ML20141L662

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Amendment 30 to Updated Final Safety Analysis Report, Chapter 15, Accident Analysis, Volume 1
ML20141L662
Person / Time
Site: Saint Lucie NextEra Energy icon.png
Issue date: 05/04/2020
From:
Florida Power & Light Co
To:
Office of Nuclear Reactor Regulation
Shared Package
ML20141L672 List:
References
L-2020-043
Download: ML20141L662 (309)
v • d • e


Text

LIST OF EFFECTIVE PAGES CHAPTER 15 ACCIDENT ANALYSIS Page Amendment Page Amendment 15-1 30 15.1.5-1 30 15-2 30 15.1.5-2 26 15-3 30 15-4 30 15.1.6-1 30 15-5 30 15.1.6-2 26 15-6 30 15.1.6-3 26 15-7 30 15.1.6-4 30 15-i 26 15.1.6-4a 26 15-ii 26 15.1.6-4b 22 15-iii 26 15.1.6-5 26 15-iv 28 15.1.6-6 18 15-v 27 15.1.6-7 26 15-va 26 15.1.6-8 30 15-vi 30 15.1.6-9 26 15-vii 26 15.1.6-10 19 15-viia 28 15.1.6-11 19 15-viii 30 15.1.6-12 26 15-viiia 26 15.1.6-13 26 15-ix 30 15.1.6-13a 26 15-ixa 30 15-x 26 F15.1.6-1 26 15-xi 26 F15.1.6-2 10 15-xii 26 F15.1.6-3 3 15.xiia 26 F15.1.6-4 26 15-xiii 26 F15.1.6-5 10 15-xiiia 26 F15.1.6-6 26 15-xiv 27 F15.1.6-7 26 15-xv 27 F15.1.6-8 26 15-xva 27 F15.1.6-9 26 15-xvi 26 15-xvii 26 15.1.7-1 26 15-xviia 26 15.1.7-2 26 15.1.1-1 12 15.1.7-3 26 15.1.1-1a 26 15.1.1-2 26 15.1.8-1 26 15.1.1-3 26 15.1.8-2 21 15.1.1-4 28 15.1.1-5 0 15.2.1-1 26 15.1.1-6 0 15.2.1-2 26 15.1.1-7 26 15.2.1-3 30 15.1.1-8 26 15.2.1-4 26 15.1.1-9 26 15.2.1-4a 26 15.1.1-10 26 15.2.1-5 26 15.1.1-11 24 15.2.1-5a 26 15.2.1-6 26 15.2.1-7 26 15.1.2-1 15 15.1.2-2 11 F15.2.1-1 26 F15.2.1-2 26 15.1.3-1 16 F15.2.1-3 26 15.1.3-2 18 F15.2.1-4 26 15.1.3-3 18 F15.2.1-5 26 F15.2.1-6 26 15.1.4-1 30 F15.2.1-7 26 15.1.4-2 26 15.1.4-3 26 15.1.4-4 26 15.1.4-5 26 UNIT 1 15-1 Amendment No. 30 (05/20)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 15 ACCIDENT ANALYSIS Page Amendment Page Amendment F15.2.1-8 26 15.2.5-2 26 F15.2.1-9 26 15.2.5-3 26 F15.2.1-10 26 15.2.5-4 26 F15.2.1-11 26 F15.2.5-1 26 15.2.2-1 26 F15.2.5-2 26 15.2.2-2 26 F15.2.5-3 26 15.2.2-2a deleted 26 F15.2.5-4 26 15.2.2-3 26 F15.2.5-5 26 15.2.2-4 26 F15.2.5-6 26 F15.2.5-7 26 F15.2.2-1 26 F15.2.5-8 26 F15.2.2-2 26 F15.2.5-9 26 F15.2.2-3 26 F15.2.5-10 26 F15.2.2-4 26 F15.2.5-11 26 F15.2.2-5 26 F15.2.2-6 26 15.2.6-1 0 F15.2.2-7 26 F15.2.2-8 26 F15.2.2-9 26 15.2.7-1 30 F15.2.2-10 26 15.2.7-2 26 15.2.7-2a 26 15.2.3-1 30 15.2.7-2b 26 15.2.3-2 26 15.2.7-3 26 15.2.3-2a 26 15.2.7-3a 18 15.2.3-3 26 15.2.7-4 26 15.2.7-5 26 F15.2.3-1 26 15.2.7-5a 26 F15.2.3-2 26 F15.2.3-3 26 F15.2.7-1 26 F15.2.3-4 26 F15.2.7-2 26 F15.2.3-5 26 F15.2.7-3 26 F15.2.3-6 26 F15.2.7-4 26 F15.2.3-7 26 F15.2.7-6 26 F15.2.3-8 26 F15.2.7-7 26 F15.2.3-9 26 F15.2.7-8 26 F15.2.3-10 26 F15.2.7-9 26 F15.2.3-11 26 F15.2.7-10 26 F15.2.7-11 26 15.2.4-1 26 F15.2.7-12 26 15.2.4-2 26 F15.2.7-13 26 15.2.4-3 26 F15.2.7-14 26 15.2.4-4 26 F15.2.7-15 26 15.2.4-5 26 F15.2.7-16 26 15.2.4-6 26 F15.2.7-17 26 15.2.4-6a 26 F15.2.7-18 26 15.2.4-7 26 F15.2.7-19 26 15.2.4-8 26 F15.2.7-20 26 F15.2.7-21 26 15.2.5-1 18 F15.2.7-22 26 15.2.5-1a 26 F15.2.7-23 26 F15.2.7-24 26 F15.2.7-25 26 F15.2.7-26 26 UNIT 1 15-2 Amendment No. 30 (05/20)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 15 ACCIDENT ANALYSIS Page Amendment Page Amendment 15.2.8-1 26 F15.2.11-9 26 15.2.8-2 26 F15.2.11-10 26 15.2.8-2a 29 F15.2.11-11 26 15.2.8-3 27A F15.2.11-12 26 15.2.8-4 29 F15.2.11-13 26 F15.2.11-14 26 F15.2.8-1 29 F15.2.11-15 26 F15.2.11-16 26 15.2.9-1 26 F15.2.11-17 26 15.2.9-2 26 15.2.9-3 26 15.2.12-1 26 15.2.9-4 26 15.2.12-1a 26 15.2.9-5 26 15.2.12-2 26 15.2.9-5a 18 15.2.12-2a 26 15.2.9-6 26 15.2.12-2b 26 15.2.9-7 26 15.2.9-8 26 F15.2.12-1 26 15.2.9-9 26 F15.2.12-2 26 F15.2.12-3 26 F15.2.9-1 26 F15.2.12-4 26 F15.2.9-2 26 F15.2.12-5 26 F15.2.9-3 26 F15.2.12-6 26 F15.2.9-4 26 F15.2.12-7 26 F15.2.9-5 26 F15.2.12-8 26 F15.2.12-9 26 15.2.10-1 26 F15.2.12-10 26 15.2.10-2 26 F15.2.12-11 26 15.2.10-3 26 F15.2.12-12 26 F15.2.12-13 26 F15.2.12-14 26 15.2.11-1 26 F15.2.12-15 26 15.2.11-1a 28 F15.2.12-16 26 15.2.11-2 28 F15.2.12-17 26 15.2.11-2a 28 F15.2.12-18 26 15.2.11-2b 30 F15.2.12-19 26 15.2.11-2c 26 15.2.11-2d 26 15.2.13-1 26 15.2.11-2e 24 15.2.13-1a 27A 15.2.11-2ea 26 15.2.13-1b 26 15.2.11-2eb 26 15.2.13.2 26 15.2.11-2f 28 15.2.13-3 26 15.2.11-3 26 15.2.13-4 27A 15.2.11-3a 26 15.2.13-5 26 15.2.11-3b 26 15.2.13-6 28 15.2.11-4 26 15.2.13-7 29 15.2.11-5 26 15.2.13-8 29 15.2.11-6 26 15.2.13-9 26 F15.2.11-1 26 F15.2.13-1 29 F15.2.11-2 26 F15.2.13-2 29 F15.2.11-3 26 F15.2.13-3 29 F15.2.11-4 26 F15.2.13-4 29 F15.2.11-5 26 F15.2.13-5 29 F15.2.11-6 26 F15.2.13-6 29 F15.2.11-7 26 F15.2.13-7 29 F15.2.11-8 26 F15.2.13-8 29 UNIT 1 15-3 Amendment No. 30 (05/20)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 15 ACCIDENT ANALYSIS Page Amendment Page Amendment F15.2.13-9 29 15.3.4-2d 26 F15.2.13-10 29 15.3.4-2e 24 F15.2.13-11 29 15.3.4-3 18 15.3.4-4 18 15.2.14-1 26 15.3.4-5 26 15.2.14-2 26 15.3.4-6 26 15.2.14-3 30 15.3.4-7 26 15.2.14-4 30 15.3.4-8 26 15.2.14-5 30 15.3.4-9 30 15.3.4-10 26 F15.2.14-1 30 15.3.4-11 26 F15.2.14-2 30 F15.2.14-3 30 F15.3.4-1 26 F15.2.14-4 30 F15.3.4-2 26 F15.3.4-3 26 15.3.1-1 26 F15.3.4-4 26 15.3.1-2 30 F15.3.4-5 26 15.3.1-3 30 F15.3.4-6 26 15.3.1-3a 26 F15.3.4-7 26 15.3.1-3b 27 F15.3.4-8 26 15.3.1-3c 27 F15.3.4-9 26 F15.3.4-10 26 F15.3.1-1 27 F15.3.4-11 26 F15.3.1-2 27 F15.3.4-12 26 F15.3.1-3 27 F15.3.4-13 26 F15.3.1-4 27 F15.3.4-14 26 F15.3.1-5 27 F15.3.4-15 26 F15.3.1-6 27 F15.3.4-16 26 F15.3.1-7 27 F15.3.4-17 26 F15.3.1-8 27 F15.3.4-18 26 F15.3.1-9 27 F15.3.4-19 26 F15.3.1-10 27 F15.3.4-20 26 F15.3.1-11 27 F15.3.4-21 26 F15.3.1-12 27 F15.3.4-22 26 F15.3.1-13 27 F15.3.1-14 27 15.4.1-1 26 15.4.1-2 26 15.3.2-1 26 15.4.1-2a 30 15.4.1-2b 26 15.3.3-1 24 15.4.1-2c 30 15.3.3-2 25 15.3.3-3 26 15.4.1-3 30 15.4.1-3a 26 F15.3.3-1 0 F15.3.3-2 0 15.4.1-4 11 F15.3.3-3 0 15.4.1-4a 26 F15.3.3-4 0 15.4.1-5 26 15.4.1-6 26 15.3.4-1 26 15.4.1-7 24 15.3.4-1a 26 15.4.1-8 26 15.3.4-2 26 15.4.1-9 26 15.3.4-2a 30 15.4.1-10 26 15.3.4-2b 26 15.4.1-11 24 15.3.4-2c 26 15.4.1-12 24 15.4.1-13 24 UNIT 1 15-4 Amendment No. 30 (05/20)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 15 ACCIDENT ANALYSIS Page Amendment Page Amendment 15.4.1-14 26 F15.4.1-18 26 15.4.1-14a 30 F15.4.1-19 26 15.4.1-14b 26 F15.4.1-20 26 15.4.1-15 26 F15.4.1-21 26 15.4.1-16 27 F15.4.1-22 26 15.4.1-17 27 F15.4.1-23 26 15.4.1-18 26 F15.4.1-24 26 15.4.1-19 26 F15.4.1-25 26 15.4.1-19a 30 F15.4.1-26 26 15.4.1-20 26 F15.4.1-27 26 15.4.1-21 24 F15.4.1-28 11 15.4.1-22 24 15.4.1-23 24 15.4.2-1 26 15.4.1-24 26 15.4.2-2 26 15.4.1-25 26 15.4.2-2a 26 15.4.1-26 24 15.4.2-3 26 15.4.1-27 26 15.4.2-4 26 15.4.1-28 26 15.4.2-4a 26 15.4.1-28a 26 15.4.1-29 26 15.4.3-1 21 15.4.1-30 26 15.4.3-2 19 15.4.3-3 24 F15.4.1-1 27 F15.4.1-1a 27 F15.4.1-2 27 F15.4.1-3 27 F15.4.1-4 27 F15.4.1-5 27 F15.4.1-6 27 F15.4.1-7 27 F15.4.1-8 27 F15.4.1-9 27 F15.4.1-10 27 F15.4.1-11 27 F15.4.1-12 27 F15.4.1-13 27 F15.4.1-14 27 F15.4.1-15 27 F15.4.1-16 27 F15.4.1-17 27 UNIT 1 15-5 Amendment No. 30 (05/20)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 15 ACCIDENT ANALYSIS Page Amendment Page Amendment 15.4.3-4 26 15.4.5-5 26 15.4.3-5 24 15.4.5-6 26 15.4.3-6 18 15.4.5-7 26 15.4.3-7 23 15.4.5-8 26 15.4.3-8 26 15.4.5-9 26 15.4.3-9 26 15.4.3-10 26 F15.4.5-1 26 F15.4.5-2 26 15.4.4-1 27 F15.4.5-3 26 15.4.4-2 26 F15.4.5-4 26 15.4.4-2a 26 F15.4.5-5 26 15.4.4-2b 29 F15.4.5-6 26 15.4.4-3 26 F15.4.5-7 26 15.4.4-4 26 15.4.4-4a 27 15.4.6-1 26 15.4.4-4b 24 15.4.6-2 30 15.4.4-4c 27 15.4.6-2a 26 15.4.4-4d 26 15.4.6-2b 26 15.4.4-4e 26 15.4.6-3 30 15.4.4-5 26 15.4.6-3a 26 15.4.4-6 29 15.4.6-3b 26 15.4.4-6a 29 15.4.6-3c 25 15.4.4-7 26 15.4.6-3d 26 15.4.4-8 26 15.4.6-4 30 15.4.4-9 26 15.4.6-5 26 15.4.4-10 29 15.4.6-5a 26 15.4.6-6 26 F15.4.4-1 26 15.4.6-7 26 F15.4.4-2 26 15.4.6-8 26 F15.4.4-3 26 15.4.6-8a 26 F15.4.4-4 26 15.4.6-8b 30 F15.4.4-5 26 15.4.6-9 26 F15.4.4-6 26 15.4.6-10 26 F15.4.4-7 26 15.4.6-11 26 F15.4.4-8 26 15.4.6-12 26 F15.4.4-9 26 F15.4.4-10 26 F15.4.6-1 26 F15.4.4-11 26 F15.4.6-2 26 F15.4.4-12 29 F15.4.6-3 26 F15.4.6-4 26 15.4.5-1 26 F15.4.6-5 26 15.4.5-1a 26 F15.4.6-6 26 15.4.5-1b 26 F15.4.6-7 26 15.4.5-2 30 F15.4.6-8 26 15.4.5-2a 26 F15.4.6-9 26 15.4.5-2b 26 F15.4.6-10 26 15.4.5-2c 25 F15.4.6-11 26 15.4.5-2d 26 F15.4.6-12 26 15.4.5-2e 26 F15.4.6-13 26 15.4.5-3 26 F15.4.6-14 26 15.4.5-4 30 F15.4.6-15 26 15.4.5-4a 26 F15.4.6-16 26 15.4.5-4b 30 F15.4.6-17 26 UNIT 1 15-6 Amendment No. 30 (05/20)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 15 ACCIDENT ANALYSIS Page Amendment F15.4.6-18 26 F15.4.6-19 26 F15.4.6-20 26 F15.4.6-21 26 F15.4.6-22 26 F15.4.6-23 26 F15.4.6-24 26 F15.4.6-25 26 F15.4.6-26 26 F15.4.6-27 26 F15.4.6-28 26 F15.4.6-29 26 F15.4.6-30 26 15.5-1 26 15.5-2 26 15.5-3 26 15.5-4 26 15.5-5 30 15.5-6 30 15.5-7 26 15.5-7a 28 15.6-1 26 15.6-2 26 15.6-3 26 15.6-4 26 15.6-5 26 15.6-5a 26 15.6-6 26 15.6-7 26 15.6-8 26 15.6-9 26 15.6-10 26 15.6-10a 26 15.6-10b 26 F15.6-1 21 F15.6-2 7 F15.6-3 7 F15.6-4 21 F15.6-5 21 F15.6-6 21 F15.6-7 26 F15.6-8 26 UNIT 1 15-7 Amendment No. 30 (05/20)

ACCIDENT ANALYSIS CHAPTER 15 TABLE OF CONTENTS Section Title Page 15.1 GENERAL 15.1.1-1 15.1.1 CLASSIFICATION OF ACCIDENTS 15.1.1-1a 15.1.1.1 Section 15.1 References 15.1.1-1a 15.1.2 ACCIDENT PARAMETERS 15.1.2-1 15.1.3 TRIP SETTINGS 15.1.3-1 15.1.4 COMPUTER PROGRAMS 15.1.4-1 15.1.4.1 Deleted 15.1.4-1 15.1.4.2 Deleted 15.1.4-2 15.1.4.3 Deleted 15.1.4-2 15.1.4.4 Deleted 15.1.4-2 15.1.4.5 Deleted 15.1.4-4 15.1.4.6 Deleted 15.1.4-4 15.1.4.7 Deleted 15.1.4-4 15.1.4.8 Deleted 15.1.4-5 15.1.4.9 Deleted 15.1.4-5 15.1.5 METHODOLOGY 15.1.5-1 15.1.5.1 Deleted 15.1.5-1 15.1.5.2 Deleted 15.1.5-1 15.1.5.3 Deleted 15.1.5-1 15.1.5.4 Deleted 15.1.5-2 15.1.6 SAFETY ANALYSIS EVALUATION FOR THE FOR THE ST. LUCIE 1 CORE 15.1.6-1 15.1.6.1 Introduction and Summary 15.1.6-1 15.1.6.2 Calculational Methods and Input Parameters Code Description 15.1.6-1 15.1.6.3 Modeling Uncertainties 15.1.6-3 15.1.6.4 Design Parameters 15.1.6-4 15.1.6.5 Deleted 15.1.6-4 15.1.6.6 Deleted 15.1.6-4a 15.1.6.7 Deleted 15.1.6-4a 15.1.6.8 Reload Safety Analysis 15.1.6-4a 15.1.6.8.1 Event Review and Analysis for the Current Cycle 15.1.6-4a 15.1.6.8.2 Summary of Results 15.1.6-4b 15.1.7 INSTALLATION OF REPLACEMENT STEAM GENERATORS 15.1.7-1 15.1.8 INSTALLATION OF REPLACEMENT PRESSURIZER 15.1.8-1 UNIT 1 15-i Amendment No. 27 (04/15)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.2 ANTICIPATED OPERATIONAL OCCURRENCES (CLASS 1 ACCIDENTS) 15.2.1-1 15.2.1 UNCONTROLLED CEA WITHDRAWAL 15.2.1-2 15.2.1.1 Identification of Causes 15.2.1-2 15.2.1.2 Analysis of Effects and Consequences 15.2.1-4 15.2.1.2.1 Uncontrolled CEA W ithdrawal from a Subcritical or Low 15.2.1-4 Power Startup Condition 15.2.1.2.2 Uncontrolled CEA W ithdrawal at Power 15.2.1-5 15.2.1.3 Deleted 15.2.1-5 15.2.1.4 Deleted 15.2.1-5a 15.2.2 TRANSIENTS RESULTING FROM THE MALFUNCTION OF ONE STEAM GENERATOR 15.2.2-1 15.2.2.1 Identification of Causes 15.2.2-1 15.2.2.2 Analysis of Effects and Consequences 15.2.2-1 15.2.2.3 Deleted 15.2.2-2 15.2.2.4 Deleted 15.2.2-2 15.2.2.5 Deleted 15.2.2-2 15.2.2.5.1 Deleted 15.2.2-2 15.2.2.5.2 Deleted 15.2.2-2 15.2.2.5.3 Deleted 15.2.2-2 15.2.2.5.4 Deleted 15.2.2-2a 15.2.2.5.5 Deleted 15.2.2-2a 15.2.3 CEA DROP ACCIDENT 15.2.3-1 15.2.3.1 Identification of Causes 15.2.3-1 15.2.3.2 Analysis of Effects and Consequences 15.2.3-2 15.2.3.3 Deleted 15.2.3-2a 15.2.3.3.1 Deleted 15.2.3-2a 15.2.3.4 Deleted 15.2.3-2a 15.2.4 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION -

BORON DILUTION EVENT 15.2.4-1 15.2.4.1 Identification of Causes 15.2.4-1 15.2.4.2 Analysis of Effects and Consequences 15.2.4-2 15.2.4.3 Conclusions 15.2.4-3 15.2.4.4 Deleted 15.2.4-3 15.2.4.5 Deleted 15.2.4-6a 15-ii Amendment No. 26 (11/13)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.2.5 LOSS OF COOLANT FLOW ACCIDENT 15.2.5-1 15.2.5.1 Identification of Causes 15.2.5-1 15.2.5.2 Analysis of Effects and Consequences 15.2.5-1a 15.2.5.3 Deleted 15.2.5-2 15.2.6 STARTUP OF AN INACTIVE REACTOR COOLANT PUMP EVENT 15.2.6-1 15.2.7 LOSS OF EXTERNAL ELECTRICAL LOAD AND/OR TURBINE STOP VALVE CLOSURE 15.2.7-1 15.2.7.1 Overview 15.2.7-1 15.2.7.2 Safety Analysis 15.2.7-2 15.2.7.3 Effect of Replacement Steam Generators 15.2.7-3 15.2.8 LOSS OF NORMAL FEEDWATER FLOW 15.2.8-1 15.2.8.1 Identification of Causes 15.2.8-1 15.2.8.1.1 Loss of Normal Feedwater 15.2.8-1 15.2.8.1.2 Feedwater System Pipe Breaks 15.2.8-1 15.2.8.2 Analysis of Effects and Consequences 15.2.8-1 15.2.8.2.1 Maximum Primary System Pressure 15.2.8-2 15.2.8.2.2 Minimum Departure from Nucleate Boiling Ratio (MDNBR) 15.2.8-2 15.2.8.2.3 Long Term Cooling 15.2.8-2 15.2.8.3 Reload Safety Analysis 15.2.8-2a 15.2.8.3.1 Loss of Normal Feedwater 15.2.8-2a 15.2.9 LOSS OF OFFSITE POWER TO THE STATION AUXILIARIES 15.2.9-1 15.2.9.1 Identification of Causes 15.2.9-1 15.2.9.2 Analysis of Effects and Consequences 15.2.9-2 15.2.9.3 Results 15.2.9-4 15.2.9.4 Conclusion 15.2.9-5 15.2.9.5 Reload Safety Analysis 15.2.9-5 15.2.10 EXCESS HEAT REMOVAL DUE TO FEEDWATER SYSTEM MALFUNCTIONS 15.2.10-1 15-iii Amendment No. 26 (11/13)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.2.10.1 Identification of Causes 15.2.10-1 15.2.10.2 Analysis of Effects and Consequences 15.2.10-1 15.2.10.3 Deleted 15.2.10-2 15.2.10.4 Deleted 15.2.10-3 15.2.10.5 Deleted 15.2.10-3 15.2.11 EXCESS LOAD 15.2.11-1 15.2.11.1 Identification of Causes 15.2.11-1 15.2.11.2 Analysis of Effects and Consequences 15.2.11-1a 15.2.11.3 Deleted 15.2.11-2d 15.2.12 DEPRESSURIZATION OF THE REACTOR COOLANT SYSTEM 15.2.12-1 15.2.12.1 Identification of Causes 15.2.12-1 15.2.12.1.1 Analysis of Effects and Consequences 15.2.12-1 15.2.12.2 Results for MDNBR 15.2.12-1a 15.2.12.3 Deleted 15.2.12-1a 15.2.12.4 Deleted 15.2.12-1a 15.2.13 STATION BLACKOUT ANALYSIS 15.2.13-1 15.2.13.1 Identification of Causes 15.2.13-1 15.2.13.2 Analysis of Effects and Consequences 15.2.13-1 15.2.13.3 Results 15.2.13-4 15.2.14 INCREASE IN REACTOR COOLANT INVENTORY 15.2.14-1 15.3 POSTULATED ACCIDENTS (CLASS 2 ACCIDENTS) 15.3.1-1 15.3.1 LOSS OF REACTOR COOLANT FROM SMALL RUPTURED PIPES OR FROM CRACKS IN LARGE PIPES WHICH ACTUATES EMERGENCY CORE COOLING SYSTEM 15.3.1-1 15.3.1.1 Identification of Causes 15.3.1-1 15.3.1.2 Analysis of Effects and Consequences for Small Break LOCA 15.3.1-2 15.3.1.3 SBLOCA Results 15.3.1-3 15.3.1.4 Deleted 15.3.1-3a 15.3.1.5 Deleted 15.3.1-3a 15.3.2 MINOR SECONDARY SYSTEM PIPE BREAKS 15.3.2-1 15.3.2.1 Identification of Causes 15.3.2-1 15.3.2.2 Analysis of Effects and Consequences 15.3.2-1 15.3.3 INADVERTENT LOADING OF A FUEL ASSEMBLY INTO THE IMPROPER POSITION 15.3.3-1 15.3.3.1 Identification of Causes 15.3.3-1 15.3.3.2 Analysis of Effects and Consequences 15.3.3-2 15.3.3.3 Extended Power Uprate Evaluation 15.3.3-3 15.3.3.4 Deleted 15.3.3-3 15.3.4 SEIZED ROTOR EVENT 15.3.4-1 15.3.4.1 Identification of Causes 15.3.4-1 15.3.4.2 Analysis of Effects and Consequences 15.3.4-1 15.3.4.3 Results 15.3.4-2a UNIT 1 15-iv Amendment No. 28 (05/17)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.4 POSTULATED ACCIDENTS (CLASS 3 ACCIDENTS) 15.4.1-1 15.4.1 MAJOR REACTOR COOLANT SYSTEM PIPE BREAK (LOCA) 15.4.1-1 15.4.1.1 Identification of Causes 15.4.1-1 15.4.1.2 Reload Safety Analysis 15.4.1-2 15.4.1.3 Deleted 15.4.1-4 15.4.1.4 Deleted 15.4.1-4 15.4.1.5 Radiological Consequences 15.4.1-5 15.4.1.6 Hydrogen Accumulation in Containment 15.4.1-12 15.4.1.7 Effect of Replacement Steam Generators 15.4.1-13 15.4.2 WASTE GAS DECAY TANK LEAKAGE OR RUPTURE 15.4.2-1 15.4.2.1 Identification of Causes 15.4.2-1 15.4.2.2 Radiological Analysis 15.4.2-1 15.4.2.3 Deleted 15.4.2-2 15.4.3 FUEL HANDLING ACCIDENT 15.4.3-1 15.4.3.1 Identification of Causes 15.4.3-1 15.4.3.2 Radiological Analysis 15.4.3-3 15.4.3.3 Effect of Replacement Steam Generators 15.4.3-7 15.4.4 STEAM GENERATOR TUBE FAILURE 15.4.4-1 15.4.4.1 Identification of Causes 15.4.4-1 15.4.4.2 Analysis of Effects and Consequences 15.4.4-2 15.4.4.3 Deleted 15.4.4-3 15.4.4.4 Deleted 15.4.4-4 15.4.4.5 Radiological Analysis 15.4.4-4a 15.4.4.6 Conclusions 15.4.4-4e 15.4.4.7 Deleted 15.4.4-4e UNIT 1 15-v Amendment No. 27 (04/15)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.4.5 CEA EJECTION EVENT 15.4.5-1 15.4.5.1 Identification of Causes 15.4.5-1 15.4.5.2 Analysis of Effects and Consequences 15.4.5-1 15.4.5.3 Results 15.4.5-2 15.4.5.4 Radiological Analysis 15.4.5-2a 15.4.5.5 Deleted 15.4.5-2e 15.4.5.6 Deleted 15.4.5-2e 15.4.5.7 References 15.4.5-2e 15.4.6 STEAM LINE BREAK ACCIDENT 15.4.6-1 15.4.6.1 Identification of Causes 15.4.6-1 15.4.6.2 Analysis of Effects and Consequences 15.4.6-2 15.4.6.3 Results 15.4.6-3 15.4.6.4 Radiological Consequences 15.4.6-3a 15.4.6.5 Conclusion 15.4.6-4 15.4.6.6 Deleted 15.4.6-4 15.4.6.7 Deleted 15.4.6-4

15.5 REFERENCES

FOR CHAPTER 15 15.5-1 15.6

SUMMARY

OF OPERATING LIMITS 15.6-1 15.6.1 REACTOR PROTECTION SYSTEM 15.6-1 15.6.2 SPECIFIED ACCEPTABLE FUEL DESIGN LIMITS 15.6-1 15.6.3 LIMITING SAFETY SYSTEM SETTINGS 15.6-2 15.6.3.1 Local Power Distribution Control 15.6-2 15.6.3.2 Thermal Margin/Low Pressure 15.6-2 15.6.3.3 Additional Trip Functions 15.6-2 15.6.4 LIMITING CONDITIONS FOR OPERATION 15.6-2 15.6.4.1 DNB Monitoring 15.6-2 15.6.4.2 Linear Heat Rate Monitoring 15.6-3 15.6.5 SETPOINT ANALYSIS 15.6-3 15.6.5.1 Limiting Safety System Settings 15.6-3 15.6.5.2 Limiting Conditions for Operation 15.6-4 15.

6.6 REFERENCES

FOR SECTION 15.6 15.6-5 15-va Amendment No. 26 (11/13)

ACCIDENT ANALYSES CHAPTER 15 LIST OF TABLES Table Title Page 15.1.1-1 Classification of Accidents Analyzed 15.1.1-2 15.1.1-2 Nonapplicable Accidents 15.1.1-4 15.1.1-3 Design Bases Events Considered in EPU (3020 Mwth) 15.1.1-7 Safety Analysis 15.1.1-4 Deleted 15.1.1-9 15.1.1-5 Fuel and Vessel Design Limits 15.1.1-10 15.1.1-6 Design Basis Events Analyzed Using Alternative Source Term 15.1.1-11 (AST) Methodology 15.1.3-1 Reactor Protective Instrumentation Trip Setpoint Limits 15.1.3-2 15.1.6-1 Deleted 15.1.6-5 15.1.6-2 Deleted 15.1.6-6 15.1.6-3 St. Lucie Unit 1 Operating Parameters 15.1.6-7 15.1.6-4 Framatome (formerly AREVA) Fuel Design Parameters for 15.1.6-8 EC292529 St. Lucie Unit 1 15.1.6-5 St. Lucie Unit 1 Bounding Neutronics Characteristics and Shutdown 15.1.6-9 Margin 15.1.6-6 Summary of St. Lucie Unit 1 Chapter 15 Event Review For 15.1.6-12 Current Cycle 15.1.7-1 Comparison of Steam Generators at Conditions for 2700 MWT 15.1.7-2 15.1.8-1 Comparison of Pressurizers 15.1.8-2 15.2.1-1 Kinetics Parameters for the CEA Withdrawal Event 15.2.1-6 15.2.1-2 Event Table for CEA Withdrawal at Power 15.2.1-7 15.2.2-1 Key Parameters Assumed in the Analysis of Loss of Load to One 15.2.2-3 Steam Generator 15.2.2-2 Sequence of Events for Loss of Load to One Steam Generator 15.2.2-4 15.2.3-1 Kinetics Parameters for the CEA-Drop Event 15.2.3-3 15.2.3-2 Event Table for CEA Drop 15.2.3-3 UNIT 1 15-vi Amendment No. 30 (05/20)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.2.4-1 Boron Dilution Event: Input Parameters 15.2.4-7 15.2.4-2 Boron Dilution Event: Results 15.2.4-8 15.2.5-1 Kinetics Parameters for the Loss-of-Coolant Flow Event 15.2.5-3 15.2.5-2 Event Table for a Loss-of-Coolant Flow 15.2.5-4 15.2.7-1 Loss of External Load Sequence of Events for Primary Side 15.2.7-4 Over Pressurization Case 15.2.7-2 Loss of External Load Sequence of Events for HFP Secondary 15.2.7-5 Side Over Pressurization Limiting Case 15.2.7-3 Loss of External Load Sequence of Events for MDNBR Case 15.2.7-5 15.2.7-4 Loss of External Load Inoperable MSSV Results 15.2.7-5a 15.2.8-1 Plant Initial Condition and Key Parameters for Loss-of-Normal 15.2.8-3 Feedwater Analysis 15.2.8-2 Sequence of Events for Loss of Normal Feedwater Analysis 15.2.8-4 15.2.9-1 Deleted 15.2.9-6 15.2.9-2 Deleted 15.2.9-7 15.2.9-3 Deleted 15.2.9-8 15.2.9-4 Deleted 15.2.9-9 15.2.11-1 Excess Load: HFP Analysis Parameters 15.2.11-2f 15.2.11-2 Excess Load: Sequence of Events For HFP Limiting Case (Maximum Load Increase, -29.6 pcm/°F) 15.2.11-3 15.2.11-3 Excess Load: HZP Analysis Parameters 15.2.11-3a 15-vii Amendment No. 26 (11/13)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.2.11-4 Sequence of Events for Excess Load Event At HZP 15.2.11-3b Conditions 15.2.11-5 IOMSSV - Inputs and Assumptions 15.2.11-4 15.2.11-6 IOMSSV Steam Generator Tube Leakage 15.2.11-5 15.2.11-7 Control Room /Qs 15.2.11-6 15.2.11-8 IOMSSV Dose Consequences 15.2.11-6 15.2.12-1 Initial Conditions and Biasing for the RCS Depressurization Event 15.2.12-2 15.2.12-2 Sequence of Events for RCS Depressurization Event 15.2.12-2 15.2.12-3 RCS Depressurization/Pressurizer Overfill: Initial Conditions and 15.2.12-2a Biasing 15.2.12-4 RCS Depressurization/Pressurizer Overfill: Sequence of Events 15.2.12-2b 15.2.13-1 Key Parameters for the Station Blackout Event 15.2.13-6 15.2.13-2 Sequence of Events for the SBO Event 15.2.13-7 15.2.13-3 Parameter Variation in the SBO Analysis 15.2.13-8 15.2.13-4 Deleted 15.2.13-9 15.2.14-1 CVCS Malfunction Event: Initial Conditions and Input 15.2.14-4 Parameter Biasing 15.2.14-2 CVCS Malfunction Event: Sequence of Events 15.2.14-5 15-viia Amendment No. 28 (05/17)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.3.1-1 HPSI Flow Rate Vs RCS Pressure Used in the SBLOCA Event 15.3.1-3b 15.3.1-2 Current SBLOCA Analysis Parameters 15.3.1-3c 15.3.4-1 Initial Conditions and Biasing For RCP Rotor Seizure Event 15.3.4-5 15.3.4-2 Sequence of Events For RCP Rotor Seizure Event 15.3.4-6 15.3.4-3 Deleted 15.3.4-7 15.3.4-4 Reactor Coolant Pump Shaft Seizure (Locked Rotor) - 15.3.4-8 Inputs and Assumptions 15.3.4-4a DELETED 15.3.4-9 EC292761 15.3.4-5 Locked Rotor Steam Release Rate 15.3.4-9 15.3.4-6 Locked Rotor SG Tube Leakage 15.3.4-10 15.3.4-7 Control Room /Qs 15.3.4-10 15.3.4-8 Locked Rotor Dose Consequences 15.3.4-11 15.4.1-1 Sampled LBLOCA Parameters 15.4.1-14 15.4.1-1a Plant Operating Range Supported By the LOCA Analysis 15.4.1-14a 15.4.1-1b Statistical Distributions Used For Process Parameters 15.4.1-15 15.4.1-1c Summary Of Major Parameters For the Limiting PCT Case 15.4.1-16 15.4.1-1d Calculated Event Times For the Limiting PCT Case 15.4.1-17 15.4.1-1e LOCA Containment Leakage Source Term 15.4.1-18 15.4.1-1f Containment Heat Sink Data 15.4.1-19 15.4.1-1g Containment Initial and Boundary Conditions 15.4.1-19a 15.4.1-1h Summary Of Results For the Limiting PCT Case 15.4.1-19a 15.4.1-2 Maximum Potential Recirculation Loop Leakage (Outside Containment) 15.4.1-20 15.4.1-3 Deleted 15.4.1-21 15.4.1-4 Deleted 15.4.1-22 UNIT 1 15-viii Amendment No. 30 (05/20)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.4.1-5 Class 3 - Design Basis Accident Off-Site Doses (Historical) 15.4.1-23 15.4.1-6 Loss-of-Coolant Accident (LOCA) - Inputs and Assumptions 15.4.1-24 15.4.1-7 LOCA Release Phases 15.4.1-27 15.4.1-8 Adjusted Sump to RWT Leakage Flow Rate 15.4.1-27 15.4.1-8a RWT Leakage Flow Rate 15.4.1-27 15.4.1-9 Reactor Coolant Source Term 15.4.1-28 15.4.1-10 Control Room /Q 15.4.1-29 15.4.1-11 LOCA Dose Summary 15.4.1-30 15.4.2-1 Waste Gas Decay Tank Rupture (WGDT) - Inputs and Assumptions 15.4.2-2a 15.4.2-2 WGDT Source Term - 165,000 Curies Xe-133 Equivalent 15.4.2-3 15.4.2-3 EAB X/Q 15.4.2-3 15.4.2-4 LPZ X/Q 15.4.2-4 15.4.2-5 Common St. Lucie HVAC E/Q Table 15.4.2-4 15.4.2-6 Common St. Lucie Control Room Unfiltered 15.4.2-4a Inleakage X/Q 15.4.2-7 St. Lucie Units 1 and 2 Waste Gas Decay Tank Failure 15.4.2-4a 15.4.3-1 Fuel Handling Accident (FHA) - Inputs and Assumptions 15.4.3-8 15.4.3-2 Fuel Handling Accident Source Term 15.4.3-9 15.4.3-3 Control Room /Qs for Containment Release and For FHB Release 15.4.3-10 15.4.3-4 Fuel Handling Accident Dose Consequences 15.4.3-10 15-viiia Amendment No. 26 (11/13)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.4.4-1 Key Parameters Assumed in the Steam Generator Tube Rupture Event 15.4.4-5 15.4.4-2 Sequence of Events for the Steam Generator Tube Rupture Event 15.4.4-6 (45 min. Operator Action Time) 15.4.4-2a Key Parameters Assumed in the Steam Generator Tube Rupture 15.4.4-6 Overfill Event 15.4.4-2b Sequence of Event For the Steam Generator Tube Rupture Overfill 15.4.4-6a Event (45 min. Operator Action Time) 15.4.4-3 Steam Generator Tube Rupture (SGTR) - Inputs and Assumptions 15.4.4-7 15.4.4-4 SGTR Mass Releases Rates 15.4.4-8 15.4.4-5 SGTR Iodine Equilibrium Appearance Assumptions 15.4.4-8 15.4.4-6 SGTR Concurrent Iodine Spike (335 x µCi/gm) Activity Appearance 15.4.4-9 Rate 15.4.4-7 SGTR 60 Ci/gm D.E. I-131 Activities 15.4.4-9 15.4.4-8 Control Room /Qs 15.4.4-10 15.4.4-9 SGTR Dose Consequences 15.4.4-10 15.4.5-1 CEA Ejection: Input Parameter Biasing For HFP and HZP Cases 15.4.5-3 15.4.5-1a CEA Ejection: Input Parameter Biasing For Part-Power Cases 15.4.5-3 15.4.5-2 CEA Ejection: Event Results For HFP and HZP Cases 15.4.5-4 15.4.5-2a CEA Ejection: Sequence of Events For HFP and HZP Cases 15.4.5-4a 15.4.5-2b DELETED 15.4.5-4b EC292761 15.4.5-3 Control Element Assembly (CEA) Ejection - Inputs and Assumptions 15.4.5-5 15.4.5-4 CEA Steam Release Rate 15.4.5-7 15.4.5-5 CEA Steam Generator Tube Leakage 15.4.5-7 15.4.5-6 Control Room /Q (for releases from the steam generators) 15.4.5-8 15.4.5-7 CEA Ejection Dose Consequences 15.4.5-8 15.4.5-8 Deleted 15.4.5-9 15-ix Amendment No. 30 (05/20)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.4.6-1 Pre-Scram Main Steam Line Break: 15.4.6-5 Input Parameter Biasing 15.4.6-2 Deleted 15.4.6-6 15.4.6-3 Post-Steam Line Break: 15.4.6-7 Input Parameter Biasing 15.4.6-4 Pre-Scram Main Steam Line Break: 15.4.6-8 Limiting Case Sequence of Events 15.4.6-4a Post-Scram Main Steam Line Break: 15.4.6-8 HZP Sequence of Events 15.4.6-4b Post-Scram Main Steam Line Break: 15.4.6-8a HFP Sequence of Events 15.4.6-4c DELETED 15.4.6-8b EC292761 15.4.6-5 Main Steam Line Break (MSLB) - Inputs and Assumptions 15.4.6-9 15.4.6-6 MSLB Steam Release Rate 15.4.6-10 15.4.6-7 MSLB Steam Generator Tube Leakage 15.4.6-11 15.4.6-8 Secondary Side Source Term 15.4.6-11 15.4.6-9 Control Room /Q (for releases from the steam generators) 15.4.6-12 15.4.6-10 MSLB Dose Consequences 15.4.6-12 15.6-1 Uncertainties Applied in LPD LSSS Calculations 15.6-6 15.6-2 Uncertainties Applied in the TM/LP LSSS Calculations 15.6-7 15.6-3 Transient Biases Applied in the TM/LP LSSS Calculation 15.6-8 15.6-4 Additional Trip Functions 15.6-9 (Only Those Used In Setpoints Verification) 15.6-5 Uncertainties Applied in the LCO Calculations 15.6-10 15.6-6 Additional Uncertainties Applied in DNB LCO CEAD 15.6-10a Calculations 15.6-7 Additional Uncertainties Applied in DNB LCO LOCF 15.6-10b Calculations 15-ixa Amendment No. 30 (05/20)

ACCIDENT ANALYSES CHAPTER 15 LIST OF FIGURES Figure Title 15.1.6-1 Deleted 15.1.6-2 St. Lucie Unit 1 LPD LSSS 15.1.6-3 St. Lucie Unit 1 - TM/LP Correction Function A1 15.1.6-4 St. Lucie Unit 1 - TM/LP Correction Function QR1 15.1.6-5 DNB LCO for St. Lucie Unit 1 15.1.6-6 Deleted 15.1.6-7 Deleted 15.1.6-8 Deleted 15.1.6-9 Deleted 15.2.1-1 St. Lucie Unit 1 - Reactor Power - CEA Withdrawal At Power 15.2.1-2 St. Lucie Unit 1 - Total Core Heat Flux Power - CEA Withdrawal At Power 15.2.1-3 St. Lucie Unit 1 - Pressurizer Pressure - CEA Withdrawal At Power 15.2.1-4 St. Lucie Unit 1 - Pressurizer Liquid Level - CEA Withdrawal At Power 15.2.1-5 St. Lucie Unit 1 - RCS Loop Temperatures - CEA Withdrawal At Power 15.2.1-6 St. Lucie Unit 1 - RCS Total Loop Flow Rate - CEA Withdrawal At Power 15.2.1-7 St. Lucie Unit 1 - Margin to TM/LP RPS Trip - CEA Withdrawal At Power 15.2.1-8 St. Lucie Unit 1 - Margin to VHP RPS Trip - CEA Withdrawal At Power 15.2.1-9 St. Lucie Unit 1 - Reactivity Feedback - CEA Withdrawal At Power 15.2.1-10 Deleted 15.2.1-11 Deleted 15-x Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.2-1 Loss of Load/1 Steam Generator Event Core Power vs Time 15.2.2-2 Loss of Load/1 Steam Generator Event Reactivity Feedback vs Time 15.2.2-3 Loss of Load/1 Steam Generator Event SG Pressures vs Time 15.2.2-4 Loss of Load/1 Steam Generator Event Pressure SG Difference vs ASGPT Setpoint and vs Time 15.2.2-5 Loss of Load/1 Steam Generator Event Core Inlet Temperatures vs Time 15.2.2-6 Loss of Load/1 Steam Generator Event RCS Loop Flow Rates vs Time 15.2.2-7 Loss of Load/1 Steam Generator Event Pressurizer Pressure vs Time 15.2.2-8 Loss of Load/1 Steam Generator Event Pressurizer Level vs Time 15.2.2-9 Loss of Load/1 Steam Generator Event Steam Flow Rates vs Time 15.2.2-10 Loss of Load/1 Steam Generator Event MSSV Flows vs Time 15.2.3-1 St. Lucie Unit 1 - Reactor Powers - CEA Drop 15.2.3-2 St. Lucie Unit 1 - Total Core Heat Flux Power - CEA Drop 15.2.3-3 St. Lucie Unit 1 - Pressurizer Pressure - CEA Drop 15.2.3-4 St. Lucie Unit 1 - Pressurizer Liquid Level - CEA Drop 15.2.3-5 St. Lucie Unit 1 - RCS Loop Temperatures - CEA Drop 15.2.3-6 St. Lucie Unit 1 - RCS Total Loop Flow Rate - CEA Drop 15.2.3-7 St. Lucie Unit 1 - Steam Generator Pressures - CEA Drop 15.2.3-8 St. Lucie Unit 1 - Steam Generator Flow Rates - CEA Drop 15.2.3-9 St. Lucie Unit 1 - Reactivity Feedback - CEA Drop 15.2.3-10 Deleted 15.2.3-11 Deleted 15.2.5-1 St. Lucie Unit 1 - Reactor Power - Loss of Coolant Flow 15.2.5-2 St. Lucie Unit 1 - Total Core Heat Flux Power - Loss of Coolant Flow 15.2.5-3 St. Lucie Unit 1 - Pressurizer Pressure - Loss of Coolant Flow 15.2.5-4 St. Lucie Unit 1 - RCS Loop Temperatures - Loss of Coolant Flow 15.2.5-5 St. Lucie Unit 1 - RCS Total Loop Flow Rate Temperatures - Loss of Coolant Flow 15.2.5-6 St. Lucie Unit 1 - Reactivity Feedback - Loss of Coolant Flow 15.2.5-7 Deleted 15-xi Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.5-8 Deleted 15.2.5-9 Deleted 15.2.5-10 Deleted 15.2.5-11 Deleted 15.2.7-1 Loss of External Load Reactor Power vs. Time (Primary Side Pressure Case) 15.2.7-2 Loss of External Load Pressurizer and Peak RCS Pressure (Primary Side Pressure Case) 15.2.7-3 Loss of External Load Pressurizer Liquid Level vs. Time (Primary Side Pressure Case) 15.2.7-4 Loss of External Load Pressurizer Safety Valve Flow vs. Time (Primary Side Pressure Case) 15.2.7-5 Loss of External Load RCS Loop Temperatures (Primary Side Pressure Case) 15.2.7-6 Loss of External Load RCS Cold Leg Loop Flow Rates (Primary Side Pressure Case) 15.2.7-7 Loss of External Load Steam Line Pressures (Primary Side Pressure Case) 15.2.7-8 Loss of External Load MSSV Flow Rates (Primary Side Pressure Case) 15.2.7-9 Loss of External Load Reactivity Feedback (Primary Side Pressure Case) 15.2.7-10 Loss of External Load Reactor Power (Secondary Side Pressure Case) 15.2.7-11 Loss of External Load Pressurizer Pressure (Secondary Side Pressure Case) 15.2.7-12 Loss of External Load Pressurizer Liquid Level (Secondary Side Pressure Case) 15.2.7-13 Loss of External Load RCS Loop Temperatures (Secondary Side Pressure Case) 15.2.7-14 Loss of External Load RCS Cold Leg Loop Flow Rates (Secondary Side Pressure Case) 15.2.7-15 Loss of External Load Main Steam System (SG Dome) Pressures (Secondary Side Pressure Case) 15.2.7-16 Loss of External Load MSSV Flow Rates (Secondary Side Pressure Case) 15.2.7-17 Loss of External Load Reactivity Feedback (Secondary Side Pressure Case) 15.2.7-18 Loss of External Load Reactor Power (MDNBR Case) 15.2.7-19 Loss of External Load Total Core Heat Flux Power (MDNBR Case) 15-xii Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.7-20 Loss of External Load Pressurizer Pressure (MDNBR Case) 15.2.7-21 Loss of External Load Pressurizer Liquid Level (MDNBR Case) 15.2.7-22 Loss of External Load Pressurizer PORV Flow Rate (MDNBR Case) 15.2.7-23 Loss of External Load RCS Loop Temperatures (MDNBR Case) 15.2.7-24 Loss of External Load RCS Total Loop Flow Rate (MDNBR Case) 15.2.7-25 Loss of External Load Steam Generator Pressures (MDNBR Case) 15.2.7-26 Loss of External Load Reactivity Feedback (MDNBR Case) 15.2.8-1 Loss of Feedwater Flow Event Steam Generator Inventories vs. Time 15.2.9-1 Deleted 15.2.9-2 Deleted 15.2.9-3 Deleted 15.2.9-4 Deleted 15.2.9-5 Deleted 15-xiia Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Contd)

Figure Title 15.2.11-1 Core Power for HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-2 Total Core Heat Flux Power For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-3 Pressurizer Pressure HFP Limiting Excess Load (Maximum Load Increase, MTC of

-29.6 pcm/oF) 15.2.11-4 RCS Loop Temperature For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-5 RCS Total Loop Flow Rate For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-6 Steam Generator Pressure For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-7 Steam and Feedwater Flow Rates For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-8 Reactivity Feedback For HFP Limiting Excess Load (Maximum Load Increase, MTC of

-29.6 pcm/oF) 15.2.11-9 Reactor Power - HZP Excess Load 15.2.11-10 Total Core Heat Flux Power - HZP Excess Load 15.2.11-11 Pressurizer Pressure - HZP Excess Load 15.2.11-12 RCS Loop Temperatures - HZP Excess Load 15.2.11-13 RCS Total Loop Flow Rate - HZP Excess Load 15.2.11-14 Steam Generator Pressures - HZP Excess Load 15.2.11-15 Steam and Feedwater Flow Rate - HPZ Excess Load 15.2.11-16 Reactivity Feedback - HZP Excess Load 15.2.11-17 Peak Fuel Centerline Temperature - HZP Excess Load 15.2.12-1 Reactor Power - RCS Depressurization 15.2.12-2 Total Core Heat Flux Power - RCS Depressurization 15.2.12-3 Pressurizer Pressure - RCS Depressurization 15.2.12-4 Pressurizer PORV Flow Rate - RCS Depressurization 15-xiii Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Contd) 15.2.12-5 RCS Loop Temperatures - RCS Depressurization 15.2.12-6 RCS Total Loop Flow Rate - RCS Depressurization 15.2.12-7 Reactivity Feedback - RCS Depressurization 15.2.12-8 Deleted 15.2.12-9 Deleted 15.2.12-10 Deleted 15.2.12-11 Deleted 15.2.12-12 Pressurizer PORV Flow Rate - RCS Depressurization / Pressurizer Overfill 15.2.12-13 Pressurizer Pressure - RCS Depressurization / Pressurizer Overfill 15.2.12-14 RCS Coolant Temperatures - RCS Depressurization / Pressurizer Overfill 15.2.12-15 RCS Subcooling - RCS Depressurization / Pressurizer Overfill 15.2.12-16 Total RCS Flow Rate - RCS Depressurization / Pressurizer Overfill 15.2.12-17 Indicated Reactor Power - RCS Depressurization / Pressurizer Overfill 15.2.12-18 Total HPSI and Charging Flow Rates - RCS Depressurization / Pressurizer Overfill 15.2.12-19 Pressurizer Liquid Volume - RCS Depressurization / Pressurizer Overfill 15.2.13-1 Total RCS Leakage - Station Blackout 15.2.13-2 Reactor Power (Decay Heat) - Station Blackout 15.2.13-3 Pressurizer Pressure - Station Blackout 15.2.13-4 Pressurizer Liquid Level - Station Blackout 15.2.13-5 RCS Reactor Vessel Upper Head Subcooling Margin - Station Blackout 15.2.13-6 RCS Average Temperatures - Station Blackout 15.2.13-7 ADV Flow Rates - Station Blackout 15.2.13-8 Steam Generator Pressure - Station Blackout 15.2.13-9 Steam Generator Liquid Level - Station Blackout 15.2.13-10 Steam Generator Total Mass - Station Blackout 15.2.13-11 Reactor Vessel Liquid Level (Above Bottom of Active Core) - Station Blackout 15-xiiia Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.14-1 Reactor Power - CVCS Malfunction Event 15.2.14-2 RCS Average Temperature - CVCS Malfunction Event 15.2.14-3 Pressurizer Pressure - CVCS Malfunction Event 15.2.14-4 Pressurizer Water Volume - CVCS Malfunction Event 15.3.1-1 Reactor Power for 3.70 in. Diameter Break - SBLOCA 15.3.1-2 Primary and Secondary Pressures for 3.70 in. Diameter Break - SBLOCA 15.3.1-3 Break Void Fraction for 3.70 in. Diameter Break - SBLOCA 15.3.1-4 Break Flow Rate for 3.70 in. Diameter Break - SBLOCA 15.3.1-5 Loop Seal Void Fractions for 3.70 in. Diameter Break - SBLOCA 15.3.1-6 RCS Loop Flow Rate for 3.70 in. Diameter Break - SBLOCA 15.3.1-7 MFW Flow Rate for 3.70 in. Diameter Break - SBLOCA 15.3.1-8 AFW Flow Rate for 3.70 in. Diameter Break - SBLOCA 15.3.1-9 Steam Generator Total Mass for 3.70 in. Diameter Break - SBLOCA 15.3.1-10 Total HPSI Mass Flow Rate for 3.70 in. Diameter Break - SBLOCA 15.3.1-11 Total SIT Mass Flow Rate for 3.70 in. Diameter Break - SBLOCA 15.3.1-12 RCS and Reactor Vessel Mass Inventories for 3.70 in. Diameter Break - SBLOCA 15.3.1-13 Hot Assembly Collapsed Liquid Level for 3.70 in. Diameter Break - SBLOCA 15.3.1-14 Hot Spot Cladding Temperature and Coolant Temperature for 3.70 in. Diameter Break - SBLOCA 15.3.3-1 Typical BOL Power Distribution with Correct Fuel Loading, Maine Yankee 15.3.3-2 Power Distribution for Postulated Interchange of Two C Assemblies, Maine Yankee 15.3.3-3 Power Distribution for Postulated Interchange of Two C Assemblies, Maine Yankee 15.3.3-4 Power Distribution for Postulated Interchange of an A and C Assembly, Maine Yankee UNIT 1 15-xiv Amendment No. 27 (04/15)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.3.4-1 Reactor Power - Seized Rotor Event 15.3.4-2 Total Core Heat Flux Power - Seized Rotor Event 15.3.4-3 Pressurizer Pressure - Seized Rotor Event 15.3.4-4 RCS Loop Temperatures - Seized Rotor Event 15.3.4-5 RCS Total Loop Flow Rate - Seized Rotor Event 15.3.4-6 Reactivity Feedback - Seized Rotor Event 15.3.4-7 Deleted 15.3.4-8 Deleted 15.3.4-9 Deleted 15.3.4-10 Deleted 15.3.4-11 Deleted 15.3.4-12 Deleted 15.3.4-13 Deleted 15.3.4-14 Deleted 15.3.4-15 Deleted 15.3.4-16 Deleted 15.3.4-17 Deleted 15.3.4-18 Deleted 15.3.4-19 Deleted 15.3.4-20 Deleted 15.3.4-21 Deleted 15.3.4-22 Deleted 15.4.1-1 Scatter Plot of Operational Parameters 15.4.1-1a Scatter Plot of Operational Parameters (Continued)

UNIT 1 15-xv Amendment No. 27 (04/15)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.4.1-2 PCT vs PCT Time - Scatter Plot From 59 Calculations 15.4.1-3 PCT vs One-Sided Break Area - Scatter Plot From 59 Calculations 15.4.1-4 Maximum Oxidation vs PCT - Scatter Plot From 59 Calculations 15.4.1-5 Total Oxidation vs PCT - Scatter Plot From 59 Calculations 15.4.1-6 Peak Cladding Temperature (Independent of Elevation) for the Limiting Case 15.4.1-7 Break Flow for the Limiting Case 15.4.1-8 Core Inlet Mass Flux for the Limiting Case 15.4.1-9 Core Outlet Mass Flux for the Limiting Case 15.4.1-10 Void Fraction At RCS Pumps for the Limiting Case 15.4.1-11 ECCS Flows (Includes SIT, LPSI and HPSI) for the Limiting Case 15.4.1-12 Upper Plenum Pressure for the Limiting Case 15.4.1-13 Collapsed Liquid Level in the Downcomer for the Limiting Case 15.4.1-14 Collapsed Liquid Level in the Lower Plenum for the Limiting Case 15.4.1-15 Collapsed Liquid Level in the Core for the Limiting Case 15.4.1-16 Containment and Loop Pressures for the Limiting Case 15.4.1-17 Normalized Power vs Time for the Limiting Case 15.4.1-18 Average Core Inlet Flow Rate During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-19 Hot Channel Inlet Flow Rate During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-20 PCT Node Fluid Quality During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-21 PCT Node Fuel (Average), Cladding, and Fluid Temperatures During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-22 PCT Node Heat Transfer Coefficient During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-23 PCT Node Heat Flux During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-24 Core Quench Level for the Limiting Case 15.4.1-25 PCT Node Heat Transfer Coefficient (to PCT Node Quench) for the Limiting Case 15.4.1-26 PCT Node Cladding Temperature for the Limiting Case 15.4.1-27 GDC 35 Loop vs No-Loop Cases 15.4.1-28 Allowable Control Room Intake as a Function of Cont. and Bypass Leakage UNIT 1 15-xva Amendment No. 27 (04/15)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.4.4-1 Reactor Power vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-2 Pressurizer Liquid Level vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-3 Pressurizer Pressure vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-4 RCS Loop Temperatures vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-5 RCS Total Loop Flow Rate vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-6 Steam Generator Pressures vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-7 Reactivity Feedback vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-8 Steam Generator Masses vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-9 MSSV Flow Rate vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-10 Total Break Flow Rate vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-11 Integrated Break Flow vs Time - Steam Generator Tube Rupture (Hot Side Break) 15.4.4-12 Ruptured Stem Generator Liquid Volume vs Time - Steam Generator Tube Rupture (Overfill) 15.4.5-1 Reactor Power vs Time - CEA Ejection (BOC HFP) 15.4.5-2 Total Core Heat Flux Power vs Time - CEA Ejection (BOC HFP) 15.4.5-3 RCS Loop Temperature vs Time - CEA Ejection (BOC HFP) 15.4.5-4 RCS Total Loop Flow Rate vs Time - CEA Ejection (BOC HFP) 15.4.5-5 Reactivity Feedback vs Time - CEA Ejection (BOC HFP) 15.4.5-6 Peak Fuel Centerline Temperature vs Time - CEA Ejection (BOC HFP) 15.4.5-7 Peak RCS Pressure vs Time - CEA Ejection (BOC HFP) 15.4.6-1 Reactor Power - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-2 Total Core Heat Flux Power - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-3 Pressurizer Pressure - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-4 Pressurizer Liquid Level - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-5 RCS Loop Temperatures - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-6 RCS Total Loop Flow Rate - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-7 Steam Generator Pressure - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-8 Break Flow Rate - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15-xvi Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.4.6-9 Steam and Feedwater Flow Rates - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-10 Reactivity Feedback - Pre-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-11 Break Flow Rates - Post-Scram Main Steam Line Break (HFP, 3.0 Ft2 Break, MTC -20 PCM/°F) 15.4.6-12 Steam Generator Pressures - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-13 Combined MFW and AFW Flow Rates - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-14 Steam Generator Mass Inventories - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-15 Core Inlet Fluid Temperatures - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-16 Pressurizer Liquid Level - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-17 Pressurizer Pressure - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-18 Total HPSI Flow Rate - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-19 Reactivity Feedback - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-20 Core Power - Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-21 Break Flow Rates - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-22 Steam Generator Pressures - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-23 Combined MFW and AFW Flow Rates - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-24 Steam Generator Mass Inventories - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-25 Core Inlet Fluid Temperatures - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-26 Pressurizer Liquid Level - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-27 Pressurizer Pressure - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-28 Total HPSI Flow Rate - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-29 Reactivity Feedback - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-30 Core Power - Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15-xvii Amendment No. 26 (11/13)

CHAPTER 15

LIST OF FIGURES (Cont'd)

Figure Title 15.6-1 Deleted 15.6-2 St. Lucie Unit 1, TM/LP Trip Function A1 15.6-3 St. Lucie Unit 1, TM/LP Trip Function QR1 15.6-4 Deleted 15.6-5 Deleted 15.6-6 Deleted 15.6-7 Linear Heat Rate LCO Used In LPD LCO Verification 15.6-8 Power Measurement Uncertainty vs. Power 15-xviia Amendment No. 26 (11/13)

CHAPTER 15 ACCIDENT ANALYSIS 15.1 GENERAL Previous chapters describe the major systems and components of the plant and evaluate their reliability from a safety standpoint. It is the purpose of this section to assume that certain accidents occur despite the precautions taken to prevent their happening. The potential consequences of such occurrences are then examined to determine their effect on the plant, to determine whether plant design is adequate to minimize consequences of such occurrences, and to assure that the health and safety of the public and plant personnel are protected from the consequences of even the most severe of the hypothetical accidents analyzed.

Chapter 15 has been modified so that the Safety Analysis Report (SAR) has been incorporated into the text.

Therefore, the user has available the current cycle information.

15.1.1-1 Amendment No. 26 (11/13)

15.1.1 CLASSIFICATION OF ACCIDENTS Each Chapter 15 event is categorized wth respect to its potential consequences. The events fall into two principal classifications: Anticipated Operational Occurrences (AOOs) and Postulated Accidents (PAs). Where applicable, the RPS and/or ESF were assumed to fulfill their function as needed to mitigate the consequences of a given event. The event classifications employed for the entended power uprate (EPU) are described below.

Anticipated Operational Occurrences (Class 1 Accidents)

  • AOOs include those events which: (1) do not induce fuel failures, (2) do not lead to a breach of barriers and fission product release, (3) may not require operation of any engineered safety features, and (4) do not lead to significant radiation exposure offsite.

Postulated Accidents (Class 2 and 3 Accidents)

  • PAs include those which: (1) may induce fuel failures, (2) may lead to a breach of barriers and fission product release, (3) may require operation of engineering safety features, and (4) may result in offsite radiation exposures in excess of normal operational limits, but less that allowed regulatory limits.

Table 15.1.1-1 is a listing of the accidents based on the Regulatory Guide 1.70, "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants," Revision 1, issued October 1972. Table 15.1.1-1 also lists and classifies the accidents evaluated in this section and references the section in which the accident is discussed. Several accidents listed in the Standard Format and Content guide are not applicable. These accidents are listed in Table 15.1.1-2 with an explanation.

Table 15.1.1-3 provides a listing of those design basis events which were reanalyzed for EPU (3020 MWth) operation. The dose consequences of selected events were subsequently evaluated using the Alternative Source Term methodology prescribed in Regulatory Guide 1.183. These events are listed in Table 15.1.1-6.

Table 15.1.1-5 lists fuel and vessel design limits. Table 13.8.2-2 provides the engineered safety features response times.

15.1.1.1 Section 15.1 References

1. "Standard Review Plan for the Review of Safety Analysis Report for Nuclear Power Plants,"

NUREG-0800, U.S. Nuclear Regulatory Commission, July 1981.

2. USNRC Regulatory Guide 1.183, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Plants, July 2000.

15.1.1-1a Amendment No. 26 (11/13)

TABLE 15.1.1-1 CLASSIFICATION OF ACCIDENTS ANALYZED Section Item Accidents Classification Number 1 Uncontrolled CEA withdrawal from a subcritical or low power condition, including CEA or temporary control device removal error during refueling AOO 15.2.1 2 Uncontrolled CEA withdrawal at power AOO 15.2.1 Transients resulting from malfunction of one steam generator AOO 15.2.2 3 CEA Drop Accident AOO 15.2.3 4 Chemical and volume control system malfunction AOO 15.2.4; 15.2.14 5 Loss of forced reactor coolant flow AOO 15.2.5 28 Single reactor coolant pump locked rotor PA 15.3.4 6 Startup of an inactive reactor coolant loop or recirculation AOO 15.2.6 7 Loss of external electrical load and/or turbine Stop Valve Closure AOO 15.2.7 8 Loss of normal feedwater AOO 15.2.8 9 Loss of offsite power to the station auxiliaries AOO 15.2.9 10 Excessive heat removal due to feedwater system malfunctions AOO 15.2.10 11 Excessive load increase, including that resulting from a pressure regulator failure or inadvertent opening of a relief valve or safety valve AOO 15.2.11 16 Loss of reactor coolant, from small ruptured pipes or from cracks in large pipes, which actuate emergency core cooling PA 15.2.12; 15.3.1 Station blackout AOO 15.2.13 17 Minor secondary system pipe break outside containment PA 15.3.2 25 Steamline breaks PA 15.4.6 18 Inadvertent loading of a fuel assembly into an improper position PA 15.3.3 15.1.1-2 Amendment No. 26 (11/13)

TABLE 15.1.1-1 (Continued)

Section Item Accidents Classification Number 27 Major rupture of pipes containing reactor coolant up to and including double-ended rupture of the largest pipe in the reactor coolant system (Loss-of-Coolant Accident) PA 15.4.1 20 Waste gas decay tank rupture PA 15.4.2 21 Steam generator tube rupture PA 15.4.4 22 CEA ejection accident PA 15.4.5 29 Fuel handling accident PA 15.4.3 Fuel clad failure plus steam generator leak PA 15.4.4 Residual heat removal system failure (Ref. Sec. 9.3.5)

Loss of condenser vacuum (Ref. Sec. 7.7.1.4.2)

Turbine bypass valve failure (Ref. Sec. 5.2.2; 7.7.2.3.2) 15.1.1-3 Amendment No. 26 (11/13)

TABLE 15-1.1-2 NONAPPLICABLE ACCIDENTS

  • Item Accident Reason 1 Anticipated variations in reactivity load of the The plant does not use on-line refueling and fuel reactor to be compensated by means of control followers. The xenon poisoning, fuel burnup, system action. Examples of such variations are and reactivity feedback effects are taken into buildup and burnout of xenon poisoning, fuel account in design and analyses postulated in temperature, moderator and void coefficients. this section. Xenon poisoning and fuel burnup are described in Chapter 4.

13 Failure of the regulating instrumentation, causing, for example a power-coolant mismatch. A reactor coolant flow controller malfunction is Include reactor coolant flow controller failure not possible as the design does not include resulting in increasing flow. coolant flow controllers. Any failure in the instrumentation which causes a power-coolant mismatch will result in an accident less severe than the loss of external load (Section 15.2.7).

14 Possibilities for equipment failures involving loss of component integrity which shifts safety The plant has no instrumentation which serves a action of instrumentation from one of prevention function of process control and of initiation of to one initiating protective safeguard against the emergency safety systems. See Sections 7.2 release of radioactivity. and 7.3.

15 External causes of accidents such as storms, flood or earthquake. Internal causes of Such external events could result in damage to accidents such as major and minor fires. non-Class I systems, the consequence of which would be less severe than those of accidents which are analyzed.

The plant is designed to withstand maximum flood levels including wave runup without any radiological consequences. See Section 2.4.5 and 3.4.

Major or minor fires do not reduce the ability to safely shut down the plant or mitigate the consequences of a LOCA, and not result in the release of radioeffluents. See UFSAR Section 9.5.1 and the Fire Protection Design Basis Document (Reference 119) for the fire protection system discussion. See Section 7.3.2.3.2, 7.4.2.1.2 and 8.3.1.2.3.

  • This table is presented here for historical information only.

UNIT 1 15.1.1-4 Amendment No. 28 (05/17)

TABLE 15.1.1-2 (Cont.)

Item Accident Reason 22 Break in instrument line or lines from There are no instrument lines which contact the primary system that penetrate reactor coolant system and which penetrate the containment containment.

24 Small spills or leaks of radioactive fluids Small spills or breaks could not result in significant offsite doses. The net flow of ground water at the site is eastward into the Atlantic Ocean (see Section 2.4.12). Doses resulting from leakage to the Atlantic Ocean would be smaller than those resulting from normal plant operation. (See Section 11.2) 26 Control room unhabitability The provisions for shutting down the reactor from emergency control stations are discussed in Section 7.4.1.8. Control room unhabitability would not result in the release of radioeffluents from the plant.

30 Loss of component cooling water The redundancy of the component cooling system assures component cooling availability at all times. See Section 9.2.2.3.2 for a single failure analysis of this system. A loss of redundancy in the component cooling system does not result in the release of radioeffluents from the plant.

31 Loss of one redundant dc system Loss of one redundant dc system does not prevent the safe shutdown of the plant or the mitigation of the consequences of a LOCA. This single failure does not result in the release of radioeffluents from the plant. See Section 8.3.2.

15.1.1-5

TABLE 15.1.1-2 (Cont.)

Item Accident Reason 33 Turbine trip with failure of generator A turbine trip with failure of the generator breakers to open breaker to open cannot affect the safe shutdown of the plant or the mitigation of the consequences of a LOCA. Motorizing the generator cannot result in turbine overspeed.

This failure does not result in the release of radioeffluents from the plant. See Section 8.2.2.

34 Loss of instrument air Complete loss of instrument air does not reduce the ability to safely shut down the reactor or mitigate the consequences of a LOCA. Loss of instrument air does not result in the release of radioeffluents from the plant. See Section 9.3.1.

35 Malfunction of turbine gland sealing The turbine gland steam system is described in system Section 10.4.3. This anticipated operational occurrence is evaluated in Sections 11.2 and 11.3 for both 0.1 and 1 percent failed fuel.

15.1.1-6

TABLE 15.1.1-3 DESIGN BASIS EVENTS CONSIDERED IN EXTENDED POWER UPRATE (3020 MWth) SAFETY ANALYSIS Anticipated operational occurrences for which Analysis Status intervention of the RPS is necessary to prevent exceeding acceptable limits:

15.2.4 Boron Dilution Reanalyzed 15.2.6 Startup of an Inactive Reactor Coolant Pump Not Reanalyzed 15.2.11 Excess Load Reanalyzed 15.2.7 Loss of Load Reanalyzed 15.2.8 Loss of Feedwater Flow Reanalyzed 15.2.10 Excess Heat Removal due to Feedwater Malfunction Reanalyzed 15.2.12 Reactor Coolant System Depressurization Reanalyzed 15.2.1 Control Element Assembly Withdrawal(1) Reanalyzed 15.2.5 Loss of Coolant Flow(2) Reanalyzed 15.2.9 Loss of AC Power(2) Dispositioned 15.2.2 Transients Resulting from the Malfunction of One Steam Reanalyzed Generator(3) 15.2.13 Station Blackout Reanalyzed Anticipated operational occurrences for which RPS trips and/or sufficient initial steady state thermal margin, maintained by the LCOs, are necessary to prevent exceeding the acceptable limits:

15.2.1 Control Element Assembly Withdrawal Reanalyzed 15.2.5 Loss of Coolant Flow Reanalyzed 15.2.9 Loss of AC Power Dispositioned 15.2.3 Full Length CEA Drop Reanalyzed 15.2.2 Transients Resulting from the Malfunction of One Steam Reanalyzed Generator

1) Requires high power and variable high power trip; event is discussed in respective section below.
2) Requires low flow trip; event is discussed in respective section below.
3) Requires P across the steam generator trip; event is discussed in respective section below.

15.1.1-7 Amendment No. 26 (11/13)

TABLE 15.1.1-3 (Cont'd)

Postulated Accidents: Analysis Status 15.4.5 CEA Ejection Reanalyzed 15.4.6 Steam Line Rupture Reanalyzed 15.4.4 Steam Generator Tube Rupture Reanalyzed 15.3.4 Seized Rotor Reanalyzed 15.4.1 Loss of Coolant Accident Reanalyzed 15.3.2 Minor Secondary System Pipe Not Reanalyzed 15.3.3 Improper Fuel Loading Not Reanalyzed 15.4.2 Waste Gas Decay Tank Rupture Not Reanalyzed 15.4.3 Fuel Handling Accident Not Reanalyzed 15.3.1 Loss of Reactor Coolant from Small Ruptured Pipes or from Reanalyzed Cracks in Large Pipes which Actuates ECCS 15.1.1-8 Amendment No. 26 (11/13)

DELETED 15.1.1-9 Amendment No. 26 (11/13)

TABLE 15.1.1-5 FUEL AND VESSEL DESIGN LIMITS Event Class Criteria Anticipated Specified acceptable fuel design limits (SAFDLs)

Operational Occurrences (AOOs) MDNBR 95/95 limit

  • Peak fuel centerline temperature melt temperature Peak system pressure RCS 2,750 psia MSS 1,100 psia Postulated Accidents Radiological doses within regulatory limits Peak system pressure RCS 2,750 psia or less than the value that will cause stresses to exceed the faulted condition stress limit MSS 1,100 psia 15.1.1-10 Amendment 26 (11/13)

TABLE 15.1.1-6 DESIGN BASIS EVENTS ANALYZED USING ALTERNATIVE SOURCE TERM (AST) METHODOLOGY 15.2.11 Stuck Open Main Steam Safety Valve 15.3.4 Reactor Coolant Pump Shaft Seizure 15.4.1 Loss of Coolant Accident (LOCA) 15.4.3 Fuel Handling Accident 15.4.4 Steam Generator Tube Rupture 15.4.5 Control Element Assembly Ejection 15.4.6 Steam System Piping Failures 15.1.1-11 Amendment No. 24 (06/10)

15.1.2 ACCIDENT PARAMETERS Nominal and steady state parameter values are given in Chapter 4.

15.1.2-1 Amendment 15 (1/97)

THIS PAGE LEFT INTENTIONALLY BLANK 15.1.2-2 Am. 11-7/92

15.1.3 TRIP SETTINGS The reactor is protected by the reactor protective system (Section 7.2) and engineered safety features system (Section 7.3). In case of abnormal transients, the reactor protective system is set to trip the reactor and prevent core damage.

The interval between the time at which the measured variable reaches the setpoint at the sensor and the time at which the trip breakers are open is defined as the trip delay time. An additional time delay of 0.5 second is assumed after the trip breakers open until the CEAs start to insert into the core. This is the time required for the magnetic flux of the CEA holding coils to decay sufficiently to release the CEAs.

A time delay of 0.5 seconds from trip breaker opening until the start of CEA insertion is the design basis used in the accident analyses.

As part of the CEDM functional acceptance test program, all mechanisms are tested to ensure conformance with the specified delay time requirement not to exceed 0.5 seconds.

All mechanisms tested at hot (610 F) or cold (ambient) conditions have delay times not exceeding 0.20 seconds.

The CEA insertion time assumed in the accident analyses was changed to 3.1 seconds at the time of the Cycle 3 reload (Technical Specification Amendment #32). This insertion time includes the interval between the initial movement of the CEA and the time at which the CEA has reached 90 percent insertion in the reactor core. The 3.1 seconds also includes the delay due to the decay of the magnetic flux of the CEA holding coils. Table 15.1.3-1 lists the reactor protective system trips, trip setpoints and uncertainties. Table 13.8.2-1 lists the reactor protective system response times.

15.1.3-1 Amendment No. 16, (1/98)

TABLE 15.1.3-1 REACTOR PROTECTIVE INSTRUMENTATION TRIP SETPOINT LIMITS (See Tech. Spec. Table 2.2-1) 15.1.3-2 Amendment No. 18, (04/01)

TABLE 15.1.3-1 REACTOR PROTECTIVE INSTRUMENTATION TRIP SETPOINT LIMITS (See Tech. Spec. Table 2.2-1) 15.1.3-3 Amendment No. 18, (04/01)

15.1.4 COMPUTER PROGRAMS Descriptions of the principal computer codes used in the Framatome (formerly AREVA) safety analyses EC292529 for EPU operation are provided below.

S-RELAP5 The S-RELAP5 code is a Framatome (formerly AREVA) modification of the RELAP5/MOD2 code. S- EC292529 RELAP5 was used for simulation of the transient system response to accidents. Control volumes and junctions are defined which describe all major components in the primary and secondary systems that are important for the event being analyzed. The S-RELAP5 hydrodynamic model is a two-dimensional, transient, two-fluid model for flow of a two-phase steam-water mixture. S-RELAP5 uses a six-equation model for the hydraulic solutions. These equations include two-phase continuity equations, two-phase momentum equations, and two-phase energy equations. The six-equation model also allows both non-homogeneous and non-equilibrium situations in reactor problems to be modeled.

RODEX2 RODEX2 (References 114 and 115) was developed to perform calculations for a fuel rod under normal operating conditions. The code incorporates models to describe the thermal-hydraulic condition of the fuel rod in a flow channel; the gas release, swelling, densification and cracking in the pellet; the gap conductance; the radial thermal conduction; the free volume and gas pressure internal to the fuel rod; the fuel and cladding deformations; and the cladding corrosion. RODEX2 has been extensively benchmarked; its predictive capabilities were correlated over a wide range of conditions applicable to light water reactor fuel conditions. For non-LOCA applications, RODEX2 was used to validate the gap conductance used in the analyses and to establish the fuel centerline melt LHR as a function of exposure.

A penalty to cover thermal conductivity degradation with burnup was applied as necessary, where applicable.

XCOBRA-IIIC The XCOBRA-IIIC code (Reference 116) is a steady-state thermal-hydraulics code that calculate the axial and radial flow and enthalpy distribution within assemblies and sub-channels for non-LOCA events.

When used in conjunction with core boundary conditions from the S-RELAP transient analysis and the HTP DNB correlation (Reference 110), XCOBRA-IIIC also calculates the corresponding MDNBR.

MDNBR calculations are performed in a two-step process. Calculations are first performed on a core-wide basis to calculate the axially varying flow and enthalpy distribution in the peak powered fuel assembly. Next, these flow and enthalpy boundary conditions are applied to a sub-channel model of the peak powered assembly to determine the local conditions for the calculation of MDNBR.

PRISM Framatome (formerly AREVA) PWR neutronics methodology uses the NRC-approved advanced nodal EC292529 simulator code system SAV95. SAV95 is built around the assembly spectrum/depletion code system MICBURN-3/CASMO-3 developed by Studsvik Scandpower and the three-dimensional reactor code PRISM. PRISM is a three-dimensional, coarse-mesh reactor simulator using two-group diffusion theory.

The simulator code models the reactor core in three-dimensional (X-Y-Z) geometry, and the reactor calculations can be performed in quarter- or full-core geometry. The code calculates the reactor core reactivity, nodal power distribution, pin power distribution, and in-core detector responses and can be used to simulate fuel shuffling, insertion, and discharge. A summary of the key validation results for SAV95 code system is presented in Reference 103.

15.1.4-1 Amendment No. 30 (05/20)

DELETED 15.1.4-2 Amendment No. 26 (11/13)

DELETED 15.1.4-3 Amendment No. 26 (11/13)

DELETED 15.1.4-4 Amendment No. 26 (11/13)

DELETED 15.1.4-5 Amendment No. 26 (11/13)

15.1.5 METHODOLOGY The approved methodology for evaluating non-LOCA transients is described in Reference 117. For each non-LOCA transient event analysis, the nodalization, chosen parameters, conservative input and sensitivity studies were reviewed for applicability to the EPU in compliance with the SER for non-LOCA topical report (Reference 117).

  • The nodalization used for the calculations supporting the EPU was specific to St. Lucie Unit 1 and was consistent with the Reference 117 methodology.
  • The parameters and equipment states were chosen to provide a conservative estimate of the challenge to the acceptance criteria. The biasing and assumptions for key input parameters were consistent with the approved Reference 117 methodology.
  • The S-RELAP5 code assessments in Reference 117 validated the ability of the code to predict the response of the primary and secondary systems to non-LOCA transients and accidents. No additional model sensitivity studies were needed for this application.

The approved methodology for performing DNB calculations using the XCOBRA-IIIC is described in Reference 108. The SER for the Reference 108 topical report states that the use of XCOBRA-IIIC is limited to the snapshot mode. Thus, MDNBR calculations were performed using a steady-state XCOBRA-IIIC model with core boundary conditions at the time of MDNBR from the S-RELAP5 transient analyses.

The Reference 109 topical report describes the method for performing statistical DNB analyses. Two conditions were noted in the SER for the Reference 109 methodology:

  • The methodology is approved only for CE type reactors which use protection systems as described in the Reference 109 topical report.
  • The methodology includes a statistical treatment of specific variables in the analysis; therefore, if additional variables are treated statistically Framatome (formerly AREVA) should re-evaluate the EC292529 methodology and document the changes in the treatment of the variables. The documentation will be maintained by Framatome (formerly AREVA) and will be available for NRC audit. EC292529 Both of these conditions are met since St. Lucie Unit 1 is a CE reactor, and no additional variables were used in the statistical DNB analysis.

The DNB calculations were performed utilizing the NRC-approved HTP CHF (or DNB) correlation described in the Reference 110 topical report. The fuel design parameters for Framatome (formerly AREVA) CE EC292529 14x14 HTP assembly are within the applicable range for the HTP CHF correlation. The St. Lucie Unit 1 EPU operating conditions are within the applicable range of coolant conditions for the HTP CHF correlation.

Reference 118 incorporates M5 properties into the S-RELAP5 based non-LOCA methodology (Reference 117).

UNIT 1 15.1.5-1 Amendment No. 30 (05/20)

15.1.5 METHODOLOGY (Continued)

CEA ejection analysis was performed to verify compliance with overpressure requirements and to determine the amount of fuel failures based on DNB and fuel centerline melt using the approved Reference 117 methodology. The approved methodology for calculating the enthalpy deposition for a CEA ejection accident is given in Reference 111.

The following calculations, related to post-LOCA and dose consequences, used methods based on basic engineering principles:

  • Post-LOCA Criticality - A mass balance was performed to determine the decrease in boron concentration in the sump as the pumped fluid in the containment sump became diluted due to retention of boron in the primary system. Conservative assumptions were made to maximize the dilution of the fluid in the containment sump. The boron concentration in the sump at the time of hot leg injection was compared to the critical boron concentration.
1. Atmospheric Steam Releases - An energy balance was performed to determine the steam releases to the atmosphere to cool the plant down to 212°F. The energy balance accounted for the heat contained in the primary and secondary fluid, the heat contained in the primary and secondary metal structures and decay heat. Steam release data are used in the radiological dose analyses.

15.1.5-2 Amendment No. 26 (11/13)

15.1.6 SAFETY ANALYSIS EVALUATION FOR THE ST. LUCIE UNIT 1 CORE 15.1.6.1 Introduction and Summary The results of the transient analyses indicate the current plant configuration satisfies licensing criteria with respect to LOCA-ECCS, setpoints or plant transients. The local power density and DNBR setpoint analyses verified that adequate margin to Technical Specification limits exists.

The cycle to cycle changes are evaluated by the fuel vendor and the results of the evaluation are reported in the Safety Analysis report. The topics addressed include neutronics parameters, thermal hydraulic design analysis, setpoint analysis and a review of the Chapter 15 events. The event review and results for the current cycle are presented in Section 15.1.6.8. The non-LOCA accident analyses performed by Framatome (formerly AREVA) for the EPU are documented in Reference112. The non-LOCA analyses EC292529 (Reference 112) support the M5 fuel rod design introduced in Cycle 26.

15.1.6.2 Calculational Methods and Input Parameters Code Description (for reference only; may not reflect current cycle analysis)

The transient analysis for St. Lucie Unit 1 EPU was performed using S-RELAP5 the Framatome (formerly EC292529 AREVA) Plant transient simulation model for pressurized water reactors. The simulation code models the behavior of pressurized water reactors under both normal and abnormal conditions by solving the transient conservation equations for the primary and secondary systems numerically. Core neutronics behavior is modeled using point kinetics, and the transient conduction equation is solved for fuel temperatures and heat fluxes. State variables such as flow, pressure, temperature, mass inventory, steam quality, heat flux, reactor power and reactivity are calculated during the transient. Where appropriate the Reactor Protection System (RPS) and control system are modeled to describe the transients. The departure from UNIT 1 15.1.6-1 Amendment No. 30 (05/20)

nucleate boiling ratio (110) is calculated for the hot channel during the transients using a hot channel model and the HTP correlation.

The system model used by S-RELAP5, models the reactor, both primary coolant loops, both steam generators and both steam lines. All major components (pressurizer, coolant pumps, and all major valves) are also modeled.

The trip functions used in the model consist of calculated trips set in conjunction with the limiting conditions of operation (LCO's) which protect the specified acceptable fuel design limits (SAFDL's) based on fuel centerline melt and departure from nucleate boiling (DNB) and trips based on single state variables.

The calculated trips for St. Lucie Unit 1 consist of an LPD trip and a thermal margin/low pressure (TM/LP) trip. The LPD trip protects against a power excursion exceeding the local power density limit of fuel centerline melt which is typically > 21 kW/ft. The trip is based on core power, Q, defined as the larger of the neutron flux power and the thermal power and on the peripheral axial shape index (ASI); which is defined as, PLOW - PUP ASI = --------------------

PLOW + PUP where PLOW and PUP are the output from the bottom and top ex-core flux sensors, respectively. Figure 15.1.6-2 shows the LPD trip function.

The TM/LP trip is based on the same auctioneered core power as the LPD trip. In addition, it also depends upon the ASI, and the inlet temperature TIN. The form of the trip function is, PVAR = 2061 A1 (ASI) QR1 (Q) + 15.85 TIN - 8950, where A1 and QR1 are shown in Figures 15.1.6-3 and 15.1.6-4, respectively. Pressurizer pressure is the system variable which is compared to the trip setpoint, PVAR. The TM/LP trip protects the core from the onset of DNB with at 15.1.6-2 Amendment No. 26 (11/13)

least a 95% probability as long as the plant is operated within the appropriate limiting conditions of operation (LCO) shown in Figure 15.1.6-5.

A set of ASI-dependent scram curves provides a conservative scram curve for each ASI.

Two basic kinds of axial power distributions were considered in the analysis. For transients and accidents where thermal margin (DNB) is the limiting factor, top peaked axial power distributions with delayed scram were limiting.

The pump response to a loss of power was modeled by setting the shaft rotation speed derivative equal to the pumping torque, divided by the effective inertia. The flow in each of the four cold legs was calculated based on the pump head and the required pressure drop. The effective inertia was then adjusted to provide a good fit to plant data.

15.1.6.3 Modeling Uncertainties The present plant transient analysis is basically a deterministic analysis. Thus, steady state measurement and instrumentation errors were taken into account in an additive fashion to ensure conservative calculations of MDNBR. The plant uncertainties related to initial conditions in the MDNBR calculations are:

Power + 0.3% for calorimetric error at 100% rated power Inlet coolant temperature + 3oF for deadband and measurement error RCS pressure - 40 psi for steady-state measurement errors Combined with design flow, these parameter uncertainties minimize the initial minimum DNBR. These uncertainties are not included in the plant system modeling explicitly, rather they are used to establish a conservative bound to the initial minimum DNBR.

The trip setpoints are based on Technical Specification Limits (47). Statistical verification of the calculated trips (LPD and TM/LP) is presented in the cycle specific Safety Analysis Report (SAR). These trip setpoints are modeled conservatively in the transient analysis to provide bounding simulations of the plant response.

The pressurizer control system was modeled in such a fashion that it could not ameliorate the effects of transients. The spray system was operable during DNBR transients while the heaters were off, thus tending to minimize DNBR. For pressurization transients, e.g. loss-of-electric load, the spray system and pressurizer relief valves were disabled.

Additional conservatisms in the pressurization transient include conservative modeling of the high pressure trip rated initial power plus uncertainty, a conservative choice of kinetics parameters, and a bottom-peaked core to delay termination of the transient as long as possible.

15.1.6-3 Amendment No. 26 (11/13)

15.1.6.4 Design Parameters Table 15.1.6-3 lists the Operating Parameters used in the EPU analysis.

The Framatome (formerly AREVA) fuel design parameters for St. Lucie Unit 1 are summarized in Table EC292529 15.1.6-4. Table 15.1.6-5 lists the bounding neutronics parameters, both for beginning of cycle (BOC) and end of cycle (EOC) conditions. The values used in the analysis for the moderator temperature coefficient and shutdown margin are consistent with the Technical Specification limits for these parameters. The radial peaking factor corresponds to the Technical Specification Limit of 1.65 allowing for a 6% uncertainty.

15.1.6.5 Deleted 15.1.6-4 Amendment No. 30 (05/20)

15.1.6.6 This section is deleted 15.1.6.7 This section is deleted.

15.1.6.8 Reload Safety Analysis Event Review and Analysis for current cycle.

15.1.6.8.1 Event Review and Analysis for the Current Cycle A review of the events in this section was performed to support operation with consideration of fuel design detail, current core physics parameters and changes in operational limits.

15.1.6-4a Amendment No. 26 (11/13)

The methodology of the review:

1) Assessed the relative margin of similar events to events acceptance criteria by examining the controlling parameters or event initiators.
2) Determined the bounding event of similar events based on these margins.
3) Examined the effect on the limiting event for cycle specific changes.
4) Determined whether the event was bounded by an accepted event analysis.
5) Reanalyzed the limiting event when it was not bounded by an accepted event analysis.

15.1.6.8.2 Summary of Results A summary of the results of the event review is presented in the cycle specific safety analysis report.

15.1.6-4b Amendment No. 22 (05/07)

DELETED 15.1.6-5 Amendment No. 26 (11/13)

Table 15.1.6-2 Deleted 15.1.6-6 Amendment No. 18, (04/01)

Table 15.1.6-3 St. Lucie Unit 1 Operating Parameters CORE Total Heat Output (MWt) 3020 Heat generated in fuel (%) 97.5 Pin Radial Peaking Factor 1.65 REACTOR COOLANT SYSTEM Minimum Coolant Flow Rate (gpm), measured minus uncertainty 375,000 Pressure (psia) 2250 Core Inlet Average Temperature (°F), maximum 551 STEAM GENERATORS Feedwater Temperature (°F) 436 Pressure (psia) 856 Steam Flow (Mlb/hr) @ 3020 MWt 13.00 15.1.6-7 Amendment No. 26 (11/13)

Table 15.1.6-4 Framatome (formerly AREVA) Fuel Design Parameters EC292529 For St. Lucie Unit 1 Fuel Pellet Diameter (in) 0.377 Outer Clad Diameter (in) 0.440 Inner Clad Diameter (in) 0.384 Active Fuel Length (in) 136.7 15.1.6-8 Amendment No. 30 (05/20)

TABLE 15.1.6-5 ST. LUCIE UNIT 1 BOUNDING NEUTRONICS CHARACTERISTICS AND SHUTDOWN MARGIN Parameter BOC EOC Moderator Temperature Coeffecient (TS limits) pcm/°F +7 ( 70% RTP) -32 (100%

+2 (> 70% RTP) RTP)

Doppler Temperature Coefficient, pcm/°F (bounding range) -0.80 -1.75 Delayed Neutron Fraction 0.006376 0.005069 U-238 Fission-to-Capture Ratio 0.699 Fraction of heat generated in the fuel 0.975 Minimum Required Shutdown Margin, pcm 3600 15.1.6-9 Amendment No. 26 (11/13)

Deleted 15.1.6-10 Amendment No. 19 (10/02)

Deleted 15.1.6-11 Amendment No. 19 (10/02)

TABLE 15.1.6-6

SUMMARY

OF ST. LUCIE UNIT 1 CHAPTER 15 EVENT REVIEW FOR CURRENT CYCLE SRP/UFSAR Cross Reference Event Description Disposition SRP UFSAR (Referenced to SRP) 15.1.1 15.2.10.2.1 Decrease in Feedwater Temperature Bounded by 15.1.3 15.1.2 15.2.10.2.2 Increase in Feedwater Flow Bounded by 15.1.3 15.1.3 15.2.11 Excess Load (Increase in Steam Flow)

Transient Response Bounded by AOR DNB Re-analyzed FCM Re-analyzed 15.1.4 15.2.11.3.2 Inadvertent Opening of a Steam Generator Relief Bounded by AOR or Safety Valve 15.1.5 15.4.6 Steam Line Break Accident Pre-Trip Transient Response Bounded by AOR Post-Trip Transient Response Bounded by AOR DNB Re-analyzed FCM Re-analyzed Mode 3 with SIAS Blocked Bounded by AOR Steam Release for Radioloqical Doses Bounded by AOR

--- 15.3.2 Minor Secondary System Pipe Breaks Bounded by 15.1.5 15.2.1 15.2.7 Loss of External Electrical Load and/or Turbine Stop Valve Closure Transient Response Bounded by AOR DNB Re-analyzed 15.2.2 15.2.7.2.2 Turbine Trip Bounded by 15.2.1 15.2.3 15.2.7.2.3 Loss of Condenser Vacuum Bounded by 15.2.1 15.2.4 15.2.7.2.4 Closure of MSIVs Bounded by 15.2.1 15.2.5 Steam Pressure Regulator Failure Not part of the licensing basis 15.2.6 15.2.9 Loss of Non-emergency AC Power to Station Bounded by 15.3.1 and Auxiliaries 15.2.7 15.2.7 15.2.8.1.1 Loss of Normal Feedwater Bounded by AOR 15.2.8 15.2.8.1.2 Feedwater System Pipe Breaks (Cooldown) Bounded by 15.1.5

--- 15.2.13 Station Blackout Bounded by AOR 15.3.1 15.2.5 Complete Loss of Forced Reactor Coolant Flow (4 pump coastdown)

Transient Response Bounded by AOR DNB Re-analyzed 15.3.2 --- Flow Controller Malfunction Not part of licensing basis UNIT 1 15.1.6-12 Amendment No. 27 (04/15)

TABLE 15.1.6-6

SUMMARY

OF ST. LUCIE UNIT 1 CHAPTER 15 EVENT REVIEW FOR CURRENT CYCLE (Cont.)

SRP/UFSAR Cross Reference Event Description Disposition SRP UFSAR (Referenced to SRP) 15.3.3 15.3.4 Seized Rotor Event Transient Response Bounded by AOR DNB Re-analyzed Steam releases for Radiological Doses Bounded by AOR 15.3.4 --- Reactor Coolant Pump Shaft Break Not part of licensing basis 15.4.1 15.2.1.2.1 Uncontrolled CEA Bank Withdrawal from a Bounded by AOR Subcritical or Low Power Startup Condition 15.4.2 15.2.1.2.2 Uncontrolled CEA Bank Withdrawal at PowerA Transient Response Bounded by AOR DNB Re-analyzed FCM Re-analyzed 15.4.3 15.2.3 CEA Misoperation (CEAD Only)

Transient Response Bounded by AOR DNB Re-analyzed FCM Re-analyzed 15.4.4 15.2.6 Startup of an Inactive Reactor Coolant Pump Part loop operation not Event allowed by Technical Specifications 15.4.5 --- Flow Controller Malfunction Causing an Increase Not part of licensing in BWR Flow Rate basis 15.4.6 15.2.4 CVCS Malfunction that Results in a Decrease in Bounded by AOR the Boron Concentration in the Reactor Coolant 15.4.7 15.3.3 Inadvertent Loading of a Fuel Assembly into the Bounded by UFSAR or Improper Position AOR 15.4.8 15.4.5 Spectrum of Control Rod Ejection Accidents Transient Response Bounded by AOR DNB Re-analyzed FCM Bounded by AOR Enthalpy Deposition Re-analyzed Steam releases for Radiological Doses Bounded by AOR 15.4.9 --- Spectrum of Rod Drop Accidents Not part of licensing basis 15.5.1 --- Inadvertent Operation of the ECCS Bounded by 15.5.2 15.5.2 --- CVCS Malfunction that Increases RCS Inventory Bounded by AOR UNIT 1 15.1.6-13 Amendment No. 27 (04/15)

TABLE 15.1.6-6

SUMMARY

OF ST. LUCIE UNIT 1 CHAPTER 15 EVENT REVIEW FOR CURRENT CYCLE (Cont.)

SRP/UFSAR Cross Reference Event Description Disposition SRP UFSAR (Referenced to SRP) 15.6.1 15.2.12.1 Inadvertent Opening of a Pressurizer Safety or Relief Valve Transient Response (SAFDL) Bounded by AOR Bounded by AOR Transient Response (Pressurizer overfill) Bounded by AOR DNB Re-analyzed 15.6.2 --- Radiological Consequences of the Failure of Small Not part of licensing basis Lines Carrying Primary Coolant Outside Containment 15.6.3 15.4.4 Radiological Consequences of a Steam Generator Bounded by AOR Tube Rupture 15.6.4 --- Radiological Consequences of a Main Steam Line Not part of licensing basis Failure Outside Containment (BWR) 15.6.5 15.3.1 Loss of Coolant Accident (Small Break) Re-analyzed 15.6.5 15.4.1 Loss of Coolant Accident (Large Break) I ECCS Re-analyzed Analysis Transient Post-LOCA Criticality Time-to-criticality 10 hr 15.7.1 15.4.2 Waste Gas Decay Tank Leakage or Rupture Bounded by AOR 15.7.2 --- Radiological Liquid Waste System Leak or Failure Deleted (Release to Atmosphere) 15.7.3 --- Postulated Radioactive Release Due to Liquid Not part of licensing basis Tank Failure 15.7.4 15.4.3 Fuel Handling Accident Bounded by AOR 15.7.5 --- Spectrum of Cask Drop Accidents Not part of licensing basis

--- 15.2.2 Transients Resulting from the Malfunction of One Steam Generator Asymmetric Events:

Loss of Load (Single MSIV Closure)

Transient Response Bounded by AOR DNB Re-analyzed Excess Load Bounded by Loss of Load (Single MSIV Closure)

Loss of Feedwater Flow Bounded by Loss of Load (Single MSIV Closure)

Excess Feedwater Bounded by Loss of Load (Single MSIV Closure) 10.5 Loss of Normal Feedwater Bounded by AOR 10.5 Feedwater System Pipe Breaks (Heatup) Bounded by AOR UNIT 1 15.1.6-13a Amendment No. 27 (04/15)

FIGURE 15.1.6-1 DELETED Amendment No. 26 (11/13)

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Figure 15.1.6-6 DELETED Amendment No. 26 (11/13)

Figure 15.1.6-7 DELETED Amendment No. 26 (11/13)

Figure 15.1.6-8 DELETED Amendment No. 26 (11/13)

Figure 15.1.6-9 DELETED Amendment No. 26 (11/13)

15.1.7 INSTALLATION OF REPLACEMENT STEAM GENERATORS As a result of tube degradation, Florida Power & Light Company replaced the original steam generators (OSGs) with two replacement steam generators (RSGs) manufactured by Babcock & Wilcox, Canada.

A comparison of the OSGs with the RSGs is made in Table 15.1.7-1.

The primary side, nozzle-to-nozzle pressure drop of the RSGs is approximately 99% of the OSGs. The unplugged heat transfer capacity of the RSGs is only one percent greater than that of the unplugged OSGs. Consequently, the primary system response to upset conditions with the RSGs will be equivalent to the original plant response.

Both steam generators are feed ring types with similar secondary mass inventories at zero and full power.

The circulation ratio of the RSGs (4.3) is similar to that of the OSGs (4.0). Therefore, although the RSGs will experience less level shrink and swell than will the OSGs, the secondary side response of the RSGs to upset conditions will be equivalent to that of the OSGs.

Since the primary and secondary side response characteristics of the RSGs are equivalent to those of the OSGs, the sequence of events and thermal-hydraulic response to accidents with the RSGs are equivalent to those with the OSGs. Equipment important to safety will actuate in the same way and operate under the same conditions (i.e., within its operating limits) with the RSGs as with the OSGs.

Consequently, the effect of SG replacement on the accident analyses is minor. Nonetheless, each accident analysis in Chapter 15 was evaluated to confirm that the analysis is bounding with the RSGs.

If not, it was determined that the plant response with the RSGs would meet NRC-approved acceptance criteria.

The accident analyses performed for the EPU used parameters consistent with the RSGs.

15.1.7-1 Amendment No. 26 (11/13)

TABLE 15.1.7-1 COMPARISON OF STEAM GENERATORS AT CONDITIONS FOR 2700 MWT*

PARAMETER REPLACEMENT STEAM ORIGINAL STEAM GENERATOR GENERATOR Primary Side Volume: No Tubes Plugged 1698 ft3 1646 ft3 Secondary Side Mass: @ 0% Full Power 208041 lb 223102 lb

@ Full Power 129482 lb 137970 lb Full Power Steam Flow 5900000 lb/hr 5900000 lb/hr Primary Side Non-recoverable Pressure @70,000,000 lb/hr** @70,000,000 lb/hr Drop 4 Pump Flow (no plugs or sleeves) 40.4 psia (Ref 2) 40.7 psia (Ref 2) 4 Pump Flow (18% tubes plugged) 58.3 psia (Ref 2) N/A Primary Side Design Pressure 2500 psia 2500 psia Secondary Side Design Pressure 1000 psia 1000 psia Primary Side Design Temperature 650°F 650°F Secondary Side Design Temperature 550°F 530°F Primary Side Operating Pressure 2250 psia 2250 psia Steam Outlet Conditions: Pressure 885 psia** 885 psia Maximum Carryover 0.1 % 0.2%

Feedwater Temperature @ Full Power 435°F* 435°F Heat Transfer Rate @ Full Power 4.63E + 09 Btu/hr 4.623E + 09 Btu/hr Full Power Circulation Ratio 4.3 4.0 Flow Restrictor Flow Area 530.9 in2 no credit taken Steam Outlet Nozzle I.D. 34 in 34 in Primary Side Heat Transfer Surface Area: 82424.3 ft2 78986 ft2 No Tubes Plugged Secondary Side Heat Transfer Surface Area: 93706.7 ft2 90647 ft2 No Tubes Plugged

  • Note: This table is for historical purposes. The conditions differ from those of the EPU.
    • Note: This evaluation is based on 401,000 gpm primary flow. Per reference, the expected best estimate flow for Cycle 15 is 413,508 gpm producing a steam pressure of 887.9 psia at nozzle (downstream of flow restrictor) and 893 psia drum. These conditions are calculated with a feedwater return temperature of 432.4°F.

15.1.7-2 Amendment No. 26 (11/13)

TABLE 15.1.7-1 (continued)

COMPARISON OF STEAM GENERATORS AT CONDITIONS FOR 2700 MWT*

REPLACEMENT ORIGINAL STEAM PARAMETER STEAM GENERATORS GENERATORS Number of Tubes 8523 8519 Tube O.D.: Nominal 0.75 in 0.75 in Upper Tolerance +0.000 in +0.0 in Lower Tolerance -0.005 in -0.0075 in Tube Wall Thickness: Nominal 0.045 in 0.048 in Tolerance +/-0.004 in +/-0.005 Tube Material:SB-163, Code Case N-20 Alloy 690 Alloy 600 Tube Thermal Conductivity: @ 400F 8.92 Btu/ft-hr-F 10.1 Btu/ft-hr-F

@ 500F 9.54 Btu/ft-hr-F 10.6 Btu/ft-hr-F

@ 600F 10.167Btu/ft-hr-F 11.1 Btu/ft-hr-F Tube Pitch 1.00 in 1.00 in Tube Min. Strength (per ASME Code):

Yield 40 Ksi 35 Ksi Tensile 80 Ksi 80 Ksi 15.1.7-3 Amendment No. 26 (11/13)

15.1.8 INSTALLATION OF REPLACEMENT PRESSURIZER As a result of increased susceptibility of primary water stress corrosion cracking (PWSCC) of Alloy 600 and comparable weld material, the original pressurizer (OPZR) at St. Lucie, Unit 1 was replaced with a replacement pressurizer (RPZR) manufactured by Framatome ANP, SAS of Paris, France.

The pressurizer is a safety-related component and was manufactured in compliance with the requirements of 10 CFR 50 Appendix B. It was designed, fabricated, and analyzed as a direct replacement for the existing pressurizer. A comparison of the OPZR and RPZR design data is presented in Table 15.1.8-1. This table illustrates the physical and thermal-hydraulic similarity between the replacement and original designs.

The RPZR occupies the same physical envelope as the OPZR. There are no changes to interfaces with the reactor coolant, or to major component supports or piping supports. The RPZR design enhancements compared to the OPZR design include (1) large bore nozzles integral with the upper and lower head forgings, (2) use of Alloy 690 and exclusion of all Alloy 600 related materials, and (3) a more reliable heater pressure boundary.

Given the similarities of the pressurizers, the event sequences and thermal-hydraulic responses are not affected by the pressurizer replacement. Consequently, the pressurizer replacement causes no significant effect upon the normal and upset operations of the St. Lucie Unit 1 power plant. Nonetheless, each accident analysis in Chapter 15 of the UFSAR was evaluated in Reference 1 to confirm that the analysis of record remains applicable and the relevant acceptance criteria are met.

The accident analyses performed for the EPU used parameters consistent with the RPZR.

Reference 1 - AREVA Report 77-5044551-02, Replacement Pressurizer Report for FPL St. Lucie Unit 1.

15.1.8-1 Amendment No. 26 (11/13)

TABLE 15.1.8-1 COMPARISON OF PRESSURIZERS PARAMETER UNITS RPZR OPZR Design Pressure psig 2485 2485 Design Temperature °F 700 700 Normal Operating Pressure psig 2235 2235 Normal Operating Temperature °F 653 653 Nominal Internal Free Volume ft3 1500 1500 Calculated Internal Free Volume ft3 1528 1512 Normal Operating Water Volume ft3 600<V<800 600<V<800 Normal Steam Volume, Full Power ft3 700<V<900 700<V<900 Spray Flow, Maximum gpm 375 375 Spray Flow, Continuous gpm 1.5 1.5 Surge Line Nozzle, nom in. 12" Sch 160 12" Sch 160 Safety Valve Nozzle (3), ID in. 3" flanged 3" flanged Relief Valve Nozzle (1), 1D in. 4" Sch 160 4" Sch 160 Spray Nozzle (1), nom. in. 4" Sch 160 4" Sch 160 Level Inst. Nozzle (4), nom. in. 1" Sch 160 1" Sch 160 Temp. Inst. Nozzle (2), nom. in. 1" Sch 160 1" Sch 160 Pressure Inst. Nozzle (2), nom. in. 1" Sch 160 1" Sch 160 Spray Nozzle dP (max flow rate at 550°F) psid 15 15 Spray Nozzle Angle degree 30 30 Hydrostatic Test Pressure psia 3125 3125 Max Heatup °F/h 100 100 Cooldown Rate °F/h 200 200 Material Vessel - SA-508, Gr 3, Cl. 2 SA-533, Gr B, Cl.1 Cladding, Shell & Upper Head - 308/309 SS 304 SS Cladding, Lower Head - 308/309 SS Ni-Cr-Fe Dimensions Overall Length in. 443.38* 441.375 Outside Diameter in. 106.56 106.5 Inside Diameter in. 96.56 96.25 Cladding thickness (minimum) in. 0.2 0.125 Surge Diffuser ID in. 11.938 11.938 Surge Diffuser Screen Thickness in. 0.375 0.375 No. of Holes in Screen - 792 792 Diameter of Holes in Screen in. 0.5 0.5 Manway Dia. in. 16 16 Weight Total Dry Weight (inc. heaters) lbm. 201,200 194,500 Total Flooded Weight (inc. heaters) lbm. 294,200 287,500 Pressurizer Heaters Number Installed - 120 120 Heater Design Pressure psia 2500 2500 Heater Design Temperture F 800 775 Heater Capacity, each kW 13.3 13.3 Sheath OD in. 0.875 0.855 Sheath Metal Thickness in. 0.12 0.12 Heated Length in. 51.07 53 Nozzles Upper Level Nozzle Elevation in. 396.5 396.5 Lower Level Nozzle Elevation in. 36.5 36.5 Level Nozzle Span in. 360 360

  • Includes a 2" extension on the spray nozzle that will be partially or totally removed prior to installation.

15.1.8-2 Amendment No. 21 (12/05)

15.2 ANTICIPATED OPERATIONAL OCCURRENCES (CLASS 1 ACCIDENTS)

This class of accidents can be split into two groups. The first group is those anticipated operational occurrences (AOOS) for which intervention of the RPS is necessary to prevent exceeding acceptable limits:

15.2.1 Control Element Assembly Withdrawal(1) 15.2.2 Transients Resulting from the Malfunction of One Steam Generator(3) 15.2.4 Boron Dilution 15.2.5 Loss of Coolant Flow(2) 15.2.6 Startup of an Inactive Reactor Coolant Pump 15.2.7 Loss of Load 15.2.8 Loss of Feedwater Flow 15.2.9 Loss of Off-site AC Power(2) 15.2.10 Excess Heat Removal due to Feedwater Malfunction 15.2.11 Excess Load 15.2.12 Reactor Coolant System Depressurization 15.2.13 Station Blackout Analysis 15.2.14 Increase in Reactor Coolant Inventory 15.2.14.1 Inadvertent Operation of ECCS 15.2.14.2 CVCS Malfunction The events in this category were analyzed for EPU operation (3020 MWth) to determine that acceptable limits on DNBR, FCM, Reactor Coolant System (RCS) upset pressure, and guidelines established for design basis accidents will not be exceeded. Each of the event writeups in the section identifies which criterion the event in question addresses. Protection against violating these limits will continue to be assured by the Reactor Protection System (RPS) Limiting Safety System Settings (LSSS) setpoints. The setpoints have been modified (as necessary) to include changes necessitated by the results of the EPU analyses of these events. The methodology used to generate the Limiting Safety System Settings (LSSS) for the TM/LP and ASI RPS trips is discussed in Reference 109.

For those events in this section where DNBR or FCM values were calculated and quoted, the calculations were performed using the nominal values of key NSSS parameters listed in Table 15.1.6-

3. Uncertainties were accounted for in determining the values of DNBR or FCM by applying appropriate values of aggregate uncertainties to the limiting rod power. For those events analyzed to determine that the RCS upset pressure limit or guidelines established for design basis accidents are not exceeded, the methods used are the same as previously reported in reload licensing submittals.

Effects of NSSS parameter uncertainties on these limits are not assessed statistically.

1 Requires high power and variable high power trip; event is discussed in the second group.

2 Requires low flow trip; event is discussed in the second group.

3 Requires P across the steam generator trip; event is discussed in the second group.

15.2.1-1 Amendment No. 26 (11/13)

Instead, applicable uncertainties are assumed to occur simultaneously in the most adverse direction.

When values of the NSSS parameter used in evaluation of the RCS pressure and dose limits differ from those given in Table 15.1.6-3, they will be specifically noted.

The second group of AOOs is those for which RPS trips and/or sufficient initial steady state thermal margin maintained by the LCOs, are necessary to prevent exceeding the acceptable limits:

15.2.1 Control Element Assembly Withdrawal 15.2.2 Transients Resulting from the Malfunction of One Steam Generator 15.2.3 Full Length CEA Drop 15.2.5 Loss of Coolant Flow 15.2.9 Loss of Off-site AC Power 15.2.13 Loss of On-site and Off-site AC Power (Station Blackout)

The events in this category were analyzed for operation to determine the initial margins that must be maintained by the Technical Specification LCO limits such that acceptable DNBR and upset pressure limits will not be exceeded during any of these events. The initial margin required to prevent the appropriate limits from being exceeded for any of these events was determined by analyzing them using the initial conditions specified in Table 15.1.6-3; see Table 15.2.13-1 for Station Blackout event initial conditions. These conditions were chosen to assure that sufficient initial overpower margin is available at the initiation of the most limiting AOO in this category. The method of generating Limiting Conditions for Operation (LCO) is discussed in Reference109.

The results of the analyses are provided in the following sections.

15.2.1 UNCONTROLLED CEA WITHDRAWAL 15.2.1.1 Identification of Causes The CEA withdrawal event is analyzed to determine the initial margins that must be maintained by the LCOs such that in conjunction with the RPS (Variable High Power Trip) the DNBR and fuel centerline melt (FCM) design limits will not be exceeded.

The withdrawal of CEAs adds reactivity to the core causing the core power and heat flux to increase.

Since the heat extraction from the steam generators remains relatively constant there will be an increase in reactor coolant temperature. While a continuous withdrawal of CEAs is considered unlikely, the reactor protective system is designed to terminate any such transient before fuel thermal design limits or system overpressure limits are reached.

15.2.1-2 Amendment No. 26 (11/13)

An additional consideration for the withdrawal of CEAs from subcritical or low reactor power is that the normal reactor feedback mechanisms, moderator feedback and Doppler feedback, are delayed until the power generation in the core is large enough to effect changes in the fuel and moderator temperatures.

A continuous withdrawal of CEAs could result from a malfunction in the reactor regulating system or control element drive system. CEA withdrawal accidents can cover a range of initial power conditions, from subcritical conditions existing during startup to normal full power operating conditions.

Startup of the reactor involves a planned sequence of events during which certain CEA groups are withdrawn at a controlled rate and in a prescribed order to increase the core reactivity gradually from a subcritical to a critical state. To ensure that rapid shutdown by CEAs is always possible when the reactor is critical or near critical, administrative procedures and interlocks require that groups of CEAs be withdrawn in a specified sequence. The withdrawal sequence, and the group power dependent insertion limits, ensure there is adequate shutdown margin at the hot standby condition with the most reactive CEA of the shutdown group assumed to remain in the fully withdrawn position.

Once the shutdown groups have been withdrawn, the regulating groups are withdrawn as necessary to achieve criticality and to meet power demand. Regulating CEA groups are withdrawn in a programmed sequence as discussed in Section 7.7.1.1.

The CEA Control System contains design features that ensure the following actions: EC291158 a) Insertion of the regulating CEAs before the shutdown CEAs are inserted; b) Simultaneous withdrawal of no more than two groups of CEAs; c) Proper sequential withdrawal of CEAs.

No single equipment or operator failure will cause the CEA Control System to improperly carry out the EC291158 above listed actions to the extent that safety limits are reached. For additional discussion of the CEA Control System see Section 7.7.1.1.

The CEA withdrawal event is classified as one for which the acceptable DNBR and centerline melt limits are not violated by virtue of sufficient initial steady state thermal margin provided by the DNBR and Linear Heat Rate (LHR) related Limiting Conditions for Operations (LCO's). Depending on the initial conditions and the reactivity insertion rate associated with the CEA withdrawal, either the variable high power level or Thermal Margin/Low Pressure (TM/LP) trip, in conjunction with the initial steady state LCO's prevents DNBR limits from being exceeded. An approach to the FCM limit is terminated by either the variable high power level trip or the local power density (LPD) trip. The analysis only took credit for the variable high power trip to determine the required initial overpower margin for DNBR and FCM.

15.2.1-3 Amendment No. 30 (05/20)

The zero power case was analyzed to demonstrate that acceptable DNBR and centerline melt limits are not exceeded. For the zero power case, a reactor trip, initiated by the variable high power trip at 25% (15% + 10% uncertainty) of rated thermal power, was assumed in the analysis.

The key parameters for the cases analyzed are reactivity insertion rate due to rod motion, moderator temperature feedback effects, and axial power distribution. The input values selected maximize the power increase and thus the margin degradation.

If the rate of change of neutron flux is in excess of a set rate, the rate-of-change-of-power trip and a CEA-withdrawal prohibit will become operative and an alarm will be actuated in the control room. The CEA withdrawal prohibit is operative at power levels above 10-4 percent of rated power and will be actuated if the rate is greater than approximately 1.5 decades per minute. When the power is between 10-4 percent and 15 percent of full power, a reactor trip will be initiated automatically if CEA withdrawal results in a rate of change of the neutron flux greater than approximately 2.49 decades per minute (see Section 7.2). In the case of a reactivity addition at a slower rate, such that the high rate-of-change of power setpoint is not exceeded, a reactor trip will be actuated by high power level, high pressurizer pressure, thermal margin/low pressure or low steam generator water level.

In addition to the high pressurizer pressure trip at 2400 psia, protection against over pressurization of the reactor coolant system is provided by the pressurizer power operated relief valves, which are set to open at 2400 psia, and by ASME code design safety valves which are set to open at 2500 psia.

15.2.1.2 Analysis of Effects and Consequences(1) 15.2.1.2.1 Uncontrolled CEA Withdrawal from a Subcritical or Low Power Startup Condition This event is initiated by a continuous CEA withdrawal that could result from: (1) operator error and (2) a malfunction in the reactor regulating system or control element drive system. The event is initiated from a Mode 2 startup (critical) condition at zero power. The event is characterized by a large and rapid positive reactivity insertion that can challenge the DNB and FCM SAFDLs and RCS pressure. Reactor trip occurs on a VHPT signal; however, the power excursion is mitigated by Doppler reactivity feedback prior to reactor trip.

Detailed analyses were performed with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References 117 and 108). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures) and produce an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110). A hot-spot model in S-RELAP5 was used to calculate the fuel centerline temperature during the transient.

The input parameters and biasing were consistent with or conservative relative to the approved methodology.

  • Initial Conditions - HZP initial conditions, maximum HZP core inlet temperature and minimum TS RCS flow rate for four-pump operation were assumed in order to maximize the challenge to DNB and FCM SAFDLs.

Additional cases from HZP were run for evaluation of peak RCS pressure. Maximum HZP core inlet temperature and minimum TS RCS flow rate were used for these calculations.

  • Reactivity Feedback - BOC and EOC parameters were evaluated. TS/COLR MTC values at HZP were assumed. Scram worth was conservatively set to the minimum TS/COLR shutdown margin.

15.2.1-4 Amendment No. 26 (11/13)

  • Reactor Protection System Trips and Delays - The reactor protection system trip setpoints and response times were conservatively biased to delay the actuation of the trip function. In addition, control rod insertion into the core is delayed to account for the CEA holding coil delay time. For conservatism, the high rate-of-change trip was not credited in the analysis of this event initiated from HZP. The existence of this trip, however, makes initiating this event from subcritical modes of operation inconsequential.
  • Pressurizer Pressure Control - Pressurizer pressure control (i.e., pressurizer sprays, heaters and PORVs) parameters and equipment states were conservatively treated for both the SAFDL analysis and the RCS overpressure analysis. For the SAFDL cases, the pressurizer pressure control parameters and equipment states were selected to reduce the primary system pressure which provided a conservative calculation of the MDNBR during the transient. For the RCS overpressure cases, the pressurizer pressure control parameters and equipment states were selected to maximize the primary system pressure which provided a conservative calculation of the peak RCS pressure during the transient.
  • CEA Withdrawal Characteristics - A bounding differential worth was assumed together with a maximum CEA withdrawal speed. The CEA was conservatively assumed to continuously withdraw beyond the time of reactor trip.
  • Gap Conductance - Gap conductance was set to a conservative value, consistent with the time-in-cycle for the reactivity coefficients, to maximize the heat flux through the cladding and minimize the negative reactivity inserted due to Doppler feedback.

The principally challenged acceptance criteria for this event are:

This criterion is met by assuring that the minimum calculated DNBR is not less than the 95/95 DNB correlation limit. Additionally, fuel centerline melt is demonstrated to be precluded in the most adverse location in the core.

This criterion is met by assuring that the peak RCS pressure is less than the acceptance criterion of 2,750 psia, i.e., 110% of the design pressure.

The calculated MDNBR is above the 95/95 CHF correlation limit. The peak fuel centerline temperature was calculated to be less than the fuel centerline melt limit. The peak RCS pressure for this event is bounded by the loss of external load event (Section 15.2.7).

(1) Obtained from the non-LOCA EPU analysis, Sections 3.17 and 3.18.

15.2.1-4a Amendment No. 26 (11/13)

15.2.1.2.2 Uncontrolled CEA Withdrawal at Power An inadvertent CEA bank withdrawal at power could be caused by two potential initiators: (1) operator error, or (2) a malfunction of either the CEA drive mechanism or of the CEDM which results in an uncontrolled, continuous CEA bank withdrawal. The positive reactivity addition from the CEA withdrawal results in a power transient. Due to relatively constant heat extraction from the steam generators during the event, the increase in reactor power produces an increase in reactor coolant temperatures and core heat flux, thereby decreasing the margin to the DNB and FCM SAFDLs, and the RCS overpressure limit.

While a continuous CEA withdrawal is considered unlikely, the reactor protective system is designed to terminate any such transient before fuel thermal design limits are reached. Protection against violation of the SAFDLs is provided primarily by the VHP, TM/LP, LPD and HPP trips. No single active failure will affect the analysis for this event.

Detailed analyses were performed with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References117 and 108). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures) and produce an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110).

A spectrum of positive insertion rates is possible from very slow to fast, limited only by bank worth and maximum drive speed. Two reactivity feedback matrices of cases are analyzed: One for most-positive reactivity feedback (most-positive MTC and least-negative Doppler coefficient), and the other for most-negative feedback (most-negative MTC and most-negative Doppler coefficient). A range of initial reactor power levels were analyzed for both the SAFDL challenge and the RCS pressure challenge.

For both reactivity feedback matrices of cases, bounding reactivity insertion rate ranges are considered. The lower bound of the reactivity insertion rate range analyzed also bounds the reactivity insertion rate corresponding to Mode 1 Boron Dilution.

The input parameters and biasing were consistent with or conservative to the approved methodology.

  • Initial Conditions - For evaluation of the SAFDLs, power levels ranging from 25% to HFP were evaluated with a maximum core inlet temperature and TS minimum RCS flow in order to ensure that the limiting initial conditions relative to the challenge to the SAFDL limits were identified.

For evaluation of peak RCS pressure, power levels ranging from 25% to HFP were analyzed. Cases were also analyzed with the initial pressurizer pressure, cold leg temperature and RCS flow rate biased to account for operating ranges and measurement uncertainties to ensure that the limiting CEA withdrawal RCS pressure case was bounded.

  • Reactivity Feedback - The reactivity feedback coefficients were biased according to the approved methodology. Both BOC and EOC kinetics were analyzed to assess the impact of moderator and Doppler feedback (Table 15.2.1-1). The moderator temperature coefficients were assumed to be +7 pcm/°F for the BOC cases (this value is bounding of the most positive TS value) and -32 pcm/°F for the EOC cases (this value is equal to the most negative TS value). Doppler reactivity was biased to bound a range of feedback from BOC to EOC. Scram worth was conservatively set to a minimum value appropriate for the initial power level being analyzed.
  • Reactor Protection System Trips and Delays - This event is primarily protected by the TM/LP, VHP and HPP RPS trips. The reactor protection system trip setpoints and response times were conservatively biased to delay the actuation of the trip function. In addition, control rod insertion is delayed to account for CEA holding coil delay time.

15.2.1-5 Amendment No. 26 (11/13)

Pressurizer Pressure Control - Pressurizer pressure control (i.e., pressurizer sprays, heaters and PORVs) parameters and equipment states were conservatively treated for both the SAFDL analysis and the RCS pressure analysis. For the SAFDL cases, the pressurizer pressure control parameters and equipment states were selected to reduce the primary system pressure which provided a conservative calculation of the minimum departure from nucleate boiling ratio (MDNBR) during the transient. For the RCS pressure cases, the pressurizer pressure control parameters and equipment states were selected to maximize the primary system pressure, which provided a conservative calculation of the peak RCS pressure during the transient.

  • CEA Withdrawal Characteristics - A bounding differential worth was assumed together with a maximum CEA withdrawal speed. As a conservative analytical assumption, withdrawal of the CEA was not terminated at reactor trip.
  • Gap Conductance - Gap conductance was set to conservative values consistent with the time-in-cycle for the reactivity coefficients.

This event is classified as an AOO event and, consistent with the current licensing basis, the principally challenged acceptance criteria are:

This criterion is met by assuring that the minimum calculated DNBR is not less than the 95/95 DNB correlation limit. Additionally, the fuel centerline melt criterion is met by demonstrating that the peak LHR is less than the LHR limit corresponding to the fuel centerline melt temperature.

This criterion is met by assuring that the peak RCS pressure is less than the acceptance criterion of 2,750 psia, i.e., 110% of the design pressure.

The results of the analysis demonstrated that the DNB SAFDL limit is most challenged at EOC HFP initial conditions. The sequence of events is given in Table 15.2.1-2. Plots of key system parameters are shown in Figures 15.2.1-1 to 15.2.1-9. The limiting MDNBR was calculated to be above the 95/95 CHF correlation limit. The peak LHR does not significantly challenge the LHR limit for this event.

Results of the RCS pressure analysis demonstrated that peak RCS pressure increases with increasing core power, with the overall limiting initial condition being HFP with BOC reactivity feedback. The peak RCS pressure was less than the acceptance criterion and was bounded by the loss of external load event (Section 15.2.7).

The analysis also demonstrates that this event does not challenge the pressurizer level for overfill.

15.2.1-5a Amendment No. 26 (11/13)

Table 15.2.1-1 Kinetics Parameters for the CEA Withdrawal Event Parameter Value EOC Scram Reactivity Minimum HFP Minimum HFP Moderator Temperature Coefficient +7 pcm/°F -32 pcm/°F Doppler Reactivity Coefficient -0.80 pcm/°F -1.75 pcm/°F 15.2.1-6 Amendment No. 26 (11/13)

Table 15.2.1-2 Event Table for CEA Withdrawal at Power Event Time (seconds)

Bank withdrawal begins 0.0 PORV opens 31.8 Pressure reaches TM/LP trip setpoint 89.0 Core power reaches VHP trip setpoint (NI signal) 89.6 Reactor scram TM/LP (including trip response delay) 89.9 Maximum core power 89.8 Maximum heat flux power 90.0 MDNBR 90.0 CEA insertion begins 90.4 Pressurizer pressure peaks 91.4 15.2.1-7 Amendment No. 26 (11/13)

Reactor Power- CEA Withdrawal at Power 150 100 4~

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~

0:::

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Q) 3:

0 a..

50

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0 0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTOR POWER- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-1

Total Core Heat Flux Power- CEA Withdrawal at Power

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~ 1000 0 ~~~~~~--~~--~~--~~--~~--~~--~~~--~~~

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-2

Pressurizer Pressure - CEA Withdrawal at Power 2300

~ 2200

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s

~

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a... 2100 2000 1900 ~~~--~~--~~--~~--~~~--~~--~~--~~~~~~

0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 PRESSURIZED PRESSURE - CEA WITHDRAWAL AT POWER FIGURE 15.2.1-3

Pressurizer Liquid Level - CEA Withdrawal at Power 90

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0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 PRESSURIZED LIQUID LEVEL- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-4

RCS Loop Temperatures- CEA Withdrawal at Power 640 620 G:' 600 o.._

e Avg . Th ot

........... Avg . Tcold 560 540 0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-5

RCS Total Loop Flow Rate- CEA Withdrawal at Power 50000 ~~~~--~~ ~ --~-~~ ~~~--~~~--~-~ ~ ~--~~~~--~~1--~~

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0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-6

Margin to TM/LP RPS Trip - CEA Withdrawal at Power 500 400

"(/) 300

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a_

--2

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-100

- 200 ~~~--~~--~~~--~~--~~~--~~--~~~--~~~

0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 MARGIN TO TM/LP RPS TRIP- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-7

Margin to VHP RPS Trip - CEA Withdrawal at Power 10

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0 c

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m

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0 ~~~--~~~~~~--~~~~~~--~~~--~~~~~~

0 10 20 30 40 50 60 70 80 90 100 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 MARGIN TO VHP RPS TRIP- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-8

Reactivity Feedback- CEA Withdrawal at Power 5.0

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK- CEA WITHDRAWAL AT POWER FIGURE 15.2.1-9

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 DNBR- CEA WITHDRAWAL FIGURE 15.2.1-10

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTIVITY- CEA WITHDRAWAL FIGURE 15.2.1-11

15.2.2 TRANSIENTS RESULTING FROM THE MALFUNCTION OF ONE STEAM GENERATOR 15.2.2.1 Identification of Causes The transients resulting from the malfunction of one steam generator are analyzed to determine the initial margins that must be maintained by the LCO such that in conjunction with the RPS (asymmetric steam generator protective trip) the DNBR and fuel centerline melt design limits are not exceeded.

The four events which affect a single generator are identified below:

a) Loss of Load to One Steam Generator (LL/ISG) b) Excess Load to One Steam Generator (EL/ISG) c) Loss of Feedwater to One Steam Generator (LF/ISG) d) Excess Feedwater to One Steam Generator (EF/ISG)

Of the four events described above, it has been determined that the Loss of Load to One Steam Generator (LL/ISG) transient is the limiting asymmetric event. Hence, only the results of this transient are reported.

The event is initiated by the inadvertent closure of a single main steam isolation valve. Upon the loss of load to the single steam generator, its pressure and temperature increase to the opening pressure of the secondary safety valves. The intact steam generator "picks up" the lost load, which causes its temperature and pressure to decrease, thus causing the core average inlet temperature to decrease and enhancing the asymmetry in the reactor inlet temperature. In the presence of a negative moderator temperature coefficient this causes an increase in core power and radial peaking. Resultant core temperature asymmetries can then potentially cause an approach to DNB and CDM limits. The Asymmetric Steam Generator Protective Trip (ASGPT) serves as the primary means of mitigating this transient. Additional protection is present from the steam generator level trip.

15.2.2.2 Analysis of Effects and Consequences Detailed analyses were performed for the Loss of Load to One Steam Generator event with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References 117 and 108). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures). The core fluid boundary conditions, average rod surface heat flux, and a bounding radial peaking augmentation factor were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110).

Due to the asymmetric nature of this event, it is analyzed with a sectorized core model that simulates the asymmetric aspects of the event.

The input parameters and biasing (Table 15.2.2-1) were consistent with the approved methodology.

  • Initial Conditions - This event was assumed to initiate from HFP conditions with a maximum core inlet temperature and TS minimum RCS flow. This set of conditions minimizes the initial margin to DNB.

15.2.2-1 Amendment No. 26 (11/13)

  • Core and Reactor Vessel Model - A split core is used to simulate the asymmetric thermal-hydraulic and reactivity feedback effects that can occur during this event. One core sector is used to model the core sector which is directly impacted by the affected SG and another core sector is used to model the sector which is not directly impacted. Mixing in the downcomer, lower plenum and cross-flow in the core region is conservatively modeled.
  • Reactivity Feedback - The reactivity feedback coefficients were biased according to the approved methodology. The coolant temperature from the affected loop actually increases faster than the coolant temperature from the unaffected loop decreases. However, the decreasing coolant temperature from the unaffected loop combined with a large negative EOC MTC will have a more dominant effect on core power than the increasing coolant temperature from affected loop combined with a positive TS MTC. Power fractions in the core regions are calculated as a function the inlet temperatures to the affected and unaffected sectors. The core power fractions are used to conservatively bias the reactivity response, thereby producing a conservative core power response.
  • Radial Peaking Augmentation - The asymmetric core inlet temperatures cause a slightly asymmetric core power distribution. A bounding radial peaking augmentation factor based on the core inlet temperatures to the core sectors was applied to the peak rod power for the DNB calculations.

The Loss of Load to One Steam Generator event is classified as an AOO and, consistent with the current licensing basis, the acceptance criteria are:

Peak primary and secondary side pressures are bounded by the Loss of Load event because the unaffected SG for the Loss of Load to One Steam Generator event takes part of the load from the affected SG. The SAFDL criterion is met by assuring that the minimum calculated DNBR is not less than the 95/95 DNB correlation limit.

SG-1 is defined as the SG with the closed MSIV and SG-2 is defined as the SG without the closed MSIV.

The sequence of events is summarized in Table 15.2.2-2. In addition, key system parameters illustrating the transient are presented in Figures 15.2.2-1 to 15.2.2-10. The limiting MDNBR was calculated to be above the 95/95 CHF correlation limit.

15.2.2-2 Amendment No. 26 (11/13)

TABLE 15.2.2-1 KEY PARAMETERS ASSUMED IN THE ANALYSIS OF THE LOSS OF LOAD TO ONE STEAM GENERATOR Parameter Value Core Power 3,020 MWt + 0.3%

Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Scram Reactivity Minimum HFP Moderator Density Reactivity Consistent with EOC MTC of

-32 pcm/°F Doppler Reactivity EOC conservatively biased to account for uncertainty and cycle variation 15.2.2-3 Amendment No. 26 (11/13)

TABLE 15.2.2-2 SEQUENCE OF EVENTS FOR LOSS OF LOAD TO ONE STEAM GENERATOR Event Time (sec.)

Initiation of event (initiation of closure of MSIV on SG-1) 0.0 MDNBR occurred (radial peaking augmentation factor 0.0 conservatively applied to initial conditions)

SG-1 MSIV fully closed 0.01 MSSV flow begins for SG-1 1.7 ASGPT setpoint reached 3.1 Peak core average heat flux occurs 3.5 ASGPT occurs (after 0.9 sec. delay) 4.0 CEA insertion begins (after 0.5 sec. delay) 4.5 15.2.2-4 Amendment No. 26 (11/13)

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FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF LOAD/1 STEAM GENERATOR EVENT SG PRESSURE DIFFERENCE VS.

ASGPT SETPOINT AND VS. TIME FIGURE 15.2.2-4

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FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF LOAD/1 STEAM GENERATOR EVENT CORE INLET TEMPERATURES VS. TIME FIGURE 15.2.2-5

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FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF LOAD/1 STEAM GENERATOR EVENT PRESSURIZER PRESSURE VS. TIME FIGURE 15.2.2-7

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FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF LOAD/1 STEAM GENERATOR EVENT STEAM FLOW RATES VS. TIME FIGURE 15.2.2-9

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF LOAD/1 STEAM GENERATOR EVENT MSSV FLOWS VS. TIME FIGURE 15.2.2-10

15.2.3 CEA DROP ACCIDENT 15.2.3.1 Identification of Causes The full length CEA drop event is reanalyzed to determine the initial thermal margins that must be maintained by the Limiting Conditions for operation (LCO's) such that the DNBR and fuel centerline melt design limit will not be exceeded.

The CEA drop accident is defined as the inadvertent release of a CEA causing it to drop into the core.

The CEA drive is of the magnetic jack type. The occurrence of an electrical or mechanical failure in this mechanism, that would result in a CEA drop, is unlikely. However, the opening of the electrical circuit of the holding coil would cause a CEA drop accident.

In the case of a full length CEA drop, a rapid decrease in reactor power would follow, accompanied by a decrease in the average reactor coolant temperature. Moreover, the power distribution would be distorted as a result of the new configuration. If the initial turbine load demand were at full power and if the combination of the core power overshoot and the distorted power distribution could result in local power densities and heat fluxes in excess of design limits if the accident were initiated with the plant at design limit conditions. EC291158 15.2.3-1 Amendment No. 30 (05/20)

The worst case of a CEA left in the core results from the failure to remove a dual CEA (i.e., a shutdown CEA) from the core during startup following a shutdown.

Technical Specifications and CEA interlocks require that all shutdown CEA's be withdrawn before any regulating CEA's are withdrawn. Three CEA position indicating systems and deviation alarms described in Section 7.5.1.3 would inform the operator if a CEA were left inserted. The CEA position indicating systems and deviation alarms would also alert the operator in the event of insertion of the CEA banks to their maximum bite limits with a single regulating CEA left out of the core. Thus, these conditions are considered highly unlikely.

15.2.3.2 Analysis of Effects and Consequences(1)

The CEA Drop event is defined as the inadvertent release of a CEA causing it to drop into the core. A dropped CEA could be detected by either a position limit switch on each CEDM or by a reduction in power as measured by the ex-core detectors.

The negative reactivity insertion when the CEA drops into the core causes a reduction in the core power and reactor coolant temperatures. The magnitude of the decrease in core power and RCS temperatures depends on the worth of the dropped CEA. At EOC conditions, a strongly negative MTC will produce a positive reactivity insertion that can return the reactor to the full-power condition with elevated radial power peaking corresponding to the new radial power distribution caused by the dropped CEA. Increased cladding heat fluxes and fuel temperatures in the hot assembly result in a challenge to the DNB and fuel centerline melt SAFDLs. For a given dropped CEA worth, there is a tradeoff between the resultant return-to-power and the radial peaking augmentation factor. A lower worth dropped CEA will result in a higher resultant peak power level, but a lower radial peaking augmentation factor. A higher worth dropped CEA will result in a lower resultant peak power level, but a higher radial peaking augmentation factor. The return to power following a Dropped CEA transient may be limited by the excess capacity of the plant's turbine control valve. In response to a decrease in the secondary-side steam flow resulting from the initial drop in core power, the turbine valve will throttle open in an attempt to maintain a constant load demand.

Protection against exceeding the SAFDLs is provided by the combination of the initial steady-state margin to DNB (defined by maintaining the ASI and power within the DNB LCO barn), the VHPT, and the TM/LP trip. Depending on the dropped CEA worth, the event may be terminated by a reactor trip or there may be no reactor trip and the plant returns to some final steady power level.

Since the systems designed to mitigate this event (namely, the RPS) are redundant, there is no single active failure that will adversely affect the consequences of this event.

Detailed analyses were performed with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References 117 and 108). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures) and produce an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110).

Calculations were performed at EOC HFP conditions, maximum Technical Specifications core inlet temperature, and minimum Technical Specifications RCS fiow rate. This produces the minimum margin to the DNB limit. The event was analyzed with the most negative HFP MTC which results in the most positive moderator reactivity feedback as the RCS cools down due to the dropped CEA.

A range of dropped CEA worth was analyzed since there is a tradeoff between the maximum return-to-power and the radial peaking augmentation factor associated with any given dropped CEA worth.

The input parameters and biasing were consistent with the approved methodology.

  • Initial Conditions - This event was assumed to initiate from HFP conditions with a maximum core inlet temperature and TS minimum RCS flow. This set of conditions minimizes the initial margin to DNB.

15.2.3-2 Amendment No. 26 (11/13)

  • Reactivity Feedback - The reactivity feedback coefficients were biased according to the approved methodology (Table 15.2.3-1). The moderator temperature coefficient was set to the most negative TS limit, i.e., -32 pcm/°F, to produce the most positive moderator reactivity feedback due to a dropped CEA.

Dropped CEA Worth - A range of dropped CEA worth from 25 pcm to 200 pcm were analyzed to determine the most limiting combination of worth and radial peaking augmentation.

Gap Conductance - Gap conductance was set to a conservative EOC value to be consistent the time-in-cycle for the reactivity coefficients.

This event is classified as an AOO and, consistent with the current licensing basis, the principally challenged acceptance criterion is:

This criterion is met by assuring that the minimum calculated DNBR is not less than the 95/95 DNB correlation limit. Additionally, fuel centerline melt is demonstrated to be precluded in the most adverse location in the core.

The system responses are shown in Figures 15.2.3-1 to 15.2.3-9 for the limiting case (200 pcm). The sequence of events is given in Table 15.2.3-2. Since the auctioneered power does not decrease significantly (the B-power does not decrease significantly), the floating VHPT setpoint remains unchanged for all cases; thus, no reactor trip occurs. Since there is no reactor trip in any of the cases, the power asymptotically reaches a new steady value. Thus, the maximum core power is reported at the end of the calculations when there is no significant increase in core power and no significant change in any of the parameters that are input to the DNBR calculations. The limiting MDNBR was calculated to be above the 95/95 CHF correlation limit. The peak LHR was calculated to be less than the fuel centerline melt limit.

(1)

Obtained from EPU analysis, Section 3.19.

15.2.3-2a Amendment No. 26 (11/13)

Table 15.2.3-1 Kinetics Parameters for the CEA-Drop Event Parameter Value Moderator Temperature Coefficient -32 pcm/°F Doppler Reactivity Coefficient -1.75 pcm/°F Table 15.2.3-2 Event Table for CEA Drop Case Event Time (sec.)

200 pcm Rod drop initiated 0.0 Minimum core power 3.0 Maximum return to power 300.0 15.2.3-3 Amendment No. 26 (11/13)

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTOR POWERS- CEA DROP FIGURE 15.2.3-1

Total Core Heat Flux Power - CEA Drop 3100 I I 4 -- --

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER- CEA DROP FIGURE 15.2.3-2

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE- CEA DROP FIGURE 15.2.3-3

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 PRESSURIZER LIQUID LEVEL-CEADROP FIGURE 15.2.3-4

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES- CEA DROP FIGURE 15.2.3-5

RCS Total Loop Flow Rate- CEA Drop 50000 40000 u

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE-CEADROP FIGURE 15.2.3-6

Steam Generator Pressures- CEA Drop 860 I

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 STEAM GENERATOR PRESSURES-CEADROP FIGURE 15.2.3-7

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 STEAM FLOW RATES- CEA DROP FIGURE 15.2.3-8

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Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK-CEADROP FIGURE 15.2.3-9

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 DNBR- CEA DROP FIGURE 15.2.3-10

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTIVITY- CEA DROP FIGURE 15.2.3-11

15.2.4 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION - BORON DILUTION EVENT 15.2.4.1 Identification of Causes The chemical and volume control system (CVCS) described in Section 9.3.4 regulates both the chemistry and the quantity of coolant in the reactor coolant system. Changing the boron concentration in the reactor coolant system is a part of normal plant operation, compensating for long term reactivity effects, such as fuel burnup, xenon buildup and decay, and plant startup and cooldown. For refueling operations, borated water is supplied from the refueling water tank, which assures adequate shutdown margin. An inadvertent boron dilution in any operational mode adds positive reactivity, produces power and possibly temperature increases, and, in MODES 1 and 2 (startup and power operations) can cause an approach to both the DNBR and FCM limits.

Boron dilution is conducted under strict administrative procedures which specify permissible limits on the rate and magnitude of any required change in boron concentration. Boron concentration in the reactor coolant system can be decreased either by controlled addition of unborated makeup water with a corresponding removal of reactor coolant (feed and bleed) or by using the CVCS ion exchangers. The ion exchangers are normally used for RCS boron removal when the boron concentration is low and the feed-and-bleed method becomes inefficient. Boron concentration is determined by sampling the RCS.

During normal operation, concentrated boric acid solution is mixed with demineralized makeup water to the concentration required for proper plant operation and is injected into the reactor coolant system via the charging pumps.

Dilution of the reactor coolant can be terminated by isolation of the makeup water system, by stopping either the makeup water pumps or the charging pumps, or by closing the charging isolation valves. A charging pump must be running in addition to a makeup water pump for boron dilution to take place.

The CVCS is equipped with the following indications and alarm functions, which will inform the reactor operator when a change in boron concentration in the reactor coolant system may be occurring:

a) Volume control tank level indication and high and low alarms b) Makeup flow indication and alarms c) Volume control tank isolation.

In addition to the above, a boron dilution alarm is provided by the excore neutron flux monitoring system.

15.2.4-1 Amendment No. 26 (11/13)

To assist the reactor operator in maintaining an adequate shutdown margin, CEA insertion below a position that would provide a minimum of one percent shutdown margin (assuming one stuck CEA) is accompanied by control room alarms.

Because of the procedures involved and the numerous alarms and indications available to the operator, the probability of a sustained or erroneous dilution is very low.

15.2.4.2 Analysis of Effects and Consequences 15.2.4.2.1 Method of Analysis The time required to achieve criticality from a subcritical condition due to boron dilution is based on the initial and critical boron concentrations, the boron reactivity worth, and the rate of dilution. Reactivity increase rates due to boron dilution are based on the boron worth and the dilution rate.

Cases have been analyzed for all six operational modes, i.e., power operation, startup, hot standby, hot shutdown, cold shutdown, and refueling.*

The boron dilution event was analyzed with the approved Reference 117 methodology.

An inadvertent boron dilution adds positive reactivity, produces power and temperature increases, and during operation at power (Mode 1) can cause an approach to both the DNBR and FCM limits. Since the TM/LP trip system monitors the transient behavior of core power level and core inlet temperature at power, the TM/LP trip will intervene, if necessary, to prevent the DNBR limit from the being exceeded for power increases within the setting of the variable high power level trip. Mode 1 boron dilution event is bounded by the reactivity insertion rates considered in the CEA Withdrawal at Power event (Section 15.2.1 ).

In the event of an unplanned dilution during Mode 2 power escalation, the plant status is such that minimal impact will result. The plant will slowly escalate in power and activate a power-related trip (TM/LP or VHP). The acceptance criteria for Mode 2 must provide sufficient time to prevent a return to criticality. Prior to trip, challenges to the DNB and FCM SAFDLs are bounded by other events, such as CEA Withdrawal at Startup or Low Power (Section 15.2.1 ).

Two models are typically used to evaluate the boron dilution transient,

  • instantaneous mixing model, and
  • dilution front model.

The instantaneous mixing model is applicable when at least one RCP is operating and assumes the unborated water is instantaneously mixed with the entire water volume in the RCS. The dilution front model is used when the core is being cooled by the SDCS (no RCPs operating); for these operating modes the RCS flow is much lower than operating with a RCP and the assumption of instantaneous mixing of the unborated water with the entire RCS volumes is not valid.

15.2.4.2.1.1 Input Parameters and Assumptions The input parameters are shown in Table 15.2.4-1.

The calculated time-to-criticality for both models is dependent on the critical-to-initial boron concentration ratio, the RCS coolant volume/mass and the flow rate of the boron dilution stream. In addition, for the dilution front model, a range of SDCS coolant flow rates is required.

A conservative dilution time constant was used that assumed not only a conservative average SGTP of 15% but also the availability of three charging pumps for all modes. In each case, it is also assumed that the boron dilution results from pumping unborated demineralized water into the reactor coolant system at the maximum possible rate of 147 gpm (3 x 49 gpm per charging pump).

15.2.4-2 Amendment No. 26 (11/13)

15.2.4.2.1.2 Acceptance Criteria The acceptance criteria for Modes 2 through 6 is that the time to criticality allows operator action to terminate the event.

The required time to operator action for Modes 2 through 5 is 15 minutes. The required time to operator action for Mode 6 is 30 minutes.

15.2.4.2.2 Results Table 15.2.4.2-2 shows the results from the boron dilution event.

The results of the instantaneous mixing model shows that there is adequate time to operator action prior to a significant loss in shutdown margin for Modes 2, 3, and 4.

The results of the dilution front model shows that there is adequate time to operator action prior to a significant loss in shutdown margin provided the SDCS flow rate is maintained at or above the minimum flow rate limits shown in Table 15.2.4.2-2.

  • An additional boron dilution event would be via the Iodine Removal System (NaOH spray additive). This event is not governing, however.

See Reference 42.

15.2.4.3 Conclusions Because of the equipment and controls and the administrative procedures provided for the boron dilution operation, the probability of erroneous dilution is considered very small. Nevertheless, if a dilution of boron in the reactor coolant should occur, alarms and indications identified in Section 15.2.4 would alert the operator to this condition. The maximum reactivity addition due to the dilution is slow enough to allow the operator to determine the cause of the dilution and take corrective action before significant shutdown margin is lost.

15.2.4-3 Amendment No. 26 (11/13)

DELETED 15.2.4-4 Amendment No. 26 (11/13)

DELETED 15.2.4-5 Amendment No. 26 (11/13)

DELETED 15.2.4-6 Amendment No. 26 (11/13)

DELETED 15.2.4-6a Amendment No. 26 (11/13)

TABLE 15.2.4-1 BORON DILUTION EVENT: INPUT PARAMETERS Parameter Boron Concentration, ppm (Critical/Initial for limiting case) Boron Ratio Startup (Mode 2) 1157/1506 0.768 Hot Standby (Mode 3) 1157/1506 0.768 Hot Shutdown (Mode 4) 1172/1498 0.782 Cold Shutdown (Mode 5) 1180/1449 0.815 Refueling (Mode 6) 1620/2069 0.783 Charging Flow, gpm per pump 49 Number of Charging Pumps 3 Partial RCS Volume, ft3 3616 3

Full RCS Volume, ft 8303 Sweepout Volume, ft3 1717 15.2.4-7 Amendment No. 26 (11/13)

TABLE 15.2.4-2 BORON DILUTION EVENT: RESULTS Parameter Operator Required Time-to-Criticality SDCS Min. Flow Response Time (min.) (min.) (gpm)

Instantaneous Mixing Model Startup (Mode 2) 15 63.95 N/A Hot Standby (Mode 3) 15 63.95 N/A Hot Shutdown (Mode 4) 15 75.83 N/A Dilution Front Model Hot Shutdown (Mode 4) 15 23.19 780 Cold Shutdown (Mode 5) 15 22.52 780 Refueling (Mode 6) 30 35.33 3000 15.2.4-8 Amendment No. 26 (11/13)

15.2.5 LOSS OF COOLANT FLOW ACCIDENT 15.2.5.1 Identification of Causes The loss of coolant flow event is analyzed to determine the minimum initial margin that must be maintained by the Limiting Conditions for Operations (LCO's) such that in conjunction with the RPS (low flow trip), the DNBR limit will not be exceeded.

A loss of normal coolant flow may result either from a loss of electrical power to one or more of the four reactor coolant pumps or from a mechanical failure, such as a pump shaft seizure, (refer to Section 15.3.4). Simultaneous mechanical failure of two or more pumps Is not considered credible. Under voltage or under frequency of the motor drive electrical power source can result in a reduction of coolant flow; and, if the flow reduction from either cause is greater than the flow rate trip setpoint, a reactor trip is initiated.

Credit for a functioning reactor coolant pump anti-reverse rotational device (ARRD) is taken in evaluating the loss of reactor coolant flow events. The major concern with loss of the ARRD is reverse flow in the affected loop thereby allowing flow from the operating loops to be diverted from the core. Given that the reverse flow due to failure of an ARRD would occur only after the pump had coasted down due to flywheel inertia, and that the critical time period for the limiting event (seized shaft) has a very short time span (less than 10 seconds), the failure of the ARRD would not be expected to adversely impact the loss of reactor coolant flow events analysis.

The design of the onsite electrical power system for the reactor coolant pumps is such that no single failure from a normal operating condition can cause a complete (4-pump) loss of flow accident where the pump-motor-flywheel combination is the only available source of coastdown energy. Reactor coolant pumps 1A1 and 1B2 are connected to 6.9 kV bus 1A1, and pumps 1B1 and 1A2 are connected to 6.9 kV bus 1B1. (Refer to Table 8.3-1.) Therefore, loss of a single bus will result in loss of power to two reactor coolant pumps.

In the event of a turbine-generator trip (either turbine lockout or generator lockout), the power source for the reactor coolant pumps is automatically switched to the offsite transmission lines. This transfer is accomplished within three cycles with no significant effect of the reactor coolant loop flow rate (refer to Section 8.3.1.1.1). There is no intentional time delay introduced to either of these transfer modes.

Reactor trip on loss of coolant flow is initiated by a low coolant flow rate as determined by a reduction in the sum of the steam generator hot to cold leg pressure drops. For a loss of flow at full power operating condition, a trip will be initiated when the flow rate drops to the low flow trip setpoint analysis value.

15.2.5-1 Amendment No.18, (04/01)

The 4-Pump Loss of Coolant Flow produces a rapid approach to the DNBR limit due to the rapid decrease in the core coolant flow. Protection against exceeding the DNBR limit for this transient is provided by the initial steady state thermal margin which is maintained by adhering to the Technical Specifications' LCO's on DNBR margin and by the response of the RPS which provides an automatic reactor trip on low reactor coolant flow as measured by the steam generator differential pressure transmitters.

The increasing primary system coolant temperatures caused by the decrease in reactor coolant flow rate also results in expansion of the primary coolant volume, causing an in-surge into the pressurizer and thereby an increase in the pressure of the primary system. However, pressure limits are not challenged by this event.

15.2.5.2 Analysis of Effects and Consequences Detailed analyses were performed with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References 117, 108 and 109). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures) and produce an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110).

A single case was analyzed at BOC HFP initial conditions maximum TS core inlet temperature and minimum TS RCS flow rate. The factors affecting scram time were chosen to maximize the scram delay with the trip signal delay and holding coil delay times set to their maximum values. This produced the most significant challenge to the DNB limit.

15.2.5.2.1 Input Parameters and Assumptions The input parameters and biasing were consistent with the approved methodology.

  • Initial Conditions - HFP initial conditions, maximum Technical Specifications core inlet temperature and minimum Technical Specifications RCS flow rate were modeled in order to minimize the initial margin to DNB.
  • Reactivity Feedback - Since this event involves an increase in the core coolant temperature, the event was assumed to occur at BOC with a maximum TS/COLR MTC at full power (Table 15.2.5-1). However, this event occurs quickly and is generally not sensitive to neutronic parameters. A minimum HFP scram worth was used to conservatively prolong the degradation in flow while maintaining relatively high core power.
  • Gap Conductance - Gap conductance was set to a conservative BOC value to delay the transfer of heat from the fuel rod to the coolant allowing the primary system flow to decay further thus leading to a conservative prediction of DNBR.
  • RCS Flow - The coastdown charateristics of the RCPs were conservatively benchmarked to plant data.

15.2.5-1a Amendment No. 26 (11/13)

15.2.5.2.2 Acceptance Criteria The event is classified as an AOO and, consistently with the current licensing basis, the principally challenged acceptance criterion is:

This criterion is met by assuring that the minimum calculated DNBR is not less thn the 95/95 DNB correlation limit. Since this event does not involve a significant power transient or augmented peaking, the fuel centerline melt is not challenged.

15.2.5.2.3 Results The sequence of events is given Table 15.2.5-2. Plots of key system parameters are shown in figures 15.2.5-1 to 15.2.5-6. The MDNBR with deterministically applied uncertainties was calculated for the extended power uprate (EPU) to be greater than the 95/95 limit. Statistical evaluation of this event is performed as part of the DNB LCO analyses. (Section 15.6.5.2).

15.2.5-2 Amendment No. 26 (11/13)

Table 15.2.5-1 Kinetics Parameters for the Loss-of-Coolant Flow Event Parameter Value Moderator Temperature Coefficient +2 pcm/°F Doppler Reactivity Coefficient -0.80 pcm/°F 15.2.5-3 Amendment No. 26 (11/13)

Table 15.2.5-2 Event Table for a Loss-of-Coolant Flow Event Time (sec.)

Pump coastdown initiatives 0.0 Low RCS flow trip setpoint reached 1.008 Reactor scram on low RCS flow rate 2.033 (including trip response delay)

CEA insertion begins 2.533 Peak core power 2.54 MDNBR 3.75 CEAs fully inserted 5.43 Peak pressurizer pressure 5.59 15.2.5-4 Amendment No. 26 (11/13)

Reactor Power - Loss of Coolant Flow 120 100 ---

80 a:

I-0::::

0~

60

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5:

0 0..

40 20

\_______ - - ..-

0 0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTOR POWER- LOSS OF COOLANT FLOW FIGURE 15.2.5-1

Total Core Heat Flux Power- Loss of Coolant Flow 4000 ~--~----~----~----~----~----~--~----~----~----~

3500

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1500 1000 ~--~----~----~----~----~----~--~----~----~----~

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER- LOSS OF COOLANT FLOW FIGURE 15.2.5-2

Pressurizer Pressure - Loss of Coolant Flow 2400

~

J 2350 If)

If)

~

a..

2300 2250._--4=~--~----~----~----~----~----~----~--~----~

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 PRESSUR~ERPRESSURE-LOSSOF COOLANT FLOW FIGURE 15.2.5-3

RCS Loop Temperatures- Loss of Coolant Flow 640 ~--~----~----~----~----~----~----~----~--~-----.

620 12 600 o.__...

e Avg. Thot

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-~

ctl Cl>

                    • Avg . Tcold a.

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1-580 560 540 ~--~----~----~----~----~----~----~----~--~----~

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES- LOSS OF COOLANT FLOW FIGURE 15.2.5-4

RCS Total Loop Flow Rate- Loss of Coolant Flow 40000 u

Q) en E

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Q) a::: 30000 ctl 3

0 IJ..

en en ctl

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20000 10000 ~--~----~----~--~----~----~--~----~----~--~

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE- LOSS OF COOLANT FLOW FIGURE 15.2.5-5

Reactivity Feedback- Loss of Coolant Flow 2.0 ~--~----~----~----~----~----~----~----~--~-----,

0.0 ----.-,_._.........-tt-----~~~--~---~--~*~-~* ~** --------~---- ~~..:..~.:-.~. -.*-~--~-----~-~--~--~ ~--- -~--- - :-..~--~-~-

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0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK- LOSS OF COOLANT FLOW FIGURE 15.2.5-6

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 COLD LEG FLOWS - LOSS OF COOLANT FLOW FIGURE 15.2.5-7

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 PRESSURES- LOSS OF COOLANT FLOW FIGURE 15.2.5-8

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 WATER LEVELS- LOSS OF COOLANT FLOW FIGURE 15.2.5-9

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 DNBR- LOSS OF COOLANT FLOW FIGURE 15.2.5-10

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 REACTIVITY- LOSS OF COOLANT FLOW FIGURE 15.2.5-11

15.2.6 STARTUP OF AN INACTIVE REACTOR COOLANT PUMP EVENT Although analyzed for the original FSAR (Reference 1), this section has been deleted because Technical Specifications do not pemit operation at power (Modes 1 and 2) with less then 4 reactor coolant pumps operating.

15.2.6-1

15.2.7 LOSS OF EXTERNAL ELECTRICAL LOAD AND/OR TURBINE STOP VALVE CLOSURE Identification of Causes and Event Description A rapid large reduction of power demand on the reactor while operating at full power can cause a corresponding reduction in the rate of heat removal from the reactor coolant system. The most probable cause of a rapid loss of load is a turbine trip. The event can also occur as a result of abnormal variations in network frequency. The primary challenge of this transient is to the vessel pressurization acceptance criterion.

The plant is designed to accept a 29% step reduction in load without actuating a reactor trip signal. In the event of a complete loss of load, the steam dump and bypass system is normally available to remove energy from the reactor coolant system. When no credit is taken for the steam dump and bypass system or the pressurizer power-operated relief valves, the pressurizer and main steam safety valves function to ensure that neither the reactor coolant system nor the steam generator pressures exceed design limits. The steam dump and bypass system which discharges steam to the condenser is described in Sections 10.4.4 and 7.7.1.3.2. If the steam dump and bypass valve system fails to respond in the open position, the reactor will trip on a loss of load.

When the turbine stop/control valve closes, the steam flow is terminated, causing the secondary system temperature and pressure to increase. The primary-to-secondary heat transfer decreases as the secondary system temperature increases. If the reactor is not tripped when the turbine is tripped, the primary system temperature continues to rise.

The primary liquid will expand and the pressurizer steam space is compressed, causing the pressurizer pressure to rise. If this continues, the reactor will trip on high pressurizer pressure, reducing the primary heat source. As the heat load into the primary system decreases, the primary system pressurization will begin to diminish. If the setpoint for opening the primary system code safety valves is exceeded during the initial system pressurization, these valves will open to relieve pressure and to mitigate the pressure transient. The mitigative features of the pressurizer spray, pressurizer relief valves, and the steam bypass system are assumed not to function so as to exacerbate the calculated pressurization of the primary system. Energy is removed during the early phase of the transient through the steam generator safety valves when the steam generator pressure exceeds the safety valve opening setpoint.

The main purpose of analyzing this event is to demonstrate that the primary and secondary pressure relief capability is sufficient to limit the primary pressure to less than 110% of the design pressure (i.e. 2750 psia), and to limit the secondary pressure to less than 110% of the design pressure (i.e. 1100 psia). This event is also analyzed to ensure that the SAFDLs are not exceeded under the limiting assumptions of no credit for a direct reactor trip on turbine trip.

Conservative initial conditions were used in the analysis. Input parameters were separately biased to maximize the increase in reactor power and system overpressurization during the transient for the overpressurization events, and separate input biasing was used to reduce calculated DNBR for the MDNBR event analysis. In addition, part-power cases were analyzed to assess the impact to secondary side pressures due to varying numbers of main steam safety valves (MSSVs) being out-of-service.

15.2.7.1 Overview There are three subevents for a LOEL event: one that challenges the RCS primary side overpressurization, one that challenges the RCS secondary side overpressurization, and another that challenges MDNBR.

For the primary overpressurization event, bounding results are calculated assuming the maximum tube plugging level.

Steam generator tube plugging increases the temperature difference between the primary and secondary sides. This then results in the temperature/pressure required to reach the MSSV setpoint, and a corresponding increase in the surge line flow into the pressurizer on the primary side. The maximum SGPT level of 10% is used for the analysis.

For the secondary side overpressurization event, with no credit taken for reactor trip on turbine trip, the secondary system pressure rapidly increases. Also, because no credit is taken for the steam dump and bypass system, only the main safety valves are available for secondary system pressure relief. Zero SGTP is assumed in order to maximize heat transfer from the primary system to the secondary system.

(Radiological consequences are not addressed by Framatome (formerly AREVA).) EC292529 15.2.7-1 Amendment No. 30 (05/20)

15.2.7.2 Safety Analysis A Loss of External Load (LOEL) event is initiated by either a loss of external electrical load or a turbine trip. Upon either of these two conditions, the turbine stop valve is assumed to rapidly close. Normally, a reactor trip would occur on a turbine trip. However, to calculate a conservative system response, the reactor trip on turbine trip is disabled. The steam dump system (ADVs) is assumed to be unavailable.

These assumptions allow the loss of External Load event to bound the consequences of a turbine trip -

steam dump system available, a Loss of Condenser Vacuum - steam dump system available, a Loss of Condenser Vacuum - steam dump system unavailable, and an MSIV closure event.

The Loss of External Load event primarily challenges the acceptance criteria on primary system overpressurization, secondary system overpressurization, and DNBR. The event results in an increase in the primary system temperatures due to an increase in the secondary side temperature. As the primary system temperatures increase, the coolant expands into the pressurizer causing an increase in the pressurizer pressure. The primary system is protected against overpressurization by the pressurizer safety and relief valves. Pressure relief on the secondary side is afforded by the steam line safety/relief valves. Actuation of the primary and secondary system safety valves limits the magnitude of the primary system temperature and pressure increase.

With a positive moderator temperature coefficient, increasing primary system temperature results in an increase in core power. The increasing primary side temperatures and power reduce the margin to thermal limits (i.e., DNBR limits) and challenge the DNBR acceptance criteria.

15.2.7.2.1 Description of Analyses and Evaluations Detailed analyses were performed with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References 117, 108, and 109). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures) and produce an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate using the HTP CHF correlation (Reference 110).

Three set of cases were analyzed from HFP initial conditions to assess the challenges to the acceptance criteria: (1) primary side pressure, (2) secondary side pressure and (3) MDNBR. In addition, part-power cases were analyzed to assess the impact to secondary side pressures due to the varying number of main safety steam valves being out-of-service to provide the basis for Technical Specification 3/4.7.1.

The key input parameters and their values used in the analysis of the loss of external load event are consistent with the approved Reference 117 methodology.

  • Initial Conditions - This event was analyzed from the HFP plus measurement uncertainty since the resultant loss of steam load was the greatest and presented the most significant challenge to the safety valve performance for primary system pressure and for secondary system pressure with all MSSVs operable. In addition, for the MDNBR case, assuming a HFP initial condition with a maximum core inlet temperature and TS minimum RCS flow minimized the initial margin to DNB.

Initial cold leg temperatures, RCS flow rate, pressurizer pressure and pressurizer level were ranged from bounding low to bounding high values, including uncertainties, to determine the limiting cases for the challenges to primary system and secondary system overpressure.

Separate biasing was applied to determine the limiting cases for the challenges to the primary system and secondary system overpressure criteria.

15.2.7-2 Amendment No. 26 (11/13)

For part-power cases, the secondary side peak pressure was calculated for one, two, and three out-of-service MSSVs per steam line. The analysis validates the TS Table 3.7-1 allowed variable high power trip (VHPT) setpoints as a function of the number of out-of-service MSSVs, based on maintaining the peak secondary side pressure to less than 110% of design. Initial conditions were conservatively treated, based on maximizing secondary side pressure. The range of the initial conditions for power level, cold leg temperature, RCS flow rate, pressurizer pressure, and pressurizer level accounted for uncertainties, and were conservatively selected based on the HFP results and were consistent with the initial power levels.

  • Reactivity Feedback - BOC kinetics parameters were biased to maximize the increase in reactor power during the transient. In general, the reactivity feedback was not significant for this event.
  • Pressurizer Pressure Control - Pressurizer pressure control (i.e., pressurizer sprays, heaters and PORVs) was treated differently among the various cases. For the primary side overpressure case, the parameters and equipment operational states were selected to maximize the primary system pressure. For the secondary side pressure case, the parameters and equipment operational states were selected to maximize the secondary system pressure. For the MDNBR case, the parameters and equipment states were selected to reduce the primary system pressure, which provided a conservative calculation of the minimum DNBR during the transient.
  • Pressurizer and Main Steam Safety Valves - For the cases that evaluate peak primary and secondary system pressures, the pressurizer and main steam safety valves were conservatively modeled. The valves were sized to relieve their respective design flows accounting for valve accumulation. The opening setpoints were biased high to the Technical Specification upper tolerance limits.
  • Gap Conductance - Gap conductance was set to a conservative BOC value to be consistent with the time-in-cycle for the reactivity coefficients.
  • Steam Generator Tube Plugging - Both minimum (0%) and maximum (10%) steam generator tube plugging were considered depending on the acceptance criterion being evaluated (i.e.

primary system overpressure, secondary system overpressure and MDNBR).

  • Single Failure - No single active failure will prevent operation of any system required to function for this event.

This event is classified as an AOO event and the acceptance criteria are:

  • The pressures in the RCS and main steam system should be less than 110% of design values.

Peak primary and secondary side pressures are calculated to verify that pressure limits are met. For the SAFDLs, this criterion is met by assuring that the minimum calculated DNBR is not less than the 95/95 DNB correlation limit. Since this event does not involve a significant power transient or augmented peaking, the fuel centerline melt limit is not challenged.

15.2.7-2a Amendment No. 26 (11/13)

15.2.7.2.1a Primary Side Overpressurization Event The objectives in analyzing this event are to demonstrate that the primary pressure relief capacity is sufficient to limit the pressure to less than 110% of the design pressure. No credit is taken for direct reactor trip on turbine trip, the turbine bypass system, the steam dump system, or the PORVs. The event was evaluated using the maximum SGTP (10%).

The peak RCS pressure for the limiting case is 2,744 psia. This is below the 110% of design pressure criterion (i.e., 2,750 psia), which satisfies the overpressure design criterion.

The sequence of events is given in Table 15.2.7-1. The transient response is shown in Figures 15.2.7-1 through Figure 15.2.7-9. Figure 15.2.7-1 shows the reactor power as a function of time. Figures 15.2.7-2 through 15.2.7-9 show the pressurizer and peak RCS pressure, the pressurizer liquid level, the PSV flow rate, the RCS loop temperatures, the RCS cold leg flow rates, the steam line pressures, the MSSV flow rates, and the reactivity feedback, respectively.

15.2.7.2.1b Secondary Side Overpressurization Event The Loss of External Load analysis was biased to calculate the bounding peak maximum secondary side pressure. The code input was changed to bias the calculation for maximum secondary pressure, instead of for maximum primary pressure.

The peak main steam system pressure (SG dome) and the peak secondary side pressure for the limiting case are less than 110% of design (i.e. 1,100 psia). The sequence of events is given in Table 15.2.7-2.

The peak main steam system pressure (SG dome) is 1,092 psia.

The transient response is shown in Figures 15.2.7-10 through 15.2.7-17. Figure 15.2.7-10 shows the reactor power as a function of time. Figures 15.2.7-11 15.2.7-17 show the pressurizer pressure, the pressurizer liquid level, the RCS loop temperatures, the RCS cold leg loop flow rates, the main steam system (SG dome) pressures, the MSSV flow rates, and the reactivity feedback, respectively.

Peak main steam system (SG dome) pressure results for the limiting cases analyzed at part-power assuming MSSVs out-of-service that were made to support the power levels and numbers of the MSSVs out-of-service are shown in Table 15.2.7-4. For those part-power cases with one, two, and three MSSVs out-of-service per SG, the calculated peak main steam system (SG dome) and the peak secondary side pressures were less than 110% of design (i.e. 1,100 psia). The results of the analysis validates the Technical Specification allowed VHPT setpoints.

15.2.7.2.1c Minimum DNBR Event The MDNBR case was evaluated assuming a HFP initial condition with a maximum core inlet temperature, Technical Specification minimum RCS flow, and maximum steam generator tube plugging level (10%).

These conditions minimized the initial margin to DNB. In addition, the parameters and equipment states for this case were selected to reduce the primary system pressure, which provided a conservative calculation of the minimum DNBR during the transient.

15.2.7-2b Amendment No. 26 (11/13)

The sequence of events is given in Table 15.2.7-3. The transient response is shown in Figures 15.2.7-18 through 15.2.7-26. Figure 15.2.7-18 shows the reactor power as a function of time and Figure 15.2.7-19 shows the reactor power based on rod surface heat flux as a function of time. Figure 15.2.7-20 through 15.2.7-26 show the pressurizer pressure, the pressurizer liquid level, the pressurizer PORV flow rate, the RCS loop temperatures, the total RCS flow rate, the SG pressures, and the reactivity feedback, respectively.

The calculated MDNBR was greater than the 95/95 limit for the CHF correlation.

15.2.7.2.1.2 Radiological Consequences The radiological consequences of this event are bounded by the event in Section 15.2.11.3.2.

15.2.7.2.2 Turbine Trip The event is similar to the LOEL event but is initiated by trip of the turbine. A reactor trip on the TT signal is expected. Since the LOEL analysis disabled the reactor trip on TT in favor of the high pressure trip (which would occur much later), the LOEL analysis bounds this event.

15.2.7.2.3 Loss of Condenser Vacuum This event is also similar to the LOEL event but is initiated by loss of condenser vacuum. The loss of condenser vacuum both disables steam bypass and results in a gradual decrease in steam flow compared to that resulting from the stop valve closure. Since both effects are assumed for the LOEL event, the loss of condenser vacuum event is bounded by the LOEL event.

15.2.7.2.4 Closure of Main Steam Isolation Valve This event postulates that one or both of the MSIVs close to initiate the event. The closure of both the MSIVs is not worse than the closure of the turbine stop valves on a turbine trip. The more rapid closure of the turbine stop valves produces a more severe system transient than does the closure of both MSIVs.

Closure of both MSIVs is thus bounded by the loss of external load event.

The evaluation of a closure of a single MSIV is provided in Section 15.2.2.

15.2.7-3 Amendment No. 26 (11/13)

DELETED 15.2.7-3a Amendment No. 18, (04/01)

TABLE 15.2.7-1 for Loss of External Load Sequence of Events for Primary Side Overpressurization Case EVENT TIME (sec.)

Turbine Trip 0.0 High Pressurizer Pressure trip setpoint reached 7.0 Reactor trip occurred on High Pressurizer Pressure 7.9 (including trip response delay)

CEA insertion begins 8.4 Peak reactor power occurred 8.4 Pressurizer safety valves opened 8.9 Peak primary pressure occurred 9.9 Peak core-average RCS temperature occurred 10.3 Steam generator Bank 1 MSSVs opened (both SGs) 10.9 Peak pressurizer level occurred 13.0 Peak main steam system pressure (SG dome) occurred 17.2 15.2.7-4 Amendment No. 26 (11/13)

TABLE 15.2.7-2 Loss of External Load Sequence of Events for HFP Secondary Side Overpressurization Limiting Case Event Time (sec.)

Event initiation, (Turbine trip) 0.0 Pressurizer spray begins 2.5 Steam generator Bank 1 MSSVs open (both SGs) 4.3 Steam generator Bank 2 MSSVs open (both SGs) 6.3 High Pressurizer Pressure trip setpoint reached 6.8 Reactor trip occurred on High Pressurizer Pressure 7.7 (including trip response delay)

Peak reactor power occurred 8.2 CEA insertion begins 8.2 Pressurizer safety valves opened 9.3 Peak main steam system pressure (SG dome) occurred 14.0 TABLE 15.2.7-3 Loss of External Load Sequence of Events for MDNBR Case Event Time (sec.)

Turbine trip 0.0 Pressurizer PORV opened 4.6 Steam generator Bank 1 MSSVs opened (both SGs) 4.8 High Pressurizer Pressure trip setpoint reached 6.3 Reactor trip occurred on High Pressurizer Pressure 7.2 (including trip response delay)

CEA insertion begins 7.7 Peak reactor power occurred 7.7 MDNBR 8.0 15.2.7-5 Amendment No. 26 (11/13)

TABLE 15.2.7-4 Loss of External Load Inoperable MSSV Results Peak Main Steam Maximum Allowed Maximum Number of System Pressure Power Level -

Inoperable MSSVs on Any SG (SG Dome) High Trip Setpoint (psia) (% RTP) 1 Inoperable MSSV per SG 1,090 88.5 2 Inoperable MSSVs per SG 1,091 79.8 3 Inoperable MSSVs per SG 1,091 66.5 15.2.7-5a Amendment No. 26 (11/13)

Reactor Power Loss of External Load (Primary Side Pressure Case) 120 110 -

100 ~ -

90 -

a.. 80 -

1-a:::

~

0 70 -

Q) 3:

0 60 -

a..,_

- 0

( .)

ro Q) 50 -

a::: 40 -

30 -

20 -

10 -

0 I 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD REACTOR POWER (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-1

Pressurizer and Peak RCS Pressure Loss of External Load (Primary Side Pressure Case) 2800 2600 RCS Design Pressure

- C/)

~

0.

2400 (J)

I...

J C/)

C/)

(J)

I...

a.. 2200 2000

El Top of Pressurizer

;:::] Vessel Bottom Pressur 1800 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER AND PEAK RCS PRESSURE (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-2

Pressurizer Liquid Level Loss of External Load (Primary Side Pressure Case) 100 I 80

~ 60

/

0

(])

_J "0

(])

J C"'
.:i 40 20 0

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER LIQUID LEVEL (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-3

Pressurizer Safety Valve Flow Loss of External Load (Primary Side Pressure Case) 200.0 150.0

-- ( /)

E

..0

(].)

ro a:: 100.0

~

0 LL

(/)

(/)

ro

a:

50.0 0.0 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER SAFETY VALVE FLOW (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-4

RCS Loop Temperatures Loss of External Load (Primary Side Pressure Case) 640

~HL-1

HL - 2

- - - T_avg

- ..,.._, CL-1A 620 - - CL-1B

~ CL- 2A

* CL -2B 600 LL 0

Q)

I....

J rI....o 580 , ...

Q)

a. "

E Q) I

-1 "

I-- /

/ "

560 ""

540 520 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD RCS LOOP TEMPERATURES (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-5

RCS Cold Leg Loop Flow Rates Loss of External Load (Primary Side Pressure Case) 11600

8 CL- 1A

            • CL- 1 B

- - 0 CL-2A 11400 - -6 CL-2B

---en

..0 E

11200

( l) rn a:::

~

0 LL en en 11000 rn

~

10800 10600 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD RCS COLD LEG LOOP FLOW RATES (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-6

Steam Line Pressures Loss of External Load (Primary Side Pressure Case) 1100 l MSSV 5* 8 I MSSV *-*

~** ***********************

1000 ro

'(i) a.

i (/)

900 ~

~

a..

800 700 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD STEAM LINE PRESSURES (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-7

MSSV Flow Rates Loss of External Load (Primary Side Pressure Case) 1400 1200 1000

.0

(/)

(])

E 800 ro

+-'

a::

~

0 u.. 600

(/)

(/)

ro

~

400 200 0 (5----...1....-83--.........- - - ' - _ . . . _ _ _ _ . . . _ _ _

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD MSSV FLOW RATES (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-8

Reactivity Feedback Loss of External Load (Primary Side Pressure Case) 5 .---~--~--~--~--~--~--~--~--~--~

0

~----""~- - - - -

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

- - - - - - of,- - - - - - <~ - - - - - - - - - - -

(flo

~

z:;

u

8 Total rn ------ Scram Q) 0:: - - 0 Moderator

- -6 Doppler

-5 v-e-

~---------6.}------------------R------------------R---------------R---------------F---

- 10 ~~--~--~--~--~--~--~--~--~~

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD REACTIVITY FEEDBACK (PRIMARY SIDE PRESSURE CASE)

FIGURE 15.2.7-9

Reactor Power Loss of External Load (Secondary Side Pressure Case) 120 110 -

100 -

90 -

0..

80 -

r-a:

§?. 70 -

0

<1.>

~

0 60 -

0..

0 50 -

t5 ro

<1.>

a: 40 -

30 -

20 -

10 -

0 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD REACTOR POWER (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-10

Pressurizer Pressure Loss of External Load (Secondary Side Pressure Case) 2800 ~~--~--~--~--~--~--~--~~--~

2600 ro- 24oo

"(i) c..

~

J

(})

(})

Q)

\....

a.. 2200 2000 1800 ~~--~--~--~--~--~--~--~--~~

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER PRESSURE (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-11

Pressurizer Liquid Level Loss of External Load (Secondary Side Pressure Case) 100 80 60 0~

(])

(])

__J

'Q
J 0"'
.:J 40 20 0

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER LIQUID LEVEL (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-12

RCS Loop Temperatures Loss of External Load (Secondary Side Pressure Case) 640 ~--~--~--~~~~--~--~--~--~--~

540 520 ~--~--~--~~~~--~--~--~--~--~

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD RCS LOOP TEMPERATURES (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-13

RCS Cold Leg Loop Flow Rate Loss of External Load (Secondary Side Pressure Case) 10000 9800

.n

( /)

E 9600

....ro Q) 0::: ----) CL-1A 3:

0 ******D CL- 18 LL

- - CL-2A

(/) 9400

(/)

ro - -6 CL- 28

2 9200 9000 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD RCS COLD LEG LOOP FLOW RATE (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-14

Main Steam System (SG Dome) Pressures Loss of External Load (Secondary Side Pressure Case) 1150 ,-~--~--~--~--~--~--~--,-~---,

110% Secondary Design Pressure 1100 1050

~

J 1000

(/)

(/)

Q) a..

950 ----8 SG-1 Dome

0 SG-2 Dome 900 850 ~--~--~~~~~~~~--~--~--~--~

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD MAIN STEAM SYSTEM (SG DOME)

PRESSURES (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-15

MSSV Flow Rates Loss of External Load (Secondary Side Pressure Case) 1600 ~~--~--~--~--~--~--~--~--~~

1400 1200

~ 1000

..c Q) co a::: 800 3:

0 LL

(/)

(/)

co 600

a:

400 200 o ~~~--~~--~--~--~--~--~--~--~

0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD MSSV FLOW RATES (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-16

Reactivity Feedback Loss of External Load (Secondary Side Pressure Case) 5 0 ~----~~

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

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

6CT

o::; ~Total u

ro ------ Scram (I) cr:: - - 0 Moderator

- -6 Doppler

-5 -

~

8-****-*****

--E-**

-10 0 10 20 30 40 50 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD REACTIVITY FEEDBACK (SECONDARY SIDE PRESSURE CASE)

FIGURE 15.2.7-17

Reactor Power Loss of External Load (MDNBR Case)

~

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

80 EL 1-0::

~

e.....

.... 60 a.>

==

0 a..

40 20 0 ~~--~--~--~~~~--~--~--~~--~--~--~--~~

0 5 10 15 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD REACTOR POWER (MDNBR CASE)

FIGURE 15.2.7-18

Total Core Heat Flux Power Loss of External Load (MDNBR Case)

~ 3000 -

~

L...

Q)

~

0 a..

X

I u:::

-roQ) 2000 I

Q)

(.)

~

I (f)

"0 0

0:: 1000 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD TOTAL CORE HEAT FLUX POWER (MDNBR CASE)

FIGURE 15.2.7-19

Pressurizer Pressure Loss of External Load (MDNBR Case) 2500

~ 2400 s

(/)

J

(/)

(/)

~

a. 2300 2200 2100 ~~--~--~--~--~--~--~--~--~--~--~--~--~--~~

0 5 10 15 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER PRESSURE (MDNBR CASE)

FIGURE 15.2.7-20

Pressurizer Liquid Level Loss of External Load (MDNBR Case) 75 c('(]

a.

(/)

Q) 70 Q)

...J

'2
J 0"
.::i 65 60 ~~--~--~--~--~--~~--~--~--~--~--~~--~--~

0 5 10 15 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER LIQUID LEVEL (MDNBR CASE)

FIGURE 15.2.7-21

Pressurizer PORV Flow Rate Loss of External Load (MDNBR Case) uQ) 100

~

g Q)

-ro

"~

0 u::

fJ) fJ) rn

§! 50 0*---~~--~~~~~--~~--~--~--~--~--~~~~--~

0 5 10 15 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD PRESSURIZER PORV FLOW RATE (MDNBR CASE)

FIGURE 15.2.7-22

RCS Loop Temperatures Loss of External Load (MDNBR Case) 600 Avg. Thot

~

l ----------* Avg . Tcold ro... 5ao Q) c..

E

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

560 .. -*-_.-

Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD RCS LOOP TEMPERATURES (MDNBR CASE)

FIGURE 15.2.7-23

RCS Total Loop Flow Rate Loss of External Load (MDNBR Case) 50000 ~~--~--~--~~--~--~--~--~~--~--~--~--~-,

40000 uQ) 1/)

--E

.0 ro 30000 0::::

3 0

u:::

1/)

1/)

ro

~

20000 10000 L-~--~--~--~~--~--~--~--~~--~--~--~--~~

0 5 10 15 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD RCS TOTAL LOOP FLOW RATE (MDNBR CASE)

FIGURE 15.2.7-24

Steam Generator Pressures Loss of External Load (MDNBR Case)

e SG-1 1000

                      • SG-2 ro-

'(i)

.3:

<1.>

I 1/)

1/)

<1.>

CL C)

(f) 900 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD STEAM GENERATOR PRESSURES (MDNBR CASE)

FIGURE 15.2.7-25

Reactivity Feedback Loss of External Load (MDNBR Case)

5. 0 .------.-----.-----.----,---.,---,-------,-----,-----.----y--.---,..------.-----,----,

0.0 --- - - - - ---- ---- --+------.. . . . .=*~;".;0'" " * - * - *- *-*** *"'"' -.-:- :::.:-:.::-..-:-..:-:~--~--~-~******** ****-

e;::- ----Total

  • *** ******* Moderator
  • -a - - -
  • Doppler ro Q) - _ ..,Scram 0:::

-5. 0

- 10. 0 '-----'-----'-----'----'---'---J__---'-----'-----'----'----'---J__---'-----'----'

0 5 10 15 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF EXTERNAL LOAD REACTIVITY FEEDBACK (MDNBR CASE)

FIGURE 15.2.7-26

15.2.8 LOSS OF NORMAL FEEDWATER FLOW 15.2.8.1 Identification of Causes 15.2.8.1.1 Loss of Normal Feedwater The loss of normal feedwater flow accident is defined as a reduction in feedwater flow to the steam generators (SGs) when operating at power, without a corresponding reduction in steam flow from the steam generators. The result of this mismatch is a reduction in the water inventory in the steam generators.

The condensate and feedwater system is described in Section 10.4.6 and the system flow path and components are shown on Figures 10.1-2(a-d).

A complete loss of feedwater flow to the steam generators results when (1) malfunctions in the feedwater regulating systems for both steam generators cause all feedwater regulating valves to close; (2) the loss of all feedwater or condensate pumps is assumed; (3) in manual feedwater control, the operator either closes the feedwater regulating valves or closes the feedwater stop valves; or (4) a main feedwater header ruptures (check valves in each line downstream of the header prevent blowdown of the steam generators through such a rupture).

The auxiliary feedwater system is described in Section 10.5 and shown on Figure 10.5-2. It is available to provide sufficient feedwater flow to remove residual heat generation from the reactor coolant system following reactor trip from rated power. The AFS system consists of one noncondensing steam turbine driven auxiliary feedpump and two motor driven auxiliary feedpumps. The reactor protective system provides protection by the Steam Generator Low Liquid Level Trip.

The acceptance criteria for this event is to maintain the capability to transfer heat loads from the reactor system to a heat sink during operational occurrences.

A complete and instantaneous loss of feedwater flow is assumed for this analysis because this provides the greatest reduction in steam generator liquid inventory. Per the initial FSAR (Revision 36-12/20/74),

the steam generators are designed to withstand the thermal shock and loading imposed by a total loss of feedwater and subsequent refill transient (also see Section 5.5.1).

15.2.8.1.2 Feedwater System Pipe Breaks This event is a cooldown event in the licensing basis for the plant. As such, the feedwater pipe break event is bounded by the steamline break event since the area for flow in a broken feedwater pipe is less than that of a severed steamline. The smaller area for flow results in a lower steam relief rate which produces a more benign event.

The heat-up aspect of the event is analyzed in UFSAR 10.5.3 to demonstrate that adequate cooling can be provided to remove post-trip decay heat.

15.2.8.2 Analysis of Effects and Consequences Three subevents are postulated for this event; (1) maximum Primary System Pressure, (2) Minimum Departure from Nucleate Boiling Ratio (MDNBR), and (3) long term cooling. The sections below describe the analysis performed and the results obtained for these three subevents.

15.2.8-1 Amendment No. 26 (11/13)

15.2.8.2.1 Maximum Primary System Pressure This event is characterized by a heatup of the primary fluid as heat transfer is degraded when the steam generator inventory is depleted. This event is bounded by the Loss-of-External-Load (LOEL) event, Section 15.2.7. The termination of steam flow in the LOEL event causes a more severe pressurization of the primary and secondary systems.

15.2.8.2.2 Minimum Departure from Nucleate Boiling Ratio (MDNBR)

This event is not limiting with respect to DNBR and is insensitive to fuel design.

15.2.8.2.3 Long Term Cooling This event is initiated by a malfunction of the main feedwater (MFW) system, resulting in the total loss of normal feedwater flow to both steam generators (SGs). A sudden loss of subcooled MFW flow causes SG heat removal rates to decrease and SG levels to drop as the plant continues to operate at power.

This, in turn, causes reactor coolant tempeatures to increase. The reactor coolant expands, surging into the pressurizer.

SG liquid levels, which have been steadily dropping since the termination of MFW flow, soon reach the low SG level reactor trip setpoint. This initiates a reactor scram, thereby ending the short-term-heatup phase of the event.

The automatic turbine trip at reactor scram, in conjunction with the continuing primary to secondary transfer of the core decay heat and the reactor coolant pump (RCP) heat, cause SG pressures to increase.

SG levels continue to drop and soon reach the low-low SG level auxiliary feedwater (AFW) actuation setpoint. This initiates the starting sequence for the AFW pumps.

As the delivery of AFW begins and the decay heat level drops, liquid levels in the fed SG stabilize and then begin to rise, which causes reactor coolant temperatures to stabilize and then to begin to decrease.

The single active failure assumed for this event is the loss of the turbine-driven AFW pump. The turbine-driven pump is higher capacity than a motor-driven AFW pump, so its loss produces more severe consequences.

The key input parameters and their values listed in Table 15.2.8-1 were used in the analysis of this event and are consistent with the approved Reference 117 methodology.

  • Initial Conditions - This event was analyzed from hot full power (HFP) which produces the highest decay heat level and the most significant challenge to the AFW system to remove decay heat.
  • Reactivity Feedback - Since this event involves an increase in the core coolant temperature, the event is assumed to occur at beginning of cycle (BOC) with a maximum TS/core operating limits report (COLR) moderator temperature coefficient (MTC) at full power. However, this event is generally not sensitive to neutronic parameters.
  • Decay Heat - Decay heat was calculated using the 1973 ANS standard plus actinides in accordance with the approved methodology.
  • Reactor Protection System (RPS) Trips and Delays - This event is primarily protected by the low SG level trip. The RPS trip setpoints and response times were conservatively biased to delay the actuation of the trip function. In addition, control rod insertion is delayed to account for the CEA holding coil delay time.
  • Steam Generator Blowdown - SG blowdown is assumed to be in operation during this event.

15.2.8-2 Amendment No. 26 (11/13)

  • Offsite Power - To maximize RCP heat, it was assumed that offsite power was available and that the RCPs continued to run with a conservative heat input of 20 MWt.
  • Auxiliary Feedwater - Two motor-driven AFW pumps were assumed to deliver AFW flow to each SG. A single failure of the higher capacity turbine-driven AFW pump was assumed. These assumptions minimized the SG inventory during the event, thereby maximizing the challenge to the acceptance criteria.

Under EPU conditions, higher power level produces higher heat load on SGs, promoting faster depletion of SG inventory, and higher decay heat increases the challenge to long term decay heat removal. This increases the challenge to the capability of the MSSVs and AFW to remove decay heat. The increase in RCS temperature for the EPU does not significantly affect the consequences of the event.

The sequence of events for this analysis is given in Table 15.2.8-2. The analysis showed that a reactor trip on low steam generator level occurred at 31.8 seconds. Figure 15.2.8-1 gives the liquid inventory in the EC288300 steam generators as a function of time. The liquid inventories continue falling after AFW initiation at 364 seconds, though at a slower rate. The steam generator levels continue to fall until the decay heat falls far enough for the AFW flow to match the steam flow through the MSSVs. The minimum SG liquid inventory of EC288300 0 lbm occurred at 269 seconds for SG-1 and 274 seconds for SG-2. The analysis demonstrated that the acceptance criteria are satisfied.

UNIT 1 15.2.8-2a Amendment No. 29 (10/18)

TABLE 15.2.8-1 PLANT INITIAL CONDITIONS AND KEY PARAMETERS FOR LOSS OF NORMAL FEEDWATER ANALYSIS PARAMETER VALUE Core Power 3,020 MWt + 0.3%

Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Pressurizer Level 68.6%

Moderator Temperature Coefficient +2 pcm/°F Doppler Reactivity Coefficient -0.8 pcm/°F Steam Generator Initial Pressure 830 psia Steam Generator Initial Liquid Level 65% Narrow Range Low SG Level RPS Trip 25% Narrow Range Low SG Level ESF Trip (AFW) 14% Wide Range AFW Flow Rate 276 gpm per motor-driven pump (2 electric motor-driven pumps)

AFW Temperature 111.5°F Steam Generator Blowdown Flow 120 gpm per SG MSSV Setpoints Bank 1: 1,000 psia + 3%

Bank 2: 1,040 psia + 3%(*)

Single Failure Loss of Turbine Driven AFW Pump Reactor Regulating System Manual Mode Steam Dump and Bypass System Inoperative Feedwater Regulating System Inoperative Auxiliary Feedwater System Automatic Mode

  • Tolerance used for MSSV Bank 2 opening setpoint is conservatively bounding.

UNIT 1 15.2.8-3 Amendment No. 27A (01/16)

TABLE 15.2.8-2 SEQUENCE OF EVENTS FOR LOSS OF NORMAL FEEDWATER ANALYSIS EVENT TIME (SEC.)

Total loss of main feedwater 0.0 Low SG level trip setpoint reached 31.8 Reactor trip on low SG level (including response delay),

and turbine trip on reactor trip 32.7 CEA insertion begins 33.2 Low steam generator level AFAS setpoint reached in SG-2 34.2 Low steam generator level AFAS setpoint reached in SG-1 34.2 Maximum pressurizer pressure 35.1 First opening of Bank 1 MSSVs in both loops 35.1 EC288300 CEAs fully inserted 36.1 First opening of Bank 2 MSSVs in both loops 37.1 Closure of Bank 2 MSSVs in both loops 49.0 Minimum SG-1 liquid inventory 269 Minimum SG-2 liquid inventory 274 Motor-driven AFW pumps begin delivery to feedwater lines, which begins sweepout of hot MFW into the SGs 364 Maximum pressurizer level 686 Feedwater piping purged of hot MFW ~759 Maximum RCS average temperature 1,504 Maximum hot leg temperature 1,507 Minimum hot leg subcooling 1,789 UNIT 1 15.2.8-4 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 LOSS OF FEEDWATER FLOW EVENT STEAM GENERATOR INVENTORIES FIGURE 15.2.8-1 Amendment No. 29 (10/18)

15.2.9 LOSS OF OFFSITE POWER TO THE STATION AUXILIARIES 15.2.9.1 Identification of Causes The loss of offsite power (LOOP) event is evaluated to determine that the DNBR limit will not be exceeded and the site boundary doses will not exceed the 10 CFR 100 guidelines.

Loss of offsite power (LOOP) is defined as a complete loss of offsite electrical power and a concurrent turbine trip. As a result of such an accident, electrical power would be unavailable for the reactor coolant pumps and main feedwater pumps. Under such circumstances, the plant would experience a simultaneous loss of load, a loss of feedwater flow and a loss of forced reactor coolant flow.

The loss of offsite power is followed by automatic startup of the emergency diesel generators. The power output of each is sufficient to supply electrical power to all engineered safety features and to ensure the capability of establishing and maintaining the plant in a safe shutdown condition. Since emergency power is not available for the control element assembly drive mechanisms (CEDMs), the deenergization of the CEDM magnetic holding coils releases the CEAs and allows them to drop into the core. Thus, the possibility of core damage is prevented by the prompt tripping of the reactor. The reactor is tripped by a low reactor coolant flow rate signal.

Numerous visual and audible alarms are incorporated in the control room for the purpose of warning the operator if limiting conditions are approached or if off normal conditions exist for any system. As a consequence of LOOP any of several alarms would serve to inform the operator as to the nature of the situation. The following trip (and pretrip) signals provide audible and visual indications to the operator during the course of the accident:

15.2.9-1 Amendment No.26 (11/13)

a) Turbine trip b) Reactor coolant low flow trip c) Low steam generator water level trip.

Power to the instrumentation required for these alarms and trips is supplied by the emergency power supply described in Section 8.3.1.1.6.

Subsequent to reactor trip, stored heat and fission product decay heat must be dissipated. In the absence of forced reactor coolant flow, convective heat transfer through the core is maintained by natural circulation. Initially, the residual water inventory in the steam generators is used and steam is released to the atmosphere via the steam generator safety valves. Subsequent to the availability of standby power, plant cooldown is controlled via atmospheric steam dump valves.

15.2.9.2 Analysis of Effects and Consequences The loss of AC power event is defined as a complete loss of offsite electrical power and a concurrent turbine trip. Under such circumstances, the plant would experience a simultaneous loss of load, a loss of main feedwater flow, and a loss of forced reactor coolant flow.

The early part of the event (0-10 seconds) is similar to the loss of forced reactor coolant flow event (four-RCP coastdown) (Section 15.2.5) because the steam generator inventory would not have been reduced sufficiently to affect heat removal, and there is no pressure increase due to loss of load. Therefore, the DNB SAFDL is essentially the same as that for the loss of forced reactor coolant flow event.

The challenge to peak primary and secondary overpressure for the loss of AC power event (with secondary-system isolation near the time of reactor scram) is bounded by the loss of external load event, with secondary-system isolation at event initiation and continued reactor power operation for a considerable period of time (Section 15.2.7). Due to natural circulation and the associated higher long-term average RCS temperature for the loss of AC power event relative to the loss feedwater flow event (Section 15.2.8), the loss of AC power event will result in a slightly higher pressurizer level than for the loss of feedwater flow event. However, the loss of feedwater flow event does not significantly challenge pressurizer overfill; thus, the loss of AC power event will not challenge pressurizer overfill.

The loss of AC power event is bounded by the loss of normal feedwater flow event (Section 15.2.8) regarding minimum steam generator inventory because the loss of feedwater flow event has continued RCP operation with its associated pump heat input to the RCS. In addition, with the RCPs running, the average long-term RCS temperature will be lower than for the loss of AC power event with natural circulation, thus more energy must be removed from the RCS for the loss of feedwater flow event.

15.2.9-2 Amendment No. 26 (11/13)

DELETED 15.2.9-3 Amendment No. 26 (11/13)

DELETED 15.2.9-4 Amendment No. 26 (11/13)

DELETED 15.2.9-5 Amendment No. 26 (11/13)

DELETED 15.2.9-5a Amendment No. 18, (04/01)

DELETED 15.2.9-6 Amendment No. 26 (11/13)

DELETED 15.2.9-7 Amendment No. 26 (11/13)

DELETED 15.2.9-8 Amendment No. 26 (11/13)

DELETED 15.2.9-9 Amendment No. 26 (11/13)

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF NORMAL ON-SITE, OFF-SITE ELECTRICAL POWER EVENT CORE POWER VS. TIME FIGURE 15.2.9-1

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF NORMAL ON-SITE, OFF-SITE ELECTRICAL POWER EVENT CORE AVERAGE HEAT FLUX VS. TIME FIGURE 15.2.9-2

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF NORMAL ON-SITE, OFF-SITE ELECTRICAL POWER EVENT REACTOR COOLANT SYSTEM TEMPERATURES VS. TIME FIGURE 15.2.9-3

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF NORMAL ON-SITE, OFF-SITE ELECTRICAL POWER EVENT REACTOR COOLANT SYSTEM PRESSURE VS. TIME FIGURE 15.2.9-4

DELETED Amendment No. 26 (11/13)

FLORIDA POWER AND LIGHT COMPANY ST.LUCIE PLANT UNIT 1 LOSS OF NORMAL ON-SITE, OFF-SITE ELECTRICAL POWER STEAM GENERATOR PRESSURE VS. TIME FIGURE 15.2.9-5

15.2.10 EXCESS HEAT REMOVAL DUE TO FEEDWATER SYSTEM MALFUNCTIONS 15.2.10.1 Identification of Causes There are two possibilities for excessive cooling action by the feedwater to the steam generators:

decrease of temperature or increase of flow. These two types of accidents are discussed in this section.

Excessive feedwater cooling action may result in a lower temperature in the reactor coolant system, higher reactor power due to a negative moderator temperature coefficient and high water levels in the steam generators. Protection against these undesirable conditions is provided by steam generator water level alarms with automatic or manual control actions to reduce feedwater flow and in extreme cases by reactor trips due to high neutron flux, low pressurizer pressure, thermal margin/low pressure, or low steam generator pressure.

A decrease in feedwater temperature may be caused by:

a) Loss of one of several feedwater heaters. The loss could be due to interruption of steam extraction flow or to an accidental opening of a feedwater heater bypass line. The high pressure heaters increase the feedwater temperature by 56F at full load. In order to lose this heating, two valves (one per extraction line) would have to be closed. The loss of any of the low pressure heaters before the feedwater pumps will produce a lesser effect due to the compensating effect of the high pressure heater in the cycle. The modifications done for EPU increased the feedwater temperature rise, but it remains below 100°F.

b) Accidental starting of the auxiliary feedwater system. The auxiliary feedwater system supplies relatively cold water from the condensate storage tank to the steam generators; an accidental starting of this system would, therefore, simultaneously decrease feedwater temperature and increase feedwater flow. Since the maximum capacity of an auxiliary feedwater pump is about 2 percent of nominal full power flow, this accident has a smaller effect on the reactor than the other accidents discussed in this section.

An increase in feedwater flow may be caused by complete opening of a feedwater control valve.

Complete opening of both feedwater control valves can increase feedwater flow by about 20 percent above nominal. Since the two valves and their control are independent, the maximum flow increase is considered to be by action of a single valve and is, therefore, 10 percent above nominal. A description of the feedwater regulating system is given in Section 7.7.1.3.1.

15.2.10.2 Analysis of Effects and Consequences 15.2.10.2.1 Decrease in Feedwater Temperature This event is initiated by a reduced feedwater temperature at full power. A decrease in feedwater temperature may be caused by a loss of one of several feedwater heaters or an accidental starting of the AFW system. The sudden reduction in feedwater temperature results in a cooldown of the SG, a temperature and pressure decrease in the RCS, and a higher power with a most negative MTC at EOC.

The increase in power and reduction in RCS pressure during the transient cause a decrease in DNB margin, while the decrease in RCS temperature during the transient causes an increase in DNB margin.

The overall effect is a decrease in DNB margin and a challenge to the DNB SAFDL. However, the increase in heat removal due to a decrease in feedwater temperature is far less than that for the increase in steam flow event. The operating conditions for the EPU will not change the relative behavior and severity of this event. This event remains bounded by the increase in steam flow event (Section 15.2.11).

15.2.10-1 Amendment No. 26 (11/13)

15.2.10.2.2 Increase in Feedwater Flow An increase in feedwater flow event, initiated at HFP, is caused by the complete opening of a single feedwater control valve because the two feedwater control valves and their control are independent. This event is addressed in Section 15.2.2.

15.2.10-2 Amendment No. 26 (11/13)

DELETED 15.2.10-3 Amendment No. 26 (11/13)

15.2.11 EXCESS LOAD 15.2.11.1 Identification of Causes The increase in steam flow (or excess load increase) event is defined as any rapid increase in steam generator steam flow other than a steam line rupture (discussed in Section 15.4.6). It is initiated by a postulated failure or misoperation of the main steam system and results in an increase in steam flow from the steam generators.

As discussed in Section 7.7.2.3.2, the steam dump and bypass system is designed based on the criteria that no single component failure or operator incorrect action can cause the improper opening of more than one dump valve. However, for analysis purposes, the postulated initiating events include the opening of all steam dump and bypass valves or the opening of the turbine control valves due to controller failure.

At hot full power (HFP), the increase in steam flow creates a mismatch between the energy being generated in the reactor core and the energy being removed by the secondary system and results in a cooldown of the primary system. A power increase will occur if the moderator temperature reactivity feedback coefficient is negative. If the power increase is sufficiently large, either overpower or thermal margin limits will be reached with the event being terminated by a reactor trip. If the power increase is less significant, the reactor will stabilize at an elevated power level without reaching a reactor trip and with no violation of any safety limit.

At hot zero power (HZP), the result of the increase in steam flow is a power mismatch between the primary and secondary systems. The immediate response to the additional steam flow demand is a rapid decrease in SG pressure. The SG temperature will also rapidly decrease, as more heat (steam) is being extracted than is being added. Since the reactor is not producing any heat, the secondary side cools down the primary side. The RCS temperature will decrease and the pressurizer pressure and level will consequently decrease. In the presence of a negative moderator temperature coefficient (MTC) and a negative Doppler reactivity coefficient, positive reactivity insertion will occur in response to the decreasing coolant and fuel temperatures. These feedbacks cause an increase in core power which slows down the decrease in core coolant temperatures. As the core power and fuel temperatures increase, the negative Doppler reactivity coefficient tends to mitigate the rapid increase in power. The core power will increase at an exponential rate until the setpoint on the variable high power trip (VHPT) is reached and initiates a reactor trip. With the decreasing level and pressure, the charging pumps and pressurizer heaters will automatically turn on. Since the pressurizer pressure and level control systems are not safety grade, no credit is allowed for this automatic feature to mitigate the decrease in level and pressure.

The following load increase incidents have been examined and have been determined to be the most severe in the following cases:

"A" Opening of all steam dump and bypass valves at power due to turbine trip permissive failure: The circuit between the steam dump controller and the dump valves is open while the turbine generator is on line. Should the turbine trip permissive fail closed under load conditions it would, according to the temperature program of the controller, cause full opening of the dump and bypass valves.

"B" Opening of the steam dump and bypass valves at hot standby conditions due to steam dump controller malfunction: The most severe incident for this case at hot standby would occur for the case in which it is assumed that the steam dump valve controller yields an incorrect signal and causes the steam dump and bypass valves to completely open, leaving the auto-manual controller in the control room as the means of closure. This case represents the upper limit under hot standby condition.

"C" Opening of the turbine control valves at hot standby or at power due to controller failure: The most rapid load increase at hot standby would occur for the case in which it is assumed that the turbine control valves opened completely.

15.2.11-1 Amendment No. 26 (11/13)

15.2.11.2 Analysis of Effects and Consequences The most limiting load increase events at full power and hot zero power conditions occur for the complete opening of the steam dump and bypass valves. Of these two events, the full power case is the more limiting case (i.e., approaches closer to the acceptable DNBR and FCM limits).

Detailed analyses were performed with the approved non-LOCA methodology given in Reference 117.

For this event, the S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures), and peak system pressures. The core fluid boundary conditions and average rod surface heat flux were then input to XCOBRA-IIIC code (Reference 108), which was used to calculate the MDNBR using the high thermal power (HTP) critical heat flux (CHF) correlation (Reference 110).

Input Parameters, Assumptions and Acceptance Criteria The key input parameters and their values used in the analysis of this event are consistent with the approved Reference 117 methodology. The analysis parameters used in the HFP and HZP analyses are shown in Tables 15.2.11-1 and 15.2.11-2, respectively.

  • Initial Conditions - Two sets of initial conditions were considered. First, the event was assumed to initiate from HFP conditions with a maximum core inlet temperature and TS minimum RCS flow (Table 15.2.11-1). This set of conditions minimizes the initial margin to departure from nucleate boiling (DNB),

A second set of conditions (Table 15.2.11-2) assumed that the event initiated from a HZP condition. The core inlet temperature was set to the HZP value with TS minimum RCS flow.

  • Reactivity Feedback - The reactivity feedback coefficients were biased according to the improved methodology. For the cases initiated from HFP, a range of negative moderator reactivity feedback was analyzed up to an MTC that bounds the most negative TS limit. Negative moderator reactivity feedback leads to higher power levels during the event as a result of the primary system cooldown. Doppler reactivity was biased to minimize the effects of negative feedback from increasing fuel temperatures.

For HZP initiated cases, the most negative MTC permitted by the TS/core operating limits report (COLR) was assumed. Doppler reactivity was biased to minimize the effects of negative feedback from increasing fuel temperatures.

  • Reactor Protection System Trips and Delays - The event is primarily protected by the VHPT, which terminates the moderator feedback driven power excursion. The RPS trip setpoints and responses were conservatively biased to delay the actuation of the trip function. In addition rod insertion was delayed to account for CEA holding coil delay time.

The overcooling of the primary system results in decalibration of both the excore nuclear detectors and calculated thermal power signal used as inputs to RPS trips. This results in a delay for the RPS reactor power to reach VHPT setpoint. In addition, the resistance thermal detector (RTD) delay times for the hot leg and cold leg were conservatively biased to minimize the measured thermal power and further delay the VHPT.

  • Feedwater Systems - The main feedwater (MFW) control valve was assumed to increase the feedwater flow in response to the perceived increase in steam flow. For the HFP case, a maximum MFW flow rate of 150% of rated flow was modeled. The auxiliary feedwater (AFW) system was modeled to provide maximum flow at a minimum temperature 40°F to exacerbate the cooldown of the RCS for the HZP case.
  • Steam Dump and Bypass System - A bounding capacity of 8.0 Mlbm/hr was assumed as the initiator of this event. Maximizing the capacity of the steam bypass control system (SBCS) worsens the cooldown of the RCS and the moderator reactivity driven power response.

UNIT 1 15.2.11-1a Amendment No. 28 (05/17)

  • Gap Conductance - Gap conductance was set to a conservative end of cycle (EOC) value to maximize the heat flux through the cladding and minimize the negative reactivity inserted due to Doppler feedback.
  • Steam Generator Tube Plugging (SGTP) - No SGTP was assumed so as to maximize the primary-to-secondary side heat transfer, which exacerbates the reactivity insertion due to moderator feedback.
  • Single Failure - Prior to scram, there is no single failure that will adversely affect the consequences since the systems designed to mitigate this event (namely, the RPS) are redundant. After scram, the worse single failure is the failure of one high pressure safety injection (HPSI) pump to start and deliver boron to the core.

The principally challenged acceptance criterion for this event is:

This criterion is met by assuring that the minimum calculated departure from nucleate boiling ratio (DNBR) is not less than the 95/95 DNB correlation limit. Additionally, fuel centerline melt is demonstrated to be precluded in the most adverse location in the core.

15.2.11.2.1 Excess Load Event at Full Power This section describes an Excess Load analysis for the St. Lucie Unit 1 nuclear power plant. This analysis addresses the thermal-hydraulic core characteristics resulting from an Excess Load event.

The scope of this analysis includes:

- Plant transient response calculations S-RELAP5,

- Core thermal-hydraulic calculations XCOBRA-IIIC,

- MDNBR calculations, and

- Peak LHR calculations.

The load increase event may be caused by one of the following initiating events at the HFP:

  • Section 15.2.11.1 Event A: Opening of all steam dump and bypass valves at power due to turbine trip permissive failure: The circuit between the steam dump controller and the dump valves is open while the turbine generator is on line. Should the turbine trip permissive fail closed under load conditions it would, according to temperature program of the controller, cause full opening of the dump and bypass valves.
  • Section 15.2.11.1 Event C: Opening of the turbine control valves at power due to controller failure.

A range of increased steam flow rates was considered from fully opening the turbine control valves up to an excess steam release bounding the capacity of the steam dump and bypass control system (SBCS) flow rate (i.e. excess steam release of 8.0x106 lbm/hr). This range of increased steam flow rates bounds the excess load event, which is limited by the opening of the steam dump and bypass valves, resulting in an increase in steam flow to approximately 160% of rated load, which bounds the steam dump and bypass system capabilities as described in Section 7.7.1.3.2. A range of MTC values from -5 pcm/°F to -

35 pcm/°F was considered for the maximum excess load case to determine the limiting MDNBR and FCM cases.

This analysis also includes the effects of power decalibration. Power decalibration is caused by density-induced changes in the reactor vessel downcomer shadowing of the power-range ex-core detectors during heatup or cooldown transients. The nuclear power levels indicated by those instruments are lower than the actual reactor power levels when the coolant entering the reactor vessel is cooler than the normal temperature for full-power operation (and higher when the vessel inlet coolant is warmer than the normal full-power temperature). This effect is included in the modeling of the power-dependent reactor trips credited in this analysis. The VHPT, the TM/LP trip function, and the LPD trip all depend on the indicated nuclear power level.

UNIT 1 15.2.11-2 Amendment No. 28 (05/17)

Analysis Results The limiting MDNBR and LHR results for the cases analyzed are described below.

The transient is initiated by an increase in steam flow. A steam flow of 8.0 Mlbm/hr, which bounds the maximum capacity of the SBCS, was found to most challenge the acceptance criteria. The sequence of events for the limiting case (maximum load increase and MTC of -29.6 pcm/°F is presented in Table 15.2.11-2 and the primary and secondary system responses are presented in Figures 15.2.11-1 through 15.2.11-8. The increased steam flow (see Figure 15.2.11-7) creates a mismatch between the core heat generation rate and the steam generator heat removal rate. This power mismatch causes the primary-to-secondary heat transfer rate to increase, which in turn causes the primary system to cool down (see Figure 15.2.11-4). With a negative MTC (see Figure 15.2.11-8), the primary system cooldown causes the reactor power level to increase (see Figures 15.2.11-1 and 15.2.11-2). The core power continues to increase until reactor scram occurs on VHPT ceiling. This terminates the power excursion. The limiting MDNBR was calculated to be above the 95/95 CHF correlation limit. The peak linear heat rate (LHR) was calculated to be less than the fuel centerline melt limit.

UNIT 1 15.2.11-2a Amendment No. 28 (05/17)

15.2.11.2.2 Excess Load Event at Hot Zero Power For the HZP event, the potential event initiators in St. Lucie Unit 1 are:

  • Section 15.2.11.1 Event B: Opening of the steam dump bypass valves at hot standby conditions due to steam dump controller malfunction: The most severe incident for this case at hot standby would occur for the case in which it is assumed that the steam dump valve controller yields an incorrect signal and causes the steam dump and bypass valves to completely open, leaving the auto-manual controller in the control room as the means of closure.
  • Opening of the turbine control valves at hot standby due to control failure: The most rapid load increase at hot standby would occur for the case in which it is assumed that the turbine control valves opened completely.

A single bounding case was analyzed, biased to maximize the challenge to thermal margins, considering a full opening of all turbine control valves, and the most negative MTC permitted by Technical Specifications.

An Excess Load Increase event initiated from criticality will be more adverse than an event initiated from a subcritical condition, because the positive reactivity insertion due to moderator feedback is not initially counteracted by the additional negative reactivity in the core (in excess of that introduced by the SCRAM). An Excess Load Increase event initiated from extremely low power conditions (e.g. 10-9 of rated) will also be more adverse than one initiated from higher power conditions (e.g. 1% RTP), because the power increase will be delayed until a significant amount of positive reactivity has been inserted into the core.

Therefore, the assumed plant state of an initial power level of 10-9 of rated, in conjunction with a core just at criticality (i.e. in other words, a Mode 2 condition) will produce a core power response that bounds both Mode 2 and Mode 3 operation.

In Mode 1 operation, the RPS functions are available and active, which means that the VHPT delays will be far less than they are for the case where a low-power bypass cancellation delay must be accounted for. Additionally, the minimum power level for Mode 1 operation permitted by the technical specifications is 5% of rated. At this power level, the power excursion will be far less dramatic than it would for the case initiated from 10-9 of rated power. For these two reasons, the HZP event analyzed considering a bounding Mode 2 initial state also bounds the possibility of the event initiated from a low-power Mode 1 condition.

Analysis Results The Zero Power Excess Load Event was initiated at the conditions given in Table 15.2.11-3. The most negative MTC permitted by the Technical Specifications/ Core Operating Limits Report (COLR) was assumed in this analysis. This MTC, in conjunction with the decreasing coolant inlet temperature enhances the rate of increase in the core heat flux at the time of reactor trip. Doppler reactivity was biased to minimize the effects of negative feedback from increasing fuel temperatures. The minimum HZP CEA shutdown worth available is conservatively assumed in this analysis. The VHP Trip is set to the minimum value plus maximum uncertainty. The VHP Trip delay is augmented by an additional delay that compensated for trip bypass cancellation delay as power increases above 1% RTP.

The sequence of events for the zero power case is presented in Table 15.2.11-4. The transient response is shown in Figures 15.2.11-9 to 15.2.11-17. Figure 15.2.11-9 shows the reactor power as a function of time. Figure 15.2.11-10 shows the core power based on rod surface heat flux. Figures 15.2.11-11 through 15.2.11-17 show the pressurizer pressure, the RCS loop temperatures, the total RCS flow rate, the SG pressures, the steam and feedwater flow rates, the reactivity feedback, and the peak fuel centerline temperature, respectively.

The MDNBR is greater than the 95/95 CHF correlation limit and was calculated to be bounded by that for EC292529 the HFP case. The peak centerline temperature during the event was calculated to be less than the fuel melt temperature limit.

15.2.11-2b Amendment No. 30 (05/20)

15.2.11.2.3 Radiological Analysis See Section 15.2.11.3.2.

15.2.11-2c Amendment No. 26 (11/13)

15.2.11.2.4 Conclusions For the full and zero power excess load events initiated by a full opening of the steam dump and bypass valves, the DNBR and FCM limits are not exceeded. In addition, the core remains subcritical following automatic initiation of the auxiliary feedwater flow and manual tripping of the RCPs on SIAS due to low pressurizer pressure. The reactivity transient during a HFP and HZP excess load event is less limiting than the corresponding steam line rupture events. (Tripping of the RCPs is a conservative analysis assumption).

Inadvertent opening of a turbine control valve produces consequences less severe than opening of the steam dump and bypass valves for both the HFP and HZP cases.

15.2.11.3 DELETED 15.2.11.3.1 DELETED 15.2.11-2d Amendment No. 26 (11/13)

15.2.11.3.2 Radiological Consequences for Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.2.11.3.2.1 Background This event is caused by an Inadvertent Opening of a Steam Generator MSSV. Due to the pressure differential between the primary and secondary systems and assumed steam generator tube leakage, fission products contained in the primary coolant before the accident are discharged from the primary into the secondary system. The analysis assumes that the SG tubes do not remain covered and therefore no credit is taken for scrubbing in the SG nor is credit taken for a flashing fraction for the primary leakage into the SGs. As a result, all of this leaked RCS radioactivity is released to the outside atmosphere from the secondary coolant system through the steam generator via the MSSVs. In addition, all of the activity initially present in the SGs is assumed to be released to the environment over a 2-hour period.

Radiological releases due to the opening of a power operated atmospheric dump valve are bounded by the stuck open MSSV event. The St. Lucie Unit 1 AST dose analysis methodology is presented in Reference 107.

15.2.11.3.2.2 Compliance with RG 1.183 Regulatory Positions Since Regulatory Guide (RG) 1.183 does not provide specific guidance for this event, the guidance of Appendix G for the RCP Shaft Seizure (Locked Rotor) event is judged to be closely applicable to the conditions of an inadvertent open MSSV. Therefore the following discussion for the IOMSSV refers to the RG 1.183 positions as stated in Appendix G for the Locked Rotor event.

1. Regulatory Position 1 - No fuel damage is postulated to occur. The source term for this event is due to the initial RCS and Secondary side activity present at the beginning of the event.
2. Regulatory Position 2 - No fuel damage is assumed for this event.
3. Regulatory Position 3 - The activity released from the fuel is assumed to be released instantaneously and homogeneously through the primary coolant.
4. Regulatory Position 4 - Iodine releases from the SGs to the environment are assumed to be 97%

elemental and 3% organic.

5. Regulatory Position 5.1 - The primary-to-secondary leak rate is apportioned between the SGs as specified by TS 6.8.4.l (0.5 gpm total, 0.25 gpm to any one SG). Thus, the tube leakage is apportioned equally between the two SGs.
6. Regulatory Position 5.2 - The density used in converting volumetric leak rates to mass leak rates is based upon RCS conditions, consistent with the plant design basis. The SG tube leakage mass flow rate is provided in Table 15.2.11-6.
7. Regulatory Position 5.3 - The primary-to-secondary leakage is assumed to continue until after shutdown cooling has been placed in service and the temperature of the RCS is less than 212°F.
8. Regulatory Position 5.4 - The analysis assumes a coincident loss of offsite power.
9. Regulatory Position 5.5 - All noble gas radionuclides released from the primary system are assumed released to the environment without reduction or mitigation.

15.2.11-2e Amendment No. 24 (06/10)

10. Regulatory Position 5.6 - The steam generator tubes are not assumed to remain covered throughout this event for St. Lucie Unit 1. Therefore, the iodine and transport model for release from the SGs is as follows:
  • Appendix E, Regulatory Position 5.5.1 - Both steam generators are assumed to dryout.

Therefore, all of the primary-to-secondary leakage is assumed to flash to steam and be released to the environment with no mitigation.

  • Appendix E, Regulatory Position 5.5.2 - All of the SG tube leakage is assumed to flash for this event.
  • Appendix E, Regulatory Position 5.5.3 - All of the SG tube leakage is assumed to flash for this event.
  • Appendix E, Regulatory Position 5.5.4 - The radioactivity within the bulk water in the SGs is assumed to be released directly to the environment over a 2-hour period.
  • Appendix E, Regulatory Position 5.6 - Steam generator tube bundle uncovery is postulated for this event for St. Lucie Unit 1.

15.2.11.3.2.3 Other Assumptions

1. The initial RCS activity is assumed to be at the TS 3.4.8 limit of 1.0 µCi/gm Dose Equivalent I-131 and 518.9 Ci/gm DE XE -133 gross activity. The initial SG activity is assumed to be at the TS 3.7.1.4 limit of 0.1 µCi/gm Dose Equivalent I-131.
2. This evaluation assumes that the RCS mass remains constant throughout the event.
3. The entire contents of both steam generators are assumed to be released to the environment over a 2-hour period.

15.2.11.3.2.4 Methodology Input assumptions used in the dose consequence analysis of the Inadvertent Opening of a MSSV event are provided in Table 15.2.11-5. Primary coolant is released to the SGs as a result of postulated primary-to-secondary leakage. The activity in the RCS tube leakage is released directly to the environment until being terminated at 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In addition, the entire secondary side activity is released to the environment over a 2-hour period.

For this event, the Control Room ventilation system cycles through three modes of operation:

  • Initially the ventilation system is assumed to be operating in normal mode. The air flow distribution during this mode is 920 cfm of unfiltered fresh air and an assumed value of 460 cfm of unfiltered inleakage.
  • After the start of the event, the Control Room is isolated due to a high radiation reading in the Control Room ventilation system. A 50-second delay is applied to account for diesel generator start time, damper actuation time, instrument delay, and detector response time. After isolation, the air flow distribution consists of 0 cfm of makeup flow from the outside, 460 cfm of unfiltered inleakage, and 1760 cfm of filtered recirculation flow.

At 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> into the event, the operators are assumed to initiate makeup flow from the outside to the control room. During this operational mode, the air flow distribution 15.2.11-2ea Amendment No. 26 (11/13)

  • consists of up to 504 cfm of filtered makeup flow, 460 cfm of unfiltered inleakage, and 1256 cfm of filtered recirculation flow.
  • The Control Room ventilation filter efficiencies that are applied to the filtered makeup and recirculation flows are 99% for particulate, 95% elemental iodine, and 95% organic iodine.

15.2.11.3.2.5 Radiological Consequences The Control Room atmospheric dispersion factors (/Qs) used for this event are based on the postulated release locations and the operational mode of the control room ventilation system. The release-receptor point locations are chosen to minimize the distance from the release point to the Control Room air intake.

For this event, all releases are assumed to occur from the ADV that produces the most limiting /Qs.

When the Control Room Ventilation System is in normal mode, the most limiting /Q corresponds to the worst air intake to the control room. When the ventilation system is isolated, the limiting /Q corresponds to the midpoint between the two control room air intakes. The operators are assumed to reopen the most favorable air intake at 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Development of control room atmospheric dispersion factors is discussed in Appendix 2J. The /Qs for this event are summarized in Table 15.2.11-7.

For the EAB dose analysis, the /Q factor for the zero to two-hour time interval is assumed for all time periods. Using the zero to two-hour /Q factor provides a more conservative determination of the EAB dose, because the /Q factor for this time period is higher than for any other time period. The LPZ dose is determined using the /Q factors for the appropriate time intervals. These /Q factors are provided in Appendix 2I.

RG 1.183 lists no specific acceptance criteria for this event; therefore, the most limiting dose limits are used. Per Section 4.4 and Table 6 of RG 1.183, the most limiting dose limits for the Exclusion Area Boundary (EAB), Low Population Zone (LPZ), and Control Room (CR) are:

Area Dose Criteria EAB 2.5 rem TEDE (for the worst two-hour period)

LPZ 2.5 rem TEDE (for 30 days)

Control Room* 5 rem TEDE (for 30 days)

Control room dose limit is specified in 10 CFR 50.67 The radiological consequences of the Inadvertent Opening of the MSSV event are analyzed using the RADTRAD-NAI code and the inputs/assumptions previously discussed. As shown in Table 15.2.11-8, the results of both cases for EAB dose, LPZ dose, and Control Room dose are all within the appropriate regulatory acceptance criteria given in Regulatory Guide 1.183.

15.2.11-2eb Amendment No. 26 (11/13)

Table 15.2.11-1 Excess Load: HFP Analysis Parameters Parameter Hot Full Power Core power 3,020 MWt + 0.3%

Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Pressurizer Level 65.6%

Scram Reactivity Minimum HFP Moderator Temperature Coefficient -5 to -35 pcm/°F Doppler Reactivity Coefficient -1.40 pcm/°F Gap Conductance Conservative EOC value RTD Delay Times 0 sec. (Thot) 10 sec. (Tcold)

Pressurizer PORV Available Pressurizer Heaters Disabled VHP RPS Trip Credited SBCS Capacity 8.0 Mlbm/hr MFW Capacity 150% rated SG Tube Plugging 0%

UNIT 1 15.2.11-2f Amendment No. 28 (05/17)

Table 15.2.11-2 Excess Load: Sequence of Events for HFP Limiting Case (Maximum (Load Increase, -29.6 pcm/°F)

Case Event Time (sec.)

Hot Full Power SBCS system opens to full capacity 0.0 VHPT setpoint reached 19.4 Reactor scram on VHPT (including trip response delay) 20.3 CEA insertion begins 20.8 Minimum (prior to scram) core inlet temperature reached 20.8 Peak neutronic power 20.8 Maximum clad surface heat flux 20.9 MDNBR 20.9 15.2.11-3 Amendment No. 26 (11/13)

TABLE 15.2.11-3 Excess Load: HZP Analysis Parameters Parameter Hot Zero Power Analysis Value Core Power 10-9 RTP Core Inlet Temperature 532°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Pressurizer Level 33%

Scram Reactivity Minimum HZP Moderator Temperature Coefficient -32 pcm/°F Doppler Reactivity Coefficient Bounding least negative feedback vs. fuel temperature Gap Conductance Conservative EOC value RTD Delay Times Inconsequential since thermal power was not credited Pressurizer PORV Available Pressurizer Spray Not modeled Pressurizer Heaters Disabled VHP RPS Trip 25% RTP (15% RTP plus 10% uncertainty)

VHP RPS Trip Delays 0.40 sec. for delay, plus 0.70 sec.

for bypass cancellation AFW Temperature 40°F AFW Flow Rate (Total) 2,950 gpm SBCS Capacity SBCS initiating event bounded by larger capacity of all TCV opening SIAS Credited SG Tube Plugging 0%

15.2.11-3a Amendment No. 26 (11/13)

Table 15.2.11-4 Sequence of Events for Excess Load Event at HZP Conditions Case Event Time (sec.)

Turbine control valves fully opened Hot Zero Power 0.0 AFW reaches full delivery rate VHPT setpoint reached 11.0 Peak power in transient 11.1 Reactor scram on VHPT (including trip response delay) 12.1 CEA insertion begins 12.6 Maximum fuel centerline temperature 14.8 CEAs fully inserted 15.5 Main steam isolation setpoint reached 21.4 HPSI setpoint reached 26.1 Main steam isolation completed 28.3 15.2.11-3b Amendment No. 26 (11/13)

Table 15.2.11-5 IOMSSV - Inputs and Assumptions Input/Assumption Value Core Power Level 3030 MWt (3020 + 0.3%)

1.0 Ci/gm DE I-131 and 518.9 Ci/gm DE XE Initial RCS Equilibrium Activity

-133 gross activity (Table 15.4.1-9)

Initial Secondary Side Equilibrium Iodine Activity 0.1 Ci/gm DE I-131 (Table 15.4.6-8)

Steam Generator Tube Leakage 0.5 gpm (Table 15.2.11-6)

Time to Terminate SG Tube Leakage 12.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Secondary Side Mass Releases to Environment Entire inventory in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Steam Generator Secondary Side Partition Coefficient none Maximum - 226,800 lbm per SG Maximum mass used for initial secondary SG Secondary Side Mass inventory release to maximize secondary side dose contribution.

Atmospheric Dispersion Factors Offsite Appendix 2I Onsite Tables 15.2.11-7 Control Room Ventilation System Time of Control Room Ventilation System 50 seconds Isolation Time of Control Room Filtered Makeup Flow 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Control Room Unfiltered Inleakage 460 cfm Breathing Rates:

Offsite RG 1.183 Section 4.1.3 Onsite RG 1.183 Section 4.2.6 Control Room Occupancy Factor RG 1.183 Section 4.2.6 15.2.11-4 Amendment No. 26 (11/13)

Table 15.2.11-6 IOMSSV Steam Generator Tube Leakage Time Flow Rate (hours) (lb/min) 0.00 3.103 0.50 3.361 0.75 3.428 1.00 3.536 1.39 3.565 2.00 3.657 4.00 3.756 8.00 3.945 10.50 4.012 12.4 0.00 15.2.11-5 Amendment No. 26 (11/13)

Table 15.2.11-7 Control Room /Qs Time (hours) /Q (sec/m3) 0 6.30E-03 0.013889 2.84E-03 1.5 1.62E-03 2.0 1.32E-03 8.0 5.06E-04 24.0 3.88E-04 96.0 3.30E-04 720.0 3.30E-04 Table 15.2.11-8 IOMSSV Dose Consequences EAB Dose (1) LPZ Dose (2) Control Room Dose (2)

Case (REM TEDE) (REM TEDE) (REM TEDE)

Inadvertent Opening of a MSSV 0.03 0.03 0.39 Acceptance Criteria 2.5 2.5 5 (1)

Worst 2-hour dose (2)

Integrated 30-day dose 15.2.11-6 Amendment No. 26 (11/13)

Core Power HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/°F) 125

.. . . .. . .... .. *;..:.-- '- .... -- . . -:-.: ' \

,:,:. .**:.:.#--- I 100 .. .,-; ...-* I

.,...,.,.==""'--=---=-~~-

  • \

I 1i:' 75  :~

\ -

1--

0::: \

~ \

\

..... \

Q) 3: \

&. 50 \

\

\

Core Power

  • Decalibrated Nl Power

- - -

  • Thermal Power 25 -

I I I *--, .. ,_

0 0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CORE POWER FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-1

Total Core Heat Flux Power HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/°F)

~ 3000

2:

Q.)

~

0 a...

X

1 u:::

....<tl 2000 Q.)

r:

Q.)

(.)

{g

1

(/')

"'0 0

0::: 1000 0 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-2

Pressurizer Pressure HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/°F) 2200 ~~

-ro

'(i) a.

Q)

J 2000 -

If)

If)

~

a..

1800 -

1600 ~~~--~~~~~~--~~--~~~--~~--~~~--~~~

0 5 10 15 20 Ti me (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-3

RCS Loop Temperatures HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcmfOF)

I 640 620

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

600 -

0

-w:- 580

~

- e Avg . That

J ** * **
  • Avg . Tcold ro Q) 0..

I-

~ 560 I ........ ............ . .

540 520 500 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-4

RCS Total Loop Flow Rate HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/°F) 40000 ...

-( .)

Q)

If)

.D E

- 30000 Q) ro 0::

0 LL If)

If) ro

~

20000 -

10000 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-5

Steam Generater llressures HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcmfOF) 800

- -* SG-1

  • SG-2 Q)

~

(/)

700

~ *-._

a..

(.?

(/)

600 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM GENERATOR PRESSURE FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-6

Steam and Feedwater Flow Rates HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcmfOF) 3000 u

Q) en Q) ro 0:: 2000

~

- -* SG-1 Steam u::

0 en *********** SG-2 Steam en -- -

2 __ .._ SG-2 MFW

- - --<~~~ SG-1 AFW 1000

- - -~ SG- 2 AFW o.-~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM AND FEEDWATER FLOW RATES FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -

29.6 pcm/°F)

FIGURE 15.2.11-7

Reactivity Feedback HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/°F) 0

- - ~ ..

-- -- - - - - ~--

~ /

/ /'

~

. Total I I

....... *********** Moderator

~

(.) - - -* Doppler ro Q) - -

-5

-10 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK FOR HFP LIMITING EXCESS LOAD (MAXIMUM LOAD INCREASE, MTC OF -29.6 pcm/°F)

FIGURE 15.2.11-8

Reactor Power- HZP Excess Load 400 c:::- 300 f--

0::

~

Q)

~

~ 200 100 a._~--~~~--~~--~-~~~~~ - --~~--~~======~==~~

0 5 10 15 20 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR POWER HZP EXCESS LOAD FIGURE 15.2.11-9

Total Core Heat Flux Power- HZP Excess Load I I I 900 r- -

700 -

~

~

Q) 3:

500 -

0 CL X

J -

LL 300

<U -

Q)

I Q) 100 -

u

~

J C/)

"0 0 -100 r- -

0:::

-300

-500 0 5 10 15 20 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER HZP EXCESS LOAD FIGURE 15.2.11-10

Pressurizer Pressure- HZP Excess Load 2400 I 2200 -

-ro 2ooo

~

'(i)

-a.

~

J

(/)

(/)

~

a.. 1800 -

1600 -

1400 0 5 10 15 20 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE HZP EXCESS LOAD FIGURE 15.2.11-11

RCS Loop Temperatures- HZPExcess Load 540

. ~. ~

520 0

i.L

<ll

J ctl 500

<ll ...

a. .. ** . ... *-

_______. Avg . Thot - **-**....

E

<ll *********** Avg . Tcold 1-480 460 I I I 0 5 10 15 20 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES HZP EXCESS LOAD FIGURE 15.2.11-12

RCS Total Loop Flow Rate- HZPExcess Load 40000 0(l)

(/)

.0 E

(l) ro 0:: 30000

~

0 u.

(/)

(/)

<U

~

20000 5 10 15 20 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE HZP EXCESS LOAD FIGURE 15.2.11-13

Steam Generator Pressures - HZP Excess Load

- - - SG-1

*-----* SG-2 500 400 ~~~--~~--~~--~~~--~~--~~--~~~--~~--~~

0 5 10 15 20 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM GENERATOR PRESSURES HZP EXCESS LOAD FIGURE 15.2.11-14

Steam and Feedwater Flow Rate - HZP Excess Load 5000

- - - SG-1 Steam

*--* SG-2 Steam 4000 ---

- - a SG-2 MFW

-- _____,. SG-1 AFW uQ)

-- ~ SG-2AFW

(/)

~E 3000

~

-Q) m 0:::

5: --, , _

0 u::: 2000

(/)

(/)

m

~

1000 o.-~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM AND FEEDWATER FLOW RATE HZP EXCESS LOAD FIGURE 15.2.11-15

Reactivity Feedback - HZP Excess Load I I 4.00 -

2.00 ** * * ** * ** ** * ~

0.00 11-----~~=:::::-==---- _.,.____._ - * .--?~--= .: :- :. . -. . . ----------- - ..

\

\

___. Total

~ -2 .00 \ -

  • *********** Moderator \

uro - - -* Doppler \

(]) - -

0:::

- 4 .00 \ -

-6.00

\~

I -

l ______ _

-8.00 -

-10.00 ~~~--~~--~~--~~--~~--~~~~--~~--~~--~~--~~~

0 5 10 15 20 Ti me (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK HZP EXCESS LOAD FIGURE 15.2.11-16

Peak Fuel Centerline Temperature- HZPExcess Load 2000

~

~

m C])

0...

E C])

I-1000 5 10 15 20 25 30 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PEAK FUEL CENTERLINE TEMPERATURE HZP EXCESS LOAD FIGURE 15.2.11-17

15.2.12 DEPRESSURIZATION OF THE REACTOR COOLANT SYSTEM 15.2.12.1 Identification of Causes The Inadvertent Opening of Pressurizer Pressure Relief Valve, or Reactor Coolant System (RCS)

Depressurization, event is defined, for St. Lucie Unit 1, as an accidental opening of one or both of the pressurizer power-operated relief valves (PORVs), due to a mechanical failure, spurious actuation signal, or unanticipated operator action.

The event results in a loss of RCS fluid and a fairly rapid RCS depressurization. If the moderator temperature coefficient (MTC) is positive, positive moderator density reactivity feedback caused by the depressurization leads to an increase in core power. The specified acceptable fuel design limits (SAFDLs) challenge is soon terminated, when the reactor trips on a thermal margin I low pressure (TM/LP) signal, but the RCS fluid loss and depressurization continue.

The pressurizer liquid level begins to decrease significantly after the reactor trip, and this actuates the RCS charging pumps and minimizes RCS letdown. A low-low pressurizer pressure signal subsequently actuates high-pressure safety injection (HPSI). The HPSI and charging serve to restore the pressurizer level, but if the HPSI and charging flows are not throttled or terminated, the pressurizer will begin to overfill. To prevent liquid discharge through the open PORV(s), the operators will have to close the open PORV(s) or the corresponding block valve(s) prior to the pressurizer dome becoming liquid-filled.

15.2.12.1.1 Analysis of Effects and Consequences The RCS depressurization event was used in assessing the bias term in the TM/LP trip. Trip processing delays and measurement uncertainties were used to verify the value of that bias.

The event simulated was a failure of both pressurizer relief valves fully open. A combined flow rate of 120% of rated for the two pressurizer relief valves at rated pressure (2400 psia) was simulated. The pressurizer heater capacity was set to zero to allow a more rapid depressurization, and thereby reduce the transient MDNBR.

Detailed analyses were performed with the approved non-LOCA methodology given in Reference 117. For this event, the S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures), and an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA IIIC code (Reference 108), which was used to calculate the MDNBR using the higher thermal performance (HTP) critical heat flux correlation (Reference 110). This event was also addressed as part of the TM/LP statistical setpoint analyses (Section 15.6.5) using the Reference 109 methodology.

A single calculation was performed at BOC HFP conditions, maximum TS core inlet temperature, and minimum TS RCS flow rate using the parameters listed in Table 15.2.12-1. These parameters produced the minimum margin to the DNB limit. A conservative moderator density reactivity feedback was used, based on the hot zero power (HZP) TS/ core operating limits report moderator temperature coefficient (MTC).

15.2.12.1.2 Description of Analyses for Pressurizer Overfill The purpose of this analysis was to evaluate the pressurizer overfill consequences of the RCS Depressurization event. Detailed analyses were performed using the S-RELAP5 code (Reference 117). The S-RELAP5 code was used to model the key primary and secondary system components, reactor protection system (RPS) and engineered safety features actuation system (ESFAS) trips, and core kinetics. The calculations were performed to determine the operator action time necessary for precluding liquid relief through a single accidentally opened pressurizer PORV.

15.2.12-1 Amendment No. 26 (11/13)

Initial conditions and input parameter biasing (listed in Table 15.2.12-3) were designed to ensure conservatively high HPSI and charging flow rates, maximize initial pressurizer level, provide maximum reactivity feedback, and maximize the post-reactor-trip RCS heatup. Assumptions regarding mitigating systems and functions, along with a limiting single-failure, produce the most challenging scenario regarding pressurizer overfill.

The principally challenged acceptance criterion for this analysis is to demonstrate that the event does not generate a more serious plant condition. The analysis objective is to determine the minimum time for the pressurizer dome to become liquid-filled. A transient-termination operator action time based on this analysis result will ensure that no liquid is relieved through the accidentally opened PORV.

15.2.12.2 Results A summary of the MDNBR transient events sequence is given in Table 15.2.12-2. Upon failure of the relief valves, the RCS pressure fell rapidly, as shown in Figure 15.2.12-3, and a reactor trip on the TM/LP function occurred at 39.2 seconds. Figures 15.2.12-1 to 15.2.12-7 show the simulated plant response for this event. The limiting MDNBR was calculated to be above the 95/95 limit for the HTP CHF correlation. The sequence of events for the limiting pressurizer overfill case* is shown in Table 15.2.12-4. The system response is presented in Figure 15.2.12-12 to Figure 15.2.12-19. The analysis showed that the minimum time from the event initiation to the pressurizer dome becoming liquid-filled is 7 minutes.** Thus, the operators will have no more than 7 minutes from the inadvertent opening of a pressurizer PORV to terminate the event, by closing the PORV or its block valve.

  • The limiting case is initiated with maximum RCS temperatures and assumes that the pressurizer heaters are unavailable and that a LOOP occurs at reactor trip - which, in turn, renders the SBCS unavailable.
    • The pressurizer is considered to be full when the liquid fraction in the dome reaches 1.00.

15.2.12-1a Amendment No. 26 (11/13)

Table 15.2.12-1 Initial Conditions and Biasing for the RCS Depressurization Event*

Parameter Value Core Power 3,020 MWt + 0.3%

Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Pressurizer Level 65.6%

Scram Reactivity Minimum HFP Moderator Density Reactivity Based on the most positive TS MTC Doppler Reactivity Coefficient -0.80 pcm/°F Gap Conductance Conservative BOC values Pressurizer Spray Available Pressurizer Heaters Disabled PORV Flow Rate 367,200 lbm/hr at 2400 psia (two valves)

Table 15.2.12-2 Sequence of Events For RCS Depressurization Event Event Time (sec.)

PORV fail open 0.0 TM/LP trip reached 38.3 Reactor scram on TM/LP (including trip 39.2 response delay)

MDNBR 39.6 CEA insertion begins 39.7

  • These parameters represent the EPU analysis. Disposition for the current cycle is documented in the cycle specific safety analysis report.

15.2.12-2 Amendment No. 26 (11/13)

Table 15.2.12-3 RCS Depressurization / Pressurizer Overfill: Initial Conditions and Biasing Parameter Value Initial Reactor Power 3029.06 MWt Initial Core Inlet Temperature Range 532°F - 554°F Initial RCS Flow Rate (total) 375,000 gpm Initial Pressurizer Pressure 2185 psia Initial Pressurizer Level 68.6%

Moderator Reactivity Moderator density feedback corresponding to +7.0 pcm/°F MTC Doppler Temperature Coefficient (DTC) -0.80 pcm/°F Scram Reactivity 6017.22 pcm Steam Generator Tube Plugging 10% (both steam generators)

Open Pressurizer PORV Flow Rate (single Sized to relieve 154,540 lbm/hr PORV) at 2400 psia (steam only)

PPZR 2061 psia x A1* x QR1**

TM/LP Reactor Trip Setpoint +15.85 psia/°F x Tinlet - 8950 psia, or PPZR 1847 psia TM/LP Reactor Trip Signal-Processing Delay 0.9 s MFW Status Initially on auto, then terminated at reactor trip Actuation of All Charging Pumps At reactor trip***

Charging Flow Rate (total) 147 gpm RWT Temperature 51°F SBCS Capacity Range 24% - 58%

SBCS Secondary System Pressure Setpoint 910 psia MSSV Setpoints Open on pressure higher than 1030.0 psia (for Bank 1) and 1060.8 psia (for Bank 2)

Low-Low Pressurizer Pressure Safety Injection 1640 psia Actuation Signal (SIAS) Setpoint Safety Injection Availability Delay After SIAS 0.0 s HPSI Flow Rate Maximum, for both HPSI pumps A1 (of the TM/LP reactor trip function) was conservatively assumed to be 1.0 in the S-RELAP5 model.

    • QR1 (of the TM/LP reactor trip function) is at 1.0 at power levels above 97.2% of the rated thermal power (RTP).

15.2.12-2a Amendment No. 26 (11/13)

Table 15.2.12-3 RCS Depressurization / Pressurizer Overfill: Initial Conditions and Biasing (Continued)

Parameter Value Automatic Termination of Charging and Actuation Not credited of Letdown (after pressurizer level restored)

Low-Low Steam Generator Level Auxiliary 14% narrow range (NR)

Feedwater Actuation Signal (AFAS) Setpoint AFW Actuation Delay After AFAS 330 s*

AFW Flow Rate (total) 2 electric pumps x 296 gpm / pump AFW Temperature 104°F Note: Reducing the AFW flow to 276 gpm and increasing the AFW temperature to 111.5°F is determined to have insignificant impact on this event analysis.

This maximum AFW actuation delay, which includes time for emergency diesel generator startup and sequencing, was used not only for LOOP cases but also---as an additional conservatism---for no-LOOP cases.

Table 15.2.12-4 RCS Depressurization / Pressurizer Overfill: Sequence of Events Event Time (s)

Event initiation - single pressurizer PORV inadvertently opens 0.0 Pressurizer pressure reaches TM/LP setpoint 60.2 TM/LP signal actuates reactor trip, offsite power is assumed to be lost, MFW is lost, RCPs begin to coast down, turbine trips, and all RCS charging is assumed 61.1 to begin Lowest steam generator (SG) level reaches AFAS setpoint 66.1 MSSVs first open 66.5 Pressurizer pressure reaches SIAS setpoint 107.2 HPSI begins 110.1 AFW flow to SG-1 and SG-2 begins 396.1 Pressurizer dome becomes liquid-filled 444.7 15.2.12-2b Amendment No. 26 (11/13)

Reactor Power- RCS Depressurization 120 100.1 --------.----------------~---------~-

-  : -.-------~--~ -

80 -

a:-

I-0::

~60

<1>

5:

0 0..

40 - -

20 - -

0 0 10 20 30 40 50 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR POWER- RCS DEPRESSURIZATION FIGURE 15.2.12-1

Total Core Heat Flux Power- RCS Depressurization 4000 ~--~----~----~----~----~----~----~----~--~-----.

~ 3000 - --

5....

Q)

~

0 a..

X

l LL

-roQ) 2000 I

Q) 0

~

l (j)

"'0 0

0::: 1000 0 ~--~----~----~----~----~----~----~----~--~----~

0 10 20 30 40 50 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER- RCS DEPRESSURIZATION FIGURE 15.2.12-2

Pressurizer Pressure- RCS Depressurization 2200 ro-

.(ij

-a.

~ 2000

1

(/)

(/)

~

0..

1800 10 20 30 40 50 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE- RCS DEPRESSURIZATION FIGURE 15.2.12-3

Pressurizer PORV Flow Rate- RCS Depressurization 80 0Q) en

..0 E 60 Q)

(13 0::

5:

0 LL en 40 en (13

2:

20 0.-----~--~----~----~----~----~----~----~--~----_J 0 10 20 30 40 50 Ti me (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PORV FLOW RATE- RCS DEPRESSURIZATION FIGURE 15.2.12-4

RCS Loop Temperatures - RCS Depressurization 620 600 u::-

o.._..

Avg. Thot

~

J *********** Avg . Tcold ro I....

580 r-Q) 0.

E Q) 1-

  • ' -. ~-

560 r- -

540 0 10 20 30 40 50 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES- RCS DEPRESSURIZATION FIGURE 15.2.12-5

RCS Total Loop Flow Rate- RCS Depressurization 50000 40000 uQ.l

(/)

E

..0

~

Q.l ro 0::: 30000

~

u.

(/)

(/)

Ctl

~

20000 10000 0 10 20 30 40 50 Ti me (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE- RCS DEPRESSURIZATION FIGURE 15.2.12-6

Reactivity Feedback- RCS Depressurization 5.0 ~--~----~~----~----~ ~ ----~-----~ ~ --~----~~----~----~

0.0 --------------~--- ~- ----~--- ~......--------il_..,__

~ ------- T ota I

  • ........... Moderator
o:::;

() - - -

  • Doppler ro

<1> - -

-5. 0

- 10.0 ~-~--~~--~--~ 1 --~---~ 1 -~--~1 --~--~

0 10 20 30 40 50 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK- RCS DEPRESSURIZATION FIGURE 15.2.12-7

DELETED Amendment No.26 (11 /13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURES- RCS DEPRESSURIZATION FIGURE 15.2.12-8

DELETED Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 WATER LEVELS- RCS DEPRESSURIZATION FIGURE 15.2.12-9

DELETED Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 DNBR- RCS DEPRESSURIZATION FIGURE 15.2.12-10

DELETED Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTIVITY- RCS DEPRESSURIZATION FIGURE 15.2.12-11

Pressurizer PORV Flow Rate- RCS Depressurization I Pressurizer Overfill

- - PORV Flow Rate 40 u

~ 30 E

.0

=..

2 ro 0::::

3 0

20 u_

10 100 200 300 400 500 600 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PORV FLOW RATE- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-12

Pressurizer Pressure- RCS Depressurization I Pressurizer Overfill 2400 2200

- - Pressurizer Pressure 2000 1800 ro-

"(ii E; 1600 Q)

I en en Q) 1400 a..

1200 1000 800 600 0 100 200 300 400 500 600 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-13

RCS Coolant Temperatures- RCS Depressurization I Pressurizer Overfill 620 600

- -* RCS Avg . Thot

* RCS Avg . Tcold 580

~

1

-ro.._ 56o

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

E a.> -*-*-*-** *-** *** **-* *-*-* .... *** *---**-----*--* *** ..... *** ...... * .. -**-------- * -* **** .... * ..........

I--

540 520 500 0 100 200 300 400 500 600 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS COOLANT TEMPERATURES- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-14

RCS Subcooling- RCS Depressurization I Pressurizer Overfill 70 Hot Leg 1 Subcooling

    • -**** *** Hot Leg 2 Subcooling 60 50 L:L 0

- 0>

.!!: 40 0

0

(.)

.0

s CJ) 0> 30 Q)

....J 0

I 20 10 0

0 100 200 300 400 500 600 T ime (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS SUBCOOLING - RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-15

Total RCS Flow Rate- RCS Depressurization I Pressurizer Overfill 110 100 90 - - Total RCS Flow Rate 80 -

-:§!. 70 -

~

<1>

C\l 0:: 60 s:0 u.. 50

(/)

(/)

C\l

~ 40 -

30 -

20 10 -

~

0 0 100 200 300 400 500 600 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL RCS FLOW RATE- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-16

Indicated Reactor Power- RCS Depressurization I Pressurizer Overfill 120

- - Ind icated Power 100 -

a... 80 r- -

1-0:::

R

~

Q.)

~

0 60 f- -

a...

"'0

-~

Q.)

ctl

"'0 c:: 40 r- -

20 f- -

0 0 100 200 300 400 500 600 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 INDICATED REACTOR POWER- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-17

Total HPSI and Charging Flow Rates-RCS Depressurization I Pressurizer Overfill

e Total HPSI Flow Rate

  • Total Charging Flow Rate 120 100 uQ) c/)

"E so

..0

-Q) co 0:: 60

..Q LL 40 20 **----* -------------- ------------* ---------------* -------*-------* ----- ---------* -------------- * -------------- * -----**--*-----

o.-~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0 100 200 300 400 500 600 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL HPSI AND CHARGING FLOW RATES- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-18

Pressurizer Liquid Volume- RCS Depressurization I Pressurizer Overfill 2000

e PZR Liquid Volume 1800 ************ PZR Total Geometric Volume 1600 1400 1200

~ 1000

J 0

> 800 600 400 200 0

0 100 200 300 400 500 600 Time (s)

Amendment No.26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER LIQUID VOLUME- RCS DEPRESSURIZATION I PRESSURIZER OVERFILL FIGURE 15.2.12-19

15.2.13 STATION BLACKOUT ANALYSIS 15.2.13.1 Identification of Causes 10 CFR 50.63, "Loss of all alternating current power," required that a plant must be able to withstand for a specified duration and recover from a station blackout. The specific St. Lucie Unit 1 requirements are provided by NRC Safety Evaluation of Station Blackout (SBO) Rule (Reference 90);

this UFSAR section addresses Section 2.3.6 " Reactor Coolant Inventory". Other requirements for the SBO rule are discussed in UFSAR Sections 8.3 and 9.4.

The results of this analysis have shown that Unit 1 can successfully withstand a Station Blackout event for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Specifically:

1) Adequate reactor coolant system inventory is maintained to ensure sufficient core cooling and to ensure that the core does not uncover;
2) There is no fuel failure;
3) RCS coolant pressure remains within limits, and;
4) The resulting radiological dose rates are bounded by the Loss of Offsite Power Event (UFSAR Section 15.2.9)

Operator action is credited to throttle flow from the steam driven auxiliary feedwater pump, to maintain Steam Generator level. At 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, operator action is credited to connect the Unit 1 to a Unit 2 4160 V safety bus, providing ac power from the Unit 2 EDG. At 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, operator action is credited to open the atmospheric dump valves resulting in the closure of the main steam safety valves.

After 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, either offsite power is restored or one or both St. Lucie Unit 1 EDGs are started, thus terminating the event. The results of the analysis show that after SBO, the plant is in a condition from which recovery from the SBO is achievable.

Florida Power and Light has implemented operator training and emergency procedures to assure maintenance of sufficient core cooling for the SBO event, and recovery therefrom, consistent with the NRC SBO safety evaluation for St. Lucie (Reference 96).

15.2.13.2 Analysis of Effects and Consequences The SBO event is defined as a complete loss of alternating current power to the essential and nonessential switchgear buses. SBO involves the loss of offsite power concurrent with turbine trip and failure of both Emergency Diesel Generator sets. For Unit 1, this results in the loss of all onsite AC power except that supplied by inverters from the two safety related battery sources. This provides power to the 120 V AC (safeguards) instrument power and other required loads (e.g., Auxiliary Feedwater system). The DC coping period is assumed to end after one hour when the Unit 1 4160 V 1AB bus and Unit 2 4160 V2AB bus are manually connected and AC power is available to Unit 1, based on excess Unit 2 EDG capacity (Reference 90 and 96).

The steady-state and transient loading limits of the Unit 2 EDGs were determined to be acceptable for the anticipated SBO loading profile. The capability of the alternate AC power source and the inter-unit tie to support the SBO mitigation is described in FSAR section 8.3.1. The Class 1E station batteries have sufficient capacity to power the necessary loads for one hour under SBO conditions with adequate margin. Emergency DC batteries are not affected since the power to one of the safety divisions of the electrical distribution system will be available one hour after occurrence of the SBO to re-energize the battery chargers.

At the time of the SBO, power supply is lost to the following systems: MFW pumps, reactor scram mechanism (holdout coils), RCPs, pressurizer heaters, steam dump bypass system, and Sl system.

In addition, RCP seal leakage is conservatively assumed. All AC powered components not powered by an inverter are not started until after the one hour DC coping period.

15.2.13-1 Amendment No. 26 (11/13)

This event is essentially a natural circulation cooldown with the secondary side heat sink limited to the initial SG shell side liquid inventory and Auxiliary Feedwater flow provided by the steam turbine-driven AFW pump.

The Reference 117 rnethodology was used with SBO-specific modifications to accommodate the event as defined in References 90, 94, and 96.

10 CFR 50.63, "Loss of all alternating current power," requires that a plant be able to withstand a specified duration and recover from a SBO. The specific St. Lucie Unit 1 requirements are provided by NRC Safety Evaluation of Station Blackout (SBO) Rule (References 90 and 96); this analysis addresses Section 2.3.6 "Reactor Coolant Inventory" with the following assumptions:

  • Best estimate full power conditions
  • No independent equipment failures (other than those associated with the event) occur during the course of the transient.

The previous licensing analysis was based on the RETRAN computer code whereas the analysis supporting the EPU was performed using S-RELAP5. Changes from the licensing basis presented in References 90, 94, and 96 included:

  • Higher rated initial core power of 3,020 MWt vs. 2,700 MWt (reflecting the EPU)
  • Lower RCS leakage flow rate of 60 gpm vs. 120 gpm, due to installation of N9000 RCP seals
  • Credit for flow from one charging pump beginning at one hour, where previously no credit was taken
  • Decay heat based on 100% of the 1973 ANS Standard vs. 105% of the 1979 version
  • Incorporation of blowdown (cleanup) flow from the Steam Generators as part of the initial condition. This blowdown flow is usually stopped by operator action at 20 minutes, but for this analysis, the flow duration is extended to 25 minutes in order to be conservative.

The operator will utilize ADV's to control secondary pressure at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Prior to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the MSSV's will cycle to control secondary pressure. St. Lucie Unit 1 has two ADVs, one on each steam line. It has been assumed that at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the operator starts manual operation of the ADVs to control RCS temperature between 532°F (No-Load temperature) and 540°F.

The relatively high temperature band (between 532°F and 540°F) chosen for manual ADV control was selected to maintain secondary pressure below the MSSV setpoint and still maintain the RCS pressure high to maximize the RCS leakage.

The total initial RCS leakage flow rate was modeled as 60 gpm. This represents 10 gpm leakage from each RCP seal plus 20 gpm as a combination of identified and unidentified leakage allowed by Technical Specifications. A value of 10 gpm for each RCP seal is a conservatively high allowance for the N9000 RCP seals used at St. Lucie Unit 1. RCP leakage was modeled to decrease with decreasing RCS pressure.

UNIT 1 15.2.13-1a Amendment No. 27A (01/16)

As indicated in UFSAR Section 6.2.1.2, the heat-up and pressurization of the containment during the SBO event is a function of the RCS leak rate. The original St. Lucie Unit 1 analysis considered an initial total RCS leakage rate of 120 gpm (RCS leakage allowed by the Technical Specifications plus reactor coolant pump seal leakage); the leakage is pressure dependent and therefore decreases with decreasing RCS pressure. New analyses have been performed for 60 gpm of total leakage. This leakage reduction is based on NRC-approved WCAP-16175-P-A (References 114 and 115), which documents improved RCP seal performance during loss of seal cooling conditions. Since the mass and energy released into the containment in the original analysis is significantly larger than the EPU analysis, the original LOCA and HELB environmental profiles remain valid for the EPU. Therefore, the operability of equipment needed for safe shutdown inside containment is acceptable for the SBO event under EPU conditions.

The input parameters and biasing for the analysis of this event are shown in Table 15.2.13-1. As an exception to the usual biasing presented in the Reference 117 methodology, the input parameters reflect more of a best estimate approach in accordance with the plant specific current licensing basis.

The analysis must show that the plant can successfully withstand a SBO event for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

The prime directive in Reference 95 is ensuring that the core remains covered. Avoiding core uncovery is interpreted as maintaining a collapsed liquid level in the reactor vessel above the top of the fuel or active core. With an active core height of 136.7 inches, this corresponds to a minimum level of approximately 11.4 feet above the bottom of the active core. As a more restrictive criterion, in order to avoid "breaking suction" in the RCS loops, the water level in the reactor vessel should not drop below the top of the hot leg nozzles. The top of the hot leg is approximately 18.7 feet above the bottom of the core. Avoiding core uncovery ensures that no fuel failures occur. Sufficient inventory must be available in the Condensate Storage Tank for decay heat removal. In order for the Steam Generator to remain effective in removing heat from the RCS, it is necessary to avoid dryout of the secondary side.

15.2.13-1b Amendment No. 26 (11/13)

DELETED 15.2.13-2 Amendment No. 26 (11/13)

DELETED 15.2.13-3 Amendment No. 26 (11/13)

15.2.13.3 Results and Conclusions The results of this analysis are summarized in Table 15.2.13-3. The transient sequence of events is shown in Table 15.2.13-2, and the transient results are shown in Figure 15.2.13-1 to Figure 15.2.13-11.

RCS leakage follows the same general trend as pressurizer pressure. Opening and closing of the MSSVs provides limited cooling of the RCS for the first hour. Opening the ADV at one hour produces a sharper drop in RCS temperature and pressure. The operator manually controls the ADV's to control RCS temperature between 532°F and 540°F. RCS leakage decreases to a minimum of approximately 30 gpm at a minimum RCS pressure of approximately 1,000 psia at about 80 minutes.

This is less than the charging flow rate of 40 gpm. The minimum reactor vessel level occurs between 70 and 90 minutes where the level drops slightly below the Support Plate at the top of the Upper Guide Structure (separating the upper head from the upper plenum). With a minimum water level of approximately 29 feet, there is substantial margin to the top of the hot leg nozzles at 18.7 feet.

There is no significant change in RCS temperature, pressure, or power prior to reactor scram, so this event does not challenge the DNBR or FCM SAFDLs. Significant steam generator liquid mass inventories were retained in both steam generators, so there was adequate mass in the steam generators supplied by AFW to make up for the steam mass lost through the MSSVs and ADVs.

Likewise, the total amount of AFW delivered is well within the initial inventory of the Condensate Storage Tank. Thus, all acceptance criteria are satisfied for this event.

UNIT 1 15.2.13-4 Amendment No. 27A (01/16)

The results of the analysis show that at the end of a 4-hour SBO, core cooling is maintained and sufficient liquid inventory remains in the vessel to ensure that the core does not uncover and therefore no fuel failures occur. Maximum RCS and secondary pressures are maintained well below 110 percent of design pressure.

The RCS temperature at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> into the event is about 556°F. When the ADVs are first opened at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the RCS is cooled down from 556°F to 532°F. Thereafter, the RCS temperature is controlled between 532°F and 540°F. These cooldown ranges are not large enough to cause the available shutdown margin to be depleted. Therefore, the core remains subcritical following reactor trip for the duration of the event.

15.2.13-5 Amendment No. 26 (11/13)

TABLE 15.2.13-1 KEY PARAMETERS FOR THE STATION BLACKOUT EVENT PARAMETER VALUE Core Power 3,020 MWt Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Pressurizer Level 65.6%

Scram Reactivity 8,125 pcm Pressurizer PORV Disabled Pressurizer Spray Disabled Pressurizer Heaters Disabled Pressurizer Safety Valves Available SBCS Disabled ADV Available with operator action after 1 hr.

Charging Pump 40 gpm with operator action after 1 hr.

MSSV Available Low SG Level ESF Trip (AFW) Credited AFW (Steam-driven pump) 600 gpm as full flow, throttled to approximately half flow after 10 min.3 with operator action MSSV Setpoints Bank 1: 4/SG @ 1,000 psia Bank 2: 4/SG @ 1,040 psia Steam Generator Blowdown Flow 120 gpm per SG terminated at 25 min.

Condensate Storage Tank water volume 116,000 gal1 Duration/coping time 4 hr.

Total initial RCP leakage 60 gpm2 1

This analysis would bound any increase in the CST water volume to a value greater than 116,000 gal.

2 Leakage is RCS pressure dependent.

3 The accident analysis conservatively assumes 10 minute operator action to throttle AFW flow, however, this is not an action timing requirement for operations to perform.

UNIT 1 15.2.13-6 Amendment No. 28 (05/17)

TABLE 15.2.13-2 SEQUENCE OF EVENTS FOR STATION BLACKOUT EVENT Time seconds minutes Loss of all AC Power:

scram 1 turbine trip begin Main Feedwater coastdown begin RCP coastdown begin RCP leak Bank 1 MSSVs in both loops open (begin cycling) 6 SG low level setpoint reached 128.6 EC288300 Beginning of AFW delivery to SGs 458.6 AFW flow throttled to about half of initial ~600 ~10 SG blowdown flow secured 25 Operators open ADVs (for the first time) 3600 60 EC288300 Operator supply power and start one charging pump PZR level off scale low 3870 ~65 EC288300 Upper Head subcooling lost ~71.4 Operator closes ADVs (for the first time) ~4830 ~81 Minimum level in the reactor vessel ADVs open (for the second time) ~5420 ~90 EC288300 ADVs close (for the second time) ~5830 ~97 Minimum RCS pressure PZR level recovers (and remains above zero % span) ~7940 ~132 AFW flow is (temporarily) stopped (for the first time) ~10500 ~175 EC288300 AFW flow resumes ~11330 ~189 End (power is restored) 14400 240 UNIT 1 15.2.13-7 Amendment No. 29 (10/18)

TABLE 15.2.13-3 PARAMETER VARIATION IN SBO ANALYSIS HOURS INTO THE TRANSIENT Parameter 0 1 2 3 4 Vessel Level 30 30 30 30 30 Leakage Flow 60 49.2 35.2 37.9 40.1 Mass to Containment 0 0.020 0.034 0.048 0.063 Energy to Containment 0 11 18 25 33 EC288300 RCS Pressure 2255 1755 1200 1270 1350 RCS Tavg 578.4 556.2 538.3 538 537.4 SG Inventory 0.127 0.088 0.112 0.152 0.164 Steam to Atmosphere 0 0.24 0.36 0.42 0.50 Vessel Level: collapsed water vessel level above the bottom of the active core, in feet Leakage Flow: total leakage flow out of the RCS (mostly through RCP seals), in gpm Mass flow to integrated mass leakage into containment, Million lbm Containment:

Energy to total integrated leakage energy, in Million Btu Containment:

RCS Pressure: at the top of the Pressurizer, in psia RCS Tavg average RCS temperature, in oF SG Inventory: Steam Generator (A or B) inventory, in Million lbm Steam to integrated total steam flow out of the secondary (MSSVs and ADVs), in Atmosphere: Million lbm 15.2.13-8 Amendment No. 29 (10/18)

TABLE 15.2.13-4 STEADY-STATE STATION BLACKOUT LOADS ON UNIT 2 EDG DELETED 15.2.13-9 Amendment No. 26 (11/13)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL RCS LEAKAGE STATION BLACKOUT FIGURE 15.2.13-1 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR POWER (DECAY HEAT)

STATION BLACKOUT FIGURE 15.2.13-2 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE STATION BLACKOUT FIGURE 15.2.13-3 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER LIQUID LEVEL STATION BLACKOUT FIGURE 15.2.13-4 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS REACTOR VESSEL UPPER HEAD SUBCOOLING STATION BLACKOUT FIGURE 15.2.13-5 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS AVERAGE TEMPERATURES STATION BLACKOUT FIGURE 15.2.13-6 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 ADV FLOW RATES STATION BLACKOUT FIGURE 15.2.13-7 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM GENERATOR PRESSURE STATION BLACKOUT FIGURE 15.2.13-8 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM GENERATOR LIQUID LEVEL STATION BLACKOUT FIGURE 15.2.13-9 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM GENERATOR TOTAL MASS STATION BLACKOUT FIGURE 15.2.13-10 Amendment No. 29 (10/18)

EC288300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR VESSEL LIQUID LEVEL (ABOVE BOTTOM OF ACTIVE CORE)

STATION BLACKOUT FIGURE 15.2.13-11 Amendment No. 29 (10/18)

15.2.14 INCREASE IN REACTOR COOLANT INVENTORY Discussion and analysis of the following events are presented in this section:

a) Inadvertent operation of the emergency core cooling system during power operation (Section 15.2.14.1) b) Chemical and volume control system malfunction that increases reactor coolant inventory (Section 15.2.14.2)

These events, considered to be AOOs, cause an increase in reactor coolant inventory.

15.2.14.1 Inadvertent Operation Of The Emergency Core Cooling System During Power Operation Inadvertent operation of the ECCS during power operation (Mode 1) is caused by a malfunction which results in startup of the safety injection pumps such as an inadvertent Safety Injection Actuation Signal (SIAS). This event is not analyzed since the shutoff head of the injection pumps is much less than the RCS pressure in Mode 1. The impact of initiation of charging flow upon SIAS is the same as the CVCS malfunction event analyzed in Section 15.2.14.2.

15.2.14.2 Chemical And Volume Control System Malfunction That Increases Reactor Coolant lnventorv 15.2.14.2.1 Accident Description A Chemical and Volume Control System (CVCS) Malfunction event that produces an unplanned increase in reactor coolant system inventory may be caused by operator error or a failure in the pressurizer level transmitter which causes an erroneous low-low level signal.

The generated signal is transmitted to the controller, which responds by starting the two stand-by charging pumps and closing the letdown flow control valve to its minimum flow position. The CVCS Malfunction is assumed to occur without increasing or diluting the primary coolant initial boron concentration. With the mismatch between letdown and charging flow, the pressurizer mixture level and pressure increase. The pressurizer sprays mitigate the pressure increase. The operators are alerted to the event either by a high pressurizer pressure trip (HPPT) or by the pressurizer high level alarm (PHLA), and mitigate the event by reducing charging flow and/or restoring letdown flow. The case of a CVCS malfunction that produces a boron dilution is presented in Section 15.2.4.

15.2.14.2.2 Description of Analyses and Evaluations The purpose of this analysis was to evaluate the CVCS Malfunction event I inadvertent operation of ECCS event. Detailed analysis was performed using the S-RELAP5 code (Reference 117). The S-RELAP5 code was used to model the key primary and secondary system components, Reactor Protective System (RPS) and Emergency Safety Features (ESF) actuation trips and core kinetics. The calculation was performed to determine the operator action time necessary to mitigate the CVCS Malfunction event.

15.2.14-1 Amendment No. 26 (11/13)

15.2.14.2.3 Input Parameters and Assumptions A single limiting case was analyzed. Parameter biasing, assumptions, and an assumed single-failure were designed to ensure a conservatively high CVCS charging flow rate, maximize initial pressurizer level, and provide maximum reactivity feedback. Assumptions regarding operator actions and mitigating systems and functions, along with a limiting single-failure, produce the most challenging scenario regarding pressurizer fill.

The initial conditions and input parameters biasing for the analysis of this event are shown in Table 15.2.14-1.

  • Initial Conditions - The event was initiated from rated power plus uncertainty conditions with a maximum core inlet temperature and minimum Technical Specification (TS) Reactor Coolant System (RCS) flow.
  • Reactivity Feedback - End-of-Cycle (EOC) Doppler and moderator feedback were assumed for this event. Minimum scram worth with the most reactive rod stuck out of the core was assumed.
  • Reactor Protective System Trips and Delay - Reactor protection trip setpoints and delay times were biased to conservatively estimate the operator action time. The high pressurizer pressure trip was based on the nominal value plus uncertainty.
  • Pressurizer Conditions - A nominal pressurizer pressure and nominal pressurizer level plus uncertainty were assumed. The pressurizer safety valve (PSV) setpoint was based on the nominal value minus tolerance while the pressurizer high level alarm was based on the nominal high level alarm value plus uncertainty. The biasing of pressurizer parameters ensures the calculation of a minimum time to fill the pressurizer.
  • CVCS Charging - Maximum CVCS charging flow and a conservative charging temperature were assumed to ensure the most limiting conditions for the CVCS event.
  • Single-Failure - The assumed single-failure is the complete closure of letdown flow control valve that occurs concurrently with the start of the second and the third charging pumps.
  • Charging Boron Concentration - The charging flow boron concentration is assumed to be equal to the initial RCS boron concentration.

15.2.14-2 Amendment No. 26 (11/13)

15.2.14.2.4 Acceptance Criteria This event is classified as an AOO. The acceptance criteria for this event are:

1. Pressure in the reactor coolant and main steam systems should be maintained below 110% of the design values,
2. Fuel cladding integrity should be maintained by ensuring that the minimum departure from nucleate boiling ratio (MDNBR) remains above the 95/95 DNBR limit for pressurized water reactors (PWRs), and
3. An AOO should not generate a more serious plant condition without other faults occurring independently.

The principally challenged acceptance criterion for the CVCS Malfunction is to demonstrate that the event does not generate a more serious plant condition. The analysis objective is to show that the pressurizer does not become water-solid before the operator can terminate the transient, within 10 minutes after the event begins. This ensures that no solid-water is relieved through the pressurizer power operated relief valves (PORVs).

15.2.14.2.5 Results A single limiting case was analyzed for the CVCS Malfunction event at hot full power (HFP)

EOC conditions. The sequence of events is shown in Table 15.2.14-2. The system response is presented in Figures 15.2.14-1 to Figure 15.2.14-4. The analysis showed that the operators will have more than 10 minutes from the event initiation to terminate the EC292529 event. The analysis also showed that the operators have 608.5 seconds (more than 10 minutes) from the time of receipt of the pressurizer high level alarm to terminate the event before the pressurizer reaches a water-solid condition.

15.2.14-3 Amendment No. 30 (05/20)

TABLE 15.2.14-1 CVCS Malfunction Event: Initial Conditions and Input Parameter Biasing Parameter Value Initial Reactor Power 3029.06 MWt Initial Core Inlet Temperature 551°F Initial Reactor Coolant Flow Rate 375,000 gpm Initial Pressurizer Pressure 2250 psia Initial Pressurizer Liquid Level 68.6%

Moderator Temperature Coefficient (MTC) -32 pcm/°F Doppler Temperature Coefficient (DTC) -1.75 pcm/°F Scram Reactivity (1) 6017.22 pcm (2)

High Pressurizer Pressure Trip 2435 psia Pressurizer High Level Alarm 73.6%

CVCS Charging Flow (total) 147 gpm CVCS Charging Temperature 104°F RCP Bleedoff 4 gpm Steam Generator Tube Plugging 10%

Pressurizer Spray On Auto Pressurizer PORVs Not Credited PSVs Open on pressure higher than 2437.5 psia / Close on pressure lower than 2413.1 psia Reactor Coolant Pumps Operating Main Feedwater Automatic Letdown Flow Isolated Pressurizer Proportional Heaters On Auto Pressurizer Heaters Conservatively turned On when the pressurizer EC292529 level is greater than 3.6% above nominal level Notes (1) and (2) - No reactor trip occurred in the analysis.

15.2.14-4 Amendment No. 30 (05/20)

TABLE 15.2.14-2 CVCS Malfunction Event: Sequence of Events Event Time (1)

Event initiation - Erroneous low-low pressurizer level control system signal; Second and third 10.0 charging pumps start; Letdown flow is isolated Pressurizer High Level Alarm reached 176.4 Maximum pressurizer pressure occurred 744.0 EC292529 Maximum pressurizer volume occurred 784.9 Note (1) - these values include the 10 second steady-state time.

15.2.14-5 Amendment No. 30 (05/20)

EC292529 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR POWER CVCS MALFUNCTION EVENT FIGURE 15.2.14-1 Amendment No. 30 (05/20)

EC292529 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS AVERAGE TEMPERATURE CVCS MALFUNCTION EVENT FIGURE 15.2.14-2 Amendment No. 30 (05/20)

EC292529 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE CVCS MALFUNCTION EVENT FIGURE 15.2.14-3 Amendment No. 30 (05/20)

EC292529 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER WATER VOLUME CVCS MALFUNCTION EVENT FIGURE 15.2.14-4 Amendment No. 30 (05/20)

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