ML20197F286

Insp Repts 50-413/97-14 & 50-414/97-14 on 971012-1122. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20197F286
Person / Time
Site:	Catawba
Issue date:	12/19/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20197F239	List: IR 05000414/1997008 ML20197F234 ML20197F248 ML20197F286
References
50-413-97-14, 50-414-97-14, NUDOCS 9712300176
Download: ML20197F286 (34)

See also: IR 05000413/1997014

Text

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U.S. NUCLEAR REGULATORY COMMISSION

REGION 11

Docket Nos: 50 413. 50 414

License Nos: NPt'-35. NPF 52

Report Nos.: 50 413/97 14. 50 414/97-14

Licensee: Duke Energy Corporation

Facility: Catawba Nuclear Station. Units 1 and 2

' Location: 422 South Church Street

Charlotte, NC 28242

Dates: October 12 - November 22. 1997

Inspectors: D. Roberts. Senior Resident Inspector

R. Franovich, ResidMt Inspector

M. Giles, Resident inspector (in Training)

D.Forbes.RadiationSpecialist.RegionII(SectionsR1.2.

R1.3. RI.4, R3.1. Re.l. and R8.1)

Approved by: C. Ogle. Chief

Reactor Projects Branch 1

Division of Reactor Projects

Enclosure 3

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EXECUTIVE SUMMARY

Catawba Nuclear Station. Units 1 and 2

NRC Inspection Report 50-413/97-14, 50 414/97 14

This integrated inspection included aspects of licensee operations

maintenance, engineering and plant support. Thereportcoversa5 week

period of resident inspection. It also includes the results of an announced

inspection by a regional radiation specialist.

Doerations

. In general, the conduct of operations was professional and safety

conscious. (Section 01.1) 1

e A minor overpower excursion resulted in the 15 minute running average

for reactor thermal

an extended aeriod. power slightly

The power exceeding

excursion licensed power

was contained limits for

within criteria

established Jy previous NRC guidance. (Section 01.2)

e Control room o)erators failed to detect an extinguished 'DC Power On"

light for the Unit 1 turbine-driven auxiliary feedwater pump for almost

three days. The impact on Jump operability of the blown fuse which

caused the extinguished 1191t. will be reviewed during closeout of the

URI. (Section 01.3)

. Operations personnel inappropriately entered the Technical Specification

action statement more than an hour after a reactor trip system logic

function failed to meet surveillance test acceptance criteria. However,

the failed function was repaired, successfully retested, and returned to

service before Technical Specification actions were required. (Section

01.4)

• Nuclear Systerr Directive 317 provided structure and delineated

responsibilities for freeze protection. Proceduralized activities were

initiated and completed in a timely manner, and work requests were

initiated to resolve identified discrepancies. The licensee's efforts

to effectively protect plant equipment and systems from freezing

conditions improved since the previous cold weather season. (Section

02.1)

• Four unreltted non emergency events were reported to the NRC in

accordance with Title 10 Code of Federal Regulations. Part 50.72 during

the period. All of the events were properly reported with sufficient

information provided. (Section 02.2)

• Examples of poor performance were noted concerning activities

surrounding the inappropriate tagout of a residual heat removal system

miniflow valve during planned maintenance. (Section 04.1)

. A deviation, with two examples, from NRC commitments was identified.

Both examples involved administrativc errors resulting in commitments

Enclosure 3

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being changed internally without proper notification of the NRC.

(Sections 08.1 and 08.2)

licintenance

• Surveillance activities observed by the inspectors involved good

workmanship, proper use of procedures, good radiological practices. and

) roper management of Technical Specification action statements. (Section

11.1)

• New fuel movement activities to support the upcoming Unit I refueling

outage were performed well. (Section M1.2)

Enoineerinq

• An unresolved item was identified concerning containment penetrations

associated with stea < cupply lines to both units' turbine driven

auxiliary feedwater ,o ms, which were not in compliance with Title 10

Code of federal Regulations. Part 50. Appendix A. General Design

Criterion 57. The licensee had submitted an exemption request

concerning this issue to the NRC during the previous inspection report

period. (Section El.1)

. Remote manual closure capability existed for dual function containment

isolation valves; however, the action involved resetting the emergency

diesel generator load sequencer. an action requiring further evaluation

to be conducted under the above unresolved item. (Section El.1)

. A non cited violation was identified concerning the use of aluminum

separators in high efficiency particulate air 111ters located inside

containment. (Section E8.2)

ElantSunnort

• An example of poor oerformance was identified related to a radiological

control area boundary beinc) compromised. This minor discrepancy was

immediately corrected by plant aersonnel and properly addressed by

licensee management. (Section 11.1)

. The licensee effectively imalemented a program for shipping radioactive

materials required by the NRC and Department of Transportation

regulations. (Section R1.2)

. The licensee was meeting established goals for radioactive waste

generated. Radiological facility conditions and housekeeping in

radioactive waste storage areas were observed to be good. (Section

R1.3)

Enclosure 3

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• One violation was identified for failure to provide current dose rate i

information on a radioactive inaterial label as required by Ti'.ie 10 Code

of Federal Regulations. Part 20.1904(a). (Section Rl.3)

• The licensee's water chemistry control program for monitoring primary

and secondary water quality had been implemented for those parameters

reviewed. in accordance with the Technical Specification requirements

and the Station Chemistry Manual for pressurized water reactor water

chemistry. (Section RI.4)

. The licensee had properly implemented procedures to maintain an

effective program to monitor and control liquid and gaseous radioactive

effluents to limit doses to members o the public. Theprojected

offsite doses resulting from those effluents were well within the limits

specified in the Technical Specifications, the Offsite Dose Calculation

Manual. and Title 40 Code of Federal Regulations. Part 190. (Section

R3.1)

. The licensee was effectively conducting formal radiation protection and

chemistry audits as required by Technical Specifications and was

completing corrective actions in a timely manner. (Section R7.1)

. Tha Emergency Jperations facility located in downtown Charlotte. North

Carolina and its associated equipment were in good repair and condition.

Energency communication and plant computer equipment in the Technical

Support Center was in good working order. (Section P2,1)

Enclosure 3

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Renort Details  ;

Sumary of Plant Status

Unit 1 operated at or near 100% )ower until November 21, when it began its

end of-cycle 10 coast down for 11e upcoming refueling outage. The unit ended

the inspection period at 98 percent power,

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Unit 2 operated at or near 100 percent power until October 20, when a power

redu: tion was initiated to comply with Technical Specification (TS) 3.6.3  :'

following a nitrogen leak associated with the accumulator for main feedwater *

isolation valve 2CF 33. Power was reduced to approximately 15 percent power,

at which the time the valve was gagged shut a.1d repairs commenced. _Upon ,

completion of the leak repair and valve post naintenance testing activities. '

the unit was returned to 100 percent power on October 21. On November 21. a ,

' power reduction to 50 percent was initiated to allow a control circuit card

associated with main turbine control valve C h1 to be replaced. Licensee ,

personnel also replaced a solenoid valve ano cleaned instrument air lines

associated with main generator power circuit breaker (PCB) 28. These

activities were completed on November 22 and power was increased to 97 percent  !

by the end of the inspection period.  ;

Review of Vodated Final Safety Analysis Reoort (UFSAR) Commitments

While performing inspections discussed in this repart, the inspectors reviewed ,

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

The inspectors verified that the UFSAR wording was consistent with the

observed plant practices, procedures, and parameters.

I. Operations

01 Conduct of Operations

01.1 General Comments (71707)

The inspectors conducted frequent control room tours to verify proper

staffing, operator attentiveness and communications, and adherence to

approved procedures. The inspectors attended opf.ations turnovers and

site direction meetings to maintain awareness of overall plant

operations. Operator logs were reviewed to verify operational safety

and compliance with 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 lousekeeping. Problem Identification Process (PIP) reports

were routinely reviewed to ensure that potential safety concerns and

equipment problems were reported and resolved.

In general, the conduct of operations was professional and safety- .

conscious. .The Unit 2 power reduction associated with feedwater

isolation valve 2CF-33 was conducted safely. Good plant equipment

material conditions and housekeeping were noted throughout the report

Enclosure 3

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period. However as addressed below, several human performance related  !

deficiencies wele identified.

01.2 H1nor Excursion Over Licensed Power Limits for Unit 1

a. .lmeection Scone (71707)

The inspectors reviewed the circumstances associated with a minor power i

excuision on Unit 1. f

b. Observations and findinas

P

On October 21, 1997. the inspector noted during a review of control room

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logs that the Unit 1.15 minute running average for reactor power, as ,

indicated by the Operator Aid Computer (OAC), had exceeded 100 percent.

<

The Unit 1 operator noticed this at 3:39 a.m. and reduced turbine load

by 5 megawatts and inserted control rodt. two steps to bring power aelow

100 percent. Operations personnel later generated station PIP l-C97-

3382 to document and investigate the power excursion.

The inspectors reviewed the PIP and noted that the Unit 1 OAC 15 minute  :

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average was stated as having been in alarm for 15 minutes. The

inspectors reviewed 0AC trend reports for reactor power and noted that .

the maximum instantaneous reactor power level, according to secondary

heat balance best estimates (computer point C1P1445), was ap3roximately 1

100.6 percent recorded just before 3:15 a.m. According to tie trend

report.powercontinuallyspikedbetween99.7and100.3percentpower

for the next 20 25 minutes before operators noticed the 15 minute

average and reduced power. Computer trends indicated that the 15 minute

average

However,it peaked at 100.05

never .'eached the percent

alarm setand was

point in for yercent).

(100.1 about 20 minutes.

Further 1

discussions with plant personnel and review of alarm listory data

indicated that the statement in the PIP concerning the alarm being in

for 15 minutes was in error. Later, this :tatement was corrected in the

PIP documentation. '

Further investigation by the inspectors determined that routine reactor

cooldnt system Doron dilutions were )erformed earlier in the shift.

However, this was last done 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> aefore the noted power excursion.

The inspector interviewed control room personnel who indicated that

several activities were occurring at the time of the minor over power.

including those associated with a Unit.2 down power (see Section 08.2 of '

this report). The operator indicated that these activities may have

been a distraction and

minute average earlier,possibly prevented him from noticing the 15- i

Discussions with operators 31d plant management indicated that operators

were expected to maintair eactor p& ar at licensed power levels.

Operators were expected to contiv.' ly monitor power and immediately

take actions to keep it within i yt. Plant management discussed this- -

Enclosure 3

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excursion with those personnel involved in the event and emphasized the

need for iiereased diligence when monitoring power levels.

The inspectors reviewed NRC guidance on minor power excursions and noted

that the power level did not exceed previously established criteria,

c. Conclusion

The inspectors concluded from their review that the )ower excursion was

minor and was contained within criteria established )y previous NRC

. guidance.

01.3 Control Power Unavailable to the Unit 1 Turbine Oriven Auxiliarv

Mger (Af W) Pumo Irio And lhrottle Valve

a. Insocction Scone C/110D.

The inspectors reviewed the circumstances associated with a loss of

control power to the Unit 1 turbine driven AFW pump trip and throttle

valve.

b. Observations and Findinni

During a control room tour on November 17, the inspectors noted that the

~0C (Direct Current) Power On" li

4 driven AFW pump was extinguished.ght associated

The inspectors with

informed the the Unit

o)erator 1 turb

at the controls of this observation. The operator replaced the wio and

the light was still not lit. The inspectors mentioned that they had

3reviously observed the light to be out 3 days earlier on November 14

)ut had assumed then that the extinguished light was related to ongoing

maintenance involving a 72-hour LC0 on the system. Theoperatorstated

that this ? ulb was in the control circuit for the AFW pump turbine trip

and throttle valve. Subsequent licensee troubleshooting determined that

fuse FU-2 in control panel 1ELCP0245 was blown. A review of several

electrical drawings indicated that control aower and electrical

overspeed trip functions for the trip and tirottle valve were powered

through this fuse. The trip and throttle valve and the turbine driven

AFW pump were declared inoperable shortly after 10:00 a.m. and the fuse

was subsequently replaced.

The inspectors discussed aspects of this incident with plant personnel

to determine whether operators may have missed opportunities to identify

the deficiency earlier, and to determine the true impact of the blown

fuse on the system's capability to perform its safety functions. The

inspectors noted that t1e blown fuse also caused control power

indication to be extinguished at a local control panel, and that if the

fuse was indeed blown for more than 3 days, plant personnel may have

missed additional opportunities to identify a problem while on-field

tours. The ins)ector noted that there were no formal checks in licensee

procedures of tle *DC Power On" light in the control room.. There were

Enclosure 3

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also no control room alarms indicating control power unavailability for

the trip and throttle valve.

Engineering personnel were still evaluating whether or not losing

control power or the electrical overspeed trip function rendered the ,

sy. tem inoperable. According to Section 20.4.1.1. " Auxiliary feedwater ,

Pump Turbine," of s)ecification CNS-1593.SA-00 0001. Design Basis

Specification for tie Main Steam to Auxiliary Equipment System (SA) and ,

feedwater Pump Turbine Exhaust System (TE). Revision 11: at least one of

the overspeed trip devices (mechanical or electrical) must be operable <

for the turbine driven auxiliary feedwater pump to be operable. The t'

mechanical overspeed trip function was not affected by the blown fuse.

The inspectors concluded that further review of this incioent and its '

impact on the turbine driven AFW pump was necessary. Pending further -

NRC review, this item is characterized as Unresolved item (URI) 50-

413/97-14 01: Control Power Unavailable to the Unit 1 Turbine Driven i

AFW Pump's Trip and Throttle Valve.

c. Conclusion

Control room o)erators failed to detect an extinguished *DC Power On"

light for the Jnit 1 turbine driven AFW pump for more than three days.

The impact of the blown fuse on pump operdbility will be reviewed during

closeout of the URI. t

01.4 Hanaaement of Technical Soecification (TS) Limitina conditions for

Operation

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a. InspectionStone(71707)

During a surveillance test of the Unit 2 reactor trip system  ;

instrumentation on October 10. 1997, a problem associated with the

overpower differential temperature (0PDT) reactor trip logic was

identified. The inspector discussed the test failure with operations

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3271, personnel, read the associated TS, and reviewed station PIP 2 C97-

b. Observations and Findinas

During the performance of IP/2/A/3200/002A Solid State Protection

System (SSPa) Train A Periodic Testing, Revision 21. on October 10.

1997, the OPDT reactor trip logic test acceptance criterion was not met.

A red lamp illuminated to indicate that a malfunction of the logic

testing was detected (a green lamp would have illuminated if the logic

test had been acceptable). The surveillance test began at 9:56 a.m.,

and the failure was identified some time before noon. Test technicians

backed out of the test, and the reactor trip system was removed from the

TS Action item List at 12:10 p.m. Engineering aersonnel were_ involved

to assist operations personnel in determining tie extent of the

operability concern (i.e., was the problem limited to OPDT trip logic or

Enclosure 3 -

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did it affect all of the solid state protection system). Engineerin

personnel concluded that the problem was limited to the OPDT trip lo ic

and communicated their conclusion to operations per.vnnel at around :00

p.m. The A train of Automatic Trip and Interlo: 's ' unctional Unit

19 of TS 3.3.1. Table 3.3-1) was declared inopc'e 30 p.m.

placing the unit in a six hour action statement .. n the function

or be in Hot Standby (Mode 3) in the following six v v

The inspectors questioned operaticns shift personnel about the decision

to enter the required action at 1:00 p.m. rather than when the OPDT

reactor trip logic ttst failure occurred. The response was that

engineering involvement was needed to determine the scope of the )roblem

(and inoperability) so that the appropriate TS action could be tacen.

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Af ter the inspectors discussed the issue with the operations shift

personnel, they recognized that determining the scope of the

inoperability was independent of the time after which actions were

required. .

Engineering personnel determined that a failed circuit card caused the

test failure. The circuit card was replaced, and testing was com)leted

successfully. The action statement was terminated at 4:30 p.m. tlat

same day.

c. Conclusions

The inspectors concluded that operations personnel inappro)riately

entered the TS action statement more than one hour after t1e test

failure of a reactor trip system logic function. The failed function

was repaired, successfully retested and returned to service before TS

actions were required.

02 Operational Status of Facilities and Equipment

02.1 Cold Weather Protection Preoarations

a. Insnection Scone (71714)

.The inspectors reviewed Nuclear System Directive (NSD) 317. Freeze

fruiection Program. Revision 1: interviewed the freeze protection

coordinator: reviewed procedures and work orders to determine what

actions had been taken to prepare for cold weather; and independently-

inspected some vulnerable equipment exposed to the environment for

freeze protection,

b. Observations and Findinas

The licensee completed NSD 317 in March 1997. The NSD governs the

freeze protection alans at all three Duke nuclear stations. During the

previous cold weatler season, the NSD had not been finalized and a

formal program was not in place for ensuring that effective measures

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Enclosure 3

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were in place to protect plant equipment and systems from sub freezing j

conditions.

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The station assigned a freeze protection coordinator to monitor the

status of preparation activities. An equipment freeze protection ,

program was developed to identify operating plant systems, structures  !

and components (SSCs) that may be subjected to freezing temperatures

during the cold weather season. An engineering support program was ,

initiated to ensure that specific freeze protection measures for

vulnerable SSCs were identified to facilitate the preparation and

completion of a pre-seasonal eneckout. Pre seasonal checkouts were '

executed via various model work orders for inspection and testing of

electrical heat trace and instrument box heaters. The freeze protection

plan includes surveillance procedures to inspect SSCs considered to be

critical to plant operation on a monthly interval and as necessary

during extreme cold weather.

The inspectors discussed the status of freeze protection preparations

.with the freeze protection coordinator. According to the coordinator,

the annual preventive maintenance activities had been completed by the

end of the inspection report period, and work-orders or work requests -

had been generated to address identificd discrepancies. The freeze .

protection coordinator had performed inspections of vulnerable areas and

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submitted a list of discrepancies to the maintenance orcanization. Most

ofthesediscrepancieswereresolvedbytheendoftheInspection ,

period.

The inspectors conducted inspections of equipment that historically had

been vulnerable to cold or freezing temperatures. The inspectors >

notified the freeze protection coordinator of a few minor discrepancies.

The inspectors also reviewed the work orders associated with the annual ,

preventive maintenance (PM) and verified that work had been completed.

c. Conclusions

Nuclear System Directive 317 provided structure and delineated

responsibilities for freeze protection. Proceduralized activities were

initiated and completed in a timely manner, and work orders or work

requests were initiated to resolve identified discrepancies. The

inspector concluded that the licensee's efforts to effectively protect

plant equipment and systems from freezing conditions had improved since

the previous cold weather season.

02.2 Prompt Onsite Response to Events (93702)

.

The licensee reported four unrelated events to the NRC Headquarters

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Operations Officer via the Emergency Notification System in accordance

with 10 CFR 50.72. The following events were all reported in a timely

fashion with sufficient information being provided,

Enclosure 3

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Oil Sheen on Lake Wylie on October 15 i

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On October 15. the inspectors were notified of a thin oil sheen that was

discovered on Lake Wylie during a main fire pump test. The source of  :

the oil was determined to be an overflowing pump bearing reservoir which

caused oil to spill around the fire pump motor and eventually into the

lake. The oil sheen was contained by a boom beneath the pum) structure. i

The licensee notified the South Carolina Department of Healt1 and

Environmental Controls and the National Response Center, which in turn

required notification of the NRC 'q accordance with 10 CFR

50.72(b)(2)(vi).

Plant Shutdown Reauired By TS on October 20

As discussed in Section 08.2 of this report. the licensee initiated a >

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Unit 2 shutdown on October 20 when it entered TS Limiting Condition for

Operation 3.6.3 action statement following the inoperability of the 2A ,

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steam generator main feedwater isolation valve 2CF-33. The unit was

helti at 15 percent power after the valve was deactivated and gagged

shut. The valve was repaired and a forced unit shutdown was avoided.

This item was reported to the NRC in accordance with 10 CFR

50.72(b)(1)(1)(A).

'

)otential Non Conservatism in a Calculation used to Distinauist Between

Reactor Coolant System F' ow Versus leactor Power Restricted anc

)rohibited 02eratino Rea1ons

On October 23. the licensee reported a potential nonconservatism in each  !

units' 15 3/4.2.5. Departure from Nucleate Boiling (DNB) Parameters.

Figure 3.2 1. Reactor Coolant System Total Flow Rate Versus Rated

Thermal Power - Four Loops in Operation. Essentially, licensee

personnel determined that the curve provided in Figure 3.21 for each

unit permitted potential plant operation at reduced power levels with

reactor coolant system flow rates that could possibly challenge DNB

ratio design limits for certain analyzed transients. As a precaution,

until this condition could be resolved, the licensee implemented

administrative restrictions requiring reactor coolant system flow rates

to be maintained above those specified as the permissible operation

region for 100 percent power. These restrictions were verified to be in -

place by the resident inspectors. Long term corrective actions included

completing an analysis to allow a revision to the TS requirements to

eliminate the non-conservatism. This item was reported in accordance

with 10 CFR 50.72(b)(2)(111)(D). The licensee documented this issue in

a 30 day written follow up Licensee Event Re) ort (LER 50-413/97-007)

near the end of the inspection period. Furtier inspector review of this

issue will.be conducted and tracked under the LER in subsequent'

inspection reports.

Enclosure 3

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Potential for Overfilli.Da Steam Generator Durina a Postulated Accident

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On November 18. the licensee re)orted a single failure vulnerability

involving the loss of 125 Volt )C vital instrument and control

distribution center EDE or ELF during a postulated steam generator tube

rupture event coincident with a loss of offsite power. The licensee

determined, following a detailed analysis that the loss of either of

these busses would result in the inability to isolate turbine driven

auxiliary feedwater pump flow to a ruptured steam generator. The steam

generator would be pntentially overfilled, resulting in uncontrolled

releases of radioactivity to the atmosphere.

Because of this potential, and until further corrective actions are

determined, the licensee implemented conservative administrative

controls limiting the amount of dose equivalent iodine in the reactor

coolant system to ensure the consequences of the Chapter 15 steam

generator tube rupture analysis remain bounding. These restrictions

were contained in procedure CMP 3.4.17.1. Primary Chemistry. Revision 28

and verified by the inspectors. At the close of the inspection period,

the licensee was evaluating several o)tions for long-term corrective

actions. This item was reported to tie NRC in accordance with 10 CFR

50.72(b)(1)(11)(B).

04 Operator Knowledge and Performance

04.1 Residual Heat Removal (RHR) System Potentially Placed in An Unanalyzed

Condition

a. Insoection Scope (71707)

The inspectors reviewed the circumstances involving an August 20. 1997,

tagout in which the RHR system was potentially ) laced in an unanalyzed

condition. The inspector reviewed the Catawba Jesign Basis Document

(DBD) CNS 1561.ND 00-0001: the UFSAR. Section 6.3 and Chapter 15: and

PIP 2-C97 2722. The inspectors also ruiewed the licensee's root cause

investigation, completed during this inspection period. and discussed

this issue with engineering and operations personnel.

b. Observations and Findings

Residual heat removal system valve ND59B 1s a motor 0)erated globe valve

located in the minimum flow lines of the 18 and 2B RH1 pumps. Valve

N059B and its associated miniflow line normally protect either B train

pump from cavitation at low flow conditions or following a complete loss

of suction during the decay heat removc1 or emergency core cooling modes

of operation.

On August 20. 1997, at 3:38 a.m. operations issued removal and

restoration (R&R) tagout 27-1498 to support work on the Unit 2 Train B

RHR miniflow loop. Unit 2 train B RHR was declared inoperable and

Enclosure 3

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entered into the Technical Specification Action Item Log (TSAIL). The

planned work included a miniflow valve controlling set point

modification, a gauge replacement, and an instrument calibration. The

R&R tagged valve ND59B open with power removed. Approximctely 2-1/2

hours later at 6:00 a.m., work control personnel realized that the

tagout was in conflict with Catawba Design Basis and Criteria,

Specification CNS-1561.ND-00-0001. Revision 5, which stated that "with

ND59B stuck open and incapable of closing, the resulting diversion of

RHR ) ump fluid to the recirculation loop is an unanalyzed condition."

At tiat time, operations personnel cleared the tagout and closed the

valve. Station PIP 2-C97-2722 was initiated and the licensee later

determined that a past operability evaluation was required.

Engineering

September 1997, is, personnel

and concluded completedthat the the

RHRpast

systemo)erability evaluation

was operable during on

the time the miniflow valve was tagged open. The inspectors discussed

this conclusion with licensee personnel and upon reviewing UFSAR Table

6-7, Catawba Nuc1 car Station Emergency Core Cooling System Flow Rates,

arrived at the same conclusion. This was based on the fact that the

RdR flow capacity (approximately 500 gallons per minute) normally

diverted from the reactor coolant system recirculation loop by miniflow

valve ND59B, when subtracted from the total RHR flow ca)acity, still

resulted in sufficient RHR flow being delivered to the RCS during the

post-accident recirculation mode. However, the inspectors considered

the tagging ciscrepancy to represent a problem that could have had

adverse plant impact.

A root cause investigation of the improper tagging incident was

completed by the licensee during this inspection period which concluded

that engineering persornel improperly communicated a 1993 DBD revision

to affected groups. The RHR DBD had been revised then to provide a

discussion of the "unanalyzed condition." However, this analysis did

not take into consideration lesser flow requirements assumed in UFSAR

Table 6-7 for the post-accident long-term recirculation mode of

operation, the time at which the RHR system alignment would be changed

and the miniflow valve would become a diversion flow path.

The inspectors considered other human performance weaknesses contributed

tc the tagging error. When the calibration work order from which the

tagout was generated (PM 95054445) was developed in July 1995, a note

was added for operations personnel to tag the tr niflow valve open. i

Although personnel involved in planning the set point change

modification were aware of the DBD statement, and verbiage was included

in the modification package to ensure the tagout was correct and would

not place the RHR system in an unanalyzed condition, the set point

modification was performed under an existing tagout for the preventive

maintenance work, which had the valve opened on August 20.

The inspectors noted that the DBD had not been consulted when the tagout

associated with the August 20, 1997, activities was developed a week

Enclosure 3 I

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i . .

10

earlier. The inspectors, discussed this with licensee management, who

stated that the 1995 PM work order note likely contributed to an

overr'. ding operating philosophy that tagging the valve open during

maintenance was appropriate. Several corrective actions were generated

for PIP-2-C97-2722, including developing a policy for communicating

engineerits document revisions to affected groups and designating a

specific work management mtem panel to document engineering

recommendations and spe notes. The inspector asked whether or not

the DBD reference to t b analyzed condition" would be deleted to

reflect the engineering e.idlysis discussed above. Licensee management

indicated they would evaluate changing the DBD.

c. Conclusions

The inspectors concluded that although having the Unit 2 train B RHR

pump out of service with valve ND598 de-energized open did not place the

plent in an unanalyzed condition, examples of poor performance were

identified concerning activities leading up to the valve inappropriately

being tagged open during plaaned maintenance.

08 Miscellaneous Operations Issue (92901)

08.1 (Closed) LER 50-414/95-01: Reactor Trip Due to Closure of a Main Steam

isolation Valve

The event described in this LER involved an automatic reactor trip due

to the failure of a digital optical isolator (D01) in the B main steam

isolation valve control circuit that caused the valve to close. This

LEP was discussed in NRC Inspection Report 50-413.414/97-12 and remained

opea pending further NRC review,

Planned corrective action 2 was to develop a PM program to periodically

monitor continuously enc gized E-max 00ls with model numbers 175C156 and

175C157 in critical applications. Instead, the licensee initiated a PM

program to re) lace DOIs that perform a control function and that have AC

voltage for t1eir inaut )ower su) ply every twelve years. The inspectors

determined that the 4RC 1ad not )een apprised of the change.

In light of recent DOI failures that resulted in manual reactor trips in

July and August 1997, the inspectars asked the licensee if monitcring

the D01s could have revealed the root cause (degraded resistors) of the

r eent DOI failures. The licensee indicated that the test methodology

that would have been used to periodically monitor the D01s would not

have revealed degraded resistors (the cause of the 1997 failures). The

inspectors concluded that, while testing the DOIs had the potential to

reveal degraded D01s during periodic testing, the likelihood that it

would have done so was low. Therefore, tl. commitment change did not

substantially reduce the opportunity to identify degraded DOI resistor::

and take subsequent actions to prevent the 1997 001 failures.

Enclosure 3

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__ - _ - - - - _ --_ - _____-___ - __ - - _ ___

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11- .

According to Nuclear System Directive (NSD) 214. Comitment Management:

ts are a source of NRC-

EProgram Revision

comitments. 2.-214.8.4i

Section Licensee Event

Remove or-Rep" Change a.Comitment. stated .'

that the regulatory compliance-(RGC) group should be notified if- a

comitment change is needed, and that RGC will determine, in part. if

'

-

the NRC- should be notified.- The NSD'incor> orates a 1994 draft document

prepared by the Nuclear Energy Institute (4EI). entitled " Guideline for

Managing NRC Commitments."

-

.

Acc0rding to NSD 214, when a comitment is changed, the original

comitment-will be modified with a description of the change in the

appropriate section of the PIP database (which is used to track NRC

comitments-to resolution). The NSD further stated that if the change  ;

is determined to be significant enough, a new commitment may be-

generated. However, proper cross-references shall be provided to link

-the original commitment to the revised commitment. The licensee

determined that the NRC was not apprised of the commitment change

'

because the corrective actions representing the comitment were

improperly cross-referenced. As a result, the changed corrective action

was not identified as an-NRC commitment, and RGC was not notified.- The

inspector concluded that the licensee failed to notify the NRC of a

-

comitment change regarding planned corrective actions delineated in LER

50-414/95-01. This issue is charact rized as one example of Deviation

50-413.414/97-14-02: Changing NRC Comitments Without Properly

Notifying the NRC.o ,

4

'

This item is closed.

.

08.2 (Ocen) Violation R0-413/97-08-01: Inadequa'.e Alarm Response Results in

Inadequate and untimely Correctite Actions for Valve Operability

' Determination

.The inspectors reviewed Violation 50-413/97-08-01 for an April- 3.1997.

.

-incident following a similar occurrence on October 20, 1997. where a

feedwater isolation valve became inoperable after a nitrogen leak

developed on its accumulator.

On the morning of October 20, 1997. just before shift turnover, the Unit

2-control room operators received a computer alarm indicating low--

nitrogen gas pressure in the accumulator associated with the 2A steam

,

generator main feedwater isolation' valve. 2CF-33. The valve was-

declared inoperable and TS Limiting Condition for Operation (LCO) 3.6.3

was imediately entered. Nitrogen pressure was checked and found to be

at 1640.psig, which was below the low operability limit of 2050 psig.

The' accumulator-was recharged to 2760 psig and the TS'LC0 was exited.

- Approximately 2-3 hours'later at 9:55 a.m., another low aressure alarm

~

-

was received, ard operators again entered the 4-hour TS _C0 action-

requirement to either return the valve to operable status, de-energize

(gag) it shut, or initiate plans to be in Hot Standby in the following 6

hours. After the second alarm. the accumulator was found to be at 1810

Enclosure 3

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

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12

spsig and a-leak was detected from a solenoid valve at the actuator. The i

nitrogen: accumulator was1again recharged but could not be maintained ,

above the low pressure limit. Technical Specification 3.6.3 required  !

that= the plant to be in Hot Standby (Mode _3) by _7:55 p.m. l

Plant management decided that a power reductior, would be initiated-

shortly after 1:00 ).m.- .The unit was reduced to approximately 15

rpercent power and t1e valve was gagged shut just before the TS LCO

Laction to be in Hot Standby was required, thus avoiding a forced.

shutdown. A leaking 0 ring at a solenoid-to tube connection was

detected. The solenoid was re) laced and the valve was tested

successfully. Unit 2 exited tie LCO action statement and was returned-

. to 100 percent-power on October 21.

-

.

e

'

The inspectors reviewed Violation 50-413/97-08-01 which documented a. .

timilar occurrence on April 3.1997. Involving feedwater isolation valve )

1CF-51. Following the April 3. 1997, incident. plant personnel

determined that the control room 0AC alarm set point was set at or near

- the pressure at which the valve became inoperable. One of the planned

corrective actions-documented in-the licensee's written response to the.

violation: dated July 22, 1997. was for engineering personnel to evaluate

whether'the alarm set-point could be raised to provide more margin

-

between it and the operability limit thereby allowing operators more <

time to react to an actuator leak. According to the licensee's letter.

>' ~

4

this action was to be completed by September 30, 1997. Following the. J

-

.0ctober 20 ;1997.: occurrence, the inspectors inquired about the status - i

i '

-of the engineering evaluation. Licensee personnel indicated that it had

not been performed and that engineering personnel had been internally

granted an extension of the due date from the safety assurance group to

October 31.

The inspectors noted that the NRC had not been notified of this

commitment change and upon inquiring furt'ner, were told that an

administrative error in the data-entry process for the PIP associated

with the- April 3.1997, incident allowed engineering to be granted an

extension without evaluating the impact of changing this commitment.

Upon discovery of the error, licensee personnel corrected it in the PIP

database and an engineering evaluation was completed by the new

deadline. A modification was subsequently initiated to raise the

-accumulator alarm set points for-all of the feedwater isolation valves

and provide greater margin above their operability' limits.

The inspectors determined that the failure to perform the engineering

evaluation in a timely manner further increased the chances of a

feedwater isolation valve becoming inoperable prior to the control room

receiving the alarm. 'The inspettors reviewed the documents associated

-

with NRC commitment management programs described in Section 08.1 above

and determined that the failure to perform this evaluation by September

30. 1997. constituted a Deviation from NRC commitments. This issue is-

-

characterized-as the second example of Deviation 50-413.414/97-14-02:

Enclosure 3

0

= ..

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

_ . _ _ _

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13

Changing NRC Commitments Without Properly Notifying the NRC. Violatir

50-413/97-08-01 will remain open pending completion of all of the

licensee's corrective actions and further review by the inspectors.

Maintenance

M1 Conduct of Maintenance

[ M1.1 General Comments (61726)

The inspectors observed portions of the fol h ing surveillance and

inspection activities:

. NPP-312. Nuclear Fuel And Core Component Receipt Inspections.

. PT/1/A/4200/09A. Auxiliary Safeguards Test Cabinet Periodic Test.

• PT/1/A/4400/06A. Nuclear Spray (NS) Heat Exchanger 1A Heat

Capacity Test.

. PT/1/A/4400/09. Cooling Water Flow Monitoring For Asiatic Clams

And Mussels Quarte'ly Test.

. PT/1/A/4200/04B. Containment Spray Pump 1A Performance Test.

. PT/1/A/4350/0028. Diesel Generator 18 Operability Test,

s Retype No. 28

\ During these activities. the ins ectors noted proper use of procedures,

properly calibrated measuring and test equipment effective radiological

controls, and adequate communication between personnel performing the

tests.

M1.2 New Fuel Movements (62707)

The inspector observed movement of new fuel from the dry storage racks

to the spent fuel pool in pre]aration for the upcoming Unit 1 end-of-

cycle 10 refueling outage. T11s activity was conducted under Work Order 97063472-01. Move New Fuel from New Fuel Vault to Spent Fuel Pool. The

technicians used procedures OP/1/A/6550/011. Retype 21. Internal

Transfer of Fuel Assemblies and Components: and OP/1/A/6550/006. Retype

11. Transferring Fuel with the Spent Fuel Manipulator Crane. The

inspector noted. for the fuel assemblies observed, that they were placed

correctly in locations referenced by the procedure attachment. Proper

radiological controls were observed. Crane chNklist prerequisites had

been completed as required. This work activity was conducted well.

M8 Miscellaneous Maintenance Issues (92902)

M8.1 (Closed) Inspector Follow UD Item (IFI) 50-413.414/97-08-04:

Reportability of Nuclear Service Water (NSW) System Actuations.

This item was opened to determine the reportability of NSW system

actuations. The licensee generated station PIP 0-C97-1715 to document

the clarification. The licensee determined that the NSW system is

Enclosure 3

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14

required for support of the Engineered Safety Features (ESF). As such.

the NSW system is characterized as an ESF support system in the UFSAR.

Section 7.3.1.1.5. ESF Support Systems. The licensee concluded that,

since the NSW system is not an ESF and since 10 CFR 50.72 and 50.73

require licensee's to report any event or condition that results in a

manual or automatic actuation of any ESF. actuations of the NSW system

were not reportable.

The inspector reviewed ap)licable sections of NUREG 1022. Event

Reporting Guidelines 10 C R 50.72 and 50.73: NUREG 0800, the Standard

Review Plan (SRP) for the Review of Safety Analysis Reports for Nuclear

Power Plants. Light Water Reactor Edition. June 1987: the UFSAR: and

Nuclear System Directive 202. Reportability. Revision 8. The

characterization of the NSW system as an ESF support system was in

agreement with the SRP which referred to service water systems as

auxiliary systems that directly support ESF systems. However. Chapter 6

of the UFSAR. Engineered Safety Features, does not contain a listing of

ESF systems: a listing, which does not include the NSW system, is

located in Nuclear System Directive 202. Reportability. Revision 8

Appendix A. Engineered Safety Features. Chapter 7 of the UFSAR.

Instrumentation and Controls. Section 7.3.1.1.1 lists ESF functions

initiated by the Engineered Safety Features Actuation System (ESFAS):

the NSW pumps which provide cooling water to the component cooling

sy> tem heat exchangers and are thus the heat sink for containment

cooling, are listed.

Based on this r;"tiew, the inspectors determined that NSW system

.

actuations are not reportable. This item is closed.

III. Enaineerina

El Conduct of Engineering

El.1 Operation Of Dual Function Containment isolation Valves-Temocrarv

Instruction (TI) 2515/136 (Closed)

a. Inspection Scoce

The inspectors used TI 2515/136. Operation of Dual Function Containment

Isolation Valves, to determine if the licensee had procedures in place

to remotely close containment isolation valves when required while a

safety injection or a containment spray signal was present. The

inspector discussed this issue with engineering personnel, and reviewed

the UFSAR and design basis documentation.

b. Observations and Findinas

The Tl included a questionnaire survey with four items. Item 1

requested that the inspectors identify the dual function valves as

listed in the UFSAR and determine whether differences existed in the

Enclosure 3

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plant. Licensee personnel provided a list of containment isolation

valves, which included dual function valves. The inspector compared the

valve list to the valves shown on UFSAR Table 6-77, Containment

Isolation Valve Data. All valves identified by the licensee were found

to exist in Table 6-77.

During the ins)ectors' review, it was noted that two of the valves

listed SA-1 ()enetration M 261. B Main Steam to Auxiliary Feedwater

Pump Turbine) and SA-4 (Penetration M-393,~ C Main Steam to Auxiliary

Feedwater Pump Turbine), did not comply with 10 CFR 50. Appendix A.

General Design Criterion 57. General Design Criterion (GDC) 57. Closed

System Isolation Valves, specifies that each line that penetrates

primary reactor containment and is neither part of the reactor coolant

pressure boundary nor connected directly to the containment atmosphere

shall have at least one containment isolation valve which shall be

either automatic, locked closed, or capable of remote manual operation.

Valves SA-1 and SA-4 are manual gate valves and normally in the locked

open )osition. These valves and containment penetrations exist in both

Catawaa Units 1 and 2. The GDC 57 noncompliance had been previously

identified and an exemption request (from GDC 57) was submitted on

September 2, 1997. This item is being tracked as Unresolved Item 50-

413.414/97-14-03: Noncompliance With 10 CFR 50. Appendix A. General

Design Criterion 57 Closed System Isolation Valves.

Item 2 asked whether or not a safety-related dual function valve could

be closed from the control room with a switch and remain closed in the

presence of a containment spray or safety injection signal. As

indicated by the licensee's list, reset and closure capability existed

with remote. manual control on all safety-related dual function valves

with the exception of SA-1 and SA-4, which were locked open. Some

valves, as indicated on the licensee's list, would require the emergency

diesel generator (EDG) load sequencer be reset in addition to normally

resetting the ESF (or Safety Injection) signal. The EDG Load Sequencer

system engineer indicated that resetting the ESF signal would not affect

the configuration or operating status of any safety-related equipment,

and that resetting the EDG Load Sequencer would not affect the EDG or

any com)onents being powered from the safety-related 4160 volt busses.

While tie inspectors were familiar with the reset capability for the

safety injection signal, further NRC inspection was necessary to verify

thet resetting the EDG Load Sequencer during an accident would not

adversely impact the operation of safety-related plant equipment. This

review effort will be conducted under URI 50-413,414/97-14-03 discussed

above.

Item 3 requested, for valves that do not have a switch for remote

closure [i.e. , SA-1 and SA-4]. if any proceduralized method existed

(such as deenergizing circuits or lifting leads or installing leads)

that would facilitate remote closure. Since valves SA-1 and SA-4 are

locally operated manual valves, no remote method of closure existed.

Enclosure 3

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Item 4 requested,lfor valves that do not have'any remote method of-  ;

closure:available [i.e.. -SA 1 and SA-4], whether there were any other

means that the licensee had to close the. isolation valve. The licensee -

.

provided a list of eight emergency procedures that contain provisions to

isolate Penetration M-261 or M 393'as required. Two isolation options  ;

were provided. - The first-option utilizes the SA-1 or SA-4 valve as

required located in the plant doghouses. The second option-isolates the

>

penetration by closing valves SA-3 or SA 6 located downstream of:SA-1-

and SA-4 =in the Penetration Area if SA-1 and SA-4 were inaccessible.

j

.

The inspectors reviewed these procedures and found that the procedural

guidance to' establish containment isolation manually for penetrations.M-

261 and M-393 was available to operators when needed. ,

-c. " Conclusions

=An unresolved item was identified concerning containment penetrations

-associated with steam supply lines-to both units' turbine driven

i auxiliary feedwater h h in compliance with 10 CFR 50,

1A>pendix A, GDC 57. The' pumps,

licensee had w icsubmitted

were notan exemption request to

t1e NRC for this-issue. Remote manual closure capability. existed for

-

• dual function containment isolation valves; however, the action involved

resetting the emergency diesel generator load sequencer, an action

requiring further evaluation to be conducted under the above-mentioned

. unresolved item, ,

,

E2 Engineering-Support of Facilities and Equipment i

p

E2.1 Solid State Protection System (SSPS) Testino Deficiency

a. Insoection Scooe (37551)

The inspectors reviewed the licensee's discovery of a logic testing

. deficiency associated with both trains of each unit's SSPS - November

11, 1997.

b. Observations and Findinas ,

The test deficiency-involved the failure to perform adequate testing of

two universal-cards associated with feedwater isolation functions and

the P-10 source range. nuclear instrumentation reactor trip block

permissive. . Theiuniversal cards contained previously unidentified

parallel: circuit paths which were not being isolated and independently

verif ted to actuate the logic circuitry associated with each function.

sBoth units entered TS 4.0.3 after identifying the missed surveillance

testing; The procedures were revised and the testing conducted-

,

' satisfactorily before each unit exited TS 4.0.3.

The test anomaly was identified by personnel in the licensee's General-

Office and.was immediately communicated to the SSPS vendor and to

various other nuclear power facilities via operating experience data

-Enclosure 3

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17- )

-bankst Several facilities have since identified the same or.similar;

deficiencies in their SSPS logic testing procedures,

~

c. Conclusion

-The licensee has issued LER 50;413/97-08 to document the' missed TS-

surveillances and discuss the safety consequences and corrective actions- 1

- taken for the deficiency. Further NRC-review will-be conducted during

closecut of the LER.  ;

Miscellaneous Engineering Issues (92903)

'

E8

E8.1-- (Closed) Insoector Follow UD Item 50-413.414/96-18-04: Quam. fication

,

' of_ Refueling Water-Storage Tank (FWST) Heat Losses Through Tank Roof

--Including a Wind Velocity Factor.

This-item involved minor modification CNCE-8309 to de-energize one.of >

four-FWST heater clusters. The licensee performed an evaluation to

demonstrate that minimum required tank tem)erature of 70-degrees

- Fahrenheit (*F) could be maintained with t1e three remaining: heaters.

-The evaluation involved a calculation. CNC 1249.00-00-0065. Operability

Determination for PIP 1-C96-1870 - Heater Sizing for the FWST, that .

'

quantified-heat losses from the tank assuming a minimum temperature of -

5*F and wind velocity of up to 20 miles per hour (mph). The calculation " -

-

>1ndicated that'the total FWST~ heat lossiat was-81.88 KW. r -

,t

The inspector;noted that-the calculation: accounted for wind-induced heat-

losses from the tank walls, but not from the tank roof. To address this

observation the licensee completed Revision 1 of calculation CNC-

1249.00-00-0065 and concluded that, accounting for heat losses from the

FWST roof assuming a 5 m3h average wind velocity the total FWST heat

< loss was 93.46 KW at an WST temperature of-75*F and environmental

temperature of -5*F. With one heater cluster inoperable and-de-

-energized, the total heater capacity available is 90 KW. The-licensee

indicated that the environmental tem ereture selected for design

comparison in the calculation was be ow the coldest temperature ever

recorded at the site. it was unlikely that temperatures would drop to

that temperature. The licensee also indicated that the heat loss would

t 'be 87.42 KW if the tank wall temperature were assumed to be 70 F (the TS

value)'. and therefore within the heating capacity of the three remaining

heater clusters. Based on these and other conservative heat loss-

assumptions applied to the calculation, the licensee asserted that the

-

remaining heater capacity was marginal to maintain the FWST at 75 F. but

that it was adequate to prevent a temperature drop below the TS-required

value of 70*F.

.

. Refueling water storage tank temperature-indications are available in

'

the control room. In addition, a low

a

.

temperature alarm will be

. generated at 74 F. The alarm response would be to dispatch an operator

to verify heater operation. A Lo-Lo temperature alarm would be

. Enclosure 3

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a

r -- Wwy wr,y,u

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c18_-  ;

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+ - generatsd when. tank temperature reaches 70*Fi The response then would.

-

= be to declare the FWST inoperable per the appropriate TS, Based on the; i

heat loss calculation, monitoring-capabilities and response procedures. . .

the ins >ector concluded:that-FWST temperature was not likely to-_ drop 4

,

.

below t1e TS required value of 70*F as:a result of this minor 1 . . 7

modification. -Shouldsa-low temperature alarm be ger.erated, effective-

measures were in place to ensure that action will be-taken to correct

the. low temaerature condition or. place the unit in a safe condition; In ,

. addition.- tie licensee planned to correct the heater leakage, re-

energize the heater and return' it to service during the upcoming end-of-

icycle 10 refueling outage, scheduled to begin in late November.-

. The ins)ector noted that the wind velocity assumed for heat _ losses from

the tan ( walls was 20 mph.-whereas 1t was assumed to-be only 5 mph.for-

heat losses from the tank roof.- While no explanation for this

' '

discrepancy was- 3rovided in the calculation, the inspector concluded

that, since the 1 eater was:to be returned to service in December 1997,  ;

'

this discrepancy did not pose a safety concern. This item is closed.

b E8.2_ (Closed) Unresolved Item-50-413.414/97-11-04: Use of Aluminum High

Efficiency Particulate Air (HEPA) Filter Separators Inside Containment.

'

- This item involved the licensee's ~1dentification of aluminum HEPA filter

i

separators in the containment ventilation system's containment auxiliary '

w a- charcoal filter units?(CACFUs) that had~not been accounted for:in the

~

t :

- ~

station's aluminum-inventory records'. :The licensee initiated an >

l --  ;

evaluation _to determine the-root cause'of the inappropriate material.

,

usage.

.

The licensee's evaluation revealed that the HEPA filters had contained

-

aluminum since 1986 or before. Design Specification CNS-1211.00-3,

Containment Auxiliary Charcoal Filter Units, Section 5.5, High

,

Efficiency Filter Section, states that " Separators, if used, shall be

304 stainless-steel." The licensee determined that the original HEPA

.

filters were a separatorless, nuclear grade filter without aluminum.

However, at some undetermined point in time, the station began to use a

different HEPA filter, containing aluminum. ,in the CACFUs. The licensee.

- could not locate any documentation to support the change in filters and

'

terminated the ioot cause evaluation, which was not likely to reveal the

origination of the discrepancy.

- The. inspector concluded that, although the error leading-to the.

discrepancy had occurred over. ten years ago, the licensee has since

"

established a 3rocess that would prevent a similar oversight from

,

occurring _ at tae:present time. - A changeLin filter components (or other -

. components:inside containment) would involve the-modification process.

- Essentially, NSO.301. Nuclear Station-Modifications.: dated September 30, ^

1997? required that a Technical Issues Checklist be completed for- any

temporary.: minor, or nuclear station;(permanent-and major) modification.

_ The Technical 7 Issues Checklist, located in Appendix A of the NSO. 1

' Enclosure 3-

,

. -

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-19

addressed containment. issues and hydrogen control. The question "Does

the change add aluminum or zinc that could potentially increase the

amount of hydrogen gerierated inside the containment post accident?"

would likely prompt a review for this potential during the current

modification process.

The licensee re-evaluated the original hydrogen generation calculation

and determined that the amount of hydrogen generated inside containment

following a design basis accident that would oe produced by the

additional aluminum did not exceed revised allowable limits.

Therefore, the safety consequences were minor. However, measures were

not effective in preventing the selection of thesc filters for use in an

unsuitable application as required by 10 CFR Part 50. Appendix B.

Criterion III. This constitutes a violation of minor significance and

is characterized as a Non-Cited Vielation (NCV). consistent with Section

IV of the NRC Enforcement Policy. This item is identified as NCV 50-

413.414/97-14-04: Failure to Control Use of Aluminum Inside The

Containment Building.

The ins)ector determined that the licensee hed been informed by

Westing louse of the potential that certain HEPA filters were being

manufactured with aluminum separators. The information was conveyed via

Vendor Information Letter 96-30 in September 1996. The licensee's

response to the information was to consult the design specification

(CNS-1211.00 3) to determine if aluminum was specified.' Upon finding

that the specification required the.use of 304 stainless steel, the

licensee concluded that the CACFU's " EPA filters did not contain _.

aluminum. The inspector concluded 4 at the original review in response

to the Westinghouse information letter was cursory and ineffective in

revealing this discrepancy. The inspector reviewed the revised hydrogen

generation calculation: no concerns or discrepancies were identified.

This item is closed.

IV. Plant Sucoort

R1 Radiological Protection (RP) and Chemistry Contro'

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

a. Insoection Scoce (71750)

The inspectors periodically toured the RCA during the inspection period.

Radiological control practices were observed and discussed with

radiation protection personnel, including RCA entry and exit controls,

survey postings, and radiological area material conditions.

Enclosure 3

- . _ . .

_ - . . .. .. m .. _ _ _ _ _ . _ _ _ _ _ . . . ._

a c

. .-

d

'

- 20

b'.  : Observations and Findinas'

,

100 November.17. the inspectors noticed an RCA exit door propped wide-

_open with a brick. -The doorway was on the 594 foot elevation of the-

-

.

auxiliary building at the end of corridor number 517 and provided RCA'-

,

-access from the outside. - Two stanchions with a roped sign hanging

-between them ncrmally blocked 6ccess past the door into tns: RCA but the

- -stanchions and' sign had been moved to the side and out of viewt -The

sign was intended to warn personnel that they were about to enter the 3

- RCA and directed them to contact radiation protection, personnel for

_

assistance. At the-time of the ins)ector's obstrvation. no personnel

were present to control access at t11s RCA entry point. 1

'

The inspectors notified radiation protection (RP) 3ersonnel who- -

'immediately responded to the location and closed tie-door. Later. the

'

same: sign was attached to a swing gate which was placed at the entrance.

,

-The gate would close after allowing personnel pre-appraved access across-

.the boundary. -The inspectors were in. formed by RP personnel that a:

maintenance crew-had been using the door to bring scaffolding into the

- plant in preparation.for the upcoming Unit I refueling outage. The-

maintenance crew had received permission from RP to use the door. The

crew had moved the, sign blocked the door open, and temporarily left the

drea to Conduct other activities.

.~ "

r :The inspectors discussed with" licensee personnel the need to properly- *

-

.

control access:to the RCA. Licensee personnel generated PIP 0-C-97-3670:

>

^

to document this deficiency. The incident was discussed in a-subsequent: -

c daily management meeting. In addition to the immediate corrective

4 actions above. RP management discussed this incident with scaffolding

supervisors who later discussed it with their crew members to reinforce

proper procedures for entering the RCA.

-The inspectors later observed that general access to this area from the

outside was limited to the scaffold crew because of a second external

n . barrier that had been _placed outside to control personnel traffic.

While this barrier was not intended for RCA access control it reduced

the significance:of the inspectors' finding.

c. Conclusions-

An example of poor performance was identified related to an RCA boundary

.

-being_ compromised. -This' minor _ discrepancy was immediately corrected by_

-

plant personnel and properly addressed by licensee management.

s3

,

RI.2 Transoortation of Radioactive Materials

'

-ai -Insoection Scone (86750) -

L '

The inspectors evaluated the licensee's transportation of radioactive

materials programs for implementing the revised Department of

Enclosure 3

.

., , - , , , , - ... .,. - , , . ~ . - - 4 , .. ,----

.v. . * e. ---.w

-

'

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21

Transportation (00T) and. NRC trans)ortation regulations for shipment of

radioactive materials as required )y 10 Code of Federal Regulations

(CFR) 71.5 and 49 CFR Parts 100 through 177.

b. Qb.servations and Findinos

The inspectors reviewed procedures and determined that they adequately

addressed the following: assuring ' hat the receiver has a license to

receive the material being shipped; assigning the form. quantity type,

and proper shipping name of the material to be shipped: classifying

waste destined for burial; selecting the type of package required:

assuring that the radiation and contaminatis : limits are met: and

preparing shipping papers.

Licensee's records for the six shipments of radioactive material

performed in 1997 were reviewed and the inspectors determined the

shipping papers contained the required information. The inspectors also

determined the licensee had maintained records of shipments of licensed

material for a period of three years after shipment as required by

10 CFR_71.91(a). In addition, the licensee )ossessed a current

certificate of approval (NRC Form 311) for t1eir " Quality Assurance

Program Description for Radioactive Material Shipping Packages Licensed

Under 10 CFR 71." The licensee had also maintained current NRC

certificate of compliance for the NRC approved cask in use.

The inspectors reviewed the training records for selected individuals

-

authorized to sign shipping papers and: handle radioactive waste which

included a w area su)ervisc who was assigned to the area of

transportati .. the weet of the inspection. The training specifically

addressed the new rules for the following to)ics: low specific activity

(LSA) and surface contaminated object (SCO) idzards, definitions, and

requirements: placarding, labeling, and marking of vehicles and

packages: use of Systems Internationals (SI) units on shipping papers,

labels, and emergency response instructions after April 1.1997: package

selection: waste classification: shipping papers; and receipt procedures

and surveys. The inspectors concluded that personnel involved with

radioactive material shipping were maintaining current training

qualifications.

c. Conclusions

The licensee had effectively im)1emented a program for shipping

radioactive materials required ]y NRC and DOT regulations.

R1.3 Radiolooical Protection and Chemistry Controls

a. Insoection Scone (84750)

The inspectors reviewed implementation of-selected elements of the

licensee *s radiation protection and chemistry program. The review

Enclosure 3

.

_ . .. . . _ , . . _ . . _ _ _ . . . _ _ _. _ _ . _ _ _ .

V

.

. -

._

'

.o ^

,

,

-

22

1

included observation of radiological protection activities for the

control of. radioactive material as required by 10 CFR Parts 20,1801.

~

-

_ __

1802. 1902. and 1904.

b.-' Observations and Findinos ,

i The inspectors reviewed licensee goals for waste generated and buried

-

,

and determined the licensee was meeting these goals. During tours of

-

- the auxiliary building and radwaste building facilities, the inspectors

reviewed survey _ data and performed selected independent radiation and ,

contamination surveys of radioactive material storage areas. During a

'

tour of the hot tool issue room on November 19, 1997, the inspectors

found a vacuum cleaner with radiation dose rates higher than indicated

'

on the radioactive material label.. dated 1995, affixed to the vacuum 1

4

cleaner. The tag stated radiation levels to be 1.5 millirem per hour on

-contact and 0.5 millirem at 30 centimeters. However, the inspectors

determined and the licensee confirmed radiation levels to be up to 40

< millirem per hour contact and 2-3 millirem at 30 centimeters. Also, the

vacuum cleaner hose was not taped or capped on the end as required by-

'

licensee procedure for vacuum cleaners in storage. Licensee procedure

'

required vacuum cleaners to be surveyed after use.and that current

- survey information was to be included on the radioactive material label

"

(yellow tag). - The licensee taped over the vacuum hose and performed

independent radiation-and contamination surveys of the vacuum cleaner

and the general area'. :The licensee determined contamination hadinot. -

-

• -

-

-

1been spread as:a result of the open hose. The licensee also relabeled r

the vacuum cleaner to include current' survey information. .

4

^

Ouke Power Company. System Radiation Protection Manual. Procedure No.

III-18. titled Use of Vacuum Cleaners In Radiologically Controlled

Areas. Revision 3. dated August 1. 2996, states that vacuum cleaners

should be surveyed during and after use and update dose rates on yellow

'

_ tags, if applicable, each time a radiation survey is performed.

10 CFR 20.1904(a) recuires, that the licensee shall ensure that each

container of licensec material bears a durable. clearly visible label

~

bearing the radiation symbol and the words CAUTION RADI0 ACTIVE MATERIAL

or DANGER RADI0 ACTIVE MATERIAL. The label must also provide sufficient

information-(such as radionuclides f the quantity

i .of radioactivity, radiation-levels.present, kinds ofan estimate

materials, and o mass

enrichment) to permit individuals-handling or using the containers or

working in the vicinity of the containers. to take precautions to avoid

or minimize exposures.

The-inspector informed the licensee that failure to provide current

-survey.information on the radioactive material label constituted a

violation of licensee procedure Use of Vacuum Cleaners In Radiologically

Controlled Areas. III-18. Revision 3 and a violation of 10 CFR

-

" -

20.1904(a). This item is identified as Violation 50-413.414/97-14-05:

1 Failure to Label Radioactive Material As Required by 10 CFR 20.1904.

Enclosure 3

g -

-1

.

t + -- W- w -e-vip---r r- w - ,->N,-,r ,-cv-m ,- -

w

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

.

.

23

c. Conclusions

The licensee was meeting established goals for radioactive waste

generation. During plant tours, radiological facility conditions and

housekeeping in radioactive waste storage areas were observed to be -

good. One violation was identified for failure to provide current dose

rate information on a radioactive material label as required by licensee

procedure and 10 CFR 20.1904(a).

P1.4 Water Chemistry Controls

a. Insoection Scoce (847501

The inspectors reviewed implementation of selected elements of the

licensee's water chemistry control program for monitoring primary and

secondary water quality as described in the TS limits, the Station

Chemistry Manual, and the UFSAR. The review included examination of

program guidance and implementing procedures and analytical results for

selected chemistry parameters,

b. Observations and Findinos

The inspectors reviewed selected analytical results recorded for Units 1

and 2 reactor coolant primary water chemistry samples taken between May,

=

1997 and November, 1997, and secondary system water chemistry samples

taken between August, 1997 and November, 1997. The selected parameters

reviewed for primary water chemistry included dissolved oxygen,

chloride, pH. and fluoride. The selected parameters reviewed for

secondary water chemistry included hydrazine, dissolved o.xygen sodium,

copper, and chloride. Those primary system parameters reviewed were

maintained well within the relevant TS limits for power operations.

Those secondary system parameters reviewed were maintained according to

station procedures.

The inspectors reviewed and discussed the licensee's system for tracking

performance indicators in the areas of primary and secondary water

chemistry. The inspectors noted the licensee had maintained a high

level of success in human performance and equipment reliability in 1997

based on performance indicators for these areas which included no missed

surveillances and no mispositioning of components.

c. Conclusions

Based en the above reviews, it was concluded that the licensee's water

chemistry control program for monitoring primary and secondary water

quality had been implemented, for those parameters reviewed in.

accordance with TS requirements and the Station Chemistry Manual for

pressurized water reactor water chemistry. The licensee had maintained

a high level of success in human performance and equipment reliability

-in 1997.

Enclosure 3

. .

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24

R3 Radiation Protection and Chemistry Procedures and Documentation

R3.1 Radiation Protection and Chemistry Procedures and Documentation

a. Insoection Scone (84750)

The inspectors reviewed licensee effluent release limits and pathways as

described in the licensee's Offsite Dose Calculation Manual and in

Chapter 16 of the Selected License Commitments Manual,

b. Observations and Findinas

The inspectors reviewed annual effluent data for 1996 and compared the

data to previous annual reports back to 1992. Arinual Radioactive

Effluent Release Reports were required to be submitted to the NRC prior

to May 1 of each year. Summaries of the quantities of radioactive

-materials in liquid and gaseous effluents released from the facility and

an assessment of the radiation doses due to those releases were required

to be included in the reports. The inspectors reviewed the supporting

data for the effluent release report covering 1996. The amount of

activity released during 1996 as dissolved gases in liquid effiuents and

fission gases, and that released as iodines and particulates in gaseous

effluents was generally within the ranges observed in past years. The

annual average per unit radiation doses for an individual from the

-

liquids and gaseous effluents were only a small percentage of their

respective annual limits. The total body dose as calculated by

environmental sampling data, was 0.902 millirem for 1996. There were no

abnormal releases reported in 1996.

c. Conclusions

Based on the above reviews. it was concluded that the licensee had

maintained an effective program to monitor and control liquid and

gaseous radioactive effluents, thereby limiting dose to members of the

public. The )rojected offsite doses resulting from those effluents were

well within tie limits specified in the TS. Offsite Dose C61culation

Manual, and 40 CFR 190.

R7 Quality Assurance in Radiation Protection and Chemistry Activities

R7.1 Ouality Assurance in Radiation Protection (RP) and Chemistry

a. Insoection Scooe (84750)

Licensee activities and self assessment programs were reviewed to

determine t.he adequacy of corrective action programs for identified

deficiencies in the areas of RP and chemistry.

Enclosure 3

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

. 4

o

25 -j

.

bl Ilc trvations and Findinos

-Reviews by the= inspectors: determined that Quality AssuranceLaudits-and

self assessments-in the RP and chemistry areas were accomplished _by

.

reviewing-procedures, observing work, reviewing industry documentation,

and performing plant walkdowns to include surveillance of work areas by

supervisors and technicians during normal work coverage. Documentation

of problems by licensee representatives was included in Quality

Assurance Audits and self assessment _ reports. Corrective actions-were

> included in the licensee's-PIPS and were being completed in a timely

manner.

'

c. Conclusions-

'

4

The ins

RP andchemistry

pectors-determined the-licensee

audits as required was effectively

by the TS-and was completing conducting formal ,

corrective actions in a timely manner. *

R8 Miscellaneous Radiation Protection and' Chemistry Issues (92904) ,

,

R8,1 (Closed) URI 50-413.414/97-04-Q2; Determine the y plicability of

'

-Monitoring Requirements of Criterion 64 of 10 CFR s0 A)pendix A: and

Reporting Requirenents of 40 CFR 190 and 10 CFR 50.36a legarding

Potential Unmonitored Release Pothways. .

.

This item was-closed using guidance from Regulatory Guide 1.109, ,

Calculation of Annual Doses to Man from Routine Releases of Reactor

Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50.

Appendix I. The specific guidance was found in Appendix 01. No

violation of regulatory requirements was identified. This item is

closed.

P2 Status of Emergency Protection Facilities, Equipment, and Resources

e

P2.1 General Comments (71750)

.

The inspectors toured the Eme'gency Operations Facility located in

downtown Charlotte. North Carolina on November 18, 1997. The inspectors

observed that the facility and associated. equipment, including emergency

communication telephones and plant computer screens and controls were

. functioning and in good repair. During tours of the Technical Support

.

Center, facility equipment was also noted to be in working order and of

good condition and repair.

.

Enclosure 3

d

,. , . - ~ _

. .

26

V. Manaaement Meetinoq

X1 Exit Heeting Sumary

The inspector presented the inspection results to members of licensee

management at the conclusion of the inspection on December 3, 1997. The

licensee acknowledged the findings presented. No proprietary

information was identified.

Enclosure 3

-

. .

27.

PARTIAL LIST OF PERSONS CONTACTED _

Licensee

.

M. Birch. Safety Assuranco Manager

M. Boyle. Radiation Protection Manager

R. Glover. Operations Superintendent

J. Forbes. Engineering Manager

R. Jones. Station Manager

K. Nicholson, Compliance Specialist

M. Kitlan Regulatory Compliance Manager

G.-Peterson Catawba Site Vice-President

R. Propst. Chemistry Manager

Enclosure 3

. .

28

INSPECTION PROCEDURES USED

IP 37551: -Onsite Engineering

IP 61726: Surveillance

IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71714: Cold Weather Preparations

IP 71750: Plant Support Activities

IP 84750: Radioactive Waste Treatment, and Effluent and Environmental

Monitoring

IP 86750: Solid Radioactive Waste Management and Transportation of

Radioactive Materials

IP 92901: Follow up - Operations

IP 92902: Follow up - Maintenance

IP 92903: Follow up - Engineering

IP 92904: Follow up - Plant Support

IP 93702: Prompt Onsite Response to Events

TI-2515/136: Operation of Dual Function Containment Isolation Valves

ITEMS OPENED, CLOSED, AND DISCUSSED

i Opened

50-413/97-14-01 URI Control Power Unavailable to the Unit 1

Turbine-Driven AFW Pump's Trip and

Throttle Valve (Section 01.3)

50-413.414/97-14-02 DEV Changing NRC Commitments Without Properly

Notifying the NRC (Section 08.1 and 08.2)

50-413,414/97-14-03 URI Noncompliance With 10 CFR 50 Appendix A

General Design Criterion 57 (Section

El.1)

50-413.414/97-14-04 NCV Failure to Control Use of Aluminum Inside

the Containment Building (Section E8.2)

50-413,414/97-14-05 VIO Failure to label Radioactive Material As

Required by 10 CFR 20.1904 (Section R1,3)

Closed

50-414/95-01 LER Reactor Trip Due to Closure of a Main

Steam Isolation Valve (Section 08.1)

50-413.414/97-08-04 IFI Reportability of Nuclear Service Water

System Actuations (Section M8.1)

Enclosure 3-

. .

29

50-413.414/96-18-04 IFI Quantification of Refueling Water Storage

Tank Heat Losses Through Tank Roof

Including a Wind velocity Factor (Section

E8.1)

50 413.414/97-11-04 URI Use of Aluminum HEPA Filter Separators

Inside Containment (Section E8.2)

50 413.414/97-05-02 URI Determine the Applicability of Monitoring

Requirements of Criterion 64 of 10 CFR 50.

Appendix A: and Reporting Requirements of

40 CFR 190 and 10 CFR 50.36a Regarding

Potential of Unmonitored Release Pathways

(Section RF, 1)

TI 2515/136 TI Operation of Dual Function Containment

Isolation Valves (Section El.1)

Discussed

50-413/97-08-01 VIO Inadequate Alarm Response Results in

Inadequate add Untimely Corrective Actions

for Valve Operability Determination

. (Section 08.2) -

LIST OF ACRONYMS USED ,

AFW - Auxiliary Feedsater

CACFU - Containment Auxiliary Charcoal Filter Units

CFR -

Code of Federal Regulations

DC -

Direct Current

DBD -

Design Basis Documents

DEV -

Deviation

001 - Digital Optical Isolator

DOT -

Department of Transportation

DNB -

Departure From Nucleate Boiling

EDG -

Emergency Diesel Generator

ESF -

Engineered Safety Features

ESFAS - Engineered Safety Features Actuation System

FWST -

Refueling Water Storage Tank

GDC - General Design Criterion

HEPA - High Efficiency Particulate Air

KW -

Kilowatt-

LC0 -

Limiting Condition for Operation

LER -

Licer.see Event Report

LSA -

Low Specific Activity

MPH -

Miles Per Hour

NEI -

Nuclear Energy Institute

NRC -

Nuclear Regulatory Commission

Enclosure 3

o .-

30

NS - Nucicar Spray

Nuclear System Directive

~

NSD -

NSW --

Nuclear Service Water

0AC- - Operator Aid Computer

00CM -

Offsite Dose Calculation Manual

0PDT - 0,erpower Differential Temperature

PCB -

Power Circuit Breaker

PDR -

Public Document Room

PIP - Problem Investigation Report

PM -

-Preventive Maintenance

PORVS - Power Operated Relief Valves

PSIG - Pounds per Square Inch Gauge

RCA - Radiological Control Area

RGC -

Regulatory Comaliance .

"RHR -

Residual Heat Removal

RP -

Radiation Protection

R&R -

Repair and Restor 6 tion

SCO - Surface Contaminated Object

SI - System Internationale

SRP -

Standard Review Plan

SSC - Structures. Systems, and Components

SSPS -

Solid State Protection System

TS --

Technical S ecification

TSAll -

UFSAR -

.. Technical S ecification Action Items List

Updated Fin 1 Safety Analysis Report r:

-URI- -

Unresolved Item

VIO -

-Violation -

WO -

Work Order

Enclosure 3-

9