspection team concluded that

backdating to avoid a violation of the 14-day TS requirement was

I not '0117 ="h-"-ti tted T= idditi^=, the r^ cer- th t ibis

i practice m- a plant-wide problem,==- et *"11 y =nh=* =-t itt ed .

i However, the inspection team did confirm that TCP 1802-C-7-90-1 had

! been dated incorrectly; this was a violation of Administrative

i Procedure 00100-C, " Quality Assurance Records Administration,"

! Paragraphs 4.1.1.4 and 4.1.1.8 and will be followed as:

! 19-l's tq -G

' VIO 50-424/90-xx-@2' and 50-425/90-mm-er, " Failure to Establish or

Implement Procedures for Required Activities." \ 1

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<

g y Reportability of Previous Enaineered Safety Features Actuation

System Load Seauencer outaaes  !

An allegation indicated that the operations Department incorrectly l

used a 72-hour shutdown requirement when one of the two ESFAS load

sequencers was previously inoperable. It was also indicated that

l VEGP had taken no action to ensure that the past occurrences were ,

l identified and reported to the NRC as required by 10 CFR 50.73,

j despite newly acquired information that deenergizing an ESFAS i

.

sequencer required entry into the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> limiting condition for

l operation (Iro) action requirements of TS 3.0.3. In addition, the

possibility existed that the 140 for TS 3.0.3 (i.e. , 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> to hot

. standby) were exceeded when the sequencers were previously

i deenergized for maintenance and testing. This concern was based on

(1) the lack of a specific TS for the sequencers, (2) the '

operations Department historically linking the sequencer outages to

! the emergency diesel generator (EDG) 140 of TS 3.8.1.1.b (78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />

, to hot standby), (3) a limited review of past maintenance work

i orders (MW0s) indicated possible sequencer deenergiration; and

'

(4) comments by the engineering staff that the sequencers had been

previously deenergized.

Discussion

l There are two ESFAS sequencers for each unit--one for each 4.16-

e kilovolt (kV) emergency bus. Each sequencer is activated by one of

! two conditions, undervoltage (UV) on the associated emergency bus

! or a respective train's safety injection (SI) signal. Upon receipt

i of either or both of the initiating signals, each sequencer will

j perform all or part of the following functions:

' '

Start the associated EDG.

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j Stop any test sequence in progress.

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Strip the associated emergency bus of all loads (UV j

i only).

close the associated EDG breaker (UV only).

[ Energize the associated train's engineered safety

features (EST) loads as determined by the initiating

j signal.

l Each ESFAS sequencer contains three levels of UV detection and

j

system response, as well as the power supply for this UV circuitry.

Four potential transformers monitor the emergency bus voltage for  !

} these three levels of degraded bus voltage (Invel 1, 5 70 percent: l

Level 2, 5 86 percent; and 14 vel 3, 5 88.5 percent) and furnish an  ;

analog signal to three sets of four bistables located in one of the

4-

.

five sequencer cabinets.

!

Level _1 is the " loss of voltage" and Level 2 is the " degraded

!

i

voltage" which is referred to in TS Table 3.3-2, Items 6.d, 8.a.

and 8.b. As these TS items (applicable in Modes 1 through 4) do

i

not address the loss of all four channels in Level 1 or in Level 2

i

(as would be the case when the sequencer is deenergized), TS 3.0.3

would apply if such a loss were to occur. It should be noted,

i

however, that if the sequencer were deenergized, it could not

respond to a safety injection signal either. Therefore, there

would be only one automatic safety injection actuation channel

! (i.e., associated with the unit's unaffected sequencer) and Item

i 1.b of TS Table 3.3-2 (6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to hot standby) would be the most

l- limiting 140. 1

'; Discussions with the operations manager, the assistant general i

,

manager-plant support, and system engineers for the ESFAS and  !

i sequencers confirmed that the Operations Department historically '

2

linked the sequencer outages to the emergency diesel generator

(EDG) 140 of TS 3.8.1.1.b (78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> to hot standby) . Although the )

!

applicability

had

of TS Table 3.3-2 and TS 3.0.3 to sequencer outages l

l been recently identified, past sequencer outages were not

reviewed. Therefore, with the assistance of the licensee, the  ;

i

inspection team reviewed the completed MWOs which were performed on '

4

the sequencers on Units 1 and 2, as well as the related

i

1

Instrumentation and control (I&C) , Engineering, and Operations

Department surveillance tests.

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The review of completed MWOs did identify several instances where

the work performed would most likely require the sequencers to be

,

deenergizedt however, the associated unit was found to have not

.

been in Modes 1, 2, 3, or 4 at the time the work was performed.

.

Somewhat = related to this concern, the review did identify two

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occurrences (March 4 and June 17, 1987) where the Unit 1 Train B

l sequencer was inoperable during the change of sequencer controller

4

card A (SI4T A4-3) . Specifically, when the controller card was

j removed, both the automatic SI function and UV function for the

sequencer were rendered inoperable. Because the unit was in Mode

i 3 (hot standby) during these two occurrences, the sequencers and

the ESFAS were required to be operable per TS 3.3.2. However, the

i associated 140 status sheets (1-87-354, dated March 4, 1987 and 1-

I

87-566, dated June 17, 1987) only recognized TS I40 3.8.1.1.b as

being applicable to the outage. Despite the fact that 140s

,

associated with TS Table 3.3-2 (Item 1.b) and TS 3.0.3 were not

-

recognized, these TS were not violated since the system was

j . restored within 30 minutes and 10 minutes, respectively, f1F

i ' fditie , 2- ran unit rerrin:d in 5:t Ot:nry, pert:tility "adar

_

4

j *^ 07 00.72 w 00.73  :: n;t r:';;ir:d [i.:., there t' : pr:r  !

.

r=A n<-+ 6 ihil: 1. 2 TS LOO (10 OFP 50.?2) ner we G. piani.-aken I

j te hat utandhy er : :::Olt ;f e TO LOO (10 m 50. H ) F. 1

,

i

similar to the MWO review, the inspection team's review of related

I&C, Engineering, and Operations Department's surveillance tests

l did not find any examples of the sequencers or the ESFAS being

l deenergized in Modes 1 through 4. Completed 18-month ESFAS channel

i calibrations, EDG tests, and ESTAS tests were verified as having

i been done in Modes 5 and 6. Completed quarterly testing of the

i ESFAS Auto SI K610 slave relay, which removed the automatic SI

signal to the sequencer, were verified to be performed within time

i limits allowed by TS 3.3.2. All other sequencer testing that used

l installed test circuitry is automatically bypassed on an SI or UV

signal.

4

i

In addition to the inspection team's review of MWos and ,

l surveillance test procedures, the system engineers for the l

i

sequencers and ESFAS [as well as the nuclear steam supply system l

(NSSS) supervisor) were asked if they knew of any time in which the l

4- sequencers were deenergized in Modes 1 through 4. None of these '

)

engineers remembered any such occurrences.

'

A review of applicable operator treining material (System

1

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.

' Description 8b for Engineered Safety Features System Sequencers)

revealed that there was no reference to ESFAS TS 3.3.2, just those

for the diesel and other power sources and distributions (i.e., TS

i 3.8.1.1, TS 3.8.3.2, TS 3.8.2.1, TS 3.8.3.1, and TS 3.8.3.2.).

This finding, along with the March 4 and June 17, 1987, occurrences

l discussed above, indicates that the operations Department

historically has not linked sequencer outages to the 140s of TS 3.3.2 or TS 3.0.3. Nevertheless, discussions with the operations

,

~ manager and the licenced operators on shift indicated that although

no written guidance or TS interpretation existed for the

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sequencers, the operations Department staff would currently  !

consider all applicable TS requirements, including TS 3.3.2 and

j 3.0.3.

! Conclusion

The 140 actions of TS Table 3.3-2, "ESFAS Instrumentation," are  ;

'

] applicable for determining the operability of ESFAS components;

'

however,-if a load sequencer is not operable, the more restrictive i

requirement of TS Table 3.3-2, TS 3.0.3, or the affected system Iro

i should be considered. Although the EDG LCO of TS 3.8.1.1.b had  ;

'

been used for sequencer outages in t.he past, the allegation's  ;

concern of possibly exceeding the 140 for TS 3.0.3 when the  :

.

sequencers were previously deenergized yM * not 5: ';11y ,

} c'2:t: .tiatad. loa!nR*1co.

} Because there is no specific TS for the sequencers and considering ,

j (1) their unique interaction with numerous other systems and  ;

j equipment, and (2) the varying degrees in which related failures,  !

i maintenance work, and surveillances can affect the sequencers'  :

j associated functions, the inspection team concluded that additie.31  !

guidance for the operators is warranted. Therefore, this issue l'

l

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will be followed as an inspector followup item pending further

review and evaluation and is identified as -

I

N-If 39- 6

IFI 50-424/90-M and 50-425/90-xm-94, "Iack of Operator Guidance I

1

concerning the Leo Actions Applicable During ESFAS Sequencer '

outages."

1

.- 2:11211!ty -' h-==~ v nine.1 r:eneratera

{

i An allega n indicated that VEGP counted the number of starts

e failures o e EDGs incorrectly and misrepresente is

l information know in (1) a verbal presentation to C, (2)

a formal response to Region II confirmation o ction letter

l (CAL), and (3) LER 90-00 , evision 0, issued owing the March

j- 20, 1990, event involving fa es of the f1A. In addition, it

j was alleged that VEGP attempte use the EDG reliability

issue with Revision 1, and delayed . -006, Revision 1, in order

j to avoid drawing attention to ese inco et representations.

1-

i

Discussion

]

The spection team reviewed the following:

i

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!, 1) VEGP presentation in the Region II office ~ on April 9, 1990

concerning the site area emergency event of March 20, 19 .

his presentation is identified as Enclosure 2 to the Re on

i meeting summary letter of May 14, 1990. /

1

4

~2) VEG 1etter dated April 9, 1990, in response to the Region II

i cont ation of action letter (CAL) dated March 23,'1990. }

}  !

j 3) LER 90-006, issued April 19, 1990, to report the site area

emergen event of March 20, 1990. >

i These documentsMnd the following procedures describe the EDG

operability.statu and the licensee's program for recording EDG

! start information and the EDG surveillance test frequency i

4 requirements:

\

Procedure 550 8-C, " Diesel Start.Ing" l

?

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Procedure 1314 -1, "EDG Operation for Maintenance

Troubleshooting Maintenance Testing"

^

Procedure 14980-1, EDG Operability Test" i

e

l The licensee indicated in a tran

\/arency used during the Region II

l presentation that there were 18 s cessful starts on EDG f1A and 19

i

' successful starts on EDG $15 tyeen the loss-of-offsite-power

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event (March 20, 1990) and the pXesentation to Region II of

April 9, 1990. The inspectiop' team r iewed the EDG start logs and

j the detailed EDG start records complet during the performance of

i Surveillance Procedures 13145-1 and 1498 -1. The inspection team's

i review of these records in'dicated that th a were 31 EDG f1A and 29

'

EDG #1B attempted startpi Two of the EDG A and eight of the EDG

f1B starts involved pr#blems or failures. EDG f1A there were a

i total of 29 successful starts and on E 013 there were 21

i successful starts. However, there were s veral intermittent

problems or failurm/ s during the EDG f18 start tempts. Although

! there were 29 6 sequential starts n EDG f1A, the

inspection team,7identified

ccessful, that there were on1 12 successful,

j sequential staits of EDG $15 during this time peri .

i

! TS 4.8.1.1. .a requires that each EDG be demonstrate operable in

l accordane with the periodicity specified in TS Tabl 4 . 8-1 by

l' Verifyl that the EDG starts and assumes rated fra ency and ,

voltage in accordance with the EDG surveillance test This

. surve lance test required a minimum run time of 1 hou at a

l .desi ated load. The inspection team found that at the time the

l pre entation to the NRC, the operability test of the EDGs had een

s cessfully demonstrated two times. In addition, the EDGs ad

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i uccessfully passed four operability tests before Unit i entere

j e 2. Therefore, the EDGs were reliable and operable before t e i

j presentation.

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The WRC Region II Office was not verbally informed of the l

j

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incomp'lete information regarding the number of EDG starts until

1 June 11 1990 (approximately 2 months after.the presentation). .

j Although evision 1 of LER 90-006, dated June 29, 1990, correctly  !

) identifiedsthe number of sequential, successful EDG starts from the i

j and of the'saintenance test program (i.e., the first successful

! operability st per TS 4. s . l .1. 2 a ) until the issuance of LER 90-

i 006, Revision , dated April 19, 1990, this revision (June 29,

j 1990) did not address the number of EDG starts that should have

been cited in th presentation, in the VEGP letter in response to

the CAL, and in R 90-006, Revision O. The correct number of ,

j sequential, ' success ul starts for EDG #18 was 12 and not 19 as  !

! indicated in the pres tation. Therefore, the NRC was not informed l

of the correct informa ion in a timely manner. 1

The information presente to the NRC did not coopletely describe

. the problems and failures k at occurred with EDG $18. However, the '

i testimony indicates that t general manager's intention was to

i demonstrate that the problem involving the immediate trip of EDGs

identified during and follow gfthe March 20, 1990 event were

corrected prior to Unit 1 start .- Therefore, a compliation of the

total number of successful sta' s (i.e., a start that did not

s

ortan factor in his presentation.

i immediatelytrip)wasanimp/

l The testimony also indica d that e unit superinten: lent (Us) i

-

researched the EDG starti history fo the NRC presentation based

on a request from the ge ral manager. e general manager did not

ask the US to prepare a complete descri ion of the EDG starting

i history. specifica11 ' the general manage requested a summary of

l only the successfu starts--the informati concerning the EDG

j problems and fallu s was not requested. In ddition, the Us used

j the unit reactor rator logs instead of the E operating logs to

compile the EDG tarting history. The reactor perator logs did

! not contain a etailed description of problems failures which

! occurred dur g the EDG starts. The US did not ceive specific

j guidance co erning the type.of EDG starts that he w requested to

l

summarise. In addition, the testimony indicated that the original

, assumptigns and EDG $1B start information used in the esentation

were alp 6 used in the VEGP response to the CAL, and in R 90-006

issuedApril 19, 1990.

, i

.

Thef [nspection team's review of ' the Unit 1 EDG's reliabil and

o rability status between March 21 and June 14, 1990, raise the

11owing additional concern. The review was performed to ve fy

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t at all EDG failures were identified and classified as eit

va id or non-valid and were reported to the NRC as required b TS

r

4.8. .1.3 and TS 6.8.2. The inspection team discovered tha the

foll ing f ailures during starts of EDG f1B had not been clas ified

as val d or non-valid and, consequently, had not been repofted to

the NRC ursuant to TS 4.8.1.1.3 and TS 6.8.2.

EDG S art Date Remarks

/

1-90-13 3/22/90 EDG trfp, high-

temperature lube oil.

Ma i n 't e na nce

troubleshooting test.

/

1-90-134 3/23/90 EDG / trip, low jacket

water pressure.

M ,4 i nt a nance

2 troubleshooting test.

.

1-90-136 3 24/90 EDG intentionally stopped

due to alarmed condition,

high jacket water

temperature. Maintenance

troubleshooting test.

1-90-157 5/23/ 0 EDG trip, high jacket

water temperature

M a i nt e na nce

troubleshooting test. i

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1-90-160 5/23/90 END G trip, 1ow

tutbocharger

-161 o i' pressure.

Main nance

-162 troub e. shooting test.

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1-90-164 5/23/90 EDG trip high jacket

water

-163 temperature. Maintenance

troubleshoot g test.

I

These in .ction findings were discussed with the e ineering l

support anager who agreed that these types of failures ave not '

been ported. The licensee committed to have all E start I

,

recor s reviewed for any unreported failures.

Th inspection team also four.. that a violation -as previou ly

i entified for the failure to report all EDG failures in Inspecti

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, Re rt 50-424/87-57 dated November 1987. Although the failur to

,

repo all EDG failures is a violation of TS 3.8.1.1.3

6.8.2, the inspection team concluded that the failure

d TS

' s the

result inadequate implementation of corrective a ions to

j

l

prevent re urrence of a violation and, as such, is a vjdlation of

- 10 CFR 50 Ap ndix 8, Criterion XVI, " Corrective Actiop," and will

be followed a

VIO 50-424/90-xx- , " Failure to Determine and Implement Adequate

j Corrective Actions. ,

,

/

j Conclusion

1

/

/ l

i The. allegation that VEGP i orrectly counted the number of starts

l

and feilures of the EDGs a knowingly misrepresented the EDG '

. reliability in order to s1 cad the NRC was partially l

. substantiated. On the basis of u sworn testimony and its review

j j

of EDG records, the. inspection te concluded that the Region II 1

,

presentation was not intended to r resent a specific number of

j successful valid tests as specified in G 1.108 and TS 4. 8.1.1.2a, l

i

but rather to describe the EDG maintenan test program and the EDG ,

! reliability status. Nevertheless, the i ction team concluded  !

i

that the NRC was not informed of the incor et information until

the NRC asked for it dh[ ring the inspection. l

e lack of specific I

guidance concerning he EDG information desi d, coupled with

inadequate researc  !

of the EDG starting histo , resulted in 1

providing incomp te and therefore inaccurate infotsation to the ]

NEC. The CAL r ponse and LER 90-006 were also inco ct because

they were bas on the IDG start information that was c iled for

! the VEGP pr antation in the Region II Office. The inspec on teaa

! concluded at the failure to provide accurate information o the

] NRC was a violation of 10 CFR 50.9 requirements and wil be

l follow as: .

l VI 50-424/0-xx-05; 50-425/90-xx-05, " Failure to provide Accurate

,

r

ornation to the NRC."

, 7 6 y Air Quality of Emeraency Diesel Generator Startina Air System

\

An allegation indicated that VEGP had no basis for its conclusions

i regarding the air quality of the EDG starting air system and

misrepresented the air quality in the licensee's written response ,

to the CAL.

I

f Discussion

i

i

The ir. pection team reviewed the maintenance records and deficiency

cards associated with Unit 1 EDG starting air system. The team i

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4

was established when preoperational tests were init

on Unit 1 in November 1986. t

' this date, '

part of 1988,but' not on a scheduled frequency.During Dewpoint themeasurements

latter w:

!

i established to measure the EDG starting air system The

dewpoi{

!

the

current air drPM progran required checking the dewpoint monthly, cleanin  !

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addition, yer condensing

operating units,11882-1,

Procedure and cleaning the fan motors. In

i "Outside Area Rounds," i

i dryers

noisture. be blown down on a daily basis untilrequired that the E)

i

they were free of

operators blev The inspection team verified that the plant equipment ,

performance of their down the air systems on each shift during the

rounds.

!

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A review of the Unit 1 EDG maintenance history records indicat e

d

.

that the majority

specifications. of the devpoint

There were instances, measurements taken were n

withi i

j

i asasurements were above specifications.however, when the dewpoint i

primarily

instruments, attributed to problems with (1) These conditions were

l

extended pwriods (2) ofsystem

time, andair dryers beingthe dewpoint measuring

system following maintenance. (3) repressurizing the EDG air start

out of service for I

i

s

The inspection team reviewed maintenance records associated an

with

internal inspection of the EDG air start system air receiver5-

micron control _ air system filter inspection and replacement ,

the replacement of the dowpoint measuring instrument, with and

analyzer. an EG6  ;

i

• Following the loss of offsite power event of March 20 G

1990, the control air system instrument lines were disconnected or

,-

f

maintenance troubleshooting and functional tests of Calcon sensors

The system engineers associated with this work stated that no .

i

evidence of internal noisture or corrosion was noted

inspection and calibration of the calcon sensors or theair cortrol

during

system instrument lines when this equipment was disconnected for

.

!

maintenance troubleshooting and testing.

j Conclusion -

'

!.

The inspection team concluded that the licensee did have an

{'

adequate basis to assess the quality of the EDG starting air

system. ,

1

inspection

addition, the of EDG air start system components a on. In

for degr

i PM program dewpoint readings have shown more

i

The

concerning allegation

EDG air

that

start

VEGP

system

did not have a ements

aer.basis for th

-4.i.uil-i A C #id *4 C D quality was not

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um * A INhgebm.

yQWidLC. L m. eta & Guy as@v

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M

y Reportability of Previous System Outages l

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An allegation indicated that VEGP failed to immediately notify the \< >

{

j

NRC as required by 10 CFR 50.72 when VEGP identified that both

trains of the containment fan coolers (CFCs) had been previously

inoperable at the same time on Unit 1.

i

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.

I Discussion

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I

The inspection team's review of plant records indicated that this  !

! condition occurred when EDG f1A was declared inoperable when tape

(used when the EDG was being painted) was found on the EDG fuel

j rack. The tape kept the fuel injector piston from moving and

i injecting fuel into the EDG. With EDG f1A inoperable, the

.

equipment associated with the Train A was also inoperable. In the

process of investigating the installation of the tape, VEGP  !

i;

identified that this condition existed during a period when the

Train B containment fan coolers were also in a degraded condition  :

j for maintenance.

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During the performance of Surveillance. Procedure 14623-1, Train B

!

1

containment

speed. 140 1-90-560 fan cooler (CFC) 1-1501-A7-003 failed to start in slow

was initiated at 0115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br /> on June 19, 1990,

J and maintenance on the CFC was initiated. The CFC was returned to

j operable status on June 19,1990, at 1415 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.384075e-4 months <br />. Approximately 9

hours later [on June 19,1990, at 2359 (Lco 1-90-562)), EDG f1A was

i

determined to be inoperable because the tape had been installed on

i- the fuel rack. On July 17, 1990, VEGP issued LER 90-014 to

j

identify the previously unrecognized violation of the 140 in

accordance with 10 CFR 50.73.

'

, Conclusion

!

Based upon the fact that VEGP did not become aware that both trains

,

of CFCs were simultaneously inoperable until after the Train B CFC

!

j fan had been returned to service, the immediate notification

requirements of 10 CFR 50.72 were not applicable. The allegation

, that previously

the VEGP failed to immediately

degraded c notify the NRC upon discovery of

e , - ,ondition> .

of the CFCs was not .Se44y

j

g.1 W Intimidation of Plant Review Board (PRB) Members

i

i

f An allegation indicated that Plant Review Board (PRB) members were

allegedl

j meeting.y intimidated and pressured by the general manager in a PRB

The meeting occurred in February 1990, to determine the

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acceptability of the safety analysis for the installation of the

FAVA microfiltration system.

Discussion

T.i j

k

As discussed in Section ht" of this inspection report, several ,

!

'

safety evaluations were performed for the installation of a

temporary modification which installed the FAVA microfiltration

i system. Discussions with PRB members indicated that during the

t review of these safety evaluations, various PRB members had

1 expressed reservations on several occasions concerning the

4

acceptability of the installation of the FAVA system.

!

.' Despite these reservations, the inspection team's review of the PRB

Meeting minutes associated with this temporary modification

j

identified few instances of the PRB members documenting their

i dissenting opinions. Specifically, PRB meeting 90-15 (dated

February 8, 1990) documented one PRB member's negative vote and

'

i dissenting opinions regarding the acceptability of exempting the

temporary modification from regu'.atory requirements and the

, adequacy of the system's safety evaluation. PRS Meeting 90-28

. (dated March 1, 1990) indicated that information and issues

regarding the FAVA system's safety analysis were presented to the

j PRB and that the general manager solicited written comments and

! questions from other members for resolution. The only other

l example was in PRB meeting 90-32 (dated March 6, 1990) which

!- identified a dissenting opinion related to the acceptability of

j votina on the FAVA system installation when the PRB member who  ;

raised the initial questions and concerns on the operation of the

i FAVA system was not present.

! Discussions with the PRB members indicated that during the various

PRB meetings concerning the installation of the FAVA system, the  ;

i PRB members felt intimidated and pressured by the presence of the '

l- general manager at the PRB meeting. The sworn testimony confirmed

4

that on one occasion an alternate voting member felt intimidated  ;

and feared retribution or retaliation because the general manager i

j was present at the meeting and the PRB member knew the general 1

j. manager wanted to have the temporary modification approved.  ;

j However, the testimony also indicated that the.PRB member did not '

a

alter his vote and felt comfortable with how he had voted. In

l addition, the PRB member was not aware of any occasions on which he

or any other PRB member had succumbed to intimidation or feared  ;

i

! retribution.

!

'

The incpection team verified that the general manager was informed l

i

following this meeting that several PRB members viewed his presence

as intimidating. As a result, on March 1, 1990, the general

,

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manager set with all PRB members to reiterate the member's duties

and responsibilities.

He specifically told the members that his

presence at PRB meetings must not

influence them and that  !

alternates should be

responsibility. Heselected who would feel comfortable with this

also addressed i

the difference between

and their respective methods for resolution. or quality concerns,

professional differences of opinion and safety

conclusion ,

The inspection

felt intimidated

was present at the andPRB team

feared retribution

meeting. concludedbecause the that general in manager

on* case a PRl

However, this member 6ala nor W

change his vote in response to this pressure and the general

manager met with the PRB to allay fears. Based on the testimony,

the inspection team concluded that retribution did not occur. i

Nevertheless, this confirmed event and the absence of dissenting '

opinions in the PRB meeting minutes indicate that there was a '

potential for an adverse affect on open discussions at the meeting, t

The licensee needs to ensure that PRB members freel

express their technical opinions and safety concerns.y and openly

K Personnel Accountability

As a result of several comments and questions by the licenced

operators

to rate theto the inspection team, the team reviewed the method used

supervisors. performance of the shift superintendents and unit shift

Discussion

The o

rations manager stated that the shift superintendents (SSs)

"

e SSs re ed to su int ndent

i s and a

US personally prepared the performance appraisals of the 8 s.

i The personnel accountability system, first used in 1989, was a pay-

for-performance methodology. Annual pay increases and e percentage

i of

in the Operations Department

accountability categories. bonus were dependent on their ratings

,

i

subdivided into performance categories.Each accountability Most of the performance category was  !

categories vern based upon group performance.

.

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eliminated, any differential in pay will Once these are i

result from eight

t

performance categories. Implementation of the plan in 1989 could

i result in

superintendent. up to an $8,000-a-year difference 'n bcnus pay to a shift

weights are: The performance categories and their relative

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Personnel safety 4.1%

i

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Regulatory compliance 10.2%

.

ESFAS actuation 12.2% }

I Reactor trips 10.2%

!

'

• MWO performance 4.1%

'

.

Special projects a.2% '

=

Personnel development 30.6%

l .

Training 20.4%

,

i

{ Therefore, 51 percent will be associated with personnel development

]

and training and 32.6 percent will be associated with the number of

LERs, and violations (i.e. , regulatory compliance (10.2 percent),  ;

.

ESFAS actuation (12.2 percent) and reactor trips (10.2 percent)]. '

Conclusion

'

The inspection team concluded that there was a

t

potential

'

,

disincentive for identifying items which may result in LERs or

violations.

'

In addition, the inspection team concluded that the

j operations manager

information to the inspection provided incorrect

team. or inadequately researched

!

i

The inaccurate information )

concerned whether the operations manager personally performed the

a

performance appraisals of shift superintendents. The information i

-was not very important because the inspection team did not use the 3

j informationteam

inspection as the basis forthat

concluded a significant

this failure inspection finding. The {

-

to provide accurate ]

i information was an example of a violation of the 10CFR 50.9

{

requirements

followed as: to provide accurate information to the NRC and will be

' 14-1L- Ig-12.

,

VIO 50-424/90-aoeHPJ; 50-425/90.xx-65, " Failure to Provide Accurate

Information to the NRC."

'

j 3.0 EXIT INTERVIEWS

1

'

The inspection scope and findings were summarized on August 17,

i

1990, with those persons indicated in Appendix 2. The inspection

team described

inspection results.the areas inspected and discussed in detail the

The licensee made numerous

,

comments. dissenting

i

materials provided to or reviewedThe licensee did not identify as proprietary any o

i inspection. by the inspector during this

,

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APPENDIX 1

LIST OF TRANSCRIBED INTERVIEWS

DATE TIME PERSON

,

8/14/90 904 hours0.0105 days <br />0.251 hours <br />0.00149 weeks <br />3.43972e-4 months <br /> George Bockhold

911 hours0.0105 days <br />0.253 hours <br />0.00151 weeks <br />3.466355e-4 months <br /> Jim Swartzwelder

1023 hours0.0118 days <br />0.284 hours <br />0.00169 weeks <br />3.892515e-4 months <br /> Harvey Handfinger

1026 hours0.0119 days <br />0.285 hours <br />0.0017 weeks <br />3.90393e-4 months <br /> Bill Diehl

1109 hours0.0128 days <br />0.308 hours <br />0.00183 weeks <br />4.219745e-4 months <br /> Mike Horton

1335 hours0.0155 days <br />0.371 hours <br />0.00221 weeks <br />5.079675e-4 months <br /> Mike Chance

1136 hours0.0131 days <br />0.316 hours <br />0.00188 weeks <br />4.32248e-4 months <br /> Jimmy Paul cash

1338 hours0.0155 days <br />0.372 hours <br />0.00221 weeks <br />5.09109e-4 months <br /> Dudley Carter

1529 hours0.0177 days <br />0.425 hours <br />0.00253 weeks <br />5.817845e-4 months <br /> Bruce Kaplan

1625 hours0.0188 days <br />0.451 hours <br />0.00269 weeks <br />6.183125e-4 months <br /> Greg Lee

1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> Jeff Gasser

8/15/90 906 hours0.0105 days <br />0.252 hours <br />0.0015 weeks <br />3.44733e-4 months <br /> Allen Mosbaugh

937 hours0.0108 days <br />0.26 hours <br />0.00155 weeks <br />3.565285e-4 months <br /> Ernie Thornton

1009 hours0.0117 days <br />0.28 hours <br />0.00167 weeks <br />3.839245e-4 months <br /> John Gwin

1048 hours0.0121 days <br />0.291 hours <br />0.00173 weeks <br />3.98764e-4 months <br /> Steve Waldrup

1335 hours0.0155 days <br />0.371 hours <br />0.00221 weeks <br />5.079675e-4 months <br /> Jerry Bowden

1452 hours0.0168 days <br />0.403 hours <br />0.0024 weeks <br />5.52486e-4 months <br /> John williams

1637 hours0.0189 days <br />0.455 hours <br />0.00271 weeks <br />6.228785e-4 months <br /> Carolyn Tynan

1730 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.58265e-4 months <br /> John Williams l

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APPENDIX 2

PERSONS CONTACTED

Licensee Employees

• J. Aufdenkampe, Manager Technical Support

• G. Bockhold, Jr. , General Manager Nuclear Plant

• D. Carter, Shift Superintendent

J. Bowden, Work Planning ,

J. Cash, Unit Superintendent l

M. Chance, Senior Engineer, Engineering Support ,

• S. Chesnut, Technical Support i

C. Coursey, Mair.cenance Superintendent l

W. Diehl, Shif t Supervisor, Operations

Frederick, Safety Audit and Engineering Group Supervisor

,

• G. 1

J. Gasser, Shift Superintendent, Operations

• L. Glenn, Manager. - Corporate Concerns

• D. Gustafson, Maintenance Engineering Supervisor i

J. Gwin, Corporate Systen Engineer

• H. Handfinger, Manager Maintenance

• K. Holmes, Manager Training and Emergency Preparedness  !

• M. Horton, Manager Engineering Support

.

,

B. Kaplan, Senior Engineer, Engineering Support

G. Lee, Plant Engineering Supervisor, Operations

• R. LeGrand, Manager Health Physics and Chemistry

W. Lyons, Quality Concerns Coordinator  ;

• G. McCarley, Independent safety Engineering Group Supervisor

• C. McCoy, Vice-President, Georgia Power Company

• R. Mcdonald, Executive Vice-President, Georgia Power Company l

• D. Moncus, Outage and Planning  ;

• A. Mosbaugh, VEGP Staff '

R. Odom, Nuclear Safety and Compliance Manager l

• A. Rickman, Senior Engineer - Nuclear Safety and Compliance i

• L. Russell, Independent safety Engineering Group, SONOPCO

• M. Shelbani, Senior Engineer  !

• C. Stinespring, Manager Plant Administration

• S. Swanson, Outage and Planning Supervisor  ;

• J. Swartzwelder, Manager Operations -

E. Thorton, Shif t Supervisor, Operations I

• E. Toupin, Oglethorpe Power Corporation .

C. Tynan, PRB Secretary i

S. Waldrup, Planning and Scheduling Supervisor

J. Williams, Shift Superintendent, Operations ,

• Attended exit interview, August 16, 1990.  ;

!

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APPENDIX 2

PERSONS CONTACTED (continued)

! NRC Employees Who Attended Exit Interview

-

R. Aiello, Resident Inspector - Vogtle

B. Bonser, Senior Resident Inspector - Vogtle

M. Branch, Senior Resident Inspector - Watts Bar

R. Carroll, Project Engineer - RIIK. Brockman, Chief, Reacto

i

N. Huneauller, Reactor Engineer - NRRL. Carner, Senior R

0. Matthews,

>

Project Director - NRR

J. Milhoan, Deputy Regional Administrator - RII

R. Starkey, Resident Inspector - VogtleL. Reyes, Directo

P. Taylor, Reactor Inspector - RII

M. Thomas, Reactor Inspector - RII

,

C. VanDenburgh, Section Chief - NRR

J. Wilcox, Operation Engineer - NRR

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APPENDIX 3

LIST OF ACRONYMS i

AOP Abnormal Operating Procedure

ARB. Alternate radwaste building

ASME' American Society of Mechanical Engineers

CAL Confirmation of action letter i

CFC Containment Fan Cooler j

CFR Code of Federal Regulations l

CIV containment isolation valve

DC Deficiency card

DRP Division of Reactor Projects

EDG Emergency diesel generator i

Electric Power Research Institute

'

EPRI

ESF Engineered safety features

ESFAS Engineered safety features actuation system

TSAR Final Safety Analysis Report  ;

NUT Holdup tank

I&C Instrumentation and controls

IFI Inspector follovup iten

IST Inservice test

kV Kilovolt

LCO Limiting condition for operation

LER Licensee Event Report

NWO Maintenance work order

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Regulation

NSCW Nuclear service cooling water

NSSS Nuclear steam supply system

OI Office of Investigations

PM Preventative maintenance

PRB Plant Review Board

psig Pounds per square inch gauge

PVC Polyvinyl chloride

QA Quality Assurance

RII Region II Office

RCS Reactor coolant system

l REA Request for engineering assistance

RG Regulatory Guide ,

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l RHR Residual heat removal

SER Safety Evaluation Report

j SI safety injection

i SONOPCO Southern Nuclear Operating Company

SRM Source range monitor

. SS shift superintendent '

SSS Shift support supervisor

LIMITED DISTRIBUTION - Not For Public Release

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LIMITED DISTRIBUTION - Not For Public Release

DRAPT - PREDECISIONAL INFORMATION

APPENDIX 3 '

LIST OF ACRONYMS (continued)

STS Surveillance task sheet

TCP Temporary change to procedure

TS Technical Specification

USS Unit shift superintendent

UV Undervoltage

VEGP Vogtle Electric Generati!.g Plant

VIO Violation

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LIMITED DISTRIBUTION - Not For Public Release

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