ML18151A207

Evaluation of Potential Severe Accidents During LOW Power and Shutdown Operations at Surry,Unit 1.Analysis of Core Damage Frequency from Internal Events During Mid-Loop Operations.Appendices A-D

ML18151A207
Person / Time
Site:	Surry
Issue date:	06/30/1994
From:	Dennis Bley, Bozoki G, Chu T, Dang V, Diamond D, Holmes B, Caroline Hsu, Ilberg D, Dante Johnson, Kohut P, Lin J, Musicki Z, Nathan Siu, Su R, Wong S, Yang J AEA TECHNOLOGY, BROOKHAVEN NATIONAL LABORATORY, MASSACHUSETTS INSTITUTE OF TECHNOLOGY, CAMBRIDGE, PLG, INC. (FORMERLY PICKARD, LOWE & GARRICK, INC.), SOREQ NUCLEAR RESEARCH CENTER, YAVNE, ISRAEL
To:	NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES)
References
CON-FIN-L-1922 BNL-NUREG-52399, NUREG-CR-6144, NUREG-CR-6144-V02P2, NUREG-CR-6144-V2-P2, NUREG-CR-6144-V2P2, NUREG-CR-6144-V2PT2, NUDOCS 9408150192
Download: ML18151A207 (460)

Text

NUREG/CR-6144 BNL-NUREG-52399 Vol. 2, Part 2 Evaluation of Potential Severe Accidents During Low Power and Shutdown Operations at Surry, Unit 1 Analysis of Core Damage Frequency from ernal Events During Mid-Loop Operations Appendices A - D Prepared by T. L. Chu, Z. Musicki, P. Kohut, D. Bley, J. Yang, B. Holmes, G. Bozoki, C. J. Hsu, D. J. Diamond, D. Johnson, J. Lin, R. F. Su, V. Dang, D. Ilberg, S. M. Wong, N. Siu Brookhaven National Laboratory Prepared for U.S. Nuclear Regulatory Commission 9408150192 940630 PDR ADOCK 05000280 P - -

- - - '~ - - -

PDR

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• NUREG/CR-6144 BNL-NUREG-52399 Vol. 2, Part 2 Evaluation of Potential Severe Accidents During Low Power and Shutdown Operations at Surry, Unit 1 Analysis of Core Damage Frequency from Internal Events During Mid-Loop Operations Appendices A - D Manuscript Completed: January .1994 Date Published: June 1994 Prepared by T. L. Chu, Z. Musicki, P. Kohut, D. Bley1, J. Yang, B. Holmes2, G. Bozoki, C. J. Hsu, D. J. Diamond, D. Johnson 1, J. Lin 1, R. F. Sus, V. Dangs, D. Ilberg4, S. M. Wong, N. Siu3 Brookhaven National Laboratory Upton, NY 11973 Prepared for Division of Safety Issue Resolution Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 NRC FIN L1922 G Inc., 4590 MacArthur Boulevard, Newport Beach, CA 92660-2027

~A Technology, Winfrith, Dorchester, Dorset, England, DT2 8DH MIT, Cambridge, MA 02139 (N. Siu currently at EG&G, Idaho Falls, ID 83415) 4 Soreq Nuclear Research Center, Yavne 70600, Israel

ABSTRACT Traditionally, probabilistic risk assessments (PRA) of severe accidents in nuclear power plants have considered initiating events potentially occurring only during full power operation. Some previous screening analyses that were performed for other modes of operation suggested that risks during those modes were small relative to full power operation. However, more recent studies and operational experience have implied that accidents during low power and shutdown could be significant contributors to risk.

During 1989, the Nuclear Regulatory Commission (NRC) initiated an extensive program to carefully examine the potential risks during low power and shutdown operations. The program includes two parallel projects being performed by Brookhaven National Laboratory (BNL) and Sandia NationalLaboratories (SNL).

Two plants, Surry (pressurized water reactor) and Grand Gulf (boiling water reactor), were selected as the plants to be studied.

The objectives of the program are to assess the risks of severe accidents initiated during plant operational states other than full power operation and to compare the estimated core damage frequencies, important accident sequences and other qualitative and quantitative results with those accidents initiated during full power operation as assessed in NUREG-1150. The scope of the program includes that of a level-3 PRA.

The objective of this volume of the report is to document the approach utilized in the level-1 internal events PRA for the Surry plant, and discuss the results obtained. A phased approach was used in the level-1 program. In phase 1, which was completed in Fall 1991, a coarse screening analysis examining accidents initiated by internal events (including internal fire and flood) was performed for all plant operational states (POSs). The objective of the phase 1 study was to identify potential vulnerable plant configurations, to characterize (on a high, medium, or low basis) the potential core damage accident scenarios, and to provide a foundation for a detailed phase 2 analysis.

In phase 2, mid-loop operation was selected as the plant configuration to be analyzed based on the results of the phase 1 study. The objective of the phase 2 study is to perform a detailed analysis of the potential accident scenarios that may occur during mid-loop operation, and compare the results with those of NUREG-1150. The scope of the level-1 study includes plant damage state analysis, and uncertainty analysis.

Volume 1 summarizes the results of the study. Internal events analysis is documented in Volume 2. It also contains an appendix that documents the part of the phase 1 study that has to do with POSs other than mid-loop operation. Internal fire and internal flood analyses are documented in Volumes 3 and 4. A separate study on seismic analysis, documented in Volume 5, was performed for the NRC by Future Resources Associates, Inc. Volume 6 documents the accident progression, source terms, and consequences analysis.

In the phase 2 study, system models applicable for shutdown conditions were developed and supporting thermal hydraulic analysis were performed to determine both the timing of the accidents and success criteria for systems. Initiating events that may occur during mid-loop operations were identified and accident sequence event trees were developed and quantified. In the preliminary quantification of the mid-loop accident sequences, it was found that the decay heat at which the accident initiating event occurs is an important parameter that determines both the success criteria for the mitigating functions and the time available for operator actions. In order to better account for the decay heat, a "time window" approach was

• iii NUREG-CR/6144

developed. In this approach, time windows after shutdown were defined based on the success criteria

• established for the various methods that can be used to mitigate the accident. Within each time window, the decay heat and accident sequence timing are more accurately defined and new event trees developed and quantified accordingly. Statistical analysis of the past outage data was performed to determine the time at which a mid-loop condition is reached, and the duration of the mid-loop operation. Past outage data were used to determine the probability that an accident initiating event occurs in each of the time windows. This probability is used in the quantification of the accident sequences.

The mean core damage frequency of the Surry plant due to internal events that may take place during mid-loop operations is SE-06 per year, and the 5th and 95th percentiles are SE-07 and 2E-05 per year, respectively. This can be compared with the mean core damage frequency from internal events of 4E-05 per year estimated in the NUREG-1150 study for full power operations.

NUREG/CR-6144 iv

Contents Appendix A Data Base of Plant Experience Identified For Initiating Event Quantification Appendix B Review of U.S. Nuclear Regulatory Commission (NRC) Information Notices, Generic Letters, Bulletins and Circulars Appendix C System Fault Trees Appendix D Statistical Analysis of Time to Mid-Loop and Duration of Mid-Loop V NUREG/CR-6144

FOREWORD (NUREG/CR-6143 and 6144)

Low Power and Shutdown Probabilistic Risk Assessment Program Traditionally,probabilisticrisk assessments (PRA) of severe accidents in nuclear power plants have considered initiating events potentially occurring only during full power operation. Some previous screening analysis that were performed for other modes of operation suggested that risks during those modes were small relative to full power operation. However, more recent studies and operational experience have implied that accidents during low power and shutdown could be significant contributors to risk.

During 1989, the Nuclear Regulatory Commission (NRC) initiated an extensive program to carefully examine the potential risks during low power and shutdown operations. The program includes two parallel projects performed by Brookhaven National Laboratory(BNL) and Sandia National Laboratories(SNL), with the seismic analysis performed by Future Resources Associates. Two plants, Surry (pressurized water reactor) and Grand Gulf (boiling water reactor), were selected as the plants to be studied.

The objectives of the program are to assess the risks of severe accidents due to internal events, internal fires, internal floods, and seismic events initiated during plant operational states other than full power operation and to compare the estimated core damage frequencies, important accident sequences and other qualitative and quantitative results with those accidents initiated during full power operation as assessed in NUREG-1150.

The scope of the program includes that of a level-3 PRA.

The results of the program are documented in two reports, NUREG/CR-6143 and 6144. The reports are organized as follows:

For Grand Gulf:

NUREG/CR-6143 - Evaluation of Potential Severe Accidents during Low Power and Shutdown Operations at Grand Gulf Volume 1: Summary of Results Volume 2: Analysis of Core Damage Frequency from Internal Events for Operational State 5 During a Refueling Outage Part 1: Main Report Part 1A: Sections 1 - 9 Part 1B: Section 10 Part lC: Sections 11 - 14 Part 2: Internal Events Appendices A to H Part 3: Internal Events Appendices I and J Part 4: Internal Events Appendices K to M Volume 3: Analysis of Core Damage Frequency from Internal Fire Events for Plant Operational State 5 During a Refueling Outage Volume 4: Analysis of Core Damage Frequency from Internal Flooding Events for Plant Operational State 5 During a Refueling Outage Volume 5: Analysis of Core Damage Frequency from Seismic Events for Plant Operational State 5 During a Refueling Outage vii NUREG/CR-6144

Foreword (continued)

Volume 6: Evaluation of Severe Accident Risks for Plant Operational State 5 During a Refueling Outage Part 1: Main Report Part 2: Supporting MELCOR Calculations For Surry:

NUREG/CR-6144- Evaluation of Potential Severe Accidents during Low Power and Shutdown Operations at Surry Unit-1 Volume 1: Summary of Results Volume 2: Analysis of Core Damage Frequency from Internal Events during Mid-loop Operations Part 1: Main Report Part lA: Chapters 1 - 6 Part 1B: Chapters 7 - 12 Part 2: Internal Events Appendices A to D Part 3: Internal Events Appendix E Part 3A: Sections E.1 - E.8 Part 3B: Sections E.9 - E.16 Part 4: Internal Events Appendices F to H Part 5: Internal Events Appendix I Volume 3: Analysis of Core Damage Frequency from Internal Fires during Mid-loop Operations Part 1: Main Report Part 2: Appendices Volume 4: Analysis of Core Damage Frequency from Internal Floods during Mid-loop Operations Volume 5: Analysis of Core Damage Frequency from Seismic Events during Mid-loop Operations Volume 6: Evaluation of Severe Accident Risks during Mid-loop Operations Part 1: Main Report Part 2: Appendices NUREG/CR-6144 viii

APPENDIX A

• DATA BASE OF PLANT EXPERIENCE IDENTIFIED FOR INITIATING EVENT QUANTIFICATION A-1

Appendix A Data Base of Plant Experience Identified for Initiating Event Quantification

~

A.1 One Line Summary of All Events in the Data Base .. _................................. A-3 A.2 Descriptions of Events Used in the Quantification .................................. A-18 A.2.1 Loss of RHR Events (RHR2A, 2B, 3, 4, 5, 6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-19 A.2.2 Loss of 4 kV Bus (4 kV, 4 kV/P6) ............................................. A-45 A.2.3 Loss of Vital Bus (VITAL) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-53 A.2.4 Loss of Component Cooling Water (CCW) ...................................... A-60 A.2.5 Inadvertent Safety Feature Actuation (ESFAS, ESPAS/SI) . . . . . . . . . . . . . . . . . . . . . . . . . . . A-62 A.2.6 Loss of Instrument Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-69 A.2.7 LOCAs (HCVCS, HRHR, JCVCS, JRHR, KRCS) ................................ A-75 A.2.8 Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-80 A-2

• Appendix A.1 One Line Summary of All Events in the Data Base

• A-3

Page No. 08/18/93 PHASE 2 - LOSS OF RESIDUAL HEAT REMOVAL YHILE AT SHUTDO\/N FOR PYRS INITIAL SEA-PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 Le~* NUREG APPL!-

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOD *. CAT CAT SEARCH 1410 CABIL.

---

*****------------------------------------------------------~---------------------------------------------------- --~---------------------------~------

Byron 1 5000454 07/24/85 85-070-1 Mcide 1 A-10 NA2 2 Davis Besse 1 5000346 06/05/78 78-063 Mode 5 A.7 E27 NA2 3 Maine Yankee 5000309 09/29/82 82-032 Mooe 6 A-10 NA2 4 McGuire 1 5000369 02/07/81 81-010 Mode 6 A.5 E11 NA1,2 5 Palisades 5000255 06/22/84 84-007 Mode 5 A-1 NA2 6 Rancho Seco 5000312. 05/26/83 83-023

• Mode 6 A-10 NA2 7 Rancho Seco 5000312 07/25/89 009 . Mode 5 1 hr 26 min 98 NA2 8 Salem 1 5000272 05/20/89 019 zero power 58 min 33 3.51 NA2 9 Three Mile Island 5000320 09/08/77 Mode 4 and 5 A.9 E40 NA1 10 Zion 1 5000295 09/10/82 82-028 Mode 1 Not actual A-4 NA2 failure 11 Zion 1 5000295 11/16/82 82-042 Mode 1 Not actual A-4 l,lA2 I

failure

.p.. 12 Zion 1 5000295 06/09/83 83-018 *Hot or cold Not actual A-4 NA2 shut. failure 13 3b 3b Braidwood 2 5000457 03/18/90 002 zero power 10 min 231 14 3b 3b Callaway 1 5000483 07/17/84 84-016 Mode 5 A-3 D.2 15 3b 3b Glnna 5000244 03/07/84 84-003 Mode 5 A-3 B.1 NA3 16 3b 3b Maine Yankee 5000309 03/24/82 82-013

• Mode 5 A-3 17 3b 3b McGuire 2 5000370 09/05/89 010 Mode 5 2 hr 51 min 179 18 3b 3b Rancho Seco 5000312 04/19/81 81-024 Mode 5 A.3 Da6 19 3b 3b Sequoyah 1 5000327 02/01/87 013 Mode 5 124 20 3b 3b St. Lucie 1 5000335 11/03/78 78-041 Mode 5 3.7 hr A.3 Db1 21 4KV 6b Arkansas Nuclear 1 5000313 12/05/89 040, 1 of 2 CSD 103 events 22 4KV 6b Afkansas Nuclear 1 5000313 12/06/89 040, 2 of 2 . CSD 9 min 103:

events 23 4KV 6b Arkansas Nuclear 2 5000368 11/14/89 022 Shutdown 1 min 171 24 4KV 4 Beaver Valley 1 5000334 07/03/79 79-018 Mode 5 or 6 21 min A.6 E20 25 4KV 511 Beaver Valley 1 5000334 06/29/83 83-020 Mode 6 92 sec A-6 AEOD-A. E10 NA,1 26 4KV Sb Catawba 1 5000413 01/07/89 001 Mode 5 193 27 4KV 611 Crystal River 3

• 5000302 08/28/89 031 Mode 5 19 min 77 28 4KV 6b Davis Besse 1 5000346 05/28/78 78-060 Mode 6 1.5 min A.6 AEOD-C E15

'1

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• LOSS OF RESIDUAL HEAT REMOVAL ~HILE AT SHUTD~N FOR P~S INITIAL SEA*

PHASE 2 sss EVENT PLANT RECOVERY . NSAC52 BROOK CR5015 Gl99 LER NUREG APPL!*

CAT CAT PLANT NAME DOCKET NO DATE LER *-CONDITION TIME CAT. CAT. AEOO *CAT CAT SEARCH 1410 CABIL.

29 4KV 6b Davis Besse 1 5000346 06/15/78 78-067 Cold shut. 2 min (total of A.6 AEOO*C E16 3 events) 30 41CV 6b Ft. Calhoun 5000285 12/14/85 85-011 Refueling 15 min i:.5 shut.

31 4KV 6b HcGuf re 1 5000369 11/29/88 038 zero power 174 32 4KV 6b Millstone 2 5000336 12/09/81 81*043 Mode 5 30*60 min A.6 E25 33 4KV 6b North Anna 1 5000338 03/23/39 006

• Mode 5 10 sec 150 34 4KV 6b. North Anna 1 5000338 04/16/89 010 .. Mode 5 151 35 4KV 6b North Anna 2 5000338 04/16/89 010, inferred Mode 5 151 from LER 36 4KV Rancho Seco 5000312 12/08/86 86-030

• Mode 5 A*1 A;4 37 4KV 2b Salem 1 5000272. 04/24/79 79-059 Mode 6 2 min (second A.6 E18

!l>

I event on V,

05/08/79) 38 4KV 2b Salem 1 5000272 05/08/79 79-059 Mode 6 4 min (1st A.6 E18 event on 04/24/79) 39 4KV 10 Salem 1 5000272 03/16/82 82-015 45 min AEOD*A E2 40 4KV 1 Salem 2 5000311 12/20/83 83-066 Mode 5 22 min A*1 AEOO*A A7 41 4KV 6b Surry 1 5000280 05/24/86 86*017 Mode 6 A*6 i:_.3 42 4KV 6b Three Mlle Island 5000289 01/09/87 001 .Refueling 64 shutdown 43 4KV 6b llolf Creek 10/16/87 17 min 1.34 44 4KV/P6 4 Calvert Cliffs 1 5000317 11/12/80 80-058 Mode 5 or 6 10 min A.4 E6 45 4KV/P6 Diablo Canyon 1 5000275 01/25/85 85-006 . Mode 5 2 min A*1 A.6 46 4KV/P6 6b Fiirley 1 ~000348 . 01/16/81 81*001 . Shutdown 1 min A.6 E23 47 4KV/P6 6b North Anna 2 5000339 04/08/83 83*031 Mode 5 A*6 48 4KV/P6 6b Salem 1 5000272 01/04/83 83*001 Hodes 4 and A-6 A12 5

49 4KV/P6 6b Salem 2 5000311 04/13/83 83-014, 1 of 2 Mode 5 < 1 min A*6 events 50 4KV/P6 6b Salem 2 ' 5000311 04/18/83 83*014, 2 of 2 Mode 5 < 1 min A*6 events

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PHASE 2 sss EVENT PLANT RECOVERY NSAC52 *BROOK CR5015 GI99 LER *. NUREG APPll

• CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT, CAT. AEOO. CAT CAT SEARCH 1410 CABIL,

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*------------------------------------------------------ .----------------*---~------~-----*

51 4~/P6 6b Surry 1 5000280 02/04/89 005, Unit 2

• Mode 5 3 min 44 event also 52 4KV/P6 6b Surry 1 5000280 04/06/89 010, Unit 2 Mode 5 1 min 47 event also 53 4KV/P6 6b Surry 2 5000280 02/04/89 005 (descr In Mode 5 44 Surry 1) 54 4KV/P6 6b Surry 2 5000280 04/06/89 010 (descr in Mode 5 1 min 47 Surry 1) 55 4~/P6 6b Zion 2 5000304 01/17/86 86-005*1 Mode 5 A-6 E.9 56 AIR Beaver Valley 1 5000334 08/29/85 85-015 Mode 1 10 min 12 57 AIR Callaway 5000483 11/05/84 84-059 . Mode 1 20 min 35 58 AIR Calvert Cliffs 1 5000317 01/27/87 87-003 Mode 1 20 min 2 59 AIR Catawba 1 5000413 01/14/85 85-004 . Mode 2 15 min 51 60 AIR Cook 1 5000315 11/25/85 NPE Mode 1 20 min 2969

~ 61 AIR Davis Besse 1 5000346 12/07/87 87-015 Mode 1 31 min 62

°' 62 AIR McGuire 1 5000369 11/02/85 85-034 Mode 1 20 min 179 63 AIR Ml l lstone 3 5000423 04/12/87 87-020 Mode 1 20 min 64 AIR 10 North Anna 2 5000339 04/03/89 89-007 Mode 6 22 min 153 . NA.*

65 AIR Oconee 3 5000287 08/14/84 84*005 Mode 1 20 min 1 66 AIR Prairie Island 1 5000282 05/08/85 85-009 Mode 1 20 min 246 67 AIR Shearon Harris 1 5000400 08/04/87 87-041 . Mode 1 20 min 245 68 AIR Surry 1 5000280 01/07/86 86-001 Mode 1 10 min 287 69 AIR Yankee Rowe 5000029 10/04/86 86-012 Mode 1 10 min 305 70 cc" 10 Braidwood 1 5000456 01/21/87 011 zero power 14 min 226' 71 CCII 10 Byron 1 5000454 04/08/87 012 zero power 17 min 222 72 ccw 10 Maine Yankee 5000309 06/02/81 81-007 Mode 6 30 min A.10 E47 73 cc" 10 Salem 2 5000311 06/23/83 83-032 AEOO*A* ES NA 74 CCII 10 Turkey Pol nt 3 5000250 10/07/83 83-018 AEOO*A . E1 75 OIL TRANS Surry 2 281 10/25/89 015 CSD 76 ESFAS 6b Arkansas Nuclear 2 5000368 04/23/88 007 Mode 5 5 min 168' N'A3 77 ESFAS 4 Calvert cliffs 1 5000317 05/07/79 79-015 Shutdown 15 min . A.4 ES NA3 78 ESFAS 4 Calvert Cl lffs 1' 5000317 11/03/80 80-062

• 2 of 3 Mode 6

• A.4 E7 NA3 events

Page No. 4 08/18/93 e

PHASE 2 - LOSS OF RESIDUAL HEAT REMOVAL YHILE AT SHUTDOIIN FOR PYRS INITIAL SEA-PHASE 2 sss EVEHT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 LER, NUREG APPLI -

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOO CAT

• CAT SEARCH 1410 CABIL, 79 ESFAS 4 Calvert Cliffs 5000317 11/03/80 80-062 - 1 of 3

• Mode 6

• A,4 E7 NA3.

events 80 ESFAS 4 Calvert Cliffs 5000317 11/04/80 80-062 - 3 of 3 Mode 6 A,4 E7 NA3 events 81 ESFAS 4 Calvert Cliffs 2 5000318 09/24/78 78-033

• Mode 5 or 6 23 min A.4 E4 NA3 82 ESFAS 4 Calvert Cliffs 2 5000318 01/07/83 83-005 9 min AEOO-A EB 1 NA3 83 ESFAS 6b Cook 1 5000315 09/07/85 85-046 Mode 5 2 min A-1 E.10 84 ESFAS 1 Davis Besse 5000346 05/14/77 77-006 AEOO-C .

85 ESFAS Davis Besse 5000346 05/19/77 77-007 AEOO-C 86 ESFAS Davis Besse 5000346 05/27/77 77-002 AEOO-C.

87 ESFAS Davis Besse 5000346 05/28/77 77-003 AEOO-C.

88 ESFAS Davis Besse 5000346 06/12/77 77-005 AEOO-C .

> 89 ESFAS Davis Besse 1 5000346 04/19/80 80-029 Mode 6 2 hr 30 min . A,1, A.4 AEOO-C A11, I

-..J E1 90 ESFAS 4 Davis Besse 1 5000346 06/14/80 80-049 Mode 6 2 min A.4 AEOO-C E2 91 ESFAS Davis Besse 1 5000346 07/24/80 80-058, 1 of 2 Mode 5 50 min .A.1 AEOO-C A14 events 92 ESFAS Davis Besse 1 5000346 07/24/80 80-058, 2 of 2 Mode 5 2 min .A.1 AEOO-C. A15 events 93 ESFAS Davis Besse 1 5000346 08/01/80 80-058, 8/3/80 Mode 5 3 min A.1 A16 in descrlp 94 ESFAS Davis Besse 1 5000346 08/13/80 80-060 Mode 5 5 min A.1 AEOO-C A17 95 ESFAS 1 Dlablo Canyon 1 5000275 09/08/86 86-012 Mode 5 2 min A-1 A.7 96 ESFAS Farley 1 5000348 09/18/78 78-069 .Mode 5 7 min . A.1 A6 97 ESFAS North Anne 5000338 11/06/79 79-145 Mode 6 5 min A,1 A9 98 ESFAS Selem 1 5000272 09/02/76 76-004 .Mode 6 19 min *A.1 A1 99 ESFAS 6b Selem 2 5000311 06/23/83 83-031, 2 of 2 Mode 5 A-6 AEOO-A E4 events 100 ESFAS 6b Selem 2 5000311 06/23/83 83-031, 1 of 2 Mode 5 A-6 AEOO-A E4 events 101 ESFAS Sequoyah 5000327 09/16/82 82-116 Mode 5 6 min A-1 AEOO-A A13 102 ESFAS Sutmer 5000395 10/02/84 84-044 Mode 5 frrmediately A-1 . A.18 103 ESFAS LTOP Surry 1 280 11/13/84 023 Refueling SD NA

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PHASE 2 sss EVENT RECOVERY NSAC52 BROOK CR5015 Gl99 LER: NUREG APP.LI*

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT, AEOD CAT CAT SEARCH 1410 CABIL,

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**----------------------------------------------------------------------------------------~

104 ESFAS 4 Surry 2 281 08/18/89 004 0%, Unit 2 384*.

csi>

105 ESFAS Trojan 5000344 03/20/78 78*010 Mode 5 ,;., 1 A4 106 ESFAS/SI LTOP Surry 1 280 04/26/80 024 CSD Maintenance 107 ESFAS/SI TRANS Surry 1 280 03/01/84 005; loss of 2 CSD vital bus*

108 ESFAS/SI LTOP Surry 1 280 11/16/84 024

• Refueling so 109 ESFAS/SI LTOP Surry 1 280 05/11/86 014 ** Shutdown 110 ESFAS/SI LTOP Surry 1 280 06/05/89 022 CSD 111 ESFAS/SI LTOP Surry 2 281 06/12/85 007 Refueling SD 112 ESFAS/SI LTOP Surry 2 281 11/16/86 016 CSD lf' 113 ESFAS/SI 4 Surry 2 281 09/08/89 005 0%; Unit 2 385*

CX>

cso 114 HCVCS HCVCS Turkey Point 3 250 01/15/88 002

• _being cooled

down 115 HRHR HRHR Catawba 1 413 06/11/90 013 CSD (Mode 5) 116 HRHR HRHR Sequoyah 1 327 02/11/81 021 *.A.3 Db2 117 HRHR HRHR Sequoyah 2 328 08/06/81 094 A.3,A.4 E3 NA1 118 JCVCS JCVCS Robinson 2 261 01/29/81 005 119 JCVCS *JCVCS llaterford. 3 382 12/16(85 057 pl_nt heatup 120 JCVCS JCVCS Yankee Rowe 029 06/27/86 010 Mode 5, D, 1 Malnt Out 121 JRHR JRHR Braidwood 1 456 03/25/88 008 OX power l~vel 122 JRHR JRHR Braidwood 1 456 12/01/89 016 9X power level 123 JRHR JRHR McGuire 2 370 08/05/84 017 OX power level 124 JRHR JRHR Surmer 1 395 05/06/85 014 .* CSD (Mode 5) A.20 125 KRCS KRCS North Anna 1 338 06/17/87 014 *OX power, refuel.

126 KRCS KRCS Trojan 344 07/03/81 013_

Page No. 6 08/18/93 PHASE '2

• LOSS OF RESIDUAL HEAT.REMOVAL WHILE AT SHUTD~N FOR PWRS INITIAL SEA*

PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 LEl1 NUREG APP.LI*

CAT CAT PLANT NAME DOCKET NO DATE LER ~ONDITION TIME CAT. CAT. AEOD CAT CAT SEAR~H 1410 *cA~~L.

127 LOOP Connecticut Yankee 5000213 08/24/84 84-014 oi power 20 min E.1 LOOP 128 LOOP Ft. Calhoun 1 5000285 03/21/87 008 Refueling 40 min 53 LOOP cond.

129 LOOP Indian Point 3 5000286 ..

11/16/84 84-015 Mode 5 "E;6 LOOP 130 LOOP McGuire 1 5000369 09/16/87 021 zero power 29 min 173 LOOP 131 LOOP 6b Oconee 3 5000287 09/11/88 005 Mode 5 15 min 62 1.35 132 LOOP 6b Selem 1 5000272 06/02/84 84-013, 1 of 2 Mode 6 30 sec A-6 E.2 events 133 LOOP 6b Selem 2 5000272 06/02/84 84-013, 2 of 2 Mode 5 30 sec . A-6 .E.2 events 134 LOOP Sen Onofre 1 5000206 04/22/80 80*015 Mode 5 4 min A.6 E21 LOOP 135 LOOP 2b Vogtle 1 5000424 03/20/90 006 Refueling 36 min 207

i,. outage Ji 136 RHR1 Beaver Valley 1 5000334 05/21/80 80-031 Mode 5 A.1 A12 137 RHR1 Braidwood 2 5000457 02/23/89 001 zero power 43 min 230*

138 RHR1 Calvert Cliffs 1 5000317 10/12/83 83-061 Mode 6 30 min A-1 AEOD*A A9 139 RHR1 Calvert Cliffs 1 10/23/83 40 min 3.23 140 RHR1 1 Calvert Cliffs 1 5000317 03/22/86 86-002 Mode 5 1 min

• A.13 141 RHR1 1 Calvert Cliffs 2 5000318 10/22/79 79-038 Mode 5 3 min A.1 A8 142 RHR1 Catawba 1 5000413 08/15/86 86-044*1 Mode 5 15 min A-1 A.21 143 RHR1 1 Crystal River 3 5000302 03/06/80 80-015 Mode 5 8 min A.1 A10 144 RHR1 1 Crystal River 3 5000302 10/23/88 022 . Mode 5 74 145 RHR1 Davis Besse 5000346 07/22/77 77-009 (two AEOD*C events) 146 RHR1 Devis Besse 5000346 08/08/80 80-058 3 min AEOD*C 147 RHR1 Davis Besse 1 5000346 05/28/80 80-043 Mode 6 2 min A.1 AEOO*C A13 148 RHR1 Dlablo Canyon 1 5000275 09/29/81 84-004 Hodes 4/5/6 5 min A-1 149 RHR1 Dlablo Canyon 1 5000275 10/27/83 84-004 Hodes 4/5/6 1 hr A-1 150 RHR1 Dleblo Canyon 1 5000275 01/20/85 85-005 Mode 5 9 min A-1 A.5 151 RHR1 Farley 1 5000348 09/18/78 78-069 Mode 5 3 min A.1 A6 152 RHR1 Farley 1 5000348 11/28/80 80-077 Mode 5 4 min A.1 A18 153 RHR1 Farley 1 5000348 12/25/80 80-080 Mode 6 5 min A.1 A19 154 RHR1 Farley 1 5000348 05/06/85 85-008 Mode 5 47 min A-1 A.16

Page No. 7 08/18/93 PHASE 2

• LOSS OF RESIDUAL HEAT REMOVAL ~HILE AT SHUTD~N FOR P~RS INITIAL SEA*

PHASE 2 sss EVENT PLA,NT RECOVERY NSAC52 BROOK CR5015 Gl99 LER NUREG APPll*

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOO . . CAT CAT SEAR¢H 1410 CABIL.

155 RHR1 Ft. Calhoun 1 5000285 01/08/89 001 Refueling 5 min 59 cond.

156 RHR1 Indian Point 3 5000286 09/30/76 76-3-36(A) Mode 5 8 min A.1 A3 157 RHR1 McGuf re 1 5000369 04/27/81 81-072 Mode 5 15 min A.1 A21 . NA1 158 RHR1 McGuf re 1 5000369 08/04/81 81-129 Mode 5 15 min A.1 A22 NA1**

159 RHR1 McGuire 1 5000369 11/18/81 81-185 Mode 5 22 min A.1 A23 NA1 160 RHR1 McGuire 2 5000370 01/15/84 84-002 Mode 5 49 min A*1 AEOD-B A.17 161 RHR1 North Anna 2 5000339 04/23/80 80-001

• Mode 6 A.1 A11+ NA1 162 RHR1 North Anne 2 5000339 04/14/83 83-023 Mode 6 < 1 min A-1 AEOO-A A17 163 RHR1 Rancho Seco 5000312 08/08/85 85-016 Mode 5 *A.10 164 RHR1 Rancho Seco 5000312 08/14/85 85-016 Mode 5 A.10 165 RHR1 Rancho Seco 5000312 07/15/87 038 Mode 5 40 min 93

r.... 166 RHR1 167 RHR1 Rancho Seco Selem 1 5000312 5000272 02/28/89 09/20/76 002 76-005 Mode 5

• Mode 5 10 min 30 min A.1 A2 97 0

168 RHR1 Selem 2 5000311 05/14/83 83-024, 2 of 2 AEOO*A AS events 169 RHR1 Selem 2 5000311 02/09/84 84-002 Mode 5 17 min A-1 AEOO*B A.9 170 RHR1 Seabrook 1 5000443 10/11/89 012 zero power 50 min 217. NA1 171 RHR1 Sequoyah 1 5000327 05/14/85 85-020 Mode 5 16 min A-1 A.15 172 RHR1 Shearon Harris 1 5000400 10/15/87 060 Mode 5 5 min, 15 min 185.

173 RHR1 Shearon H~rrfs 1 5000400 12/10/89 022 Mode 5 3 min 186, 174 RHR1 St. Lucie 1 5000335 03/29/83 83-021 10 min A-1 AEOO*A A14 175 RHR1 Sumier 5000395 09/16/82.82-002 A-1 176 RHR1 Sumier 5000395 10/15/82 82-004 Mode 5 1 min A-1 177 RHR1 turkey Point 3 5000250 10/08/83 83-019 Mode 6 6 min A-1 AEOO*A A2 178 RHR1 Turkey Point 3 5000250 10/25/85 85-036 Mode 5 27 min A-1 A.1 179 RHR1 Turkey Point 3 5000250 11/21/88 029 cold 4 min 16 shutdown 180 RHR1 Turkey Point 4 5000251 11/28/81 81-015, 1 of 2 Mode 5 2 min A.1 A24 events 181 RHR1 Turkey Point 4, 5000251 11/29/81 81-015, 2 of 2

• H*ode 5 1 min A.1 A25 events 182 RHR1 Turkey Point 4 5000251 11/30/84 84-027 Mode 6 4 min A-1 A.2

Page No. 8 08/18/93 PHASE 2 - LOSS OF RESIDUAL HEAT. REMOVAL \./HILE AT SHUTDO\.IN FOR P\.IRS INITIAL SEA-PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 LER. NUREG APPL!*

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME . CAT. CAT. AEOO CAT CAT SEARrH 1410 CA~IL.

183 RHR2A 2a Arkansas Nuclear 2 ~000368 08/29/84 84*023 Mode 5 AEOD*B B.5 184 RHR2A 2a Catawba 1 5000413 04/22/85 85-028 Mode 5 12 min

• A*2 B.8 185 RHR2A 2a Cook 2 06/16/88 22 min 3.46 186 RHR2A 2a Davis Besse 1 5000346 04/18/80 80-030 Mode 5 29 min A.3 AEOD*C Da3 187 RHR2A 2a Gfnna 5000244 04/12/83 83*015 . Mode 6 12 min A-2 AEOD*A . C1 188 RHR2A 28 McGuire 1 5000369 03/02/82 82*024 Mode 5 50 min A*2 AEOD*A 87 189 RHR2A 2a McGuire 1 5000369 04/05/83 83*017 Mode 6 A*2 AEOD*A B8 190 RHR2A 2a* McGuire 2 5000370 12/31/83 83*092 Mode 5 43 min A*2 AEOD*A 89 191 RHR2A 2a McGuire 2 5000370 01/09/84 84*001 Mode 5 62 min A*2 AEOO*B B.6 192 RHR2A 2a North Anna 2 5000339 05/20/82 82-026 8 min A-2 AEOO*A BS 193 RHR2A 2a North Anna 2 5000339 05/20/82 82*026 26 min A*2 AEOD-A B4 194 RHR2A 2a North Anna 2 5000339 05/20/82 82*026 1 hr A*2 AEOD*A 83

> 195 RHR2A 2a North Anna 2 5000339 05/03/83 83-038 Mode 6 A-2 AEOD*A cs

....I 196 RHR2A 2a North Anna 2 5000339 10/16/84 84*008*1 *Mode 5 2 hr A-2 AEOD*B B.3 197 RHR2A 2a San Onofre 2 5000361 03/26/86 86-007 Mode 5 49 min B.4 198 RHR2A 2a Sequoyah 2 5000328 08/06/83 83*101 Mode 6 17 min A*2 AEOD*A* C3 Mode 10 199 RHR2A 2a Trojan 5000344 03/25/78 78-011, 1 of 2 Mode 5 10 min A.2 B1 events 200 RHR2A 2a Trojan 5000344 03/25/78 78*011, 2 of 2 Mode 5 10 min A.2 B2 events 201 RHR2A 2a Trojan 5000344 06/26/81 81*012 Mode 5 75 min .. A.2 B4 202 RHR2A 2a 1/aterford 5000382 03/14/86 86*004 Mode 5 1 hr 19 min E.11 203 RHR2A 2a 1/aterford 5000382 07/14/86 86*015 Mode 5 3 hr 41 min B.7 204 RHR2A 2a 1/aterford 3 05/12/88 3.45 205 RHR2A 2a Zion 1 5000295 09/14/84 84*031 Mode 5 45 min A-2 AEOD*B B.2 206 RHR2B 2b Beaver Valley 1 5000334 09/04/78 78*049 1 hr A.2 C3 207 RHR2B 2b Beaver Valley 1 5000334 01/17/80 80*002

• Mode 5 A,2 cs 208 RHR2B 2b Beaver Valley 1 5000334 04/08/80 80*022 Mode 5 35 min A.2 C6 209 RHR2B 2b Beaver Vat tey 1 5000334 04/11/80 80*023 Mode 5 70 min A.2 C7 210 RHR2B 2b Beaver Valley 1 5000334 03/05/81 81*019 . Mode 5 54 min A.2 cs 211 RHR2B 2b Byron 1 5000454 09/19/88 007 .Mode 6 14 min 224 212 RHR2B 2b Cook 2 5000316 05/21/84 84*014 Mode 5 25 min A*2 AEOO*B C.2 213 RHR2B 2b Ofablo Canyon 2 5000323 04/10/87 005 Mode 5 1 hr 28 min 11~

Page No. 9 08/18/93 PHASE 2

• LOSS OF RESIDUAL HEAT REMOVAL WHILE AT SHUTDOWN FOR PWRS INITIAL SEA*

PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK . CR5015 Gl99 LER*, NUREG APPi:J

• CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT.

• CAT. AEOO CAT CAT SEARCH 1410 CAB.IL*.

214 RHR2B

- 2b HI l lstone 2 5000336 03/14/79 79-008 Mcx:1e 5 A.2 C4 215 RHR2B 2b North Anna 1 5000338 10/19/82 82-067 Mode 6 36 min A-2 AEOO*A 81 216 RHR2B 2b North Anna 1 5000338 10/20/82 82-067 Mode 6 33 min r.-2 AEOD*A B2 217 RHR2B 2b North Anna 2 5000339 07/17/82 82-049 Mode 5 A-2 218 RHR2B 2b North Anna 2 5000339 07/30/82 82-049 46 min AEOO*A B6 219 RHR2B 2b Pal !sades 5000255 10/15/87 035 Cold 29 min 22 3.44 shutdown 220 RHR2B 2b Rlnghals 4 08/23/84 26 min 3.30 NM:

221 RHR2B 2b Salem 1 5000272 06/30/79 79-059 Mode 6 34 min A.2 83 222 RHR2B 2b Sequoyah 1 5000327 10/09/85 85-040 Mode 5 A-2 C.3 223 RHR2B 2b Sequoyah 1 5000327 01/28/87 012 Mode 5 30 min 123 3.40 224 RHR2B 2b Sequoyah 1 5000327 05/23/88 021 Mode 5 134

> 225 RHR2B 2b Surry 1 5000280 05/17/83 83-024 Mode 5 A*2 AEOO*A C2

,!.. 226 RHR2B 2b Trojan 5000344 05/21/77 77-016 Mode 5 55 min A.2 C1 N 227 RHR2B 2b Trojan 5000344 04/17/78 78-011 Mode 6 A.2 C2 228 RHR2B 2b Trojan 5000344 05/04/84 84-010-1 Mode 5 40 min A-2 AEOD*B 229 RHR2B 2b Zion 2 5000304 12/14/85 85-028 Mode 5 75 min C.1 230 RHR28 2b Zion 2 5000304 01/13/86 85-028 Mode 5 75 min A-2 231 RHR3 3a2 Arkansas 2 5000368 11/14/79 79-087 M.ode 5 3 hr A.7 E28 232 RHR3 9 Calvert Cliffs 2 5000318 10/17/78 78-035 Mode 5 2 hr . A.10 E45 233 RHR3 3a2 Calvert Cliffs 2 5000318 03/24/87 003 Mode 6 15 hr 20 min 113' 234 RHR3 3a2 Calvert Cliffs 2 5000318 05/07/87 004 Mode 5 16 hr 55 min 114

• 235 RHR3 Crystal River 3 5000302 02/12/86 Mode 5 236 RHR3 Sb Davis Besse 1 5000346 07/10/80 80-057 Mode 6 A.5 E9 NA3 237 RHR3 3a2 Dlablo Canyon 5000275 06/25/88 017 Mode 5 34 . NA2 236 RHR3 6a Farley 2 5000364 09/28/83 83-042 Mode 6 A-6 AEOO*A E11 239 RHR3 Sb McGuire 1 5000369 04/28/81 81-073 Mode 5 *20 min A.6 E37 NA1 240 RHR3 9 McGuire 1 5000369 06/02/81 IE Circ. 81-10 Mode 5 A.9 E42 NA1 07/02/81 241 RHR3 11 McGuire 2 5000370 03/07/83 83-002 Mode 6 *3 hr A-10 Mode 8 242 RHR3 Sb Pal !sades 5000255 01/08/78 78-003

• Mode 5 45 min A.5 EB 243 RHR3 3a2 Palo Verde 5000528 03/19/88 022 Mode 6 247 LEAK 244 RHR3 Sb Salem 2 5000311 04/13/81 81-005 Mode 5 5 hr 22 min A.7 E33

Page No. 10 08/18/93 PHASE 2 - LOSS OF RESIDUAL HEAT REMOVAL ~HILE AT SHUTD~N FOR P~RS INITIAL SEA-PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 LER NUREG APPL! -

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOO CAT CAT SEARCH 1410 CABIL.

245 RHR3 3a2 Zion 1 5000295 01/04/90 001

• Mode 3 7 hr 47 min 70 246 RHR4 6a Arkansas 2 5000368 08/16/78 78-001 Mode 5 2.8 hr A.6 E17 NA1 247 RHR4 Arkansas 2 5000368 01/01/79 79-086 Mode 5 248 RHR4 3a1 Arkansas 2 5000368 10/13179 79-086 Mode 6 A.10 E46 249 RHR4 3a1 Arkansas 2 5000368 01/09/83 83-003 Mode 5 A-10 250 RHR4 3a1 Calvert Cliffs 1 5000317 01/24/78 78-004, 78-011 Mode 4 and 5 A.10 E44 251 RHR4 6a Crystal River 3 5000302 04/25/78 78-020 Cold shut. A.6 E14 252 RHR4 6a Crystal River 3 5000302 02/02/86 86-003 Mode 5 24 min A-6 E.8 253 RHR4 3c Farley 2 5000364 11/27/87 008 Refueling 167

• outage 254 RHR4 Se McGuire 1 5000369 02/05/81 81-009 Mode 6 3 hr A.5 E10 NA1 255 RHR4 9 McGuire 1 5000369 11/23/88 049 *Mode 6 39 min 175 *

i,. 256 RHR4 6a North Anna 1 5000338 06/14/82 82-043 Mode 5 A-6

~ 257 RHR4 6a North Anna 2 08/02/82 3.17 w 258 RHR4 6a North Anna 2 5000339 08/16/82 82-050 Mode 5 A-6 259 RHR4 3a1 North Anna 2 5000339 05/22/83 83-042 Mode 4 30 min A-10 ~A 260 RHR4 6a Rancho Seco 5000312 05/05/82 82-012 Mode 5 A-6 261 RHR4 3a1 Salem 1 5000272 12/13/82 82-089 Mode 6 A-6 262 RHR4 3a1 San Onofre 5000361 08/31/87 014 Mode 5 18 hr 16 ..

263 RHR4 3a1 Trojan 5000344 04/25/78 78-017 Mode 5 1 min A.3 Da1 264 RHR4 6a Turkey Po_lnt 3 5000250 10/23/85 85-034 Mode 5 A-7 265 RHRS Sb Arkansas Nuclear 1 5000313 10/26/88 014 Mode 6 23 min 100 3.50 266 RHRS Sb Arkansas Nuclear 1 5000313 12/19/88 024 zero power 12 min 10,:

267 RHR5 Sa Beaver Val Ley 1 5000334 05/12/82 82-018 Mode 5 2 min A-6 AEOO*A E9 268 RHR5 3c Calvert Cliffs 1 5000317 02/08/80 80-011 Mode 5 1 hr 33 min A.3 Da2 Closed 269 RHR5 6b Calvert Cliffs 1 5000317 05/17/82 82-026 2 min AEOO-A E6 270 RHRS Sb Calvert Cliffs 2 5000318 01/23/81 81-003 Mode 6 5 min A.7 E32 271 RHRS Connecticut Yankee 5000317 03/05/88 Mode 5 hr 2 min 272 RHRS 6b Connecticut Yankee 5000317 03/10/88 007 Mode 5 1 hr 22 min 6 273 RHRS 6b Cook 2 5000316 12/09/82 82-109 Mode 6 A-6 274 RHRS 6b Crystal River 3 5000302 07/16/80 IE Info Notice '.Mode 5 21 min A.3, A.7. Da5,

\

81-10 E31 I

275 RHRS 9 Crystal River 3 5000302 04/21/81 IE Clrc. 81-10, Mode 5 Similar event A.9 E41

Page No, 11 08/18/93 PHASE 2 - LOSS OF RESIDUAL HEAT REMOVAL YHILE AT SHUTDOYN FOR PYRS INITIAL SEA-PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 LER NUREG APrLI -

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT, CAT. AEOO CAT CAT SEARCH 1410 CABIL, 07/02/81 10/01/81 276 RHR5 Crystal River 3 5000302 10/01/81 Mode 5 277 RHRS 6b Davis Besse 1 5000346 05/31/80 80-044 Mode 6 8 min A,7 AEOO-C E29 278 RHR5 6b Davis Besse 1 5000346 04/18/81 81-024 Mode 5 1 min (2 min in A.6 AEOO-C E24 AEOO-C) 279 RHRS 6b Farley 1 5000348 03/07/83 83-009 Mode 6 A-6 280 RHR5 3c Farley 1 5000348

• 11/07/86 86-020 Mode 5 . A-3 Mqde 12 281 RHRS Farley 1 5000348 11/15/86 Mode 5 282 RHRS 6b Ft. Calhoun 5000285 10/19/77 77-023 Mode 6 A,7 E26 283 RHRS Se Glnne 5000244 05/01/83 83-017 . Mode 5 A-6 AEOO-A A1 284 RHRS 3a2 Indian Point 3 5000286 05/12/83 83-002 Mode 5 A-10 285 RHRS Sb Haine Yankee 5000309 06/10/81 81-008 Mode 6 5 min A.5 E12 286 RHRS 11 Hf l lstone 3 5000423 06/08/87 030 Mode 5 33 min 199**

r 287 RHRS 3e2 North Anna 1 5000338 06/01/80 80-053 Mode 5 34 min A.3, A.7

• Da4, E30

.i,-

288 RHRS 6b North Anne 1 5000338 02/18/83 83-009 Mode 5 5 min A-10 AEOD-A C4 289 RHRS 9 Oconee 1 5000269 06/29/81 Duke ltr to NRC Mode 5 A.9 E43 07/31/81 290 RHR5 3a2 Oconee 3 5000287 04/06/87 005 Mode 5 61 291 RHR5 Sb Pelf sades 5000255 07/18/81 81-030 Mode 5 1 hr 30 min A,5 E13 292 RHRS 4 Rancho se;o 5000312 10/03/86 86-016 Mode 5 13 mfn A.11 293 RHRS 3a2 Robinson 5000261 06/11/87 014 zero power 27 294 RHRS 3c Salem 2 5000311 06/12/81 81-041 Mode 4 1 hr 5 min A.3 Da7 295 RHRS, 6b Salem 2 5000311 05/24/83 83-025 Mode 5 A-6 AEOO-A E3 296 RHRS 9 Sen Onofre 2 5000361 03/14/82 82-002 Mode 6 90 min A-10 297 RHR5 6b SUll1ler 5000395 11/06/84 IE Daily Report 7 min AEOD-B 298 RHRS 10 Surry 1 5000280 03/18/89 009 zero power 11 hr 28 min 46 299 RHRS 10 Surry 2 5000281 02/19/86 86-004 Mode 5 10 min E.4 300 RHRS 7 Vogtle 1 5000424 03/18/87 055 Mode 3 205 . NA2 301 RHR6 8 Beaver Valley 1 5000334 05/03/81 81-048 Mode 4 A.8 E38 302 RHR6 8 Crystal River 3, 5000302 08/15/77 77~101 Mode 4 A.8 E34 303 RHR6 8 Crystal River 3 5000302 03/04/79 79-022 Mode 4 A.8 E35 304 RHR6 8 Crystal River 3 5000302 04/25/79 79-046 Mode 4 A,8 E36

Page No. 12 08/18/93 PHASE 2 - LOSS OF RESIDUAL HEAT REMOVAL WHILE AT SHUTD~N FOR PWRS INITIAL SEA-PHASE 2 SSS EVENT PLANT RECOVERY NSAC52 BROOK CR5015 G199 LE~- NUREG APPL!-

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOO CAT CAT SEARCH 1410 CABIL,

---

*---------------------------------------------------------------------------------------------------------------------------------------------------------~.,

305 RHR6 8 Davis Besse 1 5000346 01/07/81 81-004 .Mode 4 15 min A.6 AEOD-C E22 306 RHR6 8 Glnna 5000244 03/03/84 84-002 Mode 4 A-8 307 RHR6 8 Glnna 5000244 05/14/84 84-005 Mode 4 A-8 308 RHR6 8 Oconee 2 5000270 09/18/81 81-017 Mode 1 A.8 E39 309 RHR6 8 Oconee 3 5000287 10/15/85 85-003 Mode 4 A-8 E.7 310 RHR6 8 Robinson 5000261 07/15/82 82-009 Mode 6 A-8 311 RHR6 8 Robinson 5000261 07/27/82 82-009 .. Mode 6 A*8 312 RHR6 8 Sen Onofre 2 5000361 04/26/83 038 Mode 4 A*8 313 RHR6 8 Turkey Point 4 5000251 05/23/89 004 . Mode 4 20 314 SWGR 12 Surry 2 5000281 03/12/87 001 Mode 5 48 315 TRANS TRANS Surry 1 280 07/09/81 026 Routine startup 316 TRANS TRANS Surry 1 280 01/05/82 010 Routine SD

r- 317 TRANS TRANS Surry 1 280 01/06/82 001 HSD t;; 318 TRANS TRANS Surry 1 280 04/15/82 048 Routine

• startup 319 TRANS TRANS Surry 1 280 10/17/82 112 Routine startup 320 TRANS TRANS Surry 1 280 04/07/84 008 Routine SD 321 TRANS TRANS Surry 1 280 06/19/84 016 Routine startup 322 TRANS TRANS Surry 1 280 01/27/85 004 Routine startup 323 TRANS TRANS Surry 1 280 01/28/85 006 Startup 324 TRANS TRANS Surry 1 280 02/07/86 010 Routine startup 325 TRANS TRANS Surry 1 280 02/08/86 009 Routine startup 326 TRANS TRANS Surry 1 280 09/16/86 022, event on CSD 9/20/86 327 TRANS TRANS Surry 1 280 07/18/89 030 100%, Unit 2 265*

CSD 328 TRANS TRANS Surry 1 280 07/23/89 031 100%, Unit 2 266*

Page llo. 13 08/18/93 PHASE 2 - LOSS OF RESIDUAL HEAT REMOVAL ~HILE AT SHUTD~N FOR P~RS INITIAL SEA*

PHASE 2 sss EVENT PLANT RECOVERY NSAC52 BROOK CR5015 Gl99 LEI\ NUREG APPL! -

CAT CAT PLANT I/AME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOD CAT CAT SEAR"CH 1410 CABIL.

CSD 329 TRANS TRANS Surry 2 281 12/19/82 075 Hot SD 330 TRANS TRANS Surry 2 281 09/21/83 038 . Hot SO 331 TRANS TRANS Surry 2 281 04/15/84 009 2% power 332 TRANS TRANS Surry 2 281 04/20/84 012 Hot SO 333 TRANS TRANS Surry 2 281 03/16/87 002 Hot SD 334 TRANS TRANS Surry 2 281 09/10/88 022 .Refuel Ing outage 335 TRANS TRANS Surry 2 281 09/16/89 007 Subcritical 336 TRANS TRANS Surry 2 281 09/18/89 009 14% power 337 VITAL 1 Calvert Cliffs 2 5000318 02/04/81 81-004 Mode 6 17 min A.1 A20 338 VITAL Calvert Cliffs 2 5000318 11/22/82 82-053 Mode 6 4 min A*1 AEOO-A A10 339 VITAL 6b Calvert Cliffs 2 5000318 11/24/82 82-054 AEOO*A E7

>I 340 VITAL 1 Calvert Cliffs 2 5000318 12/28/82 82-055 AEOO*A A11

341 VITAL Calvert Cliffs 2 5000318 01/04/83 83-001 15 min AEOO*A A12 342 VITAL Catawba 1 5000413 11/26/88 026 Mode 5 2 sec 191' 343 VITAL 2b Comanche Peak 1 07/18/89 3.52 NA1 344 VITAL 1 Crystal River 3 5000302 08/19/78 78-042 Mode 6 15 min A.1 A5 345 VITAL 1 Devis Besse 1 5000346 06/28/79 79-067 Mode 5 18 min A.1 AEOO*C A7 346 VITAL Dlablo Canyon 2 5000323 01/17/86 86-002 Mode 5 13 min A-1 A.14 347 VITAL Dleblo Canyon 2 5000323 06/29/87 011 Mode 4 5 min 118 348 VITAL McGuire 1 5000369 06/24/82 82-053 6 min AEOO*A A19 349 VITAL McGuf re 1 5000369 07/13/82 82-053 A-1 350 VITAL Millstone 2 5000336 01/06/82 82-002 7 min AEOO*A A15 351 VITAL North Anne 1 5000338 01/22/83 83-003 Mode 6 4 min A-1 AEOO-A A16 352 VITAL North Anne 1 5000338 04/22/87 007 Mode 5 146' 353 VITAL North Anne 2 5000339 04/29/83 83-036 Mode 6 < 1 min A-1 AEOO*A A18 354 VITAL Pelo Verde 2 5000529 01/30/86 86-005 Mode 5 E.12 355 VITAL 6b Rancho Seco 5000312 06/24/82 82-015 Modes 4 and A-6 AEOO*A A8 5

356 VITAL Rancho Seco 5000312 11/15/86 86-024 Mode 5 A-1 A.12 357 VITAL Selem 2 5000311 05/14/83 83-024,1 of Modes 4 end lnrnedletely A-1 AEOO*A A4 2*5/15/83 LER 5

Page No. 14 08/18/93 PHASE 2

• LOSS OF RESIDUAL HEAT REMOVAL ~HILE AT SHUTDOIIN FOR P~RS INITIAL SEA*

PHASE 2 SSS EVENT PLANT RECOVERY NSAC52 BROOK CR5015 G!99 LER. NUREG APPL!*

CAT CAT PLANT NAME DOCKET NO DATE LER CONDITION TIME CAT. CAT. AEOD CAT CAT SEARCH 1410 CABIL,

• 358 VITAL Salem 2 5000311 . 11/28/83 83-062 Mode 5 A-1 AEOO*A A6 359 Vl.TAL 6b South Texas 1 5000498 02/12/89 008 Mode 5 243

• 360 VITAL 1 Surrner 5000395 11/12/83 83-136 Mode 5 5 min A-1 AEOO*A A20 361 VITAL 1 Surrner 5000395 10/18/84 84-045 "Mode 5 25 min A-1 AEOO*B A.19 362 VITAL Turkey Point 4 5000251 03/15/86 86-006 Mode 6 5 min A-1 A.3 363 VITAL Zion 1 :i000295 03/17/82 82-011 Mode 6 3 min A-1 AEOO*A A3 364 V!TAL Zion 2 5000304 01/03/86 86-001 Mode 5 A-1 A.8 Number of Records 364 file: query and report Fullphs2

Appendix A.2 Descriptions of Events Used in the Quantification A-18

p. LER DATA BASE* RHR2A 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHR2A Arkansas Nuclear 2 08/29i84 Mode 5 (from AEOO): During RCS draindown, faulty level instrunentation led to air _binding of the DHR pul1). A tygon mananeter configuration was being used - however, the operators did not account for reactor vessel pressurization due to the presence of nitrogen purge gas. RCS t~. went from 140 deg Fah to 205 deg Fah .~11pprox. 35 min. toss).

(from CR5015): Power Level - 0%. On 8/29/84 the plant was in mode 5 and the RCS level was being monitored by a temporary level indicator coMected to the bottom of the RCS hot leg and vented to atmosphere. A nitrogen purge of the RCS was in progress to usweept* hydrogen from the system prior to maintenance. The RCS was being vented via the upper vessel head vent and due to nitrogen flow exceeding vent flow capacity the RCS became slightly pressurized. This resulted in a manometer effect and inaccurate indication of RCS level. The level indication inaccuracy led to draining of the water in the RCS hot leg below the minillUII level for adequate shutdown cool fng pul1) suction. SOS loop flow indication began oscillating between 2000 and 4000 gpm indicating cavitation of the SOC pul1).

Consequently the us 11 soc pul1) was nitrogen purge were secured. Decay heat removal aligrment was shifted to the uA 11 SOC loop and normal flow of approx. 3000 gpm was established. During the period SOC flow was off, RCS bulk average temperature increased from approx. 140 to 205 deg Fah resulting in a change from mode 5 to mode 4. To prevent recurrence the temporary level system reference leg has been changed from venting to atmosphere to venting to the pressurizer steam space. Changes have been made to nonnal and abnonnal operating procedures to irrprove system and operator response to similar events.

RHR2A Catawba 1 04/22/85 Mode 5 12 min (from Seabrook): Both trains of Residual Heat Removal (ND) were inoperable. This was the result of ND Train A being declared inoperable on April 20, 1985, at 1600 hrs for the performance of various ND Train A related work requests and ND Puq> B being secured on April 22, 1985, at 2039:21 hrs due to loss of purrp suction. Also, Tecli. Spec. 3.4.1.4~2 was violated on April 22, 1985 at 0522 hrs when reactor coolant (NC) system draining began with ND train A inoperable.

(from CR5015): Power level - OX. on April 22, 1985, from 2039:21 to 2051:17 hrs, both trains of residual heat removal (RHR) were inoperable. This was a result of RHR train A being declared inoperable on April 20, 1985, at 1600 hrs, for the perfonnance of various train A related work requests, and RHR purrp B being secured on April 22, 1985, at 2039:21 hrs due to loss o f ~ suction.

Also, tech spec 3.4.1.4.2 was violated on April 22, 1985, at 0522 hrs when reactor coolant (RC) system draining began with RHR train A inoperable.* Catawba Unit 1 was in mode 5 (cold shutdown) when these incidents occurred. False RC system level indication apparently contributed to the loss of RHR pul1) B suction. However, the cause.of the false level indication is not known at this time. With RHR Train A inoperable, the limiting conditions for operation of Tech Spec 3.4.1.4.2 were not met. However, prior to begiming RC system draining, a decision had been made to allow draining to begin with RHR2A Cook 2 06/16/88 22 min After all fuel from the reactor vessel had been removed with the reactor cavity flooded, the upper internals were replaced. The mid-loop water level indicator was valved out. The water level was reduced by ~ing water to the refueling water storage tank at 2000 gpm wi~h a residual heat removal pul1). When the observed water level decreased to the top of the upper internals, the pul1) began to cavitate. The pul1) was stopped and vented. The purrp was then started at a reduced flow rate. After approximately 22 minutes of operation with the observed water level just below the top of the upper internals, the purrp again started to cavitate. The mid-loop water level indicator was valved in and indicated that the reactor vessel level was at mid-loop. Because the purrp flow rate exceeded the leakage rate around the upper internals, a void had been created under the upper internals. The industry was informed of this event in INPO Significant Event Report CSER) 36-88.

A-20

LER DATA BASE - RHR2A 08/27/93

p. 2 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHR2A Davis Besse 1 04/18/80 Mode 5 29 min (from NSAC52, p. A-11): RCS water level decreased from 7011 to 3711 above the.hot leg piping centerline, causing erratic flow rate due to inadequate pump suction conditions. The RHRS pump was secured five minutes later at a level of 35 11

• The inventory loss was via a partially open discharge valve from RHRS cooler #2 to the makeup and purification system. Sane inventory may have also been lost via cross connects to RHRS loop 1, which was being drained.

(from AEOD): 29-minute Loss of OHR. Leakage of RCS water through a partially closed valve resulted in inadequate DHR pump NPSH and erratic JX.111P flow operation. The pump was secured until the leak was stopped and RCS level restored. During the event, RCS tel11)erature rose from 93 deg Fah to 103 deg Fah.

RHR2A Ginna 04/12/83 Mode 6 12 min (from Seabrook): Prior to the dilute chemical addition, a small amount of water was being used in the channel head in conji.,ction with air pressure at 30 psig to properly seat the dams to minimize leakage past the dams into RCS. During this process, water drained coopletely through the leaky dam in the cold leg nozzle, thus allowing air to pass through, resulting in an air bubble formation passing through the RCS and entraining the RHR pump suction thus causing loss of the RHR located on the hot leg of the same loop. The RHR pump in operation at the time was manually tripped by the Control Room operator to prevent damage to the pump. Prior to this event, the RCS Boron Concentration had been borated to greater than 2400 ppm (2~00 ppm required for refueling shutdown mode).

(from AEOD):* Air binding of RHR pump (12 minute Loss).

RHR2A McGuire 1 03/02/82 Mode 5 50 min (from Seabrook): A Residual Heat Removal (ND) pump low discharge alarm resulted in ND Pump 1A being stopped due to signs of cavitation. With the redundant Puip 1B out of service for maintenance, no means existed for core residual.

(from AEOD): Low RCS level due to vessel draining and inaccurate level indication. Operating RHR pump started to cavitate, the other pump was undergoing maintenance. (Event lasted 50 minutes - a licensee analysis indicated that 4 hrs were available prior to the onset of boiling.)

RHR2A McGuire 1 04/05/83 Mode 6 (from Seabrook): The Residual Heat Removal (ND) P~ began to cavitate and eventually both the punps were stopped.

(from AEOD): Low RCS level due to vessel draining and valved out level sensor. Both RHR punps cavitated. (Duration of event unknown)

RHR2A McGuire 2 12/31/83 Mode 5 43 min (from Seabrook): Residual Heat Removal (ND) PUli) B was observed to have zero discharge flow and was subsequently tripped and ND Train B declared inoperable.

(from AEOD): Low RCS level due to draining and inadequate level indication. Running RHR pump had no flow (43 min*. loss).

RHR2A McGuire 2 01/09/84 Mode 5 62 min (from Seabrook): During draining operators of the Reactor Coolant (NC) System Residual Heat Removal (ND) Pump B was observed to have zero discharge flow. Pump B motor ~rage was low and the ND system pressure and Pump B discharge pressure were equal. Based on these factors, ND Pump B was tripped and ND train B was declared inoperable at 1650. The FWST to ND Pump Isolation valve was twice cycled to A-21

p. 3 LER DATA BASE - RHR2A 08/27/93 PHASE 2 CATEGORY PLANT NAME EVENT DATE INITIAL PLANT CONDITION RECOVERY TIME provide core cooling and raise NC System l~vel wHh. water from the Fueling *llatei- Storage Tank while venting the NO Suction line and~ B. The core teq>erature rate of rise decreased after the first water addition, and the second addition resulted in slightly decreased core teq>eratures. ND P~ B was restarted at 1720 and flow was restored. On January 9, 1984, operators were again decreasing level in the Reactor coolant loops when a coa.,uter alarm for low ND P~ A discharge pressure was received.

Fluctuations in NOP~ A discharge pressure was received. Fluctuations in NOP~ A motor aaperage were noted and si111Jltaneous fluctuations in discharge pressure and flow also occurred. After the low NO Flow arriunciator alarmed, ND P~ A was tripped at 1246 and NO Train A was therefore inoperable.

Operators manually opened the NO system to FWST isolation valve, raising the Reactor Coolant Loop level with water from the MT. The suction line and puJ1) were vented and the puJ1) was restarted at 1348.

(from AEOO): During draining operations, a procedural deficiency led to inadequate NPSH/air entrail'IOent of the DHR puips (1 hr. 2 min. loss).

(from CR5015): Power level - OX. on Dec. 31, 1983 at 1640, during draining operations of the reactor coolant (NC) system, residual heat removal (ND) puJ1) B was observed to have zero discharge flow. P""'

B motor aaperage was low, and the ND system pressure and puJ1) B discharge pressure were equal. Based on these factors, NO puJ1) B was tripped and ND train B was declared inoperable at 1650. The FWST to ND puJ1) isolation valve was twice cycled to provide core cooling and raise NC system level with water from the refueling water storage tank, while venting the ND suction line and puJ1) B. The core temperature rate of rise decreased after the first water addition, and the second addition resulted in decreased core temperatures. ND puJ1) B was restarted at 1720, and flow was restored. on Jan. 9, 1984 operators were decreasing level in the reactor coolant loops when a coa.,uter alann for low ND puJ1) A discharge pressure was received. Fluctuations in ND puJ1) A motor ~rage were noted and si111.1ltaneous fluctuations in discharge pressure and flow also occurred. After the 0 low ND flow" annunciator alarmed, ND puJ1) A was tripped at 1246, and ND train A was inoperable- Operators manually opened the ND system to FWST isolation valve, raising the reactor coolant loop level with water from the FWST.

The suction line and puJ1) were vented, and the~ was restarted at 1348. These incidents are clue to inadequate guidelines recording the water level to be maintained in the reactor coolant loops during ND operation.

RHR2A North Anna 2 05/20/82 1 hr (from Seabrook): Not found in A-2 (from AEOD): Lost suction to RHR puips due to draining of RCS and erroneous level indication (three events: 8 min, 26 min, 1 hr losses).

RHR2A North Anna 2 05/20/82 8 min (from Seabrook): Not found in A-2.

(from AEOD): Lost suction to RHR puips due to draining of.RCS and erroneous level indication (3 events: 8 min, 26 min, 1 hr losses).

RHR2A North Anna 2 05/20/82 (from Seabrook): Not found in A-2.

(from AEOD): Lost suction to RHR puJ1)S due to draining of RCS and erroneous level indication (3 events: 8 min, 26 min, 1 hr losses).

A-22

p. 4 LER DATA BASE - RHR2A 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHR2A North Anna 2 05/03/83 Mode 6 (from Seabrook Sheet 3 of 9): On May 3, 1983, suction to the B Residual Hea~ Removal (RHR) ~ was lost while transferring water from the Reactor Coolant system (RCS) to the refueling water storage tank (RWST) via the Refueling Purification (RP) System. The AP~ was secured and the B RHR P~ started but suction was not available.

(from AEOO): Inadequate monitoring of RCS level. Loss of RHR l)U1" suction. (Duration of event 1i1known)

RHR2A North Ame 2 10/16/84 Mode 5 2 hr (from Seabrook Sheet 7 of 9): A coaplete loss of Residual Heat Removal (RHR) capability occurred when both RHR.~ were wiable to operate due to the introduction of air into the RHR system. The incident occurred during the drain down of the Reactor Coolant System (RCS) when the level of the RCS was being monitored via a standpipe off the centerline of one of the RCS loops.

(from AEOD): Clogging of a standpipe used for RCS level monitoring resulted in a 64 11 error. Upon introduction of air, the operating~ cavitated. The redundant p111p was started and it also cavitated. Both~ became airbcx.rld (2 hr loss).

(from CR5015): Power level - 0%. On 10-16-84, with North Anna Unit 2 in Mode 5 a complete loss of RHR capability occurred when both RHR ~ were unable to operate due to the introduction of air into the RHR system. The incident occurred during the drain down of the RCS, when the level of the RCS was being IIIDnitored via a standpipe off the centerline of one of the RCS loops. The isolation valve to which the standpipe was attached became clogged sometime during the drain down and falsely indicated 64 11 above centerline when in fact the level was below the RHR suction line (below centerline).

Subsequently, letdown from the RCS w~s isolated and makeup initiated. RHR capability -was regained 2 hrs after initiation of the event. RCS level indication was moved to an alternate tap off toop centerline and indicated satisfactorily.

RHR2A San Onofre 2 03/26/86 Mode 5 49 min (from CR5015): Power level* 0%. March 26, 1986 at 2208 with Unit 2 in cold shutdown, the shutdown cooling system (SOCS) experienced a total loss of flow for a period of 49 minutes. This occurred while reactor coolant system (RCS) level was being reduced to repair a leaking cold leg steam generator nozzle dam which had been installed to allow work in steam generator channel heads. Using the established level indication, which was later found to be in error, the RCS was drained to a level where vortexing occurred at the RCS/SOCS suction connection causing the SOCS/LPSI ~ to eventually become airbound. The~ were stopped and the system vented, reestablishing socs flow at 2257.

concurrent with the restoration of socs flow, both gas channels of the fuel handling isolation system actuated on high noble gas a result of the RCS degasing. The high pressure safety injection system was used to make-up to the RCS until SOCS flow returned to a stable state. The cause of the event was erroneous level indication resulting in the operators not recognizing the RCS low level condition prior to coaplete loss of SOCS flow. IlllllE!diate corrective action was taken to prevent SDCS/LPSI ~ damage, restore socs flow to a stable state and recalibrate the level indicators. Changes in plant design, procedural revisions, formal control of level indicator installation, and operator training will be undertaken.

RHR2A Sequoyah 2 08/06/83 Mode 6 77 min (from Seabrook Sheet 4 of 9): At 0838 CC) during l)U1" down of the refueling cavity to perform maintenance on the Loop 4 Reactor Coolant System Cold Leg Nozzle Inspection Plate, the B Train Residual Heat Removal P~ began to cavitate.

Cfrom AEOD): False RCS level indication by makeshift tygon tube and rubber hose level instrument. RCS A-23

p. 5 LER DATA BASE - RHR2A 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

~ . . . . *. . . .

t~rature rose from 103 deg Fah to 195 deg Fah in 77.min: Plant h.ad been shut* down 18. days earlier *.

RHR2A Trojan 06/26/81 Mode 5 75 min (from NSAC52, p. A-10): While reducing RCS level, in preparation for maintenance, the RHRS ~ began cavitating and was secured. Inventory reduction was terminated and RCS charging was established.

Investigation found a shut pressurizer vent valve which isolated the reactor vessel level indicating system internal reference leg. The pressurizer vent and reactor vessel head vent were opened, and standpipe level stabilized approx. 5 feet lower than the previously indicated level. (Close to the RHRS suction tap off an RCS hot leg.) Attempts to restart the RHRS JlUl1) failed due to air entrained in the RHRS suction line. The RHRS suction valves were closed and the RlolST suction valve was opened in order to provide a positive suction to the RHRS ~ - Flow was restored 75 minutes after event initiation.

RHR2A Waterford 03/14/86 Mode 5- 1 hr 19 min (from CR5015): Power level - 0%. on 3-14-86 Waterford Steam Electric Station Unit 3 was in Mode 5 (cold shutdown) (as a result of a scheduled surveillance/maintenance outage which began on 3-7-86) with both loops of the reactor coolant system CAB) drained. At 1035 hrs on 3-14-86 operations personnel, in preparation for maintenance on SI-406A, loop 2 shutdown cooling return relief valve, started low pressure safety injection CLPSI) JlUl1) B (BP). The primary nuclear plant operator observed the flow in the B shutdown cooling (BP) train to be zero CO gpm) and LPSI ~ B motor current to be 33 ~ - The control room supervisor ordered the JlUl1) secured, and proceeded to the B safeguards JlUl1) room to investigate local conditions. The investigation revealed that SJ-1248, low pressure safety injection puJ1) B discharge valve, was closed with a danger tag affixed to the valve. The valve was mistakenly closed during a tag-out which was conducted on the 3/13-14/86 midnight shift. The valve was opened and at 1154 hrs on 3-14-86 the B LPSI ~ was placed into service. The valve was inadvertently closed because plant operators did not use the clearance request sheet when they conducted the tag-out. To prevent this from recurring, a revision will be made to procedure UNT-5-003, "Clearance Requests, Approval and Release," and the operations superintendent will stress the function of clearance sheets with operations. personnel.

RHR2A Waterford 07/14/86 Mode 5 3 hr 41 min (from CR5015): Power level - 0%. On July 14, 1986 Waterford Steam Electric Station Unit 3 was in Mode

_5 (cold shutdown) when operations personnel were draining the reactor coolant system (RCS) CAB) to facilitate the replacement of the seal package for reactor coolant JlUl1) 2A. The RCS was being maintained by draining into the refueling water storage pool (RWSP) (via the low pressure safety injection~ B mini-recirculation valves, Sl-1208, -1218) and holdup tanks (via the chemical volume control system (CB) purification ion SI-423). At 0113 hrs operations persomel secured draining the RCS by closing SJ-423. However, operations personnel neglected to close SJ-1208 and -1218 resulting in RCS inventory being~ into the RWSP. In addition, because of insufficient nitrogen pressure, local reactor vessel level indication was suspect. At 0317 hrs LPSI pu'i) B began cavitating.

Operations inmecliately secured the pu!i), tenninating shutdown cooling (SOC) (BP). At 0658 hrs SOC was restored by a process of refilling the RCS and cycling the LPSI punps to restore flow. (Since the RCS tell1)erature increased to the point of localized boiling, the LPSI punps were subjected to steam binding). This event was due to sinultaneously using more than one method of draining the RCS, and inaccurate level indication. These problems will be corrected by plant modification and procedural changes.

RHR2A Waterford 3 05/12/88 (from NUREG-1410): The reactor vessel water level was being lowered to mid-loop to remove the steam generator nozzle dams and to test a new digital reactor vessel water level indicator. Tygon ti.bing was being used to monitor the reactor vessel water level. At an indicated level of 18 ft on the tygon tubing and 14 ft on the digital instrument, the operating low pressure safety injection~ started cavitating and was secured. The water Level was raised and the other Low pressure safety injection A-24

p. 6 LER DATA BASE - RHR2A 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME J:M.11P was started. However, a loop seal i~ the tygon t~ing was not detected. Th~*reactor vessel water level was again lowered until the operating low pressure safety injection purp started cavitating. The reactor vessel water level was then raised, restoring decay heat removal. The industry was informed of this event in INPO Significant Operating Experience Report (SOER) 88-3.

RHR2A Zion 1 09/14/84 Mode 5 45 min (from Seabrook Sheet 6 of 9): While in cold shutdown, draining the RCS in preparation for steam generator primary-secondary leak testing, the RCS level dropped below the suction line for the RHR J:M.IIP*

(from AEOO): While draining the RCS in preparation for primary-secondary leak testing, the RCS level dropped below the DHR suction line. The liquid level was being read from a manometer type arrangement.

Incorrect level measurement resulted from the fact that the manometer reference leg was pressurized by nitrogen purge gas. RCS teq,erature increased from 110 deg Fah to 147 deg Fah (45 min. loss).

(from CR5015): Power level - 0%~ While in cold shutdown, draining the RCS in preparation for SG primary-secondary leak testing the RCS level dropped below the suction line for the RHR pulp as a result of an inproper valve lineup which gave false indication of the RCS level. The RHR punp was stopped when it was noticed that the motor anperage was fluctuating. The valve lineup was checked and the lineup error corrected. RCS level was increased to normal and the RHR pulp was restarted. RCS tenperature increased from 110 F to'147 F during the 45 minutes the punp was off. No abnormal conditions developed as a result of this event. Station procedures will be revised to prohibit simultaneous draining and purging operations, a procedure for loss of RHR will be prepared. Retraining will be conducted in proper valve lineup procedures.

A-25

p. 1 LER DATA BASE - RHR2B 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

. . . ; . . . . . . *. . . ~- .

RHR2B Beaver Valley 1 01/17/80 Mode 5 (from NSAC52, p. A-9): The reactor vessel vend ecluctor was in service in preparation for refueling. A low flow alarm for RHRS was received and low flow and low motor current were indicated. A second RHRS

~ was started and was also air bound~ Both pu1')S were vented and flow restored.

RHR2B Beaver Val Ley 1 04/08/80 Mode 5 35 min (from NSAC52, p. A-9): While att~ting to increase RHRS flow to the Tech Spec value requ)red for dilution (3000 gpm), the running RHRS ~ lost flow. The second RHRS ~ was also found to be air bound. RCS level was increased, puips vented and flow restored in 35 minutes.

RHR2B Beaver Valley 1 04/11/80 Mode 5 70 min

<from NSAC52, p. A-10): While att~ting to increase RHRS heat exchanger flow, the nr11ing RHRS ~

lost suction. (Heat exchanger flow was increased by decreasing bypass flow, not increasing~ flow.)

The airbotm RHRS ~ was secured. The other~ was started, became airbound and was also secured.

Both pu1')S were vented, and RCS level was increased. Full RHRS flow was restored in 70 miootes.

RHR2B Beaver Valley 1 03/05/81 Mode 5 54 min (from NSAC52, p. A-10): Reactor vessel water level was inadvertently lowered. The RHRS low flow alarm was actuated, accompanied by low current on the operating~- System flow dropped to 500 gpm.

Swapping the operating JlUlll for the idle~ resulted in an indicated flow of zero gpm. Returning to the original~ restored flow to 500 gpm. 600 gallons of coolant were added to the RCS, RHRS pu1')S were vented, and flow restored in 5.{ minutes. RCS tenperature increased 66 F to 168 F. Investigation revealed that remote level indication in the control room was 611 higher than actual level as indicated by a local standpipe.

RHR2B Byron 1 09/19/88 Mode 6 14 min (from LER Search): On Sept. 19, 1988, "the reactor was fully depressurized in the refueling operational IIIOde at a t~rature of approx. 95F. Reactor cavity water level was approx. 411

• A:reactor vessel stud hole protective insert had worked free and was floating on the water surface. At 1052 the 1B residual heat removal (RHR) purp was operated* to lower reactor cavity water level to the vessel flange to permit insert replacement. Visual sighting of cavity water level was believed to be an accurate and timely indication for the evolution based on past experience. While coopleting the draining evolution, the 1A RHR ~ showed signs of cavitation and was stopped by a licensed reactor operator. Within 2 miootes of stopping the JlUlll, the reactor vessel was gravity filled from the refueling water storage tank. Within 14 minutes, shutdown core cool i_ng was restored using the 1B RHR purp. This report is submitted voluntarily. The 1A RHR ~ cavitation was caused by the entraimient of air to the ~

• s suction. It is believed that air was adaitted by a vortex when reactor vessel water level lowered below the top of the reactor coolant hot legs. The cause of the excessive lowering of vessel water level was a failure to c~rehend the fluid restriction created when the upper.internals assenbly is fully seated on the hold down spring.

RHR2B Cook 2 05/21/84 Mode 5 25 min (from Seabrook): With the Reactor Coolant System at half-loop, the control Room operators started a second residual heat removal CRHR) ~ in preparation for removing the operating RHR ~ from service. With both~ running, flow became excessive for the half loop condition causing cavitation and air binding of both puips. Both ?U1')S were out of service for approximately 25 minutes while they were being vented which is within the one hr.

(from AECO-B): Procedural error with a partially drained RCS. Si111.1ltaneous operation of two DHR puips caused vortexing at the loop suction. Both pu1')S became airbound (25 min. loss).

A-26

• p.

PHASE 2 2

CATEGORY PLANT NAME LER DATA BASE - RHR2B EVENT DATE I NIT I AL" PLANT CONDITION 08/27/93 RECOVERY TIME

---

~------------------------------------------------------

(frcm CR5015): Power level - 0%. With the unit in cold shutdown (Mode 5) and the* reactor coolant system at half-loop, the control room operators started a second residual heat removal (RHR) pulp in preparation for removing the operating RHR pulp frcm service. With both purps running, flow became excessive for the half-loop condition causing cavitation and air binding of both purps. Both purps were out of service for approx. 25 mins while they were being vented which is within the 1 hr action statement time limit of Tech spec 3.4.1.3. To prevent recurrence the procedure which controls the operation of the RHR purps has been changed to include specific instructions to stop the operating JlU1'>

prior to starting the second pulp while at half-loop.

RHR2B Diablo Canyon 2 04/10/87 Mode 5 1 hr 28 min (frcm LER Search): On April 10, 1987, at 2123 PDT, with the Unit in Mode 5 (cold shutdown) during a refueling outage, RHR flow was interrupted when both RHR trains became inoperable due to airbound RHR purps. The 10 CFR 50.72 report was made at 2230 POT. The RCS had been drained to midloop level for SG nozzle dam installation. The loss of RCS inventory to the reactor coolant drain tank due to a leaking valve caused a decrease in RCS water level, vortexing in the purps* suction line, and air entrainnent in the RHR purps. At 2251 PDT, after verification that the SG manways were still installed and after venting of the RHR JlU1'>5, the RCS was flooded from the refueling water storage tank and an RHR pulp started. RHR flow was interrupted for approx. 1 hr and 28 minutes. This resulted in some localized boiling and, contrary to TS 3.0.4, an inadvertent entry to Mode 4 (hot shutdown) but no damage to the core or significant radiological release occurred. The unit was stable at 0230 FDT, April 12, 1987, and was returned to normal Mode 5 midloop operation. The nunerous actions taken to prevent recurrence of this event, including procedure revisions, training, and design changes, are described in the text of this LER.

RHR2B Millstone 2 03/14/79 Mode 5 (from NSAC52, p. A-9>: RCS level was drained to the hot leg center line for SG eddy' current testing.

RHRS flow was lost due to RHRS pulp air binding. Attenpts at pulp.venting and transfer to the alternate pulp were unsuccessful. When RCS teq>erature increased to 190 F, the RHRS purp suction from the RWST was opened to prime the suction. This action restored flow, but resulted in RCS floodup and spillover of approx. 15,000 gallons of water through the open S/G manway to contaiment. Teq>erature reached 208 F during the transient. Containment integrity was verified prior to entering Mode 4.

RHR2B North Anna 1 10/19/82 Mode 6 36 min (from Seabrook): On October 19, _1982, suction to the A and B Residual Heat Removal System (RHR) purps was lost for about 36 minutes. On Oct. 20, 1982, A and B (RHR) pulp suction was lost for 33 minutes.

(from AEOO): RCS drained to below centerline of hot leg nozzles. RHR suction was lost because of low RCS level and incorrect level indication. (10/19/82, 36 min loss)

RHR2B North Anna 1 10/20/82 Mode 6 33 min (from Seabrook): Not found in A-2 (from AEOO): RCS drained to below centerline of hot leg nozzles. RHR suction was lost because of low RCS level and incorrect level indication. (10/20/82, 33 min. loss)

A-27

p.

RHR2B 3

PHASE 2 CATEGORY PLANT NAME North Arna 2 LER DATA BASE* RHR2B EVENT DATE 07/17/82 INITIAL PLANT CONDITI~N Mode 5 08/27/93 RECOVERY TIME (from Seabrook): Not found in A*2 RHR2B North Anna 2 07/30/82 46 min (from AEOO): Lost suction to 11A11 RHR l)U1'l clue to draining. Diagnosed as a l)U1'l problem. The us 11 was then started and it also became airbouncl (46 min. loss).

RHR2B Palisades 10/15/87 Cold shutdown 29 min (from LER Search): on Oct. 15, 1987, at 1837, low pressure safety injection CLPSI) l)U1'>, P*67A CBP;P) was manually secured from operation due to erratic discharge pressure and flow. The reactor was in cold shutdown condition with the primary coolant system (PCS) CAB) drained to the 617 1811 level (centerline of the.hot and cold legs is at 618 1 211 ) at the time of the event. The PGS was drained to the centerline in order to support steam generator CAB;SG) nozzle dam modifications. At the time of the event, LPSI l)U1'l P*67A was taking suction froni the PCS at the hot leg, discharging through shutdown cooling heat exchangers E*60A and E*60B CBP;HX) and returning flow to the PCS at the cold legs. The erratic discharge pressure and flow were the result of an i111Jroperly placed jUll1Jer which caused a LPSI discharge valve to cycle open/closed. The failure to properly place the jU111Jer was the result of a data transposition error during the plaMing phase for "as-left" valve testing. Shutdown cooling flow was isolated for 29 minutes, with PCS teqlerature increasing from 92 to 129 degrees F. Shutdown cooling flow was restored after the errantly placed jU111Jer was removed. All similar valve testing was iamediately stopped and all jU111Jers installed to support testing removed.

(from NUREG-1410) The reactor was in cold shutdown with the reactor coolant system drained to mid-loop for steam generator nozzle dam modification. An errantly placed jUll1Jer in the control circuit for the operating low pressure safety injection l)U1'l caused the valve to cycle open and close. The valve cycling caused the reactor coolant system level to rise and fall, which resulted in 1000 gallons of water being -pu1')ed out through the open steam generator manways. The l)U1'l was then tripped by the operators. During the 29 minutes decay heat removal was lost, the reactor coolant tenp. increased from 92 deg Fah. to 129deg Fah.

RHR2B Salem 1 06/30/79 Mode 6 34 min (from NSAC52, p. A*9): Reactor vessel level was lowered to approximately one inch above the low operating level for the RHRS l)U1'>. The operating~ started to lose suction and was secured.

Reactor vessel level was increased six inches, and the RHRS l)U1'l restarted. Flow was lost for 34 minutes.

RHR2B Sequoyah 1 10/09/85 Mode 5 (from Seabrook Sheet 8 of 9) At 1807 CST during cold Shutdown, swap over from B Train to A Train Residual Heat Removal CRHR) resulted in both trains becoming inoperable due.to air injection into the suction of the pull1JS. This requires both pull1JS to be vented and required RCS level to be raised from 695 ft. 1 in. to 695 ft. 5 in. to prevent a possible recurrence of the vortex problem. Suction for RHR comes from the Loop 4 hot leg which has centerline of 695 ft. 5 in.

(from CR5015): Power level* OX. On 10*9*85 at 1807 CST during cold shutdown, swap over from 1 8 1 train to 'A' train RHR resulted in both trains becoming inoperable due to air injection into the suction of the l)U1'>S. TMs required both l)U1'lS to be vented and required RCS level to be raised from 695 1 1" to 695'5" to prevent a possible recurrence of the vortex problem. Suction for RHR comes from the loop 4 hot leg which has a center line of 695 1 511

• The cause for the loss of flow can be attributed to the additional suction caused by placing the standby RHR l)U1'l inservice coupled with the low RCS level of 695 1 111

• System operating instruction (SOI)-74, "RHR System," is being revised to change the lower RCS operating limit from 695 1 011 to 695 1 611 and will require the operating l)U1'l to be removed from A-28

p. 4 LER DATA BASE* RHR2B 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME service prior to starting the standby purp. The unit was in cold shutdown with only a 0.2 degrees F rise in RCS temperature resulting from the event. Tech Spec 3.4.1.4 action.CB> says that"* ** with no RHR loops in operation, suspend all operations involving a reduction in boron concentration of the RCS. 11 At the time of this event, the chemical volume control system (CVCS) (Makeup System) was tagged out of service; therefore, no violations of Tech Specs occurred.

RHR2B Sequoyah 1 01/28/87 Mode 5 30 min (from LER Search): Units 1 and 2 were in Mode 5 at 0% power. Previous to this event, the Unit 1 RCS water level was drained down to elevation 695 1 611 for SG maintenance work. Due to a faulty level indication of 696 1 6" in the RCS water level indication system, the operator was lowering the water level back to about 695 1 6'1

• The RHR putp 1A*A began to lose suction as indicated by the motor current and purp flow rate meters oscillating and the miniflow valve opening. The operator inmediately stopped the puip; entered the action statement of Tech Spec LCO 3.4.1.4; and began to align RHR puip 1B-B for letdown to chemical volune control system (CVCS), vent puip 1A-A, and raise water level using the charging putp. S~utdown decay heat removal was lost at 0620 EST and reinstated at 0750 EST. RCS temp.

increased by 20 F, and the detectable boron concentration was not reduced. About 500 gallons were spilled from the SG manways since the water level was being increased by the charging purp. No personnel were injured, and there was no equipment damage. The cause of the faulty level indication was collection of debris in the inlet to the sight glass which was being monitored. Operations initiated weekly flushings of the sight glass and installed a redundant tygon tube which will be COllpSred to the sight glass level on a daily basis *

• (from NUREG-1410): The reactor coolant system had been reduced to mid-loop for steam generator work.

Because of a faulty level indicator, the reactor coolant system water level was reduced U'ltil the operating residual heat removal putp started losing suction. Approx. 500 gallons of water were spilled from the steam generator manways when level was increased using the charging purp. The false level indication was caused by the presence of debris in the inlet to the sight glass which was being monitored. During the 90 minutes that decay heat removal was lost, the reactor coolant temp. increased*

from 95 deg Fah to 115 deg Fah.

RHR2B Sequoyah 1 05/23/88 Mode 5 (from LER Search): On May 23, 1988, at 1215 EDT, while Unit 1 was in cold shutdown with the reactor coolant system (RCS) partially drained to support maintenance, a loss of the operating train of the residual heat removal (RHR> system occurred. The "B" train of RHR was in operation when it was decided to place the "A" train RHR heat exchanger in service to enhance plant temperature control. To place the "A" train in service, an assistant unit operator (AUO) was dispatched to open two valves. The AUO, however, misunderstood the instruction and wrote down an incorrect valve nunber. The incorrect valve was a manual valve (1-HCV-74-34) used to align the discharge of the RHR purps to the refueling water storage tank (R~ST). Upon opening valve 1-HCV*74*34, the AUO heard unusual flow noise and subsequently telephoned the control room CCR) operator for further instructions. The assistant shift operation supervisor (ASOS) in the CR received an RHR mini flow alarm, and noticed RHR putp alll)erage oscillating, unstable flow indication, and the indicated RCS water level was off-scale low. The ASOS subsequently stopped the 11 811 train RHR puq:> and entered the applicable action statements of Tech Specs for a Loss of RHR. The RCS was then refilled above the top of the RCS loops by gravity feed from the R~T via the RHR system.

RHR2B Surry 1 05/17/83 Mode 5 (from Seabrook Sheet 3 of 9): The B RHR puq:> was removed from service on two occasions due to cavitation. This resulted in less than two operable RHR loops and no loops in operation.

(from AEOD): Inaccurate standpipe level indication - low RCS level, RHR purp cavitated. (Duration of A-29

p. 5 LER DATA BASE* RHR2B 08/27/93 PHASE 2 PLANT NAHE EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME event unknown)

RHR2B Trojan 05/04/84 Mode 5 40 min (from Seabrook Sheet 4 of 9): During an RCS drain down to support refueling operations at 1650 on May 4, 1984, Residual Heat Removal CRHR) Cooling could not be reinitiated for a total of 40 minutes due to air entrail"lllent in the suction of the A RHR ~ - Both RHR !)U1')S had been stopped for ten minutes for amual ESF actuation response time testing. An additional 30 minutes were required to restore sufficient RCS water inventory to restart an RHR puip. The 8 RHR 1)1.111) was then started and the RCS t~rature rise was terminated. The highest indicated RCS hot leg t~rature reached about 201 deg Fahrenheit.

(from AEOO): During RCS draindown faulty level measurement led to air binding of the RHR 1)1.111). The RCS was vented to atmosphere. A tygon manometer configuration was being used to measure RCS level, however, 11crud blockage" of the manometer tap led to erroneous level measurement. RCS t~rature went from 105 deg Fah to 201 deg Fah (40 min. loss).

RHR2B Zion 2 12/14/85 Mode 5 75 min (from CR5015): Power level - 0%. On 12-14 at 3:25, 28 RHR ~ became airbound as a result of vortexing. Unit 2 was in cold shutdown with the reactor head installed but not tensioned and the RCS vented to atmosphere. 2B RHR PJ1') had been in operation providing decay heat removal with RHR letdown in progress and 2B charging 1)1.111) providing make-up flow to the RCS. Decay heat removal was lost for 75 minutes with a RCS change in t~rature of 15 degrees F. The unit had been shutdown for approx. 100 days therefore the safety significance was minimal. The cause of the event was identified to be inadequate procedures coupled with the lack of knowledge of the level at which the RHR Pl.l11)S begin to cavitate. As a contributing factor, there were problems found with the level indication. To prevent recurrence, procedures will be reviewed and changed reflecting the lessons learned. :Training will be concb:ted on RCS level measurement and loss of RHR suction. The RCS level system will be modified in order to provide reliable remote level indication during all refueling configurations.

RHR2B Zion 2 01/13/86 Mode 5 75 min (Sheet 9 of 9) The 2B Residual Heat Removal (RHR) puip became airbounc:I as a result of vortexing. Unit 2 was in cold shutdown (Mode 5) with the reactor head installed but not tensioned and the reactor coolant system (RCS) vented to atmosphere. 2B RHR puip had been in operation providing decay heat removal with RHR letdown in progress and 28 charging 1)1.111) providing makeup flow to the RCS. Decay heat removal was lost for 75 mintues with an RCS change in teff1:). of 15 deg Fahrenheit. The unit had been shutdown for approx. 100 days; therefore the safety significance was minimal.

A-30

_J

p. 1 LER DATA BASE - RHR3 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHR3 Arkansas 2 11/14/79 Mode 5 3 hr (from NSAC52, p. A-23): Small Leak discovered in socket weld on LPSI flow*orifice valve. LPSI system (RHRS) was out of c011111ission for three hrs for weld repair.

RHR3 Calvert Cliffs 2 03/24/87 Mode 6 15 hr 20 min (from LER Search): At 1330 on March 24, 1987, with Unit 2 in mode 6 at OX power, two in hole leaks were discovered in the 1/211 diameter inlet piping to a relief valve (2-RV-439) in the shutdown cooling CSOC)/low pressure safety injection (LPSI) system header. Borated water was spraying from the area where the pipe was welded to the header nozzle at the rate of approx. 1 gpm. At 2330 on March 24, 1987, shutdown cooling flow was reduced below the Tech Spec requirement of 3000 gpm and Unit 2 entered an action statement. At 0430 on March 25, 1987, an alternate cooling path from the reactor vessel hot leg nozzle, through LPSI pl.lip #22 through the SDC heat exchanger to the spent fuel pool and the fuel transfer canal and to the refueling pool was established. At 0920 work was begun on replacing the leaking pipe spool and relief valve with a tenporary mechanical device (i.e., nipple and cap) per plant procedures. After this replacement was conpleted, SOC was reestablished in the nranal mode at 1450 on March 25, 1987. The time spent in the action statement (i.e., event duration) was 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and 20 minutes. On March 31, 1987, a facility change request (FCR) #87-29 was approved to investigate the piping and support configuration at 2RV 439 and to implement design changes if required.

RHR3 Calvert Cliffs 2 05/07/87 Mode 5 16 hr 55 min (from LER Search): At 0700 on May 7, 1987, with Unit 2 in Mode 5 at OX power, a leak was discovered in the 0.5 11 diameter inlet piping to a relief valve C2*RV-439) in the shutdown cooling (SOC)/low pressure safety injection CLPSI) system header. At 1400 containment integrity was established per plant procedures and an alternate cooling path to the core was established using high pressure safety injection (HPSI) ~ #22 and containnent spray plJlp #21. At 1410 with no SOC loops operable, unit 2 entered an action statement. The cracked pipe spool was replaced and SOC loop #21 was retumed,to service at 2355 on May 7, 1987. The event duration was 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> and 55 minutes. Because of a similar failure of the inlet pipe to this relief valve on March 24, 1987 and the subsequent installation of a new inlet piping support; analysis to determine the cause of failure was conducted. Metallurgical examination determined the mode of failure to be fatigue due to cyclic torsional/bending loading. An analysis and redesign of the inlet piping was performed and the new piping configuration installed on May 23, 1987. Piping associated with other relief valves in the LPSI and HPSI systems will be reviewed for similar configuration and support problems.

RHR3 Crystal River 3 02/12/86 Mode 5 See description of Crystal River 3, 02/02/86 event.

RHR3 Farley 2 09/28/83 Mode 6 (from Seabrook): The 2B RHR purp tripped while the B RHR loop was in service and the A RHR loop was secured.

(from AEOO): Operating RHR P\.11'> failed while redundant purp was secured. (Duration of event unknown)

RHR3 McGuire 2 03/07/83 Mode 6 3 hr While moving a tenporary incore detector, the rope used to hold the detector cable fell into the reactor vessel and was drawn into C Hot Leg. Residual Heat Removal (RHR) PUl1) 2A was secured from service for 3 hrs (with PUl1) 28 also secured) to allow rope retrieval efforts.

A-31

p. 2 LER DATA BASE - RHR3 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

--* --* .-- -- . --. . .~ - ---.-. --. - ... .. - . -

RHR3 Salem 2 04/13/81 Mode *s 5 hr 22 min (from NSAC52, p. A-25): All RCPs and RHRS ~ s were de-energized to facilitate the replacement of a relief valve in the RHRS. Tech specs allow these pumps to be de-energized for one hour. The maintenance and restoration of RHRS flow required 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 22 minutes.

A-32 *

• p.

PHASE 2 CATEGORY

---~-. --

RHR4 Arkansas 2 PLANT NAME LER DATA BASE - RHR4 EVENT DATE

-- -.- -- -. --- ---------- -- -- -- --- --- -----01/01/79 INITIAL*PLANT CONDITION 08/27/93 RECOVERY TIME Heide 5* .

See description of Arkansas 2, 01/09/83 event. (Date of this event is d ~ date--date not specified in description.)

RHR4 Arkansas 2 10/13/79 Mode 6 (from NSAC52, p. A-30): An RHRS heat exchanger tube leak was indicated by an increase in the heat exchanger radiation 11100itor reading. The heat exchanger was then isolated on both the service water and reactor coolant sides.

RHR4 Arkansas 2 01/09/83 Mode 5 An alarm was received on the Service Water (SW) monitor CWRITS-1453) for the shutdown cooling (SOC) heat exchanger (2E-35A) which indicated the possibility of a tube leak. Radiochemistry sall1)ling verified the tube leak.20-35A was secured and the redundant heat exchanger (2E-35B) was placed in service. Since this leak from the SOC system to the SW system was a degradation of a system designed to contain radioactive matter. A previous occurrence regarding SOC tube leaks was reported in LER-79-086. It should be noted that this heat exchanger tube bundle had been replaced during the last Unit 2 refueling outage.

RHR4 Crystal River 3 02/02/86 Mode 5 24 min (from Seabrook): The Reactor Coolant system was vented to the Reactor Bldg atmosphere and drained below the level of the reactor coolant PJIPS* At 2148 hrs, decay heat~ tripped due to a motor overload caused by a ~ shaft faiCure. Start up of the redundant PJ1'> was delayed because an isolation valve on the suction side of the plJIP could not be opened from the Control Room. The valve was manually opened and system operation was restored at 2212 hrs. On 2/12/86, the B train of the Decay Heat Removal System was being refilled and movement of the~ and piping was noticed.

EXB!llination of pipe restraints in the system revealed that several pipe hangers were loose or damaged.

All damaged equipment has been repaired. Both *decay heat purps have been rebuilt.

(from CR5015): Power level - OX. on Feb. 2, 1986, Crystal River Unit 3 was in Mode 5 while perfoming repairs on a reactor coolant plJIP. The reactor coolant system was vented to the reactor bldg atmosphere and drained below the level of the reactor coolant purps. At 2148 hrs, decay heat PJ1'> 1B tripped due to a motor overload caused by a plJIP sh~ft failure. Start-up of the redundant plJIP was delayed because an isolation valve on the suction side of the puip could not be opened from the control room. The valve was manually opened and system operation was restored at 2212 hrs. On Feb. 14, 1986, the 11811 train of the decay heat removal system was being refilled and movement of the PJ1'> and piping was noticed. Examination of pipe restraints in the system revealed that ~.eyerat pipe hangers *were loose or damaged. All damaged equipment has been repaired. Both decay heat purp; have been rebuilt.

Decay heat removal system operating procedures have been revised to address mini111.111 required reactor coolant level and provide iq,roved fill and vent instructions. New breaker and torque switch settings have been established for the isolation valve. Preventative maintenance procedures will require periodic lubrication of the valve drive shaft.

RHR4 Farley 2 11/27/87 Refueling outage *

(from LER Search): This special report is being submitted in accordance with Technical Specification 3.4.10.3. At 0445 on 11-27-87, during a refueling outage, a residual heat removal (RHR) loop suction pressure relief valve opened when one of two series RHR containnent suq, suction valves in the same train (HOV 8812A) was stroked. Reactor coolant system (RCS) pressure and pressurizer level decreased.

The level and pressure in the pressurizer relief tank (PRT) (to which the RHR relief valve relieves) increased and the PRT rupture disk ruptur-ed. Based on these indications, it was believed that the relief valve may have stuck in the open position. To isolate the relief valve, the operators stopped the RHR P'1'> in the affected train and closed the loop suction isolation valves. This event was apparently caused by a localized pressure pulse created when MOV 8812A was opened. The section of pipe A-33

p.

PHASE 2 CATEGORY 2

PLANT NAME LER DATA BASE - RHR4 EVENT DATE INITIAL PLANT CONDITION 08/27/93 RECOVERY TIME between the two contairment surp suction isolation valves had bee~ drained to perform~ local' leak rate test and had not been refilled. Apparently, the filling of this space, which. occurred when MOV 8812A was opened, caused a localized pressure pulse which resulted in the lifting of the relief valve. To prevent recurrence, the applicable procedure.swill be changed to ensure that lines drained for local leak rate testing are subsequently refilled.

RHR4 McGuire 1 11/23/88 Mode 6 39 min (frcm LER Search): On 11/28/88, at 1643, perfonnance personnel were perfonning the contairment spray (NS) system valve stroke timing procedure for valve 1NS-18, NS suction frcm contairment surp. About 25 sec after the execution of the valve stroke timing test, RHR (ND)~ 18 lost its suction pressure and

• operations (OPS) manually stopped the pul1) to prevent damage to the purp. Unit 1 was in mode 6, refueling, with train 18 of the ND system in operation. OPS ill1)lemented loss of ND procedure, and directed the reactor head maintenance crew to exit the reactor cavity area. At 1722, OPS after ensuring that ND train 1A was properly fjlled and vented, cross connected train 1A to the train 18 heat exchanger to pressurize the train 1A piping, started NO purp 1A, and put train 1A of the ND system in service to provide decay heat removal for the reactor coolant (NC) system. Between 1643 to 1722, the NC system tenp. increased frcm 90 F to 116 F. At 1930, after filling and venting ND train 18 piping and ND JXIIP 18, OPS started ND pulp 18. At 1950, train 18 of the ND system was put back in service and at 2108, OPS secured ND train 1A. This event is assigned a cause design deficiency because inadequate system venting in the horizontal piping between valves 1NS-18 and 1NI-1848, SI contairment surp 8 train isolation, allowed air to be trapped in the piping and forced the air to the suction of ND purp 18 causing the purp to beccme air bound *

. .RHR4 North Anna 1 06/14/82 Mode 5 on 6/14/82, only one of the coolant loops listed in T.S. 3.4.1.3 was operabl'e due to the failure of. the Residual Heat Removal Subsystem 8 Plllp (1-RH-P-18).

RHR4 North Anna 2 08/02/82 With the reactor coolant system drained to mid-loop, one residual heat removal purp was operating.

When flow frcm the operating residual heat removal purp decreased, approx. 200 gallons of water was added to the reactor coolant system to restore flow to normal. Since suction to the operating residual heat removal purp was maintained, decay heat removal capability was not lost. The water level dropped below mid*loop because of a seal leak on one residual heat removal purp ccmbined with inaccurate reactor coolant system water level indication.

RHR4 North Anna 2 08/16/82 Mode 5 The 1A Residual Heat Removal (RHR) purp was removed frcm service thereby leaving operable only one loop for decay heat removal since the 18 RHR pulp remained available to ensure decay heat removal.

RHR4 Rancho Seco 05/05/82 Mode 5 (Sheet 1 of 11) The A Decay Heat Puip inboard bearing was found to be leaking oil. Since the unit was in cold shutdown, the only consequence was the changing over to the 8 Decay Heat purp.

RHR4 Salem 1 12/13/82 Mode 6 (Sheet 2 of 11) At 0750 hrs, 12/13/82, due to excessive leakage from the mechanical seal, No. 12 Residual Heat Removal (RHR) p.1111) was.declared inoperable and Action Statement 3.9.8.2 was entered. No.

11 RHR JXIIP was started to provide RHR flow.

A-34

p. 3 LER DATA BASE - RHR4 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

• 18 i,r*

• RHR4 San Onofre 08/31/87 Mode 5 (from LER Search): On 8/31/87, at approx. 1900, with Unit 2 in Mode 5 and the reactor coolant system (RCS) at approx. 350 psia and 127 degrees F, failure of alloy steel packing gland follower studs during manual operation of motor operated shutdown cooling system (SOCS) suction isolation valve 2HV-9378 resulted in leakage estimated at 100 gpm through the packing gland. Operation of the SOCS continued via a redundant flow path. RCS inventory was maintained by isolating letdown flow and using charging f)U1')S as depressurization and venting of the RCS proceeded. Containment closure was pr~tly restored and there was no effluent release from containment above regulatory limits. At 1100 on Sept. 1, a tell'f)Orary repair was c~leted which reduced the leak rate to approx. 1/4 gpm, effectively terminating the event. The cause of stud failure has been attributed to (1) packing leakage resulting in wastage clue to boric acid corrosion, (2) decrease in lubricating characteristics and hardening of packing, and (3) the initial thrust required to open the valve. Corrective actions include reduction of the maxinun thrust necessary to open the valve by installation of a modified packing gland assenbly less susceptible to leakage and hardening of packing, and replacement of packing gland studs with corrosion resistent material. The health and safety of plant personnel and the public were not affected by event.

RHR4 Turkey Point 3 10/23/85 Mode 5 (Sheet 1 of 2) At 0915 on 10/23/85, the 3A Residual Heat Removal (RHR) ~ was declared out of service COOS) when it did not meet the seal leakoff acceptance criteria during an operability test. At this time, the B emergency diesel generator (EOG) was OOS for maintenance. This placed the unit in a condition where upon loss of off-site power, no RHR loop would be available for core cooling for approx. 18 hrs. Plant management decided since the 3A RHR pulp could still operate and~ water to leave it lined up to the RHR system until the B EOG was returned to service. This would allow for core cooling in the event that off-sit~ power was lost. TS 3.4.1.E requires two coolant loops be operable and one coolant loop in operation whenever the Reactor Coolant System.(RCS) temp. is less than 350 deg Fahrenheit. The 3A RHR pulp being OOS exceeded the requirements of this TS. During *this event, Unit 3 was in cold shutdown with the 38 RHR pulp providing core cooling. The A EOG was *operable and the 3A RHR pulp was lined up to the RHR system to allow for core cooling in the event of a loss of off-site power until the B EOG was placed back in service. No heat up of the Reactor Coolant System was observed while the B EOG was OOS *

• A-35

p. 1 LER DATA BASE - RHRS 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHRS Arkansas Nuclear 1 10/26/88 Mode 6 23'min (from LER Search): On 10/26/88, with the reactor in a refueling mode, I&C te.chnicians working on a trend recorder in a control room cabinet removed an unlabeled fuse thought to be in line with the power supply to the recorder. This resulted in a loss of power to the controllers for both decay heat removal CDHR) cooler outlet valves CV-1428 and CV-1429. Upon loss of power to their controllers the valves went to the closed position, which was inconsistent with their design failure mode of open-Closure of both these valves resulted in the inoperability of*both trains of OHR, due to unavailability of a flow path through the OHR coolers. The event was terminated approx. 20 minutes later when control room operators questioned the I&C technicians about their work, and the technicians reinserted the fuse. During the event, the reactor coolant temperatures increased approx. 18F to a final ten.,erature of approx. 87F. No change in reactor bldg radiological conditions, source*renge counts or reactor coolant level was noted. Investigations after the event revealed that the cooler outlet valves*

electric pneumatic positioner output lines had been reversed causing both valves to fail closed on loss of controller power. The reversed output lines were properly reconnected and both valves were verified to open on loss of power.

(from NUREG-1410) Refueling had been con;ileted and the reactor head re-installed. The reactor coolant system water level was et mid-loop because the reactor coolant~ seal areas and the steam generator manways were open. A technician error caused a loss of power to both decay heat flow control valve controllers, causing the valves to close. Decay heat removal was lost for 23 minutes and reactor coolant temp. increased from 69 deg F to 87 deg F. By design, in order to prevent the unnecessary loss of core cooling capability, the decay heat removal flow control valves fail open upon loss of either control power or control air. Investigation revealed that the valves failed close because the air tubing from the valves* electric-pneunatic positioner had been reversed during installation. The industry was informed of this event in INPO Significant Event R~port CSER) 26-89.

RHRS Arkansas Nuclear 1 12/19/88 zero power 12 min (from LER Search): On 12/19/88 the decay heat removal (OHR) system inboard suction valve (CV-1050) closed resulting in a loss of OHR system flow. Following indication that the OHR suction valve was closing, the plant operator followed the appropriate procedures to secure the operating OHR~-

Actions were then taken which returned the DHR system to operation in approx. 12 minutes. At the time of the event, a contract electrician was performing equipment inspections in the room which contains a panel housing the control relays for CV-1050_ This individual inadvertently jarred the panel housing the control relays for CV-1050 at approx. the time of this event. The cause of this event has been determined to be inadvertent opening of the normally closed permissive contacts of a control relay for cv-1050. As determined during the investigation of this event, the permissive contacts of this relay are sensitive to mechanical shock. As a result of this event, a caution label has been placed at this control panel to caution against mechanical agitation of the panel. A plant modification will be implemented to replace this relay with a model less sensitive to mechanical shock. Additionally, other relays of this type will be reviewed for possible safety or operational problems due to susceptibility of these relays to mechanical shock.

RHRS Beaver Valley 1 05/12/82 Mode 5 2 min (From Seabrook): An attempt to start RHR ~ CRH-P-1B)failed due to a circuit breaker racking mechanism problem. Inmediately prior to this attempt, the power to the bus supplying the operating RHR

~ (RH-P-1A) had been removed in accordance with procedure TOP 82-27. This resulted in an interruption of RHR flow lasting 2 minutes.

(from AEOO): Failure to start RHR ~ due to circuit breaker problem. RHR ~ that had been operating was erroneously secured prior to attempt to startup idle~ (2 min. loss).

A-36

p. 2 LER DATA BASE - RHR5 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

. .... .... - . . .. . : ~ . . - *. . . . .. . . .

RHR5 Calvert Cliffs 1 02/08/80 Mode 5 1 hr 33 min (from NSAC52, p. A-11): A pressure spike during pump venting caused an RHRS relief valve to lift and fail to reseat. (Required relief setpoint as 315 + or - 8 psig, but actual relief setpoint was 285 psig, so pressure spike of approx. 35 psig caused event.) Pressurizer level decreased from 14011 to 9011 (approx. 1,200 gallons of coolant) in about 2 minutes, when the RHRS was stopped and isolated from the RCS, halting the loss of coolant. The relief was gagged and RHRS flow restored 1*1/2 hrs later. An RCP was jogged during the loss of RHRS to circulate coolant.

RHR5 calvert Cliffs 1 05/17/82 2 min (from AEOO): Spurious opening of breaker from the operating DHR pulp (2 min. loss).

RHRS calvert Cliffs 2 01/23/81 Mode 6 5 min (from NSAC52, p. A-24>: Valve position indication was lost for an RHRS suction valve. Questioning the actual valve position, the operator stopped flow teaporarily to prevent possible pulp damage. Valve position indication and flow were restored.

RHR5 Connecticut Y_i3nkee 03/05/88 Mode 5 1 hr 2 min See description of .Connecticut Yankee, 03/10/88 event.

RHR5 CoMeCticut Yankee 03/10/88 Mode 5 1 hr 22 min (from LER Search): On 3/10/88 at 1659 while performing a plant heatup from Mode 5 (RCS pressure= 309 psig, RCS tenp = 108 F) in preparation for a reactor coolant system (RCS) hydrostatic pressure test, a control operator coapleting an operating procedure checklist discovered that the residual heat removal (RHR) system had,been shutdown for gr~ater. than one hour (1 hr, 22 minutes) resulting in a violation of the plant Tech Spec. Following the discovery of this event, a review of the operations log reveafed I

that a similar violation occurred on 3/5/88, during a plant heatup when the operating RHR purp was *.1 shutdown for 1 hr, 2 minutes while still in Mode 5. At the time of the discovery, the plant had already entered Mode 4 where operation of the RHR system is not required.* Therefore, no iamediate corrective action to place the RHR system back in service was necessary. These events are the result of a failure to observe a specific precaution in the plant operating procedure for plant heatup. All licensed operators have been made aware of the violation and changes have been made to the appropriate operating procedures to prevent recurrence. This event is being reported under 10 CFR 50.73(A)C2)CI)(B) since it involved a condition prohibited by the plant's Tech Spec.

RHR5 Cook 2 12/09/82 Mode 6 The west RHR was in service supplying core cooling at 3000 gpm. A reactor coolant high level alarm was received and investigation of equipment showed that the west RHR pulp breaker had tripped.

RHR5 Crystal River 3 07/16/80 Mode 5 21 min (from NSAC52, p. A-12): Gross packing Leak on makeup puip discharge cross connect valve necessitated securing only operable makeup puip, which in turn necessitated securing RCPs due to loss of seal injection. Since the RHRS was not operating, decay heat removal was lost for 21 minutes during interim valve repair. The RHRS was then restored to operation to conduct final repairs. During those repairs, an iq>roper valve lineup on the RHRS heat exchangers caused a rapid cooldown of the RCS and loss of pressurizer level. When recovery was atteq>ted by depressurizing the RCS, and providing RHRS suction from the 811ST, injection flow could not be established due to reverse seating of RIIST check valves from RCS pressure. Inventory loss due to shrinkage caused pressurizer level to remain offscale for approx.

45 minutes.

A-37

p. 3 LER DATA BASE - RHRS 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME (from NSAC52, p. A-24) Same as above.

RHRS Crystal River 3 04/21/81 Mode 5 Similar event 10/01/81 (from NSAC52, p. A-28): Final stages of plant cooldown, RHRS initiated and RCPs secured at 270 F and 250 psis; plant then cooled and depressurized over next 15 hrs to 106 F, 50 psig. During depressurization, the injection of auxiliary spray and coapensating coolant letdown created a slow pressurizer outsurge of greater than 360 F water into the 'A' hotleg. Further depressurization flashed the hot water in the 1A' hot leg. Pressurizer level increased from about 8211 to 18011 (equating to a void of approx. 300 ft3). The A loop hot leg RTD read approx. 300 F, which was above the 50 psig saturation teaperature.

RHRS Crystal River 3 10/01/81 Mode 5 See description of Crystal River 3, 04/21/81 event RHR5 Davis Besse 1 05/31/80 Mode 6 8 min (from NSAC52, p. A-23): Indicated decay heat flow dropped low off-scale. The RHRS pl.ll1' was stopped to prevent possible damage. The other RHRS pl.ll1' was not available due to maintenance. The puip was restarted after cause of low indication was determined.

(from AEOO): 8-minute loss of OHR flow. The operating OHR punp was secured by a control room operator. (An I&C mechanic took a DHR flow meter out of service to perform surveillance testing.

Control room personnel were unaware of this. Upon seeing that the OHR system flow had dropped offscale, a control room operator stopped the punp.)

RHRS Davis Besse 1 04/18/81 Mode 5 1 min (2 min in AEOO-C)

(from NSAC52, p. A-21): As a result of a small fire in a 345 kV bus, a rapid bus isolation was performed. A 13.8 kV bus was not transferred in sufficient time to prevent a loss of essential 4160 V power to the operating RHRS punp. The emergency diesel started and flow was restored in approx. one minute.

(from AEOD): 2-minute loss of OHR flow. In response to 0 two burning potential devices" on a bus, the bus was isolated. An error was made in the sequence of transferring power and isolating the bus.

Power was lost to the operating OHR pc.11p.

RHR5 Farley 1 03/07/83 Mode 6 The A Train RHR system was declared inoperable when the 1A RHR punp was inadvertently secured.

RHR5 Farley 1 11/07/86 Mode 5 A Residual Heat Removal (RHR) loop suction pressure relief valve opened to reduce Reactor Coolant System (RCS) pressure. On 11/7/86, the RCS (in the solid condition) pressure was being increased to 400 psis prior to starting A Reactor Coolant Puq:, (RCP). The operator increased pressure too rapidly and was unable to stop the increase prior to the 18 RHR loop suction pressure relief valve opening.

The opening of the relief valve controlled and reduced the RCS pressure. On 11/15/86, the RCS was being maintained in the solid condition at approximately 400 psis with the 18 and 1C RCPS running.

Depending on plant conditions, RCS pressure while solid can either increase or decrease when starting RCP. The operating crew had anticipated a pressure decrease; however, pressure increased when the 1A RCP was started. The operator tried to limit the pressure increase but the 1A RHR loop suction A-38

p. 4 LER DATA BASE - RHRS 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

--*---- ***-----. h.-----.--- .------ ... -- .--.- ~- - ... ---. -.* -:--- -- . -- . . . - . -

pressure relief valve opened. The opening of *the reli.ef valve ~ontrolled anci reduced RCS 'pressure.

RHRS Farley 1 11/15/86 Mode 5 See description of Farley 1, 11/07/86 event.

RHR5 Ginna 05/01/83 Mode 5 (from Seabrook): The R~ST level had decreased to 20% level which required by procedure to stop one RHR

~ - The A RHR pi.lllp was stopped and flow dropped to zero. Control Room operator noticed MOV*704B (B RHR ~ suction valve) closed. The A RHR ~ was restarted and flow reestablished and the B RHR ~

stopped. Thus for a period of less than two hours while filling the reactor cavity the B RHR JlU1'> was run with its suction valve closed. The auxiliary operator checked B RHR ~ and found it warm but no seal leakage. The l)U1'> was tested for flow and vibration with conditions found normal.

(from AEOO): Filling reactor refueling cavity - low R~T. secured "A" RHR ~ - SUction valve on operating 11811 pc.np was closed. (Duration of event unknown)

RHR5 Indian Point 3 05/12/83 Mode 5 A small leak was identified on the RHR miniflow at the weld joint between valve 1870 and Line 337.

RHR5 Maine Yankee 06/10/81 Mode 6 5 min (from NSAC52, p. A-19): RHRS flow was interrupted when an outboard stop valve closed. Valve reopened and flow re-established in five minutes.

RHRS Mill~tone 3 06/08/87 Mode 5 33 min (from LER Search): On June 8, 1987 at 1345 hrs and 0% power, *an inadvertent IIIOde change from mode 5 *

(cold shutdown) to Mode 4 (hot shutdown) occurred. The incident occurred during an investigation by plant personnel to determine why the train B residual heat removal system suction isolation (from the reactor coolant system) valve did not stroke during the previous plant cool-down. The root cause of the inadvertent mode change was operator error. The reactor operator failed to monitor reactor coolant system temperature for a period of 33 minutes and did not identify the possibility of a mode change due to the isolation of the heat sink for the reactor coolant system. The entry into Mode 4 occurred before the appropriate plant technical specifications for the mode change were satisfied. After the incident was identified, the inmecliate operator action was to return the plant to Mode 5 (cold shutdown) below the maxi111111 temperature requirements. As corrective action, operators have been briefed of the incident and have been reminded of the iq>ertance of 1110nitoring plant responses during evolutions. The operator directly involved in the incident has been relieved of license duties until demonstrated deficiencies in performance can be resolved by plant management.

RHRS North Anna 1 06/01/80 Mode 5 34 min (from NSAC52, p. A-12 and p. A-24): To check the size of the packing gland on an RHRS valve, the packing gland nut was loosened. The mechanic was not aware that RCS pressure was being increased. The packing came loose, dislodging the packing nut, and leaking primary water into contair,nent. To reduce RHRS pressure, the operating RHRS punp was secured for 34 minutes and the RCS pressure reduced while the packing nut was teq,orarily installed. One RHRS ~ was then operated for 54 minutes. The ~

was then secured again to repack the valve. Neither RCPs or RHRS puips were operated for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 43 minutes while repacking the valve.

A-39

p. 5 LER DATA BASE - RHR5 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHR5 North Anna 1 02/18/83 Mode 5 5 min (from Seabrook): On 2/18/83, indications of cavitation were observed on B Residual Heat Removal (RHR)

~ and later on A RHR puip. The B Pc.J1'l was started and returned to service in approximately 5 minutes. An RHR PtJJ1) operability was subsequently verified.

(from AEOO): Both RHR Pc.J1'>S were cavitating. Cause not detennined (5 min. loss).*

RHR5 Oconee 1 06/29/81 Mode 5 (from NSAC52, p. A-29): Final stages of plant cooldown: RHRS initiated and last RCP secured at 225 F, 310 psig. Pressurizer level was then reduced from 250 to 100 inches to fulfill an omitted requirement (procedure required lowering pressurizer level to 10011 before securing RCPs). This RCS letdown moved 4,000-5,000 gallons of stagnant 423 F water from the pressurizer to the "Au hotleg. The RCS pressure was then lowered. After about 25 hrs of pressurizer cooldown, pressure was lowered below saturation pressure for the hottest water in the "A" loop (120 psig, 350 F). A steam bubble of approx. 300 cu.

ft. was fonned in the top of the "A" loop "J" leg. A rapid pressurizer insurge occurred as the 300 cu.

ft void was fonned.

RHR5 OConee 3 04/06/87 Mode 5 (from LER Search): on April 6, 1987 at approx. 1500 hrs the reactor coolant (RC) system on Unit 3 was cooled to the extent that technical specification limits in Table 3.1-2 were exceeded. Unit 3 was at cold shutdown and in preparation fo~ startup following a refueling outage. The inadvertent cooldown was due to reactor coolant leaking through the outlet valve (3LP-12) of 3A low pressure injection cooler while. the shell side of the cooler was being flushed with low pressure service water. The leakage through 3LP*12 and subsequent cooldown occurred when 3LP-11 was opened in the process of performing an equipment restoration procedure. The root cause of the event was that the procedure for performing.maintenance on 3Lr-12 did not provide adequate guidance to direct personnel on how to adjust the closing limit switch on valve operators which are controlled by a limit switch on the closing stroke. Imnediate corrective actions were taken to isolate the low pressure injection cooler and secure the RC flow by closing valve 3LP-9 upstream of the cooler. The leaking valve 3LP-12 was then manually closed. Linear elastic fracture mechanics analysis of the most limiting reactor vessel beltline metal indicated that this event had no effect on the integrity of the pressure vessel.

RHR5 Palisades 07/18/81 Mode 5 1 hr 30 min (from NSAC52, p. A-19): A shutdown cooling heat exchanger outlet valve failed closed, causing loss of RHRS flow. Closure of this air-operated valve isolated flow from both RHRS heat exchangers to the RCS.

Primary coolant temperature increased from approx. 123 F to 197 F.

RHR5 Rancho Seco 10/03/86 Mode 5 13 min (from CR5015): Power level - OX. IJhile in cold shutdown on Oct. 3, 1986, during instrunent & control investigation of abnormal indication on panel H2SFB for decay heat system (OHS) 11811 room Sl.l11) stack lights, SFAS 11811 bistables tripped causing HV-20002 to close, which tripped DHS 11811 pl.l11). The plant was without the use of the normal DHS for approx. 13 minutes. Due to the *extended period that the plant has been s~ut down, there was a small, but detectable increase of reactor coolant temperature.

Steps were taken inmediately to restore a DHS train to service in accordance with the. intent of Tech Spec 3.1.1.5. This event is reportable according to 10 CFR Part 50.73(a)(2)(1V & V). The cause of the incidents was l&C technicians troubleshooting abnormal indication on panel tl2SFB for DHS ue 11 puip room (east) Sl.l11) stack lights (1811 level indication) on panel H2SFB. The iamediate cause of the spurious actuation was an electric arc from the Sl.l11) level stack light when 11 rolling-over 11 the respective bulb.

The arc initiated the trip of inverter 11 811

• As a long term corrective action, the DC vital power supplies will be modified to be equipped with static transfer switches.

A-40

p. 6 LER DATA BASE - RHRS 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVER)(

CATEGORY DATE CONDITION TIME

. .. .. . .. . .. . ~ *. .. . . ..

RHRS Robinson 06/11/87 zero power (from LER search): On June 11, 1987, during zero power physics testing following a refueling outage, a valve packing failure resulted in primary system leakage of approx. 23 gallons per minute. An unusual event was declared. Initial indications were that the leak was from the #1 seal of 11 C11 reactor coolant pulp. Based on an erratic standpipe level and high temperature in the seal leakoff Line, the pulp was stopped. Later, similar indicatio'ns were noted for the "B" reactor coolant puip and it too was stopped. Subsequent investigation of the leakage determined the source of the leak to be residual heat removal valve RHR-750 inside contairment, based on high temperature in its leakoff lines. Conmon piping is shared by this line and the~ seal leakoff lines. The packing was replaced, the unusual event terminated, and plant startup reinitiated. The need for additional long-term corrective action is being evaluated.

RHRS Salem 2 06/12/81 Mode 4 1 hr 5 min (from NSAC52, p. A-13): During plant cooldown, the RHRS suction relief valve lifted. RHRS puips were secured and the RHRS suction valves from the RCS were closed to halt the loss of inventory. The RCS depressurization transient was terminated 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 5 minutes after _the relief valve actuation. The RHRS was returned to service and RCS pressure increased to 335 psig.

RHR5 Salem 2 05/24/83 Mode 5 (from Seabrook Sheet 5 of 11): No. 21 Residual Heat Removal (RHR) P<Jll1' and No. 21 Fuel Handling Bldg exhaust fan were observed to trip. Deenergization of No. 21 RHR puip resulted in no RHR loop being in operation and Action Statement 3.4.1.4B was entered. The purrp was inmediately restarted and flow restored. No reduction in Reactor Coolant System Boron concentration occurred ~ith the RHR loop inoperable.

(from AEOD): RHR puip trip caused by logic/circuitry problem on the "safeguards equipment control" (SEC) system. (Duration of event unknown)

RHRS San Onofre 2 03/14/82 Mode 6 90 min (Sheet 1 of 5) Shutdown cooling was lost due to nitrogen intrusion as a result of backflushing a filter in the purification system. Shutdown cooling flow was lost for 90 minutes. Public safety was not endangered because no irradiated fuel was in the core.

RHR5 St.mmer 11/06/84 7 min (from AEOD): A procedural error in testing relays on the bus supplying the OHR pulp caused the bus to strip. The associated diesel was out for maintenance (7 min. loss).

RHR5 Surry 1 03/18/89 zero power 11 hr 28 min (from LER Search): On 3/18/89, at 0912 hrs, it was discovered that the manual RHR and c ~ t cooling (CC) valves to the "A" RHR heat exchanger (HX) were open, but the manual RHR outlet valve of the "B" HX was closed. In addition, the CC isolation trip valve TC-CC-109A was closed thus prohibiting CC flow through the "A" RHR HX. Consequently, with no CC flow through the "A" HX and no RHR flow through the 11 B11 HX, there was no RCS cooling loop in operation. This condition had existed since 2144 hrs, March 17, 1989 and is contrary to Tech Spec 3.1.A.1.D.2. The CC containnent isolation trip valve for the "A" RHR HX was reopened, restoring cc flow to the HX, terminating the loss of RHR cooling and the RCS heat up. Following this discovery, a root cause analysis was performed by the personnel involved. The cause of the event was operator error. The operators were under the incorrect ass~tion that the "B" RHR HX outlet manual isolation valve was in the open position. In addition, the CC trip valves were manipulated without use of a procedure. Other contributing factors were also identified. Personnel associated with the event were disciplined. The nutber of off-shift licensed A-41

p. 7 LER DATA BASE - RHR5 08/18/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY' CATEGORY DATE CONDITION TIME operators permitted to assune licensed positions on the same shift has been limited. In addition~

off-shift operators rm.ist be relieved by an on-shift operator.

RHR5 Surry 2 02/19/86 Mode 5 10 min (from CR5015): Power level - 0%. On 2-19-86 with Unit 2 at cold shutdown, operators were performing a test of the component cooling (CC) check valves in the residual heat removal (RHR) system. During this test, an operator made an incorrect valve lineup which resulted in the isolation of CC flow to the 'A' RHR heat exchanger and RHR flow to the *s* RHR heat exchanger for approx. 10 minutes. During this period, RCS temperature and pressure were closely monitored and no abnormal increases were noted. The root cause of this event was hlJllan error in that the operator failed to follow the steps in the written procedure which would have ensured the proper valve lineup. A contributing factor was poor CCllllUl'lication between the control room operator and the operator performing the valve lineup. The operators involved in this event prepared a report describing the circunstances which led to this error and it will be placed in the operator's required reading manual. This event will also be evaluated by the h1.1Dan performance evaluation coordinator.

A-42 *

p. LER DATA BASE* RHR6 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME RHR6 Beaver Valley 1 05/03i81 Mode 4 (from NSAC52, p. A-26): In the process of putting the RHRS in operation, one of the RHRS suction valves would not open, precluding use of the RHRS. The valve was *subsequently opened manually.

RHR6 Crystal River 3 03/04/79 Mode 4 (from NSAC52, p. A-26): During RCS cooldown, both series RHRS suction valves could not be opened from the control room. Both valves are inside containnent and were opened by hand to permit RH~S flow.

RHR6 *crystal River 3 04/25/79 Mode 4 (from NSAC52, p. A-26): An RHRS suction valve failed to open remotely during plant cooldown, due to various problems with the valve's motor operator. The valve was repaired, tested, and restored to service in 13-1/2 hrs.

RHR6 Davis Besse 1 01/07/81 Mode 4 15 min (from NSAC52, p. A-21): A control roan operator atteapted to start a decay heat l)U1') as a normal step in establishing RHRS flow during plant cooldown. The pull) did not start, and the l)U1') breaker was racked out for inspection. No problems were found; the breaker was racked in, and the l)U1') started successful Ly.

(from AEOO): DHR puip failed to start clue to a breaker problem. Electricians were able to restart the p!.11') after a 15 minute delay.

RHR6 Gil'V18 03/03/84 Mode 4 While cooling down the Reactor Cooling System (RCS) to cold shutdown condition for the annual refueling and maintenance outage periodic: test PT-2.4.1, cold/refueling motor operated valve*surveillance (RHR system - 700 valves) was in progress. MOV-700 (RCS loop A Residual Heat Removal suction stop valve>

failed to stroke to the open position when actuated from the Control Roan.

RHR6 Gil'V18 05/14/84 Mode 4 On 5/14/84, while cooling down the Reactor Coolant System (RCS) to the cold shutdown condition for sludge lancing and crevice cleaning, MOV-700 (RCS Loop A Residual Heat Removal Suction Valve) failed to stroke to the open position when actuated from the Control Room. Following manual unseating of the valve, maintenance persomel performed an inspection of the valve exterior. This inspection revealed that the packing gland flange had shifted out of the vertical position to a point where the flange was in contact with the valve stem. This could have caused a mechanical binding in the stem and torque-out of the valve operator. The valve was then stroked*manually to verify no mechanical binding. The valve was then stroked twice electrically. The valve functioned satisfactorily with proper motor current readings and acceptable opening and closing times indicating no mechanical binding. A visual inspection of the valve stem and stem threads verified adequate cleanliness and lubrication. Torque switch settings were verified withi_n the manufacturers design settings. On 5/22/84 when the RCS was heating up to hot shutdown, the valve was again stroked to verify proper operation. Again, the valve functioned properly with proper motor current readings and acceptable opening and closing times.

Operation of this valve will continue to be monitored during the next cooldown of the RCS.

RHR6 oconee 2 09/18/81 Mode 1 (from NSAC52, p. A-27): Primary to secondary leakage was detected indicating a OTSG tube leak. The i,iit was shut down, cooled down and depressurization initiated to reduce the leak rate. When plant conditions permitted, RHRS operation was attelll)ted. A RHRS suction valve failed to open on demand. A reactor bldg entry was made to open the valve manually. After three unsuccessful atteapts to open the A-43

p. 2 LER DATA BASE - RHR6 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME valve manually, the entire valve operator was removed and the valve opened with manual hoists. RHRS operation was then established, RCPs secured, and the RCS depressurized to stop the OTSG tube leak.

RHR6 Oconee 3 10/15/85 Mode 4 (from Seabrook Sheet 3 of 4) An unsuccessful att~t to open an electric motor operated (EMO) valve (3LP-2) was made from the Unit 3 Control Room. Unit 3 was in hot shutdown after coming off-line for maintenance. The valve is required to open in order to indicate the decay heat removal cooling mode.

(from CR5015): Power level - OX. On 10*15-85 at 0955 hrs, an unsuccessful atteopt to open an electric motor operated valve was made from the Unit 3 control room. Unit 3 was in hot shutdown after coming off-line for maintenance. The valve is required to open in order to initiate the decay heat removal cooling mode. The cause of the incident was the torque switch settings on the valve. Rotork nuclear actuator settings were not set high enough to operate the valve under system pressure. The EMO valve torque switch settings were not specified in the design modification package used to replace the valve actuator with a new Rotork nuclear actuator. The corrective action was to open the valve from the valve actuator contacts at the motor control center, bypassing the valve actuator's torque switch limit control circuit. The analysis supporting the licensing basis for Oconee does not require the ill'lllediate opening of this valve. The failure to ill'lllediately open this valve only results in a delay in the initiation of'decay heat removal cooling mode.

RHR6 Robinson 07/15/82 Mode 6 (Sheet 1 of 4) On both occasions, motor operated valve, RHR-759A, a residual heat removal exchanger discharge valve, failed to open.

RHR6 Robinson 07/27/82 Mode 6 (Sheet 1 of 4) On both occasions, motor operated valve, RHR-759A, a residual heat removal exchanger discharge valve, failed to open.

RHR6 San onofre 2 04/26/83 Mode 4 (Sheet 1 of 4) Preparations in progress for Mode 3 entry, Shutdown Cooling System (SOCS) heat exchanger isolation valves 2HV8150, 2HV8152 and 2HV8153 could not be remotely operated from the Control Room upon initiation of shutdown cooling to avoid personnel radiation exposure from Local operation.

RHR6 Turkey Point 4 05/23/89 Mode 4 (from LER Search): On 5/23/89, at 1820 EST, with Unit 4 in Mode 4 and the reactor coolant t~rture below 350 degrees, residual heat removal (RHR) motor operated valve MOV-4-751, RHR normal suction isolation valve, failed to open with the control switch. This valve was to be opened from the alternate shutdown panel to place RHR in service for its normal heat removal function as part of an operability check of the panel. When this valve failed to open, the reactor continued to be cooled by removing heat through the steam generators. The valve was manually moved from its seat. The valve subsequently stroked smoothly with the control switch. The root cause of this event is hydraulic locking of the valve. To prevent recurrence of this problem, the valve has been modified with an equalizing line which will assure that the pressure in the bonnet of the valve is at an equal or lower pressure than the high pressure side of the valve. Additionally, MOV-4-750, the RHR valve ill'lllediately upstream cif valve MOV-4-751, has been modified. The corresponding Unit 3 valves will also be modified to assure that these valves do not experience a hydraulic locking event. The Unit 3 valves, MOV-3-750 and MOV-3-751, will be modified prior to the Unit's return to power.

A-44

p.

PHASE 2 CATEGORY 4KV PLANT NAME Arkansas Nuclear 1 LER DATA BASE* 4KV EVENT DATE INITIAL PLANT CONDITION 12/05/89 CSO 08/27/93 RECOVERY TIME (from LER Search): On 12/5/89 at 0645 and 12/6/89 at 2205, while the plant was shutdown in a maintenance outage, automatic actuations of an emergency diesel generator (EOG) occurred as a result of loss of power to a 480 volt CV) engineered safeguards (ES) bus. Prior to both events, the BS and 86 480V ES busses were crossconnected to facilitate maintenance activities. The Dec. 5 event occurred as a result of a persOMel error which occurred while operators were attenpting to 11splitout 11 the BS and 86 busses and return the ES power distribution system lineup to normal. The error resulted in a loss of power to Bus 86 which caused the offsite feeder breaker for 4.16 kilovolt bus A4 to open and initiated a start of the 1 8 1 EOG which tied on to the A4 bus. The Dec. 6 event was also the result of a personnel error which caused a loss of power to 480V ES Bus BS. This condition caused the offsite feeder breaker for A3 to trip and the 'A' EOG to start. The momentary loss of power to A3 caused the operating decay heat removal (OHR) pull) to trip. OHR flow was lost for approx. 9 minutes and resulted in a reactor coolant system tenp. increase of 17 degrees. Management briefings were conducted for the operating crews prior to restart from the outage covering the lessons learned from these events.

4KV Arkansas Nuclear 1 12/06/89 cso 9 min See description of Arkansas Nuclear 1, 12/05/89 event.

4KV Arkansas Nuclear 2 11/14/89 Shutdown min (from LER Search): On 11/14/89, maintenance personnel initiated a post maintenance test, using instructions in a maintenance job order, to silll.llate an undervoltage on a 480 Vac engineered safety features (ESF) motor control center (285) by placing a jurper across the 285 *unc1ervoltage relay contacts. Iamediately following this step, the normal offsite power feeder breaker to the associated 4160 Vac ESF bus C2A3> unexpectedly opened resulting in the loss of power to 2A3. The electrical bus deenergized as designed. The test steps provided in the job order did not identify that 2A3 would deenergize *as part. of the test. When 2A3 was deenergized, a tow pressure safety injection CLPSI) P'-fl'>,

which was supplying flow for decay heat removal and a service water pull) deenergized. A standby LPSI P'-f1'> powered from the redundant 4160 Vac ESF electrical bus was started in approximately one minute and flow reestablished. Since* the plant had been shutdown for several days prior to this event, the reactor decay heat levels were low and the momentary interruption of flow did not result in any significant reactor coolant system t~rature or pressure increases. The test was reevaluated and satisfactorily completed. The root cause of this event was determined to be inadequate post maintenance test controls.

4KV Beaver Valley 1 07/03/79 Mode 5 or 6 21 min (from NSAC52, p. A-20): While switching a vital bus to the alternate source, containment isolation phase B (high-high containnent pressure) actuation occurred. This tripped both emergency 4 kV stub bus breakers resulting in loss of the operating RHRS P'-fl'>*

4KV Catawba 1 01/07/89 Mode 5 (from LER Search): On 1/7/89 at approx. 0302 hrs, 6900V tie breaker ITC-7 tripped after reactor coolant (NC) pulp 1C had been started and power to 4160 essential bus 1ETA was lost. The loss of power caused an isolation of the bus with no back-up power available due to diesel generator 1A being out of service. The blackout resulted in a loss of power to residual heat removal pulp 1A, fuel pool cooling pull) 1A, and component cooling P'-f1'> 1A2. Subsequently, due to a charging flow control valve failing open, NC system pressure increased and caused a pressurizer PORV to lift 7 times. The 6900V switchgear 1TC is separated into two sides which are comected by normally open tie breaker 'iTc~i. The tie breaker was closed because 1T2A was out of service. The tie breaker tripped open on overcurrent because a ground overcurrent relay was installed in the time delay overcurrent relay location. The ground overcurrent relay was not designed for the inrush current caused by starting the NC pulp. The A-46

p. 2 LER DATA BASE - 4KV 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

. ~ .. .  : . . *. . .

unit was in Mode 5, cold shutdown, when the incident occurred and had operated'iri ail modes of operation. This incident is attributed to an inappropriate action. It appears the relays were swapped during the initial installation during 1978. Time delay and ground overcurrent relays were placed into the correct locations. An inspection was performed to verify the correct relays were installed in all other similar applications.

4KV Crystal River 3 08/28/89 Mode 5 19 min (from LER Search): Crystal River Unit 3 was in Mode 5 (cold shutdown) to perform repairs to a nuclear services raw water pulp with the 11811 decay heat train (DH) removed from service. The 11A11 DH train was operating and the reactor coolant system was filled and intact with an operable steam generator. At 0237 on Aug. 28, 1989, the 11A11 480 volt engineered safeguards (ES) stepdown transformer faulted causing DH closed cycle cooling~ 11A11 (DCP-1A) to de-energize. Loss of DCP-1A l'"emoved the cooling for DH tl'"ain "A", !"endel'"ing this tl'"ain inoperable. At 0256, DH tl'"ain 11 811 and its suppol'"t systems wel'"e stal'"ted. The 11A11 and 11 8 11 480 volt ES buses wel'"e then Cl'"oss-tied to provide AC powel'" to the "A11 bus.

The loss of DH cooling caused an incl'"ease in RCS terl1)E!l'"atul'"e and an inadvel'"tent entry into Mode 4 (hot shutdown). The tl'"ansfonnel'" has been replaced. The tl'"ansformel'" faulted due to insulation degradation caused by aging. Dul'"ing the event, opel'"atol'"s attempted to opel'"ate the 11811 tl'"ain DH suction isolation valve (DHV-40) fl'"om the contl'"ol l'"oom. This valve failed because the nut secu!"ing the linkage between the motol'" opel'"ator and the valve stem had backed off from nonnal opel'"ation. DHV-40 has been l'"epaired and the nut on the linkage has been staked to pl'"event it from backing off. The l'"edunc:lant valve, DHV-39, will be staked.

4KV Ft. Calhoun 12/14/85 Refueling shut. 15 min (fl'"om !=R5015): Powel'" level - 0%. on 12-14-85 at 1010 hl'"s while in a l'"efueling shutdown, a DC bus and 2 AC instMJDent buses we!"e lost as well as all essential 480V buses. The loss of powel'" initiated safegual'"d signals: pl'"essul'"iZel'" pl'"essul'"e low signal, safety injection actuation signal, contail'1llent isolation act!JStion signal, and ventilation isolation actuation signal. Also lost due to the powel'"

failul'"e we!"e shutdown cooling, compl'"essed ail", tul'"bine plant cooling watel'" and some contl'"ol room indications. The powel'" failul'"e occul'"l'"ed due to the pel'"sonnel el'"l'"OI'" and an altel'"ed electl'"ical distribution system lineup due to testing, maintenance, and modification wol'"k. The technician inadvel'"tently tl'"ippec:1 the l'"elay contl'"olling the breakel'" that was pl'"oviding the 161 kv powel'" to the 4160v 1A4 safeguards bus and which fo tul'"n powel'" all 480V buses including the battery chargel'"s. With the loss of the battery chal'"gel'"s, DC bus #2 became inopel'"able because battery #2 was disconnected fol'"

maintenance. Also, AC instl'"Lment buses Band D were inopel'"able as they al'"e powel'"ed from DC bus #2.

This l'"esulted in a pal'"tial loss of contl'"ol l'"oom indications. Corl'"ective action lncluded.l'"estol'"ing powel'" to the 480V buses within 15 minutes. A meeting was held with the ind.ividuals involved befol'"e allowing them to l'"etul'"n to theil'" testing.

4KV McGuire 1 11/29/88 zel'"o power (from LER Seal'"ch): On 11/29/88, operations was l'"estoring the 1A busline to service and noticed that standby b!"eakel'" 1TD-6, which supplies switchgeal'" gl'"oup 1TD of the 6900V bus, l'"equired excessive pl'"essul'"e to !"ack in the connect position. To ensul'"e thel'"e wel'"e no problems with the breakel'", OPS decided to test the bl'"eakel'" by cycling it. An OPS supel'"visol'" instructed an operator to l'"ack the bl'"eakel'" to the test position, cycle it, and then l'"estol'"e it to the connect position. With the bl'"eakel'"

in test and the contl'"ol boal'"d switch in manual, the opel'"ator closed the standby breaker at 2112 fl'"om

'the control l'"oom. The nonnal breakel'" opened as designed and power was lost to switchgeal'" gl'"oup 1TD resulting in a train B blackout. Residual heat l'"emoval (ND) pulp 1B auto tl'"ipped because it is not a blackout load. The diesel generatol'" auto started and loaded as l'"equired. Nonnal power was restol'"ed and ND~ 1B was 1"esta1"ted to restore core cooling. The l'"eactol'" coolant temp increased by 4F dul'"ing A-47

p. 3 LER DATA BASE - 4KV 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME the time that ND pump 1B was sh~t down *. Thi~ event is assigned a cau~e of management .. deficiency ..

because the OPS supervisor did not provide adequate written and/or verbal instructions to the operator for correctly testing standby breaker 1TD-6, and a contributory cause of defective procedure because procedure OP/1/A/6350/08, operation of station breakers, did not contain precautions prior to testing breakers.

4KV Millstone 2 12/09/81 Mode 5 30-60 min (from NSAC52, p. A-22): With the RCS depressurized and drained to the hot leg midpoint, the running RHRS pump tripped due to 345 kV switchyard breaker testing. Core heatup from 90 F to over 208 F occurred over a period of about 30-60 minutes. When the RHRS pump was restarted, previously colder, stagnant RHRS t~ratures increased from 90 F to 208 Fin about 2 minutes. The second RHRS pump was started, and the hot coolant in the core area and the colder coolant in the RCS and RHRS continued to equalize, resulting in an RHRS t~rature drop to 130 Fin about 7 minutes.

4KV North Anna 03/23/89 Mode 5 10 sec (from LER Search): At 1053 hrs on 3/23/89, with Unit 1 in Mode 5 (cold shutdown), the 11 1H" emergency bus was inadvertently de-energized for approx. 10 seconds during the performance of 1-PT-82.3A, 1H diesel generator test (simulated loss of offsite power in conjunction with an ESF actuation signal).

This is considered an inadvertent engineered safeguards feature CESF) actuation and is reportable pursuant to 10 CFR 50.73CA)C2)CIV). A four hour report was made in accordance with 10 CFR 50.72(A)(2)(I1). Immediate corrective actions included automatic start of the 11 19 11 component cooling water pump, the manual start of the 11 19 11 residual heat removal pump, and verification that de-energized equipment was either returned to service or was reset. Further corrective actions include investigating and correcting the circuit design of the trip block relay. In addition, appropriate emergency di~el generator periodic tests will be revised to prevent testing when in an abnormal electrical configuration. This event posed no significant safety iq,lications because the 111H" emergency diesel generator CEDG) started as designed and reloaded the 0 1H11 emergency* bus in less than 10 seconds. In addition, the 11 1J" EOG was operable and was capable of providing power to required .

systems when the 0 1H 11 emergency bus was inadvertently de-energized.

4KV North Anna 1 04/16/89 Mode 5 (from LER Search): On April 16, 1989 at 1115 hrs, with both units in Mode 5 (cold shutdown) the normal power supply to 1H and 2J 4160V emergency bus was lost when a lifted wire was inadvertently grounded during removal for switchyard modifications required for design change package CDCP) 88-05. The 1H and 2J emergency diesel generators automatically started on the loss of power and re-energized their associated emergency bus. This event is an engineered safety feature CESF) actuation and reportable pursuant to 10 CFR 50.73(A)(2)(IV). A four hour report was made pursuant to 10 CFR 50.72(B)C2)(II).

In conjunction with the loss of power the Unit 1 residual heat removal CRHR) pump, 1-RH-P-1A, tripped on undervoltage and is reportable pursuant to 10 CFR 50.73(A)C2)(V)(B). Abnormal procedure 10 was initiated and 1H and 2J emergency diesel generators (EOG) were verified in operation and supplying their respective bus. Abnormal procedure CAP) 11.2 was also initiated and residual heat removal capability subsequently restored on Unit 1 by starting "8 11 RHR pump. No significant safety consequences occurred due to this event, since the redundant emergency bus remained available to supply power to required plant equipment. Also, the 1H and 2J *EDGs auto started and re-energized the emergency busses as designed.

4KV North Anna 2 04/16/89 Mode 5 See description of North Anna 1, 04/16/89 event.

A-48

ll.* 4 LER DATA BASE* 4KV 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME 4KV Rancho Seco 12/08/86 Mode 5 (from Seabrook Sheet 20 of 20) The plant was in cold shutdown removing decay heat via the Decay Heat Removal System (DHS) Train Bon Dec. 8, 1986. Startup transformer #1 was scheduled for routine preventive maintenance. A loss of the 4A bus power attendant diesel generator start and decay heat system (DHS) isolation occurred during the transfer of the source transformer at 2:18 PM on Dec. 8, 1986.

(from CR5015): (Make E.10 Table A.4) Power level - OX. The plant was in cold shutdown, removing decay heat via the decay heat removal system CDHS) train as 11 on Dec. 8, 1986. Startup transformer No.

1 was scheduled for routine preventive maintenance. A loss of the 4A bus power, attendant diesel generator start, and decay heat system (DHS) isolation occurred during the transfer of the source transformer at 2:18 PM on Dec. 8, 1986. An automatic feature of the nuclear service bus is a five-second limit on having two sources feeding the bus. The control roan operator closed startup transformer No. 2 supply breaker 4A10 onto the 4A bus. When the operator opened the supply breaker (4A01) from startup transformer No. 1, breaker 4A10 from startup transformer No. 2 had just coq>leted_

the automatic five-second run-out and had tripped open. These events left the 4A bus without either the normal or alternate supply. An attendant result was that when power was restored, DHS suction valve HV-20001 closed as would be expected in this situation causing the DHS isolation. The power supplies to both HV-20001 and HV-20002 are currently racked out. The purpose for the DHS system valve interlocks is to prevent over-pressuring the DHS piping with RCS pressure. Since the RCS is "open to atmosphere" there is no need for the interlocks to protect the DHS piping from over-pressure.

41CV Salem 1 04/24/79 Mode 6 2 min (second event on 05/08/79)

.(fr(!III N!!AC52, p._A-20): Twice during performance of tests on vital bus breakers, the vital bus, supplying the operating RHRS JlU1'> was inadvertently de.;energized causing a loss of RHRS flow. Fl-ow was restored in 2 minutes and 4 minutes respectively.

41CV Salem 1 05/08/79 Mode 6 4 min (1st event on 04/24/79)

(from NSAC52. p. A-20): Twice during performance of tests on vital bus breakers, the vital bus supplying the operating RHRS puip was inadvertently de-energized causing a loss of RHRS flow. Flow was restored in 2 minutes and 4 minutes respectively.

41CV Salem 1 03/16/82 45 min (from AEOD): Vital bus tripped. Component cooling water and service water were lost. Redundant trains were out for maintenance (45 min. loss).

41CV Salem 2 12/20/83 Mode 5 22 min

<from Seabrook Sheet 8 of 20): During a maintenance shutdown, 2RH1 closed, resulting in a loss of RHR flow. The event took place during the transfer of 2B4KV vital bus from one station power transformer to the other. The backup power supply for 2B instrunent inverter was deenergized for maintenance. The transfer resulted in a momentary loss of the instrunent bus; 2RH1 closed in interlock.

(from AEOD): Loss of vital bus - clue to personnel error resulted in closure of suction/isolation valve (22 min. loss)

• 4KV Surry 1 05/24/86 Mode 6 (from Seabrook Sheet 10 of 11) On 5/24/86, Unit 1 was at refueling shutdown with Reactor cavity flooded and forced circulation in service; Unit 2 was at 100% power. Due to maintenance and design A-49

p. 5 PHASE 2 CATEGORY.

PLANT NAME LER DATA BASE - 4KV EVENT DATE INITIAL PLANT CONDITION 08/27/93 RECOVERY TIME change work in progress on Unit 1, nunerous electrical busses were cross .. tied. Among th~se were 1h'and 1J4160V emergency busses and vital busses 1-II and 1-IV. #1 emergency diese~ generator was out of service. At approximately 1520 hrs, reserve station service feeder breaker 15Da opened. This resulted in an undervoltage transient sensed at 1J emergency bus. #3 emergency diesel generator autostarted and assuned load. By design, the 1J stub bus breaker opened during the transient which resulted in the loss of the operating 1B residual heat removal and 1B c ~ n t cooling puips. The stub bus breaker was reset and the coqionents were returned to service. Nunerous spurious trip signals, alarms and A Hi Consequence Limiting Safeguards signal were generated during the transient.

(from CR5015): Power level - Ol. On May ~4, 1986 Unit 1 was at refueling shutdown with reactor cavity flooded and forced circulation in service; Unit 2 was at 100% power. Due to maintenance and design change work in progress on Unit 1, nunerous electrical buses were cross tied. Among these were 1H and 1J 4160V emergency buses and vital buses 1-II and 1-IV. #1 emergency diesel generator was out of service. At approx. 1520 hrs, reserve station service feeder breaker 1501 opened. This reuslted in an undervoltage transient sensed at 1J emergency bus. #3 emergency diesel generator auto started and assuned load. By design, the 1J stub bus breaker opened during the transient which resulted in the loss of the operating 1B residual heat removal and 1B component cooling puli)S. The stub bus breaker was reset and the coqionents were returned to service. Nunerous spurious trip signals, alarms and hi consequence limiting safeguards signal were generated during the transient.

4KV Three Mile Island 1 01/09/87 Refueling shutdown (from LER Search): TMI-1 was in refueling shutdown mode wHh 11B" decay heat removal system in operation. Appendix R modification work required that a wire be lifted in the circuit for the 1E 4160V current transformer. Unbeknownst to the electrician, he lifted and opened one phase on the 1E bus current transformer. With this phase open, the imbalance caused an apparent neutral current and operation of the neutral overcurrent relay. This protective feature tripped and locked out the feeder breakers to the 1E bus. The resulting undervoltage condition on the 1E bus caused the auto start of .

the B emergency diesel generator. The root cause of the event was inadequate instruction to the electrician perfQrming the work at an energized bus. The automatic start of the emergency diesel generator is reportable under 10 CFR 50.73CA)(2)CIV). There was no safety significance to the auto start of the emergency diesel generator.* Although the operating decay heat removal system was momentarily shutdown due to the de-energized 1E 4160V bus, there was no safety significance since the backup system was available. Corrective action taken was to reconnect the wire, reset the lockout, and re-energize the bus. Work was stopped and not restarted until the work instructions were assessed and an appropriate sequence developed.

4KV Wolf Creek 10/16/87 17 min (from NUREG*1410): The unit was in a refueling outage and the refueling cavity was flooded with 60 fuel assent>lies in the reactor. One emergency diesel generator had been removed from service and one safety bus had been removed from service for cleaning. An electrician came in contact with a lead energized from the other safety bus. The energized bus deenergized. The emergency diesel generator started and loaded. The emergency diesel generator output breaker was tripped to remove the electrician who came in contact with the energized lead. After the electrician was removed, the emergency diesel generator output breaker would not close. The anti-pll11) circuit of the output breaker prevented reclosure of the breaker once it had been opened after the diesel generator started on unclervoltage. Decay heat removal capability was lost for 17 minutes. The industry was informed of this event in INPO Significant Event Notification (SEN) 22.

A-50

p. LER DATA BASE - 4KV/P6 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY-CATEGORY DATE CONDITION TIME 4KV/P6 Calvert Cliffs 1 11/12/80 Mode 5 or 6 1(1 *min (from NSAC52, p. A-17): A 4 kV bus nonnal feed breaker spuriously opened. The diesel generator started automatically, re-energizing the bus. During the voltage transient, a vital bus voltage went low, and ESFAS A logic actuated, which caused a loss of shutdown cooling flow.

4KV/P6 Diablo Canyon 1 01/25/85 Mode 5 2 min (from Seabrook): A loss of vital 4KV bus voltage resulted in the autostarts of diesel generator (DG) 1-2, Contairrnent Fan Cooler System 1-5, and Auxiliary Saltwater purp 1-2. In addition, for approximately 2 minutes, the Decay Heat Removal Capability was lost when the closure of the loop 4 RHR suction valve (MOV-8702) resulted in both Residual Heat Removal (RHR) trains being isolated from the Reactor Coolant system. The RHR suction valve was subsequently opened and RHR flow established.

Within two minutes all other affected equipment and systems were returned to their normal standby conditions.

(from CR5015): Power level - OX. At 1750 PST, 1-25-85, with Unit 1 in Mode 5 (cold shutdown), a loss of vital 4KV bus voltage resulted in the autostarts of DG 1-2, containnent fan cooler system 1-5, and_

aux saltwater purp 1-2, and the transfer of the control room ventilation system to mode 4. In addition, for approx. 2 minutes, the decay heat removal capability was lost when the closure of the loop 4 RHR suction valve (MOV-8702) resulted in both RHR trains being isolated from the RCS. The RHR suction valve was subsequently opened and RHR flow established within 2 minutes. All other affected equipment and systems were returned to their normal standby conditions. Investigation has shown that the cause of this event was misadjustment of the aux switches on the bus G feeder breakers (HG 13 and 14). The aux switches were adjusted to a new tolerance and the breakers were tested with satisfactory results. To prevent recurrence, procedure E-51.2, u4.16KV circuit breaker PM (preventative maintenance)," is being revised to identify the specific aux switch adjustment required for the bus f~er ~reakers. Similar events 275/85-004 and 85-005.

4KV/P6 Farley 1 01/16/81 Shutdown 1 min (from NSAC52, p. A-21): A loss *of power to a startup transformer de-energized 4160 V power to the running RHRS purp. The emergency di~sel generator auto started and re-energized the bus, and the RHRS purp was restarted. Flow was lost for 1 minute.

4KV/P6 North Anna 2 04/08/83 Mode 5 (Sheet 4 of 11) On 4/8/83 power was lost to the A Residual Heat Removal (RHR) subsystem when the 2H 4160 volt emergency bus was de-energized. This action resulted in leaving only one coolant loop CB RHR subsystem) operable. A single RHR loop provides sufficient heat removal capability in Modes 4 or 5.

4KV/P6 Salem 1 01/04/83 Modes 4 and 5 (from Seabrook Sheet 3 of 11) The Control Room operator observed that No. 1B vital bus had tripped.

Since it is supplied from the bus, No. 12 residual heat removal (RHR) purp was deenergized; loss of the purp rendered the associated RHR loop inoperable and Action Statement 3.4.1.4A was entered. The operator inmediately started No. 11 RHR pu1p to restore core cooling flow. The second purp remained operable.

4KV/P6 Salem 2 04/13/83 Mode 5 < 1 min See description of Salem 2, 04/18/83 event.

4KV/P6 Salem 2 04/18/83 Mode 5 < 1 min (Sheet 4 of 11) On two separate occasions, on 4/13 and 4/18, operating loads on the No. 2A 4KV and 460V vital buses were observed to trip. In both cases, due to the de-energization of No. 21 Residual Heat Removal (RHR) purp No. 21 RHR loop was no longer in operation. In each instance, the RHR loop was A-51

p. 2 LER DATA BASE - 4KV/P6 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME inmediately returned to operation.

4KV/P6 Surry 1 02/04/89 Mode 5 3 min (from LER Search): On Feb. 4, 1989, at 2345 hrs, with Units 1 and 2 in cold shutdown, the #1 and #3 emergency diesel generators auto-started and loaded onto the 1H and 2J emergency busses respectively.

This event is reported pursuant to 10 CFR 50.73Ca)C2)CIV). The diesels started due to the de-energization of the 1H and_2J emergency busses due to the failure of a 4160 volt supply_ circuit breaker. The running residual heat removal CRHR) puip de-energized during the event. The redundant RHR puip was started approx. 3 minutes later to supply RHR flow. The failed circuit breaker was cleaned and tested satisfactory. Safety-related 4160 volt supply circuit breaker operator mechanisms will be refurbished. The preventive maintenance program for 4160 volt circuit breakers is being evaluated.

4KV/P6 Surry 1 04/06/89 Mode 5 1 min (from LER Search): On April 6, 1989 at 0431 hrs, with Units 1 and 2 in cold shutdown, an electrical fault in the plant switchyard resulted in the failure of a lightning arrestor on the 500 kv side of the

1. 2 auto-tie transformer. This reuslted in a differential lockout of the transformer which created under voltage conditions on the electrical buses, including the 1H and 2J 4160v emergency buses, that were being supplied by the transformer. A rnm>er of components were de-energized, including the operating "A'i residual heat removal (RHR) punp for Unit 1 and certain Unit 1 radiation monitors. The redundant "B11 RHR pull) was started within one minute. The #3 emergency diesel generator auto started and loaded on to the de-energized 2j emergency bus. Operators perfonnecl the appropriate procedures to restore power to the affected electrical buses and c ~ t s . This event is being reported due to violations of technical specifications and an unplanned engineered safety features actuation. The cause of the lightning arrestor failure camot be determined. Some minor coq:,onent failures were noted during the event *. _The cause.of these failures are being investigated and corrective actions will be taken as appropriate.

4KV/P6 Surry 2 02/04/89 Mode 5 See description of Surry 1, 02/04/89 event.

4KV/P6 Surry 2 04/06/89 Mode 5 1 min See description of Surry 1, 04/06/89 event.

A-52

• Appendix A.2.3 Loss of Vital Bus (VITAL)

A-53

p. LER DATA BASE - VITAL 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVE~Y CATEGORY DATE CONDITION TIME

. *~ . . . .. *. .. . . ---------------. ------------- -------------- - -----------------------

VITAL Calvert Cliffs 2 02/04/81 Mode 6 17 min*

(from NSAC52, p. A-5): RHRS flow was lost due to inadvertent de-energization of one 120 V ac vital bus. De-energizing the vital bus caused a high pressure input to an RHRS suction valve control circuit, causing the valve to shut. The~ was stopped, vital bus re-energized, *and flow restored in 17 minutes.

VITAL Calvert Cliffs 2 11/22/82 Mode 6 4 min (from Seabrook): While deenergizing instrunent power supply panel 2V02, shutdown cooling flow was lost. A shutdown cooling return valve, 2-SI-652, shut when this panel was deenergized due to an incorrectly installed terrporary j ~ r meant to prevent 2*SI-652 closure. Shutdown cooling flow was restored four minutes later.

(from AEOO): Technician incorrectly de-energized a power supply panel; caused closure of a DHR return valve (4 min. loss).

VITAL Calvert Cliffs 2 11/24/82 (from AEOO): OHR lost due to a failed power supply. (Duration of event unknown>-

VITAL Calvert Cliffs 2 12/28/82 Vital inverter failed, caused an isolation of the OHR return line_ (Duration of event unknown_)

VITAL Calvert Cliffs 2 D1/04/83 15 min Inverter tripped during surveillance testing - caused isolation of the DHR return line. (15 min loss)

VITAL Catawba 1 11/26/88 Mode 5. 2 sec Cfrom_LER Search): On 11/26/88, at 1805:07 hrs, static inverter 1EID and 120 VAC power panelboard 1ERPD experienced an undervoltage condition for approx- 2* seconds. As a result, nultiple alarms associated with engineered safeguards features were displayed in the control room. *The nuclear service water (RN) pit B emergency lo level alarm occurred and cleared when it was acknowledged. All idle RN

~ started as expected and the suction valves and discharge valves for the system automatically swapped to the standby nuclear service water pond. There was a false reactor coolant (NC) system wide range pressure signal which caused residual heat removal (ND) system suction isolation valves 1ND1B and 1ND36B to close as expected. In addition, contairmient purge (VP) system train B, which was in service, automatically shutdown. The Unit 1 control room area ventilation system train B filter inlet valve closed due to a false chlorine detection alarm. Unit 1 was in Mode 5, cold shutdown, at the time of this incident. Unit 2 was in Mode 1, power operation, at 48% reactor power at the time of this incident. A work request was closed out.- Following the undervoltage condition, operations personnel noted a ground on 125 voe distribution center 1EDD. This condition is being investigated. The root cause for this incident could not be determined.

VITAL Davis Besse 1 06/28/79 Mode 5 18 min (from NSAC52, p. A-2): An accidental short circuit in one channel of reactor protection was caused by a slipped alligator clip during surveillance testing. This blew an inverter fuse, causing the loss of an essential bus. Loss of power to the SFAS channel on that bus actuated the pressure bistable trip input on one RHRS suction valve, causing a loss of RHRS flow. The RHRS puup was secured to protect the puip. The bus-was reenergized from an alternate source, the suction valve reopened, and flow restored.

(from AEOO): 18-minute loss of OHR. During surveillance testing, a slipped alligato~ clip caused a short circuit and failure of power supply to an SFAS channel. As a result; OHR.suction valve closed.

A-54

p. 2 LER DATA BASE - VITAL 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

. *--..- . ----- .----* .. 4-- *. ---. ------------. ----- .-- ----. -*-------.----- .- . ------------ -- ------

VITAL Diablo Canyon 2 01/17/S6 Mode 5

• 13 in,n (from Seabrook): At 0455 PST on 1/17/S6, while attenpting to transfer instr',lllE!nt AC Panel PY 2-1A from normal to backup power supply, an unlicensed operator went to the wrong panel and inadvertently transferred instrunent AC Panel PY 2-1 to its backup power source. This momentary Loss of power caused relay actuation which resulted in the closure of Residual Heat Removal CRHR) valve 8702.

(from CR5015): Power level - 0%. At 0455 PST on 1-17-86, while attenpting to transfer il'l$trunent AC panel by 2-1A from normal to backup power supply, an unlicensed operator went to the wrong panel and inadvertently transferred instrunent AC panel PY 2-1 to its backup power source. This momentary loss of power caused relay actuation which resulted in the closure of residual heat removal (RHR) valve 8702. In response to the ensuing loss of flow alarm, RHR pulp 2-1 was secured by a licensed operator.

RHR valve 8702 was reopened from the control room. RHR puip 2-1 was restarted, observed for seal damage, and declared operable at 0508 PST, 1-17-S6. No operations were in progress that involved a reduction in reactor coolant system boron concentration. Thus, the requirements of Tech Spec 3.4.1.4.1 action B were met. To prevent recurrence, the operator involved has been counseled, operating procedures on transferring instrunent AC panel power supplies will be revised, and panel identification labels in the instrument AC panels will be upgraded.

VITAL Diablo Canyon 2 06/29/87 Mode 4 5 min (from LER Search): At 1829 PDT on ~une 29, 1987, with the Unit in Mode 4 (hot shutdown), a faulted coil on relay 2TC441HX initiated a voltage transient on instruuent power panel PY-24, which resulted in closure of residual heat removal (R~R) valve B701. The momentary voltage transient resulted in an actuation of the RHR autoclosure inter.lock CACI) function since the ACI and the faulted relay share a conman instrument power supply. The ACI activation caused RHR valve 8701 to close. The licensed operators no~ed.that RHR ~ 2-1 discharge terperature was decreasing rapidly and then observed RHR valve 8701 was shut. In response *to the valve closure, RHR ~ 2-1 was secured*and valve 8701 was reopened. RHR ~ 2-1 was restarted at 1834 PDT, and no abnormal pulp seal leakage*was observed. The four hour non-emergency report required by 10 CFR 50.72CB)C2)CIII)CB) was made at 1945 PDT. The failure of the relay was a result of the coil shorting. Melted nylon around the iron core interface *,

surfaces and some slight corrosion of the surfaces was noted. Pgande is preparing a letter for submittal to the NRC requesting and justifying removal of the RHR ACI function. The RHR ACI function will be removed after NRC staff review and approval of the proposed change.

VITAL McGuire 1 06/24/82 6 min (from AEOD): Inverter failure caused closure of suction/isolation valve (6 min. loss).

VITAL McGuire 1 07/13/82 Static inverter EVIA malfunctioned causing a residual heat removal system (ND) isolation valve to close. Operators restored.ND flow, but not before loss of flow effected a transition from Mode 5 to.

Mode 4.

VITAL Millstone 2 01/06/82 7 min (from AEOD): Technician error during a preventive maintenance test resulted in loss of a vital instrunent panel, and autoclosure of the suction/isolation valves (7 min. loss).

VITAL North AMS 1 01/22/83 Mode 6 4 min (from Seabrook): RHR flow was lost for approximately 4 minutes.

(from AEOD): Failed inverter, caused RHR suction/isolation valve to close. (4 min loss)

A-55

p. 3 LER DATA BASE - VITAL 08/27/93 PHASE 2 EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME VITAL North Ama 1 04/22/87 Mode 5 Cfran LER Search): At 1530 hrs on April 22, 1987, with Unit 1 in Mode 5, the residual heat removal (RHR) suction line was isolated when MOV-1701 closed due to a loss of power to the 120 VAC vital bus (VB) 1-III. MOV-1701 being closed resulted in a t~rary loss of the RHR system. Therefore, this event is reportable pursuant to 10 CFR 50.73CA)C2)CVII)CB). At 1515 hrs on April 22, 1987, during the performance of a periodic test, the 1-III inverter failed, resulting in a loss of power to VG 1-III.

Vital bus 1-III supplies power to an auxiliary relay for pressure channel P-1403 which provides the logic to close MOV-1701 on high RCS pressure. IJhen this auxiliary relay was de-energized an auto closure signal was sent to MOV-1701, thereby closing MOV-1701. Power was quickly restored to VB 1-III, MOV-1701 was reopened and RHR flow was restored. The cause of the inverter failure was determined to be a blown fuse. To prevent recurrence of this type of event, North Anna is actively pursuing a technical specification change to eliminate this RHR interlock.

VITAL North Anna 2 04/29/83 Mode 6 < 1 min (fran Seabrook Sheet 5 of 20): One of two source range channels (N-31) and the Contairment Particulate and Gaseous Radiation monitors (MR-259 & 26) were deenergized. The vital bus was pranptly reenergized and the cleenergized equipment pranptly restored.

(fran AEOO): Loss of vital bus. RHR suction/isolation valve closed. Caused by maintenance personnel conducting a test as loads were being transferred (<1 min. loss).

VITAL Palo Verde 2 01/30/86 Mode 5 Cfran CR5015): Power level - OX. At 1924 MST on 1-30-86, Palo Verde 2 was in Mode 5 when an unauthorized modification on a vital power inverter* caused*a failur~ of the train 'A', class 1E, I&c power system, which resulted in a control room essential filtration actuation signal *and a t~rary loss of train 'A' shutdown cooling. The cause of the failure was attributed to inadequate control of a modification consisting of a resistor jU!pered around a capacitor in the circuit. The modification caused an excessively high current on an inverter circuit board, and resulted in 3 blown inverter fuses. The inverter loss caused a loss of power to a radiation monitoring unit, which in turn caused the CREFAS and the t~rary termination of train 'A' soc. As corrective action, all inverters were inspected for additional unauthorized modifications, the blown fuses were replaced, and inverter specs were checked. Additionally, work control procedures will be revised to esq:ihasize the i~rtance of removing all t~rary modifications prior to putting an electrical system back in service.

VITAL Rancho Seco 06/24/82 Modes 4 and 5 (from Seabrook Sheet 1 of 11): During a preventive maintenance procedure on the B inverter, there was a momentary loss of power to the B bus. This in turn caused a short duration loss of DHRS. The core t~rature remained unaffected by this loss of flow and the A system was available on standby.

(from AEOO): Sillllltaneous test and maintenance caused failure of bus, closure of the suction/isolation valve, and loss of DHR flow. (Duration of event unknown)

VITAL Rancho Seco 11/15/86 Mode 5 (from Seabrook Sheet 19 of 20) The plant was in cold shutdown, removing decay heat via the Decay Heat Removal System (OHS); Train A, on Nov. 15, 1986. At 1:00 PM, in preparation for a fuse replacement activity in the S1A Bus inverter, S1A bus power was momentarily interrupted, DHS overpressure distables tripped, HV-20001 closed which tripped DHS AP~ as designed. Steps were taken inmediately to restore a DHS train to service in accordance with T.S. 3.1.1.5.

A-56

p. 4 LER DATA BASE - VITAL 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME (from CR5015): Power level - 0%. The plant was in cold shutdown, removing decay heat via the decay heat removal system (OHS) train "A" on 11*15-86. At 1:00 PM, in preparation for a fuse replacement activity in the S1A bus inverter, S1A bus power was momentarily interrupted, DHS over-pressure bistables tripped, HV-20001 closed which tripped OHS "A"~ as designed. Steps were taken inmediately to restore a OHS train to service in accordance with Tech Spec 3.1.1.5. The basic cause of the inverter failure is that the original design did not allow for testability of the device through the use of a substitute power source. That design deficiency, identified as early as 1979 CNCR's-1258, Revision 2), was recognized by the current action plan for performance illl)rovement. There is a preventive maintenance procedure, EM 171A, "station inverter routine - static products inverters," that is scheduled to be performed once per year on the inverters, a 120VAC vital bus system illl)rovement was approved, but has not been illl)lemented yet.

VITAL Salem 2 05/14/83 Modes 4 and 5 inmediately (from Seabrook Sheet 5 of 20): On two separate occasions on May 14 and 15, 1983, a Residual Heat Removal system suction valve was observed to have closed, thus eliminating flow in the operating RHR loop. In each instance, the operating putp was stopped and Action Statement 3.4.1.48 was entered. No reduction in reactor coolant system boron concentration occurred with an RHR loop out of service. A loop was inmediately restored to service.

Cfr0111 AEOD): RHR suction valve closed during operation. (Duration of events unknown) The 05/14/83 event was triggered by a vital instrunent bus which was de-energized for maintenance *

• VITAL Salem 2 11/28/83 Mode 5 (from Seabrook Sheet 8 of 20): During a maintenance shutdown, 2A vital instrunent bus was transferred to its alternate power supply to perform routine meter calibrations on 2A inverter. A voltage transient caused 2RH2 to shut resulting in a loss of RHR flow. The valve was inmediately reopened and RHR flow was re-established.

(from AEOD): Vital bus transfer caused voltage spike which resulted in closure of suction/isolation valve. (Duration of event unknown)

VITAL South Texas 1 02/12/89 Mode 5 (from LER Search): On 2/12/89, Unit 1 was in mode 5. At 0529 hrs a plant operator noticed evidence that inverter IV-1203, which supplies uninterruptable power to distribution panel DP-1203, was overheating. The operator inmediately transferred the distribution panel to its al terna.te source and secured the inverter. Since this was a dead bus transfer, it resulted in a momentary loss of power and subsequent actuation of the control room and fuel handling bldg HVAC systems to the emergency mode, tripping of residual.heat removal plJ1'l 18, and shifting of centrifugal charging putp 18 suction to the refueling water storage tank from the volune control tank. These systems were restored to normal operation after power was restored. The cause of this event was a short to ground on the secondary side of the inverter ferroresonant transformer. Corrective actions include replacement and failure analysis of the failed transformer.

VITAL Sllllller 11/12/83 Mode 5 5 min (from Seabrook Sheet 7 of 20) An Engineered Safety Feature (ESF) 120 VAC vital instrunentation panel, APN-5901, was transferred to alternate power to accarmodate modifications to its normal power source.

~ith Train 8 Residual Heat Removal System in service, its suction valve, XVG-8701A closed. The valve was reopened within approximately 5 minutes. No adverse consequences resulted due to plant conditions and the short duration of the event.

A-57

p. 5 LER DATA BASE* VITAL 08/27/93 PHASE 2 CATEGORY PLANT NAME EVENT DATE INITIAL PLANT CONDITION RECOVERY TIME

--.----. -----------. ----------------------- ~---.-----------.-----------------------------------------

(from AEOD): (Date is 11/12/84) Bus transfer during plant modification caused an interruption of power to an ESF instrunentation bus. An erroneous overpressurization signal resulted causing suction/isolation valve closure, and interruption of DHR flow (5 min. loss).

VITAL S1.11111er 10/18/84 Mode 5 25 min (from Seabrook Sheet 11 of 20): On Oct. 18, 1984, outage with Train A of the Residual Heat Removal CRHR) System in service, RHR Train Bout of service for routine maintenance, and the reactor coolant system (RCS) vented at a temperature of approximately 110 deg Fahrenheit. At 1605 hrs, a power loss to 120 VAC distribution panel APN-5901 deenergized Solid State Protection System (SSPS) Channel I and caused the instrunent panel for RCS wide range pressure (PT-403) to initiate valve XVG-8701A.

(from AEOD): 1 OHR loop was out for surveillance testing. An inverter failure caused closure of the operating loop's suction isolation valve (25 min. loss).

(from CR5015): Power level - a,:. On 10-18*84, the plant was in Mode 5 for the first refueling outage with train 1 A1 of the RHR system in service, RHR train 1 B1 out-of-service for routine maintenance, and the RCS vented at a temperature of approx. 110 F. At 1604 hrs a power loss to 120V AC distribution panel APN-5901 de-energized solid state protection system (SSPS) chamel I and caused the instrument channel for RCS wide range pressure (PT-403) to initiate an auto-closure of the operable RHR train*s suction isolation valve XVG*8701A. Following determination that the power loss had been caused by personnel error during the performance of a plant modification, operations personnel restored power to APN-5901. XVG*8701A was opened and train 1 A1 of the RHR system returned to operable status at 1630 hrs (total time of RHR isolation was approx. 25 minutes). RCS temperature increased from 110 F to 130 F during the event. The loss of RHR met the conditions of an alert, and the proper notifications were made in accor:dance with the emergency plan.

VITAL Turkey Point 4 03/15/86 Mode 6 5 min (from Seabrook Sheet 18 of 20) Work was progressing to deenergize and replace a vital bus feeder breaker, 4P08. When breaker 4P08-3 was opened, the RHR ~ suction valve went closed. Upon receipt of the letdown, isolation alarm, the RHR ~ was stopped,the breaker re-energized, the valve re-opened, the ~ restarted, and flow restored in approximate.Ly 5 minutes.

(from CR5015): Power level - 0,:. On 3*15-86, while Unit 4 was in a scheduled refueling outage Mode 6, work was progressing to de-energize and replace a vital bus feeder breaker 4P08. When breaker 4P08-3 was opened, the RHR ~ suction valve went closed. Upon receipt of the letdown isolation alarm, the RHR ~ was stopped, the breaker re-energized, the valve reopened, the~ restarted and flow restored in approx. 5 minutes. Tech Spec action statement 3.10.7.2 was entered during the approx. 5 minutes of flow loss. There was no noticeable increase in the 93 F system temperature. When breaker 4P08*20 was opened, a process radiation monitor rack was lost, causing the containment ventilation system to isolate and the control room ventilation system to isolate and switch over to the recirculation mode, as designed. The purge valves were secured per Tech Spec action statement 3.10.2.A, by removing power fuses. No significant increase in activity was recorded on the plant vent effluent monitoring system during this event; other means of monitoring containment activity were available. No release path to outside containment was available. When de-energized, feeder breaker FP08 replacement was c~leted, power was restored and the systems were then returned to their normal l ine*up.

VITAL Zion 1 03/17/82 Mode 6 3 min (from Seabrook Sheet 1 of 20): RHR suction valve 1MOV*RH8702 started to close due to an inadvertent opening of inverter 111 output breaker. The running~ was tripped. The inverter output breaker was A-58

• • • p. 6 PHASE 2 CATEGORY PLANT NAME LER DATA BASE - VITAL EVENT DATE INITIAL PLANT CONDITION 08/27/93 RECOVERY TIME reclosed, RHR suction valve 1MOV-RH8702 was reopened, and the RHR system was restored to operation within 3 minutes.

(from AEOO): Inadvertent (contractor personnel) opening of inverter output breaker caused closure of the RHR puf1) suction valve (3 min. loss).

VITAL Zion 2 01/03/86 Mode 5 (from Seabrook Sheet 17 of 20) A momentary fluctuation of output of inverter power supply Bus 213 (cause unknown) caused the charging flow control valve, 2VC-FCV121, to fail to the 20% demand position and also caused 2MOV-RH8701, the RHR puf1) suction isolation valve to fail closed- This increased charging flow from 39 to 190 gpm and isolated letdown flow resulting in lifting of the pressurizer power operated relief valves (PORVs). \lhile investigating the cause, Bus 213 was again deenergized and the PORVs again lifted-(frcm CR5015): Power level - 0%. At 1547 on 1-3-86 Unit 2 was shut down for a refueling outage and the RCS was filled solid with no bubble in the pressurizer. A momentary fluctuation of output of inverter power supply bus 213 (cause unknown) caused the charging flow control valve, 2VC-FCV121, to fail to the 20% demand position, and also caused 2MOV-RH8701 the RHR p!.111) suction isolation valve to fail closed. This increased charging flow from 39 to 190 gpm, and isolated letdown flow resulting in lifting of the pressurizer power operated relief valves (PORV 1 s). \lhile investigating the cause, Bus 213 was again deenergized and the PORV's again lifted. The cause of the bus output fluctuation is currently unknown. This event is reportable since Tech Spec 6.6.3.H requires a 30 day written report on actuation of the overpressure protection system

• A-59

Appendix A.2.4 Loss of Component Cooling Water (CCW)

A-60

p. 1 LER DATA BASE* CC\.I 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME CC\.I Braidwood 1 01/21/87 zero power 14 min (from LER Search): The 1B residual heat removal (RHR) heat exchanger (HX) -was out of service with the tube side drained. Preparat1ons were made for draining the component cooling water CCC) shellside of the HX to allow replacement of a flange gasket. AT 1745 draining of the shell side of the HX was started. At 1802 the 1A CC puip tripped due to low level in the CC surge tank. The low level alarm on the main control board did not amunciate although the sequence of events recorder did indicate a low level. The draining was stopped, the surge tank refilled, and the isolation valves were *checked. At 1816 the 1A CC puip was restarted and the system was restored to normal. The cause was the CC inlet isolation valve leaking and contributing was the failure of the cc surge tank high/low level alarm to amunciate on the main control board. Additionally, the CC motor operated outlet valve on the 1B RHR HX was found 6 turns off its seat. The leaking valve has been repaired, the limits for a motor operated valve were adjusted, the main control board alarm was troubleshot and the synptoms could not be duplicated. Work is in progress to check the calibration and scaling on the CC surge tank instrunent loop.

CCW Byron 1 04/08/87 zero power 17 min (from LER Search): On 4/8/87, at approx. 1725, a contracted maintenance crew began work on the limitorque motor operator of the 11 1A11 residual heat removal (RH) heat exchanger conponent cooling water outlet isolation valve, 1CC9412A. This valve was a point of isolation for work on the RH heat exchanger, which required it to be drained of coqx,nent cooling water CCC). Shift operating personnel granted permission, with the understanding that if it became necessary for the crew to stroke the valve, they would obtain authorization. Maintenance crew stroked the valve in order to release torque on the motor gear set. It is unclear whether they actually received authorization or not. This allowed CC to back flow through 1CC9412A to the heat exchanger and out the drain. This caused the (CC) surge tank to reach the low level CC puip trip. The 11 1A" cc put;> tripped at 1726 on 4/8/87. The surge tank is conmon to both trains, consequently, both trains of c~ent cooling were inoperable. Leak was discovered and isolated. System was then re-filled, and the 11 1A11 cc JlU1'> re-started. Total time both trains were inoperable was 17 minutes. Cause of the event was a conm..nication breakdown between the maintenance crew and shift operating perso,nnel. Contracted maintenance personnel now work Wlder the same procedures as station personnel. Similar event: 455/86-001.

CCW Maine Yankee 06/02/81 Mode 6 30 min (from NSAC52, p. A-30): During refueling shutdown, service water cooling to the RHRS cooler was interrupted for approx. 30 minutes as a result of a breaker trip.

CCW Turkey Point 3 10/07/83 (from AEOO): Flow restriction on component cooling water discharge valve on RHR heat exchanger.

(Duration of event unknown)

• A-61

Appendix A.2.5 Inadvertent Safety Feature Actuation (ESFAS, ESFAS/SI)

• A-62

p. LER DATA BASE* ESFAS 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

. . . .. . . .~ . ..*. . .

ESFAS Cook 1 09/07/85 Mode 5 2 min (from Seabrook): Power was lost to the Control Room instr1.111ent bus distribution circuits for channel 3 and channel 4. This resulted in various ESF reactor trip signals and loss of the residual heat removal pl.l11JS. Channel 3 and 4 circuits were being powered by an alternate source while the nonnal power source was out of service.

(from CR5015): Power level - OX. on 9/7/85 at 0720 hrs with Unit 1 in Mode 5 power was l.ost to the control room instrlllleflt bus distribution circuits for channel 3 and 4. This resulted in various ESF reactor trip signals and loss of the RHR PJl1)S. Channel 3 and 4 circuits were being powered by an alternate source while the normal power source was out of service. The circuit breaker for channel 3 tripped as a result of an inadequately terminated lead. A licensed operator investigating the power loss thought the channel 4 circuit breaker had tripped also. The operator then attenl)ted to reset the breakers by opening then closing the breaker. This resulted in the channel 4 breaker being momentarily de-energized. This caused various ESF reactor trip signals and the loss of RHR pl.l11JS (due to the refueling water storage tank level indication reading low from power loss). This placed the unit in a LCO per Tech Spec 3.4.1.3. The RHR system was made operable within 2 mins after loss. To prevent recurrence the operator has been counseled not to take imnediate actions where the situation does not require it.

ESFAS Davis Besse 1 04/19/80 Mode 6 2 hr 30 min (from NSAC52, p. A-3, p. A-15): A loss of two vital instrunent buses resulted in a safety features actuation (SFA) while in mode 6. Control power was also lost to the RHRS suction valves interlock,.

causing them to shut. The SFA caused the suction of decay heat ~ #2 to be transferred to the BIJST and then emergency suq:,. Water from the BWST was gravity fed to the emergency suq:, during valve stroking time (approx. 1*1/2 minutes). The RHRS ~ injected about 3,500 gallons of BIJST water into the RCS, resulting in a small amount flowing out of tygon tubing used for vessel level indication.

• Approx. 1,500 ga.llons of RWST w~ter drained to the emergency *s~.

• The RHRS purp then lost suction and became airbound. Extensive~ venting was conducted and RHRS flow was restored 2-~/2 hrs later. RCS tenl)erature increased from 90 F to 170 F.

(from AEOO): 2-1/2 hr loss of OHR. Vibration from construction work actuated a ground fault relay.

Due to an abnormal electrical lineup associated with outage activities, loss of power resulted in SFAS actuation. Control power to the OHR suction valves was lost, causing the suction valves to close. The SFAS actuation transferred the OHR puip suction to the BWST and then to the enpty suip. The~

became airtxx.nd. RCS tenl)erature increased from 90 deg Fah to 170 deg Fah while the vessel head was detensioned (140 deg Fah is the maxi nun temp. al lowed while the vessel head is detensioned).

ESFAS Davis Besse 1 06/14/80 Mode 6 2 min (from NSAC52, p. A*15): Maintenance induced voltage transient in containment pressure section of the Safety Features Actuation System (SFAS) caused an SFAS actuation. This caused RHRS ~ suction to switch from the RCS to the borated water storage tank, injecting.16,000 gallons of BIJST water into the refueling canal. Seven minutes later, a low BWST level actuation of SFAS shifted RHRS ~ suction to the empty emergency suq:>. The RHRS puip lost suction and was stopped causing a loss of decay heat flow.

(from AEOD): OHR~ flow loss for about 2 minutes. Inadvertent SFAS actuation caused OHR puip realignnent to the BWST and BWST isolation. An I&C mechanic was restoring containment pressure inputs to SFAS following an Integrated Leak Rate Test. Because of a procedural inadequacy, SFAS was actuated and the OHR~ was realigned to deliver BIJST water to the RCS and the refueling canal. When BWST level dropped to the low level limit, SFAS level 5 actuation took place closing the BIJST isolation valve causing a loss of suction to the OHR puip

• A-63

p. 2 LER DATA BASE - ESFAS 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

-.-----* - *-------* .----- *. --- .--.\-- -- .-

ESFAS Davis Besse 1 07/24/80 Mode 5 2 min (from NSAC52, p. A-4): While attenq:>ting to clear Lights on the SFAS following maintenance, technicians adjusted a potentiometer, unaware the RHRS suction valve trip feature had been restored. This caused an RHRS suction valve closure. The RHRS pump was inrnediately stopped, and flow was restored within 2 minutes.

(from AEOO): DHR flow was lost for about 2 minutes due to an inadvertent closure of one of the DHR isolation valves. Subsequent to making a plant modification, an I&C mechanic performed restoration work out of sequence. As a result, one of the isolation valves closed.

ESFAS Davis Besse 1 07/24/80 Mode S SO min (from NSAC52, p. A-4): A loss of RHRS flow was caused by inadvertent automatic closure of an RHRS suction valve. The running RHRS pump was stopped to prevent damage. A manual bypass line around the shut RHRS suction valve was opened, system venting was performed, and the pump restarted. RHRS flow was lost for 50 minutes.

(from AEOO): DHR flow was lost for SO minutes because of an automatic closure of an isolation valve.

An electrician blew a fuse while conducting wire pulling operations associated with a plant design change. As a result of the blown fi'..se, an automatic closure of one of the OHR isolation valves took place, and the pump became air-bound. The DHR flow path was restored by opening the manual bypass valves. During the event, the hottest in-core thermocouple t~. rose from 104 deg Fah to 111 deg Fah.

ESFAS Davis Besse 1 08/01/80 Mode 5 3 min (from NSAC52, p. A-S): (Date is 8/3/80) During maintenance, a SFAS bistable was removed resulting in closure of a RHRS suction valve. The operating RHRS pump was stopped to prevent damage. The bistable was replaced and RHRS flow restored in approx. 3 minutes.

ESFAS Davis Besse 1 08/13/80 Mode 5 S min (from NSACS2, P. A-S): Maintenance performed on a SFAS cabinet resulted in RHRS suction valve closure.

The operating pump was stopped. The RHRS suction valve was reopened, the pump vented, and RHRS flow reestablished in approx. S minutes.

(from AEOO): DHR flow was lost for about S minutes due to an inadvertent closure of one of the OHR isolation valves. Valve closure occurred during SFAS channel modification work. The I&C mechanic failed to fully defeat the automatic isolation valve trip prior to performing SFAS channel modification work.

ESFAS Diablo Canyon 1 09/08/86 Mode 5 2 min (from Seabrook): An Instrunentation and Controls CI&C) technician inadvertently grounded a power supply while installing a modification in a Solid State Protection System CSSPS) cabinet. The momentary grounding of the power supply caused relay actuation which resulted in the closure of Residual Heat Removal CRHR) valve 8702 and an RHR low flow alarm. In response to the RHR low flow alarm, the operating RHR pump was secured by a licensed operator. RHR valve 8702 was reopened from the Control Room. The RHR pump was restarted at 2316 PDT and no seal damage was observed.

(from CR5015): Power Level - OX. AT 2314 PCT on Sept. 8, 1986, with the unit in Mode 5 (cold shutdown), an instrunentation and controls CI&C) technician inadvertently grounded a power supply while A-64

~* .

p. 3 PHASE 2 CATEGORY PLANT NAME LER DATA BASE - ESFAS EVENT DATE

~ . . .

INITIAL PLANT CONDITION 08/27/93 RECOVERY TIME installing a modification in a solid state protection systems (SSPS) cabinet. The ~tary grounding.

of the power supply caused relay actuation which resulted in the closure of r.esidual heat removal (RHR) valve 8702 and an RHR low flow alarm. In response .to the RHR low flow alarm, the operating RHR ~

was secured by a licensed operator. RHR valve 8702 was reopened from the control room. The RHR ~

was restarted at 2316 PDT, and no seal damage was observed. A significant event report was not filed within the 4-hour time requirement of 10 CFR 50.72. The significant event report was made at 1744 PDT, Sept. 9, 1986. The event was reviewed at an I&C tailboard meeting e1J1X!asizing attention to energized and potentially energized circuits when working on electrical corrponents. The circllllStances and lessons learned from the event will be evaluated for possible inclusion in the generic new eaployee training program for I&C personnel. Additional training on 10 CFR 50.72 reporting requirements will be provided for all applicable personnel.

ESFAS North Anna 1 11/06/79 Mode 6 5 min (from NSAC52, p. A-3): A jl.lll)er was installed in the solid state protection system for the p..irpose of conducting time response testing without disabling the automatic closure of RHRS suction valves. A false high pressure signal caused an RHRS suction valve to shut. Flow was re-established in approx. 5 minutes.

ESFAS Salem 2 06/23/83 Mode 5 See description of other Salem 2, 06/23/83 event.

ESFAS Salem 2 06/23/83 Mode 5 (from Seabrook Sheet 6 of 11): During routine shutdown operation, the Control Room operator observed two different instances in which a SJJl:lrious Safeguards Equipment Control (SEC) System actuation caused various loads on the No. 2A vital bus to be de-energized. In the second case~ the bus infeed breaker opened with no automatic transfer, rendering the bus inoperable. In both instances, *due to the loss of the operating Residual Heat Removal CRHR) ~ . flow in the operating RHR loop was lost.

(from AEOO): Loss of RHR J)U'i> due to sp..irious actuation of the SEC (safeguards equipment control) system. (Duration of event unknown)

ESFAS Sequoyah 1 09/16/82 Mode 5 6 min (from Seabrook Sheet 3 of 20): Both trains of the Residual Heat Removal System were declared inoperable due to the inadvertent closing of RHR suction valve 1-FCV-74-2.

(from AEOO): Power was removed to allow modification work on solid state protection system; RHR suction valve closed. (Duration of event unknown)

ESFAS Si.mner 10/02/84 Mode 5 inrnediately (from Seabrook Sheet 11 of 20) With Train B of the Residual Heat Removal (RHR) system in service, an instrument and control (l&C) technician removed two (2) fuses in Solid State Protection System (SSPS) cabinet XPN-7020 for personnel safety during inplementation of a modification. The fuses were inmediately replaced when the technician heard a relay activate. The deenergized circuit caused the Train A RHR suction isolation valves XVG-8702A and B cone valve in each RHR train) to close.

Operations persornel illlllediately restored Train B RHR to service after the valve closure.

(from CR5015): Power level - 0%. On Oct. 2, 1984, the plant was in Mode 5 with train 11 B11 of the residual control (l&C) technician removed two (2) fuses in solid state protection of a modification.

The fuses were illlllediately replaced when the technician heard a relay activate. The de-energized circuit caused the train "A" RHR suction isolation valves XVG-8702 A & B Cone valve in each RHR train)

A-65

p. 4 LER DATA BASE - ESFAS 08/27/93 PHASE 2 CATEGORY

~

PLANT NAME EVENT DATE INITIAL PLANT CONDITION RECOVERY TIME

. ---~---*-r***.. -. --*--- .----. ---.--------.------- .----------------------- *** ----------------------

to close. Operations personnel illlllediately restored train i1Ei 11 RHR to service after the v~lve closurt:.

The cause was determined to be drawing errors. At 1700 hrs during performanc;e of the same modification on SSPS cabinet XPN-7010, a similar RHR isolation occurred via the train 11811 RHR suction isolation valves XVG-8701 A & B (one valve in each R.HR train). The I&C technician was lifting *leads affected by the modification to prevent a repeat of the previously mentioned isolation when a defective fuse holder interrupted power to the train 11811 circuitry. Operations personnel illlllediately restored train "B" RHR to service after the valve closure. To prevent a potential recurrence, the licensee initiated a drawing revision and replaced the defective fuse holder on OCt. 9 and OCt. 10, 1984, respectively.

ESFAS Surry 2 08/18/89 ox, Unit 2 cso Power level - OX. On 8/18/89 with Unit 2 at cold shutdown (CSD) at 1010 hrs, 3 motor operated valves (MOVs) in the safety injection (SI) system actuated. The valves are designed to reposition when a recirculation mode transfer CRMT) signal is generated upon a low level condition in the R\.IST. However, no low level existed at the time. This spurious R.MT actuation constitutes an unplanned engineered safety features (ESF) carponent actuation and was reported to the NRC per 10CFR50.72(B)(2)CII). An electrician inadvertently energized a relay that actuated the valves while placing a j ~ r on an adjacent terminal in support of an engineering work request. A hllll8n performance evaluation system (HPES) investigation was conducted and a report prepared. Reconmendations made in the report will be evaluated and appropriate actions taken_

A-66

p. LER DATA BASE - ESFAS/Sl 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

. . . ~* . :: ', . . . . . . . .. .

ESFAS/SI Surry 1 04/26/80 CSD Maintenance Power level - 0%. On 6/12/85 at 1735 hrs with the unit in refueling shutdown, a spurious safety injection occurred during PT 18.2A (SI functional test). The procedure contains 1 step that executes 2 actions, reset and then block SI. This led to the spurious SI. The SI function test for units 1 and 2 will be'moclified to provide separate steps and signoffs to reset and block SI.

ESFAS/SI Surry 1 03/01/84 CSD Power level - 0%. on March 1, safety injection signals were initiated as a result of c011pleting 3 of 4 high contairvnent pressure signals and c~leting 2 of 3 high steam flow signals. At the time of the event, operators were performing MOP 26.9 (removal of vital bus sole transformer I-I) when vital bus and III were mistakenly cross corviected out of phase. This reuslted in a voltage transient on vital bus I and III, which caused spurious containment high pressure and high steam flow signals. The voltage transient in vital bus I and III is believed to have resulted in tripping 2 of 4 contairment high pressure relays. Since channel II was in trip prior to the voltage *transient, the 3 of 4 matrix for containment high pressure was COllpleted and safety injection was initiated. Also, the power transient resulted in resetting the high steam flow low tavg or low steam pressure safety injection circuitry. since high steam flow signals were also generated with voltage transient and both low header pressure low tavg were present, safety injection was actuated. The operator was re-instructed in the correct manner of removing the vital bus sola transformer. labels have been made for both unit's manual transfer switches. Fan S8B iris damper shall be run in the automatic mode.

ESFAS/SI Surry 1 11/16/84 Refueling SD Power level - 0%. With the unit in a refueling shutdown condition, a spurious safety injection occurred when returning CLS-hi (equivalent to contairment depressurization actuation system) to service. The controlling procedure was inadequate in that the procedure did*not require the resetting of CLS-hi. The ill1)8ct on the unit was minimal and the unit was returned to a normal condition.

OUt~tanding *work procedures, that* required the de-energhing* of *cts-hi; were held in *abeyance ...itil the procedures could be modified.

ESFAS/SI *surry 1 05/11/86 Shutdown Power Level - OX. On May 11, 1986 at 0841 with Unit shutdown and on the residual heat removal system and Unit 2 at 100% power, Unit 1 experienced a t~rary degradation of 1 8' clc bus voltage. The decrease in 1 8 1 de bus voltage caused '8' train reactor annunicator panels f-1( to become inoperable.

Safety injection actuation caused the pressurizer level to increase and exceed the tech spec limit of 33%. The event and its cause were diagnosed and safety injection terminated by 0843. Pressurizer level peaked at 42% and decreased to Less than 33% by 0847. RCS pressure remained constant during the event. The 1 8 1 de bus was restored to full voltage at 0900 and the annunciators returned to service at 0905. The cause of the event was an inadequate procedure in a design change to replace the *1 8 1 batteries. Design changes for replacing the other station batteries will use a revised procedure to preclude recurrence.

ESFAS/SI Surry 1 06/05/89 CSD Power Level - 0%. On June 5, 1989 at 1141 hrs, with Unit 1 at cold shutdown, an unplanned initiation of an engineered safety feature CESF) occurred during preparations to conmence a special test. The initiating signal was a low steam generator CS/G) level trip that resulted in closure of the S/G blowdown trip valves, opening of the auxiliary feedwater CAFW) valves, closure of the motor driven AFW JlU1'> breaker and opening of the steam driven AFW ~ steam supply valves. The ESF actuation occurred while siaulated S/G level signals were being transferred from one channel to another. The test directors were aware of the potential consequences of this action, but did not inform the shift supervisor. The test directors were counseled as to the necessity of keeping the shift supervisor cognizant of testing activities.

A-67

p. 2 LER DATA BASE - ESFAS/SI 08/27/93 PHASE 2 CATEGORY ESFAS/SI

~

Surry 2 PLANT NAME EVENT DATE 06/12/85 INITIAL PLANT CONDITION Refuel 1ng SO RECOVERY TIME Power level - 0%. On 6/12/85 at 1735 hrs with the unit in refueling shutdown, a spurious safety injection occurred during PT 18.2A (SI functional test). The procedure contains one step that executes 2 actions, reset and then block SI. This led to the spurious SI. The SI function test for units 1 and 2 will be modified to provide separate steps and signoffs to reset and block SI.

ESFAS/SI Surry 2 11/16/86 CSD Power level - 0%. On Nov. 16, 1986 with Unit 2 at cold shutdown, during the performance of periodic test 16.3 (type 'A' test), a hi consequence limiting safeguards (CLS) signal was generated resulting in the unplanned closure of the containment radiation monitoring trip valves TV-RM-200A, 2008, and 200C.

This event was due to an inadequate procedure which did not instruct test personnel to close the trip valves affected by the hi CLS signal. The procedure will be modified to correct this inadequacy. This report is submitted pursuant to 10CFR50.73CA)C2)CIV).

ESFAS/SI Surry 2 09/08/89 0%; Unit 2 CSO Power level - 0%. On Sept. 8, 1989 at 2142 hrs, with Unit 2 in cold shutdown, during performance of a periodic test on the turbine building flood control circuitry, two of the four condenser waterbox circulation water (C\l) inlet isolation valves closed unexpectedly. The condenser inlet valves are designed to close upon the initiation of a hi hi consequence limiting safeguards (CLS) signal in coincidence with a loss of offsite power; however, no actual hi hi els signal was present. The event is being reported as an unplanned engineered safety features CESF) coqx>nent actuation. A four hour non-emergency report was made to the NRC per 10CFR50.72. The event was caused by a relay in the flood control circuit that did not drop out as required during testing which resulted in actuation of the valves. It was detennined that the original relay had been replaced with a new relay which required 1 less hold-in current causing this event to occur. An investigation will be conducted to determine how the new relays.were installed.

A-68

p. LER DATA BASE - AIR 09/14/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME AIR Beaver Valley 1 08/29/85 Mode 1 10 min On 8/29/85 at 1248 hrs, a low station air pressure alarm was received. Operations personnel responded by starting the standby station air compressor. The reduced air pressure initially caused one main steam isolation valve to drift closed. The resultant increased steam flow caused steam line pressures to drop in the other two steam lines. The pressure drops were sufficient to actuate the rate-compensated low steamline pressure safety injection signal. The safety injection signal caused a resultant reactor trip. The control room operators followed the applicable emergency procedures and stabilized the plant in hot standby. An unusual event was declared at 1300 hrs and terminated at 1315 hrs. The low station air pressure was the result of a failed solder fitting on the instrument air system. The solder fitting failed due to a faulty heater control on an instrunent air dryer and improper equipment restoration. During subsequent plant recovery actions, water was found spraying from both low head safety injection pump wedge control rod seals. Both~ were declared inoperable which required an entry into cold shutdown. Postulated failure on the control rod seals was from a minor flow induced pressure transient. Following equipment repair, a plant startup to full power operations was conmenced on 9/1/85.

AIR callaway 11/05/84 Mode 1 20 min On 11/5/84 at 1156 CST and 11/6/84 at 0450, with the plant in mode at 45% power and 16% power, respectively, air lines supplying the SG feedwater regulating valves failed which caused ESF actuations along with reactor trips. The first event was due to a failure of the air line connection to the feedwater control valve, FCV-530, for SG *c*. Upon the loss of air supply, FCV-530 failed closed resulting in a lo-lo level in SG *c* which caused a reactor trip, turbine trip, feedwater isolation signal (FWIS), aux feed~ater actuation signal (AFAS) and SG blowdown isolation signal (SGBIS). The second event was due to a failure of the air line to the 'A' feedwater pump recirculation valve FV-2B causing it to fall open and closed then open. The resultant feedwater flow oscillations produced a

. high level in SG *c* c~using a turbi.ne trip, FWIS, AFAS and SGBIS. Due* to the FWIS and AFAS, SG levels began to decrease and at 0454 a lo-lo level on SG 'D' caused a reactor trip. The air line failures were.due to improper material applications and resulting fatigue cracking caused by the vibrations imposed on the air lines during feedwater system operation. Temporary repairs using copper or stainless steel tubing were made and design changes to install hangers are being made in accordance with aaninistrative procedures.

AIR Calvert Cliffs 1 01/27/87 Mode 1 20 min Power level - 100%. At 1809 on Jan. 27, 1987 the unit was manually tripped due to decreasing steam generator levels, which resulted from a loss of instrl.lllent air. At 1816 the reactor coolant pumps were stopped, because_ cooling water was isolated upon the loss of air pressure. Reactor coolant system temperature was maintained by the use of auxiliary feedwater and manual control of the atmospheric dump valves. At 1825 instrl.lllent air pressure was restored, and two reactor coolant pumps were started. At 1840 the remaining two reactor coolant pumps were started and the unit was maintained in Mode 3 (hot standby). To prevent recurrence of this type of event an engineering analysis is being performed to identify modifications that can increase the reliability of the instriinent air system, and the general supervisor-operations is reviewing this event with all operators.

AIR Catawba 1 01/14/85 Mode 2 15 min On 1-14-85, at 1440 hrs, the Unit 1 reactor was manually tripped. The reactor coolant pumps had been previously shutdown due to the loss of motor cooling water, and the ability to control unit reactivity was therefore less than desirable. The loss of motor cooling is attributed to a malfunction of service water valve 1RN-A83, which opens to supply an alternate source of cooling water to the reactor coolant pumps when the normal source is not available. On 1-14-85, a vendor was onsite to drill additional wells associated with the cathodic protection system. While drilling, an instriinent air system line A-70

p. 2 LER DATA BASE - AIR 09/14/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

---

. - . ----' .--- .--------- . ~ ..... --------------------------------------------.------------- - ----- --

was drilled through. The VI line which was* ;up~~red supplies control air to th~ cont. chilled *water control panel (1YV-CP-1). The loss of control air to 1YV-CP-1 caused the YV. chillers and piinps to shutdown. This sytem supplies the normal source of cooling water to the reactor coolant pump motors.

The 4 service water swap-over valves, which supply an alternate water source, are supplied by a different VI header than 1YV-CP-1. The swap-over valves therefore did not att~t to realign as they did not experience a loss of control air. Realizing that a swap-over to service water had not occurred, the NCO realigned the YV control switch from auto to service water but did not receive indication that a swap-over had taken place. Verification revealed that 1RN-A83 was still closed.

AIR Cook 1 11/25/85 Mode 1 20 min On 25 Nov, the reactor tripped while surveillance from the nuclear power range instrunent N-41 time constant rate trip circuit was in progress. The surveillance required the bistables for N-41 to be tripped. That resulted in a standing quadrant power tilt (QPT) alarm. Tech Specs required that the QPT be calculated with less than 4 power range instrtinents in service. During the process of taking electrical current readings from the other power range channels, to perform the tilt calculations, a spike occurred on N-44. The spike was found to have been caused by removal of the meter probe used for taking the current readings. The spike in power range instrument N-44 resulted in the 2-out-of-4 logic required for a rate trip.

Following the reactor trip with the turbine driven aux Fil~ <TDAFP) operating at rts normal speed, the turbine would not respond to control signals to reduce speed. The TDAFP was tripped and SG level was controlled using motor driven aux Fil~- Local control of the TDAFP could have been taken if it had been required. During the investigation, it was discovered that the control air tubing to the TDAFP governor had broken off. The cause of the tubing failure was attributed to its location. It was believed that per~orviel had .us.ed the t~ing as a hand hold ~hile checking TDAFP governor oil level.

To prevent recurrence of the reactor trip, operating procedures were changed to prohibit the use of a meter probe in an operable power range drawer for current readings when the bistables were tripped in another power range drawer for surveillance testing. To prevent recurrence of the control air tubing failure, a design change was completed that rerouted the tubing to prevent its being used as a hand hold.

AIR Davis Besse 1 12/07/87 Mode 1 31 min On 12/7/87 the unit experienced a reactor trip at 0656 hrs from 81% reactor thermal power. The initiating event was a loss of instrument air pressure which caused several secondary system valves to go to their failed position. Reactor power increased to the integrated control system (!CS) high demand limiter, feedwater flow increased causing reactor coolant system Tave to decrease. Due to a large moderator t~rature coefficient, reactor power increased to the reactor protection system high flux trip setpoint. The post-trip plant response was normal except that steam generator 1.1 pressure was slightly lower and steam generator 1.2 level was higher than the expected post trip ranges.

Operator actions were required to close.the moisture separator reheater (MSR) second stage reheat steam source valves and to stabilize steam generator 1.1 water levels. The loss of instrument air pressure was caused by direct venting of the instrunent air header to atmosphere when a solenoid valve failed on instrunent air dryers 1-1 and 1-2. This solenoid valve was repaired. The MSR second stage reheat steam source valves did not close clue to a pressure switch failure. This switch was replaced. The ICS did not respond fast enough to steam generator 1-1 decreasing water level. A modification to the ICS is scheduled *

• A-71

p. 3 LER DATA BASE - AIR 09/14/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY ,DATE CONDITION TIME AIR McGuire 1 11/02/85 Mode 1 20 min On 11-2-85 at 0640 a section of braided, flexible pipe on the discharge of instrument air COl!pressor B ruptured at a welded seam. As a result, all VI loads not protected by check valves experienced decreased VI pressure. The Low VI pressure caused the feedwater .control valves on each unit to begin to close, causing SG levels to decrease. At 0641, Unit 1 experienced a reactor/turbine trip on SG 1A low-low level. Pressurizer pressure dropped below the safety injection setpoint (1845 psig) initiating SI. The pressure dropped was partially d~e to a higher than normal steam loads with some-valves failing open on loss of VI. Unit 2 tripped on SG 2A low-low level, but pressure did not decrease to the SI setpoint. Both units were at 100% power at the time of the incident. VI c~ressor B was isolated and VI pressure returned to normal. The ruptured pipe was replaced. Several modifications are being reviewed for possible implementation.

AIR Millstone 3 04/12/87 Mode 1 20 min on April 12, 1987 at 0618 hrs, while operating at 66% power in Mode 1, a reactor trip occurred due to low low steam generator level in the D steam generator. The control room operators were in the process of increasing power during the initial startup following a scheduled maintenance outage. Approx. 15 minutes prior to the trip, the operators had increased reactor power from 56% to 66% within a 16 minute interval. When at 66% power the speed controller to the A turbine-driven feedwater pump (3FWS-P2A) began to oscillate. The responsible operator asslJlled manual control of the pump in an attempt to stop the oscillations. He was unable to.do so before the level in the D steam generator fell to the low low level and the plant tripped. The operators verified the opening of all reactor trip breakers and full insertion of all control rods. The root cause of the reactor trip is equipment failure. The primary cause was an air leak in an air supply Line to the D feedwater regulating valve, which resulted in Low low steam generator level. The leak had been fixed. A contributing cause was oscillations in the A turbine~driven f~wate~ punp controller. A vendor representative was consulted and found no problems with the~ *cont~olle~~ .. It respo~~-c~rrectly ~ring a plant startup on April 13, 1987. No other work is planned.

AIR Oconee 3 08/14/84 Mode 1 20 min on Aug. 14, 1984 at 1126 hrs, Unit 2 tripped from 100% full power (FP) when the instrument air Line to the POIIDEX outlet valves was accidentally sheared. The loss of air to the outlet valves caused the valves to fail shut which resulted in a loss of condensate flow to the condensate booster (CB) punps.

The CB pumps tripped and caused the main feeclwater (MFDW) ~ to trip on low suction pressure. The loss of the MFDW pumps initiated a reactor anticipatory trip. Approx. 16 minutes after the trip, the "3A" MFDW punp was restarted to r:eestablis~ MFDW flow. The emergency feeclwater (EFOW) control valves, 3FDW-315, 316, closed on an indication of 750 psig discharge pressure from the "3Ai, MFDW punp as designed. The once through steam generator's (OTSG's) were isolated from all feeclwater flow for approx. 9 minutes as a result of the automatic closing of the EFDW control valves and lack of MFDW flow due to insufficient discharge pressure from 3A MFDW pump. The inmediate corrective action was to stabilize the unit in a hot shutdown condition using emergency feedwater (EDFW). The inmediate corrective action to *restore feedwater flow *to the OTSG was to manually open the EFDW control valves and to increase 3A MFDW punp speed. The sheared air line was repaired. The unit was restarted and reached 100% FP at 0100 on Aug. 17, 1984.

AIR Prairie Island 1 05/08/85 Mode 1 20 min on May 8, 1985 at about 1323, a 2-inch copper instr1.111ent air l i_ne separted at a soldered elbow joint (PSF). As a result, the Unit 1 side of the instrunent air system (LD) depressurized enough to cause the feedwater regulating valve (FCV) to No. 12 steam generator to close. At 1326, Unit 1 tripped on Low steam generator level plus feedwater ftow/steam flow mismatch. Cable tray (TY) wrapping for A-72

p. 4 LER DATA BASE - AIR 09/14/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME Appendix R compliance was in progress in the vicinity of the break, and the air Line was moved somewhat to accomplish the wrap. This apparently placed enough stress on the elbow to cause it to separate.

The Unit was maintained in hot shutdown while repairs were made. A walkdown inspection of the instrunent air system was performed in areas of the plant where cable tray wrapping had taken place or was in progress. No additional problem areas were identified. The Unit was returned to service at 1847 on May 9.

AIR Shearon Harris 08/04/87 Mode 1 20 min The plant was operating at 100% reactor power in Mode 1, power operational on Aug. 1987. Instrument air dryer 1A was out of service for repairs. Instrunent air dryer was bypassed at approx_ 1715 hrs to replace the desiccant. Work was completed the dryer 1B and at approx. 2150 hrs the clearance on the dryer was removed. The restoration alignment on the clearance for placing dryer 18 back into service was incorrect. When the valves were repositioned in accordance with the clearance restoration lineup the instrunent air compressors were isolated from the air system. The air isolation caused air pressure to decay and caused air operated valve to go to "fail safe" positions. In particular, the main feedwater regulating valves to drift shut and the heater drain level control valves to divert drain flow to the condenser. Heater drain purps 1A and 18 tripped and a manual turbine runback was initiated. This was followed by a trip of main feedwater purp 1A which initiated an automatic turbine runback. The loss of instrunent air resulted in a decrease in steam generator water Levels. The**

turbine runback resulted in shrink in steam generator levels and resulted in a reactor trip at 2154 hrs due to steam generator feedwater steam/flow mismatch with low steam generator water levels.

AIR Surry 1 01/07/86 Mode 1 10 min On 1-7-86, an *aux. ventilation system safety mode initiated* alarm was received in the control room at 2059 hrs and the aux. ventilation emergency fans, 1-VS-F-58A and 588, auto started. Within seconds, trip valves TV-1204 and TV~CC-107 closed. While the ope~ators atterrpt~ to open the_ trip.valves, they noted instrunent air header pressure decreasing and feed flows decreasing. Inmediately, the operators attempted to open the feed reg. valves CFRV). However, due to the decrease of instrunent air CIA) pressure, operators could not prevent the FRV's from fully closing and at 2104 hrs a reactor trip occurred as a result of a Low steam generator (S.G.) level coincident with feed flow Less than steam flow signal. The decrease of IA pressure was due to ice formation in the Unit 1 IA dryer that resulted in blocking air flow. A hot gas bypass valve in the dryer was not properly adjusted. The Unit 1 IA dryer was the source of the problem and was bypassed. IA pressure was returned to normal and the affected system and c~nents were realigned. The bypass valve was properly adjusted by a service representative. Turbine building logs will be revised to incorporate IA dryer condenser temperature readings.

AIR Yankee Rowe 10/04/86 Mode 1 10 min While operating at 100% power in Mode 1 at 0917 on Oct. 4, 1986, the No. 3 (main) control air compressor air pressure switch CA-PS-453 failed. As a result of this failure and the subsequent inability of the back-up air compressors to rapidly restore the air pressure, the air header pressure decreased sufficiently to lock (by design) the feedwater control valves (FCV-FW-1000, 1100, 1200, and 1300) into the as-is position at 0918. Subsequently, the operators initiated steps by procedure to reset/restore the feedwater control valves to normal. As soon as the first feedwater control valve was reset (unlock) it began to rapidly open. This preferential feeding of No. 1 steam generator caused the Levels in the other three steam generators to rapidly decrease, resulting in a reactor scram on Low steam generator Level at 0938. The root cause of this event is the failure of the air pressure switch CCA-PS-453) coupled with recovery procedure guidance inadequacies for resetting of the feedwater control valves upon Lock-up. Corrective action included repair of the failed equipment and clarification of procedure instructions. All automatic safety systems functioned as required. The A-73

\

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p. 5 LER DATA BASE - AIR 09/14/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

~ .' . . . . . - . --. . -.- . - .. ---- . . . .. : .;

faulty air pressure switch for No. 3 control air c~ressor was replaced.

A-74

p. LER DATA BASE* LOCAs 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME

• * * . **** .. "I * * * . *

• HCVCS Turkey Point 3 01/15/88 being cooled down Power level - OX. On 1/15/88, Unit 3 was being cooled down and depressurized. Pzr spray valve PCV*3-455B was identified as having erratic operation on 1/11/88, and a plant work order to correct the problem was issued. lolith the reactor coolant system (RCS) t~. at 400 degrees F and pressure at approx. 950 psig, it was decided to slow the cooldown rate from 90 deg. F per hr to about 20 deg per hr, due to the shortly upcoming shift turnover. At 0650, as the coolclown rate was being decreased, the pzr level started to increase. _At this point, the reactor control operator (RCO) secured charging J)U1')

3A. An adjustment was made to valve PCV-3-455B at 0650 in order to decrease.RCS pressure. By 0730, shortly after turnover, RCS pressure decreased to.625 psig and the accUD.Jlators started to inject.

Upon noticing the RCS pressure drop, an RCO inmecliately closed PCV-3-455B and terminated the RCS pressure decrease. Approx. 65 gallons of water were injected into the RCS. The primary cause of the event was a defective controller for valve PCV-3-455B. Contributing causes were the RCO's failure to note the decreasing RCS pressure in time to take proapt corrective action, and a misc0111DJnication between the oncoming and the offgoing RC0 1 s. The controller for valve PCV*3-455B was replaced.

HRHR Sequoyah 1 02/11/81 The residual heat removal (RHR) contairment spray was inadvertently initiated when an assistant unit operator (AUO) opened valve 1-FCV-72-40, which isolates the RHR system from the containment spray header. The spray continued for approx. 35 minutes releasing approx. 40,000 gallons of primary water and 65,000 gallons of refueling water storage tank water to the contairment bldg. The UO received alarms indicating a rapid decrease in pressurizer level and pressure. The uo notified the shift engineer (SE) of the condition and then tripped reactor coolant J)U1')S 1 and 2 (pumps 3 and 4 were not running). The situation was diagnosed as a possible loss of coolant accident (LOCA) and emergency operating instruction (EIO) O and 1 were consulted. The AUO, who opened the isolation valve, entered the control room with another UO discussing the valve. At this time the control room ~loyee checked the indicator light.

and. . verified

. ~ .

it was. indeed open. The valve was shut and IP*4 was terminated.

(from NSAC2, p. A*13) An RHRS containment spray isolation valve was inadvertently opened creating a loss of _coolant accident (LOCA) from the RCS via the RHRS to the containment spray header. The pressurizer ~tied and RHRS JXl1'> suction was essentially lost in about 2 minutes. The LOCA lasted for 39 minutes, during which (minute 10) the RIJST was valved into the RHRS in an attenq:,t to makeup for lost inventory. But the RHRS suction valve from the RCS was left open, permitting the LOCA to continue.

Also, residual RCS pressure overcame the pressure head of the RlolST, limiting the supply of makeup water. High pressure safety injection was manually initiated after 35 minutes. A total of approx.

40,000 gallons of reactor coolant and 60,000 gallons of RIJST water was sprayed into the containment.

JCVCS Robinson 2 01/29/81 *.:

A spurious safeguards actuation and reactor trip were received resulting from a high steam flow spike caused by turbine governor valve/E-H oil problems. Letdown flow _was restored. RCS pressure began decreasing with contairment pressure and dew point increasing. Upon contairment entry following letdown isolation, a letdown line drain valve (CVCS-200E) was found partially opened and leaking through with its pipe end-cap missing. Cause is the valve vibrating open and the pipe cap, which was serving as a pressure boundary, failing to hold at sometime following the first SI. Approx. 4500-6000 gallons of water leaked to the contairment sump during the event. Letdown was secured. The valve was secured in the closed position and a new cap was installed.

JCVCS lolaterford 3 12/16/85 plnt heatup Power level - 0%. On Dec. 12, 1985, lolaterford Steam Electric Station Unit 3 was conducting a plant heatup following an outage. At 2340 hrs the plant was at 444 degrees and 1490 psis when a reactor coolant system (RCS) leak was indicated inside containment. The chemical and volume control system (CVCS) was isolated at 0007 hrs and the leakage stopped. At 0040 hrs an inspection of the containment A-76

p. 2 LER DATA BASE* LOCAs 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME determined the leakage to be from relief valve RC 526 on the ten;,orary reactor cool.ant pul1J seal .

injection system. The system was isolated and the eves was restarted at 0046 hrs. A subsequent calculation verified RCS leakage was less than one gallon per minute. Since there was no operable boration flow path or charging path while RC 526 was opened, the plant was in a condition prohibited by technical specifications for approx. 29 minutes. The apparent root cause of the event was the failure of utility licensed operators to doc1.111ent the status of this sytem during shift turnover. The shift turnover procedure.has been revised to provide for a 24 hr format turnover sheet for all licensed positions. This will facilitate review of turnover information from several previous shifts. Since, due to plant conditions, the boration capability of the charging system would not have been required during an accident, this event did not affect public health and safety.

JCVCS Yankee Rowe 06/27/86 Mode 5, Maint out Power level - OX. On June 27, 1986, at 0137 hrs during a maintenance outage with the plant in Mode 5, main coolant was inadvertently drained to the Low pressure surge tank CLPST). This could have resulted in a Loss of shutdown cooling. This event occurred while transferring to the alternate method of shutdown cooling per procedure OP-2162, Attachment c. Performance of this procedure was necessary because of the failure of the shutdown cooling pulp's shaft seal. During the evolution, approx. 2000*

gallons of water was drained from the pzr and main coolant pressure dropped from 100 psig to 10 psig.

The pzr did not enpty. The control room operator CCRO) inmediately secured the LPST cooling pulp and the primary auxiliary operator (PAO~ isolated the flow path. The CRO started all three charging puips and restored pzr Level and pressure. The root cause of this occurrence has been attributed to personnel error. While conducting the alternate shutdown cooling valve lineup, CH-V-654 was not fully shut, which resulted in a main coolant system to LPST flow path. The* PAO thought that the valve had ccapleted its full travel when he operated the manual valve. This occurrence was reviewed with the appropriat~ plant personnel arict the need for strict procedural compliance was esrphasized. This is the first occurrence of this nature. There were no adverse effects to the public health or safety as the*

result of this occurrence.

. JRHR Braidwood 1 03/25/88 0% power level Power level - OX. On March 25, 1988 and March 27, 1988, operators noted a decreasing volune control tank Level which caused increased make-up. Reactor coolant water inventory balance surveillances confirmed that unidentified leakage was in excess of 1 gpm. The source of the March 25, 1988 occurrence was thought to be an improperly Locked closed valve which was inadvertently bunped off its closed seat. The residual heat removal (RHR) ~ suction relief valves may have contributed to the generating station emergency plan unusual event for both occurrences. Leakage past the seats by measuring the downstream tenperature indicated the source of leakage. Subsequent investigation of one of the relief valves indicated that the disc insert pin was broken as a result of inproper nozzle ring setting. The 1A RHR suction relief valve has been repaired and reinstalled. The 18 relief valve will be tested and repaired as necessary prior to restart of the unit. There have been no previous occurrences of Crosby relief valve failures.

JRHR Braidwood 1 12/01/89 0% power Level Power level - OX. At 0142 on 12/1/89 while drawing a bubble in the pzr, reactor coolant system (RCS) pressure slowly increased from 375 psig to 404 psig. At this time the 18 residual heat removal (RHR) pulp suction relief valve, which had a setpoint of 450 psig, actuated and remained open. Charging flow was increased but pzr level indicated 0% by 0151. Reactor operators concluded that an RHR pulp suction relief valve had lifted because hold up tank Levels were increasing rapidly. The operating train of RHR, 1A, was isolated at 0155. At 0200 RCS pressure reached 272 psig and stabilized. RCS Level was at the Lower portion of the pzr surge Line and flow into the RCS was equal to the flow exiting the RCS.

At 0215 the Licensed supervisors decided to return the second charging pulp to service per

• 10CFR50.54(X). At 0235 the second charging~ was started. At 0245 pzr level was above 0%. At 0319 A-77

p. 3 LER DATA BASE - LOCAs 08/27/93 PHASE 2 CATEGORY PLANT NAME EVENT DATE INITIAL PLANT CONDITION RECOVERY TIME 0

field reports identified that the 18 RHR ~ suction relief had act~ted; At 0350 the 11 11 RHR train*

was isolated which terminated the event. Approx. 64,000 gallons had relieved through the valve. The cause of the early lift was dirt between the valve spindle and guide sleeve which affected valve lift setpoint adjustment. The cause for the valve remaining open was an incorrect nozzle ring setting due to a personnel error.

JRHR McGuire 2 08/05/84 0% power level Power level - 0%. On 8/6/84, McGuire 2 operators discovered a broken weld on the residual heat removal (RHR) system letdown line to the chemical and voliine control system (CVCS). The RHR system was in service at the time, and water was spraying from the broken pipe and from the stem of the valve C2NV-121) in the eves. An estimated 3000 to 7000 gallons of contaminated water was contained in the heat exchanger room, the RHR and contaiment spray SUit), and the B floor drains~ and tank. Upon discovery the leaking line was isolated, a subsequent inspection revealed a nurt>er of supports/restraints CS/RS) damaged, and the broken socket weld coq>letely separated. On 45/85, 7 socket welds with crack indications were discovered on the 2-inch crossover piping between valves 2ND-17 and 2ND-32. No weld failured occurred as in 8/84- Six of the welds with indications were in piping rep.laced after the failure, but before vibration testing fol lowing the 8/84 failure. Causes of the August event are attributed to c ~ n t malfunction/failure, due to loose packing in 2NV-121, and to an unusual service condition, because a gas void in the line resulted in water hanmer. The cause of the April event is classified as an unusual service event, because socket welds were not designed to withstand the severe loading of the.vibration testing that occurred in 8/84. Damaged piping and S/RS have been replaced. The subject valves have been modified.

JRHR S1m11er 1 05/06/85 CSD (Mode 5)

Power level - 0%. On May 5, 1985 at approx. 22 hrs, a reactor coolant system (RCS) pressure transient resulted in a challenge of a resid~l heat removal CRHR) suction relief valve. The plant was in cold shutdown (Mode 5) with RHR system (Train "A") in operation. 'Di~sel generator CD/G) surveillance testing was in progress and had resulted in a non-valid test failure during an attenpt to parallel the 0/G to the ESF bus CXSW-108). The failure to parallel the D/G was a result of failure of the speed control switch on the aiain control board. During troubleshooting activities on the.DIG, a personnel error resulted in a loss of ESF bus CXSW-108). Major equipment affected included the loss of the 11811 coq>onent cooling water CCCW) ~ . 11811 service water CSW) ~ . and 11011 HVAC chiller and chill water

~ - The loss of CCW flow to the reactor coolant pump (RCP) required the shutdown of the operating RCP. The breaker was reclosed to ESF bus (XSW-108) and the bus was reloaded. Upon restart of the RCP with solid plant operation, pressure spikes occurred which resulted in the challenge to the train "A" RHR suction relief valve. Following the relief valve actuation, an operator noted that pressurizer relief tank CPRT) level continued to increase apparently due to a failure of the relief valve to reseat. Approx. 1600 gallons of RCS inventory were released to the PRT.

KRCS North Anna 1 06/17/87 0% power, refuel.

Power level - 0%. On June 6, 1987, during the 59th day of a refueling outage with Unit 1 in Mode 5 and Unit 2 in Mode 1, a problem developed with the Unit 1 'A' reactor coolant~ CRCP) motor which required motor replacement. The RCP motor was uncoupled at 0420 hrs on June 18, 1987, resulting in a small but expected leak up the pull> shaft of several gallons per minute. It was believed that the makeup flow rate to the reactor coolant system (RCS) compensated for this and other inventory loss because pressurizer level was held at approx. 20%. However, at 0130 hrs on June 21, 1987, it was discovered that pressurizer pressure was subatmospheric, and as a result, pressurizer level was not a reliable indication of RCS inventory. RCS inventory had decreased by approx. 17,005 gallons. There was no impact on safety because the residual heat removal system remained in service throughout this event. Corrective actions have been identified to address procedural, training and RCS inventory indication inadequacies during Mode 5 operation. Although there was no impact on safety, and it is not reportable under 10CFR50.73, this report is being submitted as a voluntary LER due to the potential for A-78

p. 4 LER DATA BASE - LOCAs 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME foaclvertent RCS inventory loss.

KRCS Trojan 07/03/81 Reactor coolant system leakage of approx. 14 gallons per minute was experienced during the perfonnance of a reactor coolant system integrity test. This is in excess of the technical specifications limit of 10 gmp for identified leakage. The source was leaking drain valves on the reactor coolant loops. The type of valve used to isolate the loop drains nust be torqued to ensure they seat properly. Plant procedures did not specify this requirement. As a result, the valves were checked shut during preoperational valve lineups but were not torqued *

• A-79

Appendix A.2.8 Transients A-80

p. LER DATA BASE - TRANS 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME TRANS Surry 1 07/09/81 lfoutine startup The maxinun allowable containnent partial pressure of T.S. was exceeded. The unit was shut clown and brought to cold shutdown in accordance with T.S. requirements. The containment pressure increase was caused by a feedwater leak through a failed flange gasket for "A" auxiliary feedwater line flow limiting venturi. The high temperature viton gasket used was not c~tible with the slip on flanges used. The gaskets for all three AF~ venturies were replaced with flexatalic gaskets.

TRANS Surry 1 01/05/82. Routine SO

~ile removing the unit from service, a spurious SI signal was generated. Trip valve, TV-CC-109B, failed to close as designed. The coaponent cooling CCC) system is a closed system and its itnegrity was maintained during the event; therefore, an isolation barrier existed between the containment and the environnent. A search for an electrical cause for the valve malfunction revealed no problems. No specific mechanical cause has been found. Efforts have been initiated to further investigate the event but no definitive answers are available at this time.

TRANS Surry 1 01/06/82 HSO A spurious safety injection caused a phase 1 containnent isolation. Trip valve CC-1098 failed to close as required by tech spec. The cause of the event was determined to be a piece of teflon tape (type used to seal threaded air fittings) which prevented operation of the three way SOV that controls TV-CC-109B. Corrective actions consisted of checking valve operator circuit, establishing adninistrative control of the valve, removing foreign material, testing as per PT 18.6B and returning to service.

TRANS Surry 1 04/15/82 Routine startup The reactor coolant system was diluted to a boron concentration wherein the critical rod position achieved, if the control rod assemblies were withdrawn in normal sequence, would have been lower than the insertion limit for zero power. This is contrary to tech spec 3.12.A.4 and reportable per tech spec 6.6.2.B.(3). Failure to maintain makeup boron concentration equal to RCS concentration resulted in an overdilution. Because of errors in the ECP calculations, the dilution was not detected until the subsequent approach to criticality. The controlling bank was inserted and the RCS borated to the required concentration.

TRANS Surry 1 10/17/82 Routine startup One of two required boric acid flow paths to the core became unavailable and bit recirc was terminated clue to the temporary loss of boric acid transfer p!lll) 1-CH-P-2A. This is contrary to tech spec 3.2.C.4 and 3.3.A.3, and is reportable per tech spec 6.6.2.BC2). The motor trip appears to have been a random incident. The p!lll) breaker was reset and flow verified to the VCT and blender.

TRANS Surry 1 04/07/84 Routine SD Power level - 0%. On April 7, 1984, with Unit 1 at 5 x 10(-11) amperes on the intermediate range and inserting control rods shutdown, a reactor trip was initiated when source range NI-31 CEIIS No. R1) reinstated with indication above the high flux trip setpoint. Inmediately following the trip, all control and protection systems functioned as expected with the exception of source range NI-31, which failed high. Approx. 4.5 hrs following the reactor trip, with NI-31 failed high, source range Nl-32 was declared inoperable due to noise. Mith the unit at a hot shutdown condition, source range indication was unavailable for about 4 hrs. Appropriate abnormal procedures were implemented to insure posit.ive reactivity was not added to the core. The preaq> to NI-31 was replaced and source range indication was established. Prior to the start-up, the source range detector for NI-32 was replaced and the channel returned to service *

• A-81

p. 2 LER DATA BASE - TRANS 08/27/93 PHASE 2 CATEGORY PLANT NAME EVENT DATE INITIAL PLANT CONDITION RECOVERY TIME TRANS Surry 1 06/19/84 Routine startup Power level - 010%. On June 19, 1984, with the unit just Less than 10% power, a reactor trip resulted when 2 of 4 nuclear power channels, NI 44 and NI 41 exceeded 10% power with the turbine unlatched. A primary plant cooldown of approx ** 8 F/min and a primary dilution of 58 ppn contributed to the power increase. Following the trip, all control and protection systems functioned as expected. Main steam was isolated and the turbine stop valves were closed to Limit primary plant cooldown. Precautions will be added to station procedures (OP 1.4 and PT 15.1C) to prevent testing the steam driven auxiliary feedwater pulp near the P-10 setpoint without the main turbine being Latched.

TRANS Surry 1 01/27/85 Routine startup Power level - 010%. On 1/27/85, Unit 1 was critical with reactor power stable at 5X following a reactor trip on 1/26/85 (see LER 85-003-00). The steam~ valves were isolated earlier because of known but not specifically identified or quantified leakage. As the d ~ were unisolated, the resulting leakge led to a primary system ten.,erature decrease which caused reactor power to increase.

As power neared 10X, it was decided to latch the turbine to prevent a trip. Approx. 2 minutes after the turbine was Latched, the 4 turbine stop valves closed resulting in a reactor trip at 0748 hrs. One factor contributing to the trip was not sufficiently considering the effect of the steam Leakage on plant parameters. Another contributor to the event was that only one electro hydraulic (EH) pulp was available and running when the turbine was Latched and it did not satisfy the EH demands during the Latching operation. The steam dlllp Leakage was identified and isolated. The hunan performance evaluation system coordinator is investigating this event and will provide feedback to the operating staff to i~rove hunan performance in similar circ1.111Stances.

TRANS Surry 1 01/28/85 Startup Power Level - 015%. On 1/28/85, during a Unit 1 startup, a reactor trip occurred due.to a differential pressure anti-motoring turbine trip. Plant parameters did not indicate that a generator motoring condition existed. The trip occurred because the exhaust pressure sensing Line root valve in the anti-motoring instrunentation was isolated. It is believed that this valve, while shut, developed a small Leak dur~ng a previous period of power operation, allowing the sensing line to become pressurized. The line remained sufficiently pressurized during the shutdown period to cause the anti-motoring delta p setpoint to be exceeded as the turbine was being loaded. Station drawings and valve Line up checklists for the main steam system will be changed to reflect the correct position and function of the valves. (from chulowp.Ler)

TRANS Surry 1 02/07/86 Routine startup Power level - 015%. On 2/7/86, a Unit 1 startup was in progress. Feedwater control was in manual and the transition from bypass to main feed regulating valve (FRV) CEIIS FCV) was taking place when the 11C11 steam generator feed flow suddenly had a step increase above demand. When demand was decreased, the flow went to zero. llhen the 11 c11 FRVwas opened the second time, the flow again increased significantly.

The operator closed the FRV; however, he was unable to prevent a high level condition in the steam generator and at 2338 hrs, a feed pulp trip and turbine trip occurring initiated a reactor trip. The cause of this event was the failure to adjust the feedback cam on the 11c° FRV following maintenance, which prevented fine control of the valve. Due to a procedural inadequacy, the instrunent department was not notified to check the control adjustments of the valve following maintenance just prior to startup.

TRANS Surry 1 02/08/86 Routine startup Power level - 002X. on 2/8/86, at 2% power, during a Unit 1 startup, the operating main feedwater pulp tripped due to a high Level in *c* SG. This caused the AFW plllpS to auto start. The high SG Level occurred when the *c* main feedwater bypass valve failed to close on demand. This valve was found to have a dust accimJ.Jlation in the air pilot relay which blocked air to the valve operator. The blockage A-82

p. 3 LER DATA BASE - TRANS 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TJHE was removed and the valve closed. SG levels were returned to nonnal. Engineering will evaluate methods for controlling contamination in the instrunent air system.

TRANS Surry 1 09/16/86 CSD Power level - 100%. On Sept. 16, 1986, with Unit No. and Unit No. 2 at 100% power, a reactor protection system relay failed during the perfonnance of Unit 1 monthly surveillance testing. The relay failure resulted in a partial train 'B' engineered safety feature (ESF) actuation. On Sept. 20, 1986 with Unit 1 at hold shutdown and Unit 2 at 100% power the same reactor protection relay failed.

Again, a partial train 1 8 1 ESF actuation was initiated. The cause ~f both relay failures was determined to be a failure of the coil. The coil has been replaced, the relay re-installed and satisfactorily tested.

TRANS SUrry 1 07/18/89 100%, Unit 2 - CSD Power level - 100%. On July 18, 1989 with Unit 1 at 10DX power and Unit 2 in cold shutdown, following the manipulation of a service water (SW) valve to the Unit 2 bearing cooling heat exchangers, the Unit 1 charging J:lU1'> SW pul"8 became air bound and the pul"8 were declared inoperable. This is contrary to Technical Specification 3.3.A.7. The cause of this event has been attributed to air entering the SW lines that supply the charging puip SW pul"8. The affected pul"8 were vented and returned to service.

Aclclitional high point vents are being installed. A procedure for periodic venting has been developed and restoration procedures enhanced. In addition, a design change being i8')lemented to increase the size and nud>er of the SW supply li~s to the pul"8 has appropriate vents to facilitate removal of entrapped air. Engineering is also continuing their investigation of the event to determine if other actions are required.

TRANS Surry 1 07/23/89 100%, Unit 2 CSD Power level - 100%. on July 23, 1989 at 1747 hrs, with Unit 1 at 10DX power an Unit 2 at cold shutdown, following manipulation of a service water (SW) valve to the Unit 2 bearing cooling water heat exchangers, discharge pressures for the control roomtrelay room CCR/RR) air conditioning chillers' SW

~ and the Unit 1 and Unit 2 charging puJil SW FlU1')S decreased due to air binding in the J)U1')S. The PtJ1')S were declared inoperable. Also, the two operating CR/RR chillers tripped on high condenser discharge pressure. This is contrary to Technical Specification 3.3.A.7 and 3.23.C. The cause of the event has been attributed to air entering the SW lines that supply the puJilS. The affected~ were vented and returned to service and the CR/RR chillers were returned to service. Additional high point vents are being installed. A procedure for periodic venting has been developed and the abnonnal procedure for restoration has been enhanced. In addition, a design change being iq,lemented to increase the size and nunber of SW supply lines to the puq,s has provisions for appropriate vents to facilitate removal of entrapped air. Engineering is continuing their investigation of the event to determine if other actions are required.

TRANS Surry 2 12/19/82 Hot SD

~ile conducting the RCs integrity test (PT 11), a weld leak on the 'A' steam generator channel head drain piping at 2*Rf*159 was identified. Inmediate action was taken to return the unit to CSD. This event is reporable pursuant to Tech Spec 6.6.2.A.(3). The leakage was within the capability of the nonnal make up system. The cause of this event is believed to be poor fusion between successive passes in a small area of the weld. The unit was returned to CSD and the defective weld was repaired. Liquid penetrant examination of the final weld revealed no defects.

TRANS Surry 2 09/21/83 Hot SD With.Unit 2 at hot shutdown while conducting the RCS integrity test (PT 11) a weld leak on the NA" steam generator channel head drain piping at 2-RC-159 was identified. Actions were taken to return the Unit to cold shutdown. This event is contrary to tech spec 3.1.C.4 and is reportable per tech spec 6.6.2.B.(4). Leakage was within the capability of the normal make-up system. The exact cause has not A-83

p. 4 LER DATA BASE - TRANS 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT RECOVERY CATEGORY DATE CONDITION TIME been determined. An identical event occurred on 12/19/82 and the weld leak was attributed to inadequate fusion between successive weld passes. Only the portion of the ~eld determined to be defective was repaired. It is suspected that undetected defects remained and propagated to the surface. The weld was cOlli)letely ground out and rewelded and tested satisfactorily.

TRANS Surry 2 04/15/84 2% power Power level - 002%. At 1604 on 4/15/84 following a maintenance outage, Unit 2 was at 2% reactor power when a reactor trip occurred as a result of an intermediate range CNI-35) high flux trip. Plant parameters did not indicate a valid high flux trip. An electrician was checking for continuity across the switch for TV-SS-201A when an arc occurred resulting ina spike on vital bus 1 2which caused th*e spike on NI-35. The nultimeter was selected to resistance instead of voltage. (from chulowp.ler)

TRANS Surry 2 04/20/84 . Hot SO Power level - OX. On April 20, 1984 at 0216 hrs, with the unit at hot shutdown, a reactor trip occurred due to a high flux on source range NI-32. The reason for the trip was personnel error by a instrllllent technician while he was troubleshooting NI-32 which had a failed premq:>. The instrllllent technician was disciplined. A replacement premq:> is on order and will be installed when it arrives.

TRANS Surry 2 03/16/87 Hot SO Power level - OX. On March 16 1987 at 1704 hrs, Unit 2 was at intermediate shutdown with shutdown banks 'A' and 'B' withdrawn. During the performance of a periodic test of a steam flow transmitter CEIIS-FT) on Unit 2, a reactor trip"by turbine trip occurred, resulting in the insertion of the shutdown banks CEIIS-Ra>). This test trips permissive P-7 bistables CEIIS-33) (turbine first stage pressure) ad sinulates a signal of 10X power. Since the turbine was unlatched at the time, permissive P-7 CEIIS*JC) was activated, resulting in a reactor trip by turbine trip. The periodic test procedure requires the instrument technician to ensure that the turbine is latched if plant conditions are such that the reactor trip breakers CRTB'S) are closed and reactor power is less than 10X. The technician believed that the RTB's were open when in fact, they had been closed earlier in the day. The technician continued with the proceudre, and tripped the P-7 bistables, resuting in the activation of P-7 and the ensuing reactor trip by turbine trip. The technicians have been re-instructed to *obtain the status of. plant conditions from the shift supervisor.

TRANS Surry 2 09/10/88 Refueling outage Power level - 004%. On Sept. 10, 1988 at 0158 hrs, with the unit 2 reactor at 4X power, during a shutdown for a refueling outage, a reactor trip by turbine trip occurred. The event occurred while oeprators were attepting to maintain the turbine at synchronous speed, with the generator output breakers open. \lhen the valve position Limiter was raised, per the procedure, a unexpectedly rapid opening of the turbine governor valves and a rapid increase in turbine first stage pressure occurred, resulting in a turbine trip/reactor trip. Operators followed appropriate plant procedures and quickly stabilized the plant following the trip. The cause of the event has been attributed to a coabination of an inadequate procedure, a faulty valve position limit indication, and an unexpectedly fast valve position limiter setting response. The controlling procedure used during the event will be revised to ensure that the turbine control system is placed in the configuration intended. Testing will be performed on the electro hydraulic control (EHC) system, which will determine if any additional actions will be required.

TRANS Surry 2 09/16/89 Subcritical Power level - 0%. On Sept. 26, 1989 at 1228 hrs with Unit 2 subcritical, during a reactor startup, a manual reactor trip was initiated when it was determined that i~roper bank overlap existed between the

'A' and 1 8' control rod banks. The reactor trip was initiated to insert all control rods and to reset the control rod step counters to zero. A four hour non-emergency report was made to the Nuclear A-84

p. 5 LER DATA BASE - TRANS 08/27/93 PHASE 2 PLANT NAME EVENT INITIAL PLANT *;Eeo\/Etf ,

CATEGORY DATE CONDITION TIME Regulatory Comnission per 10CFR50.72. Troubleshooting did not reveal the cause of the illf)roper bank overlap. During the subsequent reactor startup, no problems were encountered with control rod bank overlap.

TRANS Surry 2 09/18/89 14% power Power level - 14%. on Sept. 18, 1989, at 1042 hrs, with Unit 2 reactor at 14% power and the turbine at 1800 rpm under no load conditions, a reactor trip signal was generated. A generator backup differential lockout relay 86 Bu tripped the turbine, and since reactor power was greater than 10%, the turbine trip initiated a reactor trip. Operators performed the appropriate plant procedures and quickly stabilized the plant following the trip. The 86 bu generator backup lockout relay trip was caused by the spurious actuation of the generator backup illf)edance relay CKD-41). The exact cause of the spurious actuation of the relay could not be determined, however faults were discovered in the relay. The faulted KD-41 relay was replaced and appropriate testing was performed. The generator startup procedure has been revised to ensure that reactor power is less than 10X prior to closing the exciter field breaker. A four hour non-emergency report was made to the Nuclear Regulatory Carmission in accordance with 10CFRS0.72.

A-85

APPENDIX B Review of U.S. Nuclear Regulatory Commission (NRC)

Information Notices, Generic Letters, Bulletins and Circulars B-1 NUREG/CR-6144

Appendix B Review of U.S. Nuclear Regulatory Commission (NRC)

Information Notices, Generic Letters, Bulletins and Circulars B.1 Summary of Findings

£m.

B-3 B.2 Review of NRC Information Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-4 B.3 Review of Generic Letters, IE Bulletins and IE Circulars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-11 NUREG/CR-6144 B-2

• Appendix B: Review of U.S. Nuclear Regulatory Commission (NRC)

Information Notices, Generic Letters, Bulletins and Circulars B.1 - Summacy of Findina:s Potential Degradation of Systems that Can Be Used for Accident Mitigation

1. Due to the activities in an outage, transient material and debris may be inside the containment. They may clog up the suctions from the containment sump in a LOCA The operability of the low head injection system, inside containment recirculation system, and outside containment recirculation system will be affected. (IN 88-22) Use the June 16, 1988 event as failure data for recirculation pumps. (IN 89-77)

2. During startup, when the power is above 10%, the intermediate power level(25%) trip will be blocked.

If the reactor power is lowered below 10%, and two of the four bistable switches fails to reset, then the reactor will not trip until 109%. This applies to both power range and intermediate range channels. Tech.

Spec. allows one channel to be taken out of service. (IN 86-105)

3. Common mode failure of four normally closed motor operated valves, that control the service water flow to the recirculation spray heat exchangers, to open.(IN 83-46)

Potential Initiating Events

1. Inadvertent lifting of fuel assembly while lifting the upper internal, February 26, 1986 and Indian Point Oct.

90 (NSAC-129, IN88-92,IN 86-58) Damage to fuel assembly during refueling (IEC 80-13).

2. Inadvertent withdrawal of control rod. The events at Vermont Yankee on November 7, 1973 and Millstone 1 on November 12, 1976 can be used as a data.(IN 88-21)

3. Pressurizer surge line movement and deformation due to thermal stratification (IEB 88-11)

B-3 NUREG/CR-6144

B.2 Review of NRC Information Notices:

90-19: Potential Loss of Effective Volume for Containment Recirculation Spray at PWR Facilities Entrapment of containment spray water in the refueling canal may lead to insufficient water returned to the sump, and inadequate net positive suction head to the containment spray pumps and low head safety injection pumps. This may happen if the refueling canal drain valve is closed.

Resolution: The RWSTs of both units are cross connected, and the amount of water that can be heldup in the refueling canal is only a small fraction of the water in a RWST.

89-77: Debris in Containment Emergency Sumps and Incorrect Screen Configurations June 16,1988, Surry. July 8, 1989, Trojan. Diablo Canyon.

88-28: Potential for Loss of Post-LOCA Recirculation Capability due to Insulation Debris Blockage March 14, 1988, Susquehanna. (It appears that any recirculation will be not likely during an outage. Due to the activities going on, it is not likely to keep the floor inside the containment clean.)

Resolution: The concern regarding the ability to use recirculation while the reactor is shutdown due to the potential problem of transient materiai debris due to the activities during shutdown need to be modelled. Surry's low pressure injection/recirculation system does not have heat exchanger for heat removal. Therefore, long term heat removal may depend on containment spray/recirculation.

90-06: Potential for Loss of Shutdown Cooling While at Low Reactor Coolant Level July 18, 1989, Comanche Peak. Loss of the invertor supplying power to the controller for the RHR heat exchanger flow control valve (FCV) caused the FCV to open to the fully open position. The sudden increased flow caused vortexing at the RHR suction.

Resolution: Use it as a loss of RHR event. It occurred prior to initial criticality. Therefore, it is not used to estimate the frequency of loss of RHR.

90-05: Inter-system Discharge of Reactor Coolant December 1, 1989, Braidwood, 68000 gallon. Stuck open RHRS relief valve, and inability of operators to identify the leak(lack of EOP) caused the incident to last more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> before the condition of the plant is stabilized.

Resolution: Use it as a loss of RHR event with RCS solid while drawing a bubble in POS 12.

89-73: Potential overpressurization of Low Pressure Systems September 5, 1989, McGuire Unit 2. Containment spray system(design pressure 220psig) was overpressurized by 450 psig RCS pressure during functional test of suction valve from the sump. 2200 gallons of coolant was lost. In adequate test procedure.

Resolution: Surry's RHR system does not take suction from the sump. Neither does the containment spray system. The two recirculation systems do, however, they do not take suction from RWST. The low head injection system injects into all cold and hot legs, takes suction from the RWST and the containment sump, and does not take suction from the RCS. Therefore, this scenario does not apply to Surry. The injection lines are shared between the high head injection system and low head injection system. Normally the LHSI is isolated from charging NUREG/CR-6144 B-4

by one check valve and two closed MOVs. Upon spurious SI in shutdown condition, if the check valve fails open, the LHSI may be overpressurized. LHSI flow path will be open with the normally operating charging pump injecting to it and the RCS. Similar scenario may occur at power. We need to review test procedures for high head injection system, low head injection system and RHRS to identify possible scenarios that may lead to an interfacing systems LOCA This should be considered as a special initiator.

89-41: Operator Response to Pressurization of Low-Pressure Interfacing System March 9, 1989, Votgle. Leakage through inboard isolation valve of the RHR system cause the RHR system pressure to stay high after taken out of service. Operators opened the suction valves from the RWST to relieve the pressure.

Resolution: This can be used as a data in interfacing LOCA analysis. Surry's RHR system does not take suction from RWST.

89-71: Diversion of the Residual Heat Removal Pump Seal Cooling Water Flow during Recirculation Operation Following a Loss-of-Coolant Accident Haddam Neck PRA During normal operation, CCW system provides cooling to the RHR heat exchangers and pump seal coolers. During a LOCA condition, CCW is isolated and service water is used to provide cooling to the RHR components. A single failure of one of tile service water motor-operated valves to open following a LOCA would result in only one branch of service water being available to provide cooling to both RHR heat exchangers and the seal water coolers.

Resolution: A review of ccw and sw operations at Surry showed that the CCW to the RHR heat exchanger will be isolated on a safety injection signal. However, RHR is not used for safety injection.

The low head injection pumps at Surry are self-cooled. Loss of CCW and SW are considered in support system failures.

89-67: Loss of Residual Heat Removal Caused by Accumulator Nitrogen Injection ,.

May 20, 1989, Salem 1, cold shutdown. Full flow test of accumulator check valve caused 1800 cubic feet of nitrogen to enter the RCS. Both RHR pumps were nitrogen bound. Operators had difficulty in locating the drain and vent valves.

Resolution: Use it as a loss of RHR data 88-23: Potential for Gas Binding of High-Pressure Safety Injection Pumps During a Loss-of-Coolant Accident February 26, 1988, Farley 1. Hydrogen from VCT may accumulate in the high point in the charging pump suction (pipe segment between the charging pump suction and the LHSI discharge).

Resolution: Need to get isometrics for LHSI, HHSI, RHR and RCS.

May 13, 1988, South Texas. October 12, 1988, Surry. Hydrogen from the volume control tank or air dissolved in RWST water may be released to ECCS piping between RWST and HPSI.

Resolution: Need to get isometrics for LHSI, HHSI, RHR and RCS.

October 30, 1989, Trojan nuclear plant. Both high head injection pump may be inoperable if a safety injection signal occurs while the manual bypass" valve around the motor operated

• VCT outlet isolation valves is opened per test procedure.

B-5 NUREG/CR-6144

Resolution: At Surry, the seal water go to the charging pump suction directly without going to the VCT..

It is connected to the VCT only through a relief valve RV1362B that allows relief into the*

VCT.

87-57: Loss of Emergency Boration Capability due to Nitrogen Gas Intrusion May 28, 1987, Turkey Point Unit 4. Nitrogen entered the boric acid system through a failed boric acid transfer pump mechanical seal. The seal is provided with an accumulator tank partially filled with demineralized water. The accumulator is given a 40-psi nitrogen overpressure to preclude leakage of the boric acid across the seal faces. As demineralized water entered the boric acid system through the failed seal, additional nitrogen was automatically supplied to the accumulator to maintain the pressure. The falling water level then allowed the nitrogen cover gas to enter the boric acid system through the failed seal.

Resolution: A failure mode of boric acid transfer pump 82-19: Loss of High Head Safety Injection Emergency Boration and Reactor Coolant Makeup Capability February 12, 1982, McGuire unit 1. Hydrogen from the positive displacement pump suction dampener entered the common suction of the charging system, causing both centrifugal charging pumps and the PDP to be inoperable.

Resolution: A CCF of charging pumps. Surry does not have a positive displacement charging pump.

83-49 and 82-32: Sampling and Prevention of Intrusion of Organic Chemicals into Reactor Coolant System February 13, 1983, Hatch. April 24, 1982 Hatch Unit 1. May 5, 1983, LaSalle. (Can similar events occur at a PWR leading to degraded core heat removal or reactivity accident?)

Resolution: A systematic way of identifying such scenarios is needed, otherwise, these events can be used as data for the scenarios. The Lasalle event is considered also possible for a PWR, with the condensate storage tank replaced by primary grade water storage tank. However, the event does not seem to have any significant safety impact. It may require cleanup of the RCS, but is not an initiating event.

89-54: Potential Overpressurization of the Component Cooling Water System May 15, 1989, Surry. A design deficiency in the CCW system relief valve was reported. The capacity of the relief valve is not sufficient to relieve a tube rupture of the thermal barrier beat exchanger. Additional relieve valves installed.

Resolution: In design change package 89-008, the CCW inlet check valve to the thermal barrier was replaced by two check valves in series. The thermal barrier outlet is isolated by a trip valve upon high flow.

89-32: Surveillance Testing of Low-Temperature Over-Pressurization Systems Beaver Valley, Turkey Point, Shearon Harris. Stroke time requirement in inservice testing (15 sec) for PORV was not consistent with the safety analysis (2 sec).

Resolution: LTOP bas been identified before and will be considered.

88-92: Potential for Spent Fuel Pool Draindown October 2, 1988, Surry Unit 1. Potential drain down of spent fuel pool to 13 inch above t o p .

of fuel assembly.

NUREG/CR-6144 B-6

• Resolution: Design change package ??? installed new cavity seal in the Oct. 90 refueling outage. NSAC-129 identify events involving drop of one fuel assembly, inadvertent lifting of a fuel assembly, and misposition of 4 fuel assemblies into 4 control cells with the control rods withdrawn.

84-93: Potential for Loss of Water from the Refueling Cavity August 21, 1984, Haddam Neck.

Resolution: Beyond the scope except for flooding Resolution: Consider it for internal flooding analysis 88-87: Pump Wear and Foreign Objects in Plant Piping Systems May 16, 1988 Surry Unit 2, auxiliary feedwater system. June 6, 1988, Surry Units 1 and 2, recirculation spray pumps.

Resolution: Get information on improvement in design or operation. Include these failure modes.

88-36: Possible Sudden Loss of RCS Inventory During Low Coolant Level Operation Diablo Canyon. Westinghouse cold opening scenario 87-23: Loss of Decay Heat Removal During Low Reactor Coolant level Operation Diablo Canyon.

86-101: Loss of Decay Heat Removal due to Loss of Fluid Levels in Reactor Coolant System Resolution: Already identified.

88-21: Inadvertent Criticality Events at Oskarshamn and at U.S. Nuclear Power Plants July 30, 1987, Oskarshamn. November 7, 1973, Vermont Yankee. November 12, 1976.

Inadvertent withdrawal of a control rod that is adjacent to a fully withdrawn control rod leads to criticality, and the scram system shutdown the reactor.

Resolution: This is a reactivity accident that should be modelled.

88-17: Summary of Responses to NRC Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants" December 9, 1986, Surry Unit 2. 1987, Trojan. December 10, 1987, LaSalle Unit 1. Pipe thinning in feedwater line.

86-106: Feedwater Line Break December 9. 1986, Surry Unit 2.

Resolution: Find information on improvement in surveillance of feedwater lines and determine if the scenario need to be modelled..

87-59: Potential RHR Pump Loss Potential for dead heading one of two RHR pumps in systems that have a common miniflow recirculation line serving both pumps, during a small LOCA. Capacity of miniflow recirculation line for single pump operation.

Resolution: NRC or Westinghouse should have resolved this. Get resolution from NRC.

87-46: Unidentified Loss of Reactor Coolant June 21, 1987, North Anna Unit 1, cold shutdown. 17,000 gallons of coolant was lost and voids formed in the vessel head and SG tubes. Misleading pressurizer level indication.

B-7 NUREG/CR-6144

Resolution: This is a LOCA event that can be used as data. Misleading level indication need to be

• modelled.

• 84-55: Seal Table Leaks at PWRs January 20 ,1984, Zion Unit 1. April 19, 1984, Sequoyah.

Resolution: Minor leaks during power operation. We will look into failure of temporary seals used during refueling.

87-40: Backseating Valves Routinely to Prevent Packing leakage June 12, 1987, Surry Unit 1. A low flow reactor trip occurred due to the failure of the stem of a hot leg loop stop valve. Similar event occurred March 7, 1974.

Resolution: Surry does not use electrical backseating of the loop stop valves any more. Use it as data for power operation.

86-105: Potential for Loss of Reactor Trip Capability at Intermediate Power Levels (If a reactivity insertion occurs above 10% power, no scram will occur until 109% power)(If a reactivity insertion occurs below 10% a single failure of a bistable switch to reset may lead to failure of scram system.)

Resolution: We need to model it.

86-79: Degradation or Loss of Changing Systems at PWR Nuclear power Plants Using Swing-Pump Designs June 26, 1985, Surry Unit 1. Pump A was down for maintenance, and when pump B was racked out, an interlock caused the running pump C (swing pump) to trip.

Resolution: This will be modeled. No additional action needed.

86-63: Loss of Safety injection Capability December 28, 1984, Indian Point 2. Two leaky valves in the discharge of the boron injection tank enabled highly concentrated boric acid to flow to the low pressure discharge line (SI pump suction) and to precipitate in the pumps, which were not heat traced. Degassing of the nitrogen cover gas dissolved in the boric acid solution is believed to be one of the likely sources of gas found in the pumps.

Resolution: Surry does not have boron injection tank.

86-58: Dropped Fuel Assembly February 26, 1986, Haddam Neck. A spent fuel assembly was inadvertently lifted from the core when the upper core support structure was removed from the reactor vessel. The assembly impacted the core barrel and was knocked off.

Resolution: . Use it as well as the recent Indian Point incident as data for failure of one fuel assembly.

85-12: Recent Fuel Handling Events Resolution: We need to model it along with events in NSAC-129.

86-01: Failure of Main Feedwater Check Valves Causes Loss of Feedwater System Integrity And Water-hammer Damage November 21, 1985, San Onofre Unit 1.

Resolution: We need to model it.

80-01: Fuel Handling Events NUREG/CR-6144 B-8

December 11, 1979, inadvertent raising of spent fuel assembly, December 17, 1979, a new fuel assembly was dropped in the fuel pool. Pilgrim.

Resolution: Combine with NSAC-129.

84-70: Reliance on Water Level Instrumentation with a Common Reference Leg All the wide range level instruments have a common reference leg that developed a leak. The leak made the operators to maintain an apparent level while the actual level decreased, thereby causing the pressurizer to drain and a bubble to enter the top of the head.

Resolution: We need to find out about the design of level instrumentation at Surry. Is this a LOCA?

84-42: Equipment Availability for Conditions During Outages Not Covered by Technical Specifications January 8, 1984, Palisades. Loss of offsite power with one diesel generator 2 down for maintenance and the service water pump that is powered from diesel generator 1 was also down for maintenance. DG 1 was tripped 50 minutes later upon overheating.

Resolution: Already identified.

83-46: Common-Mode Valve Failures Degrade Surry's Recirculation Spray Subsystem February 9, 1983, Surry. Four normally closed MOVs that permit service water flow to the recirculation spray heat exchangers failed to open. Possible causes are corrosion, marine growth, infrequent testing, and low torque switch setting.

Resolution: A common mode failure. Check if 1150 models it.

83-41: Actuation of Fire Suppression System Causing Inoperability of Safety-Related Equipment May 28, 1981, Surry unit 2. and other events. Discharge from the foam distributor system installed in the main (reserve) diesel fuel oil tank caused 4000 gallons of water be introduced and widely distributed in the diesel fuel system before a routine periodic test disclosed the presence of water.

Resolution: Get information on fixes implemented to determine if it need to be modelled.

82-45: PWR Low Temperature Overpressurization Protection August 1976, Turkey Point Unit 4. Possible causes of inoperable PORVs:

1. Operation with both PORVs isolated (block valves closed) because of known PORV leakage.

2. Operator error during maintenance.

3. Isolation and venting of instrument air to the PORV actuators during integrated leak rate testing.

4. Low nitrogen(backup accumulator) pressure to PORV actuators.

Resolution: LTOP will be analyzed.

82-17: Overpressurization of Reactor Coolant System November 28, 29, 1981, Turkey Point 4. A pressure spike caused by starting a reactor coolant pump caused automatic isolation of the RHR suction valves. OMS failed to operate because a pressure transmitter isolation valve was found closed, the summator in the supposedly operable electrical circuitry failed, and the redundant OMS circuit was out of service.

Resolution: Already identified.

B-9 NUREG/CR-6144

82-28: Hydrogen Explosion While Grinding in the Vicinity of Drained And Open Reactor Coolant

• System .

April 20, 1982, Arkansas nuclear One Unit 1. A craftsman was grinding the HPI pipe line in preparation for welding. A hydrogen explosion occurred and blew the craftsman away by about 3 feet.

Resolution: Consider it in fire analysis.

81-10: Inadvertent Containment Spray due to Personnel Error February 11, 1981, Sequoyah.

Resolution: Already identified.

81-09: Degradation of Residual Heat Removal

• March 5, 1981, Beaver Valley, midloop operation.

Resolution: Already identified.

81-04: Cracking in Main Steam Lines February 23, 1981, Surry Unit 1. A lengthy crack indication in the I.D. counterbore area of a weldment on the in-line "T' fitting which connects the vertical run of 30-inch piping to the safety relief valve header and 30-inch main steam line of steam generator A Resolution: Use it in LOCA frequency assessment.

80-44: Actuation of ECCS in the Recirculation Mode While in Hot Shutdown December 5, 1980, Davis Besse. Inadvertent actuation caused a flow path to the RCS via the borated water storage tank and the DHR piping. No BWSTwater was pumped into the RCS.

Rather, during the valve transition time of about 1.5 minutes, approximately 15,000 gallons of borated water was drained from the BWST to the containment emergency sump.

Resolution: RHR system at Surry is independent of safety injection system and does not take suction from RWST or containment sump.

80-20: Loss of Decay Heat Removal Capability at Davis-Besse unit While in a Refueling Mode April 19, 1980, Davis-Besse. Loss of power to non-essential 480 v bus caused recirculation mode actuation, and loss of RHR suction. (extensive maintenance activities)

Resolution: Already identified in RHR data base.

80-34: Boron Dilution of Reactor Coolant During Steam Generator Decontamination May 29, 1980, Trojan. July 5, 1980, San Onofre 1, high pressure demineralizedflushing water leaked by a dislodged nozzle seal and the resulting reactivity addition exceeded the tech. specs.

Resolution: Already included in reactivity accident.

79-04: Degradation of Engineered Safety Features Arkansas Nuclear One, units 1 and 2. MSIV closure at unit 1 lead to loss of ac power at unit 2 which was in hot standby.

Resolution: A cause for loss of offsite power.

NUREG/CR-6144 B-10

Review of Generic Letters, IE Bulletins & IE Circulars Conclusions GL -- generic letter IEB -- IE Bulletin IEC -- IE Circular

1) Loss of RHR. Some special concerns are: a) in mid.loop operation, if boiling begins in the RCS and the cold leg is open (e.g. maintenance on the pumps), the increased pressure will force water out of the opening, thus further decreasing time available for recovery (GL 87-12, 88-17; Diablo Canyon April 10, 1987); air ingestion will cause erroneous level indication (it should be noted that in the Diablo Canyon event, RHR pumps were able to handle a few percent air ingestion). c) maintenance activities may cause loss of redundancy during shutdown (IEB 80-12, Davis Besse, April 19, 1980). d) service water problems may cause loss of RHR (IEC 81-11, GL 89-13; Brunswick, a BWR, Dec 8, 1980 -- SW train A in maintenance, B not aligned because a expected to be repaired before boiling reached, A train repair took too long).

2) Steam void generation during depressurization. Hot metal out of the main flow path. Pressurizer level increases suddenly. Steam can interfere with heat removal. (IEC 81-10, 80-15; Crystal River 3,'April 21, 1981, during cold shutdown; McGuire 1, June 1981, during heatup; also St. Lucie 1, June 11, 1980 during full power -- loss of CCW flow to RCPs causes reactor trip -- cooldown for a few hours until rise in press. level. Problems lead to eventual use of LPSI)

3) Condensate booster pumps can be used for secondary, but need to depressurize first (GL 88-20)

4) Steam binding of AFW pumps. Due to leakage past isolation valves of hot water from the MFW. IEB 85-01, GL 88-03; Crystal River 3 1982 & 1983; Robinson 2, 1981 through 1983; D. C. Cook, 1981; McGuire 2, 1984; Catawba 1, Nov. 1984)

5) Water hammer can disable important safety systems. (GL 86-07; San Onofre l, Nov. 21, 1985, 60%

power, loss of all ac power for 4 min followed by a severe water hammer which caused a steam leak, damage to plant equipment and loss of feedwater for 3 min; caused by check valve failure)

6) Overfill of steam generators, overcooling, overheating-- obvious concerns (GL 81-28, 81-16, 83-37)

7) Low temperatureoverpressurization. (GL 88-11; the criticallimits and the operatingwindow had been changed recently-- to make it more difficult).

8) Boron dilution events during hot standby (only 15 mins available btw. an alarm and loss of shutdown margin)

9) Control rod withdrawal with only one RCP operating in hot standby may violate DNBR (for W plants

-- FSAR says 2 RCPs operating in hot standby, but TS allows only one -- OK for most accidents except uncontrolled rod withdrawal; GL 86-13)

10) Sump screen blockage. Obvious concern, maybe more so in shutdown. Plants most vulnerable are the ones with small debris screen area ( < 100 sq. ft), high ECCS recirc. pump requirements(> 8000 gpm)

• and small NPSH margins(< 1-2 ft of water) (GL 85-22)

B-11 NUREG/CR-6144

11) Control of heavy loads. Suny did a load drop analysis to satisfy requirements (GL 85-11).

12) Loss of shutd~wn margin during refueling operations. Baltimore Gas & Electric presented this analysis for its Calvert Cliffs units, in March of 1987. It shows that at some intermediate positions during refueling, and assuming clustering of higher enrichment fresh fuel for the extended cycle, criticality can occur. (GL 89-03).

13) Pressurizer surge line movement and deformation due to thermal stratification. This occurs during heatup, cooldown and also steady state, due to stratification of hot water flowing from the pressurizer and the layer of "cold" water from the hot leg in the pressurizer surge line (IEB 88-11; Trojan observed unexpected movement of PSL at each refueling since 1982, with the "latest" one actually touching the restraints and causing plastic deformation; Beaver Valley 2 also noticed the PSL movement and the snubber movement during power ascension).

14) Possible loss of pumps (e.g. RHR pumps) in miniflow conditions. The stronger pump will cause deadheadiilg of the weaker pump (2 pumps in parallel with a common miniflow line). The capacity of line may not be enough to support even one pump miniflow (IEB 88-04)

15) Damage to fuel assemblies during refueling. Observed extensive damage to grid straps in W fuel assemblies, caused by hitting diagonally neighboring assembly during insertion (IEC 80-13, Salem 1, LER 79-44).

NUREG/CR-6144 B-12

• Generic Letters of Interest to Surry Shutdown Study 81-07: Control of Heavy Loads, also GL 85-11. The response should include use of electrical interlocks or mechanical stops, single failure proof cranes and load drop analysis. The last one was done at Surry, and the areas analyzed were the spent fuel pool area and the containment building. Boron dilution events during hot standby. 15 min available between the first alarm and loss of all shutdown margin.

81-16: Overfilling of steam generators 81-22: eves leak at H.B. Robinson plant -- inadvertent operation of charging pumps. 6000 gal in letdown train of eves. Inconsistency between tech specs and safety analysis (in 3 loop W plants). FSAR assumes 2 RePs in operation in Mode 3 (hot standby). Tech specs say one is OK. With only one pump, an uncontrolled withdrawal of the control bank from the subcritical condition may cause violation of DNBR criteria.

86-07: Water hammer and loss of power at San Onofre. This occurred at 60% power. All 5 check valves were disabled.

85-22: Post LOeA sump screen blockage. The plants that are most vulnerable are the ones with: - small debris screen area ( < 100 ft**2) - high Eees recirculation pumping requirements (>8,000 gpm) -

small NPSH margins ( < 1-2 ft of water).

85-16: High boron concentration. At Indian Point 2, all 3 SI pumps were frozen with crystallized H3B03.

Boron injection tank(BIT) has a high concentration of boric acid (in case of a steam line break).

Surry 1 & 2 have requested to remove the BIT or reduce the concentration to 2,000 ppm. The request was granted.

85-13: Davis Besse loss of main and auxiliary feedwater 85-09: Generic W modifications for reactor trip system. Require at power testing of undervoltage and shunt trip attachments.

85-07: Inadvertent boron dilution events. 110% pressure in the RHR. Instrumentation is not required.

85-02: SGTR prevention. TV camera for loose parts and foreign objects -- after any secondary side modifications and eddy current testing.

89-21: USis and GSis:

water hammer SG tube integrity A-31 RHR shutdown requirements A-49 pressurized thermal shock A-47 control systems: overftll protection, overcooling, overheating transients. Surry has 2 out of 3 logic, with one channel used both for control and protection. MFW isolated by closing the MFW isolation valves and tripping the MFW pumps.

System interactions -- flood, seismic, electrical reliability and operator actions 89-13: Service water system problems B-13 NUREG/eR-6144

88-17: Loss of decay heat removal. NUREG-1269 (report on Diablo Canyon event) identified many generic

• weaknesses.

NUREG/CR-6144 B-14

APPENDIX C SYSTEM FAULT TREES

• C-1 NUREG/CR-6144

APPENDIX C SYSTEM FAULT TREES PAGE C.1 Accumulator System C-3 C.2 Auxiliary Feedwater System .................................................. C-8 C.3 Charging Pump Cooling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-72 C.4 Component Cooling Water System ........................................... C-82 C.5 Compressed Air System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-104 C.6 Component Spray System C-113 C.7 Emergency Power System C-119 C.8 Emergency Switchgear Ventilation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-143 C.9 High Pressure Injection & Recirculation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-159 C.10 Low Pressure Injection & Recirculation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-193

• C.11 Primary Pressure Relief System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-235 C.12 Recirculation Spray Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-243 C.13 Residual Heat Removal System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-265 C.14 Service Water System .................................................... C-280 (The Fault Trees for the Service Water Components are included in the Fault Trees of those systems that depend on Service Water)

(See App. C.3, C.4, C.8 & C.12)

C.15 Steam Generator Recirculation and Transfer System C-281 C.16 Steam Generator Secondary Relief System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-293 C.17 Consequence Limiting Control System ........................................ C-305 C.18 Reactor Protection System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-308 C.19 Recirculation Mode Transfer System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-310 C.20 Safety Injection Actuation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-313 C-2

Appendix C.1 Accumulator System

• C-3

ACCUMULATORS (ACC)

(05)

INSlF FLOW INSUF FLOW INSUF Fl.C1N THRU P!PE SEGM:NT Tl-RU PIPE SEGMEtfl" THRU PIPE :6EGMENT PS120 PS121 . PS122 ACC4 ACCS ACC4 ACCS ACC6 PAGE 1, 2 & 3

ACCUMULATORS (ACC4)

(ACC)

NStf FLOW lflU Pf'£ SECIEl(I' PS120 PAGE 1, 2 & 3

ACCUMULATORS (ACC)

(ACCS)

NSlF FLOW TiflU PPE SEGI.ENT PS121 PAGE 1, 2 & 3

ACCUMULATORS (ACC)

(ACC6) tlSt.f" Fl.OW lfllJ Pf'E SEG1.£NT PS122 PAGE 1, 2 & 3

Appendix C.2 Auxiliary Feedwater System C-8

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFW-1)

(L)

.lJ"llf-CII..V-OC~.1111 NW-WV-PC-15 E PAGE 1 & 9

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFW-_.: 1)

(AFWS)

INSLF FLON THRU PIPE SEG PS87 &: PS88 0

..... INSUFFICIENT FLOW Tt-ROUGH PIPE INSUFFICIENT FLOW TffiOUGH PIPE 0 SEGl-,,ENT PSB7 SEGl-,,ENT PSBB INSUFFICIENT INSUFFICIENT FLOW Tl-ROUGH PPE FLOW THROUGH PIPE SEGMENT PSB3 SEGMENT PSB4 AFW-MOV-PG-151C AFW-MOV-PG-1510 AFW1.3

e AUXILIARY FEEDWATER TO f OF 3 SG (AFW-1)

(AFW13) n-PA.GE 1

AUXILIARY FEEDWATER TO 1* OF 3 SG (AFW-1)

(AFW14)

....0N Af!lfl

• PAGE 7

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFW-1)

(AFW15)

INSLF FLOW n~u PIPE SEG seo. PS81. & PS62 AfV/17 AFWIB AFVI-TNK-Vf-CST AFW-ACT-fA-PMP38 AFW:,_CCf -lK-STMBD 4KVIJ E1B

.Al"W-CKV-CC-4257?'

lo!.A-FW3B

>fVH.IDP-fS-FWJA. AFW-CKV-<JO--CV157 AFW-TCP-fS-fW2 AfW-CKV-00--0/142

P0S-R6 AFW-MDP-MA-FW3B POS-D6 AFW-MDP-MA-FW3B P0S-R10 .A.FW- MDP-:-MAOFW3B

• AUXILIARY FEEDWATER TO 1 OF 3 SG (AFW-1)

(AFW17)

INSUFFICIENT FLOW THROUGH PIPE SEGMENT PS81 FALUS IN PIPE FAlURE OF 120 V FALURE OF 4KV AC SEGMENT PS81 FTRN DC BUS 1A. BUS 1H JA AFW-TNK-VF-CST AFW-ACT-FA-PMPJA AFW-CCF.::_LK-STMBD EtA. 4KV1H INSUFFICIENT ST AlfD MAINTEN* NCB FLOW THRU PUMP ON APW MDP DUE TO BACKFLOW AFW-cKV-cc-,rn577 MA-Fl'i'3A BACKFLOW BACKFLO#

THROUGH MDP FW3B THROUGH TDP FW2 AFW-MDP-FS-FW3B AFW-CKV-00-C\1172 AFW-TDP-FS-FW2 AFW-CKV-OO-C\1142

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFW-1)

(AFW18)

AFW-TNK-W-CST AFW-CCf"-lK-STIJ8D APW-ClCV -CC-42577 MA-rw.:

AFW-ACT-FA-VL.VA .AFW-ldS-PG-1UB AfW-1,1DP-FS-fW3.'. AFW-CIN-OO-CV¥5>7 >fW-1JDP-FS-f1//3B AFW-CIN--00---0/172

TEST AND MAINTENANCE ON AFW MDP 3A n

I

....J

AUXILIARY FEEDWATER TO 1*0F 3 SG (AFW-1)

(AFW21) 0 00 MVI-N:f-'"A*"-111 AP\f-119-PO-SICI

.,..u

• PAGE 6

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFW'.:-1)

(AFW22)

INSUF STM FLOO THRU PIPE SEG PS95, PS96, PS97 INSUF STM FLOW INSUF STM FLC/,11 INSl..f" STM FLOW Tl-RU PIPE SEG THRU PIPE SEG THRU PIPE SEG PS95 PS96 PS97 AF JJ AFW-CKV-FT-CV182 AFW-XVM-PG-X\187 AFW-CKV-FT-CV178 AFW-XVM-f'G-XV120 AFW-CKV-FT-C.V176 AFW-XVM-PG-X\1158

, I

TEST AND MAINTENANCE ON AFW TRAIN A MOVS

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(L2) nI N

1119.f" na.

~%Glf"!

>l'NI /<IWl KW2 NWJ NWI ,.WJ PAGE I J

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW1)

(AFW1)

NW-OY-FT-Ci27 NV-IIO/-PO-IIF PAC( 1

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW2)

PAGE 9

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-:2)

(AFW3)

• PAC( 10

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW13A)

PAGE 2

AUXILIARY FEEDWATER TO 2

• OF 3 SG (AFW-2)

(AFW14A)

.an-co-oc-toot MW-ctN-n-t::toJ MW-w-rc-rcorn IFW-cl(V-FT-<Nllt PACE 8

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW15A)

AFW-rn<-VF-csr AFW-CCf-LK-STMBD*

AFW-CKV-CC-42077 UA-P'W2 AFW-ACT-FA-VLVA AF'lf-HS-PG-i9B AFW-MDP--1'S-FW3A AFW-a<Y-00-D./157 AFW-MCP-FS-FW:38 AFW-CKV-DO-D./172

TEST AND MAINTENANCE ON AFW TDP2 8

00 POS-R6

• AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW16A)

INSUfFICIENr

(:J,H THROUGH PIPE SEGMENT PS81 AFW17A AL~ (F 41N AC FALUR£ (F 120 V BUS 'lJ DC BUS 1l N'W-ACT-FA-PMPJB AFW-CCF-LK-STMBD

• AFW-TNK-VF--<:ST 4KV1J ElB TBS AND MAINTENAN ON MW lo!DP 3B

.AYW-CKV-CC---i2577 MA-FW3B AFW-1DP-FS-FW2 AFW-CKV---OO--<:V1~2 AFW-MCf'-FS-FWJA AFW-CK!l-00--0l'.57

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW17A)

FAit.URE CF 12<:N DC BUS \I>.

AFW-TNK-VF-<:ST AFW-ACT-fA-PMPJA AFW-CCF-lK-STMBO 8

0 4K\11H E\I>.

Al"W-CKV-CC-42~77

)U.-PW:!A

}FVI-TDP-FS-FW2 AFW-CKV-OO-CV1+2 AFW-MCP-fS-FWJB AFW-C'rW-OO-CVf72

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW21A) 8....

..,... ""' A.OW

~~-~

M'W-J.Cf-l'A-\1..W AN-WI-PO-ltO 1'F'IIW.

PAGE 7

AUXILIARY FEEDWATER TO 2 OF 3 SG (AFW-2)

(AFW22A) 8 N

INSUF STEAM FL<JN THRU PIPE INSJ.A' STEAM FLOW THRU PPE INSl,f S FLOW THRU PPE SEG SEG PS95 SEG PS96 PS97 AFW-CKV-FT-C\1182 AFW-YNM-PG-Xl/87 AFW-CKV-FT -CV178 AFW->NM-PG->N 120 AFW-CKV-FT-CV176 AFW-XVM-PG-Xl/158

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFW-3)

(L3)

NU fl.OW TIRJ PH 5m

.UW-CIV-CC-&TO&I PAGE I

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFW-3)

(AFW13B)

NN....f:JN-"-0/LJS AIW-cxi-lT~l.18 JSW-P'fl'-IC-ICONN U'ff-Cl'f-OC-Hlt PAC( I

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFW-3)

(AFW14B) 8 V,

£n-CKY-oc-eooit NW-CN-n-etUJ MW-W'~C-ICOtN IFW-tJi<<-FT-fYdl PAGE 7

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFW-3)

(AFW15B)

INSLF FLOW Tt-flU PIPE SEG seo. PS8t & PSe2 AFW 58 AFW17B AFW-TNK-VF-CST AFW-ACT-fA-PMP3B AF\V_:CCF -lK-STMBD 4KVIJ ElB TE

.AP'W-CKV-CC-12577 ldA-FW3B

• NVl-1JDP-FS-F\V3A AFW-CKV--00-CV157 AFW-TCP-fS-FW2 AF\V-CKV-OO-CV142

• AUXILIARY FEEDWATER (AFW17B) 1 OF 2 SG (AFW-3)

INSUFFICIENr FLOW THROUGH PIPE SEGMENT PS81 f AULTS IN PIPE FAILURE OF 120 V FALURE OF 4KV AC SEGMENT PS81 PrRN DC BUS 1A. BUS 1H 3A AFW-TNK-VF-csr AFW-ACT-FA-PMP3A AFW-CCF .;_LK-STMBD EtA. 4KV1H INSUFFICIENT T ST AND MAINTEN NCE FLOW THRU PUMP ON MW MDP 3A DUE ro BACKFLOW MW-CICV-CC-42577 MA-FW3A BACKFLOW BAO<FLOW THROUGH MOP FW3B THROUGH TDP FWZ AFW-MDP-FS-FW3B AFW-CKV-OO-C'/172 AFW-TDP-FS-FW2 AFW-CKV-OO-C'/142

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFW-3)

(AFW18A)

FAU.TS IN PPE SEGtJENT PSOO mp TRAIN AFW-TNK--VF-CST N'W-<:CF -LK-STl,Bl 8

00 TB T AND MAINTBNA CE ON AFW TDP2 APW-CICV-CC--42577

!U.-FW2 AFW21 INSUF STM FLOW TlflU PPE SEO PS95, PS96, PS97 AFVI-ACT-FA-VLVA 1'FW'J2 AFVI-MDP-FS-FWM AFW-O<V-OO-CV157 AfW-t.Cf'-fS-FWJB AFW-CIN--00--0/172

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFWS-1)

(LS POS 3-13) 0 INi\F Fl0'/1 TO MN I 50 FRIJ AT LfAST 1 AFW PU*

o*

!D AJ'W-XDB-FO-AOT UW-<XV-CC-27:188 UW-CJrY-cc-i1:iee J.PW-CICV-CC-.1!7M9 APW81~ APW8U AJ'W~LS APW-ll PAGE 1 & 9

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFWS-1)

(AFWS5)

PAD.DUI Df MIJ'f

,w1en:1

• PAGE 8

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFWS-1)

(AFWS13)

PACE 1

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFWS-1)

(AFWS14)

PAGE 7

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFWS-1)

(AFWS15)

INSlF FLOW TffiU PIPE SEG PSB1, & PS62 Al"W~17 AFW-TNK-VF-CST AFW-CCF-lK-sn.mo E18 TB T AlfD MAINTEIIA CE ON .AFW MDP 3B AP'W-CKY-CC-4Z577 MA-PW3D

>FW-IJOP-FS-FWJA AFW-CK\I--OO--CV157 AFW-CKV-00-CV'i.f.2

AUXILIARY FEEDWATER TO 1 OF 3 SG (AFWS-1)

(AFWS17)

INSUFFICIENf FLOW THROUGH PPE SEGMENf PS81 FALUS IN PIPE FAILURE OF 120 V FALURE OF 4KV AC SEGMENf PS81 PTRN DC BUS tA. BUS 1H JA AFW-TNK-VF-CST AFW-CCF.~LK-STMBD 4KV1H INSUFFICIENf ST Alm MAINTEN NCll FLOW THRU PUMP ON AFW MDP DUE TO BACKFLOW Al"W-CKV -cc-Hm77

.AJ' S26 MA-F'W3A BACKFLOW BACKFLOW THROUGH MOP FW3B THROUGH TOP FW2 PAGE 3 & 4

-AFW-MOP-FS-FW38 AFW-CKV-OO-CV172 AFW-CKV-OO-CV142

AUXILIARY FEEDW ATER POS 3-13 (AJFW4-1)

MOV FW151A MOV FW15L\ MOV PW151A CCF 2/2 FAILURE OF AFW FW"-JGLA PLUGGED PAILS TO OPEN MOV 151A,B MCC-1H1-2 MOV IN MAINTENANCE EH2

.AFW-MOV-PG-151A AFW-MOV-FT-151A .AFW-MOV-CC-151

AUXILIARY FEEDWATER POS 3-13 (AFW42)

IIOT n1e11 .,... nm, Pll>>U OP tll1' ft.UGGJD FAQ.I TO OID' .lei 1101 U nvu Allf-i,o'{-P0-11111 !-H-IIOV-PT-1811

AUXILIA*RY FEEDWATER POS 3-13 (AFW43) 1i1ov n1e10 ft.UQOID WCN "JOIO Ud.l TO DnJI Pd.VRI OP tn AO aol U1.

UVlll MW-WOV-PT-MUC

AUXILIARY FEEDWATER POS 3-13 (AFW44)

(')

J:..

00 ll<W "J&U) tA&Ulla cw t n FAD.I 10 OFD AC IOI U uvu AIW-IIOY-PO-IOID .UI-MOV-PT-IOlb

AUXILIARY FEEDWATER - POS 3-13 (AFW45) ltO'W"ffJDll 11ar nnm FAQ.I TO WU

• Aa.111.S OP tn ft.VGOIO AC IOI IX U:VLD

.AlW*IIOY-PQ*IOII AP11*11<1V-n*IOII AP1l*IIOY-<<*IOI

AUXILIARY FEEDWATER - POS 3-13 (AFW46)

IIO'i ,o PAaJJU Of' tn

,.a., "J&U' Of'D AC IUI U APW-IIOV-P0-11111' AH-IIOV-n-llllP AH---<C-1111 L

• AUXILIARY FEEDWATER TO 1 OF 2 SG (AFWS-3)

(LS3)

AFW-XHE-FO-ACT INSUF FLOW THRU PIPE SEG PS85 & PS86 J..PW-CKV-CC-27~88 AFW--O<I/-FT-C\158 AFW--O<Y-FT--0/89 .APW -CKV-CC-27:)88 AFWS6 INSUFF K:IENT INSUFrlCENT .

(JIJ THROUGH PIPE L<JN TIROOGH PIPE SEGMENT PS87 SEG~ENT PS88 INSUFFK:IENT FALURES Of INSUFFICENT FAILURES OF LON THROLGH PIFE MOV LOW T tftOUGH P FE l.lav SEGM[NT PS63 FW151C S[GfJENT PS84 FW1510 AFV/5130 AFV/4J APNSl4B AFW44 PAGE 1

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFWS-3)

(AFWS6)

~N FALJ..ll£ OF rALUl[ CF

,ff.. r:t'11

--r-H'OSMB NW4t IFWSUII HW'1

• PAGE 8

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFWS-3)

(AFWS13B)

PAC[ 1

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFWS-3)

(AFWS14B)

PAGE 7

• AUXILIARY FEEDWATER TO 1 OF 2 SG (AFWS-3)

(AFWS15B)

INSlF Fl.OW THlU PIPE SEG PSB1. & PS82 AFW IOB AFW917B ALURE or 4KV AC BUS 1J AFW-TNK-Vf-<:ST AFW-CCF--lK-STMBD 4KVIJ E1B 1'!A-PW3B B.I.CKR..0\11 HROUGH TOP FW2 AFW-f..lOP-FS-FWJA AFW-CKV--OO-CV157 AFW-CK\/-00-CV1+2

AUXILIARY FEEDWATER TO 1 OF 2 SG (AFWS-,,3)

(AFWS17B)

INSUFFICIENT FLOW T~OUGH PIPE SEGlv£NT PSB 1 FAULTS IN PIFE FA!...URE OF 120 V FALURE OF 4KV AC SEGMENT PS81 PTRN DC BUS 1A BUS 1H JA AFW-TNK-VF -CST AFW-CCF-LK-STMBD E1A 4KY1H INSUFFICIENT T ST AND MAINTBN CE FLOW THRU PUMP ON AFW MDP a.A DUE TO BACKFLOW

.AFW-CKV -CC-4il077 MA.-FW3A BACKFLOW 8ACKFLOW THROUGH MOP FWJB THROUGH lDP FW2 PAGE 3 &-:.4 AFW-MDP-FS-FW3B AFW-CKY-OO-<N172 AFW-CKV-00-0/142

AUXILIARY FEEDWATER TO 3 OF 3 SG WINDOW 1 - (LSW 1)

~

l~~I 1'§.!#1 l~FI If I " l.9111 ff WI ff '

1£ I IIW-1

"~

I ff ....

AUXILIARY FEEDWATER TO 2 OF 3 SG WINDOW 2&3 (LSW23) 0 Vt 00 AJ'W-OXV-OC-Z756D Af\'I-CK\I-FT-CV27 .O.f\'I-CK\I-FT-CV5! Af\'1-CK>/-FT-CV!D An1-csv-co-zr511a FO~-D~

AJ'W-OSV-OO-Z756D AJ'W913 AJ'W914 AJ'W913 AJ'W914 AJ'W4Z PAGE 1 & 9

AUXILIARY FEEDWATER TO 1 OF 3 SG WINDOW 4 (LSW4)

INSUF fl.OW INSUF Fl.OW THRU APE SEG THRU APE SEC PS93 TO SG A PS91 TO SC C AJ'l'f-cxv-cc-arooe AF.V-CKY-FT-D/27 AFW-CKY-FT-tv5! AFW-CKY-FT -tvBQ FOS-DO AJ'l'fS13 AJ'l'fU PAGE 1 & 9

SEO. AT UNIT 1 AFW 1 OF 3 SG (SBOU 1-L) POS 1/2, 14/15 rAa.ORII OP APW SUPFLT mow UftlT R LTDU ll!l!D l-1L PAD.URI OJ'

,uamn 1

""' n Affl-11111-PO-OIBBO

SBO AT UNIT 1&2 -. AFW 1 OF 3. SG (SBOU1U2-L) - POS 1/2, 14/15 FAD.Vim Of AIW FAll.'OlD OP sum., ~ow An PIOII OllrF o,ur 1 LTOU PAD.UJJ or tUamJO D M91'01

.UWTDPI

SEO AT UNIT 1 AFW 1 OF 3 SG (SBOU 1-LS) POS 3-13 rAILOH!I OP /11'11

!n.JJIP'LT PROW UflIT &

.!!1110 1-111 PAD.URI or TUILBJlnl t Al'lfl PD AlW-Illl-PO-Ol!BO AJIWTDPl

SBO AT UNIT 1 AFW TO 10F 3 SG (LTDU)

(LTDU)

L'l'DIM LTDUl3 L1DUH LTI>llU LTDUJt PAGE 1 & 9

SBO AT UNIT 1 AFW TO 1 OF 3 SG (L TDU)

(L TDU5)

~-

NUFICOII LTDUII

• PAGE 8

SBO AT UNIT 1 AFW TO 1 OF 3 SG (LTDU)

(L TDU13) ns flOW ftftV~ot:O LtDUI~

PAGE 1

SBO AT UNIT 1 AFW TO 1

• OF 3 SG (LTDU)

(LTDU14) p,o.cc 7

SBO AT UNIT 1 AFW TO 1 OF 3 SG (LTDU)

(LTDU15)

UDUII!

PAGE 2 ~ 3

SBO AT UNIT 1 AFW TO 1 OF 3 SG (LTDU)

(L TDU 18)

INSUFFICl£NT CN/ lHROUGH PIPE SEGl,ENT PSBO FAU...lS IN PIPE SEGMENT PSBO TOP lRAIN AFW-lNK-VF-CST AFW-CCF -LK-STM3D TB T AND MAINTBNA CE INSUFFICIENT FLOW TO TCPFW2 ON .AYW TDPa FLOW THRU PUMP THRU PIPE SEG DUE TO BACKFLOW P59B AF'lf-CKV-CC-4ol577 MII-FW2 LTDU21 INSUF STM FLOW VLV THRU PIPE SEG PS95, PS9$, PS97 AFW-ACT-FA-VLVA APW-.MS-P0-196 LTDU22 PAGE 2,, 4 & 5 AFW-0<!/-00-CV157 AFW-CKV-OO-CV172

SBO AT UNIT 1 AFW TO 1 OF 3 SG (LTDU)

(LTDU21)

PAGE 6

3'J'ld 0

0 (zzno11)

(no11) 8S -=:IOL 01 M-=:1\/ L llNn 1\/ OBS

FAILURE OF UNIT 2 TURBINE DRIVEN AFW PUMP

Appendix C.3 Charging Pump Cooling System C-72

CHARGING PUMP A -COOLING (CPCA)

(CPCA)

. *~"",

,nwoo

"'°'

PA<:£. t & J

CHARGING PUMP A COOLING (CPCA)

(CPC1)

• PAGE 1

CHARGING PUMP A COOLING (CPCA)

(CPC2)

INS LFFICIENT OW THROUGH PIPE SEGMEIB PSI01 CE FAU..TS IN PPE FAU.TS IN PIPE SEGMENT *PS101 FAILURE OF 48QV SEGMENT PS101 CO~D

• AC MCC 1JH CPC-ICC-FA-Sv\P8S GCWl813 EJ1 CPC-CCF-LF-STRAB

TEST AND MAINTENANCE ON MOP SW108 POs-D6

• CHARGING PUMP A COOLING (CPC/

(CPC3)

INSLfflCIENT FLOW Tl-ROUGH PIPE SEGt.ENT PS111 FAU.TS IN PPE FALURE OF 480V SEGMENT PS111 AC MCC 1J1-1 CONTD CPC-K:C-FA-CCPBS EJ1 TE T AND MAINTENA CE BACKFLOW ON MDP CC2B T~Ol./GH PS118 MA.-CC2B CPC-CKV-OO-CV764 CPC-MDP-FR-CC2A

TEST AND MAINTENANCE ON MDP CC2B n

.!J 00 POS-Rt)

CHARGING PUMP A .COOLING (CPCA)

(CPC4) 8

\0 PAGE J

CHARGING PUMP B COOLING (CPCB)

(CPCB) 0 00 0

CPC-tt-fA-Tt"i88 CPC, CFC-XVM-PC-XVl'II CPC1 CJ'C2 PAGE 1 & 2

CHARGING PUMP C COOLING (CPCC)

(CPCC)

(")

00 1'6\mC[IIT , tfi1F now THRU INIIT na11 Ttllll "ia~l)ff ~i c,e ~ ,r,:01£M" CfC P~f..iE<M:NT C9C-CC-f"A-TCWC CFC3 C>'C4

.wPR!°lJ/t/J-PSl>I CfC2 Cl'C-lMl;>C-X\/111 CPC-XW-PG-X\/171 CPC1 PAGE 1

Appendix C.4 Component Cooling Water System C-82

• COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER TO RHR HX 1A, CCW1 SUFP, CC WAT.BR TO RHR Ill U smr. cc SUPPLY )ff UFF, cc*: Dt8CHAR PROM lll!ADER A TO HEADBR A CC!W-XVM-PO-CC178 CCW-80-RVHQA cc. le 0

00 w

CCW-XVld-PO-CC214' CCW-CKV-PT-CC177 CCW13 CCW-XVM-PO-CCIO! ccw-xvt.1-n-cc1a1 CCWH CCW-CO-PT-818~

COMPONENT COOLING WATER IITSTEM FAULT TREES INSUFFICIENT CC WATER FROM UNIT 1 CC HEADER, CCW13 fM..lPS: <F ... tr,/

H! 6Tl8 l!US 1H

TEST AND MAINTENANCE HT EXCHGR E1B

(')

~

POS-R6 ~-UTX-WA-Cf& POS-06 C:Cfi'-HTX-1.11.-£'8 CCW-K'X-LWX]B POS-Rtl

COMPONENT COOLING WATER SYSTEM FAULT TREES TRIP VALVE CC-TV-109. FAILURES, CCW14-0 00 0\

CCII-AOV-UA-lCllA OCff-AOV-PT-IOOA CCll'-J:B1!l-10PH.1 CCl<-AOV-PCl-lOOA CCW-AOV-OC-IODA IA-LF-OUTJA Bil

COMPONENT COOLING WATER SYSTEM FAULT TREES FAILURE TO START CC-P-1B BY AUTOSTART OR OPERATOR, CCW19 OP. FAIL PUHP TBST CCW-LF-PSlDIA CCW-l:Hl!-IOP1',I CCW-l:HB-FO-SP1B CC'l!'-XHB-IOPU.1

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER TO RHR HX 1B, CCW2 lllBUPP. CO '!IA'! R

'10 RHR la l IN9Ul'J'. CC 9 LY an 1801( HEADER B II CX:W-XVM-PO-CCUI~ ccw-sa-RVJl9'11 cw-xv1o1-rr-co1s&

ccwu CC'!I-CCP-J'l-9198

COMPONENT COOLING WATER SYSTEM FAUJLT TREES INSUFFICIENT CC WATER SUPPLY FROM HEADJER B, CCW23 0

00 v::.,

CCW-XMV-PO--;CC220 CCW13 CCW-CICV-FT-CC176 SP-Sl-Cl,SI-HE

COMPONENT COOLING WATER FAULT TREES, . TRIP VALVE CC-TV-109B FAILURES, CCW24 FAL~S OF CONTANI.ENT Olffi.ET VALVES rp Vdvo CC-l\l-Fol1Tes

• CCW-XW-PG-CC100 LOSS OF CONTRO..

PON R TO CC-TV-109BF l!E Of 12<N AC Vlr.bJ..

CCW-ACN-P0-1098 E211 lA-LF-OUTIA TRP VALVE FALURE SP GNEN SP.* 51/0.SI SK;NAL SP-SI-QSH£ CCW-ACN-FT-1098 CCW-XI-E-10P14,1

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFF. CC WATER TO RHR PUMP COOLER RH-E-2A, CCW3 CClf-Ll'-Rm::>A cc 3 CClf-110-~VUO CCW-90-RY 121 COKT..UrnIXlfT OUTLaT VALVBS OCff-XMV-PO-CCJal OCff-XMV-PG-COJJI CCl\'23

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFF. CC WATER TO RHR PUMP COOLER RH-E-2B, CCW4-TO cc,r-eo-RV u.e CCW-80-RV UU CON'TJ.IRUINT ounBT YALVBS Cmf-UIY-PD-cc11e CUlf-XMV-PO-CClla CCl!23 CCW24

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER TO ANY OF THE 3 RCP THERMAL BARRIERS, CCW5 cc ~

CCW-SO-JIVlleA. CCW-AOV-SC-120A. CC'i'1'-S0-RVIL6B CCW-AOV-SC-@B CCW-90-RVIL6C CC!I-AOV-9C-120C CCW-BO-IIV!~O CClll3 OUTl!tfli~fllf1'kffifl,ll!l~

INS~R. AIR S'TS.

L SB OF PUNCTIOI IA8-AOV-OC-CC1D7 IAS-AOV-PG-CClOY IA-LP-OUTIA Ell

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER TO RHR HX 1A, CCW1S sun. cc WA.TH TO RHR Ill: LA CC SUPPLY IN Urf', CC. DIBCHAR lll!A.DER Jt. TO Hil.\DER A CCW-XllV-P0-CCl79 CCW-SO-RVHIIA.

CCW-:UIV-PD-CC2H CCW-CltV'-FT-CCl77 CCWL3 SP-SJ-CL SI-BB CC'lf-X)!V-PQ-CCIW CCW-XllV-PCI-CCl81 CC'll'HD

COMPONENT COOLING WATER SYSTEM FAULT TREES TRIP VALVE CC-'fV-109A FAILURES, CCW14S CC-TV-109A l'AILU ES CCW-AOV-OC-109A C~-AOV-PG-iOSA IA-LF-OUTIA Ell SP-81-CLSI-HE CCW-AOV-FT-108A CCW-XKB-10P14.l

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER TO RHR HX 1B, CCW2S JPn!IJPJ'. CC WATI TO JUIR B:I. Je TO lmb.CIIR P I!f9U71. OC 91J LY PRO)( Jfl'ADJIR OClf-80-BVUH COWl98 cc,r .. ,

l

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER SUPPLY FROM HEADER B, CCW23S FAILURES ccw-xMJ-PG-cc220 CCW13 CCW-CKV-FT-CC 176 SP-Sl-CLSI-HE

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFFICIENT CC WATER TO RHR HX 1B, CCW2S 0

\0

• oo TO 04.0U'*

m,un. cc st1 L'1 PUOll Ml"AD!IR O:W-90-RVUII CCWl98 CC11"&41

• COMPONENT COOLING WATER FAULT TREES TRIP VALVE CC-TV-109B FAILURES, CCW24S PAIL RJIB DP CONTAIHM NT OUTLllT VALVES TRIP VALVE cc-TY-L09B PAILURl!lS CC11'-:XIN-PO-CCiQD CCW-AOV-OC-109B CCW-AOV-P0-1090 IA -LF-OUTIA Btlll SP-SI-CUI-BB CCW'-AOV-FT-109B CCW-:XHE-IOPH.1

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFF. CC WATER TO RHR PUMP COOLER RH-E-2A, CCW3S

• • -~

RBR SUL CO R R -B-U

. LO OJ' P CTIDI CCW-LT-JUl:EU.

0 0

0 CCW-SO-RVU8 CC!l-90-ftV121 OO!f-l!MV-PO-CCJ22 OCW-l!MV-PO-CCIJI

COMPONENT COOLING WATER SYSTEM FAULT TREES INSUFF. CC WATER TO RHR PUMP COOLER RH-E-2B, CCW4-S TD lll.\DIR D CCV-80-RVLL.8 CCW'-80-RVUH 00\f-IIIY-PO-CCJIG OCl'l'-IMY-PO-COl 13 CCWZ3S OCITU8

FAIL URE TO COOL RCS PUMP SEALS FROM UNIT 2 ccw FROM EQUATION ON PAGE B-9 nI

~

0 N

REC-XHE-FO-SCOOL MA-U2B1A

TEST AND MAINTENANCE ON RCP 1C S?

()

0 I

v>

1_6_ 1 15 I I~ I

"' -1)11 "' --R1l

Appendix C.5 Compressed Air System C-104

LOSS OF CONTAINMENT IA TOP EVENT =C~

()

I 0

u.

LOOSCFIHw.RY~

<ru "%':!-~ ~

w w.suc ~

LOSS OF CIA SUCTION Lea' Cl'.-AOII-FT-l'.10] Cl'.-AOll-f'G-108 C.S-BB a..s-H

• COMPONENT COOLING WATER (CCW1)

(W) to FLOW FALURC CF FM.U<E OF IBROUGH Pl)l.(P HfAT EX(l-jl,,NOER HfAT EXCH4NGER TRAIN 1--<:C-4'- IB E-1' E-1l ES!B~ ES!B\J *w.-C1B PAGE 1 & 2 CCW-1.0P-FR--<:CP V. CCW-O<V-CO-CV557

Loss of Turbine Building Instrument Air 0

0 00 EJ2 El2 l'S-a>s-FR-L'.C-1 EJ2 a.s-HH

Loss of Both SA Compressors 0

0 v::,

BOU9B-L09P BOUSB-LCSP SAS-CPS-f11-1S>.C1 L.OSP SIIS-CPS~-2S>.CI ~S~PS-fR-2SACI

TURBINE BUILDING INSTRUMENT AIR-CSD 0

0 SA-CSD L'.S-AO\I-FT-TV12B EJ2 EJ2 L'.S-CPS-FS-L.\C-1 L'.S-cf'S-l'R-L.\C-1 L.\S--O'm--lf-L.\D1 LOSP HOU5E-L0SP

Loss of Both SA Compressors CSD 0

IIDUH-LO!P noum-101 LOSP LOSP SAS-CPS-rR-ISl,CI

This page intentionally left blank.

C-112

Appendix C.6 Containment Spray System

• C-113

CONTAINMENT SPRAY SYSTEM (CS-S)

~@) POWER & S/D

/BOUSE-POS313 HOUBE-POS313 Cft IS CS9-TRA-MA CBB1NS1S

CONTAINMENT SPRAY SYSTEM (CSS)

(CSS1N115)

POS 1, 2, 14, IN LfflCUIT FROM CSS 1RAtl A

(")

I Vt tlSlF Fl.ON NO nw Ps:10 g;J,P 1RAIN CS14. C TD)

FALURE Of t2(N fALURE Of 48(N AC EJJS 1H AU rn [4801H QS-AC1-FA-QS2A fALUlE OF 400/

AC MCC IH1-2 BHe QS-ACT-FA-Q..S2A QS-ACT-<P-CLS2 QS-ACT-fA-<LS29

• CLS-ACT-OP-QS2

CONTAINMENT SPRAY SYSTEM (CSS)

(CSS1N313)

POS 3-13 tlSI.J"Fl::ENT R.OW FROM CSS TRAtl A

(")

I

°'

NStF R.OW THRIJ P~ 8;l"'

TRAtl CS'!!. C TD)

FAlU1E OF t2<:N CS5-MDP-OP-N3 CS9 NH E1!. E480tH tlSI.J"FK:ENT LOW Tl-ROUGH Pl'E SEGI.ENT PS53 FAlm£ CF 4W/

AC MCC 1H1-2 IH~

EJ2

CONTAINMENT SPRAY SYSTEM (css)

( CSS2N 115) 0

..... E~OOU E'B

-.J 1NSUFF1CEIIT INSUFFICIENT Fl.OIi TI-R()UGH AP FLCJ// THRO!JCH PIP SEOMENT PSS~ SEGI.ENT PS55 ClS-ACT-Cf'-CLS2 a.5-ACT--FA-0..52B l.l\-CSIB C 57 C SB QS-ACT--OP--0.$2 ClS-ACT-fA-QS:1A QS-ACT-OP-0.S2 CLS-ACT--FA--<LS!!S

TEST AND MAINTENANCE ON css MOP 18 0

00 POS-DS C:SS-UIP-W.-C:S1l

Appendix C. 7 Emergency Power System C-119

ELECTRICAL POWER - STUB BUS 1H (ESTB1H)

(ESTB1H)

FALUlE OF 4KV AC STl.E BUS 1H FAURE OF 4VKV OPEAATOR TO 4180V AC BUS 1H RECONNECT AFTER 1H LOSP ACP-CRB-C0-15H9 ACP-BAC-ST -ST81H ACP-BAC-MA-STB1 4KV1H PAGE 1 ACP-Xl-£-FO-STBBS LOSP HOUSE-l

ELECTRICAL POWER MCC 1H1-1 ( 4KV 1H) ( 4KV 1H)

KOU!IB-Bl HOUS[-U'

"°'-DOOi DCP-Cl'.T-lP-ll!Wl DCP-11\T-lP-ll',11'.

TEST AND MAINTENANCE ON DIESEL GENERATOR 1 ELECTRICAL POWER - 4801H BUS (E4801H)

(E4801H)

FAILURE OF 480V AC BtJS 1H tbl1 FAILURE OF 4VKV ACP-CRB-C0-14H 1 AC BUS 1H ACP-TFM-N0-1H ACP-CRB-C0-15H7 CP-BAC-ST-4801H CP-BAC-MA-4801H 4KV1H PAGE

ELECTRICAL POWER - MCC 1H1-1 (EH1)

(EH1)

FALLRE OF 80V AC MCC-1H1-1 FAILURE OF 480V AC BUS 1H1 ACP-CRB-C0-14H 14 ACP-BAC-ST -1H 1-1 ACP-BAC-MA-1H1-1 tbl1 FAILURE OF 4KV AC BUS 1H PAGE 1 4KV1H

• ELECTRICAL POWER - MCC 1H1-2 (EH2)

(EH2)

FAILLRE OF 480V AC MCC-1H1-FAlURE OF 480V AC BUS 1H1 ACP-CR8-C0-14H13 ACP-BAC-MA-1H1-Z FAILURE OF 4KV AC BUS 1H 4KV1H PAGE t

ELECTRICAL POWER - STUB BUS 1J (ESTB 1J)

(EST81J) .

FAil.i.RE OF 4KY AC STUB BUS 1J FAILURE OF 4VKY AC BUS 1J ACP-CRB-C0-15J9 ACP-BAC-MA-STBiJ.

ACP-BAC-ST -STB1J EPS 2DC PAGE 1 ACP-XHE-FO-STBBS LOSP

ELECTRICAL POWER - MCC 1J1-1 (EJ1)

(4KV1J)

FALLRE OF 41<V AC Bl.5 1J HOUS8-B2 HOU KB-Bl FALURE Cf" 1W. PO\'iER 10

'*' BUS 1J B0UIJII-L2 HOUBB-L3 UN!NAL'BUTY Cf' OIE58..

PROB-IHFAILIIDL2 PROB-IHPAILIIDLJ GEI-EAATOR #3 ACP-BAC-IU-UCVWACP--8.!.C-ST-4KVIJ HOUst-LOSP JlA-D003 DCP-BAT-LP-BATIB DCP-CCP-LP-B'1'1AB

TEST AND MAINTENANCE ON DIESEL GENERATOR 3

....0N 00 I

ELECTRICAL POWER

• MCC 1H1-2 (EH2)

(EH2)

FAILLRE OF 480V AC MCC-1H1-FALURE OF 480V AC BUS 1H1 ACP-CRB-C0-14H13 ACP-BAC-ST-1H1-2 ACP-BAC-MA-1H1~2 tbl3 FALURE OF 4KV AC BUS 1H 4KV1H PAGE 1

ELECTRICAL POWER - 4801J BUS (E 4801J)

(E4801J)

FAILURE OF 480V AC BUS 1J 0

w 0

tbl1 FALURE OF 4VKV - - -

AC BUS 1J ACP-TFM-N0-1.J ACP-CR8-C0-15J7 ACP-BAC-ST -4801J ACP-BAC-MA-4801J 4KV1J PAGE

ELECTRICAL POWER - MCC 1J1-1 (EJ1)

(EJ1)

FAILURE OF 480V AC MCC-1J1-1 FAILURE OF 480V AC BUS 1J1 ACP-CRB-C0-14J16 ACP-B<\C-ST-1J1-1 ACP-BAC-MA-1J1-.

tbl1 FALURE OF 4KV AC BUS 1J PAGE 1 4KV1J

ELECTRICAL POWER MCC 1J1-2 (EJ2)

(EJ2)

FAILURE OF 480V AC MCC-1J1-2 E2 FAILURE OF 480V AC BUS 1J1 ACP-CRB-C0-14J 14 ACP-BAC-ST -1J 1-2 ACP-BAC-MA-1Jl-2 tbl.3 FALURE OF 4KV AC BUS 1J PAGE 1 4KV1J

ELECTRICAL POWER

• (E1A)

DC BUS 1A (E1A)

FALUlE OF 125V DC BUS tA.

FAlURE OF DC BUS 1A POWER SOLRCES DCP-EDC-ST-BUStA.

EPS ODC FAURE OF FAURE OF FAILURE OF POWER TO DC BUS POWER TO DC BUS 125V DC POWER 1A FROM UPS V.2 1'. FROM LIPS 1" 1 FROM BATTERY 1" FALUlE OF FAURE OF POWER FROM UPS PONER FROM I.PS 14.2 16.1 DCP-CRB-C0-19 DCP-Cffi-C0-20 DCP-B4.T-LP-BAT \A.

EPS 2ZZ

• EPS -OC FALURE OF 48CN FAURE OF 48(N AC MCC 1--11-2 AC MCC lHl-1 EH2 EH1 PAGE 1

ELECTRICAL POWER - DC BUS 18 (E 1B)

(E1B)

FALURE OF 125V DC BUS IB EB FAILURE OF" DC BUS 1B POWER SOURCES DO'-BDC-Sf-BUSIB FAILURE OF FAft..URE OF FALURE OF POWER TO DC BUS POWER TO DC BUS 125V DC POWER 1B FROM UPS 181 18 FROM UPS 132 fRCM BO.TTERY 18 EPS DC.

FAILURE O" FAILURE OF POWER FROM UPS 125V OC POWER 181 FROM BAffiRY 18 OCP-CRB-C0-2{ DCP-CRB-C0-23 DCP-BAT--LP-B1\T1B DCP-CCF--LP-BTIAB FAI..URE OF 400V AC MCC lJl-2 PAGE MA-UPSB1 E'..11 E'..12 Mi!.-UPS82

TEST AND MAINTENANCE ON BATTERY CHARGER B1 POS-D6 ACP-l!CH-"'-IPSB1 ACP-l!CH-IIIGUPS81

TEST AND MAINTENANCE ON BATTERY 18 POS-11<1 DCP-IIOC-11'.~Ttl POS-Rt>

TEST AND MAINTENANCE ON BATTERY CHARGER-B2 ACP-BCH-M\-LPS82 POS-R1l

B..ECTRICAI.. POWER - vrrAL BUS 1 (E 1)

(E11) 0

~

00 PAGE 1 Dl2

• ELECTRICAL BUS 111 (E2111) w.-vem ACP-CRB~0-11 A01-IW-NO-l..PSB1 ACP-TFM-00-181-2 ACP-mB-00-fUiBJ r.JI WA-8AT1B ACP-fEC-NO-UPSB 1 ACP-CAB-CO-FE9BE ACl'-TFI.I-II0-191-1 DCP-CRB-C0-~4 DCP-BtJC:-ST-Bl...611 fALLRE OF PC'llffi FROM LI'S 102 10 DC BUS 13 E 13 EJ2 OCP-CRB-C0-23 ACP..flEC-NO-U'S82 DCP-&.T--U'-&.TIB DCP~CF--U'-l!TW!

TEST AND MAINTENANCE ON VITAL BUS SUPPLY POS-R1l

• e

ELECTRICAL POWER BUS 1111 (E31111)

(E31111)

E

• PAGE 1

[HI

ELECTRICAL POWER - VITAL BUS 1v' (E411V)

(E411V)

E 'ti NOi

[J2

• EJI

Appendix C.8 Emergency Switchgear Ventilation System

• C-143

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(VS1)

VI OVB IU ovs 121 GVs:lll3 OVS1913 QVS181S OVS17U OVSl813

VENT!LA TION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS1213)

LOSS OF FUNCTIO STANDBY ABU AIR HANDLING UN T IN AIR HANDLIN 1-VS-AC-IJ 1 VS-AC-6 UNSCHED ED UNIT l-YS-AC-6 PAN MOTOR FAUL S MAllfTE!fANCB VS-.A.HU-LF-YSAC6 VS-AHU-MA-VSAC6 1 VS-AC-6 FAN MO OR 1 VS-AC-6 FAN MO OR 1 VS-FM0-6 POWER LOSS MANUAL SBLECTO 1-B-O RX TRIP R FAILS TO STAR.T FAILS TO RUN FO AILURE OF -i80V C SWITCH FAILS OP SI STEP 18 1-YS-PM0-6 IISSION .1-VS-FMO 6 llCC-lJl-1 A/C GROUP 1B NTILAT!Olf ALIGN"~ BNT EJ.I V9-FMO-PS-PM06 VS-PMO-FR-:PM06 VS-SW-CO-ACGJHB VS-XHE-PO-E018

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS1313)

I SUFP AIR COOLIN FR M RUNNING UNIT 1 AHU 1-VS-AC-7 GVS 313 LOSS OF FUNCTION 1- S-AC-7 FAN MDT R 1- S-FM07 POWER L IN AIR HANDLING AILS TO RUN FO F ]LURE OF 4-80V i UNIT 1-VS-AC-7 ISSION, 1-VS-FMO 7 MCC-1H1-1 8H1 VS-AHU-LF-VSAC7 VS-FMO-FR-FM07

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS1613)

INS FF CHILLED WATE SU PLY FROM RUNNIN HILLER TRAIN A GVS 613 TABLE 1 JNSUFT[C[ENT SW E ECTR[CAL FAULTS VS-BCFLOWDIVER FLO THROUGH CHILL R WITHIN CHILLER S-MDP-FR-VSPZA 1-VS-E-4-A TRAIN A S-CKV-PG-VS288 S-MOV-SC-P107A S-CHL-FR-VSE4-A GVS1913 GVS 62~

(1-V -FM0-7 POWER L ss) (CHlLLE A LOSS OF CON RQL F !LURE OF 4-BOV A POWER . FAILURE OF 120V AC 11CC-1J1-1 POWER TO VITAL BUS l II!

EJ1 E31III

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS1713)

GVS 713 T ST ANO W.INTENA.NC FA LTS WITH CHILLE E ECTRlCAL FAULTS 0 CHILLER 1-VS-E-4 1-VS-E-4-B WIT IN

• CHILLER TRAIN B TABLE 2 S-XVM-PG-VS294-S-MDP-FS-VSP2B MA-VSE4B GVS 721 *GVS1763 S-MDP-FR-VSP2B S-CKV-P'T-VS292 S-XVM-PG-VS291 VS-BCFLOWDIVER S-MOV-FT-PG107B C ILLER 1-VB-E-4B INSUFFICIENT SW C ILLER 1-YS-E-4B F.AILS TO START :FLO THROUGH ST.AND F ILS TO RUN FOR HILLER 1-VS-E-48 24- HR MISSION GVSU013 VS-CHL-FS-VSE4B VS-CHL-FR-YBE4B

TEST AND MAINTENANCE ON CHILLER 1-VS-E-4B POS-06 POS-Atl

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS1813)

IN UFF CHILLED WAT R SU PLY FROM RUNNI 0 CHILLER TRAIN C GVS 813 TABLE 3 INSUFFICIENT SW LECTRICAL FAULTS VS-BCF'LOWDIVER FL Yf THROUGH CHIL R WITHIN CHILLER S-MDP-FR-YSP2C 1-VS-E-4-C TRAIN C S-CKV-PG-YS296 VS-MOV-SC-P107C YS-CHL-FR-VSE4C GVS11113 OL POWER) :FAILUR OF AC POWER,- TO VI AL BUS 2..::.m 2EH1-1 2E3111.1

VENT! ION SYSTEM, VS (EMERGENCY* SWITCHGEAR ROOM COOLING)

(GYS1913) av LGZL sw.e-crv-Po-n,1, ov lll!Z SW"!I-XK2-.UO.lil.oa OV ltlZ DTSlll!!I va-wo,-ra-Ts,u.

SWB-JKB-A.PltlJO V.S-CCP-n'-PAJ,C

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS11013)

GY L1D!l VB L8 nDBT 1JW8-PCV-PT-l00B SWB-CCV-PT-8"'929 321 l!TR.l1n:R. T!I-UI 1lf9UfflC1BNT 11 PLUCCBD DVRUf 11,0W THROUGH P MP 8TANDBr 1-VS-P-lfl OCWJ!l3 GV 1U]B3 IJM'~-XVII-PO-Sw:121 BlfP-BTR-PO-TBt~C a_ .

811'8-Xl!ll-APIUO 8'1t'B-CC1-PO-T81~C.*

PROB OP ccr T

\TIVT8D:oTlARB~~: :c CV 11083 CVB1763 VS->1DP-F8-V81'1D VB-MDl'-TR-VllPIB AP-12.00 B!RYl WATER aT:,TBu ABNORMAL CONDIT 0~8

~W8-Dill-A.Pl2.00 V8-CC1-PT-f'ABC

VENTILATlON SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS11113) lll90'PP ff I or CXJLD WATGI Cl!JLLIA 1-n-1 e fff 1181

,nn-AO'l'-oc-1000 ftl-CIY-M-IYI~

m,a-:uai-.uon.oo ffl!I-Cc:7-PO-Tl!l:!C CV:!11911)

Yl-ll'Dr-rl:-TBPlC 11"1'~-IHZ-APla.oo V9-CCP-IT-PA.IIO

VENTILATION SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS3113)

INSU FlCIENT CHlLLED ATER F OM 1 OF 2 BACK P C ILLERS 1-VS-E-3A 8 GV 113 I SUFFICIENT CHILL D I SUFFICIENT CHILL I ATER FROM BACK P ATER FROM BACK l HILLER 1-VS-E-3 CHILLER 1-VS-E-3 GVS3213 GVS3313

VENTILATiON SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS3213)

GYS 213 SYSTEM C ILLER 1~vs-E-3A C ILLER 1-VS-E-3A CONFIGURATION EM HG BACKUP POWE FAULTS FAULT FR M 480V MCC JJ1-EJ1 VS-MDP-FR-VSP:JA VS-CKV-PG-VS278 C ILLER 1-VS-E-3A APORATrYE CON-FAILS TO RUN ENSER 1-YS-E-JA 24- HR FAILS TO RUN VS-XVM-FT-YSl:!47 VS-XVM-FT-VS2!H VS-XIIE-FO-FCA1D VS-CHL-FR-VSE3A VS-EVC-FR-VSElA

VENTILATRON SYSTEM, VS (EMERGENCY SWITCHGEAR ROOM COOLING)

(GVS3313)

SYSTEM C ILLER 1-VS-E-3B C ILLER 1-VS-E-3B HILLER J-VS-E-3B CONFIGURATION PUM S 1-VS-P-3B l'AI S CHECK VALVE FAULTS FAULT TO RUN 24- HR 1-VS-271 VS-MDP-FR-VSP3B VS-CKV-PG-VS271 GATE VALVE C ILLER 1-VS-E-3B APORATIVE CON-1-VS-iU7 :FAILS FAILS TO RUN ENSER 1-VS-E-IB T OPEN OR PLUGS 24- HR :FAILS TO RUN

( D VS-XVM-FT-VS247 VS-XVM-FT-VS201 VS-XHE-FO-FCA1D VS-CHL-FR-VSE3B VS-EVC-FR-VSE1B

VENTILATION SYSTEM, VS (SERVICE WATER SYSTEM (GCW1813)

SW'S-%0-DU.00 PAULTl!I c:rc-n11-ro-:SY1l U.-LP-OtrrlA Q'O-<Jl'&-PCJ-8TJl.lA.

aw-J.ov-rr-Sltaea

VENTILATION SYSTEM, VS (SERVICE WATER SYSTEM INTERFACE) ( GCW 1813)

FAllT9 0

V\

00 EH2

Appendix C.9 High Pressure Injection and Recirculation System C-159

FAIL URE OF FEED AND SPILL USING HPI SYSTEM WINDOW 1&2 FALURE OF FEED ANO SPLL USING HPI FAL HIGH PRES FAL HIGH PRES OW TO HOT LEG- OW TO CLO LEG-CHRG PMP MANUAL CHRG PMP MANUAL 021-LG 02

FAILURE OF FEED AND SPILL USING HPI SYSTEM - WINDOW 3&4 (FSW34H) l'AILURI! or l"EED AND SPILL U91HG HP[

FAILURB or HP! !IYSTl!M PAILURE Ol" HPI FAlLURJI OF HP[ TO HOT LEO TO COLD L!G D2 D2BLG

HIGH PRESSURE INJECTION AUTOMATIC (Di)

(D1)

HPI-CKV--FT -C\1225 CKV-<:CF -FT--0..ll.G INSUFr\CIENr INSUFFICIENr INSUfFICENT LCNI TfflOl.lGH Pll'E OW THRDUGH PIPE LCNI TlflOOOH PFE SEGt.ENT PS12 SEGMEHr PS22 SEGIJENT P521 HPI8 INSUFFICBIT LOW Tl-ROUGH IICP CH-16 IN PS12 SIS-ACT-f"A-5193 If' 17 INSlF FLOW FM INSf CPC CHIB:SW TE T AIID MAUITENA CE CH-18, 1C DI£ 0 LUBE 011., CC TO ON HP! )!DP CHi TO BI.CKF1.0W SEN.. C:Oa.ER lf'l21 E1B CPCB 4W1J E2\I MA.-CH18

HIGH PRESSURE INJECTION AUTOMATIC (D 1)

(HPl4)

INSUF FLOW THROUGH PIPE SEGMENT PS11 H 14 INSUF CPC CH1A:SW INSUF FLOW NCI!: FAILURE OF 4KV AC FROM CHA.RGING 1A TO LUB OIL, CC TO PUMP SUCTION SEAL COOLER BUS 1H HEADER HPI-MDP-FR-1A.6HR 4KV1H HPl9 PAGE 1

TEST AND MAINTENANCE ON CHARGING PUMP 1A

HIGH PRESSURE INJECTION - AUlOMATIC (D1)

(HP16)

IA21 PAGE 5

TEST AND MAINTENANCE ON HPI MOP CH1C

HIGH PRESSURE INJECTION - AUTOMATIC (D1)

(HPl7)

PAGE 6

HIGH PRESSURE INJECTION - AUTOMATIC (01)

(HPl8)

£.JI

• PAGE 7

TEST AND MAINTENANCE ON HPI MOP CH1B

HIGH PRESSURE INJECTION AUTOMATIC (D 1)

(HPl9)

FM.LIi£ CF rALLRE*or MCWll1X TO a.ta: l,()'{11 & rn a.osr S6...<cf-F..._S!ll en Eta 00 PAGE 2 & 3

HIGH PRESSURE INJECTION - AUTOMATIC (01)

(HPl21)

Q

....J PAGE 4

HIGH PRESSURE INJECTION AUTOMATIC (Dl)

(D1-C)

HPl-o<V-n-cv225 CK\1-0Cl'-FT-Q.CX.O B~i-XBE-PO-COLD HP 2C HPH HPl7 HFIB 515-ACT-FA-SISB H'l9 HPI 7C SF CPO CH'B:5\11 T LUBE OL, CC TO SE/>I. COO.ER H'121 EIB CPCB 4KV\J E21Il

HPI TO HOT LEGS MANUAL (D1HLG)

(D1HLG)

P.AU. HIOH PRBB l'LOW HOT LEOS RM 3 CBRG PUP l,!A.NUAL HPI-XHB-l'O-BOTLG Cl(V-CCF-FT-HTL02 CKV-CCP-FT-HTLG1 NPWHLO HP 2B INSLFFICIENT INSIF FLOW C/W THROUGH PIPE THROUGH PIPE SEGMEtfT PS13 SEGMEtfT PS11 HPl700 HPl800 1-f'IS H'l4 SIS-ACT-FA-Slffi H'19 HP! 7H

!NSF <l'C CH1B:SW FALURE OF 120V LUBE OL, CC TO DC Bl.6 1B SE.Al COCI.ER HPl21 CPCB E2lll IM-CHIB

HIGH PRESSURE INJECTION - AUTOMATIC (01)

(HPl700)

EHi PAGE 6

HIGH PRESSURE INJECTION - AUTOMATIC (01)

(HPI800) zu PAGE 7

HIGH PRESSURE INJECTION - MANUAL (D2)

(D2)

EIB H'M EHi £J1 t:zll W.-CH111

HIGH PRESSURE INJECTION - MANUAL (D2-23)

(2/3 pumps)

Q(V-<Xl'-FT-0.tl.C 4KVU EHi £J1

'1' .un MllJnD nca or  !!:PI M'.DP en tf'al E:111

HIGH PRESSURE INJECTION MANUAL (02)

(HPl4A)

INSIF FLOW THROUGH PIPE SEGMENT PS11 HP4A NSF CPC CHtA.:SW FROM Cw..RGING T ST AND MAINTE!f lfCB FALURE OF 4KV AC TO LUBE Ol, CC T PUMP SUCTION CHARGlNG PUMP 1A BUS 1H SE.l>J.. COO..ER HEADER HPI-MOP-FR-tA.6HR HPl9A MA-CHIA 4kV1H PAGE 1 I

HIGH PRESSURE INJECTION MANUAL (D2)

(HPI6A) t-lSUFFICIENT FLOW THROUGH PIP SEGMENT PS13 tJSUF FLOW INSF CPC CH 1C:SW FROM CHA.RGNG FALURE OF 4KV A FAIL.URE OF 120V TO LUBE 0~ CC T PUMP SUCTION BUS 1H DC BUS 1A SEN. COu...ER HEADER HP19A HP JBA 4KV1H E1A CPCC FROM CHARGING FALURE OF ST .AND MAINTEN NCE PUMP DUE TO 120V AC POWER ON HP! MDP CH BACKFLOW TO VITAL BUS 1-1 HPl21 El MA-CHlC

HIGH PRESSURE INJECTION MANUAL (02)

(HPl9A) rALUE or <<JIN rALLRt Of <<JIN AC woe 111-2 ACP-TAC-lP-V\-2

£H2 EH2 PAGE 3 & 4

HIGH PRESSURE INJECTION MANUAL (D2)

(D2HLG)

CKI/-CCF-fT-HTl.G1 Ck\l-CCF-fT-HllG2 mJ-JlD-PO-R:m.O 0

00 F'AURE l:E <lt{V At rM.lJIIE <1' -48(N BUS U M; I.ICC IHI-I 4KI/U EHi FJ1 CII

HIGH PRESSURE INJECTION TO HOT LEGS - MANUAL (D2HLG-23, 2/3 PUMPS)

CK>'-<X:F-fT-111l.G1 CK>'-CCF-fl-1111.Cl2 n:n-xm-Po-nm.o

~KVU EH1 lf>QI E2\I W.-CH1B

HIGH PRESSURE NJECTION - RCP SEALS {03)

(03)

HIGH PRESSURE INJf;CTION - RCP SEALS (03)

(D3-C)

CII

HIGH PRESSURE INJECTION EMERGENCY BORATION (HPI-EB)

(04)

PPS-XH!:-f0-£1J8CR DJ EH2 PPS~Gv-FT-1456 PPS-CCF-FT-PCRV PPS-SOll-fT-1455C PPS-CCl'-fT-PCW Ell w.-uee PAGE. 1 & 2 EH2 EJ2

HIGH PRESSURE RECIRCULATION (HPR-H2)

(H2)

INSUF FLOW FRM 3 CHRG PMPS IN Tl-£ ~CIR MOOE l>ISUF FLOW TO INSUF FLOW TO CHRG suer HD FM TI-E ca..o LEGS FRM LPSI MCNS1863A/B 3 CHRG PUMPS NSUFFICIENT FLO/'/ INSUFFICIENT FLO/'/ NSUFFICIENT FROM LPR MOV FROM LPR MOV FLOW FROM 1863B 1863A CHARGING PUMP MOP-CH1A HPR8 INSF CPC CH~:SW INSUFFICIENT INSUFFICIEITT FLOW FROM FLOW FROM FAILURE OF 4KV AC BUS 1H TO §~ 86-a.~ TO CKo\RGING PUMP MOP-CH13 CH,\RGING PUMP .

MDP-CH19 HPI-MDP-FR-1!.6HR HPR-MDP-FR-A18HR MA-CHIA 4KV1H CPCA I-PR13 T ST AND MAINTEN CE ON HP! MDP CH1 PAGE MA-CH1B HPR14 HPR15

HIGH .PRESSURE RECIRCULATION (HPR-H2)

(H2)

PAGE 1

HIGH PRESSURE RECIRCULATION (HPR-H2)

(HPR14)

....000 00 PAGE 2

HIGH PRESSURE RECIRCULATION (HPR-H2)

(HPR15)

....0 00 IO H'I-IG'-rR-lf,Qfl ... -Clt't'-00-cmll PAGE 3

HIGH PRESSURE RECIRCULATION (HPR-H2)

(HPR13)

PAGE 4

HIGH PRESSURE RECIRCULATION (HPR-H2)

(HPR8)

....0\0 lll'Rl2 H.t.F FtbW IU(

ID 8'04Dl<AC£ Tiffi i<>, Ctt-1'<

HI SS-1.CT-fA-Sl!A SS-1.CT-fA-&IS!I lf'Rl4 lfll!I PAGE 5

HIGH PRESSURE RECIRCULATION (HPR-H2)

(HPR12)

---

111-ICtlH

[Ill

• P.A.GE 6

• Appendix C.10 Low Pressure Injection and Recirculation System C-193

FAIL URE OF FEED AND SPILL USING LPI SYSTEM WINDOW 1&2 POfN2 Wit W/2 "1/NlOWI

FAIL URE OF FEED AND SPILL USING LPI SYSTEM - WINDOW 3&4 (FSW34L)

FAILURE, OF FEED .AND SPil.L USING LPI FAILURE OF LP! SYSTEM FAILURE OF LPI FAILURE OF LPI TO COLD LEG TO HOT LEG D6-C LPIHLG

LOW PRESSURE IN.ECTION (LPI)

(D6)

L 12 E'I\ E\B IM-SII>. IM-SIIB

TEST AND MAINTENANCE ON LPI MDPSl1A TEST AND MAINTENANCE ON LPI MDPS\18 l ST AND WJNTE~C OS 6 o1 a Drained POS 10 of a ON LPI MDPSl1B Molnlenonce Ouloge Refueling Outage

- STAlE 6 LP1-MDP-W.-Sl18 P0S-R10 LPI-MDP-W.OSl18 POS~6 LPI-MDP-MA-Sl18 POS-D6

• _J

TEST AND MAINTENANCE ON LPI 1862A

(")

I

~

LOW PRESSURE INJECTION (LPI)

(06-C) r.ut.UCII CfJ1 4Wi AO.

MCC JIil-i

=

Fdua at caobnt p'p,n:,w~

(")

N 0

0 r>.LURE Of 121N DC IJ.J5 ll SS-1,CT-FA-S~B CB LPHIDP-fS-SI\B U'l-00-00-o/W

Loss of LPI Flow Path (D6-CG) 061-l()

LPPS<l LPI-O<V-FT-2..:l HA""i!l1A

!IA-m19

LOW PRESSURE INJECTION P.ATH TO HOT LEGS (D6HLG)*

IN9UF FLOW PRM 2 LOW PRES SI l&PS TO HOT LEG NO FLOW TO HOT LEGS OU: TO CHEC V>LVE rALURES CKV-CCF-FT-HTLG1 RlTT-TNK-LF-RWST *CKV-CCF-FT-H1LG2 NFWH..G INSUFFICIENT NO FLOW FLOW TO THROUGH PlPB MOV 1890B SEGMENT Pll47 D631HLG DBUHLG

LOW PRESSURE INJECTION TO HOT LEGS (D630HLG)

INSUF FLOW TO OV1890B FROM LOW HEAD SI TRAIN A INSUF FLOW TO MOV18908 FROM LPI TRA.IN A T ST ANO MA.INTENANCE ON LPI MOP SI tA.

lw\-S11A

LOW PRESSURE INJECTION TO HOT LEGS (D631HLG) 063 H...G INSUF FLOW TO M ¥1890A FROM LP!

TRAIN A T ST Al-D W.NfENA.NCE ON LPI MOP Sl'\A.

MA-S11A

LOW PRESSURE INJECTION TO HOT LEG (D640HLG)

NSUF FLOW TO W'i/18900 FROM L l£AO SI Tlv\lN 8 INSl..f FlCW TO I.OV18908 FROM LP Tlv\N B ST At-o MA.INTENAN ON LPI t.OP Sl13

~-Sl1B

LOW PRESSURE INJECTION TO HOT (D641HLG)

INSUF FLOW TO OV1890A FROM LO HEAD SI TRAIN B D64 f-LG1 T ST AND MI\INTEN<\NC ON LPI MDP Sl1B MA.-S118

LOW PRESSURE INJECTION TO HOT LEGS (LPIHLG)

LPIHLG LPl-lCllE-ro-BOTLO LPH LPRT U't:900 LMtOO LP130L I.PHO.I

LOW PRESSURE INJECTION TO HOT LEGS (LPIHLG)

LPR6

• PAGE 5

LOW PRESSURE INJECTION TO HOT LEGS (LPIHLG)

LPR7 PAGE 5

LOW PRESSURE INJECTION TO HOT LEGS (LPIHLG)

LP\300 INSUF FLOW TO OVl8900 FROM LOW HEAD SI ll'AIN A LPI 00 MUF FLOW TO FAILURE OF 4&N FAn..URE OF 120V MDV1B90B FROM LPI AC BUS il DC BUS lA.

lRAIN A E4B01H INSUFFICIENT FLOW FM LHSI th.

DUE TO BACKFLOW W.-S11'\

LPHA)P-FS-SI 19 LP1-CKV-00-CV50

LOW PRESSURE INJECTION TO HOT LEGS (LPIHLG)

E480'H LPI-MOV-PC-1862.o.

ILA-BIIA LPl-)(\/l,I-P0-XV!i7 LPl-<:KV-FT-C\158 LPI-I.DP-FS-SI\O\ LPI-MDP-FR-1.!, 'HR LPI-OCl"-fS-SIWI LPl-<:KV-00-o/50 lPI-MlP-fS-911

LOW PRESSURE INJECTION TO HOT LEGS (LPIHLG)

LPl400 NSUF FLOW TO OV1890B FROM LOW HEAD SI TRAIN B LPI 00 INSUF FLOW TO FAllJRE OF 12CN MOV1890B FROM LP1 FAILURE OF 48CN TRAIN B AC BUS 1J DC BUS 1B E4801J E1B LPI-MDP-FS-SIV. LPl-a<V-OO-CV58

LOW PRESSURE INJECTION TO HOT LEGS (LPl~-1LG)

LPI401 INSUP FLOl'I' TO li0V1B90A. FROM L W HEAD SI TRAIN FAl.URE OF 480J FAlURE OF 12CN AC BUS 1J DC BUS 18 LP 601 E4801J E1B INStFFlCIENT 1 ST AND W.NTEW.NC FLOW FM U-lSI 18 ON l.P1 MDP S118 DUE TO BACKA..OW LP 81 W.-S118 LPI-MDP-FS-Sll~ LPI-CKV-OO-CVS8

LOW PRESSURE RECIRCULATION TO RCS (LPR-LH)

(HAS)

LPR4 lPR9 Lf'Rtt llllUJ't at """

.A.O lhn 1B

[4801i PAGE 1

LOW PRESSURE RECIRCULATION TO RCS (LPR-LH)

(LPR4) now TO COLD Ll:Ol!I

• Dt ITCJPPIZI

!Bl

[12 [H1 PAGE 5

LOW PRESSURE RECIRCULATION - TO RCS (LPR-LH)

(LPR9)

Elt2 PAGE 2

_j

LOW PRESSURE RECIRCULATION TO RCS (LPR:.-LH)

(LPR 10)

PIPE SEGMENT PS33 FALA.TS NSUF A..OW DLE FALLIRE CF 4BOV FAR.URE OF 12CN TO BACKLEAKAGE AC BUS1J DC BUS 18 THRU MOP SI-V.

E4601J E18 MA-Sl18 LPI-MDP-FS-SI\<\ LPI-CKV-00-GVSB

LOW PRESSURE RECIRCULATION - TO RCS (LPR-LH)

(LPR 11) 8 00 IIIT-ACT-1.l-Rlff8B

• PAGE 4

LOW PRESSURE RECIRCULATION TO RCS (LPR-* LH)

(HAS)

SUMPPLUC LPR4 PPE SEGM:HT PSJZ fAlLTS LPRl1 LPR10 LPR9

'I'll

£48011 )lA-SIIA LPI--0\\1-00-<.VM LPl-1.0P-FS-Sltl

\.

LPI TO HOT LEGS-RECIRCULATION MODE (HASHLG)

HASHLG LPR900 LPRO LPR100 LPRll LPR901 LPRO LPRiOJ LPRLL

LPI TO HOT LEGS-RECIRCULATION MODE (HASHLG)

LPR100 PIPE SEGt.£Nr PS33 FAU.TS FAURE OF 120v TE AW IMMEl'll.NCI':

DC BUS 18 ON LPI MOP S119 W>.-SIIB E4801J E18 LPH.ICl'-fS-SI\I. LPI-CKV--OO--<:V58

LPI TO HOT LEGS--RECIRCULATION MODE (HASHLG)

LPR101 PPE !:EGMENT Ps;l3 FAULTS LPHJDP-FS-SIV. LPI-CK',/-OO-C\156

LPI TO HOT LEGS-RECIRCULATION MODE (HASHLG)

LPR800 PIFE SEGfJENr PS32 FAU.TS 1[

E4801H LPI-CKV--OO-CV50 LPH.ICJ'-FS-51 IB

LPI TO HOT LEGS-RECIRCULATION MODE (HASHLO)

LPR801 PlfE SEGijENf PS32 FALi.TS TE E4601H rn W.-511' PAGE 1 LPI-CKV-00-CV50 lPHJCf'-fS-SIIB

LOW PRESSURE RECIRCULATION. - TO HPR* (LPR-HH)

(H1)

PAGf:. 1

LOW PRESSURE RECIRCULATION TO HPR (LPR-HH)

(LPR-H.HA)

PAGE 1

LOW PRESSURE RECIRCULATION TO HPR (LPR-HH1)

INSUF FLOW ROM LPSJ PMP lRN A TO Mr:N 1863A LPR HH1 INSUFFICIENT NSUF FLOW FLCfN THROUGH THRU PS37 OR EGMEt-IT PS32 PlRN FALI.RE TO ISOL A PS30 LPR-HH~ LPR-HH3 W--SJIA PAGE 2*

LPI-CKV-OO-CV50 LPJ-MDP-FS-S\18.

LOW PRESSURE RECIRCULATION TO HPR (LPR-HH)

(LPR-HH2)

INS\F FLOW M LPSI PMP TRN B TO M[}I 18~B LPR HH2 ltslFFICIEHT flr::JN FROM LPSI PMP TRN B FALURE OF 120V FALURE OF 48fN DC BUS 18 AC BUS 1J EIB PAGE :4" LPI-CKV--00-C\158 LPI-MDP-FS-S111.

LOW PRESSURE RECIRCULATION TO HPR (LPR~HH)

FALURE Cf' 120\/ FAl.URE OF 480\/

DC BUS 1'. AC BUS 1H E4601H LPl-1ADP-FR-A24HR

LOW PRESSURE RECIRCULATION - TO HPR (LPR-HH)

(LPR-HHS) g 0

PAGE 3

LOW PRESSURE RECIRCULATION TO HPR (LPR-HH)

(LPR-HH2)

LPR-IH!

fALU!( OF" l2C¥ oo lllfl e

[Ii E<IIOU PAGE 4

LOW PRESSURE RECIRCULATION TO HPR (LPR-HH)

(LPR-HHB)

LPR-lt£ PAGE 6

LOW PRESSURE RECIRCULATION - TO HPR (LPR-HH)

(LPR-HHE)

PAGE 1

LOW PRESSURE RECIRCULATION TO HPR (LPR-HH)

EJ2 LPIH.ICW-FT-1!!112B LPR-CCl'-FT-B!VII Ll'R-<:Cl'-FT-680,l,8 LPR-<:K\I-FT-CV~7 RMT-<X:f-FA-USCII.

• Appendix C.11 Primary Pressure Relief System C-235

FAILURE TO CLOSE BOTH PORV (PORV1)

FALU~Q.Ct;E EIA FALTO a.DS£ PPS--S<1,'--00-'1455C PORil PATH r~Jg.Q.OSE E1B FPS-5DY-00-1.o6 PPS-OCF-fT-Pal'I FPS-CX>"-fT-15358 FPS-MDY-00-153B

PORV FAILS TO OPEN ON DEMAND (PORV2) 1AILl1RB OP PDRY TO OP.BN' PO l'Pill:-AaV'-OC-J'iCl~C fPB-MOT'-PO-JG34:i pa"? pathwa, oJOH4 PPS-MOV-PT-1.!118 PPs-eov-n-us,c

.... POll\'-1',!.Tll-t:Lllll

PRIMARY PRESSURE RELIEF 1 OF 2 (P 1)

(P 1)

INSlFFICIEITT n DW THROUGH PIPE SEGMENT PS131

~

PPS-OP-SBT-SD 00 HOUBB-POB3l3 f ALURE Cf" 120V OC BUS 16.

E1B fJA-1455C PPS-tJDV-l'C-1535 PPS-MDV-l'C-1536 rALURE or 48CN AC MCC 1H1-Z PAGE 1 & 2 EH2

_J

PRIMARY PRESSURE RELIEF 2 OF 2 (P)

(P)

POff/ B.OCIC 11.V

¥IP~

PPS-Ml'/-F0-1!5.JS EH2 PAGE 1

PRIMARY PRESSURE RELIEF ATWS (P2)

(P2)

PAGE 1 & 2 w

TEST AND MAINTENANCE ON PORV 1455C

TEST AND MAINTENANCE ON PORV 1456 PPS---1111-t!Sll

Appendix C.12 Recirculation Spray Systems C-243

INSIDE SPRAY RECIRCULATION (ISR)

(F 1)

E~l!OIH SUIIPPLUO SWS-MJt'-P<l- ~

SWS12 SWS1J

~

Q_

c.n w

0 c.n z

C-245

INSIDE SPRAY RECIRCULATION POS 1,2,14,15 POS 3-13 TRAIN A TRAIN B DUE AL LEVE NOT HOUSE POS 3-13 (J

N

.i:,. HOU6E-NOT-P06313 I6R1N115 1SRi!N110 HOUSE-POS313 0\

MCW-CCF-VF-SBO nrn-TRA-MA ISR1N313 L06P HOUSE-SB01 HOUSE-SB02 HOUSE-LO SP

E4!!01H BIIXPPLUO WS-NCW-l'0-100,I.

SWS9 SWS-1<<:N-<P-RSFP SWS1Z SWS1J

INSUF COOLING a:" PIPE SEGMENT Containment PS60 FLOW Sump Plugged ISR-1.CP-OP-\A.8 E4B01H SUl\ll'PLUG EIA

() MCW-CCF-VF-IN..VL

~

00 FALURE OF MCC 1H1-2 INSUFFk:!ENT i'>ISUF FLOW LOW THROUGH PIPE THROUGH PIPE SEG SEGMENT PS67 PS66 TO HEADER A SWS-MOV-OP-RSS SW5-MOV-PG-10fA SWS-MOV-PG-105A EH2 SWS9 SWS10 P88 KFX INSUF FLOW THROUGH PIPE SEG PS69 AND PS70 Sl'B-MOV-PG-1061' SWS-MOV-PG-1068 INSUFFICIENT INSUFF~IENT OW THROUGH PIPE LOW THROUGH PIP£ SEGMENT PS 69 SEGMENT PS7Q,*

SWS12 swsu

INSIDE S.PRAY RECIRCULATION (ISR)

(ISR2)

NO SDWI. FOO.I Q.CS llWN B E-!80\J a.5-ACT-CP-<2S2

~

\0 NSlF FU1//

~J~f'I.

SWS-M:JY-PO-ll5B BJll CUI-AnT-P.A.-C.&211 fffl'&-WOV-C>-1!!:PP' IHSlfrC[NT' n.~-~Jalt

~10 PAG(6

POS 1,2,14,15 POS 3-13 TRAIN A TRAIN B POS n NOT 3-13

~

HOUSE 0

POS 3-13 0SR2N11B HOUSE-POS313 HOUSE-NOT-POS313 0SR1N11B RAIN A OSR,-TRA-MA MCW-CCF-VF-SBO LOSP HOUSE-SB01 HOUSE-SB02 HOUSE-LOSP

INSITTICEITT OW /COctlNG FROM POS 1,Z,14,15 g PIPE SEG PS71 NSITTCENT" INSl..fFICENT INSITTICEITT COO.ING OF PPE FlON IN PM' TRAN 00/COCUNG fROt.4 EG.EITT PS71 fl(m A OF PS71 Plf>E SEG PS71 SWS5 OSR5

INSLfflCEITT POS 3-13 OWICOCt.lNG FROM PIPE SEG PS71 OSRl 313 INSLfFICENf INSl.f'FICEITT NSl.f'FICENI' FUJII IN PM' TRAN OW/COOJNG FROM COO.ING OF PPE A OF PS71 PIPE SEG PS71 EG.ENT PS71 FLOW OSR5

INSU'FICENT INSUFFICENT INSU'FICENr CO<X.JNG OF PPE FlOW IN Pt.fl "TRAIN ow/coa..m FROM B OF PS72 Pff: SEG PS72 EGI.EITT PS72 FlOW SWS6

OUTSIDE SPRAY RECIRCULATION (OSR)

(OSRS)

FICIENT FLOW COOLING FRO Pl~ E SEG PS71 NO CLCS DOESITT START FALURE OF 480V OPER ACT'N OF OSR OSR FAUJRE OF fl.CN IN POS 3-t3 TRAIN A DC BUS 1A. AC BUS 1H E4801H Containment NOT Sump Plugged POS 3-13 0SR~MDP-OP-2A8 QS-ACT -OP-CLS2 SUMPPLUG HOUSE-POS313 HOUSE-NOT-POS313

OUTSIDE SPRAY RECIRCULATION (OSR)

( OSR6.)

INSUFFICENT FLOW/COOLING FROM PIPE SEG PS72 ACTUATION FM.lRE OF 120V FAl.l..RE OF 460V NO OF£R NT TRA.IN B DC BUS 18 AC BUS 1J OSR POS J-1J E18 Containment NOT Sump Piuiged POS J-13 QS-ACT -OP-QS2 OSR-MDP-OP-2AB HOUSE-l!OT-POS:ll:l SU!IPPLUO l-00SE-POS3 13

(c;SMS)

(c:1SO) NOl1Vln:JcJl:J3cJ )-.'v'cJdS 301SlnO

OUTSIDE SPRAY RECIRCULATION (OSR)

(SWS6)

PAIT.URE OP EST ANO MA.INTENANC MCC 111-2 ON SWS MOV 104D MA.-lOID POB 3-13 INSUFFICIENT INSUFFICIENT INSUF FLOW OW THROUGH PIPE LOW THROUGH PIPE "THROUGH PIPE SEG SEGMENT PS67 SEGMENT PS68 PS6S TO HEN)ER A CLS-ACT-PA-CLSaB SWS-MOV-OP-RSFP SWS-MOV-OP-RSS HOUSB-POB313 HOUEJE-NOT-POS313 SWS9 SWS'IJ SWS-MOV-PG-106"' SWS-MOV-PG-!068 INSUFFICIENT CN/ THROUGH PIPE SEGMENT PS70 SWS12 5WS13

TEST AND MAINTENANCE ON SWS MOV 1040 g

00

OUTSIDE SPRAY RECIRCULATION (OSR)

(SWS9)

INSUFFICIENT LOW THROUGH PIPE SEGMENT PS67 NO CLS SIGW\L NO OPER OPENING FAR.URE OF 480V AND OPS DON'T T ST AND W.iNTENA.NC OF RS SW MOVS AC MCC 1H1-1 OPEN RS SW MOVS ON SWS MPV 103A EH1 MA-103A POS NOT 3-13 POS 3-13 SWS-MCN-OP-RSS SWS-MOV-OP-RSFP CLS-AGT-FA-CLS2A HOUSE-POS313 HOUSE-NOT-POS313

TEST AND MAINTENANCE ON SWS MOV 103A OUTSIDE SPRAY RECIRCULATION (OSR)

(SWS10)

INSLfFICENT Fl.OW TffiOUGH PFE SEGMENT PS68 OPERS DON'T OPEN l'O Q.S SK;NAL At-o RS SW t.10t'S FALURE OF 4BOV OPERS DON'T OPEN ACC MCC l.Jl-1 RS SW MCNS EJ1 POS. t-KJT 3-13 POS 3-13 SWS-MOV-OP-RSS SWS-MCN-<P-RSFP QS-ACT-FA-QS2B 1-0USE-POSJlJ /HOIJSE-POSJ13

INSIDE SPRAY RECIRCULATION (ISR)

(SWS12)

P~4

• INSIDE SPRAY RECIRCULATION (ISR)

(SWS13)

INSUFFICENT L<:J>N THROUGH PIPE SEGMENT PS70 I'¥) OPER I'¥) QS SIGNAL OPENING Of RS fALURE Of 480V AND NO OPER

~ MOVS AC MCC 1H1-1 CPENNG OF RS EHl POS NOT 3-13 POSE 3-13 SWS-M'.JV-OP-RSS SWS-MOV-Cf>-RSFP QS-ACT-FA-QS2A HOUSE-POS313 /HOUSE-POS313

Cotainment Sump is Plugged( causes failure of rec1rcu\ation) antainment Sum Plugged Time Window Time Window 2-House Evenl 1-House Evenl WINDOW2 LPR-CCF-PG-SUMP2 WINDOW1 LPR-CCF-PG-SUMP1

• Appendix C.13 Residual Heat Removal Systems C-265

FAIL URE OF RH.R SYSTEM TO COOL REACTOR, 10F2 (FT W3)

Inaurr Flow From Segment P 9, d1sch to Loop 3 RHR3 CHECK VALVE RHR MCJ\/ 1720A. COMMON CAUSE lnsurrtolent Flo O{ si 130 FALS FAILS TO OPERATE FAILURE Of RHR Loss of Power ro*m RHR HX Hea er TO OPEN ON DEMAND. MOVS 1720A, 17209 ~l ldCC1H1-2 EH2 RHR4 ACC-CKY-FT-CV130 RHR-MCN-FT -1720A RHR-MOV-PG-1720A RHR-CCF-FT-720AB MA-1720A

TEST AND MAINTENANCE ON RHR MOV 1720A

INSUFF FLOW FROM SEG PS9, DISCH TO LOOP 3 (FT W3)

Cl-£0< VALVE COM.ION CAUSE 0/ SI 147 FALS FAll.flE CJ'. RfR TO Cf'EN. M<NS 172M,17200 RHH EJ2 ACC-CKV-PT-CVH7 Rl-fl-MOV-FT -17208 R!-fH.<<:N-PG-17208 RI-R-CCF-FT-72Q/>.B

RHR4 1Ht-mt--co-1n1 LI. ... CCJ'-Lr-D'AII:

LODI l!IJI ecw

'l"O Ml II 1.

IBA.-:Dr\"-PJ'-IY.'.() 111m-JWT-1f-rl'U

RHRB RHI-X'IM...fO-X'/2 ~R-<:<T-FS-LOP>JI CSTII\I ....,.

Maintenence of RHR Pump 8

RHRMOD TBL1 MAINTENANCE OF TEST AND MAINTENAN E r r-aov-co- RHR PUMP B N RHR MOV 1120A rhr-xmv-ft-xv20 rhr-xmv-ft-xv24 MA-RHR1B MA-17ZOA HOUSE-RHR5A

RHR11

RHR14 EH2 RIR tJfN 1700 Rt-ft MOTOR OPER RtR l.r:N 1701 FALS 10 CffRAlE )ILVE 1701 PLUGGED FALS TO OPEN ON OEMAJ-0 ON CfiWD RHH!OV-PG-1700 RHH!OV-fT-1700 IMHIOV-f>G-1701 RHH,!OV-fT-1701

W3-S Loss of RHR POSs 3-13 W3-S lnsuff Flow from Segment PS9 Disch to Loo 3 RHR3-S T ST AND MAINTENANC CHECK VALVE Loss of Power ON RHR MOV 1720 CV si 130 FAILS lnsuff Fl0.w at MCC1H1-2 Thru SegmBnt TO OPEN PS 7, HX Disch Hdr Mi\-1720A EH2 RHR4-5f ACC-CKV-FT-CV130

RHR3-S CHECK VPJ..VE CV SI 147 FAILS TO OPEN.

RHR4-S ACC-CKV-FT-CV147

RHR4-S Insufficient Flow from RHR H header IWD llJ..007-LP-Dl'AI*

........ IHHM.H>O-XVII uu-*

RIR-lMl-f'C-MI ffllHIIX---PO-EB

• • 11.-:cn--rr-S:V!IQ am-J:tff-rr-nu

RHR8-S RlfH><V-rT-CV! IHH.(P-F5-IHIII lilll&-WDP-M4-UID.l!I rgau [18 Rtfl-Q(V-00-CVl1 RHl:-XW-PG-XYO

RHR11-S

[fl ESTBfl

Appendix C.14 Service Water System (The Fault Trees for the Service Water Components are included in the Fault Trees of those systems that depend on Service Water)

(See App. C.3, C.4, C.8 & C.12)

• C-280

Appendix C.15 Steam Generator Recirculation and Transfer System C-281 I

SG RECIRCULATION 2 OUT OF 3 (SGRT1)

IOff O mHA ,.1.n.vn P.uLVU IICIH-IIO<J IICIHI

ALL SG RECIRCULATION FAILED (SGRT2)

ICRT A HlLID SCRT I PA !LID OIi 01 ll'ca,BIIATIOWI.L IJl'OPmATIOltA.L 8GRT C PAO.trRI l!(IRT C unn lL OOHA 80JIT-804

• • - 9QDTC IORT-SIOC

SG RECIRCULATION AND TRANSFER SG A (SGRTA)

JUIOIICUIATI0'11' TA0.9 1!1GllT2& CCWB 80RT-JHB-P8-l00

SG RECIRCULATION AND TRANSFER - SG B (SGRTB) w1un>a r.L1L1S TO .UIGJ toH lff91'!Dll IOT2"

SG RECIRCULATION AND TRANSFER SG* C (SGRTC) n N

00 O'I ccwa SOlliZC SORT-xm:-'9-100

SG RECIRCULATION SYSTEM SG A (SGRT2A)

N PLOW 'OPSTRJ!AM OP HTX RT-BIA SGR SA SGRTU BORT-HTX-PO-BlA. SOHT-llTX-LX-EiA SORT-RT.J:-UA-l!IA CC IA 1Jff& ILABJ.J; LOOP DOtl:5!:-LOm' ...

SOIIT-CKV-PT-IITH SOIIT-PlJP-FR-IITiA BORT-PllP-1'8-RTIA BORT-PIIP:-l!A:-RTLA

SG RECIRCULATION SYSTEM SG (SGRT2B)

N now OP:!IT!IMJ,(

OP HTX llT-J:lD SGR SB BORT-HTX-PO-BIB SORT-RTX-LK-EIB BGRT-HTX-llA-Blll CC IA UNA. !LULE LOOP DOUB!.-LOl!P B0BT-CKV-PT-BT90 SOBT-PllP-FR-BT 1B SORT-PJJP-FB-RT 1E B0RT-Pl,IP-l(A-!lTlll

SG RECIRCULATION** SYSTEM SG C (SGRT2C)

N l'LOW UP.STRl!Ali OP HTX llT-lliC SOR SC sanr,c B0RT-HTX-P0-B1C BORT-BT:C-LK-EIC BORT-RT:c-llA-BiC ICC 1A UNA. ILABLE LOOP DOU:11:-LOSP B0RT-CKV-PT-RT4D BORT-PllP-Jl'!I-RTIC BORT-PllP-Jl'S-RTIC SOR'l'-PllP-llA.-RTIC

SG RECIRCULATION SG A (SGR.T4.A)

IrnmlllD V.U.Y!I OOTEIOARD VJJ..V a.omsn CLOSm e:GRT-NT-PG-BD1 8GRT-lff'-PG-8D2 BOIIT-M'T-PCJ-BJ>t.

ea <<A m-JJ.!1 OOMT/.UW-!Orl DU BORT-AOV-PQ-1001 80D.T-AOV-L~-IOOA 90h'l"-AOT-OC'-1Ml P.LnJ,1RII OP l2D .T/1.C VrrAJ. BQll II tl-lAB COKT/M"'fl'-BG?I' ri_iJI 90RT-J.OV-Llt-lOOB 9[JRT-.1.ffl/-0C-IC0B

SG RECIRCULATION SG B (SGRT4B)

OOTbCIARD VJJ.V Cl.081:D 8GRT-lff-P0-BD1l 80RT-llV-PO-BDL2 IIORT-ICV-PO-!JDH SO <z+

aa HC o-u..s !U

!OQT-AOV-P0-1008 !OkT-AOV-LX-IOOII !ORT-AOY-00-1008 JHgi"ROhlXHT A.CR LliX AT TV-BD-100,

• u

[1-L.\8 SDRT-AOV-u.:-IOOP SORT-.lCN-OC-lOOF CO'tIT/il"ff-BGK C,UI

Appendix C.16 Steam Generator Secondary Relief System

• C-293

SECONDARY SIDE HEAT REMOVAL FOR REFLUX COOLING WINDOW 1 (SSHW1)

SGB-DAAN:0-R SSHR5 SSlfl6 SSHRIB S5Hl19 Ssttl/\6. ssimo 9SHR-AOV'-XHB-1D9 9SHR-AOV'-XHB-1D~

SECONDARY SIDE HEAT REMOVAL FOR REFLUX COOLING WINDOW 2&3 (SSHW23) 2 3

(')

~ ~

I FAllf£ 0 TIile N B't!'ASS

\0 Vl 1:t SOHRIIIED-R SOC..m'ANED-R POS--01 SSHR3 ~ SSHRI I

SS!IR7

~~w~fi!

TI) 1£/aR S5m1! SSH\111 SSH\!\\ SSHR1l SSHR2Q SS!MII SSHR-AOV-Xl£-"m SSHR-AOV-X1£-m SSHR-AOV-Xl£-m

SECONDARY SIDE HEAT REMOVAL FOR REFLUX COOLING WINDOW 4 (SSHW4)

_c:  :::J.._

~ "-7"'<:-

() SG D-Cl!Al!ED FALtre <F HFAT FALIJ£ ClF r£CAY FALIJ£ 0 TlRBHE

~

IM'AS9 IE~OOH .Jm~

O'I SS>>R2 SGA-OW!ED-R

_c l SGIH:11/JIED-R

___c SS~ SGC-mANm-ff POS-Oa

~ ~

• .FALMSO

....,..,... ~

SSHR, SSHRa . . SS1l!7 Nl~ffl tt= rt::,:

TI> IEJCER Dum> lo Oord>rw,r SS1111! SSIIW?. SSIIRD SSIIR20 SSIMI\

SSll{---Xl£-ffl SS!§l-A<7"-Xl£-ffl SSIII-AllY-Xl£-ffl

• SECONDARY SIDE HEAT REMOVAL FOR REFLUX COOLING (SSHW 1A) failure ot bypass condenser unavailable CJR-COND-UNAVLBL cc tallure or bypau VD.Ives PCS-CCF-FT-TRBYP Not Loe of Air TIA-CSD HOUSE-AIR

SG A STEAM PATH FAILURE FA URE OF NON-RETUR VALVE TO OPEN

(') FALURE OF W.IN I STEAM TRIP WJ...VE FAILURE OF BF"/

N TO OPEN OB4 TO OPEN

\0 00 OSS OF INSTRUMENT MST -A BF"/ 08~

AIR MST-A BPV OB4

• TEST OR PLUGGED MAINTENANCE rn-cso MSS-XVM-PG-084 MSS-XVM-W.-084 MSS-CCF--f'G-XVM '.IISS-XVM-XHB-BYPS

• SG B STEAM PATH FAILURE CF lllH-llETU N VN.VE TO 1:FEN nI N MSS-lfl\l-FT-118

\0

\0 r>UIIE CF W.H STtAM fllP V>LW::: fAWl'tf OF WT-!I 10 QPfH gl'-/ 11!!i TO a::tN USS-JMJ.l)Q-11&

SG C STEAM PATH FAlURE Q

w 0

0

SG A PORV FAILURE TAU.UR! OP llO PORV nI LDSS 07 nratRUMCl:T A[R w

0 JUSTL09P !ll.lt-vrr-BUS ll88-AOV-PT-iOU. IISS-A<W-PO-IOIA K8B~CP-r?-01ABO llSS-AOV-PO-IOlA SO A UJl.lV .I.ILABlll 8G A POW IN TB!J? OR l'lllll IIIDUCCD lLl.11lTBliJ.HC3 l!PUlllOU!

H,ILURD MSS-AOV-WA-10lA n-1>--v-10"

!O.l-mu.nnm-Jl

SG B PORV FAILURE J'AILURB 01' !10 PORT

!IG 11 POKY oc PJ,D..UR.B or SO D l'Ol!V

~lOOlllD LDSII 01' PAILUJUI Ot rt.UOOBD no i, raev lll!IID.UMC!JT Am BIUt:l-VlT>J. IDB JR'STlDSP 1108-AOY-PT-IOIB IIBS-AOV-l'CI-IOIB ll8S~CP-J'1'-0lil0 IIBS-AOY-PC-IOID rm 1*DUC11D SCI 9 POl!1' OI '11191' DR l!Pll!IIOU3 PJJLUJIJI SU..llfTtlfAll'C!l FI-O-V-101\ 1188-AOV-IIA-IOJB 1101-DR&ll'n:D-II

SG C PORV FAILURE FAO.UR!I oP 1!10 PO!\T U19Tl09P SB~-VJ'l'-BUB w:ee-<:a-rr-oIAM MSS-AO'Y'-PC-LOLO nu 1mrocm sa o PORV IIPUbJOOS 1H 'J'Bff CR J'.A!LU.lll! MAUl'TCIIAlfCJ; fl-D-V-IDI'. .----s,-Lo---=o---, IISS-AC!V-IL!.-1010 11114IJ<m SOO-DllAlllBD-11

LOSS OF INSTRUMENT AIR h0l.6E MNr L2 klltl1lrwa LOSS Cl Cf'Srtt: [*uni.

IWfR ft--LHlHt-S Hcust-t.<JSP ft-1.2-XHC~ HCUZ-U

Appendix C.17 Consequence Limiting Control System

• C-305

Consequence Limiting Control System Train A

(')

I lll 0

0\

NO SIGN/II.. FROM a.cs lRAN A O..S-ACT-FA-OS2A

CLCS-B NO SIGNAL FROM a...cs TRAIN B E18 CLS-ACT-FA-CLS2B

Appendix C.18 Reactor Protection System C-308

FAILURE OF RPS TO SCRAM THE REACTOF K

Appendix C .19 Recirculation Mode Transfer System C-310

Recirculation Mode T rorisf er System Train A N:'.> SIGN4.L FROM COMMON CAUSE RI.ITS TRAIN A FALURE RI.IT OLE TO MISCALIBRATION RI.IT-ACT-FA-RMfSA RI.IT-CCF -FA-MSCAL

RMT-B RMT-B

(') .

I

~

N NO SIGN/'.L FROM COMMON CAUSE RMTS TRAIN B FALURE RMT DUE TO MISCALBRATKlN E4 Hv RMT-ACT-FA-RMTSB RMT-CCF-FA-MSCAL

Appendix C.20 Safety Injection Actuation System C-313

Safety Injection Actuation Syst_em Train NO SIGW.. FROM 515 TRAN A E11 E1' SIS-ACT -f'A-Sist..

Safety Injection Actuation System Train B NO SIGNAi. FROM SIS TRA~ B SIS-ACT-FA-SISB

APPENDIX D Statistical Analysis of Time to Mid-Loop and Duration of Mid-Loop

• • D-1 I

APPENDIX D STATISTICAL ANALYSIS OF TIME TO MID-LOOP AND DURATION OF MID-LOOP PAGE Appendix D.1 Bayesian Analysis of Time to Mid-Loop . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-3 Appendix D.2 Bayesian Analysis of Duration of Mid-Loop . . . . . . . . . . . . . . . . . . . . . . . . . . D-12 Appendix D.3 Recovery Curves for Accident Initiating Events . . . . . . . . . . . . . . . . . . . . . . . . D-16 Appendix D.4 Assessment of Uncertainty Parameters of Basic Events . . . . . . . . . . . . . . . . . . . D-23 D-2

APPENDIX D.1 Bayesian Analysis of Time to Mid-Loop

• D-3 I

D.1 Bayesian Analysis of Time to Mid-loop This Appendix summarizes a Bayesian analysis of three quantities:

• the time-to-mid-loop (POS 6)

• the time-to-second mid-loop (POS 10)

• the duration of mid-loop (POS 6 and POS 10)

Note that in all three cases, the random variable is assumed to be a shifted Iognormal, i.e., the time to mid-loop T = t + t', where t' is the lower bound for T and t is lognonnal distributed with density function given by (using the T50,q formulation) exp{.!.(ln(t/TsJl l 2

1

~at 2 a r The following lists the time shift for each of the POSs:

POS t' Pos 6 - Refueling outage POS 6 - Drained Maintenance Pos 10 - Regulating outage 2 days 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> 2088 hours These times were estimated using the operating procedures and past plant experience. The rest of this appendix deals with the distibution oft and shows the results for T. Reference [1] is a paper that documents the method used in the analysis in more detail.

TIME TO MID-LOOP DISTRIBlIT.ION Data for the time to mid-loop consist of population data and Surry-specific data. Regarding ~he former, it is assumed that the time-to-mid-loop for each plant is lognonnally distributed with parameters µ and u, and that these parameters vary from plant to plant. The population data (generally) consist of experts' "best estimates" and "lower bounds" for each plant-specific distribution. (In some cases, only a "best estimate" is provided.) The "best estimates" are interpreted as medians; the "lower bounds" are interpreted as 5th percentiles.

1) First Stage: Population Variability Sudace for T51 and" Likelihood Functions:

Assume T50 and a are independent, lognormally distributed parameters. Then (for the ith plant):

D-4

Prior Distribution (1st Stage):

Data: Table D.1-1 Posterior Distribution (Characteristics):

J!st "!ill µ.,. a,,

Mean 4.1438 0.4971 -0.5776 0.7729

• Expected Population Variability Surface:

gl (T50) : JIf(T I 50 Jlse,flso}'ff'1 (p.so,U so)dp.50du50 g1(a) = fff(a Iµ.,,a,)T1(µ.,,u,,)dµ,,du,,

(Note that the f(*) are based on JI and a, rather than T541 and u.)

2) Secoad Stage: Ezpeded Distribution for Tune-To-Mid-loop The analysis distinguishes between refueling outages and drained maintenance outages.

Likelihood Function:

For the ith data point from Surry,

• D-5 I

Prior Distribution (2nd Stage):

Expected Distribution:

Refueling Outage:

Data:

Event Date 'ltme (h)

R 02/83 184 R 06/83 293 R 02/84 88.1 R 09/84 161 R1 (Unit 2) 03/20/85 239 R2 (Unit 1) 05/10/86 91.9 R3 (Unit 2) 10/04/86 100 R4 (Unit 1) 04/09/88 174 RS (Unit 1) 09/14/88 315 R6 (Unit 2) 09/10/88 203 Expected Distribution Characteristics (see Figure D.1-1):

Meanl91 5th78.7 S0thl55 95th422 D-6

Drained Maintenance Outage:

Data:

Event Date 'lime (h)

D 10/82 121 D 12/82 44.0 D 06/83 24.0 D 09/83 106 D 12/83 42.1 D 12/83 27.9 D 03/84 37.6 D 10/84 82.S Dl (Unit 1) 04/29/85 94.8 D2 (Unit 1) 08/06/85 105 D3 (Unit 2) 10/29/85 61.S D4 (Unit 1) 01/24/86 74.8 D5 (Unit 2) 06/17/86 53.3 D6 (Unit 1) 12/11/86 276 D7 (Unit 2) 12/09/86 1282 D8 (Unit 1) 05/16/87 74.9 D9 (Unit 1) 06/23/87 53.7 DlO (Unit 2) 12/09/87 184 DU (Unit 2) 05/16/88 291 D12 (Unit 2) 10/12/89 403 Expected Distribution Characteristics (see Figure D.1-1):

Mean190 Sth27 S0th10S 95th618 TIME TO SECOND MID-LOOP (POS 10) DISTRIBUTION

• D-7 I

Only Surry-specific data (3 points) are available. (Note that this POS is relevant only for refueling

• outages.) A straightforward Bayesian approach is used.

Eqieded DisCributioa f(t) = fffy(tl 11,~)1r1 (µ,u)dµdo Data Event Date 'lime (h)

R1 (Unit 2) 03/20/85 1909 R3 (Unit 2) 10/04/86 934 R6 (Unit 2) 09/10/88 2905 0

7.7276 0.53473 Expeded Didribution Characteristics for T Mean2619 5th942 50th2270 95th5471 D-8 *

• 930902 best f(T)s ch PDFs for Time to Midloop Distributions Given Population and Surry Data 0.01 given population data given pop. and Surry data (20 drained maint. outages only) 0.008 given pop. and Surry data (all 30 outages 1982-89) given pop. and Surry data (1 O refueling outages only)

I I \

I I

0.006 I I I t1 I

I I I

'° I I

\

I I

0.004 I I I

I I I

I I

I I

0.002 0 JJL~*j:~-1----+-.:........-~=~-:-:* -~--=-=-===*---=---=-.- - - -

I -=* - - - - - - - - - - I; '

~~~~~~iinim,:iiiimii~.....,;;;;,;;;;.=mJ-=-~L~

0 100 200 1 I

• 300' 400 500 . 600 700 800 \ 1900

\

Time to Midloop [hrs)

Figure D.1-1 Distributions of Time to Mid-loop

Table D.1-1 Population Data on Time to Mid-loop Based on Responses to Generic Letter 87-12 Plant# Median(hr) Sth(hr) 9Sth(hr) 1 84.6 74.8 2 66 3 72 4 72 24 s 48 6 56 7 48 8 77 9 120 10 33 11 30 12 44.S 13 48 14 121 15 72 16 72 17 52 18 96 19 48 20 99 528 21 65 22 147 76 23 so 24 72 25 120 26 23 27 14 D-10

• Plant#

Table D.1-1 (continued)

Median(hr) Sth(hr) 9Sth(hr) 28 48 24 29 53 30 42 31 34 32 120 48 33 106 34 144 35 50 144 36 51 37 48 38 116 39 56 16 40 168 72 41 44 42 30.5 43 54 37 44 108 45 69 46 161 The population data for the time to mid-loop were collected from responses to NRC Information Notice 87-12. The plants were asked to provide information on their time to midloop experiences. The plants provided "typical," minimum and maximum values of the time to mid-loop. In this analysis, these have been interpreted as median, 5th percentile, and 95th percentile values.

• D-11

Appendix D.2 Bayesian Analysis of Duration of Mid-Loop D-12

D.2 Bayesian Analysis of Mid-loop Duration MID-WOP DURATION DISTRIBUTION Only Surry-specific data are available. Analyses are done for refueling outages and drained maintenance outages. In the case of the former, POS 6 and POS 10 mid-loops are distinguished. A straightforward Bayesian approach is used.

'7To(µ,u)oo_1 u

~ Dimihutioa r<t> = IIfy(tl 11,0)1r1(µ,u)dµc1u Refueling Outage, POS 6 Data.:

Event Date Time (h)

RI (Unit 2) 03/20/85* 134 R2 (Unit 1) OS/10/86 61.7 R3 (Unit 2) 10/04/86 41.6 R4 (Unit 1) 04/09/88 79.4 RS (Unit 1) 09/14/88 100 R6 (Unit 2) 09/10/88 681

µ Mean 4.714 1.146 5th 3.923 0.652

• D-13 I

50th 95th Correlation 4.710 S.513 0.028 1.046 1.999 -

• Mean238 Stb14.2 SOthl12 9Sth876 REFUELING OUTAGE, POS 10 Note that the expected distribution bas a reverse J-shaped pdf. Auxiliary MathCAD computations confirm that this is appropriate, even though the joint pdf is 11 and a is unimodal and well-behaved.

Event Date 'lhne (h)

R1 (Unit 2) 03/20/85 141 R3 (Unit 2) 10/04/86 52.3 R6 (Unit 2) 09/10/88 452 11 Mean S.021 1.593 5th 3.413 0.619 50th S.011 1.273 95th 6.656 3.798 Correlation 0.039 Mean444 Sth6.3 S0th1S1 9Sth2S68 D-14

• DRAINED MAINTENANCE OUfAG~ POS 6 Event Date Thoe (h)

Dl (Unit 1) 04/29/85 153 D2 (Unit 1) 08/06/85 42.S D3 (Unit 2) 10/29/85 79.4 D4 (Unit 1) 01/24/86 182 D5 (Unit 2) 06/17/86 191 D6 (Unit 1) 12/11/86 1072 D7 (Unit 2) 12/09/86 59.9 D8 (Unit 1) 05/16/87 144 D9 (Unit 1) 06/23/87 10.9 D10 (Unit 2) 12/09/87 28.3 DU (Unit 2) 05/16/88 206

• D12 (Unit 2)

Posterior Distribution Characteristics 10/12/89

µ ,,

266 Mean 4.692 1.282 5th 4.065 0.892 50th 4.691 1.232 95th 5.318 1.849 Correlation 0.001 Eq,eded Disaributioa Characteristics Mean.255 5thll.9 S0th109 95th9S8

• D-15

.: . /

Appendix D.3 Recovery Curves for Accident Initiating Events D-16

Appendix D.3 Recovery Curves for Accident Initiating Events The data that was used in estimating the frequency of initiating events show that the initiating event can be terminated by eliminating their causes. In the event trees, recovery of the following initiating events was modeled as top events in the event trees:

Loss of Offsite Power Loss of 4 KV Bus Loss of CCW Inadvertent Safety Injection Loss of Vital Bus Loss of Instrument Air Recovery of offsite power is discussed in section 4.3.1. The recovery of the rest of the above initiating events was analyzed using a single stage bayesian analysis. The computer code BAYES3D written by N.

Siu was used. The recovery time is assumed to be lognormally distributed. The prior distribution of the parameters µ and u is assumed to be inversely proportional to u. The likelihood function is the density function of the lognormal distribution. Tables D.3-1 to D.3-5 list the input data and results.

D-17

Table D.3-1 Statistical Analysis of Recovery Time of 4KV Bus Recovery Times of Loss Percentiles of Time of 4 KV Bus(minutes) to Recovery 1 9.00 Probability Percentile

(%) (minutes) 2 1.00 5 0.33 3 21.00 10 0.62 4 1.53 15 0.96 5 19.00 20 1.34 6 1.50 25 1.80 7 2.00 30 2.34 8 15.00 35 2.99 9 60.00 40 3.77 10 0.17 45 4.71 11 2.00 50 5.87 12 4.00 55 7.32 13 45.00 60 9.15 14 22.00 65 11.54 15 17.00 70 14.72 75 19.13 80 25.68 85 36.08 90 55.52 95 104.87 Mean=29.09minutes D-18

Table D.3-2 Statistical Analysis of Recovery Time of CCW Recovery Times of Loss Percentiles of Time of CCW (minutes) to Recovery Probability Percentile

(%) (minutes) 1 14.00 5 7.17 2 17.00 10 8.97 3 30.00 15 10.44 20 11.76 25 13.04 30 14.30 35 15.58 40 16.90 45 18.29 50 19.76 55 21.35 60 23.10 65 25.06 70 27.30 75 29.94 80 33.20 85 37.42 90 43.54 95 54.46 Mean =26.16 D-19

Table D.3-3 Statistical Analysis of Recovery Time of Inadvertent Safety Injection Recovery Times of Inadvertent Percentiles of Time Safety Injection(minutes) to Recovery Probability Percentile

(%) (minutes) 1 5.00 5 0.86 2 15.00 10 1.39 3 23.00 15 1.92 4 9.00 20 2.48 5 2.00 25 3.10 6 150.00 30 3.78 7 2.00 35 4.54 8 50.00 40 5.40 9 2.00 45 6.39 10 3.00 50 7.55 11 5.00 55 8.91 12 2.00 60 10.55 13 7.00 65 12.56 14 5.00 70 15.10 15 19.00 75 18.39 16 6.00 80 22.97 85 29.67 90 41.07 95 66.35 Mean=18.70 D-20

Table D.3-4 Statistical Analysis of Recovery Time of Loss of Vital Bus Recovery Times of Loss Percentiles of Time of Vital Bus(minutes) to Recovery Probability Percentile

(%) (minutes) 1 0.03 5 0.33 2 1.00 10 0.60 3 3.00 15 0.91 4 4.00 20 1.25 5 4.00 25 1.65 6 5.00 30 2.12 7 5.00 35 2.67 8 5.00 40 3.33 9 6.00 45 4.12 10 7.00 50 5.08 11 13.00 55 6.26 12 15.00 60 7.74 13 17.00 65 9.64 14 18.00 70 12.15 15 25.00 75 15.58 16 15.00 80 20.60 85 28.45 90 42.84 95 78.36 Mean=21.34

• D-21

Table D.3-S Statistical Analysis of Recovery Time of Loss of Instrument Air Recovery Times of Loss Percentiles of Time of Vital Bus(minutes) to Recovery Probability Percentile

(%) (minutes) 1 10.00 5 9.32 2 20.00 10 10.68 3 20.00 15 11.70 4 15.00 20 12.58 5 20.00 25 13.40 6 31.00 30 14.17 7 20.00 35 14.93 8 20.00 40 15.68 9 20.00 45 16.45 10 20.00 50 17.24 11 20.00 55 18.07 12 10.00 60 18.95 13 10.00 65 19.91 70 20.98 75 22.18 80 23.62 85 25.40 90 27.84 95 31.89 Mean=18.55 D-22

APPENDIX D.4 Assessment of Uncertainty Parameters of Basic Events

• • D-23

Appendix D.4 Assessment of Uncertainty Panuneters of Basic Events Frequency of Outages The uncertainty of the frequency of outages was estimated judgmentally. Table D.4-1 lists the characteristic parameters of the outage frequencies. In chapter 9, the point estimates of the frequencies were calculated at using the Surry plant experience. They are taken to be the mean frequencies of the outages. It was the Surry experience that the time between 2 refueling outages sometimes is as longer as 2 years.

Therefore, a frequency of 0.5 per year is quite possible to occur. It was taken to be the 25th percentile of the distnbution of the frequency of refueling. That is, the probability that the time between 2 refueling outages is longer than 2 years is 0.25. A lognormal distnbution is assumed with these parameters. In the case of drained maintenance, it is the plant experience that a unit may go to drained maintenance twice a year. Therefore, 3 times a year is taken to be an upper bound (95th percentile) of the frequency of drained maintenance.

Another parameter used in the quantification is the fraction(FRAC-POSlO) of time that the plant goes to mid-loop operation after refueling is completed in a refueling outage. The review of plant experience found that in 3 out of 6 refueling outages the plant went to the second mid-operation. Therefore, the mean of this fraction is taken to be 0.5. It is assumed to be uniformly distnbuted between O and 1.

Conditional Probability of a Time Window Given That the Initiating Event Occurred in a POS In order to correctly determine the success criteria for the mitigating functions, the time window approach was developed. Given that the accident initiating event had occurred in a POS, the probability that it occurred in a given time window was determined in section 9.3 using data colloected on time to mid-loop and duration of mid-loop. The uncertainty in the time when the accident occurs is reflected in the probabilities of the time windows. Therefore, the conditional probabilities of the time windows take on single values with no uncertainty parameter. They are listed in Table D.4-2 for the accident initiating events. For all initiating events except over draining to mid-loop(RHR2A), the distribution of the time when the accident occurs is calculated as the time to mid-loop plus the duration of mid-loop times an uniform distribution. For RHR2A, the time when the initiating event occurs is the same as the time to mid-loop.

Maintenance Unavailability Two types of maintenance events are used, the ones adopted from NUREG-1150 study, and those estimated using plant outage data. For those maintenance evetns of NUREG-1150, the uncertainty data of NUREG-1150 was used Chapter 9 documents the maintenance data collected from the plant. The uncertainty of these maintenance unavailabilities was derived by judgement using the following rules:

1. If the mean is small, a lognormal distribution with some EF is assumed.

2. If the mean is close to 1, a uniform distribution is assumed. If the mean is larger than 0.5, the upper bound is set to 1. If the mean is lower than 0.5, the upper bound is set to twice the mean.

D-24

Table D.4-1 Characteristic Values of Frequency of Outages (per year)

Mean Error 5% SO% 95% ll u Factor Refueling 0.6 1.46 0.40 0.584 0.8S4 -O.S375 0.2309 Drained 1.2 3.22 0.29 0.932 3.00 -0.07 0.7104 Maintenance

• D-25

Table D.4-2 Conditional Probability that an IE Occurs in the 1ime Wmdows Given it Occurred in the POS WINDOW 1 WINDOW2 WINDOW 3 WINDOW 4 Definition <= 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> > 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> and > 240 hours0.00278 days <br />0.0667 hours <br />3.968254e-4 weeks <br />9.132e-5 months <br /> and > 32days

<= 240 hours0.00278 days <br />0.0667 hours <br />3.968254e-4 weeks <br />9.132e-5 months <br /> <= 32 days All IEs except RHR2A D6 1.17E-01 0.436 0.375 7.20E-02 R6 1.7E-02 0.543 0.41 3.4E-02 RlO 0.0 0.0 0.016 9.84E-01 RHR2A only D6 0.31 0.454 0.21 2.6E-02 R6 5.82E-02 0.7 0.24 1.48E-03 RlO 0.0 0.0 2.2E-02 0.98 D-26

• Kiyoharu Abe Dept. of Reactor Safety Research Nuclear Safety Research Center Tokai Research Establishment JAERI Tokai-mura, Naga-gun Ibaraki-ken, Ephraim Asculai Division of Nuclear Safety Wagramestrasse, 5 P.O. Box 100 A-1400 Wien AUSTRIA JAPAN Vladimar Asmolov Head, Nuclear Safety Department Sarbes Acharya I. V. Kurchatov Institute Department of Energy of Atomic Enegry NS-1/FORS Moscow, 123181 Washington, DC 20585 RUSSIA Dr. Ulvi Adalioglu J. .de Assuncao Cekmece Nukleer Arastraima ve Cabinete de Proteccao e Egitim Merekezi Seguranca Nuclear P.K. 1 Ministerio da Indusstria Havaalani/ISTANBUL Ave. de Republica 45-6 TURKEY 1000 Lisbon PORTUGAL Dr. Eng. Kiyoto Aizawa Senior Engineer H.P. Balfanz, Head Reactor Eng. Dev. Department Institute of Probabilistic*

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U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER (Assigned by NRC. Add Vol., Supp., Rev.,

and Addendum Numbers, If any.)

BIBLIOGRAPHIC DATA' SHEET (See instructions on the reverse)

NUREG/CR-6144 ITLE AND SUBTITLE BNL-NUREG-5 2399 Evaluation of Potential Severe Accidents During Low Vol.2 Part 2 Power and Shutdown Operations at Surry, Unit 1: 3. DATE REPORT PUBLISHED YEAR Analysis of Core Damage Frequency from Internal MONTH Events During Mid-loop Operations-Appendices A-D June 1994

4. FIN OR GRANT NUMBER L1922

5. AUTHOR{S) 6. TYPE OF REPORT T.L. Chu, z. Musicki, P. Kohut, D. Bley 1, J.Yang,.

2 B. Holfes, G. l\ozoki, C.J Hsu, D.J. piamond, D. Johnso~ 1, J. Lin, R.F. Su, V. Dang, 3 D. Ilberg, S.M. Wong, N. Siu 7. PERIOD COVERED (Inclusive Dates)

8. p ER FORM I NG ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region. U.S. Nuclear Regulatory Commission, and mailing address; if contractor. provide name and mailing address.)

1 Brookhaven National Laboratory PLG Inc,, 4590 McArthur Blvd. Newport Bch, CA 92660-2027 2

Upton, NY 11973 AEA Technology, Winfrith, Dorchester, Dorset, England, DT2 8DH 3 MIT, Cambridge, MA 02139 (N, Siu currently at EG&G, Idaho Falls, ID 84315) 4 sore Nuclear Research Center Yavne 70600 Israel

9. SPONSOR I NG ORGAN I ZA Tl ON - NAME AND ADDRESS /If NRC, type "Same as above": if contractor, provide NRC Division, Office or Region. U.S. Nuclear Regulatory Commission, and mailing address.)*

Division of Safety Issue Resolution Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission shington, DC 20555-0001 PPLEMENTARY NOTES

11. ABSTRACT /200 words or less)

During 1989, the Nuclear Regulatory Commission (NRC) initiated an extensive program to carefully examine the potential risks during low power and shutdown operations. The program includes two parallel projects being performed by Brookhaven National Laboratory (BNL) and Sandia National Laboratories (SNL). Two plants, Sutry (pressurized water reacto.r) and Grand Gulf (boiling water reactor), were selected as the plants to be studied. The objectives of the program are to assess the risks of severe accidents initiated during plant operational states other than full power operation and to compare the estimated core damage frequencies, important accident sequences and other qualitative and quantitative results with those accidents initiated during full power operation as assessed in NUREG-1150. The objective of this report is to document the approach utilized in the Surry plant and discuss the results obtained. A parallel report for the Grand Gulf plant is prepared by SNL. This study shows that the core-damage frequency during mid-loop operation at the Surry plant is comparable to that of power operation. We recognize that there is very large uncertainty in the human error probabilities in this study. This study identified that only a few procedures are available for mitigating accidents that may occur during shutdown.

Procedures written specifically for shutdown accidents would be useful.

12. KEY WO R DS/D ESCR: PTO RS (List words or phrases that will assist researehers in locating the report.) 13. AVAi LABILITY STATEMENT Surry-1 Reactor-Reactor Shutdown; Surry-1 Reactor-Risk Assessment; Surry-2 Reactor-Reactor Shutdown; Surry-2 Reactor-Risk Assessment; (This Page)

Failure Mode Analysis, Reactor Accidents, Reactor Core Disruption, Reactor Start-up, RHR Systems, Systems Analysis, Thermodynamics, Unclassified (This Report) ndia National Laboratories

• Unclassified

15. NUMBER OF PAGES

16. PRICE NRC FORM 335 (2-89)

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