ML17289B186

Annual Operating Rept,1992. W/930301 Ltr

ML17289B186
Person / Time
Site:	Columbia
Issue date:	12/31/1992
From:	John Baker WASHINGTON PUBLIC POWER SUPPLY SYSTEM
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
GO2-93-048, GO2-93-48, NUDOCS 9303090004
Download: ML17289B186 (81)

Text

ACCELERANT DOCUMENT DISTR~~VTION SYSTEM ACCESSION NBR:9303090004 FACIL:50-397 WPPSS DOC.DATE: ~~~ NOTARIZED: NO Nuclear Project, Unit 2, Washington Public Powe DOCKET 05000397 AUTH. NAME AUTHOR AFFILIATXON BAKERgJ.W. Washington Public Power Supply System RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"Annual Operating Rept,1992." /930301 tr.

DISTRIBUTION CODE: ZE47D COPIES RECEIVED:LTR TITLE: SAIC Contract NRC-82-130 Correspondence7Report/etc.

) ENCL 2 BISE:

D NOTES:

RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD5 PD 1 0 CLIFFORD,J 2 2 INTERNAL: ACRS 6 6 AEOD/DOA 1 1 EO /DS TPAB 1 1 NRR/DRCH/HHFB 1 1 R G FILE 02 1 1 RGN5 FILE 01 1 1 EXTERNAL: NRC PDR 1 1 NSIC 1 1 NOTE TO ALL"RIDS" RECIPIENTS:

I'LEASE HELP US TO REDUCE WASTE! CONTACIFIE 1)UCUMEN'! CON'I'I'OL D!aV, ROOM Pl-37 (EXT. 504-2065) TO ELIMINATEYOUR NAME Flk')45 DIS VleiDIJTIO'4 LISTS FOR DOCUMENTS YOU DON'T NEED!

TOTAL NUMBER OF COPIES REQUIRED: LTTR 16 ENCL 15 r

I 1

WASHINGTON PUBLIC POWER SUPPLY SYSTEM P.O. Bec968 ~ 3000Geotge Wasbfngton Way ~ Rtcbtand, Wasbtngton 99352<968 ~ (509)372-5000 March 1, 1993 G02-93-048 Docket No. 50-397 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555 Gentlemen:

Subject:

WNP-2, OPERATING LICENSE NPF-21 ANNUALOPERATING REPORT 1992

References:

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 Operation Information Appendix A In accordance with the above listed references, the Supply System hereby submits the Annual Operating Report for calendar year 1992. Should you have any questions or comments, please contact Mr. A. G. Hosier, Manager, WNP-2 Licensing.

Sincerely,

. W. Baker WNP-2 Plant Manager (Mail Drop 927M)

Enclosure CC: Mr. J. B. Martin, NRC - Region V Mr. D. L. Williams, BPA (MD 399)

Mr. R. F. Mazurkiewicz, BPA (MD 399)

NRC Resident Inspector (MD 901A) 080021 9303090004 92i231 PDR ADOCK 05000397 R PDR

t t WASHINGTON NUCLEAR PLANT NO. 2 ANNUAL OPERATING REPORT 1992 DOCKET NO. 50-397 FACILITY OPERATING LICENSE NO. NPF-21 Washington Public Power Supply System 3000 George Washington Way Richland, Washington 99352

TABLE OF CONTENTS

1.0 INTRODUCTION

1.1 1992 WNP-2 Load Profile 1.2 Reactor Coolant Specific Activity Levels 2.0 REPORTS 2.1 Annual Personnel Exposure and Monitoring Report 2.2 Main Steam Line Safety/Relief Valve Challenges 2.3 'ummary of Plant Operations 2.4 Significant Corrective Maintenance Performed on Safety-Related Equipment 2.5 Fuel Performance 2.6 10CFR50.59 Changes, Tests and Experiments 2.6.1 Plant Modifications 2.6.2 Temporary Modifications/Instrument Setpoint Changes 2.6.3 FSAR Changes 2.6.4 Problem Evaluations 2.6.5 Plant Tests and Experiments 2.6.6 Plant Procedure Changes 2.6.7 Fire Protection Program Changes 2.7 Diesel Generator Failures

The 1992 Annual Operating Report of Washington Public Power Supply System Plant Number 2 (WNP-2) is submitted pursuant to the, requirements of Federal Regulations and Facility Operating License NPF-21. Plant WNP-2 is a 3323 MWt, BWR-5, which began operation on December 13, 1984.

During January 1992 new monthly records were set for electricity generation and plant capacity factor when the plant ran, on average, at 100 percent power. On February 25, 1992 the plant was shutdown due to problems identified in the Containment Atmosphere Control (CAC) System. From an engineering analysis, determined that drain lines associated with the system were it was required to be modif ied to ensure the lines would remove water formed in the hydrogen recombiners. Following modification efforts and a final series of tests, the plant resumed full power operation on March 19, 1992.

On April 18, 1992 the plant was shutdown for the annual maintenance and refueling outage. In the remaining months of the year following the outage, the plant experienced three forced shutdowns due to 1) the loss of the "B" phase signal from a 500KV transformer potential device, 2) high drywell leakage, 3) core power oscillations of 20 percent power during preparation to change the Reactor Recirculation (RRC) System pumps to high-speed (60Hz) operation.

During 1992 there were several examples of major accomplishments which required significant effort on the part of Supply System personnel to complete. The following is a summary of those efforts.

The seventh refueling outage was successfully completed and significant activities included:

~ Replacement of the low-pressure Main Turbine Rotors (this was the culmination of a three-year, $ 30 million project that will reduce turbine maintenance and increase electrical output by an additional 15-to-20 megawatts).

~ Off-loading of all 764 fuel assemblies and draining of the vessel to allow for inspection of reactor components and chemical decontamination.

~ Chemical decontamination of the Reactor Recirculation (RRC)

System.

~ Rebuilding 30 of the Control Rod Drive Mechanisms.

~ Nondestructive examination of Main Condenser tubes.

The 1992 capacity factors, based on net electrical energy output are listed below.

Month Ca acit Factor January 100.18 February 78.84 March 37.34 April* 55.16 June**

July 25.68 August 37.01 September 95.78 October 99.82 November 86.91 December 102. 5

.Overall 59. 73

• Started Maintenance and Refueling Outage

• • Ended Maintenance and Refueling Outage NOTE: Capacity factors for 1992 were based on a Maximum Dependable Capacity (MDC) of 1085 MWe. (The MDC was revised to 1112 MWe in January 1993.)

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1 2 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, and is reported in accordance with Technical Specification paragraph 6.9.1.5.c.

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. In addition, as shown below, the specific activity of the primary coolant was routinely sampled and was, in all cases, less than 100/E-bar microcuries per gram.

NASH. PUBLIC PONER SUPPLY SYSTEM UCi/gm NNP-2

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2.0 REPORTS The reports provided in this section meet the requirements of Federal Regulations and the NNP-2 Operating License. They cover the requirements of the WNP-2 Technical Specifications, Sections 6.9.1.4 and 6.9.1.5 and provide the information specified by Regulatory Guide 1.16, "Reporting of Operating Information." In addition, Section 2.6 provides the information required by 10CFR50.59, "Changes, Tests, and Experiments."

2.1 ANNUAL PERSONNEL EXPOSURE AND MONITORING REPORT The information provided in this section of the report is required by the WNP-2 Technical Specifications, Section 6.9.1.5a, and Regulatory Guide 1.16, Revision 4. These values are estimated doses for the listed activities based on pocket dosimetry readings.

WASHINGTON PUBLIC POWER SUPPLY SYSTKH RER 020 RADIATION EXPOSURE RECORDS 01/26/93 10i51 WORK AND JOB FUNCTION REPORT / 1 ~ 16 APPENDIX A NUCLEAR PLANT HO ~ 2 REPORT FOR CALENDAR YEAR 1992 NUMBER OF PERSOMS RECEIVING OVER 100 NREM TOTAL liAN REH STATION UTILITY CONTRACTORS STATION UTILITY CONTRACTORS EMPLOYEES EMPLOYEES AND OTHERS EMPLOYEES EMPLOYEES AND OTHERS OPERATIONS 6 SURVEILLANCE MAINTENANCE PERSONNEL 2 '99 0 F 000 1 ~ 630 3o310 0 ~ 000 1 ~ 185 Ieh29 0.000 OPERATING PERSONNEL EIILJJLJJBSICSWERSOIINE~04 SUPERVISORY PERSONNEL 1 ~ 419

~M 0F 000 0 F 000 0 '00 1 ~ 556 0 '00 aa 0 F 000 oao 0 000 0 ~ 000 0 ~ 100 ENCINEERING PERSONNEL 2e079 3 '72 2e327 0 ~ 572 1.400 0 '45 ROUTINE MAINTENANCE MAINTENANCE PERSONNEL 212 '3S 4 '44 374+653 165 +769 1 ~ 947 230 ~ 415 OPERATINC PERSONNEL 40+675 F 049 j 0 F 000 40+635 0 '35 0 F 000 tN SUPERVISORY PERSONNEL 21 ~ 337 1 ~ 000 2+631 7 ~ 016 0 '03 0 '05 ENGINEERING PERSONNEL 28+515 34 '44 62 '59 11@092 1 1 ~ 067 3S ~ 143 INSKRVICE INSPECTION MAINTENANCE PERSONNEL Oe361, Oo120 ir 2.322 0 '95 0 '95 I a 227 OPERATINC PERSONNEL 0 F 000 -.' F 000 J

'e000 0 ~ 000 0 F 000 0 F 000 SUPERVISORY PERSONNEL 0 '45 0 ~ 000 0 F 000 0 '70 0 F 000 0 F 000 ENGINEERING PERSONNEL 0+203 0 '77 0 ~ 176 0 ~ 1$ 5 0 '91 0 ~ 110 SPECIAL MAINTENANCE NAINTENANCE PERSONNEL ST 705 0 '29 12 ~ 056 5 '90 0 '20 4 '58 OPERATIMC PERSOMNEL 0 '44 0 F 000 0 F 000 0 '62 0 F 000 0 F 000 tS SUPERVISORY PERSONNEL 0 '91 0 ~ 000 0 F 000 0 '22 0 F 000 Oe000 ENGINEERING PERSONNEL I ~ 451 1 ~ 343 0 '04 Oeh$ 0 0.587 0 '62 WASTE PROCESSINC MAINTENANCE PER8ONNEL 2 '58 0 '38 2+651 2 '70 0 '30 Oe937

'20 OPERATING PERSONNEL SUPERVISORY PERSONNEL QHIKL ~IX0+020 0 '26 0 F 000 0 F 000 Oo000 0 '35 0

0 '20 a~mrna 0 F 000 0 F 000 Oo000 0 '60 ENCINEERINC PERSONNEL 0 ~ 12$ 0 '29 0 '66 0 '35 0 ~ 140 Oe195 REFUELINC MAINTENANCE PERSONNEL OPERATINC PERSONNEL ESWIE~3JI SUPERVISORY PERSONNEL ENGINEERIMC PERSONNEL 18+345 2 '89 1.815 1 ~ 813

~ 0 '07 0 '51 0 F 000 1 ~ 797

~ 0 355 0 F 000 0 '25 0 521 24e95$

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'35 5 ~l 0 eh 1 6 0 ~ 155 0.000 1 ~ 260 0 ~ 110 0 F 000 0 ~ 005 0 '10 TOTAL MAINTENANCE PERSONNEL 245 '06 6 '38 393+667 202 '92 ' '08 238 '32 OPERATING PERSONNEL EllLB~IXRKRJJUUUlWEL~

SUPERVISORY PERSONNEL 45 '57 25 '33 5.000 I F 000 0

> 0 F 000 3e491 KJP~QQ 46+089 8ih88 0 '90 0 '03

~~05 0 F 000 1 270 ENGINKERINC PERSONNEL 34 'S9 42 162 67 '53 13 '99 14ob45 39 '65

~ ++CRAND TOTALsee 401 o286 54+300 541 F 408 310 F 801 19 ~ 146 332 '72

2.2 MAIN'TEAM LINE SAFETY RELIEF VALVE CHALLENGES This .section contains 'information pertaining to mainin steam line safety/relief valve challenges for calendar year 1992 accordance with the requirements of WNP-2 Technical Specification 6.9.1.5(b).

NOTEs Includes ~ ll In Situ Tests For Each Actuation or Failure to Actuate:

5/R Valve Serial Number 63790 00 0124 63790-00.0061 Component 10 (Location) NS.RV-20 NS RV 56 Oats of Actuation 03/19/92 03/19/92 (NO/OA/TR)

Time of Oay 0226 0217 (2a Nour Clock)

Type of Actuation (Code)

Cause/Reason for Actuation (Code)

Rx Opcratiny Condition Prior to Lift (Code)

Rx Pover Level Prior to ISX 15X Lift (X Rated Thermal)

Time Req'd for Tailpipe N/A Temp to Return to Normal Other Instrumensation PROCESS CONPUTER PROCESS CONPUIER Type (Code)

Other Instruaentation Open Open Number Readiny and Units Rx Prcssure Prior to 9a3 9a3 Actuation (PSIG)

F AVA A F APP A Reseat Prcssure At N/A NIA Valve Closure (PSIG)

Duration of This Actuation 30 scc I csin. 25 sec (Nlnutes. Seconds)

Failures. Reports (Code)

LER Number None None (5 Olylt NLsaber)

Convents Rcyardiny This Tes Ves Actuation Attachedl (Tcs or No)

CONTINUED 2.2 MAIN STEAM LINE SAFETY RELIEF UALVK CHALLENGES HGfEc Includes all ln Sbsa Tasse Fot Eacb Aauauon or Fsl/usu so Ac nss u:

S/R Valve Serial Number 62 790404 I 22 d37904041 26 d)7904040t7 d)79040405 6 Component ID (Lot anon) MS-RV-ID MS.RV-)D MS-RV-2C MSS5ndC Dase of Accuauon (MO/Dn/YR) 0C/I I/92 Ot/Ig/92 Ot/II/92 Time of Day (It Bouc Clocb) I)OS IS)0 l 425 T)pc of Acnsas'usn (Cods)

Cause/Reason for Ac usa uon (Code)

Rx Open sing Cond sYson Prior so L(h (Code)

Rx Ps/cur Level Prior us Lih (% Raud T)scrmaO Time Res))i for Tailpipe Temp to N/A N/A N/A H/A Rcmm so t/orms l Osbcr tnsuumenndon Typ>> (Code)

Osber Inssnsmcrmskus OPEN OPEN OPEH Number Reading and Uniu Rx Prcsausu Prio m 9ld 976 9)S Accuauon (PSIG)

IF AVAILABLE/IFAPPUCABLE Reseat Plcssuse Ac H/A I//A N/A Valve Closure (PSIG)

Durauon oflbi~ Accession 6 sc*

(Mlnuus, Seconds}

Failusrs, Rcpons (Code)

LER i/umber (S Digit Number) Noes Commenn Regarding T)sia Ycs Ycs Ycs Ycs Acmsdon Anscbedl (Yc ~ or I/o)

2.2 MAIN STEAM LINE SAFETY RELIEF VALVE CHALLENGES CONTINUED NOI'E: Includes all In Situ Tests For Each Actuation or Failure to Actuate:

S/R Valve Serial Number 63790404048 63790404054 63790404055 63790404059 63790404045 Component ID (Location) hlS-RV-I A MS.RV-2A MS.RV-3A MS.RV4A MS.RV-]B Date of Actuation (MO/DA/YR) 07/06/92 07/0682 07/0682 07/0682 Time of Day (24 Hour Clock) 0338 0433 0328 Type of Actuation B (Code)

Cause/Reason for Actuation (Code)

Rx Operating Condition Prior to Lift (Code)

Rx Power Level Prior to Lift (% Rated Thermal)

<<15% <<15% <<15% >> 15% <<15%

Time Req'd for Tailpipe NIA N/A NIA NIA N/A Temp to Return to Normal Other Instrumentation PROCESS PROCESS PROCESS PROCESS PROCESS Type (Code) COMPUTER COMPUTER COMPUTER COMPUTER COMPUTER Other Instrumentation OPEN OPEN OPEN ~ OPEN OPEN Number Reading and Units Rx Pressure Prior to 950 950 950 950 950 Actuation (PSIG) tf AVAILABLKltPAPPLICABLE Reseat Pressure At NIA NIA N/A NIA NIA Valve Closure (PSIG)

Duration of This Actuation 18 scc 28 scc 16 sec 48 scc 15 sec (Minutes, Seconds)

Failures, Reports (Code)

LER Number (5 Digit None None None None None Number)

Comments Regarding This Yes Yes Actuation Attached?

(Ycs or No)

2. 2 MAIN STEAM LINE SAFETY RELIEF VALVE CHALLENGES CONTINUED NOTE: Includes all In Situ Tests For Each Actuation or Failure lo Actuate:

S/R Valve Serial Number 63790404049 63790404052 63790404056 63790404061 63790404046 Component ID (Location) MS-RV-2B MS.RV-3B MS.RYE MS.RV-SB MS.RV-IC Date of Actuation (hlO/DA/YR) 07/06/92 07/06/92 07/06/92 07/06/92 Time of Day (24 Hour Clock) 0348 0251 0359 0415 0343 Type of Actuation (Code)

Cause/Reason for Actuation (Code)

Rx Operating Condition Prior to Lift (Code)

Rx Povver Level Prior to ~ 15% ~ 15% ~ 15% ~ 15% ~ 15%

Lift (% Rated Thermal)

Time Req'd for Tailpipe N/A NIA N/A N/A NIA Temp to Return to Normal Other Instrumentation PROCESS PROCESS PROCESS PROCESS PROCESS Type (Code) COhlPUTER COMPUTER COMPUTER COMPUTER COMPUTER Other Instrumentation OPEN OPEN OPEN OPEN OPEN Number Reading and Units Rx Pressure Prior to 950 950 950 950 950 Actuation (PSIG) tp AvArLABLKJIFAP PLlCAB LE Reseat Prcssure At N/A NIA NIA NIA N/A

'alve Closure (PSIG)

Duration of This Actuation 19 sec None 50 scc 28 sec 29 scc (Minuics, Seconds)

Failures, Reports (Code) B,D LER Number (5 Digit None 92433 None None None Number)

Comments Regarding This Yes Actuation Attachcd7 (Yes or No)

2. 2 MAIN STEAM LINE SAFETY RELIEF VALVE CHALLENGES CONTINUED NOTE: Includes all In Situ Tests For Each Actuation or Failure to Actuate:

S/R Valve Serial Number 63790404047 63790.004051 63790404058 63790404062 63790404050 Component ID (Location) MS-RV-2C MS-RV-3C MS.ROC MS-RV-5C MS-RV-ID Date of Actuation (MO/DA/YR) 07/06/92 07/06/92 07/06/92 Time of Day (24 Hour Clock) 0334 0408 0320 0412 Type of Actuation B (Code)

Cause/Reason for Actuation (Code)

Rx Op<<rating Condition Prior to Lift (Code)

Rx Power Lcvcl Prior to ~ 15% ~ 15% ~ 15% ~ 15% ~ 15%

Lift (% Rated Thermal)

Time Rcq'd for Tailpipe NIA NIA NIA N/A NIA Temp to Return to Normal Other Instrumentation PROCESS PROCESS PROCESS PROCESS PROCESS Type (Code) COMPUTER COMPUTER COMPUTER COMPUTER COMPUTER Other Instrumentation OPEN OPEN OPEN OPEN OPEN Number Reading and Units Rx Pressure Prior to 950 950 950 950 950 Actuation (PSIG)

IF AVAILABt.UlPAPPt.tCABLK Reseat Pressure At N/A NIA NIA NIA NIA Valve Closure (PSIG)

Duration of This Actuation 24 sec 33 sec 45 scc 15 scc (Minutes, Seconds)

Failures, Reports (Code)

LER Number (5 Digit None None None None Noae Number)

Comments Regarding This Actuation Attached?

(Ycs or No)

2.2 MAIN STEAM LINE SAFETY RELIEF VALVE CHALLENGES CONTINUED NOTE: Includes all In Situ Tests For Each Actuation or Failure to Actuate:

S/R Valve Serial Number 6379040-0124 63790404126 63790404060 63790404052 63790404052 Component ID (Location) MS.RV-2D MS.RV-3D MS.RVQD MS-RV-3B MS.RV-3B Date of Actuation (MO/DAIYR) 07/06/92 07/06/92 07/06/92 07/11/92 Titne of Diy (24 Hour Clock) 0419 0351 0312 0455 1335 Type of Actuation B B B (Code)

Cause/Reason for Actuation (Code)

Rx Operating Condition Prior to Lift (Code)

Rx Power Level Prior to ~ 15% ~ 15% ~ 15% ~ 15% ~ 15%

Lift (% Rated Thermal)

Time Req'd for Tailpipe N/A NIA NIA NIA NIA Temp to Return lo Normal Other Instrumentatiori PROCESS PROCESS PROCESS PROCESS PROCESS Type (Code) COMPUTER COMPUTER COMPUTER COMPUTER COMPUTER Other Instrumentation OPEN OPEN OPEN OPEN OPEN Number Reading and Units Rx Pressure Prior to 950 950 950 950 950 Actuation (PSIG) tF AvAILABLErtFAPPLICABLE Reseat Pressure At N/A N/A NIA 940 888 Valve Closure (PSIG)

Duration of This Actuation 19 sec I min, 21 sec I min, 45 scc 2min,29 ace 2 min,58 ace (hiinutes, Seconds)

Failures, Reports (Code) B,D B,D LER Number (5 Digit None None None 92433 Number)

Comments Regarding This Actuation Attacftcd?

(Ycs or No)

2. 2 MAIN STEAM LINE SAFETY RELIEF VALVE CHALLENGES CONTINUED NOTE: Includes all In Situ Tests For Each Actuation or Failure to Actuate:

S/R Valve Serial Number 63790-M-053 63790404060 6379M04051 63790404049 63790404045 Component ID (Location) MS.RV-3B MS-RVAD MS-RV-3C MS-RV-2B ~

MS-RV-IB Date of Actuation (MO/DA/YR) 07/19/92 07/19/92 07/1962 07/19/92 07/19/92 Time of Day (24 Hour Clock) 2007 2018 2030 2034 Type of Actuation (Code)

Cause/Reason fpr Actuation (Code)

Rx Operating Condition Prior to Lift (Code)

Rx Pawer Level Prior to Lift (S Rated Thermal)

Time Reti'd for Tailpipe N/A N/A N/A N/A Temp to Return to Normal N/A'ROCESS Other Instrumentation PROCESS PROCESS PROCESS PROCESS Type (Code) COMPUTER COMPUTER COMPUTER COMPUTER COMPUTER Other Instrumentation OPEN OPEN OPEN OPEN OPEN Number Reading and Units Rx Pressure Prior to 948 948 948 948 948 Actuation (PSIG)

IF AVAILABLE/IFAPPLICABLE

Reseat Pressure At N/A N/A N/A N/A N/A Valve Closure (PSIG)

Duration of This Actuation 45 scc I min II sec 10 sec 16 sec (Minutes, Seconds)

Failures, Reports (Code)

LER Number (5 Digit None None None None None Number)

Cotnments Regarding This Actuation Attachcd7 (Ycs or No)

2.2 MAIN STEAM LINE SAFETY RELIEF VALVE CHALLENGES CONTINUED CODES:

T e of Actuation A. Automatic B. Remote Manual C. Spring Plant Condition A. Construction B~ Startup or Power Ascension Tests in Progress C. Routine Startup D. Routine Shutdown E. Steady State Operation F. Load Changes During Routine Operation G. Shutdown (Hot or Cold)

H. Refueling Reason for Actuation A. Overpressure B. ADS or Other Safety System C. Test D. Inadvertent (Accidental/Spurious)

E. Manual Relief

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tll. POOR IRRI llllllLRRRKRI RRIH LRIIL ~RR V 0 OPR V ECU R 92%1 2/22/92 F 14.2 A RB CRDRVE The plant was downpowered and generator was removed from grid to permit drywell entry for veriflcation of source of FDR leakage. It was found to be coming from flange of CRD 42-59. The CRD was isolated and the plant returned to power operation.

92~ 2/25/92 F 101.3 H SE RECOMB The plant was shutdown after an engineeringing evaluation determined that drain piping from both Containment Atmohsphere Control (CAC) units was improperly designed, ModiTication of drain piping is in prog fess o

/@MME ARY'YPE REASON METHOD SYSTEM & COMPONENT F-FORCED A-EQUIP FAILURE F-ADMIN 1-MANUAL'-MANUAL EXHIBITF & H S-SCHED B-MAINTOR TEST G-OPER ERROR SCRAM INSTRUCTIONS FOR C-PZFUELING H-OTHER 3-AUTO SCRAM PREPARATION OF D-REGULATORY RESTRICTION 4-CONTINUED DATA ENTRY SHEET E-OPERATOR TRAINING & 5-REDUCED LOAD LICENSEE EVENT REPORT LICENSE EXAM 9-OTHER (LER) FILE (NUREG -0161)

OVN RED TI' REPOR BIO: hLAAI 0 R

TVVg IQQR~ Rg~~ ++DID ~ER~Q ~V'EM IVE I T P 92-02 2/25/92 F 436.4 H 92-007 SE RECOMB Concluded outage for modificaiton of Containment Atmospheric Control (CAC) drain piping.

QHg5I~RV. WNP-2 returned to service on March 19 after completion of plant modifications.

REASON MET OD SYSTEM 8c COMPONENT F-FORCED A-EQUIP FAILURE F-ADMIN I-MANUAL EXHIBITF Ec H S-SCHED B-MAINTOR TEST G-OPER ERROR 2-MANUALSCRAM INSTRUCTIONS FOR C-REFUELING H-OTHER 3-AUTO SCRAM PREPARATION OF D-REGULATORY RESTRICTION 4-CONTINUED DATA ENTRY SHEET E-OPERATOR TRAINING 8c 5-REDUCED LOAD LICENSEE EVENT REPORT LICENSE EXAM 9&THER (LER) FILE (NUREG%161)

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0 REPORT PERIOD: QP~RI ~1? 0 LATE TYPE ~Hg1@ ggAAj~ fgggI~D gg1~Q 5VVjT~E RR PRE 92-03 4/18/92 S 308.4 C RC FUEL XX Plant was shutdown as scheduled for refueling outage R-7.

QJg~fRY'NP-2 operated routinely until April 18, 1992 when it was shutdown for refueling outage R-7.

TY 8 REASON METHOD SYSTEM & COMPONENT F-FORCED A-EQUIP FAILURE F-ADMIN I-MANUAL EXHIBITF & H S-SCHED B-MAINTOR TEST G-OPER ERROR 2-MANUALSCRAM INSTRUCTIONS FOR C-REFUELING H-OTHER 3-AUTO SCRAM PREPARATION OF D-REGULATORY RESTRICTION 4-CONTINUED DATA ENTRY SHEET OPERATOR TRAINING & 5-REDUCED LOAD LICENSEE EVENT REPORT LICENSE EXAM 9-OTHER (LER) FILE (NUREGW161)

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REPORT PERIOD: JQI V 1992

~AT ~ P+~ I&~A~ ~~HD ~ER~Q /Yam E RRE VE I T PRE 92-03 4/18/92 S 460.4 C RC FUEL XX Concluded refueling outage R-7.

92-04 7/20/92 S 3.7 B HA MECFUN Generator was removed from service for overspeed testing and turbine bypass valve testing. It was resynchronized to grid after successful completion of testing.

92-05 7/21/92 S 16.4 B HA TURBIN Generator was removed from grid for torsional testing of turbine rotors. After satisfactory completion of testing, it was returned to service.

5ggJ5~R'NP-2 returned to service from refueling. Subsequently, two scheduled outages for testing were completed.

TYPE REASON METHOD SYSTEM & COMPONENT F-FORCED A-EQUIP FAILURE F-ADMIN 1-MANUAL EXHIBITF &H S-SCHED B-MAINTOR TEST G-OPER ERROR 2-MANUALSCRAM INSTRUCTIONS FOR C-REFUELING HITHER 3-AUTO SCRAM PREPARATION OF D-REGULATORY RESTRICTION 4-CONTINUED DATA ENTRY SHEET BWPERATOR TRAINING& 5-REDUCED LOAD LICENSEE EVENT REPORT LICBNSB EXAM 9-OTHER (LER) FILE (NUREG4161)

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UNIT IIUTD DUCTI N M M

0 RE ORT PE 0: ~A Ql DATE TYPE HOl~ ~+~ ~GIBED LER~O $ YYTElg A E& RRE IVEA TI T PREVE E 9246 8/1/92 F 12.95 A EB TRANSF Generator was removed from BPA grid due to loss of signal from B Phase 500KV potential device. The bushing was replaced and generator resynchronized to grid.

9247 8/14/92 F 19.0 CG VALVEX The reactor was downpowered and generator removed from grid to permit drywell entry for identification and repair of diywell leakage, The leakage was identified as a packing leak on RWCU-V-103. The valve was manually backseated to stop leak and the plant returned to power operation.

9248 8/15/92 F 385.56 A 92437 RC FUELXX The reactor was manually scrammed from 35% power due to core instability. Core power oscillations of 209o power occurred during

~r.

preparation to change RRC pumps to high speed (60 Hz) operation.

investigation and evaluation of the event by an NRC Augmented ~,

a number of recommendations and corrective actions were implemented and the plant returned to power operation on August 31, 1992 (see LER 92437).

$ Q~~RY'NP-2 incurred three forced outages in August as described above.

TYPE REASON METHOD SYSTEM & COMPONENT F-FORCED A-EQUIP FAILURE F-ADMIN 1-MANUAL EXHIBIT F & H S-SCHED B-MAINTOR TEST G-OPER ERROR 2-MANUALSCRAM INSTRUCTIONS FOR C-REFUELING H-OTHER 3-AUTO SCRAM PREPARATION OF D-REGULATORY RESTRICflON 4-CONTINUED DATA ENTRY SHEET E-OPERATOR TRAINING & 5-REDUCED LOAD LICENSEE EVENT REPORT LICENSE EXAM 9-OTHER (LER) FILE (NUREG4161)

A O

b4 H RED YI N M O

Ql REPORT PERIOD: BE 2 IHL 92-09

~11/21/92 DJJI S

H 53.8 I

B

• Ml M T"e 1

LE M Kl~ CbtLJtEZ EB ELECON C US 8c C CTIVE ION 0 EV Generator was removed from service for cleaning ofhigh voltage insu due to buildup of chemical deposits from cooling tower driA. Also repaired source of Dryweli FDR leakage (RFW-V-10B). The plan then returned to service.

MMARY'NP-2 incurred one scheduled outage in November as described above.

TYPE REASON METHOD SYSTEM 8c COMPONENT F-FORCED A-EQUIP FAILURE F-ADMIN 1-MANUAL EXHIBIT F & H S-SCHED B-MAINTOR TEST G-OPER ERROR 2-MANUALSCRAM INSTRUCTIONS FOR C-REFUELING H-OTHER 3-AUTO SCRAM PREPARATION OF

.D-REGULATORY RESTRICTION 4-CONTINUED DATA ENTRY SHEET E-OPERATOR TRAINING 8c 5-REDUCED LOAD LICENSEE EVENT REPORT LICENSE EXAM 9-OTHER (LER) FILE (NUREG -0161)

2~3 SlJMMARY OF PLANT OPERATIONS GENERATOR RUN TIMB 1992 GENERATOR NO. HOURS DA'IB ON UN OFF UN S.D. RUH TIM OUTAG 1312 I PLANT WAS DOWNPOWERED AND GENERATOR REMOVED FROM GRID AT1312 HOURS ON 2fl2TO PERMIT DRY (CY 92) fF) 110 WEILEHIRY IN SEARCH OF LEAKAGEALSO CRD 4269 STARTED DRIFIINO Dl AND CONTAINMENTPAR. 126120 TICVLATBMONIIORS CMS RIS-17/Ih & B INCREASED FROM 600 TO 1800 CPM IN 30 MINUIES. FDR DRY-WELLLEAKAGEWAS 222 GPM BY ACIVALMEASUREMENT. UPON EHIBANCE OF DR~

LEAKAGE WAS FOUND TO B B FROM CRD 42.59 FIANGE THE CRD WAS ISOLA'IBDTO SIQP LEAK.

THE SOURCE OF (IQTRVH) 1404.12 GENERATOR SYNCHRONIZED TO SPA GRID 14.17 2 AN UNUSUALEVENT WAS DFAXARED ON 2n5 AT 1315 HOURS AS A RESULT OF A DISPOSfIION SY POC Ill ON PER 2924150 THATBOTH CAC SYSTEMS ARE NOT DES IGHED PROPERLY AND ARB TIIEREFORB IN OPER ABIB PLANT5HUID OWN WAS COMMENCED ANDTHE GENERATOR WAS TAKENOFF UNE AT 1838 HOURS. 63.76 3/19/92 041$ GENERATOR SYNCHRONIZED TO BPA GRID 3 GENERATOR WAS REMOVED FROM GRID AT033$ HOURS DUE ON 4/18 FOR START OF R 7 REFUELINO OUTAGE.

112 71816 R 7 OllfAGEOFFICIALLYENDED WfIIIFIRST CLOSING OF GENERATOR BREAKER AT0423 OH 7/20.

1955 GENERATOR WAS REMOVED FROM GRID AT 1955 HOURS ON 7fl0 FOR OVERSPEED TESIINO.

113 1553 GENERATOR SYNCHRONIZED TO SPA GRID.

Ifll/92 5 GENERA'IQR WAS REMOVED FROM GRID AT 0424 HOURS ON lfllFOR'IURBINETQRSIONALTESIIHG.

114 lnl/92 2050 GENERA'IQR SYNCHRONIZED TO SPA GRID. 16A3 6 GENERATOR WAS REMOVED FROM GRID DUE TO LOSS OF 8'HASB SIGNAL FROM 'IR.M4 SOkv BUSH ING 11$ POTF2fIIALDECVICE. 8 PA REPLACED fl'fIH ONE FROM TR.M2 SPARE TRANS FORM EIL 8/01/92 1802 GENERATOR SYNCHRONIZED TO BPA GRID 12.95 7 GENERATOR WAS REMOVED FROM GRID DUE TO DRYWELLLEAKAGEEXCEEDING 3 OPM. SOURCE OF LEAK 116 WAS FROM RWCV-V 103 PACKING. 296.12 8/14/92 2109 GENERATOR SYNCHRONIZED TO BPA GRID 8 REACIQR WAS MANUALLYSCRAMMED AT35% POWER 'IQ CORB POWER OSCILLATI0NSOF 20% POWER.

117 OSCBLATIONS WERE BEIWEEN 2596*4$ % OH APRM RECORDERS. ALSO NUMEROUS LPRM DOWNSCALES.

GENERATOR SYNCHRONIZED TO SPA GRID Ilfll/92 9 GENERATOR WAS REMOVED FROM GRID FOR CLEAIIINOOF 3Y INSULATORS &'IO REPAIR LEAKIN DR YWELL 118 LEAKWAS FROM RFW.V 108.

I I/2$/92 111$ 53.77

'IHRU 17/3 1/92 924.7$

$ 50736 3276.14 fF) FORCED OUTAGE

2.4 SIGNIPICANT CORRECTIVE MAINTENANCE PERPORMED ON SAPETY" RELATED E UIPMENT This section of the report normally contains the information required in accordance with the Regulatory Guide 1.16, Revision 4, Section C.l.b(2)(e).

However, for this reporting period (1992), information on significant corrective maintenance performed on safety- related equipment will be submitted separately from this annual operating report.

2 5 FUEL PERFORMANCE This section is provided in accordance with the requirements of the WNP-2 FSAR, Section 4.2.4.3, and Regulatory Guide 1.16, Revision 4, Section C.l.b.(4).

In accordance with commitments and requirements described in the WNP-2 FSAR, Section 4.2.4.3, a visual inspection of discharged fuel from Cycle 7 was performed in the month of October 1992. The purpose of the inspection was to verify assembly and fuel rod integrity. The inspection was also used to fulfilla commitment to inspect Siemens Power Corporation (SPC) high-burn-up 8X8 assemblies and note any unusual fuel rod growth. At the same time, a visual inspection of two discharged fuel channels was also performed.

A total of four fuel assemblies and two channels discharged at the end of Cycle 7 were inspected. No evidence of rod bow, abnormal fuel rod growth or mechanical damage were noted during the inspection of the assemblies. Furthermore, little or no nodular corrosion was observed on the clad surface.

The fuel channels inspected displayed a uniform covering of light oxidation on unwelded surfaces. However, the heat-effected zone of the weld surface was clean and consistent with past inspections.

In addition, there was no observable mechanical damage to the channels.

2.6 10CRR50.59 CHANCES TESTS AND EXPERIMENTS Federal Regulations (10CFR50.59) and the Facility Operating License (NPF-21) allow changes to be made to the facility and procedures 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 1992 are provided. Included are summaries of the safety evaluations.

2.6.1 PLANT MODIFICATIONS Permanent plant modifications at WNP-2 are implemented with a Plant Modification Request (PMR) or Basic Design Change (BDC). The following PMRs/BDCs implemented in 1992 required a Safety Evaluation in accordance with 10CFR50.59. Each permanent change was evaluated and determined neither to represent an Unreviewed Safety Question nor require a change to the WNP-2 Technical Specifications.

2.6.1.1 BDC 55-1 99-OA This BDC provided for the correction of plant drawings to reflect the as-built condition of Control Air System (CAS) valve CAS-V-100/93. During construction the valve was added to the plant, however, the top-tier drawing was not updated to reflect the existing configuration.

It was concluded from the safety evaluation that this activity was limited to as-built and documentation changes only to non-safety related components in a non-safety related system. Accordingly, this activity would not alter assumptions made previously in the Licensing Basis Documents (LBD) or impair any operator action.

2.6.1.2 BDC 1-030 -OA This BDC provided for the replacement of spacers in the Standby Service Water (SSW) System at the inlet to Diesel Cooling Water (DCW) Heat Exchangers DCW-HX-1A2/1B2 with restricting orifices.

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It would was concluded from the safety evaluation that this activity meet the design, material and construction standards applicable to the SSW System. Furthermore, the system would not be required to operate outside of its design limits and no changes to system interfaces were created by this activity.

2.6.1.3 BDC 91-0071-Z This BDC provided for the modification of several test/vent/drain line connections. The scope of the BDC was to modify the connection configuration from socket welds to butt welds on several lines.

It was concluded from the safety test/drain/sample/vent/instrument evaluation that the change to the line would provide stronger welds and a stronger section of pipe more resistant to shock and less likely to fatigue and break than the original configuration. The proposed activity increased the endurance of the weld in the test/drain/sample/vent/instrument line.

2.6.1.4 BDC 55-2256-OA This BDC provided for the clarification of Drawing M524 to allow the flexibility of using Standby Service Water (SSW) System valves SSW-V-70A/B during plant operations other than shutdown.

It was concluded from the safety evaluation that a malfunction of equipment which would require the use of the service water system and/or spray pond has been addressed in the LBD discussion of mitigating accidents. Furthermore, the use of these valves would not reduce the availability of the service water system or spray pond 2.6.1.5 PMR 0-0268-OA This PMR provided for the modification of the position indication mechanism for Reactor Core Isolation Cooling (RCIC) System testable check valve RCIC-V-66 on the head spray line by addition of a second return spring, a second set screw securing the movement arm cam to the indicator shaft, and removal of the unused switch trip pins on the movement arm cam.

It was concluded from the safety evaluation that this activity affected only the valve position indication mechanism, which has no safety function. In addition, the modification would improve the ability of the disk position switch trip arm to return to a position enabling correct valve position indication.

l1 2.6.1.6 PMR 86-0627-OA This PMR provided for installation of a cross-tie between the discharge of Fuel Pool Cooling (FPC) System pump FPC-P-3 and the Equipment Drains Radioactive (EDR) System. Installation of the cross-tie would allow the water volume in the suppression pool to be lowered using the FPC System.

It was concluded from the safety evaluation that the new configuration would eliminate the need to start Residual Heat Removal (RHR) System pump RHR-P-2B by using FPC-P-3, a non-safety related piece of equipment. Furthermore, it was concluded that the installation of the cross-tie and operation of associated piping and valves would not increase the probability of the occurrence of any accident evaluated in the LBD.

2.6.1.7 BDC 8 -02 -23AP This BDC provided for replacement of'hree Reactor Core Isolation Cooling (RCIC) System Bailey pressure transmitters (RCIC-PT-4, RCIC-PT-5 and RCIC-PT-7) with Rosemount Series 1153 transmitters.

It was concluded from the safety evaluation that the form and function were identical for both types of transmitters. In addition, it was concluded that the loop function would remain as originally designed, there was no change in system function and the modification does not increase the probability of an occurrence of an accident previously evaluated in the LBD.

2.6.1.8 BDC 88-0048-OA This BDC provided for the replacement of Diesel Oil (DO) System Magnetrol capacitance level sensors and transmitters (DO-LITS-10A, DO-LITS-10B and DO-LITS-15) with Magnetrol ultrasonic level sensors and transmitters. In addition,'ocal level indicators DO-LI-10A, DO-LI-10B and DO-LI-15 were to be replaced with Dixon Bar Graphs.

It was concluded from the safety evaluation that this activity serves to improve the reliability. of the diesel oil measurement in the diesel oil storage tanks. Furthermore, it was concluded that there was no relationship between the effects of this activity and the probability of occurrence of any event described in Chapter 15 of the FSAR.

2.6.1.9 BDC 87-0244-OA This BDC provided for installation of the Reactor Recirculation (RRC) System Adjustable Speed Drives (ASDs) and auxiliary equipment.

It was concluded from the safety evaluation that the change involves only the location and installation of the ASDs and auxiliary equipment and there are no direct connections to existing equipment or systems important to safety. Since the change only involves the location and installation of the ASDs, the safety evaluation concluded that no new failure mode for safety-related equipment or systems would be introduced by this installation.

2.6.1.10 BDC 0-0100-OA This BDC provided for installation of pipe connections and blind flanges in four locations in the Scram Discharge Volume (SDV)

System for the purpose of fresh water or chemical cleaning.

It was concluded from the safety evaluation that the modification would not affect the safety function of the SDV System and there would be no increase in the probability of occurrence of malfunction of equipment important to safety. It was also concluded that the proposed activity met the original design specification;

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2. 6 2 TEMPORARY MODIFI TIONS AND INSTRUMENT SETPOINT HANGE The following are summaries of temporary modif ications and instrument setpoint changes. As required by 10CFR50.59, each change was evaluated and determined neither to represent an Unreviewed Safety Question nor a change to the WNP-2 Technical Specifications. Temporary modifications are made by means of the Temporary Modification Request (TMR) process and instrument setpoint changes are made under the Instrument Setpoint Change Request (ISCR) process.

2.6.2.1 TMR 2- 82 This TMR provided for the installation of a regulating transformer in series with the alternating source circuit for Inverter IN-3 to limit fault current and provide fuse coordination in the event of a downstream short circuit.

It was concluded from the safety evaluation that the new circuit configuration was functionally identical to that of the original design and that installation of the regulating transformer would not increase the probability of occurrence of an accident previously evaluated in the LBD.

2.6.2.2 ISCR 1111 This ISCR provided for changing the instrument setpoints for the vacuum breakers between the Reactor Building and the Suppression Pool. Based on device uncertainties and manufacturer's range of operation, it was concluded that the maximum setting should be 0.443 psid instead of 0.50 psid.

It was concluded from the safety evaluation that establishment of the lower setpoint would not increase the probability of occurrence of an accident and the consequences of vacuum breaker opening is not impacted by this change.

2.6.2.3 ISCR 1112 This ICSR provided for changing the instrument setpoints for several Main Steam Leakage Control (MSLC) System pressure switches to allow initiation of the inboard MSLC System at greater than 35 psig containment pressure.

It was concluded from the safety evaluation that changing of the setpoint would not increase the probability of an accident and the only change is to allow initiation of the inboard system at peak containment pressure.

2.6.2.4 ISCR 1121 This ISCR provided for changing the instrument setoints for several Main Steam Leakage Control (MSLC) System pressure indicating switches to allow initiation of the inboard MSLC System at peak containment pressure.

It was concluded from the safety evaluation that changing of the setpoint would not increase the probability of an accident of a different type and the only change is to allow initiation of the inboard MSLC System at a pressure between the Main Steam Isolation Valves (MSIVs) that is greater than peak containment pressure of 34.7 psig.

2.6.2.5 ISCR 1122 This ISCR provided for changing the instrument setpoint for Main Steam Leakage .Control (MSLC) System pressure indicating switch MSLC-PIS-20 to.allow initiation of the outboard MSLC System at peak containment pressure.

It was concluded from the safety evaluation that changing of the setpoint would not increase the probability of an accident and the only change is to allow initiation of the outboard MSLC System at peak containment pressure of 34.7 psig.

t 2.6.2.6 ISCR 1120 This ISCR provided for changing the instrument setpoint for Main Steam Leakage Control (MSLC) System pressure indicating switch MSLC-PIS-24 to allow initiation of the outboard MSLC System at peak containment pressure.

It was concluded from the safety evaluation that changing of the setpoint would not increase the probability of an accident and the only change is to allow initiation of the outboard MSLC System at peak containment pressure of 34.7 psig.

2.6.2.7 ISCR 1150 This ISCR provided for changing the intrument setpoint for Reactor Feedwater (RFW) System flow switches RFW-FS-618A and RFW-FS-618B in response to core flow instability issues raised following a scram that occurred on August 15,1992. The setpoint changes the Reactor Recirculation (RRC) System low feedwater flow cavitiation interlock to a lower value.

It was concluded from the safety evaluation that changing of the setpoint would neither increase the probability of the occurrence of an accident nor increase the probability of malfunction of equipment important to safety. Changing of the setpoint involves cavitation protection and there is sufficient design margin.

2.6.2.8 IS R 1160 This ISCR provided for changing the instrument setpoints for several Radwaste Building Mixed Air (%R-HVAC) System temperature switches to meet Station Blackout requirements that battery room temperature should be maintained > 74 degrees F.

,It was concluded from the safety evaluation that changing of the setpoints does not affect system function and the new setpoints were within the limits of the engineering design calculation.

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2. FSAR CHANGES General Changes to the FSAR evaluated within the definition of 10CFR50.59 are reported in this section.

2.6.3.1 SCN 1-058 This SCN provided for revision of the Emergency Plan in that certain tables and associated notes describing Emergency Action Level (EAL) initiating conditions were deleted from Section 6 of Chapter 13.3, "Emergency Preparedness Plan (EPP)."

It was concluded from the safety evaluation that 'elimination of certain EAL examples from the EPP would not impact the consequences of an accident or reduce evaluation for the margin of safety.

2.6.3.2' N 2-002 This SCN provided for clarification of the Residual Heat Removal (RHR) System cross-connect to the Fuel Pool Cooling (FPC) System.

It was concluded from the safety evaluation that the consequences of a malfunction would not increase and operation Loop B of RHR in the FPC assist mode would not cause an accident different from those previously analyzed.

2.6.3.3 SCN 92-036 This SCN provided for the revision of the Emergency Plan by deleting reference to use of the Department of Energy (DOE) helicopter for providing protective action notification to the Columbia River transient population within the WNP-2 Emergency Planning Zone (EPZ).

It was concluded from the safety evaluation that this activity would not impact the consequences of an accident because use of the helicopter was one of three actions taken to provide notification to a particular segment of the public. However, to compensate for the loss of the helicopter, the Supply System installed additional sirens to provide notification to the transient population within the EPZ for the Columbia River.

2.6.3.4 SCN 2-041 This SCN provided for the revision of the discussion of the Reactor Protection System (RPS) Motor-Generator (MG) Set coastdown time to reflect plant data.

It was concluded from the safety evaluation that the probability of transients resulting from power disturbances would not be increased because the MG Set maintains the one-second licensing basis and there is sufficient margin.

2.6.3.5 SCN 2-048 This SCN provided for revision of the description of activities on or near the site including construction of the Plant Engineering Center (PEC), various Hanford Site activities, air traffic patterns, Yakima Firing Range activities and gas pipelines.

It was concluded from the safety evaluation that the proposed activities would not increase the probability of occurrence of an accident or create the possibility of an accident of a different type than previously evaluated in the LBD as those activities that did involve some hazard were too distant from the site.

2.6.3.6 SCN 2-055 This SCN provided for partial implementation of the WNP-2 Cycle 8 core thermal limits and other core-related changes.

It was concluded that the Cycle 8 reload design would not increase the probability of occurrence of previously evaluated accidents or introduce any new equipment malfunctions.

2.6.3.7 SCN 2-060 This SCN provided for the revision of the Emergency Plan by deleting reference to the Crisis Management Center (CMC) as an emergency facility and the Managing Director Representative position.

It was concluded that the proposed activity would have no impact on occurrence of an accident and deletion of the CMC and Managing Director Representative position would not increase the .

consequences of an accident.

2.6.3.8 This SCN provided for the revision of FSAR Sections 13.1.1 and 13.1.2 to reflect several organizational changes that were made.

It was concluded from the safety evaluation that the proposed activity would not change the intent or commitments described in the LBD.

2.6.3.9 SCN 92-078 This SCN provided for revision to Diesel Generator loading schedules and associated text in FSAR Section 8.3.

It was concluded from the safety evaluation the proposed activity would not increase the probability of occurrence of an accident or increase the consequences of design basis accidents.

2.6.3.10 SCN 2-091 This SCN provided for revision to FSAR Section 9.2.5 to describe the results of a re-evaluation of the WNP-2 Ultimate Heat Sink Analysis.

It was concluded from the safety evaluation that the revised Ultimate Heat Sink (UHS) Analysis shows that the UHS would be capable of accomplishing its safety function following a LOCA, without the availability of offsite power, and that the cooling capability would be maintained for 30 days without outside makeup.

2.6.4 PROBLEM EVALUATIONS The Plant Problems-Plant Problem Reports Procedure (PPM 1.3.15) provides instructions for the disposition and documentation of plant problems. Plant problems are documented on a Problem Evaluation Request (PER). . The following PERs were evaluated to provide assurance that the disposition did not involve an Unreviewed Safety Question or represent a change to the Technical Specifications.

2.6.4.1 PER 2 1-0874 This PER was written because directions provided to change the plant emergency DC battery charger current limit settings were not made in accordance with an approved process. Directions were provided to change the current limit settings from 125 percent to 110 percent. However, these chargers were tested during startup with current limiting settings at 125 percent. Following further review, it was determined that there was not a problem with revising the charger current limit from 125 percent to 110 percent of rated output. An evaluation was performed which determined that there was sufficient margin in the capacity of the chargers to restore the associated battery from minimum charge state to a fully charged state within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while supplying the continuous loads connected to the distribution bus.

It was concluded from the safety evaluation that the loss of charger function is not an accident initiator and would not increase the probability of an accident previously evaluated in the LBD. Furthermore, revising the charger current limit setting would not increase the consequences of an accident evaluated previously as the safety function to supply the connected load while recharging the associated station battery remains the same.

2.6.4.2 PER 2 2-0171 This PER documented a situation where it was discovered that surveillance procedures for the Standby Gas Treatment System (SBGT) had flow readings being taken in CFM without any compensation for density variations. Analysis had shown that flow under harsh environment conditions would be high enough to trip the overloads on system fans. Following further evaluation, the SBGT flow limiter setpoint was revised.

It was concluded from the safety evaluation that consequences of an accident were not impacted and the new flow limiter setpoint would ensure that the SBGT System would operate within its design envelopes.

2.6.4.3 PER 2 2-01 3 This PER documented a Steam Leakage situation where it was determined that Main Control (MSLC) System 50-minute timer MSLC-RLY-TK/2 may not allow enough time for the outboard main steam lines to depressurize. Following further evaluation, procedures were revised to allow the timer to be reset which would allow adequate time for depressurization.

It was concluded from the safety evaluation that the procedural changes would not increase the probability of occurrence of an accident previously identified. Furthermore, even with the extended depressurization period, all equipment would be bounded by previous analysis and, therefore, there would be no increase in the consequences of an accident evaluated previously in the LBD.

2.6.4.4 PER 2 2-022 This PER was written to document Containment Atmosphere Control (CAC) System operability concerns pertaining to 1) automatic versus manual recycle valve control, 2) controlling CAC recycle flow based on recombiner exit temperature, and 3) validity and accuracy of CAC flow meter readings. Following further evaluation, actions taken included 1) the change of recycle valve control to manual at a constant recycle ratio rather than manually varying the recycle valve to maintain catalyst bed temperatures below 1150 degrees F,

2) changing Service Water (SW) scrubber flow strategy, and 3) considering a change in recycle flow ratio during the long-term, post-accident time period.

It was concluded from the safety analysis that the actions taken would ensure equipment operability during accident conditions such that the consequences of an accident would be mitigated.

Furthermore, analysis results demonstrated that 'he CAC System would function to maintain oxygen levels inside containment below the levels originally reported in the FSAR.

2.6.4.5 PER 2 2-0287 This PER documented a situation where i;t was determined that the Appendix R calculation required certain operator actions to be taken in the event of fires both within the main control room and outside of the main control room. However, these areas had not been provided with the required emergency lighting. Following further evaluation, the decision was made to use portable battery-powered lighting in place of permanently-installed, battery-powered lamps.

I It was lights concluded from the safety analysis that the use of portable would not increase the consequences of an accident since they are mitigation equipment. Furthermore, the portable lighting was shown, by a plant walkdown of all actions required and areas involved, to provide adequate lighting to allow for the performance of necessary actions.

2.6.4.6 PER 2 2-0596 This PER documented a situation where, during the maintenance and refueling outage, an object believed to be a "Brag Rag" was observed to be floating around in the vessel about two-thirds of the way down from the pool surface to the core top. Efforts to retrieve the object were unsuccessful.

It was concluded from the safety evaluation that damage to fuel caused by fuel assembly flow blockage, interference with control rod operation and harmful chemical impacts from the "Brag Rag" were considered to be insignificant.

2.6.4.7 PER 2 2-0702 This PER documented a situation where it was discovered that the as-found settings for the Emergency Diesel Generator Overspeed Trip Time Delay in the electric overspeed trip circuit did not agree with the design settings. Following further evaluation, the decision was made to continue to operate with the time delay relay settings different than indicated on plant drawings until they could be recalibrated.

It was concluded from the safety evaluation that no increase in equipment malfunction would occur with the existing settings because all time delay relay settings in the field were conservative to the required safety functions. Furthermore, all the relays identified provide accident mitigation only (or none at all) and, therefore, changes in the settings would not increase the

.probability of occurrence of an accident.

2.6.4.8 PER 292-074 This PER documented a situation where, during maintenance for Reactor Feedwater (RFW) System flow control valve RFW-FCV-10B, damage to the valve internals was noted. Following further review, the decision was made to continue operation until a new shaft and plug assembly could be obtained, and installed.

It was concluded from the safety evaluation that the probability of the occurrence of an accident would not be increased due to the

degraded condition of the 'low control valve. Furthermore, failures associated with this component remain bounded and would not exceed or change previously evaluated limiting conditions analyzed.

2.6.4.9 PER 2 2-078 This PER documented a situation where switchgear breaker control circuits for Reactor Closed Cooling (RCC) Water System pumps, Reactor Building Outside Air (ROA-HVAC) System fans and Reactor Building Exhaust Air (REA-HVAC) System fans were not provided with proper electrical separation. Following further review, the affected areas were placed on an hourly fire tour until the design discrepancies could be solved.

Xt was concluded from the safety evaluation that, since compensatory conditions were in place, the resulting conditions were equivalent to proper application of electrical separation practices. The compensatory measures consisted of verification of the area fire detection system component operability and an hourly fire tour of the affected areas.

2.6.4.10 PER 2 2-0871 This PER documented a situation where it was determined that Radwaste Building Mixed Air (WMA-HVAC) fans WMA-FN-52A and WMA-FN-52B would trip on Loss of Offsite Power (LOOP) and not automatically restart. These fans provide cooling to the cable spreading room. Following further review, procedures were modified to require a manual restart of these fans following a LOOP.

Zt was concluded from the safety evaluation that, when the cable spreading room exceeds 104 degrees F, the effect on cable ampacity is minimal due to the short duration of the ambient temperature rise until cooling is re-established by manual start of the fans.

Furthermore, there were no operability concerns identified relating to the capability to maintain acceptable temperatures in the area after the fans are manually started.

2.6.4.11 PER 292-0879 This PER, documented a situation where, during a review for subcompartment pressurization of Emergency Core Cooling System (ECCS) pump rooms, it was determined that some penetrations in the common walls between the pump rooms were found to be sealed with silicone foam. The silicone foam was not qualified or rated as a watertight seal by the vendor. Following further review, compensatory measures were established until proper penetration

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seals could be installed in the pump rooms. These measures included manual detection and mitigation of line-crack resultant floods (Operator Tours), and blocking open the water-tight door between the High Pressure Core Spray (HPCS) and Control Rod Drive (CRD) pump rooms.

It was concluded from the safety 'evaluation that the actions to manually detect and mitigate a flooding event are mitigating actions which would neither cause nor increase the probability of occurrence of an accident as previously evaluated in the LBD.

Furthermore, the actions taken of change from automatic mitigation or passive barriers to manual detection and mitigation actions would not increase the consequences of an accident previously evaluated.

2.6.4.12 PER 292-0 84 This PER documented a situation where it was determined that alternate installed pressure gauges for the Residual Heat Removal (RHR) System pumps and the High Pressure Core Spray (HPCS) System pump did not meet the intent of the ASME Code requirement that the full scale range of each instrument shall be three times the reference value or less. Following further review, the decision was made to use TDAS points for these pumps (TDAS points for these instruments are analog signals with digital output and meet .the ASME Code requirements).

It was concluded from the safety evaluation that use of the TDAS instrumentation would provide acceptable accuracy to ensure that the pumps are performing at the required flow and pressure conditions. Therefore, the instrumentation would meet its required design function an no increase in the consequences of an accident previously evaluated would occur.

2.6.4.13 PER 2 2-1029 This PER documented a situation where it was determined that an annunciator circuit was routed between Division 1 and Division 2 safety-related raceways, which violated the direct bridging criterion of the WNP-2 Design Specification for electrical separation. The circuitry involved pertained to High Pressure Core Spray (HPCS) pump room cooler. Service Water (SW) flow and temperature switches SW-FS-27 and SW-TS-27 respectively. Following further review, compensatory measures in the form of fire tours were established until the design deficiency could be resolved.

It was concluded from the safety evaluation that allowing plant operation with the annunciator bridging circuit in place was acceptable because compensatory measures were established. The compensatory measure was to establish an hourly fire tour, thereby, preventing the spread of any localized fire that may occur post-

accident between redundant divisions. Furthermore, the annunciator circuits were routed in control raceway (low energy circuits) which supply only milliamps of current.

2.6.4.14 PER 2 2-1191 This PER documented a situation where wetwell airspace temperatures in excess of 140 degrees F, caused by leaking Main Steam Safety Relief Valves (MSRVs), required increased wetwell spray operation and suppression pool cooling. Following further review, it was determined that continued operation could be allowed pending resolution of the problem.

It was concluded from the safety evaluation that there were no credible mechanisms, as a result of higher wetwell air space temperature, which could increase the probability of an accident.

Furthermore, design limits for containment analysis were not exceeded, assumptions in the FSAR were not changed, operator action and response time were not altered and the equipment involved was qualified for the operating conditions.

2.6.4.15 PER 2 2-1222 This PER documented a situation where Auxiliary Steam (AS) System line break mitigation valves AS-V-68A and AS-V-68B were determined to have a total stroke-to-close time of approximately 21 seconds instead of 20 seconds as specified by design. Following further review, it was determined that there was suf ficient margin to increase the stroke time limit.

It was stroke concluded from the safety evaluation that increasing valve time extends the accident mitigation time and results in an increase in building profile temperatures of approximately five degrees F. However, the increase in area temperature does not affect the. qualification of safety-related equipment required to respond to an accident since the existing qualification envelopes the increase. Furthermore, changing valve closing stroke time would not result in the occurrence of an accident.

2.6.4.16 PER 2 2-1263 This PER documented a situation where samples of Auxiliary Condensate (CO) System return tank CO-TK-1 were determined to contain tritium activity. The immediate disposition was to continue to monitor tritium levels in the Auxiliary Boiler by periodic sampling, the frequency of which would be determined by trending.

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It was concluded from the safety evaluation that operation of the systems as radioactive Auxiliary Boiler and associated steam systems would not alter any assumptions made in previous evaluations of high or moderate energy line breaks, or any other accidents. Therefore, there would be no increase in the probability of occurxence of malfunction of equipment important to safety. In addition, operation of the Auxiliary Boiler and associated steam systems would not be affected by the tritium in the water.

2.6.4.17 PER 2 2-1338 This PER documented a situation where six fuses on branch circuits of E-PP-US were of a size and/or type other than that specified in design documentation. One of the branch circuits supplied power to Class 2+ equipment required under Regulatory Guide 1.97, "Post Accident Monitoring Instrumentation." The remaining circuitry supplied power to non-safety related, Class 2 loads. The immediate disposition was to allow the fuses to remain installed until they could be replaced with the preferred fuses.

It was concluded from the safety evaluation that failure of these fuses to coordinate under fault conditions would not initiate an accident or event. Furthermore, an evaluation of load information indicated that the as-installed fuse on the branch circuit supplying Class 2+ loads was of sufficient size to perform its safety function, and that faults or failures of the Class 2 branch circuits would not impact the operation of equipment important to safety.

2.6.4.18 PER 292-1359 This PER documented that the WNP-2 ATWS Evaluation did not account for the time required for Standby Liquid Control (SLC) storage tank outlet valves SLC-V-1A and SLC-V-1B to stoke open. The original ATWS analysis did not account for valve opening in the time assumed for boron transport from the SLC system to the reactor.

It was concluded from the safety analysis that the delay in boron transport would increase the time to shutdown the reactor during an ATWS. However, the time delay of approximately 30-to-35 seconds would result in no significant increase in accident consequences.

Furthermore, there would be no impact on equipment due to the delay in boron initiation.

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2.6.4.19 PER 2 2-1376 This PER documented a situation where it was determined that 10 fuses were of indeterminate type in instrument rack E-IR-02. The immediate disposition was to allow the fuses to be installed until they could be replaced with the preferred fuses.

It was concluded from the safety evaluation that E-IR-02 is a Class 2 instrument rack of which the branch circuits serve no safety function. Failure of these fuses to properly clear under fault conditions would not initiate an accident or an event.

Furthermore, faults or failures on these Class 2 branch circuits would not impact the operation of equipment important to safety and, therefore, would not increase the consequences of an accident.

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2.6.5 PLANT TESTS AND EXPERIMENTS This section of the report covers WNP-2 Plant tests and experiments not described in the Safety Analysis Report as required by 10CFR50.59.

There were no tests or experiments performed under the provisions of 10CFR50.59 in 1992.

2 6.6 PLANT PROCEDURE CHANGES The Plant Procedure Control Program requires a 10CFR50.59 evaluation whenever a procedure is changed. This provides assurance that the change does not require a change to the.

Technical Specifications or involve an Unreviewed Safety Question.

The following are summaries of significant plant procedure changes that were processed during 1992.

2.6.6.1 Procedure Revision Form for Test Procedure 8.3.227 The procedure for operation of the Residual Heat Removal (RHR)

System in the Fuel Pool Cooling (FPC) assist mode was revised by removing steps for recording data and covering of the ventilation ducts in preparation for core offload. In addition, spool pieces were installed and the commitment was made to run RHR/FPC only during shutdown conditions.

It was concluded from the safety evaluation that these activities do not increase the probability of occurrence of an accident or increase the consequences of an accident previously evaluated in the LBD. Operation of RHR, Loop B, in the FPC assist mode would not cause an accident different from those previously analyzed.

2.6.6.2 Procedure Revision Form for PPM 8.4.70 The procedure for thermal performance testing of room coolers PRA-FC-1A and PRA-FC-1B was revised to enable thermal performance testing of cooling coils in Standby Service Water System pump houses 1A and 1B in response to Generic Letter 89-13. The testing was performed with the respective service water pump in operation to provide cooling water to the coil. To maintain a high pump house temperature during the test, the supply ventilation fan damper setpoints were reset to prevent cold outside air from entering.

It was concluded from the safety evaluation that the ability of the pumps in the pump houses to perform their safety function would not be impacted and, as a result, the consequences of an accident previously evaluated would not be increased. Furthermore, temporary changes in the fan and damper setpoints would not change the existing analysis and, therefore, the probability of an accident was not increased.

2.6.6.3 Pro edure D via ion F rms 2-1208 2-120 and 2-1464 Procedures for performing channel functional testing of the Loose Parts Monitoring Detection system were changed to allow for continued surveillance testing while Channels 1, 2 and 8 were out of service at various intervals.

It was concluded from the safety evaluation that the Loose Parts Monitoring System is a monitoring system with no accident mitigating features and, therefore, would not impact the consequences of an accident. Furthermore, the loss of monitoring capability in three channels would not create a new type of accident.

2.6.6.4 Procedure D viation Form 2-1312 The procedure for operation of the Residual Heat Removal System was modified to increase the value below which wetwell temperature must be maintained due to excessive wetwell airspace temperatures caused by leaking Main Steam Relief Valves.

It was concluded from the safety evaluation, that there were no credible mechanisms, as the result of higher wetwell airspace temperature, which would increase the probability of an accident.

Furthermore, the affected equipment is qualified for the operating conditions and no failures of materials would be anticipated.

2.6.6.5 Procedure Revision Form for PPM 8.3.240 The procedure for motor operated valve differential testing of Residual Heat Removal System (RHR), Loop B, was revised to provide testing instructions for demonstrating that selected motor operated valves would properly operate when required to perform their intended safety function. This testing was being performed in response to Generic Letter 89-10.

It was concluded from the safety evaluation that, since the RHR is used. to mitigate accidents and that the testing would not System establish conditions which exceed any safety system design or operating limits, implementation o f the procedure would not increase the probability of occurrence of an accident evaluated previously in the LBD. Furthermore, the testing would not create a different type of malfunction than previously evaluated in the LBD.

2.6.6.6 Procedure Deviati n Form 2-1106 The procedure for motor operated valve differential pressure testing of the Auxiliary Steam (AS) System was modified to change the required operating mode for testing from Operational Modes 4 and 5, to any mode when heating steam is not required for the reactor building.

It was concluded from the safety evaluation that the test would not change the consequences of a malfunction of equipment important to safety evaluated previously in the LBD. Furthermore, the dynamic stroke testing of the motor operated valves with the AS System operating within system design limits would not create or contribute to a steam line break or introduce any different accidents not evaluated in the LBD.

2.6.6.7 Procedure Revision Form for PPM 8.3.233 This procedure was developed for testing the capability of various Fuel Pool Cooling (FPC) motor operated valves to properly function when subjected to maximum achievable differential pressures. The testing was being performed in response to Generic Letter 89-10.

It was concluded from the safety evaluation that the testing would not increase the consequences of an accident evaluated previously in the LBD. Furthermore, there would be no significant increase in the probability of occurrence of malfunction of equipment important to safety-evaluated previously in the LBD.

2.6.6.8 Procedure Revision Form for PPM .3.11 This procedure was developed to establish a method for determining reactor core flow such that the result may be used to calibrate associated indications and instrumentation.

It was concluded from the safety evaluation that this activity verifies the proper core flow value and implements the correct calibration of the core flow loop. There would be no effect on the probability of occurrence of an accident evaluated previously in the LBD. Furthermore, the only effect of this activity is to ensure a properly calibrated core flow signal. Accordingly, there would be no effect on the probability of occurrence of malfunction of equipment important to safety.

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2.6.6.9 Pro dure R vision Form for PPM 4 12 4 7 The procedure which covers unintentional entry into the region of potential core power instabilities was revised to provide for short-term operating strategies for Cycle 8 following the core instability event that occurred on August 15, 1992. Several recommended operating strategies were described for minimizing the occurrence of core instabilities.

It was concluded from the safety evaluation that the recommended strategies would not increase the consequences of an accident previously evaluated in the LBD because they proposed operation further away from core thermal limits previously evaluated as acceptable in the area of instability susceptibility. Operations with increased margin in critical power ratio, radial peaking, axial peaking and core inlet subcooling (coupled with increased surveillance) would not increase the consequences of an accident.

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2.6.7 FIRE PROTECTION PROGRAM CHANGES The following changes involving the Fire Protection Program are reported in accordance with the NRC Letter Dated May 25, 1989 which approved Amendment No. 67 to the Facility Operating License.

2.6.7.1 SCN 88-030 Revision 2 This SCN provided for the relocation of the material in FSAR Section 9.5.1 (Fire Protection System Description) to FSAR Appendix F (Fire Protection Evaluation). The SCN completes the commitment made to the NRC to "complete the FSAR rewrite to clarify and consolidate commitments covered in FSAR Section 9.5. 1 and Appendix F." (Reference Letter 602-87-129, GC Sorensen to JB Martin, dated April 13, 1987.)

The SCN incorporates a number of changes to the fire protection program description which resulted from outstanding SCNs, from previous changes to the fire protection procedures, or from plant design changes.

It was concluded the fire from the 10CFR50.59 Review that the description of protection program as described in the Licensing Basis Documents was modif ied by this SCN. However, the intent of procedures, processes and commitments in the LBD was not changed, the level of fire protection provided within the plant was not degraded, and the capability to achieve safe post-'fire shutdown was not adversely affected by these changes.

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)a 2.7 REPORT OF DIE EL GENERATOR FAILURES This section contains information regarding diesel generator failures, valid and nonvalid, in accordance with the requirements of WNP-2 Technical Specification 4.8.1.1.3. WNP-2 experienced a total of two valid failures and one nonvalid failure in 1992 for the three emergency diesel generator units.

2.7.1 Identity of diesel generator unit and date of failure.

Division One Emergency Diesel Generator (DG-1)

September 20, 1992 (0147 hours0.0017 days <br />0.0408 hours <br />2.430556e-4 weeks <br />5.59335e-5 months <br />) .

Number designation of failure in last 100 valid tests:

This was the First Failure of the last 100 valid tests. This Failure was determined to be a "Valid" Failure.

Cause of failure:

During the performance of the Technical Specification required monthly surveillance test, Operations was unable to obtain full load on the Division One Diesel Generator. The unit was unloaded and shut down while a trouble shooting plan was developed.

Corrective measures taken:

The problem was ident ified to be a governor actuator that would not respond properly to a signal from the governor controls.

The governor actuators used on tandem diesel engines are a "Matched" set and are calibrated at the factory as a set. The actuators on both diesel engines were replaced with a factory calibrated "Matched" set.

Length of time the diesel generator unit was unavailable:

The Diesel Generator was out of service for 109 hours0.00126 days <br />0.0303 hours <br />1.802249e-4 weeks <br />4.14745e-5 months <br /> and returned to service at 1445 hours0.0167 days <br />0.401 hours <br />0.00239 weeks <br />5.498225e-4 months <br /> on September 23, 1992.

Current surveillance test interval:

Thirty-one days.

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Verification of test interval:

The surveillance test interval of thirty-one days is in conformance with the Technical Specification Requirements and the recommendations of the NRC Regulatory Guide 1.108, position C.2.d.

Identity of diesel generator unit and date of failure:

Division Three Emergency Diesel Generator (DG-3)

September 28, 1992 (0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />).

Number designation of failure in last 100 valid tests:

This was the First Failure of the last 100 valid tests. This Failure was determined to be a "Valid" Failure.

Cause of failure:

During the performance of the Technical Specification required monthly surveillance test, Operations was unable to maintain full load on the Division Three Diesel Generator. The unit would accept load and when the Operator released the governor control switch, the load would begin decreasing without any Operator action. The unit was unloaded and shut down while a trouble shooting plan was developed.

The problem was identified to be a governor control switch in which a cam internal to the switch had come loose. This allowed the "Lower" side of the control switch to be actuated whenever the Operator would release the control switch handle. This caused the load to be reduced on the generator.

Corrective measures taken:

A new switch was installed and the diesel generator unit tested satisfactorily.

Length of time the diesel generator unit was unavailable:

The Diesel Generator was out of service for 70 1/2 hours and returned to service at 0023 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> on October 1, 1992.

Current surveillance test interval:

Thirty-one days.

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Verification of test interval:

The surveillance test interval of thirty-one days is in conformance with the Technical Specification Requirements and the recommendations of the NRC Regulatory Guide 1.108, position C.2.d.

Identity of diesel generator unit and date of failure:

Division Two Emergency Diesel Generator (DG-2)

November 30, 1992 (0914 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.47777e-4 months <br />).

Number designation of failure in last 100 valid tests:

This was the First Failure of the last 100 valid tests. This test was determined to be a nonvalid failure.

Cause of failure:

During the performance of the Technical Specification'equired monthly surveillance test, the Division Two Diesel Generator failed to obtain nominal voltage within the required ten seconds.

The unit did obtain rated voltage in approximately 16 seconds without any Operator intervention.

Corrective measures taken:

The normal troubleshooting procedures were implemented, which included subsequent test runs (three fast starts).

The event did not repeat itself during the testing. A decision was made to replace the voltage regulator because it was found out of calibration. All other apparent causes for the failure to achieve the required voltage were eliminated. The Diesel Generator retested satisfactorily and was returned to service.

Length of time the diesel generator unit was unavailable:

The Diesel Generator was out of service for 87 hours0.00101 days <br />0.0242 hours <br />1.438492e-4 weeks <br />3.31035e-5 months <br /> and returned to service at 0021 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> on December 4, 1992. A waiver of compliance was requested and granted from the NRC for an extension of the action statement.

Current surveillance test interval:

Thirty-one days.

Verification of test interval:

The surveillance test interval of thirty-one days is in conformance with the Technical Specification Requirements and the recommendations of the NRC Regulatory Guide 1.108, position C.2.d.

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