ML20128R095

Insp Repts 50-413/96-13 & 50-414/96-13 on 960728-0907. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering,Plant Support & Plant Status

ML20128R095
Person / Time
Site:	Catawba
Issue date:	10/07/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20128Q953	List: ML20128Q950 ML20128R086 ML20128R095
References
50-413-96-13, 50-414-96-13, NUDOCS 9610210290
Download: ML20128R095 (31)

See also: IR 05000413/1996013

Text

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

1 Docket Nos: 50-413. 50-414

i License Nos: NPF-35. NPF-52

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Report Nos.

50-413/96-13. 50-414/96-13

j Licensee: Duke Power Company l

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Facility: Catawba Nuclear Station. Units 1 and 2

! Location: 422 South Church Street

Charlotte. NC 28242

! Dates: July 28 - September 7. 1996

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Inspectors: R. J. Freudenberger. Senior Resident Inspector

a P. A. Balmain. Resident Inspector

J. L. Coley, Reactor Inspector. Region II

R. L. Franovich Resident Inspector

L. R. Moore. Reactor Ins)ector

S. B. Rudisail Project Engineer. Region II

P. S. Tam. Project Manager. NRR

H. L. Whitener. Reactor Inspector. Region II '

] M. N. Miller. Reactor Inspector Region II

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Approved by: L. D. Wert. Acting Chief

Reactor Projects Branch 1

4 Division of Reactor Projects

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Enclosure 2

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9610210290 961007 3

DR ADOCK 0500

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EXECUTIVE SUMMARY

, Catawba Nuclear Station. Units 1 & 2

NRC Inspection Report 50-413/96-13. 50-414/96-13

, 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 ]y regional reactor safety and retctor projects

, inspectors and reviews by a licensing project manager. In addition, the

results of a maintenance inspection conducted by a regional reactor inspector

during the week of July 8. has been included in Sections M2.3 and M/.

Ooerations

, . Although a required 10 CFR 50.72 report was submitted late (Non-Cited

l Violation 50-414/96-13-01), communication conventions were consistently

utilized, a timely decision regarding the initiation of the shutdown was

made, and good command and control was exhibited during a forced Unit 2

shutdown. (Section 01.1)

. A procedure change to prewarm the Residual Heat Removal pump prior to

placing it in service resulted in the unanticipated binding of a manual

, isolation valve, which rendered the system inoperable (VIO 50-413.414/

96-13-02). (Section 01.2)

. The licensee was proactive in determining the source of the water on the j

ground surface in the vicinity of Nuclear Service Water System piping. l

The delay of Unit 2 startup until the source was identified and repaired

demonstrated an appropriate focus on safe operation of the facility.  ;

(Section 01.3)

Maintenance

. The licensee's effort to determine root causes was thorough and adequate

to ensure appropriate classification of safety significant motor

failures. (Section M1.1)

. The decision to delay refueling until the 1A Residual Heat Removal Pump

could be returned to an operable status was considered to be indicative

of a conservative operational approach. The root cause evaluation of

the motor failure was of an appropriate scope. (Section M1.2)

. The actions to re] air damaged secondary contact blocks on the Unit 1

Reactor Trip Brea(ers (RTBs) and bypass RTBs were appropriate. Planned

corrective actions also were appropriate. (Section M1.3)

. The licensee was actively monitoring and evaluating equipment

reliability. Adverse trends were identified, and corrective actions

were initiated. Actions reviewed by the inspectors addressed the

concerns and were comprehensive in scope. (Section M2.1)

Enclosure 2

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Executive Summary 2

. The Maintenance self-assessment program was effective and well managed.

The program identified a high number of rework items which were the

result of poor work practices. (Sections M2.1 and M7.1)

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. An inadequate procedure caused unanticipated component actuations that l

interfered wit 1 the dilution flow for a liquid radioactive release. I

(Violation 50-413.414/96-13-02). (Section M3.1)

. The licensee identified a violation (non-cited) involving the

performance of Emergency Diesel Generator Head reassembly steps out of I

sequence (Non-Cited Violation 50-413/96-13-03). (Section M4.1) '

Enaineerina

. An example of a violation for inadequate design control was identified

in that Main Steam Isolation Valve (MSIV) solenoid valve nameplate

rating was less than the instrument air maximum pressure (Violation 50-

413.414/96-13-04). (Section El.2)

. Actions to determine the root cause of the B main feedwater pump trip

were timely and appropriate. Proposed corrective actions were adequate.

(Section E2.1)

. Several Unit 1 modifications were implemented during the outage to

resolve existing equipment problems and improve plant reliability. The

modifications demonstrated appropriate control of the design control

process at Catawba. The requirements of 50.59 were met for associated

safety evaluations that were reviewed. (Section E2.2)

. The erosion / corrosion program was effective in identifying main

feedwater pipe localized wall thinning. (Section E2.3)

. The 1995 revision of the Catawba UFSAR matched the provisions of 10 CFR

50.71 and was therefore in compliance with 10 CFR 50.71.(Section E3.1)

. Design input errors in Calculation 1223.04-00-0009 were not identified

by the licensee on two occasions: first during the independent review of

the calculation in November 1993, and again during the licensee's steam

supply station (SSS) pre-inspection self-assessment in June 1996

(Violation 50-413.414/96-13-04). (Section E4.1)

Plant Sucoort

. An unauthorized entry of an individual into the Radiation Control Area-

without appropriate dosimetry. training, or body burden analysis was

identified as a violation of Radiation Protection Directive No. II-1.

Radiation Area Access and Monitoring Devices (Violation 50-413,414/96-

13-06). Corrective actions for a previous occurrence were not effective

in preventing recurrence. (Section R1.1)

Enclosure 2

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Reoort Details

Summary of Plant Status

Unit 1 was in a refueling / steam generator replacement outage for the duration

of the inspection period.

Unit 2 was in a forced outage because of inoperability of both trains of the

Control Room Ventilation System between August 3 and 12. The unit operated at

or near 100% power throughout the remainder of the inspection period.

Review of UFSAR Commitments

A recent discovery of a licensee operating their facility in a manner contrary

to the Updated Final Safety Analysis Report (UFSAR) description signified the

need for a special focus review that compares plant practices, procedures,

and/or parameters to the UFSAR descriptions. While performing inspections

discussed in this report, the inspectors reviewed the applicable portions of

the UFSAR that related to the areas ins)ected. The inspectors verified that

the UFSAR wording was consistent with tie observed plant practices,

procedures, and/or parameters. No deficiencies were identified.

I. Operations

01 Conduct of Operations

01.1 Unit 2 Forced Shutdown

a. Insoection Scooe (71707)

On August 3.1996. Catawba Unit 2 entered Technical Specification 3.0.3

and was shut down when both trains of the Control Room Area Ventilation

system became inoperable. During the forced outage, the inspectors

observed control room activities, assessed equipment failures and

reviewed reporting requirements.

b. Observations and Findinas

Train B of the Control Room Area Ventilation system was out of service

for planned maintenance. The system's A Train pressurization fan motor

subsequently failed, and Technical Specifications (TS) required the unit

to shutdown /cooldown (see section M1.1 of this report). While the unit

was in Hot Shutdown (Mode 4) on August 4. a fan motor failure occurred ,

on Train A of the Auxiliary Building Ventilation System (see section

M1.1 of this report). This failure resulted in both trains of Auxiliary

Building Ventilation being inoperable because Train B was out of service

for )lanned filter testing. Subsequent problems encountered with

esta)lishing Residual Heat Removal flow on Train B (See section 01,2 of

this report) required the use of Train A of the Residual Heat Removal

system to take the unit to cold shutdown (Mode 5) at 12:58 p.m. on

August 4.

Enclosure 2

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The inspector observed control room activities during the forced

shutdown and noted that communication conventions were consistently

utilized. a timely decision regarding the initiation of the shutdown was

made, and good command and control was exhibited.

The licensee identified a missed 10 CFR 50.72 report regarding the

failure of the A Auxiliary Building Ventilation Filtered Exhaust Fan

Motor. Prior to the failure, the B train was removed from service for

filter testing and replacement. With both trains inoperable, a second

condition existed that required entry into TS 3.0.3. On-shift personnel l

considered re)orting of this second condition as having been

accomplished )y the previous report and did not make a second report

regarding this failure. This condition was later recognized as

reportable under 10 CFR 50.72(b)(2)(iii)(d) and a report was made. The ,

report did not meet its associated timeliness requirements. The

licensee initiated a Problem Investigation Process (PIP) Report for this i

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occurrence (PIP 0-C96-2058). Corrective actions included a " read and

sign" discussion of the occurrence for operations personnel and plans

for including performance and assessment of reportability determinations

in simulator training. This licensee-identified and corrected violation

is characterized as Non-Cited Violation 50-414/96-13-01: Failure to

Report Inoperability of Both Trains of Auxiliary Building Ventilation,

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

c. Conclusions

With the exce) tion of a late 10 CFR 50.72 report, operators perTarmed

well during tie forced shutdown in response to ventilation system

failures.

01.2 Residual Heat Removal Train B Inocerable Durina Unit 2 Forced Shutdown

a. Insoection Scooe (71707)

On August 4 during the forced shutdown when TS 3.0.3 was entered after

both trains of Control Room Ventilation were inoperable, control room

operators were attempting to place the B train of the Residual Heat

Removal (RHR) system in service. The 2B RHR heat exchanger inlet manual

isolation valve. 2ND-53, was closed by procedure and became wedged in

its seat. A stem to disc failure was incurred during attempts to open

the valve. As a result. B train of RHR was inoperable during the Unit 2

cooldown from Mode 4 to Mode 5. The inspector interviewed plant

personnel and reviewed procedures, system diagrams, and metallurgical

analysis report #2032. The inspector also reviewed the licensee's root

cause evaluation and associated recommendations.

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b. Observations and Findinas

i Operators attempted to place B train RHR in service'using

l OP/2/A/6200/04. Retype #13. Residual Heat Removal System. Enclosure 4.1.

Startup of the RHR System During Normal Plant Cooldown. A recent

! procedure change directed clerators to close valve 2ND-53 at step 2.6.29

and bypass flow around the leat exchanger. Flow was diverted through

the heat exchanger bypass line and into the letdown system so that the 1

2B residual heat removal pump and associated suction and discharge

piping could be slowly heated to within 50 F of reactor coolant system

temperature before the pump was placed in service. The procedure change

l was designed to prevent thermal deformation of the pum) casing and

subsequent casing leakage. The procedure introduced t1e potential for

thermally induced pressure locking of 2ND-53.

Step 2.6.46 of OP/2/A/6200/04 directed operators to open 2ND-53 to

establish flow through the heat exchanger and place B train RHR in

service. The valve could not be opened by normal use of a reach rod or

direct, unassisted manipulation of the handwheel. A valve wrench was

used to open the valve, and a stem to disc failure occurred but was not )

immediately recognized. As'a result, the B train of the residual heat i

removal system was inoperable during unit cooldown from Mode 4 to Mode 5 1

and remained inoperable from 10:00 a.m. on August 4. 1996, until 4:00

p.m. on August 7, 1996. The A train of RHR was placed in service so

that unit cooldown to Mode 5 could be achieved within the remaining time

allowed by TS.

Valve 2ND-53 is a manual double disc gate valve. and it is located near

(approximately 1.5 feet from) the heat exchanger bypass flowpath. The

licensee concluded that the most likely cause of the valve binding was

thermally induced pressure locking as RHR temperature increased.

The stem to disc failure occurred at a link that affixes the stem to the

disc. According to metallurgical analysis report #2032. Catawba Linkage

from 2ND-53, fracture of the 2ND-53 linkage was caused by a single

overstress event, most likely attributable to attempts by plant

personnel to free the stuck valve. No signs of pre-existing cracks or

other material problems that might have made the linkage susceptible to

premature failure were detected.

The inspector questioned the use of a valve wrench to open the valve and

determined that Operations Management Procedure 2-33 allows for the use

of a valve wrench if no more than normal force of a "large individual"

is applied. The inspector determined that the requirements of this

procedure were complied with.

, The inspector reviewed the change to OP/2/A/6200/04 for prewarming the

l pump before placing the system in service, including the 10 CFR Part

50.59 evaluation. The inspector concluded that the potential for

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pressure locking and thermal binding was evaluated during the 10 CFR

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Enclosure 2

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50.59 review process. However, the evaluation was narrow in scope

(limited to active valves) and the licensee concluded'that, since 2ND-

53 was a manual isolation valve. it would not be affected by these

phenomena.

The licensee did not recognize that 2ND-53 was broken until flow could

not be established through the heat exchanger, at which time the failure

of 2ND-53 was self-disclosing. Because the binding and subsequent

failure of valve 2ND-53 resulted in the inoperability of the B train of 1

RHR. only one train of RHR was operable during the Unit 2 forced

cooldown.

Incidentally, the inspector determined that the Unit 1 procedure for

prewarming the RHR pumps had been changed before the refueling / steam

generator replacement outage began. The change involved isolating the

letdown piping from the RHR system to prevent water hammer in the

letdown piping as RHR was placed in service and the RHR to letdown

piping was rapidly pressurized. The same procedure change had not been

made to Unit 2 procedures when the forced shutdown was initiated. The

inspector considered implementation of procedure changes that were not

unit specific on only one unit to be a poor practice. The licensee

revised operation department guidelines to require simultaneous

implementation of non-unit specific procedure changes in the future.

c. Conclusions

Procedure changes to OP/2/A/6200/04 were inadequate in that the

procedure established conditions which caused thermally induced pressure

locking of valve 2ND-53. The valve was damaged in attempts to open it,

thereby extending the time that the B-train of RHR was inoperable. This

issue is characterized as Example 1 of Violation 50-413.414/96-13-02:

Inadequate Procedures.

01.3 Nuclear Service Water System Pioe Leak in Yard

a. Insoection Scoce (40500 and 71707)

On August 8. licensee maintenance technicians identified water bubbling

up from the ground near the steam generator storage facility. The

licensee was aware that nuclear service water (RN) system piping was

buried in the general vicinity where the water was found and, concerned

that an RN pipe was leaking, excavated the piping. A hole was found on

the B train supply header, and a modification was implemented to repair

the 42-inch pipe. The inspector reviewed the modification package,

including the 10 CFR 50.59 evaluation, observed parts of the excavation.

attended a PORC meeting, and reviewed the compensacory actions that were

developed to ensure that, during the pipe repair, the seismic integrity

of the RN piping was maintained and tornado missile protection could be

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Enclosure 2

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reestablished within one hour of a tornado watch or warning

notification.

b. Observations and Findinas

l The leak emerged from an external pit initiated from corrosion. The pit

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was approximately two inches in diameter on the outer surface of the

pipe and roughly three-sixteenths of an inch in diameter on the inner

pipe surface. The hole was temporarily plugged. Minor modification

CNCE-8150 was developed to make 3ermanent code repairs to the defect and

other non-through wall pits in tie vicinity. The pits appeared to be

caused by localized damage to the protective coating while on the piping

during initial installation. While the source of the water was being

investigated and repaired. Unit 2 startup was delayed.

c. Conclusions

The inspector concluded that the licensee was proactive in determining

l the source of the water on the ground surface. Compensatory actions

i that were in effect during the pipe repair were appropriate. The delay

of Unit 2 startup until the source was identified and repaired

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demonstrated an appropriately conservative focus on safe operation of

the facility.

II. Maintenance

l M1 Conduct of Maintenance

M1.1 Follow-uo of Ventilation Motor Failures

a. Insoection Scooe (93702)

On August 3.1996. Unit 2 entered TS 3.0.3 due to both trains of the

l Control Room Ventilation system being inoperable. The B train of

Control Room Ventilation was inoperable due to Nuclear Service Water

system work in progress. The A train became inoperable when the filter

fan motor breaker trip)ed and would not reset. This resulted in both

l trains of ventilation 3eing inoperable; thereby requiring entry into TS

l 3.0.3. During the shutdown the auxiliary building ventilation exhaust

fan tripped on a ground fault. The inspector reviewed the failuru of

the ventilation system motors to determine if the failures were

l appropriately classified and adequate corrective actions completed or

l planned.

l b. Observations and Findinas

{ The inspector reviewed the failure of the Control Room Ventilation

System Fan Motor 1CRA-PFT-1. The failure of this motor was determined

to be an electrical failure due to a ground fault on the T3 phase

winding. This failure was verified using a winding analysis test. The

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winding analysis test includes a winding resistance measurement. an

insulation resistance (megger) test, a Hi-pot test, a polarization index

test and a surge comparison test. The results of this test identified a

ground fault with the megger indicating failure at 400 volts and the

surge test. revealing a 92% mismatch between two of the three phases.

, Further analysis was performed by the motor manufacturer. Reliance

! Electric, which confirmed the licensee's results. This motor was

approximately 15 years old and had been in service since initial

i operation of the plant. A definitive root cause for the fault of the

motor was indeterminate, but age related failure was suspected. The

motor was replaced and the system returned to service prior to Unit  !

restart.

l Additionally, the inspector reviewed the failure of the Auxiliary

l Building Filtered Exhaust Fan Motor ABXF-2A Initial failure

l investigation revealed a phase to ground fault on all three phases.

This was determined by meggering. Bearing failure was suspected due to I

difficulty in rotation of the motor; however, after the motor was i

removed and taken to the shop for troubleshooting the cause of the i

rotation difficulty was determined to be melted copper from the damage

caused by the fault. The inspector observed this inspection by the

licensee and also reviewed the motor damage. The inspector concurred

with the licensee's assessment during this preliminary investigation. ,

The motor was subsequently shipped to a vendor troubleshooting and l

repair facility for further analysis.

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The inspector reviewed the licensee's root cause effort to determine -l

whether a common cause had initiated the failure of the two motors and

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possibly resulted in other motors being susceptible to failure. From

! this review the inspector determined that a common cause for these two

! motor failures had not been identified. The licensee's review for a

l common root cause was adequate to ensure that these two failures were

l random failures without a single initiating cause.

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c. Conclusions

! The inspector concluded that the licensee's effort to determine root

cause was thorough and adequate to enst ce appropriate classification of

the motor failures.

M1.2 Followuo of Residual Heat Removal Motor Failure

a. Insoection Scot. (62703)

On August 31. the 1A Residual Heat Removal Pump tripped after

I approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of run time following installation. The ins)ector

! reviewed the operational impact and the root cause evaluation of t1e

failure.

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Enclosure 2

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b. Observations and Findinas

At the time of the failure. Unit 1 had no' fuel in the core and

preparations were underway to initiate refueling. Plant TS allow core

alterations with one operable Residual Heat Removal pump and the

refueling cavity filled. Based on questioning by o)erations personnel,

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the licensee chose to delay refueling until the 1A lesidual Heat- Removal

Pump could be returned to an operable status. The inspector considered

this decision to be reflective of a conservative operational approach.

Based on information provided by the licensee, the motor that failed had

been refurbished by Westinghouse in 1994. The refurbishment was l

primarily a mechanical refurbishment to correct an out of tolerance i

condition on the upper bearing housing and improve vibration of the j

motor. Electrical testing indicated that the motor was in good

condition. After storage in the contaminated warehouse on site at

Catawba, the motor was installed in July, 1996. Electrical testing

again indicated that the motor was in good condition at that time.

Shortly after functional testing, the motor failed while in service. '

Initial cause investigation during disassembly indicated the fault was

initiated by a turn-to-turn fault in the stator windings. The licensee

root cause analysis was not complete at the end of the report seriod.  :

but poor storage conditions in the contaminated warehouse was seing

investigated as a possible cause.

c. Conclusions

The licensee's decision to delay refueling until the 1A Residual Heat

Removal Pump could be returned to an operable status was considered to

be reflective of a conservative operational approach. The cause

evaluation of the motor failure was of an appropriate scope.

M1.3 Reactor Trio Breaker Secondary Contact Blocks

a. Insoection Scoce (62703)

In June 1996, the licensee identified cracked secondary contact blocks

on the reactor trip breakers (RTBs) and bypass RTBs at the McGuire and

Catawba Nuclear Stations. The issue is documented in NRC Ins)ection

Report 50-413.414/96-10. In this inspection report period, t1e

inspector reviewed work orders (W0s) to verify that all damaged

secondary contact blocks on the Unit 1 RTBs and bypass RTBs were

replaced with new blocks prior to unit restart from a refueling and

steam generator replacement outage. The inspector also reviewed the

procedure for handling RTBs and bypass RTBs. and reviewed the licensee's

root cause evaluation and proposed corrective actions.

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b. Observations and Findinas

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The inspector reviewed the task completion notes associated with W0s

96054700-01. 96010780-01. 96019781-01. and 96026725-01 and determined

that the damaged RTB and bypass RTB secondary contact blocks were

l replaced with new blocks. The inspector also reviewed the root cause

l evaluation which indicated that mishandling was the most likely cause

i for the damage to the secondary contact blocks. Based on the facts

presented in the root cause, the inspector concluded that this root

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cause was the most likely. Proposed corrective actions include: (1)

revise the standard procedure for breaker maintenance during refueling l

outages. SI/0/A/2410/001. Westinghouse DS-416 Air Circuit Breakers l

Inspection and Maintenance, to include a torque limit for the secondary  ;

contact block assembly mounting bolts: (2) to remove and inspect all l

secondary contact blocks on each breaker during each breaker PM: (3) add I

a caution statement to OP/0/A/6350/10. Operation of Station Breakers and l

Disconnects, to note the need for careful handling during breaker

movement to avoid damage to secondary contact blocks and other breakable

parts: and (4) provide two breaker hoists each dedicated to a unit.

versus the existing single shared hoist.

c. Conclusions

The inspector concluded that the licensee's actions to repair damaged

secondary contact blocks on the Unit 1 RTBs and bypass RTBs were

l appropriate. Planned corrective actions were also appropriate.

M1.4 Maintenance Observations

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a. Insoection Scooe (62700)

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l The inspectors observed and reviewed portions of various licensee

corrective and preventive maintenance activities to determine

implementation of administrative controls, plant procedures, work

instructions industry codes and standards. Technical Specifications and

regulatory requirceents.  ;

The inspectors observed portions of the following work activities:

! * WO 96045006-01 Diesel Generator 1A: Pull 4 heads and pistons;

l measure and inspect liners and welds. Remove

j and replace 12 additional heads.

. WO 95053556-01 Component Cooling Water Pump 1A2 Corrective

Maintenance.  ;

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b. Observations and Findinas

The inspectors observed that the licensee had implemented the pro mr

administrative controls in the performance of maintenance. For t1ose

periods of maintenance observed

cleanliness was maintained, tools were

properly calibrated, inventory control logs were maintained, exclusion

of foreign material was implemented, procedures were at the job and

followed, Quality Control personnel were closely following the work, and  !

procedure sign off was performed by both the craft and Quality Control

personnel as steps were performed. Additionally, supervisory oversight

was evident and personnel performing the maintenance were knowledgeable i

in their assigned tasks. I

c. Conclusi ,

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The ins'.;ctors concluded that the licensee has developed and implemented l

adequate maintenance controls to assure reliability of equipment. j

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Eouioment Performance and Availability Monitorina

a. Insoection Scoce (62700) l

The inspectors reviewed plant records and procedures to evaluate the

licensee's activities to maintain equipment reliability. The licensee

monitors equipment performance and availability in several ways. Some

of these methods are: i

e Component Failure Analysis Reports (CFAR) using the Nuclear Plant

Reliability Data System (NPRDS) to compare Catawba performance

with industry averages for specific equipment.

• Failure Analysis Trending System (FATS) using the Work Management

System to obtain equipment maintenance history and maintenance

work order data for trending system / component performance.

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e Maintenance Assessments using maintenance rework items as a

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performance indicator to improve maintenance efficiency and

equipment reliability.

i e Self-Initiated Technical Audit (SITA) using a focused approach to

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highlight 3roblems in a specific area. In this case the Diesel

Generator Recovery Program.

( * Problem Investigation Process (PIP) Reports used to document

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identified plant problems, proposed corrective actions and problem

i resolutions.

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b. Observations and Findinos l

The inspectors reviewed portions of the above documents to evaluate the

l licensee's activities to monitor and maintain equipment reliability.

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The following was noted: l

• CFAR results reported July 1996 indicated that 24 Catawba

components were higher than the industry average. The licensee

reviews the failure history of each of these components for cause l

and corrective action.

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• The FATS quarterly report is the main method for establishing

i adverse equipment trends. In this report the equipment

performance was evaluated over the previous 18 months to detect

adverse trends and the previous 36 months to detect repeat

failures, In the first quarter of 1996, adverse trends were

I identified for pressure switches and battery chargers in the  ;

electrical area and motors. HVAC chillers and diesel engines in 1

the mechanical area. The report provided a description of the i

problem problem significance, explanation of the trend,

corrective action. PIP to track corrective action. Modifications

if required, and the action plan. For instance, for the diesel

generator,19 specific actions were identified.

. Maintenance assessment of rework items was started in March 1995.

Assessment for 1995 has identified problems in several areas. Of

the 120 potential rework events assessed. 74 were confirmed as

rework events. Of the 74 events. 41 or 55% of the total were due

to )oor work practices. These included inadequate self-checking,

lacc of independent verification and skill based discrepancies.

l The assessment made detailed recommendations to improve these

! discrepancies and to focus management attention.

, The assessment also identified strengths in Steam Generator. HVAC.

l and Pipe Support maintenance where maintenance crews had

I recognized and corrected maintenance weaknesses.

The Problem Investigation Process was used to track corrective

actions.

l

• The Diesel Generator Recovery Program was initiated as a result of

l reliability and availability decrease in diesel performance. A

! SITA was performed to identify the problems and the recovery

l 3rogram developed to resolve the problems. Areas such as design

! 3 asis. Maintenance. Operation, and trending were addressed.

1

! . The inspector reviewed PIP 0-C96-0172. initiated for tracking the

i failure of Instrument Air Compressor D motor. The root cause was

! ioentified as a break down of insulation from loss of cooling due

,

to dirt and oil deposits. Thorough corrective action was taken.

Enclosure 2

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,

11

Actions included upgrading the insulation, check of insulation

every 18 months, internal inspection every 36 months, installation

]

of thermocouples and trending of temperature' data,

c. Conclusions  ;

Based on review of portions of the above documents and discussions with

licensee personnel, the inspectors concluded that the licensee was

actively monitoring and evaluating equipment reliability. Adverse

trends were identified and corrective actions initiated. Those actions

reviewed by the inspectors addressed the concerns and were comprehensive

,

in scope.

3

M2.2 Safety-Related Carbon Filter Status

>

a. Insoection Scooe (61726)

"

The inspector reviewed the status of the Unit 1 and Unit 2 safety-

related carbon filters, including the Annulus. Auxiliary Building,

Control Room. Fuel Pool, and Containment Purge Ventilation Systems.

b. Observations and Findinas

On August 1, the 28 Auxiliary Building Ventilation carbon filter unit

failed a TS required bypass leakage surveillance test. After

troubleshooting for approximately three days the licensee re

carbon and surveillance testing was completed successfully. The placed the

'

inspector verified by reviewing methyl iodide penetration test results

that safety-related filters in both units met TS requirements. Carbon

filters such as the 2B auxiliary building unit which are operatad

continuously or have restrictive surveillance test acceptance criteria

have been replaced more often than intermittent duty filters.

Penetration test results showed consistent iodine adsorption ability

relati m to carbon age.

,

c. Conclusion

Sofety-related carbon filters were found to meet TS requirements for

methyl iodide penetration. The licensee was meeting carbon sampling

requirements.

M2.3 Observation of General Material Condition

a. Insoection Scoce (62703)

The inspector conducted a walkdown inspection of Unit 2 to examine

, general housekeeping conditions. In addition, the safe shutdown and

auxiliary shutdown rooms and panels were examined to determine their

material condition and identify any existing deficiencies. The main

transformers and switchyard were also included in the walkdown. Also.

Enclosure 2

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12

I

portions of on-going maintenance work and test activities were reviewed

i that included: (1) installation of optical isolators: (2) control room

area chiller test: and (3) air compressor motor alignment.

b. Observations and Findinas

The housekeeping observed was adequate. The maintenance de)artment was

recently assigned housekeeping responsibility in 1996. In Jnit 2. very

few leaks were identified. The valve stems for MOVs were lubricated and

in good condition. Not all the stems for manual valves and air operated  ;

valves were up to the same standards as the MOVs. The switchyard's  !

relay building and battery rooms were in good condition. The switchyard

disconnect switches were also in good condition as observed from the

ground.

M3 Maintenance Procedures and Documentation

M3.1 Nuclear Service Water System Valve Realianments Durina Liauid Waste

Release

a. Insoection Scooe (61726) 4

On August 13 during Auxiliary Shutdown Panel (ASP) 1B testing, valve

1RN-58B. Nuclear Service Water Loop B Return to Standby Nuclear Service

Water Pond Isolation Valve, and valve 1RN-8438 Nuclear Service Water to

Conventional Low Pressure' Service Water Isolation Valve. were

inadvertently realigned to establish a flowpath to the Standby Nuclear

Service Water Pond. A liquid radioactive waste release was initiated

after the valves had realigned to the pond, and since RN was diverted to

the pond, it was not available to carry the radwaste to the low pressure

servicc water system for discharge to Lake Wylie. The inspector

discussed the occurrence with 31 ant personnel'and reviewed procedures,

system diagrams, the Off-site Jose Calculation Manual and liquid

radiological release package #0336, and PIP 0-C96-2123.

b. Observations and Findinas

The licensee initiated a root cause investigation to determine why the

valves changed position during ASP 1B testing. The root cause

investigation revealed that procedure PT/1/A/4700/14. Retype #0.

Auxiliary Shutdown Panel 1B Functional Test Enclosure 13.9. Control

Room / Auto Closure of 1NI-65B and 1NI-888. was inadequate. Specifically,

the preparer of the procedure failed to recognize that valve.

1RN-58B

,

and 1RN-843B would be affected by the simulation of control transfer

l from the control room to 1ASPB. As a result these valves were omitted

from step 12.3.1 of PT/1/A/4700/14. Step 12.3.1 of PT/1/A/4700/14

listed eight affects of the manipulation of three transfer relays and

, directed the performer to verify that the listed effects would not

adversely affect plant conditions. Since the effects on valves 1RN-58B

and 1RN-843 were not listed, no such verification was made. As a

,

Enclosure 2

~ _ - . - - - . . .- .-. -- --

13

result. the valves repositioned during the test, isolating flow to a

portion of the Nuclear Service Water System that was in service to

support a liquid radioactive release.

l

l The inspector questioned the impact of the valve repositionings on the

liquid radioactive waste release and determined the following:

• The concentrations of radionuclides in the waste stream were such

that dilution flow was not required to comply with the limits

stated in 10 CFR 20. Appendix B. Table 2. Column 2.

• Since flow was isolated to the Nuclear Service Water System

discharge header to Lake Wylie. the liquid radioactive waste may

have collected in the header until the system alignment was

returned to normal. Had the radionuclide concentrations been

i higher, dilution flow requirement may not have been met. The

'

licensee plans to evaluate process controls to ensure that Nuclear

Service Water flow remains available throughout the duration of a

release.

c. Conclusions

The inspector concluded that procedure PT/1/A/4700/14. Auxiliary

l Shutdown Panel 1B Functional Test, was inadequate in that it did not

l specify all components which would be affected by the test. This

procedure inadequacy resulted in valve repositions in the Nuclear

'

Service Water System which isolated flow to a portion of the system

which was supporting a liquid radioactive release and is identified as

Example 2 of Violation 50-413.414/96-13-02: Inadequate Procedures.

l M4 Maintenance Staff Knowledge and Performance

M4.1 Emeraency Diesel Generator Head Reassembiv (62703)

During this inspection the licensee identified a failure to follow

3rocedure problem during reassembly of the diesel generator cylinder

leads per procedure MP/0/A/7400/009. Revision 10. 3/6/89. Diesel Engine

Cylinder Head Removal And Replacement. MP/0/A/7400/009 is a " Reference

!

Use" procedure for which, by Nuclear System Directive (NSD) 704.

Technical Procedure Use and Adherer.ce. Revision No. 3. 9/21/95. the

steps must be followed in sequence unless a deviation is documented.

NSD 704, paragraph 704.6. states that .t is the intent that steps in

" Continuous Use" and " Reference Use" procedures be performed

sequentially where the procedure does not specify flexibility.

Out-of-secuence steps are acceptable only if a deviation is allowed by

the procecure or is made under the following conditions:

. The sequence deviation shall be reviewed by a knowledgeable

supervisor.

4

Enclosure 2

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14

. Out-0f-Sequence steps shall be reviewed and initialed by the

performer and a knowledgeable supervisor prior to performing the

steps. j

. The supervisor shall ensure that a clarifying explanation of why

the deviation was made is documented within the procedure or work

order.

. The supervisor determination should take into account the

i necessity for a procedure change.

l

! Steps 11.3.17 to 11.3.20 of MP/0/A/7400/009 deal with the installation I

l of the intake elbow for the airline from the cylinder head to the air l

l header intake manifold. The procedure specifically requires that the

elbow be installed and torqued to the cylinder head, the head installed.

the elbow aligned to the intake manifold by moving the head, and then l

torque head holddown nuts.

'

i

l The licensee deviated from the secuence of the procedural ste)s by first

installing and torquing the cylincer head before installing t1e elbows i

on 4 cylinders. When this was discovered the condition was corrected by '

removing the cylinder heads and installing the elbow per procedure.  !

l

The licensee stated that, although the machine could be reassembled  !

either way, the purpose for this sequence of steps was to avoid the l

possibility of stressing the elbow while aligning it to a fixed head and l

intake manifold in a cramped space. l

Investigation showed that the su)ervisor had directed the technician to

install and torque the cylinder leads 3rior to installing the elbows on

the heads for four cylinders. The tec1nician and supervisor failed to

annotate the procedure steps and the supervisor did not make a

clarifying statement in the procedure as to why the deviation was

necessary.

The inspector reviewed the circumstances and determined that the

licensee had violated the requirements of NSD 704, paragraph 704.6 in

that the deviation was not properly documented. The situation was

identified by the licensee, was corrected immediately, and had minimal l

safety significance. This licensee-identified and corrected violation '

is being treatet as a Non-Cited Violation, consistent with Section

VII.B.1 of the NRC Enforcement Policy. This issue is identified as Non-

Cited Violation 50-413/96-13-03: Failure To Follow Procedure For

Deviation Of Step Sequence.

4

Enclosure 2

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15' I

i

M7 Quality Assurance in Maintenance Activities

l

M7.1 Imolementation of Self-Assessment Proarams

!

t

i a. Insoection Scoce (40500. 61726. and 62703)

!

The inspector reviewed the implementation of the new maintenance self-

assessment program and portions of the work reduction program initiated

in January 1996. The self-assessment program was reviewed in depth to

l determine the effectiveness of the licensee's controls in identifying.

l -resolving, and implementing corrective action in the maintenance area.

!

b. Observations and Findinos

Self-assessment was part of the licensee's Quality Assurance program and

is described in Section 17.3.3 of the Duke-1 -Topical Report. Corporate

procedure NSD-607. Revision 2. Self-Assessments, was the controlling

l administrative procedure. Procedure MMP 1.14. Revision 0. Maintenance

Self-Assessment Process Guideline, was approved February 29, 1996, for

implementing the program.

The program was comprised of two categories. The first requires

continuous assessment. The second requires assessment on an as-needed

basis. The as-needed includes control of vendors, chemical control,

pre-job briefings, staffing, and procedures used.

l The self-assessment corrective actions are managed in four ways:

(1) Key management issues are major concerns that have a maintenance

i manager assigned as a sponsor to oversee the corrective action:

(2) Focus issues are concerns su3ervisors (foreman) follow for job

! observations and briefings: (3) Rework issues occurring within 90 days

l are identified in the rework program; and (4) Small scope items that

have ownership under a certain individual or crew.

The first two quarter assessments identified several problem areas such

as: (1) Work Practices - adherence to following technical procedures:

(2) Communications - technical procedures have errors and administrative

directives are numerous, overlapping, confused, and sometimes hidden:

(3) Foreign Material Exclusion - housekeeping and foreign material

entering system: (4) Misposition devices continued to be a problem: and

l (5) Rework with pumps, valves, and heat exchangers.

'

The inspector reviewed 10 Problem Investigation Process (PIP) reports to

verify the licensee was implementing approariate and timely corrective

action for the problem areas identified a3ove. Overall, there were:

. (1) four key management issues: (2) two focus items: (3) 16 rework

items: and (4) 43 small scope items addressed in the PIPS listed.

1

.

Enclosure 2

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The license's work order (WO) reduction program has been effective. The

backlog of 1231 in January 1996, was reduced to 429. The backlog for

W0s over six months old has been reduced from 279 to 99 and the W0s over

'

one year have been reduced from 79 to 20 over the same time period in

1996.

c. Conclusion

The maintenance department has implemented an effective self-assessment

program that is detailed and well managed. Problems such as poor work )

3ractices, foreign material exclusion and configuration control have

3een identified and management has sup)orted im)lementing appropriate

corrective action. The work order bacciog has )een significantly

reduced during 1996.

,

III. Enaineerina

El Conduct of Engineering

E1.1 Review of Radioaraohs for Relief Reauest No. 95-01 (Weld No.1RHRB-W3)

a. Insoection Scooe (57090)

On August 22, 1996, the inspectors reviewed the licensee's radiographic

film for Weld No.1RHRB-W3. This review was-conduct because during the

licensee's ultrasonic examination of Unit I residual heat removal heat l

exchanger flange-to-shell circumferential Weld No.1RHRB-W3. two '

directional coverage as required by ASME Section XI. Appendix III and

Section V Article IV as modified by Code Case N-460, could not be

obtained,

b. Observations and Findinas

The causes of the scan limitation were part geometry and physical

barriers. Where possible, a combination of angles and wave modes were

used to maximize the coverage obtained. The weld and base metal at the

component inside surface was covered from at least one direction with a

minimum of one angle. The licensee provided NRC's Office of Nuclear

Reactor Regulation (NRR) an ISI Limitation Report that gave the layout

of Weld 1RHRB-W3. The layout showed flange geometry and bolting limited

ultrasonic scanning: thus precluding examination of approximately 78% of

the weld volume. The licensee proposed using radiography as an

alternate volumetric examination method. However, a modification to the

heat exchanger had to be completed to allow access to the ID surface for

source positioning and the qualification of an acceptable radiographic

technique. The radiographic examination was scheduled to be performed

in the first refueling outage of the Second 10-Year Interval (End of

Cycle 9). Although this examination would be performed after the close

of the first inspection interval. it would enhance the 22% Code-acquired

volumetric examination coverage achieved using ultrasonic techniques.

Enclosure 2

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i I

l

17

NRR Safety Evaluation Report (SER) for Relief Request No. 95-01

concurred with the licensee's proposed alternative examination method.

NRR concluded that, based on the coverage obtained and the radiographic

examination scheduled during the first outage of the second inspection

interval, it was reasonable to conclude that degradation, if present,

would be detected. Thus, reasonable assurance of continued inservice

structural integrity would be provided.

The inspector's review of radiographic film for weld 1RHRB-W3 did not

reveal any unacceptable indications. The inspector also concluded that

the licensee had made the best attempt possible to examine the weld with

radiography. However, 100% volumetric coverage was also not obtained

with this method of examination. The licensee's " Limited Examination

Coverage Worksheet" for this method of examination revealed that out of

i the 258.75 square inches in the inspection volume, a total of 149.15

i

'

square inches (58%) were examined with radiography. The examination

limitation was due to component configuration, which resulted in a

l portion of the weld metal and 100% of the base metal on the flange side

of the weld not being recorded.

c. Conclusion

Based on the licensee's best attempt with a combination of one

directional ultrasonic examination of the weld and base material- 10. as

well as the additional radiographic examination coverage, the inspectors

,

concluded 'that it was reasonable to assume that significant degradation.

l if present, would be detected. Thus, reasonable assurance of continued

l

inservice structural integrity will be provided.

E1.2 Solenoid Valve Nameolate Ratina Less than Instrument Air Desian Pressure

a. Insoection Scoce (37551) 1

The inspector reviewed the u.ain steam isolation valve solenoid valve

application as it related to maximum instrument air system design

pressures.

b. Observations and Findinas

During testing and troubleshooting of main steam isolation valve

actuators discussed in Section E8.3, the licensee identified that the

cause of a previous MSIV stroke time failure was associated with a

malfunctioning solenoid exhaust valve. When an MSIV closure signal is

generated, these solenoid valves function as pilot valves that operate

by spring force to vent pilot air when the solenoid is deenergized.

, This in turn repositions a shuttle valve that exhausts air from the MSIV

! actuator and allows the MSIV to close. During replacement of the

solenoid valves on the Unit 1 actuators, the licensee recognized that

internal springs in the replacement solenoid valves were larger than the

1 existing valves and concluded that the relatively low spring force

Enclosure 2

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18

,

available in the existing solenoid valves may have contributed to the

'

previous stroke time failure.

Subsequent to this troubleshooting, the inspector compared the nameplate

pressure ratings for the solenoid valves to the maximum design pressure

of the instrument air system based on instrument air system relief valve

settings (Flow Diagram CN-1605-1.1). On August 22. the inspector

identified that the nameplate rating of the solenoid valves (100 psi)

was less than the relief setpoints for main air receiver tanks located

at the discharge of the main air compressors (115 psi). The inspector

informed the licensee of this discrepancy and questioned whether normal

o)erating pressures of the instrument air exceeded the design rating of

t1e solenoid valve and if provisions existed for control room operators

to detect an increase in instrument air pressure resulting from a

malfunction of the instrument air system. At the time of identification

this concern only pplied to Unit 2 since Unit 1 was shutdown and the i

Unit 1 solenoid va ves had been refurbished. '

The licensee took actions to measure air pressures locally at the Unit 2

MSIVs and found air pressure at ap3roximately 91 psi. Normal instrument

air pressure at the discharge of t1e air compressors is approximately

100 psi. The 3ressure differential between the air compressors and

MSIVs is attri)uted to air system losses. The licensee also initiated

an increased surveillance of instrument air pressures because no high

pressure alarms were available in the control room. The licensee

performed additional bench testing of the old Unit 1 solenoid valves and

determined that the solenoid valves would function properly above 115

psi with the exception of the solenoid valve assumed to have caused the

1SM-1 stroke time failure. The licensee also obtained vendor

concurrence to operate the valves with air pressures up to 120 psi.

c. Conclusion

The licensee's initial and subsequent actions were adequate to resolve

an NRC identified discrepancy where the nameplate design rating of the

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

instrument air system. This discrepancy is significant because it

resulted in the unrecognized potential to degrade the ability of the

main steam isolation valves to close in the event of an instrument air

system malfunction. This issue is identified as Example 1 of Violation

50-413.414/96-13-04: Inadequate Design Controls (Selection of MSIV

Solenoid Valves.)

l

,

l Enclosure 2

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19

E2 Engineering Support of Facilities and Equipment

E2.1 Main Feedwater Pumo B Trio Durina Unit 2 Startuo

a. Insoection Scooe (37551)

On August 10, during the Unit 2 restart from a forced shutdown, the 2B

main feedwater pump tripped on high discharge pressure while operators

were attempting to place it in service. A Failure Investigation Process

(FIP) team was formed to determine why the pump tripped. The inspector

observed the initial meeting of the FIP team, discussed the issue with

engineering personnel, and reviewed instrument details and Problem

Investigation Process (PIP) report 2-C96-2110.

b. Observations and Findinas

Several indication anomalies associated with the pump trip were noted

during the aump startup and trip. Specifically, control room operators

indicated tlat they did not receive an annunciator for high pump

discharge pressure prior to the pump trip, nor did the control room

indication for pump discharge pressure reach the high discharge pressure

setpoint of 1385 psig. As a result, there was some confusion over the

validity of the pump trip.

According to data obtained from the Operator Aid Computer (0AC), the 2B

Main Feedwater pump discharge pressure closely approached and probably l

reached the pump discharge pressure high setpoint. This indicated that

'

the trip was valid. To explain the anomalies observed by the control

room operators, the licensee began to explore the pump discharge

pressure instruments. The inspector reviewed drawing number CN-1499-

CF1. Revision 8, Instrument Detail for Feedwater Pump Discharge Pressure

and discussed the drawing with engineering personnel to understand how

the indication and control instruments functioned.

Three pum) discharge pressure switches perform a pump trip function on 2

out of 3 ligh discharge pressure signals. Two of these pressure

switches sense process fluid directly. As such, these switches provide

an instantaneous res)onse to changes in pump discharge pressure. The

third pressure switc1 is operated by a pneumatic transmitter. This

pressure switch is not as responsive to changes in pump discharge

pressure. In addition, the same pneumatic transmitter provides the

signal to indicate pump discharge pressure on the control board and to

the high pump discharge pressure annunciator. The OAC data was

transmitted from an electronic transmitter which directly sensed process

fluid.

The B Main Feedwater pump apparently tripped when a short duration

i pressure spike was sensed by the pressure switches which monitor the

! process fluid directly, thereby satisfying the 2 out of 3 trip logic.

! The OAC data were valid, but process limitations introduced a lag in the

i

Enclosure 2

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20

transmission of the pump discharge pressure information to the control ,

board gauge and annunciator. As a result, the control indications were j

l

consistent with the conditions in the plant and the pump trip was valid. 4

The FIP team concluded that a combination of factors caused the B Main

Feedwater aump discharge pressure to reach the Jump trip setpoint.

l Steam for iain Feedwater pump operation while t1e associated unit is

offline is typically provided from the other unit. Since Unit 1 was in

l a refueling / steam generator replacement outage, steam was provided by an

,

auxiliary boiler. The FIP team concluded that the combination of

l supplying auxiliary steam from a single auxiliary boiler and relatively

rapid increases in pump speed demand by the control room operator caused  ;

the speed to overshoot, causing the high discharge pressure. 1

The FIP has recommended that two auxiliary boilers be used to supply

steam to the main feedwater pum) turbines in future unit start-ups

occurring when both units are slut down An extended time for steam

piping and turbine chest warming was also proposed. Operator monitoring

of steam pressure at the low pressure steam admission valve to the main

feedwater pump turbine during pump starts was identified as an

additional potential corrective action.

c. Conclusions

'

The inspector concluded that the licensee's actions to determine the

root cause of the 28 main feedwater pump trip, and evaluate the

l indication anomalies observed by the operators were timely and

,

appropriate. Proposed corrective actions addressed the apparent cause

l

identi fied.

E2.2 Enaineerina Sucoort of Facilities and Eauioment - Modifications

a. Insoection Scooe (37550)

The inspector reviewed several Nuclear Station Modifications (NSMs)

implemented during the current Unit 1 outage. The modification review

included verification that design control requirements of Regulatory

l Guided 1.64 and ANSI N45.2.11-1974. Quality Assurance Requirements for

i the Design of Nuclear Power Plants, and licensee procedures were

implemented. Elements of the design process reviewed included post

!

modification testing, procurement, procedure revision, training, 50.59

safety evaluation, and field verification of plant hardware changes as

applicable. The following NSMs were reviewed:

• CN-11360. Diesel Generator Battery Charger Replacement

! * CN-11375. Upgrade Allowable Temperature for Some Auxiliary

Feedwater (CA) System Piping

i

-

Rian 8%Ws f CA System F w pt miz t n nd Run-out

Enclosure 2

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21

. CN-11372, Revise Run-out Setpoints for Component Cooling (KC)

l System Single Pump Operation

b. Observations and Findinas

The following modifications were implemented to resolve long-standing ,

i

equipment problems at Catawba:

l

. The DG battery chargers were replaced (CN-11360) to resolve a

reliability concern with the previous chargers related to the

impact of ambient temperatures on charger performance. The

purchase specification recuired vender testing to verify the new

chargers were not impactec by the anticipated DG room ambient

temperature transients.

. Piping supports for portions of the Auxiliary Feedwater system

were modified (CN-11375) to allow increasing the piping allowable

temperature.

. The Auxiliary Feedwater flow optimization and run-out protection '

circuit deletion (CN-11371) was to com3ensate for the changed

Auxiliary Feedwater operating system claracteristics associated

with the new steam generators.

. Future run-out protection was to be provided by mechanical stops

on the Auxiliary Feedwater pump flow control valves.

. The Component Cooling water pump run-out setpoint change (CN-

11372) was to permit single pump operation of the Component

Cooling system for normal plant conditions. Singic pump operation

would allow the pumps to operate at an optimum condition with

reduced vibration ar.J impeller wear.

Post modification testing performed and scheduled was adequate to verify

equipment and system function following the modifications. Appropriate

procedures were revised and adequate training was scheduled or completed

for the",e modifications. The licensee's 50.59 safety evaluations were

detailed and adequately justified the conclusions. An outstariding issue

from a previous NRC inspection remains open related to the 50.59

evaluation for the Auxiliary Feedwater piping temperature upgrade.

Procurement documentation demonstrated that the appropriate quality

level material was used for installed equipment and materials. Field

verification for the Auxiliary Feedwater piping supports and the DG

chargers demonstrated that equipment installation was consistent with

,

the Nuclear Station Modification requirements.

l

c. Conclusion

l Several Unit 1 modifications were implemented during the outage to

resolve existing equipment problems and improve plant reliability. The

l Enclosure 2

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22  ;

modifications demonstrated appropriate control of the design control l

process at Catawba. For the safety evaluations reviewed. the  !

requirements of 50.59 were met.

E2.3 Main Feedwater Pioino Erosion / Corrosion 1

a. Insoection Scoce (37551) l

During the Unit 1 Steam Generator Replacement Outage, the licensee

identified erosion / corrosion of a localized area in the main feedwater

piping between the check valves and isolation valves in the doghouses.

The licensee requested approval of ASME Code Case N-480 to allow for

planned replacement of some of the affected piping during the next

refueling outage. The inspector reviewed the erosion / corrosion

inspection data and PIP 0-C96-1963.

b. Observations and Findinas l

With the approval of the ASME Code Case N-480. the licensee performed

evaluations to support operation until the next refueling outage for two

of the four feedwater lines on Unit 1. One line was degraded to the

point that a repair was performed and the remaining line was acceptable

"as is." During the forced outage on Unit 2 erosion / corrosion

inspections of similar locations were performed with acceptable results.

NRC approval to implement ASME Code Case N-480 was required prior to ,

restart of Unit 1. This approval was received in a letter dated i

September 9. 1996,

c. Conclusions

The inspector concluded that the erosion / corrosion program was effective

in identifying this issue and an appropriate decision was made to

inspect Unit 2 for similar conditions at the first available

opportunity.

E3 Engineering Procedures and Documentation

E3.1 1995 Revision to the Uodated Final Safety Analysis Reoort

By letter dated May 28. 1996, the licensee submitted the 1995 revision

to the Updated Final Safety Analysis Report (UFSAR) in accordance with

10 CFR 50.71. This regulation requires that this submittal shall

contain all the changes necessary to reflect information and analyses

submitted to the Commission by the licensee or arepared by the licensee

pursuant to Connission requirement since the su3 mission of the original

FSAR or, as appropriate. the last updated FSAR.

l

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[- 23

a. InsDection ScoDe

10 CFR 50.71 provides that the updated FSAR shall be revised to include

the effects of

• "All changes made in the facility or procedures as described in

the FSAR."

e " Safety evaluations performed by the licensee either in support of

requested license amendments. . . ." - Since this category clearly

involves NRC staff approval of licensing basis changes, other

changes that the staff approved (e.g., topical reports, reliefs to

ASME Code sections, exemptions, etc.) but were not conveyed as

amendments are also implied.

"

....or in support of conclusions that changes did not involve an

unreviewed safety question" - These are evaluations performed by

the licensee in accordance with the provisions of 10 CFR 50.59.

. "All analyses of new safety issues performed by or on behalf of

the licensee at Commission request" - Examples include licensee

actions as a result of generic letters, bulletins, etc.

b. Observations and Findinas

The inspector reviewed the 1995 revision of the Catawba UFSAR in-office

and met with licensee personnel on-site. The purpose of the review was

to confirm if the changes made in the 1995 revision comply with the

provisions of 10 CFR 50.71. The inspector reviewed the changed pages to

confirm that all changes'were appropriately addressed by licensing

actions. 10 CFR 50.59 reports, or regional inspection activities.

The inspector traced the changes in the 1995 revision of the UFSAR to

documents in the official NRC records such as amendments to the

operating license, staff letters transmitting safety evaluations, annual

10 CFR 50.59 reports submitted by the licensee, inspection reports, or

licensee letters. The inspector confirmed that the 1995 revision does

not constitute a source of initial communication (to NRR) of these

changes.

The inspector noted that some UFSAR changes made under 10 CFR 50.59

appeared to have not been reported in the periodic update submitted

immediately after the changes were made. Examples include CN-50422. CN-

50431. CE-3604. CE-3605, and CE-60212. The licensee should review the

circumstances involved and determine the cause of the delayed update.

The inspector noted that the licensee had performed the required

analyses in accordance with 10 CFR 50.59 and concluded that the

apparently late reporting of some changes was not a violation of

regulatory requirements.

I

Enclosure 2

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The inspector noted that UFSAR Section 13.1 regarding the licensee's

nuclear organization, had been revised. The licensee had not performed

an evaluation in accordance with 10 CFR 50.59. or sought prior staff- l

a) proval. The inspector reviewed the changes and determined that the j

clanges do not reduce the organizational resources committed to r/ lear i

safety and are therefore acceptable. In an August 20, 1996, meeting, j

the licensee stated that it planned to institute an internal procedure

to ensure that such changes receive sufficient evaluation in the future.

c. Conclusion

The inspector concluded that the 1995 revision of the Catawba UFSAR

matched the provisions of 10 CFR 50.71. and is therefore in compliance

with 10 CFR 50.71.

E4 Enaineerina Staff Knowledae and Performance

E4.1 Standby Shutdown System (SSS) Ooerability

a. Insoection Scooe (92903)

The inspector reviewed the licensee's activity to resolve a recently ,

identified issue related to the operability of the SSS. )

1

b. Observations and Findinas

During an inspection of the SSS on July 8-12. 1996, (NRC Inspection

Report 50-413.414/96-10) an NRC inspector noted non-conservative

assumptions / design inputs in calculation CNC 1223.04-00-0009, Standby i

Make-up Pump (SMUP) Sizing, dated November 1,1993. Discussions with  !

the licensee indicated these incorrect assumptions did not impact the

calculation conclusion that the SMUP was operable for the required

72-hour period of an SSS' event. Further review by the licensee after

the inspection determined that the design input errors did impact the

calculation conclusion, resulting in an operability concern for both

Units 1 and 2 SSS. Problem Investigation Process Report (PIP) 0-C-96-

1824 was initiated by the licensee on July 18, 1996, to address this

issue.

The calculation included the following errors:

• Incorrect determination of Spent Fuel Pool (SFP) Inventory: boil

off not included

. Incorrect pump speed

. Incorrect SFP (cycle specific) temperature

Enclosure 2

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• Design minimum pump flow rather than actual flow used for SFP

inventory reduction

The significant error was the temperature value used for the SFP which

provided the water source for SMUP to the reactor coolant pump seals.

The temperature was derived from a heat up rate based on pool loading of

spent fuel that was specific to a past cycle on Unit 2. -This

temperature value would not be appropriate for any other pool loading.

A calculation revision in November 1993 reviewed the SMUP suction

pulsation danpener based on these past cycle conditions and concluded

that the dampener (and SMUP) was operable for the required 72-hour

period. The dampener's function is to assure adequate net positive

suction head (NPSH) for SMUP operation. The licensee's recent

evaluation initiated by PIP 0-C-96-1824. determined that the dampener

(and SMUP) operability could not be assured near the end of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ,

period.

At the time that the operability concern was identified. Unit 2 was at

power and Unit 1 was in an extended outage for steam generator

replacement. The licensee determined that the Unit 2 SSS was operable

but degraded and Unit 1 SSS was inoperable. Unit 1 SSS was not required

to be operable until entering mode 3.

The Unit 2 SSS degraded operability determination was based on analysis

and imposition of more limiting SFP temperature requirements. The

analysis was provided by Calculations CNC 1201.30-00-0019, Catawba Unit

2 SFP Decay Heat and Temperature Calcuiction for PIP 0-C96-1824, dated

July 24. 1996, and CNC 1223.04-00-0069, Unit 2 Cycle 8 SMUP NPSH l

Requirements for PIP 0-C96-1824. dated July 24. 1996. The SFP decay

heat calculation determined that with an initial SFP temperature of

125 F and the current Unit 2 SFP load, the SFP temperature would be

aaproximately 181 F. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after the initiation of an SSS event. The i

SiUP NPSH calculation determined that at 181 F, adequate NPSH was

available to the SMUP, assuming the suction dampener was inoperable.

The licensee established controls to assure that the SFP temperature was

maintained less than 125 F. The SFP temperature alarm was reset to

115 F (included a 9 F instrument error) and increased operations

surveillance for SFP temperature monitoring. The normal summer

temperature range of the SFP was 100-105 F. The inspector reviewed the

calculations and verified the correct design input values were used.

The above actions were immediate corrective actions to establish Unit 2

SSS operability for the current fuel cycle. Long-term corrective

actions were being evaluated and will include resolution of the Unit 1

SSS operability prior to restart of the unit.

c. Conclusion

The licensee's immediate corrective actions were adequate to resolve

present operability concerns on Unit 2. The licensee failed to identify

Enclosure 2

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1 the design input errors in Calculation 1223.04-00-0009 on two occasions:

i first during the independent review of the calculation in November 1993,

and again during the licensee's SSS pre-inspection self-assessment in

June 1996. This issue is identified as Example 2 of Violation 50-

413.414/96-13-04. Inadequate Design Controls (Standby Shutdown System

Make-up Pump Sizing Calculation.)

E8 Hiscellaneous Engineering Issues

E8.1 Safety-Related Loaic Circuits Testina Discreoancy

-

a. Insoection Scooe (37551)

The inspector reviewed the licensee's response to their finding that the

.

'

testing of the degraded voltage and undervoltage logic on the DG load

sequencer had been insufficient. The licensee's finding was in response

to the review of safety-related logic circuits required by Generic

Letter (GL) 96-01. " Testing of Safety-Related Logic Circuits."

b. Observations and Findinas

During the review of the safety-related logic circuits required by GL 96-01, the licensee discovered that part of the logic circuits for the

degraded voltage and undervoltage relays for the emergency diesel

generator load sequencer logic circuits were not being tested

completely. This logic is a 2 out of 3 logic circuit. Portions of the

logic circuit were not verified during surveillance testing in that not

all possible combinations of logic were tested. This resulted in

portions of circuitry not being verified operable during each

surveillance cycle. The licensee documented this issue in PIP 0-C96-

2015.

Both Units 1 and 2 were affected by this testing deficiency: however,

both Units were shutdown at the time of discovery. The licensee's

corrective action was prepration and completion of revised testing

which would satisfy the testing requirements for the logic circuitry.

Procedure IP/2/A/4971/075A Logic Testing for Degraded Bus and Load

Sequencer Voltage Circuits was completed to satisfy the testing

requirements. The inspector reviewed this test procedure and found that

it adequately resolved the testing concern. The licensee planned to

complete this testing for both Units 1 and 2 prior to restart.

c. Conclusions

Licensee identification of this test deficiency met the intent of

Generic Letter 96-01 and corrective actions were appropriate.

Enclosure 2

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E8.2 Temocrary Station Modification Audit Proaram (92903) l

(Closed) Violation 50-413.414/94-30-01. Inadequate Corrective Action for

Temporary Station Modification (TSM) Program Deficiency. This item 1

addressed the licensee's failure to correct a TSH program deficiency '

related to periodic audits of active TSMs. The licensee identified that

several monthly audits required by procedure were not performed. After i

the completion of the corrective actions, an NRC inspector reviewed the l

TSM program and identified approximately 30 active TSMs which were not l

included in the previous audit. This demonstrated that the licensee's

original corrective actions were not adequate. The licensee's

corrective action for the violation was to revise the TSM audit process

to. incorporate increased management oversight and increase guidance for

the audit process. The inspector reviewed the June 1996 quarterly TSM

audit and verified that all active TSMs were included. The inspector

concluded that the licensee adequately resolved the TSM program

deficiency related to periodic audits. 1

E8.3 Main Steam Isolation Valve 1SM-1 Reoortability Evaluation (92903) I

(Closed) Unresolved Item 50-413/96-02-05. Review of MSIV 1SM-1

Reportability Evaluation and In-Plant Review of PIP Initiation

Performance. During this inspection aeriod the licensee completed the

Reportability Evaluation and troubleslooting for the stroke time failure

of Main Steam Isolation Valve 1SM-1 (refer to PIP 1-C96-0751). Results

of testing performed during the current 1E0C9 refueling outage

determined that the cause of the stroke time failure was due to an

intermittently malfunctioning B-train exhaust solenoid valve. Based on

the test results, the licensee plans to submit an LER. The inspector ,

reviewed the results of the licensee's in-plant review of PIP initiation i

during test activities (Report No. SA-96-41(CN) (SRG). PIP 0-C96-1759).

The licensee's audit consisted of the review of approximately 150

completed test procedures and other records. The review concluded that

PIPS are being initiated to assess systems / components that do not meet

test acceptance criteria. The review recommended enhancements to NSD

208. Problem Investigation Process, to clarify references for PIP

initiation. The inspector concluded from this review that the failure

to initiate PIPS in response to test failures is not a programmatic

concern.

IV. Plant SuoDort

R1 Radiological Protectior.' and Chemistry Controls

R1.1 Individual Escorted into Radiation Control Area

a. Insoection Scooe (71750)

On July 19. 1996, a contractor employee escorted his spouse into the

Radiation Control Area during a plant tour. A radiation protection

Enclosure 2

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technician in u)per containment questioned their need to enter that area

and requested tlat they leave. While exiting the Radiation Control Area

a second radiation protection technician questioned the absence of l

appropriate dosimetry and recognized the unauthorized access. Problem

Investigation Process (PIP) Report 1-C96-1837 was initiated to address

the issue. A root cause analysis was performed by the licensee because

station management recognized the similarity of this occurrence to an '

issue in October 1995. The inspector reviewed the PIP and its l

associated root cause, discussed the issue with the contractor employee. '

and reviewed the circumstances of the previous occurrence documented in

NRC Inspection Report 50-413.414/95-22.

b. Observations and Findinas

While in the Radiation Controlled Area, the individuals remained

together, did not enter any high radiation areas, and had one electronic

dosimeter which was operating. The electronic dosimeter registered no

exposure during the entry.

1

The inspector noted that the previous occurrence was characterized as a  !

non-cited violation (NCV 50-413,414/95-22-03) since it was identified by i

the licensee, was apparently an isolated case, and appropriate

'

corrective actions were initiated.

The recent issue was also identified by the licensee and appropriate

actions were taken by radiation protection personnel to question,

identify, and document the occurrence. Appropriate sensitivity to the

issue was demonstrated by the performance of a root cause evaluation

which identified expanded proposed corrective actions.

Conclusioilg

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c.

The unauthorized entry of an individual into the Radiation Control Area

without appro]riate dosimetry, training, or body burden analysis is a i

violation of Radiation Protection Directive No. II-1, Radiation Area

Access and Monitoring Devices. Since corrective actions for a previous.

similar occurrence were not effective in preventing recurrence, this

issue is identified as Violation 50-413.414/96-13-05: Repeat Radiation

Control Area Entry Without Dosimetry.

1

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors ] resented the inspection results to members of licensee l

management at tie conclusion of the inspection on September 16, 1996. The ,

licensee acknowledged the findings presented. No proprietary information was

identified. l

Enclosure 2

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

!

Bhatnager. A. Operations Superintendent

Coy. S. Radiation Protection Manager ,

Eller. R., Licensing Specialist i

Forbes, J. , Engineering Manager .

Funderburk. W. , Work Control. Superintendent j

Hallman.-W., Project Director. SGRP

Harrall. T.. IAE Maintenance Superintendent

Kelly..C... Maintenance Manager

Kimball. D.. Safety Review Group Manager

Kitlan, M., Regulatory Compliance Manager

Lowery J., Compliance Specialist

McCollum. W. Catawba Site Vice-President

Nicholson. K., Compliance Specialist

Parker. R., Manager. Inage

Patrick, M. , Safety Assurance Manager

Peterson G., Station Manager

Propst. R., Chemistry Manager

Rogers. D., Mechanical Maintenance Manager

Rose. I., Manager. Workforce Processing

Self. T. , Maintenance Supervisor

Tower. D.. Compliance Engineer

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Enclosure 2

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{

INSPECTION PROCEDURES USED

IP 37550: Engineering

IP 37551: Onsite Engineering

IP 40500: Effectiveness-of Problem Identification and Prevention

IP 57090: NDE Procedure Radiographic Exam. Procedure Review

IP 61726: Surveillance Observation

IP 62700: Maintenance Program Implementation

IP 62703: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 92903: Followu) - Engineering

IP 93702: Onsite Response to Events

ITEMS OPENED, CLOSED. AND DISCUSSED

Onened

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50-414/96-13-01 NCV: Failure to Report Inoperability of Both

Trains of Auxiliary Building Ventilation (Section

01.1).

50-413, 414/96-13-02 VIO: Inadequate Procedures (Sections 01.2. M3.1).

50-413/96-13-03 NCV: Failure To Follow Procedure For Deviation of -

Step Sequence (Section M4.1). -

50-413.414/96-13-04 VIO: Inadequate Design Controls for (1) Standby j

Shutdown System Make-up Pump Sizing Calculation, and 1

(2) Selection of MSIV Solenoid Valves (Sections E4.1 l

and E1.2).  ;

'

50-413.414/96-13-05 VIO: Repeat Radiation Control Area Entry Without

Dosimetry (Section R1.1). ,

Closed

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50-413.414/94-30-01 VIO: Inadequate Corrective Action for Temporary  ;

Station Modification Program Deficiency (Section

E8.2). 3

50-413/96-02-05 URI: Review of MSIV 1SM-1 Reportability

Evaluation and In-Plant Review of PIP Initiation

Performance (Section E8.3).

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Enclosure 2  !

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i

LIST OF ACRONYMS USED

1

ANSI - American Nuclear Standard Institute

ASME - American Society of Mechanical Engineers

Auxiliary Shutdown Panel

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ASP -

CA -

Auxiliary Feedwater System

CFAR -

Component Failure Analysis Report

CFR -

Code of Federal Regulations

CNS -

Catawba Nuclear Station i

CR -

Control Room

DG -

Diesel Generator

DPC -

Duke Pts:er Company

EOC -

End of Cyck

• F -

degrees Fahrenheit

FATS - Failure Analysis Trending System

GL -

Generic Letter

HVAC - Heating. Ventilation, and Air Conditioning

IAE -

Instrument and Electrical

ID -

ID Inner Diameter i

IFI -

Inspector Followup Item

IR -

Inspection Report

KC -

Component Cooling

LER -

Licensee Event Report

MOV -

Motor Operated Valve

MSIV - Main Steam Isolation Valve

, NDE -

Non-Destructive Examinations

l NPRDS - Nuclear Plant Reliability Data System

'

NPSH - Net Positive Suction Head

NSD -

Nuclear System Directive

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NSM -

Nuclear Station Modification

'

OOS -

Out-of-Service

l PIP -

Problem Investigation Process

PM -

Preventive Maintenance

l PORC - Plant Operations Review Committee

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RG -- Regulatory Guide

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RHR -

Residual Heat Removal

RN -

Nuclear Service Water System

RTB -

Reactor Trip Breaker

SFP -

Spent Fuel Pool

SGRP - Steam Generator Replacement Project

SITA - Self-Initiated Technical Audit

l SMUP -

Standby Make-up Pump

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SSS -

Standby Shutdown System

TSM -

Tem)orary Station Modification

TS -

Tec1nical Specifications

UFSAR - Updated Final Safety Analysis Report

URI -

Unresolved Item

VC/YC - Control Room Ventilation and Chilled Water Systems

VIO -

Violation

WO -

Work Order

Enclosure 2

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