ML17059B355

Insp Repts 50-220/96-10 & 50-410/96-10 on 960728-0907. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML17059B355
Person / Time
Site:	Nine Mile Point
Issue date:	11/25/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17059B353	List: ML17059B352 ML17059B354 ML17059B355
References
50-220-96-10, 50-410-96-10, NUDOCS 9612030145
Download: ML17059B355 (72)

See also: IR 05000220/1996010

Text

U.S. NUCLEAR REGULATORY COIVIIVIISSION

REGION I

Docket/Report Nos.:

50-220/96-06

50-41 0/96-06

License Nos.:

DPR-63

NPF-69

Licensee:

Niagara Mohawk Power Corporation

P. O. Box 63

Lycoming, NY 13093

Facility:

Nine Mile Point, Units

1 and 2

Location:

Scriba, New York

Dates:

July 28 - September

7, 1996

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

9b22030145 9bli25

PDR

ADQCK 05000220

8

PDR

EXECUTIVE SUIVIMARY

Nine Mile Point Units 1 and 2

50-220/96-10

8t 50-410/96-10

July 28 - September 7, 1996

This integrated inspection report includes reviews of licensee operations,

engineering,

maintenance,

and plant support.

The report covers

a 6-week period of resident inspection.

PLANT OPERATIONS

During the Unit

1 shutdown of July 28, the inspectors

noted difficulties with respect to the

operator's ability to control reactor vessel water level, and confusion on the part of the

Station Shift Supervisor

(SSS) regarding the proper action when one control rod was at an

indeterminate position.

The SSS briefing for the shutdown was weak and did not include

significant detail or a discussion of past problems.

Management oversight of the Unit

1 reactor startup on August 20 was good, and the pre-

evolution brief by the Operations Manager was detailed and safety-focused.

The control

room staff demonstrated

a questioning attitude and the briefing appeared

synergistic.

The

presence

of a Quality Assurance

(QA) auditor and a Unit 2 senior reactor operator (SRO) in

the control room during the startup was a positive attribute.

Unit 1 experienced two control rod drive (CRD) uncouplings during the period.

The actions

taken each time were appropriate.

The decision to declare one of the CRDs inoperable due

to recurring uncouplings,

and the inability to verify coupling at the projected critical rod

height during the planned startup was appropriate

and conservative.

MAINTENANCE

The troubleshooting,

repair, and post-maintenance

testing activities associated

with

repetitive failures of a Unit 2 main steam line (MSL) radiation monitor were methodical,

thorough,

and appropriate.

However, removal of the LCO required trips to conduct post-

maintenance

testing, prior to declaring the MSL radiation monitor operable,

appears to be a

violation of TS.

NMPC disagrees with this position and submitted

a letter to the NRC

Office of NRR for clarification of the requirements.

In addition, the need to remove LCO

required trips to complete the testing to determine operability is not limited to the MSL

radiation monitors at Unit 2, and may be generic to other plant systems.

(URI 96-01-01)

The Unit

1 shaft-driven feedwater pump friction clutch failed to engage

during a power

ascension,

Following repairs and post-maintenance

testing, the system was improperly

restored because

of personnel

error.

This resulted in the clutch trying to engage while the

output shaft was secured with a maintenance

pin, causing damage to the clutch

mechanism.

When personnel

removed the pin, the shaft started to rotate, which could

have caused

serious personal injury. Not withstanding the near miss, the technical

meetings were thorough and safety-focused.

Plant management

was actively involved

with numerous technical and operational concerns.

The final repairs appeared

appropriate

and technically sound.

0V

Executive Summary (cont'd)

Unit 2 started

a shutdown because

both divisions of the control building chilled water

system were inoperable due to low service water flow through the chillers.

NMPC's

determination of the low setpoint for the service water flow trip was inadequate

design.

(URI 96-10-02)

The work orders were technically correct and the adjustments

were

performed correctly and without incident.

The NMPC procedure for procedure

changes

was inconsistent with the requirements of the

Unit 2 TSs, which require two members of the unit management

staff to approve the

change,

at least one of whom holds an SRO license.

The procedure allowed approval by a

"procedure owner" if the change was considered

editorial.

One of the possible editorial

corrections allowed was one-for-one changes to existing information, if the change was

supported

by the reviews and approvals for the design document.

This is a violation of TS 6.8.3

(VIO 96-10-03).

A strong procedure review and approval process should have

identified this.

This is the second example in less than a year where the NRC identified a

programmatic procedure that departs from the requirements of the license.

The other

example was implementation of temporary modifications prior to completion of the required

safety evaluations.

Three maintenance

related issues were associated

with poor personnel performance.

A

Unit

1 operator pulled the wrong fuses during application of a markup, resulting in the

inadvertent scram of a control rod; a Unit 1 operator made a calculational error during

completion of a core spray topping pump surveillance, resulting in a six week delay in

identifying that the pump differential pressure

was higher than the acceptance

criteria;

and a Unit 2 Instrumentation

and Controls (l&C) Supervisor incorrectly changed

a work

order, resulting in maintenance

on the wrong division of the hydrogen/oxygen

(H,/0,)

monitoring system.

In each case, the procedures

were not properly implemented.

(VIO 96-10-04)

ENGINEERING

On August 28, 1996, Unit 2 operators entered the EOPs due to a positive pressure

in the

reactor building.

During a surveillance on the standby gas treatment system, including the

emergency recirculation ventilation subsystem,

the test damper closed and the normal inlet

damper opened.

This placed the recirculation system in parallel operation with the normal

ventilation exhaust fan; thus, less air was available for removal by the normal ventilation

fan.

An interlock caused the inlet damper to open if the test damper closed while the

system was running.

The operators responded

appropriately to the transient, and the

operability determination was adequate

for normal operations;

however, the adequacy

of

the surveillance procedure, with regards to the potential for a failure of the test damper to

result in a challenge to secondary containment integrity, is unresolved.

(URI 96-10-05)

General Electric (GE) informed NMPC that the cycle specific safety limit minimum critical

power ratio (SLMCPR) for both units may be more limiting than previously determined for

generic calculations.

Both units implemented administrative limits until the completion of

the GE cycle specific analysis.

After receipt of the GE analysis, both units updated the

core monitoring computer to reflect the change

in the SLMCPR.

e

TABLE OF CONTENTS

page

EXECUTIVE SUMMARY

TABLE OF CONTENTS

.

~

~

~

~

~

~

IV

SUMMARY OF ACTIVITIES

Niagara Mohawk Power Corporation (NMPC) Activities ....

Nuclear Regulatory Commission

(NRC) Staff Activities

I. OPERATIONS

01

Conduct of Operations........

~ ~........

~

~ ~............

~

01.1

General Comments

01.2

Unit

1 Shutdown to Repair the Shaft Driven Feedwater

Pump

.

01.3

Unit 1 Startup .......

~ . ~........

~

~ ..

02

Operational Status of Facilities and Equipment ..

~ ~.... ~........

02.1

Unit 1 Control Rod Uncouplings

02.2

Unit 2 RCIC Walkdown

08

Miscellaneous

Operations

Issues ..

~

~ ..'.... ~...

~

~

~ ~...,,...

-08.1

(Closed)

Unit

1 Special Report: ¹12 Drywell High Range

Gamma Radiation Monitoring System Inoperable

08.2

(Closed)

Unit 1 Special Report: ¹12 Drywell High Range

Gamma Radiation Monitoring System Inoperable

08.3

(Closed)

VIO 50-220/95-03-01:

Operator Actions Contrary to

Procedures

08.4

(Closed)

URI 50-220/95-03-02:

Procedures

not Consistent

with Technical Specifications

08.5

(Closed)

URI 50-220/95-16-01:

Weak Initial Operability

Determinations

~

~

~

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2

2

2

2

4

4

4

6

6

II. MAINTENANCE

M1

Conduct of Maintenance

M1.1

Unit 2 Main Steam Line Radiation Monitor Failures

M1.2

Unit 2 LPCS Pump Suction Valve Leak Rate Testing

M2

Maintenance

and Material Condition of Facilities and Equipment

M2.1

Repairs to Unit 1 Shaft Driven Feedwater

Pump ..........

M2.2

Unit

1 Control Rod Scram Solenoid Pilot Valve Diaphragm

Replacement......

~ .. ~.................

~

~ ~.....

M2.3

- Unit 2 TS Required Shutdown due to Both Divisions of the

Control Building Chilled Water System Inoperable

.

~ .

~

~ ..

~ .

M3

Maintenance

Procedures

and Documentation ....

M3.1

Procedure

Changes

Not in Accordance with TS Requirements

M4

Maintenance Staff Knowledge and Performance ..

M4.1

Personnel

Performance

~ ~........ ~....

M4.2

Unit

1 Inadvertent Scram of a Single Control Rod.........

M4.3

Calculation Error During Unit

1 Core Spray Surveillance

~

~

~

~

~

~

~

0

~

~

8

8

9

11

11

11

13

14

15

15

16

16

17

18

IV

I

Table of Contents (cont'd)

M4.4

Unit 2 Maintenance Activities on the Incorrect Division of H,O,

Monitoring ... ~......... ~........... ~............

19

M4.5

Conclusion

- Inadequate

Personnel Performance........,

.

~

.

20

M8

Miscellaneous Maintenance

Issues ..........................

20

M8.1

(Closed)

LER 50-410/96-08:

Technical Specification

Violations Caused by Inadequate

Procedure ........... ~...

20

M8.2

(Closed)

LER 50-220/96-06:

Technical Specification Violation

Caused

by Cognitive Error in Calculation Verification ........

21

21

21

21

23

III. ENGINEERING

E2

Engineering Support of Facilities and Equipment ~.......

~

~

.

~

~ ~...

E2.1

Unit 2 Secondary

Containment Pressurization

E8

Miscellaneous

Engineering

Issues

E8.'I

(Closed) LERs 50-220/95-05 and 50-220/95-05 Supplement

1:

Building Blowout Panels Outside the Design Basis Because of

Coflstructlotl Error ......,...,...............,......

23

E8.2

Incorrect Safety Limit Identified by General Electric .........

25

E8.3

(Clos~~I LER 50-220/96-05:

Incorrect Safety Limit Caused by

Inadequate

Calculational Procedure ..

~ . ~........... ~....

26

-E8.4

(Closed) LER 50-410/96-06:

Incorrect Safety Limit Caused by

Inadequate

Calculationa( Procedure .....

~

.

~ .. ~...

~

~ ~....

26

E8.5

(Closed) LER 50-410/96-06 Supplement

1: Incorrect Safety

Limit Caused

by Inadequate

Calculational Procedure .... ~....

26

IV. PLANTSUPPORT...............................

~...........

~ ..

26

V. MANAGEMENTMEETINGS

X1

Exit Meeting Summary.......

~ ~.......

X3

Management

Meeting Summary

X3.1

SALP Meeting .... ~...........

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26

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27

ATTACHMENT

Attachment

1 - Partial List of Persons

Contacted

- Inspection Procedures

Used

- Items Opened,

Closed, and Updated

- List of Acronyms Used

REPORT DETAILS

Nine Mile Point Units

1 and 2

50-220/96-1 0 8E 50-41 0/96-1 0

July 28 - September 7, 1996

SUMMARYOF ACTIVITIES

Niagara Mohawk Power Corporation (NMPC) Activities

Unit 1

During this inspection period, Nine Mile Point Unit

1 (Unit 1) operated

at varying

reactor power levels due to mechanical difficulties with the ¹13 shaft-driven

feedwater pump.

On July 29, Unit

1 was shutdown to evaluate

and repair the ¹13

feedwater pump clutch mechanism;

additional activities during the outage included

a drywell entry to repack a main steam isolation valve and repair an inoperable

safety relief valve acoustic monitor and thermocouple.

On August 3, Unit 1 was

restarted, but reactor power was limited to approximately 46% because

the repairs

to ¹13 feedwater pump were unsuccessful.

Unit

1 was again shutdown on August

8 to repair ¹13 feedwater pump, and investigation identified damaged

dental clutch

gear teeth.

Unit

1 was restarted

on August 11, but reactor power was still limited

to 46% while an engineering

evaluation determined

a course of action for repair of

the ¹13 feedwater pump.

On August 17, Unit 1 was shutdown, ¹13 feedwater

pump was repaired successfully,

and the unit was restarted

on August 21,

achieving full power on August 23.

Unit 1 operated

at essentially 100% reactor

power for the remainder of the period.

Unit 2

Nine Mile Point Unit 2 (Unit 2) maintained essentially 100% power throughout the

period, with a short reduction to 85% power on August 14 due to maintenance

on

the control building chilled water system.

Nuclear Regulatory Commission (NRC) Staff Activities

Ins ection Activities

The NRC resident inspectors performed inspections of the licensee's activities

in

the areas of operations,

maintenance

and surveillance, engineering,

and plant

support.

The inspectors conducted their inspections during normal, backshift, and

weekend hours.

There were no specialist inspections conducted

during this period.

The results of the inspection are contained

in this report.

U dated

Final Safet

Anal sis Re ort

UFSAR Reviews

A recent discovery of a licensee operating their facility in a manner contrary to the

UFSAR description highlighted the need for additional verification that licensees

were complying with UFSAR commitments.

While performing the inspections

discussed

in this report, the inspectors reviewed the applicable portions of the

UFSAR related to the areas inspected.

The inspectors verified that the UFSAR

wording was consistent with the observed

plant practices, procedures

and/or

parameters,

with the following exception.

The description of the

Unit 2 emergency

ventilation system does not discuss the interlock associated

with the unit cooler

test damper (see Section E2.1).

I. OPERATIONS

01

Conduct of Operations (71707)

'1.1

General Comments

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of

ongoing plant operations.

In general, the conduct of operations was professional

and safety-conscious;

specific events and noteworthy observations

are detailed in

the sections below.

01.2

Unit

1 Shutdown to Re air the Shaft Driven Feedwater

Pum

a.

Ins ection Sco

e

On July 28, 1996, Unit 1 was shutdown to repair the ¹13 shaft driven feedwater

pump.

The inspectors reviewed plant procedures

prior to the scheduled

shutdown

(N1-OP-43A, "Reactivity Control," and N1-OP-43B, "Balance of Plant Startup and

Shutdown" ), attended the pre-evolution briefing held by the Station Shift Supervisor

(SSS), and observed portions of the shutdown.

Observations

and Findin s

On July 28, 1996, the inspectors monitored Unit

1 control room operations

associated

with the normal plant shutdown to repair the shaft driven feedwater

pump.

Initial reactor power level was approximately 45%.

Plant staff verified

shutdown prerequisites

and established

the desired rod configuration.

The power

reduction and securing of the main turbine occurred without incident.

The reactor

was manually scrammed at low power to complete the reactor shutdown.

The inspectors noted that the operators

had difficulty maintaining reactor vessel

water level with the normal band.

Initially, as a result of the scram, reactor vessel

water level lowered from a normal level of 76 inches to approximately 38 inches.

High pressure

coolant injection (HPCI) initiated at 53 inches, as expected.

By

design,

HPCI is supposed

to secure at 95 inches to automatically maintain reactor

level within a pre-established

band.

However, due to leakage past the feedwater

Topical headings such as 01, M8, 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 that was used as inspection guidance Is listed for each applicable report section.

regulating valves, and excessive flow from the control rod drive (CRD) system,

reactor vessel level continued to rise above the top of the narrow range level

instrumentation.

The operators verified that the reactor was shutdown.

All control rods indicated

fully inserted, except one.

The numeric rod position indication (RPI) for control rod 14-47 did not indicate, the green "full-in"lights for the rod on the full-core display

were not lit, and the process computer identified the rod position as full out.

The

confusion over the position of control rod 14-47 delayed resetting of the scram for

nearly one hour.

This delay exacerbated

the problem with the rising reactor vessel

water level, as full CRD flow continued until the scram was reset.

The SSS

discussed

the problem with the Operations Manager and concluded that procedure

N1-OP-43A allowed the scram to be reset to verity that all control rods were

inserted.

The scram was reset and control rod 14-47 indicated fully inserted.

Subsequently,

a procedure

change was processed

to make it consistent with the

associated

emergency operating procedure

(EOP), N1-EOP-3.1, Rev. 1, which

required the scram to be reset to allow for alternate control rod movement in the

event a rod was stuck.

The inspectors

observed the SSS's pre-evolution brief, which broadly reviewed the

upcoming shutdown

and outage work scope.

But the inspectors noted that there

was little interaction between the SSS and the operating crew relative to potential

problems or past difficulties; such as previous problems with the rod position

indication on shutdowns.

Additionally, delineation of responsibilities and overall

coordination techniques

were not discussed

among the crew.

This lack of

communication and forethought may have contributed to the problems that the

crew experienced

with reactor level, or the confusion as to the proper action when

one control rod was at an unknown position.

The inspectors discussed

the

shutdown with the SSS, who concurred that the shutdown did not go smoothly.

The SSS stated that the crew had not performed

a shutdown recently, and that

training in the simulator would have been beneficial in reviewing plant response

and

clarifying operator roles and responsibilities.

On August 17, the loss of RPI for the same control rod recurred during a

subsequent

shutdown with a scram from =5% power.

During this scram, the full-

core display again failed to identify position for control rod 14-47; however, the

process computer indicated the rod had inserted.

When questioned

by the

inspectors, the system engineer indicated these losses of RPI were due to failures in

the RPI system probe buffer card and the full-in over-travel reed switch.

The buffer

card was replaced,

and the reed switch is scheduled for additional troubleshooting

during the next extended

outage.

Conclusions

The shutdown did not progress smoothly.

Difficulties were noted with respect to

controlling reactor vessel water level, and there was confusion regarding the proper

action when one control rod was at an indeterminate position.

The inspectors

considered the SSS briefing weak, in that it did not include significant detail of the

planned shutdown nor a discussion of past problems.

This may have caused

some

the problems noted by the inspectors.

Unit 1 Startu

Ins ection Sco

e

The inspectors observed control room operations during a plant- startup on August

20, 1996.

Specifically, the inspectors

monitored part of the startup prerequisite

verification, the initial reactor startup, power ascension,

and post-maintenance

testing of the shaft-driven feedwater pump.

Observations

and Findin s

During the reactor startup, the inspectors noted that operations management

was

present to observe the evolution.

Prior to the special evolution (power ascension

and testing of the shaft-driven feedwater pump), the Operations Manager conducted

a Management

Expectations

Briefing with the crew in accordance

with procedure

GAP-SAT-03, "Control of Special Evolutions," Revision 02, Section 3.4.1.

The

discussion included management's

expectations for conduct of operations,

detailed

hardware and operational changes

pertaining to the ¹13 feedwater pump temporary

modification, and addressed

the upcoming schedule of events.

The startup was completed without incident.

The inspectors noted that a quality

assurance

(QA) auditor monitored the power ascension

and the post-maintenance

testing of the ¹13 feedwater pump.

Also, subsequent

to criticality and prior to

placing the unit online, Unit 1 operations management

was present to observe the

conduct of control room operations.

Additionally, the inspectors noted that a Unit 2

senior reactor operator (SRO) monitored Unit 1 control room activities, as an

independent

observer, to identify weaknesses

and ways to develop consistency

between the units.

Conclusions

Management oversight of the reactor startup was good, and the pre-evolution brief

was detailed and safety-focused.

The control room staff demonstrated

a

questioning attitude and the briefing appeared

synergistic.

The presence

of QA and

a Unit 2 SRO in the control room during the startup was a positive attribute.

Operational Status of Facilities and Equipment (71707)

Unit

1 Control Rod Uncou lin s

Ins ection Sco

e

During this inspection period, the licensee identified two potential control rod drive

(CRD) uncouplings

at Unit 1

~ The inspectors discussed

current and previous CRD

uncouplings with plant management

'and staff; reviewed licensee Deviation/Event

Reports (DERs), including potential causes

and proposed/completed

corrective

actions; and reviewed General Electric (GE) Service Information Letter (SIL) No.

052, Supplement

2 (dated July 31, 1974) and Supplement

3 (dated March 17,

1989) relating to CRD anomalies.

Observations

and Findin s

On July 31, 1996, CRD 46-27 was being continuously withdrawn as part of startup

prerequisites.

The plant was shutdown with the mode switch in REFuEL.

During the

rod withdrawal, the over-travel annunciator alarmed, indicating that the rod was

potentially uncoupled.

The rod was fully inserted and probably recoupled.

During a

subsequent

withdrawal, the rod again indicated uncoupled.

The Operations

Manager was concerned that the estimated position for CRD 46-27 during the

upcoming startup would be approximately 12 inches, and uncoupling checks could

not be performed at this rod height.

Therefore, plant management

decided, after

discussion with reactor engineering

personnel, to fully insert the rod, declare the rod

inoperable, valve it out of service, and perform repairs during the upcoming

refueling outage (RFO14) in Spring 1997.

On August 6, 1996, a second

CRD (¹ 18-35) indicated that it was uncoupled during

the weekly uncoupling checks.

The rod was inserted and verified recoupled,

and

returned to the previous position, in accordance

with Procedure

N1-OP-5.

NMPC stated that CRD uncouplings were uncommon at Unit 1; however, in

1991/1992, five CRD uncouplings occurred during that fuel cycle period.

NMPC

documented

the uncouplings on four DERs.

Four of the five CRD units were

replaced during the next refueling outage,

and the other CRD unit was replaced

during a later forced outage.

Since 1992, no other CRD uncouplings were

documented.

Of the five 1991/1992 CRD uncouplings,

one resulted from separation

of the inner

filter from the stop piston.

During rod withdrawal, the inner filter impacted against

the uncoupling rod with sufficient force to uncouple the drive from the rod.

Inner

filter separation

could be attributable to either improper inner filter installation or

distortion/wear of the inner filter latching spring.

A second uncoupling was

attributed to a bent uncoupling rod in the center spud hole; NMPC assumed

the

most probable cause was that the uncoupling rod was reversed

in the spud base,

permitting the uncoupling rod to move within the spud.

The root causes of the

remaining three CRD uncouplings were not positively determined.

The inspectors'eview

of GE SIL 52 identified that all CRD uncoupling problems

were attributed to internal drive problems.

The probable causes

were:

1) improper

installation and engagement

of the inner filter; 2) improper positioning of the control

rod lock plug due to binding of the lock plug shaft or uncoupling D-handle; 3) crud

buildup on the inner filter; or 4) the wrong uncoupling rod or mispositioning of the

uncoupling rod.

GE also determined

~;at if a drive uncoupled

and was subsequently

recoupled, the drive was considered

operable; however, motion should be restricted

0

to jog only mode of withdrawal operation and the drive should be removed for filter

screen inspection and replacement

during the next scheduled

outage.

Although CRD uncoupling was not a common industry occurrence,

NMPC

documented

their evaluation of the GE SIL against the potential for this to occur at

Unit 1.

From an accident perspective,

an uncoupled

rod could result in a positive

reactivity excursion due to a dropped rod, which is an analyzed condition.

The

inspectors did not identify any safety concerns.

C.

Conclusions

NMPC's decision to declare CRD 46-27 inoperable due to recurring uncouplings

and

the inability to verify coupling at the projected critical rod height appeared

appropriate

and conservative.

02.2

Unit 2 RCIC Walkdown

The inspectors walked down the accessible

portions of the Unit 2 reactor core

isolation cooling (RCIC) system, and reviewed the recently completed surveillance

tests for the system (N2-OSP-ICS-001) to verify operability.

The material condition

of the components

and the general housekeeping

were acceptable,

with the

exception of a minor packing leak on the steam trap bypass valve.

NMPC was

aware of the steam leak, had scheduled it for repair, and completed the repairs

subsequent

to the end of the reporting period.

08

Miscellaneous Operations Issues (90712, 92700, 92910)

08.1

Closed

Unit 1 S ecial Re ort: ¹12 Dr well Hi h Ran

e Gamma Radiation

Monitorin

S stem Ino erable

On March 25, 1996, with Unit

1 operating at 100% reactor power, NMPC declared

the ¹12 drywell high range gamma radiation monitoring system inoperable to

replace

a resistor.

During the period when ¹12 drywell high range gamma radiation

monitoring system was out of service, the redundant system was operable.

Repairs

were completed on March 26, and NMPC returned the system to service following

post-maintenance

calibration.

NMPC submitted

a special report to the NRC within 14 days, as required by Unit

1

Technical Specifications (TS) 3.6.11-1, Action Statement Table 3.6.11-2 (3a)

~ The

inspectors reviewed the special report and confirmed that all required information

was provided.

08.2

Closed

Unit 1 S ecial Re ort: ¹12 Dr well Hi h Ran

e Gamma Radiation

Monitorin

S stem lno erable

On August 11, 1996, with Unit

1 reactor mode switch in sTARTuP, NMPC removed

the ¹12 drywell high range gamma radiation monitoring system from service due to

a downscale indication.

Instrument and control (ISC) technicians checked the

calibration of the system and found no out-of-tolerance condition.

The IRC

technicians

also performed

a wire integrity check and source check, but noted no

abnormalities.

During the period when ¹12 drywell high range gamma radiation

monitoring system was out of service, the redundant system was operable.

NMPC

declared the system operable on August 13, after calibration and a 24-hour period

of monitoring.

NMPC submitted

a special report to the NRC within 14 days, as required by Unit 1

TS 3.6.11-1, Action Statement Table 3.6.11-2 (3a).

The inspectors reviewed the

special report and confirmed that all required information was provided.

08.3

Closed

VIO 50-220 95-03-01: 0 erator Actions Contrar

to Procedures

In April 1995, Unit 1 experienced

a reactor scram due to a turbine trip. During the

post-scram review, NMPC identified two cases where procedures

were not properly

implemented:

During the immediate actions following the scram, the Chief Shift Operator

(CSO - a licensed reactor operator) failed to properly position the reactor

mode switch.

After the scram, during troubleshooting

to determine why Power Board ¹11

failed to automatically transfer to the reserve power supply, it was

determined that an operator had not performed an electrical continuity check

of the fast transfer control circuitry after the turbine generator was paralleled

to the grid on the previous startup.

NMPC attributed the cause of both of the above instances to operators not self-

verifying correct completion of all necessary

actions after the conclusion of the

activity.

In addition, the SSS failed to ensure that personnel

on his shift had

referred to the appropriate procedures

to verify implementation,

as written. The

corrective actions included a reinforcement of specific procedural requirements

and

NMPC's expectations

regarding the use and adherence

to procedures

and self-

checking.

The inspectors considered

the corrective actions acceptable.

08.4

Closed

URI 50-220 95-03-02:

Procedures

not Consistent with Technical

S ecifications

During a review of the reactor scram in April 1995 (discussed

in Section 08.3), the

inspectors considered

certain procedures

were not consistent with Unit 1 TSs.

Specifically, the scram procedure

(N1-SOP-01, "Reactor Scram" ) and the EOP for an

anticipated transient without a scram (NMP1-EOP-3, "Failure to Scram" ) allowed the

reactor mode switch to be left in the REFUEL position.

When in the hot shutdown

condition, the Unit

1 TS required the mode switch to be in the sHuToowN position

except for scram recovery operations.

As a result of discussions with the NRC

inspectors,

NMPC initiated DER 1-95-1241.

NMPC determined that the procedures

were acceptable,

as written, but that the

implementation needed clarification.

By placing the mode switch in the REFUEL

position, the operators

are able to manipulate control rods, as necessary,

to insert

any control rods that did not settle at position "00" on the scram; if no rod

movement was being attempted,

the mode switch was to be in the sHuTDowN

position.

The associated

procedures

were changed to reflect the clarifications

discussed

above; i.e., maintaining the mode switch in REFuEL while in the hot

shutdown condition for reasons

other than scram recovery, is not permitted.

The

inspectors considered the corrective actions acceptable.

08.5

Closed

URI 50-220 95-16-01:

Weak Initial 0 erabilit

Determinations

ln September

1995, based on discussions with the SSS and a review of the SSS

log, the NRC identified two instances where initial operability determinations

by

shift supervision were considered

weak.

NMPC initiated a review of the specific

instances

and determined that the SSS had performed an appropriate operability

determination, but had not clearly documented

the basis for the determination

in the

SSS log. The inspectors reviewed the associated

DER and the specific final

operability determination

and discussed

the concern with NMPC operations

management.

The inspectors

have since observed that the bases for operability

determinations

are better documented.

The inspectors

had no further questions

regarding this item.

II, MAINTENANCE

'VI1

Conduct of Maintenance (61726, 62703, 62707)

Using Inspection Procedures

61726, 62703, and 62707, the inspectors periodically

observed plant maintenance

activities and performance of various surveillance tests.

In general, maintenance

and surveillance activities were conducted

professionally,

with the work orders (WOs) and necessary

procedures

at the work site and in use,

and with the appropriate focus on safety.

Specific activities and noteworthy

observations

are detailed in the sections below.

The inspectors reviewed

procedures

and observed

portions of the following maintenance/surveillance

activities:

~ WO 96-10638-00

~ N2-ISP-MSS-R1 09

~ N2-OSP-CSL-R@002

~ WO 96-1 1 21 9-01

~ WO 96-11219-02

Troubleshooting

of Division II H,/0, Monitor

Main Steam Line High Radiation Monitors Instrument

Channel Calibration

Hydrostatic Leakrate Test for 2CSL" MOV112

Lower Setpoint for Condensing

Water on Chiller

2HVK "CHL-1A

Lower Setpoint for Condensing

Water on Chiller

2HVK"CHL-1 B

Surveillance activities are included under "Maintenance."

For example, a section involving surveillance observations might

be Included as a separate sub.topic under M1, "Conduct of Maintenance."

4 N2-IPM-SWP-R109

0 N2-OPS-GTS-M001

o

N1 ST Q'IB

GAP-OPS-02

4 GAP-PSH-01

NIP-PRO-04

Calibration of the Control Building Service Water Flow

Instrument Channels

Standby Gas Treatment System Functional Test

Core Spray Loop 12,Pumps

and Valves Operability

Control of Hazardous

Energy and Configuration Tagging

Work Control

Procedure

Change Evaluations

Unit 2 Main Steam Line Radiation Monitor Failures

lns ection Sco

e

The inspectors reviewed the troubleshooting,

repair, and post-maintenance

testing

activities associated with repetitive failures of the Unit 2 main steam fine (MSL)

radiation monitor on August 29, and September

3, 1996.

The inspectors

also

reviewed the applicable TS sections,

and discussed

the method used by NMPC to

declared the system operable following the corrective maintenance.

Observations

and Findin s

On August 29, during a walkdown of the control room main control panels, the

oncoming Assistant Station Shift Supervisor (ASSS) observed that the "8" MSL

radiation monitor (2MSS" RT46B) was reading abnormally high.

A review of the

three previous shift checks identified that the indications were normal ~ The

radiation monitor was declared inoperable and TS 3.3.1 was entered.

The TS

action statement

requires placing the inoperable channel in a tripped condition

within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

This causes

a

~/~ trip signal for the nuclear steam supply shutoff

system (NSSSS) and a

~/~ reactor protection system

(RPS) scram.

DER 2-96-2054

was written to address

the failure concurrent with initiation of repair activities.

Troubleshooting

identified that the detector was working properly but that the

monitor control panel drawer had a problem.

NMPC replaced the suspect drawer

with a functioning spare drawer.

Subsequent

investigation identified a bad module

in the drawer.

The troubleshooting

and repairs took longer than twelve hours to complete.

Thus,

NMPC took the required actions and inserted the channel trips, as required by the

TS limiting condition for operation (LCO) ~

On August 30, the routine calibration

(N2-ISP-MSS-R109, "Main Steam Line High Radiation Monitors Instrument Channel

Calibration," Revision 1) was being used for post-maintenance

testing to determine

the radiation monitor operability.

During the post-maintenance

testing on August 30, the inspectors observed that the

LCO required trips were cleared in support of testing.

The inspectors questioned

shift management

regarding removal of the trips while the LCO action statement

was still in effect.

The SSS informed the inspectors that the trips had to be cleared

to perform the surveillance test before the channel could be declared operable.

Additionally, the SSS stated that this had been discussed

with operations

10

management;

and referred to the basis section associated

with TS 4.0.3, which

states that surveillance requirements

have to be met to demonstrate

that inoperable

equipment has been restored to operable status.

Not withstanding the above justification, the removal of the LCO-required trips prior

to declaring the MSL radiation monitor operable appears to be a violation of TS 3.3.1

~

NMPC disagrees with this interpretation of the TS and, subsequent

to the

inspection period, issued

a letter to the NRC (dated October 21, 1996), requesting

a

clarification of a "... longstanding

[industry] position that permits the conduct of

certain technical specification surveillance and testing needed to demonstrate that

previously inoperable equipment has been restored to an operable condition."

Pending

an evaluation of this issue by the NRC Office of Reactor Regulation (NRR),

and a review of the NRR response

to NMPC, this item will remain unresolved.

(URI 50-41 0/96-10-01)

On September

3, operators

again observed that radiation monitor 2MSS" RT468

was spiking from 650 mrem/hour to 1450 mrem/hour.

The radiation monitor was

declared inoperable

and troubleshooting

identified a bad connector between the

drawer and the detector.

The connector degradation

was apparently due to heat,

but manipulation of the cable and connector during the August 30~ troubleshooting

and testing may have contributed to connector failure.

Although NMPC has had no indication of problems with the other three channels of

MSL radiation monitoring, they checked the local temperatures

for all of the MSL

radiation monitor connectors

and found them within vendor recommendations.

NMPC also intended to examine the remaining connectors

during the upcoming

refueling outage.

The inspectors considered this action to be appropriate.

NMPC replaced the connector for MSL radiation monitor 2MSS" RT468 and was

able to determine operability of the affected portions of the radiation monitor

without removing the LCO required trips.

The inspectors, through discussions with

the work supervisor,

and review of the repairs and plant drawings, verified that the

post-maintenance

testing was adequate.

Conclusions

Troubleshooting

activities for both MSL radiation monitor failures were methodical

and thorough.

The examination by NMPC for similar connector degradation was

considered

appropriate.

However, removal of the LCO required trips, prior to

declaring the MSL radiation monitor operable,

appeared

to be a violation of TS;

furthermore, the need to remove LCO required trips to complete the testing to

determine operability is not limited to the MSL radiation monitors.

This item is

unresolved

pending further NRC review.

11

M1.2

Unit 2 LPCS Pum

Suction Valve Leak Rate Testin

Ins ection Sco

e

On August 27, 1996, leak rate testing on the Unit 2 low pressure

core spray (LPCS)

pump suction valve failed due to the inability to achieve rated test pressure;

subsequent

testing was successful.

The inspectors

observed

portions of the retest,

reviewed the test procedure,

and discussed

the test with NMPC staff.

b.

Observations

and Findin s

During performance of procedure

N2-OSP-CSL'-R@002,

"Hydrostatic Leakrate Test

for 2CSL" MOV112," Revision 2, Unit 2 operators were unable to reach the required

test pressure of 50-52 pounds per square inch gage (psig).

While trying to

pressurize the space between motor operated

valve (2CSL" MOV112) and the

manual isolation valve (2CSL "V121), the operators injected approximately 30

gallons of water and only raised pressure

from 5 psig to 17 psig.

The test was

considered

unsatisfactory

and appropriate actions were taken in accordance

with TS

for an inoperable containment isolation valve.

Additionally, a DER was written to

address the test failure.

Based on previous successful

leak rate testing of MOV112, and other MOVs in

similar plant configurations,

NMPC evaluated the test failure and believed that the

manual isolation valve was not completely closed, possibly due to foreign material

on the valve seat.

NMPC cycled open and closed 2CSL"V121, under the

appropriate administrative controls, satisfactorily retested MOV112 without any

'djustments

to the valve, and exited the LCO.

The inspectors reviewed the initial test procedure which was completed

unsatisfactorily, and discussed

the cause of the test failure with the system

engineer,

Based on the discussion

and a review of the DER disposition, the

inspectors considered

the cause reasonable.

C.

Conclusions

The inspectors considered

the analysis to determine the cause of the LPCS pump

suction valve surveillance failure to be good.

Subsequent

retest of the valve was

successful

and timely.

M2

IVlalntenance and Material Condition of Facilities arid Equipment

(61726, 62703)

M2.1

Re airs to Unit

1 Shaft Driven Feedwater

Pum

a.

Ins ection Sco

e

The friction clutch for the Unit

1 ¹13 shaft-driven feedwater pump failed to engage

during a power ascension

on July 22, 1996.

The inspectors reviewed the

associated

troubleshooting,

evaluation,

and repair activities; discussed

the course of

0

12

action with plant staff and management;

attended review meetings,.and

reviewed

applicable DERs,

design document changes,

temporary modifications, and

applicability reviews.

Observations

and Findin s

On July 19, 1996, the ¹13 shaft-driven feedwater pump was secured

as part of a

scheduled

power reduction to inspect and clean the main turbine condenser water

boxes.

On July 21, while attempting to engage the feedwater pump friction clutch

prior to increasing power, the clutch failed to adequately

engage,

resulting in the

inability to achieve required speed.

The licensee determined that failure of the

friction clutch to engage was due to internal binding of an associated

solenoid

operated valve (SOV-29-01 V1A/B), which resulted in insufficient oil pressure to the

friction clutch.

A representative

from the vendor, Philadelphia Gear, noted

discoloration of the valve internals, presumed to be a result of lubricating oil

breakdown,

and concluded that the SOV failed from age-related

wear.

The SOV

was replaced,

and two additional SOVs used under similar operational conditions,

were identified and replaced.

DER 1-96-1696 was written to identify these

deficiencies.

On July 22, following repairs on the shaft-driven feedwater pump, NMPC personnel

cleared the markup to conduct post-maintenance

testing.

However, the SOV was

left in the "engaged" position; and when control power and actuating oil pressure

were restored

as part of the markup clearance, the friction clutch tried to engage

the output shaft which was locked in position with the maintenance

pin. The pin is

designed to prohibit movement of the feed pump output shaft.

This resulted in

damage to the clutch mechanism.

When plant personnel

removed the pin, the shaft

started to rotate.

This could have resulted in serious personal injury and was

considered

a "near-miss" by NMPC. The licensee issued

DER 1-96-1718 to address

this issue and determine the root cause.

Unit 1 was shutdown on July 28 to

perform repairs.

Plant management

conducted

"tail-gate" training with all

maintenance

and operations personnel relative to the personnel

errors described

above.

The training included

a discussion of what happened,

how the activity

should have been performed, and the potential consequences.

Unit 1 was restarted

on August 3, with reactor power limited to approximately

46% because

of the inoperable shaft-driven feedwater pump.

On August 7, during

startup of the ¹13 pump, the dental clutch failed to properly engage.

On August 8,

NMPC took the unit off-line. NMPC identified two possible reasons for why the

dental clutch did not engage:

(1) a gasket was missing on a control oil supply

line spectacle flange, and (2) the constant bleed ports for the friction clutch

had been clogged, but were cleaned

and opened.

The system engineer stated that

the combination of the gasket and the constant bleed ports probably lowered the

friction clutch actuating oil pressure,

allowed slippage of the friction clutch,

and caused dental clutch damage.

The speed mismatch of the feedwater pump

input and output shafts resulted in the damage to the dental clutch.

The plant

was again restarted

on August 11, with the shaft-driven feedwater pump

inoperable,

and operated

at approximately 46% rated thermal power until another

0

13

outage on August 17.

NMPC was informed that repairs to the dental clutch would

take about 15 weeks.

After considering several options, NMPC elected to operate

the pump solely on the friction clutch.

Unit

1 was restarted

on August 22, post-maintenance

testing was completed

satisfactorily, and the unit returned to full power on August 23.

The inspectors

noted that NMPC's technical meetings were thorough and safety-focused,

and the

engineering applicability review per 10 CFR 50.59 was determined to be

appropriate.

C.

Conclusions

Failure to confirm the position of the SOV following maintenance,

and poor

coordination between the ltkC technicians

and operations personnel

during clearing

of the markup, resulted in friction clutch engagement

with the maintenance

pin

installed.

Also, plant personnel who removed the pin could have sustained

serious

personal injury.

The technical review meetings were thorough and safety-focused.

Plant

management

raised numerous technical and operational concerns, that were

subsequently

resolved.

Overall, the inspectors determined that the final repairs

appeared

appropriate

and were technically sound.

However, personnel inattention

resulted in damage to the clutch mechanism,

and could have resulted in a serious

personal injury.

M2.2

Unit 1 Control Rod Scram Solenoid Pilot Valve Dia hra

m Re lacement

In the fall of 1995, industry concerns

regarding slow scram insertion times were

identified.

Particularly, the 5% insertion times were found to be increasing for

scram solenoid pilot valves (SSPVs) equipped with Viton diaphragms.

At Nine Mile,

only Unit 1 was affected, since Unit 2 SSPVs are of a different design.

As

documented

in NRC Inspection Report 50-220/96-02,

NMPC initiated periodic at-

power scram time testing, as recommended

by the Boiling Water Reactor Owner's

Group's (BWROG's) Regulatory Response

Group (RRG), to address the concern.

Since the concern was identified, NMPC had been replacing the Unit

1 Viton

diaphragms with new Buna-N diaphragms.

By August 11, 1996, all Unit 1 SSPV

Viton diaphragms were replaced with the new material and tested satisfactorily.

Subsequently,

NMPC terminated the periodic at-power scram time testing at Unit 1

~

Since February 1996, the inspectors

have periodically monitored the diaphragm

replacements,

discussed

and observed

NMPC's actions to resolve the concern with

the Viton diaphragms,

and noted no concerns.

0

14

M2.3

Unit 2 TS Re uired Shutdown due to Both Divisions of the Control Buildin

Chilled

Water S stem lno erable

Ins ection Sco

e

On August 13, 1996, the Unit 2 SSS initiated a plant shutdown because

both

divisions of the control building chilled water system were inoperable.

The

inspectors monitored portions of the shutdown and the maintenance

activities to

return the systems to service; this included

a review of the maintenance

and

surveillance packages,

the shutdown procedure,

and the administrative procedures

supporting the work.

b.

Observations

and Findin s

When starting the Division 2 emergency

diesel generator

(EDG) for a planned

surveillance test, the Division 2 control building chiller automatically tripped due to

low service water flow. The chiller is part of the control building chilled water

system, which is a subsystem

of the control room outdoor air special filter train

system.

The special filter train system

is an emergency system that ensures

the

control room and remote shutdown rooms are capable of being maintained habitable

during post-accident

modes of plant operation by diverting outside air through

a

charcoal filter. The chillers support the operation of the special filter train by

cooling the outside air.

In accordance

with the Unit 2 TS 3.7.3, the Division 2

control building outdoor air special filter train system needed to be declared

inoperable.

The chiller tripped at 10:26 a.m. on August 13, at which time the SSS declared the

Division 2 chiller inoperable.

With one division of the special filter train system

inoperable, the TS LCO action statement allows 7 days for repairs or the plant must

be shutdown.

NMPC engineering determined that the trip setpoint for the low

service water flow automatic action was set too high, and had been since June

1989, when the low trip setpoint was increased from 215 gallons per minute (gpm)

to 250 gpm.

It was determined that the Division

1 chiller was also affected, and

the SSS declared that chiller inoperable at 5:11 p.m. With both divisions of the

special filter train system inoperable, TS 3.7.3 is not applicable.

TS 3.0.3 states

that when an LCO cannot be met, place the plant in an operational condition where

the TS does not apply.

In this case, the plant was required to be shutdown within

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Power reduction was started at 5:45 p.m.

Coincident with shutdown activities,

engineering

reviewed the design of the service water system in conjunction with the

anticipated demands

on the system during accident conditions.

They determined

that the low flow setpoint could be adjusted from the current 250 gpm to 210 gpm.

Maintenance work orders were initiated to adjust the trip setpoints

(WO 96-11219-

01 and WO 96-11219-02, Lower Setpoint for Condensing

Water on Chillers

2HVK"CHL-1A and 2HVK"CHL-1B, respectively).

The Division

1 chiller was

declared operable after the flow setpoint had been adjusted

and satisfactorily

0

15

tested.

At 8:11 p.m., power reduction was stopped at 85% and Unit 2 exited TS 3.0.3.

Power was returned to 100% the same day.

NMPC's preliminary determination of the cause for the low setpoint for the service

water flow trip was inadequate

design.

Pending completion of the engineering

evaluation by NMPC and NRC review, this item will remain unresolved.

(URI 50-41 0/96-1 0-02)

The inspectors reviewed the work orders and monitored part of the trip setpoint

adjustment.

The work orders were technically correct and the adjustments

were

performed correctly and without incident.

During the review of the change to the

surveillance procedure for the calibration of the chiller service water flow

instruments that was used for the post maintenance

test, the inspectors identified

that the procedure

change evaluation

(PCE) form was incorrectly completed.

Specifically, the preparer of the PCE and the responsible

procedure owner (RPO)

were the same person.

Per NMPC Procedure

NIP-PRO-04, "Procedure

Change

Evaluations," Paragraph 3.3.1.a, the RPO must be an individual other than the

preparer.

Another qualified RPO reviewed and approved the PCE before work

continued;

and the original RPO generated

a deviation/event report (DER 2-96-1906)

to document the problem and initiate corrective actions to prevent recurrence.

The

failure to properly complete the PCE form is a violation of TS 6.8.1.

Based on the

immediate corrective actions and low safety consequence,

this NRC identified

violation is being treated as a Non-Cited Violation, consistent with Section IV of the

NRC Enforcement Policy.

C.

Conclusion

The SSS recognized the effect of the chiller tripping during the test of the EDG and

took the appropriate actions related to one inoperable division of the control building

outdoor air special filter system.

When the second division was also deemed

inoperable, the actions required by TS 3.0.3 were initiated coincident with

adjustments to the flow switches.

NMPC's preliminary determination of the cause

for the service water flow trip low setpoint was inadequate

design.

M3

Maintenance Procedures

and Documentation (61726, 62703, 62707)

M3.1

Procedure

Chan

es Not in Accordance with TS Re uirements

Ins ection Sco

e

During the review of the procedure

change evaluation

(PCE) forms associated

with

the repairs of the control building chillers discussed

in Section M2.3 of this report,

the inspectors noted that the procedure was not consistent with the requirements of

Unit 2 TSs.

16

Observations

and Findin s

TS 6.8.3 requires temporary changes

to procedures

be approved by two members

of the unit management

staff, at least one of whom holds an SRO license on the

affected unit.

NIP-PRO-04, "Procedure Change Evaluations," paragraph 3.3.3.c,

does not require an SRO approval; only an RPO approval is needed for editorial

corrections.

NMPC site-common procedure

NIP-PRO-04 has defined

a type of procedure

change

called an "editorial correction."

Editorial corrections included enhancing existing

information already in the procedure that was not technical, correcting obvious non-

technical errors to existing information, updating reference numbers to other

documents

or correcting misspellings,

and other administrative type of correction.

This practice is not uncommon

in the nuclear industry.

However, NIP-PRO-04 also

allowed design changes to be considered

as "editorial corrections."

Editorial

correction Criterion 3, allowed one-for-one changes to existing information to

incorporate changes to controlled design documents.

The changes

needed to be

entirely supported

by the reviews and approvals for the design document.

The

design document shall be referenced

on the PCE and may include EDC [Engineering

Design.Change]/DCRs

[Document Change Requests],

specifications,

or approved

calculations (such as setpoints by EDCs).

To revise the chiller service water low flow setpoint,

a PCE was generated

for

surveillance Procedure

N2-IPM-SWP-R109, "Calibration of the Control Building

Service Water Flow Instrument Channels."

The PCE was classified as an editorial

correction, with RPO approval only. A change to the acceptance

criteria should be

considered

a technical change,

and SRO approval is required.

The failure to obtain

SRO approval of the temporary change prior to implementation

is a violation of

Unit 2 TS 6.8.3.

(VIO 60-410/96-10-03)

Conclusion

A shrong procedure review and approval process

should have identified that the

PCE procedure was not consistent with the requirements of the Technical

Specifications.

This is another example where the NRC has recently identified a

programmatic procedure that departs from the requirements

of the license.

A past

example was discussed

in NRC Inspection Report 96-01, and related to the

implementation of temporary modifications prior to the completion of the required

safety evaluations.

Maintenance Staff Knowledge and Performance (61726, 62703, 62707)

Personnel

Performance

The inspectors reviewed the below three maintenance-related

issues,

all associated

with personnel performance

errors.

The review included applicable portions of the

SSS and CSO logs, plant procedures,

Licensee Event Reports (LERs), DERs, the

17

UFSARs and TSs.

Also, the inspectors

held discussions

with plant personnel

and

management

regarding these events.

Unit

1 - inadvertent scram of the wrong control rod;

Unit 1 - calculation error not identified during core spray surveillance; and

Unit 2-- maintenance

on the wrong division of H,/0, monitoring.

The details associated

with these issues are provided in the following three

sections, with an overall conclusion provided in Section M4.5 of this report.

Unit 1 Inadvertent Scram of a Sin le Control Rod

On July 26, 1996, with Unit 1 operating at approximately 45% power, control rod 18-31 had been fully inserted and removed from service to support maintenance

activities on the associated

hydraulic control unit (HCU). During the application of

the markup for HCU 18-31, the operator applying the markup removed the fuses for

the wrong control rod (38-31), causing rod 38-31 to scram from the fully

withdrawn position.

(A markup is a component tagging process

used to provide

protection for personnel

and/or equipment during operation, maintenance

and

modification activities. Within the industry, this is commonly referred to as a

tagout.)

The control room operators identified the error, instructed the operator to

replace the fuses for control rod 38-31, and complete the markup of HCU 18-31.

The SSS conferred with Reactor engineering,

and control rod 38-31 was restored to

the fully withdrawn position.

NMPC reactor engineering

informed the inspectors that the!mpact of the

inadvertent rod scram on the plant was minimal, due to the low power level at the

time of the event.

The inspectors considered

NMPC's immediate actions to recover

from the event to be appropriate.

As noted on the associated

DER, the apparent

cause was that the operator failed to

verify the correct component prior to removing the fuses.

NMPC also determined

that a contributing factor was the operator's self-imposed schedular pressure to

prepare for shift turnover.

As a result of this event, the individual involved was counseled

and Unit 1

operations management

generated

a night order to emphasize

their expectation of

concurrent verification during the application of markups associated

with HCU

maintenance.

Concurrent verification was defined as a second checker positively

identifying the correct component

and intended action before any actions are taken.

NMPC's expectation regarding the use of concurrent verification was already

provided in the Unit 1 Operations

Reference

Manual

~ Through discussions

with

Unit 1 personnel,

the inspectors ascertained

that prior to this event, HCU markups

were completed using independent

verification and not the more conservative

concurrent verification.

Until recently, HCU maintenance

was not routinely

completed at power.

The inspectors considered

these corrective actions appropriate

to address this particular event.

18

The inspectors reviewed Procedure

GAP-OPS-02, "Control of Hazardous

Energy and

Configuration Tagging," Revision 6, which required the operator applying the

markup to place all necessary

devices in the required position and then apply the

completed tag.

The failure to remove the correct fuses,

as per the markup order, is

considered

an example of a procedural violation.

The violation is described

in

Section M4.5.of this report.

Calculation Error Durin

Unit 1 Core S

ra

Surveillance

On July 17, 1996, Unit 1 plant management

determined that the unit had been

operated

in a condition prohibited by TS since June 6, 1996.

Specifically, a

calculational error, during the performance of surveillance test procedure

N1-ST-

Q1B, "Core Spray Loop 12 Pumps and Valves Operability," was identified for core

spray topping pump 121 (CSTP-121) differential pressure

(dp).

The surveillance

test involved throttling core spray system flow to meet prescribed procedural

guidance values and obtain flow data.

The control room operators

used this data to

perform additional calculations to determine pump differential pressure.

The operator who performed the initial calculations omitted a pressure

correction

factor8or gauge elevation.

During the same shift, the ASSS discovered the error

and corrected

a portion of the calculation, the result of which was to be carried

forward to subsequent

steps.

However, the ASSS failed to carry the corrections

through the remainder of the calculations.

The following day, the inservice testing

(IST) supervisor also failed to identify the error during his review.

The error was

finally discovered

six weeks later, July 17, during a final supervisory review. When

the error was discovered,

the licensee determined that the pump dp was higher than

the acceptance

criteria. Although the pump remained available, the pump was

declared inoperable because

the dp was outside of the acceptable

range and,

therefore, the surveillance test was unsatisfactory.

A differential pressure

higher

than expected

is normally considered

good.

However, since this was an IST

examination, the acceptable

range is determined

by the pump curves defined by the

American Society of Mechanical Engineers

(ASME) manual.

The surveillance was

reperformed

on July 17, the dp was acceptable,

and CSTP-121 was declared

operable.

The licensee's root cause was cognitive personnel

error due to inadequate

self-

checking of'calculations; also, the failure of more than one individual to identify the

error is significant.

The calculation error in performance of surveillance test N1-ST-

Q1B, and the failure to perform adequate

supervisory reviews, are additional

examples of procedural violations,

The violation is described

in Section M4.5 of this

report.

Subsequently,

NMPC issued

LER 50-220/96-06, describing this event.

The review

of the LER is contained

in Section M8.2 of this report.

19

M4.4

On July 25, 1996, while Unit 2 was operating at 100% reactor power, I&C

technicians performed troubleshooting

on the wrong division of the

hydrogen/oxygen

(H,/0,) monitoring system.

At the time of the event, the Division

2 H,/0, monitor was inoperable due to the indicated H, concentration

(1.6%) being

inconsistent with actual chemistry samples (0%).

During troubleshooting

activities

performed under WO 96-10638-00, technicians lifted leads for the Division

1 H,/0,

annunciators.

When the Division

1 annunciators

alarmed in the control room, the

operators contacted the technicians

and work was immediately stopped.

Upon

investigation, the crew determined that the steps in the WO were for lifting the

annunciator

leads for Division

1 instead of Division 2.

The Division

1 lifted leads

were reconnected,

and a DER was written to evaluate the event.

Subsequently,

the

Division 2 H,/0, indication was repaired and declared operable on July 26.

Through discussions

with maintenance

and operations

personnel,

the inspectors

ascertained that the lifted leads did not impact the operability of the Division

1 H,/0,

monitor.

The inspectors verified this information by a review of applicable plant

drawings and the Unit 2 UFSAR.

The apparent cause of the event, as described

in DER 2-96-1754, was inadequate

self-checking by the l&C Supervisor.

Specifically, during performance of the WO,

the l&C Foreman

and Supervisor determined that the annunciator should be

defeated

(i.e., lifting the leads) to minimize disruptions of control room operations.

To accomplish this, a WO change was made to incorporate steps from a previously

approved procedure

(N2-ISP-CMS-0110).

When incorporating the steps into the

work order, the l&C Supervisor inadvertently copied the portion pertaining to the

wrong division.

To assess

the quality of NMPC's root cause and corrective actions, the inspectors

reviewed the applicable WO, surveillance procedure,

and DER, and discussed

the

event with the NMPC I&C Supervisor.

The inspectors

also reviewed the associated

administrative procedure,

GAP-PSH-01, "Work Control," Revision 15

~

GAP-PSH-01

states that if a change to an in-progress work order would adversely affect the

scope or plant impact statement,

the work must be stopped until the WO has been

updated or another WO generated.

Although the intended change would not have

affected the original scope or plant impact; the implementation of the change did, in

fact, adversely affect the scope

and the plant impact statement.

Therefore, the

change was not made in accordance

with GAP-PSH-01, Section 3.11

~ 1, and is

considered

an example of a failure to properly implement the procedure.

The

violation is described

in Section M4.5 of this report.

Although procedure

GAP-PSH-01 allows minor WO changes to be completed by the

supervisor without independent

review, the inspectors considered

the lack of

independent

review for determining whether a WO change

is considered

minor, and

for determining the adequacy of the minor WO changes

themselves,

to be a

vulnerability.

The inspectors were also concerned that the technicians

had possible

opportunities to identify that the WO was directing work on the wrong division of

0,

20

H,/0, monitoring.

In particular, the cabinet containing the annunciator leads was

clearly marked Division 1, and should have prompted the technicians to question

whether the step text of the work order was correct.

This sort of questioning

attitude is promoted by NMPC's "STAAR" (sToP, THINK, AsK, AGT, REYIEw) policy.

M4.5

Conclusion

- Inade

uate Personnel

Performance

In sections M4.2 through M4.4, the inspectors described three maintenance

related

issues associated

with poor personnel

performance.

These are:

(1) a Unit 1

operator pulled the wrong fuses during the application of a markup, resulting in the

inadvertent scram of a control rod; (2) a Unit

1 operator made a calculational error

during completion of a core spray topping pump surveillance, resulting in a six week

delay in identifying that pump differential pressure

was higher than acceptance

criteria; and (3) a Unit 2 IKC Supervisor made

a minor change to a WO, but

incorporated work steps for the wrong division of H,/0, monitoring, resulting in

maintenance

on the wrong division.

In each case, procedural requirements

were

violated as a result of personnel

errors; and each is an example of a violation of TS 6.8.1, which requires procedures

be properly implemented.

(VIO 50-220/96-10-04

8c 50-41 0/96-10-04)

In addition, relative to working on the wrong division of H,/0 the inspectors

considered the lack of independent

review for a WO change to be a vulnerability.

Also, the failure of the technicians to identify that the WO was directing work on

the wrong division to be indicative of poor questioning attitude.

Relative to the

calculational error, supervisory reviews by the ASSS or the IST supervisor were

inadequate

in that they failed to identify that the core spray topping pump did not

meet the surveillance test acceptance

criteria.

M8

Miscellaneous Maintenance Issues (90712, 92700)

M8.1

Closed

LER 50-410 96-08:

Technical S ecification Violations Caused

b

Inade

uate Procedure

During preparations for RF05, scheduled to begin September

28, 1996, Unit 2

personnel identified that the downscale

rod block function of the source range

monitors (SRM) had been inoperable during portions of the first four refueling

outages.

During core offload in the previous outages,

as each SRM channel

indicated downscale

(i.e., less than 3 counts per second

[CPS)), the rod block

function relay was removed and jumpers were installed.

This allowed removal of

control rod blades.

NMPC Unit 2 TS Table 3.3.6-1, note (f), permits the function to

be inoperable during refueling, if the associated

SRM channel is downscale.

During

the subsequent

channel functional test prior to reload, the downscale

rod block

function was not tested.

As fuel was loaded into the core, and the SRM channel

came on scale, the rod block relay was installed in the affected channel.

Per TS 3.3.6., the downscale

rod block function was required to be operable prior to the

SRM channel exceeding

3 cps.

0,

21

The apparent

cause of the missed surveillances was a misinterpretation of the TS

requirement for the SRM downscale

rod block function.

No corrective actions were

required since the event was discovered prior to the beginning of the RFO5, and the

necessary

changes

were incorporated into the refueling procedures.

This licensee

identified violation is being treated

as a Non-Cited Violation, consistent with Section

VII.B.1 of the.NRC Enforcement Policy.

M8.2

Closed

LER 50-220 96-06:

Technical S ecification Violation Caused

b

Co nitive

Error in Calculation Verification

The inspectors reviewed LER 50-220/96-06 and determined that it satisfactorily

described the event, the root cause evaluation, and corrective actions to prevent

similar occurrences.

As discussed

in Section M4.3 of this report, a calculational

error during a surveillance test resulted in the failure to identify.that Core Spray

Topping Pump 121 failed to meet the test procedure acceptance

criteria,

Specifically, the pump had high differential pressure

(dp).

However, the procedure violation discussed

in section M4.5, also caused

NMPC to

violate Unit 1 technical specifications since the pump should have been declared

inoperable.

TS 3.1.4.b states that if one pump is inoperable, the redundant

component must be verified operable daily until the pump is returned to service, and

the pump must be returned to service within 7 days.

If the pump is not restored to

an operable condition within seven days, TS 3.1.4.d requires the reactor be

shutdown within one hour, and in a cold shutdown condition within the next ten

hours.

The failure to declare the pump inoperable when the results of the

surveillance test were unacceptable

is a violation of TS 3.1.4.

The inspectors noted

the high dp indicated the pump was performing in excess of the value required and

the surveillance test was successfully performed once the calculational error was

identified.

Based on the corrective actions and low safety consequence,

this

licensee identified violation is being treated as a Non-Cited Violation, consistent

with Section VII.B.1 of the NRC Enforcement Policy.

III. ENGINEERING

E2

Engineering Support of Facilities and Equipment (37551, 40500, 93702)

E2.1

Unit 2 Secondar

Containment Pressurization

a.

Ins ection Sco

e

On August 28, 1996, while at 95% power, Unit 2 operators entered the emergency

operating procedures

(EOPs) for "secondary containment control," due to positive

pressure

in the reactor building.

The inspectors reviewed the description of the

operators'ctions

as contained

in the SSS logs, and reviewed the applicable

EOP.

The inspectors discussed

the event, inr luding the cause of the event, with shift

personnel, the system engineer,

and plant management.

The inspectors

also

0,

22

reviewed the applicable TSs, UFSAR sections,

DER, and plant drawings to assess

the adequacy of the related plant design.

Observations

and Findin s

On August 27-, 1996, Unit 2 operators declared the "A" train of the standby gas

treatment system (GTS) and emergency recirculation ventilation unit cooler 413A

(2HVR"UV413A) inoperable for the performance of the GTS functional surveillance

test (N2-OSP-GTS-M001).

This surveillance procedure

required the unit cooler to be

operated

in the test mode.

At 1:17 a.m. on August 28, the control room operators

received

a reactor building normal ventilation alarm, indicating reactor building

pressure

at +1.25" water gauge.

Operators entered the EOPs for secondary

containment control and TS 3.6.5.1 for secondary containment integrity as

required.

Initial indications were that the unit cooler test damper closed and the

normal inlet damper opened.

At 1:48 a.m. control room operators secured

normal

reactor ventilation and pressure

returned to normal, allowing the operators to exit

the EOPs and TS 3.6.5.1.

Through a review of the SSSs logs, EOPs and TS, and

discussions with the SSS, the inspectors determined the operators'esponse

to the

event to be appropriate.

As documented

in DER 2-96-2038, the cause of the secondary

containment

pressurization

was the shift in unit cooler 413A from the test mode to the

emergency

mode.

In the emergency mode, the unit cooler was connected to the

main exhaust duct for the "below refueling floor" exhaust subsystem.

This placed

the emergency ventilation system in parallel operation with the normal ventilation

exhaust fan.

Since the emergency system was recirculating air within the reactor

building, less air was available for removal by the normal ventilation exhaust fan.

This resulted in positive pressure within the secondary containment.

The inspectors

reviewed the applicable plant drawings, discussed

the issue with the on-watch

ASSS and the system engineer,

and determined the cause to be reasonable.

Through discussions

with the ASSS, the inspectors ascertained

that the emergency

ventilation unit coolers contained

an interlock that caused the GTS inlet damper to

open if the test damper closed while the system was running.

The inspectors

reviewed the applicable drawings with the ASSS and verified the circuitry

associated

with this interlock; based

on this review, the inspectors determined that

the emergency ventilation system responded

as designed to the test damper failure.

However, the inspectors review of the UFSAR, Section 9.4.2.5.3, noted that this

particular interlock was not included in the description of the test damper

operations.

NMPC performed troubleshooting

and functional testing of the test damper and the

associated

circuitry under WO 96-12209-00.

No problems were identified and

failure could not be reproduced.

The surveillance test was reperformed with no

problems.

Engineering provided the operators with an analysis supporting the

operability of the emergency ventilation system.

Subsequently,

the emergency

ventilation system and GTS were returned to an operable status, with the test

damper in the closed position.

23

The inspectors reviewed the supporting analysis and determined it adequate

for

normal operations.

However, the inspectors were concerned that the design of the

test damper interlock allowed secondary

containment pressure to become positive

upon failure of the test damper during the performance of the surveillance test.

According to DER 2-96-2038,

a review to possibly change the procedure was

requested

as part of the supporting analysis.

Therefore, until NMPC completes their

analysis, and the NRC has reviewed the results, the adequa "y of the surveillance

procedure with regards to the potential for a failure of the test damper to result in a

challenge to secondary containment integrity will remain an unresolved

item.

(URI 50-41 0/96-1 0-05)

C.

Conclusions

The operators responded

appropriately to the reactor building pressure transient that

occurred

as a result of the emergency ventilation unit cooler test damper failing shut

during GTS surveillance testing.

Review of plant drawings indicated that the

emergency ventilation system responded

as designed.

The operability determination

supporting analysis was determined to be adequate

for normal operations;

however,

the adequacy of the surveillance procedure with regards to the potential for a failure

of the test damper to result in a challenge to secondary containment integrity is

unresolved.

E8

Miscellaneous Engineering Issues (90712, 92700)

E8.1

Closed

LERs 50-220 95-05 and 50-220 95-05 Su

lement 1:

Buildin

Blowout

Panels Outside the Desi

n Basis Because of Construction Error

a.

Ins ection Sco

e

LER 50-220/95-05 was originally reviewed in NRC Inspection Report 50-220/96-05.

The LER accurately described the fact that oversized bolts were installed in the

reactor and turbine building blowout panels; however, the following weaknesses

were identified:

the LER did not adequately

address the failure to report the condition in

October 1993, or in March 1995;

the LER did not provide sufficient details regarding the 1993 calculational

error to allow for an adequate

assessment

of the licensee's corrective

actions to prevent recurrence;

and

the LER did not address

the potential for, and the significance of, a reactor

building failure.

The inspectors reviewed LER 50-220/95-05, Supplement

1, to determine if the

above items were adequately

addressed.

b.

Observations

and Findin s

Supplement

1 to LER 50-220/95-05 provided additional details regarding the missed

reportability requirements

and the calculational error.

NMPC's bases for not

completing the required reportability notifications, and the technical details

regarding the calculational error provided in the LER supplement,

were consistent

with those contained

in Special Inspection Report 50-220/96-05.

Additionally, the

corrective actions included in the LER supplement

appear comprehensive,

in that the

engineering,

reportability, and configuration control aspects

related to the issue

were adequately

addressed.

The inspectors determined that Supplement

1 to LER

50-220/95-05 adequately addressed

the reportability and calculational weakness

identified during review of the original LER.

As described

in the LER Supplement,

NMPC reanalyzed the building failure pressures

to determine the potential for, and the significance of, a reactor building failure.

These analyses

determined that the actual failure of the reactor and turbine

buildings would not occur below an internal pressure

of 143 pounds per square foot

(psf) and 135 psf, respectively.

Additionally, NMPC recalculated the upper

bounding values for the blowout panels for both the original and currently installed

confic~rations, using an elliptical methodology.

The elliptical methodology is more

appropriate for design of blowout panels, where a conservative

upper-bound

failure

point must be established.

Results of the calculations for original installation indicated the panel blowout

point could have been as high as 128 psf and 122 psf for the reactor and

turbine buildings, respectively.

For the current installation, the calculations indicated the blowout points are

a maximum of 65 psf and 62 psf for the reactor and turbine buildings,

respectively.

These calculations were assessed

by members of the NRR staff in August 1996,

and determined to be acceptable.

The results of the assessment

were sent to

NMPC in a letter, dated October 7, 1996.

Based on the results of the analyses,

NMPC determined that had a transient occurred, the blowout panels would still have

functioned to relieve internal pressure

before the calculated failure point of the

reactor and turbine building superstructures.

C.

Conclusions

The inspectors determined that the Supplement to LER 50-220/95-05 adequately

addressed

the weaknesses

identified in the original submittal.

Therefore,

LER 50-

220/95-05 and Supplement

1 to the LER are closed.

0

25

E8.2

Incorrect Safet

Limit Identified b

General Electric

a.

Ins ection Sco

e

On April 9, 1996, General Electric (GE) informed NMPC that the cycle specific

safety limit minimum.critical power ratio (SLMCPR), for both units, may be more

limiting than determined by previously performed generic calculations.

The

inspectors

assessed

NMPC's actions in response

to the GE information, including a

review of applicable DERs, LERs, the TS, the 10 CFR Part 21 notification, and core

operating limits reports (COLRs). Additionally, the inspectors discussed

the issue

with the plant managers,

and engineers from NMPC's reactor engineering

and fuels

and analysis engineering departments.

b.

Observations

and Findin s

On April 9, 1996, GE informed NMPC that cycle specific SLMCPR, for both units,

may be more limiting than previously calculated.

On April 10, NMPC contacted

GE

to discuss the information and ascertained

that non-conservatism

in the SLMCPR

had been identified at several plants; NMPC determined that it definitely applied to

Unit 2but Unit 1 was not expected to be impacted.

Furthermore,

GE would be

performing cycle specific calculations for both units.

GE recommended

that Unit 2

implement administrative controls to ensure compensation

for the non-conservatism

until the cycle specific calculations were completed.

On April 10, NMPC initiated a DER, common to both units, regarding the concern,

and implemented administrative limits at both units until completion of the GE cycle

specific analysis.

Subsequently,

the GE analysis determined that new SLMCPRs

were needed for Unit 2, and Unit 1 as well. Both units updated the core monitoring

computer to reflect the change

in the SLMCPR, and the previous administrative

limits were removed.

On May 24, 1996, GE notified the NRC, via letter, that the nonconservatism

in the

generic SLMCPR, when applied to some actual core and fuel designs, was

reportable under 10 CFR Part 21

~ The inspectors reviewed the notification and

verified that the actions taken at both units was appropriate.

Therefore, the GE

10 CFR Part 21, "Reportable Condition, Safety Limit MPCR [minimum critical power

ratio] Evaluation," for both units is closed.

As stated in the applicable LERs, NMPC evaluated the core performance for the

current operating cycle.

They determined that the operating limit, as adjusted to

compensate

for the error, was never exceeded,

and that the safety limit would not

have been exceeded

for any analyzed plant transient.

The inspectors discussed

the

evaluations with NMPC personnel

and considered

them appropriate.

The Unit 1 COLR will be updated

by NMPC upon receipt of the revised supplemental

licensing report from GE. The Unit 2 COLR revision incorporated the new limits,

and appeaied to be appropriate,

containing the required reviews and approvals.

Furthermore, the SLMCPR value specified in the Unit 2 TS, Section 2.1.2, will be

26

updated following restart from RFO5, scheduled for late October 1996.

Until the

revision is complete, the SLMCPR will be controlled administratively and limited by

the core monitoring computer.

c.

Conclusions

The inspectors observed the actions taken by both units in response

to the

nonconservative

SLMCPR calculations provided by GE, and determined the actions

were appropriate.

Additionally, the inclusion of an administrative limit at Unit 1,

even though GE initially indicated the Unit 1 was not expected to be impacted by

the calculation error, indicated an appropriate safety focus.

E8.3

Closed

LER 50-220 96-05:

Incorrect Safet

Limit Caused

b

Inade

uate

Calculational Procedure

The inspectors reviewed the subject LER and determined that it satisfactorily

described the event, the root cause evaluation, and corrective actions.

A detailed

review of the issues associated

with this LER is contained

in Section E8.2.

E8.4

Closed

LER 50-410 96-06:

Incorrect Safet

Limit Caused

b

Inade

uate

Calculational Procedure

The inspectors reviewed the subject LER and determined that it satisfactorily

described the event, the root cause evaluation, and corrective actions.

A detailed

review of the issues associated

with this LER is contained

in Section E8.2.

E8.5

Closed

LER 50-410 96-06 Su

lement 1: Incorrect Safet

Limit Caused

b

Inade

uate Calculational Procedure

The inspectors reviewed the supplement to the subject LER and noted that the

changes

were editorial only.

IV. PLANT SUPPORT

The resident inspectors routinely monitored the performance of activities related to

the areas of radiological controls, chemistry, emergency

preparedness,

security, and

fire protection.

No significant observations

were identified during this period.

V. MANAGEMENTMEETINGS

X1

Exit IVleeting 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 October 18, 1996.

27

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.

X3

Management Meeting Summary

On August 8, 1996, a meeting between the NRC and NMPC management

was held

at the Joint New Center to discuss the results of Systematic Assessment

of

Licensee Performance

(SALP), Report Numbers 50-220/96-99 and 50-410/96-99 for

Nine Mile Point Units

1 and 2. This meeting was open to the public.

ATTACHMENT 1

PARTIAL LIST OF PERSONS CONTACTED

Nia ara Mohawk Power Cor oration

R. Abbott, Vice President,

Nuclear Generation

J. Aldrich, Maintenance

Manager, Unit

1

M. Balduzzi, Operations

Manager, Unit 1

C. Beckham, Manager, Quality Assurance

J. Burton, Director, ISEG

J. Conway, Operations

Manager, Unit 2

K. Dahlberg, General Manager, Projects

R. Dean, Manager, Unit 2 Technical Support

M. McCormick, Vice President,

Nuclear Safety Assessment 5 Support

L. Pisano, Maintenance

Manager, Unit 2

N. Rademacher,

Plant Manager, Unit

1

R. Smith, Operations

Manager, Unit 2

K. Sweet, Technical Manager, Unit

1

K. Ward, Technical Manager, Unit 2

D. Wolniak, Licensing Manager

W. Yaeger, Manager, Engineering,

Unit 1

INSPECTION PROCEDURES USED

IP 37551:

IP 40500:

IP 60605:

IP 61726:

IP 62703:

IP 62707:

IP 71707:

IP 71750:

IP 90712:

IP 92700:

IP 93702:

IP 92901:

On-Site Engineering

Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing

Problems

Preparations

for Refueling

Surveillance Observations

Maintenance

Observation

Maintenance

Observation

Plant Operations

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

Prompt Onsite Response

to Events at Operating Power Reactors

Followup - Operations

ITEMS OPENED, CLOSED, AND UPDATED

OPENED

50-41 0/96-1 0-01

50-41 0/96-1 0-02

50-41 0/96-1 0-03

50-220

S.

50-41 0/96-1 0-04

50-410/96-1 0-05

CLOSED

50-220/95-03-01

50-220/95-03-02

50-220/95-1 6-01

50-41 0/96-08

50-220/96-06

URI

Standby gas treatment system interlock caused the

containment to experience

a positive pressure

VIO

Failure to follow procedures

URI

Procedures

not consistent with TS

URI

Weak initial operability determinations

LER

TS violations caused

by inadequate

procedure

LER

TS violation caused

by cognitive error in calculational

verification

URI

Main steam line radiation monitor returned to service prior

to being declared operable

URI

Service water design not fully analyzed for all accident

conditions and service water header combinations

VIO

PCE procedure not consistent with the requirements of

TS

VIO

Multiple examples of failure to follow procedures

50-220/95-05

50-220/95-05-01

50-220/96-05

50-410/96-06

50-41 0/96-06-01

LER

LER

LER

LER

LER

Building blowout panels outside the design basis because

of construction error

Building blowout panels outside the design basis because

of construction error

Incorrect safety limit caused

by inadequate

calculational

procedure

Incorrect safety limit caused

by inadequate

calculational

procedure

Incorrect safety limit caused

by inadequate

calculational

procedure

UPDATED

NONE

10CFR21

Reportable condition, safety limit MPCR evaluation

0

LIST OF ACRONYMS USED

ASSS

BWR

BWROG

CFR

CIV

COLR

cps

CRD

CSL

CSO

DCR

DER

dp

ECCS

EDG

EOP

ESF

FSAR

GE

gpfn

GTS

HCU

HPCI

IRC

IN

IR

IST

LCO

LER

MCPR

MOV

MSIV

MSL

NCV

NMPC

NRC

NRR

NSSSS

PCE

psf

psia

pslg

QA

RCIC

RFO

RPI

Assistant Station Shift Supervisor

Boiling Water Reactor

Boiling Water Reactor Owners Group

Code of Federal Regulations

Containment Insolation Valve

Core Operating Limits Report

counts per second

Control Rod Drive

Low Pressure

Core Spray

Chief Shift Operator

Document Change

Request

Deviation/Event Report

differential pressure

Emergency

Core Cooling System

Emergency

Diesel Generator

Emergency Operating Procedure

Engineered

Safety Feature

-Final Safety Analysis Report

General Electric

gallons per minute

Standby Gas treatment System

Hydraulic Control Unit

High Pressure

Coolant Injection

Instrument and Controls

Information Notice

Inspection Report

In-service Testing

Limiting Condition of Operation

Licensee Event Report

Minimum Critical Power Ratio

Motor Operated Valve

Main Steam Isolation Valve

Main Steam Line

Non-Cited Violation

Niagara Mohawk Power Corporation

Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Nuclear Steam Supply Shutoff System

Procedure

Change Evaluation

pounds per square foot

pounds per square inch absolute

pounds per square inch gage

Quality Assurance

Reactor Core Isolation Cooling

Refueling Outage

Rod Position Indication

RPO

RPS

RRG

SIL

SLMCPR

SORC

SOV

SRAB

SRM

SRV

SSPV

SSS

STA

STAAR

TS

UFSAR

URI

VIO

WG

WO

Responsible

Procedure

Owner

Reactor Protection System

Regulatory Response

Group

Service Information Letter

Safety Limit Minimum Critical Power Ratio

Station Operations Review Committee

Solenoid Operated Valve

Safety Review and Audit Board

Source range Monitor

Safety Relief Valves

Scram Solenoid Pilot Valve

Station Shift Supervisor

Shift Technical Assistant

Stop, Think, Ask, Act, Review

Technical Specification

Update Final Safety Analysis Report

Unresolved Item

Violation

Water Gauge

Work Order