L-2016-198, Redacted Turkey Point, Units 3 & 4, Updated Final Safety Analysis Report, Chapter 9, Auxiliary and Emergency Systems
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TABLE OF CONTENTS
Section Title Page 9.0 AUXILIARY AND EMERGENCY SYSTEMS 9-1
9.1 General Design Criteria 9.1-1 9.1.1 Related Criteria 9.1-1 Reactivity Control System Malfunction 9.1-1 Engineered Safety Features Performance Capability 9.1-1 Containment Heat Removal Systems 9.1-2
9.2 Chemical and Volume Control System 9.2-1 9.2.1 Design Bases 9.2-1 Redundancy of Reactivity Control 9.2-1 Reactivity Hot Shutdown Capability 9.2-1 Reactivity Shutdown Capability 9.2-2 Reactivity Hold-Down Capability 9.2-3 Codes and Classifications 9.2-4 9.2.2 System Design and Operation 9.2-5 Expected Operating Conditions 9.2-7 Reactor Coolant Activity Concentration 9.2-7 Reactor Make-up Control 9.2-9 Automatic Make-up 9.2-10 Dilution 9.2-11 Alternate Dilute 9.2-11 Boration 9.2-12 Alarm Functions 9.2-13 Charging Pump Control 9.2-13 Components 9.2-14 Regenerative Heat Exchanger 9.2-14 Letdown Orifices 9.2-14 Non-Regenerative (letdown) Heat Exchanger 9.2-15 CVCS Letdown Bed Demineralizers 9.2-15 Resin Fill Tank 9.2-16 Reactor Coolant Filter 9.2-16 Volume Control Tank 9.2-17 Charging Pumps 9.2-17 Chemical Mixing Tank 9.2-18 Excess Letdown Heat Exchanger 9.2-18 Seal Water Heat Exchanger 9.2-18 Seal Water Filters 9.2-19 Seal Water Injection Filters 9.2-19 Boric Acid Filter 9.2-19 Boric Acid Tanks 9.2-19 Batching Tank 9.2-20 Boric Acid Transfer Pumps 9.2-20 Boric Acid Blender 9.2-21 Recycle Process 9.2-21 Holdup Tanks 9.2-21 Holdup Tank Recirculation Pump 9.2-21 Gas Stripper Feed Pumps 9.2-22 Monitor Tanks 9.2-22 Monitor Tank Pumps 9.2-22 Valves 9.2-22 Piping 9.2-23
9-i Revised 04/17/2013 C26 TABLE OF CONTENTS (Continued)
Section Title Page 9.2.3 System Design Evaluation 9.2-23 Availability and Reliability 9.2-23 Control of Tritium 9.2-24 Leakage Prevention 9.2-24 Incident Control 9.2-25 Malfunction Analysis 9.2-26 Galvanic Corrosion 9.2-27 9.2.4 References 9.2-28 9.3 Auxiliary Coolant System 9.3-1 9.3.1 Design Bases 9.3-1 Performance Objectives 9.3-1 Component Cooling Loop 9.3-1 Residual Heat Removal Loop 9.3-1 Design Characteristics 9.3-2 Component Cooling Loop 9.3-2 Residual Heat Removal Loop 9.3-3 Codes and Classifications 9.3-3 9.3.2 System Design and Operation 9.3-4 Component Cooling Loop 9.3-4 Design Bases 9.3-5 Pump Performance 9.3-10 Maximum Flow Considerations for ECCs 9.3-10 Spent Fuel Pit Heat Exchanger Minimum Flow 9.3-11 Residual Heat Removal Loop 9.3-12 Component Cooling Water Components 9.3-14 Component Cooling Water Heat Exchangers 9.3-14 Component Cooling Water Pumps 9.3-14 Component Cooling Water Surge Tank 9.3-14 Chemical Pot Feeder Tank 9.3-14 Component Cooling Water Valves 9.3-15 Component Cooling Water Piping 9.3-15 Component Cooling Water Head Tank 9.3-15 Residual Heat Removal Loop Components 9.3-15 Residual Heat Exchangers 9.3-15 Residual Heat Removal Pumps 9.3-16 Residual Heat Removal Valves 9.3-16 Residual Heat Removal Piping 9.3-16 9.3.3 System Evaluation 9.3-17 Availability and Reliability 9.3-17 Component Cooling Loop 9.3-17 Residual Heat Removal Loop 9.3-18 Leakage Provisions 9.3-18 Component Cooling Water Loop 9.3-18 Residual Heat Removal Loop 9.3-20 Incident Control 9.3-21 Component Cooling Loop 9.3-21 Residual Heat Removal Loop 9.3-22 Malfunction Analysis 9.3-22 9.3.4 Test and Inspection Capability 9.3-22 9.3.5 References 9.3-24
9-ii Revised 09/20/2016
C28 TABLE OF CONTENTS (Continued)
Section Title Page 9.4 Sampling System 9.4-1 9.4.1 Design Bases 9.4-1 Performance Requirements 9.4-1 Design Characteristics 9.4-1 High Pressure - High Temperature Samples 9.4-2 Low Pressure - Low Temperature Samples 9.4-2 Expected Operating Temperatures 9.4-2 Codes and Standards 9.4-2 9.4.2 System Design and Operation 9.4-3 Components 9.4-5 Sample Heat Exchangers 9.4-5 Delay Coil 9.4-5 Sample Pressure Vessels 9.4-5 Sample Sink 9.4-6 Piping and Fittings 9.4-6 Valves ` 9.4-6 9.4.3 System Evaluation 9.4-7 Incident Control 9.4-7 Malfunction Analysis 9.4-7
9.5 Fuel Storage and Handling 9.5-1 9.5.1 New Fuel Storage 9.5-1 9.5.1.1 Design Basis 9.5-1 9.5.1.2 System Description 9.5-2 9.5.1.3 System Evaluation 9.5-3 9.5.2 Spent Fuel Storage 9.5-3 9.5.2.1 Design Basis 9.5-3 9.5.2.2 System Description 9.5-4 Auxiliary Building 9.5-4 Spent Fuel Pit 9.5-5 Region I Spent Fuel Pit Racks 9.5-6 Region II Spent Fuel Pit Racks 9.5-7 Cask Area Rack 9.5-8 Radiation Protection 9.5-9 9.5.2.3 System Evaluation 9.5-9 Criticality Analysis 9.5-9 Spent Fuel Pit Storage Racks 9.5-10 Cask Area Storage Rack 9.5-13 Postulated Accidents Affecting Reactivity 9.5-14 9.5.3 Spent Fuel Pit Cooling and Purification 9.5-16 9.5.3.1 Design Basis 9.5-16
9-iii Revised 04/17/2013 C26 TABLE OF CONTENTS (Continued)
Section Title Page 9.5.3.2 System Description 9.5-17 Component Description 9.5-18 Spent Fuel Pit Heat Exchangers 9.5-18 Spent Fuel Pit Pumps 9.5-18 Refueling Water Purification Pump 9.5-18 Spent Fuel Pit Skimmer Strainer 9.5-18 Spent Fuel Pit Filter 9.5-18 Spent Fuel Pit Demineralizer 9.5-19 Spent Fuel Pit Skimmer 9.5-19 Spent Fuel Pit Valves 9.5-19 Spent Fuel Pit Piping 9.5-19 9.5.3.3 System Evaluation 9.5-19 Thermal-Hydraulic 9.5-19 SFP Bulk Temperature Analysis 9.5-20 Procedural Controls 9.5-25 SFP Local Temperature Analysis 9.5-26 Time-to-Boil Analysis 9.5-28 Spent Fuel Pool Makeup 9.5-29 Leakage Provisions 9.5-30 Incident Control 9.5-31 Spent Fuel Pit Structural Analysis for Thermal Conditions 9.5-31 9.5.3.4 Test and Inspection Capability 9.5-33 9.5.4 Fuel Handling System 9.5-32 9.5.4.1 Design Basis 9.5-32 9.5.4.2 System Description 9.5-33 Major Structures Required for Fuel Handling 9.5-35 Refueling Cavity 9.5-35 Refueling Canal 9.5-36 Refueling Water Storage Tank 9.5-36 Spent Fuel Storage Pit 9.5-36 New Fuel Storage 9.5-37 Major Equipment Required for Fuel Handling 9.5-37 Reactor Vessel Stud Tensioner 9.5-37 Reactor Vessel Head Lifting Device 9.5-37 Reactor Internals Lifting Device 9.5-38 Manipulator Crane 9.5-38 Spent Fuel Handling Crane 9.5-40 Spent Fuel Cask Handling Crane 9.5-41 Fuel Transfer System 9.5-41 Reactor Cavity Filtration System 9.5-41 Refueling Operation Activities 9.5-41 Refueling 9.5-43 Reactor Reassembly 9.5-44 9.5.4.3 System Evaluation 9.5-45 Incident Protection 9.5-46 Malfunction Analysis 9.5-46 9.5.4.4 Test and Inspection Capability 9.5-46 9.5.5 References 9.5-47
9-iv Revised 04/17/2013 C26 TABLE OF CONTENTS (Continued)
Section Title Page 9.6 Facility Services 9.6-1 9.6.1 Fire Protection Program 9.6-2 9.6.1.1 Design Basis Summary 9.6-2 9.6.1.1.1 Defense-In-Depth 9.6-2 9.6.1.1.2 NFPA 805 Performance Criteria 9.6-2 9.6.1.1.3 Codes of Record 9.6-3 9.6.1.2 System Description 9.6-4 9.6.1.2.1 Required Systems 9.6-4 9.6.1.2.2 Definition of "Power Block" Structures 9.6-4 9.6.1.3 Safety Evaluation 9.6-5 9.6.1.4 Fire Protection Program Documentation, Configuration Control and Quality Assurance 9.6.5 9.6.2 Miscellaneous Water Systems 9.6-6 Intake Cooling Water System 9-6.6 System Design 9.6-7 System Evaluation 9.6-9 Water Treatment System 9.6-9 Primary Water Make-up System 9.6-10 System Design 9.6-10 9.6.3 System Design Evaluation 9.6-11 Malfunction Analysis 9.6-11 Minimum Operating Conditions 9.6-11 Test and Inspections 9.6-11 9.6.4 References 9.6-12 9.7 Equipment and System Decontamination 9.7-1 9.7.1 Design Basis 9.7-1 9.7.2 Methods of Decontamination 9.7-2 9.7.3 Decontamination Facilities 9.7-3
9.8 Auxiliary Building HVAC Systems and Containment Purge Systems 9.8-1 9.8.1 Auxiliary Building Ventilation and Containment Purge System s 9.8-1 9.8.1.1 Design Basis 9.8-1 9.8.1.2 System Design and Operation 9.8-1 9.8.2 Electrical Equipment Room HVAC System 9.8-3 9.8.2.1 Design Basis 9.8-3 9.8.2.2 System Design and Operation 9.8-3 9.8.2.3 Safety Analysis 9.8-4 9.9 Control Building Ventilation System 9.9-1 9.9.1 Control Room 9.9-1 9.9.1.1 Design Basis 9.9-1 9.9.1.2 System Design and Operation 9.9-3 9.9.1.3 Normal Operation 9.9-4 9.9.1.4 Control Room Emergency Operation Design 9.9-4 9.9.1.4.1 CREVS Recirculation Filter Train 9.9-4 9.9.1.4.2 CREVS Compensatory Filtration Unit 9.9-4 9.9.1.5 Automatic Emergency Design 9.9-5 9.9.1.6 Control Room Hability Program 9.9-6 9.9.2 Control Building Annex 9.9-7 9.9.2.1 Design Basis 9.9-7 9.9.2.2 System Design and Operation 9.9-7 9.9.2.3 Safety Analysis 9.9-8 9-v Revised 09/20/2016 C28 TABLE OF CONTENTS (Continued)
Section Title Page 9.9.3 Computer/Cable Spreading Room HVAC System 9.9-9 9.9.3.1 Design Basis 9.9-9 9.9.3.2 System Design and Operation 9.9-9 9.9.3.3 Safety Analysis 9.9-9 9.10 Normal Containment Ventilation System 9.10-1 9.10.1 Design Basis 9.10-1 Performance Objectives 9.10-1 Design Description 9.10-1 9.10.2 System Design 9.10-2 Containment Ventilation 9.10-2 9.10.3 References 9.10-4
9.11 Auxiliary Feedwater System 9.11-1 9.11.1 Design Basis 9.11-1 9.11.1.1 System Operation 9.11-1 9.11.1.2 Auxiliary Feedwater Flow Control Valves 9.11-1 9.11.1.3 Nitrogen Backup System to the Auxiliary Feedwater Control Valves 9.11-2 9.11.2 Auxiliary Feedwater Pumps 9.11-3 Standby Feedwater Pumps 9.11-4 9.11.3 Condensate Storage Tanks 9.11-5 9.11.4 References 9.11-5
9.12 Post-Accident Hydrogen Control 9.12-1 9.12.1 DELETED 9.12-1 9.12.2 DELETED 9.12-1
9.13 Post-Accident Sampling System 9.13-1 9.14 Post-Accident Hydrogen Monitoring System 9.14-1
9.15 Emergency Diesel Generator Auxiliaries 9.15-1 9.15.1 Emergency Diesel Generator Fuel Oil Storage and Transfer System 9.15-1 9.15.1.1 Design Basis 9.15-1 9.15.1.2 System Description 9.15-2 9.15.1.3 Safety Evaluation 9.15-7 9.15.1.4 Tests and Inspections 9.15-9 9.15.1.5 Instrumentation Application 9.15-10 9.15.2 Emergency Diesel Generator Cooling Water System 9.15-11 9.15.2.1 Design Bases 9.15-11 9.15.2.2 System Description 9.15-13 9.15.2.3 Safety Evaluation 9.15-16 9.15.2.4 Tests and Inspections 9.15-17 9.15.2.5 Instrumentation Application 9.15-18 9.15.3 Emergency Diesel Generator Air Start System 9.15-19 9.15.3.1 Design Bases 9.15-19 9.15.3.2 System Description 9.15-21 9.15.3.3 Safety Evaluation 9.15-24 9.15.3.4 Tests and Inspections 9.15-25 9.15.3.5 Instrumentation Application 9.15-26
9-vi Revised 09/20/2016
TABLE OF CONTENTS (Continued)
Section Title Page 9.15.4 Emergency Diesel Generator Lubrication System 9.15-27 9.15.4.1 Design Bases 9.15-27 9.15.4.2 System Description 9.15-29 Scavenging Oil System 9.15-30 Main Lube Oil System 9.15-30 Piston Cooling Oil System 9.15-30 Soak Back Oil System 9.15-31 9.15.4.3 Safety Evaluation 9.15-34 9.15.4.4 Tests and Inspections 9.15-35 9.15.4.5 Instrumentation Application 9.15-35
9.15.5 Emergency Diesel Generator Combustion Air Intake/Exhaust System 9.15-37 9.15.5.1 Design Bases 9.15-37 9.15.5.2 System Description 9.15-39 9.15.5.3 Safety Evaluation 9.15-40 9.15.5.4 Tests and Inspections 9.15-41 9.15.5.5 Instrumentation Application 9.15-42
9.16 Load Center and Switchgear Rooms Air Conditioning System 9.16-1 9.16.1 Design Basis 9.16-1 9.16.2 System Design and Operation 9.16-1 9.16.3 Safety Analysis 9.16-3
9.17 Instrument Air System 9.17-1 9.17.1 Design Basis 9.17-1 9.17.2 System Design and Operation 9.17-1 9.17.3 Safety Analysis 9.17-3 9.17.4 References 9.17-3 9.18 Technical Support Center 9.18-1
9-vii Revised 09/20/2016
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9-viii Revised 09/20/2016 C28 LIST OF TABLES
Table Title 9.2-1 Chemical and Volume Control System Code Requirements
9.2-2 Nominal Chemical and Volume Control System Performance
9.2-3 Principle Component Data Summary
9.2-4 Parameters Used in the Calculation of Reactor Coolant Fission Produce Activities (Per Unit for 24 Month Cycle)
9.2-5 Equilibrium Reactor Coolant System Specific Activity
9.2-6 Tritium Production in the Reactor Coolant
9.2-7 Malfunction Analysis of Chemical and Volume Control System
9.3-1 Component Cooling Water Loop Component Data
9.3-2 Residual Heat Removal Loop Component Data
9.3-3 Deleted
9.3-4 Auxiliary Coolant System Code Requirements
9.3-5 Failure Analysis of Pumps, Heat Exchangers and Valves
9.3-6 Allowable Range of Flows Through Components in Post-LOCA Recirculation Mode
9.4-1 Sampling System Code Requirements
9.4-2 Sampling System Components
9.4-3 Malfunction Analysis of Sampling System
9.5-1 Fuel Handling Data
9.5-2 Cranes, Hoists and Elevators
9.5-3 Nominal Fuel Parameters Used in the Criticality Analysis 9.5-4 Region I Spent Fuel Storage Cell Nominal Parameters 9.5-5 Deleted
9.5-6 Deleted
9.5-7 Region II - Spent Fuel Storage Cell Nominal Parameters
9.5-8 Deleted
9.5-9 Deleted
9-ix Revised 04/17/2013 C26C26 LIST OF TABLES (Continued)
Table Title 9.5-10 Spent Fuel Pool Soluble Boron Requirements
9.5-11 Deleted
9.5-12 Deleted
9.5-13 Deleted
9.5-14 Deleted 9.5-15 Deleted
9.5-16 Spent Fuel Cooling Loop Component Data
9.5-17 Applicable Design and Fabrication Codes, Standards and Specifications for Spent Fuel Storage Racks
9.5-18 Fuel Category Ranked by Reactivity 9.5-19 Blanketed Fuel - Coefficients to Calculate the Minimum Required Fuel Assembly Burnup (Bu) as a Function of Enrichment (En) and Cooling Time (Ct) 9.5-20 Non - Blanketed Fuel - Coefficients to Calculate the Minimum Required Fuel Assembly Burnup (Bu) as a Function of Enrichment (En) and Cooling Time (Ct) 9.5-21 Maximum k Eff for each 2X2 Array with No Soluble Boron
9.5-22 Nominal RCCA Specifications
9.5-23 Nominal Metamic Inserts Specifications
9.5-24 IFBA Requirements for Fuel Category I-2
9.6-1 Equipment Design Parameters
9.6-2 Intake Cooling Water System - Code Requirements
9.8-1 Auxiliary Building Fan Data Summary
9.10-1 Normal Containment Ventilation Data Summary
9.11-1 Auxiliary Feedwater Pump/Turbine Construction Data
9.11-2 Auxiliary Feedwater System - Code Requirements
9-x Revised 04/17/2013
C26C26C26 LIST OF FIGURES
Figure Title 9.2-1 Chemical & Volume Control System Boric Acid System
9.2-1a Deleted
9.2-1b Deleted
9.2-2 Chemical & Volume Control System Boron Recycle System
9.2-3 Chemical & Volume Control System Boron Recycle System
9.2-4 Chemical & Volume Control System Boron Recycle System
9.2-5 Chemical & Volume Control System Charging and Letdown (Unit 3)
9.2-6 Chemical & Volume Control System Charging and Letdown (Unit 3)
9.2-7 Chemical and Volume Control System Seal Water Injection to RCP (Unit 3)
9.2-8 Chemical and Volume Control System Charging and Letdown (Unit 4)
9.2-9 Chemical and Volume Control System Charging and Letdown (Unit 4)
9.2-10 Chemical and Volume Control System Seal Water Injection to RCP (Unit 4)
9.2-11 Nitrogen & Hydrogen Systems - Hydrogen and CO 2 Supply 9.3-1 Component Cooling Water System (Unit 3)
9.3-1a Deleted
9.3-1b Deleted
9.3-2 Component Cooling Water System (Unit 3)
9.3-3 Component Cooling Water System (Unit 3)
9.3-4 Component Cooling Water System (Unit 3)
9.3-5 Component Cooling Water System (Unit 3)
9.3-6 Component Cooling Water System (Unit 4)
9.3-7 Component Cooling Water System (Unit 4)
9.3-8 Component Cooling Water System (Unit 4)
9.3-9 Component Cooling Water System (Unit 4)
9.3-10 Deleted
9-xi Revised 04/17/2013
LIST OF FIGURES (Continued)
Figure Title 9.3-11 Deleted
9.4-1 Nuclear Steam Supply System - Sample System (Unit 3)
9.4-2 Nuclear Steam Supply System - Sample System (Unit 4)
9.5-1 Fuel Transfer System
9.5-2 Reactor Cavity Seal for Units 3 and 4
9.5-2a Alternative Segmented Reactor Cavity Seal for Units 3 and 4
9.5-3 Spent Fuel Pool at Elevation 18'0"
9.5-4 Spent Fuel Pool at Elevation 58'0"
9.5-5 Section A-A of Spent Fuel Pool
9.5-6 Spent Fuel Pool Arrangement
9.5-7 Nominal Dimension for the Region I Spent Fuel Pit Storage Cells
9.5-8 Nominal Dimension for the Region II Spent Fuel Pit Storage Cells
9.5-9 Nominal Dimensions for Region I Cask Area Rack Storage Cells
9.5-10 Deleted
9.5-11 Spent Fuel Pool Cooling System (Unit 3)
9.5-12 Spent Fuel Pool Cooling System (Unit 4)
9.5-13 Deleted
9.5-14 Metamic Inserts for Region II Racks
9.5-15 Region II Rack Cell with MetamicŽ Insert and Fuel Assembly
9.5-16 Illustration Showing Correct Spatial Orientation of MetamicŽ
Inserts
9.5-17 Example of Region II Rack Insert Loading Sequence
9.6-1 Intake Cooling Water System (Unit 3)
9.6-2 Intake Cooling Water System (Unit 3)
9.6-3 Deleted
9.6-4 Deleted
9.6-5 Intake Cooling Water System (Unit 4)
9.6-6 Intake Cooling Water System (Unit 4)
9.6-7 Deleted
9.6-8 Turbine Plant Cooling Water System (Unit 3)
9-xii Revised 04/17/2013
LIST OF FIGURES (Continued)
Figure Title 9.6-9 Turbine Plant Cooling Water System (Unit 4)
9.6-10 Water Treatment Plant System Filtration
9.6-11 Water Treatment Plant System Demineralizer
9.6-12 Water Treatment Plant System Demineralizer
9.6-13 Water Treatment Plant System Waste Neutralization
9.6-14 Water Treatment Plant System - Sampling System
9.6-15 Primary Water Makeup System (Unit 3)
9.6-16 Primary Water Makeup System (Unit 3)
9.6-17 Primary Water Makeup System (Unit 4)
9.6-18 Primary Water Makeup System (Unit 4)
9.8-1 Auxiliary Building Ventilation System
9.8-2 Deleted
9.8-3 Spent Fuel Pool and New Fuel Storage Area Ventilation (Unit 3)
9.8-4 Spent Fuel Pool and New Fuel Storage Area Ventilation (Unit 4)
9.8-5 Containment Purge System and Penetration Cooling System (Unit 3)
9.8-6 Containment Purge System and Penetration Cooling System (Unit 4)
9.9-1 Control Building HVAC, Elevation 42'-0"
9.9-2 Control Building HVAC, Elevation 30'-0"
9.9-3 DC Equipment/Inverter Rooms HVAC (Sheet 1)
9.9-3 DC Equipment/Inverter Rooms HVAC Sections (Sheet 2)
9.9-4 Control Building Ventilation Control Room HVAC
9.9-5 Control Building Ventilation Computer Facility/Cable Spreading Room HVAC 9.10-1 Containment Normal and Emergency Cooling Systems (Unit 3)
9.10-2 Containment Normal and Emergency Cooling Systems (Unit 4)
9.11-1 Deleted
9.11-2 Auxiliary Feedwater System Turbine Drive for AFW Pumps
9.11-3 Auxiliary Feedwater System Auxiliary Feedwater Pumps
9.11-4 Auxiliary Feedwater System Steam to Auxiliary Feedwater Pump Turbines (Unit 3)
9-xiii Revised 04/17/2013 C26 LIST OF FIGURES (Continued)
Figure Title
9.11-5 Auxiliary Feedwater System Auxiliary Feedwater to Steam Generators (Unit 3) 9.11-6 Auxiliary Feedwater System Nitrogen Supply to AFW Control Valves (Unit 3)
9.11-7 Auxiliary Feedwater System Steam to Auxiliary Feedwater Pump Turbines (Unit 4)
9.11-8 Auxiliary Feedwater System Auxiliary Feedwater to Steam Generators (Unit 4) 9.11-9 Auxiliary Feedwater System Nitrogen Supply to AFW Control Valves (Unit 4)
9.11-10 Condensate Storage System (Unit 4)
9.11-11 Condensate Storage System (Unit 3)
9.12-1 Post-Accident Containment Vent and Sampling System Flow Diagram (Unit 3)
9.12-2 Post-Accident Containment Vent and Sampling System Flow Diagram (Unit 4)
9.15-1 Emergency Diesel Engine and Oil System DG 3A Air Starting System (Unit 3)
9.15-2 Emergency Diesel Engine and Oil System DG 3B Air Starting System (Unit 3)
9.15-3 Emergency Diesel Engine and Oil System DG 3A Fuel Oil (Unit 3)
9.15-4 Emergency Diesel Engine and Oil System DG 3B Fuel Oil (Unit 3)
9.15-5 Emergency Diesel Engine and Oil System DG 3A LO & Cooling Water
9.15-6 Emergency Diesel Engine and Oil System DG 3B LO & Cooling Water
9.15-7 Emergency Diesel Engine and Oil System EDG 4A Air Starting System (Unit 4)
9.15-8 Emergency Diesel Engine and Oil System EDG 4B Air Starting System (Unit 4)
9.15-9 Emergency Diesel Engine and Oil System EDG 4A Fuel System (Unit 4)
9.15-10 Emergency Diesel Engine and Oil System EDG 4B Fuel System (Unit 4)
9.15-11 Emergency Diesel Engine and Oil System DG 4A LO & Cooling Water
9.15-12 Emergency Diesel Engine and Oil System DG 4B LO & Cooling Water
9.16-1 Turbine Building Ventilation Load Center & SWGR Rooms Chilled Water System - Train A (Unit 3)
9.16-2 Turbine Building Ventilation Load Center & SWGR Rooms Chilled Water System - Train B (Unit 3)
9-xiv Revised 04/17/2013
LIST OF FIGURES (Continued)
Figure Title
9.16-3 Turbine Building Ventilation Load Center & SWGR Rooms Chilled Water System - Train A (Unit 4)
9.16-4 Turbine Building Ventilation Load Center & SWGR Rooms Chilled Water System - Train B (Unit 4)
9.17-1 Instrument Air System (Unit 3)
9.17-2 Instrument Air System (Unit 4)
9-xv Revised 04/17/2013 9.0 AUXILIARY AND EMERGENCY SYSTEMS The Auxiliary and Emergency Systems are supporting systems required to ensure
the safe operation or servicing of the Reactor Coolant System (detailed in
Section 4). Various components in some of the systems are shared by Unit 3
and Unit 4: Appendix A discusses this sharing and lists the shared components.
In some cases, the dependable operation of several systems is required to
protect the Reactor Coolant System by controlling system conditions within
specified operating limits. Certain systems are required to operate under
emergency conditions.
This section analyzes component malfunctions, inadvertent interruptions of
system operation, or partial system failure and how the design avoids hazardous
or unsafe conditions.
The systems considered under this category are:
a) Chemical and Volume Control System
b) Auxiliary Coolant System
c) Sampling System
d) Facility Service Systems
e) Fuel Handling System
f) Equipment and System Decontamination
g) Auxiliary Building Ventilation System
h) Control Room Ventilation System
i) Containment Ventilation System
j) Auxiliary Feedwater System
9-1 9.1 GENERAL DESIGN CRITERIA The criteria which apply primarily to other systems discussed in other Sections are listed and cross-referenced because details of directly related systems and equipment are given in this Section. Those criteria which are specific to one of
the Auxiliary and Emergency Systems are listed and discussed in the
appropriate system design basis section.
9.1.1 RELATED CRITERIA
Reactivity Control Systems Malfunction
Criterion: The reactor protection systems shall be capable of protecting against any single malfunction of the reactivity control system,
such as unplanned continuous withdrawal (not ejection or dropout)
of a control rod, by limiting reactivity transients to avoid
exceeding acceptable fuel damage limits. (GDC 31)
As described in Section 7 and justified in Section 14, the Reactor Protection Systems are designed to limit reactivity transients to DNBR ~ 1.30 due to any
single malfunction in the deboration controls.
Engineered Safety Features Performance Capability
Criterion: Engineered Safety Features such as the emergency core cooling system and the containment heat removal system shall provide sufficient performance capability to accommodate the failure of any single active component without resulting in undue risk to the health and safety of the public. (GDC 41)
Each of the auxiliary cooling systems which serves an emergency function provides sufficient capability in the emergency operational mode to accommodate
any single failure of an active component and still function in a manner to
avoid undue risk to the health and safety of the plant personnel and the public.
9.1-1 Containment Heat Removal Systems Criterion: Where an active heat removal system is needed under accident conditions to prevent exceeding containment design pressure this system shall perform its required function, assuming failure of any single active component. (GDC 52)
Each of the auxiliary cooling systems which serves an emergency function to prevent exceeding containment design pressure, provides sufficient capability in
the emergency operational mode to accommodate any single failure of an active
component and still perform its required function.
9.1-2 9.2 CHEMICAL AND VOLUME CONTROL SYSTEM The Chemical and Volume Control System a) adjusts the concentrations of
chemical neutron absorber for chemical reactivity control, b) maintains the
proper water inventory in the Reactor Coolant System, including makeup for
system leakages, c) provides the required seal water flow for the reactor
coolant pump shaft seals, d) processes reactor coolant letdown, e) maintains
the proper concentration of corrosion inhibiting chemicals in the reactor
coolant and, f) maintains the reactor coolant and corrosion activities to
within design levels. The system is also used to fill and hydrostatically test
9.2.1 DESIGN BASES
Redundancy of Reactivity Control Criterion: Two independent reactivity control systems, preferably of different principles, shall be provided. (GDC 27)
In addition to the reactivity control achieved by the rod cluster control
assemblies (RCCA) as detailed in Section 7, reactivity control is provided by
the Chemical and Volume Control System which regulates the concentration of
boric acid solution neutron absorber in the Reactor Coolant System. The
system is designed to limit the rate of uncontrolled or inadvertent reactivity
changes to a value which provides the operators sufficient time to correct the
situation prior to system parameters exceeding design limits.
Reactivity Hot Shutdown Capability
Criterion: The reactivity control system provided shall be capable of making and holding the core subcritical from any hot standby or hot operating condition. (GDC 28)
The reactivity control systems provided are capable of making and holding the
core subcritical from any hot standby or hot operating condition, including
those resulting from power changes. The maximum excess reactivity expected for
the core occurs for the cold, clean condition at the beginning of life of the
initial RCC assemblies and boric acid. The full length RCC assemblies are
divided into two categories comprising control and shutdown groups.
9.2-1 Revised 04/17/2013 The control group, used in combination with boric acid, provides control of the
reactivity changes of the core throughout the life of the core at power
conditions. This group of RCC assemblies is used to compensate for short term
reactivity changes at power such as those produced due to variations in reactor
power requirements or in coolant temperature. The boric acid control is used
to compensate for the more slowly occurring changes in reactivity throughout
core life such as those due to fuel depletion and fission product buildup and
decay.
Reactivity Shutdown Capability
Criterion: One of the reactivity control systems provided shall be capable of making the core subcritical under any anticipated operating condition (including anticipated operational transients)
sufficiently fast to prevent exceeding acceptable fuel damage
limits. Shutdown margin should assure subcriticality with the
most reactive control rod fully withdrawn. (GDC 29)
The reactor core, together with the reactor control and protection system is
designed so that the minimum allowable DNBR is no less than 1.30 and there is
no fuel melting during normal operation including anticipated transients. The
shutdown groups are provided to supplement the control group of RCC assemblies
to make the reactor at least one per cent subcritical (k eff) = 0.99) following trip from any credible operating condition to the hot, zero power condition
assuming the most reactive RCC assembly remains in the fully withdrawn
position.
Sufficient shutdown capability is also provided to maintain the core
subcritical for the most severe anticipated cooldown transient associated with
a single active failure, e.g., accidental opening of a steam bypass or relief
valve. This is achieved with combination of control rods and automatic boron
addition via the Safety Injection System with the most reactive rod assumed to
be fully withdrawn.
9.2-2 Revised 04/17/2013 Reactivity Hold-Down Capability Criterion: The reactivity control systems provided shall be capable of making the core subcritical under credible accident conditions with appropriate margins for contingencies and limiting any subsequent
return to power such that there will be no undue risk to the
health and safety of the public. (GDC 30)
Normal reactivity shutdown capability is provided by RCC assemblies, with boric
acid injection used to compensate for the long term xenon decay transient and
for cooldown. Any time that the unit is at power, the quantity of boric acid
retained in the boric acid tanks and ready for injection will always exceed
that quantity required to support a cooldown to cold shutdown conditions
without letdown. Under these conditions, adequate boration can be achieved
simply by providing makeup for coolant contraction from a boric acid tank and
the refueling water storage tank. The minimum volume maintained in the boric
acid tanks, therefore, is that volume necessary to increase the RCS boron
concentration during the early phase of the cooldown of each unit, such that, subsequent use of the refueling water storage tank for contraction makeup will
maintain the required shutdown margin throughout the remaining cooldown. In
addition, the boric acid tanks have sufficient boric acid solution to achieve
cold shutdown for each unit if the most reactive RCCA is not inserted. This
quantity will always exceed the quantity of boric acid required to bring the
reactor to hot standby and to compensate for subsequent xenon decay.
The boric acid solution is transferred from the boric acid tanks by boric acid
pumps to the suction of the charging pumps which inject boric acid into the
reactor coolant. Any charging pump and any boric acid transfer pump can be
operated from diesel generator power on loss of offsite power. Boric acid can
be injected by one charging pump and one boric acid transfer pump at a rate
which shuts the reactor down with no rods inserted in less than forty minutes
when a feed and bleed process is utilized (less than 30 minutes when the
available pressurizer volume is utilized). In forty additional minutes, enough
boric acid can be injected to compensate for xenon decay although xenon decay
below the equilibrium operating level will not begin until approximately 12-15
hours after shutdown. If two boric acid pumps and two charging pumps are
available, these time periods are reduced. Additional boric acid is employed
if it is desired to bring the reactor to cold shutdown conditions.
9.2-3 Revised 04/17/2013 C26 On the basis of the above, the injection of boric acid is shown to afford
backup reactivity shutdown capability, independent of control rod clusters
which normally serve this function in the short term situation. Shutdown for
long term and reduced temperature conditions can be accomplished with boric
acid injection using redundant components.
Codes and Classifications
All pressure retaining components (or compartments of components) which are
exposed to reactor coolant, comply with the following codes:
a) System pressure vessels - ASME Boiler and Pressure Vessel Code,Section III, Class C, including para. N-2113, original equipment;Section III, Class 3 or Class 2, post-steam generator repair equipment.
b) System valves, fittings and piping - USAS B31.1, including nuclear code cases.
System component code requirements are tabulated in Table 9.2-1.
The tube and shell sides on the regenerative heat exchanger and the tube side
of the excess letdown exchanger are designed to ASME Section III, Class C.
This designation is based on the following considerations: (a) each exchanger
is connected to the reactor coolant system by lines equal to or less than 3",
and (b) each is located inside the containment. Analyses show that the
accident associated with a 3" line break does not result in clad damage or
failure. Reactor coolant escaping during such an accident is confined to the
containment building.
9.2.2 SYSTEM DESIGN AND OPERATION
Various components of the Chemical and Volume Control System are shared by the
two units. These components are shown in Table 9.2-3 and discussion concerning
the sharing is given in Appendix A. The following discussion is for the
Chemical and Volume Control System for one unit and applies equally to either
unit.
9.2-4 Revised 04/17/2013 The Chemical and Volume Control System, shown in Figures 9.2-1 through 9.2-10, provides a means for injection of boric acid, chemical additions for corrosion control, and reactor coolant cleanup and degasification. This system also adds makeup water to the Reactor Coolant System, processes water let down from the Reactor Coolant System, and provides seal water injection to the reactor coolant pump seals. Materials in contact with the reactor coolant are austenitic stainless steel or equivalent corrosion resistant materials.
System components whose design pressure and temperature are less than the Reactor Coolant System design limits are provided with overpressure protective devices.
System discharges from overpressure protective devices (safety valves) and system leakages are directed to closed systems. Effluents removed from such closed systems are monitored and discharged under controlled conditions.
During operation, reactor coolant flows through the letdown line from a loop cold leg on the discharge side of the pump and, after processing is returned to the cold leg of another loop on the discharge side of the pump via a charging line. An alternate charging connection is provided on a loop hot leg. An excess letdown line is also provided for removing coolant from the reactor coolant system. The largest required charging pump flow to maintain normal operation with 45 gpm letdown orifice, 7.5 gpm RCP seals runoff and 1 gpm RCS leakage is supplied by one charging pump in operation.
Each of the connections to the Reactor Coolant System has an isolation valve located close to the loop piping. In addition, a check valve is located downstream of each charging line isolation valve. Reactor coolant entering the Chemical and Volume Control System flows through the shell side of the regenerative heat exchanger where its temperature is reduced. The coolant then flows through a letdown orifice which reduces the coolant pressure. The cooled, low pressure water leaves the containment building and enters the auxiliary building where it undergoes a second temperature reduction in the tube side of the non-regenerative heat exchanger followed by a second pressure reduction by the low pressure letdown valve. After normally passing through one of the CVCS letdown demineralizer(s), where impurities are removed, coolant flows through the reactor coolant filters and enters the volume control tank through a spray nozzle.
9.2-5 Revised 07/15/2016 C28 Hydrogen is automatically supplied, as determined by pressure control, to the
vapor space in the volume control tank, which is predominantly hydrogen and
water vapor. The hydrogen supply line has an excess flow valve (Figure 9.2-11)
upstream and outside of the Charging Pump Room which will automatically close
if the hydrogen flow increases beyond its specific flow setting due to a
downstream pipe rupture thus eliminating possible release of hydrogen into the
charging pump room. The hydrogen within this tank is supplied to the reactor
coolant for maintaining a low oxygen concentration. Fission gases are
periodically removed from the system by venting the volume control tank to the
Waste Disposal System.
During plant shutdown, dissolved hydrogen in the RCS must be removed prior to
opening the RCS for maintenance or refueling. Hydrogen removal can be
performed in either or a combination of the following methods: 1) The VCT level
can be raised and lowered repeatedly to "burp" the hydrogen-rich VCT gas space
to the waste gas system. When the level is lowered, fresh nitrogen is admitted
to the gas space. 2) Hydrogen peroxide is added to the RCS to react with the
dissolved hydrogen to form water.
The charging pumps take suction from the volume control tank and return the
coolant to the Reactor Coolant System through the tube side of the regenerative
heat exchanger.
A newly borated bed of mixed resin (H-BO 3 form) is used intermittently to remove excess lithium which is formed from B 10 (n,)Li 7 reaction. After saturation with lithium the mixed bed (Li-BO
- 3) is ready for service as a mixed bed demineralizer for purification.
Boric acid is dissolved in the batching tank to a concentration of
approximately 3.0 to 4.0 percent by weight. A transfer pump is used to
transfer the batch to the boric acid tanks. Small quantities of boric acid
solution are metered from the discharge of an operating transfer pump for
blending with primary water as makeup for normal leakage or for increasing the
reactor coolant boron concentration during normal operation. The solubility
limit for 4.0 weight percent boric acid is reached at a temperature of 57 o F. A 5 o F room temperature measurement uncertainty is added to obtain ambient room temperature limit of 62 o F. This temperature is sufficiently low that the normally expected ambient temperatures within the auxiliary building will
maintain boric acid solubility.
9.2-6 Revised 04/17/2013 C26C26 Excess liquid effluents containing boric acid flow from the Reactor Coolant
System through the letdown line and are collected in the holdup tanks. As
liquid enters the holdup tanks, the nitrogen cover gas is displaced to the gas
decay tanks in the Waste Disposal System through the waste vent header. The
concentration of boric acid in the holdup tanks varies throughout core life
from the refueling concentration to essentially zero at the end of the core
cycle. A recirculation pump is provided to transfer liquid from one holdup
tank to another and to recirculate the contents of individual holdup tanks.
Liquid effluent in the holdup tanks is processed as a batch operation. This
liquid is pumped to the waste holdup tank for processing as liquid waste.
A fresh bed of mixed resin (H-OH form) can be used intermittently to remove
boron from the reactor coolant near the end of core life. When the mixed bed has been saturated with Boron (H-BO 3), it is ready for use in removing cesium and lithium.
During cooldown when the residual heat removal loop is operating and the
letdown orifices are not in service, a flow path is provided to remove
corrosion impurities and fission products. A portion of the flow leaving the
residual heat exchangers passes through the non-regenerative heat exchanger, mixed bed demineralizers, reactor coolant filters and volume control tank. The
fluid is then transferred, via the charging pump or gravity drain, through the
tube side of the regenerative heat exchanger into the Reactor Coolant System.
Expected Operating Conditions
Tables 9.2-2, 9.2-3, and 9.2-5 list the system performance requirements, data
for individual system components and reactor coolant equilibrium activity
concentration. Table 9.2-4 supplements Table 9.2-5.
Reactor Coolant Activity Concentration
The parameters used in the calculation of the reactor coolant fission product
inventory, including pertinent information concerning the expected coolant
cleanup flow rate and demineralizer effectiveness, are presented in Table
9.2-4.
9.2-7 Revised 04/17/2013 The results of the calculations are presented in Table 9.2-5. In these
calculations defects in one percent of the fuel rods are assumed to be present
at initial core loading and are uniformly distributed throughout the core and
the fission product escape rate coefficients are therefore based upon an
average fuel temperature.
The fission product activity in the reactor coolant during operation with small
cladding pinholes or cracks in 1% of the fuel rods is computed using the
following differential equations:
For parent nuclides in the coolant,
for daughter nuclides in the coolant,
where: N = population of nuclide
D = fraction of fuel rods having defective cladding R = purification flow, coolant system volumes per sec.
B o = initial boron concentration, ppm B' = boron concentration reduction rate by feed and bleed, ppm per sec
= removal efficiency of purification cycle for nuclide
= radioactive decay constant v = escape rate coefficient for diffusion into coolant Subscript C refers to core Subscript w refers to coolant Subscript i refers to parent nuclide Subscript j refers to daughter nuclide
9.2-8 Revised 04/17/2013 N )Bt - B B + Rn + ( - N Dv = dt dN wi oii C i wi i N + N )Bt-B B + Rn + ( - N Dv = dt dN wiwj ojj C j wj i J Tritium is produced in the reactor from ternary fission in the fuel, irradiation of boron in the burnable poison rods (during initial fuel cycle
only) and irradiation of boron, lithium and deuterium in the coolant. The
deuterium contribution is less than 0.1 curie per year and may be neglected.
The parameters used in the calculation of tritium production rate are presented
in Table 9.2-6.
Reactor Makeup Control The reactor makeup control consists of a group of instruments arranged to
provide a manually pre-selected makeup composition to the charging pump suction
header or the volume control tank. The makeup control functions are to
maintain desired operating fluid inventory in the volume control tank and to
adjust reactor coolant boron concentration for reactivity and shim control.
Makeup for normal leakage is regulated by the reactor makeup control which is
set by the operator to blend water from the primary water storage tank with
concentrated boric acid to match the reactor coolant boron concentration.
The makeup system also provides concentrated boric acid or primary water to
either increase or decrease the boric acid concentration in the Reactor Coolant
System. To maintain the reactor coolant volume constant, an equal amount of
reactor coolant is let down to the holdup tanks. Should the letdown line be
out of service during operation, sufficient volume exists in the pressurizer to
accept the amount of boric acid necessary for hot standby.
Boration to the cold shutdown concentration is also achievable without letdown
when boration is performed in conjunction with the plant cooldown through the
required makeup for coolant contraction. Specifically, if boric acid is
injected first from the boric acid tanks and then from the refueling water
storage tank to maintain constant pressurizer level during the cooldown, sufficient boric acid will be added to the RCS to maintain the required
Makeup water to the Reactor Coolant System is provided by the Chemical and
Volume Control System from the following sources:
a) The primary water storage tank, which provides water for dilution when the reactor coolant boron concentration is to be reduced.
b) The boric acid tanks, which supply concentrated boric acid solution when reactor coolant boron concentration is to be increased.
9.2-9 Revised 04/17/2013 c) The refueling water storage tank, which supplies borated water for normal or emergency makeup.
d) The chemical mixing tank, which is used to inject small quantities of solution when additions of hydrazine or pH control chemical are necessary.
Makeup is provided to maintain the desired operating fluid inventory in the
Reactor Coolant System. The operator can stop the makeup operation at any time
in any operating mode by remotely closing the makeup stop valves. One primary
water makeup pump and one boric acid transfer pump are normally operated.
A portion of the high pressure charging flow is injected into the reactor
coolant pumps between the pump impeller and the shaft seal so that the seals
are not exposed to high temperature reactor coolant. Part of the flow is the
shaft seal leakage flow and the remainder enters the Reactor Coolant System
through a labyrinth seal on the pump shaft. The shaft seal leakage flow cools
the lower radial bearing, passes through the seals, is cooled in the seal water
heat exchanger, filtered, and returned to the volume control tank.
Seal water inleakage to the Reactor Coolant System requires a continuous letdown of reactor coolant to maintain the desired inventory. In addition, bleed and feed of reactor coolant are required for removal of impurities and
adjustment of boric acid in the reactor coolant.
Automatic Makeup
The "automatic makeup" mode of operation of the reactor makeup control provides
boric acid solution preset by the operator to match the boron concentration in
the Reactor Coolant System. The automatic makeup compensates for minor leakage
of reactor coolant without causing significant changes in the coolant boron
concentration.
Under normal operating conditions, the mode selector switch and makeup stop valves are set in the "AUTO" position. A preset low level signal from the
volume control tank level controller causes the automatic makeup control action
to open the makeup stop valve to the charging pump suction, open the
concentrated boric acid control valve and the primary water makeup control
valve.
9.2-10 Revised 04/17/2013 The flow controllers adjust flow so that the concentration of the blend matches
that of the preset concentration. The primary water and the boric acid streams
meet and are mixed in the boric acid blender. Makeup addition to the charging
pump suction header causes the water level in the volume control tank to rise.
At a preset high level point, the makeup is stopped; the primary water makeup
control valve closes, the concentrated boric acid control valve closes and the
makeup stop valve to charging pump suction closes.
Dilution The "dilute" mode of operation permits the addition of a pre-selected quantity
of primary water makeup at a pre-selected flow rate to the Reactor Coolant
System. The operator sets the makeup stop valves to the volume control tank
and to the charging pump suction in the "auto" position, the mode selector
switch to "dilute", the primary water makeup flow controller set point to the
desired flow rate, and the primary water makeup batch integrator to the desired
quantity. If the dilution flow deviates ~5 gpm from the preset flow rate, an
alarm indicates the deviation. One primary water pump runs continuously to
provide makeup water as required. Makeup water is added to the volume control
tank and then goes to the charging pump suction header. Excessive rise of the
volume control tank water level is prevented by automatic actuation (by the
tank level controller) of a three-way diversion valve, which routes the reactor
coolant letdown flow to the holdup tanks. When the preset quantity of primary
water makeup has been added, the batch integrator causes the primary water
makeup control valve to close.
Alternate Dilute
The "Alternate Dilute" mode of operation permits the addition of a pre-selected
quantity of reactor makeup water at a pre-selected flow rate to the Reactor
Coolant System. A primary water pump is normally operating. Before actuation
of the "Start" Control Station, the operator sets the mode selector switch to "Alternate Dilute", the reactor makeup water flow controller set point to the
desired flow rate, and the reactor makeup water "batch integrator" to the
desired quantity.
9.2-11 Revised 04/17/2013 The operator actuates the "Start" Control Station. This mode of operation is similar to the "dilute" mode except both the makeup stop valves to the Volume
Control tank and charging pump suction are opened. Primary water is
simultaneously added in the volume control tank and in the charging pump
suction header. By adding primary water at both locations the delay time for
injecting primary water is reduced and hydrogen is added to a portion of the
primary water flow. Excessive water level in the volume control tank is
prevented by automatic actuation of a three-way diversion valve (by the tank
level controller), which routes the reactor coolant letdown flow to the hold-up
tanks. When the preset quantity of reactor makeup water has been added, the
batch integrator causes the reactor makeup water control valves to close. This
mode of control is used when there are daily load changes. After the "Alternate Dilute" mode requirements are satisfied, the operator may return the
mode selector switch back to "Dilute" to permit the addition of reactor makeup
water as required.
Boration The "borate" mode of operation permits the addition of a pre-selected quantity
of concentrated boric acid solution at a pre-selected flow rate to the Reactor
Coolant System. The operator sets the makeup stop valves to the volume control
tank and to the charging pump suction in the "Auto" position, the mode selector
switch to "borate", the concentrated boric acid flow controller set point to
the desired flow rate, and the concentrated boric acid batch integrator to the
desired quantity. If the boration flow deviates 1.5 gpm from the preset flow
rate, an alarm indicates the deviation. Placing the reactor makeup control
switch in the "start" position starts the selected boric acid transfer pump, and permits the concentrated boric acid to be added to the charging pump
suction header. The total quantity added in most cases is so small that it has
only a minor effect on the volume control tank level. When the preset quantity
of concentrated boric acid solution has been added, the batch integrator causes
the concentrated boric acid transfer pump to stop and the concentrated boric
acid control valve to close.
9.2-12 Revised 04/17/2013 The capability to add boron to the reactor coolant is sufficient so that no limitation is imposed on the rate of cooldown of the reactor upon shutdown. The
maximum rates of boration and the equivalent coolant cooldown rates are given
in Table 9.2-2. One set of values is given for the addition of boric acid from
a boric acid tank with one transfer and one charging pump operating. The other
set assumed the use of refueling water but with two of the three charging pumps
operating. The rates are based on full power operating temperature and on the
end of the core life when the moderator temperature coefficient is most
negative.
By manual action of the operator, the boric acid transfer pump can discharge
directly to the charging pump suction and bypass the blender and volume control
tank.
Alarm Functions
The reactor makeup control is provided with alarm functions to call the
operator's attention to the following conditions:
a) Deviation of primary water makeup flow rate from the control set point
b) Deviation of concentrated boric acid flow rate from the control set point
c) If the reactor makeup control selector is not set for the automatic makeup control mode, a volume control tank low level alarm occurs at 12%
of tank level.
Charging Pump Control
Three positive displacement variable speed drive charging pumps are used to
supply charging flow to the Reactor Coolant System.
The speed of each pump can be controlled manually or automatically. During
normal operation, only one of the three pumps is automatically controlled.
During normal operation, only one charging pump is operating and the speed is
modulated in accordance with pressurizer level. During load changes the
pressurizer level set point is varied automatically to compensate partially for
the expansion or contraction of the reactor coolant associated with the Tavg
changes.
9.2-13 Revised 04/17/2013 C26 Tavg compensates for power changes by varying the pressurizer level set points
in conjunction with pressurizer level for charging pump control. The level set
points are varied between 22 and 60 percent of the adjustable range depending
on the power level at a full load Tavg of 583 o F. Charging pump speed does not change rapidly with pressurizer level variations due to the reset action of the
pressurizer level controller.
If the pressurizer level increases, the speed of the pump decreases, likewise
if the level decreases, the speed increases. If the charging pump on automatic
control reaches the high speed limit, an alarm is actuated and a second
charging pump is manually started. If the speed of the charging pump on
automatic control does not decrease and the second charging pump is operating
at maximum speed, the third charging pump can be started and its speed manually
regulated. If the speed of the charging pump on automatic control decreases to
its minimum value, an alarm is actuated and the speed of the pumps on manual
control is reduced.
Components
A summary of principal component data is given in Table 9.2-3.
Regenerative Heat Exchanger
The regenerative heat exchanger is a multiple shell and U-tube unit which is
designed to recover the heat from the letdown stream by reheating the charging
stream during normal operation. This exchanger also limits the temperature
rise which occurs at the letdown orifices during periods when letdown flow
exceeds charging flow by a greater margin than at normal letdown conditions.
The letdown stream flows through the shell of the regenerative heat exchanger
and the charging stream flows through the tubes. The unit is made of
austenitic stainless steel, and is of all-welded construction.
Letdown Orifices
One of the three letdown orifices controls flow of the letdown stream during
normal operation and reduces the pressure to a value compatible with the
non-regenerative heat exchanger design. These orifices are used in parallel to
pass maximum purification flow at normal Reactor Coolant System operating
pressure.
9.2-14 Revised 04/17/2013 C26 The 45 gpm orifice is normally in service to minimize charging pump wear, and
two 60 gpm orifices are normally available. The orifices are placed in and
taken out of service by remote manual operation of their respective isolation
valves. A combination of the standby orifices may be used in parallel with the
normally operating orifice in order to increase letdown flow when the Reactor
Coolant System pressure is below normal or when additional letdown is desired (e.g., for RCS cleanup). This arrangement provides a full standby capacity for
control of letdown flow. Each orifice consists of bored pipe made of
austenitic stainless steel.
Non-Regenerative (letdown) Heat Exchanger
The non-regenerative heat exchanger cools the letdown stream to the operating
temperature of the mixed bed demineralizers. Reactor coolant flows through the
tube side of the exchanger while component cooling water flows through the
shell. The letdown stream outlet temperature is automatically controlled by
TCV-*-144 or manually controlled by throttling manual valve *-834. The unit is
a multiple-pass-tube heat exchanger. All surfaces in contact with the reactor
coolant are austenitic stainless steel, and the shell is carbon steel.
CVCS Letdown Demineralizers Five flushable demineralizers maintain reactor water chemistry. The main
demineralizers are the A, B, D, and E demineralizers. The C demineralizer has
smaller capacity and may be connected in series with either the A or B
demineralizers.
A hydrogen ion form cation resin and a hydroxyl form anion resin are initially charged into the demineralizers. This resin bed is used to reduce RCS boron
concentration (usually near the end of core life).
When saturated with boron, the resin is converted to an H-BO 3 form and is used intermittently to control the concentration of lithium-7 which builds up in the
coolant from the B 10 (n,)Li 7 reaction. In addition, each of the main demineralizers have sufficient capacity to maintain the cesium-137 concentration in the coolant below 1.0 c/cc with one percent defective fuel.
The demineralizer would be used intermittently to control cesium.
9.2-15 Revised 04/17/2013 When saturated with lithium, the resin is converted to an Li 7-BO 3 form and is used to maintain reactor coolant purity. This form of resin removes both fission and corrosion products. In this form, the resin bed is designed to
reduce the concentration of isotopes in the purification stream (except for
cesium, yttrium, and molybdenum) by a minimum factor of 10. Each of the main
demineralizers has sufficient capacity after operation for one core cycle with
one percent defective fuel rods to reduce the activity of the primary coolant
to refueling concentration.
With the exception of the C demineralizer, each demineralizer is sized to
accommodate the maximum letdown flow. The number of demineralizers available
provides flexibility and ensures standby capacity should a demineralizer become
exhausted during operation. Additionally, the demineralizers may be charged with specialized resins (OH
- Anion, H+ Cation, or Li 7-OH mixed bed) if desired.
The C demineralizer is limited in use to 60 gpm letdown flow, and if used, is placed in series with either A or B demineralizers.
The demineralizers are made of austenitic stainless steel and are provided with
suitable connections to facilitate resin replacement when required. The
vessels are equipped with resin retention screens.
Resin Fill Tank The resin fill tank is used to charge fresh resin to the demineralizers. The line from the conical bottom of the tank is fitted with a dump valve and may be
connected to any one of the demineralizer fill lines. The demineralizer water
and resin slurry can be sluiced into the demineralizer by opening the dump
valve. The tank, designed to hold approximately one third of the resin volume
of demineralizers A, B, D, or E, is made of austenitic stainless steel.
Reactor Coolant Filter The three filters collect resin fines and particulates larger than 25 microns from the letdown stream. The vessel is made of austenitic stainless steel, and
is provided with connections for draining and venting. Design flow capacity of
the filters shall at least be equal to the maximum purification flow rate.
Bases considered to determine when the reactor coolant filter will be replaced
are: (1) a high pressure differential across the filter, (2) a set time limit
after which the filter will be replaced, and (3) when a portable radiation
monitor shows radiation in excess of established limits.
9.2-16 Revised 04/17/2013 Volume Control Tank The volume control tank collects the excess water released from zero power to
full power, that is not accommodated by the pressurizer. It also receives the
excess coolant release caused by the deadband in the reactor control
temperature instrumentation. Overpressure of hydrogen gas is maintained in the
volume control tank to control the hydrogen concentration in the reactor
coolant at 25 to 50 cc per kg of water.
The reactor coolant hydrogen concentration can be reduced to 15 cc per kg prior
to shutdown, provided that the operating period does not exceed two days and
the reactor coolant hydrogen is monitored once per shift.
A spray nozzle is located inside the tank on the inlet line from the reactor
coolant filter. This spray nozzle provides intimate contact of the gas and
liquid phases. A vent path discharging to the Waste Disposal System permits
removal of gaseous fission products which are stripped from the reactor coolant
and collected in this tank. The volume control tank also acts as a head tank
for the charging pumps and a reservoir for the leakage from the reactor coolant
pump controlled leakage seal. The tank is constructed of austenitic stainless
steel.
Charging Pumps
Three charging pumps inject coolant into the Reactor Coolant System. The pumps
are the variable speed positive displacement type, and all parts in contact
with the reactor coolant are fabricated of austenitic stainless steel and other
material of adequate corrosion resistance. Pump seal leakage is collected and
routed to the waste holdup tanks for disposal. In order to minimize this
leakage, which has proven to be a burden on the waste disposal systems of
previous nuclear units, the pumps were modified after installation. This
modification which has been successful in other projects, consists of new
design plungers and seals, with a seal head tank. The pump design precludes
the possibility of lubricating oil contaminating the charging flow, and the
integral discharge valves act as check valves. Hydraulic accumulators are
installed on the suction and discharge piping of the charging pumps to
attenuate vibration and acoustically decouple this piping from the pumps.
9.2-17 Revised 04/17/2013 Each pump is designed to provide the full charging flow and the reactor coolant
pump seal water supply with normal seal leakage. Each pump is designed to
provide rated flow against a pressure equal to the sum of the Reactor Coolant
System maximum pressure (existing when the pressurizer power operated relief
valve is operating) and the piping, valve and equipment pressure losses of the
charging system at the design charging flows.
One of the three charging pumps can be used to hydrotest the Reactor Coolant
System. The pumps are normally energized manually from the control room, and
flow is automatically controlled by pressurizer level.
Chemical Mixing Tank
The chemical mixing tank is used to prepare caustic solutions for pH control, hydrazine for oxygen scavenging and hydrogen peroxide for shutdown chemistry
control.
The capacity of the chemical mixing tank is determined by the quantity of 35
percent hydrazine solution necessary to increase the concentration in the
reactor coolant by 10 ppm. This capacity is more than sufficient to prepare
the solution of pH control chemical for the Reactor Coolant System.
The chemical mixing tank is made of austenitic stainless steel.
Excess Letdown Heat Exchanger
The excess letdown heat exchanger cools reactor coolant letdown flow until the
flow rate is equal to the nominal injection rate through the reactor coolant
pump labyrinth seal, if letdown through the normal letdown path is blocked.
The unit is designed to reduce the letdown stream temperature from the cold leg temperature to 195
°F. The letdown stream flows through the tube side and component cooling water is circulated through the shell side. All surfaces in contact with reactor coolant are austenitic stainless steel and the shell is
carbon steel. All tube joints are welded.
Seal Water Heat Exchanger
The seal water heat exchanger removes heat from the reactor coolant pump seal
water returning to the volume control tank and reactor coolant discharge from
the excess letdown heat exchanger. Reactor coolant flows through the tubes and
component cooling water is circulated through the shell side.
9.2-18 Revised 04/17/2013 C26 The tubes are welded to the tube sheet because leakage could occur in either
direction, resulting in undesirable contamination of the reactor coolant or
component cooling water. All surfaces in contact with reactor coolant are
austenitic stainless steel and the shell is carbon steel.
The unit is designed to cool the excess letdown flow and the seal water flow to
the temperature normally maintained in the volume control tank if all the
reactor coolant pump seals are leaking at the maximum design leakage rate.
Seal Water Filter
The two filters collect particulates from the reactor coolant pump seal water
return and from the excess letdown heat exchanger flow. The filter is designed
to pass the sum of the excess letdown flow and the maximum design leakage from
the reactor coolant pump seals. The vessel is constructed of austenitic
stainless steel.
Seal Water Injection Filters
Two filters are provided in parallel, each sized for the injection flow. They
collect particulates from the water supplied to the reactor coolant pump seal.
Boric Acid Filter
The boric acid filter collects particulates from the boric acid solution being
pumped to the charging pump suction line. The filter is designed to pass the
design flow of two boric acid pumps operating simultaneously. The vessel is
constructed of austenitic stainless steel and the filter elements are
disposable synthetic cartridges.
Boric Acid Tanks
The boric acid tank capacities are sized to store sufficient boric acid
solution to support a cooldown to cold shutdown conditions without letdown.
Under these conditions, adequate boration can be achieved simply by providing
makeup for coolant contraction from a boric acid tank and the refueling water
storage tank. The minimum volume maintained in the boric acid tanks, therefore, is that volume necessary to increase the RCS boron concentration
during the early phase of the cooldown of each unit, such that, subsequent use
of the refueling water storage tank for contraction makeup will maintain the
required shutdown margin throughout the remaining cooldown.
9.2-19 Revised 04/17/2013 In addition, the boric acid tanks have sufficient boric acid solution to
achieve cold shutdown for each unit if the most reactive RCCA is not inserted.
The concentration of boric acid solution in storage is maintained between 3.0
and 4.0 percent by weight. Periodic manual sampling is performed and
corrective action is taken, if necessary, to ensure that these limits are
maintained. Therefore, measured amounts of boric acid solution can be
delivered to the reactor coolant to control the concentration. The combination
overflow and breather vent connection has a water loop seal to minimize vapor
discharge during storage of the solution. The tanks are constructed of
austenitic stainless steel.
Batching Tank
The batching tank is sized to hold several days makeup supply of boric acid
solution for the boric acid tank. The basis for makeup is reactor coolant
leakage of 1/2 gpm at beginning of core life. The tank may also be used for
solution storage. A local sampling point is provided for verifying the
solution concentration prior to transferring it to the boric acid tank or for
draining the tank.
The tank manway is provided with a removable screen to prevent entry of foreign particles. In addition, the tank is provided with an agitator to improve
mixing during batching operations. The tank is constructed of austenitic
stainless steel, and is not used to handle radioactive substances.
Boric Acid Transfer Pumps
Two 100% capacity centrifugal pumps per unit are used to circulate or transfer chemical solutions. The pumps circulate boric acid solution through the boric
acid tanks and inject boric acid into the charging pump suction header.
Although one pump is normally used for boric acid batching and transfer and the other for boric acid injection, either pump may function as standby for the
other. The design capacity of each pump is equal to the normal letdown flow
rate. The design head is sufficient, considering line and valve losses, to
deliver rated flow to the charging pump suction header when volume control tank
pressure is at the maximum operating value (relief valve setting). All parts
in contact with the solutions are austenitic stainless steel and other
adequately corrosion-resistant material.
9.2-20 Revised 04/17/2013 C26C26 The transfer pumps are operated either automatically or manually from the
control room or from a local control panel. The reactor makeup control
operates one of the pumps automatically when boric acid solution is required
for makeup or boration.
Boric Acid Blender
The boric acid blender promotes thorough mixing of boric acid solution and reactor makeup water from the reactor coolant makeup circuit. The blender
consists of a conventional pipe fitted with a perforated tube insert. All
material is austenitic stainless steel. The blender decreases the pipe length
required to homogenize the mixture for taking a representative local sample.
Recycle Process
The recycle process is common to Units 3 and 4 and the description below is of the components furnished to serve both units.
Holdup Tanks
Three holdup tanks contain radioactive liquid which enters the tank from the letdown line. The liquid is released from the Reactor Coolant System during
startup, shutdowns, load changes and from boron dilution to compensate for
burnup. The contents are processed through the waste holdup tank.
The three liquid storage tanks' capacity is approximately four Reactor Coolant
System volumes. The tanks are constructed of austenitic stainless steel.
Each tank is equipped with relief devices for external and internal
overpressure protection. Two vacuum breaker valves and one relief valve on
each tank are set as described in Table 9.2-3.
Holdup Tank Recirculation Pump
The holdup tank recirculation pump is used to mix the contents of a holdup tank
or transfer the contents of one holdup tank to another holdup tank. The wetted
surface of this pump is constructed of austenitic stainless steel.
9.2-21 Revised 04/17/2013 Gas Stripper Feed Pumps
The three gas stripper feed pumps are used to transfer the contents of the
holdup tanks to the waste holdup tank #1. One pump is normally used during the
transfer operation. The non-operating pumps are maintained in standby and are
available for operation in the event that the operating pump malfunctions.
These centrifugal pumps are constructed of austenitic stainless steel.
Monitor Tanks
Process holding tanks that are used for bulk storage of waste water. When one
tank is filled, the contents are analyzed prior to release. These tanks are
constructed of stainless steel.
Monitor Tank Pumps
Two monitor tank pumps discharge water from the monitor tanks. Each pump is
sized to empty a monitor tank in approximately 2.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />. The pumps are
constructed of austenitic stainless steel.
Valves Some valves that perform a modulating function are equipped with two sets of
packing and an intermediate leakoff connection that discharges to the Waste
Disposal System. Other valves may have stem leakage control. Globe valves are
installed with flow over the seats when such an arrangement reduces the
possibility of leakage. Basic material of construction is stainless steel for
all valves except the batching tank steam jacket valves which are carbon steel.
Although originally designed for steam service, the source of steam to the
batching tank steam jacket has since been abandoned.
Isolation valves are provided at all connections to the Reactor Coolant System.
Lines entering the reactor containment also have check valves inside the
containment to prevent reverse flow from the containment. Safety related power
operated gate valves were evaluated for their susceptibility to pressure
locking and thermal binding as required by NRC Generic Letters 89-10 and 95-07.
The emergency boration valves (MOV-*-350) have a design feature (a hole
drilled in the upstream disc to provide relief from the inter-disc space) which
preclude the potential for pressure locking as described in the two generic
letters.
9.2-22 Revised 04/17/2013 Relief valves are provided for lines and components that might be pressurized above design pressure by improper operation or component malfunction. The excess letdown line is provided with thermal overpressure protection from post accident containment heat up (GL 96-06). Pressure relief for the tube side of the regenerative heat exchanger is provided by a bypass line around valve CV-*-310A. Relief valves settings and capacities are given in Table 9.2-3.
Turkey Point has manual operating features for selected air-operated valves as described in the Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4 (Reference 1) in the Chemical and Volume Control System. The installation of these features provides a manual means of operating these valves if the valve misoperates.
Piping All Chemical and Volume Control System piping handling radioactive liquid is austenitic stainless steel. All piping joints and connections are welded, except where flanged connections are required to facilitate equipment removal for maintenance and hydrostatic testing.
9.2.3 SYSTEM DESIGN EVALUATION
Availability and Reliability
A high degree of functional reliability is assured in this system by providing standby components where performance is vital to safety and by assuring fail-safe response to the most probable mode of failure.
The system has three charging pumps, each capable of supplying the normal reactor coolant pump seal and makeup flow.
The electrical equipment of the Chemical and Volume Control System is arranged so that multiple items receive their power from various 480 volt buses (refer to Section 8.2). Each of the three charging pumps is powered from separate 480 volt buses.
9.2-23 Revised 09/20/2016 C28 The two boric acid transfer pumps are also powered from separate 480 volt buses. One charging pump and one boric acid transfer pump are capable of
meeting cold shutdown requirements shortly after full-power operation. In
cases of loss of AC power, a charging pump and a boric acid transfer pump can
be placed on the emergency diesels if necessary.
Control of Tritium
The Chemical and Volume Control System is used to control the concentration of
tritium in the Reactor Coolant System. Essentially all of the tritium is in
chemical combination with oxygen as a form of water. Therefore, any leakage of
coolant to the containment atmosphere carries tritium in the same proportion, as it exists in the coolant. Thus, the level of tritium in the containment
atmosphere, when it is sealed from outside air ventilation, is a function of
tritium level in the reactor coolant, the cooling water temperature at the
cooling coils, which determines the dew point temperature of the air, and the
presence of leakage other than reactor coolant as a source of moisture in the
containment air.
There are two major considerations with regard to the presence of tritium:
a) Possible plant personnel hazard during access to the containment.
Leakage of reactor coolant during operation with a closed containment
causes an accumulation of tritium in the containment atmosphere. It is
desirable to limit the accumulation to allow containment access.
b) Possible public hazard due to release of tritium to the plant environment. Neither of these considerations is limiting in this plant.
The concentration of tritium in the reactor coolant is maintained at a level
which precludes personnel hazard during access to the containment. This is
achieved by discharging processed letdown water to the circulating water
discharge
Leakage Prevention
Quality control of the material and the installation of the Chemical and Volume
Control valves and piping, which are designated for radioactive service, is
provided in order to essentially eliminate leakage to the atmosphere. The
components designated for radioactive service are provided with welded
connections to prevent leakage to the atmosphere.
9.2-24 Revised 04/17/2013 However, flanged connections are provided in each charging pump suction and
discharge, on each boric acid pump suction and discharge, on the relief valves
inlet and outlet, on three-way valves and on the flow meters to permit removal
for maintenance. Holdup tanks are provided with threaded vacuum breakers.
The positive displacement charging pumps stuffing boxes are provided with
leakoffs to collect reactor coolant before it can leak to the atmosphere. All
valves which are larger than 2 inches and which are designated for radioactive service at an operating fluid temperature above 212
°F were originally provided with a stuffing box and lantern leakoff connections. The leakoff connection and double set of packing may not be applicable since industry testing and
experience has demonstrated better performance with a standard single packing
set. Leakage to the atmosphere is essentially zero for these valves. All
control valves are either provided with stuffing box and leakoff connections or
are totally enclosed. Leakage to the atmosphere is essentially zero for these
valves.
Diaphragm valves are provided where the operating pressure and the operating
temperature permit the use of these valves. Leakage to the atmosphere is
essentially zero for these valves.
Incident Control
The letdown line and the reactor coolant pumps seal water return line penetrate
the containment. The letdown line contains three air-operated valves inside
the containment and one air-operated valve outside the containment which are
automatically closed by the containment isolation signal.
The reactor coolant pumps seal water return line contains motor-operated
isolation valves, outside and inside the containment, which are automatically
closed by the containment isolation signal.
The three seal water injection lines to the reactor coolant pumps and the
charging line are inflow lines penetrating the containment. Each line contains
two check valves inside the containment. The first of the two check valves
from containment penetration is programmatically tested to provide isolation of
the containment if a break occurs in these lines outside the containment.
9.2-25 Revised 04/17/2013 C26 Malfunction Analysis
To evaluate system safety, failures or malfunctions were assumed concurrent
with a loss of coolant accident and the consequences analyzed are presented in
Table 9.2-7. As a result of this evaluation, it is concluded that proper
consideration has been given to unit safety in the design of the system. If a
rupture were to take place between the reactor coolant loop and the first
isolation valve or check valve, this incident would lead to an uncontrolled
loss of reactor coolant. The analysis of loss of coolant accidents is
discussed in Section 14.
Should a rupture occur in the Chemical and Volume Control System outside the
containment, or at any point beyond the first check valve or remotely operated
isolation valve, actuation of the valve would limit the release of coolant and
assure continued functioning of the normal means of heat dissipation from the
core. For the general case of rupture outside the containment, the largest
source of radioactive fluid subject to release is the contents of the volume
control tank. The consequences of such a release are considered in Section 14.
When the reactor is subcritical; i.e., during cold or hot shutdown, refueling
and approach to criticality, the relative reactivity status (neutron source
multiplication) is continuously monitored and indicated by BF 3 counters and count rate indicators.
Any appreciable increase in the neutron source multiplication, including that
caused by the maximum physical boron dilution rate (See Table 9.2-2), is slow
enough to give ample time to start a corrective action (boron dilution stop
and/or emergency boron injection) to prevent the core from becoming critical.
The maximum dilution rate is based on the abnormal condition of two charging
pumps operating at full speed delivering unborated primary water to the Reactor
Coolant System at a particular time during refueling when the boron
concentration is at the maximum value and the water volume in the system is at
a minimum.
At least two separate and independent flow paths are available for reactor
coolant boration; i.e., the charging line, or the reactor coolant pumps
labyrinths. The malfunction or failure of one component will not result in the
inability to borate the Reactor Coolant System.
9.2-26 Revised 04/17/2013 C26 An alternate flow path is always available for emergency boration of the reactor coolant. As backup to the boration system the operator can align the
refueling water storage tank outlet to the suction of the charging pumps.
Boration during normal operation to compensate for power changes will be
indicated to the operator from the flow indicators in the boric acid transfer
pump discharge line. When the emergency boration path is used, three
indications to the operator are available. The primary indication is a flow
indicator in the emergency boration line. The charging line flow indicator
will indicate boric acid flow since the charging pump suction is aligned to the
boric acid transfer pump discharge for this mode of operation. The change in
boric acid tank level is another indication of boric acid injection.
On loss of seal injection water to the reactor coolant pump seals, seal water
flow may be reestablished by manually starting a standby charging pump. Even
if the seal water injection flow is not reestablished, the unit can be operated
indefinitely since the thermal barrier cooler has sufficient capacity to cool
the reactor coolant flow which would pass through the thermal barrier cooler
and seal leakoff from the pump volute.
Galvanic Corrosion
The only types of materials which are in contact with each other in borated
water are stainless steels, Inconel, Stellite valve materials and Zircaloy fuel
element cladding. These materials have been shown (1) to exhibit only an insignificant degree of galvanic corrosion when coupled to each other.
For example, the galvanic corrosion of inconel versus 304 stainless steel resulting from high temperature tests (575
°F) in lithiated, boric acid solution was found to be less than -20.9 mg/dm 2 for the test period of 9 days. Further galvanic corrosion would be trivial since the cell currents at the conclusion of the tests were approaching polarization. Zircaloy versus 304 stainless steel was shown to polarize at 180
°F lithiated, boric acid solution in less than 8 days with a total galvanic attack of -3.0 gm/dm
- 2. Stellite versus 304 stainless steel was polarized in 7 days at 575
°F in lithiated boric acid solution. The total galvanic corrosion for this couple was -0.98 mg/dm
- 2. As can be seen from the tests, the effects of galvanic corrosion are
insignificant to systems containing borated water.
(1) WCAP 1844 "The Galvanic Behavior of Materials in Reactor Coolants" D. G. Sammarone, August, 1961 Non-Proprietary.
9.2-27 Revised 04/17/2013 C26C26C26 9.
2.4 REFERENCES
- 1. STD-M-006, Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4.
9.2-28 Revised 09/20/2016 C28
TABLE 9.2-1 CHEMICAL AND VOLUME CONTROL SYSTEM CODE REQUIREMENTS
Regenerative heat exchanger ASME III (1), Class C Non-regenerative heat exchanger ASME III, Class C, tube side, ASME VIII, shell side
CVCS letdown demineralizers ASME III, Class C
Reactor coolant filters ASME III, Class C
Volume control tank ASME III, Class C
Seal water heat exchanger ASME III, Class C, tube side, ASME VIII, shell side
Excess letdown heat exchanger ASME III, Class C, tube side, ASME VIII, shell side
Chemical mixing tank ASME VIII
Seal water injection filters ASME III, Class C
Holdup tanks ASME III, Class C
Boric acid filter ASME III, Class C
Condensate filter ASME III, Class C
Hydraulic Accumulators ASME III, Class 2, 1977 plus
Summer 77 Addenda (4) Piping and Valves (3) USAS B31.1 (2)
NOTES :
- 1. ASME III - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code Section III, Nuclear Vessels.
- 2. USAS B31.1 - Code for Pressure Piping, and special nuclear cases where applicable.
- 3. Aloyco valve weld ends in accordance with Westinghouse Spec. No.
G-676241, Dwg. No. 498B932, hydrostatically retested at system test pressures after installation.
- 4. Replacement parts are procured in accordance with NRC Generic Letter 89-09, since the original manufacturer has dropped their N-stamp.
Rev. 16 10/99 TABLE 9.2-2 NOMINAL CHEMICAL AND VOLUME CONTROL SYSTEM PERFORMANCE (1) Unit design life, years 60 Seal water supply flow rate, gpm (2) 24 Seal water return flow rate, gpm 7.5 Normal letdown flow rate, gpm 60
Maximum letdown flow rate, gpm 120
Normal charging pump flow (one pump), gpm 69
Normal charging line flow, gpm 45
Maximum rate of boration with one transfer and
one charging pump from an initial RCS concentration of 1800 ppm, ppm/min 6.5
Equivalent cooldown rate to above rate of
boration, o F/min 1.5 Maximum rate of boron dilution with two
charging pumps from an initial RCS
concentration of 2500 ppm, ppm/hour 350 Two-pump rate of boration, using refueling
water, from initial RCS concentration
of 10 ppm, ppm/min (3) 6.2 Equivalent cooldown rate to above rate of
boration, o F/min 1.4 Temperature of reactor coolant entering system
at full power (design),
o F 555.0 Temperature of coolant return to reactor
coolant system at full power (design),
o F 493.0 Normal coolant discharge temperature to
holdup tanks, o F 127.0 Amount of 3.0 weight percent boron solution
required to meet cold shutdown requirements,
at end of life with peak xenon (including
consideration for one stuck rod). This value is based on a usable volume of 10,275 gallons 11,175 plus 900 gallons volumetric uncertainty.
NOTES :
- 1. Reactor coolant water quality is given in Table 4.2-2.
- 2. Volumetric flow rates in gpm are based on 130 o F and 2350 psig.
- 3. 6.2 ppm/min remains a bounding minimum boration rate for two pumps at EPU conditions
Revised 08/03/2016 C28C28 TABLE 9.2-3 Sheet 1 of 2
PRINCIPLE COMPONENT DATA
SUMMARY
Heat Letdown Letdown Design Design
Transfer Flow T Pressure Temperature Quantity 1 Btu/hr lb/hr F psig,shell/tube F,shell/tube
Heat Exchangers Regenerative 1 8.65 x 10 6 29,826 265 2485/2735 650/650 Non-regenerative 1 14.8 x 10 6 29,826 163 150/600 250/400 Seal water 1 2.17 x 10 6 126,756 17 150/150 250/250 Excess Letdown 1 4.75 x 10 6 12,400 360 200/2485 250/650
Capacity Design Design Each Pressure Temperature Quantity 1 Type gpm Head psig F Pumps Charging 3 Pos.displ. 77 2385 psi 3000 250 Boric acid transfer 4* Centrifugal 60 235 ft. 150 250 Holdup tank recirculation 1* Centrifugal 500 100 ft. 150 200 Monitor tank 2* Centrifugal 100 150 ft. 150 200
Gas stripper feed 3* Canned 25 185 ft. 150 200 Gas stripper bottom 2 Centrifugal 12.5 93 ft. 75 300 Design Design Pressure Temperature Quantity 1 Type Volume,Each psig F
Tanks Volume 1 Vert. 300 ft 3 75 Int/15 Ext 250 Boric Acid 3* Vert. 9100 gal Atmos. 250 Chemical mixing 1 Vert. 6.0 gal 150 250 Batching 1* Jacket Btm. 800 gal Atmos. 250 Holdup 3* Vert. 13,000 ft 3 15 200 RWST 1 Vert. 338,000 gal Atmos. 200
Rev. 16 10/99
TABLE 9.2-3 Sheet 2 of 2
Design Design Pressure Temperature Quantity 1 Type Volume psig F Tanks (continued)
Monitor 2* Vertical 10,000 gal Atmos. 150
Resin Design Design Volume Flow Pressure Temperature Quantity 1 Type ft 3 gpm psig F Demineralizer Vessels (5) 2 Flushable 30 120 200 250 1 Flushable 20 60 200 250 2 Flushable 43 120 200 250
Relief Pressure
Quantity 1 psig Capacity Relief Valves Charging pumps 3 2735 77 gpm Regenerative heat exchanger*** 1 N/A N/A Holdup tank 3 12 120 gpm
Letdown line (intermediate pressure section) 1 600 240 gpm Seal water return line 1 150 165 gpm
Batching tank heating jacket 1 20 320 lb/hr Volume control tank 1 75 170 gpm Holdup tank vacuum brks 2 1-3 in/WC** 100 scfm Letdown line (downstream 1 450 120 gpm
Of non-regenerative heat
exchanger)
Unit 3 Excess Letdown Line**** 1 2730 114 gpm
1 Quantity per unit unless otherwise specified.
- Shared or capable of being shared by Unit 3 and Unit 4.
- Actual cracking pressure (Nominal Cracking Pressure may be higher)
One vacuum breaker is capable of providing the minimum flowrate capacity shown.
- Regenerative Heat Exchanger is protected from thermal overpressure by a bypass line around CV-*-310A instead of a relief valve.
- Unit 4 Excess Letdown is provided with a reverse bypass line, with a check valve for thermal overpressure protection for GL 96-06.
Revised 03/14/2016 C28 TABLE 9.2-4 Sheet 1 of 1 PARAMETERS USED IN THE CALCULATION OF REACTOR COOLANT FISSION PRODUCT ACTIVITIES (PER UNIT FOR 24 MONTH CYCLE)
- 1. Core thermal power, Mwt 2652
- 2. Fraction of fuel containing clad defects 0.01
- 3. Reactor Coolant System Water Mass (lb m) 397,544
- 4. Reactor coolant average temperature, o F 576.5
- 5. Purification flow rate (nominal), gpm 60
- 6. Effective cation demineralizer flow, gpm 6
- 7. Volume control tank volumes and conditions
- a. Vapor, cu ft 180
- b. Liquid, cu ft 120 c Pressure, psig 18 d. Temperature, F 127
- 8. Fission product escape rate coefficients during full power operation:
- a. Kr and Xe isotopes, sec
-1 6.5 x 10
-8 b. Br, I, Rb and Cs isotopes, sec
-1 1.3 x 10
-8 c. Te, Se, Sn and Sb isotopes sec
-1 1.0 x 10
-9 d. Mo, Tc and Ag isotopes, sec
-1 2.0 x 10
-9 e. Sr and Ba isotopes, sec
-1 1.0 x 10
-11 f. Y, Zr, Nb, Ru, Rh, La, Ce Pr, Nd and Pm isotopes, sec
-1 1.6 x 10
-12
- 9. Mixed bed demineralizer isotopic decontamination
factors:
- a. Kr, Xe isotopes and other isotopes 1.0
- b. Br, I, Sr and Ba isotopes 10.0
- 10. Cation Mixed bed demineralizer isotopic decontamination factors
- a. Cs-134, Cs-137, and Rb-86 10.0 b. Kr, Xe, Sr, Ba, Rb-88, Rb-89, CS-136, CS-138, Br, I, 1.0 and other isotopes
- 11. Volume control tank noble gas stripping fraction (closed system):
Isotope Stripping Fraction Kr-83 7.6 x 10
-1 Kr-85 6.3 x 10
-5 Kr-85m 5.7 x 10
-1 Kr-87 8.2 x 10
-1 Kr-88 6.8 x 10
-1 Kr-89 9.9 x 10
-1 Xe-131m 1.5 x 10
-2 Xe-133 3.2 x 10
-2 Xe-133m 7.4 x 10
-2 Xe-135 3.2 x 10
-1 Xe-135m 9.4 x 10
-1 Xe-137 9.8 X 10
-1 Xe-138 9.5 x 10
-1
- 12. Primary Makeup Water System Adds 200,000 gallons/year of clean water
Revised 04/17/2013 C26C26C26C26C26C26C26 Table 9.2-5 Page 1 of 2 EQUILIBRIUM REACTOR COOLANT SYSTEM SPECIFIC ACTIVITY Revised 04/17/2013C26 Table 9.2-5 Page 2 of 2 EQUILIBRIUM REACTOR COOLANT SYSTEM SPECIFIC ACTIVITY Revised 04/17/2013 C26 TABLE 9.2-6 SHEET 1 of 2 TRITIUM PRODUCTION IN THE REACTOR COOLANT (PER UNIT) Basic Assumptions:
Unit Parameters: 1.Core thermal power, MWt 2296 2.Coolant water volume, ft 3 9,400 3.Core volume, ft 3 937.3 4.Core volume fractionsa.UO 2.2990 b.Zr + SS.0933 c.H 2 0.6077 5.Unit full power operating timesa.Initial cycle 78 weeks (18 months) b.Equilibrium 49 weeks (11.3 months) 6.Boron Concentrations (Peak hot full power equilibrium Xe)a.Initial cycle, ppm 890 b.Equilibrium cycle, ppm 825 7.Burnable poison boron content (total-allrods), Kg13.4 8.Fraction of tritium in core (ternary fission + burnable boron) diffusing thru ss clad; thru Zr-clad 0.30; 0.01* 9.Ternary fission yield 8 x 10-5 atoms/fission
- The assumption that 1% of the ternary produced tritium diffuses into the coolant is based on the experience and analysis made of retention in the
Shippingport, Breznau and Ginna zircaloy clad fuel.
TABLE 9.2-6 SHEET 2 of 2 10.Nuclear cross-sections and neutron fluxes B 10 (n, 2a,) T; mb (nv; n/cm 2-sec) 1 Mev < E < 5 Mev = 31.59 (Spectrum weighted) 5.04 x 10 13 E > 5 Mev = 75 7.4 x 10 12 Li 7 (n, na) T (99.9% purity) 3 Mev < E < 6 Mev = 39.1 (Spectrum weighted) 2.14 x 10 13 E > 6 Mev = 0.4 2.76 x 10 12 Li 6 (n, a) T (99.9% purity Li
- 7) = 675 barns; nv = 2.14 x 10 13 n/cm 2-sec II.CALCULATIONS (per unit) curies/year curies/year A. Tritium from Core Initial Cycle Equilibrium Cycle 1.Ternary Fission 8,180 8,180 2.B 10 (n, 2a) T (in ss clad poison rods) 592 N.A. 3.B 10 (n, a,) Li 7 (n, na) T 1,110 N.A. 4.Release fraction (x 0.30, A2,3) 511 N.A. 5.Release fraction (x 0.01, A1) 82.82. Total release to Coolant 593.82. B. Tritium from Coolant 1.B 10 (n, 2a) T 843 582 2.Li 7 (n,na) T (limit 2.2 ppm Li) 6.6 6.6 3.Li 6 (n,a) T (purity of Li 7 =99.9%)6.6 6.6 4.Release Fraction (x 1.0)5.Total Release to Coolant856.2595.2 C. Total Tritium in Coolant 1,449.677 TABLE 9.2-7 MALFUNCTION ANALYSIS OF CHEMICAL AND VOLUME CONTROL SYSTEM
Component Failure Comments and Consequences
- 1) Letdown line Rupture in the line inside the reactor containment The remote air-operated
valve located near the
coolant loop is closed on
low pressurizer level to
prevent supplementary loss
of coolant through the
letdown line rupture. The
containment isolation
valve in the letdown line
outside the containment
and also the orifice block
valves are automatically
closed by the containment
isolation signal initiated
by the concurrent loss of
coolant accident. The
closure of these valves
prevents any leakage of
the containment atmosphere
outside the containment.
- 2) Normal and alternate charging line See above. The check valves located near the coolant alternate loops prevent
supplementary loss of
coolant charging line
through the line rupture.
The check valves located
at the boundary of the
containment prevent any
leakage of the containment
atmosphere outside the
containment.
- 3) Seal water return line See above The motor-operated isolation valve located
return line both outside
and inside the containment
are manually closed or are
automatically closed by
the containment isolation
signal initiated by the
concurrent loss of coolant
accident. The closure of
these valve prevents any
leakage of the containment
atmosphere outside the
containment.
Revised 04/17/2013
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-1 REFER TO ENGINEERING DRAWING 5610-M-3046 , SHEET 1
REV.13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CHEMICAL AND VOLUME CONTROL SYSTEM BORIC ACID SYSTEM FIGURE 9.2-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-2 REFER TO ENGINEERING DRAWING 5610-M-3046 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CHEMICAL AND VOLUME CONTROL SYSTEM BORON RECYCLE SYSTEM FIGURE 9.2-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-3 REFER TO ENGINEERING DRAWING 5610-M-3046 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CHEMICAL AND VOLUME CONTROL SYSTEM BORON RECYCLE SYSTEM FIGURE 9.2-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-4 REFER TO ENGINEERING DRAWING 5610-M-3046 , SHEET 4
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CHEMICAL AND VOLUME CONTROL SYSTEM BORON RECYCLE SYSTEM FIGURE 9.2-4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-5 REFER TO ENGINEERING DRAWING 5613-M-3047 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 CHEMICAL AND VOLUME CONTROL SYSTEM CHARGING AND LETDOWN FIGURE 9.2-5
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-6 REFER TO ENGINEERING DRAWING 5613-M-3047 , SHEET 2 REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 CHEMICAL AND VOLUME CONTROL SYSTEM CHARGING AND LETDOWN FIGURE 9.2-6
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-7 REFER TO ENGINEERING DRAWING 5613-M-3047 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 CHEMICAL AND VOLUME CONTROL SYSTEM SEAL WATER INJECTION TO RCP FIGURE 9.2-7
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-8 REFER TO ENGINEERING DRAWING 5614-M-3047 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 CHEMICAL AND VOLUME CONTROL SYSTEM CHARGING AND LETDOWN FIGURE 9.2-8
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-9 REFER TO ENGINEERING DRAWING 5614-M-3047 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 CHEMICAL AND VOLUME CONTROL SYSTEM CHARGING AND LETDOWN FIGURE 9.2-9
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-10 REFER TO ENGINEERING DRAWING 5614-M-3047 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 CHEMICAL AND VOLUME CONTROL SYSTEM SEAL WATER INJECTION TO RCP FIGURE 9.2-10
FINAL SAFETY ANALYSIS REPORT FIGURE 9.2-11 REFER TO ENGINEERING DRAWING 5610-M-3065 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 NITROGEN & HYDROGEN SYSTEMS HYDROGEN & CO2 SUPPLY FIGURE 9.2-11
9.3 AUXILIARY COOLANT SYSTEM 9.3.1 DESIGN BASES
The Auxiliary Coolant System consists of three loops; the component cooling
loop, the residual heat removal loop, and the spent fuel pit cooling loop as
shown in Figures 9.3-1 through 9.3-9, 6.2-1, 6.2-5, 9.5-11, and 9.5-12. Each
unit has a similar Auxiliary Coolant System. The description contained
herein applies to both units. The spent fuel pit cooling loop and components
are described in Section 9.5.
Performance Objectives
Component Cooling Loop
The component cooling loop (see figures 9.3-1 through 9.3-9) is the heat sink
for the residual heat removal loop, the Chemical and Volume Control System, the spent fuel cooling loop and various Reactor Coolant System components.
The CCW system is designed with sufficient redundancy such that a single
active failure will not prevent the system from accomplishing its support
function of cooling safety related equipment.
The loop design provides for detection of radioactivity entering the loop
from the reactor coolant source and also provides for isolation from this
inleakage.
The CCW system design satisfies performance objective requirements for
Thermal Power Uprate operation as indicated in Reference 10.
The residual heat removal loop (see figures 6.2-1 and 6.2-5) is designed to
remove residual and sensible heat from the core and reduce the temperature of
the Reactor Coolant System during the second phase of plant cool down.
During the first phase of cooldown, the temperature of the Reactor Coolant
System is reduced by transferring heat from the Reactor Coolant System to the
Steam and Power Conversion System.
All active loop components which are relied upon to perform their function
are redundant.
9.3-1 Revised 04/17/2013 The loop precludes any significant reduction in the overall design reactor
shutdown margin when the loop is brought into operation for residual heat
removal or for emergency core cooling by recirculation. The loop design
includes provisions to enable hydrostatic testing to applicable code test
pressures during shutdown.
Loop components, whose design pressure and temperature are less than the
Reactor Coolant System design limits are provided with overpressure
protective devices and redundant isolation means.
The RHR system design satisfies performance objective requirements for Extended Power Uprate operation as indicated in Reference 16.
Design Characteristics Component Cooling Loop
One pump and three component cooling water heat exchangers are normally
operated to provide cooling water for various components located in the
auxiliary and containment buildings. The water is normally supplied to all
components being cooled even though one of the components may be out of
service.
Makeup water is taken from the primary water storage tank, as required and
delivered to the surge tank. A backup source of water is provided from the
water treatment plant via the demineralized water system.
The operation of the loop is monitored with the following instrumentation:
- a. Temperature detectors in the inlet and outlet lines for the component cooling heat exchangers.
- b. A pressure detector on the line between the component cooling pumps and the component cooling heat exchangers.
- c. A temperature and flow indicator in the outlet headers from the component cooling water heat exchangers.
- d. A radiation monitor on the inlet headers to the component cooling pumps.
The CCW system is flow balanced each refueling outage to ensure adequate flow
is available to system components during normal power operation and post-
accident conditions.
9.3-2 Revised 04/17/2013 C26C26 The flow balance further ensures that individual component minimum and
maximum flow limits are not exceeded due to changes in the system
configuration which would occur in response to a design basis accident.
Two pumps and two residual heat exchangers perform the decay heat cooling functions for the reactor. After the Reactor Coolant System temperature and
pressure have been reduced to 350 o F and 450 psig respectively, decay heat cooling is initiated by aligning one pump to take suction from the reactor
outlet line and discharge through the heat exchangers and into the reactor
inlet line. If only one heat exchanger is available, reduction of reactor
coolant temperature is accomplished but at a lower rate.
The equipment utilized for decay heat cooling is also used for emergency core cooling during loss-of-coolant accident conditions. This is described in
Section 6.
Codes and Classifications
All piping and components of the Auxiliary Coolant System are designed to the
applicable codes and standards listed in Table 9.3-4. The component cooling
loop water contains a corrosion inhibitor to protect the carbon steel piping
and is subject to chemical controls to protect the austenitic stainless steel
components. Austenitic stainless steel piping is used in the residual heat
removal loop, which contains reactor coolant, and in the spent fuel pit
cooling loop, which contains water without corrosion inhibitor.
9.3-3 Revised 4/17/2013 9.3.2 SYSTEM DESIGN AND OPERATION
Component Cooling Loop
Component cooling is provided for the following heat sources:
- a. Residual heat exchangers (Auxiliary Coolant System, ACS)
- b. Reactor coolant pumps (Reactor Coolant System)
- c. Non regenerative heat exchanger (Chemical and Volume Control System, CVCS)
- d. Excess letdown heat exchanger (CVCS)
- e. Seal water heat exchanger (CVCS)
- f. Sample heat exchangers (Sampling System)
- g. Waste gas compressors (Waste Disposal System)
- h. Residual heat removal pumps (ACS)
- i. Safety injection pumps (Safety Injection System, SIS)
- j. Containment spray pumps
- k. Spent fuel pit heat exchangers (ACS) l. Charging pump (CVCS)
- m. Normal containment coolers
- n. Control rod drive coolers
- o. Emergency containment coolers
- p. Post Accident Sampling System (PASS)
At the reactor coolant pump, component cooling water removes the heat from
the bearing oil and the thermal barrier. Since the heat is transferred from
the component cooling water to the intake cooling water, the component
cooling loop serves as an intermediate system between the reactor coolant and
intake cooling water system. This double barrier arrangement reduces the
probability of leakage of high pressure, potentially radioactive coolant to
the intake cooling water system. It also reduces the probability of in-
leakage of chlorides from the salt water intake to the demineralized primary
system.
During normal full power operation, one component cooling water pump and two
or three component cooling water heat exchangers accommodate the heat removal
loads. Each of the two standby pumps provides 100% backup, during normal
operation. Two pumps and three heat exchangers are utilized to remove the
residual and sensible heat during unit shutdown to ensure the CCW shell side
flow does not exceed established flow limits.
9.3-4 Revised 04/17/2013 C26C26 Higher shell side flow rates are allowed for limited periods of time. If one of the pumps or one of the heat exchangers is not operated, safe shutdown of
the unit is not affected, however, the time for cooldown is extended. If one
CCW heat exchanger were out of service, RCS cooldown would continue to be
possible, although at a much slower rate. Analysis has shown that the Steam
Generator Steam Dump to Atmosphere (SDTA) can be utilized beyond the point in
time at which RHR is aligned to the RCS. In addition, when RHR Cut-in Time is
achieved, the operating RCP can be secured, at which point the Maximum CCW
Temperature will be allowed to rise from 125°F to 130°F. This results in an
analyzed cooldown time of less than 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />. (Reference 15)
The head tank accommodates normal expansion and limited in-leakage of water.
The head tank and surge tank combine to accommodate contraction and ensure a
continuous component cooling water supply until a leaking cooling line can be
isolated. A single inlet/outlet line connects the head tank to the top of
the surge tank. Two surge lines are provided on the surge tank, so that each
surge line is connected to one of the two partitioned sections of the surge
tank. The lines are connected to each of the two component cooling headers
in the suction side of the component cooling water pumps.
The CCW head tank is normally vented to the Waste Holdup Tank. A radiation
monitor in each component cooling water pump inlet header annunciates in the
control room and closes a valve in the head tank vent line in the unlikely
event that the radiation level reaches a pre-set level above the normal
background. The head tank vent line is also isolated on high head tank level
to mitigate overflow to the Waste Holdup Tank. Redundant component cooling
water headers are provided (see Figure 9.3-1).
Design Bases
The design basis of the Component Cooling Water System is to provide
sufficient heat removal from the Engineered Safety Features to the ultimate
heat sink (ICW System), post accident.
(1,2) The system, which is normally operated in an open configuration, is designed with sufficient capability to
accommodate the failure of any single, active component without resulting in
undue risk to the health and safety of the public following a Maximum
Hypothetical Accident (MHA). The most limiting single active failure
considered was the loss of one diesel, which results in only one CCW pump
starting automatically to mitigate the consequences of the MHA. This assumed
single failure also results in the loss of a complete train of engineered
safety features, including the inability to open the CCW isolation valve
associated with one RHR heat exchanger and one Emergency Containment Cooler (ECC).
9.3-5 Revised 04/17/2013 C26 Although a complete train of engineered safety feature components will be inoperable on loss of a diesel, CCW flow to these components will continue, except as noted above in the case of an RHR heat exchanger and one ECC. In
support of the Extended Power Uprate (EPU) project, detailed CCW System
thermal analyses were performed to evaluate overall performance following
worst-case design basis accidents. Maximum expected system operating
temperatures were calculated for both the double-ended primary system pipe
break and secondary (steam) pipe failure. In the thermal analyses, a
consistent set of conservative cooling system operating parameters were
defined for several analyzed single failure conditions. These included the
failure of a diesel generator, a containment spray pump and ICW pump. To
restrict CCW System post-accident operating temperatures to within acceptable
ranges, a design basis change remains in effect at EPU conditions to limit
the maximum number of ECCs automatically starting to no more than two, assuming when only two CCW heat exchangers are in operation. Previously, all
three ECCs were allowed to auto start. The applicable Engineered Safety
Features at Turkey Point Units 3 and 4 include:
- a. Residual Heat Removal heat exchangers (Auxiliary Coolant System, ACS)
- b. Residual Heat Removal pumps (ACS)
- c. Safety Injection pumps (Safety Injection System, SIS)
- d. Containment Spray pumps
- e. Emergency Containment Coolers
- f. Support systems for the above
The CCW system is periodically placed in a split header configuration for
short periods of time to allow the performance of inservice testing of the
CCW pumps. During these periods of split header configuration, the CCW
system is not able to serve the needs of a fully redundant and automatic two-
train fluid system. Therefore Technical Specification provisions and certain
other plant operating restrictions are imposed during these CCW system
configurations.
With respect to the noted safety function, the Component Cooling Water
System's performance is characterized by the minimum required and maximum
allowable flow rates through the Engineered Safety Features listed above and
through the other required and connected loads, and the corresponding heat
transfer rates. In the various EPU project post-accident thermal analyses, a
range of expected CCW System flows was analyzed based on detailed hydraulic
flow calculations. The system flow calculations were based on revised CCW
System flow balance criteria as provided in Table 9.3-6.
9.3-6 Revised 04/17/2013 C26C26C26 It should be noted that the Engineered Safety Features (with the exception of the Emergency Containment Coolers) operate in two sequential post-accident
phases. The first, the injection phase, requires operation of the Safety
Injection (SI), Containment Spray (CS) and Residual Heat Removal (RHR) pumps, taking suction from the Refueling Water Storage Tank (RWST). A safety
injection signal automatically starts the SI and RHR pumps and aligns them
for RCS cold-leg injection, which commences when the RCS pressure falls below
the shutoff head of each pump. Containment Spray pump operation is initiated
by coincident High and High-High Containment pressure signals (two-out-of-
three). Two Emergency Containment Coolers (ECC) will be started automatically
upon receipt of a safety injection signal, and will continue to run
throughout the injection and recirculation phases. To ensure that two units
are in operation post-accident, the third ECC will automatically start
following a failure of one of the other two units.
The recirculation phase is initiated after the RWST volume is depleted. This
phase differs from the injection phase in that the RHR pumps are re-aligned
to take suction from the containment sump. The RHR pumps discharge through
the RHR heat exchangers and then to the SI pump suction. The RHR pumps can
also discharge to the CS pump suction when containment conditions are
elevated.
The CCW system has also been designed to ensure that no portion of the system
can reach saturation pressure during design basis accident scenarios, precluding the potential for formation of steam voids. The CCW head tank has
been designed and installed to provide sufficient static head, such that
component cooling water temperatures up to 270ºF will not initiate steam void
formation.
The CCW system heat removal functions have been evaluated for the following
operating configurations:
- a. Power Operation (which includes hot shutdown and hot standby operations).
- b. Residual Heat Removal (RHR) Cooldown (which includes hot shutdown, cold shutdown and refueling operations).
- c. Post-Accident (which includes both the injection and recirculation phases of a LOCA and the injection mode of a MSLB).
In addition, the two CCW system headers can be periodically isolated (i.e.,
split header) to support special system evolutions. This configuration was
also evaluated for post-accident operation.
9.3-7 Revised 04/17/2013 C26C26 The CCW heat exchanger heat removal capacity was relaxed to offer increased system operating margin. The capacity of the CCW heat exchangers was relaxed by increasing the total tube resistance from the design value of 0.00159 hr-
ft 2-oF/BTU to 0.003 hr-ft 2-oF/BTU at 95 oF ICW inlet temperature. For added conservatism, all containment integrity analyses, which explicitly model heat transfer to the ICW System, were performed at an ICW inlet temperature of 100 oF. In addition, for thermal evaluation of the CCW system the total tube resistance was lowered to 0.00285 hr-ft 2-F/Btu to account for the water properties of the ultimate heat sink and align with the containment analysis performed for EPU.
Since the CCW system configuration can physically provide a shell side flow greater than the design maximum, plant operation must be procedurally limited to prevent such configurations. To eliminate the potential for CCW heat exchanger shell side flows to exceed the maximum specified flow limits, both procedural controls and CCW system flow balancing limitations have been established. The operating procedure restrictions limit the number of operating CCW pumps to N-1, where N is the number of in-service CCW heat exchangers. Limitations on the number of major CCW system end users (emergency containment coolers, RHR heat exchangers and normal containment coolers) have also been established and proceduralized.
For the Power Operation and RHR Cooldown configurations, thermal performance calculations were performed using standard water-to-water heat exchanger heat transfer equations and generalized heat transfer methodology. For Power Operation, thermal analyses were performed at steady-state plant operating conditions to calculate maximum expected CCW heat exchanger operating temperatures.
During postulated design basis events, the CCW system major heat loads (ECCs and the RHR heat exchangers) are variable in nature and are dependent on containment operating conditions. As such, the GOTHIC Computer Code, which was used in containment integrity analyses, was also used to conservatively calculate limiting CCW system and ICW system post-accident operating temperatures. The results of the GOTHIC computer code were used in conjunction with an AFT Fathom incompressible flow network analysis to determine CCW system piping temperatures during post accident conditions
Peak CCW system operating temperatures occur during post-accident operations due to elevated containment temperatures and unrestricted heat rejection into the CCW system. A calculated maximum CCW System supply temperature of 158.6°F is acceptable for post-accident operation, and the basis for this temperature increase over the previous design temperature of 150 oF is validated for the Extended Power Uprate project (Reference 16).
9.3-8 Revised 08/17/2016 C28 Numerous failure cases have been modeled to target containment integrity, CCW
system and ICW system integrity. The most limiting scenarios that affect CCW
system integrity were identified as the failure of one train of Emergency
Power, failure of one Containment Spray pump, failure of one ICW pump during
a Large Break LOCA, or during a Main Steam line break.
For the Power Operation configuration, the maximum CCW system supply temperature (CCW heat exchanger outlet temperature) is 105
°F. For the RHR Cooldown configurations, adequate RCS cooldown performance is maintained with
a CCW system supply temperature of 125
°F. For post-accident operation, the following are the most critical CCW system operating temperatures:
- a. CCW System heat exchanger shell side inlet (return) temperature. b. CCW System heat exchanger Shell side outlet (supply) temperature.
- e. CCW System heat exchanger ICW outlet temperature.
For the CCW system heat exchanger return temperature, the CCW system outlet temperature shall remain at or below the system design temperature (200
°F) and within CCW pump Net Positive Suction Head (NPSH) limitations. The CCW system heat exchanger supply temperature shall remain within analyzed limits
to ensure that equipment cooled by the system remains operable. The most
limiting CCW system supply temperature calculated in the Westinghouse EPU containment analysis is 158.6
°F This temperature profile is most critical for the Safety Injection pump lube oil cooler. The safety injection pump
lube oil cooler was evaluated at EPU for 165
°F, greater than the peak supply temperature of 158.6
°F. For the ECCs, the upper limiting temperature due to piping stress limitations is approximately 197
°F.
9.3-9 Revised 04/17/2013 C26C26C26 Pump Performance The plant design bases specify that the operation of one CCW pump and one RHR
heat exchanger during an MHA is adequate for accident mitigation.
Readjustment of CCW System valve positions will change the operating point of
the CCW pumps, with respect to the CCW total system pressure drop, from the
original start-up configuration. The CCW pump performance at these new valve
positions has been demonstrated to meet the design requirements by a
combination of tests and calculations.
The two criteria evaluated were adequate flow to the CCW System and adequate
NPSH to the CCW pumps. Testing and CCW System hydraulic analyses have
demonstrated that one pump could provide the required flow to the entire CCW
System.
The CCW system has also been designed to ensure that no portion of the system
can reach saturation pressure during design basis accident scenarios, precluding the potential for formation of steam voids. The CCW head tank has
been designed and installed to provide sufficient static head, such that component cooling water temperatures up to 270
°F will not initiate steam void formation. The required NPSH for one pump at 15,000 gpm is approximately 46 ft. with the installed CCW head tank, the available NPSH is 123.8 ft when the maximum post accident suction temperature is 182.5
°F. Therefore, sufficient NPSH is available. Installation of the CCW head tank increases available static head by a nominal 29 psig. That added NPSH will ensure that pump
performance will remain unaffected by establishing added margin during
elevated temperature operation.
Maximum Flow Considerations for ECCs
Each cooler consists of 60 five-pass tubes in parallel with an additional 60
five-pass tubes to form a ten-row coil. From the standpoint of the component
cooling water, this configuration can be represented by 120 parallel tubes.
When the tubing cross-section (1-1/8 inch diameter, 0.049 inch wall) is
considered, an average velocity of 6.4 feet per second is produced by a flow
of 2000 gpm.
Flows to the ECCs may exceed the continuous design flow rating of 2000 gpm
for short periods of time based on limiting the erosion rate of the Admiralty
tubes to 5 mils/year. The shorter the time frame the greater the allowable
flow rate.
9.3-10 Revised 04/17/2013 C26 The relationship of allowable flow maximums versus time durations is as follows:
2000 gpm Continuous Operation 3200 gpm 1 Month (Post-LOCA Recirculation Limit) 3600 gpm 1 Week 5000 gpm 24 Hours (Initial Safety Injection Limit) 5500 gpm 1 Hour
Pressure in the tubes is not a likely mechanism for failure, since the tubes
have a design pressure well in excess of the pressure deliverable by the CCW
pumps. The addition of the CCW head tank and the resultant increase in
overall CCW system pressure will reduce the margin between deliverable
pressure and design pressure, but will not result in pressure at the ECC
exceeding the tube design pressure.
As shown above, during the injection phase of an MHA, flows to the ECCs could
exceed those values cited in Table 9.3-6. This additional flow is not
anticipated to adversely effect the ECCs ability to perform their safety
function for the following reasons:
- a. Duration of the injection phase is short in comparison to the recirculation phase.
- b. The operator has the ability to decrease flow to the ECCs (i.e., aligning CCW to RHR) if he believes the ECCs are receiving excessive
CCW flow.
- c. The design of the ECCs, as described above, is such that additional flow above its design maximum should not degrade the coolers' ability
to perform their safety related function.
Spent Fuel Pit Heat Exchanger Minimum Flow
SFP Heat Exchanger CCW flow requirements are a function of the spent fuel being stored in the pit. The minimum CCW flow rate to the Primary SFP heat exchanger has been established at 1,200 gpm during CCW System flow balancing.
Actual CCW flow to the Primary SFP heat exchanger would be higher during normal operation. Calculations conclude that CCW flow to the Primary SFP heat exchanger would exceed 1850 gpm during normal plant operation. During refueling operations, CCW flow to the Primary SFP heat exchanger can be temporarily increased to 2800 gpm for each SFP heat exchanger. The supplemental SFP heat exchanger must also comply with the safety related CCW system flow balance requirements to ensure adequate flow to ESF equipment.
9.3-11 Revised 04/17/2013 C26 Residual Heat Removal Loop The Residual Heat Removal (RHR) loop consists of heat exchangers, pumps, piping and the necessary valves and instrumentation. During shutdown, coolant flows from the Reactor Coolant System to the RHR pumps, through the
tube side of the RHR heat exchangers and back to the Reactor Coolant System.
The inlet line to the RHR loop starts at the hot leg of one reactor coolant
pump and the return line normally connects to the low head Safety Injection
System piping to the three cold legs. The RHR heat exchangers are used to
cool the water during the latter phase of Safety Injection System operation.
These duties are defined in Section 6. The heat loads are transferred by the
RHR heat exchangers to the component cooling water.
During unit shutdown, the cooldown rate of the reactor coolant system is
controlled by manually regulating the flow through the tube side of the RHR
heat exchangers. A bypass line and an automatic flow control valve around
the RHR heat exchangers are used to maintain a constant flow through the
residual heat removal loop and to control cooldown.
Double, remotely operated valving in the inlet line is provided to isolate
the RHR loop from the Reactor Coolant System. To protect the RHR system
against excess pressure and to prevent an intersystem LOCA, the RHR inlet
isolation valves, MOV-750 and MOV-751, are supervised by pressure switches
which will automatically close these valves at or above 525 psig; an
isolation alarm warns the operator. A pressure spike, either real or
spurious, during low pressure operation could result in the closure of these
valves. This event could lead to the loss of the letdown flow path, potentially leading to RCS overpressurization and/or loss of decay heat
removal capability. To prevent this event from occurring, the autoclosure
interlock (ACI) for MOV-750 and MOV-751 may be defeated during RHR system
operation for Reactor Coolant System shutdown cooling in Modes 5 and 6.
Manual override of the ACI is also provided to allow operation of the
isolation valves when the overpressure modification system is in the low
pressure mode. MOV-750 and MOV-751 are locked closed during normal plant
operation and following a Loss of Coolant Accident to provide containment
isolation. This is accomplished by locking the breakers for MOV-750 and MOV-
751 open. Two remotely operated valves in parallel and two check valves in
series isolate each line to the Reactor Coolant System cold legs from the RHR
loop. Overpressure in the loop is prevented by a relief valve which
discharges to the pressurizer relief tank.
9.3-12 Revised 04/17/2013 The cooldown capability of the RHR system has been evaluated for a number of cases for each of the following scenarios:
- a. RHR system cut-in evaluation
- b. Normal Cooldown (all cooling equipment available)
- c. Appendix R Cooldown
- d. Abnormal Cooldown (equipment unavailable)
- e. Accident cases include Main Steam Line Break (MSLB), Reactor Coolant Pump Single Failure Locked Rotor (SFLR), and Steam Generator Tube Rupture (SGTR).
A "better estimate" methodology was used to determine appropriate input values for the RHR cool down analysis. This methodology provides more nominal, as opposed to extremely conservative, values of input parameters.
Seasonal variability of the ICW temperature, the CCW heat exchanger fouling factor, and the auxiliary plant heat loads were considered in performing the cool down analyses listed above.
For the RHR system cut-in evaluation, the RHR system is capable of accepting
the RCS heat removal function as early as 7.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> based on the most
restrictive operating parameters and with all cooling equipment trains
available. This is well within the 13-hour duration considered in the CST
sizing basis.
For the Normal Cooldown evaluation, the maximum calculated duration to cool down the RCS from "no load" to 200
°F is 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />.
For the Appendix R Cooldown evaluation, the maximum calculated duration to cool down the RCS from "no load" to 200
°F is 64 hours7.407407e-4 days <br />0.0178 hours <br />1.058201e-4 weeks <br />2.4352e-5 months <br />.
For the Abnormal Cooldown evaluation, RCS cooldown would continue to be
possible, although at a much slower rate. In addition, the time at which the
RHR system can be placed into service would also be extended.
For the MSLB, SFRF, and SGTR accident cases, the maximum calculated duration to cooldown the RCS from "No load" to 200
°F ranges from 61 to 64 hours7.407407e-4 days <br />0.0178 hours <br />1.058201e-4 weeks <br />2.4352e-5 months <br />.
9.3-13 Revised 04/17/2013 C26C26C26C26C26 Component Cooling Water Components
Component Cooling Water Heat Exchangers
The three component cooling water heat exchangers are of the shell and
straight tube type. Intake cooling water circulates through the tubes while
component cooling water circulates through the shell side. Parameters are
presented in Table 9.3-1.
Component Cooling Water Pumps
The three component cooling water pumps are horizontal, centrifugal units.
The pump casings are made from cast iron (ASTM 48) which is corrosion-erosion
resistant. The material thickness is dictated by high quality casting
practice and ability to withstand mechanical damage and as such are
substantially overdesigned from a stress level standpoint. Parameters are
presented in Table 9.3-1.
Component Cooling Water Surge Tank
The component cooling water surge tank, in combination with the head tank, is
designed to accommodate changes in component cooling water volume. The surge
tank has piping connections to both CCW loops and the head tank, and is
constructed of carbon steel. Parameters are presented in Table 9.3-1. The
surge tank also has a flanged opening at the top of the tank. The flanged
opening can be used to access the tank during periods of reduced inventory, but is normally inaccessible due to the level maintained in the head tank.
Chemical Pot Feeder Tank
The chemical pot feeder tank provides for the direct addition of corrosion
additive to the component cooling water. Parameters are listed in
Table 9.3-1.
9.3-14 Revised 04/17/2013 Component Cooling Water Valves The valves used in the component cooling water system are normally constructed of carbon steel with bronze or stainless steel trim. Self-actuated spring loaded relief valves are provided for lines and components that could be pressurized to their design pressure by improper operation or malfunction.
Turkey Point has Manual Operating features for selected air-operated valves as described in the Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4 (Reference 17) in the component cooling water system. The installation of these features provides a manual means of operating these valves if the valve misoperates.
Component Cooling Water Piping All original component cooling water system piping is carbon steel with welded joints and connections except at components which might need to be removed for maintenance. The piping added with the CCW head is welded austenitic stainless steel, except at selected component connections, to provide added corrosion resistance and reduced maintenance requirements.
Component Cooling Water Head Tank
The component cooling water head tank provides added static head to increase CCW system pressure above saturation pressure during all design basis accidents and accommodates changes in CCW system volume in combination with the surge tank. The head tank is constructed of austenitic stainless steel to provide added corrosion resistance and reduce maintenance requirements. Parameters are presented in Table 9.3-1. In addition to piping connections to the surge tank and Waste Holdup Tank, the head tank includes vacuum breaker protection, local level indication, and a valve for chemical addition, if required.
Residual Heat Removal Loop Components
Residual Heat Exchangers The two residual heat exchangers located within the auxiliary building are of the shell and U-tube type with the tubes welded to the tube sheet. Reactor coolant circulates through the tubes, while component cooling water circulates through the shell side. The tubes and other surfaces in contact with reactor coolant are austenitic stainless steel and the shell is carbon steel.
9.3-15 Revised 09/20/2016 C28 Residual Heat Removal Pumps The two residual heat removal pumps are in-line, centrifugal units with special seals to prevent reactor coolant leakage to the atmosphere. All pump parts in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material.
Residual Heat Removal Valves
The valves used in the residual heat removal loop are constructed of austenitic stainless steel or equivalent corrosion resistant material.
Manual stop valves are provided to isolate equipment for maintenance.
Throttle valves are provided for remote and manual control of the residual heat exchanger tube side flow. Check valves prevent reverse flow through the residual heat removal pumps.
Valves that perform a modulating function are equipped with two sets of packing and an intermediate leakoff connection that discharges to the Waste Disposal System. An alternate packing configuration is also used where full packing sets have been installed and leakoff lines were cut and capped.
Manually operated valves have backseats to facilitate repacking and to limit the stem leakage when the valves are open.
Turkey Point Unit 3 has Manual Operating features for selected air-operated valves as described in the Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4 (Reference 17) in the Residual Heat Removal Loop. The installation of these features provides a manual means of operating these valves if the valve misoperates.
Residual Heat Removal Piping
All residual heat removal loop piping is austenitic stainless steel. The piping is welded except for flanged connections at the control valves.
9.3-16 Revised 09/20/2016 C28 9.3.3 SYSTEM EVALUATION
Availability and Reliability
Component Cooling Loop
For continued cooling of the reactor coolant pumps, and the excess letdown
heat exchanger, most of the piping, valves, and instrumentation are located
outside the primary concrete shield at an elevation well above the
anticipated post-accident water level in the bottom of the containment. (The
exception is the cooling lines for the reactor coolant pumps which can be
isolated by two valves in series following the accident.) In this annular
area the component cooling equipment is protected against credible missiles
and from being flooded during post-accident operation. Also, this location
provides radiation shielding which allows for maintenance and inspections to
be performed during power operation.
Outside the containment, the residual heat removal pumps, the residual heat
exchangers, the spent fuel heat exchangers, the component cooling pumps and
heat exchangers, and associated valves, piping and instrumentation are
maintainable and inspectable during power operation. System design provides
for the replacement of one pump or one heat exchanger while the other units
are in service.
Several of the components in the component cooling loop are fabricated from
carbon steel. The component cooling water contains a corrosion inhibitor to
protect the carbon steel. Welded joints and connections are used except where
flanged closures are employed to facilitate maintenance. With the exception
of portions which are normally isolated, the entire system is seismic Class 1
design. The components are designed to the codes given in Table 9.3-4. In
addition the components are not normally subjected to any high pressures (See
Table 9.3-1) or stresses. Hence a rupture or failure of the system is very
unlikely.
During the recirculation phase following a loss-of-coolant accident, one of
the three component cooling water pumps delivers flow to the shell side of
one of the residual heat removal heat exchangers.
9.3-17 Revised 04/17/2013 C26 Residual Heat Removal Loop
Two pumps and two heat exchangers are available to remove residual and sensible heat during unit cooldown. If only one heat exchanger is operating, reduction of reactor coolant temperature is accomplished but at a lower rate.
With this operating condition, safe operation of the unit is not affected. The
function of this equipment following a loss-of-coolant accident is
discussed in Section 6.
Leakage Provisions
Component Cooling Water Loop
Welded construction is used where possible throughout the component cooling
loop piping, valves and equipment to minimize the possibility of leakage. The
component cooling water could become contaminated with radioactive water due
to a leak in any heat exchanger tube in the Chemical and Volume Control, the
Sampling, or the Auxiliary Coolant Systems, or a leak in the cooling coil for
the reactor coolant pump thermal barrier.
Tube or coil leaks in components being cooled would be detected during normal
operation as described in Sections 4.2.7 and 6.5.
Leakage from or to the component cooling water loop can be detected by a change of level in the component cooling head tank. The rate of water level
change and the area of the water surface in the head tank or subsequently in the surge tank, permits determination of the leakage rate. In-leakage from a
radioactive source may also be detected by radiation monitors located on the
main inlet headers. To assure adequate determination of leakage and the
potential leakage source, the operator would check that temperatures are
stable.
The component which is leaking can be located by sequential isolation or inspection of equipment in the loop. If the leak is in one of the component
cooling water heat exchangers, the leaking heat exchanger would be isolated
and repaired. During normal operation, the leaking heat exchanger could be
left in service with leakage up to the capacity of the makeup line to the
system from the primary water storage tank. By manual transfer, emergency
power is available for primary water pump operation.
9.3-18 Revised 04/17/2013 Volumetric expansion of the CCW system due to system temperature increases has been evaluated. For the CCW system, the most limiting temperature swing would
occur following a design basis accident when heat rejection to the CCW system
is not manually limited. For this condition, a CCW head tank insurge would
occur due to high heat loads and an overall increase in CCW system operating
temperature. An increase of 100 o F, which would bound any thermal swing postulated, would result in a volumetric expansion of approximately 350
gallons/header or 700 gallons total. The CCW head tank has a surge volume of
less than 200 gallons. If a large thermal insurge occurred (e.g. during a
LOCA), the overflow would be routed to the waste holdup tank. This would not
impact safe system operation.
The component cooling water temperature increase associated with a normal
plant cooldown will not overfill the component cooling water head tank;
however, the heatup associated with accident heat loads may be sufficient to
overflow the tank. The head tank vent line will isolate on high tank level;
however, that non-safety function is subject to single failure and may permit
the tank to overflow. If the head tank overflows, the loss of inventory is
not critical to CCW system function since the remaining head tank and surge
tank inventory is adequate to ensure continued system function.
Should a large tube side to shell side leak develop in a residual heat removal
heat exchanger, the water level in the component cooling head tank would rise, and the operator would be alerted by a high water level alarm. An isolation
valve in the vent line of the tank is automatically closed in the event of
high radiation level at the component cooling water pump suction header. If
the leaking residual heat exchanger is not isolated from the component cooling
loop before the inflow completely fills the head tank, the relief valve on the
surge tank lifts. The discharge of this relief valve is routed to the
auxiliary building waste holdup tank.
The severance of a cooling line serving an individual reactor coolant pump
cooler would result in substantial leakage of component cooling water.
However, the piping is small as compared to piping located in the missile
protected area of the containment. During normal operation, the water stored
in the CCW head tank and surge tank after a low level alarm together with
makeup flow provides ample time for the closure of the valves external to the
containment to isolate the leak before cooling is lost to the essential
components in the component cooling loop. If a design basis leak (defined as
a 50 gpm leak) were to occur coincident with a design basis LOCA, the
installed automatic valves in the supply and return lines to the RCP isolate
rapidly, such that the inventory remaining in the CCW head tank would be
sufficient to ensure continued CCW system operability under all design basis
conditions.
9.3-19 Revised 04/17/2013 The relief valves on the component cooling water header downstream from each of the reactor coolant pumps are designed to relieve the thermal expansion of
liquid enclosed in the piping system that can occur if the thermal barrier
cooling water return piping is isolated while a heat load continues to be
imposed by the thermal barrier heat exchanger. These relief valves protect
the cooling water supply and return piping associated with the reactor coolant
pump thermal barrier heat exchanger from overpressurization.
The relief valves on the cooling water lines downstream from the sample, excess letdown, seal water, non-regenerative, spent fuel pit and residual heat
exchangers are sized to relieve the volumetric expansion occurring if the
exchanger shell side is isolated when cool, and high temperature coolant flows
through the tube side. The set pressure equals the design pressure of the
shell side of the heat exchangers.
The relief valve on the component cooling surge tank is sized to relieve the
maximum flow rate of water which enters the surge tank following a rupture of
a reactor coolant pump thermal barrier cooling coil. The set pressure is lower
than the surge tank design pressure due to the installed static head tank.
The relief valve set pressure prevents overpressurization of the CCW piping
during design basis accident conditions. Initial protection is provided by an
isolation valve which automatically closes on high flow in the event of a
thermal barrier coil rupture.
During reactor operation all equipment of the residual heat removal loop is
idle, and the associated isolation valves are closed. During the loss-of-
coolant accident condition, water from the containment sump is recirculated
through the exterior piping system. To obtain the total radiation dose to the
public due to leakage from this system, the potential leaks have been
evaluated and discussed in Sections 6 and 14.
Each of the two residual heat removal pumps is located in a shielded
compartment with a floor drain. In each compartment the leakage drains to a
sump and is then pumped to the waste holdup tank by sump pumps. Two 75 gpm
sump pumps are provided in each compartment and each is capable of handling
the flow which results from the failure of a residual heat removal pump seal.
The residual heat exchangers are located in a third compartment with two sump
pumps.
Each sump has a level indicator which will warn the operator of high water
level. Both of the lines from the containment sump to the individual residual
heat removal pumps has two remotely operated isolation valves in series.
9.3-20 Revised 04/17/2013 Incident Control Component Cooling Loop
Component Cooling Containment isolation valves MOV-1417, -1418, and CV-739, are automatically closed on a Phase A containment isolation signal.
Component Cooling Containment isolation valves MOV-716B, -730, and -626 are
automatically closed on a Phase B containment isolation signal. The cooling
water supply header to the reactor coolant pumps contains a check valve
inside and two remotely operated valves outside the containment wall. The
cooling water supply line to the excess letdown heat exchanger contains a
check valve inside the containment which is closed during normal operation.
Except for the normally closed makeup line and equipment vent and drain
lines, there are no direct connections between the cooling water and other
systems. The equipment vent and drain lines outside the containment have
manual valves which are normally closed unless the equipment is being vented
or drained for maintenance or repair operations.
Following a loss-of-coolant accident, one component cooling water pump and
two component cooling water heat exchangers accommodate the heat removal
loads. If either a component cooling water pump or component cooling heat
water exchanger fails, one of the two remaining pumps provides 100% backup
and each standby heat exchanger provides 50% backup. Valves on the component
cooling water return lines from the safety injection, containment spray and
residual heat removal pumps are normally open. Each of the component cooling
water return lines from the residual heat removal heat exchangers has a
normally closed remotely operated valve. If one of the valves fails to open
at initiation of long-term recirculation, the valve which does open supplies
a heat exchanger with sufficient cooling to remove the heat load.
Normally cross-connected, redundant component cooling water headers are
provided for the unlikely event of a single failure in the component cooling
water system following a loss of coolant accident. Header cross-connect
valves are provided so that a passive failure (defined as 50 gpm leak) in the
system can be isolated and cooling water flow can still be maintained to the
necessary engineered safeguards equipment which require cooling water.
9.3-21 Revised 04/17/2013 Residual Heat Removal Loop The residual heat removal loop is connected to the reactor outlet line on the
suction side and to the reactor inlet line on the discharge side. On the
suction side, the connection is through two electric motor-operated gate
valves in series. Both these valves are interlocked with reactor coolant
system pressure. However, the autoclosure interlock (ACI) for these valves
may be defeated during RHR system operation for Reactor Coolant System
shutdown cooling in Modes 5 and 6. This action is intended to prevent a
pressure spike, either real or spurious, from causing a loss of the letdown
flow path which could potentially lead to RCS overpressurization and/or loss
of decay heat removal capability. On the discharge side the connection is
through two check valves in series and two electric motor operated gate
valves in parallel. All of these are closed whenever the reactor is in the
operating condition.
Malfunction Analysis
A failure analysis of pumps, heat exchangers and valves is presented in
Table 9.3-5.
9.3.4 TEST AND INSPECTION CAPABILITY
The residual heat removal pumps flow instrument channels can be calibrated
during shutdown.
The active components of the Auxiliary Coolant System are in either
continuous or intermittent use during normal operation. Component testing in
accordance with the plant IST Program is conducted, along with visual
inspections and preventative maintenance.
Samples are analyzed to determine the amount of radioactivity in the reactor
coolant system. If the radioactivity level is high a reactor coolant sample
is analyzed and Gamma Spectroscopy is used to determine the existence of
defects in fuel cladding. The frequency of sampling for gross activity and
for radiochemical analysis of the reactor coolant system will be adequate to
detect fuel clad defects to support operation as based on past experience.
9.3-22 Revised 04/17/2013 For the Residual Heat Removal System loop to be considered operable, it must
be filled with water to ensure that it can reliably perform its intended
function. To address this, Generic Letter 2008-01 was issued to discuss the
consequences of gas entrained in systems such as the Residual Heat Removal
System loop that could compromise their operability. In response to this, a
Gas Accumulation Management Program (GAMP) was established to provide long
term void management. Locations in the Residual Heat Removal System loop, where gases could potentially accumulate, are periodically monitored using
ultrasonic testing and/or vented to verify the system is filled. From the
results of this monitoring, the GAMP ensures that gas accumulated within the
Residual Heat Removal System loop is identified, evaluated, trended, and
effectively controlled to prevent unacceptable degradation of performance of
any structures, systems or components, ultimately to ensure system
operability.
Filling and venting operations and periodic system operational and leakage
tests are required to ensure that the Residual Heat Removal System loop
piping and components are not damaged from water-hammer loads that may result
from pump flows into voided discharge lines. The system must be periodically
verified full by venting the accessible discharge piping high points. The
inaccessible discharge piping high points that may be susceptible to gas
accumulation are deemed appropriate to proactively provide the capability to
vent each of these locations and to allow for future monitoring and trending, if it becomes necessary.
9.3-23 Revised 04/17/2013 9.
3.5 REFERENCES
- 1. Bechtel Letter SFB-2345 from G.N. Nutwell (Bechtel) to E. Preast (FPL), dated March 24, 1986.
- 2. NRC Letter "Component Cooling Water Flow Balancing - Turkey Point Plant Units 3 and 4," from D. G. McDonald (NRC) to C.O. Woody (FPL), dated
February 5, 1987.
- 3. Safety Evaluation, JPE-LR-87-45, "Justification for Continued Operation for ICW System Design," Revision 3, dated March 17, 1989.
- 4. NRC Safety Evaluation for Amendment No. 111 and 104 to Facility Operating Licenses for Turkey Point Units 3 and 4, respectively, dated
November 21, 1984.
Additional Information," dated October 5, 1984.
- 6. FPL letter L-76-178, "Proposed License Amendment to Facility Operating Licenses DPR-31 and DPR-41 Supplemental Information," dated April 30, 1976.
- 7. NRC letter to R. E. Uhrig (FPL) from George Lear (NRC), Re: Amendment No. 23 to License DPR-31 and Amendment No. 22 to License DPR-41, dated
March 17, 1977.
- 8. Safety Evaluation, JPN-PTN-SENP-95-026, Revision 03, "Safety Evaluation for CCW Flow Balancing and Post-Accident Alignment Requirements to
Support Current and Uprated Conditions," dated October 12, 1995.
- 9. Westinghouse WCAP-14276,"Turkey Point Units 3 and 4 - Uprating Licensing Report," Revision 1, dated December 1995 (Section 5.5.5).
- 10. Westinghouse WCAP-14291, Vols 1 - 3,"Turkey Point Units 3 and 4 -
Uprating Engineering Report for Thermal Power Uprate," dated December
1995.
- 11. FPL letter L-2002-151 to the NRC, "Reduction of Decay Time for Core off-load and Revision of Technical Specification 3/4.9.3," dated October 21, 2002.
9.3-24 Revised 04/17/2013 9.
3.5 REFERENCES
(cont'd)
- 12. NRC letter (Eva A. Brown) to FPL (J. A. Stall), "Turkey Point Units 3 & 4 - Issuance of Amendments Regarding Reduction in Decay Time From 100 Hours to 72 Hours (TAC Nos. MB6549 and MB6550), License Amendments 223/218, effective March 4, 2003.
- 13. Engineering Evaluation PTN-ENG-SENS-06-041, "Defeat of Residual Heat Removal System Suction Valve Autoclosure Interlock During Operation for Shutdown Cooling," Revision 0.
- 15. Westinghouse Calculation CN-SEE-I-11-15, "Turkey Point RHR Cooldown With One CCW HX Inoperable," Revision 0.
- 16. Westinghouse Technical Report WCAP-17152-P, "Turkey Point Units 3 and 4 Extended Power Uprate Engineering Report," August 2012.
- 17. STD-M-006, Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4.
9.3-25 Revised 09/20/2016 C28 TABLE 9.3-1 Sheet 1 of 2 COMPONENT COOLING WATER LOOP COMPONENT DATA
Component Cooling Water Heat Exchangers
Quantity 3 Type Shell and Straight Tube
Heat Transferred, Btu/hr (shutdown condition) 14.7 x 10 6 Heat Removal Capability (Design Basis Heat Load), Btu/Hr 62.2 x 10 6(3) Shell Side (component cooling water) :
- Inlet Temp.
o F 174.6 - Outlet Temp.
o F 158.6
- Maximum Allowable Unit 3 Flow Limits (gpm) : - Continuous Operation (TEMA limit)
(1) 4,063 - Normal Plant Evolutions (testing, surveillance 6,840 activities, heat exchanger cleaning, etc.;
Represents manufacturer's limit without vibration concerns) - 31 Day (erosion and vibration limit for 7,200 long-term post-accident recirculation)
- Initial Safety Injection 7,500 (erosion and vibration limit)
- Maximum Allowable Unit 4 Flow Limits (gpm) : - Continuous Operation (TEMA limit)
(1) 6,756 - Normal Plant Evolutions (testing, surveillance 8,000 activities, heat exchanger cleaning, etc.;
Represents manufacturer's limit without vibration concerns) - 31 day (erosion limit) 11,900
- Design Temperature, o F 200 - Design Pressure, psig 150
- Material Carbon Steel
Tube Side (intake cooling water) : - Inlet Temperature, (Nominal Design), o F 95 (2) - Outlet Temperature, (Nominal Design), o F 107 - Design Flow Rate, lb/hr 4.0 x 10 6 - Design Pressure, psig 100 - Design Temperature, o F 200 - Material Aluminum Brass
NOTES : 1. Tubular Exchanger Manufacturers Association.
- 2. The inlet temperature of 95 o F can be exceeded if heat exchanger performance monitoring demonstrates the ability to remove postulated post accident heat loads at the elevated inlet temperature.
- 3. This represents the heat removal rate at the stated accident conditions.
Actual heat removal will vary as a function of tube side and shell side flow
rates, ICW temperature, accident conditions, and heat exchanger fouling.
Revised 04/17/2013 C26C26 TABLE 9.3-1 (continued)
Sheet 2 of 2 Component Cooling Water Pumps
Quantity 3 Type Horizontal Centrifugal
Rated capacity, gpm, each 7500 Rated head, ft H 2 0 185 Motor horsepower, hp 450 Casing material Cast Iron Design pressure, psig 150
Design temperature o F 200 Component Cooling Water Surge Tank
Quantity 1 Volume, gal 2000 Normal water volume, gal. 1000 Design pressure, psig 100
Design temperature, o F 200 Construction material Carbon Steel
Component Cooling Head Tank
Quantity 1 Volume, gal 300 Normal water volume, gal 150 (approx.)
Design pressure, psig 100
Design temperature, o F 200 Construction material Stainless steel
Chemical Pot Feeder Tank
Quantity 1 Volume, gal 3 Design pressure, psig 150
Design temperature, o F 200 Component Cooling Water Loop Piping and Valves
Design pressure (except for the
excess letdown heat exchanger piping between valves *-738 and CV-*-739), psig 150
Design pressure of the piping between valves *-738 and CV-*-739), psig 200
Design temperature, o F 200
Revised 04/17/2013 TABLE 9.3-2 Sheet 1 of 2 RESIDUAL HEAT REMOVAL LOOP COMPONENT DATA
Reactor coolant temperature at startup of residual
heat removal, o F 350 Time to cool reactor coolant system from 350 o F to 140 o F, hr. (all equipment operational) 20 (NOTE 1)
Refueling water storage temperature, o F Ambient
Decay heat generation at 20 hrs after shutdown condition, Btu/hr. 53 x 10 6 (NOTE 2)
Approximate refueling cavity fill time, hr. 1
Approximate refueling cavity drain time, hr. 10
H 3 BO 3 concentration in refueling water storage tanks, ppm boron > 2400
Residual heat removal pumps Quantity 2 Type Vertical Centrifugal Rated capacity, gpm, each 3,750 Rated head, ft H 2 0 240 Motor horsepower, hp 300 Material Stainless Steel Design pressure, psig 600 Design temperature, o F 400 Residual Heat Removal Heat Exchangers Quantity 2 Type Shell and U-tube Heat transfer, Btu/hr 29.4 x 10 6
NOTE:
- 1. Cool down time for Extended Power Uprate was evaluated to be 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> to 200 o F under the most restrictive operating parameters. The maximum calculated time to reach 140 o F was 107 hours0.00124 days <br />0.0297 hours <br />1.76918e-4 weeks <br />4.07135e-5 months <br />.
- 2. This is a typical value of decay heat generation. The actual value varies slightly between units and fuel cycles.
- 3. RHR heat exchangers are rated for 600 psig but analyzed for structural capability to withstand an overpressure excursion up to 720 psig under OMS
conditions.
Revised 04/17/2013 C26C26 TABLE 9.3-2 (continued)
Sheet 2 of 2
Shell side (component cooling water) Inlet temperature, o F 108 Outlet temperature, o F 115 Design flow rate, lb/hr. 4.31 x 10 6 Design pressure, psig 150 Design temperature, o F 200 Material Carbon Steel
Tube side (reactor coolant)
Inlet temperature, o F 140 Outlet temperature, o F 124 Design flow rate, lb/hr. 1.87 x 10 6 Design pressure, psig 600 (NOTE 3) Design temperature, o F 400 Material Stainless Steel
Revised 06/30/2008 C23 TABLE 9.3-3
DELETED
Revised 09/29/2005
TABLE 9.3-4 AUXILIARY COOLANT SYSTEM CODE REQUIREMENTS
Component cooling water heat exchangers ASME VIII*
Component cooling water surge tank ASME VIII Component cooling water head tank ASME VIII Component cooling water system piping and valves USAS B31.1**
Residual heat removal heat exchangers Tube side ASME III***, Class C Shell side ASME VIII Residual heat removal piping and valves USAS 831.1
Spent fuel pit filter ASME III, Class C Spent fuel pit heat exchanger Tube side ASME III, Class C Shell side ASME VIII Supplemental spent fuel pit heat exchanger Tube side ASME III, Class 3 Shell side ASME III, Class 3 Spent fuel pit demineralizer ASME III, Class C Spent fuel pit loop piping and valves USAS B31.1
- ASME VIII - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section VIII ** USAS B31.1 - Code for Pressure Piping, and special nuclear cases where applicable *** ASME III - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section III, Nuclear Vessels.
Revised 04/17/2013 C26
TABLE 9.3-5
FAILURE ANALYSIS OF PUMPS, HEAT EXCHANGERS, AND VALVES
Components Malfunction Comments and Consequences
- 1. Component cooling water Rupture of a pump The casing is designed for 150 psi and 200 o F which pumps casing exceeds maximum operating conditions. Pump is inspectable and protected against missiles. Rupture due to missiles is not considered credible. Each unit is isolable. One of the three pumps can carry the total
emergency heat load.
- 2. Component cooling Pump fails to start One operating pump supplies sufficient water for water pumps emergency cooling.
- 3. Component cooling Manual valve on This is prevented by prestartup and operational checks.
water pumps a pump suction Further, during normal operation, each pump is checked line closed on a periodic basis which would show if a valve is closed.
- 4. Component cooling Valve on discharge The valve is checked open during periodic operation water pumps line sticks closed of the pumps during normal operation.
- 5. Component cooling Tube or shell Rupture is considered improbable because of low heat exchanger rupture operating pressures. Each unit is isolable. Two units can carry total emergency heat load.
- 6. Demineralized water Sticks open The check valve is backed up by the manually operated makeup line check valve. Manual valve is normally closed.
valve
- 7. Component cooling Left open This is prevented by prestartup and operational checks.
heat exchanger vent On the operating unit such a situation is readily or drain valve assessed by makeup requirements to system. Low level annunciation on the CCW head tank is used to identify system leakage.
- 8. Component cooling Fails to open There is one valve on each outlet line from each heat water valve from exchanger. One heat exchanger remains in service and residual heat provides adequate heat removal during long term exchanger recirculation. During normal operation the cooldown time is extended.
Revised 05/01/2005 TABLE 9.3-6 Sheet 1 of 1 ALLOWABLE RANGE OF FLOWS THROUGH COMPONENTS IN POST-LOCA RECIRCULATION MODE Minimum Maximum Component Flow GPM Flow GPM Containment Spray Pump Seal Cooler 5.6 20 Note 7 RHR Heat Exchanger 2,500 10,400 Note 1 HHSI Pump Seal and Bearing Coolers 7.0 20 Note 8 RHR Pump Seal Cooler 5.6 30 Emergency Containment Cooler 2000 3,200 Note 3 Spent Fuel Pit Heat Exchangers 1200 3,080 Note 9 Non-Regenerative Heat Exchanger
--- 1,235 Notes 1, 2 Charging Pump Hydraulic Coupling Cooler 50 57 Note 6 Seal Water Heat Exchanger
--- 227 Note 2 Sample Cooler
--- 44 Note 2 Waste Gas Compressor Seals
--- 90 Note 2 Unit 3 CCW Hx Shell Side
--- 7,200 Note 4 Unit 4 CCW Hx Shell Side
--- 11,900 Note 5 NOTES: 1. The maximum RHR and Non-Regenerative heat exchanger flow rates are component flow limits and not post-LOCA recirculation mode flow limits.
- 2. Only maximum flows are of interest for t he non-essential components which may not be isolated during an accident.
- 3. 3,200 gpm is acceptable for the Post-LOCA recircul ation period of one month. Refer to Table 6.3-1 for additional time dependent acceptable flow rates.
- 4. 7,200 gpm is a 31 day erosion / vibration limit for long-term post-accident recirculation. 7,500 gpm is acceptable for 20 minutes, 6,840 gpm for normal plant evolutions, and 4,063 gpm for continuous operation.
- 5. 11,900 gpm is a 31 day erosion limit for long-te rm post-accident recirculation. 8,000 gpm is acceptable for normal plant evolutions, and 6,756 gpm is acceptable for continuous operation.
- 6. Previous values were 20 gpm min. and 60 gpm max.
- 7. (Unit 4) New FLOWSERVE seal coolers installed via PC/M 07-081 are limited to a maximum flow of 17 gpm. 8. The Safety Injection Pump Seal Cooler could encounter a CCW maximum flow rate of 36 gpm during a LOCA. 9. 3080 gpm bounds the maximum flow for each spent fuel pit heat exchanger.
Revised 04/17/2013 C26C26C26C26C26C26
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-1 REFER TO ENGINEERING DRAWING 5613-M-3030 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-2 REFER TO ENGINEERING DRAWING 5613-M-3030 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-3 REFER TO ENGINEERING DRAWING 5613-M-3030 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-4 REFER TO ENGINEERING DRAWING 5613-M-3030 , SHEET 4
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-5 REFER TO ENGINEERING DRAWING 5613-M-3030 , SHEET 5
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-5
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-6 REFER TO ENGINEERING DRAWING 5614-M-3030 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-6
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-7 REFER TO ENGINEERING DRAWING 5614-M-3030 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-7
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-8 REFER TO ENGINEERING DRAWING 5614-M-3030 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-8
FINAL SAFETY ANALYSIS REPORT FIGURE 9.3-9 REFER TO ENGINEERING DRAWING 5614-M-3030 , SHEET 4
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 COMPONENT COOLING WATER SYSTEM FIGURE 9.3-9
9.4 SAMPLING SYSTEM 9.4.1 DESIGN BASES
Performance Requirements
This system provides samples for laboratory analysis to evaluate reactor coolant, and other reactor auxiliary systems chemistry during normal operation.
It has no active emergency function. This system is normally isolated at the
containment boundary.
Sampling system discharge flows are limited under normal and anticipated fault
conditions (malfunctions or failure) to preclude any fission product releases beyond the 10 CFR 20 guidelines. Each unit has an identical sampling system and
no equipment is shared between units except the drains and vents to the Waste
Disposal System. The description contained herein is equally applicable to
either unit.
Design Characteristics
The system is capable of obtaining reactor coolant samples during reactor operation and during cooldown when the system pressure is low and the residual
heat removal loop is in operation. Access is not required to the containment.
Sampling of other process coolants, such as tanks in the Waste Disposal System, is accomplished locally. Equipment for sampling secondary and non-radioactive
fluids is separated from the equipment provided for reactor coolant samples.
Leakage and drainage resulting from the sampling operations are collected and
drained to tanks located in the Waste Disposal System.
Two types of samples are obtained by the system: high temperature -high pressure Reactor Coolant System samples which originate inside the reactor containment, and low temperature -low pressure samples from the Chemical and Volume Control
and Auxiliary Coolant Systems.
9.4-1 High Pressure - High Temperature Samples A sample connection is provided from each of the following:
a) The pressurizer steam space
b) The pressurizer liquid space
c) Hot legs of loops A and B
Low Pressure - Low Temperature Samples
A sample connection is provided from each of the following:
a) The mixed bed demineralizer inlet header
b) The mixed bed demineralizer outlet header
c) The residual heat removal loop, just downstream of the heat exchangers
d) The volume control tank gas space
e) The accumulators
Expected Operating Temperatures
The high pressure, high temperature samples and the residual heat removal loop
samples leaving the sample heat exchangers are held to a temperature of
approximately 130 F to minimize the generation of radioactive aerosols.
Codes and Standards
System component code requirements are given in Table 9.4-1.
9.4-2 Rev 4 7/86 9.4.2 SYSTEM DESIGN AND OPERATION
The Sampling System, shown in Figures 9.4-1 and 9.4-2, provides the representative samples for laboratory analysis. Analysis results provide guidance in the operation of the Reactor Coolant, Auxiliary Coolant, Steam and Chemical and Volume Control Systems. Analyses show both chemical and radiochemical conditions.
Typical information obtained includes reactor coolant boron and chloride concentrations, fission product radioactivity level, hydrogen, oxygen, and fission
gas content, corrosion product concentration, and chemical additive concentration.
The information is used in regulating boron concentration adjustments, evaluating fuel element integrity and mixed bed demineralizer performance, and
regulating additions of corrosion controlling chemicals to the systems. The Sampling System is designed to be operated manually, on an intermittent basis.
Samples can be withdrawn under conditions ranging from full power to cold
shutdown.
Reactor coolant liquid lines, which are normally inaccessible and require frequent sampling, are sampled by means of permanently installed tubing leading
to the sampling room.
Sampling System equipment is located inside the auxiliary building with most of it in the sampling room. The delay coil and sample lines with remotely operated
valves are located inside the containment.
Reactor coolant hot leg liquid, accumulator liquid, pressurizer liquid and
pressurizer steam samples originating inside the containment flow through
separate sample lines to the sampling room. Each of these connections to the Reactor Coolant System has a remote operated isolation valve located close to the sample source. The samples pass through the containment to the auxiliary building, and into the sampling room, where they are cooled (pressurizer steam samples condensed and cooled) in the sample heat exchangers. The sample stream pressure is reduced by a manual throttling valve located downstream of each
sample pressure vessel. The sample stream is purged to
9.4-3 Rev 11 11/93 the volume control tank in the Chemical and Volume Control System or to the Waste Holdup Tank in the Waste Disposal System until sufficient purge volume has passed to permit collection of a representative sample. After sufficient purging, the sample pressure vessel is isolated and then disconnected for laboratory analysis
of the contents.
Alternately, liquid samples may be collected by bypassing the sample pressure
vessels. After sufficient purge volume has passed to permit collection of a
representative sample, a portion of the sample flow is diverted to the sample
sink where the sample is collected and in-line analysis may be performed.
The reactor coolant sample originating from the residual heat removal loop of
the Auxiliary Coolant System has a remote operated, normally closed isolation valve located close to the sample source. The sample line from this source is
connected into the sample line coming from the hot leg at a point upstream of the sample heat exchanger. Samples from this source can be collected either in
the sample pressure vessel or at the sample sink as with hot leg samples.
Liquid samples originating at the Chemical and Volume Control System letdown line at the mixed bed demineralizer inlet and outlet pass directly through the
purge line to the volume control tank. Samples are obtained by diverting a portion of the flow to the sample sink. If the pressure is low in the letdown line, the purge flow is directed to the chemical drain tank. The sample line from the gas space of the volume control tank delivers gas to the gas sample tree in the gas analyzer room adjacent to the primary chemistry lab. Valve alignments can be made to send gas to grab sample collection in the gas analyzer room, for isotopic analysis, or to the sample extraction board in the primary chemistry lab, for gas concentration analysis. An alternate sample line from the gas space of the volume control tank delivers gas samples to the volume control tank sample
pressure vessel in the sampling room.
The sample sink, which is located in the sampling room, contains a drain line to
the Waste Disposal System.
Local instrumentation is provided to permit manual control of sampling
operations and to ensure that the samples are at suitable temperatures and
pressures before diverting flow to the sample sink.
9.4-4 Rev. 16 10/99
Components A summary of principal component data is given in Table 9.4-2.
Sample Heat Exchangers
Three sample heat exchangers reduce the temperature of samples to 127 o F before samples reach the sample vessels and sample sink. The tube side of
the heat exchangers is Alloy 600 or austenitic stainless steel as shown on
Table 9.4-2, while the shell side is carbon steel.
The inlet and outlet tube sides have Swagelok high pressure fittings (for
connections to the high pressure sample lines. Connections to the component
cooling water lines are socket-weld joints. The samples flow through the
tube side and component cooling water from the Auxiliary Coolant System
circulates through the shell side.
Delay Coil
The reactor coolant hot leg sample line contains a delay coil, consisting of
coiled tubing, which has sufficient length to provide at least 40 seconds
sample transit time within the containment and an additional 20 seconds
transit time from the reactor containment to the sampling hood. This allows
for decay of short lived isotopes to a level that permits normal access to
the sampling room.
Sample Pressure Vessels
The high pressure sample trains, the residual heat removal loop sample train
and the volume control tank gas space sample train each contain sample
pressure vessels which are used to obtain liquid or gas samples. The hot leg
and the residual heat removal loop sample lines have a single sample pressure
vessel in common. Integral isolation valves are furnished with the vessel
and quick-disconnect coupling valves containing poppet-type check valves, are
connected to nipples extending from the valves on each end. The vessels, valves and couplings are austenitic stainless steel.
9.4-5 Rev. 16 10/99
Sample Sink The sample sink is located in a hooded enclosure which is equipped with an
exhaust ventilator. The work area around the sink and the enclosure is large
enough for sample collection and storage for radiation monitoring equipment.
The sink perimeter has a raised edge to contain any spilled liquid.
Piping and Fittings
All liquid and gas sample lines are austenitic stainless steel tubing and are
designed for high pressure service. Socket weld fittings and compression
fittings are used in the Sampling System, Both, inside and outside the
containment. Quick disconnect couplings are used on sample vessels and on
in-line analyzers. Lines are so located as to protect them from accidental
damage during routine operation and maintenance.
Valves Remotely operated stop valves are used to isolate all sample points and to
route sample fluid flow inside the reactor containment. Manual stop valves
are provided for component isolation and flow path control at all normally
accessible Sampling System locations. Manual throttle valves are provided to
adjust the sample flow rate as indicated on Figures 9.4-1 and 9.4-2.
Check valves prevent gross reverse flow of gas from the volume control tank
into the sample sink.
All valves in the system are constructed of austenitic stainless steel or
equivalent corrosion resistant material.
An isolation valve is provided outside the containment on all sample lines
leaving the containment, which fails closed and automatically closes upon
actuation of the containment isolation signal.
9.4-6 Rev. 16 10/99 9.4.3 SYSTEM EVALUATION
Incident Control
The system operates on an intermittent basis, and under administrative manual
control.
Malfunction Analysis
To evaluate system safety, the failures or malfunctions are assumed
concurrent with a loss-of-coolant accident, and the consequences analyzed.
The results are presented in Table 9.4-3. From this evaluation it is
concluded that proper consideration has been given to unit safety in the
design of the system.
9.4-7
TABLE 9.4-1 SAMPLING SYSTEM CODE REQUIREMENTS
Sample heat exchanger (3) ASME III (1), Class C, tube side ASME VIII, shell side
Sample pressure vessels ASME III, Class C
Piping and valves USAS B31.1 (2)
NOTES :
- 1. ASME III - American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section III, Nuclear Vessels.
- 2. USAS B31.1 - Code for Pressure Piping and special nuclear cases where applicable.
- 3. All three sample heat exchangers for Unit 4 and the pressurizer liquid sample heat exchanger for Unit 3 conform to ASME III Class 3, 1977
Edition, including the Summer 1977 Addenda.
Rev. 10 7/92
TABLE 9.4-2 Sheet 1 of 2
SAMPLING SYSTEM COMPONENTS
Sample Heat Exchanger (1)
General Number 3 Type Counter flow Design heat transfer rate (duty for
652.7 o F sat. steam to 127 o F liquid), each, Btu/hr 2.12 x 10 5 Shell Design pressure, psig 150 Design temperature, o F 350 Component cooling water flow, gpm 40 Pressure loss at 40 gpm, psi 25 Operating cooling water temperature, inlet, o F 105 Operating cooling water
temperature, outlet (maximum),
o F 130 Material Carbon steel Tubes Tube diameter, O.D., in.
3/8 Design pressure, psig 2485 Design temperature, o F 680 Sample flow, normal, each, lb/hr 209 Maximum allowable pressure loss, each 209 lb/hr, psi 10 Operating sample temperature, inlet (maximum),
o F 652.7 Operating sample temperature, outlet (maximum),
o F 127 Material Inconel 600, Austenitic stainless steel for Unit 3 pressurizer steam heat exchanger and Unit 3 reactor coolant heat exchanger.
NOTES : 1. All three sample heat exchangers for Unit 4 and the pressurizer liquid sample heat exchanger for Unit 3 meet or exceed the criteria specified.
Rev. 10 7/92
TABLE 9.4-2 SHEET 2 of 2
Sample Pressure Vessels Number, total 5
Volume, pressurizer steam sample, ml 75
Volume, pressurizer liquid sample, ml 75
Volume, reactor coolant hot leg sample, ml 75
Volume, volume control tank sample, ml 75
Design pressure, psig 2485
Design temperature, o F 680 Material Austenitic Stainless
Steel
Manual Throttle Valves Normal operating temperature, o F 120-130 Design pressure, psig 2485
Body design temperature, o F 680
Piping Liquid and gas sample line internal
diameter, in. 0.245
Design Pressure, psig 2485
Design temperature, o F 680
TABLE 9.4-3 MALFUNCTION ANALYSIS OF SAMPLING SYSTEM
Comments and
Sample Trains Malfunction Consequences
Pressurizer steam space Remotely operated A diaphragm-operated sample, pressurizer sampling valve valve on each line liquid space sample, inside outside the containment accumulator or hot containment fails is closed on containment leg sample to close high pressure signal.
Inside containment Sample line break A diaphragm-operated sample trains inside containment valve on each line upstream of remotely outside the containment operated valve is closed on containment high pressure signal.
FINAL SAFETY ANALYSIS REPORT FIGURE 9.4-1 REFER TO ENGINEERING DRAWING 5613-M-3036 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 NUCLEAR STEAM SUPPLY SYSTEM SAMPLE SYSTEM FIGURE 9.4-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.4-2 REFER TO ENGINEERING DRAWING 5614-M-3036 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 NUCLEAR STEAM SUPPLY SYSTEM SAMPLE SYSTEM FIGURE 9.4-2
9.5 FUEL STORAGE and HANDLING The Fuel Storage and Handling System provides a safe effective means of storing, transporting and handling fuel from the time it reaches the plant in an unirradiated condition until it is stored at the Independent Spent Fuel Storage Installation (ISFSI) or leaves the plant after post-irradiation cooling. The system is designed to minimize the possibility of malfunction that causes fuel damage and potential fission product release. The Fuel Storage and Handling System includes the new and spent fuel storage racks, refueling cavity, the spent fuel pit, spent fuel pit cooling and purification system and the fuel transfer system.
The ventilation system for new and spent fuel storage is described in Section 9.8.
Dry storage of spent fuel pursuant to 10 CFR 72 is provided as discussed in Section 1.2.10.
The following sections related to fuel storage and handling under 10 CFR 50.
The Technical Specification 5.5.1, "Criticality," critical design features for the storage racks are identified in Sections 9.5.1 and 9.5.2 and associated tables. These critical design features are highlighted to better ensure continued compliance with Technical Specification 5.5.1.
The identification of these critical design features of the storage racks is a corrective action to prevent recurrence from the root cause evaluation of AR 403641 and shall be maintained in the UFSAR consistent with the licensing basis criticality analysis.
9.5.1 NEW FUEL STORAGE 9.5.1.1 Design Basis
Criterion: Criticality in the new and spent fuel storage pits shall be prevented by physical systems or processes. Such means as geometrically safe configurations shall be emphasized over procedural controls. (1967 Proposed GDC 66)
Criterion: Provisions shall be made in the design of fuel and waste storage facilities such that no undue risk to the health and safety of the public could result from an accidental release of radioactivity. (1967 Proposed GDC 69)
9.5-1 Revised 09/20/2016 C28C28 b) provide sufficient spacing [Technical Specification 5.5.1 critical design feature] between fuel assemblies to maintain a subcritical
array (k eff 0.95) during flooding with unborated water; and
c) preclude the possibility of storing a fuel assembly in other than prescribed locations [Technical Specification 5.5.1 critical design
feature].
Additionally, upon implementation of the license amendments of the spent fuel pool cask racks (Reference 14), Turkey Point elected to comply (Reference 15) with the requirements of 10CFR50.68(b) (Reference 11)
which includes restrictions on the reactivity of stored fresh (new)
fuel. 9.5.1.2 System Description Table 9.5.1 provides the relevant design data for new fuel storage. The new fuel storage facility is located in the Auxiliary Building in the
new fuel room. New fuel is stored dry at a floor elevation of 18'6" with
the top of the rack at elevation 31'3".
The new fuel storage area is sized for storage of the fuel assemblies normally associated with the replacement of one-third of a core. New
fuel storage for each unit consists of an "L" shaped rack with 54 square
cavities arranged in a three deep array. New fuel assemblies are stored
in a vertical position within each cavity with a center-to-center
spacing between the fuel assemblies of 21" [Technical Specification
5.5.1 critical design feature]. The top of each cavity is separated
from the adjacent cavity by metal decking such that fuel assemblies may
only be placed in the designated spaces [Technical Specification 5.5.1
critical design feature]. The size of each cavity is approximately 9.5"
x 9.5" [Technical Specification 5.5.1 critical design feature].
The new fuel storage room is protected from missile impact by a concrete roof and concrete walls. The entry into the new fuel storage facility
consists of a roll-up metal door, which is not missile resistant.
However, the only safety related components which are exposed to missile
impact through the door opening are new fuel assemblies. Since these
assemblies are not irradiated, they do not present a potential for
uncontrolled release of radioactivity in excess of 10CFR50.67
guidelines.
The method of transferring new fuel to the new fuel storage room and into the new fuel storage racks is discussed in Section 9.5.4
9.5-2 Revised 04/17/2013 C26 9.5.1.3 System Evaluation
The new fuel storage racks store new fuel vertically in an array that maintains K eff 0.95, even if flooded with unborated water. This is accomplished by a center-to-center spacing of 21" between the fuel
assemblies when stored in the new fuel storage rack. Since the new fuel
storage rack is designed with metal decking between storage cavities, the placement of fuel assemblies in other than prescribed locations is
not possible.
The new fuel storage facilities are designed as Class 1 Structures, Systems and Equipment and built in accordance with applicable codes.
Chapter 5, Appendix 5A details the Seismic Classification and Design
Basis for the storage facility.
9.5.2 SPENT FUEL STORAGE
9.5.2.1 Design Basis
Criterion: Criticality in the new and spent fuel storage pits shall be prevented by physical systems or processes. Such means as
geometrically safe configurations shall be emphasized over
procedural controls. (1967 Proposed GDC 66)
Criterion: Adequate shielding for radiation protection shall be provided in the design of spent fuel and waste storage
facilities. (1967 Proposed GDC 68)
Criterion: Provisions shall be made in the design of fuel and waste storage facilities such that no undue risk to the health and
safety of the public could result from an accidental release
of radioactivity. (1967 Proposed GDC 69)
The spent fuel storage racks are designed:
a) to allow storage of no more than 1510 fuel assemblies in the spent fuel storage pit racks (286 fuel assemblies in Region I racks and no more than 1093 fuel assemblies in Region II racks and 131 fuel assemblies in the Region I cask area rack);
b) to maintain subcritical conditions with a K eff of less than 1.0 with unborated water in the spent fuel pit;
9.5-3 Revised 04/17/2013 C26
c) to maintain subcritical conditions with a K eff of less than or equal to 0.95 with a specified level of soluble boron;
d) to preclude the possibility of storing a fuel assembly in other than prescribed locations [Technical Specification 5.5.1 critical design
feature];
e) to allow spent fuel cooling by the spent fuel pit cooling system;
f) 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[3];and
g) to Seismic Category I requirements, and are classified as ANS Safety Class 3 and ASME Code Class 3 Component Support Structures.
Additionally, upon implementation of the license amendments of the spent fuel pool cask racks (Reference 14), Turkey Point elected to comply (Reference 15) with the requirements of 10CFR50.68(b) (Reference 11)
which includes restrictions on the reactivity of stored spent fuel.
9.5.2.2 System Description Auxiliary Building The Auxiliary Building (including the spent fuel portion) is designed to Seismic Category I requirements. The spent fuel storage portion of the
Auxiliary Building has reinforced concrete walls, floors and roof with
interior partitions designed to provide plant personnel with the
necessary radiation shielding and to protect the equipment from the
effects of adverse atmospheric conditions including hurricane and
tornado winds, temperature, external missiles, and corrosive
environment. The walls and floors of the spent fuel pit are lined with
stainless steel. The spent fuel storage structure with the augmented
storage capability has been analyzed for the loads and loading
combinations listed in Chapter 5, Appendix 5A for Class I structures.
The increased loading due to additional storage of spent fuel elements
in the pit and cask area was included in the analysis.
9.5-4 Revised 04/17/2013 The analysis results confirmed that the structural integrity of the spent fuel storage area of the Auxiliary Building, when subjected to an increased number of stored fuel assemblies, including the installation
of Metamic inserts in Region II Racks, is maintained under all required
load combinations (References 1 and 17).
Spent Fuel Pit The fuel storage portion of the Auxiliary Building is shown on Figures 9.5-3, 9.5-4 and 9.5-5. The spent fuel pit is located in the Auxiliary
Building and is designed for the underwater storage of up to 1535 fuel
assemblies in the spent fuel pit (approximately 9 full cores) including
131 spent or fresh fuel assemblies in the cask area rack and
miscellaneous fuel handling tools. The spent fuel pit contains both
Region I and Region II racks. The spent fuel rack layout is shown on
Figure 9.5-6.
The combined number of fuel assemblies loaded into the spent fuel pool storage racks and the cask pit rack is restricted to no more than the
capacity of the spent fuel pool storage racks except during activities
associated with reactor core offload/reload refueling activities (Reference 14).
From the 1118 storage cells in the Region II racks, 25 cells are removed from fuel storage service leaving 1093 cells available in Region II for fuel storage service.
These cells are located in or in close proximity to the cooling system return piping discharge flow path. Some of these cells in the discharge
flow path are damaged by flow-induced vibration in such a manner that
storage cells no longer conform to the center-to-center spacing
requirements of the storage cells. The damaged cells and those cells in
close proximity to the discharge flow path are restricted from fuel
storage service (Reference 19) to assure fuel is not damaged and
sub-criticality requirements are maintained.
Additional cooling capacity was added to support increased SFP heat load due to EPU. The added cooling flow required an impingement plate to be installed below the return pipe over the damaged cells. In order to reduce the return flow velocity adequately, the impingement plate extends beyond the damaged cells such that a total of 25 cells are removed from service.
9.5-5 Revised 04/17/2013 C26C26C26 Region I Spent Fuel Pit Racks The spent fuel pit Region I racks consist of two (2) 8 x 11 modules and one (1) 10 x 11 module for a total of 286 storage locations. Region I is the high- enrichment, core off-load region. Region I racks in the
spent fuel pit permit storage of 286 fresh and irradiated fuel
assemblies.
The Region I storage racks are free-standing, seismically qualified components composed of individual storage cells made of stainless steel.
These racks have a neutron absorbing material, Boraflex, which is
attached to each cell. No credit is taken for Boraflex in the
criticality safety analysis. The cells within a module are
interconnected by grid assemblies to form an integral structure as shown
in figure 9.5-7. Each Unit 3 rack module is provided with leveling
screws which contact the spent fuel pool floor embedments and are
remotely adjustable from above through the cells at installation. Each
Unit 4 rack module has plates under the interior support pads rather
than leveling screws. The modules are neither anchored to the floor nor
braced to the pool walls.
A typical fuel rack assembly consists of three major sections which are the leveling screw, the lower and upper grid assemblies, and the cell
assembly. The tops of the support plates are welded to the fuel rack
base plate. The leveling screws transmit the loads to the pool floor
embedments, provide a sliding contact, and provide for the leveling
adjustment of the rack. The lower grid consists of box-beam members, side plates and the base plate. The bottom of the cell assembly is
welded to the lower grid. The upper grid consists of box-beam members
and side plates. The upper part of the cell assembly is welded to the
upper grid. The upper and lower grid assemblies maintain the 10.6-inch
centerline-to-centerline spacing between the cells [Technical
Specification 5.5.1 critical design feature] and provide the structural
connections between the cells to form a fuel rack assembly.
The major components of the cell assembly are the fuel assembly cell, the Boraflex (neutron absorbing) material for which no credit is taken
in the rack criticality analysis, and the wrapper. The wrapper is
attached to the outside of the cell by spot welding the entire length of
the wrapper. The wrapper covers the Boraflex material and also provides
for venting of Boraflex to the pool environment. Depending on the
location within the rack array, some cells have a Boraflex/wrapper
assembly on four sides, three sides or two sides.
9.5-6 Revised 04/17/2013 C26 Without credit for Boraflex as a neutron absorber, the placement of fuel into Region I is now controlled based on specific loading patterns, defined by four allowable 2x2 arrays. The use of RCCAs (see Table 9.5-22) as a neutron absorber is credited in two of the
defined loading patterns.
Region II Spent Fuel Pit Racks
The Region II racks consist of three (3) 9 x 13 modules, one (1) modified 9 x 13 module, one (1) 9 x 14 module (minus 25 cells removed
from fuel storage service), three (3) 10 x 13 modules and one (1) 10 x
14 module for a total storage capacity of 1093 fuel assemblies (see
Figure 9.5-6).
The Region II storage racks are the same basic design as the spent fuel pit Region I racks with the following exceptions:
a) The cells are assembled in a checkerboard pattern with a 9.0-inch centerline-to-centerline spacing [Technical Specification 5.5.1
critical design feature] shown in Figure 9.5-8.
b) The cells are welded to the base support assembly and to one another to form an integral structure without use of grids as used in spent
fuel pit Region I racks.
c) The Region II racks were manufactured with Boraflex poison panels installed; however, due to the degradation, Boraflex poison panels
are no longer credited in the criticality analysis. As a
consequence, criticality control within the Region II spent fuel
racks is provided by following prescribed loading patterns which
include specific fuel categories based upon enrichment, burnup and
cooling time, along with the use of a combination of Rod Cluster
Control Assemblies (RCCAs), water gaps and Metamic inserts (see
Table 9.5-23). Metamic inserts are a metal matrix composite of
aluminum and boron carbide. The Metamic inserts are manufactured
with a nominal boron carbide content of 0.0160 g/cm 2 and a minimum of 0.0150 g/cm 2 [Technical Specification 5.5.1 critical design feature].
Metamic inserts will be installed in Region II racks cells between
the fuel assembly and the inside cell wall (see Figures 9.5-14 and
9.5-15), when required by the specific loading pattern.
9.5-7 Revised 04/17/2013 C26C26 It is demonstrated in Reference 18 that by following the prescribed loading schemes along with the use of a combination of RCCAs, Metamic and water gaps, Region II spent fuel rack criticality is
controlled. Due to fabrication/installation issues, it is preferred
that the Metamic inserts be installed in the spent fuel pit rack
resultant cells; however, there is no prohibition to installation in
formed cells, when required.
Cask Area Rack The cask area of the spent fuel pit is designed for the installation of a fuel transfer cask to allow fuel transfer operations. However, to
provide increased fuel storage capability, a rack may be installed in
the cask area when not performing fuel transfer operations. The Region
I cask area rack is a 11 x 12 module with 131 storage locations (one
location has been omitted to allow the placement of a fuel handling
tool). The cask area rack is of the same basic design as the spent fuel
pit Region I racks with the following exceptions: a) The center-to-center spacing of the cells is 10.1" E-W and 10.7" N-S
[Technical Specification 5.5.1 critical design feature](see Figure
9.5-9). b) Boral panels are installed as a neutron absorber instead of Boraflex. c) Bearing pads, 12" square, are installed between the rack leveling screws and the pit floor to provide sliding contact and distribute
the rack weight. When fuel transfer operations are necessary, fuel assemblies stored in the cask area rack will be relocated to the spent fuel pit racks and the
cask area rack will be removed, decontaminated, as necessary, and placed
in storage.
Controls for the installation of the cask area rack contain two hold points to ensure proper orientation of the racks in the spent fuel pool
[Technical Specification 5.5.1 critical design feature]. Verification
of the proper cask rack orientation is implemented by an authorized
quality control inspector during installation of the racks to ensure
consistency with associated spent fuel pool criticality analysis
assumptions (Reference 18).
9.5-8 Revised 04/17/2013 C26C26 Radiation Protection Radiation levels in the spent fuel storage area of the Auxiliary Building are controlled within limits during normal storage operations by maintaining a prescribed water level in the spent fuel pit to provide
shielding. During reactor refueling, adequate shielding for radiation
protection is provided by conducting all spent fuel transfer and storage
operations underwater. This permits visual control of the operation at
all times while maintaining low radiation levels, as low as reasonably
achievable for periodic occupancy of the area by operating personnel.
The spent fuel pit water level is indicated by a level transmitter which
causes an audible alarm in the control room on high or low levels, and
water removed from the pit must be pumped out since there are no gravity
drains. 9.5.2.3 System Evaluation Criticality Analysis
Criticality of fuel assemblies stored in the spent fuel pit storage racks is prevented in the following ways: In the cask area rack, a Region I storage rack, criticality is prevented by the design of the rack which limits fuel assembly
interaction by fixing the separation distance between stored
assemblies and/or by placing a neutron absorber panel between storage
cells. The Region I and Region II spent fuel pit storage racks were
manufactured with Boraflex poison panels; however, due to
degradation, Boraflex is no longer credited in the criticality
analysis. Currently, criticality is controlled in these racks by
specific fuel storage patterns based on minimum burnup values for
selected enrichments and cooling times and the use of a combination
of RCCAs, Metamic inserts and/or water gaps. The design of the spent fuel pit racks incorporates the requirements of, and are in accordance with, USNRC "OT Position for Review and Acceptance
of Spent Fuel Storage and Handling Applications, "April 14, 1978, as
amended by the NRC letter dated January 18, 1979 and the applicable
portions of the NRC Regulatory Guides, Standard Review Plan Sections and
published standards as listed in Table 9.5-17.
9.5-9 Revised 04/17/2013 The design criteria for preventing criticality in the spent fuel pit storage racks and the cask area rack are provided in Reference 11 and are based on the 95/95 rule, i.e., criticality calculations are
performed with a 95% probability at a 95% confidence level. The criteria
are as follows:
- 1. k eff less than 1.0, without the presence of soluble boron; 2. k eff less than or equal to 0.95 with the presence of a defined level of soluble boron in the spent fuel pit water.
Spent Fuel Pit Storage Racks
The criticality analysis of Reference 18 qualifies the spent fuel pit storage racks for the current and future inventory of spent fuel. Note that the cask area rack is addressed separately. The spent fuel pit storage rack analysis was based on:
The storage of fuel assemblies in a 2 X 2 array Fuel categories determined by enrichment, burnup and post-irradiation cooling times Rules and restrictions for combining the 2 X 2 arrays and fuel categories to create acceptable loading patterns The criticality safety analysis was performed using the three-dimensional SCALE Version 5.1 Monte Carlo code package and the two dimensional PARAGON lattice code.
The methodology for depleting fuel assemblies to support burnup credit in the spent fuel pool criticality safety calculations includes the depletion of two-dimensional unit assemblies as an infinite array in reactor core geometry with PARAGON at the bounding reactor core conditions. Once the fuel assembly is depleted to a desired assembly-average burnup, it is allowed to decay to its most reactive state. The assembly-averaged isotopic concentrations from PARAGON are then brought to cold conditions, 68°F and 14.7 psi. The following assumptions are made during the depletion simulations.
A bounding moderator temperature profile is assumed A bounding relative power profile is assumed Each fuel assembly contains a bounding amount of burnable poison absorber rods (BPRAs) and/or integral fuel burnable absorber (IFBA) A bounding soluble boron concentration is assumed 9.5-10 Revised 04/17/2013 C26 KENO V.a, part of the SCALE package was used for all criticality calculations. All references to KENO in this section refer to KENO V.a.
In general, KENO three-dimensional calculations model a 2x2 array of cells surrounded by periodic boundary conditions. Additional KENO models with more than four cells and different boundary conditions are generated to investigate the effect of eccentric fuel assembly positioning, interfaces between racks, and to analyze accident conditions. The following assumptions are made during the criticality calculations.
All calculations are performed using an explicit model of the fuel and storage cell geometry. Calculations are performed assuming an infinite radial array of fuel assemblies or assembly patterns. Specifically, all gaps between adjacent Region II rack modules are conservatively ignored, i.e., cells in neighboring Region II rack modules are assumed to be separated by a single cell wall only. The actual configuration in the Turkey Point spent fuel pool has a cell wall on each side of the Region II rack-to-rack gap. Region I rack-to-rack separation was also ignored. The three-dimensional KENO models assume 60 cm of unborated water above and below the active fuel length, even when soluble boron is credited in the analysis. This conservatively bounds the effect of any borated water displacement due to end fittings. All inserts are assumed to have the same orientation as is depicted in Figure 9.5-16. [Technical Specification 5.5.1 critical design feature]. All of the final two insert calculations are performed with the two inserts in the same row, a "parallel" arrangement. because this gives a more limiting (higher) k eff results than a checkerboard arrangement. The normal operating temperature range of the Turkey Point spent fuel pools is accounted for in each storage array with the application of a temperature bias which includes Monte Carlo uncertainties. Empty cells credited in the analysis are modeled as containing only full density water [Technical Specification 5.5.1 critical design feature]. Note: Metamic inserts and RCCAs are allowed in empty cells.
Using the results of the criticality and bias and uncertainty calculations, loading curves are calculated for each 2x2 array. The analysis utilized conservative targets by ensuring that:
- 1. k eff for all permissible storage configurations remains <
0.94 when the storage racks are fully loaded with fuel of the highest permissible reactivity and the pit is flooded with borated water at the temperature corresponding to the highest reactivity.
9.5-11 Revised 04/17/2013 C26
- 2. k eff remains < 0.99 if the pit is flooded with unborated full-density water at the temperature corresponding to the highest reactivity.
The maximum k eff values are calculated with a 95% probability at a 95%
confidence level and include all applicable biases and uncertainties.
The acceptance criteria utilized in the development of the loading curves maintains a minimum 0.01 k (1000 pcm) margin to the regulatory requirements.
Applicable biases and uncertainties account for the effects of physical variations of the fuel and racks, characterization of fuel burnup, and the validation of KENO. Physical variations considered include the reactivity effects of manufacturing tolerance for the fuel, rack, and poison inserts, as well as the potential for eccentric loading of the fuel within the racks in addition to the effects of variation in pit water temperature. For storage arrays which credit fuel burnup uncertainties associated with fuel depletion, reactor records, fission product worth, and variation in reactor power operating history are also considered. A bias and bias uncertainty to validate KENO was also developed and included based on the comparison of KENO calculated results to laboratory criticality experiments. All biases and uncertainties used in the criticality analysis are discussed in detail in Section 4.3.2 of Reference 18.
For all Fuel Categories except I-1 and 1-2, an equation specifying the minimum required burnup as a function of the initial enrichment and post-irradiation cooling time is developed. The uncertainty in the burnup is included in the determination of the minimum burnup requirement and so it is appropriate to use the nominal burnup for comparing to the minimum required burnup determined from the loading curves. The burnup requirements are established as 3rd degree polynomial functions in the form of:
Bu = (A 1 + A 2*En + A 3*En 2 + A 4*En 3)* exp [ - (A 5 + A 6*En + A 7*En 2 + A 8*En 3)*Ct] + A 9 + A 10*En + A 11 , *En 2 + A l2*En 3 where: Bu = Minimum required assembly average burn up (GWd/MTU) En = Initial Enrichment (Nominal 235 U Enrichment) (wt%) Ct = Post Irradiation Cooling Time (years) Ai = Coefficients (see Tables 9.5-19 and 9.5-20)
9.5-12 Revised 04/17/2013 C26 Separate functional relationships are developed for blanketed and non-blanketed fuel assemblies. Pre-EPU blanketed assemblies must use the EPU curves. Note that for blanketed assemblies, the enrichment to be used in the loading curve equation is the enrichment of the axial section between the blanket material (the enrichment of the axial blankets is excluded when determining the assembly enrichment for application of loading curve).
Since the loading curve is an exponential in cooling time, any cooling time between 0 and 25 years is allowed to be evaluated by the curve for blanketed fuel assemblies and between 15 years and 25 years for non-blanketed fuel assemblies. Fuel assemblies with cooling times greater than 25 years must conservatively use a value of 25 years.
The loading curves are valid for any enrichment between 2.0 and 5.0 wt.%
for blanketed assemblies and between 1.8 and 4.0 wt.% for non-blanketed assemblies.
Coefficients for all loading curves, for both blanketed and non-blanketed assemblies are listed in Tables 9.5-19 and 9.5-20.
After the loading curves were developed, they were validated using confirmatory calculations. In addition to confirming the individual storage arrays, all interfaces between arrays within a region and between regions were confirmed to comply with the applicable regulatory requirements.
Calculations were also performed to confirm that a soluble boron concentration of 500 ppm in the spent fuel pit ensures that k eff does not exceed the regulatory limit of 0.95 under normal conditions for all fuel storage arrays.
Cask Area Storage Rack The approach taken for the cask area storage rack was different than that taken for the rest of the spent fuel pit storage racks. For the cask area storage rack, all fuel and rack dimensions are set to the worst case tolerances and positions. The fuel is modeled as fresh 5.0 wt.%
235 U. After the addition of the validation bias and bias uncertainty, the worst case k eff is 0.9735 which is well below the regulatory limit for the unborated case. The 500 ppm soluble boron requirement was developed for the non-cask area storage arrays, which are more reactive when unborated. Therefore, it is clear that for the Cask Area Rack, when soluble boron is considered, the k eff limit of <
0.95 is satisfied.
9.5-13 Revised 04/17/2013 C26 Postulated Accidents Affecting Reactivity The following reactivity increasing accidents are considered in this analysis:
Misloaded fresh fuel assembly into incorrect storage rack location Inadvertent removal of an absorber insert Spent fuel pool temperature greater than normal operating range (150°F) Loss of water gap between Region I and Region II due to seismic event Dropped fresh fuel assembly Misplaced Fuel assembly in the spent fuel pit racks Misplaced Fuel assembly in the cask area storage rack Misloaded cask area storage rack Misloaded upender The misloaded fresh fuel accident scenario is analyzed by placing a 5.0 wt.% 235 U fresh fuel assembly into the water-filled cell required by Array II-A. This is expected to be the bounding condition since the fresh assembly is being surrounded by the most reactive fuel allowed in Region II. A 6x6 model is utilized with periodic boundary conditions containing one misloaded fresh fuel assembly. A misload into one of the empty cells in Array I-A is also analyzed and found to be less limiting. This accident requires 1683 ppm of boron to maintain k eff less than 0.95, including biases and uncertainties.
The removal of an absorber insert from an already analyzed array is bounded by the misload because the incorrectly placed assembly will be more heavily burned than the analyzed misload case, therefore this accident is covered.
The spent fuel pool is to be operated at less than 150 °F. However, under accident conditions this temperature could be higher. This condition is analyzed and found to be less limiting that the fresh misload case.
A seismic event could reduce the spacing between rack modules in the spent fuel pool. This accident scenario is analyzed by not modeling any water gap between a representative Region I and Region II interface model.
Additionally, the fuel assemblies are eccentrically positioned toward the interface.
Results demonstrate a large margin to the regulatory limit, therefore the remaining interfaces are not analyzed.
9.5-14 Revised 04/17/2013 C26 During placement of the fuel assemblies in the racks, it is possible to drop the fuel assembly from the fuel handling machine. The dropped assembly could land horizontally on top of the other fuel assemblies in the rack. In this case, there is significant separation between the dropped fuel assembly and the rest of the fuel assemblies due to the top nozzle, fuel rod plenum, fuel rod end plug. and the separation between the fuel rod and the top nozzle. It is clear that the misloaded fresh fuel assembly described above is far more limiting than a single assembly lying horizontally on top of other assemblies in the rack. It is also possible that a fuel assembly could be dropped in its location with such force that the resultant fuel assembly deforms the support structure such that more of the fuel assembly is below the absorbers. The removal of an absorber insert represents 100% of the assembly below the absorber and this has already been evaluated to be non-limiting.
It is possible to misplace a fuel assembly in a location not intended for fuel. Any assembly placed outside of the racks is surrounded by water on at least two sides. The misloaded fresh assembly discussed above is surrounded by fuel on all four sides. The additional neutron leakage of the two sides not facing fuel ensures that this condition is bounded by the fresh misload event. The Cask Area Rack has a corner where there is no storage cell box. It is possible, though very unlikely, that a fresh fuel assembly could be placed in this corner such that there is only one panel of Boral separating this misplaced fuel assembly from the fuel assemblies in the Cask Area Rack.
This condition was analyzed and found to be bounded by the fresh misload event. One side of the Cask Area Rack does not contain any Boral absorber because it is designed to face the pool wall. While it is considered extremely unlikely that the cask rack could be mis-positioned, if the entire rack is rotated 180 degrees, then the side with no Boral will be facing fuel assemblies in Region II. This condition was analyzed and found to be bounded by the fresh misload event.
When a fuel assembly is positioned in the upender, it possible to bring another fuel assembly in close approach to the upender. The condition of having two fully enriched fuel assemblies in direct contact with one another is bounded by the misload into the storage array I-A. While the assemblies are slightly closer together in the upender event, the I-A misload accident surrounds the misloaded assembly with fresh fully enriched fuel on all sides. The additional leakage associated with having no neighboring assemblies ensures that this accident is bounded.
9.5-15 Revised 04/17/2013 C26 For an occurrence of the postulated accident conditions, the double contingency principle of ANSI/ANS-8.1-1983 can be applied. It specifies that assumption of two unlikely, independent, concurrent events need not be considered to ensure protection against a criticality accident. Dilution of the boron concentration in the spent fuel pool and the misload of an assembly are two independent accidents. Therefore, for the accident conditions postulated, the presence of additional soluble boron in the storage pool water (above the concentration required for normal conditions) can be assumed as a realistic initial condition.
The spent fuel pool boron dilution analysis was performed to support the partial credit of soluble boron. The purpose of the analysis was to determine that sufficient time is available to detect and mitigate dilution of the spent fuel pool prior to exceeding the k eff design bases limit of 0.95. The analysis utilized 1950 ppm as the spent fuel pool initial boron concentration and evaluated the dilution to 650 ppm. The dilution analysis concluded that an inadvertent or unplanned event that reduced the boron concentration below 650 ppm was not credible. The required initial spent fuel pool boron concentration has increased to 2300 ppm while the required boron concentration to maintain a k eff of 0.95 has been reduced to 500 ppm.
Therefore, the previous boron dilution analysis bounds the current boron limit in the Technical Specifications and the amount of soluble boron credited in the criticality safety analysis.
9.5.3 SPENT FUEL PIT COOLING AND PURIFICATION 9.5.3.1 Design Basis
The spent fuel pit cooling and purification system is designed to :
a) remove the residual decay heat generated by the spent fuel elements (9 full cores) stored in high-density fuel racks contained within
each spent fuel pit; b) maintain the spent fuel pool water temperature less than 150°F for planned refuelings; c) maintain purity and optical clarity of the spent fuel pit water; d) remain functional during and after seismic events; and e) remain structurally intact at spent fuel pit water temperatures of 212°F.
9.5-16 Revised 04/17/2013 C26 9.5.3.2 System Description
The spent fuel pit cooling loop is designed to remove residual heat from fuel assemblies stored in the high-density storage racks contained
within the spent fuel pit. Following completion of a normal refueling, up to 80 fuel assemblies are permanently discharged and stored in the
spent fuel pit along with previously discharged fuel assemblies. During
a typical refueling outage, the full core is off-loaded to the spent
fuel pit. The cooling loop is capable of removing the decay heat from
1535 assemblies (1404 assemblies in the spent fuel pit storage racks and
131 assemblies stored in the cask area rack, when installed). The
discharged spent fuel is stored in the spent fuel pit until it can be
shipped off site.
The spent fuel pit cooling loop consists of pumps, heat exchangers, filters, a demineralizer, piping and associated valves and instrumentation. The pumps draw water from the spent fuel pit, circulate it through the heat exchangers and return it to the spent fuel pit. The component cooling water system cools the heat exchangers.
Spent fuel cooling loop component data is provided on Table 9.5-16. The cooling loop has been analyzed and is designed to remain functional
during and following a seismic event and to structurally withstand a
design temperature of 212°F. The available NPSH exceeds the pump NPSH
requirement at the design flow for temperatures up to 209°F, for each of
the installed pumps in the procedurally controlled normal system
alignment. Loop piping is so arranged that failure of any pipeline does
not drain the spent fuel pit to less than 6 feet above the top of the
stored fuel elements. The clarity and purity of the spent fuel pit
water is maintained by passing approximately 5% of the loop flow through
filters and demineralizer. The spent fuel pit pump suction lines, penetrate the spent fuel pit wall above the fuel assemblies. The
penetration location prevents loss of water as a result of a possible
suction line rupture. The return lines have a 1/2-inch hole in the pipe
near the normal level for a siphon break function.
Since the spent fuel pit is located outside the containment, it is not affected by any loss-of-coolant accident in the containment. The water
in the pit is isolated by a valve in the refueling canal during most of
the refueling operation. Only a very small amount of interchange of
water occurs as fuel assemblies are transferred during refueling.
9.5-17 Revised 04/17/2013 C26C26C26 Component Description Spent Fuel Pit Heat Exchangers The spent fuel pit heat exchangers are of the shell and U-tube type with the tubes welded to the tube sheet. Component cooling water circulates
through the shell, and spent fuel pit water circulates through the
tubes. The tubes are austenitic stainless steel and the shell is carbon
steel. Spent Fuel Pit Pumps The spent fuel pit pumps circulate water in the spent fuel pit cooling loop. All wetted surfaces of the pumps are austenitic stainless steel, or equivalent corrosion resistant material. Pump operations are
manually controlled from a local station. The cooling loop design does
not incorporate redundant active cooling components (primarily pumps),
because of the large heat capacity of the spent fuel pit and its
corresponding slow heat-up rate. Nonetheless, two (2) 100% capacity
pumps which are permanently piped into the spent fuel pit cooling system
have been installed. One of these pumps running with one of the spent
fuel pit heat exchangers is sufficient to cool the spent fuel pit during
normal operations. During refueling activities, one or both pumps may
be required based on actual conditions. An emergency pump is also
connected to the suction and discharge lines of the 100% capacity pumps
to be used in an emergency situations.
Refueling Water Purification Pump The refueling water purification pump circulates water in a loop between the refueling water storage tank and the spent fuel pit demineralizer
and filters. All wetted surfaces of the pump are austenitic stainless
steel. The pump is operated manually from a local station.
Spent Fuel Pit Skimmer Strainer A stainless steel strainer is located at the inlet of the spent fuel pit skimmer loop suction line for removal of relatively large particles
which might otherwise clog the spent fuel pit skimmer filters.
Spent Fuel Pit Filter The three pit filters remove particulate matter from the spent fuel pit water. The filter cartridge is synthetic fiber and the vessel shell is
austenitic stainless steel.
9.5-18 Revised 04/17/2013 C26C26C26 Spent Fuel Pit Demineralizer The demineralizer is sized to pass 5% of the loop circulation flow, to provide adequate purification of the fuel pit water for unrestricted access to the working area, and to maintain optical clarity.
Spent Fuel Pit Skimmer
A skimmer pump and three filters are provided for surface skimming of the spent fuel pit water. Flow from this pump is returned to the spent fuel pit.
Spent Fuel Pit Valves
Manual stop valves are used to isolate equipment and lines, and manual throttle valves provide flow control. Valves in contact with spent fuel pit water are austenitic stainless steel or equivalent corrosion
resistant material.
Spent Fuel Pit Piping
All piping in contact with spent fuel pit water is austenitic stainless steel. The piping is welded except where flanged connections are used to facilitate maintenance 9.5.3.3 System Evaluation Thermal-Hydraulic
Thermal-hydraulic calculations have been performed in support of a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> full core offload using the existing Region I and Region II spent fuel racks with specified loading patterns including the use of RCCAs, Metamic inserts, and water cells and the installation and use of a cask
area rack. The calculations determine the decay heat effects on the
spent fuel pit bulk temperature, local cell/fuel assembly temperatures
and time-to-boil on loss of cooling. The following discusses each of
these analyses and provides the results.
Calculations were performed to demonstrate the capability of the spent fuel pit cooling system to remove the decay heat during a planned 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> full core offload and during an unplanned 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> full core offload
with and without spent fuel pit cooling. The calculations considered
the four different SFP heat-up cases derived from the Standard Review
Plan (SRP). These cases address maximum normal and maximum abnormal
heat load conditions. In support of a reduced decay time (72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
offload), FPL has redefined the SRP cases to reflect the planned
refueling practice of full core offloads.
9.5-19 Revised 04/17/2013 The abnormal case is now interpreted to be an unplanned or emergency full core offload 36 days after a planned refueling shutdown. The SRP
assumption of a 36 day period between shutdowns is retained in the
updated analysis scenarios.
In keeping with the above, a planned refueling would offload the entire core (157 fuel assemblies) beginning at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The postulated
unplanned, forced shutdown scenario would also offload the entire core
beginning at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown preceded by a 1/2 core offload (assumed to be 80 assemblies to bound one reload batch) 36 days earlier.
A refueling temperature limit of 150°F for peak pool temperature was
selected as the acceptance criteria during refuelings with full core
off-loads.
SFP Bulk Temperature Analysis
The spent fuel pit bulk temperature analysis addresses the four different SFP heat-up cases derived from the Standard Review Plan (SRP).
The analysis for these cases and results are described below.
Case 1: Planned Refueling Full core offload initiated at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown.
Case 2: Planned Operation 1/2 core offload with capacity inventory at 36 days after shutdown.
Case 3: Unplanned Operation with Spent Fuel Pool Cooling Full core offload at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a forced shutdown with 1/2 core recently offloaded (36 days after a planned refueling
shutdown).
Case 4: Unplanned operation without Spent Fuel Pool Cooling Full core offload at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a forced shutdown with 1/2 core recently offloaded (36 days after a planned refueling
shutdown) with loss of SFP cooling at bulk peak pool water
temperature (time to boiling begins at bulk peak pool water
temperature).
9.5-20 Revised 04/17/2013 C26C26C26C26 The planned refueling (Case 1) is evaluated at two different CCW temperatures. A low CCW temperature of 85°F is analyzed as Case 1a with a high fuel transfer rate of 8 fuel assemblies per hour. A second case
is analyzed with CCW at its maximum temperature of 105°F. This latter
case is designated Case 1b below and is analyzed with a fuel transfer
rate of 6 fuel assemblies per hour. These two cases demonstrate the
capability of the SFP cooling system at various CCW temperatures.
The following input parameters were used in the analysis:
Input Parameter Value Full Core Decay Heat Load 35.64 MBtu/hr at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 11.98 MBtu/hr at 36 days
Full Capacity (past refuelings)
SFP Heat Load
5.29 MBtu/hr CCW Inlet Temperature
Case 1a Cases 1b, 2, 3, and 4
85°F 105°F CCW Flow Rate
Cases 1a,1b, 3, and 4
Case 2 2800 gpm (minimum) per heat exchanger
1200 gpm (minimum) per heat exchanger SFP Cooling Flow Rate
Cases 1a,1b, 3, and 4
Case 2 2200 gpm (minimum) per heat exchanger
1600 gpm (minimum) per heat exchanger Heat Exchanger Fouling
Supplemental Heat Exchanger
Fouling 0.000075 hr-ft 2-°F/Btu 0.0005 hr-ft 2-°F/Btu Heat Exchanger Tube Plugging
Allowance
Supplemental Heat Exchanger Tube
Plugging Allowance
0%
0.425% Fuel Assembly Transfer Rate
Case 1a Case 1b 8 per hour
6 per hour SFP Water Inventory 2,027,714lbm SFP Water Make-up Rate 100gpm Allowance for Existing Racks 1404 Fuel Assemblies Allowance for Cask Area Rack 132 Fuel Assemblies The analysis uses the same methodology and assumptions for heat exchanger performance as those used to support thermal power uprate (performed in 1996 under License Amendments 191 and 185 for Units 3 and 4, respectively).
9.5-21 Revised 04/17/2013 C26C26C26C26 The existing Heat exchanger effectiveness was quantified in 1996 to support the SFP cooling analyses at uprated conditions. Heat exchanger effectiveness was calculated using plant data obtained from the 1993 and
1994 Unit 4 refueling outages, and an empirically derived fouling factor
of 0.000075 hr-ft 2-°F/Btu. The use of this fouling factor (in lieu of the design fouling factor used by the heat exchanger manufacturer for
sizing purposes) is justified by the fact that tube side SFP water is
continuously purified and slightly acidic and the shell side water is
treated CCW.
Data collected during the recent 2002 Unit 4 refueling outage confirmed that there has been no observable change in heat exchanger performance
compared to 1993/1994 data.
Minimum tube and shell side flow rates have been assumed in the analysis to conservatively model the existing SFP heat exchanger performance.
The assumed flow rates are 10% lower than the operating flow rates
during a refueling outage. This provides additional conservatism to
account for potential future heat exchanger degradation, (e.g., fouling, tube plugging). No tube plugging is assumed in the heat-up analysis
since no tubes are currently plugged in the original heat exchanger (after 30 years of heat exchanger operation). The supplemental heat
exchanger effectiveness is based on vendor performance data.
The decay heat values in the updated analysis were determined from the ORIGEN-S historic and projected burnup schedules. The 1/2 core is assumed to be 80 assemblies to bound one reload batch.
Acceptance criteria for the SFP bulk heat-up analysis:
- a. The bulk maximum SFP temperature shall remain below 150°F from a full core offload during a planned refueling.
- b. The bulk maximum temperature shall remain below 212°F during an unplanned offload evolution.
The 150°F acceptance criterion specified above for planned refuelings was established for the SFP cooling systems as part of the thermal power uprate. The 150°F value was based on a review of other plants'
licensing requirements, and the first re-racking at Turkey Point (performed in 1977 under License Amendments 23 and 22 for Units 3 and 4, respectively).
9.5-22 Revised 04/17/2013 C26C26C26C26 It was applied during the analysis of the Turkey Point Unit 4, Cycle 16 (pre-uprate) full core offload. Accordingly, the 150°F temperature
limitation represents a reasonable criterion for both partial and full
core offloads for both Turkey Point spent fuel pits.
The 212°F acceptance criterion specified for unplanned offloads is representative of bulk SFP boiling conditions.
Results of the SFP bulk heat-up analysis:
Case 1: Planned Refueling 1a. The maximum expected SFP bulk temperature for a full core offload at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown is 120°F with a CCW inlet temperature of 85°F, and a transfer rate of 8 fuel assemblies per hour.
1b. The maximum expected SFP bulk temperature for a full core offload at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown is 139°F with a CCW inlet temperature of 105°F, and a transfer rate of 6 fuel assemblies per hour.
Case 2: Planned Operation
The maximum expected SFP bulk temperature for a 1/2 core offload with capacity inventory at 36 days after shutdown is less than or equal to 141 °F.
Case 3: Unplanned Operation with Spent Fuel Pool Cooling
The maximum expected SFP bulk temperature for a full core offload at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a forced shutdown (36 days after a planned refueling shutdown) with 1/2 core recently offloaded is 148°F. This temperature assumes that the entire core is offloaded as a complete unit at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The time to reach this maximum steady-state temperature with SFP cooling is 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after offload .
Case 4: Unplanned Operation without Spent Fuel Pool Cooling
The maximum expected SFP bulk temperature for a full core offload at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a forced shutdown (36 days after a planned refueling shutdown) with 1/2 core recently offloaded, with a subsequent loss of cooling, is 212°F. If SFP cooling were lost at the time of the peak pool temperature (148°F), the pool would reach boiling conditions in 2.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />.
9.5-23 Revised 04/17/2013 C26C26C26C26C26 The analysis for a planned refueling is provided below.
Heat-up Analysis results - Planned Refueling Analysis CCW Temperature Peak SFP Temperature 72-hour Offload Case 1a 85°F 120°F 72-Hour Offload Case 1b 105°F 139°F As shown above, the analysis for a planned refueling predicts peak SFP temperatures < 150°F for a full core offload with CCW temperature at
105°F.
9.5-24 Revised 04/17/2013 C26C26 Procedural Controls Plant procedures control the allowable off-load start time, fuel assembly off-load rate, and administrative SFP bulk temperature limit required to maintain pool temperature below 150°F. As indicated, administrative controls are used to ensure SFP bulk water temperature
does not exceed 150°F during planned refuelings. The requisite controls
include minimum off-load start time, maximum SFP bulk temperature, maximum fuel assembly transfer rate, the number of pumps and heat
exchangers in operation, and the system operating alignment. These
controls are incorporated into plant procedures governing reactor
refueling.
The evaluated off-load schedule is also affected by CCW temperature.
This variable, along with off-load start time and fuel assembly transfer rate, affects the SFP heat-up and the peak SFP water temperature. To
address this process variable, plant operating procedures controlling
minimum start time, maximum fuel assembly transfer rate, and the number
of pumps and heat exchangers in operation relate these parameters to CCW
temperature required to maintain SFP temperature below the 150°F limit.
An administrative bulk pool temperature limit is imposed to ensure that
the 150°F limit is not exceeded after completion of off-load activities
due to the inherent lag in SFP heat-up. The specified administrative
limit will maintain SFP temperature below 150°F without intervening
operator action. Bounding values are provided in procedures with an
option to use cycle-specific values prior to commencing off-load
activities.
Due to the many variables that can have an impact on SFP temperature, Turkey Point may elect to use a cycle-specific off-load start time and fuel assembly off-load rate in lieu of the bounding restrictions.
Consideration will be given to the actual core power history, scheduled
off-load start time, actual CCW temperature, predicted SFP heat
exchanger performance and planned fuel assembly off-load rate in the
establishment of the specific control values.
Regardless of whether cycle-specific or bounding off-load parameters are used for a particular refueling, plant procedures require that fuel transfer to the SFP be suspended if the administrative temperature limit
is reached during off-load. Resumption of off-load activities would
occur when the bulk SFP temperature decreases below the administrative
limit and additional administrative requirements are satisfied. Note
that Turkey Point may elect to perform a partial in-core shuffle in
conjunction with administrative temperature controls, to complete a
planned off-load without interruption and maintain bulk SFP water
temperature below 150°F.
9.5-25 Revised 04/17/2013 C26C26 SFP Local Temperature Analysis An analysis was performed to determine if the water in the storage racks will remain subcooled with the decay heat associated with 72-hour offload conditions.
Acceptance criteria for the SFP local thermal-hydraulic analysis:
- a. The local maximum SFP temperature shall remain below the local saturation temperature of the water.
- b. The maximum fuel cladding temperature in the SFP shall remain below the local saturation temperature of the water. If the maximum fuel
cladding temperature exceeds the local saturation temperature of the
water, a departure from nucleate boiling shall not occur.
In the SFP storage rack cells, decay heat from the fuel induces a natural circulation of water upward through the fuel assembly. Cooler
water is supplied to the bottom of the rack cells through various flow
holes. Water gaps or plenums between the racks and the SFP floor and
walls allow the water from the area above the rack to flow to the inlet
of the rack cells.
Fluid flows and temperatures within a rack cell loaded with fuel having a 72-hour decay time were determined by rigorous computational fluid
dynamics (CFD) analysis. The CFD analysis was performed using the
FLUENTŽ fluid flow and heat transfer modeling program. A single
bounding case was evaluated that includes the highest bulk temperature
(150°F) and decay heat load, and conservative hydraulic parameters.
Key assumptions of the SFP local thermal-hydraulic analysis include:
No downcomer flow exists between the individual storage rack modules. The hydraulic resistance of every rack cell in the SFP includes the
hydraulic resistance that would result from a dropped Metamic insert
lying across the top of the rack which is more conservative than a
dropped fuel assembly. A fouling of 0.0005 hr-ft 2-°F/Btu is imposed on the outside of the fuel rods to account for any crud layer. The maximum local water temperature (at the fuel rack exit) and peak
fuel assembly heat flux (typically near the mid-height of the active
fuel) occur coincidentally.
9.5-26 Revised 04/17/2013 The Metamic inserts are assumed to be installed such that the flow area around the fuel assembly is minimized. The rack cell inlet temperature is equal to the SFP bulk temperature
of 150°F. The flow area in the gaps between the Metamic insert and the storage
rack cell wall is not credited in the analysis.
Results of the SFP local thermal-hydraulic analysis:
Parameter Value Peak Local Water Temperature 185.5°F Peak Fuel Cladding Temperature 252.2°F The saturation temperature of water in the SFP increases with increasing depth (pressure). The critical location for localized boiling in the
fuel racks is at the top of the active fuel height. The minimum depth
of water at the top of the active fuel height is 26.8 feet. At this
water depth, the saturation temperature of water is 242.1°F. The
calculated peak local water temperature is below the local saturation
temperature; however, the calculated peak cladding temperature was
determined to be greater than the calculated local saturation
temperature; therefore, further evaluation was required to show that
departure from nucleate boiling (DNB) did not occur. The evaluation
determined that the maximum fuel assembly heat flux is approximately
3200 watt/meter
- 2. The minimum heat flux to cause DNB to occur is approximately 10 6 watts/meter 2; consequently, DNB will not occur and the local water temperature analysis was acceptable.
9.5-27 Revised 04/17/2013 C26C26 Time-To-Boil Analysis
Upon a loss of spent fuel pit cooling, the spent fuel pit will begin to heat-up due to decay heat. An analysis was performed to determine the time available before the spent fuel pit reaches 212°F (boiling) upon
loss of spent fuel pit cooling following a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> full core off-load.
The acceptance criteria for that analysis was as follows:
unplanned off-load evolution shall be sufficient to permit alignment
of available make-up sources.
- b. The required make-up rate to replace water due to boiling shall be less than the existing rate of 100 gpm.
NOTE: the credited make-up source for the spent fuel pits is 100 gpm from the demineralizer water system. In the event that the
demineralized water system is not available, alternate makeup can be
provided via the seismic Category I refueling water storage tank, or
via temporary (non-Category I) connections from the fire water system
or primary water storage tank.
The analysis concluded that the time-to-boil for an unplanned full core off-load at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following forced shutdown (36 days after a planned refueling shutdown) with 1/2 core recently off-loaded was 2.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />
assuming that SFP cooling is lost at the time of the peak pool
temperature (148°F). If spent fuel pit cooling is lost, 2.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> is
considered sufficient time for corrective action to be taken to initiate
alternate cooling and/or makeup. The maximum boil-off (makeup) at 212°F
for this condition is 99 gpm. This make-up rate is within the 100 gpm
acceptance criteria established for the SFP bulk heat-up analysis.
In addition to borated makeup water available from the RWST, available unborated water sources for makeup to the SFP have been previously
discussed in Attachment 6 to FPL letter L-99-176 in support of
Amendments 206 and 200 for Turkey Point Units 3 and 4, respectively. As
documented in L-99-176, the following unborated makeup sources satisfy
the 100 gpm acceptance criterion: Demineralized Water System, Primary
Water System (direct connection or local hose station) and the fire hose
station outside the SFP.
9.5-28 Revised 04/17/2013 C26 Spent Fuel Pool Makeup The increased spent fuel storage capability does not affect the design basis or functional requirements for makeup to the spent fuel pool.
Makeup requirements for unexpected leakage are as summarized in the AEC (NRC) Final Safety Evaluation Report, Section 9.6.
A normal makeup flow rate to the spent fuel pool is 100 gpm provided from the demineralized water system.
In the event of a loss of the normal demineralized water makeup supply to the spent fuel pool, alternate makeup can be provided via the Seismic Class I refueling water storage tank or via temporary connections from
the fire water system or the primary water storage tank. The supply
piping from these sources is not seismically installed, since Turkey
Point is located in a seismically inactive area far from any recorded
damaging shocks (
Reference:
FSAR Section 2.11). There are approximately
180,000 gallons of water in the pool above the top of the spent fuel
under normal conditions. If a leak should occur and the normal
demineralized water supply becomes inoperable, a long period of time
would be available before the water level would lower to the top of the
spent fuel. For example, if the assumed leak were 100 gpm, 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />
would be available to connect an alternate supply or to repair the
normal source. In addition, should all sources of fresh or
demineralized water become unavailable, sufficient time exists to
install a temporary source using portable pumps and fire hoses using
salt water as a makeup source.
Sufficient time is available to assure the viability of this alternate approach to that of the Regulatory Guides 1.13 and 1.29.
An analysis of the spent fuel pool in the boiling regime using salt water indicates that corrosion problems are not significant. At boiling temperatures, the oxygen content of water is extremely low such that
stress corrosion is reduced greatly because necessary shielding
corrosion products to form cathodic areas in the cracks cannot form due
to lack of oxygen. That is, of the cathodic reactions on the passive
surface that are required to sustain the anodic reaction within the
crack, namely 2H 2 0 + 2e-------------> H 2 + 20H-1/20 2 + H 2 0 + 2e- ---------> 20H-the latter reaction is essentially eliminated.
9.5-29 Revised 04/17/2013 C26 The absence of the oxygen related cathodic reaction greatly reduces the anodic reactions within the crack, namely 2CR + 3H 2 0-----------> CR 2 0 3 + 6H+ + 6e- 3H+ + e- ----------> H(Fe) + H 2 (companion cathodic reaction)
Propagation of cracks in the boiling water environment will be minimal.
Use of sea water will not result in unacceptable corrosion of the Zircalory-4 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.
Leakage Provisions
Whenever a failed fuel assembly is transferred from the fuel transfer canal to the spent fuel storage pool, a small quantity of fission products may enter the spent fuel cooling water. A small purification
loop is provided for removing these fission products and other
contaminants from the water. The probability of inadvertently draining
the water from the cooling loop of the spent fuel pit is exceedingly
low. The only means of draining the cooling loop is through such
actions as opening a valve on the cooling line and leaving it open when
the pump is operating. In the unlikely event of the spent fuel pit
cooling loop being drained, the spent fuel storage pit itself cannot be
drained and no spent fuel is uncovered since the spent fuel pit cooling
connections enter near the top of the pit. The temperature and level
indicators in the spent fuel pit would warn the operator of the loss of
cooling. The slow heat-up rate of the spent fuel pit, as indicated in
Table 9.5-16, would allow sufficient time to take any necessary action
to provide adequate cooling using the emergency cooling connections
provided while the cooling capability of the spent fuel pit cooling loop
is being restored.
9.5-30 Revised 04/17/2013 Incident Control The most serious potential failure of the spent fuel pit cooling loop is complete loss-of-water in the storage pit when fuel is in the pit. To protect against this possibility, the cooling pump suction lines
penetrate the pit wall and terminates near the normal water level so
that a break in the pipe will not gravity drain the pit. The pit drain
piping penetrates the pit wall at an elevation 6 feet above the top of
the fuel assemblies. Complete siphon draining of the pit by a break in
this line is prevented by a normally closed valve located near the pit
wall at the same elevation as the penetration. A break in this line
upstream of the valve will only drain the pool to an elevation 6 feet
above the fuel assemblies. One of the cooling water return lines (8")
penetrates the pit wall about one foot below the normal water level, and
the other return line (10") goes into the pit from above the normal
water level. To prevent siphon draining the pit a 1/2" inch hole is
drilled in the 8" and 10" lines.
In the event of failure of one of the 100% capacity spent fuel pit cooling pumps the other 100% capacity pump is available to replace the failed pump. If the failure occurs during refueling, which requires both 100% pumps to be in operation, the emergency pump, which is connected to the suction and discharge lines of the 100% capacity pumps, is available to provide additional cooling.
Spent Fuel Pit Structural Analysis for Thermal Conditions In support of spent fuel pit re-racking, analyses were performed to demonstrate the structural adequacy of the spent fuel pool and liner to
the possible temperature gradients that might exist at elevated
temperatures within the pool. The following provides an insight into
and a summary of the analyses:
A temperature gradient (not a temperature difference) of 150°F (180°F inside pool and 30°F outside air) was considered in the structural
analysis of the pool. Additional structural analyses have been
conducted on the pool for a temperature gradient reflecting a 212°F
water temperature and 30°F air temperature.
As part of the EPU SFP analysis due to higher fuel enrichment, the potential for Gamma heating of the concrete was evaluated. No additional heating of the pool concrete will occur provided freshly discharged fuel is not stored in the outer fuel rack row adjacent to the SFP Liner.
9.5-31 Revised 04/17/2013 C26C26C26C26 Except for the changes in water temperature, the analysis was identical to that described in response to NRC Questions 9, 10, and 11 (submitted
to Florida Power and light via letter of August 13, 1984 - Reference
13).
The analysis conservatively assumes that sufficient time elapses to allow thermal equilibrium to be reached; the results are therefore
independent of time. For the load case which includes thermal
considerations but ignores the seismic event, the pool would be expected
to remain at 212°F for only a short time before corrective action would
result in reduced temperatures. During this time period, the likelihood
of a seismic event, particularly at this site, is considered extremely
remote. This load case results in stresses which are within the
original design criteria allowables.
When both seismic and thermal conditions are assumed to occur simultaneously, there occur localized instances of reinforcing steel
stresses slightly exceeding the allowable stress of 36 ksi. However, these minor localized occurrences (which take place only if seismic and
thermal accident conditions occur simultaneously) cannot be construed as
causing a loss of function or loss of structural integrity. The
criteria included in the Updated FSAR (Appendix 5A,Section II)
recognizes this fact by allowing such types of occurrences (including
localized yielding) under certain conditions.
Additionally, the ASME Boiler and Pressure Vessel Code,Section III, Division 2, Subsection CC-3000 (including Summer 1981 Addenda)
recognizes the self-limiting nature of thermal stress in reinforced
concrete and allows reinforcing strains in excess of yield strain under
thermal accident conditions. Although this reference does not apply to
Turkey Point Units 3 and 4 as a design basis, it does represent an
approach to thermal loads considered acceptable by the engineering
community.
Liner plate integrity was investigated in a separate analysis. This analysis conservatively considered both the difference between the
concrete temperature (average of 212°F and 30°F) and temperature of the
liner plate (212°F) as well as the difference in thermal coefficients of
expansion of the two materials. The analysis evaluated the liner plate, as well as stresses in the welds and embeds associated with it. The
results of the analysis showed that there would be no loss of function.
9.5-32 Revised 04/17/2013 9.5.3.4 Test and Inspection Capability In accordance with the requirements of ASME XI, Subsection IWP (Inservice Testing of Pumps in Nuclear Power Plants), instrumentation is provided for the Units 3 and 4 Spent Fuel Pit Cooling Pumps. The Unit 3 and 4 SFP Cooling System is provided with a pitot tube (annubar) flow element with a local flow indicator in the suction lines to the SFP cooling water pumps. The SFP heat exchangers are provided with temperature and flow indicators for performance testing.
9.5.4 Fuel Handling System The Fuel Handling System consists of the refueling cavity, refueling transfer canal, manipulator crane, the fuel transfer equipment, spent fuel pit bridge crane, containment polar crane, spent fuel cask handling crane, new fuel bridge crane and the new fuel elevator. The general arrangement of the Fuel handling System is shown in Figure 9.5-1.
The spent fuel pit is provided with a spent fuel pit cooling and purification system which is discussed in Subsection 9.5.3.
9.5.4.1 Design Basis The Fuel Handling System is designed for handling and storage of new and spent fuel assemblies, providing an area for RCCA change out and for the required assembly, disassembly, and storage of reactor internals and the reactor vessel closure head. The fuel handling equipment includes interlocks, travel limiting features, and other protective devices to minimize the possibility of mishandling or equipment malfunction that could result in inadvertent damage to a fuel assembly and potential fission product release.
All 10 CFR 50 spent fuel transfer and storage operations are designed to be conducted underwater to ensure adequate shielding during refueling and to permit visual control of the operation at all time.
9.5.4.2 System Description
The reactor is refueled with equipment designed to handle the spent fuel under water from the time it leaves the reactor vessel until it is placed in a transfer cask for either storage at the site Independent Spent Fuel Storage Installation (ISFSI), or shipment from the site. Boric acid is added to the water to ensure subcritical conditions during refueling.
9.5-33 Revised 09/20/2016 C28C28 The Fuel Handling System is divided between two areas: The Auxiliary Building and the containment. The refueling cavity in containment and the transfer canal in the Auxiliary Building are flooded only during shutdown for refueling. The spent fuel pit is continuously full of water during refueling and when spent fuel is stored in the spent fuel pit.
The cavity and canal are connected by the Fuel Transfer System consisting of an underwater conveyor that carries the fuel through an opening in the containment. The refueling cavity is flooded with borated water from the refueling water storage tank. In the refueling cavity, fuel is removed from the reactor vessel, transferred through the water and placed in the fuel transfer system by a manipulator crane. In the spent fuel pit the fuel is removed from the transfer system and placed in storage racks with a long-handled manual tool suspended from the spent fuel pit bridge crane. Both the manipulator crane and the long-handled tool can handle only one assembly at a time.
For fuel cask transfer operations, any fuel stored in the cask area rack is first removed and placed in the other spent fuel pit racks. The cask area rack is then removed, decontaminated as required, and placed in dry storage. After satisfying a required decay period for offloaded spent fuel, the cask is lowered into the cask pit area and spent fuel that meets dry fuel storage requirements in 10 CFR 72 is removed from the spent fuel racks and loaded into the cask. The cask is then removed from the spent fuel pool cask pit by the cask handling crane located above the Auxiliary Building and either transferred to the ISFSI (transfer cask) or shipped off site.
New fuel assemblies are received and stored in racks in the new fuel storage area using the new fuel bridge crane. The new fuel bridge crane unloads the new fuel assembly shipping containers and also removes the assemblies from the containers and stores them in the new fuel storage racks. During refueling one new fuel assembly at a time is removed from the storage racks by the new fuel bridge crane and placed in a specially assigned rack from where it is picked up by the new fuel mono-rail hoist and placed in the new fuel elevator in the spent fuel pit fuel transfer canal. The new fuel elevator lowers the new fuel assembly into the canal where it is picked up by the long handled tool attached to the spent fuel bridge crane. The fuel assembly is then placed in the transfer carriage which delivers it to the refueling canal, or it may be temporarily stored in the spent fuel pit.
9.5-34 Revised 09/20/2016 C28 The new fuel storage area is sized for storage of the fuel assemblies normally associated with the replacement of one-third of a core.
Major Structures Required for Fuel Handling
Refueling Cavity
The refueling cavity is a reinforced concrete structure that forms a pool above the reactor when it is filled with borated water for
refueling. The cavity is filled to a depth that limits the radiation at
the surface of the water as low as reasonably achievable during fuel
assembly transfer.
The reactor vessel flange is sealed to the bottom of the refueling cavity by a clamped, gasketed seal ring which prevents leakage of
refueling water from the cavity. This seal is placed and secured after
reactor cooldown but prior to flooding the cavity for refueling
operations. The installed cavity seal ring assembly for both Units 3
and 4 is shown in Figure 9.5-2.
An alternative segmented cavity seal ring is used in place of the gasketed seal ring shown in Figure 9.5-2. The segmented seal ring is
sectioned into five sections that can be installed in reduced time
without the need of the polar crane to place or remove the seal, thereby
reducing refueling activity critical path time. The alternative
segmented cavity seal ring assembly for both Units 3 and 4 is shown in
Figure 9.5-2a. The use of the alternative segmented cavity seal ring as
the primary cavity seal is necessary due to the installation of the
Integrated Head Assembly. The original, single piece cavity seal ring
cannot be lifted from or lowered into position with the head in place
because of interferences with components of the Integrated Head
Assembly.
The cavity is large enough to provide storage space for the reactor upper and lower internals, the rod cluster control assembly (RCCA) drive
shafts, and miscellaneous refueling tools. The floor and sides of the
refueling cavity are lined with stainless steel.
An approved coating (e.g. Instacote) is applied to the refueling cavity and refueling canal prior to flooding the cavity for fuel movement to improve water tightness of the stainless steel liner. The coating is removed upon completion and drain down of the cavity. Unit 4 refueling canal has been evaluated to leave the applied coating for an extended period of time as a supplemental barrier to improve leak tightness and minimize degradation of the stainless steel liner.
9.5-35 Revised 04/17/2013 C26 Refueling Canal
The refueling canal is a passageway extending from the refueling cavity to the inside surface of the containment. The canal is formed by two
concrete shielding walls, which extend upward to the same elevation as
the refueling cavity. The floor of the canal is at a lower elevation
than the refueling cavity to provide the greater depth required for the
fuel transfer system tipping device located in the canal. The transfer
tube enters the reactor containment and protrudes through the end of the
canal. The canal walls and floor are lined with stainless steel.
Refueling Water Storage Tank
The normal duty of the refueling water storage tank is to supply borated water to the refueling canal for refueling operations. In addition, the
tank provides borated water for delivery to the core following either a
loss-of coolant or a steam line rupture accident. This is described in
Chapter 6. The capacity of the tank is based upon the requirement for
filling the refueling cavity and refueling canal. The water in the tank
is borated to a concentration which assures reactor shutdown by at least
5% d k/k when all RCC assemblies are inserted and the reactor is cooled
down for refueling. The tank design parameters are given in Chapter 6.
Spent Fuel Storage Pit
The spent fuel storage pit is designed for the underwater storage of spent fuel assemblies and control rods after their removal from the
reactor. The pit design parameters are listed in Table 9.5-1. Control
rods are stored in fuel assemblies.
Spent fuel assemblies are handled by a long-handled tool suspended from the spent fuel pit bridge overhead crane and manipulated by an operator
standing on the movable bridge over the pit. The spent fuel storage pit
is constructed of reinforced concrete having thick walls and is Class I
seismic design. The entire interior pit face and transfer canal is
lined with stainless steel plate. The probability of rupture of the pit
is exceedingly low. The pit rests on compacted rock which has an
extremely low permeability. Loss of water through an area equal to the
floor area with a full pool head of water is less than 1 gpm.
Storage racks are provided to hold spent fuel assemblies and are erected on the pit floor. Fuel assemblies are held in a rectangular array, and
placed in vertical cells. The racks are designed so that it is
impossible to insert fuel assemblies in other than the prescribed
locations, thereby ensuring the necessary spacing between assemblies.
9.5-36 Revised 04/17/2013 The spent fuel pit is provided with continuous water level indication with alarm setpoints. Exceeding the setpoint causes an audible alarm in
the control room. Low water level is made up by normal sources. Excess
water is pumped out since there are no gravity drains.
New Fuel Storage
New fuel assemblies and control rods are stored in a separate area whose location facilitates the unloading of new fuel assemblies or control
rods from trucks. This storage vault is designed to hold a reload
region in racks in the storage area listed in Table 9.5-1. The
assemblies which make up the remaining part of the first core are stored
in the spent fuel pit which otherwise remains unused until the time of
first refueling.
Major Equipment Required for Fuel Handling
Reactor Vessel Stud Tensioner
The stud tensioner is a hydraulically operated (oil as the working fluid) devise provided to permit preloading and unloading of the reactor
vessel closure studs at cold shutdown conditions. Stud tensioners were
chosen in order to minimize the time required for tensioning or
unloading operations. Three tensioners are provided and they are
applied simultaneously to three studs approximately 120° apart. A
compact hydraulic power unit is positioned above each of the three
utilized tensioners. The studs are tensioned to their operational load
in a predetermined sequence to prevent high stresses in the flange
region and unequal loadings in the studs. Relief valves are provided on
each tensioner to prevent over tensioning of the studs due to excessive
pressure. Charts indicating the stud elongation and load for a given
oil pressure are included in the tensioner operating instructions. In
addition, gauges are provided to measure the elongation of the studs
after each tensioning step.
Reactor Vessel Head Lifting Device
The Integrated Head Assembly (IHA) includes lifting components that provide an integral means for lifting the reactor vessel head without
the need to remove and/or reinstall a lifting tripod. These lift
components are made up of three clevises, three lifting rods, the tripod
assembly, and the integral missile shield, and are mounted to the lift
lugs on the RVCH.
9.5-37 Revised 04/17/2013 Reactor Internals Lifting Device
The reactor internals lifting device is a fixture provided to remove the upper reactor internals package and to move it to a storage location in
the refueling canal. The device is lowered onto the guide tube support
plate of the internals and is manually bolted to the support plate by
three bolts. The bolts are turned by long torque tubes extending up to
an operating platform on the lifting device. Bushings on the fixture
engage guide studs mounted on the vessel flange to provide close
guidance during removal and replacement of the internals package. This
lifting device can also be used to remove the lower internals once the
vessel has been cleared of all fuel assemblies.
Manipulator Crane
The manipulator crane is a rectilinear bridge and trolley crane with a vertical mast extending down into the refueling water. The bridge spans
the refueling cavity and runs on rails set into the floor along the edge
of the refueling cavity. The bridge and trolley motions are used to
position the vertical mast over a fuel assembly in the core. A long
tube with a pneumatic gripper on the end is lowered from the mast to
grip the fuel assembly. The upper end is still contained in the mast
when the gripper end contacts the fuel. A winch mounted on the trolley
raises the gripper tube and fuel assembly up into the mast tube. The
fuel is transported while inside the mast tube to its new position. The
manipulator can lift only one fuel assembly at a time.
All controls for the manipulator crane are mounted on a removable console on the trolley which are removed from containment during
operation. The bridge is positioned with the aid of a TV monitoring
system. A TV camera on the bridge truck and trolley provides position
information to the operator via a monitor. The drives for the bridge, trolley, and winch are variable speed and include separate inching
control on the winch. Electrical interlocks and limit switches on the
bridge and trolley drives protect the equipment. In an emergency, the
bridge, trolley, and winch can be operated manually using a handwheel on
the motor shaft.
The suspended weight on the gripper tool is monitored by an electric load cell indicator mounted on the control console. A load in excess of
110 percent of a fuel assembly weight stops the winch drive from moving
in the up direction.
9.5-38 Revised 04/17/2013 The gripper is interlocked through a weight sensing device and also a mechanical spring lock so that it cannot be opened when supporting a fuel assembly.
Safety features are incorporated in the system as follows:
a) Bridge, trolley, and winch drives which are interlocked to prevent simultaneous operation of any two drives.
b) Two redundant position safety switches, the GRIPPER TUBE UP position switches, which prevents bridge and trolley main motor drive operation except when it is actuated, or when the below listed
conditions are met:
- 1. Gripper switch in unlatch position.
- 2. Gripper 12" up into upper mast with no weight indicated on load cell. 3. Gripper up disengaged (G.U.D.) switch in operate mode.
c) An interlock which prevents the opening of a solenoid valve in the air line to the gripper when the suspended weight indicated by an electric load cell is greater than the weight of the empty gripper
tool, or the tube down disengaging permissive circuit limit switch is
open. As back-up protection for this interlock, the mechanical
weight actuated lock in the gripper prevents operation of the gripper
under load even if air pressure is applied to the operating cylinder.
d) The backup OVERLOAD switch, which opens the hoist drive circuit in the up direction when the loading is excessive.
e) An interlock on the hoist drive circuit in the up direction, which permits the hoist to be operated only when either the OPEN or CLOSED
indicating switch on the gripper is actuated.
f) Hoist slow zones operating through limit switches on the hoist cut out the main hoist control and transfer control to the inching
control at critical elevations of hoist travel.
g) Bridge and trolley drives are interlocked by travel limit switches to limit the outer mast to a path of travel that clears the guide studs
in the reactor vessel, the upper internals in their storage position
and the brackets and tool racks on the wall of the transfer canal.
9.5-39 Revised 04/17/2013 h) An underload circuit in the fuel loading hoist of the manipulator crane which prevents damage to fuel assemblies as they are being inserted into the core.
i) A dual cable hoist to retain a load under single cable failure.
j) A hoist load indicator system to provide continuous load readout.
Suitable restraints are provided between the bridge and trolley
structures and their respective rails to prevent derailing and the
manipulator crane is designed to prevent disengagement of a fuel
assembly from the gripper in the event of a maximum hypothetical
Spent Fuel Handling Crane
The spent fuel handling crane is a traveling bridge with a top-running trolley mounted on an overhead structure. The trolley is equipped with
two hoists, one on each side of the bridge. The crane spans the spent
fuel pit so that it can transfer fuel from the fuel transfer canal into
the storage racks located in the pit. The fuel assemblies are moved
from the fuel transfer canal and within the spent fuel pit by means of a
long-handled tool suspended from one of the hoists on the trolley. The
hoist travel and tool length are designed to limit the maximum lift of
active fuel to a safe shielding depth. Control consoles are roller
mounted an each of the bridge handrails. All operator actions, including bridge, trolley and hoist travel can be performed from the
control consoles, which in turn can be moved from one end of the bridge
to the other. A fixed scale and pointer location indication system for
the bridge and trolley is provided. Hoist position is also indicated.
The hoists are provided with limit switches, overload sensors and other safety features to withstand two-blocking, load hang-ups and other overloading, mis-reeving, and single cable failures. The capacity of
each hoist is two tons. The crane has weight sensors that are
interlocked to limit the total load on both hoists combined to a maximum
of two tons.
In addition, an in-line weight sensing system is provided for each hoist to limit the lifting load to preclude accidental fuel damage should binding occur. When lifting over spent fuel, the total load is limited
to 1 ton by procedures, limit switches and load sensors.
9.5-40 Revised 04/17/2013 Spent Fuel Cask Handling Crane The spent fuel cask handling crane is a traveling bridge crane arranged to serve both spent fuel pits. Limit switches prevent movement of the
cask beyond the laydown area in the bottom of the pit, prevent
interference of the cask crane bridge, trolley and hoist with fuel racks
or building structures, and restrict vertical lift of the cask to an
elevation of about six inches above the top of the pit wall. The
interlocks are administratively initiated by a selector switch located
in the control cab. The crane has hurricane latches.
Fuel Transfer System
The Unit 4 fuel transfer system, shown in Figure 9.5-1, is an underwater conveyor car that runs on tracks extending from the refueling canal
through the transfer tube and into the spent fuel pit.
The conveyor car receives a fuel assembly in the vertical position from the manipulator crane. The fuel assembly is lowered to a horizontal
position for passage through the tube, and then is raised by the
upending machine to a vertical position in the spent fuel pit.
The fuel transfer system for both units utilizes a transverse cable drive operated by two electric winches located on the Spent Fuel
Operating Floor (elev. 58') to drive the conveyor car. During
operation, the conveyor car is stored in the refueling canal. The gate
valve is closed and a blind flange is bolted on the transfer tube to
seal the containment.
Reactor Cavity Filtration System
In order to assure that the borated water in the reactor refueling cavity will be clear and allow good visibility for observation during
refueling operations, a portable reactor cavity filtration system is
installed and utilized only for the duration of refueling. Various
portable systems/configurations may be used; however, each is assessed
for compatibility prior to use.
Refueling Operation Activities
The following refueling activities and their sequence are governed by approved plant procedures and schedules. Below is the typical sequence.
Preparation
a) The reactor is shutdown and cooling to ambient conditions begins.
9.5-41 Revised 04/17/2013 b) A radiation survey is made and the containment is entered.
c) Deleted d) Cooling air ducts between the IHA air plenum and the CRDM air coolers on the operating floor are disconnected and removed to storage. CRDM cables are disconnected from the bulkheads and stored on the IHA.
e) The incore thimble tubes are withdrawn.
f) Reactor vessel head insulation is removed and instrument leads are disconnected. The segmented cavity seal ring is installed: the seal segments are removed from the storage box, assembled in place and the
captured j-bolts are clamped to effect the seal.
g) The reactor vessel head nuts are loosened with the hydraulic tensioners.
h) The reactor vessel head studs are removed to storage or left on the head and removed to storage after the head is on the storage pedestal.
i) The refueling cavity drain valves are closed.
j) Checkout of the fuel transfer device and manipulator crane is started.
k) Guide studs are installed in two holes 180° apart and the remainder of the stud holes are plugged.
l) Final preparation of underwater lights and tools is made. Checkout of manipulator crane and fuel transfer system is completed.
m) The fuel transfer tube flange is removed.
n) The reactor vessel head is unseated and raised approximately one inch with the polar bridge crane and a level check is made.
o) The reactor vessel head is slowly lifted to clear the drive shafts.
p) The reactor vessel head is taken to the storage pedestal.
q) The old seal rings are removed from the reactor vessel head.
9.5-42 Revised 04/17/2013 r) The refueling cavity is filled with water to the vessel flange. The water is pumped into the refueling cavity by the Residual Heat Removal pumps from the refueling water storage tank. The normal
Residual Heat Removal System inlet valves from the Reactor Coolant
System are closed. The reactor cavity filtration system is started
as required. When the cavity is filled, the residual heat removal
loop is restored to normal operation.
s) The full length control rod drive shafts are unlatched.
t) The reactor vessel internals lifting rig is lowered into position by the polar bridge crane and latched to the support plate.
u) The reactor vessel upper internals are lifted out of the vessel and placed on the underwater storage rack.
v) The core is now ready for refueling.
Refueling The refueling sequence is now started utilizing the manipulator crane.
The sequence for fuel assemblies in non-control positions is as follows:
a) Spent fuel is removed from the core and placed into the fuel transfer carriage for relocation to the spent fuel pit. This could involve either a full or a partial core off-load during the refueling outage (Reference 1).
b) An insert shuffle (RCCAs and spent WET Annular Burnable Absorber) is performed either in the reactor core or the spent fuel pit.
c) New and reused fuel assemblies are brought in from the spent fuel pit through the fuel transfer system and loaded into the core.
d) Whenever any fuel is being added to the reactor core, or is being relocated, a reciprocal curve of source neutron multiplication is
recorded to verify the subcriticality of the core.
A transfer of the RCCAs between fuel assemblies is required when a fuel assembly containing a RCCA is spent or relocated to an unrodded position in the core. The RCCA change tool is used to transfer the RCCA to a
fuel assembly which will be located in a rodded position in the core.
9.5-43 Revised 04/17/2013 Reactor Reassembly a) The fuel transfer car is parked and the fuel transfer tube isolation valve closed.
b) The reactor vessel internals package is picked up by the polar bridge crane and replaced in the vessel.
c) The full length control rod drive shafts are relatched to the RCCAs.
d) The manipulator crane is parked.
e) The water level is lowered by opening a valve at the Residual Heat Removal pump discharge and water is pumped from the refueling cavity into the refueling water storage tank until the level is slightly
below the vessel flange. The Residual Heat Removal line is
throttled. If in operation, the reactor cavity filtration system is
shutdown, and the refueling cavity is completely drained. When the
water in the refueling cavity reaches the vessel flange level, the
valve at the Residual Heat Removal pump is closed.
The Residual Heat Removal operation is restored and the remaining water in the refueling cavity is drained into the reactor coolant
drain tank via the low point in the canal drain. The water is then
pumped back into the refueling water storage tank by the Reactor
Coolant Drain Tank pumps. The flange surface is manually cleaned.
f) The reactor vessel head flange seal ring grooves are cleaned and the new seal rings are installed in the reactor vessel head.
g) The reactor vessel head is picked up by the polar bridge crane and positioned over the reactor vessel. Fifty six (56) head studs may be attached to the head when the head is moved over the reactor vessel.
h) The reactor vessel head is slowly lowered.
i) The reactor vessel head is seated.
j) The guide studs are removed to their storage rack. The stud hole plugs are removed.
k) All head studs are replaced and retensioned.
l) The refueling canal drain valves are opened and the fuel transfer tube flange is replaced.
9.5-44 Revised 04/17/2013 m) The segmented cavity seal ring is removed: the seal segments are unclamped, disassembled, placed in their storage box, and removed for
storage outside containment.
n) Vessel head insulation and instrumentation leads are replaced.
o) Electrical cables are reconnected to the bulkheads. Cooling air ducts are reconnected to the IHA air plenum and CRDM air coolers on the operating floor.
p) Flux map thimble tubes are inserted and high pressure seals connected.
q) The system is brought up to operating temperature and pressure and the reactor vessel closure is leakage tested.
r) Control rod drives are checked.
s) Deleted t) Pre-operational tests are performed.
9.5.4.3 System Evaluation Underwater transfer of spent fuel provides essential ease and corresponding safety in handling operations. Water is an effective, economic and transparent radiation shield and a reliable cooling medium
for removal of decay heat.
Basic provisions to ensure the safety of refueling operations are:
a) Gamma radiation levels in the containment, control room and fuel storage areas are continuously monitored (see Section 11.2.3). These
monitors provide an audible alarm at the initiating detector
indicating an unsafe condition. Continuous monitoring of reactor
neutron flux provides immediate indication and alarm in the control
room of an abnormal core flux level.
b) With the exception of the personnel and equipment hatches, containment integrity is maintained when core alterations or movement of irradiated fuel occurs inside the containment.
c) Whenever any fuel is being added to the reactor core or is being relocated, a reciprocal curve of source neutron multiplication is recorded to verify the subcriticality of the core.
9.5-45 Revised 04/17/2013 Incident Protection
Direct communication between the control room and the refueling cavity manipulator crane is required whenever changes in core geometry which
affect criticality are taking place. This provision allows the control
room operator to inform the manipulator crane operator of any impending
unsafe conditions detected from the control board indicators during fuel
movement.
Malfunction Analysis
Operation of a single residual heat removal loop is permitted for decay heat removal when fuel is in the reactor vessel and the refueling cavity is filled. A loss of this single residual heat removal loop has been
evaluated to ensure adequate natural circulation cooling can be
maintained for decay heat removal. The analysis utilized GOTHIC thermal
hydraulic analysis software to evaluate natural circulation cooling
conditions with both the reactor vessel upper internals installed and
removed. In each case, adequate natural circulation conditions will be
maintained to prevent fuel damage.
For the internals in case, the natural circulation flow path modeled is up from the core to the vessel upper plenum to the refueling cavity via the
holes in the upper support plate, the CRDM guide tubes, the head spray
flow nozzles, the upper internals hold-down spring gap, and the hot leg
gap, with return flow to the core via the downcomer and barrel/baffle
bypass. A direct flow path for natural circulation from the core to the
vessel upper plenum to the refueling cavity and back to the core via the
downcomer and barrel/baffle bypass exists for the internals out case.
An analysis is presented in Section 14 concerning damage to one complete outer row of fuel elements in an assembly, assumed as a conservative limit for evaluating environmental consequences of a fuel handling
incident.
9.5.4.4 Test and Inspection Capability
Upon completion of core loading and inspection of the reactor vessel head, certain mechanical and electrical tests can be performed prior to initial criticality. The electrical wiring for the rod drive circuits, the rod position indicators, the reactor trip circuits, the in-core
thermocouples and the reactor vessel head water temperature
thermocouples can be tested at the time of installation. The tests can
be repeated on these electrical items before initial operation.
9.5-46 Revised 04/17/2013 9.
5.5 REFERENCES
- 1. FPL Letter L-2002-214 to the NRC, dated November 26, 2002, Proposed License Amendments, "Addition of Cask Area Spent Fuel Storage Racks."
- 2. FPL Letter L-84-206 to the NRC, "Proposed Amendment to Spent Fuel Storage Facility Expansion - Additional Information," dated August 14, 1984.
- 3. Newmyer, W.D., Westinghouse Spent Fuel Rack Criticality Analysis Methodology," WCAP-14416-NP-A, Revision 1, November 1996.
- 4. American Nuclear Society, "American National Standard Design Requirements for Light Water Reactor Spent Fuel Storage Facilities at
Nuclear Power Plants," ANSI/ANS-57.2-1983, October 7, 1983.
- 5. U.S. Nuclear Regulatory Commission, Standard Review Plan, NUREG-0800, Section 9.1.2, "Spent Fuel Storage," Rev. 1, July 1981.
- 6. American Nuclear Society, "American National Standard for Nuclear Criticality Safety in Operation with Fissionable Materials Outside
Reactors," ANSI/ANS-8.1-1983, October 7, 1983.
- 7. American National Standard, ANS-51.1/N18.2-1973, "Nuclear Safety Criteria for the Design of Pressurized Water Reactor Plants," August 6, 1973, Section 5.7" Fuel Handling System.
- 8. Deleted.
- 9. FPL Letter L-2002-151 to the NRC, dated October 21, 2002, Proposed License Amendment for "Reduction of Decay Time for Core Off-load and
Revision of Technical Specification 3/4.9.3."
- 10. NRC Letter (Eva A. Brown) to FPL (J.A. Stall), "Turkey Point Units 3 &
4-Issuance of Amendments Regarding Reduction in Decay Time From 100
Hours to 72 Hours (TAC Nos. MB6549 and MB6550)," License Amendments
223/218, effective March 4, 2003.
- 11. 10CFR50.68, "Criticality Accident Requirements."
9.5-47 Revised 04/17/2013 C26
- 12. "Guidance on the Regulatory Requirements for Criticality Analysis of Fuel Storage at Light-Water Reactor Power Plants," L. Kopp (USNRC) to T.
Collins (USNRC), August 19, 1998.
- 13. NRC Letter (S.A. Varga) to FPL (J.W. Williams), "Proposed Spent Fuel Pool Expansion for Turkey Point Units 3 and 4 - Request for Additional
Information," dated August 13, 1984.
- 14. NRC Letter to FPL, "Turkey Point Units 3 and 4 - Issuance of Amendments Regarding Temporary Spent Fuel Pool Cask Racks (TAC Nos. MB6909 and
MB6910)," License Amendments 226/222, November 24, 2004.
- 15. FPL Letter L-2003-213 to the NRC, "Turkey Point Units 3 and 4 - RAI Response for Addition of Spent Fuel Pool Cask Area Rack Amendment,"
September 8, 2003.
- 16. Engineering Evaluation PTN-ENG-SENS-07-032, "RHR System Operation with the Reactor Cavity Filled and the Vessel Upper Internals in Place,"
Revision 1.
- 17. FPL Letter L-2005-247 to the NRC, dated January 27, 2006, Proposed License Amendments, Spent Fuel Pool Boraflex Remedy.
- 18. WCAP-17094-P, Revision 3, "Turkey Point Units 3 and 4 New Fuel Storage Rack and Spent Fuel Pool Criticality Analysis," February 2011.
- 19. Deleted
9.5-48 Revised 10/21/2013 C27 TABLE 9.5-1 FUEL HANDLING DATA
New Fuel Storage Area Core storage capacity 1/3 Equivalent fuel assemblies 54 Center-to-center spacing of assemblies, in. 21** Maximum K eff, if flooded with unborated water <0.95 Spent Fuel Storage Pit Core storage capacity Approx 9 Equivalent fuel assemblies 1379 (1510*) Number of space accommodations for spent fuel transfer casks 1 (0*) Center-to-center spacing of assemblies, in. Region 1 - Spent Fuel Pit Storage Racks 10.6** Region 1 - Cask Area Storage Rack 10.1 E-W, 10.7 N-S** Region 2 - Spent Fuel Pit Storage Racks 9.0** Maximum K eff when flooded with water <0.95 borated to the level identified in section 9.5.2.3
Maximum K eff if flooded with unborated water <1.0 Miscellaneous Details Width of refueling canal, ft.
3 Wall thickness of spent fuel storage pit, ft. 3 to 6 Weight of fuel assembly with RCCA (dry), lb. Approx 1,634 Capacity of refueling water storage tank, gal. 338,000 Minimum contents of refueling water storage tank for Safety Injection or Spray System Operability, gal. 320,000 Quantity of water required for refueling, gal. 285,000 Minimum water required for post MHA sump recirculation pump N.P.S.H. protection including allowance for possibility of drainage delay in containment 239,000
- With Cask Area Storage Rack installed
- Technical Specification 5.5.1 Critical Design Feature
Revised 09/20/2016 C28 TABLE 9.5-2 CRANES, HOISTS & ELEVATORS
New Fuel Bridge Crane
Number 1 per unit
Capacity 4 tons
New Fuel Monorail Hoist
Number 1 per unit
Capacity 1 ton
New Fuel Elevator
Number 1 per unit
Capacity 1 fuel assembly at one time
Spent Fuel Cask Handling Crane
Number 1 Capacity main hoist: 130 tons auxiliary hoist: 25 tons
Spent Fuel Pit Bridge Crane
Number 1 crane per unit; 2 hoists per crane
Capacity 2 tons/hoist (1)
Containment Polar Crane
Number 1 per unit
Capacity Main Hook (Unit 4) 205 tons
Main Hook (Unit 3) 205 tons
Aux. Hook 35 tons
Notes:
(1)Limit switches and procedures limit load to 1 ton over spent fuel areas.
Revised 04/20/2011
C25 TABLE 9.5-3 Nominal Fuel Assembly Specification used in the Region I and Region II Rack Criticality Analysis Parameter Value Assembly type OFA/DRFA LOPAR Rod Array Size 15x15 Rod Pitch, Inches 0.563 Active Fuel Length, Inches 144 Stack Density (%TD) 97.5 Maximum Nominal Enrichment, wt%
5.0 Total Number of Fuel Rods 204 Fuel Cladding Outer Diameter, Inches 0.422 Fuel Cladding Inner Diameter, Inches 0.3734 Fuel Cladding Thickness, Inches 0.0243 Pellet Diameter, Inches 0.3659 Number of Guide/Instrument Tubes 20 / 1 Guide/Instrument Tube Outer Diameter, Inches 0.533 0.546 Guide/Instrument Tube Inner Diameter, Inches 0.499 0.512 Guide/Instrument Tube Thickness, Inches 0.017 min.
Revised 04/17/2013 C26C26C26 TABLE 9.5-4 Region I Spent Fuel Storage Cell and Fuel Nominal Parameters Rack Parameter Unit Value Rack Cell Inner Dimension inch 8.75 Rack Cell Pitch inch 10.60(2) Rack Material Stainless Steel Rack Wall Thickness inch 0.075(2) Wrapper Material Stainless Steel Wrapper Plate Thickness inch 0.020(2) Poison Panel Thickness inch 0.078 Poison Cavity Thickness inch 0.090 Poison Panel Width inch 7.5 Poison Panel Length inch 139.4 B-10 Loading in Boraflex* gm/cm 2 0.020 Bottom of Boraflex Above Support Pad inch 6.16 Fuel Parameter
maximum Axial Blanket at Each End of the Rods inch 0.0 - 8.0 Maximum Nominal Fuel Enrichment of the Central Length % 5.0 Blanket Region Enrichment % 0.79 - 2.6 Theoretical Density % 97.5(1)
(1) As per Reference 18, criticality analyses remain valid up to a maximum region average fuel pellet density of 97.5% of theoretical.
- Original Rack values, Boraflex no longer credited in the criticality analysis (2) Technical Specification 5.5.1 Critical Design Feature
Revised 04/17/2013 C26C26 TABLE 9.5-5 DELETED
Revised 09/23/2010 C25 TABLE 9.5-6 DELETED
Revised 09/23/2010 C25 TABLE 9.5-7 Region II - Spent Fuel Storage Cell Nominal Parameters Parameter Unit Value Rack Cell Inner Dimension inch 8.80 Rack Cell Pitch inch 9.0** Rack Material Stainless Steel Rack Wall Thickness inch 0.075** Wrapper Material Stainless Steel Wrapper Plate Thickness inch 0.020 Poison Panel Thickness inch 0.051 Poison Cavity Thickness inch 0.064 Poison Panel Width inch 7.5 Poison Panel Length inch 139.4 B-10 Loading in Boraflex*
gm/cm 2 0.012 Bottom of Boraflex Above Support Pad inch 6.16
- Original Rack values, Boraflex no longer credited in the criticality analysis
- Technical Specification 5.5.1 Critical Design Feature
Revised 04/17/2013 C26 TABLE 9.5-8 DELETED
Revised 09/23/2010 C25 TABLE 9.5-9 DELETED
Revised 09/23/2010 C25 TABLE 9.5-10 Spent Fuel Pool Pit Soluble Boron Requirements
Revised 04/17/2013 Normal (ppm) For Misloaded Assembly (ppm) 500 1683 C26 TABLE 9.5-11 DELETED
Revised 09/23/2010 C25 TABLE 9.5-12 DELETED
Revised 09/23/2010 C25 TABLE 9.5-13 DELETED
Revised 09/23/2010 C25 TABLE 9.5-14 DELETED
Revised 04/17/2013 C26 TABLE 9.5-15 DELETED
Revised 04/17/2013 C26 TABLE 9.5-16 Sheet 1 of 4 Spent Fuel Cooling Loop Component Data System Cooling Capacity, Btu/hr Racks Full with Full Core Off-Load at 72 Hours 35.64 x 10 6 (Equilibrium Temperature of 120
°F) (1) Racks Full with Full Core Off-Load (4)(5) 47.62 x 10 6 (Equilibrium Temperature of 139
°F) Time for Pool Water Boiling (No Heat Removal) from the Equilibrium Temperature, Hours Racks Full with Full-Core Off-Load (3) 2.7 (Equilibrium Temperature of 148
°F) Spent Fuel Pit Heat Exchanger Quantity 1 Type Shell and U-tube
Heat Transfer, Btu/hr(2) 7.96 x 10 6 Shell side (Component Cooling Water) Inlet Temperature, °F 100 Outlet Temperature, °F 106 Design Flow rate, lb/hr 1.4 x 10 6 Design Pressure, psig 150 Design Temperature, °F 200 Material Carbon Steel
Tube side (Spent Fuel Pit Water)
Inlet Temperature, °F 120 Outlet Temperature, °F 113 Design Flow Rate, lb/hr 1.1 x 10 6 Design Pressure, psig 150 Design Temperature, °F 200 Material Stainless Steel Supplemental Spent Fuel Pit Heat Exchanger Quantity 1 Type Shell and U-tube Heat Transfer, Btu/hr(6) Modes 1-5: 11.5 x 10 6 Mode 6: 20.9 x 10 6 Shell side (Component Cooling Water) Inlet Temperature, °F 105 Outlet Temperature, °F Modes 1-5: 124.2 Modes 6: 120 Design Flow rate, lb/hr Modes 1-5: 0.6 x 10 6 Mode 6: 1.4 x 10 6 Design Pressure, psig 150 Design Temperature, °F 200 Material Carbon Steel Tube side (Spent Fuel Pit Water) Inlet Temperature, °F 140 Outlet Temperature, °F Modes 1-5: 129.5 Modes 6: 121 Design Flow Rate, lb/hr 1.1 x 10 6 Design Pressure, psig 150 Design Temperature, °F 212 Material Stainless Steel
Revised 04/17/2013 C26C26 TABLE 9.5-16 Sheet 1a of 4 Spent Fuel Cooling Loop Component Data
Notes: 1. The pool equilibrium temperature at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown with pool cooling system operating, off-load rate of 8 Fuel Assemblies / hr and cooling water to heat exchanger at 85
°F. 2. Assumed pool water to heat exchanger at 120
°F and cooling water to heat exchanger at 100°F.
- 3. This heat load case also assumes that 1/2 core discharge (assumed to be 80 assemblies to bound one reload batch) precedes the full core off-load by 36 days.
- 4. The pool equilibrium temperature at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown with SFP cooling system operating, off-load rate of 6 assemblies/hr hours, and cooling water to heat exchanger at 105
°F. 5. Total assumes fuel is also stored in the 25 cells removed from service.
- 6. Heat Transfer values are based on the specified temperature and flow values for the supplemental spent fuel pit heat exchanger.
Revised 04/17/2013 C26C26C26C26 TABLE 9.5-16 Sheet 2 of 4 Spent Fuel Cooling Loop Component Data Spent Fuel Pit Pump Data Quantity 2 Type Horizontal Centrifugal Flow, gpm 2300 Minimum Developed Head, ft H 2 O 125 Motor Horsepower 100 Design Pressure, psig 150 Design Temperature, °F 200 Material Stainless Steel
Spent Fuel Pit Volume, ft 3 (Nominal) 40,000 Boron Concentration, ppm Boron 2300 Spent Fuel Pit Filter Quantity 3 Type Replaceable Cartridge Internal Design Pressure of Housing, psig 150 Design Temperature, °F 200 Rated Flow, gpm 150 Maximum Differential Pressure Across Filter Element at Rated Flow (Clean Cartridge), psi 5 Maximum Differential Pressure Across Filter Element Prior to Cartridge Replacement, psi 20
Spent Fuel Pit Demineralizer Quantity 1 Type Flushable Design Pressure, psig 200 Design Temperature, °F 250 Design Flow rate, gpm 100 Resin Volume, cu. ft. 30 Vessel Volume, cu. Ft. 43
Revised 04/17/2013 C26 TABLE 9.5-16 Sheet 3 of 4 Spent Fuel Cooling Loop Component Data Spent Fuel Pit Skimmers Quantity 2 Flow Per Unit, gpm 50 Vertical Fluctuation Range:
Floating, inch 4 Manual Adjustment, feet (nominal) 4 Spent Fuel Pit Skimmer Strainer Quantity 1 Type Basket Rated Flow, gpm 100 Design Pressure, psig 50 Design Temperature, °F 200 Maximum Differential Pressure Across Strainer Element At Rated Flow (Clean), psi 1 Perforation, inch 1/8 Spent Fuel Pit Skimmer Filter Quantity 3 Type Replaceable Cartridge Internal Design Pressure, psig 50 Design Temperature, °F 200 Rated Flow Per Cartridge, gpm 50 Filter System Rated Flow, gpm 150 Maximum Differential Pressure Across Filter Element At Rated Flow (Clean), psi 5 Maximum Differential Pressure Across Filter Element Prior To Removing, psi 20
Revised 09/29/2005 TABLE 9.5-16 Sheet 4 of 4 Spent Fuel Cooling Loop Component Data Spent Fuel Pit Skimmer Pump Quantity Type Horizontal Centrifugal Design Flow Rate, gpm 100 Developed Head, ft H 2O 50 Design Pressure, psig 50 Design Temperature, °F 200 Refueling Water Purification Pump Quantity 1 Type Horizontal Centrifugal Design Flow Rate, gpm 100 Developed Head, ft H 2O 150 Design Pressure, psig 150 Design Temperature, °F 200 Spent Fuel Pit Cooling Loop Piping and Valves Design Pressure, psig 150 Design Temperature, °F 212 Spent Fuel Pit Skimmer Loop Piping and Valves Design Pressure, psig 150 Design Temperature, °F 200 Refueling Water Purification Loop Piping and Valves Design Pressure, psig 150 Design Temperature, °F 200
Revised 09/29/2005 Table 9.5-17 Applicable Design and Fabrication Codes, Standards and Specifications for Spent Fuel Storage Racks Spent Fuel Pit Storage Racks
- 1. NRC Position for Review and Acceptance of Spent Fuel Storage and Handling Applications, April 14, 1978, as amended by the NRC letter dated January 18, 1979. 2. Not used.
- 3. NRC Regulatory Guides a. 1.13, Rev. 2, Spent Fuel Storage Facility Design Basis, Dec. 1981 (Draft).
- b. 1.25, Rev.0 Assumptions Used for Evaluating the Potential Radiological Consequence of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors, March 1972. c. 1.26, Rev. 3, Quality Group Classifications and Standards for Water Steam and Radioactive Waste Containing Components of Nuclear Power Plants, Feb. 1976. d. 1.29, Rev. 3, Seismic Design Classification, Sept. 1978.
- e. 1.92, Rev. 1, Combining Modal Responses and Spatial Components in Seismic Response Analysis, Feb. 1976. f. 1.124, Rev. 1, Service Limits and Load Combinations for Class I Linear Type Component Supports, Jan. 1978.
- 4. Standard Review Plan - NUREG-0800, Rev. 1, July 1981. a. Section 3,7.1, Seismic Design, Rev. 1, July 1981.
- b. Section 3.8.4, Other Seismic Category I Structures, Rev. 3, July 1981.
- c. Section 9.1.2, Spent Fuel Storage, Rev. 1, July 1981.
- d. Section 9.1.3, Spent Fuel Pool Cooling System, Rev.1, July 1981. 5. NRC Branch Technical Position ASB 9-2, Residual Decay Energy for Light Water Reactors for Long Term Cooling, Rev. 2, July 1981. 6. Industry Codes and Standards a. ANSI N16.1-75, Nuclear Criticality Safety in Operations with Fissionable Materials Outside Reactors. b. ANSI N16.9-75, Validation of Calculational Methods for Nuclear Criticality Safety. c. ANSI N210-76, Design Objectives for Light Water Reactor Spent Fuel Storage Facilities at Nuclear Power Stations. d. ASME Section III-80, Nuclear Power Plant Components (through Summer 1982 Addendum). e. ACI 318-63, Building Code Requirements for Reinforced Concrete.
- f. DSS-ISG-2010-1, "Staff Guidance Regarding the Nuclear Criticality Safety Analysis for Spent Fuel Pools", September 2011.
Cask Area Storage Rack
- 1. NRC Position for Review and Acceptance of Spent Fuel Storage and Handling Applications, April 14, 1978, as amended by the NRC letter dated January 18, 1979.
- 2. NUREG 0612, Control of Heavy Loads at Nuclear Power Plants, USNRC, July 1980
- 3. NRC Regulatory Guides a. 1.13, Rev.2, Spent Fuel Storage Facility Design Basis, Dec. 1981 (Draft). b. 1.25, Rev. 0, Assumptions Used for Evaluating the Potential Radiological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors, March 1972. c. 1.29, Rev. 2, Seismic Design Classification, Feb. 1976.
- d. 1.92, Rev. 1, Combining Modal Responses and Spatial Components in Seismic Response Analysis, Feb. 1976. e. 1.124, Rev. 1, Service Limits and Load Combinations for Class 1 Linear-. Type Component Supports, Jan. 1978. 4. Standard Review Plan - NUREG-0800, June 1987 a. Section 3.7.1, Seismic Design, Rev.1, July 1981.
- b. Section 3.8.4, Other Seismic Category I Structures, Rev. 1, July 1981. 5. Industry Codes and Standards a. ASME Boiler and Pressure Vessel Code,Section II Parts A and C,Section III, 1989 Edition. b. ACI 318-63, Building Code Requirements for Reinforced Concrete.
- c. ANSI N16.9-75, Validation of Calculational Methods for Nuclear Criticality Safety. d. ANSI/ANS 8.1, Criticality Safety in Operations with Fissionable Materials Outside Reactors. e. ANSI/ANS 8.17, Criticality Safety Criteria for the Handling, Storage and Transportation of LWR Fuel Outside Reactors.
Revised 04/17/2013 C26 TABLE 9.5-18 Fuel Category Ranked by Reactivity I-1 High Reactivity I-2 I-3 Region I I-4 Low Reactivity II-1 High Reactivity II-2 II-3 II-4 Region II II-5 Low Reactivity Notes:
- 1. Fuel Category is ranked by decreasing order of reactivity without regard for any reactivity-reducing mechanisms, e.g., Category I-2 is less reactive than Category I-1, etc. The more reactive fuel categories require compensatory measures to be placed in Regions I and II of the SFP, e.g., use of water filled cells, Metamic inserts, or full length RCCAs.
- 2. Any higher numbered fuel category can be used in place of a lower number fuel category from the same Region.
- 3. Category I-1 is fresh unburned fuel up to 5.0wt% U-235 enrichment.
- 4. Category I-2 is fresh unburned fuel that obeys the IFBA requirement of Table 9.5-21 or contains an equivalent amount of another burnable absorber.
- 5. All Categories except I-1 and I-2 are determined from Tables 9.5-19 or 9.5-20.
Revised 04/17/2013 C26 Table 9.5-19 Blanketed Fuel - Coefficients to Calculate the Minimum Required Fuel Assembly Burnup (Bu) as a Function of Enrichment (En) and Cooling Time (Ct)
Fuel Category Coeff. I-3 I-4 II-1 II-2 II-3 II-4 II-5 A1 5.66439153 -14.7363682 -7.74060457 -7.63345029 24.4656526 8.5452608 26.2860949 A2 -7.22610116 11.0284547 5.13978237 10.7798957 -20.3141124 -4.47257395 -18.0738662 A3 2.98646188 -1.80672781 -0.360186309 -2.81231555 6.53101471 2.09078914 5.8330891 A4 -0.287945644 0.119516492 0.0021681285 0.29284474 -0.581826027 -0.188280562 -0.517434342 A5 -0.558098618 0.0620559676 -0.03047136730.0795058096 -0.16567492 0.157548739 -0.0614152031 A6 0.476169245 0.0236575787 0.098844889 -0.06763419830.243843226 -0.05935840270.134626308 A7 -0.117591963 -0.0088144551-0.02775847860.0335130877 -0.07121303680.0154678626 -0.0383060399 A8 0.0095165354 0.0008957348 0.0024057185 -0.00408038750.0063998706 -0.00140683180.0033419846 A9 -47.1782783 -20.2890089 -21.424984 14.6716317 -41.1150 -0.881964768 -12.1780 A10 33.4270029 14.7485847 16.255208 -10.0312224 43.9149156 9.69128392 23.6179517 A11 -6.11257501 -1.22889103 -1.77941882 5.62580894 -9.6599923 -0.18740168 -4.10815592 A12 0.490064351 0.0807808548 0.127321203 -0.539361868 0.836931842 0.0123398618 0.363908736 Notes: 1. All relevant uncertainties are explicitly included in the criticality analysis. For instance, no additional allowance for burnup uncertainty or enrichment uncertainty is required. For a fuel assembly to meet the requirements of a Fuel Category, the assembly burnup must exceed the "minimum burnup" (GWd/MTU) given by the curve fit for the assembly "cooling time" and "initial enrichment." The specific minimum burnup required for each fuel assembly is calculated from the following equation:
Bu = (A 1 + A 2*En + A 3*En 2 + A 4*En 3)* exp [ - (A 5 + A 6*En + A 7*En 2 + A 8*En 3)*Ct ] + A 9 + A 10*En + A 11*En 2 + A 12*En 3
- 2. Initial enrichment, En, is the nominal central zone U-235 enrichment. Axial blanket material is not considered when determining enrichment. Any enrichment between 2.0 and 5.0 may be used.
- 3. Cooling time, Ct, is in years. Any cooling time between 0 years and 25 years may be used. An assembly with a cooling time greater than 25 years must use 25 years.
- 4. Category I-1 is fresh unburned fuel up to 5.0 wt% U-235 enrichment.
- 5. Category I-2 is fresh unburned fuel that obeys the IFBA requirements in Table 5.5-4 or contains an equivalent amount of another burnable absorber.
- 6. This Table applies for any blanketed fuel assembly.
Revised 04/17/2013 C26 Table 19.5-20 Non-Blanketed Fuel - Coefficients to Calculate the Minimum Required Fuel Assembly Burnup (Bu) as a Function of Enrichment (En) and Cooling Time (Ct)
Fuel Category Coeff. I-3 I-4 II-1 II-2 II-3 II-4 II-5 A1 2.04088171 -27.6637884 -11.2686777 20.7284208 29.8862876 -83.5409405 35.5058622 A2 -4.83684164 26.1997193 2.0659501 11.9673275 -37.0771132 94.7973724 -30.1986997 A3 2.59801889 -7.2982252 2.66204924 -14.4072388 16.3986049 -31.9583373 11.0102438 A4 -0.300597247 0.723731768 -0.513334362 2.83623963 -2.1571669 3.55898487 -1.27269125 A5 -0.610041808 0.401332891
-0.0987986108 -1.49118695 1.02330848 0.299948492 1.34723758 A6 0.640497159 -0.418616707
-0.0724198633 1.75361041 -1.21889631 -0.312341996 -1.19871392 A7 -0.219000712 0.144304039 0.106248806
-0.659046438 0.467440882 0.107463895 0.352920811 A8 0.0252870451
-0.0154239536
-0.0197359109 0.080884618
-0.0560129443
-0.0108814287
-0.0325155213 A9 -4.48207836 -5.54507376 -1.34620551 -245.825283 12.1549 39.4975573 -5.2576 A10 -2.12118634 -5.76555416 -10.1728821 243.59979 -22.7755385 -50.5818253 10.1733379 A11 2.91619317 6.29118025 8.71968815 -75.7805818 14.3755458 23.3093829 0.369083041 A12 -0.196645176 -0.732079719 -1.14461356 8.10936356 -1.80803352 -2.69466612 0.0443577624 Notes: 1. All relevant uncertainties are explicitly included in the criticality analysis. For instance, no additional allowance for burnup uncertainty or enrichment uncertainty is required. For a fuel assembly to meet the requirements of a Fuel Category, the assembly burnup must exceed the "minimum burnup" (GWd/MTU) given by the curve fit for the assembly "cooling time" and "initial enrichment." The specific minimum burnup required for each fuel assembly is calculated from the following equation:
Bu = (A 1 + A 2*En + A 3*En 2 + A 4*En 3)* exp [ - (A 5 + A 6*En + A 7*En 2 + A 8*En 3)*Ct ] + A 9 + A 10*En + A 11*En 2 + A 12*En 3 2. Initial enrichment, En, is the nominal U-235 enrichment. Any enrichment between 1.8 and 4.0 may be used.
- 3. Cooling time, Ct, is in years. Any cooling time between 15 years and 25 years may be used. An assembly with a cooling time greater than 25 years must use 25 years.
- 4. This Table applies only for pre-EPU non-blanketed fuel assemblies. If a non-blanketed assembly is depleted at EPU conditions, none of the burnup accrued at EPU conditions can be credited (i.e., only burnup accrued at pre-EPU conditions may be used as burnup credit).
Revised 04/17/2013 C26 TABLE 9.5-21 Maximum keff for each 2 X 2 Array with No Soluble Boron
(1) Maximum keff values include the sum of biases and uncertainties from Tables 5-2 and 5-3 of Reference 18.
Revised 04/17/2013 Array Maximum keff (1) I-A 0.95335 I-B/I-C 0.98971 I-D 0.98938 II-A 0.98962 II-B 0.98978 II-C 0.98995 II-D 0.98998 C26 TABLE 9.5-22 Nominal RCCA S pecifications Parameter Value Clad Inner Diameter, inches 0.4005 Clad Outer Dia meter, inches 0.439 Poison Outer Diameter, inches0.3900*
Material content, wt%
Silver 80, Indium 15, Cadmium 5 Poison Density (gm/cm
- 3) 10.17* Clad Material SS *Technical Specific ation 5.5.1 critic al design feature
Revised 04/17/2013 C26 TABLE 9.5-23 Nominal Metamic Inse rts Specifications Parameter Value Material A1-B 4 C B-10 Loading Nominal 0.0160 g/cm 2 Minimum 0.0150g/cm 2* Thickness, Inches Nominal 0.073*
Inside Width, Inches Nominal 8.35*
Formed insert Length, measured from top of the assembly Inches Approx. 155*
Welded insert Length, measured from top of the assembly Inches Approx. 152*
- Technical Specific ation 5.5.1 critic al design feature
Revised 04/17/2013 C26 TABLE 9.5-24 IFBA Requirements for Fuel Category I-2 Nominal Enrichment (wt% U-235) Minimum Required Number of IFBA Pins Enr. < 4.3 0 4.3 < Enr. < 4.4 32 4.4 < Enr. < 4.7 64 4.7 < Enr. < 5.0 80
Revised 04/17/2013 C26
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-5 REFER TO ENGINEERING DRAWING 5610-C-249, for Unit 3 5610-C-250, for Unit 4 Revised 09/20/2016 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 SPENT FUEL POOL PLAN AT ELEVATION 18' 0" FIGURE 9.5-3 C28
Revised 09/29/2005 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 SPENT FULE POOL PLAN AT ELEVATION 58' 0" FIGURE 9.5.4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.5-5 REFER TO ENGINEERING DRAWING 5610-C-257 , SHEET 1 Revised 02/09/12 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 SECTION A-A of SPENT FUEL POOL FIGURE 9.5-5 C26
FINAL SAFETY ANALYSIS REPORT FIGURE 9.5-6 REFER TO ENGINEERING DRAWING 5610-C-45-29 SHEET 2 (Unit 3)
SHEET 7 (Unit 4)
Revised 02/09/12 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 SPENT FUEL POOL COOLING SYSTEM FIGURE 9.5-6 C26 Revised 09/29/2005 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 NOMINAL DIMENSIONS FOR THE REGION I SPENT FUEL PIT STORAGE CELLS FIGURE 9.5.7
Revised 09/29/2005 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 NOMINAL DIMENSIONS FOR THE REGION II SPENT FUEL PIT STORAGE CELLS FIGURE 9.5.8
Revised 09/29/2005 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 NOMINAL DIMENSIONS FOR THE REGION I CASK AREA RACK STORAGE CELLS FIGURE 9.5.9
FIGURE 9.5-10 DELETED Revised 09/23/2010C25 FINAL SAFETY ANALYSIS REPORT FIGURE 9.5-11
__________________________
REFER TO ENGINEERING DRAWING 5613-M-3033, SHEET 1 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 SPENT FUEL POOL COOLING SYSTEM FIGURE 9.5-11 Revised 09/29/2005 FINAL SAFETY ANALYSIS REPORT FIGURE 9.5-12
__________________________
REFER TO ENGINEERING DRAWING 5614-M-3033, SHEET 1 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 SPENT FUEL POOL COOLING SYSTEM FIGURE 9.5-12 Revised 09/29/2005 FIGURE 9.5-13 DELETED Revised 09/23/2010 C25 Revised 09/23/2010 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 METAMIC INSERTS REGION II RACKS FIGURE 9.5-14 C25 Revised 09/23/2010 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 REGION II RACK CELL with METAMIC INSERTS and FUEL ASSEMBLY FIGURE 9.5-15 C25 Revised 09/23/2010FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 ILLUSTRATION SHOWING SPATIAL ORIENTATION of METAMIC INSERTS FIGURE 9.5-16 C25 Notes: 1) Numbers in the above cells are Array numbers of the assemblies in the cells.
- 2) Shaded cells contain an insert.
- 3) Cells with a cross contain only water.
- 4) The reverse sequence is an exam ple of Unloading steps for a single assembly in Array II-B Revised 09/23/2010 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 ILLUSTRATION SHOWING SPATIAL ORIENTATION of METAMIC INSERTS FIGURE 9.5-17 C25 9.6 FACILITY SERVICES 9.6.1 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 Association's (NFPA) 805, "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants" - 2001 Edition. Turkey Point Nuclear Plant Units 3 and 4 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 May 28, 2015 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).
9.6-1 Revised 09/20/2016 C28 9.6.1.1 DESIGN BASIS
SUMMARY
9.6.1.1.1 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. 9.6.1.1.2 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 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.
9.6-2 Revised 09/20/2016 C28 (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.
9.6.1.1.3 Codes of Record The codes, standards and guidelines used for the design and installation of plant fire protection systems are listed in 5610-016-DB-001, Fire Protection System NFPA 805 Design Basis document.
9.6-3 Revised 09/20/2016 C28 9.6.1.2 SYSTEM DESCRIPTION 9.6.1.2.1 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 the 5610-M-722A, Nuclear Safety Capability Assessment Basis Document, 5610-M-723A, Essential Equipment List, and 5610-E-2000A, Essential Cable List. 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 the Fire Protection System NFPA 805 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 Fire Protection System NFPA 805 Design Basis document. Fire protection system and features plant configuration information is documented in STD-M-006, Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4. Radioactive Release Structures, systems, and components relied upon to meet the radioactive release criteria are documented in Fire Protection System NFPA 805 Design Basis document. 9.6.1.2.2 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 the Fire Protection System NFPA 805 Design Basis document are considered to be part of the 'powerblock'.
9.6-4 Revis ed09/20/2 016C28 9.6.1.3 SAFETY EVALUATION The 5610-016-DB-001, Fire Protection System NFPA 805 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. o Deterministic compliance strategies. o 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. Summary of the Fire Probabilistic Risk Assessments. Key analysis assumptions to be included in the NFPA 805 monitoring program. 9.6.1.4 FIRE PROTECTION PROGRAM DOCUMENTATION, CONFIGURATION CONTROL AND QUALITY ASSURANCE In accordance with Chapter 3 of NFPA 805 a fire protection plan documented in 0-ADM-016, Fire Protection Program, defines the management policy and program direction and defines the responsibilities of those individuals responsible for the plan's implementation. 0-ADM-016:
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 appropriate authority having jurisdiction for the various areas of the fire protection program. 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 qualifications required for various fire protection program personnel. 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 the Fire Protection System NFPA 805 Design Basis document.
9.6-5 Revised 09/20/2016 C28 9.6.2 MISCELLANEOUS WATER SYSTEMS
Flow diagrams for the primary water, demineralized water, intake cooling water, chlorination and circulating water systems are shown in Figures 9.6-1 through 9.6-18.
Intake Cooling Water System
The Intake Cooling Water System (see Figures 9.6-1 through 9.6-7) is provided with normally cross-connected, redundant headers, such that the heat exchangers in the Auxiliary Coolant System and the Turbine Plant Cooling System (see Figures 9.6-8 through 9.6-9) normally receive flow from both headers. The design includes provision for isolation of turbine plant cooling water heat exchangers following a loss-of-coolant accident.
Necessary isolation valves between the 100% capacity headers and the three pumps are also provided. The supply headers are redundant, but the return merges to a non-redundant discharge header that returns water to the discharge canal. The redundant ICW supply headers addresses the design for passive failure.
The system is analyzed to ensure adequate heat removal with the highest expected temperature of cooling water, maximum loadings and leakage allowances. Each of the CCW heat exchangers for Unit 3 have the capability to be periodically cleaned by chemical injection upstream of the heat exchangers, in order to minimize tube-side fouling and preserve heat transfer capability of the heat exchangers.
9.6-6 Revised 09/20/2016 System Design The intake cooling water system supplies salt water to the tube side of the component cooling water heat exchangers. The intake cooling water system also supplies salt water to the cold side of the turbine area cooling water heat exchangers. The redundant header system is provided with isolation valves that can be shut so that failure of one loop does not require immediate shutdown of the unit.
Three intake cooling water pumps are provided for each unit. One, two, or three pumps are operated as required to support normal plant operating conditions. However, only one pump is required following a MHA. The A and B pumps are powered by 4160 volt buses which can be powered by each train's associated emergency diesel generator. The C pump is powered by a swing 4160 volt safety related bus which can be powered, through aligning the bus manually, by either the train A or train B emergency diesel generator associated with the same unit. This pump is interlocked, such that, it is started on a loss of offsite power or safety injection signal, if the supply breaker for the A or B ICW pump (associated with the A or B 4KV Bus to which it is aligned) is open and racked out.
To ensure pump operation under flood conditions, the motors are installed above the maximum flood level. The pump section columns are also installed to provide sufficient submergence under minimum water level conditions.
The intake cooling water system provides sufficient redundancy so that at least one intake cooling water pump will continue to operate to handle heat loads from design basis accidents following a postulated single active failure. A single intake cooling water pump, however, is limited in its ability to supply the required cooling water to the component cooling water heat exchangers during an accident when flow is also allowed to continue through the turbine plant cooling water (TPCW) heat exchangers.
9.6-7 Revised 09/20/2016
In order to maximize the available intake cooling water flow to the CCW heat exchangers, two fail-closed, pneumatically operated valves, POV-*-4882 and POV-*-4883, are installed on the two supply headers to the TPCW heat exchangers. The POVs will automatically isolate the TPCW heat exchangers in the event that instrument air or electrical (DC) power is lost. However, accumulators are provided on the instrument air inlet to maintain the valves open on a loss of instrument air for a sufficient duration to protect turbine plant equipment. Additionally, in the event of a safety injection actuation signal, the POVs will automatically isolate the TPCW heat exchangers. These features ensure that sufficient intake cooling water flow to the component cooling water heat exchangers will be available. These valves do not automatically isolate upon loss of offsite power (LOOP). Should a loss of offsite power event occur which is accompanied by a coincident single failure affecting the availability of one intake cooling water pump, a condition could exist where one intake cooling water pump may operate in a condition where NPSH r exceeds NPSH
- a. To mitigate this potential condition, a second ICW pump could be started, or controls that are provided locally and in the control room could be used to initiate manual closure of the POVs and isolate the TPCW heat exchangers within 30 minutes. In addition, these valves are provided with the capability to remain open for a minimum of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following a loss of instrument air to avoid potential damage to turbine plant equipment.
The intake cooling water system is designed as Class I.
9.6-8 Revised 09/20/2016 System Evaluation During normal operations two Intake Cooling Water pumps provide flow to the three Component Cooling Water heat exchangers and to the Turbine Plant Cooling Water heat exchangers. During an accident, one or two ICW pumps can provide flow to two or three CCW heat exchangers. Measures are in place to ensure the heat transfer capability of the CCW heat exchangers meets the accident heat load. This heat transfer capability is ensured even if a single active failure resulted in a partial flow of intake cooling water through the turbine plant cooling water heat exchangers. The measures include performance monitoring, and periodic cleaning of the component cooling water heat exchangers. Periodic cleaning of the Unit 3 CCW heat exchangers by chemical injection can be performed to minimize tube-side fouling, thus preserving the heat transfer capability of the heat exchangers.
The turbine plant cooling water heat exchangers are provided with cathodic protection by means of sacrificial anodes located in the heat exchanger inlet and outlet channel heads. The component cooling water heat exchangers are provided with cathodic protection by means of sacrificial anodes located in the heat exchanger inlet and outlet channel heads.
Water Treatment System
A common water treatment system (see Figures 9.6-10 through 9.6-143) is provided for Units 3 and 4 to provide the demineralized water of the required quality. The water treatment system is designed to provide all demineralized water requirements of Units 3 and 4.
Wastes from the Water Treatment Plant demineralizer regeneration process which have a pH between 2.0 and 12.5 are transferred to the neutralization basin where they are neutralized and discharged. If the pH of the demineralized regeneration waste is outside this range, it used to be sent to the waste neutralization tank where it would be neutralized and then sent to the neutralization basin. The current method of processing demineralized water, however, utilizes a Reverse Osmosis System which obviates the need for the Neutralization tank. The Neutralization Tank has been isolated from the Water Treatment Plant and renamed as the CWP Lube Water Storage Tank. It is currently used in the Circulating Water Pumps Lube Water System.
9.6-9 Revised 09/20/2016 An automatic isolation valve is provided on the common Water Treatment Plant (WTP) discharge line to prevent discharge of high conductivity water from the WTP to the storage tanks. A drain line with a manual isolation valve is located upstream and close to the automatic isolation valve.
Since the water treatment system is not required for safe shutdown of the units following a MHA, it is designated as Class III.
Some of the structures of the water treatment equipment are located between the Technical Support Center (TSC) and the Containment Hatch of Unit 3.
These structures have been credited for providing shielding to the TSC from the shine of the Unit 3 Equipment Hatch (References 2 and 3). The specific structures that have been credited with this shielding are the demineralizer tanks T12A and T12B, the Chemical Storage Building and the Water Treatment Control Cubicle.
In addition to the existing Water Treatment Plant, connections are provided for an Alternate Water Treatment Plant. A raw water supply connection and a return treated water connection are provided (Reference FSAR Figures 9.6-10 and Figure 9.6-11). The purpose of these connections is to allow use of a complete vendor supplied water purification system typically furnished as a turnkey service. The Alternate Water Treatment Plant option is currently in use and purification equipment including all auxiliaries such as acid, caustic, demineralizer trailers, etc is provided by a vendor. Other vendors may be considered at contract extension time, or the original Water Treatment Plant could be returned to service.
Primary Water Make-up System
Adequate primary water storage is provided to fulfill the water requirements load fluctuations and leakage in the reactor coolant system during normal unit operation.
The primary water is unborated, deaerated, demineralized water suitable for in the reactor coolant system. Boric acid may be added to this water in the desired concentration before it is used as the reactor coolant.
System Design
Demineralized water for the primary water make-up system can be supplied from either the existing Water Treatment Plant if it is in operation, or the Alternate Water Treatment Plant. Depending on the particular purification system being used, operation of the primary water deaerator may be required to remove dissolved oxygen from the supply stream. (See Figures 9.6-15 through 9.6-18).
9.6-10 Revised 09/20/2016 One primary water storage tank and one deaerator is provided for each unit. Two primary water make-up pumps per unit are provided. One pump is normally in operation and supplies primary water to various loads, including to the chemical and volume control system where boric acid may be added before its injection (via charging) as reactor coolant. The systems may be operated in a cross-connected arrangement or aligned to support their respective unit. The primary water make-up system is designated as Class III, since it is not required for the safe shutdown of the unit following a MHA. 9.6.3 SYSTEM DESIGN EVALUATION Malfunction Analysis The intake cooling water system is designed to prevent a component failure from curtailing normal unit operation. Two normally cross-tied, parallel headers with necessary cross connections and isolation valves provide redundant flow paths. In addition to the header isolation valves, each component also has individual isolation valves to permit removing any piece of equipment from the system. A malfunction in the water treatment system or primary water make-up system does not create any abnormal condition in reactor operation; therefore, a component failure or temporary outage is not of primary importance for reactor safety. Minimum Operating Conditions Minimum operating requirements of the intake cooling water system are met by one pump and one header. The remote operated control valve permits isolation of the non-essential services for one-pump operation within 30 minutes. Tests and Inspections All intake cooling water system components are hydrostatically tested prior to unit start-up and are accessible for periodic inspections during operation. all electrical components, transfer, and starting controls are tested. 9.6-11 Revis ed09/20/2 016 9.
6.4 REFERENCES
- 1. FPL Safety Evaluation JPE-LR-87-45,"Justification for Continued Operation of Turkey Point Unit 3 for ICW System Design," Revision 3, dated March 17, 1989.
- 2. Safety Evaluation by the Office of Nuclear Reactor Regulation for Turkey Point Nuclear Generating Unit. Nos. 3 and 4 - 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 May 28, 2015 (ML15061A237).
- 3. License Amendment Request, June 28, 2012, Transition to 10 CFR 50.48(c) - NFPA 805 Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition.
- 4. National Fire Protection Association Standards, NFPA 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition.
- 5. Regulatory Guide 1.205, Risk-Informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants, Revision 1, December 2009.
- 6. NEI 04-02, Guidance for Implementing a Risk-Informed, Performance-Based Fire Protection Program under 10 CFR 50.48(c), Revision 1, September 2005. 7. FAQ 12-0062, Updated Final Safety Analysis Report (UFSAR) Standard Level of Detail, Revision 1, May 21, 2012
- 8. 5610-016-DB-001, Fire Protection System NFPA 805 Design Basis.
- 9. 0-ADM-016, Fire Protection Program.
- 10. 5610-M-722A, Nuclear Safety Capability Assessment Basis Document.
- 11. 5610-M-723A, Essential Equipment List.
- 12. STD-M-006, Engineering Guidelines for Fire Protection for Turkey Point Units 3 & 4
- 13. 5610-E-2000A, Essential Cable List.
9.6-12 Revised 09/20/2016 C28 TABLE 9.6-1 EQUIPMENT DESIGN PARAMETERS
Intake Cooling Water Pumps
Number 3 Capacity GPM, each 16,000 T.D.H. Feet 60 Pumped Fluid Sea Water
Water Treatment System
Number 1 shared by Units 3 & 4 Capacity, GPM (nominal) 400
Primary Water Storage Tank
Primary Water Storage Tank Number 1 Capacity, gal. (nominal) 150,000 Materials of Construction Carbon steel, epoxy lined with floating diaphragm. Design Pressure Atmospheric
Deaerator Number 1 Maximum Capacity, GPM less than 150
Primary Water Make-Up Pumps
Number 2 Capacity, GPM, each 150 T.D.H. feet 350 Pumped Fluid Primary Water
Basket Strainers
Number 4
Material Body & Cover Carbon Steel, Epoxy Lined (SA515 or SA516, Gr 70)
Strainer Sections SS316
Note: Numbers of components are per unit unless otherwise indicated.
Rev. 16 10/99
TABLE9.6-2 INTAKE COOLING WATER SYSTEM-CODE REQUIREMENTS Component Codes Pumps Hydraulic Institute Standards Piping Above Ground: ASA-A21.6-1955 Below Ground: ASA-A21.8-1955 Basket Strainers ANSI B31.1 Original Replacement ASME Section VIII - Division 1 1983 Summer 1985 Rev. 16 10/99
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-1 REFER TO ENGINEERING DRAWING 5613-M-3019 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 INTAKE COOLING WATER SYSTEM FIGURE 9.6-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-2 REFER TO ENGINEERING DRAWING 5613-M-3019 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 INTAKE COOLING WATER SYSTEM FIGURE 9.6-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-3 THIS FIGURE HAS BEEN DELETED.
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 INTAKE COOLING WATER SYSTEM TUBE CLEANING FOR CCW HEAT EXCHANGERS FIGURE 9.6-3
FIGURE 9.6-4 (DELETED)
INTAKE COOLING WATER SYSTEM TUBE CLEANING FOR TPCW HEAT EXCHANGERS
Rev. 12 5/95
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-5 REFER TO ENGINEERING DRAWING 5614-M-3019 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 INTAKE COOLING WATER SYSTEM FIGURE 9.6-5
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-6 REFER TO ENGINEERING DRAWING 5614-M-3019 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 INTAKE COOLING WATER SYSTEM FIGURE 9.6-6
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-7 THIS FIGURE HAS BEEN DELETED.
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 INTAKE COOLING WATER SYSTEM TUBE CLEANING FOR CCW HEAT EXCHANGERS FIGURE 9.6-7
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-8 REFER TO ENGINEERING DRAWING 5613-M-3008 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 TURBINE PLANT COOLING WATER SYSTEM FIGURE 9.6-8
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-9 REFER TO ENGINEERING DRAWING 5614-M-3008 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 TURBINE PLANT COOLING WATER SYSTEM FIGURE 9.6-9
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-10 REFER TO ENGINEERING DRAWING 5610-M-3021 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 WATER TREATMENT PLANT SYSTEM FILTRATION FIGURE 9.6-10
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-11 REFER TO ENGINEERING DRAWING 5610-M-3021 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 WATER TREATMENT PLANT SYSTEM DEMINERALIZER FIGURE 9.6-11
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-12 REFER TO ENGINEERING DRAWING 5610-M-3021 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 WATER TREATMENT PLANT SYSTEM DEMINERALIZER FIGURE 9.6-12
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-13 REFER TO ENGINEERING DRAWING 5610-M-3021 , SHEET 4
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 WATER TREATMENT PLANT SYSTEM WASTE NEUTRALIZATION FIGURE 9.6-13
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-14 REFER TO ENGINEERING DRAWING 5610-M-3021 , SHEET 5
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 WATER TREATMENT PLANT SYSTEM SAMPLING SYSTEM FIGURE 9.6-14
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-15 REFER TO ENGINEERING DRAWING 5613-M-3020 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 PRIMARY WATER MAKEUP SYSTEM FIGURE 9.6-15
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-16 REFER TO ENGINEERING DRAWING 5613-M-3020 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 PRIMARY MAKEUP WATER SYSTEM FIGURE 9.6-16
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-17 REFER TO ENGINEERING DRAWING 5614-M-3020 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 PRIMARY WATER MAKEUP SYSTEM FIGURE 9.6-17
FINAL SAFETY ANALYSIS REPORT FIGURE 9.6-18 REFER TO ENGINEERING DRAWING 5614-M-3020 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 PRIMARY MAKEUP WATER SYSTEM FIGURE 9.6-18
9.7 EQUIPMENT AND SYSTEM DECONTAMINATION 9.7.1 DESIGN BASIS
Activity outside the core could result from fission products from defective fuel
elements, fission products from tramp uranium left on the cladding in small quantities during fabrication, products of n - Y or n - p reactions on the water or impurities in the water, and activated corrosion products. Fission products in
the reactor coolant associated with normal operation and tramp uranium are generally removed with the coolant or in subsequent flushing of the system to be decontaminated. The products of water activation are not long lived and may be
removed by natural decay during reactor cooldown and subsequent flushing
procedures. Activated corrosion products are the primary source of the
remaining activity.
The corrosion products contain radioisotopes from the reactor coolant which have
been absorbed on or have diffused into the oxide film. The oxide film,
essentially magnetite (Fe 3 O 4) with oxides of other metals including Cr and Ni, can be removed by chemical means presently used in industry.
Water from the Reactor Coolant System and the spent fuel pit is the primary potential source of contamination outside of the corrosion film of the reactor coolant system. Contact while working on primary system components could result in contamination of the equipment, tools and clothing of the personnel involved in the maintenance. Also, leakage from the system during operation or spillage during maintenance could contaminate the immediate areas and could contribute to
the contamination of the equipment, tools, and clothing.
9.7-1 9.7.2 METHODS OF DECONTAMINATION
Surface contaminants which are found on equipment in the reactor coolant system
and the spent fuel pit that are in contact with the water are removed by
conventional techniques of flushing and scrubbing as required. Tools are decontaminated by flushing and scrubbing since the contaminants are generally on
the surface only of non-porous materials. Personnel and their clothing are
decontaminated according to the standard health physics requirements.
Those areas which are susceptible to spillage of radioactive fluids are painted
with a sealant to facilitate decontamination that may be required. Generally washing and flushing of the surfaces are sufficient to remove any radioactivity
present.
The corrosion films generally are tightly adhering surface contaminants, and must be removed by chemical processes. The removal of these films is generally
done with the aid of commercial vendors who provide both services and
formulations. Since decontamination experience with reactors is continually
being gained, specific procedures may change for each decontamination case.
Portable components may be cleaned with a combination of chemical and ultrasonic
methods if required.
9.7-2 9.7.3 DECONTAMINATION FACILITIES Permanent Equipment decontamination facilities on site include a CO 2 decontamination facility located in the Dry Storage Warehouse and a Cask Handling
Facility for each unit. Portable enclosures may also be used for decontaminating
tools and equipment. Fuel handling tools and other tools can be cleaned and
decontaminated in the facility, the portable enclosures or in the refueling canal
area.
The Cask Handling Facility is used to decontaminate surfaces of large equipment and tools. In the Cask Handling Facility, the outside surfaces of the spent fuel casks and radiological material shipping containers are decontaminated before they are hauled away. The cask exterior is decontaminated before it is hauled away. Prior to hauling a spent fuel cask or radiological material shipping container to the ISFSI or offsite, the outside surface is inspected for contamination in accordance with plant procedures.
A personnel decontamination shower facility is located adjacent to the dress
facility east of the radwaste building. It is designed to prevent potential dose
rates from exceeding the limits specified in the Code of Federal Regulations. The
ventilation system filters water vapor and room air before being released to the
outside environment, and water from the decontamination shower facility is drained
to the radwaste holdup tank.
9.7-3 Revised 04/17/2013 C26C26 9.8 AUXILIARY BUILDING HVAC SYSTEMS AND CONTAINMENT PURGE SYSTEMS
This section describes the design and operation of the Auxiliary Building Ventilation System, Containment Purge System, and
Electrical Equipment Room HVAC System.
9.8.1 AUXILIARY BUILDING VENTILATION AND CONTAINMENT PURGE SYSTEMS
9.8.1.1 DESIGN BASIS
The Auxiliary Building Ventilation System is designed to meet the following
principal criteria:
a) Ensure adequate heat removal from equipment rooms and open areas during non-design basis accident conditions.
b) Control direction of flow of potential airborne radioactivity from areas of low activity through areas of higher activity, to the common ventilation exhaust during non-design basis accident conditions.
The Containment Purge System is designed to purge the containment atmosphere
for unlimited access during shutdown periods.
9.8.1.2 SYSTEM DESIGN AND OPERATION
The Auxiliary Building Ventilation System provides clean air to the operating
areas of the Auxiliary Building. The Auxiliary Building Ventilation System
is shown schematically in Figure 9.8-1. The system exhausts air from the
equipment rooms and open areas of the Auxiliary Building and Unit 4 spent
fuel storage pit, through a closed system. The Unit 4 Spent Fuel Pool and
New Fuel Storage Area ventilation is shown schematically in Figure 9.8-4.
The exhaust system includes a 100 percent capacity bank of high efficiency
particulate air (HEPA) filters, and two 100 percent capacity fans discharging
to the atmosphere via the plant vent. A separate fan exhausts air from the
Unit 3 spent fuel area through HEPA filters to its own vent and is not
connected to the Auxiliary Building Ventilation System. The Unit 3 Spent
Fuel Pool and New Fuel Storage Area ventilation is shown schematically in
Figures 9.8-3 and 9.8-4. Radiation monitoring is provided to monitor gases
and particles discharged from the spent fuel vents. Additionally, the Unit 3
Cask Handling Facility ventilation system exhausts air into the Unit 3 Spent
Fuel Pit Vent, as shown schematically in Figures 9.8-3; and the Unit 4 Cask
Handling Facility ventilation system exhausts air into the Plant Vent, as
shown schematically in Figures 9.8-4. These arrangements ensure the proper
direction of air flow for removal of potential airborne radioactivity from
the Auxiliary Building, and spent fuel areas.
9.8-1 Revised 04/17/2013 C26C26 The Auxiliary Building Ventilation System provides a minimum of five air exchanges per hour for each of the rooms and open areas of the building. The
minimum of five air exchanges per hour no longer applies to the laundry room
per blank off of air inlets and installation of split unit a/c system. This
assures adequate heat removal from operating equipment.
Operation of this system would be interrupted by a loss of normal power
supplies, as the main supply and exhaust fans are not required for operation
of engineered safety features. These exhaust fans can be manually loaded on
to the emergency diesel generators.
Additionally, the high head safety injection pump room has louvered doors installed to ensure long term cooling of the high head safety injection pumps following an accident.
The Containment Purge System is independent of the Auxiliary Building
Ventilation System and includes provisions for handling both supply and
exhaust air. The Containment Purge System ventilation is shown schematically
in Figures 9.8-5 and 9.2-6. The supply system includes an outside air
connection to roughing filters, a fan duct system and a supply penetration
with two quick-closing butterfly valves for bubble tight shut-off. The
exhaust system includes an exhaust penetration with two quick-closing
butterfly valves similar to those above, a duct system, fan, and roughing
filters with connection to the plant vent. Both supply and exhaust systems
include filters and two fans, one for each containment, with power-operated, fail-closed isolating dampers. The full flow rate is 35,000 CFM per
containment which is equivalent to 1.33 air changes per hour. However, as
discussed in the note to Table 9.8-1, the purge supply and exhaust valves
have been adjusted to limit flow to approximately 7000 CFM. The quick
closing butterfly valves act as purge isolation valves and are capable of
closing in less than five seconds on receipt of the containment isolation
signal or high activity signal from the air particulate and gas monitor. In
each case, there are two valves in series, one inside and one outside the
containment.
Prior to purging the containment, the air particulates and gas monitor and
the Area Radiation Monitor indications of the closed containment activity
levels will be used to guide the operator in use of the purge system. When
purging the containment, releases from the plant vent are continuously
monitored.
9.8-2 Revised 04/17/2013 C26C26 When the plant is in a state other than cold shutdown or refueling shutdown, the opening angles of the purge valves are mechanically restrained to less
than or equal to 30
û (54-inch purge return valves) and less than or equal to 33û (48-inch purge supply valves), hence the pre-access time period is increased to reduce containment humidity and allow habitation. Stress
reports on the two sizes of valves by the supplier indicate that the margins
between calculated stresses for the various parts and allowables are adequate
to qualify the valves (in blocked position) for closure during a DBA-LOCA.
Debris screens are located inside containment inboard of the containment
supply and exhaust purge valves. The debris screens and the pipe between the
screens are seismically designed. The debris screens are designed to
withstand the peak containment differential LOCA pressure. The debris
screens will preclude material from blocking the containment isolation valves
following a LOCA.
9.8.2 ELECTRICAL EQUIPMENT ROOM HVAC SYSTEM 9.8.2.1 DESIGN BASIS The Electrical Equipment Room HVAC System is designed to accomplish the following:
- 1. To remove heat dissipated by all equipment in the Electrical Equipment Room during normal plant operation and emergency conditions.
- 2. To provide a redundant, reliable, and independent system supplied from emergency power to maintain a temperature controlled environment for the safety related equipment located within the Electrical Equipment Rooms. 9.8.2.2 SYSTEM DESIGN AND OPERATION The Electrical Equipment Room HVAC System is designed to provide cooling and ventilation to the Electrical Equipment Room to prevent room temperature from exceeding the 104
ûF limitation for the safety related equipment. The system is comprised of one non-safety related chilled water air conditioning system and two safety related air conditioning (A/C) systems. Both safety related and non-safety related systems are controlled by wall mounted thermostats in the Electrical Equipment Room. The non-safety related system consists of one air handler with two redundant chiller units located on the roof of the Auxiliary Building. The non-safety related system is designed to maintain the Electrical Equipment Rooms below 77
ûF during normal plant operation with one chiller in operation. If one chiller unit fails, the other chiller will automatically start and maintain the room temperature within design limits.
In the event that both chiller units fail, or the air handler fails during normal operation, the two safety related air conditioning systems are designed to auto-start on the predetermined thermostat temperature settings and prevent room temperature from exceeding the 104
ûF limitation.
9.8-3 Rev. 16 10/99 The safety related system consists of two separate split A/C trains. One of the safety related air conditioning condensing units is located at the 18 foot elevation to the west and south of the Electrical Equipment Room, while the redundant condensing unit is located on the roof of the penetration area at the 42 foot elevation. The air handling units are located in the Electrical Equipment Room. Each A/C train is capable of maintaining the Electrical Equipment Room at a temperature of no more than 104
ûF. Because the safety related A/C units are required to remove emergency heat loads, they must be capable of operating during a loss of offsite power. Both safety related A/C trains are powered from vital motor control centers and, therefore, can be powered from the emergency diesel generators.
9.8.2.3 SAFETY ANALYSIS The Electrical Equipment Room HVAC System is designed with sufficient redundancy such that any single component failure, up to the malfunction of the non-safety related A/C system and one safety related A/C train, will not prevent the system from performing its intended cooling function. The design of the safety related air conditioning units provides protection against tornado generated missiles for outdoor components. This protection is based on separation and location of redundant components. In addition, the safety related air conditioning units have been designed to meet the requirements for Seismic Category I components.
9.8-4 Rev. 16 10/99 TABLE 9.8-1 Sheet 1 of 2 AUXILIARY BUILDING FAN DATA
SUMMARY
Units Installed Unit Capacity Units Required
for System Per Containment Each Normal Operation Purge System
- (1) Purge Supply
Fans 1 35,000 CFM* 1
Fan static pressure -- 3 in. W.G. --
Fan motor 1 20 HP 1
(460 V, 3 PH, 60 Hz)
Air Filters, 1 7,000 CFM* 1 roughing
(2) Purge Exhaust
Fans 1 35,000 CFM* 1
Fan static pressure -- 2 in W.G. --
Fan motor 1 20 HP 1
(460 V, 3 PH, 60 Hz)
Air Filters, Roughing 20 35,000 CFM 20
(3) Aux. Bldg., Exhaust
Fans 1 40,000 CFM 1
Fan static pressure -- 4 1/2 in. W.G. --
Fan motor 1 40 HP 1
Air filters, HEPA 20 40,000 CFM 20
- The containment purge supply and exhaust valves have been adjusted to limit
air flow to approximately 7000 CFM. See FPL letter to NRC L-83-120, R. E.
Uhrig to A. Schwencer, dated March 4, 1983, "Containment Purge Operability".
Revised 04/17/2013 C26 TABLE 9.8-1 SHEET 2 OF 2
RADWASTE SOLIDIFICATION BUILDING FAN DATA
SUMMARY
System Units Installed Unit Capacity Units Required for Per Containment Each Normal Operation
(1) Radwaste Bldg. Exhaust
Fans 2 9,210 CFM 1
Fan Static Press -- 9.54 in. W.G. --
Fan Motor 2 30 HP 1
Rev. 13 10/96
FINAL SAFETY ANALYSIS REPORT FIGURE 9.8-1 REFER TO ENGINEERING DRAWING 5610-M-3060 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 AUXILIARY BUILDING VENTILATION FIGURE 9.8-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.8-2 DELETED
Revised 06/30/2011 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 AUXILIARY BUILDING VENTILATION LAUNDRY DRYERS EXHAUST FIGURE 9.8-2 C25
FINAL SAFETY ANALYSIS REPORT FIGURE 9.8-3 REFER TO ENGINEERING DRAWING 5613-M-3034 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 SPENT FUEL POOL AND NEW FUEL STORAGE AREA VENTILATION FIGURE 9.8-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.8-4 REFER TO ENGINEERING DRAWING 5614-M-3034 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 SPENT FUEL POOL AND NEW FUEL STORAGE AREA VENTILATION FIGURE 9.8-4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.8-5 REFER TO ENGINEERING DRAWING 5613-M-3053 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 CONTAINMENT PURGE SYSTEM AND PENETRATION COOLING SYSTEM FIGURE 9.8-5
FINAL SAFETY ANALYSIS REPORT FIGURE 9.8-6 REFER TO ENGINEERING DRAWING 5614-M-3053 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 CONTAINMENT PURGE SYSTEM AND PENETRATION COOLING SYSTEM FIGURE 9.8-6
9.9 CONTROL BUILDING VENTILATION SYSTEM 9.9.1 CONTROL ROOM
9.9.1.1 DESIGN BASIS Criterion:
GDC 19-Control Room.
A control room shall be provided from which actions can be taken to operate the nuclear power unit safely under normal conditions and to maintain it in a safe condition under accident conditions, including loss-of-coolant accidents.
Adequate radiation protection shall be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident. Equipment at appropriate locations outside the control room shall be provided (1) with a design capability for prompt hot shutdown of the reactor, including necessary instrumentation and controls to maintain the unit in a safe condition during hot shutdown, and (2) with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures.
PTN has committed to 10 CFR 50, Appendix A, GDC 19 - Control Room as part of the change to the Alternate Source Term (AST) methodology for dose analysis as approved in Amendments 244/240. 10 CFR 50.67 was issued by the NRC to permit holders of facility operating licenses to revise the traditional accident source term (TID 14844) that is used in the design basis accident radiological consequence analyses with one derived from the AST methodology and requires an evaluation of the consequences of affected design basis accidents. The Control Room Ventilation System (CRVS) is designed to maintain doses to the operators within the regulatory limits of GDC-19 following the radiological consequences of a Loss-of-Coolant Accident (LOCA), Main Steam, Line Break (MSLB), Steam Generator Tube Rupture (SGTR), Locked Rotor (LR), Rod Cluster Control Assembly (RCCA) Ejection, Fuel Handling Accident (FHA), and Waste Gas Decay Tank (WGDT) Rupture accidents. Each of the radiological release accidents was evaluated following regulatory guidance for implementation of the AST provided in NRC Regulatory Guide (RG) 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors".
9.9-1 Revised 04/17/2013 C26 Clarification Item III.D.3.4, "Control Room Habitability Requirements," of NUREG 0737 required all licensees to assure that control room operators would
be adequately protected against the effects of an accidental release of toxic
or radioactive gases such that the unit(s) could be safely operated or shut
down under design basis accident conditions.
The function of the CRVS, including the Control Room Emergency Ventilation
System (CREVS), is to provide a controlled environment for the comfort and
safety of control room personnel and to assure the operability of control
room components during normal operating, anticipated operational occurrences, and design basis accident conditions.
The design basis of the system with respect to radiological emergencies is to
be capable of automatically starting under accident conditions to initiate
emergency control room pressurization and filtration, assuming the occurrence
of a single active damper or supply fan failure.
The design basis of the system with respect to other emergencies that could
affect the control room environment is to be capable of manual actuation.
Additionally, multiple self-contained breathing apparatus units are in and
near the control room for use by the control room personnel during accidental
releases of toxic gases.
As part of adopting the Alternative Source Term (AST) methodology, a Compensatory Filtration Unit has been added to the CREVS, capable of manual actuation as a qualified backup to the CREVS Recirculation Filter train.
Both of these filtration systems take suction through dual CREVS emergency air intake ducts which are located in diverse wind directions, designed to seismic criteria, and protected from environmental effects including tornado generated missiles. The AST dose analyses are based on having balanced outside air makeup from both emergency air intakes. Balanced flow is achieved by throttling valves provided in each intake branch and manual isolation valves are provided for system maintenance and designed to limit inleakage into the system.
9.9-2 Revised 04/17/2013 C26C26C26C26 9.9.1.2 SYSTEM DESIGN AND OPERATION
The control room atmosphere is filtered, and conditioned as required by a
separate ventilation system as shown on Figures 9.9-1, 9.9-2, 9.9-4 and 9.9-
- 5. This system circulates air from the control room and control room offices
through return air ducts to three 100% capacity air handling units located in
the mechanical equipment room, adjacent to the cable spreading room. Outside
air is drawn into the air handling units through roughing filters, and cooled
as required. Conditioned air is then directed back to the rooms through a
supply air duct system. The associated air conditioning condensing units are
located on top of the Control Building roof.
The CRVS, which normally draws in fresh air from the outside, also has the capability to go into a recirculation mode that is part of the CREVS. In the recirculation mode, fresh air provided from the CREVS intake piping and recirculated air from the Control Room is processed through the Recirculation Filters [High Efficiency Particulate Air (HEPA) filters and charcoal filters], and Supply Fans to maintain an acceptable control room environment during adverse radiological conditions. The CREVS Compensatory Filtration Unit is provided as a qualified backup to the CREVS Recirculation Filter train in the unlikely event of its inoperability.
The CREVS intake piping is shared by both the CREVS Recirculation Filter train and Compensatory Filtration Unit. Provisions have been made to allow isolation, as necessary, of either of the two duct branches that feed CREVS Recirculation Filter train and CREVS Compensatory Filtration Unit.
All three HVAC units are powered by swing power sources, each of which can be
powered by the emergency diesel generators. One HVAC unit is powered by MCC 3D, one unit by MCC 4D, and the third unit is powered via a transfer switch which
automatically transfers between MCCs 3B and 4B. This configuration precludes
the loss of more than one HVAC unit for any postulated single failure.
Control room equipment is designed to operate in an environment of 120 o F and 95% relative humidity. If two of three units were inoperative, the third
would maintain the environment within these limits.
The Control Room Envelope (CRE) is established as a component of the Control
Room Emergency Ventilation System (CREVS). The CRE consists of the Control
Room and the Mechanical Equipment Room (located in the southwest corner of
the Cable Spreading Room) including the Control Room's offices, rack area, kitchen, and lavatory. Both rooms are considered part of the envelope
because both are serviced and pressurized by the control room's air handlers
through common ductwork.
9.9-3 Revised 04/17/2013 C26C26C26 The boundaries of the envelope are the floors, walls, ceilings, dampers, doors and ductwork of the two rooms and are designed to limit the unfiltered
inleakage to less than or equal to 100 cfm when operating in the emergency
mode. The CRE boundary integrity is required for CREVS operability.
The CREVS Compensatory Filtration Unit located in the Purge Fan Room and the associated ductwork are Safety-Related and designed to meet seismic criteria.
It includes a supply fan, carbon filter, pre-filter, upstream and downstream HEPA filters. The supply fan motor is powered from the MCC by emergency diesel generators and has the same rating as the CREVS Supply Fans.
9.9.1.3 NORMAL OPERATION
During normal operation, fresh makeup air is admitted to this system through
an intake louver and two dampers in series located in the west wall of the
Control Building. This system maintains a positive pressure in the control
room envelope greater than that in the cable spreading room in order to prevent smoke from a hypothesized fire in the cable spreading room from
entering the control room. All control room penetrations are designed for
leak tightness standards, including doors per NFPA 80. Since the control
room is maintained at slightly more than atmospheric pressure, the
infiltration of contaminated air into the control room is negligible.
Two radiation monitors located in the normal air intake ducting continuously
monitor for radiation in the incoming air. In the unlikely event of a
maximum hypothetical accident (MHA), the Control Room ventilation will
automatically be placed in a recirculation mode as described further in
Section 9.9.1.5.
9.9.1.4 CONTROL ROOM EMERGENCY OPERATION DESIGN
9.9.1.4.1 CREVS Recirculation Filter Train
Two emergency modes of operation exist:
(1) one automatic, upon receipt of applicable signals associated with a potential radiological exposure; and
(2) the other manually initiated.
The automatically initiated mode, described in detail in Subsection 9.9.1.5, provides pressurization using a limited quantity of outside air through a
HEPA and charcoal filter system. Without pressurization, in-leakage in
excess of radiological limits could occur. No requirement currently exists
for the complete isolation provided by the manually initiated mode, since no
concerns related to chemical releases have been identified for the site.
9.9-4 Revised 04/17/2013 C26C26C26 To ensure that the Control Room operators are not impaired by an ammonia storage tank spill at Turkey Point Unit 5, a layer of floating (special
surface blanketing) balls has been installed in the impoundment basin below
the ammonia storage tanks. These balls will automatically arrange themselves
into a close packed formation if a spill occurs and reduce the release of
ammonia to the atmosphere. Consequence modeling demonstrates that the
concentration of ammonia in the control room will remain below the
Occupational Safety and Health Administration Permissible Exposure Levels (OSHA - PEL) without operator action. These levels are significantly less
than the limits to which Turkey Point committed in RG 1.78, Assumptions for
Evaluating the Habitability of a Nuclear Power Plant Control Room during a
Postulated Chemical Hazardous Chemical Release.
9.9.1.4.2 CREVS Compensatory Filtration Unit The emergency mode of operation of the CREVS Compensatory Filtration Unit is initiated manually only.
When the CREVS Recirculation Filter train is in standby or in operation, the CREVS Compensatory Filtration Unit is turned off and isolated from the associated CREVS intake branch by an isolation damper.
The CREVS Compensatory Filtration Unit is manually aligned for operation when the CREVS Recirculation Filter train is declared inoperable. Alignment of the CREVS Compensatory Filtration Unit for operation requires the closing of the isolation damper in the intake branch that feeds the CREVS Recirculation Filter train and the opening of the isolation damper in the intake branch to CREVS Compensatory Filtration Unit.
9.9.1.5 AUTOMATIC EMERGENCY OPERATION
The control room emergency mode is initiated by a containment Phase "A" signal, a high radiation signal from the containment air Radiation Monitors
R-11 and R-12, the manual initiation from a test switch, or a high radiation
signal from the redundant monitors in the control room normal air intake.
Following initiation, all exhaust fans are shut off, and the redundant
exhaust isolation dampers in series are closed. Redundant normal air intake
isolation dampers in series are closed. Redundant emergency air intake
dampers in parallel are opened. Likewise, the recirculation air path is
opened. A single air supply fan is energized to move the appropriate mixture
of recirculation control room air and new outdoor air through the HEPA and
charcoal filter system. In addition, the Technical Support Center (TSC)
ventilation system emergency mode is started from CREVS B Channel. This
feature is not part of the ESFAS system nor required for the CREV system to
meet its safety function. A TSC bypass switch is provided to prevent
automatic actuation of the TSC ventilation system during CREVS testing.
9.9-5 Revised 04/17/2013 C26C26C26 9.9.1.6 CONTROL ROOM HABILITY PROGRAM The administrative site procedure, "Control Room Habitability Program", provides the administrative controls to ensure and verify that the Control Room Envelope (CRE) meets the requirements for operability and habitability during normal, emergency, and post-accident conditions. The CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation System (CREVS), CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under Design Basis Accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 REM Total Effective Dose Equivalent (TEDE) for the duration of the accident.
The program shall include the following elements:
- b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
- c. Requirements for (i) measuring the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors," Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.
- d. Measurement of CRE pressure with respect to all areas adjacent to the CRE boundary at designated accessible locations.
9.9-6 Revised 02/06/2013 C26 9.9.2 CONTROL BUILDING ANNEX 9.9.2.1 DESIGN BASIS
The DC Equipment/Inverter Room HVAC System is designed to accomplish the following: 1. Provide a redundant, reliable, independent means of maintaining the room temperatures below the qualified operability temperature of the equipment located in the DC Equipment/Inverter rooms. 2. Maintain the battery rooms at a temperature above that at which the battery capacity must be de-rated below its required capacity. 3. Maintain adequate ventilation to ensure that hydrogen concentration remains below the lower limit for flammability. 4. Maintain room temperature during normal plant operation below the continuous operation qualification temperature of the equipment location
in the rooms. 9.9.2.2 SYSTEM DESIGN AND OPERATION The DC Equipment/Inverter Room HVAC system provides cooling ventilation in the Control Building Annex. This system provides cooling to the equipment in
the inverter rooms, the DC equipment rooms and the battery rooms which
comprise the annex. The HVAC system for these rooms consists of a common
split A/C unit and two packaged A/C units. Each packaged unit is dedicated
to the north or south equipment rooms. The common unit can provide air to
both the north and south rooms. Refer to Figure 9.9-3, sheets 1 and 2.
The system design also incorporates a supplemental cooling system consisting of portable fans and administrative controls. This supplemental cooling
system will be used to enhance ventilation in the room and also to draw
cooler air from adjacent rooms to maintain temperatures in a range compatible
with equipment operation. When not in use the dedicated fans are stored in
seismically designed restraints in close proximity to the equipment rooms.
9.9-7 Revised 04/17/2013 All of the ventilating and air conditioning equipment is capable of being powered from an emergency diesel generator (EDG). The common split A/C unit
is automatically loaded on the EDGs following a loss of offsite power. The
north and south units are powered from vital buses and may be manually
started after a loss of offsite power. Special dedicated receptacles have
been provided in the rooms to power the portable fans. These fixtures are
120 VAC fed from an EDG-backed source.
This system circulates air from these rooms to air conditioning units or the air handling unit and returns cool air into the rooms. Each unit is
controlled by a thermostat. These units are designed to maintain the
temperature in the rooms below 104 o F. In the event of a fire or failure of one of the HVAC units, the room
temperature may increase. Routine surveillance of these rooms is performed
to confirm a suitable environment for the equipment is maintained. Should
increasing temperatures be noted, supplemental cooling may be initiated using
the portable fans. The batteries have been shown to be operable at
temperatures up to 110 o F and the other safety related equipment is operable at temperatures up to 135 o F (for short time periods). The supplemental cooling system, is capable of maintaining temperatures below these limits. 9.9.2.3 SAFETY ANALYSIS
The DC Equipment/Inverter Room HVAC system is designed with sufficient redundancy such that component failures, up to and including malfunction or
unavailability of two of the three cooling units, will not prevent the system
from performing its cooling and ventilation functions. This capability
credits the administrative controls and operator actions to monitor the room
temperatures and align the portable fans if conditions warrant their use.
Analyses have demonstrated that the supplemental cooling system can maintain
the room temperatures within an acceptable range for electrical equipment
operability. Analysis (JPN-PTN-SEMP-93-010) also shows that hydrogen
concentrations will be maintained below flammable limits. The portable fans
are stored in seismically designed racks, and provided with EDG backed power
receptacles so that neither loss of offsite power nor earthquake will cause
loss of cooling capacity. Lead blankets are provided to seismically restrain
the fans during free standing operations(i.e. when removed from storage
racks). Based on the preceding, the adverse effects of any credible event or system failure will not compromise the ability to provide cooling to the DC
Equipment/Inverter rooms.
9.9-8 Revised 04/17/2013 9.9.3 COMPUTER/CABLE SPREADING ROOM HVAC SYSTEM 9.9.3.1 DESIGN BASIS The Computer/Cable Spreading Room HVAC System is designed to accomplish the following:
- 1. To remove heat dissipated by all equipment in the Computer and Cable Spreading Rooms During normal plant operation and emergency conditions.
- 2. To provide a redundant, reliable, and independent system supplied from emergency power to maintain a temperature controlled environment for
the safety-related equipment located within the Computer and Cable
Spreading Rooms.
9.9.3.2 SYSTEM DESIGN AND OPERATION The Computer/Cable Spreading Room HVAC System provides cooling and ventilation to the equipment located in the Computer Room and Cable Spreading
Room. The system is designed to maintain temperatures in the rooms below the
104°F limit for the safety related equipment.
The system is comprised of two independent chilled water A/C trains. Each train consists of 100% capacity chiller package located on the Control
Building roof and three air handling units. Two 50% capacity air handling
units for each train are located in the Computer Room. One 100 % capacity
air handling unit for each train and a common duct run are located in the
Cable Spreading Room. Each train is capable of providing 100% cooling for
both rooms during normal and emergency conditions.
During a loss of offsite power (LOOP), the system is not automatically loaded on the Emergency Diesel Generator (EDG). The system is manually loaded on
the EDG by administrative procedures. Supplemental cooling system discussed
in the Control Building Annex section will be used to enhance ventilation in
the room and also to draw cooler air from adjacent rooms to maintain
temperatures in a range compatible with equipment operation. When not in use
the dedicated fans are stored in seismically designed restraints in close
proximity to the equipment rooms. Temperature indicator located in the
Control Room provide indication to allow operators to load the system prior
to exceeding the temperature limitations.
9.9.3.3 SAFETY ANALYSIS The Computer/Cable Spreading Room HVAC System is designed with sufficient redundancy such that any single component failure, up to malfunction of a
complete train, will not prevent the system from performing its intended
cooling function. The Computer/Cable Spreading Room HVAC System is designed
and installed to Seismic Category I requirements. In addition, the chilled
water equipment located on the roof is designed to withstand the effects of a
9.9-9 Revised 04/17/2013
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-1 REFER TO ENGINEERING DRAWING 5610-M-86
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CONTROL BUILDING HVAC EL 42'-0" FIGURE 9.9-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-2 REFER TO ENGINEERING DRAWING 5610-M-87 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CONTROL BUILDING HVAC EL. 30'-0" FIGURE 9.9-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-3, SHEET 1 REFER TO ENGINEERING DRAWING 5610-M-85 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 DC EQUIPMENT/INVERTER ROOMS HVAC SHEET 1 FIGURE 9.9-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-3, SHEET 2 REFER TO ENGINEERING DRAWING 5610-M-85 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 DC EQUIPMENT/INVERTER ROOMS HVAC SECTIONS SHEET 2 FIGURE 9.9-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-4 REFER TO ENGINEERING DRAWING 5610-M-3025 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CONTROL BUILDING VENTILATION CONTROL ROOM HVAC FIGURE 9.9-4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.9-5 REFER TO ENGINEERING DRAWING 5610-M-3025 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CONTROL BUILDING VENTILATION COMPUTER FACILITY/CABLE SPREADING ROOM HVAC FIGURE 9.9-5
9.10 NORMAL CONTAINMENT VENTILATION SYSTEM
9.10.1 DESIGN BASIS
Performance Objectives
The normal containment ventilation system is designed to accomplish the
following:
a) Remove the normal heat lost from all equipment and piping in the containment during operation and to maintain the temperature at or
below a normal ambient of 120 o F. Operation with containment bulk temperatures above 120 o F has been evaluated. The evaluation (Reference 1) concludes that operation at containment bulk ambient temperatures above 120 o F but not exceeding 125 o F for a cumulative period of two weeks (i.e., 336 temperature dependent equivalent hours which is
defined consistent with NRC accepted methodology [Arrhenius] for
determining the qualified life of equipment to meet 10 CFR 50.49) per
year is acceptable with no adverse impact on plant safety.
b) Provide sufficient air mixing and circulation throughout all containment areas to permit maintenance and/or refueling operations
after reactor shutdown.
In order to accomplish these objectives, the following systems have been
provided:
a) Normal Containment Cooling System b) Control Rod Drive Mechanism Cooling System
Design Description
The design characteristics of the equipment required in the containment for
cooling during normal operation are presented in Table 9.10-1. The
Containment Ventilation System is shown schematically in Figure 9.10-1. The
Containment Ventilation System diesel generator loading is presented in
Section 8.2.
9.10-1 Revised 04/17/2013 C26 9.10.2 SYSTEM DESIGN
The Normal Containment Cooling fans are of the centrifugal type, belt drive.
Control rod drive mechanism cooling fans are direct driven, vane-axial. Each
of the Normal Containment Coolers is provided with a motor trip alarm which
alerts the operator of a failed fan and reduced air flow.
The dampers are provided with limit switches to indicate damper position.
Containment Ventilation
Turkey Point Unit 3 and Unit 4 each have four (4) fan-coil units that discharge and distribute cooled air through containment via common headered, discharge ducting. Each cooling coil in the fan-coil units is designed to transfer up to 1.94 x 10 6 Btu/hr to the Component Cooling Water system to accomplish adequate containment cooling during normal operation. Table 9.10-1 provides a summary of normal containment ventilation data.
Each air handling unit consists of the following equipment arranged so that, during normal operation, air flows through the assembly in the following
sequence: (1) cooling coils, (2) centrifugal fan, and (3) supply header.
The normal air flow rate per fan-coil unit is 120,000 SCFM.
The air handling units are located in the space between the reactor coolant
loop (secondary) shield wall and the containment wall above the refueling
floor. The shielded location makes inspection of the equipment possible at
power operation under controlled access conditions and after shutdown. (See
Figure 6.3-4).
The Control Rod Drive Mechanism (CRDM) Cooling System supplements the normal
containment cooling system and can be used to remove heat from the reactor
vessel head during natural circulation cooldown initiated by a loss of
offsite power. This system consists of fans, cooling coil and ductwork to
draw air through the control rod drive mechanism baffle and eject it to the
containment.
9.10-2 Revised 04/17/2013 C26C26C26 The CRDM Cooling Fans are non-safety related but are fed from vital motor control centers. This allows the operator to manually load the fans onto the
Emergency Diesel Generators under specified conditions. The loading of the
CRDM Cooling Fans onto the Emergency Diesel Generators will be governed by
strict administrative control.
The Emergency Diesel Generators loading is described in Section 8.2.
9.10-3 Rev. 10 7/92 9.
10.3 REFERENCES
- 1. "Safety Evaluation for Containment Bulk Ambient Temperatures," JPN-PTN-SENJ-88-052, Rev. 3, April 13, 1989.
9.10-4 Rev. 10 7/92
TABLE 9.10-1 NORMAL CONTAINMENT VENTILATION DATA
SUMMARY
UNITS INSTALLED UNITS REQUIRED PER UNIT CAPACITY FOR
SYSTEM CONTAINMENT (EACH)
NORMAL OPERATION CONTAINMENT
Normal Cooling Fan-Coil Units 4 120,000 Scfm 3(1) Cooling Coil 4 1.94 x 10 6 Btu/hr 3(1) Fan Static Pressure --- 2.74 in. W.G. ---
Fan Motor (460 V, 3 ph, 60 Hz) 4 100 HP 3(1) CONTROL ROD DRIVE
Mechanism Cooling
Fan-Coil Units 2 32,000 cfm 1
Cooling Coil 2 1.60 x 10 6 Btu/hr 1
Fan Static Pressure --- 6.3 in. W.G. ---
Fan Motor (460 V, 3 ph, 60 Hz) 2 60 HP 1
(1) High CCW supply temperature during summer months may require operation of all fan-coils.
Revised 04/17/2013 C26C26C26C26
FINAL SAFETY ANALYSIS REPORT FIGURE 9.10-1 REFER TO ENGINEERING DRAWING 5613-M-3057 , SHEET 1 5614-M-3057 , SHEET 1
Revised 04/17/2013 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 & 4 CONTAINMENT NORMAL AND EMERGENCY COOLING SYSTEMS FIGURE 9.10-1 C26C26 9.11 AUXILIARY FEEDWATER SYSTEM
9.11.1 DESIGN BASIS
The Auxiliary Feedwater System is designed to:
- 1) Sustain operation, following a loss of offsite power, for a period of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> to include maintaining the unit in Hot Standby for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> followed by a 9 hour1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> cooldown to Residual Heat Removal System entry conditions. Maximum hot standby is for 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.
- 2) Supply auxiliary feedwater to the steam generators within 95 seconds of a start signal on low-low steam generator water level during loss of normal feedwater events in which offsite power is available.
- 3) Supply auxiliary feedwater to the steam generators within 95 seconds of a start signal on low-low steam generators water level during loss of normal feedwater events in which offsite power is not available.
9.11.1.1 SYSTEM OPERATION
The Auxiliary Feedwater System is shown in Figures 9.11-2 through 9.11-9.
Upon initiation of the Auxiliary Feedwater System, the turbine steam isolation valves open and actuate position switches. These position switches actuate the solenoid valves mounted on the Auxiliary Feedwater control valves. The instrument air, in conjunction with a signal generated from the controllers in the Main Control Room is then permitted to modulate the control valves. Manual and automatic modes of operation are provided and may be selected from the Main Control Room. Flow indication is provided locally and in the Main Control Room. Auxiliary Feedwater Flow Control Valves position are provided locally.
9.11.1.2 Auxiliary Feedwater Flow Control Valves
Each steam generator auxiliary feedwater line, Train 1 and Train 2, has a flow element, flow transmitter, and flow control valve. When the AFW system is in the standby mode, controllers in the control room are set to a predetermined flow rate as delineated in the Technical Specifications and plant operating procedures.
9.11-1 Revised 08/17/2016 C28 The controller pneumatic output signal to the air operated flow control valve
is blocked by a solenoid valve, thus the control valve is closed. Upon
receipt of an AFW steam supply MOV open signal, either auto or manual, the
solenoid valves associated with the flow control valves to the steam
generators on the affected unit will be energized to open. This permits the
predetermined output signal from the controller to be applied to the flow
control valve, supplying AFW to the affected unit's steam generators. The
flow control is normally set to supply at least 125 gpm to each steam
generator. A travel limit stop is installed on each flow control valve and
is adjusted to limit the stem travel to 95% and 100% of full open, limiting
AFW flow to a Steam Generator to 1318.5 gpm, should one of the two flow
control valves fail to the full open position.
Flow indicators for AFW Trains 1 and 2 are installed under the main feedwater
platform for use during manual operation of the flow control valves. Flow
indicators are also provided on the Main Feedwater Platform.
9.11.1.3 NITROGEN BACKUP SYSTEM TO THE AUXILIARY FEEDWATER CONTROL VALVES
The Auxiliary Feedwater System flow control valves are normally operated
using motive force from the Instrument Air System. As a backup to this
source, a nitrogen system is available (see Figures 9.11-6 and 9.11-9) via
automatic transfer on low instrument air pressure. The nitrogen backup
system, consisting of two racks of five bottles each, supplies nitrogen at
approximately 80 psig via a seismically qualified regulator to the AFW Flow
Control Valves for an independent AFW train. Three out of five bottles are
normally open to the header which will provide at least two hours of nitrogen
supply. When the pressure of the three nitrogen bottles decreases to 650
psig, a low pressure alarm alerts the control room operator for "valving in" the two spare (off-line) bottles within 45 minutes after the initiation of
the alarm, in order to maintain automatic operation of the AFW flow control
valves.
The nitrogen bottle racks are designed for hurricane, tornado wind and
seismic loads. These are provided with a missile shield to prevent any
damage to plant equipment and the redundant train due to internally generated
missiles.
9.11-2 Revised 04/17/2013 C26 9.11.2 AUXILIARY FEEDWATER PUMPS
Three quick starting steam turbine driven, auxiliary feedwater pumps are provided for Turkey Point Units 3 and 4. Each pump is capable of delivering 624.8 gpm to the steam generators between 1085 psig at 5900 rpm and 120 psig at 3200 rpm.
The three pumps are installed such that each supplies auxiliary feedwater to either Unit 3 or 4, with any single pump supplying the total feedwater requirement of either unit. Two pumps (B&C) are normally aligned to AFW Train 2 and the third (A) is normally aligned to AFW Train 1.
The turbine driven pumps are supplied with steam from the unit which has lost its normal feedwater supply. RPM indicators are provided locally and in the control room to provide indication that the AFW pump/turbine is running. The turbines have an atmospheric exhaust. Steam can also be supplied from the unit having normal feedwater supply or from the unit's auxiliary steam supply. The supply valves will automatically open by any one of the following five signals.
- 1. Safety Injection. 2. Low-Low Level in any of the three steam generators. 3. Loss of both feedwater pumps under normal operating conditions. 4. Bus Stripping. a. Loss of voltage on either the A or B 4.16 KV bus. b. Degraded voltage on one 480V load center (instantaneous) coincident with safety injection and the diesel generator breaker open. c. Degraded voltage on one 480V load center (delayed) coincident with the diesel generator breaker open. 5. AMSAC signal.
The turbine casing is provided with a sentinel type relief valve for warning purposes only.
9.11-3 Revised 12/07/2015 C28 Impulse type steam traps are provided upstream of the Steam Supply MOVs and drain to the condenser. Additional impulse type steam traps are provided
upstream of the trip and throttle valves and drain to an adjacent drain
trough. The orifice type steam traps, the turbine casing drains, the exhaust
pipe drain, the gland seal drain, the governor valve and the HP and LP steam
leakoffs in the throttle trip valve drain to an adjacent drain trough. The
pump recirculation is controlled by an orifice in the recirculation piping.
The pumps can continue to supply reduced amounts of water to the steam
generators until steam pressure is reduced to 85 psig. The pump output in
pounds per hour is greater than the steam consumption until the 85 psig point
is reached. However, at 120 psig, the Residual Heat Removal System is
started and the auxiliary feedwater pumps are shutdown. Operation of the AFW
pumps under low flow conditions is administratively controlled in plant
procedures.
Cooling water is supplied to the safety related auxiliary feedwater pump oil
coolers from the second stage of the auxiliary feed pump and is discharged to
the condensate storage tanks.
Standby Feedwater Pumps
Two non-safety grade standby steam generator feedwater pumps (SSGFP) are
provided; refer to Figure 10.2-21. The standby steam generator feedwater
pumps are normally used to supply feedwater to the steam generators during
normal start-up, shutdown, and hot standby conditions. The pumps take
suction from the demineralized water storage tank and discharge into the main
feedwater header upstream of the feedwater regulating valves. These pumps
can be operated from the control room or from the local control panel. One
pump is motor driven and normally powered from the 4160 volt C-Bus. The
other pump is diesel engine driven with an integral fuel tank and electric
starting system. In case of loss of off-site power, the normal safety
supply of feedwater to the steam generators is provided by the steam turbine
driven auxiliary feedwater pumps. However, feedwater can also be supplied by
the diesel engine driven standby steam generator feedwater pump (Reference
1).
9.11-4 Revised 04/17/2013 9.11.3 CONDENSATE STORAGE TANKS
Normal water supply to the auxiliary feedwater pumps is from the two 250,000
gallon (nominal) condensate storage tanks, through locked open gate valves
and check valves. Each tank contains a 210,000 gallon minimum indicated
volume which assures a minimum usable volume of 195,331 gallons of
demineralized water for the auxiliary feedwater pumps.
The condensate storage tank design sizing is based on allowing each unit to
be taken from full power to hot standby following a loss of offsite power, and:
- 1. Kept at hot standby for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and then cooled to 350 o F in 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />, at which point the Residual Heat Removal System will be put in service, or
- 2. Kept at hot standby for about 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.
Cooldown rates for using either forced or natural circulation are governed by plant operating procedures.
An additional auxiliary feedwater supply can be provided from the water
treatment system. Demineralized water at a maximum rate of 200 gpm per unit
will be available from the water treatment system. The auxiliary feedwater
requirement to remove decay heat after thirteen hours is less than 128 gpm.
The condensate storage tanks are interconnected so that each of the pumps can
take suction from either tank.
An alternate, non-safety source of water is the 500,000 gallon demineralized
water storage tank. This tank provides the normal water source for the
standby steam generator feedwater pumps.
9.
11.4 REFERENCES
- 1. NRC Letter from Richard Croteau to J. H. Goldberg Dated May 20, 1994, TURKEY POINT UNITS 3 & 4 - ISSUANCE OF AMENDMENTS RE: ELIMINATION OF
CRANKING DIESEL GENERATORS (TAC NOS. M87662 AND M87663).
9.11-5 Revised 04/17/2013 C26C26C26C26 TABLE 9.11-1 SHEET 1 of 2 AUXILIARY FEEDWATER PUMP/TURBINE CONSTRUCTION DATA Auxiliary Feedwater Pump
Ingersoll-Rand 2-1/2 CNTAM4, four stage centrifugal, horizontally split casing.
Performance Data Nominal Speed Min.
Speed Capacity, gpm 600 600
Temperature, F. 100 100
N. P. S. H. required, feet 36 21
Suction Flooded Flooded
Total Dynamic Head, feet 2775(Nominal) 410
Steam Pressure, psig 1085 120
Steam Temperature, F. 556 540
Steam Conditions Saturated, 1/4% Saturated, 1%
moisture moisture
Speed, rpm 5900 3200
Turbine Back Pressure, psig 10 10
Brake Horsepower 758(Max) 155
Revised 11/01/2005 C22C22 TABLE 9.11-1(Continued) SHEET 2 of 2
AUXILIARY FEEDWATER PUMP/TURBINE CONSTRUCTION DATA
Pump Construction Casing 5% Chrome Stainless Steel Shaft 410 Stainless Steel Impeller 11-13% Chrome Steel Wear Rings Stainless Steel Turbine Construction
Casing Cast Steel
Shaft Alloy Steel
Bucket Wheels Forged Steel
Design Pressure 1185 psig
Blades Buckets Milled on
Forged Steel Wheel
Packing Carbon Rings
Lubrication Forced Feed
Pump Shaft Driven
Rev. 16 10/99 TABLE 9.11-2
AUXILIARY FEEDWATER SYSTEM-CODE REQUIREMENTS
Component Codes
Pumps Hydraulic Institute
Standards
Turbines NEMA SM-22-1970
Valves & Piping ASA-B31.1-1955
Rev 8 7/90
DELETED
Revised 04/17/2013 FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 CONDENSATE STORAGE REQUIREMENTS AFTER LOSS OF OFFSITE POWER FIGURE 9.11-1 C26
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-2 REFER TO ENGINEERING DRAWING 5610-M-3075 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 AUXILIARY FEEDWATER SYSTEM TURBINE DRIVE FOR AFW PUMPS FIGURE 9.11-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-3 REFER TO ENGINEERING DRAWING 5610-M-3075 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNITS 3 & 4 AUXILIARY FEEDWATER SYSTEM AUXILIARY FEEDWATER PUMPS FIGURE 9.11-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-4 REFER TO ENGINEERING DRAWING 5613-M-3075 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 AUXILIARY FEEDWATER SYSTEM STEAM TO AUXILIARY FEEDWATER PUMP TURBINES FIGURE 9.11-4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-5 REFER TO ENGINEERING DRAWING 5613-M-3075 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 AUXILIARY FEEDWATER SYSTEM AUXILIARY FEEDWATER TO STEAM GENERATORS FIGURE 9.11-5
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-6 REFER TO ENGINEERING DRAWING 5613-M-3075 , SHEET 3
REV.13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 AUXILIARY FEEDWATER SYSTEM NITROGEN SUPPLY TO AFW CONTROL VALVES FIGURE 9.11-6
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-7 REFER TO ENGINEERING DRAWING 5614-M-3075 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 AUXILIARY FEEDWATER SYSTEM STEAM TO AUXILIARY FEEDWATER PUMP TURBINES FIGURE 9.11-7
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-8 REFER TO ENGINEERING DRAWING 5614-M-3075 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 AUXILIARY FEEDWATER SYSTEM AUXILIARY FEEDWATER TO STEAM GENERATORS FIGURE 9.11-8
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-9 REFER TO ENGINEERING DRAWING 5614-M-3075 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 AUXILIARY FEEDWATER SYSTEM NITROGEN SUPPLY TO AFW CONTROL VALVES FIGURE 9.11-9
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-10 REFER TO ENGINEERING DRAWING 5614-M-3018 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 CONDENSATE STORAGE SYSTEM FIGURE 9.11-10
FINAL SAFETY ANALYSIS REPORT FIGURE 9.11-11 REFER TO ENGINEERING DRAWING 5613-M-3018 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 CONDENSATE STORAGE SYSTEM FIGURE 9.11-11
9.12 POST-ACCIDENT HYDROGEN CONTROL Turkey Point Units 3 and 4 received an exemption from the hydrogen control
requirements of 10 CFR 50.44 and 10 CFR 50, Appendix A, General Design Criteria
41, 42, and 43, in December 2001. The exemption was based in part on NRC
resolution of Generic Issue 121, "Hydrogen Control for PWR Dry Containments",
and the Turkey Point Individual Plant Examination (IPE). These evaluations
demonstrated that large dry containment building designs such as those at Turkey
Point can withstand the effects of hydrogen combustion during design basis
accidents without hydrogen concentration control.
9.12.1 DELETED 9.12.2 DELETED
9.12-1 Revised 04/17/2013 C26C26
FINAL SAFETY ANALYSIS REPORT FIGURE 9.12-1 REFER TO ENGINEERING DRAWING 5613-M-3094 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 POST-ACCIDENT CONTAINMENT VENT AND SAMPLING SYSTEM FLOW DIAGRAM FIGURE 9.12-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.12-2 REFER TO ENGINEERING DRAWING 5614-M-3094 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 POST-ACCIDENT CONTAINMENT VENT AND SAMPLING SYSTEM FLOW DIAGRAM FIGURE 9.12-2
9.13 POST ACCIDENT SAMPLING SYSTEM The capability to obtain and analyze post-accident samples of reactor coolant and containment atmosphere was originally provided as a post-TMI modification. The system was provided with in-line analyzers and
radiation detectors to maintain continuous sampling capability. The
system was intended to provide information about the radionuclides existing post-accident to support emergency response decision making during the initial phases of an accident.
In light of the significant improvements that have been made since the TMI accident in the areas of defining realistic source terms, understanding fission product behavior, and severe accident management, the NRC staff has concluded that many of the original Post Accident Sampling System (PASS) sample requirements are either unnecessary or
effectively provided by other indications of process parameters or
measurement of radiation levels. Thus, from a plant risk standpoint, there is no longer a compelling need to maintain dedicated equipment
for prompt analysis of post accident samples for emergency planning
purposes.
In keeping with the above NRC staff position, much of the original PASS instrumentation has been abandoned in-place.
The current regulatory commitments applicable to PASS include:
a) The capability to obtain and analyze highly radioactive samples
of reactor coolant, containment sump, and containment atmosphere
must be provided. The use of dedicated onsite equipment to
obtain and analyze these samples is not required.
b) The capability of classifying fuel damage events at the alert
level threshold must be provided. This capability may utilize
the normal sampling system and/or correlations of sampling or
letdown line dose rates to coolant concentrations.
c) The capability to monitor radioactive iodines that have been
released to offsite environs must be provided.
Sampling capability is provided for the Reactor Coolant System the containment atmosphere and the containment sump contents as shown on
Figure 9.4-1, and Figure 9.4-2
The reactor coolant samples are tapped off of the normal sample lines, downstream of the containment isolation valves.
The containment sump content sample is tapped off of the normal sample lines via RHR in the recirculation mode, and is provided with reach
rods on the isolation valve.
The containment atmosphere sample is tapped off of the sample line used for the containment hydrogen monitors. This sample line is provided with reach rods on the isolation valves.
9.13-1 04/27/2001 9.14 POST ACCIDENT HYDROGEN MONITORING SYSTEM
The containment post-LOCA hydrogen monitoring equipment (Figures 9.12-1 and 9.12-2) will provide reliable and accurate indication of the concentration of hydrogen gas in the containment atmosphere following a loss-of-coolant accident. Two completely independent systems are provided to monitor for free gaseous hydrogen in the range of 0 to 10 percent by volume in the containment atmosphere, with a system recorder
accuracy of +/- 2.5% full scale.
The sampling will be either educted or received under pressure based on the condition of the containment post-LOCA environment. These systems are complete
closed loops; that is the sample is returned back to the containment atmosphere.
Both recording and indicating devices are provided and located in the Control Room. Channel 1 of the containment post-LOCA hydrogen monitors will be located in
the Post Accident Sampling Room. Channel 2 will be located in the access
area to the waste gas hold up tanks.
The hydrogen monitor sample connections tie-in to the existing post accident containment ventilation system outside containment and return via the containment atmospheric sample Plant Radiation Monitoring System (PRMS) return line. The PACVS sample ports are placed in two separate pipe headers near the containment dome.
9.14-1 Rev. 16 10/99 9.15 EMERGENCY DIESEL GENERATOR AUXILIARIES The original configuration of Turkey Point Units 3 and 4, as licensed by the NRC, utilized two emergency diesel generators (EDGs), currently labeled 3A and 3B, that were shared between the two units. In 1990 and 1991, as part of an upgrade of the Emergency Power System (EPS), two additional EDGs, labeled EDGs 4A and 4B, were added to the plant. These two new EDGs were designed, to the extent possible, to the latest standards while maintaining a consistent design approach with and avoiding extensive redesign and rework of existing Emergency Power System structures/components.
9.15.1 EMERGENCY DIESEL GENERATOR FUEL OIL STORAGE AND TRANSFER SYSTEM 9.15.1.1 DESIGN BASIS The EDG fuel oil storage and transfer system consists of three separate systems. One system is associated with EDGs 3A and 3B, while the other two systems are associated with EDGs 4A and 4B (one system dedicated to each of the Unit 4 EDGs).
9.15.1.1.1 EDGs 3A AND 3B The system associated with EDGs 3A and 3B is designed to:
- 1. Provide diesel oil storage capacity for at least seven days for one EDG. 2. Maintain diesel oil supply to at least one EDG, assuming a single failure in the system.
- 3. Meet the requirements for Class I systems/components in accordance with Appendix 5A.
- 4. Withstand the maximum flood levels in accordance with Appendix 5G, and winds in accordance with Appendix 5A without loss of function.
9.15-1 Rev. 10 7/92
9.15.1.1.2 EDGs 4A AND 4B
The systems associated with EDGs 4A and 4B are designed in accordance with ANSI
Standard N195-1976, as endorsed by Regulatory Guide 1.137. These systems, in
conjunction, are designed to:
- 1. Provide diesel oil storage capacity for at least seven days for two EDGs.
- 2. Maintain diesel oil supply to at least one EDG, assuming a single failure in the systems coincident with a loss of offsite power.
- 3. Meet Seismic Category I requirements.
- 4. Withstand the maximum flood levels and tornado winds and missiles without loss of function by locating critical components inside the Unit 4 EDG Building.
- 5. Prevent the failure of nonseismic structures or components from affecting the safety related functions of the system.
9.15.1.2 SYSTEM DESCRIPTION
9.15.1.2.1 EDGs 3A AND 3B
The system associated with EDGs 3A and 3B stores diesel oil in an onsite diesel oil
storage tank, transfers the diesel oil to either one of the two diesel oil day
tanks (one tank is associated with each EDG), and transfers the diesel oil from
each EDG's diesel oil day tank to its associated skid mounted tank. Operating
diagrams representing the emergency diesel generator fuel oil storage and transfer
system, which are associated with EDG 3A and 3B, are presented in Figures 9.15-3
and 9.15-4. The major design features of this system are:
- 1. Diesel Oil Storage Tank - The diesel oil storage tank has a capacity of 64,000 gallons, which provides sufficient storage capacity to permit one EDG
(3A or 3B) to operate at its "168 hour0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> rating" for at least 7 days. This
tank is designed as a Seismic Class I structure.
9.15-2 Rev. 16 10/99
- 2. Diesel Oil Transfer Pumps - Two diesel oil transfer pumps are provided to transfer diesel oil from the diesel oil storage tank to the diesel oil day tanks. Either of these pumps can be manually aligned to
provide diesel oil flow to either or both of the diesel oil day tanks
associated with EDGs 3A and 3B. In addition, the discharge lines from
these pumps and the pumps associated with EDGs 4A and 4B are
interconnected to provide additional diesel oil supply alignment
flexibility.
- 3. Diesel Oil Day Tanks - Each EDG has a 4000 gallon diesel oil day tank.
These tanks are designed as Class I equipment and are separated from
each other by a concrete wall. Each diesel oil day tank has an
alternate fill connection which is suitable for a tie-in from a mobile
tank unit. These fill lines provide an alternate fill path for the
diesel oil day tanks should the normal supply via the diesel oil
transfer pumps become unavailable.
- 4. Solenoid Valves - Solenoid valves in the transfer lines from the diesel oil day tanks to the skid mounted tanks, in conjunction with level
switches in the skid mounted tanks, prevent the skid mounted tanks from
overflowing. The solenoid valves are provided with manual bypass
valves and associated piping. This arrangement provides capability to
fill the skid tank should the solenoid valve fail to open when required
due to a design basis rain event.
- 5. Air-Operated Valves - Air-operated valves in the transfer lines from the diesel oil storage tank to the day tank automatically open in
response to signals developed by logic circuitry incorporating tank
level and pump control switch positions. The valves can be locally
opened using a separate air source in the event normal instrument air
is not available.
- 7. Diesel Oil - The diesel oil is No. 2 fuel oil complying with the tests, limits, and applicable ASTM Standards specified in the diesel fuel oil
testing program described in the Technical Specifications. The diesel
oil is chemically treated with a biocide to prevent the deleterious
effects of biological activity upon diesel oil quality and a
stabilizing compound to enhance diesel oil long term storage.
- 8. Truck Fill Connection - Additional diesel oil can be delivered to the plant site by truck to replenish the fuel supply system during normal
operation or following an accident by way of a truck fill connection.
In addition, the truck fill connection to the systems for EDGs 4A and
4B may be used to fill this system's diesel oil storage tank.
9.15-3 Revised 08/20/12 C26 Diesel oil is normally transferred from the diesel oil storage tank automatically to maintain diesel oil day tank level by the electric motor
driven diesel oil transfer pump associated with the particular diesel oil day
tank. Each EDG's (3A and 3B) diesel oil day tank gravity feeds though a
solenoid valve to the associated skid mounted tank. Diesel oil is then drawn
from the skid mounted tank, as required, through a duplex filter to the fuel
manifold line. From here the diesel oil goes on to each injector inlet
filter and into the injector.
As described in Section 9.15.1.4, the diesel oil storage tank is drained
every ten years for sediment removal and cleaning. During this maintenance
evolution, a temporary storage and transfer system may be used to provide a
minimum 7-day supply of fuel oil to either the 3A or 3B EDG to satisfy the
system design basis. Additional storage requirements are imposed on the Unit
3 day and skid tanks and the Unit 4 diesel oil storage tanks when this
temporary system is utilized. The additional storage requirements are
contained in plant procedures.
9.15.1.2.2 EDGs 4A AND 4B
The systems associated with EDGs 4A and 4B provide each of the EDGs with a
completely independent diesel oil storage and transfer system. Each of these
systems consists of a diesel oil storage tank, a diesel oil transfer pump, and a diesel oil day tank which, in turn, supplies fuel oil to the EDG diesel
engine. Representative diagrams of the emergency diesel generator fuel oil
storage and transfer system, which are associated with EDG 4A and 4B, are
presented in Figures 9.15-9 and 9.15-10. The major design features of these
systems are:
- 1. Diesel Oil Storage Tanks - Each EDG (4A and 4B) has a diesel oil storage tank which contains approximately 40,400 gallons of diesel oil;
34,700 gallons of diesel oil is sufficient to operate one EDG for at
least 7 days per ANSI N195-1976 methodology. These reinforced concrete
tanks are steel lined and are designed, tested, and inspected in
accordance with the requirements of ASME B&PV Code,Section VIII, 1986
Edition and Addenda (ASME Section VIII) and meet Seismic Category I
requirements. Materials or coating containing aluminum and/or zinc are
not used for the construction or coating of any tank surface that may
be in contact with the diesel oil.
The diesel oil transfer pump suction connection of each tank is located six inches above the bottom of the tank to minimize the possibility of
drawing any sediment and/or water into the pump's suction. The diesel
oil transfer pump rooms are sized to contain the contents of a diesel
oil storage tank.
9.15-4 Revised 10/20/2006 C22 Overflow lines have been provided for each of the diesel oil storage tanks. These lines are piped to an equipment drain which goes to a sump located inside the associated diesel oil transfer pump room.
Also, each diesel oil storage tank has a vent line and flame arrestor connection located at the top of the tank. This vent line and flame arrestor is piped to the outside of the building and is designed to prevent entrance of water during adverse weather conditions. The exposed line and flame arrestor is not designed to withstand a tornado missile since the almost complete crimping, which would be required as a result of the missile to result in a vacuum being formed in the diesel oil storage tank, is not considered credible.
The fill lines for the diesel oil storage tanks enter near the top of the tanks. Therefore, if one of the lines were impacted by a tornado missile, there would be no significant loss in fuel inventory of the tank. Additionally, in the event that a fill line was impacted by a tornado missile, manual alignment of systems can provide alternate flow paths to fill an affected diesel oil storage tank.
Sample connections for these tanks are provided in accordance with ASTM-D270-1975, Petroleum and Petroleum Products Sampling.
- 2. Diesel Oil Transfer Pumps - Each EDG (4A and 4B) has an associated diesel oil transfer pump. Diesel oil transfer system piping can be manually aligned such that the two pumps can take suction from either or both of the diesel oil storage tanks associated with EDGs 4A and 4B and discharge into either or both of the diesel oil day tanks associated with these EDGs. In addition, the discharge lines from these pumps and the pumps associated with EDGs 3A and 3B are interconnected to provide additional diesel oil supply alignment flexibility. Each of these two pumps has sufficient capacity to supply diesel oil to both EDGs 4A and 4B at their continuous load rating.
To prevent any suspended sediment from being transferred to the diesel oil day tanks, each of these diesel oil transfer pumps has a duplex strainer located in its suction path.
9.15-5 Rev. 10 7/92 These pumps are designed in accordance with the requirements of the ASME B&PV Code,Section III, 1983 Edition, Summer 1984 Addenda, (ASME Section III) for Class 3 components and meet Seismic Category I
requirements. Inservice testing capability for these pumps is provided
in accordance with ASME Section XI.
The motor for each diesel oil transfer pump is designated Class 1E and is powered from its associated train of the emergency power system.
The pumps start and stop automatically on low and high level signals, respectively, from their associated diesel oil day tank. Also, these
pumps can be started and stopped manually, if required.
- 3. Diesel Oil Day Tanks - Each EDG has its own 650 gallon diesel oil day tank. These tanks are designed in accordance with the requirements of
the ASME Section III for Class 3 components and meet Seismic Category I
requirements. Materials or coating containing aluminum and/or zinc are
not used for the construction or coating of any tank surface that may
be in contact with the diesel oil.
- 4. Piping and Valves - Piping which performs a safety function external to the engine skid is designed in accordance with the requirements of the
ASME Section III for Class 3 components and meets Seismic Category I
requirements. Diesel oil transfer piping has been designed for a
maximum of 350 o F and 125 psig, which exceeds the system operating requirements. The safety related engine skid mounted piping, as a
minimum, is designed and analyzed to meet the stresses specified by
ANSI/ASME B31.1, Power Piping, 1986 edition (ANSI B31.1, Power Piping).
- 5. Diesel Oil
- The diesel oil is No. 2 fuel oil complying with the tests, limits, and applicable ASTM Standards specified in the diesel fuel oil
testing program described in the Technical Specifications. The oil is
chemically treated with a biocide to prevent the deleterious effects of
biological activity upon diesel oil quality and a stabilizing compound
to enhance diesel oil long term storage.
9.15-6 Rev. 16 10/99
- 6. Truck Fill Connection - Additional diesel oil can be delivered to the plant site by truck to replenish the fuel supply system during normal operation or following an accident. These two systems have a common
truck fill connection which goes to a valve header. Depending on the
valve line-up in each diesel oil transfer pump room, oil may be
transferred to either diesel oil storage tank. Diesel oil from the
truck fill connection passes through a one micron filter prior to
entering the diesel oil storage tanks. In addition, the truck fill
connection for the system associated with EDGs 3A and 3B may be used to
fill these systems' diesel oil storage tanks. The truck fill
connection performs no safety function.
Normally, diesel oil is automatically supplied to the diesel oil day tank for
each EDG from its associated diesel oil storage tank by its diesel oil
transfer pump through a solenoid valve. Diesel oil is then drawn from the
diesel oil day tank, as required, by the fuel pumps.
The diesel oil from the fuel pump (fuel priming pump or engine driven fuel
pump) is directed through a duplex filter and into the engine fuel header.
Here the fuel oil goes into each injector inlet filter and on into the
injector. Any excess fuel is then returned to the diesel oil day tank.
System pressure is maintained below 65 psig by safety relief valves located
downstream of the diesel oil transfer pumps and the DC fuel priming pumps.
9.15.1.3 SAFETY EVALUATION
9.15.1.3.1 EDGs 3A AND 3B
The design of the EDG fuel oil system associated with EDGs 3A and 3B ensures
that diesel oil storage capacity for at least seven days is provided and that
diesel oil can be supplied to at least one EDG, assuming a single failure in
the system coincident with a loss of offsite power. Sufficient time exists
for providing an alternative air source for opening the day tank fill
isolation valves should instrument air fail before the day tank is emptied.
In addition, the discharge lines of the Unit 3 diesel oil transfer pumps and
the diesel oil transfer pumps associated with EDGs 4A and 4B are
interconnected which provides the capability to transfer diesel oil from the
Unit 4 diesel oil storage tanks to either the Unit 3 diesel oil storage tank
or to the Unit 3 diesel oil day
9.15-7 Rev. 16 10/99 tanks. Also, the diesel oil storage tank and each of the diesel oil day tanks have an alternate fill connection which is suitable for a tie-in from a
mobile tank unit. These alternate fill lines provide a fill path for the
diesel oil day tanks should the normal supply via the diesel oil transfer
pumps become unavailable. Refer to Appendix 5A concerning the seismic and
wind loading design of structures, Appendix 5E concerning missile protection
criteria, Appendix 5F concerning internal flooding, and Appendix 5G
concerning external flooding for this system.
9.15.1.3.2 EDGs 4A AND 4B
There is complete redundancy of the components in the diesel oil storage and
transfer systems associated with EDGs 4A and 4B, with the exception of a
common fill station. These systems, in conjunction, ensure that diesel oil
storage capacity for at least seven days for one EDG is provided and can be
supplied to at least one EDG, assuming a single failure in one of the systems
coincident with a loss of offsite power.
If continuous operation of a diesel generator is required for an extended
period of time, additional fuel oil can be delivered to the plant site by
truck and the diesel oil storage tank(s) can be filled to enable each EDG to
supply uninterrupted power. Design provisions are included to minimize the
possibility of degrading EDG performance due to the potential resuspension of
sediment during the refilling process. The tanks are sufficiently sized to
provide ample time to be available to refill a diesel oil storage before it
reaches a very low level. The diesel oil transfer pumps' suction lines are
located six inches from the bottom of the diesel oil storage tanks and have
low flow velocity to minimize any suction turbulence. Duplex strainers are
also located downstream of the tanks to remove any sediment prior to the
diesel oil entering the EDG. Additionally, the volume of diesel oil stored
in the diesel oil day tank would provide time for the sediment to settle
prior to pumping oil from the diesel oil storage tank to the diesel oil day
tank. Also, the diesel oil storage tank not currently being refilled could
be used to supply the required diesel oil to the EDG, allowing additional
time for sediment to settle in the diesel oil storage tank being refilled.
The Safety Related portions of these systems are located inside Seismic
Category I structures (the design of these structures is discussed in
9.15-8 Rev. 16 10/99
Section 5.3.4) or otherwise protected from the effects of natural phenomena and external missiles. In addition, since each of these EDGs and their
associated diesel fuel systems are independent and physically separated from
the other by a concrete wall, an internally generated missile will not result
in the failure of more than one EDG or its associated diesel fuel system.
Also, the systems are not affected by the effects of high-energy and
moderate-energy pipe breaks, since there is no high-energy or moderate-energy
piping in the Unit 4 EDG Building.
Any single failure in the diesel oil storage and transfer systems is bounded
by the loss of an EDG. A failure modes and effects analysis associated with
the loss of an EDG has been performed and the results are discussed in
Section 8.3.
9.15.1.4 TESTS AND INSPECTIONS
During preoperational testing of the systems associated with EDGs 4A and 4B, the diesel oil transfer systems are checked for proper operation. This
testing is also required periodically by the Technical Specifications.
At least once per ten years each diesel oil storage tank will be drained, accumulated sediment removed, and the tank cleaned. In addition, the storage
and transfer systems associated with EDGs 4A and 4B will have a pressure test
in accordance with ASME Section XI performed on those portions designed to
ASME Section III, subsection ND.
The quality of oil is tested and verified prior to being put into the diesel
oil storage tanks, and periodically thereafter, per plant procedure in
accordance with the appropriate ASTM Standards specified in the diesel fuel
oil testing program as described in the Technical Specifications.
9.15-9 Rev. 16 10/99
9.15.1.5 INSTRUMENTATION APPLICATION
9.15.1.5.1 EDGs 3A AND 3B
The following instrumentation and controls are available for the system
associated with EDGs 3A and 3B:
- 1. Local diesel oil level indication is provided for the diesel oil storage tank.
- 2. Diesel oil level switches on the diesel oil day tanks provide alarms in the Main Control Room. Additional level switches are also used to
start and stop the diesel oil transfer pumps and for opening and
closing the solenoid valve at the inlet of each diesel oil day tank.
- 3. A multi-purpose level switch on each skid tank actuates the solenoid valve in the line between the diesel oil day tank and the skid tank
allowing the skid tank to be filled by gravity from the diesel oil day
tank. This switch also provides local alarms on low and high skid tank
level and an interlock to prevent EDG start and extinguish the EDG
ready to start lamp in the Main Control Room if the skid tank level is
below acceptable levels.
- 4. Local diesel oil level indication and alarms are provided for the each skid tank.
- 5. Local manual control is available for the diesel oil transfer pumps.
9.15.1.5.2 EDGs 4A AND 4B
The following instrumentation and controls are available for the systems
associated with EDGs 4A and 4B:
- 1. Local diesel oil level and temperature indication is provided for each diesel oil storage tank. Diesel oil storage tank oil level switches
provide annunciation via an EDG trouble alarm locally and in the Main
Control for diesel oil low and high level.
9.15-10 Rev. 16 10/99
- 2. Diesel oil level switches for low, low-low and high levels in the diesel oil day tanks provide annunciation via an EDG trouble alarm locally and in the Main Control Room. Additional level switches are
also used to start and stop the diesel oil transfer pumps and for
opening and closing the solenoid valve at the inlet of each diesel oil
day tank. Local diesel oil level indication is provided for each
diesel oil day tank
- 3. Oil pressure indication is provided at the diesel oil transfer pumps discharge.
- 4. Pressure switches for low diesel oil pressure provide annunciation via
an EDG trouble alarm locally and in the Main Control Room
- 5. Local manual control is available for the diesel oil transfer pumps.
- 6. Annunciation is provided via an EDG trouble alarm locally and in the Main Control Room for the diesel oil transfer pump in a tripped/off
condition.
- 7. Annunciation is provided via an EDG trouble alarm locally and in the Main Control Room for high differential pressure across the fuel oil
filter or strainer.
- 8. Annunciation is provided via an EDG trouble alarm locally and in the Main Control Room for of fuel priming pump in a no power, overload, or
timed out condition.
9.15.2 EMERGENCY DIESEL GENERATOR COOLING WATER SYSTEM
9.15.2.1 DESIGN BASES
Each EDG has a dedicated cooling water system.
9.15.2.1.1 EDGs 3A AND 3B
Each of the cooling water systems associated with EDGs 3A and 3B are designed to:
9.15-11 Rev. 16 10/99
- 2. Function independently from other cooling water systems to assure that no single failure can affect the cooling of more than one EDG.
- 3. Automatically maintain the diesel engine and lubricating oil's temperature, by means of a heater, in a prewarmed condition to minimize diesel engine wear.
- 4. Include provisions to bypass protective interlocks of the systems during emergency conditions.
- 5. Perform its function under the same environmental conditions as the EDG which it serves.
- 6. Meet the requirements for Class I systems/components in accordance with Appendix 5A.
- 7. Withstand the maximum flood levels in accordance with Appendix 5G, winds in accordance with Appendix 5A, and missiles in accordance with Appendix 5E without loss of function.
9.15.2.1.2 EDGs 4A AND 4B Each of the cooling water systems associated with EDGs 4A and 4B are designed to: 1. Cool its associated EDG to permit proper operation under all EDG loading conditions for seven days without additional cooling water being added.
- 2. Function independently from other cooling water systems to assure that no single failure can affect the cooling of more than one EDG.
- 3. Automatically maintain the diesel engine and lubricating oil's temperature by means of a heater in a prewarmed condition to minimize diesel engine wear.
- 4. Include provisions to bypass protective interlocks of the systems during emergency conditions.
9.15-12 Rev. 10 7/92
- 5. Perform its function under the same environmental conditions as the EDG which it serves.
- 6. Meet Seismic Category I requirements.
- 7. Withstand the maximum flood levels and tornado winds and missiles without loss of function by locating critical component inside the Unit
4 EDG Building or by protecting them with elevation and missile
barriers.
- 8. Prevent the failure of nonseismic structures or components from affecting the safety related functions of the system.
9.15.2.2 SYSTEM DESCRIPTION
9.15.2.2.1 EDGs 3A AND 3B
Each EDG (3A and 3B) has a self-contained cooling system, which consists of a
forced circulation cooling water loop, to cool the engine directly, rejecting
heat through an air cooled radiator. Refer to Figures 9.15-5 and 6 for an
operating diagram representative of these EDG 3A and 3B systems. The major
design features of each of these systems are:
- 1. Pumps - Each cooling loop contains two gear driven centrifugal pumps to circulate water through the closed loop.
- 2. Immersion Heaters - Each cooling loop contains an electrical immersion heater which circulates hot water, by convection, through the oil
cooler (described in Section 9.15.4) to provide standby heating of the
engine and lubricating oil when the EDG is not operating to reduce
diesel engine wear.
- 3. Expansion Tanks - Each cooling loop contains an expansion tank to allow for the expansion and contraction of the water in the cooling loop due
to changes in the water's temperature.
- 4. Cooling Fans - Each cooling loop contains two cooling fans, driven by belts from their associated EDG, which circulate air over the
radiators.
9.15-13 Rev. 11 11/93
- 5. Radiators - Each cooling loop contains an air cooled radiator.
When a diesel generator is not operating, the engine block and lubricating
oil are maintained in a warmed condition to provide for reliable starting and
reduced wear. This is accomplished by heating the cooling water with the
electrical immersion heater and the water circulating through the system due
to convection. A temperature regulator valve allows the water to bypass the
radiator when operating in this mode.
When the EDG is operating, the cooling water system removes heat from the
intake air in the turbocharger after cooler, engine water jackets, and the
lube oil system, and transfers the heat to the radiator where two fans remove
the heat by forced air to the atmosphere.
9.15.2.2.2 EDGs 4A AND 4B
Each EDG (4A and 4B) has a self-contained cooling system which consists of a
forced circulation cooling water loop, to cool the engine directly, rejecting
heat through an air cooled radiator. A representative diagram of diesel
generator cooling water system as associated with either EDG 4A or 4B is
presented by Figures 9.15-11 and 12. The major design features of each of
these systems are:
- 1. Pumps - Each cooling loop contains two centrifugal pumps, which are driven by a coupling to their associated EDGs, to circulate water
through the closed loop. These pumps meet Seismic Category I
requirements.
- 2. Immersion Heaters - Each cooling loop contains an electrical immersion heater which recirculates hot water, by convection, through the oil
cooler (described in Section 9.15.4) to provide standby heating when
the EDG is not operating. This heater is designated Class 1E and is
supplied power via Class 1E Motor Control Centers. This heater meets
Seismic Category I requirements.
- 3. Expansion Tanks - Each cooling loop contains an expansion tank with a 100 gallon capacity to allow for the expansion and contraction of the
9.15-14 Rev. 11 11/93 water in the cooling loop due to changes in the water's temperature.
This tank contains approximately 60 gallons of water, when the cooling system is in standby conditions, leaving room in the expansion tank for
the approximately 21 gallons of water expansion during system heatup to
operating conditions. The 60 gallons of water in the expansion tank
assures the cooling water pumps' net positive suction head, while
allowing for expected system leakage for seven days without water being
added to the system. This tank is located at the highest point of the
cooling system to allow for venting of the system. This tank also
provides the capability to add water to the cooling loop. These
expansion tanks are designed in accordance with the requirements of the
ASME Section VIII, Division 1, 1986 Edition and Addenda, and meet
Seismic Category I requirements.
- 4. Piping - Piping which performs a safety function external to the EDG skid is designed in accordance with the requirements of ASME Section
III for Class 3 components and meet Seismic Category I requirements.
Piping internal to the EDG skid is designed and analyzed to meet the
stresses specified by ANSI B31.1 and meets Seismic Category I
requirements. Cooling water piping has been designed for a maximum of
350 o F and 125 psig, which exceeds the system operating requirements.
- 5. Cooling Fans - Each cooling loop contains three electric, direct coupled, motor driven cooling fans which circulate air over the
radiators. Two fans provide sufficient air circulation with ambient
air conditions up to 90 o F for diesel engine loading up to 100% of rated continuous load or up to 98.5% loading with 95ºF ambient air condition.
These fans are designed to meet Seismic Category I requirements and
their motors are designated Class 1E and are provided power via Class
1E Motor Control Centers.
- 6. Radiators - Each cooling loop contains an air convection cooled radiator. These radiators are designed in accordance with the
requirements of the ASME Section VIII, Division 1 and meet the Seismic
Category I requirements.
When a diesel generator is not operating, the engine block and lubricating
oil are maintained in a warmed condition to provide for reliable starting and
reduced wear. This is accomplished by heating the cooling water with the
9.15-15 Rev. 16 10/99 electrical immersion heater and the water circulating through the system due to convection. A temperature regulator valve allows the water to bypass the
radiator when operating in this mode.
When a diesel generator is operating, cooled water is drawn through the lube
oil cooler by the two cooling water pumps. One pump supplies cooling water
to the right side inlet manifold, ten cylinders, and one side of the
discharge manifold and the other pump supplies cooling water to the other
side of the manifolds and to the other ten cylinders. A temperature
regulator valve then allows the water to pass through the radiator, to reject
the necessary heat, as required to maintain the correct temperature.
9.15.2.3 SAFETY EVALUATION
9.15.2.3.1 EDGs 3A AND 3B
Each EDG 3A and 3B has its own independent cooling water system. This
independence ensures that only one EDG will be affected by a single failure
in one of these cooling water systems. Refer to Appendix 5A concerning the
seismic design of structures, Appendix 5E concerning missile protection
criteria, Appendix 5F concerning internal flooding, and Appendix 5G
concerning external flooding for these systems.
9.15.2.3.2 EDGs 4A AND 4B
Each EDG 4A and 4B has its own independent cooling water system. This
independence ensures that only one EDG will be affected by a single failure
in one of these cooling water systems.
System components and piping have sufficient physical separation or shielding
to protect the system from externally generated missiles. In addition, since
each of these EDGs and their associated cooling water systems are independent
and physically separated from the other by a concrete wall, an internally
generated missile will not result in the failure of more than one EDG or its
associated cooling water system. Also, the systems are not affected by the
effects of high-energy and moderate-energy pipe breaks, since there is no
high-energy or moderate-energy piping in the Unit 4 EDG Building.
9.15-16 Rev. 16 10/99
These systems are located inside Seismic Category I structures (the design of these structures is discussed in Section 5.3.4) and, therefore, protected
from the effects of natural phenomena and external missiles. The radiators
are located in the outside wall of the Unit 4 EDG Building and are designed
to withstand the effects of the design basis tornado. The radiators are
protected from tornado generated missiles by a missile shield.
In the event of a cooling system piping connection failure, the resultant
loss of cooling system fluid would eventually force the affected EDG out of
service. However, the possibility for this event is very low for the
following reasons:
- 1. The cooling system operates at relatively low pressure and temperature (7 psig and 215ºF maximum) as compared with the design pressure and
temperature (125 psig and 350ºF) of the system.
- 2. The entire cooling system is analyzed for all normal and postulated loads including dead weight, thermal and seismic conditions, and is
designed accordingly.
- 3. The cooling system design is consistent with the manufacturer's standard practice which has historically proven to be very reliable
with respect to cooling system piping failures.
Although highly unlikely, should such a failure occur, available alarms and
indication would make plant operators aware of the possible degradation in
the cooling system's performance so that appropriate action could be taken.
In addition, during non-emergency use, automatic EDG shutdown would occur
when the cooling water temperatures reached 215 o F.
Any single failure in one of these cooling water systems is bounded by the
loss of an EDG. A failure modes and effects analysis associated with the
loss of an EDG has been performed and the results are discussed in Section
8.3.
9.15.2.4 TESTS AND INSPECTIONS
System components of the systems associated with EDGs 4A and 4B were
inspected and tested by the manufacturer. Following installation and prior
to declaring
9.15-17 Rev. 16 10/99 the systems operable these cooling water systems were inspected, tested, and operated. Testing was performed to verify system operability in accordance with plant Technical Specification requirements, manufacturer's recommendations, and applicable codes and standards. Additional information on the testing and inspection of the EDGs is described in Section 8.2.
9.15.2.5 INSTRUMENTATION APPLICATION 9.15.2.5.1 EDGs 3A AND 3B The necessary instrumentation and controls are provided with each of the cooling water systems associated with EDGs 3A and 3B to maintain the EDG engine jacket at the proper temperature in all modes of EDG operation. The following instrumentation and controls are available for the systems associated with EDGs 3A and 3B:
- 1. Abnormal cooling water temperature is monitored and alarmed at the local control panel and at a common EDG trouble alarm in the Main Control Room.
- 2. The EDG is interlocked to shutdown, during non-emergency operation, if the cooling water pressure or temperature goes beyond its shutdown limit. 9.15.2.5.2 EDGs 4A AND 4B The necessary instrumentation and controls are provided for each of the cooling water systems associated with EDGs 4A and 4B to maintain the EDG engine jacket at the proper temperature in all modes of EDG operation. The following instrumentation and controls are available for the systems associated with EDGs 4A and 4B:
- 1. Level switches for low expansion tank water level provide annunciation via an EDG trouble alarm locally and in the Main Control Room.
9.15-18 Rev. 10 7/92
- 2. Temperature switches for high-high and, high cooling water temperature provide annunciation via an EDG trouble alarm locally and in the Main Control Room.
- 3. Pressure switches for low-low and low cooling water pressure provide annunciation via an EDG trouble alarm locally and in the Main Control
Room.
- 4. The EDG is interlocked to shutdown, during non-emergency operation, on low-low cooling water pressure or high-high cooling water temperature.
- 5. Annunciation is provided via the EDG trouble alarm locally and in the Main Control Room for a cooling fan in a tripped or off condition.
- 6. Annunciation is provided via the EDG trouble alarm locally and in the Main Control Room for the immersion heater in a tripped or off
condition or not under automatic control.
- 7. Temperature switches for cooling water temperature provide automatic immersion heater control.
- 8. Temperature indicators provide local cooling water temperature indication.
9.15.3 EMERGENCY DIESEL GENERATOR AIR START SYSTEM
9.15.3.1 DESIGN BASES
Each EDG has its own associated air start system.
9.15.3.1.1 EDGs 3A AND 3B
The air start systems associated with EDGs 3A and 3B are designed to:
- 1. Store and provide sufficient starting air to ensure starting of its associated EDG.
9.15-19 Revised 5/02/05
- 2. Function with sufficient independence from other diesel generator air start systems to assure that no single failure can affect the provision of sufficient starting air to more than one EDG.
- 3. Perform its function under the same environmental conditions as the EDG which it serves.
- 4. Meet the requirements for Class I systems/components in accordance with Appendix 5A.
- 5. Withstand the maximum flood levels in accordance with Appendix 5G, wind loadings in accordance with Appendix 5A, and missiles in accordance with Appendix 5E without loss of function.
9.15.3.1.2 EDGs 4A AND 4B The air start systems associated with EDGs 4A and 4B are designed to:
- 1. Store and provide sufficient starting air to ensure starting of its associated EDG, assuming a single failure.
- 2. Function with sufficient independence from other diesel generator air start systems to assure that no single failure can affect the provision of sufficient starting air to more than one EDG.
- 3. Contain provisions for the periodic blowdown of accumulated moisture and foreign material in the air receiver(s).
- 4. Perform its function under the same environmental conditions as the EDG which it serves.
- 5. Meet Seismic Category I requirements.
- 6. Withstand the maximum flood levels and tornado winds and missiles without loss of function by locating critical components inside the Unit 4 EDG Building.
9.15-20 Rev. 10 7/92
- 7. Prevent the failure of nonseismic structures or components from affecting the safety related functions of the system.
9.15.3.2 SYSTEM DESCRIPTION
9.15.3.2.1 EDGs 3A AND 3B
Each EDG (3A and 3B) has an independent air start system capable of starting
its associated EDG. Refer to Figure 9.15-2 for diagrams of EDG 3A and 3B
starting air systems. The major design features of these systems are:
- 1. Air Motors - Four air motors, two independent 100% capacity sets consisting of an upper and lower air motor, are provided for cranking
each EDG.
- 2. Air Receivers - Each EDG's air start system contains two sets of two air receivers. Air receiver tanks A & B provide an air supply to one
set of air start motors and air receiver tanks C & D provide an air
supply to the second set of air start motors. The air receivers are
sized to ensure that the four air receivers have sufficient capacity, at the design pressure setpoint, for four unsuccessful (based on
nominal 2 second duration) attempts and one successful EDG starting
attempt without the need for recharging with air. In order to deliver
sufficient compressed air to both sets of air start motors for a
minimum of five starting attempts, all four air receiver tanks A, B, C
and D are valved-in to the air start system.
- 3. Electric Motor Driven Air Compressors - Each EDG's air start system contains an electric motor driven air compressor to provide charging
air to the air receivers. The discharge of the air compressors
associated with EDGs 3A and 3B may be cross connected to allow either
air compressor to supply either EDG's air receivers.
- 4. Air Quality Package Units - Each EDG's air start system contains an air quality package unit, which is located between the EDG air compressor
and air receiver tanks. The air quality unit consists of a membrane
air dryer downstream of the air compressor, an air-cooled aftercooler
upstream of the air dryer, a moisture separator and pre-filters between
the after cooler and air dryer
9.15-21 Revised 04/17/2013 C26 complete with associated piping, valves and instrumentation. The air quality package units have bypass capability which will not interrupt service of the starting air compressor to maintain the air storage
tanks at their design pressure.
When the air start system associated with EDGs 3A and 3B is in normal
standby, there is approximately 200 psig of air pressure in the piping up to
the air start solenoid valve. The electrical start signal will open the air
start solenoid valve and admit starting air to engage the pinions of the air
start motors. When both pinions are engaged, the control valve is then
actuated which admits the starting air to the air start motors. When the
starting air enters the air start motor assemblies, it first pressurizes the
pinion which engages the air start motor to the engine flywheel; then the air
turns the air start motor internals and the engine flywheel together.
9.15.3.2.2 EDGs 4A AND 4B
Each EDG (4A and 4B) has an independent air start system capable of starting
its associated EDG. Representative diagram of the EDG air start system as
associated with either EDG 4A or 4B is shown in Figures 9.15-7 and 9.15-8.
The major design features of these systems are:
- 1. Air Receivers - Each EDG's air start system contains two sets of two air receivers. The air receivers are sized to ensure that the system
has sufficient capacity, with a pressure of 185 psig in all four air
receivers and four air start motors available or 195 psig with only two
air receivers and two air start motors available, for four unsuccessful (up to five seconds each) attempts and one successful EDG starting
attempt without the need for recharging. These values are for the
receivers sizing criteria, and are not the minimum pressure required to
start the EDG. If either set of air receivers is out of service, the
other set of air receivers with either set of air start motors or both
sets of air start motors is capable of starting the associated EDG.
Redundant air start subsystems are not required for operability of the
EDG.
The air receivers are designed in accordance with the requirements of ASME Section III for Class 3 components and meet Seismic Category I
requirements. Each air receiver is protected from over pressure by
ASME Section III, Class 3 relief valves.
9.15-22 Revised 04/26/2010 C24C24
- 2. Electric Motor Driven Air Compressors - Each EDG's air start system contains an electric motor driven air compressor to provide charging air to the air receivers. Each air compressor is capable of recharging
a set of two air receivers in no more than 30 minutes following five
successive EDG starting attempts. A filter is provided at the
compressor suction to prevent dust and other foreign matter from
entering the system. While these compressors are provided power via
Class 1E Motor Control Centers, they perform no safety function, since
they are not required to function to start the EDG. The receivers
contain sufficient air reserves to successfully start the EDG.
- 3. Diesel Engine Driven Air Compressors - Each EDG's air start system contains a diesel engine driven air compressor to provide charging air
to the air receivers. This diesel engine driven air compressor
provides a backup to and can be isolated from each system's electric motor driven air compressor. Each air compressor is capable of recharging a
set of two air receivers in no more than 30 minutes following five
successive EDG starting attempts. A filter is provided at the
compressor suction to prevent dust and other foreign matter from
entering the system. These air compressors, like the motor driven air
compressors, perform no safety function.
- 4. Air Motors - Four air motors, two 100% sets consisting of an upper and lower air motor each, are provided for cranking each EDG. Each set of
two motors is supplied with starting air from a separate set of air
receivers. Cross connections in the piping allows either set of air
receivers to supply either set of air start motors. The air motors are
designed and analyzed to meet the stresses specified by ANSI B31.1.
For a normal EDG start all four air motors are used to roll over the engine. If two air start motors are inoperable, the other two have
sufficient torque to start the EDG in the required time interval.
9.15-23 Revised 9/11/2007 C23
- 5. Piping and Valves - Piping which performs a safety function and is external to the EDG skid is designed in accordance with the requirements of ASME Section III for Class 3 components and meet
Seismic Category I requirements. Piping internal to the EDG skid is
designed and analyzed to meet the stresses specified by ANSI B31.1.
Air start system piping has been designed for a maximum temperature of
350 o F and 300 psig, which meets or exceeds the system operating requirements.
- 6. Air Dryers - Each EDG's air start system contains a membrane type air dryer installed between the air compressors and the air receivers.
These air dryers ensure starting air is dried to a dew point of less
than 40 o F. The air dryer performs no safety function.
When the air start systems associated with EDGs 4A and 4B are in normal
standby, there is approximately 200 psig of air pressure in the piping up to
the two redundant air start solenoid valves. The electrical start signal
will open both of the air start solenoid valves and admit starting air to
engage the pinions of the air start motors. When both pinions are engaged, the control valve is then actuated which admits the starting air to the air
start motors. The starting air enters the air start motor assemblies, first
pressurizing the pinion and engaging the air start motor to the engine
flywheel; then the air turns the air start motor internals and the engine
flywheel together.
When the air pressure downstream of the air start motors builds to a preset
value due to the air start motors rotational velocity, a pneumatic pressure
sensing line sends air to the governor servo-booster pump and simultaneously
to the top side of the air start solenoid valve. This allows the governor to
obtain faster control of the EDG and shuts the air start solenoid valve when
the EDG has reached the necessary starting speed so the fuel racks can
maintain and accelerate the engine to the desired revolutions per minute (rpm).
9.15.3.3 SAFETY EVALUATION
9.15.3.3.1 EDGs 3A AND 3B
The air start systems for EDGs 3A and 3B are independent to ensure that a
single failure in one EDG's air start system will not result in the
9.15-24 Revised 04/17/2013 C26 unavailability of more than one EDG. Refer to Appendix 5A concerning the seismic design of structures, Appendix 5E concerning missile protection
criteria, Appendix 5F concerning internal flooding, and Appendix 5G
concerning external flooding for these systems.
9.15.3.3.2 EDGs 4A AND 4B
Each EDG 4A and 4B has its own independent air start system; therefore, a
failure in one EDG's air start system will not result in the unavailability
of more than one EDG. In addition, each EDG's air start system has
sufficient redundancy to ensure that sufficient starting air will be provided
to each EDG following a single failure in its associated air start system.
The systems are contained in structures designed to meet Seismic Category I
requirements (the design of these structures is discussed in Section 5.3.4)
and, therefore, system components and piping have sufficient physical
separation or barriers to protect the system from externally generated
missiles. In addition, since each EDG and its associated air start system is
independent and physically separated from the other via a concrete wall, an
internally generated missile will not result in the failure or more than one
air start system. Also, the systems are not affected by the effects of high-
energy and moderate-energy pipe breaks, since there is no high-energy or
moderate-energy piping in the Unit 4 EDG Building.
Functional capability of the air start systems are not adversely affected due
to a maximum probable flood because of their location in the Unit 4 EDG
Building.
Any single failure in the air start systems is bounded by the loss of an EDG.
A failure modes and effects analysis associated with the loss of an EDG has
been performed and the results are discussed in Section 8.3.
9.15.3.4 TESTS AND INSPECTIONS
System components associated with EDGs 4A and 4B were inspected and tested by
the manufacturer. Following installation and prior to declaring the systems
operable, the air start systems were inspected, tested, and operated.
9.15-25 Rev. 16 10/99 Testing was performed to verify system operability, as part of the testing of their respective EDGs, in accordance with plant Technical Specification
requirements, manufacturer's recommendations, and applicable codes and
standards. This testing included but was not limited to testing that each
air start system, consisting of four air receivers, at a minimum pressure of
185 psig and four air start motors (or two air receivers at a minimum
pressure of 195 psig and two air start motors), was capable of cranking its
associated EDG, at standby conditions, a minimum of five times (four
unsuccessful start-ing attempts followed by a successful start) without
recharging the air receivers. These values are for the receivers sizing
criteria, and are not the minimum pressure required to start the EDG. Since
redundant air start subsystems are not required for operability of the EDG, the minimum air receiver pressure value for operability with full
qualification is set to 185 psig corresponding to the minimum air pressure
required for four receivers and four air start motors. Additional
information on the testing and inspection of the EDGs is described in Section
8.2.
9.15.3.5 INSTRUMENTATION APPLICATION
9.15.3.5.1 EDGs 3A AND 3B
The following instrumentation and controls are available for the systems
associated with EDGs 3A and 3B:
- 1. Automatic and manual control of each EDG's air compressor.
- 2. Pressure switches provide input to the automatic control of the air compressors and alarms on low starting air pressure in the air
receivers both locally and at an EDG trouble alarm in the Main Control
Room.
9.15.3.5.2 EDGs 4A AND 4B
The following instrumentation and controls are available for the systems
associated with EDGs 4A and 4B:
- 1. Automatic controls are provided to start and stop the electric motor driven compressors and manual controls are provided for the diesel
driven compressors.
- 2. Pressure switches provide input to the automatic control of the air compressors and on low or high starting air pressure in the air
receivers provide annunciation via an EDG trouble alarm locally and in
the Main Control Room.
9.15-26 Revised 04/26/2010 C24
- 3. Moisture detection devices monitor the air receivers for moisture buildup (should moisture accumulate in the air receivers) and provide annunciation via an EDG trouble alarm locally and in the Main Control
Room.
- 4. Annunciation is provided via the EDG trouble alarm locally and in the Main Control Room for the air barring device in a engaged condition.
The air barring device is only engaged for EDG maintenance.
- 5. Annunciation is provided via the EDG trouble alarm locally and in the Main Control Room for the motor driven air compressors in a tripped or
off condition.
- 6. Local annunciation is provided if the start pinion of an air start motor failed to engage or recycle control during an EDG start attempt.
The air start system has no interlocks which will shutdown its associated
EDG.
9.15.4 EMERGENCY DIESEL GENERATOR LUBRICATION SYSTEM
9.15.4.1 DESIGN BASES
Each EDG has its own associated lubrication system.
9.15.4.1.1 EDGs 3A AND 3B
The systems associated with EDGs 3A and 3B are designed to:
- 1. Provide each EDG with a dedicated lubricating oil system which includes measures to provide lubrication to the diesel engine during standby
conditions and/or normal and emergency operations.
- 2. Function independently from other EDG lubrication systems to assure that no single failure can affect the operation of more than one EDG.
- 3. Automatically maintain the lubricating oil's temperature in a prewarmed condition to minimize diesel engine wear.
9.15-27 Rev. 10 7/92
- 4. Provide measures for cooling the system and removing the system heat load to permit proper EDG operation under all loading conditions.
- 5. Perform its function under the same environmental conditions as the EDG which it serves.
- 6. Meet the requirements for Class I systems/components in accordance with Appendix 5A.
- 7. Withstand the maximum flood levels in accordance with Appendix 5G, wind loadings in accordance with Appendix 5A, and missiles in accordance
with Appendix 5E without loss of function.
9.15.4.1.2 EDGs 4A AND 4B
The systems associated with EDGs 4A and 4B are designed to:
- 1. Provide each EDG with a dedicated lubricating oil system which includes measures to provide lubrication to the diesel engine wearing parts
during standby conditions and/or normal and emergency operations for
seven days without additional lubricating oil being added to the
system.
- 2. Function independently from other EDG lubrication systems to assure that no single failure can affect the operation of more than one EDG.
- 3. Automatically maintain the lubricating oil's temperature in a prewarmed condition to minimize diesel engine wear.
- 4. Provide measures for cooling the system and removing the system heat load to permit proper EDG operation under all loading conditions.
- 5. Perform its function under the same environmental conditions as the EDG which it serves.
- 6. Meet Seismic Category I requirements.
9.15-28 Rev. 10 7/92
- 7. Withstand the maximum flood levels and tornado winds and missiles without loss of function by locating critical components inside the Unit 4 EDG Building.
- 8. Prevent the failure of nonseismic structures or components from affecting the safety related functions of the system.
9.15.4.2 SYSTEM DESCRIPTION
9.15.4.2.1 EDGs 3A AND 3B
A combination of four subsystems provide lubrication for EDGs 3A and 3B.
These subsystems are the scavenging oil system, main lube oil system, piston
cooling oil system, and soak back oil system; refer to Figures 9.15-5 and
9.15-6. The major design features of these subsystems are described below:
- 1. Engine Driven Scavenging Pumps - Each EDG's lubrication system has an engine driven scavenging pump. This pump is part of the scavenging oil
system and forces the oil through the oil filter and lube oil cooler.
This pump is driven by the accessories gear train at the front of its
associated EDG.
- 2. Engine Driven Main Pressure Pumps - Each EDG's lubrication system has an engine driven main pressure pump. This pump is part of the main
lube oil system and supplies oil under pressure to most of the moving
parts of the engine. This pump is driven by the accessories gear train
at the front of its associated EDG. Although this pump is separate
from the engine driven piston cooling pump, it is located in the same
housing.
- 3. Engine Driven Piston Cooling Pumps - Each EDG's lubrication system has an engine driven piston cooling pump. This pump is part of the piston
cooling oil system and supplies oil to the two piston cooling oil
manifolds. This pump is driven by the accessories gear train at the
front of its associated EDG.
- 4. Soak Back Oil Pumps - Each EDG's lubrication system has a motor driven soak back oil pump. This pump is part of the soak back oil system and
9.15-29 Rev. 16 10/99 runs when the engine is shutdown. The pump is powered by a Class 1E Motor Control Center.
- 5. Backup Soak Back Pump - Each EDG's lubrication system has a backup soak back pump. This pump is part of the soak back oil system and is
redundant to the soak back pump. The pump motor is powered by a Class
1E Motor Control Center. A manual transfer switch allows power to be
transferred between the primary and backup soak back pumps such that
only one pump will be capable of operating at a time.
- 6. Lube Oil Coolers - Each EDG's lubrication system has a lube oil cooler. When the EDG is operating lube oil is circulated through this
cooler by the scavenging oil system and heat is removed from it by the
cooling water system. When the EDG is in a standby condition, lube oil
is circulated through lube oil cooler by the soak back oil system and
the oil is heated by the cooling water system's immersion heater and
natural circulation.
Scavenging Oil System
The scavenging oil system pump draws oil through the scavenging oil strainer
from the oil sump. The pump then forces the oil through the oil filter and
oil cooler. Oil then returns to the strainer housing to supply the main lube
oil pump and piston cooling oil pump with cooled filtered oil. Excess oil
spills over a dam in the strainer housing and returns to the oil sump.
Main Lube Oil System
The main lubrication system supplies oil, under pressure, to most of the
moving parts of the engine. The main lube oil pump takes oil from its
strainer in the strainer housing. The majority of the moving parts receive
their oil from this subsystem.
Piston Cooling Oil System
The piston cooling oil system receives oil from its strainer and delivers oil
to the two piston cooling oil manifolds extending the length of the engine, one on each side. A piston cooling oil pipe at each cylinder directs a
stream of oil to cool the underside of the piston crown and the ring belt.
Some of this oil enters the oil grooves in the piston pin bearing while the
remainder drains out through holes in the carrier skirt to the sump.
9.15-30 06/11/02 Soak Back Oil System The soak back system pump runs when the engine is shutdown to supply lube oil
to the turbocharger bearing for proper lubrication during emergency starts
and coasting down of the engine, and also to maintain flow through the main
lube oil filter and cooler to keep the engine warm during standby conditions.
The oil is warmed in the lube oil cooler due to the immersion heater
contained in the diesel generator cooling water system as described in
Section 9.15.2. The warmed oil is circulated though the engine to facilitate "cold" starts and reduce engine wear. To prevent possible overheating of the
turbocharger, oil is automatically supplied to the turbocharger after
stopping the engine. The system design ensures continuous oil flow through
each of the supply headers.
9.15.4.2.2 EDGs 4A AND 4B
A combination of four subsystems provide lubrication for EDGs 4A and 4B.
These subsystems are the scavenging oil system, main lube oil system, piston
cooling oil system, and soak back oil system. Representative diagrams of the
these subsystems associated with EDG 4A and 4B are shown in Figures 9.15-11
and 9.15-12. The major design features of these subsystems are described
below:
- 1. Engine Driven Scavenging Pumps - Each EDG's lubrication system has an engine driven scavenging pump. This pump is part of the scavenging oil
system and forces the oil through the oil filter and lube oil cooler.
This pump is driven by the accessories gear train at the front of its
associated EDG. The pump meets Seismic Category I requirements.
- 2. Engine Driven Main Pressure Pumps - Each EDG's lubrication system has an engine driven main pressure pump. This pump is part of the main
lube oil system and supplies oil under pressure to most of the moving
parts of the engine. Although this pump is separate from the engine
driven piston cooling pump, it is located in the same housing. This
pump is driven by the accessories gear train at the front of its
associated EDG. The pump meets Seismic Category I requirements.
- 3. Engine Driven Piston Cooling Pumps - Each EDG's lubrication system has an engine driven piston cooling pump. This pump is part of the piston
cooling oil system and supplies oil to the two piston cooling oil
9.15-31 Rev. 16 10/99 manifolds. This pump is driven by the accessories gear train at the front of its associated EDG. The pump meets Seismic Category I requirements.
- 4. Turbo Oil AC Pumps - Each EDG's lubrication system has a turbo oil AC pump. This pump is part of the soak back oil system and supplies lube
oil to the turbocharger bearing for proper lubrication during EDG
emergency start and coast down. The pump motor is designated Class 1E
and is powered by a Class 1E Motor Control Center. The pump meets
Seismic Category I requirements.
- 5. Backup Turbo Oil DC Pumps - Each EDG's lubrication system has a backup turbo oil DC pump. This pump is part of the soak back oil system and
is redundant to the turbo oil AC pump. The pump motor is designated
Class 1E and is powered by a Class 1E DC bus. The pump meets Seismic
Category I requirements.
- 6. Circulating Oil AC Pumps - Each EDG's lubrication system has a circulating oil AC pump. This pump is part of the soak back oil system
and maintains flow through the main lube oil filter and cooler to keep
the engine warm during standby conditions. The pump motor is
designated Class 1E and is powered by a Class 1E Motor Control Center.
The pump meets Seismic Category I requirements.
- 7. Backup Circulating Oil DC Pumps - Each EDG's lubrication system has a backup circulating oil DC pump. This pump is part of the soak back oil
system and is redundant to the circulating oil AC pump. The pump motor
is designated Class 1E and is powered by a Class 1E DC bus. The pump
meets Seismic Category I requirements.
- 8. Piping - Piping is designed and analyzed to meet the stresses specified by ANSI B31.1 and meets Seismic Category I requirements.
- 9. Lube Oil Coolers - Each EDG's lubrication system has a lube oil cooler. When the EDG is operating, lube oil is circulated through this
cooler by the scavenging oil system and heat is removed from it by the
cooling water system. When the EDG is in a standby condition, lube oil
9.15-32 Rev. 10 7/92 is circulated through the lube oil cooler by the soak back oil system and the oil is heated by the cooling water system's immersion heater and natural circulation. The lube oil cooler is designed and analyzed
to meet the stresses specified by ANSI B31.1 and meets Seismic Category
I requirements.
This lube oil sump contains sufficient inventory to assure the lube oil
system's pumps have net positive suction head while allowing for
expected system leakage for seven days without lube oil being added to
the system. The lube oil sump meets Seismic Category I requirements.
Scavenging Oil System
The scavenging oil system pump draws oil through the scavenging oil strainer
from the oil sump. The pump then forces the oil through the engine oil
filter and oil cooler. Oil then returns to the strainer housing to supply
the main lube oil pump and piston cooling oil pump with cooled filtered oil.
Excess oil spills over a dam in the strainer housing and returns to the oil
sump.
Main Lube Oil System
The main lubrication system supplies oil, under pressure, to most of the
moving parts of the engine. The main lube oil pump draws oil through the
engine oil strainer from the lube oil sump. Oil from the pump goes into the
main oil manifold which is located above the crankshaft, and extends the
length of the engine. The majority of the moving parts receive their oil
from passages directly off the manifold.
Piston Cooling Oil System
The piston cooling oil system receives oil from the lube oil sump through the
engine oil strainer and delivers the oil to the two piston cooling oil
manifolds extending the length of the engine, one on each side. A piston
cooling oil pipe at each cylinder directs a stream of oil to cool the
underside of the piston crown and the ring belt. Some of this oil enters the
oil grooves in the piston pin bearing while the remainder drains out through
holes in the carrier skirt to the sump.
9.15-33 Rev. 10 7/92 Soak Back Oil System The soak back system's pumps run continuously to supply lube oil to the
turbocharger bearing for proper lubrication during emergency starts and
coasting down of the engine, and also to maintain flow through the main lube
oil filter and lube oil cooler to keep the engine warm during standby
conditions. The oil is warmed in the lube oil cooler by the immersion heater
contained in the diesel generator cooling water system as described in
Section 9.15.2. The warmed oil is circulated though the engine to facilitate "cold" starts and reduce engine wear. To prevent possible overheating of the
turbocharger, oil is automatically supplied to the turbocharger after
stopping the engine. The system design ensures continuous oil flow through
each of the supply headers.
9.15.4.3 SAFETY EVALUATION
9.15.4.3.1 EDGs 3A AND 3B
Each EDG 3A and 3B has its own independent lubrication system. This
independence ensures that only one EDG will be effected by a single failure
in one of these lubrication systems. Refer to Appendix 5A concerning the
seismic design of structures, Appendix 5E concerning missile protection
criteria, Appendix 5F concerning internal flooding, and Appendix 5G
concerning external flooding for these systems.
9.15.4.3.2 EDGs 4A AND 4B
Each EDG 4A and 4B has its own independent lubrication system, therefore, a
failure in one EDG's lubrication system will not result in the unavailability
of more than one EDG.
The systems are contained in structures designed to meet Seismic Category I
requirements (the design of these structures is discussed in Section 5.3.4)
and, therefore, system components and piping have sufficient physical
separation or barriers to protect the system from externally generated
missiles. In addition, since each EDG and its associated lubrication system
is independent and physically separated from the other via a concrete wall, an
9.15-34 Rev. 10 7/92 internally generated missile will not result in the failure of more than one lubrication system. Also, the systems are not affected by the effects of
high-energy and moderate-energy pipe breaks, since there is no high-energy or
moderate-energy piping located in the Unit 4 EDG Building.
Functional capability of the lubrication systems are not adversely affected
due to a maximum probable flood because of their location in the Unit 4 EDG
Building.
Any single failure in the lubrication systems is bounded by the loss of an
EDG. A failure modes and effects analysis associated with the loss of an EDG
has been performed and the results are discussed in Section 8.3.
9.15.4.4 TESTS AND INSPECTIONS
System components associated with EDGs 4A and 4B were inspected and tested by
the manufacturer. Following installation and prior to declaring the
subsystems operable these diesel generator lubrication oil subsystems were
inspected, tested, and operated. Testing was performed to verify system
operability, as part of the testing of their respective EDG, in accordance
with plant Technical Specification requirements, manufacturer's
recommendations, and applicable codes and standards. Additional information
on the testing and inspection of the EDGs is described in Section 8.2.
9.15.4.5 INSTRUMENTATION APPLICATION
9.15.4.5.1 EDGs 3A AND 3B
The following instrumentation and controls are available for the systems
associated with EDGs 3A and 3B:
- 1. Main oil system pressure switches provide an alarm on low pressure and an engine trip on low-low pressure.
- 2. Scavenging oil system temperature switch provide an alarm in the Main Control Room on low temperature.
9.15-35 Rev. 16 10/99
- 3. Soak back oil system pressure switch extinguish the EDG ready to start lamp in the Main Control Room on low pressure.
9.15.4.5.2 EDGs 4A AND 4B
The following instrumentation and controls are available for the systems
associated with EDGs 4A and 4B:
- 1. Temperature indicators are provided for the lube oil temperature at the engine inlet and outlet.
- 2. Temperature switches for low, high-high and high lube oil temperature provide annunciation via an EDG trouble alarm locally and in the Main Control Room. Temperature switches for high-high temperature provide an EDG shutdown function during non-emergency operation.
- 3. Pressure switches for main manifold lube oil low pressure, piston cooling oil low pressure and crankcase high pressure provide
annunciation via an EDG trouble alarm locally and in the Main Control
Room and provide an EDG shutdown function during nonemergency
operation.
- 4. Pressure switches for lube oil low pressure and level switches for lube oil sump low level provide annunciation via an EDG trouble alarm
locally and in the Main Control Room.
- 5. Differential pressure switches for high differential pressure across the lube oil strainer and filter, and the lube oil cooler provide
annunciation via an EDG trouble alarm locally and in the Main Control
Room.
- 6. Pressure switches are provided for control of the backup circulating and turbo oil DC pumps.
- 7. Annunciation is provided via an EDG trouble alarm locally and in the Main Control Room for the backup circulating oil DC pumps or the backup
turbo oil DC pumps in a no power or overload condition or running.
9.15-36 Revised 5/02/05
- 8. Annunciation is provided via an EDG trouble alarm locally and in the Main Control Room for the backup turbo oil DC pump not in the automatic control.
- 9. The Lube Oil Metal Detector and associated alarms have been abandoned in place by EC 242379 (PC/M 08-011).
9.15.5 EMERGENCY DIESEL GENERATOR COMBUSTION AIR INTAKE/EXHAUST SYSTEM
9.15.5.1 DESIGN BASES
Each EDG has its own associated combustion air intake/exhaust system.
9.15.5.1.1 EDGs 3A AND 3B
The systems associated with EDGs 3A and 3B are designed to:
- 1. Provide combustion air to its associated EDG and exhaust the combustion products to the atmosphere.
- 2. Function independently from other EDG combustion air intake/exhaust systems to assure that no single failure can affect the operation of
more than one EDG.
- 3. Preclude degradation of the EDG's power output due to exhaust gases and other contaminants entering the air intake. The systems are physically
arranged, such that, no degradation of engine function is experienced
when an EDG is required to operate continuously at the maximum power
output.
- 4. Perform its function under the same environmental conditions as the EDG which it serves.
- 5. Meet the requirements for Class I systems/components in accordance with Appendix 5A.
9.15-37 Revised 04/17/2013 C26
- 6. Withstand the maximum flood levels in accordance with Appendix 5G, winds in accordance with Appendix 5A.
9.15.5.1.2 EDGs 4A AND 4B
The systems associated with EDGs 4A and 4B are designed to:
- 1. Provide combustion air to its associated EDG and exhaust the combustion products to the atmosphere.
- 2. Function independently from other EDG combustion air intake/exhaust systems to assure that no single failure can affect the operation of
more than one EDG.
- 3. Preclude degradation of the EDG's power output due to exhaust gases and other contaminants entering the air intake. The systems are physically
arranged, such that, no degradation of engine function is experienced
when an EDG is required to operate continuously at the maximum power
output.
- 4. Perform its function under the same environmental conditions as the EDG which it serves.
- 5. Meet Seismic Category I requirements.
- 6. Withstand the maximum flood levels and tornado winds and missiles without loss of function by locating critical components inside the
Unit 4 EDG Building or by protecting them by elevation and missile
barriers.
- 7. Prevent the failure of nonseismic structures or components from affecting the safety related functions of the system.
9.15-38 Rev. 10 7/92 9.15.5.2 SYSTEM DESCRIPTION
9.15.5.2.1 EDGs 3A AND 3B
Each EDG (3A and 3B) has an independent combustion air intake and exhaust
system. The major design features of these systems are:
- 1. Air Intake - The air intake for each EDG consists of a short section of duct work and a filter assembly and is located inside the Unit 3 EDG
Building. The air intake is provided with multiple turns to prevent
air entrained water from entering the building.
- 2. Silencers - Each EDG has its own silencer.
- 3. Exhaust Piping - The exhaust piping is designed to be suitable for the combustion gases handled.
9.15.5.2.2 EDGs 4A AND 4B
Each EDG (4A and 4B) has an independent combustion air intake and exhaust
system. Representative diagrams of the EDG combustion air intake and exhaust
system as associated with the EDG 4A and 4B are shown in Figure 9.15-7 and
9.15-8, respectively. The major design features of these systems are:
- 1. Air Intake - The air intake for each EDG is located inside the Unit 4 EDG Building. The air flow path from the building air intake is
provided with multiple turns to prevent air entrained water from
entering the EDG's air intake. The Unit 4 EDG Building is provided
with a large weather protected air intake which is located
approximately 32 feet above grade. This intake is designed in
accordance with AISC Manual of Steel Construction, 8th edition. The
building air intake is located on the opposite side of the building
from the EDG exhaust which virtually precludes the possibility of
combustion products being introduced into the building or the EDG air
intake.
- 2. Silencers - Each EDG has its own silencer. The silencer has a maximum pressure drop of one inch of water across it. The silencers are
9.15-39 Rev. 16 10/99 designed and analyzed to meet the stresses specified by ANSI B31.1 and to meet Seismic Category I requirements.
- 3. Exhaust Piping - The exhaust piping is designed and analyzed to meet the stresses specified by ANSI B31.1 and meets Seismic Category I
requirements. The piping is made of carbon steel and designed for
temperatures up to 800 o F and is suitable for the combustion gases handled.
9.15.5.3 SAFETY EVALUATION
9.15.5.3.1 EDGs 3A AND 3B
Each EDG 3A and 3B has its own independent combustion air intake/exhaust
system. This independence ensures that only one EDG will be effected by a
single failure in one of these systems. Refer to Appendix 5A for information
on the seismic design of structures, Appendix 5E concerning missile
protection criteria, Appendix 5F concerning internal flooding, and Appendix
5G concerning external flooding for these systems.
9.15.5.3.2 EDGs 4A and 4B
Each EDG 4A and 4B has its own independent combustion air intake/exhaust
system, therefore, a single failure in one EDG's combustion air
intake/exhaust system will not result in the unavailability of more than one
EDG.
The exhaust system for the diesel engine is indoors, except for the discharge
which is through an exterior wall and protected by a tornado missile shield.
Except for the exhaust discharge, as previously discussed, these systems are
located inside a Seismic Category I structure (the design of this structure
is discussed in Section 5.3.4). Since the air intake is above maximum water
level, these systems are protected from the effects of natural phenomena and
external missiles.
In addition, since each of these EDGs and their associated combustion air
intake/exhaust systems are independent and physically separated from the
other by a concrete wall, an internally generated missile will not result in
the
9.15-40 Rev. 10 7/92 failure of more than one EDG. Also, the systems are protected from the effects of high-energy and moderate-energy pipe breaks, since there is no
high-energy or moderate-energy piping located in the Unit 4 EDG Building.
Due to the location of the air intakes and the exhausts, as described in
9.15.5.2.2 above, there will be no significant contamination of the intake
air by exhaust gases.
The building's air intake is located approximately 32 feet above ground level
and the air intake path contains several turns resulting in a minimum amount
of dust or other deleterious material being introduced into the diesel engine
rooms. Although this air is reasonably clean, there will be some dust, etc.
entrained in it, and therefore, all switches in the diesel engine rooms have
been enclosed to protect them from dust and moisture, and the diesel engines'
air intakes utilize a filter to minimize the introduction of these
contaminants into the diesel engines. The greater quantity of switches, relays and other electrical contacts are located in the local EDG control
rooms directly above the EDGs. These rooms are separate from the engine
rooms and are climate controlled, i.e., air entering these rooms is filtered
and cooled via air conditioning units. Not only does this arrangement
prevent dust and other deleterious material from fouling the electrical
equipment, it prevents excess moisture from accumulating in the room that
could cause rusting or corroding of electrical contacts or the drifting of
setpoints of instruments and meters due to temperature variations. The
concrete walls and floors in the Unit 4 EDG building are sealed and/or
painted to preclude dust from being generated internally.
Any single failure in the diesel generator combustion air intake/exhaust
systems is bounded by the loss of an EDG. A failure modes and effects
analysis associated with the loss of an EDG has been performed and the
results are discussed in Section 8.3.
9.15.5.4 TESTS AND INSPECTIONS
System components associated with EDGs 4A and 4B were inspected and tested by
the manufacturer. Following installation and prior to declaring the systems
operable these diesel generator combustion air intake/exhaust systems were
9.15-41 Rev. 10 7/92 inspected, tested, and operated. Testing was performed to verify system operability in accordance with plant Technical Specification requirements, manufacturer's recommendations, and applicable codes and standards.
9.15.5.5 INSTRUMENTATION APPLICATION
9.15.5.5.1 EDGs 3A AND 3B
The diesel generator combustion air exhaust temperature for EDGs 3A and 3B is
indicated at the local control panels.
9.15.5.5.2 EDGs 4A AND 4B
The following instrumentation and controls are available, at the local
control panels, for the systems associated with EDGs 4A and 4B:
- 1. Temperature switches provide high-high and high exhaust temperature, combustion air high temperature, and turbocharger high differential
temperature annunciation via an EDG trouble alarm locally and in the
Main Control Room. Temperature switches also provide an EDG shutdown
function, during nonemergency operation, on high-high exhaust
temperature.
- 2. Pressure switches provide high exhaust pressure and combustion air low pressure annunciation via an EDG trouble alarm locally and in the Main
Control Room.
- 3. Indicators provide air box pressure, exhaust pressure, and engine exhaust temperature for each cylinder.
9.15-42 Rev. 10 7/92
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-1 REFER TO ENGINEERING DRAWING 5613-M-3022 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 3A AIR STARTING SYSTEM FIGURE 9.15-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-2 REFER TO ENGINEERING DRAWING 5613-M-3022 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 3B AIR STARTING SYSTEM FIGURE 9.15-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-3 REFER TO ENGINEERING DRAWING 5613-M-3022 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 3A FUEL OIL FIGURE 9.15-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-4 REFER TO ENGINEERING DRAWING 5613-M-3022 , SHEET 4
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 3B FUEL OIL FIGURE 9.15-4
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-5 REFER TO ENGINEERING DRAWING 5613-M-3022 , SHEET 5
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 3A LO & COOLING WATER FIGURE 9.15-5
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-6 REFER TO ENGINEERING DRAWING 5613-M-3022 , SHEET 6
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 3B LO & COOLING WATER FIGURE 9.15-6
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-7 REFER TO ENGINEERING DRAWING 5614-M-3022 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 EMERGENCY DIESEL ENGINE AND OIL SYSTEM EDG 4A AIR STARTING SYSTEM FIGURE 9.15-7
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-8 REFER TO ENGINEERING DRAWING 5614-M-3022 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 EMERGENCY DIESEL ENGINE AND OIL SYSTEM EDG 4B AIR STARTING SYSTEM FIGURE 9.15-8
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-9 REFER TO ENGINEERING DRAWING 5614-M-3022 , SHEET 3
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 EMERGENCY DIESEL ENGINE AND OIL SYSTEM EDG 4A FUEL SYSTEM FIGURE 9.15-9
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-10 REFER TO ENGINEERING DRAWING 5614-M-3022 , SHEET 4
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 EMERGENCY DIESEL ENGINE AND OIL SYSTEM EDG 4B FUEL SYSTEM FIGURE 9.15-10
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-11 REFER TO ENGINEERING DRAWING 5614-M-3022 , SHEET 5
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 4A LO & COOLING WATER FIGURE 9.15-11
FINAL SAFETY ANALYSIS REPORT FIGURE 9.15-12 REFER TO ENGINEERING DRAWING 5614-M-3022 , SHEET 6
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 EMERGENCY DIESEL ENGINE AND OIL SYSTEM DG 4B LO & COOLING WATER FIGURE 9.15-12
9.16 LOAD CENTER AND SWITCHGEAR ROOMS AIR CONDITIONING SYSTEM
9.16.1 DESIGN BASIS
The Load Center and Switchgear Rooms Air Conditioning System is designed to
accomplish the following:
- 1. Remove the heat dissipated by all equipment in the Load Center and Switchgear Rooms during normal plant operation and emergency
conditions, maintaining room temperatures below 95 o F with an outdoor air temperature of 95 o F. However, the design limit for the equipment in the Load Center Room is 104 o F, while the design limit for the equipment in Switchgear Room is 104 o F. It should be noted, that if in single train operation during emergency operations (i.e. one chiller
unit during LOOP/SI), operator action may be required to prevent
exceeding the Load Center and Switchgear Rooms equipment design
temperatures within 7 days.
- 2. Provide a redundant, reliable, and independent system supplied from emergency power to maintain a temperature controlled environment for
the safety related equipment located within the Load Center and
Switchgear Rooms.
The air conditioning system itself does not perform a safety related
function.
9.16.2 SYSTEM DESIGN AND OPERATION
The operating diagrams for the Load Center and Switchgear Rooms Air
Conditioning System are shown schematically in Figure 9.16-1 through 9.16-4.
The Load Center and Switchgear Rooms Air Conditioning System consists of two
redundant trains. Each train is provided with two 50 percent capacity
chillers, two chilled water pumps, one air separator, one expansion tank, piping, instrumentation, and four l00 percent capacity air handling units (one each for the Load Center and Switchgear Rooms). Each train is capable
of providing l00 percent cooling for the rooms during normal and emergency
conditions. Each of the rooms is served by both trains. A total of 200
percent cooling can be provided for each room during normal and emergency (i.e., loss of offsite power) conditions with both trains operating.
9.16-1 Revised 08/20/2012 C26 During normal plant operation, two chillers are required to provide l00 percent cooling for all the rooms. The chillers of the same or opposite
trains can be used to satisfy the normal demand. However, only one chiller
of either train is required during emergency conditions since the heat loads
are substantially reduced. This arrangement permits removal of a chiller unit
or train from service for maintenance while providing the required cooling
for the rooms. It should be noted, that if in single train operation during
emergency operations (i.e. one chiller unit during LOOP/SI), operator action
may be required to prevent exceeding the Load Center and Switchgear Rooms
equipment design temperatures within 7 days.
There are three modes of operation for each chiller that correspond to its
associated chilled water pump control switch positions: STANDBY, AUTO, and
ON. Following a loss of offsite power (LOOP) with the chiller control switch
in the 0N position, the chiller will automatically load onto its respective
emergency diesel generator (EDG) in approximately five minutes. As a result, both chillers of each train will be loaded on their EDG if each is selected
in the ON mode of operation. Administrative controls will be imposed to
limit the operation of the chillers of the same train in the ON mode/control
switch position. This mode will be limited to maintenance activities at
which time continuous surveillance will be required. Therefore, manual
actions may be taken to change the chiller control switch position necessary
to limit EDG loading.
When the chillers are in either the AUTO or STANDBY mode of operation, only
the lead chiller for each train will be loaded automatically on the EDGs
approximately five minutes following a LOOP. The lead chiller is determined from the position of the Chilled Water Pump Selector Switch. Whichever
Chilled Water Pump is selected (1 or 2,) that chiller is the lead, the other
is the lag. The Air Handler Units will load automatically on the EDGs in
response to room temperature regardless of the chiller mode of operation.
The Load Center and Switchgear Rooms Air Conditioning System is designed to
maintain a room temperature during normal and emergency plant conditions of
95 o F or lower with an outdoor air temperature of 95 o F. The system is designed to automatically control room temperature below the design limits.
9.16-2 1/8/04 9.16.3 SAFETY ANALYSIS
The Load Center and Switchgear Rooms Air Conditioning System is designed with
sufficient redundancy such that any component failure, up to malfunction of a
complete cooling train, will not prevent the system from performing its
cooling function. It should be noted, that if in single train operation
during emergency operations (i.e. one chiller unit during LOOP/SI), operator
action may be required to prevent exceeding the Load Center and Switchgear
Rooms equipment design temperatures within 7 days. The system is seismically
designed and backed by emergency power so that neither loss of offsite power
nor earthquake will cause loss of cooling function capability.
Exposures to other credible hazards have also been accommodated to ensure
that the required Load Center and Switchgear Room cooling is provided. The
hazards include fire, high winds, missiles, high energy pipe breaks (Unit 4
only) and heavy load drops. The risk from these hazards is considered to be
sufficiently low such that the effects would not compromise the system
cooling function capability. Nevertheless, additional cooling function
reliability and independence is provided by wall-mounted fans located in the
west wall of the building. In the extremely unlikely event that the entire
air conditioning system is rendered non-functional, an operator could open
the doors and start the fan locally to provide once-through ventilation. The
once-through ventilation concept is consistent with the original plant
design.
Based on the preceding, the adverse effects of any credible event or system
failure will not compromise the ability to provide cooling to the Load Center
and Switchgear Rooms.
9.16-3 Rev. 11 11/93
FINAL SAFETY ANALYSIS REPORT FIGURE 9.16-1 REFER TO ENGINEERING DRAWING 5613-M-3070 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 TURBINE BUILDING VENTILATION LOAD CENTER & SWGR ROOMS CHILLED WATER SYSTEM-TRAIN A FIGURE 9.16-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.16-2 REFER TO ENGINEERING DRAWING 5613-M-3070 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 TURBINE BUILDING VENTILATION LOAD CENTER & SWGR ROOMS CHILLED WATER SYSTEM-TRAIN B FIGURE 9.16-2
FINAL SAFETY ANALYSIS REPORT FIGURE 9.16-3 REFER TO ENGINEERING DRAWING 5614-M-3070 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 TURBINE BUILDING VENTILATION LOAD CENTER & SWGR ROOMS CHILLED WATER SYSTEM-TRAIN A FIGURE 9.16-3
FINAL SAFETY ANALYSIS REPORT FIGURE 9.16-4 REFER TO ENGINEERING DRAWING 5614-M-3070 , SHEET 2
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 TURBINE BUILDING VENTILATION LOAD CENTER & SWGR ROOMS CHILLED WATER SYSTEM-TRAIN B FIGURE 9.16-4
9.17 INSTRUMENT AIR SYSTEM 9.17.1 DESIGN BASIS
The Instrument Air System is designed to accomplish the following:
- 1. Provide motive power and control air to air operated components such that they operate in a predictable manner and perform their functions reliably.
- 2. Provide instrument air to achieve and maintain cold shutdown (Mode 5) during fires that require Control Room evacuation, with or without concurrent loss of offsite power.
- 3. Provide instrument air to achieve and maintain hot standby (Mode 3) during fires not requiring Control Room evacuation, with or without concurrent loss of offsite power.
9.17.2 SYSTEM DESIGN AND OPERATION
A system diagram for the Instrument Air System (IAS) is shown schematically in Figures 9.17-1 and 9.17-2.
The IAS consists of air compressors, receiver tanks, aftercoolers, moisture separators, desiccant dryers, particulate filters, instrumentation and interconnecting piping and valves. The system is designed to provide a continuous reliable air source during normal plant operation.
Each Unit has its own air supply system which is cross connected through 4" cross-tie piping. Two compressors are provided for each Unit - one diesel driven compressor and one motor driven compressor - with the rest of the air supply system comprising a receiver tank, moisture separator, desiccant dryer and particulate filters. The system also contains a "swing" dryer that can be aligned to either unit's air system. An instrument air header downstream of each unit's air supply equipment provides air to the various end users such as air operated valves. A backup air source from the service air system is also provided. This source of air is normally isolated and requires manual line-up when needed.
9.17-1 Revised 12/07/2015 C28 Each compressor is sized for sufficient capacity to provide instrument air for both Unit 3 and Unit 4 combined. The compressors have a capacity that is
greater than 750 SCFM. The system uses the motor driven compressor for its
normal source of compressed air with the two compressors operating LEAD/LAG
such that upon loss of pressure in one Unit, the opposite Unit's motor driven
compressor will load and provide compressed air as required. Control of the
load and unload feature of the motor driven compressors is from on-skid
pressure transducers.
The diesel driven compressors are capable of supplying the required capacity
without reliance on external power sources. Each diesel driven compressor
will automatically start on when the on-skid pressure transducer senses low-
low system pressure, a low voltage on the power busses to the motor driven
compressors, or from a manual start switch at the compressor panel. During
fires coincident with a loss of offsite power, instrument air availability
is assured because the diesel driven compressors are located in separate fire
zones. In the event that one of the diesel compressors is damaged by fire, the opposite Unit's compressor can supply both Units through the crosstie
piping.
The quality of the air provided by the IAS is important to proper functioning
of the end-use components. The primary method of removing particulates and
debris from the air stream is by filters installed at each end-use component.
In addition to this, particulate filters in the dryer outlet stream remove
particulates before the air gets into the IAS piping. This reduces the load
on local filters at the end-use devices and decreases their maintenance
requirements.
The method used to reduce moisture is by centrifugal moisture separators at the compressor after coolers and at the air receiver as well as desiccant dryers at the outlet of the air receiver. The desiccant dryers are capable of lowering the dewpoint of the instrument air to -40 F which satisfies the ISA standard of 18 F below minimum ambient temperature (Reference 1). The dryers require electrical power to regenerate the desiccant. Power to the Unit 3 and 4 dryers is supplied from the 'A' channel vital AC power busses from the associated unit which gives the dryer heaters a second source of power in case of a loss of offsite power. The swing dryer is powered from a nonvital source. In addition, should power not be available to the dryers, crosstie connections from the opposite Unit's instrument air supply is available.
9.17-2 Revised 04/17/2013 C26C26C26C26 9.17.3 SAFETY ANALYSIS
The IAS does not perform a safety related function, however it does provide air to safety related components. Equipment which uses instrument air and which are necessary for the plant to mitigate the consequences of an accident or to achieve and maintain safe shutdown, are designed to either fail in the required safe position or are provided with safety related backup air or nitrogen sources or have other means to accomplish their safety functions.
The IAS is designed to provide a continuous and reliable source of instrument air. The design incorporates sufficient redundancy such that any active component failure will not prevent the system from performing its function.
Both the motor-driven and diesel driven compressors are independent from their opposite unit counterpart. To achieve a continuous reliable source of instrument air, a single compressor is sized for the expected instrument air demand of both units. Because the IAS is operated cross-connected between units, the two systems will function as a single system. Normally a single motor driven compressor will supply all the instrument air required. In the event the system pressure decreases to the LAG compressor's setpoint, the second (LAG) motor driven compressor in the other unit will load and supplement the air supply. Further reduction of system pressure or a loss of power to the motor driven compressors will automatically start the first (Standby-Lead) diesel driven compressor. If further reduction of system pressure occurs the second (Standby-Lag) diesel driven compressor will start, providing a third and fourth level of reliability. An additional level of redundancy is provided by a backup air supply from the service air system.
9.
17.4 REFERENCES
- 1. Instrument Society of America Standard ISA S7.3, "Quality Standard for Instrument Air," November 16, 1981.
9.17-3 Revised 12/07/2016 C28
FINAL SAFETY ANALYSIS REPORT FIGURE 9.17-1 REFER TO ENGINEERING DRAWING 5613-M-3013 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 3 INSTRUMENT AIR SYSTEM FIGURE 9.17-1
FINAL SAFETY ANALYSIS REPORT FIGURE 9.17-2 REFER TO ENGINEERING DRAWING 5614-M-3013 , SHEET 1
REV. 13 (10/96)
FLORIDA POWER & LIGHT COMPANY TURKEY POINT PLANT UNIT 4 INSTRUMENT AIR SYSTEM FIGURE 9.17-2
9.18 TECHNICAL SUPPORT CENTER An on-site Technical Support Center (TSC) serves as a work area for use by technical and management personnel in order to provide support to Control Room personnel during an emergency. The TSC is outside of the Control Room Envelope and located in a building that is seprate from the Control Building at the back of the site property near the Circulating Water Inlet Bay. Like the Control Room, the TSC is equipped with a dedicated ventilation system that provides for a controlled environment for the comfort and safety of the TSC occupants and the protection against excessive radiological exposure during a design basis accident. The TSC ventilation system emergency mode is actuated by the same signals that initiate the Control Room Emergency Ventilation System. The TSC and its ventilation system maintain occupants' expose below 10 CRF 50 Appendix A GDC-19, i.e., 5 rem Total Effective Dose Equivalent (TEDE) limits.
9.18-1 Revised 04/17/2013 C26