ML20216H617

Insp Repts 50-369/98-02 & 50-370/98-02 on 980125-0307. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support

ML20216H617
Person / Time
Site:	Mcguire, McGuire
Issue date:	04/06/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20216H589	List: ML20216H584 ML20216H605 ML20216H617
References
50-369-98-02, 50-369-98-2, 50-370-98-02, 50-370-98-2, NUDOCS 9804210203
Download: ML20216H617 (22)

See also: IR 05000369/1998002

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-369, 50-370

License Nos: NPF-9 NPF-17

Report No: 50-369/98-02, 50-370/98-02

Licensee: Duke Energy Corporation

Facility: McGuire Nuclear Station Units 1 and 2

Location: 12700 Hagers Ferry Road l

Huntersville NC 28078

Dates: January 25. 1998 - March 7, 1998

Insper, tors: S. Shaeffer. Senior Resident Inspector

M. Sykes, Resident Inspector

M. Franovich, Resident Inspector

E. Lea, Regional Inspector (Sections 02.4 and E1.1)

Approved by: C. Ogle, Chief, Projects Branch 1 <

Division of Reactor Projects

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9804210203 980406 Enclosure 2

PDR ADOCK 05000369 '

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EXECUTIVE SUMMARY

McGuire Nuclear Station. Units 1 and 2

NRC Inspection Report 50-369/98-02, 50-370/98-02

This integrated inspection included aspects of licensee operations,

maintenance, engineering, and plant support. The report covered a six-week

period of resident inspection: in addition it includes the results of an

announced inspection by a regional inspector.

Doerations

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The licensee reported three events in accordance with the requirements

of 10 CFR 50.72. (Section 01.2)

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Plant systems operated as expected following a malfunction of the Unit 2.

main generator exciter voltage regulator. Operators responded

appropriately during a voltage regulator malfunction and subsequent

reactor trip. An NRC identified discrepancy between reactor trip

breaker train actuation times was appropriately addressed by the

licensee. (Section 02.1)

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Operators responded promptly and appropriately to the loss of motor

control center 2MXA. The licensee s efforts to identify the root cause

were inconclusive. (Section 02.2)

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Accessible components of the Unit 1 and Unit 2 containment spray systems

were properly aligned. Material condition was adequate with the

exception of valve 2NS38B. (Section 02.3)

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Operator response was adequate once the reactor was manually tri) ped,

following a significant multiple rod drop event. However, a weacness

was identified in McGuire procedure AP/1/A/5500/14. Rod Control

l- Malfunction. Revision 2. for addressing multiple dropped rods.

Procedure ambiguity and training deficiencies associated with response

to multiple rod drop events contributed to additional burdens placed on

the operators in response to the event. Once the weakness was

identified, the licensee took immediate actions to assure that cdequate

guidance was available to the operators to address potential future

dropped rod events. (Section 02.4) j

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Further followup on the licensee's previous industry experience review

regarding multiple rod drop events was identified as an Unresolved Item.

(Section 02.4)

Prior to an actual event involving multiple dropped rods, the exchange  !

of information between control room operators was conflicting following '

a pre-job briefing associated with troubleshooting efforts for rod

control system alarms. Key operations personnel did not fully discuss

or evaluate the technical bases or merit for establishing a consistent

approach to addressing potential multiple dropped rod scenarios.

(Section 02.4)

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finntenance j

. The licensee *s )ost-trip investigation, repair, and testing of the

malfunctioning Jnit 1 main generator voltage regulator verified proper

equipment operation prior to returning the unit to 100 percent power

output.-(Section M2.1) i

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One example of'a violation of Technical Specification 6.8.1 wn

identified for failing to establish adeguate instructions for the repair

.of the ICF35 valve actuator. This resulted in degraded operation of the

containment isolation valve. In addition..the licensee *s documentation

of repair activities associated with valve ICF35 was poor. (Section

M2.2)

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Spurious malfunction of Unit 1 Rod Control system power supply fuses

-resulted in a multiple drop rod event. (Section 02.4)

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A second example of Technical Specification 6.8.1 was identified due to

maintenance technicians failing to follow station procedures for the

installation of lower containment purge inlet isolation valve IVP8 seal

ring adjusting screw. The failure to follow established procedures

resulted in IVP8B being in a degraded condition. (Section M2.3)

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Maintenance practices in applying sealant to containment purge valves

was identified as a weakness that ultimately resulted in failure of

lower containment purge inlet isolation valve IVP88. (Sectior, H8.1)

Enaineerina

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Following the manual reactor trip due to multiple dropped rods, the

licensee was aggressive in establishing a special team to perform an

investigation of apparent cause and assessment of plant response.

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Resolution of identified technical issues was adequate to support unit

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restart. (Section El.1)

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An Unresolved Item was identified to investigate the adequacy of

maintenance procedures in meeting Technical 5)ecification requirements

! during repairs of refueling water storage tanc level instrumentation

system and containment pressure control system components. (Section E3.1

l and Section E3.2)

Plant Sucoort

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Locked high radiation doors were properly controlled high radiation and

l contamination areas were properly posted, and radiological area survey

maps were updated to accurately reflect radiological conditions in the

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respective areas. (Section R1.1)

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Reoort Details

Summary of Plant Status

Unit 1

' Unit 1 began the inspection period at approximately 100 percent power. On

February,9,1998. the reactor was manually tripped following an unexpected rod

drop event. Unit 1 was returned to power operation on February 11, 1998. On

February 14, 1998, the: licensee reduced rated reactor )ower to ap)roximately

25 percent to repair main feedwater isolation valve IC 35. On Fe)ruary 15.

1998, the licensee returned Unit 1 power' output to 100 percent. On March 2,

1998, the licensee reduced reactor power to aaproximately 15 percent to repair

.a hydraulic fluid leak at the main turbine. On March 3. 1998, the licensee

returned Unit 1 power to 100 percent and operated at 100 percent throughout

the remainder'of the reporting period.

Unit'2

Unit 2 began the inspection period at approximately 100 percent power. On

February 22, 1998, an automatic reactor trip occurred following a turbine

trip, after a main generator exciter voltage regulator malfunction. The unit

returned to power operation on February 24, 1998. On March 3. 1998. Unit 2

reactor power was momentaril

cfeedwater system transient. yOn reduced

Marchto7.approximately 93 percent

1998, the licensee reducedfollowing

reactor a

power from 100 percent to perform an ins

during security modification activities.pection of aend

At the 6900ofVthe

busperiod.

duct damaged

Unit 2

power escalation to 100 percent was in progress.

, - Review of Uodated Final Safety Analysis Reoort -(UFSAR) Commitments

While performing inspections discussed in this report, the inspecters reviewed

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

The inspectors verified that the UFSAR wording was consistent with the "

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observed plant practices, procedures, and parameters.

I. Ooerations

0' 1 '  : Conduct of Operations j

01.1 General Comments (71707) l

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usingInshectionProcedure71707,theinspectorsconductedfrehuent

reviews o ongoing plant operations. In general, the conduct o i

operations was professional and safety-conscious, including response to i

several complex transients. S)ecific events and noteworthy observations  :

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are detailed in the sections w11ch follow.

01.2 ~10 CFR 50.72 Notifications  !

a. Insoection Scone (71707)

During the inspection aeriod, the licensee made the following

notifications to the NRC as required or for information purposes. The

inspectors reviewed the. events for impact on the operational status of  !

the facility and. equipment. l

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b. Observations and Findinas

l 1. On February 9.1998, the licensee notified the NRC of a manual reactor trip from 100

drop)ed into the core. percent power after several control rodsSince the c

, not )een specifically analyzed. the licensee evaluated the

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>otential that-the plant was in an unanalyzed condition. On

rebruary 10. 1998, the licensee updated the notification to state ,

that an event; specific evaluation had been com

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was bounded by the applicable UFSAR analysis. pleted

This eventand

is the event

further discussed in Section 02.4.

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2. On February 15. 1998, the licensee notified the NRC of a

notification to state and local agencies following a transformer

oil spill in the McGuire switchyard. On February 16, 1998, the

licensee updated the notifications when the oil spill was

determined to have migrated to a nearby creek.

3. On February 22, 1998, the licensee notified the NRC of an

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automatic Unit 2 reactor trip. The trip occurred after.a main

generator exciter voltage regulator caused a turbine-generator

trip from 100

Section 02.1. percent power. This event is further discussed in

c. Conclusions

The inspectors concluded that the licensee reported the events in

accordance with the requirements.of 10 CFR 50.72.

02 Operational Status of Facilities and Equipment 3

02.1 Automatic Reactor Trio Followina Voltaae Reaulator Malfunction

a. Insoection Scoce (71707 and 40500)

.The inspectors responded to the station to evaluate plant and personnel  !

response following an automatic Unit 2 reactor trip.

b. Observations and Findinas

On February 22. 1998. McGuire Unit 2 automatically tripped from 100

percent when the main turbine tripped due to a generator trip. The

automatic reactor trip was expected when the turbine tripped with

reactor power greater than 48 percent. The turbine trip occurred after

a malfunction of the Unit 2 main generator exciter voltage regulator.

Reactor o)erators manually started both motor-driven auxiliary feedwater

pumps. T1e turbine-driven auxiliary feedwater pump automatically

started due to Lo-Lo Level in 2 of 4 steam generators. The 2B emergency

diesel generator automatically started, but was not required to sup)1y

safety-related loads. The unit was stabilized in Mode 3 and both t1e 2B  ;

emergency diesel generator and the auxiliary feedwater system were

returned to standby..

The inspectors lant after notification of the event

L through the NRCres ondedDuty

Regional to the

Of hicer. The inspectors reviewed alarm

log reports and Sarameter data trends. Trend data indicated that the

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malfunction of t1e voltage regulator resulted in a significant voltage

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transient. Operators responded to the transient, but were unable to

regain control of the main generator output. A generator trip occurred

as a result of loss of field. The voltage transient caused a momentary

undervoltage condition on the B Train 4160V Essential Power Bus 2ETB

resulting in the 2B emergency diesel generator automatically starting.

During reviews of plant response data, the inspectors noted

discrepancies in reactor tri

Operator Aid Computer (OAC).p breaker actuation times obtained from theThe po

between A and B Train actuation. The licensee immediately evaluated the

OAC points and determined that the computer generated time stamp for the

B reactor trip breaker was incorrect. The licensee provided the

inspectors with confirmatory information that the actual switchgear

actuation times were within the 150 millisecond acceptance criteria.

The discrepancy between reactor trip breaker train actuation times was

appropriately addressed by the licensee. The inspectors verified that 1

no undervoltage condition occurred on 2 ETA. which would have caused an i

automatic start of the 2A emergency diesel generator. The licensee i

determined that specific operations guidance should be developed for

responding to malfunctions of exciter voltage regulator. The guidance

was developed and provided to operations prior to restart.

The licenseewith

accordance immediately beganDirective

Nuclear System a reactor(NSD

trip) 505.

investigation in of

Investigation

Reactor Trips. The apparent cause identified by the licensee was a

failed voltage regulator firing circuit card. The inspectors attended

licensee restart status meetings and the Plant Operations Review

Committee meeting to confirm that identified issues had been resolved

prior to Unit 2 restart. The inspectors noted that the licensee  ;

appropriately addressed the restart issues. l

c. Conclusions

The inspectors concluded that plant systems performed as expected

following malfunction of the Unit 2 main generator exciter voltage

regulator. Operators responded appropriately to changing plant

parameters although no specific guidance had been provided for voltage i

regulator malfunction. fn NRC-identified discrepancy between reactor l

trip breaker train actuahon times was appropriately addressed by the

licensee.

02.2 Main Feedwater Transient Followina loss of Motor Control Center 2MXA

a. Insoection Scooe (71707)

The inspectors responded to the control room, following a notification

by the licensee of a Unit 2 main feedwater transient, to monitor

operator performance and evaluate plant response.

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b. Observations and Findinas

On March 3.1998, operators responded to a loss of motor control center 1

2MXA. Ground fault protective relays had tripped open the normal supply i

breaker and the alternate supply breaker did not automatically close due

to the fault. The loss of power affected main feedwater pump

recirculation valves. The valves failed open diverting a portion of the

main feedwater to the condenser hotwell. The steam generator level

control system responded as expected to the feed / steam flow mismatch.

Main feedwater flow increased and pump suction pressures approached the

pump trip setpoints. The standby condenser hotwell

started on low main feedwater pump suction pressure.pum) automatically

T1e 2A condensate

booster pump did not start because the bearing oil pump had been

disabled by the loss of 2MXA. Operators recognized the potential for a

main feedwater pump trip and reduced turbine-generator load to

approximately 93 percent.

The inspectors reviewed trend data and plant alarm logs to evaluate

plant response to the loss of 2MXA and the subsecuent feedwater system

transient. The inspectors noted that the OAC incicated a maximum

thermal power best estimate of approximately 103.9 3ercent of reactor

rated thermal power. The inspectors investigated tie computer

calculation inputs to confirm that the best estimate calculation was

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based on an error in secondary heat balance. The computer calculation

was verified to be false. The inspectors examined nuclear

instrumentation system trends confirming that the licensee did not

exceed rated reactor thermal power limits.

The licensee performed inspections and tests of protective relays and

motor control center loads to identify the cause for the protective j

relay actuation. The licensee performed visual inspection of accessible '

motor control center compartments. At the close of the inspection

period, the licensee was unable to identify the apparent cause for the

ground fault relaying. but had an open problem report to pursue the

issue.

c. Conclusions

The inspectors concluded that operators responded promptly and

appropriately to the loss of motor control center 2MXA. Licensee

efforts to identify the root cause were inconclusive.

02.3 Unit 1 and Unit 2 Containment Sorav systems (CSS) Walkdown

a. Insoection Scoce (71707)

The inspectors completed detailed inspections of selected portions of

the Unit 1 and Unit 2 CSS to assess material conditions and verify

proper system alignment. Field verification of valve position,

electrical breaker alignment, and main control room indication were

performed. The inspectors also verified local containment

control system (CPCS) (a sub-system of CSS) panel status. pressure

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b. Observations and Findinas

Material condition of equipment was adequate with the exception of valve

2NS388. Valve 2NS38B is a safety-related discharge valve from the RHR

system to the containment spray header. The inspector observed actuator

fluid leaking onto the floor. No work request had been generated. The

inspectors informed the licensee of the actuator oil leak and the

licensee included 2NS38B into their fluid leak monitoring (FLM) program

to determine additional actions The inspectors also observed

indications of boric acid leaks on other system components that were

reported to operations. Additionally, the inspectors confirmed the

licensee had an established program to monitor system leakage outside

containment to ensure Jost-accident radioligical doses would be

maintained within esta]lished limits. No system alignments or other

deficiencies were identified,

c. Conclusions

The inspectors confirmed that the selected portions of the Unit 1 and

Unit 2 containment spray systems were properly aligned. With the

exception of valve 2NS38B. material condition was adequate.

02.4 Manual Reactor Trio Followina Multiole Control Rod Insertion

a. Insoection Scooe (71707)

The inspectors responded to a manual Unit 1 reactor trip that occurred

on February 9, 1998. The inspectors observed operator performance, i

interviewed licensee personnel, and reviewed documentation to assess the l

operators' pre-trip and post-trip performance. Additional review of the  ;

rod control s

Section E1.1.ystem failure investigation process was discussed in

b. Observations and Findinas

On February 9.1998, the licensee initiated the manual reactor trip when

pressurizer pressure decreased to approximately 1950 psig. The decrease j

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in pressurizer pressure occurred as the result of multiple control rods t

unexpectedly dropping into the core. Documentation reviewed by the l

inspectors indicated that eight rods dropped fully into core and three  !

rods fell partiall 10:26:03 a.m.. The rods were from  !

, . three rod groups. y into the core atAs plant parameters changed and pressu i

approached the automatic trh setpoint of 1945.psig. the manual reactor trip was initiated at 10:27:39 a.m. Plant equipment responded to the i

, manual trip as expected and the plant was safely shutdown to Mode 3. No

! other major equipment anomalies were noted.

! The inspectors determined by interviewing licensee personnel and

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reviewing documentation that the rods dropped due to a loss of DC power

supply number 4 (PS4). The power supply was lost while technicians were

p(erforming

PS3) to identify troubleshooting the causeactivities on redundant

for an earlier power

rod control supply number 3

non-urgent

failure alarm. Both power supplies were located in rod control system

power cabinet 280. During the troubleshooting activities and coincident

with the rod drop, a rod control urgent failure annunciator also alarmed

and cleared instantly.

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Maintenance technicians determined that a failure of PS3 had caused the

rod control non-urgent failure alarm to annunciate, but was not related

to the rod control ur ent alarm. The technicians re) laced PS3 and were

restoring the AC supp to PS3 when the Rod Control Jrgent Alarm was

received and the cont 1 rods dropped into the core.

In response to the alarm, operators referred to abnormal operating

procedure AP/1/A/5500/14 Rod Control Malfunction. Revision 2, for

guidance. Post-event documentation indicated that AP-14 was referred to

by the operators each time an alarm associated with the rod control

system was received. The sequence-of-events log contained an entry for

time 10:26:03: "AP-14 was consulted; main steam pressure, )ressurizer

pressure level falling." The operators manually tripped tie reactor at

10:27:09, narrowly avoiding an automatic trip.

During interviews with the operators, the inspectors determined that the

issue of multiple dropped control rods had been previously discussed

between operating shifts. Specifically, the previous shift's SR0 stated

that during a pre-job briefing, which was conducted in conjunction with

the previously mentioned troubleshooting activities, the unit operators

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were instructed to immediately trip the reactor should multiple rods

drop into the core. The guidance to immediately trip the reactor, was

communicated to the on-coming shift's reactor operators (on duty at the

time of the event). However, when the on-duty SR0 was told of the

decision made by the previous crew, the SRO instructed the operators to

follow procedure AP-14, which did not require the reactor to be

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immediately tripped if multiple rods drop)ed. The' procedure directed

! the operators to "Begin unit shutdown to 3e in Mode 3 within 6

hours...."

The inspectors

between controlconcluded that thiswas

room operators exchan!e of pertinent

confli ting. information

Specifically, key

control room personnel failed to fully discuss or evaluate the technical

bases or merit for establishing a consistent approach to addressing

multiple dropped rod scenarios.

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The inspectors reviewed the licensee's safety evaluation for the

deletion of the negative flux rate trip, approved by the NRC in 1994, to

determine what changes to the abnormal operating procedure, if any, were

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required to address the removal of the negative flux rate trip as it

pertained to multiple dropped rods. The inspector also reviewed the

modification package to determine if any operator training was required

to provide the operator E"idance on how to handle multiple dropped rods

once the negative rate trip was removed. The inspectors did not

identify any training that was re

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associated with the modification, quired

nor didasthe

a result of the identify

inspectors changes

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specific procedure changes to address multiple dropped rods.

After completing the review of the modification package, the procedures

and training material, the ins)ectors concluded that there were

weaknesses in the licensee *s a) normal operating procedure AP-14, Case

III, in that it did not require the operators to immediately address the

issue of multiale drop)ed control rods. Multi

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addressed in 03/1/A/61)D/22. Unit 1 Data Book,ple dropped

Revision 473.rods were

Guidelines

for Recovering Misaligned / Drop)ed Control Rod. OP/1/A/6100/22 required

that the reactor be promptly slutdown, but did not define the. term

"promptl The inspector also concluded that lack of clear guidance to

address the

y". issue of multiple dropped rods, when coupled with this type

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of rod drop event. could lead to the plant being operated outside the

assumptions identified in Chapter 15 of the UFSAR (See Section E1.1)..

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The licensee evaluated existing procedures, and contacted the vendor and

other utilities to obtain information pertaining to multiple dropped

rods. As a result of the reviews and research conducted. the licensee

revised their procedure to provide clearer guidance to the operators in

the event a similar event were to occur in the future. The inspectors

reviewed these changes and found them acceptable. For the specific

McGuire rod drop event, the licensee determined that the involved rod

Battern

FSAR.

did not place the unit outside the bounds identified in the

. Conclusions

The inspectors concluded that the exchange of pertinent information

between control room operators was conflicting. Specifically. key

control room personnel failed to fully evaluate the technical bases or

merit for estabiishing a consistent approach to addressing multiple drop

rod scenarios. O

manually tripped,perator response

following was adequate

the multiple rod droponce the reactor

event. However,was

the

inspectors concluded that the guidance provided in AP-14. Case III. for

addressing multiple dropped rods was weak. Procedure ambiguity and

training deficiencies associated with response to multiple rod drop

events contributed to additional burdens placed on the operators in

response to the event. Once the weaknesses were identified. the

licensee took actions to assure that adequate guidance was available to

the operators to address multiple dropped rod events in the future.

Further followu 'on the licensee's previous industry experience review

regarding) multi9.370/98-02-03:

Item (URI 50-3 le rod drop events, will be

Followup onidentified

Licensee'sasPrevious

Unresolved

Industry Experience Review Regarding Multiple Rod Drop Events.

II. Maintencnce

M1 Conduct of Maintenance

M1.1 General Comments

i a. Insoection Scone (61726 and 62707)

The inspectors observed portions of the following work activities:

Procedure / Work Order Title

PT/1/A/4209/01A NV Pump 1A Performance Test

PT/2/A/4350/02B 28 Diesel Generator Operability Test

PT/1/A/4401/01B KC Train 1B Performance Test

PT/2/A/4600/01 RCCA Movement Test

b. Observations and Findinas

The inspectors witnessed selected surveillance. tests to verify that

approved procedures were available and in use; test equipment was

calibrated: test prerequisites were met: system restoration was

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completed: and acceptance criteria were met. In addition, the

inspectors reviewed or witnessed routine maintenance activities to

verify, where applicable, that approved procedures were available and in

use, prerequisites were met, equipment restoration was completed, and

maintenance results were adequate.

c. Conclusion l

The inspectors concluded that the observed surveillance activities were

completed satisfactorily.

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M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Malfunction of Unit .7 Main Generator Exciter Voltaae Reaulator

a. Insoection Scoce (62707)

The inspectors evaluated licensee actions to identify and resolve

malfunctions of the Unit 2 main generator exciter voltage regulator.

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b. Observations and Findinas l

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As a result of a main generator voltage regulator failure. Unit 2

automatically tripped from 100% power. The licensee examined the failed  !

regulator to identify the apparent root cause. The licensee identified  !

a malfunctioning pulse generator circuit board in one of the two firing I

circuitry drawers. The circuit card was returned to the vendor for .

further failure analysis. I

Following restart, but prior to aligning the unit to the electrical

grid, the licensee conducted additional testing of the voltage regulator

while the generator was at no load conditions. The testing was i

performed in accordance with approved temporary station procedure

TT/2/B/9700/182. Unit 2 Generator Voltage Regulator Functional

Verification. Revision 0. The inspectors monitored the test evolution

and reviewed the test procedure. The inspectors confirmed that a

malfunction of the voltage regulator or associated equi) ment during the

test evolution would not have the potential to impact t1e plant during

the test. As a result of the testing, the licensee confirmed proper

operation of the voltage regulator, specifically, the firing circuitry

and pulse generator cards. Following the test, the licensee aligned the

unit to the grid and escalated power to 100 percent. A recorder was

installed to continuously monitor regulator performance during power

escalation and 100 percent steady-state operation. No further turbine

control abnormalities were observed.

c. Conclusions

The inspectors concluded that the licensee's investigation, repair, and

testing of the malfunctioning main generator voltage regulator

approariately verified equipment condition prior to returning the unit

to 10] percent power output.

M2.2 Main Feedwater Isolation Valve Hydraulic Fluid Leak

a. Insoection Stone (62707)

The inspectors evaluated licensee performance in responding to hydraulic

fluid valve actuator deficiencies for main feedwater containment

isolation valve ICF35.

b. Observations and Findinas

On February 14. 1998, the licensee received indication of excessive

hydraulic pump operation at the valve actuator for main

feedwater/ containment isolation valve ICF35. The licensee performed

i visual inspection of the actuator and discovered hydraulic fluid leak at

an accumulator fitting. The accumulator has a nitrogen charge to

provide the closing force for the valve on a feedwater isolation signal.

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Initial attem)ts to tighten the fitting resulted in increased leakage. .

The licensee >1alted the maintenance until further plans could be  !

established.

The licensee reduced power to approximately 25 percent and closed and

de-energized the affected valve. Main feedwater was supplied to the

L Unit 1 A steam generator through the auxiliary feedwater nozzle. The

l licensee depressurized and drained the hydraulic system prior to

removing the failed fitting. The licensee determined that the fitting

had a damaged 0-ring. The fitting and 0-ring had not been properly

installed during previous maintenance. A replacement fitting was

j installed. hydraulic fluid was added, and the valve was stroke time

l tested in accordance with PT/1/A/4253/03A. Revision 25. and

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' PT/1/A/4253/038. Revision 23. Main Feedwater Valve Train A and Train B

Stroke Timing. Valve stroke times were within acceptable ranges and the i

valve was declared operable.

In the past because of numerous feedwater isolation valve hydraulic

l fluid leaks requiring unit power reductions the licensee developed and l

l initiated station modifications to remove this fitting during previous  ;

l maintenance / refueling outages. However, the licensee decided to defer i

! replacement of the fittings for valve ICF35.  !

! On February 23. 1998.- the licensee received indication of excessive l

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hydraulic system pump operation for ICF35. Investigation of the

actuator revealed no active hydraulic system leaks: however, the

hydraulic system fluid inventory was approximately 2 quarts low. The i

licensee added the necessary hydraulic fluid. performed pump capacity i

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testing to verify proper pump operation and returned the system to

l o)erable. No power reduction was necessary. The licensee determined

! tlat the low oil level was due to entrained air in the system and fluid

reservoir that aided in providing a false indication of system

l inventory. The gradual dissipation of air from the system resulted in

increased operation of the hydraulic pump.

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Based on reviews of completed maintenance procedures and discussions I

with maintenance personnel, the ins)ectors determined that the guidance

provided to perform venting of the lydraulic system following corrective ]

maintenance was inadequate to ensure complete removal of air from the

hydraulic system. The expedited repair exacerbated this problem in that i

adequate time for the entrained air to dissipate was not incorporated  !

into the procedural guidance. This failure to provide adequate guidance  :

for ventin

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50-369/9802-01:

g of valve ICF35

Failure will be

to Follow identified

and/or asAdequate

Provide an example of violation

Procedures  ;

for Maintenance on Unit 1 Containment Isolation Valves. The inspectors 1

also noted that the completed procedure did not accurately reflect

performance of the specific venting activities accomplished. This

documentation weakness was conveyed to station management. The licensee

acknowledged the documentation deficiencies and stated that actions will

be initiated to emphasize management expectations for the accuracy of

documentation.  !

!

c. Conclusion  ;

The inspectors concluded that the licensee failed to establish adequate I

guidance for the repair of the ICF35 valve actuator which resulted in

'

degraded operation of the containment isolation valve. The inspectors

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11

also concluded that the licensee's documentation of repair activities

for valve ICF35 was poor.

M2.3 Recurrino Deoradation of Unit 1 Containment Purae Valve 1VP88

a. Insoection Scone (62707)

The inspectors reviewed the repairs associated with Unit 1 containment

purge inlet valve IVP8B performed on January 31, 1998. This was the

second time in the last three months that IVP8B was found in a de

condition during a local leak rate test (LLRT) (see section M8.1) graded.

b. Observations and Findinos

'

On January 29, 1998, the licensee discovered increased leakage through

valve IVP8B during a quarterly LLRT of penetration IM456. Valve IVP8B

is a 24-inch butterfly valve that is a normally closed containment

isolation valve. The valve was degraded with b aka

3400 standard cubic centimeters per minute (sccm) (ge at sccm

6900 approximately

is the

failure limit). A retest was performed on January 30, 1998 and leakage

had '.e reased to 4350 sccm. Valve IVP88 was repaired without opening

the valve and a

January 31, 1998. post-maintenance LLRT was successfully performed on

During the repair of IVP8B on January 31, 1998.

discovered that one set screw was not tightened.which plant coincided

personnelwith

the location of the leak. There are 24 adjusting set screws evenly

spaced around the circumference of the valve that hold the elastomer

seat ring in place. Maintenance 3rocedure MP/0/A/7600/042. Fisher T-

Ring

(used9200

duringSeries Butterfly)

1E0C11 outageValve Corrective

, requires Maintenance.

that each Revision

of 24 adjusting set 7

screws be tightened 1/4 turn, one at a time. until the seat ring

contacts the seat at one point and that screws are tightened until the

seat ring contacts the seat in all areas. The licensee indicated that

the seat ring was installed during the previous Unit I refueling outage.

Contrary to the above. maintenance personnel who had replaced the seat

ring during the previous Unit I refueling outage failed to properly

install the adjusting screws that hold the elastomer seat in place.

After several quarterly LLRT tests, the seat ring ultimately deformed to

the point where it protruded from the retaining ring. The inspectors

identified this as a second example of VIO 50-369/98-02-01: Failure to

Follow and/or Provide Adequate Procedures for Maintenance on Unit 1

Containment Isolation Valves.

c. Conclusions

The inspectors concluded that the re) air on January 31. 1998 of

degraded containment purge valve IVP38 was a

additional- exam)le of a violation of TS 6.8.ppropriate. However. an

1 was identified.

Maintenance tecinicians who had worked IVP8B during the previous Unit 1

refueling outage failed to properly install the seat ring in accordance

with a plant maintenance procedure and resulted in IVP8B being in a

degraded condition.

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M8 Miscellaneous Maintenance Issues (92902)

M8.1 (Closed) URI 50-369.370/97-18-02 Potentially Inadequate Corrective

Action for Use of Sealant on Containment Purge Isolation Valves

' This URI documented the inspectors * concerns with maintenance practices

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and

inlet the

valvecircumstances related to

IVP88. The inspectors a failure

reviewed of containment

procedure MP/0 p/A/ge air

7600/042.

Fisher T-Rin

Revision No.g8.9200

and Series Butterfly

Work Order Valve Corrective

97095980-01 for the Maintenance.

repair of valve

IVP8B. The inspectors also interviewed cognizant personnel.

On November 7. 1997, the licensee determined that containment

penetration IM456 failed a leak rate test due to excess leakage through

containment purge valve IVP8B. The inspectors reviewed the corrective

actions and interviewed maintenance personnel. Containment penetration

1M456 consists of purge valves IVP8B and IVP9A that are the outboard

(located in the annulus) and inboard isolation valves, respectively.

Both valves are normally closed. The inspectors were concerned that (1)

adequate corrective action had not been taken when the same penetration

had failed leak rate testing due to leakage through IVP9A earlier in

1997, and (2) that flange sealant may not be qualified for post-accident

conditions since arocedures did not specify use of flange sealant. In

each case for IVP3B and IVP9A. the failure was attributed to excess

flange sealant that dripped onto the valve seat which prevented full

closure of the valve.

A quarterly surveillance )erformed on October 30, 1997. revealed

increased penetration leacage (490 sccm) from the previous surveillance

(2 sccm). The failure limit was 6900 sccm. In an attempt to reduce

leakage below a station goal of 100 sccm. the licensee made minor valve

adjustments and cycled the valve to gain better closure. The licensee

clarified that failure of IVP88 had occurred after the valve was cycled

between November 6 and 7, 1997. The valve failure mechanism was

attributed to sealant that had dripped from the flange onto the valve

seat T-ring. The root cause of the problem was a maintenance work

practice error when too much sealant was applied to the flange and

dripped out when the flanges were torqued during previous work on the

valve. When the valve was opened, the excess sealant spread out on the

T-ring and obstructed the valve disc when attempting to re-close the

valve. Presence of sealant in the valve would not have caused a

failure if the valve had remained closed. The licensee attributed the

increased leakage seen prior to cycling the valve due to disc movement

from spring relaxation.

In order to reduce flange leaka

for minor flange imperfections.ge. sealant

The had been

inspectors used to

determined compensate

that the

material safety data sheet (MSDS) for the sealant-indicated that the

material was qualified for containment temperatures that could be seen

in a design-basis post-accident environment at McGuire. The sealant is

a Cate

L Guide. gory.1 material

Corrective as identified

actions includedin the licensee's

in part. Power Chemistry

(1) instructing

j

maintenance

valves, and p(2) enhancement of the maintenance procedure to requireerso 1

visual inspection and cleaning of the valve seat area. The inspector

! concluded that these corrective actions were adequate.

.

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The inspectors concluded that maintenance personnel practices in

applying sealant to containment purge valves was a weakness that

ultimately resulted in failure of valve IVP8B (after cycling the valve)

l and placed the unit in a degraded condition. However, corrective

! actions taken to provide better guidance and prohibit the use of sealant

i on similar containment isolation valves were adequate to prevent

recurrence. This item is closed.

III. Enoineerina

El Conduct of Engineering

El.1 Rod Control Sv-tam Failure Investiaation

a. Insoection Scote (37551)

The inspectors reviewed documentation and interviewed licensee personnel

to determine if the licensee performed an adequale assessment of the

multiple dropped rod event. The inspectors specifically looked for

information associated with identifying the root cause and evaluating

system performance.

b. Observations and Findinas

Following the event, station management requested that a detailed

evaluation of plant performance be conducted. The licensee organized a

Failure Investigation Process (FIP) team to perform an assessment of the

multiple dropped rod event. The team was tasked with identifying the

root cause and evaluating plant response.

During the investigation process, the FIP team concluded that the rods

dropped-into the core due to a momentary loss of rod control system

power at cabinet 280. The FIP team also identified that the event, as

it occurred had not been analyzed in Chapter 15 of the UFSAR.

Specifically, the UFSAR Chapter 15 dropped rod analysis considered

combinations of different dropped rods within the same group. The event

that occurred on February 9. 1998, involved dropped rods from three

separate rod groups. Because the dropped rods were not in the same

group there was a concern of exceeding the Departure from Nucleate

Boiling Ratio limits. However, after further evaluation of the event,

the licensee determined that this specific multiple dropped rod event

was bounded by the existing UFSAR analyses.

The inspectors determined that the rods dropped due to a faulty fuse

holder associated with power scoply 4 (PS4). The faulty fuse holder

created conditions that led to 'a momentary loss of power to the rod

control system power cabinet 2BD. Following the event, a technical

evaluation team was able to recreate the failure by manipulating a fuse

holder adjacent to the suspect fuse holder. The sus ect fuse holder

indicated an intermittent open condition. The fault fuse holder was

l removed for electrical and metallurgical testing. T e results from the

l testing were inconclusive.

After addressing root cause concerns, engineering also addressed the

inspectors questions associated with control rod travel. Specifically

.why control rods in Control Bank D did not fall completely into the

core. Following a review of documentation and interviews with licensee ,

personnel, the inspectors determined that the momentary loss of power l

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14

was not of sufficient duration to allow full travel of the selected

control bank. The inspector also concluded that the electrical and

mechanical components of the rod control system responded as designed

due to t M momentary loss of power.

c. Conclusions

The inspectors concluded that the licensee was aggressive in

establishing a special team to perform an assessment of the event. The 1

assessment teams identification and resolution of issues was adequate to

support unit restart.

E3 Enaineerina Procedures and Documentation

E3.1 Unit 1 Refuelina Water Storace Tank (RWST) Level Channel 1 Inocerable

a. Insoection Scooe (37551. 62707. 90712)

The inspectors reviewed the facts and circumstances related to an

inadvertent removal of an inoperable Unit 1 RWST level channel 1

instrument 1FWLP5010. from the trip

required calibration on January 281998. ped condition while performing a TSPlant pr

TS. the DBD. and the UFSAR were reviewed. Licensee Event Report (LER)

50-369.370/98-01 was also evaluated. The inspectors discussed the

situation with plant personnel reviewed the procedures, and attended

the PORC review of the event.

b. Observations and Findinas

At approximately 10:30 on January 28. 1998, the licensee entered the TS I

action statement for an inoperable RWST level channel. The inoperable

channel was placed in the tripped condition in accordance with TS

requirements to su) port channel calibration. This channel is one of .

three RWST level clannels that provide input to the two out of three  !

logic for the automatic realignment from the RWST to the containment

sum) on low RWST level following a certain desi

Tec1nical S)ecification 3.3.2. Instrumentation.gn basis accidents. Table 3.3-3 req

that with t1e number of operable RWST level channels less than the total

number of channels, operation may proceed until performance of the next

required operational test provided the inoperable channel is placed in  ;

the tripped condition within one hour. The inspectors confirmed that '

the channel was placed in the tripped condition within the requisite

time. However, durin

current alarm module,gthe corrective maintenance

licensee improperly andtounknowingly

repair a defective

removed

the channel from the tripped condition for approximately 30 minutes.

The maintenance activity to replace a defective current alarm module was  !

performed in accordance with procedure IP/0/A/3250/020. Revision 3. RIS

Alarm Module Calibration and IP/0/A/3090/002. Revision 18. Instrument

and Electrical Troubleshooting. This failure to meet the TS

requirements was identified by the licensee following replacement of the  ;

defective current alarm module.

The RWST level instrument relays are designed to trip or actuate when

energized. With channel 1 inoperable and untripped, this configuration

reduced the emer

of two channels.gency core

In this cooling system

configuration, realignment

the RWST logicswapover

low level to two outdid

not satisfy the single failure assumptions of the plant's design sis.

.

I 15

!

The licensee did not consider this failure to meet TS requirements risk

!

significant, citing that the emergency procedures and the UFSAR Chapter

i 6 recognized that manual realignment can be performed prior to affecting

ECCS operability. However, the inspectors were concerned that manual

operator action may not be timely based on a review of previous NRC

operator licensing findings that noted slow operating crew

durin

300).g training activities (reference Inspection Report

369.370/97- 50 perfo

The licensee had acknowledged this operator performance issue,

and have attempted to improve opervor efficiency in working through

steps in the emergency procedures.

The licensee has attributed the RWST problem to an inadequate procedure.

The inspectors verified corrective actions that included correcting

alant procedures to allow for appropriate repairs of current alarms for

RWST level instrumentation. Inspectors questioned the licensee if an

evaluation had been performed of the number of previous times failed

current alarms were replaced and the duration of the repairs. The

licensee indicated that a past operability evaluation and root cause

analysis would be performed.

The inspectors concluded that the TS action statement did not permit

untripping of an inoperable channel. Pending NRC review of the past

operability evaluation, this is identified as one of two examples of

Unresolved Item 50-369.370/98-02-02. Potential Non-compliance With

Technical S)ecifications for Inoperable ESF Instrumentation for RWST

Level and C)CS.

The inspectors questioned if there were other systems that could be

susceptible to this type of problem. On February 17. 1998, the licensee

identified that a similar event had occurred on the Unit 2 Train B CPCS

(see section E3.2)

c. Conclusions

An Unresolved Item was identified for adequacy of maintenance procedures

to support repairs of defective components in the RWST level

instrumentation system and to maintain the required TS position for an

inoperable RWST level channel during repairs.

E3.2 Unit 2 Containment Pressure Control System (CPCS) Train B Inocerable

H a. Insoection Scone (37551. 62707. 90712)

Inspectors reviewed the facts and circumstances related to an

inadvertent removal of a Train 8 CPCS channel from the start permissive

while replacing a failed loop >ower supply. Plant procedures,

applicable TSs. the DBD and tie UFSAR were reviewed. LER 50-369.

, 370/98-01, was also evaluated. The inspectors discussed the situation

with plant ]ersonnel, reviewed the procedures, and attended the PORC

review of t1e event.

b. Observations and Findinas

On February 17. 1998. for Train B CPCS the licensee discovered that

maintenance work )erformed on January 29. 1998, to replace failed loop

power supply 2NSL)5510 resulted in the loop not being maintained in the

trip condition as required by Technical Specification 3/4.3.2.

Engineered Safety Features Actuation System Instrumentation. Table 3.3-

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3. Technical Specification Table 3.3-3 requires that with any of the

eight CPCS channels inoperable place the ino erable channel in the

start permissive mode within one hour and app y the applicable action

!

statement (Containment Spray - TS 3.6.2. Cont inment Air Return / Hydrogen

l Skimmer - TS 3.6.5.6). This was performed in order to work on the

! failed power supply.

During replacement of the power supply 2NSLP5510. maintenance

technicians removed fuses to isolate 1.he device. Removal of the fuses

resulted in de-energizing relays that provided control functions and

maintained the CPCS in the start permissive. De-energizing the relays

! effectively defeated the action taken to place the channel in the start

l

permissive. Defeat of the start permissive rendered the CSS 2B pump

inoperable since the pump was not capable of automatic or manual start. 4

The inspectors questioned the number of failed loo) power supplies for

CPCS channels that were repaired in accordance wit 1 the subject

procedures in the past. Inspectors ccncluded that defeat of the CPCS

start permissive on January 29, 1998, was contrary to the requirements

of TS Table 3.3-3 for CPCS. Pending further NRC review, this is

identified as the second example of Unresolved Item 50-369.370/98-02-02.

Potential Non-compliance With Technical Saecifications for Inoperable

ESF Instrumentation for RWST Level and CPCS.

c. Conclusions

! An Unresolved Item was identifisd for adequacy of maintenance procedures

to support repairs of defective components in the CPCS and to maintain

the required TS position for an CPCS channel during repairs.

IV. Plant Sucoort

R1 Conduct of Radiation Protection and Chemistry

!

R1.1 General Comments (71750)

The inspectors made frequent tours of the controlled access area and

reviewed radiological postings and worker adherence to protective

clothing re Locked high radiation doors were properly

,

controlled,quirements.

high radiation and contamination areas were properly posted.

'

and radiological area survey maps were updated to accurately reflect

radiological conditions in the respective areas.

,

V. Manaaement Meetinas

X1 Exit Meeting Summary  ;

, The resident inspectors 3 resented the inspection results to members of l

l licensee management at t1e conclusion of the inspection on March 11. 1998. l

t

The licensee acknowledged the findings presented. No proprietary information

was identified.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

l

Barron..H., Vice President. McGuire Nuclear Station

Bhatnagar. A. , Su>erintendent. Plant Operations

Boyle, J., Civil / Electrical / Nuclear Systems Engineering

Byrum. W., Manager, Radiation Protection

Cash. M., Manager. Regulatory Compliance

'Dolan. B. Manager. Safety Assurance

Evans W. Security Manager

Geddie. E., Manager. McGuire Nuclear Station

i Herran. P., Manager. Engineering

Loucks. L. Chemistry Manager

Thomas, K. , Superintendent. Work Control

Travis B., Manager. Mechanical Systems Engineering

INSPECTION PROCEDURES'USED

IP 71707i Conduct of 0)erations

IP 62707: Maintenance Observations

IP 61726: Surveillance Observations .

IP 40500.: Effectiveness of Licensee Controls in Identifying. Resolving, and

Preventing Problems

IP 37551: Onsite Engineering

IP 71750: Plant Support

IP 92902: Maintenance - Followup

IP 90712: Licensee Event Report Review

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ITEMS OPENED. CLOSED, AND DISCUSSED

OPENED

l

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50-369/98-02-01 VIO Failure to Follow or Provide Adequate Procedures

for Unit 1 Containment Isolation Valve

Maintenance (Sections M2.2 and M2.3) l

50-369.370/98-02-02 URI Potential Non-compliance With Technical

Specifications for Inoperable Engineered Safety

l Feature Instrumentation for Refueling Water

Storage Tank Level and Containment Pressure

'

Control System (Sections E3.1 and E3.2)  ;

i

'

50-369.370/98-02-03 URI Followup on Licensee's Previous Industry

Experience Review Regarding Multiple Rod Drop

Events (Section 02.4)

CLOSED

50-369.370/97-18-02 URI Potentially Inadequate Corrective Action for Use i

of Sealant on Containment Purge Isolation Valves i

(Section M8.1)

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19

l LIST OF ACRONYMS USED

*

CFR- --

Code of Federal Regulations

CPCS -

Containment Pressure Control System

-

CSS . - Containment S) ray System

DBD -

Design Basis bcument

DCN -

Design Change Notice

DES -

Duke Engineering Services

' ECCS -

Emergency Core Cooling System

EDG -

Emergency Diesel Generator '

,

EP -

Emergency Procedure i

ESF- -

Engineered Safety Feature j

,

'

FIP --

Failure Investigation Process  ;

FLM -

Fluid Leak Monitor j

IFI -

Inspector Followup Item

IN- -

Information Notice

IR -

. Inspection Report .

i

Licensee Event Report

-

LER -

i

LLRT -

Local Leak Rate Test I

MSDS - . Material Safety Data Sheet

NCV -

Non-Cited Violation i

NRC -

Nuclear Regulatory Commission

NRR -

NRC Office of Nuclear Reactor Regulation

NSD -

Nuclear Site Directive

NPSH -

Net Positive Suction Head

0AC -

Operator Aid Computer

0MP -

Operations Management Procedures

PDR -

Public Document Room

PIP -

Problem Investigation Process

PORC. - Plant Operations Review Committee -

RCCA -- Rod Control Cluster Assembly l

RWST - . Refueling Water Storage Tank

. SCCM -

Standard Cubic Centimeters Per Minute

TS -

Technical Specifications  ;

UFSAR - Updated Final Safety Analysis i

Unresolved Item

-

URI -

VIO -

Violation

. W0 -

Work Order

..