ML20129F456

Insp Rept 50-333/96-06 on 960728-0928.Violations Noted. Major Areas Inspected:Operations,Engineering,Maintenance & Plant Support

ML20129F456
Person / Time
Site:	FitzPatrick
Issue date:	10/23/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20129F432	List: ML20129F427 ML20129F441 ML20129F456
References
50-333-96-06, 50-333-96-6, NUDOCS 9610290129
Download: ML20129F456 (47)

See also: IR 05000333/1996006

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U.S. NUCLEAR REGULATORY COMMISSION

Region i

Docket No.: 50-333

License No.: DPR-59

Report No.: 50-333/96-06

Licensee: New York Power Authority

Facility: James A. FitzPatrick Nuclear Power Plant

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Location: Post Office Box 41 I

Scriba, New York 13093 l

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Dates: July 28,1996 through September 28,1996 l

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l Inspectors: G. Hunegs, Senior Resident inspector  ;

R. Fernandes, Resident inspector  !

R. Barkley, Project Engineer ,

P. Bonnett, Resident inspector  !

l L. Eckert, Radiation Specialist

j J. Furia, Senior Radiation Specialist ,

i J. Jang, Senior Radiation Specialist l

W. Schmidt, Senior Resident inspector l

R. Skokowski, Resident inspector  !

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Approved by: Curtis J. Cowgill, Chief, Projects Branch 2

l Division of Reactor Projects  !

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9610290129 961023

PDR ADOCK 05000333

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EXECUTIVE SUMMARY

James A. FitzPatrick Nuclear Power Plant

NRC Inspection Report No. 50-333/96-06

This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report includes the results of routine health physics

and effluent control program inspections. In addition, the results of a special team

inspection conducted to review the September 16,1996 reactor scram event are included.

Operations

Overall, the inspectors noted good performance by the operation staff during the inspection

period.

e During the performance of 345 KV backfeed transformer ground fault protective

relay calibration, two terminals were inadvertently shorted, which tripped the

generator output breakers and resulted in a plant scram. Because of the particular

relays involved, a residual transfer vice a fast transfer of electrical loads occurred,

resulting in the loss of numerous balance of plant loads. The inspectors determined,

with the exception of the issues noted below, that the abnormal and emergency i

procedures used during the event were appropriate and gave the guidance and

information needed by the operators and that operators responded well.

e An inadequate procedure to restore the'uninterruptible power supply (UPS) bus and

a broad scoped protective tag-out impeded the prompt restoration of UPS. Loss of l

UPS power to some control room indications, the plant paging system and the  !

security computer made communications and plant access difficult. Communication

difficulties were managed by utilization of radios. The de-energizing of the reactor

protection system (RPS) was an operator error and the misdiagnosis of the plant ,

conditions with regards to the RPS was a training weakness. Additionally, the l

training operators received for residual transfer events was unrepresentative of the

actual plant response. l

e The inspectors determined that overall, the PORC appropriately addressed nuclear

safety matters related to the September 16th plant scram. Action items required for  ;

start-up were satisfactorily resolved, and overall, the startup was performed in a ,

safe and prudent manner.  !

e The condenser response related to the September 16th event (i.e. the MSIV

isolation signal input on low condenser vacuum) remains an unresolved item (50-  ;

333/96006-02).

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Executive Summary (cont'd)

Maintenance

• The LCO maintenance activity to replace the A LPCI battery was conducted very

well with significant efforts to reduce the duration in which the plant was in the

LCO. The quality of the maintenance performed and the level of effort devoted to

the planning of the job was very good. The inspector did note that the seismic

qualification process of the battery cells, via similarity, did not ensure that the

component was an exact one-for-one replacement of the previously qualified

battery. The inspectors will followup on this issue to determine whether any

unqualifiable equipment was installed in the plant (IFl 50-333/96006-03).

• The maintenance staff responded well to the failure of the B EDG to properly 1

sequence during surveillance testing by identifying the cause and taking appropriate i

corrective actions. Subsequent documentation in LER 96-009 was clear, concise i

and provided sufficient information on the. cause and corrective actions taken and

planned for the future.

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e The 24V instrument Battery Replacement maintenance was performed well and had

the appropriate engineering, quality assurance and operations involvement.

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• Post work testing for the replacement of a capacitor in the HPCI inverter power I

supply was good and the timeliness of the corrective actions to industry information

on inverter failures was adequate.

• The licensee's actions to determine the cause of the continued difficulty over the

last six months with manually loading the B and D EDGs during surveillance testing

and increasing the testing frequency were appropriate.

• The risk significance of the 345 kV relay maintenance was not recognized during

planning or conduct of the work. The technician recognized the plant impact and

risk significance of the maintenance, but did not relay this to supervisors or control l

room staff. The subsequent personnci error resulted in a significant challenge to )

plant operators and a substantial disruption in plant activities. Contributing causes l

were improper work request planning, failure to communicate plant risk, and failure l

to properly protect energized adjacent terminals (VIO 50-333/96006-01).

Enaineerina

e Troubleshooting associated with the September 16 and 18 failures of the RHR D

circuit breaker were adequate, and the corrective actions taken to modify the

applicable safety-related circuit breakers were appropriate. However, the inspector

considered troubleshooting associated with the May 8,1996, failure of the RHR D

circuit breaker to lack the expected rigor, in that troubleshooting assumed the

location of the problem without adequate confirmation. Furthermore, the root cause

of a previous failure on May 8,1996, lacked rigor, and more thorough

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Executive Summary (cont'd)

troubleshooting, such as confirmation of this root cause, may have located a

. problem with the 52SM/LS contact 5-6 and prevented the failure of RHR D pump

during the September 16,1996, plant transient.

• The inspector concluded that adequate controls were implemented, following the

failure of a TIPS power supply and opening of three containment isolation valves, to

ensure compliance with technical specifications (TS) for inoperable containment

I isolation valves. The licensee is continuing to investigate the failure of the power

supply and opening of the isolation valves and as such the issue will remain

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unresolved pending the results of their design review (URI 50-333/96006-004).

* The inspectors reviewed and closed URI 95-21-02. The inspector concluded that

the engineering staff performed a thorough and detailed root cause investigation of

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the EQ fuse discrepancies identified to date and developed a comprehensive series

of corrective actions to prevent recurrence. However, the inspector determined that

since documentation of the environmental qualification of fuses were not in an

auditable form, as required by 10 CFR 50.49.j, a violation of NRC requirements

occurred. -This violation was not cited in accordance with Section Vll.B.1 of the

NRC Enforcement Manual.

Plant Sucoort

• During the September 16,1996, event, the implementation of the emergency plan

was a sound decision. The event was appropriately classified, timely notifications

made, and the TSC and OSC were properly staffed and provided assistance to

operators in a timely manner. EP procedures, logs and status boards were in use

and no significant EP facility discrepancies were evident. EP radiological activities

were well coordinated. Based on surveys and environmental radiation monitoring

results, there was no indication of any increased radiation levels associated with the

event. Security force members responded in a timely manner to assist with plant

communications and vital area access.

• Tne licensee implemented and maintained excellent radioactive liquid and gaseous

effluent control programs, sufficient to protect the public health and safety and the

environment. The chemistry staff also demonstrated good knowledge and ability,

and effectively implemented effluent controls in accordance with regulatory

requirements. Maintenance and attention provided to the station ventilation

systems was superior.

• The licensee continues to address previous concerns regarding radiation worker

practices and the performance of the radiation protection staff. Training of radiation

workers has become a licensee strength. Audits, surveillancas and self-

assessments of the radiation protection program continue to improve.

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j TABLE OF CONTENTS

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EX EC UTIV E S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii  :

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TAB LE O F CO NT E NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Summary of Pla nt Statu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. O p e r a t i on s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . 1

01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01.1 Generator Load Reject and Plant Trip Overview ............. 1

01.2 Startup O bservations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 3

O 2.1 Engineered Safety Feature (ESF) System Walkdowns (71707) . . . 3

03 Operations Procedures and Documentation ..................... 4

03.1 Procedure Adequacy ............................ ... 4

04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 5

04.1 Operator Performance ............................... 5

04.2 Uninterruptible Power Supply (UPS) MG Set Recovery ........ 6

04.3 De-energizing of the Reactor Protection System (RPS) Electrical

Buses ........................................... 7

05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

06 Operations Organization and Administration . . . . . . . . . . . . . . . . . . . . . 9

06.1 Plant Operations Review Committee . . . . . . . . . . . . . . . . . . . . . 9

11. M a i n t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

M1 Conduct of Maintenance ................................. 10

M 1.1 General Comments ................................ 10

M1.2 Surveillance Observations ........................... 10 .

M1.3 Conclusions on Conduct of Maintenance . . . . . . . . . . . . . . . . . 11 l

M 1.4 On-Line Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

lil. Engineering .................................................. 17

E8 Miscellaneous Engineering Issues (37551) . . . . . . . . . . . . . . . . . . . . . 17

E8.1 Review of the Residual Bus Transfer during the September 16

Plant Transient ................................... 17 j

E8.2 Failure of the D Residual Heat Removal Pump Circuit Breaker j

During Torus Water Cooling .......................... 18 l

E8.3 Traversing In-Core Probe (TIP) System Ball Valve Control I

Failure ......................................... 21 l

E8.4 (Closed) (URI) 50-333/95021-02: Environmentally Qualified i

(EO) Electrical Fuses ............................... 21 l

E8.5 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . 22

I V. Pl a nt S u p po rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 i

R1 Radiological Protection and Chemistry (RP&C) Controls (84750) ..... 23

R1.1 Management Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

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R1.2 Review of the Offsite Dose Calculation Manual (ODCM) ...... 24

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R1.3 Implementation of Radioactive Liquid and Gaseous Effluent

Control Programs . . . . . . . . . . . . . . . . . . . . ............. 25

R1.4 Calibration of Effluent / Process Radiation Monitoring Systems

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(RMS).......................................... 26

R1.5 Air Cleaning Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

R5 Staff Training and Qualifications in RP&C ..................... 27

R6 RP&C Organization and Administration ....................... 28

R7 Quality Assurance in RP&C Activities ........................ 30

R8 Miscellaneous issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

R8.1 Evaluation of Unmonitored Release After September 16,1996

Scram ......................................... 30

P1 Conduct of Emergency Preparedness (EP) Activities . . . . . . . . . . . . . . 31

P3 EP Procedures and Documentation .......................... 32

F8 Miscellaneous Fire Protection issues . . . . . . . . . . . . . . . . . . . . . . . . . 32

F8.1 Performance of the Fire Suppression System during the

] September 16 Plant Transient . . . . . . . . . . . . . . . . . . . . . . . . . 32

S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 33

V. M a n ag e m e nt M e eting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

X1 Exit Me eting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

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ATTACHMENTS

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Attachment 1 - EP Implementing Procedures Reviewed

i Attachment 2 - Procedures Reviewed Related to September 16,1996 Event

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Report Details l

Summary of Plant Status

The unit operated at 100% power until the September 16,1996, reactor scram.

Following the short forced outage and completion of corrective actions for

the event, the plant was critical on September 21 and returned to power on

September 23. The plant was operating at 70% power at the end of the inspection

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1. Operations

01 Conduct of Operations

01.1 Generator Load Reject and Plant Trio Overview

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On September 16,1996, the plant was operating at 100% power. The

uninterruptible power supply (UPS) motor-generator set was out of service for

maintenance and the UPS bus was being supplied from the alternate feed. All '

emergency core cooling system (ECCS) equipment was operable. Instrument and

control (l&C) technicians were replacing a 345 kilo-volt (KV) reverse power relay

when at 1:04 p.m., the screwdriver being used by one of the I&C technicians

slipped and touched two terminals of a generator ground protection relay. The

outgoing power circuit breakers tripped and initiated a generator load reject.

Turbine control valves received a fast close signal and turbine bypass valves opened

to dump excess steam to the condenser. A reactor scram signal was initiated by

the turbine control valves fast closure signal.

By design, the inadvertent operation of the reverse power relay operated additional

relays which blocked the fast transfer of plant buses to reserve power. A slower

residual transfer occurred and the plant buses saw an interruption of power. The

4KV buses were re-energized from reserve power after bus voltages fell to less than

25% of rated voltage. As a result of the residual transfer, many 4KV loads,

including condensate and condensate booster pumps, circulating water pumps,

service air compressors and most plant equipment power supplies (600V or lower

loads) were automatically tripped off due to the undervoltage condition and had to

be manually restored later by operator actions.

The alternate feed breaker to the UPS panel tripped on undervoltage during the

residual transfer resulting in a loss of all UPS loads including the page/ party

(Gaitronics), sound power phones, control room radio base r,tation and some plant

telephones, feedwater control and electro-hydraulic control (EHC) control power

circuits and some indications on the full core display.

When the voltage on the two emergency 4KV buses fell below 62% for 2.4

seconds, the four emergency diesel generators (EDGs) started as required. By the

time the EDGs reached rated speed and voltage, the residual transfer had restored

power to the two emergency buses; thus the EDG output breakers did not close.

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The generator trip caused the control valves to close rapidly and the bypass valves

to open. Reactor pressure increased to 1082 psig at 4 seconds after the trip,

during which the "G" safety relief valve (SRV) cycled open for a few seconds.

Reactor water level decreased as a result of the scram and turbine feed pump trip

resulting in both the high pressure coolant injection (HPCI) and reactor core isolation

cooling (RCIC) automatically initiating. Reactor water level reached its lowest

recorded level of 126 inches versus a normal operating level of 201.5 inches.

, Reactor pressure vessel (RPV) level was restored and maintained using HPCI and

RCIC pumps. For the duration of the transient, pressure was controlled using HPCI,

RCIC and manual operation of the SRVs.

With the initialloss of the electrical busses, the main circulating water pumps were

de-energized. This resulted in the loss of condenser heat removal capability and

condenser inlet water temperatures reached 225 degrees F because of continued

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heat addition from cascading steam and feedwater from the feedwater heating

system. Condenser back pressure increased until pressure increased above a point

at which one of the low pressure turbine rupture discs and reactor feed pump

rupture discs ruptured. The discs ruptured approximately 9 minutes after the I

reactor scram (about 1:13 p.m.). Electrical power was restored to the electrical

buses and loads were restored beginning appioximately 1:19 p.m.. At 1:40 p.m. a

notification of unusual event was declared and the technical support center (TSC)

and operational support center (OSC) were activated.

After the rupture discs were repaired and condenser integrity was restored, main

condenser heat removal capability was verified, and NYPA exited the emergency

plan. Normal shutdown cooling was established at 5:44 a.m. on September 20.

a. insoection Scoce

! The inspector reviewed the overall event to determine if the plant response was

bounded by the Final Safety Analysis Report (FSAR). The inspector reviewed the

transient analysis and discussed the event with plant management personnel. j

b. Observations and Findinas

The transient is described in FSAR Section 14.5.2.1, Control Valve Fast Closure -

Generator Load Rejection. The analysis described the plant response with bypass

valves available. Because of the residual bus transfer, the electro-hydraulic control

(EHC) pumps were de-energized and bypass valve (BPV) operation could not be

sustained long-term. This, however, did not impair the ability to reduce reactor

pressure through the BPV and the safety relief valve (SRV) operation; the reactor

operators maintained reactor pressure vessel (RPV) pressure and level control using

the high pressure emergency core cooling syrwms. The inspector determined that

the temporary loss of off-site power did not imnact the ability for emergency core

cooling systems to operate and fulfill their safety function.

The condenser response was evaluated against the FSAR descriptions. FSAR

section 7.11.2 states that "the condenser protection rupture disc is set at 5 psig...

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Because of the closure of the main steam isolation valves (MSIVs) on low 1

condenser vacuum, there will be no actuation of the rupture disc." The section l

continues with "However, in the unlikely event the rupture disc should rupture, the

resultant doses would not exceed those resulting from the steam line break inside ,

the turbine building as discussed in FSAR chapter 14." The licensee stated that '

Section 7.11.2 of the FSAR does not consider all conditions. The low condenser i

vacuum closure of the MSIVs is bypassed when the reactor mode switch is not in I

Run and the turbine stop valves are closed. By procedure, operators place the

mode switch in the Shutdown position after a reactor scram which bypasses the

low condenser vacuum MSIV closure signal. The licensee is continuing to evaluate i

the condenser response related to this event in conjunction with General Electric.

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The NRC plans to review the results of their evaluation.

c. Conclusions

The condenser response related to this event (i.e. the MSIV isolation signal input on

low condenser vacuum) is unresolved item (50-333/96006-02).

01.2 Startuo Observations

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a. Insoection Scope (71707)

The inspectors observed portions of the reactor startup conducted from September

21 to 23.

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b. Observations and Findinas

The startup was characterized by clear operator communications and procedure use,

attentive management oversight, and effective control by shift supervision. Shift -

turnovers were performed in a controlled manner and crew briefings were good.

c. Conclusions

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The overall startup was performed in a safe and prudent manner. I

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O2 Operational Status of Facilities and Equipment

O2.1 Enaineered Safetv Feature (ESF) System Walkdowns (71707)

The inspectors used Inspection Procedure 71707 to walk down accessible portions

of the following ESF systems:

• RHR Service Water System i

e LPCI Battery

• Emergency Service Water System

o Emergency Diesel Generator

Equipment operability, material condition, and housekeeping were acceptable in all  !

Cases.

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03 Operations Procedures and Documentation

03.1 Procedure Adeauacy

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a. Insoection Scoce l

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The inspector reviewed the abnormal and emergency operating procedures (AOP i

and EOP) listed in Attachment 2 to determine the adequacy of the guidance given to

the control room staff,

b. Observations and Findinas

The inspector determined that the abnormal and emergency operating procedures

gave appropriate guidance overall to the operators throughout the event.

Specifically, AOP-21, Loss of UPS, directed operators to verify the reactor

shutdown using back-panel indication because the front panel indications were de-

energized. The AOP also listed equipment and indications that were affected by the

UPS loss. AOP-1, Reactor Scram, and EOP-2, Reactor Pressure Vessel Control, (

sufficiently directed operator actions for stabilizing the plant and maintaining RPV

pressure and level control.

The inspector identified that the AOPs and EOPs did not direct operators to shut the

main steam isolation valves (MSIVs) in the event of a complete loss of vacuum.

The MSIVs automatically shut when main condenser vacuum reaches 8 inches (hg),

but the trip is bypassed when the reactor mode switch is not in RUN and the turbine

stop valves are shut. Operations management addressed this issue by initiating a

revision to the AOP-1, Reactor Scram and AOP-31, Loss of Condenser Vacuum,

procedures.

The senior licensed operator performing the Post Transient Evaluation identified that

AOP-57, Recovery from Residual Bus Transfer, stated that an MSIV Group 1

isolation was an automatic action. This action, however, was not the case and the

procedere was corrected. The inspector noted that these procedure deficiencies did

not negatively impact the operators performance during the event.

c. Conclusions

The inspector determined that the abnormal and emergency procedures used during

the event were adequate and gave the appropriate guidance and information needed

by the operators.

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04 Operator Knowledge and Performance

04.1 Operator Performance

a. Insoection Scope

The inspector reviewed overall operator performance during the event, including

scram verification, RPV pressure and level control, actions taken to cooldown the

RPV and restore the main condenser. The inspector reviewed operating logs,

procedures, and discussed the operator's actions with licensee management and

personnel,

b. Observations and Findinas

The control room operators responded well to the event performing the appropriate

actions as directed in the abnormal and emergency operating procedures to mitigate

the transient. The operators used alternate methods of verifying the reactor was

shutdown since the normal control panel indications were de-energized by the loss

of the UPS. Operators manually verified that all scram valves were open locally at

the hydraulic control units, to assure all control rods were fully inserted and later

confirmed that all control rods were fully inserted when power was restored to the

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UPS.

A reactor operator effectively maintained level and pressure control of the RPV

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using the high pressure coolant injection (HPCI) and reactor core injection cooling

(RCIC) systems and the safety relief valves (SRVs) to stabilize and cooldown the

reactor. The operators maintained an 80 degree cooldown rate using the above

mentioned systems until the condenser was returned to service and the cooldown

was completed using bypass valves. Pressure and temperature limits were not

exceeded throughout this evolution.

The operators responded, appropriately to the complete loss of condenser vacuum.

Due to the temporary loss of off-site power, all major plant systems were de-

energized. The operators did not immediately restart the circulating water pumps to

restore condenser vacuum because of the need to restart service water,

compressed air, and other systems necessary to support the circulating water

system and plant cooldown in accordance with the AOPs.

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The control room operators restarted the circulating water pumps about seven hours

into the event after the rupture disks were repaired and established a condenser

vacuum after 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. The operators then completed the RPV cooldown using

bypass valves to the main condenser. The inspector determined that these actions

were appropriate and within the guidance of plant operating procedures.

c. Conclusions

In generally, the control room operators responded well to the event. Operators

immediately verified the reactor shutdown, stabilized pressure and level, and cooled

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down the RPV in a controlled manner. Control room supervision methodically

restored plant systems to enable repair of the main condenser rupture disc and re-

establish condenser vacuum to complete the plant cooldown. An exception to the

otherwise good performance was the operator actions taken to de-energize the

reactor protection system (RPS) bus (see section 04.3). However, a performance

issue related to securing the reactor protection system is discussed in Section 4.3

of the report.

04.2 Uninurruotible Power Sucolv (UPS) MG Set Recovery

a. Inspection Scoce (93702)

During the residual transfer of the plant electrical buses, the alternate feed breaker

to the UPS panel tripped on under voltage and by design did not reclose following

the transfer. This resulted in a loss of all UPS loads, including plant internal

communications (Gaitronics), feedwater control, high range effluent radiation

monitors, security computer, and various control room indications. The breaker was

manually closed by the operators 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and thirteen minutes following the plant

trip. The inspector conducted interviews, reviewed plant drawings and procedures

to determine if the power supply was restored in a timely manner and the impact on

the restoration of the plant.

b. Observations and Findinos

The UPS provides power to vital low voltage loads and utilizes a double motor

generator set (AC & DC motor) as the power source. The AC motor is powered

from the vital bus and the DC motor is powered from the battery. Under normal

circumstances the UPS transfers from the AC power source to the DC power source

upon loss of voltage to the vital bus. However, on September 12, the UPS MG set

had been removed for corrective maintenance to repair a bad motor bearing and

was not available during the transient. The UPS loads at that time were placed on

the alternate feeder breaker which provides power via the 12500 emergency bus.

The alternate feeder breaker is a unique low voltage molded case circuit breaker in

that it has an electric motor operating mechanism on the front of the breaker.

When the operators responded to the tripped UPS panel in the electric bay, they

noted that the alternate feeder breaker was " flagged" in the on position. Walk

down of the power supply to the UPS distribution panel by the operators determined

that the circuit had power. After getting permission from the control room, the

electrical supervisor opened the breaker operating mechanism door to observe the

position of the handle on the actual alternate power breaker. He discovered that

the breaker was indeed tripped open. The original diagnosis that the breaker was

closed was the result of the operating mechanism flag not repositioning when the

breaker trips on under voltage. Using appropriate electrical safety precautions the

electricians attempted to reset and manually close the breaker. When the attempt

was unsuccessful, the electricians stopped and reviewed the circuitry for any

problems. Subsequently a senior reactor operator returned to the panel, and was

able to reset the breaker manually, thereby resetting the UPS bus.

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The inspector reviewed the plant drawings and determined that control power was

available to the alternate feeder breaker following the residual transfer. However,

because of the paralleling switch on the UPS panel being protective tagged in the

off position for maintenance, the operators could not have closed the breaker

electrically without first clearing the protective tag. This tagout represented a

conservative personnel and equipment protection boundary; the delay posed by this

tagout had no significant effect on the overall outcome of this plant event.

"

Additionally the inspector determined that the abnormal operating procedure

AOP-21, Loss Of UPS, would not have properly directed the restoration of the

alternate feeder breaker. The electrical operation of the breaker is such that the

under voltage coil opens the breaker and the motor operator functions to reset the

breaker so that it is ready to close automatically or when the operating switch at

the UPS panel is taken to the close position. The AOP did not have procedural

guidance for resetting the alternate feeder breaker and therefore would not have

'

allowed electrical closure of the breaker. The AOP did give subsequent guidance on j

manually closing the breaker; however, it did not give guidance on removing the

operating mechanism and operation of the molded case circuit breaker. As a result,

the licensee elected to revise the procedure and conduct training with operations

personnel on the UPS alternate feed breaker. Additionally, the work control center

is taking steps to ensure the ability to operate the UPS paralleling switch is not

significantly impeded during future protective tag-outs.

c. Conclusions

The inspector concluded that the absence of clear direction on the manual operation

of the UPS feeder breaker in the AOP and a tagout delayed the licensee in restoring

the UPS. This delay had no measurable impact on the outcome of this plant event.

The loss of the plant page and security computer made communications and plant

access difficult, but were managed by utilization of radios and posting security

guards.

04.3 De-eneraizina of the Reactor Protection Svstem (RPS) Electrical Buses

a. Insoection Scone (93702) i

l

The inspector conducted interviews and reviewed plant drawings and procedures to

determine the issues concerning the RPS power supply restoration during the

September 16 event. The impact on the restoration of the plant was also assessed.

b. Observations and Findinas i

l

Following the generator load reject and subsequent scram, the shift manager (SM)

ordered a shift of the RPS to the alternate power supply. This was done by the SM i

because he interpreted the dark full core display and the radiation monitor

annunciators alarming to be indicative of a loss of power to the RPS. RPS was

shifted to a deenergized bus which resulted in the MSIVs closing. j

I

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{ The operator tasked with transferring the power supplies failed to question the f act

i

that the white "MG-SET" light above the RPS power selector switch and the

darkened "TRANS" light meant that the system was energized and that the

alternate power supply was not. The inspector determined through walkdowns and

review of operating procedure OP-18, Reactor Protection System, that the

'

, procedure had sufficient guidance to properly shift RPS. However, because of the

'

number of activities and distractions present, the operator improperly transferred

RPS.

'

Through interviews, the inspector learned that the operators were of the impression i

that if the full core display was dark, that the RPS was de-energized in addition the l

) operators felt that the numerous radiation monitor annunciators were also indicative I

'

of a loss of RPS. The full core display is only partially powered from the RPS bus,

with additional power coming from the UPS and non vital buses. The inspector

determined, through review of plant drawings and procedures, that the loss of the

UPS bus would cause a similar alarming annunciator board, with respect to radiation I

,

monitors, as a loss of RPS.

c. Conclusions

l

The inspector concluded that the de-energizing of the RPS was an operator error '

and that the misdiagnosis of the plant conditions with regards to the RPS was a

training weakness.

j 05 Operator Training and Qualification

,

a. inspection Scope

,

The inspector reviewed simulator training regarding residual bus transfers and

discussed this issue with the training staff and operations personnel,

b. Observations and Findinos

i

Control room operators informed the inspector that they had believed that the

reactor protection system (RPS) bus was de-energized during the event. This was

partially due to their training experience at the plant specific simulator and due to

confusion regarding the power supplies for the full core display. )

The simulator ca.1 not replicate a residual bus transfer because the computer is not

modeled for this type of transient. To accomplish the effects of the scenario, ,

training instructors insert manual overrides to create the transient affecting I

simulator fidelity with the plant. The RPS was always de-energized during the

training scenario. l

The control rod Full-in and Full-out as well as other light indications on the full core

display are powered from the UPS power supply. During the event, the operators )

became confused as to the power supply that fed the full core display, and

1

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9

4

operators believed that the RPS power supply was de-energized. Operation

management determined that the operator's training was deficient in this area.

.

The Plant Operations Review Committee (PORC) discussed this issue during their

i final review of the post transient evaluation. The PORC tasked the training staff to

identify other scenarios that had simulator fidelity issues which could result in

negative training prior to start-up. Four training scenarios were ultimately identified;

these scenarios will not be used until modified and revalidated. Further, Operations

"

management conducted training sessions for the operators regarding the power

,

supplies for the full core display and other control room indications prior to startup.

c. Conclusions

i The inspector concluded that the training operators received for residual transfer

events was unrepresentative of the actual plant response. The PORC initiated a

corrective action item for the simulator staff to identify other faulty training

d

scenarios. Operations management reviewed these negative indications with the

operations staff prior to re-starting the reactor.

06 Operations Organization and Administration

06.1 Plant Ooerations Review Committee

a. Inspection Scoce

The inspector observed the Plant Operations Review Committee's (PORC) final

review of the Post Transient Evaluation and of I&C's root cause assessment into the

cause of the event,

b. Observations and Findinos

The PORC concluded that there were no unresolved safety questions associated

with this event. PORC discussed the event, station personnel performance,

equipment performance, corrective actions required and lessons learned. These

discussions were open and candid. The PORC chairman emphasized the importance

of managers to communicate expectations to the plant staff, the importance of

possessing a questioning attitude when unexpected results occur and of self-

checking to preclude mistakes caused by over-confidence. The chairman identified

several other follow-up issues required to be completed prior to startup that were

subsequently resolved by the PORC.

c. Conclusions

The inspector determined that overall, the PORC adequately addressed matters

related to nuclear safety. Action items required for start-up were resolved to the

satisfaction of the PORC. The most significant items were independently reviewed

by the resident inspectors, including the conduct of training for operators and

administrative control of the TIP system.

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11. Maintenance

1

1

j M1 Conduct of Maintenance

M 1.1 General Comments

a. Insoection Scooe (62703)

The inspectors observed all or portions of the following work activities:

• WR 95-07873 replacement of 24VDC instrument battery

• WR 96-02875 calibrate 71-59N-1UPRN05 transformer ground fault

protective relay

• WR 96-01045 installation of alternate decay heat removal system per

modification F1-95-121

• WR 96-04591 EDG droop circuit

• WR 96-04790 TIP system malfunction

• WR 96-04877 turbine exhaust rupture disk

b. Observations and Findinas

The inspectors found the work performed under these activities to be technically

sound and thorough. All work observed was performed with the work package

present and in active use. Technicians were experienced and knowledgeable of

their assigned task. The inspectors frequently observed supervisors and system

engineers monitoring job progress, and quality control personnel were present

whenever required by procedure. When applicable, appropriate radiation control-

measures were in place.

M1.2 Surveillance Observations

The inspectors observed and reviewed portions of ongoing and completed

surveillance tests to assess performance in accordance with approved procedures

and Limiting Conditions for Operation, removal and restoration of equipment, and j

deficiency review and resolution. The following tests were reviewed: l

l

• ST-2X RHR service water flow rate, strainer and inservice test

• ST-35 A Containment spray / cooling system logic system functional test

• ST-9B EDG fullload test and ESW pump operability test

b. Observations and Findinas J

The licensee conducted the above surveillance appropriately and in accordance with  !

procedural and administrative requirements. Good coordination and communication I

were observed during performance of the surveillance.  ;

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i

M1.3 C_q._plusions

n on Conduct of Maintenance

Overall, maintenance and surveillance activities were well conducted, with good

adherence to both administrative and maintenance procedures.

M1.4 On-Line Maintenance

M 1.4.1 24V instrument Batterv Reofacement

a. Insoection Scooe (62703)

During this inspection period, the licensee changed out the two sets of instrument

batteries as the result of a seismic qualification user's group recommendation for

other batteries at the plant. The inspector observed the maintenance activities and

reviewed the acceptance testing documentation to verify that the work had been

done in accordance with station procedures and industry practices. j

!

b. Observations and Findinas  !

The two instrument batteries are made up of two sets of twelve individual cells.

The replacement cells for each battery was a C&D Power Systems model KCR-7

battery, classified as QA category I and having seismic design and installation

requirements. Each redundant batter', pair provides backup power during loss of off

site power or loss of power to its associated battery charger for two SRM/lRM trip

units, and several process radiation monitors in the plant. The replacement was

performed with the plant operating and the work was performed in a manner that

maintained the battery available for service and fully operable. The battery was

maintained operable by bringing fully charged spare cells on a portable cart into the

battery room and connecting the spare cells in parallel with the cells being replaced.

After the new cells were in place and connected to the bus, the parallel connections

to the spare cells were broke and the sequence was repeated for the other sets of

cells.

The battery work was performed in accordance with maintenance procedure MP-

57.06, Battery Maintenance, Revision 16. The evolution was controlled by a

temporary operating procedure TOP-234,24 VDC Instrument Battery Replacement

With Reactor in Run Mode, which sequenced the replacement of the batteries.

The inspectors observed the proper procedures and work control documents in use.

Maintenance personnel had established and implemented appropriate ignition, fire

prevention and personnel safety controls. The maintenance was performed well,

with the mechanics being very thorough with moving, assembling and testing the

cells.

The inspector noted that the acceptance criteria for the post installation resistance

readings in the maintenance procedure was not in accordance with IEEE Standard

484-1987, Recommended Practice for Installation Design and Installation of Large

Lead Storage Batteries for Generating Stations and Substations. The maintenance

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

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12 ,

l

procedure had an acceptance criteria of less than 60 microhms. The IEEE standard

,

includes direction to remake and remeasure any connection that has a resistance

measurement more than 10% or 5 micro ohms, whichever is greater., over the

average of each type of connector. Subsequent to this, the licensee reviewed the

data and determined that three connections did not meet this IEEE criterion. Their

evaluation determine that although the resistance values did not meet this criterion, j

the resistance readings were lower than the previous readings and thus acceptable. ,

This was also the case for one connection on the initialinstallation of the A station i

battery in 1995. The licensee subsequently changed the procedure to reflect the

connection resistance readings requirements for new battery installations in the

procedure.

1

c. Conclusions

The inspector concluded that the maintenance was performed well and had the l

appropriate engineering, quality assurance and operations involvement. The j

licensee did not incorporate the complete acceptance standard for battery resistance

readings in the maintenance procedure. This reflected a lack of tieroughness in the  !

preparation of the procedure. Subsequently, this error in the procedure was

adequately addressed.

M 1.4.2 LPCI MOV Batterv Power Sucolv Reolacement

a. Insoection Scone (62703)

!

'

The inspector reviewed the preparation for and conduct of the replacement of the A

low pressure coolant injection (LPCI) motor operated valve (MOV) independent

power supply battery during a limiting condition for operation (LCO) maintenance -

evolution. The inspector reviewed the physical condition of the installed

replacement battery, commercial grade dedication documentation for the battery,  ;

the LCO preparation checklist, portions of maintenance procedures (MP)-057.06,

Revision 17, " Battery Maintenance", which was performed as part of the post-

maintenance testing on the battery, and MST-71.11, Revision 8, governing

quarterly surveillance testing on the battery.

i

b. Observations and Findinas i

This LCO maintenance activity was thoroughly evaluated prior to its conduct and

was approved based on its minimal potential safety implications to the plant. The ,

LCO maintenance evolution was well planned, supported and controlled as i

evidenced by the successful completion of the evolution in just under two days,

versus nearly 3.5 days as originally planned. The job was worked on a 24-hour

basis and considerable efforts were made by the assigned LCO coordinator and

other key individuals involved to minimize the duration the battery was out of

service as well as resolve emergent concerns. The quality of the installation work

was very good.

l

.

.

13

The inspector identified that the battery was dedicated for seismic application via

similarity to a previously quahfied battery (i.e. the battery cell size and model

number were the same as hattery cells previously procured under a 10 CFR 50

Appendix B program and seismically qualified by the manufacturer). However,

discussions with the battery manufacturer confirmed that there was recent changes

to the battery design (i.e. material changes to the battery cap to improve impact

resistance, terminal post seal changes) which raised the question whether the new

battery cells were an exact one-for-one replacement. Subsequent engineering

analysis of the design modifications confirmed that the design changes to the

battery enhanced vice detracted from the seismic qualification of the battery. DER

96-971 was written to characterize and remedy the procurement process deficiency

identified in this matter.

c. Conclusions

The LCO maintenance activity to replace the A LPCI battery was conducted very

well with significant efforts to reduce the duration in which the plant was in the

LCO. The quality of the maintenance performed and the level of effort devoted to

the planning of the job was very good. The inspector did note that the seismic

qualification process of commercial grade equipment, such as the battery cells, via

similarity, did not ensure that the component was an exact one-for-one replacement

of a previously qualified component. The inspectors will followup on the findings of

DER 96-971 to determine the extent of this issue and whether any equipment that

is not seismica;ly qualifiable was installed in the plant (IFl 50-333/96006-03).

M 1.4.3 Failure of B EDG to Start Durina Surveillance Testina

a. Inspection Scoce (62703)

The inspector reviewed the reasons and corrective actions taken for a failure of the

B ernergency diesel generator start sequence during surveillance testing on July 22.

Including a detailed review of wiring schematics, plant procedures, EDG operating

manual, and subsequently the licensee event report (LER 96-009) submitted on

August 22.

b. Observations and Findinas

Operations personnel made proper log and TS action statement entries,

documenting the situation after the B EDG was declared inoperable. Following the

test failure, operations and instrument and control (l&C) personnel took good

actions to review the possible causes, including discussions with personnel in the

switchgear room. This led to the determination that the reverse power relay had

energized, and that it happened before the assumed 3.5 second time delay.

Troubleshooting effectively determined that an incorrectly installed time delay relay

and a failed motor on the D EDG governor booster pump, resulted in the tripping of

the EDG. The observation that the reverse power relay had energize too early led

the licensee, through electrical prints, to determine that the voltage sensing time

.,

.

14

delay relay which energizes the reverse power relay had not been installed in the

correct location. In effect this led to a time delay being set at 0.8 sec from the

designed 3.5 sec. However, the licensee was prennted with a problem since this

relay had been installed in this configuration in 1990 and the EDG had started

successfully during monthly surveillance testing, except for one instance in 1992

when the D EDG governor booster pump was found failed. Subsequent

troubleshooting found that the D EDG governor booster pump had failed in this

instance as well.

NYPA identified that two other relays had been incorrectly installed during 1990.

The inspector found that the two additional incorrectly installed relays would not

have affected any other safety related functions of the EDG control circuits,

c. Conclusions

Surveillance testing properly identified equipment conditions which led to the B EDG i

not properly sequencing during a surveillance test start. The failure of the B EDG to l

properly sequence resulted from an incorrectly installed time delay relay in the

reverse power sensing circuit and the failure of the D EDG governor booster pump.

NYPA did not identify the incorrect instailation of the time delay relay in 1992 when

a similar failure occurred. However, the surveillance tests conducted since then

proved that the EDG would have performed its design function. NYPA responded

well to the failure, identified tita causes and took appropriate corrective actions.

Subsequent documantation in LER 96-009 was clear, concise and provided

sufficient information on the cause and corrective actions taken and planned for the

future.

M 1.4.4 HPCI Inverter Failure

a. Insoection Scoce (62703)

On September 6, the HPCI inverter failed. The licensee performed trouble shooting

and determined the cause to be the failure of a capacitor inside the inverter. The

inspector reviewed the post work testing documentation for the replacement

capacitor and discussed the activities with the maintenance staff.

b. Observations and Findinos

The inspector reviewed the equipment vendor manual and compared the

manufacturers information with the post work test data and found it to be

satisfactory. The inspector also reviewed the licensee's response to NRC and

industry information on failed inverters as documented in the licensee's SOER 83-

03. The inspector determined that the licensee had originally evaluated the industry

information in 1984. The issue was reviewed again by the licensee in 1992 and in

1993 additional corrective actions were incorporated into the licensee's tracking

program. The past corrective actions by the licensee included incorporation of

electrolytic capacitor testing and/or replacement in a preventative maintenance

program for the inverters. As this recent failure was an oil filled capacitor, it was

.

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15 l

!

not included in the preventive maintenance program. The licensee plans on

replacing the oil filled capacitors in the HPCI and RCIC power supply inverters in the I

next refueling outage.

c. Conclusions

The inspector concluded that the corrective actions were appropriate and that the

inverter failure rates was low. The inspector determined that the post work testing

and the timeliness of the corrective actions to be adequate. i

M1.4.5 Failure of EDGs to Load Prooerlv

i

a. insoection Scooe (62703) l

On March 15, when attempting to performing ST-98, EDG Full Load Test and ESW

Pump Operability Test, the D EDG load started to increase more than the operator j

expected. Trouble shooting by the license at that time failed to identify any )

problems, however the droop circuit was suspect. On August 23, and September i

9, the problem reappeared on the D and B EDGs respectively. The inspectors

- reviewed the events to assess the maintenance troubleshooting activities and

operability of the EDGs.

b. Observations and Findinas

During both recent events after several manipulations of the governor speed control

switch, the operator determined the performance of the EDG was improper and

opened the output breaker. The B and D EDGs were declared inoperable and the  ;

applicable LCO was entered. Trouble shooting was performed with strip chart '

recorders and instrumentation installed. The licensee was not able to identify the j

problem, but changed out the droop switches on both the B and D EDGs. The '

licensee had similar problems back in the 1977 time frame with the A EDG and I

problems with the B EDG in the 1980 time frame. The droop switches were l

replaced at that time and the problems did not reappear until this year.

In discussion with the licensee engineering staff, the inspector learned that the  ;

droop switch is utilized only during surveillance testing when the operators are 1

manually connecting the EDG to a live bus. With the switch in the normal position,

the EDG load circuit is such that it senses load and automatically increases speed to l

pick up the electricalload as the safety related equipment starts. This feature is

undesirable during surveillance testing because the bus is already loaded and

connected to the main grid at 60 hertz. With the switch in normal, following

synchronization, the EDG would try to take all the load and would overload. The

droop circuit does the opposite. In the droop mode, when the EDG senses load, it

slows down the EDG and therefore does not assume any load. At this point, the i

operator uses the speed adjust control switch to load the EDG to the required ST l

value.

!

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16

The licensee plans on continuing the monitoring of the EDGs with additional

instrumentation during the increased surveillance testing and to change out the

droop switches on the A and C EDGs. The licensee also plans on performing an

equipment failure evaluation on the removed switch to attempt to determine if

contact oxidation was a factor in the problem.

c. Conclusions

The inspector concluded the licensee's actions to determine the cause of the

continued difficulty with loading the EDGs during surveillance testing were

appropriate.

M 1.4.6 345 KV Relav Calibration

a. Inspection Scone (62703)

!

During the performance of a 345 kV relay calibration, two terminals were

inadvertently shorted, which tripped the main generator output breakers. This

resulted in a main turbine trip and reactor scram as a result of the electricalload

loss (see section 01.1). The inspector reviewed the maintenance task chronology,

work package, maintenance and administrative procedures, department written

critique, and discussed the event with the maintenance supervisor.

b. Observations and Findinas

The scope of the work request was to remove the relay from service, remove the

external capacitor from the panel, calibrate the relay, reinstall the capacitor and

return the relay to service. A pre-job brief was conducted in accordance with ICSO-

20, instrument and Controls Pre-job Briefing. During the performance of the relay

and capacitor removal, the technician identified that the capacitor leads would have

to be disconnected from the terminal board area on the relay case instead of the

capacitor. This was not expected and is significant because the original work scope

encompassed a work area that was electrically separate from the operating plant.

As discussed in section E8.1 of this report, the relay is utilized when the plant is

shutdown and is electrically separate during normal plant operation. Working near

the terminal board area had the potential to, and in this case did, actuate the

protective feature of the relay causing the plant trip. Additionally, the technician

failed to electrically insulate the adjacent terminals prior to commencing the work.

As identified in the licensee's critique, the work package planning process,

conducted on June 6, for the relay calibration did not include a review of the

physical location and arrangement of the capacitor. Administrative Procedure (AP)

10.03, Work Package Planning, step 8.1.5 states, in part, to perform a walkdown

of the work site to obtain an understanding of the specific needs and location of the

work environment. Failure to adequately walkdown the work associated with WR

96-02875-00, to perform calibration of 71-59N-1UPRNOS, was not performed with

adequate detail to identify the high risk involved with performing the maintenance

with the plant at power.

_ . _ . _ __ _

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, The job scope required the removal of a capacitor from the back of the relay case. )

When faced with disconnecting the capacitor at the terminals, the technician did not '

stop the task. The technician recognized the plant impact if terminals 1 and 2 were

contacted but did not relay this to his supervisors or control room operators,

Administrative Procedure AP-10.01, Problem identification and Work Control, step

j 8.5.7 states, in part, that personnel encountering unanticipated problems while

performing activities should stop work and notify department supervision. However .

, during the calibration of 71-59N-1UPRN05, when the technician discovered the

capacitor had soldered leads instead of mechanical fasteners, as expected, he failed

to notify his department supervision. In addition, Instrument Maintenance 1

Procedure IMP-G20, Generic Troubleshooting and Maintenance Procedure, I

referenced in the work request, states, in part, that prior to disconnecting wires,

ensure any adverse affects on plant equipment operation or operational status has i

been discussed with applicable control room operator (s) and shift manager.

, However, during the calibration of the relay, when the technician determined that l

1

the work had the potential to adversely affect the operation of the plant, he failed to l

notify control room operators, the shift manager, or his department supervision.

c. Conclusions

.

The risk significance of this maintenance was not recognized by the licensee during

'

. the work planning. When the risk was recognized, it was not communicated to the

'

control room operators or maintenance supervisor. The inspectors concluded that

the event was the result of improper work request planning, failure to communicate

plant risk, and failure to properly protect energized adjacent terminals. Inadequate

walkdown during the planning process and the failure to communicate the risk on

the plant to control room operators constituted a procedure violation (VIO 50-

, 333/96006-01).

i

111. Enaineerina

E8 Miscellaneous Engineering issues (37551)

E8.1 Review of the Residual Bus Transfer durina the Seotember 16 Plant Transient

a. Insoection Scoce

! The inspector reviewed the electrical distribution bus transfer that resulted from the

technician's error on September 16,1996. Additionally, the inspector reviewed the

1

design basis of the residual bus transfer as described in the Final Safety Analysis

Report (FSAR), the FitzPatrick Design bases Document (DBD), and station drawings

to verify that the system operated as designed.

b. Observations and Findinas

'

As described in the FSAR, the automatic residual transfer takes place either after an

unsuccessful fast transfer, or when the nature of the disturbance will not allow a

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j- fast transfer. Residual transfer is delayed until the voltage on the affected bus has

decayed to approximately 25% of the normal, allowing re-energizing of the buses

j without equipment damage.

I- 4

l The relay that the technician was calibrating, 59N-lUPRNOS, provides ground fault  !

protection for the 24 kilo-volt (kV) isolated phase bus duct during the 345 kV

. backfeed operation. During at power operation this relay is not connected to the

j system since ground protection is provided by other relays on the output of the

4

generator. The inspector independently verified that reported technician's error

l would have simulated actuation of Relay 59N-lUPR05, and that the relay actuation i

j would result in a residual bus transfer. Additionally, the inspector verified that the

{ residual transfer operated as design.

i

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During a review of the FitzPatrick design basis document (DBD) for the electrice' ,

distribution system, the inspector identified that the actuation of Relay N59-  ;

IUPRN05 was not included in Section 4.0, " System Interfaces / Boundaries,

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j

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j interlocks, and Actuations," for the affected circuit breakers, even though the relay

j was installed at the time the DBD was developed. However, the installation of the

relay was described in Section 8.38 of the Electrical Distribution System DBD, as

.  ;

part of the system history of modifications. Although the DBD is not a required

document, it is used by the licensee for informational purposes. The licensee

intends to revise the electrical distribution system DBD Section 4.0 to included

Relay N59-luPRN05 as tracked by ACTS ltem 22509. *

c. Conclusions j

The inspectors determined that the reported technician error would have simulated

the actuation of the Relay 59N-lUPR05, which resulted in the residual bus transfer.

Additionally, the inspector verified that the residual transfer operated as designed.

E8.2 Failure of the D Residual Heat Removal Pumo Circuit Breaker Durina Torus Water

Coolina  ;

a. Insoection Scope

Following the scram on September 16,1996, Residual Heat Removal (RHR) D

circuit breaker failed to close during an attempt to manually start the pump for torus

cooling. Torus water cooling was required to compensate for the heat added from

Safety Relief Valves (SRVs), High Pressure Coolant injection (HPCI) and Reactor

Core Isolation Cooling (RCIC), which were used to control reactor pressure during

the transient. The licensee initiated troubleshooting efforts to determined the

reason for the RHR D breaker failure. Throughout the transient, A,C and B RHR

pumps provided sufficient torus water cooling. The inspector reviewed the ,

licensee's troubleshooting activities associated with the failed start attempt, and the l

subsequent corrective actions. Additionally, the inspector reviewed the

maintenance history for the RHR D and other 4160 volt circuit breakers.

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19

b. Observations and Findinas

The initial troubleshooting on September 16, of the RHR D circuit breaker (4160 volt

General Electric (GE) Magne Blast, Model AMH-4.76-250-1D) indicated an "open" in

the closing circuit. After racking out the breaker for further troubleshooting, checks

of the circuit breaker internals indicated continuity. Additionally, no abnormal

indications were identified during a visual inspection of the breaker. The breaker

was racked in and operators successfully closed the breaker from the control room.

Based on a previous failure of the same circuit breaker, the licensee suspected that

the breaker was not racked in tight enough. This would cause the contacts

associated with the positive interlock to remain open and prevent the breaker from

closing. The positive interlock provides personnel safety during breaker racking

operations, which prevents the racking in of a closed circuit breaker.

On September 17, following the event, the licensee performed additional l

troubleshooting and noted that racking the breaker out slightly (less then a half of I

turn on the rackout tool) caused the same indication of an open in the closing  !

circuitry as was observed during the troubleshooting the day before. As a result,

the licensee replaced the 52lS switch associated with the positive interlock, and

cleaned and lubricawd the racking mechanisms as preventive measures. The

breaker was cycled satisfactorily as a post maintenance test (PMT).

Based on the indications that the RHR D circuit breaker was not fully racked in, the

licensee wrote WRs 96-04852-00 through 33 to verify that all safety-related circuit

breakers that have an automatic close function were racked in fully. The PMT for

these WRs was the satisfactory remote start of the connected equipment. On

September 18, during the PMT for RHR D, the circuit breaker again failed to close.

1

WR 96-0482-32 was written as a detailed troubleshooting plan to further  !

investigate the RHR D circuit breaker failures. Continuity checks of the closing

circuitry indicated the same "open" as identified on September 16. Detail

troubleshooting indicated that the "open" was at contacts 5-6 of switch 52SM/LS,

and not at the 52lS switch as earlier suspected. Additionally, the licensee verified

certain breaker measurements were within the manufacturer's allowed tolerances,

and found no indication of breaker misalignment. Failure analysis by the licensee

determined the cause to be a loose fixed contact within the switch resulting in

intermittent failure of the contacts to always make at the same point. This resulted

in the contacts intermittently closing on the high resistance tiim coating and

preventing the continuity within the closing circuit. The inspector observed portions

of the troubleshooting performed under WR 96-04852-32 and considered it to be

appropriate. The inspector also examined the internals of the failed switch and

contacts, and reviewed Memo JMD 96-425 and determined the failure mode to be

reasonable.

Contacts 5-6 of switch 52SM/LS provide the function for an automatic close

permissive or for a white light indication. Neither of these functions are used at

FitzPatrick. The licensee identified that switch 52SM/LS contacts 5-6 were not

required as a result of a February 1996 failure of the switch in both RHR service

.

.

20

water (SW) pump circuit breakers. These failures were described in NRC Inspection

Reports 50-333/96-01 & 96-03. Additionally, the RHR SW pump circuit breaker

failures were described in Licensee Event Report (LER) 50-333/96-002. The license

determined that these failures were age-related and replaced the 52SM/LS contacts

5-6 in all safety-related circuit breakers having more than 1,500 close cycles, which I

included the RHR D pump breaker. The license also developed Modification D1-96-

052 to jumper out the switch 52SM/LS contacts 5-6 on all safety-related 4160  ;

circuit breakers that require automatic or manual closure to perform the intended

accident mitigation function. This modification was scheduled to be installed during

the upcoming refueling outage scheduled for October 1996. However, as a result

of the problems identified with the RHR D breaker, the licensee completed the

modification on all applicable breakers prior to plant startup. The inspectors i

determine the modification to be technically sound, containing the required reviews '

and approvals. The inspector also reviewed the WR to install the modification on

the RHR D circuit breaker and determined it to be adequate, containing an

appropriate post modification test.

The inspector reviewed the maintenance history of the RHR D circuit breaker with i

the maintenance engineer. After the 52SM/LS switch was repaired in February

'

1996, the breaker had successfully passed all required surveillances until May 8,

1996, when it failed to close during the performance of Procedure ST-2HB, LPCI i

Initiation Logic System 8 Functional Test." WR 96-02944-00 was used to complete l

the troubleshooting of this failure, and cause of the failure was documenteri in j

Memo JMD-96-277, dated June 3,1996. The memo provided several possible j

causes for this failure, all associated with the positive interlock portion of the

,

closing circuitry. The licensee determined that no corrective actions were required I

since the safety-related breakers that have a close function, are regularly operated I

and surveillance tested, which would detect positive interlock related failures. I

Between May 8 and September 12,1996, the breaker had been successfully cycled I

six times without a failure.

The inspector reviewed the surveillance completed on May 8, and the related work

documentation. The inspector noted that, although the licensee had identified the

apparent root cause to be associated with the positive interlock portion of the

closing circuitry, they were unable to confirm the failure location.

c. Conclusions

The inspectors determined that the troubleshooting associated with the September

16 and 18 failures of the RHR D circuit breakers was adequate and the corrective

actions taken to modify the applicable safety-related circuit breakers was

appropriate. However, the inspector considered troubleshooting associated with the

May 8,1996, failure of the RHR D circuit breaker to lack rigor, in that it did not i

adequately review the recent past problems with the 52SM/LS, and it assumed the

location of the problem without positive confirmation.

!

-. . - - - - . -. . - . . -- -- -- -- . - . - . ---

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21

E8.3 Traversina In-Core Probe (TIP) Svstem Ball Valve Control Failure

a. Inspection Scope (73051)

During restoration of power, following the September 16 turbine trip, a power

supply failure in the TIP torque control unit caused the three TIP ball valves to open

with a Group 2 containment isolation signal present. The inspector reviewed the

licensee's actions to comply with TS and corrective actions for failure of the

containment isolation valve.

b. Observations and Findinas

The licensee declared the TIP system inoperable and removed power from the motor

control units. The power to the motor control units was subsequently

administratively controlled utilizing a protective tagout request (PTR) and reactor ,

analyst procedure RAP-7.3.14, Traversing incore Probe System. The procedure j

directs clearing of the PTR prior to commencing TIP runs and the re-establishment

^

of the PTR when the work is completed. In addition, the isolation valves are being

tracked daily by performance of ST-1H, Primary Containment Isolation Valve l

Inoperable Test and in the control room LCO log. l

The TIP system was upgraded in February 1991 (modification F1-88-253) to improve l

system reliability, availability, and accuracy. This Siemens design replaced an older

General Electric design and, as reported by NYPA, is the only Siemens unit  ;

operating in this application in the United States. Preliminary review by the licensee

determined that a power supply failure in the torque control unit caused an errant'

signal to be sent from the position encoders to the valve control unit for the three

ball valves. The errant signal indicated that the TIP probes were in the vessel and

the valve logic is such that this signal results in the ball valves opening.

c. Conclusion:

The inspector concluded that adequate controls were in place to ensure compliance

with technical specifications (TS) for an inoperable containment isolation valve. The j

licensee is continuing to investigate the failure of the power supply and opening of

the isolation valves therefore this issue will remain unresolved (URI 50-333/96006-

04).

E8.4 (Closed) (URI) 50-333/95021-02: Environmentally Qualified (EO) Electrical Fuses -

a. Insoection Scope

The inspector reviewed the licensee's action plan, JSED-APL-95-019, Revision 4,

governing the discrepant fuses in EQ applications noted in NRC Inspection Report

50-333/95-21, as well as root cause evaluation report JAF-RPT-ELEC-02316 on this

issue. The inspector also reviewed the licensee's EQ justifications for continued

operation [[::JAF-EQ-JC|JAF-EQ-JC]].O-96-01, Revision 1, and 96-02, Revision 0, as well as AP- ]

5.12, Revision 4, Replacement of Electrical Fuses.

.

.

22

b. Observations and Findinas

After inspection of the fuses in all 138 EQ motor control centers and electrical

panels, a total of 18 fuse discrepancies were identified and were subsequently

resolved by fuse replacement or development of EQ supporting documentation.

Identification of EQ fuse concerns and subsequent change out of the fuses in

question was completed on all equipment within the applicable LCO action time.

The root cause evaluation determined that the majority of the discrepancies were

caused by breakdowns in the fuse selection process as well as weaknesses in the

modification / work process interface. Specifically, operators and maintenance

personnel confused fuses that are environmentally qualified with fuses that were

procured for safety-related, non EQ applications as they were identical in

appearance. Furthermore, adequate documentation verifying the environmental

qualification of certain fuses qualified by similarity was not provided or errors were

made in the Bill of Materials for the fuses in specific components. However, in six

of the 18 cases, the breakdown in the process governing the installation of EQ

fuses could not be determined.

A broad range of corrective actions were implemented to prevent a recurrence of

this problem to address each of the root causes identified. Substantial progress has

been made in the implementation of these corrective actions which included a

revision to AP-5.12, Employee Training, quality assurance (QA) follow-up audits and

creation of a procedure on generating a proper Bill of Materials.

The inspector noted that the licensee has an ongoing fuse control action plan to

address additional non-EQ fuse discrepancies identified recently, most in response

to an operations department effort to validate the accuracy of operator aids in the

plant. This action plan, JSED-APL-95-008, is in the process of being implemented.

c. Conclusions

The licensee performed a thorough and detailed root cause investigation of the EQ

fuse discrepancies identified and developed a comprehensive series of corrective

actions to prevent recurrence. The majority of these corrective actions have been

completed. The success of these corrective actions is, in part, reflected by the

absence of EQ related fuse discrepancies in the last six months in spite of an

extensive ongoing fuse control program verification and improvement program.

However, since documentation of the environmental qualification of the fuses in

question was not in an auditable form as required by 10 CFR 50.49.j, a violation of

NRC requirements occurred. This violation will not be cited in accordance with

Section Vll.B.1 of the NRC Enforcement Manual as the violation was licensee

identified, non-recurring, promptly and thoroughly corrected and of low safety

significance (50-333/9606-05).

E8.5 Review of UFSAR Commitments

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

updated final safety analysis report (UFSAR) description highlighted the need for a

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

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23

special-focused review that compares plant practices, procedures, and/or

parameters to the UFSAR description. While performing the inspections discussed i

in this report, the inspectors reviewed the applica%s portions of the UFSAR that

related to the areas inspected. The inspectors verified that the UFSAR wording was l

l consistent with the observed plant practices, procedures and/or parameters.

. ,

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i l

, IV. Plant Suonert I

'

R1 Radiological Protection and Chemistry (RP&C) Controls (84750)

>

l

'

R1.1 Manaaement Controls

a. Inspection Scoce

The inspectors reviewed the management controls implemented by observation of

management-staff interactions; interviews; and review of program / organization

changes, quality assurance (QA) audits, and review of the semi-annual radioactive

effluent report.

b. Observations and Findinos

The inspectors reviewed changes to the organization and administration of the

radioactive liquid and gaseous effluent control programs and determined that I

responsibility for the programs had moved from the Operations General Manager to i

the Support Services General Manager. The Chemistry staff had primary

responsibility for conducting the radioactive liquid and gaseous effluent control  !

programs. The Operations, Engineering, Radwaste, and Instrumentation and

Controls departments supported the radiological effluent control programs relative tc

air cleaning systems, radioactive liquid discharges, and radiation monitoring nystem

calibrations. ,

1

The inspectors reviewed QA Audit Report No.96-01J (completed

February 27,1996). The audit was conducted by Nuclear Quality Assurance (NOA) l

personnel and covered the radioactive liquid and gaseous effluent control programs.

The audit findings were administrative in nature and were not of regulatory

significance. The inspectors noted that the audit team was composed of members

with appropriate technical expertise to assess the radioactive liquid and gaseous

effluent control programs. The inspectors also reviewed QA Surveillance Report

(SR) No.1878 which assessed operations performance for o simulated liquid

effluent release. The inspectors considered this to be a good initiative on the part

of the licensee because there were no opportunities to observe an actual planned

release of liquid effluents during 1995.

The inspectors reviewed the 1995 Semi-annual Radioactive Effluent Release

Reports. These reports provided data indicating total released radioactivity for liquid

and gaseous effluents. These reports also summarized the assessment of the

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24

projected maximum individual and population doses resulting from routine

radioactive airborne and liquid effluents. Projected doses to the public were well

below the Technical Specification (TS) limits. The 1995 Semi-annual Reports  ;

properly assessed unplanned releases, as required by TS. The inspectors l

determined that there were no anomalous measurements, omissions or adverse

trends in the reports.

c. Conclusions

The licensee implemented good management control and oversight of the quality of j

the radioactive liquid and gaseous effluent control programs. I

R1.2 Heview of the Offsite Dose Calculation Manual (ODCM)

i

a. Insoection Scone '

l

The inspectors reviewed the ODCM implemented at the FitzPatrick Nuclear Power I

Plant, including: (1) dose factors, (2) setpoint calculation methodology, (3)

bioaccumulation factors for aquatic sample media, (4) LER 96-001 which pertained I

to the ODCM, and (5) the impact of hydrogen water chemistry and the ability to

comply with 40 CFR 190.

b. Observations and Findinas

The ODCM provided descriptions of the sampling and analysis programs, which

were established for quantifying radioactive liquid and gaseous effluent

concentrations, and for calculating projected doses to the public. All necessary

parameters, such as effluent radiation monitor setpoint calculation methodologies,

site-specific dilution factors, and dose factors, were listed in the ODCM. The

licensee adopted other necessary parameters from Regulatory Guide 1.109. The

inspectors noted that the most recent submittal contained improved detail as

compared to previous submittals.

The inspectors reviewed the licensee's actions relative to LER 96-001, Failure to

implement Radiation Monitor instrumentation Setpoint Changes Following Revision

to the ODCM. The inspectors assessed that the LER dispositioned an ODCM-related

discrepancy that was not of regulatory significance. The inspectors had no further

questions regarding LER 96-001 and considered it closed.

The inspectors reviewed severallicensee studies concerning hydrogen water

chemistry and considered these studies to be comprehensive. Based upon the

licensee survey data, the licensee appeared to be in compliance with the

requirements of 40 CFR 190 relative dose to members of the public at the current

hydrogen injection rate of 18.5 scfm. The inspectors noted to the licensee that

there could be a potential for a compliance problem with 40 CFR 190 relative to

Niagara Mohawk Power (NMP) Corporation personnel occupying the adjacent NMP

owner controlled areas at higher hydrogen injection rates if no compensatory

measures were to be taken. The licensee was aware of this potential problem and

1

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25

was analyzing methods of managing this situation in anticipation of the need to

increase the hydrogen injection rates for increased protection against inter-granular

stress corrosion cracking.

c. Conclusions

The inspectors determined that the licensee's ODCM contained sufficient

specification, information, and instruction to acceptably implement and maintain the

radioactive liquid and gaseous effluent control programs. Licensee analyses of the

dose impact to members of the public as the result of hydrogen water chemistry

were good.

R1.3 Implementation of Radioactive Liauid and Gaseous Effluent Control Proarams

a. Inspection Scooe

inspection of this area consisted of: (1) physical walkdown of facilities and

equipment, including the control room; (2) review of selected licensee's procedures;

and (3) review of selected radioactive liquid and gaseous discharge permits with

respect to TS/ODCM requirements.

b. Observations and Findinas

During a plant tour, the inspectors noted that all effluent Radiation Monitoring ,

Systems (RMS) were operable at the time of this inspection. .The inspectors noted  !

that the effluent control procedures were detailed, easy to follow, and ODCM '

requirements were incorporated into the appropriate procedures. The inspectors

also determined that the gaseous discharge permits were complete, and met the i

TS/ODCM requirements for sampling and analyses at the frequencies and lower I

limits of detection established in the TS.- I

During a discussion with Chemistry staff, the inspectors noted that the responsible H

individuals had maintained and cananced their knowledge in the areas of: (1) i

I

radioactive liquid and gaseous effluent controls; (2) effluent and process RMS; (3)

the application of procedures designed to protect the public health and safety, and

the environment; and (4) the TS and ODCM requirements.

c. Conclusion

Based on the above observations, reviews and discussions, the inspectors

determined that the licensee established, implemented, and maintained effective

radioactive liquid and gaseous effluent control programs.

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

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i

R1.4 Calibration of Effluent / Process Radiation Monitorino Systems (RMS)

! '

a. Inspection Scone

l t

i

The inspectors reviewed the most recent calibration results for the following

! effluent and process RMS to determine the implementation of the TS requirements

j and Updated Final Safety Analysis Report (UFSAR) commitments:

$

e Liquid Radwaste Discharge Monitor,

l e Service Water Discharge Monitor,

l e Main Steam Line Radiation Monitors,

j e Reactor Building Closed Loop Cooling Radiation Manitor,

e Main Stack - Normal and High Range Noble Gas Monitors,

e Refuel Floor Exhaust Radiation Monitor,

j e Reactor Building Exhaust Radiation Monitor,

* Turbine Building Exhaust - Normal and High Range Monitors,

i e Radwaste Building Exhaust - Normal and High Range Monitors, and 'i

e Offgas Radiation Monitor

b. Observations and Findinas

The l&C Department and Radiological and Environmental Services Department

(Chemistry) had the responsibility of performing electronic and radiological

calibrations, respectively, for the above effluent / process radiation monitors. A

system engineer had the responsibility to maintain the above RMS operable and

upgrade the system, as necessary. All radiological calibration results reviewed were

within the licensee's acceptance criteria.

/ During the review of the above RMS radiological calibration results, the inspectors

independently verified several calibration results, including linearity tests and

conversion factors. The inspectors used a linear regression for the comparisons and

the comparisons were in good agreement. The licensee stated that a statistical

method, such as a linear regression, would be reviewed and applied as necessary.

The inspectors discussed effluent RMS operability / reliability with Chemistry staff.

From this interview, the inspectors determined that the Chemistry staff had good

knowledge of the effluent RMS relative to operability requirements and performance

history. The inspectors also noted that Chemistry trended the operability of the

effluent RMS.

The licensee maintained a system for monitoring the reliability of the effluent RMS.

The licensee tracked the comparison between effluent monitor reading results and

expected monitor readings determined from laboratory sample measurements, to

ensure that the effluent RMS responded acceptably. The inspectors reviewed these

comparison results for liquid and gaseous effluent monitors during this inspection

and determined that the licensee's comparisons were in reasonably good

agreement.

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

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

.

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27

c. Conclusions

The licensee has implemented effective programs for effluent RMS calibration and

reliability assessment.

R1.5 Air Cleanina Systems

a. Insoection Scope

The inspectors walked down systems, reviewed the licensee's most recent

surveillance test results, and interviewed the system engineer assigned to manage

the station air cleaning systems to determine the implementation of TS requirements

and the UFSAR commitments for: (1) the standby gas treatment system; (2) the

control room ventilation system; (3) technical support center system; and (4) the

radwaste building air cleaning system. j

b. Observation and Findinas

The inspectors reviewed the following surveillance test results:

e Visual inspection, j

e In-Place HEPA Leak Tests, 1

e in-Place Charcoal Leak Tests, 1

e Air Capacity Tests, I

e Pressure Drop Tests, and

e Laboratory Tests for the lodine Collection Efficiencies.

All test results were within the licensee's TS acceptance criteria. One individual

within the Engineering Department was assigned to manage the station ventilation

systems. All TS and UFSAR tests were conducted at the prescribed frequencies.

Unsatisfactory test results were analyzed and corrective actions were implemented

in a timely manner. The inspectors noted that attention given to the air cleaning

systems was excellent. The System Engineer monitored and trended the

performance of the air cleaning systems.

c. Conclusion

The licensee has implemented very good air filtration / ventilation system surveillance

programs for systems described in the TS and UFSAR. Attention placed on station

air cleaning systems by the engineering department was very good.

R5 Staff Training and Qualifications in RP&C

a. Inspection Scope (83522)

The inspector reviewed the training provided to both plant radiological workers and

health physics technicians. The inspector toured training facilities and also audited

one training class for health physics technicians.

1

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.

b. Observations and Findinas

4

Since the last inspection in this area, the licensee constructed a new enhanced

7 radiation worker (ERW) training facility in the training center. As previously

! discussed (NRC Inspection Report 50-333/96-03) this training program was

.

developed to address concerns with the practices of plant radiation workers

,! observed during and immediately after the last refueling outage (RFO11). The new

'

training facility is a very close approximation of the environment typically

encountered in the plant, and stresses contamination control and radiological

condition awareness. All current plant employees have taken or will have taken this

training prior to the commencement of the next refueling outage (RFO12).

The inspector reviewed plant records and observed numerous plant workers l

entering and working in the reactor facility. A general improvement in worker l

practices was observed. j

!

The inspector also attended one training session for health physics technicians and i

supervisors. The session attended was on control of radiological activities on the  !

refueling floor during an outage. Since the next refueling outage is scheduled to

commence at the end of October, this session was very timely. The session was i

set-up to encourage classroom participation and use the instructor in the role of I

discussion moderator.

c. Conclusions

Training activities continue to support and aid in improving plant radiological worker

practices. Additionally, specialized training for health physics technicians was both

timely and well presented.

R6 RP&C Organization and Administration

a. Insoection Scone (83522) .

The inspector reviewed management organization in the radiological controls

program, including maintaining occupational radiation exposure as low as is

reasonably achievable (ALARA), control of radiological work and radiological

housekeeping. The inspector made frequent tours of the radiologically controlled

area (RCA), and discussed specific radiological controls with the radiation protection

supervisors and various radiation protection technicians.

b. Observations and Findinas

in accordanca with plant Technical Specifications, responsibility for sate radiological

operations at the facility are the responsibility of the Plant Manager. The

Radiological and Environmental Services (RES) Manager serves as radiation

protection manager at the facility, and reports through the General Manager -

Support Services to the Plant Manager. The RES department is split between

chemistry and health physics groups. The health physics group consisted of a

_ -

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.

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29

radiological engineering manager, health physics manager and technical staff.

Additionally the health physics manager has several supervisors reporting directly to

him relative to instrumentation and respiratory protection, decontamination and

shipping, ALARA and operational health physics. Recent modifications included

changing the supervisor for dosimetry, and placing the responsibility for RES under

the General Manager - Support Services. Previously the RES Manager reported to

the General Manager - Operations.

Discussions with various managers, supervisors and technicians indicated that all

had an appropriate awareness of previously identified problems within the RES

Department, and that all were aware of actions taken to address these issues.

These issues, previously identified and discussed in NRC Inspection Report No. 50-

333/95-10 included poor radiological worker practices, failure of the health physics

technicians to provide appropriate support to the plant staff, and a failure of the

health physics group to properly utilize or respond to findings and recommendations

made during quality assurance reviews. Interdepartmental communications

appeared to be the common problem still needing to be addressed. All personnel

contacted identified this as a key issue that still needed to be resolved.

Since the last inspection in this area (documented in NRC Inspection Report 50-

333/96-03), the unit has generally been operating at or near full power, while

continuing preparations for refueling outage 12 (RFO12) planned for late October

1996. During this inspection, several tours of various facilities located within the

radiologically controlled area (RCA) were conducted. Extensive efforts by the ,

licensee during the past year have led to notable improvement in the area of

l

radiological housekeeping. Especially notable was the condition of the areas on the '

refueling floor. Also observed during these tours was the significant amount of

scaffolding being erected in the reactor building in preparation for the RFO12 to

support snubber inspections taking place. These inspections are occurring before ,

the start of RFO12 in order to reduce the scope of work which must be performed  !

during the outage, and consequently the outage length. Data from previous outages

indicates that 3-5 person-rem per day can be saved by minimizing the outage

length. Allinspections were taking place in locations not affected by power

operations, and therefore not leading to additional occupational exposure. j

l

For RFO 12, the licensee established goals of not more than 45 days and not mae i

than 168.8 person-rem. The ALARA goal was established at the end of 1995, and

is part of the annual site goal of not more than 260 person-rem. At the time of this

inspection, only four ALARA reviews in support of the refueling outage remained to

be completed. Data on total person-hours to be worked on four specific tasks had

not yet been provided by the appropriate working groups in order to complete these

associateci ALARA reviews. The licensee anticipated completing these remaining

reviews b/ mid-September. l

Current estimates by the ALARA staff show an anticipated total outage evposure of

184 person-rem, so that considerable exposure savings will have to be realized if

the licensee is to meet its outage exposure goal.

1

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30

J

. c. Conclusions

!

Plant management appears to have a good understanding of previously identified

problems involving radiation workers and health physics technicians, actions taken

to address these problems. Outage preparations appear appropriate in order for the

facility tc, meet its goals for outage duration and occupational exposure.

,

R7 Quality Assurance in RP&C Activities

i

a. Insoection Scope (83522)

!

'

The inspector reviewed audits, surveillances and RES self-assessments in order to

evaluate the effectiveness of quality assurance activities in the RES department.

, The inspector also discussed planned audits for the remainder of the year with

,

Quality Assurance (QA) personnel.

b. Observations and Findinas

Table R7 provides a listing of audits, surveillances and RES department self-

assessments reviewed bv the inspector. The scope and technical depth of these

reviews, especially in the self-assessments, was significantly improved over those

reviewed during previous inspections. More importantly was the acceptance of

I

findings and recommendations contained in these documents by RES management

and st sff. Findings and recommendations are now being promptly addressed and

the adequacy of responses verified i,y RES managerunt prior to submittal to QA.

i

'

An eadit of the health physics program by the QA department is scheduled to

co',imence in September,1996. The lead auditor is a QA engineer who has

i

r:eviously served as Radiological Engineering and Health Physics Manager within

.

the RES department. Several technical experts from outside the New York Power i

{ Authority have also been hired to assist in the audit. The self-assessment program

also is continuing, but will be temporarily suspended during the refueling outage.

4

c. Conclusions

!

Audits and surveillances provided by the QA department continue to be of high

quality. The RES department had made significant improvements in the areas of j

{ self-assessment and acceptance of QA findings and recommendations.

l

l R8 Miscellaneous issues I

R8.1 Evaluation of Unmonitored Release After September 16,1996 Scram

i

a. Insoection Scoce (71750) l

l

The inspector observed the performance of the EP radiological staff during the event

and reviewed radiological records and surveys. Survey results were reviewed to

4

determine the extent of radiological release.

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31

b. Observations and Findinas

After the September 16,1996, plant scram, turbine building ventilation was isolated

while there were steam leaks from a blown low pressure turbine and a reactor feed

pump rupture disk. Pressure in the turbine building resulted in steam exiting from

the turbine building, indicating an unmonitored release. During the event, onsite I

surveys were conducted by survey teams which indicated that no release occurred. l

Calculations were performed using conservative assumptions which showed that if I

any release occurred, it was negligible. The EP radiological coordinator directed

appropriate surveys and remained cognizant of radiological activities. Subsequent  ;

to the event, environmental monitoring samples were collected and surveyed and l

direct reading radiation monitors were read. The result was that no increase in

radiation levels was observed as a result of the plant transient. Analysis results for

the environmental samples were less than detectable for all plant related

radionuclides. I

c. Conclusions

During the event, EP radiological activities were well coordinated. Based on surveys

and environmental radiation monitoring results, there was no indication of any

increased radiation levels associated with the September 16,1996 event.

P1 Conduct of Emergency Preparedness (EP) Activities

a. Insoection Scope (71750)

The inspectors observed the EP organization performance during the September 16, l

1996, plant event. A review of EP staffing, event classification and notification and

facilities using LAP-1, Emergency Plan Implementation Checklist and IAP-2,

Classification of Emergency Condition, and review of the technical support center l

(TSC) and operational support center (OSC) logs and activities were also performed.

b. Observations and Findinas .

1

At 1:40 p.m. on September 16, approximately 36 minutes after the initial plant

scram, the event was classified as a notification of unusual event (NUE) in

accordance with emergency action level (EAL) 7.2.1, main turbine failure resulting

in casing penetration or damage to turbine seals or generator seals. The event

notifications were completed by 2:16 p.m. and additional followup notifications

were made as necessary. The NRC entered the monitoring phase at the incident

response center. The licensee staffed the TSC and OSC to provide support to

operations and the EP organizations were operational at 2:10 p.m. At 2:36 a.m. on

September 17, the NUE was terminated upon restoration of the main condenser and

verification of cooldown capability.

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

1

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j 32

!

c. Conclusions l

The implementation of the emergency plan was a sound decision. The event was l

il appropriately classified, notifications made and the TSC and OSC were properly

staffed and provided assistance to operators in a timely manner. EP procedures,

i

j logs and status boards were in use and significant EP facility discrepancies were not

j evident.

l

j P3 EP Procedures and Documentation

}

j An in-office review of revisions to the emergency plan implementing procedures

. submitted by the licensee was completed. A list of the specific revisions reviewed

.! are included in Attachment 1 to this inspection report. The inspector concluded

l that the revisions did not reduce the effectiveness of the emergency plan and were

i acceptable.

i

1 F8 Miscellaneous Fire Protection issues j

J

! F8,1 Performance of the Fire Suooression System durina the September 16 Plant

! Transient

$

l a. Inspection Scope

t

l

l During the September 16,1996, plant transient, fire suppression sprinkler systems  !

! within the turbine building condenser area actuated, and the fire header above the

I

'

turbine bearings charged, but did not actuate. The inspectors reviewed the

licensee's evaluation of the fire protection system performance during the event,

j and the work requests (WRs) associated with the replacement of the affected

i sprinkler heads. Additionally, discussions were held with the fire protection

} engineer, and the fire protection system engineer regarding the system

j performance, post transient plant inspections and restoration of fire protection

! equipment.

i-

l b. Observations and Findinas

i

j '

During the September 16 plant transient, both the reactor feed water pump (RFP)

!. turbine exhaast header and the main turbine hood disc ruptured, causing local

! temperatures to increase. The increase in temperature resulted in the actuation of

the fire suppression sprinkler system within the turbine building condenser area, and

l the fire water header above the turbine bearings charged. During the recovery from

j the event, operators appropriately secured the fire suppression system.

!

I Following the event, the system engineer walked down portions of the fire

- protection systems, including the sprinklers, fire detection panels and emergency

i lights, and determined that fire protection equipment responded as designed to the

j event. In areas that were wetted by the fire water released, the licensee performed

inspections of the electrical panels, cabinets and junction boxes for water intrusion

with no problems identified.

!

!

l

4

,-m .. . ..- - - , , - - - , - . - - - - - - - -- n.,. ., , r..----- ,,

..

.

33

i

Subsequently, the licensee drained the fire header above the turbine bearings and I

returned it to service. Additionally, the fire suppression sprinkler headers that had

actuated, and surrounding sprinkler heads which the licensee determined may have  !

degraded due to the increased temperatures experienced during the event, were

replaced under WR 96-04792-00. A total of 41 sprinkler heads were replaced with 1

an equivalent model head as evaluated in Design Equivalent Modification D1-92- '

197. The system was subsequently leak tested under WR 96-04792-02, and

returned to service. The inspector reviewed portions of the completed WRs and the

design equivalent modification, and determined them to be appropriate.

c. Conclusions

The fire suppression system equipment performed as designed during the

Septemtier 16 plant transient. The licensee's inspections of wetted equipment

resulting from the actuation of the sprinkler system, and subsequent sprinkler head

replacernent were reviewed by the inspector and determined to be appropriate.

S1 Conduct of Security and Safeguards Activities

a. Insoection Scope (71750)

The inspector observed security force member support during the September 16  ;

event. j

b. Observations and Findinas

The September 16 transient resulted in the loss of normal plant communications and

vital area doors failed in the locked position. Security personnel were assigned to  ;

-

strategic areas in the plant to help with access and communication for operations -  !

personnel. '

c. Conclusions  ;

i

Security force members responded in a timely manner to assist with plant

communications and vital area access.

V. Manaaement Meetinos

X1 Exit Meeting Summary

The inspectors presented the inspections results to raembers of the licensee

management at the conclusion of the inspection on October 10,1996. The

licensee acknowledged the findings presented and nc.ted that none of the materials

examined during the inspection was considered prop ietary information.

.

.

34

PARTIAL LIST OF PERSONS CONTACT

T

New York Power Authority

M. Colon.b, Plant Manager

R. Locy, Operations Manager

D. Ruddy, Director, Design Engineering

A. Zaremba, Licensing Manager  :

1

NRC .

l

C. Cowgill, Chief, Projects Branch 2

R. Keimig, Chief, Emergency Preparedness and Safeguards Branch i

W. Rutand, Chief, Electrical Engineering 3 ranch

J. Shannon, Reactor Engineer, Electrical Engineering Branch

G. Smith, Senior Physical Security inspector

.

l

I

l

l

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

.

.

35

INSPECTION PROCEDURES USED

37551 Onsite Engineering

62703 Maintenance Observations

61726 Surveillance Observations

71707 Plant Operations

71750 Plant Support

,

83522 Radiation Protection Organization and Management Controls

84750 Radioactive Waste Treatment, and Effluent and Environmental

Monitoring

ITEMS OPENED, CLOSED, AND DISCUSSED

Ooened

50-333/96006-001 VIO Maintenance planning and work associated with WR 96-

02875-00 to perform calibration of 71-59N-1UPRN05 was

improperly performed resulting in a reverse power scram and

plan transient

50-333/96006-002 URI Condenser response related to September 16,1996 reverse

power scram (i.e. MSIV isolation signal input on low condenser

vacuum)

50-333/96006-003 IFl Seismic qualification process for commercial grade equipment

50-333/96006-004 URI Failure of a TIPS power supply resulting in opening three

containment isolation valves

50-333/96006-005 NCV Documentation of environmental qualification of fuses were

not in an auditable form

Closed

50-333/9521-002 URI EQ fuse discrepancies and resulting corrective actions to

prevent recurrence

50-333/96-001 LER Failure to implement radiation monitoring instrumentation

setpoint changes following revision to the offsite dose

calculation manual (ODCM)

. . . - _ _ _

.

'

,

36

50-333/96-009 LER Incorrect Time Delay Relay Installation for Emergency Diesel 1

Generator

l

l

Discussed

'

None

4

4

1

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1

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.

.

e

ATTACHMENT 1

EP Implementing Procedures Reviewed ,

!

)

Document Document Title Revision

E-Plan Appendix H 19 ,

EAP-3 Fire 18 I

'

EAP-5.3 Onsite/Offsite Downwind Surveys and

Environmental Monitoring 4

EAP-8 Personnel Accountability 32

EAP-17 Emergency Organization Staffing 71 l

EAP-22 Operation and Use of Radio Paging Device 25  !

EAP-43 Emergency Facilities Long Term Staffing 32 l

SAP-2 Emergency Equipment inventory 20

SAP .3 Emergency Communications Testing 49

SAP-7 Monthly Surveillance Procedure for On-Call

Employees 29

SAP-8 Prompt Notification System Failure / Siren

System False Activation 9

l

1

-. _ -.

.

.

.

ATTACHMENT 2

Procedures Reviewed Related to September 16,1996 Event

Document Document Title Revision

EOP-2 Reactor Pressure Vessel Control 2

EOP-4 Primary Containment Control 2

AOP-1 Reactor Scram 28

AOP-21 Loss of UPS 2

AOP-31 Loss of Condenser Vacuum 10

AOP-57 Recovery from Residual Bus Transfer 2

OP-4 Circulating Water System 33

.

9

4

d

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i

)

$

9

l

.

A

4

4

,

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

.

~.

>a

ATTACHMENT 3

4

,

September 16,1996 Seauence of Events

1

3

1304 While performing 345 KV relay maintenance, l&C technicians shorted across relay

contacts which simulated a main generator neutral bus ground fault.

Output breakers trip, main turbine and generator trip, reactor scram on turbine

i control valve fast closure.

! Residual bus transfer results in loss of balance of plant loads and uninterruptible

, power supply.

All 4 emergency diesel generators start but do not load (as designed).

,

The "G" safety relief valve opens, reactor pressure peaks at 1082 psig.

l High pressure coolant injection and reactor core isolation cooling start at low reactor

I

vessel level. i

Recirc pumps trip and alternate rod insertion on low reactor vessel level.

Lowest indicated reactor vessel level at 126" (normal reactor vessel operating level l

is 201.5 ").  !

Operators entered EOP-2, reactor pressure vessel (RPV) Control, on low RPV water l

level. 1

I

1305 Turbine bypass valves close on loss of electro-hydraulic control (EHC). '

The reactor feed pumps trip on low suction pressure due to loss of condensate

pumps.

1311 (Approx time) B LP turbine rupture disc ruptures. Turbine building pressure reached

3 psig. Also, B RFP rupture disc ruptured at 5 psig.

1313 Loss of A and B RPS during manual transfer, MSIVs close.

1323 The "B" RPS was restored.

1327 The "A" RPS was restored.

1329 Operators attempt to restore UPS.

i

1335 TlP isolation valves open.

1340 The E-plan was entered and an unusual event was declared.

1353 Operators started the B RHR pump for torus cooling, D RHR pump failed to start.

- _ . . . _ _ _ _ _ _ . . _ - - _ ___ . _ _ _ _ _ _ _ . _ . . _ . - _ _ _ _ . _ . .

i

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.

Attachment 3 2

1410 TSC and OSC staffed.

1415 Blown rupture disk confirmed on B LP turbine.

1417 Operators successfully restored the UPS.

1421 Reset PCIS isolation and verified all rods in via full core display. j

!

1623 Fuel pool cooling restored, i

1658 Cycled D RHR pump breaker, started D RHR pump.

2016 Restored circ water system.

2022 rupture disc on LP turbine installed.

2356 MSIVs opened.

0205 Condenser vacuum reestablished. BPV used for RPV control.

I

0236 Exited unusual event.

'

0544 Started shutdown cooling on B RHR pump. i

0600 Coolant temperature less than 212 degrees.  !

0614 Mode switch in refuel.

1

1

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

o

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TABLE R7

Listino of Audits, Surveillances and

Self-Assessments Reviewed

Action Plan to improve Radiological Performance, Rev 1, July 12,1996

Review of the JAF Radiation Protection Program, January - July 1996, August 9,1996

RES Department Six Month Self Assessment, August 26,1996

JRES-SAR-96-008, Sealed Source Leak Rate Testing, May 22,1996

JRES-SAR-96-009, Radiation Worker Practices, July 17,1996

JRES-SAR-96-011, Informational Content of ALARA, Dosimetry and Radiation Protection i

Records, Logs and Reviews, July 30,1996

QA-SR-1865, Yankee Atomic Environmental Laboratory TLD Processing Review, May 13,

1996

QA-SR-1873, Review of the Action Plan to improve Radiological Performance, Action Plan

No. JRES-APL-95-015, June 28,1996

QA-SR-1879, Radwaste Shipment No. 0696-6061, July 12,1996

QA-SR-1892, Receipt inspection of HIC L-490261-55, August 8,1996

QA-SR-1898, inspection of the Capping and Storage of HlC Line L-490261-55 and Receipt

inspection of HIC Liner L-490261-40, August 14,1996

QA-SR-1902, inspection of the Capping of HIC Liner L-490261-40, August 21,1996

__