ML20137V153

Insp Repts 50-369/97-01 & 50-370/97-01 on 970112-0222. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support

ML20137V153
Person / Time
Site:	McGuire, Mcguire
Issue date:	03/24/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20137V136	List: ML20137V131 ML20137V138 ML20137V153
References
50-369-97-01, 50-369-97-1, 50-370-97-01, 50-370-97-1, NUDOCS 9704170226
Download: ML20137V153 (28)

See also: IR 05000369/1997001

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION II  !

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Docket Nos: 50-369. 50-370

License Nos: NPF-9. NPF-17

Report No: 50-369/97-01. 50-370/97-01

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Licensee: Duke Power Company

Facility: McGuire Generating Station. Units 1 & 2 ,

Location: 12700 Hagers Ferry Rd.

Huntersville. NC 28078

Dates: January 12. 1997 - February 22. 1997

Inspectors: S. Shaeffer. Senior Resident Inspector ,

M. Sykes Resident Inspector

W. Holland. Regional Inspector (paragraphs M7.1. E8.1)

P. Kellogg. Regional Inspector (paragraphs E2.2. E8.3)

V. Nerses. NRR Senior Project Manager (paragraph E3.1)

Approved by: C. Casto. Chief. Projects Branch 1

Division of Reactor Projects

Enclosure 2

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9704170226 970324

PDR ADOCK 05000369

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EXECUTIVE SUMMARY l

McGuire Generating Station. Units 1 & 2  :

NRC Inspection Report 50-369/97-01, 50-370/97-01 i

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This integrated inspection includes aspects of licensee operations, engineer-  !

ing, maintenance, and plant sup) ort. The report covers a 6-week period of

resident inspection and region aased inspection.

Ooerations

. 0)erator actions to reduce unit power and realign main feedwater flow -

t1 rough the auxiliary feedwater nozzle following identification of a

' hydraulic fluid leak at main feedwater containment isolation valve 1CF26

was good (paragraph 02.1). l

. Operator diagnosis of arid response to the loss of Unit 2 isophase bus

cooling and coincident rcd control system malfunctions was good

(paragraph 02.2). ,

. Operator response to the main generator voltage control problem was

adec uate. Improved guidance to operators regarding the degraded

concition was provided by engineering in a timely manner (paragraph

02.3).

. Control of Unit 1 shutdown for refueling was adequate. Shutdown

activities were conducted with minimal impact on the operating unit

(paragraph 02.4).

. An URI was identified to continue inspection of an RCS leak through a

letdown filter casing. Operator response to the event was good

(paragraph 03.1).

. The station's monitoring of control room indication problems, as defined

by the licensee's CRIP process, was considered to be adequately

implemented. The inspectors also concluded that the process may be

challenged during the upcoming Unit 1 OAC replacement project. The use

of Control Room information tags was generally well implemented. The

inspectors expressed a concern to Operations Management regarding

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potential overlapping of problem tracking processes, including the

operator work around process, which could present confusion regarding

problem monitoring and resolution (paragraph 04.1).

• A significant weakness was identified concerning inconsistencies between

the critical action times modeled in the simulator and the actual plant

response times during plant transients. The example noted could have

adversely impacted operator response capabilities by training on the

l incorrect critical action times. Once identified. licensee immediate

! corrective actions and response to the concerns were considered adequate

(paragraph 05.1).

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Control of overtime for plant personnel and postings to workers during

this period was adequate. Licensee assessments performed on the control

of overtime were detailed and provided good oversight (paragraphs 06.1

and 06.2).

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The results of the INPO evaluation completed in late 1996 were generally

consistent with the results of similar evaluations conducted by the NRC.

No additional NRC follow-up of any specific issue was identified

(paragraph 07.1).

Maintenance

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Corrective maintenance activities associated with malfunctions of

isophase phase bus cooling fans were thorough (paragraph M2.1).

. Control of non-tagout work activities was not sufficient to provide

adequate controls to ensure proper tracking to prevent occurrences that

may potentially result in personnel injuries and equipment damage

(paragraph M3.1).

. The licensee's restructuring of the Maintenance and Work Control

organizations to provide better distribution of responsibilities without

disrupting the current Work Control process was adequate. The

inspectors also noted that the restructuring should also enhance QA/0C

independence (paragraph M6.1).

. The licensee was actively involved in evaluation and resolution of motor

problems. The Root Cause Failure Analysis Report was thorough and

identified several focus areas for improving motor performance. Even

though some motor problems continued. the licensee's Quality Improvement

Team initiative at McGuire had produced some positive results, and

should im3 rove motor performance if the initiative is continued

(paragrapa M7.1).

Enaineerina

. The inspector concluded that engineering personnel were performing in-

depth reviews of the Refueling Water system design basis to ensure

compliance in that area and to identify any potential problems. An IFI

was identified regarding ongoing reviews of previous FWST design changes

and the FWST current design basis (paragraph E2.1).

. Reviews of engineering activities which support operations by

observations of engineering and operations personnel interfaces and

review of active engineering material in the control rooms concluded

that engineering was providing effective support to operations. The

number of open evaluations / determinations was not abnormal. The quality

of the determinations was good and the results were well documentetl

(paragraph E2.2).

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. The review of the 50.59 annual summary of changes, tests, and

experiments concluded that the licensee has complied with the

regulations (paragraph E3.1).

. The licensee's use of the trippable worth strategy in Mode 4 was

considered conservative based on available information. The licensee's

detailed evaluation of the practice confirmed that the issue was not a

safety concern. The inspectors recognized the licensee's efforts and

good questioning attitude (paragraph E4.1).

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The final root cause analysis and corrective actions for the Emergency

Diesel Generator lubricating oil pressure sensing line issue

appropriately addressed the problem (paragraph E8.1).

Plant Sucoort

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A Violation of 10 CFR 70.24 (a)(3) was identified for failing to have

established emergency procedures to address a potential criticality

event. In addition, requirements to perform evacuation drills of the

affected areas were also not met (paragraph R1.1).

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Reoort Details

Summarv of Plant Status

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

January 23, a power reduction to approximately 20 percent was made to allow

for repairs to the main feedwater isolation valve ICF26. The valve actuator

had developed a fluid leak. After repairs were completed, the unit returned

to 100 percent power. On February 11. Unit 1 began a coastdown power

i reduction leading to the U1EOC11 outage. The unit was shutdown ori

February 14. for the beginning of the planned 90 day outage. After an

extended RCS crud burst to facilitate lower outage dose, the unit was cooled

for defueling operations. At the end of the inspection period, Unit 1 was in

progress of core offload.

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

January 21 a power reduction to approximately 70 percent was necessary due to

the failure of one of the unit's isophase bus cooling fans and the inability

to immediately start the backup fan. After adjustment of a limit switch, the

backup fan was started and the unit was returned to 100 percent power the

following day. The unit operated at approximately 100 percent power for the

remainder of the inspection period.

Review of UFSAR Commitments

While performing inspections discussed in this report, the inspectors reviewed

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

The inspectors verified that the UFSAR wording was consistent with the

observed plant practices, procedures, and/or parameters.

I. Operations

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01 Conduct of Operations

01.1 G_eneral Comments F/1707)

Using Inspection Procedure 71707, the inspectors conducted frequent

reviews of ongoing plant operations. In general, the conduct of

operations was professional and safety-conscious; specific events and

noteworthy observations are detailed in the sections below. The

shutdown of Unit 1 for the planned 90 day refueling / steam generator i

replacement outage was well controlled and executed. In addition to the i

issues discussed in this report, other steam generator specific

inspections are detailed in NRC Inspection Report 369/97-03.

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02 Operational Status of Facilities and Equipment (71707)

02.1 Main Feedwater/ Containment Isolation Valve ICF26 Actuator Hydraulic

Fluid Leak

On January 23, control room operators performed a rapid down)ower of

l Unit 1 in accordance with Abnormal Procedure AP/1/A/5500/04 Rapid

L Downpower. The_ unit power was reduced to approximately 20 percent in

response to a hydraulic fluid leak at valve 1CF26. Main

Feedwater/ Containment Isolation Valve to the "D" Steam Generator..

Operators realigned main feedwater flow through the auxiliary feedwater

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nozzle to minimize the-probability of a loss of feedwater to the

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generator due to the uncontrolled closure of ICF26. The valve is

l- located in the Feedwater System flowpath to the O steam generator main  !

j nozzle in the main steam vault. Valve ICF26 is a safety related  ;

hydraulic isolation valve. The valve receives a signal to close on a

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Safety Injection Low Tavg coincident with Reactor Trip. HI-Hi doghouse 1

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Water Level, or HI-HI steam generator level

l .The inspectors noted that control room operator recognition of 'and

response to the indications of the hydraulic fluid leak were good. The

l unit remained at reduced power until-the leak could be repaired.

l Following the repair.- testing was completed and the valve returned to l

l service. The normal main feedwater flowpath was re-established and .i

l power escalated to approximately 100 percent with no additional

l operational challenges.

02.2 Isolated Phase Bus Coolina Fan ,

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a. Insoection Scope

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l The inspectors reviewed the licensee's response to the failure of the )

i Unit 2 Isolated Phase Bus Cooling System and coincident malfunction of ,

! the Unit 2 Rod Control System.  ;

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b. Observations and Findinas

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On January 20, the Unit 2 IPS cooling fan 2A tripped. Operators were

di_spatched to start the standby 2B fan but attempts to start the standby

, fan were unsuccessful. As a result, control-room operators began a

! rapid downpower in accordance with Abnormal Procedure AP/2/A/5500/04.  :

While reducing generator load, operators recognized that the rod control i

system was not responding as expected to the Tavg-Tref mismatch. The

operators took manual control of the rod control system and generator 1

load control and stabilized generator output at approximately 70 percent

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.and busline-current less than 20,000 amperes. The reduction of busline

current to less than 20,000 amperes was recommended to reduce the

overheating electrical components. The standby 2B cooling fan was

, subsequently started when the suction dam)er limit switch was manually

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adjusted. The suction damper limit switc1 position must be established

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prior to fan operation. Unit 2 returned to 100 percent power on January

21.

Work requests were generated to investigate and troubleshoot the IPB

cooling system and rod control system malfunctions. See paragraph M2.1

for'further discussion of these items.

c. Conclusions

The . inspectors concluded that operator diagnosis of and response to the

loss of IPB cooling 'and the coincident rod control system malfunctions

was good. The inspectors also concluded that the load reduction,

although not mandated by TS. was conservative.

02.3 Unit 1 Voltace Reaulator Perturbations

a. Insoection Scone

The inspectors reviewed operator response to a Unit 1 generator voltage

fluctuation and its potential impact to the unit.

b. Observations and Findinos j

On February 11. 1997, operators responded to indications that the Unit 1

generator voltage was increasing for unknown reasons. Attempts were

made to lower the voltage using the voltage adjust pushbutton with

little effect. CR o)erators dispatched NL0s to locally investigate the-

problem. Within a s1 ort time, operators stopped the continued voltage

increase: however, voltage swings were occurring. Transmission group

personnel were called to assist in the troubleshooting effort. The

maximum voltage seen during the transient was 25.45 kv and 713 MVAR.

The swings lasted approximately one hour. The operators were eventually

able to return the voltage to the normal range. The voltage swings were

determined to not have adversely affected any major plant. equipment.

The licensee. installed a recorder on the control cabinet to attempt to-

determine what caused the voltage swings. During the shutdown of Unit 1

for the outage several days later, no additional problems were

identified with the operation of the voltage. regulator. The licensee

determined that operator guidance could be improved regarding this type

of-anomaly and its potential impact on the plant. Procedural-guidance

was developed to place operating limits on the voltage swings to protect

plant equipment. The licensee plans to continue troubleshooting of the

l problem during the Unit 1 outage and will perform a root cause

investigation of the occurrence. Management focused the investigation

on determining the problem due to a potential recurrence during unit

restart from the outage.

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j c. Conclusions

'The inspectors concluded that initial operator response to the main

generator voltage control problem was adequate. Improved guidance to

operators regarding the degraded condition was provided by engineering )

in a timely manner.  !

02.4 Unit 1 Shutdown for Unit lEOC11 Outaae

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a. Insoection Scooe I

The inspectors witnessed portions of the Unit 1 shutdown.to Mode 4

focusing on special activities in progress that could impact safety

system performance or reliability to verify that licensee controls were

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j b. Observations and Findinas ,

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The inspectors witnessed portions of the Unit 1 shutdown for.1E0C11 on

l February 14. The unit entered Mode 3 on at 0412 and Mode 4 at 1438.

The shutdown was controlled in accordance with 0)erating Procedure

OP/1/A/6100/02. Controlling Procedure for Unit Slutdown. During the

shutdown, the inspectors noted that on shift control room operators were

attentive and responsive to )lant parameter changes and communicated the

changes to the appropriate slift personnel. Control room staffing met

l TS requirements and distractions were kept to a minimum in the horseshoe

i area. Operating conditions of plant equipment were ade

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and appropriate actions were initiated when necessary. Known quately

steammonitored

generator 1B leakage remained below TS leakage limits with no unexpected

increases. At the time of the unit shutdown, the leakage was

approximately 60 gad. Adequate core monitoring equipment was available '

and operable for t1e operational mode.

During the unit shutdown, the inspectors witnessed portions of ongoing

surveillance activities including B Train EDG-24 hour surveillance run.

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4160V essential power system realignment to support offsite and

L emergency power supply maintenance, and RCCA drop time testing to meet

. Generic Letter 96-01 commitments.

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The licensee encountered some unexpected difficulties 'during the <

shutdown to Mode 5. The Source range channel N31 detector failed.

Because the licensee had installed additional source range monitoring

equipment no dgnificant safety concerns were identified. The rod drop

time testing could not be completed-in its entirety due to rod control

malfunctiom. The inspectors determire3 that no deviation from the

Generic Letter 96-01 commitment existed. A primary system leak occurred

on a letdown filter casing (see paragraph 03.1). At the close of the

-inspection reporting period. no enforcement' actions were identified.

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c. Conclusions

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The inspectors noted chat licensee response to unexpected occurrences

was good and control of plant shutdown was adequate. Shutdown

activities were conducted with minimal impact on the operating unit. )

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02.5 50.72 Notifications

a. Insoection Scooe

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During the inspection period, the licensee made the following i

notifications to the NRC as required or for information purposes.

b. Observations and Findinas

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On February 15. 1997, operators made a 50.72 notification regarding

excessive leakage from an isolable leak on the Unit 1 RCS letdown filter

housing. The report was made under guidance provided by 10 CFR 50.72

(b)(1)(vi). where the leakage potentially could have hampered the

performance of station Jersonnel due to the localized requirement for

anti-contamination clotling. Based on subsequent review. the licensee

later retracted the notification based on their determination that the

leak did not pose a threat to the safety of the plant or hamper station

personnel.

c. Conclusions

The inspectors concluded that the notification was prudent and that the

retraction was adequate for the circumstances. The inspectors also

reviewed the occurrence for potential Notification of Unusual Event

(NOUE) and concluded the criteria for NOUE was not established. Details

of the event are discussed below.

03 Operations Procedures and Documentation

03.1 RCS Leakaae in Excess of TS Limit Durino letdown Filter Chanaeout

a. Insoection Scoce

The inspectors reviewed events regarding an RCS leak which developed

during changeout of the Unit 1 "A" RCS letdown filter. The unit was in

MODE 4 and in process of being taken to MODE 5 for refueling

preparations.

b. Observations and Findinos

At approximately 2350 hours0.0272 days <br />0.653 hours <br />0.00389 weeks <br />8.94175e-4 months <br /> on February 14 a leak developed at the

filter access plate on the 1A RCS letdown iter housing when operators

detensioned the housing cover. Filter c h geout was in 3rogress due to

an approximate 19 psi differential pressure reading whic1 prompted the

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activity (not uncommon during unit shutdown). The unit was in MODE 4 at

' the time of the leak and at an RCS aressure of approximately 300 psig.

All four RCPs were in operation. T1e operators entered the appropriate

j abnormal response procedures and took actions (sampled) to identify the

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leak as either RCS-'or RMWST (RMWST is demineralized flush water which is

utilized during filter changeout). The leakage was confirmed to be RCS

and operators then isolated letdown, which stopped the leakage. Prior

to repair of the leak area, operators raised a concern whether excess-

letdown could be adequately established given the low RCS pressure and-

whether pressurizer level should be reduced to increase the margin to

solid RCS oaerations. After discussing the available options.

Operations ianagement allowed letdown to be briefly reinitiated to allow

for reduction of pressurizer level from approximately 80 to 40 percent.

This and the placement of excess letdown in service allowed adequate

repair time without challenging solid operaticns.

The leak was estimated at ap3roximately 14 gpm. TS 3.4.6.2 requires

that RCS identified leakage Je limited to 10 gpm or reduce the leakage

within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and cold shutdown

with in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. As stated, the unit was in MODE 4 at

the time of the event and the leakage was secured within the allowable

TS ACTION requirements. Cleanup of the leak was completed in a timely

manner and the event did not result in any personnel contamination

incidents. Initial licensee review of the event identified leakage

through the letdown filter isolation valve, procedural weaknesses, and

configuration problems with the installed letdown filter housing vent.

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The licensee is planning o.n performing a complete root cause .l

investigation of the event. This issue will be identified as URI 50-- 1

369/97-01-01. Root Cause of RCS Letdown Filter leak.

c. Conclusions

The inspectors concluded that the operators were challenged by the RCS.

leak and reacted to the event in an appropriate manner. Root cause

evaluations will be performed to address the identified URI.

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04 Operator Knowledge and Performance (71707)

.04.1 Trackina of Control Room Problems

.a. Insoection Scone

During the inspection period, the inspectors reviewed a process by which

the licensee monitors and trends control room indication problems and

information tags on the control boards.

b. Observations and Findinas

One method that the licen a utilized to monitor CR problems is the

Control Room Indicator ~ ;1em (CRIP) process. CRIPs are routinely

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tracked by operations and' reported to site management as a performance

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measure to assess the impact of the equipment concerns on plant

l operations. The program is defined by MSD 590. A CRIP is defined as a

j control room instrument or control that cannot perform its intended

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function, including any equipment problem which prevents a dark

! annunciator condition when required. In general, these devices provide

l information to CR operators on the status of plant equipment. provides

! input to control process parameters, controls equipment operated from

l the CR. and provides integrated information retrieval and display

! capabilities.

WRs are reviewed for applicability to the CRIP criteria as part of the

work planning process. Per MSD 590, higher priority is given to those

work recuests identified as a CRIP. Innage CRIP work orders are

! expectec to be planned to allow resolution of the problem within two

L weeks of origination. The status of CRIPs are monitored by maintenance

management, operetions. and work control.

The inspector discussed the CRIP process with involved plant personnel.

performed CR walkdowns to determine if all relative issues were

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. identified as CRIPs, and reviewed the historical completion of CRIP WRs.  ;

j As of the end of 1996, the total number of innage CRIP's was eight with

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l a YTD average of six. The oldest innage CRIP was less than two weeks.

l indicating that the work off was within the program guidance. The total

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number of outage CRIP work orders was approximately 40. with the

l expectation that all items would be resolved post outage. All equipment .

l problems reviewed for CRIP applicability were found to be appropriately l

l identified as such

The inspectors also reviewed the CR information tagging process. This

j utilizes yellow information tags on a variety of CR equipment which

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allows operators to be informed about special equipment concerns.

l problems, or expected responses. The inspectors compared the current

information tags to the CR information tag log and did not identify any

i majordiscrepancies. Some minor inconsistencies were found regarding

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tag issue information such as lead contacts or initiation dates. In l

l general, operator awareness of the content of the information tags was

considered adequate. All operators questioned were knowledgeable as to

where to find additional information if necessary.

c. Conclusions

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l Based on the inspector's review, the station's monitoring of ' control

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room indication problems, as defined by the licensee's CRIP process was

[ effectively implemented. The inspectors also concluded that the process

may be challenged during the upcoming Unit 1 0AC replacement project.

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The use of CR information tags was generally well implemented. The

, inspectors expressed a concern to Operations Management concerning

- potential overlapping of problem tracking processes, including the

j operator work around process, which could present confusion regarding

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problem mc'itoring and resolution. The licensee was receptive to the

concente and was reviewing the issue for potential impacts.

05 Operator Training and Qualification

05.1 Differences in Assumed Simulator Response Times for Ooerator Actions

a. Insoection Scope

During the insaection period, the inspectors reviewed a licensee

identified pro)1em concerning discrepancies between actual plant

equipment response times versus simulator modeling of certain operator

time critical actions.

b. Observations and Findinas

During an effort to verify that F5AR response times matched actual

operator performance in transferring to RCS cold leg recirculation, the

licensee identified several critical times which needed to be evaluated.

Operators did not have problems completing the necessary steps prior to

FWST depletion; however, critical times assumed in the simulator

response were based on design assumations that differed from actual

plant performance. Specifically, t1e most significant example was

identified where the simulator was modeled with the containment spray

pump flow rate of approximately 3.400 gpm whereas actual plant flow

rates were closer to 4,000 gpm. This incorrect modeling of the

simulator could have )otentially impacted operator response to a plant

event by decreasing t1e time for critical operator action prior to FWST

depletion. The ins)ector was specifically concerned that tN. incu rect

simulator modeling lad gone undetected for a long period of time and

could have conditioned operators to expecting a certain amount of time ,

to complete key actions during event response.. l

Upon recognition of the con:.ern, operations reviewed the applicable  !

procedures and identified numerous areas were enhancements could be made

to increase the time allowed for critical action response. After the  !

procedure enhancements were made, the procedures were re-validated with l

crew performance. indicating that the critical functions could be

3erformed. In addition, operator training emphasized that since the l

WST could deplete faster than the simulator model during a design base l

LOCA, operators may have been accustomed to exaggerated critical action '

time requirements in the past. The licensee also provided additional

guidance which emphasized that key critical tasks should be performed

"without delay" At the end of the inspection period, the licensee was

continuing to evaluate other potential areas where operator critical

time monitoring could be enhanced.

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c. Conclusions

The inspectors concluded that the inconsistency between the critical

action times modeled in the simulator and the actual plant response

times during plant transients was indicative of a significant weakness.

The example noted could have adversely impacted operator response

capabilities by training on the incorrect critical action times. Once

identified, licensee immediate corrective actions and response to the

concerns were considered adequate.

06 Operations Organization and Administration (71707)

06.1 Overtime Controls

a. Insoection Scoce

The inspector performed a review of approved overtime for the most .

recent months for the plant operations and maintenance groups. The l

inspector also overviewed licensee records of all personnel overtime

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exemptions for hours in excess of established limits. Control of

overtime for plant personnel is required by Technical Specification - 6.2.2.e and NSD 200. Overtime Control. These documents require the

licensee to document and properly authorize work hour extensions.

b. Observations and Findinas

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The inspector reviewed work hour extension documentation for the subject I

groups and determined that the forms, in general, were properly filled

, out and reasons for the work hour extensions were appropriate for the i

circumstances. The inspector verified that the station manager was  !

reviewing a monthly site overtime report to determine that the use of

overtime was warranted and not being abused. l

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The inspector noted that in an overtime control report dated November

20, 1996, the licensee's evaluation of the data identified several

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discrepancies regarding the completeness of the required forms. The

problems were documented in PIP 0-M-96-3399 for corrective action.

c. Conclusions

The inspector concluded that control of overtime for plant personnel

during this period was adequate. In addition, the licensee assessments

performed on the control of overtime were detailed and provided good

oversight.

06.2 Postino of Notices to Workers i

During the ins)ection period, the inspector reviewed the licensee's

compliance wit 1 the requirements of 10 CFR 50 Part 19.11, Posting of

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Notices to Workers. The licensee implements these requirements via NSD

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205, Posting Requirements. This procedure identifies three locations

where required postings are to be maintained. The inspector verified

that the licensee conspicuously posted current copies of NRC Form-3 and

other required materials such as escalated enforcement and radiological

violations in the areas. No problems were observed by the inspectors

during this review.

07 Quality Assurance in Operations (40500)

07.1 Review of Institute of Nuclear Power Operations (INPO) report

During the inspection period, the SRI and the NRC DRP Branch Chief,

reviewed the most recent Institute of Nuclear Power Operations (INPO)

report. The review concluded that the results of the INP0 evaluation

completed in late 1996 were generally consistent with the results of

similar evaluations conducted by the NRC. No additional NRC follow-up

of any specific issue was identified.

08 Miscellaneous Operations Issues (92700)

08.1 LCL_SfD) LER 50-369/96-03: Inoperability of Both Unit 2 EDGs. This LER

is closed based on reviews performed during the closure of Violation

369.370/96-07-07. Failure to Take Adequate Corrective Action for EDG

Fuel Line Failure which is discussed in paragraph E8.3.

II. Maintenance

M1 Conduct of Maintenance

M1.1 General Comments (61726 and 62707)

The inspectors witnessed selected surveillance tests to verify that

approved procedures were available and in use, test equipment in use was

calibrated, test prerequisites were met, system restoration was

completed, and acceptance criteria were met. In addition, resident

inspectors reviewed and/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.

a. Insoection Scope

The inspectors observed all or portions of the following work

activities:

PROCEDURE /WO# TITLE

. PT/0/A/4600/78 RCCA Drop Timing Using Rod Position Grey

Code

Enclosure 2

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. PT/1/A/4350/368 Emergency Diesel Generator 18 24 Hour Run

. PT/1/A/4350/06 4160V Essential Power System Test

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. PT/0/A/4601/08A SSPS Train A Periodic Test with NC System l

Pressure > 1955 Psig

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Malfunctions of Isophase Phase Bus Coolina Fans and Rod Control System

1

a. Inspection Scoce i

The inspectors conducted inspections to verify that activities to

correct the isolated phase bus cooling system and rod control system I

malfunctions were conducted in manner to ensure safe and reliable l

equipment operation.

b. Observations and Findinas

l

Maintenance technicians were contacted to identify and correct the cause

for the 2A isophase bus cooling fan trip and subsequent 28 isophase

cooling fan failure to start. Technicians investigated the cause for

the 2A fan trip and determined that the 2A IPB fan tripped on thermal

overload due to higher than anticipated area temperatures. The area

ventilation had been secured resulting in elevated temperatures. The

licensee determined that the thermal overload trip setpoint was overly

conservative providing very little margin between normal operating

ranges and the overload relay trip setpoints. The licensee developed

and implemented modifications to replace the 2A and 2B thermal overloads

to provide additional margin. The relay was replaced and functionally

verified.

The licensee investigated the failure of the backup supply fan to start

and determined that a limit switch at the fan outlet damper failed to

provide the necessary interlock for the manual start of the standby fan.

A Work Request was written to investigate the rod control system failure

to operate in automatic when the operators began reducing power. The

licensee's investigations identified a'comaarator circuit card which

controls the rods in-rods out function. T1e card was replaced. The

licensee concluded that the rods would have 03erated properly following

s

a manual or automatic reactor trip signal. T1e comparator circuit card

was replaced and functionally tested. Rod control was returned to

automatic. No other rod control malfunctions occurred prior to unit

shutdown for refueling outage 1EOC11.

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'c. Conclusions

<

The inspectors concluded that the licensee's corrective maintenance was

effective. Rod control system repairs were adequate. Isophase cooling .

relaying modifications and damper switch replacement should provide  ;

' improved cooling system reliability.  !

M3 Maintenance Procedures and Documentation

M3.1 Work Control Process i

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a. Insoection Scooe

The inspectors performed inspection of activities related to the

unanticipated automatic trip of the "A" auxiliary electric boiler (AEB).

b. Observations and Findinas .

On January 10. the "A" AEB was started to support functional

verification following completion of mechanical maintenance activities.

The boiler was started and operated. Monitored parameters were normal

with the exception of slow steam pressure response. The boiler tripped

and station personnel observing boiler o)eration promptly exited the  ;

-area. :The licensee determined that the ] oiler tripped due to

overcurrent conditions related to' boiler ph levels. No station i

personnel were injured due to the boiler operation.

'

Prior to the boiler operation and subsequent trip, other maintenance on

the 'A' AEB on the steam pressure control loop had begun and had not  !

been com)leted prior to boiler. operation. The steam pressure control .

valve. C370 was closed with air removed. Completion of the maintenance

activity was scheduled. No tags had been issued to perform this work.

Technicians had provided information describing the maintenance effort

on the boiler and had received authorization to perform the activity. ,

The maintenance activity was not completed prior to shift turnover.

During shift turnover, the information was not communicated to the

oncoming operations shift and no tag clearance was necessary to operate

the AEB. The inspectors noted that the work control for the particular

work activity was not managed adequately to minimize the potential for.

personnel injury and/or equipment damage. 'The operation of the "A" AEB

while IAE maintenance was ongoing was due to poor communications between

operating shifts. The inspectors discussed tie occurrence and

determined that no information was readily available to inform the on-

shift operations staff of the ongoing maintenance activity prior. to

boiler operation'.

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! c. Conclusion

The inspectors reviewed the events and determined that control of no

tagout work activities was not sufficient to provide adequate controls.

Similar occurrences may potentially result in personnel injuries or

, equipment damage.

4

M6 Maintenance Organization and Administration

4

M6.1 Maintenance and Work Control Restructurina

The licensee made organizational changes in Maintenance and Work Control

to re-establish consistency between the three Duke Power licensed

facilities. The official restructuring was scheduled to be completed no

later that June 1, 1997.

Under the new organization. Quality Assurance /Ouality Control,

Procedures. Planning Clerical Sup3 ort. Welding, and Modification

Execution teams. previously under iaintenance will report to Work

Control. This licensee concluded that this restructuring should better

distribute responsibilities between Maintenance and Work Control and

does not require changes to the current work control process. The

restructuring should also enhance OA/QC independence.

M7 Quality Assurance in Maintenance Activities

M7.1 Review of Motor Reliability Problems /Imorovement Initiative

a ., inspection Scone (62700 and 4C500)

1

In June 1995. Duke Power Company identified that motor performance at

nuclear power stations did not meet industry standards. McGuire. Unit 1

performance, based on Nuclear Plant Reliability Data System data, showed

the highest failure rate for large motors of all nuclear sites in the l

country over a three year period. McGuire Nuclear Station established a  ;

_

Ouality Improvement Team initiative to improve reliability of all motors i

at the station in September 1995. The licensee initiated PIP 0-M96-0204 l

to document the problem and corrective actions at McGuire. The  !

inspectors reviewed corrective actions for PIP 0-M96-0204 including the

Motor Reliability Improvement Initiative Report, specific motor problems

and corrective actions, and conducted plant walkdowns and discussions  !

with engineering personnel responsible for implementing corrective

actions to improve motor performance.

b. Observations and Findings

A review of PIP 0-M96-0204 identified several motor problems and

corrective actions taken to date. Motors identified with high failure '

rates included Condensate Booster Pump motors. "C" Heater drain Pump

motors, Steam Generator Blowdown motors. Lower Containment Ventilation

Enclosure 2

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l motors. Control Rod Drive Mechanist Ventilation motors, Fuel Pool

l. Cooling motors, Reactor Coolant Pump motors. Turbine Building )

l Ventilation motors. Instrument Air Compressor motors, and '

l';. motor / Generator Sets. The licensee identified specific causes of the

failures for each motor type and. instituted corrective actions in most 1

l cases. For example, the Fuel Pool Cooling motor problem was deteemined I

l to be impro)er ventilation configuration resulting in lower than  ;

i required luarication levels for bearings. The ventilation was

L reconfigured to resolve the problem. The Reactor Coolant Pump Motor ,

l: problem recuired' refurbishment of each motor. This arocess has not been  !

completed cue to operational recuirements and availa)ility of only one

.

spare motor for both McGuire anc -Catawba. However, the causes of past

!

failures were understood, and corrective actions were scheduled

l The inspectors noted the licensee matrixed the causes of the motor

l failures in the Root Cause Failure Analysis Report in a Motor Fault Tree

j format, The report identified several problems associated with motor

failures. Specific failure causes were identified as inadequate

I maintenance, lack of vendor cuality control, and improper motor-

application. The licensee icentified the root cause of the motor  ;

problems as a motor program management deficiency. The inspectors  ;

! considered the licensee's failure analysis was properly focusing on

l problem areas.

The inspectors discussed the motor problems with engineering personnel i

and performed plant walkdowns to evaluate motor material conditions. In

-addition, preventive maintenance work orders and procedures were

reviewed to evaluate adequacy of the licensee maintenance in this area.  ;

The reviews. determined the licensee was focusing resources on preventive

maintenance for motors which was based on causes of past failures and

vendor recommendations. Observed conditions of motors in the plant were i

generally good. However, some items were identified which required

additional disposition. One issue involved internal inspection of RHR

(ND) and Containment Spray (NS) Pump motors. When questioned by the

inspectors, the licensee could not provide documentation of motor

internal inspections. The licensee initiated PIP 0-M97-0177 on January

L' 16, 1997, to review and disposition this issue.

The inspectors also noted that the "C" Heater Drain Pump motors

continued to exhibit some problems. During plant walkdown, the

inspectors noted oil leakage from four of the six "C" Heater Drain Pump

l motors. In addition, the air filters on the side panels for the Unit 1

j pump motors were dirty. These items were discussed with engineering

I personnel who stated they would be addressed as part of PIP 0-M96 0204

corrective actions. The licensee identified the root cause of these

motor 3roblems to be inadequate repair / refurbishment information

t- availa)le to motor repair shops. The licensee was working with

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Westinghouse to provide appropriate repair information during future

motor refurbishment. The inspectors concluded that this area requires

continued licensee attention to assure appropriate corrective actions

are implemented.

During this period, the inspectors noted several observations relating

to plant 3rocesses and housekeeping. Positive observations included:

low threslold for identification of issues in the problem investigation

process, good housekeeping in the charging pump rooms, examples of good

predictive maintenance / monitoring, good engineering response to issues,

and a thorough Operations shift turnover in the control room on January

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-16,*1997. Other observations included staging located in RHR pump room

2A and Containment Spray pump room 18. The inspectors discussed the

staging observations with the operations shift on January 16. 1997.

Operators stated they did not brief status of activities requiring

staging in operable safety-related pump rooms at shift turnovers.

Although the staging was appropriately tagged, the inspectors considered 1

that activities involving staging in operational . safety-related pump  !

rooms should be minimized with appropriate operational focus being -  ;

maintained,

c. Conclusions

The inspectors concluded-the licensee was actively involved in

evaluation and resolution of motor problems. The Root Cause Failure ,

Analysis Report was thorough and identified several focus areas for

improving motor performance.- Even though some motor problems continued,

the licensee's Quality Improvement Team initiative at McGuire had

produced some positive results, and should improve motor performance if

the initiative is continued.

III. Enaineerina

E2- Engineering Support of Facilities and Equipment

E2.1 Review of Desian Basis for the FWST and Surroundina Missile Wall

'

a. Insoection Scooe (37551)

Review of design basis for the FWST and surrounding missile wall.

b. Observations and Findinos

During the inspection' period, the inspectors questioned the design basis

for the FWST swapover function during post LOCA operator actions.

Specifically. the inspector.noted that the licensee's design did not

incorporate an interlock between the automatic post LOCA injection

realignment and actual containment sump levels. An interlock feature

has been incorporated at other facilities, including Catawba, to ensure

- that appropriate containment sump levels exist after FWST depletion in

order to ensure adequate suction supply to the ECCS pumps.

Enclosure 2

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The licensee reviewed the inspector's concern and also other in-progress

reviews that were being performed at other Duke facilities regarding the

overall design basis of the FWST. It was determined that a discrepancy

existed in the wall height of the FWST missile shield wall.

Specifically, the height of the McGuire FWST missle wall was 2 inches .

below the height of the FWST to containment sump ECCS suction swapover )

level setpoint. The FWST missle wall was desianed to protect the tank '

, during a tornado event, assuring sufficient volume to make up for the

j RCS system shrinkage during a postulated steam line break. In this

event the centrifugal charging pumps would inject to offset the volume I

contraction and to provide a source of negative reactivity for i

criticality considerations. '

.

The licensee performed extensive analysis of the concern which was

.

documented in PIP 0-M97-0180. The licensee identified that a change was

, made in the mid 1980's which raised the automatic swap-over level set  !

point from 100 inches to 150 inches. This change (NSM-MG-1-1790) made l

the swapover level relative to the bottom of the tank to be 170 inches.

3 However, the missle wall was built to be 168 inches relative to the

!>

'

bottom of the tank. Therefore, a rupture of the tank at the missle wall

height could potentially deplete the tank's volume below the auto swap

level without the required containment sump inventory for cold leg

recirculation. The licensee reviewed this scenario and concluded that

4

since auto swapover aligns the low head ECCS pumas to the sump, the Low

'

head (RHR) pumps would not be injecting due to t1e primary system

pressure not falling below the pump's shutoff head. The review

concluded that the RHR pumps would have sufficient volume in their mini-

,

flow recirculation volume to not ex3erience cavitation for the duration

of the event. In addition, the hig, and intermediate head pumps would

still have adequate suction supply from the FWST. The licensee

concluded the FWST was both past and currently operable. '

<

In addition to the above, the licensee identified several other

!

questions regarding FWST design and operator actions associated with i

FWST depletion scenarios. At the end of the inspection period, the

inspector was continuing to evaluate the licensee's engineering reviews

of the FWST design and operability basis. The reviews will be  ;

identified as IFI 369. 370/97-01-02, FWST Design Basis.

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c. Conclusions

The inspector concluded that engineering personnel were performing in-

, depth reviews of the FWST design basis to ensure compliance in that area

, and to identify any potential problems.

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, E2.2 Enaineerina Sucoort of Ooerations i

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a. Insoection Scone (37550) l

The inspector reviewed engineering activities which support operations

by observations of engineering and operations personnel interfaces and

review of active engineering material in the control rooms.

. b. Observations and Findinas

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The inspector reviewed the open o)erability evaluations, the degraded

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but operable determinations and t1e ongoing evaluations. The

evaluations and determinations were reviewed to ensure that they did not

involve an unreviewed safety question and that the margin to safety was

not decreased by the existing degraded condition. Reviewed were 13

operability evaluations, two ongoing evaluations, and three degraded but

operable determinations.

i

c. Conclusions

l The inspector concluded that Engineering was providing effective support

to Operations. The number of open evaluations / determinations was not I

abnormal. The quality of the determinations was good and the results

were well documented.

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E3 Engineering Procedures and Documentation

E3.1 Chanaes. Tests and Experiments Performed In Accordance With 10 CFR 50.59

( Aoril J .1995. to Aoril 1.1996)

a. Insoection Scooe

By letter dated October 16, 1996, the licensee submitted its annual

summary of all ch.inges, tests, and experiments that were completed under

the provisions of 10 CFR 50.59 for the period April 1,1995, to April 1,

1996. The licensee's October 18. 1996, summary includes 82 changes made

during the subject period. The ins)ector reviewed a number of these

changes against the provisions of t1e regulation.

b. Observations and Findinas

1. Backaround

10 CFR 50.59 provides that a licensee may (1) make changes in the

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

the procedures as described in the safety analysis report, (3) conduct

tests or experiments not described in the safety analysis report,

without prior Commission approval, unless the change involves a change

in the technical speciheations or an unreviewed safety question (US0).

4

The regulation defines a US0 as a proposed action that (a) may increase

Enclosure 2

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the probability of occurrence or consequences of an accident or

malfunction of equipment important to safety previously evaluated in the

safety analysis report. (b) may create a possibility for an accident or

malfunction of a different type than any previously evaluated in the

safety analysis report, (c) may reduce the margin of safety as defined

in the basis for any technical specification.

2. Procedures

The inspector reviewed the licensee's current (dated March 21, 1996)

version of Nuclear System Directive (NSD) 209 "10 CFR 50.59

Evaluations." which is a procedure that describes how Duke Power Company

(DPC) meets the requirements of 10 CFR 50.50. NSD 209 requires that

changes be evaluated against appropriate Final Safety Analysis Report

(FSAR). Technical Specifications, and NRC Safety Evaluation Report

sections to determine if there is need for revision. Specifically, the

procedure in NSD 209 has the criteria saecified by 10 CFR 50.59 broken

down into seven (7) questions. For a clange to be qualified for 10 CFR

50.59, the answers to all seven questions must be "no".

3. Trainina ,

The licensee has a required training program for personnel that perform

reviews of 50.59 screenings and evaluations. These personnel are known

as Qualified Reviewers (ors). A OR is defined by the licensee as an

individual qualified by education, training and experience to perform

the reviews for procedures, procedure changes and nuclear station

modi fications. Often preparers of procedures, procedure changes and

nuclear station modifications are also qualified as ors. A review of

the training program determined that the program covered all the

essential aspects of the 50.59 screenings and US0 evaluations.

4. Imolementation

The implementation of the licensee's 50.59 program was evaluated by

reviewing a sample of completed 50.59 screenings and USQ evaluations and

interviewing personnel involved in the preparation or review of 50.59

screenings and U50 evaluations. The sample was taken from a total of 82

changes made between April 1995 and April 1996, that were reported in

the licensee's annual summary of changes. Also, a review was done of a

sample of " screened out" (determined not to require US0 evaluation)

items that were randomly chosen from the licensee's files.

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

determine the nature and safety significance of each change. Through

this review, the inspector selected the following changes for more

detailed review onsite:

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Procedure changes - l

OP/ 1/A/6400/05, 1/A/6100/10K. 0/B/6200/109. 1/A/6200/04A.

2/A/6200/04A

EP/ 1/A/5000/FR-P.1. 1/A/5000/FR-I.1. 1/A/5000/ES-1.1.

1/A/5000/ECA-2.1. 1/A/5000/ECA-0.2. 1/A/5000/ECA-0.1.

1/A/5000/E-3. 1/A/5000/G-1

AP/ 1/A/5000/35

MP/ 2/A/7150/57. 0/B/7150/121

PT/ 1/A/4150/044

Modifications - -

NSM 12096, 12279/P6. 12441. 22096, 22441, 22445, 22454,

22455.22457.22473. 29040/P22

MM 3409, 3416, 3860. 3866. 3919, 4039. 4040, 4045. 4097. 5451.

5452. 6164. 6165. 7067.7068. 7096. 7125. 7757

Revision to NRC commitments -

Monitoring eight break locations

Licensee " screened out" items -

OP/ 2/A/6100/23

EP/ 2/A/5000/ECA-2.1

EP/ 1/A/5000/FR-P.2

PT/ 1/A/4206/03A (CHANGE 13)

IPOA 3207007

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

observations as noted below and has communicated them to licensee

personnel:

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A good self-assessment was recently performed on the 50.59 process

at Catawba. McGuire has utilized the results of this self-

assessment by incorporating the lessons learned into their 50.59

process.

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NSD 209 represents a solid foundation for the 50.59 process and

should serve the three stations well, provided the licensee is

diligent in getting personnel to correctly implement the

Directive's requirements.

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Minor administrative problems, which were similar to those

identified by the licensee in the above mentioned self-assessment,

were found in the McGuire 50.59 packages. These included:

e Blocks on some of the 50.59 forms were not checked as

required by NSD 209.

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e Illegible preparer and OR signatures were noted on some j

forms. )

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e The justification write-ups for some 50.59 packages did not

clearly address the questions asked on the 50.59 form.

c. Conclusion

Based on the review of the. licensee's October 18, 1996, annual summary

on 10 CFR 50.59 changes, and audit of the licensee's procedures and

evaluations, the inspector concludes that the licensee has complied with

the provisions of this regulation for the changes reported in the annual

summary.

E4 Engineering Staff Knowledge and Performance

. E4.1 Shutdown Bank Triocable Worth Strateay

a. Insoection Scoce (37551)

The insSectors reviewed the licensee evaluation of withdrawing shutdown

banks w111e in Mode 4 to provide additional shutdown reactivity.

i

b. Observations and Findinas

The licensee held PORC meetings to review and evaluate the practice and -l

determined that a no potential existed for a noncompliance with assumptions

used in UFSAR accident analyses. Some questions were raised about the ,

assumptions used in'the uncontrolled bank withdrawal'from zero power l

analysis. The PORC concluded that the assumptions of the current UFSAR 1

uncontrolled rod withdrawal. analysis bound any credible unexpected rod

withdrawal power transient.

-The current UFSAR analysis assumes that the reactor is critical such that

the first available trip is the 25 percent low power trip. This assumption  ;

allows for an extremely fast reactivity addition, allowing the reactor to

reach a prompt critical condition. -This_results in a severe )ower,

temperature and pressure transient by withdrawal of shutdown aanks. With

the unit subcritical in MODE 4. operators would receive the high flux at

shutdown alarm at one half decade above background counts and the reactor

would also encounter the source range trip at 10E5 cps. Therefore, a real

rod withdrawal event from subcritical conditions could be terminated by

l operator action or automatically with the reactor significantly '

subcritical. There would not be a resulting reactor coolant system

temperature or pressure transient. Therefore the consequences of such an ,

j event were determined to be bounded by the current analysis. i

Following the PORC, the licensee concluded that the withdrawal of shutdown

l banks A and B would not. place the plant in a degraded condition with

j- regards to an uncontrolled bank withdrawal event. As a result, the

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licensee revised the existing shutdown and startu) procedures to allow I

control room operators to close the reactor trip areakers and withdraw pre- .

selected shutdown rod banks during Modes 3 and 4. l

c Conclusions

The inspectors concluded that the licensee's use of the trip)able worth I

strategy was conservative based on available information. T1e inspectors q

identified no TS noncompliances or UFSAR deviations. The inspectors 3

reviewed the results of the licensee's evaluation and concluded that the

practice of early withdrawal of a shutdown bank to provide a means for

immediate negative reactivity addition during a dilution was conservative, j

E8 Miscel.laneous Engineering Issues (92902)

E8.1 (Closed) Violation 50-369. 370/96-02-02: Failure to Correct Long Term

Deficiencies Resulting in Valid Failures of EDGs.

The-issue involved emergency diesel generator failures due to inadequate

design of the lines for lubrication oil pressure sensing instrumentation

and control. The licensee responded to the Violation in a letter dated

June 6, 1996. In that letter, the licensee stated they took corrective )

actions including conducting a root cause failure analysis and identifying

corrective actions. The correcti_ve actions included periodic maintenance

to vent the lubrication oil pressure loops, periodic testing of the

lubrication oil impulse lines, and implementation of a modification on the

Unit 2 emergency diesel generator lubrication oil instrumentation lines to

shorten the lines.

The inspectors reviewed the licensee's root cause analysis report (PIP 2-M-

96-0331), verified other corrective actions were implemented as stated, and

observed routine testing of the 1B EDG on. January 14, 1997. All equipment

Serformed as required. Implementation of the modification to shorten the

Jnit 1 lubrication oil instrumentation sensing lines was scheduled for the

next refueling outage commencing in February 1997. The inspectors

. determined that corrective action without the modification in place for

Unit I was adequate; however, based on Unit 2 test results, the

modification provided additional margin to prevent recurrence of the

problem. The inspectors concluded the root cause analysis and corrective

actions for the EDG lubricating oil pressure sensing line issue

appropriately addressed the problem.

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Enclosure 2

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E8.2 (CLOSED) DEV 50-369.370/96-07-04: Failure to Comply with Commitments in

Response to Generic Letter 88-03 Steam Binding of Auxiliary Feedwater Pumps

This deviation involved the failure of the licensee to provide continuous

monitoring to detect steam voiding that was not accomplished due to the

installation of an incorrect type of resistance thermal detector (RTD).

These RTDs provide indication of auxiliary feedwater piping temperature and

activation of control room alarms when temperatures exceeded established

administrative limits. In addition, inadequate compensatory measures were

taken once the problem was identified. The inspector noted that the

licensee had installed RTDs of the correct type to provide continuous

indication of CA piping surface temperatures and alarms. This deviation is

closed.

E8.3 (CLOSED) Violation 50-369.370/96-07-07: Failure to take Adequate

Corrective Action for EDG Fuel Line Failure and LER 50-369/96-03 Rev 1.

On June 19. 1996, the licensee experienced a failure of the 4R cylinder

fuel line on the 1B EDG. The licensee issued a root cause evaluation

report of the 1B EDG fuel line failure on the 4R cylinder. The failure was

attributed to tube pullout of the 4R cylinder fuel injection line to fuel

pump connection. Specifically, the report concluded the line had ejected

from the ferrule connection due to inadequate crimping of the ferrule to

the tube. All the fuel lines on the Unit 1 EDGs had been upgraded to a new

double-walled tube design in December 1995 to prevent through wall crack

propagation. The Unit 2 EDGs fuel lines were previously replaced (all but

four were upgraded double-wall) during earlier unit refueling cycles and

had not experienced any failures. Corrective actions were developed to re-

crimp all applicable EDG fuel lines on Unit 1 and the four selected fuel

lines for t1e Unit 2 EDGs. These actions were scheduled to occur

concurrent with the routinely scheduled EDG outage days (i.e., one EDG per

month) to minimize unavailability. On July 30. 1996, the licensee

experienced an additional failure of the 1B EDG 4R cylinder, prior to

performing the re-crimping as discussed above. Based on the second failure

at the same location, the licensea expanded their original root cause

investigation process and obtained the services of two separate vendors to

act as oversig1t for the failure analysis and to provide technical

expertise. The second revision to the root cause analysis concluded that

the most likely cause of the second failure was improper crimping of the

sleeve onto the fuel line, possibly aggravated by some pressure increase at

the fuel pump outlet. The licensee also concluded that the monitoring of

cylinder exhaust temperatures was not as good of a failure indicator as

previously expected.

Based on the revised root cause, the licensee significantly expanded their

corrective actions. These PORC reviewed actions included:

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For the IB EDG. fuel lines were re-crimped, fuel line ends were

machined for proper ferrule positioning, and a 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> run performed

to verify the re-crimping process.

Enclosure 2

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Replaced both injector and fuel pump on the 4R cylinder and inspected

the two additional injectors.for contamination. No contamination was

j identi fied.

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Ferrule connections and the crimping process was reviewed by an

industry expert.

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Removed re-crimped, machined tube ends, and reinstalled all fuel

l injection lines for the 1A 2A. and 2B EDGs in an expedited manner.

!

I The inspector reviewed the licensee's response to a Notice of Violation

i dated. October 24, 1996, and the corrective actions included in that

i response. The inspector reviewed Revision 4 to MCS-1301.00-000007. dated .

j January 16. 1997, the EDG spare parts specificatico. This specification

l had been revised to address the new fuel line crimpir9 and dimensional

j requirements. Procedures MP/0/A/7400/009. Nordberg Diesel Engine Cylinder -

-

Head Removal and Installation. Rev 13. and MP/0/A/7400/01. Nordberg Diesel

Engine Fuel Oil Injection Pump Removal. Installation and Lift.to Port-

l Closure Check, Rev 5. were reviewed to ensure the new crimping and

dimensional checks had been included. The inspector reviewed the Nordberg

Diesel Owners Group Recommended Maintenance Program, endated. to verify

L that it contained a six-year recommendation to clean the injector spray

i tips. The inspector observed the spare fuel lines in the warehouse for

F proper crimping. This had been accomplished under WO 96087369. The

engineering training package discussing the fuel line failures and lessons

j learned was reviewed. Based upon the above reviews and observations, this

, item and LER 50-369/96-03. Revision 1 is closed.

r1

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IV. Plant Supoort

l

R1 Radiological Protection and Chemistry Controls

! R1.1 Review of Criticality Monitorina Reauirements

h

j a. Insoection Scooe

4

1

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Review of the licensee's compliance with criticality monitoring and '

t associated requirements contained in 10 CFR 70.24 (a).

!

l b. Observations and Findinas

j During the inspection period, the inspector reviewed the licensee's actions

i to comply with the requirements of 10 CFR 70.24 (a). The purpose of 70.24

(a) was to require monitoring, procedural guidance, and emergency drills.

L unless a specific exemption was granted to the requirements. The

. licensee's monitoring capability in the-area of the new fuel receipt / spent

i fuel pool areas consisted.of two detectors in the new fuel vault and one

detector on the refueling bridge. 70.24(a), in general, requires that a

monitoring system be capable of detecting a criticality within a required

! time frame. The coverage of the monitoring system in all areas shall be

.

l Enclosure 2

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provided by two detectors. In addition, appropriate drills and procedures i

j. shall be established as part of the requirements. l

t'

The licensee had previously received an exemption from the applicable 70.24

3 monitoring requirements as part of their special nuclear material (SNM)

4

license during construction: however, the licensee did not request an i

additional exemption cace the construction license terminated. The

i

inspectors discussed the status of their current compliance with 70.24 (a) .;

j and determined the following:

I --

No emergency procedures were in place for evacuation of the I

applicable areas nor were evacuation drills performed as required by

. 70.24 (a)(3). At the end of the inspection period, the licensee had

j developed emergency procedures and were planning the performance of

.

evacuation drills prior to the receipt or movement of any new-fuel.

l The inspector verified that the new fuel inspection and storage

procedures were on hold status such that new fuel would not be

received prior to procedure training and drill completion.

" Once identified to the licensee, prompt actions were taken to submit

i an exemption request to the Commission (dated February 4. 1997) on

i behalf of the McGuire. Catawba, and Oconee sites. On February 13,

i 1997, the NRC requested additional information regarding the

licensee's compliance with 70.24 requirements. As of the end of the

'

$

inspection period, NRR review of the exemption request was still in

i progress,

c. Conclusions

f

! The inspector discussed the above findings with NRC management and reviewed

,

the regulatory significance. Based on the review, a Violation of 10 CFR

! 70.24 (a)(3) was identified for failing to have established emergency

i procedures to address a potential criticality event. In addition,

i requirements to perform evacuation drills of the affected. areas were also

i not met. This will be identified as Violation 50-369, 370/97-01-03,

Violation of 10 CFR 70.24 Requirements.

!

V. Manaaement Meetinas

[ X1 Exit Meeting Summt.ry

I'

-The inspectors presented the inspection results to members of licensee management

at the conclusion'of the inspection on February 24, 1997. The licensee

'

acknowledged the findings presented. l

.

The inspectors asked the licensee whether any materials examined during the

' inspection should be considered proprietary. No proprietary information was

identified.

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I Enclosure 2 i

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

1

Barron, B. , Vice President. McGuire Nuclear Station

Boyle J. , Civil / Electrical Systems Engineering )

Byrum W., Manager. Radiation Protection

Cline. T. , Senior Technical Specialist. General Office Support l

Cross. R., Regulatory Compliance

Davison. Valve Supervisor l

Dolan. B. , Manager. Safety Assurance l

Geddie. E., Manager. McGuire Nuclear Station i

Harley. M., Engineering Supervisor '

Herran. P., Manager. Engineering

Jones. R., Superintendent. Operations

Karriker. S., Valve Engineer (Site GL 89-10 Program Lead)

Kunkel. N., Senior Engineer i

Lamb. J., Valve Engineer l

Michael R., Chemistry Manager l

Nazar. M., Superintendent. Maintenance l

Painter. D., Valve Engineer '

Sample, M.. Manager. Steam Generator Maintenance Group l

Setzer, F.. Valve Engineer l

Snyder. J., Manager. Regulatory Compliance i

Thomas K., Superintendent. Work Control

Travis. B. , Manager, Mechanical / Nuclear Systems Engineering i

'

Tuckman. M.. Senior Vice President. Nuclear Duke Power Company

Welch. T., Engineering Supervisor

NRC l

S. Shaeffer. Senior Resident Inspector McGuire

M. Sykes. Resident Inspector. McGuire

P. Kellogg Regional Inspector l

W. Holland. Regional Inspector  !

l

Enclosure 2

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l

INSPECTION PROCEDURES USED

IP 71707: Coriduct of Operations  !

IP 40500: Self Assessment l

IP 92700: Miscellaneious Operations Issues l

IP 62703: Maintenance Observations l

IP 61726: Surveillance Observations 1

IP 37550: Engineering

IP 37551: Onsite Engineering

IP 92902: Miscellaneous Engineering Issues  !

IP 71750: Plant Support

IP 37550: Engineering Staff Knowledge and Performance

ITEMS OPENED. CLOSED, AND DISCUSSED

)

OPENED TITLE

1

URI 50-369/97-01-01 Root Cause of RCS Letdown Filter leak l

(paragraph 03.1)

IFI 50-369.370/97-01-02 FWST design basis (paragraph E2.1) l

l

VIO 50-369.370/97-01-03 Violation of 10 CFR 70.24 Requirements I

(paragraph R1.1)

CLOSED TITLE

VIO 50-369.370/96-02-02 Failure to Correct Long Term Deficiencies

Resulting in Valid Failures of EDGs

(paragraph E8.1)

LER 50-369/96-03 Inoperability of Both Unit 2 EDGs (paragraph

08.1)

DEV 50-369.370/96-07-04 Failure to Comply with Commitments in

Response to Generic Letter 88-03 Steam

Binding of Auxiliary Feedwater Pumps

(paragraph E8.2)

VIO 50-369.370/96-07-07 Failure to take Adequate Corrective Action

for EDG Fuel Line Failure and LER 50-369/96-

03 Rev 1 (paragraph E8.3)

Enclosure 2

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LIST OF ACRONYMS USED

AEB -

Auxiliary Electric Boiler

CA -

Auxiliary Feedwater System

>

CR -

Control Room

CRIP - Control Room Indicator Problem

DRP -

Division of Reactor Projects

ECCS - Emergency Core Cooling System

EDG -

Emergency Diesel Generator

FWST - Refueling Water Storage Tank

IFI -

Inspector Followup Item

IPB -

Isolated Phase Bus

LER -

Licensee Event Report  !

.

LOCA - Loss of Coolant i

MVAR - Mega Volts Amperes Reactive i

NCV -

Non-Cited Violation

NLO -

Non-licensed Operator

NRC -

Nuclear Regulatory Commission

NRR -

NRC Office of Nuclear Reactor Regulation

PDR -

Public Document Room

PIP -

Problem Investigation Process l

PMT -

Post Maintenance Test  :

I

PORC - Plant Operations Review Committee

RCCA - Rod Cluster Control Assembly

RCS -

Reactor Coolant System

RHR -

Residual Heat Removal

RTD -

Re.sistance Temperature Detector

SNM -

Special Nuclear Material

SRI -

Senior Resident Inspector

TI -

Tem 3orary Instruction

TS -

Tec1nical Specification

UFSAR - Updated Final Safety Anclysis Report

URI -

Unresolved Item

VIO -

Violation

WO -

Work Order

WR -

Work Request .

.

Enclosure 2

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