ML23096A042

From kanterella
Jump to navigation Jump to search
Amendment 32 to Updated Final Safety Analysis Report, Chapter 9, Auxiliary Systems
ML23096A042
Person / Time
Site: Saint Lucie NextEra Energy icon.png
Issue date: 04/01/2023
From:
Florida Power & Light Co
To:
Office of Nuclear Reactor Regulation
Shared Package
ML23096A089 List:
References
Download: ML23096A042 (1)
v • d • e


Text

LIST OF EFFECTIVE PAGES CHAPTER 9 AUXILIARY SYSTEMS Page Amendment Page Amendment 9-1 32 9.1-20 22 9-2 32 9.1-21 22 9-3 32 9.1-22 23 9-4 32 9.1-23 20 9-5 32 9.1-24 0 9.1-25 16 9-i 28 9.1-26 22 9-ii 28 9.1-27 23 9-iii 28 9.1-28 18 9-iv 28 9.1-29 25 9-v 28 9.1-29a 20 9-vi 28 9.1-30 25 9-vii 28 9.1-31 15 9-viii 28 9.1-32 22 9-ix 28 9.1-33 21 9-x 28 9.1-34 20 9-xi 28 9.1-35 20 9-xii 28 9.1-36 20 9-xiii 28 9.1-37 20 9-xiv 22 9.1-38 20 9-xv 29 9.1-39 20 9-xvi 24 9.1-40 20 9.1-41 20 9.1-1 23 9.1-42 20 9.1-2 26 9.1-43 20 9.1-3 26 9.1-44 26 9.1-3a 23 9.1-44a 26 9.1-4 24 9.1-45 18 9.1-4a 25 9.1-46 26 9.1-4b 26 9.1-46a 26 9.1-4c 25 9.1-47 21 9.1-4d 26 9.1-48 22 9.1-5 26 9.1-49 21 9.1-5a 28 9.1-50 28 9.1-6 26 9.1-51 23 9.1-6a 26 9.1-52 20 9.1-6b 26 9.1-53 25 9.1-7 26 9.1-54 21 9.1-7a 26 9.1-8 26 9.1-60 15 9.1-9 21 9.1-60a 26 9.1-10 28 9.1-60b 26 9.1-11 28 9.1-61 21 9.1-12 30 9.1-62 21 9.1-13 26 9.1-63 21 9.1-13a 26 9.1-64 26 9.1-13b 26 9.1-64a 26 9.1-14 31 9.1-64b 26 9.1-15 29 9.1-64c 26 9.1-15a 26 9.1-65 26 9.1-16 28 9.1-66 30 9.1-17 26 9.1-67 21 9.1-17a 26 9.1-68 26 9.1-18 22 9.1-69 26 9.1-19 23 9.1-70 21 UNIT 1 9-1 Amendment No. 32 (04/23)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 9 Page Amendment Page Amendment 9.1-75 29 9.2-7 21 9.1-76 21 9.2-8 28 9.1-77 29 9.2-9 25 9.2-10 29 F9.1-1 15 9.2-11 28 F9.1-2 26 9.2-12 17 F9.1-3 15 9.2-13 22 F9.1-4 22 9.2-14 20 F9.1-5 21 9.2-15 28 F9.1-6 21 9.2-16 22 F9.1-7 26 9.2-17 17 F9.1-8 15 9.2-18 28 F9.1-9 23 9.2-19 22 F9.1-10 14 9.2-20 30 F9.1-11 0 9.2-21 22 F9.1-12 26 9.2-22 29 F9.1-13 22 9.2-23 26 F9.1-14 16 9.2-24 16 F9.1-15 21 9.2-25 22 F9.1-15A 20 9.2-26 16 F9.1-15B 20 9.2-27 14 F9.1-16 21 9.2-28 22 F9.1-17 15 9.2-29 18 F9.1-18 15 9.2-30 22 F9.1-19 21 9.2-31 16 F9.1-20 20 9.2-32 18 F9.1-21 20 9.2-33 24 F9.1-22a 21 9.2-34 22 F9.1-22b 21 9.2-35 22 F9.1-23a 26 9.2-36 0 F9.1-23b 26 9.2-37 26 F9.1-23c 26 9.2-38 22 F9.1-23d 26 9.2-39 16 F9.1-23e 26 9.2-40 16 F9.1-23f deleted 26 9.2-40a 26 F9.1-24 21 9.2-41 31 F9.1-25 21 9.2-42 31 F9.1-26 22 9.2-43 24 F9.1-27 22 9.2-44 24 F9.1-28 21 9.2-45 26 F9.1-29 deleted 26 9.2-46 25 F9.1-29a deleted 29 9.2-47 16 F9.1-29b deleted 29 9.2-48 0 F9.1-29c deleted 29 9.2-49 16 F9.1-29d deleted 29 9.2-50 0 F9.1-30 deleted 26 9.2-51 29 F9.1-30a deleted 29 9.2-52 22 F9.1-30b deleted 29 9.2-53 29 F9.1-30c deleted 29 9.2-54 12 F9.1-30d deleted 29 9.2-55 22 F9.1-31 deleted 29 9.2-56 22 F9.1-32 21 9.2-57 17 F9.1-33 21 9.2-58 22 9.2-59 25 9.2-1 21 9.2-60 28 9.2-2 28 9.2-61 18 9.2-3 30 9.2-62 18 9.2-4 18 9.2-62a 16 9.2-5 25 9.2-62b 17 9.2-6 26 9.2-63 26 UNIT 1 9-2 Amendment No. 32 (04/23)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 9 Page Amendment Page Amendment 9.2-64 26 9.3-20 17 9.2-65 29 9.3-21 24 9.2-66 29 9.3-22 28 9.2-67 26 9.3-23 28 9.2-68 29 9.3-24 28 9.2-68a 29 9.3-25 28 9.2-69 28 9.3-26 32 9.2-70 26 9.3-27 21 9.2-71 25 9.3-28 22 9.2-72 14 9.3-29 22 9.2-73 17 9.3-30 22 9.2-74 14 9.3-31 18 9.2-75 0 9.3-31a 17 9.2-76 0 9.3-32 24 9.2-77 28 9.3-32a 28 9.3-33 28 F9.2-1 22 9.3-34 22 F9.2-1a 22 9.3-35 26 F9.2-1b 15 9.3-35a 26 F9.2-1c 15 9.3-36 30 F9.2-1d 15 9.3-37 26 F9.2-1e 15 9.3-38 17 F9.2-2 16 9.3-39 26 F9.2-2A 0 9.3-40 22 F9.2-3 22 9.3-41 22 F9.2-4 16 9.3-42 25 F9.2-4a 15 9.3-43 30 F9.2-5 16 9.3-44 22 F9.2-6 26 9.3-45 26 F9.2-6a 0 9.3-46 30 F9.2-6b 0 9.3-47 17 F9.2-6c 0 9.3-48 28 F9.2-6d 26 9.3-48a 24 F9.2-6e 26 9.3-49 18 F9.2-6f 22 9.3-50 18 F9.2-7 16 9.3-51 18 9.3-52 29 9.3-1 29 9.3-53 29 9.3-1a 29 9.3-54 28 9.3-1b 28 9.3-55 28 9.3-2 28 9.3-56 8 9.3-3 29 9.3-57 29 9.3-4 25 9.3-57a 29 9.3-5 23 9.3-58 28 9.3-6 32 9.3-59 25 9.3-7 22 9.3-60 29 9.3-8 22 9.3-61 22 9.3-9 22 9.3-62 18 9.3-10 22 9.3-63 23 9.3-11 29 9.3-64 0 9.3-12 16 9.3-13 15 9.3-14 25 9.3-15 23 9.3-16 22 9.3-17 30 9.3-18 27 9.3-19 24 UNIT 1 9-3 Amendment No. 32 (04/23)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 9 Page Amendment Page Amendment 9.3-65 26 9.4-10 20 9.3-66 20 9.4-11 26 9.3-67 20 9.4-12 26 9.3-68 24 9.4-12a 27 9.3-69 17 9.4-13 31 9.3-70 18 9.4-14 0 9.3-71 17 9.4-15 30 9.3-72 8 9.4-16 25 9.3-73 17 9.4-17 26 9.3-74 24 9.4-18 24 9.3-75 24 9.4-19 26 9.3-76 17 9.4-20 24 9.3-77 24 9.4-21 26 9.3-78 22 9.4-22 27 9.3-79 17 9.4-23 27 9.3-80 21 9.4-24 0 9.3-81 22 9.4-25 0 9.3-82 21 9.4-26 22 9.3-83 21 9.4-27 22 9.3-84 12 9.4-28 20 9.3-85 17 9.4-29 20 9.3-86 28 9.4-30 20 9.3-87 22 9.4-30a 23 9.3-88 21 9.4-31 24 9.3-89 30 9.4-32 30 9.3-90 17 9.4-33 31 9.3-91 18 9.4-34 31 9.3-92 16 9.4-35 26 9.3-93 24 9.4-36 31 9.4-37 25 F9.3-1 16 9.4-38 30 F9.3-1a 16 9.4-39 21 F9.3-1b 15 9.4-40 0 F9.3-1c 16 9.4-41 3 F9.3-2 15 9.4-42 18 F9.3-3 0 9.4-43 0 F9.3-4 16 F9.3-5 16 F9.4-1 15 F9.3-6 1 F9.4-1a 15 F9.3-7 22 F9.4-2 15 F9.3-8 15 F9.4-2a 15 F9.3-8a 22 F9.4-3 15 F9.3-9 9 F9.4-4 23 F9.4-4A 25 9.4-1 27 F9.4-5 23 9.4-2 24 F9.4-6 0 9.4-3 28 9.4-4 26 9.5-1 28 9.4-5 15 9.5-1a 28 9.4-6 20 9.5-1b 28 9.4-7 0 9.5-1c 28 9.4-8 0 9.5-2 31 9.4-9 17 9.5-3 19 9.5-4 31 9.5-5 27 9.5-6 20 9.5-7 25 UNIT 1 9-4 Amendment No. 32 (04/23)

LIST OF EFFECTIVE PAGES (Cont'd)

CHAPTER 9 Page Amendment Page Amendment 9.5-8 31 9.5-8a 31 9.5-9 19 9.5-10 28 9.5-11 28 9.5-12 28 9.5-13 17 9.5-14 28 9.5-15 25 9.5-16 25 9.5-17 18 9.5-18 18 9.5-19 18 9.5-20 28 9.5-21 18 F9.5-1 15 F9.5-2 16 F9.5-3 16 9.6-1 28 9.6-2 23 9.6-3 29 9.6-4 20 9.6-5 4 9.6-6 29 UNIT 1 9-5 Amendment No. 32 (04/23)

AUXILIARY SYSTEMS CHAPTER 9 TABLE OF CONTENTS Section Title Page 9.1 FUEL STORAGE AND HANDLING 9.1-1 9.1.1 NEW FUEL STORAGE 9.1-1 9.1.1.1 Design Bases 9.1-1 9.1.1.2 System Description 9.1-1 9.1.1.3 System Evaluation 9.1-2 9.1.2 SPENT FUEL STORAGE 9.1-3 9.1.2.1 Design Bases 9.1-3 9.1.2.2 System Description 9.1-3a 9.1.2.3 System Evaluation 9.1-5 9.1.2.4 Testing and Inspection 9.1-8 9.1.2.5 Instrumentation Applications 9.1-8 9.1.3 FUEL POOL SYSTEM 9.1-9 9.1.3.1 Design Bases 9.1-9 9.1.3.2 System Description 9.1-9 9.1.3.3 Component Description 9.1-10 9.1.3.4 System Evaluation 9.1-12 9.1.3.5 Testing and Inspection 9.1-17 9.1.3.6 Instrumentation Application 9.1-17 9.1.3.7 Dilution of the Spent Fuel Pool 9.1-17 9.1.4 FUEL HANDLING SYSTEM 9.1-18 9.1.4.1 Design Bases 9.1-18 UNIT 1 9-i Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Contd)

Section Title Page 9.1.4.2 System Description 9.1-18 9.1.4.3 System Evaluation 9.1-30 9.1.4.4 Tests and Inspections 9.1-44a REFERENCES 9.1-46 9.2 WATER SYSTEMS 9.2-1 9.2.1 INTAKE COOLING WATER SYSTEM 9.2-1 9.2.1.1 Design Bases 9.2-1 9.2.1.2 System Description 9.2-1 9.2.1.3 System Evaluation 9.2-2 9.2.1.4 Testing and Inspections 9.2-6 9.2.1.5 Instrumentation Application 9.2-7 9.2.2 COMPONENT COOLING WATER SYSTEM 9.2-8 9.2.2.1 Design Bases 9.2-8 9.2.2.2 System Description 9.2-8 9.2.2.3 System Evaluation 9.2-10 9.2.2.4 Testing and Inspection 9.2-17 9.2.2.5 Instrumentation Application 9.2-17 9.2.3 CIRCULATING WATER SYSTEMS 9.2-19 9.2.3.1 Design Bases 9.2-19 9.2.3.2 System Description 9.2-19 9.2.3.3 System Evaluation 9.2-20 9.2.3.4 Testing and Inspection 9.2-21 9.2.3.5 Instrumentation Application 9.2-21 UNIT 1 9-ii Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.2.4 TURBINE COOLING WATER SYSTEM 9.2-21 9.2.4.1 Design Bases 9.2-21 9.2.4.2 System Description 9.2-21 9.2.4.3 System Evaluation 9.2-23 9.2.4.4 Testing and Inspection 9.2-23 9.2.4.5 Instrumentation Application 9.2-23 9.2.5 MAKEUP WATER SYSTEM 9.2-23 9.2.5.1 Design Bases 9.2-23 9.2.5.2 System Description 9.2-24 9.2.5.3 System Evaluation 9.2-25 9.2.5.4 Testing and Inspection 9.2-25 9.2.5.5 Instrumentation Application 9.2-25 9.2.6 POTABLE AND SANITARY WATER SYSTEM 9.2-26 9.2.6.1 Design Bases 9.2-26 9.2.6.2 System Description 9.2-26 9.2.6.3 Safety Evaluation 9.2-26 9.2.7 ULTIMATE HEAT SINK 9.2-28 9.2.7.1 Design Bases 9.2-29 9.2.7.2 System Description 9.2-29 9.2.7.3 Design Evaluation 9.2-32 9.2.7.4 Testing and Inspection 9.2-36 UNIT 1 9-iii Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.2.7.5 Instrumentation Application 9.2-36 9.2.8 CONDENSATE STORAGE SYSTEM 9.2-37 9.2.8.1 Design Bases 9.2-37 9.2.8.2 System Description 9.2-37 9.2.8.3 System Evaluation 9.2-37 9.2.8.4 Testing and Inspection 9.2-38 9.2.8.5 Instrumentation Application 9.2-38 9.2.9 STEAM GENERATOR BLOWDOWN COOLING SYSTEM 9.2-39 9.2.9.1 Design Bases 9.2-39 9.2.9.2 System Description 9.2-39 9.2.9.3 System Evaluation 9.2-40 9.2.9.4 Testing and Inspections 9.2-40 9.2.9.5 Instrumentation Application 9.2-40 REFERENCES 9.2-40a 9.3 PROCESS AUXILIARIES 9.3-1 9.3.1 COMPRESSED AIR SYSTEM 9.3-1 9.3.1.1 Design Bases 9.3-1 9.3.1.2 System Description 9.3-1 9.3.1.3 System Evaluation 9.3-2 9.3.1.4 Testing and Inspection 9.3-6 9.3.1.5 Instrument Application 9.3-6 9.3.2 SAMPLING SYSTEM 9.3-7 9.3.2.1 Design Bases 9.3-7 9.3.2.2 System Description 9.3-7 UNIT 1 9-iv Amendment No 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.3.2.3 System Evaluation 9.3-12 9.3.2.4 Testing and Inspection 9.3-13 9.3.2.5 Instrument Application 9.3-13 9.3.3 EQUIPMENT AND FLOOR DRAINAGE SYSTEM 9.3-14 9.3.3.1 Design Bases 9.3-14 9.3.3.2 System Description 9.3-14 9.3.3.3 System Evaluation 9.3-15 9.3.3.4 Testing and Inspection 9.3-16 9.3.3.5 Instrumentation Application 9.3-16 9.3.4 CHEMICAL AND VOLUME CONTOL SYSTEM 9.3-17 9.3.4.1 Design Bases 9.3-17 9.3.4.2 System Description 9.3-19 9.3.4.3 System Evaluation 9.3-33 9.3.4.4 Instrument Application 9.3-41 9.3.5 SHUTDOWN COOLING SYSTEM 9.3-42 9.3.5.1 Design Bases 9.3-42 9.3.5.2 System Description 9.3-42 9.3.5.3 System Evaluation 9.3-45 9.3.5.4 Instrument Application 9.3-48 9.3.5.5 Generic Letter 88-17 Commitments 9.3-48 9.3.6 FAILED FUEL DETECTION SYSTEM 9.3-49 9.3.6.1 Design Basis 9.3-49 9.3.6.2 System Description 9.3-49 UNIT 1 9-v Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.3.6.3 Testing and Inspections 9.3-49 9.3.7 POST ACCIDENT SAMPLING SYSTEM 9.3-49 9.3.7.1 Design Bases 9.3-49 9.3.7.2 System Description 9.3-50 9.3.7.3 Component Description 9.3-51 9.4 AIR CONDITIONING, HEATING, COOLING AND VENTILATION 9.4-1 SYSTEMS 9.4.1 CONTROL ROOM VENTILATION 9.4-1 9.4.1.1 Design Bases 9.4-1 9.4.1.2 System Description 9.4-1 9.4.1.3 System Evaluation 9.4-3 9.4.1.4 Testing and Inspection 9.4-10 9.4.1.5 Instrumentation Application 9.4-10 9.4.2 REACTOR AUXILIARY BUILDING VENTILATION SYSTEMS 9.4-11 9.4.2.1 Design Bases 9.4-11 9.4.2.2 Description 9.4-11 9.4.2.3 System Evaluation 9.4-13 9.4.2.4 Testing and Inspection 9.4-13 9.4.2.5 Instrumentation Application 9.4-14 9.4.3 EMERGENCY CORE COOLING SYSTEM AREA VENTILATION 9.4-15 SYSTEM 9.4.3.1 Design Bases 9.4-15 9.4.3.2 System Description 9.4-15 UNIT 1 9-vi Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.4.3.3 System Evaluation 9.4-16 9.4.3.4 Testing and Inspection 9.4-18 9.4.3.5 Instrumentation Application 9.4-18 9.4.4 RADWASTE AREA VENTILATION 9.4-19 9.4.5 TURBINE BUILDING VENTILATION 9.4-19 9.4.6 FUEL HANDLING BUILDING VENTILATION 9.4-19 9.4.7 DIESEL GENERATOR BUILDING VENTILATION SYSTEM 9.4-20 9.4.8 CONTAINMENT VESSEL VENTILATION SYSTEM 9.4-21 9.4.8.1 Reactor Cavity Cooling System 9.4-21 9.4.8.2 Reactor Support Cooling System 9.4-22 9.4.8.3 CEDM Cooling System 9.4-23 9.4.8.4 Testing and Inspection 9.4-23 REFERENCES 9.4-25 9.5 OTHER AUXILIARY SYSTEMS 9.5-1 9.5.1 FIRE PROTECTION PROGRAM 9.5-1 9.5.2 COMMUNICATIONS SYSTEMS 9.5-2 9.5.2.1 Design Bases 9.5-2 UNIT 1 9-vii Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.5.2.2 System Description 9.5-2 9.5.2.3 System Evaluation 9.5-3 9.5.2.4 Testing and Inspection 9.5-4 9.5.3 LIGHTING SYSTEMS 9.5-4 9.5.4 DIESEL GENERATOR FUEL OIL SYSTEM 9.5-5 9.5.4.1 Design Bases 9.5-5 9.5.4.2 System Description 9.5-7 9.5.4.3 System Evaluation 9.5-8 9.5.4.4 Testing and Inspection 9.5-8 9.5.4.5 Instrumentation Application 9.5-8 9.5.5 DIESEL GENERATOR COOLING WATER SYSTEM 9.5-9 9.5.5.1 Design Bases 9.5-9 9.5.5.2 System Description 9.5-9 9.5.5.3 System Evaluation 9.5-9 9.5.5.4 Instrumentation Application 9.5-10 9.5.6 DIESEL GENERATOR AIR STARTING SYSTEM 9.5-10 9.5.6.1 Design Bases 9.5-10 9.5.6.2 System Description 9.5-10 9.5.6.3 System Evaluation 9.5-11 9.5.6.4 Testing and Inspection 9.5-11 9.5.6.5 Instrumentation Application 9.5-11 9.5.7 DIESEL GENERATOR LUBRICATING SYSTEM 9.5-12 9.5.7.1 Design Bases 9.5-12 UNIT 1 9-viii Amendment No. 28 (05/17)

CHAPTER 9 TABLE OF CONTENTS (Cont'd)

Section Title Page 9.5.7.2 System Description 9.5-12 9.5.7.3 System Evaluation 9.5-12 9.5.7.4 Testing and Inspection 9.5-13 9.5.7.5 Instrumentation Application 9.5-13 REFERENCES 9.5-14 9.5A FIRE PROTECTION APPENDIX 9.5A-i 9.6 CRANES - OVERHEAD HEAVY LOAD HANDLING SYSTEMS 9.6-1 9.6.1 NUREG-0612 "CONTROL OF HEAVY LOADS AT 9.6-1 NUCLEAR PLANTS" 9.6.2 SYSTEMS SUBJECT TO NUREG-0612 9.6-1 9.6.3 IMPLEMENTATION OF NUREG-0612 GUIDELINES 9.6-2 9.6.3.1 Safe Load Paths 9.6-2 9.6.3.2 Load Handling Procedures 9.6-2 9.6.3.3 Crane Operator Training 9.6-2 9.6.3.4 Special Lifting Devices 9.6-2 9.6.3.5 Lifting Devices (Not Specifically Designed) 9.6-3 9.6.3.6 Cranes (Inspection, Testing and Maintenance) 9.6-3 9.6.3.7 Crane Design 9.6-3 9.6.4 DESIGN DESCRIPTION INFORMATION 9.6-4 9.6.4.1 Structures 9.6-4 9.6.4.2 Fuel Handling 9.6-4 UNIT 1 9-ix Amendment No. 28 (05/17)

AUXILIARY SYSTEMS CHAPTER 9 LIST OF TABLES Table Title Page 9.1-1 Deleted 9.1-47 9.1-2 Fuel Pool Water Chemistry 9.1-48 9.1-3 Design Data for Fuel Pool System Components 9.1-49 9.1-4 Fuel Pool System Instrumentation 9.1-51 9.1-5 Failure Mode Analysis of Refueling Machine 9.1-52 9.1-6 Deleted 9.1-54 9.1-7 Deleted 9.1-57 9.1-8 Deleted 9.1-57 9.1-8a Minimum Burnup as a Function of Enrichment 9.1-60a 9.1-8b Deleted 9.1-60b 9.1-9 Design Data 9.1-61 9.1-10 Table of Module Data 9.1-62 9.1-11 Module Dimensions and Weight 9.1-63 9.1-12 Summary of Criticality Safety Analyses for the Cask Pit Rack 9.1-64 9.1-12a Summary of Criticality Safety Analyses for the SFP, 0 ppm 9.1-64a 9.1-12b Summary of Criticality Safety Analyses for the SFP, 500 ppm 9.1-64b 9.1-13 Reactivity Effects of Abnormal and Accident Conditions 9.1-65 9.1-14 Calculated Peak Bulk Spent Fuel Pool Temperature Results 9.1-66 9.1-15 Deleted 9.1-67 9.1-16 Heat Transfer Data for the Fuel Pool Heat Exchanger 9.1-68 9.1-17 Historic and Projected Offload Schedule 9.1-69 9.1-18 Deleted 9.1-70 9.1-19 Deleted 9.1-70 9.1-20 Deleted 9.1-70 9.1-21 Deleted 9.1-70 9.1-22 Deleted 9.1-70 9.1-23 Loss of Cooling Time-To-Boil Calculation Results 9.1-75 9.1-24 Deleted 9.1-76 9.1-25 Local Temperature Analysis Results 9.1-77 9.2-1 Design Data for Intake Cooling Water System 9.2-41 9.2-2 Single Failure Analysis - Intake Cooling Water System 9.2-43 9.2-3 Intake Cooling Water System Instrumentation Application 9.2-45 9.2-3A Procedure for Visual Inspection of Welds 9.2-47 9.2-4 Design Data for Component Cooling System Components 9.2-50 9.2-5 Operating Flow Rates and Calculated Heat Loads for All Auxiliary 9.2-53 Equipment Cooled by the Component Cooling Water System 9.2-6 Single Failure Analysis - Component Cooling Water System 9.2-55 9.2-7 Component Cooling Water System Instrumentation Application 9.2-57 9.2-8 Design Data for Circulating Water System Components 9.2-61 9.2-9 Circulating Water System Instrumentation Application 9.2-63 9.2-10 Design Data for Turbine Cooling Water System Components 9.2-64 9-x Amendment No. 28 (05/17)

CHAPTER 9 LIST OF TABLES (Cont'd)

Table Title Page 9.2-11 Turbine Plant Components Operating Flow Rates and Calculated 9.2-66 Heat Loads 9.2-12 Turbine Cooling Water System Instrumentation Applications 9.2-67 9.2-13 Design Data for Makeup Water System Components 9.2-71 9.2-14 Makeup Water System Instrumentation Application 9.2-73 9.2-15 Design Data for Potable and Sanitary Water System Components 9.2-74 9.2-16 Design Data for Condensate Storage Tank 9.2-75 9.2-17 Design Data for Steam Generator Blowdown Cooling System 9.2-76 9.3-1 Design Data for Compressed Air System Components 9.3-52 9.3-2 Compressed Air System Instrument Application 9.3-57 9.3-3 Sampling System Flow Rates 9.3-60 9.3-4 Design Data for Sample System Components 9.3-61 9.3-5 Sampling System Instrumentation 9.3-62 9.3-6 Drains Routed to Drain Tanks 9.3-63 9.3-7 Intentionally Deleted 9.3-64 9.3-8 Reactor Coolant and Reactor Makeup Water Chemistry 9.3-65 9.3-9 Design Transients - Regenerative and Letdown Heat Exchangers 9.3-66 9.3-10 Chemical and Volume Control System Parameters 9.3-68 9.3-11 Chemical and Volume Control System Process Flow Data 9.3-69 9.3-12 Regenerative Heat Exchanger Design Data 9.3-73 9.3-13 Letdown Heat Exchanger Design Data 9.3-74 9.3-14 Purification Filters Design Data 9.3-75 9.3-15 CVCS Ion Exchangers Design Data 9.3-75 9.3-16 Volume Control Tank Design Data 9.3-76 UNIT 1 9-xi Amendment No. 28 (05/17)

CHAPTER 9 LIST OF TABLES (Cont'd)

Table Title Page 9.3-17 Charging Pumps Design Data 9.3-77 9.3-18 Boric Acid Makeup Tanks Design Data 9.3-78 9.3-19 Boric Acid Batching Tank Design Data 9.3-78 9.3-20 Boric Acid Makeup Pumps Design Data 9.3-78 9.3-21 Chemical Addition Tank Design Data 9.3-79 9.3-22 Metering Pump Design Data 9.3-79 9.3-23 Process Radiation Monitor Design Data 9.3-80 9.3-24 Boronometer Design Data 9.3-80 9.3-25 Single Failure Analysis - Chemical and Volume Control System 9.3-81 9.3-26 Chemical and Volume Control System Instrument Application 9.3-86 9.3-27 Shutdown Cooling System Design Data 9.3-89 9.3-28 Shutdown Heat Exchanger Design Data 9.3-89 9.3-29 Shutdown Cooling System Instrument Application 9.3-90 9.3-30 Post Accident Sampling System Component Data Summary 9.3-91 9.3-31 Zinc Injection Skid Design Data 9.3-93 9.4-1 Design Data for Control Room Ventilation System Components 9.4-26 9.4-1A Concentrations Outside Control Room Intake (Historical) 9.4-28 9.4-1B Puff Component of Chlorine Release Inflow into Control Room at 9.4-29 Time "t" (Historical) 9.4-1C Chlorine Concentrations in Control Room Due to Combined Effect of 9.4-30 Puff and Continuous Source (Historical) 9.4-1D Toxic Chemical Evaluation 9.4-30a UNIT 1 9-xii Amendment No. 28 (05/17)

CHAPTER 9 LIST OF TABLES (Cont'd)

Table Title Page 9.4-2 Control Room Ventilation System Instrumentation Application 9.4-31 9.4-3 Design Data for Reactor Auxiliary Building Ventilation System 9.4-32 Components 9.4-4 Reactor Auxiliary Building Ventilation Systems Instrumentation 9.4-35 Application 9.4-5 Auxiliary Building Components with SIAS, Interlocks or Manual 9.4-37 Controls 9.4-6 Design Data for ECCS Area Ventilation Equipment System 9.4-39 Components 9.4-7 Design Data for Turbine Building, Fuel Pool, and Diesel Generator 9.4-41 Building Heating and Ventilation System Components 9.4-8 Design Data for Reactor Support Cooling System and Reactor 9.4-43 Cavity Cooling System 9.5-1 Design Data for Diesel Generator Fuel Oil System 9.5-15 9.5-2 Diesel Generator Fuel Oil System Instrumentation Application 9.5-17 9.5-3 Design Data for Diesel Engine Cooling Water System Components 9.5-18 9.5-4 Design Data for Diesel Generator Starting System Components 9.5-20 9.5-5 Design Data for Diesel Generator Lube Oil System Components 9.5-21 9.6-1 NUREG-0612 Compliance Matrix 9.6-5 UNIT 1 9-xiii Amendment No. 28 (05/17)

AUXILIARY SYSTEMS CHAPTER 9 LIST OF FIGURES Figure Title 9.1-1 Fuel Handling Bldg New Fuel Storage Racks 9.1-2 Spent Fuel Pool Layout 9.1-3 Flow Diagram Fuel Pool System 9.1-4 Spent Fuel Pool Storage Rack Typical Cell Elevation Region 1 9.1-5 Spent Fuel Pool Storage Rack Typical Cell Elevation Region 2 9.1-6 Deleted 9.1-7 Reactor Refueling Arrangement 9.1-8 I/M Reactor Internal Lift Rigs 9.1-9 Refueling Machine 9.1-10 Deleted 9.1-11 Reactor Vessel Head Lifting Rig 9.1-12 Core Support Barrel Lifting Rig 9.1-13 Surveillance Capsule Retrieval Tool Assembly 9.1-14 Permanent Reactor Cavity Seal/Shield Ring General Assembly 9.1-15 Deleted 9.1-15a Deleted 9.1-15b Deleted 9.1-16 Deleted 9.1-17 Fuel Handling Building Steel Framing - Sheet 1 9.1-18 Fuel Handling Building Steel Framing - Sheet 2 9.1-19 Deleted 9.1-20 Deleted 9-xiv Amendment No. 22 (05/07)

CHAPTER 9 LIST OF FIGURES (Cont'd)

Figure Title 9.1-21 Deleted 9.1-22a Schematic Configuration of the Calculational Model for Fresh Assemblies in Region 2 Racks for Inspection and Reconstitution 9.1-22b Schematic Configuration of the Calculational Model for Fresh Assemblies in Region 2 Racks for Inspection and Reconstitution 9.1-23a Minimum Burnup as a Function of Initial Enrichment for Fuel Type 1 9.1-23b Minimum Burnup as a Function of Initial Enrichment for Fuel Type 2 9.1-23c Minimum Burnup as a Function of Initial Enrichment for Fuel Type 3 9.1-23d Minimum Burnup as a Function of Initial Enrichment for Fuel Type 4 9.1-23e Minimum Burnup as a Function of Initial Enrichment for Fuel Type 5 9.1-24 Spent Fuel Pool Storage Rack Region 1 Storage Cell Geometry 9.1-25 Spent Fuel Pool Storage Rack Region 2 Storage Cell Geometry 9.1-26 Spent Fuel Pool Storage Rack Typical Rack Elevation Region 1 9.1-27 Spent Fuel Pool Storage Rack Typical Rack Elevation Region 2 9.1-28 Cask Pit Rack Typical Region 1 Storage Cell Geometry 9.1-29a Deleted 9.1-29b Deleted 9.1-29c Deleted 9.1-29d Deleted 9.1-30a Deleted 9.1-30b Deleted 9.1-30c Deleted 9.1-30d Deleted 9.1-31 Deleted 9.1-32 Cask Pit Rack Typical Cask Pit Rack Storage Cell Layout 9.1-33 Cask Pit Rack Elevation View Cask Pit Rack Storage Cells 9.2-1 Flow Diagram Circulating and Intake Cooling Water System Sheet 1 9.2-1a Flow Diagram Circulation and Intake Cooling Water System Sheet 2 9.2-1b Circulating Water System Ocean Intake and Discharge Sheet 1 9.2-1c Circulating Water System Ocean Intake & Discharge "Profile" 9.2-1d Circulating Water System Ocean Intake & Disch Sections & Details Sheet 2 9.2-1e Circulating Water System Ocean Intake & Disch Sections & Details Sheet 3 9.2-2 Flow Diagram Component Cooling System 9.2-2A Component Cooling Water Pump 1C Pump-Valve Alignment Annunciation 9.2-3 Detail of Y Outfall for Circulating Water Discharge 9.2-4 Flow Diagram Turbine Cooling Water System 9.2-4a Flow Diagram Turbine Cooling Water System 9.2-5 Flow Diagram Fire Water, Domestic and Make-Up Systems 9-xv Amendment No. 29 (10/18)

CHAPTER 9 LIST OF FIGURES (Cont'd)

Figure Title 9.2-6 Emergency Cooling Water Canal 9.2-6a Canal Barrier Differential Water Levels Design Conditions 9.2-6b Ocean Intake Headwall Sections 9.2-6c Intentionally Deleted 9.2-6d UHS Canal Barrier 9.2-6e UHS Canal Barrier Cross-Section 9.2-6f Flow Diagram Miscellaneous Systems 9.2-7 Flow Diagram Fire Protection System 9.3-1 Flow Diagram Service Air System 9.3-1a Flow Diagram Instrument Air System 9.3-1b Flow Diagram Instrument Air System 9.3-1c Flow Diagram Instrument Air Systems 9.3-2 Flow Diagram Sampling System 9.3-3 Chemical and Volume Control System Flow Schematic 9.3-4 Flow Diagram Chemical and Volume Control System 9.3-5 Flow Diagram Chemical and Volume Control System 9.3-6 Shutdown Cooling Flow Diagram Operational Mode 9.3-7 Deleted 9.3-8 Flow Diagram Miscellaneous Sampling Systems Sheet 1 9.3-8a Flow Diagram Miscellaneous Sampling Systems Sheet 2 9.3-9 Boric Acid Solubility 9.4-1 HVAC - Air Flow Diagram 9.4-2 HVAC - Control Diagrams - Sheet 1 9.4-3 HVAC - Control Diagrams - Sheet 2 9.4-4 Deleted 9.4-5 Deleted 9.4-6 Air Flow Diagram for Reactor Cavity, Support Leg and Control Rod Drive Mechanism Cooling Systems 9.5-1 Flow Diagram Miscellaneous Systems Sheet 1 9.5-2 Flow Diagrams Emergency Diesel Generator System Diesel Generator 1A 9.5-3 Flow Diagrams Emergency Diesel Generator System Diesel Generator 1B 9-xvi Amendment No. 24 (06/10)

CHAPTER 9 AUXILIARY SYSTEMS The auxiliary systems discussed in this section are those supporting systems which are required to ensure the safe operation, protection or servicing of the major unit systems and, principally, the reactor coolant system. In some cases the dependable operation of several systems is required to fulfill the above requirements and, additionally, certain systems are required to operate under emergency conditions. The extent of the information provided for each system is commensurate with the relative contribution of, or reliance placed upon the system in relation to the overall plant safety.

The majority of the active components within these systems are located outside of the containment. Those systems with connecting piping or duct work between the containment and the reactor auxiliary building are equipped with containment isolation valves as described in Section 6.2.4.

9.1 FUEL STORAGE AND HANDLING Note: Dry storage of spent fuel, pursuant to 10 CFR 72, is provided as discussed in Section 1.2.2.11.

The following sections relate to fuel storage and handling under 10 CFR 50.

9.1.1 NEW FUEL STORAGE 9.1.1.1 Design Bases The new fuel storage rack is designed to:

a) store 80 fuel assemblies b) provide sufficient spacing between the fuel assemblies to maintain a subcritical array during flooding with nonborated water c) maintain a subcritical array under all design loadings, including the design basis earthquake d) preclude the possibility of a fuel assembly being placed between the new fuel cavities e) maintain a subcriticality of at least 2 percent for the simultaneous occurrence of design bases (b) and (c).

Additionally, in December of 1998 St. Lucie Plant elected to comply with the requirements of 10 CFR 50.68(b),

which includes restrictions on the reactivity of stored fresh (i.e., new) fuel.

9.1.1.2 System Description The location of the new fuel storage rack is illustrated in the fuel handling building general arrangement drawings, Figures 1.2-18 and 1.2-19. The new fuel storage rack is shown on Figure 9.1-1.

The method of transferring new fuel into the fuel handling building and placing it into the new fuel storage racks is discussed in Section 9.1.4.

9.1-1 Amendment No. 23 (11/08)

New fuel is stored dry at a floor elevation of 48 ft with the top of the rack at an elevation of 62 ft. This height precludes PMH induced flooding of the storage racks; nevertheless, the array of fuel assemblies is spaced to remain subcritical if flooded with nonborated water.

The new fuel storage racks consist of 80 square cavities in two separate 4 by 10 arrays separated by an aisle about 42 inches wide, formed by sealing off two central rows of storage ports. The size of the cavities (8-15/16 x 8-16/16) is sufficient to hold one fuel assembly in a vertical position. Each cavity has a hinged plate cover.

The supporting structure is designed to limit deflections so that subcriticality is maintained under all anticipated loadings. The clearance between structural framing members is small enough to prevent the wedging of a fuel assembly between adjacent cavities.

The new fuel is subjected to a maximum ambient temperature of 110°F.

9.1.1.3 System Evaluation The new fuel in the storage rack is subcritical by at least 2 percent under the assumption of flooding with nonborated water and 4.6 weight percent enriched uranium. A Technical Specification change request to utilize this enrichment was forwarded to the NRC in Reference 14 and accepted by the NRC in Reference 15.

Calculations performed for the new fuel storage racks at various degrees of moderation, including full flooding, indicate that the limiting Keff occurs for a moderator void fraction of 0.91 and has a value of 0.9767 at the 95%

confidence level. This value is within the safety criteria limit of 0.98 required for new fuel storage racks under optimum moderation conditions.

The new fuel storage racks are designed in accordance with the American Institute of Steel Construction (AISC)

Specification for the Design, Fabrication and Erection of Structural Steel for Buildings and meets ANSI Standard N18.2 paragraph 5.7.4.1. The racks and their supports are designed as seismic Class I as is the Fuel Handling Building discussed in Sections 3.8.1.1.2.

Lateral loads exerted on the rack support structure are resisted by a vertical bracing system which transmits these forces to the concrete floor or through horizontal members into the concrete walls via anchor bolts. Lateral movement of the rack with any number of fuel assemblies is prevented by these supports for all anticipated loadings.

9.1-2 Amendment No. 26 (11/13)

Regulatory position C.3 of Safety Guide 13 requires that "Interlocks should be provided to prevent cranes from passing over stored fuel . . . when fuel handling is not in progress". The only device capable of placing loads over the new fuel racks is the 5 ton capacity fuel transfer hoist. This hoist is used for handling fuel and RCP seal assemblies and tester in the new fuel building under controlled procedural conditions. The hoist may be used for maintenance and test activities when no new fuel is stored in the new fuel storage area.

9.1.2 SPENT FUEL STORAGE 9.1.2.1 Design Bases The fuel pool is designed to provide safe storage for 1706 spent fuel assemblies, control element assemblies, and new fuel during initial core loading. The system design includes interlocks, travel limits and other protective devices to minimize the probability of either mishandling or of equipment malfunction that could result in inadvertent damage to a fuel assembly and potential fission product release. Criticality is precluded by the spacing of fuel assemblies to ensure a subcritical array of Keff 0.95 is maintained, assuming credit for a portion of the soluble boron present in the fuel pool water (as discussed in Reference 23) and design basis earthquake (DBE) loading. The pool will always contain boric acid at the refueling concentration of at least 1900 ppm whenever there is irradiated fuel in the pool.

In conjunction with the fuel pool storage racks, an additional rack (cask pit rack) is capable of being installed in the cask pit area of the spent fuel pool. The cask pit rack is removable and designed to provide storage for an additional 143 assemblies. This brings Unit 1 total storage capability to 1849 assemblies with the cask pit rack installed. The cask pit rack is a Region 1 design capable of storing either fresh fuel or spent fuel regardless of burnup history. The cask pit rack is designed to maintain Keff 0.95 when the rack is fully loaded with fuel assemblies and flooded with unborated water.

The fuel handling building exterior walls, floors and interior partitions are designed to provide plant personnel with the necessary radiation shielding and to protect the equipment from the effects of adverse atmospheric conditions including winds, temperature, missiles and corrosive environment. Limit switches on the spent fuel handling machine prevent fuel from being raised to where there is less than 9 ft separating the surface of the water and the top of the active fuel length. Under these conditions and when not refueling, the direct dose rate at the pool surface is less than 2.5 mrem/hr. This number is calculated using the most active fuel assembly two days after shutdown. If the interlock should fail and if there were no operator action, the fuel handling machine could not raise the assembly above a 9 ft water-to-active-fuel-length height because of the geometry of its design. Under the conditions described above, the dose rate at the surface of the water above the assembly would be 2.5 mrem/hr or less. The grappling tool on the spent fuel handling machine is designed so that a fuel assembly cannot be released accidentally. A fuel assembly in the spent fuel pool can not be dropped from a height greater than that associated with the top of the active fuel located 9 feet below the pool water surface. The shielding provided in the fuel handling building is discussed in Section 12.1.2.4. A dividing wall to the top of the spent fuel racks separates the cask storage area of the pool from the spent fuel storage area. The wall prevents the water level from uncovering the spent fuel assemblies even if a dropped fuel cask causes damage to the pool or pool liner in the cask handling area.

Additionally, in December of 1998 St. Lucie Plant elected to comply with the requirements of 10 CFR 50.68(b),

which includes restrictions on the reactivity of stored spent fuel. Following issuance of Reference 25, St. Lucie Unit 1 now credits the presence of soluble boron in fuel pool water during normal operating conditions, consistent with requirements of 10 CFR 50.68(b)(4).

9.1-3 Amendment No. 26 (11/13)

9.1.2.2 System Description 9.1.2.2.1 Fuel Handling Building The fuel handling building general arrangement showing the location of the spent fuel storage facilities is given in Figures 1.2-18 and 1.2-19.

The fuel handling building consists of cast-in-place concrete exterior walls with interior walls which are of reinforced concrete construction. It is completely isolated from all other structures. The floors and roof are of beam and girder construction supported by columns. The building exterior walls, floors and interior partitions are designed to provide plant personnel with the necessary biological radiation shielding and protect the equipment inside from the effects of adverse environmental conditions including tornado and hurricane winds, temperature, external missiles and flooding. The design missiles are discussed in Section 3.5. Details of the structural design and analysis are given in Section 3.8.

The fuel handling building also houses the fuel handling building heating and ventilating equipment, the fuel pool heat exchanger, the fuel pool filter, the fuel pool cooling pumps and the fuel pool purification pump. In addition, the fuel handling building provides space for the storage of new fuel (refer to Section 9.1.1). Attached to the north outside wall of the fuel handling building, the Cask Handling Facility provides a decontamination area for spent fuel casks and miscellaneous equipment.

9.1-3a Amendment No. 23 (11/08)

9.1.2.2.2 Spent Fuel Pool and Cask Pit Area The spent fuel pool and adjacent cask pit area are a cast-in-place steel-lined reinforced concrete tank structure that provides space for storage of spent fuel assemblies, control element assemblies, and new fuel during core loading. The fuel pool/cask pit portion of the FHB including the walls and roof directly above the pool and pit are designed to withstand, without penetration, the impact of high velocity external missiles that might occur during the passage of a tornado. The design missiles are further discussed in Section 3.5.

The fuel pool meets those portions of Safety Guide 13 applying to the pool (13.C.1, 2, 3, 4, 5, 7) with the exception of 13.C.4. The fuel handling building is not a controlled leakage facility; however, doses from a refueling accident are kept within the guidelines established for design basis accidents without a controlled leakage building as discussed further in Section 9.4.6. The assumptions, evaluation, and results of the fuel handling accident analysis are given in Section 15.4.3. Positions one, two, three, five, and seven are met in the following ways:

Position 1: The spent fuel storage facility is seismic class I as described in Sections 3.7 and 3.8.

The seismic design control measures used to assure that the vendor has designed spent fuel racks to withstand a DBE are discussed in Section 3.7.5.

Position 2: The spent fuel storage facility is designed against hurricane or tornado winds and missiles generated by the winds from significantly affecting the integrity of the pool.

Missiles generated by hurricane or tornado winds are prevented from penetrating the building (refer to Table 3.2-1). The fuel handling building is designed in accordance with the ACI Standard Building Code Requirements for Reinforced Concrete, ACI 318-63 Part IVB, Ultimate Strength Design. Details of the structural design and analysis of the fuel handling building are given in Section 3.8.

Position 3: PSL is in compliance with NUREG-0612 and therefore in compliance with Safety Guide 13, position C3. The outdoor spent fuel cask handling crane is a single-failure-proof design with interlocks and physical stops, including the physical design of the building roof opening above the cask pit area, that prevent the crane from carrying a load over irradiated fuel stored in the adjacent spent fuel pool.

The spent fuel handling machine crane and trolley will not be parked over the spent fuel storage racks, when not handling fuel. Both the bridge and trolley of the spent fuel handling machine have lugs which engage the rails and prevent the bridge or trolley from lifting off the rails or overturning from any position during a DBE.

Position 5: The cask handling crane main hoist meets Position C.5.b. The cask handling crane is designed to provide single-failure-proof handling of heavy loads, so that a single failure will not result in a loss of capability of the crane handling system to perform its function of safely holding the load. With this design, the potential for a cask drop is considered to be extremely small, such that a cask drop accident need not be analyzed in accordance with Section 5.1.2 of NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants".

The crane auxiliary hoist is not designed to be single-failure-proof. However, administrative controls prohibit use of the auxiliary hoist inside the fuel handling building.

Therefore, a lost drop analysis inside the fuel handling building is not necessary to meet this position.

In addition, the cask handling crane cannot approach any area above where spent fuel is stored because of the design of the crane runway, the physical design of the building, and travel limit switch interlock circuitry.

9.1-4 Amendment No. 24 (06/10)

The fuel pool is designed to withstand dropping of a fuel assembly from the highest elevation that it can be lifted to by the spent fuel handling machine.

Position 7: Reliable and frequently tested (refer to Section 9.1.2.5) monitoring equipment will provide local and control room alarm of high radiation and low fuel pool water level. The fuel pool cooling system instrumentation is discussed in Section 9.1.3.6.

The fuel pool is located outside the containment in the fuel handling building. The pool is designed for the underwater storage of 1706 spent fuel assemblies (7.8 cores) plus 143 fuel assemblies in the cask pit rack, when installed and the fuel handling tools. Control element assemblies removed from the core are stored within the fuel assemblies. The pool is lined with stainless steel ASTM Specification A240, Type 304, which is the material for all of the stainless steel angles attached to the outside of the pool liner walls. This material resists the corrosive effect of boric acid in the fuel pool water.

The cask pit is located in the northeast corner of the fuel handling building and shares water with the adjacent spent fuel pool. The cask pit is sized to hold a spent fuel transfer cask. Similar to the pool, the cask pit is lined with stainless steel plate. The pit floor is approximately 3.5 feet below the floor of the spent fuel pool. The north and east pit walls are shared with the spent fuel pool. The south and west pit walls are submerged metal walls welded to the side walls at the approximate height of the top of the spent fuel pool storage racks. The height of the submerged wall is designed to maintain the pool water level above the stored fuel if an unisolable leak were to occur inside the cask pit that would completely drain the pit.

A leak detection system is provided to monitor 100 percent of the pool liner welds. The system consists of a network of stainless steel angles attached to the outside of the pool liner walls and floor by means of welds and epoxy material (Devcon ST). These monitor channels do not constitute part of the pool liner boundary but are water tight to the extent necessary to collect and isolate any leakage through the liner plate. In the event that one of the liner plate weld seams develops a leak, the liquid enters the monitor channel system and flows to one of 19 collection points at the base of the pool. In this way the leakage can be determined by pressurizing the leaking channel and looking for bubbles inside the pool. Each of the channels can be valved off in order to prevent further leakage from the pool.

9.1.2.2.3 Spent Fuel Pool Storage Racks The function of the spent fuel pool storage racks is to provide for storage of spent fuel assemblies in a flooded pool, while maintaining a coolable geometry, preventing criticality, and protecting the fuel assemblies from excessive mechanical or thermal loadings.

A list of design criteria is given below:

1. The racks are designed in accordance with the NRC, "OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications," dated April 14, 1978 (as amended by the NRC letter dated January 18, 1979) and SRP Section 3.8.4.
2. The racks were designed to meet the nuclear requirements of ANSI N210-1976.

The effective neutron multiplication factor, keff, in the spent fuel pool is less than 1.0 considering all relevant biases and uncertainties, when no soluble boron is assumed present. Keff is maintained less than or equal to 0.95, including the effects of all appropriate biases and uncertainties and under all credible conditions when soluble boron is present in the fuel pool.

3. The racks are designed to allow coolant flow such that boiling in the water channels between the fuel assemblies in the rack does not occur.

9.1-4a Amendment No. 25 (04/12)

4. The racks are designed to seismic Category I requirements, and are classified as ANS Safety Class 3 and ASME Code Class 3 Component Support Structures.
5. The racks are designed to withstand loads without violating the criticality acceptance criteria which may result from fuel handling accidents and from the maximum uplift force of the spent fuel handling machine. The spent fuel handling machine hoist load interlock is established to prevent fuel damage, consistent with fuel assembly design limits.
6. Each storage position in the racks is designed to support and guide the fuel assembly in a manner that will minimize the possibility of application of excessive lateral, axial and bending loads to fuel assemblies during fuel assembly handling and storage.
7. The racks are designed to preclude the insertion of a fuel assembly in other than design locations within the rack array.
8. The materials used in construction of the racks are compatible with the storage pool environment and will not contaminate the fuel assemblies.

The high density spent fuel storage racks consist of individual cells with 8.65 inch by 8.65 inch (nominal) square cross-section, each of which are designed to accommodate a single Combustion Engineering or Framatome PWR fuel assembly or equivalent, from St. Lucie Unit 1. A total of 1706 cells are arranged in 17 distinct modules of varying sizes in two regions. Region 1 is designed to store fresh 4.6 wt% fuel in a checkerboard of fresh and empty cells and spent fuel in the following fuel types:

  • Fuel Type 1: Region 1 storage rack 2x2 array of uniformly loaded spent fuel with an initial enrichment of 1.9 to 4.6 wt%, with one cell containing a MetamicTM insert or one fuel assembly containing absorber rods. No credit for cooling time.
  • Fuel Type 2: Region 1 storage rack 2x2 array uniformly loaded with spent fuel with an initial enrichment of 1.9 to 4.6 wt% in any three storage locations and one storage location empty. No credit for MetamicTM inserts, absorber rods or cooling time.

Region 2 is designed to store spent fuel in the following Fuel Types:

  • Fuel Type 3: Region 2 storage rack 2x2 array uniformly loaded with spent fuel with an initial enrichment of 1.9 to 4.6 wt%, with one empty location out of the four storage locations. No credit for MetamicTM inserts or absorber rods or for cooling time.
  • Fuel Type 4: Region 2 storage rack 2x2 array uniformly loaded with spent fuel with an initial enrichment of 1.9 to 4.6 wt%, with any two of the four cells containing a MetamicTM insert or absorber rods in the fuel assemblies, and the consideration of cooling times of 0, 2.5, 5, 10, 15, and 20 years.
  • Fuel Type 5: Region 2 storage rack 2x2 array uniformly loaded with spent fuel with an initial enrichment of 1.9 to 4.6 wt%, with any one of the four cells containing a MetamicTM insert or absorber rods in the fuel assemblies, and the consideration of cooling times of 0, 2.5, 5, 10, 15, and 20 years.

Limited quantities of fresh fuel can be placed in Region 2, for testing or other purposes, subject to strict controls on the fuel positioning (see Figures 9.1-22a and 9.1-22b). Fuel rod storage baskets may also be placed in Region 2. Figure 9.1-2 shows the arrangement of the rack modules in the spent fuel pool.

The high density racks are engineered to achieve the dual objective of maximum protection against structural loadings (arising from ground motion, thermal stresses, etc.) and the maximization of available storage locations. In general, a greater width-to-height aspect ratio provides greater margin against rigid body tipping. Hence, the modules are made as large as possible within the constraints of transportation and site handling capabilities.

9.1-4b Amendment No. 26 (11/13)

As shown in Figure 9.1-2, there are 17 discrete modules arranged in the fuel pool. Each rack module is equipped (see Figures 9.1-26 and 9.1-27) with girdle bars, 3/4-inch thick by 3-1/2 inches high. The nominal gap between adjacent module walls is 1-1/2 inches. The modules make surface contact between their contiguous walls at the girdle bar locations and thus maintain a specified gap between the cell walls. Table 9.1-9 gives the relevant design data on each region. The modules in two regions are of eight different types. Tables 9.1-10 and 9.1-11 summarize the physical data for each module type.

A nominal 10.12 inches center to center distance between fuel assemblies in Region 1 of the storage racks and a nominal 8.86 inches center to center distance between fuel assemblies in Region 2 of the storage racks is included in the design as shown in Figures 9.1-4 and 9.1-5. Loading of the fuel assemblies into the racks may be facilitated by the use of lead-in funnels.

As originally fabricated, Region 1 and 2 rack modules contained a neutron absorber material. Boraflex, that is a silicone-based polymer containing fine particles of boron carbide in a homogenous matrix.

Subsequent to the installation of rack modules containing this absorber material in the Unit 1 fuel pool, Boraflex was determined to be unsuitable for its intended application. Current fuel pool criticality analyses do not credit Boraflex as a neutron absorber or require that it be present in spent fuel storage racks. As a result, from the perspective of criticality analysis calculations, all Region 1 and Region 2 rack cells can accept placement of irradiated fuel.

9.1.2.2.4 Cask Pit Storage Racks The function of the cask pit storage rack is to provide for storage of fresh or spent fuel assemblies in a flooded pool, while maintaining a coolable geometry, preventing criticality, and protecting the fuel assemblies from excessive mechanical or thermal loading.

A list of design criteria for the cask pit rack is given below:

1. The rack is designed in accordance with the NRC, "OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications," dated April 14, 1978 (as amended by the NRC letter dated January 18, 1979) and SRP Section 3.8.4.
2. The rack is designed to meet the requirements of General Design Criterion 62, "Prevention of Criticality in Fuel Storage and Handling," 10 CFR 50.68, "Criticality Accident Requirements," and ANSI 8.17, "Criticality Safety Criteria for the Handling, Storage and Transportation of LWR Fuel Outside Reactors". The cask pit rack is designed to maintain Keff of 0.95 including uncertainties and tolerances and with unborated water in the spent fuel pool.
3. The rack is designed to allow coolant flow such that boiling in the water channels between the fuel assemblies in the rack does not occur.

9.1-4c Amendment No. 25 (04/12)

4. The rack is designed as Class 3 Component Support Structures in accordance with the ASME Code,Section III, Division 1, subsection NF, 1989 edition.
5. The rack is designed to withstand the load and load combinations specified in NRC "OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications,"

dated April 14, 1978 (as amended by the NRC letter dated January 18, 1979) and SRP Section 3.8.4 without violating the criticality acceptance criteria.

6. Each storage position in the rack is designed to support and guide the fuel assembly in a manner that will minimize the possibility of application of excessive lateral, axial and bending loads to fuel assemblies during fuel assembly handling and storage.
7. The rack is designed to preclude the insertion of a fuel assembly in other than design locations within the rack array.
8. The materials used in the construction of the rack is compatible with the storage pool environment and will not contaminate the fuel assemblies.

The cask pit storage rack consists of individual cells with an 8.58-inch (nominal) square cross-section separate by a 1.303-inch flux trap or water gap. The center to center distance between cells is 10.3 inches. The cask pit rack has a total of 143, Region 1, cells designed for storage of new or spent fuel assemblies with enrichments up to 4.6 weight percent U-235.

The poison used in the cask pit rack is Boral. Boral is composite material made of boron carbide and 1100-alloy aluminum that is formed into panels. A Boral panel is installed on the outside face of each cell with the exception of those on the outer perimeter of the rack. Tables 9.1-9, 9.1-10 and 9.1-11 summarize the physical data for the cask pit rack. Figure 9.1-2 shows the arrangement of the cask pit rack, when installed, in the cask pit of the spent fuel pool. Figures 9.1-32 and 9.1-33 provide typical cell layout and elevation views.

The cask pit floor is recessed and its elevation is approximately three and one-half feet below the SFP floor. This configuration requires the cask pit rack to be placed on a platform to elevate the top of the rack to the same height as the other storage racks in the SFP. The cask pit rack and platform are removable to allow a fuel transfer cask to be placed in the cask pit during the fuel transfer operations.

9.1-4d Amendment No. 26 (11/13)

9.1.2.3 System Evaluation 9.1.2.3.1 Nuclear and Thermal-Hydraulic Considerations 9.1.2.3.1.1 Neutron Multiplication Factor The following subsections describe the conditions in the spent fuel pool which are assumed in calculating the effective neutron multiplication factor (keff), the analysis methodology, and the analysis results.

9.1.2.3.1.2 Spent Fuel Pool Rack Normal Storage Considering both Region 1 and Region 2 racks, the criticality analysis of Unit 1 spent fuel storage evaluates five unique checkerboard fuel arrangements. Each storage arrangement is analyzed for a range of fuel enrichments between 1.9 w/o and 4.6 w/o U-235. The specific enrichment values analyzed depend on whether or not an assembly contains axial blankets. To determine the effect of actinide (primarily Pu-241) decay and longer-lived fission products on required burnup, six different values of post-irradiation cooling time are considered, ranging from 0 to 20 years. The effects on reactivity of radial variations in fuel enrichment within the rod lattice, tolerances in manufacturing and fabrication parameters, and time-dependent variations in fission product concentration were also considered. Table 9.1-12a summarizes the results of representative calculations of keff for each fuel storage configuration at the no boron condition. Each calculation yields a final keff value <1.0; thus, all results comply with the acceptance criteria mandated by 10 CFR 50.68(b)(4).

Calculations to quantify the soluble boron concentration necessary to ensure keff remains 0.95 were performed. Table 9.1-12b summarizes the results of these calculations for each fuel storage arrangement. Soluble boron concentrations necessary to compensate for both normal and accident conditions were substantially less than the 1900 ppm required by St. Lucie Unit 1 Technical Specifications.

Region 1 and 2 can accommodate fuel of various initial enrichments, discharge burnup and post-irradiation cooling time, provided that the combination falls within the acceptable domain as presented in Tables 9.1-8a.

These data are implemented in appropriate administrative procedures to assure verified burnup as specified in draft Regulatory Guide 1.13, Revision 2. Administrative procedures will also be employed to confirm and assure the presence of soluble poison in the pool water at all times, providing a further margin of safety and assuring subcriticality in the event of fuel misplacement during fuel handling operations, as discussed in Subsection 9.1.2.3.2.

9.1.2.3.1.3 New Fuel Storage in Spent Fuel Pool Region 2 Racks Criticality analyses confirm that, subject to certain restrictions, fresh fuel assemblies enriched to 4.6 w/o U-235 may be placed in two of the three analyzed Region 2 storage arrays. To maintain an acceptably low value of keff when adding fresh fuel to Region 2, it is required that the four Region 2 cells face-adjacent to each fresh assembly be maintained water-filled, i.e., without fuel. Additionally, for specific configurations, fresh fuel may not be placed in a cell diagonally adjacent to another fresh assembly.

Figure 9.1-22a provides pictorial guidance for the acceptable placement of fresh fuel in Region 2 racks.

9.1-5 Amendment No. 26 (11/13)

9.1.2.3.1.4 Cask Pit Rack Storage Since the cask pit rack is located in the cask pit and is separated from the spent fuel pool storage racks by walls, there are no neutron interactions between the fuel stored in the cask pit rack and fuel stored in the spent fuel storage racks.

The criticality analysis inputs and results for the cask pit rack to demonstrate the Keff is maintained 0.95 in pure water are summarized in Table 9.1-12.

9.1.2.3.1.5 Reactor Vessel Flux Reduction Assemblies Earlier Unit 1 core reloads used a small number of specially designed fuel assemblies in certain peripheral core locations as a mechanism to reduce the accumulated neutron dose on reactor vessel welds. These flux reduction assemblies are currently stored in the St. Lucie Unit 1 spent fuel storage racks.

A reactor vessel flux reduction assembly (VFRA) consists of a standard fuel assembly containing depleted UO2 with hafnium vessel flux reduction (HVFR) inserts in the guide tubes. The HVFR insert consists of an arrangement of hafnium and Zircaloy-4 filler components inside a 0.948 inch diameter by 0.040 inch wall Zircaloy-4 tubing. The axial position of the 136.7 inch hafnium region matches the active fuel stack in the core. The lower inserts in the HVFR rod utilize a wafer design where there are alternating hafnium and Zircaloy-4 wafers. This section has a total length of 12.85 inches, of which 7.74 inches is hafnium. The upper section has an annular design of hafnium with a length of 123.85 inches.

The annular hafnium is formed from 0.120 inch thick strip. The formed strips are arranged to make up two halves of a tube. Solid cylindrical Zircaloy-4 support rods fill the inner diameter of the tube for structural support. A zircaloy-4 spacer is positioned above this section to maintain component positions and to provide a single contact surface for the Inconel X-750 plenum spring. The plenum spring is included at the top fo the filler column to prevent segment separation during fabrication and shipping.

The HVFR insert has a Zircaloy bullet nosed end cap welded to the lower end of the cladding and a cylindrical Zircaloy end cap welded to the upper end of the cladding. Each rod is initially pressurized with helium to 415 psia.

The upper end cap is designed such that it is inserted and pinned to a stainless steel upper fitting containing a plunger and spring. The upper end fitting seats into the locking nut of the fuel assembly and is mechanically held down when the upper core plate compresses the plunger and spring.

The HVFR insert is designed to penetrate the dash-pot (i.e., necked down) portion of the corner fuel assembly guide tubes. This penetration provides a close fit between the HVFR assembly and the guide tube inner diameter, which minimizes the potential for fretting wear between the rod and the guide tubes.

A large axial clearance is provided between the lower end of the HVFR assembly and the bottom of the guide tube to allow for irradiation induced growth of the Zirconium Alloy cladding.

UNIT 1 9.1-5a Amendment No. 28 (05/17)

9.1.2.3.2 Postulated Accidents 9.1.2.3.2.1 Spent Fuel Pool Storage Racks The effects of credible abnormal and accident conditions on reactivity of the fuel storage racks are summarized in Table 9.1-13. Credit for soluble boron normally present in the spent fuel pool water is permitted during accident conditions, consistent with ANSI/ANS 8.1-1983 guidance. Other events, such as the horizontal or vertical drop of a fuel assembly onto or into fuel storage racks, or a mis-located fuel assembly positioned outside the racks, produce no significant positive reactivity effect. The double contingency principle of ANSI/ANS 8.1-1983 notes that, when providing protection from inadvertent criticality events, one is not required to postulate the simultaneous occurrence of two unlikely, independent events.

The reactivity effect of fuel pool water temperatures exceeding 150°F has been calculated. Temperatures of up to 257°F (125°C) have been evaluated, as were local boiling conditions with void percentages of up to 10%. The maximum increase in reactivity compared to 150°F was calculated for Region 1 and for Region 2. Calculations to quantify the soluble boron concentration required for each analyzed fuel storage arrangement have determined that 1000 ppm is required to ensure that keff does not exceed 0.95.

The misplacement of a fresh unburned fuel assembly could, in the absence of soluble poison, result in exceeding the regulatory limit of keff 0.95. This could possibly occur if a fresh fuel assembly of the highest permissible enrichment (4.6 wt%) were to be inadvertently misloaded into a Region 2 storage cell intended to be empty, or into a cell intended to hold a low reactivity fuel assembly. The reactivity consequences of these situations were investigated and it was determined that the misloading of a fresh assembly into a cell intended to remain empty is the bounding condition. A boron concentration of 1500 ppm is required to assure the regulatory limit of 0.95 for keff is not exceeded.

Administrative procedures assure the presence of soluble poison at all times. Subsection 9.1.3.7 presents a summary of the Reference 27 analysis of postulated inadvertent boron dilution events involving the spent fuel pool. See Subsection 9.1.4.3 for additional discussions of Accident Evaluations.

9.1.2.3.2.2 Cask Pit Storage Rack The effects on reactivity of the cask pit rack caused by abnormal and accident conditions are summarized in Table 9.1-13.

See subsection 9.1.4.3 for additional discussions on Accident Evaluations.

Reactivity-related events resulting from cask loading activities are bounded by the previously-analyzed events involving the spent fuel storage racks.

9.1-6 Amendment No. 26 (11/13)

9.1.2.3.3 Calculation Methods 9.1.2.3.3.1 Criticality Analyses for Spent Fuel Pool Region 1 Storage Racks As Region 1 is now primarily designed to store the more reactive portion of Unit 1's irradiated fuel inventory, the analytical methods used when no Boraflex absorber material is assumed present are now similar to the tools and methods used in analysis of Region 2 storage racks. Calculations of the Region 1 effective neutron multiplication factor, keff, rely on two primary analytical tools; the three-dimensional Monte Carlo code MCNP5 (Reference 35), and CASMO-4, a two-dimensional multi-group transport theory code based on capture probabilities (Reference 21). MCNP5 is used, often in a 2 x 2 storage cell problem geometry, to model specific fuel storage arrangements, calculate the effects on reactivity of interfaces between dissimilar regions and to calculate certain effects of individual assemblies, such as eccentric positioning within a storage cell, that can not be performed with CASMO. MCNP5 is used to determine the limiting values of soluble boron required to maintain keff within limits.

CASMO-4 is used to determine the isotopic composition of irradiated fuel for input to MCNP5 by simulating the fuel depletion experienced during Unit 1 power operation.

One checkerboard array of fresh and empty cells and two checkerboard arrays of irradiated fuel have been determined to produce acceptable results for Region 1 storage. These two checkerboard arrays of irradiated fuel are described by Fuel Type:

  • Fuel Type 1: Region 1 storage rack 2x2 array of uniformly loaded spent fuel with an initial enrichment of 1.9 to 4.6 wt%, with one cell containing a MetamicTM insert or one fuel assembly containing absorber rods. No credit for cooling time.
  • Fuel Type 2: Region 1 storage rack 2x2 array uniformly loaded with spent fuel with an initial enrichment of 1.9 to 4.6 wt% in any three storage locations and one storage location empty. No credit for MetamicTM inserts, absorber rods or cooling time.

The analysis results are applicable to all fuel designs (i.e., blanket type).

Analyses methods and results described above consider fuel designs produced by Combustion Engineering (Cycles 1-5) and Exxon Nuclear Company and its successors, Advanced Nuclear Fuels (ANF), Siemens Power Corporation, Nuclear Division (SPC-ND), and Framatome-ANP (FRA-ANP)

(Cycles 6 through the present cycle). All fuel assembly configurations and features used at St. Lucie Unit 1 (e.g., the presence or absence of axial blankets), from the beginning of commercial operation to the present, were examined.

9.1-6a Amendment No. 26 (11/13)

9.1.2.3.3.2 Criticality Analysis for Spent Fuel Pool Region 2 Storage Racks As for Region 1, the primary analytical tools used in analysis of Region 2 fuel storage arrangements are CASMO-4 and MCNP5. Each tool is used in approximately the same way as for Region 1 when developing permissible Region 2 fuel storage arrangements. Current as well as vintage fuel designs produced by both Combustion Engineering and Framatome have been considered in analysis of Region 2.

Three Region 2 checkerboard storage arrangements have been analyzed. Additionally, special rules have been developed for fresh fuel placed in Region 2 racks. The rules for the storage of fresh fuel in the Region 2 racks are as follows:

  • When the Region 2 rack is loaded with Fuel Type 3, the fresh fuel assembly must be face adjacent to empty cells and on a diagonal to spent fuel with no restriction (i.e., meets the requirement for Fuel Type 3).
  • When the Region 2 rack is loaded with Fuel Type 4, the fresh fuel assembly must be face adjacent to empty cells and on a diagonal with the spent fuel assembly which has one of the two inserts from the Fuel Type 4 configuration.
  • When the Region 2 rack is loaded with Fuel Type 5, the fresh fuel assembly must be face adjacent to empty cells and on a diagonal with the spent fuel assembly which has the insert from the Fuel Type 5 configuration.

Minimum required burnup in each checkerboard array decreases as initial enrichment decreases and as cooling time increases. The concentration of Xe-135 is conservatively set to zero for all calculations of fuel in the spent fuel racks.

The following restrictions apply to the Region 1 to Region 2 interface:

  • Fuel Type 3: Empty cells must be located on the rack periphery facing Region 1 racks.
  • Fuel Type 4 and Fuel Type 5: An insert must be present in every second cell on the periphery facing Region 1 racks. The insert must be oriented so that the corner of the L-shape is located on the outside of the rack.

9.1-6b Amendment No. 26 (11/13)

9.1.2.3.3.3 Criticality Analysis for Cask Pit Storage Rack Keff for the cask pit storage rack was determined through analysis using the MCNP4a Monte Carlo code (Reference 22). CASMO4 was used to evaluate the small reactivity effects of manufacturing tolerances.

The results of the calculations are shown on Table 9.1-12 and demonstrate that the maximum reactivity is 0.9158, which is well below the analysis limit of 0.95.

9.1.2.3.3.4 Criticality Analysis of a TN 32PTH Dry Storage Canister (DSC) in the Cask Pit Neutron multiplication of a DSC is determined for the worst case wet loading/unloading operations using the CSAS25 control module of the SCALE-4.4 3 package. Analyses consider the limiting licensed fuel type, the use of fixed neutron absorbing materials in the flooded DSCs basket, as well as credit for the presence of soluble boron in the spent fuel pool. The maximum effective neutron multiplication (keff) for both the nominal fuel geometry and the damaged fuel geometry are <0.95. The limiting fuel design for the 32PTH is the Westinghouse 17x17 rod lattice. Results obtained for this lattice bound the fuel designs used at St. Lucie Unit 1 (see References 32 and 33).

9.1.2.3.4 Rack Modification The design basis fuel assembly for rack calculations is a 14 x 14 array of fuel rods with 20 rods replaced by 5 control rod guide tubes. Independent calculations, considering other fuel assembly specifications, confirmed that the Framatome 14 x 14 rod lattice with a cladding thickness of 0.028 inches is the bounding assembly design for Region 1 calculations, whereas for Region 2, the Combustion Engineering 14 x 14 lattice with a clad thickness of 0.026 inches exhibited the highest reactivity. These assembly designs are therefore used in all subsequent calculations for the respective rack type. For the cask pit rack, calculations show the Framatome 14x14 lattice fuel is more reactive; therefore, Framatome fuel was used as the basis for the cask pit rack.

9.1.2.3.4.1 Spent Fuel Pool Region 1 Storage Cells The nominal spent fuel storage cell used for criticality analyses of Region 1 storage cells is shown in Figure 9.1-24. The rack cell may contain Boraflex absorber material sandwiched between an 8.65-inch nominal I.D., 0.080-inch thick inner stainless steel box. and a nominal 0.020-inch outer stainless steel coverplate. Although FPL has not physically (i.e., through mechanical means) removed Boraflex from the racks, criticality analyses do not credit Boraflex as a neutron absorber, for calculations this 0.075 +/- 0.007 inch gap is assumed empty. Nominally, the fuel assemblies are centrally located in each storage cell on a lattice spacing of 10.12 +/- 0.05 inches. Stainless steel gap channels connect one storage cell box to another in a rigid structure and define an outer water space between boxes. This outer water space constitutes a flux trap between the two water gaps.

9.1.2.3.4.2 Spent Fuel Pool Region 2 Storage Cells Region 2 storage cells were designed to accommodate fuel assemblies having an initial enrichment of 4.6 w/o U-235. In this region, the storage cells are composed of a single Boraflex absorber sandwiched between the 0.080-inch stainless steel walls of adjacent storage cells. These cells, shown in Figure 9.1-25, are located on a lattice spacing of 8.86 +/- 0.040 inches. As for Region 1, Boraflex has not been credited in criticality analyses although no effort has been made to physically remove the Boraflex absorber material from the racks.

9.1.2.3.4.2.1 MetamicTM Inserts MetamicTM inserts have been installed into selected Spent Fuel Pool (SFP) Region 2 rack cells as a neutron absorber.

The maximum expected quantity of MetamicTM inserts for Region 2 of the SFP is 682, assuming 2 out of every 4 cells are occupied with a MetamicTM insert.

Reference 35 provides all of the design, installation, and analysis performed to determine acceptability of the use of MetamicTM inserts in Region 2 of the Spent Fuel Pool.

9.1-7 Amendment No. 26 (11/13)

The MetamicTM inserts are manufactured in the shape of an L and, when inserted, will blanket two of the four walls of the host storage cell. Each insert consists of MetamicTM panels formed with a top landing surface. When installed, the top landing of the insert will rest on the upper guide posts of the fuel assembly. The top landing of the inserts is equipped with an interface for lifting and handling by a custom designed tool. The insert will not extend to the base-plate of the storage cell; however, the design of the insert ensures that, when seated in the rack cell, less than six inches of the bottom of the active fuel region of the fuel assembly will not be shadowed by the adjacent MetamicTM panel.

Holtec International, the MetamicTM insert provider, has evaluated the structural adequacy of the Region 2 spent fuel pool racks in response to seismic events when MetamicTM inserts are installed. Loadings postulated to occur during normal, seismic, and accident conditions were considered. All safety factors were considerably less than allowed and were judged acceptable.

Holtec International also evaluated the structural adequacy of the spent fuel pool with the MetamicTM inserts installed in the Region 2 racks. Loadings postulated to occur during normal, seismic, and accident conditions were considered. All safety factors were considerably higher than required and were judged acceptable.

Lastly, the MetamicTM inserts were analyzed for seismic loading and were found to be structurally adequate to perform their intended design function under both normal and seismic conditions.

Holtec International performed two analyses, Bulk Spent Fuel Pool temperature and Local temperature, to determine the effects associated with the use of MetamicTM inserts. The results of the analyses indicated that MetamicTM insert effects on the spent fuel pit bulk temperature were bounded by previous analysis.

The analysis showed the maximum (peak) local water temperature will be 184°F. Since the minimum depth at the top of the active fuel length is 26 feet and the saturation temperature at this depth is 242°F, local boiling will not occur while forced-flow cooling is available. Also, the calculated peak local fuel cladding temperature, 227°F is also lower than the local saturation temperature.

9.1.2.3.4.3 Cask Pit Rack A typical cell for the cask pit storage rack is shown in Figure 9.1-28. Cask pit rack cells are formed by the welding of two stainless steel 'C' channels. The 'C' channel material is 0.075-inch thick stainless steel.

The I.D. of the formed cells is a nominal 8.58 inches. Each cell is attached to other cells using connectors. The width of the connectors, 1.303 inches, forms the water gap or flux trap between the cells. The center to center distance or pitch between cells is 10.3 inches. The outside wall of each cell, except those cells on the outer perimeter of the rack, contains a 0.098 inch thick by 7.25 inch wide Boral panel held in place by stainless steel sheathing stitch welded to the outside cell wall. The Boral panels contain a nominal B-10 areal density of 0.028 gm/cm2.

9.1.2.3.5 Acceptance Criteria for Criticality Criticality is precluded by spacing of the fuel assemblies, and by burnup and post irradiation cooling time requirements which ensure that a subcritical array is maintained, assuming unborated pool water. The pool, however, will always contain boric acid at the refueling concentration of at least 1900 ppm whenever there is irradiated fuel in the pool. Considering the presence of soluble boron in the fuel pool at a concentration of at least 500 ppm, keff of the fuel pool will always be 0.95.

Criticality in the array of stored fuel inside the flooded canister is precluded by the spacing between fuel assemblies, the soluble boron present in the DSC basket and by the Al-B4C neutron absorber panels interspersed between basket cells. Cask loading operations involving a TN 32PTH DSC require that at lease 2000 ppm soluble boron be present in the fuel pool water.

Analysis of inadvertent boron dilution events involving the spent fuel pool demonstrate that no credible dilution event can cause a reduction in boron concentration to less than 500 ppm.

9.1-7a Amendment No. 26 (11/13)

9.1.2.4 Testing and Inspection The welded steel spent fuel pool storage racks were liquid penetrant tested for structural adequacy. Fuel handling cranes are load tested with a test weight in accordance with plant procedures prior to lifting fuel assemblies.

Section 3.4 of Reference 25 notes that, following the implementation of license amendment 193, the commitments to Boraflex monitoring pursuant to NRC generic letter 96-04 will no longer be necessary and may be terminated.

As per Reference 35, a MetamicTM insert surveillance program will be added to the plant monitoring program to verify the ongoing effectiveness of the MetamicTM inserts. See Chapter 18, Aging Management Programs and Time-Limited Aging Analyses Activities for a detailed description of the MetamicTM Insert Surveillance Program.

9.1.2.5 Instrumentation Applications Temperature, water level, and radiation monitoring and alarm instrumentation are provided in the control room and locally to verify that the decay heat from the spent fuel assemblies is being removed. Means are provided to control entry of personnel and to account for the flow of tools in and out of the area.

Table 12.1-7 gives the location of the area radiation monitoring in the fuel handling building. An indication of the radiation in the area is given by the high and high-high area radiation alarms.

9.1-8 Amendment No. 26 (11/13)

9.1.3 FUEL POOL SYSTEM 9.1.3.1 Design Bases The fuel pool system is designed to:

a) provide radiation shielded storage for spent fuel assemblies to limit personnel dose rates to less than 2.5 mrem/hr b) remove decay heat from up to 1849 spent fuel assemblies stored in the pool and maintain pool water temperature less than 150° F.

c) maintain purity and optical clarity of the fuel pool water d) maintain purity of the water in the refueling cavity and in the refueling water tank e) maintain the water level a minimum of 9 ft above the top of the fuel during handling and storage operation 9.1.3.2 System Description The P&I diagram of the fuel pool system is shown in Figure 9.1-3. The cooling portion of the fuel pool system is a closed loop system consisting of two full capacity pumps and one full capacity heat exchanger. The fuel pool water is drawn from the fuel pool near the surface and is circulated by the fuel pool pumps through the fuel pool heat exchanger where heat is rejected to the component cooling system. From the outlet of the fuel pool exchanger, the cooled fuel pool water is returned to the bottom of the fuel pool via a distribution header at the opposite end of the pool from the intake.

For refueling evolutions that involve a partial core offload of fuel and an incore fuel shuffle, only one fuel pool pump and the fuel pool heat exchanger are normally in service. During activities involving a full core fuel discharge, normally two fuel pool pumps and the heat exchanger are in service. The system is manually controlled and the operation monitored locally, except as follows. A pressure switch on the fuel pool pump discharge header annunciates low header pressure in the control room. The fuel pool high temperature alarm and low level alarms are annunciated in the control room. In the event the fuel pool pump breakers are opened, an alarm is annunciated in the control room. The component cooling water flow to the fuel pool heat exchanger is initially adjusted to the required flow. Further adjustments of the component cooling water are not required. The component cooling water discharge line has a flow indicator. High and low component cooling water flow alarms are annunciated in the control room.

9.1-9 Amendment No. 21 (12/05)

The clarity and purity of the water in the fuel pool, refueling cavity, and refueling water tank are maintained by the purification portion of the fuel pool system. The purification loop consists of the fuel pool purification pump, ion exchanger, filter, strainers and surface skimmers. Most of the purification flow is drawn from three levels of the fuel pool, while a small fraction is drawn through the surface skimmers to remove surface debris. A basket strainer is provided in the purification line to the pump suction to remove any relatively large particulate matter. The fuel pool water is circulated by the pump through a filter, which removes particulates, and through an ion exchanger to remove ionic material. Connections to the refueling water tank and refueling water cavity are provided for purification. Fuel pool water chemistry is given in Table 9.1-2.

Maximum dose rates from a spent fuel assembly as a function of the water height above the top of the active fuel are shown in Figure 12.1-5. Infinite irradiation of the fuel assembly, is assumed for the dose rate calculation. An axial power distribution with maximum power at the top and bottom of the fuel was used for the axial dose rate calculation while an axial peak of 1.50 was used for the radial (side) dose rate calculations for shielding requirement as described in Section 12.1. Additionally, both cases assumed a maximum radial fuel assembly peaking factor of 1.38. The decay times are not representative of any particular point in the refueling cycle and are only given to show the dose rate variation with time. Other decay times between 2 days and 60 days can be obtained by interpolation between the existing points.

When fuel transfer operations using a transfer cask are required, any fuel stored in the cask pit rack will be relocated to the spent fuel pool storage racks. The cask pit rack and platform will then be removed from the cask pit and placed in storage.

When a spent fuel transfer cask is to be loaded with spent fuel, it will be placed in the cask pit adjacent to the pool. The pit floor is low enough that spent fuel assemblies can be placed in the cask while still maintaining the minimum water level above fuel assemblies that is maintained during fuel handling and storage in the spent fuel pool. The shield plug is then placed in the cask and the unit is transferred to the cask handling facility (see Figure 1.2-18) by the single-failure-proof cask handling crane.

Depending on the fuel pool soluble boron concentration, makeup to the fuel pool is provided from the refueling water tank or from the primary water tank. Overflow protection is provided by transferring the fuel pool water on high level alarm to the refueling water tank via the purification pumps. Spent resins from the fuel pool ion exchanger are sluiced to the waste management system as described in Section 11.5.2. Local sample connections are provided on the influent and effluent of the fuel pool purification filter and the fuel pool ion exchanger effluent for verifying purification performance.

9.1.3.3 Component Description All piping, valves, instruments, and components except the fuel pool ion exchanger are located in the fuel handling building. The fuel pool ion exchanger is located in the reactor auxiliary building with the CVCS and waste management system ion exchangers. Design data for the major components are indicated in Table 9.1-3.

UNIT 1 9.1-10 Amendment No. 28 (05/17)

a) Fuel Pool Heat Exchanger The fuel pool heat exchanger is a horizontal shell and tube design with a two-pass tube side. A slight pitch, 3o above the horizontal, is provided for complete draining of the heat exchanger. The component cooling water circulates through the shell side, and pool water circulates through the tube side.

b) Fuel Pool Purification Filter The fuel pool purification filter is located upstream of the fuel pool ion exchanger to remove any particulates in the pool water. The fuel pool purification system, depending on what size micron rated filter is installed, is capable of retaining 98 percent of the particulates larger than 5 micron in size at a flow of 150 gpm. The filter micron rating is chosen prior to filter installation with consideration given to optical clarity requirements of the fuel pool and whether or not fuel inspections/moving activities are being performed. Due to the possible buildup of high activity in the filter, the unit has been designed and installed to provide for removal of the contaminated element assembly with remotely operated handling equipment. The filter drains to the drain collection header in the waste management system. A temporary portable filter/vacuum is also available to expedite outage activities to help cleanup the fuel pool to improve water clarity.

c) Fuel Pool Ion Exchanger The ion exchanger removes ionic matter from the water. Mixed bed resin is used with the anion resin converted to the borate form and the cation resin in the hydrogen form. The units are provided with all connections required to replace resins by sluicing. The ion exchanger contains a flow distributor on the inlet to prevent channeling of the resin bed and a resin retention element on the discharge to preclude discharge of resin with the effluent. As permitted by Reference 31, particle removal resin may be placed on top of the mixed bed resin bed to provide a means to remove concentrations of Co and Ni corrosion products.

d) Fuel Pool Purification Pump Suction Strainer The fuel pool purification pump suction strainer prevents any relatively large particulates from entering the purification pump. The strainer has a drain connection allowing local draining.

e) Fuel Pool Ion Exchanger Strainer The wye strainer removes particles larger than 149 microns from the purification flow. Blowdown is directed to the spent resin tank in the waste management system.

f) Fuel Pool Pumps There are two fuel pool pumps installed for parallel operation. Most operating conditions require one pump to be in operation. The pumps are provided with mechanical seals. To increase seal life and reduce maintenance, the seals are cooled by circulating a portion of the pump discharge flow to the seals which returns to the pump suction. The seals are provided with leakoff vent and drain connections.

UNIT 1 9.1-11 Amendment No. 28 (05/17)

g) Fuel Pool Purification Pump The fuel pool purification pump (Quality Group D, non-seismic) is used for purification and skimming operations. The pump has a mechanical cartridge seal for improved seal life and EC292983 reduced maintenance. No cooling or flushing lines are required. The seals are provided with leakoff vent and drain connections. The internal wetted surfaces of the pump are stainless steel.

h) Piping and Valves All the piping used in the fuel pool system is stainless steel with welded connections throughout, except for flanged connections at the suction and discharge of the pumps.

All the valves in the fuel pool system are stainless steel, 150-pound class. All valves are manually operated diaphragm type.

9.1.3.4 System Evaluation 9.1.3.4.1 Cooling System During refueling evolutions involving a partial core offload and in-core fuel shuffle one fuel pool pump and the fuel pool heat exchanger will normally be in service. For evolutions involving a full core fuel discharge to the spent fuel pool, two fuel pool pumps and the heat exchanger will normally be in service. The system is manually controlled and the operation monitored locally, except as follows. A pressure switch on the fuel pool pump discharge header annunciates low header pressure in the control room. The fuel pool temperature high alarm and the fuel pool water level switch high and low level alarms are annunciated in the control room. In the event the fuel pool pump breakers are opened, an alarm is annunciated in the control room. The component cooling water flow to the fuel pool heat exchanger is initially adjusted to the required flow. Further adjustments of the component cooling water is not required.

The component cooling water discharge line has a flow indicator. High and low component cooling water flow alarms are annunciated in the control room.

The fuel pool piping is arranged so that the pool cannot be inadvertently drained to uncover the fuel. All fuel pool piping is arranged to prevent gravity draining the fuel pool. To prevent siphoning of the fuel pool, the fuel pool cooling discharge and purification suction lines have 1/2" and 1/4" holes respectively 1 foot below the normal water level.

The only means of draining the pool below these siphon breaker holes is through an open line in the cooling loop while operating the pool cooling pumps. In such an event the fuel pool water level can be reduced to elevation 56 feet since the pump suction connection enters near the top of the pool. Adequate shielding and cooling are still provided with the water level at this point. The temperature and level alarms would warn the operator of such an event.

9.1-12 Amendment No. 30 (05/20)

9.1.3.4.2 Decay Heat Analyses 9.1.3.4.2.1 Basis The St. Lucie Plant Unit 1 reactor is rated at 3020 megawatts thermal (MWt). The core contains 217 fuel assemblies. During core offloads, the decay heat generated by spent fuel assemblies placed in the spent fuel pool is much greater than the decay heat produced during routine non-offload conditions. The fuel discharge can be made in one of the following two modes:

- Partial core refueling discharge (approximately 40% core)

- Full core discharge The decay heat analysis consists of a bulk pool temperature analysis and a local temperature analysis.

The bulk temperature analysis determines the overall pool temperature response during core off-load conditions. The local temperature analysis demonstrates that no local boiling occurs in any rack cells containing spent fuel assemblies.

9.1.3.4.2.2 Model Descriptions 9.1.3.4.2.2.1 Bulk Temperature Analysis Model The analysis model used to determine the bulk spent fuel temperatures conforms to the requirements of the USNRC Standard Review Plan, Section 9.1.3 and Section III of the USNRC "OT Position Paper for Review and Acceptance of Spent Fuel Storage and Handling Applications," April 14, 1978.

The heat input to the spent fuel pool is a function of the number of fuel assemblies stored in the pool and the amount of heat generated by those fuel assemblies. The model used in determining the Bulk Temperature of the spent fuel pool considered the heat input from two sources: the decay heat contribution from previously offloaded fuel and the decay heat contribution from fuel to be offloaded. The LONGOR computer code was used to calculate the decay heat from previously offloaded fuel while the BULKTEM program was used to calculate the decay heat from fuel assemblies to be offloaded. Both of these computer programs incorporate the Oak Ridge National Laboratory ORIGEN2 computer code for performing decay heat calculations.

The following equation defines the total decay heat generation in the spent fuel pool:

QGEN () = QP + F () x QR ()

where: QGEN () is the total time varying decay heat generation rate in the SFP, Btu/hr QP is the decay heat contribution of the previously offloaded fuel, Btu/hr F() is the fraction of the recently offloaded fuel transferred to the SFP QR () is the decay heat contribution of the fuel to be offloaded, Btu/hr is the fuel decay time after reactor shutdown, hrs The fuel pool cooling system removes heat from the SFP and rejects it through the fuel pool cooling heat exchanger to the component cooling water system. Heat removal from the SFP by the fuel pool cooling heat exchanger can be represented by the following formula:

QHx (T) = Wc x Cp x p x (T - Tci) where: QHx (T) is the heat exchanger heat rejection rate, Btu/hr Wc is the coolant (CCW) flowrate to the heat exchanger, lbm/hr cp is the specific heat capacity of water, Btu/lbm-°F p is the temperature effectiveness of the heat exchanger T is the temperature of the water in the SFP Tci is the heat exchanger cooling water (CCW) inlet temperature Table 9.1-16 provides the heat transfer data for the fuel pool cooling heat exchanger based on maximum fouling and 5% tube plugging.

9.1-13 Amendment No. 26 (11/13)

Once the decay heat generation rate is known, the thermal response of the spent fuel pool and the fuel pool cooling system to decay heat load transients can be determined by use of the following equation:

T Cx = Q GEN ( ) Q HX (T) Q ENV (T) where: C is the SFP thermal capacity, Btu/°F T is the SFP bulk temperature, °F is the time after reactor shutdown, hrs QGEN () is the transient decay heat generation rate in the SFP, Btu/hr QHX (T) is the heat rejection to the fuel pool cooling system, Btu/hr QENV (T) is the passive heat loss to the environment, Btu/hr Note: The passive heat loss to the environment includes conduction heat transfer through the SFP walls and slab as well as natural convection, thermal radiation and mass dilution from the surface of the SFP water.

A number of assumptions have been made to provide conservative results from the analysis, including:

  • The thermal performance of the fuel pool cooling heat exchanger is determined with all heat transfer surfaces fouled to the maximum design levels including a 5% tube plugging allowance and with the inlet cooling water (CCW) temperature set at the maximum design value.
  • The passive heat losses from the SFP surface to the FHB air assumes the relative humidity of the building air is 100%.
  • All reactor thermal power levels and fuel burnups are increased by 1% to account for uncertainties in calorimetric determinations.
  • The decay heat contribution of offloaded assemblies is based on a power generation of 3200 MW(t).

This allows for conservatism and provides flexibility for future operation and licensing.

  • The total fuel inventory in the SFP is based on the offload schedule as shown in Table 9.1-17.

9.1.3.4.2.2.2 Local Temperature Analysis Model The local temperature analysis is performed to determine if the decay heat generated by the fuel assemblies is sufficient to cause local boiling within the fuel storage rack. The model assumes the decay heat generated by the spent fuel assemblies is transferred to the water inducing a buoyancy-driven upward flow through each fuel rack cell. The coupled flow and temperature fields of the rack are quantified using three-dimensional Computation Fluid Dynamics (CFD) within the FLUENTTM fluid flow and heat transfer modeling program.

In the model, the decay heat generated by the spent fuel assemblies stored in the racks is treated as a volumetric heat generation in a porous media region. The program computes the coupled temperature and velocity profiles providing a single bounding scenario that includes the highest bulk spent fuel pool temperature, the highest decay heat loads, the bounding fuel cladding temperature and superheat and the highest fuel assembly hydraulic resistance. Based on the results, the peak local water temperature is determined using the programs post-processing functions.

9.1-13a Amendment No. 26 (11/13)

Several conservative assumptions were made to produce bounding results. They include:

  • All passive heat losses through the walls and floor of the SFP are neglected.
  • The bottom plenum for flow (between the rack base and floor) is modeled as less than actual width.
  • No downcomer flow is assumed to exist between rack modules.
  • The hydraulic resistance of every rack cell includes the inertial resistance that would result from a dropped assembly lying across the top of the rack.
  • The hottest fuel assemblies are assumed to be located together in the center of the rack, maximizing the local decay heat.
  • The initial bulk SFP temperature is assumed to be at the allowable bulk temperature limit.

9.1-13b Amendment No. 26 (11/13)

9.1.3.4.2.3 Analysis Results 9.1.3.4.2.3.1 Bulk Pool Temperature Results Three separate offload scenarios were evaluated to determine the transient decay heat load and resultant maximum spent fuel pool bulk temperatures. The following scenarios are evaluated:

  • Normal Partial Core Offload - Up to 100 assemblies may be offloaded and placed in the SFP EC295259 completely filling all available storage locations. One fuel pool cooling pump is in operation.

The previously offloaded fuel in the SFP is assumed to have decayed for 15 months.

  • Normal Full Core Offload - 217 fuel assemblies are offloaded and placed in the SFP completely filling all available storage locations. The 217 assemblies are separated into three distinct groups: 73 assemblies with a burnup of 55 GWD/MTU, 72 assemblies with a burnup of 49.5 GWD/MTU, and 72 assemblies with a burnup of 27.5 GWD/MTU. Two fuel pool cooling pumps are in operation.
  • Full Core Offload (w/one fuel pool cooling pump in operation) - This scenario is identical to the Normal Full Core Offload except only one fuel pool cooling pump is in operation.

Based on the calculation results, spent fuel pool temperature can be maintained under 140°F during partial core offload scenarios, and under 150°F during all full core offload scenarios.

For the case of failure of a fuel pool cooling train, the maximum temperature rise, calculated assuming the loss of one fuel pool cooling train at the time of maximum heat load, will be used to set the limit on the maximum pool temperature such that the loss of one fuel pool cooling train will not result in pool bulk temperature to exceed 150°F.

A thermal overshoot is calculated for various cases such that as long as the temperature setpoint has more margin to the limit than the calculated overshoot, a value of 150°F will not be exceeded.

A thermal overshoot of 12°F is determined to bound the following full core offload cases (additional information in Table 9.1-14):

1. Initiating offload at 95 hours0.0011 days <br />0.0264 hours <br />1.570767e-4 weeks <br />3.61475e-5 months <br /> after reactor shutdown with a CCW temperature of equal to or less than 95°F at an average rate of 6 assemblies per hour.
2. Initiating offload at 110 hours0.00127 days <br />0.0306 hours <br />1.818783e-4 weeks <br />4.1855e-5 months <br /> after reactor shutdown with a CCW temperature of equal to or less than 100°F at an average rate of 6 assemblies per hour.

Partial core offload (in core shuffle) with the failure of a fuel pool cooling train is shown to remain below 140°F for the following case:

1. Initiating offload at 95 hours0.0011 days <br />0.0264 hours <br />1.570767e-4 weeks <br />3.61475e-5 months <br /> after reactor shutdown with a CCW temperature of equal to or less than 100°F at an average rate of 4 assemblies discharged to the SFP per hour.

UNIT 1 9.1-14 Amendment No. 31 (11/21)

The limiting offload scenario when considering all pool cooling is lost results in a time to boil of 3.11 EC290004 hours, and a boiloff rate of 85.06 gpm. The time to boil is based on a loss of cooling occurring coincident with the maximum SFP bulk temperature.

9.1.3.4.2.3.2 Local Temperature Results Table 9.1-25 provides the results of the local temperature analysis. The calculated peak local water and fuel cladding temperatures are lower than the local saturation temperature (242°F). EC290004 9.1.3.4.3 Spent Fuel Pool Cooling System Summary The spent fuel decay heat calculations were performed in accordance with the guidance specified in USNRC Standard Review Plan, Section 9.1.3 and Section III of the USNRC "OT Position Paper for Review and Acceptance of Spent Fuel Storage and Handling Applications," April 14, 1978.

After a full core offload, the SFP bulk temperature rise remained below 12°F with the failure of 1 pump. EC290004 In the event of a complete loss of fuel pool cooling, there is sufficient time (3.11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> during a full core EC290004 offload) to provide an alternate means of cooling before boiling occurs in SFP.

The local water temperature of the cell containing the hottest fuel assembly stored in the spent fuel pool racks is less than the local saturation temperature of the water.

The peak fuel cladding temperature of the hottest fuel assembly stored in the spent fuel pool racks is less than the local saturation temperature of the water.

9.1-15 Amendment No. 29 (10/18)

The Reference 17 safety evaluation documents the basis for the conclusion that the routine performance of full core fuel offloads is an acceptable evolution.

9.1.3.4.3.1 Safety Evaluation The calculations for the amount of thermal energy that may have to be removed by the spent fuel pool cooling system are made using the Oak Ridge National Laboratory computer code ORIGEN2. The resulting bulk spent fuel pool temperatures are acceptable.

9.1-15a Amendment No. 26 (11/13)

9.1.3.4.3.2 Spent Fuel Pool Makeup There are several sources of fresh water on the site that are available to the fuel handling building; namely, refueling water storage tank, city water storage tanks via the fire main, city water storage tanks via the portable fire pump connection, and the primary water tank. The concurrent loss of these sources and the fuel pool cooling system is remote. Due to the fuel pool's boil-off period, there is sufficient time to obtain makeup. It should be noted that a seismic Category I backup salt water supply is available from the intake cooling water intertie. A standpipe on the fuel handling building is provided from grade to the operating deck elevation and hose connections are provided at both ends of the standpipe. Thus, via fire hose, the fuel pool makeup can be readily supplied by the intake cooling water pumps. The head provided by these pumps is sufficient to provide the required fuel pool make up. The structural and leaktight integrity of the fuel pool will not be compromised by continuous fuel pool temperatures of up to 217oF. The results of the bulk decay heat analyses indicate that these temperature are not exceeded.

The intake cooling water system connection via the hose connections can provide 150 gpm of makeup.

Emergency cooling by sea water will not result in unacceptable corrosion of the Zirconium Alloy fuel cladding or structural components. Integrity of the fuel rod cladding and containment of fuel material and fission products is therefore assured. With regard to stainless steel structural components, it is unlikely that any localized corrosion cracking can result in loss of structural integrity of these components.

Equipment and techniques can be made available to recover fuel rods. Should sea water be introduced to the fuel pool, fuel elements would be inspected prior to reload in the reactor core.

9.1.3.4.4 Purification System The purification loop is periodically run in accordance with plant procedures. It is possible to operate with either the ion exchanger or filter bypassed. Local samples permit analysis of ion exchanger and filter efficiencies. A diaphragm valve in the skimmer suction line is throttled to maintain flow balance between the skimmer and normal purification flow. Spent filters and ion exchanger resins are removed to the waste management system described in Section 11.5 for eventual disposal. The purification loop components and main process piping are Quality Group D, non-seismic. A temporary portable filter/vacuum is also available to expedite outage activities to help cleanup the fuel pool to improve water clarity.

9.1.3.4.5 Makeup System Depending on the soluble boron concentration in the spent fuel pool, makeup to the fuel pool is provided from the refueling water tank (RWT) via the 150 gpm fuel pool purification pump or from the primary water tank. The flow path of makeup water to the pool is shown on Figures 6.2-28 and 9.1-3. As indicated, the refueling water tank is isolated from the fuel pool by a locked closed valve (V07104) when makeup to the fuel pool or purification of the RWT inventory is not in progress. Makeup to the fuel pool from the RWT is initiated by opening valve (V07104) and by isolating the purification pump suction from the fuel pool by closing valve V4220. The 3 inch makeup line is routed from the refueling water tank, through the component cooling equipment area (see Figure 1.2-2), to the east side of the fuel handling building.

Inside the fuel handling building, the line runs embedded at elevation +19.5 to the valve pit where it connects to the purification pump suction line (see Figure 1.2-8).

9.1-16 Amendment No. 28 (05/17)

9.1.3.5 Testing and Inspection Each component is inspected and cleaned prior to installation into the system. Demineralized water is used to flush the entire system. Instruments are calibrated and alarm functions are checked for operability and set points during preoperational testing. The system was operated and tested initially with regard to flow paths, flow capacity, and mechanical operability.

Prior to transferring spent fuel to the pool, the system was tested to verify satisfactory flow characteristics through the equipment, to demonstrate satisfactory performance of pumps and instruments, to check for leak tightness of piping and equipment, and to verify proper operation of controls. Also the overall cooling capability was checked during initial refueling by analyzing pool temperature versus quantity of fuel transferred into the pool and comparing with expected performance. The cooling and purification systems are in either continuous or intermittent use during normal plant operation, thus no additional periodic tests are required. Normal system status is monitored remotely via permanently installed instrumentation. Fuel pool water quality is maintained based on routine sample analysis. Prior to and throughout the refueling process, when the heat load and clean-up requirements are maximum, system parameters are monitored, as appropriate, to ensure proper system performance and compliance with administrative limits.

9.1.3.6 Instrumentation Application Two means of control room spent fuel pool monitoring are provided, namely, fuel pool level alarm (LS-4420) and temperature alarm (TIA-4420). These are not seismic Category I devices. There are no Class 1E electrical services in the fuel handling building, thus all cables are routed in concrete duct banks. Seismic qualification of the temperature and level indication and installation of Class 1E conduit is not considered necessary. The bases being that i) the pool and its liner are seismic Category I; ii) failure of lines connected to the pool cannot drain the pool below elevation +56'; iii) the earthquake emergency plan will include the provision to periodically monitor pool level and temperature; and iv) that sufficient time exists to establish a source of makeup water.

Instrumentation is also provided to monitor significant temperature and pressures around the cooling and purification loops. Alarms annunciated in the control room are provided for fuel pool water level, fuel pool temperature and fuel pool pump discharge pressure.

A tabulation of instrument channels is included in Table 9.1-4.

9.1.3.7 Dilution of the Spent Fuel Pool In conformance with the methodology described in Reference 24, a boron dilution analysis of the spent fuel pool was performed to ensure that sufficient time is available to detect and mitigate any unanticipated reduction in the fuel pool boron concentration. Potential plant initiating events were identified along with the quantity of water available for dilution in each scenario.

This analysis was provided to the NRC as part of the Reference 27 license amendment request.

Based on the criticality analysis described in Reference 23, FPL determined that a soluble boron concentration of 500 parts per million (ppm) was required to maintain keff at or below 0.95. Deterministic dilution event calculations were performed for St. Lucie Unit 1 to define the elapsed times and water volume necessary to dilute the spent fuel pool from the minimum Technical Specification (TS) boron concentration of 1900 ppm (note that 1720 was conservatively used in the calculation) to a soluble boron concentration of 500 ppm. Analyses used an initial-condition spent fuel pool water inventory of 296,872 gallons.

9.1-17 Amendment No. 26 (11/13)

Assuming a well-mixed pool, the volume required to dilute the SFP from the TS limit of 1900 ppm to 500 ppm was determined to be 366,777 gallons. The various initiating events considered include dilutions originated by the primary water system, component cooling water system, intake cooling water system, demineralized water system, and service water system, as well as other events that may affect the boron concentration of the pool, such as a seismic event, pipe break, excessive precipitation event and loss of offsite power.

The boron dilution analysis concluded that an unplanned or inadvertent event that would dilute the SFP boron concentration from 1900 ppm to 500 ppm is not credible for St. Lucie Unit 1. In the Reference 25 Safety Evaluation, the NRC formed the following conclusion:

"Based on the boron dilution analysis and the processes and programs described [in Reference 27], the staff concludes that the proposed amendment to credit soluble boron for SFP criticality control is acceptable. The staff finds that the combination of alarms, personnel rounds, and revised TS requirements will ensure that sufficient time if available to detect and mitigate a dilution event prior to the SFP boron concentration decreasing below the minimum acceptable value of 500 ppm."

9.1-17a Amendment No. 26 (11/13)

9.1.4 FUEL HANDLING SYSTEM The fuel handling system includes the equipment to refuel the reactor and to safely handle and store fuel assemblies from receipt of new fuel to shipment of spent fuel.

9.1.4.1 Design Bases The fuel handling system is designed to:

a) safely handle and store fuel assemblies and control element assemblies b) safely remove, replace and store reactor internals c) by means of interlocks, travel limiting devices and other protective devices, minimize the probability of malfunction or operator initiated actions that could cause fuel damage, and potential fission product release or reduction of shielding water coverage d) conduct all spent fuel transfer and storage operations under water to limit radiation dose levels to less than 2.5 mrem/hr at the pool surface e) operate in water with the chemistry listed in Table 9.1-2 f) maintain handled fuel in a safe condition in the event of loss of power g) withstand containment internal design leak rate test pressure without loss of function (Non-removable equipment only) h) remove and install a fuel assembly at each operating location at the most adverse combined tolerance condition for the equipment, core internals and fuel assemblies i) withstand the loadings induced by the design base earthquake 9.1.4.2 System Description The fuel handling system is an integrated system of equipment, tools and procedures for refueling the reactor. The system is designed for safe handling and storage of fuel assemblies from receipt of new fuel to shipping of spent fuel. The arrangement of the fuel handling area is shown in Figure 9.1-7.

The fuel handling equipment is normally used at 18-month intervals for a period of approximately 3 weeks during which time it must operate continuously without maintenance or service.

9.1-18 Amendment No. 22 (05/07)

9.1.4.2.1 New Fuel Handling New fuel assemblies are delivered to the site in containers approved by the U.S. Department of Transportation. New fuel assemblies are removed from the shipping containers and placed in the new fuel storage racks using the new fuel handling tool attached to the 5-ton fuel transfer hoist. New CEA's may be inserted into the guide tubes of the fuel assemblies while the new fuel is in the storage rack.

During reactor refueling operations the new fuel is removed (with CEA's inserted if stored with the fuel) from the new fuel storage racks and transferred to the new fuel elevator.

The new fuel elevator lowers the fuel assembly into the refueling transfer canal where the spent fuel handling machine transfers the fuel assembly to the fuel pool upending mechanism. Interlocks prevent the spent fuel handling machine from lowering the fuel assembly unless the upender is in the vertical position. After a new fuel assembly has been placed in the upending mechanism, a spent fuel assembly may be removed from the other position of the fuel carrier and transferred to a designated position in the spent fuel storage racks.

9.1.4.2.2 Spent Fuel Handling The spent fuel handling equipment is designed to handle the spent fuel underwater from the time it leaves the reactor until it is placed in a cask for shipment from the site. Underwater transfer of spent fuel provides a transparent radiation shield, as well as the cooling medium for removal of decay heat.

Although boric acid is added to the water, soluble boron is not required for subcriticality of the fuel stored in the spent fuel pool. The major components of the system are the refueling machine, the fuel transfer equipment and the spent fuel handling machine. The refueling machine moves fuel assemblies into and out of the reactor core and between the core and the transfer equipment. The fuel transfer equipment tilts fuel assemblies from the vertical position to the horizontal, shuttles them through the containment wall to the fuel handling building transfer canal and returns them to the vertical position. The spent fuel handling machine handles fuel between the transfer equipment and the fuel storage racks in the fuel pool. The spent fuel handling machine is also used to transfer irradiated fuel from the storage racks to the DSC/transfer cask during cask loading operations.

Special tools and lifting rigs are also used for disassembly of reactor components and are included in the refueling system.

Prior to refueling, the plant is shut down and reactor coolant temperature is established at the refueling temperature (<140°F). During the cooldown, preparations are begun for the refueling operation. Special tools and lifting rigs used for disassembly of reactor components for refueling are included in the fuel handling system.

9.1-19 Amendment No. 23 (11/08)

Refueling operations are initiated with the removal of the missile shield from over the reactor. The control element drive mechanisms are disengaged from their drive shaft extensions by deenergizing the CEDM electromagnetic coils, and both mechanism and incore instrument cabling disconnected in preparation for head removal. The CEDM cooling shroud is disconnected from the duct work and the vessel vent line removed. The stud tensioners are used to remove the preload of the vessel head studs. Plugs are installed to protect the empty stud holes and two alignment pins are installed in the vessel flange for subsequent operations. The hatches of the Permanent Cavity Seal Ring are installed to provide a watertight seal such that the annulus between the reactor vessel flange and the refueling pool liner is closed, thus preventing water from entering the lower portion of the reactor cavity. A lifting frame is then installed on the head assembly and, by means of the containment building polar crane, the head is removed to its storage location.

The flange on the transfer tube is removed and, after the refueling cavity is filled, the fuel transfer, valve is opened to establish a common water level between the cavity and fuel pool preparatory to refueling.

The CEA drive shaft extensions are disconnected from the CEA's by use of a tool hung from the refueling machine auxiliary hoist. The extension shafts are then locked in place for subsequent removal with the vessel upper guide structure. The upper guide structure lift rig (Figure 9.1-8) is installed and the incore instrumentation is withdrawn into the upper guide structure and locked in place.

Provision is made in the refueling cavity for the temporary storage of the upper guide structure. After this is removed from the vessel, the refueling machine hoist mechanism is positioned at the desired location over the core. Alignment of the hoist to the top of the fuel assembly is accomplished through the use of a digital readout system. After the fuel hoist is lowered, minor adjustments can be made to properly position the hoist if misalignment is indicated on the monitor. The operator then energizes the actuator assembly which rotates the grapple at the bottom of the hoist and locks the fuel assembly to the hoist.

The hoist motor is started and the fuel assembly withdrawn into the fuel hoist box assembly so that the fuel is protected during transportation to the upending machine. The grapple is designed to preclude inadvertent disengagement as the fuel assembly is lifted vertically from the core. When the fuel assembly has been withdrawn out of the grapple zone, positive locking between the grapple and the fuel assembly is established so that uncoupling is prevented even in the event of inadvertent initiation of an uncoupling signal to the assembly. After removal from the core, the spent fuel assembly is moved underwater to the transfer area of the pool. The spent fuel assembly is lowered into the transfer carriage of the upending machine in the refueling cavity. If the fuel assembly contains a control element assembly, the CEA handling tool may be used to transfer the CEA to its new host assembly. CEA transfer may occur either in the refueling cavity or in the spent fuel pool.

Where full core offload has been performed, following completion of the defueling, the reactor internals may be temporarily reinserted into the defueled reactor vessel and the reactor head may be set on the vessel flange, if desired, to facilitate other work activities underway in containment. Water level in the vessel shall remain sufficient to cover any incore detector instrumentation present.

9.1-20 Amendment No. 22 (05/07)

If both upender baskets are being used for refueling activities, a fresh fuel assembly may be removed from the carriage and moved to the reactor as the upending machine rotates the spent assembly to the horizontal position after which a cable drive transports the carriage on tracks through the transfer tube.

Once received in the fuel pool, another upending machine returns the transfer carrier to the vertical position. The spent fuel handling machine transfers a new fuel assembly to the carrier, removes the spent fuel assembly from the transfer carrier and transports it to the spent fuel rack. The new fuel assembly is carried through the transfer tube to the refueling cavity where the refueling machine picks it up and places it in its proper position in the core. The refueling machine is also used to rearrange fuel within the core in accordance with the fuel management program.

Neutron sources described in Chapter 4 are currently stored in the spent fuel pool. Transfer of sources between fuel assemblies is performed via a tool manipulated from the spent fuel handling machine.

Capsules containing surveillance samples are similarly removed from the reactor vessel using a tool manipulated from the refueling machine which then transports them to the upender station for insertion into a dummy fuel bundle. The transfer carrier transports the dummy assembly with the surveillance capsules to spent fuel storage area for eventual disassembly and disposition.

Fuel rod leak detection or assessment of fuel cladding integrity and fuel assembly reconstitution are typically undertaken, if required, in the spent fuel pool. The equipment and techniques chosen for a particular inspection and/or reconstitution campaign (e.g., fuel sipping, ultrasonic or eddy current testing, and fuel assembly repair) will be appropriate for the intended purpose.

At the completion of the refueling operation, the fuel transfer valve is closed. The upper guide structure is reinserted in the vessel and the incore instrumentation placed in position. The drive shaft extensions are reconnected to the CEAs. The water in the refueling cavity is lowered to the level of the vessel flange using one of the low pressure safety injection pumps. Draining of the refueling cavity is completed using the reactor drain pumps; however, an alternate path is to transfer water to the RWT via the Spent Fuel Pool, provided water quality of the cavity is acceptable and RWT and Spent Fuel Pool levels are maintained within acceptable limits.

The head is lowered to the vessel flange until the drive shaft extensions are engaged by the control element drive mechanisms. Lowering of the head is then continued until it is seated. Then the head is bolted down, and the transfer tube closure flange installed. The hatches of the Permanent Cavity Seal Ring (PCSR) are removed and stored. CEDM and incore instrument cabling is reconnected. The ducting is reconnected to the CEDM cooling shroud, the vessel vent piping installed, and the missile shield placed in position.

9.1-21 Amendment No. 22 (05/07)

Since the storage capacity of the Spent Fuel Pool storage racks is insufficient to accommodate the storage of spent fuel over the plant's licensed life, the transfer of fuel to a separate storage location will eventually be necessary. To accomplish the fuel transfer, a spent fuel transfer cask will be placed in the cask pit area adjacent to the SFP. If the cask pit rack is installed in the cask pit area of the SFP, it will first require unloading and then will have to be removed along with the platform and placed in storage.

Following a cooling period that is defined by the spent fuel cask design (typically 5 years) which allows the decay heat and radioactivity levels to decrease, the spent fuel handling machine may be used to transfer the assemblies from the spent fuel racks to a spent fuel transfer cask placed in the flooded cask pit. The cask pit is located in the northeast corner of the fuel handling building adjacent to the spent fuel pool. The cask is placed in the cask pit by the overhead single-failure-proof cask handling crane. After the cask is loaded with spent fuel assemblies by the spent fuel handling machine, a shield plug is installed. The cask is then removed from the cask pit to the cask handling facility.

In the cask handling facility, the cask is cleaned to remove surface contamination. After the cask surface contamination is reduced to a safe level, the crane may load the spent fuel transfer cask onto a transporter for transport to the on-site independent spent fuel storage installation (ISFSI).

9.1.4.2.3 Component Description

1) Refueling Machine The reactor refueling machine is shown on Figure 9.1-9. The refueling machine is a traveling bridge and trolley which is located above the refueling cavity and rides on rails set in the concrete on each side of the pool. Motors on the bridge and trolley accurately position the machine over each fuel assembly location within the reactor core or fuel transfer carrier. The hoist assembly contains an air operated grappling device which, when rotated by the actuator mechanism, engages the fuel assembly to be removed.

The hoist assembly and grappling device are raised and lowered by a cable attached to the hoist winch. After the fuel assembly has been raised into the refueling machine, the refueling machine transports the fuel assembly to its designated location.

The controls for the refueling machine are mounted on a console which is located on the refueling machine trolley. Coordinate location of the bridge and trolley is indicated at the console by digital readout devices which are driven by encoders coupled to the guide rails through rack and pinion gears. An interlock status display panel is provided to give the operator an indication of interlocks that affect control function.

During withdrawal or insertion of either a fuel assembly, or a fuel assembly with a control element inserted, the load on the hoist cable is monitored at the console to ensure that movement is not being restricted. Limits are such that damage to the assembly is prevented.

Positive locking between the grapple and the assembly is provided by the engagement of the grapple actuator arm in axial channels running the length of the fuel hoist assembly.

Therefore, it is not possible to uncouple even with the inadvertent initiation of an uncoupling signal to the actuator assembly. The drives for both the bridge and trolley provide close control for accurate positioning, and brakes are provided to maintain the position once achieved. Interlocks are installed so that movement of the refueling machine is not possible when the hoist is withdrawing or inserting an assembly.

9.1-22 Amendment No. 23 (11/08)

For operations in the core, the bottom of the hoist assembly is equipped with a spreading device to move the surrounding fuel assemblies to their normal core spacing to ensure clearance for fuel assemblies being installed or removed. In addition, underwater lighting attached to the mast is provided to assure adequate visibility during in-core operations.

An anticollision device at the bottom of the mast assembly prevents damage should the mast be inadvertently driven into an obstruction, and a positive mechanical up-stop is provided to prevent the fuel from being lifted above the minimum safe water cover depth.

A system of pointers and scales serves as a backup for the remote repositioning readout equipment. Manually operated handwheels are provided for bridge, trolley and winch motions in the event of a power loss. Manual operation of the grappling device is also possible in the event that air pressure is lost.

2) Upending Machine Two upending machines are provided, one in the containment refueling cavity and the other in the fuel pool. Each consists of a structural steel support base from which is pivoted an upending straddle frame which engages the two-pocket fuel carrier. When the carriage with its fuel carrier is in position within the upending frame, the pivots for the fuel carrier and the upending frame are coincident. Hydraulic cylinders, attached to both the upending frame and the support base, rotate the fuel carrier between the vertical and horizontal positions as required by the fuel transfer procedure. Each hydraulic cylinder can perform the upending operation and can be isolated in the event of its failure. A long tool is also provided to allow manual rotation of the fuel carrier in the event that both cylinders fail or hydraulic power is lost.
3) Fuel Transfer Tube, Valve and Carriage A fuel transfer tube extending through the containment wall connects the refueling cavity with the fuel pool as shown on Figure 9.1-7. During reactor operation, the transfer tube is closed by means of a blind flange on the containment end of the transfer tube. Prior to filling the refueling cavity, the flange is removed. After a common water level is reached between the refueling cavity and the fuel pool, the fuel transfer valve is opened. The sequence is reversed after refueling is completed.

9.1-23 Amendment No. 20 (4/04)

The 36-inch diameter transfer tube is contained in a 48-inch diameter pipe which is sealed to the containment. The two concentric tubes are sealed to each other at both ends by welding rings and bellows-type expansion joints. The transfer tube valve is flange connected to the fuel pool end of transfer tube. The valve is supported in such a manner to allow for horizontal movement along the centerline of the transfer tube. The manual gear operator for the valve is designed to allow for movement of the valve due to thermal expansions and still permit operation. The valve is designed for operation from the operating floor. Description of the transfer tube valve is given in Table 9.1-3.

9.1-24

A transfer carriage conveys the fuel assemblies between the refueling cavity and the fuel pool, moving them through the fuel transfer tube on a transfer carriage. Large wheels support the carriage and allow it to roll on tracks within the transfer tube. Track sections at both ends of the transfer tube are supported from the pool floor and permit the carriage to be properly positioned at the upending mechanisms. The carriage is pulled by stainless steel cables connected to the carriage and through sheaves to its driving winch mounted on the operating floor. A two-pocket fuel carrier is mounted on the carriage and is pivoted for tilting by the upending machines. The load on the transfer cables is displayed at the master control console. An overload will interrupt the transfer operation. Manual override of the overload cutout allows completion of the transfer. The supports for the replaceable rails on which the transfer carriage rides are welded to the 36-inch diameter transfer tube.

4) CEA Handling Tool The CEA handling tool is designed to transfer irradiated control element assemblies between fuel assemblies during a fuel shuffle evolution. The tool consists of two parts; the mast/grapple assembly and the cage. The tool grapples the CEA spider and controls the CEA's five fingers as they are withdrawn from the bundle. It also provides lead-in's for positioning the tool as it is set on a bundle. The tool is suspended from a hoist on the refueling machine and is operated manually.
5) Fuel Handling Tools Two fuel handling tools are used to move fuel assemblies in the fuel pool area. A short tool is provided for dry transfer of new fuel, and a long tool is provided for underwater handling of both spent and new fuel in the fuel pool. The tools are operated manually from the walkway on the spent fuel handling machine.
6) Reactor Vessel Head Lifting Rig The reactor vessel head lifting rig is shown in Figure 9.1-11. This lifting rig is composed of a removable three-part lifting frame and a three-part column assembly which is attached to the reactor vessel closure head. The column assembly supports three hoists used for handling the reactor vessel stud tensioners.

9.1-25 Amendment No. 16, (1/98)

7) Reactor Internals Handling Equipment Two lifting rigs are used to remove either the upper guide structure or the core support barrel from the reactor vessel and to raise and lower the incore instrumentation support plate assembly.

The upper guide structure lifting rig is shown in Figure 9.1-8. This lifting rig consists of a delta spreader beam which supports three columns providing attachment points to the upper guide structure. Attachment to the upper guide structure is accomplished manually from the working platform by means of lifting bolt torque tools. The integral incore instrumentation hoist connects to an adaptor which is manually attached to the incore instrumentation structure by utilizing an adaptor torque tool. The incore instrumentation is then lifted by the polar crane auxiliary hook. The upper clevis assembly, which is common to this and the core support barrel lifting rig, is installed prior to lifting of the structure by the crane hook. Correct positioning is assured by attached bushings which mate to the reactor vessel guide pins.

The core support barrel lifting rig, shown in Figure 9.1-12, is used to withdraw the core barrel from the vessel for inspection purposes. The upper clevis assembly is a tripod-shaped structure connecting the lifting rig to the containment crane lifting hook.

The lifting rig includes a spreader beam providing three attachment points which are threaded to the core support barrel flange. This is done manually from the refueling machine bridge by means of the lifting bolt torque tool. Correct positioning of the lifting rig is assured by guide bushings which mate to the reactor vessel guide pins.

8) Stud Tensioners Three hydraulically operated stud tensioners are used to apply and remove the preload on the reactor vessel head closure studs. These tensioners are suspended from hoists which are attached to the head lift rig. The tensioner assemblies, when placed over the studs, rest upon the reactor vessel head flange. A socket is attached to the stud upper threads and when hydraulic pressure is applied to the stud tensioner pistons, the studs are elongated a predetermined amount. After the closure nuts are seated, the hydraulic pressure is released which results in the preload necessary to maintain the seal between the reactor vessel and the reactor vessel head.

A portable pumping unit is the source of hydraulic power. Hydraulic pressure is routed by hoses to the tensioner pistons. The control panel provides control of pump and tensioner operation. Pump pressure indication is also provided.

9.1-26 Amendment No. 22 (05/07)

9) Surveillance Capsule Retrieval Tool A retrieval tool is used during the refueling shutdown for manual removal of the irradiated capsule assemblies of the reactor vessel materials surveillance program described in Section 5.4.4. The surveillance capsule retrieval tool is shown in Figure 9.1-13. The tool is operated from a position on the carriage walkway of the refueling machine. Access to the capsule assembly is achieved by inserting the tool through 3-inch diameter retrieval holes in the core support barrel flange provided at each capsule assembly radial location.

A female acme thread at the end of the retrieval tool is mated to the surveillance capsule lock assembly (Figure 5.4-3) by turning the retrieval tool handle. A compressed spring in the lock assembly exerts a high frictional force at the retrieval tool-lock assembly interface to prevent disengagement during retrieval.

The overall length of the tool is 45.75 feet. The tool consists of two parts to facilitate storage. The upper portion is a 2-inch diameter tube and handle. The lower portion of the tool is also a 2-inch tube with a 1-inch outer diameter at the connector end. A 3/4-inch diameter hole in the upper end of the tool permits the polar crane to assist with the retrieval procedure and prevents inadvertent dropping of the tool. The tool is made of aluminum and has a dry weight of 40 pounds.

10) CEA Uncoupling Tool This tool is approximately 17 feet long and consists basically of two concentric tubes with a conical lead-in at the end to facilitate engagement with the CEDM extension shafts.

When installed, pins attached to the outer tube are engaged with the extension shaft outside diameter and the pins carried by the inner tube are inserted in the inner operating rod of the extension shaft. The inner tube of the tool is then lifted and rotated relative to the outer tube which compresses a spring allowing the gripper to release, thus separating the extension shaft from the CEA. The extension shaft is then handled by the tool.

11) Underwater Television The underwater camera was removed per PC/M 07143.

9.1-27 Amendment No. 23 (11/08)

12) Fuel Inspection and Reconstitution Equipment Inspection reconstitution campaigns to assess fuel cladding integrity or other aspects of fuel performance and to repair fuel assemblies are typically undertaken, if required, in the spent fuel pool. Contractors with specialized equipment may be used to conduct these activities. The equipment and techniques chosen for a particular inspection and reconstitution campaign (e.g., fuel sipping, ultrasonic or eddy current testing, and fuel assembly repair) will be appropriate for the intended purpose.
13) Hydraulic Power Package The hydraulic power package provides the motive force for raising and lowering the upender with the fuel carrier. It consists of a stand containing a motor coupled to a hydraulic pump, a sump reservoir, valves and the necessary hoses to connect the power package to the hydraulic cylinders on the upender. The valves can be lined up to actuate either or both upenders. The hydraulic fluid may be either borated or nonborated water.
14) Refueling Pool Seal The annulus between the reactor vessel flange and the floor of the refueling cavity is sealed during refueling by the use of the Permanent Reactor Cavity Seal/Shield Ring (PCSR). The PCSR (Figure 9.1-14) serves as a watertight seal to hold the refueling water above the reactor vessel and prevents it from leaking into the reactor cavity annulus. It is a permanent stainless steel ring with L-shaped flexures along the inside and outside circumferences that are welded to the reactor vessel seal ledge and to the refueling pool liner. The PCSR contains hatches which remain open during plant operation but are closed prior to filling the refueling cavity. There is also a permanent Neutron Shield installed in the reactor cavity below the PCSR that reduces neutron and gamma ray radiation dose rates but does not function to seal the refueling cavity. The PCSR is a Quality Related Seismic Component.

Provisions are made to test the hatch cover O-rings prior to filling the Refueling Pool.

Leak rate is monitored during refueling to assure that no sudden change in water level will occur.

9.1-28 Amendment No. 18, (04/01)

15) Refueling and Spent Fuel Handling Machines Fuel hoisting units on the refueling machine and spent fuel handling machine are in accordance with Specification for Electric Overhead Traveling Cranes, EDCI Specification No. 61.
16) Cask Handling Crane The spent fuel cask handling crane, including its runway, steel support structure and foundations, was replaced in 2003 in order to upgrade the main hoist load rating to 150 tons, raise the crane height by approximately 15 feet, and comply with NRC guidance for single-failure-proof cranes.

The crane is an overhead, multiple girder, top running bridge crane, with a top running trolley.

The crane bridge, trolley, and support superstructure are located outdoors, at the north end of the fuel handling building (FHB), where the crane can access the FHB interior through an opening in the roof and north wall normally covered by an L-shaped door. The crane's primary function is to transfer casks between the cask pit area adjacent to the spent fuel pool and the Cask Handling Facility and the heavy haul path. The crane runway girders are supported by a steel frame structure, with some of the structural columns supported by the FHB room and the remaining columns supported on concrete foundations at grade elevation. Both the superstructure and crane are designed as seismic Category 1 and can withstand tornado forces.

The crane's load bearing components are designed as part of a single-failure-proof load handling system, in particular the hoisting and braking subsystems. The design complies with the ASME NOG-1, Rules for Construction of Overhead and Gantry Cranes - 1998 including May 3, 2000 addenda, and CMAA #70-2000, Specifications for Electric Overhead Traveling Cranes. The design also implements the regulatory guidance for single-failure-proof cranes in NUREG-0554, Single-Failure-Proof Cranes for Nuclear Power Plants and NUREG-0612, Control of Heavy Loads at Nuclear Power Plants.

A single failure of a crane load-bearing component will not result in the loss of the crane's capability to safely retain the load. However, not all load-bearing components of the crane are assumed to be susceptible to a single failure. Some passive load-bearing items such as girders are conservatively designed with a sufficient safety factor that a failure of these components is not assumed. The remaining load-bearing components (e.g., the ropes, reeving system, and braking system) are redundant such that a single component failure will not result in a load drop event. Because of these design features, the potential for a cask drop event is considered extremely small for St. Lucie Unit 1.

The cask handling crane trolley has two hoists. The main hoist is rated at 150 tons, and meets NUREG-0612 guidelines for single-failure-proof handling systems. The main hoist will be used for load handling inside the FHB, and to transfer spent fuel casks between the FHB and the Cask Handling Facility. The auxiliary hoist is rated at 25 tons, and is of a conventional design (not single-failure-proof). The auxiliary hoist is available for handling loads outside the FHB, but will not handle loads either inside or above the FHB. Based on Section 5.1.2. of NUREG-0612, use of a single-failure-proof crane for cask handling in the FHB avoids the need to analyze for a cask drop in the vicinity of the spent fuel pool.

9.1-29 Amendment No. 25 (04/12)

The following describes the functions of interlocks that are part of the cask handling crane:

a) Crane Bridge and Trolley Lockout Keyswitch Prevents any bridge or trolley movement, by means of a key switch from the crane cab or remote radio transmitter, allowing Main and Auxiliary hoist operation only.

b) Restricted Area Lockout Keyswitch Prevents any hook movement over the entire cask pit area when there is fuel stored in the cask pit. The keyswitch is under the administrative control of the Control Room operator.

c) Control Location Selector Transfers control of the crane between the cab and the remote radio transmitter via a selector switch locate in the crane cab.

d) Bridge Stop Limits Prevents bridge from exceeding end-of-travel limits e) Trolley Stop limits Prevents trolley from exceeding end-of-travel limits f) Crane Restricted Handling Path Keyswitch and Limit Switches Prevents transporting of the cask inside the fuel handling building over areas other than the cask pit, using limit switches on the bridge and trolley, and a keyswitch to enable crane movement through the L-shaped door. The movement path of the Main Hoist hook through the L-shaped door is restricted to a corridor approximately one foot east or west of the centerline of the door opening, and the hook cannot move further south than a point approximately 11- 6 north of column line 1-FH3.

g) Hoist Overtravel Limits (Main and Auxiliary Hoists)

Prevents overtravel of the hoist in both the high and low directions. For the Main Hoist, overtravel in each direction is prevented by redundant limit switches at different settings.

h) Overload Limits (Main and Auxiliary Hoists)

Prevents sustained lifting in excess of rated capacity.

9.1-29a Amendment No. 20 (4/04)

17) Other FHB Cranes and Hosts Bulkhead Hoist The three ton bulkhead hoist used for installing and removing the fuel pool bulkhead between the pool and transfer canal is provided with the following brake systems:

a) The hoist braking system is equipped with a self-actuating load brake with a self-actuating motor brake. Each brake supports and holds the full rated load without power.

b) The trolley travel braking system is a 30 percent torque drag brake built into the gear train, running in oil, to provide smooth operation and eliminate drifting of the trolley along the beam.

New Fuel Crane The five ton underhung single bridge crane is used for handling new fuel and is provided with the following brake systems:

a) The bridge travel section of the crane is provided with a magnetic brake system which holds when the power is off and releases when the power is on.

b) The hoist braking system is equipped with a mechanical load brake and self-actuating motor brake. Each brake supports and holds the full rated load without power.

c) The trolley travel braking system is a 30 percent torque drag brake built into the gear train, running in oil, to provide smooth operation and eliminate drifting of the trolley along the beam Refueling Machine Auxiliary Hoist A one ton auxiliary hoist is provided on the refueling machine to aid in equipment and tool handling. This hoist is not used for fuel transfer but allows additional hoisting capabilities during refueling operations, thus freeing the polar crane for required heavy lifting services.

9.1.4.3 System Evaluation a) A failure mode analysis of the refueling machine is shown in Table 9.1-5.

b) The fuel handling accident analysis presented in Section 15.4.3 assumes damage to the entire group of fuel rods in an assembly as a basis for the fuel handling accident. The exclusion boundary doses resulting from a fuel handling accident are within the guidelines established for design basis accidents.

c) Reliability of the fuel handling equipment and the associated instrumentation and controls, is assured through the implementation of preoperational tests and routines.

9.1-30 Amendment No. 25 (04/12)

In addition, the following special features of the equipment assure safe and reliable operation:

1) Grapples and mechanical latches which carry fuel assemblies or CEA's are mechanically interlocked against accidental opening.
2) Equipment has suitable locking devices or restraints to prevent parts, fasteners, or limit switch actuators from becoming loose. In those cases where a loosened part or fastener can drop into, or is not separated by a barrier from, or whose rotary motion will propel it into the water of the refueling cavity or fuel pool, these parts and fasteners are lockwired or otherwise positively captured.
3) The refueling machine is capable of removing and installing a fuel assembly at each operating location at the most adverse combined tolerance condition for the equipment, core internals and fuel assemblies.
4) Positive mechanical stops prevent the fuel from being lifted above the minimum safe water cover depth and will not cause damage or distortion to the fuel or the fuel handling equipment when engaged at full operating hoist speed.
5) The hoist is provided with a load measuring device with a visual display of the load and interlocks to interrupt hoisting if the load exceeds fuel assembly design limits.
6) The stresses under the combined deadweight, live, and operating basis earthquake loads do not exceed the allowable stress of the material per AISC requirements. The equipment can withstand the loading induced by the design base earthquake vertical and horizontal loadings which are considered as acting simultaneously in conjunction with normal loads without exceeding minimum material yield stresses as specified by AISC.

Where required, keepers are provided to preclude derailment of equipment under seismic loading.

7) Gamma radiation levels in the containment and fuel storage areas are continuously monitored. These monitors provide an audible alarm at the initiating detector indicating an unsafe condition. Continuous monitoring of the count rate provides immediate indication of an abnormal core flux level in the control room and in the containment.
8) There is direct communication between the control room and the refueling machine console during fuel handling operations. This provision allows the control room operator to inform the refueling machine operator of any impending unsafe condition detected from the control room during fuel movement.

9.1-31 Amendment 15, (1/97)

9) The fuel transfer tube is large enough to provide natural circulation cooling of a fuel assembly in the unlikely event that the transfer carriage should be stopped in the tube. The operator for the fuel transfer tube valve extends from the valve to the operating elevation. Travel stops in the fuel handling equipment limit the travel to restrict withdrawal of the spent fuel assemblies. This limitation, together with water level control, results in the maintenance of a minimum water cover of 9 feet over the active portion of the fuel assembly resulting in a radiation level of 2.5 mrem/hr or less at the surface of the water. The depth of water surrounding the fuel transfer canal, transfer tube and spent fuel storage pool is maintained to limit the maximum continuous radiation levels in working areas to 2.5 mrem/hr.
10) The arrangement of the fuel handling building has been designed such that the spent fuel cask can not traverse over spent fuel stored in the spent fuel storage racks.

Administrative procedures prevent moving heavy loads over fuel stored in the cask pit rack.

11) Miscellaneous design features include - backup hand operation of hoist and traverse drives in the event of power failure, a dual wound transfer system motor to permit applying an increased pull on transfer carrier in the event it becomes stuck, a viewing port in the refueling machine trolley deck to provide visual access to the reactor for the operator, electronic and visual indication of the refueling machine position over the core, a protective shroud into which the fuel assembly is drawn by the refueling machine, transfer system upender manual operation by a special tool in the event that the hydraulic system becomes inoperative, and removal of the transfer system components from the refueling cavity for servicing without draining the water from the pool.
12) The two major subsystems of the overall fuel handling complex (refueling machine and fuel transfer system are electrically interlocked to prevent incorrect and potentially damaging sequences of operation (interlocks were also provided with the CEA change mechanism which is no longer used and may not be installed). The fuel handling system and consequently the associated electrical interlocks are not required for the safe operation of the plant. Refer to Section 7.6.1.2 for interlocks. An interlock status display panel is provided for operator information on interlocks inhibiting a control function.
13) The spent fuel handling machine is provided with an electronic load cell and digital readout for continuous indication of load and operator surveillance.

d) Cask drop analysis inside the Fuel Handling Building

Background

The original cask drop analysis inside the FHB has been deleted from this section, and is not longer part of the design basis for St. Lucie Unit 1. The cask handling crane is designed to be single-failure-proof, such that the potential for a cask drop event is considered extremely small such that a cask drop accident need not be analyzed in accordance with Section 5.1.2 of NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants".

9.1-32 Amendment No. 22 (05/07)

Figures 1.2-18 and 19 illustrate the arrangement of the building and cask handling crane. The bottom of the cask must attain elevation +77' for entry into the building through the opening provided by opening of the sliding "L" shaped door. Crane movement is restricted such that the main hook cannot travel into the spent fuel pool beyond the separating wall which separates the cask pit area from the fuel pool.

The 150-ton capacity single-failure-proof main hook is designed to retain control of the load in the event of a single failure in the lifting system. Nonetheless, it was postulated that an uncontrolled vertical descent resulting in sufficient cask energy to breach the pool liner in the cask pit could occur. It is for this reason that the submerged separating wall was provided. This approach was considered a viable alternative to the additional reinforcement in the storage area proposed in response to PSAR Question 4.1.12, Amendment 5, 12/14/69.

The separating wall and fuel pool walls are designed for hydrostatic pressure. The fuel pool is lined with 3/16 and 1/2 inch stainless steel plates which serve as leakage barriers. The separating wall consists of two 1/4 inch thick stainless steel plates which are spaced at 6 5/8 inch centers. These plates are connected by 3/8 inch stainless steel stiffening plates at intervals of 19 to 24 inches. The separating wall is "L" shaped; the sides are welded to embedded 3/4 inch stainless steel plates; and the bottom ends are welded to 1/2 inch liner plate. The height of the wall above the pool floor is 14'9". See Figures 1.2-18 and 19 for its location in the northeast corner of the fuel handling building.

9.1-33 Amendment No. 21 (12/05)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-34 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-35 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-36 Amendment No. 20 (4/04)

NUREG-0612, Control of Heavy Loads at Nuclear Power Plants and AEC Safety Guide 13 Position 5 both recommend that a cask drop be postulated unless the cask handling crane is designed as part of a single-failure-proof load handling system. Since the cask crane is designed to be single-failure-proof, a cask drop is not required to be postulated.

9.1-37 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-38 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-39 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-40 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-41 Amendment No. 20 (4/04)

e) Radiological consequences of cask drop - deleted 9.1-42 Amendment No. 20 (4/04)

THIS PAGE LEFT BLANK INTENTIONALLY.

9.1-43 Amendment No. 20 (4/04)

f) Reactivity effects of a fuel mispositioning event The misplacement of a fresh unirradiated fuel assembly of 4.6 weight % enrichment could, in the absence of soluble poison, result in exceeding the design reactivity limitation (keff of 0.95). This could occur if the assembly were to be inadvertently loaded into a Region 2 storage cell intended to remain empty, or into a cell intended to hold low reactivity fuel. Soluble poison, however, is present in the spent fuel pool water (for which credit is permitted under these conditions) and would maintain the reactivity substantially less than the design limitation.

The largest reactivity increase occurs for accidentally mispositioning a new fuel assembly into a Region 2 storage cell loaded with Fuel Type 3. Under this condition, the presence of 1500 ppm soluble boron controls keff to less than 0.95. Administrative procedures will be used to confirm and assure the continued presence of soluble poison in the spent fuel pool water.

9.1-44 Amendment No. 26 (11/13)

A criticality evaluation for the fuel inspection elevator, upender and fuel transfer tube are reported in Reference 23. The highest reactivity assuming no gap between the second assembly, is 0.8783 including calculational uncertainties and 1000 ppm soluble boron.

9.1.4.4 Test and Inspections During manufacture of the fuel handling equipment at the vendor's plant, various in-process inspections and checks are required including certification of materials and heat treating and liquid penetrant or magnetic particle inspection of welds loaded in excess of 10,000 psi. Following completion of manufacture, compliance with design and specification requirements is determined by assembling and testing the equipment in the vendor's shop. Utilizing a dummy fuel bundle and a dummy CEA, each having the same weight, center of gravity, exterior size and geometry as an actual fuel assembly, area equipment is run through several complete operational cycles. In addition, the equipment is checked for its ability to perform under the maximum limits of load, fuel mislocation and misalignment. All traversing mechanism are tested for speed and positioning accuracy. All hoisting equipment is tested for vertical functions and controls, rotation, and load misalignment. Hoisting equipment is tested to 125 percent of maximum working load. Set points are determined and adjusted limits are verified. Interlock function and backup systems operations are checked. Those functions having manual operation 9.1-44a Amendment No. 26 (11/13)

capability are exercised manually. During these tests the various operating parameters such as a motor speed, voltage, and current, hydraulic system pressures, and load measuring accuracy and set points are recorded. At the completion of these tests the equipment is checked for cleanliness and the locking of fasteners by lock-wire or other means is verified.

When installed in the plant, the equipment is again tested and the results compared to the results of tests performed at the vendor's plant. Any changes in adjustment and condition which may have ensued from transit to the site are noted.

Plant testing permits determination of characteristics which are unique to the actual site installation and therefore cannot be duplicated in the vendor's shop test. Each component is inspected and cleaned prior to installation into the system.

The crane manufacturer will furnish copies of certified mill test reports covering hooks and hoist ropes.

Prior to equipment operation recommended maintenance and preoperational tests (including checks of control circuits, interlocks, safety, and alarm functions) are performed in accordance with approved plant procedures.

9.1-45 Amendment No.18, (04/01)

REFERENCES FOR SECTION 9.1

1. DELETED
2. Not Used
3. Not Used
4. Not Used
5. Not Used
6. Not Used
7. DELETED
8. Not Used
9. C. O. Woody (FPL) to NRC Re: Spent Fuel Rerack, L-87-245 dated 6/12/87.
10. Safety Evaluation prepared by the Office of Nuclear Reactor Regulation (NRC) relating to the Reracking of the Spent Fuel Pool at the St. Lucie Plant, Unit No. 1, License Amendment 91, March 11, 1988.
11. Not Used
12. DELETED
13. Not Used
14. NRC Letter from T.J. Orf (NRC) to Mano Nazar (FPL), St. Lucie Plant, Unit 1 - Issuance of Amendment Regarding Extended Power Uprate (TAC No. ME5091).
15. Safety Evaluation Report by the Office of Nuclear Reactor Regulation Related to Amendment No. 213 to Facility Operating License No. DPR-67, Florida Power and Light Company, St. Lucie Plant, Unit No. 1 - Docket No. 50-335.
16. St. Lucie Plant Condition Report 97-0583 and Plant Manager Action Items 97-04-170 & -171.
17. FPL Safety Evaluation PSL-ENG-SENS-97-050, "Routine Performance of Full Core Fuel Offloads," Revision 2, August 2005.
18. FPL Calculation PSL-1FSM-97-020, "Fuel Pool Hx Performance During Full Core Offload," July, 1997.
19. Not Used
20. Not Used 9.1-46 Amendment No. 26 (11/13)
22. CASMO-4, A Fuel Assembly Burnup Program User's Manual, Studsvik/SOA-95/1, Studsvik of America, Inc. and Studsvik Core Analysis AB (proprietary).
22. MCNP - A General Monte Carlo N-Particle Transport Code, Version 4A, LA-12625, Los Alamos National Laboratory (1993).
23. Holtec International Report No. HI-2104714, St. Lucie Unit 1 Criticality Analysis for EPU and Non-EPU Fuel, updated through Revision 2, 9/14/2011.
24. Enclosure of NRC letter dated October 25, 1996, Safety Evaluation by the Office of Nuclear Reactor Regulation Relating to Topic Report WCAP-14416-P[-A], "Westinghouse Spent Fuel Rack Criticality Analysis Methodology," Westinghouse Electric Corporation.
25. Enclosure of NRC letter dated September 23, 2004, St. Lucie Plant, Unit 1 - Issuance of Amendment Regarding Spent Fuel Pool Soluble Boron Credit (TAC No. MB6864).
26. St. Lucie Unit 1 Technical Specifications, updated through Amendment 213, Figure 5.6-2, Allowable Region 2 Storage Patterns and Arrangements.
27. Attachments and Enclosures to FPL letter L-2002-221, St. Lucie Unit 1 Proposed License Amendment Spent Fuel Pool Soluble Boron Credit, November 25, 2002.
28. PC/M 03-098, Reconfiguration of St. Lucie Unit 1 Fuel Pool Storage, Revision 0.
29. Enclosures to NRC letter dated August 16, 2004, St. Lucie Units 1 and 2, Correction/Clarification to NRC Safety Evaluation Regarding Cask Pit Rack Amendments (TAC Nos. MB 6627 and MB 6628).
30. FPL Letter L-2002-187, St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 Proposed License Amendments Addition of Cask Pit Spent Fuel Storage Racks Technical Specification Requirements, October 23, 2002.
31. FPL Evaluation PSL-ENG-SEMS-99-043, Rev. 1, Use of PRC-01 Resin to Remove Co-58 Contaminants.
32. FPL Calculation PSL-IFJF-07-002, St. Lucie Unit 1 - Irradiated Fuel Assembly Selection for Initial Dry Cask Loading Campaign, Revision 1, October 19, 2007
33. PC/M 07130, Fuel Selection and Initial Dry Cask Loading Campaign at St. Lucie Unit 1, Revision 0.
34. MCNP - A General Monte Carlo N-Particle Transport Code, Version 5, Los Alamos National Laboratory, LA-UR-03-1987 (2003).
35. EC 273188, St. Lucie Unit 1 Spent Fuel Pit Storage Rack Borated Inserts for Extended Power Uprate (EPU), Revision 0.

9.1-46a Amendment No. 26 (11/13)

Table 9.1-1 Deleted 9.1-47 Amendment No. 21 (12/05)

TABLE 9.1-2 FUEL POOL WATER CHEMISTRY pH (77F) 4.5 to 10.6 Boric Acid, Maximum, wt % 1.5 Dissolved Air, Maximum Saturated Chloride, Maximum, ppm 0.15 Fluoride, Maximum, ppm 0.1 Sulfate, ppm 0.1 9.1-48 Amendment No. 22 (05/07)

TABLE 9.1-3 DESIGN DATA FOR FUEL POOL SYSTEM COMPONENTS

1. Heat Exchangers Quantity 1 Type Shell and Tube Tube Side Fluid Fuel Pool Water Design Temperature, F 250 Design Pressure, psig 75 Normal Operating Conditions Flow, gpm 1500 Inlet Temperature, F 120 Outlet Temperature, F 107.5 Materials ASTM-SA-240, Type 304 Code ASME III, Class C Shell Side Fluid Component Cooling Water Design Temperature, F 250 Design Pressure, psig 150 Normal Operating Conditions Flow, gpm 3560 Inlet Temperature, F 100 Outlet Temperature, F 105.3 Materials Carbon Steel Code ASME III, Class C
2. Ion Exchangers Quantity 1 Design Pressure, psig 200 Design Temperature, F 250 Normal Operating Temperature, F 120 Vessel Volume, ft3 55 Resin Volume, ft3 (useful) 32 Code ASME III, Class C Normal Flow Rate, gpm 150 Materials ASTM-SA-240, Type 304 Resin types Cation/anion mixed bed and particle removal, e.g. PRC-01
3. Pumps Fuel Pool Cooling Fuel Pool Purification Quantity 2 1 Type Centrifugal Centrifugal Design Pressure, psig 75 150 Design Temperature, F 250 250 Normal Operating Conditions Flow, each, gpm 1500 150 Head, ft 70 165 Fluid Temperature, F 120 120 9.1-49 Amendment No. 21 (12/05)

TABLE 9.1-3 (Cont'd)

Seal Type Mechanical Mechanical Horsepower 40 15 Material ASTM A-351 Type 316 Gr CF -8M Stainless Steel

4. Filters Quantity 1 Type of Elements Replaceable Cartridge Max Retention Capability 98% of particulates > 5 microns Retention of 5 micron particles 98%

Design Pressure, psig 100 Design Temperature, F 200 Design Flow, gpm 150 Material ASTM-SA-240, Type 304 Code ASTM VIII

5. Strainers Fuel Pool Purification Pump Fuel Pool Ion Suction Exchanger Quantity 1 1 Type Basket Wye Design Flow, gpm 150 150 Design Pressure, psig 100 100 Design Temperature, F 200 200 Screen Size 1/8" perforated 100 U.S. Mesh Body Material ASTM A-351 ASTM A-351
6. Fuel Transfer Valve Type Gate Size, in. 36 Design Pressure, psig 75 Normal Operating Differential Pressure 34'-6" H2O Design Temperature, F 150 Normal Operating Temperature, F 140 Materials ASTM-A-351 CF-8M Design Integrated Dose, Rads 1 x 107 Allowable Seat Leakage, cc/hr 72 UNIT 1 9.1-50 Amendment No. 28 (05/17)

TABLE 9.1-4 FUEL POOL SYSTEM INSTRUMENTATION Indication Alarm1 Normal System Parameter Contr Operating Inst.

& Location Local Room High Low Rec.1 Control Function Inst. Range(2) Range Accuracy(2)

Heat exchanger inlet

  • Heat exchanger outlet
  • temp.

Fuel pool temp. *

  • Fuel pool pump *
  • 40 psig discharge press.

Purification pump

  • 5-18 psig suction press.

Purification pump

  • 50 psig discharge press.

Ion exchanger

  • 2-10 psi differential press.

Filter differential

  • 1-25 psi pressure Fuel pool water *
  • level 1

All alarms and recorders are in the control room unless otherwise indicated.

2 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.1-51 Amendment No. 23 (11/08)

TABLE 9.1-5 FAILURE MODE ANALYSIS OF REFUELING MACHINE Component Detrimental Effect Identification Failure Mode On System Corrective Action Remarks R. M. Fuel Hoist Electrical Overload None Continue refueling Use visual presentation of Weight System Trip Fails repair on non- load on meter Complete system None interferring basis Max. stall torque of motor fails as above will not damage bundle (Ref.

16)

Fuel Carrier Wheels lock in Transfer change Switch to 5 hp mode Load sufficient to move fuel transfer tube completed carrier with all wheels Hydraulic Power Line to cylinder None Valve off defective Upender has two cylinders, supply for upender on upender ruptures line each of which is capable of raising upender Loss of hydraulic Process can continue Upend manually Use tool provided power on slower basis Brake on R.M. Does not provide Continue, repair on Redundant brake system fuel hoist required brake load None non-interferring provided basis Fuel Carrier Cable parts Delays refueling Move fuel carrier to Cable safe position with Remove fuel prior to repair manual tool R. M. Hoist Motor Power Failure Operation can be Repair Hoist using manual hand-Bridge Drive Motor Power Failure Operation can be Repair Drive using manual hand-Electronic Position Power Failure None Repair non-inter- Indexing can be accomplished Indication ferring basis by back-up scale and pointer Fuel Carrier Po- Electrical Failure None Repair non-inter- Winch motor stalls on over-sition Sensing ferring basis load System 9.1-52 Amendment No. 20 (4/04)

TABLE 9.1-5 (Cont'd)

Component Detrimental Effect Identification Failure Mode On System Corrective Action Remarks Refueling Machine Loss of air None Repair Continue, using manual mode Pressure Refueling Machine Electrical Failure None Repair non-inter- Redundant mechanical counter Electronic Hoist ferring basis provided position indication 9.1-53 Amendment No. 25 (04/12)

Tables 9.1-6 and 9.1-7 have been deleted.

Pages 9.1-55 through 9.1-59 have been removed.

9.1-54 Amendment No. 21 (12/05)

PAGE INTENTIONALLY LEFT BLANK 9.1-60 Amendment 15, (1/97)

TABLE 9.1-8a Minimum Burnup as a Function of Enrichment Cooling Time Coefficients Fuel Type (Years) A B C 1 0 -36.6860 22.4942 -1.4413 2 0 -36.1742 16.6000 -0.8958 3 0 -34.7091 23.1361 -1.6204 0 -24.5145 21.3404 -1.2444 2.5 -26.8311 22.5246 -1.5029 5 -24.7233 20.9763 -1.3246 4

10 -23.6285 19.9541 -1.2505 15 -23.5458 19.9336 -1.3180 20 -22.4382 19.2460 -1.2629 0 -8.1856 14.5275 -0.0719 2.5 -11.8506 16.1475 -0.3969 5 -16.5196 18.5309 -0.7837 5

10 -13.6831 16.3475 -0.5844 15 -12.5819 15.6175 -0.5656 20 -12.6469 16.4575 -0.5906 Notes:

1. To qualify in a fuel type, the burnup of a fuel assembly must exceed the minimum burnup BU" calculated by inserting the "coefficients" for the associated "fuel type" and "cooling time" into the polynomial function:

BU = A + B*E + C*E2, where:

BU = Minimum Burnup (GWD/MTU)

E = Initial Maximum Planar Average Enrichment (weight percent uranium-235)

A, B, C = Coefficients

2. Interpolation between values of cooling time is not permitted.

9.1-60a Amendment No. 26 (11/13)

PAGE DELETED 9.1-60b Amendment No. 26 (11/13)

TABLE 9.1-9 DESIGN DATA Min. B-10

  • Flux Trap Region Cell Pitch Loading Gap (nominal inch) (areal density) (nominal inch)

Spent Fuel Pool Storage Racks 1 ** 10.12 .020 gm/cm2 1.12 2 ** 8.86 .007 gm/cm2 0.0 Cask Pit Rack 1 10.30 0.028 gm/cm2 1.303

  • Boron, as part of Boraflex neutron absorber material is no longer credited in spent fuel pool criticality analyses.
    • Historical information 9.1-61 Amendment No. 21 (12/05)

TABLE 9.1-10 TABLE OF MODULE DATA NO. OF NO. OF CELLS CELLS TOTAL NO.

NO. OF IN N-S IN E-W OF CELLS MODULE I.D. MODULES DIRECTION DIRECTION PER MODULE Spent Fuel Pool Storage Racks Region 1 2 9 9 81 A1 and A2 Region 1 2 9 10 90 B1 and B2 Region 2 4 13 9 117 C1, C2, C3, C4 Region 2 3 13 8 104 D1, D2, D3 Region 2 2 11 8 88 E1 and E2 Region 2 1 12 8 96 F1 Region 2 2 12 9 108 G1 and G2 Region 2* 1 13 8 96 H1 Cask Pit Rack Region 1 1 11 13 143

  • Cells missing in this module due to sparger.

Refer to Figure 9.1-9 9.1-62 Amendment No. 21 (12/05)

TABLE 9.1-11 MODULE DIMENSIONS AND WEIGHT NOMINAL CROSS-SECTION

  • ESTIMATED DRY DIMENSIONS WEIGHT (lbs)

MODULE I.D. N-S E-W PER MODULE Spent Fuel Pool Storage Racks Region 1 90-1/4" 90-1/4" 26,700 A1 and A2 Region 1 90-1/4" 100-7/16" 29,800 B1 and B2 Region 2 115-11/16" 80-1/6" 24,100 C1, C2, C3, C4 Region 2 115-11/16" 71-3/16" 21,500 D1, D2, D3 Region 2 97-7/8" 71-3/16" 18,200 E1 and E2 Region 2 106-3/4" 71-3/16" 19,800 F1 Region 2 106-3/4" 80-1/16" 22,300 G1 and G2 Region 2 115-11/16" 71-3/16" 19,800 H1 Cask Pit Rack Region 1 112.105" 132.705" 32870

  • Excluding girdle bars 9.1-63 Amendment No. 21 (12/05)

TABLE 9.1-12

SUMMARY

OF CRITICALITY SAFETY ANALYSES FOR THE CASK PIT RACK Planar Average Enrichment [wt% 235U] 4.6 Uncertainties MCNP4a Bias Uncertainty (95%/95%) +/- 0.0090 CASMO-4 Bias Uncertainty (95%/95%) +/- 0.0025 Calculational Statistics (95%/95%,2.0x) +/- 0.0014 Fuel Eccentricity Negative Rack Tolerances +/- 0.0103 Fuel Tolerances +/- 0.0031 Statistical Combination of Uncertainties +/- 0.0143 Reference keff (MCNP4a) 0.8983 Biases Temperature Bias 0.0020 MCNP4a Bias (see Appendix A) 0.0012 Maximum keff 0.9158 Regulatory Limiting keff 0.9500 9.1-64 Amendment No. 26 (11/13)

TABLE 9.1-12a

SUMMARY

OF CRITICALITY SAFETY ANALYSES FOR THE SFP, 0 ppm (Representative Calculation for Each Case)

Fuel Type 1 2 3 4 5 Enrichment (wt% U-235) 46 46 46 46 46 Burnup (GWD/MTU) 40 25 40 50 60 Cooling time (yr) 0 0 0 0 0 Axial Profile Uniform Uniform Uniform Enr-Blank Nat-Blank Calculated keff 0.9348 0.9438 0.9453 0.9456 0.9400 Depletion Uncertainty 0.0139 0.0086 0.0141 0.0177 0.0207 Burnup Uncertainty 0.0069 0.0043 0.0071 0.0089 0.0103 FP Uncertainty 0.0209 0.0144 0.0215 0.0223 0.0243 MCNP Code Uncertainty 0.0087 0.0087 0.0087 0.0087 0.0087 Calculation Uncertainty (2) 0.0012 0.0010 0.0010 0.0012 0.0012 Total Uncertainty (statistical combination) 0.0275 0.0194 0.0281 0.0311 0.0347 Code bias 0.0013 0.0013 0.0013 0.0013 0.0013 Temperature Bias 0.0054 0.0044 0.0017 0.0000 0.0022 Total Correction 0.0342 0.0251 0.0311 0.0324 0.0382 Maximum keff 0.9690 0.9689 0.9764 0.9780 0.9782 Burnup (GWD/MTU) 35 20 35 45 55 Cooling Time (yr) 0 0 0 0 0 Axial Profile Uniform Uniform Uniform Uniform Nat-Blank Calculated keff 0.9655 0.9742 0.9739 0.9673 0.9617 Depletion Uncertainty 0.0123 0.0071 0.0127 0.0167 0.0196 Burnup Uncertainty 0.0062 0.0036 0.0063 0.0083 0.0098 FP Uncertainty 0.0191 0.0122 0.0199 0.0242 0.0237 MCNP Code Uncertainty 0.0087 0.0087 0.0087 0.0087 0.0087 Calculation Uncertainty (2) 0.0012 0.0014 0.0012 0.0014 0.0012 Total Uncertainty (statistical combination) 0.0251 0.0170 0.0260 0.0318 0.0335 Code bias 0.0013 0.0013 0.0013 0.0013 0.0013 Temperature Bias 0.0054 0.0044 0.0017 0.0000 0.0022 Total Correction 0.0318 0.0227 0.0290 0.0331 0.0370 Maximum keff 0.9973 0.9969 1.0029 1.0004 0.9987 Target keff 0.99 0.99 0.99 0.99 0.99 Calculated Burnup (GWD/MTU) 36.29 21.23 37.43 47.32 57.12 9.1-64a Amendment No. 26 (11/13)

TABLE 9.1-12b

SUMMARY

OF CRITICALITY SAFETY ANALYSES

SUMMARY

OF CRITICALITY SAFETY AALYSES FOR SFP, 500 ppm K-calc + Total Fuel Type Enr Bu K-calc Total Correction Correction 1.9 0.8 0.8573 0.0205 0.8778 1

4.6 36 0.8815 0.0342 0.9157 1.9 0 0.7948 0.0191 0.8139 2

4.6 21 0.8852 0.0256 0.9108 1.9 11 0.8740 0.0157 0.8897 4

4.6 47 0.8913 0.0349 0.9262 1.9 17 0.8768 0.024 0.9008 5

4.6 57 0.8861 0.0424 0.9285 1.9 3 0.8779 0.0175 0.8954 3

4.6 37 0.8945 0.0311 0.9256 9.1-64b Amendment No. 26 (11/13)

PAGE DELETED 9.1-64c Amendment No. 26 (11/13)

TABLE 9.1-13 REACTIVITY EFFECTS OF ABNORMAL AND ACCIDENT CONDITIONS Spent Fuel Pool Case Enr Bu K-calc + Total Boron K-calc Total Correction Correction Single Fresh Assembly 4.6 0 1000 0.8666 0.0117 0.8783 Mislocation Misload Accidents Region 1 Checkerboard of 4.6 0 1000 0.9138 0.0117 0.9255 Fresh and Empty Cells Fuel Type 2 4.6 21 1000 0.9129 0.0256 0.9385 Fuel Type 3 1.9 3 1500 0.8857 0.0175 0.9032 Fuel Type 3 4.6 37 1500 0.9079 0.0311 0.9390 Inspection - Fuel 4.6 47 1500 0.8700 0.0349 0.9049 Type 4 Inspection - Fuel 4.6 57 1500 0.8601 0.0424 0.9025 Type 5 Inspection - Fuel 4.6 37 1500 0.8920 0.0311 0.9231 Type 3 Single Missing Insert Fuel Type 1 4.6 36 1000 0.8140 0.0342 0.8482 Fuel Type 5 4.6 57 1000 0.8334 0.0424 0.8758 Incorrect Loading Curve Fuel Type 5 4.6 47 1000 0.8638 0.0424 0.9062 Cask Pit Rack Abnormal Temperature None Dropped Assembly - Horizontal Negligible Dropped Assembly - Vertical Negligible Into Storage Cell Misloaded Assembly N/A Mislocated Assembly N/A 9.1-65 Amendment No. 26 (11/13)

TABLE 9.1-14 Calculated Peak SFP Bulk Temperature Results Component Allowable Fuel In-Core Cooling Water Discharge Rate Number of Coincident Thermal Hold Inlet Temperature From Reactor Operating SFPCS Heat Load Overshoot Time (hr) (°F) (assemblies/hr) Pumps (MBTU/hr) (°F) 90* 95 6 1 40.1 10.95 EC292529 110 100 6 1 38.1 10.54

  • This will conservatively support a time of 95 hours0.0011 days <br />0.0264 hours <br />1.570767e-4 weeks <br />3.61475e-5 months <br /> 9.1-66 Amendment No. 30 (05/20)

Table 9.1-15 Deleted 9.1-67 Amendment No. 21 (12/05)

TABLE 9.1-16 HEAT TRANSFER DATA FOR THE FUEL POOL HEAT EXCHANGER Number of Heat Exchangers: one Coolant Flowrate (CCW) 2850 gpm SFP Water Flowrate 2000 gpm (per pump)

Heat Transfer Surface Area 4106.83 sq. ft.

Overall Heat Transfer Coefficient 331.74 Btu/sq.ft-hr-°F (fouled, 5% tubes plugged, two pumps)

Cooling Water Inlet Temperature (CCW) 95°F or 100°F Heat Exchanger Temperature Effectiveness is calculated using the following formula.

Cooling Water (CCW) Outlet Cooling Water (CCW) Inlet P =

SFP Water Inlet Cooling Water (CCW) Inlet Calculated Heat Exchanger Temperature Effectiveness:

Coolant Water Single Pump Dual Pump Inlet Temperature Temperature Temperature

(°F) Effectiveness Effectiveness 95 0.393 0.467 100 0.395 0.469 9.1-68 Amendment No. 26 (11/13)

TABLE 9.1-17 Projected Offload Schedule End-of-Cycle Offload Date Number of Average Initial 235U Number (mm/dd/yyyy) Assemblies Burnup Enrichment (MWd/MTU) (wt.%)

1 10/20/2008 96 51700 3.50 2 04/20/2010 96 51700 3.50 3 10/20/2011 96 51700 3.50 4 04/20/2013 96 51700 3.50 5 10/20/2014 96 51700 3.50 6 04/20/2016 96 51700 3.50 7 10/20/2017 96 51700 3.50 8 04/20/2019 96 51700 3.50 9 10/20/2020 96 51700 3.50 10 04/20/2022 96 51700 3.50 11 10/20/2023 96 51700 3.50 12 04/20/2025 96 51700 3.50 13 10/20/2026 96 51700 3.50 14 04/20/2028 96 51700 3.50 15 10/20/2029 96 51700 3.50 16 04/20/2031 96 51700 3.50 17 10/20/2032 96 51700 3.50 1,632 total 9.1-69 Amendment No. 26 (11/13)

Tables 9.1-18 through 9.1-22 have been deleted.

Pages 9.1-71 through 9.1-74 have been deleted.

9.1-70 Amendment No. 21 (12/05)

TABLE 9.1-23 Loss of Cooling Time-to-Boil Calculation Results DELETED EC290004 9.1-75 Amendment No. 29 (10/18)

Table 9.1-24 Deleted 9.1-76 Amendment No. 21 (12/05)

TABLE 9.1-25 Local Temperature Analysis Results Parameter Value EC290004 Peak Local Water Temperature 197°F Peak Cladding Superheat 43°F EC290004 Peak Local Fuel Cladding Temperature 240°F 9.1-77 Amendment No. 29 (10/18)

Refer to drawing 8770-G-832 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FUEL HANDLING BLDG NEW FUEL STORAGE RACKS FIGURE 9.1-1 Amendment No. 15 (1/97)

Refer to Drawing 8770-11890 Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Layout Figure 9.1-2 Amendment No. 26 (11/13)

Refer to drawing 8770-G-078 Sheet 140 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM FUEL POOL SYSTEM FIGURE 9.1-3 Amendment No. 15 (1/97)

BASE PLATE 10.12' +/- .05" PITCH

"'Z"- "Z" UEL ASSEMBLY L. - 1-1/2" REF

"' J!fJy ~

\:

(TYP.)

P_Lf- SMOOTH I I I

!==~==!

f--,1 t-- - - -,j I I l-------1 f--L-1 POISON~ [__ I _j l--l=----1 I I I f==L=j F"Z" I l--~----1 I

t-- - ,

I "Z" 1 I 1 I

I 1 1" DIA l==~=d / F L O W HOLE I I I

- -- ~_I_J ,____ /BASE PLATE I I t 6" DIA. HOLE TYP.

  • Not credited for reactivity control in criticality analyses Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Storage Rack Typical Cell Elevation Region 1 Figure 9.1-4 Amendment No. 22 (05/07)

8.86"

  • [Z
1

r-:.

0

(/)

0 0...

I A~<;" I

~ (TYP .)

"'Z"- "Z"

.-... \

1-A "~

p~u I I I I

--~--:

r-- --: /PO

  • -t~

t--

I I

L-- --1 1--L-1

[__ ~_j L-- --1

r-- b--:::J:
  • 'Z'*v 1--

I 1--~-~

1--

I I 1" Z"

[!__ _ j: ~

~

'DIA LOW HOLE L-- --1

i  :

BASE PLATE l ---'---

s l

t UJ I t

." 6" DIA. HOLE TYP.

  • Not credited for reactivity control in criticality analyses Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Storage Rack Typical Cell Elevation Region 2 Amendment No. 21 (12/05)

DELETED Florida Power & Light Company St. Lucie Plant Unit 1 Figure 9.1-6 Amendment No. 21 (12/05)

Refer to Drawing 8770-339 Florida Power & Light Company St. Lucie Plant Unit 1 REACTOR REFUELING ARRANGEMENT Figure 9.1-7 Amendment No. 26 (11/13)

IF f'O U~I FOR CR,lo,N IIO(f

/ lJ PPER C.L..£V IS AS S:EMSL'(

FORM ICI

  • SUPPORT IBEAM (fOil' UP- PO:S. ITION

1 TON HOIST HOIST ASSEMBLY OPERATOR CONSOLE POWER CENTER BRIDGE DRI TROLLEY DRIVE FUEL HOIST ASSEMBLY FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REFUELING MACHINE FIGURE 9.1-9 Amendment No. 23 (11/03)

FIGURE FOR CEA CHANGE MECHANISM INTENTIONALLY DELETED Amendment No. 14, (6/95)

FLORIDA CEA Change Mechanism Figure POWER & LIGHT CO. 9.1-10 St. Lucie Plant

COLUMN AS~ BtV Fl ORIDA POW EA. & li.IGHT CO. Rl[t3ct r ve~*se l Head l lHlng Rlg 9. 1* 1.1

~ ** - ~* h l';l.jJ;U

Refer to Drawing 8770-6506 Florida Power & Light Company St. Lucie Plant Unit 1 CORE SUPPORT BARREL LIFTING RIG Figure 9.1-12 Amendment No. 26 (11/13)

REFER TO DRAWING 8770-7060 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 SURVEILLANCE CAPSULE RETRIEVAL TOOL ASSEMBLY FIGURE 9.1-13 Amendment No. 22 (05/07)

REFER TO DRAWINGS 8770-12962 & 8770-12964 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PERMANENT REACTOR CAVITY SEAL/SHIELD RING GENERAL ASSEMBLY FIGURE 9.1-14 Amendment No. 16 (1/98)

This figure has been deleted FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-15 Amendment No. 21 (12/05)

This figure has been deleted.

AMENDMENT NO. 20 (4/04)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-15A

This figure has been deleted.

AMENDMENT NO. 20 (4/04)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-158

This figure has been deleted FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-16 Amendment No. 21 (12/05)

Refer to drawing 8770-G-826 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FUEL HANDLING BLDG STEEL FRAMING SH-1 FIGURE 9.1-17 Amendment No. 15 (1/97)

Refer to drawing 8770-G-826 Sheet 2 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FUEL HANDLING BLDG STEEL FRAMING SH-2 FIGURE 9.1-18 Amendment No. 15 (1/97)

DELETED Florida Power & Light Company St. Lucie Plant Unit 1 Figure 9.1-19 Amendment No. 21 (12/05)

This figure has been deleted.

AMENDMENT NO. 20 (4/04)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-20

This figure has been deleted.

AMENDMENT NO. 20 (4/04)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-21

4 Fresh Assemblies (all separated by at least one empty cell, closest approach)

--it- -c-- -H- -L-- r--H- --l-- -H- --l- -H- -i-

~ H L H L H L H L 1ft

~ L H L H L H L H ~

~ H ~ H ~ H L H L ~I

~ X F X F X H L H ~

L H ~ H ~ H L H L ~

~ X F IX F X H L H ~

~ H X HX H L H L ~

~ L H L H L H L H ~

-t--K- *t*- rt* f-*t*- """H""" -*t* -~ -t* -~~-

I I I High Reactivity Low Reactivity Fresh Assembly I Rod Basket Empty Cell

Reflective Boundary Condition Florida Power & Light Company St. Lucie Plant Unit 1 Schematic Configuration of the Calculational Model for Fresh Assemblies in Region 2 Racks for Inspection and Reconstitution Fi ure 9.1-22a Amendment No. 21 (12/05)

4 Fresh Assemblies (all separated by at least one empty cell)

--it- -c-- -H- --L-- r--H- --l-- -H- --l- -H- -i-

~ H L H L H L H L ~

~ L H L H L H L H ~

~ H X H X H L H L ~I

~ X F IX F X H L H ~

L H X H X H L H L ~

~ X F IX F X H L H li-

~ H X H X H L H L ~

~ L H L H L H L H ~

  • t-I

-K- *t---a- 1-*t*- """H""" -*t* -~ -t* -~~-

I I

High Reactivity Low Reactivity Fresh Assembly I Rod Basket Empty Cell

Reflective Boundary Condition Florida Power & Light Company St. Lucie Plant Unit 1 Schematic Configuration of the Calculational Model for Fresh Assemblies in Region 2 Racks for Inspection and Reconstitution Figure 9 .1-22b Amendment No. 21 (12/05)

Fuel Type 1 40 35 ~

30 I

...... 25 v

I Iv E

-a

~

\..:J ci.

J E
J 20 co E

/

J E

r:::

~

v 15 10 5 II + Fuel Type 1

- - Fit Fuel Type 1 0

1.5 '2.0 2.5 2.0 3.5 Enrichment, wto/o 4.0 4.5 5.0 Florida Power & Light Company St. Lucie Plant Unit 1 Minimum Burnup as a Function of Initial Enrichment for Fuel Type 1 Stored in Region 1 Figure 9 .1-23a Amendment No. 26 (11/13)

Fuel Type 2 25 20

=>

j

+-'

E 15

" '0

\.!)

a.

1 c:
1 co E
1 E
  • c: 10 J

~

5

  • Fuel Type 2

- - Fit Fuel Type 2 0

1.5 2.0 2.5 2.0 3.5 4.0 4.5 5.0 Enrichment, wto/o Florida Power & Light Company St. Lucie Plant Unit 1 Minimum Burnup as a Function of Initial Enrichment for Fuel Type 2 Stored in Region 1 Figure 9 .1-23b Amendment No. 26 (11/13)

Fuel Type 3 40 f

/

I 35 I

v 30 I

)

+-' 25 E

-a 5\.!:)

c:

J E 20
J co E
J E

c

~

15 If 10 I Fuel Type 3 5

- - Fit Fuel Type 3 0

1.5 2.0 2.5 2.0 3.5 4.0 4.5 5.0 Enrichment, wto/o Florida Power & Light Company St. Lucie Plant Unit 1 Minimum Burnup as a Function of Initial Enrichment for Fuel Type 3, Stored in Region 2*

Figure 9.1-23c Amendment No. 26 (11/13)

Fuel Type 4 50 45 40 35 E 30 s\..9

""'0 c:i

1 c:

...... 25

1 c:c E Fuel Type 4, 0 years
1 E Fuel Type 4, 2.5 years c: 20

~ Fuel Type 4, 5 years X Fuel Type 4, 10 years 15 + Fuel Type 4, 15 years 0 Fuel Type 4, 20 years Fit 0 years 10 Fit 2.5 years Fit 5 years 5 Fit 10 years Fit 15 years Fit 20 years 0

1.5 2.0 2.5 2.0 3.5 4.0 4.5 5.0 Enrichment, wto/o Florida Power & Light Company St. Lucie Plant Unit 1 Minimum Burnup as a Function of Initial Enrichment for Fuel Type 4, Parametric in Post-Irradiation Cooling Time, Stored in Region 2 Fi ure 9.1-23d Amendment No. 26 (11/13)

Fuel Type 5 60 50 40 E

" '0 3:

\.9 ci

J c..... 30
J co E Fuel Type 5, 0 years
J E Fuel Type 5, 2.5 years c

~ Fuel Type 5, 5 years 20 X Fuel Type 5, 10 years

+ Fuel Type 5, 15 years 0 Fuel Type 5, 20 years Fit 0 years Fit 2.5 years 10 Fit 5 years Fit 10 years Fit 15 years Fit 20 years 0

1.5 2.0 2.5 2.0 3.5 4.0 4.5 5.0 Enrichment, wt%

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

Florida Power & Light Company St. Lucie Plant Unit 1 Minimum Burnup as a Function of Initial Enrichment for Fuel Type 5, Parametric in Post-Irradiation Cooling Time, Stored in Region 2 Figure 9 .1-23e Amendment No. 26 (11/13)

8.65" +/-0.032" Box I.D.

BORAFLEX*

7.50" +/- 1/16" I l

0.075" +/-0.007" Thick ct_ of Water Gaps r I 00000000000000 00000000000000 oooooooooooo 00 000000 00 00000000000000 00000000000000 ~ 0.020" +/- 0.003" ooooooooooooo Outer SS 000000 000000 00000000000000 00000000000000 oooooooooooo 00 000000 00 1.120"+/-0.040" Water Gap 00000000000000 I

00000000000000 ir:=::::::::JI 1 0.080" Thick 0.080" +/- 0.005" Gap Channel Inner SS Box

  • May be present. Not relied on for reactivity control in criticality analyses.

Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Storage Rack Region 1 Storage Cell Geometry Figure 9.1-24 Amendment No. 21 (12/05)

Lattice Spacing 8.86".:!: 0.040"

.... 8.65".:!: 0.032" Box I.D.

.... BORAFLEX*

7-1/4"+/- 1/16" f - ctof 0.031" +/- 0.007" Thick BORAFLEX

+

00000000000000 00000000000000 oooooooooooo 00 000000 00 00000000000000 00000000000000 ooooooooooooo 000000 000000 00000000000000 00000000000000 oooooooooooo 00 000000 00 00000000000000 00000000000000 0.080" t 0.005" Inner SS Box r* May be present. Not relied on for reactivity control in criticality analyses. I Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Storage Rack Region 2 Storage Cell Geometry Figure 9.1-25 Amendment No. 21 (12/05)

+ .05" GIRDLE BAR

\

10.12 PITCH

-- ---1/,- ... \ ;-

r'

---,,,-*\;--i I .of .

-,,(1 I \

1='--=-==1

. ~I R,--- --v~'v-- -~-\il I .}I

.... .I.. ~

! I I

- I r-- r-- r-- I- r--

I I I I I I i I

~--t-*~ *-t-- 1--*~ ~J-I I 1-,_J_.~,__ L- j -- --

I

-L'- - --

I

..__~....~ __

- 169" n*--L- -- ,--,--,. -- --rt ---r- --r- -- ~- -'-,

I I I CD I

()

I

_(D CD ()

I I I J. : I l -f-I J I I Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Storage Rack Typical Rack Elevation Region 1 Figure 9.1-26 Amendment No. 22 (05/07)

-+ 04" GIRDLE BAR 8.86" PITCH

~ *- .a *-.. ~

' ~

\

I

~ I I

I I

I I

l I I I r ./ I i I I  ! I I I

I I

.. i**- -* i__\. ___ i'. . -t- --* i..

~-~--""T* ,...-~- ,.. --~ ----~-- *-~--.:f--~ ..

J. i_

--r--*

~ 169' I I I I I

I I I

I  ! i I  : _i I I I I I

J I

j I 1- -

Florida Power & Light Company St. Lucie Plant Unit 1 Spent Fuel Pool Storage Rack Typical Rack Elevation Region 2 Figure 9.1-27 Amendment No. 22 (05/07)

Bora I 7.25"Wide

~

~////////////////////

...1 Vi'

///////////////////// / L

~::z~ IL<  ::::zv v

v

~ v

~ v

~ v

~ v

~ v

~ v

~ CeiiiD v

~ Water Gap v

~

8.58" v

v v

~ v

~ Cell Wall Thickness v v

~/

~

0.075" v

v 7~ IT "7~

////////////////////// 7 r ////////////////////~

J1

~

Center to Center Spacing (Pitch) 10.30" Florida Power & Light Company St. Lucie Plant Unit 1 Cask Pit Rack Typical Region 1 Storage Cell Geometry Figure 9.1-28 Amendment No. 21 (12/05)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-29a Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-29b Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-29c Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-29d Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-30a Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-30b Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-30c Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-30d Amendment No. 29 (10/18)

DELETED EC290004 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.1-31 Amendment No. 29 (10/18)

r--

,r- -

I CONNECTOR ELEMENT \

~

PRECISION I

FORMED SHEATHING

\

I

\OlSON BOX I.D.

I (CLOSELY CONTROLLED)

~

~ (

\

) _")

LAYOUT PITCH p Florida Power & Light Company St. Lucie Plant Unit 1 Cask Pit Rack Typical Cask Pit Rack Storage Cell Layout Amendment No. 21 (12/05)

I j I

f I 1 _

~-...//

Jr~i r

'--..:_'6.:'1 -

l "X" L---t----1 L-------1 I II I r--l--:

I I I I 1-------~ /BORAL 1----L __ _j

~--l--1 l____ f l --~

1---- -----,

I I I

OUTER/

SHEATHING f===~===i I I I "X"-"X" L---F---1 L---

I

---1 I I I

~===~==d INNER

~--J __ j I I I ------SHEATHING

,---t----1 I l I FLOW HOLE (AUXILIARY)

L~ -- J++---R----* ---1+--~-

I I""

~~ ~I I

~---~lr-1~~----~1-+1~1_ _ _~1- BASEPLATE BASEPLATE HOLE

\

Florida Power & Light Company St. Lucie Plant Unit 1 Cask Pit Rack Elevation View Cask Pit Rack Storage Cells Figure 9.1-33 Amendment No. 21 (12/05)

9.2 WATER SYSTEMS 9.2.1 INTAKE COOLING WATER SYSTEM 9.2.1.1 Design Bases The intake cooling water system is designed to:

a) provide a heat sink for the component cooling, turbine cooling, and steam generator open blowdown cooling systems under normal operating and shutdown conditions b) provide a heat sink for the component cooling system under safe shutdown or LOCA conditions, assuming a single active component failure c) withstand design basis earthquake loads, tornado loads or maximum flood levels without loss of safety function d) permit periodic inspection and testing of equipment to assure system integrity and capability 9.2.1.2 System Description The intake cooling water system is shown in Figures 9.2-1 through 1E. The system consists of three pumps and associated piping and valves. The system removes heat from the component cooling heat exchangers, the turbine cooling heat exchangers, and the steam generator open blowdown heat exchangers and discharges it to the condenser discharge canal. Intake cooling water from the intake structure flows through basket strainers located at the inlets of the component cooling, turbine cooling and steam generator open blowdown heat exchangers, passes through the tube side of the exchangers, and flows to the discharge canal.

The strainers on the inlet of the component cooling water heat exchangers backwash automatically on a timer and on a differential pressure signal across the strainers. The debris passes through a fail-closed air operated discharge valve and re-enters the ICW discharge piping downstream of the restricting orifices. Automatic backwashing is not a safety-related function. During a design basis accident (DBA), the debris discharge valve is closed by de-energizing the solenoid valve via a SIAS trip to prevent flow diversion past the heat exchanger. No credit is taken for de-energizing the CCW Heat Exchanger inlet strainer control panel, which also results in closure of the debris discharge valve (See Section 8.3.1.1.4). As with the original manually backwashed strainers, the full flow bypass can be utilized to maintain flow to the CCW heat exchangers in the event of strainer clogging during a DBA.

The intake cooling water system is divided into two redundant supply header systems designated A and B. Both header systems, each aligned with an intake cooling water pump, supply normal plant operating and shutdown requirements. However, during accident conditions, one pump and header is adequate to supply the required cooling water to one component cooling heat exchanger. The turbine cooling water and open blowdown heat exchangers are supplied by nonessential headers which are automatically isolated on SIAS by valves I-MV 21-2 and 21-3. These valve operators are part of the ESFAS equipment and function according to the description in Section 7.3.1.1.3, which under local reopening after a postulated accident would produce an alarm and valve open indication in the control room. Under administrative control and procedures the control room operator would reclose the valves from the control room in such a case.

In the event that either pump 1A or 1B fails, intake cooling pump 1C may be aligned with either header A or B by positioning of the pump discharge header cross connect valve. Pump 1C has only manual (non-motor-operated) valves in the discharge header. A proper valve alignment is assured by a Technical Specification requirement.

9.2-1 Amendment No. 21 (12/05)

System design data are presented in Table 9.2-1. A description of the intake and discharge structures is given in Section 9.2.3.

Similar to the issues discussed in NRC Generic Letter 2008-01 and SER 2-05, the presence of unanticipated gas voids within the Intake Cooling Water System can challenge the ability of the system to perform its design functions due to issues such as gas binding, water hammer, injection delay times, etc. The ICW system presents little to no opportunity for gas intrusion or air entrainment.

Operating experience shows that the fill, vent, and surveillance operations procedures for the ICW system are adequate to assure acceptable system performance following maintenance or operational activities that could result in gas void formation.

9.2.1.3 System Evaluation 9.2.1.3.1 Performance Requirements and Capabilities The intake cooling water system is designed to supply sufficient cooling water to the component cooling heat exchangers to fulfill emergency requirements in the event of the design basis LOCA.

Each essential header, with one intake cooling water pump operating, fulfills the requirements of one component cooling heat exchanger during normal, shutdown, and LOCA conditions.

The intake cooling water system is sized to ensure adequate heat removal with a design seawater temperature of 95°F at plant rated power.

The design bases and actuator capabilities for MV-21-02 and 03 have been Generic Letter 89-10, "Safety Related Motor Operated Valve Testing and Surveillance," as noted in Section 3.9.2.4 9.2.1.3.2 Single Failure Analysis Only one intake cooling water pump and one essential header are required to remove the post-accident heat load from one component cooling heat exchanger. Each component cooling heat exchanger is capable of post-accident heat removal duty (Section 9.2.1.3.1). Two redundant full capacity essential headers and three full capacity pumps are provided, one pump and one header for each component cooling heat exchanger to assure adequate cooling capability if one system fails.

The third pump can be connected to either heat exchanger. Electrical power for each header system is supplied from a separate emergency power bus such that no single electrical failure can prevent operation of both header systems.

The redundant essential headers are isolated from each other during emergency conditions by two valves (SB21190 and SB21237) in the tie line connecting the headers. Each essential header is isolated from the nonessential portion of the system by a valve which closes automatically on SIAS.

Each header isolation valve receives a signal from a separate SIAS channel, hence, no single failure can cause both valves to remain open. A single failure analysis of the intake cooling water system is presented in Table 9.2-2.

UNIT 1 9.2-2 Amendment No. 28 (05/17)

With reference to Figure 9.2-1 and 9.2-1a, the separation of seismic Category I and II portions of the Circulating and Intake Water Systems is accomplished by two valves in series.

Since two 100 percent intake cooling water systems are provided, only one remotely operated valve is required. Refer to Table 9.2-2, Single Failure Analysis-Intake Cooling Water System wherein the above postulated single failure is discussed. Since the intake cooling water systems are redundant 100 percent systems, only one intake cooling water pump and header is needed to supply the required cooling water to one component cooling heat exchanger. The valves type I-SB-21-7 (the same type that isolates the third pump from the A and B headers) are manual valves. Complete isolation from this turbine cooling water heat exchanger, or alignment of the third pump, is a manual operation. However, this action is not required to assure adequate cooling water to the component cooling water heat exchanger.

9.2.1.3.3 Service Environment The intake cooling water pumps and valves are located outdoors and are designed to operate under the following environmental conditions: ambient temperature from 30°F to 120°F, 100 percent humidity, salt laden atmosphere, torrential rains and hurricane winds.

The intake cooling water system pumps and valves, which had been specified in their respective purchase specifications as being suitable for outdoor service, had been installed in place for approximately two years prior to operation. Thus, the preoperational testing for these components demonstrated the adequacy of pump and valve operations after about two years exposure to the environmental conditions specified above. Although it was felt that this exposure prior to commercial operation provided adequate assurance of operability, the Unit 1 motors and valves were operated while being sprayed with a fire hose as part of the Unit 1 preoperational test program.

A hypochlorite solution or alternate biocide is injected into the seawater upstream of the intake EC291588 cooling water pumps to control biofouling. The solution enters the circulating water and intake cooling water system in regulated quantities such that the residual chlorine in the discharge canal will not exceed the limits defined in applicable plant permits. The intake structure concrete walls below the waterline for wells 1A1, 1B1 and 2B2 were coated with a coating system of Devoe Devran 140 and Kansai Biox and the steel surfaces were coated with Amerlock 400 and Kansai Biox to reduce marine macro fouling. The pumps in the intake cooling water system have cathodic protection against corrosion and the system is protected by sacrificial anodes located in the turbine and component cooling water heat exchangers. In addition, zinc ribbon sacrificial anodes have been installed inside the ICW discharge piping from the CCW building to the discharge canal. The anodes were added to provide corrosion protection of the portion of the ICW piping that has an internal epoxy based coating system.

The intake cooling system is designed to withstand the corrosive effect of the seawater circulated.

The materials used in the system are compatible with each other.

A proposed recirculation canal was originally considered to limit marine growth in the intake structure.

The recirculation canal was never constructed, however Figure 9.2-1d shows piping tee connections on the intake piping which have been plugged, and Figure 9.2-1e shows proposed recirculation details at the discharge canal. A full description of the proposal can be found in the July 6, 1972 Amendment to the Environmental Report.

9.2-3 Amendment No. 30 (05/20)

9.2.1.3.4 Natural Phenomena The essential components of the Intake Cooling Water System, i.e., those supplying cooling water to the component cooling heat exchangers, are designed and installed as seismic Class I equipment.

That portion of the system supplying cooling water to the turbine cooling water and steam generator open blowdown systems is non-seismic downstream of the isolation valves. The seismic Class I and non-seismic portions of the system are automatically isolated from each other on SIAS. The intake cooling water pumps are located on the intake structure which is designed as seismic Class I. All underground piping is located in seismic Class I fill areas. Seismic qualification of system components is demonstrated by manufacturer calculations based on the design basis earthquake accelerations. Discussion of seismic qualification of equipment is given in Section 3.7.5.

The equipment of the intake cooling water system is located outdoors. Accordingly, the essential portions of the system are designed to withstand design basis tornado winds of 360 mph and PMH winds of 194 mph. Atmospheric depression resulting from these winds is 3.0 psi and 1.5 psi, respectively. The intake structure housing these pumps is designed as seismic Class I and can withstand the effects of winds and wave action resulting from the PMH tornadoes.

An evaluation of the capability of outdoor components to accommodate tornadic debris is provided as Appendix 3F.

Engineering Safety Evaluation, JPN-PSL-SENS-91-023, was prepared to allow the temporary removal of ICW pump missile shielding for maintenance activities on the ICW pumps and motors.

The manually operated intake cooling water header valves are not affected by hurricane-induced sprays. Isolation valves I-MV-21-2 and 3 are powered by motor operators with weatherproof enclosures and are thus suitable for outdoor service. The valves are located in the valve pit adjacent to the pump structure to protect them from water spray. The valve and motor pit structure is designed for tornado wind loading.

Protection is provided from missiles by imposing the following spatial separation criteria on redundant components located outdoors:

The original criteria used for missile protection design relative to spatial separation of piping described below in (a) and (b) is considered Historical. Subsequent spatial separation requirements are detailed in Section 6.2 of Appendix 3F.

a) Minimum separation for piping up to a height of 25 ft above yard grade is controlled by the dimensions of an airborne car weighing 4000 lb, 18 ft long, 7 ft wide, travelling at 50 mph; for piping at elevation higher than 25 ft above yard grade, minimum separation is controlled by a 2 in. by 4 in. timber, 10 ft long, travelling at 360 mph; and 9.2-4 Amendment No. 18, (04/01)

b) Underground piping minimum separation is 8.7 feet, dictated by tornado missiles. A minimum of 6 feet of earth or equivalent concrete cover is provided for protection from the airborne car.

The intake cooling water pumps are physically separated and provided with tornado missile shielding, so that the design basis missile will not preclude the availability of one pump which is the minimum requirement for safe shutdown. The physical separation of the pump power supply is consistent with the pump physical separation.

To ensure pump operation under flood conditions, the pump motors are flood protected to elevation 22.8 feet which is above the maximum calculated flood level. The pump suction columns require 4 feet of minimum submergence to deliver the design capacity of the pumps. This requirement is met under the minimum water level conditions associated with the maximum probable hurricane postulated for the site as discussed in Section 2.4.11.3.

It is conceivable that the DBE could induce soil liquefaction which in turn could result in suspended materials in the intake canal being drawn into the ICW system. A study of the soil liquefaction potential of slopes that could affect the intake structure area has been conducted. The analysis is provided as Appendix 2G. It demonstrates that with 10 cycles of strong motion associated with the DBE massive flow slides or liquefaction will not occur. There is a potential for straining or sloughing of submerged canal slopes of one to two feet. With cycles of strong motion appropriate for Florida, i.e., 2 to 3 cycles, the movements would be an inch or so. The potential sloughing or straining conditions are very local and would not induce suspension of sandy materials or even high turbidity.

Even though liquefaction will not cause suspension of sediment, an analysis was conducted to investigate the capability of the design in this regard. Section 2.5.5 discusses the analysis of sediment transport in channels. The bed load (rolling or sliding along the surface) was studied based on seive analysis data representative of the top 30 feet of onsite materials and a canal cross section representative of the canal after liquefaction. It was found that the bed load was negligible, i.e.,

basically no materials are moved by the low velocities associated with ICW pump operation.

Transport of suspended sands was also studied (see Section 2.5.5). Once liquefaction has occurred particles with grain size less than 0.075 mm can be expected to reach the ICW pumps. This corresponds to the suspended particle size encountered during normal operation. The ICW pumps can pump particle sizes up to 1/2 inch (12.7 mm), thus pumps availability would not be adversely affected by suspended materials. The consequences of liquefaction with regard to suspended materials are no more severe than normal operating conditions, hence CCW heat exchanger capability would not be adversely affected. These heat exchangers are capable of handling the full post-LOCA heat load with a 50 percent cleanliness factor. If it is assumed that the ICW system flow contains suspended materials due to liquefaction, the following comments regarding these heat exchangers would be appropriate:

9.2-5 Amendment No. 25 (04/12)

i) Figure 6.2-1C shows the maximum post-LOCA CCW temperature occurs at approximately 35 seconds with a second (lower) peak at approximately 10,000 seconds.

ii) ICW pump operation does not result in velocities that would maintain silt in suspension, thus any materials placed in suspension in the intake canal would settle out quickly. A small amount could conceivably enter the ICW system.

iii) The heat removal capability of a water/silt composition is less than water. However, the reduction in heat transfer is not expected to be more than 7 to 10 percent.

iv) High water velocities will scour silt from the tubes. Some accumulation in the water boxes would be expected, but blockage of tubes is unlikely due to the scouring effect.

Based on the preceding, it is highly unlikely that silt placed in suspension by liquefaction could significantly affect the heat transfer capability of the CCW heat exchangers.

From the above it can be concluded that the DBE will not result in an abnormally high concentration of suspended silt or sand and that suspended materials would be essentially those encountered during normal operation. This notwithstanding, if suspended materials are assumed, it is very unlikely that the ICW system performance would be unacceptably affected. Thus with regard to suspended materials, the design of the ICW system is acceptable.

9.2.1.4 Testing and Inspections The manufacturer of the intake cooling water pumps shop tested each unit over the complete range of hydraulic performance at no less than five head capacity points including the design points to measure capacity, head, power input, efficiency, and runout conditions. All fluid boundary castings and forgings were nondestructive tested in accordance with ASME Section III, Code Class 3.

Prior to installation in the system, each component was inspected and cleaned. The Preoperational testing consisted of calibrating the instruments, testing the automatic controls for actuation at the prescribed set points, and checking the operability and limits of alarm functions.

The intake cooling water system is in service during normal plant operation. System performance is monitored and data is taken periodically to confirm-heat transfer capabilities.

9.2-6 Amendment No. 26 (11/13)

The operability of the intake cooling water pumps is demonstrated in accordance with plant procedures so that their continued availability for emergency conditions is ensured.

By letter L-90-28 dated 01-25-90, FPL provided the response to the recommendations of Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The generic letter requested licensees to establish a routine inspection and maintenance program to ensure that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of the safety-related systems supplied by service water. In letter L-2000-215, FPL committed to having routine single train inspection intervals every refueling outage for the intake well and safety-related ICW piping.

9.2.1.5 Instrumentation Application Table 9.2-3 lists the parameters measured by the intake cooling water system instrumentation. The heat exchanger parameters and pump status are monitored either locally or in the control room. In every case where safety-related equipment is involved, more than one parameter is measured to assure design performance of the equipment.

The intake cooling water pumps can be started or stopped either at the switchgear or from the control room. The pumps receive a start signal upon SIAS.

The logic and instrumentation for this system is discussed in Section 7.3.1.3.2.

All valves in the system are manually operated with five exceptions. The turbine cooling water and steam generator open blowdown systems are automatically valved off of the intake cooling water on receipt of an SIAS. This operation can also be initiated either locally or in the control room. The second automatic valve in the system is the butterfly valve (one in each header) at the outlet of the component cooling water heat exchanger. This valve automatically controls outlet water flow from the exchanger. It is modulated opened and closed according to the outlet water temperature of the shell side of the component cooling water heat exchanger. The normal position for this valve is automatic except when under Operations administrative control to perform testing. In addition, valve closure is limited to 7.2 degrees from full closed position to prevent turbulent flow and system damage. The third valve is located at the outlet of the turbine cooling water heat exchangers. This valve is temperature controlled from the shell outlet side of the heat exchanger and controls intake cooling water flow. The fourth valve is located at the outlet of the steam generator open blowdown heat exchangers. This valve is temperature controlled from the shell outlet side of the heat exchanger and controls intake cooling water flow. The fifth valve is located in the 6 inch debris discharge line for the CCW heat exchanger strainers. This valve is timer and differential pressure controlled via a Programmable Logic Controller (PLC) located in the strainer control panel.

9.2-7 Amendment No. 21 (12/05)

9.2.2 COMPONENT COOLING WATER SYSTEM 9.2.2.1 Design Bases The component cooling water system is designed to:

a) provide a heat sink for auxiliary systems under normal operating and shutdown conditions; b) provide an intermediate barrier between the reactor coolant and the intake cooling water systems; c) provide a heat sink for safety related components associated with reactor decay heat removal for safe shutdown or LOCA conditions, assuming a single failure; d) withstand design basis earthquake loads, tornado loads or maximum flood levels without loss of safety function; and e) permit periodic inspection and testing of components to assure system integrity and capability.

9.2.2.2 System Description The component cooling water system is a closed loop cooling water system that utilizes demineralized water and a corrosion inhibitor to cool various components as shown schematically in Figure 9.2-2. The component cooling water system consists of two heat exchangers, three pumps, one surge tank, a chemical addition tank, and associated piping, valves and instrumentation.

The component cooling water system is arranged as two redundant essential supply header systems (designated A and B) each with a pump and heat exchanger and the capability to supply the minimum safety feature requirements during plant shutdown or LOCA conditions. The nonessential supply header (designated N), which is connected to both essential headers during normal operation, is automatically isolated from both by valve closure on a safety injection actuation signal (SIAS). During normal operation, the nonessential header supplies cooling water to the following components: fuel pool heat exchanger, sample heat exchangers, waste gas compressors, letdown heat exchanger, control element drive mechanism air coolers, reactor coolant pump motors, reactor coolant pump seals, and steam generator blowdown sampling panel.

The A and B headers serve the following components:

Header A Header B Shutdown heat exchanger 1A Shutdown heat exchanger 1B Containment fan cooler 1A Containment fan cooler 1C Containment fan cooler 1B Containment fan cooler 1D Low pressure safety injection Low pressure safety injection pump 1A pump 1B High pressure safety injection High pressure safety injection pump 1A pump 1B Containment spray pump 1A Containment spray pump 1B UNIT 1 9.2-8 Amendment No. 28 (05/17)

High pressure safety injection pump 1C is supplied by header B, however, the pump is no longer used and CCW is isolated to the pump.

The A and B header systems are isolated from each other during accident conditions. Pump 1A serves header A and Pump 1B serves header B. Pump 1C may be aligned with either header A or B by means of the cross connection valving on the suction and discharge side of the pumps and any misalignment between the component cooling water pump C motor power and the pump's motor valves will be annunciated in the Control Room. Figure 9.2-2A shows the valve arrangement for pumps.

Both the A and the B supply header systems pump demineralized cooling water through the shell side of their respective component cooling heat exchangers, through the components being cooled and back to their respective pumps. The surge tank is connected to the suction side of the pumps and is designed to accommodate volumetric thermal expansion and contraction in the system and to maintain a static pressure head at each pump suction. Demineralized makeup water is added to the surge tank through an automatic level control system by the demineralized water pump. Provisions are also made to supply makeup from the fire protection system. Although both essential headers share the surge tank, a baffle divides the lower portion of the tank into two separate compartments, each associated with one of the two essential headers. The cylindrical tank is 11 feet long and is mounted horizontally. It has a 5.5 foot diameter with a baffle height of 2.5 feet. Makeup water is added when the level falls below 36 inches and a low level alarm is initiated in the control room at 29 inches. Makeup water is stopped at a surge tank level of 48 inches and a high level alarm is initiated in the control room at 54 inches. Level indication on the tank is provided on each side of the baffle.

There is also a level gauge mounted on each side of the tank for local indication of tank level.

Leakage of reactor coolant into the component cooling water system can be detected by an increasing level in the surge tank and/or increasing radiation levels in the CCW return headers. A 1 gpm leak into the tank causes a high level alarm in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (based on an initial tank level of 40 inches in the 66 inch diameter horizontal tank). Section 5.2.4 gives a description of leak detection by surge tank level and by radiation in the component cooling water system. Any overflow or drainage from the component cooling surge tank is collected by the auxiliary building drain system and routed to the chemical drain tank. The material in this tank is treated by the waste management system as described in Section 11.2.2.2.

9.2-9 Amendment No. 25 (04/12)

A chemical additive tank in the system permits addition of a corrosion inhibitor. A radiation monitor is provided in each of the redundant headers on the outlet side of the heat exchangers. Prior to the activity in the system exceeding a predetermined setpoint, not to exceed 4 x 10-4 Ci/cc, a high radiation alarm is actuated in the control room and the surge tank vent is automatically diverted from atmosphere to the waste management system.

The valves used in the component cooling system are carbon steel and although the cooling water is not radioactive, welded construction is used, where possible, to minimize the possibility of leakage.

Self-actuated spring-loaded relief valves are provided for overpressure protection on the shutdown, sample, and letdown heat exchanger inlets as well as on the containment cooling units and waste gas compressors. All component cooling system piping is carbon steel.

Design data for component cooling water system components are tabulated in Table 9.2-4.

9.2.2.3 System Evaluation 9.2.2.3.1 Performance Requirements and Capabilities The component cooling water system is capable of providing sufficient cooling capacity to cool reactor coolant system and auxiliary systems components with two pumps and one heat exchanger in operation, although, during normal operation, flow is established through both heat exchangers. Two pumps and two heat exchangers are used during normal plant shutdown; however, if only one heat exchanger is available, the cooldown rate is decreased but plant safety is not jeopardized. Table 9.2-5 lists operating flow rates and calculated heat loads for all the auxiliary equipment cooled by the component cooling system.

Safety related equipment cooling requirements are met following a postulated LOCA with only one pump and one heat exchanger operating, even though both essential header systems are normally available.

The component cooling pumps are connected to separate emergency electrical buses (see Figure 8.3-2) which can be energized by the diesel generators. The A and B pumps are connected to the respective A or B emergency bus counterparts and the third pump is connected to the AB bus which is remote manually connected from the control room to either the A or B emergency bus.

The component cooling water system is arranged as two redundant essential supply header systems (designated A and B) each with a pump and heat exchanger and the capability to supply the minimum safety feature requirements during safe shutdown or loss of coolant accident (LOCA) conditions. The non-essential supply header (designated N") which is connected to both essential headers during normal operation and is automatically isolated from both by valve closure on a safety injection actuation signal (SIAS). EC289398 The essential headers are classified as Quality Group C while the non-essential header is classified as Quality Group D. Portions of the system supporting reactor containment boundaries are classified as Quality Group B. Section 6.2.2.2.2 addresses the quality group for the closed loop piping within containment for supply of cooling water to the containment fan coolers.

UNIT 1 9.2-10 Amendment No. 29 (10/18)

The component cooling water (CCW) to the reactor coolant pumps, and letdown heat exchangers is designed as a non-seismic (Seismic II/I), non-safety class system. Therefore, failure of this system will not adversely affect the ability to achieve an orderly cold shutdown. The propriety of the design with regard to the RCP's is discussed below and with regard to the letdown heat exchangers is responded to in Section 9.3.4.3.1. The safety consideration is that loss of CCW could result in overheating and a locked pump rotor, thereby negating the benefit derived from coastdown (about 10 seconds) during a postulated loss-of-flow incident. Simultaneous mechanical failure, e.g., shaft seizure, is not considered credible. The results of the loss-of-flow incident (Section 15.2.5) indicates the DNBR does not fall below the safety limit, and for the locked rotor incident (Section 15.3.4) less than 1 percent of the fuel experiences DNBR less than the safety limit. For these events the plant is tripped automatically on low reactor coolant flow. Thus, for these incidents there will be no offsite consequences.

The design has accommodated the potential for loss of CCW to the reactor coolant pumps in two ways, viz., (1) the pumps and motors have inherent capability to accommodate interruption of cooling water, and (2) diverse and redundant intelligence has been provided to the operator. The pump manufacturer recommends that the pump is not operated without pump heat exchanger cooling water for more than 10 minutes.

Should CCW be lost to a pump the operator will have the following reactor coolant pump intelligence for each pump (see Figure 5.5-7);

a) Pump seal heat exchanger temperature indication and alarm b) Motor upper guide bearing temperature indication c) Motor lower guide bearing temperature indication d) Motor thrust bearing upper temperature indication and alarm e) Motor thrust bearing lower temperature indication and alarm f) Pump seal controlled bleed off temperature indication.

In addition, CCW low flow annunciation is provided for the flow from each reactor coolant pump (see Figure 9.2-2). Reactor Coolant Pump alarms and indication are shown on a Distributed Control System (DCS) driven flat panel display located on RTGB-103. From the above it is concluded that sufficient time is available and adequate intelligence for the operator to trip the unit to prevent damage to the reactor coolant pumps due to loss of CCW.

UNIT 1 9.2-11 Amendment No. 28 (05/17)

The St. Lucie design precludes damage from loss of CCW due to an inadvertent containment isolation signal since the CCW isolation valves only auto close on a safety injection actuation signal (SIAS). A SIAS also automatically trips the reactor, where the loss of RCPs is acceptable as core heat removal is accomplished by natural circulation.

9.2-12 Amendment No. 17 (10/99)

The Staff in its Safety Evaluation Report of November 8, 1974 at Section 3.2 states:

"We do not agree with the applicant's Quality Group D classification for the cooling lines to:

(1) the reactor coolant pumps, and (2) the secondary side of the letdown heat exchanger of the chemical and volume control system. In order to provide a level of quality consistent with current Commission requirements for cooling water systems, we will require the applicant to provide additional nondestructive testing equivalent to that in Section III, Class 3, Article ND-5220 of the ASME Boiler and Pressure Vessel Code."

The in situ design, manufacture and installation of those portions of the "N" (non-essential) CCW header that are affected by the Staff's position are in compliance with the applicable conditions of the Commission's Construction Permit No. CPPR-74 dated July 1, 1970. The Staff in its SER April 13, 1970 approved the in situ design. Accordingly, the Commission's guidance as stated in its regulations at 10 CFR 50.109 namely, that if "such action will provide substantial, additional protection which is required for the public health and safety" provides the sole criterion for evaluating the Staff's position. The question is simply whether or not Article ND-5220 inspections result in substantial benefit, i.e., a significant enhancement of functional integrity. This article requires 100 percent dye penetrant examination, or 100 percent magnetic particle examination, or 100 percent radiography of all welds in lines greater than 4 inches that service the reactor coolant pumps (RCP's) and the letdown heat exchangers.

The pipe in question is carbon steel; it has a maximum operating pressure of 100 psig and maximum temperature of 150°F; it has a design pressure of 150 psig and design temperature of 200°F; it is schedule 30 or 40 pipe; and it has been hydrostatically tested at 225 psig. The piping is in accordance with the requirements of the American National Standards Institute Code for Pressure Piping, ANSI B31.1.0, Power Piping. Visual inspection of welds was conducted in accordance with engineering specifications as delineated in Table 9.2-3A. No other NDE is specified, nor is it required.

The carbon steel piping is subjected to modest conditions of pressure and temperature and a working fluid composed of demineralized water buffered with a corrosion inhibitor. Use of schedule 30 or 40 carbon steel piping for this service is commonplace. It has and will continue to provide an acceptable level of piping functional integrity/ reliability.

Schedule 30 and 40 pipe is thin walled, e.g., the 8 inch schedule 40 pipe servicing the reactor coolant pumps has a wall thickness of 0.322 inches. Article ND-5220 NDE requirements are accommodated by either dye penetrant or magnetic particle examination. These inspections detect small flaws 9.2-13 Amendment No. 22 (05/07)

at or near the surface, which are the appropriate consideration for this piping. Experience indicates that large flaws, if present, would be detected during hydrostatic testing, i.e., the hydro provides a satisfactory system integrity check. Based on a considerable experience base with thin walled carbon steel pipe, it is concluded that (i) the use of qualified weldors, (ii) industry approved welding procedures, (iii) visual inspection procedures,and (iv) hydrostatic testing results in piping integrity of an acceptable confidence level. The benefit afforded by the Article ND-5220 NDE requirement is simply that derived from the elimination of small surface flaws in weld areas.

Small surface or internal flaws are local discontinuities that produce local discontinuity type stresses.

The relevant consideration is whether or not these flaws can grow in service to a point where the integrity of the piping could be compromised. Defects or notches of one type of another are nearly always present in carbon steel parts because of design requirements, manufacturing and installation methods, or surface conditions. The presence of these local discontinuities may appreciably affect the fatigue properties of the carbon steel piping.

Figure F-106(a) of USA Standard B31.7, Nuclear Power Piping (1969) provides this Code's allowable fatigue curve for carbon and alloy steels with metal temperatures not exceeding 700°F. The fatigue properties of carbon steel are such that if the alternating stress intensity (Sa) is less than 10,000 psi, fatigue failure of the pipe is not a concern, i.e., the stresses in the pipe do not exceed the endurance limit of the material --- a crack will not be initiated.

The CCW piping may cycle from a low pressure (static head from the component cooling surge tank) and ambient temperature when "N" loop sections are secured, to the maximum operating conditions of 100 psig and 120°F. The system will see a modest number of such cycles during the plants' lifetime. For an 8 inch schedule 40 pipe the cyclic variation in hoop stress is from 0 to about 1,300 psi.

(Since the piping is not subjected to rapid temperature transients, thermal stresses are negligible.)

Accordingly, the alternating stress intensity (Sa) is very low, less than 1000 psi. Since Sa is more than an order of magnitude below the values where fatigue becomes a relevant consideration, it is concluded that flaws will not grow, i.e., their presence does not imperil CCW pipe integrity.

Appendix A to ASME Section XI (1974) provides a method to be utilized for the evaluation of flaws detected in metals during inservice inspection. This methodology is normally applied to thick sections where there is a likelihood of flaws and the presence of flaws may be a weighty consideration. This notwithstanding, the methods have been applied to the CCW piping as an alternate means of demonstrating the acceptability of the presence of flaws in the CCW piping. A hypothetical flaw through the pipe wall was postulated. Flaw parameters were selected to maximize the stress intensity factor (KI). Even for this extreme case (piping would not pass the hydro), the low applied stresses in the CCW piping results in a low stress intensity factor range - (KI). The stress intensity factor range is so low that it falls off of Section XI figure A-4300-1. This indicates that the crack growth rate is extremely small --- less than 10-8 inches/cycle. If the CCW system were removed from service, depressurized and returned to service for over 14,000 cycles (the system might see one or two such cycles a year),the flaw would grow less than 0.00014 inches. This flaw growth is negligible.

9.2-14 Amendment No. 20 (4/04)

In Amendment 26 (6/8/74) and Amendment 27 (6/25/74) at Q9.16 the consequences of loss of CCW to the reactor coolant pumps is addressed. Numerous alarms and the inherent capability of the pumps to accommodate loss of CCW provide ample time for operators to trip the unit and secure the pumps. The ability to achieve a cold shutdown is not affected, nor do unacceptable conditions result from loss of CCW. The Staff, in its SER of November 8, 1974, concurred with the propriety of a non-seismic classification for the CCW lines to the RCP's for this facility.

Based on the preceding it is concluded that non-destructive testing of CCW lines to the RCP's and letdown heat exchangers is not required because:

i) the required inspection of welds will not result in any substantial increase in the reliability of these CCW lines, ii) loss of CCW to the letdown heat exchangers will not adversely affect the ability to achieve an orderly cold shutdown, and iii) loss of CCW to the reactor coolant pumps will not adversely affect the ability to achieve an orderly cold shutdown, or result in conditions that affect the public health and safety.

According to Supplement 1 to the SER (May 9, 1975) the NRC concluded that the visual examination and acceptance standards applied to the CCW piping portion to the RCPs and letdown heat exchangers along with system hydrotest and crack propagation analysis constitute an acceptable basis for meeting GDC-1.

Therefore, nondestructive testing was no longer required by the NRC.

It is concluded that no undue risk to the public health and safety results from maintenance of the in situ CCW design.

As discussed in NRC Generic Letter 2008-01 and INPO SER 2-05, the presence of unanticipated gas voids within fluid systems can challenge the ability of systems to perform their design functions due to issues such as gas binding, water hammer, injection delay times, etc. Component Cooling Water System alarm response, operating procedures and the Gas Accumulation Management Program provide detection and recovery actions to address air intrusion.

9.2.2.3.2 Single Failure Analysis The component cooling water system is arranged into two redundant and independent essential supply systems, each with a pump and heat exchanger and the capability to supply the minimum complement of safety related equipment required for safe shutdown or LOCA conditions.

UNIT 1 9.2-15 Amendment No. 28 (05/17)

Automatic valves isolate the nonessential header from the two essential headers in the event of an accident. Upon occurrence of a LOCA, the valves connecting each essential header to the nonessential header (at the two cross connect points) also close automatically on SIAS thereby isolating the essential headers from each other. Each of the two valves at a cross connection receives a signal from a separate SIAS channel so that no single failure can cause both valves to remain open. If one essential header should fail, the remaining redundant essential header assures availability of at least one set of equipment and piping for accident service.

The component cooling water surge tank is common to both essential headers but is partitioned to provide independence. Consequently, there is no single failure that could prevent the component cooling system from performing its safety function. The single failure analysis is presented in Table 9.2-6.

9.2.2.3.3 Service Environment The component cooling water pumps, heat exchangers and portions of the piping and valves are located outdoors. These components are designed to operate under the following environmental conditions:

ambient air temperature from 30°F to 120°F, 100 percent humidity, salt laden atmosphere, torrential rains and hurricane winds. Section 9.2.2.3.4 describes other potential environmental conditions resulting from extreme natural phenomena.

Other system components are located within the reactor auxiliary building and are designed for the normal ambient expected in the building. No system active components are located in areas of high radioactivity.

9.2.2.3.4 Natural Phenomena All components of the component cooling water system including pumps, heat exchangers and piping which are essential for safe shutdown or to mitigate the effects of a LOCA are designed and installed as seismic Class I equipment. The nonessential portions of the system are not seismic Class I and are isolated automatically from the seismic Class I portions upon SIAS. The isolation valves are seismic Class I.

The pumps and heat exchangers are located outdoors on a seismic Class I foundation. Seismic Qualifications of system components has been demonstrated by manufacturer calculations and is discussed in Section 3.7.5.

9.2-16 Amendment No. 22 (05/07)

The spatial separation criteria for component cooling water equipment is the same as discussed in Section 9.2.1.3.4. The pumps are separated by 18 feet from centerline to centerline. In addition, tornado missile shielding is provided so that the design basis missile will not preclude the availability of a pump.

Indoor components such as the surge tank and portions of the piping and valves are protected from tornado winds and missiles since they are housed within the reactor auxiliary building.

Component cooling water system equipment susceptible to flood damage is protected by locating all safety-related components above the maximum expected PMH water level and wave runup. The elevation of the maximum expected wave runup is 17.2 ft above mean low water as discussed in Section 2.4.5.6.

9.2.2.4 Testing and Inspection Hydrostatic tests to 150 percent of design pressure were performed on the heat exchangers.

Performance tests to demonstrate design requirements were conducted and heat transfer characteristics were verified after installation. Eddy current tests of all tubes were performed in accordance with ASTM B-111, Paragraph 10, for entire tube cross sections. All pressure containing welds were checked by radiographic examination.

Hydrostatic test to 150 percent of maximum operating head was performed on each pump casing.

Performance tests were performed on each pump in accordance with the latest design code standards to establish pump characteristics. Nondestructive testing was performed on welds, forgings and castings in accordance with the requirements of ASME B31.7 and the Draft Nuclear Pump and Valve Code, Code Class III.

The component cooling water system was operated and tested initially with regard to flow paths, flow capacity and mechanical operability. Pumps were tested to demonstrate head and capacity. All automatic and manual sequences and control functions are tested to ensure design operability.

The component cooling water system is in service during normal plant operation and system performance is monitored and data taken periodically to confirm heat transfer capabilities.

9.2.2.5 Instrumentation Application Table 9.2-7 gives a functional listing of component cooling water instrumentation.

The pumps and heat exchangers have diverse parameters measured to confirm the correct operation of the equipment involved. The monitoring of flow, temperature and pressure at the points indicated in Table 9.2-7 and Figure 9.2-2 provide the control room the information for operating the essential and normal header systems.

9.2-17 Amendment No. 17 (10/99)

The valves in the component cooling water system allow:

a) isolation of the nonessential (N) header from the A and B headers on SIAS b) routing of component cooling water through the shutdown heat exchangers on SIAS c) isolation of the reactor coolant pumps and CEDM air cooler on SIAS d) routing of the component cooling water surge tank vent line to the waste management system upon a high component cooling water radiation signal e) controlling the level in the component cooling water surge tank f) directing of discharge of the 1C component cooling water pump to either the A or B header and g) controlling of flow to the containment cooling units The component cooling water pumps can be started and stopped both at the switchgear and from the control room. The pumps receive a start signal on SIAS. The logic and instrumentation are discussed in Section 7.3.1.3.1.

UNIT 1 9.2-18 Amendment No. 28 (05/17)

9.2.3 CIRCULATING WATER SYSTEMS 9.2.3.1 Design Bases The circulating water system is designed to provide a heat sink for the main condenser under normal operating and shutdown conditions. The system serves as the primary source of water for the Ultimate Heat Sink.

9.2.3.2 System Description The circulating water system is shown schematically on Figure 9.2-1.

The condenser cooling water is provided by the circulating water system which consists of intake and discharge pipes in the ocean with canals to the plant. Pumps at the intake structure provide 484,000 gpm of flow. The system is shown on Figures 9.2-1B and 9.2-1C. The maximum allowable temperature rise of the water passing through the condenser is limited by restrictions in the environmental permit.

The circulating water is taken from the ocean through two 12.0 ft. and one 16.0 ft. ID prestressed concrete pipes, commencing 1200 feet offshore. The intake pipes are buried for the entire length of their run, with approximately 25 ft. of cover under the natural dunes, 12 ft. of cover in the surf zone and at least 5 ft. of cover for the remainder of their ocean run.

This buried installation prevents interferences with littoral processes. Each pipe has a "velocity cap" to minimize fish entrapment. There is about 8 feet of water above each cap and the velocity of intake water is about 1/2 ft/sec. See Figure 9.2-1D for details.

The intake pipes are located approximately 2400 ft. south of the discharge pipe. They are buried from the intake points for a distance of about 1600 ft. beneath the ocean bottom and under the beach, terminating in a canal on the west side of the sand dunes. After passing through the inlet pipes, the circulating water is conveyed in a canal for approximately 5000 ft. to the plant intake structure.

The reinforced concrete intake structure consists of four bays. Each bay has a coarse screen, a traveling screen, a circulating water pump and is provided with auxiliary equipment. The approach velocity to each bay is less than 1 fps. From the intake structure, the water is conveyed through a buried pipeline to the condenser. The water then flows at a velocity of less than 7 fps through the tubes of the condenser, located in the turbine building, into the discharge water boxes. A continuous, on-line condenser tube cleaning system injects sponge balls at the inlet waterbox and collects the balls for recirculation at the discharge of the condenser.

9.2-19 Amendment No. 22 (05/07)

The circulating water discharge system is shown on Figures 9.2-1B and 9.2-1C. From the condenser, the discharged condenser cooling water is transported approximately 500 ft. in a buried pipeline and then about 580 ft. in a canal to State Road A1A. The water passes under a bridge. Once past A1A, the cooling water travels about 1200 ft. in a canal to an outfall structure, located on the western side of the sand dune. From the canal outfall structure, the cooling water discharge is carried about 1550 ft. and 3375 ft. offshore in a 12 ft. and 16 ft. diameter pipelines, respectively. At its termination, the 12 ft. diameter pipe is modified with a short transition section and a two part, Y-type high velocity jet discharge. The last 1400 ft. of the 16 ft. diameter discharge line is the multiport diffuser section, composed of 58 equally spaced 17 3/4 in. ports. See Section 2.4.12.1.

System design data are presented in Table 9.2-8.

9.2.3.3 System Evaluation The four circulating water pumps are each sized to provide 25 percent of the cooling water flow for the turbine condenser. The pumps are sized for the maximum condenser heat load and provide sufficient head (40 ft.) to overcome system frictional losses. The dimensions of the intake bays are designed to give a low velocity profile through the traveling screens and to provide sufficient submergence for the pump required NPSH. The circulating water, screen, wash, and intake pumps are arranged in each bay to eliminate the adverse effects of vortices, and to provide flow path and suction velocities to each pump. Three of the four bays contain intake cooling water pumps and two bays contain screen wash pumps. The pump suctions are located at different elevations in the bays.

The suction for the intake cooling water pumps is at the -18.5 ft. level followed by the suction for the circulating cooling water pumps at EL. -16.0 ft. and finally by the screen wash pumps at EL. -12.5 ft.

The intake and discharge piping are separated by 2400 ft. of ocean to prevent recirculation of heated water. See Section 2.4.12.2.

Chlorine in the form of sodium hypochlorite or alternate biocide is used to control biological fouling in EC291588 the Circulating Water System by use of a hypochlorite system serving both St. Lucie Units 1 and 2.

The hypochlorite or alternate biocide solution is mixed with the water coming into the intake structure EC291588 in order to control biofouling. The solution in the Circulating and Intake Cooling Water Systems is added in regulated quantities so that the residual chlorine at the terminus of the discharge canal will not exceed the limits as defined in applicable plant permits. As the hypochlorite solution is mixed with the water coming into the intake structure in regulated quantities, adverse corrosive effects are not expected.

9.2-20 Amendment No. 30 (05/20)

A continuous on-line condenser tube cleaning system (CTCS) that employs sponge balls to scrub the condenser tubes on the circulating water side is also used to control biological fouling. The Florida Department of Environmental Protection identified to FPL concerns regarding CTCS sponge ball loss and the potential for consumption by sea turtles. In the several responses to the State, FPL was able to demonstrate that the combination of system design features and Good Management Practices will minimize sponge ball loss to the Atlantic Ocean.

9.2.3.4 Testing and Inspection Prior to installation in the system, each component was inspected and cleaned.

Shop hydrostatic tests on the pump casings were made at a minimum of 150 percent of the maximum operating pressure.

Preoperational testing consisted of calibrating the instruments, testing the automatic controls for actuation at the proper set points, and checking the operability and limits of alarm functions. Automatic actuation of system components is tested periodically to confirm operability. The circulating water system is in service during normal plant operation. System performance is monitored and data taken periodically, on an informal basis, to confirm heat transfer characteristics.

9.2.3.5 Instrumentation Application The circulating water system is continuously monitored by measuring the condenser inlet and outlet temperature.

Table 9.2-9 lists the system parameters that are measured and Figure 9.2-1 shows the system instrumentation. Diverse parameters (discharge pressure and seal water flow) are measured on the circulating water pumps to establish that they are operating correctly.

In addition, discharge canal level and temperature are monitored.

The circulating water pumps can be started from either the control room or locally at the pumps. A pump start permissive circuit prevents starting unless:

1) There is bearing lubricating water flow,
2) the valve in the discharge line is opened at least 30 percent, and
3) the valves at the water box are full open.

9.2.4 TURBINE COOLING WATER SYSTEM 9.2.4.1 Design Bases The turbine cooling water system is designed to provide a heat sink for power cycle equipment during normal operation and normal shutdown. The system serves no safety function since it is not required to achieve safe shutdown or to mitigate the consequences of a LOCA. It is completely independent of, and has no connection with the component cooling system.

9.2.4.2 System Description The turbine cooling system is a closed loop system which uses demineralized water buffered with a corrosion inhibitor to remove heat from the turbine and other components in the power cycle (See Figure 9.2-4).

9.2-21 Amendment No. 22 (05/07)

During normal operation, water is circulated by one running turbine cooling water pump and the heat removed is transferred to the intake cooling water system through the two turbine cooling water heat exchangers. The second turbine cooling water pump is normally operated in standby and will auto start on low flow. Both pumps can be operated if necessary based on overall heat removal demand and on intake cooling water system temperature. Turbine cooling water circulates through the shell side of the heat exchangers.

A surge tank open to the atmosphere is connected to the turbine cooling water system. The tank level is automatically controlled by level switches and a level control valve with makeup from the demineralized water storage tank. Control room alarm is initiated on both high and low water levels. A corrosion inhibitor is used in the turbine cooling water system. The concentration of the inhibitor is not automatically regulated. The turbine cooling water chemistry is measured periodically and the inhibitor added when needed.

The turbine plant components cooled by the turbine cooling water systems include:

a) turbine lube oil coolers b) turbine electrohydraulic fluid coolers c) hydrogen seal oil coolers d) isolated phase bus air coolers e) hydrogen coolers f) exciter air cooling units g) heater drain pumps seal coolers h) feedwater pump oil coolers i) condensate pump motor bearing coolers j) instrument air compressor intercoolers, aftercoolers and oil coolers EC283796 k) sample coolers, secondary system l) backup station air compressor aftercooler m) hydrogen gas dryer n) sample system primary coolers Components (a), (c), (e), (f) and (l) listed above are provided with automatic temperature control valves in the cooler outlet piping. It is acceptable to operate the temperature control valve for component (e) in manual.

System component design data are presented in Table 9.2-10.

UNIT 1 9.2-22 Amendment No. 29 (10/18)

9.2.4.3 System Evaluation Each of the two pumps and heat exchangers in the turbine cooling system is designed to provide 50 percent of total system capacity. Table 9.2-11 lists operating flow rates and calculated heat loads for the turbine plant components cooled by the turbine water system. The turbine cooling water system is supplied with makeup by the demineralized water pumps. Flow through the turbine cooling water heat exchangers is monitored upstream by a local flow meter.

The turbine cooling water system is not needed to shut down the turbine generator and accessories after a turbine trip.

9.2.4.4 Testing and Inspection Prior to installation in the system, each component was inspected and cleaned.

Preoperational testing consisted of calibrating the instruments, testing the automatic controls for actuation at the proper set points, checking the operability and limits of alarm functions, and setting the safety valves.

The turbine cooling water system is in service during normal plant operation. System performance is monitored and data taken periodically, on an informal basis, to confirm mechanical, hydraulic, and heat transfer characteristics.

9.2.4.5 Instrument Application Table 9.2-12 lists the parameters measured to monitor the turbine cooling water system.

The turbine cooling water pumps can be started and stopped either locally or from the control room.

There are a number of temperature controlled valves in the system which control flow through the:

a) turbine lube oil coolers b) hydrogen seal oil unit (air side cooler) c) hydrogen seal oil unit (hydrogen side cooler) d) hydrogen coolers (valve may be operated in manual control) e) exciter cooling air units f) backup station air compressor after cooler 9.2.5 MAKEUP WATER SYSTEM 9.2.5.1 Design Bases The function of the makeup water system is to supply treated, demineralized water of the required quality for makeup use to various systems of the plant, including the reactor coolant system and the condensate feedwater system.

The makeup water system serves no safety function, since it is not required to achieve safe shutdown or mitigate the consequences of a LOCA.

9.2-23 Amendment No. 26 (11/13)

9.2.5.2 System Description At the plant site, water from the city of Fort Pierce is stored in two 500,000 gal. city water storage tanks.

Water from these tanks is supplied to the fire protection system, domestic water system and the makeup water system. The makeup water system is shown schematically on Figure 9.2-5 and equipment design parameters are given in Table 9.2-13.

Water from the makeup system is pumped through the water treatment system. Demineralized water from the water treatment system enters the Treated Water Storage Tank (TWST) via a level control valve.

There are three treated water transfer pumps taking suction from the TWST and feeding a discharge header which in turn supplies water to:

a) Unit 2 Condensate Storage Tank (CST);

b) Unit 2 Primary Water Storage Tank (PWST);

c) Unit 1 Primary Water Storage Tank (PWST); and d) Unit 1 WTP through normally opened valves. In addition, there is connection from this common header to Unit 1 CST through a normally closed valve. Additionally, TWST isolation valves and a bypass valve is provided to supply demineralized water to this header directly from the WTP if required.

A flanged connection is provided from the TWST drain line to allow connection to a portable diesel powered fire pump to backup the fire protection system if required.

The three transfer pumps consist of two 60 HP (1A and 1B) and one 7 HP pump (1C) in parallel.

Water required for reactor coolant system makeup flows to the primary water storage tank. Use of a diaphram on this tank helps to prevent aeration of the water. Water from this tank is supplied as makeup to the chemical volume and control system by means of two primary water pumps. The chemical volume and control system maintains reactor coolant system inventory by charging primary makeup water to the reactor coolant system. The primary water pumps also supply water to the waste management system.

9.2-24 Amendment No. 16, (1/98)

9.2.5.3 System Evaluation The makeup water system serves no safety function. Each of the two primary water pumps are 100 percent capacity. Adequate volume of water is always stored in the condensate storage tank to ensure availability of water for the auxiliary feedwater pumps.

The Design Basis and actuator capabilities for MV-15-1 have been reviewed in accordance with the requirements of Generic Letter 89-10, "Safety Related Motor Operated Valve Testing and Surveillance,"

as noted in Section 3.9.2.4.

9.2.5.4 Testing and Inspection Each component was inspected and cleaned prior to installation into the system. The system was operated and tested initially to ensure its proper operation, instruments were calibrated, and automatic controls were tested for actuation at the proper set points.

9.2.5.5 Instrumentation Application The instrumentation in the makeup water system is listed in Table 9.2-14. The instrumentation monitors and controls the water level of the primary water tank and monitors operation of the primary water pump.

The primary water pump can be started by hand switch in the control room or by local pushbutton. The standby primary water pump is automatically started on low pump discharge header pressure.

The flow of water into the primary water tank is controlled by a level control valve in the intake header to the tank. The makeup water to equipment located in the containment is isolated on a CIS signal (see Table 6.2-16 for data on isolation valves) by closure. The isolation valve can also be closed from the control room.

9.2-25 Amendment No. 22 (05/07)

9.2.6 POTABLE AND SANITARY WATER SYSTEM 9.2.6.1 Design Bases The potable water system supplies sufficient quantity and pressure to all sanitary plumbing fixtures and accessories, plant washdown stations and decontamination facilities.

The potable water system is designed to meet the drinking requirements for the full complement of plant staff.

The potable water system is designed to supply the quality of water required by local and state regulations.

Historically, the sanitary system has contained very low levels of licensed material. Disposal of these wastes is within the restrictions of the State of Florida Regulation (10D-91.463) and has been approved by the Florida Department of Health, Bureau of Radiation Control. The State of Florida as an "Agreement State" maintains jurisdiction over disposal of very low level radioactive waste. Approval of this disposal is therefore governed by the Florida Administrative Code which, in essence, mirrors NRC regulations.

(See References 1 and 2).

9.2.6.2 System Description The system consists of two pumps, a hydropneumatic tank and associated piping and valves.

The potable water required for plant use is taken from the two 500,000 gallon city water storage tanks, which are supplied from the city of Fort Pierce. The system is pressurized with a hydropneumatic tank and a set of pumps which assure that minimum pressure is available to supply water.

9.2.6.3 Safety Evaluation The potable water system serves no safety function since it is not required to achieve safe shutdown or to mitigate the consequence of a LOCA.

The potable water system is not connected to any system which is a potential source of radiation. The potable water system will therefore not act as a radiological contamination source.

Standpipes are provided within the City Water Storage Tanks for all non-fire related connections. These standpipes assure a minimum of 200,000 gallons of water is available to supply fire suppression systems.

See Appendix 9.5A.

9.2-26 Amendment No. 16, (1/98)

THIS PAGE LEFT INTENTIONALLY BLANK 9.2-27 Amendment No. 14 (6/95)

9.2.7 ULTIMATE HEAT SINK The design of the St. Lucie intake canal and emergency barrier specified in Amendment 30 to the Unit 1 FSAR (8/15/74) constituted the plants' UHS. The design proposed in compliance with the fundamental design criterion set forth in the Unit 1 PSAR, viz., that slopes under soil liquefaction conditions assume a 20 to 1 final slope failure surface. This criterion was considered to be and is acceptably conservative for an area of low seismicity such as Florida. The basis being that data from the Alaskan earthquake (soils are similar to St. Lucie) indicate final slopes from 8:1 to 10:1. A detailed literature search does not indicate any flatter slopes resulting from seismic activity. The liquefaction criterion resulted in a very large intake canal. It is 220 feet wide and 30 feet deep, and is more than adequate to accommodate liquefied slopes.

Because soils in the emergency (UHS) barrier area were assumed for design purposes to be liquefiable, the barrier design had to accommodate reorientation of the barrier. (The UHS barrier separates Big Mud Creek from the intake canal.) Thus, the proposed design was such that it could pass the requisite quantity of water in the upright position or any collapsed position.

The Staff has reassessed in PSAR approach of assuming liquefied slopes in light of the current state of the art. On October 21, 1974, the Staff concluded that additional assurance of the UHS function should be obtained. The Staff concern being twofold, viz., that detailed in situ soil data was not available to precisely define soil properties, and that once soil flow commences and during said flow a precise prediction of the flow's behavior is not possible. Accordingly, the staff stated that its position was that a conservative study to identify all hazards to the supply of sufficient water of acceptable quality to the intake cooling water pumps should be completed; that conservative quantitative analyses of the hazards should be performed; and that these analyses should include:

(1) a soils exploration and sampling program to define critical foundation material and geologic conditions in all areas that could adversely affect the acceptable delivery of water to the pumps, (2) a testing program to establish the strength and deformation characteristics of these materials, and (3) appropriate stability and/or deformation analyses, using the results of exploration and testing programs, to quantitatively predict the functional safety of the ultimate heat sink with respect to foundation material hazards.

The program suggested by the Staff has been conducted in accordance with its recommendations. The soils program, the analyses, and the results are provided as Appendix 2G. This study concludes that:

a) The stability of slopes in the intake canal that could conceivably affect the intake structure forebay is acceptable. Ten cycles of 9.2-28 Amendment No. 22 (05/07)

strong motion accompanying the DBE could cause local straining or sloughing of one to two feet along the "submerged" canal slopes and bottom. The DBE will not cause massive sliding or flow of materials.

b) Sliding-wedge and slip-circle methodology indicate that block slides of material in the switchyard area can not be induced by the DBE.

c) The emergency canal barrier can be constructed on in situ soils to remain upright when subjected to the DBE. Local densification of in situ soil is not required to implement this seismically capable barrier design.

The favorable results of the study indicate that the original design basis of assuming liquefiable soils was overly conservative. However, the Staff in its evaluation of Appendix 2G and Supplement No. 1 to Appendix 2G concluded that certain soils around the UHS barrier and plant intake structure required stabilization. The areas stabilized and the methods used are discussed in Supplement No. 2 to Appendix 2G.

9.2.7.1 Design Bases The ultimate heat sink (UHS) has sufficient cooling water capacity to dissipate reactor decay heat during normal and emergency shutdown conditions. Specifically, the ultimate heat sink is designed to:

a) Provide sufficient cooling water for more than 30 days to achieve and maintain safe shutdown in both units or to permit control of a LOCA in one unit and concurrent safe shutdown of the second unit.

b) Withstand the effects of severe natural phenomenon, namely, the Operating Basis Earthquake (OBE), Design Basis Earthquake (DBE), Design Basis Tornado (DBT), Probable Maximum Hurricane (PMH), or single failure of a manmade structural feature without loss of its safety function.

9.2.7.2 System Description Two independent water sources and their associated canals and conduit comprise the ultimate heat sink for the plant. The primary source of water is the Atlantic Ocean which together with the ocean intake structure, intake canal and intake structure bay area constitute the primary source of shutdown cooling water. The secondary source of cooling water is Big Mud Creek which is connected to the Atlantic Ocean through the Indian River (see Figure 1.2-1). This source utilizes an emergency (UHS) intake canal connecting Big Mud Creek with the intake bay area in front of the intake structure. Regardless of source, the shutdown cooling water is discharged into the discharge canal just south of the discharge seal well.

The water then flows through the discharge canal to the Atlantic Ocean via discharge pipes.

The primary water source draws water from the Atlantic Ocean via the circulating water system intake as described in Section 9.2.3. Two 12 foot and one 16 foot I.D. reinforced concrete pipes take ocean water from about 1200 ft offshore. The intake pipe centerline is located at Elevation-34 ft MLW.

9.2-29 Amendment No. 18, (04/01)

The primary source will be available for all natural phenomena except possibly the DBE with liquefaction.

For this unlikely event, it is conceivable for the ocean intake system to become impassable at the intake headwall due to soil liquefaction. Consequently, the second source (Big Mud Creek) is designed to accommodate a DBE. It is connected to (but normally isolated from) the intake canal and its only function is to serve as a backup for the primary source in the unlikely event of a DBE. The secondary source is never expected to be utilized in this manner.

Big Mud Creek is a natural body of water extending easterly from the Indian River just north of the plant site. Big Mud Creek was dredged during construction to a minimum elevation of -40 ft MLW with a minimum 250 ft bottom width. A 125 foot wide by 12 foot deep (-12 MLW) channel was dredged during construction from Big Mud Creek across the east side of the Indian River to the channel of the Intracoastal Waterway. The Intracoastal Waterway is a 12 foot deep channel running north-south in the Indian River.

The Indian River is connected via inlets to the ocean at Ft. Pierce to the north and at the St. Lucie River to the south.

The intake bay in front of the intake structure is separated from Big Mud Creek by a barrier wall which is placed in the UHS canal 200 ft. from its intersection with the intake canal. The barrier maintains separation between the primary and secondary sources of UHS cooling water during normal plant operation. The wall is designed to withstand maximum water differential between Big Mud Creek and the Intake Bay in combination with PMH or DBE as shown in Table 3.8-4A.

A full description of the Intake Cooling Water System is presented in Section 9.2.1 and the UHS barrier wall is described in Sections 3.8.1.1.5 and 9.2.7.2.1.

9.2.7.2.1 UHS Barrier Wall Description As stated above the evaluation of in situ soils indicates that a seismically capable UHS barrier can be implemented.

The evaluation discussed in Section 9.2.7.3.1 indicates that a hypothetical blockage of the primary water source leaves a sufficient supply of shutdown cooling water in the intake canal for onsite and/or offsite personnel to affect a connection between Big Mud Creek and the intake canal.

The St. Lucie site UHS barrier serving Units 1 & 2 is a seismically capable structure, i.e., it will remain upright during and subsequent to a DBE. Appendix 2G provides the analyses of the underlying soils verifying their stability. Supplement No. 2 to Appendix 2G indicates which soils have been stabilized.

Appurtenances required to achieve the UHS function are seismic Class 1, and non-seismic appurtenances are such that their failure cannot adversely affect the UHS function.

Excavation in the barrier wall area to about elevation -26 feet was done to remove undesirable soils.

Compaction piles densified the soils below elevation -26 ft. and a 6 ft layer of compacted soil above elevation -26 ft. provides a seismically stable foundation for the barrier. Compacted backfill is 9.2-30 Amendment No. 22 (05/07)

provided around the wall to the canal bottom at elevation -14 ft. The analysis demonstrating the stability of soils supporting the barrier wall during and subsequent to the DBE is provided in Appendix 2G and supplements thereto. Stability of the barrier wall itself is discussed in Section 3.8.1.7.5.

The concrete barrier design is free standing with a roadway at elevation +13 feet. The design of the barrier wall is consistent with requirements imposed by slope stability consideration, i.e., the wall is considerably shorter than the original concept, with conservatively accommodated liquefied slopes with a final failure surface of 20:1. Two 100 percent openings (one opening provides sufficient flow for Units 1 &

2) are provided in the barrier wall for operation of Units 1 and 2. (Additional spare penetrations are provided.) Seismic Class I pneumatically operated valves are provided to seal these openings. Motive power for the valves is seismic Class I on the wall and designed such that interruption of supply causes opening of the flow paths through the barrier wall. The capability to test the valves periodically is provided commensurate with environmental and Staff requirements. Refer to Figures 9.2-6d and 9.2-6e.

Two 54 inch diameter butterfly valves are used to control flow through the UHS barrier. The valves are designed in accordance with Code Class 3 of Section III of the ASME code. The valves are constructed from aluminum bronze alloy which retards the growth of marine organisms.

The operation of the valves is effected by means of an air cylinder-type of operator which is located in an equipment room, 11 feet directly above the centerline of the valves. The operator is connected to the valve with an 11 foot extension rod through which the operator torque is transmitted to the valve disc to open or close.

The pneumatic operator requires air under pressure to keep the valve disc in the closed position. The pneumatic operator is spring loaded so that in the event of an interruption of the air supply, the spring force will bring the operator and the valve to the open position. The operation mode of the valves is therefore fail open. The valves are required to stroke open in sufficient time to ensure a continued supply of cooling water in the event of a loss of the primary water source. The control scheme is shown in Figure 9.2-6f.

The supply of air to each valve operator is controlled by a three-way solenoid valve. The solenoids are energized by a dc power signal which is transmitted to the solenoids remote manually from the control room. If it is desired to open the butterfly valves, the control switch signal will de-energize the solenoid valves to the exhaust position. The supply of air to the operator will be interrupted, air will be exhausted, and the operator spring will decompress to open the valve disk. To close the valve, the control switch is operated again and the reverse action sets the valve to the close position. In the event of a power failure or any interruption in power supply, the solenoid will be deactivated to the exhaust position.

The air control system incorporates an in-line air accumulator tank maintained at the same pressure as that of air supplied by the plant instrument air system. If the plant air supply system is lost, the 9.2-31 Amendment No. 16, (1/98)

tank will supply the required motive air without any interruption of the continuity of the air flow to valve operators. Air back flow is prevented by check valves located upstream of the accumulator. Low air accumulator pressure is alarmed in the control room in the event that the pressure reaches a predetermined low point.

The valve operators, the air accumulator tank, the solenoid valves and local switches are located in the equipment room, a seismic Class I structure, above the butterfly valves. Lights in the control room panel indicate the position of the valves.

9.2.7.3 Design Evaluation The ultimate heat sink concept for the plant complies with the regulatory positions of AEC Regulatory Guide 1.27 in the following manner:

Regulatory position C.1 of Regulatory Guide 1.27 requires that the ultimate heat sink provide sufficient cooling for at least 30 days to permit the simultaneous safe shutdown of both units or to permit control of a LOCA in one unit with simultaneous safe shutdown of the other unit. The ultimate heat sink concept provides two independent flow path means to the plant intake structure each connected to an inexhaustible supply of cooling water, the Atlantic Ocean.

Regulatory position C.2 of Regulatory Guide 1.27 requires that the ultimate heat sink capabilities offered in regulatory position C.1 be retained following the most severe natural phenomena taken individually, site related events, or a single failure of a man made structure. Section 9.2.7.3.1 demonstrates the availability of the primary or secondary source of water during design conditions. The twin 30 inch cooling water discharge lines discharge into the discharge canal just south of the sealwell in seismic Class I soil.

In the event of liquefaction of the discharge canal, the piping is designed with an open stand pipe (elevation +13.75 ft) which will discharge water above the liquefaction level.

Regulatory position C.3 of the guide requires that at least 2 sources of cooling water able to perform the functions indicated in regulatory position C.1 be provided as part of the ultimate heat sink. The primary and secondary sources of water provide this feature.

Regulatory position C.4 of Regulatory Guide 1.27 will be addressed as appropriate in the Technical Specifications.

9.2-32 Amendment No. 18, (04/01)

9.2.7.3.1 Design Analysis for Ultimate Heat Sink The availability of the UHS for the various design conditions is summarized below:

Design Condition Primary Source Secondary Source

1. Normal Operating Operational Not required Conditions
2. PMH Conditions Operational Not required with Extreme Low Water
3. PMH Conditions Operational Not required with Extreme High Water
4. Design Basis Operational Not required Tornado
5. OBE Operational Not required
6. DBE Possible Operational Blockage Discussion of UHS availability during the above conditions is presented below:

a) Probable Maximum Hurricane The extreme conditions encountered are:

1) Flooding from ocean, Surge to El + 16.2 (See Section 2.4)
2) Extreme Low Water, Ocean El - 3.0 MLW (See Section 2.4.11.2)
3) Extreme Low Water, Indian River El. - 3.0 MLW (See Section 2.4.11.2)
4) Winds, up to 158 mph (See Section 2.4.5.1)
5) Extreme High Water, Indian River - El + 10.26 (see Figure 2.4-13)

The primary source of water for the Ultimate Heat Sink, the Atlantic Ocean, will remain functional during PMH conditions. The secondary source will be functional during all hurricane conditions including the staff's postulated stalled PMH. Refer to Figures 9.2-1b and 9.2-1c which show the principal details of the intake system. The ocean intake structures, each sized for 1150 cfs flow, are designed to withstand the largest wave that can be supported in this depth of water with breaking waves. These submerged structures will function 9.2-33 Amendment No. 24 (06/10)

through the PMH. The buried concrete pipelines (2-12 ft diameter and 1-16 ft diameter lines) are buried at least 12 ft below the ocean bottom in the surf zone and 5 ft below the bottom elsewhere.

These pipelines will not be affected by the PMH.

Assuming the dunes are topped, the intake canal would suffer eroded dike slopes and become partially filled-in due to wave action during the period that the PMH is at its peak. After the flooding subsides, the canal cross-section need be only 6 percent of its initial cross-sectional area below elevation -1.0 MLW to pass 130 cfs (2 unit, redundant emergency shutdown requirements) at 1 foot per second velocity. Considerably more cross-sectional area will be available in the canal after erosion has taken place.

b) Design Basis Earthquake The extreme conditions encountered are:

1) Seismic forces on structures with differential water levels.

The primary source of cooling water is the Atlantic Ocean. Water is withdrawn from the Atlantic and conveyed across land in a 30 ft deep by 220 ft wide canal. The system is designed to supply about 2300 cfs of ocean water. See figures 9.2-1b and 9.2-1c.

Appendix 2G provides the results of extensive field studies, laboratory testing of in situ soils, and analyses which demonstrate that massive flow slides of liquefied materials will not occur. The analysis assumed 10 cycles of strong motion, which is conservative for a region of low seismicity such as Florida (2 or 3 cycles would be more appropriate). This not withstanding, analyses assuming liquefied materials have been performed to assess their potential impact on the UHS function. These studies are discussed below.

Under seismic conditions there are several credible failure modes for the intake canal. The canal could liquefy reducing but not blocking its cross-sectional area. Because only 6 percent of the initial cross-sectional area is required to supply cooling water, there will be no loss of function. A slope stability analysis assuming soil liquefaction in the emergency canal and intake canal is presented in Section 2.5.5. The analysis demonstrates that the channel remains open to the intake structure with a minimum of 7 times the required cross-sectional area for 130 cfs flow (two unit requirement) at 1 fps average velocity. Liquefaction at the intake canal headwall structure could be the most critical failure mode in the ocean intake system.

Liquefaction analysis was again performed based on a 1/20 slope as shown in Section 2.5.5 (which overpredicts the worst slopes measured (1/8 to 1/10) for liquefaction following a severe earthquake).

At the headwall, liquefied soil could partly fill-in the canal and block the pipes if the Units are in a shutdown condition; however, analysis demonstrates that if one or both Units are operating, the 5 fps (one Unit) or 10 fps (2 Units) water velocity exiting the intake pipes will scour sands clear of the pipes and headwall structure. In this matter, the headwall structure will prevent sands from the dikes slopes from closing off the intake lines. Refer to Figure 9.2-6b.

9.2-34 Amendment No. 22 (05/07)

Because of the difficulty in accurately and scientifically predicting the effect of the soil slide on the discharging jets of water, and vice versa, where the sand will be deposited and to what depth, no definite conclusion is possible. However, the approach presented does show that a channel will remain open (by virtue of the ocean water levels being above the liquefied soil level) at the intake canal headwall if the plant is operating at the onset of the liquefaction phenomenon. When the Units are not operating, the chances of blocking the intake lines due to dike failures (liquefaction) are increased. Thus the primary source of water may be functionable after a seismic event accompanied by liquefaction.

If a hypothetical sealing of the intake canal headwall structure is assumed, then a reservoir (the intake canal is 220 feet wide by 30 feet deep by 6,000 feet long) is formed from the headwall structure to the intake structure housing the ICW pumps. The water trapped in the intake canal is 63,000,000 gallons. With liquefied slopes, (20:1 final surface slope) and a canal low point elevation of

-10 feet, this volume is reduced to 43,000,000 gallons. This large reservoir can supply a single units' ICW requirement for 65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br /> and, if liquefied slopes are assumed, for 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />.

A localized flow slide in the intake canal has been postulated and analyzed. The slide was configured such that a weir is formed in the intake canal. The weir is assumed to result from a slide based on limiting historic data (1:10, see Section 2.5.5). With two units in operation a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> supply of water is available in the intake canal to provide for shutdown cooling. Thus there is ample time to affect communication between Big Mud Creek and the intake bay.

The UHS intake canal is designed to remain open after a dike failure or liquefaction occurrence.

A liquefaction analysis as described in Section 2.5.5 was performed on the UHS intake canal. This analysis shows that a minimum cross section below low water level of 2000 sq ft would remain following a DBE. This area is 15 times the minimum cross sectional area required to carry the design flow. The channel from the Intracoastal Waterway to Big Mud Creek was originally dredged to a 12 x 125 profile, however due to the dynamic conditions of the River, silting has occurred to fill this channel back to its original profile in various locations. Therefore liquefaction is not an issue for the Barge Channel. The existing channel provides adequate flow under normal conditions. The average depth of the channel is -5 MLW with the narrowest point entering the Creek being over 500.

Conservatively assuming a 2 water depth during normal conditions, this allows more than 850 cfs to enter the Creek (assuming a 1 fps velocity). This equates to a flow of more than 6 times that required for a maximum shutdown cooling water flow of 58,000 gpm (assuming operation of both intake cooling water pumps for each unit). Extreme low water conditions are postulated only as the result of extreme low tides coincident with the effects of a worst case stalled or looped hurricane located north of the plant. Under these postulated conditions, the channel bottom elevation has the potential of being at -3.0 MLW or higher due to silting, with an extreme low water condition occurring at -3.0 MLW. In this scenario Big Mud Creek has the potential of being isolated from the River. The specific conditions required for this scenario include a seismic event (failure of the intake Canal due to liquefaction) coincident with a hurricane and extreme low water. This combination of events is considered not credible.

A seismically capable UHS barrier wall separates the UHS canal and the intake canal. Valves in this wall open to ensure availability of intake cooling water from Big Mud Creek in the highly unlikely event that the primary source of water is unavailable. Thus loss of the UHS due to an extreme natural phenomenon has been precluded by design.

9.2-35 Amendment No. 22 (05/07)

9.2.7.4 Testing and Inspection Valves provided in the barrier wall which prohibit flow from Big Mud Creek to the intake canal are tested as specified by the technical specifications. These devices are tested individually and in accordance with the restrictions on the quantity of water that may be withdrawn from Big Mud Creek as imposed by local, state, and federal authorities.

9.2.7.5 Instrumentation Application Redundant seismic Class I intake structure water level switches alert the control room operator if ever the low water level in the intake canal drops below -9 ft MLW with the UHS available as a redundant supply.

9.2-36

9.2.8 CONDENSATE STORAGE SYSTEM 9.2.8.1 Design Bases The condensate storage system is designed to:

a) provide feedwater for the auxiliary feedwater system; b) provide deaerated makeup water for the condenser hotwell and serve as a return for excess hotwell water under normal operation; and c) withstand the effects of the design basis earthquake (DBE), tornado, or PMF without loss of function.

9.2.8.2 System Description The condensate storage system is shown schematically in Figures 10.1-2(a-d).

The condensate storage system consists of a 250,000 gallon condensate storage tank which serves as a source of feedwater for the auxiliary feedwater system. The tank also serves as a source of makeup water for the condenser hotwell, and return for excess hotwell water under normal operations.

A slight positive pressure is maintained within the tank by the use of a nitrogen blanketing system to prevent any accumulation of air.

Approximately 130,500 gallons of water are required for cooldown of the reactor coolant system to 325°F, the upper temperature for starting operation of the shutdown cooling system (no RCPs, using 2 ADVs).

Alarms are sounded in the control room and at the water treatment panel on low and high water level. A low-low level is alarmed in the control room to prevent over-heating of the auxiliary feedwater pumps should the condensate level drop to minimum pump suction requirements. The low level alarm is initiated at a tank volume of ~185,000 gallons and the low-low level alarm at ~34,500 gallons. Continuous redundant indication is provided in the control room.

Refer to Section 10.5 for further discussion of the auxiliary feedwater system emergency feedwater requirements and the intertie to the Unit 2 condensate storage tank.

Design data for the condensate storage tank is given in Table 9.2-16.

9.2.8.3 System Evaluation The condensate water is expected to contain insignificant radioactivity; therefore, no provision has been made to measure radioactivity released from this source. Periodic grab samples are taken and analyzed to determine the amount of dissolved oxygen.

9.2-37 Amendment No. 26 (11/13)

The tank is designed as seismic Class I and is enclosed by a vertical concrete missile barrier with no protection on top for vertical missiles. See Appendix 3F for discussion of the basis for CST missile protection. A discussion of the seismic requirements for the condensate system piping is given in Section 10.4.6.

9.2.8.4 Testing and Inspection Prior to installation into the system the condensate storage tank was inspected and cleaned.

9.2.8.5 Instrumentation Application The condensate storage tank level is monitored by redundant safety related level monitoring channels. Continuous annunciation and indication of condensate level in the storage tank is provided in the control room. The low level setpoints are selected to provide at least 20 minutes for operator action assuming that the largest capacity AFW pump is operating. Control room indicators are listed in Table 7.5-2.

Table 10.5-2 lists the function of the instrumentation provided on the condensate storage tank and Table 7.4-1 lists instrumentation required to monitor a safe shutdown.

9.2-38 Amendment No. 22 (05/07)

9.2.9 STEAM GENERATOR BLOWDOWN COOLING SYSTEM (SGBCS) 9.2.9.1 Design Bases The steam generator blowdown cooling system is provided to reduce the temperature of the blowdown stream such that the following design criteria are achieved:

a) the blowdown stream temperature entering the blowdown treatment facility building is less than the maximum temperature allowed for processing in the blowdown demineralization system; and b) the discharge of blowdown cooling water will be in compliance with the National Pollutant Discharge Elimination System (NPDES) permit governing thermal effluents.

The cooling system is not required to achieve and/or maintain a plant shutdown, or to mitigate the consequences of an accident. Thus, the system is not safety related, and is designed as a non-safety related system.

9.2.9.2 System Description The steam generator blowdown cooling system consists of two subsystems, namely, the closed blowdown cooling system (CBCS), and the open blowdown cooling system (OBCS). The CBCS consists of closed loop. CBCS coolant removes thermal energy from the blowdown during passage through the closed blowdown beat exchangers and transmits this energy to the OBCS during passage through the blowdown heat exchangers. The OBCS transports the blowdown energy to the turbine cooling water portion of the ICW system. A diagram of the SGBCS is provided on the Steam Generator Blowdown Flow Diagrams, Figures 10.4-1, -2, and -3.

Each subsystem has 100 percent redundancy such that the design will accommodate a blowdown rate in excess of 125 gpm per steam generator (greater than 250 gpm total) with only one OBCS heat exchanger and two out of three CBCS heat exchangers in service.

9.2.9.2.1 Closed Blowdown Cooling System (CBCS)

The CBSC coolant is demineralized water buffered with a corrosion inhibitor. System chemistry is measured periodically, and an inhibitor is added as required. Automatic regulation of chemistry is not provided.

The coolant is circulated through the CBCS loop by one of two 100 percent capacity pumps. Three 50 percent capacity closed blowdown heat exchangers and a surge tank are incorporated in the design. The surge tank provides a reservoir for the CBCS, compensates for thermal expansion and shrinkage of coolant and provides a positive head on the system. Component design data is provided in Table 9.2-17.

9.2-39 Amendment No. 16, (1/98)

Makeup to the system is automatically supplied to the surge tank. Control room annunciation is provided on both high and low surge tank level, and the CBCS pumps can be started and stopped locally from the control room.

9.2.9.2.2 Open Blowdown Cooling System (OBCS)

Coolant for the OBCS is provided by the turbine cooling water portion of the intake cooling water system upstream of the turbine cooling water heat exchangers. The system flow of 5600 gpm can be supplied by the two connections from the intake cooling water lines. After passing through the open blowdown heat exchangers the water is routed downstream of the turbine cooling water heat exchangers and exits into the discharge canal.

The maximum design temperature rise through the open blowdown heat exchangers is approximately 25 F. The normal rise will be dependent on the rate of blowdown flow. A normal temperature rise of considerably less than 20 F is anticipated. The OBCS is designed such that one open blowdown heat exchanger is required for a unit blowdown rate of 250 gpm or greater. Heat exchanger design data are provided in Table 9.2-17.

9.2.9.3 System Evaluation This system is not required for safe shutdown or for mitigating the consequences of an accident. It is, however, required to support normal plant operations. Sufficient redundancy is provided to ensure SGBCS availability. For unit blowdown rates of 250 gpm, two of three closed blowdown heat exchangers, one of two CBCS pumps, one of two open blowdown heat exchangers, and two of three intake cooling water pumps are required.

9.2.9.4 Testing and Inspections The SGBCS is in service during normal plant operations and thus its performance is monitored as required by the plant operating staff to insure its continuing availability.

9.2.9.5 Instrumentation Application Instruments are provided as required to monitor system operation. The number, type, and location of these instruments are shown on Figure 10.4-3.

9.2-40 Amendment No. 16, (1/98)

REFERENCES FOR SECTION 9.2

1. FPL letter from J. A. Stall to Mr. William A. Passetti, Department of Health, Bureau of Radiation Control, Radioactive Materials Section, dated 8/14/97.
2. Florida Department of Health letter from William Passetti to J. A. Stall, dated September 3, 1997.
3. Evaluation PSL-ENG-SEMS-02-043, Rev. 4, ICW Performance Curves.
4. ALION-REP-PSL-7994-013, Evaluation of St. Lucie Plant Unit 1 and Unit 2 High Risk Non-ECCS Systems Susceptibility to Gas Intrusion, Rev. 4.
5. ALION-REP-PSL-7994-014, Evaluation of St. Lucie Plant Unit 1 and Unit 2 CCW System Susceptibility to Gas Intrusion, Rev. 0.

9.2-40a Amendment No. 26, (11/13)

TABLE 9.2-1 DESIGN DATA FOR INTAKE COOLING WATER SYSTEM

1. Intake Cooling Pumps Type Single stage, vertical Quantity 3 Capacity, each, gpm 14,500 Head, feet 130 Design temperature, F 95(max) - 40(min)

Material Case Type 316 SS Impeller Type 316 SS Shaft Stainless Steel or Monel Motor 600 hp, 4000 v, 3 phase, 60 hz, 885 rpm, with 1.15 Service Factor Motor enclosure WP II

2. Lube Water ICW pumps are self-lubricating
3. Codes NEMA, Standards of the Hydraulic Institute ASME Section VIII, ASTM, and ANSI, Nuclear Pump and Valve Code Class III
4. Discharge Piping Material (above ground) 14 inch and larger 3/8 inch wall carbon steel pipe EC 289023 with 1/8 inch cement lining or AL6XN or stainless steel for Class I piping or cast iron or ductile iron with cement lining non-Class I piping 4 inch to 12 inch Std wall carbon steel pipe with 1/8 inch cement lining/stainless steel/AL6XN EC 289023 3/4 inch to 3 1/2 inch Aluminum bronze/aluminum brass/

EC 289023 Monel/carbon steel/stainless steel/AL6XN 1/2 inch and under Aluminum bronze/carbon steel/

Monel/stainless steel (TP 316/254)/

Hastelloy/Titanium UNIT 1 9.2-41 Amendment No. 31 (11/21)

TABLE 9.2-1 (Cont'd)

Connections Cement Lined Steel 2 inches and smaller Screwed 2 1/2 inches and larger Flanged Cast Iron or Ductile Iron 2 inches and smaller Flanged 2 1/2 inches and larger Flanged Aluminum Bronze/Aluminum Brass/Monel/Stainless Steel 3/4 inch to 3 inch Screwed/Flanged or Welded Aluminum Bronze/Aluminum Brass/Monel/Hastelloy/Stainless Steel/(TP316&254)/ Titanium 1/2 inch and under Screwed/Welded or Compression AL6XN EC 289023 2 1/2 inch and larger Flanged or welded 2 inch and smaller Flanged or welded

3. Valves 1/2 inch and under Bronze/Hastelloy/Stainless Steel (TP 316/254) -

Screwed/Compression 3/4 inch to 2 inch Aluminum Bronze/Bronze / Stainless Steel- screwed, flanged or welded 2 1/2 inch and larger: Carbon Steel - rubber or polymer epoxy lined; cast, stainless EC 289023 steel-flanged or wafer or welded Code ANSI - B31.7, Class III - and ANSI - B31.1 ASME-III, Safety Class 3, Seismic Category I System design pressure, psig 90 EC 289023 System design temperature, F 125 9.2-42 Amendment No. 31 (11/21)

TABLE 9.2-2 SINGLE FAILURE ANALYSIS - INTAKE COOLING WATER SYSTEM Component Identification Method of and Quantity Failure Mode Effect on System Detection Monitor Remarks Offsite power Lost ICW pumps trip and automa- Various loss-of- CRI One ICW pump & header is tically restart on emer- power alarms adequate to supply the gency diesel generator required cooling water power. to one component cooling HX.

ICW pump suction Clogged Loss of suction for one Pump header dis- CRI Operator may start stand-(3) full capacity ICW pump. charge low pres- by pump & realign header Operator must stop pump. sure alarm cross-connect valves (if necessary),to maintain desired flow.

ICW pump (3) Fails Loss of one full capacity Pump header dis- CRI Operator may start stand-ICW pump. charge low pres- by pump & realign header sure alarm cross-connect valves (if necessary),to maintain desired flow.

ICW pump Ruptures Loss of one discharge Pump discharge CRI One ICW pump & header is discharge header header. Operator must iso- header low pres- adequate to supply the re-(2) late ruptured header by sure alarm quired cooling water to realigning cross-connect one component cooling HX.

valves(if necessary),

and ICW pump(s) to maintain desired flow.

Turbine cooling Valve fails to One ICW pump & header will Component cooling CRI One ICW pump & header is water HX isolation close upon SIAS service both one component HX tubeside outlet adequate to supply the valves MV-21-2&3 cooling HX & one turbine flow & temperature required cooling water to (2) cooling HX. indications one component cooling HX.

9.2-43 Amendment No. 24 (06/10)

TABLE 9.2-2 (Cont'd)

Component Identification Method of and Quantity Failure Mode Effect on System Detection Monitor Remarks Component cooling Inlet strainer Significant reduction of Strainer high dif- CRI One ICW pump & header is water HX (2) clogged flow to component cooling ferential pressure adequate to supply the re-HX. Operator must stop alarm & HX outlet quired cooling water to ICW pump. low flow alarm one component cooling HX.

Strainer by-pass line or cross-connect valves SB21190, SB 21237 from water supply line may be opened downstream of strainer.

Air operated Lose air supply Fail open valve - no in- Temperature & CRI temperature control terruption of cooling water flow(l) indications valves flow.

TCV-14-4A&B (2) Fails to open One component cooling Hx Temperature & CRI One ICW pump & header is lost. flow(l) indications adequate to supply the required cooling water to one component cooling Hx.

Air operated debris Lose Power/ Fail Closed Valve - No Temperature & flow (l) CRI discharge valves Air Supply diversion of ICW flow indications HCV-21-7A & Fails to close One component cooling Hx Temperature & flow (l) CRI One ICW pump & header is HCV-21-7B (2) has degraded performance indications adequate to supply the required cooling water to one component cooling Hx.

Strainer Control Panel Lose Power Strainer and Debris Discharge Strainer high differential CRI Alternate dP alarm available.

Valve Lose Power - Valve closes pressure alarm & Hx See remarks above for inlet (No diversion of ICW flow), auto- outlet low flow alarm strainer clogged.

matic strainer backwashing lost Diesel generator One fails to Loss of one ICW pump & Various loss-of- CRI One ICW pump & header is set (2) start header. power alarms adequate to supply the re-quired cooling water to one component cooling Hx.

ICW - Intake cooling water CRI - Control room indication HX - Heat exchanger SIAS - Safety injection actuation signal (1) - Local indication only (2) - The ICW headers A and B are always isolated from each other. Failure of the A header cannot affect the B header, and failure of the B header cannot affect the A header.

9.2-44 Amendment No. 24 (06/10)

TABLE 9.2-3 INTAKE COOLING WATER SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Instru- Normal Control ment Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(4) Range Accuracy(4)

Intake Cooling Water

1) Intake structure
  • 95F(max) temperature
2) Intake structure level (upstream of traveling screen) *
3) Pump discharge pressure
  • 50 psig
4) Pump discharge header pressure *
  • 50 psig Turbine Cooling Water HX Tube Side (2)
1) Inlet strainer dif-ferential pressure *
  • 1.25 psig
2) Inlet water pressure
  • 30-40 psig
3) Inlet water temperature
  • 95 F
4) Outlet water pressure
  • 17.5-27.5 psig
5) Outlet water temperature *
  • 107.5 F
6) Outlet water flow
  • 6250 gpm 9.2-45 Amendment No. 26 (11/13)

TABLE 9.2-3 (Cont'd)

Indication Alarm(1) Instru- Normal Control ment Operating Instrument System Parameter & Location Local Room High Low Recording (1) Control Function Range(4) Range Accuracy(4)

Component Cooling Water HX Tube Side(3)

1) Inlet strainer differential pressure *
  • 1.5 psi
2) Inlet water pressure
  • 25-30 psig
3) Inlet water temperature
  • 95°F
4) Outlet water pressure
  • 13.5-18.5 psig
5) Outlet water temperature *
  • 100°F
6) Outlet water flow *
  • 8250-16,500 gpm Open Blowdown Cooling System HX Tube Side
1) Inlet water pressure 30-40 psig
2) Inlet water temperature 95°F
3) Outlet water press. 20-30 psig Discharge Canal Water Temperature 50-120°F (1) All alarms and recordings are in the control room unless otherwise indicated.

(2) Turbine cooling water HX shell side instrumentation is included in Table 9.2-12.

(3) Component cooling water HX shell side instrumentation is included in Table 9.2-7.

(4) Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.2-46 Amendment No. 25 (04/12)

TABLE 9.2-3A PROCEDURE FOR VISUAL INSPECTION OF WELDS (1)

Inspection Point Connection Procedure per Ebasco General Power Piping Specification 62-69T Prior to fit-up Butt Joints and Branch Connections Joints shall be inspected prior to fit-up to ensure that the piping is clean and that the end preparations are clean and dimensionally correct. End preparations with rough surfaces shall be smoothed with emery cloth or sanding discs. The following shall be thoroughly cleaned to remove all scale, rust, grease, oil stain or other foreign material;

- Internal surfaces near weld end.

- Both pipe end preparations.

- External surfaces near weldend.

- Consumable weld inserts.

- Backing Rings.

At fit-up Butt Joints and Branch Connections Joints shall be inspected at fit-up to ensure that approved joint dimensions and methods of supporting the pipes are met.

Just prior to welding, the joint groove faces and insert shall be wiped clean using a lint-free cloth moistened with acetone.

It shall be assured that there are no flammable fumes when welding is performed. No welding shall be permitted on metal which is wet or damp in the weld groove or in the vicinity of the weld groove. When it is necessary to prevent condensing moisture, the metal shall be preheated until it is at least warm to hand touch.

9.2-47 Amendment No. 16, (1/98)

TABLE 9.2-3A (Cont'd)

Root Welds Outside Surface Butt, branch connection, socket and fillet joints shall be inspected on the outside surface after fusing the consumable insert or welding the first layer with filler metal. The sur-face shall be wire brushed and examined. The weld surface shall not contain cracks, laps, blowholes, crater pits, tungsten inclusions and arc strikes outside of the weld groove.

Inside Surface - Butt Joints and Branch Con-nections Joints shall be inspected on the internal weld surface after completion of welding if the area is accessible. It is intended that gamma ray access ports, when available, afford accessibility for internal visual inspection by using fiber optical viewing devices or borescopes. Complete accessibility infers that a man can enter a pipe or component and inspect.

The internal weld-bead and adjacent base metal surfaces shall be free of "surgaring" (thick rough oxide due to loss of purge).

Thin smooth temper films shall be accepted. The weld-bead shall show complete fusion and shall be free of sharp protrusions, recessions, or overlap. Metal/bead edge-angles shall not be less than 90 degrees. Bead height including lumps shall not exceed 3/32 inches. Well rounded depressions (suckback) are permitted up to 1/16 inch deep provided the width is at least three times the depth, and the thickness through the weld is nowhere less than adjacent base metal thickness.

In the case of complete accessibility, examination with 5-power glass shall be performed. The examination shall be made with adequate lighting and the inspected weld and base metal surfaces shall not contain cracks, laps, cold shuts, incomplete fusion, crater pits, blowholes and arc strikes outside of the weld groove.

9.2-48

TABLE 9.2-3A (Cont'd)

Completed Butt Joints and Welds Branch Connections Joints shall be inspected on the external surface to ensure that the weld surface is at least flush with the base metal and does not exceed the following thickness of weld reinforcement requirements:

Maximum Thickness of Material Thickness-Inches Reinforcement of Crown-Inches Up to 1/2 inch 1/16 Over 1/2 to 1 inch 3/32 Over 1 to 2 inch 1/8 Over 2 5/32 The undercut at the edges of the weld shall be rounded and shall not exceed 1/64 inch while maintaining minimum wall thickness and surfaces shall be cleaned of slag and shall be free of cracks, blowholes, laps, lack of fusion, cold shuts and similar defects. The weld surface shall be satisfactory for radiography and liquid penetrant or magnetic particle inspection as described in Section 1B, IIIB, IVB and VB of Ebasco Specification 73.

The base metal at the weld area shall not contain arc strikes.

Reporting For shop welds, seller shall provide a certificate of compliance verifying compliance with the requirements set forth in the engineering specification.

For field welds of the "N" CCW header, field QC verified compliance with these welding procedures.

Notes:

(1) Information provided in this table is considered historical.

9.2-49 Amendment No. 16, (1/98)

TABLE 9.2-4 DESIGN DATA FOR COMPONENT COOLING SYSTEM COMPONENTS

1. Component Cooling Pumps Type Centrifugal, horizontal split, double suction pumps Quantity 3 Capacity, each, gpm 8500 Head, feet 177 to 182 Design pressure, psi 150 Design temperature, F 185 Material Case ASTM A-216-Gr-WCB steel Impeller ASTM A-216-Gr-WCB steel Shaft SAE 4140 stainless steel Motor 450 hp, 4000 V, 60 hz, 3 phase, 1800 rpm Enclosure WP II Codes Motor: NEMA, Pump: Standards of the Hydraulic Institute; ASME Sections VIII and IX Draft Nuclear Pump & Valve Code Class III
2. Component Cooling Water Heat Exchangers Type Horizontal, counterflow, straight tubes rolled into tubesheets Quantity 2 Flow, lb/hr Shell side Tube side Normal 5.55x106 8.50x106 Shutdown (Max) 7.35x106 8.50x106 Design duty, each, Btu/hr 55.0 x 106 (normal) 165.0 x 106 (3.5 hrs after shutdown) 9.2-50

TABLE 9.2-4 (Cont'd) 65.0 x 106 (27.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after shutdown)

See Reference 9 in Section 6.2.1 for the accident heat load.

Heat transfer area, each, ft2 18,250 Design pressure, psig Shell side: 150; Tube side: 90 Design temperature, °F Shell side: 185; Tube side: 150 Material Shell Carbon steel ASTM A 515, Gr 70 Tubes Aluminum Brass SB 111 Alloy #687 Tubes Sheets Aluminum Bronze ASTM B-171 Type D Codes ASME Section VIII, TEMA Class R ASME Section III Class III

3. Surge Tank Type Horizontal Quantity 1 Design pressure, psig 50 Reduced to 50 PSIG to provide a EC289048 corrosion allowance for the tank Design temperature, °F 150 Volume, gallons 2000 Material Shell ASTM A-283 Grade C steel Dished head ASTM A-283 Grade C steel Baffle ASTM A-283 Grade C steel Code ASME Section III, Class III
4. Chemical Addition Tank Type Vertical Quantity 1 9.2-51 Amendment No. 29 (10/18)

TABLE 9.2-4 (Cont'd)

Design pressure, psig 150 Design temperature, °F 450 Volume, gal 50 Material Carbon steel SA-285-C Code ASME Section VIII Div. 1 5 Piping, Fittings and Valves Piping material Carbon steel, ASTM A 106 Gr B Seamless Design pressure, psig 150 Design temperature, °F 200 Construction:

2-1/2" and larger Butt welded except at flanged connections 2" and smaller Socket welded or screwed except at flanged connections Valves:

2-1/2" and larger Gate and globe Carbon steel, butt weld ends ANSI 150 psi Check, butterfly and ball Carbon steel, stainless steel and cast iron, flanged and/or wafer. ANSI 150 psi and 125 psi.

2" and smaller Carbon steel, socket weld ends, ANSI 150 to 600 psi Codes ANSI B31.1 and ANSI B31.7, Class III Penetration Piping is designed fabricated to ANSI B31.7 Class II Draft Nuclear Pump & Valve Code Class Il & III as applicable 9.2-52 Amendment No. 22 (05/07)

TABLE 9.2-5 OPERATING FLOW RATES AND CALCULATED HEAT LOADS FOR ALL AUXILIARY EQUIPMENT COOLED BY THE COMPONENT COOLING WATER SYSTEM Heat Load/Unit Flow/Unit Equipment Description (Btu/hr x 106) (gpm)

Reactor coolant pump motor oil cooler & seal jacket cooler 0.66 45 Reactor coolant pump motor air cooler 0.82 164 Shutdown heat exchanger 87.90(1) 4850(1) 28.33 4850 Letdown heat exchanger 20.7(2) 1275(2) 2.7 150 CEDM air cooler 2.23 200 Fuel pool heat exchanger 35.5 3560 High pressure safety injection pumps negligible 24 Low pressure safety injection pumps negligible 10 Containment spray pumps negligible 10 Boric acid evaporator condensate cooler 11.5 675 Waste evaporator condensate cooler 1.15 115 Waste gas compressor aftercooler jacket negligible 1.0 Containment fan cooler 0.75(3) 1200 Sample heat exchanger 0.52 35 EC284136 (1) The maximum heat load of 87.9 x 106 Btu/hr occurs 3 1/2 hours after shutdown and reduces gradually to 28.33 x 106 Btu/hr after 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> after shutdown. During refueling operations the heat load on the heat exchanger is expected to be 28.33 x 106 Btu/hr per shutdown heat exchanger.

(2) Maximum heat load of 20.7 x 106 Btu/hr occurs during load change only. Normal steady power heat load is only 2.7 x 106 Btu/hr. However, to accommodate the load changes without increase in temperature 1275 gpm has been considered with a heat load of 20.7 x 106 Btu/hr.

(3) Based on original analysis with three fan coolers normally operating. See Ref. 9 in Section 6.2.1 for the accident heat load.

UNIT 1 9.2-53 Amendment No. 29 (10/18)

PAGE LEFT INTENTIONALLY BLANK 9.2-54 Amendment No. 12, (12/93)

Table 9.2-6 SINGLE FAILURE ANALYSIS - COMPONENT COOLING WATER SYSTEM Component Identification Method of and Quantity Failure Mode Effect on System Detection Monitor Remarks Off-site power Lost CCW pumps trip and automatically Various loss of CRI One CCW pump & one CCW HX restart on emergency diesel power alarms are adequate to cool reactor generator power. coolant system & auxiliary systems in an emergency.

CCW pump suction Valve I-SB-14 Loss of suction for one CCW pump. CCW HX outlet high CRI Operator may start standby pump line (3) inadvertently Operator must stop pump. temperature alarm & realign header cross-connect closed valves I-MV-14-1 or 2 (if necessary) to maintain desired flow.

CCW pump (3) Fails Loss of one full capacity CCW HX outlet high CRI Operator may start standby pump CCW pump. temperature alarm & realign header cross-connect valves I-MV-14-1 or 2 (if necessary) to maintain desired flow.

CCW HX outlet Valve I-SB-14-1A Loss of one essential sup- CCW HX outlet low CRI Two CCW pumps & one HX are Line (2) or 1C inadvert- ply header system. pressure & low flow adequate to cool reactor coolant ently closed alarms system & auxiliary systems during normal operation. Operator may realign cross-connect valves 1-MV-14-1 or 2 with two CCS pumps to maintain desired flow.

Essential headers Ruptures Loss of essential CCW Various loss of flow CRI One CCW pump & one CCW HX A & B (2) supply system. & low pressure are adequate to cool reactor alarms coolant system & auxiliary systems in an emergency.

9.2-55 Amendment No. 22 (05/07)

TABLE 9.2-6 (Cont'd)

SINGLE FAILURE ANALYSIS - COMPONENT COOLING WATER SYSTEM (Contd)

Component Identification Method of and Quantity Failure Mode Effect on System Detection Monitor Remarks Nonessential supply Loses air supply Fail closed valves - flow Valve position CRI Safety related equipment cooling header main isolation discontinued through non- indicating lights requirements are available from HCV-14-8A/B essential supply header N. the valve (pneumatic) (4)

I-HCV-14-9/10 Essential supply headers A & B non-affected essential header.

isolated from each other.

Valve fails to At least one essential header Valve position CRI Safety related equipment cooling close upon SIAS isolated from header N. Essential indicating lights requirements are available from two headers A&B isolated from each redundant & independent supply other. systems A & B.

CCW surge tank air Loses air supply Fail closed valve - temporary loss CCW surge tank low CRI Bypass valve V14103 must be operated level of makeup water to surge tank level alarm opened and makeup regulated control valve manually to maintain desired water LCV-14-1 (1) level.

Fails to open Temporary loss of makeup water CCW surge tank low CRI Bypass valve V14103 must be to surge tank. level alarm opened and makeup regulated manually to maintain desired water level.

CCW surge tank (1) Loss of makeup Temporary loss of makeup water CCW surge tank low CRI Valve V15500 can be opened to water to surge tank. level alarm supply required makeup water from the fire protection system.

Diesel generator Fails to start Loss of one essential CCW Various loss-of CRI Safety related equipment cooling set (2) supply system power alarms requirements will be met with one CCW pump & one HX operating in an emergency. Standby pump may be manually connected to available generator bus.

CCW - Component cooling water system CRI - Control room indication HX - Heat exchanger SIAS - Safety injection actuation signal 9.2-56 Amendment No. 22 (05/07)

TABLE 9.2-7 COMPONENT COOLING WATER SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(4) Range Accuracy(4)

Component Cooling Water HX Shell Side (2)

1) Inlet temperature
  • 110 F
2) Outlet temperature * *
  • Modulates tempera- 100 F ture controlled butterfly valve on tube side of HX discharge
3) Outlet pressure * *
  • 80 psig
4) Outlet flow * *
  • 5600-11200 gpm
5) Outlet radiation *
  • On high radiation, 0 closes component cooling water surge tank vent valve and routes the water vapor through the waste management system Shutdown HX Shell Side (3)
1) Outlet temperature *
  • 150 F
2) Outlet flow * *
  • 4850 gpm Fuel Pool HX
1) Outlet temperature *
  • 110-120 F
2) Outlet flow * * *
  • 2850-3700 gpm 9.2-57 Amendment No. 17 (10/99)

TABLE 9.2-7 (Cont'd)

COMPONENT COOLING WATER SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(4) Range Accuracy(4)

Containment Cooling Unit

1) Outlet temperature
  • 102°F
2) Outlet flow *
  • 1200 gpm Control Element Drive Mechanism Air Cooler
1) Oulet temperature
  • 115°F
2) Outlet flow *
1) Flow *
  • 209 gpm
2) Temperature
  • 200°F Component Cooling Water Surge Tank
1) Level * *
  • Controls valving 36-48" make-up flow into tanks via LCV 14-1
2) Integrated make-up flow -

High Pressure Safety Injection Pump Cooling Water

1) Outlet temperature
  • 100°F
2) Outlet flow
1) Outlet temperature
  • 100°F
2) Outlet flow
  • 10 gpm 9.2-58 Amendment No. 22 (05/07)

TABLE 9.2-7 (Cont'd)

COMPONENT COOLING WATER SYSTEM INSTRUMENTATION APPLICATION (Contd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(4) Range Accuracy(4)

Low Pressure Safety Injection Pump Cooling Water

1) Outlet temperature
  • 100°F
2) Outlet flow

Cooling Water

1) Outlet temperature
  • 115°F
2) Outlet flow
1) Outlet temperature
  • 115°F
2) Outlet flow
  • Waste Gas Compressors Cooling Water
1) Outlet temperature
  • 115°F
2) Outlet flow
  • Component Cooling Water
  • 100 psig Pump Discharge Pressure 9.2-59 Amendment No. 25 (04/12)

TABLE 9.2-7 (Cont'd)

COMPONENT COOLING WATER SYSTEM INSTRUMENTATION APPLICATION (Contd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(4) Range Accuracy(4)

Letdown HX:

1) Outlet temperature *
  • 100°F - 140°F
2) Outlet flow * *
  • 80/190 gpm
3) Inlet Temperature * * * (6) 65°F - 95°F (1) All alarms and recordings are in the control room unless otherwise indicated (2) Component cooling water HX tube side instrumentation is contained in Table 9.2-3 (3) Shutdown HX tube side instrumentation is contained in Table 6.2-11 HX - Heat Exchanger (4) Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

(5) Boric acid and waste concentrators are no longer used and have interfaces isolated.

(6) Provides a signal to the Letdown HX Temperature Controller to adjust response for varying CCW Temperature.

UNIT 1 9.2-60 Amendment No. 28 (05/17)

TABLE 9.2-8 DESIGN DATA FOR CIRCULATING WATER SYSTEM COMPONENTS

1. Circulating Water Pumps Type Single stage, vertical removable element, mixed flow Quantity 4 Capacity, each, gpm 121,000 Head, feet 40 Material Case 2 percent Ni-Cast Iron, ASTM-A-48, Cl 30 Impeller ASTM A-296 CF3M Shaft ASTM A-276 Type 316 SS Motor Constant speed, 1500 hp, 400OV, 60hz, 3 phase, 360 rpm, with 1.15 Service Factor Enclosure WP II Codes NEMA, Standards of the Hydraulic Institute, ASME Section VIII.
2. Traveling Water Screens Type Vertical, through-flow, 10° Incline Quantity 4 Screen velocity, ft/min 10 & 20 Material Screen Stainless Steel Frame & Baskets Stainless Steel & Fiberglass
3. Screen Wash Pumps Type Five stage, vertical, turbine, wet pit Quantity 2 9.2-61 Amendment No. 18, (04/01)

TABLE 9.2-8 (Cont'd)

Capacity, each, gpm 1060 Head, feet 250 Material Case 2 percent Ni cast iron Impeller Type 316 SS Shaft Type 316 SS Motor 100 hp, 460 v, 3 phase, 60 hz, 1770 rpm Enclosure TEFC Codes NEMA, Standards of the Hydraulic Institute, ASME Section VIII.

4. Debris Filters Type Automatic (Self Cleaning)

Quantity 4 Pressure, psig 50 Temperature, F 125 Design Diff. Press., psid 45 Shell Material ASTM-A-240, Type 316Ti Perforation Size, mm 5 Code ASTM-F1199

5. Ball Strainers (Condenser Tube Cleaning System)

Type Inverted "V" Quantity 4 Pressure, psig 50 Temperature, F 125 Design Diff. Press., psid 20 Shell Material ASTM-A-240, Type 316Ti Strainer Grill Spacing, mm 5 Code ASTM-F1199 9.2-62 Amendment No. 18, (04/01)

TABLE 9.2-8 (Cont'd)

6. Ball Recirculation Pumps (Condenser Tube Cleaning System)

Type Single Stage, Non-clogging Centrifugal Quantity 4 Capacity, each, gpm 270 Head, feet 56 Case/Impeller Material AL6XN Motor 7.5 hp, 460v, 3 phase, 60hz, 1750 rpm Enclosure TEFC (Submersible)

Codes NEMA, Standards of the Hydraulic Institute

7. Ball Collector (Condenser Tube Cleaning System)

Type Manual Quantity 4 Pressure, psig 50 Temperature, F 125 Shell Material ASTM-A-285, Grade C (Rubberlined)

Code AD-Merkblatter Series B (German)

8. Piping, Fittings and Valves Pressure, psig 50 Temperature, F 135 (max)

Pipe material 3 1/2 inch and above Below ground Concrete Above ground Cast Iron, Cement Lined or Ductile Iron, Cement Lined/Reinforced Thermosetting Resin (RTR)

Fiberglass, Alloy (SS or Nickel) 9.2-62a Amendment No. 16, (1/98)

TABLE 9.2-8 (Cont'd)

Pipe material 3/4 inch to 3 inch Aluminum Brass/Aluminum Bronze/Monel 400/Carbon Steel (with internal coating)/Cast Iron or Ductile Iron (cement lined)/Reinforced Thermosetting Resin (RTR)

Fiberglass/PVC/CPVC, Alloy (SS or Nickel) 1/2 inch and under Aluminum Brass/Aluminum Bronze/Monel 400/Stainless Steel/Hastelloy/Titanium Valves 3 inches and above Cast Iron, Flanged, Rubberlined/Steel, Flanged, Rubberlined or Wafer/PVC, Flanged or Stainless Steel, Flanged 3/4 inch to 2 1/2 inch Bronze/PVC, Screwed and/or Flanged 1/2 inch and under Bronze/6 Moly Stainless Steel/Hastelloy, Screwed and/or Compression Code ANSI B31-1, B16.34 9.2-62b Amendment No. 17 (10/99)

TABLE 9.2-9 CIRCULATING WATER SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

Circulating Water Pumps

1) Discharge pressure
  • 16.4 psig
2) Lubricating water flow *
  • Pump start per- 6-10 gpm missive Discharge Valve Position Pump start per- -

missive for minimum opening Circulating Water Debris Filters

1) Differential Pressure *
  • Initiate Backwash of 30-60 in WC Debris Filter Condenser
1) Inlet temperature (one leg on
  • 95F each condenser)
2) Discharge temperature
3) Chlorine residual * (2) -
4) Differential Temperature * *

(Average of all four condensers) 29F Condenser Tube Cleaning System Ball Strainers

1) Differential Pressure *
  • 10-25 in WC Discharge Canal
1) Water temperature * *
  • 50-120F
2) Water level * * *

(1) All alarms and recordings are in the control room unless otherwise indicated.

(2) Located in the residual chlorine cabinet in the turbine building.

(3) Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.2-63 Amendment No. 26 (11/13)

TABLE 9.2-10 DESIGN DATA FOR TURBINE COOLING WATER SYSTEM COMPONENTS

1. Turbine Cooling Water Heat Exchangers Type Horizontal, straight tube, single pass Quantity 2 Design duty, each, Btu/hr 37.5 x 106 Heat transfer area, each, ft2 16,068 Gross; 15,922 Effective Design pressure, psig 150 shell side, 90 tube side Design temperature, F 150 shell side, 150 tube side Material Shell ASME SA-516, GR. 70 Tubes ASME SB-676, AL6XN Tube Sheet ASME SA-516, GR. 70 (AL6XN Clad)

Codes TEMA, Class B, ASME Section VIII

2. Turbine Cooling Water Pumps Type Horizontal Centrifugal Quantity 2 Capacity, each, gpm 5100 Head, feet 152 Material Case Cast Iron Impeller Bronze Shaft Steel Motor 250 hp, 4000 v, 3 phase, 60 Hz, 1180 rpm 9.2-64 Amendment No. 26 (11/13)

TABLE 9.2-10 (Cont'd)

Enclosure WP-II Codes NEMA, Standards of Hydraulic Institute, ASME VIII

3. Turbine Cooling Water Surge Tank Type Horizontal Quantity 1 Design pressure Atmospheric Design temperature, F 125 Volume, gallons 1000 Material ASTM A-283 Gr C Code ASME Section VIII EC289939 9.2-65 Amendment No. 29 (10/18)

TABLE 9.2-11 TURBINE PLANT COMPONENTS OPERATING FLOW TOTAL RATES AND CALCULATED HEAT LOADS Total Flow Heat Load/Unit Component Description (gpm) (Btu/hr x 106)

Turbine lube oil coolers 2900 gpm 8.45 Turbine E-H fluid coolers 40 Negligible Hydrogen seal oil units (Hydrogen Side) 100 0.32 (Air Side) 260 1.0 Isolated phase bus air coolers (per cooler) 150 1.486 Hydrogen coolers (Total for Quantity of 4) 4500 58.2 Exciter air cooler units 200 <1.61 Heater drain pumps seal coolers 13 Negligible Feedwater pumps oil coolers 20 Negligible Condensate pumps motor bearing coolers 10 Negligible Instrument air compressors (1A, 1B, 1C & 1D) 58 EC283796 Sample cooler, secondary system 10 Negligible Hydrogen Gas Dryer 4.8 Negligible Sample System Primary Coolers 30 0.2 UNIT 1 9.2-66 Amendment No. 29 (10/18)

TABLE 9.2-12 TURBINE COOLING WATER SYSTEM INSTRUMENTATION APPLICATIONS Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

Turbine Cooling Water Pump

1) Suction pressure
  • 10-15 psig
2) Outlet pressure
  • 70-75 psig Turbine Cooling Water HX Shellside (2)
1) Outlet temperature * *
  • Controls intake 99°F cooling water flow through tube side of HX by means of tem-perature control valves TCV-13-2A,2B
2) Outlet header pressure
  • 70 psig
3) TCW HX Inlet Flow Indicators
  • 0-7,000 GPM 4,281 GPM Turbine Electro-Hydraulic Fluid Coolers-
1) Outlet flow
  • 40gpm
2) Outlet temperature
1) Outlet temperature
  • 110°F
2) Inlet header flow
1) Air side coolers a) Inlet flow
  • 260gpm b) Outlet temperature
  • 110°F 9.2-67 Amendment No. 26 (11/13)

TABLE 9.2-12 (Cont'd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

2) Hydrogen side coolers a) Inlet flow
  • 100 gpm b) Outlet temperature
1) Inlet header flow
  • 4500 gpm
2) Outlet temperature
1) Inlet header flow
  • 200 gpm
2) Inlet header pressure
  • 50 psig
3) Outboard exciter cooler
  • 114°F outlet temperature
4) Inboard exciter cooler
  • 114°F outlet temperature Isolated Phase Bus Air Coolers & H2 Gas Dryer
1) Inlet header flow
  • 150-300 gpm
2) Outlet temperature
  • 118.8°F
3) Outlet flow from each cooler * *
  • 150 gpm Instrument Air Compressor (1A, 1B)
1) Intercooler, Oilcooler and Aftercooler EC283796 a) Outlet temperature *
  • 143F b) Outlet flow
  • 10 gpm 9.2-68 Amendment No.29 (10/18)

TABLE 9.2-12 (Cont'd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

Instrument Air Compressor (1C, 1D)

1) Intercooler, Oilcooler, and Aftercooler EC283796 a) outlet temp *
  • 124F b) outlet flow
  • 48 gpm EC283796 9.2-68a Amendment No. 29 (10/18)

TABLE 9.2-12 (Cont'd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

Condensate Pumps & Motor Cooling

1) Motor bearing cooler outlet a) temperature
  • 110F b) flow *
1) Outlet flow
  • 20 gpm UNIT 1 9.2-69 Amendment No. 28 (05/17)

TABLE 9.2-12 (Cont'd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

2) Outlet temperature
  • 110°F Heater Drain Pumps
1) Seal Cooler outlet a) temperature 125° F b) flow 6.5 gpm (per cooler)

Turbine Cooling Water Surge Tank

1) Level * *
  • Regulate flow to Center-tank from conden- line of sate pump by tank means of level control valve LCV-13-1
2) Integrated * -

makeup (gal)

Backup Station Air Compressor

1) After cooler a) outlet temperature * (4) b) outlet flow * (4) 1 All alarms and recordings are in the control room unless otherwise indicated.

2 Turbine cooling HX tube side instrumentation is contained in Table 9.2-3.

HX - Heat Exchanger 3 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

4 B/U STA Air Comp removed from service. Aftercooler assoc. piping & connections installed for future use.

5 Original vendor recommended values. Actual values significantly lower.

9.2-70 Amendment No. 26 (11/13)

Table 9.2-13 Design Data for Makeup Water System Components

1. Primary Water Storage Tank Quantity 1 Capacity, gallons 150,000 Material - Tank Steel, A-283, Grade C Plasite 7155 or Phenoline 368 coating Floating roof Steel A-283 Grade C, Plasite 7155 or Phenoline 368 coating Bumper Urethane Pressure Atmospheric Temperature, °F 125 (max), 30 (min)

Code AWWA-D100

2. Treated Water Storage Tank Quantity 1
3. Primary Water Pump - Quantity 2 Capacity, each gpm 300 Type Horizontal, centrifugal Head, feet 250 Material Casing Stainless steel Shaft SAE 4140 SS Impeller 316 SS Code Motor NEMA Pump Standards of the Hydraulic Institute, ASME Sections VIII and IX, latest applicable addenda 9.2-71 Amendment No. 25 (04/12)

THIS PAGE LEFT INTENTIONALLY BLANK 9.2-72 Amendment No. 14, (6/95)

TABLE 9.2-14 MAKEUP WATER SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(3) Range Accuracy(3)

Primary Water Tank Level (2) * * *

  • Control operation Full make of valve at inlet up - 4 ft.

to primary water tank Primary Water Pump

1) Discharge header pressure
  • Start standby pri-mary pump on low -

pressure

2) Discharge pressure
  • 110 psig 1 All alarms and recordings are in the control room unless otherwise indicated.

2 Alarms in both control room and water treatment panel.

3 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.2-73 Amendment No. 17 (10/99)

TABLE 9.2-15 DESIGN DATA FOR POTABLE AND SANITARY WATER SYSTEM COMPONENTS DATA INTENTIONALLY DELETED 9.2-74 Amendment 14, (6/95)

TABLE 9.2-16 DESIGN DATA FOR CONDENSATE STORAGE TANK Capacity, gallons 250,000 Operating pressure Atmospheric Operating temperature, F 3 0-12 0 Design pressure Atmospheric Design temperature, F 125 Material Epoxy lined carbon steel Seismic design Class I Code AWWA-D100 9.2-75

TABLE 9.2-17 DESIGN DATA FOR STEAM GENERATOR BLOWDOWN COOLING SYSTEM

1. Closed Blowdown Heat Exchangers Type Horizontal, straight tube, single pass(shell side,double pass (tube side)

Quantity 3 Design duty each,Btu/hr 346.x 106 Design pressure, psig 150, shell side; 985, tube side Design temperature, F 250, shell side; 550, tube side Material Channel Carbon Steel Shell Carbon Steel Tubes Monel Codes ASTM Section VIII and Section IX

& TEMAC.

2. CBCS Pumps Type Horizontal, centrifugal Quantity 2 Capacity each, gpm 1400 Head ft 155 Material Case Cast Iron Shaft Steel Motor 100 hp Enclosure NEMA B Codes NEMA, Standards of Hydraulic Institute, ASME Section VIII 9.2-76

TABLE 9.2-17 (Cont'd)

3. CBCS Surge Tank Type Horizontal Quantity 1 Design Pressure Atmospheric Design Temperature, F 150 Volume, Gallons 440 Material Carbon Steel Code ASME Section VIII
4. CBCS Chemical Feed Pot (Abandoned)

Type Vertical Quantity 1 Design Pressure, psig Atmospheric Design Temperature, F 120 Volume, gallons 25 Material Stainless Steel Type 316 Code None

5. Open Blowdown Heat Exchangers Type Counter current, single pass Quantity 2 Design Duty each, Btu/hr. 69.2 x 10 6 Design Pressure, psig 150, shell side;150, tube side Design Temperature, F 250, shell side;150, tube side Material Tubes Aluminium Brass Channel Carbon Steel w/epoxy lining Shell Carbon Steel Code ASME Section VIII and Section IX & TEMAC UNIT 1 9.2-77 Amendment No. 28 (05/17)

Refer to drawing 8770-G-082 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM CIRCULATING AND INTAKE COOLING WATER SYSTEM SH 1 FIGURE 9.2-1 Amendment No. 22 (05/07)

Refer to drawing 8770-G-082 Sheet 2 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM CIRCULATING AND INTAKE COOLING WATER SYSTEM SH 2 FIGURE 9.2-1a Amendment No. 22 (05/07)

Refer to drawing 2998-G-663 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CIRCULATING WATER SYSTEM OCEAN INTAKE &

DISCHARGE SHT.1 FIGURE 9.2-1 b Amendment No. 15 (1 /97)

Refer to drawing 8770-G-664 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CIRCULATING WATER SYSTEM OCEAN INTAKE &

DISCHARGE "PROFILE" FIGURE 9.2-1 c Amendment No. 15 (1 /97)

Refer to drawing 8770-G-664 Sheet 2 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CIRCULATING WATER SYSTEM OCEAN INTAKE &

DISCH SECTS & DETAILS SH.2 FIGURE 9.2-1d Amendment No. 15 (1 /97)

Refer to drawing 8770-G-664 Sheet 3 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CIRCULATING WATER SYSTEM OCEAN INTAKE &

DISCH SECTS & DETAILS SH 3 FIGURE 9.2-1e Amendment No. 15 (1 /97)

REFER TO DRAWING 8770-G-083, Sheets 1A & B FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM COMPONENT COOLING SYSTEM FIGURE 9.2-2 Amendment No. 16 (1/98)

~

]I r=T.-lL S*

' - VALVE LIMIT SWITCH 4160V BUS AB 4160V BUS BJ OPEN ONLY WHEN VALVE IS FULLY CLOSED.

M0'0R\ -

COMPONENT COOLING WATER PUMP MOTORS f'" r-*. r. _,

r -*"' r,.*

L~

Irn

~ L~

MV 1 MV 2 CCW DISCHARGE HEADER

" B" ANN "COMPONENT COOLING WATER PUMP-VALVES MISALIGNED" COMPOHENT

-coOLING WATER I PUMPS SUCTION SUCTION HEADER HEADER "A" " B" FLO RID A POWER 8. LI GH T COMP ANY ST . lUCIE PLANT UNIT I COMPO NEN T COOLING WATER PUMP lC PUMP- VALVE ALIGNMENT ANNUNCI ATI ON FIGURE 9. 2-2 11

SCALE 1"=10' 12'

---...L..-- +

71/2' - - - -

+ t FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 DETAIL OF Y OUTFALL FOR CIRCULATING WATER DISCHARGE FIGURE 9.2-3 Amendment No. 22 (05/07)

Refer to drawing 8770-G-089, Sheets 1A & B FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM TURBINE COOLING WATER SYSTEM FIGURE 9.2-4 Amendment No. 16 (1/98)

Refer to drawing 8770-G-089 Sheet 2 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM TURBINE COOLING WATER

>. SYSTEM FIGURE 9.2-4a Amendment No. 15 (1/97)

REFER TO DRAWINGS 8770-G-084, Sheets 1A, 1B & 1C FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT ~

FLOW DIAGRAM FIRE WATER, DOMESTIC AND MAKE-UP SYSTEMS FIGURE 9.2-5 Amendment No . 16, (1 / 98)

Refer to Drawing 8770-G-711 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 EMERGENCY COOLING WATER CANAL FIGURE 9.2-6 Amendment No. 26 (11/13)

  • Big Mud Creek Wind In take Cans 1 Minimum Low Water This condition resulta in the maximum expected differential water level act-ing on the barrier.. High water, waves and hurricane winds in the Indian River (equivalent static water level of

+7ft) with low water in the Ocean and Circulating Water System Operation giv ing minimum water level in the Intake Canal. This represents a critical design condition for normal hurricane conditions (120 mph).

Wind: 120mph Extreme High Water: Elev +3 Wave Height: 4ft MAXIMUM DESIGN DIFFERENTIAL Big Mud Creek r- Intake Canal This condition results in the maximum expected differential water level act-1- --Wind ing on the barrier wall. Highwater, 1- u SL+-6 waves and hurricane winds in the o~ean (equivalent static water level of +7ft) with a corresponding high water level in the Indian River.

o/~"\V#,.<.\\\

Wind: 120 mph High Water, Elev +5 Wave Ht. 2ft MAXIMUM DESIGN DIFFERENTIAL FLORIDA POWER & LIGHT COMPANY

  • ST. LUCIE PLAtH UHIT 1 CAN!.L BARRIER Dl FFERENTIAL WATER LEVELS DESIGN CONDITIONS FIGURE 9.2-6o  !

r

~AND DE.PO!:>IT.

~AND OI~PLACE.O BY Dl &CHAR(;)E.

uE.T VELOCITY NORMAL OCEAN TIDAL RANGE (EL 0.0 TO EL+2.. s, I TOP OF DIKE EL + t3.00 (BEFORE LIQUHACTION)

\ II OPER.TIN6 WATER LEVEL 2 UNIT* (EL- ..0 1<> * >S)

= ~

WALL ..

~ . ""'wu ~

.OIL LIQU~ -

FACTION - <!!£2E.1*-

-~~**

\ 1 -- = --

PIPE EL-: 17 -_s o'

  • VEI~o.wv r-**___*_* * * . ------- ~ .

~.

.; * * "" . * ~.~.-:-.- .. *; *- ~*' ~

J ...; ~t*

L.EFIE D SAND ERODED BY INTAKE.

VELOCITIES.

FLORIDA POWER /l. LIGtH COMPA~Y ST . LUCIE PLAtiT UHIT 1 OCEAN INTAKE HEADWALL SECTIONS FIGURE 9.2--6 h

FIGURE 9.2-6c HAS BEEN INTENTIONALLY DELETED

Refer to Drawing 8770-G-712 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 UHS CANAL BARRIER FIGURE 9.2-6d Amendment No. 26 (11/13)

Refer to Drawing 8770-G-713 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 UHS CANAL BARRIER CROSS-SECTION FIGURE 9.2-6e Amendment No. 26 (11/13)

Refer to drawing 8770-G-093 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM MISCELLANEOUS SYSTEMS FIGURE 9.2-6f Amendment No. 22 (05/07)

REFER TO DRAWING 8770-G-0 84, Sheet 3 FLORIDA POWER & LIGHT COMPANY ST. LUCXE PLANT UN~T ~

FLOW DIAGRAM FIRE PROTECTION SYSTEM FIGURE 9.2-7 Amendment No . 16, (1 / 98)

9.3 PROCESS AUXILIARIES 9.3.1 COMPRESSED AIR SYSTEM 9.3.1.1 Design Bases The compressed air system consists of the Instrument Air System and the Service Air System. The air systems serve no safety function since they are not required to achieve safe shutdown or to mitigate the consequences of a LOCA.

The design basis of the Instrument Air System is to reliably provide the required supply of dry, oil-free air at the required pressure for pneumatically operated valves, instruments and controls. Oil free compressors, air dryers and air filters located at each dryer are designed to provide air which meets the requirements of ISO 8573 Class 0, for particulate and oil, and Class 1 for dewpoint. Instrument EC283796 Air Compressors 1A or 1B can be manually loaded onto a vital power bus, if desired, during a loss of offsite power (LOOP) event. Compressors 1C and 1D are powered from a non-vital source.

The Service Air System supplies the necessary service air for normal plant operation and operation of pneumatic tools and equipment used for plant maintenance.

9.3.1.2 System Description The compressed air system is shown schematically on Figure 9.3-1, 1a, 1b and 1c and equipment design parameters are given in Table 9.3-1.

The instrument air system incorporates two full capacity (1C, 1D) and two half capacity (1A, 1B) compressors, each having a separate inlet filter, aftercooler and moisture separator. The instrument air compressors discharge to a single header connected to an air receiver and two full capacity air dryer and filter assemblies. The system supply header is divided into branch lines supplying the intake structure, service building, water treatment area, turbine building, tank storage areas, fuel handling building, steam generator blowdown building, containment building and the reactor auxiliary building. The various air operated valves and pneumatic instruments and controls are supplied from the header.

The containment instrument air compressors and associated components have been abandoned in place.

Normal operation requires one instrument air compressor (1C or 1D) to maintain air receiver pressure between 110-120 psig, with the other compressor (1C or 1D) starting automatically if the instrument air receiver pressure falls below 105 psig.

Compressors 1C & 1D are operated from the digital Master Control Panel. High and low pressure EC283796 setpoints are configured in the Master Control Panel. The Master Control Panel receives system pressure from a pressure transmitter mounted on the receiver and uses control algorithms to load and unload compressors 1C & 1D as necessary in order to maintain system pressure between these setpoints. When loaded, system pressure will increase provided the compressor output exceeds system demand. Pressure will continue to increase until the high operating setpoint is reached at which time the compressor will unload (i.e., all inlet valves will be held open), operating but compressing no air. The compressors motors are automatically started and stopped as needed.

Compressors 1C & 1D can also be operated locally based on pressure instrumentation in the compressor skid. In the event that the Master Control Panel is unavailable, compressors 1C & 1D will operate under local settings (i.e. lead / lag) and load and unload based on skid mounted instrumentation.

9.3-1 Amendment No. 29 (10/18)

Compressors 1A & 1B are each equipped with a three position selector switch with ON, AUTO and EC283796 OFF positions. When a compressor's selector switch is ON, the compressor will load and unload based on the configurable setpoints associated with this selector switch position and will function as the lead compressor. When a compressor's selector switch is in AUTO, the compressor will load and unload based on the lower setpoints associated with this selector switch position and will function as the lag compressor. In both positions, the controller automatically starts and stops the motor as needed.

Operating setpoints for the compressors are provided in plant design documents.

The instrument air system inside containment is connected to the instrument air system outside the containment via MV-18-1 which receives a CIS. Operators may choose to open MV-18-1 without EC288593 resetting CIS, by placing control switch CS-317 to CLOSE/OVERRIDE position.

Compressors 1C and 1D function as the principal source of instrument air while compressors 1A and 1B will remain off, available for use under abnormal operating conditions, whenever air compressors are required with only vital power available to meet the instrument air demand during a loss of offsite power event and when compressors 1C and 1D are not available during normal power operation. The compressors 1A and 1B will maintain the air receiver pressure to meet the system requirements.

9.3-1a Amendment No. 29 (10/18)

Two 100% capacity desiccant air dryers each with prefilter and afterfilter packages are also provided.

One of the two air dryers will operate and the other will serve as standby. The IA dryer and filter package is designed to remove all particulate matter (oil, dust) over 0.9 microns in size and reduce the moisture content to a dew point of -40oF at 110 psig.

The service air system consists of distribution piping supplied by the Unit 2 cross-tie, Construction Air, or portable compressors. The receiver outlet header is divided into branch lines supplying service air to the containment, intake structure, fuel handling building, steam generator blowdown building, reactor auxiliary building, turbine building, service building, water treatment area and tank storage areas. Service air is used for the operation of pneumatic tools and equipment used for plant maintenance.

UNIT 1 9.3-1b Amendment No. 28 (05/17)

Cross connect capability exists between the instrument air and service air systems. The cross connect consists of a flexible coupling used to reduce noise and vibrations associated with the reciprocating action of the compressors. An oil filter is provided to upgrade service air quality to instrument air standards when the cross connect is in use. Cross connection capability also exists between the Unit 1 and Unit 2 instrument and station air systems. The cross connections for the instrument air lines have normally closed pressure regulating valves which are actuated by a decrease in pressure in either unit. The station air line has normally closed manual isolation valves.

9.3.1.3 System Evaluation The power supply for the compressor motors is from the normal power distribution system. If a loss of offsite power occurs, the turbine building instrument air compressors (1A or 1B) can be manually loaded on the diesel generator sets. Instrument air system redundancy is provided by the three sets of instrument air compressor units plus the cross connect capability to the service air system. A total loss of system is highly unlikely during normal operation.

The instrument air dryer and filters are expected to remove all particulate matter (oil and dust) over 0.9 microns in size, and reduce the moisture content to a dew point of -40oF at 110 psig, as detailed in Table 9.3-1. The equipment is subjected to the manufacturer's required maintenance procedures to assure this cleanliness level.

Safety related valves which are air operated, and their valve pressure regulators, are equipped with air filters. Maintenance procedures ensure that the filters are changed when clogged. Unlikely clogging of the filter would result in loss of air to the valve, putting the valve to its fail safe position.

Although the compressed air system serves no safety function, the system does supply air to safety related components during normal operation. However, UNIT 1 9.3-2 Amendment No. 28 (05/17)

loss of compressed air to the main steam isolation valves, the diesel generator building non-essential instruments, and the component cooling system non-essential header isolation valves could not affect the operation of any safety related component. Loss of the compressed air system will not cause the EC288435 MSIVs to close immediately. Refer to main steam system description in Section 10.3.2.

The diesel generator sets are each provided with a seismic Class I air starting system (discussed in Section 9.5.6) independent from the station compressed air system. An instrument air line is routed to the diesel generator building for maintenance and instrument test functions. In the component cooling area, there are four air operated component cooling valves which fail closed on loss of air supply to isolate the non-essential component cooling header from the essential headers. Also there are two air operated intake cooling water valves which fail open on loss of air to allow cooling water flow to the component cooling heat exchangers.

Common storage facilities for hydrogen, carbon dioxide, and nitrogen are provided for Units 1 and 2.

Facilities for the bulk storage of hydrogen in tube trailers and in bottles have been provided approximately one hundred twenty feet north of the intake structure. Besides some equipment located at the intake structure, the nearest safety related equipment is the condensate storage tank, which is surrounded by a concrete missile wall located approximately 80 feet away. The storage and distribution facilities including piping are designed to comply with the Occupational Safety and Health Administration (OSHA) requirements as indicated in Section 1910.103. In addition to the bulk hydrogen storage facility, two banks of cylinders are located in the gas storage building for supplying the hydrogen gas requirements of the nuclear steam supply system. No safety related equipment is located in this building. The hydrogen gas at stored pressure is reduced to 100 psig (for NSSS application) and 75 psig (for turbine generator application) for distribution to their use points.

Carbon dioxide is stored in the bottles in the gas storage building which is adjacent to the hydrogen bulk storage facility. A manifold of 35 standard size bottles adequate for one complete purge of the turbine generator is provided in the building. The CO2 lines to and from the turbine building are under a pressure of 60-100 psig. The CO2 system does not come in close proximity to any safety related equipment and is designed to OSHA requirements.

The nitrogen system supplies low and high pressure nitrogen to various systems and vessels which require cover gas. Bulk storage facilites for nitrogen are provided by a low-pressure, 11,000 gal.

(1,020,500 scf) capacity N2 Dewar with two compressors and a high-pressure 40,000 scf tube trailer.

Both the dewar and tube trailers are located adjacent to the gas storage building. Each compressor can supply high pressure nitrogen at a rate of 5 to 8 scfm. In addition to the bulk nitrogen storage facility, a bank of 34 cylinders is located in the gas storage building for supplying the nitrogen gas for the nuclear steam supply system and also the condensate storage tank nitrogen blanketing system.

The storage facility and the distribution piping is designed to meet the requirements of OSHA.

UNIT 1 9.3-3 Amendment No. 29 (10/18)

Failure of compressed air equipment including air receivers is judged not to have any detrimental effect on safety related equipment even if the failure produces missiles. Other than process lines, the compressed air equipment is located in the turbine building which does not house any safety related equipment. The auxiliary feedwater pumps located adjacent to the turbine building and protected by a 1 steel plate structure (see Appendix 3F, Section 6.9) are in no jeopardy from projectiles caused by compressed air system ruptures.

The abandoned compressed air equipment provided inside the containment is located between the secondary shield wall and the steel containment. There are no safety related components nearby that could be affected by the rupture of the air receiver.

The design basis and actuator capabilities for MV-18-1 have been reviewed in accordance with the requirements of Generic Letter 89-10, "Safety Related Motor Operated Valve Testing and Surveillance,"

as noted in Section 3.9.2.4 In general for the compressed air system and the hydrogen, carbon dioxide and nitrogen storage and distribution systems, pressurized trailers are enclosed by concrete or fenced enclosures and are located at sufficient distance from safety related equipment to render ineffective any missiles which could possibly be caused by line or trailer rupture since these would be less severe than tornado missiles.

9.3-4 Amendment No. 25 (04/12)

All safety related air operated valves are designed to fail in the position required to perform their safety function in the event a loss of air supply occurs. The single exception to this rule applies to the containment vacuum relief valves which perform both a containment isolation function and vacuum relief function. These valves fail closed on loss of air. They are provided with accumulators which provide a minimum of three operations of the valve in the event of loss of instrument air. The accumulator and piping for operation of the valves are designed as Seismic Class I. The P & I diagram for instrument air to the vacuum relief valves is shown on Figure 6.2-47 and the control diagram for the valves is shown on Figure 9.4-2. Each accumulator is provided with test connections which allow testing of the accumulator and its associated check valves. Containment vacuum relief is discussed in sections 6.2.1.2 and 3.8.2.1.11.

Other containment isolation valve positions on power failure are indicated in Table 6.2-16. All safety related instruments and controls are non-pneumatic except for the air operated temperature control valve used to regulate intake water flow to the component cooling water heat exchangers. Temperature controlling transducers cause the control valves to fail fully open on loss of air supply.

Complete loss of instrument or service air during full power operation or under accident conditions in no way reduces the ability of the reactor protective system or the engineered safety features and their supporting systems to safely shut down the reactor or to mitigate the consequences of an accident.

The compressed air systems for Units 1 and 2 are independently capable of supplying their respective instrument and service air systems. The cross connection between the two units does not compromise the functional capability of the system.

9.3-5 Amendment No. 23 (11/08)

9.3.1.4 Testing and Inspection The systems were inspected and cleaned prior to service. Instruments were calibrated during testing and automatic controls were tested for actuation at the proper set points. Alarm functions were checked for operability and limits during plant operational testing. The system was operated and tested initially with regard to flow paths, flow capacity, and mechanical operability.

The compressed air system is in service during normal plant operation. System performance will therefore be checked by the performance of the components utilizing instrument or service air.

9.3.1.5 Instrument Application Table 9.3-2 lists the parameters used to monitor compressed air system operation.

The instrument air compressors are automatically started and stopped to maintain the air receiver EC0284952 pressure within the range of 110-120 psig. Instrument Air System compressors outside containment have local controls only. The standby instrument air compressor is started automatically on low air pressure.

After starting, the compressor runs continuously until the operator stops it manually.

The operation of automatic valves in the compressed air system is discussed in Section 9.3.1.3.

9.3-6 Amendment No. 32 (04/23)

9.3.2 SAMPLING SYSTEM The sampling system described below is utilized during normal plant operation. The Post Accident Sampling System is described in Section 9.3.7.

9.3.2.1 Design Bases The sampling system provides the means to obtain samples from the reactor coolant and auxiliary systems during normal plant startup, power operation and plant shutdown for chemical and radiochemical laboratory analysis. The results of analyses performed on these samples form the basis for regulating the boron concentration, monitoring the fuel integrity, evaluating the ion exchanger and filter performance, specifying chemical additions and maintaining the proper hydrogen concentration in the reactor coolant system.

Provisions for sampling reactor coolant during post-accident conditions (Post Accident Sampling System) are described in Section 9.3.7.

9.3.2.2 System Description The piping and instrumentation diagram for the sampling system is shown on Figures 9.3-2 and 9.3-8.

Tables 9.3-3 and 9.3-4 list the sample flow rates and system design data, respectively.

Typical analyses performed on the reactor coolant and auxiliary systems include tests for boron concentration, fission and corrosion product activity levels and concentration, dissolved gas and corrosion product concentrations, chloride concentration, coolant pH and conductivity levels. Typically the samples are collected on a periodic basis. The sampling room, located at floor elevation 19.5 ft in the reactor auxiliary building, contains instrumentation to monitor the temperature and pressure of the samples.

The sample sink, which is located within the sampling hood, has a raised edge to contain any spilled liquid. To minimize the possibility of spillage, all samples are either collected in plastic containers or in a stainless steel sample vessel. The sink is provided with a hood equipped with a fan exhausting to the plant vent.

In order to assure that a representative sample is obtained, the sampling lines are purged prior to withdrawing the sample. The pressure and flow rate of each of the purge flows is locally indicated. The duration of the purge will be sufficient to turn over a minimum of two sample line volumes.

The sample volume varies according to the type of analysis to be performed. An appropriately sized sample vessel is used to collect the sample. From this sample, the amounts of O2, H2 and dissolved fission gases may be determined. The hot leg sample may also be collected at the sample sink for a boron or chloride concentration analysis. In addition to acquiring a sample via the sample vessel, an in-line dissolved gas analyzer may be used for monitoring RCS chemistry.

9.3.2.2.1 Sampling The sampling points have been selected to obtain all the required chemical and radiological information necessary for monitoring and regulating plant reactor coolant chemistry. Separate transfer lines from the various 9.3-7 Amendment No. 22 (05/07)

sampling points to the sample sink or sample vessel are provided to allow for simultaneous sampling.

Specific samples and sampling points and criteria used in designing the sample lines are described below:

a) Reactor Coolant System Samples Reactor coolant system samples are taken from hot leg loop 1A, the pressurizer surge line and the pressurizer steam space.

1) Hot Leg Sample - The hot leg is sampled to check reactor coolant chemistry and radioactivity.

The hot leg sample tubing is arranged to include a delay coil so that the overall transient time from the loop to the containment wall is sufficient to permit the decay of short lived radionuclides.

In particular, a delay time of at least 90 seconds inside the containment is allowed for N-16 because of its high energy gamma emission. This delay time is selected to allow normal access to the sampling room.

The two types of samples which may be collected from the hot leg of the reactor coolant system are (1) a high pressure, low temperature sample collected in a sample vessel and used for determining the amounts of O2, N2, H2 and fission gases, and (2) a low pressure, low temperature sample collected at the sampling sink and used for determining the chloride and boron concentration.

A high pressure (~2235 psig) and high temperature (~650°F) sample from the hot leg of the reactor coolant system is routed to the sampling system where it is cooled to 120°F or less in a sample heat exchanger and then may be reduced in pressure by a throttling valve (V5107) to approximately 25 psig.

Before sampling, a purge flow is established by bypassing the sample vessel to assure that a representative sample is obtained. A portion of the flow is then either drawn to the sample sink where a sample is collected or the flow is diverted to the sample vessel where a high pressure sample is isolated and collected. In addition to acquiring a sample via the sample vessel, an in-line dissolved gas analyzer may be used for monitoring RCS chemistry.

2) Pressurizer Surge Line Sample - This sample is taken at the sample sink to check the boron concentration in the pressurizer surge line. A high pressure, low temperature sample is not required because the boron concentration analysis is normally the only test to be performed.

The high pressure (~2235 psig), high temperature (~650°F) sample from the pressurizer surge line is routed to the sampling system where it is cooled to 120°F or less in a sample heat exchanger and then reduced in pressure across a throttling valve (V5111) to approximately 25 psig.

The sample normally flows through a purge line to the volume control tank or to the waste management system flash tank (if the volume control tank is not available) until sufficient volume has passed to permit the collection of a representative sample. A 9.3-8 Amendment No. 22 (05/07)

portion of the flow is drawn via the grab sample valve (V5139) and a sample is collected. The purge flow is normally directed to the volume control tank in the chemical and volume control system to minimize waste generation. The pressure and flow rate to the volume control tank is locally indicated.

3) Pressurizer Steam Space Sample - This sample is taken to give a representative sample of fission products and noncondensable gases in the pressurizer steam space. A high pressure, low temperature sample can be collected in a sample vessel or a low pressure, low temperature sample can be collected in the sample sink as described above.

Grab samples can also be obtained with the sample vessels bypassed by using the sample vessel bypass lines (V5106) or (V5120). The sample vessel bypass lines are used during the initial portion of the sample line purging operation to minimize sample vessel contamination.

b) Safety Injection Samples

1) System Samples A possible sampling point is available for post accident sampling. The safety injection system sample is available to check the boron concentration of the water during the recirculation period following a LOCA from the mini-flow sample point. The pressure in the high pressure safety injection pump miniflow line varies from 120 psig to 200 psig depending on the operation of the safety injection pumps. The temperature in this line has a maximum value of 300°F.

The flow is routed through a sample heat exchanger where the temperature is reduced to about 120°F and through a throttling valve (V5128) where the pressure is reduced to approximately 25 psig. After the sampling lines are purged, a sample is collected at the sample sink.

2) Safety Injection Tanks Samples This sample is taken at the sample sink to check the boron concentration in the safety injection tanks as required by the plant technical specifications. Samples may be taken by remote operation of the sample solenoid valves associated with each safety injection tank, from the primary sample room. Each solenoid valve is provided with position indicating lights in the sample room for positive identification of the safety injection tank being sampled. Containment isolation is provided by two solenoid valves which are provided with position indicating lights in the control room, as shown on Figure 6.3-2.

This is in conformance with RG 1.97.

Before sampling, a purge volume of approximately one gallon is required to assure that a representative sample is obtained.

9.3-9 Amendment No. 22 (05/07)

c) Shutdown Cooling System Samples The shutdown cooling suction line sample allows verification of the reactor coolant boron concentration prior to and during shutdown cooling. The pressure at the shutdown cooling sample point can be as high as 350 psig and the temperature can be as high as 350°F.

The temperature and pressure are reduced using V5128 to about 120°F and 25 psig, respectively. After the sample lines have been purged, a sample is collected at the sample sink.

d) Chemical and Volume Control System Samples Sample points for the chemical and volume control system are located at purification filter 1A inlet and outlet, at the outlet of purification filter 1B (outlet of the ion exchangers) and in the purification ion exchanger series flow line. The samples at the purification filter 1A inlet and outlet provide a means to determine the particulate activity decontamination factor (DF) for crud activity of the filter. The purification filter 1A inlet sample (letdown flow) can also be a backup to the hot leg sample. The sample at the outlet of purification filter 1B together with the ion exchanger inlet sample (same as the purification filter 1A outlet sample) gives a decontamination factor of soluble activity for the ion exchanger unit, and the combined ion exchanger and filter 1B DF for particulate activity. The purification ion exchanger series flow line sample together with the samples from the inlet and outlet of the ion exchangers gives the decontamination factor for each ion exchanger if two ion exchangers are being operated in series.

The samples from the chemical and volume control system are at a temperature of 120°F and a pressure of approximately 25 psig.

Since these are the approximate operating conditions of the sampling system at the sampling room, no further reduction in temperature or pressure is required. The flow rate to the sampling room is approximately 1 gpm. After the sample lines have been purged a sample is collected at the sample sink. Purging can be to the flash tank rather than to the volume control tank to obtain an adequate flow rate due to the low differential head available.

e) Steam Generator Blowdown System Samples The samples taken from the steam generator blowdown system are used to continuously monitor the steam generator conductivity, pH, and radiation levels. A low pressure, low temperature sample can also be taken at the steam generator blowdown sampling sink and at the Cold Chemistry Lab in order to monitor steam generator chemistry.

9.3-10 Amendment No. 22 (05/07)

Steam generator blowdown samples are taken from the blowdown line of each steam generator. These high pressure (~885 psig), high temperature (~550°F) samples are individually routed to the sample heat exchangers and cooled to approximately 120°F. The pressure of the samples is then reduced to about 50-75 psig by a throttling valve. The EC284034 sample flow rates are approximately 1.25 gpm.

All continuous discharges are directed to the steam generator blowdown building for disposal or processing.

9.3.2.2.2 Component Description The major components of the sampling system are described below. The sample sink, work area and sampling lines are constructed of stainless steel to minimize any potential corrosion problems.

a) Sample Heat Exchangers The sample heat exchangers are tube-in-shell, vertical parallel flow type. Sample fluid enters the tube side at the top of the heat exchanger and the cooled samples are taken from the bottom. Component cooling water, which must be flowing before the sample fluid is introduced into the heat exchanger, enters the shell side at the top of the sample heat exchanger and exits at the bottom. The sample heat exchangers are located outside of the sample room to minimize operator exposure during the sampling process.

b) Sample Vessel The sample vessels are located inside the sample hood over the sample sink. Each vessel consists of a 300 cc stainless steel sampling cylinder with isolation valves and quick disconnect couplings. The sample vessel allows the operator to collect a high pressure, low temperature liquid or gas sample from which dissolved gases and fission gas activities can be determined. In addition to acquiring a sample via the sample vessel, an in-line dissolved gas analyzer may be used for monitoring RCS chemistry. Either the sample vessel or in-line analyzer may be aligned for use.

c) Sample Sink and Hood The sample sink is located within the sample hood. All grab samples are obtained within the sample hood and over the sample sink. A demineralized water line is routed to the sink for flushing purposes. The sample sink drains to the chemical drain tank. The sink perimeter has a raised edge to contain spilled liquid. The entrance to the sample hood is shaped so that the air drawn into the hood by the hood fan will enter in a smooth, uniform and unbroken pattern, thereby minimizing the possibility of local airborne activity outside the hood.

9.3-11 Amendment No. 29 (10/18)

d) Sample Delay Line A delay line, consisting of 150 feet of tubing, is of sufficient length to keep the reactor coolant sample flow inside the containment for a sufficient period of time to allow for the decay of radionuclides, particularly nitrogen-16. This delay line permits normal access to the sample room.

9.3.2.3 System Evaluation The sampling system is designed to provide a means of obtaining samples from the reactor coolant and auxiliary systems for chemical and radiochemical laboratory analysis. Safety features are provided to protect plant personnel and to prevent the spread of contamination from the sampling room when samples are being collected. The system is designed to limit radioactivity releases below the 10 CFR 20 limits under normal and failure conditions. The temperature and pressure of the various samples are reduced to minimize the possibility of local airborne activity. Instrumentation is provided in the sampling room to monitor the temperature and pressure of the samples before they are collected. Samples are normally taken when the hood fan is operating in order to provide a means of maintaining low airborne activity levels.

The sample lines penetrating the containment are each equipped with two pneumatically or solenoid operated isolation valves which close on actuation of the containment isolation signal (CIS). The containment isolation valves in the letdown line also close on CIS thereby stopping flow from the 9.3-12 Amendment No. 16, (1/98)

chemical and volume control system to the sampling system. The containment isolation valves are also designed to fail closed on loss of air supply. Remote control of these valves is provided to isolate any line failure which might occur outside of the containment. Should any of the remotely operated valves in the sampling system fail to close after a sample has been taken, backup manual valves in the sampling room may be closed. The sample system tubing components and valves are capable of operating at source pressure (~2485 psig) and temperature (650oF) up to and including the grab sample valves. The sample sink drains to the chemical drain tank. Any leakage from the grab sample valves in the sample sink drains to this tank. The work area around the sink provides adequate space for sample collection and storage.

The sink perimeter has a raised edge to contain spilled liquid.

The throttling valves in the sampling system have a limited flow coefficient (Cv) range. This range is based on the flow required and the differential head available under all operating conditions. This limits the sample flow rate to the required value and prevents excessively high flow.

9.3.2.4 Testing and Inspection The system was inspected and cleaned prior to service. Demineralized water was used to flush each part of the system. The system was operated and tested initially with regard to flow paths, flow rate, thermal capacity and mechanical operability. Instruments were calibrated during plant hot functional testing. The set points of the relief valves were also checked at this time.

During plant startup the sampling system is hydrostatically tested by opening the valves that connect the reactor coolant system to the sampling system and observing the pressures and temperatures as the heatup continues.

9.3.2.5 Instrument Application Table 9.3-5 lists the parameters used to monitor the sampling system operation.

9.3-13 Amendment 15, (1/97)

9.3.3 EQUIPMENT AND FLOOR DRAINAGE SYSTEM 9.3.3.1 Design Bases The equipment and floor drainage system is designed to collect leakage or spillage from equipment located in the containment, reactor auxiliary and fuel handling buildings.

Waste from radioactive drains will be collected for sampling, analysis and processing as required, to assure that releases to the environment are in accordance with the limits established by 10 CFR 20.

Leakage detection instrumentation is provided for sumps which collect drainage from the reactor coolant pressure boundary to allow detection of excessive leakage, as described in Section 5.2.4.

Storm, floor and equipment drains that are not potentially radioactive are routed to a settling basin. Refer to Figure 3.4-3 for the site drainage diagram.

9.3.3.2 System Description a) Reactor Building All drains in the shield building are collected either in the equipment drain tank or in the reactor drain tank. The equipment drains inside the containment are routed directly to the reactor drain tank as indicated on Figure 11.2-1. The floor drains collect in the reactor cavity sump and are pumped to the equipment drain tank. All drainage is then routed to the waste management system for either reuse, storage in the primary water tank or discharged to the discharge canal after sampling depending upon the quality and activity level of the water.

b) Reactor Auxiliary Building Reactor auxiliary building equipment and floor drains at elevation 19.50 and above are routed inside the reactor auxiliary building to the equipment drain tank while equipment and floor drains at elevation -0.50 and elevation -10.00 are routed to the ECCS room sumps. the sumps have automatic water level controls for transfer of the liquid to the equipment drain tanks. A cross connection is provided between the Unit 1 and Unit 2 equipment drain tanks. The line has locked closed valves at each unit.

An alternate flow path is provided to return potentially radioactive leakage, from the ECCS sumps to the containment reactor drain tank, in the event of a LOCA, as described in Section 11.2.2.1.

The radioactive chemical waste from the radio chemistry laboratory, decontamination room, and sink in the sample room are routed to the chemical drain tank. The floor drains in the vicinity of the chemical drain tank and pump are routed to the chemical drain sump tank. The sump tank has automatic level controls for transfer of the liquid waste to the chemical drain tank.

Laundry wastes from the service and reactor auxiliary buildings which are not potentially radioactive are routed to the sanitary system.

9.3-14 Amendment No. 25 (04/12)

Radioactive detergent waste from the hot toilet and shower room and hot laundry room is routed to the laundry drain tank. The equipment and floor drains in the vicinity of the laundry drain tank, pumps and filter, are routed to the laundry drain sump tank. The sump tank has automatic level controls for transfer of the liquid waste to the laundry drain tank. The water in the laundry drain tank is sampled and if activity levels are low, the water is filtered and discharged into the circulating water discharge header. The water in the discharge header is monitored for radiation.

The flow to the circulating water discharge canal is stopped by valve (FCV-6627X), shown on Figure 11.2-4c, which close on a high radiation signal, and V21462 which is administratively controlled by plant procedures.

Valve FCV-6627X can also be closed from the control room. The chemical and equipment drain tank water is pumped to the AWST and then recirculated through a filter and ion exchanger, as shown on Figures 11.2-4, 11-2-4b, and 11.2-4c. The water in the drain tanks is sampled at its respective pump discharge prior to release.

Table 9.3-6 lists the drains routed to the various drain tanks.

c) Fuel Handling Building All Potentially radioactive equipment and floor drains in the fuel handling building are routed by gravity flow to the reactor auxiliary building equipment drain tanks. Non-radioactive drains are routed to the outside together with roof drains.

The detergent waste flow drain in the cask handling facility is routed by gravity flow to the chemical drain tank in the reactor auxiliary building.

d) Storm Drainage Storm water is collected from the roofs of the reactor, reactor auxiliary and fuel handling buildings, and routed to the plant site storm drainage system. This system is physically separate from all other drainage systems.

9.3.3.3 System Evaluation Floor drains within the reactor auxiliary building are embedded so that leakage from the lines is contained within the building. Equipment and floor drains containing potentially radioactive fluids are made of stainless steel. Non-radioactive drains are galvanized steel above ground and cast iron below ground.

The sumps in the ECCS rooms have separate sump and leak detection instrumentation designed to seismic Class I requirements to enable the operator to identify which ECCS sump is filling and to initiate protective action as required.

9.3-15 Amendment No. 23 (11/08)

The remainder of the equipment and floor drainage system serves no safety function. Consequently, the system will not be designed to seismic Class I requirements.

The Unit 1 and Unit 2 drain tanks are independently capable of performing their function. The cross connection between the two units does not compromise the capability of the tanks.

There are no lines from the equipment and floor drainage system that penetrate the reactor auxiliary building below the elevation associated with the maximum wave runup. Water is thus precluded from backflowing into the reactor auxiliary building and affecting the operation of safety related equipment or equipment required to bring the plant to a safe cold shutdown.

The 8 inch diameter cast iron storm drain lines do not penetrate the reactor auxiliary building exterior walls below +22'.

A 4 inch sanitary line penetrates the reactor auxiliary building (RAB) below grade near the northwest corner of the building (see Figure 3.4-3). A break of this line in the line is essentially sealed off from ground flooding that would occur during PMH. All manholes are sealed.

The storm water drainage system consists of a number of concrete catchbasins interconnected by concrete piping. Most of the details of the system are shown in Figure 3.4-3. The system design criteria is discussed in Section 3.4.3. The system collects surface drainage and some building drainage and discharges it in the naturally low area south of the plant island. Before final discharge, the runoff is retained in a diked area (top of dike is elev. +8.0).

The radiological consequences of effluents from the equipment and floor drainage system are discussed in Chapter 11. A table of sources and volumes of waste are given in Table 11.2-1.

9.3.3.4 Testing and Inspection All welded fitting in the equipment and floor drainage system were visually inspected after installation in the system. The entire system was hydrostaticaly tested before the system was fully enclosed.

The system was smoke tested prior to operation at a pressure equivalent to 1 in. wg.

9.3.3.5 Instrumentation Application The parameters used in equipment and floor drainage system are given in the waste management system Instrument Application Table 11.2-16.

9.3-16 Amendment No. 22 (05/07)

9.3.4 CHEMICAL AND VOLUME CONTROL SYSTEM 9.3.4.1 Design Bases The chemical and volume control system is designed to:

a) maintain the chemistry and purity of the reactor coolant within the limits specified in Table 9.3-8 b) maintain the required volume of water in the reactor coolant system by compensating for coolant contraction or expansion due to plant step load changes of +/-10 percent of full power and ramp changes of +/-5 percent of full power per minute between 15 and 100 percent power and for reactor coolant losses or additions c) accept out-flow from the reactor coolant system when the reactor coolant is heated at the administrative rate of 75F/hr and to provide the required makeup when the reactor coolant is cooled at the analyzed cooldown rate of 75F/hr using two charging pumps EC290379 d) accommodate the reactor coolant system water inventory change for a full-to-zero power decrease with no makeup system operation and with the volume control tank initially at the normal operating level band e) inject concentrated boric acid into the reactor coolant system upon a safety injection actuation signal (SIAS) f) control the boron concentration in the reactor coolant system to obtain optimum control element assembly (CEA) positioning to compensate for reactivity changes associated with large changes in reactor coolant temperature, core burnup, and xenon concentration variations, and to provide shutdown margin for maintenance and refueling operations g) automatically divert the letdown flow to the waste management system (WMS) when the volume control tank is at the highest permissible level h) provide continuous on-line measurement of reactor coolant radioactivity due to fission and corrosion products i) assure that the radioactivity due to corrosion and fission products in the reactor coolant system does not exceed Technical Specification limits for an assumed 1 percent failed fuel condition j) provide auxiliary pressurizer spray for operator control of the reactor coolant system pressure during the final stages of shutdown and to allow for the cooling of the pressurizer 9.3-17 Amendment No. 30 (05/20)

k) collect the controlled bleedoff from the reactor coolant pump seals, l) provide an alternative charging path to the Reactor Coolant System should the normal charging path become inoperable, m) leak test the reactor coolant system, n) withstand the environmental conditions as presented in Section 3.11, o) withstand the expected transients given in Table 9.3-9 without any adverse effects, p) deleted, q) provide a means for filling and maintaining the boron concentration of the Safety Injection Tanks, r) provide an injection point for zinc addition to the RCS.

Portions of the CVCS system required for safe shutdown are designed and built to meet the requirements of seismic Class I in accordance with Regulatory Guide 1.29 to satisfy the design bases (e) and (f) above during and after a design bases earthquake, such as the boric acid injection portions of the systems from the boric acid makeup tanks through the boric acid makeup pumps and the charging pumps. The letdown line through the letdown heat exchanger (and the component cooling water supply), the ion exchangers and volume control tank are not required for boron injection and accordingly are designed to be Quality Group C and non-seismic Class I. Appendix 3D presents a discussion of a CVCS letdown line break and mitigation with the resultant effects on safety related equipment due to the accident environment.

The pressurizer steam space (vented through the pressurizer power relief valves) and contraction due to reactor coolant system cooldown provides sufficient volume for the injection of the required amount of concentrated (2.5 weight percent minimum) boric acid to provide a minimum of 5 percent subcritically at refueling conditions.

Generic Letter 96-06, Assurance of Equipment Operability and Containment Integrity During Design Basis Accident Conditions, requested licensees to evaluate the effects of LOCA or MSLB containment heatup on piping systems which breach the reactor containment or have isolated pipe sections. The evaluation determined that no CVCS penetrations were affected, but several vents and drains would be affected by thermal expansion without effect on CVCS operability. (Reference PSL-SEMS-96-092)

UNIT 1 9.3-18 Amendment No. 27 (04/15)

9.3.4.2 System Description 9.3.4.2.1 Normal Operation The chemical and volume control system (CVCS) is shown on the simplified diagram, Figure 9.3-3, and on the piping and instrumentation drawings, Figures 9.3-4 and 9.3-5. The system parameters are given in Table 9.3-10. The normal flow path of reactor coolant through the system is indicated by the heavy lines in Figures 9.3-4 and 9.3-5.

Normal operation includes hot standby operation and power generation when the reactor coolant system is at normal operating pressure and temperature.

Coolant flow from the cold leg in Loop 1B1 of the reactor coolant system passes through the tube side of the regenerative heat exchanger for an initial temperature reduction. The cooled fluid is reduced to the operating pressure of the letdown heat exchanger by one of two letdown control valves (LCV-2110P, LCV-2110Q). The final reduction to the operating temperature and pressure of the purification system is made by the letdown heat exchanger and one of two letdown backpressure valves (PCV-2201P, PCV-2201Q). Flow through both valves PCV-2201P and PCV-2201Q is required when operating at maximum purification flow (200 gpm) while aligned to the Shutdown Cooling System with parallel flow through two ion Exchangers. The flow then passes through a prefilter (may normally be placed in bypass), one or more of three ion exchangers, a strainer, an afterfilter, and is sprayed into the volume control tank.

The charging pumps take suction from the volume control tank and pump the coolant into the reactor coolant system. One charging pump is normally in operation and one letdown control valve is controlled to maintain an exact balance between letdown flow rate plus reactor coolant bleedoff flow rate and charging flow rate. The charging flow passes through the shell side of the regenerative heat exchanger for recovery of heat from the letdown flow before being returned to the reactor coolant system.

A makeup system provides for changes in reactor coolant boron concentration and for reactor coolant chemistry control. Concentrated boric acid solution, prepared in an electrically heated batching tank, is stored in two boric acid makeup tanks. Two boric acid makeup pumps are used to transfer the concentrated boric acid for mixing with primary makeup water in a predetermined ratio to produce the desired boron concentration. The controlled boric acid solution is then directed into the volume control tank or to the common charging pump suction header. A chemical addition tank and metering pump are used to transfer chemical additives to the suction of the charging pumps.

The volume of water in the reactor coolant system is automatically controlled by water level instrumentation mounted on the pressurizer. The pressurizer level set point is programmed to vary as a function of reactor power in order to minimize the transfer of fluid between the reactor coolant system and the chemical and volume control system during power changes. This linear relationship is shown in Figure 5.5-3. Reactor power is determined by the reactor coolant average temperature across a steam generator. A level error signal is obtained by comparing the programmed level set point with the measured pressurizer water level. Water level control is achieved by automatic control of the constant speed charging pumps and one letdown control valve in accordance with the pressurizer level control program shown in Figure 5.5-4.

9.3-19 Amendment No. 24 (06/10)

One letdown control valve is normally controlled by the pressurizer level control program to obtain a letdown flow equal to the charging flow produced by one charging pump minus the total reactor coolant pump controlled bleedoff flow. Large changes in pressurizer water level due to power changes or abnormal operations result in automatic operation of one or both of the standby charging pumps and/or modulation of one letdown control valve. The rate of letdown flow is controlled by the letdown control valve which is positioned by the pressurizer level control signal.

A VCT level control system controls the level in the VCT. When set to the automatic mode, the system maintains the water level in the volume control tank with letdown flow automatically diverted to the waste management system when the highest permissible water level is reached in the volume control tank.

When the makeup system is set to the automatic mode of operation, a volume control tank low level signal causes a preset solution of concentrated boric acid and primary makeup water to be introduced into the volume control tank. A low-low level signal automatically closes the outlet valve on the volume control tank and switches the charging pump suction to the refueling water tank.

9.3-20 Amendment No. 17 (10/99)

The chemistry and purity of the reactor coolant are controlled to ensure the following:

a) The plant is accessible for maintenance and operation without excessive radiation exposure to the operating personnel b) Long term operation of the plant is achieved without excessive fouling of heat transfer surfaces c) The corrosion rate of the materials in contact with the reactor coolant is kept at a minimum.

Chemistry control of the reactor coolant consists of removal of oxygen by hydrazine scavenging during startup, reduction of oxygen concentration during power operation by maintaining excess hydrogen concentration in the reactor coolant and by maintaining lithium concentration in accordance with the boron/lithium control program. A chemical addition tank and metering pump are used to transfer hydrazine and/or lithium to the suction side of the charging pumps for injection into the reactor coolant system, while hydrogen concentration in the reactor coolant system is controlled by maintaining a hydrogen overpressure in the volume control tank.

During the preoperational test period, 30 to 50 ppm hydrazine was maintained in the reactor coolant whenever the reactor coolant temperature was below 150°F. This is done to prevent halide-induced corrosion attack of stainless steel surfaces which can occur in the presence of significant quantities of dissolved oxygen. During heatup, any dissolved oxygen is scavenged by hydrazine thus eliminating one necessary ingredient for halide-induced corrosion. Elimination of oxygen on heatup also minimizes the potential for general corrosion. At higher temperatures, the hydrazine decomposes, not necessarily completely, producing ammonia and a high pH which aids in the development of passive oxide films on reactor coolant system surfaces that minimizes corrosion product release. The pH is maintained high by maintaining lithium concentration in accordance with the boron/lithium control program. The corrosion rates of Ni-Cr-Fe Alloy-600 and 300 series stainless steels decrease with time when exposed to prescribed reactor coolant chemistry conditions which rates approach low steady state values within approximately 200 days.

A zinc injection skid has been added and is located in the Boric Acid Batch Tank Room. A zinc acetate solution is pumped to the suction side of the RCS charging pumps via a positive displacement pump on the skid. The connection point for the zinc injection is downstream of the connection point for the metering pump for the chemical injection skid. A concentration of zinc between 5 and 10 ppb will be maintained in the reactor coolant. The final concentration will be determined based on a zinc injection strategy developed by the NSS fuel supplier. This will require continuous monitoring and recommendations prior to completion of the first 24 months of zinc injection operation.

9.3-21 Amendment No. 24 (06/10)

By the end of the preoperational test period, any fluorides or chlorides were removed from the system and concentrations in the coolant were maintained at low levels by reactor coolant purification and demineralized makeup water addition. High hydrazine concentration is not required to inhibit halide-induced corrosion, but hydrazine is still used during heatup to scavenge oxygen. This assures complete removal of oxygen on heatup while minimizing ammonia and nitrogen generation when hot and at power.

When at power, oxygen is controlled to a very low concentration by maintaining excess dissolved hydrogen in the coolant. The excess hydrogen forces the water decomposition/synthesis reaction in the reactor core to water rather than hydrogen and oxygen. Any oxygen in the makeup water is also removed by this process.

Since operating with a basic pH control agent results in lower general corrosion release rates from the reactor coolant system materials, and because the alkali metal lithium is generated in significant quantities by the core neutron flux through the reaction B10(n,)Li7, lithium is selected as the pH control agent. The production rate of lithium from this reaction is approximately 100 ppb per day at the beginning of core life and decreases with core lifetime in proportion to the decrease in boron concentration.

However, even though lithium is the choice for pH control, there has been an historical concern that higher concentrations of lithium may result in Zirconium Alloy corrosion and primary water stress corrosion cracking (PWSCC). Current industry consensus is that consequential specific lithium ion or pH effect on PWSCC is unlikely over the range of relevant primary chemistries and is small in comparison to other sources of variability in susceptibility. The plant's boron/lithium program places controls on pH and lithium to mitigate Zirconium Alloy corrosion and PWSCC susceptibility.

Early in core life lithium production is the greatest and periodic removal by ion exchange is required to control the concentration below the upper limit. Late in core life lithium additions will be necessary to maintain lithium concentration within the control limits. Lithium is removed along with cesium by intermittent operation of an ion exchanger while a second ion exchanger is operated continuously for the removal of fission and corrosion products. The resin beds remove soluble nuclides by the ion exchange mechanism. Insoluble particles are removed by the combined effect of ion exchanger(s) and/or by the cartridge type filter(s), located upstream and downstream of the ion exchangers. A strainer downstream of the ion exchangers protects against the gross release of resin to the coolant in the event of an ion exchanger retention element failure.

The boron concentration is controlled to obtain optimum CEA positioning to compensate for reactivity changes associated with changes in coolant temperature, core burnup, xenon concentration variations and to provide shutdown margin for maintenance and refueling operations or emergencies.

The normal method of adjusting boron concentration is by the technique of feed and bleed. To change concentration, the makeup system supplies either primary makeup water or concentrated boric acid to the volume control tank, or directly to the charging pump suction header, and the letdown stream is diverted to the waste management system. Toward the end of a core cycle, the quantities of waste produced due to feed and bleed operations become excessive due to the low boron concentration and deborating operations with one or two of the CVCS ion exchangers used to reduce the reactor coolant system boron concentration.

UNIT 1 9.3-22 Amendment No. 28 (05/17)

Two boric acid makeup tanks and two boric acid pumps supply boric acid to the reactor coolant system via the volume control tank and charging pumps. There are four modes of makeup system operation. In the dilute mode, a preset quantity of primary makeup water is added into the volume control tank at a preset rate. In the borate mode, a preset quantity of concentrated boric acid is introduced at a preset rate. In the manual mode, the flow rates of the primary makeup water and the concentrated boric acid are preset manually to give any boric acid solution between zero and concentrated boric acid. This latter mode can be used for makeup and filling the safety injection tanks and the refueling water tank. In the automatic mode, a preset boric acid solution is automatically mixed and introduced into the volume control tank upon demand from the volume control tank level program. The preset solution concentration is adjusted periodically by the operator to match the boric acid concentration being maintained in the reactor coolant system.

The location numbers on the chemical and volume control system P&ID, Figures 9.3-4 and 9.3-5, indicate the process flow reference points in the system. Table 9.3-11 is a tabulation of the process flow data for the three modes of purification loop operation and six modes of makeup system operation using these numbers as reference points. Basically, a letdown flow of 40 gpm is normal purification operation, a letdown flow of 84 gpm is intermediate purification operation and a letdown flow of 128 gpm is maximum purification operation. Maximum purification flow while aligned to shutdown cooling is limited to 128 gpm when using the charging pumps to maintain Pressurizer level. Flow rate may be higher than 128 gpm (charging pump maximum flow) during Shutdown Cooling purification operation (RCS temperature

<140°F, RCS vented, flow from LPSI Pump and returned to LPSI Pump suction). There are two modes of SDC purification operation. The first is through the Letdown Heat Exchanger (limited to 200 gpm with parallel flow through two ion exchangers) and the second bypasses the Letdown Heat Exchanger (limited to 360 gpm with parallel flow through two ion exchangers), with individual flow through one ion exchanger limited to 180 gpm for both modes of operation.

9.3.4.2.2 Components The major components of the CVCS are described below:

a) Regenerative Heat Exchanger The regenerative heat exchanger, located in the containment above floor elevation 16.0 feet, conserves reactor coolant system thermal energy by transferring heat from the letdown stream to the charging stream. The heat exchanger is designed to maintain a letdown outlet temperature below 450F under all normal operating conditions. The design characteristics of the regenerative heat exchanger are given in Table 9.3-12.

UNIT 1 9.3-23 Amendment No. 28 (05/17)

b) Letdown heat exchanger The letdown heat exchanger located in the auxiliary building on floor elevation 19.5 feet uses component cooling water to cool the letdown flow from the outlet temperature of the regenerative heat exchanger to a temperature compatible with long term operation of the purification system ion exchangers. The unit is sized to cool the maximum letdown flow rate from the maximum outlet temperature of the regenerative heat exchanger (450°F). To prevent possible damage to the heat exchanger by excessive component cooling water flow (1600 gpm max.) the cooling water flow rate is indicated and alarmed on high flow (1400 gpm) in the control room. The letdown temperature control valve also has a mechanical stop to limit the component cooling water flow to the letdown heat exchanger during normal plant operation. The design characteristics of the letdown heat exchanger are given in Table 9.3-13.

c) Purification filters Purification filter 1A located in the auxiliary building on floor elevation 19.5 feet removes insoluble particulates from the reactor coolant prior to entering the ion exchanger. Purification Filter 1B downstream of the ion exchangers and strainer, is the same as Filter 1A and serves to retain any resin fines that may be released from the ion exchangers. The unit is designed to pass the maximum letdown flow without exceeding the allowable differential pressure across UNIT 1 9.3-24 Amendment No. 28 (05/17)

the filter media in the maximum fouled condition. Due to the buildup of high activity levels during normal operation, the unit is designed for remote removal of the contaminated media. The design characteristics of the filters are given in Table 9.3-14.

Filter media for the 1A/1B Purification Filters is selected based on current and anticipated changes in plant loading or outage conditions. CVCS Purification Filter media was originally specified at 2 micron absolute in order to remove 95% by weight of the expected non-soluble particles from the RCS. Plant operating experience has shown that removal of a greater portion of particulates via the Purification Ion Exchangers has ALARA and radioactive waste disposal benefits. Plant operating experience has also shown that use of smaller size media in the 1B Purification Filter to remove sub-micron particulates has ALARA benefits. Accordingly, the 1A filter upstream from the purification ion exchangers is typically bypassed to allow insoluble particulates from the letdown flow to be filtered by the resin beds. Various grade filter media is used with the CVCS purification filters optimize removal of smaller non-soluble reactor coolant particles (PCM 98043).

d) Purification and Deborating Ion Exchangers -

The CVCS is provided with three identical ion exchangers. Each ion exchanger is sized for the maximum letdown flow rate. One ion exchanger is used intermittently to control the lithium and cesium concentration in the reactor coolant system and another is used for normal constant operation. The units usually contain both anion and cation resins and are provided with all connections required to replace the resins by liquid and air sluicing. The third CVCS ion exchanger, originally designated as the deborating ion exchanger, is identical to the purification ion exchangers in size and construction and was originally sized to contain sufficient anion resin to control the reactor coolant system boron concentration from 30 ppm to the end of core cycle.

However, one or two of the three ion exchangers can be used to deborate down to end of core cycle in accordance with plant procedures. Furthermore, all three ion exchangers are interchangeable depending on the operating conditions of the plant. Within each ion exchanger, cation and anion resins may be mixed or arranged in layers as determined by Chemistry personnel. As permitted by Engineering Evaluation, CVCS ion exchangers may contain an overlay of specialty resin to target removal of fine particulates and/or specific ionic species.

The design characteristics of the ion exchangers are given in Table 9.3-15. The three ion exchangers are located in the auxiliary building on floor elevation 19.5 feet. Parallel flow through two Ion Exchangers is required when operating at maximum purification flow (up to 360 gpm) while aligned to the Shutdown Cooling System and returning flow to the Shutdown Cooling System.

e) Volume Control Tank -

The volume control tank, located in the reactor auxiliary building on floor elevation 19.5 ft, accumulates letdown water from the reactor coolant system to maintain the desired hydrogen concentration in the reactor coolant, and to provide a reservoir of reactor coolant for the charging pumps. The tank is sized to store sufficient liquid volume below the normal operating band to allow a swing from full power to zero power without makeup to the volume control tank and such that sufficient useful volume is above the normal operating band to permit the accumulation of approximately 500 gallons of water during dilution operations. The accumulated water is normally sufficient to provide normal plant leakage makeup between dilution operations. The tank is provided with hydrogen and nitrogen gas supplies and a vent to the waste management system to enable venting of hydrogen, nitrogen and fission gases. the volume control tank is initially purged with nitrogen and a hydrogen overpressure is established. The design characteristics of the volume control tank are given in Table 9.3-16.

UNIT 1 9.3-25 Amendment No. 28 (05/17)

f) Charging Pumps -

The charging pumps, located in the reactor auxiliary building on floor elevation -0.50 ft, take suction from the volume control tank on the floor level above and return the purification flow to the reactor coolant system during plant steady state operations. Normally one pump is running to balance the letdown purification flow rate plus the reactor coolant pump controlled bleedoff flow rate. The second and third pumps are automatically started or stopped, as pressurizer level decreases or increases due to plant load transients. Automatic control is normally used during EC029 operation but manual control may be utilized at any time. Additionally all three charging pumps 6159 discharge into one charging header, therefore no special valve alignment for charging pump C is required. The pumps are positive displacement type with an integral leakage collection system.

Vent, drain and flushing connections are provided to minimize radiation levels during maintenance operations. The pressure containing portions of the pump and internals are austenitic stainless steel materials for compatibility with boric acid. The pump design characteristics are given in Table 9.3-17.

g) Boric Acid Makeup Tanks -

Two boric acid makeup tanks, located between reactor auxiliary building floor levels - .50 ft and 19.5 ft, provide a source of boric acid solution (2.5 weight percent minimum) for injection into the reactor coolant system. Each tank is insulated and one of the redundant strap on electrical heaters has been de-energized. Tank heaters and insulation are not required to maintain Boric Acid in solution. Each tank is capable of storing boric acid in concentrations up to 3.5 weight percent. The combination of the BAMTs and RWT contain sufficient boric acid below the normal makeup band to bring the plant to a cold 5 percent , subcritical shutdown condition. The design characteristics of the tanks are given in Table 9.3-18. The borated water concentration and volume in each boric acid makeup tank (BAMT) is based upon maintaining 3600 pcm shutdown margin during a plant shutdown. Borated water is added to the RCS inventory to makeup for RCS volume contraction during the cooldown. Sufficient boric acid is added from a BAMT to the RCS to achieve a condition where the cooldown can be concluded using inventory and boric acid concentration from the Refueling Water Tank (RWT). The BAMT volumes and concentrations were calculated in Combustion Engineering Report CEN-353(F), Rev. 01, Dated June 22, 1988. The volumes and concentrations were reverified as part of the Cycle 23 reload analysis using the same methodology as in CEN-353(F), Rev. 01.

9.3-26 Amendment No. 32 (04/23)

h) Boric Acid Batching Tank The boric acid batching tank, located on reactor auxiliary building floor level 43.0 ft and above the boric acid makeup tanks, is used for the preparation of concentrated boric acid which is batch gravity drained to the makeup tanks. The tank is designed to permit handling of up to 12 weight percent boric acid. The tank is heated and insulated and is supplied with demineralized water for mixing the boric acid solution. Sampling provisions, mixer, temperature controller and electric immersion heaters are an integral part of the batching system. The design characteristics of the tanks are given in Table 9.3-19. The solution in the batching tank must be diluted to 2.5-3.5 weight percent boric acid prior to reaching the BAMT.

i) Boric Acid Makeup Pumps The boric acid makeup pumps, located in the auxiliary building on the floor at elevation -0.5 feet, take suction from the overhead boric acid makeup tanks and provide boric acid to the makeup subsystem and to the charging pump suction header. The capacity of each pump is greater than the combined capacity of all three charging pumps. The boric acid makeup pumps are also used to recirculate makeup tank contents, to pump from one makeup tank to the other, and to supply makeup to the refueling water tank. The pumps are single stage centrifugal pumps with mechanical seals and liquid and vapor leakage collection connections. The heat tracing on the suction and discharge piping of the pumps has been de-energized, and insulation on these lines is no longer required. The design characteristics of the pumps are given in Table 9.3-20.

j) Chemical Addition Tank and Metering Pump The chemical addition tank and metering pump, both located on reactor auxiliary building floor elevation 19.5 ft, provide a means to inject chemicals into the charging pump suction header.

Primary makeup water is supplied for chemical dilution and flushing operations. The design characteristics of the tank are given in Table 9.3-21. The tank size and pump capacity are based on the maximum service requirement of hydrazine injection for oxygen scavenging on plant startup and lithium hydroxide for pH control. The design characteristics of the metering pump are given in Table 9.3-22.

k) Process Radiation Monitor (R-2202)

The process radiation monitor described in Section 11.4, located in the 1/2 inch line bypassing purification filter 1A, provides a continuous recording in the control room of reactor coolant gross gamma radiation and specific fission product gamma activity. A high alarm indicates an increase in coolant activity above the setpoint within 5 minutes of the event. The design characteristics of the pressure boundary of the monitor are given in Table 9.3-23.

9.3-27 Amendment No. 21 (12/05)

l) Boronometer (A-2203)

The boronometer has been abandoned via PC/M 02170. As a result, much of the related circuitry has been removed; however, pressure boundary portions remain installed and therefore design characteristics of the boronometer pressure boundary are given in Table 9.3-24.

m) Relief Valves To assure safe operation of the CVCS, overpressure protection is provided by relief valves throughout the system. The following is a description of the relief valves in the system.

1) Intermediate pressure letdown relief valve, V2345 The relief valve downstream of the letdown control valves protects the intermediate pressure letdown piping and letdown heat exchanger from overpressure. The valve capacity is approximately equal to the capacity of one letdown control valve in the wide open position during normal operation. The other letdown control valve must be closed and isolated before plant pressure exceeds 1500 psig.

9.3-28 Amendment No. 22 (05/07)

The relief valve set pressure, (600 psig) is less than the design pressure (650 psig) of the intermediate pressure letdown piping and letdown heat exchanger.

2) Low-pressure letdown relief valve, V2354 The relief valve downstream of the letdown backpressure control valves protects the low pressure piping, purification filters, ion exchangers and letdown strainer from overpressure. The valve capacity is equal to the original capacity of intermediate pressure letdown relief valve V2345 (i.e., 325 gpm). The set pressure is equal to the design pressure (200 psig) of the low pressure piping and components. Administrative controls are provided to govern alignment of the purification system components with the shutdown cooling system to prevent lifting V2354.
3) Charging pump discharge relief valves, V2324, V2325, V2326 The relief valves on the discharge side of the charging pumps are sized to pass the maximum rated flow of the associated pump with maximum backpressure without exceeding the maximum rated total head for the pump assembly. The valves are set to open when the discharge pressure exceeds the reactor coolant system design pressure (2485) by 10 percent.
4) Charging pump suction relief valves, V2315, V2318, V2321 The relief valves on the suction side of the charging pumps are sized to pass the maximum fluid thermal expansion rate that would occur if the pump were operated with the suction and discharge isolation valves closed. The set pressure is less than design pressure of charging pump suction piping.
5) Charging line thermal relief valve, V2435 The relief valve on the charging line downstream of the regenerative heat exchanger is sized to relieve the maximum fluid thermal expansion rate that would occur if hot letdown flow continued after charging flow was stopped by closing the charging line distribution valves. The valve is a spring-loaded check valve.
6) Volume control tank relief valve, V2115 The relief valve on the volume control tank is sized to pass a liquid flow rate equal to the sum of the following flow rates: the maximum operating flow rate from the reactor coolant Pump controlled bleedoff line; the maximum letdown flow rate possible without actuating the high flow alarm on the letdown flow indicator; the design purge flow rate of the sampling system; and the maximum flow rate that the boric acid makeup system can produce with relief pressure in the volume control tank. The set pressure is equal to the design pressure of the volume control tank.

9.3-29 Amendment No. 22 (05/07)

7) Volume Control Tank Gas Supply Relief Valve, V2105 The relief valve is sized to exceed the combined maximum capacity of the nitrogen and hydrogen gas regulators. The set pressure is lower than the volume control tank design pressure.
8) RCP Controlled Bleedoff Header Relief Valve,V2199 The relief valve at the reactor coolant pump controlled bleedoff header allows the controlled bleedoff flow to be directed to the quench tank in the event that a valve in the line to the volume control tank is closed and does not serve an overpressure protection function. The valve is sized to pass the flow rate required to assure closure of one excess flow check valve in the event of failure of the seals in one reactor coolant pump plus the normal bleedoff from the other reactor coolant pumps. The maximum relief valve opening pressure is less than the controlled bleedoff high-high pressure alarm.
9) Heat Traced Piping Thermal Relief Valves, V2123 and V2311 Relief valves are provided for those portions of the boric acid system that are heat traced and which can be individually isolated. The set pressure is equal to or less than the design pressure of the system piping. Each valve is sized to relieve the maximum fluid thermal expansion rate that could occur if maximum duplicate heat tracing power were inadvertently applied to the isolated line. Prior to implementation of PC/M 89336, valve V2311 provided protection for a piping section affected by heat tracing.

n) Piping and Valves The piping of the chemical and volume control system is austenitic stainless steel. The cooling water side of the letdown heat exchanger is carbon steel. All piping is in accordance with the code for pressure piping of the USA Standard, USASI-B31.1, or B31.7, as applicable.

The design basis and actuator capabilities for V2501, V2504, V2508, V2509 and V2514 have been reviewed in accordance with the requirements of Generic Letter 89-10, "Safety Related Motor Operated Valve Testing and Surveillance," as noted in Section 3.9.2.4.

All valves except the diaphragm type have backseats to limit stem leakage when in the open position. Diaphragm-type valves are used to prevent radioactive gas leakage from the volume control tank and also for resin sluicing operations for the ion exchangers. Manually operated valves for radioactive service with nominal sizes larger than two inches are provided with a double-packed stem and intermediate lantern ring with a leakoff connection. All actuator operated valves for liquid service have stem leakoffs or have the EPRI recommended 5 ring packing stack up, with capped leak off connections.

o) Electrical Heaters Electrical heat tracing is installed in duplicate on all piping valves, pumps and other line-mounted components that may potentially contain boric acid solutions greater than 3.5 weight percent for a significant period of time. The heat tracing is designed to prevent precipitation of boric acid due to cooling. The portions of the system that are heat traced are indicated on the piping and instrumentation diagrams, Figure 9.3-5. Portions of the waste management are also heat traced.

9.3-30 Amendment No. 22 (05/07)

The boric acid system requires heat tracing only in the Boric Acid Batching tank, the piping through the Batching strainer and the piping up to the BAMTs.

The heat tracing is designed to maintain the fluid temperature of the traced components at 160 +/-

10F with insulation designed as described below. This criterion assures that the boric acid will be at least 25F above the saturation temperature for 12 weight percent boric acid solution.

Heat tracing is only required in those sections of the boric acid makeup system that could contain greater than 3.5 weight percent boric acid solutions. The boric acid batching tank, the piping through the batching strainer and the piping up to the boric acid makeup tanks are heat traced.

Temperature controls and independent alarm circuits are included in the system.

The remaining sections of the boric acid makeup system do not require heat tracing. The boric acid concentration in these remaining sections is between 2.5 and 3.5 weight percent. Figure 9.3-9 is a plot showing the solubility of boric acid in water from 32 to 160 degrees F. Note that the solubility at 32 degrees is 2.52 weight percent and at 50 degrees is 3.49 weight percent. At or below 3.5 weight percent boric acid the ambient temperature of the auxiliary building will be sufficient to prevent precipitation within the boric acid makeup system.

Two independent full capacity strap-on-type heater banks are installed on each boric acid makeup tank. The heaters are sized to compensate for heat loss through the tank insulation to the surroundings when the tank is filled to its maximum operating level with boric acid at its maximum temperature. Each heater bank is operated by an independent controller. The heaters need not be energized to maintain 2.5 - 3.5 weight percent Boric Acid in solution. One of the heaters has been de-energized per PC/M 89336 with the other remaining operational, energizing at 60F (dropping) or decreasing temperature.

The batching tank is provided with corrosion resistant electrical immersion heaters. The heaters are sized to supply sufficient heat in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to increase the temperature of 500 gallons of 12 weight percent boric solution from 40F to 160F including the heat of solution required to dissolve the boric acid granules. The boric acid is added to the tank maintaining the demineralized water temperature above the boric acid crystallization point .

p) Thermal Insulation Thermal insulation protects personnel from contact with high temperature piping valves, and components. Equipment and sections of the system that are insulated are the regenerative heat exchanger, the charging and auxiliary spray lines downstream of the regenerative heat exchanger and the letdown line from the reactor coolant loop to the letdown heat exchanger.

Thermal insulation on these sections is designed to limit the insulation surface temperature of 150F based on ambient temperature of 120F and the maximum expected piping and component temperature. Electrically heat traced piping, valves, and other components are insulated to limit the insulation surface temperature to 120F based on an ambient temperature of 80F and a component temperature of 160F.

Thermal insulation on the batching tank is designed to limit heat losses to 16.3 Btu/hr-ft2 based on a tank temperature of 160F and an ambient temperature of 40F. Thermal insulation with ion chloride content that does not cause chloride stress corrosion or that contains a chloride stress corrosion inhibitor is used on all stainless steel surfaces and on any insulated surfaces adjacent to stainless steel surfaces where moisture from that insulation could reach the stainless steel.

9.3-31 Amendment No. 18, (04/01)

INTENTIONALLY DELETED 9.3-31a Amendment No. 17, (10/99)

q) Refueling Water Tank In addition to its primary function of providing safety injection inventory to the ECCS pumps in case of an accident, the refueling water tanks (RWT) CVCS functions include the following:

- RCS borated makeup inventory during plant cooldown

- standby emergency boration source if normal emergency boration not available

- standby suction source for the charging pumps should VCT level become too low

- borated water makeup for the refueling pool and SITs

- borated refueling water source for refueling canal The RWT is also used as a suction source and return reservoir for ECCS pump surveillance runs.

r) Zinc Injection A zinc injection skid is mounted in the Reactor Auxiliary Building, elevation 43 ft., in the Boric Acid Batch Tank Room. The skid consists of two positive displacement pumps, one of which is a spare, one mixing tank for zinc solution, one recirculation pump to mix the solution, and piping components and controls.

The zinc solution is pumped to the suction of the charging pumps. The connection point for the zinc injection is on the vent line with valve V2838 on elevation 19.5 feet of the Reactor Auxiliary Building.

Design data for the zinc injection skid are shown in Table 9.3-31.

9.3.4.2.3 Plant Startup Plant startup is the series of operations which bring the plant from a cold shutdown condition to a hot standby condition at normal operating pressure and zero power temperature with the reactor critical at low power level.

The charging pumps and letdown backpressure valves are used during initial phases of reactor coolant system heatup to maintain the reactor coolant system pressure until the pressurizer steam bubble is established. One charging pump will normally operate during plant startup to cool the letdown fluid to maintain design pressure and temperature limits in the letdown portion of the system.

During the heatup, pressurizer water level is controlled using the backpressure control valves and the letdown control valves. Letdown flow is automatically diverted to the waste management system when the high level limit is reached in the volume control tank.

The reactor coolant system boron concentration may be reduced during heatup in accordance with shutdown margin limitations. The shutdown group of control rods must be in the fully withdrawn position before any dilution of reactor coolant system boron concentration is started, for the final approach to initial criticality following refueling. For subsequent restarts during the cycle, boron concentration is adjusted prior to or after fully withdrawing the shutdown group control rods. The makeup controller is operated in the dilute mode to inject a predetermined amount of primary makeup water at a preset rate. Compliance with the shutdown margin limitations is verified by sample analysis. Technical Specification has been set to define those conditions of the CVCS necessary to assure safe reactor operation and shutdown.

9.3.4.2.4 Deleted.

9.3-32 Amendment No. 24 (06/10)

9.3.4.2.5 Plant Shutdown Plant shutdown is accomplished by a series of operations which bring the reactor plant from a hot standby condition at normal operating pressure and zero power temperature to a cold shutdown for maintenance or refueling.

Prior to plant cooldown, the gas space of the volume control tank is vented to the waste management system to reduce dissolved hydrogen concentration and fission gas activity. The purification rate may be increased to accelerate the degasification, ion exchange and filtration processes. Addition of chemicals is not normally required during plant shutdown although hydrogen peroxide may be added to the RCS to facilitate the removal of corrosion products (see PSL-ENG-SEMS-97-066).

As discussed in NRC Generic Letter 2008-01 and INPO SER 2-05, the presence of unanticipated gas voids within fluid systems can challenge the ability of systems to perform their design functions due to issues such as gas binding, water hammer, injection delay times, etc. Requirements for maintaining Charging System operability with respect to gas intrusion are contained within Gas Accumulation Management Program procedures.

Historically, the boron concentration in the RCS was increased to the cold shutdown value prior to the plant cooldown. This methodology required BAMT Boric Acid concentration in the range of 8-12 weight percent.

As a result of the Boric Acid Concentration Reduction analysis provided in Combustion Engineering Report CEN-353(F), Rev. 01, the methodology for plant shutdown was changed. The RCS is borated from the BAMTs followed by the RWT as part of normal inventory makeup due to cooldown contraction.

As part of the EPU to 3020 MWt, Technical Specification Figure 3.1-1 has been updated to provide increased boration capability. The boric acid delivery capability of the CVCS has been calculated for each temperature during the limiting cooldown without letdown for these updated Technical Specification LCOs. For each new cycle, the boron concentration needed to maintain the required shutdown margin for the new core is calculated for each temperature for the limiting cooldown. These requirements are verified to be less than the limiting capability of the CVCS as described above. In this way, the RCS boron concentration is maintained above the concentration needed to maintain the required shutdown margin throughout the cooldown.

UNIT 1 9.3-32a Amendment No. 28 (05/17)

The boron concentration in the reactor coolant is increased to the cold shutdown value during the cooldown of the plant. This is done to assure sufficient shutdown margin for maintenance activities.

During the cooldown, the charging pumps, letdown control valves, and letdown backpressure valves are used to adjust and maintain the pressurizer water level. High charging flow results in a low level in the volume control tank which initiates automatic makeup at the selected shutdown boron concentration. If the shutdown is for refueling, which requires a higher boron concentration than the cold shutdown value, the suction for the charging pumps is connected to the refueling water tank during plant cooldown. This is required because the automatic blending line from the boron system cannot supply the refueling boron concentration at maximum charging flow. All or a portion of the charging flow may be used for auxiliary spray to cool the pressurizer if the reactor coolant system pressure is below that allowable for reactor coolant pump operation.

During refueling or other shutdown periods, a portion of the shutdown cooling flow from the common header on the discharge side of the Low Pressure Safety Injection (LPSI) pumps is diverted to purify Reactor Coolant Inventory. The flow is directed to the Chemical and Volume Control System (CVCS) and is processed by the CVCS ion exchangers and filters. The flow may then be returned to the suction of the LPSI pumps via the shutdown cooling lines (Figures 6.3-1, 6.3-2 and 9.3-4).

9.3.4.3 System Evaluation 9.3.4.3.1 Performance Requirements and Capabilities The normal amount of boric acid stored solution in either of the boric acid makeup tanks and the RWT is sufficient to bring the plant to a 3600 pcm subcritical cold shutdown condition at any time during plant life if the volume required by Technical Specification Figure 3.1-1 is maintained.

The borated water concentration and volume in each Boric Acid Makeup Tank (BAMT) is based upon maintaining a 3600 pcm shutdown margin during a plant shutdown. Borated water is added to the RCS inventory to makeup for RCS volume contraction during the cooldown. Sufficient boric acid is added from the BAMT to the RCS to achieve a condition where the cooldown can be concluded using the lower boric acid concentration from the Refueling Water Tank (RWT).

The charging pumps are used to inject concentrated boric acid into the reactor coolant system. With one pump normally in operation, the other charging pumps are automatically started by the pressurizer level control or by the safety injection actuation signal (SIAS). The safety injection actuation signal also causes the charging pump suction to be switched from the volume control tank to the boric acid pump discharge.

Should the pumped boric acid supply be unavailable, the charging pumps are also lined up for gravity feed from the boric acid makeup tanks. Should the charging line be inoperative for any reason, the line may be isolated outside the reactor containment, and the charging flow may be injected via the safety injection system. The malfunction or failure of one active component does not reduce the ability to borate the reactor coolant system since an alternate flow path is always available for emergency boration. The alternate charging path, via the safety injection system, could be used to maintain the water level and boron concentration of the Safety Injection Tanks and to provide a means of functionally testing the RCS to SI isolation check valves.

If the letdown temperature exceeds the maximum operating temperature of the resin in the ion exchangers (140F) the flow will automatically bypass the ion exchangers and the process radiation monitor.

UNIT 1 9.3-33 Amendment No. 28 (05/17)

The charging pumps, boric acid makeup pumps, and all related automatic control valves are connected to an emergency bus should the normal power supply system fail. There are two emergency diesel generator sets available for this service and the components are aligned to the diesels as designated below:

Component Diesel A Diesel B Charging Pump No. 1A and seal system X Charging Pump No. 1B and seal system X Charging Pump No. 1C and seal system swing bus Boric acid makeup pump No. 1A X Boric acid makeup pump No. 1B X Boric acid gravity feed valve V2508 X Boric acid gravity feed valve V2509 X Heat tracing system No. 1A X Heat tracing system No. 1B X Boric acid makeup pump supply valve V2514 X Volume control tank discharge valve V2501 X Letdown stop valve V2515 X Letdown stop valve V2516 X Controlled bleedoff stop valve V2505 X Boric acid recirculation valve V2510 X Boric acid recirculation valve V2511 X Boric acid makeup stop valve V2512 X 9.3-34 Amendment No. 22 (05/07)

Frequently used, manually operated valves located in high radiation or inaccessible areas are provided with extension stem handwheels terminating in low radiation and accessible control areas. Manually operated valves are provided with locking provisions if unauthorized operation of the valve is condisered a potential hazard to plant operation or personnel safety.

Leakage can be detected by the gamma sensitive area radiation monitors which are located in strategic areas throughout the plant. The gamma flux level seen by each detector is indicated, annunciated and recorded in the control room. Any significant leakage from the CVCS annunciates one of these alarms.

The chemical and volume control system can also monitor the total reactor coolant system water inventory. With no leakage in the reactor coolant system the level in the volume control tank remains constant during steady state plant operation. Therefore, a decreasing level in the volume control tank alerts the operator to a possible leak. A more detailed discussion of leakage detection systems is presented in Section 5.2.4.

Shutdown Without Letdown The safety consideration, with regard to the chemical volume and control system (CVCS), is simply whether or not the facility can be brought from the hot standby condition to the shutdown cooling system window with the present design. It is demonstrated below that the letdown loop of the CVCS is not required to achieve this safety related objective. Thus the letdown loop is appropriately designed non-seismic.

The method described below was made possible by a closer examination of the core physics parameters that determine required RCS boron concentration to meet shutdown margin requirements. This method is described in more detail in CE Report CEN-353(F), Rev. 01. These changes allow boration of the RCS concurrently with plant cooldown, which allows the reduction in the BAMT boric acid storage requirements to those shown in Technical Specification Figure 3.1-1. The required shutdown margin of 3600 pcm was maintained throughout the cooldown.

The following effects must be accounted for in a plant cooldown: (1) maintaining the adequate shutdown margin, (2) accommodating reactor coolant shrink, and (3) insuring sufficient coolant is available for pressurizer pressure control. These effects are handled as follows:

- prior to cooldown, the RCS is brought to hot standby subcritical condition with the CEAS;

- the total RCS shrink from hot standby to cold shutdown is supplied from the boric acid makeup tanks and from the refueling water tank; and

- pressurizer pressure control also requires the addition of makeup supplied from the charging subsystem.

9.3-35 Amendment No. 26 (11/13)

The assumptions used to demonstrate the ability to place the plant on shutdown cooling without letdown are as follows:

- the limiting case is at end of cycle and the RCS boron concentration is 0 ppm;

- only one charging pump is used;

- the reactor coolant pumps are not available and pressurizer pressure control is accomplished via the auxiliary spray line;

- RCS temperature control is accomplished by a secondary side steam dump; and

- boric acid entering the pressurizer via the auxiliary spray line is not assumed to mix with the reactor coolant.

The requirement to maintain Technical Specification shutdown margin can be met for a range of boric acid concentrations in the BAMT and RWT. This range is bounded by 6,800 gallons of 3.5 weight percent boric acid from the BAMT and 15,600 gallons of 1900 ppm borated water from the RWT to 8,700 gallons of 3.0 weight % boric acid from the BAMT and 13,000 gallons of 1900 ppm borated water from the RWT.

The unit is placed on shutdown cooling as follows:

A. Achieve Adequate Shutdown Margin The charging pump(s) with suction from the boric acid makeup tank, via the boric acid makeup pump discharge or the gravity feed line, deliver 3.0 weight percent (minimum) boric acid to the RCS via the charging line. This is done concurrently with plant cooldown as part of the normal inventory makeup while pressurizer level is maintained constant.

Sufficient shutdown margin is provided even with the most reactive CEA stuck out of the core.

9.3-35a Amendment No. 26 (11/13)

B. Depressurization to the High Pressure Safety Injection Window and Subsequent Cooldown to the Shutdown Cooling Window The system is depressurized using spray supplied by the charging pump(s) with suction from the Boric Acid Makeup Tanks. The system is cooled down by using the atmospheric steam dump. Cooldown is within the Technical Specification limit as the RCS cools down. Shrinkage makeup will be supplied by the charging pump(s) taking suction from the boric acid makeup tanks until they are empty and then from the refueling water tank.

The cooldown and depressurization are continued until the RCS pressure reaches the high pressure safety injection pumps shutoff head at about 1400 psia and the RCS temperature greater than 50 degrees below the saturation temperature at that pressure.

At this point, these safety injection pumps are available with suction from the RWT and can be used to compensate for shrinkage. The RCS is further cooled down and depressurized to the shutdown cooling window using the RWT as a source of water.

C. Shutdown Cooling Initiation Once the shutdown cooling conditions are reached the unit is placed on shutdown cooling. Thus, safe shutdown is achieved without the use of the letdown line. It should be noted that since water is supplied with a much greater boric acid concentration than that of the RCS, the RCS boron concentration will rise and will always be greater than the minimum requirement to ensure adequate shutdown margin during the cooldown.

Since safe shutdown can be achieved without letdown flow, the letdown portion of the CVCS has no specific requirement to function for post-accident operation. It is for this reason that the letdown line is appropriately designed to the Non-Seismic Category I.

In Amendment 26 (6/8/74) and Amendment 27 (6/25/74)at Q9.21 the ability to achieve a cold shutdown subsequent to the occurrence of the design basis earthquake (DBE) was demonstrated. The analysis assumed loss of function of the letdown portion of the chemical and volume control system (CVCS) and loss of other non-seismic equipment. The Staff reviewed the analysis therein and concurred with the conclusion reached in its SER of 8 November 1974 at Section 9.4.2.

The post-DBE shutdown is not considered a routine procedure because moderator shrink resulting from the cooldown from operating conditions to the shutdown cooling system window is not accommodated in the normal manner. For the non-seismic case of loss of letdown, moderator shrink is compensated for in a normal manner with the charging pumps. Suction is from the refueling water tank (RWT) via a 3 inch seismic line (3-CH-938). Because the makeup system's automatic boron blending feature has insufficient EC292472 capacity to achieve the refueling boron concentration at maximum charging flow, this charging pump alignment is available for a refueling shutdown if the BAM tanks are not available.

9.3-36 Amendment No. 30 (05/20)

Shutdown Without Auxiliary Spray and Without Letdown The above procedure utilized pressure control via the auxiliary spray valve SE-02-3. If it is assumed that the valve was not available also, the operator can still bring the plant to safe shutdown.

Since a charging pump flow of 44 gpm delivers water to the RCS loops at a rate of about 6.1 lbs/second (RCS inventory at normal pressurizer level is about 470,000 lbs), the addition of cool fluid to pressurizer is slow. Thus, it is reasonable to assume that the entire pressurizer is at thermodynamic equilibrium. With this assumption, those stated heretofore, and neglecting pressurizer heat loss (about 50 kw), the cooldown to a 1200 psia window without use of SE-02-3 is accomplished as follows:

a) The pressurizer is slowly filled with fluid via the surge line by charging with suction from the BAMT until the level is increased from 460 to 1300 cubic feet. The equilibrium pressure is 1600 psia, and about 4800 gallons of fluid is added from the BAMT. The BAMT usage and RCS concentration cited include the effect of shrink. (It should be noted that fluid entering the pressurizer does so via the RCS thus, credit for boron is assumed for all fluid entering the pressurizer. The RCS boron concentration is therefore greater than that arrived at in the previous procedure.)

9.3-37 Amendment No. 26 (11/13)

b) The saturation temperature in the pressurizer is about 605F whereas the RCS temperature is about 532F. The RCS must remain subcooled. Thus, RCS cooldown via the atmospheric steam dump is initiated to reduce the RCS temperature to about 470F. Shrink causes the pressurizer level to fall to about 700 cubic feet.

c) The pressurizer is again slowly filled from the BAMT from 700 to 1300 cubic feet. Accounting for shrink, the equilibrium pressure is 1200 psia, and about 3600 gallons (8400 gallons total) was added from the BAMT.

d) The HPSI window has been reached; the operator could now inject HPSI from the RWT. About 8400 gallons from the BAMT is required to reach the HPSI window.

e) The same procedure as above could be used to reach the shutdown cooling window except that the RWT supplies the charging flow.

The propriety of assuming that equilibrium (saturation) conditions are achieved in the pressurizer in a timely manner would be difficult to establish analytically. Qualitative discussion demonstrates that the assumption is reasonable. Since an alternative positive means of depressurization is available, the need to experimentally verify the rate of pressurizer cooldown is obviated. The alternate being controlled actuation of the pressurizer power operated relief valves. This is accomplished as follows:

a) The operator places the pressurizer power relief valve control in override. This defeats the high pressurizer pressure trip signal which opens these valves.

b) The operator initiates a high pressurizer pressure trip signal by pulling two channel trip units.

c) The operator places the pressurizer power operated relief valve control in Normal. The trip signal opens the relief valves. Returning the control to override closes the relief valves.

It must be noted that the entire discussion above is predicated on the assumption that many highly unlikely events occur. Even under the various conditions postulated the operator can achieve his shutdown cooling window, which demonstrates the adequacy of the design.

9.3-38 Amendment No. 17 (10/99)

The above demonstrates that safe cold shutdown can be achieved even if a single failure is assumed in addition to the highly unlikely combination of events postulated therein. Nonetheless, if the Staff requires it and so states in the SER, a second auxiliary spray valve will be installed in parallel with auxiliary spray valve I-SE-02-3. Since the design can accommodate the postulated event plus single active failure, the addition of this valve would be governed by 10 CFR 50.109 requirements. It would be installed prior to completion of the first refueling outage. (Note: A second auxiliary spray valve, I-SE-02-4, has been installed in parallel with I-SE-02-3).

Plant Shutdown After a Tornado Event In the above discussions, it is assumed that RCS shrink makeup is available from the boric acid makeup tank (BAMT) and the refueling water tank (RWT). For normal cooldown at a boron storage concentration of 3.5 percent by weight, 6800 gallons is available from the BAMT and approximately 13,000 gallons from the RWT. The RWT provides ample water storage but offers no specific protection against tornado missiles. As required by the NRC in Condition of License item I.4 and committed to in Appendix 3F, Section 6.13, the following modification has been implemented.

A two inch piping intertie has been provided between the Safety Injection Tank (SIT) common drain to the RWT, (Figure 6.3-1) and the inlet to the volume control tank (Figure 9.3-5). The minimum Technical Specification capacity for each SIT is 1090 cubic feet of water at 1900 ppm boron which makes them suitable for BOL Mode 5 makeup.

Following a postulated tornado wherein it is assumed that both the RWT and the Primary Water tank have been rendered inoperable, the remaining immediately available makeup sources for RCS makeup are the two Boric Acid Makeup tanks. Conservatively assuming that only one BAMT is available, the minimum allowable inventory for this tank is sufficient to maintain pressurizer level during the initial phase of RCS cooldown to an approximate Tavg of 450°F. Following implementation of the required SIT/VCT valve lineup, RCS cooldown would be continued by maintaining pressurizer level with RCS makeup using the charging system and the SIT/VCT tornado protected makeup source. The available inventory of one BAMT and two safety injection tanks is sufficient to accommodate the RCS shrinkage requirements down to a Tavg of less than 200°F.

The SIT/VCT intertie forms an integral part of the St. Lucie Unit 1 emergency safeguards and is consistent with the design criteria used in the existing systems. The piping from the SIT header to the VCT inlet is classified as Quality Group C, non-seismic and the VCT inlet connection as Group C, non-seismic. The validity of the non-seismic classification of the intertie is premised on not postulating concurrent preceding design basis natural phenomenon.

9.3.4.3.2 Single Failure Analysis Shown in Table 9.3-25 is a single failure analysis for the chemical and volume control system. At least one failure is postulated for each major component.

9.3-39 Amendment No. 26 (11/13)

Additionally, various line breaks throughout the system are also considered. In each case the possible cause of such a failure is presented as well as the local effects, detection methods and compensating provision.

St. Lucie Unit 1 was licensed before the issue of NUREG-0800 Branch Technical Position RSB 5-1, and therefore, is classified as a Class 3 plant. Compliance with the requirements of RSB 5-1 is based on the combined I&E and DOR review of related plant features for operating reactors. RSB 5-1 requirements for CVCS include use of single failure proof pressurizer auxiliary spray for RCS depressurization and boration for cold shutdown.

9.3.4.3.3 Testing and Inspection Each component was inspected and cleaned prior to installation in the system. Demineralized water was used to flush the system.

Instruments were recalibrated during startup testing. Automatic controls were tested for actuation at the proper set points. Alarm functions were checked for operability and limits during preoperational testing.

The safety valve settings were checked.

9.3-40 Amendment No. 22 (05/07)

The system was operated and tested initially with regard to flow paths, flow capacity and mechanical operability. Pumps were tested at the vendor's plant to demonstrate head and capacity.

Prior to preoperational testing, the components of the chemical and volume control system were tested for operability. The components and subsystems checked include the following:

a) operation of all automatic and remote controlled valves; b) boric acid makeup pumps; c) nitrogen and hydrogen pressurization systems; d) charging pump operational check; e) check of miscellaneous valve functions, alarms and interlocks; f) instrumentation on the boric acid makeup tanks, volume control tank and boric acid batching tank; and g) installation of all valves for proper flow direction.

The system was tested for integrated operation during preoperational testing. Any defects in operation that could affect plant safety were corrected before fuel loading. As part of normal plant operation, tests and inspections, data tabulation and instrument calibrations were made to evaluate the condition and performance of the chemical and volume control system equipment. Instrumentation is available to the operators during normal plant operation to assess system heat transfer capabilities and purification efficiency.

The charging pumps permit leak testing of the reactor coolant system during plant startup operations and connections are provided to install a hydrostatic test pump in parallel with the charging pumps.

9.3.4.3.4 Natural Phenomena The chemical and volume control system components are located in the reactor auxiliary building and in the containment building and are therefore not subject to the natural phenomena described in Chapter 3 other than seismic (discussed in Section 3.7). The reactor auxiliary building arrangement showing the chemical and volume control system components is shown in Figures 1.2-12 through 1.2-17. The likelihood of sub-freezing temperatures is very low. Administrative controls have been established to monitor RAB air temperature to ensure that the BAMT solution is maintained above 55°F.

9.3.4.4 Instrument Application Table 9.3-26 lists the parameters used to monitor the chemical and volume control system.

9.3-41 Amendment No. 22 (05/07)

9.3.5 SHUTDOWN COOLING SYSTEM 9.3.5.1 Design Bases The shutdown cooling system is designed to:

a) reduce the temperature of the reactor coolant from 350°F* to refueling water temperature and maintain this temperature during refueling assuming a single active failure b) control reactor coolant temperature during the early stages of plant startup c) withstand design basis earthquake loads without loss of function d) withstand the post-LOCA short and long term environmental and corrosion conditions without loss of function.

9.3.5.2 System Description The shutdown cooling system is shown schematically in Figure 9.3-6. System component design data are given in Table 9.3-27 and the shutdown heat exchanger design data are given in Table 9.3-28. The safety injection pump design data are given in Table 6.3-2. System instrumentation utilization is described in Section 7.4.1.3. The shutdown cooling system uses portions of the reactor coolant system, safety injection system and the containment spray system in accomplishing its design functions.

9.3.5.2.1 Normal Operation During normal power operation, there are no components of the system in operation.

9.3.5.2.2 Plant Shutdown Plant shutdown to refueling conditions is the series of operations which bring the reactor from a hot standby condition of approximately 2235 psig and 532°F to a cold shutdown condition of zero psig and 135°F. Cooldown from hot standby to 325°F is accomplished through the steam dump and bypass system in conjunction with either the feedwater or auxiliary feedwater system as discussed in Chapter 10.

Shutdown cooling is initiated when the reactor coolant system conditions drop below the design pressure and temperature of the shutdown cooling equipment. At this time the system is aligned for shutdown cooling. In the shutdown cooling mode, reactor coolant is circulated using one or both of the low pressure safety injection pumps. Flow control valve FCV-3306 bypasses the shutdown cooling heat exchangers and is used in conjunction with HCV-3657 to control RCS cooldown rate. The motor operated bypass valve for FCV-3306, MV-03-2 (normally locked open), is typically closed for SDC service. For two-train service, the flow path

9.3-42 Amendment No. 25 (04/12)

from the common pump discharge splits and runs through the bypass valve (FCV-3306) and the cooling loop valve V3658 (locked open), and motor operated valves V3452 and valve V3453 (normally locked closed); through the shutdown cooling heat exchangers; through motor-operated valves V3456 (locked closed) and V3457 (locked closed), and air operated valve HCV-3657 (normally closed); to the low pressure safety injection header; and enters the reactor coolant system through the safety injection nozzles. The circulating fluid flows through the core and is returned from the reactor coolant system to the low pressure safety injection pump suction through two shutdown cooling lines. One shutdown cooling line is located in each reactor vessel hot leg pipe. In returning to the pumps, the fluid passes through normally locked closed motor-operated isolation valves V3651 and V3652 in the line from loop 1B and motor-operated valves V3480 and V3481 in the line from loop 1A. The isolation valves in the suction lines are interlocked to prevent inadvertent opening. Both valves in each of the suction lines are independently controlled by separate instrumentation channels. The interlock on these valves is further described in Section 7.6.1.1. An alarm in the control room notifies the operators if these valves are open and RCS pressure exceeds the SDCS high pressure setpoint. Any combination of pumps, heat exchangers and discharge injection paths is acceptable in meeting the system heat removal and flow requirements.

The component cooling system is the heat sink to which the reactor coolant residual heat is rejected.

Each shutdown heat exchanger receives cooling water to its shell side from a separate component cooling system essential header. The shutdown heat exchangers are sized to establish refueling water temperature (135°F) with the design component cooling water temperature (100°F) 27-1/2 hours after shutdown following an assumed infinite period of reactor operation.

System flow is established in a controlled manner to minimize the heat-up rate of the system low pressure safety injection pumps, shutdown heat exchangers and piping. The system components have been analyzed for the worst case thermal transients expected over the life of the plant for both normal and abnormal conditions.

The initial plant cooldown rate is maintained at 85°F per hour (administrative limit) or less. The cooldown EC290379 rate is controlled by adjusting the flow rate through the heat exchangers. This is accomplished by either adjusting the total system flow using the discharge headers, opening the heat exchanger bypass valve or by throttling the heat exchanger discharge control valve. If desired, the shutdown cooling flow indicator-controller (FIC-3306) can maintain a constant total shutdown cooling flow rate to the core by adjusting the heat exchanger bypass flow to compensate for changes in flow rate through the heat exchangers. During initial cooldown the temperature differences for heat transfer are large, thus only a portion of the total shutdown flow is diverted through the heat exchangers. As cooldown proceeds the temperature differences become less and the flow rate through the heat exchangers is increased to the maximum achievable. At this time full shutdown cooling flow (with the exception of any bypass valve leakage and purification flow) is through one or both of the heat exchangers.

Shutdown cooling is operated in accordance with Technical Specification during plant shutdown to maintain a refueling water temperature of 135°F or less.

A shutdown purification piping crosstie is provided in the chemical and volume control system such that during shutdown cooling a portion of the flow can be bypassed from the inlet upstream of the shutdown heat exchangers through the letdown 9.3-43 Amendment No. 30 (05/20)

portion of the chemical and volume control systems and returned to the suction line of the low pressure safety injection pumps (or returned to the RCS via the charging pumps). Flow through this bypass stream provides filtration and ion exchange of the reactor coolant via the purification filter(s) and ion exchanger(s). The design of the shutdown purification piping is consistent with that of the existing systems, i.e., Quality Group B non-seismic. The shutdown purification piping crosstie is isolated during normal plant operation using three manually operated and administratively controlled valves.

9.3.5.2.3 Plant Startup The shutdown cooling function is used during the early stages of plant startup to control reactor coolant temperature. Heat generated by reactor coolant pumps and by core decay heat is removed as required by the shutdown cooling system. Prior to commencing plant heatup above 325°F the interconnections to the reactor coolant system are isolated and the system is aligned for safety injection in accordance with plant procedures. The four isolation valves in the shutdown cooling suction lines are closed.

9.3.5.2.4 Refueling The transfer of refueling water from the refueling water tank to the reactor cavity may be accomplished using the safety injection system at the start of refueling. The reactor vessel head is removed and either a low or high pressure safety injection pump is used. For this operation, these pumps take water from the refueling water tank and inject it into the reactor coolant loops through the normal flow paths. The containment spray or the charging pumps may also be used for this operation.

At the end of refueling operations, refueling water is returned from the reactor cavity through the reactor coolant system and safety injection system to the refueling water tank. A connection is provided from the shutdown cooling heat exchanger discharge to the refueling water tank for this purpose. The low pressure safety injection pumps are used for the transfer operation.

Instrumentation is provided as shown in Figure 5.1-3 to monitor the refueling water level in the reactor vessel during reactor refueling operations. It consists of two differential pressure transmitters (one narrow range and the other wide range). Two separate level indicators along with visible and audible low level alarms are provided in the control room. When not in use, each level transmitter is isolated by redundant safety related isolation valves. The refueling level indication instrument loops interface with the Emergency Response Data Acquisition and Display System (ERDADS).

9.3.5.2.5 Emergency Operation The shutdown cooling system heat exchangers are used during the recirculation phase of safety injection system operation following a LOCA. Heat is removed from the containment sump water through the shutdown cooling heat exchangers by means of the containment spray pumps. During normal plant operation, the containment spray pumps are aligned to flow through the shutdown cooling heat exchangers. In the shutdown cooling mode of operation, isolation valves act to separate the heat exchangers from the containment spray system. The cooling system also provides the capability of diverting a portion of the cooled water from the containment spray system to the suction of the high pressure safety injection pumps for injection of cooler water into the core. For further discussion refer to Sections 6.2 and 6.3. All valves requiring operation following a LOCA are motor-operated, and controlled from the Control Room, to minimize personnel exposure after an accident.

9.3-44 Amendment No. 22 (05/07)

9.3.5.3 System Evaluation SDC performance was evaluated for a minimal power level of 3020 MWt for a normal cooldown and with a single failure. Satisfactory system performance was confirmed.

9.3.5.3.1 Performance Requirements and Capabilities When the reactor coolant system pressure falls below 1700 psig the SIAS is manually blocked. The SIAS is automatically unblocked any time the reactor coolant system pressure rises above 1706 psig. When reactor coolant pressure falls below 400 psig the safety injection tank isolation valves are closed. Prior to placing the system in operation, the boron concentration is verified in the safety injection system. Should the concentration be too low, corrective measures are used to bring it to refueling conditions prior to placing SDC in service.

System components with design pressure and temperature less than the reactor coolant system design limits are provided with overpressure protection devices and redundant isolation means. System discharge from overpressure protection devices is collected in closed systems.

Pressure relief valves are provided to protect sections of piping from pressure increases due to the thermal expansion of the contained water and inadvertant cross connections with other pressure sources.

The relief valves are shown in Figure 6.3-1 and 6.3-2.

Control valves are equipped with two sets of packing and intermediate leakoff connections that discharge to the waste management system or have the EPRI recommended 5 ring packing stack up, with capped leak off connections. Manual valves have backseats to limit stem leakage when in the open position.

Manual isolation valves are provided to isolate equipment for maintenance. Throttle valves are provided for remote manual control of heat exchanger tube side flow. Check valves prevent shutdown cooling reverse flow through the low pressure safety injection pumps.

Leakage within the emergency core cooling system equipment room described in Section 6.2.2 normally drains to the room, sump. From there it is pumped to the waste management system. Should a gross gasket failure or equipment failure occur which cannot be directly isolated, the spillage flows to the room sump. The sump pumps in each room will handle leakage for short periods of time. If leakages are greater than pump capacity or if gaseous radiation releases are greater than liquid waste system capabilities, the room is isolated. Room isolation is accomplished by stopping the pumps in that room and closing the sump isolation valve.

If a tube-to-shell leak develops in the shutdown heat exchanger, the water level in the component cooling system surge tank gives a high level alarm as described in Section 9.2.2. RCS in-leakage will be detected by radiation monitors in the CCW return headers which, upon detection, will alarm in the control room and also cause the CCW surge tank vent line to divert from venting to atmosphere to an alignment that will direct any excess inventory (i.e., in-leakage) to the Radioactive Waste Managemen System.

The shutdown cooling system components are designed to operate in the environment to which they would be exposed following a LOCA. Refer to Section 3.11. To ensure long term performance of the shutdown cooling system without degradation due to corrosion, only materials 9.3-45 Amendment No. 26 (11/13)

compatible with the pumped fluid are used. The possibility of chloride induced stress corrosion of austenitic stainless steel is minimized by use of insulation material with low soluble chloride content.

During long-term operation chloride stress corrosion due to recirculation of the containment sump water is minimized since the shutdown cooling system is not highly stressed.

9.3.5.3.2 Single Failure Analysis The failure of any single active or passive component in the shutdown cooling system during recirculation following a LOCA will not result in a loss of cooling capability. Sufficient isolation capabilities, interconnections and redundancy of components are provided to ensure adequate reactor core cooling.

This is further discussed in Section 6.3.

The single failure of an active component during shutdown cooling operation will not result in a loss of cooling capability. The reactor coolant system can be brought to refueling temperature using one low pressure safety injection pump and one shutdown heat exchanger, but the cooldown process would be considerably longer.

To control the rate of reactor coolant system cooldown, reactor coolant can be bypassed around the shutdown cooling heat exchangers, total shutdown cooling flow can be controlled by the injection headers or the heat exchanger outlet control valve can be throttled. In automatic control, FIC-3306 allows maintaining a constant total shutdown cooling flow to the core. Loss of the automatic control function will not reduce the shutdown cooling system cooling capability. Due to equipment maintenance concerns, the preferred operating method is using the injection header valves to control flow. Individual injection header flow instruments can be used to determine the system flow. The automatic flow control facilitates cooldown, but its function may be duplicated by operator action. The flow may be controlled by operation of motor controlled valves using the low pressure safety injection pump discharge pressure (utilizing the certified pump characteristic performance curve) as an indication of system flow rate.

Valve FCV-3306 can be used in the shutdown cooling mode to bypass flow around the shutdown cooling heat exchangers in order to limit plant cooldown rate at the initiation of shutdown cooling to the administrative limit of 85°F/Hr. Due to the high logarithmic temperature difference at initiation of EC290379 shutdown cooling (325°F) the heat exchangers are very efficient during this mode of operation and flow bypass may be required to control the cooldown rate. This bypass operation may continue for about one hour into the cooldown while the reactor vessel head is still in place. Since FCV-3306 is a fail open valve its failure could result in continued bypass flow and a limited cooldown rate as reactor coolant system temperatures decreased. Local manual operation of FCV-3306 and HCV-3657 ensures that control of cooldown rate can continue. There would be no violation of fuel design limits nor the design conditions of the reactor coolant system pressure boundary if this occurred. Should FCV-3306 fail closed a motor operated bypass valve MV-03-2 is provided to facilitate continuation of an orderly cooldown.

FCV-3306 can also be used to insure that a minimum flow through the core always exists. Flow controller FIC-3306 has a manual set point which insures that adequate flow is always supplied to the core such that the full power temperature difference is not exceeded at the initiation of shutdown cooling. This can also be controlled manually using total system flow and/or heat exchanger flow. Since decay heat is highest at this point it insures the T limit will not be exceeded throughout cooling. When in this mode of operation FCV-3306 is fully closed and all flow is through the heat exchangers (except for bypass valve leakage and purification flow). The head may be on or off the vessel during this phase. Should FCV-3306 fail open at this point it will 9.3-46 Amendment No. 30 (05/20)

begin bypassing flow around the shutdown cooling heat exchangers. The reactor coolant system temperatures will gradually rise to a steady state value which the shutdown cooling heat exchangers are capable of maintaining. The exact temperature will depend on when in shutdown cooling the failure occurs, component cooling water temperature, and the amount of flow bypassed. In no case will there be a violation of fuel design limits nor the design conditions of the reactor coolant system pressure boundary.

Valve FCV-3306 shown on Figure 6.3-1 is locked in the open position and valve HCV-3657 is key locked in the closed position during normal operation in readiness for system availability for safety injection during a postulated LOCA. Status lights in the control room confirm the correct position of the valves for the injection mode of system operation. The valves are the air operated type with loss of air or signal power maintaining the valves in the required position for injection actuation. Redundant power is supplied to the valves to insure against loss of function due to loss of one power train supply.

During the shutdown cooling mode of operation with locks removed under administrative control, throttling valve HCV-3657 can be partially opened by the operator which can automatically partially close FCV-3306 to maintain the shutdown cooling flow constant, as monitored by the flow instrumentation. These valves can be manually operated to control heat exchanger flow. On loss of control air during shutdown cooling the valves automatically take the injection mode position, which could temporarily terminate shutdown cooling until the operator sets the valve positions manually with the hand operators provided on each valve.

No single failure of an active component during residual heat removal will result in a loss of core cooling capability. The reactor coolant system can be brought to refueling temperature using one low pressure safety injection pump and one shutdown cooling heat exchanger. Remotely operated valves HCV-3657 and FCV-3306, shown on Figure 6.3-1, are equipped with local hand operators in the event of their active failure.

Failure of an injection valve HCV-3615, 3625, 3635 and 3645, shown on Figure 6.3-2, will not preclude the capability of cooling the plant. Double sets of suction valves are provided from the reactor coolant loop providing redundancy in the event of valve failure in this area.

The loss of offsite power would not effect the system other than delay the flow of coolant for thirty (30) seconds until the onsite-power system can pick up the load.

A single failure of passive component during shutdown cooling will result in the interruption of the cooldown but will not result in a loss of core cooling. Should a portion of the shutdown cooling system piping outside of the containment sustain a failure during cooldown from 325F, the shutdown cooling system can be isolated while core decay heat is removed by the main steam and feedwater systems.

The reactor coolant system is then maintained in this partial cooldown condition (approximately 300F) while repairs are affected on the shutdown cooling system. A failure of a shutdown-cooling suction line will not interrupt cooldown, since the second suction line will permit continued cooldown at a reduced rate.

9.3-47 Amendment No. 17 (10/99)

Continued core cooling in the event of a passive failure, occurring after the reactor vessel head has been removed, is provided by manual alignment and initiation of the safety injection system. The safety injection tank outlet isolation valves and high pressure safety injection control valves are opened, the high pressure safety injection pumps are started and the shutdown cooling system is isolated. The containment cooling system is used to remove core decay heat. These actions, initiated from the control room, will ensure the continuation of core cooling.

In the highly unlikely event of total failure of the refueling water indicators' non-safety related components concurrent with failure of both safety related isolation valves the flow will be limited by the restriction orifices to less than the capacity of one charging pump.

9.3.5.3.3 Testing and Inspection Preoperational tests were conducted to verify proper operation of the shutdown cooling system. The preoperational tests included calibration of instrumentation, testing of the automatic flow control, verification of adequate shutdown cooling flow and verification of the operability of all associated valves.

To ensure availability of the shutdown cooling system, components of the system are periodically tested.

As described in Section 6.3.4, the low pressure safety injection pumps, air and motor operated valves, instrumentation and check valves associated with the safety injection systems are tested on a quarterly basis.

As discussed in NRC Generic Letter 2008-01 and INPO SER 2-05, the presence of unanticipated gas voids within fluid systems can challenge the ability of systems to perform their design functions due to issues such as gas binding, water hammer, injection delay times, etc. Requirements for maintaining system operability with respect to gas intrusion are contained within Technical Specifications and Gas Accumulation Management Program procedures.

Heat exchanger bypass valve leakage is tested on a frequency determined by historical test data. Table 5.2-12 shows the pressure isolation valves under the scope of Generic Letter 87-06, "Periodic Verification of Leaktight Integrity of Pressure Isolation Valves," which are required to be part of a testing program.

These system and component tests, together with shutdown cooling heat exchanger thermal performance data taken during refueling are sufficient to demonstrate the operability of the shutdown cooling system.

9.3.5.3.4 Natural Phenomena Since the shutdown cooling system is essential for a safe shutdown of the reactor, it is a seismic Class I component and designed to remain functional in the event of a design basis earthquake.

Components of the system are located within the reactor auxiliary building or the containment and therefore would not be subject to natural perturbations other than seismic.

9.3.5.4 Instrument Application Table 9.3-29 lists the parameters used to monitor the shutdown cooling system.

9.3.5.5 Generic Letter 88-17 Commitments Generic Letter 88-17 was issued to address concerns related to the loss of decay heat removal capability during non-power operations based on several industry incidents. The generic letter required the implementation of expeditious actions as well as programmed plant enhancements to address this issue.

FPL provided commitments to implement these requirements in letters to NRC (L-88-552 and L-89-38).

The commitments made by FPL were in the following areas: 1) personnel training on the events; 2) availability of instrumentation to verify state of RCS and cooling systems performance; this includes the use of core exit thermocouples and SDC supply/return line temperature for core exit conditions and RCS water level indicators for reduced inventory; 3) procedures for normal and off-normal reduced inventory SDC operation and administrative controls for containment closure prior to core uncovery; 4) at least one HPSI pump and charging pumps available to maintain RCS in stable and controlled condition; 5) the UNIT 1 9.3-48 Amendment No. 28 (05/17)

performance of time to RCS boiloff, core uncovery and vent area analyses to supplement design information and support procedures/instrumentation; 6) guidelines to ensure perturbation-causing operations are minimized; and 7) controls to avoid RCS pressurization when hot leg nozzle dams are in place simultaneously. In addition, licensees were required to identify and submit appropriate changes for Technical Specifications that restrict or limit the safety benefit of the actions identified in the generic letter.

9.3-48a Amendment No. 24 (06/10)

9.3.6 FAILED FUEL DETECTION SYSTEM 9.3.6.1 Design Basis The failed fuel detection system is designed to provide an indication of fuel clad failures.

9.3.6.2 System Description Failed fuel detection is accomplished using the process radiation monitor of the chemical and volume control system. The location of the process radiation monitor is shown on Figure 9.3-4 and is identified as R-2202. The monitor design data are given in Table 9.3-23.

The process radiation monitor is described in Section 11.4.2. It is located in the 1/2 inch line bypassing the chemical and volume control system purification filter 1A and provides a continuous recording in the control room of both the reactor coolant gross gamma radiation and the specific fission product gamma activity. A high alarm indicates an increase in coolant activity above the setpoint within five minutes of the vent. The specific nuclide monitored is Iodine-135 because it is easily released from a failed rod and consequently it is found in relative abundance in the reactor coolant in the event of fuel cladding failure.

An alarm from the process radiation monitor can be caused by a clad failure or crud release due to normal plant transients. Historical data from the monitor as well as present trends are used to determine whether the alarm is due to clad failure or crud release.

9.3.6.3 Testing and Inspections Component testing and inspections are conducted as specified in Section 9.3.4 for the chemical and volume control system.

9.3.7 POST ACCIDENT SAMPLING SYSTEM According to Tech Spec. Amendment No. 174, the requirements to have and maintain the PASS have been eliminated. The information provided in this section is kept for historical purposes.

The Post Accident Sampling System (PASS) consists of shielded skid-mounted sample stations and local control panel. The PASS provides a means to obtain and analyze unpressurized reactor coolant samples.

The system provides process monitoring of dissolved hydrogen in the pressurized reactor coolant sample stream. Containment sump samples can also be obtained from LPSI piping when the unit is in the recirculation mode. Containment atmosphere samples and hydrogen monitoring are provided by the hydrogen sampling system detailed in Section 6.2.5.2.3.

9.3.7.1 Design Bases The Post Accident Sampling System (PASS) is designed based upon the criteria set forth in NUREG-0660 as modified by Section II.B.3 of NUREG-0737 which deals with implementation of capabilities for sampling reactor coolant during post-accident condition. Combustion Engineering Owners Group issued in September 1993 the NRC approved Topical Report CEN-415 Revision 1-A "Modification of Post Accident Sampling System Requirements." This report, approved by the NRC on April 12, 1993, allows the deletion of sampling requirements for containment sump pH and dissolved oxygen in reactor coolant samples. The report also approved deleting the requirement for containment hydrogen analysis. Heat tracing of containment atmosphere sample lines is not required if the Core Damage Assessment procedure bases the assessment on noble gas concentration in lieu of iodines. Some components which are no longer required by the design, including heat tracing and instruments, may remain in place, but will not be maintained as required equipment. The system is designed with the following design bases:

a) minimize personnel radiological exposures; b) simplify sample system operational requirements for collecting post-accident reactor coolant chemistry and radiochemistry information; 9.3-49 Amendment No. 18, (04/01)

c) provisions for obtaining representative reactor coolant samples from hot leg (high pressure) and containment sump (recirculation) samples from the low pressure safety injection pump discharge (low pressure);

d) the capability to cool and depressurize samples from lines with high temperatures and pressures to allow for safe handling; e) continuously accept reactor coolant samples and separate the dissolved gases from the liquid; f) provision for taking diluted liquid grab samples (up to 1:1000 dilution) for chloride, boron and radioisotopic analysis; g) provision to measure and record continuously degassed liquid flow; h) indication of concentration of dissolved hydrogen in the reactor coolant sample; i) provision for taking gas grab samples; and j) sample flow is returned to the containment to preclude unnecessary contamination of other auxiliary systems and to ensure that radioactive waste remains isolated within the containment.

9.3.7.2 System Description The Piping and Instrumentation diagrams for the PASS are shown on Figures 9.3-8:

a) The post-accident sampling system samples are taken from the hot leg piping of the reactor coolant loop or from the LPSI discharge. Either a reactor coolant (main loop) sample or a containment sump sample may be taken by opening the associated solenoid valve at the sample collection station. The sample is then passed through an existing sample cooler where it is cooled.

b) The high pressure reactor coolant sample passes through a dissolved hydrogen process monitor.

c) The sample is then depressurized by passing through a pressure reducing valve station. The cooled and depressurized sample passes through a gas-liquid separation system consisting of a nitrogen gas sparger, a gas separator and a gas release valve.

9.3-50 Amendment No. 18, (04/01)

d) Liquid passes through a flow meter where the flow rate is measured and recorded, and finally to the reactor coolant drain tank. To obtain a diluted grab sample the liquid is passed through a 4-way valve. By changing the valve position an exact amount of liquid is captured in the straight bore. The captured sample is flushed out with a required amount of demineralized water, depending on the dilution desired (i.e., 1:250, 1:500, 1:1000, etc.), to a shielded diluted grab sample container. The diluted grab sample is then transported to the onsite laboratory. The diluted grab sample can be analyzed for boron, chlorides and radioisotopes. Provisions for flushing all lines have been made.

e) If the dissolved hydrogen process monitor is not used for dissolved hydrogen determination or a dissolved gas sample is required, the depressurized liquid sample is routed to the nitrogen gas sparger, gas separator, and gas release valve. An overpressure is maintained in the gas separator in order to maintain proper liquid level. Gas is stripped from a measured volume of the liquid sample. The pressurized nitrogen and stripped gases can be vented to a sample bomb.

The sample bomb can be moved to the laboratory for hydrogen determination and/or radioactive gas analysis. Excess gas is routed back to the containment building.

9.3.7.3 Component Description The major PASS components and data summary are given in Table 9.3-30.

9.3-51 Amendment No. 18, (04/01)

TABLE 9.3-1 DESIGN DATA FOR COMPRESSED AIR SYSTEM COMPONENTS

1. Instrument Air System Outside Containment Air Compressor Quantity 4 EC283796 Two (2) compressors (lA, 1B) Type: 2-Stage, Rotary Screw, oil-free, water-cooled, enclosed in a sound insulated enclosure.

Design capacity, scfm 163 Discharge pressure, psig 107 Motor 40 hp, 3 phase, 60 Hz, 460V Enclosure Totally enclosed, fan cooled Code ASME Section VIII, NEMA Two (2) compressors (lC, 1D) Type: 2-Stage, Rotary Screw, oil-free, EC283796 water-cooled, enclosed in a sound insulated enclosure.

Design Capacity, SCFM 411 Discharge Pressure, psig 125 Motor 100HP, 3-Phase, 60 Hz, 460V Enclosure Totally enclosed fan cooled Codes ASME Section VIII, NEMA EC283796 Air Receiver Type Vertical Quantity 1 Design pressure, psig 125 Design Temperature, F 125 Actual volume, ft3 96 Code ASME Section VIII EC283796 Air Dryer Type Heatless regeneration Desiccant Activated alumina desiccant Quantity 2 Capacity, scfm 400 Outlet moisture content with saturated air inlet -40°F dew point at 100 psig EC283796 9.3-52 Amendment No. 29 (10/18)

TABLE 9.3-1 (Cont'd)

EC283796 Piping and Valves Valves 150 lb ANSI for 2-1/2" and larger 600 lb ANSI for 2" and smaller Piping Seamless ASTM A-106, Grade B (2-1/2" thru 6")

Code ANSI B31.1.0 (ANSI B31.7 -

penetration piping)

2. Instrument Air System (Inside the Containment Abandoned in place)

Air Compressor Type Horizontal, non-lubricated liquid ring rotary type; single stage Quantity 2 Design capacity, scfm 48 Discharge Pressure 100 Motor 40 Hp, 3 phase, 60 Hz, 460V Enclosure Totally inclosed fan cooled Code ASME Section VII, NEMA Intake Filter Silencer Type Dry type Quantity 2 Base size, inches 6 Aftercooler and Moisture Separator Type Shell & tube Quantity 2 Code ASME Section VIII Air Receiver Type Vertical Quantity 1 Design Pressure, psig 125 Design Temperature, F 125 Actual Volume, ft3 24 Code ASME Section VIII 9.3-53 Amendment No. 29 (10/18)

TABLE 9.3-1 (Cont'd)

Prefilters Type Cartridge Quantity 2 Capacity (scfm) 60 Filtration 0.6 microns -100% Removal Air Dryer Type Heatless Regeneration Desiccant Activated Alumnia Quantity 2 Capacity 43 scfm Outlet moisture content with saturated air inlet -40 dew point at 100 psig Afterfilters Type Cartridge Quantity 2 Capacity (scfm) 50 Filtration 0.9 microns - 100% Removal

3. Service Air System UNIT 1 9.3-54 Amendment No. 28 (05/17)

TABLE 9.3-1 (Cont'd)

Piping and Valves Valves 150 psi ANSI for 2-1/2" and larger 600 psi ANSI for 2" and smaller Piping Seamless ASTM A-106, Grade B (2-1/2" thru 6")

Code ANSI B31.1.0 (ANSI B31.7 - penetration piping)

UNIT 1 9.3-55 Amendment No. 28 (05/17)

PAGE 9.3-56 INTENTIONALLY BLANK 9.3-56 Am. 8-7/89

TABLE 9.3-2 COMPRESSED AIR SYSTEM INSTRUMENT APPLICATION Indication Alarm(l) Instru- Normal Control ment Operating Instrument System Parameter & Location Local Room High Low Recording (1) Control Function Range(2) Range Accuracy(2)

Instrument Air System (Outside Containment)

Instrument Air Compressor (1A,1B)

1) Discharge temperature *
2) Discharge pressure
  • 107 psig EC283796 Instrument Receiver Pressure * *
  • 1) Controls in- 100-120 psig strument air compressor operation
2) Second compres-sor cut-in. at 105 psig EC283796 9.3-57 Amendment No. 29 (10/18)

TABLE 9.3-2 (cont)

Indication Alarm(l) Instru- Normal Control ent Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(2) Range Accuracy(2)

Instrument Air Compressor (1C,1D)

1) Discharge temp
2) Discharge Pressure
  • 125 psig EC283796 Instrument Air Dryer (1A,1B)
1) Inlet pressure
  • 90-110 psig
2) Outlet temperature
  • 90-110°F 9.3-57a Amendment No. 29 (10/18)

TABLE 9.3-2 (Cont'd)

Indication Alarm(l) Instru- Normal Control ment Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(2) Range Accuracy(2)

3) Outlet pressure
  • 90-110 psig Afterfilter Package 90-110 psig Outlet Pressure * *
  • 90-110 psig Discharge Air Header Pressure *
  • 90-100 psig UNIT 1 9.3-58 Amendment No. 28 (05/17)

TABLE 9.3-2 (Cont'd) 1 All alarms and recordings are in the control room unless otherwise indicated.

2 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.3-59 Amendment No. 25 (04/12)

TABLE 9.3-3 SAMPLING SYSTEM FLOW RATES Approximate flow rates at standard conditions, gpm Pressurizer Steam Space 0.5 Pressurizer Surge Line 0.7 Reactor Coolant System Hot Leg 0.8 LPSI PP 1A Suction Line 1.0 High-Pressure Safety Injection Pump 1.0 Miniflow Line CVCS Purification Filter 1A Inlet 1.0 CVCS Purification Filter 1A Outlet 1.0 CVCS Purification Filter 1B Outlet 1.0 CVCS.Purification Ion Exchanger Series Flow Line 1.0 Steam Generator Blowdown Line 1.25 EC284034 Safety Injection Tanks 1.0 Common Low Pressure Safety Injection Pump Discharge 1.0 9.3-60 Amendment No. 29 (10/18)

TABLE 9.3-4 DESIGN DATA FOR SAMPLE SYSTEM COMPONENTS

1. Sample Heat Exchanger Quantity 4 (Identical units)

Type Shell and Tube, Vertical Tube Side (Sampling)

Fluid Reactor Coolant Design Pressure, psig 6000 Pressure Drop, psi 55 @ 250 lbs/hr Material Ni Ci Fe Shell Side (Cooling Water)

Fluid Component Cooling Water Design Pressure, psig 375 Pressure Drop, psi 3 @ 3 gpm Material Ni Ci Fe Code ASME, VIII

2. Sample Vessel Quantity 2 Internal Volume, cc 300 Design Pressure, psig 2485 Design Temperature, °F 250 Normal Operating Pressure, psig 2235 Normal Operating Temperature, °F 120 Material Stainless Steel (316)

Fluid Reactor Coolant Code ASME, VIII

3. Relief Valves
a. Relief Valve in Hot Leg Sample Line (V5109)

Set Pressure, psig 100 Accumulation, % 10 Backpressure Buildup, psi 35 Superimposed Backpressure, psi 31 Capacity, gpm for water @ 100°F 8.0 Normal Fluid Temperature, °F 120 Maximum Fluid Temperature, °F 250

b. Relief Valve in Pressurizer Steam Sample Line (V5124)

Set Pressure, psig 100 Accumulation, % 10 Backpressure Buildup, psi 35 Superimposed Buildup, psi 31 Capacity, gpm for water @ 100°F 8.0 Normal Fluid Temperature, °F 120 Maximum Fluid Temperature, °F 250 Code Commercial

4. Hood Fan Type Centrifugal Motor Horsepower, hp 1/4 Fan Speed, rpm 1725 Flow Rate, scfm 515 9.3-61 Amendment No. 22 (05/07)

TABLE 9.3-5 SAMPLING SYSTEM INSTRUMENTATION Indication Alarm(l) Instru- Normal System Parameter Control ment Operating Instrument

& Location Local Room High Low Recording(1) Control Function Range(2) Range Accuracy(2)

Heat Exchanger Outlet Temperature

  • 120 F Sample Vessel Inlet
  • 2250 Pressure psig Sample Vessel Outlet
  • 0-60 Pressure psig Sample Flow
  • 0.7 gpm 1 All alarms and recorders are in the control room unless otherwise indicated.

2 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.3-62 Amendment No. 18, (04/01)

TABLE 9.3-6 DRAINS ROUTED TO DRAIN TANKS

1. Equipment Drain Tanks Miscellaneous valve leakoffs Miscellaneous pump leakoffs CVCS equipment drains Safety injection system drains Fuel pool drains Waste management system drains Blowdown tank CVCS ion exchangers Waste management system ion exchangers Fuel pool ion exchangers Preconcentrator ion exchangers Boric Acid condensate ion exchangers
2. Laundry Drain Tanks Hot showers Hot sinks Laundry pumps Laundry drain sump pump Laundry sump
3. Chemical Drain Tanks Sample sink Component cooling drains Decontamination room drains Chemical laboratory drains Cask Handling Facility drains Fuel handling building sump pump Chemical drain sump pump 9.3-63 Amendment No. 23 (11/08)

TABLE 9.3-7 HAS BEEN INTENTIONALLY DELETED 9.3-64

TABLE 9.3-8 REACTOR COOLANT AND REACTOR MAKEUP WATER CHEMISTRY(1)

Reactor Makeup Water Source Analysis(2) Typical Value(2) pH 6.0 - 8.0 @ 25°C Conductivity < 0.2 mhos/cm @ 25°C Chloride < 1.0 ppb Fluoride < 1.0 ppb Sulfate < 1.0 ppb Sodium < 1.0 ppb Silica < 10.0 ppb Suspended Solids < 10.0 ppb Reactor Coolant (Mode 1)

Control Parameter(3) Steady State Limit Dissolved Oxygen < 100 ppb Chloride < 150 ppb Fluoride < 100 ppb Hydrogen 25 - 50 cc H2/KgH2O(6)

Sulfate < 50 ppb Lithium Consistent with the requirements of the boron/lithium control program.(5)

Zinc Acetate (Depleted Zinc) 5 ppb - 10 ppb, Notes (7)

Diagnostic Parameter Steady State Typcial Value Boron Consistent with fuel cycle boron projections.

Conductivity Consistent with concentration of additives.

pH Consistent with concentration of additives.

Suspended solids < 10 ppb Hydrazine During startup only, maintain residual until dissolved oxygen is removed.

Ammonia Trend to monitor.

Notes:

(1) Reference safety evaluation PSL-ENG-SENS-99-005.

(2) In order to prevent degradation of chemistry parameters in the RCS it is necessary to minimize impurity content through the makeup water. Typical values indicated above are those normally achieved in makeup systems and are used for diagnostic evaluation of RCS chemistry values.

(3) Control Parameters are those parameters that require strict control due to material integrity consideration.

(4) Diagnostic Parameters are those parameters which assist the chemistry staff in interpreting primary coolant chemistry variations, or those parameters which may affect radiation field buildup, corrosion performance of system materials, or fuel integrity.

(5) Reference PSL-ENG-SEMS-13-011.

(6) Hydrogen lower limit reduced to 15 cc H2/KgH2O 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before shutdown.

(7) PC/M: 09013, Zinc Injection.

9.3-65 Amendment No. 26 (11/13)

TABLE 9.3-9 DESIGN TRANSIENTS Regenerative and Letdown Heat Exchangers Variation Level Letdown Flow Charging Transient Cycles in 60 Years Initial - Final Rate Initial - Final Flow (GPM) (GPM)

Step Power Change 2000 90% - 100% 40 - 89 (100 sec) 44 89 - 40 in 11.7 min Step Power Change 2000 100% - 90% 40 - 29; 44 29 - 40 (88 2.8 min)

Ramp Power Change 15000 15% - 100% 5%/min 40 - 128 44 in 16 min 128 - 40 in 17 min Ramp Power Change 15000 100% - 15% -5%/min 40 - 29; 44-88-132; 29 - 40 132-88-44 in 27 min in 19 min Reactor Trip 440 100% - 0% 40 - 29; 44-88-132; 29 - 40 132-88-44 in 30 min in 22 min Loss of Load 45 100% - 0% 40 - 116-29; 44-88-132; 29 - 40 132-88-44 in 28.3 min in 20 min 9.3-66 Amendment No. 20 (4/04)

TABLE 9.3-9 (Cont'd)

Variation Level Letdown Flow Charging Transient Cycles in 60 Years Initial - Final Rate Initial - Final Flow (GPM) (GPM)

Maximum 1000 - 40-128; 44-88-132; Purification 128-40 132-88-44 Loss of Charging 100 - 40 - 0 44-0 0 - 40 0-44 Loss of Letdown 50 - 40 - 0 44 0-128-40 15 min after restart Short Term 400 - 40 - 0 44-0 Isolation - 0 - 40 0-44 Regen. Ht. Exch.

Long Term 800 40 - 0 44-0 Isolation - 0 - 40 0-44 Regen. Ht. Exch.

Boron Dilution 10,000 - 40 - 128 44-132 128-40 132-44 9.3-67 Amendment No. 20 (4/04)

TABLE 9.3-10 CHEMICAL AND VOLUME CONTROL SYSTEM PARAMETERS Normal letdown and purification flow, gpm 40*

Normal charging flow, gpm 44 Reactor coolant pump controlled bleedoff, 4 pumps, gpm 4 Normal letdown temperature from reactor coolant system, °F 550 Normal charging temperature to reactor coolant system loop, °F 395 Ion exchanger operating temperature, °F 120

  • Letdown Flow varies between 40, 84 & 128 gpm depending on number of charging pumps in service. Purification flow maximum while on shutdown cooling is 140 gpm (nominal) with one Ion Exchanger in operation. Maximum purification flow while aligned to the Shutdown Cooling System with parallel flow through two Ion Exchangers is 200 gpm (nominal).

9.3-68 Amendment No. 24 (06/10)

TABLE 9.3-11 CHEMICAL AND VOLUME CONTROL SYSTEM PROCESS FLOW DATA CVCS NORMAL PURIFICATION OPERATION One Charging Pump in Operation CVCS Location: 1 2 3 4 5 6 7 7a 7b 8 9 Flow, gpm 40 40 40 40 40 39 1 1/2 1/2 40 40 Press., psig 2110 2090 435 430 25 22 25 24 24 21 20 Temp., F 550 262 262 120 120 120 120 120 120 120 120 CVCS INTERMEDIATE PURIFICATION OPERATION Two Charging Pumps in Operation CVCS Location: 1 2 3 4 5 6 7 7a 7b 8 9 Flow, gpm 84 84 84 84 84 83 1 1/2 1/2 84 84 Press., psig 2075 2005 445 430 43 40 43 42 42 38 35 Temp., F 550 334 334 120 120 120 120 120 120 120 120 CVCS MAXIMUM PURIFICATION OPERATION Three Charging Pumps in Operation CVCS Location: 1 2 3 4 5 6 7 7a 7b 8 9 Flow, gpm 128 128 128 128 128 127 1 3/4 3/4 128 128 Press., psig 1995 1785 465 430 75 68 75 74 74 64 57 Temp, F 550 375 375 120 120 120 120 120 120 120 120 NOTES:

The pressure drop across the purification prefilter, afterfilter, and ion exchanger varies with loading. The pressure drops shown are typical.

The pressure in the volume control tank varies and affects the pressures at locations 5 through 11 and 14a through 14g proportionally.

CVCS location numbers are shown on Figures 9.3-4 and 9.3-5.

The parameter values provided above are historical and could change depending on other plant conditions; for example, required RCS hydrogen concentration would change VCT normal operating pressure conditions.

9.3-69 Amendment No. 17 (10/99)

TABLE 9.3-11 (Cont'd)

CVCS NORMAL PURIFICATION OPERATION One Charging Pump in Operation CVCS Location: 10 10a 10b 10c 11 12 13 14 14e 14f 14g (a,b,c,d)

Flow gpm 40 40 40 44 44 44 44 1 0 4 4 Press., psig 19 18 15 15 15 2235 2225 100 100 100 16 Temp, F 120 120 120 120 120 120 395 120 120 120 CVCS INTERMEDIATE PURIFICATION OPERATION Two Charging Pumps in Operation CVCS Location: 10 10a 10b 10c 11 12 13 14 14e 14f 14g (a,b,c,d)

Flow, gpm 84 84 84 88 88 88 88 1 0 4 4 Press., psig 33 30 15 15 15 2280 2255 100 100 100 16 Temp., F 120 120 120 120 120 120 340 120 120 120 120 CVCS MAXIMUM PURIFICATION OPERATION Three Charging Pumps in Operation CVCS Location: 10 10a 10b 10c 11 12 13 14 14e 14f 14g (a,b,c,d)

Flow, gpm 128 128 128 132 132 132 132 1 0 4 4 Press., psig 54 47 15 15 15 2385 2335 100 100 100 16 Temp., F 120 120 120 120 120 120 310 120 120 120 120 NOTES:

The pressure drop across the purification prefilter, afterfilter, and ion exchanger varies with loading. The pressure drops shown are typical.

The pressure in the volume control tank varies and affects the pressures at locations 5 through 11 and 14a through 14g proportionally.

CVCS location numbers are shown on Figures 9.3-4 and 9.3-5.

The parameter values provided above are historical and could change depending on other plant conditions; for example, required RCS hydrogen concentration would change VCT normal operating pressure conditions.

9.3-70 Amendment No. 18, (04/01)

TABLE 9.3-11 (Cont'd)

CVCS MAKEUP SYSTEM OPERATION AUTOMATIC MODE Blended Boric Acid Concentration = 925 ppm CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 174 174 10 10 0 10 140 140 150 0 0 0 164 154 10 10 0 0 Press, psig 7 91 91 86 15 20 140 20 20 12 91 15 91 91 91 20 7 7 Temp, F 70 70 70 70 70 70 60 60 65 70 70 70 70 70 70 70 70 70 CVCS MAKEUP SYSTEM OPERATION BORATE MODE Three Charging Pumps Operating CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 180 180 16 16 0 16 0 0 16 0 0 0 164 154 10 10 0 0 Press, psig 7 90 90 76 15 20 165 20 20 12 90 15 90 90 90 20 7 7 Temp, F 70 70 70 70 70 70 60 60 70 70 70 70 70 70 70 70 70 70 CVCS MAKEUP SYSTEM OPERATION DILUTE MODE Three Charging Pumps Operating CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 160 160 0 0 0 0 128 128 128 0 0 0 160 150 10 10 0 0 Press, psig 7 88 88 88 15 20 142 20 20 12 88 15 88 88 88 20 7 7 Temp, F 70 70 70 70 70 70 60 60 60 70 70 70 70 70 70 70 70 70 NOTES:

The data shown for the various modes of operation is typical. The pressure in the isolated piping of the CVCS makeup system will normally be 0 psig but may range as high as 140 psig before the relief valve lifts. CVCS location numbers are shown on Figures 9.3-4 and 9.3-5.

The parameter values provided above are historical and could change depending on other plant conditions; for example, required RCS hydrogen concentration would change VCT normal operating pressure conditions.

9.3-71 Amendment No. 17 (10/99)

TABLE 9.3-11 (Cont'd)

CVCS MAKEUP SYSTEM OPERATION - MANUAL MODE Blended Boric Acid Concentration = 2300 ppm CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 150 150 10 10 0 10 50 50 60 0 0 0 140 130 10 10 0 0 Press, psig 7 109 109 103 15 20 155 20 20 12 91 15 109 109 109 20 7 7 Temp, F 70 70 70 70 70 70 60 60 75 70 70 70 70 70 70 70 70 70 CVCS MAKEUP SYSTEM OPERATION - EMERGENCY BORATION (SIAS) Via boric acid makeup pump and one pump is operating Three charging pumps operating Two boric acid makeup pumps operating CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 142 142 132 0 0 0 0 0 0 0 132 132 10 0 10 10 0 0 Press, psig 7 97 97 97 97 15 165 15 15 12 97 92 97 97 97 20 7 7 Temp, F 70 70 70 70 70 70 60 60 70 70 70 70 70 70 70 70 70 70 CVCS MAKEUP SYSTEM OPERATION - EMERGENCY BORATION (SIAS) Via Gravity Feed CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 66 66 Press, psig 7 7 7 7 5 15 165 15 15 12 7 5 7 7 7 7 7 7 Temp, F 70 70 70 70 70 70 60 60 70 70 70 70 70 70 70 70 70 70 CVCS MAKEUP SYSTEM OPERATION - SHUTDOWN BORATION CVCS Location: 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Flow, gpm 156 156 16 0 0 0 0 0 0 0 16 16 140 130 10 10 0 0 Press, psig 7 109 109 109 109 15 165 15 15 12 90 89 109 103 90 90 7 7 Temp, F 70 70 70 70 70 70 60 60 70 70 70 70 70 70 70 70 70 70 N0TES: The data shown for the various modes of operation is typical. The pressure in the isolated piping of the CVCS makeup systems will normally be 0 psig but may range as high as 140 psig before the relief valve lifts. CVCS location numbers are shown on Figures 9.3-4 and 9.3-5.

9.3-72 Am. 8-7/89

TABLE 9.3-12 REGENERATIVE HEAT EXCHANGER DESIGN DATA

1) Design Parameters Quantity 1 Type Shell and Tube, Vertical Code ASME Section III Class C, Tema-R Tube side- letdown Fluid Reactor Coolant, 1.5 wt % Boric Acid Maximum Design pressure, psig 2485 Design temperature, F 650 Materials Stainless Steel, Type 304 Pressure loss at 128 gpm, psi 99 Normal flow, gpm 40 Design flow, gpm 128 Shell Side- Charging Fluid Reactor Coolant, 12 wt % Boric Acid Maximum Design pressure, psig 3025 Design temperature, F 650 Materials Shell ASME SA-182, F 304 Tubes ASME SA-213, TP 304 Baffles ASME SA-240, TP 304 Tube Sheet ASME SA-182, F 304 Channel ASME SA-312, TP 304 Pressure loss at 132 gpm, psi 36.2 Normal flow, gpm 44 Design flow, gpm 132 2 Operating Parameters Minimum Maximum Maximum Letdown/ Letdown/ Letdown/

Maximum Maximum Minimum Tube Side - Letdown Normal Charging Charging Charging Flow - gpm @ 120F 40 30 128 128 Inlet Temp. - F 550 550 550 550 Outlet Temp. - F 262 165 375 450 Shell Side - Charging Flow - gpm @ 120F 44 132 132 44 Inlet Temp. - F 120 120 120 120

'Outlet Temp. - F 395 212 310 452 9.3-73 Amendment No. 17 (10/99)

TABLE 9.3-13 LETDOWN HEAT EXCHANGER DESIGN DATA

1) Design Parameters Quantity 1 Type Shell and Tube Horizontal Tube side - letdown Code TEMA-R and ASME Section III, Class C Fluid Reactor Coolant, 1.5 wt % Boric Acid Maximum Design pressure, psig 650 Design temperature, °F 550 Pressure loss at 128 gpm, psi 21 Normal flow, gpm 40 Design, gpm 128*

Materials Shell ASME SA-53 Carbon Steel Tubes ASME SA-213, Type 304 Cover ASME SA-106 Gr B, Carbon Steel Tubesheet ASME SA-182, F 304 Channel ASME SA-240, Type 304 Shell Side - cooling water Code TEMA-R and ASME Section III Fluid Component Cooling Water Design pressure, psig 150 Design Temperature, °F 250 Materials Carbon Steel Normal flow, gpm 157 Design flow, gpm 1200

2) Operating Parameters Minimum Maximum Maximum Letdown/ Letdown/ Letdown/

Maximum Maximum Minimum Tube Side - Letdown Normal Charging Charging Charging Flow - gpm @120°F 40 30 128 128 Inlet Temp, °F 262 165 375 450 Outlet Temp, °F 120/120 120/120 120/120 120/127 Shell Side (Cooling Water)

Flow - gpm @120°F 80/190 21/51 427/1200 542/1200 Inlet Temp, °F 65/100 65/100 65/100 65/100 Outlet Temp, °F 137/130 130/127 142/127 143/135

  • Maximum flow while aligned to Shutdown Cooling System is 140 gpm (nominal) with one Ion Exchanger in operation. Maximum purification flow while aligned to the Shutdown Cooling System with parallel flow through two Ion Exchangers is 200 gpm (nominal).

9.3-74 Amendment No. 24 (06/10)

TABLE 9.3-14 PURIFICATION FILTERS DESIGN DATA Quantity 2 (1A filter is normally bypassed)

Type elements Cartridges Retention for 2 micron and larger particles, % by wt 95 per Section 9.3.4.2.2(c) media size varies Normal operating temperature, °F 120 Design pressure, psig 200 Maximum allowable pressure loss clean, psi @

128 gpm 5 per filter (nominal)

Maximum allowable pressure loss, loaded, psi @

128 gpm The filter elements have a maximum loaded pressure differential of 75 psid. 25 (per filter)

Design temperature, °F 250 Design flow, gpm 128*

Normal flow, gpm 40 Code ASME III, 1968 Edition through Winter 1969 Addenda Class C Materials, wetted SA-240 Type 304 Stainless Steel Fluid, wt % boric acid, maximum 1.5 TABLE 9.3-15 CVCS ION EXCHANGERS DESIGN DATA Quantity 3 Type Flushable Design pressure, psig 200 Design temperature, °F 250 Normal operating temperature, °F 120 Resin volume, ft3 each (total) 36.2 Resin volume, ft3 each (useful) 32.0 Normal flow, gpm 40 Maximum flow, gpm 128*

Code for vessel ASME III, 1968 Edition, Winter 1969 Addenda, Class C Retention screen size 80 U. S. Mesh Material Stainless Steel, SA-240, Type 304 Fluid, wt % boric acid, maximum 1.5 Resin types Cation/anion stratified or mixed bed Specialty resin overlay

  • Maximum Flow while aligned to Shutdown Cooling System is 140 gpm (nominal) with one Ion Exchanger in operation. Maximum purification flow while aligned to the Shutdown Cooling System with parallel flow through two Ion Exchangers is 200 gpm (nominal).

9.3-75 Amendment No. 24 (06/10)

TABLE 9.3-16 VOLUME CONTROL TANK DESIGN DATA Quantity 1 Type Vertical, Cylindrical Internal volume, gallons 4200 Design pressure, internal, psig 75 Design pressure, external, psig 15 Design Temperature, F 250 Normal operating pressure, psig 7 to 30 Normal operating temperature, F 120 Normal spray flow, gpm 40 Blanket gas - during plant operation Hydrogen Code ASME III, Class C Fluid, wt % boric acid, maximum 12 Material ASME SA-240 Type 304 9.3-76 Amendment No. 17 (10/99)

TABLE 9.3-17 CHARGING PUMPS DESIGN DATA Quantity 3 Type Positive Displacement, Triplex Design pressure, psig 3250 Design temperature, F 250 Capacity, gpm 44 Normal discharge pressure, psig 2310 - 3010 Normal suction pressure, psig 20 - 78 Normal temperature of pumped fluid, F 120 NPSH required, psia 9.0 Driver rating, hp 100 Materials in contact with pumped fluid 17-4PH Stainless (SA-705 Gr630 1150HT/ or 1100HT)

Fluid, wt % boric acid, maximum 12 Applicable Codes - pressure boundary* Welding procedures and welder qualification -

ASME Section IX, 1966 Edition. Non-destructive tests and acceptance standards -

ASME Section VIII unfired pressure vessels, 1968 edition.

  • Charging pump cylinder head replacements may be integrally machined blocks without welding, inspected in accordance with ASME B&PV Section III, 1977 edition.

9.3-77 Amendment No. 24 (06/10)

TABLE 9.3-18 BORIC ACID MAKEUP TANKS DESIGN DATA Quantity 2 Volume, gal each 9975 Design pressure, psig 15 Design temperature, F 250 Normal operating temperature, F 60 to 120 Type heater 6 Electrical Strap-on (See Note 1) Heaters, 2.25 kw Total each (2 banks of 3 each)

Fluid wt % boric acid, Design 12 (see Note 2)

Material ASME SA-240 Type 304 Code ASME III, Class C TABLE 9.3-19 BORIC ACID BATCHING TANK DESIGN DATA Quantity 1 Internal volume, gal 636 Design pressure Atmospheric Design temperature, F 200 Normal operating temperature 170 Type heater Electrical Immersion Number of heaters 3 Heater capacity, kw each 15 Fluid, wt % boric acid maximum 12 Material ASME SA-240 Type 304 Code None TABLE 9.3-20 BORIC ACID MAKEUP PUMPS DESIGN DATA Quantity 2 Type Centrifugal, Horizontal Design pressure, psig 150 Design temperature, F 250 Design head, ft 231 Design flow, gpm 143 Normal operating temperature, F 60 to 120 NPSH required, ft 8 Motor horsepower 25 Motor voltage/phase/Hz 440/3/60 Fluid, wt % boric acid design 12 (See Note 2)

Material in contact with liquid Austenitic Stainless Steel Code Draft ASME Code for Pumps and Valves for Nuclear Power, November 1968, Class 2 Note 1: One bank of heaters for each BAMT has been deenergized.

Note 2: While the BAMTs and BAMPs were designed to contain 12 weight percent boric acid, they now store boric acid within the range of 2.5-3.5 weight percent.

9.3-78 Amendment No. 22 (05/07)

TABLE 9.3-21 CHEMICAL ADDITION TANK DESIGN DATA Quantity 1 Internal volume, gals 12 Design pressure Atmospheric Design temperature, F 100 Normal operating temperature Ambient Materials Austenitic Stainless Steel Code None TABLE 9.3-22 METERING PUMP DESIGN DATA Quantity 1 Type Piston-diaphragm Design pressure, psi 150 Design Temperature, F 200 Design flow, gph 0-40 Normal discharge pressure, psig 15.0 - 20.0 Fluid Hydrazine (N2 H4), Lithium Hydroxide or Amonium Hydroxide Horsepower, hp 1/2 Diaphragm material Teflon Code None 9.3-79 Amendment No. 17 (10/99)

TABLE 9.3-23 PROCESS RADIATION MONITOR DESIGN DATA Quantity 1 Type Gamma scintillation Design pressure, psig 200 Design temperature, F 250 Normal operating temperature, F 120 Normal flow rate, gpm 0.5 Measurement range, Ci/cc, I-135 10-4 to 102 Code USA Standard C99.1-1966 Criteria for Inspection of Highly Reliable Soldered Connections in Electronics and Electrical Applications TABLE 9.3-24 BORONOMETER DESIGN DATA (1)

Quantity 1 Vessel design temperature, F 250 Vessel design pressure, psig 200 Normal operating temperature, F 120 Normal flow rate, gpm 0.5 @ 0.5 psid (min.)

89 @ 6.8 psid (max.)

Code for vessel ASME III, Class C, 1968 Edition through Winter 1969 Addenda Size, inlet and outlet, in 1/2 flanged (1)

The boronometer has been abandoned via PC/M 02170; however, pressure boundary portions remain installed.

9.3-80 Amendment No. 21 (12/05)

TABLE 9.3-25 SINGLE FAILURE ANALYSIS - CHEMICAL AND VOLUME CONTROL SYSTEM Inherent Component/ Symptoms and Method of Compensating No. Location Failure Mode Cause Local Effects Detection Provision(s) 1 Regenerative Heat Decrease in Excessive High temperature in letdown High temperature alarm (1) Hot flow will automatically Exchanger (RHX) ability fouling or crud line from TIC-2221 bypass IX's and PRM Transfer heat deposition (2) TIC-2221 will shut valve V2515 and stop letdown flow Regenerative Heat Shell to tube Corrosion and/ Eventual out of spec. boron Isolate letdown and Safe plant shutdown not Exchanger (RHX) leakage or manufactur- concentration. Also heat measure flow on FIA-2212 affected. Charging via SIS ing defect exchanger temperature while charging. Perform filling pressurizer, letdown via disparities. only during shutdown reactor coolant pumps 2 Letdown Heat Decrease in Excessive High temperature in letdown High temperature alarm Hot flow will automatically Exchanger (LHX) ability to transfer fouling or crud line or abnormally high cooling and indication from bypass IX's heat deposition water flow rate reading from TIC-2224 and high TIC-2223 temperature Letdown Heat Cross Leakage Corrosion and/ Radioactivity will be transferred Activity monitor in CCW Safe plant shutdown not Exchanger (LHX) or manufactur- to CCW will sound alarm and high affected ing defect level alarm on CCW surge tank.

3 Line, between Rupture Faulty weld High temperature in letdown High temperature alarm TIC-2221 will shut valve TIC-2221 and line from TIC-2221 and low V2515 and stop letdown flow LCV-2110P (out- pressure alarm from side containment) PA-2201 4 Line, between Rupture Faulty weld Loss of pressure in letdown line Low pressure alarm from TIC-2221 will close letdown LHX and TIC-2224 PA-2201 and high temp. stop valve V2515 alarm TIC-2221 Note: Abbreviations of components listed at end of table.

9.3-81 Amendment No. 22 (05/07)

TABLE 9.3-25 (Cont'd)

Inherent Component/ Symptoms and Method of Compensating No. Location Failure Mode Cause Local Effects Detection Provision(s) 5 Purification Filter Clogs Contamination High differential pressure P sensor, PDIS-2202 or Bypass line will across filter PDIS-2210 will actuate alarm facilitate cartridge replacement Purification Filter Cartridge rupture Excessive Contamination of IX's andPRM None for small breaks, for Bypass line will Differential pressure larger breaks the reading of facilitate cartridge PDIS-2202 or PDIS-2210 will replacement be lower than normal. Also periodic sampling for activity buildup 6 Radiation Monitor Fails to detect high Electrical May allow a buildup of Laboratory analysis of coolant Backup by sampling levels of radiation malfunction contamination sample system and local samples Radiation Monitor False indication of Electrical Alarm Laboratory analysis of coolant Backup by sampling high level of rad- malfunction sample system and local iation samples 7 Deleted 8 Ion Exchanger(s) Fail to remove Resin exhausted Buildup in RCS activity Alarm from PRM and Bypass ion for purification contamination laboratory sample analysis exchangers during replacement of resin 9.3-82 Amendment No. 21 (12/05)

TABLE 9.3-25 (Cont'd)

Inherent Component/ Symptoms and Method of Compensating No. Location Failure Mode Cause Local Effects Detection Provision(s) 9 CVCS Ion Fails to remove Resin Unable to maintain power Coolant sample, and Bypass and replace resin in ion Exchangers for boron from coolant exhaustion at end of core cycle power exchanger(s) deboration 10 Charging Pumps Fails to provide Seal failure, High letdown temp at Low level in pressurizer, low Low level in pressurizer will start sufficient flow to electrical TIC-2221, and low flow alarm at pump outlet second and third pump RCS malfunction, or charging flow rate at (FIA-2212) low NPSH FIA-2212, and low pressurizer liquid level 11 Line, Makeup to Rupture Faulty weld Possible loss of makeup, Low VCT level alarm, VCT level controller LC-2227 Volume Control activity release from VCT, possible annunciation of area will close VCT discharge valve Tank (VCT) VCT low pressure radiation monitors, VCT low and open valve to refueling pressure alarm water tank 12 Boric Acid Fails off Electrical Precipitation, inability to TIC-2213 will indicate low Sufficient reserve in makeup Batching Tank malfunction mix boric acid temperature tanks is available until Heater and malfunction is corrected Controller Boric Acid Fails on Electrical Overheating of boric acid TIC-2213 will indicate high Isolate and repair, sufficient Batching Tank malfunction in batching tank temperature reserve in makeup tanks Heater and Controller 13 Boric Acid Fails to start Electrical Unable to batch boric acid Visual Isolate and repair, sufficient Batching Tank malfunction solution reserve in makeup tanks Mixer 14 Boric Acid Leak Faulty weld or Loss of boric acid Level indication and alarm Redundant full capacity standby Makeup tank connection tank 15 Line Discharge Leak Faulty weld or Loss of boric acid Level indication and alarm Redundant standby tank Boric Acid connection Makeup Tank 9.3-83 Amendment No. 21 (12/05)

TABLE 9.3-25 (Cont'd)

Inherent Component/ Symptoms and Method of Compensating No. Location Failure Mode Cause Local Effects Detection Provision(s) 16 Boric Acid Makeup Fails to start Electrical Loss of flow Pump Discharge pressure Redundant standby pump, Pump malfunction or low alarm gravity feed or use shaft break refueling water tank 17 Line, Boric Acid Pump Rupture Faulty weld Loss of boric acid Pump discharge pressure Redundant standby pump, low alarm and boric acid from refueling water tank 18 Line, Gravity feed to Rupture Faulty weld Loss of boric acid Boric acid makeup tank Alternate flow path of boric acid charging pump suction level indication and alarm available from refueling water tank 19 Heat Tracing (Note 1) Fails off Electrical Decrease in temperature Any malfunction of heat Redundant standby heat tracing malfunction in heat traced sections tracing annunciates a local and controls alarm 20 Volume Control Tank Rupture Faulty weld Loss of liquid and Pressure and level Charging pump suction will (VCT) radioactive gases indication and alarms on automatically be supplied by VCT, and radiation alarm in refueling water tank on low level auxiliary building in VCT 21 Line, Discharge of Rupture Faulty weld Loss of coolant, radioactive Pressure and level VCT discharge valve will close VCT gases and liquids released indications and alarms in on low VCT level and charging and low VCT pressure VCT pump suction will switch to refueling water tank 22 Line, Refueling Water Rupture Faulty weld Loss of RWT contents Level alarm in RWT Ability to borate the RCS with Tank to CVCS contents of makeup tanks not affected. Isolation valve at tank Note 1: This affects only those sections of the system where heat tracing must be retained.

9.3-84 Amendment No. 12, (12/93)

TABLE 9.3-25 (Cont'd)

Inherent Component/ Symptoms and Method of Compensating No. Location Failure Mode Cause Local Effects Detection Provision(s) 23 Line, Charging Pump Rupture Faulty weld Loss of pressure, Loss of Low pressure alarm Isolate, charge through HPSI Discharge coolant (PIA-2212) and low flow header alarm (FIA-2212) 24 Line, VCT to charging Rupture Faulty weld Loss of charging capability, VCT low pressure alarm, Trip charging pump, and initiate pump loss of coolant and low charging pressure injection with HPSI pump from radioactive gases alarm and low flow alarm the RWT when available.

25 Refueling Water Rupture Tornado Missile Loss of RWT Contents Level alarm in RWT Ability to borate the RCS with Storage Tank BAMT and SIT/VCT intertie.

ABBREVIATIONS CCW Component cooling water system IX Ion exchanger LHX Letdown heat exchanger PRM Process radiation monitor RCS Reactor coolant system RHX Regenerative heat exchanger RWT Refueling water tank SIS Safety injection system SIT Safety Injection Tank VCT Volume control tank 9.3-85 Amendment No. 17 (10/99)

TABLE 9.3-26 CHEMICAL AND VOLUME CONTROL SYSTEM INSTRUMENT APPLICATION Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording (1) Control Function Range(3) Range Accuracy(3)

B.A. Makeup Tank Temp.2 *

  • Heaters 60-120°F B.A. Batching Tank Temp.
  • Heaters 140-160°F Letdown Temp. After Regen Hx *
  • Letdown Flow Isolation 263-334°F on High Temp Letdown Temp. After Letdown Hx * * *
  • Component Cooling 100-120°F Water flow to Letdown Hx Letdown Temp. After Letdown Hx *
  • Process Radiation 100-120°F Monitor Isolation and Ion Exchanger Bypass on High Temp Volume Control Tank Temp. *
  • 100-120°F Regen. Hx Shell Temp.
  • 395°F Letdown Pressure * *
  • Letdown and Backpressure Control Valves Purif. Filter *
  • 1-30 psid Ion Exchanger
  • 1-15 psid Letdown Strainer *
  • 0-20 psid B.A. Pump Discharge Press2 *
  • 85-110 psig UNIT 1 9.3-86 Amendment No. 28 (05/17)

TABLE 9.3-26 (cont'd)

Indication Alarm(1) Normal System Parameter Contr. Operating Inst.

and Location Local Room High Low Rec.1 Control Function Inst. Range(3) Range Accuracy(3)

B.A. Strainer

  • 0.25-5.0 psid Charging Pump Header Press2 *
  • 100 psig Charging Pump Suction Press
  • Charging Pump 10 to 29.73 psia Permissive Volume Control Tank Press * *
  • 15 psig Charging Pump Seal Lube Leakage *
  • 0.0 gpm B.A. Makeup Tank Level * * * * **

Volume Control Tank * *

  • Level Replenishment, 40-55%

Bypass to WMS, Tank Isolation Chg. Pump Lube Oil Level *

  • Charging Pump Seal Lube Tank *
  • 16 in WC Level Letdown Flow *
  • 40 gpm Boron & Process Rad Flow *
    • As per St. Lucie Technical Specifications 3/4 3.1.2.7 and 3.1.2.8 9.3-87 Amendment No. 22 (05/07)

TABLE 9.3-26 (cont'd)

CHEMICAL AND VOLUME CONTROL SYSTEM INSTRUMENT APPLICATION Indication Alarm(1) Normal System Parameter Contr. Operating Inst.

and Location Local Room High Low Rec.1 Control Function Inst Range(3) Range Accuracy(3)

Demineralized Water Flow * * *

  • VCT Level, Boron 0-150 gpm Conc Charging Flow2 *
  • Process Radiation * *
  • 10-3 (R2202) Ci/cc (I-135) 1 All alarms and recorders are in the control room unless otherwise indicated.

2 Instruments required to assure injection of boric acid into the reactor coolant system during postulated accidents.

3 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.3-88 Amendment No. 21 (12/05)

TABLE 9.3-27 SHUTDOWN COOLING SYSTEM DESIGN DATA Code - piping Code for Pressure Piping, ANSIB31.7,

- valves Class II Draft ASME Code for - Pumps and Valves for Nuclear Power, November 1968 Shutdown Cooling System Start-up Approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after reactor shutdown or trip Design Pressure, psig a) Reactor coolant pressure boundary to valves isolating suction side of LPSI pumps 2485 b) Remaining piping and valves up to suction of the LPSI pumps 350 c) From discharge side of LPSI pumps to the low pressure safety injection valves 550 HCV 3615, 3625, 3635, 3645 d) From the inlet to the low pressure safety injection valves to the safety injection line 2485 loop penetrations.

Design Temperature, F 350 Reactor Coolant System Cooldown Rate (At initiation of Shutdown 75F/hr (analyzed cooldown EC290379 rate) 85°F/hr (administrative limit for normal shutdown)

Cooling)

Refueling Temperature, F 135 Material - Piping and Valves Austenitic Stainless Steel Nominal Shutdown Cooling Flow, gpm 3000 (Total)

TABLE 9.3-28 SHUTDOWN HEAT EXCHANGER DESIGN DATA Shutdown Cooling Mode Tube Side Flow, Million lb/hr 1.5 Inlet Temperature F 135 Outlet Temperature F 116.3 Shell Side Flow, Million lb/hr 2.41 Design Temperature, P -

Inlet Temperature, F 100 Design Pressure, psig -

Outlet Temperature, F 111.6 9.3-89 Amendment No. 30 (05/20)

TABLE 9.3-29 SHUTDOWN COOLING SYSTEM INSTRUMENT APPLICATION Indication Alarm1 Normal System Parameter Contr Inst. Operating Inst.

and Location Local Room High Low Rec1 Control Function Range(2) Range Accuracy(2)

Heat Exchanger Inlet

  • Variable Temperature Heat Exchanger Outlet
  • Variable Temperature Heat Exchanger Inlet
  • Heat Exchanger Variable Flow Bypass Valve Heat Exchanger Flow
  • Heat Exchanger Variable Bypass Valve 1 All alarms and recorders are in the control room unless otherwise indicated.

2 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.3-90 Amendment No. 17 (10/99)

TABLE 9.3-30 POST ACCIDENT SAMPLING SYSTEM COMPONENT DATA

SUMMARY

(HISTORICAL)

MAJOR COMPONENTS All the following components are supplied in four (4) major prefabricated skids:

1. Sample Selection and Strainer Station
2. Pressure Reduction and Sampling Station
3. Phase Separator
4. Control Console COMPONENTS DESCRIPTION SKID/LOC Magnetic Flow Meter Flow Rate: Up to 2000 cc/min 2 (Liquid) Instrument with signal converter and recorder.

Linear Mass Flow Meter Flow Rate: Up to 5000 cc(STP)/min 2/4 (GAS) Instrument with digital readout box.

Gas Grab Sample 45cc stainless steel, double ended, sampling 2 Cylinder cylinder with isolating needle valves, leak-tight quick-connects with double ended shutoff fittings on both sides.

Gas Separator with Stainless steel construction; designed for 3 Gas Release Valve total gas separation at design conditions.

At steady state operation, the gas release valve will maintain normal liquid level.

Pressure Indicator Range: 0-2500 psig 1/4 Dissolved Hydrogen Analyzer Indicate H2 concentration continuously with 2/4 provisions for remote calibration. Range 0-2000cc (STP) H2/kg H20. Sensitivity: + 2% of full scale.

9.3-91 Amendment No. 18, (04/01)

TABLE 9.3-30 (Cont'd)

COMPONENTS DESCRIPTION SKID/LOC Pressure Indicator 1-150 psig 1/4 Temperature Indicator 50-600F 1/4 Temperature Indicator 50-150F 1/4

- Strainer Stainless Steel 1

- Pulsation Dampener Stainless Steel approx 1000cc 3 9.3-92 Amendment No. 16, (1/98)

TABLE 9.3-31 Zinc Injection Skid Design Data Zinc Injection Skid 1 Design Pressure, psig 150 Design Temperature, °F 40 -120 Design Flow Rate, gph 0.16 - 1.60 Fluid Water & Zinc acetate*

  • Depleted zinc is used. Depleted zinc is produced by reducing Isotope 64Zn from 48.6% of the naturally occurring atoms to less than 1%. Ref: Sec 5.4.6, page 5-18 of EPRI Report 1013420, Dec 2006.

9.3-93 Amendment No. 24 (06/10)

REFER TO DRAWING 8770-G-085, Sheets lA & B FLORIDA POWER & LIGHT COMPANY ST. LUCZE PLANT UNIT 1 FLOW DIAGRAM SERVICE AIR SYSTEM FIGURE 9.3-1 Amendment No. 16, (1/98)

REFER TO DRAWJ:NG 8770-G-085, Sheets 2A, B &: C FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM INSTRUMENT AIR SYSTEM FIGURE 9.3-la Amendment No. 16, (1/98)

Refer to drawing 8770-G-085 Sheet 3 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1

  • FLOW DIAGRAM INSTRUMENT AIR SYSTEM FIGURE 9.3-1b Amendment No. 15 {1/97)

REFER TO DRAWING 8770-G-0 85, Sheets 4A & B

.I:"LUK.LDA POWER Oc: LIGHT COMPANY ST. LOCJ:E PLANT ONJ:T 1 FLOW DIAGRAM INSTRUMENT AIR SYSTEMS FJ:GURE 9.3-lc Amendment No. 16, {1/98)

Refer to drawing 8770-G-078 Sheet 150 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1

  • FLOW DIAGRAM SAMPLING SYSTEM FIGURE 9.3-2 Amendment No. 15 (1/97)

-o cnO

~~

m t-<  :;Q ~ letdown g r.>>O letdown I Fi Iter

..... r-  :;Q ...._..

(I) .......... Flow -~

'"dG)g t l I-'  ::I:

Control lll-t Purification Deborating Deborating

sn Outside f I ~ 1Process Radiatio'l- [on (on bn rtp R.eoctor i""" Monitor Exchanger Exchanger Exchanger H... IIN Containment

~ Boronometer f-J *

, - ' Boric Acid Inside

--- - - - il ______, Recovered Strainer I Boric Acid- Botching Reactor Tank Containment Coolant Pump I ~

() ToWMS Controlled t

-n  ::r oco Bleed-Off

E3 Primary 1 I Strainer I Vln* Chemical 1 Makeup Water J---!1 '

nru

r- Addition

. r - ,_ _ t.._t........ t t coru Tank 3::J Q)c::::l..

t<

no Acid .... Makeup Makeup RCS Regenerative Strainer Tank Tank

-c:

~3 l<>op Heat Exchanger~ Charging

.,co f+- Pump 1 3n ruo -* ,1----J c;3.

"C., Boric Acid coO

., letdowr; Charging H. ..._. _________I 14-f Makeup Q) Vl Stop I f-1-- Pump Pump

~

ocn Valve ,

J-

_co I 3 ~ Charging I ...,_~om Refueling Boric Acid

~ Pump 14-' ater Tank Makeup From I Pump RCS lDop Inside I Outside

!l Reactor Reactor VJ Containment Containment c ~

VJ I <a (I) 6 I

REFER TO DRAWING 8770-G-078, Sheets 120A & B FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT ~T 1 FLOW DIAGRAM CHEMICAL AND VOLUME CONTROL SYSTEM FJ:Gti'RE 9.3-4 Amendment No. 16, (1/98)

REFER TO DRAWING 8770-G-0 78, Sheets 121A & B FLORIDA POWER & LIGHT COMPANY ST. LUC~E PLANT UNZT 1 FLOW DIAGRAM CHEMICAL AND VOLUME CONTROL SYSTEM FJ:GURE 9.3-5 Amendment No. 16, (1/98)

V34641 VM61 SHUTDOWN COOliNG HEAT EXCHANGERS HVC 3667 LOOP 1A2 HCV3616 -to-V3114 Vl206 :J I N_... - - - LOOP 1A1 V3227

DELETED Amendment No. 22 (05/07)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.3-7

Refer to drawing 8770-G-092 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1

  • FLOW DIAGRAM MISCELLANEOUS SAMPLING SYSTEMS-SH 1 FIGURE 9.3-8 Amendment No. 15 (1197)

Refer to drawing 8770-G-092 Sheet 2 Amendment No. 22 (05/07)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM MISCELLANEOUS SAMPLING SYSTEM SH 2 FIGURE 9.3-8a

  • 18 17 I

16 15 J

v 14 v

J 13 12

}f

~

.. 11

-&, 10 v I> 9 I

t-a::

,jW iii~a rl lr

_.z

~-7 rl v

6 Jl 5

Jf "

r~

l)v 4

3 In/~

2 1

0 20 40 60 80 100 120 140 160 TEMPERATURE (degrees F)

AMENDMENT NO.9 (7/901

9.4 AIR CONDITIONING, HEATING, COOLING AND VENTILATION SYSTEMS 9.4.1 CONTROL ROOM VENTILATION 9.4.1.1 Design Bases The control room ventilation system is designed to:

a) Limit control room doses due to airborne activity to within GDC 19 limits b) Maintain the ambient temperature required for personnel comfort during normal conditions c) Permit personnel occupancy and proper functioning of instrumentation and control during all normal and Design Basis Accident conditions assuming a single active failure d) Withstand design basis earthquake loads without loss of function e) Permit personnel occupancy during a toxic gas release accident 9.4.1.2 System Description The control room ventilation system flow diagram is shown on Figure 9.4-1 and the control diagram is shown on Figure 9.4-3. System design data are given in Table 9.4-1. Safety and seismic classifications for components of the Control Room Ventilation System are given in Table 3.2-1. The area served by this system is the Control Room, the Technical Support Center, and all other areas west of the RAJ line, on the 62.0-foot elevation, including the ERDS Cabinet Area of the SAS Computer Room.

See Sections 6.4, 12.2, and 15.4 for related information concerning the Control Room HVAC.

9.4.1.2.1 Normal Operation During normal operation the control room is air conditioned by three redundant 50 percent capacity units (HVA/ACC-3A, B, C). Two units are normally running with the third unit in a standby status available for manual actuation in the event of a failure of one of the operating units. The normal operating conditions in the control room are those recommended by ASHRAE for comfort air conditioning. With 93°F outside ambient air temperature, a maximum control room air temperature of 125°F is reached 54 minutes after loss of all three air conditioning units assuming intake of outside air at 750 cfm. This temperature is based on a class room temperature of 98°F, 10 person occupancy, 2000 watts of emergency lighting, equipment heat gains, and the adjacent HVAC and electrical equipment rooms at 104°F. Since equipment within the control room is qualified for higher temperature (135°F per Table 3.11-1), loss of all three air conditioning units is acceptable. At 125°F, continued habitability for periods of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is permissible. Through judicious allocation of plant operating personnel it will be possible to maintain continuous occupancy of the control room. In addition, the operator can bring the plant to safe shutdown from outside the control room. From the above, it is concluded that the control room air conditioning units need not be protected from design basis hurricane winds, tornado winds or tornadic debris.

The control room ventilation system consists of split system air conditioners (i.e., an indoor and outdoor section), a ducted air intake and air distribution system, and a filter train with HEPA filters and charcoal absorbers with two redundant booster centrifugal fans. The indoor section is located at elevation 62 ft. and includes a cabinet type centrifugal fan, a direct expansion refrigerant cooling coil and filters. The outdoor section is a single assembly which includes a refrigerant condensing coil and fans, and refrigerant compressors. Both the indoor and outdoor sections are seismic Class I.

UNIT 1 9.4-1 Amendment No. 27 (04/15)

Control room air is drawn into the indoor air handling section through a return air duct system and roughing filters, and is cooled as required. Conditioned air is directed back to the control room through a supply air duct system. Outside air makeup is effected through either of two outside air intakes located in the north and south walls of the reactor auxiliary building at elevation 78' 9".

Two air conditioner units are normally in operation with the selected intake valves open.

9.4.1.2.2 Emergency Operation On receipt of a containment isolation signal (CIS) from either Unit 1 or 2 or high-high radiation signal at a Control Room outside air intake, the booster fans are automatically started and the charcoal filter train dampers are opened. Outside air intake is isolated by the redundant valves FCV-25-14, -15, -

16, -17 located in the outside air makeup ducts. The kitchen and toilet exhaust ducts are isolated by redundant valves FCV-25-24/FCV-25-25 and FCV-25-18/FCV-25-19, respectively. The control room air is recirculated through the HEPA filters and charcoal adsorbers. Air flow through the units is monitored and loss of flow conditions are annunciated. Position of air intake isolation valves, fan inlet dampers and filter inlet damper is indicated in the control room. Refer to Section 7.3.1.3.5 for additional information on Control Room ventilation instrumentation and control.

The Control Room Ventilation System removes potentially radioactive particulates and iodine from the Control Room during the Post-LOCA operating mode using a HEPA filter, charcoal adsorber, and Control Room Emergency Ventilation Booster Fans HVE-13A and HVE-13B. The system operates Post-LOCA to maintain a positive pressure in the Control Room, relative to all adjacent spaces. The flow control valves installed in each air intake are manually throttled to control the flow of air being drawn into the Control Room. Post-LOCA makeup flow enters through one or both of these ducts and passes through the charcoal adsorber and HEPA filter. Thus, all makeup air is filtered.

The control room is maintained at a slight positive pressure when receiving outside air makeup. This pressure differential deteriorates if there is no air makeup. Refer to Section 15.4.1.8d for the calculational model used in determining post-LOCA control room doses.

The control room filtration system has been modified to increase its dose reduction effectiveness during the post-LOCA operating mode. The system is operated post-LOCA to maintain a positive control room pressure. Flow control valves installed in each air intake control the flow of air being drawn into the control room. Post-LOCA makeup flow enters through one of these valves and passes through the charcoal filters. Thus, all makeup is filtered. Control room pressure and intake air flow indication is provided. The ability to operate in this mode has been verified by a preoperational test as discussed in Section 6.4.

The control room has three air duct penetrations; two for the outside air intake, and one for the toilet area and kitchen exhausts. All three penetrations are isolated on a CIS by low leakage butterfly valves. (The outside air intake and exhaust valves also close upon receipt of a high-high radiation signal from associated radiation monitors located in the air intakes.)

Piping and cable tray penetrations are sealed against the concrete wall. Electrical raceways are sealed against inleakage by means of air-tight fire stops. The fire stop consists of high temperature insulation on top of a high temperature fire board cut to accept the raceway and sprayed from below with a fire retardant.

9.4-2 Amendment No. 24 (06/10)

Should a loss of offsite power occur the air conditioner units are automatically loaded on the emergency diesel generator sets. Refer to Table 8.3-2. The engineered safety features instrumentation and controls contained within the control room are tested to remain operable over a temperature range of 40 to 130F and a humidity up to 94 percent. Reactor protective system instrumentation in the control room is designed to remain operable for the range 40 to 135F and humidity of 90%.

Administrative controls provide for all doors leading to the control room to be closed when not in use.

Regarding the fresh air makeup during normal operation, the fresh air makeup is less than 1 air change per hour. Dampers with a closure time of 35 seconds are provided.

The total infiltration of outside air to an isolated control room via doors, penetrations dampers, roof and walls was originally calculated to be 34.2 cfm with a 1/8 inch water gage differential across all openings (see Section 6.4); this is less than the Staff's limit of 0.06 air changes per hour (equivalent to 56 cfm). In the accident analysis presented in Section 9.4.1.3 below an infiltration rate of 100 cfm was assumed. Tech Spec Amendment #38 increased this value to 450 cfm (see Section 15.4.1.8d).

One extra self-contained breathing apparatus unit is provided for every three units required.

An analysis has been performed to determine both personnel habitability and equipment operability in the control room (CR) during a Station Black Out (SBO) event. The loss of AC power during an SBO event will result in a loss of control room air conditioning. Alternate AC power is assumed to be unavailable for the first hour of the event, and the station copes on DC power during that time. The control room ventilation system is assumed not to function during the one-hour DC coping period.

Calculated temperatures for the control room during the DC coping period remain within the stations heat stress procedural guidelines; therefore, the control room remains habitable for continuous occupancy during a station blackout event. The peak calculated control room temperature is essentially equal to the acceptable steady state temperature for equipment operability per NUMARC 87-00, Rev. 0, Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors, and therefore operability requirements for safe shutdown equipment in the control room are met.

9.4.1.3 System Evaluation Control room ventilation system components essential to safety are designed and installed in accordance with seismic Class I requirements. Purchase specifications require manufacturers to submit type test - or calculational data to verify the capability of the equipment to function during and following a design basis earthquake. Refer to Section 3.7.5 for a discussion of seismic qualification.

The unit can be brought to a safe and stable plant condition by using the primary control station (PCS) located external to the control room in the event of a fire in the control room (Refer to Section 7.4.1.8).

UNIT 1 9.4-3 Amendment No. 28 (05/17)

Only one booster fan, HEPA filter and air conditioner are required for ventilation, filtration and cooling of the control room air under post-accident conditions. Electrical power for each booster fan, damper, outside air intake isolation valves and air conditioner is supplied from a separate emergency power bus to prevent a single electrical failure from disabling both units.

Table 6.2-13A presents a comparison of the control room ventilation system to the regulatory positions of Regulatory Guide 1.52.

Toxic Gas Release Analysis Pursuant to NRC Post-TMI requirements in reference 2, a control room habitability report was prepared in 1981 showing that control room operators are adequately protected against the effects of accidental release of toxic and radioactive gases and that the plant can be safely operated or shutdown under design basis accident conditions. See reference 1 for analysis assumptions.

Table 9.4-1D provides the analysis results.

The short separation distances between the control room air intakes and the locations at which toxic chemicals were expected to be stored onsite required a separate analysis be performed for ammonium hydroxide and carbon dioxide. For the case of ammonium hydroxide it was assumed that all the ammonia in solution in one 55 gallon drum became airborne. For carbon dioxide the contents of one tank (360 scf) were assumed to completely vaporize. The instantaneous diffusion model presented in Regulatory Guide 1.78 was utilized. The results indicate that the concentrations at the control room HVAC system outside air intake remain below toxicity limits thus no action was to be taken by the operators nor were any safety system functions performed. Furthermore, significant quantities of ammonium hydroxide are not stored at the plant site. Therefore, ammonium hydroxide poses no threat to the control room operators.

Cyclohexylamine was evaluated in the Reference 1 report. However, this chemical is no longer stored at the plant site. Therefore, this chemical no longer poses a threat to the control room operators. Based on stored volume, concentration, distance, toxicity limits and volatility, present chemicals stored for secondary system chemical control use are bounded by the review for cyclohexylamine and/or the review for their use within Unit 2.

In addition to the toxic gas analysis, the habitability report also documented a radioactive release analysis to control room personnel. The analysis was conducted using guidelines of SRP 6.4. The results of this analysis are shown below (historical values):

Analysis Dose (Rem) Regulatory Limit (Rem)

Whole Body 1.9 5.0 Skin 18.0 30.0 Thyroid 18.0 30.0 The above dose information has been retained for historical informational purposes. Information relative to current system performance assumptions and the resulting dose assessment is provided in the discussion of the event consequences as reported in Chapter 15 of this UFSAR.

Chlorine Release Analysis (Historical)

The environment around and inside the control room was originally evaluated for an accidental release of chlorine from a one ton storage cylinder. Original plant design required a chlorine detection system capable of automatically isolating the outside air intakes upon receipt of a chlorine accident signal. The one ton cylinder has since been removed and the NRC Safety Evaluation Report for license amendment #57 concluded that the chlorine detectors are no longer required. The following calculation and related tables remain for historical purposes as a design limiting case for the Control Room Ventilation System (note that this analyses assumes operation of the chlorine detection system which is no longer operational).

The chlorine cylinder, containing 1 ton of chlorine (liquid), was assumed to rupture. Using information from A. E. Howerton, "Area Affected by a Chlorine Release" (presented at the Chlorine Institute, N.Y.

2/1/68) 22.5% of the liquid chlorine (450 lbs) will immediately flash as a gaseous cloud into atmosphere.

9.4-4 Amendment No. 26 (11/13)

THIS PAGE INTENTIONALLY LEFT BLANK 9.4-5 Amendment 15, (1/97)

The other 1550 lbs will remain on the ground and evaporate slowly. Accordingly there are two components to the release of chlorine; a puff component and a continuous component. Because of the basic difference in the nature of these two components, they were treated separately, and the results were superimposed.

The Puff Component After a rupture, the 450 pound chlorine puff will be dispersed in the air. However, prior to dispersion, this puff will occupy a finite volume which depends on temperature and pressures. The volume 450 lbs of chlorine will occupy is:

[450 lbs] [454g/lb] [mole/70g] [22.4 L/mole] [103 L/m3] = 65.4m3 This volume is conservative, since it assumes that the puff is released non-violently. In reality of course, the puff is released with great turbulence which increases the volume and thereby the dispersion.

The Gaussian model was used to estimate dispersion (see "Meteorology and Atomic Energy" at page 115).

(x - ut ) 2 y 2 2

( -[ - + h ] )

exp 2 xi 2 yi 2 zi (x, y, z) = (1)

Q 2 3/2 xi yi zi + V Where:/Q = 1/m3 xi Are the standard deviations of the Gaussian at the concerned X distances yi down wind zi V is the initial "puff" volume (m3) u is the average wind speed (taken to be 1 m/sec) x Horizontal coordinate point of interest h Release height (m)

The values of a were obtained from Meteorology and Atomic Energy for stable conditions (see page 175);

xi = yi = 0.02 X 0.89 zi = 0.05 X 0.61 Where: x = down wind distance to control building = 100 m u = 1 m/sec 9.4-6 Amendment No. 20 (4/04)

Equation (1) for the control room becomes:

exp [ - (100 - t 2 ]

(100, 0, 0) = (2)

Q 2 3/2 (1.2)(1.2) (0.83) + 65.4 Table 9.4-1.A lists the /Q valves calculated for various times, along with the concentration outside the control room due to the puff component.

It is assumed that 1 ppm is the action level, i.e., when 1 ppm is detected in the intake the sequence of events described in (c) above begin. Thus for 2 seconds unfiltered air enters the control room air space at a rate of 750 cfm. After 2 seconds the air entering via the intakes is filtered. The results of the puff release analysis are provided in Table 9.4-1B. Air entering the control room from 2 to 8 seconds is filtered (99.7%), the peak influx rate occurs at 2 seconds for the unfiltered component and at about 7 seconds for the filtered component. Beyond 10 seconds the puff component is negligible.

About 2.2 x 10-3 pounds of chlorine enter the control room from the puff component. The concentration at t = 10 seconds is simply the mass of chlorine from the puff component divided by the control room volume (1594 m3). The result is 0.206 ppm.

The Continuous Component The remaining 1550 lbs of chlorine will form a puddle with a surface area of 352 ft2. This is based on the construction of a containing curb which would surround the storage tanks. The A. E. Howerton report* presents the evaporation rate of this component, and it may be calculated that after 34 minutes all the chlorine will have evaporated. The evaporation rate is a function of time as follows:

Qt = Qo exp (-rt)

Where:

Qt is the evaporation rate at any time t (lbs/sec)

Qo the initial evaporation rate at t = o lbs 2 Qo = (20 2

) * (352 ft ) * (1/3600 hr/ sec )

hr ft

= 1.96 lbs/sec r = evaporation rate decay rate obtained by curve fit from Howerton data.

= 7.3 x 10-4 (sec-1)

It is assumed that the evaporating chlorine will be dispersed by a /Q developed utilizing Halitsky's approach (see "Atomic Energy and Meteorology" at Section 5.5). The /Q value used was 1.8 x 10-3 sec/m3. The concentration in the control room due to the continuous component is found as follows:

(1 - 2)

A(T) = * /Q

  • F2
  • Qo [exp (- r T) - exp(-ZT)] + Ao exp (-Zt*)

Z - r 9.4-7

Where A(T) - chlorine content in the control room at time t + 94.2 2 = Filter cleanup efficiency for inleakage or inflow.

= 0, 0<T<2 sec, 35<T <

= 0.999, 2 sec <T<

F2 = Control room inflow (m/sec)

= 750 cfm, 0<T< 35 sec

= 100 cfm, 35 sec<T<

Qo = Evaporation rate at t=0 t* = Time into each phase (accident phases defined below)

Ao = The pounds of chlorine present at the beginning of each phase.

Z = Defined previously as L+R Since it takes 94.2 seconds for the cloud to reach the control room, T is defined in terms of real time t as follows:

T = t -94.2, or T=0 when t = 94.2 There are four accident phases for the continuous release component, namely, phase 1, 0<T<2 sec.,The normal control room makeup air flow (750cfm) is entering the control room unfiltered.

phase 2, 2<T<35 sec., The normal makeup flow is being filtered phase 3, 35<T<2040 sec., The isolated control room inleakage enters the control room unfiltered.

phase 4, 2041 sec<T, Boil off is complete and the chlorine source is completely evaporated.

The continuous component is provided in Table 9.4-1C. This table also provides the simultaneous puff component and the total control room concentration. It indicates that the peak concentration in the control room will be in the order of 0.44 ppm.

The above analyses attempts through conservative methodology to assess the potential chlorine concentration in the control room resulting from a catastrophic failure of a standard one ton cylinder.

The results are highly sensitive to the time to divert normal control room makeup to the charcoal filters. This sensitivity arises due to the model assumed, i.e., the initial volume of the cloud and the Gaussian plume assumption used to represent atmospheric diffusion. The initial cloud volume was assumed to be 65.4m3, i.e., it is a highly concentrated cloud 5 meters in diameter. This cloud is artificially elevated from the chlorine tank elevation (+19') to the control room intake elevation (+78'9")

and allowed to diffuse in accordance with the Guassian model while being transported to the intakes.

This methodology neglects the gravity effect (chlorine is heavier than air), any turbulent cloud formation, and the effect of interposing structures. It should also be noted that the distance to the nearest face of the control complex was assumed (100 meters) 9.4-8

whereas, the intakes are located along the north and south faces of the RAB (about 120 meters downwind). In summary, it is felt that the model is adequate for its intended purpose, namely, to assess the potential effect on control room habitability. If such an event were to occur, the combined effects of gravity, interposing structures, the frequency of occurrence of poor meteorology and wind direction, and the intake's elevation are such that it is highly unlikely that high concentrations of chlorine will reach the intakes.

Based on Table 2.3-7, Seasonal Hourly Distribution of Calm And Variable Winds, March 1, 1971 to February 29, 1972, 50 foot wind level; the longest consecutive period of calm wind conditions is 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. The five percentile meteorological condition corresponds to approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of calm wind conditions. The definition of a calm wind condition is when the average hourly measured wind speed is less than 1.0 mph.

The frequency of wind flow directly toward the control room from the chlorine tanks is 4.0% from the WSW wind direction and 9.0% for the sum of the two coterminus wind directions.

A chlorine cloud could not persist for more than the maximum number of hours of calm wind conditions because:

1. The median wind speed associated with a calm wind condition should be approximated by 0.5 mph (

Reference:

AEC Draft Regulatory Guides; February 20, 1974, Docket No. RM-50-2, Page D-8). Therefore, even during calm wind conditions, atmospheric movement will dilute the chlorine cloud.

2. Unstable atmospheric conditions, which are very frequent in the St. Lucie area. (Annual frequency of 31.8%, Reference, Table 2.3-1A) will provide turbulent atmospheric mixing.

Based on the above a chlorine emergency cannot persist for several days. At worst, it could persist for hours. The analysis presented above indicates that control room concentrations are expected to be less than 1 ppm. Thus provisions for delivery, handling and storage of a supply of bottled air for several hundreds of hours of control room occupancy is not required. Storage provisions for bottled air is provided for six hours of control room occupancy.

The preceding chlorine analysis was also performed for varying air intake rates from 100 cfm up to 1000 cfm. For all cases it was determined that results were in accordance with R.G. 1.78 criteria.

The airborne transport of a puff release of 25 percent of the contents of a 150 lb. cylinder was modeled using the instantaneous release diffusion model presented in Reg. Guide 1.78. However, chlorine releases from onsite storage was found to be limiting.

For a discussion of the storage of chlorine at the St. Lucie County wastewater treatment facility on Hutchinson Island, and the transportation of chlorine to this facility, refer to the St. Lucie Unit 2 FSAR Subsections 2.2.2 and 2.2.3.

9.4-9 Amendment No. 17 (10/99)

9.4.1.4 Testing and Inspection Preoperational tests are performed on the system to ensure meeting performance and design basis requirements. All automatic and manual sequences are tested to ensure proper operation.

Manufacturers test include:

a) pressure testing HEPA filter casings at 30 in. wg vacuum for distortion b) pressure testing casings at 2 psig for leaks c) performing filtration tests to verify filter design performance for filtration, air flow capacity, air flow resistance, moisture and overpressure resistance and shock and vibration d) verifying charcoal adsorber design efficiency 9.4.1.5 Instrumentation Application Table 9.4-2 lists the measured parameters for monitoring the performance of the control room ventilation system.

The air conditioners, centrifugal fans and outside air intake valves are controlled by remote manual operation in the control room. The outside air intake valves can also be opened or closed by direct manual operation.

9.4-10 Amendment No. 20 (4/04)

9.4.2 REACTOR AUXILIARY BUILDING VENTILATION SYSTEMS 9.4.2.1 Design Bases The reactor auxiliary building ventilation systems are designed to:

a) provide ventilation to permit proper functioning of equipment during normal operation b) provide air flow from areas of low potential radioactivity to areas of higher potential radioactivity c) provide an air supply for cooling of safety related equipment assuming a single active failure d) withstand design basis earthquake loads without loss of its cooling function of safety related equipment 9.4.2.2 Description The reactor auxiliary building ventilation systems consist of the main ventilation and various auxiliary system which are shown on Figure 9.4-1. The main system ventilates equipment areas such as pump rooms, the waste management system processing and storage areas, chemical and volume control system equipment rooms, and all potentially contaminated areas. The main ventilation system exhausts through the plant vent.

The electrical switchgear rooms and the battery rooms are served by the electrical equipment room ventilation system. Personnel areas such as locker rooms, offices, the machine shop, and laboratory are served by various miscellaneous ventilation systems. Laboratory areas are exhausted by the main reactor auxiliary building exhaust system. The reactor auxiliary building ventilation air flow is shown in Figure 9.4-1. The reactor auxiliary building ventilation systems P&I diagrams are shown on Figure 9.4-3.

9.4.2.2.1 Reactor Auxiliary Building Main Ventilation System The system consists of an air supply subsystem and an air exhaust air system (HVE-10A,B). Air supply is effected through wall louvers, roughing filters, two 100 percent capacity centrifugal fans (HVS-4A,B) and duct distribution systems. Component data are given in Table 9.4-3.

The air supply system provides the cooling requirements for the low and high pressure safety injection pumps and the containment spray pumps, and is designed as seismic Class I. Upon loss of normal power, the supply fans (HVS-4A, B) are automatically connected to the on-site emergency diesel generator sets. Main supply fan HVS-4A is powered from bus 1A-2 and fan HVS-4B from bus 1B-2.

The air exhaust system includes a 100 percent capacity bank of prefilters and HEPA filters, two 100 percent capacity exhaust fans (HVE-10A,B) and duct exhaust system. The exhaust system serves no safety function. Under accident conditions the engineered safety features pump rooms are supplied and exhausted by the ECCS area ventilation system described in Section 9.4.3.

9.4-11 Amendment No. 26 (11/13)

The reactor auxiliary building main ventilation system provides a minimum of four air changes per hour for each of the rooms in the building. Ventilation rate is sized to achieve the design ambient maximum temperature of 104°F in the equipment areas (excluding ECCS areas during accident conditions, See Section 9.4.3) with an outside air temperature of 93°F.

The exhaust from potentially contaminated areas is discharged to the plant vent. Exhaust from other areas is directed outside the building. Refer to Section 12.2 for a discussion of the reactor auxiliary building radiation monitoring system.

An analysis has been performed to determine any adverse affects on equipment operability in the RAB due to lack of ventilation during a Station Black Out (SBO). The RAB Main Ventilation System serves two areas that contain equipment necessary for a safe shutdown in the event of a SBO. These areas are the CEA MG area at 19 ft. elevation and the charging pump room on the -0.5 ft. elevation. Initially, during a SBO, all RAB ventilation fans will lose power. Alternate AC power is assumed to be unavailable for the first hour of the event, and the station copes on DC power during that time. The RAB Main Ventilation System is assumed not to function during the one-hour DC coping period. The peak calculated temperatures in the CEA MG area and the Charging Pump Room during the DC coping period are less than 108°F. Temporary temperature excursions up to 120oF will neither affect the operability of safety related equipment in these rooms nor reduce their service life.

9.4.2.2.2 Reactor Auxiliary Building Electrical Equipment and Battery Room Ventilation System Electrical equipment rooms 1A, 1B, and 1C, the static inverter room, and battery rooms 1A and 1B are ventilated by an air supply subsystem and individual room exhaust fans. Air supply is affected through a louvered intake, filters, 2 centrifugal supply fans operating in parallel (HVS-5A, 5B) and a duct distribution system. Equipment room 1A is exhausted by power roof ventilators RV-3 and 4. Equipment room 1B and the static inverter room are exhausted through the wall by fan HVE-12. Equipment room 1C is exhausted through the wall by fan HVE-11. This room is also provided with supplemental cooling from non-safety related air conditioners ACC-4 and 5 and air is recirculated within the room by fans HVA-4 and 5, respectively. Battery Rooms 1A and 1B are exhausted by power roof ventilators RV-2 and RV-1, respectively. All of these components normally are operating. Component data are given in Table 9.4-3.

Upon loss of offsite power, the electrical equipment rooms supply fans, exhaust fans, and roof ventilators, and the battery rooms' exhaust fans are automatically connected to the emergency diesel generator set.

The electrical equipment rooms fans are powered by separate emergency buses, as are the battery room exhaust fans. The supply and exhaust fans are designed as seismic Class I. This ventilation system (supply and exhaust fans) is safety related since it is required for proper functioning of the emergency electrical distribution equipment.

During normal operation with one non-safety grade air conditioner and all supply and exhaust fans operating, the ventilator air flowrates for the electrical equipment rooms, static inverter room and battery room are sized to achieve a temperature less than 104oF with an outside air temperature of 93oF. In the event of both air conditioners not being in operation, the ventilator air flowrates are sufficient to maintain all the rooms less than 104oF. In the event of one supply fan and one air conditioner operating, the supply fan operates at 2/3 the capacity of two supply fans, which is sufficient to cool all the rooms, below 104oF.

The analysis below was performed prior to implementation of PC/M 06145, which provided an auto-start capability for EER exhaust fans and roof ventilators. The text is maintained for discussion of bounding design conditions with regards to temperature.

During an emergency condition that involves a loss of offsite power, the automatic restart of the battery room exhaust fans and the electrical equipment room supply fans ensures that temperatures will not exceed 120oF in any of the rooms. Analysis has demonstrated that temporary (and infrequent) 9.4-12 Amendment No. 26 (11/13)

temperature excursions up to 120oF will neither affect the operability of safety related equipment in these rooms nor reduce their service life.

An analysis has been performed to determine temperatures in the electrical equipment rooms 1A, 1B and 1C, the static inverter room, and battery rooms 1A and 1B during a Station Blackout (SBO). Separate heat loads were determined and used to calculate maximum probable ambient temperatures. Initially, during an SBO event, all ventilation fans, both supply and exhaust, will be inoperable. Alternate AC power is assumed to be unavailable for the first hour of the event, and the station copes on DC power during that time. The ventilation fans serving these rooms are assumed not to function during the one-hour DC coping period. The peak calculated temperatures in the electrical equipment rooms 1A, 1B and 1C, the static inverter room, and battery rooms 1A and 1B during the DC coping period are less than 110°F. As stated in the preceding paragraph, this temporary temperature excursions up to 120°F will neither affect the operability of safety related equipment in these rooms nor reduce their service life.

Operational abnormalities or components failures resulting in the Electrical Equipment Room temperatures exceeding 102oF are annunciated in the Control Room. This high temperature alarm setpoint was selected to be below maximum acceptable evaluated room temperatures, yet high enough to eliminate nuisance annunciation during the summer months when the outside ambient temperature may exceed the design basis temperature of 93oF for short periods of time.

9.4.2.2.3 Reactor Auxiliary Building Miscellaneous Ventilation Systems The design data for the miscellaneous ventilation systems are shown in Table 9.4-3. Flow diagrams are shown on Figure 9.4-1 and P&I diagrams on Figure 9.4-3.

The locker and machine shop areas may be ventilated by supply fans HVS-3 and exhausted by fans HVE- 4 and HVE-5 (abandoned in place) respectively or the areas may be cooled by package-type air conditioning units. Machine shop air is passed through a prefilter and HEPA filter before being vented to the 19.5 hallway.

UNIT 1 9.4-12a Amendment No. 27 (04/15)

EC293372 The health physics count room, first aid room and health physics office are serviced by mini split system air handling units.

The counting room, instrument calibration and repair shop, and radiological chemical lab are serviced by mini split system air handling units. EC291231 9.4.2.3 System Evaluation Plant ventilation systems required for the operation of safety related components meet the same requirements for redundancy, independence, emergency power, quality assurance, and natural phenomena as the safety systems which they serve.

Where redundant safety related components (such as emergency electrical switchgear) require ventilation for proper operation, each redundant component is served by a separate ventilation fan and associated dampers and controls. In this way failure of a single active ventilation component can affect operation of only one of the redundant safety related components. The inlet louvers provided on HVAC systems are fixed and cannot fail in a closed position. Each of the redundant ventilation components and its controls are powered from a separate emergency bus which is part of the same emergency electrical load group as the components which it serves.

All ventilation system components required to perform safety functions are designed and installed as seismic Class I equipment and are located in seismic Class I structures. Purchase specifications require manufacturers to submit type test or calculational data to verify the capability of the equipment to function during and following a design basis earthquake. Seismic qualification of Class I components is discussed further in Section 3.7.5.

Battery room ventilation has been sized to avoid buildup of hydrogen.

9.4.2.4 Testing and Inspection Manufacturer tests include:

a) pressure testing HEPA filter casings at 6 in. wg vacuum for distortion b) pressure testing casings at 8 in. wg for leaks.

c) performing filtration tests to verify filter design performance for filtration, air flow capacity, air flow resistance, moisture and overpressure resistance, and shock and vibration d) verifying charcoal adsorber design efficiency 9.4-13 Amendment No. 31 (11/21)

9.4.2.5 Instrumentation Application Table 9.4-4 lists the parameters used to monitor and control auxiliary building ventilation systems.

The reactor auxiliary building vent systems (including the engineered safety features area which is discussed in Section 9.4.3) receive SIAS signals. Table 9.4-5 lists components receiving an SIAS and the control function of that signal. The function of the SIAS is to provide the proper flow path for supply air to the engineered safety features area and to draw all exhaust air from this system through the HEPA and charcoal filter bank. Section 9.4.3 discusses the ECCS area ventilation system.

Components which can be manually operated and/or which have operational interlocks are listed in Table 9.4-5.

System instrumentation design and logic is discussed in Section 7.7.

9.4-14

9.4.3 EMERGENCY CORE COOLING SYSTEM AREA VENTILATION SYSTEM 9.4.3.1 Design Bases The emergency core cooling system (ECCS) area ventilation system is designed to provide post-LOCA filtration and adsorption of fission products in the exhaust air from areas of the reactor auxiliary building which contain the following equipment:

a) containment isolation valves b) low pressure safety injection pumps c) high pressure safety injection pumps d) containment spray pumps e) shutdown heat exchangers f) piping which contains recirculating containment sump water following a LOCA 9.4.3.2 System Description The ECCS area ventilation system air flow diagram is shown on Figure 9.4-1, the control diagram on Figure 9.4-3 and design data on Table 9.4-6.

The air exhaust system consists of two redundant centrifugal exhaust fans (HVE-9A, B), HEPA and charcoal filter banks, and associated duct work dampers and controls. The exhausted air is vented to the outside atmosphere.

Under normal operation, the reactor auxiliary building main ventilation supply(HVS-4A/B) and exhaust system HVE-10A/B provides the necessary ventilation of the ECCS pump rooms as described in Section 9.4.2.2.1. Under accident conditions when several or all of the pumps are operating, the air supply to the nonessential section of the reactor auxiliary building is directed to the pump rooms to provide the additional cooling air requirement. The ventilation air flow rate is sized to maintain an ambient temperature at or below 120°F in the ECCS equipment areas during accident operating conditions.

Dampers are positioned automatically on SIAS signal to provide the proper flow path for supply air to the ECCS area. Simultaneously, the dampers in the exhaust ductwork are positioned to allow the fans to draw all exhaust air from the area through the HEPA and charcoal filter bank before discharge to the atmosphere. Seventeen (17) seconds following the SIAS actuation, exhaust fans HVE-9A & 9B are EC 205055 started. Two ECCS ventilation system exhaust monitors, connected to the noble gas monitoring system, measure the airborne effluent from the ECCS area. Table 9.4-5 lists the components actuated on SIAS and gives the control function of the SIAS on that component.

The ventilation system is sized to maintain a slightly negative pressure in the ECCS area with respect to surrounding areas of the reactor auxiliary building. Access into the ECCS area from other parts of the reactor auxiliary building is through gasketed selfclosing or locked closed doors. Opening of locked doors is under administrative controls.

9.4-15 Amendment No. 30 (05/20)

Piping penetrations into the enclosed area are provided with flexible rubber seals which limit the amount of in-leakage. The seals permit differential movement between the piping and the wall due to thermally or seismically induced motion.

9.4.3.3 System Evaluation The ECCS area ventilation system components meet the same requirements for redundancy, independence, emergency power, quality assurance, and natural phenomena as the safety systems which they serve.

Redundant safety related components such as the safety injection pumps, shutdown heat exchangers or containment spray pumps require ventilation for proper operation. Both trains of ECCS equipment are located within a single ventilation system envelope that is served by two trains of ventilation. Each ventilation train is capable of providing the necessary air flow to support operation of two trains of ECCS.

In this way failure of a single active ventilation component does not effect ECCS operation. Each of the redundant ventilation components and its controls is powered from a separate emergency bus.

Dampers connecting the ECCS area ventilation system with other parts of the auxiliary building main exhaust and supply systems fail in the closed position upon loss of control air or power. Dampers which align flow from the area through the charcoal filter train and exhaust fans fail in the open position.

The ventilation system is sized to maintain a slightly negative pressure in the engineered safety features area with respect to surrounding areas of the auxiliary building. Ductwork conveying air to the HEPA and charcoal filters will also be at negative pressure. Upon loss of normal power, the system will be automatically connected to the emergency power source if required to operate. The fans and dampers associated with each of the separate filter trains are powered from separate buses and receive actuation signals from separate SIAS channels. No single failure will prevent both trains from operating.

All ventilation system components are designed and installed as seismic. Class I equipment and are located in seismic Class I structures. Purchase specifications require manufacturers to submit type test, or calculational data to verify the capability of the equipment to function during and following a design basis earthquake.

Charcoal filter components receive factory and fluid tests similar to those described for the shield building ventilation system in Section 6.2.3.4.

See Table 6.2-13A for a comparison of the ECCS area ventilation system to the regulatory positions of Regulatory Guide 1.52.

a) Adsorber Considerations Charcoal adsorber performance can be adversely affected by humidity or heat. Methyl iodide adsorber efficiency for impregnated charcoal, as is supplied for the ECCS area ventilation system(MSA-85851), is reduced rapidly for humidities in excess of 90 percent, and the onset of iodine desorption begins at about 300°F. Each effect is discussed below.

9.4-16 Amendment No. 25 (04/12)

The ECCS equipment area is ventilated by passing outside air through it. The ECCS area ventilation system maintains the ECCS equipment area at a negative pressure, thus, iodine activity associated with any ECCS or containment spray system equipment leakage is passed through the ECCS system charcoal absorbers. It should be noted at this point, that equipment leakage immediately following a LOCA is expected to be minimal. Nonetheless, estimates of post LOCA equipment leakage have been made, and for evaluation purposes are assumed to persist from the initiation of the LOCA. The leakage assessment is provided in Table 15.4.1-2. A maximum total leakage of 2,375 cc/hr (approximately 0.60 gal per hour) has been determined appropriate for the equipment in question.

The sump water, which is recirculated through the shutdown heat exchangers upon receipt of a Recirculation Actuation Signal (RAS), only exceeds 212°F for a brief period early in the transient. By the time RAS occurs, sump water temperature has decreased below 212°F and any ECCS equipment leakage would not flash to steam.

Based on the above, the characteristics of the ECCS area ventilation system air flow may be summarized as follows:

1) The flow has the temperature and humidity characteristics of the outside supply air flow.
2) Flashing of the small leakage flow to steam is not expected during recirculation due to sump water temperatures being below 212°F.
3) Iodine associated with equipment leakage will generally stay with the fluid with only a small fraction becoming airborne.

Due to the small leakage rates involved, the effect of iodine partition between liquid and vapor spaces, and the large capacity charcoal absorber train, the heat loading due to iodine decay is insignificant.

Utilizing AST dose analysis methodology, the total effective dose equivalent resulting from ECCS equipment leakage during a postulated LOCA event are reported in UFSAR Table 15.4.1-11.

9.4-17 Amendment No. 26 (11/13)

The post-LOCA dose contribution from ECCS area equipment leakage is below the limit for normal operation (10 CFR 20 limits yield about 1.5 rem per year of exposure), and is only a small fraction of the guidelines established for design basis accidents. In light of this, the question of methyl iodide efficiency is academic, and the design with regard to humidity control is considered satisfactory, i.e., heaters are not required.

9.4.3.4 Testing and Inspection Preoperational tests were performed on the system to ensure that it is capable of meeting its performance and design basis requirements. All automatic and manual sequences were tested to ensure proper operation.

Manufacturers tests include:

a) pressure testing HEPA filter casings at 11 in. wg vacuum for distortion; b) pressure testing casings at 8 in. wg for leaks; c) performing filtration tests to verify filter design performance for filtration, air flow capacity, air flow resistance, moisture and overpressure resistance, and shock and vibration; and d) verifying charcoal adsorber design efficiency.

9.4.3.5 Instrumentation Application Table 9.4-4 lists the parameters used to monitor and control system operation. The function of the instrumentation is to monitor pressure across the HEPA filters and alarm low exhaust fan flow. The operator manually starts the standby unit on a low flow alarm.

Table 9.4-5 lists the ECCS area vent system components that are actuated by an SIAS and the control function of the SIAS.

Both exhaust fans are automatically started on SIAS, but the operator can manually shut one fan down and place it on standby.

9.4-18 Amendment No. 24 (06/10)

9.4.4 RADWASTE AREA VENTILATION The radwaste area is located inside the reactor auxiliary building and is serviced by the reactor auxiliary building main ventilation system which is discussed in Section 9.4.2.

9.4.5 TURBINE BUILDING VENTILATION The turbine building is an open structure with no ventilation system for the equipment areas except for the switchgear room and chemical storage areas which are enclosed. The chemical storage area is ventilated by a wall mounted supply fan and relief damper. The turbine building switchgear is provided with a filtered air supply and with wall mounted relief louvers for ventilation. Additionally, the system provides a slight positive pressure in the switchgear room to help maintain a dust-free environment.

The turbine building ventilation system serves no safety function. System design data are given on Table 9.4-7.

9.4.6 FUEL HANDLING BUILDING VENTILATION The fuel handling building ventilation system is designed to reduce plant personnel doses by preventing the accumulation of airborne radioactivity in the fuel handling building due to diffusion of fission products from the spent fuel pool. The system is also designed to ventilate the spent fuel cooling equipment contained within the fuel handling building.

The fuel handling building ventilation system consists of two separate supply systems and two separate exhaust systems. The system flow diagram is shown on Figure 9.4-1 and the control diagram is given on Figures 9.4-2 and 9.4-3.

Each supply system consists of a hooded wall intake, an air handling unit with filters and a fan section, and a duct distribution system. One system supplies air to the fuel pool area and the other system supplies air to the lower areas.

The fuel pool area air is exhausted through air inlets around the periphery of the fuel pool. Air is discharged by two 100 percent capacity centrifugal fans to the atmosphere through a prefilter, HEPA filter bank, charcoal absorbers and out the FHB vent stack.

Air exhaust from the lower areas is passed through a prefilter and HEPA filter bank before being discharged by a centrifugal fan to the atmosphere through the FHB vent stack.

9.4-19 Amendment No. 26 (11/13)

The analysis of the fuel handling accident is provided in UFSAR Section 15.4.3, and the offsite doses are provided in Table 15.4.3-4. The resultant doses are considered acceptably low. Nonetheless, a design modification has been implemented to provide the charcoal filter capability required by the staff. This modification was completed prior to the initial transfer of spent fuel from the unit 1 containment to the fuel building.

The modification consists of installing a single charcoal filter bed downstream of the HEPA filters in the fuel pool area exhaust. The charcoal bed is provided for elemental iodine removal only. Since the methyl iodide fraction is a small fraction of the iodine inventory, and the consequences of the fuel handling accident without charcoal filtration are acceptably low, the design basis for the fuel pool system retrofit is appropriate. A manual damper is installed on the upstream side of the filter assembly to provide the capability for periodic testing of the charcoal filter assembly's elemental iodine efficiency.

Radiological considerations of system operation are discussed in Section 12.2.2.5.

Radiation passing out the FHB vent stack is monitored and recorded locally. Fuel pool air exhaust fan low flow is alarmed in the control room.

The fuel pool air exhaust fans are controlled manually from the control room. The fan inlet dampers are opened and closed on the same control signal as the exhaust fans. These dampers are air operated and fail closed on loss of power or compressed air.

The fuel pool air supply fan is controlled from a local switch with fan status lights provided in the control room. The operation of the supply fan is interlocked with the operation of the fuel pool exhaust fans.

Preoperational tests are performed on the system to ensure meeting performance and design basis requirements. This system is in service during normal plant operation and so is monitored continuously through its performance.

9.4.7 DIESEL GENERATOR BUILDING VENTILATION SYSTEM The diesel generator building ventilation system is designed to provide ambient conditions suitable for occupancy when the emergency generators are not in operation. A power roof ventilator located in each room is sized (5000 cfm) for four air changes per hour. The system serves no safety function since it is not required for operation of the emergency generators. When the diesel generators are in operation, the fans serving the engine cooling system radiators also provide ventilation air flow through the building.

There are no automatically controlled valves in this system. There is only one piece of equipment to be controlled, the power roof ventilator, and it is actuated manually from a local switch.

9.4-20 Amendment No. 24 (06/10)

9.4.8 CONTAINMENT VESSEL VENTILATION SYSTEM The major ventilation systems located inside the containment vessel are listed below. Each system is designed according to the scheme used for identification purposes as shown on the control diagrams, referenced by:

Scheme System Control Diagram A Containment Purge System Figure 9.4-2 B Containment Vacuum Relief Figure 9.4-2 C Containment Fan Coolers Figure 9.4-2 D Airborne Radioactive Removal Units Figures 9.4-2 and 9.4-3 E Reactor Support Cooling System Figure 9.4-2 F CEDM Cooling System Figure 9.4-2 G Reactor Cavity Cooling System Figure 9.4-2 H Hydrogen Purge System Figure 9.4-2 A system closely related to the containment vessel ventilation systems is Scheme I, the shield building ventilation system (Section 6.2.3).

Schemes A and D are designed to limit doses to plant personnel and are discussed in Section 12.2. The remaining schemes with the exception of E and G are discussed in Section 6.2.

The system flow diagram is shown on Figure 9.4-1 and design data for schemes E and G are given in Table 9.4-8.

9.4.8.1 Reactor Cavity Cooling System The reactor cavity cooling system is designed to ventilate the annular space between the reactor vessel and the concrete primary shield wall to limit the concrete surface temperature to a maximum of 150°F to minimize the possibility of concrete dehydration and consequent faulting. The cooling system limits thermal growth of the supporting steel work, in conjunction with the reactor support cooling system which is discussed in Section 9.4.8.2, and also cools the reactor vessel insulation.

Refer to Appendix 3H for the results of a loss of cooling flow analysis.

Basic components consist of two axial fans, each sized for 100 percent capacity, and a ducted air supply system. Cooled air, between 100 and 105°F, is drawn from the fan cooler ring header and directed into the annular space formed between the reactor vessel and the primary shield wall.

9.4-21 Amendment No. 26 (11/13)

During normal operation only one fan is operated while the other acts as a standby. Each fan can be started manually from the control room. An air flow switch in the discharge of each fan annunciates on low flow after a 10 second time delay. The reactor cavity cooling fan motors are tripped (if running) and blocked from starting/restarting on a safety injection actuation signal (SIAS) event due to the environmental conditions inside the containment building.

Ambient temperatures are recorded from two locations 180 degrees apart and alarmed at or below 150°F.

An engineering evaluation (PSL-ENG-SEMS-99-032) was performed to determine the minimum redundancy required for this indication, and the compensatory actions in the event that less than the minimum number of channels are available. Should there be less than the minimum number of operable channels, the minimum number of operable channels will be restored during the next refueling outage, or an alternate monitoring program will be implemented.

Power is supplied to the fans from Class IE motor control centers. In case of loss of offsite power, the fans are loaded on the diesel generators and automatically restarted to provide continued cooling of the reactor cavity in order to facilitate maintenance of the reactor in a hot standby condition. Each 100 percent capacity redundant fan is thus available to maintain reactor cavity cooling upon loss of offsite power.

The reactor cavity cooling system is not required to safely shut down the reactor or mitigate the consequences of a LOCA. There are no safety related components located in the reactor cavity which require cooling to perform their function other than the out-of-core neutron detectors which are qualified to function at 180°F. There will be no appreciable dehydration of the concrete in the reactor cavity even if it is exposed to a temperature of 250°F for an extended period of time (at least one month).

All system components are suitable for operation in 120°F ambient and 1 rad/hr radiation dose rate environments.

9.4.8.2 Reactor Support Cooling System The purpose of the reactor support cooling system (in conjunction with the reactor cavity cooling system) is to limit the temperature at the bottom of the lubrication plate between the reactor and support leg to 300°F, restrict thermal growth of the reactor vessel supporting steelwork to 3/16 inch by limiting surface temperature to 140°F and limit the temperature at steel concrete interfaces to 150°F. See Appendix 3H for ventilation requirements to maintain these restrictions.

The structural steel members beneath the lubrication plates are cooled by utilizing air at 120°F from the containment atmosphere. Either of two 100 percent capacity centrifugal fans supplies this air through ductwork and distributes approximately 3800 cfm to each of the three support legs. Flow nozzles are used to distribute the air uniformly to the support structures.

During normal operation, one fan is operated while the other acts as a standby. Each fan is started manually from the control room. An air flow switch in the discharge of each fan annunciates an alarm on low flow after a 10 second time delay. The reactor support cooling fan motors are tripped (if running) and blocked from starting/restarting on a safety injection actuation signal (SIAS) event due to the environmental conditions created inside the containment building.

The reactor support cooling system is not required to safely shut down the reactor or mitigate the consequences of a LOCA.

UNIT 1 9.4-22 Amendment No. 27 (04/15)

Power is supplied to the fans from Class 1E motor control centers. Upon loss of offsite power, the fans are loaded on to the diesel generators and automatically restarted to provide continued cooling of the reactor supports in order to maintain the hot standby condition.

All system components are suitable for operation in 120F ambient and 1 rad/hr radiation dose rate environments.

The temperature of each reactor support is monitored by a temperature recorder and alarms at or below 150F. An engineering evaluation (PSL-ENG-SEMS-99-032) was performed to determine the minimum redundancy required for this indication, and the compensatory actions in the event that less than the minimum number of channels are available. Should there be less than the minimum number of operable channels, the minimum number of operable channels will be restored during the next refueling outage, or an alternate monitoring program will be implemented.

9.4.8.3 CEDM Cooling System The control element drive mechanism (CEDM) cooling system is designed to ventilate the CEDM magnetic Jack coils and thus maintain them at a temperature below 350F.

The CEDM cooling system consists of redundant cooling fans and a cooling coil enclosed in a mounting at floor elevation 62'-0". The CEDM P & I and flow diagrams are shown on Figures 9.4-2 and 9.4-6.

A negative pressure is maintained inside the CEDM cooling shroud by fans HVE 21A or 21B. Air enters the cooling shroud at the ambient containment air temperature, is distributed by an orifice plate to the 69 CEDM chimneys, and leaves at approximately 150F. The heated air is cooled in an air to water heat exchanger and is discharged back to the containment. Component cooling water at 100F from the nonessential header supplies the heat exchanger.

The CEDM cooling system is in service during normal plant operation. One fan is operated while the other serves as a standby.

Each fan is started manually from a control switch either locally or in the control room. Indicating lights in the control room indicate operating status. Additionally, an air flow switch in the discharge of each fan annunciates a failure to start. The control element drive mechanism cooling fan motors are tripped (if running) and blocked from starting/restarting on a safety injection actuation signal (SIAS) event due to the environmental conditions created inside the containment building.

Fans HVE-21A and B are interlocked so that on an electrical motor trip or low flow for the running fan automatically starts the standby fan.

Refer to Section 4.2.3.1.3 for an evaluation of loss of CEDM cooling air flow.

9.4.8.4 Testing and Inspection Preoperational tests are performed on the systems to ensure that they are capable of meeting performance and design basis requirements. Automatic controls are tested for proper actuation.

These systems are in service during normal plant operation and system performance is monitored continuously.

UNIT 1 9.4-23 Amendment No. 27 (04/15)

The reactor support cooling system functional capability was verified by heating the reactor support beam with infrared heaters until the temperature throughout the beam was stabilized. Cooling air was then supplied, and the test data revealed that a cooling air flow of 3200 cfm per reactor support achieves satisfactory cooling of the reactor support beam.

9.4-24

REFERENCES TO SECTION 9.4

1. R.E. Uhrig (FPL) to D. G. Eisenhut (NRC) Re: St. Lucie Unit 1, Docket 50-335, Post TMI Requirements, L-81-4 dated 1/2/81.
2. NUREG-0737, "Clarification of TMI Action Items," Item III.D.3.4, "Control Room Habitability Requirements".

9.4-25

TABLE 9.4-1 DESIGN DATA FOR CONTROL ROOM VENTILATION SYSTEM COMPONENTS

1. Air Conditioners (HVA-3A,B,C)

Quantity 3; 2 running, 1 standby Type split system, direct expansion with air cooled condensers Air flow, each, cfm 9500 Fan static pressure, in. wg 3.75 Outside intake air flow, cfm 750

2. Booster Fans (HVE-13 A,B)

Quantity 2 Type Centrifugal Material Steel Air flow, cfm 2000 Fan static pressure, in. wg. 5

3. Motors (HVE-13 A,B)

Quantity , per fan 1 Type Electric, 3 HP Insulation Class B, powerhouse Enclosure & ventilation Open, drip-proof

4. HEPA Filters (HVE-13)

No. of Cells 2 Air flow, cfm 2000 Cell size, in. 24 wide x 24 high x 111/2 deep Cell arrangement 1 wide x 2 high mounted on structural frame Max. resistance, clean, in. wg. 1.0 Efficiency, percent See Technical Specification Testing Requirements 9.4-26 Amendment No. 22 (05/07)

TABLE 9.4-1 (Cont'd)

Material Glass paper separated by aluminum inserts, supported on cadmium plated steel or SS frame Code UL-586, Class 1

5. Charcoal Adsorbers (HVE-13)

Make and type MSA 85851 (or equivalent, see Note 1)

Material Adsorber, activated coconut shell charcoal; enclosure, stainless steel type 304L ASTM gaskets, Neoprene ASTM D1056, Grade SCE-43; frame, steel ASTM-A36 Bulk density (bone dry), lb/ft3 28 to 30 Loading capacity 2.5 mg of iodine per gram of charcoal Nominal charge/cell, lb 46 Particle size distribution Mesh 8, 10, 14, finer Cell size 24 in. wide, 8 in. high, 30 in.

deep Cell arrangement 1 wide x 6 high mounted on structural cradle frame Bed thickness, in. nominal 2 Quantity per bank 6 Air flow, cfm 2000 Efficiency See Technical Specification testing requirements Max. air resistance, in. wg 1.15 Nondestructive test USAEC Report DP-1082 ANSI N510-1975 ASTM D3803-1989 Frequencies per R.G. 1.52 (R.2)

6. Ducts Material Galvanized steel Note 1: Charcoal trays have been upgraded to comply with NRC GL 99-02.

9.4-27 Amendment No. 22 (05/07)

TABLE 9.4-1A CONCENTRATIONS OUTSIDE CONTROL ROOM INTAKE (Historical)

T Time* /Q C ppm (sec) (Sec) (1/m2) (lbs/m3) 94 7.22 x 10-9 3.25 x 10-6 4.92 x 10-1 0 94.2 1.47 x 10-8 6.61 x 10-6 1.0

-7 -4 1 95 3.29 x 10 1.48 x 10 2.24 x 101 2 96 7.49 x 10-6 3.37 x 10-3 5.10 x 102 3 97 8.49 x 10-5 3.82 x 10-2 5.78 x 103 4 98 4.83 x 10-4 2.17 x 10-1 3.28 x 104 5 99 1.37 x 10-3 6.16 x 10-1 9.32 x 104 6 100 1.93 x 10-3 8.69 x 10-1 1.32 x 105 7 101 1.37 x 10-3 6.16 x 10-1 9.32 x 104 8 102 4.83 x 10-4 2.17 x 10-1 3.28 x 104 9 103 8.49 x 10-5 3.82 x 10-2 5.78 x 103 10 104 7.49 x 10-6 3.37 x 10-3 5.10 x 102

  • Time after tank rupture. T = 0, is the time at which 1 ppm is detected at the control room air intake.

Given the concentrations outside the control room the concentrations inside the room were calculated as follows:

dA lbs -1

= It( ) - A (lbs)

  • Z ( sec )

dt sec A(t) = Mass in control room (lbs) at time t.

Where: It = 450 lbs * /Q 1/m3

  • F1 m3/sec * (1-1)

Z = [L 1/sec] + [R 1/sec]

/Q Found on Table 9.4-1A F1 is the intake rate 1 is the filter efficiency L is the leak rate out of the room R is the removal rate via filtration Z assumed = 0 for this analysis 1 = 0, 0<t<2 1 = 0.999, 2<t<10 9.4-28 Amendment No. 20 (4/04)

TABLE 9.4-1B PUFF COMPONENT OF CHLORINE RELEASE INFLOW INTO CONTROL ROOM AT TIME "t" (Historical)

T (sec) t (sec) lbs/sec 0* 94.2 2.34 (-6) 1* 95.0 5.24 (-5) 2* 96.0 1.19 (-3) 3 97.0 1.35 (-5) 4 98.0 7.69 (-5) 5 99.0 2.18 (-4) 6 100.0 3.07 (-4) 7 101.0 2.18 (-4) 8 102.0 7.69 (-5) 9 103.0 1.35 (-5) 10 104.0 1.19 (-6)

  • Unfiltered flow. Equation 3 is used with a 99.9 filter efficiency for periods after two seconds (t>2 sec.)

9.4-29 Amendment No. 20 (4/04)

TABLE 9.4-1C CHLORINE CONCENTRATIONS IN CONTROL ROOM DUE TO COMBINED EFFECT OF PUFF AND CONTINUOUS SOURCE (Historical)

Phase T Puff (ppm) Continous (ppm) Total (ppm) 1 0 0.206 0 2.06(-1) 2 0.206 2.37(-1) 4.43(-1) 4 0.206 2.37(-1) 4.43(-1) 6 0.206 2.37(-1) 4.43(-1) 8 0.206 2.37(-1) 4.43(-1) 2 9 0.206 2.37(-1) 4.43(-1) 15 0.206 2.37(-1) 4.43(-1) 21 0.206 2.37(-1) 4.43(-1) 27 0.206 2.37(-1) 4.43(-1) 35 0.206 2.37(-1) 4.43(-1) 3 36 0.202 2.36(-1) 4.38(-1) 100 0.196 2.25(-1) 4.21(-1) 300 0.177 2.03(-1) 3.80(-1) 500 0.160 1.84(-1) 3.44(-1) 1,000 0.124 l.43(-1) 2.61(-1) 2,040 0.0733 8.44(-2) 1.57(-1) 4 2,041 0.0733 8.44(-2) 1.57(-1) 3,000 4.51(-2) 5.20(-2) 9.71(-2) 4,000 2.72(-2) 3.13(-2) 4.02(-2) 5,000 1.64(-2) 1.88(-2) 3.52(-2) 6,000 9.86(-3) 1.14(-2) 2.12(-2) 10,000 1.30(-3) 1.50(-3) 2.80(-3) 20,000 8.20(-6) 7.54(-6) 1.77(-5) 9.4-30 Amendment No. 20 (4/04)

TABLE 9.4-1D TOXIC CHEMICAL EVALUATION (Historical)

Distance From Peak Conc. (ppm) Time to Reach Toxicity Limit Quantity Toxic Chemical Control Room Toxicity Limit Note (ppm) Released At OAI Inside Control Rm (feet) (minutes) 55 gal; 30%

Ammonium Hydroxide 500 210 7.69 (+4) 1.32 (+2) 1 by weight Carbon Dioxide 10000 450 360 SCF 4.40 (+3) - 1, 2 55 gal; 100%

Cyclohexylamine 20 100 3.45 - 2, 3 by weight Chlorine (offsite) 15 580 38 lb 1.58 (+3) 4.86 Chlorine (onsite) 15 328 500 lb - 25 9 Notes:

1) The concentration was determined assuming that the toxic chemical becomes instantaneously airborne following the rupture of the container.
2) Not a design basis event, because the calculated concentration at the outside air intake of the control room is less than the toxicity limit.
3) The concentration was determined assuming that the toxic chemical evaporates following the rupture of the container.

9.4-30a Amendment No. 23 (11/08)

TABLE 9.4-2 CONTROL ROOM VENTILATION SYSTEM INSTRUMENTATION APPLICATION Indication Alarm Instru- Normal Control ment Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(2) Range Accuracy(2)

Control Room

1) Temperature
  • Start air conditioners at 75°F 75°F
2) Intake Air Radiation * *
  • Indicates which intake is cleaner 10-102 cpm Booster Fan
1) Inlet damper position * -
2) Outlet flow
  • 2000 cfm Indoor Unit
1) Outlet flow
  • 9500 cfm Outside Air Intake Position * -

HEPA Filter Damper Position * -

1 All alarms and recordings are in control room unless otherwise indicated.

2 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.4-31 Amendment No. 24 (06/10)

TABLE 9.4-3 DESIGN DATA FOR REACTOR AUXILIARY BUILDING VENTILATION SYSTEM COMPONENTS

1. Reactor Auxiliary Building Main Supply System (HVS -4A & B)

Number of fans installed 2 Number of fans normally operating 1 Fan capacity, each, cfm 67,515 EC284412 Fan static pressure, in. wg 3 Fan motor HP 60 No. of filters 36

2. Reactor Auxiliary Building Main Exhaust System (HVE-10A & B)

Number of fans installed 2 Number of fans normally operating 1 Fan capacity, cfm 72,390 Fan static pressure, in. wg 9.32 Fan motor HP 150 No. of prefilters 72 No. of HEPA filters 70

3. Electrical Equipment and Battery Room Ventilation Supply System (HVS-5A & B)

Number of fans installed 2 Number of fans normally operating 2 Fan capacity, each, cfm (two fans in operation) 29,300 Fan Static pressure, in. wg 3.5 Fan motor HP 30 No. of filters 30

4. Electrical Equipment Room Exhaust System Number of fans installed a) Room 1A (RV-3, RV-4) 2 b) Room 1B (HVE-12) 1 c) Room 1C (HVE-11) 1 Number of fans normally operating a) Room 1A 2 b) Room 1B 1 c) Room 1C 1 Fan capacity, cfm each a) Room 1A 8,500 b) Room 1B 19,800 c) Room 1C 19,800 9.4-32 Amendment No. 30 (05/20)

TABLE 9.4-3 (Cont'd)

Fan static pressures in. wg a) Room 1A 0.25 b) Room 1B 0.50 c) Room 1C 0.50 Fan motor, HP a) Room 1A 1.5 b) Room 1B 7.5 c) Room 1C 7.5 No. of prefilters None

5. Electrical Equipment Room 1C Air Conditioners (HVA-4, HVA-5, ACC-4, ACC-5)

Number of Air Handlers 2 Number of Air Hand, norm. oper. 2 Air Hand. Capacity, cfm, HVA-4 9.000 HVA-5 5,000 EC 295070

6. Battery Room Exhaust System (data given is identical for battery rooms 1A and 1B (RV-2 & -1)

Number of fans installed in each room 1 Number of fans normally operating in each room 1 Fan capacity, cfm 1,000 Fan static pressure, in. wg 0.25 Fan motor, HP 0.25 No. of prefilters None

7. Locker Area and Machine Shop Ventilation Supply System (HVS-3) (abandoned in place)

Number of fans installed 1 Number of fans normally operating 1 Fan capacity, cfm 11,325 External static pressure, in. wg 1.25 Fan motor, HP 7.5 Filters Yes

8. Locker Area Exhaust System (HVE-4) (abandoned in place)

Number of fans installed 1 Number of fans normally operating 1 Fan capacity, cfm 1,850 Fan static pressure, in. wg 0.5 Fan motor, HP 0.5 No. of filters None

9. Machine Shop Area Exhaust system (HVE-5) (abandoned in place)

Number of fans installed 1 Number of fans normally operating 1 Fan capacity, cfm 7,000 Fan static pressure, in. wg 4.5 Fan motor, HP 10 No. of prefilters 6 No. of HEPA filters 6 9.4-33 Amendment No. 31 (11/21)

TABLE 9.4-3 (Cont'd)

EC293372 DELETED EC291231 9.4-34 Amendment No. 31 (11/21)

TABLE 9.4-4 REACTOR AUXILIARY BUILDING VENTILATION SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(2) Range Accuracy(2)

Main Supply System (HVS-4A & -4B)

1) Inlet temperature
  • 32-93F
2) Outlet temperature
  • 35-96F
3) Fan outlet flow *
  • Low flow alarm in 66,615 cfm control room
4) HPSI & CS Pump Room A & B (HVS-4A & -4B) a) Temperature *
  • 43-104F (Normal) 120F (Accident) b) Differential Pressure
  • Low differential pressure -0.25 wg alarm in control room to -1.0 wg ECCS Exhaust Fans (HVE-9A & -9B)
1) HEPA filter differential *
  • High differential pressure 1.15"wg pressure alarm
2) Charcoal Adsorber P *
  • 1.15"wg
3) Outlet flow
  • Low flow alarm in control 30,000 cfm room
4) Exhaust flow rate
  • Indication to App. I & SA -

computer Main Exhaust System (HVE-10A & -10B)

1) HEPA filter differential *
  • Alarm in control room 1 to 3"wg pressure 0.7" wg
2) Prefilter P
  • Low flow alarm in control 72,390 cfm
3) Exhaust flow room 9.4-35 Amendment No. 26 (11/13)

TABLE 9.4-4 (Cont'd)

Indication Alarm(1) Normal Control Instrument Operating Instrument System Parameter & Location Local Room High Low Recording(1) Control Function Range(2) Range Accuracy(2)

Electrical Equipment & Battery Room Vent System (HVS-5A

& -5B)

1) Supply system air intake
  • 32-93F temperature
2) Prefilter P * -0.3 to

-1.0"wg

3) Electrical equipment
  • High temperature alarm 55-110F temperature in control room Locker Area & Machine Shop Ventilation System (HVE-4, -5 & HVS-3) (abandoned in place)
1) Room temperature Control power to electric 45F to 105F
2) Inlet temperature coils
3) Outlet temperature
  • EC293372 EC291231 1 All alarms and recordings are in the control room unless otherwise indicated.

2 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.4-36 Amendment No. 31 (11/21)

TABLE 9.4-5 AUXILIARY BUILDING COMPONENTS WITH SIAS, INTERLOCKS OR MANUAL CONTROLS Manual Control SIAS Control SIAS Control Component Local Room Yes No Interlock Function

1. Main supply fans (HVS-4A,4B) * *
  • Start
2. Supply air dampers to engineered
  • HVE-9A,9B Open safety features pump room (D-1,D-2,D-3,D-4)
3. Supply air dampers to
  • HVE-9A,9B Close pipe tunnel (D-8A,8B)
4. Supply air(1) dampers to selected
  • HVE-9A,9B Close areas (D-7A,7B,D-11A,11B)
5. Exhaust air dampers for engineered
  • HVE-9A,9B Close safety features pump room (D-9A,9B)
6. Main exhaust air dampers
  • HVE-9A,9B Close for pipe tunnel (D-12A,12B)
7. Main exhaust dampers for shutdown heat
  • HVE-9A,9B Close exchangers (D-5A,5B, D-6A,6B)
8. Main exhaust a) fans *
  • None Stop (HVE-10A,10B) b) inlet *
  • None None dampers (1) Selected areas: specific branch ducts to corridor as shown on Fig.

9.4-1 9.4-37 Amendment No. 25 (04/12)

TABLE 9.4-5 (Cont'd)

Manual Control SIAS SIAS Control Control Component Local Room Yes No Interlock Function

9. ECCS area exhaust a) fans (HVA-9A,9B) *
  • None Start(1) b) filter train inlet dampers (D-13,D-15) *
  • HVE-9A, 9B Open c) fan inlet dampers (D-14,D-16) *
  • HVE-9A, 9B Open d) fan outlet dampers (L-7A,7B) *
  • HVE-9A, 9B Open Electrical and battery room ventilation systems
1. Supply fans (HVS-5A,5B) *
  • None None
2. Room 1A exhaust fans (RV-3,4) *
  • None None
3. Room 1B, fan (HVE-12) and damper (L-10) *
  • None None
4. Room 1C fan (HVE-11) and damper (L-9) *
  • None None
5. Battery room exhaust fans (RV-1, RV-2) *
  • None None Locker areas and machine shop ventilation system (abandoned in place)
1. Supply fan (HVS-3) *
  • HVE-4 None
2. Locker room exhaust fan (HVE-4) and damper (L-5) *
  • HVS-3 None
3. Machine shop exhaust fan (HVE-5) and damper (L-6) *
  • HVS-3 None Radio chem lab. count room and instrument room.a/c system (abandoned in place)
1. A/C fan (HVS-3) *
  • None None (1) The starting of ECCS area exhaust fans HVE-9A & 9B is delayed seventeen (17) seconds EC 205055 following a SIAS actuation.

9.4-38 Amendment No. 30 (05/20)

TABLE 9.4-6 DESIGN DATA FOR ECCS AREA VENTILATION EQUIPMENT SYSTEM COMPONENTS

1. Fans Quantity 2 Capacity, cfm 30,000 Static pressure, in. wg 7.0 (HVE-9A), 5.5 (HVE-9B)

Actual air flow at inlet, cfm 30,000 Air density, lb/ft3 0.075 Code Class III Type, both systems Centrifugal, variable pitch belt, air foil, non-overloading Variable inlet vane

2. Motors Quantity 2 Type Horizontal; 50 HP (HVE-9A),

40 HP (HVE-9B); 460 volt 3 phase, 60 cycle Insulation Class B powerhouse Enclosure & ventilation Open, drip-proof

3. HEPA Filters Quantity, per bank 30 Air flow, cfm 30,000 Cell size, in. 24 x 24 x 111/2 Cell arrangement 5 wide x 6 high Max resistance, clean, in. wg 1.0 Max resistance, loaded, in. wg 3.0 Efficiency 99.97% with 0.3 micron DOP smoke Material Glass asbestos paper separated by aluminum inserts, supported on cadmium plated steel or SS frame Code UL-586, Class 1
4. Charcoal Adsorbers Quantity per bank 90 Air flow, cfm 30,000 Cell size, in 24 x 8 x 30 Cell arrangement 6 wide x 15 high Max air resistance, in. wg 1.15 Efficiency 99.9% min of iodines with 5% in the form of methyl iodine, when operating at 70 percent relative humidity and 150 F 9.4-39 Amendment No. 21 (12/05)

TABLE 9.4-6 (Cont'd)

Loading capacity, gm 6000 gm stable iodine and 360 gm of radioactive iodine including 300 gm of methyl iodine Maximum residence time, sec 0.25 Material adsorber activated coconut shell charcoal Enclosure stainless steel type 304L ASTM Gaskets Neoprene ASTM D1056, Grade SCE -43 Frame Steel ASTM-A36

5. Ducts Material galvanized sheet metal, ASTM Specification, A-525 Class E 9.4-40

TABLE 9.4-7 DESIGN DATA FOR TURBINE BUILDING, FUEL POOL, AND DIESEL GENERATOR BUILDING HEATING AND VENTILATION SYSTEM COMPONENTS

1. Turbine Building Air Exhaust System Switchgear Room Number of fans installed (HVS-18 & 19) 2 Number of fans normally operating 2 Fan capacity, cfm, each 15,000 Fan static pressure, in. wg 2.75 Fan motor HP 15 No. of filters 2 Chemical Storage Number of fans installed (HVE-20) 1 Number of fans normally operating 1 Fan capacity,cfm, each 750 Fan static pressure, in. wg 0.25 Fan motor HP 0.25 Filters yes
2. Diesel Generator Building Air Exhaust Systems (data given is identical for both rooms)

Number of fans installed (RV-5 & 6) 2 Number of fans normally operating 1 Fan capacity, cfm 5000 Fan static pressure, in. wg 0.06 Fan motor HP 1.0 No. of filters none 9.4-41 Am. 3-7/85

TABLE 9.4-7 (Cont'd)

3. Heating and Ventilation Room Air Exhaust System Number of fans installed (HVE-17) 1 Number of fans normally operating 1 Fan capacity, cfm 5000 Fan static pressure, in. wg 1.5 Fan motor HP 3 No. of filters none
4. Fuel Pool Air Supply System Fuel Pool Area Lower Area (HVS-6) (HVS-7)

Number of fans sections installed 1 1 (HVS-6 & 7)

Number of fans normally running 1 1 Fan capacity, cfm 9800 8600 External static pressure, in. wg 1 0.75 Fan motor HP 5 5 No. of filters 9 9

5. Fuel Pool Air Exhaust System HVE-16A & B HVE-15 Number of fans installed (HVE-16A & B, 2 1 HVE-15)

Number of fans normally running 1 1 Fan capacity, cfm 10,350 8,450 Fan static pressure, in. wg 7.25 8.00 Fan motor HP 20 10 No. of prefilters 9 9 No. of HEPA filters 9 9 No. of charcoal adsorber cells 30 -

9.4-42 Amendment No. 18, (04/01)

TABLE 9.4-8 DESIGN DATA FOR REACTOR SUPPORT COOLING SYSTEM AND REACTOR CAVITY COOLING SYSTEM

1. Reactor Support Cooling System Number of fans installed (HVE-3A & 3B) 2, one standby Number of fans normally operating 1 Fan capacity, cfm, each 11,400 Fan static pressure, in. wg 10.75 Fan motor HP 40
2. Reactor Cavity Cooling System Number of fans installed (HVS-2A & 2B) 2, one standby Number of fans normally operating 1 Fan capacity, cfm, each 20,000 Fan static pressure, in. wg 3.3 Fan motor HP 20
3. CEDM Cooling System Number of fans installed (HVE-21A & 21B) 2 Number of fans normally operating 1 Fan capacity, cfm, each 55,200 Fan static pressure, in. wg 10.5 Fan motor HP 125 Entering water temperature, F 100 Water quantity, flow rate, gpm 196 9.4-43

Refer to drawing 8770-G-862 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 HVAC-AIR FLOW DIAGRAM FIGURE 9.4-1 Amendment No. 15 (1/97)

Refer to drawing 8770-G-862 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 HVAC-AIR FLOW DIAGRAM FIGURE 9.4-1a Amendment No. 15 (1/97)

Refer to drawing 8770-G-878 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1

  • HVAC-CONTROL DIAGRAMS-SHEET 1 FIGURE 9.4-2 Amendment No. 15 (1/97)

Refer to drawing 8770-G-879 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 HVC-CONTROL DIAGRAMS-SHEET 2 FIGURE 9.4-2a Amendment No. 15 (1/97)

Refer to drawing 8770-G-879 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1

  • HVAC-CONTROL DIAGRAMS-SHEET 2 FIGURE 9.4-3 Amendment No. 15 (1/97)

DELETED FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.4-4 Amendment No. 23 (11/08)

..,,ID;~ ~

r.-.~

~~  ;-rr- r-IPl.V-~'*

(f}

tp D*tf. IFi1- ~!.s _m _J.!.~~rs ~c,..esl~<

( l~ ~. I I or.. ,.. I (i:T I I HVF*I3A. [ To

<'DN'."'"

A...,..

. ( T~ r.r

~!!:-+:::_, __Cfl~---

/::;"\ I _rn 1)-l'f I - 1 I II VE *138 *~=1 I I I I I I

r-- - - .J r - - - - ---1

' t I f!,,,.rJ'..,. '

r ' I.,...

I NolfTH SOUTH I FlfN'S r*tlf:f*.J!J-H~

. . >7 .,...,

~

1t --

I I

~

f

~-,

I "FRtJr"' I I I I

  • I .... roo 0 I ____ . I I I 1 ,,.,., ,_ - - - - - - I I I

@CI>DS / / 1

  • l;' .,..... I - - -- -- - - .._,, - - - - - - - - -- J I I I I I

-~---

I

. 8 ------ - - - - -....J ,

1. I L------

I -*------- ;I .

0 1 11 ------ ------- ---

L'-------

II

,1 I 11 t

_.J I L---,  ;

I

- -I- -

L ----

L- - --...J FLORIDA POWER & LIGfT a:Mf>NfT ST. LUOE PLAMT UNIT 1 CONTROL ROOM YEHTILATIOH snTEM-Q-ILORIHE ACC10HT DETECTION SIGNAL (CADS) DIAGRAM FIGURE 9. 4-4A

DELETED FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FIGURE 9.4-5 Amendment No. 23 (11/08)

  • REt.CTO!(

COOU!~G (Ot~E FA!~ STA~WBY)

SUPPc:*~T SYSTE, 1

/,

EL. 36'

u. OTHER SUPPORT
10 Ll..\g ...J STRUCTUf~i
S EL. 13' vt- -~1 i <

~~~~ G  ::>-

OJ~

C"' c. 0 C'~ 1.~ -1

!.tl 1  ::i.:

V1 R v Qt; E E

-* c ss REACTOR ..:;,:

_, A CAViTY 0::

sur;,p PUIAP a.. T E

SHAFT 0 L

t...,_ R

!FLORIDA POV!ER [!. LIG~IT~;~~"~*

  • l L- . ~~~:..:~CC!_E_~~~~~.~:~~::=~-1~.--~-~-*-*,

I

. l"'.P.

I AIR FLC*\! D! *\GIVo_ir, FCf< F-T;\:::-TOR

'\'l'fY

. 1 (I r , ..) 1' 1*,,

,,. J='*'C' T 'L rcc*

L > It,![)~

!X~IYC t,\t:::C~!\r11SM C~.OLilJ,G SYS i L:h~S

~-*--.-~--~---~--~-~~~-.:.----~*~~.~~-=---~~~~-***--~.-*-~---.!

  • ., , '! ~t-'C*L ll"';iJ ' f . [)('J i).

\.

\

l

9.5 OTHER AUXILIARY SYSTEMS 9.5.1 FIRE PROTECTION PROGRAM The fire protection program is based on the NRC requirements and guidelines, Nuclear Electric Insurance Limited (NEIL) Property Loss Prevention Standards and related industry standards.

With regard to NRC criteria, the fire protection program meets the requirements of 10 CFR 50.48(c), which endorses, with exceptions, the National Fire Protection Associations (NFPA) 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants - 2001 Edition. St. Lucie Nuclear Plant Unit 1 has further used the guidance of NEI 04-02, Guidance for Implementing a Risk-Informed, Performance-Based Fire Protection Program under 10 CFR 50.48(c) as endorsed by Regulatory Guide 1.205, Risk-Informed, Performance Fire Protection for Existing Light-Water Nuclear Power Plants.

Adoption of NFPA 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition in accordance with 10 CFR 50.48(c) serves as the method of satisfying 10 CFR 50.48(a) and General Design Criterion 3. Prior to adoption of NFPA 805, General Design Criterion 3, "Fire Protection" of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50, "Licensing of Production and Utilization Facilities," was followed in the design of safety and non-safety related structures, systems, and components, as required by 10 CFR 50.48(a).

NFPA 805 does not supersede the requirements of GDC 3, 10 CFR 50.48(a), or 10 CFR 50.48(f).

Those regulatory requirements continue to apply. However, under NFPA 805, the means by which GDC 3 or 10 CFR 50.48(a) requirements are met may be different than under 10 CFR 50.48(b). Specifically, whereas GDC 3 refers to SSCs important to safety, NFPA 805 identifies fire protection systems and features required to meet the Chapter 1 performance criteria through the methodology in Chapter 4 of NFPA 805. Also, under NFPA 805, the 10 CFR 50.48(a)(2)(iii) requirement to limit fire damage to SSCs important to safety so that the capability to safely shut down the plant is satisfied by meeting the performance criteria in Section 1.5.1 of NFPA 805.

A Safety Evaluation was issued on March 31, 2016 by the NRC, that transitioned the existing fire protection program to a risk-informed, performance-based program based on NFPA 805, in accordance with 10 CFR 50.48(c).

9.5.1.1 DESIGN BASIS

SUMMARY

9.5.1.1.1 Defense-In-Depth The fire protection program is focused on protecting the safety of the public, the environment, and plant personnel from a plant fire, and its potential effect on safe reactor operations. The fire protection program is based on the concept of defense-in-depth. Defense-in-depth shall be achieved when an adequate balance of each of the following elements is provided:

(1) Preventing fires from starting, (2) Rapidly detecting fires and controlling and extinguishing promptly those fires that do occur, thereby limiting fire damage, (3) Providing an adequate level of fire protection for structures, systems, and components important to safety, so that a fire that is not promptly extinguished will not prevent essential plant safety functions from being performed.

UNIT 1 9.5-1 Amendment No. 28 (05/17)

9.5.1.1.2 NFPA 805 Performance Criteria The design basis for the fire protection program is based on the following nuclear safety and radiological release performance criteria contained in Section 1.5 of NFPA 805:

  • Nuclear Safety Performance Criteria. Fire protection features shall be capable of providing reasonable assurance that, in the event of a fire, the plant is not placed in an unrecoverable condition. To demonstrate this, the following performance criteria shall be met.

(a) Reactivity Control. Reactivity control shall be capable of inserting negative reactivity to achieve and maintain subcritical conditions. Negative reactivity inserting shall occur rapidly enough such that fuel design limits are not exceeded.

(b) Inventory and Pressure Control. With fuel in the reactor vessel, head on and tensioned, inventory and pressure control shall be capable of controlling coolant level such that subcooling is maintained such that fuel clad damage as a result of a fire is prevented for a PWR.

(c) Decay Heat Removal. Decay heat removal shall be capable of removing sufficient heat from the reactor core or spent fuel such that fuel is maintained in a safe and stable condition.

(d) Vital Auxiliaries. Vital auxiliaries shall be capable of providing the necessary auxiliary support equipment and systems to assure that the systems required under (a), (b), (c), and (e) are capable of performing their required nuclear safety function.

(e) Process Monitoring. Process monitoring shall be capable of providing the necessary indication to assure the criteria addressed in (a) through (d) have been achieved and are being maintained.

  • Radioactive Release Performance Criteria. Radiation release to any unrestricted area due to the direct effects of fire suppression activities (but not involving fuel damage) shall be as low as reasonably achievable and shall not exceed applicable 10 CFR, Part 20, Limits.

Chapter 2 of NFPA 805 establishes the process for demonstrating compliance with NFPA 805.

Chapter 3 of NFPA 805 contains the fundamental elements of the fire protection program and specifies the minimum design requirements for fire protection systems and features.

Chapter 4 of NFPA 805 establishes the methodology to determine the fire protection systems and features required to achieve the nuclear safety performance criteria outlined above. The methodology shall be permitted to be either deterministic or performance-based. Deterministic requirements shall be deemed to satisfy the performance criteria, defense-in-depth, and safety margin and require no further engineering analysis. Once a determination has been made that a fire protection system or feature is required to achieve the nuclear safety performance criteria of Section 1.5, its design and qualification shall meet the applicable requirement of Chapter 3.

9.5.1.1.3 Codes of Record The codes, standards and guidelines used for the design and installation of plant fire protection systems are listed in the DBD-FP-1, Fire Protection Design Basis Document.

UNIT 1 9.5-1a Amendment No. 28 (05/17)

9.5.1.2 SYSTEM DESCRIPTION 9.5.1.2.1 Required Systems Nuclear Safety Capability Systems, Equipment, and Cables Section 2.4.2 of NFPA 805 defines the methodology for performing the nuclear safety capability assessment. The systems, equipment, and cables required for the nuclear safety capability assessment are contained in PSL-ENG-SEMS-98-035, St. Lucie Unit 1 Nuclear Safety Capability Assessment Basis Document; 8770-B-048, Unit 1 Nuclear Safety Capability Assessment (NSCA); 8770-B-049, Unit 1 Essential Equipment List, and St. Lucie Plants Units 1

& 2 EDISON Cable and Raceway Database.

Fire Protection Systems and Features Chapter 3 of NFPA 805 contains the fundamental elements of the fire protection program and specifies the minimum design requirements for fire protection systems and features. Compliance with Chapter 3 is documented in DBD-FP-1, Fire Protection Design Basis Document.

Chapter 4 of NFPA 805 establishes the methodology and criteria to determine the fire protection systems and features required to achieve the nuclear safety performance criteria of Section 1.5 of NFPA 805. These fire protection systems and features shall meet the applicable requirements of NFPA 805 Chapter 3. These fire protection systems and features are documented in DBD-FP-1, Fire Protection Design Basis Document.

Radioactive Release Structures, systems, and components relied upon to meet the radioactive release criteria are documented in DBD-FP-1, Fire Protection Design Basis Document.

9.5.1.2.2 Definition of Power Block Structures Where used in NFPA 805 Chapter 3 the terms Power Block and Plant refer to structures that have equipment required for nuclear plant operations. For the purposes of establishing the structures included in the fire protection program in accordance with 10 CFR 50.48(c) and NFPA 805, the plant structures listed in DBD-FP-1, Fire Protection Design Basis Document are considered to be part of the powerblock.

9.5.1.3 SAFETY EVALUATION The DBD-FP-1, Fire Protection Design Basis Document, documents the achievement of the nuclear safety and radioactive release performance criteria of NFPA 805 as required by 10 CFR 50.48(c). This document fulfills the requirements of Section 2.7.1.2 Fire Protection Program Design Basis Document of NFPA 805. The document contains the following:

  • Identification of significant fire hazards in the fire area. This is based on NFPA 805 approach to analyze the plant from an ignition source and fuel package perspective.
  • Summary of the Nuclear Safety Capability Assessment (at power and non-power) compliance strategies.

- Deterministic compliance strategies

- Performance-based compliance strategies (including defense-in-depth and safety margin)

  • Summary of the Non-Power Operations Modes compliance strategies.
  • Summary of the Radioactive Release compliance strategies.
  • Key analysis assumptions to be included in the NFPA 805 monitoring program.

UNIT 1 9.5-1b Amendment No. 28 (05/17)

9.5.1.4 FIRE PROTECTION PROGRAM DOCUMENTATION, CONFIGURATION CONTROL AND QUALITY ASSURANCE In accordance with Chapter 3 of NFPA 805 a fire protection plan documented in 1800022, Fire Protection Plan, defines the management policy and program direction and defines the responsibilities of those individuals responsible for the plans implementation. 1800022:

  • Designates the senior management position with immediate authority and responsibility for the fire protection program.
  • Designates a position responsible for the daily administration and coordination of the fire protection program and its implementation.
  • Defines the fire protection interfaces with other organizations and assigns responsibilities for the coordination of activities.
  • Identifies the procedures established for the implementation of the fire protection program, including the post-transition change process and the fire protection monitoring program.
  • Identifies the quality requirements of Chapter 2 of NFPA 805.

Detailed compliance with the programmatic requirements of Chapters 2 and 3 of NFPA 805 are contained in DBD-FP-1, Fire Protection Design Basis Document.

UNIT 1 9.5-1c Amendment No. 28 (05/17)

9.5.2 COMMUNICATIONS SYSTEMS 9.5.2.1 Design Bases The communications systems are designed to assure reliable and diverse intraplant communications and outside telephone service for normal operation and emergency conditions.

9.5.2.2 System Description 9.5.2.2.1 Intraplant Communications Intraplant communications facilities are as follows:

a) A low level intraplant paging and communication (PA) system with six communications channels, one page and five parties.

The PA system is composed of handset stations, speakers (horn and cone type), speaker amplifiers, and associated cabling and hardware all mounted in suitable enclosures and located throughout the plant to provide full plant coverage.

b) A sound powered communications system has stations located in vital areas to provide reliable voice communication between the Control Room, Technical Support Center, Reactor Auxiliary Building, Diesel Generator Building, Turbine Building, Intake Structure and Component Cooling Areas. This system can also be utilized for hot shutdown communications in the unlikely event of control room evacuation coincident with a complete loss of normal communication.

The sound powered communications system consists of headsets, remote jack stations, and associated cabling and hardware.

The sound powered communication system requires no external power. The power necessary for communication is derived from the spoken voice.

EC292504 c) An interoffice communications system with a Internet Protocol Telephony (IPT) system.

EC292504 The IPT system consists of a Main Module located in St. Lucie South Service Building, a remote module located in St. Lucie North Service Building, and supporting equipment together with associated cabling/wiring, telephone sets, and switching devices all mounted in enclosures located throughout the plant and offices.

d) Site evacuation, containment evacuation, E-plan activation and fire signals are incorporated into the PA system. Each alarm is a distinct signal generated from a tone generator, initiated by operator action. High containment radiation initiates a containment evacuation signal; in addition two emergency pushbuttons in the containment can also initiate this signal. The signals are applied to horns located throughout the station. To ensure that site alarms and announcements are available in all plant areas, a "vital alarm relay" is provided, which advances speaker volume to the maximum available level during vital alarms. In addition, a manual volume override is provided for control room announcement of emergency conditions and testing.

e) A diverse two-way radio system is provided for normal and emergency onsite and near-site communications. The radio trunking system operates on the 900 MHz frequency band, and is the main source for onsite two-way radio communications. The repeaters are in a separate structure west of the plant, with an emergency generator and air conditioning. The antennas are mounted on an adjacent tower. In addition, Unit 1 and Unit 2 each have a 900 MHz transceiver that can provide "talk-around" capability onsite using hand held radios if the trunking system fails.

9.5-2 Amendment No. 31 (11/21)

9.5.2.2.2 External Communications Bell Telephone System installation including two lines for telemetering, load control and supervisory control, are provided for external communications via phones located in the control room, various offices, labs, switchyard control house, security and records building and service building.

In the event of complete loss of all plant telephone service, a telephone line is provided for voice communication between the plant control and the System Load Dispatch Office. This is in addition to the normal plant telephone service.

As a back-up to the telephone lines, the cellular telephone system can provide emergency communications between required local, state and federal (NRC, FEMA) governmental agencies, as well as various offsite FPL departments and locations. A fixed cellular telephone transceiver with parallel- connected phonesets in the control room is installed on RAB elevation 43 feet. The antenna is installed on the RAB roof. This system provides a telephone link which is independent of the offsite commercial telephone wire system.

Located in the Control Room is a phone dedicated to notifying the NRC of all situations in which SL-1 is in an uncontrolled or unexpected condition of operation (Emergency Notification System).

9.5.2.3 System Evaluation Communication facilities of the types described are conventional and have a history of reliable operation at Florida Power & Light Company Plants.

The availability of the PA system is assured by powering the system from 120 Vac vital bus #1 which has three alternate supplies (see 8770-G-332, Sheet 1):

a) inverter, fed from an emergency MCC b) voltage regulating transformer, fed from emergency MCC c) dc power from station battery 9.5-3 Amendment No. 19 (10/02)

The two-way radio and cellular telephone transceivers are also powered from the 120 V ac Vital Bus

  1. 1. The associated radio equipment (desktop controllers) in the TSC is powered from 120 V ac Vital Bus 1D. The associated radio equipment (desktop controllers) in the control room is powered from 120 V ac Normal/Emergency (N/E) Lighting Panel LP-126, which is backed by Emergency Diesel Generator 1B.

The LGR radio antenna system is designed for 194 mph hurricane winds and is intended to remain operational during a design basis hurricane.

EC292504 The availability of the IPT system is assured by powering this system from:

EC292504 a) Remote module - 480V Power Panel PP-135 located in the Security and Records Building which has Emergency Diesel Back-up Power EC292504 b) Main Module - This module is supplied from PP-153 Ckt #4 located in South Service Building which has Diesel Generator Back-up.

The availability of the Emergency Notification System (ENS) is assured by powering the onsite EC292504 telephone company package (IPT) from a diverse Class 1E power source.

The availability of the sound powered system is assured by having no operating power requirement.

In the event of a loss of the normal offsite power sources, the communications system will remain operable based on the power sources indicated above. The diverse means of communications available ensure that no single active failure will prevent operation of the communication system. The PA, IPT and sound powered communication system interconnecting cable is segregated to prevent EC292504 common mode failure.

9.5.2.4 Testing and Inspection Most of the communication systems are in routine use and this provides a check of the continued availability. Those systems not frequently used will be tested at periodic intervals to assure operability when required.

9.5.3 LIGHTING SYSTEMS There are three lighting systems, the normal ac system, the normal/emergency (N/E) ac system, and the emergency dc system. The normal ac lighting system is designed to provide indoor and outdoor illumination levels in accordance with recommended levels published in the Illuminating Engineering Society Handbook (4th Edition). All indoor lighting is either fluorescent, incandescent, light emitting diode (LED) or high intensity discharge (HID) luminaries. Incandescent lighting is used exclusively in the containment and fuel pool area except in underwater applications in the fuel pool and refueling cavity in which quartz lighting is used. The housing for the fixtures inside the containment will not contain aluminum.

UNIT 1 9.5-4 Amendment No. 31 (11/26)

The outdoor lighting is provided by LED, HID or incandescent sources controlled by a photoelectric cell. A control room selector switch allows manual or photoelectric operation of the lighting. Specific outdoor lighting (e.g. doorway lighting) is locally switched.

The N/E ac lighting consists of two (A and B) physically and electrically separate systems. Either of these two systems will provide the necessary indoor and outdoor lighting to allow orderly maintenance and continuance of plant operation at all times. Section 8.3.1 gives a detailed description of the on-site power system.

Upon failure of off-site power, the N/E lighting circuits are powered by the diesel generator sets through the emergency portion of the auxiliary busses. The building egress areas are part of the N/E lighting system. In the case where neither the A or B N/E lighting system is operating (as during the time between loss of off-site power and the starting of the diesel generator sets) there are independent battery pack emergency light units which supply an additional backup lighting source.

These battery pack emergency lights provide additional lighting with complete loss of AC power.

The control room is supplied with redundant emergency dc lighting in addition to normal and N/E lighting. There are two physically and electrically separate A and B systems energized from separate station batteries through separate conduits, fixtures and panels. Section 8.3.2 discusses the dc power system in detail. The lighting system is automatically energized by fail closed relays located within the control room.

Lighting supports inside the control room have been designed as seismic Class I.

9.5.4 DIESEL GENERATOR FUEL OIL SYSTEM 9.5.4.1 Design Bases The diesel generator fuel oil system is designed to:

a) provide oil storage capacity for at least seven days accident load operation of one emergency diesel generator set.

b) maintain fuel supply to at least one diesel generator set, assuming a single active or passive failure.

UNIT 1 9.5-5 Amendment No. 27 (04/15)

c) withstand design basis earthquake loads without loss of function d) withstand maximum flood levels and tornado wind loading without loss of function A contract is maintained with a fuel oil supply and/or shipping company for normal supply of diesel fuel oil.

This source would be used under storm condition if available. In the event that the local firms were also affected by the storm other means and sources of fuel oil would be arranged for in accordance with plant procedures and the site emergency plan.

In the unlikely event there were no bridges open which would permit trucking of fuel to the Plant, a barge would be chartered to transport fuel oil from the Canaveral Terminal or the Port of Miami to the St. Lucie site in approximately one (1) day. Any of these facilities has on hand adequate diesel oil for the supply of the emergency diesel generators as a matter of routine. Barges are equipped with on-board pumps and hoses to off-load the fuel at the plant site.

9.5-6 Amendment No. 20 (4/04)

9.5.4.2 System Description The diesel fuel oil system is shown in Figures 9.5-1, 9.5-2 and 9.5-3. Design data is found in Table 9.5-1.

The diesel generator fuel oil system is used to transfer diesel fuel oil from the on-site storage tanks to the day tanks which supply the emergency diesel generator sets.

Two completely redundant subsystems are provided, each consisting of a diesel oil storage tank (DOST), transfer pump, day tank, interconnecting piping and valves and associated instrumentation and controls. Subsystem A serves diesel generator 1A and subsystem B serves diesel generator 1B.

All electrical power necessary for operation of each subsystem is supplied from the associated diesel generator bus.

The main components of the system are the following:

a) Day tanks - two tanks in each redundant system are interconnected to provide a total usable capacity of approximately 240 gallons of fuel to each diesel generator set at the diesel oil transfer pump stop setting.

b) Diesel oil storage tank - Two tanks (maximum usable capacity of 19120 gallons per tank between the suction elbow and non-seismic fill line) are provided. Each tank feeds its respective diesel generator. Two diesel oil storage tanks and two day tanks (per engine set) are provided with a combined usable volume which is sufficient for at least 7 days accident load operation of one diesel generator set. Two cross-connects, each having locked closed double valves, exist between the discharges of the tanks. The cross tie system is seismic Class I throughout.

c) Fuel oil transfer pump - One 25 gpm pump in each system to transfer oil from the storage to the day tanks.

d) Interconnecting piping and valves - Cross connection lines with locked closed valves are provided for transferring oil between the redundant systems. The cross connection lines are provided at both the pump suction and discharge.

The diesel fuel oil tanks are located on an outdoor platform. The pumps are located in a seismically designed enclosure capable of withstanding tornado missile impact. The day tanks and associated instrumentation are located inside the diesel generator building. The diesel oil transfer pumps are located above the maximum flood level to ensure their operation during floods.

A 2 inch line with locked closed valves at each Unit has been incorporated in the design to provide cross connection capability between Units 1 and 2.

Fuel oil is supplied by the fuel oil transfer system through a common solenoid valve to day tanks at each engine. Fuel may be added to the tanks by gravity feed when there is sufficient head in the DOST. A fuel transfer pump is provided for forced feed when the DOST level is insufficient for gravity feed.

9.5-7 Amendment No. 25 (04/12)

9.5.4.3 System Evaluation The design of the diesel generator fuel oil systems provides electrical and physical separation of components to assure that the system can withstand a single failure. The pumps, tanks and other equipment in the system are designed for seismic Class I service. The equipment is designed to withstand the normal outdoor conditions of heat, humidity, and salt spray prevalent at the site.

Redundant components of the diesel generator fuel oil system are designed for, inherently resistant to, or protected from, both high velocity winds and tornado driven missiles. The diesel oil transfer pumps, valves, piping, and restraints are designed to withstand design basis tornado winds of 360 mph coincident with the atmospheric pressure drop of 3 psi in 3 seconds. Tornado missile protection is discussed in Appendix 3F. Appendix 3F discusses the adequate inherent tornadic debris resistance of the diesel oil storage tanks. The two diesel oil storage tanks are separated by 20'-0". EC294222 The transfer pumps are 69'-0" distant from each other. The discharge lines from the pumps exit the Diesel Oil Transfer Pump Rooms through the walls below grade at the 1A DO Transfer Pump Room and above grade at the 1B DO Transfer Pump Room, then run underground to the Diesel Generator Building where they rise above grade and enter the Diesel Generator Building. Both the above ground and underground portions of the lines are protected from design basis tornado missiles in accordance with the requirements of UFSAR Section 3.5 The two lines (e.g., both trains) are more than 10 0 apart at the closest underground point.

EC294222 The piping and intertie connecting the Unit 2 EDG fuel transfer system to the cross-connection piping between the Unit 1 EDG fuel transfer pumps feature tornado missile protection. However, the cross-connection piping between the Unit 1 fuel transfer pumps is not missile protected. The design is acceptable since, as described in Appendix 3F regarding exposed equipment required for safe shutdown, the probability of a design-basis tornado missile rendering redundant EDG fuel transfer system components non-functional is acceptably low. Appendix 3F further describes that the components and piping are essentially invulnerable to the spectrum of small, wind-generated objects characterized as tornado debris. In the event a tornado missile disables a Unit 1 fuel transfer train, fuel to the affected EDG is provided by aligning the redundant fuel transfer train and cross-connection piping between the Unit 1 fuel transfer pumps or by means of the intertie to the Unit 2 fuel transfer system. In the event a tornado missile disables the cross-connection piping between the Unit 1 fuel transfer pumps, normal EDG fuel transfer is not disrupted. In either scenario, concurrent losses due to tornado-generated debris need not be considered given the robustness of the EDG fuel transfer system components and piping.

The diesel generator fuel oil systems for Units 1 and 2 are independently capable of supplying their respective diesel generator sets. The normally closed cross connection between the A and B storage tanks does not compromise the functional capability of the system.

Similar to the issues discussed in NRC Generic Letter 2008-01 and INPO SER 2-05, the presence of unanticipated gas voids within the Diesel Generator Fuel Oil and Transfer System can challenge the ability of the system to perform its design functions due to issues such as gas binding, water hammer, injection delay times, etc. EDG subsystems present little to no opportunity for gas intrusion or air entrainment. The fill, vent, and surveillance operations procedures for the EDG subsystems assure acceptable system performance following maintenance or operational activities that could result in gas void formation. These procedures ensure that the subsystem is left in an operable condition on a monthly basis.

9.5.4.4 Testing and Inspection The components are inspected and cleaned prior to installation into the system. Instruments are calibrated during testing and automatic controls are tested for actuation at the proper set points.

Alarm functions are checked for operability and limits during plant preoperational testing. Actuation of system components is tested periodically in accordance with the Technical Specifications.

UNIT 1 9.5-8 Amendment No. 31 (11/21)

9.5.5 DIESEL GENERATOR COOLING WATER SYSTEM 9.5.4.5 Instrumentation Application Table 9.5-2 lists the measured parameters for monitoring the performance of the diesel generator fuel oil system.

Each diesel fuel oil transfer pump has its own STOP/AUTO/RUN selector switch located on the diesel generator local panel. Each pump is controlled by the level of its corresponding day tanks. The transfer pump is stopped on a high level signal when it is operating in the automatic mode. If the pump is in the automatic mode and is stopped by the level switch, the signal can be overridden by putting the pump in the manual mode. This override capability permits manual transfer of fuel oil to either tank through each pump.

Low level in the DOST or a LO-LO level signal in a day tank is indicated locally on the diesel generator panel and is alarmed in the control room via a "diesel generator malfunction" alarm. The LO-LO level actuated malfunction alarm is seismic Class I and designed and installed in accordance with IEEE 279.

UNIT 1 9.5-8a Amendment No. 31 (11/21)

9.5.5 DIESEL GENERATOR COOLING WATER SYSTEM 9.5.5.1 Design Bases Each diesel generator set cooling water system is comprised of two independent cooling water systems, one for each tandem diesel engine.

Each diesel generator set cooling water system is designed to:

a) cool the diesel generator sufficiently to permit proper operation under all diesel loading conditions b) withstand design basis earthquake loads without loss of function c) perform its function under the same environmental conditions as the diesel generator which it serves d) function independently from its counterpart cooling water system to assure that no single failure can prevent cooling of both diesel generator sets 9.5.5.2 System Description Each of the two engines in each tandem diesel generator set has a self-contained cooling system which consists of a forced circulation cooling water system which cools the engine directly, and an air cooled radiator system which removes the heat from the cooling water. The system is pressurized (20-30 psig) but contains a surge tank for water expansion. The tank operates at slightly above atmospheric pressure (approximately 4 psig). Each cooling water pump and radiator fan are driven directly from its respective engine crankshaft. Each diesel generator set cooling system requires no external source of power and does not depend on any external plant cooling system.

Makeup water for normal maintenance functions is furnished from a 1 inch normally isolated demineralized water line as shown an Figures 9.5-2 and 9.5-3. The makeup water system is not essential for the successful continuous operation of the diesel generator.

The engine cooling water is maintained at a "keep warm" temperature of between 125°F to 155°F by immersion heaters in the water jacket system which circulates warm water through the lube oil heat exchangers. Auxiliary lube oil pumps circulate the warmed lube oil continuously.

Design data for the diesel generator cooling water system are given in Table 9.5-3. The system is shown on Figures 9.5-2 and 9.5-3.

Refer to Section 8.3.1.1.7 for the description of the emergency onsite power system.

9.5.5.3 System Evaluation Each diesel generator set cooling water system is capable of providing sufficient capacity to cool the diesel which it serves under all loading conditions.

Each diesel generator set cooling water system is independent of any 9.5-9 Amendment No. 19 (10/02)

external power or cooling water source. Failure of either cooling system cannot affect its redundant diesel generator set. There are no connections between cooling systems of redundant diesel generator sets.

Each cooling water system is designed as seismic Class I. Seismic qualification of system components are discussed in Section 3.7.5.

The cooling water system, including the radiator, is protected from hurricane and tornado winds, external missiles and flooding by virtue of its location inside the diesel generator building. See section 3.3 for a discussion of wind and tornado loadings, and Section 3.4 for a discussion of water level (flood) design. See Appendix 3F for a discussion of tornado missile protection.

All components in this system are designed to operate under the most severe conditions of temperature and pressure expected during operation of the diesel generator.

Similar to the issues discussed in NRC Generic Letter 2008-01 and INPO SER 2-05, the presence of unanticipated gas voids within the Diesel Generator Cooling Water System can challenge the ability of the system to perform its design functions due to issues such as gas binding, water hammer, injection delay times, etc. EDG subsystems present little to no opportunity for gas intrusion or air entrainment. The fill, vent, and surveillance operations procedures for the EDG subsystems assure acceptable system performance following maintenance or operational activities that could result in gas void formation. These procedures ensure that the subsystem is left in an operable condition on a monthly basis.

9.5.5.4 Instrumentation Application In the event of a SIAS or loss of off site power the diesel generator is not shut down on high engine water temperature. Section 8.3.1.1.7 discusses all diesel generator lockout signals. Highwater temperature is alarmed locally and annunciated as a common trouble alarm in the control room.

Water pressure is monitored with local indication, and low water level is alarmed locally and annunciated in the control room.

9.5.6 DIESEL GENERATOR AIR STARTING SYSTEM 9.5.6.1 Design Bases The diesel generator set air starting system is designed to:

a) store and provide sufficient charging air to allow starting of its associated diesel generator set b) withstand design basis earthquake loads without loss of function c) operate under the same environmental conditions as the diesel generator which it serves d) provide starting of its associated diesel generator set.

9.5.6.2 System Description Each diesel generator set has an independent air starting system completely separate from the other and other compressed air plant systems. Each of the two tandem engines on each set is provided with two air start motor sets (2 motors per set) for a total of four sets per diesel generator set. Each diesel generator set is also provided with an electrically driven air compressor. This compressor provides charging air to two sets of two air receivers (4 air receivers - total, per diesel generator set).

Each set of air receivers has a capacity for five cold starts for the diesel generator set .

UNIT 1 9.5-10 Amendment No. 28 (05/17)

Upon receiving a start signal, the four 125v dc solenoid valves are energized to open, engaging all four air start motor sets. Each of the two air starting lines normally connects two air receiver tanks to one air start motor set per engine.

Starting system design data are given in Table 9.5-4. The system is shown on Figures 9.5-2 and 9.5-3.

Refer also to Section 8.3.1.1.7 for the system operation description.

9.5.6.3 System Evaluation Each diesel generator air starting system is capable of starting its respective diesel generator set if any two of its four air start motor sets function. This compressor assures that the four starting air receivers are fully charged at all times. Starting of the generator sets is independent of any source of electrical power, except for the air start solenoid valves which require 125v dc power.

All portions of each diesel generator air starting system from the check valve at the inlet header of each air receiver tank pair through the air start motors are designed as seismic Class I. Seismic qualification of system components is discussed in Section 3.7.5.

Any single failure of the starting air system for a diesel generator set can only affect the diesel generator set which it serves. There are no interconnections between starting air systems of redundant diesel generator sets.

The air starting system is protected from hurricane and tornado winds, external missiles and flooding by virture of its location inside the diesel generator building.

All system components are designed to operate in the ambient temperature of the diesel generator building.

The EDG air start system is self contained and does not come into contact with the other EDG fluid subsystems. This system presents little to no opportunity to present gas intrusion or air entrainment issues similar to GL 2008-01 or INPO SER 2-05.

9.5.6.4 Testing and Inspection The testing and inspection of the diesel generator sets, including the air starting system, is discussed in Section 8.3.1.3.

9.5.6.5 Instrumentation Application Local alarms are provided for low starting air pressure, an air receiver outlet valve not full open, and a starting circuit dc failure, and are alarmed on a common annunciator in the control room. The automatic starting and loading of the diesel generators is discussed in Section 8.3.1.1.7.

UNIT 1 9.5-11 Amendment No. 28 (05/17)

9.5.7 DIESEL GENERATOR LUBRICATING SYSTEM 9.5.7.1 Design Bases The diesel generator lubrication system is designed to:

a) supply sufficient lubrication to permit proper operation of its associated diesel generator set b) withstand design basis earthquake loads without loss of function c) perform its function under the same environmental conditions as the diesel generator which it serves 9.5.7.2 System Description Each engine of each tandem diesel generator set has a self-contained lube oil system consisting of a lube oil sump located at the base of the engine, a main engine lube and piston cooling pumps, a scavenging pump, an AC and DC motor driven soakback pumps, filter, strainer, heat exchanger and associated piping. The lube oil heat exchanger is served by the diesel generator set cooling water system. In the normal diesel generator operating mode, no external source of power or other plant system is required for the diesel generator set lube oil system. In the standby mode, the lube oil is constantly circulated by the AC soakback pump and warmed when the diesel generator is not operating. Warming is accomplished by passing the oil through the lube oil heat exchanger which receives warm water via immersion heaters (refer to Section 9.5.5). The DC soakback pump serves as the backup upon loss of the AC pump.

System design data are given in Table 9.5-5. The system is shown on Figures 9.5-2 and 9.5-3.

9.5.7.3 System Evaluation The diesel generator lubrication system is capable of providing sufficient lubrication for the diesel generator under all loading conditions.

During diesel generator operation, the lubricating system is independent of any source of external power or cooling water. Failure of the lube oil system on one diesel generator set cannot affect the redundant diesel generator set.

The diesel generator lube oil system is designed as seismic Class I. Seismic qualification of system components is discussed in Section 3.7.5.

The lube oil system is protected from hurricane and tornado winds, external missiles and flooding by virtue of its location inside the diesel generator building.

All components of this system are designed to operate under the most severe conditions of temperature and pressure expected during operation of the diesel generator.

Similar to the issues discussed in NRC Generic Letter 2008-01 and INPO SER 2-05, the presence of unanticipated gas voids within the Diesel Generator Lubricating System can challenge the ability of the system to perform its design functions due to issues such as gas binding, water hammer, injection delay times, etc. EDG subsystems present little to no opportunity for gas intrusion or air entrainment.

The fill, vent, and surveillance operations procedures for the EDG subsystems assure acceptable system performance following maintenance or operational activities that could result in gas void formation. These procedures ensure that the subsystem is left in an operable condition on a monthly basis.

UNIT 1 9.5-12 Amendment No. 28 (05/17)

9.5.7.4 Testing and Inspection The testing and inspection of the diesel generator sets, including the lube oil system, is described in Section 8.3.1.3.

9.5.7.5 Instrumentation Application The diesel generator is shut down and its breaker tripped on low engine oil pressure, except in the event of a SIAS or loss of offsite power, under which condition it alarms only. This condition will be alarmed locally and annunciated as a common trouble alarm in the control room. Local alarm and control room annunciation as a common trouble alarm are also provided on low lube oil level.

9.5-13 Amendment No. 17 (10/99)

REFERENCES FOR SECTION 9.5

1. Safety Evaluation by the Office of Nuclear Reactor Regulation for St. Lucie Plant, Unit Nos.

1 and 2 - Issuance of Amendments Regarding Transition to a Risk-Informed, Performance-Based Fire Protection Program in Accordance with Title 10 of the Code of Federal Regulations Section 50.48(c), dated March 31, 2016 (ML15344A346).

2. License Amendment Request, Transition to 10 CFR 50.48(c) - NFPA 805 Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition, dated March 22, 2013.
3. National Fire Protection Association Standards, NFPA 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition.
4. Regulatory Guide 1.205, Risk-Informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants, Revision 1, dated December 2009.
5. NEI 04-02, Guidance for Implementing a Risk-Informed, Performance-Based Fire Protection Program under 10 CFR 50.48(c), Revision 2, dated April 2008.
6. FAQ 12-0062, Updated Final Safety Analysis Report (UFSAR) Standard Level of Detail, Revision 1, dated May 21, 2012.
7. DBD-FP-1, Fire Protection Design Basis Document.
8. 1800022, Fire Protection Plan.
9. 8770-B-048, Unit 1 Nuclear Safety Capability Assessment (NSCA).
10. 8770-B-049, Unit 1 Essential Equipment List.
11. PSL-ENG-SEMS-98-035, St. Lucie Unit 1 Nuclear Safety Capability Assessment Basis Document.
12. St. Lucie Plants Units 1 & 2 EDISON Cable and Raceway Database.

UNIT 1 9.5-14 Amendment No. 28 (05/17)

TABLE 9.5-1 DESIGN DATA FOR DIESEL GENERATOR FUEL OIL SYSTEM

1. Piping and Valves Material Carbon Steel, A106 GR B Pressure, psig Suction 50 Discharge 100 Temperature, °F Suction 120 Discharge 120 Pipe sizes 2-1/2 inches and over Schedule 40 2 inches and under Schedule 40 or 80 Connections 2-1/2 inches and larger Butt weld or Victaulic 2 inches and smaller Socket weld or Threaded (Day Tank Vent Line)

Valves 2-1/2 inches and larger Butt weld and/or flanged 2 inches and smaller Socket welded Code ANSI B 31.7 Class III or USAS B31.1 (Day Tank Vent Line)

2. Diesel Oil Transfer Pump Type Horizontal and centrifugal Number 2 Capacity, Gpm 25 Discharge pressure, psig 30 Material Casing A296-68 GR CF8M SS Impeller A296-68 GR CF8M SS Shaft A296-68 GR CF8M SS Code ASME Section III, Class 3 latest applicable addenda
3. Diesel Oil Storage Tanks Quantity 2 Usable Capacity, gal (maximum) 19,120 Gross Capacity, gal (at fill level) 20,593 Material Carbon Steel ASTM A 131 Grade A Pressure Atmospheric 9.5-15 Amendment No. 25 (04/12)

TABLE 9.5-1 (Cont'd)

Temperature, F 125 Code API 620 Seismic design Class I

4. Day Tanks Quantity per diesel generator 2 Usable capacity, gal (maximum; 120 at Diesel Oil Transfer Pump Level Switch stop setting)

Gross capacity, gal 200 Material 3/16" carbon steel ASTM A-36 Pressure, psig Atmospheric Temperature, F 185 Code ASME Section III, Class 3, latest applicable addenda Seismic design Class I 9.5-16 Amendment No. 25 (04/12)

TABLE 9.5-2 DIESEL GENERATOR FUEL OIL SYSTEM INSTRUMENTATION APPLICATION Indication Alarm(1) Instru- Normal (1)

Control ment Operating Instrument System Parameter & Location Local Room High Low Recording Control Function Range(6) Range Accuracy(6)

Diesel Oil Storage Tank Level(2) *(5)

  • Full-4 ft Full-50%

Day Tank Level(3) *(5) *

  • 1) Control operation of Full Diesel oil transfer pump
2) Stop pump on high level when pump is in automatic mode(4) 1 All alarms and recordings are in the control room unless otherwise indicated.

2 Local alarms only.

3 Local alarm and controls on the diesel generator panel.

4 This "stop" can be overridden by switching pump to "manual" mode.

5 Local panel alarms are annunciated In the control room.

6 Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

9.5-17 Amendment No. 18, (04/01)

TABLE 9.5-3 DESIGN DATA FOR DIESEL ENGINE COOLING WATER SYSTEM COMPONENTS

1. Radiator 12 cylinder engine 16 cylinder engine Type Flat tube Flat tube Quantity, per 1 1 diesel engine Design duty, 5,340,000 7,080,000 BTU/hr Heat transfer 64 96.2 area (frontal), ft2 Design pressure, 35 35 psig Design temp- 250 250 erature, F Air flow, acfm 110,000 145,000 Material Tubes Yellow brass Yellow brass Fins Copper Copper Seismic design Class I Class I
2. Expansion Tank Dimensions, diameter & 24,48 length, in.

Quantity, per diesel 1 engine Design pressure, psi 50 Material ASTM A-36-3/16" plate Seismic design Class I Code ASME Section VIII, latest applicable addenda 9.5-18 Amendment No. 18, (04/01)

TABLE 9. 5 - 3 (Cont'd)

3. Piping, Fittings and Valves Material 5 in. and 6 in. piping ASTM A-53 or ASTM A-106 Grade B seamless Design pressure, psig 39 Welding Plain end welding procedure SMA-P-1-3 Codes ASME B&PV Code,Section VIII, Div.1, latest applicable addenda 9.5-19 Amendment No. 18, (04/01)

TABLE 9.5-4 DESIGN DATA FOR DIESEL GENERATOR STARTING SYSTEM COMPONENTS

1. Compressor Type Air cooled, reciprocating piston Quantity 1 Design capacity, scfm 18 Discharge pressure, psig 220
2. Air Receiver Quantity 4 Design pressure, psig 200 Design temperature, F 650 Volume, ft3 32 Material SA 455 A Code ASME Section VIII, Div 1
3. Piping, Fittings and Valves Piping material SA 312, Type 304 Design pressure, psig Compressors to Air Receiver Inlet Isolation Valves 250 Air Receiver And Air Delivery Piping 220 Code ASME Section VIII, latest applicable addenda UNIT 1 9.5-20 Amendment No. 28 (05/17)

TABLE 9.5-5 DESIGN DATA FOR DIESEL GENERATOR LUBE OIL SYSTEM COMPONENTS Piping, Fittings and Valves Piping material ASTM-A-53 or ASTM-A-106 GR B Design pressure, psig 89 Design temperature, F 265 Welding SMA-P-1-4 Codes ASME Section III, Class 3, latest applicable addenda 9.5-21 Amendment No. 18, (04/01)

Refer to drawing 8770-G-086 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAM MISCELLANEOUS SYSTEMS SH.1 FIGURE 9.5-1 Amendment No. 15, (1/97)

Refer to drawing 8770-G-096, Sheets 1A, B & C FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAMS EMERGENCY DIESEL GENERATOR SYSTEM DIESEL GENERATOR 1A FIGURE 9.5-2 Amendment No. 16 (1/98)

Refer to drawing 8770-G-096, Sheets 2A, B & C FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW DIAGRAMS EMERGENCY DIESEL GENERATOR SYSTEM DIESEL GENERATOR 1B FIGURE 9.5-3 Amendment No. 16 (1/98)

9.6 CRANES - OVERHEAD HEAVY LOAD HANDLING SYSTEMS 9.6.1 NUREG-0612 "CONTROL OF HEAVY LOADS AT NUCLEAR PLANTS" The objectives of NUREG-0612 are: (a) to ensure that all load handling systems at nuclear power plants are designed and operated so that their probability of failure is uniformly small and appropriate for the critical tasks in which they are employed; and (b) to ensure that, for load handling systems in areas where their failure might result in significant consequences, either (1) additional features are provided to ensure that the potential for a load drop is extremely small, or (2) conservative evaluations of load handling accidents indicate that the potential consequences of any load drop are acceptably small.

9.6.2 SYSTEMS SUBJECT TO NUREG-0612 The following overhead load handling systems are subject to the general guidelines of NUREG-0612:

reactor building polar crane intake structure bridge crane spent fuel cask handling crane auxiliary telescoping jib crane refueling machine 1-ton hoist fuel pool bulkhead monorail Turbine Building Gantry Crane The pump room, charging pump, and diesel generator A and B monorails have been excluded because the function of these monorails involves a sole-purpose maintenance lift. Therefore, the equipment which could possibly be damaged by a load drop will already be inoperable for maintenance.

The spent fuel cask handling crane has been replaced with a new 150/25 ton crane. The new crane's main hoist complies with the single-failure-proof criteria of NUREG-0612 and NUREG-0554.

UNIT 1 9.6-1 Amendment No. 28 (05/17)

9.6.3 IMPLEMENTATION OF NUREG-0612 GUIDELINES 9.6.3.1 Safe Load Paths Specific safe load paths are designated and referenced in the applicable procedures, for major loads which routinely are carried over the same route or routes. To provide suitable visual aid to crane operators, an individual is used to lead the heavy load over the path. Deviations require prior approval by the On-site Review Group.

9.6.3.2 Load Handling Procedures Procedures have been developed for handling heavy loads over or in proximity to irradiated fuel and safe shutdown equipment. This administrative procedure describes the measures taken to ensure that heavy loads remain within the safe load paths. In addition, the procedure defines the safe load paths. The procedure requires that (1) a sign is placed at the controls of each affected crane stating that all heavy loads greater than or equal to 1380 lbs. shall be carried in the defined safe load path and (2) a map of the safe load paths is posted on the crane.

9.6.3.3 Crane Operator Training A program for crane operator training, qualification, and conduct, will be implemented in accordance with ANSI B30.2-1976, Chapter 2-3 with the following exceptions:

1. Eye test of 20/40 in both eyes for new employees will be required.
2. A crane deadman switch will be used instead of a main line disconnect to secure power because of the power requirements of the crane motor heaters.
3. Controls necessary for crane operation will be tested before beginning a new shift.
4. At shift change, the upper limit device will be tested under no load unless the hook is loaded or unless no crane operation in the area of the upper limit is anticipated.

9.6.3.4 Special Lifting Devices The following special lifting devices have been identified as subject to compliance with the criteria of NUREG-0612:

reactor vessel closure head lift rig (RVCH LR) 9.6-2 Amendment No. 23 (11/08)

internals and upper guide structure lift rig (I&UGS LR)

EC287230 spent fuel transfer cask lifting yoke spent fuel transfer cask lifting yoke extension A detailed comparison of the existing design of these devices to the design, fabrication, and testing requirements of ANSI N14.6 has been performed. Results indicate that the spent fuel transfer cask lifting yoke and extension are in compliance with ANSI N14.6-1993, and that the reactor vessel closure head lift rig and internals and upper guide structure lift rig are in compliance with ANSI N14.6-1978 with the following limited exceptions:

periodic testing will be performed in accordance with Section 5.3.1(2) (which specifies nondestructive examination techniques). As an alternative, a load test may be performed in accordance with Section 5.3.1(1), with the exception that the load shall be equal to 125% of the maximum load to which the device is subjected.

the RVCH LR was not load tested to prevent overstressing, while the I&UGS LR was load tested to only 125% of rated load.

Note: The specified periodic inspections of the reactor vessel closure head lift rig and the internals and upper guide structure lift rig shall be performed at an interval not to exceed ten years [Reference PSL-ENG-SEC-08-028, Rev. 0, Requirements for Periodic Inspection and Testing of Special Lifting Devices in Reactor Containment Building (Unit 1)].

9.6.3.5 Lifting Devices (Not Specifically Designed)

The program for sling use and maintenance meets the requirements of ANSI B30.9. Further, the rated capacities are marked on each sling. Since crane hoisting speeds are relatively slow (main hoists - less than 8 fpm; auxiliary hoists - less than 30 fpm), any contribution from a dynamic effect would not be significant and sling ratings do not consider dynamic loading.

9.6.3.6 Cranes (Inspection, Testing, and Maintenance)

The crane inspection, testing, and maintenance program complies with the requirements of ANSI B30.2-1976 with the exception that tests and inspections are performed prior to use where it is not practical to meet the frequencies of ANSI B30.2 for periodic inspection and testing, or where the frequency of crane use is less than the specified inspection and test frequency.

9.6.3.7 Crane Design Handling systems in use were evaluated. The following systems fall within the scope of the CMMA-70 specification and the ANSI B30.2-1976 standard:

reactor building polar crane spent fuel cask handling crane intake structure crane The design of the main hoist of the spent fuel cask handling crane, in addition to following CMMA-70 and ANSI B30.2-1976, also complies with NUREG-0554, "Single-Failure-Proof Cranes for Nuclear Power Plants." The crane's auxiliary hoist is of conventional design.

9.6-3 Amendment No. 29 (10/18)

Although the reactor building polar crane and the intake structure crane were designed to EOCI-61, "Specifications for Electric Overhead Traveling Cranes", and ANSI B30.2-1961, a detailed comparison has been performed with the more restrictive design criteria of CMAA-70 and design of these cranes was determined to comply with these revised criteria. The primary differences between the EOCI-61 and CMAA-70 specifications are in advancement in girder design practice and higher allowable stresses in CMAA-70. Although the cranes are designed to EOCI-61, which specifies ASTM-A7 steel, the higher grade ASTM-A36 steel has been used, which is in conformance with CMAA-70 requirements.

Further, although the new telescoping jib crane inside containment does not fall within the scope of CMAA-70, the design was specified to conform to CMAA-70, CMAA-74, and ANSI B30.2, as applicable.

9.6.4 DESIGN DESCRIPTION INFORMATION 9.6.4.1 Structures Reference the following FSAR sections for additional information:

3.7.3.9 Reactor Building Crane Restraints 3.8.1.1.2 Fuel Handling Building and Cask Handling Crane Support Structure 3.8.1.1.4 Intake Structure 9.6.4.2 Fuel Handling Reference section 9.1 for additional information on the refueling machine hoist, spent fuel cask handling crane, and fuel pool bulkhead hoist.

9.6-4 Amendment No. 20 (4/04)

Table 9.6-1 NUREG-0612 Compliance Matrix Weight Interim Interim or Guideline I Guideline 2 Guideline 3 Guideline 4 Guideline 5 Guideline 6 Guideline 7 Measure I Measure 6 Capacity Safe Load Crane Op Special Lifting Crane-Test Technical Special Heavy Loads (tons) Paths Procedure Training Devices Slings and Inspection Crane Design Specifications Attention

1. Containment 175 -- -- C -- -- C C -- --

Polar Crane Reactor Vessel Head 119.7 C C -- C -- -- -- -- C Upper Guide Structure 64.4 C C -- C -- -- -- -- C Inservice Inspec-tion Tool 4.5 C C -- C -- -- -- -- C Reactor Pool And Pumps 4.3 C C -- -- C -- -- -- C Missile Shields 72.8 C C -- -- C -- -- -- C Crane Load Block 1.7 C C -- -- C -- -- -- C Pressurizer Missile Shields 48 C C -- -- C -- -- -- C

2. Intake Structure Bridge Crane 45 C C C -- C C -- -- C C = License action complies with NUREG-0612 Guidelines 9.6-5 Am. 4-7/86

Table 9.6 1 (Cont'd)

NUREG-0612 Compliance Matrix Weight Interim Interim or Guideline I Guideline 2 Guideline 3 Guideline 4 Guideline 5 Guideline 6 Guideline 7 Measure I Measure 6 Capacity Safe Load Crane Op Special Lifting Crane-Test Technical Special Heavy Loads (tons) Paths Procedure Training Devices Slings and Inspection Crane Design Specifications Attention 3.Fuel Building Spent Fuel Cask Handling Crane 150 -- -- C -- -- C C -- --

(main hoist)

Spent Fuel Transfer Cask 129.5* C C -- -- C -- -- C -- EC287230

4. Auxiliary Telescoping Jib Crane 1.0 -- -- C -- -- C C -- --
5. Refueling Machine Hoist 1.0 -- -- C -- -- C C -- --
6. Fuel Pool Bulkhead Monorail 3.0 -- -- C -- -- C C -- --

Fuel Pool Bulkhead 2.5 C C -- -- C C --

C = Licensee action complies with NUREG-0612 Guidelines

  • include the weight of the spent fuel transfer cask lifting yoke and lifting yoke extension 9.6-6 Amendment No. 29 (10/18)
Retrieved from "https://kanterella.com/w/index.php?title=ML23096A042&oldid=3590155"