ML20198N177

Insp Repts 50-352/97-07 & 50-353/97-07 on 970722-0915. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20198N177
Person / Time
Site:	Limerick
Issue date:	10/27/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20198N168	List: ML20198N165 ML20198N170 ML20198N177
References
50-352-97-07, 50-352-97-7, 50-353-97-07, 50-353-97-7, NUDOCS 9711030182
Download: ML20198N177 (42)

See also: IR 05000352/1997007

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

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Docket Nos.

50 352

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50 353

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License Nos.

NPF39

NPF 85

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Report Nos.

97 07

97 07

Licensee:

PECO Energy

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Facilities:

Lirnc:,ck Generating Station, Units 1 and 2

Location:

Wayne, PA 19087 0195

Dates:

July 22,1997 through September 15,1997

Inspectors:

N. S. Perry, Senior Resident inspector

R. L. Fuhrmeister, Project Engineer

L. L. Eckert, Radiation Specialist

R. M. Latta, Operations Engineer, NRR

L. L. Campbell, Senior Operations Engineer, NRR

Approved by:

Clifford Anderson, Chief

,

Projects Branch 4

Division of Reactor Projects

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EXECUTIVE SUMMARY

Limerick Generating Station, Units 1 & 2

NRC Inspection Report 50 352/97 07, 50 353/97-07

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This integrated inspection included aspects of PECO Energy operations, engineering,

maintenance, and plant support. The report covers an 8 week period of resident

inspection.

Ooerotions

Since a number of valves were identified as inadequately locked as required, a

programmatic problem existed concerning how valves are locked and independently

verified as adequately locked. Immediate corrective actions taken of verifying all

accessible valves listed in the Locked Valve List, as adm ately locked were good.

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(Section 02.1)

The reactor water clean-up (RWCU) system automatically isolated due to a high

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differential flow condition while restoring a filter demineralizer to service. The high

differential flow condition was caused by the B RWCU filter domineralizer Y strainer

manual drain va!ves leaking into the backwash receiving tank. The affected valves

were adjusted, and the filter domineralizer was returned to service; no other

comparable valves were found leaking on Unit 1 or Unit 2. Additionally, on August

6, for Unit 2, and September 10, for Unit 1, there were a number of RWCU

luolations. This large number of isolations over a fairly short period of time was a

challenge for the operators. These concerns regarding the RWCU systems for both

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units will remain as an inspector follow up item, pending review for common cause

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issues and maintenance rule implications. (Section 08.2)

Maintenance

Observed maintenance activities were conducted well using approved procedures or

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work instructions, and were completed with satisfactory results. Communications

between the various work and support groups were good, and supervisor oversight

was good. (Section M1.1)

in general, surveillances were performed by knowledgeable personnel, and were

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satisfactorily completed. In particular, very good system manager support for the

Unit 1 reactor core isolation cooling (RCIC) test; also noted was the knowledge level

of the attending equipment operator for the RCIC pump run. Overall, surveillance

tests were conducted well using approved procedures, and were completed with

satisfactory results. Communications between the various work and support groups

were good, and supervisor oversight was good. (Section M1.2)

Proper actions woro taken to ensure that a TS required voltage verification was met,

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once it was discovered to be potentially missed. However, personnel did not

properly track the missed surveillance step to ensure that it was completed when

the clearance was removed. Additionally, the engineering review which concluded

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Executive Summary

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that the TS tequirement had been met by an alternate means appeared weak.

(Section M1.3)

Personnel identified foreign materialin the high pressure coolant injection (HPCI)

turbine exhaust drain pot drain line which rendered the HPCI system inoparable

since an undetermined amount of condensed water was present in the HPCI turbine.

This resulted in a violation of the foreign material exclusion (FMEl program. (Section

M8.1)

Enaineerina

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Actions taken to address each 021 test failure have been appropriate. Although no

clear tie between the f ailures has been determined, investigations continue.

(Section E1.2)

Operators appropriately declared three EDGs inoperable when they became aware of

a potentlat problem with the fuel oil due to a high cloud point. The EDGs were

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declared operable later the same day after it was shown that the oilin the storage

tanks was below the cloud point maximum. However, documentation for the

operability datermination was weak,in that various work groups had to be

contacted to get all of the facts of the operability determination. (Section E1.2)

Plant Suncort

The licensee maintained and implemented good routine radioactive liquid and

gaseous effluent control programs. Tne radiation monitoring system (RMS)

calibration program was good, as were the ventilation system surveillance program

and Quality Assurance and Quality Control programs. Several opportunities were

identified in which RMS system tracking and trending could be improved.

Fire protection procedures were found to provide adequate guidance and appropriate

acceptance criteria for testing fire protection equipment. (Section F3.1)

Station personnel identified that a potential voltage mismatch may exist between a

fire protection deluge valve and its control panel, resulting in marginal power

available to operate the valve. An evaluation concluded that a technical

specification noncompliance occurred between issuance of the facility operating

license for Unit 1 on October 26,1984, and December 20,1995, when the

technical specifications were relocated to the Technical Requirements Manual, since

the valve may have been unable to perform its design function. Corrective actions

included making adjustments to the valve to optimize mechanical operation, posting

a continuous firewatch, increased testing of the valve, and the valve was replaced

on September 3,1997. This violation had more than minor significance since it

resulted in a condition where a technical specification-required deluge valve was

inoperable for an extended period of time and resulted in a non-cited violation. The

safety consequences for this event were low. (Section F8.1)

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TABLE OF CONTENTS

S u m m a r y o f Pl a nt S t a t u s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01

C ond uct o f O p e ration s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

02

Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . 1

02.1 Control ei Locked Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

07

Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

07.1 Self. Assessment Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

08

Miscellaneous Operations issues . . . . . . . . .

3

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08.1 (Closed) LER 2 97 008, Automatic Closure of Drywell Chilled Water

System Primary Containment isolation Valves, An ESF Actuation,

Resulting From Emeigency Diesel Generator Voltage Regulation Failure . 3

08.2 (Closed) LER 2 97 009, Reactor Water Clean-up (RWCU) Isolation, An

ESF, Caused by a RWCU Filter Der.iineralizer Y Strainer Manual Drain

Valves Leaking into the Backwash Receiving Tank . . . . . . . . . . . . . . . .

3.

II . M aint e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

M1

Conduct of Maintenance

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M 1.1 General Comments on Maintenance Activities . . . . . . . . . . . . . . . . . . . 4

M1.2 General Comments on Surveillance Activities . . . . . . . . . . . . . . . . . . . . 5

M1.3 Potential Missed Surveillance Test

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M8

Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

M 8.1 (Closed) LER 2 97 007 Unit 2 HPCI System inoperable Due to

Clogged Turbine Exhaust Drain Line

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Ill. Engineering

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E1

Conduct of Engineering

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E 1,1

D21 Emergency Diesel Generator issues

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E1.2 Emocqancy Diesel Generator High Cloud Point Response . . . . . . . . . . . . 8

E7

Quality Assurance on Engineering Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 9

E 7.1.1

Review of PECO Audits and PECO's Use of Third Party Audits . . 10

E 7.1.2

Review of Commercial Grade Surveys . . . . . . . . . . . . . . . . . . . 14

E7.1.3

Purchase Order Revision Controls . . . . . . . . . . . . . . . . . . . . . . 15

I V . Pl a n t S u p p o r t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

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Table of Contents

R1

Radio'ogical Protection and Chemistry (RPF s Controls . . . . . . . . . . . . . . . . . 17

R1.1 Implementation of the Radioactiv<

id and Gaseous Effluent

ControI Programs . . . . . . . .

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R2

Status ot RP&C Facilities and Eoulpment .

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R2.1 Calibration of Effluent / Process / Area / Accident Radiation Monitoring

Systems (RMS) ..............................

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R2.2 Air Cle aning Syste ms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

R7

Quality Assurance (CA) in RP&C Activities . . . . . . . . . . . . . . . . . . . . .

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F1

Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

F1.1

Main Control Room Fire Suppression System . . . . . . . . . . . . . . . . . . . 21

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Status of Fire Protection Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . 22

F2.1

in Plant Walkdo wns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

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Fire Protection Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . 24

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Procedure Upgrade Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

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Fire Protection Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 28

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F6.1

Fire Prote ction Council . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

F6.2 Fire Protection Focused improvement Team . . . . . . . . . . . . . . . . . . . . 29

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F8

Miscellaneous Plant Support issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

F8.1

(Closed) LER 1 97 006, Previous Condition Prohibited by Tech Specs

in thrt a Fire Protaction System Deluge Valve may not have

Funedoned per Design Since issuance of the Unit 1 Operating License . 30

V. Management Meetings . . . . . . . . . . . . . . . .

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X1

Exit Maeting Sum mary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

X2

Review of UFS AR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

ITEhnS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

LIST O F ACRO NYM S USE D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

LIST O P DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

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Report Details

Summary of Plant Status

Unit 1 began the inspection period operating at 100 percent power. The unit remained at

full power throughout the inspection period with minor exceptions for testing and the

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following events:

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August 31

Operators reduced reactor power to 60 percent following a

loss of one control rod's position during the weekly control rod

exercise test. After fully inserting the control rod, the unit

returned to 100 percent power on September 1.

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September 12

Operators reduced reactor power to approximately 60 percent

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to perform a control rod sequence exchange, to scram time

test control rods, and to work on the A reactor feed pump.

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The unit was returned to 100 percent power on September 14,

after completion of the activities.

Unit 2 %gon the laspection period operating at 100 percent power. The unit remained at

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full power throughout the inspection period with minor exceptions for testing and the

following event:

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August 11

Operators reduced reactor power to 97 percent after a steam

leak was identified at the main turbine first stage pressure

switch. The switch was isolated and power was returned to

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100 percent the same day.

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1. DoeratioDE

01

Conduct of Operations'

01.1

General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted freque:it reviews of

ongoing plant operations, in general, PECO Energy's conduct of operations was

professional and safety conscious.

02

Operational Status of Facilities and Equipment

02.1 Control of Locked Valves

a.

insoection Scoos (71707)

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During this inspection period, the inspector identified instances where valves,

required to be locked to restrict operation, were not adequately locked.

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' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report

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outline. Individual reports are not expected to address all outline topics.

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Additionally, operations personnel idantified other similarly inadequately locked

valves. Immediate corrective actions were discussed with operations personnel.

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b.

Observations and Findinas

On August 18, the inspector identified a Unit 1 C core spray valve (0521F016C,

seal vent to drain) which appeared to be inadequately locked in that the chain

around the valve handwheel had a large amount of slack in it. After checking the

other Unit 1 core spray pumps, the inspector notified control room operators of the

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valve. Operators subsequently tightened up the chain. On August 20, the

inspector identified two analogous core spray valves on Unit 2 with an excess of

slack in the chain. Again control room operators were notified and the valve chains

were tightened. On August 22, the inspector discussed the locking of valves with

plant management, and noted that the operators should have checked the other

unit's core spray valves when one was identified as deficient; plant management

was in agreement. On August 26, the inspector performed a walkdown of the Unit

1 reactor building to determine if other valve locking devices were adequate; the

inspector performed a similar walkdown of the Unit 2 reactor building on August

27. A significant number of valves were identified as potentially inadequately

locked. After verifying that the valves were required to be locked, the inspector

notified control room operators of the concern that there may be a number of valves

in the plants which are inadequately locked.

During the next several days, operations personnel walked down all accessible

valves listed on the Locked Valve List to determine the extent of the problem. No

valves were identified as out of the required position. However, a number of valves

were identified as either inadequately locked or in need of tightening up of the

locking mechanisms. Prior to the end of the inspection period, all accessible valves

required to be locked were appropriately verified as adequately locked. No further

discrepancies were identified by the inspector.

Limerick administrative procedure A C-000, Centrol of Locked Valves and Devices,

Revision 0, requires in part, that the lock.ou

.: be applied through the

handwheel or other operating mechanism to restrict operation of the valves and

devices listed in the Locked Valve List. Additionally, the procedure notes that the

intent of the locking device is for administrative control over the position of

specified valves and devices, and 'he component should be locked so as to prevent

excessive movement. During thie qspection period, the inspector and subsequently

operators identified a number of valves which were not adequately locked as

required by administrative procedure A C 008. This is a violation. (VIO 50 352.

353/97 07 01)

c.

Conclusions

Since a number of valves were identified as inadequately locked as required, a

programmatic problem existed concerning how valves are locked and independently

verified as adequately locked, immediate corrective actions taken of verifying all

accessible valves listed in the Locked Valve List, as adequately locked were good,

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07

' Ouality Assurance in Operations

07.1 Self-Assessment Activities (71707)

During the inspection period, the inspectors reviewed or attended various self-

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assessment activities, including:

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various Plant Operations Review Committee (PORC) meetings and meeting

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minutes

the quarterly Nuclear Review Board (NRB) meeting on September 4

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various quality verification and independent safety engineering group reports

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The inspectors noted in particular that at the NRB meeting, members thoroughly

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reviewed plant events and appropriately questioned plant management concerning

root causes and corrective actions. The NRB members actively participated in the

meeting with open discussions of the issues, while maintaining a focus on safety.

08

Miscellaneous Operations issues (90712)

08.1 (Closed) LER 2 97 008. Automatic Closure of Drvwell Chilled Water System Primarv

Containment isolation Valves. An ESF Actuation. Resultino From Emeroency Diesel

Generator Voltaae Reaulation Failure.

This Licensee Event Report (LER) concerned an instance where a relay failure

associated with an electrical bus overvoltage condition, which was caused by an

EDG voltage regulation failure, caused the automatic closure of drywell chilled water

system primary containment isolation valves. The event occurred during

performance of a special test for the D21 EDG. The cause of the relay failure was

determined to be a coil failure that resulted from the excessive voltage of the event;

no other loads connected to the bus were found to be adversely affected. The

drywell chilled water system valves were reopened and declared operable when the

f ailed control circuit relay was replaced. Troubleshooting, maintenance , and testing

were completed on the D21 EDG. The EDG voltage regulator's failed rectifier bank

was swapped to an alternate rectifier bank and tested satisfactorily; the EDG was

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then restored to an operable condition. The defective rectifier bank will be shipped

offsite for failure analysis. The LER met the requirements of 10 CFR 50.73, and the

inspector had no further questions regarding the event.

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08.2 (Closed) LER 2 97-009. Reactor Water Clean-uo (RWCU) Isolation. An ESF. Caused

by a RWCU Filter Demineralizer Y Strainer Manual Drain Valves Leskina into the

Backwash Receivina Tank.

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This LER concerned an instance where the RWCU system automatically isolated due

to a high differential flow condition while restoring a filter demineralizer to service.

The high differential flow condition was caused by the B RWCU filter domineralizer

Y strainer manual drain valves leaking into the backwash receiving tank. The

affected valves were adjusted, and the filter demineralizer was returned to service;

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no other comparable valves were fouvf leaking on Unit 1 or Unit 2. The LER met

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the requirements of 10 CFR 50.73, and the inspector had no further questions

regarding the event. However, the inspector noted that on August 6, for Unit 2,

and September 10, for Unit 1, there were a number of RWCU isolations. The

inspector was concerned that this large number of isolations over a fairly short

period of time was a challenge to the operators. The inspector was also concerned

that these events could indicate less than adequate maintenance or engineering

attention of the systems or less than adequate management attention. These

concerns regarding the RWCU systems for both units will remain as an inspector

follow up item, pending review for common cause issues and maintenance rule

implications. (IFl 50 352,353/97 07 02)

II. Maintenance

M1

Conduct of Mainten6nce

M1.1 General Comments on Maintenance Activities (62707)

a.

Insoection Scoos (62707)

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The inspectors observed selected maintenance activities to determine whether

approved procedures were in use, details were adequate, technical specifications

were sat;sfied, maintenance was performed by know!edgeable personnel, and post-

maintenance testing was appropriately completed.

The inspectors observed portions of the following work activities:

Unit 2 Standby Liquid Control tank level sensing line cleaning, on August 27

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D21 Emergency Diesel Generator fuelline replacement, on August 29

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Replacement of Unit 1 fire protection deluge valve 173, on September 2

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Unit 2 reactor core isolation cooling (RCIC) valve work, on September 9

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Unit 1 RCIC governor va!ve servo replacement, on September 11

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b.

Observations and Findinas

For the standby liquid control (SLC) tank level sensing line cleaning, the inspector

noted that the work was well coordinated between the maintenance personnel and

control room operators. During the cleaning process, the inspector identified a

chain and lock around the instrument tubing on top of the SLC tank. This was

brought to the attention of operations personnel, who were unable to identify the

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source of the lock; no locks or devices were identified in the area as missing a lock

and chain. Operations personnel concluded that the chain and lock must have been

inadvortently left there from a previous activity; operators removed the chain and

lock from the top of the tank. The inspector independently tried to determine if any

valves or devices in the area were missing a chain and lock; none were identified.

Additionally, the Unit 1 SLC tank was inspected, and no similar conditions were

identified. The inspector agreed with the operator's conclusion as the most likely

source of the chain and lock.

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For the Unit 1 RCIC governor valve servo replacemer t, the inspector observed that

there was very good system manager interface with the operators and the

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maintenance personnel. The inspector noted that although the location of the servo

is difficult to reach with some climbing required, the work was completed without

incident.

c.

Conclusions

Overall, the inspector concluded that the observed maintenance activities were

conducted well using approved procedures or work instructions, and were

completed with satisfactory results. Communications between the various work

and support groups were good, and supervisor oversight was good.

M1,2 General Comments on Surveillance Activities (61726)

a.

Insoection Scone (61726)

The inspectors observed selected surveillance tests to determine whether approved

procedures were in use, details were adequate, test instrumentation was properly

calibrated and used, technical specifications were satisfied, testing was performed

by knowledgeable personnel, and test results satisfied acceptance criteria or were

properly dispositioned.

The inspectors observed portions of the following surveillance activities:

D21 Emergency Diesel Generator (EDG) weekly, on August 14, 21, 28, and

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September 4

D13 EDG monthly, on August 19

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Unit 1 Standby Uquid Control pump, valve and flow, on August 25

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Unit 2 B Residual Heat Removal pump, valve and flow, on September 4

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Unit 1 RCIC pump, valve and flow, on September 10

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D23 EDG monthly, on September 10

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Unit 2 RCIC pump, valve and flow, on September 12

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b.

Observations and Findinos

in general, the inspector observed that the surveillances were performed by

knowledgeable personnel, and were satisfactorily completed. In particular, the

inspector observed very good system manager support for the Unit 1 RCIC test;

also noted was the high level of system knowledge of the attending equipment

operator for the RCIC pump run.

c.

Conclusions

Overall, the inspector concluded that observed surveillance tests were conducted

well using approved procedures, and were completed with satisfactory results.

Communications between the various work and support groups were good, and

supervisor oversight was good.

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M1.3 Potential Missed Surveillance Test (61726)

a.

Insoection Scooe (61726)

The inspector reviewed an instance where a technical specification required

surveillance test was apparently missed on July 18. The inspector reviewed the

operations logs concerning the surveillance, reviewed the surveillance test,

reviewed the engineering justification for how the testing requirement was

alternately met, and discussed the situation with appropriate plant persor.nel.

b.

Observations and Findinas

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On July 16, a portion of weekly surveillance test ST 6 094 450 0,120 VAC

Safeguard Power Distribution Alignment and Voltage Check, could not be performed

due to a clearance on a distribution panel (03Y501).- The procedure step, which

required verification of 120 VAC nominal voltage at the panel, could not be

completed since the panel was deenergized. it appears that when it was identified

that the surveillance test step could not be completed, the clearance should have

been annetated to indicate that when the clearance was removed, the missed

procedure step should be completed to meet the technical specification (TS)

requirement. Apparently, this was not done, and the clearance was removed

without performing the voltage verification afterwards.

On July 18, plant personnel identified that the surveillance had apparently been

missed, and that the TS requirement had not been met. The surveillance test step

was immediately performed satisfactorily, thereby satisfying the TS requirement.

Engineering personnel determined, on July 18, that the TS requirement had bean

met by an alternate means; apparently on July 17, dampers were successfully

stroked, which are powered from the distribution panelin question.

Technical Specification 4.8.3.1 requires, in part, that specified power distribution

system divisions shall be determined energized at least once per 7 days by verifying

correct breaker alignment and voltage on the panels: 120 VAC distribution panel

03Y501 is one of the specified panels. Surveillance test procedure ST 6 094-450-

O, step 4.5.3 requires verification of 120 VAC nominal voltage present at panel

OCC564, which verifies that distribution panel 03Y501 is energized. It was not

clear to the inspector that successfully cycling dampers properly verified 120 VAC

nominal voltage present at the panel. Subsequent to this, the operators who

restored the distribution panel pointed out that they had properly verified the panel

vcitage during the restoration, even though they were not directed to; therefore, the

technical specification surveillance requirement was met,

c.

Conclusions

Proper actions were taken to ensure that a TS required voltage verification was met,

once it was discovered to be - 'stially missed. However, personnel did not

properly track the missed su-

ance step to ensure that it was completed when

the clearance was removed. Additionally, the engineering review which concluded

that the TS requirement had been met by an alternate means appeared weak.

.

. - - -

,

-

.-

I

!

7

I

M8

Miscellaneous Maintenance issues (90712)

M8.1 (Closed) LER 2 97 007 Unit 2 HPCl System inocerable Due to Cloaaed Turbine

Exhaust Diain Line

This LER concerned an instance where the Unit 2 HPCI system was declared incperable

due to the failure of a routine test; the test concluded that the HPCl turbine exhaust drain

pot orifice was clogged. This rendered the HPCI system inoperable since personnel could

not determine how much water was present in the HPCI turbine. The blockage was

identified during performance of a quarterly surveillance test designed to verify that the

drain line is not blocked. The immediate corrective action was to disassemble and clean

the drain line; a small piece of cloth was found block!ng the drain line. Ercineering

]

personnel concluded that since no water was found in the drain line, HPCI would have

perfortned its intended function and was therefore available. Planned corrective actions

included: evaluation of tasks to ensure appropriate foreign material exclusion (FME)

prsctices are specified, evaluation of the HPCI system for increased monitoring in

accordance with Limerick's Maintenance Rule Program, communication of this event to

appropriate personnel, and review of FME Program enhancements in progress to ensure

that the circumstances of these events are addressed by planned actions. Plant

management concluded that the foreign material was most likely introduced during the

system work performed during the refueling outage in February 1997, due to less than

adequate implementation of PECO Nuclear's FME program. Administrative procedure A C-

131, Foreign Material Exclusion, requires in part that FME control recommendations be

defined and included in the work package, and that workers shall understand and adhere to

FME requirements. This violation of the FME program had more than minor significance

since it caused the HPCI system to be inoperable, and was programmatic since it required

broader corrective actions to address identified issues associated with the control of FME.

(VIO 50 353/97 07 03)

lli. Enaineerina

E1

Conduct of Engineering

E1.1

D21 Emeroency Diesel Generator issues (37551)

Lnsoection Scoce

During this inspection period and going back several months, the inspector noted a

number of issues concerning the D21 EDG. This EDG has been oa an increased

frequency testing since early July 1997. The inspector discussed the D21 EDG

failure with engineering personnel, reviewed the associated test failure special

reports, and observed a number of D21 surveillance tests.

b.

Observations and Findinas

,

During this inspection period, D21 had two test failures, one on July 26, and the

other on August 28. There have been two other D21 test failures in 1997, one on

January 1, and the other on July 3. The July 3, test failure resulted in increasing

______ _-_____ -

-

3

the technical specification test frequency from monthly to weekly. The two

additional failures since than have iesulted in extending the time period for the

increased frequency testing. The July 3, failure is suspected to be related to

problems ast.ociated with the govemore; both the electronic and mechanical

governors were replaced and the old ones were returned to the manufacturer for

failure analysis. The July 26, failure was du' '.o one of the two rectifier banks

malfunctioning; this rectifier bank was also sent out for failure analysis. The August

28, failure was due to a significant fuel oA leak on the fuel oil return header tube.

The tube's support was found to be loose, which resulted in the tubing rubbinq on a

jacket water pipe elbow, due to engine vibration; the tubing wore through, causing

the iaak. The damaged section of tubing was replaced and successfully pressure

tested, all similar tubing supports for all eight EDGs wcre inspected and tightened as

necessary, the repaired D21 tubing will be replaced during the next overhaul

,

I

(scheduled for later in 1997), and an rassessment of tubing supports will be

performed to investigate the modification or replacement of the tubing supports to

provide a more positive clamp of the tube and prevent rotation of the support,

l

Through discussions with engineering personnel, the inspector determined that the

EDus are currently classified as a Maintenance Rule Al system, which results in

increased management attention to the system. Although the EDGs were already

j

an A1 system, the fuel oil tubing failure was classified as a maintenance

i

preventable functional failure, which would result in an evaluation to determine if

the system should be classified as an A1 system. Currently the EDGs are getting

increased attention from management, engineering and maintenance personnel.

Additionally, the inspector noted that the D21 EDG is scheduled for an 18 month

'

overhaul inspection late this year. One of the issues engineering personnel plan to

address is the vibration of the engine; although D21's vibration is within the

acceptable range, it is higher the all of the other EDGs. No clear tie has been

identified between the failures on D21 at this time; however, results of the failure

analyses may provide additional information,

c.

Conclusions

Actions taken to address each D21 test failure have been appropriate. Although no

clear tie between the failures has been determined, investigations continue.

E1.2 Emeraency Fasel Generator Hioh Cloud Point Resoonse (37551)

a.

Insoection Scoos

On August 12, operations personnel were notified of an unsatisfactory tost result

for the EDG fuel oil clouc' point. Specifically, the cloud point maximum is 17

degrees Fahrenheit, whereas the tested cloud point for fuel oil delivered on July 17,

18, and 22 was 18 degrees Fahrenheit. The inspector reviewed the actions taken

by plant personnel to verify that the affected EDGs were operable.

i

---__w

9

b.

Observations and Findinas

After operations personnel were notified of the out of specification fuel oil test

results, they declared the affected EDGs inoperable; one Unit 1 EDG (D13) and two

Unit 2 EDGs (D21, D23) were affected by the test results. Technical specifications

require that within 31 days of obtaining the fuel oil sample the specified properties

be verified as met; cloud point is one of the specified properties. For the above

event, the fuel oil was sampled on July 17,18, and 22, and the results were made

known to operations personnel on August 12. Once the EDGs were declared

inoperable, the operators, in conjunction with engineering and chemistry personnel,

devised a plan to determine if the EDGs were inoperable based on the fuel oil

storage tank oil cloud point. The fuel oil storage tanks were sampled, and the

results were immediately tested for cloud point; all were found to be well below the

maximum level. Since the sample might not be a true representation of overall tank

cloud point, since the tank could not be easily recirculated and mixed, chemistry

personnel analytically determined that the storage tanks' cloud points were

acceptable. This was easily accomplished since only a few thousand gallons of

unacceptable fuel oil was added to tens of thousands of existing fuel oil with quite a

bit of margin to the cloud point maximum. The three EDGs were declared operable

late on August 12.

On August 13, when the inspector tried to review the operability determination for

declaring the EDGs operable, no good documentation could be located. Only after

discussing the event with operations, engineering and chemistry personnel, could

the inspector get the complete story as to why the EDGs were declared operaole.

Operations management agreed that a better job of documentation could have been

done,

-

c.

Conclusions

Operators appropriately declared three EDGs inoperable when they became aware of

a potential problem with the fuel oil due to a high cloud point. The EDGs were

declared operable later the same day after it was shown that the oil in the storage

tanks was below the cloud point maximum. However, documentation for the

operability determination was weak,in that various work groups had to be

contacted to get all of the facts of the operability determination.

E7

Quality Assurance on Engineerlag Activities (38701)

During this reporting period the inspectors evaluated selected aspects of PECO's

procurement program in ceder to confirm that the licensee was effectively

implementing a OA program to ensure that safety related items were in

'

conformance with reguletory requirements, licensee commitments and industry

standards. Specifically, the inspectors reviewed PECO's governing procedural

controls contained in procedures P-C-7," Services Requisition Process," Revision 2,

and P-C-9, " Evaluated Vendor List," Revision 1, as well as selected procurement

purchase orders, the supporting documentation and the associated audit reports.

Within this area the inspectors examined the audit reports used by PECO for

10

qualifying and maintaining Quality Systems, Inc. (OSI) on its Evaluated Vendors List

i

(EVL), as well as the audit of Continental Technical Services (CTS). The inspectors

1

also performed a limited review of the commercial grade item survey of Dryden Oil

Company.

E7.1.1

Review of PECO Audits and PECO's Use of Third Party Audin

1.

Review of the 1992 PECO Audit Report for OSI

The inspectors performed a partial review of the 1992 PECO audit of OSI that was

conducted February 26 27,1992, at OSI's Birdsboro, PA facility (Reference: PECO

Audit Report No. VA A 174937, dated March 24, 1992). This audit assessed OSl's

pedormance relative to the conducting utility subcontractor audits, surveillances

snd inspections. The scope of the audit appeared to be acceptable for the services

being provided with the exception that there was no documentation to support

PECO's decision not to review the areas of order entry (the processing of incoming

safety-related customer purchase orders) and procurement.

2.

Review of PECO's Use of the 1994 Duquesne Audit Heport for OSI

The inspectors also reviewed PECO's use of a 1994 Nuclear Procurement Issues

Committee (NUPIC) joint audit of OSI for the purposes of maintaining OSI on the

PECO EVL. The audit scope was limited to inspection and auditing services

provided by OSI to the nuclear industry. This audit was performed by the

Duquesne Light Nuclear Group (Duquesne) at OSI's Birdsboro, PA facility on March

10-11,1994. Duquesne used NUPIC Audit Checklist, Revision 4 (the NUPIC

checklist effective for the period of January 27,1993, through April 19,1994).

The scope of the Duquesne audit checklist appeared to be acceptable for the

'

services being provided with the exception that there was no documentation to

support PECO's acceptance of Duquesne's decision not to review QSl's order entry

and procurement practices.

PECO informed the inspectors that prior to January 1995, PECO Instruction No. 4,

" Evaluated Vendors List Instruction," Revision O, dated December 16,1993, was

used to accept NUPIC audits including the 1994 Duquesne audit of OSI. Section

7.2.3, " Quality Assurance Audit / Survey Review," and Exhibit 4-8, " Audit / Survey

Review Form Checklist," of Instruction No.4 requires that th: PECO Assessor

assigned to process a NUPIC audit report, evaluate the acceptability of the

information contained in the NUPIC audit report and its supporting checklist and

ensure that any NUPIC checklist attributes marked "Not Applicable" are adequately

explained and justifiable. Contrary to the requirements of Instruction No. 4, there

was no explanation in the 1994 Duquesne audit and checklist for entering "Not

Applicable" for Checklist Items No.1, " Order Entry," and No. 4, "Procuremont."

The 1994 Duquesne audit of OSI reviewed the corrective action that was

implemented by OSI to address two audit findings contained in the 1992 PECO

audit report for OSI. The 1992 PECO audit report for OSI contained the following

statements concerning two audit findings, documented as Vendor Corrective Action

Requests (VCR):

-

. .

.

-

.

..

_

. - .

_ - .

. _ - - _ _ . - - -

...

-

-

11

1

VCR VA O 2151 was issued because QSI has been performing internal

e

audits utilizing personnel not independent of OSI operations.

VCR O 2152 was issued because internal audit plans were not being

reviewed by another lead auditor prior to the performance of the audit

required by QSI procedure.

The inspectors verified that the 1994 Duquesne audit of OSIincluded an adequate

review of the implementation of the corrective action for the two VCRs identified in

the 1992 PECO audit of OSI. The following statements were contained in the 1994

Duquesne OSI Audit Report concerning the implementation of OSl's correctiva

action for the two VCRs identified during the 1992 PECO audit of OSI:

ABSTRACT:

Continued corrective action implementation for findings identified

during the previous NUPlC Joint Audit (PECO Audit No. VA A-

174937, 2/26 27/92) was satisfactory.

SECTION SUMMARY, Section XI- Program Compliance, item C

,

Internal audits are performed by the Vice President of Operations,

who has no direct responsibility for quality assurance functions, and

reports directly to the President / Chief Executive Officer for QSI. The

1993 internal audit plan was reviewed by an independent lead

auditor. The checklist satisfactorily documented the objective

evidence reviewed.

Based on the above audit results, it appeared that the 1994 Duquesne audit had

verified that OSI had and continued to implement adequate corrective action for the

two VCRs identified during the 1992 PECO audit of OSI.

3.

Review of the 1997 PECO Audit Report for QSI

The inspectors also performed a partial review of the 1997 PECO Assessment No.

A1077041, dated April 2,1997, for an audit that was conducted on March 3,

1997, at OSI's Birdsboro, PA facility. The assessment evaluated the

implementation of OSI's OA program as it applies to providing QA auditing and

Quality Verification inspection personnel and services. The assessment was

performed using Revision 7 of the NUPIC Audit Checklist. The scope of the audit

appeared to be acceptable for the services being provided and included within its

scope order entry and procurement. This assessment report contained the following

statements concerning order entry and procurement.

,

<

e

investiaated Results, item 1, Order Entry

,

A review and discussion of order entry activities noted that the only

current nuclear utility orders for audit and/or inspection activity has

. .

.

12

been from PECO and Centerior Energy (CEI). The current PECO

contract for QA services has no releases against it. The CEl contract

for offsite QA support has had various work releases in the last audit

period. QSI has also provided audit / inspection services for nuclear

vendors but they were not addressed in this audit. in accordance

with the OSI QA program, the President and QA Manager have the

responsibility for implementing the QA policy as it pertains to the

services provided and contractually imposed. Seven (7) purchase

order releases were reviewed and found to be properly addressed by

OSI as described on the Quality Assurance Agent Support Forms

(OAASFs). No instances were identified where purchase order

requirements could not be met, This area is considered satisfactory.

e

investiaated Results, item IV, Procurement

Procurements are controlled by Sections 4 and 7 of the Qaality

System, Inc QA Manual. Per discussion with the QA

Manager, OSI does not purchase material or equipment. Any

inspections reo' ring calibrated equipment to be performed by

QSI are accomplished using the client's andts vendor's

equipment. While OSI does have measures established for the

procurement of services, none have been issued.

4.

Review of Audit Reports for CTS

The inspectors performed a partial review of the 1995 PECO Audit Report No. VA-

A0945946, dated August 2,1995, for an audit that was conducted July 19 20,

1995, at CTS's Stone Mountain, GA facility. The audit scope was limited to

inspection, nondestructive examination (NDE), and auditing services provided by

CTS to the nuclear industry. The scope of the audit appeared to be acceptable for

the services being provided. The NUPIC Audit Checklist used by PECO for this

audit was Revision 6 (the NUPIC checklist effective on March 26,1995). As a

result of this audit, nine VCRs were issued.

5.

Comparison of OSI and CTS Audit Reports

The inspectors questioned PECO about the apparent differences in selected audit

checklist elements used for the audit of OSI and CTS. Initially, it appeared that the

audit scope for CTS was far more extensive than the audit scope for QSI. The

inspectors determined that this was the result of the use of different revisions of

the NUPIC audit checklists being used to audit OSI and CTS.

For example, Revision 4 of the NUPIC Audit Checklist was used for the 1994

Duquesne audit of OSI and the following are some of the NUPIC Audit Checklist

sections that were identified as being applicable or not applicable for QSl:

• Section 1 - Order Entry, NOT APPLICABLE (NA)

,

• Section IV - Procurement, NA

I

_ _ _

. _ . _ - -

.

___ .

_

_

_ _ _ _ .

13

e Section VI- Fabrication / Assembly, Special Processes, NA (See NOTE)

e Section Vil- Test / Inspection, APPLICABLE

e Section Vill- Handling, Storage, and Shipping, NA

e Section IX - Calibration, NA

e Section X - Document Control, AFPLICABLE

NOTE:

According to PECO, special processes (e.g., NDE services) is a

service provided by OSI.

However, Revision 6 of the NUPIC Audit Checklist was used for the 1995 PECO

audit of CTS. The following are some of the NUPIC Audit Checklist sections that

were identified as being applicable or not app licable for CTS.

e Section 1 - Order Entry, APPLICABLE

e Section IV - Procurement, APPLICABLE

Section V - Material Control / Handling, Storage, & Shipping, NA

e

e Section VI Fabrication / Assemble /Special Processes, NA (See NOTE)

e Section Vil- Test / Inspection, APPLICABLE

e Section Vill - Calibration, NA

e Section IX - Document Control, APPLICABLE

NOTE:

For Audit Checklist item No. VI,Section IV,

" Fabrication / Assembly /Special Processes," of the PECO audit reports

states, " CTS's scope of service does not apply to the control of

fabrication, assembly and special processes since they only provide

Quality Assurance Services (i.e., OA/QV Inspections). The

assessment of CTS's control over the qualification and certification of

-

NDE personnel is addressed in Section V Inspection / Tests of this

report."

Based on a review of the above information, the NRC inspectors determined that

the only apparent differences in the NUPIC Audit Checklist sections used for the

1994 Duquesne of OSI and the 1995 PECO Audit of CTS were as follows:

e

Order Entry was reviewed during the CTS sudit, but was not reviewed during

the OSI audit.

e

Procurement was reviewed during the CTS Audit, but was not reviewed

during the OSI audit.

Conclusion

,

Based on a review of PECO's 1992 audit of Quality Systems, Inc. (OSI) and PECO's

use of a 1994 Duquesne' audit of OSI for the purposes of maintaining OSI on the

PECO Evaluated Vendor List (EVL), the inspectors determined that PECO failed to

document why the areas of order entry and procurement were not considered and

,

reviewed during the implementation audit of OSI quality assurance (QA) program.

,

The inspectors determined that the acceptance of the 1994 Duquesne audit

!

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

14

appeared to be contrary to the requirements of PECO Instruction No. 4, " Evaluated

Vendors List Instruction," dated December 16,1993, becaute of Duquesne not

explaining why the areas of order entry and procurement were not reviewed during

the audit. However, the inspectors determined that the scope of the 1997 PECO

audit of QSt included the order entry and procurement processes. In its 1997 audit

of OSI, PECO determined that OSI had adequate OA program and implementing

procedure controls in place for the order entry process and based on a review of

several order entries, PECO determined that these controls were being effectively

implemented. Further, in its 1997 audit of OSIin the area of procurement, PECO

detemined that OSI had not issued any purchase orders (POs) for safety-related

equipment or services.

Because of the nature of the audit omissions in the 1992 PECO audit and the 1994

Duquesne audit and the fact that the 1997 audit confirmed OSI had implemented

adequate QA controls for order entry and in the area of procurement, OSI had not

issued any safety-related POs, the failure of PECO to evaluate OSl's implementation

of these areas constitutes a violation of minor significance and is being treated as a

non-cited violation consistent with Section IV of the NRC Enforcement Policy.

(NCV 50 352,353/97-07 04)

l

E7.1.2

Review of Commercial Grade Survevs

1.

Commercial Grade Survey of Dryden Oil

The inspectors performed a limited review of PECO's 1994 commercial grade

survey of the Dryden Oil Company (Dryden) that was conducted April 12-13,1994,

at Dryden's Baltimore, MD facility (Reference: PECO Assessment No. CG A-

OR'34410, dated May 11,1994). The commercial grade survey was performed

using the NUPIC Commercial Grade Survey Checklist, Revision 1, and assessed

Dryden's commercial controls and performance relative to the supply of lubricants,

oils, and greases. Dryden was placed on PECO's EVL as a supplier of commercial

grade products rather than safety-related products or services. As such, Dryden

products would be dedicated by PECO as basic components before use in sa:ety-

related applications. The inspectors determined that since placing Dryden on its

EVL, for the purpose of providing commercial grade items, PECO had issued only

one purchase requisition (Material Requisition No. 0118464) to Dryden for the

supply of non-safety-related oil, and that there was no evidence that the oil had

ever been used. Further, PECO informed the inspectors that the oil had been -

supplied by Dryden in 1995 and was now classified as surplus material.

The inspector concluded that the Dryden Oil survey was adequate to place the

. company on the EVL as a commercial grade supplier. Because PECO is a NUPIC

member,its commercial grade survey of Dryden may be used by other NUPIC

members fer procuring commercial grade items from Dryden and dedicating them as

basic components.

,

l

_

~

.-

-

. _ _ .

-- -

i

15

' E7.1.3

Purchase Order Revision Controls

a.

Insoection Scone

The inspectors reviewed PECO's program for the establishment of technical

procurement controls described in procedures P-C-7," Services Requisition

Process,' Revision 2, and P-C 9, " Evaluated Vendor List," Revision 1. The

inspectors also evaluated the implementation of PECO's procurement program

during the revit>w of safety-related purchase orders (POs) involving OSI and CTS.

b.

Observations and Findinas

The inspectors reviewed selected POs in order to determine if these documents

provided appropriate methods and responsibilities for the requisition of safety-

related items and services. In particular, the inspectors examined POs B-LOA-

000479 and B-LOA .000516, which concerned the acquisition of quality verification

support services from CTS and OSI respectively. Based on the review of these POs

it was determined that PECO's Purchasing Department had initiated the requisition

subsequent to a request from Nuclear Quality Assurance (NOA) for support services

et both the Limerick and Peach Bottom stations for future outage work. However,

as indicatea by the licensee, neither OSI nor CTS had provided any quality

verification personnel (e.g., ANSI N 45.2.6 Level I,11, or 111 inspectors) to either

Limerick or Peach Bottom.

As determined by the inspectors, the CTS PO (B-LOA 000479) had been

appropriately initiated by authorized personnel in the licensee's purchasing

organization in accordance with the requirements of procedure P C-7. The

inspectors also ascertained that subsequent changes to the PO including the

termination of this requisition were appropriately authorized by functionally

designated PECO personnel. However, during the review of the associated

purchase order documents, the inspectors noted that despite the apparent change in

scope of the PO for CTS (e.g., Revision 1 placed the order on hold and Revision 2

canceled the requisition) limited supporting information, related to a record of

transaction or a purchase order review form, was available to address the potential

effects of these changes on the technical and quality requirements of the PO.

Additionally, as described in paragraph 7.11 of procedure P-C-7, changes to an

issued PO require that the requester prepare a Request for Change Order (RCO)in

accordance with Exhibit P-C-7-9 of the procedure. However, as determined by the

inspectors the specified RCO had not been completed in conjunction with the

termination of PO B-LOA-000479 as required.

During the review of PO B-LOA 000479, the inspectors noted that a June 22,

1995, memorandum, from the Peach Bottom Quality Division to PECO's

procurement organization, conceming the composition of contract support personnel

4

had been forwarded to all of the organizations competing for the quality verification

support services contract. The memorandum stated that, "It would be beneficial if

at least 5 of the 16 candidates hava current Level ll certifications in: Ultrasonic

Inspections (UT) or instrumentation and Controls." Based on the review of this

'

--

-

- - - - - - _ _ - - , , - . -

16

memorandum, the inspectors determined that it had been properly forwarded to the

prospective contractor organizations by PECO's procurement organization and that

it did not materially alter the intent of the PO in that it merely expanded on the

specific areas of expertise associated with the requested ANSI N45.6 SNT-TC-1 A,

Level 11 certified inspectors. Therefore, this memorandum was not regarded as a

substantive change to the requisition which would have necessitated a revision to

the purchase order.

As a result of the review of procedure P-C-7, the inspectors determined that

appropriate provisions had been established for the evaluation of " sole source"

suppliers including the development of Exhibit P-C-7 7, Pole Source Justification

form. Howevor, none of the POs reviewed during this inspecthn involved sole

source suppliers and the examination of this area was limited to the ovaluation of

PECO's procedural controls.

As previously noted, PO B-LOA-000479 underwent two revisions the first of which

placed the requisition on hold, pending the completion of an audit of CTS's quality

,

assurance (QA) plan. Relative to Revision 1 of the PO, the licensee stated that the

terms "QA program" and "QA plan" were used interchangeably relative to the

process of verifying the vendors compliance to the requirements of Appendix B of

10 CFR Part 50. The need for auditing CTS's OA program had been documented

on PEP 10003739, dated March 13,1995, subsequent to the licensee's

determination that a safety-related PO had been issued to an unapproved vendor

(CTS) who was not on the Evaluated Vendors List (EVL). Specifically, the PEP

indicated that contrary to the requirements of Procedure Number PA 3,

" Administrative Controls for Purchase of items and Services for Nuclear Safety

Related Applications at Power Plants" and Procedure P-C-7, Revision 1, purchasing

had incorrectly issued a PO to a supplier of quality verification personnel services

without the vendor being listed as either approved or conditionally approved on the

EVL. The PEP further stated that the vendors OA program would need to be

formally evaluated and approved by NOA prior to the vendor providing quality

verification services. This condition was imposed even though CTS would be

working under PECO's OA program, because the PO specified that the vendor was

responsible for supplying ANSI N 45.2.6 Level 11 qualified inspection personnel

under CTS's OA program, which was required to meet the applicable criteria of

Appendix B of 10 CFR Part 50.

Based on the review of PEP 10003739 the inspectors determined that appropriate

corrective actions had been developed in response to this nonconformance including

the revision of procedures PA-3 and P-C-7 to clarify the requirements related to the

placement of safety related service POs and an organizational realignmeni which

currently has the Nuclear Group processing their own procurement requisitions.

However, as a result of the review of this PEP, it was determined that the

documented generic implications review of similar POs, to verify that the identified

condition was an isolated occurrence, had not been completed in conjunction with

the close out of the Performance Enhancement Program (PEP). Subrequent to the

identification of this issue, the licensee revised PEP 10003739, on September 16,

1997, to address the inappropriate closure of the PEP without completing the

17

generic implications assessment. The revised PEP indicated that Nuclear Quality

Assurances' current assessment (A1103691) involving the Nuclear Groups

procurement activities included a review of POs for products and services.

Specifically, the evaluation was performed to determine if safety related products

i

and services were being procured from approved or conditionally approved vendors

1

on PECO's EVL in accordance with procedures P-C 1 and P-C-7. This assessment,

which utilized a representative sampling process, did not identify any deficiencies

and the generic review aspect of this PEP was appropriately completed.

c.

Conclusions

Within the areas examined, two examples involving the lack of adherence to

administrative controls related to procurement transactions were identified. The

examples included the issuance of a purchase order to a supplier of quality

verification personnel services without the vendor being listed on the evaluated

vendor list, documented in PEP 10003739, and the failure to complete a request for

change order when a contract was terminated. The inspectors also identified that

PEP 10003739 had been inappropriately closed without the performance of the

specified generic implications review. However, the licensee's subsequent

corrective actions were prompt, and included a comprehensive assessment of the

Nuclear Groups procurement activities. Although the noncompliances identified

collectively indicate a weakness in the licensee's implementation of procurement

controls, this failure constitutes a violation of minor significance and is being treated

as a non-cited violation consistent with Section IV of the NRC Enforcement Policy.

(NCV 50-352,353/97-07 05)

IV. Plant Suooort

R1

Radiological Protection and Chemistry (RP&C) Controls

R 1.1

Imolementation of the Radioactive Liouid and Gaseous Effluent Control Proarams

a.

Insoection Scoos (84750)

The inspection consisted of: (1) tours of radioactive liquid and gaseous effluent

pathways and process facilities; (2) review of unplanneti or unmonitored release

pathways; (3) 1996 Annual Radioactive Effluent Release Report; and, (4) review of

the Offsite Dose Calculation Manual (ODCM).

b.

Observations and Fmdinas

The inspector reviewed the 1996 annual radioactive effluent release report. This

report provided data indicating total released radioactivity for liquid and gaseous

effluents. The annual report also summarized the assessment of the projected

maximum individual and population doses resulting from routine radioactive airborne

and liquid effluents. Projected doses to the public were well below the Technical

Specification (TS) limits. The inspector identified no additional anomalous

measurements, omissions or adverse trends in the reports.

_-

. - - .-

=

18

The inspector reviewed a licensee 10 CFR 50.59 analysis pertaining to numerous

typographical discrepancies within the ODCM and planned changes to address

those discrepancies. The inspector identified no additional discrepancies within the

ODCM or noted any inadequacies pertaining to the 10 CFR 50.59 analysis. The

licensee was in the process of implementing new dose assessment software at the

time of the inspection. The licensee plans to make additional changes to the ODCM

prior to formal programmatic implementation of this software.

The inspector conducted a tour and reviewed selected radioactive liquid and gas

processing facilities and equipment, including effluent / process / area radiation

,

monitors and air cleaning systems. The major component out of service at the time

of the inspection was the RM-21 Radiation Monitoring System (RMS) computer and

the licensee was initiating actions to address this particular equipment problem.

Although this equipment was out of service, it did not impact the licensee's

capability to comply with licensee requirements, in that it is used as a data

collection tool. The licensee is performing manual data retrievalin accordance with

the ODCM.

The inspector reviewed a special study conducted by the licensee to account for

potential releases from a modificatiun of the Chemistry Laboratory roof. This report

was well-detailed and no inadequacies were noted by the inspector,

c.

Conclusions

Based on the above reviews, that inspector determined that the licensee maintained

and implemented good routine radioactive liquid and gaseous effluent control

programs.

R2

Status of RP&C Facilities and Equipment

R2.1

Calibration of Effluent / Process / Area / Accident Radiation Monitorina Systems (RMS)

a.

Insppction Scoce (84750)

The inspector reviewed the most recent calibration results for the following selected

effluent / process / area / accident RMS.

North Stack Effluent

Wide Range Accident

Residual Heat Removal (RHR) Service Water

South Stack Effluent

'

Air Ejector Offgas Effluent

Liquid Radioactive Waste Discharge

Service Water

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19

b.

Observations and Findinos

t

The inspector noted that the licensee used multiple calibration sources and took

multiple roadings during the RMS calibration process. All calibration results

reviewed were within the licensee's acceptance criteria.

The inspector discussed the maintenance and operability / reliability with the RMS

4

system engineer who has been assigned the system for the past several years. The

inspector reviewed work orders for RMS back into 1996. The inspector noted that

the backlog and timeliness of addressing problems has improved. The system

engineer attributed this improvement to the fix-it-now teams.

The inspector noted the following potential areas for improvement regarding the

RMS.

Reliability / availability was not formally tracked.

e

,

One of the acceptance criteria was that the calibration factor had to be

within 135% of the previous calibration factor. The inspector considered

this a large acceptance band.

Linearity of the RMS was not formally determined. The inspector noted that

e

the correlation coefficient from a least squares fit of the calibration data was

a good parameter for trending system performance.

,

.

The Radiation Protection Manager indicated that these matters would be reviewed

and corrective actions would be taken, as appropriate.

,

1

c.

Conclusions

The RMS calibration program was good. Several opportunities were identified in

which system tracking and trending could be improved.

R2.2 - Air Cleanino Svstems

,

a.

Insoection Scoce (84750)

The inspector reviewed the licensee's most recent surveillance test results (visual

inspection, in-place high efficiency particulate air (HEPA) leak tests, in-place

charcoal leak tests, air capacity tests, pressure drop tests, and laboratory tests for

the iodine collection efficiencies) for the control room, reactor enclosure and

refueling area, standby ges treatment, and radioactive waste enclosure common

tanks vent and equipment.

b.

Observations and Findinos

'

No discrepancies were noted for the in-place HEPA leak tests, in-place charcoal leak

j

tests, air capaci y tests.

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The licensee's TS specify Regulatory Position C.6.a of Regulatory Guide (RG) 1.52,

Revision 2, March 1978, as the requirement for the laboratory testing of the

charcoal. RG 1.52 references ANSI N509-1976, " Nuclear Power Plant Air-Cleaning

.

Units and Components." ANSI N509-1976 specifias that testing is to be performed

in accordance with paragraph 4.5.3 of RDT M 161T, " Gas Phase Adsorbents for

Trapping Radioactive lod *e and lodine Components." Charcoal efficiency testing

was conducted by a ver. Jr service. The Office of Nuclear Reactor Regulation

(NRR) has identified a potential testing discrepancy regarding charcoal efficiency

testing using the methodology described in RDT M 161T. This matter involves

.

testing conditions for the charcoal. This matter will be further reviewed

'

(IFl 50-353/97 07-06).

One minor matter regarding a lack of acceptance criteria in the Radioactive Waste

Enclosure Common Tank Vent and Equipment procedure ST-4-079 320-0 was

noted by the inspector. The inspector assessed that the most recent surveillance

'

results did not appear to conflict with the system flow rates denoted in the UFSAR.

The inspector reviewed a 10 CFR 50.59 review pertaining to a potential surveillance

test failure of the "A" CREFAS Monthly Operability Test conducted on June 18,

'

1997. This analysis determined that an eighth of an inch water gauge had been

i

maintained with respect to surrounding structures and outside conditions and

identified some discrepancies in the surveillance procedure in-use at that time.

Corrective actions were taken. The inspector noted no discrepancies pertaining to

this 10 CFR 50.59 review.

The inspector reviewed work orders for selected systems back into 1996. The

'

inspector noted that the backlog and timeliness of addressing problems has

improved. The system engineers attributed this improvement to the fix it-now

teams.

!

c.

Conclusions

Based on the above reviews and discussion, the inspector determined that the

licensee implemented a good surveillance program.

R7

Quality Assurance (QA)in RP&C Activities

.

a.

Insoection Scone (84750)

L

The inspection consisted of: (1) review of the 1996 audit: (2) a radiation protection

self assessment; and (3) implementation of the measurement laboratory quality

'

control program for radioactive liquid and gaseous effluent samples.

- b.

Observations and Findinas

'

The inspector reviewed the NOA audit of the effluents program. The audit was

well-targeted and no issues of regulatory significance were noted by the audit team.

.

4

. _ _ _ _ _

_ _ _ -___ _ - _ __ - -

21

The licensee's self-assessment was self-critical and highlighted challenges regarding

RMS aging and ODCM discrepancies.

OC over instrumentation was very good. The inspector reviewed the QC data for

inter-laboratory comparisons. The inspector noted that the last two tutium samples

(second quarter 1996 and first quarter 1997) were in disagreement with the vendor

,

laboratory. The licensee attributed the first disagreement to improper distillation

techniques. Thn licensee was unable to explain the second disagreement. The

Chemistry Supervisor noted to the inspector that this discrepancy had not been

investigated. The inspector considered this lack of follow up to be a weakness in

chemistry laboratory QC. The Chemistry Supervisor stated to the inspector that

sample preparation OC would be programmatically strengthened.

c.

.Qnpelusions

Based on the above reviews, the inspectors determined that the licensee's OA audit

was good. Overall, the licensee implemented a good OC program to validate

measurement results for effluent samples.

F1

Control of Fire Protection Activities

F1.1

Main Conttql Room Fire Sucoression System (71750)

l

During this inspection period, the inspector reviewed the UFSAR basis for an

automatic fire suppression system for the control room with a focus on inadvertent

actuation of the system, in so doing, the inspector considered the following

I

questions:

1.

Does the control room have an automatic fire suppression system (AFSS)?

If yes, does it have initiation logic along with actuation on a automatic time or

manual delay basis and what chemical is used (e.g., water, halon, carbon dioxide,

etc.)? Describe briefly.

If no, identify what is used for fire suppression in the control room.

2.

With an AFSS, does the licensee have specific or general

abnormal / emergency procedures for an inadvertent actuation of the AFSS

during operations and shutdown?

Desciibe immediate actions and briefly describe supplemental actions.

3.

Do licensee procedures and/or technical specifications provide for the use of

emergency breathing apparatus for in the control room (give type of

apparatus: SCBA, Air line, etc.)? Is there sufficient equipment to support the

control room staff? Are the numbers specified in TS, procedures,

surveillances? Do these numbers reflect what actually exist in the plant?

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Briefly describe the type of apparatus and when they would be used.

Limerick Generating Station's UFSAR 9A.5.3.24, Fire Area 24, Control Room and

Peripheral Rooms, states that a fire activates smoke detectors, which cause an

audible / visual annunciation to register on the fire protection panels in the control

room. Operators then callin the plant fire brigade to manually extinguish the fire.

+

There is no automatic fire suppression system for the control room. Fire procedure

F A-533, Control Room 533 and Peripheral Rooms 530 to 535 (El. 269) Fire Area

24, revision 4, proposes stretching a CO2 hose line into the control room, from just

outside the control room door, and attacking the fire, as the primary strategy. The

secondary strategy is to stretch the dry chemical unit hose from the turbine building

through the control room door and attacking the fire. For fires in the peripheral

rooms, the procedure proposes attackirig the fire using portable fire extinguishers,

located in the control room, as the primary strategy; the portable extinguishers use

halon as the extinguisher.

Limerick UFSAR 6.4.4.2.3 states that full-faced demand self-contained breathing

>

apparatus rated for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per cylinder and protective clothing are available for

contro! room operators. Routine Test procedure RT-0-111-900-0, revision 18, One-

hour SCBA Cylinder inspection and Functional Test, which is performed monthly or

after use, specifies a minimum of 14 SCBA Paks for the control room. The

inspector counted 14 SCBA Paks in the control room. Special Event procedure SE-

2, revision 10, Toxic Gas / Chlorine, directs operators to don self-contained breathing

apparatus within 2 minutes for: High Toxic Chemical Conc alarmed; Control Room

Chlorine Isolation Initiated alarmed; and Harsh or unusual odor.

F2

Status of Fire Protection Facilities and Equipment

F2.1

In-Plant Walkdowns (92904)

a.

Scoos of insoection

The inspector conducted in-plant walkdowns of portions of several fire protection

procedures, During these walkdowns, the inspector took note of the material

condition of the. fire protection equipment. The specific procedures which were

evaluated in the f; eld are indicated in the list of procedures in the attachment to this

report. Additionally, the inspector discussed recently identified problems with

deluge valves with fire protection staff members.

b.

Observations and Findinos

Recently, several issues have developed which involve the facility design. These

issues include identification of structural steel requiring fireproof coating, aiming and

testing of emergency lighting units required for safe shutdown, and compatibility

___ _ problems between the installed fire suppression system deluge valves and their

electronic control panels. To assist with resciution of these design issues, PECO

will assign a supervisor from the Probabilistic Safety Assessment (PSA) group in

Nuclear Engineering to the site for a period of six montns. The PSA group is the

organization within Nuclear Engineering with responsibility for fire protection.

_ _ _ _ _ _ _ _ __ - _ - _ _

. - - _

23

Auxillary Equipment Room Halon* Stations

The inspector observed the condition of the Unit 1 and Unit 2 Auxiliary Eo.uipment

Room Halon* banks. The Halon* cylinders ond connections were free of excessive

corrosion products. The connections were tight and marked to show whether the

cylinder which was connected at that point was in the main or reserve bank, and

which cylinder was connected (Main 1, Reserve 2, etc.).

Fire Suppression Water System Deluge Valves

The inspector noted the condition of the sprinkler systems throughout the plant and

observed that they appeared to be well-kept and in good condition. Two open head

sprinkler systems were inspected in detail, the Unit 1 Reactor Enclosure Hatchway

Elevation 217' Sprinkler System, DL-72, and the Unit 1 Reactor Enclosure Water

Curtain Elevation 217', DL-68. The equipment was well-preserved, lined up for

actuation, and the valves associated with the deluge valve station were clearly

marked.

During discussions with the fire protection staff, the in 3ector was informed that

PECO had recently determined that there is a compatibility problem between the

installed deluge valves and the currently installed electronic control panels. This

matter was evaluated by PECO Nuclear Engineering, and corrective actions included

replacement of the six inch deluge valves. Currently, when a deluge valve fails a

surveillance test, it is reworked, and returnri to fe'l functional condition.

Fireproof Coated Steel

The incpector observed the status of the coating on beams in the plant which are

required to be protected from the effects of an exposure fire. The inspector noted

that there were uncoated attachments on several of the beams, in response to the

inspector's questions regarding the extent to which attachments need to t,e coated,-

PECO engineering personnel contacted the supplier of the coating material, and

were advised that unless the attachment constitutes a significant portion of the

beam cross-section, it need not be coated beyond the depth of the beam coating.

Plans are to incorporate this information into a specification being generated which

willlist, in detail, those beams requiring protection (see discussion in Section F4.1).

The inspector found this response acceptable.

Battery Powered Emergency Lights

The inspector performed a walk down of the Unit 2 Residual Heat Removal (RHR)

system equipment listed in UFSAR Appendix 9A as requiring remote cperation for

shutdown from outside the control room. The inspector noted the Nsitioning of the

emergency lighting units (ELUs) and the aiming of the heads. The inspector

dotermined that the RHR equipment and the pathways to the RHR equipment are

illuminated. The inspector also notad that many of the ELUs now have red labels

affixed indicating that the units are required for safe shutdown and the heads are

not to be moved. Fire protection staff members informed the inspector that

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24

completion of the safe shutdown lighting review was expected in the September-

October time frame this year. PECO currently plans to mark the lamp heads

'

showing the alming points starting about November 1997. The inspector checked

the condition of a number of ELUs and found them to be free of corrosion, with

proper electrolyte levels and charging indications. A review of previously completed

_ inspections indicated that several ELUs were found to have deficiencies during each

'

inspection. The deficiencies were entered into the PECO corrective action system.

Fire Dampers

The inspector used the mechanical drawings listed in ST-7-022-921-2,

Attachment 1, Rev.1, Fire Damper Tabulation, to locste fire dampers in two areas

i

of the Unit 2 Reactor Enclosure, Area 13 of Elevations 253' and 217', For those

dampers readily accessible (i.e., not greater than six feet from floor level nor in high

radiation areas), the inspector verified that the locations shown on the drawings

matched the field locations. In addition, the inspector evaluated labeling and

accessibility to perform maintenance. The inspector did not open the access panels

at the dampers. The inspector determined that the dampers were at the locations

shown on the drawings, and those accessible had bar code labels affixed,

c.

Conclusions

Based on the observed condition of the selected equipment in the field, the

inspector concluded that the fire protection equipment is in good repair, readily

identifiable, and ready for use.

F3

Fire Protection Procedures and Documentation

F3.1

Procedure Uoarade Proaram (92904)

a.

Insoection Scooe

The inspector reviewed a sample of current revisions of procedures governing fire

protection activities. The inspector evaluated the extent of the revisions, and their

affect on the procedures' useability, in addition, several procedures were taken to

the field by the inspector to evaluate adequacy of the procedures for conducting the

activities. The procedures reviewed are listed in an attachment to this report.

Those procedures which were " walked-down" in the field are identified in the

attachment.

b.

Observations and Findinas

As discussed in NRC Integrated Inspection Report (01) 50-352 & 353/97 01, PECO

had initiated a Project Plan to improve fire protection procedures. Action Request

(AR) A1050861, Limerick Generating Station _(LGS) Fire Protection Procedures, is

being used to track the surveillance test (ST) and routine test (RT) procedures in the

Fire Protection Rewrite Procedure Project which was initiated to enhance the clarity

of fire protection test procedures. The AR contains 55 separate items to track

.

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25

individual procedures, with scheduled completion dates prior to the next scheduled

use of the procedure, in view of the goal of Industrial Risk Management (IRM) to

trensfer the testing to other departments for performance, the revised procedures

will u:e the station standard format with simpler steps, corresponding sign-offs for

each step, and caution statements and notes set off prior to the step to which they

are applicable (human factors format). The change of fire protection from Technical

Specifications to Technical Requirements Manual (TRM) is also being captured in

the revisions. Inspector observations related to specific procedures are given

below:

Halon* System inventory Procedures

Procedures ST-7 022-3531, Rev. 4, Halon System inventoryi and ST-7-022-353 2,

Rev. 6, Halon System inventory, formerly checked both the main and reserve banks

at the same time, if any of the cylinders were found to be out of specification on

weight or pressure, the procedure directed moving cylinders between the banks to

return at least one bank to operable status. The new revisions test one bank at a

time, either the main or reserve bank. This ensures that one bank remains operable

at all times, since the bank under test is returned to operable status before the other

bank is taken out of service for test. In addition, the format has been changed to

the human factors format, and steps have been simplified. The prior revisions

required recording the empty weight of the cylinder from the stamping at the neck.

The new rovision simply requires recording the cylinder empty weight, since a

number of the new cylinders have the empty weight marked on a label affixed to

the side, rather than stamped at the neck. The inspector walked-down procedures

ST-7-022-353 2, Rev. 6 Halon System Inventory, ST-7-022 353 2, Rev. 7, Unit 2

Main Bank Halon System Inventory,-and ST-7-022-354, Rev. O, Unit 2 Reserve

Bank Halon System Inventory, in the field and found them to be adequate for

performing the required tests.

Procedure RT-7-022-353-0, TSC Halon System Inventory, ensures the gaseous

agent fire suppression system for the Technical Support Center (TSC)is operable.

The new revision, Rev. 5, sets off notes and cautions at the appropriate step, and

adds specific sign-offs for meeting the minimum weight and pressure range

acceptance criteria. Rev. 5 also improves the readability of the procedure over

Rev. 4, and simplifies the instructions. Fire protection group personnel informed the

inspector that they plan to contract this work, along with all other " commercial

building" (outside the power block) fire protection system testing, to an outside

company. Responsibility for oversight will remain with the PECO fire protection

group.

Emergency Lighting Unit Procedures

The inspector reviewed the current and prior revisions of the safe shutdown ELU

test procedures,_ RT-6-108-300-0, Rev. 6 and 4, RT-6108 300-1, Rev. 5 and 4,

and RT-6-108 300-2, Rev. 4 and 3, Safe Shutdown Eight (8) Hour Self Contained

Battery Pack Operation Verification. The prior revisions of the procedure contained

directions for irispecting the ELUs, along with individual step signoffs for the

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

26

inspection steps, diagrams showing individual ELUs, paths and equipment to be

illuminated, and signoffs for each safe shutdown ELU. The new revisions retain the

diagrams and individual ELU signoffs, but have deleted the individual inspection step

signoffs to improve clarity. The inspection steps and acceptance criteria have been

retained.

Fire Rated Structural Assembly Procedures

l

Procedure ST-7-022 920-1, Rev. 3, Un41 Refuel Fire Rated Assembly inspection,

!

provides guidance and acceptance criteria for conducting inspections of fire rated

structural assemblies (including structural steel) and electrical raceway fire

encapsulations. The procedure requires all visible and accessible assemblies to be

inspected. The specific items to be inspected are listed in attachments to the

procedure. Attachment 1 provides a list of the fire rated structural assemblies

(walls, slabs, etc.) and Attachment 2 provides a list of the raceway encapsulations.

At the current time, all the raceway encapsulations are considered to be inoperable

in accordance with NRC Generic Letter (GL) 92-08 regarding Thermo-Lag issues,

and hourly fire watches are being performed. There is a corresponding procedure

and set of attachments for Unit 2.

!

in August 1996, PEP issue 5811, insulation Missing From Structural Steel, was

I

initiated, documenting deficiencies identified during the inspection of the fire rated

assemblies. One of the difficulties identified by PECO employees was identification

of the specific structural steel members which required coating. The fire protection

group has maintained a copy of Engineedng Work Request (EWR) L 00508 which

showed those steel members requiring protection from exposure fires. The

drawings included in the EWR package date from 1989, and are not otherwise

available at the site. To resolve the problem with accessibility of the information,

PECO Nuclear Engineering is developing a specifieration, NE 264, which willlist each

specific structural steel member requiring coating, and the required extent of the

coating. The Unit 2 portion of the listing has been incorporated into ST-7-022-920-

2, Attachment 1, Rev. 5, Structural Fire Rated Assembly Tabulation, dateo April 22,

1997. The inspector concluded that this will simp!!fy obtaining the information, and

makes performing the inspection easier. The Unit 1 listing has not yet been

incorporated into the corresponding tabulation, which still contains a single signoff

for the steel being inspected in accordance with the EWR,

Fire Damper inspection Procedures

PEP 6033, improvements to Fire Protection Procedures and Program, has an entry

from March 1997, indicating that several of the procedure revisions tracked by AR

A1050861 are overdue. One of the overdue revisions was for ST-7-022-921-2,

Fire Damper Inspection. This procedure contains instructions for inspection and

functional testing of fire dampers. The procedure contains wording which allows

corrective actions to be taken if a fire damper does not perform properly during the

functional test, and requires a notation in the Additional Action / Test Comments

Section. The procedure also contains a requirement to clean and lubricate the

latching mechanism of trap door type fire dampers. The list of dampers to be

a

27

inspected is contained in an attachment to the procedure. Revision 2 of the

procedure, dated May 21,1997, revised the reference to the list of dampers. The

inspector field verified locations of dampers in several plant areas, as discusseu in

Section F2.1, using ST-7-022-9212, Attachment 1. Rev.1, Fire Damper

Tabulation, dated February 14,1995. The dampers were located at the positions

shown in the referenced drawings, and were readily identifiable. The inspector

noted that several of the dampers would require significant preparatory work in the

form of scaffolding and health physics surveys to perform the inspections.

Fire protection group personnel informed the inspector that the current procedure

was cumbersome to use in that it required inspections of dampers in several

systems at the :ame time. Their intent is to revise the procedure and tabulation to

group the fire

"oers on a system basis, rather than plant area basis. This will

enable persont C h .erforrn the inspections during system outage weeks.

While reviewin9 other fire damper inspection procedures, the inspector noted that

ST-7-022 9210, Rev. 6, Fire Damper inspection, had two temporary changes

against it at the time of the inspection. One corrected a TRM reference to the

correct technical specifications (for control room ventilation LCOs) and the other

required compensatory actions to be taken during the inspection of the dampers in

the control room normal and emergency Ventilation systems. These compensatory

measures are necessary because with the ductwork access panels open, the

ventilation systems cannot isolate on toxic gas release, radiation release, or steam

line breaks. These compensatory actions were developed as a result of an ongoing

review of fire protection procedures to determine plant impacts.

Sprinkler System Procedures

Two recently revised procedures covered sprinkler systems: RT-7-022-322-0,

Remote Buildings (Outside PAB) Sprinkler System Operability Verification, and

RT-7 022-320-1, BOP Fire Protection Sprinkler System operability.

The buildings outside the protected area boundary (PAB) were not within the scope

of NRC purview, ' ut the inspector reviewed the procedure to verify consistency

o

with in-plant procedures. PECO plans to contract this work to an outside company,

so the procedure was revised to a more conventional text format. Cautions and

notes were set off just prior to the step to which they apply, as with the human

factored procedure formst.

The balance of plant (BOP) procedure will be used by station personnel and so was

converted to the human factored procedure format. The BOP procedure was also

split into two procedures. RT-7 022-3201, Rev. 6, BOP Fire Protection Sprinkler

System Operability Verification, details the 18-month tests of wet pipe sprinkler

systems in the turbine building. RT-7-022-321 -1, Rev. O, Outage Wet Pipe

Sprinkler System Operability Verification and Visual Inspection, tests those systems

which are not accessible during normal operation (condenser bay and moisture

separator area).

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4

_To_ evaluate a representative procedure which had not been revised, the inspector

reviewed ST 7 022-730-1, Rev 4, Fire Suppression Water System (FSWS)

,

Air / Water Nozzle Flow Test. This procedure tests open head sprinkler systems and

!

pre-action sprinkler systems in the Unit 1 Reactor Building and Diesel Generator

i

Cells. The procedure provides.a discrete set of instructions for each individual

sprinkler system. The inspector perfornied a field verification of steps for two

i

systems. The systems evaluated were Reactor Etelosure Hatchway Elev. 217,

j;

Deluge Fire Protection Sprinkler System, DL-72, and Reactor Enclosure Water

l

Cortain Elev. 217, Deluge Fire Protection System, DL 68. The inspector determined

-

p

that for those open head systems where the potential exists to trip the deluge

[

valve, appropriate steps are included to prevent water discharge, and to restore the

system in accordance with station operating procedures. The inspector noted that

Section 4.3 of Precautions and Limitations provides three alternative methods which

.

may be used for verifying air flow at the open nozzles. A previous review by the

,

[

resident inspection staff determined that PECO is using a fourth method, which is

j

functionally equivalent.

I

f

The use ot a functional equivalent would appear to be permissible, since the

j

procedure step states to _ verify flow at each nozzle, without specifically stating

how. The inspector noted that the procedure calls for verifying air flow at each

a

.

j

- nozzle, out does not provide the number of nozzles in the various sprinkler systema.

c.

. Conclusions

b-

Based on the review of the new and prior procedure revisions, along with the field

I

walkdown of the procedures, the inspector concluded that the procedures provide

p

adequate guidance and appropriate acceptence criteria for testing of fire protection

,

systems.

,

j:

F6-

Fire Protection Organization and Administration

i:

F6.1 - Fire Protectio, Council (92904)-

4

a.

Insoection Scoae

The inspector discussed the activities of the Fire Protec'..on Council with several of

.its members, and reviewed the action items which were generated during its

i

meetings.

b.

Observations and Findinas

'

As discussed in NRC IR 50-352 & 353/97-01, PECO instituted a Fire Protection

Council in February 1997. At the time of that inspection, insufficient time had -

passed to achieve any significant results.

The Fire Protection Council is comprised of the IRM Managers from Limerick (LGS)

and Peach Bottom (PBAPS), the Nuclear Engineering Department (NED) Probabilistic

p

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Safety Assessment (PSA) Branch Manager, the LGS and PBAPS Fire Protection

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Program and Firt. Protection System Managers, and the NED PSA Fira Protection

Program and Safe Shutdown Program Managers. Other personnel are added if

needed to address specific issues. The management sponsor for the council is the

Executive Vice-President, Nuclear.

The council is functioning to provide management oversight of the fire protection

improvement projects, to establish priorities and to coordinate the efforts between

NED, PBAP3 and LGS. The council has obtained funding to bring in contractor

assistance for the procedure improvement project at LGS, and has added additional

contractor support for the program for calendar year 1998. The council has created

several additional fire protection performance indicators for tracking, including the

availability of the diesel driven, motor driven, and backup fire pumps. The council

will focus on program and process issues, and leave the equipment issues to the

focused improvement team discussed in Section F6.2.

c.

Conclusions

Based on the discussions with members of the Fire Protection Council and review of

the Action items generated at its meetings, the inspector concluded that the council

was a good initiative for bringing fire protection issues to management's attention

and prioritizing the improvement efforts.

F6.2 Fire Protection Focused imorovement Team (92904)

a.

Insnection Scoce

'

The inspector discuesed the Focused improvement Team (FIT) with team members,

and attended a FIT meeting on-site.

b.

Observations and Findinas

The Fire Protection FIT was assembled to provide a higher level of attention to

address equipment problems at the Limerick site. The purpose of the team is to

identify equipment issues, prioritize the equipment issues, search for commonalities

between the Peach Bottom and Limerick sites, and determine courses of action for

long-term resolution of equipment reliability and maintenance issues.

The initial meeting of the FIT was held August 14,1997. It consisted of a

" brainstorming" session to identify the known and potential hardwars issues with

fire protection systems. Action items from the meeting included developing a list of

obsolete parts / equipment and breaking down the equipment issues into logical

groupings, such as fire pump bearing problems, fire diesel battery problems, and so

forth. A second meeting, which the inspector attended, was held August 21,

1997.

The FIT goal is to identify all of the fire protection system functions and

components which do not meet expectations for performance or maintainability and

ensure that the identified issues are being properly addressed. In addition, the FIT

..__

_

-__

_ . . _ _ _

i

)

30

will attempt to anticipate future problem areas based on PECO and industry

experience. An example is a recently identified issue with testing of foam fire

fighting equipment. After performing the required test, the concentrate remains in

the lines, and can cause the foam concentnte check valve to stick with a resultant

failure of the next test. The FIT is evaluating what actions to take for resolving this

emergent problem.

c.

Conclusions

Based on the issues raised at the FIT meeting, and a review of the action items in

progress, the inspector concluded that the FIT is a good initiative to identify fire

protection equipment and system problems.

F8

Miscellaneous Plant Support issues (90712)

F8.1

(Closed) LER 1-97 006, Previous Condition Prohibited by Tech Snecs in that a Fire

Protection System Deluae Valve may not have Functioned oer Deslan Since

issuance of the Unit 1 Operatina License.

This LER concerned an instance where station personnel identified that a potential

voltage mismatch may exist between a fire protection deluge valve and its control

panel, resulting in marginal power available to operate the valve. An evaluation

concluded that a technical specification noncompliance occurred between issuance

of the facility operating license for Unit 1 on October 26,1984, and Decembcr 20,

1995, when the applicable technical specifications were relocated to the Technical

Requirements Manual, since the valve may have been unable to perform its design

function. Corrective actions included making adjustments to the valve to optimize

mechanical operation, posting a continuous firewatch, increased testing of the

valve, and the valve was replaced on September 3,1997. This violation had more

tn:.n minor significance since it resulted in a condition where a technical

specification-required deluge valve was inoperable for an extended period of time.

However, safety consequences for this event were low, since no actual fires

occurred in the area. Additionally, had a fire occurred and had the valve failed to

automatically operate, it would have been manually activated by the fire brigade,

which would have responded to the fire alarm. This licensee-identified and

corrected violation is being treated as a non-cited violation, consistent with Section

Vll.B.1 of the NRC Enforcement Policy. (NCV 50 352/97-07 07)

V. Manaaement Meetinas

4

X1

Exit Meeting Summary

The inspector presented the inspection results to members of plant management at the

conclusion of the inspection on September 17,1997. The plant manager acknowledged

'

the inspectors' findings. The inspectors asked whether any materials examined during the

inspection should be considered proprietary. No proprietary information was identified.

.

J

.

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.

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. . - _

_ _ .

.__ _ ._

_ . . . . . _ .

[

,

31

,

X2

Review of UFSAR Commitments

- A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR

description highlighted the need for a spacial focused review that compares plant practices,

-

'

procedures and/or parameters to the UFSAR description. While performing the inspections

discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that

related to the areas inspected. The inspectors verified that the UFSAR wording was

consistent with the observed plant practices, procedures and/or parameters.

,

.

4

4

.

J

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4

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I

- , . - ,

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

32

INSPECTION PROCEDURES USED

IP 37551:

Onsite Engineering

IP 38701:

Procurement Program

IP 61726:

Surveillance Observation

IP 62707:

Maintenance Observation

IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

IP 84750

Radioactive Waste Treatment, and Effluent and Environmental Monitoring

IP 90712:

In-office Review of Written Reports

IP 90713:

Review of Periodic and Special Reports

IP 92904:

Followup - Plant Support

IP 93702:

Prompt Onsite Response to Events at Operating Power

Reactors

ITEMS OPENED, CLOSED, AND JISCUSSED

Ooened

l

[

352,353/97-07-01 VIO

Control of Locked Valves (O2.1)

352,353/97-07-02 IFl

Concerns associated with a number of RWCU isolations.

(08.2)

353/97-07 03

VIO

HPCI System Inoperable Due to Clogged Turbine Exhaust Drain

r

Line. (M8.1)

{

353/97-07-06

IFl

Charcoal Efficiency Testing Adequacy (R2.2)

Closed

352,353/97-07-04 NCV Review of PECO Audits and PECO's Use of Third Party Audits

(E7.1.1 )

352, 353/97-07-05 NCV Purchase Order Revision Controls (E7.1.3)

352/97-07-07

NCV Fire Protection System Deluge Valve may not have Func.tioned

per Design. (F8.1)

352/1-97-006

LER

Previous Condition Prohibited by Technical Specifications in

that a Fire Protection System Deluge Valve may not have

Functioned per Design Since issuance of the Unit 1 Operating

License. (F8.1)

353/2 97-007

LER

Unit 2 HPCI System inoperable Due to Clogged Turbine

Exhaust Drain Line. (M8.1)

.

.

1

.

.

_.

_

33

ITEMS OPENED, CLOSED, AND DISCUSSED (Continuod)

353/2 97-008

LER

Automatic Closure of Drywell Chilled Water System Primary

Containment isolation Valves, an ESF Actuation, Resulting

from Emergency Diesel Generator Voltage Regulation Failure.

(08.2)

353/2 97 009

LER

Unit 2 Reactor Water Clean-up Isolation, an ESF, Caused by a

RWCU Filter Demineralizer Y Strainer Manual Drain Valves

Leaking into the Backwash Receiving Tank. (08.3)

Discussed

None

LIST OF ACRONYMS USED

AFSS

Automatic Fire Suppression System

AR

Action Request

BOP

Balance of Plant

CEI

Centerior Energy

CFR

Code of Federal Regulations

CREFAS

Control Room Engineering Fresh Air System

EDG

Emergency Diesel Generator

ELU

Emergency Lighting Unit

ESF

Engineered Safety Feature

EWR

Engineering Work Request

FIT

Focused improvement Team

FME

Foreign Material Exclusion

FP

Fire Protection

FSWS

Fire Suppression Water System

GL

Generic Letter

HEPA

High Efficiency Particulate

HPCI

High Pressure Coolant injection

IFl

inspection Follow-up Item

IR

inspection Report

IRM

Industrial Risk Management

LCO

Limiting Condition For Operation

LER

Licensee Event Report

LGS

Limerick Generating Station

NCV

Non-Cited Violation

NDE

Nondestructive Examination

NED

Nuclear Engineering Department

NOA

Nuclear Quality Assurance

NRB

Nuclear Review Board

NRC

Nuclear Regulatory Commission

NUPIC

Nuclear Procurement issues Committee

ODCM

Offsite Dose Calculation Manual

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

- _ _._ _. _ _ ..

_

_

-34

_

IPAB1

Proterted Area' Boundary

PBAPS4

Peach Bottom Atomic Power Station

_ PECO -

- PECO _ Energy

.

PEP

Performance Enhancement Process

-PO-

Purchase Order.

' PORC -

Plant Operations Review Committee

PSA

Probabilistic Safety Assessment

' QA -

Quality .^ ssurance

-QC-

Quality Control

'

QV

Quality Verification

_

RCIC '-

Reactor Core Isolation Cooling-

RCO-

_ Request for Change Order

RHR

Residual Heat Removal

-RMS

Radiation Monitoring System

4

RP&C

Radiological Protection and Chemistry

RP'

Radiation Protection

-

RT

Routine Test

RWCU.

Reactor Water Clean-up

b

SCBA

- Self Contained Breathing Apparatus -

SLC

Standby Liquid Control

ST-

Surveillance Test-

TRM

Technical Requirements Manual

-TS

-Technical Specification

TSC-

Technical Support Center

.UFSAR

Updated Final Safety Analysis Report

.

URI

Unresolved item

VIO

Violation

.

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.- . _. ____ _ _____ _ . _ . _. _. _

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'

35

1;

"

LIST OF DOCUMENTS REVIEWED.

,

Procedures

.

I

- A-c-043,' Surveillance Testing Program, Rev. O

{-

- A C-079, Procedure- Adherence and Use, Rev.

ST-7-022 3531, Halon System Inventory, Rev. 4

1~

ST-7 022-3531, Unit 1 Main Bank Halon System Inventory, Rev. 5

ST-7 022-354-1, Unit.1 Reserve Bank Halon System inventory, Rev. 0

- iST-7 022-353 2, Halon System Inventory, Rev. 6

!

lST-7-022-353-2,' Unit 2 Main Brnk Halon System Inventoryi Rev. 7

iST-7-022 354-2, Unit 2 Reserve Bank Halon System Inventory, Rev. O

i ST-7-022-730-1, FSWS Air / Water Nozzle Flow Test, Rev. 4

I

. . __

iST-7-022-9201, Unit 1 Refuel Fire Rated Assembly Inspection, Rev. 3

!

- l ST-7-022 920-1, Attachment 1, Structural Fire Rated Assembly Tabulation, Rev. 'J (with

'

- temporary change 1-87-0903 1)

,

ST-7-022 9201- Unit 1 Refuel Fire Rated Assembly inspection, Rev. 2

,

ST-7-022-920 1,- Attachment 1,-Structural Fire Rated Assembly Tabulation, Rev. 2

_

ST 7-022-920-2, Attachment 1, Structural Fire Rated Assembly Tabulation, Rev. 5 (with

temporary change 1 97 0904 2)

L

ST-7 022 921-0, Fire Damper Inspection, Rev. 6 (with temporary changes 1-97-0901-0

and 2 97-0908-0)

-

ST-7-022 921-0, Attachment 1, Fire Damper Tabulation, Rev. 6

- ST-7 022-921_-1, Fire Damper inspection, Rev. 5

,

i ST-7-022-921 -2, Fire Damper Inspectioni Rev. 2

i ST-7-022-921 -2, Attachment 1, Fire Damper Tabulation, Rev.1

ST-7-022-922 0, Fire Rated Penetration Test Sample Visual inspection, Rev. 6

l

ST-7-022-922-0, Attachment 1, Fire Rated Penetration Seal Tabulation, Rev. 4

5

RT-6-108-300-0, Safe Shutdown Eight (8) Hour Selt-Contained Battery Pack Operation

'

Verification, Rev. 6

'

RT-6-108-300-0, Safe Shutdown Eight (8) Hour Self-Cor tained Battery Pack Operation

Verification, Rev. 4 -

.

RT-6-108-300-1, Safe Shutdown Eight (8) Hour Self Contained Battery Pack Operation

. Verification, Rev 5-

RT 6-108 300-1, Safe Shutdown Eight (8) Hour Self-Contained Battery Pack Operation

Verification, Rev. 4

>

i RT-6-108-300-2, Safe Shutdown Eight (8) Hour Self Contained Battery Pack Operation

- Verification, Rev. 4

4

RT-6-108-300-2,. Safe Shutdown Eight (8) Hour Self Contained Battery Pack Operation

'

Verification, Rev.~3

RT-7 022 3201, BOP Fire Protection Sprinkler System Operability Verification, Rev.6

,

RT-7-022-320 1, BOP Fire Protection Sprinkler System Operability Verification,' Rev. 5

RT 7-022-321-1, Catage Wet Pipe Sprinkler System Operability Verification and Visual

Inspection, Rev. O

L

RT-7-022-322 0, Remote Buildings (Outside PAB) Sprinkler System Operability Verification,

Rev.6

RT-7-022 322-0, Remote Buildings (Outside PAB) Sprinkler System Operability Verification,

Rev.5

+

4

'

.

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_____ _ _ - ____-___-___ - - _ _

_ _ _ _

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36

RT 7 022 353 0, TSC Halon System Inventory, Rev. 5

RT 7 022 353 0, TSC Halon System Inventory, Rev. 4

S22.8.C, Hatchway Flow Control Valve Reset, Rev. 6

S22.8.E Pre Action or Deluge System Reset, Rev. 6

i Denotes procedures which were walked down, in part, in the facility

\\

htd@e.rino Documents \\

Specification A 39A, Fire Protection Specification for Structural Steel Fireproofing

(CAFCOTE 800), Limerick Generating Station Units 1 and 2, Rev.8

l

Specification A 39A, CAFCOTE 560 Application and Installation Guide, Rev.1

i

Specification A 39, Specification for Structural Steel Fireproofing for the Limerick

Generating Station Units 1 and 2

Engineering Work Request L 00508, Fire Coating on Structural Steel Beams, Rev. 8

A 305, Sher? 1, Architectural; Alr/ Steam / Fire & Water Boundaries Floor Plan El 177' 0"

Unit i, Rev.12

A 305, Sheet 2, Architectural; Air / Steam / Fire & Water Boundaries Floor Plan El.177' 0"

Unit 2, Rev. O

A 305, Sheet 3, Architectural Security Boundaries Flocr Plan El.177' 0" Unit 1&2, Rev.

O

A 306, Sheet 1, Architectual Air / Steam / Fire & Water Boundaries Floor Plan El. 201' 0"

Unit 1, Rev.16

A 306, Sheet 2, Architectural Air / Steam / Fire & Water Boundaries Floor Plan El. 201' 0"

Unit 2, Rev. O

A 306, Sheet 3, Architec" .el Security Boundaries Floor Plan El 201' 0" Unit 1&2, Rev.

O

A 307, Sheet 1, Architectural; Air /Steem/ Fire & Water Laundaries Floor Plan El. 217' 0"

Unit 1, Rev.19

A 307, Sheet 2, Architectural: Air / Steam / Fire & Water Boundaries Floor Plan El. 217' 0"

Unit 2, Rev. 3

A 307, Sheet 3, Architectural Security Boundaries Floor Plan El/ 217' 0" Unit 1&2, Rev.

O

A 308, Sheet 1, Architectural; Air / Steam / Fire & Water Boundaries F!oor Plan El. 253' 0"

Unit 1, Rev.13

A 308, Sheet 2, Architectural; Air / Steam / Fire & Water Boundaries Floor Plan El. 253'-0"

Unit 2, Rev. O

A 308, Sheet 3, Architectural Security Boundarles El. 253' 0" Unit 1, Rev. O

A 309, Sheet 1, Architectural; Air / Steam / Fire & Water Boundaries Floor Plan El 283' 0" &

269' 0" Unit 1, Rev.16

A 309, Sheet 2, Architectural; Air / Steam / Fire & Water Boundarles Floor Plan El. 283' 0" &

269' 0" Unit 2, Rev. O

A 309, Sheet 3, Architectural - Security Boundaries Floor Plan El. 283' 0" & 209' 0" Unit

1 &2, Rev. O

A 310, Sheet 1, Architectural: Air / Steam / Fire & Wbter Boundaries Floor Plan El. 313'-0",

302' & 332' Unit 1, Rev.13.

A 310, Shset 2, Architectural: Air / Steam / Fire & Water Boundaries Floor Plan El. 313' 0",

302' & 352' Unit 2, Rev. O

y

v

.

.

. -

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

.-

-

---

_-. - -

37

.

A 310, Sheet 3, Architectural Security Boundaries Floor Plan El. 313'0", 302' & 332'

)

Unit 1&2, Rev. O

i

A 311, Sheet 1, Architectural; Air / Steam / Fire & Water Boundarles Floor Plan El. 352'-0"

'

]

Unit 1, Rev. 6

A 311, Sheet 2, Architectural; Air / Steam / Fire & Water Boundaries Floor Plan El. 352' 0"

Unit 2, Rev. 0

l

A 311, Sheet 3, Architectural Security Boundaries Floor Plan El. 352' 0" Unit 1&2, Rev.

1

0

4

A 185, Architectural Control Bldg. Fire Proofing Sec. & Det., Rev. 5

C 426, Control Room Area Floor Plan, El. 239' 0" Area 8, Rev. 24

!

C 432, Control Room Area Floor Plan, El. 254' 0" Area 8, Rev. 22

'

3

C 440, Control Room Area 8, Sections and Dettils, R: v.12

l

C 473, Sheet 1, Control Room Area 8 Structural Steel, Framing Plan El. 254' 0" & El.

j

269' 0", Rev.12

j

C 473, Sheet 2, Control Room Area 8 Structural Steel, Traffic Control Barriers El. 269' 0",

l

. C 478, Control Room Area 8 Structural Steel, Framing Plan El. 289' 0" & El 304' 0", Rev.

Rev.0

1

i

12

l

C 191, Reactor Building Units 1&2, Structural Steel Column Schedule, Rev. 24

'

i

C 460, Control Room Area 8 Structural Steel, Framing Plan El. 239' 0", Rev.16

j

M 1151, Heating and Ventilating Reactor Bldg. Unit No. 2 Plan at El. 217' 0" Area 13,

i

Rev.16

{

M 1152, Heating and Ventilating Reactor Bldg. Unit No. 2 Plan at El. 253' 0" Area 13,

Re'.'. 19

4

j

Other Dpeuments

UFSAR, Appendix 9A

Limerick Unit 1 Technical Requirements Manual

'

Limerick Unit 2 Technical Requirements Manual

PEP lssue 5811, insulation Missing From Structural Steel

PEP lssue 6033, Fire Protection Procedure improvements

Action Request A1050861, PEP 10006033 LGS Fire Protection Procedure

'

l

Quality Concern 127, irregularities in Performance of Fire Protection Surveillance Tests

,

I

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.

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