ML17059B940

Insp Repts 50-220/98-01 & 50-410/98-01 on 980104-0214. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML17059B940
Person / Time
Site:	Nine Mile Point
Issue date:	03/20/1998
From:	Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17059B938	List: ML17059B937 ML17059B939 ML17059B940
References
50-220-98-01, 50-220-98-1, 50-410-98-01, 50-410-98-1, NUDOCS 9803310055
Download: ML17059B940 (80)

See also: IR 05000220/1998001

Text

U.S. NUCLEAR REGULATORYCOMMISSION

REGION I

Docket/Report Nos.:

50-220/98-01

50-41 0/98-01

License Nos.:

DPR-63

NPF-69

Licensee:

Niagara Mohawk Power Corporation

P. O. Box 63

Lycomnin, NY 13093

Facility:

Nine Mile Point, Units

1 and 2

Location:

Scriba, New York

Dates:,

January 4- February 14, 1998

Inspectors:

B. S. Norris, Senior Resident Inspector

T. A. Beltz, Resident Inspector

R. A. Skokowski, Resident Inspector

Approved by:

Lawrence T. Doerflein, Chief

Projects Branch

1

Division of Reactor Projects

9803310055

980320

PDR

ADQCK 05000220

6

PDR

TABLEOF CONTENTS

page

TABLEOF CONTENTS

EXECUTIVE SUMMARY

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SUMMARYOF ACTIVITIES'........... ~.....

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Niagara Mohaw'k Power Corporation (NMPC) Activities

Nuclear Regulatory Commission (NRC) Staff Activities...

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Conduct of Operations ..................................

01.1

General Comments......,............,............

01.2

Initiation of a Unit 2 Plant Shutdown due to Inoperable Containm

Atmospheric Gaseous/Particulate

Radiation Monit'ors........

01.3

Identification of a Reactor Fuel Leak at Unit 2...........:.

01.4

Inadequate Shift Turnover for Unit 1 Rea'ctor Operator.......

02

Operational Status of Facilities and Equipment

02.1

Inadequate Separation Between Conduits for Safety-Related

Temperature Elements

02.2

Control of Catch Containments at Unit 1

02.3

Review of Unit 1 Extended Markup/Holdout Quarterly Report ..

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Miscellaneous Operations Issues ...........................

08.1

(Closed) LER 50-410/98-01: Entry'into TS 3.0.3 Due to Contain

Atmospheric Gaseous/Particulate

Radiation Monitors Inoperable

I I ~ MAINTENANCE

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Conduct of Maintenance ~.................

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M1.2

Replacement of Leaking Fuel Delivery Valve on a Unit 2 EDG

M2

Maintenance and Material Condition of Facilities and Equipment .....

M2.1

Unit 1 Liquid Poison System Surveillance Testing Deficiency

M8

Miscellaneous Maintenance Issues..........................

M8.1

Administrative Closure of Escalated Enforcement Items ......

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Conduct of Engineering ~... ~.......

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General Comments...................

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E2

Engineering Support of Facilities and Equipment

E2.1

Maintenance on Unit 1 Service Water Valve Violated Secondary

Containment Integrity............ ~...................

E2.2

Longstanding Holdout on Temperature Control Valve for Unit 1

Control Room Emergency Ventilation System

EB

Miscellaneous Engineering Issues.............................

E8.1

(Closed) LER 50-410/97-05-01:

High Pressure

Core Spray System

Inoperable Due to Failed,Unit Cooler

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Table of Contents (cont'd)

E8,2

E8.3

E8.4

E8.5

E8.6

E8.7

E8.8

E8.9

E8.10

(Closed) LER 50-220/97-10-01:TS

Required Shutdown Due to

Emergency Cooling Condenser Tube Leak

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(Closed) LER 50-410/97-13:

Prior to 1992, Emergency Switchgear

Not Seismically Qualified With Breakers Racked Out ..........

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(Closed) LER 50-410/97-16:

Missed TSSR 4.3.4.1.2 for ATWS-RPT

T'ip of LFMG .. ~.................. ~.............

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(Closed) VIO 50-220/96-07-03:

UFSAR Drawing Changed Without

Performing a 10 CFR 50,59 Safety Evaluation.............

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(Closed) 10 CFR 21 Notification: Potentially Defective Diesel

Generator Air Start Solenoid Valves... ~....

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(Opened) 10 CFR 21 Notification: Potentially Defective GE SBM-Type

Switches Unit 1

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(Closed) URI 50-220/96-05-03:

Lack of 10CFR50.59 Safety

Evaluation for the Modification to Restore the Unit 1 Blowout Panels

to Compliance with UFSAR................

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(Closed) Unit 2 Special Report:

Division I Standby EDG Non-valid

Test and Non-valid Failure..........

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Administrative Closure of Escalated Enforcement Items ........ 25

IV. PLANT SUPPORT

R1

Radiological Protection and Chemistry, Controls

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R1.1

Potentially Contaminated Truck Released from Unit 1.....,

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Miscellaneous RPRC Issues.............................

R8.1

Administrative Closure of Escalated Enforcement Items ...

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Status of Fire Protection Facilities and Equipment

F2.1

Unit 1 Unplanned Fire Alarms and Preaction Sprinkler System

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V. MANAGEMENTMEETINGS

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Exit Meeting Summary ................................

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ATTACHMENT

ATTACHMENT1 -

Partial List of Persons Contacted

Inspection Procedures

Used

Items Opened, Closed, and Updated

List of Acronyms Used

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EXECUTIVE SUMMARY

Nine lVlile Point Units 1 and 2

50-220/98-01 5. 50-41 0/98-01

January 4 - February 14, 1998

This NRC inspection report includes reviews of licensee activities in the functional areas of

operations, engineering, maintenance,

and plant support.

The report covers a six-week

period of inspections and reviews by the resident staff.

PLANT OPERATIONS

Unit 2 operators responded appropriately to the failure of the Division II containment

atmosphere

gaseous/particulate

radiation monitor that occurred while the Division I monitor

was inoperable for maintenance.

Station Operations Review Committee members

maintained the proper safety focus during the meeting to discuss the basis for requesting

enforcement discretion.

Routine monitoring of the Unit 2 fuel reliability index allowed NMPC to identify a reactor

'uel

leak early, before it degraded any further. The flux tilting and power suppression

evolution was methodical and well-controlled due, in part, to good communication and

coordination among all involved organizations.

NMPC took aggressive actions to prevent

further leak degradation.

During an inspection in the Unit 2 residual heat removal pump rooms, the inspectors

identified inadequate

separation between conduits for safety-related temperature elements

of different divisions.

(NCV) A breakdown in communications between an Assistant

Station Shift Supervisor and a system engineer resulted in a one week delay in recognizing

the impact that inadequate conduit separation

had on the operability of safety-related plant

equipment.

Most catch containments installed in Unit 1 were adequately installed and maintained.

However, many designated

as "permanent" did not have an engineering evaluation to

determine if a plant change or modification was required.

(NCV) The most recent semi-

annual catch containment review lacked depth, in that NMPC failed to fully evaluate

whether catch containments should be removed or that those designated

as "permanent"

had the required engineering evaluation.

The quarterly reviews of extended markups at Unit 1 were weak in that the reviewers

failed to identify numerous markup discrepancies that were later identified by the

inspectors.

Unit 1 management was aware of the weaknesses,

and proposed corrective

actions appeared

appropriate.

MAINTENANCE

NMPC appropriately evaluated the impact of a leaking fuel delivery valve on the operability

of the Unit 2 emergency diesel generator.

0

Executive Summary (cont'd)

Based upon the NRC inspectors'uestions,

NMPC management

declared the Unit 1 liquid

poison system inoperable.

Portions of the system piping had not been periodically flow

tested and NMPC was unable to readily ascertain whether the piping'from the liquid poison

tank to the pump suction valves was obstructed.

NMPC's decision to declare the liquid

poison system inoperable and commence

a shutdown was conservative,

and the actions

taken to test the system were appropriate. The special evolution brief was thorough.

Although the pievious Unit 1 liquid poison system surveillance testing met technical

specification requirements, the testing was inadequate to verify system operability.

(VIO)

ENGINEERING

As a result of a good questioning attitude by a system engineer, NMPC identified that

maintenance

on the Unit 1 service water drag valve in the reactor building violated

secondary containment integrity. Past maintenance

on the valve exceeded the allowable

limiting condition for operation outage time, and a reactor shutdown had not been initiated

in accordance with the technical specification requirements.

(NCV) The inspectors

identified that NMPC failed to perform a design change for permanently installed

scaffolding.

(NCV)

The inspectors identified that the temperature control valve for the Unit 1 control room

emergency ventilation system had been inoperable since 1983. The administrative controls

to disposition the failed valve had not been properly implemented; i.e., the controlled

drawings did not indicate the inoperable valve, nor was an engineering evaluation

performed, as required by procedures, to determine if continued operation with the

degraded condition was acceptable.

(VIO)

Prior to April 30, 1992, Unit 2 operated with circuit breakers in the racked out position,

and failed to recognize the adverse impact on switchgear seismic qualification and,

therefore, switchgear operability.

(NCV) Although NMPC took appropriate actions in 1992

to preclude future operations with breakers in the racked out position, they failed to

recognize that they were in an unanalyzed, condition, and that the condition was

reportable.

(NCV)

NMPC identified that a portion of the Unit 2 testing for the recirculation pump trip in

response to an anticipated transient without scram was not completed in accordance with

the technical specifications.

(NCV) Specifically, the logic system functional testing failed

to include the high reactor pressure trip of the low frequency motor generator.

In addition,

the failure to specify an acceptability range for the low frequency motor generator time

delay in the subsequent

procedure change procedure indicated weaknesses

in the

procedure and in the review of the associated

procedure change.

Furthermore, in

December 1996, NMPC missed an opportunity to identify the inadequate

surveillance test

due to a non-conservative interpretation of the Updated Final Safety Analysis Report.

The licensee's actions at both units to address

an industry concern with potentially

defective emergency diesel generator air start solenoid valves was timely and technically

sound.

1

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Executive Summary (cont'd)

NMPC responded quickly and appropriately to a vendor notification related to a possible

failure of spring-return switch'es used in the emergency cooling and containment spray

systems at Unit 1

~ Control room operators were aware of the potential failure mode;

however, the associated

operating procedures

had not been revised to include a

precautionary note related to the concern.

PLANT SUPPORT

Control room and fire brigade personnel appropriately responded to numerous Unit 1 fire

alarm actuations,

and the investigation effort appeared

adequately coordinated.

The failure

to fully investigate and resolve previous similar false fire protection system actuations was

a weakness

and likely contributed to the recent event.

Although Unit 1 fire suppression

system operability did not appear to be affected by degraded components, the impact of

the deficiencies could hinder plant personnel responding to an in-plant fire due to potential

multiple false alarms.

REPORT DETAILS

Nine Mile Point Units 1 and 2

50-220/98-01

8L 50-41 0/98-01

January 4 - February 14, 1998

SUMMARYOF ACTIVITIES

Niagara Mohawk Power Corporation (NMPC) Activities

Unit 1

Nine Mile Point Unit 1 (Unit 1) started the inspection period at full power.

On the morning

of January 21, 1998, the licensee commenced

a unit shutdown due to the liquid poison

system being inoperable (Section M2.1 of this report).

Reactor power was reduced to

approximately 70% when the operability of the liquid poison system was confirmed; full

power was achieved later that day.

The unit remained at full power throughout the

remainder of the inspection period.

Unit 2

Nine Mile Point Unit 2 (Unit 2) started the inspection period at 95% power, limited to 95%

due to the moisture separator reheaters

being removed from service.

On January 7, 1998,

the licensee commenced

a unit shutdown due to both drywell radiation monitors being out-

of-service (Section 01.2 of this report); reactor power was lowered to approximately 50%.

During the power reduction, NMPC requested,

and was granted, enforcement discretion by

the NRC. The unit was returned to 95% power on January 8.

On January 24, reactor

power was again reduced to approximately 50% to identify the source of a potential fuel

leak (Section 01.3 of this report).

The unit was returned to 95% on January 30.

On

February 14, reactor power was lowered to approximately 81% to perform a rod pattern

adjustment, and this power level was maintained through the remainder of the inspection

period.

Mana ement Reor anization

On January 23, 1998, Mr. John H. Mueller assumed the position of Senior Vice President

and Chief Nuclear Officer of NMPC. Mr. Mueller succeeded

Mr. B. Ralph Sylvia.

Nuclear Regulatory Commission (NRC) Staff Activities

Ins ection Activities

The NRC resident inspectors conducted inspection activities during normal, backshift, and

deep backshift hours.

The results of the inspection activities are contained in the

applicable sections of this report.

U dated Final Safet

Anal sis Re ort Reviews

While performing the inspections discussed

in this report, the inspectors reviewed the

applicable portions of the Updated Final Safety Analysis Report (UFSAR) related to the

0

areas inspected.

The inspectors verified that the UFSAR wording was consistent with the

observed plant practices, procedures

and/or parameters.

Exceptions noted were:

(1) the

conduit for safety-related residual heat removal temperature elements of different electrical

divisions were in contact, although the Unit 2 UFSAR specifies a minimum conduit-to-

conduit physical separation of ~/z-inch (Section 02.1 of this report); and (2) the logic

sy'tem functional testing of the anticipated transient without scram-recirculation pump trip

of the low frequency motor generator on high pressure

had not been performed due to a

non-conservative interpretation of the Unit 2 UFSAR (Section E8.3 of this report).

I. OPERATIONS

01

Conduct of Operations (71707)

'1

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General Comments

Using NRC Inspection Procedure 71707, the resident inspectors conducted frequent

reviews of ongoing plant operations to verify that the units were operated safely:

and in accordance with licensee procedures

and regulatory requirements.

The

reviews included tours of both accessible

and normally inaccessible

areas of both

units, verification of engineered

safeguards features

(ESF) system operability,

verification of adequate control room and shift staffing, verification that the units

were operated in conformance with technical specifications, and verification that

logs and records accurately identified equipment status or deficiencies.

In general,

the conduct of operations was professional and safety-conscious;

specific events

and noteworthy observations

are detailed in the sections below.

01.2

Initiation of a Unit 2 Plant Shutdown due to Ino erable Containment Atmos heric

Gaseous

Particulate Radiation Monitors

a.

Ins ection Sco

e

The inspectors assessed

NMPC's performance in response to a failure of the.

Division II containment atmosphere gaseous/particulate

radiation monitor concurrent

with the Division I monitor being inoperable for preplanned maintenance.

The

inspectors observed Unit 2 control room troubleshooting activities and initiation of

the reactor shutdown,

The inspectors reviewed the Station Shift Supervisor's

(SSS)

logs, applicable procedures,

and technical specifications (TS), and discussed

related

issues with on-duty operators, technicians,

and management.

In addition,

discussions were held with NRC management

and technical staff members from the

Region

I Office and the Office of Nuclear Reactor Regulations (NRR) with regard to

enforcement discretion.

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Topical headings such as 01, MB, etc., are used in accordance with the NRC standardized reactor inspection report outline.

Individual reports are not expected to address all outline topics.

The NRC inspection manual procedure or temporary instruction

(Tl) that was used as inspection guidance is listed for each applicable report section.

Observations

and Findin s

On January 7, 1998, at 4:41 a.m., Unit 2 experienced

a failure of the Division II

containment atmosphere gaseous/particulate

radiation monitor (2CMS"CAB10B).

At the same time, the redundant Division I radiation monitor (2CMS"CAB10A) was

out-of-service for maintenance to replace

a portion of the heat trace circuitry. With

both divisions of containment radiation monitoring inoperable, the Unit 2 operators

entered TS 3.0.3, which required actions be initiated within one hour to shutdown

the reactor, and to place the mode switch in STARTup within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. At

5:35 a.m., the operators commenced

a reactor shutdown.

Attempts to return 2CMS"CAB10Ato service were unsuccessful.

The licensee's

initial troubleshooting determined that both divisions of containment radiation

monitoring failed due to moisture intrusion.

NMPC determined that they would not

be able to return the monitors to an operable status within the 6-hours allowed by

TS before having to complete the reactor shutdown.

Therefore, NMPC notified the

NRC and requested enforcement discretion to delay the shutdown during restoration

of the equipment, and avoid an unnecessary

plant shutdown.

NMPC continued to

reduce reactor power and, at 11:23 a.m., with the reactor at 50% power, Region

I

verbally granted enforcement discretion from the TS requirements until 9:00 a.m. on

January 8, 1998. The enforcement discretion was granted provided that during the

discretionary period:

(1) drywell atmospheric grab samples would be taken and

analyzed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and (2) primary containment floor and equipment drain

leakage detection systems would be monitored every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

Subsequently,

on

January 9, 1998, a written Notice of Enforcement Discretion (NOED) was issued.

Further licensee troubleshooting determined that 2CMS"CAB10B(Division II) failed

due to a defective flow control transducer board, and not due to moisture-intrusion.

The board was replaced, and the monitor was calibrated and returned to service on

January 7, 1998, at 6:20 p.m.

Restoration of the Division II monitor allowed

NMPC'o

exit the TS shutdown actions and eliminated the continued need for NRC

enforcement discretion.

2CMS "CAB10Awas returned to an operable status on

January 9, 1998.

The inspectors observed control room activities shortly after Unit 2 operators

identified that 2CMS "CAB10B had failed. The operators'ctions

were consistent

with the licensee's procedures

and TSs,

Troubleshooting and repair activities were

methodical.

The inspectors observed the Unit 2 Station Operating Review

Committee (SORC) meeting that discussed the basis for requesting enforcement

discretion and noted that the SORC members maintained the proper safety focus

throughout the meeting.

In addition, during the period enforcement discretion was

granted, the inspectors verified that the drywell atmospheric grab samples were

taken and analyzed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and that the primary containment floor and

equipment drain leakage detection system were monitored every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

Conclusion

Unit 2 operators responded appropriately to the failure of the Division II containment

atmosphere

gaseous/particulate

radiation monitor that occurred while the Division I

monitor was inoperable for maintenance.

SORC members maintained the proper

safety focus during the meeting to discuss the basis for requesting-enforcement

discretion.

Identification of a Reactor Fuel Leak at Unit 2

Ins ection Sco

e

The inspectors assessed

NMPC's identification of a reactor fuel leak at Unit 2, and

subsequent

actions to address the leak.

The inspectors reviewed plant operating

data, licensee procedures,

and other related documentation, including the Unit 2

UFSAR. The inspectors observed portions of the flux tilting and power suppression

evolution. Additionally, the inspectors discussed the issue with the Unit 2 Plant

Manager and Operations Manager, and members of the reactor engineering and

radiation monitor calibration groups.

Observations

and Findin s

On January 16, 1998, NMPC concluded that a reactor fuel leak had developed at

Unit 2. This was based on a small increase in the fuel reliability index (FRI). The

FRI is an analysis of xenon isotopes present in offgas samples,

and is used to

provide indication of fuel failure. The FRI is performed weekly at both units.

The

FRI on January 10, 1998, was 75 microcuries per second (pCI/sec), which was a

significant increase over the previous readings that ranged between 10 and

20 pCI/sec.

However, offgas activity remained relatively steady.

NMPC discussed

the indications with General Electric (GE) and, on January 16, concluded that a

small fuel leak existed and had probably developed late in December 1997.

Based on the increase

in FRI, NMPC initiated the "Level 1" actions, as described in

Procedure

FRG-1, "Fuel Reliability Guidelines."

The initiation of Level

1 actions

was conservative since FRG-1 defines a Level

1 condition as a FRI greater than

100 pCI/sec above the cycle baseline.

Plans were developed to locate the fuel

leak(s) and to suppress the power in the vicinityof the leak(s).

During the interim,

control rod movement at Unit 2 was minimized to avoid aggravating the leak.

To facilitate locating the leaking fuel, NMPC connected

a continuous on-line isotopic

monitor. The isotopic monitor alleviated the need to obtain and analyze chemistry

samples, therefore minimizing the time between control rod manipulations.

The on-

line isotopic monitoring equipment required changes to the Unit 2 UFSAR sections

associated with the plant radiation monitors.

The changes were reviewed in

accordance with Title 10 of the Code of Federal Regulations, Part 50.59 (10 CFR 50.59)

~ Additionally, NMPC Procedure. N2-REP-31, "Power Suppression Testing,"

was revised to incorporate the use of the on-line isotopic monitoring,equipment.

0

The inspectors reviewed these changes,

including the 10 CFR 50,59 safety

evaluation, and found them acceptable.

On January 23, Unit 2 operators commenced

a down power to 55% and began

power suppression testing in accordance with Procedure N2-REP-31.

The purpose

of the test was to identify the location of the fuel leaks by varying power through

control rod movement and observing offgas radiation changes.

NMPC considered

this test a special evolution, as defined in Procedure GAP-SAT-03, "Control of

Special Evolutions." The inspectors ob'served that appropriate management

oversight was present during the test.

The inspectors also observed that the test

was conducted

in a methodical manner and was well-controlled due, in part, to

good communication and coordination among all involved organizations.

The testing was completed on January 27, and data indicated that only one location

within the core had fuel rod leakage.

The suspected

location was between control rods 18-27, 14-27 and 14-23, with the greatest indications near control rod 18-27.

Following the testing, these three control rods were left completely inserted to

suppress the power in the location of the fuel leak.

Subsequently,

reactor power

was slowly returned to full power (95%), so as not to further aggravate the fuel

leak.

The next weekly FRI was within the normal 10 to 20yCi/sec range, indicating

that the power suppression was successful.

Historically, BWRs are normally operated with a symmetric control rod pattern.

This

was necessary to determine reactor core thermal power, since the computer

program used core mirror imaging in the calculations.

However, operating with

three adjacent control rods inserted to suppress the fuel leak resulted in an

asymmetric control rod pattern.

Unit 2 had previously updated their three

dimensional reactor core monitoring (3D Monicore) computer program to the

"Baseline 94" version.

This allowed the 3D Monicore program to automatically

account for asymmetric rod patterns.

The inspectors discussed the unusual rod

pattern with Unit 2 reactor engineering personnel and reviewed supporting

documentation from GE, and no concerns were identified.

Conclusion

Routine monitoring of the Unit 2 fuel reliability index allowed NMPC to identify a

reactor fuel leak early, before it degraded

an'y further. The flux tilting and power

suppression

evolution was methodical and well-controlled due, in part, to good

communication and coordination among all involved organizations.

NMPC took

aggressive actions to prevent further leak degradation.

Inade

uate Shift Turnover for Unit 1 Reactor 0 erator

During a tour of the Unit 1 control room soon after shift turnover, chief station

operator (CSO), a licensed reactor operator (RO), was questioned by the inspectors

as to the status of 4122 emergency cooling (EC) condenser radiation monitor,

which was inoperable due to a failed surveillance test.

The CSO had not been

informed by the off-going CSO during the shift turnover that the monitor was

r

inoperable.

The inspectors discussed this'weakness with the SSS and the Unit 1

Operations Manager.

Both concurred with the inspectors conclusion that the shift

turnover by the off-going CSO was weak.

02

Operational Status of Facilities and Equipment (71707)

02.1

Inade

uate Se

aration Between Conduits for Safet -Related Tem erature Elements

a 0

Ins ection Sco

e

During a visual inspection of equipment within the Unit 2 residual heat removal

(RHR) pump rooms, the inspectors questioned the physical separation between

conduits for safety-related temperature elements of different electrical divisions.

The inspectors assessed

the licensee's

actions to correct the condition, and

reviewed the applicable sections of the UFSAR and associated

plant drawings.

b.

Observations

and Findin s

On January 30, 1998, the inspectors identified that the conduit for temperature

element

2RHS "TE49Awas touching the conduit for temperature element

2RHS "TE49B. These temperature elements are powered from Division I and

Division II, respectively, and provided containment isolation signals for shutdown

cooling valves (Group 5) and reactor core isolation cooling (RCIC) steam supply

valves (Group 10). The inspectors were concerned that a fault in one division could

potentially impact the other division due to the inadequate separation.

This concern

was discussed with the on-watch Assistant Station Shift Supervisor (ASSS).

The initial response was that the Unit 2 system engineers concluded no problem

existed.

The inspectors questioned the basis for this conclusion, and learned that

there was a breakdown in communications between the ASSS and th'e system

engineers.

Specifically, the system engineers understood the problem to be with

the temperature elements and not with the conduit.

On February 6, the system

engineering staff identified the location where the conduits were touching and

informed the control room. The on-watch operators declared the two temperature

elements inoperable, and took the actions required by the TS.

In addition, NMPC

notified the NRC in accordance with 10 CFR 50.72. Work order (WO) 98-01546-00

was generated

and proper separation was established.

The inspectors reviewed the applicable plant drawings with members of the system

engineer staff and determined that a fault impacting both divisions would be no

worse than a fault impacting only one division. This was because:

(1) each

temperature element provided a signal to both containment isolation groups (Groups

5 and 10);

(2) the containment isolation system logic only required one signal for

actuation; and (3) the containment isolation system logic was designed

as fail safe.

The Unit 2 UFSAR, Section 8.3.1.4.2,,"Physical Separation," specified a minimum

conduit-to-conduit separation of ~/~-inch. The failure to maintain the Unit 2 plant

configuration in accordance with the specification provided within the UFSAR is a

violation of 10 CFR 50 Appendix B, "Quality Assurance Criteria for Nuclear Power

Plants and Fuel Reprocessing

Plants," Criterion III, "Design Control." This failure

constitutes

a violation of minor significance and is being treated as a Non-Cited

Violation (NCV), consistent with Section IV of the NRC Enforcement Policy.

(NCV 50-410/98-01-01)

C.

Conclusion

During an inspection in the Unit 2 residual heat removal pump rooms, the inspectors

identified inadequate separation between conduits for safety-related temperature

elements of different divisions.

(NCV) A breakdown in communications between

an Assistant Station Shift Supervisor and a system engineer resulted in a one week

delay in recognizing the impact that inadequate conduit separation

had on the

operability of safety-related plant equipment.

02.2

Control of Catch Containments at Unit 1

a 0

Ins ection Sco

e

The inspectors reviewed the catch containment tracking log maintained in the Unit 1

control room and performed a random sampling of catch containments installed in

the plant to assess

the adequacy of administrative controls for catch containment

installation and removal.

Issues were subsequently discussed with operations

personnel.

b.

Observations

and Findin s

During routine plant walkdowns of the Unit 1 reactor and turbine buildings, the

inspectors examined installed catch containments.

A catch containment is a device

installed below plant equipment to divert or contain water typically resulting from

component leakage or condensation.

The inspectors observed that, generally, catch

containments were adequately installed and maintained in accordance with NMPC

Procedure GAP-OPS-04, "Control of Catch Containments."

The inspectors reviewed the catch containment tracking log maintained in the Unit 1

control room and identified that the log accurately reflected the catch containments

installed in the plant. The inspectors observed that many of the catch containments

in the log were greater than five years old; approximately one-half of the current

fifty-fourcatch containments were installed between 1990 and 1993. These older

catch containments were installed either to collect condensation

or were awaiting

disposition as a "permanent" plant change.

GAP-OPS-04, Section 3.1.4, required that a catch containment designated

as

"permanent" be assessed

by system engineering to determine if a plant change was

desired and to initiate a modification as required.

The procedure required a

determination as to the continued need for each catch containment.

The inspectors

identified that many of the catch containments designated

as "permanent" did not

have documented engineering evaluations performed to determine if a plant change

0

or modification was required.

This failure to perform an engineering evaluation as

required by GAP-OPS-04 constitutes

a violation of minor significance and is being

treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement

Policy.

(NCV 50-220/98-01-02)

The inspectors identified that the required semi-annual catch containment review

had last been performed in October 1997. The inspectors considered the review to

lack sufficient depth, in that the licensee failed to fully evaluate whether catch

containments should be removed or that those catch containments designated

as

"permanent" had the required engineering evaluation performed.

Operations staff

acknowledged that catch containments were not being effectively removed or

adequately evaluated for permanent installation.

A Deviation/Event Report (DER

1-98-0078) was issued to address this concern, and the licensee performed a

detailed catch containment review. The Unit 1 Operations Manager directed that

the catch containment tracking log be updated and modified to ensure better

personnel responsibility and accountability for each log entry, and to provide

sufficient information for determining the status of engineering evaluations.

Subsequently,

approximately twenty-two catch containments were removed from

the reactor and turbine buildings.

Conclusions

Most catch containments installed in Unit 1 were adequately installed and

maintained.

However, many designated

as "permanent" did not have

an'ngineering

evaluation to determine if a plant change or modification was required.

(NCV) The most recent semi-annual catch containme'nt review, lacked depth, in that

NMPC failed to fully evaluate whether catch containments should be removed or

that those designated

as "permanent" had the required engineering evaluation.

Review of Unit 1 Extended Marku

Holdout Quarterl

Re ort

Ins ection Sco

e

The inspectors reviewed the Unit 1 extended markup/control tag/holdout quarterly

audit report and discussed findings with the Shift Technical Advisor (STA);

Observations

and Findin s

The inspectors reviewed the Unit 1 quarterly audit report of extended markups,

control tags, and holdouts.

The quarterly audit was used to determine the

continued need and applicability of each current markup on file and to ensure that

discrepancies

are documented.

Unit 1 Procedure N1-PM-Q2, "Periodic Review of

Hazardous Energy and Configuration Tagging System," provided the administrative

controls for completing the quarterly audit, which was last completed on

January 15, 1998.

/

The inspectors discussed the results with the STA, who was responsible for

coordinating the review and maintaining the quarterly audit report.

The inspectors

~

~

e

noted many weaknesses

in the maintenance of the audit report, such as:

(1) the

associated

work documents were not current, (2) the individual responsible for

completing the required work was either not listed or the name was not current, and

(3) the expected work completion date was either incomplete or indeterminate.

The

Unit 1 Plant Manager informed the inspectors that most equipment with

longstanding unavailability was not receiving engineering reviews or Plant Manager

concurrences,

as required by NMPC Procedure NIP-ECA-01, "Deviation/Event

Report." A specific example of this is a longstanding holdout on the control room

emergency ventilation system, as discussed

in Section E2.2 of this inspection

report.

I

The inspectors discussed the program implementation weaknesses

with the Unit 1

Operations Manager.

The Operations Manager was aware of the weaknesses,

which also included the administrative tracking of control room deficiencies,

operator work-arounds, and catch containments

(previously discussed

in Section

02.2). The Operations Manager issued an internal memorandum to Unit 1

management

and Operations department supervisors that delegated the

responsibility for tracking these issues to the STAs. Also, a meeting was held to

discuss past programmatic weaknesses

in tracking of longstanding holdouts.

A

draft revision to the quarterly audit report was presented

at this meeting, and

included a tracking mechanism for ensuring applicability reviews and safety

evaluations were completed.

The inspectors considered these changes to be

appropriate.

C.

Conclusions

The quarterly reviews of extended markups at Unit 1 were weak in that the

reviewers failed to identify numerous markup discrepancies that were later identified

'by the inspectors.

Unit 1 management was aware of the weaknesses,

and

proposed corrective actions appeared. appropriate.

08

Miscellaneous Operations Issues

(92901)

08.1

Closed

LER 50-410 98-01: Entr

into TS 3.0.3 Due to Containment Atmos heric

Gaseous

Particulate Radiation Monitors Ino erable

The technical issues associated with this licensee event report (LER) were described

in Section 01.2 of this inspection report.

The inspectors verified that the LER was

completed in accordance with the requirements of 10 CFR 50.73.

Specifically, the

description and analysis of the event, as contained in the LER, were consistent with

the inspectors'nderstanding

of the event.

The root cause, and corrective and

preventive actions as described in the LER were reasonable.

This LER is closed.

10

II. MAINTENANCE

M1

Conduct of Maintenance (61726, 62707)

M1

~ 1

General Comments

Using NRC Inspection Procedures

61726 and 62707, the resident inspectors

periodically observed plant maintenance activities and the performance of various

surveillance tests.

As part of the obseivations, the inspectors evaluated the

activities with respect to the requirements of the Maintenance

Rule, as detailed in

Title 10 of the Code of Federal Regulations, Part 50.65 (10 CFR 50.65).

In general,

maintenance

and surveillance activities were conducted professionally, with the

work orders (WOs) and necessary

procedures

in use at the work site, and witlithe

appropriate focus on safety.

Specific activities and noteworthy observations

are

detailed in the inspection report.

The inspectors reviewed procedures

and observed

all or portions of the following maintenance/surveillance

activities:

~

WO 94-101-01

TCV 210.1-56 to be Retired in Place

~

WO 98-00279-00

Repair Leaky Delivery Valve on Division I EDG

~

WO 98-509-02

~

N1-MMP-072-247

Clean Reactor Building

Service Water Temperature Control Valve TCV-72-146

(RBCLC) and TCV-72-147 (TBCLC) Maintenance

~

N1-MAP-MAI-0301

Scaffold Control

~

N2-OSP-ENS-M001

4.16 kV Emergency Bus Under and Degraded Voltage

Functional Test

~

N2-ISP-RDS-Q106

Quarterly Functional/Calibration of Control Rod Block

Scram Discharge Volume High Water Level Instrument

Channel

~

N2-ISP-CMS-M@001

Suppression

Pool Water Temperature Calibration

M1.2

Re lacement of Leakin

Fuel Deliver

Valve on a Unit 2 EDG

a.

Ins ection Sco

e

The inspectors observed the Unit 2 maintenance activities associated with the

replacement of a leaking fuel delivery valve on the one emergency diesel generator

2 Surveillance activities are included under

Maintenance."

For example, a section involving surveillance observations might

be inciuded as a separate sub-topic under Ml, "Conduct of Maintenance."

0

11

(EDG). Additionally, the inspectors reviewed the applicable WO and discussed

related issues with the SSS, system engineer, and maintenance

supervisor.

b.

Observations

and Findin s

On January 6, 1998, Unit 2 operators declared the Division I EDG inoperable for

pre-planned maintenance.

TS 3.8.1.1 allows the Division I EDG to be inoperable

provided that it is restored to operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; otherwise, the plant is to be

in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Due to unforeseen events,

including an unexpected trip of the EDG due to a failed optical isolator transmitter

board (see Section E8.9), the maintenance

activities were not completed until the

morning of January 9.

During the post-maintenance

surveillance test of the EDG,

one of the fuel delivery valves developed

a leak. Although the surveillance test was

considered satisfactory, the SSS decided that the EDG would remain inoperable

until the valve was replaced and tested.

This decision was made about the same

time the 72-hour portion of the TS limiting condition for operation (LCO) expired.

NMPC determined that no immediate actions would be necessary to shutdown the

reactor, since the time to replace and test the valve was expected to be short.

The inspectors observed the valve replacement.

The activity was completed in

accordance with WO 98-00279-00.

Proper Quality Assurance

(QA) and

management

oversight were noted during the activity. Upon completion of a

satisfactory post-maintenance

test, the SSS declared the EDG operable and exited

the LCO action statement.

The Unit 2 EDG system engineer informed the inspectors that cracking of fuel

delivery valves was an industry concern, initiallyidentified in May 1996. As a

result, NMPC initiated DER 2-96-1275 to evaluate the consequences

of delivery

valve failures and determined there was no adverse impact on EDG operability.

NMPC had planned to replace all the suspect valves in October 1996, but the

valves of newer design were not available for installation.

Since then, NMPC has

received the new valves, and plans to install them during the next refueling outage.

The inspectors reviewed DER 2-96-1275 and the associated

engineering supporting

analysis (ESA), which justified EDG operability with the suspect valves, and the

inspectors considered the licensee's actions to be acceptable.

C.

Conclusion

NMPC appropriately evaluated the impact of a leaking fuel delivery valve on the

operability of the Unit 2 emergency diesel generator.

0

12

M2

Maintenance and Material Condition of Facilities and Equipment (61726)

M2.1

Unit 1 Li uid Poison S stem Surveillance Testin

Deficienc

Ins ection Sco

e

NMPC initiated a normal reactor shutdown of Unit I based on the liquid poison

system being declared inoperable due to a section of piping not being previously

tested.

The inspectors discussed the issue with the Unit 1 Operations Manager and

the system engineer, and reviewed the event notification.

b.

Observations

and Findin s

In the summer of 1997, the inspectors had monitored a monthly surveillance test of

the Unit 1 liquid poison system.

The inspectors, through discussions with operators

and the inservice testing (IST) supervisor, identified that all current liquid poison

system surveillance tests were performed with the liquid poison pumps taking a

suction from a test tank filled with demineralized water.

This system configuration

maintained the pump suction valves closed, and isolated the section of piping from

the liquid poison tank to the pump suction valves.

The inspectors questioned the

IST supervisor as to whether the liquid poison system had been periodically tested

to confirm adequate flow through this piping. The supervisor was unable to

determine whether that section of piping had ever been previously tested.

NMPC initiallydid not question system operability. This determination was based

upon the current surveillance testing meeting the requirements

in the TSs and

UFSAR, that the system design included tank heaters

and temperature indicators,

and that the piping under concern was insulated and heat-traced.

However, the IST

supervisor informed the inspectors that Unit 2 TSs required periodic flow verification

through the section of piping from the liquid poison tank to the pumps, at least

every eighteen months, to ensure the system was unobstructed.

The IST

supervisor also contacted other nuclear facilities to determine if this section of

piping was periodically tested throughout the industry.

Based upon this further

information from these facilities, the IST supervisor informed the inspectors that a

procedure would be developed to periodically take suction from the liquid poison

tank, and that the procedure would most likely be conducted during the next

refueling outage.

In January 1998, the inspectors queried Unit 1 staff as to the status of the

proposed liquid poison system surveillance test procedure.

The inspectors question

received a higher level of NMPC management attention.

After subsequent

management

review, NMPC concluded that the ability to readily ascertain whether

the piping from the liquid poison tank to the pump suction valves was unobstructed

was in question, and the system was declared inoperable on January 21, at

7:35 a.m.

The licensee commenced a,normal orderly shutdown within one hour of

declaring the system inoperable, as required by Unit 1 TS 3.1.2.e.

The inspectors

considered the licensee's decision to declare the liquid poison system inoperable

13

and commence

a shutdown to be conservative,

and the actions to test the system

to be appropriate.

In parallel with the shutdown, the licensee developed and approved

a surveillance

test to verify system flow when taking suction from the liquid poison tank.

The

inspectors observed the special evolution brief conducted prior to performing the

test.

The senior manager and the principal test engineer for the brief were the

Unit 1 Operations Manager and an off-shift Senior Reactor Operator, respectively.

The inspectors considered the special evolution brief to be thorough, in that it

detailed the purpose of the test and emphasized

procedural adherence,

communications,

and abort criteria.

The inspectors monitored the special evolution

locally in the reactor building, and determined that NMPC personnel performed the

test adequately.

The test results confirmed that no obstruction existed, and that

the liquid poison system could establish adequate flow when taking suction from

the liquid poison tank.'he test results received

a timely and adequate

supervisory

review and the liquid poison system was declared operable at 2:30 p.m. The

shutdown was discontinued and power ascension

commenced, with full power

achieved at 4:35 p.m.

The Operations Manager informed the inspectors that routine performance of this

test would occur on a cyclic basis.

The inspectors agreed with NMPC that the

testing requirements for the liquid poison system, as discussed

in Unit 1 TSs and

the UFSAR, had been met.

However, the lack of a questioning attitude to routinely

demonstrate that the entire liquid poison system was capable of performing the

required function was considered

a weakness.

The failure to periodically verify that

the liquid poison system was operable from the liquid poison tank to the pump

suction valves is a violation of 10 CFR 50, Appendix 8, Criterion XI, "Test Control,"

which requires that a test program be established to assure that all testing required

to demonstrate

a system willperform satisfactorily in service is identified and

performed in accordance with written procedures.

(VIO 50-220/98-01-03)

Conclusions

Based upon inspectors questions,

NMPC management declared the Unit 1 liquid

poison system inoperable.

Portions of the system piping had not been periodically

flow tested and NMPC was unable to readily ascertain whether the piping from the

liquid poison tank to the pump suction valves was obstructed.

NMPC's decision to

declare the liquid poison system inoperable and commence

a shutdown was

conservative,

and the actions taken to test the system. were appropriate. The

special evolution brief was thorough.

Although the previous Unit 1 liquid poison

system surveillance testing met technical specification requirements, the testing

was inadequate to verify system operability.

(VIO)

M8

Miscellaneous Maintenance Issues (92700, 92902)

M8.1

Administrative Closure of Escalated Enforcement Items

The escalated

enforcement items (EEls) listed below are being administratively

closed, due to the issuance of the indicated enforcement action (EA) letter and

associated

determination.

EEI 50-220/96-12-01:

EEI 50-220/96-12-05:

EEI 50-220/96-1 2-06:

EEI 50-220/96-12-07:

closed by EA 97-007, VIO 1013

closed by EA 97-007, VIO 1023

closed by EA 97-007, withdrawn

closed by EA 97-007, withdrawn

III. ENGINEERING

E1

Conduct of Engineering (37551)

E1.1

General Comments

Using NRC Inspection Procedure 37551, the resident inspectors frequently reviewed

design and system engineering activities, including justifications for operability

determinations,

and the support by the engineering organizations to plant activities.

E2

Engineering Support of Facilities and Equipment

(37551)

E2.1

Maintenance on Unit 1 Service Water Valve Violated Secondar

Containment

~lnte rit

a.

Ins ection Sco

e

During preparation for maintenance

on a service water valve in the Unit 1 reactor

building, NMPC identified that the maintenance

had the potential to jeopardize

secondary containment integrity. The inspectors discussed the issue with the SSS

and the system engineer, reviewed the event notification and the revised WO, and

observed the rescheduled

maintenance activities on the service water valve.

b.

Observations

and Findin s

On January 27, 1998, during preparations for routine maintenance

on the Unit 1

reactor building service water drag valve (TCV-72-146), the system engineer for

the service water system questioned whether the planned maintena'nce

could

jeopardize secondary containment (reactor building) integrity. On January 29,

NMPC determined that the maintenance

did provide a possible pathway to violate

secondary containment, and placed the planned maintenance

on hold.

In addition,

because this evolution was routinely performed, most recently on December 11,

15

1997, an event notification to the NRC was initiated in accordance with 10 CFR 50.72.

F

The planned maintenance was the routine replacement of the internal strainer in the

drag valve; to perform this, the valve bonnet must be removed.

Since there is no

downstream valve,'the drag valve cannot be isolated.

Unit 1 TS, Section 3.4.1,,

limits the reactor building leakage rate to 1600 cubic feet per minute (cfm). If

service water was lost during the maintenance,

a pathway from the reactor building

to the outside atmosphere would exist,'xceeding the TS limitfor reactor building

leakage.

Previously, the maintenance was performed without entering the

associated

LCO. The LCO allowed four hours to return the leakage rate to within

allowable limits, or initiate a shutdown and be in cold shutdown within the next ten

hours.

Normally, the valve bonnet was removed for greater than four hours, thus

exceeding the allowable LCO time frame.

The failure to initiate an orderly shutdown

after the bonnet was removed for greater than four hours was a violation of the

Unit 1 TS, Section 3 4.1. This non-repetitive, licensee identified and corrected

violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1

of the NRC Enforcement Policy.

(NCV 50-220/98-01-04)

The inspectors reviewed the associated

work order (WO 98-00509-02), the

mechanical maintenance

procedure (N1-MMP-072-247), the markup (1-98-87), the

service water system piping and instrumentation drawing (C-19022-C), and other

related documentation.

The inspectors observed performance of the drag valve

strainer replacement on February 7.

The WO was appropriately revised to include a

statement of plant impact:

"breaching of service water pressure boundary is a

breach of secondary containment."

Because of difficulties encountered

in the past

when removing the valve bonnet from the valve body, a jacking device was

manufactured to aid in this portion of the task.

In addition, to ensure that the

bonnet would be removed for no more that four hours, the maintenance technicians

conducted

a "dry-run" of the evolution prior to'performing the actual work. The

inspectors noted several maintenance

supervisors and managers present at the job-

site observing the work, The inspectors considered the preplanning of the work and

the dry-run to be significant contributors in being able to complete the work in less

than two hours.

The inspectors identified that the attached permit for the scaffold being used for the

maintenance

indicated that the expected load was 600 pounds and that the scaffold

was erected for an indefinite period of time. The inspectors discussed with one of

the maintenance

supervisors

in the area the fact that the maintenance

personnel

and tools on the scaffold platform exceeded the expected load.

The supervisor

stated that this had been identified the day before, and that the actual capacity was

1050 pounds.

The inspectors then questioned whether the scaffold had been

analyzed for permanent installation.

Review by NMPC identified that the scaffold

had not been appropriately processed for permanent installation in accordance with

Procedure N1-MAP-MAI-0301,"Scaffold Control," Revision 8; specifically,

paragraph 1.2.2 requires that scaffolding used as a permanent platform be

processed

as a design change.

DER 1-98-325 was initiated to document the

problem and initiate corrective action.

The failure to perform a design change for

16

the permanently installed scaffold constitutes

a violation of minor significance and is

being treated as a Non-Cited Violation, consistent with Section IV of the'NRC

Enforcement Policy.

(NCV 50-220/98-01-05)

Conclusion

As a result of a good questioning attitude by a system engineer,

NMPC identified

that maintenance

on the Unit 1 service water drag valve in the reactor building

violated secondary containment integrity. Past maintenance

on the valve exceeded

the allowable limiting condition for operation outage time, and a reactor shutdow'n

had not been initiated in accordance with the technical specification requirements.

(NCV) The inspectors identified that NMPC failed to perform a design change for

permanently installed scaffolding.

(NCV)

Lon standin

Holdout on Tem erature Control Valve for Unit 1 Control Room

Emer enc

Ventilation S stem

Ins ection Sco

e

The inspectors identified a yellow holdout on the control room emergency

ventilation system (CREVS) temperature control valve (TCV) dating from 1992. The

inspectors questioned the SSS and determined that the valve was inoperable.

The

inspectors reviewed the holdout log, the WO, the DER, the UFSAR, and the

associated

procedures.

Observations

and Findin s

During a tour of the Unit 1 control room, the inspectors identified a yellow holdout

(YHO 1-92-10045) on the temperature control valve (TCV 210.1-56) for the

CREVS. The YHO was dated January 16, 1992.

Discussions with the SSS

revealed that the TCV had been inoperable since the early 1980s.

The TCV is a three-way control valve for the chilled water to the control room

ventilation area coolers.

The TCV controller failed as a result of aging, and a one-

for-one replacement was not available.

In 1983, a bypass valve around

TCV 210.1-56 was installed per modification N1-83-61. The bypass was to ensure

maximum cooling and maintain the control room temperature below 75 degrees

Fahrenheit,

as stated in the UFSAR, for protection of vital equipment and personnel

comfort. This portion of the ventilation system was also part of the control room

emergency ventilation system (CREVS). The CREVS would be initiated if the

radiation monitors in the ventilation intake from outside detected

a high radiation

level, such as the result of a main steam line break outside containment.

WO 94-

101-01 was initiated in 1994 to replace the TCV controller.

In May 1996, DER 1-

96-1223 was initiated to document the longstanding YHO, and to note that the

system drawing failed to include the bypass valve or indicate that the TCV was

failed open.

The disposition for the DER was to retire the TCV in place; the DER

also noted that a safety evaluation would be required since the TCV was shown on

an UFSAR drawing. The scheduled completion date was December 18, 1997. The

17

DER further stated that the control room temperature could be regulated by

positioning the ventilation dampers.

The DER stated that engineering had evaluated

that the current system operation would not impact the intent of the system design.

The TCV was added to the "Plant Equipment Retirement List" per Technical

Department Instruction N1-TDI-18, "Equipment Retirement."

The Plant Equipment

Retirement List was a tracking mechanism for out-of-service equipment, but the TDI

still required documentation to be completed before the equipment was formally

retired-in-place.

As of the date of the inspection, no action had been taken to

complete this documentation.

Subsequent to the end of the inspection period,

NMPC management decided to attempt to repair the valve or find a replacement

"

controller, if possible.

NMPC Procedure GAP-DES-03, "Control of Temporary Modifications," defines

temporarily lifted leads that modify the electrical circuit design or configuration as

an example of a temporary modification. The procedure further states that

temporary alterations identified and controlled by other administrative processes

are

exempt from the requirements of the procedure.

However, GAP-DES-03, Section

1.2, specifically states that, even though excluded from the temporary modification

procedure requirements, the exemptions are not excluded from the requirements of

NMPC Procedure NIP-SEV-01, "ApplicabilityReviews and Safety Evaluations."

As

of the date of the inspection, NMPC had not performed either an applicability review

or a safety evaluation.

This is a violation of the Unit 1 TS, Section 6.8.1, which

requires procedures to be implemented, as written. (VIO 50-220/98-01-06)

C.

Conclusion

The inspectors identified that the temperature control valve for the Unit 1 control

room emergency ventilation system had been inoperable since 1983. The

administrative controls to disposition the failed valve had not been properly

implemented; i.e., the controlled drawings did not indicate the inoperable valve, nor

was an engineering evaluation performed, as required by procedures, to determine if

continued operation with the degraded condition was acceptable.

(VIO)

E8

Miscellaneous Engineering Issues (90712, 92700, 92903)

E8.1

Closed

LER 50-410 97-05-01: Hi h Pressure

Core S

ra

S stem Ino erable Due

to Failed Unit Cooler

The technical issues associated with this LER were described in NRC Inspection

Report (IR) 50-410/97-04, Section 02.2.

The inspectors completed an in-office

review of the additional information provided in LER 50-410/97-05, Supplement

1,

and found it acceptable.

This LER is closed.

18

E8.2

Closed

LER 50-220 97-10-01:TS Re uired Shutdown Due to Emer enc

Coolin

Condenser Tube Leak

The technical issues associated with this LER were described in NRC IR 50-220/

97-07, Section 01.2; NRC IR 50-220/97-11, Section M1.2; and NRC IR 50-220/

97-12, Section E8.7.

Subsequent to the original LER, the licensee identified

additional information pertinent to the event and included that information in

Supplement

1 to the LER. The inspectors performed an in-office review of the

LER supplement.

NMPC concluded that the EC condenser tube failures resulted from a combination of

thermal fatigue and intergranular stress corrosion cracking due to the upper tubes of

the EC condenser tube bundles being in a continuous steam condensing mode.

The

licensee determined the root cause of the failed tubes resulted from an original

design deficiency, in that the EC condenser return isolation valve leakage limitations

were not specified.

NMPC also stated that an opportunity was missed to identify

this condition during a 1977 modification, in which an originally installed

temperature

alarm system was modified without a thorough understanding of the

system design basis.

This modification resulted in masking the normal operating

water level in the EC condenser steam inlet piping.

The LER supplement further detailed isotopic analysis reviews by the Unit 1

chemistry department,

and NMPC concluded that small EC condenser tube leaks

likely existed since March 1996.

NMPC also included in the LER supplement that:

(1) dose calculations for the quarter ending September were well below TS offsite

dose limits, (2) the EC system decay heat removal function was not significantly

affected by the EC condenser tube degradation,

and (3) the EC system station

blackout and 10 CFR 50 Appendix R functions could have still been performed.

The inspectors verified that the LER supplement was completed in accordance with

the requirements of 10 CFR 50.73. Specifically, the description and analysis of the

event, as contained in the LER supplement, were consistent with the

inspectors'nderstanding

of the event.

The inspectors considered the root cause and

corrective and preventive actions as described

in the supplement were reasonable.

This LER supplement

is closed.

E8.3

Closed

LER 50-410 97-13: Prior to 1992

Emer enc

Switch ear Not Seismicall

Qualified With Breakers Racked Out

a.

Ins ection Sco

e

The inspectors reviewed the details associated with the LER and the applicable DER

and procedures.

In addition, the inspectors reviewed the LER to verify completion

in accordance with 10 CFR 50.73.

'I

E

19

Observations

and Findin s

On October 29, 1997, NMPC determined that prior to April 30, 1992, Unit 2 had

racked out circuit breakers from 4160-volt switchgear such that the switchgear no

longer met seismic requirements.

The licensee identified this issue during a review

of NRC Information Notice (IN) 97-53, "Circuit Breakers Left Racked Out in Non-

Seismically Qualified Positions."

A member of the Unit 2 operations support staff

noted that other licensees

had reported similar conditions, but no report could be

located for Unit 2.

~On March 27, 1992, while Unit 2 was shutdown for refueling, NMPC initiated DER

2-92-Q-1144to address the seismic qualification of circuit breakers

in the racked

out condition. The initial SSS review of the DER concluded that operability and

reportability determinations were not applicable.

During the DER disposition, NMPC

design engineering determined that the switchgear were only seismically qualified

with the breakers racked in. Therefore, the switchgea'r would have been inoperable

during situations with breakers racked out,

Prior to April 30, 1992, the practice at

Unit 2 was to rack out circuit breakers for an extended period, although the practice

was limited to only one safety division at a time.

In 1997, NMPC concluded that prior to April 30, 1992, they had probably racked

out breakers in excess of eight hours.

When a division of AC (alternating current]

was energized, Unit 2 TS 3.8.3.1 required the division to be reenergized within

eight hours or be in at least HoT sHuTDowN within the next twelve hours.

Based on

DER 2-92-Q-1144, NMPC revised the applicable procedures to halt the practice of

leaving circuit breakers in the racked out position.

The inspectors considered the

actions taken to prevent recurrence to be appropriate and effective, based on

current observations during plant tours.

However, the failure to meet the

requirements of TS 3.8.3.1, prior to April 30, 1992, was a violation. This non-

repetitive, licensee-identified and corrected violation is being treated as a Non-Cited

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

(NCV.50-41 0/98-01-07)

Although NMPC took adequate

actions in 1992 to discontinue the practice of

racking out breakers, they failed to recognize during their review that the practice

had placed them in an unanalyzed condition, and that the condition was reportable.

The failure to report an unanalyzed condition to the NRC is a violation of 10 CFR 50.72 and 50.73. This failure constitutes

a violation of minor significance and

is'eing

treated as a Non-Cited Violation, consistent with Section IV of the NRC

Enforcement Policy.

(NCV 50-410/98-01-08) As described

in the LER, the reason

for not recognizing reportability could not be determined, but a contributing factor

was that the DER process

in 1992 was not clear relative to the reporting

requirements.

Since 1992, improvements have been made to the DER procedure,

and plant personnel were trained on the reporting requirements.

The inspectors

have reviewed the DER procedure and,considered

the reportability guidance to be

acceptable.

20

The inspectors verified that the LER was completed in accordance with the

requirements of 10 CFR 50.73.

Specifically, the description and analysis of the

event, as contained in the LER, were consistent with the inspectors'nderstanding

of the event.

The root cause and corrective and preventive actions as described

in

'he

LER were reasonable.

This LER is closed.

C.

Conclusion

Prior to April 30, 1992, Unit 2 operated with circuit breakers in the racked out

position, and failed to recognize the adverse impact on switchgear seismic

qualification and, therefore, switchgear operability.

(NCV) Although NMPC took

appropriate actions in 1992 to preclude future operations with breakers in the

racked out position, they failed to recognize that they were in an unanalyzed

condition, and that the condition was reportable.

(NCV)

E8.4

Closed

LER 50-410 97-16: Missed TSSR 4.3.4.1.2 for ATWS-RPT Tri of LFMG

Ins ection Sco

e

The inspectors reviewed the details associated with the LER and the applicable

DERs, TSs and UFSAR sections.

The inspectors reviewed surveillance test

procedures

and applicable plant drawings, and discussed with members of the

NMPC engineering and licensing staffs the ATWS-related testing performed at

Unit 2.

In addition, the inspectors reviewed the LER to verify completion in

accordance with 10 CFR 50.73.

b.

Observations

and Findin s

While drafting the LCOs for the ATWS-RPT [anticipated transient without scram-

recirculation pump trip] section of the Unit 2 improved technical specifications (ITS),

NMPC noted that the current logic system functional testing (LSFT) for the ATWS-

RPT did not include the trip of the low frequency motor generator (LFMG) on high

reactor pressure,

as described in the basis for the ITS.

DER 2-97-3105 was

initiated to document the concern, which was identified on November 7, 1997,

while Unit 2 was shutdown for repair to a recirculation flow control valve. Although

NMPC was evaluating whether testing was required by their current TSs, they

made a one-time revision to the applicable surveillance test procedure and, on

November 9, satisfactorily tested the trip of the LFMG on high reactor pressure.

Subsequently,

on December 3, 1997, NMPC determined that the LSFT of the

ATWS-RPT of the LFMG trip for high reactor pressure was required by technical

specification surveillance requirement (TSSR) 4.3.4.1.2.

The inspectors reviewed the applicable UFSAR and TS sections, and DERs.

The

inspectors determined that the failure to previously complete LSFT of the ATWS-

RPT LFMG trip on high reactor pressure was a violation of TSSR 4.3.4.1.2.

This

failure constitutes

a violation of minor significance and is being treated as a Non-

Cited Violation, consistent with Section IV of the NRC Enforcement Policy.

(NCV 50-41 0/98-01-09)

21

NMPC stated in the LER that the same issue had been previously reviewed through

DER 2-96-3268, initiated in December 1996.

During that review, NMPC had

determined that testing of the ATWS-RPT LFMG trip on high reactor pressure was

not necessary to satisfy TSSR 4.3 4.1.2. The basis, as stated in the LER, was that

the LFMG trip on high reactor pressure did not affect the transients, since during the

ATWS the peak reactor pressure

and peak cladding temperature would have

occurred before the 25-second time delay would have caused the LFMG to trip.

The inspectors discussed the testing requirements

and UFSAR description with

members of NMPC's engineering, technical support, and licensing groups.

The

discussions

also focused on how the licensee reached their incorrect conclusion in

1996 that the testing was not required.

The inspectors determined that the

conclusion was based on a non-conservative

interpretation of the UFSAR.

The inspectors, with members of the Unit 2 system engineering staff, reviewed the

applicable procedures

and plant drawings and verified that the revised surveillance

test adequately tested the time delay and the LFMG trip. The inspectors noted that

although the licensee recorded the actual time delay observed during the test, they

did not provide an acceptable

range of values.

Through discussions with the

Engineering Manager, the inspectors ascertained that, based on an engineering

determination, the times obtained were acceptable.

The inspectors also discussed

with the Maintenance and Engineering Managers, the failure to specify an

acceptable

range.

They agreed that the failure to specify acceptable values was a

poor practice; a DER was written to review this further. The inspectors considered

the failure to specify an acceptability range for the LFMG time delay as a weakness

in the procedure and in the review of the associated

procedure change.

The inspectors verified that the LER was corn'pleted in accordance with the

requirements of 10 CFR 50.73.

Specifically, the description and analysis of the

event, as contained in the LER, were consistent with the inspectors'nderstanding

of the event.

The root cause and corrective and preventive actions as described

in

the LER were reasonable.

This LER is closed.

Conclusion

NMPC identified that a portion of the Unit 2 testing for the recirculation pump trip in

response to an anticipated transient without scram was not completed in

accordance with the technical specifications.

(NCV) Specifically, the logic system

functional testing failed to include the high reactor pressure trip of the low

frequency motor generator.

In addition, the failure to specify an acceptability range

for the LFMG time delay in the subsequent

procedure change procedure indicated

weaknesses

in the procedure and in the review of the associated

procedure change.

Furthermore, in December 1996, NMPC missed an opportunity to identify the

inadequate

surveillance test due to a non-conservative interpretation of the UFSAR.

0

22

Closed

VIO 50-220 96-07-03: UFSAR Drawin

Chan

ed Without Performin

a

10 CFR 50.59 Safet

Evaluation

The inspectors performed an in-office review of the licensee response to an

inadequate

10 CFR 50.59 safety evaluation for a proposed revision to the Unit 1

UFSAR service water system drawing.

The preliminary safety evaluation incorrectly

concluded that the UFSAR was unaffected.

Therefore, no safety evaluation was

performed.

The licensee's root cause and corrective actions for the violation, as

stated in their November 1996 response to the NRC, were appropriate.

NMPC

conducted

a random sample review of preliminary safety evaluations generated

between 1990 and 1994 to determine the potential scope of the issue.

The

inspectors determined that the licensee's review was thorough.

The inspectors

considered the actions to prevent recurrence to be adequate.

Based upon the

inspectors'eview,

the violation is closed.

Closed

10 CFR 21 Notification: Potentiall

Defective Diesel Generator Air Start

Solenoid Valves

Ins ection Sco

e

The inspectors reviewed the details associated with the 10 CFR 21 (Part 21)

notification regarding potentially defective Graham-White air start solenoid valves

for EMD EDGs, and NMPC's evaluation for applicability to both units.

The

inspectors reviewed the applicable DER for each unit and discussed the related

issues with members of NMPC's engineering staff.

Observations

and Findin s

On January 22, 1998, Engine Systems, Inc. (ESI) issued

a Part 21 notification (SC

97-04Property "GE part 21" (as page type) with input value "SC</br></br>97-04" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.) pertaining to possibly defective air start solenoid valves used with EMD

EDGs.

Specifically, in 1990 the valves were modified with a larger internal spring

to reduce air leakage past the valves.

However, ESI recently determined that with

the increased spring size, the valves may not operate satisfactorily with a combined

low air system pressure ((200 pounds per square inch gage (psig)) and low

solenoid coil voltage ((105 volts direct current (Vdc)).

ESI recommended that (1) if

the minimum coil terminal voltage could not be maintained, then the internal spring

should be replaced with an appropriately-sized

spring, and (2) if the valve springs

were not replaced, then the licensee should test an installed or spare solenoid valve

to verify proper operation at the site specific minimum air pressure

and voltage.

NMPC reviewed the Part 21 and identified that both Unit 1 EDGs and the Unit 2

Division III (high pressure core injection system) EDG contained the suspect valves.

At Unit 1, the licensee determined that the worst-case condition would be a system

air pressure of 191 psig combined with a solenoid coil terminal voltage of 100.2

Vdc. This worst case voltage was based on end-of-life battery conditions.

NMPC

determined that for a minimum system air pressure of 191 psig, a coil voltage of

107 Vdc would be sufficient to ensure proper valve operation.

Since both Unit 1

23

station batteries were replaced in the Spring 1997, NMPC recalculated coil terminal

voltage using an appropriate aging factor for the current condition of the installed

batteries,

and concluded that coil terminal voltages were adequate to ensure valve

operability.

However, this evaluation only provided a short-term justification, and

based on discussion with the EDG system engineer, NMPC intends to replace the

valves in the near future.

At Unit 2, the worst case condition would be 215 psig system air pressure

combined with approximately 109 Vdc at the solenoid coil. Therefore, system air

pressure

and voltage were adequate to ensure operability of the installed valves.

'owever,

based on discussions with the EDG system engineer, NMPC was

evaluating whether to replace the valves in May 1998, during the refueling outage,

or complete the testing as recommended

by ESI in the Part 21.

The inspectors reviewed the Part 21, and considered the licensee's actions to

address the concern at each unit to be timely and technically sound.

Therefore, this

Part 21 is closed.

Conclusion

The licensee's actions at both units to address

an industry concern with potentially

defective emergency diesel generator air start solenoid valves was timely and

technically sound."

0 ened

10 CFR 21 Notification: Potentiall

Defective GE SBM-T

e Switches

Unit 1

Ins ection Sco

e

NMPC initiated a DER as a result of a General Electric Nuclear Energy (GENE) issued

Part 21 notification of a possible adverse condition related to the spring-return

function of some GE-provided control switches that could damage the associated

control circuits.

The inspectors reviewed the Part 21, the DER, and the related

operating procedures,

and discussed the issue with control room personnel.

Observations

and Findin s

On January 27, 1998, GENE issued

a Part 21 notification informing licensees of a

possible failure of certain GE SBM-ty'pe control switches having a spring-return

feature and which were manufactured after March 1996. The switches were

manufactured

as a commercial grade item by another division of GE; GENE then

dedicated the switches and supplied them to nuclear power plants as a basic

component for safety-related applications.

In early January 1998, GENE was

notified by another licensee of a failure of one of the switches to automatically

spring return to the normal position; subsequently,

GENE was notified of several

other failures.

GENE determined that the most probable failure mode was

mechanical binding internal to the switch. The Part 21 listed two safety concerns:

(1) possible damage to the control circuitry, and (2) the possibility that the control

~

~

circuits would not be able to perform the safety function due to the failure to reset

to the normal position.

NMPC identified that seven GE SBM-type switches manufactured after March 1996

were installed in safety-related functions in Unit 1: control switches for the EC

condenser vent-to-torus blocking valves; containment spray bypass-to-torus

blocking valves; and the containment spray test-to-torus flow control valve.

NMPC

engineering initiated DER 1-98-0202to resolve this concern.

The inspectors reviewed the DER and Part 21 notification, and discussed the issue

with the maintenance engineer responsible for the disposition.

In addition, the

inspectors discussed the potential failure mechanism with Unit 1 control room

operators; all operators interviewed were knowledgeable of the need to ensure that

the switches were returned to the normal position.

The inspectors also reviewed

the affected procedures.

Neither Procedure N1-OP-13, "Emergency Cooling

System" or Procedure N1-OP-14, "Containment Spray System" contained

a

precautionary note about the possible failure of the spring return switches.

This

was discussed with the ASSS, who stated that he would discuss the development

of a temporary procedure change with his management.

The NRC willreview the

DER disposition upon completion.

This will be tracked as an open Part 21 item.

Conclusion

NMPC responded quickly and appropriately to a vendor notification related to a

possible failure of spring-return switches used in the emergency cooling and

containment spray systems at Unit 1. Control room operators were aware of the

potential failure mode; however, the associated

operating procedures

had not been

revised to include a precautionary note related to the concern.

Closed

URI 50-220 96-05-03: Lack of 10CFR50.59 Safet

Evaluation for the

Modification to Restore the Unit 1 Blowout Panels to Com liance with UFSAR

During the NRC Special Inspection 50-220/96-05regarding

the Unit 1 reactor and

turbine building blowout panels being outside the design basis, an apparent violation

was identified regarding the lack of 10 CFR 50.59 safety evaluation for the March

1995 modification to restore the blowout panel relief pressures to compliance with

the UFSAR. Following the enforcement conference, the NRC reclassified this issue

as an unresolved item pending additional NRC review, as documented

in the letter

from the NRC to NMPC dated June 18, 1996.

Prior to March 1995, the reactor and turbine building blowout panels were fastened

with shear bolts larger than those specified on plant drawings causing the relief

pressure to be greater than that described in the UFSAR.

In March 1995, NMPC

modified the blowout panels by removing every other shear bolt, which was

intended to restore the relief pressure to that stated within the UFSAR. The

particular concern described in NRC IR,.50-220/96-05 was that, although the UFSAR

did not explicitly describe the size or spacing of the blowout panel bolting, the

change did alter the blowout panel design.

Therefore, it should have required a

25

10 CFR 50.59 safety evaluation.

Following discussions with NRR, it was concluded that this modification did not

change the system design as described

in the UFSAR, nor did it involve a change to

the TS; therefore, the modification to'restore the blowout panels to the pressure

stated in the UFSAR did not need a 10 CFR 50.59 safety evaluation.

The

inspectors had no further questions,

and this item is closed.

E8.9

Closed

Unit 2 S ecial Re ort: Division I Standb

EDG Non-valid Test and Non-

valid Failure

On January 8, 1998, the Division I EDG tripped on overspeed

during a monthly

surveillance test.

Subsequently, the licensee verified that an actual overspeed

condition did not occur, and that a fault in the test mode circuitry caused the trip.

Particularly, the optical isolator transmitter board and associated

receiver board in

the secondary start circuitry failed due to thermal aging.

The failed circuitry

provided a repeater signal to trip the EDG in an overspeed condition; however, this

signal was only utilized in the test mode and is bypassed

during the emergency

mode.

The isolator was replaced and the EDG was re-tested successfully.

The

isolator failure was documented

in DER 2-98-0033, and NMPC began evaluating the

need to replace additional isolators, as part of the DER review.

As required by TS 4.8.1.1.3, NMPC documented the EDG failure in a special report

to the NRC (NMPC letter NMP2L 1749 dated February 5, 1998).

As documented

in that report, NMPC determined that the test was non-valid based on the guidance

provided in NRC Regulatory Guide (RG) 1.108, "Periodic Testing of Diesel Generator

Units Used as Onsite Electric Power Systems at Nuclear Power Plants," because the

trip was initiated from a portion of circuitry bypassed

in the emergency mode.

The

inspectors reviewed the applicable plant drawings and confirmed that the trip would

not have occurred in the emergency mode.

The inspectors'eview of the failure,

and the guidance provided in RG 1.108, indicates that NMPC appropriately

determined that the failure and test were non-valid.

E8.10 Administrative Closure of Escalated Enforcement Items

The escalated

enforcement items (EEls) listed below are being administratively

closed, due to the issuance of the indicated enforcement action (EA) letter and

.

associated

determination:

EEI 50-410/96-15-02:

EEI 50-410/96-16-01:

EEI 50-410/96-16-02:

EEI 50-410/96-16-03:

EEI 50-410/96-16-04:

EEI 50-410/96-16-05:

EEI 50-410/96-1 6-06:

EEI 50-410/96-1 6-10:

closed by EA

closed by EA

closed by EA

closed by EA

closed by EA

closed by EA

closed by EA

closed by EA

96-475, VIO 3013

96-494, VIO 3043

96-494, VIO 3043

96-494, VIO 2023

96-494, VIO 2013

96-494, VIO 3023

96-494, withdrawn

96-494, VIO 3033

26

In addition, two of the EEls were classified as non-cited violations (NCVs) in the EA

letter; as such, these NCVs are being assigned tracking numbers in this inspection

report:

EEI 50-410/96-16-07:

EEI 50-41 0/96-1 6-08:

closed by EA 96-494, NCV 50-410/98-01-10

closed by EA 96-494, NCV 50-410/98-01-11

IV. PLANT SUPPORT

Using NRC Inspection Procedure 71750, the resident inspectors routinely monitored

the performance of activities related to the areas of radiological controls, chemistry,

emergency preparedness,

security, and fire protection.

Minor deficiencies were

discussed with the responsible management,

and significant observations

are

detailed below.

R1

Radiological Protection and Chemistry Controls (71750)

R1.1

Potentiall

Contaminated Truck Released from Unit 1

On February 9, 1998, NMPC was notified that radiation levels on an empty flat-bed

trailer, released from Unit 1 on February 7, 1998, may have exceeded

levels

specified in 49 CFR, Part 173.443(c).

The trailer was placed in a secure area on

Babcock and Wilcox's property in Parks Township, Pennsylvania to await further

surveys and evaluation.

This is characterized

as an unresolved item pending

further surveys and review of the results by NRC.

(URI 50-220/98-01-12)

R8

Miscellaneous RP&C Issues (71750)

R8.1

Administrative Closure of Escalated Enforcement Items

The escalated

enforcement items (EEls) listed below are being administratively

closed, due to the issuance of the indicated enforcement action (EA) letter and

associated

determination:

EEI 50-220/97-07-07:

closed by EA 97-530, VIO 1013

EEI 50-220/97-07-09:

closed by EA 97-530, VIOs 1033 & 1034

EEI 50-220 & 50-410/97-07-10:

closed by EA 97-530, VIO 1023

EEI 50-220 & 50-410/97-07-12:

closed by EA 97-530, withdrawn

In addition, two of the EEls were classified as non-cited violations (NCVs) in the EA

letter; as such, these NCVs are being assigned tracking numbers in this inspection

report:

EEI 50-220 & 50-410/97-07-06:

closed by EA 97-530,

NCV 50-220 & 50-410/98-01-13

EEI 50-220 & 50-410/97-07-11:

closed by EA 97-530,

NCV 50-220 & 50-410/98-01-14

~

~

27

F2

Status of Fire Protection Facilities and Equipment (71750)

F2.1

Unit 1 Un lanned Fire Alarms and Preaction

S rinkler S stem Actuation

Ins ection Sco

e

The inspectors reviewed the circumstances

surrounding unplanned fire alarms and

preaction sprinkler system actuation at Unit 1. The inspectors evaluated control

room and fire brigade response to the event, and discussed the issue with fire

protection supervision,

b.

Observations

and Findin s

On January 8, 1997, multiple fire alarms were indicated in the Unit 1 control room

originating from local fire panels (LFPs) 3, 4, and 5 in the Unit 1'turbine building

(TB). Control room staff announced the alarms and investigation by the fire brigade

identified that a LFP-3 detection zone was in an alarm condition and that a preaction

sprinkler system had initiated on TB 261'261-foot] elevation.

Subsequently, wet

pipe sprinkler system water flow alarms were received on LFPs 3, 4 and 5 for the

offgas building, TB 291',elevation,

and TB 351'levation, respectively.

The inspectors observed licensee actions from both the Unit 1 control room and in

the TB. The fire brigade confirmed that no fire existed, and that no water had

actually been discharged to the TB. Due to inclement weather (rain and high

winds), numerous roof leaks had been detected during the day, and the licensee

identified water in an area adjacent to a fire detector located in TB 261'.

Subsequent

licensee investigation concluded that water intrusion into this detector

resulted in the initial preaction sprinkler system alarm on LFP-3. Additionally, the

licensee presumed that the false indication of the wet pipe system water flow

alarms was caused by a backup of the sprinkler system drain header, since water

had overflowed the air gap funnel drain cups associated with the wet pipe sprinkler

system on TB 261'nd TB 277'. The inspectors observed that both control "room

and fire brigade personnel responded

appropriately to the event and the

investigation effort was adequately coordinated.

Through discussions with the fire protection supervisor, previous similar

occurrences

were attributed to limited drainage on the wet pipe system common

drain header,

and that the water overflow on TB 277'as likely a result of system

backpressure.

The system had design features, including retard chambers and

check valves, to minimize the impact of system backpressure

perturbations,

producing erroneous alarms.

However, the fire protection supervisor stated that

erroneous

alarms sometimes occurred, even during routine surveillance testing.

System backpressure,

concurrent with check valve leakage, could result in pressure

switch actuations and provide false indications of wet pipe system flow on TB

261'nd

TB 291'levations.

The inspectors considered that the failure to fully

investigate and resolve previous similar, occurrences was a weakness

and likely

contributed to the recent event.

28

The licensee issued

a DER 1-98-0040 to document the issue, and several Problem

Identification (PID) entries were made to address

1) the potential poor system

drainage,

2) the roof leakage,

and 3) check valve seat leakage.

The inspectors

walked down the affected fire protection systems with the fire protection

supervisor.

The system configuration appeared to support the licensee's conclusion

for actuation of the wet pipe system flow indications.

The licensee replaced

a

check valve located on TB 261', and the inspectors observed that the check valve

body and seat revealed significant wear and corrosion, and the valve disc was

degraded.

Subsequent

discussion witlithe supervisor indicated that further

corrective action included replacement of similar-type ch'eck valves within the wet

pipe system to preclude the backpressure

spikes.

The inspectors considered

licensee corrective actions to be appropriate.

Although the inspectors did not

consider fire protection system operability to be affected by the degraded

components, the impact of the deficiencies could hinder plant personnel responding

to an in-plant fire due to potential multiple false alarms.

c.

Conclusions

Control room and fire brigade personnel appropriately responded to numerous Unit 1

fire alarm actuations,

and the investigation effort appeared

adequately coordinated.

The failure to fully investigate and resolve previous similar false fire protection

system actuations was a weakness

and likely contributed to the recent event.

Although Unit 1 fire suppression

system operability did not appear to be affected by

degraded components, the impact of the deficiencies could hinder plant personnel

responding to an in-plant fire due to potential multiple false alarms.

V. IVIANAGENENTMEETINGS

X1

Exit Meeting Summary

At periodic intervals, and at the conclusion of the inspection period, meetings were

held with senior station management to discuss the scope and findings of this

inspection.

The final exit meeting occurred on March 6, 1998.

During this meeting, the

resident inspector findings were presented.

NMPC did not dispute any of the

findings or conclusions.

Based on the NRC Region

I review of this report, and

discussions with NMPC representatives,

it was determined that this report does not

contain safeguards

or proprietary information.

ATTACHMENT1

PARTIALLIST OF PERSONS CONTACTED

Nia ara Mohawk Power Cor oration

R. Abbott

D. Barcomb

D. Bosnic

J. Burton

H. Christensen

J ~ Conway

G. Correll

R. Dean

A. DeGracia

S. Doty

K. Dahlberg

G. Helker

A. Julka

P. Mazzafero

L. Pisano

R. Randall

V. Schuman

R. Smith

R. Tessier

C. Terry

C. Ware

K. Ward

D. Wolniak

Plant Manager, Unit 1 (Acting)

Manager, Unit 2 Radiation Protection

Manager, Unit 2 Operations

Manager, Quality Assurance

Manager, Security

Vice President, Nuclear Engineering

Manager, Unit 1 Chemistry

Manager, Unit 2 Engineering

Manager, Unit 1 Work Control

Manager, Unit 1 Maintenance

Plant Manager, Unit 2 (Acting)

Manager, Unit 2 Work Control

Director, ISEG

Manager, Unit 1 Technical Support

Manager, Unit 2 Maintenance

Manager, Unit 1 Engineering

Manager, Unit 1 Radiation Protection

Manager, Unit 1 Operations

Manager, Training

Vice President,

Nuclear Safety Assess

Manager, Unit 2 Chemistry

Manager, Unit 2 Technical Support,

Manager, Licensing

ment 5. Support

INSPECTION PROCEDURES USED

IP 36100

IP 37551

IP 61726

IP 62707

IP 71707

IP 71714

IP 71715

IP 71750

IP 90712

IP 92700

IP 92901

IP 92902

IP 92903

IP 92904

10 CFR Part 21 Inspections at Nuclear Power Plants

On-Site Engineering

Surveillance Observations

Maintenance Observations

Plant Operations

Cold Weather Preparations

Sustained Control Room and Plant Observation

Plant Support

In-Office Review of Written Reports of Nonroutine Events at Power

Reactor Facilities

Onsite Followup of Written Reports of Nonroutine Events at Power

Reactor Facilities

Followup -, Plant Operations

Followup - Maintenance

Followup - Engineering

Followup - Plant Support,

A-1

I

Attachment

1

ITEMS OPENED, CLOSED, AND UPDATED

OPENED

50-41 0/98-01-01

50-220/98-01-02

50-220/98-01-03

50-220/98-01-04

50-220/98-01-05

50-220/98-01-06

50-41 0/98-01-07

50-410/98-01-08

50-41 0/98-01-09

50-41 0/98-01-1 0

50-41 0/98-01-1

1

50-220/98-01-1 2

50-220 &

50-41 0/98-01-1 3

NCV

NCV

VIO

NCV

NCV

VIO

NCV

NCV

NCV

NCV

NCV

URI

NCV

Inadequate Separation Between Conduits for Safety-

Related Temperature

Elements

Failure to Perform Required Engineering Evaluations on

Longstanding Catch Containments

Liquid Poison System Surveillance Testing Inadequacy

Service Water Valve Maintenance Violated Secondary

Containment

Failure to Perform a Design Change for a Permanently

Installed Scaffold

Failure to Perform an Engineering Safety Analysis for

Inoperable CREVS TCV Failed Since 1992

Switchgear Inoperable due to Racked Out Circuit

Breakers

Failure to Report an Unanalyzed Condition

Failure to Perform LSFT of the ATWS-RPT LFMG Trip on

High Pressure

Administrative Closure of EEI 50-410/96-16-07

Administrative Closure of EEI 50-410/96-16-08

Potentially Contaminated Truck Released Offsite

Administrative Closure of EEI 50-220 & 50-410/97-07-

06

50-220 &

50-41 0/98-01-14

NCV

~

Administrative Closure of EEI 50-220 & 50-410/97-07-

11

Part 21

GE SBM-Type Switches

CLOSED

50-220/96-1 2-01

EEI

50-220/96-1 2-05

EEI

Failure to Include Six SSCs in the Scope of the

Maintenance

Rule

Ineffective Goals and Monitoring for (a)(1) SSCs

50-410/96-1 5-02

EEI

50-410/96-1 6-01

EEI

50-410/96-1 6-02

EEI

Failure to Check MOV Pressure

Locking Calculations

Control Room Chiller Deficiencies for SW Setpoints

Control Room Chillers Inoperable due to SW Setpoints

A-2

Attachment

1

50-410/96-1 6-03

EEI

50-410/96-1 6-04

EEI

50-410/96-1 6-05

EEI

50-410/96-1 6-07

EEI

50-410/96-1 6-08

EEI

Failure to Repair Control Room Chillers After Previous

TI'Ips

RCIC Lube Oil PCV Failed Open Since 1991

RCIC Design Calculations Incorrect and No Independent

Review

No Safety Evaluation Performed for RCIC PCV Failed

Open

UFSAR Not Updated When New Design for RCIC PCV

=

Installed

50-410/96-1 6-10

50-220 &.

50-410/97-07-06

50-220/97-07-07

50-220/97-07-09

50-220 5,

50-41 0/97-07-1 0

50-220 5

50-41 0/97-07-1

1

50-410/98-01-01

50-41 0/98-01-02

50-220/98-01-04

50-220/98-01-05

50-41 0/98-01-07

50-41 0/98-01-08

50-410/98-01-09

50-410/98-01-1 0

50-41 0/98-01-1

1

50-220 5

50-41 0/98-01-1 3

50-220 6

50-41 0/98-01-1 4

EEI

EEI

EEI

EEI

EEI

EEI

NCV

NCV

NCV

NCV

NCV

NCV

NCV

NCV

.NCV

NCV

NCV

Design Errors Related to RCIC

Failure to Update PCPs

Radwaste Shipment Exceeded 49 CFR Limits

Radwaste Shipments to Wrong Address

Radwaste Shipment of Wrong Liner

Failure to Identify and Correct Problems with PCPs

Inadequate

Separation Between Conduits for Safety-

Related Temperature Elements

Failure to Perform Required Engineering Evaluations on

Longstanding Catch Containments

'

Service Water Valve Maintenance Violated Secondary

Containment

Failure to Perform a Design Change for a Permanently

Installed Scaffold

Violation of TSs Switchgear Inoperable due to Racked

Out Circuit Breakers

Failure to Report an Unanalyzed Condition

Violation of TSs Failure to Perform LSFT of the ATWS-

RPT LFMG Trip on High Pressure

Administrative closure of EEI 50-410/96-16-07

Administrative closure of EEI 50-410/96-16-08

Administrative closure of EEI 50-220 5. 50-410/97-07-'06

Administrative closure of EEI 50-220 5 50-410/97-07-11

A-3

0

Attachment

1

50-410/97-05-01

50-220/97-10-01

50-410/97-1 3

50-41 0/97-1 6

50-410/98-01

50-410/98-02

50-220/96-07-03

50-220/96-05-03

Part 21

LER

LER

LER

LER

LER

LER

VIO

URI

Potentially Defective Diesel Generator Air Start Solenoid

Valves

HPCS System Inoperable Due to Failed Unit Cooler

TS Required Shutdown Due to EC Condenser Tube Leak

Prior to 1992, Emergency Switchgear Not Seismically

Qualified with Breakers Racked Out

Missed TSSR 4.3.4.1.2 for ATWS-RPT Trip of LFMG

Entry Into TS 3.0.3 Due to Containment Atmospheric

Gaseous/Particulate

Radiation Monitors Inoperable

Violation of TS 6.2.2.b - No Licensed Operator At-the-

Controls

UFSAR Drawing Changed Without Performing a

10CFR50.59 Safety Evaluation

Lack of 10 CFR 50.59 Safety Evaluation for the

Modification to Restore the Unit 1 Blowout Panels to

Compliance with UFSAR

WITHDRAWN

50-220/96-1 2-06

EEI

50-220/96-1 2-07

EEI

50-410/96-1 6-06

EEI

50-220 5

EEI

50-41 0/97-07-1 2

Unacceptable

Performance Criteria to Verify Preventive

Maintenance was Effective

Ineffective Monitoring and Untimely Evaluation of (a)(2)

SSCs

RCIC Inoperable Since 1991

Failure to Conduct Audits of Vendors Supplying

Shipping Casks

UPDATED

None

LIST OF ACRONYMS USED

AC

ASSS

ATWS-RPT

cfm

CFR

CMS

CREVS

CSO

DER

Alternating Current

Assistant Station Shift Supervisor

Anticipated Transient Without Scram - Reactor Pump Trip

cubic feet per. minute

Code of Federal Regulations

Containment Monitoring System

Control Room Emergency Ventilation System

Chief Station Operator

Deviation/Event Report

A-4

Attachment

1

EA

EC

EDG

EEI

ESA

ESF

ESI

FRI

GE

HPCS

IN

IR

IST

ITS

I<V

LCO

LER

LFMG

LSFT

pCI/sec

MOV

NCV

NMPC

NOED

NRC

Part 21

PCP

PCV

PDR

pslg

RBCLC

RCIC

'FO

RG

RHR

RO

'SE

SORC

SRO

SSC

SSS

STA

SW

TB

TBCLC

TCV

Enforcement Action

Emergency Cooling

Emergency Diesel Generator

Escalated Enforcement Item

Engineering Supporting Analysis

Engineered Safeguards

Feature

Engine Systems, Inc.

Fuel Reliability-Index

General Electric

High Pressure

Core Spray

Information Notice

Inspection Report

Inservice Testing

Improved Technical Specifications

kiloVolt

Limiting Condition for Operation

Licensee Event Report

Low Frequency Motor Generator

Logic System Functional Testing

microCuries per second

Motor-Operated Valve

Non-Cited Violation

Niagara Mohawk Power Corporation

Notice of Enforcement Discretion

Nuclear Regulatory Commission

Title 10 of the Code of Federal Regulations Part 21

Process Control Program

Pressure

Control Valve

Public Document Room

pounds per square inch gage

Reactor Building Closed Loop Cooling

Reactor Core Isolation Cooling

Refueling Outage

Regulatory Guide

Residual Heat Removal

Reactor Operator

Safety Evaluation

Station Operating Review Committee

Senior Reactor Operator

Structure, System, and Component

Station Shift Supervisor

Shift Technical Advisor

Service Water

Turbine Building

Turbine Building Closed Loop Cooling

Temperature Control Valve

A-5

'l

Attachment

1

TS

TSSR

UFSAR

Unit 1

Unit 2

URI

Vdc

VIO

WO

YHO

Technical Specification

Technical Specification Surveillance Requirement

Updated Final Safety Analysis Report

Nine Mile Point Unit 1

Nine Mile Point Unit 2

Unresolved Item

volts direct current

Violation

Work Order

Yellow Holdout

A-6