Text

Discusses 970116 Predecisional Enforcement Conference in Region IV to Discuss Apparent Violations Identified in Insp Rept 50-482/96-21.List of Attendees,Licensee Presentation & NRC Handouts Encl
	ML20134A613
Person / Time
Site:	Wolf Creek
Issue date:	01/21/1997
From:	Gwynn T; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:	Carns N; WOLF CREEK NUCLEAR OPERATING CORP.
References
	EA-96-470, NUDOCS 9701290014
	Download: ML20134A613 (148)
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UNITED STATES

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AR LINGTON, TE XAS 76011 8064

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JAN 21 1996

EA 96-470

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Neil S. Carns, President and

Chief Executive Officer

Wolf Creek Nuclear Operating Corporation

}

P.O. Box 411

Burlington, Kansas 66839

SUBJECT:

PREDECISIONAL ENFORCEMENT CONFERENCE (NRC INSPECTION

REPORT 50-482/96-21 AND NOTICE OF VIOLATION)

Dear Mr. Carns:

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This refers to the predecisional enforcement conference conducted in the Region IV office

on January 16,1997. This conference related to the discussion of apparent violations

identified in NRC Inspection Report 50-482/96-21 and was held at the request of

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Region IV.

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The licensee presented a summary of the causes for the apparent violations and their

corrective actions. With respect to the first apparent violation with four examples, the

licensee admitted that four violations had occurred, but disagreed that there was a

programmatic problem. In addition, the licensee stated that the first example was a

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10 CFR 50.71(e) violation, and not a 10 CFR 50.59 violation. For the second apparent

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violation, the licensee admitted that the violation had occurred; however, the licensee did

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not believe that the violation was safety significant. The licensee indicated that the

violation had the same root cause as apparent violation 3 and should, therefore, be

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included in the third violation. For the third apparent violation with nine examples, the

licensee agreed that five of the violations had occurred, but disagreed with four of the

cited examples. Although the licensee provided some information to support this view,

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they were not prepared to provide specific information to support the basis for this view.

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Nevertheless, the licensee agreed that the examples indicated a programmatic breakdown

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in the implementation of their corrective action program. During the meeting, the licensee

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agreed to supply the NRC with additional information identified in Enclosure 1.

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The additional licensee information, the attendance list, the licensee's presentation, the

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meeting agenda, the apparent violations, the inspection report, and a copy of the safety

evaluation for Plant Modification Request PMR 00903, which was provided during the

conference, are enclosed to this summary.

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in accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this

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mmmary and its enclosures will be placed in the NRC Public Document Room.

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9701290014 970121

PDR

ADOCK 05000482

0

PDR

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Wolf Creek Nuclear Operating

-2-

Corporation

Should you have any questions concerning this matter, we will be pleased to discuss them

with you.

Sincerel

Thomas P. Gwynn, Dire tor

Division of Reactor

ty

Docket No.: 50-402

License No.: NPF-42

Enclosures:

1. Additional Licensee information

2. Attendance List

3. Licensee Presentation

4. Meeting Agenda, Apparent Violations, inspection Report

5. Licensee's Plant Modification Request PMR 00903

cc w/ Enclosures 1 & 2:

Neil S. Carns, President and

Chief Executive Officer

Wolf Creek Nuclear Operating Corporation

P.O. Box 411

Burlington, Kansas 66839

Vice President Plant Operations

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, Kansas 66839

Jay Silberg, Esq.

Shaw, Pittman, Potts & Trowbridge

2300 N Street, NW

Washington, D.C. 20037

Supervisor Licensing

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, Kansas 66839

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Wolf Creek Nuclear Operating

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Corporation

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Supervisor Regulatory Compliance

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, Kansas 66839

Chief Engineer

Utilities Division

Kansas Corporation Commission

1500 SW Arrowhead Rd.

' Topeka, Kansas 66604-4027

Office of the Governor

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State of Kansas

Topeka, Kansas 66612

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Attorney General

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Judicial Center

301 S.W.10th

2nd Floor

Topeka, Kansas 66612-1597

County Clerk

Coffey County Courthouse

Burlington, Kansas 66839-1798

Public Health Physicist

Division of Environment

Kansas Department of Health

and Environment

Bureau of Air & Radiation

Forbes Field Building 283

Topeka, Kansas 66620

Mr. Frank Moussa

Division of Emergency Preparedness

2800 SW Topeka Blvd

Topeka, Kansas 66611-1287

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Project Engineer (DRP/B)

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Branch Chief (DRP/TSS)

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Leah Tremper (OC/LFDCB, MS: TWFN 9E10)

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DOCUMENT NAME: G:\\EB\\ MEETINGS \\WCECMTG. PAG

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ENCLOSURE 1

ADDITIONAL INFORMATION THE LICENSEE AGREED TO SUPPLY DURING THE

ENFORCEMENT CONFERENCE

This information consisted of the following:

A list of errors that the licensee found in the inspection report.

Information on the applicability of the safety evaluation for Plant Modification

Request PMR 00903 to the essential service water strainers differential pressure.

The number of hours that the two centrifugal charging pumps were operable and

the licensee's procedures that put one of the pumps in the pull to lock position from

the second apparent violation.

Clarifying information on examples three, four, six, seven and nine of the third

apparent violation.

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ENCLOSURE 2

UST OF PERSONNEL ATTENDING EA 96-470 ENFORCEMENT CONFERENCE,

JANUARY 16,1997

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PREDECISIONAL ENFORCEMENT CONFERENCE ATTENDANCE

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LICENSEE / FACILITY

Wolf Creek Nuclear Operating Corporation

DATE/ TIME

January 16. 1997. 1 p.m.

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CONFERENCE LOCATION

Region IV, Arlington. Texas

EA NUMBER

EA 96-470

NRC REPRESENTATIVES

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PREDECISIONAL ENFORCEMENT CONFERENCE ATTENDANCE

LICENSEE / FACILITY

Wolf creek Nuclear operating corporation

DATE/ TIME

January 16. 1997. 1 p.m.

CONFERENCE LOCATION

Region IV Arlington, Texas

EA NUMBER

EA 96-470

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ENCLOSURE 3

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COPY OF SLIDES PRESENTED BY WOLF CREEK NUCLEAR OPERATING CORPORATION

DURING PREDECISIONAL ENFORCEMENT CONFERENCE EA 96-470, JANUARY 16,1997

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January 16,1997

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Agenda

Opening Comments: Clay Warren, Chief Operating Officer

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Engineering issues:

Rick Muench, Vice President Engineering

- Proposed Violation of 50.59:

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e ESW backwash setpoints

e Frequency of RCP Flywheel Inspections

e ESW underground piping test requirements

e Frequency of turbine valve testing

Operations issues: Chris Younie, Manager Operations, and

Kevin Davison, Supervisor Operations Support

- Proposed violation of Technical Specifications due to two CCPs being

Operable

- Proposed violation for inadequate corrective action from Performance

improvement Request 93-0131 regarding weaknesses found in the

Technical Specification Clarification program

Closing Statements: Britt McKinney, Plant Manager

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Proposed 50.59 Violation

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e WCNOC agrees that four Level IV

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violations occurrec

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e WCNOC's position is that aggregation is

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not consistent with NUREG 1600 due to:

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Unique circumstances

Non-programmatic root causes

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No safety significance

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Incidence rate is relatively low

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Proposed 50.59 Violation

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e Three of the four examples occurred prior to

imalementation of the revisec USQD procecure

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issued in 1995 and related training which

occurred during 1996

e Incidence Rate

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1996 E&TS results:

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-23 USQDs reviewed with one discrepancy in the

level of documentation; however the conclusion

was accurate

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Proposed 50.59 Violation

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e Incidence Rate

-29 regulatory screenings reviewed with three

examples of inaccurate conclusions; one example

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being from 1985; one impacting 50.71(e) not 50.59

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Auxiliary Feedwater System Functional Assessment

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results:

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-237 design packages reviewed with nine

discrepancies identified - no cases where the

conclusions were incorrect

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e No 50.59 programmatic issue

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ESW Backwash Setpoints

e WCNOC agrees that a change was made to

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the facility that should have been incorporated

into the USAR

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e USQD performed for the modification

e This is a 50.71(e) USAR update issue not

50.59

e Root Cause

Personnel error in completing the Licensing

Screening Form

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ESW Backwash Setpoints

e Safety Significance:

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No safety significance: As the vendor

originally recommended, strainer backwash

is initiated at a pressure drop of 2 psid

greater than the clean pressure drop

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Actual backwash pressure is significantly

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higher (144 psid) than the 21 psid

assumed by the vendor

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ESW Backwash Setpoints

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o Corrective Actions

USAR change request initiated

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53 change packages from the same time period we e

reviewed with no additional USAR update errors fotnd

Confidence that the ESW SFA would have discovered

this error

o Re.ated Corrective Actions

Regulatory procedures and training program changes

since 1985

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Compliance culture training in 1997

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RCP FlywheelInspections

e WCNOC made an exception to

Regulatory Guide 1.14 regarding the

frequency of RCP Flywheel Inspections

without prior NRC approval

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e Root Cause:

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Personnel error: Inappropriate application

of regulatory guidance

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RCP FlywheelInspections

e Safety Significance

No significance: Three year UT of the RCP

flywheel bore and keyway was completec

satisfactorily

o Corrective Actions:

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Operability evaluation performed

License amendment requestec

USAR change initiated

Compliance culture training in 1997

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Turbine Valve Testing

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e Documentat.on in a USQD was

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incomplete to support the conclusion

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e Root Cause

Personnel error

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Turbine Valve Testing

e Safety Significance

A change in the frequency of the testing does

not increase the probability of an accicent

Failure of the turbine does not effect safety

related equipment

Operating experience

e Corrective Actions

USQD revised to include adcitional information

Work product evaluations

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ESW Underground Pipe Testing

e The Essential Service Water (ESW)

System is a rec undant system as stated in

the USAR

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o Each train of the ESW System is a non-

rec undant system

o There is no regulation, regulatory

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guidance, code guidance or Wolf Creek

license basis that requires that these two

c efinitions be consistent

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ESW L~nderground Pipe Testing

e The ESW System underground piping test is

consistent with the ASME Code

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e The change in the ESW underground piping

test does not require NRC prior approval

e In Part 9900 of the Inspection Manual, NRC

reserves the right to disagree with the

application of the ASME Code

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ESW Underground Pipe Testing

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e The NRC has verbally indicated to Wolf Creek

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that they do not agree with this use of the

Coc e

e Recommend that the NRC cocument their

position to the industry

e Wolf Creek performed an operability

evaluation.

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ESW pump test - system pressurized to normal

operating pressure

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ESW Underground Pipe Testing

No measurable changes in system parameters

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which would indicate the presence of measurable

leakage

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Overall structural integrity has been evaluated to

not be a problem

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w Leakage exceeding acceptance criteria would be

evident

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o Action

Wolf Creek will revise the test procedure for

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Refuel IX

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Summary

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Is s u e

Date

Circ u m sta n ces

A d eq u ate

A d e q u a te

USAR

R elief

R e q u e st/Lic e n s e

R e g u la to ry

USQD

Updated

S c re e n in g

P erfo rm ed

Requested

RCP

2/95

Misapplication of ;(N

Yes

No

F lyw h e el

N R C G uidance

^

Und rg ound

11/95

"^

^

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D f ni ion

Piping

ESW

7

(

Backwash

1985

I Personnel Error

No

Yes

No

N/A

S e p oin ts

Turbine

in com plete

T h ro ttle

6/96

D o cu m e n ta tio n

Yes

No

Yes

N/A

Valve Testing

F req u e n cy

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New USQD Training / Regulatory Screening Procedure: September 1995

USQD/ Regulatory Screening Training: December 1995 - December 1996

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Work Product Evaluations Start: July 1996

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Summary

e WCNOC agrees there are three examples of

50.59 errors and one example of a 50.71(e)

error; however WCNOC disagrees that they

indicate a programmatic breakdown of the

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50.59 process

e WCNOC considers aggregation not consistent

with the NUREG 1600, and that each of the

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examples is a reasonable Level IV violation

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Operation's Concerns

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Chris Younie and Kevin Davison

WCNOC Operations

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Technical Specification Violation

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e It is Wolf Creek's position that TSC 009-85

is an additional example of ineffective

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corrective action, not a separate violation.

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This is based on:

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All TSC problems stem from a single root

cause and

There are no special circumstances that

separate TSC 009-85 from the TSC issues

reported

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Technical Specification Violation

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o Technical Specification Clarification 009-85

allowed operation of both CCPs in Mode 5

which when performed in 1985 and 1994

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conflicted with Technical Specifications

(TS 3.5.3/3.5.4)

Duration of both CCPs operable is limitec to 8

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minutes

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Technical Specification Violation

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e Safety Significance

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a There is no safety significance to

performing this evolution

A single PORV has sufficient capacity to

relieve the mass addition of 2 CCPs without

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exceeding 10 CFR 50 Appendix "G" limits

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Technical Specification Violatign

e The Incident Investigation Team

cetermined the root cause was

WCNOC's organizational culture was

misaligned with the regulatory

environment. This misalignment was

evidenced in the following areas.

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Technical Specification Violation

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Technical Specification Application

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-Wolf Creek's " mind set" was to assess plant

conditions and utilize operational knowledge in

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the application of Technical Specifications

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Misapplication of the TSC Process

-This misapplication resulted in instances where

the clarification resulted in a change to

Technical Specifications without prior regulatory

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approval.

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Technical Specification Vio:Lation

Standards

-This " mind set" also influenced the standards

applied to TSC review, approval and internal

assessment of the health of the TSC process

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Technical Specification Violation

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e This apparent violation should be

combined with apparent violation 9621-06

as an example of inadequate corrective

action since:

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There are no special circumstances that

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separate this occurrence from the other TSCs

reported

The root cause and corrective actions apply to

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all TSC concerns

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Inadequate Corrective Actions

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e WCNOC identified weaknesses in 1993

with specific TSCs and with the TSC

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process. The corrective actions did not

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prevent recurrence or identify all existing

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problems

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e Wolf Creek agrees that TSC 009-85 and

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the other inappropriate TSCs reported

constitutes inadequate corrective action

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Inadequate Corrective Actions

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o Safety Significance

TSC 009-85 allowed two CCPs to be operable in

modes 4,5, and 6

- No safety significance since a single PORV has sufficient

capacity to relieve the mass addition of two CCPs without

exceeding Appendix "G" limits

TSC 010-85 allowed for daily containment

inspections vice per entry inspections

'

- No safety significance since Generic Letter 93-05 (Line

Item TS improvements) allows for daily inspections. A

License Amendment Request has been generated

___

______

_ _ _ _ _ _ _ _ _ _ _ _ _ _

i

Inadequate Corrective Actions

.

I

o Safety Significance (continued}

TSC 033-85 allowed containment penetration vent

and drain valves to be opened without considering

that evolution to be a breach of containment

4

'

integrity provided dedicated operators were

,

!

stationed to close the valves

l

'

- Low safety significance since dedicated operators were

assigned. No release resulted from LLRT activities

j

- Administrative requirements existed requiring valves to be

closed if direct communication with the Control Room was

lost

i

1

>

-

- - - - - -

--

-o

.-

. - - - _ _ - _ _ _ _ _ _ - _ _ _ _ _ - _

r

>

,

Inadequate Corrective Actions

,

.

i

.

e Safety Significance (continued)

TSC 004-86 allowed ECCS Accumulators to be

considered operable based on contained volume

and pressure vice absence of alarms as previously

.

required

i

-Low safety significance since Technical

'

Specification required water volume and

pressure was maintained. Amendment 103

issued 11/22/96 allowing this condition

.

i

i

- - - - - - - - - -

-

- - -

-

- - -

- - - -

-

------ ---------

- - - -------------

_ _ _ _ _ _ _

-

_

_ -

_

_ _

. -

-

.

Inadecuate Corrective Acti ns

e Safety Significance (continued}

TSC 016-86 allowed hydrostatic testing between

first off and second off boundary valves with

,

'

required temperature control

- Low safety significance since hydrostatic

'

pressure for these test is less than cold hydro

pressure. The piping in these areas is not

subject to embrittlement

.

s

. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _

______:.

_

_ _ _ _

,

Inadequate Corrective Actions

-

,

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!

)

e Safety Significance (continued}

TSC 005-94 EDG allowed Hot Restart testing to be

separated from the 24 run if a pre-warming diesel

'

i

run was conducted

-Low safety significance since previous

j

surveillance requirement allowed credit for the

24 diesel run if the Hot Restart test was not

successful. Amendment 101 separated Hot

Restart testing from the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months run

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Inadequate Corrective Actions

'

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. . . a

a.

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^5

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o Root Cause

j

The root cause for inadequate corrective

i

action is a misalignment between the

organizational culture and the regulatory

environment

A mind set existed which used operational

knowledge in the application of Technical

1

Specifications, and in some cases

compromised literal compliance

.

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- -

-

- - -

-

_

_ _ . _

. _ _ _

_

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TSC Corrective Actions

- ---

_

_ _ _

e immediate Corrective Actions:

WCNOC performed an extensive evaluation

of the existing TSCs and the TSC

i

procedure

i

-WCNOC identified five additional instances

j

where Technical Specifications were violated.

LERs were submitted for these instances

i

>

e Three TSC were reviewed and found to nolviolate

l

Technical Specification requirements and did not

l

constitute a change to the existing specifications

(TSC 026-85 - QPTR; TSC 001-94 - Source Range;

TSC 002-96 - Source Range Power Supplies)

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-

.

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_

- _ _

_

-

- -

.

_. _-

.

_

TSC Corrective Actions

>.J-lM

32 - -

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, _ _

_

___ _

P

e immediate Corrective Actions ('continuec):

This review identified ten TSCs which were no

-

longer needed and one TSC which was overly

conservative. These TSCs have been deleted

.

(Total of 17 deleted)

.

Three TSC were identified as needing revision

l

-

Chief Operating Officer issued letter to all

personnel detailing expectations for

compliance with requirements

>

.

-

}

TSC Corrective Actions

3

_ _ ___

__

e immediate Corrective Actions (continued):

g

An Incident Investigation Team was

,

chartered to determined the root cause and

appropriate corrective actions

.

)

o Additional Corrective Actions:

Improved Standard Technical Specification

program underway

Safety System Functional Assessments,

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previously committed to, will confirm that

these corrective actions are appropriate

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--

TSC Corrective Actions

,

_ . ~ - ic

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' <;. .

_ _ _

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-

e Adcitional Corrective Actions (continued):

All site personnel will mee: with Chief

Operating Officer to reinforce expectations

for compliance with requirements

Cultural Survey will determine con ~:ent of

future compliance training

.

f

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.

. .

.

._ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ .-._ _ _ _.

Summary

_

-

o Wolf Creek's position is that apparent

I

violations 9621-05 and 06 should be

r

i

combined into a single violation of

inadequate corrective action

-

o Wolf Creek acknowledges weaknesses

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,

i

in our Corrective Action Program

Corrective Actions for this weakness were

i

discussed with NRC staff on December 6,

i

1996

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_ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _

.

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Summary

-

,

__

b

o Corrective Actions taken were prompt

and comprehensive

e Low safety significance

o Recent examples of site-wide

)

identification of literal compliance issues

demonstrates acceptance of

I

!,

implemented Corrective Actions.

.,

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_ _ _ _ _ _ _ _ _

__

_ _______

_ _ _ .

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Summary Statements

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Britt McKinney

WCNOC Plant Manager

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--- - -- --- - ----_ - _

-.

-- -

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Summary Statements

,

!

o WCNOC Culture:

j

Management fosters a favorable

}

environment to raise issues

Literal Compliance:

- October 1996: Chief Operating Officer and

Plant Manager meet with PSRC

- November 1996: Chief Operating Officer

notification (letter) to Station employees

!

-

- - . _ . - -

-

i

Summary Statements

e WCNOC understands the problem

.

'

e Initiatives to improve organizational performance:

NSRC and PSRC membership strengthened:

- New Chair on each committee

- Use of industry experience

- Line organization ownership of issues

'

- Quarterly review of selected plant safety topics

System Self Assessments on key systems:

}

'

- Design basis review

-Technical Specification review

USA conducting SA/QV (1/6/97 to 1/17/97)

,

.

. .

.

. .

.

- . _ - _ _ - -

_- - .

- -

-

_ _ . ..

.

!

Summary Statements

Corrective Action Program changes:

-Electronic initiation allows ease of tracking and

trending all PIRs (10-14-96)

-PIR coordinators assigned to each group (in place)

l

-Corrective Action Review Board (in place)

- Resource loading of PIRs (1st qtr '97)

,

- FPI employee culture survey (1st qtr '97)

FPI Root Cause and Causal Factor training for PIR

coordinators and line managers (1st qtr '97)

MARC training for supervisors / managers (1st qtr '97)

.

- - _

- - . . _ _ _ . .

-_

_

.

_ . _

_ _ _ _ . . . _ _ _ _ _ _ . _ _

Summary Statements

l

e Mitigating factors:

Low Safety Significance on the individual items

discussed in the violations

Equipment remained operable and coulc 3erform its

safety function

No evidence of significant scope and content

areakdown/inacec uacy in the USAR/ Technical

Specifications

>

Control of the Licensing Basis is occurring

l

No modifications required to restore Design Basis

All occurred before listed initiatives began

,

i

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f

i

ENCLOSURE 4

NRC MEETING AGENDA, APPARENT VIOLATIONS, AND INSPECTION REPORT SUPPLIED

DURING PREDECISIONAL ENFORCEMENT CONFERENCE EA 96-470, JANUARY 16,1997

l

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4

PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA

CONFERENCE WITH WOLF CREEK OPERATING CORPORATION

JANUARY 16. 1997

NRC REGION IV. ARLINGTON, TEXAS

1.

INTRODUCTIONS /0PENING REMARKS - T.P. GWYNN. DIRECTOR DIVISION OF REACTOR

SAFETY

2.

ENFORCEMENT PROCESS - M. VASQUEZ. ENFORCEMENT SPECIALIST

3.

APPARENT VIOLATIONS & REGULATORY CONCERNS - K.E. BROCKMAN. DEPUTY

DIRECTOR DIVISION OF REACTOR SAFETY

4.

LICENSEE PRESENTATION

5.

BREAK (10. MINUTE NRC CAUCUS IF NECESSARY)

6.

RESUMPTION OF CONFERENCE

7.

CLOSING REMARKS - C. WARREN. WCNOC

8.

CLOSING REMARKS - T.P. GWYNN. DIRECTOR DIVISION OF REACTOR SAFETY

4

-

APPARENT VIOLATIONS *

PREDECISIONAL ENFORCEMENT CONFERENCE

j

'

WOLF CREEK GENERATING STATION

JANUARY 16,

1997

NOTE: THE APPARENT VIOLATIONS OlSCUSSED AT THIS PREDECISIONAL ENFORCEMENT

CONFERENCE ARE SUBJECT TO FURTHER REVIEW AND MAY BE REVISED PRIOR TO ANY

RESULTING ENFORCEMENT ACTION.

._ _._ _

. _ _ . . _ _ _

_ _ _ _ _ _ _ _ .

l

APPARENT VTOLATION

FIRST APPARENT VIOLATION

1.

10 CFR 50.59 (a)(1) allows the holder of a license to make changes to

the facility and procedures as described in the final safety analysis

report without prior Commission approval unless the proposed change

involves a change in the Technical Specifications or an unreviewed

safety question.

10 CFR 50.59(b)(1) requires that the licensee shall

maintain records of changes to the facility and that these records

include a written safety evaluation which provides the basis for the

determination that the change does not involve an unreviewed safety

question.

10 CFR 50.59 (c) requires licensees to submit an ap)lication

for an amendment for changes which involve a change to the Tec1nical

Speci fications.

Contrary to the above.

1.

On March 13. 1984 the licensee issued Set Point Change Request

,

EF-84-01. which changed the operation of the essential service

water self cleaning strainer as described in Table 9.2-5 of the

U] dated Safety Analysis Report, without a determination that the

c1ange did not involve an unreviewed safety question.

Specifically. Table 9.2-5 specified that the set point for

l

initiation of the backwash was 3.0 psi whereas the set point

change allowed a new setpoint of approximately 5.0 psi.

This

i

resulted in operation of the system contrary to the Updated Safety

'

Analysis Report description through October 25. 1996.

,

2.

On January 11. 1995, the licensee issued Updated Safety Analysis

Report Change Request 95-003 which revised Chapters 3A and 5.4.-1

l

of the Updated Safety Analysis Report to include an exemption to

Regulatory Guide 1.14. " Reactor Coolant Pump Flywheel Integrity."

!

commitments for scheduled surface and ultrasonic examinations of

reactor coolant pump flywheels. The licensee failed to properly

determine that this change involved a change to the Technical

Specifications.

Specifically the Regulatory Guide schedule, as

specified by reference in Technical Specification 4.4.10. which

l

was superseded by Technical Specification 6.8.5.b on October 2.

1995. required the flywheel surface and ultrasonic examination at

,

approximately 10-year intervals.

This schedule was changed to 12

years without prior NRC approval.

The change resulted in a

failure to meet the requirements of Technical Specifications 4.4.10 and 6.8.5.b for the 10-year inspection of the "D" Reactor

Coolant Pump Flywheel.

3.

On December 13. 1995. the licensee's screening for revisions to

Procedures STS PE-049C. "A Train Underground Essential Service

Water System Piping Flow Test." and STS PE-049D. "B Train

Underground Essential Service Water System Piping Flow Test."

{

failed to indicate that Chapter 9.2 of the Updated Safety Analysis

Report was affected by the change.

The procedure changes

i

THIS APPARENT VIOLA, <0N IS SUBJECT TO FURTHER REVIEW AND MAY BE

l

REVISED

f

.

_

._

_ _ _

_ . . .

_

_ _ - -

._ . - _ _ . _ .

_.

_ _ . _ .

__

_

APPARENT VIOLATION

,

reclassified the systems as non-redundant whereas the Updated

Safety Analysis Report. provided a description of the essential

service water system as redundant.

As a result, the licensee

failed to either submit a request for an alternative to the

inservice inspection requirements or to process a change to

Chapter 9.2 of the Updated. Safety Analysis Report and determine

whether the change involved an unreviewed safety question.

4.

On March 26, 1996, the licensee performed a 10 CFR 50.59

unreviewed safety question determination regarding changing the

main turbine overspeed protection test frequency from every 7 days

to every 92 days, without providing supporting documentation to

conclude that an unreviewed safety question was not involved.

The

unreviewed safety question determination did not address the

licensee's experience with the testing of these valves and did not

contain any information as to the acceptability by the turbine

vendor, of the decreased surveillance frequency of the turbine

valves.

THIS APPARENT VIOLATION IS SUBJECT TO FURTHER REVIEW AND MAY BE

REVISED

-. .

_

. - _ - - . -

. - . - = _ . .

. - - . - . . - . - .

. . . . .

. - . - . . _ = . . . . . - .

d

i

APPARENT VIOLATION

,

)

SECOND APPARENT VIOLATION

i

a

2.

Technical Specification 3.5.4 requires one centrifugal charging pump be

!

inoperable when in cold shutdown (Mode 5) with the reactor vessel head

on.

,

Contrary to the above. on October 24. 1994. March 22. 1996, and

j

March 26, 1996, the licensee maintained two centrifugal charging pumps

operable while the plant was in cold shutdown with the reactor vessel

head on.

These actions were performed as allowed by plant procedures

!

which were revised in accordance with licensee interpretations of

j

Technical Specification requirements.

.

4

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6

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THIS APPARENT VIOLATION IS SilBJECT TO FURTHER REVIEW AND MAY BE

REVISED

1

.

APPARENT VIOLATION

THIRD APPARENT VIOLATION

3.

Criterion XVI of Appendix B to 10 CFR Part 50 requires. in part. that

measures be established to assure that conditions adverse to quality are

promptly identified and corrected.

Contrary to the above. on March 31. 1994, the licensee's corrective

actions in response to Quality Assurance Audit K381 findings regarding

the use of technical specification interpretations which could

potentially conflict with Technical specification requirements or

operability determinations, were not adecuate to identify potential

conflicts between the interpretations anc the Technical Specifications.

Specifically. the licensee's screenings of Technical Specification

Clarifications listed below, which were performed to resolve the

concerns of the Quality Assurance audit findings and which involved

changes to the Technical Specifications, failed to properly determine

that changes to the Technical Specifications were involved.

As a

result, prior Commission approval to change the Technical Specifications

was not obtained prior to implementation which resulted in non-

compliances with Technical Specification requirements.

1.

Technical Specification Clarification 009-85 allowed two

centrifugal charging pumps to be available while in cold shutdown.

This clarification involved a change to Technical Specification 3.5.4 which specified only one centrifugal charging pump be

operable in cold shutdown.

This change was implemented without

prior Commission approval.

Utilization of this clarification

resulted in non-compliance with the Technical Specifications on

October 24. 1994: March 22. 1996: and March 26. 1996.

2.

Technical Specification Clarification 010-85 allowed daily

containment closeout inspections following multiple containment

entries in one day.

This clarification involved a change to

Technical Specifications 3.5.3 and 4.5.2 which specify a

containment visual inspection for loose debris be performed

following each containment entry.

3.

Technical Specification Clarification 026-85 allowed increasing

power while the Quadrant Power Tilt Ratio exceeded the prescribed

limit of 1.02.

This clarification involved a change to Technical Specification 3.2.4.a.4 which prohibited increasing power with the

Quadrant Power Tilt Ratio greater than 1.02.

4.

Technical Specification Clarification 033-85 allowed containment

penetrations be considered operable if dedicated operators were

assigned to close inoperable containment isolation valves.

This

clarification involved a change to Technical Specification 3.6.1.1

which specified that all containment penetrations be operable by

automatic isolation valves.

THIS APPARENT VIOLATION IS SUBJECT TO FURTHER REVIEW AND MAY BE

REVISED

_

-

. _ .

. _ _ _

_ _ _ _

. _ _

_ _ _

_

9

4

i

APPARENT VIOLATION

5.

Technical Specification Clarification 004-86 allowed cold leg

accumulators be considered operable upon receipt of level and

pressure alarms if accumulator level and pressure was within

.

prescribed limits.

This clarification involved a change to

Technical Specification Surveillance Requirements 4.5.1 and 4.0.3

s

1

which required the accumulators be considered inoperable upon

receipt of alarms.

Utilization of this clarification resulted in

!

non-compliance with the Technical Specifications on September 25.

1996.

,

6.

Technical Specification Clarification 001-94 allows the reactor

coolant system to be cooled down, an activity which involves a

.

positive reactivity change, with one source range channel of

1

nuclear instrumentation inoperable.

This clarification involved a

change to Technical Specification 3.3.1 which specified that with

4

i

one source range channel ino)erable, all operations involving

j

positive reactivity changes se suspended.

4

i

7.

Technical Specification Clarification 004-94 deleted emergency

i

diesel generator testing of the redundant diesel if the inoperable

diesel was rendered inoperable by a support system failure.

This

clarification involved a change to Technical Specification 3.8.1.1

which specified that the redundant emergency diesel generator be

,

tested within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if one emergency diesel generator was

i

inoperable for any reason except for preplanned preventative

j

maintenance, testing, or maintenance to correct a deficiency

!

which. if left uncorrected. would not affect the operability of

the diesel generator.

,

!

8.

Technical Specification Clarification 005-94 allowed hot restart

testing of an emergency diesel generator be performed any time

!

before or after the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months load test as long as the hot restart

test was performed within 5 minutes of a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months diesel run.

This

clarification involved a change to Technical Specification 4.8.1.1.2.g.7 which specified that a hot restart test be performed

4

within 5 minutes following the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months test. Utilization of this

j

clarification resulted in non-compliance with the Technical

i

Spec fications on October 15. 1994: October 17. 1994: March 23.

1996: and March 26. 1996.

-

!

9.

Technical Specification Clarification 00e96 allows one of the two

required source range neutron flux monitors to be considered

)

operable when in the refueling condition when powered from a non-

l

safety related power supply.

This clarification involved a change

to Technical Specification 3.9.2 which specifies that two source

.

range neutron flux monitors to be operable and powered by its

}

normal safety related power supply when in the refueling

condition.

i

.

!

THIS APPARENT VIOLATION IS SUBJECT TO FURTHER REV"

AND MAY BE

REVISED

.

k" " MW

UNITED ShTES

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NUCLEAR REGULATORY COMMISSION

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611 RYAN PLAZA DRIVE, sulTE 400

k...../

AR LINGToN. T E xAS 76011-8064

December 31,1996

EA 96-470

Neil S. Carns, President and

Chief Executive Officer

Wolf Creek Nuclear Operating Corporation

P.O. Box 411

Burlington, Kansas 66839

SUBJECT: NRC INSPECTION REPORT 50-482/96-21 AND NOTICE OF VIOLATION

Dear Mr. Carns:

An NRC inspection was conducted October 7-11 and 21-25,1996, at your Wolf Creek

Generating Station reactor f acility. The enclosed report presents the scope and results of

that inspection. The overall conclusions of the inspection were discussed with

Mr. O. Maynard and others of your staff on October 25,1996. An exit meeting was held

with your staff on November 8,1996. In addition, the overall results of this inspection

were discussed with Mr. Terry Damashek, on December 31,1996.

The inspection team found numerous problems in your implementation of the

10 CFR 50.59 review process, which resulted in the use of incorrect Technical

Specification clarifications, the failure to perform required inservice inspection and testing,

and operating the f acility differently than described in the Updated Safety Analysis Report.

Design basis notebooks were found to be uncontrolled and out-of-date, which hindered

your staff's ability to access design basis information. As a result, your staff had difficulty

retrieving and communicating design information and using this information to support

subsequent engineering calculations, modifications, adequate surveillance testing, and

operability determinations.

Although system engineer knowledge was excellent, it appeared to be the result of the

personalinitiative taken by system engineers and their immediate supervisors, and not the

result of any specific management guidance or administrative requirement. Training

guidance was found to be very general and did not provide a minimum standard for system

engineer training or knowledge. Communication of management expectations for system

!

engineering had improved; however, the previous NRC engineering inspection performed in

!

May 1995, found similar weaknesses in the management and supervisory oversight of the

I

system engineering program, indicating ineffective corrective action.

I

!

The inspection identified several violations of NRC requirements involving: (1) f ailure to

maintain design control, in that, the containment air cooler heat removal calculations

assumed incorrect essential service water flow rates; (2) the f ailure to follow administrative

1

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, -

- _ _ _ _ - - . _ - _ - . - - - - - -

- _ - . . - _ _ - -

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{

Wolf Creek Nuclear Operating

-2-

l

Corporation

j

procedures for performing operability determinations; and (3) the failure to implement

,

Technical Specification surveillance requirements regaiding verification of the correct

position of mechanical position stops. The violations are cited in the enclosed Notice of

Violation (Notice) and the circumstances surrounding the violations are described in detail

in the enclosed report. Please note that you are required to respond to this letter and

should follow the instructions specified in the enclosed Notice when preparing your

response. The NRC will use your response, in part, to determine whether further

enforcement action is necessary to ensure compliance with regulatory requirements.

The inspection also identified three apparent violations that are being considered for

escalated enforcement action in accordance with the " General Statement of Policy and

Procedure for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600.

Specifically, the first apparent violation involved four examples where your 10 CFR 50.59

safety review process f ailed to properly determine that changes to your facility, as

described in the Updated Safety Analysis Report, and changes to the Technical

Specifications were involved. As a result, a determination that an unreviewed safety

question did not exist or prior NRC approval was not obtained before the changes were

implemented. The second apparent violation involved plant operation in the cold shutdown

condition for an extended period with two centrifugal charging pumps operable contrary to

Technical Specification requirements. The third apparent violation involved inadequate

corrective action for a quality assurance finding regarding the use of Technical

Specification interpretations, which failed to identify and correct conflicting positions

between the interpretations and the Technical Specifications. These examples indicate a

potential programmatic breakdown of the design control process, which also involved a

f ailure of the Plant Safety Review Committee to identify the problem. The examples are

discussed in detail in Sections E2.2, E2.3, and E2.7 of the enclosed inspection report. In

i

addition, please be advised that the number and characterization of apparent violations

described in the enclosed inspection report may change as a result of further NRC review.

A predecisional enforcement conference to discuss these apparent violations has been

scheduled for January 16,1997. This conference will be open for public observation in

accordance with a recent change to the enforcement policy (61FR65088). The decision to

hold a predecisional enforcement conference does not mean that the NRC has determined

that a violation has occurred or that enforcement action will be taken. This conference is

being held to obtain information to enable the NRC to make an enforcement decision, such

as a common understanding of the facts, root causes, missed opportunities to identify the

apparent violation sooner, corrective actions, significance of the issues and the need for

lasting and effective corrective action. In addition, this is an opportunity for you to point

out any errors in our inspection report and for you to provide any information concerning

your perspectives on: 1) the severity of the violations,2) the application of the f actors

that the NRC considers when it determines the amount of a civil penalty that may be

assessed in accordance with Section VI.B.2 of the Enforcement Policy, and 3) any other

application of the Enforcement Policy to this case, including the exercise of discretion in

accordance with Section Vll.

l

1

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.,.

,

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_ _ _ .

_,.

-

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,

Wolf Creek Nuclear Operating

-3-

Corporation

You will be advised by separate correspondence of the results of our deliberations on this

matter. No response regarding these apparent violations are required at this time.

,

In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter,

its enclosure and your response will be placed in the NRC Public Document Room (PDR).

To the extent possible, your response should not include any personal privacy, proprietary,

or safeguards information so that it can be placed in the PDR without redaction.

,

Should you have any questions concerning this inspection, we will be pleased to discuss

them with you.

'

,

j

Sincerely,

i

/s/

i

l

Thomas P. Gwynn, Director

i

Division of Reactor Safety

Docket No . 50-482

License No. NPF-42

Enclosures:

Notice of Violation

NRC Inspection Report

50-482/96-21

,

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]

cc w/ enclosures:

Vice President Plant Operations

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

-

Burlington, Kansas 66839

i

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Jay Silberg, Esq.

Shaw, Pittman, Potts & Trowbridge

2300 N Street, NW

Washington, D.C. 20037

,

Supervisor Licensing

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, Kansas 66839

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Wolf Creek Nuclear Operating

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Corporation

Supervisor Regulatory Compliance

Wolf Creek Nuclear Operating Corp.

P.O. Box 411

Burlington, Kansas 66839

Chief Engineer

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Utilities Division

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Kansas Corporation Commission

1500 SW Arrowhead Rd.

Topeka, Kansas 66604-4027

Office of the Governor

State of Kansas

Topeka, Kansas 66612

Attorney General

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Judicial Center

301 S.W.10th

2nd Floor

Topeka, Kansas 66612-1597

County Clerk

Coffey County Courthouse

Burlington, Kansas 66839-1798

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Public Health Physicist

Division of Environment

Kansas Department of Health

and Environment

Bureau of Air & Radiation

Forbes Field Building 283

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Topeka, Kansas 66620

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Mr. Frank Moussa

Division of Emergency Preparedness

2800 SW Topeka Blvd

Topeka, Kansas 66611-1287

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ENCLOSURE 1

NOTICE OF VIOLATION

Wolf Creek Nuclear Operating Corporation

Docket No.-

50-482

Wolf Creek Generating Station

License No.- NPF-42

During an NRC inspection conducted on October 7-11 and 21-25,1996, three violations of

NRC requirements were identified. In accordance with the " General Statement of Policy

and Procedure for NRC Enforcement Actions," NUREG-1600, the violations are listed

below:

A.

10 CFR 50, Appendix B, Criterion 111, requires, in part, that measures be established

to assure that regulatory requirements and the design basis are correctly translated

into specifications, drawings, procedures, and instructions. These measures shall

include provisions to assure that appropriate quality standards are specified and

included in design documents.

Contrary to the above, on October 18,1996, the design basis was not correctly

translated into specifications for Configuration Change Package 07111, Revision 1,

which was approved with an incorrect assumed essential service water flow rate.

Specifically, the basis for the suitability of the containment air coolers with reduced

heat removal capacity used calculations with an assumed essential service water

flow rate of 4000 gpm rather than the actual flow rate of 2000 gpm available to the

coolers.

This is a Severity Level IV violation (Supplement 1) (50-482/96021-01).

B.

Criterion V of Appendix B to 10 CFR Part 50 requires, in part, that activities

affecting quality shall be prescribed by documented instructions, procedures, and

drawings appropriate to the circumstances, and shall be accomplished in

accordance with these instructions, procedures, or drawings.

Procedure ADM 02-024, " Technical Specification Operability," requires operability

determinations to include a determination of the requirement or commitment

established for the equipment.

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Contrary to the above, on October 22,1996, at 2:10 pm, the shif t supervisor

reviewed a statement that listed conflicting Updated Safety Analysis Report,

Technical Specification and Calculation GN-MW-005 information, which pertained

to containment air cooler essential service water flow rates, and performed an

operability determination without including the requirement established for

the equipment. Specifically, the shif t supervisor relied on an out-of-date

Calculation GN-MW-005, which. assumed a cooler group (i.e., two coolers) flow

rate of 4000 gpm, instead of determining the actual requirement for containment air

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cooler group essential service water flow rate of 2000 gpm.

This is a Severity Level IV violation (Supplement I)(50-482/96021-05).

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C.

Technical Specification 6.8.1.a states, in part, that written procedures shall be

established, implemented and maintained, covering the applicable procedures

recommended in Appendix A of Regulatory Guide 1.33, Revision 2.

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Regulatory Guide 1.33,' Appendix A, Section 3.n, requires procedures for startup,

operation, and shutdown of the chemical and volume control system.

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Procedure STS BG-004, "CVCS Seal injection and Return Flow Balance,"

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Revision 4, provides procedural guidance for setting the positions of sealinjection

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throttle valves BGV-198, BGV-199, BGV-200, and BGV-201, and performing

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Technical Specification Surveillance Requirement 4.5.2.g (verifying the correct

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position of mechanical position stops) for these valves.

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Contrary to the above, on October 23,1996, Procedure STS BG-004 did not

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specifically require operators to tighten or verify the mechanical position stops for

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valves BGV-198, BGV-199, BGV-200, and BGV-201.

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This is a Severity Level IV violation (Supplement I) (50-482/96021-06).

Pursuant to the provisions of 10 CFR 2.201, Wolf Creek Nuclear Operating Corporation is

hereby required to submit a written statement or explanation to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a

copy to the Regional Administrator, Region IV,611 Ryan Plaza Drive, Suite 400, Arlington,

Texas 76011, and a copy to the NRC Resident inspector at the facility that is the subject

of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation

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(Notice). 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

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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. Your response may reference or

include previous docketed correspondence, if the correspondence adequately addresses the

required response. If an adequate reply is not received within the time specified in this

Notice, an order or a Demand for Information may be issued as to why the license 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.

Because the response will be placed in the NRC Public Document Room, to the extent

possible, it should not include any personal privacy, proprietary, or safeguards information

so that it can be placed in the Public Document Room without redaction. However, if it is

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necessary to include such information, it should clearly indicate the specific information

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that should not be placed in the Public Document Room, and provide the legal basis to

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support the request for withholding the information from the public.

Dated at Arlington, Texas

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this 31st day of December,1996

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ENCLOSURE 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

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Docket No.-

50-482

License No.;

NPF-42

Report No..

50-482/96-21

Licensee:

Wolf Creek Nuclear Operating Corporation

Facility:

Wolf Creek Generating Station

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Location:

1550 Oxen Lane, NE

Burlington, Kansas

Dates:

October 7-11 and 21-25,1996

Team Leader:

J. Tedrow, Senior Resident inspector

Inspectors:

R. Azua, Project Engineer

P. Campbell, Mechanical Engineer

M. Fallin, Consultant, Scientech, Inc.

P. Goldberg, Reactor Inspector

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F. Ringwald, Senior Resident inspector

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J. Stone, Project Manager

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Approved By:

C. VanDenburgh, Chief, Engineering Branch

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Division of Reactor Safety

Attachment:

Supplemental Information

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TABLE OF CONTENTS

EXECUTIVE SUMMARY

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Report Details

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lit. Engineering

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Conduct of Engineering . . . . .

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E1.1

General Comments .

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E1.2 Permanent Plant Modification Review .

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E1.3 Temporary Plant Modification Review . .

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E1.4 Review of Engineering Calculations

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E1.5 Review of Performance Improvement Requests . . . . . . . . . .

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E1.6 Work Package Review

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E2

Engineering Support of Facilities and Equipment

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E 2.1

General Comments . . . . . . .

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E2.2 Review of Facility and Equipment Conformance to the Final

Safety Analysis Report . .

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E2.3

10 CFR 50.59 implementation .

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E2.4 Unsupported Operability Determination . .

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E2.5 System Walkdowns (37550) . .

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E2.6 Engineerirr Work Backlog . . . .

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E2.7 Surveillance Testing . .

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E2.8 Industry Event Assessment and Lessons Learned

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E3

Engineering Procedures and Documentation

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E3.1

Review of Design Basis Documents . . . . .

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Engineering Staff Training and Qualification

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E5.1

System Engineering Staff Training and Qualification . .

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E6

Engineering Organization and Administration .

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E6.1

System Engineering

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E6.2 Design Engineering .

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Quality Assurance in Engineering Activities

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E8

Miscellaneous Engineering issues .

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E8.1

(Closed) Inspection Fo!!owup Item 50-482/9504-03: Use of

gear operator stop not for actuator braking .

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E0.2 (Closed) Licensee Etent Report 50-482/96001: Loss of

circulating water c'ue to icing on traveling screens

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E8.3 (Closed) Licensee Event Report 50-482/96002: Loss of

essential ser / ice water train due to icing on trash racks

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Exit Meeting summary . . . . . .

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ATTACHMENT: Supplemental Information

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EXECUTIVE SUMMARY

Wolf Creek Generatin0 Station

NRC Inspection Report 50-482/96-21

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This team inspection evaluated the effectiveness of the Wolf Creek system and design

engineering organizations to respond to routine and reactive site activities which included

the identification and resolution of technical problems. The performance of safety and

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operability evaluations, and self-assessment activities were also included in this inspection.

Enoineerina

The inspection team found that modification packages included appropriate safety

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evaluations, and appropriately specified post-modification testing. In addition,

associated drawings and procedures were generally updated as required, and the

engineering calculations were satisfactory. However, the inspection identified a

design control violation regarding the use of outdated calculations for capping

containment air cooler tubes. In addition, the team considered the licensee's

control of the design basis information to support the safety function of the

emergency core cooling system to properly operate following a postulated internal

missile generation and impact to be poor (Sections E1.2 and E1.4).

The inspection team determined that the administrative procedures that the licensee

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had developed for the review and evaluation of changes in accordance with

10 CFR 50.59 were appropriate. However, the team found numerous discrepancies

between the Updated Safety Analysis Report and the actual plant conditions and

identified problems in the licensee's implementation of the 10 CFR 50.59 review

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process. The team identified one apparent violation involving fc,ur examples, which

were indicative of a programmatic breakdown in the control of this activity. These

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examples involved: (1) the operation of the essential service water self-cleaning

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strainer backwash setpoint differently than described in the Updated Safety

Analysis Report, (2) the performance of inservice inspection and testing of the

reactor coolant pump flywheel examination differently than described in the

Technical Specifications, (3) the performance of underground pressure testing of

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essential service water piping differently than described by the Updated Safety

Analysis Report, and (4) the performance of a safety evaluation regarding changing

the main turbine overspeed protection test frequency without performing sufficient

evaluation to conclude that an unreviewed safety question was not involved

(Sections E2.2, E.2.3, and E2.7).

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Although the licensee's corrective action for a 1993 quality assurance audit required

the performance of a 10 CFR 50.59 screening of Technical Specification

clarifications, the screening did not identify potential conflicts between the

Technical Specifications and the clarifications. Specifically, the licensee screenings

of nine Technical Specification clanfications, which were performed to resolve the

concerns of the quality assurance audit, failed to determine that these clarifications

involved unauthorized changes to the Technical Specification requirements, in

addition, a followup quality assurance audit f ailed to recognize that the conditions

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found during the original audit were not corrected. This f ailure was identified as an

apparent violation involving inadequate corrective action. The inspectors also noted

that the screenings of the Technical Specification clarifications were subsequently

reviewed by the Plant Safety Review Committee, and they also failed to identify the

issues involving Technical Specification compliance (Section E2.3).

Based on the number of findings in the 10 CFR 50.59 area and the recent

indications of improper screenings for Updated Safety Analysis Report change

requests, the team concluded that training did not appear to have been effective in

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avoiding continuing deficiencies (Section E2.3).

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The team identified that a shif t supervisor violated the licensee's administrative

procedures regarding operability determinations when he relied, in part, on an

out-of-date calculation. Previous examples identified by NRC inspectors indicated a

declining trend in the performance of on-shift operability determinations

(Section E2.4).

The team found that housekeeping was generally very good and noted that the

material condition of system components had little evidence of boric acid leakage

and few deficiencies. A very good threshold for deficiency identification had been

established. However, the inspection team identified that system walkdowns by

the safety injection system engineers did not include all plant areas where system

components were located (Section E2.5).

The team considered temporary shielding controls to be weak because they did not

require an engineering review of erected temporary shielding and periodic

inspections of installed temporary shielding. In addition, the residual heat removal

system engineer was not knowledgeable of the condition of temporary shielding,

even though it had been installed for several years (Section E2.5).

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The licensee managed the engineering open item workload appropriately, but the

licensee did not have a formal program to control the backlog. The inspectors were

concerned that the program had a high threshold for backlog criteria, and failed to

trend the impact on engineering personnel workload (Section E2.6).

In general, the inspection team found that surveillance tests for the systems

selected had been accomplished in accordance with Technical Specification

requirements and were performed at the correct periodicity. However, the team

identified one violation associated with an inadequate procedure to verify

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emergency core cooling throttle valve mechanical position stops (Section E2.7).

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Uncontrolled and out-of-date design basis notebooks hindered the licensee's control

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of design basis information. The licensee's control of design basis information was

found to be weak,in that, it did not provide a centrallocation for the design basis

information. In general, licensee personnel had difficulty retrieving some design

basis information (Section E3.1).

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Although system engineering knowledge was excellent it appeared to be the result

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of the personal initiative taken by system engineers and their immediate supervisors,

and not due to any specific management guidance or administrative requirement.

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Training guidance was found to be very general and did not provide a minimum

standard for system engineer training or knowledge. Overall, licensee management

communication of system engineering expectations has improved; however, the

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weaknesses identified in the previous NRC engineering inspection in May 1995, had

not been corrected (Sections E5.1 and E6.1).

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Report Details

Ill. Enaineerin_g

E1

Conduct of Engineering

E1.1

General Comments (37550)

Using inspection Procedure 37550, the team reviewed three safety-related systems

to verify the licensee's ability to maintain these systems in an operable status. The

three systems reviewed were: (1) essential service water, (2) residual decay heat

removal, and (3) safety injection. The team reviewed the adequacy of the

licensee's plant mndification processes (permanent and temporary), engineering

calculations, performance improvement requests, and documentation of work

performed on system components.

E1.2 Permanent Plant Modification Review

a.

Inspection Scope

The team reviewed several safety-related plant modification records listed in the

attachment to verify conformance with applicable installation and testing

requirements as prescribed by procedures. Specific attributes reviewed and/or

verified by the team included: (1) 10 CFR 50.59 safety evaluations, (2) post-

modification testing reqe rements, (3) safety-related drawing updates, (4) Updated

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Safety Analysis Report updates, (5) training requirements, and (6) field installation.

b.

Observations and Findinas

in general, the team found the modification packages reviewed included appropriate

safety evaluations. The specified post-modification testing in the modification

packages was appropriate and associated drawings and procedures were generally

updated as required.

Outdated Calculations Used for Canoina Containment Air Cooler Tubes

The essential service water system supplies the containment air coolers under

accident conditions. The system contains four coolers total, with two coolers for

each of two safety-related trains of essential service water. Each cooler has

12 coils with 32 circuits of 6 multiple passes, totaling 2304 tubes per cooler.

The team reviewed Configuration Change Package CCP-07111, Revision 0, which

was initiated on October 17,1996, to address a leaking tube which had developed

in one of the 12 cooler coils in Containment Air Cooler SGN-01C, one of the two in

the A train of essential service water. The package was issued to assess the effect

of plugging (or capping) the tube and continuing to use the cooler. A 7-day action

statement was entered on October 17,1996, and an engineering review was

initiated. The assessment for this change concluded that up to 64 tubes could be

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plugged based on Calculations SA-90-030, CWR-02424-90,and GN-MW-005. The

team noted that these calculations used a flow rate of 2000 gpm through each

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cooler instead of more recent calculations which were based on a flow rate of

1000 gpm through each cooler.

Change Package CCP-07111, Revision 1, was issued, and approved by the Plant

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Safety Review Committee, on October 18,1996, because cooler SGN-01C

continued to have leakage problems. Plans were to install a blind flange on the

supply header flange and on the return header flange to the leaking coil. The one

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affected coil was to be abandoned in place untilit could be replaced. The change

package stated that the removal of one coil bundle,32 circuits, would reduce total

flow through the containment cooler pair by a maximum of 2 percent and

referenced Calculation GN-MW-005, Revision O. The change package also stated

that the removal of one coil bundle would reduce the heat transfer capacity

Containment Coolers SGN01 A and SGN01C, by approximately 1/24, which was

previously analyzed under Calculation SA-90-030. Calculations SA-90-030, dated

April 23,1990, and GN-MW-005, dated April 25,1990, used a flow rate of

2000 gpm per cooler (4000 gpm per pair of coolers).

Change Package CCP-07111, Revision 2, was issued, and approved by the Plant

Safety Review Committee, on October 20,1996, when a second coil on cooler

SGN-01C developed a leak. The package stated that one objective was to allow up

to three cooling coils to be blanked off if needed. The package stated that the

removal of one coil bundle, 32 circuits, will reduce total flow through the

containment cooler pair by a maximum of 2 percent for a total of 6 percent with

three coils removed and again referenced Calculation GN-MW-005, Revision O. The

change package also stated that a sensitivity study wes performed to determine the

.effect of degraded performance of containment coolers on the containment pressure

and temperature response following a postulated main steam line break accident.

The change package referenced Calculation SA-90-025, dated April 9,1990, which

also used 2000 gpm flow through each cooler, for this sensitivity study.

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Subsequent to these calculations, the licensee had identified that the essential

service water system total flow had degraded due to erosion and corrosion in the

system and was concerned that the analyzed flow rate to the containment air

coolers, along with other cooling loads, may not be assured. Calculation

SA-90-057, dated November 1990, determined the containment peak temperature

and pressure that would result if the capacity of the containment air coolers were

assumed to be only 45 percent of the original capacity due to a reduction in the

flow rate through each cooler from 2000 to 1000 gpm. or 4000 gpm per train to

2000 gpm per train. The calculation supported Technical Specification Amendment

50, issued November 4,1991, which changed the required minimum flow rate

specified in Technical Specification 4.6.2.3.b from 4000 gpm per cooler group to

2000 gpm per cooler group. Calculation SA-90-057 concluded that sufficient heat

removal capability existed with the lower flow rate.

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The licensee's most recent flow balancing of the essential service water system

was conducted in the 1994 refueling outage and set the measured flows, by

throttling valves to the desired position, as follows:

Train A:

Cooler SGN01 A

1022 gpm

Cooler SGN01C

1034 gpm

Train B:

Cooier SGN01B

1150 gpm

Cooler SGN01D

1440 gpm

The team determined that Calculations GN-MW-005, SA-90-025, and SA-90-30 did

not reflect the current operation of the coolers (i.e.,1000 gpm current flow versus

2000 gpm flow) and predated the calculation for 1000 gpm and the subsequent

Technical Specification change. Both Revisions 1 and 2 of Change Package

CCP-07111 included an unreviewed safety question determination concluding that

the removal of three coils from service did not constitute an unreviewed safety

question. The conclusion was based on the outdated calculations discussed above.

None of the referenced calculations based on a 2000 gpm flow rate for each cooler

were denoted as either out-of-date or as not reflecting the current configuration of

the equipment. However, the essential service water system engineer, who

coordinated the efforts, was aware that the ilow rate had been reduced to

approximately 1000 gpm per cooler subsequent to the Technical Specification

amendment.

Performance improvement Request PIR-962669 was initiated on October 20,1996,

based on questions from the Plant Safety Review Committee on the 10 CFR 50.59

safety determination associated with Change Package CCP-07111, Revision 2. In

this improvement request, the difference in the margins between the capacity of the

coolers with 1000 gpm versus 2000 gpm was explained, and the impact of

blocking three coils was addressed. The improvement request concluded that the

containment peak pressure would not be exceeded based on Calculation SA-90-057

results. As of October 25,1996, Change Package CCP-07111, Revision 2, had not

been revised to reference the design information that reflected current operation of

the coolers with a flow rate of 1000 gpm each (or 2000 gpm flow rate per a group

of two coolers). However, the team considered the information provided in the

improvement requests addressed the current operability conclusion of the coolers

with the blocked coils (2 of 12 in the C cooler).

10 CFR 50, Appendix B, Criterion 111, requires, in part, that measures be established

to assure that regulatory requirements and the design basis are correctly translated

into specifications, drawings, procedures, and instructions. These measures shall

include provisions to assure that appropriate quality standards are specified and

included in design documents. The suitability of continued use of Containment Air

Cooler SGN-01C with 2 of 12 coils blocked from essential service water flow,

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assessed in Change Package CCP-07111, was determined based on calculations

that did not reflect the current operating configuration of the equipment (i.e., the

reduction in flow requirements from 4000 gpm per cooler group to 2000 gpm per

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cooler group), which is considered to be a violation of 10 CFR 50, Appendix B,

Criterion 111(50-482/96021-01).

Licensee management stated that they considered references to outdated

calculations and information to be acceptable as long as current data was utilized in

present calculations. The team recognized that the licensee could have used the

calculations based on 2000 gpm flow per cooler as a comparison analysis for

1000 gpm flow per cooler if the engineering analysis had stated such.

c.

Conclusions

in general, the team found the modification packages reviewed included appropriate

safety evaluations. The specified post-modification testing in the modification

packages was appropriate and associated drawings and procedures were generally

updated as required. The team identified one violation regarding the use of

outdated calculations for capping containment air cooler tubes.

E1.3 Temporary Plant Modification Review

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a.

Inspection Scope

The team reviewed a number of the licensee's active safety-related temporary

modifications listed in the Attachment. This effort was performed to verify that

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these modifications were in conformance with plant procedures. In addition,

nonsafety-related temporary modifications were also reviewed to determine if they

were appropriately categorized, and if 10 CFR 50.59 evaluations were appropriately

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performed.

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b.

Observations and Findinas

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The team identified that the licensee had only 14 temporary modifications installed

in the plant. Of these modifications, five were identified as safety related. The

team reviewed these temporary modifications against the requirements of

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Administrative Procedure AP 211-001, " Temporary Modifications," Revision 1, and

did not note any discrepancies. Affer:ted procedures and drawings were also

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reviewed to determine if appropriate changes were annotated. No problems were

noted.

The licensee had assigned an engineering supervisor to monitor temporary

modifications in the plant. The licensee maintained a computerized log of these

modifications, with assigned durations. The team interviewed the engineering

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supervisor and found him to be cognizant of the temporary modifications installed in

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the plant. The team noted that this effort was designed to identify those temporary

plant modifications that could be easily removed or corrected, and to make sure that

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long term corrective actions were applied to the remaining temporary modifications

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in a reasonable time.

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Conclusions

The licensee efforts in reducing the number of temporary modifications in the plant

have been very successful.

E1.4 Review of Enaineerina Calculations

a.

Inspection Scope

The team reviewed the adequacy of several design engineering calculations listed in

the Attachment associated with the three subject systems to determine whether the

calculation assumptions were technically reasonable and properly supported.

b.

Observations and Findinas

The team found that the licensee's calculations were satisf actory. The calculations

reviewed provided sufficient information and assumptions to reach the conclusion

stated. The team found some minor mistakes in the calculations regarding the

correct atmospheric pressure for the elevation of the plant, and conversion of pump

horsepower to heat transferred to the coolant system, which did not adversely

affect the calculation's conclusion. Licensee personnel were informed of these

mistakes for correction.

Inadeauate Support of Desian Basis

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The team reviewed Calculation IMS-01, " Missiles," Revision 0, to verify a statement

in the Updated Safety Analysis Report, Section 6.3.1.1, regarding the design bases

for the emergency core cooling system. The Updated Safety Analysis Report

contained general information that stated the system was designed to withstand the

effect of generated missiles. The calculation also contained an unlisted attachment

which listed the summary of rotating equipment in safety-related areas, by room

number. This attachment utilized Resolutions (1) and (2) which stated that room

coolers and pumps were not considered to be credible missile sources based on

"The Internal Missile Hazards Analysis Program Overview," Items B.4.C and B.4.A.

The team requested these documents for review, but the licensee was unable to

locate or retrieve them during the inspection. No other documentation was

available to justify these assumptions. The team was, therefore, unable to

determine if the design of the system was adequate to support the system's safety

l

function under postulated generated missiles.

l

On November 8,1996, the licensee obtained the missing information from the

architect-engineer. These documents were provided to the team on November 12,

1

I

5

1996. The documents were hand-written and contained justification for omitting

the pumps as credible missile sources due to the thickness of the pump casings.

The licensee stated that they disagreed with the inspection team's finding, in that,

the missing information was not part of the design bases cf the plant and,

therefore, need not be readily available. The team noted that the missing

information was an element of the licensing basis for the emergency core cooling

system as described in the Updated Safety Analysis Report, Section 6.3.1.1,in

Safety Design Basis Two. Since the design basis includes information identifying

the specific safety functions of the system and supporting analysis for reference

bounds for the system design, the team considered the plant design basis to be

,

inadequately supported without this documentation. Due to the difficulty the

licensee experienced with retrieving this information, the team considered the

licensee's control of this design information to be poor.

c.

Conclusions

in general, the calculations were found to be satisfactory. The control of the design

basis information to support the safety function of the emergency core cooling

system to properly operate following a postulated internal missile generation and

impact was considered to be poor.

E1.5 Review of Performance Imnrovement Reauests

a.

Inspection Scope

The licensee issued performance improvement requests as a means to identify

problems with components and systems and to place these problems in their

corrective action system for resolution. The team reviewed performance

improvement requests listed in the Attachment associated with the three subject

systems to determine the adequacy of the resolution, whether the systems'

operability was properly determined, and that the proposed corrective actions were

adequate to preclude recurrence.

b.

Observations and Findinos

The team found that the performance improvement requests had resolutions with

proper engineering justification and that the proposed corrective actions were

adequate to preclude recurrence.

E1.6 Work Packaae Review

a.

Inspection Scope

The team reviewed work packages listed in the Attachment associated with the

three subject systems, and work history printouts, to determine if repetitive

problems existed and to determine the present material condition of the system.

This information was compared with the results of the system walkdowns.

6

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_ _ . .

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b.

Observations and Findinas

The team found that the work packages were performed in accordance with their

instructions and the engineering staff was knowledgeable of the work performed.

No recurrent problems were noted. The team's walkdown results indicated that the

j

licensee was maintaining the systems in good condition and a very low threshold

for deficiency identification had been established.

E2

Engineering Support of Facilities and Equipment

E2.1

General Comments (37550)

To ascertain engineering support of plant activities, the team walked down the

l

selected systems with the system engineer, reviewed the system description

r

provided in the Updated Safety Analysis Report, compared the Updated Safety

t

Analysis Report description with design basis information, evaluated the engineering

work backlog, compared surveillance testing records and test procedures with

design basis information and Technical Specifications, and reviewed the engineering

disposition of selected industry events for lessons learned.

E2.2 Review of Facility and Eauipment Conformance to the Final Safety Analysis Report

Description

a.

Inspection Scope

l

A recent discovery of a licensee operating its facility in a manner contrary to the

Safety Analysis Report description highlighted the need for a special focused review

that compares plant practices, procedures and/or parameters to the Safety Analysis

Report description. While performing the inspections discussed in this inspection

report, the inspectors reviewed the applicable sections of the Final Safety Analysis

Report that related to the selected inspection areas,

b.

Observations and Findinas

!

The team found that the Final Safety Analysis Report was generally consistent with

l

the actual plant configuration. The team noted several discrepancies in the

descriptions as noted below:

Imoroner Chanae to Essential Service Water Self-Cleanina Strainer Backwash

Setooint

The team reviewed Section 9.2.1, " Station Service Water System," and

'

Table 9.2-5, " Essential Service Water System Component Data," of the Wolf Creek

Updated Safety Analysis Report. The team noted that Table 9.2-5 for the essential

service water system self-cleaning strainers listed a strainer capacity of 15,000 gpm

with a maximum dif ferential pressure of 3.0 psi. The team asked the licensee to

venty the capacity at this differential pressure. The licensee stated that the signal

.

to start the self-cleaning strainers was 5.0

0.5 psi not the 3.0 psi stated in

7

l

Table 9.2-5. During the first week of the inspection, the licensee was not able to

determine the reason for the difference in the maximum strainer differential

pressure.

During the inspection, the licensee contacted the strainer vendor to determine if a

.iaximum strainer differential pressure of 5.5 psi was acceptable. The licensee

stated that setting the maximum differential pressure at 6.0 psi would not cause

any physical damage to the strainer. However, it might detract from the strainers

ability to self clean upon initiation of the backwash cycle. The licensee stated that

the vendor indicated that a pressure drop of 1.0 psi, clean, across the strainer was

based on laboratory tests and did not account for the pressure drop across the inlet

and outlet connections, or specific piping connections. In addition, the vendor

recommended a strainer backwash initiation at a pressure drop 2.0 psi greater than

the clean pressure drop.

The team reviewed vendor data on the strainers. One chart plotted pressure loss

versus flow. The team noted that for a clean strainer there was a pressure drop of

1.0 psi at a flow of 15,000 gpm. The team reviewed another plot of pressure loss

versus percent of strainer clogged. The team noted that, with a differential

pressure of 5.0 psi, the plot indicated that the strainer surf ace was 95 percent

clogged. In addition, the team reviewed the licensee's data on strainer dif ferential

pressure and system flow. The team found that, since 1994, the normal differential

pressure across the strainers has been approximately 3.0 to 3.5 psi and the system

flow was approximately 15,000 gpm. In addition, the team reviewed startup test

data from 1984 which listed a strainer differential pressure less than 1 psi at a flow

over 15000 psi. The licensee could not explain what caused the pressure to

increase from less than 1.0 psiin 1984 to more than 3.0 psiin 1994.

The team considered the Updated Safety Analysis Report setpoint discrepancy to be

important since a change in strainer differential pressure could directly affect system

flow rates. Based on reviewing the licensee's recent test data, which showed

system flow greater than the design flow rate of 15,000 gpm, the team concluded

that there were no operability concerns on account of the discrepancies.

10 CFR SO.59(a)(1) allows the holder of a license to make changes to the f acility

and procedures as describad in the final safety analysis report without prior

Commission approval unless the proposed change involves a change in the

Technical Specifications or an unreviewed safety question.

The team reviewed setpoint Change Request EF-84-01, dated March 13,1984.

This document requested a setpoint change for the self cleaning strainer pressure

instruments to change the setpoint to 5.5 psid. The cover sheet was annotated

with an "N/A" following questions concerning if any Updated Safety Analysis

Report section or limit was affected by the change. The modification had a

10 CFR 50.59 screening, but no safety analysis. The team found that the screening

stated that the change described in the primary document did not involve a change

8

to the Updated Safety Analysis Report. However, the strainer table was a part of

the Updated Safety Analysis Report and included the 3.0 psi maximum differential

pressure for a dirty strainer. The team considered the licensee's failure to perform a

safety evaluation to be the first example of an apparent violation of 10 CFR 50.59

(50-482/96021-02).

Emeroency Core Coolina System Water Hammer

The team noted that Updated Safety Analysis Report, Section 6.3.2.2, stated that

all emergency core cooling system discharge piping is water solid during plant

operation and, therefore, water hammer in the injection line is precluded. The team

questioned this statement since solid pipe operation alone will not always preclude

waterhammer events depending upon the piping configuration and flow

characteristics. The licensee responded by acknowledging that this statement was

not appropriate. The licensee initiated Plant improvement Request 96-2675 and

stated that the Updated Safety Analysis Report would be revised to clarify the

water hammer statement. The licensee provided applicable sections of the safety

evaluation report which oiscussed how the residual heat removal system design

i

features and proper venting and filling procedures prevented water hammer. The

!

team concluded that no operability concern existed.

Containment Pressure Used in Pumo Net Positive Suction Head Calculations

in Section 6.3.2.2 of the Updated Safety Analysis Report discussion about

net-positive suction head, the statement is made that the calculation of available

net-positive suction head in the recirculation mode assumes that the vapor pressure

'

of the liquid in the sump is equal to the containment ambient pressure. This is the

case only when containment ambient pressure is atmospheric in accordance with

Regulatory Guide 1.1, " Net Positive Suction Head for Emergency Core Cooling and

Containment Heat Rernoval System Pumps." The actual net-positive suction head

calculations use atmospheric ambient conditions. The team considered the Updated

Safety Analysis Report statement to be misleading. Licensee personnel

acknowledged the inspector's comment and initiated an Updated Safety Analysis

l

Report change to clarify the wording.

Incorrect Capacity of Essential Service Water Pumo Prelube Storaae Tank

The team reviewed Section 9.2.1.2.2.2 of the Updated Safety Analysis Report,

which stated that the essential service water prelube storage tank size was based

on supplying a minimum of 6 gpm water for 5 minutes to the essential service

water pump bearings without any makeup from the essential service water line.

The team asked the licensee how they verify this statement.

t

The licensee verified that the tank would hold enough water to supply 30 gallons of

water without any makeup. However, the licensee determined that the maximum

flow to the bearings would only .be 1.0 to 1.5 gpm due to the size of the piping

from the prelube tank to the pump bearings. The licensee stated that there was no

operability concern since the pump vendor had installed bronze bearings in the

9

l

pump because of the possibility for pump start without prelubrication. Therefore,

the tank was not needed for pump operability requirements. In addition, the team

1

determined that the licensee did not know the necessary flow rate of water to

!

properly lubricate the bearings as recommended by the pump vendor to reduce

wear. The team noted that Table 9.2-5 listed the capacity of the prelube tank to be

43 gpm. The team determined that 43 gallons was the volume of the tank with a

usable volume of 35 gallons. The licensee prepared Plant Improvement Request

96-2617, dated October 16,1996, to resolve these discrepancies and correct the

Updated Safety Analysis Report.

c.

Conclusions

Although there were numerous discrepancies between the Updated Safety Analysis

Report and the actual plant conditions, the inspection team determined that the

discrepancies did not present an operability concern. The inspection team identified

one apparent violation regarding operation of the essential service water self-

cleaning strainer backwash setpoint differently than described in the Updated Safety

Analysis Report. In addition, the team noted that the licensee had difficulty in

j

retrieving design information.

E2.3

10 CFR 50.59 Imolementation (37001J

a,

insoection Scope

)

The team reviewed the licensee's program guidance, training program information, a

sample of 50.59 screenings and associated unreviewed safety question

determinations, a sample of 50.59 screenings that did not require an unreviewed

safety question determination, and interviewed a number of individuals who perform

50.59 screenings and prepare unreviewed safety question determinations. In

addition, a sample of Updated Safety Analysis Report changes were reviewed.

j

b.

Observations and Findinas

The licensee's safety evaluation process for changes to the facility is controlled by

Procedure AP 26A-003, " Screening and Evaluating Changes, Tests, and

Experiments," Revision 1. This procedure was recently revised in February 1996.

1

The procedure delineated the licensee's methods, training requirements, and

responsibilities to determine and document whether f acility changes can be made

without prior NRC approval. The process used to determine if an unreviewed safety

question exists is a two step process.

The first step was a screening process that made a determination as to

whether or not the proposed change was a change to the facility as

described in the Technical Specifications, Updated Safety Analysis Report,

nonradioactive liquid or gaseous discharges, nonradiological solid waste,

i

thermal discharges, security plan, safeguards contingency plan, security

guard training plan, radiological emergency plan, an NRC or INPO

i

commitment, and physical changes within the site boundaries. If the answer

1

l

10

to all questions was negative, then a change to the Updated Safety Analysis

Report was deemed not to exist and the change could proceed without an

unreviewed safety question determination prepared. An affirmative answer

to any of the questions required further evaluation. Only if the screening

determined that it was a change to the Updated Safety Analysis Report, was

an unreviewed safety question determination required.

The second step involved documentation of an unreviewed safety question

determination on Form APF 26A-003-03,"10 CFR 50.59 Unreviewed Safety

Question Determination," by answering a series of questions and recording

the basis for each answer. If the answer to all questions was "no," then an

unreviewed safety question did not exist and the change could be

implemented without prior approval of the NRC. If the answer to any

question was "yes," then NRC approval was required prior to implementing

the proposed change. Procedure AP 26B-003," Revisions to the Updated

Safety Analysis Report," provided instructions for issuing changes to the

Updated Safety Analysis Report.

The team determined that these procedures provided appropriate guidance for the

development and approval of reviews and approvals under 10 CFR 50.59.

The licensee developed a training program for personnel that performed 50.59

screenings and prepared unreviewed safety question determinations. The team's

review of the training program determined that the program covered all the essential

aspects of the 50.59 screenings and unreviewed safety question determinations. In

addition, there was a requirement that by the end of calendar year 1996, personnel

performing 50.59 screenings and preparing unreviewed safety question

determinations must have taken the training. The need for requalification training

will be determined by significant changes to Procedure AP 26A-003, an increasing

trend in the number of Plant Improvement Requests indicating deficiencies in

j

completed screenings or unreviewed safety question determinations, self-

i

assessment results and quality assurance audit results.

The team evaluated the implementation of the 50.59 program by reviewing a

sample of completed 50.59 screenings and determinations as contained in the Wolf

Creek Generating Station Annual Safety Evaluation Report for 1995, a listing of the

changes approved since January 1,1996, and interviewing a number of persor.ael

involved in the preparation of 50.59 screenings and determinations. Several

deficiencies were identified as delineated below:

Inadeauate Justification of Chanae to Turbine Oversoeed Protection

Unreviewed Safety Question Determination 59 96-0067 and associated Updated

Safety Analysis Report Change Request 96-044 evaluated and changed the

surveillance frequency for the four high pressure turbine stop valve, six low

pressure turbine reheat stop valves and six low pressure reheat intercept valves

from once per seven days to once per 92 days. This change was based on NRC's

Generic Letter 93-05, "Line-Item Technical Specifications improvements to Reduce

11

l

Surveillance Requirements for Testing During Power Operations." The guidance

provided in the generic letter for changing the turbine valve surveillance frequency,

requested that licensees include a statement in their amendment request that the

proposed change is compatible with plant operating experience and a statement that

the turbine manuf acturer concurred with the proposed change. However, the

inspection team noted that the unreviewed safety question determination did not

address the licensee's experience with the testing of these valves and did not

contain any information as to the acceptability, by the turbine vendor, of the

decreased surveillance frequency of the turbine valves. Based upon interviews with

licensee personnel, the team determined that the licensee had not fully considered

these factors and that the turbine vendor had not been contacted.

10 CFR 50.59 (b)(1) requires that records of changes include a written safety

evaluation which provides the bases for the determination that the change, test, or

experiment does not involve an unreviewed safety question. Even though the

turbine test frequency change did not involve a license amendment, the licensee

should have been aware of the specific information the NRC deemed appropriate to

include in this unreviewed safety question determination based on the generic letter.

Therefore, the team determined that the basis included with this change did not

provide adequate information to come to the conclusion that an unreviewed safety

question did rm axist. The team considered the failure to fully evaluate that the

change did not involve an unreviewed safety question to be the second example of

an apparent violation of 10 CFR 50.59 (50-482/96021-02).

The licensee subsequently informed the team that the information needed to justify

the change did not involve an unreviewed safety question was available and the

determination would be revised to include it.

Inadeauate Screeninas of Technical Specification Clarifications

The team reviewed several proposed Updated Safety Analysis Report changes,

including three that would have incorporated Technical Specification clarifications

into the Updated Safety Analysis Report. These clarifications had been screened

and determined to neither change the Updated Safety Analysis Report nor the

Technical Specifications and had been issued for review and approval.

Change Request 96-094 was written to add existing Technical Specification

Clarification 009-85 for a Technical Specification that had been relocated to

Chapter 16 of the Updated Safety Analysis Report. The clarification allowed closing

the breaker and operation of a second centrifugal charging pump while swapping

pumps when in operating Modes 4,5, or 6. The team reviewed current Technical

Specifications 3/4.5.3 (arm"

in Mode 4) and 3/4.5.4 (applicable in Modes 5

-

and 6) and determined t'.at both allowed only one charging pump to be operable.

.

On October 2,1995, a change to Technical Specification 3/4.5.4 (Amendment 89)

was made that added a 4-hour action period to disable one pump.

The team determined that the licensee had changed Operating Procedure

SYS BG-201, "Shif ting Charging Pumps," in 1985 to incorporate the Technical

12

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1

Specification clarification. The clarification received a further screening in March

1994 as a result of a quality assurance finding. The team was informed that the

operating procedure had been previously used, and the 4-hour action period

exceeded, on March 22 and 26,1996. In addition, during two occasions on

October 24,1994, while the plant was in Mode 5, both charging pumps were

operable. The team considered the initial screening done for the operating

procedure and the subsequent screening done for this clarification in 1994 to be

inadequate as they changed a Technical Specification requirement and resulted in

operation of a second charging pump while in Mode 5, contrary to Technical Specification 3.5.4. Failure to perform the required actions of Technical Specification 3.5.4 is considered to be an apparent violation of the Technical

i

Specification (50-482/96021-03),

i

l

The licensee subsequently voided this proposed change request and the Technical

Specification clarification. A revision to the operating procedure was also initiated

to prohibit this action.

Following the identification of the team's concerns about Technical Specification

clarifications, the licensee formed an internal investigation team to review and

determine the adequacy of all 45 active clarifications and whether or not

compliance with Technical Specification requirements was being achieved. As a

result of that continuing review, the licensee identified two additional clarifications

which were improperly screened and that resulted in Technical Specification

J

non-compliance as follows:

Technical Specification Clarification 004-86 allowed cold-leg accumulators to

be considered operable upon receipt of level and pressure alarms if

accumulator level and pressure was within prescribed limits. This

j

clarification involved a change to Technical Specification Surveillance

j

Requirements 4.5.1 and 4.0.3, which required the accumulators be

'

considered inoperable upon receipt of alarms.

The licensee determined that from September 25 to October 2,1996, the

associated level alarm was energized and the Technical Specification action

statement was not met because of the f ailure of one levelindication channel

on Cold Leg Accumulator B. The Technical Specification action statement

required restoration within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or hot shutdown within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months

followed by reactor coolant system depressurization below 1000 psig within

the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The team noted, however, that the alarm function did not

affect the ability of the system to perform its safety function.

Technical Specification Clarification 005-94 allowed hot restart testing of an

emergency diesel generator to be performed any time before or after the

24-hour load test, as long as the hot restart test was performed within

5 minutes of a 2-hour diesel run. This clarification involved a change to

Technical Specification 4.8.1.1.2.g.7, which specified that a hot restart test

be performed within 5 minutes following the 24-hour test. There was a

footnote to the Technical Specification that allowed the hot restart test to be

13

done following a warmup run if it f ailed the hot restart test following the load

test. This clarification allowed the complete decoupik 9 ti.e., allowing the

hot restart test to be performed anytime after engine warmup and not

requiring a f ailure of the hot restart test following the load test) of the load

test and the hot restart test. This Technical Specification was changed by

the NRC with Amendment 101, issued on August 8,1996, and allows the

decoupling of these two requirements. This amendment was implemented

by the licensee on November 7,1996.

The licensee determined that prior to issuance of this amendment, hot restart

,

testing of the diesels was not performed in accordance with the Technical

Specifications. Specifically, during Refueling Outage 7, Emergency Diesel

Generator A was load tested on September 17,1994, and the hot restart

test was not performed until October 15,1994. Emergency Diesel

Generator B was load tested on September 16,1994, and the hot restart

test was not performed until October 17,1994.

The licensee also determined that during Refueling Outage 8, Emergency

Diesel Generator A was load tested on February 6,1996, and the hot restart

'

test was not performed until March 26,1996. Emergency Diesel Generator

B was load tested on March 16,1996, and the hot restart test was not

performed until March 23,1996. Again, since the licensee's hot restart test

method was allowed by the Technical Specifications under certain

conditions, the team considered the consequences of these violations to be

minor.

In addition, the team evaluated the licensee's review of all the clarifications and

identified the following clarifications that provided guidance contrary to Technical

Specification requirements and could have resulted in non-compliance due to

inadequate screenings:

Technical Specification Clarification 010-35 allowed daily containment

closeout inspections following multiple containment entries in one day. This

clarification involved a change to Technical Specifications 3.5.3 and 4.5.2

which specify a containment visualinspection for loose debris be performed

following each containment entry.

Technical Specification Clarification 026-85 allowed increasing power while

the quadrant power tilt ratio exceeded a prescribed limit. This clarification

involved a change to Technical Specification 3.2.4.a.4 which prohibited

increasing power with the quadrant power tilt ratio greater than the

prescribed limit.

Technical Specification Clarification 033-85 allowed containment

penetrations to be considered operable if dedicated operators were assigned

to close inoperable containment isolation valves. This clarification involved a

change to Technical Specification 3.6.1.1 which specified that all

containment penetrations be operable by autornatic isolation valves.

14

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_

d

Technical Specification Clarification 001-94 allows the reactor coolant

system to be cooled down, an activity which involves a positive reactivity

change, with one source range channel of nuclear instrumentation

inoperable. This clarification involved a change to Technical Specification 3.3.1, Table 3.3-1, Functional Unit 6.b, " Source Range Shutdown,"

Action 5, which specified that with one source range channel inoperable, all

operations involving positive reactivity changes be suspended.

Technical Specification Clarification 004-94 deleted emergency diesel

generator testing of the redundant dieselif the inoperable diesel was

rendered inoperable by a support system failure. This clarification involved a

change to Technical Specification 3.8.1.1 which specified that the redundant

emergency diesel generator be tested within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if one emergency

<

diesel generator was inoperable for any reason except for preplanned

preventive maintenance, testing, or maintenance to correct a deficiency

which, if left uncorrected, would not affect the operability of the diesel

generator. This clarification extended this footnote to include inoperable

support systems on one diesel as a condition that would not require a start

test of the other diesel. This Technical Specification was changed by the

NRC with Amendment 101, issued on August 8,1996, and was

implemented by the licensee on November 7,1996.

Technical Specification Clarification 002-96 allows one of the two required

source range neutron flux monitors to be considered operable when in the

refueling condition when powered from a nonsafety-related power supply.

This clarification involved a change to Technical Specification 3.9.2, which

specifies that two source range neutron flux monitors to be OPERABLE in the

refueling condition (Mode 6). Although Technical Specification 3.9.2 does

not specify the power source requirement, the definition of OPERABILITY

l

does include a requirement for electric power, which refers to the normal

'

safety-related power supply.

The licensee provided the result of an audit done of the existing clarifications by

their quality assurance group in February 1993. This audit identified the following

potential consequences that could result in the use of Technical Specification

clarifications:

Failure to comply with Regulatory, Technical Specification, or other

applicable requirements;

Poor performance ratings, concerns, or more severe actions from the NRC

for a potentially inadequate or incorrect Technical Specification clarification

program;

Inappropriate actions being taken by operators;

15

Potentially non conservative actions which could require NRC approval prior

to implementation; and/or

Overly conservative actions for plant shutdown without consideration of

=

other risks involved.

As a result of that audit, the licensee reviewed membership on the Technical

Specification clarification committee for appropriateness; reviewed guidance for

preparation of clarifications; and performed a 10 CFR 50.59 review (screenings) of

all current clarifications. In addition, the screenings of the clarifications were

reviewed and approved by the Plant Safety Review Committee. These activities

resulted in voiding eleven clarifications, revision of six clarifications, and one

clarification was considered for a Technical Specification amendment. The

remaining clarifications were deemed by the licensee to meet requiremeats. This

'

i

action was completed in March 1994. The quality assurance group performed a

follow up audit to evaluate the effectiveness of the corrective actions which

concluded that the corrective actions were adequate to resolve the concern. This

audit and review of the completed corrective actions failed to identify additional

potential conflicts between the clarifications and Technical Specifications.

10 CFR 50, Appendix B, Criterion XVI, requires in part, that measures be

established to assure that conditions adverse to quality are promptly identified and

corrected. The team determined that the licensee's corrective actions, done

following the quality assurance finding, were inadequate and f ailed to identify the

conflicting statements in the clarifications with the Technical Specifications. Based

upon the numerous deficiencies in this area, the team concluded that a

programmatic breakdown in the licensee's 10 CFR 50.59 screening program had

occurred. This breakdown included the licensee's quality assurance group which

initially identified potential concerns with the clarifications, but did not properly

i

assess the adequacy of the licensee's corrective action, and the Plant Nuclear

Safety Review Committee which reviewed the clarification screenings and also

j

f ailed to note that changes to the Technical Specifications were involved. The

f ailure to perform adequate corrective action for the identified clarification

deficiencies is contrary to the requirements of 10 CFR 50, Appendix B,

j

Criterion XVI, and is considered to be an apparent violation (50-482/96021-04).

'

At the time of the exit meeting on November 8,1996, the licensee had reviewed

the clarifications and determined that occasions had occurred in which the

Technical Specifications were violated and planned to submit five licensee event

reports on these items.

Imcroper Cnanae to Reactor Coolant Pumo FlywheelInspection Freauency

The team reviewed Updated Safety Analysis Report Change Request 95-003,

" Screening for Licensing Basis Changes," approved January 11,1995, regarding a

change in the examination schedule for the reactor coolant pump flywheels.

Specifically, the description of the proposed change stated that Regulatory

Guide 1.14, Revision 1, required a 10-year reactor coolant pump motor flywheel

16

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- - _ _

-

_ ,

.

-- -- ,

-

.

examination coinciding with the inservice inspection program interval. This change

clarified the intended examination schedule by revising Chapters 3A and 5.4.1 of

the Updated Safety Analysis Report to include an exception to the Regulatory Guide

examination schedule. The examination schedule was changed to 12 years to

accommodate the "D" reactor coolant pump flywheel which had not been inspected

per the previously established schedule. The response to Screening Question 2 on

whether the change results in a revision to the Operating License, including the

Technical Specifications, was marked "No "

Technical Specification 4.4.10, which was applicable January 9,1995, stated that

each reactor coolant pump flywheel shall be inspected in accordance with the

recommendations of Regulatory Position C.4.b of Regulatory Guide 1.14,

Revision 1, August 1975. This Technical Specification was subsequently

superseded by Technical Specification 6.8.5.b in License Amendment 89, issued

October 2,1995, which contained the same statement. Regulatory Guide 1.14,

" Reactor Coolant Pump Flywheel Integrity," Revision 1,1975, Paragraph C.4.b.(2)

states that a surface examination of all exposed surfaces and complete ultrasonic

volumetric examination of the flywheel be performed at approximately 10-year

intervals, during the plant shutdown coinciding with the inservice inspection

schedule as required by Section XI of the ASME Code.

The interval for inservice inspection is based on 120 months pursuant to 10 CFR 50.55a(g)(4), with the initial interval beginning on the date of commercial operation.

Commercial operation for the Wolf Creek plant commenced September 3,1985.

Provisions in Paragraph IWA-2400(c) allowed that each inspection interval may be

decreased or extended by as much as 1 year. The provisions of Paragraph C.4.b of

Regulatory Guide 1.14 specified that the surface and ultrasonic examination of the

flywheel be performed ".

at approximately 10-year intervals." Therefore, using

the code provisions for the inservice inspection interval, the surface examination of

all of the reactor coolant pump flywheels should have been completed by

September 3,1996. The licensee confirmed on October 25,1996, that the surf ace

and ultrasonic examination of the "D" reactor coolant pump flywheel has not yet

,

!

been performed and is currently scheduled for the Fall 1997 refueling outage during

reactor coolant pump maintenance.

Section 50.59, " Changes, Tests, and Experiments," allows licensees to make

changes to licensed facilities or to perform tests and experiments at licensed

,

faci lities when these changes, tests, and experiments (1) do not change the

l

parameters specified in the f acility operating license, including Technical

j

Specifications, or (2) present an unreviewed safety question. If the changes, tests,

l

or experiments change the operating license, including Technical Specifications, or

present an unreviewed safety question, NRC approvalis required prior to

implementing the change or performing the tests or experiments. By reference in

the Technical Specifications, any exceptions to the reactor coolant pump motor

flywheelinspection program delineated in paragraph C.4.b of Regulatory

Guide 1.14, must be approved by the NRC.

17

l

examination coinciding with the inservice inspection program interval. This change

clarified the intended examination schedule by revising Chapters 3A and 5.4.1 of

)

the Updated Safety Analysis Report to include an exception to the Regulatory Guide

examination schedule. The examination schedule was changed to 12 years to

accommodate the "D" reactor coolant pump flywheel which had not been inspected

per the previously established schedule. The response to Screening Question 2 on

whether the change results in a revision to the Operating License, including the

Technical Specifications, was marked "No."

'

Technical Specification 4.4.10, which was applicable January 9,1995, stated that

each reactor coolant pump flywheel shall be inspected in accordance with the

recommendations of Regulatory Position C.4.b of Regulatory Guide 1.14,

Revision 1, August 1975. This Technical Specification was subsequently

superseded by Technical Specification 6.8.5.b in License Amendment 89, issued

October 2,1995, which contained the same statement. Regulatory Guide 1.14,

" Reactor Coolant Pump Flywheel Integrity," Revision 1,1975, Paragraph C.4.b.(2)

states that a surface examination of all exposed surfaces'and complete ultrasonic

volumetric examination of the flywheel be performed at approximately 10-year

intervals, during the plant shutdown coinciding with the inservice inspection

schedule as required by Section XI of the ASME Code,

The interval for inservice inspection is based on 120 months pursuant to 10 CFR 50.55a(g)(4), with the initial interval beginning on the date of commercial operation.

Commercial operation for the Wolf Creek plant commenced September 3,1985.

Provisions in Paragraph IWA-2400(c) allowed that each inspection interval may be

decreased or extended by as much as 1 year. The provisions of Paragraph C.4.b of

Regulatory Guide 1.14 specified that the surface and ultrasonic examination of the

flywheel be performed ". . . at approximately 10-year intervals." Therefore, using

the code provisions for the inservice inspection interval, the surface examination of

all of the reactor coolant pump flywheels should have been completed by

September 3,1996. The licensee confirmed on October 25,1996, that the surface

and ultrasonic examination of the "D" reactor coolant pump flywheel has not yet

been performed and is currently scheduled for the Fall 1997 refueling outage during

reactor coolant pump maintenance.

.

Section 50.59, " Changes, Tests, and Experiments," allows licensees to make

changes to licensed facilities or to perform tests and experiments at licensed

facilities when these changes, tests, and experiments (1) do not change the

parameters specified in the f acility operating license, including Technical

Specifications, or (2) present an unreviewed safety question. If the changes, tests,

or experiments change the operating license, including Technical Specifications, or

present an unreviewed safety question, NRC approvalis required prior to

,

implementing the change or performing the tests or experiments. By reference in

the Technical Specifications, any exceptions to the reactor coolant pump motor

flywheelinspection program delineated in paragraph C.4.b of Regulatory

Guide 1.14, must be approved by the NRC.

17

- _

. _ _ _ . _ . _ . _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ . -

The team considered a change to the examination schedule would result in a

change to the Technical Specifications by reference in paragraph C.4.b of

Regulatory Guide 1.14. Therefore, the proposed change to the examination would

require NRC approval prior to implementing the change. Failing to properly perform

the screening for the proposed change to the surface examination schedule for the

reactor coolant pump flywheels to identify a change to the Technical Specification

is contrary to 10 CFR 50.59 and is considered to the third example of the apparent

violation discussed in Section E2.2 of this report (50-482/96021-02).

After being informed of this discrepancy, the licensee performed an operability

determination for the "D" reactor coolant pump which concluded that the pump was

capable of performing its safety related design function. This determination was

based upon satisf actory examination results of the flywheel keyways and bore

which were last performed during Refueling Outage 7. In addition, nuclear industry

experience has indicated that a decrease in inspection requirements is appropriate in

some cases. Based upon this information and consultation with the Office of

Nuclear Reactor Regulation, the team concluded that continued operation of the

pump until the examination could be performed was not a safety concern.

c.

Conclusions

Numerous problems were identified with the licensee's implementation of the 50.59

review process, which were indicative of a programmatic breakdown. Further

evidence of a continuing breakdown in the review process was evident by the

existence of changes made since 1994 in which the licensee did not recognize

changes to the Technical Specifications (reactor coolant pump flywheelissue) or

other NRC approved programs (essential service viater system buried pipe testing

discussed in Section E2.7).

The team determined that the program procedures the licensee has developed for

the review and evaluation of changes in accordance with 10 CFR 50.59 were

appropriate. Based on the number of findings in the 50.59 area, and the recent

indications of improper screenings for Updated Safety Analysis Report change

requests, the team concluded that training did not appear to have been effective in

avoiding continuing deficiencies.

The licensee's corrective action for a quality assurance audit, initiated in 1993,

identified potential problems with the use of Technical Specification clarifications,

did not identify potential conflicts between the Technical Specifications and the

clarifications. The followup audit by quality assurance failed to recognize that the

conditions found during the original audit finding were not corrected. This was

considered to be an apparent violation involving inadequate corrective action. In

addition, the review of the clarifications by the Plant Safety Review Committee, and

their f ailure to identify continuing issues involving Technical Specification

compliance, calls into question the performance of that group.

18

E2.4 Unsupported Operability Determination

a.

Inspection Scope (37550)

The team reviewed one operaon.., determination made during the inspection by a

shif t supervisor associated with team observations.

b.

Observations and Findinas

On October 22,1996, the team noted that the shift supervisor reviewed an informal

listing of inspection issues raised by the team. Item 133 noted that several

different documents, Technical Specification requirements, Updated Safety Analysis

Report sections, and a calculation identified conflicting essential service water flows

through the containment air coolers. Item 133 also identified two questions

regarding the correct number for essential service water flow through the

containment air coolers and, the correct number for heat removal rate of a single

containment air cooler. The shif t supervisor reviewed this listing, then logged the

following entry into the Shift Supervisor Log: "1410 Reviewed Items 130-134 on

Engineering and Technical Services NRC inspection list - No operability /reportability

issues noted."

The team asked the shift supervisor what the basis was for the log entry identifying

no operability issues for item 133. The shift supervisor stated his basis was

Calculation GN-MW-005, Revision 2, which used 4000 gpm flowrate per cooler

group, and that the assumption had been made that, "...the engineers knew what

i

they were doing." The team noted that the flow information used by this

calculation had been superseded, and that the present containment cooler flow was

2000 gpm flowrate per cooler group. The team questioned the engineer regarding

how the list had been presented to the shift supervisor. The engineer stated that

the list had been handed to the shift supervisor, and that there had been no

substantive discussion regarding item 133.

Administrative Procedure ADM O2-024," Technical Specification Operability,"

Revision 3, step 5.3.2, required the shift supervisor to perform a number of actions

associated with the operability determination to ensure sufficient scope of review.

This step required the shift supervisor to determine the requirement or commitment

established for the equipment, and why the requirement or commitment may not be

met. In cases where the operability determination was not straightforward,

Procedure ADM O2-024 also required the shift supervisor to use the information

available to make the determination, and start the actions stated in

Procedura AP 28-001," Evaluation of Nonconforming Conditions of installed Plant

Equipment," Revision 4, to obtain sufficient information to completely answer all

questions.

The team determined that the operability evaluation performed by the shift

supervisor failed to include all the required actions, in that, the shift supervisor did

not properly identify the minimum acceptable flow rate for the containment air

cooler given the conflicting statements of containment air cooler flow in the

19

- - _ . - - . .

-

. ~ --

. . . - - ~ - - - - -

- - - . -

Updated Safety Analysis Report and other documents, and compare the actual

cooler flow with the minimum flow requirement as stated in Technical Specification 4.6.2.3.b. This is a violation of 10 CFR 50, Appendix B, Criterion V

(50-482/96021-05).

The inspection team noted that NRC Inspection Reports 50-482/96-012,

50-482/96-11,and 50-482/96-09,had previously identified several examples where

the NRC had identified poorly supported operability determinations. The team

determined that while the previous examples of poorly supported operability

evaluations were not identified as violations of requirements, they indicated a

declining trend in performance. The violation identified in this paragraph was

determined to be more significant than the previous examples, in that, the shift

supervisor stated that the operability determination was, at least in part, based on

an out-dated calculation and an unsupported reliance on engineering.

c.

Conclusions

The team concluded that the shift supervisor violated 10 CFR 50, Appendix B,

Criterion V, when an operability determination failed to comply with the licensee's

procedure on operability determinations, and relied, at least, in part, on an out-dated

l

calculation. Previous examples identified by NRC inspectors indicated a declining

!

trend in the performance of operability determinations on shift.

E2.5 System Walkdowns (37550)

1

(

l

a.

Inspection Scope

i

The team performed a walkdown of the three subject systems and other selected

plant areas to determine the overall material condition of equipment and

maintenance of housekeeping. In addition, the team walked down several portions

of the spent fuel pool cooling system, component cooling water system, and

instrument air system,

b.

Observations and Findinas

The team found the housekeeping was generally very good. The team noted that

the system engineers and design engineers were both knowledgeable of their

,

systems. The engineers demonstrated their knowledge during the walkdown by

l

explaining component deficiencies in detail and relating to the team specific

l

operational problems with system operation. The material condition of system

l

components was noted to be very good with little evidence of boric acid leakage

i

and few deficiencies noted during the walkdown. The team noted that several

'

minor system leaks had been previously identified by licensee personnel which

!

indicated that a very good threshold for deficiency identification had been

established.

20

___

_

__

_ _ _ _

__

_

__

_

The team reviewed the system engineers' notebooks for the three systems selected.

The team noted that these notebooks were maintained in a well organized manner,

and the separate sections were tabbed for easy reference. The safety injection

system engineer kept the trend data and system walkdown sheets current, and had

a sufficient breadth of material to support the stated description of system engineer

responsibilities.

The team asked the safety injection system engineer what the maintenance rule

performance goals and actual system performance was for the safety injection

system. Both the present and former system engineers knew that the safety

injection system performance was exceeding the goal by a wide margin. However,

neither engineer could readily identify the actual system performance statistics

,

without speaking with the maintenance rule coordinator. While tha team did not

]

view this as a significant weakness, it did indicate that in this case the system

engineers did not have ready access to current maintenance rule pe;'ormance

statistics for their system.

Safety Iniection System Enaineer System Walkdown

The team noted that the safety injection system engineer had been assigned to this

system 8 weeks prior to the inspection. During this period, the system engineer

,

had conducted only one joint walkdown with the previous system engineer. The

system engineer conducted system walkdowns approximately weekly, but

management only required these walkdowns biweekly. The system engineer's

supervisor had participated in one of these walkdowns.

During the walkdown with the team, the system engineer did not tour the

1988 foot elevation of the auxiliary building and was, therefore, unaware of a

flange leak on the suction line between the refueling water storage tank and the

,

common suction header supplying the eight emergency core cooling pumps. When

asked by the team, the prior system engineer stated that walkdowns had included

portions of the 1988 elevation of the auxiliary building, but had never included the

high radiation area encompassing the pipe chase area. The system engineer

'

ind:cated that these walkdowns took from 1.5 to 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months each, but that during

some weeks the system engineer would take credit for system engineer presence in

the field supporting maintenance as the system walkdown for the week. With the

exception of the 1988 elevation of the auxiliary building, the system engineer's

walkdown was adequate.

The team discussed with licensee management their expectations for system

engineering walkdowns. Management stated that they expected the system

engineers to perform walkdowns in all areas containing system components,

although less frequently for high radiation areas due to exposure concerns.

21

._

_ _ __ .

_ _

__ -.

_-_ _ _ _ _ _

_

__

_ _ _ _ _ _ .

Residual Heat Removal Temporary Shieldina

The team noted that temporary shielding had been erected on the hot leg suction

piping for both trains of residual heat removal cooling and asked about this situation

and potential impact on system operability. The system engineer stated that this

shielding was installed in 1991 per a temporary shielding request. The team

reviewed the shielding request and scaffolding permits which controlled the erection

of scaffolding used to support the shielding off of the system piping. The team

noted that the scaffolding permits did not address potential static loads which might

be applied if the plastic straps which held the shielding to the scaffolding should

f ail. Licensee personnel acknowledged this deficiency in the scaffolding evaluation

and inspected the erected scaffolding and temporary shielding. Licensee personnel

found that portions of the shielding were not secured by tie wraps as specified in

the evaluation and decided to remove the scaffolding pending completion of a new

,

evaluation.

The licensee completed a subsequent evaluation which determined that the secured

and unsecured shielding would not have adversely affected safety related piping

underneath the scaffolding. The team determined that the erected scaffolding and

shielding had not been reviewed by engineering personnel and the system engineer

was not knowledgeable of the condition of this temporary shielding even though it

had been installed for several years. The team considered the temporary shielding

controls to be weak for not requiring an engineering review of erected temporary

shielding and periodic inspections c,f installed temporary shielding. The licensee

j

subsequently revised Procedure AP 25A-700,"Use of Temporary Lead Shielding,"

to require periodic inspections, verify shielding installation conformed with the

engineering disposition, and evaluation of the need for permanent shielding if

temporary shielding is installed for 6 months.

c.

Conclusions

The team found the housekeeping was generally very good. The team noted that,

in general, system engineers and design engineers were very knowledgeatile of their

system. The material condition of system components was noted to be very good

with little evidence of boric acid leakage and few daficiencies. A very good

threshold for deficiency identification had been established. System walkdowns by

the safety injection system engineers did not include all plant areas were system

components were located.

l

The team considered temporary shielding controls to be weak for not requiring an

l

engineering review of erected temporary shielding and periodic inspections of

installed temporary shielding. The residual heat removal system engineer was not

knowledgeable of the condition of temporary shielding even though it had been

installed for several years.

l

22

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---

-

- -

-

_-

- - _ -

4

E2.6 Enaineerina Work Backloa (37550)

,

4

a.

Insoection Scope

i

The team discussed the status of the engineering backlog with the Assistant to the

Vice President of Engineering. The discussions included actions taken by the

j

engineering organization to reduce the backlog.

b.

Observations and Findinas

.

The licensee's engineering backlog program was managed by the Assistant to the

Vice President of Engineering. The team interviewed the program manager and

found him to be knowledgeable of his responsibilities, but noted that no one had

4

been assigned backup responsibilities for this effort. This observation was

j

compounded by the fact that this program was not procedurali

c', and that the

data was manually collected and tracked. Therefore, the team considered the

program to be very susceptible to personnel changes in the organization. In

addition,it was noted that the open item information collected had not been trended

to determine the overall impact the open items had on the engineering department

-

workload.

'

The licensee's engineering backlog listed only 65 open items. The team found this

number to be artificially low because the licensee's threshold for backlog items was

high (i.e., several categories listed backlog criteria as high as 1 to 3 years old). The

,

licensee explained that when the program was initially started in 1992, the backlog

'

l

criteria was set high intentionally so as to identify those items which were the

i

oldest, while keeping the number of backlog items at manageable levels (i.e., with

)

these backlog criteria, the licensee engineering backlog, at the time, was greater

i

than 700 open items). However, the team noted that by 1994 the licensee had

l

significantly reduced their engineering backlog, but had f ailed to adjust the backlog

criteria. The f ailure by the licensee to reduce the threshold of the backlog criteria

.

was considered a weakness.

]

To better understand the work load on engineering personnel, the team questioned

the number of open items presently assigned M the department. At the time of this

inspection, there were approximately 1508 tc. i open items. To determine the

impact of the open items and to assess the safety significance of items still open,

.

the team reviewed a number of the open items listed (plant improvement requests,

,

corrective work requests, licensee event reports, etc.). The team determined that

the open items had been appropriately categorized and given the appropriate

prioritization for correction and closeout.

i

A number of closed items were also reviewed. Licensee actions in closing these

items were considered to be appropriate.

I

!

23

i

-

..

--

-

_ .._ .

.

_ _ - - . ..

.~ _

-

Finally, the team interviewed members of the engineering staff with regard to work

backlog. Open items were tracked by engineering supervisors at the group level.

Engineers appropriately scheduled and worked on open items according to their

prioritization and procedural requirements.

The licensee indicated that according to their records, the overall number of open

items that are tracked has been generally on the decline. However, performance

improvement requests were the only open item group that had showed a steady

increase. The licensee attributed this to a lower threshold for issuance of these

reports and a heightened awareness by plant personnel due to increased training in

this area.

,

c.

Conclusions

The licensee managed the engineering open item workload appropriately, but the

licensee backlog program was found to be behind the industry standard due to the

lack of a formalized program, high threshold for backlog criteria, and the f ailure to

trend the impact of the backlog on engineering personnel workload.

E2.7 Surveillance Testina

,

a.

Inspection Scope

1

The inspector reviewed Technical Specification surveillance reprements for the

three systems selected and the most recently completed surveillance tests for each

of these surveillance requirements,

b.

Observations and Findinas

The surveillance for the systems selected accomplished the Technical Specification

surveillance requirements and were performed at the correct periodicity. Exceptions

are noted below:

Imoroner Verification of Emeroency Core Coolina System Throttle Valve Mechanical

Stoo Position

Technical Specification Surveillance Requirement 4.5.2.g required the licensee to

verify the correct position of each mechanical position stop for the listed emergency

core cooling system valves every 18 months. This verification ensures that

sufficient cooling flow is available for post-accident conditions. The licensee

accomplished this surveillance requirement by performing Procedures STS EM-001,

" Emergency Core Cooling System Throttle Valve Verification," Revision 11, and

STS BG-004, " Chemical and Volume Control System Seal Injection and Return Flow

Balance," Revision 4. These procedures required workers to measure the valve

stem height for the valves specified in the Technical Specification.

24

. . - . - _ . - - - - - _ _ . . . . _ _ _ . - . - _

. _ _ . - - - - - . - - - . . - . _

.

!

t,

i

The team asked how the surveillance procedures verified the position of the

j

mechanical position stops. The 12 EM (Safety injection) system valves listed in

Technical Specification 4.5.2.g, and Valve BGV-202, did not have mechanical

'

,

position stops, but were locked in place using a locked chain as specified in

j

Procedure AP 21G-001, " Control of Locked Component Status," Revision 7. Seal

j-

injection valves BGV-198, BGV-199, BGV-200, and BGV 201 had valve stem

j

locknuts to secure the valve in position, but they were not required to be tightened

J

or verified during performance of the surveillance test. In addition, the team noted

that the procedure contained a drawing of the valve which did not indicate the -

presence of a locking nut.

'

W

l

The team considered the surveillance procedure to be deficient for not including the

!

specific design attributes of the mechanical stops and specific action necessary to

j

verify the correct position of the stops. In response to this concern, the licensee

j

checked the locknuts, and found them tight. The team interviewed two rion-

j_

licensed operators who had recently performed this surveillance procedure, and

l

l-

found that the operators could not recall whether they tightened the locknuts during

4

this surveillance, or not. The system engineer also interviewed another non-

[

licensed operator who had recently performed this surveillance and also found that

]

the operator could not recall tightening the locknuts. The failure of

.

!-

Procedure STS BG-004 to require the test performer to tighten the locknuts for

these valves is a violation of Technical Specification 6.8.1.a (50-482/96021-06).

,

a

,

3

Imorocer Essential Service Water Underaround Pinina Pressure Test

,

i

j

The team reviewed Performance improvement Request 95-2326, which was

!

. initiated on September 20,1995, to request a change in the test method for

!

essential service water system underground piping pressure tests. The description

j

of the problem stated that past performances of Test Procedure STS PE-049C,

j

" Essential Service Water System Underground Piping Leakage Test," Revision 1,

!

had proven to be very cumbersome and manpower intensive. This test was written

j

to satisfy the requirements of ASME Section XI as implemented by the licensee's

i

inservice inspection program for this Code Class 3 system. The test method being

f

used included the installation of blank flanges, isolating the system, and

l

determination of the rate of pressure loss. Because this portion of pipe is buried

i

underground, the initiator requested that the optional testing requirements in

4

Article WA-5244 of the ASME Code be considered for alternative testing of buried

i

components. Article IWA-5244 contains three options that are based on system

j

redundancy and piping isolation abilities:

(a)

In non-redundant systems where the buried components are isolable

by means of valves, the visual examination VT-2 shall consist of a

leakage test that determines the rate of pressure loss. Alternatively,

the test may determine the change in flow between the ends of the

3

!-

buried components. The acceptable rate of pressure loss or flow shall

!

be established by the owner.

4

1

?

25

.

If

,

. _ _ . .

_

(b)

In redundant systems where the buried components are nonisolable,

the visual examination VT-2 shall consist of a test that determines the

change in flow between the ends of buried components. In cases

where an annulus surrounds the buried components, the areas at each

end of the buried components shall be visually examined for evidence

of leakage in lieu of a flow test.

(c)

in non-redundant systems where the buried components are

nonisolable, such as return lines to the heat sink, the visual

examination VT-2 shall consist only of a verification that the flow

during operation is non impaired.

In the evaluation for this request, the engineer concluded that each of the two trains

of essential service water could be considered a non-redundant system. This

interpretation determined that each train provided cooling water only to the loads

associated with that train (i.e., Train A of essential service water supplies cooling

water to Train A heat loads, and Train B of essential service water supplies cooling

water to Train B heat loads, with no other cooling water supply to the separate

trains). This interpretation was not based on an ASME Code definition or an official

ASME Interpretation.

As a result of the evaluation, the engineer further concluded that paragraph (c)

of Article IWA-5244, could be applied to the buried portions of the essential

service water system. This conclusion resulted in revisions to Test

Procedure STS PE-049C, "A Train Underground Essential Service Water System

Piping Flow Test," and development of new Test Procedure STS PE-049D,

"B Train B Underground Essential Service Water System Piping Flow Test," which

eliminated the previous method of performing the visual examination VT-2 (i.e.,

determination of the rate of pressure loss) and implemented visual examination VT-2

that consisted only of a verification that the flow during operation is not impaired.

Section 9.2.1.2, " Essential Service Water System," of the Updated Safety Analysis

Report states that the essential service water system consists of two redundant

cooling water trains. The team considered the licensee's interpretation of system

non-redundancy to contradict this statement in the licensing basis.

The 10 CFR 50.59 screening for the test procedure change indicated that

Chapter 9.2 of the Updated Safety Analysis Report was reviewed. The screening

did not discuss the discrepancy regarding redundant versus nonredundant

definitions for the essential service water system trains. The licensee did not

submit a request for NRC review and approval of the alternative test method.

Neither did the licensee revise Chapter 9.2 of the Updated Safety Analysis Report to

indicate that the essential service water system trains could be considered

nonredundant systems. Therefore, the team considered that the screening for the

proposed change to the underground piping test procedures was deficient for not

26

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. - -

-- -

- - -

.

. . -

identifying that a change to the Updated Safety Analysis Report or inservice

inspection program (Technical Specification 4.0.5) was involved. This deficiency is

contrary to the requirements of 10 CFR 50.59 and is considered to be the fourth

example of the apparent violation (50-482/96026-02).

The revised Procedure STS PE-049C was used for the system pressure test

performed for the third 40-month period in the first 120-month interval. The test

was completed on January 17,1996. Likewise, Procedure STS PE-049D was

performed during January 1996. Performance of the revised tests resulted in the

failure to comply with the requirements of Section XI of the ASME Code for buried

piping in redundant systems and non-compliance with Technical Specification 4.0.5.

During the exit meeting, the licensee disagreed with the team's conclusion that this

matter was a violation. The licensee stated that since neither the AMSE Code nor

the Technical Specifications defined the term "redunuant"; therefore, it was

appropriate for them to do so. The licensee's inservice inspection engineer had

attended industry working group committee meetings, which discussed pressure

testing and the definition of redundant and non-redundant systems. The licensee

referred to the 1995 Addenda to the 1995 Edition of Section XI of the ASME Code,

Article IWA-5244, which had been changed to differentiate test methods based

only on whether the piping is isolable or non-isolable, and removed references to

redundant or nonredundant. The inservice inspection engineer utilized this

knowledge when interpreting these requirements for underground piping pressurt

testing. In addition, the onsite Authorized Nuclear Inservice inspector had reviewed

the change to the test procedure and had no comment. However, the inspection

team noted that the NRC has not yet endorsed the 1995 Addenda and the

Authorized Nuclear Inservice inspector has no responsibility under 10 CFR 50.59.

c.

Conclusions

in general, the team found that the surveillance for the systems selected

accomplished the Technical Specification surveillance requirements and were

,

performed at the correct periodicity. However, the team identified one violation

j

associated with an inadequate procedure to verify emergency core cooling throttle

valve mechanical position stops, and an example of an apparent violation regarding

pressure testing of essential service water system underground piping.

E2.8 Industry Event Assessment and Lessons learned

a.

Inspection Scope

The team reviewed two industry events to determine the licensee's action to

prevent similar problems. Industry documented f ailures of 4.16 kV General Electric

Magne-Blast circuit breakers to properly close, and of improper refurbishment of

4.16 kV breakers by overhaul vendors, were selected for review due to generic

applicability to the plant.

27

i

1

2

l

identifying that a change to the Updated Safety Analysis Report or inservice

inspection program (Technical Specification 4.0.5) was involved. This deficiency is

contrary to the requirements of 10 CFR 50.59 and is considered to be the fourth

example of the apparent violation (50-482/96026-02).

The revised Procedure STS PE-049C was used for the system pressure test

performed for the third 40-month period in the first 120-monthinterval. The test

was completed on January 17,1996. Likewise, Procedure STS PE-049D was

performed during January 1996. Performance of the revised tests resulted in the

failure to comply with the requirements of Section XI of the ASME Code for buried

piping in redundant systems and non-compliance with Technical Specification 4.0.5.

During the exit meeting, the licensee disagreed with the team's conclusion that this

matter was a violation. The licensee stated that since neither the AMSE Code nor

the Technical Specifications defined the term " redundant"; therefore, it was

appropriate for them to do so. The licensee's inservice inspection engineer had

attended industry working group committee meetings, which discussed pressure

testing and the definition of redundant and non-redundant systems. The licensee

referred to the 1995 Addenda to the 1995 Edition of Section XI of the ASME Code,

Article IWA 5244, which had been changed to differentiate test methods based

i

only on whether the piping is isolable or non isolable, and removed references to

redundant or nonredundant. The inservice inspection engineer utilized this

knowledge when interpreting these requirements for underground piping pressure

testing. In addition, the onsite Authorized Nuclear Inservice inspector had reviewed

the change to the test procedure and had no comment. However, the inspection

team noted that the NRC has not yet endorsed the 1995 Addenda and the

Authorized Nuclear Inservice Inspector has no responsibility under 10 CFR 50.59.

c.

Conclusions

In general, the team found that the surveillance for the systems selected

i

'

accomplished the Technical Specification surveillance requirements and were

performed at the correct periodicity. However, the team identified one violation

associated with an inadequate procedure to verify emergency core cooling throttle

valve mechanical position stops, and an example of an apparent violation regarding

pressure testing of essential service water system underground piping.

E2.8 Industry Event Assessment and lessons Learned

,

a.

Inspection Scope

The team reviewed two industry events to determine the, licensee's action to

prevent similar problems. Industry documented f ailures of 4.16 kV General Electric

Magne-Blast circuit breakers to properly close, and of improper refurbishment of

4.16 kV breakers by overhaul vendors, were selected for review due to generic

applicabihty to the plant.

27

. _ _ _ _ _ . _ _

__m

__ _ . _ _ _ _ _ _ _ _ _ . . _ . _ . _ . _ _ _ . _ _ _ _ _ _

b.

Observations and Findinas

The team found that the licensee had received reports of these events and had

taken corrective actions to prevent occurrence of these problems at Wolf Creek.

Preventive maintenance procedures and procurement documentation had been

I

reviewed by licensee personnel and appropriate revisions made to identify and

correct similar problems.

E3

Engineering Procedures and Documentation

E3.1

Review of Desian Basis Documents

a.

Inspection Scope

The team reviewed the design basis documents for the essential service water

system, the residual heat removal system, and the safety injection system to verify

the validity of the design basis and determine the case of retrieving the information.

b.

Observations and Findinas

The team reviewed the design basis notebook for the essential service water

system and determined that the notebook had beer approved in May 1993 and had

not been updated since then. The team noted a statement in the notebook that

when the notebook was to be used for design input, the user should take into

account the changes issued af ter the approval date of the notebook. At the time of

the notebook approval, the notebook had been a controlled document.

The team reviewed Interoffice Correspondence ED 96-0047, dated September 17,

1996, concerning design basis notebooks. The letter stated that due to downsizing

of engineering and the need to reorganize the work effort, design engineering had

identified that the notebooks were an opportunity to reduce the demand on

engineering services. Some of the licensee's actions were to keep the notebook for

information only and not maintain it as a controlled document. In addition, the

licensee decided that the system description documents would be used to keep

design basis information in the future. The licensee further stated that the extent of

information added to the system description would vary depending on the

judgement of the responsible engineer. The design engineering manager stated that

there was no need for the notebooks since all of the engineers were very

experienced and knew where to find the design basis information.

Since the design basis notebooks provided information to support the design and

licensing basis and provided the location of other design bases documents, the team

considered that uncontrolled and out dated notebooks hindered the control of design

basis information. This conclusion was supported by the fact that no other

controlled document provided this information. The team also noted during the

inspection, there were times when the licensee had difficulty retrieving design basis

information. The team considered the licensee's control of design basis information

to be weak for not providing a central location for the design basis information.

28

.

--

.

.-

.

-

..

~-

. . -

- - - -_

-. - -._ _ -

..

--_

..- - -

k

s

c.

Conclusions

!

,

Uncontrolled and out-of-date design basis notebooks hindered the control of design

basis information. The licensee's control of design basis information was found to

'

be weak,in that, it did not provide a centrallocation for the design basis

information. Licensee personnel had difficulty retrieving some design basis

l

information.

ES

Engineering Staff Training and Qualification

E5.1

System Enaineerina Staff Trainina and Qualification (37550)

a.

Inspection Scope

A review was performed of the system engineering training program. The team

reviewed Administrative Procedures AP-23-006, " System Engineering Program, "

Revision 3, and AP 30F-001," Engineering Support Personnel Training and

Qualification Program," Revision 2. The team discussed the training requirements

with a number of system engineers, and members of their direct management,

ll

during individual interviews. In addition, the team reviewed the training records for

all of the system engineers.

b.

Observations and Findinas

The team found the guidance for system engineering training and management

expectations provided in the licensee's administrative procedures to be general in

nature. Training requirements for engineers newly assigned to the system

engineering department, were developed by the engineer's immediate supervisor,

and were found to consist of " Qualifying Activities," which included " Evaluation of

Nonconforming Conditions of Installed Plant Equipment," (i.e. operability

determinations) " Engineering Calculations," "Unreviewed Safety Question

Determination," etc. Specific training on assigned systems was not required and

,

l

was lef t to each engineer's discretion to take system-specific courses that

periodically were offered for operations personnel. With regard to those situations

in which system engineers were assigned to a specific system, but were later given

responsibility for another system, the team noted that little guidance on training was

available other than for " Qualifying Activities." Finally, none of the procedures

were found to specify a time period for completion of training requirements nor

were there any minimum criteria for system engineer acceptance. In response to

this concern, the system engineering management issued a performance

improvement request.

In spite of the overall general guidance, the team found that the system engineer's

knowledge of each of their assigned systems was excellent. This was due, in part,

.

to a significant number of engineers having been involved in operator systems

training prior to entering the system engineering program. In addition, the system

!

engineers and their immediate supervisors displayed excellent initiative to improve

i

their knowledge.

29

-

-.

. . .

-

_.

. _ . _ _ _ . - . - _ _ _ . _ _ _ _ . _ . . _ _ _ _ _ _ _ _ . _ _ _ . .

__ . _ _ . _ _ _ .

4

3,

s

!

<-

l

For example, the system engineers interviewed were knowledgeable of industry

problems and maintained periodic contact with other utilities and equipment

'

vendors. The system engineers also periodically walked down their systems in

accordance with a system walkdown schedule that had been reviewed and

approved by their immediate supervisors. The system engineering supervisors

f

encouraged their personnel to attend technical presentations, classes, and meetings -

'

held by vendors or other utilities. One specific example of the initiative taken by the

system engineering supervision involved the reactor coolant system engineer, who

had been recently assigned to take responsibility for this system. His supervisor

.

arranged a visit to the Callaway plant, which had an identical reactor coolant

(

system and was in an outage. This afforded the system engineer an opportunity to

!

walk down the reactor coolant system and become f amiliar with his system which

he might not have been able to do at Wolf Creek until their next assigned refueling

outage.

,

Finally, almost all system engineers were found to have completed the appropriate

" Qualified Activities" training as indicated by their departments training records.

Those cases where engineers had not completed their assigned training was due

specifically to the fact that they had recently been assigned to their present

position.

c.

Conclusions

System engineering knowledge was found to be excellent and was based on the

initiative taken by system engineers and their immediate supervisors, and not by

any specific guidance provided in administrative procedures available. Training

guidance was found to be too general. Specifically, it did not provide a minimum

standard for system engineer training or knowledge.

E6

Engineering Organization and Administration

E6.1

System Enaineerina (37550)

a.

Inspection Scope

The team interviewed the system engineering manager, three group supervisors,

and seven system engineers. The team focussed on licensee management

- expectations of the system engineers and the system engineering program. This

included the method in which these expectations were communicated to the system

engineers, the mechanics of how plant problems were identified and corrected, and

the adequacy of communication between the system engineering department and

other plant organizations such as operations and maintenance. Additionally, the

system engineers were questioned on technicalinformation and outstanding

deficiencies for their assigned systems, including actions they were taking to

resolve those deficiencies.

30

.

b.

Observations and Findinas

1'

The licensee management expectations of the system engineers and the

system engineering program were delineated in licensee Administrative

Procedure AP 23-006, ." System Engineering Program," Revision 3, and

Administrative Instruction Al 23-002," System Engineering Plant Walkdowns,"

Revision O. Licensee management also communicated their expectations verbally

j

either directly or through the group supervisors.

j

As stated previously in this report (Section E5.1), the team found that the guidance

provided in the administrative procedures and instructions were generalin nature.

,

More specific guidance was verbally provided to the system engineers, at the group

'

level, by their appropriate supervisors.

The system engineers stated that although engineering management expectations

were generalin nature, they believed that the guidance being provided presently

was an improvement over the lack of guidance that existed in 1995. This

improvement was in part the result of Self Ansessment Reports SEL 95-039,

" System Engineering," dated January 19,1996, and SEL 96-025, " System

Engineering Self Assessment Effectiveness Follow-up," dated September 16,1996.

The system engineers indicated that with a clearer definition of their job scope, they

have a better understanding as to what they are required to do and which type of

activities they can defer to another organization. The team found that system

engineers understood their management's expectation in which they would be the

" experts" of their assigned systems and take " ownership" of their assigned

responsibilities.

In accordance with the procedural guidance, system engineers also had developed

primary trending parameters, and walkdown guidelines for their assigned systems,

which were reviewed and approved by their group supervisors. However, the team

noted that the consistency of how these two aspects of the system engineers

workload were being performed was not closely monitored by engineering

management. In addition, the system engineers used system notebooks in an

inconsistent manner. Nonetheless, the system engineers knowledge of their

individual systems was excellent. Operations and maintenance planning personnel

considered the system engineers as the " experts" of their assigned systems and as

the focal point for any questions on these systems. Operations personnelindicated

that they had confidence in system engineering persorinel to provide them the

appropriate information to make operability determinations.

System engineers displayed " ownership" of their system by following maintenance

activities being performed on their assigned systems. Plus, system engineers

periodically reviewed corrective work requests to identify if any applied to their

assigned system. As mentioned in Section E2.6, system engineers demonstrated

this ownership during the system walkdowns with team members.

31

3

1

-

- . -

- - . .

.

, , _ - ,

_,

-

,

. _ _ _ _ _ _ _ _ _ _ _ , _ _ . _ _ -

_ . _ _ _ _ _ . _ _ _

- _ . .

_ _ .

_ . _ _

_

i

t

i

!

The team noted the. the system engineering program did not specify the need for

backup system engineers for the safety-related equipment. The licensee had an

unofficial system engineer backup program, but it did not have any basic training

criteria or knowledge expectations. In addition, some of the system engineers were

unaware that they had been assigned as backup system engineers, and others were

not aware that any backup system engineers had been assigned to their system.

Finally, other plant personnel were unaware as to whom were the backup system

engineers, and what systems they were responsible for. This is considered to be a

weakness in the system engineering program, and behind industry standards.

i

c.

Conclusions

Overall, the system engineers were found to be knowledgeable of management

expectations and their responsibilities. Licensee management communication of

system engineering expectations has improved. The lack of assigned backup

system engineers was considered a program weakness.

E6.2 Desian Enaineerina (37550)

a.

Inspection Scope

The team conducted interviews with personnel from the maintenance planning, and

.

operations departments to evaluate the extent and effectiveness of design

l

engineering communications. The team also reviewed a number of change

l

packages and performance improvement requests that required engineering.

involvement, in an effort to determine how technical issues were resolved.

b.

Observations and Findinas

The team identified that cooperation and communication among the design

engineering department and operations, and maintenance planning departments

were good. Engineers indicated that management encouraged identification of plant

problems. This has contributed to the increase in the number of performance

improvement requests.

The team found that the performance improvement requests and change packages

reviewed had technical resolutions with proper engineering justifications and that

the proposed corrective actions were adequate.

The team noted that engineers were appropriately utilizing available design basis

documents to determine if a proposed change was within the original design basis.

All personnelinterviewed were aware that the design basis notebooks were not

controlled documents, and they only used them as reference documents.

c.

Conclusions

The team concluded that the licensee was effectively implementing their program to

respond to requests for engineering resolution of plant problems.

l

32

. .

_

-

__

-

___

.-

, . .

-

. ~ . _

-_

_ - - .

. - - . -

_ - _ . _ - -

. . - .

. . . - - -

l

4

i

1

!

E7

Quality Assurance in Engineering Activities

]

a.

Insoection Scope (37550)

!

The team reviewed four recent quality assurance self assessment reports related to

engineering activities. Self Assessment Report SEL 96-033," Licensee Event Report

Program," dated October 2,1996, SEL 96-025, " System Engineering Self

i

Assessment Effectiveness Follow-Up," dated September 9,1996, and SEL 95-056,

j

!

" Auxiliary Feedwater System," dated January 9,1996, were reviewed to evaluate

I

the effectiveness el tre licensee's controls in identification and resolution of plant

problems. Although not complete, the inspection team reviewed the assessment

plan and prelimir'.ary findings for an auxiliary feedwater functional assessment.

j

b.

Observations and Findinas

!

The team found that the self assessments were broad in scope and provided

meaningful findings and recommendations for potential program enhancements. As

an example, the auxiliary feedwater system self assessment resulted in a number of

i

improvement recommendations. These recommendations encompassed more than

'

enhancements to system performance and reliability but system engineering

,

program enhancements also. One such improvement recommendation included

l

placing the site wide trending program in a centralized location (e.g., trending data

is located in several groups and information exchanged is not formalized). Other

,

.

i

recommendations included a review of spare parts availability. Although.

j

improvements since the previous self assessment (SEL 95-039) had occurred, the

system engineering self assessment identified weaknesses in management and

j

supervisory oversight of the system engineers. The self assessments resulted in the

issuance of a number of performance improvement requests to address the

weaknesses identified.

!

t

i

The team found that the auxiliary feedwater system functional assessment plan

!

included similar items that the team was reviewing, in addition, some of the initial

l

findings from this self assessment effort were similar to those identified in this

i

report.

I

'

c.

Conclusions

The team concluded that the licensee's self-assessment reports were effective.

E8

Miscellaneous Engineering issues

E8.1

(Closed) Insoection Followuo item 50-482/9504-03: Use of gear operator stop nut

4

i

for actuator braking.

0

The licensee contacted the valve operator manufacturer who reviewed the

i

licensee's procedures for setting the stop nuts and limit switch settings and

'

concurred with the licensee's actions. The load applied to the stop nuts was within

i

rated design load.

'

33

i

.i

i

n

--- -

,,y.

,

. - - - , - ,

_,_r

- . .

-

,ye-

,

y

1

l

E8.2 (Closed) Licensee Event Report 50-482/96001: Loss of circulating water due to

icing on traveling screens.

This event was discussed in NRC Inspection Report 50-482/96-03 and was the

subject of a violation as listed in NRC letter EA96-124, dated February 29,1996,

item 06014. No new issues were revealed by the licensee event report and

followup on the licensee's corrective actions will be performed during the review of

the violation.

E8.3 (Closed) Licensee Event Report 50-482/96002: Loss of essential service water

train due to icing on trash racks.

This event was discussed in NRC Inspection Report 50-482/96-03 and was the

subject of two violations as listed in NRC letter EA96-124, dated February 29,

,

'

1996, items 02013 and 04013. No new issues were revealed by the licensee

event report and followup on the licensee's corrective actions will be performed

during the review of the violations.

V. Manaaement Meetinas

X1

Exit Meeting Summary

The team presented the inspection results to members of licensee management at the

conclusion of the inspection on October 25,1996. An exit meeting was held via

teleconference on November 8,1996. The licensee acknowledged the findings presented.

The overall scope and results of the inspection were discussed with Mr. Terry Damashek,

on December 31,1996.

i

The licensee did not identify that any propriety information was reviewed by the team.

)

34

l

I

i

ATTACHMENT

SUPPLEMENTAL INFORM ATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

l

G. Boyer, Director, Site Support

T. Damashek, Supervisor, Regulatory Compliance

R. Flannigan, Manager, Nuclear Engineering

T. Garrett, Manager, Design Engineering

B. Grieves, Supervisor, Systems Engineering

T. Hood, Supervisor, Design Engineering

N. Hoodley, Manager, Support Engineering

R. Hubbard, Superintendent, Operations

O. Maynard, Chief Administrative Officer

B. McKinney, Plant Manager

T. Morrill, Manager, Regulatory Services

R. Muench, Vice President Engineering

G. Neises, Supervisor, Reactor Engineering

D. Neufeld, Acting Manager, Integrated Planning and Scheduling

W. Norton, Manager, Performance Improvement and Assessment

K. Scherrch, Supervisor, Systems Engineering

R. Sims, Manager, Systems Engineering

J. Stamm, Supervisor, Safety Analysis

C. Warren, Chief Operating Officer

C. Younie, Manager, Operations

NRC

S. Freeman, Residant inspector

INSPECTION PROCEDURES USED

IP 37550

Engineering

IP 37001

10 CFR 50.59 Safety Evaluation Program

IP 92903

Followup - Engineering

1

. - -

- _ _ _ _ _ _

, - _ _ .

. . . - _

. . . - . - _ .

.- . . -

..

_

.

- ..

.

1

)

~

'

ITEMS OPENED AND CLOSED

l

Opened

50-482/96021-01

VIO

Inadequate Control of Design 8ases (Section E1.2)

50-482/96021-02

APV

Four Examples of the Failure to Properly Perform 5afety

Evaluations (Sections E2.2, E2.3, E2.3, and E2.7)

50 482/96021-03

APV

Failure to disable centrifugal charging pump while in cold

shutdown (Section E2.3)

50-482/96021-04

APV

Inadequate Corrective Action for Screening Technical

Specification Clarifications (Section E2.3)

50-482/96021-05

VIO

Unsupported Operability Determination for Containment

Cooler Flow (Section E2.4)

50-482/96021-06

VIO

Inadequate Procedure for Verification of Emergency Core

Cooling Throttle Valves Mechanical Position Stops

(Section E2.7)

Closed

50-482/95004-03

IFi

Use of Gear Operator Stop Nut for Actuator 8 raking

(Section E8.2)

50-482/96001

LER

Loss of Circulating Water due to Ice (Section E8.3)

50-482/96002

LER

Loss of Essential Service Water train due to Ice

(Section E8.4)

,

LIST OF DOCUMENTS REVIEWED

Unreviewed Safety Question Determinations

Number

Title

59 93-0211

Main Steam isolation Actuator Upgrade Modification, Revision 0

59 94-0174

Deletion of Reporting Requirements from Updated Safety Analysis

Report for Seismic Monitors, Revision 0

59 95-0003

Reactor Coolant Pump FlywheelInspection Clarification, Revision 0

59 95-0016

Spent Fuel Pool Surveillance Level Indicator, Revision 0

59 95-0034

Fire Area Combustible Load Evaluation, Revision 0

2

.

-

I

,

2

59 95-0046

Optional Opening Between Room 1203 and Room 1204, Revision 0

59 95-0057

Minimum Acceptance Criteria for Centrifugal Charging Pump B,

Revision 0

59 95-0061

Transient Cable Separation Criteria, Revision 0

59 95-0063

Biennial Relevancy Procedure Review Requirements, Revision 0

59 95-0109

Auxiliary Feedwater Pump Turbine Exhaust Line Upgrade, Revision 0

59 95-0129

Emergency Diesel Generator Design Explanation, Revision 0

59 95-0150

Auxiliary Feedwater Flowrate Revision, Revision 0

59 95-0151

Emergency Core Cooling System Flowrate Revision, Revision 0

59 95-0156

Boron injection Tank Recirculation Pump Removal and Removal of

Thermal Relief Valve, Revision 0

59 96-0032

Operation with Polypropylene Filter Membrane Materialin Spent Fuel

Pool, Revision 0

59 96-0034

Delete Reporting Requirements for Meteorological Tower

j

instrumentation, Revision 0

59 96-0038

Use of Safety injection Pump for Boration in Mode 6, Revision "

59 96-0086

Downgrade of Reactor Coolant Pump #1 Seal Leak Off Pressure

Indicator, Revision 0

59 96-0109

Highpressure Feedwater Heater Bypass Test, Revision 0

'

59 96-0115

Delete Program Descriptions from Updated Safety Analysis Report,

Revision 0

59 96-0143

Revise Updated Safety Analysis Report to Reflect use of Auxiliary

Feedwater in Residual Heat Removal Process, Revision 0

59 96-0148

Revise Scaffolding Procedure, Revision 0

59 96-0155

Clarification of Regulatory Guide 1.144, Revision 0

3

_ . . _ - -

. . _ . .

._ _ _ - ._ _ . _ _ _ _ .-_-_ _ _ -. _

__.m

. _ _ _ . _ _ . . . _ - _ _

- -

.

i

f

Updated Safety Analysis Report Change Requests Associated With

Technical Specification Amendments

i

Number

Title

i

Amendment 89

Updated Safety Analysis Report Change Request 95-137, dated

'

12/1/95, Borated Water Sources

1

Amendment 91

Updated Safety Analysis Report Change Request 95-138, dated

j

12/1/95, Refueling Water Storage Tank Boron Concentration

.

)

Amendment 93

Updated Safety Analysis Report Change Request 96-004, dated

1/11/96, Relocate Time Response Tables to Updated Safety Analysis

Report

[

Amendment 94

Updated Safety Analysis Report Change Request 96-104, dated

.

9/17/96, Operation of Emergency Fuel Oil Transfer System

3

Updated Safety Analysis Report Change Requests

i

j

Number

Title

,87-022

Corrections to Typographical Errors in Chapter 6, dated 7/15/87

96-031

Surveillance Frequencies for Main Dam, Saddle Dams, and Baffle

Dikes, dated 2/16/96

96-094

Incorporate Technical Specification Interpretation, dated 8/29/96

i

96-095

incorporate Technical Specification Interpretation, dated 8/29/96

96-096

incorporate Technical Specification Interpretation, dated 8/30/96

96-104

Revise Emergency Diesel Generator Transfer Pump Logic, dated

9/17/96

96-118

Revise Spent Fuel Pool Rack information, dated 9/26/96

91-047

Correction to Updated Safety Analysis Report Change Request

90114, dated 7/10/91

4

_ _ _ _

.

_ _.

._

.

_

._.

_

Regulatory Screenings

Number

Title

.

05622

Revision 0, Motor Operated Valve

l

05720

Revision 0 and Revision 1, Pressure Locking Modification

05782

Revision 2, Turbine Driven Auxiliary Feedwater Pump Resistor Modifications

,

05846

Revision 0, NK Battery Replacement

05900

Revision 0, Pressure Locking / Thermal Binding Evaluation

,

05906

Revision 0, Centrifugal Charging Pump High Temperature Alarm

05927

Revision 0, Low Flow Cavitation Limit Exceeded

06023

Revision 0, Pacific Valve Configuration Change

06025

Revision 0, Drain Holes in Code Relief Valves

06107

Revision 0, Relief From American National Standards Institute Code

Hydrostatic Test Requirements

,

06183

Revision 0, Delete Thermal Relief Valves from Component Cooling Water

System

06189

Revision 0, Battery Charger Alarm Setpoint

06252

Revision 0, Turbine Driven Auxiliary Feedwater Pump Valve Stem

Replacement

06285

Revision 0, Revised Thermal Design Flow

06304

Revision 0, Load Drop for New Fuel Storage Facility

06394

Revision 0, Safety injection Pump Rework

j

06445

Revision 0, New Safety injection Pump A and Rotating Element B Approval

2121

Revision 5, Flow Element EM FE0928 ALARA Concern

,

3749

Revision 1, SMB-00 Torque Switch improvement

4055

Revision 4, Valve EM HV8807A & B Speed Reduction

4139

Revision 6, Motor-operated Valve - Concerns with EM HV8814A/B

5

4145

Revision 4, Adjust Torque Switch Settings on EM HV8924

4148

Revision 7, Motor-operated Valve - Disposition for EM HV8801 A/B & EM

HV9903A/B

4150

Revision 5, Valve EM HV8835 Motor-operated Valve Disposition

4385

Revision 2, Main Control Board Switch Engraving Discrepancies

4394

Revision 13, Target Rock Valves Replacement

4537

Revision 4, Boron injection Tank Recirculation Removal

6424

Revision 1, Fabrication of Thrust Collar Spacer for PEM01 A

6457

Revision 0, Safety injection Pump Motors PEM01B Bolts Modification

Industry Technical Information Program Reports

.

Number

Title

02102

Liberty Technologies, 10-2-92:10 Code of Federal Regulations Part 21

Notification, Stem Material Constants And Torque Calibrator Effects Impact

Votes Testing Accuracy, Potential For Overthrust

02340

NRC Information Notice 93-37: Eyebolts With Indeterminate Properties

Installed in Limitorque Valve Operator Housing Covers

02371

Limitorque Maintenance Update 92-02: Motor Pinion Keys, Motor

,

i

Performance, Declutch Tips, Torque Switch Repeatability, Actuator

Nameplate, Actuator Wiring

02372

Limitorque Maintenance Update 92-02: Motor Pinion Keys, Motor

Performance, Declutch Tips, Torque Switch Repeatability, Actuator

Nameplate, Actuator Wiring

02373

Limitorque Maintenance Update 92-02: Abor Pinion Keys, Motor

Performance, Declutch Tips, Torque Switch Repeatability, Actuator

Nameplate, Actuator Wiring

6

.

-.___

__. _ __.- _._.__..___ _.___.___ _ _._..-.._ _. _

d

5

i

.

r

i

\\

~

Calculations

Number

Title

I

i

C-1989-130

Seismic Reanalysis of Refueling Water Storage Tanks, Revision 2

l

j

EF-M 014

Ultimate Heat Sink Thermal Analysis Review for Power Uprate,

Revision 1

EF-M-029

Minimum Essential Service Water Temperature Rise, Revision 1

i

EF-M-030

Determine Required Essential Service Water Warming Line Flow,

!

Revision 0

1

!

EF-M-031

Determine Orifice Sizes for Ultimate Heat Sink Outlet, Warming Line

Outlets, and FE-3&4 Necessary to Ensure 5000 GPM Essential

j

Service Water Warming Line Flow and the Corresponding Maximum

[

Pressure Downstream of FE-3&4,

,

1

Revisioa O

!

l

EF-M-032

Determine Hydraulic Grade Line Elevation Required at the Essential

i

,

l

Service Water Warming Line Branch, Revision 0

i

EF-M-033

Evaluate if 1" Thick Plate is Acceptable for EF-FE-03 & EF-FE-04,

i

Revision 0

l

EF-M-034

Investigate Design for Ultimate Heat Sink Discharge Orifice Plate on

j

Essential Service Water System, Revision 0

!

EF-M-035

investigate Design for Warming Line Discharge Orifice Plate on

l

Essential Service Water System, Revision 0

EF-M-036

Determination of Maximum Lake Temperature for Operation with

Warming Flow, Revision O

EF-M 037

Summary of Document Control Procedure 06349 M-11EF01 Flow

Diagram Changes, Revision 0

ECCS 5

Centrifugal Charging Pump "A" Net Positive Suction Head

Determination During Cold Leg Recirculation, Revision 0

ECCS-6

Centrifugal Charging Pump "B" Net Positive Suction Head

Determination During Cold Leg Recirculation, Revision 0

ECCS-7

Centrifugal Charging Pump "A" Net Positive Suction Head

Determination During Hot Leg Recirculation from Residual Heat

j

Removal Sump "A," Revision 0

7

1

_ - . _ _

_ . , -

_ ,_

, _ . . . _ _

.~_

,

_

_ _ .

_ _ _ _ . . . _ . _

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

t-

!

ECCS-8

Centrifugal Charging Pump "B" Net Positive Suction Head

Determination During Hot. Leg Recirculation from Residual Heat

'

Removal Sump "A," Revision 0

'

ECCS 9

Refueling Water Storage Tank to Safety injection Pump A - Criteria

Calc. (1 - 10), Revision 0

,

ECCS-10

Residual Heat Removal Sump A to Safety injection Pump A Suction -

Mode F, Revision O

ECCS-11

Residual Heat Removal Sump A to Safety injection Pump B Suction -

Mode F, Revision 0

,

ECCS-17

Maximum Head Loss from Refueling Water Storage Tank to Either

Centrifugal Charging Pump During injection Phase of SIS, Revision 0

ECCS-32

Containment Sump "B" to Safety injection Pump "B" Inlet, Mode E,

Revision O

ECCS-36

Refueling Water Storage Tank to Safety injection Pump "B" Suction

Mode A, Revision 0

ECCS-47

Safety injection Pumps Net Positive Suction Head from Refueling

Water Storage Tank, Revision O

EF 35

ESW Pump Head Requirement, Revision 2

EJ-29

Residual Heat Removal- Flow Orifice Sizing, Revision O

i

EJ 30

Residual Heat Removal Pumps A&B Net Positive Suction Head,

Revision 1

EJ-35

Residual Heat Remova Pump Minimum Flow Recirculation Line Orifice

Sizing, Revision O

EJ-37

Residual Heat Removal Co!d and Hot Leg Recirculation Orifices,

Revision O

EJ 38

Containment Recirculation Sump Screen, Revision 0

EJ-40

Containment Recirculation Sump Screen Fluid Velocity, Revision 0

EJ-M-001

Verification of Relief Valve Capacity for Valves EJ8708A&B,

Revision 0

EJ-M 017

Potential Susceptibility for Pressure Locking of Motor-operated Valves

EJHV8819A&B, Revision 2

8

I

1

EJ-M-019

Sizing of Expansion Pipe for Valves EJHV8811 A&B for Pressure

Locking Concerns, Revision 1

EJ MH 001

Heat Transfer for the Evaluation of Thermal Binding and/or Pressure

Locking of Valves EJ-HV8716A&B, Revision 0

EJ-S-003

Min. Wall Thickness Evaluation, Revision 1

1 -H BC-W

Essential Service Water Discharge Piping Design Pressure and

j

Minimum Wall Thickness Determination, Revision 1

IMS-01

Missiles, Revision O

PB-01

Total Pipe Break Summary, Revision 1

BN-20

Refueling Water Storage Tank Level Set-Points, Revision 1

.

Modifications

Number

Title

03377

Seismic Reanalysis of Refuel Water Tank, Revision 0

03838

EF/EA Cross Tie Piping Modification, Revision 0

Temporary Modification Order

Number

Title

96-018-EJ

Installation of Pressure Gauge Downstream of Valve HV8840

96 024-BB

Eliminate Nuisance Alarm of annunciator D074, Revision 2

96-038-FP

Replace Plant Diesel Fire Pump with Temporary Pump While Fire Pump is

Repaired, Revision 1

96-040-SE

Eliminate inadvertent alarm of Control Room Annunciators 828 and 83C,

Revision 0

96-020-AB

Install Temperature Monitoring Equipment on the Main Steam Isolation Valve

Accumulators, Revision 0

96-021-BB

Protect Vessel Head Seismic Support Plate from Excessive Leakage from the

Vessel Head Vent Valves, Revision 0

9

-

- - .

. _ .

. .

-

i

\\

Self Assessment Reports

Number

Title

j

95-056

Auxiliary Feedwater System

+

95-039

System Engineering Self Assessment

96-025

System Engineering Self Assessment Effectiveness Follow-Up

96-033

Licensee Event Report Program

Drawings

Number

Title

M-12BB01

P&lD Reactor Coolant System, Revision 15

M-12BG03

P&lD Chemical & Volume Control System, Revision 16

M-12BN01

P&lD Borated Refueling Water Storage System, Revision 08

M-12EJ01

P&lD Residual Heat Removal System, Revision 15

M-12EM01

P&lD High Pressure Coolant injection System, Revision 16

M-12EM02

P&lD High Pressure Coolant Injection System, Revision 09

M-12EM03

P&lD High Pressure Coolant Injection System Test Line, Revision 00

Reportability Evaluation Request Form

Number

Title

96-035

Mechanical Position Stops on BG Valves, dated October 23,1996

Procedures

Number

Title

28D-001

Self Assessment Process, Revision 2

05-004

Specifications, Revision 1

05-003

Design Document Change Notice, Revision 1

10

05C-002

Engineering Evaluation Requests, Revision 0

05-002

Dispositions and Change Packages, Revision 2

05-001

Change Package Planning and implementation, Revision 2

211001

Temporary Modifications, Revision 1

AP23L-001

Lake Water Systems Corrosion and Fouling Mitigation

Programs,

Revision 0

SYS EF-205

ESW/Cire Water Cold Weather Operations, Revision 1

STS EF-100A

ESW System inservice Pump A and ESW A/ Service Water Cross

Connect Valve Test, Revision 17

STS EF-1008

ESW System inservice Pump B and ESW B/ Service Water Cross

Connect Valve Test, Revision 18

STS EF-001

Essential Service Water Valve Check, Revision 7

STS IC-917

Analog Channel Operation Test Essential Service Water To Air

Compressor isolation, Revision 5

STS IC-602 A

Slave Relay Test K602 Train A Safety injection, Revision 8

,

'

STS IC-603 A

Slave Relay Test K603 Train A Safety injection, Revision 14

STS IC-608 A

Slave Relay Test K608 Train A Safety injection, Revision 11

STS IC-609 A

Slave Relay Test K609 Train A Safety injection, Revision 10

STS IC-927

ESW to Air Compressor High DP isolation, Revision 3

STS IC-918

Channel Calibration Essential Service Water to Air Compressor

Isolation, Revision 4

STS AL-005

Auxiliary feedwater Auto Pump Start and Valve Actuation, Revision

11

STS KJ-001B

Integrated D/G and Safeguards Actuation Test Train B, Revision 14

AP 14A-003

Scaffold Construction and Use, Revision 3

AP 21G-001

Control of Locked Component Status, Revision 7

STS BG-004

Chemical and Volume Control System Seal Injection and Return Flow

Balance, Revision 5

11

ST S EM-001

ECCS Throttle Valve Verification, Revision 11

MGE LT-012

SMB 000 Removal / Replacement, Revision 1

EMG ES-12

Transfer to Cold Leg Recirculation, Revision 7

AP 02-002

Chemistry Surveillance Program, Revision 2

STS EM-0038

ECCS (Safety injected Pump) Flow Balance, Revision 0

STS EM-003A

ECCS (Centrifugal Charging Pump) Flow Balance, Revision 0

STS CR-001

Shift Logs for Modes 1,2, & 3, Revision 33

STS BG-002

ECCS Valve Check and System Vent, Revision 8

STS EM-003

ECCS Flow Balance, Revision 8

STS IC-902A

Actuation Logic Test Train A Residual Heat Removal Suction isolation

j

Valves, Revision 0

i

STS IC-9028

Actuation Logic Test Train B Residual Heat Removal, Revision 0

STS KJ-001 A

Integrated D/G And Safeguards Actuation Test - Train A, Revision 14

STS KJ-001B

Integrated D/G And Safeguards Actuation Test - Train B, Revision 14

STS IC-740A

Residual Heat Removal Switchover to Recirculation Sump Test - Train

A, Revision 9

STS IC-740B

Residual Heat Removal Switchover to Recirculation Sump Test -

Train B, Revision 9

Work Requests and Work Packages

Number

Title

110110

Motor-operated valve motor insulation found designated incorrectly

104812

Residual Heat Removal Pump Mechanical Seal Leakage

104898

Replacement of Relief Valve EJ8856A

106028

Residual Heat Removal Heat Exchange A Shell to Waterbox Bolting Torque

Verification

107013

Valve EJV0053 Needs Lubrication of Stem

12

.

107292

Screens require refurbishment due to corrosion

108111

Essential service water pump motor oil level low

109892

Running of Residual Heat Removal Pumps Below 1700 gpm for Extended

Periods of Time

109954

Inspect Pump Internals Due to Material Found in Valve ME8956C

110193

Wall thickness due to corrosion

110524

Installation of Temporary Gauge @ EJV0063 Downstream of HV8840

)

110622

Valve EJHCV0606 Leaks By (open)

-

110955

Essential service water pump operation below flow limits

110959

Residual Heat Removal Pump A Run at Flow Rates Below 1700 gpm

113208

Essential service water pump casing line leaking

113614

Leaking valve

113731

Valve EJ HCV-8890B Will Not Open

114876

Verify Shell to Waterbox Bolting Torque for EEJ01 A (open)

115491

Check Valve EJ8730B Not Fully Seating (open)

108477

Essential service water pump prelube tank level indicator f ailed

109280

Cross tie valve f ailed leakage test

111729

Replacement of handle on essential service water tank screen

110136

Valve actuator shaft sheared off

Performance Improvement Requests

Number

Title

96-1488

Drawing change not properly removed from document control file

96 0634

Limit switch rotors not set correctly

96-0500

Drawing not added to vendor manual

13

-

.

=

_ ..

.

_ - - .

-

.

96-1617

Questions related to essential service water icing event

96-1542

Non safety-related sealant used

96-1288

Confusion in throttle valve position

96-0659

Multiple failures of actuator shear pins

96-0365

Level indicator problems

96-1684

Inservice Testing stroke time f ailure

96-1214

Valve exceeded maximum alert stroke time

96-1741

Incorrect stroke time in procedure

96-1836

Corroded bolt holes on essential service water tank basket

96-1395

Difficulties encountered with controlotron operation

96-0737

Severe corrosion on essential service water piping and valves

96-0579

Severe corrosion on essential service water strainer backwash piping

96-2502

Valve failed stroke time test

96-1953

Fuse blocks found swapped

96-1902

Procedure conflict with updated safety analysis report

96-2675

USAR Statement on ECCS Water Hammer

96-2729

Missing Internal Missiles Design Basis Calculation Refe ence

96-2733

Questionable Use of a Pipe Whip Assumption in a Design Basis

Calculation

95-0428

Industry event evaluation regarding SI Pump Runout Potential

96 2710

Mechanical Position Stops on BG Valves

94-0427

Low Flow Cavitation Limit Exceeded

94-0092

Limitorque Maintenance Update 92-02

94-0090

Limitorque Maintenance Update 92-02

94-0089

Limitorque Maintenance Update 92-02

14

,

95-0910

CCW Return Thermal Relief Valve Not Rescating

95-2901

Plant Modification Prepared Without Referring to Interim Drawing

Changes

96-1014

Excessive Valve Local Leak Rates

94-0825

Potential for inadvertent Safety injection Actuation During

Surveillance Testing

96-0308

Generic Letter 96-01

95-0625

Mitigation and Evaluation of Pressurizer Thermal Transients Caused

by Insurges and Outsurges

95-0336

Lifting of Residual Heat Removal Relief Valves EJ8856A, B & EJ8842

96-0384

Thermal Binding Issue w/ Regard to Motor-operated valve EJ

HCV8840

.

15

. . . _ _

_ _ . _ _ . . _ . _ _ _ - . . _

. _ . _ _ . _ _ _

. . - . _ . - . _ . _ _ _ _ . _ _ . _ _ ~ _ . _ . _ _ _ _ . . _ . _ _ . - . _ . , _ _ _ _ _ _ _ _ . ,

1

i

ENCLOSURE 5

COPY OF THE LICENSEE'S PLANT MODIFICATION REQUEST PMR 00903 PRESENTED

,

DURING PREDECISIONAL ENFORCEMENT CONFERENCE EA 96-470; JANUARY 16,1997

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PERFORMING 10CTK50.59

SATITY EVALUATIONS

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(SHIFT 1 of 3)

INSTRUCTIONS:

Complete parts I. II. III. V. and VI for all design chang

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3

ATION on the SATETY RIVIIk' RECORD. if one or more itCom

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E.

YES

/ KO

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3

document involve making changes in the

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N

analysia repert?

C.

TES

[NO

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document involve conducting tests or

expericents not described in the safety

analysis report?

II. f_SAR CRANCE DETERMINATION

A.

YES

NO

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document invelve a change to the TSAT?

b.

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IV.

10rTt50.59 UNREVID.'ED SATTTY OUEST!07: DETERMINATION

N/A

-

N

Cecplete the UNREVIEb'ED SAFETY QUESTION DETERMIl:ATION on the SAFETT

~

REVIEW REf.0P.D.

O

YES

/ NO

Doer the change described in the prinary

'

_

o

document involve an UNREVIEEED SAFEn

QUESTION, as determined on the EAFEU*

I

N

REVIEW RECORD.

If YES, a SATETT JUSTITICATION is required to justify the acceptability

of the change.

V.

LICENSIliC CHECKLIST DETER}ff tlATION

For all items in this part, identify where the change should be cade and

briefly describe the change in the space provided. (Attach additional

sheets if required.)

The following harsrds analyses need to be 9pdated as a result of the

change described in the primary document.

[ NO

II/I

YES

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(LICENSING REVID! SUPPLDEh7)

(SHEET 3 of 3)

.

I

I NO

Fire Estards

YES

_

Tire Preak

NO

YES

_

Missile

1 TES I NO

'

Flooding

YFS

NO

_

ALAPA

YES

No

reviews need to be updated

_

i

The following qualifiestion prograss or licens ng

.9

i ry document.

as a result of the change described in the pr na

m

EnvironmentcI Qualification

YES

NO

_

Seisnic Qualification

YES

NO

_

Human Factors Revtes

N0

YES

N

_

I

CCCT.DINATIC!: /J:D APPF.0 VAL

Date

_

Approval

VI.

/

Date

Coordination

b

bfl4 Ih

19 S5

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Mach,

19!(/s @

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Tilesponsible Engid6er

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Rev, o

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Insticting Docucent No. West.B B 4 -It 6 pcv. 7

PMP No.

c & - I C. 3 - W

Rev. ]

,

SATETT kEVIEW RECORD

,

UNF.EVIEWID SATETT QUESTION DETERMINATION

(SHEET 1 of 2)

INSTRl'CTIONS:

1.

Evaluate each of the criteria Lclow for applicability te the chanac

,

t

described in tha primary document and check YES or NO as appropriate.

-

,

2.

In the space below each criterion, document the applicability evaluation

for each criterion; negative declarations and justifications are

required. (Attach additional sheets, if required.)

N

3.

If any criterion is applicable, er 1HREVID'ED SAFETY QUESTION exists and

a SAFETY JUSTIFICATION must be docueented. NRC approval is required

,

prior to making the change or conducting the test er experiment.

"'

,

.

"'*

A.

YES

/ NO

Will the probability of occurreuce of an accident

i

previously evaluated in the safety analysis report

~

be increased?

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3.

YES

NO

Will the consequences of an accident previously

evaluated in the safety analysis report be

N

increased?

See A

e t.

!

C.

YES

NO

Is there e possibility that an accident of a

different type from any evaluated previously in

~

the safety analysis report may be created?

l

i

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1

bet A abovt

I

.

D.

YES

NO

kil) the probebility of occurrence of malfunctions

of equipment important to safety, previously

evaluated in the safety analysis, be increased?

.*

,

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A nw o v e.

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SAFEU pp

DE ERMINATION

.

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UEF,gyIEVED SAFETY Q

(SHEET 2 of 2)

Will the consequences of a sw1 function of equipment,

d in the

important to safety, previously evaluate

YES

NO

safety analysis report, be increased?

E.

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In there a possibility that a malfunction of

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t d which

equipment iriportant to saf ety, may be crea e

YES

V NO

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it,the safety ct.alysis report?

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Will a reduction in the margin of safety, asin

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YES

NO

C.

result?

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An UNREVIEVED SAFETT QUESTION exists. (i.e. , any o

the above criteria are applicable).

YES

NO

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See A

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PmiOc40!

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REDA No. N-L-$0b- h

Rev. A

Initiating Document xhLR e + ne Rev. A

PHP No.

c s . t &, ~3 - w

Rev.

o

,

I

i

,

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A!>nA RIVII'n' RISULTS

.

!

,

'

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PART I - CIRNGES NOT I!TVOLVING RADIATION HAZARDS

It can be concluded that there is reasonable assurance that this

!

proposed design change does not involve a radiation hasard.

This

proposed design change does not require design provisions or

l

considerations to comply with ALARA guidelines.

i

%

'

9

b.'

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Prelininary ALARA Review

,

"

Primah Group Supervisor Dite

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Tinal A1. ARA Reviev

.

Licensing Engineer

Date

,

N

PART II - CRANGES INVOLVING POTENTIAL RADIATION RAZARDS

-

I hereby verify that this proposed design change does include

appropriate design provisions and considerations that cortply with

!

O

ALARA guidelines to the extent practicable. There is assurance

that radiation exposures to plant operating personnel vill be

o

,

i

l

ALARA.

l

N

i

Preliminary ALARA Review Primary Group Supervisor

Date

Final ALAP.A Peview

Date

Licensing Engineer

PART III - APPROVALS

,

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Project Engineer or

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Initiating Document NollW L A A4-RARev.

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. C S, - # & 3 - V

-

Rev. T

TIRE PROTECTION REVID' CERTIFICATION

i

A.

_ PRELIMINARY FIRE FROTECTION RryIEW

I hereby certify that

this design change does not

proposed design change can be developed so thatprot

'

impact the fire

thet the

requirements will be cer.

fire protection

f'

Signed:

'

!

i

10-% states

n

_

Raftponsible EngineerU

Date~

(Origination Discipline)

.--

Reviewed:

A final fire prottetion review (is)

'

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required.

La

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chlGroupSupervi$ry

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Serpor MthanicalSupervisor(Jobsite) Gro#p Supervisor or

r Date

~

Date

TIKAL MIRE PROTECTION REVIDI

Senior Supervisor (Jobsitc)

E.

_,_

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o

I hereby certify that

desi n char.ge incorporates design provisions tothe doculeentation pre

t

n

,

protection requirements.

e

.

assure fire

N

Signed:

>

Signed:

Mechanical Responsible Engineer Date

itemponsible Engineer

Date

(Originating Discipline)

Mechanical Group Supervisor or

Senior Mechanical Supervisor (Jobsite) Uroup Supervisor or

Date~

Daty

i

(Originating Disciplir.e)

C.

A PPROVA L S

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Proj ect Engineer or

Date

Ass't. Project Engineer (Jobsite)

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.

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__

_ _ _ _ . . . _ _

l

xsNsAs CAs sNo titcraic company

- . s :-: :w.. .

December 17, 1984

Mr J H Smith

Project Engineering Manager

l

.

Bechtel Power Corporation

i

15749 Shady Grove Road

Caithersburg, MD 20877-1454

-

'

FNPLB 84-118

TE - 19970 K93

SUB: Setpoint Information

REF: 1) SLKE-1179

2) KNPLB 84-116

_

. , .

Dear Mr Smith:

O

The attachment should close out all iters listed on Peference 1

for Kansas cas & Electric action, with the exception of Item 12.

'

Item 12 cannot be obtained until af ter ILRT, however since Item 12

is only required as a check, this should not hold up the setpoint

.,'

generation. Included in 'the attachment is a prio: "

Sist, if you

have any questions on this please contact Charlw e n.ts at (316)

-

O

364-8421, extension 1796.

1

O

Sincerely,

.

i

N

.

)Jp/vt,.

sv w

Melvin L ohnson

Manager Noelear Plant Engineering

'

!

,

CR.M: dab

.!

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cc: J Long w/a

,'

R Ennis w/a

C M Herbst w/a

M $ptstolles w/a i

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Item N eber Per Reference 1

i

Item 2:

See KNPLB 84-116

Item 3 & 4:

All these concerns are resolved by the revised

.

setting tolerance table. Please note, based on the

revised values, Bechtel should revise the Tech Spec

1

setpoints for instrument loops AL-37, 38, 39 and AC-

j

231, 232, 233,

'

.

Item 5 & 6:

All calibration periods are shown on the calibration

j

f requency table.

Item 7:

See KNPLB 84-116

.

Item 8:

See KNPLB 84-116

Item 9:

See KNPLB 84-116

i

Item 11:

The following test data was obtained by KC&E Start

,

l

Up.

Flow (x10

lbs/hr)

P (ht)

1.6

59.62

'

1.38

41.60

1.15

33.28

0. 9!i

17.19

0.75

-

10.26

0.5

2.77

Item 12:

This cannot be conpleted until af ter ILRT due to the

ILRT valve lineups.

Please note, Bechtel has stated

that this information is not required for generation

of thrs setpoint.

Item 13:

Per marro from chemistry the radiation monitors

setpoints (safety limits) are as follows:

,

GT - 31,32

4.9 E-3 uci/cc

G3 - 27,28

2.2 E-3 uci/cc

GK - 4,5

1.1 E-3 uci/cr

CT - 22,33

2.08 E-2 uci/cc

Kz-85 was used for preliminary data.

Please also supply data for the use of Xe-133.

l

1

'

'.

,

.-

- - -

-

f

__

_ _ . _ . _ _ _ _ _

__

N'

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%a.-.-J k m< segos

~5e follosing as a list of the BOP instruient loops for which

Beentel is calculating setpoints in support of Reg Guide 1.105.

"'he list sets priorities (f tczn 1-6,1 being the highest priority)

l

,

-

1

in order that Bechtel eay complete the calculations in a canner

which will support fuel load and power ascension.

.

Prioritv*

System

Loops

1

GK

2,3

'

1

GK

4,5

'

1

GT

22,31,32,33

'

2

EF

43,44

2

EG

1,2

f

2

In

107,108

3

AL

37,38,39

,

4

AC

231,232,233

{

.,

5

GG

27,28

-

6

BB

17,18,19,20

6

EF

19,20

)

-

6

IE

62

6

EU

77,78

"~

6

Di

15,16

7

6

EN 17,19

6

IC

25,26,125,126

-

6

CD

1,11

%

6

GM

1,11

6

JE

1,21 ( A ,C)

6

JE

1,21 (B)

~'

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See sheet 2 of 2 for explaination of priority codes

O

Priority

N

1

Regaired for surveillance testing in modes

. 1,2,3,4,5,6

2

Regaired for surveillance testing in modes

1,2,3,4

3

Regaired for surveillance testing in modes 1,2,3

Required for surveillance testing in mode 1

4

-

5

Regaired for surveillance testing in mode

1,2,3,4,5,6 after 1st refueling

6

No surveillance test requirenent exists

OPERATIONE MODES

REACTIVITY

% RATED

AVERAGE COOLAlff

MODE

CONDITION, K

THER'%L PCfdER*

TEMPERATURE

gg

.

1.

ICWER OPERATION

> 0.99

> 5%

> 350 F

2.

STARTUP

I 0.99

< 51

I 350 F

'

3.

HM STANDBY

7 0.99

0

I 350 F

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HM SHimXhH

< 0.99

0

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5.

COLD SHWDCAH

< 0.99

0

< 200 F

t

~ 140 F

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6.

REFUELING **

< 0.95

0

,

Excluding decay heat.

-

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less than fully tensioned or with the head removed.

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SNUPPS-WC

TABLE 9.2-1

,,

ESSENTIAL SERVICE WATER SYSTEM CC?'PONENT DATA

1

l

Essential Service Water Pump (all data is per pump)

Quantity

2 (100% each)

Type

Vert centrifugal - 2 stg.

with packed stuffing boxes

C ar ', ci ty ,

gpm

15,000

TDH

ft

361

Submergence required, ft

9

Platerial

C

Case

Carbon steel

Impeller

Aluminum - Bronze

Shaft

Stainless Steel

Design Codes

AstT Section, III C1. 3

Driver

Type

Electric motor

Horsepower

1,750

RPM

885

Power Supply

4,000 V 60 Hz, 3-phase, C1.1E

Design Code

NEMA

Seismic design

Category I

Essential Service Water Pump Prelube Storage Tanks

/*

(all data is per tank)

Quantity

2

Type

Vertical

Capacity, gallons

43

Design pressure

Atm.

Design temperature, F

122

Shell material

Carbon steel

Corrosion Allowance

1/16 inch

Design code

ASME Section III, C1. 3

Seismic design

Category I

'

Essential Service Water Self Cleaning Strainers

(all data is per strainer)

.

Quantity per unit

2

Capacity, gpm

15,000

Pressure drop, clean

1.1 psi

Pressure drop, dirty *

3.0 psi

'

Strainer openings

1/16 inch

Design pressure psig

200

Design temperature, F

100

At start of backwash

i

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-- -

. . - - .

.- - - . . ~ . - . _ _

. - , - - . -

. . - . -

_ . - . - . . _ . . -

.

A3 i

SNUPPS-WC

,

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TABLE 9.2-1

a

]

ESSENTIAL SERVICE WATER SYSTEM COMPONENT DATA-

l

Essential Service Water Pump (all data is per pump)

!

Quantity

2 (100% each)

,

o

Type

Vert centrifugal - 2 stg.

with packed stuffing boxes

capacity, gpm

15,000

TDH, ft

361

Submergence required, ft

9

}

Material

-

Case

Carbon steel

3

j

Impeller

Aluminum - Bronze

Shaft

Stainless Steel

!

I

Design Codes

ASME Section, III C1. 3

Driver

!

Type

Electric motor

Horsepower

1,750

4

RPM

885

j

Power Supply

4,000 V 60 Hz, 3-phase, C1.1E

Design Code

NEMA

d

Seismic design

Category I

'

4

Essential Service Water Pump Prelube Storage Tanks

'

(all data is per tank)

'

Quantity

2

Type

Vertical

Capacity, gallons

43

l

Design pressure

Atm.

Design temperature, F

122

Shell material

carbon steel

Corrosion Allowance

1/16 inch

Design code

ASME Section III, C1. 3

Seismic design

Category I

Essential Service Water Self Cleaning Strainers

(all data is per strainer)

Quantity per unit

2

Capacity, gpm

15,000

Pressure drop, clean

1.1 psi

Pressure drop, dirty *

3.0 psi

Strainer openings

1/16 inch

Design pressure psig

200

Design temperature, F

100

At start of backwash

}{bD-OOD

%

C'C.7 POI:3T Cll ANGC REQUEST

,.-

,

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LEF

.Mt ni

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SYS DSS

YR

No

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PART I

System

EF- EMEW1 Al %0G WA%~.R

Component No.

'Pb% 19 l/2. % 20 V2

Computer Point (s)Funct ion _. SELF" OtF4 MING SYMNER 'D/PSatety-Relat

Yes

j_l N6

Component

\\

Mft

Prasent

Requested

}

Setpoint

(ATER

Tolerance

S,5 PSjD

LA N

-t-- O. 5%

Reference Drawing _ J K 2. Ef0% A/2

Manual-

W

Requested by__EAny 'fONLE.

Date

S/

13

/

89

I&C Supervisor Approval Alfa Wo% lMITI ATEb

Reason for Change Abb MatinWARY SETPotLIT

Date

/

_

.

~

.

PART II

Affected Drawings

Mh

Procadures_

Mh

PSAR or Tech Spec Section(s) MA

FSAR or Tech Spec Limit (s)

NA

'

ALARA Review

Date

/

Engineering Review:

_

!!A ig

'

Recommend ed

Rejected l]

Date 3

/ /3

/ '84

Remarks- 'PD a l9 t/2 *2G L/f WlLL

-

f esits 6ecem.eru.rt:r Tm8- wt va(sa-mes <^""ATT A0.h m .

.

TN,[" Operations Review:

- / /

BC 5:tM u2fo

Sig nature

f

/#3

Da t e J-73 M

'

~ Recommend ed l]

Rejected l]

t

/

Remarks

-

Signature

N/A

Date

/

PART III

_a

,

Set Point Change Request

Approved

I

}

Dj approved

Plant Support Su pe rv iso r

/j[y[

l

PSRC Review:

Approved

j~~l

Disapprov$d

s / _Da_te

3

~

-e

t

/ 3- 9

l

NA

[-l

PSRC Chairman

DEel

/

_

PA RT IV

Actual Setpoin

,j . f ,c Y

[

D

Completed by_

- Eo,_WA.&//7 M L

Dato

/ / /) / E

,

CC:

Originator

NEUENEU

Resul ts Engineering

Ope ra t io ns

Computer Engineering

Tr ai n i ng

JUL 07 $36

AD:t 05-102

I&C

Rev. O

NPE

dage 4 of 4

EORC3 ?COM

,

KOS~ 005

-

,.

Molf Creek Generating Station

'

FSRC l!!: VIEW SilEET

Figure 0

,

PROCEDURE MUMBER AND REVISION:

ADrA-O5-1O hO

PROCEDURE TITLE:

ko

(:o-

CG M

o ed

c.

C

gu t- A E F - 84 -o \\

.

Superintendent of Operations

Date

Superintendent of Technical Support

Date

SuperinteM qf Itainten nce

Date

Chemist

--

--

Date

3-N aP r

U

i

!!ealth Phys icist

Date

I&C Supervisor

Date

Superintendent of Plant Sug > rt

D a t e J- ~/J --f %

,

Reactor Supervicor

i

l} D

Date

,M,-

Results Supervisor

f.-s /[

Dated

Yk

C

,

, ,-

.

Superintendent of Requ i itor, , Ou . i ty and Adia i n i p..ra-

tive Services

.-

/M.E

Date 3 V'/ 'PV

'

V

Quality Assurance

Date

( AC:1, STS, OCP only)

!

I

Approved:

[M

/ #A/,Jr na td-/9-J P

PS HC Cit a t r:aan

RECEIVEU

AM 07-100

JUL 07 ssg

nuv- 15

Parte 17 of 20

QA RECORDS ROOM

..

'

/(Ub-00b

-

.

-

,

'

,

SETPOIN T ltJOEX

INPUT Font.1

.

SYS

,

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FUNCTION CCOE

I

SEC.NO.

elf

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Ol0ll19}

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SUF

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SERVICE DESCRIPTION

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SETPOINT INDEX

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INPUT FORT.1

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.

SYS

FUNCTION CODE

SEO.NO.

El

flDISIll

gol2lO'

[Il/if

gyp

73

'

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SERVICE DESCRIPTION

E S W

SELF. C_ ' L

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,

.

SS Esf/in),417pn6LSE /C,909

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,

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INSTRUMENT SETPOINT

50

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PlSll IDI

I

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tl

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151%l j

Y behc..$, $hW$' ,/.,~ <l5U

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ML20134A613

Text

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