ML20210N734

Insp Repts 50-413/97-09 & 50-414/97-09 on 970608-0719. Violations Noted.Major Areas Inspected:Aspects of Licensee Operations,Maint,Engineering & Plant Support

ML20210N734
Person / Time
Site:	Catawba
Issue date:	08/18/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20210N708	List: ML20210N703 ML20210N711 ML20210N734
References
50-413-97-09, 50-413-97-9, 50-414-97-09, 50-414-97-9, NUDOCS 9708260105
Download: ML20210N734 (32)

See also: IR 05000413/1997009

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Notice of Violation

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withholding of such material, you muit tpecifically identify the portions of

your response that you seek to have witkield and provide in detail the bases

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for your claim of withholding (e.g., explain why the disclosure of information

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will create an unwarranted invasion of personal privacy or provide the

confidential commercial or financial information).

If safeguards information

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1s necessary to provide an acceptable response, please provide the level of

protection described in 10 CFR 73.21.

Dated at Atlanta, Georgia

this 18th day of August, 1997

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Enclosure 1

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U. S. NUCLEAR REGULATORY COMMISSION

REGION 11

Docket Nos:

50-413, 50 414

License Nos:

NPF-35. NPF-52

Report Nos..

50-413/97 09. 50 414/97-09

Licensee:

Duke Power Company

Facility:

Catawba Nuclear Station. Units 1 and 2

Location:

422 South Church Street

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Charlotte. NC 28242

Dates:

June 8 - July 19, 1997

Inspectors:

J. Zeiler. Acting Senior Resident inspector

R. L. Franovich, Resident inspector

M. Giles. Resident inspector (In Training)

N. Economos Region 11 Inspector (Sections M8.1. 2. 3. 4)

R. M. Moore. Region 11 Inspector (Sections 08.1. E2.1 )

Approved by:

S. M. Shaeffer. Acting Chief

Reactor Projects Branch 1

Division of Reactor Projects

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Enclosure 2

9708260105 970818

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ADOCK 05000413

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EXECUTIVE SUMMARY

Catawba Nuclear Station. Units 1 & 2

NRC Inspection Report 50 413/97-09, 50 414/97 09

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.

Doerations

A Non Cited Violation (NCV) was identified for failure to declare three

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ice condenser intermediate deck doors inoperable and log an associated

Technical Specification Action item Log entry after identifying ice

buildup on the doors.

This item along with several other minor human

performance weaknesses indicated a need for greater attention to detail

and questioning attitude by operations personnel during the performance

of routine activities (Section 01.1).

The root cause evaluations of a reactor coolant pump trip and subsequent

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reactor trip were adequatel

involve human error or non y performed. The cause of the trip did not

conservative decision making.

The protective

relaying associated with the short bus of 2TB functioned as designed.

However, a delay in troubleshooting activities to locate the source of

the associated ground indicated that the ground received a low priority

status in the work schedule and that trained personnel were not readily

available to troubleshoot ground indications in a timely manner (Section

w.2).

Control room operators were effective in precluding a turbine runback by

reducing reactor power to 50% before the 28 Main Generator Power Circuit

Breaker opened on low air pressure.

The licensee's root cause

evaluation was detailed, and actions to prevent recurrence were

considered adequate (Section 01.3).

The decision to deviate from the preferred normal alignment of

Lower Containment Ventilation Unit (LCVU) operation to support

planned maintenance exhibited non-conservative work scheduling and

operatorjudgement.

This resulted in lower containment air

temperature increasing slightly above the adjusted Technical

Specification limit for a brief period of time.

The LCVU

operating procedures did not address the adverse impact of

removing two LCVUs from service simultaneously, nor did the

procedure address the interaction between LCVU operation and

integrated containment ventilation systems.

These procedural

inadequacies were identified as a NCV (Section 01.4).

A violation (first example) for failure to follow procedure was

identified related to Operations failure to adequately document 10 CFR 50.59 screening evaluations (Section 08.1).

Enclosure 2

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Maintenance

A Failure In!estigation Process (FIP) team was thorough in investigating

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the cause of an electrical flash in a 600 Volt breaker cubicle

associated with Motor Control Center 2MXM. The root cause indicated

configuration and procedure weaknesses in the method of locking out 600

Volt breaker cubicles to the maintenance position.

Adaquate corrective

actions to prevent recurrence of this incident were implemented (Section

M1.1).

The licensee's identification of a technician's failure to follow a leak

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rate test procedure that resulted in an invaild test of valve 2NV-874

during the previous refueling outage was an example of good questioning

attitude: however, the procedure completion review was untimely.

The

Plant Operations Review Committee performed a thorough review of

subsequent activities to aroperly retest the valve.

Good engineering

support was arovided, bot 1 in developing a leak rate test procedure and

briefing paccage for the evolution.

The failure to follow the leak rate

test procedure was identified as a Violation (Section M1.2).

Enaineerina

The licensee's identification of a discrepancy between primary and

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secondary thermal power indication exhibited attention to detail in the

review of plant data.

Actions to initiate a FIP team to investigate the

root cause were appropriate and steps to reduce reactor power until the

discrepancy was understood were conservative.

Replacement of a faulty

T,,, card was well-planned, coordinated and controlled and executed in

an expediticas manner (Section El.1).

Resolution of Design Base Document (DBD) open items was generally

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adequate.

However, a violation (second example) for failure to follow

procedure was identified related to Engineering's failure to enter DBD

open items into the Problem identification Process as required by

procedure and stated in the licensee's response to the Des'.gn Basis

50.54f letter (Section E2.1).

The licensee's corrective action audit that assessed the resolution of

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Self-N iated Technical Audit findings was identified as a strength in

correc " ve action performance (Section E2.1).

The licensee adequately addressed the Emergency Diesel Generator 10 CFR

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Part 21 issue related to potentially defective intake / exhaust springs

(Section E2.1).

Based on in-office review of the licensee *s March 31, 1997, annual

summary on 10 CFR 50.59 changes, onsite review of the licensee's 10 CFR 50.59 evaluations, and audit of the licensee's procedures, the inspector

concluded that the licensee had complied with t1e provisions of the

regulation for the changes listed in the annual summary (Section E3.1).

Enclosure 2

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Plant Suncort

Radiological control practices observed during the inspection period

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were considered to b(. proper (Section R1.1).

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Enclosure 2

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Reoort Details

Summary of Plant Status

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Unit 1 operated at or near 100% power during the inspection period.

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On June 26, a Unit 2 reactor trip occurred on low Reactor Coolant System loop

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flow as a result of an electrical ground fault which de energized the

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electrical bus that powers the "2B' Reactor Coolant Pump (RCP).

The unit was

returned to 100% power operation on June 29.

Power was reduce 1 to 50% on July

2 to preclude a turbine trip / reactor trip u)on the anticipated failure of

Main Generator Power Circuit Breaker (PCB) 23.

A solenoid (or pilot) valve

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associated with the air supply to all three main generator PCB poles had

failed, rendering the air system unable to deliver air to the breaker. The

solenoid valve was replaced, and the unit was returned to 100% power the

following day.

Reactor power was reduced to 99.3% on July 15 in response to a

discrepancy between primary and secondary thermal power indications.

The

discrepancy was attributed to feedwater venturi defouling and hot leg

streaming, and did not reflect an actual temperature difference. The unit

returned to 100% power on July 17 and operated at or near 100% power for the

remainder of the inspection period.

Review of UDdated Final Safety Analysis Report (UFSAR) Commitm_gn_t1

While performing inspections discussed in this report, the inspector reviewed

the applicable portions of the UFSAR that were related to the areas ins)ected.

The inspector verified that the UFSAR wording was consistent with the o) served

plant practices, procedures, and/or parameters.

I. Operations

01

Conduct of Operations

01.1 General Comments (71707)

The inspector conducted frequent control room tours to verify proper

staffing operator attentiveness and communications. and adherence to

approved )rocedures.

The inspector attended daily operations turnover

and Site )irection meetings to maintain awareness of overall plant

operations.

Operator logs were reviewed to verify operational safety

and compliance with Technical Specifications (TS).

Instrumentation,

computer indications, and safety system lineups were periodically

reviewed from the Control Room to assess o)erability.

Plant tours were

conducted to observe equipment status and

Jousekeeping.

Problem

Identification Process (PIP) reports were routinely reviewed to assure

that potential safety concerns and equipment problems were reported and-

resolved,

in general, the conduct of operations was professional and safety

conscious. Good )lant equipment material conditions ar.d housekee ing

were noted througaout the report period.

However, as addressed b low,

sevcral minor operator human performance deficiencies were identified

Enclosure 2

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involving a failure to enter a TS Action Statement, failure to identify

equipment status anomalies, and failure to properly document a Technical

Specification Action item Log (TSAIL) entry.

Failure to Declare Unit 2 Ice Condenser Intermediate Deck Doors

inoDerable and Enter ADolicable TS Action Statement

On June 17 at 2:38 p.m., while performing the weekly TS surveillance on

the intermediate deck doors the licensee identified that three doors

had ice buildup (reported to be less than one half inch thick). The

function of these doors is to open during a des.gn basis accident to

ensure that the containment loss Of Coolant Accident (LOCA) atmos)here

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would be diverted through the ice condenser.

Upon discovery of t1e ice,

a test procedure discrepancy was entered and a work request was

initiated to remove the ice.

However, work to remove the ice or

investigate the extent of the impact on the door opening function was

not initiated due to problems with personnel accessing containment

through the containment airlock door.

Later that night, the oncoming

Shift Work Manager became aware of the previces day's problem and

-contacted engineering personnel to perform an operability evaluation of

the condition.

The following morning, the inspector reviewed the

results of this evaluation.

The evaluation concluded that the " ice

condenser" was operable.

This was based primarily-on a previous McGuire

Nuclear Station analysis that showed up to one-third of the intermediate

deck doors could fail to open and there would still be enough ice

condenser flow area for LOCA heat removal.

The inspector determined the

evaluation focused to narrowly on the ice condenser system operability

and failed to adequately evaluate the operability of the intermediate

deck doors, especially with regard to consideration of information in

the applicable TS and Bases.

TS 3.6.5.3 requires the intermediate deck doors be operable in Modes 1-

4.

TS Surveillance Recuirement 4.6.5.3.2 requires a 7-day verification

that the intermediate ceck doors be closed and free of frost

accumulation.

The TS Bases also states that impairment by ice, frost.

or debris is considered to render the doors inoperable, but capable of

opening.

Based on this, the inspector concluded that operations

personnel had failed to declare the three doors inopera]le and follow

the Action Statement of TS 3.6.5.3.a when the problem was initially

identified. This action statement allowed power operation to continue

for up to 14 days provided ice bed temperature was monitored at least

once per four hours and the maximum ice bed temperature was maintained

less than or equal to 27*F.

The licensee initiated PIP 2-C97-2014-to

investigate this incident.

On June 18. after repairing the containment airlock, ice was removed

from the three intermediate deck doors.

The cause of the ice buildup

was found to be the failure of heat tracing on an ice condenser air

handling fan drain line, which prevented adequate draining of defrost

condensate. The heat tracing was subsequently repaired. The licensee

Enclosure 2

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determined during activities to remove the ice that all three doors were

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not blocked to the extent that would have prevented their opening during

a LOCA.

The inspector also noted that the ice bed monitoring system was

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operational during the period that ice was on the doors and control room

annunciator alarms would have alerted the operators of anomalous ice bed

temperatures. Therefore, the ins)ector considered the safety

consequences of this incident to )e minimal.

The inspector reviewed Operations Management Procedure (OMP) 2-29.

Technical Specifications Action Item Log. Step 3.4 requires that non-

compliance with a Limiting Condition For Operation requiring operation

in a TS Action Statement, be logged in TSAll.

The ins)ector determined

that a TSAll entry was not logged for this condition w1en ice was

identified on the doors rendering them inoperable.

The failure to

declare the doors inoperable and enter a TSAll entry for t % applicable

TS Action Statement in accordance with OMP 2-29 was identitied as a

Violation of TS 6.8.1. Procedures and Programs. This failure to follow

procedures constitutes a violation of minor significance and is being

treated as a Non-Cited Violation (NCV). consistent with Section IV of

the NRL Enforcement Policy. This item is identified as NCV 50 414/97-

09 01:

Failure to Declare Ice Condenser Intermediate Deck Doors

Inoperable and Log Appropriate TSAll Entry.

Auxiliary Shutdown Panel Volume Control Tank (VCT) Instrumentation Drift

During a walkdown of the four Motor Driven Auxiliary Feedwater Shutdown

Panels, the inspector identified that three of the four VCT level

indications were not reading accurately.

There is one VCT gauge on each

Shutdown Panel. Gauge indications differed from control room

indications by as much as 20 percent level.

The ins)ector alerted

operations-personnel to-the problem and noted that t1ey were very

responsive in initiating corrective actions.

Due to subsequent problems

in calibrating the gauges and unavailability of like parts, engineering

modifications were developed and implemented to replace the gauges with

more accurate models.

Based on discussions with Instrumentation and

Electrical (IAE) personnel, it was indicated that most likely, the

gauges had drifted out of accuracy over a long period of-time.

The inspector reviewed periodic surveillance test procedures associated

with verifying Shutdown Panel instrumentation indications.

VCT level

was not among the indications checked periodically.

The inspector

noted. however, that VCT level was not required by TS to be o)erable

from the Shutdown Panels.

However, the VCT indication could )e

potentially used during operation from the Shutdown Panels.

It was also

apparent that-there had been opportunities to have identified the gauge

output drift during the periodic surveillances of other Shutdown Panel

instrumentation.

Enclosure 2

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Unit 2 Power Rance Channel NI-42 Soare Window Illuminated

On June 27. 1997, the day after Unit 2 tripped on low Reactor Coolant

System flow, the inspector noticed an annunciator window on the Nuclear

Instrument (N1) 42 Power Range drawer that was illuminated.

The

annunciator window was labeled " spare" and appeared to serve no

function.

The inspector questioned the control room operators about the

illuminated window. The window apparently first illuminated following

the trip; however, the operators were not aware that the window was

illuminated, nor the reason for the condition.

Based on subsequent

discussions with reactor engineering personnel, the inspector learned

that this spare annunciator window was previously used as the negative

rate trip indication light. During the previous refueling outage. this

trip function was isolated from the reactor protection logic, the

modification that implemented the rate trip change was supposed to have

removed the bulb from these windows on all of the N1 drawers. .It was

believed that the bulb in the NI-42 drawer was removed, but may have

been reinstalled by lAE personnel by mistake during subsequent NI

maintenance activities following the refueling outage. The light was

extinguished once the rate trip function was reset and the bulb. removed.

The licensee initiated a PIP to address this problem.

TS Loaaina Error for Trackina Containment Airlock Door Seal Surveillance

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On July 11, 1997, during review of the Unit 2 TSAIL. the inspector

noticed an incorrect entry that was made on July 9.

The entry was for

tracking a TS required 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> airlock door seal test following opening

of the airlock door on July 9.

The time required for the test to be

performed was listed in TSAIL as July 16 instead of July 12.

The

inspector discussed the error with operations personnel who corrected

the entry.

It was also indicated that the seal test was scheduled to be

performed that same day.

Based on this, the inspector determined the

test would not have been missed even though the TSAll was incorrect.

The inspector was concerned that the TSAll error had not been identified

over the two previous two days that the problem existed.

Individually, the above problems had little actual safety consequences.

however, in the aggregate represented the need for greater attention to

detail and questioning attitude by operations personnel during the

performance of routine activities.

01.2 Unit 2 Reactor Trio on low Reactor Coolant System Flow-

a.

Insoection Scope (71707. 937,01).

On June 26 a Unit 2 reactor trip from 100% power occurred when the 2B

Reactor Coolant Pump (RCP) tripped and caused a loss of flow signal in

the associated loop. The inspector discussed the unit trip with

engineering, operations and maintenance personnel, as well as reviewed

the associated electrical diagrams. Unit Trip Report and Pl? 2-C97-2221.

Enclosure 2

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Observations and Findinas

On June 21. a negative leg ground was detected on ron vital distribution

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bus 2CDB.

The ground subsequently was traced to tre 125 VDC control

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power circuit of breaker 2T6 6.

On June 26. the b"eaker was opened to

facilitate troubleshooting the cause of the ground.

The Instrument and

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Electrical (IAE) technicians noticed that the breaker failure initiation

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relay in 2TB 6 control cubicle was chattering, but continued with their

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troubleshooting activities.

Shortly thereafter, a reactor trip

occurred.

The licensee determined that. the source of the ground fault was the

breaker pushbutton, a Cutler-Hammer E30 model,

lhe pushbutton had

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failed and created a negative leg-to ground fault on 2CDB. The

pushbutton internals had changed state when 2TB 6 was tripped open

during troubleshooting, introducing a fault path to the positive leg.

Noise from the cabinet ground was induced through the switch and the

breaker failure initiation relay (94B) coil, causing it to chatter and

eventually actuate to trip the incoming breaker on the short bus of 2TB.

The auto close function of the 2TB tie breaker was blocked by a lockout

rela

bus,y, and the bus de-energized. The 2B RCP. which is supplied from the

tripped, and the subsequent low flow in the B loop caused a reactor

trip.

The inspector discussed the reactor trip with operations and engineering

personnel to determine if the root cause involved a human error. The

chattering of the relay, generated when 2TB 6 was opened, could have

been stop)ed if the IAE technicians had reclosed the breaker when they

noticed tlat relay chattering.

However, they did not understand what

was causing the chattering at the time.

The inspector concluded that

the IAE technicians responded appropriately by leaving the breaker in

the opened position since the cause and impact of the relay chattering

were not understood.

The inspector inquired about the time delay between ground detection

(identified on a Saturday) and troubleshooting activities (initiated the

following Wednesday).

l.icensee personnel indicated that Single Point Of

Contact (SPOC) technicians were not trained and qualified to use the

ground chasing equipment.

As a result a'stempts to locate the ground

could not be made until the following Monday when a trained IAE

technician would be available. Also, priority status was not associated

with troubleshooting the ground indication early in the week.

In

addition, the inspector determined that only two techniciant on site

were fully qualified to use the ground-chasing equipment to locate the

source of a ground, and that_one of those technicians had been offsite

since February and was not scheduled to return until October of this

year. A shortage of trained personnel available to perform the

troubleshooting contributed to the delay.

At the end of the ins)ection

period, the delay in investigating the ground, associated contri)uting

factors, and appropriate corrective actions were not addressed within

the licensee's corrective action program.

Enclosure 2

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The unit was restarted on June 28 after trip list activities were

performed and minor equipment problems were corrected. The licensee is

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planning to document the reactor trip in a Licensee Event Report.

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c.

Conclusions

The inspector concluded that root cause evaluations of the reactor trip

were adequately performed.

The cause of the tt!p did not involve human

error or non conservative decision making. The protective relaying

associated with the short bus of 2TB functioned as designed. The

inspector determined that, although the delay in troubleshooting

activities to locate the source of the ground did not affect the outcome

(reactor trip), challenges existed in the following areas: (1)

associating appropriate priority to locating ground indications in a

timely manner, and (2) ensuring that trained personnel are avullable to

troubleshoot ground indications. At the end of the inspection period,

efforts to address the delay, understand its causes, and identify

corrective actions were not evident in the licensee's corrective action

program.

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01.3 Unit 2 Downoower in Response to Generator Outout Breaker Trouble

a.

insoection Scone (71707)

On July 2. Unit 2 control room operators received a generator breaker

trouble alarm and identified a continuous decrease in minimum close air

3ressure on 28 Main G2nerator Power Circuit Breaker (PCB). Operators

Jegan a rapid load reduction, and the PCB automatically tripped after

reactor power reached 50%.

The inspector reviewed PIP 2 C97 2177 and

discussed the downpower and associated equipment failure with licensee

personnel.

b.

Observations and Findinos

On July 2, the Main Generator PCB 2B Trouble annunciator alarmed in the

control room.

Control room operators determined that there was a

continuous decrease in air 3ressure on the 28 Main Generator PCB,

indicating an approach to 11e minimum air pressure is required to open

the breaker. Air

' the resulting arc. pressure is required to open the breaker and dissipate

Since the safety function of the PCB was to open, it

was designed to automatically open before the minimum pressure required

for this function is reached.

The minimum tri

Generator PCB 2B is between 446 and 452 psig. p pressure on Main

To preclude an automatic turbine runback on the potential automatic

opening of the PCB operators began a rapid load reduction, The PCB

automatically tripped after reactor power reached 50%.

No overcurrent

alarms were received on Main Transformer 2A.

The license deternJned that a solenoid (or )ilot) valve associated with

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the air sup)1y to a:1 three main generator )CB poles had failed,

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rendering t1e air system unable to deliver air to the breaker.

Normally, the solenoid valve receives signals from the breaker poles to

Enclosure 2

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supply air to them. When the air pressure on any pole reaches

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a> proximately 485 psi.-a pressure switch actuates and the solenoid valve

sluttles to pneumatically control a regulator that delivers air to the

breaker poles. When air pressure is restored to 500 psi the signal

from the pole to the solenoid is terminated.

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Station PIP 2-C97-2177 documented the root cause of the solenoid

failure.

The failed solenoid was new and had been installed during the

April 1997 refueling outage.

The component failure was attributed to a

deformed nylon bushing.

The valve had been assembled to compensate for

the defect which initially allowed the valve to operate as designed.

However, the valve's internal components drifted from their assembled

positions over time and eventually were unable to engage with the

valve's lower assembly, thereby preventing air flow to the poles.

To address the potential that newly purchased solenoid valves could be

installed with problems, the licensee had revised procedure

IP/0/B/4974/01, Main Generator PCB Maintenance. - Revision 5 of the

procedure included a Note between Steps 10.3.7 and 10.3.8. The-Note

read: "If pilot valve is replaced, ensure pilot valve has been

disassembled and inspected for pro>er assembly and components. or

rebuilt prior to installation." T1e inspector verified that this

procedure change had been made,

c.

Conclusions

The inspector concluded that control room operators were effective in

)recluding a turbine runback by reducing reactor power to 50% before the

3CB opened.

The licensee's root cause evaluation was detailed and

actions to prevent recurrence were adequate.

01.4 Lower Containment Air Temoerature Exceeded for Short Duration

a.

Insnection Stone (71707)

On June 30. the licensee was performing maintenance on the Unit 2

Lower Containment Ventilation Units (LCVUs). While the 2A and 20

LCVUs were out of service, the lower containment temperature

increased to 117.4'F. The inspector reviewed apalicable operating

procedures. TS. the FSAR, tagout requirements, tie innage work

schedule, and PIP 2 C97-2127.

The inspector also discussed the

-issue with operations, engineering and work control personnel.

b.

Observations-and Findinas

During normal operation. the Containment Chilled Water (YV)

chillers service various containment loads including the LCt!Us and

the Reactor Coolant Pump (RCP) Motor Air Coolers.

0_n June 30,

preventive maintenance (PM) and electrical motor testing were

scheduled for the 2A and 20 LCVUs. The 2A LCVU was removed from

Enclosure 2

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service first.

After the PM for the 2A LCVU was completed, but

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before motor testing was completed, operations personnel decided

to remove the 2D LCVU for PM.

The 2D LCVU was removed from

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service at 10:55 a.m.

While both LCVUs were out of service, lower

containment temperature increased.

To compensate for the

temperature increase, control room operators adjusted the

o)eration of the remaining inservice LCVUs (2B and 2C) from

"iormal" to "High Speed." and then to " Max Cool." However, for a

brief period of time lower containment temperature had exceeded

the high high temperature Operator Aid Computer (0AC) alarm

setpoint of 115.6'F and the adjusted TS limit of 117.2*F.

ultimately reaching 117.4'F.

Lower containment temperature was

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above 117'F for approximately 3 minutes before it was restored to

within TS limits.

The Action required by TS 3.6.1.5 was to

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restore the air temperature to within the limits within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or

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be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Since the

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bich lower containment temperature existed for only a few minutes.

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th6 licensee was in compliance with the TS action.

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At anroximately 11:10 a.m., operations personnel decided to post)one

the M on the 2D LCVU. recall the associated tags and return the _CVU to

service until the 2A LCVU was restored to operation.

While operators

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were returning the 2D LCVU to service and all three LCVUs to normal

alignment, the YV chillers in service (A and C) trip>ed on low flow.

Based on a review of the circumstances surrounding t1e trip of the A and

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C YV chillers, the inspector discerned that the following took place.

When the B and C LCVUs were taken to " Max Cool" in an effort to reduce

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lower containment temperature, the flow control valves in the chiller

loop fully opened as designed, and thermostatic control of,the chilled

water supply was lost. When operations subsequently restored the D LCVU

to service and returned the LCVUs to normal operation, thermostatic

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control of the flow control valves was reinstated.

The existing

temperature caused the flow control valves to throttle closed, and the

chillers tripped on low load.

Normal alignment with the A and B YV

chillers was established within 30 minutes of the chiller trips. The C

YV chiller had also been restarted, but tripped after running for 10

minutes.

Shortly thereafter, containment temperatures were restored to

normal levels.

Operations surveillance procedure PT/1/A/4600/02A. Mode 1 Periodic

Surveillance Items. Enclosure-13.1. Periodic Surveillance Items Data,

approved January 23, 1997, provides surveillance acceptance criteria in

-

accordance with the lower containment temperature limits imposed by TS 3.6.1.5.

Lower containment minimum and maximum air temperature limits

are based on the average inlet temperatures of the operating LCVUs.

Temperature readings associated with non running LCVUs provide

indication of static air temperature and therefore, are not used to

determine average containment air temperature.

Therefore. temperature

':mits are adjusted conservatively as a function of uncertainty (because

of the reduced sample size) in generalizing local indications to average

Enclosure 2

1

..-._..__ ,,

,a..

._-..,....,--...--m.__-

-

- - _ _ - _ . . _ .

.

.-m.

-

-

-

9

containment air temperature. As the number of LCVUs in service

decreases, the temperature limit decreases (becomes more conservative).

With two LCVUs running. the lower containment TS limit of 120*F was

adjusted to 117.2'F.

The Containment Lower Compartment Ventilation Subsystem as

described in the FSAR is designed to maintain a maximum

temperature of 120*F in the lower compartment during rnrmal plant

operation.

During normal operation, three units (each providing

33.3% capacity) are in service, and one unit is on standby.

3

Technical Specification Interpretation 3.6.1.5 states that

!

containment air temperature can be maintained with one active

component out-of-service (i.e., three LCVUs in service).

Based upon a review of the FSAR and TS as well as discussions

with on-shift operators, the inspector determined that the

4

decision to remove the D LCVU from service while preventive

maintenance (PM)s on the A LCVU were ongoing was non conservative

and caused lower containment temperature to exceed the adjusted TS

limit.

The inspector also determined that problems existed with procedure

OP/2/A/6450/01. Containment Ventilation Systems. dated June 15. 1994,

which controls the configuration of the LCVUs. The procedure did not

provide adequate guidance to address the impact of removing two LVCus

from service on lower containment temperature.

Operations Management

Procedure 2-18. Tagout Removal and Restoration Procedure. Revision 46.

Responsibility 4.8. states that the person placing or removing tag (s)

shall check procedures affected and any outstanding tagouts associated

with that procedure / system for any adverse effects.

Because the adverse

impact of removing 2 LCVUs from service was not addressed in the

procedure, this responsibility could not be effectively realized.

n addition, procedure OP/2/A/6450/01 did not address the interaction

between LCVU operation and integrated Containment Ventilation (VV)

Systems.

Step 2.7.3 of OP/2/A/6450/01. Enclosure 4.12. LCVU Additional

Cooling and YV Chiller Trip Prevention directs the operator to ensure

that three LCVUs are in the " NORM" position. The performance of this

step caused the A and C YV chillers to trip.

Procedure

slowly reduce the demand on the system was not provided, guidance to

nor was a

precaution or note provided to warn of the potential to induce a chiller

trip as a function of load demand changes.

The inspector also noted that no procedure guidance was available for

swapping between running and_non running LCVU units. OP/2/A/6450/01.

Enclosure 4.2. Lower Containment Ventilation Unit Startup and Normal

Operation, provided procedural guidance for starting up the system by

placing three LCVUs in operation.

Enclosure 4.7. Lower Containment

Ventilation Unit Shutdown provides procedural guidance for shutdown of

the system by placing all four LCVU switches in the OFF position.

Enclosure 2

-

l

10

However, no procedural guidance existed for stopping an individual LCVU

and subsequently restarting it or making other required alignment

changes needed to facilitate the performance of the PM. The inspector

recognized that this lack of procedural guidance was unrelated to the

lower co'itainment temperature increase and the YV chiller trips.

l

The inspector also identified a minor discrepancy in the planned

l

innage work schedule.

The 2A LCVU had two work items planned to

be worked which included a PM and electrical motor testing.

The

PM on the 2A LCVU was scheduled to be completed at 12:00 p.m. on

June 30, 1997.

The motor electrical testing on the 2A LCVU was

scheduled to be completed at 1:00 p.m. on June 30.

The PM on the

20 LCVU was scheduled to commence at 12:00 p.m. on June 30.

immediately following the scheduled completion of the PM on the 2A

LCVU.

This schedule allowed both the A and 0 LCVUs to be out of

service for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, which was non conservative and not in

accordance with the alignment described in the FSAR.

c.

Conclusions

The inspector concluded that the decision to deviate from the

preferred normal alignment of LCVU operation to support planned

maintenance exhibited non conservative work scheduling and

operator judgement.

As a result. lower containment temperature

increased slightly above the adjusted TS limit for a brief period

of time.

However, temperatures were reduced below the adjusted TS

limit within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> as required by the TS action requirement.

Therefore, exceeding the lower containment air temperature on

plant equipment had minor safety significance and did not pose a

threat to safety related equipment. The LCVU operating procedures

did not address the adverse impact of removing two LCVUs from

service. simultaneously. nor did the procedure address the

interaction between LCVU operation and integrated containment

ventilation systems. These procedural inadequacies constituh a

violation of TS 6.8.1. Procedures and Programs. This failure

constitutes a violation of minor significance and is being treated

as a NCV. consistent with Section IV of the NRC Enforcement

Policy.

This item is identified as NCV 50-414/97-09-02:

Inadequate LCVU Operating Procedure.

08

Hiscellaneous Operations Issues (92901)

,

08.1

(Closed) Un.reigh.ed_Ltem (URI) 50-413.414/94-13-02:

Emergency Operating

Procedure (EOP) 50.59 Evaluations Not Reviewed by Nuclear Safety Review

Board (NSRB) as Required by TS

This item was related to an apparent failure to meet the TS requirement

for the NSRB to review 50.59 evaluations for E0P changes. The

inspector's review determined that the re

being appropriately reviewed by the NSRB quired 50.59 evaluations were

The licensee's procedures had

Enclosure 2

__-_______ __-_ - _ _ - .

11

been inconsistent in defining the 10 CFR 50.59 screening evaluation and

the 10 CFR 50.59 Unreviewed aafety Question (US0) evaluation. The TS

requirement was intended for the NSRB to review the 10 CFR 50.59 U50

evaluations. Nuclear Site Procedure NS0-209, 10 CFR 50.59 Evaluations.

Revision 6. was revised after 1994 to clearly define the two

evaluations. The licensee initiated a change to NSD 703. Administrative

Instruction for Station Procedures, to clearly distinguish on the

procedure change process documentation whether the evaluation performed

was a screening evaluation or an USQ evaluation. The inspector reviewed

three US0 evaluations for E0P changes and verified the US0 evaluation

,

'

had been sent to the NSRB_for review. A 1995 evaluation had been

i

reviewed and two 1997 evaluations were scheduled for review at the next

NSRB meeting.

The inspector concluded that this issue was adequately

resolved and the TS requirements had been met by the licensee.

During the invettigation of the above issue, the inspector reviewed

a) proximately 20 examp',cs of 10 CFR 50.59 screening evaluations for E0P

c1anges and identified a deficiency in the licensee's procedure

implementation of this activity.

Specifically, the justifications for

the screening questions were inadequate in many changes.

The

justifications were inadequate in that they only repeated the screening

question as a negative statement. NSD 209, 10 CFR 50.59 Evaluations.

Revision 5. required the doca,3ntation of justification for responses to

50.59 screening questions.

It further stated that justifications should

be complete enough so that an independent reviewer cculd come to the

same conclusion.

The following E0P change 50.59 screening evaluations

were inadequate and did not meet the applicable procedure requirements:

o

EP/2/A/5000/FR 1.2 dated November 17, 1995

EP/1/A/5000/FR-1.1 dated September 19. 1996

e

OF/1/A/6350/08 dated February 28. 1996

EP/2/A/5000/F-0 dated March 26, 1997

e

EP/1/A/5000/FR H.1 dated August 16, 1996

e

EP/1/A/5000/FR-H.1 dated January 30, 1995

This failure to follow NSD 209 for 10 CFR 50.59 screening evaluations,

is identified as the first example of Violation (VIO) 50 413.414/9/-09-

04:

Failure to Follow Procedure. The inspector did not identify any

US0 condition related to the inadequate 50.59 screening evaluations.

The inspector noted that the 50.59 screening evaluations for E0P changes

were performed by the Operations organization.

Previous inspections of

50.59 evaluation performance have concluded that the Engineering

organization performed to a high standard in this area for 50.59

evaluations related to modifications.

Although both organizations

Enclosure 2

12

receive the same training and use the same procedures. Operation's

performance in this activity was deficient as previously noted. The

inspector reviewed a 1997 50.59 USO evaluation for an E0P change.

This

evaluation was good in that it included a well detailed justification

for responses to the USQ evaluation questions.

This indicated that the

>

Operations deficient performance was related only to the 50.59 screening

evaluations.

II. Maintenance

l

M1

Conduct of Maintenance

1

M1.1 Electrical Flash Durinn Breaker Preventive Maintem nte

a.

Inspection Stone (62707)

The inspector reviewed the circumstances and the licensee's corrective

actions associated with an electrical flash that occurred inside a 600

Volt non safety-related breaker cubicle while periodic breaker PM was

being performed. The electrical flash resulted in a minor personnel

injury and extensive damage to the breaker cubicle.

b.

Observations and Findinas

On June 3. 1997, an Instrumentation and Electrical (IAE) technician was

aerforming PM on 600 Volt breakers 2MXM-F09C and 2MXM-F090.

These

areakers supplied power to two Unit 2 ice condenser refrigeration air

handling fans. The PM activity involved testing the overcurrent

protective devices associated with the breakers.

The technician had

removed breaker F09C from its cubicle and was in the process of removing

breaker F090 from its cubicle. While removing F090, an electrical ficsh

occurred in the F09C cubicle, which was located directly above F09D.

The technician received minor facial burns. but was not seriously

injured.

Breaker F09C was electrically welded in its cubicle as a

result of the electrical fault,

The inspector responded to the breaker

work location and noted good licensee immediate actions in response to

the incident. These actions included terminati'

11 PM work, roping

off the area for personnel safety consideratior .

nd initiating a

Failure Investigative Process (FIP) to determine the root cause of the

electrical fav a.

On June 6, 1997. Motor Control Center 2MXM was de energized, and the

breaker cubicle for F09C inspected.

The damage to the bus was minimal;

however, the stabs for F09C were badly damaged and recuired replacement.

Both breakers F09C and F09D were repaired, tested, anc returned to

service.

The inspector attended the PORC meeting conducted to discuss

the repair plans and noted that management performed a thorough review

of the plans with good discussions on the impact of the work planned on

the plant. The repairs were completed without incident.

Enclosure 2

_____

-

13

The FlP team was thorough in their investigations and determined that

the stabs b? hind breaker F09C had come in contact with the energized

bus.

Since the breaker power connecting cables had been determed and

left untaped in the bottom of the breaker cubicle. an electrical ground

path was created when the cables were re energized. The FIP determined

the method for racking the breaker out in the maintenance position was

inadequate.

In the maintenance position a lock tab on the front of the

breaker cubicle had been used to position the breaker away from the bus;

l

however this method did not provide sufficient distance between the bus

and stabs. While this method had not resulted in any problems in the

past, the result of having two breakers in the maintenance position,

located one above the other, created an even smaller bus / stab distance

that resulted in electrical flash over.

As a result of the FlP investigations, instrumentation procedures

governing work on 600 Volt breakers were revised to change the method of

racking out these breakers for maintenance.

Instead of using the lock

tab, procedures directed that a padlock be placed on the breaker or the

bteaker be removed completely to ensure adequate stab / bus distance is

maintained.

In addition, IAE personnel involved with breaker work were

to be provided training on this new method of racking 600 Volt breakers

out to the maintenance position.

c.

Conclusions

The inspector concluded that the FlP team was thorough in investigating

the cause of the electrical flash.

The root cause evaluation revealed

configuration weaknesses in the method of locking out 600 Volt breaker

cubicles to the maintenance position. The inspector determined that the

licensee adecuately implemented corrective actions to prevent recurrence

of this incicent.

M1.2 'Jngdeounte Leak Rate lest of Unit 2 Containment Isolation Valve

a,

insoection Scope (40500. 61726. 62707)

On June 4,1997, the licensee identified that Unit 2 containment

isolation valve 2NV 874 had not been properly Type C leak rate tested in

accordance with 10 CFR 50. Appendix J during the previous. refueling

outage.

On June 6. the valve was properly tested and failed the Type C

leak rate test. -The valve disc was replaced, and the valve was

successfully tested on June 7.

The licensee submitted LER 50 414/97-004

. to document the inadecuate leak cate test conducted during the outage.

The inspector reviewec the circumstances associated with the inadequate

testing, attended PORC meetings to discuss retesting valve 2NV-874

online, witnessed aspects of the June 6 retest, reviewed leak rate test

results, and discussed the incident with engineering and Operations Test

Group (OTG) personnel,

Enclosure 2

_

-

i

14

b.

Observations and Findinas

On &ne 4.1997 the OTG Suaervisor was conducting a procedure

completion verification of Jnit 2 Periodic Test (PT) procedure

PT/2/A/4200/01C. Containment Isolation Valve t.eak Rate Test.

This

procedure had been performed during the previous refueling outage in

1

April 1997. During the review, the supervisor idcntified that Step

2.2.3 of Enclosure 13.7. Penetration No. M228 Type C 1.eak Rate Test had

been marked "Not Applicable by the OTG technician performing the test.

I

,

resulting in the step not being performed. This step required test vent

I

flow path valve 2NV 873 to be opened while testing inside containment

isolation check valve 2NV 874 (associated with the Standby Makeup System

'

flowpath to the reactor coolant pump seals). Without an open test vent

flowpath, the leak rate test on 2NV 874 had been invalid.

The inspector verified that appropriate actions were implemented upon

identification of the invalid lea ( rate test. These actions included

2NV 874 being declared inoperable and in accordance with TS 3.6.3,

the

outboard containment isolation valve (2NV 872A) in the penetration was

closed and power was removed from the valve operator within four hours.

The inspector attended the June 5 and 6 PORC meetings conducted to

discuss activities to retest 2NV-874.

Management thoroughly discussed

the impact on the plant with testing the valve while online.

In

addition engineering developed a special leak rate test procedure and a

detailed briefing package explaining the necessary actions for

controlling the retest activities.

On June 6. the inspector witnessed aspects of the leak rate test on 2NV-

874. The inspector noted that testing was well controll?d and performed

in accordance with the test procedure.- The valve was not able to be-

pressurized and resulted in-a failed leak rate test.

Valve maintenance

was performed resulting in replacement of the valve disc and disc

spring. A subsequent leak rate test was performed following the

maintenance activity.

The inspector reviewed the results of this

testing which verified that leakage was within acceptable limits.

Following successful testing 2NV 874 was declared operable and the

penetration was returned to its normal configuration,

C_Qn.clusions

c.

n

The inspector concluded the identification by the OTG Supervisor of a

procedure discrepancy that resulted in an invalid leak rate test of nD-

874 was an example of good questioning attitude. The PORN performed a

thorough review of subsequent activities to properly perform the leak

rate test. Good engineering support was )rovided, both in developing a

leak rate test procedure and briefing paccage for the evolution.

The inspector noted that the procedure completion review was not

performed by the OTG Supervisor following actual completion of all

testing or prior to plant startup from the refueling outage.

Since this

Enclosure 2

_ _ _ _

-

. . - _ .

__-

--_

---

- -

-

- - . . - - _-

_.

15

l

was the only review that was recuired following test procedure

completion, the inspector consicered the review untimely.

Had this

review been completed prior to plant startup, this problem may have been

identified and corrected arior to the unit entering a mode recuiring

containment integrity.

T1e failure to open test vent valve 2hV-873

during/4200/01C was identified as a violation of TS 6.8.1. leak rate testing of

PT/2/A

This issue

is identified as Violation E0-414/97-09 03:

Failure to Follow Procedure

Results in Invalid Local Leak Rate Test of Valve 2NV 874.

M8

Miscellaneous Maintenance Issues (92902.

l

M8.1 (Closed) VIO 50 413. 414/97-01-01: Failure to Include all Structures.

S stems and Components in the Scope of the Maintenance Rule as Required

b 10 CFR 50.65

This violation was identified when the inspectors determined that the

licensee had incorrectly excluded a number of structures. systems and

components from the scope of the Maintenance Rule.

The licensee

acknowledged the violation and issued a Problem Investigation Process

(PIP) report PIP No. 0 C97-0419. to document correctivo actions taken

!

and, track the progress made in addressing the issues.

The systems

affected included Nuclear Sampling (NM). Main Steam to Auxiliary

Equi) ment (SA). Auxiliary Building Chilled Water (YN) and Ice Condenser

l

Hitti Pins (NF).

Following a review by the site Expert Panel these

'

systems or components were added to the scope of the Maintenance Rule.

Corrective actions taken or planned included a review of the 239

functions that had been excluded from the Maintenance Rule scope. This

'

review was scheduled for completion in December 1997.- and will be

documented in PIP No. 0-C97-0419,

In addition, structures and functions

excluded from the Maintenance Rule will be reviewed for Generic Scoping

applicability. The due date for this review is also December 1997. The

inspectors concluded the licensee's corrective actions were appropriate.

,

M8.2. (Closed V10 50-413.414/97 01-04: Failure to implement the Requirements

of (a)(1) and (a)(2) of the Maintenance Rule

l

This violation was identified when the inspectors determined that the

l

licensee was using Forced Outage Rate (FOR) instead of Unplanned

l

Capability loss Factor (UCLF) as a Plant Level Performance Criteria for

!

monitoring A2 systs....; 3er 10 CFR 50.65. The concern was that FOR was

'

not as sensitive as UC F in detecting declining performance in some

systems.

The licensee acknowledged the violation and took appropriate action to

correct the problem.

The licensee incorporated the Plant Transient

Criteria as part of the Forced Outage Criteria. This combination of

criteria was intended to provide appropriate equivalent defense in depth

monitoring as the Unplanned Capability Loss Factor. A Plant level

Enclosure 2

l

.

-

..

._

.

--

-

--

-

1

16

l

Performance Criteria called Plant Transients, which defined unacceptable

performance was added to Engineering Directives Manual (EDM)-210 as Rev.

i

4.

The inspectors concluded the licensee's corrective actions were

'

appropriate.

M8.3 (Closed) Insoector Followuo item (IFI) 50 413.414/97-01-02: Followup and

'

Review of Licensee Procedure to implement the Requirements of (a)(1) and

(a)(2) of the Maintenance Rule after issuance of Regulatory Guide 1.160,

Rev.2

EDM-210." Requirements for Monitoring the Effectiveness of Maintenance

i

at Nuclear Power Plants or the Maintenance Rule " Rev. 5.

revised the

definition of Maintenance such that it was now in agreement with

Regulatory Guide 1.160. Rev. 2, dated March 1997.

Revision 5 of the EDM

now considers any operator action performed in support of Maintenance as

a Maintenance Preventable Function Failure (MPff) candidate.

In

addition, the flow gra)h of Appendix A to the subject EDM, were revised

for clarity.

One of tie two was revised from Vendor Error to Off-site

Vendor Services while the other from Operations or Plant configuration

control to Operation or Plant Configuration Control not associated with

a maintenance activity.

The inspectors concluded the licensee's

i

corrective actions were appropriate.

M8.4 (Closed) IFT 50-413.414/97-OL-01 Followup on Licensee Actions to

Provide Performance Criteria for Structures After Resolution of this

Issue

EDM-210. " Requirements for Monitoring the Effectiveness of Maintenance

at Nuclear Power Plants or the Maintenance Rule." Rev. 5. changed the

3erformance criteria for all Maintenance Rule structures to comply with

legulatory Guide 1.160. Rev. 2.

This criteria applies to both risk and

non-risk significant Maintenance Rule structures.

EDM 410. " Ins)ection Program for Civil Engineering Structures and

Components." Rev. 1. dated June 16, 1997, is the controlling document

for monitoring and assessing civil engineering structures and' components

to the requirements of 10 CFR 50.65 and Regulatory Guide 1.160,.Rev. 2.

dated March 1997. It provides examination guidelines, acceptance

criteria and documentation requirements.

As such. Catawba civil

,

engineering was responsible for implementing the ins)ection program for

l

structures and components.

The inspectors reviewed EDM-410. Rev. 1 for

content and adequacy.

The inspectors noted that the procedure provided

adequate guidelines and the acceptance criteria contained within,

followed Regulatory Guide 1.160. Rev. 2 guidelines for acceptable and

.

unacceptable performance criteria.

l

l

Through discussions and document review, the inspectors ascertained that

the inspection program for structures was adequately administered and

implemented.

Responsible engineers had received training and were

familiar with Maintenance Rule requirements as they applied to their

area of responsibility.

5

Enclosure 2

L

___

_--

.

.

..

.

..

_

_

__

,

/

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

__

- _ __

_ _ _ _ _ _ _ _ _

17

At the close of this inspection. 39 structures had been inspected and an

additional 120 were scheduled for inspection by year's end.

Ins)ection

per the revised EDMs -210 and -410 commenced on July 1, 1997.

T1e

inspectors reviewed the licensee's classroom training material. ES-CN-

97-21. used to cormiunicate Regulatory Guide 1.160. Rev. 2 guidelines.

Training of personnel was held between June 9 and 18. 1997.

The

inspectors concluded the licensee's corrective actions were ap]ropriate.

III. Enaineerina

El

Conduct of Engineering

El.1 Primary and Secondary Thermal Power DiscreDancy

a. -Insoection Stone (37551)

On July 15 the licensee discovered a discrepancy of approximately 0.6%

between the Unit 2 primary and secondary thermal power indications.

Secondary thermal

was reduced to 99. power was immediately reduced to 99.3% (reactor power

7%) and a FIP team was initiated to determine the

cause of the discreaancy. The inspector attended management briefings

by the FIP team mem)ers on the progress of their investigation: reviewed

associated TS and TS Interpretations: and discussed the issue with

Operations. Engineering and Maintenance personnel.

b.

Observations and Findinas

On July 15. Operations personnel were notified by the reactor

engineering group that there was a 0.6% discrepancy between primary and

secondary thermal power indications, and that actual thermal Jower might

be greater than the secondary thermal power (the designated tiermal

power best estimate) indication. The reactor engineering group

discovered, during a routine review of secondary plant parameters, that

primary thermal power had slowly increased over time since the Unit 2

restart from the April 1997 refueling outage.

A FIP team was initiated

to determine the cause of the discrepancy, and control room operators

decreased reactor aower to 99.3%. Tae reactor was operated at 99.3%

power until the FI) team could determine the cause of the discrepancy.

The FIP team determined, during the course of their investigation, that

theT,Yto586.9F. indication had been drifting downward since May 11, 1997, from

587.3

Operations responded by decreasing T,,, to minimize

the T * /T

error.

Lowering T,,, caused the reactor to increase AT to

maint'aIn,r,,actorpowerequaltosecondarypower. The drift in the T,,,

e

indication resulted in changes in T

Tm

T,,, and AT but did not

cause a change in indicated or actud3 primary and secondary thermal

power.

Although the FIP team could not attribute this indication drift

to the primary / secondary thermal power indication discrepancy they

determined that a degraded 7300 process card was responsible for the

Enclosure 2

.

.

-

.

-

. . _ .

}

18

drift and initiated plans to have the card replaced after the root cause

of the power indication discrepancy was identified.

The FIP team also determined that indicated feedwater flow had decreased

while steam flow had remained constant.

This was attributed to

feedwater venturi defouling as a function of the new cycle (restart from

the April refueling outage was in early May). the recent reactor trip

(June 26), and was the recent rapid downpower (July 2). The result of

defouling was a decrease in indicated feedwater flow with a

consequential decrease in indicated secondary thermal

maintains secondary Thermal Power Best Estimate (TPBE) power. Operations

near 100% by

periodically opening flow control valves, which in turn causes primary

power to increase to maintain T

defouling caused an increase in.,, for 100% power level. The gradual

actual and indicated primary thermal

power, as well as actual secondary thermal power.

However, the

resultant discrepancy between indicated and actual secondary thermal

)ower accounted for approximately 0.10% to 0.15% of the 0.6% discrepancy

)etween primary and secondary indicated thermal power.

The major contributor (0.3% to 0.4%) to the discreaancy between primary

and secondary thermal power was determined by the

IP team on July 16 as

hot leg streaming. According to Westinghouse, hot leg streaming refers

to the inability to accurately characterize bulk hot leg temperature.

The licensee examined data from the Unit 2 Beginning of C.rcle and

identified changes in the behavior of this phenomenon from previous

cycles.

S)ecifically. calculations revealed that indicated Tw had

increased ay 0.2*F and caused indicated primary thermal power to

increase.

As discussed above these changes were originally masked by

the decrease in primary tem

T,,,/T,,, as a function of T,,,peratures accompanying the decrease in

-

indication drift.

Hot leg streaming has occurred in previous cycles on both units and has

resulted in as high as a 1.0% difference between primary and secondary

thermal power. To account for this, an adjustment factor in the OAC

calculation corrects the discrepancy.

The FIP team concluded that sea:dary thermal power had always been

accurately and correctly indicated, and that primary thermal power

indication did not reflect an actual increase in power level above TS

limits. The inspector discussed the impact of the primary thermal power

indication on Reactor Protection System setpoints and functions.

According to the reactor engineering group, the venturi defouling and

hot leg streaming factors did not constitute a sufficient temperature

error to warrant adjustment via the Reactor Coolant System (RCS)

Temperature Calibration Procedure, which is run quarterly. The OPAT and

OTAT trip strings remained within their TS limits.

In addition, the

nuclear instrumentation system is calibrated to secondary thermal power,

so the associated overpower trip setpoints were unaffected.

Enclosure 2

,

_,

-.-.-.c.

. ---

-

_ _ _ _

- _ _ _ _

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

-

- - - - - -

-

19

Reactor Power was increased to 99.5% on July 16 and the degraded T,q

card was replaced on July 17.

The inspector attended the prejob brief

for the card replacement and observed the work activity in the control

room. The replacement was successfully completed within less than 1

hour and without incidence.

At the end of the inspection period, the

3a

license was considering either performina periodic manual calculations

to the correct the thermal power aiscrepancy, or conducting a full

calorimetric to account for the deviation.

c.

Conclusiqn_q

,

The inspector concluded that the licensee's identification of the

E

thermal power discrepancy exhibited attention to detail and a thm

review of plant data. Actions to initiate a FlP team to invr

g

root cause were appropriate, and steps to reduce reactor po'

a

discrepancy was understood were conservative and indicative

positive nuclear safety ethic.

Replacement of the faulty T,

,a was

well-planned. coordinated and controlled, and executed in an expeditious

manner.

E2

Engineering Support of Facilities and Equipment

.

E2.1 Review of Corrective Actions

a.

Inspedjon Scooe (37550. 92903)

The inspector reviewed Engineering corrective actions to resolve open

itens identified during the development of the station Design Base

Documents (DBDs) and findings from Self-initiated Technical Audits

(SITAs).

Also reviewed were the licensee's actions to address a 10 CFR Part 21 issue related to a defective Emergency Diesel Generator (EDG)

intake / exhaust valve spring. Anplicable regulatory requirements

included 10 CFR 50 Appendix B. ESAR. Technical Specifications and

implementing licensee procedures.

b.

Observations and Findinos

DS_Qs

Developed between 1990 and 1994. DBDs consolidated design and licensing

documentation for selected station systems and programs. The ]rocedure

guidance for development and maintenance of DBDs was provided

ay

Enoineering Directives Manual . EDM-170. Design Specifications, revision

5.

Open items were evaluhed for operability during the DBD development

'

and Licensee Event Reports (LERs) initiated as required.

EDM-170

required the remaining items to be entered into the Problem

Investigation Process (PIP) for tracking and resolution. Additionally,

the l u ensee's February 10. 1997. response to the 10 CFR 50.54f letter

related to the Adequacy and Availability of Design Basis Information.

P

4

N

stated that DBD open items woeli be ente 1

into the PIP for trackir.g

and resolution.

Enclosure 2

.

Mi

20

TM inspector reviewed the resolution of open item in the Reactor

coolant System DBD to sample the adecuacy of item resolution activity.

Approximately 20 items were evaluatec to verify that the PIP and

interfacing station programs evaluated and resolved the open item

issues.

The items were adequately resolved.

An independent industry audit of Catawba in late 1996, identified as a

finding the numerous lon9-term unresolved DBD open items. The response

to the finding was to initiate a blanket PIP (PIP 0-C97-0595 dated

March 5,1997) to cover the systems with the identified open items.

Many of these open items were not previously in the PIP process. The

PIP corrective actions established a schedule to resolve and close the

referenced DBD open items by September 1. 1997,

During this inspection, the inspector identified additional E

'en

items which were not entered into the PIP process nor incluau .d the

blanket PIP. The open items.were included in DBD CNS-1435.00-0002. Post

Fire Safe Shutdown, revision 4. and DBD CNS-1465.00-00-0018. Station

Blackout (SBO) Rule, revision 2.

Although not entered into the PIP

3rocess. the licensee provided meeti g documentation indicating the Post

rire Safe Shutdown open items were being evaluated.

These items were

identified by a November 1995 electrical post fire shutdown review

performeo after the initial DBD development and entered into the DBD by

revision 4 at that time. There was no c: :umented evaluation of

o)erability or A

tie PIP process.ppendix R commitments which would have been addressed by

Following the inspector's identification of this issue

the licensee initiated PIP 0-C97-1918 to track resolution of these open

items.

The inspector identified no significant safety concerns related

to the open items reviewed. This failure to follow procedure for

resolution of DBD open items is identified as the second example of

Violation 50-413.414/97-09-04: Failure to Follow Procedure.

SITAS

The ins)ector reviewed a recently comp'eted SITA report dated June 11.

1997, w11ch reviewed the adequacy of resolution of SITA findings.

The

scope of the audit was good in that it reviewed the resolution of 80

findings from four previous SITAs. The depth of the audit was good in

that corrective act ans were verified through the extent of station

programs (e.g. . PIP work requests, modification etc. .) involved in the

resolution. The findings were well defined and demonstrated an

independent and objective audit. Corrective actions for the findings

hcd not yet been developed.

EDG 10 CFR Part 21 Notice

The inspector ruiewed the licensee's actions to address a Cooper

Industries 10 CFR Part 21 notice regarding potentially defective EDG

intake / exhaust valve springs which was applicable to Catawba. The

notice was initiated in 1991 and revised on May 1. 1997. The licensee

had included an inspection for the spring defect into the EDG

maintenance procedure. A defective spring was identified at Catawba in

1996. The spring was replaced. analyzed, and sent to the vendor for

'

Encloture 2

.

_

._.

_ _ _ _

..

..

.

.

..

.

.

..

21

further analysis.

The licensee's respon.e to the notice on this issue

was appropriate,

c.

Conclusions

Resolution of DBD open items was generally adequate in that no safety

significant issues were identifieo in the open items. A violation was

identified for failure to follow licensee procedure requirements to

enter open DBD open items into the station PIP process for tracking and

resolution.

The audit of SITA corrective actions demonstrated that the

.

licensee was aggressively following SITA findings and is identified as a

strength in corrective action performance. Additionally, the licensee

adequately addressed the EDG 10 CFR Part 21 issue related to potentially

defective intake / exhaust springs.

E3

Engineering Procedures and Documentation

E3.1 Chanaes. Tests. and Exneriments Performed in Accordance With

10 CFR 50.59 (thru December 31. 1996)

a.

Insoection Scone (37551)

'

f

By letter dated March 31, 1997. Duke Power Company (the licer.see)

submitted its annual summary of all changes, tests, and experiments,

which were completed under the provisions of 10 CF,150.59 for the period

through December 31. 1996. The licensee's March 31, 1997, summary

included approximately 380 changes made during the subject period. The

inspector evaluated these changes against the p,avisions of the

regulation.

<

b.

Observations and Findinas

In accordance with 10 CFR 50.59, a licensee may:

(1) make changes in

the facility as described in the safety analysis report, (2) make

changes -in the procedures as described in the safety analysis report,

and (3) corduct tests or experiments not described in the safety

analysis report, without prior Commission approval, unless the change

involvy a changc in the Technical Specifications or an Unreviewed

Safety duestion (US0). The regulation defines an US0 as a proposed

action that:

(a) may increase the probability of occurrence or

consequences of an accident or malfunction of equipment important to

safety previously evaluated in the safety analysis report, or (b) may

create a possibility for an accident or malfunction of a different type

than any previously evaluated in the safety analysis report or (c) may

reduce the margin of safety as defined in the basis for any Technical

Specification.

The inspector reviewed the licensee's current (dated March 10. 1997)

version of Nuclear System Directive 209. "10 CFR 50.59 Evaluations."

which is patterned after NSAC-125. " Guidelines for 10 CFR 50.59 Safety

Enclosure 2

.

_ _ _ _

_--

__

--

22

Evaluations." June 1989.

This document requires that changes be

evaluated against the appropriate Final Safety Analysis Report (FSAR).

Technical Specifications, end NRC Safety Evaluation Report sections to

determine if there is need for revision.

Specifically, the criteria

specified by 10 CFR 50.59 are broken down into seven (7) questions.

For

a change to be qualified for 10 CFR 50.59, the answers to all seven

questions must be "no".

Based on review of this document, and the

review of the licensee's 10 CFR 50.59 evaluations. the inspector

concluded that the licensee's directive appropriately reflects the

criteria of this regulation and that. if followed accordingly, should

ensure that a change would be correctly performed under this regulation.

The inspector performed an in-office review of the licensee's summary to

determine the nature and safety significance of each change. Through

this review, the inspector selected the following changes for more

detailed review onsite:

e

Exempt Changes:

Exempt Change CE-3176

Exempt Change CE-3705

Exempt Change CE-3759

Exempt Change CE-4745

Exempt Charge CE-4746

Exempt Change CE-4821

Exempt Change CE-4822

Exempt Change CE-7416

Exempt Change CE-7977

Exempt Change CE-8126

Exempt Change CE-8182

Exempt Change CE-8245

Exempt Change CE-8410

Exempt Change CE-61008

Exempt Change CE-61162

Miscellaneous Changes:

e

SIMULATE (a computer code) Version 4

Modifications:

NSM CN-11371

NSM CN-20396

0:?rable But Degraded Evaluations:

o

PIF 2-C97-0157

PIP 2-096-3250

Operability Evaluations:

e

Enclosure 2

_

~

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

23

Operability Evaluation dated 2/15/94

Operability Evaluation dated 2/18/94

Operability Evaluation dated 6/28/94

e

Procedure Channes:

OP/1/A/6200/11

AM/2/A/5100/07

OP/2/B/6200/33. Change 4 Rev. 4

OP/1/A/6550/14

PT/1/B/4700/82

The ins ector determined that these changes were correctly evaluated

under t e provisions of 10 CFR 50.59

During the in-office and onsite reviews, the inspector made a number of

observations and has communicated them to licensee personnel:

The use of n ke-specific system identifiers in the annual summary

u

(which is submitted to the NRC and is thus available to the

public) is discouraged unless the licensee provides a key in the

l

l

summary. These identifiers do not bear any apparent correlation

l

to the actual systems (e.g. , NC = reactor coolant system. KC =

l

component cooling system, etc..).

The inspector made a similar

observation on the summary submitted on March 2~. 1996 (see

Inspection Report 50-413.414/96-10).

'

The licensee's corresponding revision of the UFSAR. per 10 CFR

o

50.71. lags behind 10 CFR 50.59 evaluations.

The next u)date of

the UFSAR. scheduled for late 1997. should capture all tie changes

that are within the scope of the UFSAR.

While the licensee had acceptably evaluated all the changes

e

audited by the inspector, a number of them eppeared in the summary

with insufficient information for a reader to even determine what

system was involved, or what change was made.

The inspector

recommended a several-sentence description. identifying the

system, the component, and the nature of the change, and

accompanied by a several-sentence evaluation.

Despite this

problem with the summary, the evaluations were found to be

thorough and in compliance with 10 CFR 50.59.

The licensee was

aware of this aroblem with the summary and has initiated actions

to correct suc1 weakness by revising its guidance document. NSD

209 (see Problem Investigation Process Form 0-C97-2027. dated June

19. 1997).

The term " Exempt Changes" may cause confusion in the context of 10

CFR 50.59.

It is a term internal to the licensee's docunentation.

It pertains to changes that "do not require the Modification

Enclosure 2

- _ _ _ _

1

b

24

Program controls for configuration management and therefore are

specifically exempted from the requirements to process an

editorial NM or NSM." According to licensee personnel, an " exempt

change" is essentially a minor change.

The summary contained a significant number of errors, which stated

e

the opposite of the actual facts.

For example, test procedure

TT/1/A/9200/88 states "there are Unreviewed Safety Questions

associated with this test procedure" when the onsite evaluation

shows that there was no unreviewed safety question.

The licensee

submitted a letter on July 9, 1997, correcting such errors.

c.

Crnclusions

Based on in-office review of the licensee's March 31, 1997, annual

summary on 10 CFR 50.59 changes, onsite review of the licensee's 10 CFR 50.59 evaluatius, and audit of the licensee's 3rocedures, the inspector

concluded that the licensee had complied with t1e provisions of the

regulation for the changes listed in the annual summary.

l

IV. Plant Suocort

R1

Radiological Protection and Chemistry Controls

R1.1 Tours of the Radiolooical Control Area (RCA) (71750)

The inspectors periodically toured the RCA during the inspection period.

Radiological control practices were observed and discussed with

t

!

radiological control personnel, including RCA entry and exit, survey

postings

locked high radiation areas, and radiological area material

conditions.

The inspector concluded that radiological control practices

were proper.

V. Management Meetinas

X1

Exit Meeting Summary

The inspectors ) resented the inspection results to members of licensee

management at t1e conclusion of the inspection on July 11 and July 23. 1997.

The licensee acknowledged the findings presented.

No proprietary information

was identified.

Dissenting comments were not received from the licensee.

Enclosure 2

_ - _ _ _ . - - - _

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t

25

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Bhatnager. A. . Operations Su>erintendent

Birch. M. . Safety Assurance ianager

Coy., S., Radiation Protection Manager

Forbes. J., Engineering Manager

Jones. R.. Station Manager

Harrall. T., Instrument and Electrical Maintenance Superintendent

Kelly. C.. Mainteriance Manager

Kimball . D. , Safety Review Group Manager

Kitlan. M., Regulatory Compliance Manager

'

Nicholson. K., Compliance Specialist

Peterson. G., Catawba Site Vice-President

Tower. D., Regulatory Compliance

l

,

4

Enclosure 2

u

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

__

26

INSPECTION PROCEDURES USED

IP 37551:

Onsite Engineering

IP 40500:

Effectiveness of Licensee Controls in Identifying. Resolving, and

i

Preventing Problems

IP 61726:

Surveillance Observation

IP 37550:

Engineering

IP 62707:

Maintenance Observation

IP 71707:

Plant Operations

IP 71750:

Plant Support Activitia

IP 92901:

Followup - Operations

IP 92902:

Followup - Maintenance

IP 92903:

Followup - Engineering

IP 93702:

Prompt Onsite Respense to Events

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

i

50-414/97-09-01

NCV

Failure to Declare Ice Condenser

Intermediate Deck Doors Inoperable and Log

Appropriate TSAIL Entry (Section C1.1)

50-414/97-09-02

NCV

Inadequate Lower Containment Ventilation

Unit Operating Procedure (Section 01.4)

'

50-414/97-09-03

VIO

Failure to Follow Procedure Results in

Invalid Local Leak Rate Test of Valve 2NV-

874 (Section M1.2)

50-413.414/97-09-04

VIO

Failure to Follow Procedure - Two Examples

(Sections 08.1. E2.1)

Closed

50-413.414/97-01-01

VIO

Failure to Include All Structures Systems

and Components in the Scope of the

Maintenance Rule as Required by 10 CFR 50.65(b) (Section M8.1)

50-414.414/97-01-02

IFI

Followup and review of licensee procedure

to implement the requirements of (a)(1)

and (a)(2) of the Maintenance Rule after

issuance of Revision 2 of Regulatory Guide 1.160 (Section M8.3)

50-413.414/97-01-03

IFl

Followup on Licensee Actions to Provide

Performance Criteria for Structures After

Resolution of this Issue (Section M8.4)

Enclosure 2

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

_

27

50-413.414/97-01-04

VIO

Failure to implement the requirements of

(a)(1) and (a)(2) of the Maintenance Rule

(Section M3.2)

50 413.414/94-13-02

URI

Emergency Operating Procedure 50.59

Evaluations Not Reviewed by Nuclear Safety

Review Board as Required by TS (Section

l

'

08.1)

<

l

List of Acronyms

!

CFR

Code of Federal Fagulations

-

DBD

Design Basis Documents

-

EDG

Emergency Diesel Generator

-

EDM

Engineering Directives Manual

-

E0P

Emergency Operating Procedure

-

FIP

Failure Investigative Process

-

FSAR

Final Safety Analysis Report

-

IAE

-

Instrument and Electrical

IFI

-

Inspector Followup Iten

IST

Inservice Testing

-

LCVU

Lower Containment Ventilation Unit

-

LER

-

Licensee Event Report

LLRT

Local Leak Rate Test

-

MPFF

Maintenance Preventable Function Failure

-

NCV

Non Cited Violation

-

NM

Nuclear Sampling

-

NRC

Nuclear Regulatory Commission

-

NSD

-

Nuclear Site Directive

NSRB

Nuclear Safety Review Board

-

DAC

Operator Aid Com] uter

-

POR

-

Public Document

Room

PIP

-

Problem Investigation Process

PM

-

Preventive Maintenance

asig

Pounds Per Square Inch Gauge

-

RCA

-

Radiologically Controlled Area

RCP

-

Reactor Coolant Pump

RCS

Reactor Coolant System

-

RG

-

Regulatory Guide

SA

--

Main Steam to Auxiliary Equipment

SB0

-

Station Blackout Role

SITA -

Self Initiated Technical Audit

SPOC

Single Point of Contact

-

TPBE -

Thermal Power Best Estimate

TS

-

Technical Specifications

TSAIL -

Tech Spec' Action Item Log

UCLF -

Unplanned Capability loss Factor

UFSAR -

Updated Final Safety Analysis Report

Enclosure 2

_

28

URI-

-

Unresolved Item-

USO

Unreviewed Safety Question

-

VDC'

Volts direct current

-

.

VIO

Violation

-

-VV

Containment Ventilation

-

WO

Work Order

-

YN

Auxiliary Building Chilled Water

-

l

Enclosure 2

_