ML17285A313

Annual Operating Rept 1988

ML17285A313
Person / Time
Site:	Columbia
Issue date:	12/31/1988
From:	Powers C WASHINGTON PUBLIC POWER SUPPLY SYSTEM
To:	Martin J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
References
NUDOCS 8903130595
Download: ML17285A313 (99)

Text

ACCELZ P ATED D1 K 8 1.'Tl OA DE 8 04 ST310.'i SY> TEN REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:8903130595 DOC.DATE: 88/12/31 NOTARIZED: NO DOCKET g

FACIL:50-397 WPPSS Nuclear Project, Unit 2, Washington Public Powe 05000397 AUTH.NAME AUTHOR AFFILIATION POWERS,C.M.

Washington Public Power Supply System RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"W

-2 A nu l Operating Rept 1988." W/890228 ltr.

DISTRIBUTION CODE:

IE56D COPIES RECEIVED:LTR + ENCL Q SIZE:

TITLE: 20.407 Annual Personnel Monitoring Rpt/A nual Ra Exposure NOTES pt y Fun~

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02 RGN5 01 EXTERNAL: LPDR NSIC COPIES LTTR ENCL 1

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1 RECIPIENT ID CODE/NAME PD5 PD AEOD/DSP/TPAB NRR/DOEA/EAB 11 NUDOCS-ABSTRACT RES BROOKS,B NRC PDR COPIES LTTR ENCL 5

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WASHINGTON PUBLIC POWER SUPPLY SYSTEM P.O. Box 96S

~ 3000 George 1vashington 11'ay

~ Richland, 11'ashington 99352 Docket No.

50-397 February 28, 1989 Hr. J.B. Hartin Regional Administrator Region V

U.S. Nuclear Regulatory Commission 1450 Haria Lane, Suite 210 Walnut Creek, CA 94596

Subject:

NUCLEAR PLANT NO.

2 ANNUAL REPORT

Reference:

1)

Title 10, Code of Federal Regulations, Part 50.59(b) 2)

WNP-2 Technical Specifications, 6.9. 1.4 and 6.9. 1.5 3)

Regulatory Guide

1. 16, Reporting of Operating Information-Appendix A

In accordance with the above listed references, the Supply System hereby submits the Annual Report for calendar year 1988.

Should you have any questions or comments please contact H.R. Wuestefeld, WNP-2 Assistant Plant Technical Hanager.

Very truly yours, C.

Powers Plant Hanager CHP:HRW:TRW Attachments

ANNUAL OPERATING REPOR T OF WNP-2 FOR 1988 OOCKET NO. 50-397 FACILITY OPERATING LICENSE NO.

NPF-21 Washington Public Power Supply System 3000 George Washington Way Richland'ashington 99352 8903].30595

TABLE OF CONTENTS

1.0 INTRODUCTION

1 -

1 1.1 1988 Power History Graph for WNP-2........

1 4

2.0 REPORTS 2.1 Annual Personnel Exposure and Monitoring Report 2.2 Hain Steam Line Safety/Relief Valve Challenges

2. 3 Summary o f P 1 ant Opera t i on 2.4 Summary of Significant Haintenance Performed on Safety Related Equipment 2.5 Indications of Failed Fuel 2.6 Plant Hodifications

~

2.6.1 Plant Design Changes 2.6.2 Lifted Leads and Jumpers 2.6.3 FSAR Amendment Evaluations 2.6.4 Other 2.7 Plant Tests and Experiments 2.8 Plant Procedure Changes 2.9 Reactor Coolant Specific Activity Levels.

2.9.1 WNP-2 Dose Equivalent Iodine Graph 2.10 Diesel Generator Failures 2 -

1 2 -

2

~

~

2 3

2-8 2 17 2 - 24 2-27 2-28 2 - 39 2 41 2-44 2 - 53

. 2-54 2 - 58 2 59 2-60

1.0 INTROOUCTION The 1988 Annual Operating Report of Washington Public Power Supply System Plant Number 2

(WNP-2) is provided as a

supplement to the Honthly Operation Report.

This report is submitted in accordance with the requirements of Federal Reg-ulations and Facility Operating License NPF-21.

It should be noted that, for ease of reference and completeness, additional required reports are also in'-

cluded.

WNP-2 is a

3323

HWt, BWR-5, which began commercial operation on Oecember 13, 1984.

On January 18, 1988 the Plant was shutdown after 35 days of operation to cor-rect a condenser tube in-leakage problem.

Several leaking tubes were plugged and the Plant was returned to service.

Oue to condenser in-leakage and rapidly increasing conductivity the Plant was again shutdown on February 13, 1988 for condenser tube and baffle plate repairs.

Ouring this

shutdown, the reactor building (secondary containment) was overpressurized by the inadver-tent start of a

reactor building air supply

fan, causing the designed roof rupture panels to relieve with resultant damage to the roof.

As a result of Engineering analyses/evaluations, and inspection and testing performed, it was determined that the roof ruptured as designed.

In addition, no, other damage was found and the repair effort successfully restored secondary containment to an operational condition.

From April 30, 1988 to June 19, 1988 the Plant was in a

shutdown condition as scheduled for the annual maintenance and refueling outage.

Following the

outage, the Plant was restarted and operated until August 24, 1988 when it was shutdown because of unidentified leakage in primary containment which exceeded Technical Specification limits.

Reactor Core Isolation Cooling (RCIC) valve RCIC-V-63 was identified as the major source of leakage and the valve was repaired and returned to service.

On September ll, 1988 reactor power was reduced to approximately 6~ to allow drywell entry For inspection of Containment Supply Purge System piping welds.

The inspection was required after liquid nitrogen cracked a welded joint in a

six-inch pipe outside of containment while Plant Operators were inerting containment.

A forced outage occurred on October 27, 1988 due to a cracked weld in a

main steam line trap station drain in the Turbine Building.

Repairs were made and the Plant was returned to service within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

On Oecember 1,

1988 the Plant was shutdown again due to air leakage through Containment Supply Purge Valves CSP-V-9 and CSP-V-5 which exceeded Technical Specification limits.

The valve seats on the CSP valves were replaced and the Plant was restarted and ran at or near 100% capacity for the remainder of the year.

1-1

During 1988, there were several examples of major accomplishments which required significant effort on the part of Supply System personnel to success-fully complete.

The following is a

summary of those efforts:

(a)

The third refueling outage was successfully completed.

Significant activities included:

o Replacement of both Reactor Water Cleanup (RWCU) pumps.

The new

pumps, which are unique because both the motor and pump are combined in one unit, do not have seals and are designed for zero leakage.

o High pressure turbine inspection.

The turbine was dismantled, cleaned and inspected to ensure there were no cracks or defects in the turbine blades.

o Installation of the Anticipated Transient Without Scram-Alternate Rod Insertion (ATWS-ARI) System.

As an independent system to the Reactor Protection System (RPS),

the ATWS-ARI System acts as a

back-up to ensure that the control rods are inserted when an RPS actuation occurs.

o Overhaul of the Diesel Generators.

Two of the five diesel engines were overhauled.

Modifications were installed on the Division I and II diesel engines to allow idle speed operation during surveillance testing.

o Removal of spent fuel assemblies and refueling the reactor.

The refueling activity included replacing 152 fuel assemblies, using a

fuel shuffle scheme.

(b)

WNP-2 continued to have an excellent record for limiting worker radiation exposure.

In 1988, total radiation exposure at the Plant was 352 man-rem.

The Institute for Nuclear Operation

( INPO) has set 460 man-rem as the industry goal for 1990 for BWRs.

(c)

During the year WNP-2 experienced only one unplanned automatic shutdown (Scram),

which is well below the industry average of 2.7.

The reactor automatically shutdown on February 4,

1988 from 100 percent power due to iMain Steam Isolation Valve isolation caused by improper execution of a

Technical Specification surveillance procedure.

(d)

In terms of electrical

output, WNP-2 provided more than six billion kilowatt-hours to the Bonneville Power Administration.

This amount marked an 11 percent increase in electrical generation over 1987.

In

addition, the Plant was available for power production nearly 69 percent of the time during

1988, exceeding the overall industry average for BWRs of 65 percent.

(e)

Another new generation mark was established in

November, when a

net 768,651,000 kilowatt-hours was generated (the highest for any 30-day month in the history of the Plant).

1-2

During the year WNP-2 received 20 NRC Notice of Violations (NOVs):

Seventeen (17) Level IV and three (3) Level Y.

Also during

1988, a total of 38 License Event Reports (LERs) were written and submitted pursuant to the requirements of 10CFR50.73.

The 1988 capacity factors, based upon net electrical energy output, are listed in the following table.

Month Ca acit Factor January February March April May June July August September October November December Overa 1 1 85.7 33.6 60.3 91.6 0

5.8 93.9 70.6 58.3 86.1 97 '

63.5 62.2

" Started Maintenance/Refueling Outage

"" Ended Maintenance/Refueling Outage 1-3

100 WNP-2 1988 Power History 90 I

80 0

CL 70 lU E

60 l-

'U 50 GlK Q

40

~O 0

30.

20.

10.

Refueling Outage Jan Feb Mar Apr May Jun JuI Aug Sep Oct Nov Dec Jan 1988 Data based on average power generated per day. Therefore, recovery from a scram that occurred within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period willnot indicate a zero percent power level.

2.0 REPORTS The reports provided in this section meet the requirements of Federal Regula-tions (10CFR50.59) and the WNP-2 Operating License.

Complete data For the year 1987 has been included.

2-1

RER-WASIJINQTON PUDI.

R SUPPLY SYSTEtt RADIATION E JURE RECORDS WORN AND BOD FUtJCTION REPORT /

1. 16 APPENDIX A 02/14/89 NUCLEAR PJ ANT NO.

2 REPORT NUttQER OF PERSONS RECEIVINQ OVER 100 MREH FOR CALENDAR YEAft 1908 TOTAL ttAN-REtt IP UTILITY EtJPLOYEES

0. 000

0. 000 HEALTH PJJYSICS PERSONNEL

25. 908

=

0. 000

12. 663

" 25. 451 '""

0. 000 SUPERVISORY PERSONNEL

12. 369

0. 077

0. 397

6. 947

0. 030 ENQINEER INQ PERSONNEL

6. 816

7. 740

3. 191

2. 321

2. 118 STATION UTILITY CON1RACTORS STATION Et1PLOYEES EtJPLOYEES AND OTHERS EttPLOYEES OPERATIONS Ic SURVEILLANCE HAINTENANCE PERSONNEL

20. 539

0. 000

1. 024

9. 806 OPE RATINQ PERSONNEL

30. 306

0. 000

0. 000

25. 746 CONTRACTORS AND OTHERS

0. 125

0. 000

5. 280

0. 130

0. 935 ROUTINE HAINTENANCE SUPERVISORY PERSONNEL

0. 830

0. 461

0. 749

0. 358 END INEERltJQ PERSONNEL

5. 529

7. 659

5. 569

1. 445

0. 421

3. 230 HAINTENANCE PERSONNEL

82. 894

0. 090

61. 034

44. 517

0. 067 OPERATINQ PERSONNEL

3. 516

0. 000

0. 000

2. 817

0. 000 HEALTH PHYSICS PERSONNEL

4. 175 0: 000

5. 069 7."233 0: 000

20. 239

0. 000 3:

712'.

143

2. 124 INSERV ICE INSPEC TION HAINTENANCE PERSONNEL

1. 265

0. 000

14. 011

0. 895

0. 000

5. 210 OPERATINQ PERSONNEL

0. 326

0. OOQ

0. 000

0. 288

0. 000

0. 000 HEALTH PHYSICS PERSONNEL

0. 003

0. DOO

0. 054

1. 203

0. 000

0: 045 SUPERVISORY PERSONNEL

1. 133

0. 446

0. 124

0. 298 ENDINEERINQ PERSONNEL

0. 366

. 2. 533

5. 275

0. 141

0. 349

1. 107

0. 040

0. 900

.0 SPECIAL HAINTFNANCE HAINTENANCE PERSONNEL IQ7. 741

0. 407

79. 906

79. 180 OPERATINQ PERGONtJEL

2. 428

0. 000

0. QQO

2. 145 HEALTH PHYSICS PERSONREC ~627

0. 000

17. 624

15. 73'I SUPERVISORY PERSONNEL

2. 863

1. 016

l. 730

0. 970 ENQ INEER INQ PERSONNEL

12. 787

9. 804

12. 551

3. 394

0. 461

3. 580

0. 452

h. 117

0. 219

30. 556

0. 000 O. 000 0: 000 "11; 098

~ 4 WASTE PROCESSINQ MAINTENANCE PERSONNEL

1. 51$

0. 000 OPERATINQ PERSONNEL

0. QOQ

0. 000 HEALTH"PHYSICS PERSONNEL=K'8I3 O. 000 SUPERVISORY PERSONNEL

0. 000

0. 000 ENQINEERINQ PERSONNEL

0. 000

0. 000

0. 000

0. 000 0:"696

0. 000

0. 000

l. 152

0. 000

0. 000

0. 000

0. 000

0. 000 I. 042 0: '000 =

2: 020

0. 000

0. 000

0. 000

0. 000

0. 000

0. 000 47

~ 1 REFUELINQ HAINTENANCE PERSONNEL

7. 925 O. 008 OPERATINQ PERSONNEL

0. 699 O. QOO HEALIH PHYSICS PERSONNEL IE376

0. 000 SUPERVISORY PERSONNEL

0. 679

0. 000 ENQINEERINQ PERSONNEL

0. 901

0. 239

2. D23

7. 084

0. 000

0. 595 3.'536

0. 575

0. 000

0. 644

0. 158

0. 260

0. 004

0. 000

0. 277

0. 000

0. 054

0. 052

0. 000 1". 168

0. 000

0. 000 44 TOTAL t&INTENANCE PERSONNEL 221. 879

0. 505 157. 998 142. 634 OPERATINQ PERBONNEL

37. 275

0. 000

0. OQO

31. 591

0. 290

0. 000

56. 407

0. 000 47 HEALTH PHYSICS PERSONNEC 4~02

0. 000 Og. 647 51.'373

0. 00024.

123"'UPERVIBORY PERSONNEL

17. 874

2. 000

3. 000

9. 217

1. 261

0. 765 ENQINEERINQ PERSONNEL

26. 399

27. 975

26. 744

7. 561

10. 087

10. 130 EE 52 54

+4%CRAND TOTALOJ6%

345. 129

30. 480 227. 389 I

4 2

2 I

242. 376

11. 638

91. 425 60ll 72 66

2.2 HAIN STEAN LINE SAFETY/RELIEF VALVE CHALLENGES This section contains information concerning main steam line safety/relief valve challenges for calendar year 1988 in accordance with the requirements of NUREG 0737, Item II.K.3.3, and as-required by iWNP-2 Technical Specifications, Administrative Controls section, paragraph 6.9.1.5(b).

TYPE OF PLANT REASON FOR REACTOR ACTUATION CONDITION ACTUATION POWER ASSOCIATED OATE COMPQMEMT TO

~CODE

~CODE

~CODE LEVEL LED 01/18/88 01/18/88 01/18/88 01/18/88 01/18/88 01/18/88 01/18/88 HS-RV-58 MS-RV-58 MS-RV-30 HS-RV-5C MS-RV-40 MS-RV-48 MS-RV-4A 8

8 8

B B

8 B

OX 05 0$

0$

0'~

0$

05 The 01/18/88 actuations were in response to a

manual reactor trip following a condenser tube leak forced shutdown.

02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 02/04/88 MS-RV-lA HS-RV-4A HS-RV-18 HS-RV-28 MS-RV-38 HS-RV-58 HS-RV-1C HS-RV-1C HS-RV-2C MS-RV-2C HS-RV-5C HS-RV-10 MS-RV-30 B

B A

8 A

8 A

8 A

8 8

8 8

0$

05 05 05 OX OX 05 05 On 05 0$

05 05 88-03 88-03 88-03 88-03 88-03 88-03 88-03 88-03 88-03 88-03 88-03 88-03 88-03 The 02/04/88 actuations were in response to an RPS actuation caused by im-proper execution of a Technical Specification surveillance procedure.

2-3

2.2 HAIN STEAN LINE SAFETY/RELIEF VALYE CHALLENGES (Continued)

TYPE OF PLANT REASON FOR REACTOR ACTUATION CONDITION ACTUATION POMER ASSOCIATED OATE COMPONENT ED

~CODE

~COOE

~COOE LEVEL LEO 04/30/88 HS-RV-58 04/30/88 MS-RV-1A 04/30/88 HS-RV-2A 04/30/88 MS-RV-3A 04/30/88 HS-RV-4A 05 05 05 05 0$

The 04/30/88 actuations were required for setpoint testing.

06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 06/22/88 HS-RV-2B MS-RV-38 HS-RV-48 HS-RV-58 MS-RV-lc HS-RV-2C HS-RV-3C HS-RV-4C MS-RV-5C MS-RV-1D MS-RV-2D HS-RY-3D MS-RV-4D HS-RV-3A MS-RV-4A 06/22/88 MS-RV-1A 06/22/88 HS-RV-2A 06/22/88 HS-RV-3A 06/22/88 HS-RV-4A 06/22/88 HS-RV-18 9X 9X 9X 9f 95 9$

95 9$

9F'5 9~w 9X 9+

9N 9$

9$

95 95 95 9X The 06/22/88 actuations were in support of the acoustic monitoring system calibration procedure, Technical Specification requirement 3/4.4.2.

2.2 MAIN STEAM LINE SAFETY/RELIEF VALVE CHALLENGES (Continued)

TYPE OF PLANT REASON FOR REACTOR ACTUATION CONDITION ACTUATION PONER ASSOCIATED DATE CONPONENT IO

~CODE

~CODE

~CODE LEVEL LED 07/20/88 07/20/88 07/20/88 07/20/88 07/20/88 07/20/88 07/20/88 MS-RV-18 MS-RV-3C MS-RV-2D HS-RV-2A MS-RV-38 MS-RV-3A MS-RV-1C 955 95%

955 955 955 955 95%

The 07/20/88 actuations were manually cycled to reduce thru seat leakage.

07/21/88 MS-RV-1C 07/21/88 HS-RV-18 07/21/88 MS-RV-18 955 955 95K The 07/21/88 actuations were to support post maintenance testing of acoustic monitors.

09/06/88 09/06/88 09/06/88 09/06/88 09/06/88 HS-RV-5C HS-RV-40 MS-RV-1C MS-RV-30 MS-RV-18 09/06/88 HS-RV-2C 09/06/88 HS-RV-10 35 35 3'05 205 205 205 The 09/06/88 actuations were required for setpoint testing and acoustic mon-itor testing following maintenance.

2-5

2.2 MAIN STEAM LINE SAFETY/RELIEF VALVE CHALLENGES (Continued)

TYPE OF PLANT REASON FOR RE'ACTOR ACTUATION CONDITION ACTUATION POWER ASSOCIATED DATE COMPONENT ID

~CODE

~COOE

~CODE LEVEL LED 09/08/88 MS-RV-4D 15$

The 09/08/88 actuation was to support post maintenance testing of an acoustic monitor.

12/08/88 12/08/88 12/08/88 12/08/88 12/08/88 MS-RV-2A MS-RV-3A MS-RV-18 MS-RV-38 MS-RV-3A 125 125 125 12$

12$

The 12/08/88 actuations were in support of post maintenance testing of acous-tic monitors.

2-6

2.2 MAIN STEAM LINE SAFETY/RELIEF VALVE CHALLENGES (Continued)

COOES:

T e of Actuation A.

Automatic B.

Remote Manual CD Spring Plant Condition A.

B.

C.

0.

E.

F.

G.

H.

Construction Startup or Power Ascension Tests in Progress Routine Startup Routine Shutdown Steady State Operation Load Changes Ouring Routine Operation Shutdown (Hot or Cold)

Refueling Reason for Actuation A.

B.

C.

0.

E.

Overpressure AOS or Other Safety System Test Inadvertent (Accidental/Spurious)

Manual Relief NOTES:

1)

Remote manual actuations occurred in support of acoustic monitor position indication calibration testing required by Technical Specifications LCO 3/4.4.2.

2)

Spring set testing was performed in accordance with ASME Section XI and Technical Specifications requirement in applica-bility paragraph 4.0.5.

2-7

2.3 SUHHARY OI.

PLANT OPERAl'ION INCLUDING UNI T SHUTOOI/NS/POWER REDUC1IONS GENERA10R OUTAGE OI=I -LINE CAUSE SIIUTDOMN I ER DATE TYPE HOURS CODE HETHOD NUHOER 1/5/00 S

0 H

5 SYSl Efh COHPONEN1'ONROO CAUSE ANO ACTION TO PREVEN'I'ECURRENCE Reactor power was reduced, as re-

quired, to perform a scheduled control rod sequence exchange.

1/18/88 P

1/20/08 F

2/4/88 F

2/13/08 P

40.0 6.0 45.7 529.4 3

00-03 2

00-06 HC HA CD HC IITEXCH INSTRU INSTRU HTEXCH The plant was shutdown to correct a

condenser tube in-leakage problem.

Several leaking tubes were plugged and the reactor was returned to service.

The generator was removed from the grid to recalibrate turbine DEll auto stop oil pressure switches.

1 he reac tor automa t ica 1 ly shutdown From 100K, power due to HSIV isolation caused by improper execution of a Technical SpeciFication surveillance procedure.

The reactor was manually shutdown due to condenser'in-leakage and rapidly increasing conductivity.

The outage was extended by an inadvertent start of a reactor building supply fan which overpressurized the reactor building, causing the designed roof rupture pan-els to relieve with resultant damage to the roof.

2.3

SUMMARY

OF PLANT OPERA1ION INCLUDING UNIT SNUTDOlJNS/POMER REDUCTIONS (Continued)

GENERAlOR OUTAGE OFF-LINF DATE 1YPE NOURS CAUSE SNUTDOLN Lf;R CODE METNOD NUMBER SYSl'EH COMPONENT CAUSE AND ACl ION TO PREVENT RECURRENCE 3/23/00 F

06.5 NC IITEXCH The plant was manually shutdown due to high conductivity as a result of a condenser in-leakage problem.

4/30/00 S

thru 6/19/08 e

6/24/00 S

6/24/80 S

1197.5 1.7 77.2 RC UA FUEL MFCFUN CONROD The plant was shutdown as scheduled for the annual refueling and main-tenance outage.

The generator was removed from the grid to perform turbine overspeed testing.

The generator was removed from the grid for SCRAM testing.

The plant remained shutdown for replacement:

of a faulty Main Steam Isolation Valve Actuator.

8/19/00 S

RB CONROD Reactor power was reduced, as re-quired, to perform a scheduled conlrol rod sequence exchange.

8/24/88 F

92'5 1

08-29 CI VALVEX lhe plant was shutdown when unidenti-fied leakage in primary containment exceeded 1'echnical Specification limits.

A Reactor Core Isolation Cooling (RCIC) valve RCIC-V-63, was identified as the major source of leakage.

The valve was repaired and returned to service.

2.3 SUHflARY OF PLANT OPERATION INCLUDING UNIT SHUTDOWNS/POWER REDUCTIONS (Continued)

GENERATOR OUlAGE OFF-LINE CAUSE SHU100WN LER DATE TYPE HOURS CODE HETHOD NUNDER 0/20/00 S

275.05 0

9 SYSTEH COHPONENT CAUSE AND ACTION TO PREVLNT RECURRENCE lhe plant remained off line for mod-ifications of Residual Heat Removal check valves, HS-SRV/Vacuum breaker repair and implementation of a design change to the Control Room ventilation system.

9/ll/00 F

10/27/00 S

12/1/88 F

35.60 47.97 208.9 HB 1

88-037 SA PIPE XX VALVEX The generator was removed from the grid and reactor power was reduced to permit drywell entry for inspection of Containment Supply Purge system piping and containment penetration welds.

The plant was shutdown due to a crack-ed weld in a main steam line trap station drain.

Repairs were made and the plant was returned to service.

lhe plant was shutdown due to air leakage through Containment Supply Purge valves (CSP-V-9) and (CSP-V-5) exceeding lechnical Specification limits.

Additionally, Hain Steam Isolation Valve 20A stuck while open-ing and required repair prior to plant restart.

The valve seats on the CSV valves were replaced and the plant was returned to operation.

2.3 SUHMARY Ol PLAN'I OPERATION INCLUDING UNll SIIUTDOWNS/POWER REDUCTIONS (Continued)

GENERATOR OUTAGE OFF-L INE DATE TYPE tlOURS CAUSE SllUTDOWN I.ER CODE HETIIOD NUMBER SYSlEM COMPONENT CAUSE'ND AC1'ION TO PREVENI RECURRENCE 12/12/88 S

12/30/88 S

0 ll 5

CONROD CONROD Reactor power was reduced to reset.

cont'rol rod pattern for 100$ power.

Reactor power was reduced, as re-quired, to perform a scheduled contro1 rod sequence exchange.

CAUSE CODE

'IOTAL FOR 1988 TOTAL GENERAI'OR OFF-LINE IlOURS 949.1 354.7 1197.5 92.6 0.0 45.7 6.8 TOTAL 2646.4

2.3 SUHHARY OF PLANT OPERATION INCLUDING UNIT SIIUTDOWNS/POWER REDUCTIONS (Continued)

SUHHARY OF CODFS OUIAGE TYPE F -

I orced S

Scheduled CAUSE CODE A -

Equipment. Failure 0

Haintenance or Test C -

Refueling 0 Regulatory Restriction E

External Cause F

Administration G Personnel Error N -

Other SHUTDOWN HETNOD Hanual 2

Hanual Scram 3

Auto Scram 4 -

Continued 5

Reduced Load 9

Other

2.3 SUMHARY OF PLANT OPERATION INCLUDING UNIT SHUTDOWNS/POWER REDUCTIONS (Conlinued)

SYSTEH COOL STANDARD CODE CA CD CF CN CI IA EA NA IIB SYSTEH DESCRIPTION React. or Vessels 8 Appurtenances Coolant Recirculation Systems 5 Controls Hain Steam Isolation Systems 8 Controls Residual Neat Removal Systems 5 Controls Feedwater Systems 8 Controls Reactor Coolant Pressure Boundary Leakage Detection Systems Reactor Trip Systems Offsite Power Systems 8 Controls AC Onsite Power Systems 8 Controls Other Electric Power Systems 5 Controls Turbine Generator 8 Controls Hain Steam Supply Systems 8 Controls Hain Condenser Systems 5 Controls Other Features of Steam 8

Power Conversion Systems (not included elsewhere)

Hain Steam System

2.3 SUHHARY OF PLANT OPERATION INCLUDING UNIT SIIUTDOHNS/PO'iKR REDUC1IONS (Continued)

SYSTEH CODE STANDARD CODE RC SE SYSTEH DESCRIPTION Reactivity Control Systems Reactor Core Reactor Containment Systems Containment Combustible Gas Control Systems

& Controls

2.3 SUHMARY OF PI.AWI OPERATION INCLUDING UNI f SflUTDOllNS/POHER REDUC1IONS (Continued)

COMPONENl CODE COMPONENT TYPE/CODE COMf'ONENT TYPE'NCLUDES:

Circuit Closers/Interrupters (CK'IDRK)

Control Rod Drive Mechanism (CONROD) lfeat Exchangers (lllEXCH)

Circuit Dreakers Contactors Contro I lers Starters Switches (otlier than sensors)

Switchgear Control Rod Drive Hechanism Condensers Coolers Evaporators Regenerative lleat Exchangers Steam Generators Fan Coil Units Instrumentation and Controls (INSlRU)

Hechanical Function Units (HECFUN)

Controllers Sensors/Detectors/Elements Indicators Differentials Integrators (Totalizers)

Power Supplies Recorders Switches l'ransmitt.ers Computation Modules Mechanical Controllers Governors Gear Boxes Varidrives Couplings

2.3 SUHHARY OF PIAN1'PERATION INCLUDING UNIT SHUTDOWNS/POWER REDUCTIONS (Continued)

COHPONENT CODE COHPONFNT TYPE/CODE Penetrations, Primary Containment (PFNETR)

Pipes, Fitt:ings (PIPEXX)

Pumps (PUHPXX)

'elays (RELAYXX) l'ransformers (TRANSF)

Turbines (TUROIN)

Valves (VALVEX)

COHPONENT TYPE INCI UDES:

Air Locks Personnel Access fuel Handling Equipment Access Elect:rica 1 Inst.rument Line Process Piping Pipes fit:I;ings Pumps Switchgear Trans formers Steam Turbines Gas lurbines Hydro Turbines Valves Dampers

2.A SIGNIFICANT HAINTENANCE PERFORHEO ON SAFETY-RELATE~OE UIPHENT EgUI PHENT

~ElLUIR ING HAINTENANCE SYSTEH PROB! FH ACTION TAKEN OG-RLY-OG2/LR NHA-TS-12A IYJHA-T[C-12A2 DG-RLY-DG1/K14.

I HO" Diesel Generator I

Con tro 1 Room IIVAC "A" Diesel Genera-tor During the monthly sur-veillancee, DG2 failed to come up to rated voltage.

During the performance of a surveillance

test, temperature switch 12A would not calibrat;e.

During the performance of a Technical Specification surveillance, a relay failed and completely deenergized the diesel generator.

During the troubleshooting act.ivities, it was noted that: the voltage regulator latching relay was picked up erro-neously.

lhis relay was removed and replaced with an approved

spare, tested and returned to service.

During the trouble shooting evolution, the technicians found that the inst:ru-ment. providing input to the temperature switch required adjustment.

No re-placement paris were required, the sur-veillance was completed and the instru-ment loop was returned to service.

The DG gi control circuit was tagged out and it was noted that the K14 relay had a burned up relay coil ~

The relay was removed and replaced with an approved

spare, tested and returned to service.

FPC-FCV-1 FPC-DP IC-1 HPCS-RLY-5051/A Fuel Pool Cooling High Pressure Core Spray The valve/controller for FPC bypass flow is not controlling flow prop-erly.

The relay target/seal-in unit will not adjust to the proper value.

The flow control valve was isolated and instrument technicians performed an op-erational recalibration on the asso-ciated dP switch.

The valve was func-tionally checked and operat:ed correctly.

The relay was removed and found to be inoperable.

The relay was replaced with an approved spare, tested and returned to service.

2.4 SIGNIFICANT MAINTENANCE PERl'ORMED ON SAFE1'Y-RELA1ED CILUIPMEN1 (Continued)

EQUIPMENT

~RE UIRING HAINl'ENANCE SYSTEM PROBLEM AC fION I AKEN HS-V-28A HS-V-200 HS-V-28C HS-V-28D MS-V-22A HS-V-220 MS-V-22C HS-V-220 Hain Steam The qualified life of t.he associated HSIV limit swit.ches and solenoid pi-lot valves dictates that these components be re-placed or rebuilt during the R3 outage.

1'he limit switches were disconnect:ed and overhauled including t.he replacement of all consumable components.

The asso-ciated solenoid pilot valves were re-moved and replaced with approved spares.

lhe valves were reassembled, funct.ion-ally tested and returned to service.

RllR-RHS-V/53A Residual lleat; Re-Valve has "closed" in-dicat:ion regardless of actual valve position.

The position switch contacts were check-ed for tightness and found to be snug.

1'he posit.ion switch was replaced and correct valve posit.ion indication re-stored.

The valve was returned to service.

SGT-TS-102 Standby Gas Treat-ment The high temperature alarm associated with the outlet temperature of HEPA unit 0-1 alarms at 80 F rather than 120'F.

The temperature switch was recalibra-functionally tested and returned to service.

CRD-LTS-601A CRD-Ll'S-6010 CRD-LTS-601C CRD-LTS-601D Control Rod Drive Scram discharge volume level instruments ex-ceeded trip setpoint-reca1 ibrate.

Reca1 ibra t:ed the scram di scha rge volume level instrument:s and returned the loop to service.

DCW-N-1C Diesel Cooling Hater The immers ion hea ter cycles on/off causing a

HPCS system ground.

During the troubleshooting process the immersion heater was found faulted to ground.

The heater was replaced, tested and returned to service.

2.4 SIGMIFICANT IIAINTENANCE Pl:RFORMEO ON SAFETY-R~EI.ATEO E UIPMENT (CenIInnerI)

EQUIPHENT M

SYSTEH PROBI.EH ACTION TAKEN HS-V-20A HS-V-280 HS-V-20C HS-V-280 Hain Steam Hain Steam Isolation Valves 20A, 200,

28C, and 20D failed their local leak rate tests'is-assemble and repair per planL procedures.

lhe valves were disassembled and over-hauled.

The repair included machining the valve seats, cleaning Lhe main

discs, reassembly and repcrforming the local leak rate test.

All valves passed the LLRT following overhaul.

IIPCS-42-4A7C High Pressure Core Spray The breaker for Lhe NPCS keep-filled pump has a

broken actuator arm.

This breaker cannot be safely energized in this condition.

The defective breaker was removed and replaced with an approved

spare, tested and returned to service.

SGT-1'C-201 Standby Gas Treat-ment The temperature switch associated with the dis-charge of charcoal filter 101 would noL reset.

The faulty switch was

removed, replaced with an approved

spare, calibrated and returned to service.

HS-AO-28C HS-AO-200 Hain Steam General Electric requires a five-year Hain Steam Isolation Valve operator overhaul.

Valve operators were removed and re-placed with previously rebuilt spares.

lhe replacement operators were installed on the valves and tested satisfactorily.

REA-E/S-6130 Reactor Building Exhaust Air Hhile performing a Tech-nical Specification test, the power supply for a radiation indicating switch failed.

During troubleshooting it was determined that the power supply for RIS-6090 could not be repaired.

The power supply was replaced with and approved

spare, the surveillance was satisfactorily complet-ed and the instrument loop was returned to service.

2.4 OTHER SIGNIFICANT NAINTENANCE EFFORTS Hain Condenser Ins ection and U

rades Previous inspections of the Hain Steam Condenser had identified problems with condenser tube thinning caused by errosion from the low quality steam dumps and condensate drains to the main condenser, Errosion damage to the tubes had previously caused several unplanned outages.

Extensive efforts were taken to install perforated errosion plates and modify high energy baffles to prevent errosion from reoccurring in these areas.

Subsequent plant shutdowns and in-spections have demonstrated that the modifications were successful in prevent-ing further tube degradation in the modified areas.

Errosion/Corrosion Ins ection Pro ram The errosion/corrosion pipe wall thinning inspection program examined 65 pipe locations during the February and April outages.

The effort included a

team of seven fulltime NOE Specialists and Engineers.

Both water and steam piping from five major systems were examined.

Over 20,000 individual wall thickness measurements were made.

The trended results indicate that wall thinning is occurring in some of the higher energy steam piping and several drain lines.

Pipe wall buildup by welding was completed at four elbows on the Bleed Steam System piping and one tee on the Moisture Separator Reheater drain piping.

As a result of data taken during the 1987

outage, the majority of elbows in the eighteen inch Extraction Steam lines were built up on the 0.0.

by welding.

This was done to prevent thru wall errosion prior to the 1989 outage when all carbon steel elbows in this pipe run will be replaced with stainless steel elbows.

All of the thickness measurements taken have been input into the data base for trending and remaining life predictions.

Heat Exchan er Tube Inte rit Pro ram The heat exchanger tube integrity program examined over 12,000 heat exchanger tubes or the equivalent of 65 miles of tubing.

Eddy current inspection iden-tified leaking and flawed tubes in Feedwater Heaters 6A and 68, Main Steam Condenser and the Reactor Closed Cooling Heat Exchangers A, 8, and CD Based on the

data, criteria for preventive plugging was developed.

In addition, several tubes were removed and metallurgical analysis was performed on the defects.

Samples of the tubes were analyzed using an electron microscope.

Stress corrosion cracking was identified in the Feedwater Heater 6A and 68 tubing.

Based on the inspection date and future trending, accurate estimates of remaining useful life can be made.

This effort involved four fulltime Supply System Engineers and NOE Specialists, and twelve contract employees, 2 - 20

2.4 OTHER SIGNIFICANT MAINTENANCE EFFORTS (Continued)

Westin house 480 Volt Circuit Breaker Ins ection In response to NRC Bulletin 88-01, "Defects in Westinghouse Circuit Breakers",

the Supply System performed short-term and long-term inspections on twenty-one (21) type OS-416 480 volt A.C. circuit bre'akers in Class lE safety related applications.

Six (6) of the 21 circuit breakers passed the required accept-ance criteria for both the short-term and the long-term inspections with no limitations.

Three (3) of the remaining 15 circuit breakers failed to pass the long-term required acceptance criteria based upon improper roller align-ment.

Spare breakers were located to replace the three failed breakers.

One of these three spare breakers also failed the roller alignment criteria, an additional spare breaker was located and installed.

Fifteen (15) circuit breakers (including the replacement breakers) passed the weld inspection criteria for limited

use, which will require periodic reinspections, or replacement= of breaker pole shafts.

The long-term inspection was successfully performed on these breakers.

"B" Loo H draulic Power Unit and Flow Control Valve Actuator Refurbishment The "B" Reactor Recirculation Pump Hydraulic Power Unit (HPU) and the Flow Control Valve (FCV) Actuator were disassembled and refurbished during the R-3 outage as part of a preventative maintenance program designed to reduce nui-sance leakage from the HPUs.

The refurbishment included the cleaning and polishing of the inside of the cylinder, the installation of new seals, and tolerance verification.

The flow control valve actuator was sent to the manufacturer For a

complete overhaul'y implementing an extensive main-tenance program on these components, the potential for introduction of fyrquel (hydraulic fluid), into the radwaste system is reduced, One-Year Diesel En ine Maintenance The Supply System performed the manufacturers'ecommended one-year preven-tative maintenance to all five of the NNP-2 diesel

engines, This maintenance

included, but was not limited to, replacement of all filter elements in the lube oil, fuel oil and intake air systems, engine one-revolution inspection, and inspection of all of the turbo charger after coolers.

Additionally, the power pack assemblies on the lA2 and 182 engines were replaced.

All equipment was found to be free of excessive wear or degradation.

2 - 21

2.4 OTHER SIGNIFICANT MAINTENANCE EFFORTS (Continued)

During the 1987 refueling/maintenance (R2) outage, all four main steam bypass valves were modified to reduce steam loss.

As a followup action to that mod-ification, a

special test was performed during the 1988 outage to determine the Balance of Plant (BOP) steam loss with all turbine bleed steam isolation va 1 ves closed.

The conc 1 us ion, fol lowing thi s test, was that the tota 1 BOP main steam loss was approximately equivalent to a 1/2" steam line, routed to the main condenser.

In an attempt to verify this test conclusion, two of the modified valves were disassembled and inspected during the R3 outage

~

The valves had approximately zero leakage following one year of service.

During the 1989 maintenance

outage, the remaining two valves will be disassembled and inspected.

Turbine Maintenance During the 1988 refueling

outage, the High Pressure turbine was disassembled for manufacturer's required inspections.

Visual inspections were performed with only minor errosion found at the horizontal joint of the HP shell at both blade ring fits and at the horizontal joint of the inner glands.

No unaccept-able indication of any cracks were found.

Additionally, visual inspections were performed on the reheat

valves, the turbine oil reservoir, the HP turbine discharge piping and the last stage blades of the Low Pressure turbine.

No unacceptable indications of cracking, errosion or any other abnormality were found during these inspections.

Main Turbine Throttle Valves Prior to plant

shutdown, a

test was performed to determine if WNP-2 could repeat a scenario from a Westinghouse Advisory Letter 87-03, where the throt-tle valves "stick open".

During the performance of this test, we were able to get one out of four valves to "stick open".

An in-house root cause evaluation was performed and a

minor modification was made to the valves which entailed changing some insulation on the throttle valve bonnet at thecross head sup-port location and increasing the clearance from the cross head to the cross head support to the maximum allowable.

Following these modifications, another test was performed, and the "sticking" condition was not repeated.

Main Turbine Governor Valves During the 1988 refueling

outage, WNP-2 implemented a manufacturers'ecom-mended "stiff stem and bolted bushing" modification to the gl and 44 governor valves.

This modification was implemented in attempt to solve the governor valve vibration problem which has been occurring at WNP-2 for 2 years.

During the valve disassembly, the valve configuration was modified by adding a relief groove in the plug seal ring groove to eliminate a

theorized valve binding scenario.

During the 1989 refueling

outage, an inspection will be made to evaluate the effectiveness of this modification.

Additionally, a

complete dimensional mapping was performed on all four governor valves to evaluate the current valve configuration and for future historical data.

2-22

2.4 OTHER SIGNIFICANT MAINTENANCE EFFORTS (Continued)

Im 1 emen tat i on of the MOVATS Pro ram The MOVATS testing program For the 1988 refueling outage included twenty-one (21) motor operators (HO) which had not been previously tested and seven (7) post maintenance tests of MO's which had been tested during the 1987 outage.

All seven of the followup tests were completed with satisfactory test results.

Ouring the

testing, a

generic problem with torque switches in SMB-000 MO's was discovered.

The problem switches are made of melamine and exhibit two failure modes; cam binding and broken cam lugs.

All torque switches for safety related SMB-000 HO's made of melamine were replaced with torque switches of a different material and with metal cam lugs.

In addition, a

sample of torque switches of other materials was inspected to assure the problem was limited to melamine.

The scope of torque switch replacements was expanded when Equipment qualifica-tion Engineering determined that a family of SMB-00 HO's had torque'witches of similar design and material as those in SMB-000 HO's.

All such torque switches were replaced, or justified as not needing replacement.

The torque switch failures were determined to be reportable per 10CFR Part 21 and reported via LER 88-17.

2 23

2.5 INDICATIONS OF FAILED FUEL INTRODUCTION In accordance with the commitment and requirements described in WNP-2

FSAR, Section 4.2.4.3, a

visual inspection of discharged fuel assemblies from WNP-2, Cycle 3

was performed on October 10-11, 1988.

The purpose of the in-spection was to verify assembly and rod structural integrity.

In addition, a

visual inspection of discharged fuel channels was performed at the same time.

SUMMARY

OF INSPECTION RESULTS A total of nine assemblies and four channels discharged at the end of Cycle 3

were inspected.

No evidence of geometric distortion, rod bow or cladding defects were observed.

The fuel did exhibit nodular corrosion which covered portions of the cladding on some of the fuel rods inspected.

The extent of coverage did not appear to have changed significantly when compared to the fuel discharged at the end of Cycle 2.

Therefore, it is concluded that the rate of nodular growth appears to have slowed.

This level of crud induced localized nodular corrosion coverage is most closely related to G.E.

visual standard No. 2.

A foreign object was observed resting on the lower tie plate between two fuel rods in one assembly.

During Cycle 3,

a fuel failure believed to be a single rod leaker was detected about mid-way through the cycle.

Flux testing con-ducted during the cycle identified several suspected assemblies.

The reduction in off-gas activity noted during Cycle 4

indicates the leaking assembly was discharged (refer to Section 2,9 of this report).

Fretting marks were noted on several assemblies, particularly in the region of the sixth grid.

The marks appear to be a slightly polished area on the clad and may have been caused during the dechanneling operation.

The inspected channels all exhibit a

generous coating of a flake-like oxide layer.

Some scratches were noted and two possible pre-hole locations were observed.

SELECTION OF ASSEMBLIES AND CHANNELS During the spring 1988 refueling outage, 152 assemblies were discharged.

Nine of these assemblies and four channels were selected for visual inspection.

The nine assemblies represent greater than 5

percent of the discharged fuel and are representative of the highest burnup assemblies in the discharged batch.

The visual examination of the peripheral rods included observations for cladding

defects, fretting, rod

bow, missing components, corrosion, crud disposition and geometric distortions.

The four channels selected had expe-rienced weld repair during manufacturing.

2 24

2.5 INOICATIONS OF FAILEO FUEL (Continued)

Of the 152 assemblies discharged, there are 38 sets of four assemblies with approximately the same exposure and power history.

Assemblies inspected were selected to provide a

range of both exposure and power history.

In addition, preference was given to assemblies which underwent power increases greater than 10 percent in Cycle 3.

The selected assemblies are all high enriched (2.19 weight percent U-235) assemblies.

Some characteristics of the selected assemblies are shown in Table l.

TABLE 1.0 CYCLE 3

OISCHARGEO FUEL ASSEMBLIES SELECTEO FOR EXAMINATION FUEL ASSEMBLY EXPOSURE IDENTIFICATION

~NND/NTU CYCLE 3 POWER INCREASE CHANNEL FEATURES COMMENT LJT 465 18,322 37.3X (Oecrease)

Weld Repair Channel LJT 424 LJT 646 20,703 16.1$

20,462' 15.05 Next to Suspect Leaker Cell 1/8 Core Symmetric to LJT 424 LJT 814 20,644 14.95 Weld Repair Channel LJT 417 LJT 658 LJT 719 LJT 709 21,588 13.35 20,121

- 19.95 18,944 17,0%

20,614 15.15 Weld Repair Channel Weld Repair Channel From Suspect Leaker Cell; Highest Power In Cycle From Core Center 1/8 Core Symmetic to LJT 814 LJT 444 20,570 0.05 The nine assemblies inspected have exposures from 18,322 to 21,588 MWO/MTU.

The highest (110$ core average) and lowest (58$ core average) power asseblies for Cycle 3 are

included, and represent power changes from -375 to

+16K from those experienced in Cycle 2.

An assembly from a

suspect leaker cell and an assembly adjacent to a suspect leaker cell were included in the inspection.

2-25

2.5 INOICATIONS OF FAILEO FUEL (Continued)

INSPECTION TECHNI UE The poolside visual examination was performed with an underwater periscope system and the results of the fuel inspection recorded with a 35mm camera.

In

general, two sides of each fuel assembly were viewed.

Photographs were taken of the points of interest.

A total of 60 photographs of the examined fuel and channels were taken.

The inspection procedure involved moving the selected fuel assembly in a vertical position past the fixed periscope.

This was ac-complished by raising the fuel assembly out of the spent fuel rack with the fuel handling mast on the refuel bridge.

Channel inspection was performed in a similar manner.

An assembly wash station was used to remove surface crud from some of the edge fuel pins in order to assess the rate of nodular growth under the surface corrosion (crud).

INSPECTION CRITERIA Visual inspection of the selected assemblies was performed to determine the extent of the following phenomena:

o Proper rod seating in the lower tie plate, o

Rod bow and spacing, o

Spacer location and perpendicularity, o

Finger spring condition, o

Condition of tie rod hex nuts and other structural components, o

Nodular corrosion and crud formation, and o

Rod fretting.

RESULTS OF THE FUEL EXAMINATION The inspected fuel assemblies appeared to have good structural integrity.

The upper tie plates were level, -fuel pin springs had ample compression space, tie rod nuts were snug and all of the fuel pins observed were properly seated in the lower tie plate.

The spacers appeared perpendicular to the fuel pins and were properly located.

No finger spring damage was observed.

The grid spacers in general exhibit a

heavy nodular buildup which appears to have saturated based on comparsion with past observations.

1'he only anomoly was the observation of a

foreign object observed on the lower tie plate of LJT 658.

This object appeared to be of sufficient size that entry from either the lower or upper tie plate is improbable.

2-26

2.6 PLANT MOOIFICATIONS Federal Regulations (10CFR50.59) and the Facility Operating License (NPF-21) allow changes to be made to the facility as described in the Safety Analysis Report and tests or experiments to be conducted which are not described in the Safety Analysis Report without prior Nuclear Regulatory Commission (NRC)

approval, unless the proposed

change, test or experiment involves a change in the Technical Specifications incorporated in the license or an unreviewed safety question.

In accordance with 10CFR50.59, summaries of the permanent design changes and temporary plant modifications completed in 1988 are provid-ed'~

Included are summaries of the safety evaluations.

2-27

2.6.l PLANT OESIGN CHANGES The following plant design changes were completed in l988 and reported in accordance with 10CFR50.59.

These modifications were eva'luated and it was determined that they did not (a) increase the probability of occurrence of an accident or malfunction of the equipment important to safety, as previ-ously evaluated in the WNP-2 updated Final Safety Analysis Report (FSAR),

(b) create the possibility of an accident or malfunction of a different type than previously evaluated in the FSAR, (c) reduce the margin of safety as defined in the basis for any WNP-2 Technical Specifications, or (d) require a change to the WNP-2 Technical Specifications.

2 28

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 84-1394 Plant Design Change 84-1394 was initiated to replace the originally in-stalled Reactor Mater Cleanup, (RWCU) pumps which had a history of Frequent failures.

High maintenance frequencies and long replacement part lead times From the vendor required the Supply System to maintain a costly large spare parts inventory.

Additionally, pump overhaul attributed to radiation exposure to maintenance personnel ranging from:1.5 to 3.5 Han-Rem per pump overhaul.

This modification installed two Hayward Tyler sealess pumps.

Each pump has a

rating of 480 GPM with a total system flow capability of 133 percent.

The pumps are expected to increase

.system reliability, reduce maintenance and improve reactor water quality with the systems additional Flow capacity.

This modification did not result in a

change to the WNP-2 Technical Spec-ifications or involve an unreviewed safety question because the system capability or function was not reduced in any manner.

The additional capacity has not been used pending completion of an engineering stress analysis.

PLANT DESIGN CHANGES 85-0115-1 5 86-0624 Plant Design Changes 8501151 and 8606240 were init ia ted to provide additional isolation versatility to subsystems of the fire protection system.

This modification provides increased versatility to isolate por-tions of the fire protection system as a result of damage, surveillance, or maintenance, thus minimizing the decrease in fire protection coverage.

This increases the system availability and reliability.

These modifications installed manual isolation valves on fire protection lines to provide additional isolation versatility.

Also, a sleeve was in-stalled on a line running under the diesel generator building, reducing the probability of damage to this line from a safe shutdown earthquake.

These modifications did not result in a

change to the WNP-2 Technical Specifications or involve an unreviewed safety question because the in-creased availability and reliability of the fire protection system derived from increased isolation versatility outweighs the negligible decrease in system reliability caused by increasing the number of valves.

This is because the valves added are manually repositioned,

locked, and position verification performed

monthly, which results in an acceptably low prob-ability of failure.

2 - 29

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 85-0115 Plant Design Change 85-0115 was initiated to install automatic sprinklers for fire protection in a

high fire loading area in the Radwaste Building.

Also, this satisfies a related recommendation From the (ANI Recommendation 84-lla) and accounts for a modification in the fire loading for the area protected.

The area is now used for temporary storage of transitory com-bustibles such as those accumulated during a refueling outage.

This modification installed automatic sprinklers and the associated elec-trical alarm wiring for the truck bay and storage area in the 437 foot elevation of the Radwaste Building.

This modification did not result in a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because:

(1) this installation is not a safety related system; (2) an evaluation determined that water in this area would not affect the performance of any safety related equipment; and (3) fire protection in this area reduces the prob-ability oF damage to safety related equipment and/or unintentional release of radionuclides to the environment caused by a fire in this area.

PLANT DESIGN CHANGE 85-0131 Plant Design Change 85-0131 was initiated to prevent debris from entering the weir box in the Circulating Water Pump House (CWPH) and becoming en-trained in the Circulating Mater and Plant Service Water (TSW)

Systems.

This reduces fouling in downstream components which increases the reliabi 1-ity oF these components served by the TSM and decreases the probability oF unplanned transient events.

This modification lowered the CMPH weir box vent stacks and installed steel "g" decking over the CWPH basin.

This modification did not involve a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because the circulating

water, tower

makeup, and plant service water systems are not safety related.

Also, damage or malfunction of any of these systems would not affect the performance of any safety related equipment.

2 - 30

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 85-0545 Plant Design Change 85-0545 was initiated to provide standby AC power to the Cooling Jacket Mater (CJlJ) pumps that supply cooling water to the plant control air compressors..

Standby AC power was already available to the compressors prior to the modification.

The availability of the CJM pumps allows for continued operation of the compressors following a

Loss oF Offsite Power event.

The continued availability of the control air com-pressors would provide air supply to non-safety related components and instruments.

This results in making more components available to mitigate the

event, therby minimizing the consequences of the event and increasing the probability of a successful shutdown.

This modification connected the operating and backup CJM pumps to Division 1

and Division 2 emergency power sources.

Only one pump is needed to circulate cooling water to all three air compressors.

Auto-standby con-trols were provided to automatically start the backup pump in the event the operating pump failed or lost power.

This modification did not result in a

change to the MNP-2 Technical Speci-fications or involve an unreviewed safety question because:

(1) the increased load From the CJW pumps was already included in the FSAR evalua-

tion, and (2) the continued availability of the air compressors following a loss of offsite power makes more components available to minimize the con-sequences of the event, increasing the probability of a successful shutdown.

PLANT DESIGN CHANGE 85-0564 Plant Design Change 85-0564 was initiated because the auto advance function of the intake air filters for the Control

Room, Radwaste, Turbine and Reactor Buildings did not operate properly with the originally installed dP switches.

The wide variations in air flow caused the dP switched to act-uate the auto filter advance process unnecessarily, thereby wasting roll filters.

This design change replaced the originally installed dP switches with auto advance timers for all roll type intake air filters located in the Control

Room, Radwaste, Turbine and Reactor Buildings.

The installation of the automatic advance timers did not require a modifi-cation to the MNP-2 Technical Specifications or involve an unreviewed safety question because the new timers increase the reliability of the system and have not affected the Functional characteristics oF the system.

2-31

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 85-0718 Plant Design Change 85-0718 was initiated to resolve a

gap in gaseous ef-fluent monitoring between the normal and extended range monitors.

Oue to a

OfF Site Dose Calculation Hanual requirement, the Mi-Hi setpoint was set at 2 decades less than the top of scale on the normal sample rack.

By design, the Hi-Hi trip signal transfers the flow to the extended range

monitor, which incorporates a

one decade overlap with the normal

range, resulting in a monitoring gap of approximately 1 decade.

Rather than revise the OOCN calculation and bases for the Hi-Hi setpoint, a

design modification to route the sample through both sample racks contin-uously rather than the previous transfer arrangement was implemented.

This design provides continuous monitoring capabilities throughout all monitor-ing ranges.

There were no modifications to the WNP-2 Technical Specifications as a

result of this design change.

This change did not involve an unreviewed safety question because with the continuous monitoring capabilities, the system is more reliable and eliminates the possibility of any sample gaps.

PLANT DESIGN CHANGE 86-0229 Plant Design Change 86-0229 was initiated in response to requirements set forth in 10CFR50.62 "Requirements for Reduction of Risk From Anticipated Transients without SCRAM (ATWS) Events for Light-Hater-Cooled Nuclear Power Plants".

An Alternate Rod Insertion (ARI) system was installed at WNP-2 during the refueling/maintenance outage of 1988.

This system was designed to insert all control rods in the event of an ATWS condition (Low Level 2 or High Rx pressure without a

SCRAN).

The installed system consists of manual con-trols and a

logic system in the main control

room, eight new instruments installed in two plant instrument racks and nine new solenoid valves in-stalled in strategic locations designed to vent the Control Rod Drive air header which in turn will open the individual scram inlet and outlet

valves, thereby automatically inserting the control rods.

This plant modification did not result in a

modification to the WNP-2 Technical Specifications (as approved by the NRC endorsement of the BWROG proposal) or result in an unreviewed safety question because the ARI system is designed to actuate in the event the RPS trip system does not scram the plant.

Therefore, as a

backup system to

RPS, the ATWS-ARI system increases the margin oF a safe shutdown.

2 - 32

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 86-0343 Plant Design Change 86-0343 was initiated as a result oF a fire protection walkdown which noted that the Shift Manager s office window was not con-structed with a fire retardant material and therefore was not bounded by the combustible material loading evaluation.

This modification replaced the originally installed window with a one-hour fire rated window and in addition added fire retardant wall paneling, book

shelves, office furniture and carpet.

An aluminum suspended ceiling and a

fire stop at the south wall line between the existing computer Floor and concrete sub-floor was also installed.

This modification did not result to a

change in the MNP-2 Technical Speci-fications or involve an unreviewed safety question because the reduction of combustible material in the control room reduces the consequences of damage to safety related equipment.

PLANT DESIGN CHANGE 86-0618 Plant Design Change 86-0618 was initiated to provide improved control dur-ing the shutdown cooling mode.

The result of the modification is reduced wear on the Residual Heat Removal (RHR) system components resulting in improved RHR System reliability.

This modification installed control circuitry to allow throttling of the RHR heat exchanger discharge valves (RHR-V-3A8B) during the shutdown cool-ing mode.

The RHR-V-3AHB valves and the RHR heat exchanger bypass valves (RHR-V-48A88) are used to control cooling during the shutdown cooling mode.

The previous method of control used the RHR-V-48A88 and the cooldown injection valves (RHR-V-53A&B), which resulted in significant wear in the RHR-V-53A8B valves.

This modification did not result in a

change to the NNP-2 Technical Speci-fications or involve an unreviewed safety question because:

(1) the overall reliability of the RHR system was

improved, and (2) the boundary conditions of the FSAR evaluations remained unchanged.

2 33

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 87-0009 Plant Design Change 87-0009 was initiated because the originally designed and installed Traversing In-Core Probe (TIP)

System containment isolation valves did not meet the specified ASNE design criteria.

The configuration remained unchanged as presented in the FSAR.

This modification removed the originally installed ball valves, containment penetration Flanges and the tubing between the outboard valves and the

flanges, and replaced them with ASHE qualified components.

The design or function of these components did not change as a result oF this modifica-tion.

The design change was implemented to ensure verbatim compliance with design criteria per 10CfR50.Appendix A.

This modification did not result in a

change to the WNP-2 Technical Speci-fication or result in 'an unreviewed safety question because:

(1) the margin of safety was not reduced by upgrading the components and (2) the func-tional design of the system was not altered as a result of this design change.

PLANT DESIGN CHANGE 87-0085 Plant Design Change 87-0085 was initiated to ensure control room indication from the Circulating Mater Pump House (CWPH) and circulating water equip-ment control would be available following a loss-of-offsite power or a

LOCA events This results in making information and components available to mitigate the

event, thereby minimizing the consequences of the event and increasing the probability of a successful shutdown.

This modification provides standby power to the supervisory panels in the CWPH from the Division 1

and 2 diesel generators (OG).

This modification did not result in a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because:

(1) the increased load to the DGs from the supervisory panels does not exceed the allowable DG continuous load rating; (2) the increased load to the DGs was included in the FSAR evaluation; and (3) the continued availability of con-trol room indication from the CWPH and equipment control makes more infor-mation and components available to minimize the consequences of the event, increasing the probability of a successful shutdown.

2-34

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 87-0160 Plant Design Change 87-0160 was initiated as a result of concerns noted by a Nuclear Regulatory Commission Inspector during a routine plant tour.

The major concerns were that personnel were not always notifying Health Physics to perform,a radiation survey prior to working on the refueling bridge, and that all equipment being removed From the Fuel Pool was not being imme-diately surveyed upon removal as required by approved plant procedures.

This plant modification installed a

dedicated power supply and mounting bracket on the refuel bridge platform to accommodate the installation of an Area Radiation Monitor (ARM).

Prior to the start of refuel activities, the ARM is installed on the refuel bridge by the Health Physics organization as required by plant procedures.

This modification did not result in a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because the addition of the ARM has increased personnel safety and enhances the radiation monitor-ing capabilities at WNP-2.

PLANT DESIGN CHANGE 87-0229 Plant Design Change 87-0229 was initiated to provide improved air filtra-tion to the Air Inlet Room of the High Pressure Core Spray (HPCS)

Emergency Diesel Generator (DG).

This modification provides cleaner intake air to the diesel

engine, particularly when the engine is running at idle speeds and during periods of high ambient dust concentrations and volcanic ashfall.

The existing oil bath filter for the diesel

engine, which is loc-ated in the Air Inlet

Room, is inefficient at low engine speeds.-.

As

result, the modification reduces engine wear per unit time of operation, thereby increasing engine reliability.

This design change installed air Filters at the inlet of the Air Inlet

Room, upstream of the diesel engine oil bath filter, and removed the HVAC prefi lters on the outlet from the Air Inlet Room to the HVAC.

Also, a

delta-pressure gage was installed across the new filters to provide Filter loading indication.

To ensure filter integrity and limit air flow resis-

tance, the filters are replaced at or prior to reaching a maximum allowable delta-pressure.

This modification did not result in a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because the OG reliabil-ity is increased by reduced engine wear through improved intake air filtra-tion.

In the unlikely event filter replacement is severely neglected and the filters -become heavily

loaded, the filters are designed to fail prior to any loss of engine power caused by restricted air flow allowing an unrestricted flow path to the engine air intake lines through the existing oil bath filter.

2 - 35

2.6.1 PLANT OESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 87-0328 Plant Design Change 87-0328 was initiated to improve the reliability of the drains to the diesel engine starting air dryers, and to reduce th'e frequen-cy and magnitude of repair to the dryer drains.

The improved reliability of the drain system reduces the probability of fouling downstream compo-nents which results in increased reliability of the diesel generators.

The automatic drain traps were removed by this design

change, and the dryer drain lines wer replaced with stainless steel parts and piping to reduce corrosion to drain piping.

Manual blowdown of the drains is performed periodically.

This modification did not result in a

change to the WNP-2 Technical Speci-

'ications or involve an unreviewed safety question because the reliability of the air dryer drain system was

improved, thereby increasing the reli-ability of the diesel generators.

PLANT OESIGN CHANGE 88-0026 Plant Oesign Change 88-0026 was initiated to provide additional containment isolation capability for the Reactor Core Isolation Cooling (RCIC) system.

This reduces the probability of the RCIC suction line becoming a contain-ment leakage path to the environment and satisfies the requirements for containment isolation and leakage mitigation criteria as specified by the NRC.

(For further information see LER 88-002).

This modification installed a

new check valve (RCIC-V-204) downstream of the motor operated Condensate Storage Tank (CST) valve (RCIC-V-10) and relocated the 2-inch RCIC keep full pump suction line (2" RCIC-(8)-l-l) downstream of RCIC-V-204.

In the event of a design basis LOCA concurrent with a seismic event and a single component failure, the two-inch RCIC keep full pump suction line would become a

leakage path from the suppression pool to the environment without the check valve.

This modification did not result in a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because:

(1) the low probability of a

check valve to fail closed negligibly reduces the reli-abilityy of the RCIC

system, (2) increases the probability of successful containment isolation following an event requiring isolation, (3) the boundary conditions used in the FSAR were not affected, and (4) the WNP-2 Technical Specifications margins were not altered.

2 - 36

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 88-0060 Plant Design Change 88-0060 was initiated to replace the built-up roofing and insulation on the reactor building that was damaged during the Reactor Building overpressurization event on February 14, 1988.

This modification replaced the damaged reactor building built-up roof with an elastic sheet membrane roof system.

This roof system is designed to allow over-pressure relief prior to any structural damage being done to the reactor building structure during a design basis

tornado, maximum credible overpressurization event.

The modification did not result in a

change to the WNP-2 Technical Speci-fications or involve an unreviewed safety question because the reactor building roof membrane replacement does not affect the boundary conditions used in the FSAR evaluations or affect the performance of safety related equipment during FSAR analyzed accident conditions.

PLANT DESIGN CHANGE'8-0079 Plant Design Change 88-0079 was initiated to replace two pressure switches that provide input to the flain Steam Safety Relief Valve Actuators.

These pressure switches had degraded such that they needed to be

replaced, however, the manufacturer no longer supplies Class I switches and no spare parts were available.

This design change replaced the originally installed pressure switches with new switches that met the Class I design specifica-tions.

This modification did not result in a

change to the WNP-2 Technical Speci-fications or result in an unreviewed safety question because the replace-ment switches perform the same function as the originally installed equip-

ment, they meet the required Class I design specifications and the devices are not covered in the WNP-2 Technical Specifications.

2-37

2.6.1 PLANT DESIGN CHANGES (Continued)

PLANT DESIGN CHANGE 88-0151 Plant Design Change 88-0151 was initiated to ensure the Residual Heat Removal System (RHR) suppression pool suction valves would not be opened prior to closing the RHR shutdown cooling suction valves.

The modification prevents a valve lineup that would unintentionally drain the reactor vessel to the suppression pool.

This modification changes the open control logic For the suppression pool suction valves (RHR-Y-4A&B) by adding an interlock that prevents RHR-V-4A&B from opening if the shutdown cooling valves (RHR-V-6A&B) are open.

This modification also removes the seal-in from the opening control circuit of the RHR-V-4A&B to allow manual control at any time.

Previously, the valve open circuit would seal-in and the valve could not be closed until it reached the full open position.

This modification did not result in a

change to the MNP-2 Technical Speci-fications or involve an unreviewed safety question because:

(1) the chan-ges significantly reduced the probability of an inadvertent lineup in the Residual Heat Removal (RHR) system that would drain the reactor vessel, and (2) the boundary conditions of the FSAR evaluations remained unchanged.

PLANT DESIGN CHANGE 88-0188 Plant Design Change 88-0188 was initiated to relocate selected Rod Position Indication (RPI) cables to spare penetration circuits.

This modification restored RPI operability to two control rods without changing the safety function of the penetrations.

This plant design change relocates control rod 46-07 and 10-39 RPI system cables to spare penetration circuits.

The RPI circuits for those rods were found to have open circuit wires in their penetrations.

This modification did not result in a

change to NNV-2 Technical Specifica-tions or involve an unreviewed safety question because:

(1) the safety function of the penetration was not changed, and (2) the boundary condition for the FSAR evaluation was not changed.

2 - 38

2.6.2 LIFTED LEADS ANO JUMPERS The following are summaries of noteworthy modifications made to the plant by the use of lifted leads and jumpers during 1988.

Each modification was evaluated and determined not to represent an unreviewed safety question or require a change to the WNP-2 Technical Specifications.

Electrical Jum er on Refuelin Brid e Cable Lo ic Leads An electrical jumper was installed around the broken control logic leads in the refueling bridge cable that rendered the "over-the-core" interlock in-operable.

The broken leads resulted in a

rod block, thus preventing start-up.

The modification returned to service the Reactor Manual Control System (RMCS) that allowed withdrawal of the control rods for reactor operation.

At the conclusion of R3, when parts were available, the broken cable was replaced.

The installation of this jumper did not involve an unreviewed safety ques-tion or reduce any margin of safety as defined in the WNP-2 Technical Spec-i fications.

Wi th the reactor fully assembled, and the drywell head and shield blocks installed, the interlocks are not required to be functional.

The Technical Specifications require the refueling bridge interlocks be operable only when in the refueling mode.

Since the plant was not in the refueling mode nor relying upon operation of the refueling bridge when the jumper was applied, the margin of safety was not affected.

Lifted Leads on a Main Steam Line Drain Valve Ino erable Status Indication A Bypass and Inoperable Status Indication (BISI) relay was jumpered for the deenergized main steam line drain valve, MS-V-67A, to clear the out-of-ser-vice

alarm, this action allowed possible'dditional alarms to be re-cognized.

The deenergization of the valve causes a BISI alarm, masking any other out-of-service component alarms.

The valve was deenergized and in the shut position.

This relay removal and jumper did not involve an unreviewed safety question or reduce the margin of safety as defined in the WNP-2 Technical Speci-fications because:

(1) the valve was deenergized in the closed po"ition, capable of performing the FSAR analyzed safety function without changing state; (2) the shut valve causes a negligible affect on the reliability of.

normal operating systems resulting in a negligible change in probability of an unplanned transient event; and (3) the lifted relay removes the known and accepted alarm condition, and unmasks potential BISI alarms from other components, reestablishing original the level of status information to the control room.

2 - 39

2.6.2 LIFTED LEADS AND 30MPERS (Continued)

Lifted Leads on a

RHR Shutdown Coolin Return Line Valve Ino erable Status Indication A

Bypass and Inoperable Status Indication (BISI) relay was lifted for a

de-energized cooldown injection

valve, RHR-V-53A, to clear the out-of-service

alarm, allowing possible additional alarms to be recognized.

The deenergiza-tion of the valve causes a

BISI alarm,.

masking any other out-of-service alarms.

The valve was deenergized and in the shut position.

This lifted relay did not involve an unreviewed safety question or reduce the margin of safety as defined in the MNP-2 Technical Specifications because:

(1) the valve was deenergized in the closed

position, capable of performing the FSAR analyzed safety functions without changing state; (2) the shut valve has no affect on the reliability of normal operating systems resulting in no change in the probability of an unplanned transient event; and (3) the lifted relay removes the known and accepted alarm condition, and unmasks potential BISI alarms from other components, reestablishing the necessary level of status information to the control room.

2-40

2.6.3 FSAR ANENONENT EVALUATIONS The following are summaries of changes made to the FSAR which were not ini-tiated as a

result of a

plant modification.

Prior to submitting an FSAR

change, an analysis is performed in accordance with 10CFR50.59 to ensure the proposed modification does not involve an unreviewed safety question.

The following summaries represent changes in system operation, clarification and/or updates of system descriptions, clarification of Supply System posi-tions and, in some

cases, changes to commitments previously made in the FSAR.

Cha ter 6

Containment S ra s

Nodification -

This revision to the FSAR deletes the requirement for a

15 second maximum closure time for the Residual Heat Removal (RHR) system minimum flow valves.

Technical Specifications and allows the two year Valve Position Indication (VPI) program requirements to be satisfied.

In order to satisfy the VPI requirements for stroke and stroke

rate, the open limit switch had to be ad-justed for further opening of the valve.

As a result, the FSAR 15 second maximum closure time could not be met.

However, the valve stroke time is not required per the Technical Specifications since the valve does not receive an isolation signal.

Also, an engineering evaluation determined that

1) the valves travel at the same rate and are within the travel rate design guide-lines (four inches per minute),

2) the valves will be open to the same posi-tion at the same time as measured during Plant Startup

Testing, and

3) the further opening will have a negligible effect because the largest reduction in flow/pressure is caused by three restriction orifices downstream.

Consequen-tly, this modification does not constitute a facility change since component function and purpose are not altered or limited, and component or system reliability is not reduced.

Cha ter 6

Containment S ra s

Modification This modification lowers the Low Pressure Core Spray (LPCS) relief valve setpoints on the LPCS-RV-18 and LPCS-RV-31 from 550 psig and 100 psig to 427 psig and 97 psig, respectively.

Basis for Chan e - This modification was made to ensure adequate overpressure protection on the LPCS pump (LPCS-P-1) suction and discharge lines.

This modification reflects setpoints calculated in the analysis documentation and does not involve an reviewed safety question because the margin to overpres-sure protection of the LPCS piping is increased.

2 41

2.6.3 FSAR AMENOMENT EVALUATIONS (Continued)

A endix B

WNP-2 Res onse to Re ulator Issues Resul tin from TMI-2 Modification This revision changes:

(1) the liquid sample dilutant from 100 ml to 10 ml (Page 8.2-16a);

(2) the sample bottle size from 27 ml to 21 ml (Page 8.2.16b);

and (3) the quarterly operability testing, analysis compar-

ison, personnel

training, and annual drill to reflect the current practices (B.2-16c).

Basis for Chan e - This modification was made to correct sample volume errors and to clarify quarterly operability testing, sample analysis comparison, and training and drill criteria to reflect the actual practices that meet the requirements of THI-2 Section II.B.3 for post-accident sampling, station samples.

Cha ter 7

Safet Related Ois la Information Modification This change adds descriptions of post-accident monitors consis-tent with the as-built plant conditions and corrects inaccuracies.

Basis for Chan e

This change updates the FSAR to accurately reflect WNP-2 completed commitment to R.G 1.97 R2.

An unreviewed safety question was not involved because no revisions were made to the existing system operations and the changes had no effect on the Technical Specification margins.

Cha ter 7

Main Steam Line-Tunnel Hi h Oifferential Tem erature Modification Changes were made to clarify the actual plant configuration and operation of the Hain Steam-Line Tunnel high differential temperature channels.

Basis for Chan e - The changes more accurately describe the actual plant con-figuration.

An unresolved safety question was not involved because:

(1) the revised description of the plant configuration remains within the FSAR bound-ary conditions and evaluations, and (2) the revisions had no effect on the Technical Specification margins.

2 - 42

2.6.3 FSAR ANENOMENT EVALUATIONS (Continued)

Cha ter 11 Solid Maste Mana ement S stem Modification The radwaste processing. contractor was changed to another ven-dor.

The section was revised to reflect current operations using Pacific Nuclear for radwaste processing.

Basis for Chan e -

Changing the radwaste contractor will not significantly alter the processes or methods employed to safely process the radwaste.

The same activities, types and quantities of radwaste are involved as before the contractor change.

This change does not result in a change to the NNP-2 Tech-nical Specification margins and does not involve an unreviewed safety question because:

(1) the processes performed are not significantly difFerent, (2) the radwaste will continue to be handled safely in accordance with 10CFR50.61, and (3) the boundary conditions For the FSAR evaluations and the NNP-2 Technical Specification margins were not changed.

2 - 43

2.6.4 OTHER Included in the Plant Nonconformance Reporting (NCR) process at WNP-2 is the requirement to perform a

10CFR50.59 Evaluation For those NCRs which are dis-positioned as "Use-As-ls,"

"Repair,"

or "Conditional Release."

The specific purpose of the 10CFR50.59 evaluation is to recognize these categories of NCRs as implementing a

change to the facility, thus requiring a

10CFR50.59 evalua-tion.

When a

10CFR50.59 Safety Evaluation is performed, the NCR is reviewed by the Plant Operating Committee and approved by the Plant Manager prior to the equipment being declared operable.

The following is a discussion of plant changes which were made by means of the NCR process during 1988:

NCR 288-050 (Reactor Building Roof Rupture Oue to HVAC Overpressurization Transient) o Problem Oescri tion Rupture of the reactor building roof occurred as a result of a HVAC over-pressurization transient.

Overpressurization resulted from operation of a return outside air fan without associated exhaust air fan in operation due to logic circuit wiring error.

The reactor building roof (secondary containment) was restored to as-built conditions prior to operation, except for installation of the environmental covering.

o Corrective Action The immediate disposition

("Repair" and "Use-As-Is" )

included:

(1) analysis of the release fasteners which concluded the roof. ruptured as

designed, (2) additional compensatory measures to prevent another roof

rupture, and (3) restoration of the roof to satisfy the FSAR defined pro-tective and secondary containment functions.

The environmental covering was not installed on the roof prior to operation of WNP-2 because it does not provide a

protective or secondary containment function

and, as a

result, does not affect secondary containment integrity.

The protective function of the roof of the reactor building is to contain a

High Energy Line Break (HELB) per FSAR Section 6.2.3 (limit is 0.25 psid) and rupture at 0.5 psid per the high wind and tornado design bases (FSAR Section 3.3.2).

An engineering evaluation of the restored roof configuration determined the roof would rupture prior to the 0.5 psid, which is conservative and acceptable, and would 'contain the 0.25 psid HELB.

The strength of the environmental covering was conserva-tively not considered in the failure mechanism of the

roof, but the weight of the covering is considered in the loading of the roof members.

The roofing material does not provide missile protection (FSAR Section 3.5).

A building leak test without the environmental covering satisfied the Technical Specification leakage criteria, i.e.,

less than 2240 CFM at 0.25 inches w.c.

A single Standby Gas Treatment (SGT) train is verified to satisfy the minimum allowable capacity requirements every 18 months.

2-44

2.6.4 OTHER (Continued)

The missing roof covering was considered only as an environmental barrier for the structural material.

Any affects such as corrosion were consid-ered negligible and would not affect the roof rupture characteristics for the period of time the covering was absent.

This is because the release fasteners are beneath the "g" decking, and therefore, were provided some protection from the environment.

The roof covering installation was com-pleted approximately one and a

half months after installation of the roof.

Degradation due to corrosion had negligible affect on the release fasteners and no affect on the

leakage, as the decking joints were caulked.

The lack oF environmental covering on the roof did not result in a change to the

'l<NP-2 Technical Specifications or involve an unreviewed safety question because:

(1) secondary containment integrity had been verified acceptable by testing per the Technical Specification criteria, (2) the margin of safety was maintained without the roof covering, and (3) the boundary conditions for the FSAR evaluations were not changed.

MCR 287-326 (Potential Flooding of Diesel Generators from Automatic Fire Protection Sprinklers) o Problem Oescri tion Actuation of all fire protection sprinklers in the High Pressure Core Spray (HPCS) diesel generator room from a fire could potentially flood into the fuel transfer areas for the HPCS and the two standby diesel gen-erator

engines, resulting in loss of the fuel transfer pumps.

Assuming loss of the HPCS diesel engine from fire, the two standby diesel genera-tors would be lost following consumption of the, fuel in the day tanks.

This event could potentially result in a

common mode Failure of all three diesel generators.

A second postulated common mode failure of the standby diesel generators consists of a fire in the OG-2 room.

This would be Followed by actuation of the sprinklers resulting in possibly oil and water flooding into the common corridor between the diesel generator and reactor building where Division 1

and 2 conduits are installed.

A fire in the corridor could damage the Division 1

cable and result in loss of the safe shutdown capability.

o Corrective Action The immediate disposition ("Repair" ) included the following:

(1) install additional curbing at the north exit to all three diesel generator rooms sufficient to preclude flooding in the corridor area; (2) cut slots in each south door of the diesel generator rooms to drain accumulated water to the outside area to prevent flooding of the fuel transfer

pumps, and (3) diversion dikes will be placed outside the doors to direct the flow away from the building and air intake areas.

2 45

2.6.4 OTHER (Continued)

This change is designed to eliminate a

common mode failure of the standby emergency diesel generators by eliminating the potential For transfer pump flooding through the addition of the curbing and slots in the south doors to the diesel generator rooms.

The second postulated event goes beyond the design bases for the plant, and therefore, is not considered a

credible event.

However, it should be noted that the curbing would also prevent flooding in the corridor, further reducing the already very un-likely second postulated event.

This increases the reliability of the standby diesel generators' metal bar was

'.nstalled across the vertical opening in the south doors to prevent unauthorized persons from entering the diesel generator rooms.

Flappers were installed across the openings with magnetic latches to prevent entry of rodents and varmints.

Installation of the curbing and slots in the doors did not result in a

change to the WNP-2 Technical Specifications or involve an unreviewed safety question because:

(1) a common mode Failure of the standby diesel generators was eliminated increasing their reliability, (2) the margins of safety in the Technical Specifications were unchanged, and (3) the boundary conditions in the FSAR evaluations were not changed.

NCR 288-494 (Lack of Qualification Testing on HPCS Relay Seal-In Unit) o Problem Oescri tion A seal-in unit was installed for a

High Pressure Core Spray (HPCS) relay (HPCS-RLY-5051/A) without seismic qualification testing.

Qualification testing had not been completed on a

random sampling of the same lot of seal-in units prior to installation oF this seal-in unit.

The seal-in unit ensures a constant HPCS relay trip signal until the manual reset is actuated.

o Corrective Action The NCR immediate disposition of "Use-As-Is" for this seal-in unit was justified for the following reasons:

(1) this seal-in unit design was identical to the one it replaced, and therefore, was expected to pass the seismic qualification testing, and (2) the probability of Failure From a

postulated seismic event is low because the unit is designed for a high vibration environment.

Use of the seal-in unit without seismic qualification testing did not result in a

change to the WNP-2 Technical Specifications or involve an unreviewed safety question because:

(1) the margin of safety provided in the Technical Specifications remained unchanged, and (2) the boundary conditions for the fSAR evaluations were not changed.

2-46

2.6.4 OTHER (Continued)

NCR 288-538

( Inoperable Fuel Oil Day Tank Transfer Switch) o Problem Descri tion The transfer switch on the top of the fuel oil day tank For the standby diesel generators was bent against the switch

cover, making the switch inoperable.

Although the inoperable level switch would prevent automatic transfer of Fuel oil from the storage tank to the day tank, the low and high level alarms on the day tank would alert operators to provide remote manual control of the transfer pump.

It appeared that bending of the switch was caused by using it as a hand-hold to gain access to the top of the tank.

o Corrective Action The immediate disposition ("Repair" )

was to elongate the hole in the top of the switch cover to allow the cover to be offset, and

thus, prevent bind'.ng of the switch against the cover.

The switch is scheduled to be replaced.

Also, permanent and easy access to the top of the tank will be provided to eliminate the need to use the switch as a hand-hold.

This repair did not result in a

change to the MNP-2 Technical Specifica-tions or involve an unreviewed safety question because:

(1) operability of the switch was restored, (2) level alarms and remote manual control of the transfer pump provides added assurance the fuel oil day tank would have fuel without overflow under accident conditions, and (3) the bound-ary conditions in the FSAR evaluation were not changed.

NCR 288-541 (Seat Replacement of Two Containment Exhaust Purge Valves with Unqualified immaterial) o Problem Descri tion The valve disk seats for two Containment Exhaust Purge (CEP) valves (CEP-V-1A CEP-V-2A) were replaced November 21, 1985 with a nitrile

rubber, tradename Buna-N, instead of the Viton rubber seal material authorized by the CVI data.

Although these two valves are physically located in the reactor building (outside of containment).

they can potentially experience a

containment environment/accident profile inter-nally since they are both located on a 30-inch purge exhaust line that is near the top of the containment.

o Corrective, Action An analysis was performed to estimate the worst case accident conditions at the valves.

The temperature and radiation exposure results of the analysis were compared to the material test data.

The test data demon-strated the Buna-N seat material has a service life of six years includ-ing the ability to survive the worst case LOCA.

2 - 47

2.6.4 OTHER (Continued)

These valves are subjected to periodic technical surveillance require-ments.

The test surveillance history for the three years of service demonstrated they are functioning as required with the nitrile material.

The seats in these

valves, as well as all other like valves, are expected to be replaced with a

nitrile material within 1989.

Therefore, based upon the analysis and test

data, the nitrile material is qualifiable for use in the subject valves.

The use of Buna-N rubber instead of Viton did not result in change to the WNP-2 Technical Specifications or involve an unreviewed safety question because:

(1) the nitrile material is qualifiable for use as seat mat-erial in the subject

valves, (2) the valve function, performance require-

ments, and design was not

changed, (3) the margin of safety provided in the Technical Specifications remain unchanged, and (4) the boundary con-ditions for the FSAR evaluations were not changed.

NCR 288-403 (One Train of HVAC Remote Air Intake Valves Disabled and Blocked Open) o Problem Descri tion A single failure would cause the Control Room Heating and Ventilation (HVAC) System to operate in the recirculation mode during an emergency condition.

An Engineering Evaluation

Report, (Design and Operating Deficiencies in Control Room Emergency Ventilation

Systems, gE802) was written by the NRC OfFice For Analysis and Evaluation of Operational Data (AEOD) identifying this generic problem.

During a

Loss of Coolant Ac-cident (LOCA),

the normal fresh air intake for the Control Room HVAC would be isolated and two remote air intake lines would be opened.

Each remote air intake line has two isolation valves.

One valve on each line is powered by Division 1

and 2.

A single failure (hot short was assumed as the failure since the valves are fail open) in a

power division could cause a

valve in each remote air intake line to isolate.

This would result in a neutral pressure condition which would increase the inleakage to the control room, which is an unanalyzed condition.

o Corrective Action The immediate corrective action ("Repair" )

was to disable and block open the west remote air intake valves to the Control Room

HVAC, i.e ~

WOA-V-51A and WOA-V-52A.

The motor operators on the four remote air intake valves were removed to eliminate electrically induced single failure potentials.

One of two purge valves on each intake line were deenergized open to provide more reliable radiation monitoring in the event oF the above described failure.

2-48

2.6.4 OTHER (Continued)

This eliminates the single failure vulnerability of the control room remote air intake system.

Both intake paths have Division 1

and 2 oper-ated valves.

Nithout the corrective

action, a

hot short failure in either division would cause a

loss of both remote air intake paths post-accident.

Therefore, the reliability of the Control Room HVAC is significantly increased following a LOCA event.

Removal of the motor operators to the four remote air intake

valves, blocking open the valves in one remote air intake line, and deenergizing the two intake line* purge valves did not result in a

change to the MNP-2 Technical Specifications or involve an unreviewed safety question because:

(1) the reliability oF the remote air intake system Following a LOCA event was increased; (2) the operation of the radiation monitors or their ability to detect a

plume over a

remote air intake was not impact-ed, (3) the margins of safety in the Technical Specifications were un-

changed, and (4) the boundary conditions used in the FSAR evaluations were not changed.

NCR 288-471 (ECCS Relief Valve Setpoints Exceed Piping Design Pressure) o Problem Uescri tion A

Low Pressure Core Spray (LPCS) relief valve (LPCS-RV-31) setpoint was determined to be set higher than the pump suction piping design pres-sure.

Determination of the wrong setpoint neglected forty feet of static head on the discharge side of the valve.

The calculation error was discovered during a

SSF1 review of the design data base.

o Corrective Action The immediate corrective action

("Use-As-Is" )

was to rely on operational evaluation and actions necessary to prevent an unnecessary pressurization

event, which includes opening the LPCS pump suction valve LPCS-V-1 when deemed necessary.

The LPCS-RY-31 relief function is required only when the LPCS-V-1 valve is closed.

The mechanism for pressurization comes from high to low pressure interface valve leakage.

There is no Design Basis Accident (DBA) in the FSAR requiring LPCS-V-1 closure.

The valve does provide isolation capability, accommodating a

single active component failure and is primarily For long term leakage control.

However, the bounding Emergency Core Cooling System (ECCS) leakage event determined the largest pump room is filled and concludes that adequate NPSH is available for the remaining ECCS pumps.

The ECCS pump room flooding instrumentation will alert the control room of a poten-tial flooding condition,

however, the evaluation does not take credit for isolation, i.e.,

closure of LPCS-V-1.

The most probable pressure bound-ary failure identiFied for the ECC Systems has been identified as the pump shaft mechanical seal.

Valve LPCS-V-1 will be able to be closed given the

failure, with less concern for piping protection due to the relief provided by the leak.

2 - 49

2.6.4 OTHER (Continued)

The potential for an overpressure condition of approximately 14 psig does not appear from preliminary evaluations to represent a pipe failure con-dition.

In any

event, the ECCS pump room flooding analysis bounds a

suction piping failure, and therefore, the accident is evaluated in the FSAR.

As a result of this corrective action, the WNP-2 Technical Specifications were not changed and an unreviewed safety question was not involved because:

(1) the margin of safety in alerting, the control room of either a

potential For or an existing intersystem LOCA was not

changed, (2) failure of the LPCS pump suction

',ine is bounded by FSAR evaluations, and (3) the boundary conditions for the FSAR evaluations were not changed.

NCR 288-138 (Disabling Corridor Fan in Diesel Generator Building) o Problem Descri tion Under certain emergency conditions, operation of a corridor fan in the Diesel Generator

Building, DEA-FN-51, could result in an unmonitored radiological effluent release, During some postulated post-accident con-ditions, this fan could pull air from the Turbine Building and exhaust it directly to atmosphere.

The most severe radiological accident in the Turbine Building is a main steam line break with a source term concentra-tion of 3.312E-4 microCi/cc.

The above concentration is within the range

- specified in Regulatory Guide 1.97 for which effluent monitoring is required.

o Corrective Action The immediate corrective action ("Use-As-Is" ) included:

(1) an engineer-ing assessment which determined that OEA-FN-51 was not required for cool-ing during normal or emergency conditions, (2) disabling the fan by pulling its power fuses, and (3) closing the back draft damper.

Further corrective actions will include:

(1) removal of the fan OEA-FN-51 and its accessories, (2) sealing the opening created by the removal of the

fan, and (3) a design review to ensure that no other potential violations of Regulatory Guide 1.97 due to unmonitored leakage paths exist.

Disabling the corridor fan and closing the back draft damper did not result in a

change to the WNP-2 Technical Specifications or involve an unreviewed safety question because:

(1) a potentially unmonitored, un-filtered radiological release path was eliminated, (2) the margins of safety in the Technical Specifications were unchanged, and (3) the bound-ary conditions used in the FSAR evaluations were not changed.

2 50

2.6.4 OTHER (Continued)

NCR 288-389 (Nozzle Ring Setscrew in MSRV Exceed Oesign Tolerances) o Problem Oescri tion The nozzle ring setscrews manufactured for the Main Steam Safety Relief Valves (MSRV) did not meet dimensional tolerances allowed by design.

A ne~'etscrew was designed to reduce the failure rate by reducing the thermally induced

loads, minimizing stress

rises, and increasing the strength of the setscrew.

o Corrective Action The immediate corrective action

("Use-As-Is" )

was to use the as-manufac-tured setscrews because the as-built configuration is acceptable.

The tolerances specified originally were based upon perceived easily achiev-able tolerances which were much more precise than necessary.

The as-built dimensions exceeded the specified allowable tolerances but were within acceptable tolerances for the intended application.

Using the setscrews with the's-built dimensions which expanded the specified tolerances did not result in a

change to the NNP-2 Technical Specifications or involve an unreviewed safety question because:

(1) the as-built setscrews do not affect the relief valve setpoints, (2) the margins of safety in the Technical Specifications were unchanged, and (3)

.he boundary conditions used in the FSAR evaluations were not changed.

NCR 288-395 (Use of Original Setscrew Oesign for Main Steam Relief Valve) o Problem Oescri tion The new nozzle ring setscrews for the Main Steam Relief Valve (MSRV) with the tapered shank could not be installed in one of the MSRVs (MS-RV-2B) due to proximity of other plant equipment.

The improvements to the new setscrew included reducing the length to minimize thermally induced load-ing and tapering the shank to eliminate stress rises in the area where previous failures had occurred.

o Corrective Action To allow installation into MS-RV-2B, the tapered shank on the new set-screws was machined down to the original straight shank designs A curved radius was machined at the interface of the smaller straight shank diam-eter and the larger diameter portion of the setscrew to minimize stress risers.

Consequently, the improvements made in the new setscrew were retained in the modified setscrew.

2-51

2.6.4 OTHER (Continued)

Using the modified setscrews did not result in a

change to the WNP-2 Technical Specifications or involve an unreviewed safety question because:

(l) the modified setscrews retained the new setscrew design improvements, (2) the margins of safety in the Technical Specifications were unchanged, and (3) the boundary conditions used in the FSAR evalua-tions were not changed.

2-52

2.7 PLANT TESTS ANO EXPERIHENTS Federal Regulations (10CFR50.59) and the Facility Operating License (NPF-21) allow tests or experiments to be conducted which are not described in the Safety Ana 1ys i s Report without prior Nuc 1 ear Regulatory Commission (NRC) approval unless the proposed

change, test or experiment involves a

change in the Technical Specifications incorporated in the license or an unreviewed safety question.

Prior to performing any test or experiment, a safety evaluation was performed in accordance with 10CFR50.59.

All such evaluations were reviewed and ap-proved by the Plant Operations Committee prior to the performance of the tests.

It was concluded from the reviews that the tests performed in 1988 did not (1) place the unit in an unanalyzed configuration or condition not bounded by design

basis, or (2) perform an operation not described in the FSAR which could have an adverse affect on safety-related equipment or systems.

The fol-lowing are summaries of tests performed in a

mode of operation not described in the FSAR.

It should be noted,

however, that the abnormal mode of operation did not place the unit in an unanalyzed condition.

PPH 8.3.94 5

PPH 8.3.10.9 ATWS-ARI Lo ic Acce tance Test This procedure was prepared to verify that the Anticipated Transient Without Scram Alternate Rod Insertion (ATWS-ARI) system installed at WNP-2 meets all of the functional design requirements of the ATWS Rule described in 10CFR50.62 as applicable to boiling water reactors.

This logic test verified appropriate operation of the special eight ARI scram air header bleed valves.

Loss of air pressure in the scram air header results in insertion of all control rods from the control rod drive accumulators and reactor pressure.

The test verified the special valves opened on low reactor level signal or high reactor pressure

signal, independent of the Reactor Protection System (RPS).

Also, the accep-tance criteria that the rods initiate motion within 15 seconds and all rods are fully inserted within 25 seconds from the time of the event was met.

PPH 8.3.90 and 8.3.96 Standb Oiesel En ine Governor Control S stem Prep erational Test To provide increased reliability of the standby diesel generators, new gov-ernor control systems were installed to allow slow start for testing and runback to idle under no load accident conditions.

A preoperational test was performed to verify operational capability to runback engine to idle speed under no load conditions preceded by a

demand signal and automatic return to full speed on loss of offsite power indication.

The test also demonstrated the slow start capability, i.e., start and run engine at idle speed for a pre-determined warm up period followed by ramp up to full test speed.

2-53

2.8 PLANT PROCEOURE CHANGES Procedures described in the HNP-2 Final Safety Analysis Report (FSAR) are developed and used by the Plant Operating Staff and various offsite support organizations.

In 1988, the Plant Staff made changes to procedures in accor-dance with 10CFR50.59 and concluded that none of the changes involved unre-viewed safety questions.

Changes to procedures were generally either administrative or technical in nature.

Administrative revisions consisted of title, organizational and editorial changes; while technical changes were the result of system or com-

,ponent modifications, or improvements in the procedural process.

In all instances, a

safety evaluation was conducted for each change in accordance with 10CFR50.59.

All such evaluations were reviewed and approved by the Plant Operating Committee and are available For audit.

It was concluded from the reviews that the probability of occurrence or consequences of an accident or equipment malfunction was not increased, there was no reduction in any plant safety

margins, and the possibility of an accident or malfunction not previ-ously evaluated was not increased.

The following is a

discussion of significant plant procedure changes and development during 1988:

1.

PPM 1.1.7 "Restart Evaluation Process" This procedure was developed during the year and provides a process for evaluating the readiness of the plant for startup and return to power following a refueling outage of predefined scope.

The process evaluates deviations from the planned outage scope and new work created during the outage.

This

process, or portions of this process, can also be used at the discretion of the Plant Manager following any major outage.

The restart process 'ollowing a

reactor scram is covered separately by PPM 1.3.5, "Reactor Trip and Recovery."

PPM 1.2.6 "Biennial Review of Plant Procedures" The purpose of this procedure is to describe the review mechanism and provide a reviewer's guide for the biennial review of plant procedures.

The primary improvement to the procedure was the addition of a procedure reviewer's guide.

The guide provides criteria to be used as an aide in performing a quality review of plant procedures.

A separate reviewers guide is included for each volume of the Plant Procedures Manual.

2 54

2.8 PLANT PROCEOURE CHANGES (Continued) 3.

PPM 1.3.12 "Plant Problems Problem Evaluation Re uest" The purpose of this procedure is to provide instructions for the iden-tification and documentation of plant problems.

This procedure was completely re-written

and, used in conjunction with PPM 1.3.15, "Plant Problems Plant Problem Reports,"

provides the basis for documenting

-and resolving both hardware and software problems, at WNP-2.

The major change to the procedure is the development of the following four new processes for problem identification and documentation:

o Problem Evaluation Re uest PER A document, the purpose of which is to establish a controlled method to formally communicate the existence of a plant problem to plant management for action.

This form can be initiated by anyone knowl-edgeable of an existing or potential plant problem which requires resolution.

o Nonconformance Re ort NCR A document, the purpose of which is to disposition all reportable, potentially reportable or safety significant plant problems.

This form is initiated by the plant supervisory* staff so designated by the Plant Manager.

o Material Oeficienc Re ort MOR A document, the purpose of which is to disposition all non-report-

able, non-safety significant plant problems which directly relate to

material, equipment or components (both installed and non-installed).

This form is initiated by those members of the Plant supervisory staff or other personnel so designated by the Plant Manager.

o Plant Oeficienc Re ort PO~R A document, the purpose of which is to disposition all non-report-

able, non-safety significant plant problems which are not disposi-tioned by an NCR or MOR.

This Form is initiated by those members of the Plant supervisory staff so designated by the Plant Manager.

2-55

2.8 PLANT PROCEDURE CHANGES (Continued) 4.

PPM 1.3.15 "Plant Problems - Plant Problem Re orts" As previously discussed, this procedure and PPM 1.3.12 form a

new framework for documenting and resolving both hardware and software prob-lems at WNP-2.

The procedure was developed during the year and provides instructions for the disposition and documentation of plant problems.

Feedback to plant personnel of Lessons Learned from inhouse experience is also provided as part of this procedure.

5.

PPM 1.3.19 "Housekee in The purpose of this procedure is to provide guidelines and responsibil-ities to 'be used to control the cleanliness of WNP-2 facilities.

The primary improvement in this procedure was to expand the responsibil-ities of the Floor/Area Coordinators in the areas of material defi-

ciencies, industrial safety

hazards, cleanliness and housekeeping deficiencies, and radiological protection deficiencies.

6.

PPM 1.3.48 "Root Cause Anal sis" The purpose of this procedure is to establish the process and provide instructions for conducting formal analysis of plant events/problems.

The root cause analysis procedure serves to:

o Improve plant availability by preventing repetitive equipment breakdown through identification of root cause(s) for such failures, and implementation of corrective action which mi'nimizes the prob-ability of recurrence.

o Provide criteria For evaluation of plant problems such that the level of the problem analysis can be appropriately, scaled to the level of the event.

0 Establish a

set of organized questions which supplement sound technical judgment in the analysis of plant problems.

This concept allows personnel at all levels of the plant organization to partic-ipate in implementation of the process.

This is a

new procedure developed during the year to formally document the root cause analysis program and it is used in conjunction with PPMs 1.3.12 and 1.3.15 (discussed previously).

2-56

2.8 PLANT PROCEDURE CHANGES (Continued) 7.

PPM 1.3.49 "Work Control Center Grou This procedure was developed during the year and describes the duties of the Work Control Center Group (WCCG) and its interfaces with other plant organizations.

The duties include review of all regularly scheduled Maintenance Work Requests (MWRs) to evaluate the need for a

Clearance Order (CO).

The WCCG also reviews all Preventive Maintenance (PMs) for the need of a Clearance Order.

These reviews are performed prior to such work being sent to the Control Room and help in determining the safe configuration of the plant to support necessary maintenance.

The WCCG consists of,. but is not limited to, operations representatives (Senior Reactor

Operator, Reactor Operator and equipment operator) and maintenance representatives (Electrical and Mechanical).

8.

PPM 1.9.1 "Plant Safet Pro ram" The purpose of this procedure is to outline the WNP-2 Industrial Safety and Fire Protection Program and define the associated responsibilities.

The primary changes to this procedure were adding specific responsibil-ities of the Plant Safety Marshall and the responsibility for management to perform quarterly reviews of their supervisor's work areas.

The Plant Safety Marshall has the authority to terminate any work which does not meet Supply System Safety requirements, 2-57

2.9 REACTOR COOLANT SPECIFIC ACTIVITY LEVELS This section contains information relative to reactor coolant cumulative iodine levels, iodine spikes and specific activity of all isotopes other than iodine.

The specific activity of the primary coolant was significantly less than 0.2 microcuries per gram dose equivalent I-131 as set forth in WNP-2 Technical Specification LCO 3/4.4.5 and paragraph 6.9.1.5.c.,

(see 1988 cumulative iodine

graph, attached).

The specific activity of the primary coolant was routinely sampled and analyzed as required by WNP-2 Technical Specifications, and was in all cases, less than or equal to 100/E microcuries per gram.

A graph showing cumulative iodine dose equivalent for the calendar year 1988 is provided for reference and information only.

Refer to Section 2.5 of this report for the discussion of the fuel pin failure that caused the iodine trend prior to the 1988 refueling outage.

2 58

WNP-2 Reactor Dose Equivalent iodine 1O0

120EQ PRI 8 1O-1 10 -2 E

O 10 3 1O-4 10 5 10.6 Jan 1 Mar 1 Apr 30 Jun 29 Aug 28 Oct 2?

Dec 26 1988 890049M

2.10 REPORT OF DIESEL GENERATOR FAILURES This section contains information pertaining to the reporting of diesel gen-erator

failures, valid and

nonvalid, in accordance with the requirements of WMP-2 Technical Specification 4.8.1.1.3.

This report provides the information required by Regulatory Position C.3. b of. Regulatory Guide 1. 108, Revision 1,

August 1977.

2 - 60

E

2.10 REPORT OF DIESEL GENERATOR FAILURES Diesel Generator Failure Number One l.

Identity of diesel generator unit and date of failure:

Division One Emergency Diesel Generator Nay 22, 1988 2.

Number designation of failure in the last 100 valid tests:

Not applicable.

This was a nonvalid failure.

The unit was inoper-able for maintenance and design modification.

3.

Cause of failure:

The direct cause of the failure -was an open circuit in the relay K-14A operating coil for the diesel speed control circuit associated with the newly installed idle speed modification.

The failure resulted in voltage regulator shutdown which caused generator output to fail.

The cause of the relay failure was inadequate design.

The relay was an Alternating Current (AC) relay which was installed in a Direct Current (DC) circuit.

This resulted in overheating and pre-mature failure of the coil.

Corrective measures taken:

The AC rated relay was replaced with the correct DC rated relay.

Both Division One and Division Two idle speed modification designs were reviewed for similar errors.

5.

Length of time diesel generator unit was unavailable.

Not applicable for this nonvalid failure.

6.

Current surveillance test interval (after the failure):

Thirty-one days 7.

Verification of test interval:

The surveillance test interval of thirty-one days is in conformance with Regulatory Guide 1.108 position C.2.d.

2 -

61

2.10 REpORT OF DIESEL GENERATOR FAILURES (Continued}

Di es el Genera tor Fa i 1 ure Number Two l.

Identity of diesel generator unit and date of failure:

Division Two Emergency Diesel Generator June 6,

1988 2.

Number designation of failure in the last 100 valid tests:

This was the first failure in the last 100 valid tests.

3.

Cause of failure:

The direct cause of the failure was a "relay race" created by inad-equate circuit design for the generator exciter control circuit.

This circuitry had been recently changed by the idle speed modifica-tion installed during the 1988 plant refueling and maintenance outage.

The "relay race",

rapid operation of the LR relay operating

coil, caused overheating and open circuit.

This resulted in shut-down of the generator.

4.

Corrective measures taken:

The newly installed design modification was reviewed and changed to eliminate the "relay race" in both Division One and Division Two Emergency Diesel Generators.

5.

Length of time diesel generator unit was unavailable:

Thirty-eight and one half hours.

6.

Current surveillance test interval (after this failure):

Thirty-one days 7.

Verification of test interval:

The surveillance test interval of thirty-one days is in conformance with Regulatory Guide 1.108 position C.2.d.

2-62

2.10 REPORT OF DIESEL GENERATOR FAILURES (Continued)

Diesel Generator Failure Number Three 1;

Identity of diesel generator unit and date of failure:

High Pressure Core Spray (Division Three)

Emergency Diesel Generator September 3,

1988 2.

Number designation of failure in the last 100 valid tests:

Not applicable.

This was a

nonvalid failure because it resulted from operator error.

3.

Cause of failure:

The cause of the test failure was the operator failing to assume electrical load rapidly enough to prevent actuation of the reverse power protective relay during initial loading of the unit.

4.

Corrective measures taken:

The operatirig procedures were modified to add guidance to preclude inadvertent reverse power trips during initial loading of the diesel generators.

5.

Length of time the diesel generator unit was unavailable:

Not applicable for this nonvalid failure.

6.

Current surveillance test interval (after this failure):

Thirty-.one days 7.

Verification of test interval:

The survei'ilance test interval of thirty-one days is in conformance with Regulatory Guide 1.108 position C.2.d.

2 63