ML20148F944

Insp Repts 50-413/97-07 & 50-414/97-07 on 970323-0426. Violations Noted.Major Areas Inspected:Licensee Operations, Maint,Engineering & Plant Support

ML20148F944
Person / Time
Site:	Catawba
Issue date:	05/23/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20148F917	List: ML20148F913 ML20148F929 ML20148F944
References
50-413-97-07, 50-413-97-7, 50-414-97-07, 50-414-97-7, NUDOCS 9706050102
Download: ML20148F944 (50)

See also: IR 05000413/1997007

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos:

50-413, 50-414

License Nos:

NPF-35 NPF-52

Report Nos.:

50-413/97-07. 50-414/97-07

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Licensee:

Duke Power Company

Facility:

Catawba Nuclear Station Units 1 and 2

Location.

422 South Church Street

Charlotte. NC 28242

Dates:

March 23 - April 26,1997

Inspectors:

R. J. Freudenberger, Senior Resident Inspector

P. A. Balmain, Resident Inspector

R. L. Franovich. Resident Inspector

R. A. Gibbs, Resident Inspector (In Training)

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J. L. Coley, Jr. . Reactor Inspector (Sections M2, E2.1)

D. B. Forbes, Radiation Specialist (Sections R1, R5, R7)

W. H. Miller, Jr.. Reactor Inspector (Sections 08.1, F2,

F3. FS, F6. F7 F8)

R. L. Moore, Reactor Inspector (Sections E2.2, E4.1, E8.1.

E8.2)

Approved by:

C. A. Casto, Chief

Reactor Projects Branch 1

Division of Reactor Projects

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Enclosure 2

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EXECUTIVE SUMMARY

Catawba Nucleer Station. Units 1 & 2

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NRC Inspection Report 50-413/97-07. 50-414/97-07

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This integrated inspection included aspects of licensee operations.

maintenance, engineering, and plant support. The report covers a 6-week

period of resident ins)ection: in addition. it includes the results of

announced inspections ay regional reactor safety inspectors.

Operations

A Unit 2 loss of spent fuel pool cooling, which was caused by an

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inadequate containment penetration test procedure, was identified as a

violation.

Other barriers that could have prevented the event included

increased emphasis on the importance of the system function during the

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pre-job brief and more diligent control board monitoring.

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operator's performance in response to the event was appropriate.

The

Catawba Safety Review Group evaluation of the event was detailed and

identified substantive corrective actions. (Section 01.1)

Midloop Activities were well controlled.

Nevertheless, the process for

restoring equipment necessary for gravity flows to the core may not be

ensured by administrative controls. (Section 01.2)

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The inspector concluded that selected initial conditions for the

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compensatory action associated with the main control room pressure

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boundary were satisfied.

The inspector further concluded that operator

effectiveness in im)lementing this complex compensatory action was

challenged by lengtly initial conditions, and the practice of not

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periodically reverifying required initial conditions. (Section 01.3)

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Problems encountered with the Boron Dilution Mitigation System during

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the Unit 2 refueling outage were indicative of historically low

reliability and availability, which caused additional control room

operator workload to compensate for the system's low reliability.

(Section 01.4)

The inspector concluded that actions by operations and Radiation

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Protection personnel in response to the radiation alarm in the fuel

handling building were good. However. foreign material exclusion

administrative controls were not properly im)lemented by personnel

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working in the fuel transfer canal area of t1e fuel handling building.

(Section 01.5)

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A Unit 1 pressurizer )ower operated relief block valve control circuit

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failure occurred whic1 is a potential repeat of a previous 1995 failure.

The licensee has planned appropriate actions to determine the cause of

the control circuit component failure. (Section 01.6)

Enclosure 2

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Maintenance

The inspector concluded that, in general, outage-related maintenance

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activities were ap]ropriately conducted. Although multiple barriers to

minimizing the risc of human error during reactor coolant pump seal

maintenance were noted, the inspector was unaware of any human

performance problems associated with the work. (Section M1.1)

The licensee's resolution of long-standing elevated vibration levels

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associated with the Unit 2B nuclear service water pump motor was very

good.

Deficiencies identified with a spare nuclear service water pump

motor, a previous motor failure, and findings identified by licensee

assessments of warehouse storage and handling practices raised questions

about control and storage of spare motors. The issue is identified as

an Inspector Followup Item and will be reviewed during a future

inspection. (Section M1.2)

Certification records for nondestructive examination (NDE) personnel,

weld examinations, and NDE examination procedures were in accordance

with Code requirements. (Section M2.1)

Review of the eddy current outage plan, equipment setup and acquisition

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procedures, personnel and equipment certifications, and observation of

data acquisition activities revealed that required documentation was

available and complete, and data acquisition personnel were

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knowledgeable of the eddy current examination process. (Section M2.2)

The licensee has implemented an effective program for the detection of

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flow accelerated corrosion in components. This program is based on

recommendations found in recognized industry standards. (Section M2.3)

The maintenance / work control self-assessment programs effectively

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identified areas for improvement and a]propriate corrective actions.

The self-assessments apparently contri)uted to improvement in the

performance of the Maintenance and Work Control organizations. (Section

M7.1)

Enaineerina

The licensee's actions to replace all control rod assemblies that had

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evidence of tip cracking were appropriate. (Section El.1)

Documentation for the modification of the Unit 2 pressurizer manway was

satisfactory, and engineering considerations for the modification,

inspection, and cleaning of the pressurizer were very good. (Section

E2.1)

Design controls for Unit 2 outage modifications were consistent with

regulatory requirements. (Section E2.2)

Enclosure 2

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The motor shaft key way cracking in large high speed limitorque motor

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actuators at-Catawba was an example of good identification and

resolution of equipment problems using the Operating Experience Program.

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(Section E4.1)

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Plant Sucoort

The licensee was effectively maintaining controls for personnel

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monitoring, control of radioactive material, radiological postings. and

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radiation area /high radiation area controls as required by 10 CFR Part 20. One Non-Cited Violation was identified for failure to source check

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survey instruments as required by licensee procedure. (Section R1.1)

The licensee was maintaining programs for controlling exposures As Low

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As Reasonably Achievable and continued to be effective in controlling

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overall collective dose. (Section R1.2)

Radiation protection technicians and radiation workers were receiving an

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appropriate level of training to perform work activities involving

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radiation and/or radioactive material. (Section RS)

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The licensee was performing Quality Assurance Audits and effectively

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assessing the radiation protection program as required by 10 CFR Part

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20.1101 and completing corrective actions in a timely manner. (Section

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R7)

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The low number of open maintenance work orders and degraded fire

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protection components, in conjunction with the good material condition

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of the fire protection components and fire brigade equipment, indicated

that, in general

appropriate em3hasis had been placed on the

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maintenance and operability of t1e fire protection equipment and

components. (Section F2.1)

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The work to repair the suction screens for the fire pumps' suction

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piping had been ooen since 1991 and was not complete.

The failure to.

complete this work in a timely manner was identified as a Violation.

(Section F2.1)

Good surveillance and test procedures were provided for the fire

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protection systems and features with effective procedure implementation.

.The coordination of the fire protection water piping cleaning project

was excellent. (Section F2.2)

The fire protection program implementing procedures were good and met

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licensee and NRC requirements.

Implementation of procedures for the

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control of. ignition sources, transient combustibles, and general

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housekeeping was good. An issue regarding time limits for restoration

of inoperable fire protection components will be reviewed further by the

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NRC under an Inspector Followup Item.

(Section F3)

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Enclosure 2

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The fire brigade organization and training met the requirements of the

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site procedures.

Performance by the fire brigade during a drill was

excellent. The use of the fire brigade safety officer position used

during fire emergencies was identified as a program strength. (Section

F5)

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Strong coordination and oversight were provided over the facility's fire

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protection program.

The Fire Protection BEST was a positive force in

the identification of potential problems and in the development and

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implementation of enhancements to the fire protection program. (Section

F6)

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The 1995 audit and assessment of the facility's fire protection program

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was comprehensive and appropriate corrective action was promptly taken

to reso:ve the identified issues. An issue regarding the control of OA

audit frequencies was identified as an Inspector Followup Item will be

reviewed further by the NRC. (Section F7)

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Enclosure 2

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Report Details

Summary of Plant Status

Unit 1 began the ]eriod operating at 100% power and operated at essentially

full power througacut the inspection period.

Unit 2 began the period in cold shutdown (Mode 5) in preparation for the End

of Cycle (EOC8) refueling outage. One scheduled period of reactor coolant

system reduced inventory /midloop began and completed on April 23.

Midloop was

entered to support the reactor coolant system vacuum refill evolution. At the

close of the inspection period the Unit had returned to cold shutdown (Mode 5)

and heatup activities in preparation for unit restart were beginning.

Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitgents

While performing inspections discussed in this report, the inspectors reviewed

the applicable portions of the UFSAR that were related to the areas inspected.

The inspectors verified that the UFSAR wording was consistent with the

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observed plant practices, procedures, and/or parameters,

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I. Operations

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Conduct of Operations

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01.1 Loss of Spent Fuel Pool Coolina

a. Insoection Scope (71707)

On April 8. Unit 2 was in a refueling outage with all of the fuel off-

loaded to the spent fuel pool.

The Operator Aid Computer was out of

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service for replacement, and alignments for testing of containment

isolation valves in the component cooling water non-essential header

were in progress.

Inventory was inadvertently drained from the

component cooling water system over a seventy minute period. until the

low-low level setpoint in the component cooling water surge tanks was

reached. At this level, automatic isolation of the non-essential header

occurred. the drain path was isolated, and cooling flow to the spent

fuel pool heat exchanger and pump motor cooler was isolated.

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shutdown the pump to prevent overheating, initiated makeup to t1e

component cooling water surge tanks. and closely monitored spent fuel

pool temperature. Spent fuel pool temperature increased to a maximum of

108 F. within the TS limit. while operators determined the cause of the

loss of component cooling water inventory and returned the non-essential

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header to service.

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As a result of the event, the licensee initiated Problem Investigation

Process (PIP) report 2-C97-1090 and initiated a root cause evaluation

that was performed by the Catawba Safety Review Group.

The inspector responded to the site upon notification of the loss of

spent fuel pool cooling: discussed the event with various personnel

Enclosure 2

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involved; reviewed PT/2/A/4200/01T, Containment Penetration Valve

Injection Water System Performance Test, approved 3/26/97: reviewed data

on component cooling water surge tank level spent fuel pool cooling

pump motor temperatures, and spent fuel pool temperature: and reviewed

the root cause evaluation documented in the referenced PIP.

b. Observations and Findinas

At the time of the loss of spent fuel pool cooling, approximately 19

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hours were available prior to boiling in the spent fuel pool. Operators

methodically restored cooling within 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, after identifying the

cause, assessing equipment condition, and realigning the component

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cooling water system.

The licensee's root cause evaluation considered procedural adequacy.

o]erator performance, ad supervisory oversight of the evolution.

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taese areas, problems were identified and appropriate corrective actions

were delineated.

Procedure PT/2/A/4200/01T, Containment Penetration Valve Injection Water

System Performance Test, included steps for the alignment of four

component cooling water containment penetrations that included valve

manipulation sequences that were incorrect. The incorrect sequences

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caused drain paths to be aligned through the inside containment

penetration vent on all four penetrations. The licensee's evaluation

revealed that the Unit 1 procedure had similar errors. The errors

occurred during a process to convert engineering test procedures into

the operations procedure format.

Proposed corrective actions included a

formal validation of the technical adequacy of other procedures that

have been or were to be converted. This procedure inadequacy, which

caused the loss of spent fuel cooling constitutes a Violation (VIO) of

TS 6.8.1. Procedures and Programs, and is identified as VIO 50-414/97-

07-01:

Inadequate Procedure Resulting in Loss of Spent Fuel Pool

Cooling with Core Off-loaded.

The licensee's evaluation of operator performance concluded that the

equipment operator that performed the valve alignments appropriately

questioned the high flow rate from the vent valves as they were opened,

but failed to stop and contact su3ervision when this unexpected response

was obtained. Also, the control aoard operators were not timely in

their assessment of an observed increased rate of input to the

containment floor and equipment sump.

The inspector noted that the pre-job brief for performing the

containment Jenetration alignments was incomplete.

Personnel conducting

the pre-job arief did not emphasize that the component cooling water

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system was affected by the procedure and was being relied upon for

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cooling the spent fuel pool with the core off-loaded.

Also, the control

room operators could have more diligently monitored this system, since

it was performing an important function, and identified the decreasing

level in the component cooling water surge tanks before automatic

actions occurred. Operations management had similar observations and

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took actions to imarove monitoring of systems performing important

functions during t1e remainder of the outage.

c. Conclusions

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The loss of spent fuel pool cooling was caused by an inadequate

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containment penetration test procedure.

Other barriers that could have

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prevented the event included increased emphasis on the importance of the

system function during the pre-job brief and more diligent control board

monitoring.

The operator's performance in response to the event was

appropriate. The Catawba Safety Review Group evaluation of the event

was detailed and identified substantive corrective actions.

01.2 Preoarations for Midlooo

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a. Insoection Scooe (71707)

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Near the conclusion of its refueling outage. Unit 2 entered midloo) on

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April 23 for vacuum refill of the Reactor Coolant System (RCS). Tie

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inspector reviewed Generic Letter 88-17. Loss of Decay Heat Removal.

Catawba Nuclear Site Directive 3.1.30. Unit Shutdown Configuration

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Control. Rev. 8. and the operating 3rocedures governing the RCS

draindown to midloop, operation wit 1 reduced RCS inventory, and vacuum

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refill. The inspector conducted control room observations during the

draindown to midloop and portions of unit operation at midloop.

b. Observations and Findinos

The inspector verified that the requirements delineated in Catawba

Nuclear Site Directive 3.1.30 were satisfied.

Specifically, multiple

thermocouples were available for temperature monitoring; ultrasonics and

sightglass indications were available for level monitoring: vital power

was available from both offsite sources, as well as two emergency diesel

generators; necessary emergency core cooling equipment was either

operable or available: and the gravity flowpath criteria were satisfied

for midloop operation with low decay heat.

Just prior to reduced inventory operations, the inspector noticed that

valves 2ND-33. Residual Heat Removal (RHR) System Return to the

Refueling Water Storage Tank (FWST). 2FW-27A and 2FW-55B. RHR Pumps 2A

and 2B Suction from the FWST. were available as opposed to operable.

These valves are in the flowpaths of the three gravity feeds to the RCS.

The valves were tagged closed in support of RCS maintenance.

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inspector questioned the a)proariateness of considering the associated

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flowpaths available with tie RiR and FWST valves closed under a tagout.

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Normal makeup to the reactor coolant system via the chemical and volume

control system was available.

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The inspector inquired about the status of the RHR and FWST valves

during reduced inventory and midloo) operations and determined that.

although they were tagged closed, t1e Work Control Center filed the tags

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in a prominent location to facilitate equipment restoration in the event

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that these valves were needed to mitigate a loss of RHR.

The inspector reviewed Catawba Nuclear Site Directive 3.1.30 to

determine if administrative requirements were being met. The directive

stated that, for midloop operations with low decay heat load, two

available gravity flowpaths were required. The directive defines

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"available" as "the status of a system, structure or component that is

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in service or can be placed in service in a functional or operable state

by immediate manual or automatic actuation." The directive considers

actions taken by operators to clear tags acceptable for restoring

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equipment to functional or operable status within a reasonable period of

time.

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The inspector raised a concern to the licensee that, while valves 2FW-

27A. 2FW-55B. and 2ND-33 could possibly be restored to service in a

reasonable period of time, other components that might be impacted by

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the maintenance activity in progress might not be accounted for before

the gravity flowpath would be utilized.

Hence, points of compromised

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system integrity, which could allow flow to be diverted from the RCS.

might be overlooked and either reduce the assumed flow to the RCS or

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extend the amount of time needed to place the gravity flowpath in

service.

Although no such conditions were identified during the midloop

and vacuum refill evolutions, the licensee plans to evaluate Nuclear

Site Directive 3.1.30 to determine if changes are warranted prior to the

next refueling outage.

c. Conclusions

The inspector concluded that the draindown to midloop, midloop

operation, and vacuum refill were conducted without incident.

In

general, the licensee implements effective controls for these

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evolutions.

However, the inspector questioned the availability of

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equipment required for gravity flow to the core and expressed concern

that the process for restoring needed equipment may not be sufficiently

controlled.

01.3 Doerator Aid Comouter Installation and Comoensatory Action

a. Insoection Scooe (71707)

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During the Operator Aid Computer (OAC) installation, the inspector

periodically verified that the Loss of DAC procedure was implemented

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while the OAC was unavailable.

The inspector observed an open main

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control room door and reviewed the associated compensatory action.

" Control Room Pressure Boundary." dated March 20. 1997, to verify that

the licensee had satisfied selected initial conditions that allowed the

door to remain open.

The inspector also evaluated the licensee's

im)lementation of the compensatory action guidance following receipt of

a Jnit 2 fuel handling building high radiation alarm that occurred on

March 24.

b. Observations and Findinas

During the Unit 2 OAC installation. the OAC was not available for

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automatic surveillance of numerous plant parameters. As a result, the

control room operators were required to implement PT/1/A/4600/09. Loss

of Operator Aid Computer, and perform those surveillances manually'on

specified time intervals. The inspector periodically verified that the

procedure was in use while OAC monitoring was unavailable. Often a

dedicated reactor operator was available to perform this function.

although that could not always be accommodated.

The inspector

determined that the procedure was in place and being implemented when

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required.

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The inspector observed that the Unit 2 control room vital access door

was opened on March 22 and was left open continuously to allow passage

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of a flexible ventilation duct (approx. 12 inch diameter). The duct was

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used to exhaust fumes generated from welding performed to install the

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replacement operator aid computer in the Unit 2 main control board

panel. The inspector discussed the compensatory actions with

engineering and operations 3ersonnel to determine if the compensatory

actions would ensure that tie control room would pressurize sufficiently

to meet control room habitability requirements during design basis

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events.

Both operations and engineering personnel stated the design

basis for contrM room pressurization and habitability would be met

provided that initic1 conditions of the compensatory action were

satisfied and that the control room door would be manually closed, after

separating a connection in the duct. if certain plant events (e.g..

safety injection signal) were to occur.

The inspector verified that selected initial conditions were satisfied

and found no discrepancies with the plant conditions that existed at the

time of the inspection.

The inspector observed, however, that the

initial conditions of the compensatory action were not being

periodically verified to ensure that plant changes since the initial

condition verification on March 22 had not invalidated the assumptions

supporting the compensatory action. Operations personnel informed the

inspector that periodic verification of initial conditions for the

compensatory actions was not required.

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The inspector expressed a concern to the licensee that, because there

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was a high number of initial conditions required for this particular

compensatory action and because of the relatively long duration of the

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replacement operator aid com) uter installation, periodic verification of

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initial conditions may have 3een warranted to ensure that necessary

conditions continued to be met.

Additionally, the licensee recognized

that changes in plant ventilation equipment status created by refueling

outage activities could invalidate the assumptions of the analysis

supporting the compensatory action.

The licensee initiated timely corrective actions to periodically

reverify the initial conditions of the compensatory action.

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periodicity of the reverification varied based on the potential for the

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condition to change.

The inspector observed the reverification of the

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initial conditions following implementation of the licensee's corrective

actions.

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The inspector observed two other minor discreaancies during the review

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of the compensatory action im)lementation.

T1e control room door was

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not closed on March 24 when tie Unit 2 spent fuel pool bridge radiation

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monitor (2 EMF 4) alarmed although this appeared to be a condition for

closing the door.

The inspector determined that the radiological

conditions that caused the alarm were inconsequential and not related to

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a release (refer to Section 01.5).

The inspector also found that the

accountability log sheet that specified individuals responsible for

manually closing the control room door had not been signed for one day.

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The inspector determined that the individuals involved were aware of

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their responsibilities, but had committed an administrative error.

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The licensee documented the inspector's concerns in Problem

Investigation Process (PIP) Report 0-C97-0988 and initiated actions to

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determine:

(1) if the response to the alarm was appropriate: (2) the

cause of the administrative error: and (3) if a reverification process

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for compensatory actions is needed.

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c. Conclusions

The inspector concluded that control room operators were appropriately

implementing their procedure for Loss of OAC when the OAC was

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unavailable during the installation process. Additionally, operator

effectiveness in implementing a complex compensatory action was

challenged by numerous initial conditions and the lack of periodic

reverification to ensure that they were being continuously met.

01.4 Boron Dilution Mitiaation System Reliability

a. Insoection Scope (71707)

Du' ring the Unit 2 shutdown for refueling outage 2E0C8. multiple problems

associated with the Boron Dilution Mitigation System (BDMS) were

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encountered.

The inspector investigated the nature of each problem and

reviewed the work history of the BDMS for both units. The inspector

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reviewed the FSAR and Technical Specifications (TS) and discussed system

performance and vulnerabilities with engineering personnel.

b. Observations and Findinas

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The BDMS consists of two trains and is designed to protect the reactor

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from an inadvertent criticality by automatically stopping the flow of

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unborated water to the core during shutdown conditions.

Required by TS

in Modes 3, 4. 5. and 6. the BDMS uses two source range detectors to

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monitor the subcritical multiplication of the reactor core.

An alarm

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set)oint is continually calculated, and if the setpoint is exceeded,

eitler train of BDMS will automatically shut off both reactor makeup

water pumps, align the suction of the charging pumps to the Refueling

Water Storage Tank (FWST), and isolate flow to the charging pumps from

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the Volume Control Tank.

Because these functions are automated, no

operator action is required.

Technical Specification 3.9.2 requires both trains of the BDMS to be

operable during Mode 6.

If one or bcth trains are inoperable, the

licensee must either suspend core alterations or verify' that source

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range neutron flux monitors are operable with alarm setpoints

a)propriately calculated for the current (and, during core reload,

clanging) steady-state count rate.

The licensee also must take

additional actions to verify that audible alarms are available in the

control room and containment, and that reactor makeup water pump flow

rates are within limits.

In addition the BDMS is required operable

during Modes 3, 4 and 5 by TF 3.3.3.11.

kDuringtheUnit2refuelingoutage,multipleproblemswiththeBDMSwere

encountered. On March 25. Unit 2 BDMS interlock testing revealed a

failure to secure the reactor makeup water pumps.

The failure was

attributed to a failed optical isolator.

On March 28 during core

offload to the Spent Fuel Pool, a spike on the B train source range

instrument caused the charging pump suction to swap from the Volume

Control Tank to the FWST.' This spike was attributed to noise generated

by welding activities during the Operator Aid Computer replacement and

exacerbated by a loose plug at the data processing cabinet. A third

problem, which also occurred during the core offload, was associated

with a shutdown monitor that failed to a zero signal reading.

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of the latter two problems the BDMS was declared inoperable, and the

required TS actions were performed.

Problems with the BDMS had been encountered periodically in the past.

According to the licensee's Work Management System (WMS), numerous work

requests have been written since 1987 for the BDMS.

Since 1986. 134

work requests have been closed for the Unit 1 BDMS: since 1987. 83 work

requests have been closed for the Unit 2 BDMS. The inspector could not

consistently determine if specific work requesis were generated to

resolve system problems or if they were "onerated for other reasons

(e.g. nameplate installation).

Nonetheles:.. the volume of work requests

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related to this system seemed high.

The inspector expressed to the

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licensee a concern with BDMS reliability and availability, as well as

the resulting impact (i.e., additional calibrations and monitoring) to

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control room operators. The licensee had come to the same conclusion

through a system review independent of the NRC's inspection.

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their findings, the licensee had recently decided to incorporate the

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BDMS into the site's Top Equipment Problem Resolution (TEPR) program.

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c. Conclusions

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Problems encountered with the BDMS during the' Unit 2 refueling outage

'

. were indicative of historical system performance problems, which affect

plant operation during modes 3. 4. 5 and 6.

The inspector concluded

that, since additional monitoring and calibration activities are

required when the BDMS is inoperable the BDMS has caused additional

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control room operator workload to compensate for its unreliability. The

licensee has indicated that efforts are being initiated to improve

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system reliability and, thereby. reduce operator burden through the TEPR

process.

So that the licensee's efforts to correct this adverse system

.

performance trend can be monitored to resolution, this issue is

'

identified as Inspector Followup Item 50-413.414/97-07-02: Boron

Dilution Mitigation System Reliability Resolution.

.

01.5 Fuel Handlino Buildina Evacuation

a. Insoection Scooe (71707)

'The inspector evaluated the licensee's response to a radiation alarm

resulting in an evacuation of the fuel handling building that occurred

on March 24. The inspector reviewed licensee's procedures, conducted

interviews with involved personnel, and walked down the fuel handling

building.

b. Observations and Findinas

On March-24. the inspector responded to the control room when the

control room operators announced over the public address system the

i

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evacuation of the fuel handling building.

During this time, the water

'

level in the fuel transfer canal had been lowered to facilitate

maintenance on valve 2KF-122. Fuel Transfer Canal Isolation Valve. The

ins)ector found that the spent' fuel pool bridge radiation detector

(2EiF-4) had alarmed, and annunciator response procedure for alarm 2-

RAD-3 had been implemented. The control room o)erators conservatively

elected.to evacuate the fuel handling building )ecause the ah:r.m was not

expected.- The inspector verified that the control room operators

i

properly followed their procedures and that the appropriate level of

supervisory oversight was maintained during the event.

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The inspector also discussed the event with Radiation Protection

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personnel and found that proper actions were completed.

Radiation

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Protection technicians surveyed the area and reported back to the

control room.

Subsequently, the 2FME-4 alarm setpoint was raised to

2

three times the background radiation level in'accordance with approved

!

procedures.

Additionally, the inspector verified that the area survey

map for the fuel handling building was updated, and the associated

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instrument log for 2 EMF-4 was changed to reflect-the new setpoint.

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Because the alarm was not anticipated, the licensee initiated actions to

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evaluate the root cause of the event and determine appropriate

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corrective action.

Discussions with various plant )ersonnel revealed

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that better coordination between affected plant wort groups and a

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possible procedure enhancement were needed during fuel transfer canal

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draining. This would provide for an increase in the alarm setpoint to

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accommodate the expected increase in background radiation levels in the

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area with the canal drained.

!

On March 25. the inspector performed a walkdown of the fuel handling

building for area familiarization.

During the walkdown the inspector

performed a housekeeping assessment with emphasis on the licensee's

'

adherence to foreign material exclusion (FME) requirements. ' The

>

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inspector found that miscellaneous items (e.g. safety belt, tool bag,

2

face shield. grease gun, and paper) i.ere on the transfer canal catwalk

area and had not been logged into the cleanliness logbook. The licensee

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subsequently issued PIP 2-C97-08/1 to document this NRC observation and

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address corrective actions.

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c. Conclusions

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The inspector concluded that actions by operations and RP personnel .in

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response to the radiation alarm in the fuel handling building were good.

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However, administrative controls over FME were not pro)erly im)1emented

by personnel working near the fel transfer canal in t1e fuel landling

t

building.

01.6 Unit 1 Pressurizer Block Valve Control Circuit Failure

a. Insaection Scone (71707. 61726. 62707)

'

On March 20, Unit 1 pressurizer Power 0)erated Relief Valve (PORV) block

valve INC-33A failed.to. stroke closed w1en the valve control switch was

placed in the closed position during surveillance testing. A similar

failure of this valve had occurred on August 10, 1995. The inspector

reviewed the licensee's immediate actions to comply with TS action

requirements and an associated operability evaluation. The inspector

also reviewed PIP documentation (1-C97-0781 and 1-C95-1204) and the

licensee's evaluation of the potential repeat failure.

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b. Observations and Findinos

The block valve is controlled with a three position control switch

(open/close/ override).

During the surveillance test the valve failed to

close when the "close" Josition was selected.

The licensee declared the

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valve inoperable and suasequently succeeded in closing the valve using

'

the " override" position.

The inspector verified that the licensee met

TS requirements after the valve was declared inoperable (TS 3.4.4.

.

Relief Valves).

Maintenance troubleshooting determined that the failure occurred in an

interlock portion of the block valve's control circuit. The interlock

uses position signals generated from stem mounted limit switches located

,

on the two other Unit 1 pressurizer PORV block valves. An operability

evaluation performed after troubleshooting efforts concluded that the

block valve was operable since it would remain capable of closing as

required using the " override" position.

The licensee's investigation of

.

the previous failure in 1995 found that a limit switch lever shaft had

broken.

The licensee has scheduled work orders to inspect the limit

switches and block valves during the next refueling outage and will

initiate further investigation if the same type of failure has occurred.

J

c. Conclusions

'

.

A Unit 1 pressurizer PORV block valve control circuit failure occurred

.

which is a potential repeat of a previous 1995 failure. The licensee

has planned appropriate actions to determine the cause of the control

'

circuit component failure when the components are accessible at the next

refueling outage.

08

Miscellaneous Operations Issues (92901. 92902)

08.1

(Closed) VIO 50-413.414/94-13-01: Failure To Follow Procedure NSD 703

4

And Station Directive 34.0.5 Requirements.

The inspectors reviewed the corrective actions identified by the

licensee for this violation in letters dated August 15. 1994, and August

8.1995, and verified that these actions were reasonable and complete.

The licensee's evaluation substantiated the violation and identified

'

approximately 600 comaonents which were provided with an identification

'

tag that identified t1e component number, but the tag did not include

the component's noun name as required by the site's procedures. The

inspectors performed a sample inspection of these components and

verified that the identification tag included both the component number

and noun name.

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08.2 (Closed) VIO 50-413/95-07-01: Inadequate Modification Procedure

Resulting in Loss of RHR.

TN/1/A/1331/00/01A. Procedure for the Implementation of NSM CN-11331.

Work Unit 01. did not receive adequate cross disciplinary review to

determine operational impact and scheduling to determine a safe plant

condition for implementation. The licensee's response dated April 28,

1995. stated that immediate actions were taken to revise the procedure

and stop work on modification implementation until all modification

packages were reviewed for similar errors. Additionally, the licensee

formed two self-assessment teams to determine root cause of the event.

The modification process was also revised to add new screening criteria

for critical modifications that require an independent Senior Reactor

1

0)erator review to determine safe plant conditions for implementation of

t1ese modifications.

The inspector reviewed corrective action

j

documentation (PIP 1-C95-0203) and verified that the licensee completed

these actions.

08.3 (Closed) VIO 50-413.414/95-07-02: Inadequate Valve Verification

Activities - Two Examples.

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Both examples of the violation involved personnel that failed to use

proper verification methods or independent verification of determining

.

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valve position or valve location.

The licensee's response dated April

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28, 1995, stated that procedure revisions and additional training was

l

provided for the plant staff that is involved in these verification

activities.

The ins)ector verified that Operations Management Procedure

2-33. Valve and Breacer Position Verification and Valve Operations, was

revised to provide guidance for verifying the position of deenergized

motor operated valves.

In addition, the licensee provided training to

establish worker skills in error reduction. The inspector concluded

,

that the licensee's corrective actions were appropriate.

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II. Mainwunce

M1

Conduct of Maintenance

1

M1.1 Unit 2 Outaae Maintenance Items

a. Insoection Scope (62707)

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The resident inspector monitored and inspected various work items during

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the Unit 2 E0C8 refueling outage.

Among these were: (1) a modification

to replace the 2A and 2B Emergency Diesel Generator (DG) battery

chargers: (2) inspection and preventive maintenance on the 2B DG: (3)

the inspection and reconditioning of valves in the Safety Injection (NI)

system: (4) the repair of Loose Parts Monitoring System Channel 17.

Steam Generator (SG) manway: (5) the inspection of the containment sump

recirculation valve 2NI-185B: and (6) inspection of the A and D Reactor

!

Coolant Pump (RCP) number 1 seals.

The inspector discussed the

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maintenance activities with the licensee, obtained copies of the work

packages and observed portions of the maintenance in progress.

b, Observations and Findings

l'

(1)

The Unit 2 125 Volt DC DG battery chargers were replaced under

station modification CN-21360.

The inspector reviewed the work

Jackages associated with TN/2/A/1360/00/02E, which governed the A

Xi battery charger replacement., and TN/2/A/1360/00/03E, which

governed the B DG battery charger replacement. The inspector

verified that an 8-hour load test on DG chargers- 2A and 28 a

polarity check, output voltage check and current check were

,

successfully completed before the battery chargers were installed.

Steel frames and grout pads were fabricated for the chargers. The

inspector also verified that provisions for maintaining electrical

i

separation, fabricating and installing electrical enclosures,

grounding cables, sealing the cable terminations, and using

crimping tools were included in the work packages.

Cable

installation was ')rocedurally controlled, and electrical

isolations and ca]le terminations were recorded in the associated

procedure. A charger capacity test was satisfactorily performed,

the battery was equalized and charged, batteries were inspected.

.

and the charger's high and low voltage relay alarms were

calibrated.

(2)

The inspection and maintenance plan for the 2B DG included

activities typically performed on a five-year interval. The

l

inspector observed portions of the activities in progress and

reviewed the work package and associated work orders,

The

licensee disassembled sections of the DG: cleaned the engine

block; replaced hoses: refurbished the engine-driven fuel oil

pump: inspected cams and rollers: inspected the jacket cooling

water pump drive gear: inspected strainers for the starting air

system; and inspected and refurbished a temperature regulating

valve in the DG jacket cooling water system.

(3)

Multiple check valves, suspected of leaking, were inspected during

l

the outage. The licensee inspected valve 2NI-171, Safety

Injection pumps to RCS loop C cold leg injection header check

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valve, and determined that the valve had low seating contact.

A

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minor modification was generated, and the disc was replaced with a

new disc of a different design that provided better seating

integrity.

Valve 2NI-175. RHR header A to RCS Loop C cold leg check valve,

was inspected: the valve was cycled, and the disc operated freely

,

without binding. The valve body and disc seats had no indication

H

of degradation.

The valve body and disc seats were cleaned, and a

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visual inspection revealed wide seat contact.

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Valve 2NI-176 RHR Header A to RCS Looi D cold leg check valve.

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showed no evidence of seat wear or leacage. The licensee cleaned

the seating surfaces and determined that they were finely. polished

.'

with no indication of degradation.

l

The disc in valve 2N!.-169. Safety Injection pumps to RCS lcop D

cold leg injection header, was replaced, and the valve body seat

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was lapped until good contact could be visually verified. A-small

!

defect was polished out of the valve bonnet.

The defect was

i

believed to have caused minor external leakage in December 1995

and had been seal welded at that time to stop the leakage.

The inspector did not identify any concerns associated with the NI

system check valve maintenance.

(4)

Unit 2 Loose Parts Monitoring System Channel 17. SG manway, was

repaired during a forced outage in December 1996. The channel had

been declared inoperable on January 2, 1996.

Subsequent

troubleshooting revealed that the failure of the channel

originated in the field. The licensee initiated a work request to

,

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repair the channel during an outage window, at which time the

necessary containment entry could be made. To notify the NRC that

Channel 17 of the Loose Parts Monitoring System was inoperable for

.

.

longer that 30 days, the licensee submitted a s)ecial report on

l

February 11, 1996, in accordance with Selected .icensee

Commitment Section 16.7-4, and TS 6.9.2.

The inspector discussed the repair with licensee personnel,

reviewed the associated work order. WO 96000758-01, and verified

,

that the channel )roblem had been corrected. The licensee had

determined that tie acoustic sensor' had an open _ connector at the-

female hard line connector point. The sensor was replaced and-

!

satisfactorily tested. The channel was returned to service on

December 16, 1997.

(5)

Prior to the last refueling outage-(2EOC7) the licensee determined

!

that containment sump recirculation valves NI-184A and NI-185B.

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double-disc gate valves, were susceptible to pressure locking.

!

During 2EOC7 the licensee im)lemented a station modification to

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install a bonnet vent on eac1 sump recirculation valve.

The

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bonnet vents provided a relief path from the valve body to the

residual heat removal (RHR) aump discharge line to preclude

pressurization in the valve Jody and subsequent wedging of the

i

valve discs into their respective seats. The bonnet vent valves

'

were intended to remain open during full )ower o)erations,

although they could be. closed to isolate RHR leacage past the

containment-side valve disc.

7

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During startup from the- previous refueling outage. 2EOC7.- the

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licensee determined that the containment-side seat of 2NI-185A was

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leaking.

Since the bonnet vent valve (2NI-488) bypassed the RHR

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suction-side disc a minor flow 3ath was created from the FWST.

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via the RHR suction header. to t1e containment sump.

To block the

!

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leakage, vent valve 2NI-488 was locked closed. A work order was

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generated to inspect and repair 2NI-185B during 2E0C8.

l

The licensee opened the valve to inspect the seatirig surfaces

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during the refueling outage: the inspection results were

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documented in PIP 2-C97-1066. At several locations around the

perimeter of the containment-side valve body seat, small

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semicircular indicat ons were visible. The containment-side disc

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seat had similar marks where the two surfaces had mated. The

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licensee could not determine why the pattern was present on the

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valve body seat, nor coula the valve vendor explain these

!

indications. The indications in the seat surfaces were the likely

!

!

cause of the seat leakage during the previous operating cycle.

)

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The licensee opted to leave the valve in its as found condition to

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avoid disturbing the seating of the RHR-side disc. The inspector

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questioned this decision, since they had been aware of the seat

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leakage during the preceding operating cycle and had ample time to

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plan for re) air during the refueling outage.

The licensee

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explained tlat extensive time and resources could be allocated to

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improve the containment-side di.;c seating, but that improvement

j.

could not be guaranteed and that the RHR-side disc seating

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integrity could be disturbed in the process.

i

To test valve seating integrity.of the containment-side disc. the

<

licensee applied 50 psig from the RHR pump side of the valve with

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vent valve 2NI-488 closed: no signs of leakage into the

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containment sump were identified.

Valve 2NI-488 was then' opened.

!

!

and leakage into the sump was observed.

Valve DI-488 was then

closed, and leakage into the sump was isolated oy the seating

l

integrity of the RHR-side disc and the bonnet vent valve. An

i

operability evaluation, documented in PIP 2-C97-1172. stated that

(1) valve 2NI-488 will be administratively controlled in the-

closed position, and (2) valve 2NI-185A is operable with 2NI-488

closed.

The inspector concluded that the o)erability evaluation

,

i

and actions taken to address seat leakage w1ile accounting for

!

pressure locking and thermal binding were appropriate.

(6)

The inspector observed RCP seal inspections and maintenance. The

!

ins)ector also reviewed the task completian comments associated

wit 1 work orders 96098973-01 and 96098974-01 (for 2A and 2D RCP

seal work, respectively). The 2D RCP numoer 1 seal was cleaned

and inspected verified to be in good condition. and reinstalled.

A chip was found in the outer edge of the 2A 'RCP number 1 seal

,

surface. A new set of stationary and running seals was installed,

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and the maintenance personnel verified that the seal moved freely

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up and down.

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The inspector noted that RCP seal work was conducted in confined

areas around the RCPs.

The work areas were difficult to access

and cramped.

In addition, cleanliness and lighting levels during

the maintenance activities were adversely affected by the cramped

working spaces.

c. Conclusions

The inspector concluded that, in general, outage-related maintenance

'

activities were ap]ropriately conducted.

Although multiple barriers to

minimizing the risc of human error during RCP seal maintenance were

noted, the ins)ector was unaware of any human performance problems

associated wit 1 the work.

M1.2 Unit 2 Nuclear Service Water Pumo Motor Reolacement

a. Insoection Scope (62707)

The inspector reviewed the licensee's resolution to elevated vibration

levels associated with the 2B nuclear service water pump / motor assembly.

The 2B nuclear service water pump has experienced intermittent periods

of elevated vibration since 1994.

During the inspection period, the

licensee identified problems with the condition of the s

service water replacement motor stored in the warehouse. pare nuclear

.

Accordingly,

the inspector reviewed the results of previous licensee assessments of

spare motor storage practices, previous motor failures, and an ongoing

licensee assessment of maintenance and storage practices for spare

motors.

b. Observations and Findinas

The 28 Nuclear Service Water pump is a smooth running pump with normally

low measured vibration levels.

In 1994 and 1995 the pump / motor assembly

3eriodically experienced an increase in vibration relative to its past

)aseline performance and also relative to the other nuclear service

water pumps. The relative increase in vibration levels caused the pump

to enter Alert levels although it continued to remain in the smooth

running range,

As a result of this experience, the licensee performed

extensive inspection of this pump and motor during the current refueling

outage.

Internal inspection of the pump showed no damage or

degradation.

Vibration measurements made during an uncoupled run of the

motor indicated that the source of elevated vibrations was confined to

the motor. Based on additional analysis of vibration dr.ta performed by

'

Electrical System Support (ESS) personnel, the licensee determined that

an internal rub was occurring in the motor and elected to replace it.

The spare nuclear service water pump motor developed severe oil leaks

from its lower bearing during initial check out runs performed in the

'

motor test shop prior to its installation.

Inspections of the saare

motor internals performed by an offsite vendor determined that tie lower

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bearing surfaces were partially melted due to rubbing or inadequate

lubrication.

Additional testing revealed more problems and the spare

motor was considered unacceptable for use and required extensive rework

and repair.

The licensee subsequently performed internal inspections of

the installed nuclear service water pump motor and determined the cause

of the eleyated vibration resulted from mechanical looseness in the

,

upper bearing components. An off center condition in the lower bearing

housing was also discovered.

The licensee corrected these

adeficiencies, which eliminated the elevated vibration characteristic as

measured in uncoupled runs and coupled inservice pump tests.

In 1996, a residual heat removal pump motor failed soon after functional

testing. The licensee determined that poor storage conditions may have

contributed to this failure (refer to NRC Inspection Report 96-13). The

licensee has recently performed two assessments of motor storage and

handling practices and identified several findings and recommendations.

Inspector Followup Item (IFI) 50-413.414/97-07-03, Review Corrective

Actions For Storage and Handling Assessment Findings, is identified to

verify that the licensee has completed corrective actions resulting from

the followirig assessments:

(1) Assessment Report CTS-09-96. Electric

Motor P.M. - 12/2/96; and (2) Assessment Report SA-97-61(CN)(SRG),

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Assessment of Warehouse Material Condition - 4/23-28/97.

.

c. Conclusions

The licensee's resolution of long-standing elevated vibration levels

,

associated with the Unit 2B nuclear service water pump motor was very

good.

Deficiencies identified with a spare nuclear service water pump

motor, a previous motor failure, and findings identified by licensee

assessment of warehouse storage and handling 3ractices raised questions

about control and storage of spare motors. T1e issue is identified as

an Inspector Followup Item and will be reviewed during a future

inspection.

M2

Maintenance and Material Condition of Facilities and Equipment

M2.1 Observation of Unit 2 Inservice Insoection Work Activities

a. Insoection Scope (73753)

The present Unit 2 E0C8 refueling outage was the first outage, of the

first inspection period, of the second inservice inspection interval.

The applicable code for Unit 2, for the second inservice inspection

interval was the American Society of Mechanical Engineers (ASME) Code

l

Section XI, 1989 Edition, no Addenda. The inspector reviewed

l

documentation and observed ultrasonic, magnetic ) article, and liquid

l

penetrant examination activities to determined w1 ether the inservice

~

inspection (ISI) activities were performed in accordance with Technical

specifications (TS), the applicable ASME Code, and/or requirements

imposed by NRC/ industry initiatives.

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Enclosure 2

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b. Observations and Findinos

The inspector reviewed the ISI outage examination plan and certification

records for all NDE examiners aerforming ISI examinations this outage.

l

The following procedures, whic1 were used in the examination activities

observed by the inspector, were reviewed for technical content:

NDE-600. " Ultrasonic Examination of Similar Metal Welds in Wrought

Ferritic and Austenitic Piping." Revision 9

NDE-610. " Ultrasonic Examination of Dissimilar Metal Welds and

.

Cast Austenitic Welds Using Refracted Longitudinal and Shear

i

Waves." Revision 4

NDE-660 " Ultrasonic Examination of Reactor Pressure Vessel Head

.

to Flange Welds." Revision 2

NDE-25. " Magnetic Particle Examination." Revision 17

.

NDE-35. " Liquid Penetrant Examination." Revision 16

.

Examinations of the following components were also observed by the

inspector to determine if the examination procedures were followed,

.

whether examination personnel were knowledgeable of the examination

method and operation of the test equipment, and if the examination

results and evaluation of the results were recorded as specified in the

ISI program and NDE procedures.

. Welds Examined

NDE Method Used

2RPV-101-101***

Ultrasonic Examination

2RPV-102-101***

Ultrasonic Examination

2CA-59-8

Ultrasonic Examination

2CA-59-11

Ultrasonic Examination

2RPV-101-101

Magnetic Particle Examination

2CA-59-8

Magnetic Particle Examination

2CA-59-11

Magnetic Particle Examination

2NV-242-3

Liquid Penetrant Examination

2NV-242-4

Liquid Penetrant Examination

2NV-242-10

Liquid Penetrant Examination

2NV-242-11

Liquid Penetrant Examination

2RPV-W80-101SE

Liquid Penetrant Examination

i

2RPV-W81-101SE

Liquid Penetrant Examination

2RPV-W82-101SE

Liquid Penetrant Examination

2RPV-W79-101SE

Liquid Penetrant Examination

2RPV-W80-101

Liquid Penetrant Examination

,

2RPV-W81-101

Liquid Penetrant Examination

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2RPV-W82-101

Liquid Penetrant Examination

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2RPV-W79-101

Liquid Penetrant Examination

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• • • • Note: Only portions of the 0 degree and 45 degree scans for these

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reactor vessel head welds were observed due to radiation dose

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limitations.

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c. Conclusion

NDE personnel certifications records, weld examinations, and NDE

examination procedures were in accordance with Code requirements.

M2.2 Observation of Unit 2 Steam Generator Eddy Current Data Acouisition

Activities

a. Insoection Scooe (73753)

The inspector reviewed documentation and observed eddy current data

l

acquisition activities to dstermine whether these activities were

,

i

performed in accordance with Technical Specifications (TS), the 1989

j

Edition of Section XI to the ASME Code, and requirements imposed by

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NRC/ industry initiatives.

,

b. Observations and Findinas

,

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l.

The licensee was performing bobbin coil eddy current examinations of 62%

of the tubes in all four steam generators for Unit 2.

In addition, a

25% sample of the hot leg tube sheet transitions in each steam generator

'

will be examined using a motor rotating pancake coil (MRPC). At the

time of this ins)ection the licensee had just started the examination

activities and t1e data acquired was being sent directly to the McGuire

Nuclear Plant for analysis.

Therefore, the inspector's examination of

'

l

these activities was limited to review of the outage eddy current

'

inspection plan, examiner and equipment certifications, and review of

examination procedures No. NDE-707 Revision 3, "Multifrequency Eddy

l

Current Examination of Non-Ferrous Tubing. Sleeves and Plugs Using a

Motorized Rotating Coil Probe", and No. NDE-701 Revision 3.

"Multifrequency Eddy Current Examination of Steam Generator Tubing at

McGuire. Catawba and Oconee Nuclear Stations and observation of the eddy

.

current data acquisition process,

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c. Conclusion

Review of the eddy current outage plan, equipment setup and acquisition

procedures, personnel and equipment certifications, and observation of

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data acquisition activities revealed that required documentation was

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available and complete. and data acquisition personnel were

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knowledgeable of the eddy current examination process.

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Enclosure 2

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M2.3 Unit 2 Flow Accelerated Corrosion (FAC) Proaram

a. Insoection Scooe (49001)

The inspector held discussions with the licensee's erosion / corrosion

!

engineers to determine the scope of FAC examinations scheduled for this

outage: the condition of the plant piping as revealed by inspection: the

extent of pipe replacement recuired: and whether proper examination

expansion was performed when cefective components were found.

b. Observations and Findinas

i

The licensee's FAC program for Unit 2 was based on the Electric Power

Research Institute's (EPRI) Document No. NSAC-202L. " Recommendation for

an Effective Flow Accelerated Corrosion Program." Revision 1.

In

addition. EPRI's CHEC Works Computer Codes were used, as well as

,

'

portions of the licensee's prev'ous program for erosion / corrosion to

identify components which will require examination.

Initially, a sample

of 55 components were scheduled for ultrasonic examination during the

EOC-8 refueling outage.

The sample also included the entire component.

upstream and downstream of the initial component. The licensee planned

to replace six components without further examination, based on

'

corrosion growth rates confirmed last outage.

The examination of

.

components for FAC this outage were approximately 40% complete when

audited by the inspector. As a result of these examinations, five

additional components will be replaced this outage.

The inspector

verified that expansion ins)ections.were correctly performed as a result

of the components found to 3e unacceptable based on inspections

performed this outage.

The inspector also inquired as to why the

initial inspection sample was so small.

The licensee stated that

smaller samples with a high volume of essential components. based on

tracking and trending was now possible on Unit 2 for the following

reasons:

Significant previous replacements of components with

.

erosion / corrosion resistant materials.

Changes in secondary chemistry control have reduced wear rates

.

significantly.

The entire upstream and downstream components from a sample

.

selected for inspection are also examined.

'

Unit 2 was designed with heater drains and moisturizer separator

.

reheater drains which have erosion / corrosion resistant materials

downstream of all control valves.

FAC program maturity.

.

The inspector agreed with the licensee's reasoning.

Enclosure 2

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c. Conclusion

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The licensee has implemented an effective program for the detection of

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flow accelerated corrosion in components.

This program was based on

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recommendations found in recognized industry standards.

M7

Quality Assurance In Maintenance Activities

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M7.1 Maintenance Self Assessment Prooram

a. Insoection Scone (62707. 40500)

The inspector reviewed the status of maintenance and work control self-

assessment programs.

The inspection included review of NSD 607. Self-

Assessments; maintenance and work control annual assessment plans for

1996 and 1997: selected self-assessment reports; and maintenance / work

l

control performance indicators,

b

Observations and Findinas

The licensee's self-assessment program consisted of two types of self-

assessments, routine and non-routine.

Routine assessments were

'.

performed on a quarterly or semi-annual basis and included topics such

j

as PIPS, Job Observations. Rework. Material Condition / Housekeeping. Work

Order Quality. Budget. Radiation Dose / Contamination. Planning, and Work

Control Process.

Non-routine assessments were performed when the need

i

was apparent to management to assess a certain area or function. Some

1

examples were Procedure Use and Adherence. Environmental Compliance.

Pre-job Briefings. Control of Vendors, and Work Task Skills.

Corrective

actions from the self-assessments were tracked for completion through

PIPS.

The inspector noted that the self-assessments that were reviewed

effectively identified areas for improvement, and appropriate corrective

'

actions were recommended and entered in the Problem Investigation

'

Process for resolution.

Of the routine assessments reviewed the

inspector considered the quarterly assessment of Job Observation Trends,

initiated in 1997, to be an effective use of the data generated by first

line supervisor observations.

Since the initiation of the Maintenance / Work Control Self-Assessment

Programs in mid and late 1995. performance indicators such as work order

backlog, schedule efficiency, and control board indication problems all

showed improving trends.

c.

Conclusion

'

Based on the inspection described above. the inspector concluded that

the maintenance / work control self-assessment programs effectively

identified areas for improvement and appropriate corrective actions.

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Enclosure 2

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The self-assessments apparently contributed to improvemert. in the

performance of the Maintenance and Work Control organizations.

III. Enaineering

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Conduct of Engineering

El.1 Unit 2 Control Rod Tio Crackina

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a. Insoection Scoce (61726. 37551)

During routine outage related examinations of Unit 2 control rod .

assemblies, the licensee identified a higher than expected number of

,

!

control rods with tip cracking. The inspector reviewed the licensee's

L

testing procedure, results of the examinations, and corrective actions

_

for test failures,

b. Observations and Findinos

l

Industry experience has shown that control rods develop tip cracking as

!

a result of cladding interaction caused by swelling of the absorber

l

material inside this portion of the rods. . Tip cracking and other

potential control rod defects such as mechanical wearing are monitored

.

every refueling outage by the licensee using procedure PT/0/A/4150/26.

Rod Control Cluster Assembly (RCCA) Ultrasonic / Eddy Current Testing.

,

The inspector. discussed the results of the testing with reactor

'

engineering personnel.

The inspector observed that twenty.six control

rod assemblies were found with indications of tip cracking.

This

exceeded the expected number of twelve control rod assemblies aredicted

-

,

to have tip cracks

The licensee ordered additional rod assem) lies

'

fabricated by the vendor and replaced each control rod assembly that had-

evidence of tip cracking.

The inspector verified by reviewing control

rod assembly deficiency evaluations that the twenty six assemblies were

replaced.

'

c. Conclusions

The licensee's actions to replace all control rod assemblies that had

evidence of tip cracking were appropriate.

E2

Engineering Support of Facilities and Equipment

E2.1 Review of Tentative Repair Activities for the Manway Cover on the Unit 2

Pressurizer

a. Insoection Scone (62001)

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The Catawba Unit 2 pressurizer manway cover experienced a leak during

i

the end of cycle 8 shutdown for refueling.

To repair the leak, the

licensee elected to use an alternate method of repair consisting of a

1

Enclosure 2

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welded diaphragm, in lieu of a flexitallic gasket.

The licensee also

planned to replace the bolts and nuts on the manway cover with studs and

nuts.

Another issue addressed in this modification was the inspection

and clean-up of the boric acid which had leaked from the flange of the

manway behind the insulation on the pressurizer.

The inspector

!

reviewed this modification to ensure that documentation required for

this repair was available, and that inspection and cleanup of the boric

!

,

l

acid crystals behind the pressurizer was properly addressed.

1

b. Observations and Findinas

In 1987, the licensee experienced several stuck bolts on the Unit 1

'

pressurizer manway. At that time the licensee used the alternate method

of repair delineated in the Westinghouse Technical Manual for the

pressurizer.

This repair consisted of using a welded diaphragm, in lieu

of a flexitallic gasket.

In addition, the licensee substituted studs

for the bolts used in the manway flange. At that time the licensee also

l

realized that this same modification may some day be required for Unit

2. so 10 CFR 50.59 evaluations for the alternate modification method and

calculations for the stress analysis of the studs and nuts were

conducted for each Unit in 1987.

The inspector reviewed this

documentation as well as the Westinghouse Pressurizer Technical Manual

and drawings for this alternate method of repair. The information

,

.

reviewed was found to be satisfactory.

The inspector was initially concerned with the licensee's tentative

plans to remove insulation only from the top and bottom of the

pressurizer in order to flush the boric acid crystals from behind the

insulation, and to use technical justification based on boric acid

corrosion rates documented in an EPRI document (TR-102748S) for

acceptance of any possible damage to the pressurizer.

The inspector's

concern was based on the fact that the corrosion rates given in the EPRI

document differed significantly from the corrosion rates established by

Westinghouse under similar conditions and documented in NRC Generic Letter 88-05 " Boric Acid Corrosion of Carbon Steel Reactor Pressure

Boundary Components in Pressurized Water Reactor Plants".

In addition,

the inspector did not believe that the plan to use technical

justification met the intent of Catawba's Nuclear Site Directive 3.3.16.

which stated. "When there is evidence that boric acid has run under

l

insulation remove enough insulation during the inspection 3rocess to

assure all boric acid has been identified and evaluated. S1ould the

investigation reveal no damage to the contaminated components, the area

is to be cleaned until free of visible borori crystals." During

discussions held with senior licensee management, the inspector was

informed that the plans for boric acid damage examination and flushing

on the pressurizer which were identified to the inspector were very

,

' tentative and only one of many options being considered. The inspector

l

was also informed that a meeting on this issue was planned for following

i

week and the decisions reached in this meeting would be forwarded to the

)

inspector for review.

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Enclosure 2

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On April 9.1997, the inspector was informed of the licensee plans for

inspection and cleaning of boric acid on the pressurizer.

These plans

would remove three additional sections of insulation and would allow

visual inspection to be performed in spot locations from the top to the

bottom of the pressurizer. The only disadvantage was visual inspection

could only be performed on the lower side of each of the sup) ort rings

except the top support ring. The licensee proposed that teclnical

l

justification be used for the acceptance of the up)er portion of each

support ring using the EPRI criteria which Westinglouse agreed was

a)propriate for this corrosion wear application.

These actions resolved

,

!

t1e inspector's concerns.

l

The licensee )lanned to flush the pressurizer shell with hot water for

l

four to five lours in an attempt to dissolve the crystals and remove

them from the carbon steel surface. To verify that the flushing process

was effective in removing the boron, the licensee planned to collect

water samples hourly at the base of the pressurizer and obtain data on

boron concentrations, expecting the concentrations to decrease over

l

time. The inspector questioned the confidence level of the validation

l

plan as a function of sampling frequency, and asked if an hourly sample

would provide sufficient data to verify that boron concentrations were

indeed decreasing over time. The licensee agreed that more frequent

.

sampling would yield a more robust conclusion and planned to sample the

flushing water every half hour. The ins)ector reviewed the results of

i

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the pressurizer flushing, documented in )IP 2-C97-0952. and concluded

that the flushing plan was effective in removing any dried boric acid

!

from the pressurizer shell.

c. Conclusions

The inspector concluded that documentation for the modification of the

Unit 2 pressurizer manway was satisfactory and engineering

considerations for modification, inspection, and cleaning of the

pressurizer shell were very good.

Results of the boric acid cleanup

indicated that the plan had been effective.

E2.2 Desian Control

a. Ir;soection Scope (37550)

r

The inspector reviewed modifications being implemented during the Unit 2

outage.

A)plicable regulatory requirements included Regulatory Guide 1.64 and AiSI N45.2.11-1974. Quality Assurance Requirements for the

Design of Nuclear Power Plants 10 CFR 50.59,10 CFR 50 Appendix B the

.

licensee's Quality Assurance Topica'l Report (Duke-1-A), and associated

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Enclosure 2

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design control implementing procedures.

The following modifications

were reviewed:

VN 8303H

Replacement of Limitorque Motors on 2NI-54A. 2NI-65B.

.

2NI-76A. and 2NI-183B

CN 21377

Modify Safety Injection (SI) Logic to Delete Low Stear

.

Pressure Input

CN 21375

Upgrade Allowable Temperature for Some Auxiliary Feed

.

Water (CA) Piping.

b. Observations and Findinas

The specified post modification testing requirements on the above

modifications adequately verified the design function of the modified

equipment.

Implementation of the SI signal deletion (CN 21377) resulted

in damage to six process cards in the Solid State Protection System

cabinet due to short circuits experienced during wiring terminations.

The damaged cards were identified during post modification testing.

Appropriate actions were initiated to replace the damaged cards and

,

verify the integrity of the remaining installed cards.

'

Replacement Motor Operated Valve Limitorcue motors (VN 8303H) were set

'

up using the VOTES testing procedures anc implementing the applicable GL 89-10 requirements.

The modification was required because tie original

size motors for the NI valves were not available.

Cracks were found on

the motor shafts' key way of the installed motors.

Post modification

verification was accomplished by Quality Control inspections for the CA

piping support modifications to upgrade the allowable piping temperature

(CN 21375).

The 50.59 evaluations for the modifications were adequate. A regulatory

issue was pending on the 50.59 evaluation for the CA piping upgrade (NRC

Inspection Report 50-413.414/96-03).

The SI logic signal deletion

safety evaluation was documented in licensing amendments 158 and 150.

c. Conclusion

Regulatory design control requirements were appropriately implemented

for the Unit 2 outage modifications reviewed during this inspection.

E4

Engineering Staff Knowledge and Performance

E4.1 Identification and Correction of Eauioment Problems

a. Insoection Stone (37550)

The inspector reviewed the licensee's actions related to the

identification and resolution of MOV limitorque motor shaft cracking.

Enclosure 2

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Applicable regulatory requirements included 10 CFR 50 Appendix B and the

licensee's Topical Quality Assurance Program.

b. Observations and Findinas

industry experience reports in 1995 and late 1996 noted examples of

<

motor shaft key way cracking in large high speed limitorque MOV motors.

<

The reports generally indicated the problem occurred in 3600 rpm motors

sized at 80 ft-lbs and larger. There were ten applications identified

,

at Catawba which included the four cold leg accumulator isolation valves

)

and the NI-183 valves on each unit. The licensee implemented a motor

shaft inspection into the GL 89-10 program in 1996.

No cracks were

identified on the Unit 1 valves inspected during the previous outage.

'

There were cracks identified on three Unit 2 valves inspected during the

current outage.

Replacement motors of the original sizes were

unavailable therefore a minor modification was implemented to change

the motor sizes.

The original 175 ft-lb motor on 2NI-183B was replaced

with a 150 ft-lb motor from Cold Leg Accumulator valve 2NI-54.

The

original 150 ft-lb motors on 2NI-54A. 2NI-65B and 2NI-76A were replaced

with 80 ft-lb. 80 ft-lb. and 100 ft-lb motors, respectively.

Valve

motor torque switch settings and parameters were revised to meet the

recuirements of the GL 89-10 program and motor / valve application.

Adcitionally, the associated motor control center overload heaters were

.

replaced on each valve to be consistent with the motor protection

requirements.

c. Conclusion

4

The identification and correction of MOV shaft key way cracking in Unit

2 safety injection system valves was a good example of engineering

identification and resolution of equipment problems.

Industry operating

experience was appropriately incorporated into licensee activities and

effectively eliminated a potential safety-related equipment failure

'

mechanism.

E8

Hiscellaneous Engineering Issues (92903)

E8.1 .(flosed) VIO 50-413.414/96-13-04: Inadequate Design Controls - Two

Examples

Example 1-Selection of Main Steam Isolation Valve (MSIV) Solenoid

Valves:

This item identified a discrepancy where the nameplate design

rating of MSIV solenoid valves was less than the maximum design pressure

of the instrument air system. The ins)ector reviewed the licensee's

response dated November 6. 1996.

The Jnit 1 solenoid valves were

replaced with aapropriate valves prior to identification of the

discrepancy.

T1e valve manufacturer certified by letter that the

l

existing Unit 2 solenoid valves were acceptable until replacement at the

i

next refueling outage. The inspector verified that the Unit 2 solenoid

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valves were replaced with upgraded valves during this refueling outage

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Enclosure 2

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(MW0s 96070278. 96070289. 96070280. 96070287) and testing of the

replacement solenoid valves was performed satisfactorily (PT

2/A/4200/09. Engineered Safety Feature Actuation Periodic Test).

Examole 2-Standby Shutdown System (SSS) Make-uo Pumn . Calculation - This

item identified calculation design input errors '

'd to the system

conditions and pulsation damper which were useo

.wify the Net

4

Positive Suction Head (NPSH) for the SSS make-up pum). The licensee's

November 6. 1996, response to the violation stated tie design inputs for

the SSS make-up pum) sizing calculation and the damper design would be

evaluated and opera]ility for the Unit 1 and 2 pumps verified. The

inspector reviewed the licensee's completed corrective actions and

verified that the in)ut errors were resolved. Additionally, the actions

to assure pump opera]ility were completed.

E8.2 (Closed) DEV 50-413.414/92-01-03.: Breaker Coordination

This deviation was closed based on NRC Inspection Report 50-413.414/96-

19.

E8.3 (Closed) VIO 50-413.414/96-12-03: Inadequate Design Controls For

Ensuring Containment Crane Wall And Floor Drain Screens Implemented

Design Requirements.

.

This item identified containment crane wall penetrations and floor drain

i

screens that did not implement design requirements developed to preclude

transport of debris to the Emergency Core Cooling System sum) screens.

The licensee's October 29, 1996. violation response stated tlat the

crane wall Jenetrations were filled with cualified foam to preclude any

flow throug1 them and modifications were ceveloped correct the screen

size of the floor drain screens.

The inspector reviewed the licensee's

j

completed corrective actions, including minor modifications (CNCE-8116.

)

8139. 8186) and drawing revisions (CN-1070-5. rev. 14).

The inspector

also performed a walkdown of the unit 2 containment building and

verified that the modifications were installed.

IV. Plant Support

R1

Radiological Protection and Chemistry Controls

R1.1 Tour of Ridioloaical Protected Areas

a. Insoection Scooe (83750. 71750)

The inspectors reviewed implementation of selected elements of the

licensee's radiation protection program as required by 10 Code of

Federal Regulations (CFR) Parts 20.1201. 1208, 1501. 1502. 1601, 1703.

i

1802. 1902, and 1904.

The review included observation of radiological

protection activities, including personnel monitoring controls, control

Enclosure 2

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of ra'dioactive material, radiological postings, and radiation area /high

radiation area controls,

b. Observations and Findinas

During tours of the Auxiliary Building and radioactive waste

!

storage /handhng facilities. the inspector reviewed survey data and

'

performed selected independent radiation and contamination surveys of

radioactive material storage areas.

Observations and survey results

determined-the licensee was effectively controlling and storing

radioactive material.

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~The inspector reviewed records for selected employees who had recently

.

!

worn respiratory protection equipment. The inspector verified that for -

<

the records reviewed, each worker had successfully completed respiratory

l

protection training, was medically qualified, and was fit-tested for the

l

specific respirator type used in accordance with licensee procedural

!

requirements. All respiratory protection equipment observed during

facility tours was being maintained in a satisfactory condition.

The

-

licensee had continued to implement engineering controls for respirator

reductions.

During plant tours, the inspector observed that Extra High Radiation

.

,

Areas were locked as required by licensee procedures. The inspector

l

also observed dosimetry controls for these areas were also established

in Radiation Work Permits (RWPs) as required by licensee procedures.

E

t

The licensee's records indicated that the licensee was maintaining

2

approximately 145,000 square feet (ft ) of floor space as a

P

Radiologically Controlled Area (RCA).

Records also showed that the

licensee maintained approximately 800-1000 ft2 (or less than 1 percent)

of the RCA as contaminated area during non-outage periods.

During the-

current outage period, the licensee was maintaining approximately 1200

'

2

.

ft as contaminated area.

The inspectors reviewed Personnel Contamination Event (PCE) reports

t

prepared by the licensee to track, trend, determine root cause, and any

necessary followup action. Approximately 49 PCEs had occurred in 1997:

of which, approximately 38 PCEs had occurred during the current Unit 2

outage.

The inspectors reviewed PCE log sheets for the past three years

and noted PCEs continued to trend downward. The licensee attributed

this reduction to several planned contamination control initiatives,

.uch as: increased followup with workers following contamination events:

,

reduction of contaminated areas: and reductions in radioactive waste.

!

During facility tours. the inspectors observed that survey

instrumentation and continuous air monitors observed in use within the

-

!

RCA were operable and currently calibrated. The inspectors observed a

survey instrument (portable frisker) in the Unit 2 Reactor Containment

(

Building which had not been source checked as required by licensee

Enclosure 2

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Procedure HP/0/B1003/22. Paragraph 4.9.

The licensee conducted an

-

immediate investigation and located another frisker in the Unit 2

Reactor Containment Building which was available for use in the area

that had not been source checked.

The licensee removed both instruments

from the work area and performed a source check of the instruments to

verify operability.

Both instruments source checked satisfactorily.

The licensee also initiated a Problem Investigation Process (PIP) report

to investigate the problem. The inspectors informed the licensee that

using survey instruments that had not been source checked was a

violation of licensee procedure and TS 6.8.1. Procedures and Programs.

However, based on the licensee's immediate corrective actions and the

safety significance of the circumstances. this licensee identified and

corrected violation is being treated as a Non-Cited Violation consistent

,

with Section VII.B.1 of the NRC Enforcement Policy.

NCV 50-413.414/97-

07-04:

Failure to Source Check Survey Instruments as Required by

Licensee Procedures.

The ins)ectors reviewed controls for entering the RCA and performing

work. T1ese controls included the use of RWPs to be reviewed and

understood by workers prior to entering the RCA.

The inspectors

reviewed selected RWPs for adequacy of the radiation protection

requirements based on work scope, location, and conditions.

For the

RWPs reviewed, the inspectors noted that appropriate protective

.

clothing and dosimetry were required.

During tours of the plant, the

inspectors observed the adherence of plant workers to the RWP

requirements.

The inspectors also verified the licensee was effectively

managing controls for any declared pregnant women in regards to

,.

embryo / fetus doses as required by 10 CFR 20.1208. The licensee was

holding current personnel dosimetry accreditation from the National

,

Voluntary Laboratory Accreditation Program (NVLAP) as required by 10 CFR 20.1501.

c. Conclusions

Based on observations and procedural reviews, the inspectors determined

the licensee was effectively maintaining controls for personnel

monitoring. respiratory protection, control of radioactive material,

radiological postings, and radiation area /high radiation area controls

as required by 10 CFR Part 20.

One NCV was identified for failure to

source check survey instruments as required by licensee procedure.

R1.2 Occuoational Radiation Exoosure Control Proaram

l

a. Insoection Scooe (83750)

The inspectors reviewed the licensee's implementation of 10 CFR

'

20.1101(b) which requires that the licensee shall use, to the extent

practicable, procedures and engineering controls based upon sound

radiation protection principles to achieve occupational doses and doses

,

Enclosure 2

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to members of the public that are As Low As Reasonably Achievable

(ALARA).

b. Observations and Findinas

The inspectors review of the licensee's ALARA program determined that

the licensee had established an annual exposure goal of approximately

286 person-rem, which included the Unit 2 outage goal of 132 person-rem

and Jart of a planned Unit 1 outage to begin late in 1997.

At the time

of t1e inspection the licensee was tracking approximately 9 person-rem

below previous estimates. The licensee had continued to track and trend

outage exposures for purposes of future outage preplanning and it was

determined that exposures continue to trend downward based on ALARA

initiatives.

Several ALARA initiatives reviewed during the inspection

that attributed to lower personnel exposures included: improved

scheduling to optimize the use of shielding and reduce worker congestion

in areas; replacement of stellite valve components with components made

from low to no stellite materials: a successful crudburst during the

Unit 2 shutdown which reduced Unit 2 dose rates by approximately 15

percent lower than previous Unit 2 outages; increased use of shielding:

and a improved method for workers to initiate ALARA suggestions.

During tours of the facility the inspectors also observed Radiation

.

protection (RP) technicians controlling access to work areas to minimize

Personnel exposure and briefing workers in the work areas as

radiological conditions changed.

The inspectors also observed personnel

beir.g briefed on ALARA considerations during specific briefings

conducted to address RWP requirements.

c. Conclusions

,

Based on licensee planning efforts to reduce source term and the

licensee's efforts to achieve established exposure goals which were

challenging, the inspectors determined the licensee was maintaining

programs for controlling exposures ALARA and continued to be effective

j

in controlling overall collective dose.

R5

Staff Training and Qualification in Radiation Protection

j

a. Insoection Scoce (83750 and 84750)

,

Training was reviewed to determine whether radiation protection

technicians had been instructed in radiation procedures to minimize

,

radiation exposures and control radioactive material as required by 10

'

CFR 19.12.

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b. Observations and Findinas

The inspectors reviewed training requirements for RP technicians and the

4

continuing training curriculum for the period of January 1,1996.

Enclosure 2

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through April 5, 1997, which included industry events and topics to

minimize radiation exposure.

The inspectors also interviewed RP

personnel and observed work practices to determine the effectiveness of

continuing training.

i

c. Conclusions

Based on the training activities reviewed, the inspectors determined

radiation protection technicians were receiving an appropriate level of

training to perform routine work activities involving radiation and/or

radioactive material.

R7

Quality Assurance in Radiation Protection and Chemistry

a. Insoection Scooe (83750)

10 CFR 20.1101 requires that the licensee periodically review the RP

program content and implementation at least annually.

Licensee periodic

reviews of the RP program were reviewed to determine the edequacy of

identification and corrective actions.

'

b. Observations and Findinas

.

By reviewing RP procedures, observing work, reviewing industry

documentation, and performing plant walkdowns to include surveillance of

work areas by supervisors and technicians during normal work coverage,

the inspector determined that Quality Assurance audits and Self-

Assessment efforts in the area of RP were accomplished.

Documentation

of problems by licensee representatives was included in Quality

Assurance Audits and Self-Assessment Reports.

Corrective actions were

included in the licensee's Problem Investigative Process and were being

completed in a timely manner.

During the inspection, the inspector reviewed the licensee's self-

assessment processes for evaluating an event in which unsuspected resin

was found in the 2B containment spray heat exchanger on April 10, 1997.

The resin was analyzed by gamma isotopic analysis and determined to be

mixed bed resin.

The licensee began immediate followup actions to

determine the extent of a Jotential spread of resins into plant systems

that could be affected.

T1e licensee formed a Failure Investigation

Process Team to determine the source of the resin and to develop a

recovery plan.

The team was divided into key areas to identify the root

cause, evaluate sluicing operations and alignments that could affect the

potential spread of resin, identify potentially degraded ecuipment.

identify components that could be potentially impacted, anc develop a

cleanup plan.

The licensee's investigation revealed that the probable

,

'

source of the resin was a potential tear in a screenwire used to contain

!

mixed resin inside of an ion exchanger. The ion exchanger is used

'

during spent fuel pool cleanup evolutions. The licensee determined that

i

only a small amount of resin was present in the containment spray

Enclosure 2

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system, and cleanup actions were initiated to remove the resin that had

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been identified. A total of approximately 200 - 250 milliliters of

o

resin was removed from the spent fuel pool purification and containment

!

spray systems.

The licensee initiated actions to clean out ion

6

<

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exchanger post filter housings whenever filters are changed to help

i

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eliminate the potential for the small amounts of resin from entering

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into the containment s] ray system. The licensee's engineering

'

evaluation concluded tlat there were no operability concerns resulting

.

from this event, and the inspector concluded that the licensee's review

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for operability was logical.

The inspector determined that the licensee

!

was aggressive in performing a root cause analysis of the resin event.

!

!

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and the licensee's assessments of the event were good.

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c. Conclusions

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!

The inspector determined the licensee was performing Quality Assurance

!

Audits and effectively assessing the radiation protection program as

required by 10 CFR Part 20.1101. The inspector also determined the

licensee was completing corrective actions in a timely manner.

l

F2

Status of Fire Protection Facilities and Equipment

'

f

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F2.1 00erability of Fire Protection Facilities and Ecuioment

a. Inspection Scoce (64704)

i

i

The inspectors reviewed open corrective maintenance work orders on fire

'

protection components and operation's list of out-of-service fire

protection equipment to assess the licensee's performance for returning

degraded fire protection components to service.

In addition, walkdown

!

inspections were made to assess the material condition of the plant's

l

fire protection systems, equipment, features and fire brigade equipment.

t

b.

Observations and Findinos

!

Maintenance and Ooerability of Fire Protection Ecuioment and Comoonents

l

As of March 31, 1997, there were approximately 22 fire protection

)

related work requests-in which the work had not been completed. Most of

these involved minor corrective maintenance work items and did not

' i'

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affect the operability of the components.

All of these work requests.

i

except for work request item 910001140, were initiated in 1997 or late

1996.

Item 910001140 involved repairs to the fire pump suction screens

which were to be corrected by minor modification CE-3197. This work had

!

been completed except for the proper reinstallation of the suction

screens.

As of the date of this inspection, these screens had not been

,

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fully installed to the botsom of the screen frame.

This resulted in an

!

estimated area approximately 78x11 feet in size near the bottom of the

pump suction pit not being filtered.

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Two of the three fire pumps take suction from the fire protection

suction pit.

This suction pit was provided with two suction screens

with 3/8-inch mesh installed to filter and prevent raw lake water trash

and debris from entering the suction pit for the pumps and clogging the

suction inlets for the two pumps.

The third fire pump takes suction

from the suction pit for the low pressure service water pumps.

The fire pump suction screens were found degraded in late 1990 and

repairs were initiated in 1991.

Following these repairs. the suction

'

screens were not properly reinstalled.

Reportedly, a lifting beam

device was misplaced during the modification process.

Without the beam

device the filters could not be properly installed.

The Catawba Fire

Protection OA Program has been incorporated into the Duke Topical Report

GA Program as OA Condition 3.

The Topical Report. Section 17.3.1.6

states that Duke has established a corrective action process whereby all

i

personnel are to assure conditions adverse to quality are promptly

identified, controlled, and corrected. Also. Topical Report Section

17.3.2.13 - Corrective Action. requires conditions adverse to quality to

be corrected

The failure to correct the degraded filter screens for

the fire pumps in a timely manner is identified as Violation 50-

413.414/97-07-05.

Following this inspection, the licensee notified the

inspectors that these screens were properly installed on May 14. 1997.

.

Otherwise, the inspectors concluded that there was no significant

maintenance backlog associated with fire protection components.

Also, as of March 31. 1997, there were 22 degraded or inoperable fire

protection components.

Most of these items were related to the Unit 2

refueling outage which was in progress.

For example several fire

barrier penetrations were open for movement of materials through open

floor hatches and the CO system for the 2A diesel generator was removed

2

from service due to maintenance work being performed on the diesel

engine. The remaining degraded features were either in nonsafety-

related areas or were minor discrepancies which did not affect the

operability of the system or component.

Four of these items had been

degraded since late 1996. the remainder had been degraded since early

1997

The inspectors verified that appropriate com)ensatory measures

had been implemented for the degraded components, w1ere required.

One

degraded component required a continuous fire watch and three degraded

'

components required an hourly fire watch patrol. The remaining degraded

components were considered operable and did not require any compensatory

actions.

'

The inspectors toured the plant and noted that the operable fire

protection systems were well maintained and the material condition was

very good.

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Fire Briaade Eauioment:

The fire brigade turnout gear was stored in a fire brigade equipment

building adjacent to the Unit 2 Turbine Building. A sufficient number

,

of turnout gear, consisting of coats, Sants boots, helmets, etc., was

provided to equip the fire brigade mem)ers expected to respond in the

i

event of a fire or other emergency. The equipment was properly stored

'

and well maintained.

c.

Conclusions

The low number of open maintenance work orders and degraded fire

protection components, in conjunction with the good material condition

of the fire protection components and fire brigade equipment, indicated

that, in general, appropriate em)hasis had been placed on the

maintenance and operability of tie fire protection equipment and

components.

The work to repair the suction screens for two of the three fire pump's

suction piping had been o)en since 1991 and was not complete. The lack

of prompt resolution of t1e work was identified as a violation.

F2.2 Surveillance of Fire Protection Features and Eauioment

.

a.

Insoection Scone (64704)

The inspectors reviewed the following completed surveillance and test

procedures:

-

IP/0/A/3350/13. Revision Change 0 Retype 5. EFA System Detector

Test Procedure, Data Gathering Panel 10.

Completed January 20,

1997.

-

IP/0/A/3350/16. Revision Change 0 Retype 2. EFA System Detector

Test Procedure, Data Gathering Panel 13.

Completed February 6.

1997.

-

PT/0/A/4400/01A, Revision Change 0 Retype 32. Exterior Fire

Protection Functional Capacity Test.

Completed January 29, 1996.

-

PT/0/A/4400/01S, Revision Change 0 Retype 25. Exterior Fire

Protection System - Raw Water Yard (RY) Fire Protection Flow

(Underground) Periodic Test.

Completed April 9.1996 and December

5, 1996.

The frecuency of selected surveillance test procedures were also

reviewec,

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Enclosure 2

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b.

Observations and Find 1nas

The completed fire protection surveillance tests reviewed by the

inspectors had been appropriately completed and met the. acceptance

criteria. The test procedures were well written and met the fire

3rotection surveillance requirements of FSAR Chapter 16.9. Selected

_icensee Commitments (SLC). The surveillance procedures for the

capacity tests on the fire pumps required test data for multiple points

j

on the pump curve to be obtained.

This data provided good verification

of the pump's performance.

During the review of Surveillance PT/0/A4400/01A. the inspectors noted

that the October 1995 surveillance test indicated that the water flow

through the piping system would not deliver adequate fire flows

This

test is conducted every three years and measures the flow of water

through various sections of piping to determine if the system will

'

provide an adequate flow path from the fire pumps to the various

i

sprinkler and hose stations located in the plant to meet the required

l

design head 3ressure and volume requirements.

Following the October

1995 test, t1e system was extensively flushed and retested in April

i

1996. This test found that the system remained deficient.

The flow

tests were performed by isolating the normal loop piping such that the

flow tests were through a single pipe.

The system would provide the

.

required design flow rates as long as the loop flow paths were

maintained in service.

The licensee developed a major pipe cleaning and flushing project

utilizing the " hydro-lase" process which was performed by station

personnel working under the supervision and coordination of a vendor

specialist.

During the pipe cleaning activities several automatic

sprinkler systems and hose stations were required to be removed from

service.

The licensee coordinated this work to require a minim;m number

of systems to be inoperable at any one time.

Appropriate compensatory

actions, consisting of a fire watch with backup fire suppression, were

provided as remedial actions while the required fire suppression systems

'

were inoperable.

Based on the review of the work activities and

interviews with the plant staff, the inspectors concluded that good

coordination and oversight of these activities were provided.

Following

completion of the pipe cleaning activities the underground piping was

retested in December,1996 and was found to be capable of delivering the

required fire flow.

The surveillance requirements for the fire protection systems were

contained in FSAR Chapter 16.9.

The results of the inspector's review

I

of these features is located in Section F3.

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c.

Conclusions

Good surveillance and test procedures were provided for the fire

protection systems and features.

Procedure implementation was

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effective. The coordination of the fire protection water piping

cleaning project was excellent.

F3

Fire Protection Procedures and Documentation

a.

Insoection Scooe (64704)

The inspectors reviewed the following procedures for compliance with the

NRC requirements and guidelines:

-

Nuclear Station Directive 112. Revision 0. Fire Brigade

Organization. Training and Responsibilities

-

Site Directive 2.12.5, Revision 3. Control of Combustible

Materials Within the Protected Area

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Site Directive 2.12.6. Revision 3. Fire Protection. Detection and

Barrier Impairment Reporting

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Site Directive 2.12.7. Revision 4. Fire Protection / Detection

!

Remedial Actions

!.

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Site Directive 3.3.9. Revision 1. Hot Work Authorization

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FSAR Chapter 16.9. (Revision dated 1/30/96). Auxiliary Systems

(Fire Protection Systems)

-

Prefire Plans. Revision 6. Catawba Prefire Plans 6.1d Procedures

Plant tours were also performed to assess procedure compliance.

b.

Observations and Findinas

The above procedures were the principle procedures issued to implement

the facility's fire protection program.

These procedures contained the

requirements for program administration. controls over combustibles and

i

ignition sources, fire brigade organization and training, and

o)erability requirements for the fire protection systems and features.

,

T1e procedures were well written and met the licensee's commitments to

!

the NRC.

The inspectors performed plant tours a"d noted that, even though the

plant was in a refueling outage, implementation of the site's fire

l

prevention program for the control of ignition sources, transient

l

combustibles, and general housekeeping was good.

The accumulation of

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transient combustible materials and the number of maintenance activities

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in process due to the refueling outage were-more than anticipated during

normal plant operations.

However, appropriate fire prevention controls

were being applied to these activities.

Enclosure 2

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FSAR Chapter 16.9. Selected Licensee Commitments. Auxiliary Systems

(Fire Protection Systems) provides the operability and surveillance

requirements for the fire protection systems and components.

The

inspectors compared these requirements to the requirements which were

formerly in the TS. These requirements remained essentially the same,

except for the following testing frequency changes:

fire detectors.

from monthly to annually; fire protection valve alignments, from monthly

to quarterly; and hose station inspection, from monthly to quarterly.

The licensee had recently changed these surveillance inspection

frequencies based on satisfactory results from performance based

,

l

evaluat wis of these systems. The inspectors verified that appropriate

l

10 CFR 50.59 safety evaluations had been performed for these revisions.

,

The trending data on the performance based surveillance inspections were

reviewed and indicated that the reliability of these systems was greater

than 99 percent.

This substantiated the changes made to the

!

surveillance frequency requirements. The operability requirements in

the SLC were adequate.

However, the water supply and fire detection

systems were the only systems which had time limits established for

restoring inoperable components to operable status. This issue is being

evaluated further by the NRC and is identified as an Inspector Followup

Item pending completion of this review. IFI 50-413.414/97-07-06: Time

Limits for Restoration of Inoperable Fire Protection Components.

.

The prefire plans reviewed by the inspectors were found to be

satisfactory.

A minor modification was in process to relocate and

remove some of the fire extinguishers presently installed within the

.

plant. Also, a standard fire protection water supply system was

scheduled to be installed by late 1991 for the nuclear service water

'

intake pumping structure.

The prefire plans were scheduled to be

revised upon completion of these modifications.

In the interim.

controlled copies of the prefire plans had been marked to indicate the

plant changes as they were completed for each plant area.

c.

Conclusions

The fire protection program implementing procedures were good and met

licensee and NRC requirements.

Implementation of procedures for the

control of ignition sources, transient combustibles, and general

housekeeping was good. An issue regarding time limits for restoration

of inoperable fire protection components will be reviewed further by the

NRC.

F5

Fire Protection Staff Training and Qualification

a.

Inspection Scope (64704)

The inspectors reviewed the fire brigade organization and training

program for compliance with the NRC guidelines and requirements.

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Enclosure 2

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b.

Observations and Findinas

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The organization and training requirements for the 31 ant fire brigade

were established by Nuclear Station Directive 112. Revision 0. Fire

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Brigade Organization. Training and Res]onsibilities. The fire brigade

I

for each shift was composed of a fire arigade leader and at least four

j

brigade members from operations and approximately five members from

maintenance.

The fire brigade leeder was a senior reactor o]erator

(SRO) and was normally one of the unit shift supervisors. T1e other

members from Operations were non-licensed plant operators. One of the

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fire brigade members was normally assigned the duties of fire brigade

safety officer to provide technical and administrative assistance to the

fire brigade leader and to hel) cssure the safe performance of each fire

l

brigade member by checking eac1 member for appropriate dress out prior

to entering the fire area, maintaining records of each fire brigade

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,

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exposure to fire or radiatinn hazards, use of self contained breathing

apparatus, and reviewing the prefire plans during the emergency for

'

assurance that appropriate measures are being followed for compliance

l

with applicable safety and fire hazards in the area. Assignment of a

'

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fire brigade safety officer was identified as a program strength.

l

Each fire brigade member was required to receive initial, quarterly and

annual fire fighting related training and to satisfactorily complete an

.

annual medical evaluation and certification for participation in fire

brigade fire fighting activities.

In addition each member was required

i

to participate in at least two drills per year.

.

As of the date of this inspection, there were a total of 34 operations

trained fire brigade leaders and 73 operations personnel and 29

maintenance personnel on the plant's fire brigade. Approximately 6 fire

brigade leaders.12 operations fire brigade members and 5 mintenance

fire brigade members were assigned to each of the five operations crews.

This was a sufficient number of personnel to meet the facilities fire

brigade procedure requirements for one team leader and nine members per

l

shift.

The inspectors reviewed the training and medical records for the fire

brigade members and verified that the training and medical records were

up to date.

The facility utilized off-site qualified state certified

fire brigade training instructors and a state fire training facility to

perform the annual fire brigade training and practical fire training

,

i

scenarios.

During this inspection, the inspectors witnessed a fire brigade drill

involving a simulated fire in an electrical motor for a component

cooling pump located on the 560 foot elevation of the auxiliary

building.

The response of the fire brigade to the simulated fire was

excellent. The brigade leader's direction and fire brigade members'

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performance, especially the safety officer, were outstanding.

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Enclosure 2

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critique to discuss the brigade performance and future enhancements was

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held following the drill.

,

c.

Conclusions

The fire brigade organization and training met the requirements of the

site procedures.

Performance by the fire brigade during a drill was

excellent.

The use of the fire brigade safety officer position during

fire emergencies was identified as a program strength.

F6

Fire Protection Organization and Administration

i

a.

Insoection Scooe (64704)

]

The licensee's managemerit and administration of the facilities fire

protection program were reviewed for compliance with the commitments to

the NRC and to current guidelines.

b.

Observations and Findinas

The Civil. Electrical. Reactor. Nuclear Engineering Manager was assigned

the responsibility for implementing the facility's fire protection

program. An engineer was assigned the task of coordinating the entire

,.

fire 3rotection program and for coordinating the maintenance,

opera)ility and modifications on the fire suppression systems, fire

barriers, and fire barrier penetrations.

Another engineer was

i

responsible for coordinating the maintenance, o)erability and

modifications on the fire detection systems.

T1e Manager of Safety

Assurance was responsible for providing appropriate training for the

facility fire brigade and for providing guidance and support in the

'

implementation of the facility's fire protection program.

Support on

generic fire 3rotection issues was provided to the site by an engineer

assigned to t7e Corporate Nuclear Engineering Division.

A corporate Fire Protection Business Excellence Steering Team (BEST).

composed of representatives from each of the three Duke nuclear plants

and the corporate staff, was meeting monthly to discuss fire protection

issues and im)rovements needed to enhance the fire protection program at

each site.

T1e inspectors reviewed the minutes for the first three

meetings in 1997 and noted a number of issues were under consideration

which, if im)lemented should improve the overall fire protection

program at t1e Duke facilities.

The inspector concluded that these

meetings were a positive element of the facility's fire protection

program.

c.

Conclusions

Strong coordination and oversight were provided over the facility's fire

-

protection program.

The Fire Protection BEST was a positive factor in

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the identification of potential problems and in the development and

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implementation of enhancements to the fire protection program.

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F7

Quality Assurance in Fire Protection Activities

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a.

Insoection Scooe (64704)

The following audit report was reviewed:

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Audit SA-95-24(CN)(RA). Triennial Fire Protection Audit conducted

May 15 through June 8, 1995

b.

Observations and Findinas

Audit SA-95-24(CN)(RA) was a triennial 0A audit of the facilities' fire

protection program.

The licensee informed the inspectors that this was

the only comprehensive audit of the fire protection program performed

since Duke's December 18, 1991, request to use performance based

criteria for establishing auoit frequencies was approved by the NRC.'s

letter dated May 7. 1992.

Previously, the TS had required annual,

biannual and triennial audits of the fire protection program.

However,

based on the licensee's assessment of good fire protection performance.

only this one triennial audit had been performed at Catawba in recent

.

years.

TS 6.5.2.9 identified a number of site audits which were performed under

the cognizance of the Nuclear Safety Review Board.

The licensee's

December 18, 1991, letter indicated that the audit frequency for all of

these audits were deleted from the TS. and the OA Topical report was to

be revised to indicate that the " audits of selected aspects of

operational phase activities are performed with a frequency commensurate

with safety significance and in such a manner as to assure that an audit

of all safety related functions is completed within a period of two

years." The OA topical report was revised, but only requires an audit

of all "0A Condition 1 functions" to be completed within a period of two

years. Many of the audit items listed by TS Section 6.5.2.9 are

classified as OA Condition 2 or 3 functions.

The specified time for

these audits are not listed in the OA topical report. The inconsistency

of not providing a specified frequency for Condition 2 and 3 functions

is being further reviewed by the NRC and is identified as Inspector

Follow-up Item pending completion of this review. 50-413.414/97-07-07:

Audit Frequency Requirements for Activities other than OA Condition 1

Functions.

The inspectors reviewed the audit findings from the 1995 OA report and

the corrective actions taken on the identified discrepancies. The

report indicated that a comprehensive audit had been performed with nine

findings identified.

The corrective action on each finding had been

completed in a timely manner.

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c.

Conclusions

The 1995 audit and assessment of the facility's fire protection program

was comprehensive and appropriate corrective action was promptly taken

to resolve identified issues. An issue regarding the control of 0A

audit frequencies will be reviewed further by the NRC.

F8

MiscellaneousFireProtectjonIssues

F8.1 Fire Protection Related NRC Information Notices

The inspector reviewed the licensee's evaluation for the following NRC

Information Notices (IN):

'

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IN 92-18. Potential loss of Shutdown Capacity During a Control

Room Fire

-

IN 92-28. Inadequate Fire Suppression System Testing

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IN 93-41. One Hour Fire Endurance Tests Results For Thermal

Ceramics. 3M Company FS 195'and 3M Company E-50 Interam Fire

,

Barrier Systems

..

-

IN 94-28. Potential Problems with Fire Barrier Penetration Seals

-

IN 9--31. Potential Failure of WILCO. LEXAN-Type HN-4-L. Fire Hose

Nozzles

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IN 94-58. Reactor Coolant Pump Lube Oil Fire

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IN 95-36. Emergency Lighting

The licensee's evaluations and corrective actions for these ins were

appropriate, except the evaluation documentation for some of the ins did

not fully indicate the results of the evaluations which were actually

performed.

V. Manaaement Meetinos

X1

Exit Meeting Summary

The inspectors ) resented the inspection results to members of licensee

management at t1e conclusion of the inspection on April 30. 1997.

On May 14

a teleconference was held between Region II DRS management and licensee

management representatives to discuss the violation included with this report.

l

The licensee acknowledged the findings presented.

No proprietary information

was identified.

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Enclosure 2

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

Bhatnager,

A., Operations Superintendent

Birch. M., Safety Assurance Manager

Christopher. S. , Emergency Planning Supervisor

.

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Copp. S Nuclear Regulatory Affairs Manager

Coy. S., Radiation Protection Manager

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Forbes. J.,

Engineering Manager

'

Giles, R.

Work Control Inservice Inspection Coordination

,

Harrall. T.

Instrument and Electrical Maintenance Superintendent

'

Kelly. C.. Maintenance Manager

!

Kimball. D., Safety Review Group Manager

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Kitlan. M., Regulatory Compliance Manager

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Kulla

D.

Civil Engineering Supervisor

McCollum

W., Catawba Site Vice-President

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Nicholson. K., Compliance Specialist

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Peterson. G., Station Manager

l.

Propst. R., Chemistry Manager

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Purser, M.. Senior Engineer

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Robinson

G., Work Control Execution Support

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Rogers

D., Mechanical Maintenance Manager

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Tower, D., Compliance Engineer

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INSPECTION PROCEDURES USED

IP 37550:

Engineering

IP 37551:

Onsite Engineering

IP 40500:

Effectiveness of Licensee Controls in Identifying, Resolving, and

Preventing Problems

IP 49001:

Inspection of Erosion / Corrosion Monitoring Programs

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IP 61726:

Surveillance Observation

IP 62001:

Boric Acid Program Prevention Program

IP 62707:

Maintenance Observation

IP 64704:

Fire Protection Program

,

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IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

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IP 73753:

Inservice Inspection

'

IP 83750:

Occupational Radiation Exposure

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IP 84750:

Radioactive Waste Treatment and Effluent and Environmental

Monitoring

IP 92901:

Followup - Operations

IP 92902:

Followup - Maintenance

IP 92903:

Followup - Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

.

Opened

50-414/97-07-01

VIO

OPEN

Inadequate Procedure Resulting in

Loss of Spent Fuel Pool Cooling with

Core Off-loaded. (Section 01.1)

50-413,414/97-0? 32

1FI

OPEN

Boron Dilution Mitigation System

Reliability Resolution. (Section

01.4)

50-413.414/97-07-03

IFI

OPEN

Review Corrective Actions For

Storage and Handling Assessment

Findings. (Section M1.2)

50-413,414/97-07-04

NCV

OPEN

Failure to Source Check Survey

Instruments as required by licensee

procedure. (Section R1.1)

50-413.414/97-07-05

VIO

OPEN

Failure to Repair Degraded Suction

Screen Filters for Fire Pumps in a

Timely Manner. (Section F2.1)

50-413,414/97-07-06

IFI

OPEN

Time Limits for Restoration of

Inoperable Fire Protection

,

Components. (Section F.3)

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Enclosure 2

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50-413.414/97-07-07

IFI

OPEN

Audit Frequency Requirements for

Activities other than OA Condition 1

Functions. (Section F.7)

Closed

50-413.414/94-13-01

VIO

CLOSED

Failure to follow Procedure NSD 703

and Station Directive 34.0.5

requirements.

(Section 08.1)

l

50-413/95-07-01

VIO

CLOSED

Inadequate Modification Procedure

Resulting in Loss of RHR. (Section

i

,

08.2)

50-413.414/95-07-02

VIO

CLOSED

Inadequate Valve Verification

Activities - Two Examples. (Section

08.3)

50-413.414/96-13-04

VIO

CLOSED

Inadequate Design Controls (MSIV

Solenoid Valves). Standby Shutdown

System Makeup Pump Sizing

Calculation (Section E8.1)

50-413.414/92-01-06

DEV

CLOSED

Breaker Coordination (Section E8.2)

.

50-413.414/96-12-03

VIO

CLOSED

Inadequate Design Controls For

Ensuring Containment Crane Wall and

Floor Drain Screens Implemented

Design Requirements (Section E8.3)

l

Enclosure 2

_

_

,

_

I

,

'

g..

6

.

44

l

l

LIST OF ACRONYMS USED

l

ALARA -

As Low As Reasonably Achievable

ANSI

-

American Nuclear Standards Institute

ASME -

American Society of Mechanical Engineers

BDMS -

Boron Dilution Mitigation System

,

'

CA

-

Auxiliary Feedwater (system)

CHEC -

Designation for EPRI computer code

CFR

-

Code of Federal Regulations

DEV

-

Deviation

DG

-

Diesel Generator

DPC

-

Duke Power Company

EFA

-

Fire Detection System

EPRI

-

Electric Power Research Institute

ESS

-

Electric System Support

FAC

-

Flow Accelerated Corrosion

FME

-

Foreign Material Exclusion

FSAR -

Final Safety Analysis Report

FWST -

Refueling Water Storage Tank

2

ft

-

Square Feet

ft-lb -

foot-pounds (force)

GL

-

Generic Letter

IFI

-

Inspector Followup Item

.

IN

-

Information Notice

IR

-

Inspection Report

ISI

-

Inservice Inspection

MOV

-

Motor Operated Valve

MSIV -

Main Steam Isolation Valve

NCV

-

Non Cited Violation

NDE

-

Nondestructive Examination

NI

-

Nuclear Safety Injection (system)

NSD

-

Nuclear System Directive

NSM

-

Nuclear Station Modification

NRC

-

Nuclear Regulatory Commission

OAC

-

Operator Aid Computer

PCE

-

Personnel Contamination Event

PIP

-

Problem Investigation Process

PORV -

Power Operated Relief Valve

psig -

Pounds Per Square Inch Gauge

QA

-

Quality Assurance

RCA

-

Radiologically Controlled. Area

RCP

-

Reactor Coolant Pump

RCS

-

Reactor Coolant System

RHR

-

Residual Heat Removal

RP

-

Radiation Protection

revolutions per minute

rpm

-

RWP

-

Radiation Work Permits

SG

-

Steam Generator

SI

-

Safety Injection

l

SLC

-

Select Licensee Commitments

'

Enclosure 2

.

a.-

s

.

45

SSS

-

Standby Shutdown System

TEPR -

Top Equipment Problem Resolution

TS

-

Technical Specifications

UFSAR -

Updated Final Safety Analysis Report

VIO

-

Violation

VN

-

Variation Notice

WO

-

Work Order

.

i

l

I

!

,

i

Enclosure 2

l

l