ML20137E983

Insp Rept 50-333/97-01 on 970105-0222.Violations Noted. Major Areas Inspected:Operations,Maintenance,Engineering & Plant Support

ML20137E983
Person / Time
Site:	FitzPatrick
Issue date:	03/24/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20137E965	List: ML20137E960 ML20137E969 ML20137E983
References
50-333-97-01, 50-333-97-1, NUDOCS 9703280348
Download: ML20137E983 (34)

See also: IR 05000333/1997001

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U.S. NUCLEAR REGULATORY COMMISSION

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Region I

License No.: DPR-59

Report No.: 97-01 l

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Docket No.: 50-333

Licensee: New York Power Authority  ;

Post Office Box 41 i

Scriba, New York 13093

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Facility Name: James A. FitzPatrick Nuclear Power Plant

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Dates: January 5,1997 through February 22,1997  !

Inspectors: G. Hunegs, Senior Resident inspector *

R. Fernandes, Resident inspector l

D. Dempsey, Reactor Engineer i

J. Furia, Senior Radiation Specialist '

D. Silk, Senior Emergency Preparedness Specialist

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

Division of Reactor Projects

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9703280348 970324

PDR ADOCK 05000333 ,

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EXECUTIVE SUMMARY

James A. FitzPatrick Nuclear Power Plant

NRC Inspection Report 50-333/97-01

Operations

e A large influx of fish blocked the travelling screens causing a reduction in intake

water level and leading to a manual reactor scram on January 23,1997. Operator

response was appropriate to place plant in a safe condition.

The automatic start function on high differential pressure for 2 of the 3 travelling

screens was disabled for maintenance at the time of the event. The licensee's work

planning and control process did not identify the risk significance of this evolution

and thus allowed this to occur. Failure to recognize the importance of the travelling

screens automatic start function resulted in a poor decision to remove two of the

three travelling screens from service at the same time.

e The reactor startup, conducted on January 28, was performed in a safe and

controlled manner.

e Operator actions taken to isolate the steam leak located in a feedwater heater gauge

glass and prepare the piant for the feedwater transient were good and the decision

to evacuate the turbine building was conservative,

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• On January 24, while preparing to enter shutdown cooling, the D residual heat

removal pump tripped due to an invalid isolation signal. The equipment responded

properly and operator actions taken to establish shutdown cooling were appropriate. .

Corrective actions to install a high point vent modification to prevent shutdown ",

cooling isolation were not timely. Three years have elapsed since the corrective i

actions were assigned and the complete corrective actions have not been fully l

implemented. The licensee is still reviewing the event and as such the issue will {

remain unresolved (URI 50-333/9701-01). t

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• Use of overtime for workers conducting safety related activities was appropriately

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controlled. When individuals would exceed the work hour limits, a memorandum '

was on file authorizing the overtime.

Maintenance

• The licensee identified that several safety related breakers had failed latching pawl

cotter pins which could result in equipment operational failures. The licensee

replaced cotter pins for 17 of 21 safety related breakers and implemented additional

corrective actions. Corrective actions to address the problem with the failure of

cotter pins in breakers were adequate. A failure analysis for the cotter pins was

performed and was determined to be comprehensive and provided further

information on a generic GE Magne Blast breaker issue.

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Executive Summary (cont'd)

• On January 13, the C service water pump failed to start. The cause was

determined to be a high resistance contact in the breaker closing circuit. As a result

of a history of problems, the licensee was aggressively pursuing reliability issues

with the GE Magne-blast circuit breaker contact switches.

• A maintenance error resulted in the installation of an incorrect gasket on a

feedwater heater gauge glass and resulted in a challenge to operators when a steam

leak subsequently developed. Maintenance planning and work control documents

lacked sufficient detail to ensure that the work conducted during the gauge glass

maintenance was done correctly.

Enaineerina

• Administrative post-modification requirements for revision of drawings, procedures,

and other design-basis documents were implemented effectively,

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• The guidance for determining the operability of degraded or nonconforming systems l

and components provided in procedure AP-03.11 was consistent with NRC Generic  ;

Letter 91-18. Information contained in Technical Support memoranda was adequate j

to support the operability determinations performed by Operations Shift Managers.

• The installation of devices to restrain the disengaging levers of twelve safety-related

air-operated containment isolation valves improved the reliability of the valves.

However, the modifications were implemented contrary to 10 CFR 50.59

requirements for changes to the facility. (VIO 50-333/9701-02) 1

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• A Notice of Deviation involving revision of the Updated Final Safety Analysis Report .i

(NOD 50-333/928101) and an unresolved item concerning control and review of ":

vendor calculations (URI 50-333/951301) were closed.  !

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Plant Suooort l

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• The licensee continues to maintain a very good emergency preparedness program.

The emergency response facilities, equipment, instrumentation and supplies were

found to be maintained in a state of readiness. Based upon an interview with a

county emergency response representative, it was determined that the licensee

maintains a very good rapport with offsite agencies and support organizations.

• The licensee's corrective actions for radiological worker and radiation protection

practices appears to have been successful, based on the results observed during

RFO12. A~ithough total exposure for the outage was the lowest in over a decade,

the outage exceeded its exposure goal by more than 30% as a result of inadequate

oversight and control of contractor activities.

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TABLE OF CONTENTS

EX EC UTIVE SU M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TABLE O F CO NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

Summ ary of Plant Statu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. O pe r a tio n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

01.1 Manual Scram Due to Fouling of Traveling Screens by Fish . . . . . 1

01.2 Re a ctor St a rtup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

01.2 Leaking Feed Water Heater Gauge Glass . . . . . . . . . . . . . . . . . . 4

O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 4

O2.1 Engineered Safety Feature System Walkdowns ............. 4

O2.2 Shutdown Cooling Isolation and RHR Pump Trip . . . . . . . . . . . . . 5

06 Operations Organization and Administration . . . . . . . . . . . . . . . . . . . . . 6

06.1 Use of Overtime ................................... 6

08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

08.1 (Closed) Violation 50-3 3 3/9 600 5-0 2 . . . . . . . . . . . . . . . . . . . . . 7

08.2 (Closed) LER 5 0-3 3 3 /9 5 007 . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

08.3 (Closed) LER 5 0-3 3 3 /9 5 010 . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

08.4 (Closed) LER 50-333/95013 including Rev. 01 . . . . . . . . . . . . . . 7

11. M ai nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

M1 Conduct of Maintenance .................................. 8

M 1.1 General Comments ................................. 8

M1.2 General Comments on Surveillance Activities . . . . . . . . . . . . . . . 8

- M1.3 Conclusions on Conduct of Maintenance . . . . . . . . . . . . . . . . . . 9

M2 Maintenance and Material Condition of Facilities and Equipment ...... 9

M2.1 4160 Volt GE Magne Blast Breaker Cotter Pins . . . . . . . . . . . . . . 9

M2.2 Service Water Pump Breaker Failure ..................... 9

M2.3 Feedwater Heater Gauge Glass Maintenance .............. 10

M8 Miscellaneous Maintenance issues .......................... 11

M8.1 (Closed) LER 5 0-3 3 3 /9 400 6 . . . . . . . . . . . . . . . . . . . . . . . . . . 11

M8.2 (Closed) LER 50-333/95006, Rev.1 .................... .11

M8.3 (Closed) LER 50-3 3 3 /9 501 1 . . . . . . . . . . . . . . . . . . . . . . . . . 11

M8.4 (Closed) LER 5 0-3 3 3/9 5 012 . . . . . . . . . . . . . . . . . . . . . . . . . . 12

M8.5 (Closed) LER 5 0-3 3 3 /9 6014 . . . . . . . . . . . . . . . . . . . . . . . . . . 12

111. Engineering .................................................. 12

El Conduct of Engineering .................................. 12

E1.1 Implementation of Plant Modifications . . . . . . . . . . . . . . . . . . . 12

E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 13

E2.1 Review of Operability Determinations ................... 13

E2.2 Modification of Fisher Butterfly Valves .................. 14

E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

E8.1 (Closed) LER 5 0-3 3 3 /9 5 01 5 . . . . . . . . . . . . . . . . . . . . . . . . . . 16

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Table of Contents (cont'd)

E8.2 (Closed) Deviation 50-3 3 3/9 2-81 -01 . . . . . . . . . . . . . , . . . . . . 16

E8.3 (Closed) Unresolved item 50-33 3/9 5-13-01 . . . . . . . . . . . . . . . 16

I V . Pl a nt S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 17

R5 Staff Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . . 19

R7 Quality Assurance in RP&C Activities ........................ 20

P1 Conduct of Emergency Preparedness Activities ................. 20

P1.1 Response to Actual Events . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

P1.2 Effectiveness of Licensee Controls in Identifying, Resolving and

Preventing Problems ............................... 20

P1.3 Offsite Interf ace .................................. 22

P2 Status of EP Facilities, Equipment, Instrumentation and Supplies . . . . . 22

P3 EP Procedures and Documentation .......................... 24

P5 Staff Training and Qualification in EP . . . . . . . . . . . . . . . . . . . . . . . . . 25

P6 EP Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . 26

P7 Quality Assurance (QA) in EP Activities . . . . . . . . . . . . . . . . . . . . . . . 26

P8 Miscellaneous EP Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

P8.1 Updated Final Safety Analysis Report (UFSAR) Inconsistencies . 27

P8.2 (Closed) Follow-Up item 50-333/95012-01 ............... 27

V. M a n a g e m e nt M e e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

X1 Exit M e eting Sum m a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

X2 Review of UFSAR Commitments . . . . . .................... 28

X3 Licensee Management Changes ............................ 28

ATTACHMENT

Attachment 1 - Emergency Plan and implementing Procedures Reviewed

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Report Details

Summarv of Plant Status

The unit began this inspection period at 96 percent power with power uprate testing in l

progress. Following completion of power uprate testing, the unit was at 100 percent  ;

power on January 6. l

The plant was downpowered on January 11 due to a main transformer cooling fan control

transformer f ailure, which resulted in a loss of main transformer cooling.

On January 22, while attempting to isolate a leaking gauge glass on a feed water heater,

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the shift manager directed a precautionary evacuation of the turbine building when the j

steam leak increased in size. The plant was operating at 100% power and power was

reduced to 90% in anticipation of removal of the feed water heater from service. The  !

operators subsequently isolated the leak utilizing additional isolation valves. The unit was '

returned to 100% power at 5:00 p.m. on January 22.

On January 23, operators rapidly reduced power and inserted a manual reactor scram

when decreasing intake water level was noted. The level decrease was due to fish

! impingement on the traveling screens. Following completion of a post transient evaluation,

reactor startup commenced on January 28 and the plant was operating at 100% on

January 31 and rernained there through the end of the inspection period.

1. Operations

01 Conduct of Operations'

01.1 Manual Scram Due to Foulina of Travelina Screens by Fish

a. Insoection Scope

On January 23,1997, at 10:24 p.m. a manual reactor scram was initiated when

decreasing lake intake water level indication was noted. All rods inserted and all

systems functioned as required. There were no engineered safety features

actuations. The inspectors responded to the site to verify safe shutdown and

assess event response. The inspectors interviewed licensee personnel including

mechanics, operators and licensee management, reviewed applicable procedures

including emergency classification and operation procedures and reviewed the post

transient evaluation,

b. Observations and Findinas

On January 23, at 10:00 p.m. the control room received a high differential level

alarm for the traveling screens. The alarm was the first indication of any

' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardize 3

reactor inspection report outline. Individual reports are not expected to address all cautli:ie

topics.

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abnormalities with the intake system. The B and C traveling screens had been

secured due to maintenance and the A traveling screen was in automatic. '

Operators began to lower reactor power in order to secure a circulating water pump

, and operators were dispatched to the intake structure. Operators noted that the A

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traveling screen shear pin was sheared and attempted to start the B and C traveling

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screens. When attempting to start the B and C traveling screens, their shear pins j

sheared. With the reduced power, operators secured one circulating water pump,-

but intake level continued to decrease. At 10:24 p.m., intake water level reached >

240 feet and a manual reactor scram was inserted. The intake water level

continued to drop while operators commenced a normal reactor cooldown using the

condenser as the heat sink. In order to secure the last circulating water pump, the

high pressure coolant injection (HPCI) system was started in the pressure control

mode in preparation for closing the main steam isolation valves (MSIVs). The last

, circulating water pump was secured following closure of the MSIVs and intake -

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water level started trending up. l

Classification of emergency conditions require a notification of unusual event (NUE)

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at an intake bay water level less than 237 feet. As the lowest level observed was

239 feet, emergency classification was not required. Licensee design bases show

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that the minimum required level for safety related pumps is 235 feet. The licensee

made a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> non emergency 10 CFR 50.72 report and originally reported that the

shutdown was due to ice formation. Subsequent licensee investigation determined

that no ice was present and that a large intake of three spine stickleback fish

occurred which overloaded the traveling screens. ,

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On January 24, at 12:15 a.m., following replacement of the shear pins, the  !

traveling screens were started, the circulating water system.was restored, and plant .;

cooldown continued to cold shutdown using turbine bypass valves. When placing -

the residual heat removai (RHR) system into shutdown cooling, the D RHR pump

tripped during to the starting transient. (see section O2.2]

, The circulating water system uses water from Lake Ontario. Circulating water is >

brought into a large forebay area from the underground intake tunnel. Water passes

through trash racks and then through travelling screens. Trash racks, and traveling

screens are provided to filter the water before it passes to the individual pump bays. i

The inspector reviewed the maintenance activities conducted on the travelling

screens. During the last monthly inspection, mechanics noted some wear on the

chain components for the 2B and 2C traveling screens. Based on this, the licensee -

elected to perform a weekly inspection until the annual preventive maintenance was

completed during the scheduled period in March 1997.

The weekly inspection was scheduled as minor maintenance under PM 9700069 for -

travelling screens 2B and 2C. The job scope was discussed at the 2:30 p.m.

supervisor meeting and the control switches for the 28 and 2C travelling screens  ;

were tagged stopped at 4:00 p.m. which effectively removed the travelling screen t

automatic operation mode. The inspection was non-intrusive and included a visual

inspection of the chains, buckets, knuckles and pins for the travelling screen

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operating mechanisms. Mechanics began the inspection at 9:00 p.m. and work

was completed at 9:45 p.m. Mechanics did not observe any fish loading during the i

conduct of maintenance. l

The inspector discussed the licensee's decision to conduct the maintenance with

planning and operations management personnel. The licensee stated that the j

travelling screens would have been available during the maintenance activity as the j

protective tagging program allowed for operation of the travelling screens. The N

importance of the travelling screens automatic start feature in ensuring that the  ;

screens would not become overloaded was not recognized. The licensee has

completed several corrective actions including travelling screen operating procedure

changes and heightening awareness for operations and planning personnel. '

The inspector noted that previous problems with intake water level have occurred; j

one event in 1990 was due to debris. At that time, the alarm was made inoperable i

during maintenance and consequently, corrective actions focused on the

instrumentation and not on travelling screen maintenance. In 1993, ice formation

on the intake bars blocked flow of water into the plant, resulting in subsequent

lowering of intake water level; a manual scram had to be inserted during that event. l

c. Conclusions

A large influx of fish blocked the travelling screens causing a reduction in intake

water level and leading to a manual reactor scram. Operator response was

appropriate, allowing the plant to be quickly placed in a safe condition. The 1

automatic start function on high differential pressure for 2 of the 3 travelling

screens was disabled for maintenance at the time of the event. The licensee's work d

planning and control process allowed this to occur. Failure to recognize the .

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importance of the travelling screens automatic start function resulted in a poor

decision to remove two travelling screens from service at the same time.

01.2 Reactor Startuo

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a. Insoection Scope  ;

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The inspectors observed portions of the reactor startup conducted on January 28, l

1997. Inspector attention was focused on reactivity control, operator procedure- J

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use and operator communications.

b. Observations and Findinas

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

attentive management oversight and effective control by shift supervision.

c. Conclusions

The reactor startup was performed in a safe and controlled manner.

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01.2 Leakina Feed Water Heater Gauae Glass

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a. Insoection Scope  ;

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At 4:00 PM on January 22,1997, while attempting to isolate a leaking gauge glass

on the six stage feed water heater, the control room directed a precautionary

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evacuation of the turbine building when the steam leak increased in size. The plant

was operating at 100% power and was reduced to 90% in anticipation of removal ,

of the feedwater heater from service. The operators subsequently isolated the leak

utilizing additional isolation valves and stopped the steam leak. i

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b. Observations and Findinas

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The steam leak occurred following shift turnover and had minimalimpact on plant

operations as the majority of the work force had left for the day. There were no

personnel contaminations and the air sample in the area of the feedwater heater

indicated no airborne contamination. The heat source for the sixth stage feedwater

heater is extraction steam from the high pressure turbine and is at approximately

300 pounds per square inch pressure. The two section gauge glass is connected by

3/4 inch steel piping to the heater shell and provides local indication of water level.

Preliminary investigation by the licensee determined that the gasket separating the

upper and lower section of the gauge glass as the source of the steam leak. The

cause of the gauge glass failure is discussed in the maintenance section of this

report.

c. Conclusions

The actions taken to isolate the steam leak and prepare the plant for.the feedwater

transient were good and the decision to evacuate the turbine building was

conservative.

02 Operational Status of Facilities and Equipment

02.1 Enaineered Safetv Feature System Walkdowns

The inspectors performed a walk down of accessible portions of the following

systems and performed general area tours:

eemergency service water system

ehigh pressure coolant injection

semergency diesel generator

estation battery

eresidual heat removal (RHR) system

Equipment operability, material condition and housekeeping were good.

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02.2 Shutdown Coolina Isolation and RHR Pumn Trio

a. Insoection Scone

On January 24, while preparing to enter shutdown cooling, the D RHR pump tripped

following the automatic closure of the two shutdown cooling isolation valves i

10MOV-17 and 10MOV-18. The licensee postulated that the valves went closed l

automatically after receiving an invalid high reactor pressure (>75 psig) isolation <

signal. The licensee subsequently vented the system and successfully started the. I

pump and entered shutdown cooling. The inspector reviewed the event to evaluate

the licensee's response to the pump trip and the corrective actions for previous

shutdown cooling isolation events.

The inspector reviewed the event with the operations staff and reviewed the system

logic drawings to verify correct operation of the logic circuitry. The inspector also  !

reviewed the system flushing and venting procedures required for entering l

shutdown cooling and discussed the process with the licensee's engineering staff.

b. Observations and Findinas

inadvertent shutdown cooling isolations have occurred in the past and have been l

discussed in several previous NRC inspection reports. Unresolved item 50- l

333/9310-02 was assigned to track the licensee's efforts to resolve recurring '

problems (seven events in three years) with inadvertent shutdown cooling isolations

when first placing an RHR pump in service. The unresolved item was reviewed and i

closed in NRC inspection report 50-333/9328. At that time, corrective actions  !

included an in-depth engineering review which concluded that the root cause was

air trapped in the instrument tubing for protective pressure switch,02PS-128A.

Additionally, the shutdown cooling procedure was changed to include properly i

venting the instrument line. This was found to be effective during shutdown

cooling operations during the Fall 1993 maintenance outage. Long term corrective

actions were to reroute the pressure switch sensing line to eliminate the air trap; I

this modification was also completed.

The inspector also reviewed a 1993 root cause analysis of RHR shutdown cooling

isolations, JSEM-93-049. The licensee evaluated several potential causes including

a f aulty pressure switch, electrical problems, vibration, an instrument tubing defect,

and air in the instrument lines. Although no definite root cause was determined, the

licensee concluded that the most probable cause was air entrapment in one of the

two pressure instrument lines. Corrective actions included removal of the air trap in

02PS-128A instrument tubing, addressing valve leakage past the RHR pump and

LPCI and SDC suction valves and initiation of a modification to install a high point

vent located in the RHR suction piping to allow more thorough fill and vent of the

SDC suction piping. The action commitment tracking system (ACTS) item, ACTS

9744, for the above corrective actions was closed in March 1994. However, the

high point vent modification has not yet been installed. This modification is

currently scheduled to be completed in 1997.

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c. Conclusions

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l The inspector concluded that the equipment responded properly and the licensee's

postulated sequence of events was sound. The inspector concluded that operator

i actions taken to establish shutdown cooling were appropriate. -The engineering -

review conducted previous to this event was comprehensive. However, corrective j

actions to install a high point vent modification to prevent shutdown cooling

isolation were not timely. Three years have elapsed since the corrective actions

were assigned and the complete corrective actions have not been fully .

implemented. The licensee is still reviewing the event and as such the issue will

remain unresolved (URI 50-333/9701-01).

06 Operations Organization and Administration

06.1 Use of Overtime i

a. Insoection Scoce

The inspector reviewed the licensee's use of overtime during November and

December,1996. During that time period, the plant was shutdown for the refueling

outage which resulted in overtime being routinely used. Technical Specification section 6.2.2.6 delineates the requirements for overtime use, and administrative

procedure AP-11.03, Control of Overtime, describes NYPA's overtime approval

policy. The inspector reviewed the above procedure and overtime records for

selected operation, engineering, radiological controls and maintenance personnel.

b. Observations and Findinas

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Technical Specifications require that administrative procedures shall be developed '

and implemented to limit the working hours of unit staff who perform safety-related

functions. AP-11.03 describes the work restrictions for individuals performing

safety related work. The Plant Manager can authorize exceeding these work hour

limits for special circumstances. Authorization is obtained through the use of an

attachment to AP-11.03 which specifies the amount of overtime to be used and the

purpose of exceeding work hour limits.

The AP requires that the Plant Manager authorize overtime exceeding 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a

24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day,168

hour period. During the outage, certain workers typically exceeded 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in

seven days. The inspector noted that when individuals exceeded the work hour

limits, a signed memorandum was on file authorizing the overtime.

c. Conclusion

Based on the inspector's review, use of overtime was appropriately controlled.

When individuals would exceed the work hour limits, a memorandum was on file

authorizing the overtime.

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08 Miscellaneous Operations issues

08.1 (Closed) Violation 50-333/96005-02: failure to control overtime for personnel. In

February and March 1996, the requirements to limit the working hours of unit staff

who perform safety-related functions were not met in that a radiological protection

worker and a maintenance planner exceeded the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> work limitation during a

seven day period without appropriate authorization for the deviation from overtime

guidelines. The licensee's corrective actions included reinforcing management's

expectations and revising procedure AP-11.03, Control of Overtime, to clarify

restrictions on overtime usage. Based on verification that licensee corrective

actions have been completed and the inspector's conclusion that overtime during

the outage was appropriately controlled, violation 50-333/96005-02 is closed.

08.2 (Closed) LER 50-333/95007: Enforcement Discretion Required For Control Room j

Ventilation Operability Requirements. The request for enforcement discretion was

reviewed in NRC inspection report 50-333/95006. TS section 3.11.A.1 requires

both control room emergency ventilation air supply fans to be operable whenever

reactor coolant temperature is greater than 212 F. During the 1994/1995 refueling

outage, one of the two trains of control room emergency ventilation was not

available when the plant was preparing for reactor vessel hydrostatic testing. This

resulted in a day-for-day delay in the refueling outage. Standard technical

specifications do not have these requirements and the licensee has submitted a

Technical Specification Change Request (TSCR) to remove this requirement to be

consistent with standard TS.

08.3 (Closed) LER 50-333/95010: Technical Specifications Required Shutdown Due to

Unidentified Drywell Leakage. This event was reviewed in NRC inspection report

50-333/95011. The licensee identified an increasing trend in the drywell floor

leakage rate and elected to begin a normal plant shutdown. The leakage rate

subsequently increased to greater than the TS limit of a 2 gpm increase in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

period. Upon entry into the drywell, the cause for the unidentified leakage was j

determined to be a packing leak on a manual 3/4 inch valve in the reactor water

recirculating system. The licensee completed additional corrective actions during

the 1996 refueling outage to minimize the possibility of packing leakage from

manually operated valves in the drywell.

08.4 (Closed) LER 50-333/95013 includina Rev. 01: Loss of Feedwater Flow Transient

Due to Personnel Error. This event was reviewed in NRC inspection report 50-

333/95018. The corrective actions will be reviewed and evaluated by open items

VIO 95-18-01 and URI 95-18-02. For administrative purposes, LER-95-013 and

LER-95-013 Rev. 01 are closed.

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ll. Maintenance

M1 Conduct of Maintenance  !>

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M1.1 General Commenig

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a. Insoection Scope

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

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) eMP 0054.02 4.16 KV switchgear maintenance

j eWR 97-00077 repair residual heat exchanger B steam inlet isolation valve  ;

eWR 96-06552 replace strongbacks on equipment hatch

eWR 96-06665 repair K safety relief valve temperature element j

eWR 97-00662 345 KV main transformer T-1B  :

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b. Observations and Findinas t

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The inspectors found the work performed under these activities to be professional  :

and thorough. Technicians were experienced and knowledgeable of their assigned j

task. ,

M1.2 General Comments on Surveillance Activities

a. Insoection Scope

The inspectors observed selected surveillance tests to determine whether approved

procedures were in use, details were adequate, test instrumentation was properly - ~

calibrated and used, technical specifications were satisfied, testing was performed

by knowledgeable personnel, and test results satisfied acceptance criteria or were

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properly dispositioned.

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The inspectors observed portions of the following surveillance activities:

eST-261 Reactor water clean-up isolation logic system functional and simulated

automatic actuation test

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eST-34A Primary Containment isolation System (PCIS) Group 2 Logic

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Functional And Simulated Automatic Actuation Test

eST-20K Control rod withdrawal checks

b. Observations and Findinas l

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l The licensee conducted the above surveillance activities appropriately and in

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accordance with procedural and administrative requirements. Good coordination j

and communication were observed during performance of the surveillance. j

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M1.3 Conclusions on Conduct of Maintenance

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

adherence to both administrative and maintenance procedures.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 4160 Volt GE Maane Blast Breaker Cotter Pins

a. Inspection Scoce

During the last refueling outage the licensee identified during planned maintenance

several safety related breakers with failed latching pawl cotter pins. Further

investigation by the licensee revealed that on two previous occasions broken or

missing cotter pins had been discovered by the maintenance staff. The inspector

reviewed the maintenance activities and the corrective actions for the event

including the equipment failure evaluation.

b. Observations and Findinas

The licensee inspected all the safety related breakers that have a safety function to

close. Nine breakers had broken cotter pins and one breaker was missing a cotter

pin. The D residual heat removal (RHR) pump breaker was missing a cotter pin

which resulted in the latching pawl starting to back out of the retaining bracket.

The licensee postulated that this would have eventually caused the breaker to fail to

close. As a result of the inspections, the licensee replaced 17 of the 21 safety

related breakers latching pawl shaft cotter pins with stainless steel cotter pins.

Metallurgical analysis of one of the broken carbon steel cotter pins showed that the -

failure was the result of high cycle fatigue. Other corrective actions planned are to

revise the maintenance procedure to include inspection of the cotter pins,

implement the vendor design change via the modification process for the cotter pin,

determine an inspection interval, and replace the cotter pins in the non-safety

related breakers and the 4 remaining safety related breakers.

c. Conclusions

Corrective actions to address the problem with the failure of breaker cotter pins

were good. The failure analysis was comprehensive and provided further

information on a generic GE Magne Blast breaker issue.

M2.2 Service Water Pumo Breaker Failure

a. Inspection Scoom

On January 13, the C service water pump failed to start upon demand from the

control room. The pump is not safety related and is one of three service water

pumps available. The pump power supply is via a GE Magne-Blast circuit breaker

and is sirnilar to the safety related breakers used at the FitzPatrick plant. The

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licensee determined the pump start failure was the result of the latch checking

switch failing to conduct current in the closing circuit of the breaker. The inspector

reviewed the work request and subsequent corrective actions for the event.

b. Observations and Findinas

The latch check switch is normally in a closed position and completes the circuit for ,

electrically closing the breaker. When the closing springs are held in the charged I

position by the closing latch, the latch checking switch is closed. The licensee

determined that the switch carries very little current and does not break current in

this particular application. It is a GE contact switch part number CR2940U310 and

is utilized in six different applications on each of the 4160 volt breakers. The

licensee has had five failures of these switches in the past year, four of which were .

age related and one in which a new switch failed. The failure mode can be l

characterized as high resistance across the contacts and is difficult to repeat  ;

because cycling the contacts cleans the contact surface, resulting in a decrease in l

the contact resistance. Regarding the previous failures, two were latch checking I

switch failures and three were in another application (see NRC inspection report 50-  ;

333/96006).  ;

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Based on the recent failure and the failures in the past year the licensee replaced l

the latch checking switches and the other five GE contact switches in 16 of the 20 l

in-service safety related breakers. The licensee concluded that the contact switches .

require periodic replacement. J

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c. Conclusions

As a result of a history of breaker problems, the licensee was aggressively pursuing >

reliability issues with the GE Magne-blast circuit breaker contact switches.

M2.3 Feedwater Heater Gauae Glass Mnintenance

1

a. Insoection Scope

On January 26, feedwater heater 6A lower level gage glass was disassembled and

repaired due to a steam leak (see section 01.2 of this report). Investigation by the

licensee determined that the cause of the steam leak was the replacement of the

gasket which seals the gauge glass pressure boundary with the wrong raterial.

The work was completed during the previous refueling outage and incluced five J

other gauge glass units. During the recent forced outage, the licensee replaced all

the previously worked gauge glasses with the correct material. The inspector

reviewed the routine work request, vendor manual and the discussed the issue with

maintenance engineering.

b. Observations and Findinas

The heat source for the sixth stage feedwater heater is extraction steam from the

high pressure turbine and is at approximately 300 pounds per square inch pressure.

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The two section gauge glass is connected by 3/4 inch steel piping to the heater

shell and provides localindication of the water level. The level gauge glasses were

installed on the heaters during the 1992 refueling outage.

The gauge glass assembly consists of a cover, cushion, glass, and a gasket. The

licensee determined that the cushion and the gasket had been reversed during the

reassembly of eight gauge glasses during the last refueling outage. The

replacement parts were not labeled; the similarities between the new and old

material were used as the method of identification. The replacement materials were

ordered as spares, at a different time than when the initial installation was l

completed, and a different material [nobestos] was supplied with the replacement

kit. This materiallooked similar to the original gasket material, but is not

recommended for high temperature applications. As a result, the replacement

gasket was not able to withstand the service environment of the steam system. i

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c. Conclusions

The inspector concluded that the event was not safety significant in that the gauge

glasses are not safety related, the steam leak was of a minor nature, and by design,

the gauge glass stop check isolation valves prevent large steam leaks. However,

the maintenance error did challenge the operators and eight components were

affected. Maintenance planning and work control documents lacked sufficient detail

to ensure that the work conducted during the outage was done correctly.  !

M8 Miscellaneous Maintenance issues

M8.1 LQlosed) LER 50-333/94006: EQ Concerns Possibly Affecting Safety Related i

Electrical Switchgear in the Turbine Building. This issue was discussed in NRC -

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inspection report 94-23 and the unresolved item, 94-23-01 was closed in NRC l

inspection report 95-14. I

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M8.2 (ClosedLLER 50-333/95006, Rev.1: Reactor Safety Relief Valve Setpoint Drift. l

The original LER was reviewed and closed in NRC inspection report 50-333/95-08.

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The revised LER provided the results of an analysis done to evaluate the impact of  !

ten pilot assemblies that deviated by more than one percent from the values I

specified in the TS during the post outage as-found lift setpoint testing. The

analysis concluded that the impact of the higher as-found SRV set-points did not

result in a violation of the ASME reactor vessel peak allowable pressure limit and

met the imposed criteria of 50 psig for margin to the overpressure protection limit.

M8.3 (Closed) LER 50-333/95011: Excessive Leakage of Primary Containment Isolation

Valves. This event was reviewed in NRC inspection report 50-333/95-11. The

licensee determined that the loca! leak rate testing results on the X-41 penetration

may have exceeded the TS leakage limit. The two reactor water sample valves

associated with this penetration were replaced during the 1996 refueling outage

with a globe valve design vice a double disc gate valve design which had a history

of poor local leak rate testing (LLRT) performance.

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M8.4 (Closed) LER 50-333/95012: Primary Containment Makeup Nitrogen Flow  ;

Monitoring Surveillance Missed Due to Personnel Error. Nitrogen makeup flow is

utilized as a means to demonstrate primary containment integrity as indicated by

lack of gross leakage. Makeup nitrogen usage was verified by alternate means to ,

show that gross leakage did not exist and procedure changes were made to provide  !

for alternate means of meeting the surveillance requirements of monitoring nitrogen y

makeup flow. l

M8.5 (Closed) LER 50-333/96014: Manual Scram Due to Leak in the Main Turbine a

Electro-Hydraulic Control (EHC) System. On December 15,1996, a manual scram ,

was initiated due to an EHC system fluid leak from the number 4 turbine bypass  :

valve actuator seal. The actuator seal was replaced and satisfactorily retested prior ,

to plant restart. An engineering evaluation determined that the primary actuator l

seal was most likely damaged during installation. This event as well as the EHC

system failure was discussed in NRC inspection report 50-333/96-08.

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The licensee's long term corrective actions include a review of the repair techniques j

and retest requirements to enhance long term reliability of all turbine valve i

actuators. Additionally, the licensee is evaluating the need for a modification to 1

provide isolation valves on the EHC supply line to turbine valve actuators. The l

inspector noted that LER 50-333/96003 documented a manual scram on February

22,1996 due to a leak in the main turbine EHC system. The EHC system leak

described in LER 96003 is different than the bypass valve actuator sealleak in that

it was due to an EHC system tube crack and not a seal failure.

Ill. Enaineerina

E1 Conduct of Engineering

E 1.1 Imolementation of Plant Modifications

a. Inspection Scooe i

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The inspector reviewed eight recently completed plant modification packages to

verify that affected documents were changed in accordance with NYPA

administrative procedures. Documents pertaining to the following modifications

were inspected:

• D1-96-036 Contromatics ball valve substitution

• D1-95-127 Separate fuses to M/A transfer stations

• M1-92-088 Replace 02-2SOV-001 & -002 with piston check valves

• M1-94-031 Replace RCIC motor-operated valve 13MOV-131

• M1-95-114 HPCI turbine shaft sealleakoff drain lines

• D1-96-068 HPCI steam trap drain pipe replacement  !

• M1-95101 Replace scram discharge instrument volume isolation

valves

• D1-96-OO7 Replace safety relief valve 3-way solenoid valves

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b. Observations and Findinas

The modifications reviewed during the inspection affected approximately 40 plant

drawings, the plant equipment data base, the UFSAR (four changes), Operator Aids,

operating and surveillance procedures, the design basis docurnents, the JAF fuse

list, and inservice test program documents, and required one NRC commitment

change. With the exception of certain drawings, the inspector found that all of the

affected documents had been changed to reflect the modifications. All of the Type

A drawings (control room drawings vital for safe operation and shutdown of the

plant) were changed well within the time limit mandated in procedure DCM-22A,

Drawing Update. Drawings affected by the modifications, but not yet updated,

were listed properly in the Revision in Progress Data Base, providing adequate

notice to potential users that the drawings on file were not up-to-date.

c. Conclusions

The inspector concluded that the licensee effectively implemented the

administrr.tive requirements of the plant modification procedures.

E2 Engineering Support of Facilities and Equipment

E2.1 Review of Operability Determinations

a. Insoection Scope

The inspector reviewed a sample of technical services memoranda written by

system engineers to assist the Operations Shift Managers in performing operability

determinations for degraded or nonconforming conditions. The determinations are > .

performed in accordance with administrative procedure AP-03.11, " Operability

Determinations."

b. Observations and Findinas

Procedure AP-03.11 assigns the responsibility for final operability determinations to

the Ooerations Shift Managers (SMs). Technical Services engineers review the

operability review forms prepared by the SMs when degraded or nonconforming

conditions are identified, and, as needed, provide calculations and analyses to

support the determinations. The results of the engineering reviews are

communicated to Operations via technical services memoranda. The inspector l

reviewed the following memoranda to assess technical adequacy and conformance

with the guidelines contained in NRC Generic Letter 91-18, "Information To )

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Licensees Regarding Two NRC Inspection Manual Sections On Resolution Of

Degraded And Nonconforming Conditions And On Operability":

e JDED-97-0011 Operability assessment for DER 97-0059, HPCI  !

and RCIC 300 percent steam flow T.S. limit non- l

conservative l

• JTS-96-0467 Evaluation of SLC system operability

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l e JTS-96-0454 Operability assessment of installed Topez inverters

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whose part numbers do not match with the plant

l drawings part numbers (DER-96-22699)

l e JTS-96-0423 Operability impact of valve misposition incidents noted

in NRC integrated inspection report 50-333/96-05

e JTS-96-0405 Operability of B train EDGs on 9/9/96

e JTS-96-0377 Operability test for the [B train EDG) governor booster

pump, ACTS No. 21884

o JTS-96-0034 Clarification of operability determination (AP-03.11) for

PlDs 66999, 67000, 67001, 67002, 67003, 66881,

and 66714 (fuse EQ documentation not readily

available]

While the level of technical detail provided in the memoranda varied considerably, the

inspector concluded that sufficient information was provided to support the licensee's

conclusions that the affected systems and components were operable.

c. Conclusions

The guidance for determining the operability of degraded or nonconforming systems

and components provided in procedure AP-03.11 was consistent with NRC Generic

Letter 91-18. Information contained in Technical Support memoranda was adequate

to support the operability determinations performed by Operations Shift Managers.

E2.2 Modification of Fisher Butterfiv Valves

a. Inspection Scone

During a walkdown of the reactor building, the inspector observed a tie-wrap

apparently holding down the air operator disengaging lever of safety-related torus-

to-drywell vacuum breaker isolation valve 27AOV-101B. A similar condition (tie-

wraps or hose clamps) existed on valve 27AOV-101 A and containment vent and

purge valves 27AOV-111 through 118. The inspector questioned whether the tie-

wraps or hose clamps had been installed as a modification.

b. Observations and Findinas

The vacuum breaker isolation and containment purge and vent valves are described

in UFSAR Sections 5.2.3.6 and 5.2.3.7, respectively. The valves are Fisher Control

Company series 9200 butterfly valves equipped with a Bettis air actuator on one

end and a Limitorque handwheel operator on the other. Normally, the valves are

aligned normally for remote operation via the air actuators, and the manual

handwheel operators are disengaged. The actuators connect to the valve stems

through slot and key (disengaging lever) mechanisms. Fisher drawing F-39119

(NYPA drawing 10.00-416) shows that the valve operators are equipped with a

spring-loaded ball to hold the disengaging lever in place.

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NRC Circular No. 80-12, Valve-Shaft-To-Actuator Key May Fall Out of Place When

Mounted Delow Horizontal Axis, informed licensees of an event in which the

operator key of a containment isolation valve similar to those at Fitzpatrick became

disengaged. The valve vendor (Pratt Company) proposed modifications, such as

adding shims, to eliminate the problem. In response to the Circular, the licensee

began to restrain the air actuator disengaging levers using hose clamps or plastic

tie-wraps. The addition of these restraints to the valves was not controlled or

evaluated in accordance with the licensee's modification processes, the valve

drawings were not revised to reflect the installation of the restraints, and no 10 CFR

50.59 screen or safety evaluation was performed. Rather, a precaution was added

to maintenance procedure MP 7.1, Containment Vent and Purge Valve

Maintenance, to reflect the installation of the restraints. Subsequently, the

precaution was carried over into the current procedure, MP 59.54, Fisher Controls

Type 9200 Butterfly Valves.

The Fitzpatrick Individual Plant Examination takes credit for the plant operators'

ability to vent the torus locally in the event of an air actuator failure. Technical

Services System Engineering memorandum JSEM-92-092, dated

December 16,1992, discussed the development of written instructions to guide the

operators in manually operating the containment vent and purge valves. The

memorandum discussed the need to restrain the operator keys, stated that the

addition of restraints had been discussed with the valve vendor, and concluded that

"...no design change was felt to be required." Emergency procedure EP-6, Post-

Accident Venting of Primary Containment, subsequently was revised to provide the

needed guidance. However, the addition of restraints change to the valve operators

was not unplemented as a modification, and no evaluation was performed per

10 CFR 50.59.

10 CFR 50.59 permits licensees to make changes to the facility or to procedures, as i

described in the FSAR, without prior NRC approval, provided that the changes do  !

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not involve an unreviewed safety question. Records of these changes must include

a written safety evaluation which provides the bases for the determination that an j

unreviewed safety question does not exit. The inspector concluded that the '

installation of hose clamps or tie-wraps on the vacuum breaker isolation and

containment vent and purge isolation valves should have been controlled under the

licensee's modification program, and that failure to perform and document a safety

evaluation for the installation was a violation of 10 CFR 50.59.

(VIO 50-333/97001-02)

The licensee initiated a deviation event report to track corrective action and to

evaluate the extent of condition. A temporary modification package was being

developed at the end of the inspection to document the installation of the restraints.

c. Conclusion

The Installation of restraints on the isolation valve disengaging levers improved the

reliability of the valves. However, the unevaluated installation was contrary to

10 CFR 50.59 requirements for changes to the facility.

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E8 Miscellaneous Engineering issues y

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E8.1 (Closed) LER 50-333/95015: Omission of RWR Seal Purge Flow from Reactor Heat f

Balance. The licensee determined that a portion of the control rod drive (CRD) l

system flow to the reactor pressure vesselis not accounted for in the reactor heat

balance. The issue is of concern at a number of boiling water reactors and the

licensee response to the design inadequacy is being coordinated with the BWR f

Owners Group and General Electric Company. l

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' E8.2 - (Closed) Deviation 50-333/92-81-01: Crescent area cooler emergency service water _i

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flow retes were less than the minimum required value specified in the Updated Final .

Safety Analysis Report (UFSAR). The licensee's responses to the Notice of ,

Deviation were documented in NRC inspection repc-ts (IR) 50-333/93 26 and [

94-06, and the needed UFSAR revision and resolution of the technical aspects of l

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the issue were discussed in IR 50-333/95 05. Regarding the administrative aspects

of the Notice, the licensee assessed the UFSAR against NRC Regulatory Guide (RG) i

1.70, " Standard Formet And Content Of Final Safety Analysis Reports For Nuclear

Power Plants." NYPA considered that UFSAR revision commensurate with the level

cf detail contained in the RG would only duplicate the information already contained  ;

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in the design basis documents, and concluded that the revision would not be

beneficial. Based on the administrative controls regarding accuracy and updating

imposed on the design basis documents in procedure CMM 2.1, " Design Basis  ;

Document Preparation and Control," the inspector considered the licensee's position

to be acceptable. ,

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The inspector reviewed procedure NLP-3, " Final Safety Analysis Report (FSAR)

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Amendment Preparation and Control." The procedure specifies the process of

preparation of FSAR updates to ensure accurate and timely submittal of changes to -i

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the NRC pursuant to 10 CFR 50.71(e), applies to all personnel, including contractors

and consultants, involved in activities that could affect the UFSAR. The procedure

contains detailed guidelines for initiation, review, and approval of changes as well [

as clearly defined responsibilities. The inspector concluded that the procedure l

adequately addresses the NRC concerns cited in the Notice of Deviation.  !

E8.3 (Closed) Unresolved item 50-333/95-13-01: Document control procedures did not j

require original outside vendor calculations and other design documents to be j

submitted directly to the document control center (DCC). Thus the DCC remained  ;

unaware of calculations under review or otherwise being held by the engineering

organization. As a result, the inspector previously found instances in which the

document control system did not have the latest revisions of calculations referenced

in the design basis documents. The licensee developed a multi-faceted action plan,

NGES-APL-95-007, to address this issue.

Under the action plan, NYPA requested calculations and other design documents

from its architect-engineer (Stone and Webster Engineering Corporation - SWEC),

the nuclear steam system supplier (General Electric Corporation), and 33 other

vendors. A 100% check of the SWEC document index by the licensee revealed

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l 49 missing calculations. The licensee has obtained, reviewed, and entered all but -;

three of these documents into the system, and the remaining items are being l

tracked by the licensee's action commitment tracking system (ACTS). In addition, i

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NYPA was performing a complete verification of calculations performed by the q

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remaining vendors. The licensee informed the inspector that the verification is

approximately 88% complete, and about 52 missing calculations have been i

identified. NYPA was attempting to locate the documents internally before

requesting them from the vendors. This item also is being tracked by an ACTS  !

item, with a due date of March 31,1997. NYPA also compiled a list of calculations

requiring engineering review for acceptance prior to being entered into the -

document control system. Of 188 items, all but five reviews were completed at the

time of the inspection. Finally, NYPA reviewed a 10% sample of modifications

designed by outside organizations since 1992. Approximately 87 calculations were

identified and verified as entered properly into the document control system. The i

inspector considered that the sample provided adequate assurance that these design i

documents were captured properly.

The licensee determined that the original discrepancies were caused by inadequate t

document control procedures and training. The inspector noted that procedure

revisions had been drafted, and that the corrective actions were due for completion

in March 1997. In addition, procedure DCM-11a, " Control Review, Comment and

Acceptance of Vendor Documents," dated August 16,1996, requires all vendor

documents to be addressed directly to the DCC, which subsequently releases copies

to site engineering for review, thus maintaining ultimate control of the documents.

The inspector concluded that NYPA performed a thorough extent of condition

review and implemented effective corrective actions in recapturing, reviewing, and

entering design calculations into its document control system.

IV. Plant Support j

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

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a. Insoection Scope

The inspector reviewed the effectiveness of the licensee's training program for

radiation workers and radiation protection technicians by observation of worker

practices in the field. Areas examined included: work controls; radiation work l

permits; and pre-job preparations and briefings, includ!ng reviews to maintain

occupational exposures as low as is reasonably achievable (ALARA).

b. Observations and Findinas i

During the last licensee refueling outage (RFO11), the NRC identified extensive

problems with radiological worker and radiation protection technician work practices

(see NRC Inspection Reports 50-333/94-30;95-03;95-10). Since that time, the

licensee has undertaken an effort to address these issues through its radiation i

protection improvement program, and to upgrade worker performance.

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The inspector reviewed documentation related to outage performance during the

recently completed outage (RFO12), including contamination control logs, radiation 4

protection logs and turnover sheets, deviation event reports (DERs) and surveillance

reports issued by the Quality Assurance (QA) Department. These documents

indicated that the licensee's improvement program had a positive effect during the  :

refueling outage, as evidenced by the significant drop in instances of poor

radiological worker practices. This conclusion is also supported by the previous

findings in this area that were observed during the refueling outage (see NRC

Inspection Report 50-333/96-07).

For RFO12, the licensee had established a goal of not more than

45 personnel contamination events. In support of this goal, the licensee had

conducted extensive station decontamination in the year prior to the outage,  ;

bringing the total clean area to greater than 96% of all recoverable space. This  !

included a significant clean-up of the refuel floor. During the outage, the licensee

documented 114 personnel contaminations. Of these, two involved an internal

uptake of radioactive material (during under vessel work), with the highest

measured uptake being 20 millirem. Discussions with the Health Physics Manager

indicated that a review of all the contamination events was currently being i

conducted as part of the Radiological and Environmental Services (RES) outage  !

review.

Also, for RFO12, the licensee had established a business goal of not more than

168 person-rem. The ALARA staff had estimated the outage work at 188.6 person-

rem. Total exposure for the refueling outage was 249 person-rem. A review of the i

outage exposures and discussions with the ALARA staff revealed that over half of

the over budget exposure arose from the CRD change-out. As previously discussed ,

in NRC Inspection Report 50-333/96-07, several of the wrong CRD mechanisms I

were removed. The consequent rework (i.e., the CRD replacement activities and  !

the removal of the correct CRD mechanisms) resulted in the total exposure of the

task to be 25.85 person-rem compared to the pre-outage established estimate of

9.77 person-rem, based on past outage performance. This error led to three

additional days of outage length. An average outage day for RFO12 resulted in

6 person-rem of exposure, resulting in an increase of 18 person-rem for the

additional three days. Although final licensee review of this event was not

complete, discussions with RES staff and licensee management indicated that better

New York Power Authority oversight of the contractor performing this work might

have prevented this error. The same contractor was also utilized for reactor

disassembly and reassembly. In this work, the goal of 6.7 person-rem was

exceeded by 6 person-rem. Additional work which was completed over budget

included replacement of the reactor recirculation pump insulation packages, local

leak rate testing and repair of test failures, and the torus destudging. Although the

249 person-rem represents the lowest refueling outage exposure total at FitzPatrick

in over a decade, weaknesses in work process controls, and contractor oversight l

were apparent contributors to the increased personnel exposure.

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l c. Conclusions

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The licensee significantly improved its radiological worker and radiation protection i

technician performance during RFO12. Significant attention has been focused on

radiological worker performance and the performance of radiation protection

technicians. The positive contribution to personnel dose savings that could have

been realized, as a result of apparent programmatic improvement efforts involving

radiation protection and radiation worker practices, was effectively defeated by the

weaknesses in work process controls and contractor oversight.  !

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R5 Staff Training and Qualification in RP&C )

a. Insoection Scone

The inspector reviewed training programs for the RES radiation protection staff

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planned for 1997. The inspector reviewed course topics and the first quarter of

1997 training schedule for radiation protection technicians and first line supervisors.

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b. Observations and Findinag l

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For 1997, the licensee established four training cycles for its radiation protection -

technicians. Training needs/ requirements for the RES staff are established by a

curriculum committee which includes personnel from the RES and Training

Departments, that meets on a regular basis to determine the training program for

RES technicians. The initial training cycle for 1997 was set to commence in late

January, and was scheduled to include training on: Merlin-Gerin wireless remote

monitoring system; multi and single channel analysis; whole body counter .

operation; and area radiation monitor operation. Topics to be included during later

training cycles included specific instrumentation operation and calibration and

preparation / review courses for the National Registry of Radiation Protection

Technologists examination.

Based on observations made by the inspector, the licensee's technician training

program in 1995 and 1996 was very effective in addressing poor technician

performance involving unresponsiveness to radworker problems / issues and poor

intradepartmental communications. All technicians and supervisors attended a i

variety of training sessions at both the technical training center on-site and at a

local college. During the recently completed refueling outage and during this l

inspection, the inspector observed a significant improvement in technician  :

performance as it related to support of rad workers and in appropriate

communications between technicians and towards management.

c. Conclusions

The licensee's training programs for radiation protection technicians aided in

improving previously identified poor technician performance.

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R7 Quality Assurance in RP&C Activities l

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a. Inspection Scope

The inspector reviewed surveillances conducted by QA during the RFO12 in order to l

evaluate the effectiveness of quality assurance activities.  ;

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b. Observations and Findinas .

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During RFO12, QA conducted surveillances of plant activities and documented the

findings in weekly surveillance reports. These reports were organized along the }

lines of the Systematic Assessment of Licensee Performance (SALP) utilized by the i

NRC. The inspector reviewed five of these surveillance reports which represented  !

the first five weeks of the outage. The surveillance reports included a discussion of l

plant support activities, especially radiation protection. A review of outage i

exposures, contamination reports and radworker performance issues was also ,

included. The surveillance team included 10 or 11 quality assurance specialists and j

engineers. No safety significant issues in the area of radiation protection were l

identified in the surveillances reviewed. Although this program provided generally I

timely results to plant management, aforementioned problems in the area of

contractor oversight were not identified.

c. Conclusions

The licensee's program for assurance of quality in the radiation protection program,

is generally effective. However, QA did not identify weak contractor oversight as a

potential problem.

P1 Conduct of Emergency Preparedness Activities

P1.1 Response to Actual Events

Since the last emergency preparedness (EP) program inspection (June 1995), one i

event occurred on September 16,1996, that required an unusual event I

classification declaration to be made. The inspector reviewed the licensee's  ;

response to the event and determined that emergency response efforts were

performed well. The licensee's assessmr,nt of the event, including postulation of j

the event occurring off hours, was comprehensive and thorough. Overall, the  :

licensee's response and assessment of the event was good.  !

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P1.2 Effectiveness of Licensee Controls in Identifyina, Resolvina and Preventina Problems

a. Insoection Scope

The inspector reviewed the licensee's system for tracking and resolving EP-related l

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b. Observations and Findinas

The inspector reviewed procedures AP-03.02, Deviation and Event Reporting, and

AP-03.08, Action and Commitment Tracking System. The inspector found these

procedures to be satisfactory for identifying, assigning responsibility for resolution,

and tracking of issues. Most EP-related issues were generated from drill / exercise

reports and training feedback forms. The inspector considered these to be excellent

sources to improve the implementation of the emergency plan (the Plan). EP issues

were appropriately prioritized and closure was generally timely. Two issues

assigned to the EP department were overdue. One dealt with IFl 95-12-01 (see

Section P8.2), as the licensee awaited NRC closure of the issue, and the other was

a low priority issue related to the operations support center. The inspector

considered these overdue issues to be isolated occurrences.

The inspector reviewed the licensee's effectiveness in resolving several past issues.

The inspector reviewed the NRC-identified issue regarding the post accident

sampling system (PASS) not functioning properly during the last full-participation

exercise (Inspection Report 50-333/95019). Initially, the licensee suspected that

the vials used in the system were ths incorrect size. However, upon further

investigation, the licensee determined that the weight of the shielding associated

with the equipment had slightly deformed the system such that the PASS would not

operate as designed. This condition only existed at one location in the plant. The

licensee installed supports to address the deformation of the equipment and will

monitor this situation to verify the long-term effectiveness of the corrective action.

The original problem with the PASS has not recurred. Another issue dispositioned i

by the licensee resulted in a more congruent interface between operations and

emergency response. Specifically, control room evacuation meets the criteria for an

alert declaration. However, control room evacuation could detract from or delay )

implementation of the Plan. To address the issue, the licensee developed an

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implementing procedure to provide direction to the operators regarding event

declaration and offsite notification. The abnormal procedure used when evacuating )

the control room directs operators to the implementing procedure to ensure that

emergency response requirements are completed. Additionally, the inspector

observed that there were no repeat occurrences of issues identified during the 1995

quality assurance audit.

To enhance its self-assessment capability, the EP department issued

SAP-22, Emergency Planning Program Self-Assessment. This procedure provides a l

methodology for conducting self-assessments and criteria for assessing program

effectiveness. Because this procedure was implemented only one week prior to this

inspection, the inspector was unable to evaluate the effectiveness of the procedure.

The inspector determined that the procedure contained useful criteria for self- j

assessment.

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c. Conclusions

Based upon the review of selected items, the inspector concluded that the licensee

effectively tracks and resolves items in accordance with the significance of the

issues and has broad corrective actions to address issues.

P1.3 Offsite Interface

a. Insoection Scooe

The inspector interviewed a county official, who is responsible for emergency

response, to assess the licensee's interface and support of offsite agencies. The

inspector also reviewed the implementation of the public information program,

b. Observations and Findinas

The inspector interviewed the Oswego County Emergency Management Office

Director. The director stated that he has received very good support from the

licensee in training, annual emergency action level (EAL) reviews, resolution of

offsite exercise issues, and in interactions during drills and exercises.

The inspector reviewed the public information literature regarding EPc Telephone

inserts, public postings, and emergency preparedness zone resident booklets all

contained sufficient information about how to respond to a radiological emergency.

Media training matenal was distributed to the local media to inform them about

emergency response procedures. The licensee's public information department

utilizes a tracking system to ensure the timely completion of the above mentioned

items as well as procedure reviews, news center equipment surveillances and

exercises.

c. Conclusions

Based upon the interview, the inspector concluded that the licensee continues to

maintain an excellent working relationship with the county. The licensee's public

information program distributes useful information to the public and local media.

P2 Status of EP Facilities, Equipment, instrumentation and Supplies

a. Insoection Scoce

The inspector conducted an audit of emergency equipment in the control room, the

operations support center (OSC), the technical support center (TSC), and the

emergency operations facility (EOF). The inspector reviewed documentation of

j equipment surveillances and tests conducted during the past year for completeness

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and accuracy. The inspector also assessed the EOF and new joint news center

(JNC) for simultaneous staffing by the licensee and Niagara Mohawk personnel.

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b. Observations and Findinns

With the assistance of licensee personnel, the inspector audited equipment and

supplies in the control room, the OSC, the TSC, and the EOF. The inspector

verified that specified equipment was present at the sampled locations and that the

latest revisions of the implementing procedures were available. The inspector

sampled radiological monitoring instrumentation in the facilities and verified that the

calibrations were current. The inspector verified that the licensee had conducted

testing of the TSC ventilation system and the system was satisfactory. The

inspector reviewed the documentation of the licensee's facility and communications

equipment surveillances for 1996. Surveillances were completed as required, and

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following each drill, all discrepancies were documented and promptly resolved.

Since the last EP program inspection, the licensee installed cellular telephones in the ,

control room, TSC and OSC to address a potential communication system l

vulnerability. To further diversify the communication system, the licensee plans to

implement a satellite telephone pending further review and procedure development.

The inspector assessed the status of the EOF and the new JNC because these

facilities are shared by the licensee and the neighboring Nine Mile Point Nuclear

Station personnel. The facilities were well equipped and orderly. The EOF seating

was arranged such that if the f acilities were simultaneously staffed by the two

licensees, location of personnel would be possible. Based upon a review of the

seating assignments against the EOF staffing specified in the Plans, there appears to

be adequate space and equipment (seating, desks, telephones, computers, etc.) to

accommodate simultaneous staffing.

A common external event (i.e., natural phenomenon) affecting both licensees would

be the most likely cause of simultaneous staffing of the EOF and JNC. The

inspector reviewed the EALs associated with external events for both licensees and

determined that an alert would be the highest classification that could occur.

Because both licensees activate their facilities for an alert classification,

simultaneous staffing could occur. At an alert classification level, there is minimal

impact on the public. In the event of conditions resulting in a general emergency

classification at both sites, the EOF is arranged such that the individuals responsible

for developing the protective action recommendations (PARS) share a common

location in the EOF and, therefore, can readily compare and coordinate a single PAR

for offsite agencies. The inspector concluded that, in the unlikely event of

simultaneous EOF and JNC activation, the licensees have sufficient space anc'

equipment to perform their functions and have made provisions to coordinate PARS

for the offsite agencies. Both licensees are tentatively planning to conduct a

simultaneous staffing drill in 1998 to determine if any modification of these facilities

is necessary.

Prior to declaring the JNC operational on May 6,1996, the licensee provided

classroom training and walkthroughs of the facility for JNC personnel. Within a

month of becoming operational, the licensee conducted drills at the JNC. At the

time of this inspection, not all JNC personnel had participated in a drill, but

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sufficient personnel have received training, walkthroughs and drill practice to staff l

the f acility.

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The facilities and equipment were determined to be in a good state of operational

readiness. Surveillances were performed as required. The EOF and JNC were well

designed and equipped and appeared to be sufficient to accommodate simultaneous

staffing by both licensees. l

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P3 EP Procedures and Documentation I

a. Insoection Scope

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The inspector assessed the process that the licensee uses to review and change the ,

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implementing procedures (IPs). The inspector also reviewed recent IP changes to

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assess the impact on the effectiveness of the EP program.

b. Obiervations and Findinas

The inspector assessed the 10 CFR 50.54(q) review (effectiveness review) process l

and annual Plan review process performed by the licensee. AP-02.04, Control of -

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Procedures, clearly describes criteria for the effectiveness reviews which include

effects upon the FSAR and the Plan. The inspector also verified that the Plan and i

the implementing procedures were reviewed as required. The inspector discussed l

several recent EAL changes and determined that the changes were acceptable and

reflected recent changes to setpoints and technical specifications. -li

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The inspector verified that letters of agreement with offsite emergency agencies and

support organizations are valid and have been or are in the process of being updated l

as required by the Plan. l

The inspector had conducted an in-office review of recent IP changes. Based upon

the licensee's determination that the changes do not decrease the overall

effectiveness of the Plan and after limited review of the changes, no NRC approval ,

is required in accordance with 10 CFR 50.54(q). Implementation of these changes l

will be subject to inspection in the future to confirm that the changes have not

decreased the overall effectiveness of the Plan, j

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The inspector sampled the licensee's document distribution process for the Plan and

implementing Procedures by comparing copies of those documents at the

emergency response facilities and the NRC Region i Office with the most recent ,

controlled copy. The copies were consistent with one another. j

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c. _ Conclusions

Based upon the review of recent licensee changes and the review of the licensee's

procedures addressing changes and reviews, the inspector concluded that this area

was well implemented.

P5 Staff Training and Qualification in EP

a. Insoection Scone

The inspector reviewed EP training records, qualification examinations, training

procedures, and the Plan's training requirements to evaluate the licensee's EP

training program.

b. Observations and Findinas

The inspector sampled several requalified emergency response organization (ERO)

members and verified that they had received annual classroom training and had

participated in a drill within the past two years as required by ITP-12, Emergency .

Response Training. The inspector sampled several newly qualified ERO members

and verified that they received classroom training, a walkthrough at the assigned

f acility, and participated in a drill as required by ITP-12.

The inspector compared one 1995 examination with a 1996 examination for

emergency directors (EDs) and observed that only one question (out of 20) was the

same. The inspector compared the questions of the three versions of the 1996 ED

examinations and observed that there was at least a 30% variation as required in

TP-1.04, Exemination Administration and Control. The inspector concluded that the

licensee places strong emphasis on training as noted by the variation in the

examination content, especially considering that the three 1996 ED examinations

were administered within a one week period.

Regarding licensee emphasis on ERO training, the inspector noted in ITP-12 that

failure to maintain ERO qualification will result in site photo identification badges

being voided and removed from the site access center, i.e., access to the facility

would not be possible. The inspector considered this to be an excellent method of

communicating expectations of emergency response training; and responsibilities to

the licensee's staff.

The inspector reviewed exercise records for 1996 and verified that the scenarios

received the required management review and that the required drills were

performed within the exercise. Specifically, communications drills, medical drills,

radiological monitoring drills, radiation protection drills and PASS drills were

conducted.

The inspector verified that training for offsite responders was being conducted in

accordance with the Plan. Fire, ambulance, hospital, and media training was

conducted. The annual EAL training was conducted for state and county officials

which included tours of the plant, the simulator, the EOF and the new JNC.

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c. Conclusion

The licensee conducted emergency response training as required. The inspector

concluded that, based upon the licensee's overall good performance during the

September 16,1996, unusual event and exercise records, training has been

effective.

P6 EP Organization and Administration

. -The inspector reviewed the licensee's EP department staffing and management to

determine what changes have occurred since the last program inspection

(June 1995) and if those changes had any adverse effect on the EP program.

Since the last program inspection, several personnel changes occurred related to the

EP department. A new EP trainer has been in position for approximately one year.

There are no longer ded;cated technicians performing the facility surveillances;

rather, the surveillances are now being rotated through a group of technicians. The

EP Coordinator (EPC) now reports to a new General Manager, Support Services

(GMSS), who has been in position for the last 18 months. The inspector observed

no indication of negative impact upon the EP program as a result of these changes.

The EPC and the assistant EPC have not been assigned any. additional

responsibilities since the last inspection that could distract from their EP duties. The

EP staff (the EPC, the assistant EPC, and a clerk) continued to receive strong

management support as evidenced by cooperation from supporting departments

(operations, maintenance, public information, training, radiation protection) to be

able to manage and implement an effective EP program.

P7 Quality Assurance (QA)in EP Activities

a. Inspection Scope

The inspector interviewed the lead QA auditor, and reviewed 1995 and 1996 QA

audit reports and the audit checklist for the 1996 audit to assess the effectiveness

of EP program audits.

b. Observations and Findinas

The lead auditor has been performing audits of the EP program for the past four

years and was the lead auditor during the last two audits. The audit teams for the

1995 and 1996 audits consisted of four persons, some of whom possessed EP

expertise. The audits were conducted over approximately a two week period, but

also included observations from QA surveillances performed throughout the year.

The audit plan directs that all aspects of the EP program be thoroughly investigated

over a three year period as indicated on an audit matrix. The checklist used for the

1996 audit was determined to be sufficiently detailed to assess the program. The

1995 and 1996 audit reports were thorough and the observations supported the

conclusions. The subjects specified by 10 CFR 50.54(t) were addressed and the

. reports contained several recommendations. There were no repeat

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l recommendations from 1995 to 1996. The inspector verified that the reports were

l distributed to the appropriate levels of licensee management and that the portions

of the reports addressing the offsite interface were sent to offsite officials. ,

c. Conclusions

The audits of the EP program were thorough and the reports were useful for

licensee management to assess the effectiveness of the EP program. The inspector

concluded that the amount of resources invested into the audit was indicative of the

licensee's commitment to perform an effective assessment of the EP program.

P8 Miscellaneous EP issues

P8.1 Uodated Final Safety Analysis Reoort (UFSAR) Inconsistencies

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

UFSAR description highlighted the need for a special focused review that compares

plant practices, procedures, and/or parameters to the UFSAR description. Section

13.8.5 of the UFSAR provides a brief statement about the Plan. Since the UFSAR

does not specifically include EP requirements, the inspector compared several

licensee activities to the Plan. The inspector specifically reviewed offsite support

organization training, media training, and public information. No discrepancies were j

noted. The quality of the training and the materials available for the media and the I

public was very good.

P8.2 (Closed) Follow-Un item 50-333/95012-01: Emergency communication

vulnerabilities. It was determined that all site telephone lines go through the same

room prior to leaving the site. Therefore, despite having several telephone systems,

there existed a common vulnerability because all communication lines pass through

the same room and thus, could be disabled by a fire, sabotage, or possibly by an

inadvertent sprinkler system actuation in that room.

The licensee installed five cellular telephones; one in the control room, three in the

TSC, and one in the OSC. These telephones appear identical to other telephones

except that they are connected to antennae located on the perimeter of the building.

The inspector observed the licensee use one of the cellular telephones to verify its

operability. The inspector reviewed the communication surveillances of emergency

communications equipment and verified that the licensee included the cellular

telephones in the periodic surveillances and had verified their operability. During a

June 1996 drill, the licensee developed a scenario that resulted in the loss of all

communication systems except for the cellular telephones. The cellular telephones

performed wellin providing communications onsite among the emergency response

facilities and in relaying updated information to the EOF, which, in turn, then relayed

it to offsite agencies.

To further diversify the communication system, the licensee has obtained a satellite

telephone. It was not yet being used because further reviews and procedure

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development is required. However, the licensee demonstrated that the satellite

telephone can be used presently to contact outside telephone networks.

Based on the installation of the cellular telephones, their demonstrated use during

the June 1996 drill and regular surveillances, and the availability of a satellite

telephone, this issue is closed.

V. Manaaement Meetinas

X1 Exit Meeting Summary

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

the conclusion of the inspection on March 6,1997. The licensee acknowledged the

findings presented.

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

X2 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 special focused

review that compares plant practices, procedures and/or parameters to the UFSAR

description. While performing the inspections discussed in this report, the inspector

reviewed the applicable portions of the UFSAR that related to the areas inspected. The

inspector verified that the UFSAR wording was consistent with the observed plant

practices, procedure and/or parameters.

X3 Licensee Management Changes

On February 4,1997, the New York Power Authority named J. Knubel to the Senior Vice

President and Chief Nuclear Officer position, succeeding W. Cahill, Jr. Additionally, the

licensee reorganized the senior management structure and personnel at FitzPatrick to add

an additional position of General Manager, Operations and to reestablish the Site Executive

Officer position. Effective February 6,1997, M. Colomb, the current Plant Manager, was

named to the Site Executive Officer position. D. Lindsey, the current General Manager

(GM), Maintenance, assumed the responsibility of GM Operations and D. Topley, the

current Training Manager, assumed the responsibility of GM, Maintenance. R. Locy, the

current Operations Manager will replace D. Topley. P. Brozenich, the current Assistant

Operations Manager, will become the Operations Manager.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

N. Avrakotos, Emergency Preparedness Coordinator

G. Brownell, Licensing Engineer

M. Colomb, Site Executive Officer

J. Cox, Emergency Preparedness Training

D. Downs, Quality Specialist

D. Lindsey, General Manager - Maintenance

J. Maurer, General Manager - Support Services

J. McCarty, Quality Assessment Supervisor

M. Prarie, A.ssistant Emergency Preparedness Coordinator

D. Vandermark, Quality Assurance Manager

T. Dougherty, Director - Nuclear Engineering

D. Topley, General Manager - Maintenarce

D. Ruddy, Director - Design Engineering

Offsite Aaencies ,

G. Brower, Oswego County Emergency Management Director  !

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D. Dempsey, Reactor Engineer

R. Fernandes, Resident inspector - FitzPatrick

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INSPECTION PROCEDURES USED

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37550 Engineering

37551 Onsite Engineering

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62703 Maintenance Observations ]

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61726 Surveillance Observations l

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71707 Plant Operations

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71750 Plant Support

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82701 Operational Status of the Emergency Preparedness Program

i 83750 Occupational Radiation Exposure

92903 Followup - Engineering

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ITEMS OPENED, CLOSED, AND DISCUSSED  ;

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50-333/9701-01 URI Modification to install vent to prevent. shutdown cooling

isolation i

50-333/97001-02 VIO 10 CFR 50.59; failure to perform safety evaluation for

modification to safety-related air-operated valves

Closed

50-333/92081-001 NOD Crescent area cooler emergency service water flowrate less l

than minimum specified in Updated Final Safety Analysis

Report

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50-333/9512-01 IFl Emergency communications vulnerability [

50-333/9605-02 VIO failure to control overtime for personnel l

50-333/94006 LER EQ Concerns Possibly Affecting Safety Related Electrical  !

Switchgear in the Turbine Building

50-333/95006 LER (Rev.1) Reactor Safety Relief Valve Setpoint Drift

50-333/95007 LER Enforcement Discretion Required For Control Room Ventilation

Operability Requirements.

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50-333/95010 LER Technical Specifications Required Shutdown Due to

Unidentified Drywell Leakage. i

50-333/95011 LER Excessive Leakage of Primary Containment isolation Valves.

50-333/95012 LER Primary Containment Makeup Nitrogen Flow Monitoring

Surveillance Missed Due to Personnel Error.

50-333/95013 LER (including Rev. 01), Loss of Feedwater Flow Transient Due to

Personnel Error.

50 333/95013-001 URI Control of vendor-supplied design documents

50-333/95015 LER Jmission of RWR Seal Purge Flow from Reactor Heat Balance

50-333/96014 LER Manual Scram Due to Leak in the Main Turbine Electro- ,

Hydraulic Control (EHC) System

Discussed

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LIST OF ACRONYMS USED

ALARA As Low As Reasonably Achievable

ASME American Society of Mechanical Engineers

BWR Boiling Water Reactor

CDF Core Damage Frequency

CFR Code of Federal Regulations

CREFAS Control Room Emergency Fresh Air System

DAW Dry Active Waste

DP differential pressure

dpm disintegra' ions per minute

ECCS Emergency Core Cooling System

EDG Emergency Diesel Generator

ESF Engineered Safety Feature

FME Foreign Material Exclusion -

FR Federal Register

FWLCS Feedwater Level Control System

HCU Hydraulic Control Unit

HPCI High Pressure Coolant injection

IFl Inspection Followup Item

IPE Individua! Plant Evaluation

IR Inspection Report

ISEG Independent Safety Engineering Group

ISI Inservice inspection

IST Inservice Testing

LER Licensee Event Report

LSA Low Specific Activity

MSIV Main Steam isolation Valves

NCR Nonconformance Report i

NCV Non-Cited Violation

NDE Non-Destructive Examination

NRC Nuclear Regulatory Commission

OSHA Occupational Safety and Health Administration

PEP Performance Enhancement Program l

PCRVICS Primary Containment and Reactor VesselIsolation Control System l

ppm parts per million

PSA Probabilistic Safety Assessment

psig pounds per square inch gage

QA Quality Assurance

QC Quality Control i

RCA Radiological Controlled Area l

RCIC Reactor Core Isolation Cooling

RHR Residual Heat Rernoval

RP Radiation Protection

RP&C Radiological Protection and Chemistry

RWCU Reactor Water Clean-Up

RWP Radiation Work Permit

SCO Surface Contaminated Objects

SDC Shutdown Cooling

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SRV Safety Relief Valve l

TS Technical Specification

UE Unusual Event i

UFSAR Updated Final Safety Analysis Report i

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VIO Violation  :

EAL Emergency Action Level l

ED Emergency Director

EOF Emergency Operations Facility l

Emergency Preparedness

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EPC Emergency Preparedness Coordinator  :

ERO Emergency Response Organization I

GMSS General Manager Support Services  ;

IP Implementing Procedure

JNC Joint News Center l

NRC Nuclear Regulatory Commission l

OSC Operations Support Center  !

QA Quality Assurance

TSC Technical Support Center i

UFSAR Update Final Safety Analysis Report  ;

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ATTACHMENT 1

EMERGENCY PLAN AND IMPLEMENTING PROCEDURES REVIEWED

Document Document Title Revision

E-Plan Section 2 13

Section 5 30

Appendix A 13

LAP-2 Classification of Emergency Conditions 16

EAP-4.1 Release Rate Determination 6

EAP-5.3 Onsite/Offsite Downwind Surveys and

Environmental Monitoring 5

EAP-8 Personnel Accountability 33

EAP-14.1 Technical Support Center Activation 17

EAP-14.6 Habitability of the Emergency Facilities 12 ,

EAP-17 Emergency Organization Staffing 72 i

EAP-43 Emergency Facilities Long Term Staffing 33

SAP-2 Emergency Equipment Inventory 21

SAP-3 Emergency Communications Testing 50 l

SAP-21 Placement, Testing and Operation of Wireless  ;

Telephone Equipment in Plant Environs O

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