ML20132C847

Insp Rept 50-333/96-07 on 960929-1116.Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20132C847
Person / Time
Site:	FitzPatrick
Issue date:	12/13/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20132C830	List: ML20132C826 ML20132C839 ML20132C847
References
50-333-96-07, 50-333-96-7, NUDOCS 9612190039
Download: ML20132C847 (35)

See also: IR 05000333/1996007

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U.S. NUCLEAR REGULATORY COMMISSION

Region I

Docket No.: 50-333

License No.: DPR-59

Report No.: 50-333/96-07 j

Licensee: New York Power Authority  !

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Facility: James A. FitzPatrick Nuclear Power Plant l

Location: Post Office Box 41

Scriba, New York 13093

Dates: September 29,1996 through November 16,1996

Inspectors: G. Hunegs, Senior Resident inspector

R. Fernandes, Resident inspector

J. Furia, Senior Radiation Specialist

S. Klein, Reactor Engineer l

G. Morris, Reactor Engineer

P. Peterson, NDE Technician l

R. Reyes, Reactor Engineer

D. Silk, Senior Emergency Preparedness Specialist

, Approved by: Curtis J. Cowgill ll1, Chief

' Projects Branch 2  ;

Division of Reactor Projects

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PDR ADOCK 05000333

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EXECUTIVE SUMMARY

i James A. FitzPatrick Nuclear Power Plant

l NRC Inspection Report No. 50-333/96-07

This integrated inspection included aspects cf licensee operations, engineering,

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

inservice inspection, and engineering inspections by Region I inspectors.

l Ooerations

• The shutdown for the refueling outage was safe and well controlled. Good

command and control, communication and procedure adherence were noted.

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• Overall, defueling operations were conducted safely and in accordance with

procedures. Communications were good and the verification of bundle location and

orientation was properly performed. An exception to good performance was that,

during fuel movement, the grapple switch was inadvertently operated. This mis-

l operation was not initially brought to the attention of the refuel bridge senior reactor

l operator which delayed initiation of appropriate corrective action to install a cover

over the switch.

Maintenance

i * A personnel error which resulted in the incorrect identification of CRDs to be

i removed was compounded because a second check failed to recognize the error. In

addition, unexpected conditions and indications related to the position indication

probes and hydraulic control unit vent valve maintenance were not adequately

pursued which contributed to the incorrect exchange of three CRDs. .The failure to

accurately locate CRDs for exchange is a violation (VIO 50-333/96007-01).

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l * During control rod blade replacement, while withdrawing the combined grappling

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tool, a fuel support piece (FSP) was inadvertently withdrawn and subsequently

l became lodged in the control rod blade guides several feet above the core plate.

l Fuel handlers exhibited poor work practices by failing to ensure that the FSP was

not attached to the tool. In addition, the procedure did not provide direction to

check the handling tool when raising it. The refueling SRO demonstrated good

work p.ractices by recognizing that the fuel support piece was stuck. The fuel

support piece recovery evolution was well planned and conducted carefully.

• The inservice inspection (ISI) program was well documented, controlled and

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implamented. The program manager demonstrated good knowledgeable of ISI

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requirements and good internal communications were noted. A licensee developed

checklist was an improvement over previous controls to ensure that ISI

requirements were met. NYPA has good oversight of the NDE subcontractor and

t NDE examinations.

' * Nondestructive examination (NDE) was performed in accordance with requirements.

The licensee NDE Level lli oversight of the NDE subcontractor was an effective

means to identify missed indications and/or defects.

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Executive Summary (cont'd)

Enaineerina

e Overall, the installation and pre-operational test for the decay heat removal (DHR)

system were acceptable. Original calculations for the DHR system heat removal

capacity were not thorough in that the calculations did not account for the

additional circulation provided by the control rod drive and reactor water cleanup

systems remaining in service during the preoperational test.

• Design control weaknesses were identified that included the use of unverified

assumptions, engineering judgements, and input data for the safety-related station

batteries modification; reactor protection system / electrical protection assembly

(RPS/ EPA) undervoltage trip calibration; an evaluation of moderate energy break in

the DHR piping; analysis of the DHR system performance; and assessment of the

combined decay heat load of the Reactor Core and Spent Fuel Pool during refueling

outages. (VIO 50-333/96007-03)

e inadequate acceptance criteria were used for the battery service tests and RHRSW

inservice tests. (VIO 50-333/96007-04)

• A failure to utilize the temporary modification process to install a temporary HEPA

filter / blower in the "A" RHR Heat Exchanger room resulted in a violation of 10 CFR

50.59. (VIO 50-333/96007-05)

• Frompt corrective action was not taken to correct deficiencies associated with

residual heat removal system design basis documentation verification, and the

average power range monitor flow bias trip calibration period. (VIO 50-333/

96007-06)

• The inspectors identified a potential weakness in the depth of reviews performed as

part of the Engineering Assurance (EA) initiative. An inspector followup item was

opened pending review of phase ll of the EA assessment of modification quality.

(IFl 50-333/96007-07)

Plant Suocort

• Significant improvements were noted in radiological worker and radiation protection

technician performance. Significant attention has been focused on radiological

worker performance, and several licensee initiatives in this area were observed.

However, one violation concerning proper high radiation area entry was identified.

(VIO 50-333/96007-08)

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

j program is generally very effective. However, one violation regarding corrective

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action effectiveness in the radioactive shipping program was identified

(VIO 50-333/96007-09).

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TABLE OF CONTENTS

EX EC UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TA B LE O F C O NT E NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

Summ ary of Pla nt Stat us . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

01.1 Power Reduction and Shutdown . . . . . . . . . . . . . . . . . . . . . . . . 1 l

01.2 Ref ueling Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1

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02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 3 l

02.1 Engineered Safety Feature System Walkdowns (71707) ....... 3

11. M a int e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

M1 Conduct of Maintenance .................................. 3

M 1.1 General Comments ................................. 3

M1.2 Surveillance Observations ............................ 3

M1.3 Conclusions on Conduct of Maintenance . . . . . . . . . . . . . . . . . . 4

M1.4 Incorrect Control Rod Drive Removal . . . . . . . . . . . . . . . . . . . . . 4

M 1.5 Stuck Fuel Support Piece . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

M1.6 Inservice inspection (ISI) Program Review ................. 6

M1.7 NDE Observation and Data Review . . . . . . . . . . . . . . . . . . . . . . 7

M7 Quality Assurance in Maintenance Activities .................... 8

Ill. Engineering ................................................... 9

El Conduct of Engineering ................................... 9

E1.1 Alternate Decay Heat Removal Installation and Start-up ....... 9

E1.2 Electrical Engineering Analyses . . . . . . . . . . . . . . . . . . . . . . . . 10

E1.3 Mechanical Design Calculations ....................... '12

E1.4 RHR Heat Exchanger Room HEPA Filter (Blower) Installation ... 13

E1.5 Design-Basis Documents ............................ 15

E1.6 Closure of ACTS ltems Related to Safety System Functional

I n s p e ctio ns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

E1.7 Modifications .................................... 18

E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 19

E2.1 Setpoint Control .................................. 19

E4 Engineering Staff Knowledge and Performance . . . . . . . . . . . . . .. 20

E4.1 Surveillance Test Acceptance Criteria . . . . . . . . . . . . .... 20

E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . 21

E7.1 Engineering Assurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

E8.1 (Closed) Unresolved item 50-333/9 6-05-04 . . . . . . . . . . . . . . . 22

E8.2 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . 23

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Table of Contents (cont'd)

I V Pl a nt S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

R1 Radiological Protection and Chemistry Controls ................. 23

R7 Quality Assurance in RP&C Activities ........................ 25

P8 Miscellaneous EP Issue .................................. 27

V. M a n ag e m e nt Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

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Report Details

Summarv of Plant Status

The plant was taken off line on October 26,1996 to begin the scheduled refueling

outage. The alternate decay heat removal system (ADHR) was placed in service to

provide for decay heat removal. In addition to refueling, major activities planned to

l be completed include replacement of service water piping, main steam isolation

valve repair, replacement of control rod drive mechanisms and main turbine work,

l. Operations

01 Conduct of Operations

l 01.1 Power Reduction and Shutdown

a. inspection Scoce (71707)

l The inspectors witnessed various portions of the shutdown preparations,

power reduction, and reactor cooldown and depressurization activities. The

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inspectors' objective was to determine the effectiveness of management

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controls in ensuring a safe transition to shutdown.

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b. Observations and Findinas

i The unit was shutdown per operating procedure (OP)-65, Start-up and Shutdown

l Procedure. Power reduction was performed in accordance with reactor analyst

procedure RAP-7.3.16, Plant Power Changes, and the main generator was removed

from service on October 26, in accordance with applicable operating procedures.

l The unit was in cold shutdown at 10:40 p.m. and the reactor mode switch was

taken to the refuel position at 11:33 p.m. on October 26.

The inspectors noted good command and control of unit shutdown activities.

Communications were professional and precise with three-point communications

used. Coordination of various shut down activities by licensed operators was very

good. Appropriate oversight of personnel during manipulation of the reactor

controls was noted. For example, a second checker for control rod motion and

selection was stationed, in addition, senior licensee management personnel were

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assigned for shift coverage.

c. Conclusions

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The shutdown for refueling outage number 12 was safe and well controlled. Good

i command and control, communication and procedure adherence were noted.

01.2 Refuelina Operations

a. Insoection Scope

The inspectors observed defueling operations in accordance with reactor

! analyst procedure (RAP)-7.1.048, Spiral Offload /Onload Refueling Procedure,

! to verify that refueling operations were being performed safely and in

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l , compliance with technical specifications. The inspectors observed refueling

operations from both the control room and the refueling bridge. Additionally,

various refueling prerequisites were reviewed.

I b. Observations and Findinas l

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The fuel moves were conducted by a contractor with licensed operators providing l

oversight and verification on both the refuel bridge and in the control room. The

licensee utilized a computerized fuel move tracking system in the control room to

provide an additional verification of correct fuel moves. Several issues resulted in i

delays of the defueling operations and are discussed below: I

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l During the initial core off-load, the fuel handlers were somewhat hindered in

moving fuel because of the effect of thermoclines in the vessel cavity water

which made visual verification of in-vessel work difficult. These thermoclines j

were different than those observed in past refueling outages because of the i

operation of the alternate decay heat removal (ADHR) system. The

thermoclines were caused by the mixing of the cooler ADHR water coming

l into the reactor cavity and the hotter water exiting the vessel cavity.

i On two occasions the refueling bridge had minor maintenance problems

which delayed fuel movements for several hours.

1 On November 4, the refuel bridge operator had completed lowering a bundle

into the spent fuel pool and after the proper verifications of bundle location

he operated the grapple open/close switch to the open position; however the

closed lamp was illuminated. This was unexpected as the intended operation

was for the grapple to open. The operator then recognized that the switch

was operated in the wrong position (which may have been the result of

bumping the switch during the lowering of the bundle into the rack). This

information was not immediately brought to the attention of the refueling

senior reactor operator (SRO), but a request for a switch cover was made.

Fuel moves were continued with a different fuel handler. On the following

shift the fuel handlers secured moving fuel until a switch cover could be

installed and licensee management was notified of the misposition of the

switch. Following the installation of a temporary modification to provide a

cover for the grapple switch defueling was resumed. A critique was held the

next day to discuss the event. Corrective actions included operations

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management briefing the refueling crews on expectations with regard to the

l importance of raising safety issues and concerns.

l c. Conclusions

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Overall, defueling operations were conducted safely and in accordance with

procedures. With the exception of not immediately communicating the mis-

operation of the grapple switch to the refuel bridge SRO, communications

were good. The verification of bundle location and orientation was properly

performed.

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02 Operational Status of Facilities and Equipment

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02.1 Enaineered Safetv Feature System Walkdowns (71707)

The inspectors used Inspection Procedure 71707 to walk down accessible portions

of the following systems:

l * Emergency Diesel Generator

j * Alternate Decay Heat Removal

l * Fire Protection System

l * Portions of Containment System

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! Equipment operability, material condition, and housekeeping were acceptable.

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! 11. Maintenance

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M1 Conduct of Maintenance

M 1.1 General Comments

l a. Insoection Scoce (62703)

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

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• WR 95-07511 perform discharge testing of B station

• WR 96-05107 adjust / repair butterfly valves in DHR system l

l *WR 96-05258 perform preventive maintenance on 4160 breaker l

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• WR 95-06497 replace service water isolation valve )

• WR 95-04678 minor inspection high pressure coolant injection (HPCI) I

turbine and pump l

l *WR 95-06137 repair HPCI turbine steam supply valve l

• WR 95-07840 replace HPCI booster pump mechanical seal l

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b. Observations and Findinas

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

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and thorough. All work observed wat performed with the work package present

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

assigned task. The inspectors frequently observed supervisors and system

engineers monitoring job progress, and quality control personnel were present

whenever required by procedure. When applicable, appropriate radiatinn control

j measures were in place.

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M1.2 Surveillance Observations

a. Inspection Scone (61726) j

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The inspectors observed and reviewed portions of ongoing and completed l

surveillance tests to assess performance in accordance with approved procedures l

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

deficiency review and resolution. The following tests were reviewed:

• ST 24D reactor core isolation cooling (RCIC) automatic isolation logic

system functional and simulated automatic actuation test

• ST 24F RCIC System inoperable test

• ISP-B1 RCIC auto isolation instrument functional test

• ST-9D emergency diesel generator (EDG) test

• ST-18 main control room emergency fan and damper operability test

b. Observations and Findinas

The licensee conducted the above surveillance appropriately and in accordance with

procedural and administrative requirements. Good coordination and communication

were observed during performance of the surveillance. -

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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.

I M1.4 incorrect Control Rod Drive Removal

a. Inspection Scoce

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As a result of personnel error, the incorrect control rod drives (CRDs) were

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exchanged during the CRD exchange. The inspectors reviewed the event and

observed the event critique and meetings. The licensee's recovery plan was

reviewed and subsequent CRD exchanges were observed.

b. Observations and Findinas

During the preparation for the CRD exchange, the CRDs designated for exchange

were not marked correctly which resulted in the unintentional exchange of three

CRDs. The first two CRDs exchanged were the wrong drives because of the

temporary labelling error. When removing the third drive, workers did not exchange

the drive that they were intending to remove which was an additional error. This

occurred because the removal tool was lined up to the wrong CRD. Following the

third CRD exchange, the CRD exchange work was stopped due to excessive

leakage observed at the high point vents during work conducted on the hydraulic

control units (HCUs) in parallel with the CRD exchange evolution,

in parallel with the CRD replacement, work was being conducted on hydraulic

control unit vent valves. Problems with draining the vent lines were occurring

which prompted additional investigation and led to the identification of the above

error. Operators had questioned the excess water and had the contractor reverify

that they were working on the correct CRD during the first two CRD exchanges.

After excessive water flow was observed from the vent valve during the exchange

of the third CRD, the shift manager stopped work.

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MP-004.03, CRD Removai and Rep:acement, describes removal and replacement of

control rod drives. The procedure requires that all CRDs to be removed are 4

accurately located and readily identified (marked) prior to removal. During the work -

preparation phase, the wrong CRDs had been identified for removal. The error j

occurred because the CRDs to be changed out had been improperly identified and I

the second check failed to recognize the identification tagging error. To identity

which CRDs kere to be removed, the contractor had used a core map and used the

undervessel doorway as a reference point. Licensee review concluded that the core

map was oriented incorrectly. There were other opportunities to have identified the

problem sooner. First, it was noted that there was some discussion among vendor

l_ personnel concerning labels on the position indication probes (PIP) (which was an

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indication that the CRDs had been improperly identified), but this was not brought

i to the attention of licensee management and was thought to be a PIP label error.

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Additionally, there were inconsistent indications of whether a rod was uncoupled

based on the uncoupling tool results. These indications were documented by l

j Engineering, but they failed to identify the fact that multiple rods were still coupled j

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and thus recommended that the CRD work proceed. The licensee continued the l

, CRD exchange for the CRDs which had positive indication that they were uncoupled ~j

while continuing to evaluate the questionable results. Also, as described above,  !

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excess water from the HCU was not evaluated until the third CRD had been i

exchanged.

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l C. Conclusions

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l A personnel error which resulted in the incorrect identification of CRDs to be

removed was compounded because a second check failed to recognize the error. In i

addition, unexpected conditions and indications related to the PIPS and HCU vent i

valve maintenance were not adequately pursued which contributed to the incorrect

exchange of three CRDs. The failure to accurately locate CRDs for exchange is a  !

violation (VIO 50-333/96007-01).

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M1.5 Stuck Fuel Suooort Piece

a. Insoection Scoce

The inspectors observed control rod blade replacement and followed up on a stuck

fuel support piece which occurred during control rod blade replacement activities.

b. Observations and Findinos

On November 14, while conducting control rod blade replacements, a fuel support

piece (FSP) became lodged between two blade guides and was suspended several

feet above the core plate. At the time all fuel was off loaded and in the spent fuel '

pool. Blade replacement activities had just been placed on hold by the refueling

senior reactor operator because of difficulties encountered with engaging the

combined grappling tool in the FSP.

The inspector attended the licensee's critique of the event and learned that the

most likely cause of the FSP becoming lodged in the blade guides above the core

plate was the result of the combined grappling tool becoming stuck in the FSP while

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withdrawing the tool. The fuel handlers stated that the clearances between the

grappling tool and the FSP flow orifices were very tight and as a result may have

caused the FSP to remain on the tool as it was being withdrawn. As the tool was

being withdrawn out of the vessel, the FSP became lodged between the adjacent

control rod blade guides. The fuel handlers did not notice anything abnormal while

removing the grappling tool. Subsequent to recommencing the control rod blade

moves, the relieving SRO noted that the fuel support piece was not in the normal

position.

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The licensee generated a temporary operating procedure, TOP-241, Cell 34-07 Fuel i

Support Piece Recovery, to utilize a nylon rope and handling poles to reseat the

FSP. Following the recovery, the procedure also addressed visual inspection of the

FSP in the spent fuel pool lay down area, and inspection of the affected blade

guides and adjacent in-core instruments. The FSP was successfully recovered and

inspections indicated that there was no apparent damage.

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c. Conclusions

While withdrawing the combined grappling tool, the fuel handlers exhibited poor

work practices by failing to ensure that the FSP was not attached to the tool, in

addition, the procedure did not provide direction to check the handling tool when

raising it. The refueling SRO demonstrated good work practices by recognizing that

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the fuel support piece was stuck. The fuel support piece recovery evolution was

well planned and conducted carefully.

M1.6 Inservice insoection (ISI) Proaram Review

a. Insoection Scooe (73753)

The inspectors assessed the ISI program, related nondestructive examination (NDE)

activities, and the implementation of the ISI program. Included in the review were

the ISI NDE procedures and the certification of the NDE personnel. The review

included ultrasonic testing (UT), liquid penetrant testing (PT), magnetic particle

testing (MT) and radiographic testing (RT) procedures.

b. Observations and Findinas

The licensee is in the third inspection period of the second inspection interval, as

described in the American Society of Mechanical Engineers (ASME) Code, Section

XI. The ASME Code requires 100% of the scheduled ASME Class 1,2 & 3

inspection items to be completed by the end of the inspection interval. At

FitzPatrick, the 1996 refueling outage is the last outage in the second inspection

interval.

The licensee extended the second inspection interval 14 months due to an extended

shutdown, and an additional nine months, as described in the ASME Code, Section

XI, IWA-2430. The extended inspection interval did not effect the intergranular

stress corrosion cracking (IGSCC) inspection program, which is defined in Generic

Letter 88-01, nor the commitment to the NRC to perform ultrasonic (UT)

examination and evaluation of the indications in the reactor vessel head.

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The NRC issued a safety evaluation report (SER) on October 27,1987, for the

licensee's ISI plan and ASME code relief requests. Subsequent SERs were issued

for disposition of relief requests dated after October 27,1987.

The licensee utilized NDE subcontractors at FitzPatrick to perform the ISI NDE

examinations. The subcontractor is responsible to submit the final data to the

NYPA NDE Level 111 for evaluation. The NYPA NDE Level lli has the final

acceptance or rejection of the NDE examination and data.  !

The inspector verified the Authorized Nuclear Inservice inspector (ANil) oversight of

ASME Section XI NDE ISI activities. ASME Code,Section XI, IWA-2000 is a ,

requirement for the licensee to provide the opportunity for the ANil to review the  ;

NDE procedures, NDE personnel certifications, and final data reports.  :

The licensee developed an ISI program checklist to aid in tracking ISI program  ;

requirements. The checklist included the component, work request, exam type, j

procedure, sketch identification and additional notes.

The inspector reviewed the reacto; pressure vessel internal visual examination data

sheet for the shroud for a weld in which some crack like indications were identified

on a vertical weld. The documentation indicated that the indications were minor-

and that all criteria were met.

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Conclusions

The ISI program was well documented, controlled and implemented. The program

manager was knowledgeable of ISI and ASME Code requirements. There is good

communication between the ISI manager, engineering and plant management. The

documentation supporting the examinations was accurate and readily available for

review by the inspector. The inspector rev!ewed the ISI program checklist which

was used as a guide to ensure that all required ISI was completed. The checklist

was an improvement over previous controls. NYPA demonstrated good oversight of

the NDE subcontractor and NDE examinations.

M1.7 NDE Observation and Data Review

a. Inspection Scooe (73753)

The scope of this inspection was to observe NDE activities and review final NDE

examination data.

b. Observations and Findinas

The inspectors observed the NDE subcontractor performing magnetic particle testing

(MT) and ultrasonic examination (UT) on reactor core isolation cooling (RCIC) piping

welds 4" W22-902-4 FW 74 and 74A. Procedures used to perform the examination

were MT-FPK-100V1, Revision 0, and UT-FPK -102, Revision 0, respectively. UT of

the N-9 control rod drive return nozzle was also witnessed by the NRC inspectors. I

The procedure used for the N-9 nozzle was GE PDI-UT-2, Revision O. [NUREG 0619

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requested boiling water reactors (BWR) licensees to examine the N-9 nozzle for

IGSCC.]

The licensee's NDE Level Ills performed an over-check (re-performance of the

examination) of the UT performed by the subcontractor on RCIC welds 4" W22-

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902-4 FW 74 and 74A. The NYPA NDE Level Ill's results did not match the results

of the UT examinations by the subcontractor. This discrepancy was properly

addressed.

c. Conclusion

NDE was performed in accordance with the ASME Code and site NDE procedures.

The NYPA NDE Levellli oversight of the NDE subcontractor was an effective means

to identify missed indications and/or defects. The results of the examinations were

j reviewed and accepted by a NYPA NDE Levelill.

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M7 Quality Assurance in Maintenance Activities

a. Scoce

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Quality assurance (QA) with regard to NDE/ISI activities was reviewed.

b. Observations and Findinas

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l The inspectors reviewed the quality assurance (QA) oversight program as it related

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to the NDE activities during the outage. The licensee indicated that their approval

process to allow technicians to perform NDE on-site did not include a proficiency

examination. Instead, the licensee had planned to perform a surveillance or an over-

check for all the technicians for each NDE method.

A matrix was developed listing all the contracted NDE technicians. The matrix

would be used to document the QA surveillance or the over-check activities.

i

'

Additionally, an NDE Level ill reviewed and approved all the NDE data. The

inspector also verified that, on the previous outage, the QA oversight matrix had

a been completed and that there had been a surveillance or an over-check on all the

technicians,

in addition, QA lessons learned from the previous outage resulted in one request

into the " Action and Commitment Tracking System" (ACTS) to review contractor

procedures and equipment for consistency with the licensee's requirements prior to

initiating NDE work for future outages. The inspector verified that the review had

been completed.

c. Conclusions

The QA oversight program was effective and well executed. However, the

inspectors noted that no guidance document existed that described the QA NDE

oversight activities.

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

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9

111. Enaineerina

E1 Con <iuct of Engineering

E1.1 Alternate Decav Heat Removal Installation and Start-uo l

l

a. Insoection Scope (37551)

i

The inspector reviewed the licensee's installation of the alternate decay heat

removal system (ADHR). The inspector performed walkdowns of the system piping I

and pipe supports, observed welding and in process assembly of system piping,

reviewed safety evaluations and quality assurance activities, and observed system

functional testing,

b. Observations and Findinas

I

Utilizing NYPA drawing FM-133A and B, the inspector verified correct valve  ;

orientation pipe configuration and weld quality for various portions of the piping I

l system. The inspector reviewed welders qualifications and verified that welders

l had the proper filler material for the task they were working at various times during

system construction. Welders were knowledgeable about the welding procedures.

The inspector witnessed portions of and reviewed the data for POT 32C, l

Decay Heat Removal System Functional Test. The intent of the test

procedure was to ensure that the decay heat removal system was capable of

removing the heat generated by the spent fuelin both the reactor vessel and

in the fuel pool. The performance of the test consisted of placing one train

of the ADHR system in service (one recirc pump, one secondary loop heat

exchanger and pump, and one cooling tower operating), securing the residual

heat removal (RHR) shutdown cooling system and monitoring reactor cavity

as well as system temperatures. The testing was conducted by a test

! engineer with assistance from operations, instrument and control (l&C),

i radiological protection, craftsman, and senior level management personnel.

The inspector did note that during the test, the control rod drive (CRD) and

reactor water clean-up (RWCU) systems were in service providing

approximately 240 gallons per minute flow and the resulting core mixing.

The decay heat removal system functional test was to demonstrate that the

ADHR system would remove heat from the reactor cavity and the spent fuel

pool using natural circulation. The inspector noted that the licensee's

original calculations for the heat removal capacity did not account for the

additional circulation provided by the CRD and RWCU systems, which were

in service during the test. Preliminary results indicate that there is no

.

significant change in natural circulation flow characteristics of the reactor

vessel, refueling cavity and spent fuel pool (SFP) regions; however, this item

will remain an inspector followup item (IFl 50-333/96007-02) pending NRC

review of the licensee's final calculations.

I

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i

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10

c. Conclusions

Overall, the installation and pre-operational test for the ADHR system were i

acceptable. Original calculations for the ADHR heat removal capacity were not i

thorough in that the calculations did not account for the additional circulation

provided by the CRD and RWCU systems remaining in service during the l

preoperational test.

E1.2 Electrical Enaineerina Analvses

I

a. Inspection Scoce

The inspectors reviewed selected engineering calculations and analyses to evaluate

the quality of engineering involvement in site activities,

b. Observations and Findinas

Station Batterv Calculations

The inspectors found that the direct current (dc) voltage drop analysis of Calculation

No. JAF-CALC-ELEC-00426, Revision 1, dated October 16,1992, concluded that,

with a calculated "A" battery terminal voltage of 109 volts, some safety-related

loads would be provided insufficient voltage. The licensee's justification for

acceptance was based on the margin between the calculation assumption of 90%

battery capacity and the previous performance test (MST-71.21, October 3,1989)

that demonstrated 105% capacity. No attempt was made to equate capacity

margin to increased battery terminal voltage, and no action item was issued to

restrict battery capacity to a value above 90%. The same calculation used a

battery load profile whose critical period load was 158 amps less than the load

profile contained in the battery sizing calculation (EDA-JAF-87-B01) in effect at the

time. A similar error existed for the "B" battery in Calculation [[::JAF-CALC-00427|JAF-CALC-00427]],

Revision 0, dated June 4,1992.

Battery sizing calculation, JAF-CALC-ELEC-01418, "125V DC Power System B

Sizing," Revision 0, dated November 21,1994, superseded Calculation EDA-JAF-

87-B01, dated September 18,1987, and was issued to include new loads. One

load (711NV.18) added as a result of Modification F1-89158 increased the load by

12 amps. The modification included an electrical calculation change form (ECCF)

that indicated the load increase was 2.5 kVA (20 amps). The licensee was not able

to justify the smaller,12 amp load. A similar error existed with the "A" Battery

Calculation JAF-CALC-ELEC-01417, Revision 0, dated November 21,1994.

Failure to correctly maintain the design basis of the safety-related station batteries

is the first of five examples of a violation of the design control requirements of

10 CFR 50, Appendix B, Criterion Ill. (VIO 50-333/96007-003)

The same 1994 calculation used a design margin sizing correction factor of 1.0.

IEEE Standard 485, " Battery Sizing," defines design margin as accounting not only

for future load growth, but also for a battery that is not fully charged. Cell specific

gravity affects battery capacity. The calculation used battery capacity input data

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

...

.

11

based on a fully charged cell with 1.215 specific gravity. However, the battery

surveillance procedures accept a battery with an averaged specific gravity of only

1.205. This 0.010 point difference in specific gravity equates to approximately a

3% difference in capacity for a lead acid cell. Therefore, the design margin  ;

correction factor used in the calculations was not conservative.

RPS/ EPA Undervoltaae Trio Calibration Extension

The evaluation prepared to support a seven-month extension of the reactor

l protection system electrical protection assembly (RPS/ EPA) calibration period was

based on a calculation (JAF-CALC-ELEC-OO1516, Revision 0, dated April 28,1994)

that used measured voltages as input data. The work request (94-02935-00)

issued for the measurements required two voltmeters which read "...as close as

possible...." The accuracy of the voltmeters was not documented. The inspectors

l noted that the data recorded indicated that the precision of the meters was no  !

better than 0.1 Volts, f

l The calculation did not compare the required and minimum expected voltages to

l. determine margin. The inspector found that the margin (0.1 Volt) would have been

l negated by the precision of the meters alone, without regard to accuracy of the -

l

l meters. This is the first of three examples of a violation of the test control

( requirements of 10 CFR 50, Appendix B, Criterion XI. (VIO 50-333/96007-004)

,

j EPA Undervoltaae Trio Setooint Calculation Uncertaintv

Calculation JAF-CALC-ELEC-OO757, " EPA for Normal Supply Feeder," Revision 6,

dated December 20,1995, assumed that there was no temperature effect (TE) on

l the uncertainty calculation if.the device was operated anywhere within the specified

l operating temperature range of 40*F to 122*F. Regarding the basis of this

assumption, the licensee stated that temperature effects would be captured'in the

referenced accuracy (RA) term of the uncertainty calculation. The inspector noted

that the RA term, as stated in the calculation, was developed from statistical '

analysis of the Drift Analysis Instrument Report (JAF-RPT-RPS-OO456). Data used

l in that analysis came from actual plant operation which did not cover the entire

j specified operating temperature. The licensee indicated the manufacturer did not

separately account for TE for the installed EPA undervoltage components. Upon

'

request, the licensee produced the sections of the vendor's equipment manual

which described the existing (GEK83433C) and replacement (GEK 103900) EPA

logic cards. The manual for the replacement EPAs, which the licensee indicated

have not been installed, do indicate a TE over the required operating temperature

range of <-0.6 Vac at 40 F to < + 1.0 Vac at 127 F.

l The inspector noted that Type 1 Change D1-90-228, which approved the

{ installation of the replacement EPA logic cards on July 31,1995, indicated that the

replacement EPA logic card had increased thermal stability. The Type 1 Change

also indicated that when the replacement logic card is installed, the setpoint

! calculations would be updated to reflect new temperature drift data.

!

!

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,

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...

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12

c. Conclusions

i

Violations of the design control and test control requirements of 10 CFR 50,

j' Appendix B, reflected a lack of rigor in the performance of design engineering

activities.

t l

i~

E1.3 Mechanical Decian Calculations )

i

a. Inspection Scope (37550)

)

[ The inspector reviewed licensee responses to open items identified during a self-

'

assessment Safety System Functional Inspection (SSFI) of the high pressure coolant

a injection system (HPCI). A design calculation was performed by the licensee in

response to an open item pertaining to vortex formation in the condensate storage

tank during HPCI pump suction switchover to the suppression pool. The inspector

,

reviewed this calculation and others performed to support an alternate decay heat l

. removal system (ADHR) modification.  !

i l

i b. Observations and Findinas

l

,

The inspector reviewed several design calculations and identified several

j weaknesses as described below:

! 1. Calculation No. JAF-CALC HPCI-00840, Revision 0, was performed in .

l response to HPCI SSFl Open item No. 22. The calculation concluded that l

j the potential existed for vortex formation in the CST during HPCI pump

suction switchover to the suppression pool in a postulated loss of coolant

accident. The calculation qualitatively indicated that the short duration (less

than 3 minutes) of these vortices and the potential for some air ingestion

j would not adversely affect HPCI pump operability. There was no indication

that the pump manufacturer had been consulted to confirm that the pump

,

would not be adversely affected by some amount of air ingestion,

j Subsequent to the inspection, the licensee informed the inspector that the

pump manufacturer had agreed that the pump would not be adversely

! affected by the limited amount of air ingestion, and that the calculation will

1

be revised to document the manufacturer's concurrence.

} 2. An analysis (Calculation JAF-CALC-DHR-03445 dated July 12,1996)

i performed to evaluate the consequences of a moderate energy break in the

! DHR piping assumed failure of a non-safety-related sump pump as the

limiting single failure. In addition, the calculation did not clearly indicate

i whether safety-related components might be adversely affected by the

,

resulting calculated flood height. Non-safety-related components typically

'

are assumed nqt to function as desired in evaluating the consequences of

initiating events; consequently, the sump pump must be assumed not to

function (versus a worst case single failure). In this case, failure of a safety-

related component must be considered to ensure that worst case conditions

- are fully evaluated for the single active component failure. The licensee

subsequently informed the inspector that the calculated 5.6-inch flood height

!

.

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x

...

r.-

13

in the Crescent Area would not impact any safety-related equipment required

for safe shutdown. The inspector agreed with the licensee's assessment,

but observed that the calculation will need to be changed to consider the

appropriate single failure vulnerabilities.

3. Calculation JAF-CALC-DHR-02380, " Alternate Decay Heat Removal System

Thermal-Hydraulic Analysis," Revision 0, dated June 4,1996, performed to

verify a GE analysis of ADHR system performance used a computer model

that had not been checked or documented. In addition, the computer code

used in the calculation modeled the plate heat exchanges as counterflow

tubular heat exchanges and did not confirm that results were consistent with

the manufacturer's heat exchanger performance data sheet.

4. Calculation JAF-CALC-MISC-02244, " Assessment of the Combined Decay

Heat Load of the Reactor Core and Spent Fuel Pool During Refueling

Outages," Revision 0, dated January 29,1996, was performed to support

the installation of the new ADHR system as documented in JAF-RPT-DHR-

02413, " Evaluation of the Decay Heat Removal System," Revision 3. This

report provides the basis for the conclusions of safety evaluation JAF-SE-96-

042, "Use of the Decay Heat Removal System in Various Plant Modes and

Configurations," Revision 2. The calculation uses the methodology of

Branch Technical Position ASB 9-2 to calculate decay heat. The report

states in part, that the "... combined RPV and SFP decay heat loads have

been conservatively calculated as a function of time post shutdown...."

However, the calculation does not include the 10% uncertainty factor l

prescribed by the Branch Technical Position. Further, the report and the i

calculation incorrectly refer to this uncertainty factor (used in the BTP to

account for differences in experimental data) as margin rather than as a l

correction needed to account for data spread as described in the BTP.

c. Conclusions

The licensee's evaluations of HPCI pump vortexing and moderate energy line break 1

of DHR piping, and DHR heat exchanger modeling were additional examples of a

'

violation (VIO 50-333/96007-003) of the design control requirements of 10 CFR

50, Appendix B, Criterion lil.

The errors in the alternate decay heat removal system calculations reviewed by the

inspectors had no adverse impact on safe operation of the system. However, the

inspectors considered the items collectively to indicate lack of rigor in the  !

performance of design activities.

E1.4 RHR Heat Exchanaer Room HEPA Filter (Blower) Installation

I

a. Inspection Scope (37550)

A temporary high efficiency particulate air (HEPA) filter and blower were installed in l

the "A" RHR heat exchanger room in an attempt to reduce room temperatures that I

had resulted in high temperature alarms and emergency operating procedure (EOP)

entries on several occasions during the summer. The inspector reviewed

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14  !

!

! Memorandum JTS-96-0369, dated August 20,1996, which addressed questions

I (after the fact) as to whether this installation should have been considered a

temporary modification. The inspector also discussed the installation with NYPA I

design engineers and the HVAC system engineer.

I l

3

b. Observations and Findinas

i.

3

j Memorandum JTS-96-0369 stated that: (1) Temperatures in the "A" RHR heat j

exchanger room (23RTD-018) are about five Fahrenheit degrees warmer than in the

'

i

! "B" RHR heat exchanger room, and two degrees higher than those on which the I

! entry conditions for emergency operating procedures were based; (2) The ultimate

! heat sink temperature limit has been raised from 77*F to 82*F (FSAR Section

j 9.7.1.2), providing a basis for raising the high room temperature alarm setpoint by

. five degrees; and (3) A setpoint change is being initiated to raise the high room

I temperature alarm setpoint.

!

j As described in Section 4.10.3 of the FitzPatrick FSAR, an equipment area

j temperature monitoring system is utilized to detect reactor coolant pressure

3

boundary leakage outside of the primary containment. Temperature sensors are

j -located in the vicinity of the equipment to be monitored, and are calibrated with the

! station in operation with normal ventilation patterns and ambient temperature levels

, to detect a seven gallon per minute leak. The RHR equipment area temperature

alarm is shown in Table 4.10-1 of the FSAR.

l

l The inspector found that, prior to installing the temporary blower, the licensee did '

! not document an evaluation to determine: (1) the impact of the existing higher

{ normal operating temperatures on predicted maximum temperatures in the area

during postulated accident, loss of offsite power, or safe shutdown conditions; (2)

the effects of higher room temperatures on safety-related equipment required during .

j accident or safe shutdown conditions; or (3) the effect of the HEPA filter / blower

I installation on the capability to detect steam leaks in the room, as described in the

FSAR.

f

The licensee stated that all safety-related equipment in the room was reviewed, and

l is qualified to temperatures greater than 2C6 F. Thus, the slight increase in the

[ setpoint temperature for EOP entry was (in retrospect) acceptable. The high energy

[ line break analysis peak room temperature limit will not be affected by the higher

l room temperatures indicated by detector 23RTD-01B. This resistance temperature

1

detector (RTD) is located near an un-insulated steam valve and is three feet above

j- locations where more representative room temperatures prevail (~ 99 F). The

j licensee concluded that the HEPA filter / blower did not provide sufficient air flow to

l mask the detection of steam leaks. In addition, the licensee stated that the HEPA

filter / blower installation had not been effective in reducing the bulk room

4 temperature. Consequently, a setpoint change is being processed to resolve the

j problem.

!

j 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

not involve a change in the technical specifications or involve an unreviewed safety

! question. Records of these changes must include a written safety evaluation which

1

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15

provides the bases for the determination that an unreviewed safety question does

not exist. NYPA Administrative Procedure AP.-05.02, " Control of Temporary

Modifications," Revision 5, provides for a technical assessment of temporary plant

modifications. The procedure defines a temporary modification as a " temporary

alteration of plant equipment that does not conform to controlled plant drawings or

other design documents." Further, Section 7.4 states (in part) that temporary

modifications should be used "to correct a design deficiency when a permanent

modification cannot be promptly installed..." The inspectors concluded that the

HEPA filter / blower installation should have been controlled as'a temporary plant

modification, and that failure to perform and document a safety evaluation for the

installation was a violation of 10 CFR 50.59. (VIO 50-333/96007-005)

The licensee agreed that the installation should have been treated as a temporary

'

modification, and that the appropriate reviews should have been performed and

documented. The licensee informed the inspector that the HEPA filter /b'ower had i

been removed, since it had not been effective.

c. Conclusions

The temporary filter / blower did not have an adverse impact on equipment area

temperature monitoring system operation. However, the unevaluated installation of

the temporary blower in the "A" RHR heat exchanger room was contrary to 10 CFR

50.59 requirement, for changes to the facility as described in the FSAR, and the

licensee's administrative controls for temporary modifications. ' Licensee action to

change the high room temperature alarm setpoints to preclude spurious high room

ter.ipmrture alarms and unnecessary EOP entries in hot summer months appeared

to be appropriate.

E1.5 Desian-Basis Documents

a. Insoection Scope

The inspectors reviewed the results of the licensee's design basis documentation

(DBD) validation program which is managed by the licensee's corporate Engineering

Programs group. Only two JAF DBDs have been validated to date; residual heat

removal (RHR) DBD-10 (December 2,1994) and air treatment system DBD-27

(December 27,1994).

b. Observations and Findinas

The inspectors observed that the licensee's DBD validation project to date had

identified 114 discrepancies within the RHR DBD. Fifty-four of the items were

forwarded to the FitzPatrick site for resolution in memorandum CM-BDDM-95-04, j

dated April 26,1995. The discrepancies involved questions concerning the Final 1

Safety Analysis Report (FSAR), procedures, lesson plans, and design-basis

calculations. The inspectors found that site engineering had not acknowledged or

taken any action on the 54 DBD items prior to the inspection. The licensee

subsequently found that a similar problem also existed regarding the safety-related

air treatment system (ATS) DBD open items forwarded to the site.

l

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16

On October 11,1996, the licensee issued DERs 96-1214 and 96-1215 to review

and evaluate the RHR and ATS open items. Twenty-four of the 54 RHR items were

immediately dispositioned based on prior work, and the remaining 30 items were

reviewed by the licensee for operability and assigned Action Commitment Tracking

System (ACTS) itern numbers for followup. All of the ATS items were assigned

ACTS item numbers for followup.  ;

1

c. Conclusions i

The licensee's failure to promptly identify and disposition the DBD open items was

the first of two examples of a violation of the corrective action requirements of

10 CFR 50, Appendix B, Criterion XVI. (VIO 50-333/96007-006)

E1.6 Closure of ACTS items Related to Safety Svstem Functional Insoections

a. Insoection Scoce (37550)

,

q

l

The inspector reviewed the basis for closure of several Action / Commitment

!

Tracking System (ACTS) items that had been closed by NYPA. The inspector found

two instances in which ACTS items identified during SSFis were not fully addressed

J

!

l by the licensee.

4

[

!

b. Observations and Findinas

e

i Surveillance Testina of RHR Heat Exchanaer Service Water Flow l

f

i . Surveillance procedure ST-2X, "RHR Service Water Flow Rate, Strainer, and

_ inservice Test (IST)," verifies that the residual heat removal service water (RHRSW)

pumps individually will deliver the technical specification-required flow rate of

'

4000 gpm to the RHR heat exchanges. RHR SSFl Observation ME-06 identified that

3 instrument error was not accounted for in the acceptance criteria of ST-2X. A

similar issue was identified by the NRC during an emergency service water SSN in -!

.

1992 (IR 50-333/92-081). Actions were completed to address instrument error on

a programmatic basis in revisions to Procedure AP-19.01, " Surveillance Testing

l Program." ACTS #13038 closed the open item on this specific issue (ST-2X) based '

on the licensee's judgement that there is considerable margin in the heat transfer

) capability of the RHR heat exchanges, assuming flows less than those required by

, the JAF Technical Specifications.

)

ACTS #13925 requested that the instrument error associated with measuring

,

RHRSW flow using the installed instrumentation and ultrasonic flow meters should

. be established. However, this item was still open at the time of the inspection and

j was not scheduled for completion until November 22,1996. Recent ST-2X ,

} surveillance test results indicate that, on several occasions, measured RHRSW flow I

4 to the RHR heat exchanges was 4000 gpm. However, actual flow rate could have

been less than 4000 gpm when instrument error is considered. The inspector  ;

'

i concluded'that the acceptance criterion did not adequately verify the minimum flow

rate established in the technical specifications. This is the second example of a

j violation of the test control requirements of 10 CFR 50, Appendix B.

!

i.

a

1

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17

For the following reasons, the inspector also concluded that the RHRSW pumps

were functional: (1) Procedure ST-2X establishes RHRSW flow as closely as

possible to the inservice test reference value of 4000 gpm by throttling closed the

RHR heat exchanger outlet throttle valves. Under accident conditions, the throttle

'

valves would open fully providing additional flow through the heat exchanges;

(2) Test TST-22, performed to verify the pump performance curves, shows that the

pumps are capable of delivering flow rates in excess of 5000 gpm; (3) Comparison

between the normally installed instruments and temporary ultrasonic flow

instruments, indicate that the installed instruments underestimate pump flow by as

much as 400 gpm. l

1

ESW Cross-Connect Valve Leakaae

l

ACTS #4242 originated from an NRC observation during the emergency service )

water (ESW) SSFI, and concerned leakage across valve 15MOV-101 that might I

adversely impact flow supplied to ESW loads. The ACTS item was closed based on I

Memorandum JTS-93-0800 dated December 3,1993, " Leakage Across

15MOV-101, RBCLC/ESW Cross-Connect Supply Valve." The memorandum states

that the redundant ESW pump would compensate for any cross-connect leakage.

However, assuming a single failure of the redundant pump during an accident,

leakage could impact flow supplied to other ESW loads. The licensee did not

address this issue, and the inspectors considered the licensee's basis for closure to

be incomplete. l

Subsequent to the inspection, JAF Engineering developed a revised evaluation

(JTS-96-0472, " Potential 15MOV-101 Seat Leakage," deted November 2,1996)

and basis for closure of this ACTS item. The revised evaluation stated that local

leak rate test data for similar type valves indicate leakages of less than one gpm. In

addition, the evaluation established that the potential for seat surface degradation of

this valve is minimized by operational history, the results of inspections, and more

favorable system and operating conditions.

c. Conclusions

Based on the revised evaluation of ESW valve 15MOV-101, the inspector

considered it unlikely that seat leakage would adversely impact flow to other

ESW loads under accident conditions. However, the inspector also concluded that

the licensee's initial bases for ACTS item closure were not always complete and

thorough.

The RHRSW flow acceptance criterion of surveillance procedure ST-2X did not

account for instrument error, and thus did not incorporate acceptance limits

contained in applicable licensing documents. This is an additional example of a

violation (VIO 50 333/96007-004) of 10 CFR 50, Appendix B, Criterion XI, " Test

Control."

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!

l ,E1.7 Modifications

! a. Inspection Scooe (37550)

a

The inspector reviewed several minor modifications and temporary modifications

i including:

1

j * MMP No. M1-92-088, " Replace 02-2SOV-001 and 002 with Piston Check l

.

Valves," Revision 0, dated April 17,1996 >

!

4 * MMP No, M1-95-103, " Replacement of Reactor Sample Containment

Isolation Valves 02-2AOV-39,40," Revision 0, dated April 29,1996

j * Type 1 Change # D1-96-007, " Replacement of MSSRV 3-Way Solenoid

j Valves," Revision 1

i

e Temporary Modification 95-127, Ultrasonic FW Flow Equipment

+ * Temporary Modification 96-123, Recorder to monitcr RWR A&B Seal

} Parameters

,

• Temporary Modification 95-093, Temporary Sample Point for Reactor

Coolant Samples

in addition, the inspector reviewed temporary modification audits and sampled

associated surveillance test results,

b. Observations and Findinas

Two non-safety-related temporary modifications have been in place since 1991.

The licensee stated that the modifications (91-224 and 91-238) were scheduled to

be made permanent in 1997. The remainder of the installed temporary

modifications were initiated in the 1995-96 time frame. The inspector reviewed

several of these temporary modifications and identified no problems. In addition,

the inspector sampled several temporary modification audits (e.g., ST-1Q,

" Protective Tags and Temporary Modification Verification," Revision 4) and found

that temporary modifications were being appropriately reviewed by the licensee to

ensure that they are properly authorized, installed, and evaluated.

c. Conclusions

The inspector concluded that minor and temporary modifications were appropriately

documented, and implemented in accordance with plant procedures.

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l 19

l E2 Engineering Support of Facilities and Equipment '

I

i

E2.1 Setooint Control

a. Inspection Scope

I

i

The inspectors reviewed the methodology used by the licensee to extend the  !

, calibration period for technical specification-related instrument loops to support a

l 24-month operating cycle. The methodology was documented in report JAF-RPT-

RPS-0132A, " Reactor Protection System (RPS) Surveillance Test Extensions,"

.

Revision 3, dated November 1995.

l  !

b. Observations and Findinas

The inspectors noted that the RPS report methodology indicated that if surveillance

records revealed more than one failure to meet acceptance criteria per component,

then the surveillance frequency could not be extended. The inspectors found the

setpoint change request for the average power range monitor (APRM) flow bias trip I

had been issued to maintenance on September 20,1996, to change the calibration l

period to 30 months. l

The inspectors reviewed an instrument drift analysis that showed that the APRM  ;

flow transmitters were found out of calibration 50% of the time between 1986 and  !

1992. During that time, the flow instruments were manufactured by either Barton

or Foxboro. All eight flow transmitters were changed to a Rosemont design in  !

1993 by Modification #F1-87-099 to address the calibration problem without

changing the calibration period. The January 12,1995, calibration of the Rosemont l

transmitters resulted in transmitters A and B being found out of tolerance in the

non-conservative direction (DER-95-0290). The latest transmitter calibrations on

September 16,1996 and October 17,1996, resulted in three of eight transmitters

being found out of calibration.

The inspectors noted that Technical Specification (TS) Basis 4.1 justified a refueling

outage calibration period for the APRM flow bias trip function, based on no

significant drift at other plants. Amendment 233 to the TS recently changed this

justification based on a plant-specific drift evaluation. The inspectors found no

justification for the latest TS Basis statement, particularly in light of instrument

calibration failures documented in 1995 and 1996. In response to the inspectors'

finding (and similar questions raised by the JAF maintenance l&C department during

this inspection), the licensee issued memorandum JIC-96-120, dated

October 10,1996, to decrease the calibration period to 12 months.

c. Conclusions

The licensee failed to identify and correct promptly a condition adverse to quality

involving an unjustified extension of the APRM flow bias trip calibration period.

l This is the second example of a violation (VIO 50-333/96007-006) of 10 CFR 50,

f

Appendix B, Criterion XVI, " Corrective Action."

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i E4 Engineering Staff Knowledge and Performance

E4.1 Surveillance Test Acceptance Criteria

a. Insoection Scope

, The inspectors reviewed the history of battery surveillance servict 3st MST-71.20

'

to assess the progression of the acceptance criteria. The inspectors also reviewed

the station battery modified performance test acceptance criteria contained in

procedures MST-071.24, Revision 2, dated December 27,1994, (battery A) and

MST-071.26, Revision 0, dated January 10,1995, (battery B), and compared the

criteria against direct current (dc) voltage drop calculations JAF-CALC-ELEC-00426

(battery A) and JAF-CALC-ELEC-00427 (battery B).

b. Observations and Findinas

.

The original acceptance criterion of battery service test MST-071.20 was 1.5 volts

per cell. Subsequently, the criterion was changed to 1.0 volt per cell. Until Revision

2 of the procedure was approved in August 1989, no battery terminal voltage

criterion was included. At that time,101.5 volts was established as the test cutoff

voltage. In June 1991, the test cutoff voltage was raised to 105 volts in Revision 4

of the procedure. The acceptance criterion remained 105 volts with the new

modified performance tests MST.071.24 and MST.071.26.

The inspectors found the 105 volt direct current (dc) acceptance criterion in the

battery service test portion of modified performance tests, MST-071.24 and MST-

071.26, had no basis in design. The criterion did not relate to the minimum-

required battery terminal voltage of 109 volts dc used in the voltage drop analyses.

The licensee issued DER 96-11 in response to the finding and performed an

operability determination that compared the results of the latest battery service

tests to determine voltage at the safety-related loads. The licensee then provided

justifications for those components that could experience voltage less than nominal

rating.

The inspectors noted that the licensee's analysis assumed the minimum design

battery temperature, which would provide additional margin. Following the

inspection, the licensee informed the inspector that it would reinstall two previously

removed cells to the station batteries (for a total of 60 cells), to provide additional

margin, until a complete reanalysis of the de system can be performed,

c. Conclusions

The licensee's engineering and maintenance staffs did not recognize that the

purpose of a service test was to demonstrate that the battery could supply

sufficient voltage to the design-basis electricalloads. The inspectors concluded that

the station batteries were functional, but that the acceptance criteria for the battery

test procedures had no bases in design. This is the third example of a violation

(50-333/96007-004) of the test control requirements of 10 CFR 50, Appendix B,

Criterion XI.

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E7 Quality Assurance in Engineering Activities

E7.1 Enaineerina Assurance

a. Inspection Scope

The inspectors reviewed the results of the latest engineering assurance (EA) of

phase I of the modification quality assessment documented in NYPA Memorandum

KM-96-016, dated August 21,1996. The EA team was composed of individuals

from the licensee's White Plain Office and the Indian Point-3 site engineering staff.

The EA team reviewed 28 representative modifications developed after 1992. The

licensee indicated that the scope of the EA review was limited to the engineering

package, up to the point of issue to the field for installation. The EA reviewers

utilized a checklist that covered areas such as design interfaces, test requirements,

specifications, design reviews, calculations, design verification, and modification file

documentation. In addition, the EA also considered the document control concern

documented in NRC unresolved item (URI) 50-333/95-13-01. Ninety-two (92)

deficiencies were identified by the licensee.

b. Observations and Findinas

The inspectors reviewed one of the twenty-eight checklists used by the EA team,

and had the following observations:

e Modification F1-89-158, " Power 27 MAP from Station Batteries," added

inverter and control circuit loads to each station battery. The modification

file documentation section of the checklist included a subsection for a

" documents to be revised list." This subsection did not identify specific

plant documents that were reviewed for required revisions. Although the

checklist indicated everything was satisfactory, a check of the modification

package in response to the inspector's question revealed that the related

battery surveillance procedure was not included even though loads were

being added to the battery. Both the modification process and the EA review

missed this document.

• The inspectors noted that the licensee's design verification review identified

that calculation JAF-CALC-ELEC-1387, which had been performed by an

outside consultant, had not received a NYPA technical review as required by

the DCM-11 design control process. The EA reviewer failed to recognize

that this was a similar concern to that documented by the NRC in Unresolved

item 50-333/95-13-01 concerning document control.

• The inspectors observed that the EA modification review checklist identified

an electrical change control form (ECCF) that had been issued late. The

inspector found that the review failed to note that the load addition described

in the modification had been incorrectly incorporated into the calculation with

a different (non-conservative) value (see Section E1.1).

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c. Conclusions

The inspectors concluded that the licensee's engineering assurance program was a

good initiative. However, the discrepancies identified by the inspector in the single

sample chosen potentially indicated weakness in the depth of review. This is an

inspector followup item pending review of phase ll of the EA assessment of

modification quality. (IFI 50-333/96007-07)

E8 Miscellaneous Engineering issues

E8.1 (Closed) Unresolved item 50-333/96-05-04

a. Insoection Scope (37550)

The inspector reviewed the licensee's corrective actions in response to unresolved

item 50-333/96-05-04. A previous inspection identified errors and weaknesses in a

calculation performed to justify up to a 12-inch diameter opening in the secondary

containment without impacting the 1/4-inch water column (WC) negative pressure

requirement for the standby gas treatment (SBGT) system. The inspector reviewed:

o Corrective actions outlined in DER 96-0867.

e Calculation JAF-CALC-SC-01876, Revision 1, that addressed identified

weaknesses.

e Calculation JAF-CALC-SC-02514, " Acceptance Criteria for ST-39D, Reactor l

Building Leak Rate Test," Revision O.

e ST-39D, " Reactor Building Leak Rate Test," Revision 13.

b. Observations and Findinas l

Calculation JAF-CALC-SC-01876 was revised (1) to correct the erroneous

resistance coefficient used for the piping penetration, (2) to incorporate the latest

reactor building leak rate test results, and (3) to envelope possible air temperatures. l

The results of the revised analysis indicated that the SBGT system is capable of l

maintaining the required negative differential pressure with a 12-inch diameter hole

in secondary containment. The inspector reviewed the revised calculation and l

found that the coefficients and enveloping temperatures assumed were appropriate. I

l

The inspector also reviewed calculation JAF-CALC-SC-02514, which established

acceptance criteria to ensure acceptable leak rates. No problems were identified I

with this calculation. In addition, procedure ST-39D now requires engineering

review and concurrence that the acceptance criteria are satisfied. j

i c. Conclusions

l

! The inspectors concluded that the corrective actions outlined in DER 96-0867

- appropriately address the issues raised. Further, the revised calculation provides

appropriate corrections to the methodology used, and the reactor building leak rate

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test acceptance criteria is consistent with the results of that analysis to ensure that

design basis reactor building (negative) differential pressures are maintained.

E8.2 Review of UFSAR Commitments

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

Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a

spacial focused review that compares plant practices, procedures and/or parameters

to the UFSAR description.

While performing the inspections discussed in this report, the inspectors reviewed

the portions of the Fitzpatrick FSAR that related to inspected areas, e.g., FSAR

Sections 4.10,6.4 and 6.5, High Pressure Coolant injection. An inconsistencies

was noted between the wording of Section 4.10 of the FSAR and installation of a

,g temporary blower in the "A" RHR heat exchanger room (Section E1.3).

IV. Plant Support

R1 Radiological Protection and Chemistry Controls

a. Inspection Scope (83750)

The inspector reviewed the licensee's program and controls for assuring radiological

worker safety during a refueling outage. Areas examined included: work controls;

radiation work permits; pre-job preparations and briefings, including reviews to

maintain occupational exposures as low as is reasonably achievable (ALARA);

radiological worker practices; and radiation protection technician work practices.

The inspector also attended shift turnovers conducted between supervisors, chief

technicians and journeyman technicians.

b. Observations and Findinas

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

problems with radiological worker and radiation protection technician work practices

and documented the results in NRC Inspection Reports 50-333/94-30, 95-03,

95-10. Since RFO11, the licensee has undertaken an effort to address these issues,

and to significantly upgrade worker performance, especially during outages.

In support of the current refueling outage, the licensee's Radiological and

Environmental Services (RES) Department had modified its staffing and work

practices to include the addition of approximately 60 contractor health physics and

decontamination technicians, as well as upgrading several technicians to acting

chief technicians for certain critical work areas. A supervisor and one or more chief

technicians were assigned to the refuel floor, drywell and balance of plant (including

turbine building and reactor building), for each of two twelve-hour shifts. These

were conducted in a professional manner, outlining all work activities in progress

and stressing current and potential changing radiological conditions.

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in order to improve the control of work in the odiologically controlled area (RCA),

the licensee established two satellite control areas and an additional satellite

control / access control point, in addition to the main and secondary access control

points located in the new and old administration buildings, respectively. The two

satellite control points were established on the Reactor Building 272' elevation,

outside the drywell personnel access point and on the refueling floor. Each included

a temporary office structure where workers could check-in with the radiation

protection staff, receive pre-job briefings and log onto specific radiation work

permits (RWPs). The additional satellite control / access control point was

established on the turbine deck just outside of the high pressure turbine. The

inspector observed numerous pre-job briefings at all three of these control points.

These were conducted in a professional manner by the radiation protection

technicians, providing extensive information on radiological conditions in the work

areas. The inspector also noted a significant improvement in worker attitude by the

radiation protection technicians, especially at the main access control point. During

RFO11, the inspector had observed technicians having a non-resoonsive attitude

towards assisting radiation workers. This outage, radiation technicians were

observed on numerous occasions assisting workers with logging-in on the access

control computers, responding to portal monitor alarms and aiding workers in exiting

contaminated areas throughout the plant. During high traffic times at the main

access control point, radiation technicians not assigned to access control duties

were observed leaving their desks and lunchroom to assist radiation workers.

For the outage, the RES Manager had assigned one senior radiation protection

technician to oversee all three of the access control points (one per shift). Their

duties inclu jed: assisting workers with the computerized log-in system; ensuring

workers dosimetry was properly worn (an issue previously identified in NRC

Inspection Report 50-333/94-30); assisting workers exiting the RCA through the.

portal monitors; responding to portal monitor alarms; and tracking and investigating

personnel contaminations.

The inspector reviewed the contamination log maintained by the licensee, and

concluded that with two exceptions, many of the contaminations were unrelated

and not common to any one causal factors, such as poor work practices, improper

dress-out or failure to control the spread of contamination.

Two clusters of personnel contaminations were noted in the logs, however. The

first involved three contaminations which occurred on the refuel floor during reactor

disassembly, the other during initial work on the D-MSIV in the drywell. In the

former, the licer.see concluded that the contaminations were the result of poor

radiation worker practices and responded by issuing a deviation event report (DER)

and holding a stand-down meeting with the refuel floor contractor whose workers

were contaminated. Since the stand-down meeting, no additional personnel

contaminations were identified involving refueling floor workers. In the latter case,

two workers, one each on the day and night shift, became contaminated by free-

standing water inside the MSIV valve body. Subsequent to this, the licensee

initiated a remedial training program for each shift's work crew utilizing a mock-up

of the MSIV.

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For RFO12 the licensee had established an outage exposure goal of 168.8 person i

rem. This was based only partially on the scope of work to be performed. The goal ,

was principally established in order for the facility to meet a long-term goal of being )

in the top quartile of all boiling water reactors in the United States for three-year ,

average personnel exposure. Prior to the outage, the license's ALARA staff j

estimated that 180 person-rem was the more likely exposure based on work to be

performed during the outage. Through day 13 of the outage, exposures were

approximately 26 person-rem ahead of projection. Part of the cause for this was a

earlier start to some high exposure work in the drywell, higher than predicted

exposures during reactor disassembly, and an expansion of work scope for snubber

inspections due to test failures. Discussion.with licensee representatives indicated

that outage exposure was now likely to be approximately 200 person-rem.

On October 30,1996, a contractor work crew entered the drywell, a posted locked .

high radiation area, and worked there for approximately three hours. One of the j

three workers in this crew failed to properly log-in at the drywell satellite access  !

control point, which meant that his alarming dosimeter was not turned on during his

drywell entry. Plant Technical Specification 6.11 requires that for each locked high _!

radiation area, workers utilize a radiation work permit and have an alarming i

dosimeter with them. The RWP for this job (RWP #96-0411) clearly indicated the ,

need to wear an alarming dosimeter. The worker did not identify his failure to have  !

his dosimeter turned on until after he had left the drywell and was preparing to exit

the reactor building. Licensee investigation concluded that the worker had not.

properly logged in on the access computer at the satellite control point, and that the

worker, who admitted confusion with the access system, failed to ask for

assistance (even though there were three radiation protection technicians present at

the satellite access control point), and failed to check his dosimeter prior to entry to -

the drywell. Based on the exposures received by the other two members of this

work crew, the worker in question was assigned an exposure of 64 millirem for this

entry. The licensee also informed the inspector that there were additional cases

where individuals had failed to wear dosimetry as required. The failure to follow

plant technical specifications for locked high radiation area entry is a violation

(50-333/96007-08). While this violation would normally be a candidate for

enforcement discretion, the NRC elected to issue a violation in this matter due to

the length in which the violation existed and the number of possible opportunities

available to identify the problem.

c. Conclusions

Significant improvements were noted in radiological worker and radiation protection

technician performance. Significant attention has been focused on radiological

worker performance, and several licensee initiatives in this area were observed.

L

One violation concerning proper high radiation area entry was identified.

l R7 Quality Assurance in RP&C Activities

a. Inspection Scope (83750)

l.

The inspector reviewed QA audits and surveillances in order to evaluate the

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i effectiveness of quality assurance activities in the RES Department. In addition to a

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plant audit completed in October,1996, the inspector also discussed surveillance

l activities on-going during the refueling outage.

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l b. Observations and Findinas

l

l As part of its review of work activities and the effectiveness of corrective actions  !

for identified deficiencies during the last refueling outage (RFO11), the licensee had

a lead auditor, a corporate auditor and a six-member team of personnel conducting

independent observations of radiological worker and radiation protection technician

l practices during RFO12. The inspector observed several of these surveillances and i

discussed current findings with all three reviews. The reviewers reported no l

significant findings, and considered the radiation protection technicians to be much I

more responsive to radiological worker needs than had been observed in the past.

l

The inspector also reviewed a recently issued audit report, A96-17J, " Radiation 1

Protection Program," dated October 31,1996. This report was conducted by a l

! team of auditors and outside technical specialists during late September and early

l

October of 1996. The audit focus was on implementation of changes to radioactive l

material shipping regulations contained in Title 49, Code of Federal Regulations, and l

radiological worker and radiation protection technician practices in preparation for

RFO12. Two DERs were issued as a result of this report.

The inspector noted that one of the DERs issued from audit A96-17J involved a

licensee procedural requirement for training of radiation protection technicians j

l involved in the shipping program. The procedural requirement, found in paragraph j

l 6.3.1 of licensee procedure RW-SHP-104, Rev 1, " Radioactive Waste Data Base '

Control Program," requires that these technicians be trained and certified for the j

l operation of the RADMAN (WMG, Inc.) computer code. The auditors noted that the l

l certification for use of this code had lapsed as of June 1996. The DER (#96-1188) '

l was issued on October 10,1996. On October 22,1996, the licensee shipped

l radioactive wastes in an NRC-approved LSA > Type A shipping cask (Certificate of

l Compliance USA /9094/A) utilizing the RADMAN computer code without having the

l technicians certified or the procedure revised relative to the certification

requirement. The licensee's RES supervision had previously determined that the

,

corrective action for the DER was to delete the certification requirement, but did not j

ensure the procedure was revised prior to subsequent shipments. The inspector

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noted that no other corrective measure was apparent relative to ast,uring that the i

technicians were adequately qualified relative to the application of the RADMAN l

code.

Title 10, Code of Federal Regulations, Part 71 requires that licensee's utilizing NRC

licensed shipping containers, such as that utilized here, follow a formal quality

assurance program for their use, including the identification and correction of i

deficiencies and deviations. The failure to correct discrepancies identified with the  !

certification of technicians responsible for radioactive waste shipping is a violation I

(50-333/96007-09).

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c. Conclusions

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

especially its audit and surveillance program, is generally very effective. One

violation regarding corrective action effectiveness in the radioactive shipping

program was identified.

P8 Miscellaneous EP lesue

During the week of September 30,1996, a region-based inspector conducted a

. telephone interview with the licensee to complete NRC Temporary Instruction (TI)

2515/134, " Licensee On-Shift Dose Assessment Capabilities". The purpose of the

Tl was to gather information on the licensee's capabilities to perform on-shift dose i

assessment. It was determined that the licensee does have on-shift dose )

assessment capability supported by appropriate procedural guidance and therefore  ;

meets NRC requirements to be able to perform dose assessment at all times.

l V. Manaaement Meetinas j

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l X1 Exit Meeting Summary

1

The inspectors presented the inspections results to members of the licensee l

management at the conclusion of the inspection on November 26,1996. The

,

licensee acknowledged the findings presented. l

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The inspectors asked the licensee whether any materials examined during the

. inspection should be considered proprietary. No proprietary information was

! identified.

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PARTIAL LIST OF PERSONS CONTACTED

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Licensee

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l M. Colomb, Plant Manager

R. Locy, Operations Manager

J D. Ruddy, Director, Design Engineering

! J. Maurer, General Manager, Support Services

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C. Cowgill, Chief, Projects Branch 2

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INSPECTION PROCEDURES USED

37550 Engineering

37551 Onsite Engineering

62703 Maintenance Observations

61726 Surveillance Observations

71707 Plant Operations

71750 Plant Support

73753 inservice Inspection

83750 Occupational Radiation Exposure

ITEMS OPENED, CLOSED, AND DISCUSSED

Ooened

50-333/96007-01 VIO A personnel error contributed to the incorrect exchange of

three CRDs. The failure to accurately locate CRDs for

exchange is a violation.

50-333/96007-02 IFl Affect of RWCU and CRD flow on natural circulation flow

characteristics of the reactor vessel, refueling cavity and hFP

regions during ADHR testing.

50-333/96007-03 VIO 10 CFR 50, Appendix B, Criterion Ill, Design Control; failure to

translate design into procedures and to verify the adequacy of

design. (Five examples)

50-333/96007-04 VIO 10 CFR 50, Appendix B, Criterion XI, Test Control; failure to

incorporate appropriate acceptance limits into procedures.

(Three examples)

50-333/96007-05 VIO Failure to perform a 10 CFR 50.59 safety evaluation for

installation of a temporary blower / filter in the "A" RHR heat

exchanger room

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50-333/96007-06 VIO 10 CFR 50, Appe, dix B, Criterion XVI, Corrective Action;

failure to identify and correct promptly conditions adverse to

quality involving design basis documentation verification

program deficiency items and miscalibration of APRM flow bias

flow transmitters

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50-333/96007-07 IFl Review Engineering Assurance Program phase ll assessment of l

modification quality '

50-333/96007-08 VIO Failure to follow plant technical specifications for locked high

radiation area entry.

50-333/96007-09 VIO Licensee failed to follow a formal quality assurance program

for the use of NRC licensed shipping containers.

Closed

50-333/96005-04 URI Secondary containment calculation deficiencies

Discussed

None

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