Text

Evaluation of Potential Severe Accidents During LOW Power and Shutdown Operations at Grand Gulf,Unit 1.Analysis of Core Damage Frequency from Internal Events for Plant Operational State 5 During a Refueling Outage.Sections 1-9
	ML20071L566
Person / Time
Site:	Grand Gulf
Issue date:	06/30/1994
From:	Benavides G, Tony Brown, Dandini V, Susan Daniel, Darby J, Forester J, Kirk H, Miller S, Mitchell D, Staple B, Walsh B, Whitehead D, Yakle J; SANDIA NATIONAL LABORATORIES, SCIENCE & ENGINEERING ASSOCIATES, INC., SCIENCE APPLICATIONS INTERNATIONAL CORP. (FORMERLY
To:	; NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES)
References
	CON-FIN-L-1923 NUREG-CR-6143, NUREG-CR-6143-V02P1A, NUREG-CR-6143-V2P1A, SAND93-2440, NUDOCS 9408030161
	Download: ML20071L566 (284)
	v • d • e

{{#Wiki_filter:NUREG/CR-6143 SAN D93-2440 Vol. 2, Part i A

Eva ua~: ion of Po~:en:ia Severe Accic ents Durinob Low Power anc Sau~:c.own Coera~: ions at . Granc Gu 5, L ni~: : Analysis of Core Damage Frequency from (Internal Events for Plant Operational State 5 During a Refueling Outage Main Report (Sections 1-9) Prepared oy D. Whitchead J.1)aiby. J. LLle. J. l'orester,11. Staple. S. Mdler. S. D.iniel. T. lin m n.11. Walsh.11. Ku k. D. Mitchell. V.11.indini. G. lienavides Sandia National Laboratories Operated by Sandia Corporation l'repared for U.S. Nuclear Regulatory Cominission 9408030161 940630 PDR ADOCK 05000416 P PDR

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i l NUREG/CR-6143 SAND 93-2440 i Vol. 2, Part 1 A i l 1 Evaluation of Potential Severe i Accidents During Low Power and ; Shutdown Operations at ; Grand Gulf, Unit 1 Analysis of Core Damage Frequency from : Internal Events for Plant Operational : State 5 During a Refueling Outage Main Report (Sections 1-9) l j 2 Manuscript Cornplet.:d: April 1994 ; j Date Published: June 1994 i , 4 , Prepared by D. Whitehead, J. Darby', J. Yakle2, J. Forester 2, B. Staple, S. Miller r, S. Daniel, T. Brown, B. Walsh', H. Kirk, ! D. Mitchell, V. Dandini, G. Benavides - I l i Sandia National Laboratories ! Albuquerque, NM 87185 Prepared for Division of Safety Issue Resolution ! ! Office of Nuclear Regulatory Research ! j U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 . NRC FIN L1923 ;

 ; ' Science and Engineering Associates, Inc.,6100 Uptown Blvd. N.E.,

Albuquerque, hM 87110 i 2 Science Applications International Corporation,2109 Air Park Road S. E., Albuquerque, NM 87106 t

k t This page is intentionally left blank. t f t k t i i I f b l t I t t NUREG/CR-6143 ii Vol. 2, Part 1

Abstract During 1989 the Nuclear Regulatory Cornmission (NRC) initiated an extenive program to carefully examine the potential risks during low power and shutdown operations. Two plants, Surry (pressurized water reactor) and Grand Gulf (boiling water reactor), were selected as the plants to be studied. The program consists of two parallel projects being performed by Brookhaven National Laboratory (Surry) and Sandia National Laboratories (Grand Gulf). The program objectives include assessing the risks of severe accidents initiated during plant operational states other than full power operation and comparmg the estimated core damage frequencies, important accident sequences, and other qualitative and quantitative results with those accidents initiated durirg full power operation as assessed in NUREG-1150. The scope of the program includes that of a Level-3 PRA. A phased approach was used in the Level-1 program. In Phase I the concept of plant operational states (POSs) was developed to allow the analysts to better represent the plant as it transitions from power operation to non power operation than was possible with the traditional Technical SpeciEcation divisions of Modes of Operation. This phase consisted of a cocrse screening analysis performed for all POSs. The objective of the Phase I study was to identify potential vulnerable plant configurations, to characterize (on a high, raedium, or low basis) the potential core damage accident scenario frequencies, and to provide a foundation for a detailed Phase 2 analysis. In Phase 2 POS 5 (approximately Cold Shutdown as defined by Grand Gulf Technical Specifications) during a refueling outage was selected as the plant configuration to be analyzed based on the results of the Phase I study. The scope of the Level 1 study includes plant damage state analysis and uncertainty analysis and is documented in a multi-volume NUREG/CR report (i.e., NUREG/CR-6143). The internal events analysis is documented in Volume 2. Internal fire and internal flood analyses are documented in Volumes 3 and 4, respectively. A separate study on seismic analysis, documented in Volume 5, was performed for the NRC by Future Resources Associates, Inc. The Level-2/3 study is documented in Volume 6, and a summary of the results for all analpes is documented in Volume 1. In the Phase 2 study, system models applicable for POS 5 conditions, comprised of POS 5 on the way down to refueling and POS 5 on the way back up from refueling, were developed and supporting thermal hydraulic analyses were performed , to determine both the timing of the accidents and success criteria for systems. Initiating events that may occur during POS S were identined and accident sequence event trees were developed and quantified. Surviving sequences were examined for recovery potential, appropriate human recovery actions were incorporated into the sequence cut sets, and the sequences were then requantified. Those sequences surviving this preliminary recovery analysis were then reexamined during a

time ,

window

analysis. This time window analysis allows for a more detailed representation (i.e., a more realistic incorporation of the affects of the decrease in decay heat throughout the POS and a more time-specific incorporation of equipment ;

unavailabilities as the plant transitions from the begmmng to the end of POS 5) of the potential accident sequences that could occur while the plant is in POS 5. The mean core damage frequency of the Grand Gulf plant due to internal events for POS 5 during a refueling outage is 2.0E-06 per year, and the 5th and 95th percentiles are 4.1E-07 and 5.4E-06 per year, respectively. This compares to the . total core damage frequency of 4.0E-06 per year estimated in the NUREG-1150 study of full power operations. ! Vol. 2. Part 1 iii NUREG/CR-6143 % . - - . . , _ , - - , y _ , _.._

i This page is intentionally left blank. i F i b t NUREGICR-6143 iv Vol. 2, Part 1 i

Contents Acronymt . .................. ......................... xlvi Foreword . . . . . . . . ......... ......................... xlviii Acknowled gements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. Executive Summary . . . . . . . . . . . . . . ....................... 1-1 1.1 Obj ectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 1.2 Approach and Limitatiens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 1.3 Resul ts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 1-2 1.3.1 Insights Into Plant Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1.3.2 Insights into Plant Operations . . . . . . . . . . . . . . . . . . ......... 1-3 1.3.3 Total Plant Model Results . . . . . . . . . . . . . . . . . . . . . . . .... 1-3 1.3.4 Results froe Sequence Quantifications . . . . . . . . . . . . ........... 1-3 1.4 General Conclusions .................................. 1-7 References for Section 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 1-8

2. Program Scope and Major Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . ... 2-1 2.1 Program Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 2.2 Major Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 21

3. Selection and Characterization of POS 5 ......... . . . . . . . . . . . . . . . ... 3-1 3.1 Selection of POS 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 3.2 Characterization of POS 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 References for Section 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6

6. Analysis of Accident Initiating Events .............................. 4-1 4.1 Approach and Summary ................................ 4-1 4.2 Transient Initiating Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 4.2.1 Transients Common to All BWRs ........................... 4-1 4.2.2 Transients based on Grand Gulf Support Systems . . . . . . . . . . . . . . . . .... 4-7, 4.3 LOCA 1nitiating Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11 4.4 Decay Heat Removal Challenges ............................. 4-14 4.5 Special E vents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-16 References for Section 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-17 B ibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-18

5. Success Criteria for POS 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 5.1 Functi ons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-2 ,

5.1.1 Reactivity Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-2 5.1.2 Level Control ................................... 5-2 l 5.1.2.1 Level Control for Transients . . . . . . . . . . . . . . . . . . . . . . . ... 5-2 5.1.2.2 level Control for LOCAs . . . . . . . . . . . . . . . . . . . . . . . . ... 5-5 5.1.3 Energy Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 5.1.3.1 Energy Removal for Transients . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 5.1.3.2 Energy Removal for LOCAs . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-7 References for Section 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-13 t

6. Event Tree Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 i 6.1 Generic Trees for Transients. POS 5 . . . . . . . .. . . . . . . . . . . . . . . . ... 6-1 l 6.1.1 Generic Trees for Cold Shutdown. O psig ........................ 6-1 '

6.1.1.1 Generic Functional Event Trees, POS 5 at 0 psig . . . . . . . . . . . . . . .... 6-2 Vol. 2 Part 1 y NUREG/CR-6143 I

Contents (Continued) 6.1.1.2 Generic System-Level Event Trees, POS 5 at 0 psig .. .............. 6-2 6-2 6.1.2 Generic Trees for Cold Shutdown,1000 psig ............ ........ 6-3 6.1.2.1 Generic Functional Event Trees, POS 5 at 1000 psig . . . . . . . . . . . . . . . . . 6.1,2.2 Generic System-Level Event Trees, POS 5 at 1000 psig . . . . . . . . . . . . . . . . 6-3 6-3 6.2 Specific System-Level Event Trees for Transients ......................

                                                                                                                 ......                 6-3 6.3       Specific System-level Event Trees for LOCAs ................
                                                                                                                 .....                 6-56 6.4       Event Tree Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7-1 !

7. Plant Damage State Analysis . . . . . . . . . . . . . . ...................

                                                                    .....................                                               7-1 7.1       Purpose    ..............                   ..

7-1 7.2 Approach . . . . . . . . ........ ..................... 8-1

8. Sy stems Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

8-1 8.1 System Modeling Approach and Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 8.2 Identification of Systems . . . . . . . . ............ ...........

                                                                                               ............                              8-1 8.3       High Pressure Core Spray System (HPCS)         .     ..........
                                                                                                             .......                     8-1 8.3.1    HPCS System Description ..........                        ...........

8-3 8.3.2 HPCS System Interfaces and Dependencies .......................

                                                                                    ................                                     8-3 8.3.3    HPCS Test and Maintenance ............

HPCS Technical Specifications .. ........................ 8-3 . 8.3.4 8-8 8.3.5 HPCS logic M odel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-8 8.3.6 HPCS Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

                                                                                                             .......                     8-9 8.3.7     HPCS Operating Experience       ........                    ..     .    ...        .

Control Rod Drive (CRD) System . . . . ................... 8-9 8.4 .. . CRD System Description . . . . . ................. ...... 8-9 8.4.1 , CRD Interfaces and Dependencies . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-11 8.4.2 ' 8-11 8.4.3 CRD Test and Maintenance . . . . . . . . . . . . . . . . ........... . CRD Technical Specifications . . . . . . . . . . ......... 8-11 8.4.4 ........ 8-11 8.4.5 CRD Iegic Model .................................

                                                                                                ...........                             8-11 8.4.6     CRD Assumptions      ...................

CRD Operating Experience . . . . . . . . . . . . . . . . ............. 8-13 8.4.7

                                                                                             .............                              8-13 8.5       Suppression Pool Makeup (SPMU) System ...........

8-13 8.5.1 SPM U Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SPMU 1nterfaces and Dependencies .......... ............... 8-13 8.5.2 8-13 8.5.3 SPMU Test and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . SPMU Technical Specifications . . ..................... ... 8-13 8.5.4 8-16 8.5.5 SPM U Logic Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-16 8.5.6 SPMU Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SPMU Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-16 8.5.7 8-16 8.6 Condensate (CDS) System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Condensate System Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-16 8.6.1 Condensate Interfaces and Dependencies ........................ 8-16 8.6.2 Condensate System Test and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . 8-16 8.6.3 Condensate Technical Specifications .......................... 8-16 8.6.4 8.6.5 Condensate 1ogic Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-16 8-16 8.6.6 Condensate Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Condensate Operating Experience ........ .. 8-19 8.6.7 ............... law Pressure Core Spray (LPCS) System . . . . . . . . . . . . . . . . . . . . . . ... 8-19 8.7 LPCS System Description ..... 8-19 8.7.1 .................... ... LPCS Interfaces and Dependencies . . . . . . . . . . . . . ............ 8-19 8.7.2 LPCS Test and Maintenance . ........................... 8-22 8.7.3 8.7.4 LPCS Technical Specifications .......................... . 8-22 vi Vol. 2, Part 1 NUREG/CR-6143

1 1 1 1 Contents (Continued) 8.7.5 LPCS Iogie Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-22 8.7.6 LPCS Assumptions . . . ... ....................... 8-22 8.7.7 LPCS Operating Experience ................. ... ....... 8-22 8.8 Low Pressure Coolant Injection (LPCI) System .... ....... ......... 8-23 8.8.1 LPCI System Descri., tion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-23 8.8.2 LPCI Interfaces and Dependencies . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-23 8.8.3 LPCI Test and Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-23 8.8.4 LPCI Technical Specifications . . .......................... 8-26 8.8.5 LPCI logic Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-26 8.8.6 LPCI Assumptions ....... ...... .................. 8-26 8.8.7 LPCI Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-27 i 8.9 Standby Service Water Cross-Tie (SSWXT) System ..................... 8-27 8.9.1 SSW Cross-Tie System Description ............. ............ 8-27 8.9.2 SSW Cross-Tie Interfaces and Dependencies . . . . . . .. . . . . . . . . . . . . . . . . 8-27 8.9.3 SSW Cross-Tie Test and Maintenance ......................... 8-27 8.9.4 SSW Cross-Tie Technical Specifications . . . . ........ .. . ...... 8-27 8.9.5 SSW Cross-Tie Logic Model . . . . . . . . . . . . ................ 8-27 8.9.6 Assumptions in the SSW Cross-fie Model . . . . . . . . . . . . . ......... 8-30 8.9.7 SSW Cross-Tie Operation Experience . . . . . . . . . . . . . . . . . . . . . . . . . . 8-30 8.10 Firewater (FW) System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-30 8.10.1 Firewater System Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-30 8.10.2 Firewater Interfaces and Dependencies ........... ............. 8-30 8.10.3 Fire vater Test and Maintenance . . . . ....................... 8-30 8.10.4 Firewater Technical Specifications . . . . . . . . . . . . . . . . . . . . . . .... 8-32 8.10.5 Firewater logic Model ....... ............. ......... 8-32 8.10.6 Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-32 8.10.7 Fire Water Operation Experience ........................... 8-32 8.11 Residual Heat Removal: Suppression Pool Cooling (SPC) System . . . . . . . . . . . . . . . . 8-32 i 8.11.1 SPC Description . . . . . . . . . . . . . . . . . . . . . . . .......... 8-32 8.11.2 SPC Interfaces and Dependencies ........................... 8-34 8.11.3 SPC Test and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-34 8.11.4 SPC Technica1 Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-34 8.11.5 SPC Logic Model . . . . . . . . . . . . . . . . . ................ 8-34 8.11.6 SPC Assumptions . . . . . . . . . . . . ..................... 8-36 8.11.7 SPC Operating Experience . . . . . . . . . . . . . . . . . . . . . . ....... 8-36 8.12 Residual Heat Removal: Shutdown Cooling (SDC) System . . . . . . . . . . . . . . . . . . . 8-36 8.12.1 SDC Description . . . . . . . . . . . . . . . . . . . . . . . . . . ....... 8-36 8.12.2 SDC 1nterfaces and Dependencies ........................... 8-38 8.12.3 SDC Test and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-38 8.12.4 SDC Technical Specifications . . . . . . . . . . . . . . . . . ........... 8-38 8.12.5 SDC Logic Model ................................. 8-40 l 8.12.6 S DC Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-40 E.12.7 SDC System Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-40 ' 8.13 Residual Heat Removal: Containment Spray (CS) System ................... 8-40 8.13.1 CS Description . . . . . . . . . . . . ...................... 8-40 8.13.2 CS System Interfaces and Dependencies . . . . . . . . . . . . . . . . . . . . . . . . . 8-41 8.13.3 CS Test and Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . .... 8-41 8.13.4 CS Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-41 8.13.5 CS Imgic M odel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-41 8.13.6 CS Assumptions . ............... ...... .. . ... 8-44 8.13.7 CS Operating Experience . . . . . . . . . . . ... ..... ........ 8-45 8.14 Containment Venting System (CVS) . . ......................... 8-45 Vol. 2, Part I vii NUREG/CR-6143

Contents (Continued) 8.14.1 CVS Description . . . . . . . . . . . . . . . . . . . . . . ........... 8-45 8.14.2 CVS Interfaces and Dependencies ......... ................. 8-45 8-45 8.14.3 CVS Test and Maintenance . . . . . . . . . . . . . . .............. 8.14.4 CVS Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-45 8.14.5 CVS Logie Model ............. ..... ............. 8-45 8.14.6 CVS Assumptions . . . . . . . . . . . . . . . . . . . . . . ........... 8-45 8-45 8.14.7 CVS Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

                                                                   .....................                                               8-45 8.15 Emergency Power System (EPS)           ......

8.15.1 EPS Description .................................. 8-45 8.15.2 EPS Interfaces and Dependencies ........................... 8 49 ; 8-52 8.15.3 EPS Test and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.15.4 EPS Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . .... 8-52 - 8.15.5 EPS Imgic Models .......................... ...... 8-52 8.15.6 EPS Assumptions . . . . . . . . . . . . . . . . . . . . . . . . ......... 8-53 8.15.7 EPS Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-53 8.16 Standby Service Water (SSW) System ........ .. ............... 8 53 8.16.1 SSW System Description . . . . . . . . ...................... 8-53 8.16.2 SSW Interfaces and Dependencies . . . . . . . . . . . . . ............. 8-56 8-56 8.16.3 SSW Test and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.16.4 SSW Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-56 8.16.5 SSW Logic Model ................. .......... .... 8 56 8.16.6 SSW Assumptions. . . . . . . . . . . . . . . . . . . . . . . . . ........ 8-56 i 8.16.7 SSW Operating Experience . . . . . . . . . . . . . . . . . ............ B-56 8.17 Emergency Ventilating System (EVS) .. .............. ......... 8-58 8.17.1 EVS Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-58 8.17.2 EVS Interfaces and Dependencies ......... ................. 8-58 8.17.3 EVS Test and Maintenance ............................. 8-58 8.17.4 EVS Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-62 8.17.5 EVS logic Models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-62 8.17.6 EVS Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-62 8.17.7 EVS Operating Experience . . . . . . . . . . . . ... ....... ..... 8-62 8.18 Instrument Air System (IAS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-62 8.18.1 IAS Description ....... ..................... .... 8-62 8.18.2 IAS Interfaces and Dependencies .................. ........ B-64 8.1b.3 IAS Test and Maintenance .............................. 8-64 8.18.4 1AS Technical Specifications ............................. B-64 8.18.5 I AS Logic M odel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-64 8.18.6 IAS Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-64 8.18.7 IAS Operating Experience .............................. 8-64 8.19 Standby Gas Treatment (SGTS) System . . . . . . . . . . . . .............. 8-64 8.19.1 SGTS System Description ............ ................. 8-64 8.19.2 SGTS System Interfaces and Dependencies .......... ............ 8-66 8.19.3 SGTS System Test and Maintenance .......................... 8-69 8.19.4 w I'S System Technical Specifications ......................... 8-69 8.19.5 SGTS System legic Model . . . . . ........................ 849 8.19.6 SGTS System Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-69 8.20 Containment Isolation (CI) System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-69 8.20.1 CI System Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-69 8.20.2 CI System Interfaces and Dependencies . . . . . . . . . . . . . . . . ....... 8-69

8.20.3 CI System Imgic Model . . . . . . . . . . . . . ..... ... ....... 8-69 8.21 Hydrogen (H2)Ignitor System ........................... .. 8-69 8.21.1 H2 Ignitor System Description ..... ......... ............ 8-69 NUREG/CR-6143 viii Vol. 2, Part 1

Contents (Continued) 8.21.2 H2 Ignitor System Interfaces and Dependencies . .......... ......... 8-69 8.21.3 H2 Ignitor System legic Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-69 8.22 Alternate Decay Heat Removal (ADHR) System . . . . . . . . . . . . . . . . . . . . . . . 8-70 8.22.1 ADHR System Description . . . . . . . . . . . . . . . . . . . . . . . . . . ... 8-70 8.22.2 ADHR Interfaces and Dependencies ....... .......... . .... 8-70 8.22.3 ADHR Test and Maintenance . . . . . . ...................... 8-70 8.22.4 ADHR Technicai Specifications . . . . . . . . . . . . . . ..... ....... 8-70 8.22.5 ADHR Iogic Model. . . . . . . . . . ..................... 8-70 8.22.6 ADHR Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-70 8.22.7 ADHR Operating Experience . . . . . ....................... 8-73 8.23 Reactor Water Cleanup (RWCU) System . . . . . . . . . . . . . . . . . . . . . . . . . . 8-73 8.23.1 RWCU System Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-73 8.23.2 RWCU Interfaces and Dependencies .......... ............... 8-73 8.23.3 RWCU Technical Specifications . . . . . . ..................... 8-73 8.23.4 RWCU logic Model ............ ............. ..... 8-73 8.23.5 RWCU Assumptions .. ......... .. ... ............ 8-73 8.23.6 RWCU Operating Experience . . . ...... .................. 8-76 8.24 Reactor Recirculation System (RRS) . . . . ..... ................ 8-76 8.24.1 RRS System Description . . . . . . . . . . ........ ........... 8-76 8.24.2 RRS Interfaces and Dependencies .......................... 8-76 8.24.3 RRS Test and Maintenance . . . . . ................ ....... 8-76 8.24.4 RRS Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-76 8.24.5 RRS logic Model . . . . . . . . . . . . . . . . . . . . ............. 8-79 8.24.6 RRS Assumptions . . . . . . . . . . . . . . . . . . ............... 8-79 8.24.7 RRS Operating Experience . . . . . . . . . . . . . . . . . ............ 8-79 8.25 Component CoolinE Water (CCW) System ......... ............... 8-79 8.25.1 CCW System Description ............... .............. 8-79 8.25.2 CCW Interfaces and Dependencies . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-81 8.25.3 CCW Test and Maintenance ..... .... .................. 8 81 8.25.4 CCW Technical Specifications. . . . . ...... ............... 8-81 8.25.5 CCW Iogic Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-81 8.25.6 CCW Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-81 8.25.7 CCW Operation Experience. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-81 8.26 Plant Service Water (PSW) System ............ ............... 8-81 8.26.1 PSW System Description . . . . . . . . . . . . . . . ............... 8-81 8.26.2 PSW Interfaces and Dependencies . . . . . . . . . . . . . . . . . . . ....... 8-83 l 8.26.3 PSW Test and Maintenance . . . . . . . . . .................... 8-83 8.26.4 Technical Specificati ons . . . . . . . . . ..................... 8-83 8.26.5 PSW logic Model ................................. 8-87 8.26.6 PSW Assumptions ................................. 8-87 6.26.7 PSW Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-87 8.27 Condensate and Refueling Water Storage and Transfer System (CRWST) . . . . . . . . . . . . . 8-87 8.27.1 CRWST System Description ...... ................ .... 8-87 8.27.2 CRWST Interfaces and Dependencies . . . . . . . . . . . . . . . . . . . . . . . . . . 8-87 t 8.27.3 CRWST logic Model . . . . . . . . . . . . . . . . . .............. 8-89 8.27.4 CRWST Technical Specifications ....................... ... 8-89 8.27.5 CRWST Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-89 ; 8.28 Safety Relief Valves .................................. 8-89 8.28.1 SRV Description . . . . . . . . . . . . . . . . . . . . . . ........... 8-89 8.28.2 SRV Interfaces and Dependencies ....................... ... 8-89 i 8.28.3 SRV Test and Maintenance . . . . . . . . . . . . . . . ............ . 8-92 8.28.4 SRV Technical Specifications . . . . . ................. ..... 8-92 Vol. 2, Part 1 ix NUREG/CR-6143 i

Contents (Continued) 8-92 8.28.5 S RV legic M odel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-92 8.28.6 SRV Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.29 Justification for Systems Not Modeled . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-92 8-94 References for Section 8 . . . . . . . . . . . ....................... 9-1

9. Dependent Failure Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

                                                                             ...................                                  9-1 9.1     Dependent Failure Analysis Assumptions and Limiutions                                                                    '

9-1 9.2 Dependent Failure Development . . . . . . . . . . . . . . . . . . . . .......... Review of Existing Dependent Failure Analysis. . . . . . . . . . . . . . . . . . . . . . 9-1 9.2.1 Common Cause Failure Analysis . . . . . . . . . . . . . . . . . . . ........ 9-1 9.2.2 9-6 References for Section 9 . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ 10-1

10. Human Reliability Analysis . . . . . . . . ................. ........

General Methodology and Scope ........................ 10-1 10.1 .... 10.2 Pre-Accident Human Reliability Analysis . . . . . . . ............ ..... 10-2 Post-Accident Human Reliability Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . 10-2 10.3 10.3.1 Incorporation of Post-Accident Human Actions into PRA Models .............. 10-2 10.3.2 Treatment of Dependencies and Non-Proceduralized Actions ............... 10-3 10.3.3 Results of the Post-Accident Human Reliability Analysis . . . . . . .......... 10-3 10-4 10.4 Recovery Actions Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 10.5 Time Windows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

                                                                                         ............                            10-5 References for Section 10     .....................
                                                                 ......................                                          11-1

11. Data Base Development .............

11-1 11.1 Sources of Information for the Data Base . . . . . . . . . . . . . . . . . . . . . . . . . 11.2 Data from NUREG-1150 Analysis of Grand Gulf . . . . . . . . . . . . .......... 11-1 11-1 11.3 Plant Specific and Generic Data . . . . . ............ ........... 11-1 11.3.1 Initiating Events .................................. 11.3.2 POS Change Initiating Events . . . . . . . . . . . . . . . . . ........... 11-1 11-1 11.3.3 Frequency of POSs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11-1 11.3.3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3.3.2 Relative Time Spent in RFOs . . . . . . . . . . . . . . . . . . . . . . . . . . 11-32 11.3.3.3 Relative Times Spent in POSs During RFOs . . . . . . . . . . . . . ..... 11-32 11.3.3.4 Relative Times Spent in Power Dips Between RFOs .............. . 11-32 11.3.3.5 Relative Times Spent in POSs During Power Dips ................. 11-40 11.3.3.6 Merging of Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11-40 11-40 11.3.4 Maintenance Unavailabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3.5 Top Event Fractions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11-40 11.3.5.1 PRESS - Fraction of Time Vessel is in Hydro Test (i.e., High Pressure) ........ 11-40 11.3.5.2 ISSDC - Initial Status of Shutdown Cooling in POS5: Fraction of Time ADHR Operating to Remove Decay Heat . . . . . . . . . . . . . . . . . . . ..... 11-44 , 11-.14 11.3.5.3 ISSDB - Fraction of Time on RHR/SDC in POS 5 ................. 11.3.5.4 ISADH - Fraction of Time on ADHR in POS 5 .................. 11-44 11.3.5.5 ISSP -Initial status of SP in POS 5: With Water or Empty ............ 11-44 11.3.5.6 SPWLV - Fraction of Time Suppression Pool Water Level is 12'8' ........ . 11-45 11.3.5.7 ISMSV - Fraction of Time the MSIVs are Initially Open in POS 5 .......... 11-45 11.3.5.8 ISTRC - Fraction of Time Natural Recirculation is Possible ............. 11-46 11.3.5.9 ISTCT - Fraction of Time the Containment is Open and CTGOP - Fraction of Time the Containment is Open Iow . . . . . . . . . . . . . . . . . . . . .. 11-46 11.3.6 Estimates for System Maintenance Unavailabilities ........ .......... 11-46 11.3.6.1 HPCS System Maintenance Unavailability . . . . . . . . . . . . . . . . . . . . . 11-46 i \ l NUREG/CR-6143 x Vol. 2, Part 1

Contents (Continued) 11.3.6.2 CDS System Maintenance Unavailability . . . . . . . . . . . . . . . . . . . . . 11-46 11.4 Data Changes Necessitated by the Time Window Analysis . . . . . . . . . . . . . . . . . . 11-46 i 11.5 References for Section 11 ............................... 11-47

12. Accident Sequence Quantification . . . . . . . . . . . . . . . . . . ............. 12-1 12.1 General Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-1 12.2 Point Estimate Results from the Quantification of Each IE Both Before and After Recovery . . . . 12-1 12.2.1 T5D - bss of CCW ............................... 12-1 12.2.2 T5A - Loss of SSW . . . . . . . . . . . . . . .................. 12-2 12.2.3 TDB - Loss of IE 125 V DC Bus B .......................... 12-2 12.2.4 TIA - less of Instrument Air . . . . . . . . . . . . . . . . . . . . ........ 12-2 12.2.5 TAB - less of IE 4160 V AC Bus B . . . . . . . . . . . . . . . . . ........ 12-2 12.2.6 J2 - LOCA in Connected System (RHR) ........................ 12-2 12.2.7 ElB - Issolation of SDC Loop B . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-2 12.2.8 E2B - Loss of SDC Loop B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-2 12.2.9 EID - Isolation of ADHRS . . . . . . . . . . ................... 12-2 12.2.10 E2D -less of ADHRS ............................... 12-3 12.2.11 TSB - Loss of TBCW . . . . . . . . . . . . . .................. 12-3 12.2.12 T5C - Loss of PSW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 3 12.2.13 AS - Large LOCA ................................. 12-3 12.2.14 S2H Small LOCA During Hydro . . . . . . . . . . . . . . . . . . . ...... 12-3 12.2.15 S3H Small-Small LOCA During Hydro ....................... 12-3 12.2.16 ASHY - large LOCA During Hydro . . . . . . . . . . . . . . ........... 12-3 12.2.17 S1H-5 -Intermediate LOCA During Hydro ....................... 12-3 12.2.18 S2 S mall LOCA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-4 12.2.19 S3 Small-Small LOCA . . . . . . . . . . . . . . . ..... ........ 12-4 12.2.20 SI 5 - Intermediate LOCA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-4 12.2.21 TIOP - Inadvertent Overpressurization (Loss of RWCU) . . . . . . . . . . . . . . . . . . 12-4 12.2.22 E1C -Isolation of RWCU During Hydro ........................ 12-4 12.2.23 E2C - Loss of RWCU During Hydro . . . . . . . . . . . . . . . . . . . . . . . . . . 12-4 12.2.24 E2T - Loss of SDC Common Suction Line ....................... 12-4 12.2.25 E2V - Loss of Common Suction Line for ADHRS .......... ........ 12-4 12.2.26 TLM -Iess of Makeup (CRD) .......... .......... ... .. 12-4 12.2.27 EIT - Isolation of SDC Common Suction Line . . . . . . . . . . . . . . . . . . . . . . 12-5 12.2.26 E1V -Isolation of Common Suction Line for ADHRS . . . . . . . . . . . . . . . . . . . 12-5 12.2.29 TIHP -Inadvertent Pressurization via Spurious HPCS Actuation . . . . . . . . . . . . . . . 12-5 12.2.30 TIOF -Inadvertent Overfill via LPCS or LPCI . . . . . . . . . . . . . . . . . . . . . . 12-5 12.2.31 TORV - Stuck Open Relief Valve ..................... ... . 12-5 12.2.32 T1 - Ioss of Offsite Power . . . . . . . . . . . . . . . . . . . . . . . . . .... 12-5 12.2.33 HI - Diversion to Suppression Pool via RHR ...................... 12-5 12.2.34 TRPT - loss of Recirculation Pump . . . . . . . . . . . . . . . . . . . . ..... 12-5 12.3 Point Estimate Summary Results for Each IE Before the Time Window Analysis . . . . . . . . . . 12-6 12.4 Results from the Time Window Analysis ............. ............ 12-6 12.5 Uncertainty Calculation Results for Eau Sequence Surviving the Time Window Analysis . . . . . 12-6 12.5.1 Uncertainty Analysis Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-6 12.5.2 Uncertainty Analysis Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-7 References for Section 12 .............. .................. 12-203

13. Plant Damage State Analysis Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-1 13.1 Description of Plart Damage States ...................... ..... 13-1 13.1.1 Plant Damage State PDS1-1 ...... .................. .. 13-1 13.1.2 Plant Damage State PDS1-2 ..... ...... ........... .... 13-2 Vol. 2. Part 1 xi NUREG/CR-6143

1 1 l Contents (Continued) 13.1.3 Plant Damage State PDS1-3 ........................ ... 13-2 , 13.1.4 Plant Damage State PDS1-4 ............................. 13-2 13.1.5 Plant Damage State PDS1-5 .......... .................. 13-2 j 13.1.6 Plant Damage State PDS2-1 ......... ........ ......... 13 3 . 13.1.7 Plant Damage State PDS2-2 ....................... . ... 13-3 13.1.8 Plant Damage State PDS2-3 ...................... ...... 13-3 13.1.9 Plant Damage State PDS2-4 ................... ......... 13-3 13.1.10 Plant Damage State PDS2-5 ............ .. ............. 13-3 13.1.11 Plant Damage State PDS2-6 ............................. 13-3 13.1.12 Plant Damage State PDS3-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-4 13.2 Plant Damage State Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4

14. Results and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-1

                                                       ...................                                           ...               14-1 14.1   Results . . . . . . . . . . . .   ....

14.1.1 Core Damage Frequency Characterization . ........... .......... 14-1 14.1.2 Accident Sequence Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-1 14.1.2.1 A5 Sequences . . . . . . . . . . . . . . . . . . . . . . . . . ... ... 14-1 14.1.2.1.1 Sequence 02-06-01-27-W1. ................. ... 14-1 14.1.2.1.2 Sequence 02 06-01 W2A . . . . . . . . . . . . . . . . . . . . . . . 14-1 14.1.2.1.3 Sequence 02-06-01 W2B . . . . . . . . . . . . . . . . . . . . . . . 14-4 14.1.2.1.4 Sequence 02-06-01 W3 A . . . . . . . . . . . . . . . . . . . . . . . 14-4 14.1.2.1.5 Sequence 06-06 01-27-W3 A . . . . . . . . . . . . . . . . . . . .. 14-4 14.1.2.2 A5HY Sequence . . . . . . . . . . . . . . . . . . . . . . . . . . ...... 14-4 14.1.2.2.1 Sequence 3-07-01-27-W3A ...... ...... ......... 14-4 14.1.2.3 EIT5H Sequence .............................. . 14-4 14.1.2.3.1 Sequence 07-11-01-27-W2. . . . . . . . . . . . ........... 14-4 14.1.2.4 E2T5H Sequence ........................ ....... 14-5 14.1.2.4.1 Sequence 04- 11 27-W2. . . . . . . . . . ....... ...... 14-5 14.1.2.5 H 1-5H Sequences . . . . . . . . . . . . . . . . . . . . . . . . . . . .... 14-5 14.1.2.5.1 Sequence 03 11 27W1. . . . . . . . . . . . . . . . . . . . . . . 14-5 14.1.2.5.2 Sequence 03-01-11-01-27W2. . . . . . . . . . . . . . . ....... 14-5 14.1.2.5.3 Sequence 03-01 2-W2 . . . . . . . . . . . . . . . . . . . . . . . . 14-5 14.1.2.6 J2-5 Sequences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-6 14.1.2.6.1 Sequence 2-01-11-01-27-W2 . . . . . . . . . . . . . . . . . . . . . . . 14-6 14.1.2.7 SI-5 Sequences . . . . . . . . . . . ....... ............. 14 6 14.1.2.7.1 Sequence 02-06 01-27-W1. . . . . . ..... ........... 14-6 14.1.2.7.2 Sequence 02 06-01 W2A . . . . . . . . . . . . . . . . . . . . . . . 14-6 14.1.2.7.3 Sequence 02 06-01 W2B . . . . . . . . . . . . . . . . . . . . . . . 14 6 14.1.2.7.4 Sequence 06-06-01-27-W3 A . . . . . . . . . . . . . ......... 14-7 14.1.2. 8 S 1H.5 Sequence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-7 14.1.2.8.1 Sequence 3 01 W3 A . . . . . . . . . . . . . . . . . . . . . . . 14-7 14.1.2.9 T1-5 Sequences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-7 14.1.2.9.1 Sequence 3-14-W1 A . . . . . . . . . . . . . . . . . . . . . . . . . . 14-7 14.1.2.9.2 Sequence 3-14-W1B . . . . . . . . ................. 14-7 14.1.2.9.3 Sequence 3-14 WIC . . ....................... 14-7 14.1.2.9.4 Sequence 3 14-W1 E . . . . . . . . . . . . . . . . . . . . ..... 14-8 14.1.2.9.5 Sequence 3-14-W2A . . . . . . . . . . . . . . . . . . . . . . . . . . 14-8 14.1.2.9.6 Sequence 3-14 W2B . . . . . . . . . . . . . . . . ......... 14-8 14.1.2.9.7 Sequence 3-14-W2C . . ........ ... ....... .. 14-8 14.1.2.9.8 Sequence 3-14-W2D . . . . . . . . . . . . . . . . . . . ...... 14-8 14.1.2.9.9 Sequence 3-14-W2E . ............. ... ...... 14-8 14.1.2.9.10 Sequence 5-15-W2B . . . ... ................. 14-8 NUREG/CR-6143 xii Vol. 2, Part 1

Contents (Continued) 14.1.2.10 TSASH Sequences .............................. 14-9 14.1.2.10.1 Sequence 3 3 5-04-W2 . . . . .................... 14-9 14.1.3 Total Plant Model Results . . . . . . . . . . . . . . . . . . ............ 14-9 14.2 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . ............. 14-9 14.2.1 Specific Conclusions . . . . . . . . . . . . . . . . . . . . ............ 14-9 Volume 2, Part 2 Appendix A Definition and Characterization of Plant Operational States (POSs) and POS Change Initiators A-1 Appendix B Summary of the Detailed Review of Selected Grand Gulf Procedures .......... B-1 Appendix C Overview of Grand Gulf Power Plant .............. ........ C-1 Appendix D Initiating Event Analysis from Screening Report ................... D.1 Appendix E Updated Success Criteria ............................ E-1 Appendix F Supporting Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1 Appendix G Calculation of the Frequency and Recovery of LOSP Plus Recovery of LOSP/DG Failures . G-1 Appendix H Event Trees . . . . . . . . . . . . . . . . . . . . . . . .......... H-1 Volume 2, Part 3 Appendix I Fault Trees . . . . . . ............. ............. I-1 Appendix J Miscellaneous Topics . ...... .. .......... ..... J-1 Volume 2, Part 4 Appendix K HEP Imtor Files . . . . . . . . . . . . . . . . . . . . . . . . ...... K-1 Appendix L Supporting Information for the Plant Damage State Analysis ...... ....... L-1 Appendix M Summary of Results from the Coarse Screening Analysis - Phase 1 A .......... M-1 e Vol. 2. Part 1 xiii NUREG/CR-6143

1 1 List of Figures ) 11 Contribution to CDF by Initiating Event. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 12 Percent of CDF vs Time Window. . . . . . . . . . . . . . . . . . . . . . ........... .............. 1-5 1-3 Fractional Contribution to CDF by IE Group vs Time Window. . . . . . . . . . . . . . . . . . . . . . . ....... 16 l

                                                                                                  .......................                                   1-6 14       Percent of CDF and Percent of Time in Time Window vs Time Window.                                                                                        l 3.1 1    POS vs Percent CDF . . . . . ....................... ............................ 3-2 Potentially High Frequency, Open Containment, and Early Core Damage Sequences in POS 5 . . . . . . . . .                                            3-2 3.1 2 f

5.1-1 Grand Gulf Reactor Vessel Water Levels . . . .... .................... ............... 53 Functional Tree: S DC 0 psig . . . . . . . . . . . . . . . . . . . . . ....................... . ... 6-4 6.1-1 6.1 2 Functional Tree: Water Solid 0 psig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ ..65 Functional Tree: Overfil1 0 psig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... 6-6 6.1 3 6.1 4 Functional Tree: SDC LOCA 0 ps ig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 Functional Tree: Steaming 0 psig. . . . . . . . . . . . . . . . . . . . . . . ...................... .. 6-8 6.1-5 6.1-6 Functional Tree: SDC in Hyrdo ....... .........................................6-15 6.1 7 Functional Tree: Manual Depressurmtion in Hydro ......... ....................... . 6-16 6.1-8 Functional Tree: Auto Depressurization in Hydro . . . . . . . . . . . . . . .......................6-17 6.1-9 Functional Tree: Overpressurization in Hydro .. ........ ... ............ . . . . . . . . . . 6 18 Functional Tree: Steam in Hydro ..................... ............... . . . . . . . . . . 6- 19 6.1-10 6.2-1 E l B5H Tree. . . . . . . . . . . . . . . . .......................... . . . . . . . . . . . . . . . . . . 6 22 6.2-2 E1C-5 Tree . . . . . . . . . . ............. .. ... . .... .................... . . 6-23 6.2-3 E1D5H Tree ................. ... .......... . .. ............... . . . . . 6-24 6.2-4 EIT5H Tree. . . . . . . . . .... ......... ...... . ..... . ........ . .......... 6-25 6.2-5 E1V5H Tree ........ .................... ........................ ...... . 6-26 6.2-6 E2B5H Tree ............................... .. ... .. ....... .... . . . . . . 6-27 6.2-7 E2C.5 Tree . . . ........... ........... ...................................628 6.2-8 E2DSH Tree ......... ......................... ................. . . . . . . . . 6 29 6.2-9 E2T5H Tree ..................................... ............ . . . . . . . . . . . 6-30 6.2 10 E2V5H Tree. . . . . . . . . . . . . .... ..... ... ................. .... ..... . . . . 6-31 6.2 11 H1-5H Tree. ........................ . ................ .. . . . . . . . . . . . . 6-3 2 6.2 12 T1 5 Tree .......................... ................. .. .. . . . . . . . . . 6-33 6.2-13 TSASH Tree .. ....................... .... ............ .................634 6.2-14 T5B5H Tree ....... ......... ....... ............. ...................... 6-35 6.2 15 TSC5H Tree .............. ..........................................636 6.2 16 T5D5H Tree ....................................... .. ................. . 6-37 6.2-17 TAB 5H Tree . . . . . . . . . . . . . . ............................. .................638 6.2 18 TD B5 H Tree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................. ....... . . . . . . 6 39 6.2 19 TIA5 H Tree . . . . . . . . . . . . . . . . . . . . . . . . . . . .......... ... ................ . . . 6 40 6.2-20 TIH P5 Tree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-41 6.2-21 TIOF5 Tree . . . . . . . . . ....................... ....................... . . . . 6-4 2 6.2-22 TIOPS Tree . . . . . . . ................... ............ .................... . 6-43 6.2-23 TLM5H Tree . . . . . . . . . . . . . . . . . . . . . . . . . . .... ............... . . . . . . . . . . . . . 6-44 6.2-24 TORV5 Tree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 5 6.2-25 TRPT5 Tree .............................. ...... . .... ....... ...... . . 6-46 6.3-1 AS Tree ......... .. ............ ................................... . . . 6-47 6.3-2 ASHY Tree . . . . . . . . . .............. .... . ...............................648 6.3-3 J2-5 Tree. . . . . . . . . . . . . . . . . ...... ............... .......... ... .... . . . 6-49 6.3-4 St.5 Tree ............ ........ ........... ... ... ......... ...... . 6-50 6.3-5 S 1 H.5 Trec . . . . . . . . . . . . . . . . . . . . . . . . . ... ........ . ....... .... . . . . . . . . . 6-51 6.3-6 S2-5 Tree .................... .......................... ....... ...... . 6-52 6.3-7 S2H-5 Tree . . ............................. .... .. ............... . . . . . 6-5 3 6.3-8 S 3-5 Tree . . . . . . . . . . . . . . . . . . .......... ... .. ......... ... ....... . . . . 6 54 NUREG/CR.6143 xiv Vol. 2, Part 1

List of Figures (Continued) 6.3-9 S3H-5 Tree . . . . . . . . . . . . . . . . .... .. ...... .... . ..... .. .. .. ... . . 6-55 m.3 1 wCS System schematic .... ....... .... .... . . ..... . .. ...... . . . . . . 8 -4 8.3-2 HPC3 Dependency Diagram . . . . . . . . . . . . . .. .. .... .. ............... . .. . 85 8.3 3 System Actuation Dependency Diagram (Page 1 of 2) ....... . ..... ........... . . . . . . 8 -6 3.3-3 System Actuation Dependency Diagram (Page 2 of 2) . ..... . .... ............. ... 8-7 0.4 1 CRD System Schematic . ... ........ . ....... .. .. ... ................ . 8 10 0.4-2 CRD Dependency Diagram. ............ . .. ... . ............ ... .. . . . . . . . 8-12 0.5 1 SPMU System schematic . . . . . . . . .... . ....... ......... ......... . . . . . . . 8-14 0.52 SPMU Dependency Diagram . . - . . . . ..... .... .. ......... ........... ... . ... 8-15 8.6-1 Condensate System Schematic . . . . . . . . . . . . . . . . ............... ............... . 8 17 8.6-2 Condensate Dependency Diagram ... ..... ...... . . ... ....-.......... .. . . . 8 18 8.7-1 LPCS System Schematic ... ...........................................8-20 C.7 2 LPCS Dependency Diagram . . . . . . . . .... . . ......... . ..... ..... ...... .. 8 21 3.8 1 LPCI System schematic . . . . . .......... . .. . ... .... .... .. ............ 8-24 0.8-2 LPCI Dependency Diagram ..... .. .. .. ...... .. ...... ....... ... .. ... 8-25 O A-1 SSW Crosstie System Schematic . . . . . . . . . ......... .. . .. . . ... . .. 8 28 8.9-2 SSW Crosstie Dependency Diagram . . .. .......... .... ...... ....... . . . . . . . 8-29 8.10-1 Firewater System Schematic . . . . . .. ..... . .............. .. . ...... ..... . 8 31 8.11 1 SPC System schematic .. ............... ... .... .... ............... . . 8 33 0.11-2 SPC Dependency Diagram . . . . . . . . . . . . .. ........ . . ..... . ... . . ........835 0.12 1 SDC System schematic . . . ..... ..... . ..... ....... . .. ... .... . . . . . . . 8-37 8.12 2 SDC Dependency Diagram . ... ....... .... .... ........ .......... . . . . . 8 39 8.13 1 CS System schematic .... .... . . ...... .... . . . . .. .... ... . . . 8-42 3.13-2 CS Dependency Diagram . . . . . . . ... . ... .. ...... . . ... . . 8-43 8.14-1 CVS System Schematic . . ... ...... ..... .... .. . .. . .. . .. . . . 8-46 8.14-2 CVS Dependency Diagram . . . . . . . ..... ............. ........ ...... ... . B-47 8.15 1 EPS System Schematic . . . ........ . . .. ........... . .... . . ..... . . 8-48 8.15-2 Diesel Generator Cross Tie Schematie. . . . .. .. ..... .. . .. ....... ...... . 8-51 3.15 3 EPS Dependency Diagram. . . . . . . . . . . . . . . . . .... ............... ....... . . . . 8 52 0.16-1 SSW System Schematic (Page 1 of 2) . . . . . . . . .............. .. .... . . . . . . . . . 8 54 8.16 1 SSW System Schematic (Page 2 of 2) . . . . . . . . . . . . . .... . ..... ........ .... ... . 8-53 0.16-2 SSW Depewlency Diagram . . . . . . . . ........... ..... . ... ...... .... .... . 8-57 0.17-1 EVS System schematic .(Page l of 2) . . . . . . . . . . . .... ........... ....... . . . . . . . . 8-5 9 3.17-1 EVS System schematic .(Page 2 cf 2) . . . . . . . . . . . . . ...... .. ....... ...... . . 8-60 3.17-2 EVS Dependency Diagram . . .......... .. . .. ............... . ... . . . . . . . . 8-61 8.18 1 1AS System Schematic . . . . . . . . . .... ... ... ......... ........... .. .. ... 8-63 8.10-2 1AS Dependency Diagram ................. ................. .. .. .... ..... 8-65 ( 0.19-1 SGTS System Schematic. . . . . . . . . . . . .......... .... ......... ..... .. . . . . 8-67 8.19-2 SGTS Dependency Diagram . . . . . ..... . ..... . ............ . ......... . . . 8-68 I 8.22-1 ADHR System schematic . . . . . . . . . .. ........ . .. ............... . . . . . . 8-71 0.22-2 ADHR Dependency Diagram ............. . .... ............. . .... . .. . . . 8-72 8.23 1 RWCU System schematic ........ ........... ......... ........ . ........... 8-74 ! 8.23-2 RWCU Dependency Diagram . . . . . . . . . . . . . . . ...... .... ..... . . .... .... .. . 8-75 , 8.24-1 RRS System Diagram ........... ...... . .... .......... . . . . ........ 8-77 8.24-2 RRS Dspendency Diagram . . . . . . .... ...... .... .. . . ... ...... . .. . . 8-78 0.25-1 CCW System Diar, ram . . . . . . . . . ..... . . . .............. . .... .. .. . . . 8 80 8.25-2 CCW Dependency Diagram . . . . . . .... ....... ...... ........ ..... ........ . 8-82 3.26-1 PSW System schematic (Page l of 2) . .. ............ ... ..... . ... . . . . 8-84 8.26 1 PSW System Schematic (Page 2 of 2) . . . . . ....... . .. . ...... . ... ..... .8-85 3.26-2 PSW Dependency Diagram . . . . . . . . . . . . .... ... .... .. . . .. . . . . 8 86 3.27-1 CRWST System schematic . . . . . . . . . ..... ...... ... . . .. .. . ... . . . 8-88 8.27 2 CRWST Dependency Diagram ... ....... . .. . . .. .. .... .. .. . . . 8-90 Vol. 2, Part 1 xv NUREG/CR-6143

List of Figures (Continued) i 8.28 1 ADS & SRV System Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 91 ADS & SRV Dependency Diagram . ........................ ....... . ........... 8-93 8.28-2 11.3.3-1 Overview of Mdhodology . . . . . . ..............................................1131 11.3.3 2. Results of Analysis ..........................................................11-42 14-1 Contribution to CDF by lnitiating Event .. ....................... ........... ...... 14-3 14-2 Percent of CDF vs Time Wialow ....... ........................................143 14-3 Fractional Contribution to CDF by IE Group vs Time Window ......................... .. 14 10 i 14 4 Percent of CDF and Percent of Time in Time Window vs Time Window . . . . . . . . . . . . . . . . . . . . . . 1410 i t l NUREG/CR.6143 xvi Vol. 2. Part 1

List of Tables 4.1.1 Imtiating Events for POSS . .............................. ............ ... ..... 42 4.1.2 Updated initiating Events for All POS . . . . . . . . . . . . . . . . . ............. . ............ 4-4 5.1.1 Success Criteria for Plant Operational State (POS) 5 ...... ........ ............. ...... 5-8 6.1.1 Generic System-Level Event Trees for Transients, POS 5 0 psig ...... ...... .......... .. 6-9 6.1.2 Generic System-Level Trees for Core Cooling, POS 5 0 psig . ... .... . . . . . . . . 6 12 6.1.3 Special Generic Eveny Trees, POS 5 0 psig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 12 6.1.4 Tree lnterfaces for POS S,0 psig ........................ ... .. i

                                                                                                                                         ................613 6.1.5        Generic System. level Event Trees for Transients, POS 51000 psig . . .......................620 6.1.6        Generic Trees for Core Cooling, POS 51000 psig . . . . . . . . . . . . .........................6-20 6.1.7        Tree Interfaces for POS 5,1000 psig ............ ......... .... ............                                                                          . . . . . 6 21 7.1          Plant Damage State Characteristics and Attributes .                                 .     .             .....           ....          ............                    7-3 8.2.1        Systems Included in the Grand Gulf Study . . . . . . . . . . . . . . . . . .                                     ......... ...... .....                               8-2 9.2.1        Shutdown Study Common Cause Events                 .......................................9-4 9.2.2        Dependent Failure Event Beta Factors and Probabilities . . . . . ............ .. ......                                                                 ..        . 9-5 10.1.1.1        HEP 1 Calculation . . . . . . . . . . . . . .        .     . . .                   .                   ..................                         . . . . . 10-6 10.1.1.2        Sequence Timing and Indications           ............... ...... ..                                               .. .. ....... ..                       . . 10-7 10.1.1.3        Potential Operator Action . . . . ........                         ..... ... . . .. ..............                                                . . . . . 10-8 10.1.1.4        Time Available to Diagnose and Perform the Task . . . . . . . . . . ..                                          .................                        . . 10-9 10.1.1.5        Operator Action Performance Time ............... .... ... .... .......                                                                       . . . . . . . 10-9 10.1.1.6        Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . .                                ... ....           . . . . . . 10 10 10.1.1.7        Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . ... ........... ......... . .                                                           . 10 10 10.1.1.8        Post-Diagnosis Actian. Type Identification . .                     . .. . .                        ...... ......                   . . . . . . . . . . .        10- 1 1 10.1.1.9        Post-Diagnosis Stress. level Identification . . . . . . . . . . .                    ...... .                     ............                  . . . .. . 10 11 10.1.1.10       Total HEP . . . . . . . . . . . . . . . . . . . ............                           .               .... .... ... ...                          .. .          10 12 10.1.2.1        HEP 2 Calculation . . . . . . . . ... ............. .... .......... .........                                                                            . 10-13 10.1.2.2        Sequence Timing and indications . . . . . . . . . . . . . . . ... .......                                         . . . . . . . . . . . . . . . . . .           10- 14 10.1.2.3        Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..                                     ...     . . . . . . 10-15 10.1.2.4        Time Available to Diagnose and Perform the Task . .                             ............... ..... ..                                        . . . . . 10 15         ;

10.1.2.5 Operator Action Performance Time . . . . . . . . . . . . . . . .. ... ................ . 10 16 10.1.2.6 Diagnosis Time for Operator Action . . . . . . . . . . . . ........... ... ......... ... . 10 17 10.1.2.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . ...... .............................10-17 10.1.2.8 Post-Diagnosis Action Type Identificationper Step 10, 81 of ASEP HRAP . . . . ... ....... . 10-18 10.1.2.9 Post. Diagnosis Stress-LevelIdentificationper Step 10, 8-1 of ASEP HRAP . . . ........... 10-18 10.1.2.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . .... ... ..................... . . 10 19 10.1.3.1 HEP 3 Calculation . ................... .. ........ . ............ . . . . . 10-20 10.1.3.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . ................ ..... . . . 10-21 10.1.3.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . ...... ........... . ... 10-21 i 10.1.3.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . .. ........... .. . 10-22 10.1.3.5 Operator Action Performance Time . . . . . . . . . . . . . . ............... . . . . . . . 10-22 10.1.3.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-2 3 10.1.3.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . ........................... . . . . 10-23 10.1.3.8 Poct-Diagnosis Action Type Identificationper Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-24 10.1.3.9 Post-Diagnosis Stress-Level Identificationper Step 10, 81 of ASEP HRAP , . . . . . . . . . . . . . . . . 10-25 10.1.3.10 Total H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............... .. . . . . 10-26 10.1.4.1 HEP 4 Calculation . . . . . . . . . . . . ......... .................. ... .. ...... 10 27 1 10.1.4.2 Sequence Timing and hxlications . . . . . . . . . . . . . . .... . .. ..... .... . 10-28 10.1.4.3 Potential Operator Action . . . . ........ . .... .. . .. . ........ . . 10-28 Vol. 2, Part 1 xvii NUREG/CR-6143 i I i

List of Tables (Continued) 10.1.4.4 Time Available to Diagnose and Perform the Task . . . . . . ....... .. .............. . 10-29 10.1.4.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 2 9 10.1.4.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . ............. ....... . . . . . 10-30 , 10.1.4.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............. . 10-30 10.1.4.8 Post-Diagnosis Action Type Identification per Step 10. 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10 31 10.1.4.9 Post-Diagnosis Stress.levelldentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10 31 10.1.4.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . .. ....................... . . . . . . . . . . . . . . . 10 3 2 10.1.5.1 HEP 5 Calculation . . . . . . . . . . . . .... .. .................................. 10-33 10.1.5.2 Sequence Timing and indications . . . . . . . . . . . . . . . . ................ . . . . . . . . . . . . 10 34 10.1.5.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . .............. .... . . . . . . . 10 34 10.1.5.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-35 10.1.5.5 Operator Action Performance Time ............................................1036 10.1.5.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 37 f 10.1.5.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-37 l 10.1.5.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-3 8 10.1.5.9 Post. Diagnosis Stress.levelIdentification per Step 10, 8-1 of ASEP HRAP ...... . . . . . . . . . 10-38 10.1.5.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . ..................... ... . . . . . . . . . . . 10-3 9 , 10.1.6.1 HEP 6 Calculation . . . . . . . . . . . . . . . . . . . . ... . ......... ... ........ .... 10-40 l 10.1.6.2 Sequence Timing and indications . . . . . ....... .... . .... .......... . . . . . . 10-41 10.1.6.3 Potentia 10perator Action . . . . . . . . . . . . ... ..... ... .. .. ............ . 10-41 10.1.6.4 Time Available to Diagnose and Perform the Task ........ ....... . . . . . . . . . . . . 10-42 10.1.6.5 Operator Action Performance Time . . . . . . . . ................ ............ .... . 10 42 l , 10.1.6.6 Diagnosis Time for Operator Action . . . . . . . . ................... .......... . . 10-43 ! 10.1.6.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . ... ............... . ............... 10-43 10.1.6.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10 44 10.1.6.9 Post-Diagnosis Stress. Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-44 10.1.6.10 Total H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............. . 10-45 10.1.7.1 HEP 7 Calculation . . . . . . . . . .... ....................... . . . . . . . . . . . . . . . 10-4 6 10.1.7.2 Sequence Timing and indications ............ ................... ......... . 10-47 10.1.7.3 Potentia 10perator Action . . . . . . .. .............. ......... ... ....... . . . 10-48 10.1.7.4 Time Available to Diagnose and Perfonn the Task . . . . . . . . . . . . . . ... .......... . . . 10-49 10.1.7.5 Operator Action Performance Time ....... ... .......... ........ . . . . . . . . . . 10 5 0 10.1.7.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-51 10.1.7.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............. . 10-51 10.1.7.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . ...... . 10-52 10.1.7.9 Post-Diagnosis Stress-LevelIdentification por Step 10, 8-1 of ASEP HRAP . . ...... . . . . . . . 10-52 , 10.1.7.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . ..................................10-53 10.1.8.1 HEP 8 Calculation . . . . . . . . . . . .... .................................. . . . 10-54 10.1.8.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 5 10.1.9.1 H EP 9 Calculat ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-56 , 10.1.9.10 Tota 1 HEP................................................... ..... .. 10 57 10.1.10.1 HEP 10 Calculation .................... ............................ . . . . 10 5 8 10.1.10.2 Sequence Timing and indications . . . . . . . . . . . . . . . . . . . . ....... . . . . . . . . . . . . . . . . . 10 5 9 10.1.10.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... . . . . . 10-59 ' 10.1.10.4 Time Available to Diagnose and Perform the Task . . . ...... ... . . . . . . . . . . . . . . . . . . . 10-60 10.1,10.5 Operator Action Performance Time . . . . . . . . . . . . .................. ............ 10-60 10.1.10.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......... . . . 10-61 , 10.1.10.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....... 10-61 10.1.10.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAF . . ......... .. . 10-62 10.1.10.9 Post. Diagnosis Stress. level ldentification per Step 10, 81 of ASEP HRAP , . . . . . . . . . . . . . . . . 10-62 10.1.10.10 Tota 1 HEP . . . . . . . . . . . . . . . . . ......... ...................... . ....... 10-63 10.1.11.1 HEP 11 Calculation .................................. ..... ....... .... 10-64 10.1.11.2 Sequence Timing and indications . . . . . . . ..... .............. .. . .. . .. . . . . 10-65 NUREG/CR-6143 xviii Vol. 2. Part 1 ;

List of Tables (Continued) 10.1.11.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1045 10.1.11.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-66 10.1.11.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-67 10.1.11.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-68 10.1.11.7 Diagnosis Analysis . . . . . . . . . . . . . . ................................ . . . . . . . 10-68 10.1.11.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-69 10.1.11.9 Post. Diagnosis Stress-LevelIdentification par Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-69 10.1.11.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . ....................................10-70 10.1.12.1 HEP 12 Calculation ......................................................10-71 10.1.12.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-72 10.1.12.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . .................... . . . . . . . . . . . . 10-72 10.1.12.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-73 10.1.12.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 73 10.1.12.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . 10-74 10.1.12.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-74 10.1.12.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-75 10.1.12.9 Post-Diagnosis Stress-Level Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10 75 10.1.12.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . ...................................10-76 i 10.1.13.1 HEP 13 Calculation ..................................... . . . . . . . . . . . . . . . 10-77 10.1.13.2 Sequence Timing and indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 78 10.1.13.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . .. ........................ . . . . 10-78 10.1.13.4 Time Available to Diagnose and Perform the Task . . . . . . . ........ ......... ... .. 10 79 10.1.13.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-8 0 10.1.13.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-81 10.1.13.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ...... . . . . . . . . . 10-81 10.1.13.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-82 10.1.13.9 Post-Diagnosis Stress-Level Identific.ation per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-82 10.1.13.10 Tota 1 HEP . . . ......................................................... 10-83 10.1.14.1 HEP 14 Calculation . . . . . . . . . .................................... . . . . . . . 10-84 10.1.14.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-85 10.1.14.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-85 10.1.14.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-86 10.1.14.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-87 i 10.1.14.6 Diagnosis Time for Operator Action . . . . . . . . . .............. .. . . . . . . . . . . . . . . . . 10-8 8 10.1.14.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-8 8 10.1.14.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-8 9 10.1.14.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-89 10.1.14.10 Tota 1 HEP............................................................ . 10-90 10.1.15.1 HEP 15 Calculation ......................................................10-91 10.1.15.2 ' Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . 10-92 10.1.15.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-93 10.1.15.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-94 10.1.15.5 Operator Action Performance Time . . . . . . . . . . . . . . . ............................10-95 , 10.1.15.6 Diagnosis Time for Operator Action . . . . . . .....................................10-96 10.1.15.7 Diagnosis Analysis . . . . . . . . . ............................................10-96 ' 10.1.15.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-97 10.1.15.9 Post-D.ignosis Stress-leve11dentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10f7 10.1.15.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-9 8 10.1.16.1 HEP 16 Calculation ......................................................10-99 10.1.16.2 Sequence Timing and indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . .. 10-100 10.1.16.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....... . ... 10 100 10.1.16.4 Tirne Available to Diagnose and Perform the Task . .......... . . . . . . . . . . . . . . . . . . . . 10- 101 10.1.16.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... 10 101 Vol. 2, Part 1 xix NUREG/CR-6143

t i h List of Tables (Continued) : I

10.1.16.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-102 10.1.16.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-102 ' { 10.1.16.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10103 10.1.16.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-103 l 10.1.16.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 104 f 10.1.17.1 HEP 17 Calculation . . . . .................................................10-105 10.1.17.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-106 , 10.1.17.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-106 ; Time Available to Diagnose and Perfonn the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-107 ; 10.1.17.4 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-108 i 10.1.17.5 10.1.17.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-109 t 10.1.17.7 Diagnosis Anelysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-109 : 10.1.17.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-110 10.1.17.9 Post-Diagnosis Stress.LevelIdentification per Step 10, 8-1 of ASEP HRAP , . . . . . . . . . . . . . . . 10-110 .; ' 10.1.17.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 1 1 1 10.1.18.1 HEP 18 Calculation . . . . ................................................. 10-112 10.1.18.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-113 j 10.1.18.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-113 ; 10.1.18.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-114 l 10.1.18.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-114 ; 10.1.18.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-115 10.1.18.7 Diagnosis Ar alysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-1 15 , 10.1.18.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-116 ! 10.1.18.9 Post-Diagnosis Stress.LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-116 10.1.18.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 1 17 l 10.1.19.1 HEP 19 Calculation . . . . .................................................10-118 ; 10.1.19.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-118 l 10.1.19.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-119 l 10.1.19.4 Time Avai1=hle to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-119 l t 10.1.19.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . 10-120 10.1.19.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 121, i 10.1.19.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-121 : l 10.1.19.8 Post-Diagncsis Action Type klentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-122 10.1.19.9 Post-Diagnosis Stress-levelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-122 : 10.1.19.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 123 t 10.1.20.1 HEP 20 Calculation . . . ..................................................10-124 , 10.1.20.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 125 10.1.23.1 HEP 23 Calculation . . . ............................. . . . . . . . . . . . . . . . . . . . . 10-126 l 10.1.23.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -. 10- 127 ! l 10.1.25.1 HEP 25 Calculation . . . .................................................10-128-10.1.25.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-129 ! j 10.1.25.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 129 10.1.25.4 Time Available to Diagnose azul Perform the Task . . . . . . -. . . . . . . . . . . . . . . . . . . . . . . . . . . 10-130 j 10.1.25.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-130 10.1.25.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-131 ; 10.1.25.7 Diagnoris Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . 10-131 10.1.25.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-132 j 10.1.25.9 Post-Diagnosis Stress-Leve11dentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10132 ; 10.1.25.10 Tea 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 13 3 j 10.1.26.1 HEP 26 Celculation . . . ..................................................10-134 10.1.26.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-135 10.1.26.3 Potentia 10perator Action . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 135 10.1.26.4 Time Available to D;agnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 136 f t NUREG/CR-6143 xx Vol. 2, Part 1 ! J P 1

              .m  .     ., -           ,,-m. . . . -,_. - .

1 1 1 List of Tables (Continued) 10.1.26.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... .... 10 136 10.1.26.6 Diagnos is Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-137 ! 10.1.26.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-137 l 10.1.26.3 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-138 ' 10.1.26.Y Post-Diagnosis Stress. Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10 138 10.1.26.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 13 9 10.1.27.1 HEP 27 Calculation .....................................................10140 10.1.27.2 Sequence Timing and Indications . . . . . . . . . . . . . . ..... ............. ...... . .. 10-141 l 10.1.27.3 Potential Operator Action . . . . . . . . . . . . . . . . . .................. . . . . . . . . . . . . 10-141 10.1.27.4 Time Available to Diagnose and Perfonn the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10-142 10.1.27.5 Operator Action Performame Time . . . . . . . . . . ................ . . . . . . . . . . . . . . . 10-14 2 10.1.27.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10143 10.1.27.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . ................. . . . . . . . . . 10 143 10.1.27.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10 144 10.1.27.9 Post-Diagnosis Stress.LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-144 10.1.27.10 Total HEP . . . . . . . . . . . . . . . . .......................... .... ..... .. 10-145 10.1.28.1 HEP 28 Calculation ............ .................. . ................... 10 146 10.1.28.2 Sequence Timing and Indications . . . . . . . . . . . ... ....... .... ........ . . . . 10-147 10.1.28.3 Potential Operator Action . . . . . . . . . . . . . . . . . . .. ............. . . . . . . . . . . . . . 10 147 10.1.28.4 Time Available to Diagnose and Perfonn the Task . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 14 8 10.1.28.5 Operator Action Performame Time . . . . . . . . . . . . . . . ........... .. . . . . . . . . . . . 10-148 10.1.~.S.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . ............ ....... ... 10-149 10.1.28.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . .......................... . . . . . 10-149 10.1.28.8 Post-Diagnosis Action Type Identification . ........ ............ . . . . . . . . . . . . . . 10 150 10.1.28.9 Post-Diagnosis Stress-I.evelIdentification per Step 10, 8-1 of ASEP HRAP . . . ....... .. . 10-150 10.1.28.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . ................. ........... .... 10 151 10.1.29.1 HEP 29 Calcul tion .................................................. . . 10 152 10.1.29.2 Sequence Timing and Indications ..........................................10-153 10.1.29.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 154 10.1.29.4 Time Available to Diagnose and Perform the Task . ..................... ....... 10 155 10.1.29.5 Operator Action Performance Time . ................... ..... . . . . . . . . . . . . . . 10-155 10.1.29.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 15 6 10.1.29.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-15 6 10.1.29.8 Post-Diagnosis Action-Type Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-157 ' 10.1.29.9 Post-Diagnosis Stress.Leve11dentification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 157 10.1.29.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . ... ......... .................. ... . 10 158 10.1.30.1 HEP 30 Calculation ........... .......................... ....... . . . . . . 10 15 9 10.1.30.2 Sequence Timmg and indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 160 10.1.30.3 Potentia] Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-160 10.1.30.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-161 10.1.30.5 Operator Action Performame Time . . . . . . . . . . . . . . . . . . . . . . . . . . . ............... 10-161 10.1.30.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-162 10.1.30.7 Diagnosis Analys is . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 162 10.1.30.8 Post-Diagnosis Action Type Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 163 10.1.30.9 Post. Diagnosis Stress. Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10 163 10.1.30.10 Total H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 164 10.1.31.1 HEP 31 Calculation ..................................... ....... . . . . . 10-165 10.1.31.2 Sequence Timing and Indications . . . . . . . . . . . .. ............ . . . . . . . . . . . . . . . . . 10 166 10.1.31.3 Potential Operator Action . . . . . . . . . . . . . . . . . ................ ..... . . . . . . . . 10-166 10.1.31.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . ...... .............. 10 167 10.1.31.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . . . . . 10 167 10.1.31.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . ... ........... . . 10-168 10.1.31.7 Diagnosis Analysis . . . . . . . . . . . . . . ........... . ...... .. ..... ... 10 168 Vol. 2, Part i ni NUREG!CPv6143

List of Tables (Continued) 10.1.31.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . 10 169 10.1.31.9 Post. Diagnosis Stress-I.evelldentification per Step 10. 81 of ASEP HRAP ... . . . . . . . . . . . 10 169 10.1.31.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................... . 10-170 10.1.33.1 HEP 33 Calculation ........................................ . . . . . . . . . . . . 10-171 10.1.33.10 Total H EP . . . . . . . . . . . . . ............................................10172 10.1.34.1 HEP 34 Calculation .....................................................10-173 10.1.34.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......... ...... ...... 10-174 10.1.35.1 HEP 35 Calculation ..................................... .......... . . . . 10-175 10.1.35.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 176 10.1.35.3 Potential Operator Action . . . . . . . . . . . . . . . . ............................ . . . . 10-176 10.1.35.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10177 10.1.35.5 Operator Action Performance Time . . . . . . . . . . . ................. . . . . . . . . . . . . . 10 177 10.1.35.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-178 10.1.35.7 Diagnosis Analysis . .................. .................................10-178 10.1.35.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10179 10.1.35.9 Post-Diagnosis Stress-Leve11dentification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . 10-179 10.1.35.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............. .. ... 10-180 10.1.37.1 HEP 37 Calculation .............. ....... .................. . . . . . . . . . . . 10 181 10.1.37.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 182 10.1.37.3 Potentia 10perator Action . . . . . . . . . . . . ......... .... . . . . . . . . . . . . . . . . . . . . . . 10- 182 10.1.37.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-183 10.1.37.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....... .. . 10-184 10.1.37.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . ............. . 10-185 10.1.37.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............... . 10 185 10.1.37.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . .... ... 10-186 10.1.37.9 Post-Diagnosis Stress-bvel Identification pt r Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10 186 10.1.37.10 Tota 1 HEP............................................................ 10-187 ! 10.1.38.1 HEP 38 Calculation ......................................... .... .. . . 10 188 l 10.1.38.2 Sequence Timing and indications . . . . . ................ ............... . . . . 10-189 10.1.38.3 Potential Operator Action . . . . . . . . . . ......................... ... . . . . . . . . 10-190 l 10.1.38.4 Time Available to Diagnose and Porionn the Task . . . . . . . . . . . .............. . . . . . . 10 191 l 10.1.38.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 192 10.1.38.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . 10-193 i 10.1.38.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10- 193 ! 10.1.38.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-194 l 10.1.38.9 Post-Diagnosis Stress-hvelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10 194 10.1.38.10 Tota 1 HEP ...........................................................10195 l 10.1.39.1 HEP 39 Calculation .....................................................10-196 10.1.39.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 197 10.1.39.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-197 10.1.39.4 Time Available to Diagnose and Perform the Task . . . . ....................... ... 10 198 l 10.1.39.5 Operator Action Perfonnance Time . . . . . . . . . . . ...... .......... . . . . . . . . . . . . . 10-198 10.1.39.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . .... . . . . . . . . . . . . . 10 199 10.1.39.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . . . . . . . . . . . . 10-199 10.1.39.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-200 10.1.39.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-200 l 10.1.39.10 Total H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . 10-201 10.1.40.1 HEP 40 Calculation .................... .... ..... ....... ........ . . 10-202 10.1.40.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-203 10.1.40.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . ................. ..... .... . . 10-203 , 10.1.40.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . .............. . .. 10-204 10.1.40.5 Operator Action Performance Time . . . . . . . . . . . ............ . . .. ........ . 10-205 l 10.1.40.6 Diagnosis Time for Operator Action . . . . . . . . . .... . ... ..... ... ....... .. 10-206 NUREG/CR-6143 xxii Vol. 2. Part 1

List of Tables (Continued) 10.1.40.7 Diagnosis Analysis . . . . . . . . . . . . . . . ......................................10-206 10.1.40.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-207 10.1.40.9 Post-Diagncsis 3 tress. Level Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-207 10.1.40.10 Total H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-20 8 10.1.41.1 HEP 41 Calculation ............................................. . . . . . . . 10-209 10.1.41.10 Tota 1 HEP . . . .. . .. .... ....................................... . . . . . 10-210 10.1.42.1 HEP 42 Calculation ........................................ . ....... . . 10-211 10.1.42.2 Sequence Tirning and Indications .................. ...... ............. .... 10-212 10.1.42.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-212 10.1.42.4 Tirne Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 213 10.1.42.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-213 10.1.42.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-214 10.1.42.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . 10-214 10.1.42.8 Post. Diagnosis Action Type Identifiestion per Step 10, 8-1 of ASEP HRAP . . . . . . . ........ 10-215 10.1.42.9 Post. Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-215 10.1.42.10 Total HEP . . . . . . . . . . . . . . . . . . ....................... ...... ... . . . . . . 10-216 10.1.46.1 HEP 46 Calculation ... ..............................................10-217 10.1.46.2 Sequence Timing and Indications . . . . . . . . . . . .......................... . . . . 10-218 10.1.46.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-219 10.1.46.4 Time Availrble to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 220 10.1.46.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-221 , 10.1.46.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-222 10.1.46.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-222 10.1.46.8 Post. Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . ...... . . . . . . 10-223 10.1.46.9 Post-Diagnosis Stress.IevelIdentification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . 10-223 , 10.1.46.10 Tota 1 HEP . . . . . . . . ...................................................10-224 10.1.47.1 HEP 47 Calculation ........................................ ............ 10-225 10.1.47.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-226 10.1.47.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 226 10.1.47.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-227 10.1.47.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . ....... ....... . . .. 10-228 10.1.47.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... . . . . . 10-229 10.1.47.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-229 10.1.47.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10 230 ! 10.1.47.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-230 10.1.47.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . .......................................10-231 10.1.48.1 HEP 48 Calculation .................................................. .. 10-232 10.1.48.2 Sequence Timing and Indications ........................ ................... 10-233 10.1.48.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-233 10.1.48.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-234 10.1.48.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-234 10.1.48.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-235 10.1.48.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-235 10.1.48.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . 10-236 l 10.1.48.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-236 10.1.48.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... . . . 10-237 10.1.49.1 HEP 49 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . ....... .............. ... 10-238 10.1.49.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . ......................... . . . . . . . 10-239 ' 10.1.50.1 HEP 50 Calculation .......... .......... ............................... 10-240 10.1.50.2 Sequence Timing and Indications . . . ....... ....................... ... . . . . . 10-241 10.1.50.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . ............... ...... . . 10-241 10.1.50.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . 10-2 4 2 10.1.50.5 Operator Action Performance Time . . . . . . . . . . . . .................... .. ...... 10-242 Vol. 2, Part 1 xxiii NUREG/CR.6143

List of Tables (Continued) Diagnosis Time for Operator Action . . . . . . . . . . . . .......... .................... 10-243 10.1.50.6 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ 10-243 10.1.50.7 10.1.50.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . ...... . . 10-244 10.1.50.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-244 Total H EP . . . . . . . . . . . . . . . . . . . . . .................. ... . . ....... .... 10-245 10.1.50.10 HEP 51 Calculation .................... .. ........... .... . ..... .... 10-246 10.1.51.1 10.1.51.2 Sequence Timing and Indications . . . ................. ........ ............... 10-247 Potential Operator Action . . . . . . . . . . . . . . . . . . . .. ... ....... ............... 10 247 10.1.51.3 10.1.51.4 Time Available to Diagnose and Perform the Task . . . . . . ........... ......... .. 10 248 10.1.51.5 Operator Action Performance Time . ....... .............................. .. 10-249 10.1.51.6 Diagnosis Time for Operator Action . ...................................... .. 10 250 10.1.51.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . ................... ... .. 10-250 10.1.51.8 Post. Diagnosis Action Type Identification per Step 10, 8-lof ASEP HRAP . . . . . . . . . . . . . . . . . 10-251 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . ... .......... 10-251 10.1.51.9 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....... ..... 10-252 10.1.51.10 10.1.52.1 HEP S2 Calculation ............................... ....... .. ....... .. 10-253 10.1.52.2 Sequence Timing and Indications .... ... .......... ..... .. .... .... .. . 10-254 10.1.53.3 Potential Operator Action . . . . . . . .... ..... .............. ........... . . 10-254 Time Available to Diagnose and Perform the Task . . . . . . ........ ..... ..... ...... 10-255 10.1.52.4 Operator Action Performance Time . . . . . . .... ............. ........ . ..... 10 255 10.1.52.5 Diagnosis Time for Operator Action . . . . . . . . . . . . . ....... ........ ..... ...... 10-256 10.1.52.6 Diagnosis Analysis . . . . . . . . . . . . ......... .. ........... 10-256 10.1.52.7 ..... ... ..... Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . ..... 10-257 10.1.52.8 10.1.52.9 Post Dhgnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . .... .. . .. . 10-257 ; 10.1.52.10 Total HEP . . . . . . . . . . ..... ........ .......... .... ............. .. 10 258 10.1.54.1 HEP 54 Calculation ............... ... ............... ........... .. 10-259 . .10.1.54.2 Sequence Timing and Indications ........................................10-260 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . .............. ........ 10-260 10.1.54.3 10.1.54.4 Time Available to Diagnose and Perform the Task . . . . ......................... .. 10-261 Operator Action Performance Time . . . . . ........... ... ...................... 10-261 10.1.54.5 10.1.54.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . ............ .. . 10-262 10.1.54.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . ........ 10-262 10.1.54.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . ............ 10-26') 10.1.54.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP ... .......... . 10 263 10.1.54.10 Total HEP . . . . . . . . . . . . . . . . . . ....................... ... ....... . . . 10-264 ; 10.1.56.1 HEP 56 Calculation ................... ........... ....... .. ..... ..... 10-265 10.1.56.2 Sequ:nce Timing and indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......... 10 266 10.1.56.3 Potenti=1 Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-266 , Time Available to Diagnose and Perform the Task . . . . . . . .......................... 10-267 10.1.56.4 , 10.1.56.5 Operator Action Performance Time . . . . . . . . . . . . . . .. ...... .............. .. 10-267 ! 10 268 ! 10.1.56.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . ; . . . .......... .. ,........ 10.1.56.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............... 10 268 10.1.56.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP URAP . . . . . . ...... .. 10-269 , 10.1.56.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-269 10.1.56.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... .. 10-270 10.1.57.1 HEP 57 Calculation ............... ........... ...... .... ....... . . . . M-271 10.1.57.2 Sequence Timing and Indications ............ .......... . . . . . . . . . . .... . 10-272 10.1.57.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . ........... ........ . . . . 10-272 10.1.57.4 Time Available to Diagnose and Perform the Task . . . .................. .... . . . 10-273 10.1.57.5 Operator Action Performance Time . ................. ................. .. . 10-273 : 10.1.57.6 Diagnosis Time for Operator Action . . . . . . . . . . . . ........................... . . 10-274 10.1.57.7 Diagnosis Analysis . . . . . . . . . . . . .............. ...... . ... ....... .. 10 274 10.1.57.8 Post-Diagnosis Action Type Identification per Step 10,8-1 of ASEP HRAP . . . . .. .. . . . 10-275 NUREG/CR-6143 uiv Vol. 2, Part 1

List of Tables (Continued) 10.1.57.9 Post-Diagnosis Stress.LevelIdentification per Step 10,8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10 275 10.1.57.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........................... 10-276 10.1.58.1 HEP 58 Calculation .......... ..........................................10-277 10.1.58.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 278 10.1.58.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-278 10.1.58.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 279 10.1.58.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . ......... ............ 10-279 10.1.58.6 Diagnosis Time for Operator Action . . . . . . . . . . . . ............................... 10-280 10.1.58.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . ......................... .. . 10-280 10.1.58.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP , . . . . . . . . . . . . . . . 10 281 10.1.58.9 Post-Diagnosis Stress.leve11dentification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10 281 10.1.58.10 Tota 1 HEP............................................................ 10-282 10.1.59.1 HEP 59 Calculation .....................................................10283 10.1.59.2 Soquence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-284 10.1.59.3 Potential Operator Action . . . . . . . . . . . . . . . . . .. .................... ......... 10-284 10.1.59.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10-285 10.1.59.5 Operator Action Performance Time . . . . . . ................ ................... 10 286 10.1.59.6 Diagnosis Time for Operator Action . ....... ................................. 10 287 10.1.59.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . ................ ..... ............. 10-287 10.1.59.8 Post. Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . ......... 10-288 10.1.59.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 81 of ASEP HRAP . . . ............. 10 288 10.1.59.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... .. . 10 289 10.1.60.1 HEP 60 Calculation .....................................................10290 10.1.60.2 Sequence Timing and Indications . . . . . . . . . . . . ................................. 10 291 10.1.60.3 Potentia 10perator Action . . . . . . . . . ..................................... . . 10-291 10.1.60.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-292 10.1.60.5 Operator action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10-293 10.1.60.6 Diagnosis Time for Operator Action . . . . . . . . . . .......... ...................... 10-294 10.1.60.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-294 10.1.60.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP ................ 10-295 10.1.60.9 Post. Diagnosis Stress.Leve11dentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-295 10.1 60.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... 10 'e96 10.1.61.1 HEP 61 Calculation .................................................... . 10-297 10.1.61.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-298 10.1.61.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-298 10.1.61.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-299 10.1.61.5 Operator Action Performance Time . . . . . . ............... ........ ............ 10-299 10.1.61.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......... 10 300 10.1.61.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................... 10 300 10.1.61.9 Post-Diagnosis Stress. Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . ... 10 301 10.1.61.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............ . 10-302 10.1.63.1 HEP 63 Calculation ............................ ......................... 10-303 10.1.63.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ... 10 304 10.1.63.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 304 10.1.63.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . .... . . . . 10-305 10.1.63.5 Operator Action Performance Time . . . . . . . . . . . ................... ............ 10-306 10.1.63.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . ... .... . . . . . . 10-307 10.1.63.7 Diagnosis Analysis . . . . . . . . . ... ............................. . ..... .. 10-307 10.1.63.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . .. ...... . 10 308 10.1.63.9 Post-Diagnosis Stress-Ievel Identification per Step 10, 81 of ASEP HRAP ............. . 10-308 10.1.63.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....... .... .... . ........ 10 309 10.1.64.1 HEP 64 Calculation ..... ...........................................10-310 10.1.64.2 Sequence Timing and Indications . . . . . . . . . . . . . .......... ... . . .... .. . 10-311 Vol. 2, Part I uv NUREG/CR-6143

l l l LIST of Tables (Continued) , 1 l Potential Operator Action . . . . . . . . . . .. ........ ..... ........... ......... 10-311 10.1.64.3 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... 10 312 l 10.1.64.4 Operator Action Performance Time . . . . . . . ........ ........................... 10-312 10.1.64.5 10.1.64.6 Diagnosis Time for Operator Action . . . . . . .................... .. ....... . . 10-313 Diagnosis Analysis ........................... ... ............ ...... 10 313 l 10.1.64.7 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . ..... ......... 10 314 10.1.64.8 l Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . ........... 10 314 10.1.64.9 10.1.64.10 Total HEP . . . . . . . . ....... .... ...... ..... ...................... . 10-315 HEP 65 Calculation .... ........... . . ....... . 10 316 10.1.65.1 ........... ........ Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................... ....... 10-317 10.1.65.10 HEP 66 Calculation ........ .................................. ..... 10 318 10.1.66.1 10.1.66.2 Sequence Timing and indications . . . . . . . .. ........... .. ..... ...... .. . . 10-319 10.1.66.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . . 10-319 10.1.66.4 Time Available to Diagnose and Perform the Task . . . . ....... .......... . .... . 10 320 10.1.66.5 Operator Action Performance Time . . . . . . ....... .............. . ...... . 10-320 Diagnosis Time for Operator Action . . . . . . . ........... ... .... .... .... 10-321 10.1.66.6 ... Diagnosis Analysis . . . . . . . . . . . . . . . . . . . .............. . ... .. 10 321 10.1.66.7 ....... Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . ... .... 10-322 10.1.66.8 10.1.66.9 Post. Diagnosis Stress.I.evel Identification per Step 10, 8-1 of ASEP HRAP . . ....... .. .. 10-322 Total H EP . . . . . . . . . . . . . . . . . . . . . . . ..... ....................... ....... 10-323 10.1.66.10 10.1.66.1 HEP 66 Calculation .......... ........ .... . .......... ...... . .. .. 10 324 10.1.66.2 Sequence Timing and Indications . . . . . . .................. ...... .... .. . 10 325 10.1.66.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . ...... .. ..... .... ....... . 10-325 10.1.66.4 Time Available to Diagnose and Perform the Task . . . . . ....... ........... ... . 10 326 10.1.66.5 Operator Action Performance Time . . . . . ... ..... ... . ......... ..... .. 10 326 10.1.66.6 Diagnosis Time for Operator Action . . . . . ... ............................ .... 10 327 10.1.66.7 Diagnosis Analysis . . . . . . . . . . . . . . ....... .. ..... ............. ........ 10 327 10.1.66.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . ....... . . 10-328 10.1.66.9 Post-Diagnosis Stress.l.evelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . ........ 10 328 10.1.66.10 Total HEP . . . . . . . . . . ......... .. .. ....... ....... ......... .... . 10 329 10.1.67.1 HEP 67 Calculation ......... ........... ......... .. . ............... . 10-330 10.1.67.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . ........................ ............. 10-331 10.1.68.1 HEP 68 Calculation ........................ ............... ....... ..... 10-332 10.1.68.2 Sequence Timing and Indications . . . . . . . . . ...................... ........ .... 10 333 10.1.68.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . .. ...... ......... ......... 10-333 10.1.68.4 Time Available to Diagnose and Perform the Task . . ........ ... .......... ....... 10-334 10.1.68.5 Operator Action Performance Time . . . . ........ .......... .... . ...... .. 10-334 10.1.68.6 Diat,nosis Time for Operator Action . . . . .... .. ........ ...... . ... ....... . 10-335 10.1.68.7 Diagnosis Analysis . . . . . . . . . . . . . . ...................... ............. .. 10-335 10.1.68.8 Post-Ditgnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . .. . . ...... 10 336 10.1.68.9 Post-Diagnosis Stress-I.evel Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-336 10.1.68.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . .. . ..... ....................... . 10 337 10.1.69.1 HEP 69 Calculation ............................... ....... ... .......... 10 338 10.1.69.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ 10 339 10.1.69.3 Potential Operator Action . . . . . . . . ....... .. . ............. .......... .... 10 339 10.1.69.4 Time Available to Diagnose and Perform the Task . ........... ........ . ......... 10-340 10.1.69.5 Operator Action Perfeemance Time . . . . . . . . . . . . . . . ..... ...... ...... ........ 10 340 10.1.69.6 Diagnosis Time for Operator Action . . . . . . .............. ... .. ... ....... . 10-341 10.1.69.7 Diagnosis Analysis . . . . . . . . ........................................10341 10.1.69.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP ...... .. ... 10-342 10.1.69.9 Post. Diagnosis Stress Level Identification per Step 10, 81 of ASEP HRAP . . . . . ......... 10-342 10.1.69.10 Total H EP . . . . . . . . . . . . . . . . . . . . ..... ... .... . . . ....... .. . 10 343 10.1.70.1 HEP 70 Calculation .... ........ .......... .. . . .... . ...... . 10-344 NUREG/CR-6143 xxvi Vol. 2, Part 1

List of Tables (Continued) 10.1.70.2 Segt.mee Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-345 10.1.70.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................ 10-345 10.1.70.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . ...................... 10-346 10.1.70.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . ....................... 10-346 10.1.70.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-347 10.1.70.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-34 7 10.1.70.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-348 10.1.70.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-348 10.1.70.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-34 9 10.1.71.1 HEP 71 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-35 0 10.1.71.10 Tota 1 HE P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . 10-3 51 10.1.73.1 HEP 73 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-352 10.1.73.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 5 3 10.1.74.1 HEP 74 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-354 10.1.74.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10-355 10.1.74.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...................... 10-355 10.1.74.4 Time Available to Diagnose and Perform the Task . . . . .................. ........ . 10-356 10.1.74.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......... 10-356 10.1.74.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . .. ............... . 10-357 10.1.74.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . ............................. 10-357 10.1.74.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-358 10.1.74.9 Post-Diagnosis Stress. Level Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . 10 358 10.1.74.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 5 9 10.1.75.1 HEP 75 Calculatics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-360 10.1.75.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . ............................ 10-361 10.1.75.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . ............................. 10-361 10.1.75.4 Time Avaa .able to Diagnosa and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-362 10.1.75.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......... 10-362 10.1.75.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-363 10.1.75.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . .................. ......... 10 363 10.1.75.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . ............ 10 364 10.1.75.9 Post-Disgnosis Stress-IevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-364 10.1.75.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 65 10.1.76.1 HEP 76 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-366 10.1.76.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-367 10.1.76.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-367 10.1.76.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . ................. 10-368 10.1.76.5 Operator Action Performan e Time . . . . . . . . . . . . . . . . . . . . . ...................... 10-368 10.1.76.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-369 10.1.76.7 Diagnosis Analy 6is . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-369 ' 10.1.76.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . .... . 10-370 10.1.76.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . ........ 10-370 10.1.76.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......... . ............... 10-371 10.1.77.1 HEP 77 Calculation ................... ........... ... ... ......... .. 10 372 10.1.77.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................. 10-373 10.1.77.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . .. 10-373 , 10.1.77.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . ............... 10-374 10.1.77.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-374 10.1.77.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... ......... 10-375 10.1.77.7 Diagnosis Aralysis . . . . . . . . . . . . . . . . . . . . . . . . . . .......... ............ . 10-375 10.1.77.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP ................ 10-376 10.1.77.9 Post-Diagnosis Stress-1.evel Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-376 10.1.77.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . ......................... .. . .... .... 10-377 Vol. 2, Part 1 xxvii NUREG/CR-6143

1 l i i List of Tables (Continued) l l 10.1.78.1 HEP 78 Calculation .............. .......... .............. . . . . . . . . . . . . 10-378 ; 10.1.78.2 Sequence Timing malladications . . . . . . . . . . . . ................................. 10-379 l 10.1.78.3 Potential Operator Action . . . . . . . . . . . . . . . ............................... .. 10-379 l 10.1.78.4 Time Available to Diagnose and Perform the Task . . . . .............. ... . . . . . . . . 10-3 80 10.1.78.5 Operator Action Performance Time . . . . . . . . . . . .. ............ ............ .. 10-380 10.1.78.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 81 10.1.78.7 Diagnosis Analysis . . . . . . . . . . . . . . . . ...................................... 10-381 10.1.78.8 Post-Diagnosis Action Type Identification . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . 10-3 82 10.1.78.9 Post. Diagnosis Stress.levelIdentification per Step 10, 8-1 of ASEP HRAP . . ....... . . . . . 10-382 10.1.78.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 8 3 10.1.79.1 HEP 79 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 84 10.1.79.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 8 5 10.1.79.3 Potentia 10perator Action . . . . . . . . .........................................10-385 10.1.79.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-386 10.1.79.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . ......... . . . . . . . . . 10-386 10.1.79.6 Diagnosis Time for Operator Action . . . . . . . . . . . . .................... .. .... 10 387 10.1.79.7 Diagnosis Analysis . . . . . . . ............................................10-387 10.1.79.8 Post-Diagnosis Action Type Identification per Step 10, S-1 of ASEP HRAP . . . ..... ... .. 10-388 10.1.79.9 Post. Diagnosis Stress-Level Identification per Step 10, S-1 of ASEP HRAP . . ..... .. .. 10-388 10.1.79.10 Total HEP . . . . . . . . . . . . . . . . . . . . .... ... . ........ .......... . . 14389 10.1.80.1 HEP 80 Calculation ........ .............................. ..... . . . . . . 10-390 10.1.80.2 Sequence Timing and indications . . . . . . ........ .......................... .. 10-391 10.1.80.3 Potential Operator Action . . . . ............................... . . . . . . . . . . . . . 10-3 91 10.1.80.4 Time Available to Diagnose and Perform the Task . . . . ..................... ..... 10-392 10.1.80.5 Operator Action Perfonnance Time . . . . . . . . . . . . ........................... . 10 393 10.1.80.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 94 10.1.80.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 94 10.1.80.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP ..... . . . . . . . . . 10-395 10.1.80.9 Post. Diagnosis Stress-level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . .. . 10-395 10.1.80.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-3 96 10.1.81.1 HEP 81 Calculation .............. ... ............................. . . . . 10-397 10.1.81.10 Total HEP . . . . . . ....................... ......... . . . . . . . . . . . . . . . . . . . 10 3 98 10.1.82.1 HEP 82 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . . . . 10-3 99 10.1.82.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... . 10-400 10.1.83.1 HEP 83 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-401 10.1.83.2 Sequence Timing and Indications ........................................ ... 10-402 10.1.83.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 02 10.1.83.4 Time Available to Diagnose and Perform 'he Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-403 10.1.83.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-403 10.1.83.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . ................... ... 10-404 10.1.83.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . ............... .... ........ . 10-404 10.1.83.8 Po6t-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-405 10.1.83.9 Post-Diagnosis Stress. level Identification per Step 10. 8-1 of ASEP HRAP . . . . . ..... . . . . 10-405 10.1.83.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... . . . . . . . . . . . . . . . 10-406 10.1.85.1 HEP 85 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-407 10.1.85.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . ........... ........ ....... . . . . . . . . 10-408 10.1.86.1 HEP 86 Calculation ........................ ............... .... ....... 10-409 10.1.86.2 Sequence Timing and indications . . . . . . . . . . . . . ............. ............ ... 10 410 10.1.86.3 Potential Operator Action . . . . . . . . . . . . . . . . . . ......................... ... 10410 10.1.86.4 Time Available to Diagnose and Perform the Tssk . . . ........ ................... 10-41.1 10.1.86.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-411 10.1.86.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . ...... ............ 10-412 10.1.86.7 Diagnosis Analysis . . . . .... ............. . .. .... .. ... .... . . . . 10-412 NUREG/CR-6143 uviii Vol. 2, Part 1

l. t t, List of Tables (Continued) ; i 10.1.86.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-413 l 10.1.86.9 Post-Diagnosis Stress-hvel Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-413 l 10.1.86.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-414 f 10.1.87.1 HEP 87 Calculation . . . .................................................10-415 r 10.1.87.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-416 10.1.87.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-416 10.1.87.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-417 l 10.1.87.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-417 , 10.1.87.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-418 ! 10.1.87.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-418 10.1.87.8 Post. Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-419 l 10.1.87.9 Post-Diagnosis Stress-bvelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-419 t 10.1.87.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 20 10.1.88.1 HEP 88 Calculation . . . . .................................................10-421 ! 10.1.88.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 22 l 10.1.88.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-422 i 10.1.88.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-423 l 10.1.88.5 Operator Action Performance Time ..........................................10-423 10.1.88.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-424 . 10.1.88.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-424 10.1.88.8 Post-Diagnosis Action Type Identification per Step 10, E.1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-425 i 10.1.88.9 Post-Diagnosis Stress-hvel Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-425 10.1.88.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 26 } 10.1.89.1 HEP 89 Calculation . . . . .................................................10-427 10.1.89.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 2 8

10.1.90.1 HEP 90 Calculation . . . . .................................................10-429
10.1.90.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-430 ,

10.1.90.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-430 : 10.1.90.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-431 1 10.1.90.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-431 10.1.90.6 Diagnosis Time for Operator Action . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-432 i 10.1.90.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 32 f 10.1.90.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAF . . . . . . . . . . . . . . . . 10-433 l 10.1.90.9 Post. Diagnosis Stress-bvel Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-433 ! 10.1.90.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 34 } 10.1.94.1 HEP 94 Calculation . . . . . ................................................10-435 i 10.1.94.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 36 l 10.1.95.1 HEP 95 Calculation . . . . . ................................................10-437 10.1.95.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-438 . 10.1.95.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-438 ! 10.1.95.4 Time Available to Dugnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-439 10.1.95.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-439 . 10.1.95.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10440 l 10.1.95.7 Dia gnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-440 ! 10.1.95.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10441 ! 10.1.95.9 Post-Diagnosis Stress-hvel Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10441 ! l 10.1.95.10 Total HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . 10-44 2 10.1.%.1 HEP % Calculation . . . . . ................................................10-443 ! 10.1.%.2 Sequence Timing and Indications ............................................10-444 ( 10.1.95.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-444 j 10.1.%.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-445 ! . 10.1 % .5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-445 , 10.1.%.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-446 ! i Vol. 2, Part 1 xxix NUREG/CR-6143 '

              -_     .     .,         -r-..      .-                       - - -                                                      -                  ,

List of Tables (Continued) 10.1.96 7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......... .. 10-446 10.1.%.8 Post. Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-447 10.1.96.9 Post-Diagnosis Stress. Level Identhtion per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-447 10.1.96.10 Tota 1 HEP . . . . . . . . . . . . . . . . ...........................................10-448 10.1.99.1 HEP 99 Calculation ...................... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-44 9 10.1.99.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 50 10.1.100.1 HEP 100 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . . . . . . . . . . . 10-451 10.1.100.10 Tota 1 HEP....................................................

                                                                                                                                                                                                                           . . . . . . . 10-452 10.1.101.1         HEP 101 Calculation . . . . . . . . .         ...........................................10-453 10.1.101.10        Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 5 4 10.1.102.1         HEP 102 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-45 5 10.1.102.2         Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-456 10.1.102.3         Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-456 10.1.102.4         Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-457 10.1.102.5         Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10457 10.1.102.6         Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 5 8 10.1.102.7         D iagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-45 8 10.1.102.8         Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-459 10 1.102.9        Post-Diagnosis Stress-ImlIdentification per Step 10, 81 of ASEP HRAP                                                                       . . . . . . . . . . . . . . . 10-459 10.1.102.10        Tota 1 H EP . . . . . . . . . . . . . . . . . . . . ................                                              . . . . .        .    .  . . . . . . . . . . . . . . . 10-460 10.1.103.1         HEP 103 Calculation . . . . . . . . . . . . . . ........................                                                                                        . . . . . . . . . 10-461 10.1.103.2         Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . .                                                               .           . . . . . . . . . 10-462 10.1.103.3         Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .                                                      .             ..                   ....... 10-462 10.1.103.4        Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . .                                                                .  .            .             .  .  . . . . . . 10-463 10.1.103.5        Operator Action Performance T w . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-463 10.1.103.6         Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-464 10-4 64 10.1.103.7         Diagnosis Analysis . . . . . . . . . . . . . . . . . . .                                     . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10.1.103.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-465 10.1.103.9 Post-Diagnosis Stress-LevelIdentificationper Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-465 10.1.103.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-466 10.1.104.1 HEP 104 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-467 10.1.104.2 Sequence Timing and Indications . . . . . .......................................10-468 10.1.10G Potentia 10perator Action .................................................10-468 10.1.104.* Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-469 10.1.104.5 Operator Action Perfermance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-470 10.1.104.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 471 D iagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 10-471 l 10.1.104.7 10.1.104.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10 472 10.1.104.9 Post-Diagnosis Stress.I.evelIdentification per Step 10, 8-1 of ASEP HRAP , . . . . . . . . . . . . . . . 10 472 10.1.104.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 73 10.1.105.1 HEP 105 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 474 10.1.105.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 4 75 ' 10.1.105.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-475 10.1.105.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-476 10.1.105.5 Operator Action Performance Time . . ........................................10-477 10.1.105.6 Diagnosis Time for Operator Action . . . . ......................................10478 10.1.105.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . .................................. . 10 478 10.1.105.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-479 10.1.105.9 Post-Diagnosis Stress.levelldentification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . 10-479 10.1.105.10 Tota 1 HEP........................................................ ... 10-480 10.1.106.1 HEP 106 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 81 Sequence Timing and Indications . 10-4 82 10.1.106.2 ................. ........ . . . . . . . . . . . . . . . . Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 82 1 10.1.106.3 ........ .. .. .... xxx Vol. 2, Part 1 NUREG/CR-6143

List of Tables (Continued) 10.1.106.4 Time Av=Mahle to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-483 10.1.106.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-484 10.1.106.6 Diagnosis Time for operator Action . . . . . . . . . ...................... . . . . . . . . . . 10485 10.1.106.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 485 10.1.106.8 Post. Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-486 10.1.106.9 Post. Diagnosis Stress.l.evel Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-486 10.1.106.10 Tota 1 HEP . . . . . . . .......... ......................................10-487 10.1.107.1 HEP 107 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-48 8 10.1.107.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-489 10.1.107.3 Potentia 1 0perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10489 10.1.107.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-490 10.1.107.5 Operator Action Perfonnance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-491 10.1.107.6 Diagnosis Time for Operator Action . . . . ... ..................................10-492 10.1.107.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 92 10.1.107.8 Post. Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-493 10.1.107.9 Post-Diagnosis Stress-Level Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-493 10.1.107.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 94 10.1.108.1 HEP 108 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 95 10.1.108.2 Sequence Timing and Indications . . . . . . . . ....................................10496 10.1.108.3 Potentia 10perator Actica . . . . . . . . . . . ......................................10-4% 10.1.108.4 Time Available to Diagnose and Perform the Tar.k . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-497 10.1.108.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-4 9 8 10.1.108.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-499 10.1.108.7 Diagnosis Analysis . . . . . . . . . . . . . . ........................ ...... . . . . . . . 10-499 10.1.108.8 Post-Diagnosis Action Type Icemincation per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-500 10.1.108.9 Post-Diagnosis Stress. Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-500 10.1.108.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 01 10.1.109.1 HEP 109 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 02 10.1.109.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... . . . . . . . 10-503 10.1.109.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . ............. . . . . . . . . . . . . . 10 503 10.1.109.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-504 10.1.109.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-505 10.1.109.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10-506 10.1.109.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 506 10.1.109.8 Post-Diagnosis Action Type Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . 10-507 10.1.109.9 Post. Diagnosis Stress.bvel Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-507 ' 10.1.109.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-508 10.1.110.1 HEP 110 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 09 10.1.110.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-510 10.1.111.1 HEP 1 11 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . 10 511 10.1.111.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-512 10.1.111.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 512 10.1.111.4 Time Available to Diagnose arx1 Perform tin Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-513 10.1.111.5 Operator Action Performance Time . . . . . . . . . ......... ................ . . . . . . 10-513 10.1.111.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-514 10.1.111.7 Diagnosis Analysis . . . ..................................................10-514 10.1.1ILS Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-515 ' 10 1.11. 9 Post-Diagnosis Stress-hvel Identification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10-515 10.1.11?.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... . . . . . . . . . . . . . . 10-516 10.1.113.1 HEP 113 Calculation . . . . . . . . . . . . . . . . . . . . . . . . .............. . . . . . . . . . . . 10-517 10.1.11*.2

Sequence Timing and Indications . . . . ..... .................. . .. .... . . . . 10-518 10.1.113.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . 10 518 10.1.113.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . .. . . . ........ .. 10-519 Vol. 2 Part 1 mi NUREG/CR-6143

List of Tables (Continued)

                                                                                                                      ................. .....                                                        10-519 10.1.113.5    Operator Action Performance Time              ..................

Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 20 10.1.113.6 ... 10-520 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . .. ... ......... ....... 10.1.113.7 10.1.113.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-521 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . .

                                                                                                                                                                                  . . . . 10-521 10.1.113.9 Tota 1 HEP . . . . . . . . . . . . -. . . . . . . . . . . . . . . . . . . . . . .      . . .  .  .   .  .  .  . .   .  .  .  .   .   .  .  .   .  . . . . 10-5 22 10.1.113.10                                                                                                                                                                   . 10-523 10.1.114.1    HEP 114 Calculation . . . . . . . . . . . . . . . . . . . . . . .                                                                                      .   .. 10-524 10.1.114.2    Sequence Timing and indications . . . . . . . . . . ................ .............

Potentia 10perator Action . . . . . . . . . ..........................

                                                                                                                                                    .     . . . . . . . . . . . 10-524 10.1.114.3 10.1.114.4    Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-525
                                                                                                                                                                        . . . . . . . 10-525 10.1.114.5    Operator Action Pedormance Time . . . . . . . . . .........................

10.1.114.6 Diagnosis Time for Operator Action . . . . . .. ....... . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 2 6 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . ................ . . . . . . . . . . . . . . . . 10-526 10.1.114.7 10.1.114.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-527 ~ Post-Diagnosis Stress-Leve11dentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . .

                                                                                                                                                                               . . . . . 10-527 10.1.114.9                                                                                                                                                                     . 10-528 10.1.114.10  Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . .. ......... ....... ........... ..

10.1.115.1 HEP 115 Calculation . . . . . . . ... ... ..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 5 29 Sequence Timing and indications . . . . . . . . ... .. .... ..... ..... ..... ... 10-530 10.1.115.2 Potentia 10perator Action . . . . . . . . . . . . . ...... ....... . .... . . . . . . . . . . . . . 10-5 30 10.1.115.3 ... 10 531 10.1.115.4 Time Available to Dinnose and Perform the Task . . . . . . Operator Action Performance Time . . . . . ..... ..... . ....

                                                                                                                                         . . . . . . . . . . . . . . . . . 10-5 32 10.1.115.5 Diagnosis Time for Operator Action . . ... . ........ ..                                   .  .   .  .  . . . . . . . . . . . . . . . . . 10-532 10.1.115.6                                                                                                                                                                     . 10-533 10.1.115.7    Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
                                                                                                                                                                                                  . 10-534 10.1.115.8    Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . .

10.1.115.9 Post-Diagnosis Stress-Leve11dentification per Step 10, 8-1 of ASEP HRAP . . , . . . . . . . . . . . . 10-534 10.1.115.10 Tota 1 HEP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 35 HEP 116 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... ..

                                                                                                                                                      . . . . . . . . . . . . . 10-5 36 10.1.116.1 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . ............. .
                                                                                                                                                                                 . . . . . 10-537 10.1.116.2                                                                                                                                                                  . 10-537 10.1.116.3    Potentia 10perator Action .....              .......................................                                                                    .

Time Available to Diagnose and Perform the Task ................. . . . . . . . . . . . . . . 10-5 3 8 10.1.116.4 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .....

                                                                                                                                                                                      . . . . 10-538 10.1.116.5 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . .......                             . . . . . . . . . . . . . . . . . 10-5 39 10.1.116.6 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .             .   .  .  .  . . . . . . . . . . . . . . . . 10-5 3 9 10.1.116.7
                                                                                                                                                                                                   . 10-540 10.1.116.8   Post. Diagnosis Action Type Identificationper Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . .

10.1.116.9 Post-Diagnosis Stress-levelldentification per Step 10, 81 of ASEP HRAP . . . . . . . . . . . . . . . . 10 540

                                                                                                                                                                           ......                  . 10-541 10.1.116.10  Tota 1 HEP....................................................
                                                                                                                                                                                       .  .  .  . 10-542 10.1.117.1   HEP 117 Calculation . . . . . . . . ....... .......... ....................

Sequence Timing and indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... . . 10-543 10.1.117.2 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . ............ . . . . . . . . . . . 10-5 4 3 10.1.117.3 Time Available 'o Diagnose and Perform the Task . . . . . . . . . . . . . . . .......... . . . . . . 10-544 10.1.117.4 10-544 10.1.117.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-545 1 10.1.117.6 10.1.117.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-545 10.1.117.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . .. . 10-546 10.1.117.9 Post-Diagnosis Stress-leve11dentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-546

                                                                                                                                                                                                    . 10-547 10.1.117.10   Total HEP . . . . . . . . . . . . . . . . . . . . . ....................... ............

10.1.118.1 HEP 118 Calculation . . .................................................10-548 . . . . . . 10-54 9 10.1.118.2 Sequence Timing and indications . . . . . . . . . . . ..... . .... ............. 10.1.118.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 4 9 10.1.118.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-550 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

                                                                                                                                                                         . . . . . . . . 10-550 10.1.118.5 Diagnosis Time for Operator Action . . . . . .                ...........               ............                                .....                ... 10-551 10.1.118.6 Diagnosis Analysis . . . . . ..... ..............                                 .... .. .... ...... ..                                                 ... 10-551 10.1.118.7 mii                                                                                              Vol. 2, Part 1 NUREG/CR-6143

List of Tables (Continued) 10.1.118.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-552 10.1.118.9 Post-Diagnosis Stress-IevelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-552 10.1.118.10 TotalHEP............................................................ 10-553 10.1.119.1 HEP 1 19 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-554 10.1.119.2 Sequence Timing aa! Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 555 10.1.119.3 Potentia 10perator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 5 5 10.1.119.4 Time Available to Diagnose and Perform the Task . . . . . . . .......... . . . . . . . . . . . . . . 10-55 6 10.1.119.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . .............. . . . . . . 10-556 10.1.119.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-557 10.1.119.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-55 7 10.1.119.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-558 10.1.119.9 Post-Diagnosis Stress-Level Identificationper Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-558 10.1.119.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 5 9 10.1.120.1 HEP 120 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-560 10.1.120.2 Sequence Timing and Indications . ..........................................10-561 10.1.120.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . ............................ . 10-561 10.1.120.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 62 10.1.120.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-562 10.1.120.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 63 10.1.120.7 Diagnosis Analysis . . . . . . . . . . . . . . . . ....... .... . . . . . . . . . . . . . . . . . . . . . . . . 10-5 63 10.1.120.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-564 10.1.120.9 Post-Diagnosis Stress. level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10 564 10.1.120.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . 10-565 10.1.121.1 HEP 121 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10 566 10.1.121.2 Sequence Timig ard Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 10-567 10.1.121.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 67 10.1.121.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-568 10.1.121.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-568 10.1.121.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 10-569 10.1.121.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 69 10.1.121.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-570 10.1.121.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-570 10.1.121.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 71 10.1.122.1 HEP 122 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-572 10.1.122.2 Sequence Timing and Indications . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............ ... 10-573 10.1.122.3 Potential Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . 10-573 10.1.122.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-574 10.1.122.5 Operator Action Performance Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-574 10.1.122.6 Diagnosis Time for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-575 10.1.122.7 Diagnosis Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-5 75 10.1.122.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . ... 10-576 10.1.122.9 Post-Diagnosis Stress-levelIdentification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . 10-576 10.1.122.10 TotalHEP...................................................... ... . 10-577 10.1.123.1 HEP 123 Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... .. .. 10-578 10.1.123.2 Sequence Timing and Indications . . . . . . . . ............................... ... 10-579 10.1.123.3 Potentia 1 0pvor Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-579 10.1.123.4 Time Available to Diagnose and Perform the Task . . . . . . . . . . . . . . . . . . .. . ... .. 10 580 10.1.123.5 Operator Ac' ion Performance Time . . . . . . . . . . . . . . . ............. . . . . . . . . . . . . . 10-5 80 10.1.123.6 Diagnosis

lime for Operator Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... 10-581 10.1.123.7 Diagnosis Analysis . . . . . . . . . . . . . . ...................... . . . . . . . . . . . . . . 10-5 81 10.1.123.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . 10-582 10.1.123.9 Post-Diagnosis Stress-Level Identificationper Step 10, 8-1 of ASEP HRAP . . . . . . . . . . . . . . . . . 10-582 10.1.123.10 Tota 1 H EP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . .. 10-583 Vol. 2, Part 1 miii NUREG/CR-6143

List of Tables (Continued) 10.1.124.1 HEP 124 Calculation . ....... .. .... ... .. ....... .. .. 10-584 Sequence Timing and Indications . . . .. .. .. ..... .. 10-585 10.1.124.2 .. ......... .. . 10.1.124.3 Potential Operator Action . . . . . . .... . . . .. . .. ...... . . 10-585 ; 10.1.124.4 Time Available to Diagnose and Perform the Task . .. ....... ... .... ... ... . 10-586 Operator Action Performance Time . . .... . . ........... . ...... 10-586 10.1 24.5 . .... 10.1.124.6 Diagnosis Time for Operator Action . ...... . .. . .. . ..... . .. ... . 10-587 Diagnosis Analysis . ... .... .... .. . .... .. 10-587 10.1.124.7 .......... ... ... Post-Diagnosis Action Type Identification per Step 10, 8-1 cf ASEP HRAP . . . . . 10-588 10.1.124.8 . . Post-Diagnosis Stress. Level Identification per Step 10, 8-1 of ASEP HRAP . . . . .. ... . . 10-588 10.1.124.9 10.1.124.10 Total HEP . . . . ...... .... ... ....... ... ....... . ....... .. . 10-589 HEP 125 Calculation . . ... ... ... ... . ...... . . ...... . .... . 10-590 10.1.125.1 .. 10.1.125.2 Sequence Timing amlIndications . ... .. .. ........ .......... .. ... . . 10-591 10.1.125.3 Potential Operator Action . . . . . . ... . ... .. ....... . ... . . . 10-591 Time Avdlable to Diagnose mal Perform the Task ... ... .. ........ ... 10-592 10.1.125.4 ... . 10.1.125.5 Operator Action Performance Time . .. ..... .. ........ .... ..... . 10-592 10.1.125.6 Diagnosis Time for Operator Actio i . . .. .. .. . .... ... . ....... . 10-593 10.1.125.7 Diagnosis Analysis . .. .. .. .. .. . . ... .. . ... ... . 10-593 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . . .... . . 10-594 10.1.125.8 Post-Diagnosis Stress-LevelIdentificationper Step 10, 8-1 of ASEP HRAP . ..... .. .. 10-594 10.1.125.9 10.1.125.10 Total HEP . .......... .. ... .. . .. ... . ... . ..... . . 10-595 HEP 126 Calculation . . . . . . .. 10-596 10.1.126.1 . ... . .. ... ... ... ... . 10.2.1 Pre-Accident Human Actions and Their Mean IEPs .10-598

                                                                                                                                                                 . 10-600 10.3.1      T5D5H HEP SEQUENCE CROSS REFERENCE .

10.3.2 .10-605 TSASHIEP/ SEQUENCE CROSS REFERENCE .

                                                                                                                                                                 . 10-607 10.3.3      TDB5HIEP SEQUENCE CROSS REFERENCE .

10.3.4 10-610 TIASH HEP SEQUENCE CROSS REFERENCE

                                                                                                                                                                 . 10-615 10.3.5      TAB 5HIEP SEQUENCE CROSS REFERENCE .

10.3.6 .10-617 J2 5 IEP SEQUENCE CROSS REFERENCE . 10.3.7 ElB5HIEP SEQUENCE CROSS REFERENCE .10-618 10.3.8 E2B5H HEP SEQUENCE CROSS REFERENCE .10 521 10.3.9 .10-623 eld 5HIEP SEQUENCE CROSS REFERENCE . 10.3.10 E2DSHIEP SEQUENCE CROSS REFERENCE , .10-626 10.3.11 A51EP SEQUENCE CROSS REFERENCE .

                                                                                                                                                                  .10 628 10.3.12                                                                                                                                                           .10-629 S2HIEP SEQUENCE CROSS REFERENCE .

10.3.13 10-630 S3H-5 IEP/ SEQUENCE CROSS REFERENCE . 10.3.14 10-630 ASHYIEP SEQUENCE CROSS REFERENCE . 10.3.15 StH-5 HEP SEQUENCE CROSS REFERENCE .

                                                                                                                                                                  .10-630 10.3.16                                                                                                                                                           .10-631 S2 5 IEP SEQUENCE CROSS REFERENCE 10.3.17                                                                                                                                                           . 10-632 S3-5 HEP SEQUENCE CROSS REFERENCE .                                                                                         .

10.3.18 J2 5 IEP SEQUENCE CROSS REFERENCE .

                                                                                                                                                                  .10-633 10.3.19    TIOPSIEP SEQUENCE CROSS REFERENCE .
                                                                                                                                                                  .10-634 10.3.20    E2C.5 HEP SEQUENCE CROSS REFERENCE .                                                                                                                  .10-636 10.3.21    E2TSHIEP SEQUENCE CROSS REFERENCE                                                                                                                     .10-637 10.3.22    E2V5H HEP SEQUENCE CROSS REFERENCE .                                                                                                                  .10-639 10.3.23    TLMSHIEP SEQUENCE CROSS REFERENCE                                                                                                                     .10-640 10.3.24    ElTSH HEP / SEQUENCE CROSS REFERENCE                                                                                                                   .10-644 10.3.25     ElV5HIEP SEQUENCE CROSS REFERENCE .                                                                                                                   .10-649 10.3.26                                                                                                                                                             10-652 TIHP5 IEP SEQUENCE CROSS REFERENCE .

TIOF5 IEP SEQUENCE CROSS REFERENCE . .10-655

$ 0.3.27
 ;0.3.28     TORV5IEP SEQUENCE CROSSREFERENCE                                                                                                                      .10-658 103.29      TI-5 HEP SEQUENCE CROSS REFERENCE                                                                                                                       10-660 113.30                                                                                                                                                              10-666 lil-5HIEP SEQUENCE CROSS REFERENCE 10.3.31                                                                                                                                                             10-669 TRPT5 HEP SEQUENCE CROSS REFERENCE NUREG!CR-6143                                                     m iv                                                                                  Vol. 2. Part 1

List of Tables (Continued) 10.3.32 E2V5H HEP SEQUENCE CROSS REFERENCE . .10-675 10.3.33 H.MSH HEP SEQUENCE CROSS REFERENCE . . . . . .10-679 10.4.1 Recovery Actions and Their Mean HEPs and Error Factors . 10-683 10.5.2RI. ] HEP 2R1 Calculation . .10-684 10.5.2Rl.2 Sequence Timing and Indications . .10-685 10.5.2R1.3 Potential Operator Action . . . .10-685 10.5.2RI.4 Time Available to Diagnose and Perform the Task . .10-686 10.5.2RI.5 Operator Action Performance Time . .10-686 10.5.2RI.6 Diagnosis Time for Operator Action . . .10-687 10.5.2RI.7 Diagnosis Analysis . . .10-687 10.5.2RI.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-688 10.5.2RI.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . 10-688 10.5.2RI.10 Total HEP . . . . . . .10-689 10.5.3RI. I HEP 3RI Calculation . .. .10-690 10.5.3RI.2 Sequence Timing and Indications .10-691 10.5.3R1.3 Potential Operator Action . .10-691 10.5.3RI.4 Time Available to Diagnose and Perform the Task . .10-692 10.5.3Rl.5 Operator Action Performance Time . .10-692 10.5.3R1.6 Diagnosis Time for Operator Action . . . . .10-693 10.5.3RI.7 Diagnosis Analysis . . .10-693 10.5.3RI.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-694 10.5.3RI.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP ,. .10-694 10.5.3RI.10 Total HEP . . . . . 10-695 10.5.6RI.1 HEP 6RI Calculation . . . .10-696 10.5.6RI.2 Sequence Timing and Indications . .10-697 10.5.6R1.3 Potential Operator Action . . .10-697 10.5.6RI .4 Time Available to Diagnose and Perfonn the Task .10-698 10.5.6RI .5 Operator Action Performance Time . . .10-698 10.5.6RI.6 Diaposis Time for Operator Action . .10-699 10.5.6RI .7 Diagnosis Analysis . . . . .10-699 10.5.6RI .8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-700 10.5.6RI.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP .10-700 10.5.6RI.10 Total HEP . . .10-701 10.5.10RI.1 HEP 10R1 Calculation . . .10-702 10.5.10RI.2 Sequence Timing and Indications . . . . . .10-703 ! 10.5.10RI.3 Potential Operator Action .10-703 l 10.5.10RI.4 Time Available to Diagnose and Perform the Task . .10-704 1 10.5.10RI.5 Operator Action Performance Time . . .10-704 ! 10.5.10RI.6 Diagnosis Time for Operator Action . .10-705 l 10.5.10R1.7 Diagnosis Analysis . .10-705 l 10.5.10RI.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 ofASEP HRAP .10-706 l 10.5.1ORI.9 Post-Diagnosis Stress-levelIdentification per Step 10, 8-1 of ASEP HRAP . 10-706 10.5.10RI.10 Total HEP . . .10-707 10.5.10R2.1 HEP 10R2 Calculation . . . . . .10-708 10.5.10R2.2 Sequence Timing and Indications . . . . .10-709 10.5.10R2.3 Potential Operator Action . . .10-709 10.5.10R2.4 Time Available to Diagnose and Perform the Task .10-710 10.5.10R2.5 Operator Action Perforr,,ance Time . . . .10-710 10.5.10R2.6 Diagnosis Time for Operator Action . ,

                                                                                                                                             . 10-711 10.5.10R2.7        Diagnosis Analysis .               .           .      .                                                                    .10-711    i 10.5.10R2.8        Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                                    .10-712 10.5.10R2.9       Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                                    .10-712    l 10.5.10R2.10       Total HEP .                                                                                                                .10-713    l Vol. 2, Part 1                                                   xx.xv                                                              NUREG/CR-6143

List of Tables (Continued) 10.5.13Rl.1 HEP 13R1 Calculation . .

                                                                                                                                                           . 10-714 10.5.13RI.2     Sequence Timing and Indications         .                             .                                                                  . 10-715 10.5.13RI.3     Potential Operator Action                                .                    .                                               .             .10-715 10.5.13Rl.4     Time Available to Dispose and Perform the Task                                                                   .                          .10-716 10.5.13RI.5     Operator Action Performance Time                                                                  .              .                       . 10-716 10.5.13RI.6     Diagnosis Time for Operator Action .                                                                                                        .10-717 10.5.13RI.7     Diagnos,s Analysis .                                                                                                .                .      .10-717 10.5.13RI.8     Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                                               .. 10-718 10.5.13RI.9     Post Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP                                  .                                   .10-718 10.5.13RI.10    Total HEP .                                         .
                                                                                                                                                            .10-719 10.5.13R2.1     HEP 13R2 Calculation .                                                                                                                       .10-720 10.5.13R2.2     Sequence Timing and Indications                                                              .                                               .10 721 10.5.13R2.3     Potenti2 Operator Action                                                               .                                              - .10-721 10.5.13R2.4     Time Available to Diagnose and Perform the Task                             , .                                                              .10-722 10.5.13R2.5     Operator Action Performance Time                                                                                                             .10 722 10.5.13R2.6     Diagnosis Time for Operator Action .                                                                                           .             .10 723 10.5.13R2.7     Diagnosis Analysis .                .                                                                                .                       .10 723 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP IRAP                                                                    ,.10 724 10.5.13R2.8 10.5.13R2.9     Post-Diagnosis Stress-levelIdentification per Step 10, 8-1 of ASEP HRAP                                                                      .10 724 10.5.13R2.10    Total HEP .                                             ..                         .
                                                                                                                                                             .10 725 10.5.14RI.1     HEP 14R1 Calculation .                            .                                                                                          .10-726 10.5.14RI.2     Sequence Timing and Indications                                                           .                                                   .10 727 10.5.14RI.3     Potential Operator Action .                                                            .                                                      .10-727 10.5.14R1.4     Time Available to Diagnose and Perform the Task                                                                                              .10-728 10.5.14R1.5     Operator Action Performance Time                                       .       .
                                                                                                                                                            .10-728 10.5.14RI.6    Diagnosis Time for Operator Action .                                .                               ..            .                       . 10-729 10.5.14RI.7    Diagnosis Analysis .                  .                          .
                                                                                                                                                             .10-729 10.5.14RI.8     Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                                                      .10-730 10.5.14RI.9     Post-Diagnosis Stress-levelIdentification per Step 10, 8-1 of ASEP HRAP                                                                      .10 730 10.5.14RI.10    Total HEP . .          .    .                             .                    .                                                      .      .10-731 10.5.16RI.1     HEP 16R1 Calculation .                                                                                                                       .10 732 10.5.16RI.2     Sequence Timing and Indications               .             .                                                              .                 .10-733 10.5.16R1.3     Potential Operator Action     .          .                                             .                      .                              .10-733 10.5.16RI.4     Time Available to Diagnose and Perform the Task                                 .                  .                                         .10-734 10.5.16RI.5     Operator Action Performance Tunc                     .                   .                                            .                      .10-734 10.5.16RI.6     Diagnosis Time for Operator Action .                                                                                                         . 10-735 10.5.16RI.7     Diagnosis Analysis .      .                                      .                                 .                                          .10-735 10.5.16RI.8     Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                     .           .                    .10-736 10.5.16RI.9     Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                  .                                   .10-736 10.5.16RI.10    Tota 1 HEP . . . .                         .
                                                                                                                                                              .10-737 10.5.16R2.1     HEP 16R2 Calculation .                                        .                                                                               .10-738 10.5.16R2.2     Sequence Timing and Indications                                                               .                                    .          . 10-739 10.5.16R2.3     Potential Operator Action                      .                                                          ,                                   .10-739 10.5.16R2.4     Time Available to Diagnose and Perform the Task                                            . .                           .                    .10-740 10.5.16R2.5    Operator Action Performance Time                                                                                                              .10-740 10.5.16R2.6    Diagnosis Time for Opera 1 Action .                                                 .           .                                .         . 10-741 10.5.16R2.7    Diagnosis Analysis . . .                    .                                                         .                                       .10-741 10.5.16R2.8    Post-Diagnosis Action T3pe Identification per Step 10, 8-1 of ASEP HRAP                                                                       .10-742 10.5.16R2.9    Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                                                      .10-742 10.5.16R2.10   Total HEP .                                                                                                                                   .10-743 10.5.16R3.1    HEP 16R3 Calculation . .         . .                                                                  .                      . .               .10-744 10.5.16R3.2     Sequence Timing and Indications                                                                                                              .10-745 10.5.16R3.3    Potential Operator Action                                                                                                                      .10-745 NUREG/CR-6143                                           xxxvi                                                                                     Vol. 2, Part 1

List of Tables (Continued) 10.5.16R3.4 Time Available to Diagnose and Perfonn the Task . .10-746 10.5.16R3.5 Operator Action Performance Time . . .10-746 10.5.16R3.6 Diagnosis Time for Operator Action . .10-747 10.5.16R3.7 Diagnosis Analysis . . .10-747 10.5.16R3.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-748 10.5.16R3.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP .10-748 10.5.16R3.10 TotallEP . . .10-749 10.5.18R1.1 IEP 18R1 Calculation . .10-750 10.5.18RI.2 Sequence Timing and Indications .10-751 10.5.18R1.3 Potential Operator Action . .10-751 10.5.18RI.4 Time Available to Diagnose and Perform the Task .10-752 10.5.18R1.5 Operator Action Performance Time . . . .10-752 10.5.18RI.6 Diagnosis Time for Operator Action . . . .10-753 10.5.18RI.7 Diagnosis Analysis . . .10-753 10.5.18R1.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . .10-754 10.5.1 SRI .9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP ,10-754 10.5.18R I.10 Total HEP . . .10-755 10.5.18R1.1 IEP 18R1 Calculation . . .10 756 10.5.18RI.2 Sequence Timing and Indications .10-757 10.5.1 SRI .3 Potential Operator Action .10-757 10.5.18RI.4 Time Available to Diagnose and Perform the Task . .. .10-758 10.5.18RI.5 Operator Action Performance Time .10-758 10.5.18RI.6 Diagnosis Time for Operator Action . .10-759 10.5.18RI.7 Diagnosis Analysis . . . . . .10-759 10.5.18R1.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-760 10.5.1 SR1.9 Post-Diagnosis St; ss-Level Identification per Step 10, 8-1 of ASEP HRAP . .10-760 10.5.18RI.10 TotalIEP . . . . . .10-761 10.5.18R3.1 HEP 18R3 Calculation . . .10-762 10.5.1 SR3.2 Sequence Timing and Indications . . .10-763 10.5.18R3.3 Potential Operator Action . .10-763 10.5.18R3.4 Time Available to Diagnose and Perform the Task . .10-764 10.5.18R3.5 Operator Action Performance Time . . .10-764 10.5.18R3.6 Diagnosis Time for Operator Action . . . .. .10-765 10.5.18R3.7 Diagnosis Analysis . .. . . . . . . . . 10-765 10.5.18R3.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-766 10.5.18R3.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . .10-766 10.5.18R3.10 Total HEP . . .. . . 10-767 10.5.28RI.1 HEP 28R1 Calculation . . . . . . .10 768 10.5.28RI.2 Sequence Timing and Indications .10-769 10.5.28R1.3 Potential Operator Action . . . . . . .10-769 10.5.28RI .4 Time Available to Diagnose and Perform the Task . . . .10-770 10.5.28RI.5 Operator Action Performance Time . .10-770 10.5.28RI.6 Diagnosis Time for Operator Action . .10-771 10.5.28RI.7 Diagnosis Analysis . . . . . .10-771 10.5.28RI.8 Post-Diagnosis Action T3 pe Identification per Step 10, 8-1 of ASEP HRAP .10-772 10.5.28RI.9 Post-Diegnosis Stress-Level Identificatien per Step 10, 8-1 of ASEP HRAP . 10-772 10.5 28RI.10 TotallEP . . . .10-773 10.5.28R2.1 IEP 28R2 Calculation . . . .10-774 10.5.28R2.2 Sequence Timing and Indications .10-775 i 10.5.28R2.3 Potential Operator Action . .10-775 ! 10.5.28R2.4 Time Available to Diagnose and Perform the Task .10-776 j 10.5.28R2.5 Operator Action Performance Time .10-776 10.5.28R2.6 Diagnosis Time for Operator Action . .10-777 Vol. 2, Part I nxvii NUREG/CR-6143

List of Tables (Continued) Diagnosis Analysis . .10-777 10.5.28R2.7 . . . 10.5.28R2.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-778 10.5.28R2.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP .10-778 Total HEP . .10-779 10.5.28R2.10 . . 10.5.29R1.1 IEP 29RI Calculation . . . .10-780 Sequence Timing and Indications .10-781 10.5.29RI.2 Potential Operata Action .10-781 10.5.29RI.3 . . 10.5.29R1.4 Time Available to Diapose and Perform the Task . .10-782 10.5.29RI.5 Operator Action Performance Time .

                                                                                                                           .10-782 10.5.29RI .6   Diagnosis Time for Operator Action .             .                                       .                   .10-783 10.5.29RI.7    Diagnosis Analysis .    .                              . .         .
                                                                                                             .             .10-783 Post-Diagnosis Action-Type Identification per Step 10, 8-1 of ASEP HRAP                                      .10-784 10.5.29RI .8 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP                                       ,10-784 10.5.29RI.9 10 5.29RI.10    Total HEP . .          -                                             .
                                                                                                                            .10-785 10.5.29R2.1    IEP 29R2 Calculation .            .                                              .                            .10-786 10.5.29R2.2     Sequence Timing and Indications    .
                                                                                                                            .10-787 10.5.29R2.3     Potential Operator Action                                                                                    .10-787 10.5.29R2.4     Time Available to Diagnose and Perform the Task                                                              .10-788 10.5.29R2.5     Operator Action Performance Time                                   .     .
                                                                                                                            .10-788 10.5.29R2.6     Diagnosis Time for Operator Action .                        .                             .                  .10-789 10.5.29R2.7     Diagnosis Analysis .                        .
                                                                                                                            .10-789 10.5.29R2.8     Post-Diagnosis Action-Type Identification per Step 10, 8-1 of ASEP HRAP                                      .10-790 10.5.29R2.9     Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                     .10-790 10.5.29R2.10   Total HEP .                                                                                                  .10-791 10.5.35R1.1    HEP 35RI Calculation .                                                                                 .      .10-792 10.5.35RI.2    Sequence Timing and Indications                                                                               .10-793 10.5.35R1.3     PotentialOperator Action .                                                .
                                                                                                                            .10-793 10.5.35RI.4    Time Available to Diagnose and Perform the Task                                                               .10-794 10.5.35RI .5   Operator Action Performance Time                                                                         . 10-794 10.5.35RI .6   Diagnosis Time for Operator Action .          .
                                                                                                                             . 10-795 10.5.35RI .7   Diagnosis Analysis .     .                                     .
                                                                                                                             .10-795 10.5.35RI .8   Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                       .10-796 10.5.35Ri.9    Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP               .                       .10-796

10.5.35RI.10 TotalIEP . . .

                                                                                                                        .    .10-797 10.5.37RI.1    HEP 37R1 Calculation .       .        .                    ...                    .         .                 .10-798 10.5.37RI.2     Sequence Timing and Indications                    .
                                                                                                                   .         .10-799 10.5.37RI .3   Potential Operator Action                              . ..                                              .    . 10-799 10.5.37RI.4     Time Available to Diagnose and Perform the Task                                                              .10-800 10.5.37Rl.5     Operator Action Performance Time                                                 . .                          .10-801 10.5.37RI.6     Diagnosis Time for Operator Action .                                         .                                .10-802 10.5.37RI.7     Diagnosis Analysis . ...                                                   ..                                 .10-802 10.5.37RI.8     Post Diagnosis Action Type Identification per :',tep 10, 8-1 of ASEP HRAP                                     .10-803 10.5.37RI.9     Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                      .10-803 10.5.37RI.10    TotalIEP .                               .
                                                                                                                              .10-804 10.5.37R2.1     HEP 37R2 Calculation .                 .
                                                                                                                              .10-805 10.5.37R2.2     Sequence Timing and Indications                                       .                        .              .10 806 10.5.37R2.3    Potential Operater Action                                                                                .    .10-806 10.5.37R2.4    Time Available to Diagnose and Perform the Task                                                     .         .10-807 10.5.37R2.5    Operator Action Performince Time                                                                               .10 808 10.5.37R2.6    Diagnosis Time for Operator Action .                                                                          .10-809 10.5.37R2.7    Diagnosis Analysis .              .
                                                                                                                               .10-809 10.5.37R2.8    Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                        .10-810 10.5.37R2.9    Post-Diagnosis Stress-Level Identification per Step i0, 8-1 of ASEP HRAP                                       .10-810 NUREG/CR4143                                            xxxviii                                                      Vol. 2, Part 1

List of Tables (Continued) 10.5.37R2.10 Total HEP . .. . . 10-811 10.5.37R3.1 HEP 37R3 Calculation . .. . .10-812 10.5.37R3.2 Sequence Timing and Indications . . . .10-813 10.5.37R3.3 Potential Operator Action . .10-813 10.5.37R3.4 Tirne Available to Diagnose and Perform the Task .10-814 10.5.37R3.5 Operator Action Perfonnance Time .10-815 10.5.37R3.6 Diagnosis Time for Operator Action . . . . 10-816 10.5.37R3.7 Diagnosis Analysis . . . . . 10-816 10.5.37R3.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP ,10-817 10.5.37R3.9 Post Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . 10-817 10.5.37R3.10 Total HEP . .. .10-818 10.5.42RI .1 HEP 42RI Calculation . . . . . .10-819 10.5.42RI.2 Sequence Timing and Indications .10-820 10.5.42R1.3 Potential Operator Action . .10-820 10.5.42RI.4 Time Available to Diagnose and Perform the Task .10-821 10.5.42R1.5 Operator Action Perfonnance Time .10-821 10.5.42RI.6 Diagnosis Time for Operator Action . . 10-822 10.5.42RI .7 Diagnosis Analysis . . . .. .10-822 10.5.42R1.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP ,10-823 10.5.42RI .9 Post-Diagnosis Stress LevelIdentification per Step 10, 8-1 of ASEP HRAP . .10-823 10.5.42RI.10 Tota! HEP . . . . . 10-824 10.5.42R2.1 HEP 42R2 Calculation . . .10-825 10.5.42R2.2 Sequence Timing and Indications . .10-826 10.5.42R2.3 Potential Operator Action .10-826 10.5.42R2.4 Time Available to Diagnose and Perform the Task . . .10-827 10.5.42R2.5 Operator Action Performance Time .10-827 10.5.42R2.6 Diagnosis Time for Operator Action . . .10-828 10.5.42R2.7 Diagnosis Analysis . . . . .. .10-828 10.5.42R2.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-829 10.5.42R2.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP ,10-829 10.5.42R2.10 Tota 1 HEP . . . . . . . 10-830 10.5.49Rl.1 HEP 49R1 Calculation . . . . . 10-831 10.5.49RI.2 scouence Timing and Indications . .10-832 10.5.49R1.3 Potential Operator Action . . . . .10-832 10.5.49R1.4 Time Available to Diagnose an.1 Perfonn the Task . . .10-833 10.5.49RI .5 Operator Action Performance Time .10-833 10.5.49RI .7 Diagnosis Analysis . . . .10-834 10.5.49RI.8 Post-Diagnosis Action-Type Identification per Step 10, 8-1 of ASEP HRAP . .10-835 10.5.49R1.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP . .10-835 10.5.49R1.10 Total HEP . . . .. . . .10-836 10.5.50RI.1 HEP 50R1 Calculation . . . 10-837 10.5.50R1.2 Sequence Timing and Indications . . . 10-838 10.5.50R1.3 Potential Operator Action . . . ., .10-838 10.5.50RI.4 Time Available to Diagnose and Perform the Task . .10-839 10.5.50RI.5 Operator Action Performance Time . . . .10-839 10.5.50RI.6 Diagnosis Time for Operatoi Action . . . .10-840 10.5.50RI.7 Diagnosis Analysis . . .. ... .10-840 10.5.50RI .8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . .10-841 10.5.50RI.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP IDMP .10-841 ' 10.5.50RI.10 Total HEP . - . .10-842 10.5.50R2.1 HEP 50R2 Cs!culation . . 10-843 10.5.50R2.2 Sequence Timing and Indications . .10-844 10.5.50R2.3 Potential Operator Action . .10 844 Vol. 2, Past 1 xxxix NUREG/CR-6143

List of Tables (Continued) 10.5.50R2.4 Time Available to Diagnose and Perform the Task .10-845 10.5.50R2.5 Operator Action Performance Time . .10-845 10.5.50R2.6 Diagnosis Time for Operator Action . . .10-846 10.5.50R2.7 Diagnosis Analysis . .10-846 10.5.50R2.8 Post-Diagnosis Action Type Identification pr:r Step 10, 8-1 of ASEP HRAP . .10-847 10.5.50R2.9 Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP .10-847 10.5.50R2.10 TotalHEP . . . . 10-848 10.5.50R3.1 HEP 50R3 Calculation . . .

                                                                                                     .                   .                       .10-849 10.5.50R3.2    Sequence Timing and Indications                                     .                                         .                  .10-850 10.5.50R3.3    Potential Operator Action               .                   .                                                                    .10-850 10.5.50R3.4    Time Available to Diagnose and Perform the Task                                                                                  .10-851 10.5.50R3.5    Operator Action Performance Time                                                                                                 .10-851 10.5.50R3.6    Diagnosis Time for Operator Action .                .
                                                                                                                       .                         .10-852 10 5.50R3.7    Diagnosis Analysis . .           .                              .
                                                                                                                                                 .10-852 10.5.50R3.8    Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                                   .       . 10-853 10.5.50R3.9    Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                                  .       .10-853 10.5.50R3.10   Total HEP .       .
                                                                                                                                                  .10-854 10.5.61RI.1    HEP 61R1 Calculation .                   .
                                                                                                                                          .       .10-855 10.5.61RI.2    Sequence Timing andIndications                                                           ..                                       .10-856 10.5.61 R1.3   Potential Operator Action                                                                                           .             . 10-856 10.5.61RI.4    Time Available to Diagnose and Perform the Task                  .
                                                                                                                                                  . 10-857 10.5.61RI .5   Operator Action Performance Time                                                                                                  . 10 857 10.5.61RI.6    Diagnosis Time for Operator Action .                                 .                      .              .                      .10-858 10.5.61RI.7    Diagnosis Analysis .                              .                                         .                                     .10-858 10.5.61RI.8   Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                                         . 10-859 10.5.61RI.9   Post Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP                                         ,            .    .10-859 10.5.61RI.10   Total HEP .         .
                                                                                                                 .                    .            .10-860 10.5.64RI .1  HEP 64R1 Calculation .                 . .                             .. .                          .                            .10-861 i  10.5.64RI.2    Sequence Timing and Indications                                  .                .                                         .     .10-862 10.5.64RI .3  Poterd.ial Operator Action     .
                                                                                                               .                                      10-862 10.5.64RI.4    Time Available to Diagnose and Perform the Task . .                                                                  .         . 10-863 10.5.64RI.5    Operator Action Performance Time                                 .             ..                                                 . 10-863 10.5.64RI.6    Diagnosis Time for Operator Action .                                              .. .                      ..                    .10-864 10.5.64RI .7   Diagnosis Analysis .      .               .          .       .                                                                . 10-864 l

l 10.5.64RI.8 Post-Diagnosis Action Type identification per Step 10, 8-1 of ASEP HRAP .10-865 10.5.64R1.9 Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP . .10-865 l 10.5.64RI.10 TotalHEP . . . .

                                                                                                                                                    .10-866

! 10.5.64R2.1 HEP 64R2 Calculation . .

                                                                                                                                                    .10-867 10.5.64R2.2    Sequence Timing and Indications                                                          .                                        .10-868 10.5.64R2.3    Potential Operator Action                                         .                              .                                 .10-868 10.5.64R2.4    Time Available to Diagnose and Perform the Task                         .             .
                                                                                                                                                    .10-869

, 10.5.64R2.5 Operator Action Performance Time . . .10-869 i 10.5.64R2.6 Diagnoris Time for Operator Action . .10 870 l 10.5.64R2.7 Diagnosis Analysis . . .10-870 10.5.64R2.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-871 10.5.64R2.9 Post-Diagnosis Stress-level identification per Step 10, 8-1 of ASEP HRAP .10-871 10.5.64R2.10 Total HEP . . . . , .

                                                                                                                                                    .10-872  ,

f 10.5.66RI.1 HEP 66R1 Calculation . .

                                                                                                                   .                                .10-873 l

10.5.66RI .2 Sequence Timing and Indications .10-874 10.5.66R1.3 Potential Operator Action .

                                                                                                                                                    .10-874 10.5.66RI.4    Time Available to Diagnose and Perform the Task                                             ..                                    .10-875 10.5.66RI .5   Operator Action Performance Time                      .
                                                                                                                                                    .10-875 10.5.66RI .6  Diagnosis Time for Operator Action .               .
                                                                                                                                                     .10-876 t

NUREG/CR-6143 x1 Vol. 2, Part I

List of Tables (Continued) 10.5.66RI .7 Diagnosis Analysis . .. . .10-876 10.5.66RI.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-877 10.5.66R1.9 Post-Diagnosis Stress-Level Identifier tion per Step 10, 8-1 of ASEP HRAP .10-8;7 10.5.66RI.10 Total HEP . .

                                                                                                                                                . 10-878 10.5.67RI.1   HEP 67R1 Calculation .                                                                            .                                .10-879 10.5.67RI.2   Sequence Timing and Indications                                                                                                   .10-880 10.5.67RI.3   Potential Operator Action .                                .                                                                       .10-880 10.5.67RI .4   Time Available to Diagnose and Perform the Task                                                                              .     .10-881 10.5.67RI.5    Operator Action Performance Time .                         .                                          .                 .         .10-881 10.5.67RI .6   Diagnosis Time for Operator Action .                                                       ..     .                     .         .10-882 10.5.67RI .7   Diagnosis Analysis . ..                                                 .      .              .                                   .10-882 10.5.67RI .8   Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                        . .                .10-883 10.5.67R1.9    Post-Diagnosis Stress-Level Identification per Step 10, 8-1 of ASEP HRAP                                           .              .10-883 10.5.67RI.10   Total HEP . .    .                                                                     .        .              ,.              . 10-884 10.5.102RI.1   HEP 102R1 Calculation .                            .               .                                         .                    .10-885 10.5.102RI.2   Sequence Timing and Indications                                                                              . .                  .10-886 10.5.102R1.3   Potential Operator Action               .                             .                                                           .10-886 10.5.102RI.4   Time Available to Diagnose end Perform the Task                                                              .                    .10-887 10.5.102RI.5   Operator Action Performance Time                                          .                             .                         .10-887 10.5.102RI.6   Diagnosis Time for Operator Action .                   .                          .                                               .10-888 10.5.102RI.7   Diagnosis Analysis .                           .                                                                            .     .10-888 10.5.102RI.8   Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                                ,         .10-889 10.5.102R1.9   Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP                                                           .10-889 10.5.102RI.10  Total HEP . .           ..                                                                                            .          .10-890 10.5.119RI.1  HEP 119R1 Calculation .           .                                        .                                                      .10-891 10.5.119R1.2   Sequence Timing and Indications                                      .                                                           .10-892 10.5.119RI.3  Potential Operator Action                              .                                                                          .10-892 10.5.119RI.4  Time Available to Diagnose and Perform the Task                            ..                                                     .10-893 10.5.119R1.5  Operator Action Performance Time                                                                                                  .10-893 10.5.119RI .6 Diagnosis Time for Operator Action .                              .                                                               .10-894 10.5.119RI.7  Diagnosis Analysis .     .    .            .              .                                                                 . 10-894 10.5.119R1.8  Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP                                    .                      .10-895 10.5.119RI.9  Post-Diagnosis Stress-Level Identificationper Step 10, 8-1 of ASEP HRAP                                                           .10-895 10.5.119RI.10  Total HEP . . . . ..                                            .                         .                                       .10-896 10.5.123Rl.1   HEP 123R1 Calculation .                .                                                     .       .                            .10-897 10.5.123R1.2   Sequence Timing and Indications              ..                               .                                                   .10-898 10.5.123Rl.3   Potential Operator Action                                     .                      .                     .                      .10-898 i

10.5.123RI.4 Time Available to Diagnose and Perform the Task . .10-989 l 10.5.123RI.5 Operator Action Performance Time . . . .10-989 10.5.123R1.6 Diagnosis Time for Operator Action . . . .. ... .10-900 10.5.123R1.7 Diagnosis Analysis . . . . .10-900 10.5.123RI.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP . .10-901 10.5.123RI.9 Post-Diagnosis Stress-LevelIdentificationper Step 10, 8-1 of ASEP HRAP . .10-901 10.5.123R1.10 Total HEP . . .10-902 10.5.127.1 HEP 127 Calce.lation . . .

                                                                                                                                                 .10 903 10.5.127.2     Sequence Timing and Indications                                                                                            . 10-904 10.5.127.3     Potential Operator Action . .         .           ...                                                                            .10-904 l 10.5.127.4     Time Available to Diagnose t.nd Perform the Task                                                                                 .10-905 l 10.5.127.5     Operatar Action Perforniance Time                                                                                .               .10-906 1

10.5.127.6 Diagnosis Time for Operator Action . .10-907 10.5.127.7 Diagnosis Analysis . . . .10-907 10.5.127.8 Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP .10-908 10.5.127.9 Post-Diagnosis Stress-Level Identification per Step 10, 8 1 of ASEP HRAP .10 908 Vol. 2, Pan 1 xli NUREG/CR-6143

List of Tables (Continued) Total HEP . . .10-909 10.5.127.10 HEP 128 Calculation .

                                                                                                                                                                                                         .10-910 10.5.128.1                                           .

Sequence Timing and Indications .10-911 10.5.128.2 . . Potential Operator Action . .. . .10-911 10.5.128.3 Time Available to Diagnose and Perform the Task 10-912 10.5.128.4 Operator Action Perfonnance Time . .10-912 10.5.128.5 Diagnosir Time for Operator Action . .10-913 10.5.128.6 Diagnosis Analysis . .10 913 10.5.128.7 .

                                                                                                                                                                                                         ,10-914 10.5.128.8       Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP Post-Diagnosis Stress-LevelIdentificationper Step 10, 8-1 of ASEP HRAP                                                                                                                   .10-914 10.5.128.9 Total HEP .                                                                                                                                                          .                    .10 915 10.5.128.10                                           ..                    .               .

HEP 129 Calculation . .10-916 10.5.129.1 . Sequence Timing andIndications .. .10-917 10.5.129.2 . Potential Operator Action .10-917 10.5.129.3 10.5,129.4 Time Available to Diagnose and Perform the Task . . . .10-918 Operator Action Perfonnance Time . . 10-918 10.5.129.5 Diagnosis Time for Operator Action . . . 10-919 10.5.129.6 Diagnosis Analysis . . .10-919 10.5.129.7

                                                                                                                                                                                                          ,10-920 10.5.129.8      Post-Diagnosis Action Type Identification per Step 10, 8-1 of ASEP HRAP
                                                                                                                                                                                                          ,10 920 10.5.129.9      Post-Diagnosis Stress-LevelIdentification per Step 10, 8-1 of ASEP HRAP Total HEP .                                                                                                                                                       ,                      . 10-921 10.5.129.10                       .     .     ,

Basic Events UsedinLP&S Analysis ..I12 11.2.1 Defmitions of Plant Operational States .11 30 11.3.3-1 Durations ofFuel Cycles 2 Through 4. . .11 33 11.3.3-2 . . 11.3.3-3 Plant Operational State Changes During Refueling Outage 2 . .Il-33 11.3.3-4 Plant Operational State Changes During Refueling Outage 3 .Il-34 11.3.3-5 Plant Operational State Changes During Refueling Outage 4 . . Il-34 11.3.3-6 Durations of Plant Operational States During RFOs 2,3, and 4 . .I1 35 11.3.3-7 Plant Operational State Changes During Unscheduled Power Dips That Go Below 15% for FuelCycle 1 . . .

                                                                                                                                                  .                                                         . Il-36 11.3.3-8         Plant Operational State Changes During Unscheduled Power Dips That Go Below 15% for FuelCycle 2       .            ..             .       ..           .
                                                                                                                                                                                                     .       .11-37 11.3.3-9        Plant Operational State Changes During Unscheduled Power Dips That Go Below 15% forFuel Cycle 3 . .                                                                   .
                                                                                                                                                                                                             . Il-37 11.3.3 10       Plant Operational State Changes During Unscheduled Power Dips That Go Below 15% forFuel Cycle 4                  .      .                                .
                                                                                                                                                                                                             . Il-38 11.3.3 11       Non-RFO Time included in Analysis                                     . ..                                                                                                                . . Il-39 11.3.3 12        Summary of SCRAMS                                                  .  .                                                                           .                                        . Il 39 11.3.3 13        Summary of Controlled Shutdowns To Below 15%                                    .
                                                                                                                                                                                                             .I1-40 11.3.3-14        Durations of Controlled Shutdown PCSs                                .
                                                                                                                                                                                                         . . I l-4 I Durations of SCRAM and Recovery POSs . .                                                                          . .                                                                       .11-41 11.3.3-15                                                                                             ..                                                                              .

11.3.3 16 Relative Times in POSs . . . . Il-43 11.3.5-1 Time Vesselis in Hydro Test in POS S . . . . . . Il-43 11.3.5-2 Fraction of Time Vessel is in Hydro Test in POS 5 .

                                                                                                                                                                                                 .            . Il-43 11.3.5-3         Time Plant is on ADHR to Remove Decay Heat . . . .                            .
                                                                                                                                                                                                       .      . Il-44 11.3.5-4         Fraction of Time Plant is on ADHR to Remove Decay Heat                               .                                                                                                      . Il-44 11.3.5 5         Tune Spent With SP Water Levelin Various States . .                               .                                                                       .                     .           . Il-45 11.3.5-6         Fraction of Time SP Water Level is Nonna1, Reduced, or Empty                                                                                                          .                     . Il-45 11.3.5-7        Time Vessel Level is Suflicient for Natural Circulation in POS 5                              .                                                           .                                 . Il-48 11.3.5-8        Fraction of Time Vessel Les el is Sufficient for Natural Circulation in POS 5 .                                                                                                              .I148 11.3.6-1        Availability /Unsvailability of HPCS During POS 5                                                                                                                                            . Il-48 11.3.6 2        Fraction of Time HPCS is Unas ailable During 11.S 5                                -                                                                                                         . Il-49 xlii                                                                                                                       Vol. 2, Part 1 NUREG/CR-6143

List of Tables (Continued) 11.3.6-3 Availability / Unavailability of CDS During POS 5 . . . .. . Il-49 11.3.6-4 Fraction of Time CDS is Unavailable During POS 5 . .I1-49 11.4.1 Event Values for Time Window Analysis .. . . . .Il-50 12.2.1 Results from Quantification of TSD Acident Sequences . . .12-8 12.2.2 Results from Quantification of TSA Accident Sequences . . . . . 12-30 12.2.3 Results from Quantification of TDB Accident Sequences . 12-40 12.2.4 Results from Quantification of TIA Accident Sequences . .. . .12-45 12.2.5 Results from Quantification of TAB Accident Sequencet . . . . 12-55 12.2.6 Results frmn Quantification of J2 Accident Sequences . . . . . . .12-57 12.2.7 'tedts from Quantification of ElB Accident Sequences . . . . . . 12-69 12.2.8 Results from Quantification of E2B Accident Sequences . . . . . 12-86 12.2.9 Results from Quantification of eld Accident Sequences . .. . . .12-97 12.2.10 Results from Quantification of E2D Accident Sequences . . . . .12-101 12.2.11 Results from Quantification of TSB Accident Sequences . . .. . .. .12 104 12.2.12 Results from Quantification of TSC Accident Sequences . . . . . . 12-109 12.2.13 Results from Quantification of A5 Accident Sequences . . . .12-113 12.2.14 Results from Quantification of S2H Accident Sequences . .12 114 12.2.15 Results from Quantification of ASHY Accident Sequences .12-114 12.2.16 Results from Quantification of SlH.S Accident Sequences . .12 !!5 12.2.17 Results from Quantification of S2-5 Accident Sequences . . . . 12-115 12 2.18 Results from Quantification of S3-5 Accident Sequences .12 116 12.2.19 Results from Quantification of SI-5 Accident Sequences .. . .. .12-116 12.2.20 Results from Quantification of TIOP Accident Sequences . . . . 12 117 12.2.21 Results from Quantification ofE2T Accident Sequences . .12-118 12.2.22 Results from Quantification of E2V Accident Sequences . . . . . .12 123 12.2.2? Results from Quantification of TLM Accident Sequences .. . . . .. .12 126 12.2.24 Results from Quantification of ElT Accident Sequences . . . .12-132 12.2.25 Results from Quantification of ElV Accident Sequences . . .. . . .12-145 12.2.26 Results from Quantification of TDIP Accident Sequences . . . . . . . 12-149 12.2.27 Results from Quantification of TIOF Accident Sequences . .12-150 12.2.28 Results from Quantification of TI Accident Sequences . .. . 12-154 12.2.29 Results from Quantification ofHI Accident Sequences . . .. . . .12 169 12.2.30 Results from Quantification of TRPT Accident Sequences .12 178 12.3.1 Summary Results from Quantification of TSD Accident Sequences .. . . . 12 184 12.3.2 Summary Results from Quantification ofTSA Accident Sequences . . .12-185 12.3.3 Summary Results from Quamification of TDB Accident Sequences . .. . .12 186 12.3.4 Summary Results from Quantification of TIA Accident Sequences . . . .12-187 12.3.5 Summary Results from Quantification of TAB Accident Sequences . . . .12-188 12.3.6 Summary Results from Quantification of J2 Accident Sequences . . . 12-188 12.3.7 Summary Results from Quantification ofElB Accident Sequences . 12-189 12.3.8 Summary Results from Quantification ofE2B Accident Sequences . .12 189 12.3.9 Summary Results frc.n Quantification of eld Accident Sequences . .12 190 12.3.10 Summary Results from Quantification of E2D Accide it Sequences .12-190 12.3.11 Summary Results from Quantification of TSB Accident Sequences .12-190 12.3.12 Summary Results from Quantification of TSC Accident Sequences . 12-191 12.3.13 Summary Results from Quantification of A5 Accident Sequences . . .12 191 12.3.14 Summary Results from Quantification of S2H Accident Sequences 12-191 12.3.15 Summary Resulte from Quantification of ASHY Accident Sequences . . .12-192 12.3.16 SummaryResuits from Quantificaticn of SlH-5 Acciden! Sequences . . . 12-192 12.3.17 Summary Results from Quantification of S2-5 Accident Sequences .12-192 12.3.18 Summary Results from Quantdication of SI 5 Accident Sequences .12 193 12.3.19 Summaiy Results from Quantification of E2T Accident Sequences . . . 12-193 Vol. 2, Part 1 xliii NUREG/CR-6143

List of Tables (Continued) Summary Results from Quantification of E2V Accident Sequences . .12-193 12.3.20 Summary Results from Quantification of TLM Accident Sequences .12-194 12.3.21 Summary Results fmm Quantification of EIT Accident Sequences . . . 12-194 12.3.22 Summary Results from Quantification of E1V Accident Sequences .12 195 12.3.23 Summary Results from Quantification of T1 Accident Sequences . .12-196 12.3.24 Summary Results from Quantification ofH1 Accident Sequences . .12-197 12.3.25 12.3.26 Summary Results from Quantification of TRPT Accident Sequences . . . . . . . . . . . . . . . . . . 12-197 Summary Results for All IEs Before Time Window Analysis .12-198 12.3.27 .

 ~.4.1         Results from the Time Window Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-200 12.5.1          Uncertamty Results for Sequences Surviving Recovery Analysis (Sample Size = 1000 and Seed = 12345) ..              .      . .          .                .                       .12-201 12.5.2          Point Estimate vs. Mean Core Damage Frequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 202 Plant Damage State Descriptions                                  . .                                                  .13-1 13.1                                                      .

Plant Damage State Results . .13-5 13.2 . Core Damage Frequency Information by Sequence ......................... ..... 14-2 14.1 14.2 Core Damage Frequency and Percentage of Total Frequency by Initiating Event ..... . . . . . . 14-3 14.3 AS Sequence 02 06-01-27-W1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 12 14.4 Basic Event Importance Measures for Sequence 02-06-01 W1 . . . . . . . . . . . . . . . . . . . . . 14-12 AS Sequence 02-06-01-27-W2A . . . . . . . . . . . . . . . . . . . . . ............ ........ 14-13 14.5 14.6 Basic Event Importance Measures for Sequence 024-01-27-W2A . . . . . . . . ........... 14-13 14.7 AS Sequence 02 01 W2B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-14 14.8 Basic Event Importance Measures for Sequence 024-01-27-W2B . . . . . . . . . . . . ....... 14-14 14.9 AS Sequence 02-06-01-27-W3 A . . . . . . . . . . . . . . . . . . ................... . . . . 14-15 14.10 Basic Event Importance Measures Summary for Sequence 024-01-27-W3 A5 . . . . . . . . . . . . 14-15 14.11 A5 Sequence 064-01-27-W3 A . . . . . . . . . . . . . . . . . . . . . . . . . ........... . . . . . 14-16 14.12 Basic Event Importance Measures for Sequence 06-06-01 27-W3A . . . . . . . . . . . . . . . . . . . . 14-16 14.13 ASHY Sequence 3-07-01-27-W3 A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......... 14-17 14.14 Basic Event importance Measures for Sequence 3-07 01-27 W3A . . . ...... ... . . . . . . 14 17 14.15 EIT5H Sequence 07 11 01-27 W2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-18 14.16 Basic Event Importance Measures for Sequence 07-11 27-W2 . . . . . . . . . . . . . . . . . . . . . 14-18 14.17 E2T5H Sequence 04-11 27-W2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... 14-19 14.18 Basic Event Importance Measures for Sequence 04-11 27-W2 . . . . . . . . . . . . . . . . . . . . . 14 19 14.19 H1-5H Sequence 03 01-11 -01 27W 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 20 14.20 Basic Event Importance Measures for Sequence 03 01 11-27W1 . . . . . . . . . . . . . . . . . . . . . . 14-20 14-21 14.21 H1-511 Sequence 03-01 -11 01 -27W2 . . . . . . . . . . . . . . . . . . . . . . . . . . ............ 14.22 Basic Event importance Measures for Sequence 03-01-11-01-27W2 . . . . . . . . . . . . . . . . . . . 14-21 14.23 H1-5H Sequence 03-01 2-W2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-22 14.24 Basic Event Importance Measures for Sequence 03-01-50-2-W2 . . . . . . . . . . . . . . . . . . . . . 14-22 14.25 J2-5 Sequence 2-01 01 W2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-23 14.26 Basic Event Importance Measures for Sequence 2 01 11 01-27.W2 . . . . . . . . . . . . . . . . . . . 14-23 14.27 SI-5 fequence 024-01 -27.W 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... 14-24 14.28 Basic Event Importance Measures for Sequence 024-01 W1 . . . . . . . . . . . . . . . . . . .. 14-24 51-5 Sequence 02-06-01 W2A . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ .... 14-25 14.29 14.30 Basic Event Iroponance Measures for Sequence 024-01-27.W2A . . . . ........... . . . 14-25 14.31 51-5 Sequence 02 06 01 -27 W2B . . . . . . . . . . . . . . . . . . . . . . . . . . . ....... . ... 14-26 Basic Event Importance Measures Summary for Sequence 02-0641-27-W2B . . . . . . . .... 14-26 14.32 14.33 SI-5 Sequence 06 06-01-27-W3 A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 27 14.34 Basic Event importance Summary for Sequence 06-06-01-27-W3 A . . .. ... ..... . . 14-27 14.35 S1H-5 Sequence 3-09-01 27-W3 A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-2 8 14.36 Basic Event Importance Summary for Sequence 3-09-01-27-W3A . . . . . ......... . . . . 14-28 14.37 T1-5 Sequence 3-14-W1 A . . . . . . . . . . . . . . ..... .... ... . . .... ..... . 14-29 xliv Vol. 2, Part 1 NUREG/CR-6143

List of Tables (Continued) ! 14.38 Basic Event Importance Summary for Sequence 3-14-W1A . . . . . . . . . . . . . . . . . . . . . . . . 14 -29 14.39 T1-5 Sequence 3 14-W1B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 3 0 , 14.40 ' Basic Eveat Importance Summary for Sequence 3-14-W1B . . . . . . . . . . . . . . . . . . . . . . . . . 14-30 14.41 T1 -5 Sequence 3-14-W1 C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-31 ' 14.42 Basic Event Importance Summary for Sequence 3-14-WIC . . . . . . . . . . . . . . . . . . . . . . . . . 14-31 14.43 T1 -5 Sequence 3-14-W1 E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-32 14.44 Basic Event Importance Summary for Sequence 3-14-W1E . . . . . . . . . . . . . . . . . . . . . . . . . 14-32 14.45 T1 -5 Sequence 3-14-W2A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-33 > 14.46 Basic Event Importance Summary for Sequence 3-14-W2A . . . . . . . . . . . . . . . . . . . . . . . . 14-3 3 - 14.47 T1 -5 Sequence 3-14-W2B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-34 I 14.48 Basic Event Importance Summary for Sequence 3-14-W2B . . . . . . . . . . . . . . . . . . . . . . . . . 14-34 , 14.49 T1 5 Sequence 3 14-W2C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-35 ! 14.50 Basic Event Importance Summary for Sequence 3-14-W2C . . . . . . . . . . . . . . . . . . . . . . . . . 14 35 14.51 T1 5 Sequence 3-14-W2D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-36 ! 14.52 Basic Event Importance Summary for Sequence 3-14-W2D . . . . . . . . . . . . . . . . . . . . . . . . 14-36 ' 14.53 T1 -5 Sequence 3-14.W2E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-37 r 14.54 Basic Event Importance Summary for Sequence 3-14-W2E . . . . . . . . . . . . . . . . . . . . . . . . . 14-37 14.55 T1 5 Sequence 5-15-W1B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-38 ( 14.56 Basic Event Importance Summary for Sequence 5-15-W2B . . . . . . . . . . . . . . . . . . . . . . . . . 14 38

14.57 T5 ASH Sequence 03-51-35-04-W2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 3 9 i 14.58 Basic Event Importance Summary for Sequence 03-51 3544-W2 . . . . . . , . . . . . . . . . . . . . . 14-39 14.59 Basic Event Importance Summary for Total Plant Hodel . . . . . . . . . . . . . . . . . . . . . . . .. . 14-40 l 3

i I h r i i Vol. 2, Part 1 xlv NUREG/CR-6143

List of Acronyms ADHR Auxiliary Decsy Heat Removal ADS Automatic Depressunzation System ATWS Anticipated Transient Without Scram BNL Brookhaven NationalLaboratory BWR Boiling Water Reactor CCW Component Cooling Water CDS Condensate CI Containment Isolation CRD ControlRod Drive CRWST Condensate and Refueling Water Storage Transfer System CS Containment Spray CST Condensate Storage Tank CV Check Valves CVS Containment Venting System DBA Design Basis Accident DG Diesel Generator ECCS Emergency Core Cooling Systems EHC Electro-Hydraulic Controller EHV Emergency Ventilation System ENSDC Enhanced Shutdown Cooling EPS Emergency Power System FCV Flow Control Valve FDW Feed Water Systan FW Fire Water HCU Hydraulic ControlUnit HPCS High Pressure Core Spray 1AS Instrument Air System IRRAS Integrated Reliability and Risk Analysis System LCO Limiting Condition of Operation LOCA less of Coolant Accident LPCI lewt essure Coolant injection LPCS low Fressure Core Spray MSIV Main SaamIsolation Valve i MSL Mean Sea Level MSR Moisture Separator Reheater NPSHA Net Positive SuctionHead Available NPSHR Net Positive Suction Head Required NRC Nuclear Regulatory Commission OC Operating Condition POS Plant Operating State PPA Probabilistic Risk Assessment PSW Plant Senice Water PWR Pressunzed Water Reactor l!CIC Reactor Core Isolation Cooling RES Research(Office of NRC) RFPT Reactor Feedwater Pump Turbine RHR Residual Heat remm al RPV Reactor Pressure Vessel RRS Reactor Recirculation System . i RWCU Reactor Water Cleanup System SDC Shutdown Cooling System (s) SGTS Standby Gas Treatment System I xlvi Vol. 2. Part 1 NUREG/CR-6143

List of Acronyms (Continued) SL Safety Limit SLC Standby Liquid Control SF Suppression Pool SPC Suppression Pool Cooling SPMU Suppression PoolMakeup SPMU Suppression Pool Makeup SR Surveillance Requirement SRV Safety Relief Valve SSWXT Standby Service Water Crosstic TBCW Turbine Building Cooling Water TBV Turbine B 3pass Valve (s) UFSAR Updated Final Safety Analysis Report s Vol. 2, Part 1 xlvii NUREG/CR-6143

l Foreword j (NUREG/CR-6143 and 6144) i Low Power and Shutdown Probabilistic Risk Assessment Program i Traditionally, probabilistic risk assessments (PRA) of severe accidents in nuclear power plants have considered initiating j 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. Ilowever, more i recent studies and operational experience have implied that accidents during low power and shutdown could be significant j contributors to risk. During 1989, the Nuclear Regulatory Commission (NRC) initiated an extensive program to carefully examine the poteritial . 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, Suny (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 int rnal events, intemal 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: l NUREG/CR-6143 - Evaluation of Potential Severe Accidents During Low Power and Shutdown Opera 6ns at ; Grand Gulf Unit 1 ; Volume 1: Summary of Results Volume 2: Analysis of Core Damage Frequency from Internal Events for Plant Operational State 5 During a Refueling Outage Part 1: Main Report Part 1A: Sections 1 -9 ' Part 1B: Section 10 Part IC: 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 i 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 j Operational State 5 During a Refueling Outage Volume 5: Analysis of Core Damage Frequency frc.rn Seismic Events for Plant Operational , State 5 During a Refueling Outage t 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 NUREG/CR-6143 xlviii Vol. 2, Part I !

Foreword (Continued) For Surry: NUREG/CR-6144 - Evaluation of Potential Severe Accidents During Low Power and Shutdown Operations at Suny 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 1A: Chapers 1 - 6 Part IB: 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: Intemal 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: AnsJysis 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: Apperatices Vol. 2 Part 1 xlix NUREG/CR-6143 i

Acknowledgements i The authors wish to acknowledge the following for their contributions to this study. The numerous individuals at the Grand l Gulf site for their help in obuumng information that made this analysis possible. Richard C. Robinson, Jr. of the NRC for his , support in obtauung timely support from the IRRAS computer code developers. Kenneth Russell of Idaho Nuclear l Engineering Laboratory for his help in using IRRAS and for providing excellent code support during tlw use of IRRAS. I Members of the Senior Consulting Group and the BWROG PRA Review Committee for their review arxl suggested , improvements to the project. Finally, to Ellen Walroth and Emily Preston for their secretanal support during the project. ;

r i b l i l i i t l t l i

h l i NUREG/CR-6143 I Vol. 2, Part 1 l t

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1 Executive Summary Traditionally, probabilistic risk assessments (PRAs) of Consequently, the NRC decided to first perform a severe accidents in nuclear power plants have considered detailed analysis on one of the off power conditions. initiating events that could occur only during full power Based on trends indicated in the results of the coarse operation. Some previous screening analyses that have screening analysis, plant operational state (POS) 5 been performed for other than full-power modes of (consisting mainly of the Cold Shutdown Operating operation suggest that risks during those modes of Condition) was selected for detailed analysis. (NOTE: operation were small relative to those occurring during Plant operational states are artificial subdivisions of the full power operation. However, recent studies and time plants spend in low power and shutdown conditions. operational experiences indicate that low power and This concept was developed during Phase 1 of this shutdovn accident risks may be significant. Although project to allow the analysts to better represent the plant the power of the reactor core is much less in off power as it transitions from power operation to non power conditions than at full power, the technical specifications operation.) This report presents the results of the allow for more equipment to be inoperable in off power detailed analysis of the Grand Gulf facility in POS S conditions. In certain conditions the containment can be during a refueling outage. open. A companion project for the Surry Pressurized Water In response to the concerns over risk during low power Reactor (PWR) is being conducted by Brookhaven and shutdown conditions, the U.S. Nuclear Regulatory National Laboratory (BNL). Commission's Office of Nuclear Regulatory Research (NRC RES) has undertaken a two phase project to 1.1 Objectives analyze the frequencies, consequences, and risk of eccidents occurring during modes of operation other than The primary objective of this study was to perform a full power, detailed analysis of potential accidents that could occur at Phase 1 of the project was completed in September of 1991 [ Whitehead, et al.,1991). This phase involved a Other objectives included the following. (1) Compare coarse screening of potential accidents that could occur at the results of this study to the results of the full power e Boiling Water Reactor (BWR) while operating at other analysis for Grand Gulf [USNRC,1989] [Drouin, et al., than full power. The coarse screening approach was 1989). (2) Develop a methodology for performing PRAs adopted as a means of obtaining, in a relatively short for nuclear power plants in conditions other than at full time, some estimate of the potential for accidents during power. (3) Provide an analytical tool with which the low power and shutdown conditions and some idea of the NRC can evaluate the potential benefits of proposed msguitude of the work necessary to perform a more changes in regulations affecting the required operability detailed analysis of these operating states. The BWR of equipment when a plant is in a condition other than examined was the Grand Gulf Nuclear Power Station, a full power. single unit 1250 MWe (net) BWR 6 power plant with a Mark 111 containment, located near Port Gibscu, Mississippi. 1.2 Approach and Limitations The coarse screening analysis (the results of which are The appmach used was a modification of a standard summarized in Appendix M) indicated that to accurately level 1 PRA approach. Event trees were constructed, evaluate accidents in low power or shutdown conditions, top events were modeled using fault trees of various detailed modeling is required; and, that the risk during complexities, and the top events were quantified using these conditions cannot be shown to be insignificant by a p int estimates to produce the sequence frequencies. conservative screening analysis. Based on these These sequences were then examined for recovery conclusions, the NRC decided to have follow-on detailed p rential and salidity. For those sequences where analyses performed. recovery was applicable appropriate recovery actions were incorporated. The sequences that survived the The coarse screening analysis addressed all low power recovery analysis were then re-examined during a ' Time and shutdown conditions, but not in the detail required to Window" analysis. During this Time Window analysis cecurately quantify risk. To accurately address each of the surviving sequence cut sets were requantified based these conditions in detail represents a large effort. n their contribution to three distinct time regimes for PO4 * (i.e., entry into POS 5 to 24 hours,24 hours to Vol. 2, Part I l-1 NUREG/CR-6143

Ex. Summary entry into POS 6, and POS 5 after core alterations). shutdown cooling requires recirculation, either forced or natural, to prevent pressurization The fault trees from the full power PRA for Grand Gulf transients; were utilized wherever possible [Drouin, et al.,1989]. The IRRAS computer code was used in the construction (c) Recirculation is sensitive to actual level in the of the event trees, modification of existing fault trees and core region, which is related to but not equal to construction of new trees, and the quantification of the measured level in the dowticomer, due to eccident sequences [ Russell, et al.,1992]. In addition, density and pump head effects; information contained in the NUREG-1150 analysis of the Grand Gulf plant was used wherever applicable. (d) At decay heat levels of concern, flooding induced dryout of the core at atmospheric in comparison with the full power PRA, the event trees pressure will not occur, and the core can be for POS 5 are more complex and lengthy. His is due to cooled by steaming with about 250 gpm the relatively low decay heat in cold shutdown, resulting makeup; in a large number of ways by which cooling can be provided to the core, given the coolant is initially in a (e) To steam at low pressure, opening of one safety subcooled state. Also, the availability and configuration relief valve in relief is sufficient to maintain of plant systems in POS 5, as compared to full power, is pressure low enough so that the low head more complex to specify due to the less stringent pumps in the emergency cooling system can requirements on operability imposed by the technical provide sufficient makeup; specifications. (f) Opening of one safety relief valve in relief The methodology used in this study is the "small* event requires operator action, DC power, and air; tree /large fault tree technique. In practical applications, this technique assumes a fixed initial plant state prior to (g) In using the emergency core cooling system in the occurrence of an accident initiating event. nrough a water solid mode, opening of two safety relief the use of seven analysis

rules" (or assumptions) we valves in the relief mode prevents were able to consider numerous different conditions that overpressurizing shutdown cooling system can, and in fact do, exist at shutdown prior to the components, both in the residual heat removal occurrence of an accident initiating event. system and in the alternate decay heat removal system (ADHRS), regardless of the pump (s)

We did not address test and maintenance induced loss of used; coolant accidents (LOCAs) in this study. Development of a detailed methodology for analyzing human actions (h) In using the emergency core cooling system in during shutdown conditions is underway, and analysis of a water solid mode, opening of one safety relief such events is deferred until this improved methodology valve in the relief mode prevents is avr.ilable, overpressurizing the components in the residual heat removal system used in shutdown cooling, but components in the auxiliary decay heat 1.3 ResultS removal system may overpressurize; 1.3.1 Insights Into Plant Systems (i) Isolation of the shutdown cooling system allows

                                                                                 **              * "        E ***""

Characteristics of the plant design are a major factor Shu o 'n F ran Gulf e o ant systets are required fM operation of the valve charactenstics are of umt importance: in the safety mode; (a) Shutdown cooling system components are not (j) Use of emergency core cooling systems in a rated for full pressure, but automatic isolation water solid mode does not require suppression occurs on either high pressure or on low level; pool makeup, in the short term, to compensate (b) Use of the residual heat removal system for 1-2 Vol. 2, Part 1 NUREG/CR-6143

Ex. Summary (k) Water can be injected into the vessel at low Two classes ofinitiating events dominate the results from pressure from both service water and diesel this study. As can be seen below, LOCA/ Diversion and driven firewater pumps. LOSP/ Blackout constitute approximately 95% of the total core damage frequency. 1.3.2 Insights Into Plant Operations In POS 5 (i.e., Cold Shutdown), requirements of the technical specifications for the operability of systems and IE Class Alean % Contribution components are much less stringent than for power CDF To CDF operation. The actual availability of sy;tems depends on LOCA/ Diversion 1.3 E-06 62 plant specific practices, and on the reason for LOSP/Bla ckout '/.0E-07 33 transitioning the plant to cold shutdown, in this case, a Other 9.9E-08 5 refueling outage. 2.1E-06 100 For Grand Gulf, the following practices have an important impact on the ability to cool the core in POS 5: Figure 1-1 gives a graphical presentation of the (a) At least two safety relief valves are maintained contributions to core damage frequency by the various operable for both relief and safety operation; initiating events. For the important initiating events two types of accident sequences are among the dominant (b) Automatic isolation of the low pressure sequences. They are: shutdown cooling system is not bypassed, and both auto-isolation on high pressure and on low

Blackout - Loss of all AC power and level are maintained:
Flooding Containment -Injection of water into (c) Some subsystems of the emergency core vessel, out the SRVs to the Suppression Pool, and cooling system are available most of the time: finally out open lower containment personnel lock.

1.3.3 Total Plant Model Results From a core damage frequency vs Time Window aspect, Time Window 2 is the most important. Figure 1-2 The results from the uncertainty analysis on the total indicates that Time Window 2 contributes 58 percent of plant model (i.e., an uncertainty analysis on all of the the total core damage frequency. sequence cut sets at the same time) using 1000 samples are as follows: Another way to present the core damage frequency information is to plot the fractional contribution of each Mean Value 2.0E-006 initiator group by Time Window. This results in Figure 5th Percentile Value 4.1E-007 1-3. From this figure it can be seen that for: Median Value 1.3E-006 95th Percentile Value 5.4E-006 Time Window 1 1.3.4 Results from Sequence Quantification The core damage frequency is split between the LOCA/ Diversion and the LOSP/ Blackout g.oups The mean core damage frequency (CDF) presented here (42% and 58% respectively). results from combining the mean CDFs from all 38 sequence cut sets for the 28 sequenecs that urvived the Time Window 2 sequence analysis through the Time Window Analysis. For POS 5 during a refueling outage at Grand Gulf, the The core damage frequency is split among the sum of the mean CDFs from the surviving sequences is three groups (41 % - LOCA/ Diversion, 50 % - 2.1E-6 per year for internally initiated events (excluding LOCA/ Blackout, and 9 % - Other) internal fires and floods). Vol. 2, Part I l-3 NUREG/CR-6143

Ex. Summary TSA5H 1% AS

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E2TSH E1T5H S1H 5 " J2 5 H1-5H 2% 2% 10% S1-5 6% 1% 12% Figure 1-1 Contribution to CDF by Initiating Event A5 - Large LOCA during non-hydro conditions A5HY - Large LOCA during hydro conditions EIT5H - Isolation of Shutdown Cooling common suction line E2T5H - Loss of Shutdown Cooling common suction line H1-5H - Diversion to the Suppression Pool via the Residual Heat Removal System 12-5 - LOCA in the Residual Heat Removal System S1-5 - Intermediate LOCA during non-hydro conditions S1H-5 - Intermediate LOCA during hydro conditons TI-5 - Loss of offsite power T5A5H - less of Standby Service Water System NUREG/CR-6143 1-4 Vol. 2, Part 1

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58 % Figure 1-2 Percent of CDF rs Time Window Time Window 3 Thus, from Figures 1-3 and 1-4 we see that Time I Window 2 is the most important time regime for POS 5 All core damage frequency results frem the during a refueling outage. LOCA/ Diversion group. Comparing the results of this study with those obtained One final way to present the core damage frequency in the NUREG/CR-4550 study of Gand Gulf and the information is to plot the percent contribution to the total Grand GulfIPE we find that the mean CDF obtained in core damage frequency and the percent of time spent in this study (2.0E4) is 50 percent of the NUREG/CR-each Time Window vs the three Time Windows on the 4550 value of 4.0E-6 and almost an order of magnitude same graph. From Figure 1-4 it can be seen that even less than IPE results of 1.7E-5. though the plant spends only 21 percent of the time in Time Window 2 this Time Window contributes 58 percent to the total core damage frequency. Figure 1-4 In addition, the results from this study indicate that, also indicates that Time Window 3 contributes 35 percent unlike the NUREG/CR-4550 results, sequences other of the total core damage frequency, yet 76 percent of the than those initiated by LOSP (e.g., LOCAs) contribute time is spent in thisTime Window. significantly to the core damage frequency. Vcl. 2. Part 1 1-5 NUREG/CR-6143

Ex. Summary f5 oewDawson L 6 oses L ckout C ove see

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1 2 Figure 1-4 Percent of CDF and Percent of Time in Time Window vs Time Window 1-6 Vol. 2, Part 1 NUREG/CR4143 l

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l 1 Ex. Summary 1,4 General Conclusions (2) Grand Gules requirement that at least two safety relief valves be available in POS 5 ne conclusions drawn from this study can be grouped all ws the operators to use portions of their into three categories. They indude: Inadequate Decay Heat Removal Procedure which would otherwise be inaccessable. (1) methodological, (3) Grand Gulf's additional system for removing (2) plant specific, and decay heat (i.e., the Alternate Decay Heat Removal System) impacts the estimated core (3) generic. damage frequency during two of the three POS 5 time windows. Methodolocical Generic This study was successful in developing a methodology to estimate the risk (i.e., the core damage frequency) The results from this study appear to indicate that the associated with the operation of a BWR during low risk (i.e., core damage frequency) associated with power and shutdown conditions. The methodology operating in POS 5 during a refueling outage is less than developed and the lessons learned from its application that from operating at full power. While this should be provide the NRC with new tools that could be used in true for Grand Gulf, generalizations to other BWRs subsequent analyses. should be performed with care. The mean CDF for the Total Plant Model presented in Two factors that should be considered during any this report includes the fraction of time the plant is in generalization include: POS 5 during a refueling outage. If one wants to present the results as a conditional CDF (i.e., conditional (1) Does the other BWR have a motor driven high on the plant being in POS 5), then the results should be Pressure pump? The availability of such a divided by the value assigned to the event POSS. Thus, pump provides a mechanism for injecting for this study the conditional CDF is (2E-6)/0.031 = water at high pressure, if necessary, and also 6.5E-5 per year in POS 5. However, use of the p ovides an alternate means ofinjecting water conditional CDF is not recommended since plant at low pressure should the low pressure pumps conditions (e.g., system unavailabilities and decay heat fail. Iceds) would change dramatically during a one par time period. (2) Does the other BWR have procedures in place to deal with the loss of the normal decay heat Plant Specific removal system? If the procedures do exist, does the utility require the availability of any There are three major aspects of the specific Grand Gulf support system / component necessary for the plant model used in this analysis that significantly performance of the procedure? impacted the result. These are: (1) Grand Gulfs continued requirement for automatic isolation oflow pressure ' components in the Shutdown Cooling System given an increase in pressure and/or a > decrease in water level in POS 5. Vol. 2, Part 1 37 NUREG/CR-6143

Ex. Summary References for Section 1 [Drouin, et al.,1989] M. T. Drouin et al., " Analysis [ Whitehead, et al.,1991) D. W. Whitehead, J. L. ' of Core Damage Frequency: Darby, B. D. Staple, B. Grand Gulf, Unit 1 Internal Walsh, T. M. Hake, and T. D. Evee.s," NUREG/CR-4550, Brown, "BWR low Power and SANDS 6-2084, Vol. 6, Rev. Shutdown Accident 1, Part 1, September 1989. Frequencies Project, Phase 1 - Coarse Screening Analysis,' [ Russell, et al.,1992) K. D. Russell et al., Vol.1, Draft Letter Report,

                       ' Integrated Reliability and Risk                             Sandia National Laboratories Analysis System (IRRAS)                                       and Science and Engineering Version 4.0," NUREG/CR-                                       Associates, Inc., November 5813, EGG-2664, January                                       23,1991 update, Copy 1992.                                                        available at the NRC Public Document Room.

[USNRC,1989] USNRC, " Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants," NUREG-1150, June 1989. t 1-8 Vol. 2, Fart I NUREG/CR-6143

i s 5 6 2 Program Scope and Major Assumptions i 2.1 Program Scope to-run) would increase. nis would increase the sequence frequencies. The BWR Low Power and Shutdown Accident . Frequencies Program is a two-phase project. In Phase 1 (2) Train A of ECCS unavailable - During the ! a coarse screening Level 1 probabilistic risk assessment uutial screening quantification Train A of the ! (PRA) was completed for all low power and shutdown ECCS was assumed to be unavailable for the i plant operational states (POSs), including, for one POS, entire accident progression. During the Time internal fires and floods. Based upon the results of the Window Analysis, unavailabilities of Train A Phase I work, a detailed analysis of one POS was ECCS were based on actual Grand Gulf ! performed for Phase 2 (i.e., this report). De scope of refueling outage information. This two phased ! the Phase 2 analysis includes internal events analysis, approach to the accident sequence - internal fire, and internal floods. All Level 2 and 3 identification and quantification should not analyses will be performed under a separate project, have introduced any significant non-conservatisms into the analysis. Accounting ! His report provides the results of the detailed snalysis of for the Train A unavailabilities should , the potential accidents at the Grand Gulf plant involving significantly reduce the conservatism , significant core damage, initiated during POS 5 of a associated with the initial screening refueling outage. (NOTE: POS 5 approximates the quantification and thus provide a more realistic Cold Shutdown operational condition as defmed by representation of the core damage frequency , Grand Gulfs Technical Specifications.) Included in the associated with the operation of Grand Gulf ; appendices of this report are large parts of the work during POS 5 of a refueling outage. completed in the Phase 1 analysis that have bearing on the Phase 2 work. (3) Decay heat loads at entry into POS 5 - Decay heat loads were calculated for entry into POS The analysis focuses on releases from the reactor core 5 and were used throughout the initial inside the vessel, with the vessel head on. Part 1 of screening quantification (except for Hydro test Volume 2 (this report) addresses accidents due to intemal which was assumed to occur 30 days after start initiating events associated with direct failures of plant of refueling). For the Time Window Analysis, systems and components. Volumes 3 and 4 address the decay beat loads were calculated based on accidents initiated by intemal fires and internal floods, the entry time into each Time Window This ! respectively, change had a relatively large impact on the time available for operator actions, the main i affect f the decay heat loads on the accident 2.2 Major Assumptions analysis. 6 Major assumptions, the reasons for them, and a i (4) Truncation of sequence cut sets at IE This qualitative assessment of their impact on the results of truncation level is generally used in many this study are presented in this section. The major PRAs. It is identified here only for assumptions are: ! completeness. No significant impact on the ! dominant sequences is expected by use of this j (1) A mission tirne of 24 hours - Since the results truncation limit. + of this study are to be directly compared with those from 'he full power study, it was ' (5) No recovery of component hardware failures - decided to use the same mission time. This his is a generally accepted practice and it is mission time was used to screen any accident not necessarily the case that recovery of ; sequence that required longer than 24 hours to hardware failures would be more likely during progress to core damage on the basis that low power and shutdown. Only in the later i additional suppoit would be available to the stages of the outage would the time available operators to deal with any accident still for recovery be long enough to repair pumps unmitigated after 24 hours. If the mission , and valves. If recovery of component time increased, then all failure probabilities hardware failures were incorporated into the dependent on the mission time (e.g., DG fail-Vol. 2, Part 1 2-1 NUREG/CR-6143

Scope and Assumptions analysis, then the sequence frequencies would Through the use of seven analysis "mles" (or decrease. assumptions) we were able to consider ; numerous different conditions that can, and in fact do, exist at shutdown prior to the (6) RCIC not available for mitigation - Initially, the reactor is depressurized; thus, RCIC could occurrence of an accident initiating event. not be used. If an accident progressed to the ' However, this methodology cannot in eeneral point where sufficient steam pressure existed, then RCIC could be used as long as it was not handle time dependent changes in system in system maintenance. Incorporation of configurations. For example, the methodology RCIC into the analysis could lead to lower cannot easily model all the possible changes in sequence frequencies. system availabilities during a refueling outage i as extensive maintenance is performed on (7) Open MSIVs and empty suppression pool- different systems. For POS 5 during a During the plant specific data analysis, it was refueling outage at Grand Gulf (the subject of determined that the MSIVs are closed during this report) this is not a serious limitation, . POS 5 for a refueling outage. However, there since one division of the ECCS is generally l is no requirement that they be closed. In an always out for maintenance in POS 5. This attempt to estimate the impact of open MSIVs, assumption was the basis for the initial this study assigned a value of 0.01 to the case screening of accident sequences. During the Time Window Analysis this assumption was of open MSIVs. If the MSIVs are truly never then re-examined for the sequences that open, then those sequences with initially open MSIVs can be eliminated; thus reducing the survived the initial screening quantification and changes were made to the accident sequences ; total core damage frequency. The same kind ' of situation exists for the empty suppression to more accurately reflect the conditions for pool. Thus, if the suppression pool is never each specific POS 5 time window. l empty, those sequences where the suppression l To assess risk during actual refueling l poolis empty can be removed. operations involving extensive testing and maintenance, the methodology would need j (8) Operators not opening MSIVs without condenser vacuum - Based on operator improving to consider " rolling" unavailabilities interviews, this study assigned a failure of equipment. ' probability of 1.0 to opening the MSIVs to decrease pressure given no condenser vacuum. Similarly, the methodology does not easily It was further assumed that during the consider accidents that occur as the plant majority of POS 5, no condenser vacuum transitions among modes during shutdows (for would exist. If the operators did open the example, in Hot Shutdown the plant operators MSIVs, then (for those sequences where the switch from cooling with turbine bypass to action is valid) the sequence frequencies cooling with shutdown cooling at about 100 would decrease. However, care should be psig). Plant conditions are changing during exercised, since this action would result in this transition, and are different than those steam being released into the Turbine present while either on turbine bypass cooling Building. The affects of this steam release are or on shutdown cooling. We have assumed unknown, and it is possible that equipment that accidents occurring during such transition failures could result from this steam operations are adequately considered by our environment thereby increasing the sequence models for the initial and final states of the frequencies for sequences that are more risk transition, for the following two reasons: significant.

The time spent in transition is less (9) The methodology used in this study is the than the time spent in the states "small" event tree /large fault tree technique. transitioned from and transitioned to; In practical applications, this technique thus, accidents due to random failures 1 assumes a fixed initial plant state prior to the are less likely.

occurrence of an accident initiating event. 2-2 Vol. 2, Part 1 NUREGICR-6143

Scope and Assumptions

For Grand Gulf, and many other plants, this assumption is further supported by the practice to not disable one funcuonal system (such as core cooling with turbine bypass) until the replacement system (such as shutdown cooling)is shown to be i ope:able.

We believe that the most probable situations for which unique initiating events can occur during a transition state are those i. associated with rod withdrawal during . startup. Errors in rod movements during l such situations can challenge the reactor i trip system. Such situations do not occur in POS 5. 1 e Vol. 2, Part 1 2-3 NUREG/CR-6143

ne.-, _ 3 Selection and Characterization of POS 5 This section of the report discusses the rationale used to (4) POS 4 consisting of: OC 3 with the unit on select Plant Operating State (POS) 5 for detailed RHR/SDC analysis. This section also summarizes the characteristics of POS 5, which affected the development (5) POS 5 consisting of: OC 4 (T $; 200 degrees of the accident models. F) and OC 5 until the vessel head is off 3.1 Selection of POS 5 (6) POS 6 consisting of: OC 5 with the head off and level raised to the steam lines , As discussed in Appendix A, a Plant Operating State (POS)is defined as: "a plant condition for which the (7) POS 7 consisting of: OC 5 with the head off,

status of plant systems (operating, standby, unavailable) the upper pool filled, and the refueling can be specified with sufficient accuracy to model transfer tube open.

subsequent accident events". A POS is not identical to a Mode (or Operating Condition) as defined in the Following the completion of the screemog study, it was technical specifications [USNRC,1984]; however, POSs decided to analyze one POS in detail. Given that one are defined based on Operating Conditions. The POS was to be analyzed, POS 5 was selected. From an i technical specifications define Modes or Operating examination of the results of the screening study Conditions (OCs) as follows: summarized in Appendix M, Figures 3.1 1 and 3.1-2 were constructed. As can be seen from Figure 3.1-1, (1) OC 1, Power Operation: Mode Switch in approximately 60 percent of the total core damage ! Run, Any Temperature frequency occurs in POS 5. Therefore, from a frequency point of view POS 5 is the most logical (2) OC 2, Stanup: Mode Switch in Sunup / Hot choice. l Standby, Any Temperature ; However, frequency is not always the most important (3) OC 3, Hot Shutdown: Mode Switch in discriminator for offsite risk. In an attempt to identify Shutdown, Temperature Greater than 200*F the more important sequences from a risk perspective, Figure 3.1-2 was constructed. This figure provides a (4) OC 4, Cold Shutdown: Mode Switch in breakdown of the sequences classified as having a p tentially high frequency with regard to an open ; Shutdown, Temperature 200*F or Iower containment and early core damage - a,mportant ; (5) OC 5, Refueling: Fuelin Vessel with Head * "'**teristics fr m the limited plant damage state ) ana ys. nned during the screenimig study. From Detensioned or Removed, Mode Switch in 4 Figure 3.1-2 we see that out of a total of 303 potentially Shutdown or Refuel, temperature 140'F or high core damage sequences,178 are from POS 5 with I'**f' an open containment and early core damage. This information lends additional support to the choice of POS Appendix A provides a description of the process used to 5 for detailed analysis. identify and characterize a POS, and it discusses all of , the POSs analyzed in the screening study [ Whitehead, et In addition to the numerical results, engineering insight ' al.,1991]. Using the OCs as a startmg pomt, the was used to support the selection of POS 5 for detailed following seven POSs were defined: study. The reasons for selecting POS 5 for detailed (1) POS 1 consisting of: OC 1 and OC 2 with pressure at rated conditions (about 1000 psig) In POSs 1,2, and 3, the state of the plant is essentially and thermal power no greater than 15 % the same as for full power except that the power is lower i and pressure / temperature can be lower. Therefore, the (2) POS 2 consisting of: OC 3 from rated initiating events and configuration of mitigating systems pressure to 500 psig are essentially the same as for full power. Since the

                         ,                                                   plant is in these POSs less often than it is at full power, (3) POS 3 consisting of: OC 3 from 500 psig to                        the risk in these POSs is less than at full power, by a where RHR/SDC is initiated (about 100 psig)

Vol. 2, Part 1 3-1 NUREGICR-6143 l

Selection and Characterization l

60" f I C - , o 50 '

2. '

W 40 l o H g 30 c - e 20 2 e . 0- 10 i , , filW, , , 1 2 3 4 5 6 7 Plant Operational State (POS) Figure 3.1-1 POS vs Percent CDF Phase 1 Grand Gulf PRA Distribution of Core Damage Sequences Containment Open a 259 Totala 1163 PotentiaHy High a 30 I 73 186

                                             /                       [      , . - _ .

A" l)

                                                         -         /                           -

l Early onset to CD = 230 Figure 3.1-2 Potentially IIigh Frequency, Open Containment, and Early Core Damage Sequences in POS S N15.aC'CR-6143 3-2 Vol. 2, Part 1

f n Selection and Characterintion 1 j factor approximately equal to the fraction of time in system (s) after the break occurs.) Because of the f these POSs divided by the fraction of time at full power. inoperability of auto-isolation on high pressure in POS 5,

  ,    Based on this rationale, neither POSs 1, 2, nor 3 would          and because of the possible use of ADHR during i'

be selected for detailed analysis. POS 5, POS 5 should be chosen over POS 4 for detailed analysis. In POSs 6 and 7, the vessel head is off, thus alleviating concerns over overpressuriation of shutdown cooling During a subsequent visit to the site in June,1992, we systems components. Also, in POSs 6 and 7, the water were infonned that auto-isolation of SDC is active in level is raised, thereby providing more time for cold shutdown, POS 5. In response to this new rnitigation of accident initiating events than in POSs 4 or information, which we think is a safety enhancement, we

5. revised our detailed model of POS 5.

POS 4 and POS 5 both are shutdown states. The plant is The detailed model for POS 5, presented and in the Hot Shutdown mode during POS 4, and it is in the discussed in this report, assumes that auto-isolation of Cold Shutdown mode during POS 5 (except for that part shutdown cooling on high pressure is active when the of POS 5 associated with removing the vessel head, for plant is in cold shutdown. which the plant is in the Refueling mode.) The vessel be:d is on in POS 4, and it is assumed to be on in POS This change means that one engineering reason for

5. The core is cooled with the Shutdown Cooling (SDC) selecting POS 5 over POS 4 is negated; however, we system in both POS 4 and POS 5 and with the Alternate still believe POS 5 to be more of an engineering concern Decay Heat Removal system in pads of POS 5. These than POS 4 for the following reasons:

systems are not designed for high pressure service. If an uncontrolled pressurization transient occurs, failure of (a) The time for which the plant is in POS 5 is low pressure shutdown cooling systems components is greater than the time for which the plant is in possible in these POSs, if the systems / components are POS 4, by about a factor of 12. not isolated. Such a scenario leads to an interfacing systems Loss Of Coolant Accident (LOCA) outside (b) The technical specifications allow for more containment which cannot be mitigated with Emergency equipment to be inoperable in POS 5 during Core Cooling Systems (ECCS), in the long term, since Cold Shutdown, than in POS 4 in Hot the Suppression Pool (SP) inventory will be lost through Shutdown. For example, in Cold Shutdown the break. In POS 4, shutdown cooling is with the the SRVs are not required to be operable, the Residual Heat Removal (RHR) system, which has a suppression pool can be drained, and pressure rating of 220 psig. In POS 5, shutdown cooling containment can be open; none of this is can be provided with either RHR, or with the Auxiliary allowed in Hot Shutdown. Decay Heat Removal (ADHR) system (after 24 hours) which has a pressure rating of 80 psig. The maximum Given both the sequence insights obtained from the expected decay heat in POSs 4 and 5 is almost identical: screening study and the engineering rationale described 1.0% of full power for POS 4 and 0.9% for POS 5. above, POS 5 is the logical choice for the detailed study. When the selection of the POS for detailed analysis was made, in August 1991, we understood that in POS 5 at 3.2 Characterization of POS 5 l Grand Gulf, auto-isolation of SDC on hich r ressure (135 psig) is inactive, while in POS 4 it is active. This POS 5 is rigorously defined as: ' Cold Shutdown (OC und:rstanding was based on information that we received 4), and Refueling (OC 5) only to the point where the during a plant visit in January,1991. vessel head is off *. Once the head is off and vessel isolation oflow pressure shutdown cooling components level is at the main steam lines, the plant is in POS 6. during pressurization transients is less likely if the auto-No fuel is moved during either POS 5 or POS 6, but, as isolation function on high pressure is isolated; this defined in the technical specifications, the plant is in the behsvior was indicated in the screening study which considered this function to be moperable in POS 5. Refueling OC whenever temperature is less than 140*F, I (Isol: tion on low level is active in TOS 5, as well as in ""'h**** POS 4, thus providing for the ability to isolate an

                                                                      ""*        "'I   """E interfacing systems LOCA in the shutdown cooling l

Vol. 2, Part 1 3-3 NUREG/CR-6143 l 1

e Selection and Characterization POS 5 covers plant conditions during Cold Shutdown, (a) Cold Shutdown, not in Hydro (200*F, 0 psig, and during Refueling while the head is being removed. decay heat 0.9% of full power) In performing the detailed analysis of POS 5 as presented in this report, we assumed that the initial condition was (al) Recirculation: Forced, or Natural Cold Shutdown with the vessel head on; in terms of occident delineation, POS 6 adequately models that (a2) Shutdown Cooling: Train B of Residual portion of POS 5 associated with Refueling. Heat Removal (RHR), or Auxiliary Decay Heat Removal System (ADHRS) if plant in contrast to the situation at full power, the plant can be has been shutdown for at least 24 hours ) in POS 5 with a variety of known, pre-existing unavailabilities of equipment. At full power, essentially (a3) Main Steam Isolation Valves (MSIVs): no equipment important for mitigating an accident is closed, or open known to be unavailable, because the technical specifications do not allow the plant to remain at full (a4) Suppression Pool (SP) Inventory: Low ' power with important equipment known to be inoperable Water Level (18 ft 41/12 in),12 ft 8 for extended periods of time. 'Ibe plant can, and does, in, or empty with 170,000 gal available to enter POSs such as po3 5, with known, pre-existing the High Pressure Coolant System unavailabilities. For example, in response to detecting (HPCS) from the Condensate Storage iaoperability of certain equipment while at full power, Tank (CST) the technical specifications reauire transitioning of the plant to POS 5. Appendix A provides more discussion (a5) Containment: closed, open only above related to the issue of known, pre-existing unavailabilities grade, or open below grade of equipment. A major effort for the detailed evaluation of POS 5 was to consider known, pre-existing (a6) Safety Relief Valves (SRVs): two unavailabilities of equipment prior to the occurrence of operable an accident initiating event. . (b) Cold Shutdown, in Hydro (200*F,1000 psig, , decay heat 0.16% of full power) i POS 5 can be entered in coming down from power or in ; going back up to power. In terms of decay heat loads (b1) Recirculation: forced cnd known, pre-existing unavailabilities of equipment, coming down from full power is the worst case for (b2) Shutdown Cooling: RWCU !' analysis, as indicated in Appendix A. Therefore, our initial approach to modeling POS 5 in detail, was t (b3) MSIVs: closed essume that the POS was entered in coming down from full power. However, in a detailed review of the plant (b4) Suppression Pool Inventory: same as for conditions during cold shutdown, we noted that following (,4) , a refueling outage while going up in power, the vessel is : hydro tested in a water solid condition in cold shutdown, l (b5) Containment: same as for (a5). using the Reactor Water Cleanup System (RWCU) in a ; recirculation mode for cooling the core. We included (b6) SRVs: all operable this hydro condition in the detailed model of POS 5. Based on a review of the technical specifications and The plant can be in POS 5 with a variety of conditions procedures for Grand Gulf, augmented with information I that affect the availability of mitigating equipment should from staff at Grand Gulf, we specified the initial ! an accident occur. In the prior screening study, we availability of certain systems and components in POS 5 made conservative assumptions about these conditions, to be fixed as follows: but in this detailed analysis we have modeled various possibilities for those conditions having significant impact (c) Suppression Pool Makeup (SPMU): requires on accident progression. The variety of conditions manual initiation (auto actuation not operable) considered in the detailed analysis for POS 5 are as follows: l l NUREG/CR-6143 3-4 Vol. 2, Part 1 ;

Selection and Characterization (d) Isolation of RHR Shutdown Cooling: auto example, the methodology cannot easily model all the ! isolation on high pressure (135 psig) operable, possible changes in system availabilities during a and auto isolation en low level 3 operable. (In refueling outage as extensive maintenance is performed the screening study [ Whitehead, et al.,1991], on different systems. For POS 5 during a refueling

               't was assumed that in POS 5 auto-isolation            outage at Grand Gulf, the subject of thir report, this is of SDC on high pressure was inactive, based            not a serious limitation, since one train of the ECCS is

(

on infonnation received during the plant visit generally always out for maintenance in cold shutdown, in January,1991. During a subsequent visit and this was the conservative assumption used in our to the site in June,1992, we were informed model. To assess risk during actual refueling operations that auto-isolation of SDC is active in cold involving extensive testing and maintenance, the shutdown, POS 5.) methodology may have to be improved to consider

                                                                      ' rolling

unavailabilities of equipment.

As discussed previously, in POS 5, certain equipment can be known to be inoperable, and impose known, pre- Similarly, the methodology does not easily consider existing unavailabilities of equipment prior to the accideats that occur as the plant transitions ameng modes cccurrence of an accident initiating event. For example, during shutdown. For example, in Hot Shutdown the entry into cold shutdown from full power is required by plant operators switch from cooling with turbine bypass the technical specifications in response to inoperability of to cooling with shutdown cooling at about 100 psig. specified equipment. Known, pre-existing Plant conditions are changing during this transition, and unavailabilities of equipment can also happen due to are different than those present while either on turbine maintenance outages of equipment during cold shutdown bypass cooling or on shutdown cooling. We have as allowed by the technical specifications. In this assumed that accidents occurring dering such transition detailed screening study, we have not evaluated every operations are adequately considered by our models for possible unique combination of known, pre-existing the initial and final states of the transition, for the unavailabilities, because the number of possible cases to following reasons: consider is essentially endless. To conservatively consider the impact of these known, pre-existing

The time spent in transition is less than the time unavailabilities, we made the following assumption: spent in the states transitioned from and transitioned to; thus, accidents due to random (e) Train A of the ECCS systems and the failures are less likely, associated diesel generator are unavailable in POS 5 when an accident initiating event occurs.
For Grand Gulf, and many other plants, this assumption is further supported by the practice to items (a) through (e) as previously described, specify the not disable one functional system (such as core initial conditions considered for POS 5 prior to the cooling with turbine bypass) until the replacement occurrence of an accident initiating event. Section 5 of system (such as shutdown cooling) is shown to be this report discusses the modeling of accident sequences operable.

proceeding from these initial conditions. We believe that the most probable situations for which We did not analyze accident initiating events during the unique initiating events can occur during a transition transitioning of the plant into/out-of POS 5 from/to POS state, are those associated with rod withdrawal during 4 and POS 6, rer.pectively. The methodology used in 1 staitup. Errors in rod movements during such situations j this study is the "small' event tree /large fault tree can challenge the reactor trip system. However, rod technique. In practical applications, this technique movements are blocked in Cold Shutdown and are thus assumes a fixed initial plant state prior to the occurrence unlikely to occur in POS 5 (i.e., Cold Shutdown). of an accident initiating event. Arough the use of seven

   " rules" of analysis (see Appendix A), we were able to consider numerous different conditions that can, and in f ct do, exist at shutdown prior to the occurrence of an accident initiating event.

However, this methodology cannot in eeneral handle time dependent changes in system configurations. For Vol. 2, Part 1 3-5 NUREG/CR-6143

Selection and Conracterization , References for Section 3 [ Whitehead, et al.,1991] D. W. Whitehead, J. L. f [USNRC,1984] USNRC, " Technical Specifications, Grand Gulf Nuclear Station Unit No. Darby, B. D. Staple, B. ! 1,* Docket No. 50416, Appendix "A' Walsh, T. M. Hake, and T. to License No. NPF-29, NUREG-0934, D. Brown, "BWR Imw Power October,1984. and Shutdown Accident , Frequencies Project, Phase 1 - Coarse Screening Analysis," Vol.1 Draft Letter Report, ; Sandia NationalI.aboratories i and Science and Engineering i Associates, Inc., November , 23,1991 update, Copy ' available in the NRC Public Document Room. i i I i l I f I i i i t 3-6 Vol. 2, Part I t NUREG/CR-6143 Y

l l 4 Analysis of Accident Initiating Events 4.1 Approach and Summary internal fires and floodins were also considered; as l discussed in Section 2, Volumes 3 and 4 of this report This section of the report summarizes the identification discusses intemal fires and flooding.) In general, the and quantification of accident initiating events. An term ' Transient

in a PRA refers to any accident initiating accident initiating event is different from a plant event other than a LOCA.

operational state (POS) initiating event. As elaborated upon in Appendix A, a POS initiating event is "an event For this section of the report, we have defined which initiates controlled shutdown of the plant from full ' Transient' as any non.LOCA initiating event, excluding power, a nuisance trip from full power, or an event Decay Heat Removal Challenges and Special Events, which requires the plant to transition up or down among Decay Heat Removal Challenges are initiating events in POS in response to outage requirements or equipment which the operating shutdown cooling system is directly conditions". An accident initiating event is an event lost; Special Events are reactivity excursions. which requires the response of mitigating system (s) to prevent core damage. POS initiating events determine Table 4.1-1 summarizes the initiating events considered the known, pre-existing unavailabilities of systems and in the detailed analysis of POS 5. Point estimates components, if an accident initiating event occurs. (means) for the frequency of each event are tabulated. Both the updated (new) values and the values from the The earlier screening study identified and quantified screening study are listed. Table 4.1-1 also provides tecident initiating events for seven POS [ Whitehead, et acronyms for the events, and these acronyms are used in al.,1991]; the seven POS are discussed in Appendix A. the remainder of this Section of the report. For detailed analysis of POS 5, the subject of this report, we extended the initiating event analysis beyond that used Table 4.1-2 provides updated point estimates for the for the screening study. The extended effort was initiating events for all seven POS. undertaken for basically two reasons. First, as we modeled POS 5 in detail, new initiating events were The values in Tables 4.1-1 and 4.1-2 are frequencies identified. Section 3 summarizes the more detailed (i.e., they are failure rates). In the quantification of modeling of plant conditions in POS 5 beyond that in the accident sequences, these rates are multiplied by the screening study, and this led to the identification of new fraction of time that the plant is in the POS for which the initiating events. For example, modeling of the Hydro initiating event applies. For example, in quantifying condition in cold shutdown led to the consideration of event E, for POS 5, the frequency 0.057, is multiplied Loss of Coolant Accidents (LOCAs) at full system by the fraction of time that the plant is in POS 5. These pressure; and the modeling of the possibility that forced fractions are given in Section 11 of this report. recirculation is initially available in POS 5 led to the consideration ofloss of forced recirculation as an 4.2 Transient Initiating Events initiating event. Second, the trend identified in the screening study indicated that certain initiating events, Two classes of transient initiating events were evaluated: such as loss ofinstrument air, should be quantified more those common to any BWR, and those based on the accurately, specific support system characteristics of Grand Gulf. Altnough this report addresses POS 5, whenever an 4.2.1 Transients Common to All BWRs initiiting event was updated, the update was performed for cil seven POS. This Section of the report discusses T: Loss of Offsite Power (LOSP) Transient those initiating events that were updated, and provides data for all initiating events for all POS, including those This event was not updated. Frequencies are based on not updated fmm the screening study. Appendix D of the information provided in Appendix G. this report provides the initiating event analysis from the earlier screening study, as this analysis was the basis for T,: Transient with Loss of the Power Contersion the update. Systmi Accident initiating events were classified into four This event is not applicable to POS 5, but the values for groups: Transients, LOCAs, Decay Heat Removal the applicable POS were updated from the screening Challenges, and Special Events. (Hazard Events, namely study. Vol. 2, Part 1 4-1 NUREG/CR-6143

Initiating Event i Table 4.1.1 Initiating Events for POS 5 Initiating Description Segwening New Mean Reference Event Analysis Frequency Nomenclature Mean per Year for l i Frequency POS5 per Year for POS 5 0.13 0.13 Semening Analysis T, loss of Offsite Power (LOSP) Transient NA NA Screening Analysis T* Transient with loss of the Power Conversion System (PCS) Transient with PCS initially available NA NA Screening Analysis T, Transients involving loss of Feedwater NA NA Screening Analysis T, Transient caused by inadvertent Open Relief NA NA Screening Analysis T* Valve , 1.0E-05 3.62E45 NUREG/CR4407 l A Large LOCA at Low Pressure Large LOCA during Hydro Test (High Pressure) - 1.25E44 NUREG/CR-4407 l A. m S~ Intermediate LOCA at low Pnssure 3.0E45 3.62E 05 NUREG/CR4407 i Intermediate LOCA during Hydro Test - 1.25E44 NUREG/CR4407 S, l (High Pressure) 5 Small LOCA at Low Pressure 3.0E-04 3.62E 05 NUREG/CR4407 Small IDCA during Hydro Test (High Pressure) - 1.25E-04 NUREGICR4407 5 Snull-small LOCA at Low Pressure 3.0E-03 3.62E 05 NUREG/CR4407 5 Small-smallIDCA during Hydro Test - 1.25E 04 NUREGICR4407 (High Pressure) Interfacing LOCA NA NA Screening Analysis V Vesact Rupture NA NA Screening Analysis R H, Diversion to Suppression Pool via RHR 8.0E 02 6.lE42 NSAC-88.157 NA NA Screening Analysis l H- Diversion to Condenser via RWCU t LOCA in connected system (RCIC) NA NA Screening Analysis J, LOCA in connected systent (RHR) 5.0E 02 1.56E-02 NSAC-88,157 J, K Test / Maintenance induced LOCA

                                                                                   -    HRA to handle                                           J i

0.1 5.7E 02 NSAC-88,157 j E,,, Isolation of SDC loop B only

                      ! solation of RWCU as DHR                                  NA        1.57E-03           Assumed E,Value E_

Em Isolation of ADHRS only 0.1 5.7E-02 Assume E,, Value E Isolation of SDC common suction line 0.1 0.356 NS AC-88.157 Isolation of common suction line for ADHRS 0.1 0.356 Assume E,,Value j E,, Loss of operating R11R shutdown system 0.37 6.5E 02 NSAC-88.157 E. 4-2 Vol. 2, Part 1 NUREGICR-6143

1 l Initiating Events Table 4.1.1 Initiating Events for POS 5 (Continued) Initiating Description Screening New Mean Reference ! Event Analysis Frequency Nomenclature Mean pes Year for Frequency POS5 per Year for IVS 5 t E,, loss of RWCU as DHR NA 1.57E-03 Fault Tree Analysis E, loss of ADHRS only 0.37 6.5 E-02 Assume E, Value E, loss of SDC common suction line 0.37 3.8E42 NSAC-88.157 ; E,, loss of common suction line for ADHRS 0.37 3.8E-02 Assume E, T, , Rod withdrawal error NA NA Screening Analysis { T,, Refueling accident (rod or fuel ndsposition) NA NA Screening Analysis T, Instability Event NA NA Screening Analysis i T, loss of all Standby Servics Water (SSW) 1.8E-02 2.4E-02 NUREG/CR-1275 Vol. 3 i T, loss of all Turbine Building Cooling Water 1.8E42 2.4E-02 NURF3/CR-1275 Vol. 3 T* Loss of all Plant Service Water (includes Radial 1.8E42 2.4E-02 NUREG/CR 1275 Vol. 3 Wel!)

T, loss of all Component Cooling Water 1.8E-02 2.4E-02 NUREG/CR-1275 Vol. 3 s T,, Loss of IE 4160 V AC Bus B 9.0E-04 1.66E-03 IEEE-500 T, loss of 1E 125 V DC Bus B 6E 03 6E4)3 NUREG4666, NUREG/CR4550, Vol. I l Rev.1 ,

T,, loss ofInstrument Air 0.5 0.18 NUREG/CR-5472 l T_, Inadvertent Open Relief Valve at Shutdown NA 7.2E-02 NUREG/CR 3862 T, Inadvertent overpressurization (makeup greater 0.16 1.57E-03 Assumed E,, Value than letdown) T, Inadvertent Pressurization via spurious HPCS 1.0E-02 1.4E 02 NUREG/CR-3862 , actuation T_ Inadverten. Overfill via LPCS or LPCI 4.0E-02 2.2E-02 NS AC-88,157 l T_ loss of Recirculation Pump - 7.2E42 NUREG/CR-3862

i T,, loss of Makeup 0.49' 8E-03 FaultTree Analysis Dis value was taken from NUREG/CR-3862, EPRI Category 20 - Feedwater - Increasing Flow at Power. Note that for POS 5 inadvenent overpressurization is essentially loss of RWCU.

L

This value was taken from NUREG/CR-3862 EPRI Category 24 - Feedwater low Flow. Note that for POS 5, loss of makeup is sasentie!!y loss of CRD. '

L i Vol. 2, Part 1 4-3 NUREG/CR-6143 i

Initiating Event Table 4.1.2 Updated Initiating Events for all 10Ss Initiator POS1 POS2 POS3 POS4 POS5 POS6 POS7 0.07 0.13 0.13 0.13 0.13 0.13 0.13 T, T, 1.63 0.437 0.437 NA NA NA NA T,, 4.54 1.00 1.00 NA NA NA NA T,, 1.06 0.25 0.25 NA NA NA NA T,,, 0.16 7.2E-02 7.2E-02 NA NA NA NA A 1.39E-04 1.39E-04 1.39E-04 1.39E 04 3.62E-05 3.62E-05 3.62E-05 A, NA NA NA NA 1.25E-04 NA NA 1.39E-04 1.39E-04 1.39E-04 1.39E-04 3.62E-05 3.62E-05 3.62E-05 S, S ,,, NA NA NA NA 1.25E-04 NA NA 1.39E-04 1.39E-04 1.39E44 1.39E-04 3.62E-05 3.62E45 3.62E-05 S, NA NA NA NA 1.25E-04 NA NA S,,, 1.39E 04 1.39E-04 1.39E-04 1.39E-04 3.62E-05 3.62E-05 3.62E-05 S, S,,, NA NA NA NA 1.25E-04 NA NA V NA NA NA NA NA NA NA R NA NA NA NA NA NA NA H, NA NA NA 6.1E-02 6.1E-02 6.1E-02 6.1E-02 NA NA NA NA NA NA NA H. J, ? ? ? NA NA NA NA NA NA NA 1.56E-02 1.56E-02 1.56E-02 1.56E-02 J. K - - - - - - NA NA NA 5.7E-02 5.7E-02 5.7E-02 5.7E-02 E , ,, E , ,, NA NA NA NA 1.57E-03 NA ? ( NA NA NA NA 5.7E-02 5.7E-02 5.7E-02 E,, NA NA NA 0.356 0.356 0.356 0.356 E,, NA NA NA NA 0.356 0.356 0.356 E,s. E., NA NA NA 6.5E-02 6.5E-02 6.5E-02 6.5E-02 E. NA NA NA NA 1.57E-03 NA ? NA NA NA NA 6.5E-02 6.5E-02 6.5E-02 E,n E, NA NA NA 3.SE-02 3.8E-02 3.8E-02 3.8E-02 4-4 Vol. 2, Part 1 NUREGICR-6143

l Initiating Event Table 4.1.2 Updated Initiating Events for all POSs (Continued) Initiator POS1 POS2 POS3 POS4 POSS POS6 POS7 E, NA NA NA NA 3.8E-02 3. 8E-02 3.8E-02 T,, NA NA NA NA NA NA NA T,, NA NA NA NA NA NA NA T, NA NA NA NA NA NA NA T,, NA NA NA 2.4E-02 2.4E-02 2.4E-02 2.4E-02 T,, 2.4E-02 2.4E-02 2.4E 02 2.4E-02 2.4E-02 2.4E-02 2.4E-02 T, 2.4E-02 2.4E-02 2.4E-02 2.4E-02 2.4E-02 2.4 E-02 2.4E-02 7 T,n NA NA NA 2.4E-02 2.4E-02 2.4E-02 2.4E-02 T, NA NA NA 1.66E-03 1.66E-03 1.66E-03 1.66E-03 T,n NA NA NA 6E-03 6E-03 6E-03 6E-03 T,, 0.18 0.18 0.18 0.18 0.18 0.18 0.18 T,,, y NA NA NA 7.2E-02 7.2E42 NA NA T,n NA NA NA 1.57E-03 1.57E-03 NA NA T,,,, NA NA NA 1.4E-02 1.4E-02 NA NA T,m NA NA NA 2.2E 02 2.2E-02 NA NA i T, y NA NA NA 7.2E-02 7.2E-02 NA NA T, y NA NA NA 8E43 8E43 NA NA 1 Vol. 2, Part 1 4-5 NUREG/CR-6143

laitiating Event The frequency for this event was obtained from category is composed of 18 EPRI transient categories -see NUREG/CR-3862, " Development of Transient Initiating Table 4.3-3 of Grand Gulf NUREG/CR-4550, Vol. 6, l Event Frequencies for Use in Probabilistic Risk Rev.1, Part 1 for all but category 26 [Drouin, 2 al., l Assessments * [Mackowiak, et al.,1985]. This document 1989] These EPRI transient categories are: 1, 3, 14-was extended and updated the previous work done by the 21,26,27,29,30, and 33-36. The EPRI category 26 Electric Power Research Institute (EPRI). *lligh Feedwater Flow During Startup or Shutdown

has be n added to those listed in the Grand Gulf The T2 initiating event category is composed of 11 EPRI NUREG/CR-4550 report. From the INEL report, the transient categories (see Table 4.3-3 of Grand Gulf sunt of these EPRI categories gives 1140 events in 251.28 NUREG/CR-4550, Vol. 6 Rev.1, Part 1 [Drouin, et years of BWR operating experience. The INEL report ,

al.,1989]). These EPRI transient categories are: 2,4- also lists a subset of these events as occurring during low 10,12,13, and 37. From the INEL report, the sum of powt r (see Table 21 in the INEL report). The total of these EPRI catego,ies gives 409 events in 251.28 years low power events is 252. of BWR operating experience. The INEL report also lists a subset of these events as occurring during low Low power events as defined in the INEL repoit and the power (see Table 21 in the INEL report). The total of previous EPRI work are events that occur at 25 % power low power events is 92 in 251.28 years, or less. This category of events is much broader than those encompassed by POSs 2 and 3, but this category of Low power events as defined in the INEL report and the events p*ovides a better estimate of the initiating event previous EPRI work are events that occur at 25 % power frequency than does the overall initiating event frequency or less. This catercry of ever ts is much broader than estimate. Therefore, for POSs 2 and 3, the initiating those encompassed 9y POSs 2 and 3, but this category of event frequency estimate is 1.00. To be conservative, all events provides a betar estimati of the initiating event 1140 events were used to estimate the initiating event frequency than does tho cierall initiating event frequency frequency for POS 1. Thus, for POS 1 the initiating estimate. event frequency estimate is 4.54 events per reactor year. The mean for POSs 2 and 3 was found by using a T,: Transients Involting Loss of Feedwater binomial distribution computer to determine the median (0.35), the 5 % confidence value (0.30), and the 95 % This event is not applicable to POS 5, but the values for confidence value (0.41). The error factor is the applicable POS were updated from the screening approximately 1.2. Increasing the error factor to 3 and study. assuming a lognormal distribution about the median, the mean number of events is 0.437 per site per year. The frequency for this event was obtained from NUREG/CR-3862, " Development of Transient Initiating To be conservative, all 409 events were used to estimate Event Frequencies for Use in Probabilistic Risk the initiating event frequency for POS 1. Using the Assessments" (Mackowiak, et al.,1985]. This document analysis previously done for Grand Gulf (See Table 4.9- was generated by INEL, and extended and updated the 26 of [Drouin, et al.,1989], the initiating event previous work done by EPRI. TU 'l, initiating event frequency estimate is 1.63 events per reactor year with category is composed of 4 EPPl tmnsient categories -see an error factor of 3. Table 4.3-3 of Grand Gulf NURFG/CR-4550, Vol. 6, Rev.1, Part I for all but category 25 [Drouin, et al., T,: Transient with PCS Initially Available 1989]. These EPRI transient categories are: 22-25. The EPRI category 25 ' low Feedwater Flow During Startup This event is not applicable to POS 5, but the values for or Shutdown

has been added to those listed in the Grand the applicable POS were updated from the screening Gulf NUREG/CR-4550 report. From the INEL report, study. the sum of these EPRI categories gives 213 events in 251.28 years of BWR operating experience. The INEL The frequency for this event was obtained from report also lists a subset of these events as occurring NUREG/CR-3862,
Development of Transient initiating during low power (see Table 21 in the INEL report).

Event Frequencies for Use in Probabilistic Risk The total oflow power events is 51. Assessments" [Mackowiak, et al.,1985]. This document ' was generated by INEL, and extended and updated the low power events as defined in the INEL report and the previous work done by EPRL The T3A initiating event previous EPRI work are events that occur at 25 % power NUREG/CR-6143 4-6 Vol. 2 Part 1

Initiating Events or less. His category of events is much broader than To be conservative, all 33 events were used to estimate those encompassed by POSs 2 and 3, but this category of the initiating event frequency for POS 1. The mean was events provides a better estimate of the initiating event found by using a binomial distribution computer to frequency than does the overall initiating event frequency determine the median (0.13), the 5 % confidence value ; estimate. The mean for POSs 2 and 3 was found by (0.098), and the 95 % confidence value (0.169). The using a binomial distribution computer to determine the error factor is approximately 1.3. Increasing the error median (0.20), the 5 % confidence value (0.16), and the factor to 3 and assuming a lognormal distribution about 95 % confidence value (0.25). The error factor is the median, the mean number of events is 0.16 per site approximately 1.25. Increasing the error factor to "I and per year. essuming a lognormal distribution about the median, the mean number of events is 0.25 per site per year. 4.2.2 Transients based on Grand Gulf i To be conservative, all 213 events were used to estimate , the initiating event frequency for POS 1. He mean was T: 54 Loss of all Standby Service Water (SSW) found by using a binomial distribution computer to determine the median (0.85), the 5 % confidence value The initiating event frequency for loss of all standby (0.77), and the 95% confidence salue (0.94). He error service water was obtained from NUREG/CR-1275 Vol. factor is approximately 1.1. Increasing the error factor 3, . Operating Experience Feedback Report - Service to 3 and assuming a iognormal distribution about the Water System Failures and Degradations - Commercial median, the mean number of events is 1.06 per site per Power Reactors" [ Lam and Ieeds,1988]. This report year. reviewed and evaluated service water system failures and degradations in light water reactors from 1980 through T ,: Transient Caused by inadvertent Open Relief 1987. Yalve Over the review period of 1980 through 1987, this report The frequency for this event was taken from recorded a total of 12 events where there was a total loss NUREG/CR-3862, ' Development of Transient Initiating of service water system function. This report estimates Event Frequencies for Use in Probabilistic Risk that approximately 650 years of reactor operating Assessments" [Mackowiak, et al.,1985]. This document experience were accumu'ated during the 1980-1987 time was generated by INEL, and extended and updated the period. The mean was found by using a binomial previous work done by EPRI. The EPRI category 11 distribution computer to determme the median (0.0194),

" Inadvertent Opening of a Safety / Relief Valve (stuck)*

the 5 % confidence value (0.012), and the 95 % confidence was used as the basis of this initiating event frequency. value (0.0285). The error factor is approximately 1.5. The INEL report documented 33 total events in 251.28 Increasing the error factor to 3 and assuming a lognormal years of BWR operating experience, and they also listed distiibution about the median, the mean number of events 14 of these events as occurring during low power (Table is 0.024 per site per year. 21 in the 1NEL report). I.aw power events as defined in the INEL report and the

previous EPRI work are events that occur at 25 % power ne in tiating event frequency for loss of all standby or less. His category of events is much broader than service water was obtained from NUREG/CR-1275 Vol.

those encompassed by POSs 2 and 3, but this category of 3, . Operating Experience Feedback Report - Service events provides a better estimate of the uutiating event Water System Failures and Degradations - Commercial frequency than does the overall initiating event frequency Power Reactors * [ Lam and Leeds,1988]. His report estimate. The mean for POSs 2 and 3 was found by ' reviewed and evaluated service water system failures and using a binomial distribution computer to determine the degradations in light water reactors from 1980 through median (0.058), the 5 % confidence value (0.038), and ggg7, the 95 % confidence value (0.085). He error factor is cpproximately 1.5. Increasing the error factor to 3 and The service water system failures are used here as a assuming a lognormal distribution about the median, the reasonable estimate for turbine building cooling water mean number of events is 0.072 per site per year. system failures. Herefore, as was calculated for the loss of service water initiator frequency, the loss of turbine i Vol. 2, Part 1 4-7 NUREG/CR-6143 l

Initiating Event building cooling water frequency is based on 12 events in determine the median (0.0194), the 5 % confidence value 650 years of operating reactor experience. The mean (0.012), and the 95 % confidence value (0.0285). He was found by using a binomial distribution computer to error factor is approximately 1.5. Increasing the error , factor to 3 and assuming a lognormal distribution about ! determine the median (0.0194), the 5 % confidence value (0.012), and the 95 % confidence value (0.0285). The the median, the mean number of events is 0.024 per site l error factor is approximately 1.5. Increasing the error per year. ! factor to 3 and assuming a lognormal distribution about the median, the mean number of events is 0.024 per site T,: less of IE 4160 V AC Bus B l l per year. The initiating event frequency for loss of IE 4160 V AC l Bus B was estimated using IEEE-500 (*IEEE Guide to T,: Loss of all Plant Service Water (includes the Collection and Presentation of Electrical. Electronic, Radial Well) Sensing Component, and Mechanical Equipment The initiating event frequency for loss of all standby Reliability Data for Nuclear Power Generating Stations" service water was obtained from NUREGICR 1275 Vol. [ ANSI /IEEE,1984]. IEEE-500 tabulates for 601-15kV 3, " Operating Experien:e Feedback Report - Service switchgear bus failures, a frequency of 1.9E-07 per hour Water System Failures and Degradations - Commercial which is equivalent to 1.66E-03 per year. Power Reacton" [ Lam and leeds,1988). This report ' reviewed and evaluated service water system failures and We screened out loss of non 1E buses as initiating events, degradations in light water reactors from 1980 through as described in Appendix J, section 3 of this report. 1987. The service water system failures are used here as a reasonable estimate for plant service water system The frequency for the loss of a DC bus was estimated failures. Therefore, as was calculated for the loss of using NUREG-0666, "A Probabilistic Safety Analysis of service water initiator frequency, the loss of plant service DC Power Supply Requirements for Nuclear Power water frequency is based on 12 events in 650 years of Plants [Bvanowski, et al.,1981). This report states that operating reactor experience. He mean was found by bus failures generally fall into two categories. They are: using a binomial distribution computer to determine the median (0.0194), the 5 % confidence value (0.012), and . failure to provide DC power on demand as the 95 % confidence value (0.0285). He error factor is characterized by the loss of charger output, and cpproximately 1.5. Increasing the error factor to 3 and assuming a lognormal distribution about the median, the e operational, test, or maintenance ars resulting mean number of events is 0.024 per site per year. in the loss of DC power during normal plant E '* T,: Loss of all Component Cooling Water Re principal cause of failure for the first category The initiating event frequency for loss of all standby involved operation of the DC power system with one or service, water was obtained from NUREG/CR-1275 Vol. more batteries unable to provide sufficient power to the ' 3, " Operating Experience Feedback Report - Service bus if battery charger output is lost. Battery Water System Failures and Degradations - Commercial unavailability in this circumstance was found to be : Power Reactors * [ Lam and Leeds,1988). His report dominated by inadequate maintenance practices and reviewed and evaluated service water system failures and failure to detect battery unavailability due to bus , degradations in light water reactors from 1980 through connection faults. The point estimate for the 1987. unavailability of batteries was determined to be

                                                                  *IE     ** #'

The service water system failures are used here as a ; reasonable estimate for compc.nent cooling water system It was determined in the report that charger output loss is failures. Herefore, as was calculated for the loss of most likely to follow the momentary loss of the 480 V service water initiator frequency, the loss of component AC power supply to the chargers when the offsite cooling water frequency is based on 12 events in 650 (preferred) power supply is lost. The report (NUREG- i years of operating reactor experience. The mean was 0666) estimated the frequency of loss of offsite power to i found by using a bmonaal distnbution computer to NUREG/CR-6143 48 Vol. 2, Part 1 !

Initiating Events be 0.22 occurrences per year. Thus, it was estimated M Anomaly Caused Outside the System - These trips were that the failure probability for this first category of DC caused by problems in electrical systems not dedicated to power supply failure is 2E-04 per reactor year. Our instrument air. estimate for loss of offsite power for the shutdown study is 0.13 occurrences per year, but this difference is not The initiating event frequency for this shutdown study significant in this particular calculation since the failure was determined by summmg the first two categories (i.e., probability for the second category of DC power supply total and partial loss ofIA). The report found that for failure is much larger. the period 1984-1987 inclusive (approximately 68 years of BWR operating experience), there were three total The second category of DC power supply failure losses ofIA for BWRs, and six partial losses ofIA for included operational, test, and maintenance errors BWRs. Thus, nine failures in 68 years was used to propagating to system failure. In most cases this failure determine the initiating event frequency. He mean was category involved procedural mistakes during periods found by using a binomial distribution computer to , when the tie breaker would be closed and divisional determine the median (0.145), the 5 % confidence value independence compromised. The est'. nates of the (0.085), and the 95 % confidence value (0.21). The error probability per reactor year of single division failure due factor is approximately 1.5. Increasing the error factor to this second category of events is 6E-03, to 3 and assuming a lognormal distribution about the median, the mean number of events is 0.18 per site per The NUREG/CR-4550 Methodology report used the year. NUREG-0666 mean value of 6E-03 and a lognormal distribution with an error factor of 3. This will also be T,,y: Inadvertent Open Relief Valve (IORV) at used for this low power and shutdown study. Shutdown We screened out loss of non-1E buses as initiating His event only applies to POS 4, or POS 5 during events, as described in Appendix J, section 3 of this Hydro conditions; T, encompasses IORV events for report. POSs 1-3. He frequency for this event was taken from NUREG/CR-3862, ' Development of Transient Initiating T ,: Loss ofInstrument Air Event Frequencies for Use in Probabilistic Risk Assessments" [Mackowiak , et al.,1985). This The initiating event frequency for T was taken from document was generated by INEL, and extended and NUREG/CR-5472, "A Risk-Based R$ view ofInstrument updated the previous work done by EPRI. The EPRI Air Systems at Nuclear Power Plants", published on category 11

Inadvertent Opening of a Safety / Relief January 1990 [DeMoss, et al.,1990]. In this report, Valve (stuck)* was used as the basis of this initiating four categories were used to analyze the trips. The event frequency.

degree of IA failures defined by these four categories are es follows: The INEL report documented 33 total events in 251.28 , years of BWR operating experience, and they also listed TotalLoss of M - The instrument air system is not 14 of these events as occurring during low power (Table available for safe shutdown of the plant. The air 21 in the INEL report). Iow power events as defined in pressure has severely degraded so hat it is unable to the INEL report and the previous EPRI work are events operate any components. that occur at 25 % power or less. This category of events is much broader than those encompassed by POS 4, but Partialless ofM - He system is partially degraded or this category of events provides a better estimate of the contaminated. Although air pressure is still available, initiating event frequency than does the overall initiating some components served by instrument air will not work event frequency estimate. The mean was found by using as designed, a binomial distribution computer to determine the median (0.0575), the 5 % confidence value (0.0375), and the 95 % General Success ofM - Problems with the instrument air confidence value (0.085). The error factor is have been all or part of the cause of the event, but the approximately 1.5. Increasing the error factor to 3 and system is generally available to operate the components assuming a lognormal distribution about the median, the that it serves. mean number of events is 0.072 per site per year. Vol. 2. Part 1 4-9 NUREG/CR-6143 i

Initiating Event T,: Inadvertent Overpressurization (Makeup NSAC-157 tabulates RHR events that have occurred from Greater Than Letdown) 1984 through 1989 [ Booth,1991]. This is approximately 207 years of BWR operating experience. Four events For POS 5, the T, initiator is essentially loss of were identified in this report that involve inadvertent Reactor Water Cleanup (RWCU) (operating as letdown) overfill of the reactor vessel via LPCS or LPCL In one and failure of the operator to stop Control Rod Drive event, which occurred during startup (OC2), high water (CRD) (operating as makeup) or control pressure. As a level was caused by the outboard LPCI injection valve conservative estimate, the E loss of RWCU) initiating which was not fully seated. One es ent occurred during event frequency will be usedio(r this initiator. OC4 in which LPCI injected 6000 gallons of water into I the reactor vessel due to an error by a test engineer who T,: Inadvertent Pressurization via Spurious HPCS installed a jumper on the wrong terminal block and Actuation energized the LPCI circuitry. He remaining events occuned during OC5. In one event 15,000 gallons was De frequency for this event was taken from injected, and the other event did not report the amount NUREG/CR-3862,

Development of Transient Initiating injected. Four events in 207 years of DWR operating Event Frequencies for Use in Probabilistic Risk experience equates to 0.0193 events per site year.

Assessments * [Mackowiak, et al.,1985]. This document was generated by INEL, and extended and updated the Combining the information obtained from NSAC-88 and previous work done by EPRI. The EPRI category 33 NSAC-157 gives six events in approximately 375 years of

" Inadvertent Startup of HPCI/HPCS* was used as the            BWR operating experience. The mean was found by basis of this initiating event frequency. The INEL report      using a binomial distribution computer to detennine the documented 2 events in 251.28 years of BWR operating           median (0.0178), the 5 % confidence value (0.009), and experience. The mean was found by using a binomial             the 95 % confidence value (0.0321). The error factor is distribution computer to determine the median (0.0113),         approximately 1.8. Increasing the error factor to 3 and the 5% confidence value (0.0034), and the 95 %                  assuming a lognormal distribution about the median, the confidence value (0.026). The error factor is                   mean number of events is 0.022 per site per year, approximately 2.3. Increasing the error factor to 3 and essuming a lognormal distribution about the median, the         Tm: Loss of Recirculation Pump mean number of events is 0.014 per site per year.                                                                                .

The frequency for this event was taken from T,: Inadvertent Overfill via LPCS or LPCI NUREG/CR-3862, " Development of Transient Initiating Event Frequencies for Use in Probabilistic Risk ; NSAC-88 tabulates Residual Heat Removal (RHR) events Assessments * [Mackowiak, et al.,1985]. This document that have occurred from 1977 through 1983 [ Vine, et al., was generated by INEL, and extended and updated the 1986]. This is approximately 168 years of BWR previous work done by EPRI. The EPRI category 16 operating experience. Two events were identified in this " Trip of One Recirculation Pump

was used as the basis report that involve inadvertent overfill of the reactor of this initiating event frequency since only one recire, vessel via I.ow Pressure Core Spray (LPCS) or Low pump would be needed during shutdown. The INEL Pressure Coolant injection (LPCI). In one event, which report documented 14 events in 251.28 years of BWR occurred at Browns Ferry 2,44,000 gallons of torus operating experience. The mean was found by using a water was injected into the reactor vessel via the core binomial distribution computer to determine the median spray system. This put some water into the steam lines (0.0575), the 5 % confidence value (0.0375), and the 95 %

and spilled water into the drywell sumps via an open confidence value (0.085). The error factor is head vent. He vessel head was in place with the head approximately 1.5. Increasing the error factor to 3 and fastening nuts not installed (OCS). De other event assuming a lognormal distribution about the median, the occurred at Peach Bottom 3. Inadvertent actuation of mean number of events is 0.072 per site per year. LPCI caused injection of 65,000 gallons of torus water into the reactor vessel. Since the unit was in refueling T ,: Loss of Makeup with the reactor cavity flooded (OC5), most of the water flowed onto the fuel building floor and down a hatchway. Per POS 5, the T, initiator is loss of the Control Rod Two events in 168 years of BWR operating experience Drive (CRD) system. Since information could not be ; equals 0.0119 events per site year. found pertaining to the failure frequency of the CRD system, a fault tree analysis of the CRD system was done ; NUREG/CR-6143 4-10 Vol. 2, Part I

Initiating Events to provide an estimate for the initiating event frequency. By the cutoff date of the INEL study (December 1984), The CRD fault tree was quantified with the support there were 800 (484.73 PWR and 313.36 BWR) reactor systems removed, thus leaving only the CRD system years of commercial operating experience. The INEL hardware failures. The result is 8.0E-3. study developed pipe break failure rates for two piping system categories: LOCA-sensitive and non-LOCA-4.3 LOCA Initiating Events sensitive Pi ping. For this study, LOCA-sensitive piping was defined as piping in which a break would result in We used the full power PRA categorization for LOCA 1 ss f reactor coolant. For LOCA-sensitive systems, sizes [Drouin, et al.,1989]. In POS 5, the initial failure (as defined in the INEL study) is a leak rate of at condition of the plant is cold shutdon, and steamline least 500 gpm for BWRs. The authors of the INEL study break LOCAs are not of concern; therefore, the reason that leakage rates below this rate can be made up NUREG-4550 break size categorization for water line by the normal makeup system to replenish reactor coolant breaks was used, and this categorization, in terms of (RCIC) and, therefore does not require the initiation of equivalent break diameter, is as follows: emergency core cooling. The INEL study found only 19 pipe failures (9 in PWRs LOCA Size (Eauivalent Break Diameter) and 10 in BWRs), with no failures occurring in LOCA-sensitive systems with a leak rate 2 50 rpm. Based on A > 0.4 sq. ft. zero LOCA-sensitive system failures in 313.36 BWR years of commercial operating experience, the INEL S, Between 0.007 and 0.4 sq. ft. study gave a point estimate for a 500 TPm or greater leak of 7E-04 with a lower bound of zero and an upper bound S,

                              < 0.007 sq. ft.                    of 9.6E-03. Because there were no failures in LOCA-sensitive systems, this rate estimate depends only on the S,                            Recirculation Pump Seal             accumulated operating years experienced, and is therefore Failure; like S,,* but can be       the same for any range ofleak rates > 50 gpm. De isolated                            data does not permit more detailed assessments. The combined PWR/BWR experience of no LOCA-sensitive pipe failures in 800 reactor years results in a point value An attempt was made by INEL to update and expand the              of 3.0E-04 with an upper bound of 4.0E-03 and a lower study on pipe break failure frequencies reported in               bound of zero.

WASH-1400 [USNRC,1975]. His work is documented in NUREG/CR-4407, ' Pipe Break Frequency Estimation One important difference between the INEL study and the for Nuclear Power Plants * [ Wright, et al.,1987]. At the WASH-1400 study is that for the leak rate categories time of the WASH-1400 study, there were only 150 established in the INEL study for LOCA-sensitive piping, reactor years of commercial operating experience and no the failure rates are the same whereas in WASH-1400 failures in LOCA sensitive systems. Since there was they stay the same. The failure rates for the various pipe relatively little commercial experience at that time and no size categories shown in WASH-1400 are different. The failures, WASH-1400 also included non-nuclear utility reason for the difference is that the WASH-1400 study experience in their analysis. The pipe break failure used data from non-nuclear sources and the INEL study frequencies reponed in WASH-1400 are the following: did not. Among the data from LOCA-sensitive systems for U. S. commercial nuclear power plants, there is no LOCA-Initiatine Runture Rates (per plant per year) evidence that the rates differ by pipe size or by leak rate categories. Pipe Rupture Range Because there were few pipe break failure events (and Sire (in.) (00 5 ) Median none in LOCA-sensitive systems), INEL attempted to combme this operating experience data with failure 1\2 to 2 IE-04 -+ 1E-02 IE-03 frequencies obtained through expert opinion (subjective). 2 to 6 Bayesian statistical methods were used to integrate the 3E45 - 3E-03 3E-04 two sources to derive failure frequencies. Because the >6 lE-05

IE-03 IE44 subjective data introduced a very large level of uncertainty, the resulting values cannot be used in a Vol. 2, Part 1 4-11 NUREG/CR-6143 l

i l l l Initiating Event ! PRA. For example, the estimated pipe break failure rate

Shutdown - The plant is off-line, control rods are !

in a LOCA-sensitive system in a BWR during shutdown inserted, and the primary coolant system is cooled is 1.13E 10 with an upper limit of 1.2E-01 (nine orders down and depressurized, of magnitude!).

Transiems - Plant conditions that result in a ne BWR low power and shutdown screening analysis reactor trip. These events cause both secondary used the LOCA categories and failure rates given in systems and the primary system to undergo WASH-1400, but also applied an estimate of the moderate (within design conditions) temperature

' effects" from the analysis of the combined commercial                    and pressure transients.

and expen opinion data from the INEL study as a multiplier to the shutdown POSs (POS 5-7). These The point estiaates for these five operational states are

" effects

values can be interpreted as multipliers that for BWR non-LOCA-sensitive systems (since there were indicate how the rates of pipe ruptures or leaks vary no LOCA-sensitive system failures). These values are among the levels of conditional factors (such as operating the following:

condition). These multipliers are simply the exponential of the difference of the naturallogs of the failure rate of the particular condition and the overall failure rate. Operational Numerator Denominator Point Since the pipe break frequency values determined from Mode (N failures) (T years)* Estimate the combined commercial operving experience data and 9.40 0.0242 Starting up 0 expert opinion data could not be used (due to the very large associated uncertainties), it would also seem Normal 8 195.22 0.0410 inappropriate to apply these multipliers to the WASH- . Shuttmg Down 0 3.13 0.0727 1400 frequencies. To apply a somewhat meaningful weighting factor to the LOCA frequency for the different Shutdown 2 105.61 0.0189 POSs, we must use the commercial operating experience Transient 0 1970 0.0001 data only. The INEL study provided point estimates for each of five operational modes using the commercial operating experience data only. These five operational modes are ' defined as the following:

For the transient operational mode, the denominator is the number of transients over all operating years.
Starring Up - The starting up mode for the INEL study encompassed two areas: 1) start up of the nuclear plant from shutdown /coc,ldown conditions, To determine weighting factors from this information, we and 2) maintaining the plant for brief periods in a can normalize the point estimates. Thus, we obtain the shutdown condition in which the plant is not following multipliers for each operational state:

cooled down and depressurized, and starting up the plant from this condition. e Start up - 0.1542

Normal - 0.2613
Normal Operation - The plant is on-line and the e Shutting Down - 0.4634 primary coolant system is at normal operating e Shutdown - 0.1205 pressure, temperature, and flow. The emergency 0.0006 e Transient -

systems are on standby and will operate on demand. A, S,, S,, S, LOCAs:

Shurring Down - The plant is off-line, the reactor Em M b weighting factors are derived from is shut down, the primary coolant system is being non-LOCA-sensitive system data, the values seem to cooled down and depressunzed, and most support provide reasonable adjustments to the overall LOCA systems are shutdown. The main feedwater frequency for LOCA-sensitive systems in the different system cools the primary system to the point were operational modes. For the BWR low power and RIIR can complete the cooldown.

4-12 Vol. 2, Part 1 NUREGICR-6143

i 1 I l 1 Initiating Events ! shutdown study, the ' shutting down" and ' shutdown

NSAC-88 tabulates RHR events that have occurred from l operating modes defined above encompass the seven 1977 through 1983 [ Vine, et al.,1986]. This is POSs defined in the low power and shutdown study. approximately 168 years of BWR operating experience.

The " shutting down" mode encompasses POSs 1 through Seven events were identified in this report that involve 4, and ' shutdown

mode encompasses POSs 5 through 7. diversion of vessel inventory to the suppression pool via Multiplying the 3.0E-04 LOCA frequency (from the the RHR system. Of these seven events, five occurred INEL report) with the above ' shutting down* and during OC4, one during OC3, and one during OC5.
shutdown
factors for each POS when no hydro test of Seven events in 168 years of BWR operating experience the reactor system is being performed gives the following equates to 0.0417 events per site year.

LOCA frequencies for initiating events A, S ,, S,, and S, : NSAC-157 tabulates RHR events that have occurred from 1984 through 1989 [ Booth,1991). This is approximately

POSs 1-4: 1.39E-04 207 years of BWR operating experience. Eleven events
POSs 5-7: 3.62E-05 were identified in this report that involve diversion of vessel inventory to the suppression pool via the RHR system. Of these eleven events, eight occurred during An' Sin' Sm m' S LOCAs: OC4, and three occurred during OC5. Eleven events in For the case where a hydro test is performed in POS 5, 207 years of BWR operating expedence equates to the LOCA frequency is estimated by multiplying the 0.0531 events per site year.

3.0E-4 LOCA frequency (from INEL report) by the sum of the ' start up* and

normal
factors. Thus, for POS 5 Combining the information obtained from NSAC-88 and during the hydro test the LOCA frequency for initiating NSAC-157 gives 18 events in approximately 375 years of events A #,S S, , and S is given by: BWR operating experience. The mean was found by POS 5 meo: ($.,0b'*4)*(0.1N2 + 0.2613) = 1.25E-04. using a binomial distribution computer to determine the median (0.049), the 59E confidence value (0.0325), and Note: since the 3.0E-04 LOCA frequency from the INEL the 95 % confidence value (0.067). The error factor is

. report is valid for all LOCA leak rates > 50 gpm, 8PProximately 1.4. Increasing the error factor to 3 and LOCA values for the non-hydro and hydro situations assuming a lognormal distribvion about the median, the mean number of events is 0.061 per site per year. spply to all LOCA categories: small-small (S ,), small (S2 ), medium (Si ), and large (A). One other diversion of vessel inventory to the torus event V: Interfacing Systan LOCA ccurred, but through the main steam lines, not the RHR system. During performance of the ADS LSFT Interfacing System LOCAs were screened from analysis pr cedure (during OC5), seven SRVs which serve an for all POS as described in Appendix D. ADS function opened. When the SRVs opened, reactor water level decreased from 195 inches to 153 inches. When the SRVs opened, the main steam outlet nozzles R: Vessel Rupture were une vered and reactor water drained via the main steam line to the torus. Vessel Rupture was screened from analysis as described in Appendix D. H,: Diversion to the Condenser via RWCU H: Diversion of Vessel Inventory to the This event was screened from analysis as described in

Appendix D.

Supprtssion Pool via RHR This event is considered separate from the J and K cvents subsequently discussed, because the possibility of I:n LOCA in Operating Connected System (RCIC) inventory recovery creates a potentially different response to this type of initiator. This is not an initiating event in POS 5. The frequencies assigned to this event were not changed from the screening values. Appendix D documents the values used in the screening study. Vol. 2. Part 1 4-13 NUREG/CR 6143

initiating Event 4: LOCA in Operating Connected System (RHR) 4.4 Decay Heat Removal Challenges E* *: 1 solation from Operating RHR-Shutdown A LOCA in tl.e operating connected RHR system refers Cooling Loop to pipe ruptures and component failures (e.g., heat exchangers) connected to the primary system. ElB events are interruptions in the operating SDC train. These events are relatively easy to correct and generally NSAC-88 tabulates RHR events that have occurred from involve loss of the SDC train for less than two hours. 1977 through 1983 [ Vine, et al.,1986]. 'Ihis is approximately 168 years of BWR operating experience. NSAC-88 tabulates RHR events that have occurred from Two events were identified in this report that involve 1977 through 1983. This is approximately 168 years of loss of vessel inventory due to SDC heat exchanger BWR operating experience. Ten events were identified leaks. Both events occuned during OC5. In one event in this report that involve isolation from the operating approximately 4000 gallons of water leaked to the SDC cooling loop. Of these ten events, six were due to RBCCW in 10 minutes. No leakage rate was reported valve problems, three were due to maintenance, and one for the other event. Two events in 168 years of BWR was due to loss of heat sink. Ten events in 168 years of operating experience equals 0.0119 events per site year. BWR operating experience equates to 0.0595 events per I NSAC-157 tabulates RHR events that have occurred from 1984 through 1989 [ Booth,1991]. This is NSAC-157 tabulates RHR events that have occurred from approximately 207 years of BWR operating experience. 1954 through 1989. This is approximately 207 years of Two events were identified in this report that involve BWR operating experience. Seven events were identified loss of coolant via the RHR system to the radwaste in this report that involve isolation from the operating system. Both of these events occurred during OC5. SDC loop. Of these seven events, two were due to valve Two events in 207 years of BWR operating experience problems, two were due to maintenance, two were due to equals 0.0097 events per site year. isolation of the running RHR pump, and one was due to overpressurizing the vessel. Combining the information obtained from NSAC-88 and Combining the information obtained from NSAC 88 and NSAC-157 gives four events in approximately 375 years NSAC-157 gives 17 loss of operating SDC events in of BWR operating experience. The mean was found by approximately 375 years of BWR operating experience. using a binomial distribution computer to determine the The mean was found by using a binomial distribution median (0.0125), the 5 % confidence value (0.0055), and computer to determine the median (0.046), the 5 % the 95 % confidence value (0.022). The error factor is confidence value (0.031), and the 95 % confidence value epproximately 1.8. Increasing the error factor to 3 and (0.065). The error factor is approximately 1.4. assuming a lognormal distribution about the median, the hereasing the error factor to 3 and assuming a lognormal mean number of events is 0.0156 per site per year. Jistribution about the median, the mean number of events is 0.057 per site per year. In addition to the above events, it should be noted that Of these 17 events,10 occurred during OC4, three j three events were identified in NSAC-157 that involve occurred during OC3, three occurred during OC5, and no

                                      ' loss' of vessel coolant to the RHR system. All three of      OC was reported for the remaining event.

these events involved initiating the RHR system (during OC3) when the RHR piping was empty of water. E,c: Isolation of RWCU as SDC This event is of concern only when RWCU is being used K: Test / Maintenance Induced LOCA for SDC, which in the model for POS 5 is during hydro test conditions. Information could not te found Analysis of these events is deferred until a detailed pertaining to the frequency for isolation of the RWCU human reliability model for events occurring at shutdown system; therefore, the frequency of E * ,1.57E-03, was is developed, and applied to Grand Gulf. used for E , IC NUREG/CR-6143 4-14 Vol. 2, Part 1 L

Initiating Events E ,: Isolation of ADHRS Only during a non-routine test. No operating condition category was reported for three events. Since the Alternate Decay Heat Removal System (ADHRS) is fairly unique to Grand Gulf, and since there E:y Isolation of Common Suction Line for ADHRS is little data pertaining to ADHRS failures, no specific ADHRS frequency could be determined. Therefore, Since the Alternate Decay Heat Removal System since ADHRS performs a function similar to shutdown (ADHRS)is fairly unique to Grand Gulf, and since there cooling, the frequency used for shutdown cooling (E ,) is little data pertaining to ADHRS failures, no specific was also used for E, (0.057). ADHRS frequency could be determined. Therefore, since ADHRS performs a function similar to shutdown Ey: Isolation of Common RHR Suction Line cooling, and uses the SDC common suction line, the frequency umd for shutdown cooling (E y) was also used EIT events are isolations of either the inboard and/or for E,y (0.356). outboard motor operated valves MOV(s) in the common RHR suction line. These EIT events are relatively easy E ,: Loss of Operating RHF-Shutdown Cooling to fix and involve disruption of SDC for less than two System hours. E2B events involve major interruptions in the operating NSAC-88 tabulates RHR events that have occurred from SDC system. %cse events essentially cause a long term 1977 through 1983 [ Vine, et al.,1986]. This is loss of SDC from the previously operating train (s). approximately 168 years of BWR operating experience. Twenty-five events were identified in this report that NSAC-88 tabulates RHR events that have occurred from involve isolation of the common RHR suction line. Of 1977 through 1983 [ Vine, et al.,1986]. This is < the twenty-five events, only nine events occurred at approximately 168 years of BWR operating experience. plants that were operating commercially, the other Eighteen events were identiGed in this report that involve sixteen events occurred at units that had not yet obtained loss of the operating SDC cooling system. Of these 18 e commercial operating license. Hus, NSAC-88 gives loss of RHR events, four were due to valve problems, nine events in 168 years of BWR operating experience. two were due to maintenance, four were due to the loss This equates to 0.0536 events per site year. of the running RHR pump, and eight were due to loss of the heat sink. Eighteen events in 168 years of BWR NSAC-157 tabulates RHR events that have occurred operating experience equates to 0.1071 events per site from 1984 through 1989 [ Booth,1991]. This is year, approximately 207 years of BWR operating experience. Ninety-nine events were identified in this report that NSAC-157 tabulates RHR events that have occurred from involve isolation of the common RHR suction line. 1984 through 1989 [ Booth,1991). This is approximately Therefore, 99 events in 207 years of BWR operating 207 years of BWR operating experience. One event was experience equates to 0.478 events per site year. identified in this report that involves loss of the operating SDC. This event was loss of the running RHR pump. Combining the information obtained from NSAC-88 and One event in 207 years of BWR operating experience NSAC-157 gives 108 SDC common suction line isolation equates to 4.83E-03 events per site year. events in approximately 375 years of BWR operating , experience. The mean was found by using a binomial Combining the information obtained from NSAC-88 and l distribution computer to determine the median (0.285), NSAC-157 gives 19 loss of operating SDC events in the 5 % confidence value (0.245), and the 95 % approxituately 375 years of BWR operating experience. confidence value (0.323). The error factor is The mean was found by using a binomial distribution cpproximately 1.1. Increasing the error factor to 3 and computer to determine the median (0.052), the 5 % assummg a lognormal distribution about the median, the confidence value (0.036), and the 95 % confidence value mean number of events is 0.356 per site per year. (0.071). The errcr factor is approximately 1.4. Increasing the error factor to 3 and assuming a lognormal - Most of the events (68 out of 108) occurred during plant distribution about the median, the mean number of events I operating condition 4. Most of the remainder occurred is 0.065 per site per year. during OC3 or OC5; one event occurred during OC2 Vol. 2, Part 1 4-15 NUREG/CR-6143 l

Initiding Event Of these 19 events,14 occurred during OC4, four events in approximately 375 years of BWR operating l experience. The mean was found by using a binomial j occurred during OC5, and one occurred during OCl. distribution computer to determine the median (0.0305), l the 5 % confidence value (0.0185), and the 95 % E:x Loss of RWCU as DIIR r confidence value (0.046). The error factor is This event is of concern only when RWCU is being used approximately 1.5. Increasing the error factor to 3 and for SDC, which in the model for POS 5 is during hydro assuming a lognormal distribution about the median, the mean number of events is 0.038 per site per year. test conditions. Information could not be found pertaining to the frequency for loss of the RWCU Ten of these evots occurred during plant operating , system; therefore, a fault tree analysis on the RWCU condition 3, the remaining event occurred during l system was performed, with support systems removed to consider only RWCU system failures. The resultant operating condition 5. j frequency was 1.57E-03. E,: Iess of Common Suction Line for ADHRS E,: Loss of ADHRS Only Since the Altemate Decay Heat Removal System Since the Alternate Decay Heat Removal System (ADHRS) is fairly unique to Grand Gulf, and since there i (ADHRS)is fairly unique to Grand Gulf, and since there is little data pertaining to ADHRS failures, no specific l tittle data pertaining to ADHRS failures, no specific ADHRS frequency could be determined. Therefore, l since ADHRS performs a function similar to shutdown l

        ) HRS frequency could be determined. Therefore, ace ADHRS performs a function similar to shutdown             cooling, and uses the SDC common suction line, the                 !

cooling, the frequency used for shutdown cooling (E,,) frequency used for shutdown cooling (E,) was also used l j was also used for E, (6.5E-02). for E,(3.8E-02). E,: Loss of Common RHR Suction Line 4.5 Special Events l E2T events are events which essentially cause a total loss Three special events associated with reactivity excursions of SDC due to the inability to open the inboard and/or were examined. Th: three events are: the outboard MOV(s) in the common RHR suction line in a timely manner. E2T events are time consuming t I T'^: Rod Withdrawal Error j fix, and involve significant delays in establishing SDC. i l T: Refueling Accident I I NSAC-88 tabulates RHR events that have occurred from i '7 through 1983 [ Vine, et al.,1986]. This is T,: Instability Event. groximately 168 years of BWR operating experience.

     ;en events were identified in this report that involve loss        These events were screened from analysis for all POS as        i of the common RHR suction line. Of the ten events,                   described in Appendix D.

nine occurred at plants that were operating commercially, the other event occurred at a unit that had not yet Grand Gulf, being a BWR, does not use chemical shim, obtained a commercial operating license. Thus, NSAC- and thus contrary to the case for typical PWRs, can 88 gives nine events in 168 years of BWR operating maintain shutdown margin on rods alone in every mode, expedence. This equates to 0.0536 events per site year. even Cold Shutdown and Refueling. Reactivity excursions in the vessel due to de-boration events are not NSAC-157 tabulates RHR events that have occurred possible at Grand Gulf. from 1984 through 1989 [ Booth,1991). This is approximately 207 years of BWR operating experience. Two events were identified in this report that involve loss of the common RHR suction line. Therefore, two events in 207 years of BWR operating experience equates to 9.66E-03 events per site year. Combining the information obtained from NSAC-88 and l NSAC-157 gives 11 SDC common suction line loss 4-16 Vol. 2, Part 1 NUREG/CR-6143 l l l

F Initiating Events References for Section 4 P [ ANSI /IEEE,1984] *IEEE Guide to the Collection Water System Failures and ! and Presentation of Electrical, Degradations: Commercial Electronic, and Sensing Power Reactors," U. S. : Component Reliability Data Nuclear Regulatory l for Nuclear Power Generating Commission, NUREG-1275, Stations," ANSI /IEEE Std. Vol. 3, November 1988. ; 500-1984, John Wiley and ' Sons, New York,1984. [Mackowiak, et al.,1985] D. P. Mackowiak, C. D. , Gentillon, and K. L. Smith, i [Baranowski,1981] P. W. Baranowski, A. M. " Development of Transient ! Kolaczkowski, and M. A. Initiating Event Frequencies Fedele, "A Probabilistic for Use in Probabilistic Risk i Safety Analysis of DC Power Assessments," Idaho National Requirements for Nuclear Engineering Laboratory, , Power Plants," U. S. Nuclear NUREG/CR-3862, EGG-Regulatory Commission, 2323, May 1985. i Sandia National Laboratories, and Evaluation Associates, [USNRC,1975] USNRC, " Reactor Safety Inc., NUREG-0666, April Study; An Assessment of 1981. Accident Risks in U. S. Commercial Nuclear Power [ Booth,1991] H. R. Booth. " Residual Heat Plants: Appendix III and IV Removal Experience Review Failure Data," U. S. Nuclear i and Safety Analysis: Boiling Regulatory Commission,

Water Reactors, 1984-1989,* WASH-1400, NUREG-Mollems Engineering 75/014, October 1975. j Corporation, NSAC 157, June 1991. [ Vine, et al.,1986] G. Vine, T. Libs, S.

Farrington, and R. Allen, [Dafoss, ct al.,1990] G. DeMoss, E. Lofgren, B. " Residual Heat Removal Rothleder, M. Villeran, C. Experience Review and Safety ; Ruger, "A Risk-Based Review Analysis: Boiling Water ofInstrument Air Systems at Reactors,' Nuclear Safety i Nuclear Power Plants,* Analysis Center, NSAC-88, Science Applications March 1986. International Corporation, and Brookhaven Netional [ Whitehead, et al.,1991] D. W. Whitehead, J. Darby, j I2boratory, NUREG/CR- B. D. Staple, B. Walsh, T. 1 5472, BNL NUREG-52220, M. Hake, and T. D. Brown, ' January 1990. *BWR Low Power and < Shutdown Accident Sequence l [Drouin, et al.,1989] M. T. Drouin, J. L. Frequencies Project, Phase 1 - i LaChance, B. J. Shapiro, S. Course Screening Analysis," ' Miller, T. A. Wheeler, Vol.1. Draft letter Report, t

                          " Analysis of Core Damage                                        Sandia National Laboratories Frequency: Grand Gulf, Unit                                       and Science and Engineering 1, intemal Events," Sandia                                       Associates, Inc., November            ,

National laboratories and 23,1991 update, Copies Science Applications available at the NRC Public International Corporation, Document Room. NUREG/CR-4550, SAND 86-2084, Vol. 6, Rev.1, Part 1, [ Wright, et al.,1987] R. E. Wright, J. A. September 1989. Steverson, and W. F. Zuroff,

                                                                                           " Pipe Break Frequency

[ Lam and Leeds,1988] P. Lam and E. Leeds, Estimation for Nuclear Power

                         ' Operating Experience                                            Plants," EG&:G, NUREG/CR-Feedback Report - Service                                         4407. EGG-2421, May 1987.

Vol. 2 Part 1 4-17 NUREG/CR-6143 l

Initiating Event Bibliography J. H. Holderness, K. D. Kimball, J. P. Durham, and E. D. C. Bley, V. M. Bier, D. IL Johnson, and J. W. A. Hughes, " Brunswick Decay Heat Removal Stetkar, " Service Water Systems and Nuclear Plant Probabilistic Safety Study," Impell Corporation, Carolina Safety,' Pickard, Iowe, and Garrick, Inc., NSAC-148, Power & Light Company, and Nucon Inc., NSAC-83, May 19>0. Octcher 1985.

Loss of Vital AC Power and the Residual Heat Removal R. O. Brugge, B. Chexal, and W. H. Laymay, " Analysis System During Mid loop Operations at Vogtle Unit 1 on of Heatup and Pressurization Dming Dresden-3 March 20,1990," U. S. Nuclear Regulatory Shutdown," Nuclear Safety Analysis Center, NSAC-27, Commission, NUREG-1410, June 1990.

September 1981. P. Kohut, Z. Musicki, and R. Fitzpatrick, " Analysis of H. R. Booth, ' Analysis of Refueling Incidents in Nuclear Risk Reduction Measures Applied to Shared Essential Power Plants," Mollerus Engineering Corporation, Service Water Systems at Multi-Unit Sites,' T1rmkhaven NSAC-129, December 1988. National laboratory, NUREGICR-5526, E? NUREG-52225, August 1990. A. C. Payne, et al., ' Interim Reliability Evaluation Program: Analysis of the Calvert Cliffs Unit 1 Nuclear " Office for Analysis and Evaluation of Operational Data Power Plant, Volume 1. Main Report," Sandia National 1990 Annual Report," U. S. Nuclear Regulatory Laboratories, NUREG/CR-3511, SAND 83-2086, March, Commission, NUREG-1272, Vol. 5, No.1, July 1991. 1984. C. P. Tzanos and W. A. Bezella, " Risk Related Reliability Requirements for BWR Safety-Important Systems With Emphasis on the Residual Heat Removal , System," Argonne National Laboratory, NUREG/CR-3933, ANL-84-52, August 1984. H. L. Ornstein, ' Ope 3 ting Experience Feedback Report

 - Air Systems Problems: Commercial Power Reactors,"

U. S. Nuclear Regulatory Commissio o NUREG-1275 l Vol. 2 December 1987. W. H. Hubble and C. F. Miller,

Data Summaries of Licensee Event Reports of Control Rods and Drive Mechanisms at U. S. Commercial Nuclear Power Plants:

January 1,1972 to April 30,1978,* EG&G, NUREG/CR-1331 EGG-EA 5079, February 1980. D. M. Ericson, Jr., T. A. Wheeler, T. T. Sype, M. T. Drouin, W. R. Cramond, A. L. Camp, K. J. Maloney, F. T. Harper, " Analysis of Core Damage Frequency: Internal Events Methodology," Sandia National Laboratories, ERC Environmental and Energy Senices Company, and Science Applications International Corporation, NUREG/CR-4550, SAND 86-2084, Vol.1, Rev.1, January 1990. F. J. Mollerus, R. D. Allen

Reliability of BWR High-Pressure Core Cooling: 1978-1986,* Mollerus l

Engineering Corporation, NSAC-140, January 1990. NUREG/CR-6143 4-18 Vol. 2, Part 1

5 Success Criteria for POS 5 Success criteria are the combinations of systems and Control Rod Drive (CRD) makeup. As few as two Safety constituent components that can successfully mitigate an Relief Valves (SRVs) are requirn! to b- available, but eccident initiating event, i.e., prevent core damage. during hydro testing they are all available. Recirculation Section 4 of this report discusses accident initiating can be either forced or natural. Initial level can be events. This section of the report summarizes the normal when on forced recirculation, raised when on success criteria for POS 5. natural circulation, or the vessel can be essentially full as is the case during hydro testing. Containment can be The screening report developed success criteria for all open or closed. Suppression Pool (SP) water level can seven POS [ Whitehead, et al.,1991]. In this detailed be 18 feet 4 inches,12 feet 8 inches, or empty if study of POS 5, the success criteria for POS 5 were 170,000 gal of Condensate Storage Tank (CST) water is updated. If this update affected the success criteria for available to High Pressure Core Spray (HPCS). other POS, then these success criteria were also updated. Numerous components can be out for maintenance in Appendix E provides updated success criteria for all POS $; our model assumes all of train A is unavailable seven POS. Appendix F summarizes numerous due to maintenance in POS 5. calculations that we performed to establish the success criteria. In POS 5, cold shutdown, the initial temperature is no higher than 200 'F; therefore, contrary to the situation at , full power, flashing of primary inventory following a The success criteria for POS 5 are different from those LOCA is not of concem, even during hydro testing. The for full power. A simple extrapolation of the full power concern is draining the vessel and uncovering the fuel. success criteria for use during cold shutdown is not adequate to accurately analyze accident scenarios. The decay heat is much lower than immediately following In contrast to the situation at full power, in cold reactor trip from full power, thus allowing more time for shutdown core cooling is provided by either RHR or mitigating accidents. (In POS 5, the decay heat is, at ADHR, and full system pressure cannot be tolerated. most,0.9% of full power; it is about 8 % immediately When using these systems to cool the core, pressure after trip from full power, not including delayed fission). must be kept belo v the auto-isolation high pressure The initial temperature is much lower than at full power, setpoint or below failure pressures for components in and - except during hydro testing - the pressure is much these systems. lower than at full power (200 F compared to 545 F, and 0 psig compared to 1000 psig). To use low pressure injection pumps to cool the core following loss of shutdown cooling, SRV(s) must be As discussed in Section 3 of this report, the initial manually opened in the relief mode. His requires conditions in POS 5 can vary, and this variation has an operator action, air, and DC power. Also, as few as i impact on the success criteria. His is totally different two SRV(s) can initially be available in cold shutdown. , from the situation at full power where the variation in I initial conditions is small, since most changes in equipment availability lead to either reactor trip, or In the following discussion of success criteria, controlled shutdown as required by the technical ' Transient' refers to any accident initiating event that is specifications. not a LOCA. 'LOCA' refers to an accident initiating I event in which vessel water inventory is directly lost as , POS 5 can be entered with decay heat as high as 0.9 % the result of a breach in the reactor coolant system or 1 of full power (34 MW). However, after refueling decay associated systems. I heat will be no higher than 0.16 % of full power (6 MW) , and this is the situation during hydro testing. For non- The success criteria cover both the low pressure (non- ' hydro conditions, the Main Steam Isolation Valves hydro) situation and the high pressure hydro situation. It (MSIVs) can be open or closed; for hydro testing they should be noted that aside from different initial are closed. Shutdown cooling for the non-bydro situation conditions, the success criteria for both situations are can be with Residual Heat Removal (RHR), or with similar since if initially in hydro, the CRD pumps can be Alternate Decay Heat Removal (ADHR) 24 hours after tripped, resulting in the system 'instantly' depressurizing shutdown. During hydro testing, shutdown cooling is to about 0 psig, and low pressure cooling options can be with Reactor Water Cleanup (RWCU) letdown and used. Vol. 2, Part 1 5-1 NUREG/CR-6143

Success Criteria returns water to the downcomer through feedwater lines, 5.1 Functions and ADHRS returns water through the Iow Pressure Three functions must be successfully provided to mitigate Coolant Injection (LPCI) C injection line. (Discharge of an accident initiating event: (1) Reactivity Control, (2) either RHR or ADHR can be to the upper pool, but this Level Control, and (3) Energy Removal. The ways in is not used in POS 5 (per 1991 site visit).) which these three functions can be provided for POS 5 Level is measured in the downcomer using a differential cre discussed in the remainder of this section. pressure sensor. The sensor measures a difference in 5.1.1 Reactivity Control pressure between a head of water in the downcomer and a head of water in a reference leg. At Grand Gulf, the Reactivity control is required to prevent the reactor core safety-related level instrumentation is not compensated; from generating more energy than can be removed. In that is, in converting from pressure to level, the water in POS 5, the core must remain suberitical. the downcomer is assumed to have a density of that of water at full power rated pressure and temperature. Grand Gulf is a BWR, and does not use chemical shim Consequently, in POS 5 where the initial state is 200 F to control reactivity, i.e., the reactor is a rodded core water, the actual level is about 77 percent of the and no soluble boron in the water is used. measured level. For an actual level above instrument Consequently, contrary to the situation for a PWR, zero, the measured level is higher than actual, while for shutdown margin can be maintained with rods alone in an actual level below instrument zero the measured level all Operating Conditions (Modes) including cold is lower than actual. For example, if actual level is + 10 shutdown. inches, measured level is + 13 inches; if actual level is - 10 inches, measured level is -13 inches. (This effect is In POS 5, the rods are fully inserted, and it is extremely discussed in NSAC 88 [ Vine, et al.,1986).) , unlikely that reactivity excursions from suberitical can occur Consequently, we have assumed that reactivity The downcomer and the core are in different hydraulic control is a furetion that is always present at Grand Gulf regions of the vessel. The level of water in the core in POS 5. region can differ from that in the downcomer region due to: (1) operation of the recirculation pumps, (2) 5.1.2 Ixvel Control differences in density between downcomer water and core fluid, and (3) frictional losses due to flow. In POS Adequate level for core cooling is dependent on the type 5, the first effect is most important. With operation of of accident initiating event, and on the system recirculation pump (s), the level of water in the core configurations used to mitigate the initiating event and region is higher than that in the downcomer region due provide core cooling. Figure 5.1-1 indicates levels for to the head of the pump (s), the Grand Gulf vessel. The figure is from the technical specifications [USNRC,1984). This discussion on levels can be summarized as follows: 5.1.2.1 Level Control for Transients

Adequate level for core cooling depends on the actual level in the core region.

For all transients in POS 5, we have assumed that the core must be covered with water. There is a coupling

Level is measured in the downcomer without between level and energy removal using shutdown compensating for the increased density of water at cooling systems that requires the level to be even higher, shutdown, as subsequently discussed.
Operation of the recirculation pumps increases the 1.evel Control Usine Shutdown Cooline level in the core region relative to that in the Shutdown cooling can be provided by either RHR or A rWRS. Both options use the common suction drop line For proper circulation of water from the core region to off t recirculation suction line for suction. (ADHRS can the downcomer region, the actual level of water in the be used with suction from the upper pool, but this is core must be above the minimum steam separator done in POS when maintenance on the common suction turnaround point to allow core water to flow back down line is being pformed (per 1991 site visit).) RHR NUREG/CR-6143 5-2 Vol. 2. Part I

Success Criteria soc 7

                                    '4*t SCALE m iacwts                             WATER LEVEL NOhWCLATURE aeovt,vtsstL ztao HEICHT ABWE HEICHT RELars.t LEVELPc                          Ehi        hf eco- -                               (8)             586.5            53.5 (7)            573.7             40.7 (4)            565.7             32.7 753- -                               (3)            544 4             a 1. 4 VES!EL *-          (2)            4914            - 41.6

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Success Criteria into the downcomer. If actual core region water level is 2) flooding with either Standby Service Water Crosstic too low, RHR on shutdown cooling is ineffective in (SSWXT) or Fire Water (FW). cooling the core water; it cools the downcomer water, which is effectively decoupled hydraulically from the The amounts of water available are sufficiently large that core region water. Without cooling, and with the vessel removal of decay heat is not a problem. In POS 5, head on, the core region water heats up along the injection of about 2100 gpm of 100 F water can match ; saturation line. (Relief through the small head vent line is decay heat without any steaming. A single ECCS pump insufficient to relieve pressure.) If this pressurization can inject about 6000 to 7000 gpm into a O psig vessel. transient is not stopped, either of two undesirable SSWXT can inject about 12,000 gpm, and FW can inject l consequences occur. (1) All shutdown cooli>g is lost if about 1500 gpm. Thus, for injection with any of these ! the common suction line auto-isolates on high pressure at sources, the vessel will be full, assuming that the MSIVs 135 psig. (2)If the auto-isolation fails, eventually either are closed. For injection with any of these sources, RHR or ADHR low pressure components overpressurire SRVs must be opened. We estimate that opening of one and the result is an interfacing systems LOCA that SRV in a relief mode is sufficient for core cooling. , bypasses containment. (This LOCA can be isolated if However, unless two SRVs are opened, ADHR could the common suction line is auto-isolated on low level.) fait due to overpressure if it is not isolated on high pressure. (Even if ADHR overpressurizes, the break can Adequate measured (downcomer) level for core cooling auto-isolate on low level.) depends on the details of how shutdown cooling is provided. If recirculation pump (s) are on, then the head If ECCS pumps are used, the MSIVs must be closed to of the pump (s) provides enough level in the core region prevent loss of SP inventory. If the MSIVs are closed, whenever measured level is above low level 3, + 11.4 and SRV(s) are opened, Suppression Pool Makeup inches, where shutdown cooling is auto-isolated. If the (SPMU) is not required, in the near term, as long as the recirculation pumps are off, and one train of RHR is SP is initially at 12 feet 8 inches or above. This is used, throttled at low flow, downcomer and core water because the discharge of water from the vessel is directly levels are about equal, and the measured level must be to the SP (not to the drywell as for LOCAs inside sufficient for natural circulation from the core region. containment), and the SP has adequate level to This level is + 82 inches (measured) to provide actual compensate for vessel fill. (If the SP is initially empty level of +63 inches as required to reach the minimum with CST available to HPCS, the resultant SP level steam separator turnaround point. If actuallevelis following fill of the vessel and discharge to the SP is above low level 3 but below +63 inches, and no forced insufficient for continued ECCS operation, even if recirculation is available, operation of both loops of RHR SPMU were available.) Since SPMU is not normally at high flow can provide enough mixing to cool the core available in POS 5 (see Section 3 of this report), the lack region. This method of cooling, which we denote as of a need for early SPMU for transients, given the SP

  " enhanced shutdown cooling", is discussed in NSAC 88,         initially had at least 12 feet 8 inches of water and but is not proceduralized at Grand Gulf [ Vine, et al.,        injected water is retumed to the SP via open SRV(s), is 1986). For POS 5, with train A assumed out for                an important characteristic of the success criteria. Long maintenance (see Section 3 of this report), this enhanced       term makeup to the suppression pool is required if              ,

shutdown cooling option cannot be used. Suppression Pool Cooling (SPC) and Containment Spray (CS) are lost, to makeup for long term loss of SP In summary, we used the following measured inventory due to boiloff. (downcomer) levels as required for shutdown cooling: Level Control for Steamine (1) + 11.4 inches with forced recirculation The core can be cooled so long as the fuel rods do not (2) + 82 inches with natural recirculation (3) + 11.4 inches with ' enhanced shutdown cooling'. experience dryout . At shutdown, in POS 5, the decay heat flux is sufficiently low so that the core can be Level Control with Water Iniection cooled by natural convection of boiling saturated water. That is, flooding induced dryout is not of concern, based if shutdown cooling is lost, the core can be cooled by on our estimate of the margin between maximum and injection of water. Two types of water sources can be dryout heat fluxes as discussed in Appendix E, even used: 1) ECCS pumps using the suppression pool; and though the dryout heat flux is lower in POS 5 than at full power, due to the increased specific volume of steam at 5-4 Vol. 2, Part 1 NUREG/CR-6143

1 l l l l l Success Criteria low pressures. Thus, if the core is covered with following a LOCA in POS 5, the uncovered fuel is not I saturated water, steaming can cool the fuel. immediately cooled by steam, since the water is initially l subcooled. We performed MELCOR analyses to l To match boiloff due to steaming in POS 5 at low investigate the ability of ECCS to cool the top 1/3 of the pressure, about 250 gpm of makeup water is required. core without steaming. The results indicate that HPCS, One SRV opened in the relief mode can provide LPCS, or (conservatively) two LPCI pumps can cool the sufficient relief. top 1/3 of the core. At Grand Gulf, SSWXT and FW can also be used to mitigate LOCAs. Both of these If stammg at low pressure cannot be provided, the core systems route water to the core through LPCI injection can be steamed at high pressure. Shutdown cooling must lines. Consequently, for a large LOCA the required be isolated to allow the system to pressurize along the flow from SSWXT or FW is about that of two LPCI saturation line to rated conditions, about 1000 psig and trains, or about 12,000 gpm. Based on information from 545 F, without experiencing an interfacing systems the full power PRA, SSWXT can provide this flow rate, LOCA outside of containment. One SRV cycling at its but FW cannot [Drouin, et al.,1989]. safety setpoint provides for sufficient relief of steam. If the system does heat / pressurize to rated conditions, seal A sufficiently large break in a recirculation line does not cooling for the recirculation pumps is required, even if result in direct loss of water outside containment, even if the pumps are off, since the seals are exposed to high the MSIVs are initially open, since the break discharges temperature water. Seal cooling can be provided by to the drywell and it is sufficiently lage to prevent either injection with CRD, or out-leakage of vessel water injected ECCS water from flowing out the main steam with cooling by Component Cooling Water (CCW). lines. For smaller diameter large LOCAs, and (Unless the system pressurizes due to heatup, the water operation of many ECCS pumps, the vessel can fill up :o is 200 F, and we have assumed that outleakage of vessel the main steam lines and closure of MSIVs is required to water at this low temperature without cooling by CCW prevent loss of SP inventory outside containment. can cool the recirculation pump seals rhether the recirculation pumps are operating or not.) To prevent loss of adequate SP inventory for continued operation of ECCS pumps, SPMU is required to 5.1.2.2 Level Control for LOCAs compensate for lowered SP level as a result of filling the drywell, and (for smaller diameter large LOCAs with The control of level following a LOCA depends on both many ECCS pumps operating) filling the vessel. the size and the location of the LOCA. ! No opening of SRVs is required for any size large In POS 5, the water is initially subcooled. In contrast to LOCA, since the size of the hole is sufficient to prevent the situation at full power, flashing of water is not of pressurization and to allow for sufficient discharge of concem following a LOCA. enthalpy to match decay heat. Ievel Centrol for Larce LOCAs in a Recirculation Line Level Control for Larce LOCAs in Steam and Feedwater Lines For sufficiently large LOCAs in a recirculation line, the core cannot be covered with water due to the location of In contrast to the situation for a large LOCA in a the break. The amount of core uncovered is that above recirculation line, a break in a steam line or a feedwater the elevation of the inlets to thejet pumps - about 1/3 of line can directly result in loss of water outside the core is uncovered. The ECCS injection systems containment. inject above the core, not into the downcomer as in a PWR. HPCS and Low Pressure Core Spray (LPCS) In POS 5, steam line breaks are not LOCAs. Except for inject as a spray down over the top of the fuel, and thus the Hydro situation, the level is below the main steam provide some direct cooling of the top 1/3 of the lines, the coolant is subcooled, and pressure is O psig; uncovered core. LPCI, at Grand Gulf, does not fill fuel the steam line break has no effect. In the Hydro essemblies from the bottom; LPCI fills the volume situation, the vessel is filled and pressurized to 1000 outside each channeled fuel assembly and flows over the psig, but the coolant is only 200 'F. Thus, a steam line top of the channel and down the fuel assemblies as a break would only lower the level and not result in loss of filling film, thus also providing some direct cooling of level. the uncovered portions of fuel. In contrast to full power, Vol. 2, Part 1 55 NUREG/CR-6143

Success Criteria A feedwater line break outside contenment can be remove the energy, but not every option can be used in isolated by the closure of either of two check valves. If every situation. the break is not isolated, ECCS is lost due to loss of SP level as injected water flows out the break; however, the S.I.3.1 Energy Resnoval for Transients break does not lead to core uncovery in POS 5 since the cubcooled water can drain only to the elevation of the The following methods are available to provide core feedwater injection nozzle, which is 10 feet above the top cooling for transient accident events: of the core. If the break is isolated by closure of a check valve, then ECCS from the SP can be used (1) Closed loop cooling of subcooled vessel water providing: (1) one MSIV on each of four steam lines is using the RHR on SDC, or the ADHRS (not closed to prevent loss of SP inventory, and (2) at least available until 24 hours after shutdown). one SRV is opened to allow for egress of injected water Downcomer level must be sufficient for to prevent pressurizing to the pump (s) shutoff head, and recirculation from the core to the downcomer to allow for discharge of enthalpy. region when RHR/SDC or ADHRS is used; with forced recirculation the minimum allowed measured level is + 11.4 inches, and with natural Level Control for Sm_allLOCAs circulation the minimum allowed measured level For small LOCAs in a recirculation line any single is 4 82 inches. (Enhanced shutdown cooling can ECCS pump can maintain the core covered; also, both be used if the measured level is no lower than SSWXT and FW can cool the core. Also, for small about two feet below the average normal LOCAs, letdown can be isolated and makeup increased measured level of + 36 inches.) to prevent loss oflevel, so that normal shutdown cooling can be used. (2) Recirculation of water from the SP using the ECCS (HPCS, LPCS, or LPCI) with water flow At least one SRV must be opened to successfully use out the SRVs. To prevent loss of SP inventory, injection in response to a small LOCA, for three reasons: fluid exiting the vessel must not bypass (1) to prevent a pressurization transient as level drops containment; thus, the MSIVs must be closed. and shutdown cooling of the core water becomes ineffective (as previously discussed) before the ECCS (3) Injection of water from the SSWXT or the FW automatic actuation setpoint is reached, (2) to prevent system with water flow out the SRVs, resulting in pressurization to the injection pump (s) shutoff head after flooding of containment. injection is actuated, and (3) to allow for discharge of enthalpy sufficient to match decay heat. (4) Steaming out the SRVs with makeup to maintain level. Low capacity systems such as CRD can For small LOCAs in a feedwater line outside match steaming. If an SRV is operated in relief, containment, the same considerations for isolation apply low head pumps such as SSWXT and FW can as previously discussed for a large LOCA, but the time provide makeup. If the system is at rated available is longer. pressure and steaming on an SRV at its safety setpoint, high head pumps such as CRD and Level Control for Medium LOCAn HPCS are required for makeup. A medium LOCA exhibits the characteristics of a large (5) At sufficiently low decay heat levels (e.g., after LOCA for the larger diameter medium LOCA sizes. A refueling), letdown of hot water through the medium LOCA exhibits the characteristics of a small RWCU with makeup from the CDS and/or the LOCA for the smaller diameter medium LOCA sizes. CRD. The RWCU can operate in a closed mode in which heat is removed by its beat exchangers, 5.1.3 Energy Removal or it can operate in a letdown mode, discharging to either the main condenser or radwaste. During Given adequate level, Energy Removal from fluid in the liydro conditions which only occur after vessel must match decay heat; the methods which can be refueling, both modes are simultaneously used. used to remove energy depend on the accident situation and the availability of systems in that accident as well as Options (1) and (5) require a high enough water level for adequate forced or natural recirculation between the core the decay heat level. Mary options are available to NUREG/CR-6143 5-6 Vol. 2, Part 1

Success Criteria and downcomer regions, or for enhanced shutdown inches; or 3) empty with 170,000 gal of water from the ccoling. Options (2) and (3) fill the vessel. Option (4) CST available for HPCS. As discussed earlier in Section requires the core to be covered with water. 5.1.2.1, if the SP level is at 12 feet 8 inches or above, SPMU is not required for transients in which SRVs are Of these five options, three are ence-through (i.e., water used to route fluid from the vessel to the SP. One of in not recirculated from the SP to the reactor vessel): two MSIVs on each main steam line must be closed to (3), (4) except when using ECCS, and (5). Options (1) prevent loss of SP inventory outside containment. If the end (5) require no heat removal from containment. SP is empty and the CST is available with 170,000 gal, Option (3) requires heat removal from containment only insufficient inventory is available even with SPMU for ofter the entire inventory of water is heated to saturation. use of the SP to supply ECCS pumps. Options (2), (4), and, in the long term, (3) require Long term makeup to the suppression pool is required if containment cooling to prevent containment the containment is vented or failed from overpressure, to pressurization. Containment cooling can be provided by prevent boiloff of water to where adequate level for either the SPC or CS. If containment cooling is not ECCS pumps is lost provided, the containment can be vented and the heat sink for these options is boiling to the atmosphere a: 15 5.1.3.2 Energy Removal for LOCAs psie. If containment cooling is lost and the containment is not vented, for these options in which energy is being The following methods are available to provide core added to containment, the containment pressure will rise cooling for LOCA accident events: to maintain saturation conditions as the SP temperature increases. NUREG 4550 concluded that containment (1) For sufficiently small LOCAs, makeup from CRD would overpressurize and fail before equipment or CDS can match break flow ifletdown is temperature limits are reached (pumps, relays. and so isolated, and the methods described for option (1) on), and that structural failure of the containment would for transients can be used (see Section 5.1.3.1). not render the SP unavailable [Drouin, et al.,1989), his important conclusion means that these options can (2) Recirculation of water from the SP using the be used to cool the core with the containment failed, ECCS (HPCS, LPCS, or LPCI) with water flow (i.e., containment overpressurization is an effective way out the break. For sufficiently small LOCAs, to vent containment). The success criteria use this opening of an SRV is also required. To prevent conclusion. loss of SP inventory, fluid exiting the vessel must not bypass containment; thus, the MSIVs must be The SPMU system has two functions [SERI,1992 closed for sufficiently small LOCAs. (Section 6.2.7.1)]. (1) SPMU maintains SP level sufficiently high so that SP level is not decreased below (3) For LOCAs small enough and/or in a location the minimum required for supply of water to the ECCS such that the core can be maintained covered with pumps. SPMU compensates for all water entrapment water, the core can be flooded. Water can be volumes (drywell volume below the top of the weir wall, supplied from the SSWXT or the FW system with vessel fi'1, spray, and so on). (2) SPMU assists in water flow out the break and, for sufficiently lowering the long term containment pressure since the small LOCAs, out the SRVs, resulting in flooding heat removal capacity of one RHR train is less than the of containment. decay heat at 30 minutes, the time when containment cooling is assumed to be actuated in a Design Basis (4) For LOCAs small enough and/or in a location Accident (DBA) [SERI,1992 (Section 6.2.7.3.4)]. For such that the core can be maintained covered with tmnsients where fluid from the vessel is retumed directly water, the care can be steamed. If the LOCA is to the SP using SRVs, the amount of makeup required to sufficiently smsll, operation of an SRV in relier is fulfill the first function is less than that required for a required to poent pressurization, but steaming LOCA in which fluid is discharged to the drywell. The with an SRV at its safety setpoint is acceptable if second function of the SPMU is not required for POS 5, high pressure pumps can provide makeup. since the maximum decay beat is 34 MW and the heat removal capacity of one RHR train is 54 MW (185E+6 SPMU makeup is required in the short term for use of Btu /hr from Table 6.2-2 of [SERI,1992]). ECCS following a LOCA. The makeup is required to compensate for fluid discharged to the drywell. If SP in POS 5, cold shutdown, there are three different, cooling is lost, makeup to the SP in the long term is possible initial conditions for S.P inventory prior to the necessary to replace water boiled off. cecurrence of an accident initiating event: 1) low water Table 5.1.1 provides the success criteria used for POS 5. level (18 feet 41/12 inches) or above: 2) 12 feet 8 (This is the same table as Table E.1.2 in Appendix E.) Vol. 2, Part 1 5-7 NUREG/CR-6143

Table 5.1.1 Success Criteria for Plant Operational Statz (POS) 5" g E O Level Control Energy Removal Plant State Event 3

o large LOCA [HPCS or 2/3 LPCl* or LPCS}' and I/2 ([1/2 SPC or I/2 CSf or [ Vent Containment and h 5 SPMU I/2 SPMU*]}'

O (200 F,0 psig, except for (2 0.4 ft')A' IlYDRO; 200 F,1000 psig which affects and 4,l/2 MSIVs' and 1 SRV' and 1/2 CVs' during IIYDRO) level control and/or heat el Maximum decay heat is (Once through) removal

0.9 % (34MW),7 hours CRD and/or condensate booster steaming'(for after shutdown. unisolated feedwater line break only)

After refueling decay heat og is 0.16% (6MW),30 days Transient Success Criteria after shutdown Transient Success Criteria'(for isolated feedwater line breaks only) o l ' (Once through) SSW Crosstie and 1 SRV' 7ce o l 1 {[l/2 SPC or I/2 CSf or [ Vent Containment and CRD makeup (steam out break)' I/2 SPMU'J}' i ! 9 t hn . _ _ . . --.__..__.m -___m_. _ _ _ _ _ _ _ __ __ _ _ _ _ . _ _ _ __ _ _ _ _ _ _ -_ _ _ _ _ . . , _ , ~ . , - - - - , - - ,- , . - . . . . - * - . , - - - --,i-. ,=

Tt.ble 5.1.1 Success Criteria for Plant Operationni Statn (POS) 5" (Continued) f F {

Plant State Event Level Control Energy Renoval Medium {HPCS or 1/3 LPCl* or LPCST and 1/2 ((1/2 SPC or 1/2 CS]'or [ Vent Containment and LOCA SPMIT' and 1 SRVA' and 4,1/2 MSIVs' and 1/2 SPMU']}' (0.007 to 0.4 1/2 CVs' ft')\' which affects level os control and/or (Once through) heat removal

CRD and/or condensate booster steaming'(for unisolated feedwater line break only) os Transient Success Criteria Transient Success Criteria'(for isolated feedwater line breaks only) os (Once through) y SSW crosstied and 1 SRV

c1 {[l/2 SPC or 1/2 CSf or [ Vent Containment and CRD makeup and 1 SRV (steam out break and 1/2 SPMU']}' SRV)' i c Q N 30 l dh Z b h-

4 Table 5.1.1 Success Criteria for Plant Operational State (POS) 5 * (Continued) O Enerity Removal Pi Plant State Event Level Control

c >

Transfer to transient success criteria h Small LOCA Isolate letdown and [ increase condensate 0 (<0.007 ft')' booster", or { increase CRD and forced recirc}") which affects level or 3 control and/or heat removal

CRD and/or condensate booster steaming' (for Transient Simcess Criteria j

unisolated feedwater line break only) ol Transient Success Criteria' (for isolated (Once through) feedwater line breaks only) t F 01

 $                                   [HPCS or 1/3 LPCI'or LPCS]* and 1/2              ((l/2 SPC or 1/2 CSf or [ Vent Containment and SPMIT and 1 SRV and 4,l/2 MSIVs' and         1/2 SPMU']}'                           (

1/2 CVs' 01 (Once through) SSW crosstie ** and 1 SRV 01 A (Once through) FW given temporary makeup'* and 1 SRV ' I E ([1/2 SPC or i/2 CSf or [ Vent Containment and CRD makeup and 1 SRVs (steam out break and 1/2 SPMU']}' SRV)' a ' Y

g TENe 5.1.1 Success Criteria for Plant Oper tional State (POS) 5* (Continued) F {

Plant State Event Level Control Energy Removal Transient / [ Letdown (RWCU) and Makeup (CRD or 1/2 RHR on SDC' with SSW heat sink' Condensate / Booster')] or alternate source of makeup" E enhanced SDC* 2/2 RHR on SDC' with SSW heat sink' E [ letdown (RWCU) and Makeup (CRD or iII ADHRS' with PSW heat sink l Condensate / Booster')] or alternate source of 7 makeup" ! E I SRV and 4,1/2 MSIVs'and [lIPCS or 1/3 ([l/2 SPC or 1/2 CS]'02 [ Vent containment and LPCI* or LPCS]' I/2 SPMU']}' E

1 SRVand [SSW" crosstie or FW given (Once through) temporary makeup 9 E [CRD" and/or Condensate / Booster'] and 1 SRV ([1/2 SPC or 1/2 CS]'ol[ Vent containment and (steaming) I/2 SPMU']}' os i ([CRD" and/or Condensate / Booster'] and RWCU (360 gpm)T (Once through) 01 Isolation of SDC and 1 SRV/ Safety and [(HPCS and 4,1/2 MSIVs'} or CRD]* ([l/2 SPC or I/2 CS]'ol[ Vent containment and 1/2 SPMU']}'if HPCS used

                              't C

isolation of RHR/SDC and 1 SRV/ Safety and h [(HPCS ansd and [HPC[HPCS Pi W 6

e E

Success Criteria Table 5.1.1 Success Criteria for Plant Operational State (POS) 5* Notes

Reactivity Control by Fully Inserted Rods
Verify that in PS 5 lineups do not allow LOCA to drain the vessel (this cannot be mitigated); concern is loss of level control and/or loss of heat removal due to LOCA

' LOCA in " steam" lines not of concem since O psig primary will not flash ' LPCI Trains A and B require manual re-alignment from SDC. If ADHRS is operable, only one trains or RHR on SDC required to be operable per Tech Spec 3.4.9.2. 2/3 LPCI per MELCOR cale. ADHRS cannot handle decay heat 1 1 load until 24 hrs after shutdown.

SPMU required to prevent loss of SP inventory

' SPMU not required since maximum decay heat less than one RHR train heat removal capability 8 SPMU required to makeup for boiloff from SP when containment vented 2 " 1 SRV required to augment flow out break and prevent pressurization for break s 0.3 ft

' FW not sufficient for large LOCA since flow not equal to 2 LPCI; SSWrl' provides sufficient flow.

3 PCS not available, and Feedwater not available. SPMU to compensate for loss of inventory not required since SRVs discharge to SP.

Condensate / Booster injection may either be on standby or be unavailable

' 1 SRV provide for flow of hot water out of vessel to SP and prevent pressurization
" CRD flow rate at low vessel pressure is 240 gpm max.
" 146 gpm injection required

Maximum RWCU letdown of 360 gpm per inadequate Decay Heat Removal Procedure step 5.1.3

' NUREG/CR-4550 modeled SSW crosstie and FW.

This method can match decay heat only after refueling when decay heat is low. Either of two modes can be uset'. Tr.e RWCU can be used in a closed loop transferring heat to its heat exchangers, or RWCU letdown can be increased to a level such that the change in enthalpy between letdown and makeup matches decay heat.

SPC, CS, SPMU not required to be operable in PS 5 per Tech Specs 3.6.3.3, 3.6.3.2, and 3.6.3.4, respectively. SRVs not required to be operable in PS 5 per Tech Spec 3.4.2.1 ECCS and SP operability per Tech Specs 3.5.2 and 3.5.3. SSW operability per Tech Spec 3.7.1.1.

 ' Not modeled in the ET's; requires detailed thermal-hydraulic evaluation

Small LOCA is within makeup capability, but CRD cannot both match break flow and raise level.

 ' Adequate cooling with 1/3 core uncovered evaluated with MELCOR.

With normal level and with no recire, increased SDC provides mixing between downcomer and core To provide adequate natural circulation, rcise level with alternate sources including ECCS

 ' Main Steam Line Break not a LOCA in POS 5 (even in Hydro, it just drains full vessel down to steam lines, no flashing), but Feedwater Line Break outside containment requires one of two check valves in the broken line to close, and an MSIV on each main steam line to close to prevent loss of SP inventory with ECCS injection. Given closure of check valve and MSIVs, one SRV must open to provide for egress of injected water (see footnote y for POS 4 success criteria). In POS 5, following feedwater line break,200 F fluid does not flash, and level drops no lower than elevation of feedwater injection nozz.le; no syphon concern since in BWR core region 'open' to downcomer region. Thus, in POS 5, if feedwater line break is not isolated, which renders ECCS from SP unavailable after SP level drops below ECCS suction, core is still covered and can be steamed.

Whenever SRVs are used in conjunction with ECCS from SP, one of two MSIVs in all four steam lines must close to prevent bypass flow outside containment, and .wbsequent loss of SP inventory and loss of ECCS.

  " Only with forcod recirculation, can level be sufficient following small break LOCA for core-to-downcomer recirculation if CRD is only source of makeup.

Cooling option if vessel is heated and pressuriad to rated conditions (545 F,1000psig). RHR/SDC must be isolated; auto-isolation either on high pressure or low level. SRV steams at safety setpoint. HPCS or CRD can provide makeup for steaming at high pressure. NUREG/CR-6143 5-12 Vol. 2, Part 1

Success Criteria References for Section 5 [ Whitehead, et al.,1991] D. W. Whitehead, J. L. [Drouin, et al.,1989] M. T. Drouin et al, " Analysis Darby, B. D. Staple, B. of Core Damage Frequency: Walsh, T. M. Hake, and T. D. Grand Gulf, Unit 1 Intemal Brown, "BWR Pow Power and Events," NUREG/CR-4550, Shutdown Accident SAND 86-2084, Vol. 6. Rev. Frequencies Project, Phase 1 - 1, Part 1, September 1989. Coarse Screening Analysis," Vol.1, Draft Letter Report, [SERI,1992] System Energy Resourcec, Sandia National Laboratories Inc.,* Grand Gulf Updated and Science and Engineering Final Safety Analysis Report," Associates, Inc., November 1992. 23,1991 updre, Copies Available at the NRC Public [USNRC,1984] USNRC, " Technical Document Room. Specifications, Grand Gulf Nuclear Station Unit No.1,* [ Vine, et al.,1986] G. Vine, et al., "Residaa! Heat Docket No. 50-416, Appendix Removal Experience Review "A* to License No. NPF-29, and Safety Analysis: Boiling NUREG-0934, October,

Water Reactors,' Nuclear 1984.

Safety Analysis Center, NSAC-88, March,1986. 1 I Vol. 2, Past 1 5-13 NUREG/CR-6143 l

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6 Event Tree Analysis This section of the report discusses the event trees that generic system-level event trees. For LOCA initiating were developed for the detailed study of POS 5. The events, the specific system-level event trees were created I event trees for POS 5 have been extensively updated without using any generic trees. i from those used in the screening study [Sandia, Letter Report). Reasons for the extensive modifications to the The following sections discuss the event trees. Section trees are as follows: 6.1 discusses the generic event trees, both functional and system-level, for transients in POS 5. He generic i (1) A variety ofinitial conditions were considered functional level event trees for transients are provided in in the detailed analysis beyond those considered Section 6.1, and the generic system-level event trees for in the screening study. Rese initial conditions transients are provided in Appendix H. Section 6.2 ! are described in Section 3 of this report; and provides the top level of each transient-specific system- ! level event tree. Section 6.3 provides the top level of l (2) Fewer conservative assumptions were used in each system-level event tree for all LOCA initiating ! developing the detailed event trees than were events. He transfer event trees for the top level initiator ! used in developing the trees used in the specific event trees, both transients and LOCAs, are 7 screening study. provided in Appendix H of this report. Section 6.4 provider a definition of each acronym used in the event i Event trees were constructed for each initiating event trees. described in Section 4 of this report using the following information: 6.1 Generic Trees for Transients, . POS5 ' (1) He initial conditions as described in Section 3 f Two sets of generie transient event trees were produced - ne set f r c Id shutdan at 0 psig, and the other set for (2) The success criteria as described in Section 5 ,

                                   .                             cold shutdown at 1000 psig (the hydro test condition).         ;

and Appendix E of this report; and The decay heat for the first set was specified as 0.9 % of j (3) The calculations described in Appendix F of I""P **b '* "

8 ***"I "#"

This is the maximum decay heat expected when the p! ant

                  'E ""                                          is in cold shutdown, as described in Appendix F of this        !

rep rt. The decay heat for the hydro condition was Three types of event trees are discussed in this Section of , specified as 0.16% of full power,6 MW, when the <

' * '*P

initiating event occurs. He hydro test is performed after ,

(1) Generic, Functional Event Trees, a refueling utage, and the decay heat was specified as that following shutdown for 30 days, a reasorable num t nw f r a refuehng outage. (2) Generic, System-level Event Trees, and (3) Specific, System-Level Event Trees. 6.1.1 Generic Trees for Cold Shutdown, 0 psig The first type, generic functional event trees, are a set of event trees at a functional level that apply to any Based on detailed review nf the Grand Gulf prwedures, ; transient. (In this Section of the report, ' Transient' and discussions with plant staff, we developod the j refers to r.ny accident that is not a Loss of Coolant following heirarchy of core cooling options available in i Accident (LOCA).) The second type, generic system. POS 5 at 0 psig: level event trees, are a set of trees at the mitigating j cystems level that form the basis for the event tree (1) Shutdown Cooling with Residual Heat Removal models for each specific transient initiating event. ne (RHR) or Alternate Decay Heat Removal third type, specific system-level event trees, are the event (ADHR) (ADHR cannot handle heat load until , trees that model the mitigating systems response to each 24 hours after shutdown) of the 34 specific initiating events given in Section 4 of this report. For each transient initiating event, the and specific system-level event trees were produced from the f Vol. 2, Part 1 6-1 NUREG/CR-6143

I Event Trees . Level Control with Control Rod Drive (CRD), 6.1.1.2 Generic System-Level Event Trees, POS 5 at Condensate System (CDS), or Emergency Core 0 psig Cooling System (ECCS) Pump ' Bump' Table 6.1 1 is a listing of all of the generic, system-level l' (2) ECCS Injection with Discharge through Safety event trees for transients in cold shutdown at 0 psig. Relief Valves (SRVs) Tiese system-level trees are provided in Appendix H of this sport. 804 Table 6.1-2 ideutifies which generic system-level event Adequate Suppression Pool (SP) laventory for trees are associated with the cooling options, and Table . ECCS 6.1-3 notes special trees that interface with those trees directly involved m core cooling. , (3) Floodmg with Standby Service Water Crosstic ' (SSWXT) or Fire Water (FW) Table 6.1-4 indicates the interfaces arnong the generic system-level trees for transients in POS 5 at 0 psig. (4) Steaming at low Pressure with Relief through , SRV(s) and with Makeup (CRD, CDS, ECCS, 6.1.2 Generic Trees for Cold Shutdown, SSWXT, FW) 1000 psig ; (5) Steaming at Rated Pressure with Relief through Based on detailed review of the Grand Gulf procedures, 1 SRV(s) and with High Pressure Makeup (CRD and discussions with plant staff, we developed the l or High Pressure Core Spray (HPCS)). following heirarchy of core cooling options available in l l 'ne initial conditions considered were as follows (See Section 3 of this report for more detail.): (1) Shutdown Cooling with Reactor Water i (1) Recirculation: Forced or Natural l A!14 (2) Shutdown Cooling: RHR Train B or ADHR [ (after 24 hours) Pressure / Level Control with RWCU letdown, } and CRD Makeup - i (3) Main Steam Isolation Valves (MSIVs): Closed or Open (2) Depressurize and Use the 5 Cooling Options f for 0 psig (See Section 6.1.1) i (4) SP Level: 18 feet 4 inches,12 feet 8 inches, or i empty with 170,000 gallons of water in the (3) Steam from Hydro Conditions -[ Condensate Storage Tank (CST) available to ; HPCS The initial conditions considered were as follows (See ,[ Section 3 of this report): .t (5) Containment: Closed, Open only Above ;j Grade, or Open Below Grade (1) Recirculation: Forced .! (6) SRVs:Two Available. (2) Shutdown Cooling: RWCU l[ 6.1.1.1 Generic Functional Event Trees, POS 5 at 0 (3) MSIVs: Closed P5i8 I (4) SP Level: 18 feet 4 inches,12 feet 8 inches, 9 As an aid in developing the generic system-level event or empty with 170,000 gallons of water in the .[ trees, a set of generic functional event trees were CST available to HPCS .e produced that follow the core cooling hierarchy. Figures

{

6.1 1 through 6.15 are the generic, functional event (5) Containment: Closed. Open only Above ! trees for transients in POS 5 at 0 psig. Grade, or Open Below Grade i i I Vol. 2, Part 1 NUREG/CR-6143 6-2

Event Trees (6) SRVs: All Available. 6.3 Specific System-Level Event 6.1.2.1 ceneric Functional Event Trees, POS S at Trees for LOCAs 1000 psig The top level system-level event trees for each specific As an aid in developing the generic system-level event LOCA initiating event are given on Figures 6.3-1 trees, a set of generic functional event trees were through 6.3-9. The lower level transfer trees for these produced that follow the core cooling hierarchy. Figures top level trees are provided in Appendix H of this report. 6.1-6 through 6.1 10 are the generic functional event trees for transients in POS 5 at 1000 psig. 6.1.2.2 Generic Systern-Level Event Trees, POS 5 at 1000 psig Tcble 6.1-5 is a listing of all of the generic, system level event trees for transients in cold shutdown at 1000 psig. These system-level trees are provided in Appendix H of this report. Table 6.1-6 identifies which generic system-level event trees are associated with the cooling options. The special event trees for the hydro situation are the same as those given in Table 6.1-3 for the O psig case. Table 6.1-7 indicates the interfaces among the generic system-level trees for transients in POS 5 at 0 psig. 6.2 Specific System-Level Event Trees for Transients The top level system-level event trees for each specific trusient initiating event are given in Figures 6.2-1 i through 6.2-25. The lower level transfer trees for these : top level trees are provided in Appendix H of this report. l I N l l l l l l l Vol. 2, Part 1 6-3 NUREG/CR-6143 1

.1

m Z < C

  $                                                                                         ECCS-a.VL-CTRL          SEQ #      OUTCOME       h 0         l      PLANT-STATE-5        SHUTDOWN-COOLINGNORMAL-LVL-CTRL l                           l                 l n                                                                                                                                          $

lc d O b c w c: initial Plant State, 5 b: Shutdown Cooling with RHR/SDC or with ADHR c: Level for shutdown cooling rnointoined with normcl makeup d: Level for shutdown coohng restored with ECCS purm bump'

l. %

t= "=: C _Q:=:I2':::: = _ 3J".mL % - w , ,

wpm ' - -

[E 5 A .eas a we gi e=toH heet 3DC .&empWS sg:a-=.mw. a _ . su . [~ %YtNo~rtm% ~4 . m L t OK 3 -* 2 OK

                                                                                                    -4                   3T       ECCS 4                     4T      FLOOD 5T       OVERFILL 0                  6T       LOCA
                                                                             %                                           7T       FLOOD
                                                                             ^r                                           8 T     ECCS
                                                                             -                                            9T      OVERFILL 2
                                                                             -                                           10 T     LOCA Ii T     ECCS E
   *o a                                                     Figure 6.1-1 Functional Tree SDC 0 psig

;y        ECCS-OR-FLOOD                                             ECCS                                 FLOOD                                     SEQ #     OUTCOME n

a b c a: Use ECCS to ccd core, or FLOOD core using service water or fire water b: ECCS for transients with SRV s c: FLOOD with service water or (fir)e water t ECCS and , ired etmtoinment sweait works or or caE. t oint A[nd 4: Overf 4 wit 3: operN fois to use ECCS or no SRV in relef works, CgC MSYs open 5 T's :: artro,m',grrJecc5 -'a = = -

SW;'i'stv Mo",',4T,A'P#ihe""f"A Ee'*cJ,Tq",p'a%"Anairl"'

from erw1ronment 1 OK 2 OK a cn ., 3 T STEA M 9 4 T OVERFILL n 5 T CD-CC G T STEA M 7 T OVERFILL 5 8 T LOCA 9 T CD-CC 7: FLOOD and required containment stport works 8: FLOOD faits, or amtoment svart for FLOOO fails 9- OverfM with FLOOO sotrces. WYs open 10.- Steam out orms contcnnment in ouxecry tWng fods core cookevj equement or pment necessary fw core cooEng equpment ,of f out 2: C N O 7 N

o $

& H I w Figure 6.1-2 Functional Tree: Water Solid 0 psig o 2

5' 5 a w g _ . _ OUTCOME 5 B OVERFILL OPER-STOP-0 VFL SEQ # - x r 5 a b a: Overfill vessel, MSIVs open b: Operator action to stop overfill s om ng. Conservot fy e ng rs only core c ton lef t 2: Operator fods to st loodng before core cooling equpment is floode out

                                                                 '                             1 T STEAM r-   2
                                                           '                                  2 T  CD-CD

.N Figure 6.1-3 Functional Tree: Overfill 0 psig

 .N LOCA-SDC-PIPE              LOW-LEVEL-3                      VALVES-CLOSE g                                                                                        SEQ # OUTCOME
 ~

o b c a: LOCA in RHR b: Autoisolate s/SDC ignal to or MOVs ADHR piping outside 8 and 9 on lowcontainment level 3 c: Close MOV 8 or MOV 9 in response to Autoisolate signal

     * 'Tb?m".#.,*.4' ',,f'.?".dT#' 2Tr4t
        @ dt7 N M E Tcc$  #

D' for D t D 2: ot"cIb* met'w LocAcuMt"antM N C E mva"%e w 'L Q 4*J .7L"J* %'"??? 1 T ECCS 2 2 T CD-CB o 4: Z C a y s E

 -                                                                                                      -i Figure 6.1-4 Functional Tree: SDC LOCA 0 psig                 g

T E! 11 n m STEA M -Ill-PRESS SEQ # OUTCOME 9 o STEAM STEA M-LOW-PRESS B x s

 -                    a                              b                                   C w

a: Steam the core at low or high pressure b: Steam the core at low pressure c: steam the core at high pressure 5: Steomog et rated vessue works (SDC isosoted) 1 Stersnrq of tow pesstse works 6: Steam out opm ceriterment f#s core cocang egmment, 2 No SRV works si rmnurj rehef mode et low yesstse or no ferAetp for steamng Ct rated gressure. 3 Steam out cran enntainment into ausesy tW Cor9 h. fs4 core coo 6ng M@mpnt. Core dnmooe 7: RtRjax; owf/or ADfR m overNess.urires de to foAre 4: Steam out com WNs fats core ecchng'eotgment. .o We in response to operator oct on or en responsa or no makeio for steammg ot be pressse =<th to oute esokAe ssW on kwe level 3. Core dN. WXs cpert Core dyTWJge VfSSet open to unwonment vessel open to erwonment M tvoken $DC bne thrcuyh cpan nrNs

                                                          '                                                                 1    OK i                                                                                              ;                             2    OK 2                                   c                             3  T CD-CC e                                                                                           -7                             4  T CD-CH k                                                       3                                                                 5  T CD-CC

6 T CD-CD E-P U Figure 6.1-5 Functional Tree: Steaming 0 psig n

                                .e              ~.     --    , -. -                ,.      -

i Event Trees Table 6.1-1 Generic System-Level Event Trees for Transients, POS 5 0 psig Tree Description IE Specifies fraction of time in POS SH, and fraction of time initially on RHR loop B and initially on ADHR, or fraction of time in Hydro (see Part B) SDC Shutdown cooling initially on RHR Imop B ADH Shutdown cooling initially on ADHR HYDRO Shutdown Cooling in Hydro (Discussed in Section 6.1.2) L Level control for RHR Ioop B shutdown cooling with normal makeup LA I.evel control for ADHR shutdown cooling with normal makeup R Level control for RHR Loop B shutdown cooling with ECCS pump

bump
RA Level Control for ADHR shutdown cooling with ECCS pump ' bump'

,E                   ECCS with SRV(s) in relief mode, when initially on RHR Loop B SDC EA                ECCS with SRV(s)in relief mode, when initially on ADHR SDC EC                Containment support for E or EA trees F                 Flood core with Service water or fire water FC                Cootainment support for F tree S                  Steam core at low pressure P                  Steam core at rated pressure OF                 Overfill vessel with MSIVs open AISD               Auto Isolation of SDC on High Pressure (135 psig) when initially on RHR Ieop B SDC AIAD              Auto Isolation of SDC on High Pressure (135 psig) when initially on ADHR SDC ll                Interfacing LOCA in SDC line outside containment ASISO             LOCA in SDC Line Outside Containment that is Isolated on Low Level 3 CC, CC1, CC2      Containment trees for core damage CB,CBl.CB2        Containment trees for core damage, vessel open to outside environment CSTM              Susceptibility of equipment to steaming out open MSIVs CAUX              Susceptibility of equipment to steaming out open containment into auxiliary building SEE NOTE 1 for Explanation of Following Trees ending with 'P', 'X', 'N', or 'NP' LP                L tree with loss of offsite power (LOSP)

LX L tree with LOSP and Train 3 Crosstie (XTIE) LAP LA tree with LOSP Vol. 2, Part 1 6-9 NUREG/CR-6143

Event Trees Table 6.1-1 Generic System-Leiel Event Trees for Transients, POS 5 0 psig (Continued) Tree Description LAX LA tree with LOSP and XTIE RP R tree with LOSP RX R tree with LOSP and XTIE RAP R tree with LOSP RAX R tree with LOSP and XTIE EP E tree with LOSP EX E tree with LOSP and XTIE HPSWR E tree with LOSP and No XTIE (like an 'N' or 'NP' tree) EAP EA tree with LOSP EAX EA tree with LOSP and XTIE HPSWA EA tree with LOSP and No XTIE (like s.n 'N' or 'NP' tree) ECP EC tree with LOSP ECX EC tree with LOSP and XTIE ECNP EC tree with LOSP and No XTIE FP F tree with LOSP FX F tree with LOSP and XTIE l FNP F tree with LOSP and No XTIE < 1 FC tree with LOSP ; FCP FCX FC tree with LOSP and XTIE j l PP P tree with LOSP PX P tree with LOSP and ATIE SP S tree with LOSP SX S tree with LOSP and XTIE SNP S tree with LOSP and No XTIE ILP IL tree with LOSP ILX IL tree with LOSP and XTIE 1 . OFP OF tree with LOSP OFX OF tree with LOSP and XTIE AISDP AISD tree with LOSP 6-10 Vol. 2, Part 1 l NUREG/CR-6143 l l

                                                                                                                  ..            1

Event Trees Table 6.1-1 Generic System-Level Event Trees for Transients, POS 5 0 psig (Continued) Tree Description AISDX AISD tree with LOSP and XTIE AIADP AIAD tree with LOSP AIADX AIAD tree with LOSP and XTIE CCP, CCIP, CC2P CC trees with LOSP CCX, CCIX, CC2X CC trees with LOSP and XTIE CCN CC trees with LOSP and No XTIE CBP, CB1P, CB2P CB trees with LOSP CBX, CB1X, CB2X CB trees with LOSP and ATIE CBN CB trees with LOSP and No XTIE CSTMP CSTM tree with LOSP CSTMX CSTM tree with LOSP and XTIE [ CSTMN CSTM tree with LOSP and No XTIE CAUXP CAUX tree with LOSP CAUXX CAUX tree with LOSP and XTIE CAUXN CAUX tree with LOSP and No XTIE l Note 1: In the P trees, offsite power is lost. In the X trees, offsite power is lost and both train 1 and train 2 of emergency power are lost, ar.d train 3 of emetgency power has been crosstied to either train 1 or train 2 buses, and HPCS is lost. In the N and NP trees, offsite power is lost, both trains 1 and 2 of emergency power are lost, train 3 of emergency power is available and no XTIE of DG 3 to either train 1 or 2 is attempted. P trees have the following systems failed: those that require offsite power. X trees have the following systems failed: those that require offsite power, those that require both trains 1 and 2, and HPCS. N and NP trees have the following systems failed: those that require offsite power, and those that require train 1 or 2 of emergency power. Vol. 2, Part 1 6-11 NUREG/CR-6143

                                                                                                                                                               \
                                                                                                                                                               \

l Event Trees ! Table 6.1-2 Generic Systern-Level Trees for Core Cooling, POS 5 0 psig l l I Core Cooling Method Constituent Generic Trees

1. Shutdown Cooling with level Control IE, SDC, ADH, L, LA, R, RA, LP.LX, LAP, l LAX,RP,RX, RAP RAX i i

2. ECCS Injection E, EA, EC, EP, EX, EAP. EAX, ECP, ECX, HPSWR, HPSWA, ECNP

3. Flooding F,FC,FP,FX,FCP,FCX,FNP 1

4. Steam at I.ow Pressure S,SP,SX,SNP l

5. Steam at High Pressure P,PP,PX i l

l i Table 6.1-3 Special Generic Event Trees, POS 5 0 psig ! Concern Addressed Constituent Generic Trees Overfill with MSIVs Open OF,OFP,OFX l Interfacing LOCA in SDC Components AISD, AIAD, ASISO,IL, AISDP, AISDX, AIADP, AIADX,ILP,ILX l Steaming out Open MSIVs CSTM, CSTMP, CSTMX, CSTMN Steaming out Open Containment into Auxiliary CAUX, CAUXP, CAUXX, CAUXN Building Containment Status for Linking with Plant Damage CC, CCI, CC2, CCP, CCIP, CC2?, CCX, CCIX, States CC2X,CCN l Coatainment Status for Linking with Plant Damage CB, CBI, CB2, CBP, CBIP, CB.".P, CBX, CBlX, States, Vessel Open to Environment Outside CB2X,CBN l Conta'mment ' ( 6-12 Vol. 2, Part 1 NUREGICR-6143

                                                                                                                                                        .      l

2C R K K K K K ,K 8 4 4 - E O l l l H O O O O O 4@ a a 7 a, a, K a, K . T l l @ @ @ @ ,@ 32 6 6 9 7 5O 6O O b b c c i j xv a a a a a a l a@ a@ l D A I A g I - D S I A g k . O S t 5 0 l A a - X U A 5 5 C a a _ t

  'g             h i

s T 9 p S 1 C a . 0 5 L 3 3 S I u b b O P r . o F t f O h h m m t t a . s e c f a 7 . r P l a - t e I n . e e S r s w z 8 a r T . 4-I. t f y 6 i e h l - c F d d n n q q T . C E p p _ A 2 2 E b e o b b . 2 2 E b e o b b . A R f R f

         -      A s

r L a . f e s n . a r L a . T O D D M X l e e C i S I S IA T U r D D A A A C C F S S A - O L I TI S A L L R R E E E F F S P I A A A C C - ge 5~ ?U yChO8 65

Event Trees Table 6.1-4 "otes t

1. 'P', 'X', 'N', and 'NP' trees are not listed, since they are special cases of these trees

a. Some system for SDC works (RHR Loop B, RHR leop A, ADHR).

b. No system for SDC works, or operator fails to institute alternate SDC following loss of operating SDC system.

c. Level maintained / restored for recire or for enhanced SDC.

d. Level / makeup isolated for recire or for enhanced SDC, but no long term makeup for leakage with normal makeup, ECCS, or any other source.

c. Insufficient level, no operator recognition.

f. Insufficient level, operator recognition.

g. MSIVs closed, overpressurize RHR/SDC with overfill from CRD or CDS.

h. MSIVs open. overfill with CDS.

i. Level: .tored for recire with ECCS pump ' bump *, or overfill with LPCS/LPCI with MSIVs closed (no overpressurization of RHR/SDC).

j. Level restored for recirc with ECCS pump ' bump'.

k. MSIVs closed, overpressurize RHR/SDC with overfdl from HPCS.

1. MSIVs closed, overpressurize ADHR with overfill from HPCS, LPCS, or LPCI.

m. MSIVs open, overfill with HPCS, LPCS, or LPCI.

n. Failure to restore level with ECCS pump

bump *, due to failure of ECCS.

o. Operator fails to attempt ECCS pump ' bump' to restore level.

p. ECCS works (EC is containment support tree for ECCS).

q. ECCS fails, or operator decides to not use HPCS with 1 SRV ql: ECCS fails, or operator decides to not use HPCS with 1 SRV, or operator cannot isolate ADHR

r. Operator .tils to use ECCS, no SRV works in relief, or operator decides to not use ECCS with MSIVs open.

s. Operator fails to use ECCS, no SRV works in relief, or operator decides to not use ECCS with MSIVs open.

t. Operstor uses ECCS but MSIVs open (ECCS lost).

u. Operator fails to isolate ADHR and overpressurizes ADHR using ECCS.

v. Containment support for ECCS works.

w. Loss of ECCS due to loss of containment support.

x. Steaming from SP to vulnerable equipment locations, and failure of core cooling equipment due to steam. Transfer to CC tree (see note all).

y. Flooding works (FC is containment support tree for flooding).

z. Flooding fails.

al. Operator uses flooding but MSIVs open. , a2. Containment support for flooding works. , a3. Equipment necessary for core cooling is flooded out. Transfer to CC tree (see note all). a4 Equipment necessary for core cooling fails due to steaming from flooded containment. Transfer to CC tree (see note 11), a5. Steaming successful for core cooling, containment open, evaluate effects of steam on core cooling equipment. a6. Steaming not successful for core cooling. Transfer to CC tree (see note all). a7. LOCA in RHR/SDC line outside containment, not isolated, cannot be mitigated. Transfer to CB tree (see note a12). aB. Operator stops overfdl out open MSIVs. a9. Operator does not stop overfill out open MSIVs, flooding damages core cooling equipment. Transfer to CB tree (see note 12). a10. LOCA in RHR/SDC line outside containment, isolated on low level 3. ASISO logic is identical to E logic; fault tree linking will remove LOCA scenarios from E logic (LOCA has already occurred and been isolated) all. CC is containment state event tree for core damaged. al2. CB is containment state event tree for core damsged, and reactor vessel open to environment through: open MSIVs, or broken unisolated RHR/SDC line. c13. (This footnote no longer used in transition matrix) a14. Core cooling equipment not damaged by steun. al5. Core cooling equipment failed by stern, MSIVs open. Transfer to CB tree (see note al2). a16. Core cooling equipment failed by steam, MSIVs closed, containment open. Transfer to CC tree (see note al1). a17. Failure to open one SRV in relief, MSIVs closed. Pressurize. a18. Iow pressure steaming fails, MSIVs open. Transfer to CB tree (see note al2). a19. Steaming successful, MSIVs open, evaluate effects on equipment. bl. No ac power at all (LOSP, trains 1,2, and 3 fail); core damage, transfer to CCN tree. b2. SDC/ADHR isolated on either high pressure (135 psig) or on low level 3; sequences are like transients with loss of SDC. b3. LOCA in SDC/ADHR outside containment due to failure to auto-isolate on high pressure (135 psig) NUREG/CR-6143 6-14 Vol. 2, Part 1

F y STATE-S-l!YDRO IIYDRO-COOLING SEQ # OUTCOME n O ' 1 OK 2 T DEPRESS 3 T A UTO-DEPRESS 4 T OVERPRESS a: Plant State 5, Low Decay Heat , Hydro Condition, Water Solid, 200 F, 1000 psig b: Coolina in Hydro State with RWCU recir :ulation. Pressure Control with RWCU Letdown, -and CRD/CDS makeup t nx7 , w+o coonng. one raw oveo nessue contro

                  ?                               I $N nYsleD "oddw;O""*                      '#     "d g                               4. o<erpeeswee to dhr setpo,nts Z

d o B' y Figure 6.1-6 Functional Tree: SDC in Ilydro $ Y 3 3 _. . _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ ___-m-______ums__ - _ _ _e __m -

tT1 Z < C b SHUTDOWN-COOLING SEQ g OU'.'CO M E d

            @            DEPRESS                M AN U AL-DEPRESS                                                                    a n                                                                                                                        "

o b

h % w a b c l i 3 1 T LEVEL i

2 T ECCS i

2 1 3 T OVERPHESS e a: At Hydro Pressure with Normal Hydro Cooling Lost b: Manual Depressurization to Use Normal Shutdown Cooling Systems (RHR or ADHR) C: Normal SDC Systems Work I W M*,"*i'at M b . ~ a - 3 4.",Js#s74"# Lng , nw. e w

                    +d"' e       J".,s'J-E, vnJ r w sie           .f7 ?4 ifcs"n %

E

3 Figure 6.1-7 Functional Tree: Alanual Depressurization in Ilydro

E N AUTO-DEPRESS RWCU-COOLING SIIUTDOWN-COOLING OUTCOME SEQ # 5

a b c ? ', 1 T LEVEL q t,

                                                                                          ?                            2 T LEVEL
                                                                                          'd 3 T ECCS a: Automotec<my Depresstrized from itdo to bw pressure

b. PWCt) Racercdote cordmues to work c: Normal SDC AvehNe t Cool wdh RWCU Retirculate et bw teessure. Trnfer to tevei Control fcv rxwmat state 5. not in Hydo 2- No Coo with MCU

3. tkverws '( works. Transfer to Level Contret 4: > CE tb RWdu SOC. $romfer to ECCS few ememne 2 ate *> no tyto Z

C O Y s E ~ H w Figure 6.1-8 Functional Tree: Auto Depressurization in Ilydro Q

m Z & C E iE OUTCOME 9 DEPRESS-SAFETIES SEQ # O W OVERPRESS SAFETIES f i a b c e t , 3 1 T AUTO-DEPRESS

2 T STEAM-IlY DRO I

i 2 3 T CC-CD a: Overpressurize to Safety Volve Setpoints b: Safety Vo!ve opens at Setpoint

?           c: Oper ator Depressurizes with Safety Relief Volve
=

se V Ves? bals.Pht M 4 4:

     , '{o[evd33"J'iiJ2 is.J "sM i swevy E

W Figure 6.1-9 Functional Tree: Overpressuriistion in Ilydro 3

l' T8 H"U E M la O D v C C o T - m U KC e O OC R - t o - T a d r -

      #                 e                          y 12 H                           l I

Q i n E U . S m C a e W n S t R io t e . e o id T r n n o l a n h C io O it t R c D ' w o r n u Y d F l I ' e r y 0 1 H T u 1 A ,' s 6 i v s e in e r i r u A- U P s ig E e F T S o it 2' r e 7 d H y f S a a , O J" i R t f _ D Y a f O s

                                 ?,                       _

I I n Wl M ia m % A a m a T L E e e T S R t S % s -

: l a b or N. ya ~ Ie ZCha8:o&gw

Event Trees Table 6.1-5 Generic System-Level Event Trees for Transients, POS 51000 psig Tree Description HYDRO Hydro Condition, Shutdown Cooling Initially on RWCU Recirculation, Pressure Control with RWCU letdown and i CRD/CDS Makeup DEP Depressurization Tree for Hydro ADEP Automatic Depressurization Tree for Hydro HYHPA LOSP, No XTIE, Train 3 Available OVPR Overpressurization Tree for Hydro PISOL Steaming Tree for Hydro ADEPP ADEP Tree with less of Offsite Power (LOSP) ADEPX ADEP Tree with LOSP and Train 3 Crosstie (XTIE) l OVPRP OVPR Tree with LOSP OVPRX OVPR Tree with LOSP and XTIE PISLP PISOL Tree with LOSP PISLX PISOL Tree with LOSP and XTIE Table 6.1-6 Generic Trees for Core Cooling, POS 51000 psig I Core Cooling Method Constituent Generic trees

1. RWCU Closed Loop Cooling HYDRO

2. Depressurize and Use Non-Hydro Cooling DEP, ADEP, OVPR, ADEPP, ADEPX, OVPRP, OVPRX, (See Section 6.1.1)

HYHPA, and Section 6.1.1 Trees

3. Steam from Hydro Conditions PISOL, PISLP, PISLX 6-20 Vol. 2, Part 1 NUREGICR-6143

Tchie 6.1-7 Tree Interfaces for POS 5,1000 psig' Tree Tramfers - I S IIYDRO DEP ADEP OVPR PISOL llYllPA Part A Trees Other IIYDRO a b c n al coK ,11 DEP e d ADEP f IIYllPA m OVPR g h i PISOL j k

1. 'P', 'X', 'N', and 'NP' trees are not listed, since they are special cases of these trees

a. Lose RWCU Cooling , but Maintain RWCU letdown

b. Lose CRDI, but maintain RWCU letdown, hence depressurize e c. Lose RWCU letdown, pressurize to SRV Setpoints

 $        al. OK if maintain RWCU Cooling, ud Pressure and Level Control at flydro Conditions

d. Transfer to Part A trees, non hydro case, if depressurize

e. If do not depressurize, decay heat raises pressure to SRV Setpoints

f. Pressure is Emv. Transfer to Part A trees, non hydro case

g. If Depressurize with SRV in Relief Mode

h. If SRV works at Safety Setpoint, but do not depresurize

i. Safety Valves fail to open at safety setroint. Assume Vessel Fails, core damage, transfer to CC tree Part A

j. Transfer to CAUX tree in Part A , non hydro case, if steaming is successful

k. Steaming Unsuccessful, core damage, transfer to CC Tree Part A

11. No ac power at all (LOSP, trains 1,2, and 3 failed); core damage, transfer to CCN tree

m. Transfer to O psig trees given in Section 6.1.1 of this report

n. Only train 3 available l

l Z ! C h i O I b lc l 6 % l E w N I l l

a l 1 i i Event Trees oo o a o a o o o

         >  dd     d     d   d    d      d    d     d T    T 8    TT T

T T T

                                  -      -    -   z-T 5    khasw!awkwSSS!SS!S 555!55!5$$

o ""*******9 ccxestscRRRRsR*RRR M 8 I E H E j :::

                                                                          .n W                                                                 m W

d w i 1 O E m i E u ' E E E t 1 d I r

         $                                            5 e

1 a

         ?                                         .

s aw NUREGiCR-6143 6-22 Vol. 2, Part I

4 b .N m EC-5 POSS PRESS STAfD RESRW RLOSP DV1-2 tPCSA XT G RWLS CRD1 RWCU5 SEO l OUTc0ME o

1 *NOT-VALD 2 eNOT-VALD 3 eNOT-VALD 4 eOK 5T DEPS i I '

3 6i ADEPS i 7T OVPRS' i 8T OVPSP i , 9T HYI43A i 10 T OVPSX 11 i eCCN i 12 I OVITtS i i 13 T OVPSP 6 a een ==cu .e mus w a www em I , gT F 16 i *CCN c: STAHD specifies status of MSIV's and RECIRC when in hydro mode. Set ISMSV and ISTRC botb to 'Yes' in oil event trees transferred to. b

      ' %TJ",A87d*.:,C@.".'42 '"

(M T';;2 . %. e z C W m O T s E & H g Figure 6.2-2 ElC-5 Tree j w =

a 1-1 ( DD D D DL D D D D - LL L L L L L L AA A A A A A A A VV V V V V V V V W C -- - - -T T

                                                  -   A-WT       T NT C       TT         T        T T       OO         O        O OPPPOPSOXXXOXCO               ACN U

O NNuAAANAAANANAAANAWNAAANE**

               ** LLE*LLE*E*LLE*E                        *LLE TTTT TTT T tit                    TT TTT Ti l                            1 01234567 0

0 123456789D12345678H22222222 1111111 5 , l A C D S l S B ii ii ,i in C D S l 2 R H ia D A l e e 7 C gi , g T r P t I l I D 5 _ S A D l E l F E 3-m 2 u 6 l S m E T u g X i l F A S C l W 2 IV l D - P . S . O . L P l H D A E e - l S . S l E R P . 5 5 0 - P l H 5 D E l

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4 S N k l E1TSH l POSS l FPESS l 155D0 l FLOSP l DV1-2 l WCSA l XTED l OPSDC SEO (l RESCS OUTCOLE l N00VP f SDCDS l SDCA l n

b 1 *NOT-VAL D 2 *NOT -VALD 3T E i 4 T L 5T E 6 *NOT -VALD 7T E

                                                                                               -              8       *NOT-VALD 9T      E i       V T      LP i        11 T    LP 12 T     EP 13       *NOT -VALD 14 T     EP 15       *NOT-VAL D 16 T     EP 17 T     WSWR i       E T      EX i       N T      lx 20 T     EX 21       *NOT-VALD 22 T       X m                                                                                                 23       E.NOT-VALD b$                                                                                                24 T EX
                                          .                                                                  25 T     *CCN 26       *NOT -VALD

D[AA".

                              **          a ::::rt t,"7ca:ItU Jh$74"Ne" " *

b: NOOVP is rio overpressurization of SDC; MV 8 or MV 9 is closed trees transferred Set OPISto. (NOTE:

and SDCL to 'Yes' P, PP, and in all PX Trees event) e us,. . - *. ~., t o 2: C b o s tri n g m - H g Figure 6.2-4 EIT511 Tree

M<a~d a= - DD D DL D DL D Dt D LL L L L L AA A A A A A a A E VV V V V V% V C -- - -T V- - A - NT C TT T T T W T T T O) O O PPPOPOP XvXOXOXCO ACN U O NMAAAANANAAAANANA

                   *eLLLE*E* ELL [*EeEEAAANANE**        LLE*E iTTT T iTTT T                TTTii T             TT J                              1 123456789 012)116E78N 4               01234567 O                          1      1        11       22222222 E

S l , A C _ O S l S 8 C

                          ,i           ie                :i D

S l 2 R H ii D A l . e l W b T e r - S 1 C 1 _ S 5 E l R V I E C w 5-l 2 B 6 [ T e r X u l g A S C I' iF ._ W $ Y _ l 2 m' d I V 0 .C T -. l P m.a d i S O. A.b l R . ::: , H .. l D S A G e grTg::::E. I .

S - l E F F y*W h'

                                                                                            .e 5

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m@n:4I% = s e*Nm <$ ". o5 -

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            )                                               t e                  y s                  r e                    2

( y v P s .e 6 S S e - r O e Cn r R t a , i u g w Id C l P& Lo i F F .8 f 8 B S b mg oof O C pon t R _ E D _ l

ora of p 8 s N .

L nt I . B ew S i r D RC, oe rv n S iC RE - i t e C t

                                                          ,e        .

ie n l v rv s e S mme oe. v S c eu b o e - E ts se sr 0( t g syoa R Ct P

                                                               .h       D SSe     ed     to m

Ct s s l r i r t S Doy e S Sl e f o Ts .f h , O h xn . P ;st vi r e e rwr a n o l t8e k5t H a c o i$e t o 5 e pm r f n 8 , pos snt de r 2 olo, ia is E ts ,t fHo o f n H l t l OCe SPv 5 sR s r e ECSe 8 2 ot a I E l : b c a Cb Nh3 ~ zCbasnn6E-

T Mi n E2C-5 POS5 PRESS STAHD RLOSP DV1-2 HPCSA XTEB SEO # OUTCOME f b 1 *NOT-VALD 2 eN0T-VALD 3 eNOT-VALD 4 T OVPRS1 5 T OVPSP i 6 T HYHPA i 7 T OVPSX

                                                                              .L-       8  T   eCCN e

h c: STAto specifies status of MSIV's and RECIRC when in hydro mode. Set ISMSV ond STRC both to 'Yes' in as event trees transferred to. 1: 'S' added to transfer OVPR irmf+es that RWtS and US replace RWCU ond RWCUC (r live in generic trans tr ee b e m 5 Figure 6.2-7 E2C-5 Tree

TE Hj= DUO LLL D L E AAA A M VVV V O C TTT A W NT A OOO PPPP5XXXXCO l O NNNAAAAAA.EEtLLEE**AA#AAAACN

                      *eeLLEEL4 TiTTTTTTTiiTTT
 ,.             f                                                                                           .

O 123456789012345678 1 1 1111111 E S l A C -

 -               D S

l S B

 . .            C           ia      ,1            ii D

S l C D S Ig ll ll P O l B T E ij e e X r l T A 1 S 1 C 5 W D 2 l 2 E 1 8-V D 2 l 6 P e S r O u L g R i l F F d - C e C b Cr P ne e L o l n t. s trW lr H D u A b s Tt Fe O R A i tes D S i I 1C te W l 8 Sy n e m e Do i S A g v S ,k wr C.e , E R m eUp p m e W _ P tsL F

                                                                           ,    as rt        3 l                                                          y        t n     =

se . Ie v e S . t S Cu _ m - Ke de e O Ds Ss( (O P e fPoL i g .e a l ety c e4 - H a s tMhe n rc t r . 5 psy ima m 0 2 o ereh o f sd e - E tHt e e ie 4 H l ff o 5 sWt s e C C 2 D oNs P4 E s l L e e tr

      <b uh3 m                                                   %

0 ZCEOs&rw

td

    *1,'

k NOUVP RLOSP DV1-2 FR3A XTED OPSDC SEO f OUTCOME E2TSH POSS FRESS ISSDB E o x

     &                                                                                                                                                        1   *NOT-VALO E
     "                                                                                                                                                      2     eNOT-VALD 3     eNOT-VALO
                                                                                                                                               ,             4 T  E 5 T   *E
                                                                                                                                               ,             6 T  (P 7 T  *EP 8 T   etPSWR c                                                             ,             9 T  *EX i              10 T     *EX
                                                                                                                                          '                  11 T eCCN 12       *NOT-VALD

o. Loss of SDC common suction lina in POS SH This ranrkes at SDC isevoitie. PJR/SDC Loop B n! W operot<9 Note: Loss of common suction Ene is due to W 8 a W 9 lohng closed, and does ret render cry ECCS tron unavoe tle.

h POCVP is ro overgvesteiro1 ion of SDC * %3 W 8 or W 9 es cbsed set OPG orvj it Yes' in oli event trees transferred to. (NOTE: , P/, ond PP 1*ees) 0 O c: E2T5H is not m tratwdng event in IW.J b

            *C E                                                                                          Figure 6.2-9 E2T511 Tree i

o r

     .N
     ~

E2V5H POS5 PRESS ISADH f00VP RLOSP DV1-2 HPCSA XTEB OPSDC SEO f OUTCOME o b 1

TOT-VALID 2 *NOT-valid

                                                                                                                               .3   *NOT-VAL'D 4 T  EA 5 T  EA 6 T  *EAP 7 T  *EAP c                                                                             8 T  *HPSWA
                                                                                                                    ,           9 T *EAX I

10 T *EAX 11 T *CCN 12 *NOT-VALIO

o. Loss of SDC comrnon sucthn Ene in POS Sit This renders 08 SDC unava6Lle, A[NR o initicGy oteat,ng w Note: Loss of common sucion line is due to W 8 or W 9 fcAng closed, and does not render ony ECCS tron talovc&tle.

t>: FKXNP is no overpresstsiratum of SDC piping. IN 8 cw W 9 is closed Set OPIS and SDCL to Yes' in o8 event trees transferred to. (NOTE. P, PX, and PP 1rees) l c; E2V5H rs not an irstiotry event in ifYI)RO Z i C E O 5 7 t g 8 S H g Figure 6.2-10 E2V5H Tree j

w =

l l l

3a~ dH DD D DDD . EE E EEE PP P PPP OO O OOO LL L LLL D EE E EEED - L VV V VVVL _ E A EE E EEEA _ P DD DDDV M O V H - - D- H 12t PO- - - - C TC F OHHRGTTTT T O12CATTGTRODGAAD5OOOO ODSHHDFOO U NSSRRS5NNmNA5RRAANNNN eeA***AeeeeeA*+***+** O iTiTTT T TTTTTT l . I 2345678 9 1 01 O U1234567891111111122 - E S L ,' ,* C ,' ,' O S L e e R i' I' I' ii r H R T . 1 1 5-S 1 1 1 L 1 P O 1 1 D 2 E 6 T X e r . u ig A F S ,' C - P H 2 1 V D P S O L R C D S G S S E R P S . S O P H 5 1 H zCh9nW&%w ?O < EPEE-

TEHg E R SO d'BN . leCG iDI O0 O O F aS o , LL L L t _ e . E AA A A M VV V V ot u t O -- - O t e C TT T TR t T OOCOHOD iS NNDNDNN Ps t U . O * *S*A*F Sa e e Cu . r . T T T LSs e T _

     #                               R           e .

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                                             .t e             2 S                v             1 e.dev o.ilno                   2 6

r ev e . P e re9 r u S wr ig O O O oe pftd F N snn ean ue a C it rq _ D S f st se8 _ S _ I f eb e o rsteuh _ S f t S E o ll r _ R t ao P s n e f s n S S lo evi se O Br P is yC lu _ r i . eD a 5 P vSf Se 1 O re T On oh _ Nift _ a _ <9 ". P ;

mb $me9&~

m Z 8 C m H [6 DV1-2 HPCSA XTED ADHRR OPSDC SEO f OUTCO W O TSASH POSS fHESS tS50C SWLOS RLOSP MLOS n b d d a

 .                                                                                                                            I        *NOT-VAL O W

2 *NOT -VALO

                                                                                                                    ,        3 T       E 4 T       E
                                                   " l"     B                                                                5         *NGI-VALO 6 T       FPSWR

r 7 T FX i '

8 T *FX 1 9 T *CCN

                                                    "                                                                       10          aNOT-VALO
                                          ""                                                                                 11         *NOT -VAL 0 a SwlOS es foaure of. SDCD SIXE. LPC1, SSWXT.

Set o# these events to loed m every event tree transferred to b: Loss and ROSP. results in bss of of SSW (utiotry [ vent) sinceRLOSP fryts TR.w and i Ch f y mstrument or, with SSW bst, IA corgressevs ord af tarcoolers A i comot be co&d As indcoted ces TW94 tree N05 es foAre of FCIRC CRD, CRO1, CDS, RWDJ, l FW, VENT: set ce these systems to fo#d in everv evant tree tronsferred to Also, set (41#N to WS' ord ctvrvy TJN to TfNB ty14 change ER/ to 1SRV8 m every event tree trornferred to. c: J'l"e,' EW"ics"@ !?Jid

recovery at t e d Not eye [ W en A{Ht at h HYtM

2. .

  .N m

E Figure 6.2-13 TSA5H Tree

P R d" DD LL D L O L AA A A VV V V m TT OO

                     -                 R W

5 NT

                                                     -                  A w

PPPP5XxXxCOD NTR

                                                                                     -O                    -

m t PPPPPXxxxIOPAAAAAAAAsAAAACNY oeLLEE(LEEHLLEEW*LLEELLELiLLEE**H - iTTiiTTiiTiTTT TTTTiiTTTiTTTT i ( 1 t23456789 012345678 0123 Q E 01U3M511MB222222222M3333 1 1 67 S l A C r' O 8' S . l . m x ri i8 at l C 0 e e 5 P

                           '       l           l          11        l[       li r

l 0 T I S I S C gg gg yg O S B . S l T - B E T 1 4 . 1 K - . l 2 6 e 6 6 r u l g . 2 e i F I e r V 0 t l P H E S D A R T l . S o O t t p la . c C it 0 n 5 e 51 id - S S is M e e r t s W ib I 0 W T 0 <$FJ 3 eed Zd$9n:Db{

t4Edg 1 T DO D O - L L LL A A A . t VV R A V O k 0 -- W NT V-W NTR C TT T OO S CO PPPPSXXXXCOO - U O PPPPPXXXXCNA AAAAAAPAAAACNY NN*LLEELLEEFLLEEe*LMELLLEEHLLEE*eH

TTTTiTTITTTTTT TTiTTTiTTTTTTT T F 123456789 1 01234567890123 - O C V12U15678B22222222223333 1 4 111 S l A C D S l S B ,i ,i i C _ D 5 e l e r . t w i' li gg gi T r t I I l S 8 C C Il S . T gI II 0 5 l 5 . 1 B gt E 2 T X 6 l e r A S C u g . O l l iF 2 e t

               -                                                                      e r

V t D l H P S S O A T L R . l o S t O L A 1 la c l i t . C n T e . S i d I . l i s - S S ee - l M t r 5 5 s - 0 9 ih T l H 5 a C

5 T

l ZCE QnM&%w [

                                                                       ,.W*
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                    --                                V-                   A N 6 C                                        NT                    W ppPP5XXXXC" u4 TT T

J OO pppp CO Nr XXXC AAAAC -

e[ EEL (LE?LLEE NAAAAA4AAAP*[LLEE(LEEHLLEE.&

t O fTTTTii TTTT TiTiTTiTTiITiTT T f i2f 56789 01234567 012l O E S 10 1U111 456 fIM22222222NM333 i l A C D S l H S B C i' ' D S l _ C D S P

                           ,i        ri         i8           II       II       I  L O

l M e e I r - T F D A l 1 1 8 5 D C jI Ii II D S 5 l T B 6 E Ii 1 T X 2 l 6 . A e S C r u H' g l 2 iF l 1 V D y m P S O a l R t S

S O a e 3 Y M p o 4 C o n l C L 4 a A 2 D S S I 4 5 y f l S S E 7 P R d l 5 5 0 Y E , P l H - 5 0 5 T - l 4S N 2~ m&w bmO8W&r" i

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  %                                                          *NOT-VALD
  "                                     ,             2 et T-VALD 5 T     ADH
                                        ,             6       *NOT-VALD 7 T     HYDRO a: NOACB is loss of 1E AC bus 16 AC. Set VENT, ENSDC, SDCB, SDCBS, SSWXT, SWLVL, CRD1, ENE DC to ' Failed' in every event transferred to. Set the following co      ents to ' Failed' in every i cult tree: RHR pump B      C ECCS, SPC, CS               au mp B L.PCI pump C, lA con- pressor of f train B, e
  "       train B volves in SPMU.p CR Chonae events      B,2SRV tlepump and 1SRVB, CCW pum),SSW to 2SRV1 and 1SRV1, respective ~ly.

u a Figure 6.2-17 TABS 11 Tree y, -_._

S 7 a TDB5H POS5 PRESS ISSDC NODCB SEO # OUTCOME b 1 *NOT-VALO 2 *NOT-VALD 3 T SDC

                                      ,            4       *NOT-VALO 5 T     ADH 6       eNOT-VALD 7 T     HYDRO b: NODCB is loss of 1E DC bus 11 DB. Set               VENT    ENSDC, SDCBS, CRD1, LPCI, CS, SPC, CDS, FCIRC, RWCU, DV1-2, &

SPMKP to ' Failed'in every event i ronsfer 'ed to. Set the following components to ' Failed' in every fault y tree: train B volves to 2SRVX and 1SRN X, respectively. E m e T 9 E Figure 6.2-18 TDB51I Tree

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g AS POSS PRESS ISSDC WHERE NOLP8 CHECK SEO # OUTCOME a b c 1 eNOT-VALO 2 T ASIN 1 outside , 3 eNOT-VALD i , 4 T ASISO 2 a 5 T A50UT 3 6 T ASIN i out s,e, , 7 +NOT-VALD i , 8 T ASISO 2 9T ASOUT a tocot.on LOC mm m ces+ o, of i.,5 ans+A 10 eNOT-VAlO contonment. - thus no need to cbse MSPts ornon-esoktile(s open SRV b POS 5. steam kne .treds ossiste se not LOCA's,). and LOCA outs & contonment es a feedwoter Ene bred. b: NOLPB is failure of LPCI B, assuming fe 3dwater line break is in line B, with LPCI B flow to broken line not isolated. I Set LPCI B and SSWXT to failed in o!!

 ~                         event trees transferred to.

c: If cheth volves do not eschte e.edwater Ene tweak d- AS is LOCA == ot bw preosure DLamg tfYDRO, outs

contornment ECCS rs most due to bss of SP pressure es tigh and the freqtet of a LOCA is and f airs t eNNm er r r L tr <r Hi If check volves do isolote. tevs4 drops durang tme regsred for check vows to close and this 1 assumed to cause bss of SDC due to isobtion of SDC on low level 3, water level is o' uout tte some os for o transw nt in which makete is b:,1 ond letdown bwers level to bw levet 3 Note, that en POS 5. feedwatee 6ne O check volves are ass b dB is c vot arely that the etwck vow ore enitiopy ope.t '

1 A524 is krga LOCA tree ftv LOCA ins >de containment. 2- A$rg es hy LOCA tree for sobted LOCA outside 1 ASIXJ Irroe LOCA tree for urusoleted LOCA outside contowment. Z C E O M N

o !

6 H Z Figure 6.3-1 AS Tree g w _ _ . _ _ _ _ _ . _ _ , -- . - - - m _ _ _ . _ _ -

m Z c: k ASHY POS5 PRESS WHERE NOLPB CHECK SEO # OUTCOME f

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                                                                                             ,ns,                                                              3 T                      ASINH '

outside 4 eNOT-VAL 0 r 2 i , 5 T ASISH 6 T A50UH 3 c: Locotion of brg* LOCA irts+ tr outside of contomment. 'I wisede, assume thus no need to close MSN's ornon-eschNe; open 5HV(s). h POS 5 durmg HYDRO, steam kne breds me not LOCNs. but se ne spw.ous openng of on SRV. LOCA outside contonment rs a feedwater Ene tweak. b: NOLPB is f ailure of LPCI B, assuming feec water line break is in line B, with LPCI B fbw to t: roken line not isolated.

Set LPCI B and SSWXT to f ailed in oil b event trees transferred to.

d. A9# is LOCA wbn in R(DRO Dtring HVDRO, c: If check volves do not isolate feedwater Ene twed pessure is high and the freamncy of a LOCA is outskle contonment wwentor y In POS no hLCCS flashmgis lost due of vessel to bss wwentory of SP oferent than ct hw presstre A$ es the krge 1.OCA tree when not an tfr0RO.

and level f alls to elevation of feedwoter entrie. Il chnk valves do isolote, tavel dops durrvj trne requwed for check vrAres to close, and thrs is assurned to rouse foss of SDC due to vs.* tion cf SDC on inw lavet 3. water level is about the some os for o transeent an which rnake9 is lost and letdown lowers level to low level 3. Note, thot in POS 5. feedwater 6ne B check volves are ntially closed unless CDS is on and injecting through feedwater r11et bne B, ft is conservatively ossurned that the check voM ore intially open even thwfe m HYDRO they are iAM. 1- ASIN is large LOCA tree for LOCA inside containment-

2. ASISH is brge LOCA tree for isobted LOCA outside contonment

3. A50VT is large LOCA tree for unrsouted LOCA outside contowivent.

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7 n Figure 6.3-2 A5liY Tree l _ _ _ _ _ _ _ , . _ , m.,- . , . - ,- . . - . - , , - _ . , , , , , _ , . . . . - _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ .-

l l 2 tJ k J2-5 POSS I RHRL SDCL SEO # OUTCOME l PRESS 1 eNOT-VALID

                                                                                          ,         2   T A5lSJ 1 3   T CB 2 4   T CB g 5     eNO I -VALID

1. Break in SDC outside contoinment isolated due to outo closure of MV 8 or MV 9 on low level 3. Transfer to portion of large. LOCA tree for LOCA outside cont. that is isolated.

2: LOCA in SDC line outside cont. not isolated. Top.1/3 core uncovered. ECCS ineffective since SP inventory will be lost for LOCA outside cont. CD with containment bypassed. a: J2-5 is not on initiating event in HYDRO 2: C 5 o ? s E

                              &                                                                                        H g

w Figure 6.3-3 J2-5 Tree j

m z $ C - iE

 $      S1-5           POSS        PRESS     ISSDC     WHERE       NOLPB       CHECK SEO #   OUTCOME    f n

t 0 1 eNOT-VALID 2 T S151N 3 eNOT-VALID

                                                                                  ,     4  T A5lSO 1 i

5 T S150U o 6 T S151N 7 eNOT-VALID

                                                                                  ,     8 T  A5lSO 1
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t Medium LOCA in f erdwater line that is isolated is some as larga LOCA in feedwater line that is isolated

o. SI-5 is LOCA when at low pressure. Durina IfyDRO, pressure is high and the fr sency of a LOCA is different t low pressur e. S is medium LOCA tree for tgi 2

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    *C E                                                     Figure 6.3-4 SI-5 Tree

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[ 51H-5 POS5 PRESS WHERE NOLPB CHECK SEO # OUTCOME 1 eNOT-VALID o 2 eNOT-VALID 3T S1HIN 4 eNOT-VAL .

                                                                                   ,       5T  A51SH  i 6T  S1HOU 1: Medium LOCA in feedwater line that is isolated is some os large LOCA in feedwater line that is isolated

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o. S1H is LOCA when in INDRO. Otring INDRO,

, pressure is high and the frequency of a LOCA is dif ferent than at low pr essur e. 51-5 es medium LOCA tree fcr low pressure.

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l l b y ' S2H-5 POS5 PRESS OPLDM RLOSP DV1-2 FPCSA XTEB CDS RWCUC SEO J OUTCOME l :1 i b 1 *NOT-VAL D 2 *NOT-VALD i 3 *OK 4 T S1XFH 5 T SIXFH i 6 T SixFH I i 7 *NOT-DEVELOPED i 1 8 T SixFH 9 T *CCN 10 T SIXFH 1: Sequence logic ret devebped Sequence frequency W trtmcation b: System &oresswires N RWCUC heat removd Inst assume no ime to urusolate i+R/ SOC and A[M before W to use ECCS cs or 52H is LOCA when in HYORO. During HYDRO presstre is hgh and the freqtery of a LOCA is diferent ttwn of bw presstse. 52-5 is the snvA LOCA tree for bw presswe. Z C 9 T. n W P.

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_b i l Vol. 2, Part 1 6-55 NUREG/CR-6143

Event Trees Event Tree Acronyms CS: Successful start and run of one of two 6.4 contamment spray trains, including operator action. The event trees use numerous acronyms for the constituent events. These section defines these acronyms CSA: Successful start and run of containment for all event trees, both those in Section 6 and in Spray train A (train B not available), Appendix H of this report. including operator action. Events dealing with operator action do not involve CSNHX: Successful start and run of one of two hardware response (operation of components), unless containment spray trains with no heat specifically so stated in the description of the events, exchangers (for fission product purging), Conversely, events that are primarily hardware in nature including operator action. do r.ot involve operator action unless specifically so stated. CTGOP: Grade level opening of containment (either above grade only, or above grade and/or The events are as follows: below grade). Opening below grade could cause auxiliary building flooding, given ACMSV: Automatic closure signal to MSIVs on low flooding of containment. low low level following large LOCA inside containment. CTISL: Containment isolation with Containment Isolation System ADHIS: ADHR hardware isolates on operator command. CTISO: Containment closes. ADHRR: Success of both ADHR pumps and heat CTISN: Like CTISO but no ac power. exchangers to continue to mn. CWLOS: A sequence FLAG representing the failure ADHRl: Successful start and run of one pump and f FCIRC, RWCU, CRD, and CRDI. Set i one heat exchanger in the ADHRS system. cach event to FAILED in all event trees. ADHR2: Successful start and run of both pumps and DV1-2: Operation of IE electrical trains 1 and/or 2; heat exchangers in the ADHRS system. i failure is failure of both trains. CDS: Successful start and run of the condensate ECSBF: A sequence FLAG representing the failure system for vessel makeup. of SDCB and by assumption train B of LPCI, CS, and SPC. Set each event to CHECK: One of two (1 of 2) check valves, twice, (to FAILED in all event trees. account for feedwater lines header) must close to isolate LOCA outside containment in feedwater line B. ENSDC: Operation of the runmng RHR/SDCloop (B), and successful start and run of the CINTG: The status of primary containment (closed standby RHR/SDC loop (A). In terms of or open) in POS 5, 6, or 7, when an subsequent events used, accident initiating event occurs, ENSDC=SDCB*SDCA where

is the logical 'AND'. ENSDC can provide mixing CRD: Operation of both control rod drive between the downcomer and core if level is hydraulic pumps for vessel makeup. One no lower than two feet below normal.

pump is initially running in POS 5. EQSTM: Steam damage to equipment due to steaming CRDI: Operation of one pump in the control rod out of MSIVs, open containment, or broken drive hydraulic system. One pump is feedwater line. initially running in POS 5. NUREGICR-6143 6-56 Vol. 2, Part 1

Event Trees FCIRC: Forced recirculation with 1 of 2 ISSSL: Isolation of recirculation pump seal LOCA, recirculation pumps. before RHR/SDC auto-isolates on low level

3. Ifisolation is successful, level for FW: Alignment and operation of the fire water natural circulation can be established by system to inject into the vessel and flood isolating letdown and increasing makeup, lower containment. with either CDS or CRD (CRD cannot prevent auto-isolation of RHR/SDC on high FWLVL: Alignment and operation of the fire water pressure in POS 4 at 38 Mw). ISSSL system to inject into the vessel and maintain requires both operator action and closure of adequate level as the core is steamed isolation valves in the recirculation loop with (containment is not flooded). the break.

FWMAN: Event FWLVL but requires manual opening ISTCT: Initial status of contamment: closed or open. of FW injection valves, since air valves have failed closed. ISTRC: Initial status of reactor Recirculation system (i.e., fraction of time on natural H2: Success of the hydrogen igniter system. recirculation or capable of natural recirculation). HPCAO: Automatic isolation of HPCS at level 8, following actuation of HPCS. Includes LC-LP: Operator action to control level with LPCS component operation. or LPCI to prevent overfill. HPCS: Successful start and mn of the HPCS train. LCHPC: Operator action to control level with HPCS to prevent overpressurization of RHR/SDC HPCSA: Auto load DG3 onto train 3 IE bus, components. IALOS: A sequence FLAG representing the failure LCMK: Operator recognizes that makeup is greater of FCIRC, CRD, CRDI, RWCU, FW, and than letdown, and controls makeup. VENT. Set each event to FAILED in all event trees. LPCCF: A sequence FLAG representing the unavailability of RHR Train C due to the ISADH: Fraction of time on ADHR in POS 5 as initiator. Set LPCI Train C to FAILED in compared to all POS 5 time. all event trees. ISMSV: Initial status of MSIVs in POS 5 (i.e., LPCI: Successful start and run of any one of the fraction of time MSIVs are open). three LPCI trains. 1S 089: Operator action to locally, manually close 2LPCI: Successful start and run of 2 of 3 LPCI MOV 8 or MOV 9 to isolate SDC. trains. ISOAD: A sequence Flag indicating that SDC is LPCS: Successful start and run of the LPCS train. isolated. Set 'ADHIS' to TRUE in all event trees. MSIV: 1 of 2 MSIVs close on each of 4 main steam lines. ISSDB: Fraction of time on RHR/SDC in POS 5 as compared to all POS 5 time. MSIVO: 2 of 2 MSIVs open on 1 of 4 main steam lines. ISSDC: Initial status of SDC in POS S (i.e., fraction of time on ADHR). NOACB: A sequence FLAG representing loss of IE AC Bus 16AC. Set all events requiring ISSP: Initial status of SP in POS 5 (i.e., fraction power from this bus to FAILED in all event of time that the SP is empty). trees. Replace 2SRV with 2SRV1 and ISRV with ISRV1 in all event tree 4. Vol. 2. Part 1 6-57 NUREG/CR-6143

.l

Event Trees NODCB: A sequence FLAG representing loss of IE than two feet will prevent auto-isolation of DC Bus 11DB. This fails IA. With loss of RHR/SDC on low level 3, and will maintain DC, circuit breakers fail as-is, not ole. forced recirculation or allow for ENSDC. based on info from plant engineers. Set SDCBS, LPCI, CRDI, CRD, CDS, OPDSV: Operator action to depressurize in HYDRO RWCU, CCW, and FCIRC to FAILED in by opening one SRV in relief mode. all event trees . For event tree branches initially on ADHR, set SSWXT and SWLVL OPECC: Operator action to initiate ECCS for S1 and to FAILED. Replace 2SRV with 2SRVX S2. and ISRV with ISRVX in all event trees. OPECS: Operator action to initiate ECCS water solid NOLPB: A sequence FLAG representing the failure operation for transients including opening of LPCI, SDC, CS, and SPC *B' Trains, SRV(s). and CDS. Set each event to FAILED in n'; event trees. OPFLD: Operator recognizes need to flood vessel / containment. NOFW: A sequence flag. Set FW to FAILED in all event trees. OPFLL: Operator action to inject into ve sel and flood containment following LOCA in POS NOMKP: A sequence FLAG representing loss of SH. . CRD. Set CRD and CRD1 to FAILED in all event trees. OPHIS: Operator decides to use HPCS for ECCS water solid operation (not in the Inadequate NOOSP: A sequence FLAG indicating that a LOSP Decay Heat Removal Procedure). has occurred. Set RLOSP to FAILED in all i OPHPC: Operator action to isolate HPCS following I event trees. spurious actuation of HPCS, includes NOOVP: A sequence FLAG indicating that components operation. j overpressurization of SDC cannot occur. j Set OPIS and SDCIL to 0.0 in all event OPICT: Operator initiates closing of open ; trees. containment. NORCR: A sequence FLAG representing loss of OPIS: Operator action to isolate SDC from j forced recirculation. Set FCIRC to overpressurization in POS 5 if auto ' FAILED in all event trees. isolation on pressure fails. j OPCMT: Long term opening of containment to allow OPISA: Operator isolates ADHRS for water solid relief of steam as decay heat pressurizes ECCS operation on 1 SRV. containment following flooding with , SSWXT or FW. Includes operator action. OPLEC: Operator uses ECCS for refill to control l level. l OPCSV: Operator action to close the open SRV. OPLDM: Operator action in response to a small OPDEP: Operator action to depressurize in HYDR LOCA in POS 4,5, or 6 (if break cannot be by stopping CRD. isolated) to isolate letdown and increase i makeup to match flow out the break. ) OPDHR: Operator recognition ofinadequate core-to- Action must be accomplished before downcomer recirculation following events RHR/SDC isolates on low level 3. If for which letdown is greater than makeup. makeup is with CDS, natural circulation can includes operator action to isolate letdown, be restored allowing use of RHR/SDC (or and control makeup as necessary, before ADHRS in POS 5 and 6), but CRD alone level drops more than two feet below cannot establish natural recirculation since normal. Isolation before level drops lower CRD flow approximately equals break flow. NUREGICR-6143 6-58 Vol. 2, Part 1

l 1 l Event Trees OPLMS: Operator initiates closure of open MSIVs in OPSTH: Operator initiates steaming of core at high response to LOCA. pressure, isolates letdown, and controls ! makeup as necessary. l OPLST: Operator initiates steaming core for an unisolated feedline break LOCA in POS 5. OPSTL: Operator initiates steaming of core at high Isolates letdown. pressure (low decay heat) during HYDRO, isolates letdown, and controls makeup as OPLIL: Operator action and successful opcration of necessary. components, to isolate both a large diversion to the suppression pool and letdown before OPSTM: Operator initiates steaming of core at low level drops to the point that rnakeup cannot pressure, and isolates letdown and controls restore level for SDC. makeup. OPL15: Operator action and successful operation of OPVNT: Operator action to vent contamnent. components, to isolate both a small diversion to the suppression pool and letdown before OPISV: Operator decides to use ECCS, water solid, the level drops to point that makeup cannot if only 1 SRV is available (inadequate restore level for SDC. decay heat removal procedure specifies use of 2 SRVs). OPL2L: Operator action and successful operation of components, to isolate a large diversion to POS5: Fraction of time plant is in POS 5. the suppression pool after level drops below low level 3, but before core uncovery. PRESS: Initial pressure in POS 5; yes, low pressure (0 psig): no, HYDRO (1000 psig) and low OPMSV: Operator action to close MSIVs. decay heat. OPNCF: Operator decides to depressurize during RESAD: Operator recognizes need to unisolate HYDRO following loss of forced ADHRS. recirculation to avoid exceeding 70'F during natural circulation. This action is RESB: Operator recognizes need to unisolate not required. RHR/SDC loop B. OPOMS: Operator calls for opening MSIVs to RESCS: Operator unisolates common suction line, prevent pressurization. following closure of MV 8 or MV 9; includes components operations. OPSDC: Operator recognizes loss of operating SDC system, and initiates a standby SDC system. RESRW: Operator recognizes need to unisolate RWCUC and RWCU following isolation OPSLP: Operator action to stop LPCI/LPCS during HYDRO. following spurious actuation. RHRIL: Auto-isolation signal for RHR/SDC isolation OPSOF: Operator stops flooding through open main on low level 3 in POS 4,5,6, or 7. steamline(s). RHRIP: Auto-Isolation signal for RHR/SDC isolation OPSPM: Operator initiates SPMU when it is not on high pressure (135 psig). automatically available. RLOSP: Totalloss of offsite power following an OPSRV: Operator decides to open at least one SRV initiating event. for medium or small LOCA. RM-LT: Long term restoration of makeup following OPSSW: Operator recognizes loss of standby service loss of all letdown and makeup in POS 4,5, water. OR 6, to compensate for leakage. Includes use of ECCS pumps. Vol. 2, Part 1 6-59 NUREG/CR-6143 l

Event Trees RWCU: Operation of the running RWCU system in SGTS: Successful operation of the Standby Gas POS 4,5,or 6, to provide letdown to Treatment System. maintain vessel level by matching makeup l from CDS/CRD. SPC: Successful start and run of one of two suppression pool cooling trains. RWCUC: Operation of runmng RWCU in HYDRO in recirculation mode to remove decay heat. SPMKP: Makeup to suppression pool makeup, to compensate for boil off from suppression RWCUS: Start and run of RWCU in recire mode to pool given venting of containment, or failure remove decay heat. of containment by overpressure. Includes operator actions. RWLS: Start and run of RWCU in letdown mode. SPMKN: Like SPMKP but no AC power. SAFEC: Given success of SAFE, the SRVs that opened reclose. SPMUl: Successful opening of SPMU valves in i response to operator action OPSPM. SAFE: Any safety valve opens at safety setpoint when in HYDRO (all SRVs available). SPMUN: Like SPMUI but requires local opening of valves; no AC power SDIVB: A large diversion via RHR/SDC to the i suppression pool in POS 5, 6, or 7 (/SDIVB SPWLV: Fraction of time in POS 5 that SP w3ter represents a small diversion that is within level is at 12'8". the makeup capability of any single ECCS system / subsystem (HPCS, LPCS, LPCI) to SSWXT: Alignment and operation of standby service maintain the core covered). water train B in a cross tie mode to inject into the vessel and flood lower containment. SDCA: Successful start and run of the standby RHR/SDC loop A. STAHD: A sequence FLAG representing the status of MSIVs and RECIRC in the HYDRO Test. SDCB: Continued operation of the Operating Set ISMSV and ISTRC to 0.0 and replace RHR/SDC loop B. CRD with CRDI. SDCBR: Like SDCB, but restart of RHR pump B STISO: A sequence FLAG indicating that SDC with i required. RHR and ADHR were initially isolated. Set OPIS and SDCIL to 0.0 in all event trees. SDCBS: Successful start and run of RHR/SDC loop B. STRWC: A sequence FLAG requiring replacement of t RWCU with RWLS and RWCUC with SDCIL: RHR/SDC isolation valve MOV 8 or 9 RWCUS in all event trees. closes. STSRV: A sequence FLAG representing initial SDCUI: Operator action to use RHR/SDC or availability of all SRVs during the HYDRO ADHRS following HYDRO Test. Requires replacement of 2SRV with depressurization. (Un-isolate SDC.) 2SALL, ISRV with ISALL, and ISRVS with SAFE. SDISO: A sequence FLAG to indicate that SDC is isolated. Set events RHRIL, RHRIP, SWLOS: A sequence FLAG representing the failure ADHIS, and SDCIL all to TRUE in every of SDCB, SDCBS, LPCI, HPCS, and i event tree. SSWXT. Set each event to FAILED in all event trees. SEAL: Successful cooling of recire pump seals at ) rated temperature (545 F). Requires either SWLVL: Alignment and operation of standby service I i CRD or CCW. water train B in a cross tie mode to inject NUREG/CR-6143 6-60 Vol. 2, Part I

I I Event Trees into the vessel and maintain adequate level 2SRVB: Operation of two SRVs in the relief mode 4 as the core is steamed (containment is not with instrument air unavailable l flooded). (accumulators required). VENT: Successful operation of the containment vent 2SRVX: Operation of two SRVs in the relief mode system. with DC train B unavailable. XTIEB: Successful crosstic of DG3 to train 2; train 1 2SRVI: Operation of two SRVs in relief mode with in maintenance, no AC power from bus 16AC. Batteries deplete. . WHERE: Iocation of LOCA is outside containment (/WHERE implies LOCA is inside containment). ISALL: Operation of one SRV in relief mode following depressurization during HYDRO to use ECCS (all SRVs available). ISRV: Opention of I SRV in the Relief mode. ISRVA: Like ISRV, but no AC power. I ISRVB: Operation of one SRV in the relief mode with instrument air unavailable (accumulators required). ISRVH: Operation of one SRV in relief mode during HYDRO to depressurize (all SRVs available). ISVHA: Like ISRVH, but no AC power. ISRVS: Automatic operation of one SRV in the safety mode at full (rated) system pressure. ISRVX: Operation of one SRV in relief mode with DC train B unavailable. ! ISRVI: Operation of one SRV in relief mode with no AC power from bus 16AC. Batteries > deplete. 2LPCI: Successful start and run of two of three l LPCI trains. 2SALL: Operation of two SRVs in relief mode following depressurization during HYDRO to use ECCS (all SRVs available). 2SRV: Operation of two SRVs in the relief mode. 2SRVA: Like 2SRV, but no AC power. l Vol. 2 Part 1 6-61 NUREG/CR-6143 1

7 Plant Damage State Analysis This section of the report summarizes the plant damage appropriate characteristic. In the third step, the cut sets state (PDS) analysis, are reviewed and the appropriate attributes for each characteristic are assigned to each cut set. Since the list of characteristics generally describes the accident in less 7.1 Purpose detail than the cut set, groups of cut sets will have the same string of letters. A unique string ofletters is called Plant damage states form the interface between the an End State (ES). (ESs are similar to PDSs except that accident frequency analysis (i.e., Level 1 analysis) and they define the accident in more detail than the PDS.). the accident progression analysis (i.e., Level 2 analysis) While the number of ESs can be significantly less than t.nd as such defme the initial and boundary conditions for the number of cut sets, typically there are still too many the Level 2 analysis. In the Level 1 analysis the ESs to analyze individually in the Level 2 analysis. sequence of events thr.t will lead to core damage are Therefore, in the fourth and final step, the many ESs are identified. The minimum set of events that will result in c mbined into a manageable number of PDSs. This step core damage is called a cut set. In the plant damage is possible because within the resolution of the Level 2 state analysis, cut sets with similar characteristics that analysis many of the ESs will result in similar accident are important to the progression of the accident following progressions and releases of radioactive material. To f rm the PDSs, ES characteristics see combined such core damage are grouped together; each group constitutes aPDS. that only the information that is needed to define the initial and boundary conditions for the Level 2 analysis are defined by the PDS. For example, the individual ESs indicate the availability of many different coolant 79 Approach injection systems (e.g., LPCI, SSw cross-tie, and CDS). However, if LPCI is recoverable and the vessel is at low A four step approach was used to develop the PDSs. In pressure then the status of the other systems is not the first step, general features of the accidents that will important for the model used in the Level 2 analysis. define the initial and boundary condition for the Level 2 Thus, assuming the other characteristics of the ESs are analysis are identified. These general features define the the same, all those ESs with LPCI recoverable would be confic 4ation of the plant at the start of core damage and combined regardless of the status of SSW cross-tie and the status of systems than can be used to mitigate the CDS. Through this procese the majority of the ESs can tecident. In the second step, specific systems and plant be combined into a dozen or so PDSs, however, the features are identified that address each of these general actual number of PDSs developed will depend on the features. Each specific feature is called a characteristic; diversity of the accident sequences and the resolution the possible configurations of each system or desired for the Level 2 analysis. characteristic is called an attribute. More than one characteristic may be used to define a general feature. The general features of the accident that were used in For example, the following four systems (i.e., this study to develop the PDSs are: the status of electric charactedstics) could be used to define the general power, the status of core cooling, the status of fcature that addresses the status of core cooling : HPCS, containment beat removal, the statns of reactor pressure LPCI, SSW crosstie, and CDS. That is, HPCS is one of vessel irtegrity, the status of containment integrity, and four characteristics that defines the status of core accident timing characteristics. Each of these general cooling. The possible configurations of the HPCS accident features is discussed below. system, or attributes, during the accident are: (A) HPCS available but not being used, (B) HPCS not available and Status of Electric Power: There are systems and not recoverable, and (C) HPCS not available but components that can influence the progression of the recoverable with the recovery of offsite power. In this accident following core damage but that were not example, the HPCS characteristic has three attributes. modeled in the Level 1 analyses. Many of these systems The list of characteristics and their associated attributes depend primarily on electric power and, therefore, in define the possible plant / system configuration for a many cases this feature of the accident can be used to pc.rticular accident. This is displayed as a string of determine the availability of these systems. For alphanumeric characters. The first position corresponds example, offsite ac power is required to close the to the first characteristic, the second position corresponds containment. Similarly, emergency ac power is required to the second characteristic and so on. The alphanumeric to operate the hydrogen ignition system. character assigned to each position is the attribute for the Vol. 2, Part 1 7-1 NUREG/CR-6143

PDS Status of Core Cooling: This feature is used to identify The vessel pressure will also determine which systems systems that can be used to restore core coolant during can be used to provide makeup (i.e., high pressure the core damage process. Restoration of core cooling systems or low pressure systems). offers the potential to arrest the core damage process and prevent vessel failure. Preventing vessel failure can substantially reduce the consequences of the accident. Status of Containment Integrity: This feature defines the integrity of the containment boundary at the time of core damage. The integrity of the containment boundary Status of Containment Heat Ranoval: This feature is one of the most important factors that will determine addresses the status of systems that can be used to the severity of the accident. For severe core damage remove decay heat from the containment such as accidents in which the containment boundary remains containment sprays and the suppression pool cooling intact, the offsite consequences are generally small. On systems. In cases where the containment is closed, the the other hand, when the containment boundary is not energy released to the containment atmosphere during maintained the consequences can be quite severe. Since core damage will pressurize the containment. These in POS 5 the containment equipment hatch and personnel systems are used to attenuate this pressurization and iocks can be open, it is important to know the status of thereby reduce the load on the containment structure. these penetrations at the time of core damage. This Containment heat removal is generally necessary to feature also addresses the status of the containment vent prevent containment failure. Containment sprays are system which can be used to relieve pressure in the dso useful in that they remove aerosols from the containment when containment heat removal systems are containment atmosphere and thereby reduce any potential not available or inadequate. Opening the containment release of radioactive material. Since the suppression vent, however, will allow radioactive material in the pool is an integral part of containment heat removal, this containment atmosphere to enter the environment. feature also addresses the status of the suppression pool at the time of core damage (i.e., amount of water in the i Accident Timing Characteristics: This feature defines : pool and the terrperature of the pool) and is used to the time window that the plant is in when the initiating I identify situations where its performance may be impaired. The suppression pool is used as a heat sink event occurs and the amount of time that clapses between , for the reactor, supplies water to ECCS, and is an the occurrence of the initiating event and the onset of effective device for removing radioactive material core damage. The time window will directly affect the released from the vessel amount of decay heat and the radionuclide inventory that is present at the start of the accident. 'Ibe time window 1 combined with the amount of time that elapses between i Status of Reactor Pressure Vessel: This feature defines the start of the accident and the onset of core damage the integrity of the reactor pressure vessel and the will determine the amount of decay heat that is available pressure in the vessel at the time of core damage. The at the onset of core damage which will in turn affect the integrity of the vessel is important because it will timing of key events following the onset of core damage determine the path by which steam and radioactive (e.g., vessel failure and containment failure). The speed material will escape from the vessel. If the vessel with which the accident proceeds can affect the amount integrity is maintained the releases will pass from the of time that is available to restore core cooling and will j vessel to the suppression pool via the SRV tailpipes. As also affect the relative timing between when the release < mentioned previously, the suppression pool is an of radioactive material occurs and when the public begins ! effective device for mitigating the release. For a LNA, to evacuate. This last item can have a major impact on the vessel releases will enter the drywell. For the magnitude of early health effects. interfacing systems LOCA, the release will bypass the containment altogether and enter auxiliary building. If The characteristics that are used to define the ESs, the the vessel head vent is open a portion of the release will rationale used to collapse the ES characteristics into PDS ; enter the drywell while the remaining ponion will enter characteristics, and the mapping from ES cut sets to i the suppression pool via the SRV tailpipes. When the PDS cut sets are all provided in Appendix L. The PDS l vessel integrity is maintained, tae pressure in the vessel characteristics and attributes that define the PDSs are , will affect the timing of the ocident, the amount of provided in Table 7.1. These PDS and the core damage radioactive material releasM during core damage, and frequency associated with each are described in Section the pressure in the contakunent following vessel failure. 13. NUREG/CR-6143 7-2 Vol. 2, Part 1

l Table 7.1 Plant Damage State Characteristics and Attributes Charact. Attribute Description STATUS OF ELECTRICAL POWER 1 Status of Electrical Power i A Offsite power (OSP) svailable B OSP not available - but recoverable ! C OSP not available - not recoverable, delayed failure of core cooling D OSP not available - not recoverable, prompt failure of core cooling E OSP available - Emergency AC and DC power not available and not recoverable STATUS OF CORE COOLING 2 Status of Core Coolant Irdection A Core injection is not available and cannot be recovered B LPCI and/or SSW crosstie are unavailable due to operator error C LPCI and/or SSW crosstie are unavailable but recoverable with recovery of OSP t i STATUS OF CONTAINMENT HEAT REMOVAL - 3 Status of Containment Sprays and Suppression Pool Cooling A CS/SPC is not available and cannot be recovered i B CS/SPC is not available but can be recovered with recovery of OSP C CS/SPC is available 4 Status of Suppression Pool Level A Water at " Low Level' or " Drained Level" B Suppression pool level is at the ECCS suction strainers 5 Status of Suppression Pool Temperature A Suppression Pool is sub-cooled B Suppression Pool is saturated Vol. 2, Part 1 7-3 NUREG/CR-6143 f

PDS Table 7.1 Plant Damage State Characteristics and Attributes (Continued) Charact. Attribute Description STATUS OF REACTOR VESSELINTEGRITY 6 Status of RPV Head Vent A Head vent is open during the accident B Operators close the head vent prior to core damage i 7 Status of RPV Pressure and Integrity ! l A Primary system is at system pressure l. B Primary system is at low pressure (> 400 psia) l 1 C Primary system is at low pressure; RPV is breached by a LOCA inside l containment D Primary system is at low pressure: RPV is breached by a LOCA in SDC system l I E Primary system is at low pressure: RPV is breached by open MSIVs I'

             +-                               . STATUS OF CONTAINMENT INTEGRITY -

8 Status of Containment Lower Personnel Lock A Containment lower personnel lock is open B Containment status is unknown i 9 Status of Containment Vent System I A CVS is unavailable and cannot be recovered B CVS is unavailable but can be recovered with recovery of OSP C CVS is available but has not been used because is has not been needed l NUREG/CR-6143 7-4 Vol. 2. Pan 1

PDS Table 7.1 Plant Damage State Characteristics and Attributes (Continued) Charact. Attribute De:,cription TIMING CHARACTERISTICS 10 Time to Core Damage A Core damage occurs in 2 hour B Core damage occurs in 2.35 hours C Core damage occurs in 3.5 hours D Core damage occurs in 5.5 hours E Core damage occurs in 6.75 hours F Core damage occurs in 7 hours G Core damage occurs in 9.75 hours H Core damage occurs in 12 hours 11 Time Windows A Time Window 1: Ranges from 14 to 24 hours after shutdown B Time Window 2: Ranges from 24 to 94 hours after shutdown C Time Window 3: Ranges from 40 to 50.4 days after shutdown l Vol. 2, Part 1 7-5 NUREG/CR-6143

8. Systems Analysis This section describes the systems analysis efforts for were developed with top events corresponding to the Plant Operatig State 5 (POS 5). Section 8.1 provides an success criteria used in the event tree analysis. The introductior to the system modeling performed in the support system failure models were developed with top Grand Gulf analysis, and discusses the scope of the events corresponding to their failures called out in the modeling 'or each system. Section 8.2 identifies each front-line system model. Some systems have different system exa nined in the systems analysis effort. Sections success criteria and, hence, different top events 3.3 through 8.28 describe the modeling effort for each depending on the accident sequence and plant system. These sections each contain a system configuration in POS 5.

description, an identification of interfaces and dependencies, a discussion of operational constraints, a The fault tree models were done at the component level. description of the models developed, specific assumptions Operator actions in response to plant conditions were used in modeling, and a dircussion of any unique included in the models where specific procedures for i operational experience for each of the systems, when these actions were available. Operator errors of l applicable. (He front-line systems are discussed first commission were not included in the fault tree analysis. and then the support systems). Section 8.29 discusses the Recovery actions for component failures are handled at retionale for those systems that were " black boxed". the sequence level of analysis and are covered in Section 10 of this report. He information contained in Sections 8.3 through 8.28 was obtained from reviewing the information referenced 8.2 Identification of Systems at the end of this Section of the report. Prior to fault tree development, the systems to be 8.1 System Modelm.g Approach and modeled must be identified. All systems are categorized , Scope as either front-line systems or support systems. The i front-line systems are the systems specifically called out nree different types of system models were used in the in the event trees (see Section 6). The support systems systems analysis: (1) detailed fault tree logic model, (2) are the systems required by the front-line systems for simplified fault tree model, and (3) black box model . Successful Peration. , In the detailed fault trea logic model, all the different i kinds of failure modes are modeled for the system All systems identified in the accident sequence analysis components. nese include hardware faults, maintenance f r POS 5 that can mitigate an accident have been unavailabilities, common cause, and support and m deled. The systems that were modeled in the Grand dependent failures. In the simplified fault tree model, the Gulf study are shown in Table 8.2.1. analyst identified the dommant failure modes for the significant components for modeling. In a black box 8.3 High Pressure Core Spray model, the system is represented by a single event whos unavailability is from an established data base. The S7stem (HPCS) systems Analysis Task utilized the system fault tree models developed for the NtJREG/CR 4550 Grand Gulf 8.3.1 IIPCS System Description study as loaded into IRRAS by INEL. These system models were modified as necessary to reflect the In Pos 5 the function of the HPCS system is to provide plant / system configuration in POS 5. For those systems coolant makeup to the reactor vessel in order to not modeled in the NUREG/CR 4550 Grand Gulf Study, maintain proper water level and/or flood the reactor, but included in the scope of this study, fault tree models The HPCS system consists of a single train with were developed using the IRRAS software. System motor-operated valves and a motor driven pump. Suction models were developed for each of the front-line systems is taken from either the Condensate Storage Tank (CST) identified in the event tree headings and for all the or the suppression pool. Injection to the reactor vessel is support systems required to operate them. Fault tree via a spray ring mounted inside the core shroud. The models (i.e., detailed or siinplified) were constructed for pump is capable of delivering 550 gpm against a reactor all of the systems, except for the Turbine Building pressure of 1177 psig and a full flow of 7115 gpm Cooling Water (TBCW) system for which a black box against a reactor pressure of 200 psig. The total model was used. He front-line system failure models maximum pump run out flow is 9100 gpm. The HPCS Vol. 2. Part 1 8-1 NUREG/CR-6143

Systems Analysis Table 8.2.1 Systans Included in the Grand Gulf Study SYSTEM TYPE OF MODEL i IIPCS System Fault Tree CRD System Fault Tree CDS Dommant Failures Only l LPCI System Fault Tree l LPCS System Fault Tree SSW XT System Fault Tree FW System Fault Tree SPC System Fault Tree ADHRS System Fault Tree SDC System Fault Tree CS System Fault Tree CVS System Fault Tree EPS One fault tree for each AC tus (down to the Motor control center level) and each DC divisional bus. SSW One fault tree for each load plus one fault tree for each train's common elements. EHV One fault tree for each critical room IAS System Fault Tree SPMU System Fault Tree RRS System Fault Tree CCW System Fault Tree PSW System Fault Tree RWCU System Fault Tree SGTS System Fault Tree TBCW Black Box H2 Dommant Failures Only CRWST System Fault Tree SRV System Fault Tree NUREG/CR-6143 8-2 Vol. 2, Part 1

Systems Analysis pump is located in the auxiliary building at elevation that no credit was taken for the RCIC system in POS 5 93'0" in an enclosed room complete with fire / flood since RCIC auto isolates at a reactor pressure of 60 psig. , doors. Upon system actuation, the HPCS injection valve receives a signal to open, and the HPOS test valves A simplified schematic of the HPCS is provided by receive a signal to close. The HPCS system is Figure 8.31. Major system components are represented automatically initiated on the receipt of either a high with valves shown in their normal standby position. drywell pressure signal (2 psig) or low reactor water level (-42 inches or Level 2). A simplified actuation The HPCS system is automatically initiated and dependency diagram of the major emergency coolant L controlled. However, operator intervention is required to actuation subsystems is provided by Figure 8.3-3. The throttle flow to prevent the HPCS injection valve from CST is the initial suction source for the HPCS system. opening and closing in response to the reactor vessel Suction is automatically switched to the suppression pool level. The operator may also be required to manually upon either low CST level or high suppression pool start the system, if an automatic start failure occurs. level. The success criterion for the HPCS system is injection of The CST suction valve closes when the suppression pool flow to the reactor vessel. For further information, refer suction valve is fully open. This interlock prevents to success criteria discussions in Section 5. inadvertent draining of the CST to the suppression pool. Opening of the suppression pool valve will also resuh in Most of the HPCS system is located in a separate room closure of the CST test return line valves if they are in the aur.iliary building. Because of the relative location open. This interlock prevents flow of suppression pool of the system components, local access to the HPCS water to the CST. The HPCS system is automatically system would not be affected by either containment isolated when the reactor water level reaches +55 inches venting or containment failure. Room cooling failure is (Level 8). At this level, the HPCS injection valve closes assumed to fail the HPCS pump in twelve hours. Refer and the minimum flow valve to the suppression pool to Section 8.17 for further information on room cooling. opens. The HPCS pump continues to run. 8.3,2 IIPCS System Interfaces and 8.3.3 HPCS Test and Maintenance Dependencies The HPCS surveillance requirements are the following: The HPCS system major dependencies are DC control (a) verification of valve position once a month, (b) pump power for initiating the actuation relay logic and HPCS operability once a month, (c) motor-operated valve pump breaker, AC power for operating the HPCS pump operability once a month, (d) system functional test and valves, and HPCS pump room cooling. A simplified including r Ated automatic actuation once every dependency diagram of the HPCS system is provided in operaticp and (e) HPCS pump suction switchover Figure 8.3-2. Shown are the major support requirements verificatw a every operating cycle. for the HPCS system as indicated by the solid diamonds at the appropriate locations 8.3.4 HPCS Technical Specifications The DC power is provided by Division 3125 V DC Bus 11 DC. Power for the HPCS pump is provided by In POS 5, at least two of the following emergency core Division 3 4160 V AC Bus 17 AC, ard power for the cooling systems must be operable: a) Low Pressure Core valves and room cooler is provided by Division 3 480 V Spray (LPCS); b) any of the three trains of the low AC MCC 17B01. It should be noted that Division 3 (AC Pressure Coolant Injection (LPCI) system; or c) HPCS. end DC power) is dedicated to the HPCS system and its supports. If only one of the above systems is operable, at least one of the remaining systems must be made operable within 4 l The HPCS and Reactor Core isolation Cooling (RCIC) hours. Otherwise, all activities with the potential for l systems share a common CST suction valve. This is a draining the Reactor Vessel must be suspended, normally open manual valve and is identified as XV70 on the HPCS schematie. Failure of this valve will fail the With none of the above systems operable, Core CST as a suction source to both HPCS and RCIC. Note alterations and all activities with the potential for Vol. 2. Part 1 8-3 NUREG/CR-6143 l 1

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Systems Analysis dreining the Reactor Vessel must be suspended, and at least one of the above systems must be restored within (6) During construction of the fault tree, it was four hours. Otherwise, secondary containment integrity necessary to determine which components could must be established within the following eight hours. be taken out of service for maintenance. It was assumed that maintenance would require 8.3.5 HPCS Logic Model components to be effectively removed from the system. Standard safety precautions of component isolation were used; the general The llPCS system was modeled using a fault tree for the ' guidelines used were double blockage for high injection of coolant to the reactor vessel. The major Pressure piping or components and single octive system components were modeled. The fault tree blockage for low pressure piping or components. system model representing HPCS system is presented in Appendix 1. (7) Switchover of the HPCS pump suction to the There are several human errors incorporated into the suppression pool is assumed to be eventually required. Failure of the high suppression pool HPCS fault tree model. These errors are (a) failure to level signal for switchover was not modeled manually backup automatic HPCS actuation, (b) miscaliberation of CST level sensors, (c) miscalibration since suction can be taken from the CST until it is depleted if the high pool level signal failed. of drywell pressure sensors, (d) miscalibration of reactor vessel level sensors, (e) failure to inanually realign HPCS Low CST level can then initiate the suction switchover. This signal was modeled. pump suction from the CST to the suppression pool, and (f) failure to restore HPCS to operational standby (8) Failure of the CST or suppression pool from following maintenance. random failure or the plugging of its strainers is felt to be negligible compared to other system The potential for fire events to fail HPCS are explicitly modeled in the fault tree, failures. (9) If the HPCS minimum flow line has been 8.3.6 HPCS Assumptions demanded open and subsequently fails to close, there is the possibility that the CST will drain to (1) The HPCS test return lines were considered the suppression pool because of their difference potential diversion paths due to fire induced in elevation. However, since switchover to the inadvertent opening of the test return line MOVs suppression pool is assumed to be required, such and random failures. an occurrence will not fail HPCS. (2) The minimum flow line is not considered as a The HPCS actuation circuitry was not modeled (10) potential diversion path because ofits small size to a great degree of detail. Only elements which ; and flow limiting orifice. 1 were felt to be potentially important were included in the fault tree model. The initiating (3) Failure of the minirsim flow line to open was signal sensors and their support systems were assumed to fail the HPCS pump. The minimum explicitly modeled. The power supply for the flow line will be required to open during initial actuation circuitry is also included. Hardware startup and upon generation of a high reactor failures of relays and certain permissives are I vessel level (Level 8) signal. I grouped into one basic event. (4) Spurious signals during the sequences ofinterest (11) Failure to recover an initial loss of the normal are felt to be negligible compared to other s ion source (the CST) will be treated as a system failures because of their low probability j recovery action, of occurrence. l (12) Failure to manually realign the HPCS pump l (5) Testing of testable check valve (TCV) 5 will not suction to the suppression pool after a depletion prevent flow to the reactor vessel, nor will it of the normal suction source (the CST) and prevent TCV5 from stopping flow from the failure of automatic alignment are treated reactor vessel. explicitly, with numual switchover being 88 Vol. 2, Part I NUREG/CR-6143

Systems Analysis modeled in the fault tree. condenser is rejected to the CST by the condensate system. From the condenser hotwell makeup / reject lines, ; (13) Piping with a diameter of greater than or equal water flows to the CRD pumps through a pump l to one third of the main system piping was backwash suction filter and one of two pump suction , considered as a potential diversion path, filters. A simplified schematic of the CRD system is provided by Figure 8.4.1. Major system components are (14) The operator is assumed to throttle HPCS flow shown. after initiation to prevent the reactor vessel level from rising above accepted levels. Failure of the operator to throttle flow would result in a ne CRD pumps, together, can achieve a flow rate of I2 vel 8 signal's closing the HPCS injection approximately 238 gpm with the reactor at 1103 psia. valve. His would not fail HPCS since a low Each pump is provided with a minimum flow line reactor vessel level (Level 2) signal would which recirculates 20 gpm back to the CST. This reopen the valve. Failure of the Level 2 signal minimum flow line prevents the pump flow from is modeled in the fault tree. Failure of the Level decreasing to where the pump would overheat and 8 signal would not fail the HPCS system but possibly be damaged. l would result in filling the reactor vessel with ; water. Two discharge paths are provided for the CRD pumps. The first path is through the Hydraulic Control Units' i (15) The drywell pressure during an accident may not (HCUs) cooling headers. Flow is controlled by one of always be high enough to actuate HPCS. The two air operated control valves. When instrument air is , high drywell pressure signal failure logic lost, the control valves fail "as is". The second path is i contains an external event (i.e., house event) through the HCU charging headers. This path is : (with probability of 1.0) that represents this upstream of the control valves and fails open on !oss of potential. If a high drywell pressure signalis air. However, with both CRD pumps rimmng and the expected to be present in a particular accident reactor at nominal pressure, the second discharge path i sequence, cut sets containing this event should restricts flow, by means of an orifice, to approximately < be eliminated. 165 gpm. This flow rate is assumed insufficient for core l cooling and thus no credit is taken for this discharge I (16) Fire events which would lead to the failure of path. " the HPCS system were explicitly modeled in the fault tree. Rese events are represented as fire ; zones. Normally one CRD pump is rimmng with the suction and discharge valves to the standby pump being open. , Should the operator be required to realign the CRD # 8.3.7 HPCS Operating Experience system as a source of early high pressure injection, the ; standby CRD pump must be placed into operation and l Generic failure data wem used to quantify the fault tree one air operated control valve must be fully opened to , logic model. achieve sufficient flow to the reactor vessel. 8.4 ne CRD success criteria require that both pumps be Control Rod Drive (CRD) runnmg and the HCU cooling header discharge path be System available when CRD is required at the start of the , accident as the only coolant makeup source. However, - 8.4.1 CRD System Description when coolant makeup has been provided for a period of time and then lost, only one CRD pump is required. He CRD hydraulic system was modeled as a backup For further information, refer to success criteria source of high pressure injection. discussions in Section 5. Most of the CRD is located in ! the auxiliary building. Any physical impact of accident ; ne CRD pumps take suction from the condenser hotwell conditions on the ability of the CRD system to perform its function would be minimal. Room cooling failures ' makeup / reject line. Makeup to the condenser hotwell is provided by the CST. Excess condensate from the are assumed not to fail the CRD pumps. t Vol. 2, Part 1 8-9 NUREG/CR-6143 5

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l l l Systems Analysis 8.4.2 CRD Interfaces and Dependencies systems do not address the CRD components required for coolant injection. CRD Pump A is powered from Division 14160 V AC Bus 15 AA with control and actuation power supplied by 8.4.5 CRD Logic Model Division 1125 V DC Bus 11 DA. CRD Pump B is powered from Division 2 4160 V AC Bus 16AB with The CRD system was modeled using fault trees for its control and actuation power supplied by Division 2125 high pressure injection mode and for t:se in long term. V DC Bus 11 DB. A simplified dependency diagram of Therefore, two fault trees were developed since the the CRD system is provided by Figure 8.4.2. success criteria differed. At the start of the accident, The major dependencies are indicated by the solid both CRD pumps are required for coolant makeup. diunonds. However, in the long term when coolant makeup has l been provided, only one CRD pump is required. He CRD pumps receive no automatic initiation signals. Failures modeled in both fault trees include Instrument air is required for the operation of the flow unavailabilities associated with the pumps, support system control valves. Flow control valves fail "as is" on loss failures, and human error in aligning the second pump of instrument air.ne CRD pumps are cooled by the for operation to achieve full flow conditions when Component Cooling Water (CCW) system. He CCW necessary. The fault trees are presented in Appendix 1. system consists of three pump trains, two of which are required to operate during normal operation. Only one Three human errors are incorporated into the CRD of the pumps is powered by emergency AC power. system failure model. The first error is the operator's Given a loss of offsite power, the CCW system sheds failing to properly align the CRD system for full flow in ' unnecessary loads so that the single emergency AC the high pressure injection mode. The second error is powered train can cool essential loads. failure to restore a manual valve at the standby pump

outlet following pump maintenance. The third error is '.

! The CCW system normally transfers heat via heat failure of the operator to restart CRD pump A following I exchangers to the Plant Service Water (PSW) system. a LOCA. Testing of the pump following maintenance Portions of the PSW system (including cooling of the would not require reopening of this valve since the pump CCW beat exchangers) are interfaced with the Standby minimum flow line is upstream of the valve. Service Water (SSW) system for cooling when loss of offsite power occurs. Cooling from bodi the PSW and The potential for fire events to fail the CRD system are SSW systems is inhibited if a loss of Coolant Accident explicitly modeled in the CRD fault tree. (LOCA) signal is present. A LOCA signal can consist of either a high drywell pressure or a low reactor vessel level signal. 8.4.6 CRD Assumptions The PSW system receives cooling water from the Plant (1) The number of CRD pumps required depends on Service Water Radial Well (PSWRW) system. The the accident scenario. As discussed in Appendix PSWRW system consists of four wells, each containing F of this report, one CRD pump is sufficient for two pumps and the required piping and valves for level control, but two CRD pumps are required distributing the water. Water contained in the wells is to provide adequate makeup for steaming the derived from the Mississippi River. core. (2) No crelt is taken for the HCU charging 8.4.3 CRD Test and Maintenance injection path in the high pressure injection rnode since the flow is limited to 165 gpm at No test and maintenance requirements for the CRD pump runout. This flow is assumed to be system components required for high pressure injection insufficient for high pressure injection success. are identified in the technical specifications. However, credit for this path was taken for CRD use in the long term. 8.4.4 CRD Technical Specifications (3) CRD Pump C001 A is assumed to be initially ne technical specifications on the reactivity control operating. Vol. 2, Part 1 8-11 NUREG/CR-6143 t

Systems Analysis CONTROL ROD DRNE SYSTEM l (INJECTION MODE) r T ! rm I I FLOW CRD PUMP CRD PUMP CONTROL A B VALVE l [ ) ( h 1 l em em j l lNSTRUMENT AR A,r 1 l

AC 1 POWER 2 O 3 A DC I 'r POWER 2 $ 3 i COMPONENT COOLING WATER (PUMP $ $ COOLING) MANUti ACTUATION (1) a 4 mr DEPENDENCY DIAGRAM IS SliOWN USING FAILURE LOGIC (1) CRD PUMP "A" IS ASSUMED TO BE NORMALLY RUNNING Figure 8.4.2 CRD Dependency Diagram ; l NUREG/CR-6143 8-12 Vol. 2, Pan 1 1

l l l l Systems Analysis l l (4) Because the CCW system operation varies the suppression pool vents covered for all break sizes. availability of offsite power, an external event . (i.e., house event) is used to identify cut sets (2) By a timer, thirty minutes after a LOCA signal has l involving failure of the system when offsite been generated. His ensures an adequate long ; power is available. When this event is combined term heat sink is available regardless of break size. with other system failures involving loss of offsite power, the resulting cut sets must be (3) By manual initiation, provided a LOCA signal is removed. present or the ECCS has been manually initiated. In addition, the mode selector handswitch for each , 8.4.7 CRD Operating Experience division must be in AUTO position and the reactor mode switch must not be in REFUEL position in order to , Generic failure data were used to quantify the fault tree actuate each SPMU valve by any of the three methods logic model. listed above. , ne upper containment pool penetrations are at elevation , 8.5 Suppression Pool Makeup 187'10' Th* dump valves are located in the l containment building. The pipes discharge m, to the (SPMU) System suppression pool at the elevation or 133 feet. . 8.5.1 SPMU Description 8.5.2 SPMU Interfaces and Dependencies The SPMU system provides water from the upper containment pool to the suppression pool following a The SPMU system requires electrical power for i LOCA. Water which gravity flows from the upper operation. The two redundant SPMU lines are each containment pool to the suppression pool is of sufficient powered for separate emergency electrical buses. The quantity to keep the uppermost drywell vents covered for Train A valves are powered by emergency AC Division , most conceivable accidents. 1 MCC 15B21 while the Train B valves are powered by AC Division 2 MCC 16B41. The initiation logic for The SPMU system consists of two lines which penetrate Train A and B is powered by 125 V DC Divisions 1 and the side walls in the separator storage area of the upper 2, respectively. A simplified dependency diagram is [ containment pool. These lines are routed down to the provided in Figure 8.5.2. The major dependencies are suppression pool on either side of the steam tunnel. A indicated by the solid diamonds. sirnplified schematic of the SPMU system is provided by Figure 8.5.1. Major components are shown, with valves shown in their normal standby system position. 8.5.3 SPMU Test and Maintenance i The pool makeup line has two normally closed, ne upper containment pool level and temperature are l motor-operated butterfly valves in series. All checked every day. Valve positions are checked on a ' motor-operated valves are powered from onsite monthly basis. A system functional test, including emergency power sources maintaining divisional simulated automatic actuation of the SPMU system, is sepr. ration and redundancy. required once every operating cycle. He instrumentation and initiation logic, however, are required to be The upper pool is dumped by gravity flow when the calibrated and undergo functional tests. The frequencies , valves receive a divisionally separate but simultaneous of the tests are: (1) channel checks - every shift, (2) signal to open. He open signal for each valve division channel functional test -- monthly, (3) channel calibration j is generated in any of three ways: - monthly, and (4) logic system functional test - t once/ operating cycle. (1) By low-low suppression pool level, providing a ; LOCA signal has been generated or the 8.5.4 SPMU Technical Specifications Emergency Core Cooling System (ECCS) has been : manually initiated. This ensures adequate water No requirement in POS 5. volume in the suppression pool to keep the Vol. 2, Part 1 8-13 NUREG/CR-6143

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Systems Analysis SUPPRESSION POOL MAKEUP SYSTEM *

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Systems Analysis demanding than during normal plant operation. The l 8.5.5 SPMU Logic Model l systems required to maintain condenser vacuum are not ' required since the condensate system is unaffected by loss The SPMU system was modeled using a fault tree for the of condenser vacuum. In addition, parts of the injection of coolant to the suppression pool. The major condensate system (e.g., the low pressure heaters) are active system components were modeled. The fault tree model representing the SPMU system is presented in not required to function.The condensate pumps are powered by non-safety 4.16 kV buses. Power to Appendix I. condensate system motor-operated valves is also provided by non-safety related buses (480 V). The instrument air i The potential for fire events to fail the SPMU system are system is required to supply air to the condenser makeup explicitly modeled in the fault tree. valve and also to open the feedwater startup valve. Makeup to the condenser is provided by the condensate and refueling water storage and transfer system. 8.5.6 SPMU Assumptions Dependencies are shown in Figure 8.6.2. In POS 5 the SPMU auto-activation circuitry is assumed to be inhibited as a safety precaution for personnel 8.6.3 Condensate System Test and working in the dump area. The fault tree model Maintenance considers the failure of the SPMU valves to open on demand. The operator action to open the valves is asked In Pos 5, the condensate can be unavailable due to es an event tree top. maintenance activities . Based on past maintenance outages, the fraction of time the condensate system would 8.5.7 SPMU Operating Experience be available in POS 5 was calculated. The fraction of time the condensate system would be available is handled Generic failure data were used to quantify tre fault tree as a single system event in the condensate fault tree model. logic model. 8.6.4 Condensate Technical Specifications 8.6 Condensate (CDS) System

                                                                   "'*9'***"**" U               8' 8.6.1 Condensate System Description Credit for the condensate system as a low pressure injection system is taken in this study. The condensate          The condensate system was modeled using a simple fault system has three main condenser units, three condensate          tree. Dominant failures were considered to be loss of pumps, three condensate booster pumps, three strings of          offsite power, loss of Turbine Building Cooling Water four low pressure heaters, a condensate dram tank and            (TBCW), the operator's failing to align the system for associated valves, piping, instmmentation, and controls,         low pressure injection, common mode failure of the The condensate system supplies water to the reactor              condensate pumps, and loss ofinstrument air. As vessel through the feedwater startup valve AV513. A              ind.icated above, one human error is incorporated into the simplified schematic of the condensate system for use as        c ndensate system fault tree. This error is the failure of a low pressure injection system is shown in Figure 8.6-1.        the operator to align the system for injection to the The success criteria for the condensate system in POS 5 is one of three condensate pumps with a flow path to the reactor through the feedwater start-up flow control valve.

For further mformation, refer to the success criteria W M W Em e m M & QS m @@- modeled in the fault tree, discussions in Section 5. 8.6.2 Condensate Interfaces and 8.6.6 Condensate Assumptints Dependencies (1) Hardware failures of the condensate pumps system

    'Ihe required system dependencies for the condensate                    were assumed negligib'.e since there are three system as a low pressure injection system are less                      available pump trairA The common mode 8-16                                                 Vol. 2, Part 1 l NUREG/CP.-6143                                                                                                               I

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Systems Analysis CONDENSATE SYSTEM

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I Figure 8.6-2 Condensate Dependency Diagram NUREGICR-6143 8-18 Vol. 2, Part 1

Systems Analysis failure of these pumps from loss of offsite power The function of the LPCS System is to provide coolant to was included in the fault tree. the reactor vessel during accidents in which vessel pressure is low. (2) To utilize the condensate system as a low pressure injection system, the operator must open the The LPCS system is a single train system consisting of feedwater startup valve and place it in single motor operated and manual valves and a motor-driven element control. He startup valve is air operated pump. The LPCS pump is rated at 7115 gpm with a and fails closed on loss of air . Bypass valves and discharge head of 319 psig. He LPCS pump takes water other injection paths are available but also require from the suppression pool through strainers located 10 operator action. feet above the suppression pool floor. The LPCS pump is located in the auxiliary building at elevation 93'0* in (3) In POS 5 it is assumed that Condensate is not an enclosed room with fire / flood doors. A simplified normally operating. Therefore in order to use schematic of the LPCS is provided by Figure 8.7.1. condensate, the operator must manually align the Major system components are shown with valves shown condensate system for injection and start the in their normal standby position. condensate pumps. It is assumed that only the condensate pumps are required, i.e., the The LPCS system is automatically initiated and condensate booster pumps are not required, they controlled. The operator may be required to manually will be bypassed. start the system if an automatic actuation failure occurs. (4) In POS 5 it is assumed that the condensate pump's The success criterion for the LPCS system is injection at minimum flow valve must open for condensate rated flow to the reactor vessel. For further information, success since the amount of water needed for refer to success criteria discussions in Swtion 5. injection is much less than the minimum flow requirements of the pumps (3768 gpm). The Most of the LPCS system is located in the auxiliary minimum flow valve is modeled for failure to building. Because of the relative location of the system open. components, local access to the LPCS system would not be affected by either containment venting or containment (5) In POS 5 the need for condensate injection may be failure. Room cooling failure is assumed to fail the intermittent, therefore multiple opening and closing LPCS pump in four hours. Refer to Section 8.17 for of the startup level control valve may take place. further information on room cooling. It is assumed that if condensate successfully starts the operator will maintain condensate in 8.7.2 LPCS Interfaces and Dependencies recirculation mode. The LPCS system major dependencies are DC control (6) Condensate power dependencies were not modeled power for initiating the actuation relay logic and LPCS at the 4160 or MCC level due to the redundancy pump breaker, AC power for operating the LPCS pump provided in the system. Instead the common and valves, and LPCS pump room cooling. mode failure of the condensate system due to LOSP was modeled. The DC power is provided by Division 1 125 V DC Panel IE124Bl. Power for the LPCS pump is provided by Division 14160 V AC Bus 15AA, and power for the 8.6.7 Condensate Operating Experience valves is provided by Division 1480 V AC MCC 15B11. A simplified dependency diagram of the LPCS system is Generic failure data were used to quantify the fault tree provided in Figure 8.7.2 Major dependencies are logic model, indicated by the solid diamonds. 8.7 Low Pressure Core Spray (LPCS) Upon the receipt of a LPCS injection signal, a start signal is sent to the LPCS pump, the injection valve is SySteng demanded to open, and the test return valve is demanded 8.7.1 LPCS System Description Vol. 2, Part 1 8-19 NUREG/CR-6143 1

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Systems Analysis LOW PRESSURE CORE SPRAY SYSTEM

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3 l I 2L A DC v v POWER 2 3 LPCS TUATION $ $ EMERGENCY VENTLATING t4G)( ~ ~ ~~ -h - --- DEPENDENCY DAGRAM S SHOWN USING FALURE LOGIC. (1) SEE ACTUATION DAGRAM (FIGURE 8.3-3). (2) DEPEtOENCY NOT REOU! RED DURING SHORT TERM OPERATION. Mgure 8.7.2 LPCS Dependency Diagram l l Vol. 2, Part 1 8-21 NUREG/CR-6143

Systems Analysis the receipt of either a low reactor water level (-150 explicitly modeled in the fault tree. inches) signal or high drywell pressure (+2 psig) signal. A simplified actuation dependency diagram of the major There are several human errors incorporated into the cmergency coolant actuation subsystems is provided in LPCS fault tree inodel. These errors are miscaliberation Figure 8.3.3. All actuation sensors are shared with the of various sensors, failure to manually backup automatic LPCI Train A. LPCS actuation and control circuitry are actuation, end failure to restore valves to their proper in Division 1. The LPCS pump has a minimum flow line position following maintenance. valve (normally open) which is demanded to open given a pump start. 8.7.6 LPCS Assumptions 8.7.3 LPCS Test and Maintenance (1) During construction of the fault tree, it was necessary to determine which components could be The LPCS surveillance requirements are the following: taken out of service for maintenance. It was (a) pump operability once a month, (b) MOV operability assumed that maintenance would require once a month, (c) pump capacity test once a month, and components to be effectively removed from the (d) system functional test including simulated automatic system. Standard safety precautions of component actuation once every operating cycle, isolation were used; the general guidelines used were double blockage for high pressure piping or 8.7.4 LPCS Technical Specifications components and single blockage for low pressure piping or components. In POS 5, at least two of the following emergency core (2) The minimum flow line for the pump was not cooling systems must be operable: 1) LPCS; 2) any of the three trains of the Low Pressure Coolant Injection considered as a potential diversion path because of its size and the presence of a restricting orifice in (LPCI) system; or 3) HPCS. this line. If only one of the above systems is operable, at least one of the remaining systems must be made operable within 4 (3) The LPCS system actuation circuitry was not hours. Otherwise, all activities with the potential for modeled at a great levi. of detail. Only elements which were felt to be potentiary important were draining the Reactor Vessel must be suspended. included in the fault tree model. Hardware With none of the above systems operable, Core failures of relays and permissives were grouped Alterations and all activities with the potential for into one term. The initiating signal sensors and draining the Reactor Vessel must be suspended, and at their support systems were explicitly modeled since least one of the above systems must be restored within they are shared between various ESF systems. four hours. Otherwise, secondary containment integrity must be established within the following eight hours. (4) Failure of room cooling is assumed to fail the LPCS pump in four hours. - 8.7.5 LPCS Logic Model Failure of the suppression pool because of random (5) failure or the plugging of all its strainers is The LPCS system was modeled using a fault tree for the assumed to be negligible compared to other system injection of coolant to the reactor vessel. The major failures. retive system components and most passive system components were modeled. The fault tree model (6) Piping with a diameter of greater than or equal to representing the LPCS system is presented in Appendix one third of the main system piping was I. considered as a potential diversion path. Pipe ruptures were considered negligible compared to other system faults. Piping with a diameter of grec.ter 8.7.7 LPCS Operating Experience than or equal to one third of the main system piping were Generic failure data were used to quantify the fault tree considered as potential diversion paths. logic model. The potential for fire events to fail the LPCS system are NUREG/CR-6143 8-22 Vol. 2, Part I

Systems Analysis 8.8 Low PrcSSure Coolant Injection ne DC power to Train A is provided by Division 1 125 V DC; for Trains B and C it is provided by Division 2 (LPCI) System 125 V DC. Power for RHR Pump A is provided by Division 14160 V AC Bus 15AA. Power for RHR 8.8.1 LPCI System Description Pump B and LPCI Pump C is provided by Division 2 { 4160 V AC Bus 15AB. All pumps require pump ' < The function of the LPCI system is to provide coolant to

I*I'. A sunplified dependency diagram of the LPCI .

the reactor vessel during accidents in which system system is provided by Figure 8.8.2. He raajor + pressure is low. The LPCI system is but one mode of dependencies are indicated by the solid diamonds. the RHR system and, as such, shares components with other modes. The LPCI system is a three train system .. . . Each normally closed injection valve receives motive consisting of motor operated valves and motor driven pumps. The three pumps are each rated at 7450 gpm. P **'I' "" 480 V AC source. Tram, A mjection Trains A and B cach have two heat exchangers in series va Ws source is the Division 1480 V AC Bus 15B31 downstream of the pump. Train C is injection dedicated "". . Trains B and C m, jection valves' source is the Divisi n 2 480 V AC Bus 16B31. Many components of end has no heat exchangers. Cooling water flow to the the LPCI system are shared with the different modes of heat exchangers is not required for the LPCI mode. The the RHR system. These commonalities are as follows: LPCI pump suction source is the suppression pool. He LPCI pumps are located in the auxiliary building at (I) the RHR pumps A and B are common to the elevation 93'0* in an enclosed room with fire / flood LPCI, Suppression Pool Cooling (SPC), doors. A simplified schematic of the LPCI system is Shutdown Cooling (SDC), and Containment provided in Figure 8.8.1, Major system components are , Spray (CS) modes; and J shown with valves shown in their normal standby l position. (2) the suppression pool suction valve for Pump The LPCI system is automatically initiated and Trains A and B is common to the LPCI, SPC, and CS modes. controlled. However, operator intervention tray be required to manually realign and start the system in POS . . 5 since the individual RHR Trains A and B could be Up n receipt f a LPCI m. .jection signa 1, start signals are aligned for shutdown cooling or ADHRS and Train C sentt all umps.P Trams A, B and C m, y,ection valves could be aligned for ADHRS, given any of these are demanded to open. The test return valves are i configurations, the associated train would not demanded to close. The LPCI system a,s automatically automatically initiate for LPCI operation. initiated on the receipt of either a low reactor water level signal (-150 inches) or a high drywell pressure signal i The success criterion for the LPCI system is injection of (+2 psig). A simplified actuation dependency diagram j flow from any one pump to the reactor vessel. For of the major emergency coolant actuation subsystems is ; further information, refer to success criteria discussions Provided by Figure 8.3.3. in Section 5. Actuation sensors are LPCI actuation and control Most of the LPCI system is located in the auxiliary circuitry are divided into two divisions. Division A is building. Because of the relative location of the system associated with the actuation and control of components f i components, local access to the LPCI system would not in loop A, and Division B is associated with the { be affected by either containment venting or containment actuation and control of components in Loops B and C. i failure. Room cooling failure is assumed to fail the RHR pumps in four hours. Refer to Section 8.17 for further 8.8.3 LPCI Test and Maintenance ; information on room cooling. [ ' The LPCI system surveiliance requirements are the 8.8.2 LPCI Interfaces and Dependencies following: (a) pump ope rability once a month, (b) MOV - l operability once a month, (c) pump capacity test once ! i The LPCI system major dependencies are DC control every three months, and (d) system functional test ! power for initiating the actuation relay logic and RHR including simulated automatic actuation test once every l pump breakers, AC power for operating the RHR pumps operating cycle. , and valves, RHR pump cooling, a id RHR pump room ! l cooling. l f Vol. 2, Part 1 8-23 NUREG/CR-6143 I __i

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Vol. 2, Part 1 8 25 NUREG/CR-6143

Systems Analysis other system faults. Piping with a diameter of greater 8.8.4 LPCI Technical Specifications than or equal to one third of the main system piping were considered as potential diversion paths. In POS 5, at least two of the following emergency core The potential for fire events to fail the LPCI system are cooling systems must be operable: 1) LPCS; 2) any of the three trains of LPCI; or 3) HPCS. explicitly modeled in the fault tree. There are several human errors incorporated into the If only one of the above systems is operable, at least one LPCI system fault tree model. These errors are (a) of the remauung systems must be made operable within 4 failure to manually backup automatic actuation (b) hours. Otherwise, all activities with the potential for failure to restore valves to their proper position following draining the Reactor Vessel must be suspended. maintenance, (c) failme to realign LPCI Train C from ADHRS, (d) failure to realign LPCI Train B from With none of the above systems operable, Core Alterations and all activities with the potential for SDC, and (e) failure to realign LPCI Train B from draining the Reactor Vessel must be suspended, and at ADHRS. least one of the above systems must be restored within four hours. Otherwise, secondary containment integrity 8.8.6 LPCI Assumptions must be established within the following eight hours. (1) LPCI pump room cooling failure is assumed to fail 8.8.5 LPCI Logic Model the LPCI pumps in four hours. (2) During construction of the fault tree, it was The LPCI system was modeled using a fault tree for the nece%ary to determine which components could be injection of coolant to the reactor vessel, taken out of service for maintenance. It was assumed that maintenance would require To handle the various configurations the RHR system components to be effectively removed from the may be POS 5, the LPCI fault tree logic covers the sv .em. Standard safety precautions of component following configurations: aois n were used. The general guidelines used Cd uble blockage for high pressure piping or

LPCI Train B aligned in standby LPCI mode, components and single blockage for low pressure Pii P ng or components.
LPCI Train B aligned for SDC, (3) The minimum flow line for each pump is not
LPCI Train B aligned for ADHRS, considered as a potential diversion path because of its small sire (less than one third of the main flow
LPCI Train C in standby LPCI mode, and line).

(4) Pump isolation because of spurious signals is

LPCI Train C aligned for ADHRS. assumed to be negligible compared to other systems faults.

The application of the LPCI fault tree is dependent on the (5) The LPCI actuation circuitry was not modeled at a accident sequence being quantified and must be used with an understanding of the configuration prior to the great level of detail. Only elements which were initiating event and following the initiator. Given the felt to be potentially imponant were included in the fault tree model. The initiating signal sensors configuration, the appropriate logic development must be trimmed from the LPCI fault tree before quantification, and their support systems were explicitly modeled Note that m quantifying the accident Fequences in POS 5, since they are shared between various ESF RHR Train A was assumed to be unavailable. systems. The major active system components were modeled. The (6) The presence of a containment spray actuation fault tree model representing the LPCI system is signal was assumed to fail LPCI Trains A and B because flow would be diverted to the sprays. No presented in Appendix 1. other diversion paths were considered. Pipe ruptures were considered negligible compared to 8-26 Vol. 2, Part 1 NUREG/CR-6143

Systems Analysis (7) Flow through the heat exchangers is not required The SSW cross-tie system is used to provide a coolant for LPCI system success. makeup source to the reactor vessel during accidents in which normal sources of emergency injection have failed. (8) The spent fuel pool is an alternate suction source The SSW cross-tie system is comprised of Train B of the which must be manually valved in and, therefore, SSW system and Train B of the LPCI system. is not included in the model. The SSW cross-tie system uses SSW Pump B to inject (9) Failure of the suppression pool from random water into the reactor via the LPCI system Train B failure or tha plugging of all its strainers is injection lines. For a description of the components, assumed to be negligible compared to other system refer to Sections 8.16 and 8.8, respectively. A failures. simplified schematic of the SSW cross-tie system is provided in Figure 8.9.1. Major system components are (10) Piping with a diameter of greater than or equal to shown in their normal standby position with valves one third of the main system piping were shown. The SSW cross-tie system has no automatic considered as potential diversion paths. actuation. The system must be manually aligned and ' manually actuated. (I1) For those accident sequences in which RHR Train B is in SDC prior to asking LPCI, the operator 8.9.2 SSW Cross-Tie Interfaces and must realign the RHR pump B suction valves from Dependencies the reactor recirculation line to the suppression pool for LPCI B to be success. This realignment The dependencies for this system are the same as those does not occur automatically given a LPCI for SSW Train B and LPCI Train B and are shown in actuation signal. Figure 8.9.2. The major dependencies are indicated by the solid diamonds. He RHR heat exchangers are not (12) For those sequences in which ADHRS is/was in needed for this system, operation prior to asking LPCI, the operator must realign the RHR pumps B and C suction valves t the suppression pool for LPCI success. This 8.9.3 SSW Cross-Tie Test and Maintenance realignment does not occur automatically given a g ;; ; g ; ygy, ;, g LPCI actuation signal. same as that for the LPCI Train B. The surveillance requirement n the pump is the same as that for SSW (13) The fault tree logic was developed assuming the Pump B. This specific abgnment is not tested, SSW system must start and run upon LPCI actuation even though SSW may already be successfully operating given prior conditions (e.g. 8.9.4 SSW Cross-Tie Technical SDC operation). Specifications (14) he LPCI Train A logic only models the Although there are no technical specifications on this configuration where Train A is aligned in standby system specifically, the pump is bound to the SSW LPCI mode since in POS 5 Train A will be technical specifications (Section 8.16.4) and the injection assumed to be unavailable. valve is bound to the LPCI technical specifications (Section 8.8.4). 8.8.7 LPCI Operating Experience Generic failure data were used to quantify the fault tree 8.9.5 SSW Cross-Tie Logic Model logic model. The SSW cross-tie system was modeled using a fault tree 8.9 Standby Service Water cross-Tie for the injectim of cwlant to the reactor vessel. Tim

                                                                                    ""i ' *"'i"* 'yStem C mPonents and most passive system (SSWXT) System                                                                components were modeled. The fault tree model representing the SSW cross-tie system is presented in 8.9.1 SSW Cross-Tie System Description                                               Appendix 1.

Vol. 2, Part 1 8-27 NUREG/CR-6143 1 1

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MANUAL ACTUATION

DEPENDENCY DIAGRAM IS SHOWN USING FALURE LOGIC. Figure 8.9.2 SSW Cross-Tie Dependency Diagrmn Vol. 2, Part 1 8-29 NUPIG/CR-6143 i

Systems Analysis i Pipe Ruptures were considered negligible compared to train system consisting of one motor driven pump and other system faults. Piping with a diameter of greater two diesel-driven pumps. The pumps can each provide than or equal to one third of the main system piping were 1500 gpm at 125 psig. He pumps feed into a common considered as potential diversion paths. header that supplie*, water to the fire hoses. The pumps take suction from two 300,000 gallon water storage ne potential for fire events to fail SSW Crcss-Tie are tanks. Any pump can take water from either tank. He fire hoses are connected via an adapter to various test explicitly modeled in the fault tree. connections in the auxiliary building. These connections one hmnan error is incorporated into the SSW cross-tie feed into varinus injection systems and water can then be fault tree. His is failure of th.opcrater to pmperly injected through the systems' injection valve. The pumps align the system. are located la tl.c firewster pump house. A simplified schematic of the firewater system is provided in Figure 8.10.1. l 8.9.6 Arumptions in the SSW Cross-Tie 1 Mode! The firewater system, when used for injection, must be manually initiated and controlled. The operator is (1) His system may be unavailable because of test and required to align the system and to start the pumps. maintenance without violating technical specifications. The success criteria for the firewater system is injection (2) Proper alignment and actuation of this system is of flow from any one pump. For further information, considered as one event. refer to the success criteria discussions in Section 5. (3) The SSW pump does not require room cooling. His is assumed because the pump is housed in a Because of the relative location of the system building next to the cooling tower, with normally components, local access to the firewater system would open louvered walls. Adequate ventilation for room not be affected by either containment venting or cooling was assumed. containment failure. (4) Piping with a diameter of greater than or equal to one third of the main system piping were considered 8.10.2 Firewater Interfaces and as potential diversion paths. Dependenc.ies (5) The fault logic assumes the operator will always The two diesel driven firewater pumps have no outside have to start SSW Train B even though in POS 5 interfaces c: dependencies; each pump has self-contained there will be conditions where the pump is already battenes that provide it with starting power. The electric operating (e.g., required for operation of SDC train motor-driven pump requires BOP AC power. B. 8.9.7 SSW Cross-Tie Operation Experience 8.10.3 Firewater Test and Maintenance The firewater system surveillance requirements are the Generic failure data was used to quantify the fault tree f 11 wing: (a) water supply volume once a week, (b) logic model. pump operability once a month, (c) diesel fuel storage

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8.10 Firewater (FW) System every three months,(e) diesel inspection once every eighteen months, (f) electrolyte level in every cell and 8.10.1 Firewater System Description overall set voltage for the diesel battery banks once every seven days, and (g) battery case, racks, and terminal The firewater system was modeled as a backup source of inspection once every eighteen months. Iow pressure injection. He firewater system is a three NUREG/CR-6143 8-30 Vol. 2 Part 1

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d i Systems Analysis Firewater Technical Specifications Firewater. For initiators or sequences where 3.10.4 one division of AC power or instrument air is 1 If two of the three firewater pumps or either water lost, the isolation AOV's will fail closed. In order to use the firewater system given these storage tank is made or found to be inoperable for seven conditions the MOV bypass valve must be days, an alternate backup pump or supply may be opened by the operator. It is assumed the provided after the seven days. If this requirement cannot be met, the reactor is to be in hot shutdown in twelve operator action to open the MOV dominates as hours and cold shutdown within the following compared to the hardware failure of both valves, twenty-four hours, therefore the MOVs were not modeled. For sequences where at least one AC division is lost or instrument air is lost, gate FW4 (the 8.10,5 Firewater Logic Model modeling of the FW AOVs failing to open on demand given power and air available) should be The firewater system was modeled using two separate trimmed from the Firewater Fault trees. fzult trees for: 1) The injection of water into the reactor vessel to maintain reactor water level; and 2) the i 8.10.7 Fire Water Operation Experience injection of water into the reactor vessel for flooding containment. The major active components were modeled. Generic failure data was used to quantify the fault tree logic model. Piping and hose mptures were considered negligible as compared to other system faults. Piping with a diameter j of greater than or equal to one third of the main system 8.11 Residual Heat Removal: l i piping were considered as potential diversion paths. Suppression Pool Cool.ing (SPC) l Re potential for fire events to fail the firewater system System ! were explicitly modeled in the fault trees. j One human error is incorporated into the firewater system fault tree. This is failure of the operator t The function of the SPC system is to remove decay heat properly align and actuate the firewater system for from the suppression pool during an accident. The SPC mjection. system is but one mode of the RHR system and, as such,

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8.10.6 Assumptions The SPC system is a two train system consisting of (1) Piping with a diameter of greater than or equal motor-operated valves and motor driven pumps. Both i to one third of the main system piping were trains have two heat exchangers in series downstream of considered as potential diversion paths. the pump. Each pump is rated at 7450 gpm. Cooling water flow to the heat exchanger is required for the SPC (2) Because there are several different paths through mode. The SPC suction source is the suppression pool. which injection can occur, the individual failures The pumps are located in the auxiliary building at l of all the injection valves were considered to be elevation 93'0* in an enclosed room with fire / flood J negligible compared to other failures and were doors. A simplified schematic of the SPC (RHR) system ; i not modeled. is provided by Figure 8.11.1. Major system components are shown with valves shown in their normal standby (3) The firewater diesel-driven pumps' operating position. self-contained batteries were modeled as part of the pump boundary. T he SPC system is manually initiated and controlled. The operator is required to align the system and to start (4) The firewater discharge header isolation AOVS the pumps. In POS 5 the RHR system configuration is are auxiliary building isolation valves and accident sequence dependent, i.e., RHR Trains A and B therefore loss of division 1 or 11 AC power or can be aligned in (1) Standby LPCI mode, (2) SDC instrument air will result in isolation of mode, or (3) ADHRS. The operator action to align for l l 8-32 Vol. 2, Part I NUREG/CR-6143

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Systems Analysis SPC is dependent on the configuration RHR is in prior to The SPC mode is manually initiated. If an injection or asking SPC. spray signal is generated subsequent to the initiation of the SPC system, the SPC system will automatically ne success criterion for the SPC system is injection of realign to the LPCI or CS mode, respectively. flow from any one pump / heat exchanger train to the suppression pool. For further information, refer to the 8.11.3 SPC Test and Maintenance success criteria discussions in Section 5. The SPC system surveillance requirements are the Most of the SPC system is located in the auxiliary following: (a) pump operability once a month, (b) MOV building. Because of the relative location of the system operability once a month, and (c) pump capacity test components, local access to the SDC system would once every tluee months. not be affected by either containment venting or containment failure. Room cooling failure is assumed to 8.11.4 SPC Technical Specifications feil the RHR pumps in four hours. Refer to Section 8.17 for further information on room cooling. No requirements in POS 5. 8.11.2 SPC Interfaces and Dependencies 8.11.5 SPC Logic Model The SPC system major dependencies are DC control The SPC system was modeled using a fault tree for the power for actuation, AC power for operating the RHR removal of decay heat from the suppression pool. pumps and valves, RHR pump cooling, and RHR pump To handle the various configurations the RHR system room cooling. may be in POS 5, the SPC Fault tree logic covers the The DC power to Train A is provided by Division 1 125V l>C; for Train B it is provided by Division 2125

RHR Train A in standby LPCI mode, .

J V DC. Power for RHR Pump A is provided by Division 14160 V AC Bus 15AA. Power to RHR Pump B is

RHR Train B in Standby LPCI mode, provided by Division 2 4160 V AC Bus 16AB. Both pumps require pump cooling. A simplified dependency
RHR Train B aligned for SDC, and diagram of the SPC system is provided by Figure 8.11.2.

The major dependencies are indicated by the solid diamonds. Each loop's normally closed suppression pool

RHR Train B aligned for ADHRS.

inlet valve receives motive power from one 480 V AC source. The application of the SPC fault tree is dependent on the accident sequence being quantified and must be used with Many components of the SPC system are shared with the an understanding of the system configuration prior to the different modes of the RHR system. Rese initiating event and following the initiator. Given the configuration, the appropriate logie development must be j commonalities are as follows: trimmed from the SPC fault tree before quantification. ! (a) the RHR pumps are common to the SPC, Note that in quantifying the accident sequences in POS 5 LPCI, CS, and SDC modes; and RIIR Train A was assumed unavailable. l l (b) the suppression pool suction valve for each The major active system components were modeled. . I pump train is common to the SPC, LPCI, The fault tree model representing the SPC system is and CS modes. presented in Appendix 1. Piping ruptures were considered to be negligible SPC control circuitry is in two divisions. Division A is compared to other system faults. Piping with a diameter essociated with control of components in Loop A, and of greater than or equal to one third of the main system Division B is associated with control of components in piping were considered as potential diversion paths. Imop B. 8-34 Vol. 2, Part 1 NUREG/CR-6143

Systems Analysis l l l RESOUAL HEAT S PE bN POOL COOUNG f3 i I l TRAIN A TRAIN B PUMP AND PUMP AND VALVES VALVES ( 3 f 3 em em Ak 1 1r AC 2 J L POWER 3 7 r JL 1 1r DC 2 J L POWER 3 7 F STANDBY Jk C B I C EMERGENCY VEigTING S R M , _ __ _ _, 1 STANDBY JL RVICE A 3r {b0 G) B jh C MAtAJAL ACTUATON jg j g 7F 1r DEPEPOENCY DAGRAM G SHOWN USING FALURE LOGC. (1) DEPEtOENCY tCT RE0VRED DURING $HORT TERM OPERATON. Figure 8.11.2 SPC Dependency Diagram Vol. 2, Part 1 8-35 NUREG/CR4143 l

1 l Systems Analysis The potential for fire events to fail SPC are explicitly injection valves, and the heat exchanger bypass modeled in the fault tree. There are two human errors valve for SPC success. incorporated in the SPC system fault tree. These are (a) failure of the operator to properly align and actuate the (9) The fault tree logic was developed assuming the SSW system is in standby even though SSW may SPC mode and (b) failure to restore valves to their proper position following maintenance. already be successfully operating given prior conditions (e.g., SDC operation). 8.11.8 SPC Assumptions

                                                                                                                                             '.10)       In POS 5, SPC Train A is assumed to be Flow through the heat exchangers is required;                                                                    unavailable.

(1) therefore, the heat exchanger bypass valves must close for success. 8.11.7 SPC Operating Experience During construction of the fault tree, it was Generic failure data were used 'o quantify the fault tree (2) necessary to determine which components could logie model. be taken out of service for maintenance. It was assumed that maintenance would require components to be effectively removed from the 8.12 Residual Heat Removal: system. Standard safety precautions of Shutdown Cooling (SDC) System component isolation were used; the general guidelines used were double blockage for high 8.12.1 SDC Description pressure piping or components and single blockage for low pressure piping or components. He function of the SDC system in POS 5 is to remove decay beat during shutdown and during accidents in (3) The minimum flow line for each pump is not whicli reactor vessel integrity is maintained. He SDC considered as a potential diversion path because , system is but one mode of the RHR system and, as such, of its small size (less than one third of the main shares components with other modes. go, j;,,), The SDC system is a two train system consisting of (4) Pump isolation because of spurious signals is m t r*Perated valm and motor drim pmnps. Both assumed to be negligible compared to other trains have two heat exchangers in series downstream of tem faults

the pump. Each pump is rated at 7450 gpm. Cooling water flow to the heat exchanger is required for the SDC (5) Failure of the suppression pool from random m e. He SDC system suction source is one failure or the plugging of all its strainers is meimu ation pump s suction line. The pumps are located

! assumed to be negligible compared to other in the auxiliary building at elevation 93'0" in an enclosed l

                                             'I' #" '" " * ' '                                                                                 room with fire / flood doors. A simplified schematic of the SDC (RHR) system is provided by Figure 8.12.1.

(6) Piping with a diameter of greater than or equal to one third of the main system piping were F*I"# sys em mPonents am shown wMalm shown in their normal standby operating position. considered as potential diversion paths. In POS 5 either SDC or ADHRS is in operation (7) For those accident sequences in which RHR rem ving decay heat. If ADHRS is in operation one Train B is in SDC mode prior to asking SPC, , Train of SDC is in standby. From standby, the SDC is the operator must reah.gn the pump suction manually aligned and started when placed in operation. valves from the reactor recirculation line to the Note that for the POS 5 analysis Train A'of RHR ha suppression pool and realign the SPC and SDC a e ilaW de @m injection valves for SPC success. The success criterion for the SDC system is injection of (8) For those sequences in which ADHRS is in U w fimn any ne Pump / heat exchanger train to the operation prior to asking SPC, the operator must mactor msd For fmeer information, ufu to h realign the pump suction valves to the , su cess criteria discussed in Section 5. suppression pool, realign the SPC and LPCI NUREG/CR-6143 8 36 Vol. 2, Part I

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Systems Analysis Most of the SDC system is located in the auxiliary d. High reactor vessel pressure - 13S psig. building. Because of the relative location of the system components, local access to the SDC system would not be affected by either containment venting or containment Upon actuation, the shutdown cooling isolation signal failure. Room cooling failure is assumed to fail the RHR closes the following valves: pumps in four hours. Refer to Section 8.17 for fmther information on room cooling, a. Shutdown Cooling Inboard Suction Isolation Valve F009. 8.12.2 SDC Interfaces and Dependencies

b. Shutdown Cooling Outboard Suction Isolation Valve F008.

The SDC system major dependencies are DC control power for actuation, AC power for operating the RHR

c. Heat Spray Isolation Valve - F023. F394.

pumps and valves, RHR pump cooling, and RHR pump room cooling.

d. Shutdown Cooling Injection Valves - F053A/B.

"Ihe DC power to Train A is provided by Division 1 125 This action isolates shutdown cooling and blocks the V DC, and for Train B it is provided by Division 2125 V DC. Power for RHR Pump A is provided by Division              reopening of these valves until shutdown cooling isolation 14160 V AC Bus 15AA. Power to RHR Pump B is                    has been reset.

provided by Division 2 4160 V AC Bus 16AB. All Each suppression pool suction valve and SDC suction pumps require pump cooling. A simplified dependency valve is interlocked. The Train A suppression pool diagram of the SDC system is provided by Figure suction valve must be fully closed before the SDC 8.12.2. 'Ibe major dependencies are indicated by the suction valve can be opened. The same is true for Train solid diamonds, B valves. Each normally closed injection valve receives motor There is no automatic initiation of the SDC mode of the power from 480V AC sources. Train A's injection valve source is Division 1480 V AC and Train B's injection RHR - manual actuation is required. If an LPCI injection signal or a CS spray signal subsequently occurs, valve source is Division 2 480 V AC. the RHR system will automatically be realigned to the LPCI or CS mode respectively. However, the operator Many components of the SDC system are shared with the must manually open the suppression pool suction valves different modes of RHR system. These commonalities are as follows: (1) the RHR pump flow paths are (MV4A and MV4B) after ciudng the SDC suction valves common to the SDC, SPC, CS and LPCI modes and (2) (MV6A/B, MVA and MV9). the heat exchangers are common to the SDC, LPCI, SPC, and CS modes. 8.12.3 SDC Test and Maintenance The two SDC suction valves MV8 and MV9 are common to both SDC pumps. Valve MV8 requires Division 1 The SDC system surveillance requirements are the 480 V AC and valve MV9 requires Division 2 480V AC. following: (a) pump operability once a month, (b) MOV Complete failure of the SDC system will occur if either operability once a month, and (c) pump capacity test of these valves fails to operate. The SDC s.ution valves once every three months. automatically iso' ate when a Containment Isolation signal or a Shutdown Cooling Isolation signal is generated by: 8.12.4 SDC Technical Specifications

a. RHR equipment area ventilation high differential temperature of 99

F. In POS S, whenever the RPV pressure is less than RHR permissive setpoint, at least two of the SDC loops shall

b. RHR equipment area high temperature 165

F. be operable (one pump and one heat exchanger), with at least one loop operating if no recirculation pumps are in

c. Low reactor water level (Level 3) - 10.4 operation.

inches. 8-38 Vol. 2, Part 1 NUREG/CR-6143

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1 l 1 Systems Analysis

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l Systems Analysis Ifless than two loops are operable, the operability of the modeled in the Fault tree as failing SDC since Alternate Decay Heat Removal System (ADHRS) must draining the reactor vessel to the suppression pool be demonstrated. would result in a level 3 trip of SDC. If no loops are operational an alternate circulation method (4) Pump isolation because of spurious signals is must be established within one hour and temperatures and assumed to be negligible compared to other system pressures must be monitored at least once per hour. faults. 8.12.5 SDC Logic Model (5) Flow through the heat exchangers is required - therefore, the heat exchanger bypass valves must close for success, The SDC system was modeled using three independent foult trees for removal of decay heat from the reactor (6) SDC failure from a test's diverting flow is felt to be vessel: (1) Failure of SDC Train A to start and run from standby, (2) Failure of SDC Train B to start and run negligible because this mode is manually initiated from standby, and (3) failure of SDC Train B to continue and aligned. to operate. The major active system components were snodeled. The fault tree model representing the SDC (7) Piping with a diameter of greater than or equal to one third of the main system piping were considered system is presented in Appendix I, as potential diversion paths. He potential for fire events to fail SDC are explicitly modeled in the fault tree. Piping ruptures were (8) Spurious opening of MV42A/F (LPCIinjection valve) fails SDC even though the SDC operating considered to be negligible compared to other system faults, procedure allows this flow path for SDC injection. , Piping with a diameter of greater than or equal to one 8.12.7 SDC System Operating Experience t third of the main system piping were considered as potential diversion paths. Generic data were used to quantify the fault tree logic , model. There is one human error incorporated into the SDC system fault trees. This error is failure of the operator to properly align and actuate the SDC system. 8.13 Residual Heat Removal: r Containment Spray (CS) System 8.12.6 SDC Assumptions (1) Proper alignment and actuation of both trains of SDC is considered to be one event. 8.13.1 CS Description } (2) During construction of the fault tree, it was The function of the CS system is two fold: (1) to necessary to determine which components could be suppress pressure in the containment during accident and taken out of service for maintenance. It was (2) to remove fis:; ion product from the containment ; l I assumed that maintenance would require that atmosphere following core damage. The CS system is components be effectively removed from the but one mode of the RHR system and, as such, shares system. Standard safety precautions of component components with other modes. I isolation were used. The general guidelines used were double blockage for high pressure piping or The CS system is a two loop system consisting of components; and single blockage for low pressure motor-eperated valves and motor-driven pumps. There piping or components. are two heat exchanoers in series per loop. Each pump a mea at 7450 gpm. Cooling water flow to the heat (3) 'Ibe pump minimum flow valve MV64A/B is closed exchanger is required for CS when used to suppress prior to starting SDC to prevent draining the reactor pressure in the containment. The CS suction source is i vessel to the suppression pool. The failure of this the suppression pool. The pumps are located in the ; valve to close and failure due to spurious opening is auxiliary building at elevation 93'0" in an enclosed room 8-40 Vol. 2, Part 1 NUREG/CR 6143

I I Systems Analysis with fire / flood doors. A simplified schematic of the CS (b) the suppression pool suction valve for each l (RHR) system is provided by Figure 8.13.1. Major pump train is common to the CS, SPC, and ! system components with valves are shown in their normal LPCI modes; and standby operation position. (c) beat exchanger cooling is common to the CS, The CS system is automatically initiated and may be SDC, and SPC modes. controlled. However, operator intervention is required to manually realign and start the system in POS 5 since the The CS system is automatically initiated by a high individual RHR Train A and B could be aligned for containment pressure, with a ten minute time delay. At shutdovm cooling or ADHRS. Given these this time, if containment pressure is +9 psig and drywell configurations, the associated Train would not pressure is +2 psig, the CS system will be initiated - eutomatically initiate and spray. first, Train A and, 90 seconds later, Train B. Actuation of the CS system closes the LPCI system injection valves The success criterion for the CS system is injection of on Trains A and B, and opens the CS spray valves on flow from any one pump / heat exchanger train to the Trains A and B. Note that in POS 5 a high drywell spray ring. For further information, refer to success and/or high containment pressure signal may not be criteria discussions in Section 5. generated, since in POS 5 the containment is typically assumed to be open for maintenance access. To Most of the CS system is located in the auxidary manually initiate CS, a high drywell pressure signal building. Because of the relative location of the system must be present. If this signal is not present it must be cotaponents, local access to the CS system would not be jumpered in before CS can be manually initiated. effected by either containment venting or containment frilure. Room cooling failure is assumed to feil the RHR CS system control circuitry is in two divisions. Division pumps in four hours. Refer to Section 8.17 for further A is associated with control of components in Train A, information on room cooling. and Division B is associated with control of components in Train B. 8.13.2 CS System Interfaces and Dependencies 8.13.3 CS Test and Maintenance The CS system major dependencies are DC control The CS surveillance requirements are the following: power for actuation, AC power for operating the RHR pumps and valves, RHR pump cooling, and RHR pump (a) pump operability once a month, room cooling. (b) MOV operability once a month. The DC power to Train A is provided by Division 1 125 V DC; for Train B it is pmvided by Division 2125 V (c) Pump capacity test once every three months, DC. Power for RHR Pump A is provided by Division 1 and 4160 V AC Bus 15AA. Power to RHR Pump B is provided by Division 2 4160 V AC Bus 16AB. Both (d) system functional testing, including a pumps require pump cooling. A simplified dependency simulated automatic actuation test, once every dirgram of the CS system is provided by Figure 8.13.2. operating cycle. The major dependencies are ind*cated by the solid diamonds. Each train's normally closed suppression pool inlet valve receives motive pawer from one 480 V AC 8.13.4 CS Technical Specifications source. No requirements in POS 5. Many components of the Cs system are shared with the different modes of the RHR system. These 8.13.5 CS Logic Model commonalities are as follows: The CS system was nodeled using two independent fault (a) the RHR pumps are common to the CS, trees: (1) Pressure oppression in the containment; and LPCI, SPC, and SDC modes; O) %sion product ren.ioval in the containment. The Vol. 2, Part 1 8-41 NUREG/CR-6143

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Systems. Analysis REAOUAL HEAT NT IN SPRAY M E ( 3 l I I TRAIN A TRAIN B PLAP AND PUMP AND VALVES VALVES ( 3 ( A es em 3 AW 7F AC 2 JL POWER 1F 3 2 AL g 1F POWER 2 2k 3 STAtOBY A JL B

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l l l Systems Analysis only difference between the two fault trees is that in (1) system. Standard safety precautions of component ccoling water flow is required to the RHR 5 eat isolation were used; the general guidelines used exchangers while in (2) it is not. To bzdle the various were double blockage for high pressum piping or configurations the RHR system may be in POS 5, the CS components and single blockage for low pressure l feult tree logic covers the followig configurations: piping or components. j l (3) ne minimum flow line for each pump is not

RHR Train A r.ligned in standby LPCI mode, considered as a potential diversion path because of its small size and flow limiting orifice.
RHR Trna B aligned in standby LPCI mode, .

(4) Pump isolation because of spun.ous signals is assumed to be negligible compared to other system 1

RHR Tram. B ab.gned for SDC, and faults.
RHR Train B aligned for ADHRS. (5) The CS control circuitry was not modeled at a )

great level of detail. Only elements which were The application of the CS fault tree is dependent on the felt to be potentially important were included in accihnt sequence being quantified and the status of the the fault tree model. ccr.tainment (open and closed) and must be used with an pderstanding of the system configuration prior to the (6) Diversion of flow to the suppression pool is felt to initiating event and following the initiator. Given the be negligible compared to other system failures. configuration, the appropriate logic development must be trimmed from the CS fault trees before quantification. (7) Failure of the suppression pool from random Note that in quantifying the accident sequence in POS 5, failure or the plugging of all its strainers is RHR Train A was assurned to be unavailable. The major assumed to be negligible compared to other system I cetive system components were modeled. The fault tree failures. models representing the CS system are presented in Appendix 1. (8) Piping with a diameter of greater than or equal to I one third of the main system piping were The potential for fire events to fail CS are explicitly considered as potential diversion paths. modeled in the fault tree. (9) For those accident sequences in which RHR Train nere are several human errors incorporated into the CS B is in SDC prior to asking CS, the operator must , system fault tree model. These errors are: a) failure to realign the RHR pump B suction valves from the manually backup automatic actuation; b) failure to reactor recirculation line to the suppression pool ! restore valves to their proper position followinE for CS B to be successful. This realignment does maintenance; and c) failure to realign CS from SDC or not occur automatically given a CS activation ADHRS alignment. signal. 8.13.6 CS Assumptions (10) For those sequences in which ADHRS is/was in - operation prior to asking CS, the operator must realign the RHR pump B suction valves to the ! (1) CS system failure because of diversion paths was considered to make a negligible contribution to suppression pool for CS success. This realignment system failure since all other injection paths does not occur automatically given a CS actuation automatically close upon receipt of a CS system signal. . actuation signal. (11) The fault tree logic for CS as a means of reducing (2) During construction of the fault tree, it was containment pressure was developed assuming the necessary to determine which components could be SSW system must start and run upon CS actuation taken out of service for maintenance. It was even though SSW may already be successfully assumed that maintenance would require operating given prior conditions (e.g. SDC components to be effectively removed from the operation). NUREG/CR-6143 8-44 Vol. 2, Part 1

Systems Analysir (12) The CS Train A logic only models the signal. Since both signals are expected to be present cetfiguration where Train A is aligned in standby during a venting situation, the operator must also restore LPCI mode since, in POS 5, Train A will be inctrument air to successfully vent. The CVS assumed to be unavailable. dependency diagram is shown in Figure 8.14.2 with major dependencies indicated by solid diamonds. 8.13.7 CS Operating Experience Generic failure data were usul to quantify the fault tree 8.14.3 CVS Test and Maintenance logic model. He contamment purge exhaust lines are leak tested once every taree months. 8.14 Containment Venting System (CVS) 8.14.4 CVS Technical Specifications No requirement in POS 5. 8.14.1 CVS Description 8.14.5 CVS Logic Model When suppression pool cooling and containment sprays have failed to reduce primary containment pressure, the The CVS was modeled in a simple fault tree with failure CVS is used to prevent a prirnary containment pressure to vent r,s the top event. A human error, failure to vent limit from being exceeded. the contai.unent, is included in the fault tree. This error represents failure of the operator to restore instrument The vent path used is a 20-inch diameter purge exhaust air, jumper the damper isolation signals, and open the line which is part of the containment ventilation and dampers. filtration system. His line includes four air-operated d.mpers which are normally closed. All four fail closed 8.14.6 CVS Assumptions on loss of air. Two of the dampers are closed by a containment isolation signal. The other two are closed No assumptions were used in construction of the CVS by the standby gas treatment system initiation. The CVS fault tree. discharges to the roof of the auxiliary building. A schematic of the CVS is shown in Figure 8.14.1. 8.14.7 CVS Operating Experience ne venting procedure requires containment venting Generic data was used to quantify the fault tree logic when the pressure exceeds 17.25 psig. Venting requires g* that the operatorjump the isolation relays for each damper and then open them (they are located on back panels in the control room). The actual venting procedure cara only be initiated by order of the 8.15 Emergency Power System emergency director. (EPS) 8.14.2 CVS Interfaces and Dependencies Containment venting requires instrument air for opening The EPS consists of the AC and DC power divisions the a.ir-operated dampers. He dampers also require required by all systems (except firewater) needed to power from emergency AC Divisions 1 and 2 for midgate postulated accidents. This includes Balance of operation of the solenoids. Plant (BOP) and Engineered Safety Feature (ESF) buses, Both ESF AC and DC power are divided into three Instrument air to the auxiliary building is isolated by a separate divisions. Two of the divisions (1 and 2) are for LOCA signal (high drywell pressure); and instrument air the majority of the ESF and the third (3)is dedicated to to the containment is isolated by a containment isolation the HPCS systent and its required support systems. The EPS is shown m Figure 8.15.1. Vol. 2, Part 1 8-45 NUREG/CR-6143

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Systems Analysis CONTAINMENT VENTING SYSTEM-i

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Systems Analysis The ESF AC divisions normally receive power from one charger can restore the batteries from this minimum of three offsite sources through ESF transformers (34.5 voltage to their fully charged state within eight hours ktf/4.16 kV). In addition to the normal supply from the under normal plant operating conditions. ESF transformers, each ESF 4.16 kV bus has a standby diesel generator which is available to supply bus loads Each ESF DC battery bank consists of sixty lead-calcium upon a loss of normal AC power. These diesels may be type cells connected in series to produce the rated output started manually or automatically. The diesels of 125 V DC. Each ESF batter; bank can supply the supplyingDivisions 1 and 2 buses are rated at 7000 kW required DC loads for eleven hours after a loss of AC cnd start on a loss of normal AC power to the associated power if unnecessary loads are shed, bus, low reactor level of -150 inches, or high drywell i pressure of +2 psig. The diesel supplying Division 3 Most of the EPS is located in the diesel building and in buses (rated at 3300 kW) is exclusively for the HPCS and compartmentalized rooms within the auxiliary building, starts on a loss of normal AC, low reactor water level Any physical impact of accident conditions on the ability (-42 inches), and high drywell pressure signal of +2 of the EPS to perform its function would be minimal, psig. For Divisiona 1 and 2, the transfer of power from Diesel generators are assumed to fail in ~ fifteen minutes normal to backup or emergency power supplies is without room cooling. He battery and switchgear rooms controlled by the load shedding and sequencing system. do not require room cooling success during accident conditions. For Divisions 1 and 2, when a loss of normal power signal occurs, the diesel generators automatically start and connect to the associated ESF bus if no other source 8,15.2 EPS Interfaces and Dependencies of power is available. To prevent overloading the diesel generator when no alternate source is available, Each diesel generator has six subsystems required for its unnecessary loads are shed from the associated bus and operation: (1) fuel oil subsystem, (2) air starting those loads required for plant safety are sequenced onta subsystem, (3) lube oil subsystem, (4) jacket water the bus. For Division 3, when a loss of normal pcwer cooling subsystem, (5) combustion air intake, exhaust cecurs, the diesel generator will start and automatically and crankcase ventilation, and (6) standby generator close on the bus when at speed and voltage. excitation subsystem. With the exception of the combustion air subsystem, all of these subsystems are If Divisions 1 and 2 diesel generators fail to power their normally treated as part of the diesel generator. , buses, power can be supplied to certain Division 1 or 2 However, some of these other subsystems are dependent l loads from the HPCS diesel generator. This is on operation of other systems. The important accomplished by isolating the normal Division 3 loads dependencies are listed below and shown in Figure from the diesel and connecting either the Division 1 or 2 8.15.3 with major dependencies indicated by solid loads to the HPCS diesel generator. The electrical diamonds. equipment that is involved in accomplishing this is shown in Figure 8.15.2. The ESF AC divisions require DC power from the associated ESF DC buses for circuit breaker control The ESF 125 V DC system includes three divisions, each power, diesel generator field flashing, and the diesel fuel consisting of two battery chargers which normally supply oil booster pump. The SSW system is required to supply the load and a bank of batteries which functions as a cooling water to the jacket water cooler. , backup. Divisions 1 and 2 of the ESF DC (Buses llDA and 1IDB, respectively) system supply the majority of the ESF loads. Both are rated at 1600 amperes. The dependencies for ' Division 3' (i.e., when Division 1 Division 3 (Bus 1IDC) is dedicated to the HPCS system or 2 loads are powered from HPCS diesel generator) are , and is rated at 100 ampere hours. the same as those for the HPCS diesel generator (Division 3) shown in Figure 8.15.3. There is a limitation as to which loads can be supported by the The battery chargers normally supplying power to each Division 3 HPCS diesel generator when cross-tied to ESF bus are silicon controlled, rectifier type chargers either Division 1 or 2. The following loads on either rated at 400 amperes,125 V DC. %e ESF battery Division 1 or 2 can be supplied by the Division 3 diesel chargers maintain the terminal voltage of the associated generator: batteries above a minimum of 1.75 volts per cell. Either Voh 2, Part 1 8-49 NUREG/CR-6143

Systems Analysis

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i Systems Analysis ; The specific alignment of Division 1 or 2 loads to the

RHR Pump, HPCS diesel generator is not tested. The surveillance requirements on the diesel are discussed above.

e SSW Pump, Unit batteries' specific gravity, pilot cell voltage and temperature, and overall battery voltage are measured

Motor-Operated Valves, weekly and compared against one set oflimits. Every three months, the voltage and specific gravity of each cell i e Control Room Emergency Fan, are checked and compared against a second set oflimits.

This latter test also includes temperature measurement of ; every sixth cell. Once per operating cycle, unit batteries !

Battery Charger, are load discharge tested, i
Drywell Coolers, 8.15.4 EPS Technical Specifications ;
Fuel Pool Cooling and Recirculation Pump, For POS5 operations, at least one circuit between the ffsite transmission network and the onsite Class 1E ,
SSW Pump Fan, Distribution System, and EDG 11, or 12, as well as ;

EDG 13 when HPCS is required to be operable, shall be e Control Room Air Conditioning and Fan, operable.

SSW Cooling Tower Fans, If all offsite power circuits and/or EDG 11 or 12 are inoperable, suspend the handling of all irradiated fuel in
ESF Electrical Room Cooler Fan, the primary or secondary containment, and during Core Alterations and operations with the potential for draining
Instrument Air Compressor, the reactor vessel.

If EDG 13 is inoperable, restore within 72 hours or

Safeguards Switchgear and Battery Room Fans, declare HPCS inoperable.
ECCS Pump Room Cooler, and Division 1 or Division 2, and (when HPCS is required) -

Division 3 DC power systems must be operable. With

HPCS Diesel Generator Accessories Cooling 60 Division 1 and 2 inoperable, suspend the handling of all !

Water Pumps, irradiated fuel in the primary or secondary contamment j and dming Core Alterations and operations with the

Supply Fan and Auxiliaries. Room cooling is potential for draining the reactor vessel.

required for the diesel generator rooms. The diesel generator room cooling provides combustion air to With Division 3 DC power inoperable, HPCS must be the diesel. declared inoperable. 8.15.3 EPS Test and Maintenance 8.15.5 EPS Logic Models . Each diesel generator is manually started and loaded for The EPS was modeled using separate fault trees for each et least one hour once each month. During this monthly AC bus down to the MCC level and each DC 125 V bus. test, the starting air compressor, diesel fuel oil transfer One human error is incorporated into the fault tree , i pumpa, and diesel starting time are checked. Once per models. This is failure to manually initiate the diesel operating cycle, the condition under which the diesel generators given failure of automatic initiation. The fault i generator is required will be simulated. This test tree models representing the EPS are presented in ; demonstrates that the diesel will start and accept the Appendix I. emergency load within a specified time sequence. Each diesel generator is given an annual inspection in The potential for fire events to fail EPS components are , accordance with instructions based on the manufacturer's explicitly modeled in the fault trees. recommendations. NUREG/CR-6143 8-52 Vol. 2, Part 1

Systems Analysis A fault tree for cross-tying the Division 3 diesel operation of the switchgear and batteries during the generator to power either Division 1 or Division 2 loads accident mission time (twenty-four hours) modeled was also developed. The major active components were in this study. modeled. One human error was incorporated into the fault tree. This is failure of the operator to properly 8.15.7 EPS Operating Experience align the cross-tic and to actuate the diesel generator. Generic data were used to quantify the fault tree basic 8o15.6 EPS Assumptions events. (1) The diesel generators are tested by stanting one generator each week. During this test, the diesel is 8.16 Standby Service Water (SSW) started and brought up to full speed while isolated from its loads. Since the auto sequencing is tumed System off during the test, the operator needs to close the breaker to load the diesel. Therefore, no test unavailability was modeled. 8.16.1 SSW System Description i (2) Short circuit faults and the potential effects of The function of the SSW system is to provide heat i fault propagation were not modeled. removal from plant auxiliaries that require cooling water i during an emergency shutdown of the plant. (3) Actuation of the diesel generators by a LOCA signal was not modeled since of: site power may The SSW system is made up of three independent trains: still be available. Actuation because oflow bus A, B, and C. Each train consists of a motor-driven voltage only was modeled. pump, motor-operated valves, and heat exchangers. Train C is dedicated to the HPCS system. (4) A common cause failure of the diesel generators for AC Divisions I and 2 is included in the associated SSW Pumps A and B are vertical, centrifugal pumps, fault tree. Common cause failure of the HPCS each with a 12,000 gpm capacity. SSW Pump C is also diesel generator (Division 3) was not modeled since a vertical, centrifugal pump, but with only a 1300 gpm it is from a different manufacturer than the other capacity. Each pump takes water from the cooling tower diesel generators, and has its own maintenance basins, circulates water through the heat exchangers for program. each load, and retums the water to the towers through a motor-operated discharge valve. Each train has its own (5) Diesel generator room ventilation and jacket water discharge valve. A signplified schematic of the SSW cooling were required for diesel generator system is provided in Figure 8.16.1. Major system operation. Starting of the diesel generators also components are shown with valves shown in their normal requires DC power. Since normal AC power to the standby positions. bus is assumed lost, the DC power must be supplied by the batteries. The SSW pumps are located in pump houses away from the other buildings on the site, out by the cooling tower. (6) The load shedding and sequencing panels for Because of the relative location of the system emergency AC Divisions 1 and 2 were not included components, local access to the SSW system would not in the models since they consist of highly reliable be affected by either containment venting or failure. solid state logic boards with failure probabilities Each pump house normally has open louvers on the substantially less than diesel generators. walls. This, along with the air current from the proximity of the cooling tower, was assumed to provide (7) Proper alignment and actuation of cross-tying ample room ventilation. Thus, a loss of room cooling to Division 1 or 2 loads to the HPCS diesel generator the SSW pumps was not considered to fail the pumps. were considered as one event (or action). The SSW system is automatically initiated and controlled. (8) The switchgear and battery room Heating However, operator intervention is required to manually Ventilating and Air Conditioning (HVAC) systems start the system given an auto-start failure. are assumed not to be required for continued Vol. 2, Part 1 8-53 NUREG/CR-6143

Systems Analysis

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Systems Analysis PS-17e p, cp r, r ,' k' -

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Systems Analysis 8.16.2 SSW Interfaces and Dependencies systems required to be operable shall be operable. If a SSW subsystem associated with an ECCS pump is The SSW system major dependencies are DC control inoperable, declare that pump inoperable. power for initiating the actuation relay logic, and AC power for operating the SSW pumps and valves. He If the SSW subsystem associated with an RHR loop is ! pumps are self-cooled. found to be inoperable, declare that loop inoperable. The DC power to Trains A, B and C is provided by the Division 1 125 V DC, Division 2125 V DC, and If the SSW susbsystem associated with an EDG is Division 3125 V DC buses, respectively. Power for inoperable, declare that EDG inoperable. SSW Pump A is provided by Division 14160 V AC Bus 15AA. Power for SSW Pump B is provided by Division 8.16.5 SSW Logic Model 2 4160 V AC Bus 16AB. Power to SSW Pump C is provided by Division 3 480 V AC Bus 17B01. A ne SSW system was modeled using separate fault trees simplified dependency diagram of the SSW system is for each of its functions such as LPCS pump room provided in Figure 8.16.2. The major dependencies are cooling, RHR Pump A cooling, etc. The major active j indicated by the solid diamonds, system components and most passive system components were modeled. The fault tree models representing the Each loop's normally closed motor-operated valves SSW system are presented in Appendix 1. receive motive power from a 480 V AC source. Valves on Train A receive power from Division 1. Valves on Piping ruptures were considered to be negligible Train B receive power from Division 2, and valves on compared to other system failures. Only piping with a Train C receive power from Division 3. Upon receipt of diatr.eter of greater than or equal to one third of the main a SSW system actuation signal, start signals are sent to system piping was considered.The potential for fire , all pumps, and all normally closed MOVs that need to events to fail SSW are explicitly modeled in the fault l open are demanded to do so. trees. l The SSW system has diverse methods for actuation: 8.16.6 SSW Assumptions (1) ne signal that actuates a front-line emergency (1) The SSW pumps do not require room cooling. , I system will actuate the system; His is assumed because the pumps are housed in buildings next to the cooling tower with normally , (2) A loss of offsite power will actuate the system; open louvered walls. Adequate ventilation for room j or cooling was assumed, i 1 t (3) The actuation of any pump that requires cooling (2) Because of the diverse and redundant actuation to i from the SSW system will actuate the system. each component, actuation failures of the SSW system were assumed to be negligible compared to Because of this diversity, the failure of the SSW to other system failures and were not modeled. actuate was considered to be negligible compared to other system failures and was not modeled. (3) A common cause failure of SSW pumps A and B was modeled in the fault trees. Common cause

 . 8.16.3 SSW Test and Maintenance                                          failure of SSW pump C was excluded since it is l                                                                                approximately one-tenth the size of SSW pumps A The SSW system surveillance requirements are the                         and B.

following: (a) pump operability once a month, (b) MOV operability once a month, and (c) pump capacity test once every three months. 8.16.7 SSW Operating Experience ; 8.16.4 SSW Technical Specifications Generic failure data were used to quantify the fault tree logic model. In POS 5, the SSW subsystems associated with other NUREG/CR-6143 8-56 Vol. 2, Part 1 l l

Systems Analysis SSW TRAIN A LOADS: SSW TRAIN 8 LOADS: SSW TRAIN C LOADS: LPCS PM DC. A JACkU PW B&C RM DG B JACKET WCS RM RCIC PM. RHR A HTX RHR B&C PMP R4 8 HTX DG C JACKET R$ A RM. RM A PMP. RS COWRESSORS WER n 2 y 3 d) DC 1 h POWER A e v 8 C ACTUATION O <> C I DEPENDENCY DIAGRAM IS SHOWN USING FAILURE LOGIC Figure 8.16.2 SSW Dependency Diagram Vol. 2, Part I g.57 NUREG/CR-6143

Systems Analysis 8.17 Emergency Ventilating System Success of the ECCS pump room systems involves operation of the fan-coil units with associated cooling by the Standby Service Water System. It is assumed that failure of the EVS would fail operating 8.17.1 EVS Description diesel generators in fifteen minutes. The low pressure ECCS pumps are assumed to fail within four hours after De objective of the EVS is to maintain suitable loss of the associated room cooling. HPCS is assumed to temperatures in safety related equipment rooms to fail within twelve hours after loss of room cooling. preclude component failures.

 %e EVS cools the following: (1) standby diesel                     8.17.2 EVS Interfaces and Dependencies generator rooms, (2) pump structure service water pump rooms, (3) pump rooms for the RHR, RCIC, HPCS, and                 The ECCS pump room coolers are all cooled by the LPCS pumps, and rooms containing electrical                         Standby Service Water system. The motive force for the switchgear. The service water pump room system is                   fans for the RCIC, LPCS, and RHR-A pump room is assunal not to be required. Three independent                       provided by AC Division 1. The fans for RHR-B and subsystems, one per diesel generator room, each having              RHR-C pump rooms are powered by Division 2. The 100% capacity, are provided for the emergency diesel               HPCS pump room fan is powered by HPCS dedicated generator rooms to ir.aintain an indoor design                      AC Division 3. A simplified dependency diagram of the temperature of 120*F. Each diesel unit is provided with             EVS is provided by Figure 8.17.2. The major a fan damper system connected to the respective diesel             dependencies are indicated by the solid diamonds.

engineered safety features bus. The fan is controlled to start on diesel generator stutup and stop on diesel The diesel generator room ventilation supply fans are generator shutdown. The damper opens on the same automatically actuated when the diesel generator is signals. A heating coil has been provided to maintain the started. A control room hand switch is also provided. minimum required inside air temperature during cold The discharge air temperature is monitored and a suction weather. The ventilation system for the diesel generator temperature switch is provided to operate the fan at full rooms is shown in Figune 8.17.1. or half capacity to mair.tain the summer maximum and winter minimum space temperature. Also supplied are The cooling and emergency ventilation systems for the locally operated fan-coil units equipped with a heating safety-related pump rooms are shown schematically in coil controlled by a temperature switch and a cooling coil Figure 8.17.1. Each safety-related pump room is controlled by a temperature controller to maintain normal indoor design conditions when the diesels are idle. provided with one full-capacity fan-coil unit to prevent

  !be room temperature from exceeding 150'F during Recirculating fan-coil units for RHR Pump Rooms A, B, pump operation.

and C and the HPCS and LPCS pump rooms are automatically actuated by their respective pump starters The SSW system provides cooling water for the fan-c >il or by manual hand mitches located in the control room. uniti. He units start automatically when the associawl The fan-coil units 6

ized to remove the maximum ECCS pump starts.

expected heat gains in order to maintain the space During normal plant operation, the safety-related pump temperature below 150'F with the pumps in operation. The SSW flow to the cooling coils is 'on-off" with no rooms and penetration rooms are maintained at a slight modulation, negative pressure with respect to the corridors by the fuel handling area ventilation system. Supply air is provided from the auxiliary building ventilation system. Air is drawn from the safety-related pump rooms and 8.17.3 EVS Test and Maintenance discharged by the fuel handling area exhaust fans to the fuel handling area vent. The success criterion for the The surveillance requirements for the areas serviced by diesel generatcr rooms requires operation of the fan with the EVS are determined at least once every twelve hours. the damper opened. NUREG/CR4143 8-58 Vol. 2, Part 1 i

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Systems Analysis 8.17.4 EVS Technical Specifications 8.18 Instrument Air System (IAS) The temperature in each room seniced by the EVS must IAS Desen. t.p ion 8.18.1 be maintained at designated limits. If the temperature in any of these areas exceeds the limit for more than eight The IAS provides a pneumatic supply to support hours, a report must be submitted to the Nuclear j peration of safety related equipment. Regulatory Commission providing a record of the ' amount, the cumulative time the temperature exceeded its ne Instrument Air System for each unit consists of one ; limit, and an analysis to demonstrate the continued full-capacity, multistage, packaged centrifugal operability of the effected equipment. If the temperature c mpress r, e mplete with inlet filter, inlet air in an area exceeds its limit by more than 30*F in e er. An

er- e mmPreswh a l addition to filing a report, the temperature must be either . ,

receiver and a regenerative (heatless) desiccant air dryer. restored to within its limit in four hours or the equipment The Unit 2 IAS mmpressor, ru:civer, and dryer are in the area declared inoperable. present and operational. l Instmment air is distributed to the plant after drying to a 8.17.5 EVS Logic Models dew point of -40*F and filtration to remove particles 0.9 mier ns and larger. In addition, each instrument or he individual room cooling systems were modeled using stmments has a pressure regulating valve with gmup fault trees. The major active components were modeled. "" ""###"' Nlter 1 ated m. its mstrument air supply. The The fault tree models representing the ventilation systems l n s 1 and 2 can k manecW ns mme t air systems 4 cre presented in Appendix 1. by opening two air-operated valves from the control m m. One instmment an empressor can supply all 1 The potential for fire events to fail EVS components are , instrument air demands with the other mmpressor as a explicitly modeled in the fault trees. backup. The air-operated inter-tie valves fail open upon I ss fa to thek operators,6ereh asmring instmment Duct ruptures were considered to be negligible compared a f SUPP l y to Unit I from either instrument air system. to other system failures. No human errors were incorporated into the EVS fault tree models. 3 ,; g3 g g automatic backup supply to the instrument air system through a control valve that opens upon reduced line 8.17.6 EVS Assumpt. ions pressure in the instmment air system. ne backup connection is upstream of the instrument air dryers. (1) ne standby senice water pump room cooling Credit for the SAS is taken in this study and included systems were assumed not to be required since under the IAS discussion. the pumps operate with cold water and the room dampers are normally open. Natural air The SAS consists of two full-capacity, multistage, circulation was assumed sufficient for cooling. packaged centrifugal compressors, each complete with inlet filter, inlet air flow controller, aftercooler, and (2) Standby Service Water dependencies for the receiver. A simplified schematic of the IAS and SAS is LPCS and RilR pump room ventilation systems provided in Figure 8.18.1. are included in the LPCS and RHR fault trees. The SSW dependencies for the HPCS pump The IAS supplies clean, dry, oil-free air to EVS air i room are included in its respective ventilation valves, the CRD control system, condensate system l I system fault tree. valves, containment venting air valves, for the main steam isolation valves, RWCU AOVs, FW AOVs, PSW ; AOVs, and the SRV valves (a nitrogen system backs up 8.17.7 EVS Operating Experience the IAS supply to these valves). Generic failure data were used to quantify the fault tree The success criterion for the IAS is that either of the IAS compressors or one of the SAS compressors must supply logic models. air to system pneumatic loads. 8-62 Vol. 2, Part 1 NUREG/CR-6143

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1 i Systems Analysis Any physical impact of accident conditions modeled in 8.18.6 IAS Assumptions this study on the ability of the IAS to perform its functions would be minirnal. Room cooling failure is (1) When offsite power is lost, switchover from the assumed not to fail the IAS and SAS compressors. TBCW to the SSW does not require air. Failure of the IAS does not directly fail any related safety (2) The IAS header isolates on a containment systems. isolation signal, a LOCA signal, a loss of Div 1/2 AC power, or a loss of Div 1/2 DC power. 8.18.2 IAS Interfaces and Dependencies (3) Failure of the TBCW system to provide cooling Cooling requirements of the IAS and SAS air is dominated by TECW system pump failures. compressors and aftercoolers are normally supplied by Thus, failure of the TBCW system is not the Turbine Building Cooling Water (TBCW) system. In developed. the event of offsite power failure, the SSW system cools the air compressors and aftercoolers. (4) The Unit 2 IAS compressor was assumed to be normally operating and supplying air to the Unit The Unit 1 IAS air compressor is powered from I loads through interfacing valve AV13. emergency AC Division 2. The Unit 2 IAS and the SAS cir compressors are powered from non-safety buses. (5) No operator actions are required to provide air Following a loss of offsite power, standby onsite power from the backup IAS compressor or the SAS is provided to the Unit 1 IAS air compressors to compressor to the IAS supply header. replenish compressed air storage as required. A simplified dependency diagram of the IAS and SAS is (6) less of offsite power fails the Unit 2 IAS provided by Figure 8.18.2. The major dependencies are compressor, the SAS compressors, and the indicated by the solid diamonds. TBCW system cooling of the Unit 1 IAS compressor. 8.18.3 IAS Test and Maintenance 8.18.7 IAS Operating Experience No IAS test and maintenance requirements are identified in the Grand Gulf technical specifications. Generic failure data were used to quantify the fault tree basic events. 8.18.4 IAS Technical Specifications 8.19 Standby gas Treatment (SGTS) No requirements in POS 5. System 8.18.5 1AS Logic Model 8.19.1 SGTS System Descript. ion The IAS was tnodeled using a simple fault tree. The The function of the SGTS system is to limit the major active system components were modeled. The environmental release of radioisotopes, which can leak fault tree model representing the IAS is presented in from either the containment or fuel handling area to the Appendix I. boundary area, during accident conditions. During normal plant operation, the SGTS system is not operated Piping ruptures were considered to be negligible except during surveillance testing. compared to other system failures. Only piping with a diameter of greater than or equal to one third of the main The SGTS system consists of two subsystems, each system piping was considered. containing a 100 percent capacity recirculation fan and a 190 percent capacity charcoal filter train. The charcoal One human error is incorporated into the IAS fault tree filter train consists of a demister, an electric heater, a model. This ermr is the operator's failing to restore the Prefilter, two high efficiency particulate air (IIEPA) system following a containment isolation signal or filters, a charcoal absorber, an exhaust fan, and a 100 generation of a LOCA signal, percent capacity set of ductwork, dampers and controls. NUREG/CR4143 844 Vol. 2, Part 1 {

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Systems Analysis A simplified schematic of the SGTS system is provided (4) High drywell pressure 1.23 psig. in Figure 8.19-1. (5) Manually initiated, using push button switches The SGTS system draws air from within the auxiliary IIS-M651A and C. building, mixes this air with air from the enclosure building, and returns the mixed air to the upper enclosure (6) Containment /drywell Division I manual push building. A portion of this mixed air (4,000 scfm) is button. then exhausted to the atmosphere thmugh the charcoal filter trains to maintain the SGTS boundary at -0.25 Similar initiation logic for SGTS train B. inches we. 8.19.2 SGTS System Interfaces and The SGTS system enclosure building recirculation fans Dependencies are 100 percent capacity,17,000 scfm, vane-axial fans. Each fan is driven by a 75 hp motor. Each fan, starts The SGTS system major dependencies are AC power for tutomatically on an initiation logic if in automatic mode. operating fans and dampers, and DBC power for the The charcoal filter train exhaust fans are centrifugal 4300 SGTS system initiation logic. See Figure 8.19.2 for a scfm fans. Each fan is driven by a 20 hp motor. The simplified dependency diagram. The train A Enclosure fans automatically start on the initiation of the SGTS Building Recirculation Fan and train A charcoal filter system, or can be manually started. The automatic train exhaust fan are powered by Division I 480 V Ac initiation signals are the same as those for the LCC 15BA3 and MCC 15B11, respectively. Train A recirculation fan. charcoal filter train inlet and outlet (FO23 and FO25, respectively) dampers are also powered from MCC Upon receipt of an initiation signal to the train A SGTS 15B11. Similarly, the train B Enclosure Building subsystem, the following events occur: Recirculation Fan is powered from LCC 16BB3, and the train B charcoal filter train exhaust fan, and inlet and (1) Enclosure Building recirculation fan A starts. outlet damper are powered by MCC 16Bil. (2) Charcoal filter train A inlet and outlet dampers Division I 120 V AC supplies power to SGTS train A open (FO23 A and FO25A). damper control circuits, and Division I 125V DC supplies power to SBGT train A initiation circuit. (3) Charcoal filter train A exhaust fan starts. Similarly, Division II 120 V A C and 125 V D C supply power to SGTS train B damper control circuits and (4) Inboard dampers isolate in the fuel handling initiation logic. area, auxiliary building, and containment ventilation systems. The enclosure building recirculation fans automatically trip when: (5) Sends full open signals to SGTS A flow control dampers. (1) Motor protection device is activated. - A SGTS train A initiation signal is generated when any (2) Imss of bus voltage or LOCA (on a load shed, of the following occur: signal, the recirculation fan receives a start signal after its bus is re-energized after loss of Fuel handling area ventilation exhaust channels power, and five seconds after bus re-(1) A and D inoperable or high radiation great r energization on a LOCA). than 3.6 mrem 1/hr.

                                                                   "Ihe charcoal filter train exhaust fans trip on:

(2) Fuel handling area pool sweep exhaust. Clumnels A and D inoperable or high radiation (1) Fire detection signal. greater than 30 mrem /hr. (2) Motor protection device is activated. (3) Low-low reactor water level less than -41.6 (3) Loss of ESF voltage (fan does not receive a inches. shedding signal). l I NUREG/CR4143 8-66 Vol. 2, Part 1 w----- _ _ _ _ . - -

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Systems Analysis STANDBY GAS TREATMENT SYSTEM A I I TRAIN A TRAIN B O O em , A w AC I ' r POWER , I a t

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A w 1 ' r DC POWER ' 2 ,' r 3 DEPENDENCY DIAGRAM SHOWN USING FAILURE LOGIC Figure 8.19-2 SGTS Dependency Diagram NUREGICR-6143 8-68 Vol. 2, Part 1

i Systems Analysis 8.19.3 SGTS System Test and Maintenance 8.20.2 CI System Interfaces and Dependencies A SBGT System operability test is conducted monthly, during which time each SBGT train is run for a minimum All valves that are part of the CI system depend on either of ten hours. The charcoal filter efficiency is tested AC or DC power to change positions; all air valves fail during outages in the safe position on a loss of air. Electrical redundancy is provided in each isolation valve anangement. This redundancy elimmates dependency on 8.19.4 SGTS System Technical any one power source to attain isolation. Specifications In POS 5, two independent SBGT subsystems must be 8.20.3 CI System Logic Model operable when handling irradiated fuel in the primary or secondary containment. Two independent SBGT A fault tree logic model was not developed for the CI subsystems must be operable as well as during Core system since it is not an event tree system. Evaluation of Alterations and operations with the potential for draining CI was only required in the plant damage state definition. the reactor vessel. Therefore, only the CI system dependencies were l ' considered. As stated in the previous section, the only With one or both SBGT subsystems inoperable when major dependency identified was AC power. handling irradiated fuel in the primary or secondary containment (and during Core Alterations and operations with the potential for draining the reactor vessel) suspend 8.21 Hydrogen (H2) Ignitor System l the handling of all irradiated fuel in the primary or ; I secondary contamment, and all Core Alterations and operations with the potential for draining the reactor 8.21.1 H2 Ignitor System Description vessel. The function of the H2 Ignitor system is to prevent the 8.19.5 SGTS Syrtem Log.ic Model buildup of large quantities of hydrogen inside the : I containment during accident conditions. This is i An SGTS logic model is not needed for the analysis of l ! core damage. It will be developed for the analysis of accomplished by igniting, via a glow plug, small amounts ) of hydrogen before it has had a chance to accumulate. 1 plant damage states. l 8.19.6 SGTS System Assumptions 8.21.2 H2 Ignitor System Interfaces and Since the model for SGTS has not yet been created, no assumptions have yet been made. The H2 Ignitors have no major interfaces or dependencies except for AC power (MCCs 15B31 and l 16B31). Redundancy in the system is provided so that ! 8.20 Containment Isciation (CI) failure of any one division of AC will not fail the system. l System 8.20.1 CI System Description 8.21.3 H2 Ignitor System Logic Model The function of the CI system is to provide the necessary ne H2 initiator system was modeled using a simple fault isolation of the containment in the event of accidents or tree. The fault tree modeled the common mode failure other conditions when the unfiltered release of of the ignitors themselves as well as the common mode containment contents cannot be permitted. His is failure of AC power. The fault tree model representing accomplished by complete isolation of system lines the H2 ignitor system is presented in Appendix I. penetrating the containment. Redundant valves are providad an all lines. Vol. 2, Part 1 8-69 NUREG/CR-6143 i l l

1 l l Systems Analysis 8.22 Alternate Decay Heat Removal pumps and motoi spei.ted valve F424. Plant Service ! Water (PSW) cools the heat exchangers. Major (ADHR) System dependencies are mdicated by solid diamonds in Figure 8.22.2. , j 8.22.1 ADIIR System Description I 8.22.3 ADHR Test and Maintenance I Re function of the ADHR system is to provide an citernate snethod of decay heat removal during cold The ADHR surveillance requirements are as follows: shutdown and refueling when maintenance is being perfonned on the RHR shutdown cooling loops or (a) pump operability once a month; essociated support systems. The functional purpose of the ADHR system is important to safety, but is not safety (b) MOV operability once a month; related since the ADHR does not automatically mitigate the consequences resulting from accidents. (c) pump capacity test once every three months; and The ADHR system consists of components common to the RHR system including the RHR common suction line, (d) system functional test including simulated fuel pool cooling and cleanup piping, and the RHR Train automatic actuation once every operating C LPCI injection header. Components exclusive to eyege, ADHR include 2 ADHR pumps,2 heat exchangers, associated piping, valves, instrumentation and controls. 8.22.4 ADHR Technical Specifications The ADHR can operate in four main modes one of which No requirement in POS 5. is modeled for POS 5. In POS 5. ADHR is used in the reactor vessel cooling mode via RER A or B. During 8.22.5 ADHR Logic Model the reactor vessel cooling mode, ADHR draws water from the existing RHR common suction line. The The ADHR system was modeled using fault trees for the tractor coolant is then pumped from the reactor rem val f decay heat from the reactor vessel. Two fault recirculation loop through valves FO66A and FOO6A or trees were developed: One for two pump operation, and velves F066 and F006B to the ADHR pumps, then to the ne f r ne Pump operation. The major active system heat exchangers and back to the reactor vessel via RHR c mp nents were modeled. He fault tree is presented in C LPCI injection line. A schematic of the ADHR system is shown in Figure 8.22.1. A PPen di1 I-Piping ruptures were considered to be negligible Major system components are shown with valves in their compared to other system faults. Piping with a diameter normal standby positions. Most of the ADHR system is of greater than or equal to one third of the main system located in the auxiliary building. piping were considered as potential diversion paths. Control for the ADHR system is remote manual from the The potential for fire events to fail ADHR are explicitly control room. Flow and temperature indications are modeled iri the fault trees. provided in the control room for ADHR beat exchangers while individual manual control of pump operation with One human error was incorporated in the fault trees. pump running status lights is provided. This is failure to properly align and initiate ADHR. The success criterion for the ADHR system is to provide cooling to the reactor vessci at rated flow. For further 8.22.6 ADHR Assumptions information, refer to success criteria discussions in (1) It was necessary to model those components Section 5. assumed to be taken out for maintenance. Here, it was assumed that the components were completely 8.22.2 ADIIR Interfaces and Dependencies removed from the system. The ADHR major dependencies are AC Division 1 and 2 (2) Piping with a diameter of greater than or equal to power for motor operated valves F066A and F066B one third of the main system piping were respectively, and BOP AC bus 14HE for the ADHR 8-70 Vol. 2, Part 1 NUREG/CR-6143

Systems Analysis 6l E R

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Systems Analysis considered as potential diversion paths. the reactor vessel, aad (2) to remove decay heat from the vessel during hydro testing. For further information, (3) Pump isolation because of spurious signals is refer to success criteria discussions in Section 5. assumed to be negligible compared to other systems faults. 8.23.2 RWCU Interfaces and Dependencies (4) Failure of pump room cooling was modeled as The RWCU system's major dependencies are AC failure of the ADHR pump room air conditioning Division 1 and 2 power for the RWCU pump suction, fan. and containment isolation and MOVs. BOP AC power is supplied to the RWCU pumps, heat exchanger and filter 8.22.7 ADIIR Operating Experience demin:ralizers bypass valves, instrument air for the system's blowdown valves to the main condenser and Generic data was used to quantify the fault tree logic radwaste, and CCW for cooling the non-regenerative heat model, exchangers and pumps. Major dependencies are indicated by solid diamonds in Figure 8.23.2. 8.23 Reactor Water Cleanup (RWCU) System 8.23.3 RWCU Technical Specifications 8.23.1 RWCU Systetn Description No applicable technical specifications on RWCU operation were identified. The function of the RWCU system is to provide continuous purification of reactor water to reduce the 8.23.4 RWCU Logic Model fouling of heat transfer surfaces, minimize secondary sources of radiation, and maintain water clarity during The RWCU system was modeled using four fault trees refueling. The system also acts as a decay heat removal for its decay heat removal function and for its reactor system and reduces stratification in the reactor vessel by vessel letdown function. The major active system providing a discharge path for excess water to either the components were modeled. The fault trees are presented condenser hotwell or to the radwaste system. in Appendix I. Water is drawn into the RWCU system from both The potential for fire events to fail RWCU are explicitly recirculation lines and combined with water from the modeled in the fault trees. vessel drain. The flow is then pumped to a series of three regenerative heat exchangers. From the Piping ruptures were considered negligible compared to regenerative heat exchangers, the water is routed to the other system faults and therefore are not modeled in the non-regenerative heat exchangers and the filter fault trees. Piping with a diameter of greater than or demineralizers then to the reject lines to either the equal to one third of the main system piping were radwaste or the main condenser. See Figure S.23.1 for considered as potential diversion paths. flow description. 8.23.5 RWCU Assurnptions Major system components are shown in their standby configurations. The major equipment of the RWCU (1) It was necessary to model those components system is located in the containment. assumed to be taken out for maintenance. Here, it was assumed that the components were completely Operation of the RWCU system is controlled from the removed from the system. main control room. The outboard isolation valve will close automatically to prevent damage to the filter (2) Piping with a diameter of greater than or equal to demineralizers resins when the outlet temperature of the one third of the main system piping were noa-regenerative heat exchangers is too high. considered as potential diversion paths. The success criterion for the RWCU in POS 5 is (1) the (3) Pump isolation because of spurious signals is discharge of reactor water to either the main condenser assumed to be negligible compared to other system or radwaste system in order to maintain proper level in faults. Vol. 2, Part 1 8-73 NUREG/CR-6143

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Systems Analysis (4) The fault tree models for RWCU in letdown diagram of the RRS is provided by Figure 8.24.2. mode assume RWCU is letting down to Shown are the major support needs for the RRS as radwaste, not condenser. indicated by the solid diamonds at the appropriate places in the diagram. 8.23.6 RWCU Operating Experience The CCW system provides cooling for the upper and loer recirculation pump motors, pump motor upper and lower beanngs, and the pump seals. I.oss of seal coolmg Generic data was used to quantify the RWCU logic could result in a seal LOCA. His LOCA would be i minimal since the RRS pumps have a throttle bushing to model. limit flow in the event of a complete seal failure, l ne recirculation Pumps are driven by squirrel case 8.24 Reactor Recirculation System mduction motors. At full speed the pumps are powered

                    )                                           from 4160V AC BOP buses 11HD for loop A and 12HE for loop B. At 25 % rated speed the pumps are powered from separate 15Hz motor-generator sets. ne motor-8.24.1 RRS System Description                                   generator sets are in turn powered from 4160V AC BOP buses 13AD for loop A and 14AE for loop B.

He function of the Reactor Recirculation System (RRS) is to provide mixing of water in the downcomer region The motor-operated valves in the RRS are powered from and forced circulation through the reactor core. The 480V AC BOP MCC 11B51. The flow control valves RRS prevents stagnation and stratification of the core are hydraulic-operated valves and are mechanically region causing possible transition boiling or film boiling limited from going more than 25 % closed. The and high temperatures for the cladding of the fuel rods. hydraulic units for these valves are powered from 480V ne RRS provides nucleate boiling for optimum heat AC BOP MCC 11B51. The flow control valves fail as is transfer, improved efficiency, and lowering of fuel rod on loss of power to the hydraulic power units. cladding temperatures. In the event of a RRS failure, the Therefore, loss of pcwer at BOP MCC 11B51 would not reactor water level can be raised to provide natural necessarily fail the RRS if the system is already operating circulation through the core region. and properly aligned. The RRS consists of two loops external to the reactor The RRS pumps power supply trips upon a low reactor vessel. Each loop contains an electric motor driven water level signal (12 vel 3) when operating at 100 % centrifugal pump, two electric motor driven gate valves speed. The pumps power supply will also trip upon (for isolating the pump), and a hydraulic flow control receipt of a vessel low-low level (Ievel 2) signal when valve. A simplified schematic of the RRS system is operating at 25 % rated speed. shown in Figure 8.24.1. Major system components are shown in their normal operating position for a two loop 8.24.3 RRS Test and Maintenance operation. Since the Reactor Recirculation system is normally The Flow Control Valves (FCV). one in each loop, are operating during plant operational states 1 through 5, test hydraulically operated and are located immediately after and maintenance normally occurs during refueling the discharge of the pump and before the discharge gate outages except in cases of equipment failures or valve. De flow control valve has a range of operation impending failures. It should be noted that the pump from 25 % to full flow. These limits are mechanically seals are of a cartridge design and can be replaced restrained to prevent operation beyond these limits. without dismantling the pump. 8.24.2 RRS Interfaces sad Dependencies 8.24.4 RRS Technical Specifications The Reactor Recirculation System (RRS) major Since the Reactor Recirculation system is not a safety dependencies are the Component Cooling Water (CCW) system, there are no requirements for reactor shutdown system for pump cooling and AC power for operating the from loss of system function. recirculation pumps and valves. A simplified dependency NUREGICR-6143 8-76 Vol. 2, Part 1

Systems Analysis 1 I i l k HV60A N MV67A kMV67B k HV60B MV23A MV23B MDPIA MDPIB r RPV Figure 8.24.1 RRS System Diagram Vol. 2, Part 1 8-77 NUREG/CR-6143

Systems Analysis REACTOR RECIRCULATION SYSTEM f 'N l l REACTOR RECIRCU.ATION REACTOR RECIRCULATION LOOP A (NON-OPERATING) LOOP B (OPERATING)

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Systems Analysis 8.24.5 RRS Logic Model 8.25 Component Cooling Water The RRS was modeled using a fault tree for failure to provide forced recirculation with 1 of 2 pumps following transients in plant op: rational state 5 (POS 5). He 8.25.1 CCW System Description major active components and most passive components were modeled. The fault tree model representing the ne function of the CCW system is to provide a closed recirculation system can be found in Appendix 1. cooling loop between certain plant auxiliary components and the Plant Service Water (PSW) system or the The potential for fire events to fail the recirculation Standby Service Water (SSW) system. He Component system are explicitly modeled in the fault tree. Cooling Water (CCW) system consists of: a) nree pumps each with a 50 % capacity; b) Three heat There were no human errors modeled in the fault tree, exchangers each with a 50% capacity; c) A 550 gal. All human errors related to the operating of the RRS are capacity sage tank; and d) A 50 gal capacity chemical considered in the accident sequence event trees. addition tank. Each pump is of a single stage, horizontal, centrifugal, double suction design powered by 8.24.6 RRS Assumptions a 480V AC,100 hp electric motor. Each pump has a 1987 gpm flow rate. Each heat exchanger is cooled by (1) The system is assumed to be operating with one the plant service water system and is of a straight tube, pump (loop B) operating at 25 % capacity, and with single pass, counterflow design with a 1987 gpm the other loop either in standby or maintenance. capacity. The surge tank is located at 208'10*,well above the rest of the system, and is fed by the (2) Loop A is offline with gate valves closed and the demineralized water header. He surge tank is self-flow control valve minimum (25 % flow) position, maintaining with alarms in the event of a component ne pump is not operating. failure causing low water level, etc. The chemical ! addition tank is used to adjust chemistry of the CCW (3) The flow control valves remain in as-is position system water by manually adding or flushing chemicals, upon loss of power. Even in the minimum position it is located at 119' in area 9 of the auxiliary building. Figure 8.25.1 shows the CCW system diagram. (25 % of full flow) this is not considered a failure since adequate mixing in the core will take place. During normal operation, two of the three pumps are (4) The Component Cooling Water (CCW) system is perating with the third in standby, with both its isolation assumed to be sufficient to cool the pump and its valves open (the check valve prevents backflow). The motor (i.e., bearings, seals, windings, and standby pump auto starts on a low pressure signal of 100 lubricant) with no other cooling system being psig. Two of the three heat exchangers are operating necessary for operation. Alternatively, loss of the with the third isolated by two manual valves from the CCW system is also deemed sufficient to fail rest of the system. The surge tank is connected to the recirculation pumps. system, but the chemical addition tank is generally not connected until needed for addition of chemicals. (5) Pipe segments less than one-third of the main system pipe diameter are not considered to be The Component Cooling Water (CCW) system supplies diversion paths. cooling to the following loads: (6) Pump isolation because of spurious signals is

Recirculation pump seals and motor bearmgs, assumed to be negligible compared to other system faults.
RWCU pumps and non-regenerative heat exchangers, 8.24.7 RRS Operating Experience
CRD pump coolers, Generic data was used to quantify the fault tree logic models.
Fuel pool heat exchangers, Vol. 2. Part ! 8-79 NUREG/CR-6143 l

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Systems Analysis

Post accident sample cooler, and 8.25.3 CCW Test and Maintenance
Drywell equipment drain sump cooler. Since the Component Cooling Water (CCW) system is usually operating whenever the Recirc system, CRD Ancillary to the CCW system's main purpose of system, RWCU system, or FPCCU system is operating, supplying cooling to these loads, it also acts as an test and maintenance is usually performed during additional barrier between these potential sources of refueling outages. However, test and maintenance can be radioactive contamination and cooling water being Perfornal on purnps or heat exchangers during normal discharged into the environment. CCW pump B is operation since only two pumps (or heat exchangers) of powered by emergency AC power. Given a loss of the three are need to handle the cooling loads.

offsite power, the CCW system sheds unnecessary loads so that the single emergency AC powered train can cool 8.25.4 CCW Technical Specifications essential loads. Since the CCW system is not a safety system, there are The CCW success criteria required that two of the three no technical specification requirements. However, loss CCW umpsJ and two of the three CCW beat exchangers of CCW would prevent use of either Recire pump, CRD be in operation. Duritg LOSP, one pump operation is pumps, or RWCU. successful iLt &.hn; essential loads if the non-essential loads (fuel pool heat exchargers and Reactor Water 8.25.5 CCW Logic Model Clean Up non-regenerative heat exchangers) properly isolate. The CCW system was modeled using a fault tree model. The major active camponents were modeled. The fault 8.25.2 CCW Interfaces and Dependencies tree model representing the CCW system is present in Appendix 1. The CCW system's major dependencies are: a) The Plant Service Water (PSW) system; b) The Standby One human error was incorporated into the CCW fault Service Water (SSW) system; e) 480V AC power; d) tree model. This human error is failure of the operator 120V AC power; e) 125V DC power; and f) Instrument to start CCW pump B following LOSP. air. The three heat exchangers all use PSW system water for cooling, but the SSW system is a backup source of 8.25.6 CCW Assumptions cooling water in the event of LOSP or loss of PSW. The SSW system is also a backup cooling water source for (1) CCW pumps A and C, and CCW heat exchangers the Fuel Pool Heat exchangers during a LOSP when the A and C are assumed to be initially operating. Fuel Pool Heat Exchangers are isolated from the CCW system. Cooling from both the PSW and SSW systems is (2) Pipe ruptures were considered to be negligible inhibited if a 1.oss Of Coolant Accident (LOCA) signal is compared to other system failures. present. A LOCA signal can consist of either a high drywell pressure or a low reactor vessel level signal. 8.25.7 CCW Operation Experience CCW pumps A, B, and C are powered from buses 1IBDS,16BB3, and 12BE2 respectively. The 120V AC Generic data was used to quantify the fault tree logic power is used to control the surge tank level, RWCU model, isoittion valve control, all alarms, test circuits, and motor-operated valve heaters. The 125V DC power is used as control power for the CCW pumps, the power to 8.26 Plant Service Water (PSW) auxiliary relays for alarms, and the fuel pool heat System exchanger A valves. The instrument air operates the air operated valves in the system. 8.26J PSW Systern Description A simplified dcpendency diagram of the CCW system is The function of the Plant Service Water (PSW) System is provided in Figure 8.25.2. The major dependencies are indicated by the solid diamonds, to provide cooling to various plant heat exchangers including the Component Cooling Water (CCW) heat exchangers. Vol. 2, Part 1 8-81 NUREG/CR-6143

I Systems Analysis Y H.AT E HA A I HANG g HCAT E HANC C 5 O C] C] C] ; l 4 d> 45W AC POWER 2 h (PUuPS OrtY) 3 - h A y 12W AC POWER A l 125V DC POWER JL JL (PUuPS OttY) l i PLAPF SERVICE d> d> ik ) gyjEXCmNCERS ET 5" . . F 2< ! gTExCmNGERS

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If 6 mr I I l DEPENDENCY DIAGRAL SHOWN USING FAILURE LOGIC I i Figure 8.25.2 CCW Dependency Diagram NUREGICR-6143 8-82 Vol. 2. Part 1

l i Systems Analysis The PSW system is an open-loop system which uses the The pumps have no dependency on cooling and Mississippi river bank radial wells as its source and the ventilation systems, since they are located outside the discharge basin and circulating water pit as its two sinks. plant proper (away from other heat sources) in weather See Figure 8.26.1 (2 of 2) for the PSW diagram. The proof pumphouses and are pumping water at or below PSW system draws water from four radial wells on the ambient temperature. These radial well pumps are bank of the Mississippi river. Each well provides water lubricated by the water flowing through them, and to the suction of two pumps in parallel. The pumps are 4 provisions for lubrication on start up are provided by a stage,5000 gpm centrifugal driven by a 500 hp motor. 50 gal. bearing prelube tank, one for each two (2) These eight pumps all feed the common PSW header to pumps. The pumps are prevented from starting without supply the loads. adequate bearing prelube water. With the plant at full power, the PSW system normally requires approximately 23,000 gpm from the radial well In the event of a loss-of-offsite power, the PSW pumps pumps. Since each pump can deliver approximately 5000 would be unavailable. Non-essential PSW loads gpm, five pumps must be in service. As the plant load automatically isolate and the Standby Service Water varies, PSW pumps can be started and stopped from the System automatically aligns to provide cooling to , control room to meet PSW demand. important PSW loads. He PSW system uses this untreated water to cool The PSW system automatically isolates penetrations various heat loads and provide makeup to various treated through the Auxiliary Building Containment and Drywell water systems. He PSW supplies cooling water to the when a LOCA is sensed ( + 2 psig Drywell pressure or - Component Cooling Water (CCW) beat exchangers, the 42 inches). These isolations can be re-opened by manual Steam Jet Air Ejection (SJAE) intercondensers, the override if necessary. ADHR heat exchangers and A/C, and the Turbine Building Cooling Water (TBCW) beat exchangers. The In addition, some of the PSW components that switch to PSW provides makeup for the following treated water Standby Service Water (SSW) during a loss-of-offsite systems: a) The circulating water system; b) ne power are isolated from SSW if the loss-of-offsite power Standby Service Water (SSW) system; and c) The is followed by a LOCA. The effected components are: firewater system and the Makeup Water system. Service and Instrument Air compressors, Component Cooling Water heat exchangers, IC Steam Tunnel During a LOSP or LOCA, the Standby Service Water is coolers, and the Drywell coolers. used to supply the CCW heat exchangers, the IC Steam Tunnel Coolers, and the Drywell Coolers with cooling water. 8.26.3 PSW Test and Maintenance Since the PSW system is operating continuously to supply 8.26.2 PSW Interfaces and Dependencies cooling water to plant cooling loads, test and maintenance is performed to insure system integrity. To perform he PSW system's major dependencies are 4160 V,480 maintenance, it is assumed that all active components V, and 120 V AC power and the Instrument Air System must be effectively removed from the system. (IAS), as shown in Figure 8.26-2. Power for the PSW pumps I A, IB,1C, and ID is 8.26.4 Technical Specifications provided from 4160 V AC bus 18AG, and power for PSW pumps IE, IF,1G, and 1H is provided from 4160 Since the PSW system is not a safety system, there are V AC bus 26AG. Solenoids for air operated valves are no technical specification requirements. However, loss powered from 120V AC. Valves F121 and F117 receive of PSW would prevent use of the Component Cooling solenoid power from 16B31, and valve Fil receives Water (CCW) system, the Circulating Water system, the solenoid power from 14B11. All these valves depend ,f Turbine Building Cooling Water (TBCW) system, and instrument air to provide the motive force. The various the Alternate Decay Heat Removal System (ADMR). motor operated valves in the system require 480 V AC power. Vol. 2, Part 1 8-83 NUREG/CR-6143

Systems Analysis N h I-NIA N008A F109A F110A C001A-N Y IN

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F012 F004 - 12 1 r 120 i To TBCW Heat Exchanger Figure 8.26.1. PSW System Sclumnatic (page 1 of 2) NUREG/CR-6143 g.g4 Vol. 2, Part 1 l

7 Systems Analysis To Cire water System b SJAE Inter-Condensers F040 b E rm From P'

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Q rie l O['" Dischorge Bosin Figure 8.26.1 PSW System Schematic (page 2 of 2) Vol. 2, Part 1 8-85 NUREG/CR-6143 I

Systems Analysis Loss of PSW I I I vown V8k's VWves Ppps pgg y g2 g.N y gg y4 r121 FC27A-N FC27A N DC Pow Ac power AC Power [ 4 MV Switchger 1BAC y 416tv Switchger 28AG 480v WCC CB12 IF 480v hCC 0C21 k 483V hCC 15031 h DC Power CSV Pret 1A8 v CSV Pened 2AB 4 estnarwrit As g DEPENDENCY DIAGRAM SHOWN USING FAILURE L;CIC l I Figure 8.26.2. PSW Dependency Diagram 8 86 Vol. 2, Part 1 NUREG/CR-6143

l l 1 i Systems Analysis I l 8.26.5 PSW Logic Model ne logic model for the PSW system permits success of Common cause failures are not considered for the PSW system across system boundaries. There are no basic events that are in common with other systems. pumps, and necessary piping, valves, and 8.26.6 PSW Assumptions are outlined below. the CRWST is provided by Figure 8.27.1. Major (1) Pump isolation because of spurious signals is faults. Either storage tank can be used to fill the suppression (3) Common cause failures are assumed to occur within (4) To fail PSW, eight of eight pump lines must fail. pump line was assumed to be negligible and was not (S) Failure of the discharge path to the Circulating Water Pit is assumed to fail the PSW system. (6) Since the PSW path is normally to the Circulatint Water Pits, and only to the Discharge Basin when 8.26.7 PSW Operating Experience Generic data was used to quantify the fault tree logic model. The CRWST system major dependencies are AC 8.27 Condensate and RefuelinE i b Vol. 2, Part 1 8.27.1 CRWST System Description ] The function of the CRWST system in this analysis is to system if only one (1) of the eight (8) pumps are provide makeup to the suppression pool and/or the upper operational. His is adequate for meeting the cooling containment pool for those transients (e.g., LOCA requirements of the PSW pri. nary loads. Complete loss outside containment)in which the capacity of the SPMU of the PSW system is classified as a Special Initiator, system is inadequate to mitigate the accident. The condensate storage and transfer. subsystem (CSTS) , consists of a stainless steel storage tank (CST) with a : capacity of 300,000 gallons, two condensate transfer ; instmmentation. The refueling water storage and transfer (RWST) subsystem consists of a stainless steel storage i A number of assumptions were made during the tank (RWT) with a capacity of 350,000 gallons, two l construction of the PSW fault tree. These assumptions refueling water transfer pumps, and necessary piping, . valves, and instrumentation. A simplified schematic of l ; components are shown with valves shown in their normal assumed to be negligible compared to other system standby position. i (2) It is assumed that no tests are performed on PSW Pool or the upper containment pool. Filling the i manual valves, suppression pool is done by gravity drain through normally open air-operated valves AV130 and AV131 ! from manual valve XV46 when the RWT is the source or i a system, but not across two or more systems. manual valve XV73 when the CST is the source. For filling the upper containment pool the RWST pumps Based on this criterion, any individual failure of a are used with suction taken from manual valve XV46 ! when the RWT is the source, or air-operated valve AV40 modeled, when the CST is the source. The success criteria for the CRWST system is injection : of flow to the suppression pool or the upper containment pool. For further information, refer to success criteria , discussions in Section 5. t the pits are full, it is assumed that the line to the Except for the CST and RWT, most of the CRWST is i discharge basin will be used only as a recovery path located in the auxiliary building. Because of the relative and is therefore not modeled. location of the system components, local access to the CRWST components would not be affected by either ! containment venting or containment failure. 8.27.2 CRWST Interfaces and Dependencies ! power and instrument air for operating air-operated valves. L " f *i'h*' di"I'i " fi ,1 f r n) r AC power wm i fail the CRWST system smce the instrument air would be Water Storage and Transfer lost to the auxiliary building and the system air-operated System (CRWST) valves all fait closed on loss of instrument air. A ; 8-87 NUREG/CR-6143 ,

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Systems Analysis NDENSA SYS M N-C< Cv25A XV24A N WDPLA - MisCELt.ANTOUS YY2D l DISTRIBUTION 27 XY263 - TO AND FROM 1 R BU ON CV2SB XV24B y 1

XV34 WDPIB N-Xna M nnR Crwr CY37A XV36A POOL 8A MDP2A swst _N %

AV61 M __.H AV47 XV39 I XV46 ,, C)<C CV37 B XV36B WDP2B XV42 X ; SUP R S!ON AY131 AY130 XV41 I I Figure 8.27.1 CRWST System Schematic NUREGICR-6143 8 88 Vol. 2. Part 1

Systems Analysis i simplified depe adency diagram of the CRWST is There are twenty SRVs (eight of these are also ADS provided in Figure 8.27.2. valves) that operate in a safety mode and a relief mode. , The safety mode (or spring actuated mode) of operation l The CRWST must be manually aligned and initiated for consists of direct action of the reactor vessel steam use. pressure against a spring loaded disk that will pop open when the valve inlet pressure force exceeds the spring 8.27.3 CRWST Logic Model force. The safety mode of operation is a backup to the i relief mode of operation. The CRWST was modeled using a simplified fault tree for the injection of water to either the suppression pool The relief mode (or power actuated mode) of operation ' or the upper containment pool. Only the common RWST consists of using a pneumatic piston / cylinder assembly , suction header and major dependencies were modeled. which opens the valve by overcoming the spring force, The fault tree representing the CRWST system is even with valve inlet pressure equal to zero psig. Each ' presented in Appendix I. valve has a pressure sensing device which operates at i designated set points. When the set pressure is reached, , There were two human errors incorporated into the the pressure sensing device operates a solenoid air valve - which in turn actuates the pneumatic piston / cylinder to

  . CRWST fault tree model. These human errors are: (a)

Failure of the operator to properly align for makeup to pen the valve. - the suppression pool ; and (b) Failure of the open. tor to properly align for makeup to the upper containment pool. Here are two of eese solenoids for each SRV, one is powered from DC Division I and the other is powered fmm DC Division II. Either solenoid can operate the air 8.27.4 CRWST Technical Specifications r valve. All twenty SRVs can be operated in the relief No requirements in POS 5. m de (p wey actuated mode) by remote-manual controIs , 1 from the mam control room. The pneumatic operator is i arranged so that if it malfunctions, it will not prevent the 8.27.5 CRW,ST Assumptions safety mode of operation. - (1) Failure of common valves AV47 or XV39 to open Relief valve capacity is approximately 900,000 lb/hr. on demand alone fail the CRWST. Therefore only Each SRV discharges steam from the main steam line ; the hardware failures of these two valves were through discharge piping to a point below the minimum modeled, i.e., the RWST pumps were not modeled suppression pool water level of 18' 41/12". A t"mplified . since the failure of these two pumps does not schematic of the SRVs including the ADS function is , completely prevent the CRWST from meeting its provided in Figure 8.28-1. success criteria. ( The SRVs are located inside the drywell. Containment ! (2) Piping ruptures were considered to be negligible pressures of ~ 100 psi will prevent the opening of the I compared to other system faults. SRVs. This scenario is not a consideration in the current - study because containment is assumed to have failed at i 60 psig. Therefore, it is assumed that containment 8.28 c 'ity Relief Valves conditions will not affect SRV performance. , 8.28.1 SRV Description 8.28.2 SRV Interfaces and Dependencies S The Safety Relief Valves (SRVs) are designed to prevent an tw s depend upon the Mmment Air System @ds reactor vessel overpressurization which could lead to the Pown sources One o[6e solenm , m each SRV that can actuate the air valve is powered by

 '._ lure f the reactor coolant pressure boundary. Also,
                                                 ,                  Division I 125 V DC bus 11DA, and the other is eight of the SRVs are used by the Autometic powered by Division 11125 V DC bus 11DB. The major Depressurization System (ADS) to depressurize the dependencies are indicated by the solid diamonds. The reactor vessel to a pressure at which the low pressure lAS supplies air pressure to open the SRVs.                           ,

injection systems can inject coolant to the reactor vessel. l Vol. 2. Part 1 8-89 NUREG/CR-610 i

Systems Analysis Condensate and Refueling W ater Storage and Tr ansf er Systern 4 O 1 em l i

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AC Power ^ i 2 3V 1 3 I l l l 1 4 I Instrument Air () Manual u Actuation v Dependency Diagram is Shown Using Fault Tree Logic f Figure S.27.2 CRWST Dependency Diagram i l NUREG/CR4143 8-90 Vol. 2, Part 1

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Systems Analysis Au:umulators for each SRV contain sufficient air for one Additionally, several systems not important to actuation if the IAS is unavailable; ADS accumulators the mitigation of core damage were evaluated. These contain sufficient air for two actuations. A simplified included those systems important to defining the plant dependency diagram of the SRVs including the ADS damage states - the SGTS and Ci systems. Only function is provided in Figure 8.28-2. dependencies were examined for these systems. The condensate and H2 ignition systems have a lot of 8.28.3 SRV Test and Maintenance redundancy. The CDS system requires the operator to manually align it for injection. %e failure of the Fifty percent of the installed SRVs are removed and their Perator to do this will be several orders of magnitude set point checked at every refueling outage. Each SRVs above the independent failures. Failures that were tail pipe pressure switch is demonstrated operable every common to the whole condensate system were modeled. 31 days. He ADS surveillance requirement is that a These are support failures such as actuation, instrument system functional test with simulated automatic actuation air, electric power, and common cause. be performed at least once every operating cycle. ne H2 ignition system is diverse and highly redundant. l 8.28.4 SRV Technical Specifications Only common mode failures of the igmters (90 total) and No requirements in POS 5. The SGTS, CI and H2 Ignition systems were not top 8.28.5 SRV Logic Model events on any event tree and therefore did not require a model. However, as a system in the plant damage state The use of SRVs was modeled using many different fault definition, identification of the dependencies and trees for the depressurization of the reactor either by interfaces was required. safety mode or relief mode (automatic and remote-manual). The fault tree models are presented in Appendix B. Piping ruptures were considered to be negligible compared to other failures. A common mode event across all the SRVs also was modeled in the tree. 8.28.6 SRV Assutnptions (1) Two SRVs are normally available during shutdown conditions. (2) All SRVs are available during Hydro testing. 8.29 Justification for Systems Not Modeled All systems (front-line and their supports) t 2at are important for providing the sai*y functims (e.g., core cooling, containment cooling) that prevent core damage were modeled. However, not every system examined in this study had a detailed fault tree model developed for it. Previously, Table 8.2-1 identified the level to which each system was modeled. Some of the systems did not have detailed system fault trees developed. Simplified fault trees were developed for both Condensate and H2 with only the dominant failures modeled. TBCW was modeled as a black box. NUREG/CR4143 8-92 Vol. 2, Part 1

                                                                                                              .1 Systems Analysis .

REACTOR DEPRESSURIZATON SYSTEM fh 1 l l ! AUTOMATIC MANUAL DEPRESSURl2ATON DEPRESSURIZATION SY STEM f_ 3 fh T I I ADS DC ACTUATON PCWER ( ) f3 O f1 ADS a MAPfjAL # 1 h h DC 2 A V A POWER V 3 DEPEPOENCY DlAGRAM 15 SHOWN USING f ALURE LOOtC. (1) SEE ACTUATON DAGRAM (MGURE B 3-3) Figure 8.28-2. ADS and SRV Dependency Diagram Vol. 2, Pan 8-93 NUREG/CR-6143 T'

Systems Analysis References for Section 8 United States Nuclear Regulatory Commission, Analysis Entergy Operations, Inc., Grand Gulf Nuclear Station, of Core Damage Frequency: Grand Gulf, Unit 1 Internal Suppression Pool Makeup (SPMU) System, System Evaits, NUREG/CR-4550, SAND 86-2084, Vol. 6, Rev. Description E30, SD E30, Rev. 2. 1, Part 1, September 1989. System Energy Resources, Inc., Grand Gulf Nuclear System Energy Resources, Inc., Grand Gulf Updated Station, Residual Heat Removal System, System Final Safety Analysis Report,1992. Description, SD-E12, Rev. 3. Grand Gulf Plant Operations Manual, System Operating System Energy Resources, Inc., Grand Gulf Nuclear Instruction High Pressure Core Spray System Safety Station, Fire Protection System, System Description, SD Related, Procedure No. 04 1-01-E22-1, Revision 30, P64, Rev. 2. 8/05/91. System Energy Resources, Inc., Grand Gulf Nuclear Grand Gulf Plant Operations Manual, System Operating Station, Standby Service Water System, System Instruction Residual Heat Removal System Safety Description, SD P41, Rev. 3. Related, Procedure No. N-1-01-E12-1, Revision 44, 8/23/90. System Energy Resources, Inc., Grand Gulf Nuclear Station, Reactor Water Cleanup system, System Grand Gulf Plant Operations Manual, System Operating Description, SD G33, Rev. 3. Instruction Refueling Water Storage and Transfer System Non-Safety Related, Procedure No. M-1-01-P112, System Energy Resources, Inc., Grand Gulf Nuclear Revision 31,04/29/91. Station, Component Cooling Water System, System Description, SD-P42, Rev. 2. Grand Gulf Plant Operations Manual, System Operating Instmetion ESF Bus 15AA Safety Related, Procedure Plant Service Water / Radial Well -P44/P47 System No. 04-1 Ol-R21 15, Revision 1,11/09/90. Description, Rev.1. Grand Gulf Plant Operations Manual, System Operating System Energy Resources, Inc., Grand Gulf Nuclear Instruction ESF Bus 16AB Safety Related, Procedure No. Station, Turbine Building Cooling Water System 04-1-01-R21-16, Revision 1, 11/02/90. Description, SD-P43, Rev. 2. Grand Gulf Plant Operations Manual, System Operating K. D. Russel, et al., " Integrated Reliability and Risk Instruction BOP Bus 12HE Safety Related, Procedure Analysis System (IRRAS) Version 4.0," NUREG/CR-No. 04-1-01-R21 12, Revision 1, 01/18/90. 5813, EGG-2664, January 1992. Grand Gulf Plant Operations Manual, System Operating United States Nuclear Regulatory Commission, Analysis Instmetion BOP Bus 13AD Safety Related, Procedure of Core Damage Frequency: Grand Gulf, Unit 1 Intunal No. 04-1-01-R21 13, Revision 0, 03/15/89. Events, NUREG/CR-4550, SAND 86-2084, Vol. 6. Rev. 1, Part 2, September 1989. Grand Gulf Plant Operations Manual, System Operating Instruction BOP Bus 18AG/28AG Safety Related, Procedure No. 04-1-01-R21-18, Revision 1, 04/10/90. Entergy Operations, Inc., Grand Gulf Nuclear Station, High Pressure Core Spray (HPCS) System, System Description, SD E22, Rev. 4. Entergy Operations, Inc., Grand Gulf Nuclear Station, Control Rod Drive Hydraulic System, System Description Cll-1 A, SD C11-1 A, Rev. 4. 8-94 Vol. 2, Part 1 NUREG/CR-6143

                    --                                         -                       -                          _                  _____ M

I 9 Dependent Failure Analysis Dependent failures are those failures that defeat the differences between components at different plants. Data redundancy or diversity that is employed to improve the collection is further complicated by the fact that the availability of some plant function such as coolant descriptions of events in a given data base are often injection. inadequate for proper classification into independent or common cause categories. Therefore, the uncertainty Dependent failures involve two types of relationships incorporated into the parameter estimation for common between components - explicit dependencies between cause models must account for the potential components, and failure mechanisms which affect more misclassification of data. than one component but which are not explicitly identified in the systems analysis. The explicit Common cause failures across system boundaries were dependencies are included in the logic models of the not modeled. The detection and prevention of failure systems as individual basic events. For example, mechanisms which can lead to common cause failures are functional dependencies between front line systems and strongly influenced by maintenance practices. Because support systems, such as power and cooling, are included maintenance and testing of different systems are done in the system fault trees. Cascading or propagating separately for each system, and because there are no failures are also modeled explicitly in the fault trees. An procedures requiring actions between systems that would example of such an event is failure of a pump to start lead to common cause failures, common cause failures j due to the malfunction of a circuit breaker in the pump between systems were not modeled. control circuit. In most cases the NUREG 4550 common cause analysis The dependencies among components which are not was limited to those failures which defeat the complete explicitly identified in the systems analysis are accounted redundancy or diversity of a system design. Partial for by introducing the concept of common cause failures. common cause failures were not modeled for most These are modeled by common cause basic events systems. In cases where failure combinations are applied to the fault trees. A common cause event is probabilistically significant, they were included in the defined as the failure or unavailability of more than one common cause model. component due to some shared cause which occurs in a short period of time. The methodology for comma 9.2 Dependent Failure Development cause failue analysis for this study, as described below, evolved from insights from past PRA studies, operating experience, and from efforts within the nsk assessment 9.2.1 Review of Existing Dependent Failure community to model common cause failures. Analysis Specifically, two reports were used as the primary sources [Drouin, et al.,1989] [Ericson, et al.,1990], As noted above, the NUREG 4550 reports formed the since they contain the methods and data used in the full basis of the dependent failure analysis for the shutdown 4 power PRA analysis of the Grand Gulf plant. For those study. These documents were reviewed to determine if events which required additional data, other documents they provided a sound starting point for the analysis. As a result of the review, it was concluded that the

were used to obtain appropriate data, for example

[ Fleming, et al.,1985]. In general, the methods used methodology [Ericson, et al 1990] and its application to are simple compared to those presented in a more recent Grand Gulf [Drouin, et al.,1989] were generally report [Mosleh, et al.,1988]. However, these methods adequate and consistent. However, some inconsistencies are felt to be adequate to meet the objectives of the and errors were found. As anticipated, it was found that shutdown study. the data and events provided in the two references would need to be supplemented or modified because of the 9.1 diff*'*"' P"ating c=ditions and plant c=ngurations Dependent Failure Anal)' sis associated with shutdown. Assumptions and Limitations 9.2.2 Common Cause Failure Analysis Plant specific data on multiple failures are rare, so data collection and analysis for common cause analysis must The fat.lt tree for cach system contains, where be done on an industry basis. However, data from other appropriate, common cause failure events. Such events plants must be screened for applicability to a particular were modeled using the single event name in the fault analysis due to design, operational, and manufacturing tree, but broken out into an independent failure term and Vol. 2, Part 1 91 NUREG/CR-6143

Dependent Failure a corresponding common cause beta factor for the study were failures in the plant service water (PSW) and dominant sequence cut sets. This was done so that the two component cooling water (CCW) systems. For the common cause factor uncertainty and importance PSW system the event modeled was the failure of all measures could be calculated and examined separately. eight pumps in the system. The beta factor for this event As noted previously, the estimates for the beta factors was conservatively estimated to be the same as the factor used were obtained prirnarily from NUREG 4550. He for the common cause failure of three pumps from EPRI report was used as necessary to supplement the NUREG 4550. For the CCW system the failure of two primary sources [ Fleming, et al.,1985]. pumps was modeled using the beta factor for the failure of two SSW pumps from NUREG 4550 since they are The specific common cause events included in the system similar. fault trees are listed in Table 9.2-1. He events considered in the original Grand Gulf PRA are noted. A problem involving the treatment of safety relief valves The remainder were those considered necessary to (SRVs) was found in NUREG 4550 [Drouin, et al., adequately analyze the plant under shutdown conditions. 1989). NUREG 4550 discusses LOCAs at Grand Gulf The beta factors used for the events are shown, by due to failure of SRVs. However, sequences including system acronym, in Table 9.2. the failure of any three or more SRVs are not included. Based on the probability of this event, it cannot be As described in NUREG 4550, beta factors were used to ignored. Therefore, frequencies for failure of three or calculate the frequency of common cause failures. Since more SRVs to close after opening were estimated and the some of the events in the shutdown study are identical to event BETA-20SRVS (see Table 9.2-1), with a those in the Grand Gulf PRA, the same beta factors were conservative beta factor of 0.1 (Table 9.2-2), was added used. His was the case for failures involving the diesel to the Grand Gulf event trees so the associated sequences generator system (DGS), diesel driven pumps (DDP), could be evaluated as part of the shutdown study. For motor operated valves (MOVs) in the contamment spray the common cause failure of two SRVs the beta factor system (CSS), motor driven pumps (MDPs) in the, given in NUREG 4550 was used. residual heat removal (RHR) and standby service water (SSW) systems, and motor operated valves (MOVs) in ne event BETA-3 BAT *DCP-BAT-LP-CM was included the suppression pool cooling (SPC) and suppression pool in this study as well as the Grand Gulf PRA. NUREG makeup (SPM) systems. The same common mode 4550 gives a value of 4.0E-3 as the beta factor for the failure of three batteries. It was calculated using the data failures of three MOVs (BETA-3MOV) in the low pressure coolant injection (LPCI or LCI) system were in [Baranowski, et al.,1981], but apparently incorrectly. modeled in the Grand Gulf PRA and this study. Using the correct beta factor defmition, the beta factor Therefore, the sune beta factors were also used for these was determined to be 3.0E-3 as shown in Table 9.21. events. Common cause failure of air operated valves (AOVs) to I Additional events involving two MOVs (BETA-2MOV) open is an event which is considered in the shutdown m the LCl, SSW, reactor recirculation system (RRS) and study, but does not appear in NUREG 4550. AOV shutdown cooling (SDC) systems were modeled for the failures in the firewater (FW) and nuclear boiler systems shutdown study (see Table 9.1). For these events the (NBS) were included in the shutdown study. For both of beta factor for failure of two MOVs from NUREG 4550 these systems a beta factor of 0.1 was used per the data was used. provided in NUREG 4550. Fo. 4.e shutdown study, a number of failures oflow The other common mode failures included in the pressure MDPs were considered as shown in Table 9.1- shutdown study were the failures of motor driven

1. Common cause failures of two pumps in the alternate compressors (MDCs) in the instrument air system (IAS) decay heat removal system (ADHRS or ADR), reactor and service air system (SAS), and failure of all of water cleanup (RWCU or RWC), and RRS systems were hydrogen ignitors (H2). Based on the analysis of the modeled. For the RHR and condensate (CDS) systems, failure data presented [ Fleming, et al.,1985], the generic the failure of three MDPs were included. The beta beta factor 0.1 was used for these events.

factors used for these events were taken from NUREG 4550. The possibility of common cause failures of check valves during shutdown was considered. A briefliterature he other two MDP events included in the shutdown search and discussions with knowledgeable PRA analysts NUREG/CR-6143 9-2 Vol. 2, Part 1

                                                                                                                                       ~,
                                                                                                                                        ~

Dependent Failure ' led to the conclusion that it was not necessary to consider such failures. The beta factors used in the shutdown study and other pertinent data are summarized in Table 9.2-1. Vol. 2, Part 1 9-3 NUREG/CR4143

Dependent Failure Table 9.2-1 Shutdown Study Common Cause Events Common Cause Event Description Basic Event BETA-2DG*ACP-DGS-FS-CM' DGS fail to start due to common mode failure Common mode failure of ADHRS pumps to stan BETA 2MDPL*ADR-MDP-CM-C005 ADHRS motor-driven pumps common mode failure to nm BETA-2MDP*ADh-MDP-FR-CCF BETA-20SRVS*SRV-CCF-CC-SRVS Common cause failure of all SRVs Common cause failure of normally operating CCW pumps IA & IC BETA-2CCW*CCW-MDP-CM-1 A/C Common mode failure of the condensate pumps to stad BETA-3MDPL*CDS-MDP-CM<DMDP Common mode failure of CSS injection valves MV28 to open BETA-2MOV* CSS MOV-CM-MV28' BETA-3B AT*DCP-BAT-LP-CM' Failure of a battery to provide power due to CCF BETA-90lGNITORS*E61-H2-FO-lGNITE Comuon mode failure of hydrogen ignitors to operate BETA-AOV*FW-AOV-CM-V282/3 Common mode failure of the FW distribution header AOVs (CC) Common mode failure of diesel driven pumps to start BETA-2DDP*FWS-DDP-FS-CM' Common mode failure of the IA compressors to nm BETA-2MDC*IAS-MDC-CM-IAC Common mode failure of LPCI MOV 3A/B to operate on demand BETA-2MOV*LCI-MOV-CM-MV3 Common mode failure of MOV 4A/B/C to operate on demand BETA-3MOV*LCI-MOV-CM MV4' Common mode failure of MOV 42A/B/C to operate on demand l BETA-3MOV*LCI-MOV-CM-MV42' ' Common mode failure of LPCI MOV 48A/B to operate on demand BETA-2MOV*LCI MOV-CM-MV48 Common mode failure of SDC injection valves MV53B BETA-2MOV*LCI-MOV-CM-MV53 Common mode failure of MOV 6A/B to operate on demand l BETA 2MOV*LCI-MOV-CM-MV6 Common mode failure of MOV 64A/B/C to operate on demand BETA-3MOV*LCI MOV-CM-MV64' Common mode Eilure of MOV 66A/B to operate on demand BETA 2MOV*LCI-MOV-CM-MV66 Common mode failure of MOV 8 and 9 to operat: on demand BETA-2MOV*LCI-MOV-CM-MV8-9 Common mode failure of inboard MSIVs to operate on demand BETA AOV*NBS-AOV-CM-AV22 Common mode failure of outboard MSIVr to operate on demand BETA-AOV*NBS-AOV-CM-AV28 Common mode failure of P W 8 PSW pumps to run BETA-8PSW*PSW-MDP-CM MDPS BETA-3RHR*RHR-MDP-FS-CM' Failure of a RHR system M1./P due to CCF BETA-2MDP*RRS-MDP-CM-FR Common mode failure of recirculation pumps to run BETA-2MOV*RRS-MOV-CM-MV23 Common mode failure of RRS MOVs MV23 A/B BETA-2MOV*RRS-MOV-CM-MV67 Common mode failure of PRS LOVs MV67 A/B BETA-2MDP*RWC-MDP-CM-MDPFR RWCU motor-driven pumps common mode failure to run Common mode failure of RWCU motor driven pumps C001 A/B BETA-2MDP*RWC-MDP-FS-CCF BETA-2MDC*SAS-MDC-CM-SAC Common mode failure of the service air compressors to run Common mode failure of SDC MOV 53A/B to operate on demand BETA-2MOV*SDC-MOV-CM-MV53 BETA-2MOV*SPC-MOV-CM-MV24 Common mode failure of SPC injection valves BETA-2MOV*SPM-MOV-CC-CM Common cause failure of suppression pool makeup valve to open BETA-SRV*SRV-CCF-CC-SRVS Common cause failure of two SRVs to open BETA-2SSW*SSW-MDP-FS-CM' Failure of SSW system MDP due to CCF Common mode failure of SSW MOV 1 A/B to operate on demand BETA-2MOV*SSW-MOV-CM MV1 Common mode failure of SSW MOV 14A/B to operate on demand BETA-2MOV*SSW-MOV-CM-MV14 Common mode failure of SSW MOV 18A/B to operate on demand BETA-2MOV*SSW-MOV-CM-MV18 Common mode failure of SSW MOV 5A/B to operate on demand BETA-2MOV*SSW-MOV-CM-MVS Common mode failure of SSW MOV 68A/B to operate on demand BETA-2MOV*SSW-MOV-CM-MV68 Event included in Grand Gulf PRA (Ref 2) 9-4 Vol. 2, Part I NUREG/CR4143

Dependent Failure Table 9.2 2 Dependent Failure F=ent Beta Factors and Probabilities Component Type Systan(s) Condition No. of Comp. Beta Factor Probability MOV CSS Fail to Open 2 8.8E-2 3.0E-3 LPCI Fail to Operate 2 8.8E-2 3.0E-3 Fail to Operate 3 5.4E-2 3.0E-3 RRS Fail to Operate 2 8.8E-1 3.0E-3 SPM Fail to operate 2 8.8E-2 3.0E-3 SDC Fail to Operate 2 8.8E-2 3.0E-3 SPC Fail to Operate 2 8.8E-2 3.0E-3 SSW Fail to Operate 2 8.8E-2 3.0E-3 MDP ADHRS Fail to Start 2 1.5E-1 3.0E-3 (low pressure) Fail to Run 2 1.5E-1 7.2E-4 CDS Fail to Start 3 1.1E-1 3.0E 3 RHR Fail to Start 3 1.1E-1 3.0E-3 RRS Fail to Run 2 1.5E-1 7.2E-4 RWCU Fail to Run 2 1.5E-1 7.2E-4 Fail to Start 2 1.5E 1 3.0E-3 MDP PSW Fail to Run 8 1.4E-2 7.2E-4 SSW Fail to Start 2 2.6E-2 3.0E-3 CCW Pump Failure 2 2.6E-2 7.2E4 Diesel Driven FWS Fail to Stad 2 1.0E-1 3.0E-2 Pumps AOV FW Fail to Operate 2 1.0E-1 3.0E-3 NBS Fail to Operate 2 1.0E-1 2.0E-3 Batteries DCP Fail to 3 3.0E-3 2.4E-5 Provide Power Diesel Generators ACP Fail to Stat 2 3.8E-2 3.0E-2 SRV SRV Fail to Open 2 2.2E-1 - 3 or more 1.0E-1 - Hydrogen Ignitor H2 Fail to Operate 90 1.0E-1 2.4E-5 Motor-Driven IAS Fail to Run 2 1.0E-1 3.8E-3 Compressors SAS Fail to Run 2 1.0E-1 3.8E-3 (MDC) Vol. 2, Pad 1 9-5 NUREG/CR-6143

Dependent Failure References for Section 9 D. Ericson, et al., [Mosleh, et al.,1988] A. Mosleh, et al., [Ericson, et al.,1990]

                          " Analysis of Core Damage
                                                                                                             ' Procedures for Treating Frequency: Internal Events                                                         Common Cause Failures Methodology,"                                                                      in Safety and Reliability NUREG/CR-4550,                                                                     Studies, Procedural S AND86-2084, Vol.1,                                                               Framework and Rev.1, January 1990.                                                               Examples," NUREGICR-4780, EPRI NP-5613, M. T. Drouin, et al.,                                                              PLG-0547, Vol.1,

[Drouin, et al.,1989]

                          " Analysis of Core Damage                                                          January 1988.

Frequency: Grand Gulf, Unit 1 Intemal Events," [Baranowski, et al.,1981] P. W. Baranowsky, et al., NUREG/CR4550, "A Probabilistic Safety SAND 86-2084, Vol. 6, Analysis of DC Power Rev.1, Part 1, September Supply Requirements for Nuclear Power Plants," 1989. NUREG-0666, Ap.il 1981. [ Fleming, et al.,1985] K. N. Fleming, et al., l ' Classification and Analysis of Reactor i l Operating Experience involving Dependent Events," EPRI NP-3967, June 1985. 9-6 Vol. 2, Part 1 NUREG/CR-6143 r

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I i i u.s. NUCLEAR REGULATORY COMMISSION h egRgORu 23s Ng

NRCM 1102, Supp., Rev.. arid Addendum Num-320'.s2c2 BIBLIOGRAPHIC DATA SHEET I hbR$G[dR-6143 (see instructions on tne reversei SAND 93-2440 r UTLE AND SUBTITLE Vol. 2. Part 1 A Evaluation of Potential Severe Accidents During Low Power and a. oATE REPORT PUJLISMED Shutdown Operations at Grand Gulf, Unit 1.

MONTH YEAR Analysis of Core Damage Frequency from Internal Events for June 1994 Plant Operational State 5 Durmg a Refueling Outage ,,,,y og og,y7 ggggg, Main Report (Sections 1-9) L1923

6. AvlNvH(b) 6. TYPE OF REPORT i l

D. Whitehead, J. Darby', J. Yakle2, J. Forester 2, B. Staple, Technical S. Miller 2, S. Daniel, T. Brown, B. Walsh' , H. Kirk, 7. PERIOD COVERED (inclusive Cates) D. Mitchell, V. Dandini, G. Benavides 8 PLRFORMING ORGAN'ZATION - NAME AND ADDHESS Of NRC, provece Davision. Office of Region, U. S. Nuclear Regulatory Comm<ssion. and ma hng address; it contractor, provide name and maihng address.) Sandia National laboratories Science and Engineering Associates, Inc. 2 Science Applications International Corp. Albuquerque, NM 87185 6100 Uptown Blvd. NE 2109 Air Park Rd. SE Albuquerque, NM 87110 Albuquerque, NM 87106

9. SPONSORING ORGANIZATION *= NAME AND ADDRESS (if NRC. type "Same as above"; af Contractor. provice NRC Division. Office or Region.

U.S. Nuclear Regulatory Commission. and maahng address.) Division of Safety Issue Resolution Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission t Washington, DC 20S$5 n001

10. SUPPLEMENT ARY NOTES 6

11. ABSTRACT (200 words or less)

This document centains the accident sequence analysis of internally initiated events for Grand Gulf. Unit 1 as it op-erates in the Low Power and Shutdown Plant Operational State 5 during a refueling outage. The report documents the methodology used during the analysis, describes the results from the application of the methodology, and com-pares the results with the results from two full power analyses performed on Grand Gulf.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABluTY ST ATEMENT Unlimited

14. SECURITY CLASSIFICATIOt[

Probabilistic Risk Assessment, Low Power and Shutdown Operations, (3hi i.s:s> Boiling Water Reactor Unclassified (T hi. Report) Unclassified

16. NUMBER OF PAGES

16. PRICE NRe FORM 335 (2-49)

f 1 \ l I Printed on recycled paper Federal Recycling Program

UNITED STATES srtcut roumm ctAss natt POSTAGE AND FEES PAC NUCLEAR REGULATORY COMMISSION " "C WASHINGTON, D.C. 20555-0001 PERM 1T NO G 67 OFFICIAL BUSINESS PENALTY FOR PRtVATE USE, $300 i t i l t I l 1 i I i I

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