L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 15, Accident Analysis

St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 15, Accident Analysis

ML17171A258
Person / Time
Site:	Saint Lucie
Issue date:	05/03/2017
From:	Florida Power & Light Co
To:	Office of Nuclear Reactor Regulation
Shared Package
ML17172A000	List: L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 10, Steam and Power Conversion System L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 11, Radioactive Waste Management System L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 12, Radiation Protection L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 2, Site Characteristics L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 6, Engineered Safety Features L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 8, Electric Power L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 1, Introduction and General Description of Plant Site Characteristics L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 13, Conduct of Operations L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 14, Initial Test Program L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 15, Accident Analysis L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 16, Technical Specifications L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 17, Quality Assurance L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 18, Aging Management Programs and Time-Limited Aging Analyses Activities L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 2, Site Characteristics L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 5, Reactor Coolant System L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 7, Instrumentation and Controls L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 9, Auxiliary Systems L-2017-074, St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 9.5, Fire Protection Program Report ML17132A382 ML17171A239 ML17171A240 ML17171A244 ML17171A247 ML17171A249 ML17171A250 ML17171A256 ML17171A257 ML17171A258 ML17171A259 ML17171A261 ML17171A262 ML17298A046 ML17298A047 ML17298A048 ML17298A049 ML17298A050 ML17298A051
References
L-2017-074
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ACCIDENT ANALYSIS CHAPTER 15 TABLE OF CONTENTS Section Title Page 15.1 GENERAL 15.1.1-1 15.1.1 CLASSIFICATION OF ACCIDENTS 15.1.1-1a 15.1.1.1 Section 15.1 References 15.1.1-1a 15.1.2 ACCIDENT PARAMETERS 15.1.2-1 15.1.3 TRIP SETTINGS 15.1.3-1 15.1.4 COMPUTER PROGRAMS 15.1.4-1 15.1.4.1 Deleted 15.1.4-1 15.1.4.2 Deleted 15.1.4-2 15.1.4.3 Deleted 15.1.4-2 15.1.4.4 Deleted 15.1.4-2 15.1.4.5 Deleted 15.1.4-4 15.1.4.6 Deleted 15.1.4-4 15.1.4.7 Deleted 15.1.4-4 15.1.4.8 Deleted 15.1.4-5 15.1.4.9 Deleted 15.1.4-5 15.1.5 METHODOLOGY 15.1.5-1 15.1.5.1 Deleted 15.1.5-1 15.1.5.2 Deleted 15.1.5-1 15.1.5.3 Deleted 15.1.5-1 15.1.5.4 Deleted 15.1.5-2 15.1.6 SAFETY ANALYSIS EVALUATION FOR THE FOR THE ST. LUCIE 1 CORE 15.1.6-1 15.1.6.1 Introduction and Summary 15.1.6-1 15.1.6.2 Calculational Methods and Input Parameters Code Description 15.1.6-1 15.1.6.3 Modeling Uncertainties 15.1.6-3 15.1.6.4 Design Parameters 15.1.6-4 15.1.6.5 Deleted 15.1.6-4 15.1.6.6 Deleted 15.1.6-4a 15.1.6.7 Deleted 15.1.6-4a 15.1.6.8 Reload Safety Analysis 15.1.6-4a 15.1.6.8.1 Event Review and Analysis for the Current Cycle 15.1.6-4a 15.1.6.8.2 Summary of Results 15.1.6-4b 15.1.7 INSTALLATION OF REPLACEMENT STEAM GENERATORS 15.1.7-1 15.1.8 INSTALLATION OF REPLACEMENT PRESSURIZER 15.1.8-1

UNIT 1 15-i Amendment No.

27 (04/15)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.2 ANTICIPATED OPERATIONAL OCCURRENCES (CLASS 1 ACCIDENTS) 15.2.1-1 15.2.1 UNCONTROLLED CEA WITHDRAWAL 15.2.1-2 15.2.1.1 Identification of Causes 15.2.1-2 15.2.1.2 Analysis of Effects and Consequences 15.2.1-4 15.2.1.2.1 Uncontrolled CEA Withdrawal from a Subcritical or Low 15.2.1-4 Power Startup Condition 15.2.1.2.2 Uncontrolled CEA Withdrawal at Power 15.2.1-5 15.2.1.3 Deleted 15.2.1-5 15.2.1.4 Deleted 15.2.1-5a 15.2.2 TRANSIENTS RESULTING FROM THE MALFUNCTION OF ONE STEAM GENERATOR 15.2.2-1 15.2.2.1 Identification of Causes 15.2.2-1 15.2.2.2 Analysis of Effects and Consequences 15.2.2-1 15.2.2.3 Deleted 15.2.2-2 15.2.2.4 Deleted 15.2.2-2 15.2.2.5 Deleted 15.2.2-2 15.2.2.5.1 Deleted 15.2.2-2 15.2.2.5.2 Deleted 15.2.2-2 15.2.2.5.3 Deleted 15.2.2-2 15.2.2.5.4 Deleted 15.2.2-2a 15.2.2.5.5 Deleted 15.2.2-2a 15.2.3 CEA DROP ACCIDENT 15.2.3-1 15.2.3.1 Identification of Causes 15.2.3-1 15.2.3.2 Analysis of Effects and Consequences 15.2.3-2 15.2.3.3 Deleted 15.2.3-2a 15.2.3.3.1 Deleted 15.2.3-2a 15.2.3.4 Deleted 15.2.3-2a 15.2.4 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION - BORON DILUTION EVENT 15.2.4-1 15.2.4.1 Identification of Causes 15.2.4-1 15.2.4.2 Analysis of Effects and Consequences 15.2.4-2 15.2.4.3 Conclusions 15.2.4-3 15.2.4.4 Deleted 15.2.4-3 15.2.4.5 Deleted 15.2.4-6a

15-ii Amendment No. 26 (11/13)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.2.5 LOSS OF COOLANT FLOW ACCIDENT 15.2.5-1 15.2.5.1 Identification of Causes 15.2.5-1 15.2.5.2 Analysis of Effects and Consequences 15.2.5-1a 15.2.5.3 Deleted 15.2.5-2 15.2.6 STARTUP OF AN INACTIVE REACTOR COOLANT PUMP EVENT 15.2.6-1 15.2.7 LOSS OF EXTERNAL ELECTRICAL LOAD AND/OR TURBINE STOP VALVE CLOSURE 15.2.7-1 15.2.7.1 Overview 15.2.7-1 15.2.7.2 Safety Analysis 15.2.7-2 15.2.7.3 Effect of Replacement Steam Generators 15.2.7-3 15.2.8 LOSS OF NORMAL FEEDWATER FLOW 15.2.8-1 15.2.8.1 Identification of Causes 15.2.8-1 15.2.8.1.1 Loss of Normal Feedwater 15.2.8-1 15.2.8.1.2 Feedwater System Pipe Breaks 15.2.8-1 15.2.8.2 Analysis of Effects and Consequences 15.2.8-1 15.2.8.2.1 Maximum Primary System Pressure 15.2.8-2 15.2.8.2.2 Minimum Departure from Nucleate Boiling Ratio (MDNBR) 15.2.8-2 15.2.8.2.3 Long Term Cooling 15.2.8-2 15.2.8.3 Reload Safety Analysis 15.2.8-2a 15.2.8.3.1 Loss of Normal Feedwater 15.2.8-2a 15.2.9 LOSS OF OFFSITE POWER TO THE STATION AUXILIARIES 15.2.9-1 15.2.9.1 Identification of Causes 15.2.9-1 15.2.9.2 Analysis of Effects and Consequences 15.2.9-2 15.2.9.3 Results 15.2.9-4 15.2.9.4 Conclusion 15.2.9-5 15.2.9.5 Reload Safety Analysis 15.2.9-5 15.2.10 EXCESS HEAT REMOVAL DUE TO FEEDWATER SYSTEM MALFUNCTIONS 15.2.10-1

15-iii Amendment No. 26 (11/13)

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

Section Title Page 15.4 POSTULATED ACCIDENTS (CLASS 3 ACCIDENTS) 15.4.1-1 15.4.1 MAJOR REACTOR COOLANT SYSTEM PIPE BREAK (LOCA) 15.4.1-1 15.4.1.1 Identification of Causes 15.4.1-1 15.4.1.2 Reload Safety Analysis 15.4.1-2 15.4.1.3 Deleted 15.4.1-4 15.4.1.4 Deleted 15.4.1-4 15.4.1.5 Radiological Consequences 15.4.1-5 15.4.1.6 Hydrogen Accumulation in Containment 15.4.1-12 15.4.1.7 Effect of Replacement Steam Generators 15.4.1-13 15.4.2 WASTE GAS DECAY TANK LEAKAGE OR RUPTURE 15.4.2-1 15.4.2.1 Identification of Causes 15.4.2-1 15.4.2.2 Radiological Analysis 15.4.2-1 15.4.2.3 Deleted 15.4.2-2 15.4.3 FUEL HANDLING ACCIDENT 15.4.3-1 15.4.3.1 Identification of Causes 15.4.3-1 15.4.3.2 Radiological Analysis 15.4.3-3 15.4.3.3 Effect of Replacement Steam Generators 15.4.3-7 15.4.4 STEAM GENERATOR TUBE FAILURE 15.4.4-1 15.4.4.1 Identification of Causes 15.4.4-1 15.4.4.2 Analysis of Effects and Consequences 15.4.4-2 15.4.4.3 Deleted 15.4.4-3 15.4.4.4 Deleted 15.4.4-4 15.4.4.5 Radiological Analysis 15.4.4-4a 15.4.4.6 Conclusions 15.4.4-4e 15.4.4.7 Deleted 15.4.4-4e

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

CHAPTER 15 TABLE OF CONTENTS (Cont'd)

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

15.5 REFERENCES

FOR CHAPTER 15 15.5-1 15.6

SUMMARY

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

6.6 REFERENCES

FOR SECTION 15.6 15.6-5

15-va Amendment No. 26 (11/13)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.2.4-1 Boron Dilution Event: Input Parameters 15.2.4-7 15.2.4-2 Boron Dilution Event

Results 15.2.4-8 15.2.5-1 Kinetics Parameters for the Loss-of-Coolant Flow Event 15.2.5-3 15.2.5-2 Event Table for a Loss-of-Coolant Flow 15.2.5-4 15.2.7-1 Loss of External Load Sequence of Events for Primary Side 15.2.7-4 Over Pressurization Case 1 5.2.7-2 Loss of External Load Sequence of Events for HFP Secondary 15.2.7-5 Side Over Pressurization Limiting Case 15.2.7-3 Loss of External Load Sequence of Events for MDNBR Case 15.2.7-5 15.2.7-4 Loss of External Load Inoperable MSSV Results 15.2.7-5a 15.2.8-1 Plant Initial Condition and Key Parameters for Loss-of-Normal 15.2.8-3 Feedw ater Analysis 15.2.8-2 Sequence of Events for Loss of Normal Feedwater Analysis 15.2.8-4 15.2.9-1 Deleted 15.2.9-6 15.2.9-2 Deleted 15.2.9-7 15.2.9-3 Deleted 15.2.9-8 15.2.9-4 Deleted 15.2.9-9 15.2.11-1 Excess Load: HFP Analysis Parameters 15.2.11-2f 15.2.11-2 Excess Load: Sequence of Events For HFP Limiting Case (Maximum Load Increase, -29.6 pcm/° F) 15.2.11-3 15.2.11-3 Excess Load: HZP Analysis Parameters 15.2.11-3a

15-vii Amendment No. 26 (11/13)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.3.1-1 HPSI Flow Rate Vs RCS Pressure Used in the SBLOCA Event 15.3.1-3b 15.3.1-2 Current SBLOCA Analysis Parameters 15.3.1-3c 15.3.4-1 Initial Conditions and Biasing For RCP Rotor Seizure Event 15.3.4-5 15.3.4-2 Sequence of Events For RCP Rotor Seizure Event 15.3.4-6 15.3.4-3 Deleted 15.3.4-7 15.3.4-4 Reactor Coolant Pump Shaft Seizure (Locked Rotor) -

15.3.4-8 Inputs and Assumptions

15.3.4-4a Results From Reactor Coolant Pump Seized Rotor Event 15.3.4-9 15.3.4-5 Locked Rotor Steam Release Rate 15.3.4-9 15.3.4-6 Locked Rotor SG Tube Leakage 15.3.4-10 15.3.4-7 Control Room /Qs 15.3.4-10 15.3.4-8 Locked Rotor Dose Consequences 15.3.4-11 15.4.1-1 Sampled LBLOCA Parameters 15.4.1-14 15.4.1-1a Plant Operating R ange Supported By the LOCA Analysis 15.4.1-14a 15.4.1-1b Statistical Distributions Used F or Process Parameters 15.4.1-15 15.4.1-1c Summary Of Major Parameters F or the Limiting PCT Case 15.4.1-16 15.4.1-1d Calculated Event Times F or the Limiting PCT Case 15.4.1-17 15.4.1-1e LOCA Containment Leakage Source Term 15.4.1-18 15.4.1-1f Containment H eat Sink D ata 15.4.1-19 15.4.1-1g Containment Initial and Boundary Conditions 15.4.1-19a 15.4.1-1h Summary Of Results F or the Limiting PCT Case 15.4.1-19a 15.4.1-2 Maximum Potential Recirculation Loop Leakage (Outside Containment) 15.4.1-20 15.4.1-3 Deleted 15.4.1-21 15.4.1-4 Deleted 15.4.1-22

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

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.4.1-5 Class 3 - Design Basis Accident Off-Site Doses (Historical) 15.4.1-23 15.4.1-6 Loss-of-Coolant Accident (LOCA) Inputs and Assumptions 15.4.1-24 15.4.1-7 LOCA Release Phases 15.4.1-27 15.4.1-8 Adjusted Sump to RWT Leakage Flow Rate 15.4.1-27 15.4.1-8a RWT Leakage Flow Rate 15.4.1-27 15.4.1-9 Reactor Coolant Source Term 15.4.1-28 15.4.1-10 Control Room /Q 15.4.1-29 15.4.1-11 LOCA Dose Summary 15.4.1-30 1 5.4.2-1 Waste Gas Decay Tank Rupture (WGDT) Inputs and Assumptions 15.4.2-2a 15.4.2-2 WGDT Source Term 165,000 Curies Xe-133 Equivalent 15.4.2-3 15.4.2-3 EAB X/Q15.4.2-3 15.4.2-4 LPZ X/Q 15.4.2-4 15.4.2-5 Common St. Lucie HVAC E/Q Table 15.4.2-4 15.4.2-6 Common St. Lucie Control R oom Unfiltered 15.4.2-4a Inleakage X/Q 15.4.2-7 St. Lucie Units 1 and 2 Waste G as Decay T ank Failure 15.4.2-4a 15.4.3-1 Fuel Handling Accident (FHA) Inputs and Assumptions 15.4.3-8 15.4.3-2 Fuel Handling Accident Source Term 15.4.3-9 15.4.3-3 Control Room /Qs for Containment Release and For FHB Release 15.4.3-10 15.4.3-4 Fuel Handling Accident Dose Consequences 15.4.3-10

15-viiia Amendment No. 26 (11/13)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page

15.4.4-1 Key Parameters Assumed in the Steam Generator Tube Rupture Event 15.4.4-5 15.4.4-2 Sequence of Events for the Steam Generator Tube Rupture Event 15.4.4-6 (45 min. Operator Action Time) 15.4.4-2a Key Parameters Assumed in the Steam Generator Tube Rupture 15.4.4-6 Overfill Event 15.4.4-2b Sequence of Event For the Steam Generator Tube Rupture Overfill 15.4.4-6a Event (45 min. Operator Action Time) 15.4.4-3 Steam Generator Tube Rupture (SGTR) Inputs and Assumptions 15.4.4-7 15.4.4-4 SGTR Mass Releases Rates 15.4.4-8 15.4.4-5 SGTR Iodine Equilibrium Appearance Assumptions 15.4.4-8 15.4.4-6 SGTR Concurrent Iodine Spike (335 x µCi/gm) Activity Appearance 15.4.4-9 Rate 15.4.4-7 SGTR 60 Ci/gm D.E. I-131 Activities 15.4.4-9 15.4.4-8 Control Room /Qs 15.4.4-10 15.4.4-9 SGTR Dose Consequences 15.4.4-10 15.4.5-1 CEA Ejection: Input Parameter Biasing For HFP and HZP Cases 15.4.5-3 15.4.5-1a CEA Ejection: Input Parameter Biasing For Part-Power Cases 15.4.5-3 15.4.5-2 CEA Ejection: Event Results For HFP and HZP Cases 15.4.5-4 15.4.5-2a CEA Ejection: Sequence of Events For HFP and HZP Cases 15.4.5-4a 15.4.5-2b CEA Ejection: Event Results For Part-Power Cases 15.4.5-4b 15.4.5-3 Control Element Assembly (CEA) Ejection Inputs and Assumptions 15.4.5-5 15.4.5-4 CEA Steam Release Rate 15.4.5-7 15.4.5-5 CEA Steam Generator Tube Leakage 15.4.5-7 15.4.5-6 Control Room /Q (for releases from the steam generators) 15.4.5-8 15.4.5-7 CEA Ejection Dose Consequences 15.4.5-8 15.4.5-8 Deleted 15.4.5-9 15-ix Amendment No. 26 (11/13)

CHAPTER 15 LIST OF TABLES (Cont'd)

Table Title Page 15.4.6-1 Pre-Scram Main Steam Line Break:

15.4.6-5 Input Parameter Biasing 1 5.4.6-2 Deleted 15.4.6-6 15.4.6-3 Post-S team Line Break:

15.4.6-7 Input Parameter Biasing 15.4.6-4 Pre-Scram Main Steam Line Break:

15.4.6-8 Limiting Case Sequence of Events 15.4.6-4a Post-Scram Main Steam Line Break:

15.4.6-8 HZP Sequence of Events 15.4.6-4b Post-Scram Main Steam Line Break:

15.4.6-8a HFP Sequence of Events 15.4.6-4c Main Steam Line Break: Analysis Results 15.4.6-8b 15.4.6-5 Main Steam Line Break (MSLB) Inputs and Assumptions 15.4.6-9 15.4.6-6 MSLB Steam Release Rate 15.4.6-10 15.4.6-7 MSLB Steam Generator Tube Leakage 15.4.6-11 15.4.6-8 Secondary Side Source Term 15.4.6-11 15.4.6-9 Control Room /Q (for releases from the steam generators) 15.4.6-12 15.4.6-10 MSLB Dose Consequences 15.4.6-12 15.6-1 Uncertainties Applied in LPD LSSS Calculations 15.6-6 15.6-2 Uncertainties Applied in the TM/LP LSSS Calculations 15.6-7 15.6-3 Transient Biases Applied in the TM/LP LSSS Calculation 15.6-8 15.6-4 Additional Trip Functions 15.6-9 (Only Those Used In Setpoints Verification) 15.6-5 Uncertainties Applied in the LCO Calculations 15.6-10 15.6-6 Additional Uncertainties Applied in DNB LCO CEAD 15.6-10a Calculations 15.6-7 Additional Uncertainties Applied in DNB LCO LOCF 15.6-10b Calculations 15-ixa Amendment No. 26 (11/13)

ACCIDENT ANALYSES CHAPTER 15 LIST OF FIGURES Figure Title 15.1.6-1 Deleted 15.1.6-2 St. Lucie Unit 1 LPD LSSS 15.1.6-3 St. Lucie Unit 1 - TM/LP Correction Function A1 15.1.6-4 St. Lucie Unit 1 - TM/LP Correction Function QR1 15.1.6-5 DNB LCO for St. Lucie Unit 1 15.1.6-6 Deleted 15.1.6-7 Deleted 15.1.6-8 Deleted 15.1.6-9 Deleted 15.2.1-1 St. Lucie Unit 1 Reactor Power CEA Withdrawal At Power 15.2.1-2 St. Lucie Unit 1 Total Core Heat Flux Power - CEA Withdrawal At Power 15.2.1-3 St. Lucie Unit 1 Pressurizer Pressure - CEA Withdrawal At Power 15.2.1-4 St. Lucie Unit 1 Pressurizer Liquid Level -

CEA Withdrawal At Power 15.2.1-5 St. Lucie Unit 1 RCS Loop Temperatures - CEA Withdrawal At Power 15.2.1-6 St. Lucie Unit 1 RCS Total Loop Flow Rate - CEA Withdrawal At Power 15.2.1-7 St. Lucie Unit 1 Margin to TM/LP RPS Trip - CEA Withdrawal At Power 15.2.1-8 St. Lucie Unit 1 Margin to VHP RPS Trip - CEA Withdrawal At Power 15.2.1-9 St. Lucie Unit 1 Reactivity Feedback - CEA Withdrawal At Power 15.2.1-10 Deleted 15.2.1-11 Deleted

15-x Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.2-1 Loss of Load/1 Steam Generator Event Core Power vs Time 15.2.2-2 Loss of Load/1 Steam Generator Event Reactivity Feedback vs Time 15.2.2-3 Loss of Load/1 Steam Generator Event SG Pressures vs Time 15.2.2-4 Loss of Load/1 Steam Generator Event Pressure SG Difference vs ASGPT Setpoint and vs Time 15.2.2-5 Loss of Load/1 Steam Generator Ev ent Core Inlet Temperatures vs Time 15.2.2-6 Loss of Load/1 Steam Generator Event RCS Loop Flow Rates vs Time 15.2.2-7 Loss of Load/1 Steam Generator Event Pressurizer Pressure vs Time 1 5.2.2-8 Loss of Load/1 Steam Generator Event Pressurizer Level vs Time 15.2.2-9 Loss of Load/1 Steam Generator Event Steam Flow Rates vs Time 15.2.2-10 Loss of Load/1 Steam Generator Event MSSV Flows vs Time 15.2.3-1 St. Lucie Unit 1 Reactor Powers - CEA Drop 15.2.3-2 St. Lucie Unit 1 Total Core Heat Flux Power - CEA Drop 15.2.3-3 St. Lucie Unit 1 Pressurizer Pressure - CEA Drop 15.2.3-4 St. Lucie Unit 1 Pressurizer Liquid Level - CEA Drop 15.2.3-5 St. Lucie Unit 1 RCS Loop Temperatures - CEA Drop 15.2.3-6 St. Lucie Unit 1 RCS Total Loop Flow Rate - CEA Drop 15.2.3-7 St. Lucie Unit 1 Steam Generator Pressures - CEA Drop 15.2.3-8 St. Lucie Unit 1 Steam Generator Flow Rates - CEA Drop 15.2.3-9 St. Lucie Unit 1 Reactivity Feedback - CEA Drop 15.2.3-10 Deleted 15.2.3-11 Deleted 15.2.5-1 St. Lucie Unit 1 Reactor Power - Loss of Coolant Flow 15.2.5-2 St. Lucie Unit 1 Total Core Heat Flux Pow er - Loss of Coolant Flow 15.2.5-3 St. Lucie Unit 1 Pressurizer Pressure - Loss of Coolant Flow 15.2.5-4 St. Lucie Unit 1 RCS Loop Temperatures - Loss of Coolant Flow 15.2.5-5 St. Lucie Unit 1 RCS Total Loop Flow Rate Temperatures - Loss of Coolant Flow 15.2.5-6 St. Lucie Unit 1 - Reactivity Feedback - Loss of Coolant Flow 15.2.5-7 Deleted

15-xi Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

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

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.7-20 Loss of External Load Pressurizer Pressure (MDNBR Case) 15.2.7-21 Loss of External Load Pressurizer Liquid Level (MDNBR Case) 15.2.7-22 Loss of External Load Pressurizer PORV Flow Rate (MDNBR Case) 15.2.7-23 Loss of External Load RCS Loop Temperatures (MDNBR Case) 15.2.7-24 Loss of External Load RCS Total Loop Flow Rate (MDNBR Case) 15.2.7-25 Loss of External Load Steam Generator Pressures (MDNBR Case) 15.2.7-26 Loss of External Load Reactivity Feedback (MDNBR Case) 15.2.8-1 Loss of Feedwater Flow Event Steam Generator Inventories vs. Time 15.2.9-1 Deleted 15.2.9-2 Deleted 15.2.9-3 Deleted 15.2.9-4 Deleted 15.2.9-5 Deleted

15-xiia Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Contd) Figure Title 15.2.11-1 Core Power for HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/oF) 15.2.11-2 Total Core Heat Flux Power For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-3 Pressurizer Pressure HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-4 RCS Loop Temperature For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-5 RCS Total Loop Flow Rate For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-6 Steam Generator Pressure For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-7 Steam and Feedwater Flow Rates For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-8 Reactivity Feedback For HFP Limiting Excess Load (Maximum Load Increase, MTC of -29.6 pcm/

o F) 15.2.11-9 Reactor Power HZP Excess Load 15.2.11-10 Total Core Heat Flux Power HZP Excess Load 15.2.11-11 Pressurizer Pressure HZP Excess Load 15.2.11-12 RCS Loop Temperatures HZP Excess Load 15.2.11-13 RCS Total Loop Flow Rate HZP Excess Load 15.2.11-14 Steam Generator Pressures HZP Excess Load 15.2.11-15 Steam and Feedwater Flow Rate HPZ Excess Load 15.2.11-16 Reactivity Feedback HZP Excess Load 15.2.11-17 Peak Fuel Centerline Temperature HZP Excess Load 15.2.12-1 Reactor Power RCS Depressurization 15.2.12-2 Total Core Heat Flux Power RCS Depressurization 15.2.12-3 Pressurizer Pressure RCS Depressurization 15.2.12-4 Pressurizer PORV Flow Rate RCS Depressurization

15-x iii Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Contd) 15.2.12-5 RCS Loop Temperatures RCS Depressurization 15.2.12-6 RCS Total Loop Flow Rate RCS Depressurization 15.2.12-7 Reactivity Feedback RCS Depressurization 15.2.12-8 Deleted 15.2.12-9 Deleted 15.2.12-10 Deleted 15.2.12-11 Deleted 15.2.12-12 Pressurizer PORV Flow Rate RCS Depressurization / Pressurizer Overfill 15.2.12-13 Pressurizer Pressure RCS Depressurization / Pressurizer Overfill 15.2.12-14 RCS Coolant Temperatures RCS Depressurization / Pressurizer Overfill 15.2.12-15 RCS Subcooling RCS Depressurization / Pressurizer Overfill 15.2.12-16 Total RCS Flow Rate RCS Depressurization / Pressurizer Overfill 15.2.12-17 Indicated Reactor Power RCS Depressurization / Pressurizer Overfill 15.2.12-18 Total HPSI and Charging Flow Rates RCS Depressurization / Pressurizer Overfill 15.2.12-19 Pressurizer Liquid Volume RCS Depressurization / Pressurizer Overf ill 15.2.13-1 Total RCS Leakage Station Blackout 15.2.13-2 Reactor Power (Decay Heat) Station Blackout 15.2.13-3 Pressurizer Pressure Station Blackout 15.2.13-4 Pressurizer Liquid Level Station Blackout 15.2.13-5 RCS Reactor Vessel Upper Head Subcooling Margin Station Blackout 15.2.13-6 RCS Average Temperature s Station Blackout 15.2.13-7 ADV Flow Rates Station Blackout 15.2.13-8 Steam Generator Pressure Station Blackout 15.2.13-9 Steam Generator Liquid Level Station Blackout 15.2.13-10 Steam Generator Total Mass Station Blackout 15.2.13-11 Reactor Vessel Liquid Level (Above Bottom of Active Core) Station Blackout

15-xiiia Amendment No. 26 (11

/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.2.14-1 Reactor Power CVCS Malfunction Event 15.2.14-2 RCS Average Temperature CVCS Malfunction Event 15.2.14-3 Pressurizer Pressure CVCS Malfunction Event 15.2.14-4 Pressurizer Water Volume CVCS Malfunction Event 15.3.1-1 Reactor Power for 3.

70 in. Diameter Break SBLOCA 15.3.1-2 Primary and Secondary Pressures for 3.

70 in. Diameter Break SBLOCA 15.3.1-3 Break Void Fraction for 3.

70 in. Diameter Break SBLOCA 15.3.1-4 Break Flow Rate for 3.

70 in. Diameter Break SBLOCA 15.3.1-5 Loop Seal Void Fractions for 3.

70 in. Diameter Break SBLOCA 15.3.1-6 RCS Loop Flow Rate for 3.

70 in. Diameter Break SBLOCA 15.3.1-7 MFW Flow Rate for 3.

70 in. Diameter Break SBLOCA 15.3.1-8 AFW Flow Rate for 3.70 in. Diameter Break SBLOCA 15.3.1-9 Steam Generator Total Mass for 3.

70 in. Diameter Break SBLOCA 15.3.1-10 Total HPSI Mass Flow Rate for 3.

70 in. Diameter Break SBLOCA 15.3.1-11 Total SIT Mass Flow Rate for 3.

70 in. Diameter Break SBLOCA 15.3.1-12 RCS and Reactor Vessel Mass Inventories for 3.

70 in. Diameter Break SBLOCA 15.3.1-13 Hot Assembly Collapsed Liquid Level for 3.

70 in. Diameter Break SBLOCA 15.3.1-14 Hot Spot Cladding Temperature and Coolant Temperature for 3.

70 in. Diame ter Break SBLOCA 15.3.3-1 Typical BOL Power Distribution with Correct Fuel Loading, Maine Yankee 15.3.3-2 Power Distribution for Postulated Interchange of Two C Assemblies, Maine Yankee 15.3.3-3 Power Distribution for Postulated Interchange of Two C Assemblies, Maine Yankee 15.3.3-4 Power Distribution for Postulated Interchange of an A and C Assembly, Maine Yankee

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

CHAPTER 15 LIST OF FIGURES (Cont'd)

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

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

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.4.1-2 PCT vs PCT Time Scatter Plot From 59 Calculations 15.4.1-3 PCT vs One-Sided Break Area Scatter Plot From 59 Calculations 15.4.1-4 Maximum Oxidation vs PCT Scatter Plot From 59 Calculations 1 5.4.1-5 Total Oxidation vs PCT Scatter Plot From 59 Calculations 15.4.1-6 Peak Cladding Temperature (Independent of Elevation) for the Limiting Case 15.4.1-7 Break Flow for the Limiting Case 15.4.1-8 Core Inlet Mass Flux for the Limiting Case 15.4.1-9 Core Outlet Mass Flux for the Limiting Case 15.4.1-10 Void Fraction At RCS Pumps for the Limiting Case 15.4.1-11 ECCS Flows (Includes SIT, LPSI and HPSI) for the Limiting Case 15.4.1-12 Upper Plenum Pressure for the Limiting Case 15.4.1-13 Collapsed Liquid Level in the Downcomer for the Limiting Case 15.4.1-14 Collapsed Liquid Level in the Lower Plenum for the Limiting Case 15.4.1-15 Collapsed Liquid Level in the Core for the Limiting Case 15.4.1-16 Containment and Loop Pressures for the Limiting Case 15.4.1-17 Normalized Power vs Time for the Limiting Case 15.4.1-18 Average Core Inlet Flow Rate During Blowdown (EOB =

25s) for the Limiting Case 15.4.1-19 Hot Channel Inlet Flow Rate During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-20 PCT Node Fluid Quality During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-21 PCT Node Fuel (Average), Cladding, and Fluid Temperatures During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-22 PCT Node Heat Transfer Coefficient During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-23 PCT Node Heat Flux During Blowdown (EOB = 25s) for the Limiting Case 15.4.1-24 Core Quench Level for the Limiting Case 15.4.1-25 PCT Node Heat Transfer Coefficient (to PCT Node Quench) for the Limiting Case 15.4.1-26 PCT Node Cladding Temperature for the Limiting Case 15.4.1-27 GDC 35 Loop vs No-Loop Cases 15.4.1-28 Allowable Control Room Intake as a Function of Cont. and Bypass Leakage

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

CHAPTER 15 LIST OF FIGURES (Cont'd)

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

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.4.6-9 Steam and Feedwater Flow Rates Pre-Scram Main Steam Line Break (HFP, 3.0 Ft 2 Break, MTC -20 PCM/° F) 15.4.6-10 Reactivity Feedback Pre-Scram Main Steam Line Break (HFP, 3.0 Ft 2 Break, MTC -20 PCM/° F) 15.4.6-11 Break Flow Rates Post-Scram Main Steam Line Break (HFP, 3.0 Ft 2 Break, MTC -20 PCM/° F) 15.4.6-12 Steam Generator Pressures Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-13 Combined MFW and AFW Flow Rates Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-14 Steam Generator Mass Inventories Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-15 Core Inlet Fluid Temperatures Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-16 Pressurizer Liquid Level Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-17 Pressurizer Pressure Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-18 Total HPSI Flow Rate Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-19 Reactivity Feedback Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-20 Core Power Post-Scram Main Steam Line Break (HZP, Offsite Power Available) 15.4.6-21 Break Flow Rates Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-22 Steam Generator Pressures Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-23 Combined MFW and AFW Flow Rates Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-24 Steam Generator Mass Inventories Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-25 Core Inlet Fluid Temperatures Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-26 Pressurizer Liquid Level Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-27 Pressurizer Pressure Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-28 Total HPSI Flow Rate Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 1 5.4.6-29 Reactivity Feedback Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15.4.6-30 Core Power Post-Scram Main Steam Line Break (HZP, Loss of Offsite Power) 15-xvii Amendment No. 26 (11/13)

CHAPTER 15 LIST OF FIGURES (Cont'd)

Figure Title 15.6-1 Deleted 15.6-2 St. Lucie Unit 1, TM/LP Trip Function A1 15.6-3 St. Lucie Unit 1, TM/LP Trip Function QR1 15.6-4 Deleted 15.6-5 Deleted 15.6-6 Deleted 15.6-7 Linear Heat Rate LCO Used In LPD LCO Verification 15.6-8 Power Measurement Uncertainty vs. Power

15-xviia Amendment No. 26 (11/13)

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

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

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

Table 15.1.1-1 is a listing of the accidents based on the Regulatory Guide 1.70, "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants," Revision 1, issued October 1972. Table

15.1.1-1 also lists and classifies the accidents evaluated in this section and references the section in which the accident is discussed. Several accidents listed in the Standard Format and Content guide are not applicable. These accidents are listed in Table 15.1.1-2 with an explanation.

Table 15.1.1-3 provides a listing of those design basis events which were reanalyzed for EPU (3020 MWth) operation.

The dose consequences of selected events were subsequently evaluated using the Alternative Source Term methodology prescribed in Regulatory Guide 1.183. These events are listed in Table 15.1.1-

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

15.1.1.1 Section 15.1 References

1. "Standard Review Plan for the Review of Safety Analysis Report for Nuclear Power Plants," NUREG-0800, U.S. Nuclear Regulatory Commission, July 1981.

2. Terms for Evaluating Design Basis

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

TABLE 15.1.1-1 CLASSIFICATION OF ACCIDENTS ANALYZED Section Item Accidents Classification Number 1 Uncontrolled CEA withdrawal from a subcritical or low power condition, including CEA or temporary control device removal error during refueling AOO 15.2.1 2 Uncontrolled CEA withdrawal at power AOO 15.2.1 Transients resulting from malfunction of one steam generator AOO 15.2.2 3 CEA Drop Accident AOO 15.2.3 4 Chemical and volume control system malfunction AOO 15.2.4; 15.2.14 5 Loss of forced reactor coolant flow AOO 15.2.5 28 Single reactor coolant pump locked rotor PA 15.3.4 6 Startup of an inactive reactor coolant loop or recirculation AOO 15.2.6 7 Loss of external electrical load and/or turbine Stop Valve Closure AOO 15.2.7 8 Loss of normal feedwater AOO 15.2.8 9 Loss of offsite power to the station auxiliaries AOO 15.2.9 10 Excessive heat removal due to feedwater system malfunctions AOO 15.2.10 11 Excessive load increase, including that resulting from a pressure regulator failure or inadvertent opening of a relief valve or safety valve AOO 15.2.11 16 Loss of reactor coolant, from small ruptured pipes or from cracks in large pipes, which actuate emergency core cooling PA 15.2.12; 15.3.1 Station blackout AOO 15.2.13 17 Minor secondary system pipe break outside containment PA 15.3.2 25 Steamline breaks PA 15.4.6 18 Inadvertent loading of a fuel assembly into an improper position PA 15.3.3

15.1.1-2 Amendment No.

26 (11/13)

TABLE 15.1.1-1 (Continued)

Section Item Accidents Classification Number 27 Major rupture of pipes containing reactor coolant up to and including double-ended rupture of the largest pipe in the reactor coolant system (Loss-of-Coolant Accident)

PA 15.4.1 20 Waste gas decay tank rupture PA 15.4.2 21 Steam generator tube rupture PA 15.4.4 22 CEA ejection accident PA 15.4.5 29 Fuel handling accident PA 15.4.3 Fuel clad failure plus steam generator leak PA 15.4.4 Residual heat removal system failure (Ref. Sec. 9.3.5)

Loss of condenser vacuum (Ref. Sec. 7.7.1.4.2)

Turbine bypass valve failure (Ref. Sec. 5.2.2; 7.7.2.3.2)

15.1.1-3 Amendment No.

26 (11/13)

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

15.2.4 Boron Dilution Reanalyzed

15.2.6 Startup of an Inactive Reactor Coolant Pump Not Reanalyzed

15.2.11 Excess Load Reanalyzed

15.2.7 Loss of Load Reanalyzed

15.2.8 Loss of Feedwater Flow Reanalyzed

15.2.10 Excess Heat Removal due to Feedwater Malfunction Reanalyzed

15.2.12 Reactor Coolant System Depressurization Reanalyzed

15.2.1 Control Element Assembly Withdrawal(1) Reanalyzed

15.2.5 Loss of Coolant Flow(2) Reanalyzed 15.2.9 Loss of AC Power(2) Dispositioned

15.2.2 Transients Resulting from the Malfunction of One Steam Reanalyzed Generator(3) 15.2.13 Station Blackout Reanalyzed

Anticipated operational occurrences for which RPS trips and/or sufficient initial steady state thermal margin, maintained by the LCOs, are necessary to prevent exceeding the acceptable limits:

15.2.1 Control Element Assembly Withdrawal Reanalyzed

15.2.5 Loss of Coolant Flow Reanalyzed 15.2.9 Loss of AC Power Dispositioned

15.2.3 Full Length CEA Drop Reanalyzed

15.2.2 Transients Resulting from the Malfunction of One Steam Reanalyzed Generator

1) Requires high power and variable high power trip; event is discussed in respective section below.

2) Requires low flow trip; event is discussed in respective section below.

3) in respective section below.

15.1.1-7 Amendment No.

26 (11/13)

TABLE 15.1.1-3 (Cont'd)

Postulated Accidents: Analysis Status 15.4.5 CEA Ejection Reanalyzed 15.4.6 Steam Line Rupture Reanalyzed

15.4.4 Steam Generator Tube Rupture Reanalyzed

15.3.4 Seized Rotor Reanalyzed 15.4.1 Loss of Coolant Accident Reanalyzed 15.3.2 Minor Secondary System Pipe Not Reanalyzed

15.3.3 Improper Fuel Loading Not Reanalyzed 15.4.2 Waste Gas Decay Tank Rupture Not Reanalyzed 15.4.3 Fuel Handling Accident Not Reanalyzed 15.3.1 Loss of Reactor Coolant from Small Ruptured Pipes or from Reanalyzed Cracks in Large Pipes which Actuates ECCS

15.1.1-8 Amendment No. 26 (11/13)

DELETED 15.1.1-9 Amendment No.

26 (11/13)

TABLE 15.1.1-5 FUEL AND VESSEL DESIGN LIMITS Anticipated Operational Occurrences (AOOs)

Specified acceptable fuel design limits (SAFDLs)

MDNB R 95/95 limit Peak fuel centerline temperature melt temperature Peak system pressure RCS 2,750 psia MSS 1, 100 psia Postulated Accident s Radiological doses within regulatory limits Peak system pressure RCS stresses to exceed the faulted condition stress limit MSS

15.1.1-10 Amendment 26 (11/13)

15.1.2ACCIDENT PARAMETERSNominal and steady state parameter values are given in Chapter 4.15.1.2-1 Amendment 15 (1/97)

THIS PAGE LEFT INTENTIONALLY BLANK15.1.2-2Am. 11-7/92

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

TABLE 15.1.3-1REACTOR PROTECTIVE INSTRUMENTATION TRIP SETPOINT LIMITS(See Tech. Spec. Table 2.2-1)15.1.3-3Amendment No. 18, (04/01) 15.1.4 COMPUTER PROGRAMS Descriptions of the principal computer codes used in the AREVA NP safety analyses for EPU operation are provided below.

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

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

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

The XCOBRA-IIIC code (Reference 116) is a steady-state thermal-hydraulics code that calculate the axial and radial flow and enthalpy distribution within assemblies and sub-channels for non-LOCA events. When used in conjunction with core boundary conditions from the S-RELAP transient analysis and the HTP DNB correlation (Reference 110), XCOBRA-IIIC also calculates the corresponding MDNBR. MDNBR calculations are performed in a two-step process. Calculations are first performed on a core-wide basis to calculate the axially varying flow and enthalpy distribution in the peak powered fuel assembly. Next, these flow and enthalpy boundary conditions are applied to a sub-channel model of the peak powered assembly to determine the local conditions for the calculation of MDNBR.

RC-approved advanced nodal simulator code system SAV95. SAV95 is built around the assembly spectrum/depletion code system MICBURN-3/CASMO-3 developed by Studsvik Scandpower and the three-dimensional reactor code PRISM. PRISM is a three-dimensional, coarse-mesh reactor simulator using two-group diffusion theory. The simulator code models the reactor core in three-dimensional (X-Y-Z) geometry, and the reactor calculations can be performed in quarter- or full-core geometry. The code calculates the reactor core reactivity, nodal power distribution, pin power distribution, and in-core detector responses and can be used to simulate fuel shuffling, insertion, and discharge. A summary of the key validation results for SAV95 code system is presented in Referen ce 103.

15.1.4-1 Amendment No. 26 (11/13)

DELETED

15.1.4-2 Amendment No.

26 (11/13)

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

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

DELETED 15.1.4-5 Amendment No. 26 (11/13) 1 5.1.5 METHODOLOGY The approved methodology for evaluating non-LOCA transients is described in Reference 117. For each non-LOCA transient event analysis, the nodalization, chosen parameters, conservative input and sensitivity studies were reviewed for applicability to the EPU in compliance with the SER for non-LOCA topical report (Reference 117).

The nodalization used for the calculations supporting the EPU was specific to St. Lucie Unit 1 and was consistent with the Reference 117 methodology.

The parameters and equipment states were chosen to provide a conservative estimate of the challenge to the acceptance criteria. The biasing and assumptions for key input parameters were consistent with the approved Reference 117 methodology.

The S-RELAP5 code assessments in Reference 117 validated the ability of the code to predict the response of the primary and secondary systems to non-LOCA transients and accidents. No additional model sensitivity studies were needed for this application.

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

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

The methodology is approved only for CE type reactors which use protection systems as described in the Reference 109 topical report.

The methodology includes a statistical treatment of specific variables in the analysis; therefore, if additional variables are treated statistically SPC (now AREVA NP) should re-evaluate the methodology and document the changes in the treatment of the variables. The documentation will be maintained by AREVA NP and will be available for NRC audit.

Both of these conditions are met since St. Lucie Unit 1 is a CE reactor, and no additional variables were used in the statistical DNB analysis.

The DNB calculations were performed utilizing the NRC-approved HTP CHF (or DNB) correlation described in the Reference 110 topical report. The fuel desi gn HTP assembly are within the applicable range for the HTP CHF correlation. The St. Lucie Unit 1 EPU operating conditions are within the applicable range of coolant conditions for the HTP CHF correlation.

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

UNIT 1 15.1.5-1 Amendment No. 27 (04/15)

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

The cycle to cycle changes are evaluated by the fuel vendor and the results of the evaluation are reported in the Safety Analysis report. The topics addressed include neutronics parameters, thermal hydraulic design analysis, setpoint analysis and a review of the Chapter 15 events. The event review and results for t he current cycle are presented in Section 15.1.6.8.

The n on-LOCA accident analyses performed by AREVA NP for the EPU are documented in Reference112.

The non-LOCA analyses (Reference 112) support the M5 fuel rod design introduced in Cycle 26.

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

The transient analysis for St. Lucie Unit 1 EPU was performed using S-RELAP5 the AREVA NP Plant transient simulation model for pressurized water reactors. The simulation code models the behavior of pressurized water reactors under both normal and abnormal conditions by solving the transient conservation equations for the primary and secondary systems numerically. Core neutronics behavior is modeled using point kinetics, and the transient conduction equation is solved for fuel temperatures and heat fluxes. State variables such as flow, pressure, temperature, mass inventory, steam quality, heat flux, reactor power and reactivity are calculated during the transient. Where appropriate the Reactor Protection System (RPS) and control system are modeled to describe the transients. The departure from

UNIT 1 15.1.6-1 Amendment No. 27 (04/15)

Table 15.1.6-2Deleted15.1.6-6Amendment No. 18, (04/01)

Table 15.1.6-3 St. Lucie Unit 1 Operating Parameters CORE Total Heat Output (MWt) 3020 Heat generated in fuel (%)

97.5 Pin Radial Peaking Factor 1.65 REACTOR COOLANT SYSTEM Minimum Coolant Flow Rate (gpm), measured minus uncertainty 375,000 Pressure (psia) 2250 Core Inlet Average Temperature ( F), maximum 5 51 STEAM GENERATORS Feedwater Temperature (° F) 4 36 Pressure (psia) 8 56 Steam Flow (Mlb/hr) @

3020 MWt 1 3.00

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Table 15.1.6-4 AREVA NP Fuel Design Parameters For St. Lucie Unit 1

Fuel Pellet Diameter (in) 0.377 Outer Clad Diameter (in) 0.440 Inner Clad Diameter (in) 0.384 Active Fuel Length (in) 136.7 15.1.6-8 Amendment No.

26 (11/13)

TABLE 15.1.6-5 ST. LUCIE UNIT 1 BOUNDING NEUTRONICS CHARACTERISTICS AND SHUTDOWN MARGIN Moderator Temperature Coeffecient (TS limits) pcm

/°F +7 ( 70% RTP) +2 (> 70% RTP)

-32 (100% RTP) Doppler Temperature Coefficient, pcm/

°F (bounding range)

-0.80 -1.75 Delayed Neutron Fraction 0.006376 0.005069 U-238 Fission

-to-Capture Ratio 0.699 Fraction of heat generated in the fuel 0.975 Minimum Required Shutdown Margin, pcm 3600 15.1.6-9 Amendment No. 26 (11/13)

Deleted

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

Deleted

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

TABLE 15.1.6-6

SUMMARY

OF ST. LUCIE UNIT 1 CHAPTER 15 EVENT REVIEW FOR CURRENT CYCLE SRP/UFSA R Cross Reference Event Description Disposition (Referenced to SRP)

SRP UFSAR 15.1.1 15.2.10.2.1 Decrease in Feedwater Temperature Bounded by 15.1

.3 15.1.2 15.2.10.2.2 Increase in Feedwater Flow Bounded by 15.1.3 15.1.3 15.2.1 1 Excess Load (Increase in Steam Flow)

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

--- 15.3.2 Minor Secondary System Pipe Breaks Bounded by 15.1.5 15.2.1 15.2.7 Loss of External Electrical Load and/or Turbine Stop Valve Closure Transient Response DNB Bounded by AO R Re-analyzed 15.2.2 15.2.7.2.2 Turbine Trip Bounded by 15.2.1 15.2.3 15.2.7.2.3 Loss of Condenser Vacuum Bounded by 15.2.1 15.2.4 15.2.7.2.4 Closure of MSIVs Bounded by 15.2.1 15.2.5 Steam Pressure Regulator Failure Not part of the licensing basis 15.2.6 15.2.9 Loss of Non

-emergency AC Power to Station Auxiliaries Bounded by 15.3.1 and 15.2.7 15.2.7 15.2.8.1.1 Loss of Normal Feedwater Bounded by AOR 15.2.8 15.2.8.1.2 Feedwater System Pipe Breaks (Cooldown)

Bounded by 15.1.5 --- 15.2.13 Station Blackout Bounded by AOR 15.3.1 15.2.5 Complete Loss of Forced Reactor Coolant Flow (4 pump coastdown)

Transient Response DNB Bounded by AOR Re-analyzed 15.3.2 --- Flow Controller Malfunction Not part of licensing basis

UNIT 1 15.1.6-12 Amendment No. 27 (04/15)

TABLE 15.1.6-6

SUMMARY

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

SRP/UFSAR Cross Reference Event Description Disposition (Referenced to SRP)

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

Transient Response DNB FCM Bounded by AOR Re-analyzed Re-analyzed 15.4.4 15.2.6 Startup of an Inactive Reactor Coolant Pump Event Part loop operation not allowed by Technical Specifications 15.4.5 --- Flow Controller Malfunction Causing an Increase in BWR Flow Rate Not part of licensing basis 15.4.6 15.2.4 CVCS Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant Bounded by AOR 15.4.7 15.3.3 Inadvertent Loading of a Fuel Assembly into the Improper Position Bounded by UFSAR or AOR 15.4.8 15.4.5 Spectrum of Control Rod Ejection Accidents Transient Response DNB FCM Enthalpy Deposition Steam releases for Radiological Doses Bounded by AOR Re-analyzed Bounded by AOR Re-analyzed Bounded by AOR 15.4.9 --- Spectrum of Rod Drop Accidents Not part of licensing basis 15.5.1 --- Inadvertent Operation of the ECCS Bounded by 15.5.2 15.5.2 --- CVCS Malfunction that Increases RCS Inventory Bounded by AOR

UNIT 1 15.1.6-13 Amendment No. 27 (04/15)

TABLE 15.1.6-6

SUMMARY

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

SRP/UF SAR Cross Reference Event Description Disposition (Referenced to SRP)

SRP UFSAR 15.6.1 15.2.12.1 Inadvertent Opening of a Pressurizer Safety or Relief Valve Transient Response (SAFDL) Bounded by AOR Transient Response (Pressurizer overfill)

DNB Bounded by AOR Bounded by AOR Re-analyzed 15.6.2 --- Radiological Consequences of the Failure of Small Lines Carrying Primary Coolant Outside Containment Not part of licensing basis 15.6.3 15.4.4 Radiological Consequences of a Steam Generator Tube Rupture Bounded by AOR 15.6.4 --- Radiological Consequences of a Main Steam Line Failure Outside Containment (BWR)

Not part of licensing basis 15.6.5 15.3.1 Loss of Coolant Accident (Small Break)

R e-analyzed 15.6.5 15.4.1 Loss of Coolant Accident (Large Break) ECCS Analysis Transient Post-LOCA Criticality Re-analyzed Time-to-criticality 15.7.1 15.4.2 Waste Gas Decay Tank Leakage or Rupture Bounded by AOR 15.7.2 --- Radiological Liquid Waste System Leak or Failure (Release to Atmosphere)

Deleted 15.7.3 --- Postulated Radioactive Release Due to Liquid Tank Failure Not part of licensing basis 15.7.4 15.4.3 Fuel Handling Accident Bounded by AOR 15.7.5 --- Spectrum of Cask Drop Accidents Not part of licensing basis

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

Loss of Load (Single MSIV Closure)

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

Bounded by Loss of Load (Single MSIV Closure)

Bounded by Loss of Load (Single MSIV Closure) 10.5 Loss of Normal Feedwater Bounded by AOR 10.5 Feedwater System Pipe Breaks (Heatup)

Bounded by AOR

UNIT 1 15.1.6-13a Amendment No. 27 (04/15)

)> 3: m z 0 3: m z -f z 9

• N a:: CJ 15 !=' I 0 z i i.. '*' 1.l 1.2 '*' O.t 0.8 0.] o.e 0.4 O.J 0.2 0.1 0 -0.7 tmACCUUIU:

01D.UI011 (0.0,1.17)

C'MACC!l'Wtl OP!1UI01C ACCDU.lt..I Of D.Ul01I -0.5 -0.3 -0.1 o.t 0.3 0.5 0.7 AXW. S>Wlf: IHDIX. Y1 Figure 15 .1.6-2 St Lucie Unit 1 LPD LSSS * *

• * * *

• J.tO -"" l.'5 .... ....,,, ! 1.30 ..... .... ! l.25 c... ! ...... 1.20 .... u 8 1.15 L .... 1.10 .... 1.05 ...... c .... J .....

.......

-0.6 -0.S -0.t -0.3 -0.2 *0.1 0.0 0.1 0.2 0.3 O.i O.S 0.6 t AXIAL SHAPE INDEX . Figure 15.1.6-3 St. Lucie Unit 1 -TM/LP Correction Function Al

• m z c 3: m z .... z !=> ... 0 :::; ;o .. a: &: ...J <( ffi u. 0 z 0 B u. '*' 1 0.1 0.1 0.7 o.e o.s -o.e * * (*.08, 1.0I (.15, 1.01 UNACCEPTABLE OPERATION UN ACCEPT ABLE REGION OPERATION REGION ACCEPTABLE OPERATION

(-.5,0.651 REGION (.5,0.651

-0.4 -0.2 0 0.2 0.4 o.s PERIPHERAL AXIAL SHAPE INDEX (Y 11 (NOT APPLICABLE BELOW 40% POWERI Figure 15.1.6-5 DNB LCO For St Lucie Unit 1

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

15.2.6-1

Offsite Power To maximize RCP heat, it was assumed that offsite power was available and that the RCPs continued to run with a conservative heat input of 20 MWt.

Auxiliary Feedwater Two motor-driven AFW pumps were assumed to deliver AFW flow to each SG. A single failure of the higher capacity turbine-driven AFW pump was assumed. These assumptions minimized the SG inventory during the event, thereby maximizing the challenge to the acceptance criteria.

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

The sequence of events for this analysis is given in Table 15.2.8-2. The analysis showed that a reactor trip on low steam generator level occurred at 1 6.1 seconds. Figure 15.2.8-1 gives the liquid inventory in the steam generators as a function of time. The liquid inventories continue falling after AFW initiation at 348 seconds, though at a slower rate. The steam generator levels continue to fall until the decay heat falls far enough for the AFW flow to match the steam flow through the MSSVs. The minimum SG liquid inventory occurred at approximately 876 seconds, and was approximately 875 lbm in each steam generator.

The analysis demonstrated that the acceptance criteria are satisfied.

UNIT 1 15.2.8-2a Amendment No. 2 7A (01/16)

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

Core Inlet Temperature 551F RCS Flow Rate 375,000 gpm

Pressurizer Pressure 2,250 psia

Pressurizer Level 68.6%

Moderator Temperature Coefficient +2 pcm/F Doppler Reactivity Coefficient

-0.8 pcm/F Steam Generator Initial Pressure 830 psia Steam Generator Initial Liquid Level 65% Narrow Range Low SG Level RPS Trip 25% Narrow Range

Low SG Level ESF Trip (AFW) 14% Wide Range

AFW Flow Rate 276 gpm per motor-driven pump (2 electric motor-driven pumps)

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

Bank 2: 1,040 psia + 3%

(*)

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

Feedwater Regulating System Inoperative

Auxiliary Feedwater System Automatic Mode

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

UNIT 1 15.2.8-3 Amendment No.

27A (01/16)

TABLE 15.2.8-2 SEQUENCE OF EVENTS FOR LOSS OF NORMAL FEEDWATER ANALYSIS EVENT TIME (SEC.) Total loss of main feedwater 0.0 Minimum hot leg subcooling 4.3 Low SG level trip setpoint reached 16.1 Reactor trip on low SG level (including response delay) and 17.0 turbine trip on reactor trip CEA insertion begins 17.5 Low steam generator level AFW setpoint reached in SG-1 and 1 7.8 SG-2 Maximum hot leg temperature 19.3 CEAs fully inserted 20.4 Maximum pressurizer pressure 20.6 First opening of Bank 1 MSSVs in both loops 20.6 Maximum RCS average temperature 20.9 Maximum pressurizer level 21.2 First opening of Bank 2 MSSVs in both loops 2 3.6 Closure of Bank 2 MSSVs in both loops 27.7 Motor-driven AFW pumps begin delivery to feedwater lines, 347.8 which begins sweepout of hot MFW into the SGs Feedwater piping purged of hot MFW 740 Minimum SG-1 liquid inventory 876 Minimum SG-2 liquid inventory 878

UNIT 1 15.2.8-4 Amendment No. 2 7A (01/16) cn r ,, -10 r m cn 0 )> CJ) C! s: 0 CJ) 0 G> "Tl ;-I )>

r(3 c; z m c m n )> c 0 -:;o :E mm 3 m-1)> "'tl;;o gi .... 0-1 a. !Jl:::om r 3 N-:::0 ZG) CD i::ioZ"Tl -II .!..fijr C-t z zo 9 -t=E -to N Om _..S:: -.J :::0 < "'U )> iii m )> o cnZ Z -f -< __. 140000 120000 100000 2 80000 e Vl Vl re 60000 40000 20000 \ \ ' LOSS OF FE.EDWATER FLOW EVENT STEAM GENERATOR l!NV I ENTORIES

• SG-1 TotaJ .......... SG-2 Total --+--SG-1 Liquid -A--SG-2 Liquid \... , . . . . . . . . . ---. ..--" "-, . . . . . . _..,.---""-

' ----""" 560 I I . "**-----*

=Ht-=*"'.__,.........-. I I I 0 1000 2000 T ime(s) 3000 4000

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15.2.12 DEPRESSURIZATION OF THE REACTOR COOLANT SYSTEM 15.2.12.1 Identification of Causes The Inadvertent Opening of Pressurizer Pressure Relief Valve, or Reactor Coolant System (RCS) Depressurization, event is defined, for St. Lucie Unit 1, as an accidental opening of one or both of the pressurizer power-operated relief valves (PORVs), due to a mechanical failure, spurious actuation signal, or unanticipated operator action.

The event results in a loss of RCS fluid and a fairly rapid RCS depressurization. If the moderator temperature coefficient (MTC) is positive, positive moderator density reactivity feedback caused by the depressurization leads to an increase in core power. The specified acceptable fuel design limits (SAFDLs) challenge is soon terminated, when the reactor trips on a thermal margin low pressure (TM/LP) signal, but the RCS fluid loss and depressurization continue.

The pressurizer liquid level begins to decrease significantly after the reactor trip, and this actuates th e RCS charging pumps and minimizes RCS letdown. A low-low pressurizer pressure signal subsequently actuates high-pressure safety injection (HPSI). The HPSI and charging serve to restore the pressurizer level, but if the HPSI and charging flows are not throttled or terminated, the pressurizer will begin to overfill. To prevent liquid discharge through the open PORV(s), the operators will have to close the open PORV(s) or the corresponding block valve(s) prior to the pressurizer dome becoming liquid-filled. 15.2.12.1.1 Analysis of Effects and Consequences The RCS depressurization event was used in assessing the bias term in the TM/LP trip. Trip processing delays and measurement uncertainties were used to verify the value of that bias.

The event simulated was a failure of both pressurizer relief valves fully open. A combined flow rate of 120% of rated for the two pressurizer relief valves at rated pressure (2400 psia) was simulated. The pressurizer heater capacity was set to zero to allow a more rapid depressurization, and thereby reduce the transient MDNBR.

Detailed analyses were performed with the approved non-LOCA methodology given in Reference 117. For this event, the S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures), and an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA III Ccode (Reference 108), which was used to calculate the MDNBR using the higher thermal performance (HTP) critical heat flux correlation (Reference 110). This event was also addressed as part of the TM/LP statistical setpoint analyses (Section 15.6.5) using the Reference 109 methodology.

A single calculation was performed at BOC HFP conditions, maximum TS core inlet temperature, and minimum TS RCS flow rate using the parameters listed in Table 15.2.12-1. These parameters produced the minimum margin to the DNB limit. A conservative moderator density reactivity feedback was used, based on the hot zero power (HZP) TS/ core operating limits report moderator temperature coefficient (MTC). 15.2.12.1.2 Description of Analyses for Pressurizer Overfill The purpose of this analysis was to evaluate the pressurizer overfill consequences of the RCS Depressurization event. Detailed analyses were performed using the S-RELAP5 code (Reference 117). The S-RELAP5 code was used to model the key primary a nd secondary system components, reactor protection system (RPS) and engineered safety features actuation system (ESFAS) trips, and core kinetics. The calculations were performed to determine the operator action time necessary for precluding liquid relief through a single accidentally opened pressurizer PORV.

15.2.12-1 Amendment No.

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Initial conditions and input parameter biasing (listed in Table 15.2.12-3) were designed to ensure conservatively high HPSI and charging flow rates, maximize initial pressurizer level, provide maximum reactivity feedback, and maximize the post-reactor-trip RCS heatup. Assumptions regarding mitigating systems and functions, along with a limiting single-failure, produce the most challenging scenario regarding pressurizer overfill.

The principally challenged acceptance criterion for this analysis is to demonstrate that the event does not generate a more serious plant condition. The analysis objective is to determine the minimum time for the pressurizer dome to become liquid-filled. A transient-termination operator action time based on this analysis result will ensure that no liquid is relieved through the accidentally opened PORV.

15.2.12.2 Results A summary of the MDNBR transient events sequence is given in Tabl e 15.2.12-2. Upon failure of the relief valves, the RCS pressure fell rapidly, as shown in Figure 15.2.12-3, and a reactor trip on the TM/LP function occurred at 39.2 seconds. Figures 15.2.12-1 to 15.2.12-7 show the simulated plant response for this event. The limiting MDNBR was calculated to be above the 95/95 limit for the HTP CHF correlation.

The sequence of events for the limiting pressurizer overfill case* is shown in Table 15.2.12-

4. The system response is presented in Figure 15.2.12-12 to Figure 1 5.2.12-19. The analysis showed that the minimum time from the event initiation to the pressurizer dome becoming liquid-filled is 7 minutes.**

Thus, the operators will have no more than 7 minutes from the inadvertent opening of a pressurizer PORV to terminate the event, by closing the PORV or its block

• The limiting case is initiated with maximum RCS temperatures and assumes that the pressurizer heaters are unavailable and that a LOOP occurs at reactor trip - which, in turn, renders the SBCS unavailable.

• • The pressurizer is considered to be full when the liquid fraction in the dome reaches 1.00.

15.2.12-1a Amendment No. 26 (11/13)

Table 15.2.12-1 Initial Conditions and Biasing for the RCS Depressurization Event*

Parameter Value Core Power 3,020 MWt + 0.3%

Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Pressurizer Level 65.6% Scram Reactivity Minimum HFP Moderator Density Reactivity Based on the most positive TS MTC Doppler Reactivity Coefficient -0.80 pcm/°F Gap Conductance Conservative BOC values Pressurizer Spray Available Pressurizer Heaters Disabled PORV Flow Rate 367,200 lbm/hr at 2400 psia (two valves)

Table 15.2.12-2 Sequence of Events For RCS Depressurization Event Event Time (sec.)

PORV fail open 0.0 TM/LP trip reached 38.3 Reactor scram on TM/LP (including trip 39.2 response delay) MDNBR 39.6 CEA insertion begins 39.7

• These parameters represent the EPU analysis. Disposition for the current cycle is documented in the cycle specific safety analysis report.

15.2.12-2 Amendment No.

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Table 15.2.12-3 RCS Depressurization / Pressurizer Overfill: Initial Conditions and Biasing Parameter Value Initial Reactor Power 3029.06 MW t Initial Core Inlet Temperature Range 532°F - 554°F Initial RCS Flow Rate (total) 375,000 gpm Initial Pressurizer Pressure 2185 psia Initial Pressurizer Level 68.6% Moderator Reactivity Moderator density feedback corresponding to +7.0 pcm/°F MTC Doppler Temperature Coefficient (DTC)

-0.80 pcm/°F Scram Reactivity 6017.22 pcm Steam Generator Tube Plugging 10% (both steam generators)

Open Pressurizer PORV Flow Rate (single PORV)

Sized to relieve 154

,540 lb m/hr at 2400 psia (steam only)

TM/LP Reactor Trip Setpoint P PZR psia x A 1* x QR 1** +15.85 psia/°F x Tinlet 8950 psia, or P PZR TM/LP Reactor Trip Signal

-Processing Delay 0.9 s MFW Status Initially on auto, then terminated at reactor trip Actuation of All Charging Pumps At reactor trip***

Charging Flow Rate (total) 147 gpm RWT Temperature 51°F SBCS Capacity Range 24% - 58% SBCS Secondary System Pressure Setpoint 910 psia MSSV Setpoints Open on pressure higher than 1030.0 psia (for Bank 1) and 1060.8 psia (for Bank 2)

Low-Low Pressurizer Pressure Safety Injection Actuation Signal (SIAS) Setpoint 1640 psia Safety Injection Availability Delay After SIAS 0.0 s HPSI Flow Rate Maximum, for both HPSI pumps

____________________________

A 1 (of the TM/LP reactor trip function) was conservatively assumed to be 1.0 in the S-RELAP 5 model. ** QR 1 (of the TM/LP reactor trip function) is at 1.0 at power levels above 97.2% of the rated thermal power (RTP).

• • • For LOOP cases, no charging flow delay after LOOP (for emergency diesel generator startup and sequencing) was credited.

15.2.12-2a Amendment No. 26 (11/13)

Table 15.2.12-3 RCS Depressurization / Pressurizer Overfill: Initial Conditions and Biasing (Continued)

Parameter Value Automatic Termination of Charging and Actuation of Letdown (after pressurizer level restored)

Not credited Low-Low Steam Generator Level Auxiliary Feedwater Actuation Signal (AFAS) Setpoint 14% narrow range (NR)

AFW Actuation Delay After AFAS 330 s* AFW Flow Rate (total) 2 electric pumps x 296 gpm / pump AFW Temperature 104°F Note: Reducing the AFW flow to 276 gpm and increasing the AFW temperature to 111.5°F is determined to have insignificant impact on this event analysis.

This maximum AFW actuation delay, which includes time for emergency diesel generator startup and sequencing, was used not only for LOOP cases but also

---as an additional conservatism

---for no-LOOP cases.

Table 15.2.12-4 RCS Depressurization / Pressurizer Overfill: Sequence of Events Event Time (s) Event initiation single pressurizer PORV inadvertently opens 0.0 Pressurizer pressure reaches TM/LP setpoint 60.2 TM/LP signal actuates reactor trip, offsite power is assumed to be lost, MFW is lost, RCPs begin to coast down, turbine trips, and all RCS charging is assumed to begin 61.1 Lowest steam generator (SG) level reaches AFAS setpoint 66.1 MSSVs first open 66.5 Pressurizer pressure reaches SIAS setpoint 107.2 HPSI begins 110.1 AFW flow to SG

-1 and SG-2 begins 396.1 Pressurizer dome becomes liquid

-filled 444.7

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Amendment No.26 (11

/13)

Amendment No.26 (11/13)

This event is essentially a natural circulation cooldown with the secondary side heat sink limited to the initial SG shell side liquid inventory and Auxiliary Feedwater flow provided by the steam turbine-driven AFW pump.

The Reference 117 rnethodology was used with SBO-specific modifications to accommodate the event as defined in References 90, 94, and 96.

1 0 CFR 50.63, "Loss of all alternating current power," requires that a plant be able to withstand a specified duration and recover from a SBO. The specific St. Lucie Unit 1 requirements are provided by NRC Safety Evaluation of Station Blackout (SBO) Rule (References 90 and 96); this analysis addresses Section 2.3.6 "Reactor Coolant Inventory" with the following assumptions:

Best estimate full power conditions No independent equipment failures (other than those associated with the event) occur during the course of the transient.

The previous licensing analysis was based on the RETRAN computer code whereas the analysis supporting the EPU was performed using S-RELAP5.

Changes from the licensing basis presented in References 90, 94, and 96 included:

Higher rated initial core power of 3,020 MWt vs. 2,700 MWt (reflecting the EPU)

Lower RCS leakage flow rate of 60 gpm vs. 120 gpm, due to installation of N9000 RCP seals Credit for flow from one charging pump beginning at one hour, where previously no credit was taken Decay heat based on 100% of the 1973 ANS Standard vs. 105% of the 1979 version Incorporation of blowdown (cleanup) flow from the Steam Generators as part of the initial condition. This blowdown flow is usually stopped by operator action at 20 minutes, but for this analysis, the flow duration is extended to 25 minutes in order to be conservative.

The operator will utilize ADV's to control secondary pressure at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Prior to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the MSSV's will cycle to control secondary pressure. St. Lucie Unit 1 has two ADVs, one on each steam line. It has been assumed that at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the operator starts manual operation of the ADVs to control RCS temperature betwee n 532°F (No-Load temperature) and 540

°F.

The relatively high temperature band (between 532°F and 540°F) chosen for manual ADV control was selected to maintain secondary pressure below the MSSV setpoint and still maintain the RCS pressure high to maximize the RCS leakage.

The total initial RCS leakage flow rate was modeled as 60 gpm. This represents 10 gpm leakage from each RCP seal plus 20 gpm as a combination of identified and unidentified leakage allowed by Technical Specifications. A value of 10 gpm for each RCP seal is a conservatively high allowance for the N9000 RCP seals used at St. Lucie Unit 1. RCP leakage was modeled to decrease with decreasing RCS pressure.

UNIT 1 15.2.13-1a Amendment No. 27A (01/16)

15.2.13.3 Results and Conclusions The results of this analysis are summarized in Table 15.2.13-

3. The transient sequence of events is shown in Table 15.2.13-2, and the transient results are shown in Figure 15.2.13-1 to Figure 15.2.13-

11. RCS leakage follows the same general trend as pressurizer pressure. Opening and closing of the MSSVs provides limited cooling of the RCS for the first hour.

Opening the ADV at one hour produces a sharper drop in RCS temperature and pressure. The operator manually controls the ADV's to control RCS temperature between 532°F and 540°F. RCS leakage decreases to a minimum of approximately 30 gpm at a minimum RCS pressure of approximately 1,000 psia at about 80 minutes. This is less than th e charging flow rate of 40 gpm. The minimum reactor vessel level occurs between 70 and 90 minutes where the level drops slightly below the Support Plate at the top of the Upper Guide Structure (separating the upper head from the upper plenum). With a minimum water level of approximately 29 feet, there is substantial margin to the top of the hot leg nozzles at 18.7 feet.

There is no significant change in RCS temperature, pressure, or power prior to reactor scram, so this event does not challenge the DNBR or FCM SAFDLs.

Significant steam generator liquid mass inventories were retained in both steam generators, so there was adequate mass in the steam generators supplied by AFW to make up for the steam mass lost through the MSSVs and ADVs.

Likewise, the total amount of AFW delivered is well within the initial inventory of the Condensate Storage Tank. Thus, all acceptance criteria are satisfied for this event.

UNIT 1 1 5.2.13-4 Amendment No. 27A (01/16)

Loss of all AC Power: scram 1 turbine trip begin Main Feedwater coastdown begin RCP coastdown begin RCP leak CEA insertion begins 1.5 CEAs fully inserted 4.4 Bank 1 MSSVs in both loops open (begin cycling) 6 SG low level setpoint reached 6.6 Beginning of AFW delivery to SGs 336.6 AFW flow throttled to about half of initial 600 10 SG blowdown flow secured 25 Operators open ADVs (for the first time) 3,600 60 Operator supply power and start one charging pump PZR level off scale low ~65 Upper Head subcooling lost ~

71 Operator closes ADVs (for the first time) ~

81 Minimum level in the reactor vessel ADVs open (for the second time) ~

88 ADVs close (for the second time)

~95 Minimum RCS pressure PZR level recovers (and remains above zero % span) ~

116 AFW flow is (temporarily) stopped (for the first time) ~165 AFW flow resumes ~183 End (power is restored) 14,400 240

UNIT 1 15.2.13-7 Amendment No. 27A (01/16)

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TABLE 15.3.1-1 HPSI FLOW RATE VS. RCS PRESSURE USED IN THE SBLOCA EVENT 15 160.0 151.7 315 137.0 130.0 615 109.0 103.7 815 85.0 81.3 1015 51.0 48.7 1115 16.0 15.3 1125 8.0 5.7 11 29 0.0 0.0

UNIT 1 15.3.1-3b Amendment No. 27 (04/15)

Table 15.3.1-2 CURRENT SBLOCA ANALYSIS PARAMETERS Parameter Current Analysis Value Reactor Power, MWt 3020 + 0.3% measurement uncertainty Peak LHR, kW/ft 15.0 Radial Peaking Factor (1.65 plus uncertainty) 1.749 RCS Flow Rate, gpm 375000 Pressurizer Pressure, psia 2250 Core Inlet Coolant Temperature, °F 551 SIT Pressure, psia 244.7 SIT Fluid Temperature, °F 120 SG Tube Plugging Level, %

10 SG Secondary pressure, psia 830 MFW Temperature, °F 436 AFW Temperature, °F 111.5 Low SG Level AFAS Setpoint, %

5 HPSI Fluid Temperature, °F 104 Charging system delay time, sec 150 Reactor Scram Low Pressurizer Pressure Setpoint, psia 1807 Reactor Scram Delay Time on Low Pressurizer Pressure, sec 0.9 Scram CEA Holding Coil Release Delay Time, sec 0.5 SIAS Activation Setpoint Pressure for harsh conditions, psia 1520 HPSI Pump Delay Time on SIAS, sec 30 MSSV lift pressures Nominal + 3% uncertainty

UNIT 1 15.3.1-3c Amendment No. 27 (04/15)

Amendment No.

2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 27 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

• H K c c 0.61 0. 72 1 l. 03 l. 03 c C-12 C-16 C-12 B-16 0.61 0.77 0.98 1.14 0.93 1.00 1. 06 1. 27 1. 27 1. 05 2 c C-12 B-16 A B-16 A 0. 76 1. 06 0. 94 1. 02 1. 05 1. 04 1.19 1. 21 1. 06 1.12 1.11 1.14 3 c C-12 B-16 A B-16 A B-16 0. 76 1.14 1.02 1. 03 1. 07 1. 07 ' 1. 09 1.19 l. 28 1.09 1.13 l.13 l.18 l.14 4 c C-12 B-16 A B-16 A B-16 A 0.61 l. 06 1.02 1. 05 l. 08 1.09 l.11 l.10 5 1.00 1. 21 1.09 1.15 1.14 1.19 1.16 1. 21 C-12 B-16 A B-16 A B-16 A B-16

• 0. 77 0.94 1. 03 1. 08 1. 09 1.12 1.12 1.13 1. 06 1. 06 1.13 1.14 1. 20 1. 22 1. 22 1.18 C-16 A B-16 A B-16 A B-16 A 6 8 c 0.98 1. 02 1.07 1.09 1.12 1.12 1.14 1.13 1. 27 1.12 1.13 1.19 1.17 1. 23 1.19 1. 24 0.61 7 1.03 C-12 B-16 A B-16 A B-16 A B-16 c-12 1.14 1. 05 l.07 1.11 l.12 1.14 l.13 1.15 1. 27 1.11 1.18 1.16 1. 22 1.19 1. 24 1. 20 0. 72 1. 03 B-16 A B-16 A B-16 A B-16 A A 0. 93 1. 04 1. 09 1.10 1.13 1.13 1.15 1.14 1. 05 1.14 1.14 1. 21 1.18 1. 24 1. 20 1. 24 10 G. -* 9 11 B c D E 17 G J L B-16 Type of Fuel 1. 08 Averaqe Power of Assembly 1.14 Max. Rod Peak in Assembfy

• FLORIDA TyWcal BOL Power Distribution Figure POWER & LIGHT CO. 15.3.3-1 St. Lucie Plant ith Correct Fuel Loading Unit l MAINE YANKEE

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• C-16 .l B-16 .l B-16 J. B-16 .l 0.98 l.O) l.07 l.08 1.08 1.06 1.06 l.OL 7 c l.26 l.lJ l.14 1.18 1.13 l.16 1.10 l.14 o.60 e l.00 C-12 B-16 A B-16 .l B-16 ' B-16 1.10 1.02 l.Ob 1.07 l.o6 l.07 l.OS l.o6 9 C-12 1.2.S 1.08 l.lb 1.12 l.16 l.ll l.lS l.10 0.10 10 1.00 J..16 .l B-16 .l B-16 A B-16 A 0.90 l.00 l.oS l.OS l.07 i.os l.o6 l.OS l.Ol 1.10 1.09 l.lS l.ll l.15 l.10 l.14 11 A I c D I r 0 J L " Type of Fuel ** Average Power of Assembly i. I' Max. Rod Peak in Assembly

• FLORIDA r:igcr POWER & LIGHT CO. Power Distribution for Postulated Interchange St. Lucie Plant of Two C Assemblies 15.3.3-2 Unit l MAINE YANKEE

• *

• H l c C-12 l.11 1.LO 1 l.99 2.02 c C-12 C-16 c B-16 o.64 0.97 l.56 2.11 l.73 l.07 l.42 2.08 2.40 1.88 C-12 C-12 B-16 A B-16 A 0.61 1.02 l.09 l.LO 1.62 0.97 1.22 l.JO 1.66 1.8() l 82 c C-12 B-16 A B-16 A B-16 0.61 0.94 0.94 1.09 1.26 1.36 1.42 0.96 l.09 l.o6 l.22 l.45 l * .SJ 1.58 c C-12 B-16 A B-16 A B-16 A 0.47 0.84 0.84 0.94 l.05 1.14 1.23 l.2L 0.78 0.98 0.93 LC!.. 1.16 1.26 1.)$ l.37 C-12 B-16 A B-16 A B-16 A B-16 0.59 0.74 o.84 0.9J 0.99 1.08 1.11 1.14 c.81 0.84 0.93 l.Cl 1.10 1.17 l.2) C-16 A B-16 A B-16 A B-16 A 0.74 o. 78 o.65 0.91 0.98 l.02 1.07 l.07 c 0.96 0.61 0.92 l.00 l.05 1.12 1.14 1.17 8 0.4.S 0.11 C-12 B-16 A B-16 A B-16 A B-16 o.BS o.eo o.85 0.91 0.95 l.00 1.02 1.04 C-12 0.96 o.86 0.9) 0.97 l.04 1.06 l.12 l.09 10 OS3 0.11 B-16 A B-16 A B-16 A B-16 A o.69 0.79 o.8.5 0.90 0.9.5 0.98 l.02 0.79 0.81 0.91 0.98 1.01 1.08 l.07 l.ll A B c D E , G J L c

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• FLORIDA Power Distribution for Postulated Interchange POWER & LIGHT CO. St. Lucie Plant of an A and C Assembly 15.3.3-4 Unit l MAINE YANKEE

15.4 POSTULATED ACCIDENTS (CLASS 3 ACCIDENTS)

The following events in this class had been reanalyzed for the extended power uprate (3020 MWt) to ensure acceptable consequences.

15.4.1 Major Reactor Coolant System Pipe Break (Loss of Coolant Accident) 15.4.4 Steam Generator Tube Failure

15.4.5 Control Element Assembly Ejection

15.4.6 Steam Line Break Accident

The other events have not changed from the original FSAR submittal. Reanalysis has not been required for these events because:

a) no significant parameters have changed, or b) parameter changes have occurred but have no significance to results, or c) the uprated core power level of 3020 MWth has insignificant effect on the results.

15.4.1 MAJOR REACTOR COOLANT SYSTEM PIPE BREAK (LOSS OF COOLANT ACCIDENT)

For stretch power operation (2700 MWth) this event was analyzed by Combustion Engineering and is

described in Chapter 6. A radiological dose reassessment of the LOCA was not required since the original analysis was performed at an assumed power level of 2700 MWth. The original assessment is presented in Section 15.4.1.8.

15.4.1.1 Identification of Causes*

A major loss of coolant accident (LOCA) is defined as a break in the reactor coolant pressure boundary having an area greater than 0.5 ft

2. Such a break and the consequent coolant loss would result in loss of the normal mechanism for removing heat from the reactor core.

Because of the extreme care taken in design and fabrication of the plant, and because of the periodic testing and in-service inspection required, the probability of a major LOCA is considered to be extremely low. Nevertheless, because of the potential consequences, several important systems identified as engineered safety features have been provided to prevent the clad and fuel from melting, to limit chemical reactions, and to protect the health and safety of the public. These systems, Section 6, are the safety injection system (emergency core cooling system or ECCS) Section 6.3; the containment heat removal systems (containment spray and containment cooling) Section 6.2.2; the containment isolation system, Section 6.2.4; the shield building ventilation system, Section 6.2.3; and hydrogen control system, Section 6.2.5.

The analysis of the LOCA is discussed in Chapter 6. The initial conditions, assumptions, and a step by step sequence of events are an integral part of that discussion. The response of the safety injection system is described in Section 6.3; the response of the remaining containment related engineered safety features is described in Section 6.2

• CE-Analysis prior to Cycle 6

15.4.1-1 Amendment No. 26 (11/13) 15.4.1.2 Reload Safety Analysis 15.4.1.2.1 Introduction This section describes and provides results from a Realistic Large Break LOCA (RLBLOCA) analysis for the Saint Lucie Nuclear Plant Unit I Extended Power Uprate. The uprated reactor core power for the St. Lucie Unit I RLBLOCA is 3029.1 MWt.

This value represents the 10% power uprate and 1.7% measurement uncertainty recapture (MUR) relative to the previously rated thermal power of 2700 MWt plus 0.3% power measurement uncertainty.

The RLBLOCA analysis was perfo rmed with a version of S-RELAP5 that limits the contribution of the Forslu nd-Rohsenow model to no more than 15 percent of the total heat transfer at and above a void fraction of 0.9.

This may result in a slight increase in PCT results when compared to previous analyses for similar plants.

In concurrence with the NRC's interpretation of GDC 35, a set of 59 cases was run with a Loss of Offsite Power (LOOP) assumption and a second set was run with No-LOOP assumption to search for the limiting PCT case.

The results from both case sets are shown in Figure 15.4.1-

27. 15.4.1.2.2 Summary of Parameters The summary of major parameters for the limiting PCT case is shown in Table 15.4.1-lc.

15.4.1.2.3 Large Break LOCA Analysis The purpose of the analysis is to verify typical technical specification peaking factor limits and the adequacy of the ECCS by demonstrating that the following 10 CFR 50.46(b) criteria in Reference 1 are met:(1) The calculated maximum fuel element cladding temperature shall not exceed 2200°F.

(2) The calculated total oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation.

(3) The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel excluding the cladding surrounding the plenum volume were to react. (4) The calculated changes in core geometry shall be such that the core remains amenable to cooling. (5) Long-term cooling is not addressed in this calculation.

The analysis did not evaluate core coolability due to seismic events, nor did it consider the I 0 CFR 50.46(b) long-term cooling criterion.

15.4.1.2.3.1 LBLOCA Event Description A LBLOCA is initiated by a postulated large rupture of the reactor coolant system (RCS) primary piping. Based on deterministic studies, the worst break location is in the cold leg piping between the reactor coolant pump and the reactor vessel for the RCS loop containing the pressurizer. The break initiates a

15.4.1-2 Amendment No. 26 (11/13)

rapid depressurization of the RCS. A reactor trip signal is initiated when the low pressurizer pressure trip setpoint is reached; however, reactor trip is conservatively neglected in the LBLOCA analysis.

The reactor is shut down by coolant voiding in the core.

The plant is assumed to be operating normally at full power prior to the accident. The cold leg break is assumed to open instantaneously. For this break, a rapid depressurization occurs, along with a core flow stagnation and reversal. This causes the fuel rods to experience departure from nucleate boiling (DNB).

Subsequently, the limiting fuel rods are cooled by fi lm convection to steam. The coolant voiding creates a strong negative reactivity effect and core criticality ends. As heat transfer from the fuel rods is reduced, the cladding temperature increases.

Coolant in all regions of the RCS begins to flash. At the break plane, the loss of subcooling in the coolant results in substantially reduced break flow. This reduces the depressurization rate, and leads to a period of positive core flow or reduced downflow as the RCPs in the intact loops continue to supply water to the RV (in No-LOOP condition). Cladding temperatures may be reduced and some portions of the core may rewet during this period. The positive core flow or reduced downflow period ends as two phase conditions occur in the RCPs, reducing their effectiveness. Once again, the core flow reverses as most of the vessel mass flows out through the broken cold leg.

Mitigation of the LBLOCA begins when the safety injection actuation signal (SIAS) is issued. This signal is initiated by either high containment pressure or low pressurizer pressure. Regulations require that a worst single failure be considered. This single failure has been determined to be the loss of one ECCS pumped injection train. The AREVA Realistic Large Break LOCA (RLBLOCA) methodology conservatively assumes an on-time start and normal lineups of the containment spray to conservatively reduce containment pressure and increase break flow. Hence, the analysis assumes that the loss of a diesel generator, which takes one train of ECCS pumped injection out. LPSI injects into the broken loop and one intact loop, HPSI injects into all four loops, and all containment spray pumps are operating.

When the RCS pressure falls below the SIT (Safety Injection Tank) pressure, fluid from the SITs is injected into the cold legs.

In the early delivery of SIT water, high pressure and high break flow will drive some of this fluid to bypass the core. During this bypass period, core heat transfer remains poor and fuel rod cladding temperatures increase. As RCS and containment pressures equilibrate, ECCS water begins to fill the lower plenum and eventually the lower portions of the core; thus, core heat transfer improves and cladding temperatures decrease.

Eventually, the relatively large volume of SIT water is exhausted and core recovery continues relying solely on pumped ECCS injection. As the SITs empty, the nitrogen gas used to pressurize the SITs exits through the break. This gas release may result in a short period of improved core heat transfer as the nitrogen gas displaces water in the downcomer. After the nitrogen gas has been expelled, the ECCS temporarily may not be able to sustain full core cooling because of the core decay heat and the higher steam temperatures created by quenching in the lower portions of the core. Peak fuel rod cladding temperatures may increase for a short period until more energy is removed from the core by the HPSI and LPSI while the decay heat continues to fall. Steam generated from fuel rod rewet will entrain liquid and pass through the core, vessel upper plenum, the hot legs, the steam generators, and the reactor coolant pumps before it is vented out the break. Some steam flow to the upper head and pass through the spray nozzles, which provide a vent path to the break. The resistance of this flow path to the steam flow is balanced by the driving force of water filling the downcomer. This resistance may act to retard the progression of the core reflood and postpone core-wide cooling.

Eventually (within a few minutes of the accident), the core reflood will progress sufficiently to ensure core-wide coolin

g. Full core quench occurs within a few minutes after core-wide cooling. Long term cooling is then sustained with LPSI pumped injection system.

15.4.1-2a Amendment No. 26 (11/13) 15.4.1.2.3.2 Description of Analytical Models The RLBLOCA methodology is documented in EMF-2103 Realistic Large Break LOCA Methodology (Reference 2).

The methodology follows the Code Scaling, Applicability, and Uncertainty (CSAU) evaluation approach (Reference 3).

This method outlines an approach for defining and qualifying a best estimate thermal hydraulic code and quantifies the uncertainties in a LOCA analysis.

The RLBLOCA methodology employs the following computer codes:

RODEX3A for computation of the initial fuel stored energy, fission gas release, and fuel claddi ng gap conductance.

S-RELAP5 for the system calculation (includes ICECON for containment response).

AUTORLBLOCA for generation of ranged parameter values, transient input, transient runs, and general output documentation.

NRC Information Notice 2009-23 (Reference 4) describes an issue concerning the ability of thermal-mechanical fuel modeling codes (such as RODEX3A) to accurately predict the exposure-dependent degradation of fuel thermal conductivity. To address this issue, the analytical model applies a conservative bias as an adjustment to the calculation of fuel thermal conductivity and centerline temperature. In addition, to better follow the fuel throughout its operational life, the analytical method has been updated to specifically model both first (i.e., fresh) and second cycle (i.e., once-burned) fuel rods. The third cycle fuel does not retain sufficient energy to achieve either significant cladding temperatures or cladding oxidation and so is not explicitly modeled. This approach has been approved by the NRC for St. Lucie Unit 1.

The governing two fluid (plus non-condensibles) model with conservation equations for mass, energy, and momentum transfer is used. The reactor core is modeled in S-RELAP5 with heat generation rates determined from reactor kinetics equations (point kinetics) with reactivity feedback, and with actinide and decay heating. The two fluid formulation uses a separate set of conservation equations and constitutive relations for each phase. The effects of one phase on the other are accounted for by interfacial friction, and heat and mass transfer interaction terms in the equations. The conservation equations have the same form for each phase; only the constitutive relations and physical properties differ. The modeling of plant components is performed by following guidelines developed to ensure accurate accounting for physical dimensions and that the dominant phenomena expected during the LBLOCA event are captured.

The basic building blocks for modeling are hydraulic volumes for fluid paths and heat structures for heat transfer. In addition, special purpose components exist to represent specific components such as the RCPs or the steam generator separators. All geometries are modeled at the resolution necessary to best resolve the flow field and the phenomena being modeled within practical computational limitations.

A steady state conditions is established with all loops intact. The input parameters and initial conditions for this steady state calculation are chosen to reflect plant technical specifications or to match measured data. Following the establishment of an acceptable steady state condition, the transient calculation is initiated by introducing a break into the loop containing the pressurizer. The evolution of the transient through blowdown, refill and reflood is computed continuously using S-RELAP5. Containment pressure is also calculated by S-RELAP5 using containment models derived from ICECON (Reference 5), which

15.4.1-2b Amendment No. 26 (11/13) is based on the CONTEMPT-LT code (Reference 6) and has been updated for modeling ice condenser containments. The methods used in the application of S-RELAP5 to the LBLOCA are described in Reference 2.

15.4.1.2.3.3 Plant Description and Summary of Analysis Parameters

St. Lucie Unit 1 is a CE-designed PWR, which has two hot legs, two U-tube steam generators, and four cold legs with one RCP in each cold leg. The plant uses a large dry containment. The RCS includes one Pressurizer connected to a hot leg. The core contains 217 thermal hydraulic compatible AREVA HTP 14Xl4 fuel assemblies with 2, 4, 6 and 8 w/o gadolinia pins.

The ECCS includes one HPSI, one LPSI and one SIT injection path per RCS loop. The break is modeled in the same loop as the pressurizer, as directed by the RLBLOCA methodology. The RLBLOCA transients are of sufficiently short duration that the switchover to sump cooling water for ECCS pumped injection need not be considered.

The S-RELAP5 model explicitly describes the RCS, RV, pressurizer, and ECCS.

The ECCS includes a SIT path and a LPSI/HPSJ path per RCS loop. The HPSI and LPSI feed into a common header that connects to each cold leg pipe downstream of the RCP discharge. The ECCS pumped injection is modeled as a table of flow versus backpressure. Applying the worst single failure of one emergency diesel generator affects the ECCS pumped injection systems available, injection location, and pumped ECCS flow. A table of flow versus backpressure also describes the secondary side steam generator that is instantaneously isolated (closed MSIV and feedwater trip) at the time of the break.

A symmetric steam generator tube plugging level of I 0 percent per steam generator was assumed.

As described in the AREV A RLBLOCA methodology, many parameters associated with LBLOCA phenomenological uncertainties and plant operation ranges are sampled. A summary of those parameters is given in Table 15.4.1-

1. The LBLOCA phenomenological uncertainties are provided in Reference 2.

Values for process or operational parameters, including ranges of sampled process parameters, and fuel design parameters used in the analysis are given in Table 15.4.1-1

a. Plant data are analyzed to develop uncertainties for the process parameters sampled in the analysis. Table 15.4.1-1 b presents a summary of the uncertainties used in the analysis. Where applicable, the sampled parameter ranges are based on technical specification limits or supporting plant calculations that provide more bounding values.

For the AREVA NP RLBLOCA EM, dominant containment parameters, as well as NSSS parameters, were established via a PIRT process. Other model inputs are generally taken as nominal or conservatively biased.

The PIRT outcome yielded two important (relative to PCT) containm ent parameters--containment pressure and temperature. As noted in Table 15.4.1-1b, containment temperature is a sampled parameter. Containment pressure response is indirectly ranged by sampling the containment volume (Table 15.4.1-1b). Containm ent heat sink data is given in Table 15.4.1-1 f. The containment initial conditions and boundary conditions are given in Table 15.4.1-1

g. The building spray is modeled at maximum heat removal capacity. All spray flow is delivered to the containm ent.

15.4.1.2.3.4 LBLOCA Results

Two case sets of 59 transient calculations were performed by sampling the parameters listed in Table 15.4.1-1. For each case set, a PCT was calculated for a UO 2 rod and for Gadolinia-bearing rods with concentrations of 2, 4, 6 and 8 w/o Gd 2 O 3. Both fresh and once-burnt fuel are considered. The limiting case set, containing the highest PCT, corresponds to that with no offsite power available.

A limiting PCT of 1 788°F appears in Case 23 for a UO 2 rod in a fresh bundle. The major parameters for the limiting transient are summarized in Table 15.4.1-1c. Table 15.4.1-1d summarizes the results of the limiting case.

The fraction of total hydrogen generated was not directly calculated; however, it is conservatively bounded by the calculated total percent oxidation, which is well below the 1 percent limit.

UNIT 1 15.4.1-2c Amendment No. 27 (04/15)

The case results, event times and analysis plots for the limiting PCT case arc shown in Table

15.4.1-1 d, Table 15.4.1-1e, and in Figure 15.4.1-6 through Figure 15.4.1-26. Figure 15.4.1-1 shows linear scatter plots of the key parameters sampled from the 59 calculations. Parameter labels appear to the left of each individual plot. These figures show the parameter ranges used in the analysis.

Figure 15.4.1-2 and Figure 15.4.1-3 show PCT versus PCT time scatter plot and PCT versus break size scatter plot from the 59 calculations, respectively. Figure 15.4.1-4 and Figure 15.4.1-5 show the maximum oxidation and total oxidation versus PCT scatter plots from the 59 calculations, respectively.

Key parameters for the limiting PCT case are shown in Figure 15.4.1-6 through Figure 15.4.1-

16. Additional information from the limiting PCT case is presented in Figure 15.4.1-17 through Figure

15.4.1-26. Figur e 15.4.1-6 is the plot of PCT (independent of elevation) versus time for the limiting case; this figure clearly indicates that the transient exhibits a sustained and stable quench. A comparison of PCT results between the LOOP and no-LOOP case sets is shown in Figure 15.4.1-

27. As seen in Figure 15.4.1-27, the peak PCT is from a limiting LOOP case.

15.4.1.2.4 Conclusions A RLBLOCA analysis was performed for the St Lucie Nuclear Plant Unit 1 using NRC-approved AREVA NP RLBLOCA methods (Reference 2). Analysis results show that a LOOP case is limiting and has a PCT of 1 788°F and a maximum oxidation thickness and hydrogen generation that fall well within regulatory requirements.

The analysis supports operation at a nominal power level of 3029.1 MWt (including 0.3% uncertainty),

a steam generator tube plugging level of up to 10 percent in all steam generators, a total LHGR of 15.0 kW/ft, a total peaking factor (F Q) up to a value of 2.161, and a nuclear enthalpy rise factor (FH) up to a value of 1.

810 (including 6% measurement uncertainty and 3.5% allowance for control rod insertion effect) with no axial or bumup dependent power peaking limit and peak rod average exposures of up to 62,000 MWd/MTU. For a large break LOCA, the three 10 CFR 50.46 (b) criteria presented in Section 15.4.1.2.3 are met and operation of St. Lucie Unit 1 with AREVA NP-supplied 14xl4 M5 cladding fuel is justified.

UNIT 1 15.4.1-3 Amendment No. 27 (04/15) 15.4.1.

2.5 REFERENCES

for Section 15.4.1.2

1. Title 10, Code of Federal Regulations, Part 50, Section 50.46, "Acceptance Criteria for Emergency Core Cooling Systems for Light Water Nuclear Power Reactors." 2. EMF-2103(P)(A) Revision 0, Realistic Large Break LOCA Methodology, Framatome ANP, Inc., April2003.

3. Technical Program Group, Quantifying Reactor Safety Margins, NUREG/CR-5249, EGG-2552, October 1989.

4. U.S. Nuclear Regulatory Commission, Information Notice 2009-23, ML091550527, "Nuclear Fuel Thermal Conductivity Degradation," October 8, 2009.

5. XN-CC-39 (A) Revision 1, "ICECON: A Computer Program to Calculate Containment Back Pressure for LOCA Analysis (Including Ice Condenser Plants)," Exxon Nuclear Company, October 1978. 6. Wheat, Larry L., "CONTEMPT-LT A Computer Program for Predicting Containment Pressure Temperature Response to a Loss-Of-Coolant-Accident, "Aerojet Nuclear Company, TID-4500, ANCR-1219, June 1975.

7. U. S. Nuclear Regulatory Commission, NUREG-0800, Revision 3, Standard Review Plan, March 2007.

15.4.1-3a Amendment No. 26 (11/13)

SECTIONS 15.4.1.3 AND 15.4.1.4 HAVE BEEN INTENTIONALLY DELETED

15.4.1-4 Am. 11-7/92

PAGE INTENTIONALLY BLANK

15.4.1-4a Amendment No. 26 (11/13)

15.4.1.5 Radiological Consequences 15.4.1.5.1 Background

This event is assumed to be caused by an abrupt failure of the main reactor coolant pipe and the ECCS fails to prevent the core from experiencing significant degradation (i.e., melting). This sequence cannot occur unless there are multiple failures, and thus goes beyond the typical design basis accident that considers a single active failure. Activity is released from the containment and from there, released to the environment by means of containment leakage and leakage from the ECCS. The St. Lucie Unit 1 AST dose analysis methodology is presented in Reference 107.

15.4.1.5.2 Compliance with RG 1.183 Regulatory Positions

The revised LOCA dose consequence analysis is consistent with the guidance provided in RG 1.183, Appendix A, "Assumptions for Evaluating the Radiological Consequences of a LWR Loss-of-Coolant Accident," as discussed below:

1. Regulatory Position 1 - The total core inventory of the radionuclide groups utilized for determining the source term for this event is based on RG 1.183, Regulatory Position 3.1, at 100.3% of core thermal power and is provided in Table 15.4.1-1e. The core inventory release fractions for the gap release and early in-vessel damage phases of the LOCA are consistent with Regulatory Position 3.2 and Table 2 of RG 1.183.

2. Regulatory Position 2 - Per Section 6.2.6.1, the long term recirculation sump pH remains greater than 7.0. Therefore, the chemical form of the radioiodine released to the containment is assumed to be 95% cesium iodide (CsI), 4.85% elemental iodine, and 0.15% organic iodide. With the exception of elemental and organic iodine and noble gases, fission products are assumed to be in particulate form.

3. Regulatory Position 3.1 - The activity released from the fuel is assumed to mix instantaneously and homogeneously throughout the free air volume of the containment. The release into the containment is assumed to terminate at the end of the early in-vessel phase.

4. Regulatory Position 3.2 - Reduction of the airborne radioactivity in the containment by natural deposition is credited. A natural deposition removal coefficient for elemental iodine is calculated per SRP 6.5.2 as 2.89 hr

-1. This removal is credited in both the sprayed and unsprayed regions of containment. A natural deposition removal coefficient of 0.1 hr

-1 is assumed for all aerosols in the unsprayed region of containment as well as in the sprayed region after spray is terminat ed at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. No removal of organic iodine by natural deposition is assumed.

5. Regulatory Position 3.3 - Containment spray provides coverage to 86% of the containment. Therefore, the St. Lucie Unit 1 containment building atmosphere is not considered to be a single, well-mixed volume. A mixing rate of two turnovers of the unsprayed region per hour is assumed.

The maximum decontamination factor (DF) for the elemental iodine spray removal coefficient is 200 based on the maximum airborne elemental iodine concentration in the containment. Based upon the conservatively assumed elemental iodine removal rate of 20 hr

-1, the DF of 200 is computed to occur at 2.331 hours0.00383 days <br />0.0919 hours <br />5.472884e-4 weeks <br />1.259455e-4 months <br />. In addition, the particulate iodine removal rate is reduced by a factor of 10 when a DF of 50 is reached. Based upon the calculated iodine aerosol removal rate of 6.07 hr-1 , the DF of 50 is conservatively computed to occur at 2.334 hours0.00387 days <br />0.0928 hours <br />5.522487e-4 weeks <br />1.27087e-4 months <br />.

15.4.1-5 Amendment No. 26 (11/13)

6. Regulatory Position 3.4 - Reduction in airborne radioactivity in the containment by filter recirculation systems is not assumed in this analysis.

7. Regulatory Position 3.5 - This position relates to suppression pool scrubbing in BWRs, which is not applicable to St. Lucie Unit No. 1.

8. Regulatory Position 3.6 - This position relates to activity retention in ice condensers, which is n ot applicable to St. Lucie Unit No. 1.

9. Regulatory Position 3.7 - A containment leak rate of 0.5 Vol. % per day of the containment air is assumed for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. After 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the containment leak rate is reduced to 0.25 Vol.

% per day of the containment air.

10. Regulatory Position 3.8 - 100% of the radionuclide inventory of the RCS is released instantaneously at the beginning of the event. The containment purge flow is 500 cfm and is assumed to be isolated after 30 seconds. No filters are credited.

11. Regulatory Position 4.1 - Leakage from containment collected by the secondary containment is processed by ESF filters prior to an assumed ground level release.

12. Regulatory Position 4.2 - Leakage into the secondary containment is assumed to be released directly to the environment as a ground level release prior to drawdown of the secondary containment at 310 seconds.

13. Regulatory Position 4.3 - SBVS is credited as being capable of maintaining the Shield Building Annulus at a negative pressure with respect to the outside environment considering the effect of high windspeeds and LOCA heat effects on the annulus as described in Section 6.2. No exfiltration through the concrete wall of the Shield Building is expected to occur.

14. Regulatory Position 4.4 - No credit is taken for dilution in the secondary containment volume.

15. Regulatory Position 4.5 - 9.6% of the primary containment leakage is assumed to bypass the secondary containment. This bypass leakage is released as a ground level release without credit for filtration.

16. Regulatory Position 4.6 - The SBVS is credited as meeting the requirements of RG 1.52 and Generic Letter 99-02. The filters in the SBVS ventilation system are credited at 99% efficiency for particulates and 95% for both elemental and organic iodine.

17. Regulatory Position 5.1 - Engineered Safety Feature (ESF) systems that recirculate water outside the primary containment are assumed to leak during their intended operation. With the exception of noble gases, all fission products released from the fuel to the containment are assumed to instantaneously and homogeneously mix in the containment sump water at the time of release from the core.

18. Regulatory Position 5.2 - Leakage from the ESF system is greater than two times the value identified in UFSAR Table 15.4.1-2 for pump seals and valve stems in the ECCS area. The leakage is assumed to start at the earliest time the recirculation flow occurs in these systems and continue for the 30-day duration. Backleakage to the RWT is also considered separately as two times 1 gpm, which is the bounding value based upon RCS leakage monitoring documented in the Control Room database. RWT leakage is assumed to begin at the start of recirculation and continue for the remainder of the 30-day duration.

15.4.1-6 Amendment No. 26 (11/13)

19. Regulatory Position 5.3 - With the exception of iodine, all radioactive materials in the recirculating liquid are assumed to be retained in the liquid phase.

20. Regulatory Position 5.4 - A flashing fraction of 7.5% was calculated based upon the sump temperature at the time of recirculation. However, consistent with Regulatory Position 5.5, the flashing fraction for ECCS leakage is assumed to be 10%. This ECCS leakage enters the Reactor Auxiliary Building. For ECCS leakage back to the RWT, the analysis demonstrates that the temperature of the leaked fluid will cool below 212F prior to release into the tank.

21. Regulatory Position 5.5 - The amount of iodine that becomes airborne is conservatively assumed to be 10% of the total iodine activity in the leaked fluid for the ECCS leakage entering the Reactor Auxiliary Building. For the ECCS leakage back to the RWT, the sump and RWT pH history and temperature are used to evaluate the amount of iodine that enters the RWT air space.

22. Regulatory Position 5.6 - For ECCS leakage into the Reactor Auxiliary Building, the form of the released iodine is 97% elemental and 3% organic. An ECCS area ventilation system filter efficiency of 95% is assumed for both elemental and organic iodine. The ECCS area ventilation system meets the requirements of RG 1.52 and Generic Letter 99-

02. There is no credit for hold-up or dilution in the Reactor Auxiliary Building. The temperature and pH history of the sump and RWT are considered in determining the radioiodine available for release and the chemical form. Credit is taken for dilution of the activity in the RWT.

23. Regulatory Position 6 - This position relates to MSIV leakage in BWRs, which is not applicable to St. Lucie Unit 1.

24. Regulatory Position 7 - Containment purge is not considered as a means of combustible gas or pressure control in this analysis; however, the effect of containment purge before isolation is considered.

15.4.1.5.3 Methodology

Input assumptions used in the dose consequence analysis of a LOCA are provided in Table 15.4.1-

6. For the purposes of the LOCA analyses, a major LOCA is defined as a rupture of the RCS piping, including the double-ended rupture of the largest piping in the RCS, or of any line connected to that system up to the first closed valve. Should a major break occur, depressurization of the RCS results in a pressure decrease in the pressurizer. A reactor trip signal occurs when the pressurizer low-pressure trip setpoint is reached. A SIS signal is actuated when the appropriate setpoint (high containment pressure) is reached. The following measures will limit the consequences of the accident in two ways:

1. Reactor trip and borated water injection complement void formation in causing rapid reduction of power to a residual level corresponding to fission product decay heat, and

2. Injection of borated water provides heat transfer from the core and prevents excessive cladding temperatures.

15.4.1-7 Amendment No. 24 (06/10)

Release Inputs The core inventory of the radionuclide groups utilized for this event is based on RG 1.183, Regulatory Position 3.1, at 10 0.3% of core thermal power and is provided as Table 15.

4.1-1e. The source term represents end of cycle conditions assuming enveloping initial fuel enrichment and an average core burnup of 49,000 MWD/MTU.

From Technical Specification (TS) Surveillance Requirement 3.6.1.1, the initial leakage rate from containment is 0.5% of the containment air per day. Per RG 1.183, Regulatory Position 3.7, the primary containment leakage rate is reduced by 50% at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the LOCA to 0.25% /day based on the post-LOCA primary containment pressure history. The majority of the leakage is released through the plant stack via the SBVS. 9.6% if the total leakage is assumed to bypass the SBVS filters and is modeled as a release from a feedwater line penetration.

The ESF leakage to the Reactor Auxiliary Building is assumed to be 4 750 cc/hr based upon two times the current licensing basis value of 2 375 cc/hr. The leakage is conservatively assumed to start at 24 minutes into the event and continue throughout the 30-day period. This portion of the analysis assumes that 10% of the total iodine is released from the leaked liquid. The form of the released iodine is 97% elemental and 3% organic. Dilution and holdup of the ECCS leakage in the Reactor Auxiliary Building are not credited.

The ECCS backleakage to the RWT is initially assumed to be 2 gpm based upon doubling the current bounding value of 1 gpm. Th is leakage is assumed to start at 24 minutes into the event when recirculation starts and continue throughout the 30-day period. Based on sump pH history, the iodine in the sump solution is assumed to all be nonvolatile. However, when introduced into the acidic solution of the RWT inventory, there is a potential for the particulate iodine to convert into the elemental form. The fraction of the total iodine in the RWT which becomes elemental i s both a function of the RWT pH and the total iodine concentration. The amount of elemental iodine in the RWT fluid which then enters the RWT air space is a function of the temperature-dependent iodine partition coefficient.

The time-dependent concentration of the total iodine in the RWT (including stable iodine) was determined from the tank liquid volume and leak rate. This iodine concentration ranged from a minimum value of 0 at the beginning of the event to a maximum value of 4.07E-05 gm-atom/liter at 30 days. Based upon the backleakage of sump water, the RWT pH slowly increases from an initial value of 4.5 to a maximum pH of 4.968 at 30 days. Using the time-dependent RWT pH and the total iodine concentration in the RWT liquid space, the amount of iodine converted to the elemental form was determined using guidance provided in NUREG/CR-5950 (Reference 105). This RWT elemental iodine fraction ranged from 0 at the beginning of the event to a maximum of 0.173.

The elemental iodine in the liquid region of the RWT is assumed to become volatile and to partition between the liquid and vapor space in the RWT based upon the partition coefficient for elemental iodine as presented in NUREG/CR-5950. A GOTHIC model was used to determine the RWT temperature as a function of time which was then used to calculate the partition coefficient. The RWT is a vented tank; therefore, there will be no pressure transient in the air region that would affect the partition coefficient. Since no boiling occurs in the RWT, the release of the activity from the vapor space within the RWT is calculated based upon the displacement of air by the incoming leakage. The elemental iodine flow rate from the RWT is equal to the air flow rate times the elemental iodine concentration in the RWT vapor space.

For the organic iodine flow, the same approach was used with an organic iodine fraction of 0.0015 from RG 1.183 in combination with a partition coefficient of 1.0. The particulate portion of the leakage is assumed to be retained in the liquid phase of the RWT. Therefore, the total iodine flow is the sum of the elemental and organic iodine flow rates.

15.4.1-8 Amendment N

o. 26 (11/13)

The time dependent iodine release rate to the RWT vapor space presented in Table 15.4.1-8a is then applied to the entire iodine inventory (particulate, elemental and organic) in the containment sump.

The iodine released via the RWT air vent to the environment Table 15.4.1-8b was effectively set to 100% elemental (the control room filters have the same efficiency for all forms of iodine).

Containment purge is also assumed coincident with the beginning of the LOCA. The Hydrogen Purge system is manually isolated within 285 seconds of the beginning of the event. The initial RCS activity (at an assumed 1.0 microcuries per gram DE I-131 and 518.9µCi/gm DE XE-133 microcuries per gram gross activity) and fuel/gap release activity is modeled for 285 seconds at 500 cfm until isolation occurs.

Transport Inputs

During the LOCA event, the initial containment purge is released through the plant stack with no filtration. Leakage into the secondary containment is assumed to be released directly to the environment as a ground level release prior to drawdown of the secondary containment at 310 seconds. Activity subsequently collected by the SBVS is assumed to be a filtered release from the plant stack with a filter efficiency of 99% for particulates and 95% for both elemental and organic iodine. The activity that bypasses the SBVS is released unfiltered to the environment via a ground level release from containment. ECCS leakage into the Auxiliary Building is modeled as a release via

the Reactor Auxiliary Building. For this release path, the ECCS area ventilation system is credited with a particulate removal efficiency of 99% and elemental and organic iodine efficiencies of 95%.

The activity from the RWT is modeled as an unfiltered ground level release from the RWT.

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

Initially the ventilation system is assumed to be operating in normal mode. The air flow distribution during this mode is 920 cfm of unfiltered fresh air and an assumed value of 460 cfm of unfiltered inleakage.

After the start of the event, the Control Room is isolated due to a CIAS as a result of a high containment pressure signal. A 50-second delay is applied to account for the time to reach the signal, the diesel generator start time, damper actuation time. After isolation, the air flow distribution consists of 0 cfm of makeup flow from the outside, 460 cfm of unfiltered inleakage, and 1760 cfm of filtered recirculation flow.

At 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> into the event, the operators are assumed to initiate makeup flow from the outside to the control room. During this operational mode, the air flow distribution consists of up to 504 cfm of filtered makeup flow, 460 cfm of unfiltered inleakage, and 1256 cfm of filtered recirculation flow.

The Control Room ventilation filter efficiencies that are applied to the filtered makeup and recirculation flows are 99% for particulate, 95% elemental iodine, and 95% organic iodine.

LOCA Removal Inputs Reduction of the airborne radioactivity in the containment by natural deposition is credited. The natural deposition removal coefficient for elemental iodine is calculated per SRP 6.5.2 as 2.89 hr

-1. A natural deposition removal coefficient of 0.1 hr

-1 is assumed for all aerosols in the unsprayed region and in the sprayed region after spray flow is secured at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. No removal of organic iodine by natural deposition is assumed.

Containment spray provides coverage to 86% of the containment. Therefore, the St. Lucie Unit 1

15.4.1-9 Amendment No. 26 (11/13)

containment building atmosphere is not considered to be a single, well-mixed volume. A mixing rate of two turnovers of the unsprayed region per hour is assumed.

The elemental spray coefficient is limited to 20 hr

-1 per SRP 6.5.2. This coefficient is reduced to 0 when an elemental decontamination factor (DF) of 200 is reached. Based upon the elemental iodine removal rate of 20 hr

-1, the DF of 200 is conservatively computed to occur at 2.331 hours0.00383 days <br />0.0919 hours <br />5.472884e-4 weeks <br />1.259455e-4 months <br />. The particulate iodine removal rate is reduced by a factor of 10 when a DF of 50 is reached. Based upon the calculated iodine aerosol removal rate of 6.07 hr-1, the DF of 50 is conservatively computed to occur at 2.

334 hours0.00387 days <br />0.0928 hours <br />5.522487e-4 weeks <br />1.27087e-4 months <br />.

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

When the Control Room Ventilation System is in normal mode, the most limiting /Q corresponds to the worst air intake to the control room. When the ventilation system is isolated at 50 seconds, the limiting /Q corresponds to the midpoint between the two control room air intakes. The operators are assumed to reopen the most favorable air intake at 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Development of control room atmospheric dispersion factors is discussed in Appendix 2J. The /Qs for the LOCA releases are summarized in Table 15.4.1-

10.

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

The radiological consequences of the design basis LOCA are analyzed using the RADTRAD-NAI code and the inputs/assumptions previously discussed. In addition, the MicroShield code, Version 5.05, Grove Engineering, is used to develop direct shine doses to the Control Room. MicroShield is a point kernel integration code used for general-purpose gamma shielding analysis.

The post accident doses are the result of five distinct activity releases:

Containment Purge at event initiation.

Containment leakage via the SBVS.

Containment leakage which bypasses the SBVS.

ESF system leakage into the Reactor Auxiliary Building.

ESF system leakage into the RWT.

The dose to the Control Room occupants includes terms for:

1. Contamination of the Control Room atmosphere by intake and infiltration of radioactive material from the containment and ESF.

2. External radioactive plume shine contribution from the containment and ESF leakage releases. This term takes credit for Control Room structural shielding.

15.4.1-10 Amendment No. 26 (11/13)

3.

term takes credit for both Containment and Control Room structural shielding.

4. A direct shine dose contribution from the activity collected on the Control Room ventilation filters.

As shown in Table 15.4.1-11, the sum of the results of all dose contributions for EAB dose, LPZ dose, and Control Room dose are all within the appropriate regulatory acceptance criteria.

15.4.1-11 Amendment No. 24 (06/10)

15.4.1.6 Hydrogen Accumulation in Containment A hydrogen control system consisting of hydrogen recombiner, hydrogen purge system and a hydrogen sampling system, is included in the plant design to prevent excessive hydrogen buildup following a LOCA. The use of hydrogen recombination allows control of hydrogen buildup without any release to the environment. The hydrogen purge system is provided as a backup to the recombiner.

The results of an analysis of hydrogen accumulation in the containment following a major LOCA, show that hydrogen can be controlled by recombination or purging. These systems described in Section 6.2.5, will be used to maintain the maximum hydrogen volumetric concentration at or below 4 percent. The lower flammability limit for hydrogen in air saturated with water vapor at room temperature and atmospheric pressure is 4.1 volume percent (References 37, 38, and 39). For these conditions, a concentration of approximately 18- 19 percent is required for detonation.

These systems allow considerable operational flexibility. The specific mode of operation would be determined by the actual hydrogen generation rate, the hydrogen concentration in the containment atmosphere, the amount of airborne activity in the containment, and the prevailing meteorological conditions.

15.4.1-12 Amendment No. 24 (06/10)

15.4.1.7 Effect of Replacement Steam Generators The replacement steam generators (RSGs) have no effect on the blowdown phase of a LBLOCA because small variations in steam generator parameters have an insignificant effect on the blowdown rate, which is driven by critical flow through the break. The RSGs have no affect on the adiabatic heatup phase of the transient because the rate of clad temperature heatup is a function of core decay heat and the duration of the phase is a function of ECCS flow rates. The RSGs, with 25 percent tube plugging (18 percent plus 7 percent plugging asymmetry), have a lower flow resistance than the model of the original steam generator, with 32 percent tube plugging, that was used in the LBLOCA analyses. Consequently, the PCTs calculated using the current evaluation model remain bounding with the RSGs. Because cladding temperatures calculated by the current evaluation model are bounding, so are the local and whole-core cladding oxidations. Likewise, the conclusions in the UFSAR regarding maintenance of core cooling remain valid.

15.4.1-13 Amendment No. 24 (06/10)

TABLE 15.4.1-1 SAMPLED LBLOCA PARAMETERS Phenomenological Time in cycle (peaking factors, axial shape, rod properties and burnup)

Break Type (guillotine versus split)

Critical flow discharge coefficients (break)

Decay heat 1 Critical flow discharge coefficients (surgeline)

Initial upper head temperature Film boiling heat transfer Dispersed film boiling heat transfer Critical heat flux Tmin (intersection of film and transition boiling)

Initial stored energy Downcomer hot wall effects Steam generator interfacial drag Condenser interphase heat transfer Metal-water reaction Plant 2 Offsite power availability 3 Break Size Pressurizer Pressure Pressurizer liquid level SIT pressure SIT liquid level SIT temperature (based on containment temperature)

Containment temperature Containment volume Initial RCS flow rate Initial operating RCS temperature Diesel start (for loss of offsite power only)

_______________________________

_ 1 Not sampled in analysis, multiplier set to 1.0. 2 Uncertainties for plant parameters are based on plant-specific values with the exception of which is binary result that is specified by the analysis methodology. 3 This is no longer a sampled parameter. One set of 59 cases is run with LOOP and one set of 59 cases is run with no-LOOP. 15.4.1-14 Amendment No. 26 (11/13)

TABLE 15.4.1-1a PLANT OPERATING RANGE SUPPORT ED BY THE LOCA ANALYSIS EVENT OPERATING RANGE 1.0 PLANT PHYSICAL DESCRIPTION a) 1.1 Fuel b) a) Cladding outside diameter c) b) Cladding inside diameter d) c) Cladding thickness e) d) Pellet outside diameter f) e) Pellet density g) f) Active fuel length h) g) Gd 2 O 3 concentrations 0.440 in. 0.384 in. 0.028 in. 0.377 in. 95.35 percent of theoretical 136.7 in. 2, 4, 6, 8 w/o 1.2 RCS a) Flow resistance b) Pressurizer location c) Hot assembly location d) Hot assembly type e) SG tube plugging Analysis Analysis assumes location giving most limiting PCT (broken loop)

Anywhere in core 14X14 AREVA NP HTP fuel 10 percent 2.0 PLANT INITIAL OPERATING CONDITIONS 2.1 Reactor Power a) Nominal reactor power b) LHGR c) F Q d) Fr 3029.1 MWt 1 15.0 kW/ft 2.0 8175 - 2161 1.810 2 2.2 Fluid Conditions a) Loop flow b) RCS Cold Leg temperature c) Pressurizer pressure d) Pressurizer level e) SIT pressure f) SIT liquid volume g) SIT temperature h) SIT resistance fL/D i) Minimum ECCS boron 140.8 Mlbm/hr M 164.6 Mlbm/hr 548.0°F T F 2185 psi a P 2315 psia 62.6 percent L P 1090 ft 3 V 3 80.5°F T F (lt couples with containment temperature)

As-built piping configuration 1900 ppm

1. Includes 0.3% uncertainties

2. The radial power peaking for the hot rod is including 6% measurement uncertainty and 3.5% allowance for control rod insertion affect.

UNIT 1 15.4.1-14a Amendment No. 27 (04/15)

TABLE 15.4.1-1a PLANT OPERATING RANGE SUPPORTED BY THE LOCA ANALYSIS (Continued)

EVENT OPERATING RANGE 3.0 ACCIDENT BOUNDARY CONDITIONS a) Break location b) Break type c) Break size (each side, relative to cold leg pipe area) d) Worst single

-failure e) Offsite power f) LSPI flow g) HPSI flow h) ECCS pumped injection temperature i) HPSI pump delay j) LPSI pump delay k) Containment pressure l) Containment temperature m) Containment sprays delay n) Containment volume Cold leg pump discharge piping Double-ended guillotine or split 0.2997 A 1.0 full pipe area (split) 0.2997 A 1.0 full pipe area (guillotone)

Loss of one emergency diesel generator On or Off Minimum flow Minimum flow 120°F 19.5 sec (w/offsite power) 30.0 sec w/o offsite power 19.5 sec (w/offsite power) 30.0 sec w/o offsite power 14.7 psia, nominal val ue 80.5°F T °F 0 sec 2.46078E+06 ft 3 V 2.63655E+06 ft 3

15.4.1-14b Amendment No. 26 (11/13)

TABLE 15.4.1-1b STATISTICAL DISTRIBUTIONS USED FOR PROCESS PARAMETERS PARAMETER OPERATIONAL UNCERTAINTY DISTRIBUTION PARAMETER RANGE Pressurizer Pressure (psia)

Uniform 2185 - 2315 Pressurizer Liquid Level (percent)

Uniform 62.6 68.6 SIT Liquid Volume (ft 3) Uniform 1090.0 1170.0 SIT Pressure (psia)

Uniform 214.7 294.7 Containment Temperature (°F) Uniform 80.5- 124.5 Containment Volume (ft

3) Uniform 2.46078E+6 2.63655E+6 Initial RCS Flow Rate (Mlbm/hr)

Uniform 140.8 164.6 Initial RCS Operating Temperature (Tcold) (°F) Uniform 548.0 554.0 Offsite Power Availability 1 Binary 0,1

1 This is no longer a sampled parameter. One set of 59 cases is run with LOOP and one set of 59 cases is run with No-LOOP.

15.4.1-15 Amendment No. 26 (11/13)

TABLE 15.4.1-1c

SUMMARY

OF MAJOR PARAMETERS FOR THE LIMITING PCT CASE Fresh UO 2 Fuel Once-Burned UO 2 Fuel Cycle Burnup (EFPH) 343.73 343.68 Core Power (MWt) 3029.1 3029.1 Maximum Hot Rod LHGR (kW/ft) 1 5.157 14.702 Radial Peak (F r) 1.810 1.7 56 Axial Offset 0.0 620 0.0 620 Break Type Guillotine Guillotine Break Size (ft 2/side) 3.2791 3.2791 Offsite Power Availability Not available Not available Decay Heat Multiplier 1.0 1.0

UNIT 1 15.4.1-16 Amendment No. 27 (04/15)

TABLE 15.4.1-1d CALCULATED EVENT TIMES FOR THE LIMITING PCT CASE EVEN T TIME(S) Break Opened 0.0 RCP Trip 0.0 SIAS Issued 1.1 Start of Broken Loop SIT Injection 1 6.7 Start of Intact Loop SIT Injection (Loops 2,3 and 4 respectively) 19.3 , 19.4 and 19.4 Broken Loop HPSI Delivery Began 31.1 Intact Loop HPSI Delivery Began (Loops 2, 3, and 4 respectively)

Broken Loop HPSI Delivery Began N/A, N/A and 31.1 31.1 Intact Loop HPSI Delivery Began (Loops 2, 3, and 4 respectively)

Beginning of Core Recovery (Beginning of Reflood) 31.1, 31.1 and N/A 28.8 Broken Loop SIT Emptied 63.1 Intact Loop SITs Emptied (Loops 2, 3, and 4 respectively)

PCT Occurred 60.7, 63.4 and 66.3 51.5 Transient Calculation Terminated 605.0

UNIT 1 15.4.1-17 Amendment No. 27 (04/15)

TABLE 15.4.1-1e LOCA CONTAINMENT LEAKAGE SOURCE TERM Kr-85 1.238E+06 Pu-239 3.828E+04 Kr-85m 1. 983E+07 Pu-240 7.207E+04 Kr-87 3.767E+07 Pu-241 1.785E+07 Kr-88 5.295E+07 Am-241 2.014E+04 Rb-86 2. 817E+05 Cm-242 8.940E+06 Sr-89 7.261E+07 Cm-244 3.272E+06 Sr-90 9.934E+06 I-130 6.937E+06 Sr-91 9.016E+07 Kr-83m 9.565E+06 Sr-92 9.856E+07 Xe-138 1.320E+08 Y-90 1.036E+07 Xe-131m 9.824E+05 Y-91 9.485E+07 Xe-133m 5.358E+06 Y-92 9.904E+07 Xe-135m 3.513E+07 Y-93 1.158E+08 Cs-138 1.470E+08 Zr-95 1.337E+08 Cs-134 m 7.473E+06 Zr-97 1.330E+08 Rb-88 5.392E+07 Nb-95 1.352E+08 Rb-89 6.883E+07 Mo-99 1.581E+08 Sb-124 3.526E+05 Tc-99m 1.384E+08 Sb-125 2.324E+06 Ru-103 1.578E+08 Sb-126 1.787E+05 Ru-105 1.277E+08 Te-131 7.697E+07 Ru-106 9.086E+07 Te-133 9.845E+07 Rh-105 1.150E+08 Te-134 1.312E+08 Sb-127 1.163E+07 Te-125m 5.143E+05 Sb-1 29 3.155E+07 Te-133m 5.818E+07 Te-127 1.157E+07 Ba-141 1.304E+08 Te-127m 1.578E+06 Ba-137m 1.312E+07 Te-129 3.105E+07 Pd-109 5.544E+07 Te-129m 4.607E+06 Rh-106 9.960E+07 Te-131m 1.330E+07 Rh-103m 1.422E+08 Te-132 1.213E+08 Tc-101 1.470E+08 I-131 8.752E+07 Eu-154 2.086E+06 I-132 1.240E+08 Eu-155 1.446E+06 I-133 1.650E+08 Ei-156 4.763E+07 I-134 1.787E+08 La-143 1.198E+08 I-135 1.555E+08 Nb-97 1.342E+08

15.4.1-18 Amendment No. 26 (11/13)

TABLE 15.4.1-1e LOCA CONTAINMENT LEAKAGE SOURCE TERM (CONT.)

Xe-133 1.657E+08 Nb-95m 9.559E+05 Xe-135 4.394E+07 Pm-147 1.212E+07 Cs-134 3.335E+07 Pm-148 2.472E+07 Cs-136 8.190E+06 Pm-149 5.555E+07 Cs-137 1.384E+07 Pm-151 2.031E+07 Ba-139 1.439E+08 Pm-148m 2.971E+06 Ba-140 1.386E+08 Pr-144 1.129E+08 La-140 1.448E+08 Pr-144m 1.347E+06 La-141 1.311E+08 Sm-153 6.783E+07 La-142 1.263e+08 Y-94 1.175E+08 Ce-141 1.333E+08 Y-95 1.272E+08 Ce-143 1.207E+08 Y-91m 5.234E+07 Ce-144 1.121E+08 Br-82 7.734E+05 Pr-143 1.200e+08 Br-83 9.531E+06 Nd-147 5.290E+07 Br-84 1.632E+07 Np-239 2.435E+09 Am-242 1.235E+07 Pu-238 6.206E+05 Np-238 6.601E+07 Pu-243 1.146E+08 TABLE 15.4.1-1f CONTAINMENT HEAT SINK DATA Containment Shell C Steel 0.1171 86700 Floor Slab Concrete 21.0 12682 Misc Concrete Concrete 1.5 87751 Galvanized Steel Galvanizing C Steel 0.0005833 0.01417 130000 Carbon Steel C Steel 0.03125 25000 Stainless Steel S Steel 0.0375 22 300 Misc Steel C Steel 0.0625 40000 Misc Steel C Steel 0.02083 41700 Misc Steel C Steel 0.17708 7000 Imbedded Steel C Steel Concrete 0.0708 7.0 18000 Sump (GSI-191) C Steel 0.02895 7414 15.4.1-19 Amendment No. 26 (11/13)

TABLE 15.4.1-g CONTAINMENT INITIAL AND BOUNDARY CONDITIONS Containment free volume range, ft 3 2,460,780

- 2,636,550 Initial relative humidity 100.0% Initial compartment pressure, psia 14.7, nominal value Initial compartment temperature, °F 80.5 T 124.5 Containment spray time of delivery, sec 0.0 Containment spray flow rate, gpm 9,000.0 Containment spray temperature, °F 36.0 TABLE 15.4.1-h

SUMMARY

OF RESULTS FOR THE LIMITING PCT CASE Case #23 (Offsite Power Not Available)

Fresh Fuel UO 2 Rod Once-Burned Fuel UO 2 Rod PCT Temperature 1788°F 1 774°F Time 51.5 s 51.486 s Elevation 7.859 ft 7.8 587 ft Metal-Water Reaction Pre-transient Oxidation %

0.1992 0.666 Transient Oxidation Maximum

% 1.6551 1.5602 Total Oxidation Maximum %

1.854 2.226 Total Whole-Core Oxidation % 0.0392 N/A

UNIT 1 15.4.1-19a Amendment No.

27 (04/15)

DELETED

15.4.1-21 Amendment No. 24 (06/10)

DELETED

15.4.1-22 Amendment No.

24 (06/10)

TABLE 15.4.1-5 CLASS 3 - DESIGN BASIS ACCIDENT OFF-SITE DOSES (HISTORICAL)

Model (Rem)

Dose using AEC Safety Guide 4 Model (Rem)

Accident Body Time Period Distance Thyroid Whole Body Thyroid Whole *LOCA (Base Case) 0-2 hr 5100 ft .236 1.52x10-3 66.7 2.05 0-31 day 5 miles 1.56 4.93x10-3 42.9 0.622 *LOCA 0-2 hr 5100 ft .326 2.61x10-3 63.3 2.03 0-31 day 5 miles 2.15 8.09x10-3 40.7 0.618 *Bypass Leakage 0-2 hr 5100 ft ---- ---- 5.2 3.5x10-2 0-31 day 5 miles ---- ---- 4.2 1.5x10-2 Hydrogen Long Term 5100 ft 1.06x10-3 2.31x10-4 0.55 6.0x10-4 Purge (Base Case)

Long Term 5 miles 8.14x10-5 1.78x10-5 0.050 4.69x10-5 Hydrogen Long Term 5100 ft 1.02x10-3 9.04x 10-4 0.53 2.10x10-3 Purge Long Term 5 miles 7.85 10-5 6.96x10-5 0.03 1.64x10-4 ESF Component 0-2 hr 5100 ft ---- ---- 0.0796 ---- Leakage 0-31 day 5 miles ---- ---- 0.0714 ---- (Base Case)

ESF Component 0-2 hr 5100 ft ---- ---- 0.0793 ---- Leakage 0-31 day 5 miles ---- ---- 0.0711 ---- (Extended Burnup)

CEA Ejection:

Containment Release 0-2 hr 0-31 day EAB LPZ ---- ---- ---- ---- 0.066 0.639 6.9 x 10-5 6.9 x 10-4 Secondary Release 0-2 hr 0-31 day EAB LPZ ---- ---- ---- ---- 0.52 5 1.131 4.35 x 10-4 9.3 x 10-4 Steam Line Break(1) 0-2 hr ---- ---- ---- ---- ---- Steam Generator 0-2 hr 5100 ft 0.863 0.217 ---- ---- Tube Break Waste Gas(2) Fuel Handling Cont.

0-2 hr 5100 ft 59.1 rem 0.68 rem (Ext. Burnup) 0-2 hr 5 mile s 27.9 rem 0.319 rem 10 CFR 100 0-2 hr 5100 ft 300 25 300 25 Limits 10 CFR 100 0-31 day 5 miles 300 25 300 25 Limits 1. The doses for Steam Line Break are bounded by the LOCA doses.

2. The doses for Waste Gas Decay Tank Accident are bounded by the Fuel Handling Accident doses. *Historical information. LOCA dose consequences revised using more conservative /Q values and a one (1) mile LPZ in support of Technical Specification Amendment #38. See discussion in UFSAR Section 15.4.1.5.

15.4.1-23 Amendment No. 24 (06/10)

Core Power Level 3030 MW th (3020 + 0.3%) Core Average Fuel Burnup 4 9,000 MWD/MTU Fuel Enrichment 1.5 5.0 w/o Initial RCS Equilibrium Activity 1.0 Ci/gm DE I

-131 and 518.9 Ci/gm DE X e-133 gross activity (Table 15.4.1

-9) Core Fission Product Inventory Table 15.4.1

-1e Containment Leakage Rate 0 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 0.5% (by volume)/day 0.25% (by volume)/day LOCA release phase timing and duration Table 15.4.1

-7 Core Inventory Release Fractions (gap release and early in-vessel damage phases)

RG 1.183, Sections 3.1 and 3.2 ECCS Systems Leakage Sump Volume (minimum)

ECCS Leakage to RAB (2 times allowed value)

Flashing Fraction Chemical form of the iodine in the sump water Release ECCS Area Filtration Efficiency 67,39 4 ft 3 4 750 cc/hr Calculate d 5.5% Used for dose determination 10% 0% aerosol, 97% elemental, and 3.0% organic Elemental 95% Organic 95% Particulate 99% (100% of the particulates are retained in the ECCS fluid)

15.4.1-24 Amendment No. 26 (11/13)

RWT Back-leakage Sump Volume (at time of recirculation)

ECCS Leakage to RWT (2 times allowed value)

Flashing Fraction (elemental Iodine assumed t o be released into tank space based upon partition factor) 67,39 4 ft 3 2 gpm 0 % based on temperature of fluid reaching RWT Initial RWT Liquid Inventory (minimum) 44,147 gal Release from RWT Vapor Space Table 15.4.1

-8 Containment Purge Release 500 cfm for 30 seconds Containment Particulate/Aerosol Natural Deposition (only credited in unsprayed regions) 0.1/hour Containment Elemental Iodine Natural/Wall Deposition 2.89/hour Containment Spray Region Volume 2,155,160 ft 3 Containment Unsprayed Region Volume 350,840 ft 3 Flowrate between sprayed and unsprayed volumes 23,389 cfm Spray Removal Rates:

Elemental Iodine Time to reach DF of 200 Particulate Iodine Time to reach DF of 50 20/hour 2.331 hours0.00383 days <br />0.0919 hours <br />5.472884e-4 weeks <br />1.259455e-4 months <br /> 6.07/hour 2.334 hours0.00387 days <br />0.0928 hours <br />5.522487e-4 weeks <br />1.27087e-4 months <br /> Spray Initiation Time Spray Termination Time 80 seconds 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Control Room Ventilation System Time of automatic control room isolation Time of manual control room unisolation 50 seconds 1.5 hrs Secondary Containment Filter Efficiency Particulate 99% Elemental 95% Organic 95% Secondary Containment Drawdown Time 310 seconds Secondary Containment Bypass Fraction 9.6% Containment Purge Filtration 0 % Containment Release Secondary Containment release prior to drawdown Nearest containment penetration to CR ventilation intake 15.4.1-25 Amendment No. 26 (11/13)

Containment Release Secondary Containment release after drawdown Plant stack Containment Release Secondary Containment Bypass Leakage Nearest containment penetration to CR ventilation intake ECCS Leakage ECCS exhaust louver RWT Backleakage RWT Containment Purge Plant Stack Atmospheric Dispersion Factors Offsite Onsite Appendix 2I Table 15.4.1

-10 Breathing Rates RG 1.183 Sections 4.1.3 and 4.2.6 Control Room Occupancy Factor RG 1.183 Section 4.2.6

15.4.1-26 Amendment No. 24 (06/10)

Gap Release 30 seconds 0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Early In-Vessel 0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 1.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />

• From RG 1.183, Table 4

0.0 0.0 0.40 7.973 E-0 7 10.0 8.637 E-0 6 25.0 4.886 E-0 5 75.0 1.545 E-04 125.0 2.636 E-04 200.0 3.895 E-04 300.0 4.995 E-04 450.0 5.563 E-04 600.0 5.687 E-04 0.0 1.07 720 1.07 15.4.1-27 Amendment No. 26 (11/13)

Co-58 4.394E-02 Ba-139 4.800E-04 Co-60 8.256 E-02 Ba-140 7.124 E-03 Kr-85 4.160E+01 La-140 3.299E-03 Kr-85m 1.268E+00 La-141 2.646 E-04 Kr-87 7.574E-01 La-142 7.483E-05 Kr-88 2.247E+00 Ce-141 1.147E-03 Rb-86 3.403E-02 Ce-143 6.485E-04 Sr-89 5.691 E-03 Ce-144 9.815E-04 Sr-90 5.459E-04 P r-143 1.031E-03 Sr-91 1.526E-03 Nd-147 4.302E-04 Sr-92 6.105E-04 Kr-83m 3.826E-01 Y-90 7.799E-04 Xe-138 5.168E-01 Y-91 3.327E-02 Xe-131m 3.022E+00 Y-92 7.402E-04 Xe-133m 3.479E+00 Y-93 4.706E-04 Xe-135m 8.553E-01 Zr-95 1.159E-03 Cs-138 9.667E-01 Zr-97 5.170E-04 Cs-134m 1.179E-01 Nb-95 1.187E-03 Rb-88 2.326E+00 Mo-99 5.111E+00 Rc-89 1.022E-01 T c-99m 3.885E+00 Sb-124 1.910E-03 Ru-103 1.359E-03 Sb-125 1.277E-02 Ru-105 1.934E-04 Sb-126 9.173E-04 Ru-106 7.973E-04 Te-131 1.741E-02 Ru-105 7.047E-04 Te-134 2.280E-02 Sb-127 5.187E-02 Te-125m 2.828E-03 SB-129 2.918E-02 Te-133m 1.326E-02 T e-127 5.496E-02 Ba-141 1.009E-04 Te-127m 8.677E-03 Rh-103m 1.350E-03 Te-129 4.558E-02 Nb-97 8.889E-05 Te-129m 2.486E-02 Nb-95m 8.343E-06 Te-131m 4.273E-02 Pm-147 1.069E-04 Te-132 5.233E-01 Pm-148 1.866E-04 I-131 8.425E-01 Pm-149 3.485E-04 I-132 1.68 9E-01 Pm-151 1.021E-04 I-133 8.713E-01 Pm-148m 2.556E-05 I-134 7.726E-02 Pr-144 9.816E-04 I-135 3.933E-01 Y-94 1.528E-05 Xe-133 2.381+02 Y-91m 8.872E-04 X e-135 9.235E+00 Br-82 6.096E-02 15.4.1-28 Amendment No. 26 (11/13)

Nuclide Cs-134 6.972E+00 Br-83 1.214E-01 Cs-136 1.543E+00 Br-84 5.002E-02 Cs-137 2.899E+00

15.4.1-28a Amendment No. 26 (11/1

3) 0 7.29E-03 0.0138 9 3.17 E-03 1.5 1.76E-03 2 1.41E-03 8 5.72E-04 24 4.29E-04 96 3.57E-04 720 3.57E-04 0 2.39E-03 0.0138 9 3.91E-03 1.5 6.93E-04 2 4.88E-04 8 2.19E-04 24 1.46E-04 96 1.28E-04 720 1.28E-04

0 4.80E-03 0.0138 9 5.03E-03 1.5 3.61E-03 2 2.87E-03 8 1.20E-03 24 9.07E-04 96 7.13E-04 720 7.13E-04 15.4.1-29 Amendment No. 26 (11/13) 0 1.37E-03 0.013 89 1.34E-03 1.5 1.12E-03 2 9.10E-04 8 3.84E-04 24 2.93E-04 96 2.37E-04 720 2.37E-04 Containment Purge 3.8649E-043.7779E-045.7379E-03Containment Leakage 1.1335E+002.4687E+004.3143E+00ECCS Leakage 1.4956E-031.4751E-021.5237E-01 RWT Leakage 1.3722E-033.0891E-021.1503E-01 Shine Dose 0.20

15.4.1-30 Amendment No. 26 (11/13)

Amendment No.

2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 27 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (0 4/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 2 7 (04/15)

Amendment No. 27 (04/15)

Amendment No. 2 7 (04/15)

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4 --S fi 9 10 3 CONTROL ROOM TNTAJ{E. RATE (CFM) AMENDMENTN0.11 (7192) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 ALLOWABLE CONTROL ROOM INTAKE AS A FUNCTION OF CONT. AND BYPASS LEAKAGE FIGURE 15.4.1-28

15.4.3FUEL HANDLING ACCIDENT15.4.3.1 Identification of CausesThe likelihood of a fuel handling accident is minimized by administrative controls and physicallimitations imposed on fuel handling operations. All refueling operations are conducted in accordance with prescribed procedures under direct surveillance of a qualified supervisor. Before any refueling operations begin, verification of complete CEA insertion is obtained by ensuring all CEAs are tripped and their rod bottom lights are lit. Boron concentration in the coolant is raised to the refueling concentration and is verified by chemical analysis. At the refueling boron concentration, the core would be subcritical even with all CEA's withdrawn.After the vessel head is removed, the CEA drive shafts are removed from their respective assemblies.A load cell is used to indicate that the drive shaft is free of the CEA as the lifting force is applied.The maximum elevation to which the fuel assemblies can be raised is limited by the design of the fuelhandling hoists and manipulators to assure that the minimum depth of water above the top of a fuel assembly required for shielding is always present (see Section 9.1.4). This constraint is present in the fuel handling areas both inside containment and in the fuel handling building. Supplementing the physical limits on fuel withdrawal, radiation monitors located at the fuel handling areas provide both audible and visual warning of high radiation levels in the event of a low water level in the refueling cavity and fuel pool. Fuel pool structural integrity is assured by designing the pool and the spent fuel storage racks as Class 1 structures.The design of the spent fuel storage racks and handling facilities in both the containment and fuelhandling building is such that subcriticality would be maintained if the pool were flooded with unborated water. Natural convection of the surrounding water provides adequate cooling of fuel during handling and storage. Adequate cooling of the water is provided by forced circulation in the spent fuel pool cooling system. At no time during the transfer from the reactor core to the spent fuel storage rack is there less than 112 inches of water above a fuel assembly.Fuel failure during refueling as a result of inadvertent criticality or overheating is not possible. Thepossibility of damage to a fuel assembly as a consequence of mishandling is minimized by thorough training, detailed procedures and equipment design. The design precludes the handling of heavy objects such as shipping casks over the spent fuel pool storage racks. Administrative controls preventthe movement of heavy loads over the cask pit whenever the cask pit rack is installed in the cask areaof the SFP. Inadvertent disengagement of a fuel assembly from the fuel handling machine is prevented by mechanical interlocks, consequently, the possibility of dropping and damaging of a fuel assembly is remote.15.4.3-1Amendment No. 21 (12/05)

Should a spent fuel assembly be damaged during handling, radioactive release could occur in eitherthe containment or the fuel handling building. The ventilation exhaust air from both of these areas is monitored before release to the atmosphere (Section 11.4). Area radiation monitors provide alarm and indication of increased activity level. The affected area would then be evacuated.The original fuel handling accident analyzed the off-site dose consequences from the event occurringin the fuel handling building. A second fuel handling building analysis was performed for an extended burn-up source term. The current analysis of the Fuel Handling Accident was performed to support a Technical Specification Amendment to allow the containment personnel airlock doors to remain open during refueling operations and core alterations. This analysis evaluates the off-site dose from a fuel handling accident in the refueling canal with a water level of 23 feet.The previous analysis of a dropped fuel assembly in the fuel handling building assumed that a fuelassembly was dropped into the spent fuel pool during fuel handling. The analysis evaluated the damage potential to the dropped fuel assembly and also to the stored fuel assemblies. Interlocks and procedural and administrative controls make such an event highly unlikely; however, if an assembly were damaged to the extent that one or more fuel rods were broken, the accumulated fission gases and iodines in the gap would be released to the surrounding water. Release of the solid fission products in the fuel would be negligible since the low fuel temperature during refueling greatly limits their diffusion.The fuel assemblies are stored in the spent fuel racks at the bottom of the fuel pool. The top of therack extends above the tops of the stored fuel assemblies, so that a dropped fuel assembly could not strike more than one fuel assembly in the storage rack. In this case, impact could occur only between the ends of the fuel assemblies, the bottom end fitting of the dropped fuel assembly striking the top end fitting of the stored fuel assembly. The results of an analysis of the "end-on" energy absorption capability of a fuel assembly have shown that a fuel assembly is capable of absorbing the kinetic energy of the drop and that there will be no fuel damage. The worst fuel handling accident that could occur in the spent fuel pool is the dropping of a fuel assembly to the fuel pool floor. After striking the pool floor vertically, the assembly would rotate into a horizontal attitude; during this rotation, it is postulated that the assembly strikes a protruding structure. The fuel storage pool is designed with no protruding structures and, hence, the shape and nature of the assumed protruding structure is indeterminate. For this analysis, therefore, a line load was assumed.To obtain an estimate of the number of fuel rods which might fail in the event a fuel assembly weredropped, the energy required to crush a fuel rod and bend the entire assembly has been determined.

The point of impact was assumed at the most effective location for fuel rod damage, i.e., the center of percussion. Resistance to crushing offered by the fuel pellet is considered in the analysis. The model results in a conservative upper limit for the number of fuel rod failures. Since it is not possible to apply a line load beyond the outer row of fuel rods, failure by crushing cannot be experienced beyond the outer row. The failure mode of rods in other than the outer rows will be by bending rather than crushing.Approximately 36,000 in-lb of kinetic energy from rotation must be absorbed. The energy required tobend the assembly and crush the outer row of fuel rods to failure is 4,600 in-lb. Failure of the second row of fuel rods by bending alone requires more than 70,000 in-lb. Thus, for a fuel assembly dropped into the spent fuel pool, no more than 14 fuel rods, i.e., one outer row of rods, would be expected to fail.15.4.3-2Amendment No. 19 (10/02)

Deleted15.4.3-6Amendment No. 18, (04/01)

15.4.4ST EAM GENERATOR TUBE FAILURE 15.4.4.1Identification of Caus es T he s team gene r ator tube failure is a penetration of the ba rrier bet w een the r ea c tor coolant sys tem andthe main s team sys tem. T he integr ity of this ba rrier is si gnific ant from the standpoint of radiologic al saf etyin that a leaking s team gene r ator tube allows the tr ansfer of r ea c tor coolant into the main s team sys tem. Radioactivity contained in the r ea c tor coolant mixes wi th w ater in the shell si de of the a ffec ted s teamgene r ato r. T his radioactivity is tr an s po r ted by s team to the turbine and then to the c ondenser, or direc tly tothe c ondenser via the main s team dump and by pa ss sys tem. Nonc ondensible radioactive gases in thec ondenser are removed by the c ondenser air ejec tor di sc ha r ge to the plant vent.

Detection of r ea c tor coolant leak age to the s team sys tem is facilitated by radiation monito rs in the s teamgene r ator blow down lines (s ee Section 10.4.7), in the c ondenser air ejec tor di sc ha r ge lines (s ee Section 10.4.2 and 10.4.3) and in the main s team line radiation monito rs. T hese monito rs initiate alarms in thec ont r ol r oom and alert the ope r ator of abnorm al activity levels and that co rrective action is r equi r ed. T he behavior of the r ea c tor coolant varies depending upon the size of the r uptu r e. For leak r ates up to thec apa c ity of the c harging pumps in the c hemic al and volume c ont r ol sys tem, r ea c tor coolant inventory c anbe maintained and an auto m atic r ea c tor tr ip w ill not o ccur. T he ga s eous fi ss i on pr oducts would bereleased to atmos phere from the main s team sys tem via the c ondenser air ejec tor di sc ha r ge to the plantvent. T hose fi ss i on pr odu cts not di sc ha r ged in this way would be retained by the main s team, f eed w aterand c onden s ate sys tems. For leaks that e xc eed the c apa c it y of the c harging pumps, pre ssurizer w ater level and pre ssuriz erpre ssure de cr ea se and an auto m atic r ea c tor tr ip results. T he turbine then tr ips and the main s team dumpand by pa ss valves open, di sc harging s team direc tl y into the c ondenser. In addition to the radiationmonito rs, the s team gene r ator w ater level indic ato rs aid in the detection of these la r ger leaks since thew ater inventory in the leaking s team gene r ator w ill in cr ease more rapidl y than that of the intact s teamgene r ator followi ng the r eactor trip. (Prior to r ea c tor tr ip the w ater level in each s team gene r ator isauto m atically maintained at a c on s tant level.) As the break flow begins to depressurize the RCS, the charging pumps activate in order to make-up the lost inventory. If the RCS inventory and pressure are stabilized via the charging pumps, no reactor trip will occur. However, if the break flow exceeds the capacity of the charging pumps, the RCS pressure and inventory will continue to decrease resulting in a reactor trip on a low RCS pressure signal (TM/LP).

At normal operating conditions, the leak rate through the double-ended rupture of one tube is greater than the maximum flow available from the three charging pumps.

Following the reactor trip, the turbine will trip and, in the case where offsite power is lost, the reactor coolant pumps will coast down and make-up flow will terminate until emergency diesel generator power is available. If offsite power is available, a fast transfer to the offsite power will keep the reactor cool ant pumps running and the makeup flow available.

The loss of offsite power results in the loss of condenser vacuum and the steam dump to condenser valves are closed to protect the condenser. The continued mass and energy transfer between the RCS and secondary side results in an increase in the affected SG pressure and discharge to the atmosphere via the MSSVs and ADVs.

UNIT 1 15.4.4-1Am end m ent No. 27 (04/15)

15.4.4.5 Radiological Analysis 15.4.4.5.1 Background This event is assumed to be caused by the instantaneous rupture of a Steam Generator tube that relieves to the lower pressure secondary system. No melt or clad breach is postulated for the St. Lucie Unit 1 SGTR event. The St. Lucie Unit 1 AST dose analysis methodology is presented in Reference 10

7.

15.4.4.5.2 Compliance with RG 1.183 Regulatory Positions

The SGTR dose consequence analysis followed the guidance provided in RG 1.183, Appendix F, "Assumptions for Evaluating the Radiological Consequences of a PWR Steam Generator Tube Rupture Accident," as discussed below:

1. Regulatory Position 1 - The total core inventory of the radionuclide groups utilized for determining the source term for this event is based on RG 1.183, Regulatory Position 3.1. No fuel damage is postulated to occur for the St. Lucie Unit 1 SGTR event.

2. Regulatory Position 2 - No fuel damage is postulated to occur for the St. Lucie Unit 1 SGTR event. Two cases of iodine spiking are assumed.

3. Regulatory Position 2.1 - One case assumes a reactor transient prior to the postulated SGTR that raises the primary coolant iodine concentration to the maximum allowed by TS 3.4.8, Fig. 3.4-1 value of 60.0 Ci/gm DE I-131. This is the pre-accident spike case.

4. Regulatory Position 2.2 - One case assumes the transient associated with the SGTR causes an iodine spike. The spiking model assumes the primary coolant activity is initially at the TS 3.4.8 value of

1.0 Ci/gm DE I-131. Iodine is assumed to be released from the fuel into the RCS at a rate of 335 times the iodine equilibrium release rate for a period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This is the accident-induced spike case.

5. Regulatory Position 3 - The activity released from the fuel is assumed to be released instantaneously and homogeneously through the primary coolant.

6. Regulatory Position 4 - Iodine releases from the steam generators to the environment are assumed to be 97% elemental and 3% organic.

7. Regulatory Position 5.1 - The primary-to-secondary leak rate is apportioned between the SGs as specified by TS 6.8.4.l (0.5 gpm total, 0.25 to any one SG). Thus, the tube leakage is apportioned equally between the two SGs.

8. Regulatory Position 5.2 - The density used in converting volumetric leak rates to mass leak rates is based upon RCS conditions, consistent with the plant design basis.

9. Regulatory Position 5.3 - The primary-to-secondary leakage is assumed to continue until after shutdown cooling has been placed in service and the temperature of the RCS is less than 212°F. A n input parameter for the termination of the affected SG activity release states that the affected SG is isolated within 45 minutes by operator action. This isolation terminates releases from the affected SG, while primary-to-secondary leakage continues to provide activity for release from the unaffected SG.

10. Regulatory Position 5.4 - The release of fission products from the secondary system is evaluated with the assumption of a coincident loss-of-offsite power (LOOP).

UNIT 1 15.4.4-4a Amendment No. 27 (04/15)

15.4.4.5.3 Other Assumptions

1. This evaluation assumes that the RCS mass remains constant throughout the event.

2. For the purposes of determining the iodine concentrations, the SG mass is assumed to remain constant throughout the event. However, it is also assumed that operator action is taken to restore water level above the top of the tubes in the unaffected steam generator within a conservative time of one hour following a reactor trip.

3. Data used to calculate the iodine equilibrium appearance rates are provided in Table 15.4.4-Equilibrium Appearance AssumptionsTable 15.4.4-

6.

15.4.4.5.4 Methodology Input assumptions used in the dose consequence analysis of the SGTR event are provided in Table 15.4.4-3. This event is assumed to be caused by the instantaneous rupture of a steam generator tube releasing primary coolant to the lower pressure secondary system. In the unlikely event of a concurrent loss of power, the loss of circulating water through the condenser would eventually result in the loss o f condenser vacuum, thereby causing steam relief directly to the atmosphere from the ADVs. This direct steam relief continues until the faulted steam generator is isolated at 45 minutes.

A thermal-hydraulic analysis is performed to determine a conservative maximum break flow, break flashing flow, and steam release inventory through the faulted SG relief valves. Additional activity, based on the proposed primary

-to-secondary leakage limits, is released via steaming from the ADVs until the RCS is cooled to 212°F.

Per UFSAR, Section 15.4.4.6, no fuel failure is postulated for the SGTR event. Consistent with RG 1.183 Appendix F, Regulatory Position 2, if no, or minimal, fuel damage is postulated for the limiting event, the activity release is assumed as the maximum allowed by Technical Specifications for two cases of iodine spiking: (1) maximum pre-accident iodine spike, and (2) maximum accident-induced, or concurrent, iodine spike. For the case of a pre-accident iodine spike, a reactor transient is assumed to have occurred prior to the postulated SGTR event. The primary coolant iodine concentration is increased to the maximum value of

60 Ci/gm DE I-131 permitted by TS 3.4.8 (see Table 15.4.4-7). Primary coolant is released into the ruptured SG by the tube rupture and by a fraction of the total proposed allowable primary-to-secondary leakage. Activity is released to the environment from the ruptured SG via direct flashing of a fraction of the released primary coolant from the tube rupture and also via steaming from the ruptured SG ADVs until the ruptured steam generator is isolated at 45 minutes. The unaffected SG is used to cool down the plant during the SGTR event. Primary-to-secondary tube leakage is also postulated into the intact SG. Activity is released via steaming from the unaffected SG ADVs until the RCS is cooled below 212°F. These release assumptions are consistent with the requirements of RG 1.183.

For the case of the accident-induced spike, the postulated STGR event induces an iodine spike. The RCS activity is initially assumed to be 1.0 Ci/gm DE I-131 as allowed by TS 3.4.8. Iodine is released from the fuel into the RCS at a rate of 335 times the iodine equilibrium release rate for a period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Parameters used in the determination of the iodine equilibrium release rate are provided in Table 15.4.4-5. The iodine activities and the appearance rates for the accident-induced (concurrent) iodine spike case are presented in Table 15.4.4-

6. All other release assumptions for this case are identical to those for the pre-accident spike case.

UNIT 1 15.4.4-4c Amendment No. 27 (0 4/15)

15.4.5 CEA EJECTION EVENT 15.4.5.1 Identification of Causes The CEA ejection event is analyzed to determine the fraction of fuel pins that exceed the criteria for clad damage.

Rapid ejection of a control element assembly (CEA) from the core would require a complete circumferential break of the control element drive mechanism (CEDM) housing or of the CEDM nozzle on the reactor vessel head. The CEDM housing and CEDM nozzle are an extension of the reactor coolant system boundary and designed and manufactured to Section III of the ASME Boiler and Pressure Vessel Code. Hence, the occurrence of such a failure is considered highly unlikely.

A typical CEA ejection transient behaves in the following manner: After ejection of a CEA from the full power or zero power (critical) initial conditions, the core power rises rapidly for a brief period. The rise is terminated by the Doppler effect. Reactor shutdown is initiated by the high power level trip, and the power transient is then completed. The core is protected against severe fuel damage by the allowable CEA patterns and by the high power trip; the maximum enthalpy in the fuel during the transient is limited to an acceptable value.

15.4.5.2 Analysis of Effects and Consequences A CEA (or Control Rod) Ejection event is initiated by a postulated rupture of a control rod drive mechanism housing. Such a rupture allows the full system pressure to act on the drive shaft, which ejects its control rod from the core.

The consequences of the mechanical failure are a rapid positive reactivity insertion and an increase in radial power peaking, which could possibly lead to localized fuel rod damage.

Doppler reactivity feedback mitigates the power excursion as the fuel begins to heat up. Although the initial increase in power occurs too rapidly for the scram rods to have any significant effect on the power during that portion of the transient, the scram reactivity does affect the fuel temperature and fuel rod cladding surface heat flux.

The ejected rod causes localized peaking such that fuel failure may occur due to DNB or FCM. The RCS pressure increases for this event which may challenge the overpressure criterion.

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

The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110).

Table 15.4.5-3 lists assumptions used in the radiological dose calculations.

Deposited enthalpy was calculated using the Reference 111 methodology.

The rod ejection analysis was performed using both BOC and EOC initial conditions at power levels of HFP, 70% RTP, 20% RTP and HZP. Per the Technical Specifications, the core is held subcritical by more than 1% for Mode 3 (Hot Standby), Mode 4 (Hot Shutdown), and Mode 5 (Cold Shutdown).

Since 1% is more than the worth of the ejected control rod, evaluation of these modes is not required. For this analysis, Hot Zero Power is therefore Mode 2 (Startup).

All four reactor coolant pumps are assumed to be in operation in both Mode 1 (Power Operation) and Mode 2 (Startup).

While this postulated event could have a failure of the reactor coolant pressure boundary, it is not clear if (or to what extent) debris pulled toward the break by fluid flow would clog or block the break.

15.4.5-1 Amendment No. 26 (11/13)

Because of this uncertainty, conservative assumptions are typically used to bias the RCS pressure transient response. The evaluation of maximum RCS pressure for this event is based on a plugged hole in the head and takes no credit for pressure reduction from flow out of the break. For evaluation of DNB, the RCS pressure is held constant at the initial value and is assumed to neither increase nor decrease.

The input parameters and biasing for the analysis of this event is shown in Table 15.4.5-1 for the HFP and HZP cases, and in Table 15.4.5-1a for the part-power cases at 70% RTP and 20% RTP. The input parameters and biasing were consistent with the approved methodology.

Initial Conditions - The analysis was performed from HFP, 70% RTP, 20% RTP, and HZP initial conditions to provide a bounding fuel response to the ejected CEA. Respective bounding initial fuel rod hot spot temperatures and maximum core inlet temperatures were assumed for each initial condition. Power measurement uncertainties were applied consistent with the initial power level. TS minimum RCS flow rate was modeled.

Core Power Distributions - Conservative initial core hot spot power peaking factors corresponding to the initial power level and control rod position were used. The hot spot power peaking during the event was determined from detailed core neutronic calculations of both pre-ejection and post-ejection conditions.

Reactivity Feedback - Reactivity feedbacks were modeled that were representative, or conservatively bounding of the BOC and EOC initial conditions. Due to the rapidity of the transient, moderator feedback has a second-order impact on the consequences. TS MTC limits were modeled for the cases initiated at BOC whereas conservatively biased "least negative" MTCs were modeled for the EOC cases. The event is initially mitigated by negative Doppler reactivity feedback. As such, the Doppler reactivity assumed in the analysis was conservatively biased to minimize the negative feedback due to increasing fuel temperatures. For the HZP initiated cases, fuel temperature dependent Doppler feedback was modeled.

Reactor Protection System Trips and Delays - The event is primarily protected by the VHPT. The reactor protection system trip setpoints and response times were conservatively biased to delay the actuation of the trip function. The VHPT setpoints were set to values consistent with the initial power levels, including the trip uncertainty. In addition, rod insertion is delayed to account for the CEA holding coil delay time.

Ejected CEA Worth - To maximize the core power response to the ejected CEA, a conservatively high ejected CEA worth was assumed for each case, based on St. Lucie Unit 1 specific rod patterns and power-dependent insertion limits.

Gap Conductance - Depending on the time-in-cycle for the reactivity coefficients, gap conductance was set to either a conservative BOC value or a conservative EOC value to maximize the heat flux through the cladding and minimize the negative reactivity inserted due to Doppler feedback.

This event is classified as a Postulated Accident with the following acceptance criteria:

Fuel failures due to DNB and FCM should be limited, so as not to impair the capability to cool the core. Additionally, the fuel failures should be within the limits of fuel failures used in the radiological analysis. Fuel Coolability: The peak radial average fuel enthalpy should not be greater than 200 cal/gm.

15.4.5-1a Amendment No. 26 (11/13)

Cladding Failures: For HZP, the peak radial average fuel enthalpy should not be greater than 150 cal/gm. For intermediate power greater than 5% RTP and full power conditions, the local heat flux should not exceed thermal design limits. For pellet/cladding interaction (PCI) and pellet/cladding mechanical interaction (PCMI) failures, the change in radial average fuel enthalpy should be less than the corrosion-dependent limit depicted in Figure B-1 of SRP 4.2, Appendix B. The limit for lower burned fuel that is applicable to the EPU is for the fuel enthalpy rise to be less than 150 cal/gm. Reactivity excursions should not result in a radially averaged enthalpy greater than 200 cal/gm at any axial location in any fuel rod.

The maximum reactor pressure during any portion of the assumed excursion should be less than the value that will cause stresses to exceed the faulted condition stress limits.

Radiological consequences should be within the regulatory limits consistent with the design basis requirements.

15.4.5-1b Amendment No. 26 (11/13) 15.4.5.3 Results The results of the transient analysis cases are summarized in Table 15.4.5-2 for the HFP and HZP cases and in Table 15.4.5-2b for the part-power cases. The sequences of events for the HFP and HZP cases are shown in Table 15.4.5-2a. The power response for the BOC HFP case is shown in Figure 15.4.5-1. The peak hot spot centerline temperatures were calculated to be less than the respective fuel melt temperatures; thus, no fuel failure is predicted to occur as a result of fuel centerline melting. MDNBR was calculated to be above the 95/95 CHF correlation limit; thus, no fuel failure is predicted to occur as a result of DNB. The deposited enthalpies and enthalpy rise were calculated to be less than the applicable limits.

The BOC HFP case presented the most significant challenge to acceptance criteria.

The transient response is shown in Figures 15.4.5-1 through 15.4.5-6. Figure 15.4.5-1 shows the reactor power as a function of time. Figure 15.4.5-2 shows the core power based on rod surface heat flux. Figures 15.4.5-3 th r ough 15.4.5-6 show the RCS loop temperatures, the total RCS flow rate, the reactivity feedback, and the peak fuel centerline temperature, respectively.

The peak RCS pressure analysis was performed using input parameters biased to produce a conservatively high RCS pressure. The peak pressure results from the most limiting RCS pressure (BOC HFP) case was found to produce a smaller challenge to the RCS overpressure criterion than produced by the loss of external load event in Section 15.2. 7. The analysis also concluded that there is ample margin to the applicable overpressure criterion for this event, which is typically taken to be 120% of design pressure (3000 psia). The sequence of events for the overpressure analysis is provided in Table 15.4.5-2a and the plot of RCS pressure as a function of time is presented in Figure 15.4.5-7.

15.4.5-2 Amendment No. 26 (11/13)

1 5.4.5.4 Radiological Analysis 15.4.5.4.1 Background

This event consists of an uncontrolled withdrawal of a single control element assembly (CEA). This event is the same as the Rod Ejection event referred to in RG 1.183. The CEA Ejection results in a reactivity insertion that leads to a core power level increase and subsequent reactor trip. Following the reactor trip, plant cooldown is performed using steam release from the SG ADVs. Two CEA Ejection cases are considered. The first case assumes that 100% of the activity released from the damaged fuel is instantaneously and homogeneously mixed throughout the containment atmosphere. The second case assumes that 100% of the activity released from the damaged fuel is completely dissolved in the primary coolant and is available for release to the secondary system. The St. Lucie Unit 1 AST dose analysis methodology is presented Reference 107.

15.4.5.4.2 Compliance with RG 1.183 Regulatory Positions The CEA Ejection dose consequence analysis followed the guidance provided in RG 1.183 Appendix H, "Assumptions for Evaluating the Radiological Consequences of a PWR Rod Ejection Accident," as discussed below:

1. Regulatory Position 1 - The total core inventory of the radionuclide groups utilized for determining the source term for this event is based on RG 1.183, Regulatory Position 3.1, and is provided in Table 15.4.1-1e. The inventory provided in Table 15.4.1-1e is adjusted for the fraction of fuel damaged and a radial peaking factor of 1.

65 is applied. The release fractions provided in RG 1.183 Table 3 are adjusted to comply with the specific RG 1.183 Appendix H release requirements. For both the containment and secondary release cases, the activity available for release from the fuel gap for fuel that experiences DNB is assumed to be 10% of the noble gas and iodine inventory in the DNB fuel. For the containment release case for fuel that experiences fuel centerline melt (FCM), 100% of the noble gas and 25% of the iodine inventory in the melted fuel is assumed to be released to the containment. For the secondary release case for fuel that experiences FCM, 100% of the noble gas and 50% of the iodine inventory in the melted fuel is assumed to be released to the primary coolant. Gap release fractions have also been increased to account for high burnup fuel rods.

2. Regulatory Position 2 - Fuel damage is assumed for this event.

3. Regulatory Position 3 - For the containment release case, 100% of the activity released from the damaged fuel is assumed to mix instantaneously and homogeneously in the containment atmosphere. For the secondary release case, 100% of the activity released from the damaged fuel is assumed to mix instantaneously and homogeneously in the primary coolant and be available for leakage to the secondary side of the SGs.

4. Regulatory Position 4 - The chemical form of radioiodine released from the damaged fuel to the containment is assumed to be 95% cesium iodide (CsI), 4.85% elemental iodine, and 0.15%

organic iodide. Containment sump pH is controlled to 7.0 or higher.

5. Regulatory Position 5 - The chemical form of radioiodine released from the SGs to the environment is assumed to be 97% elemental iodine, and 3% organic iodide.

6. Regulatory Position 6.1 - For the containment leakage case, natural deposition in the containment is credited. In addition, the shield building ventilation system (SBVS) is credited. Containment spray is not credited.

15.4.5-2a Amendment No. 26 (11/1

3)

7. Regulatory Position 6.2 - The containment is assumed to leak at the TS maximum allowable rate of 0.5% for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 0.25% for the remainder of the event.

8. Regulatory Position 7.1 - The primary-to-secondary leak rate is apportioned between the SGs as specified by TS 6.8.4.l (0.5 gpm total, 0.25 to any one SG).

9. Regulatory Position 7.2 - The density used in converting volumetric leak rates to mass leak rates is based upon RCS conditions, consistent with the plant design basis

10. Regulatory Position 7.3 - All of the noble gas released to the secondary side is assumed to be released directly to the environment without reduction or mitigation.

11. Regulatory Position 7.4 - Regulatory Position 7.4 refers to Appendix E, Regulatory Positions 5.5 and 5.6. The iodine transport model for release from the steam generators is as follows:

Appendix E, Regulatory Position 5.5.1 - For the secondary release case, both steam generators are used for plant cooldown. A portion of the primary-to-secondary leakage is assumed to flash to vapor based on the thermodynamic conditions in the reactor and secondary immediately following plant trip when tube uncovery is postulated. The primary-to-secondary leakage is assumed to mix with the secondary water without flashing during periods of total tube submergence.

Appendix E, Regulatory Position 5.5.2 - The portion of leakage that immediately flashes to vapor is assumed to rise through the bulk water of the SG, enter the steam space, and be immediately released to the environment with no mitigation; i.e., no reduction for scrubbing within the SG bulk water is credited.

Appendix E, Regulatory Position 5.5.3 - All of the SG tube leakage that does not flash is assumed to mix with the bulk water.

Appendix E, Regulatory Position 5.5.4 - The radioactivity within the bulk water is assumed to become vapor at a rate that is a function of the steaming rate and the partition coefficient.

A partition coefficient of 100 is assumed for the iodine. The retention of particulate radionuclides in the SGs is limited by the moisture carryover from the SG. The same partition coefficient of 100, as used for iodine, is assumed for other particulate radionuclides. This assumption is consistent with the SG carryover rate of less than 1%.

Appendix E, Regulatory Position 5.6 - Steam generator tube bundle uncovery in the SGs is postulated for up to 45 minutes following a reactor trip for St. Lucie Unit 1. During this period, the fraction of primary-to-secondary leakage which flashes to vapor is assumed to rise through the bulk water of the SG into the steam space and is assumed to be immediately released to the environment with no mitigation. The flashing fraction is based on the thermodynamic conditions in the reactor and secondary coolant. The leakage which does not flash is assumed to mix with the bulk water in the steam generator. A conservative uncovery time of

60 minutes was assumed in the analysis.

15.4.5.4.3 Other Assumptions

1. The initial RCS activity is assumed to be at the TS 3.4.8 limit of 1.0 µCi/gm Dose Equivalent I-131 and 518.9 Ci/gm DE Xe-133 gross activity. The initial SG activity is assumed to be at the TS 3.7.1.4 limit of 0.1 µCi/gm Dose Equivalent I-131.

1 5.4.5-2b Amendment No. 26 (11/13)

2. The steam mass release rates for the SGs are provided in Table 15.4.5-

4. 3. The RCS fluid density used to convert the primary-to-secondary leakage from a volumetric flowrate to a mass flow rate is consistent with the RCS cooldown rate applied in the generation of the secondary steam releases. The high initial cooldown rate conservatively maximizes the fluid density. The SG tube leakage mass flow rate is provided in Table 15.4.5-

5. 4. The RCS mass is assumed to remain constant throughout the event.

5. For the purposes of determining the iodine concentrations, the SG mass is assumed to remain constant throughout the event. However, it is also assumed that operator action is taken to restore secondary water level above the top of the tubes within a conservative time of one hour following a reactor trip.

6. Following the CEA Ejection event, 9.5% of the fuel is assumed to fail as a result of DNB and 0.5% of the fuel is assumed to experience fuel centerline melt.

7. All secondary releases are postulated to occur from the ADV with the most limiting atmospheric dispersion factors. Releases from containment through the SBVS are assumed to be released from the plant stack with a filter efficiency of 99% for particulates and 95% for both elemental and organic iodine. The activity that bypasses the SBVS is released unfiltered to the environment via a ground level release from containment.

8. The initial leakage rate from containment is 0.5% of the containment volume per day. This leak rate is reduced by 50% after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 0.25%/day. 9.6% of the containment leakage is assumed to bypass the SBVS filters.

9. For the release inside of containment, natural deposition of the radionuclides is credited consistent with the LOCA methodology presented in Section 15.4.1.5.3. Containment sprays are not credited.

10. For the release inside of containment, containment purge is assumed coincident with the beginning of the event. As discussed in Section 6.2.5.2.2, the Hydrogen Purge system includes a demister, HEPA prefilter, two charcoal adsorber banks in series and a HEPA afterfilter. The HEPA filters are tested to meet 99.95% minimum filter efficiency. The charcoal adsorber banks are tested to meet 99% minimum filter efficiency. The analysis uses 99.5% for the HEPA filters and 98% for the charcoal filters. The Hydrogen Purge system has no automatic containment isolation valve and must be manually isolated in the event of an accident. The release fraction associated with the fuel/gap release between 30 seconds and 285 seconds when the hydrogen purge line is manually isolated is applicable.

15.4.5.4.4 Methodology

Input assumptions used in the dose consequence analysis of the CEA Ejection are provided in Table 1 5.4.5-3. The postulated accident consists of two cases. One case assumes that 100% of the activity released from the damaged fuel is instantaneously and homogeneously mixed throughout the containment atmosphere, and the second case assumes that 100% of the activity released from the damaged fuel is completely dissolved in the primary coolant and is available for release to the secondary system.

For the containment release case, 100% of the activity is released instantaneously to the containment. The releases from the containment correspond to the same leakage points discussed for the LOCA in Section 15.4.1.5.3. Natural deposition of the released activity inside of containment is credited. In addition, the shield building ventilation system (SBVS) is credited. Removal of activity via containment spray is not credited.

For the secondary release case, primary coolant activity is released into the SGs by leakage across the SG tubes. The activity on the secondary side is then released via steaming from the ADVs until the RCS is cooled to 212°F. All noble gases associated with this leakage are assumed to be released directly to the environment. The primary-to-secondary leakage is assumed to continue until the faulted steam generator is completely isolated at 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In addition, the analysis assumes that the initial iodine activity of both SGs is immediately released to the environment. The secondary coolant iodine concentration is assumed to be the maximum value of 0.1 Ci/gm DE I-131 permitted by TS. These release assumptions are consistent with the requirements of RG 1.183.

1 5.4.5-2c Amendment No. 25 (0 4/12)

The CEA Ejection is evaluated with the assumption that 0.5% of the fuel experiences FCM and 9.5% of the fuel experiences DNB. The activity released from the damaged fuel corresponds to the requirements set out in Regulatory Position 1 of Appendix H to RG 1.183. A radial peaking factor of 1.70 is applied in the development of the source terms.

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

Initially the ventilation system is assumed to be operating in normal mode. The air flow distribution during this mode is 920 cfm of unfiltered fresh air and an assumed value of

460 cfm of unfiltered inleakage.

After the start of the event, the Control Room is isolated due to a high radiation reading in the Control Room ventilation system. A 50-second delay is applied to account for diesel generator start time, damper actuation time, instrument delay, and detector response time. After isolation, the air flow distribution consists of 0 cfm of makeup flow from the outside, 460 cfm of unfiltered inleakage, and 1760 cfm of filtered recirculation flow.

At 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> into the event, the operators are assumed to initiate makeup flow from the outside to the control room. During this operational mode, the air flow distribution consists of up to 504 cfm of filtered makeup flow, 460 cfm of unfiltered inleakage, and 1256 cfm of filtered recirculation flow.

The Control Room ventilation filter efficiencies that are applied to the filtered makeup and recirculation flows are 99% for particulate, 95% elemental iodine, and 95% organic iodine.

15.4.5.4.5 Radiological Consequences

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

For the CEA secondary side release case, releases from the SGs are assumed to occur from the ADV that produces the most limiting /Qs. When the Control Room Ventilation System is in normal mode, the most limiting /Q corresponds to the worst air intake to the control room. When the ventilation system is isolated, the limiting /Q corresponds to the midpoint between the two control room air intakes. The operators are assumed to reopen the most favorable air intake at 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Development of control room atmospheric dispersion factors is discussed in Appendix 2J. The /Qs for the secondary releases are summarized in Table 15.4.5-6. For the CEA inside of containment release case, the /Qs for containment leakage are assumed to be identical to those for the LOCA discussed in Section 15.4.1.5.4.

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

The radiological consequences of the CEA Ejection are analyzed using the RADTRAD-NAI code and the inputs/assumptions previously discussed. As shown in Table 15.4.5-7, the results of both cases for EAB dose, LPZ dose, and Control Room dose are all within the appropriate regulatory acceptance criteria.

15.4.5-2d Amendment No. 26 (11/13)

DELETED 15.4.5-2e Amendment No. 26 (11/13)

Core Power 3W 3W 3,020 MWt +

0.3% 3,020 MWt +

0.3% Core Inlet Temperature 532°F 532°F 551°F 551°F RCS Flow Rate 375,000 gpm 375,000 gpm 375,000 gpm 375,000 gpm Pressurizer Pressure 2,250 psia 2,250 psia 2,250 psia 2,250 psia Pressurizer Level 33.09% 33.09% 65.6% (SAFDL) 69% (overpressure) 65.6% Scram Reactivity 3600 pcm 3600 pcm 5000 pcm 5000 pcm Moderator Temperature Coefficient

+7 pcm/°F -7.7 5 pcm/°F +2 pcm/°F -7.75 pcm/°F Doppler Reactivity Coefficient BOC fuel temperature dependent feedback EOC fuel temperature dependent feedback -0.80 pcm/°F -1.00 pcm/°F Gap Conductance Conservative BOC value Conservative EOC value Conservative BOC value Conservative EOC value VHP RPS Trip Setpoint 25% RTP 25% RTP 112% RTP 112% RTP VHP RPS Trip Delay

1.1 seconds

1.1 seconds

0.4 seconds

0.4 seconds CEA Holding Coil Delay

0.5 seconds

0.5 seconds

0.5 seconds

0.5 seconds CEA Drop Time (excluding holding coil delay time)

2.9 seconds

2.9 seconds

2.9 seconds

2.9 seconds Ejected CEA worth 650 pcm 530 pcm 400 pcm 150 pcm Post-ejection F Q 5.0 12.0 2.5 2.5 SG Tube Plugging 10% 10% 10% 10% Ejected rod worth, pcm 525 350 375 150 Doppler Reactivity Coefficient, pcm/°F -1.21 -1.39 -1.12 -1.31 Post ejection F Q 4.49 7.60 3.58 3.33 Delayed neutron fraction 0.00638 0.00527 0.00638 0.00527

15.4.5-3 Amendment No. 26 (11/13)

BOC HZP Beginning of reactivity insertion 0.0 Ejected CEA fully withdrawn 0.10 VHPT setpoint reached (NI signal) 1.18 Maximum nuclear power 1.42 Reactor scram VHPT (including trip response delay

) 2.28 CEA insertion begins 2.78 Maximum core heat flux through cladding 4.3 MDNBR 4.3 Maximum fuel centerline temperature 5.4 EOC HZP Beginning of reactivity insertion 0.0 Ejected CEA fully withdrawn 0.10 VHPT setpoint reached (NI signal) 1.44 Maximum nuclear power 1.62 Reactor scram VHPT (including trip response delay) 2.54 CEA insertion begins 3.04 MDNBR 4.0 Maximum core heat flux through cladding 4.1 Maximum fuel centerline temperature 5.4 BOC HFP Beginning of reactivity insertion 0.0 0.0 VHPT setpoint reached (NI signal) 0.02 0.02 Ejected CEA fully withdrawn 0.10 0.10 Maximum nuclear power 0.14 0.14 Reactor scram VHPT (including trip response delay) 0.42 0.42 CEA insertion begins 0.92 0.92 Maximum core heat flux through cladding 2.0 2.0 MDNBR 2.0 N/A Pressurizer safety valves open N/A 3.3 Maximum fuel centerline temperature 3.3 N/A Maximum RCS pressure N/A 3.5 Pressurizer safety valves close N/A 4.6 EOC HFP Beginning of reactivity insertion 0.0 VHPT setpoint reached (NI signal) 0.05 Ejected CEA fully withdrawn 0.10 Maximum nuclear power 0.13 Reactor scram VHPT (including trip response delay) 0.45 CEA insertion begins 0.95 Maximum core heat flux through cladding 1.3 MDNBR 1.3 Maximum fuel centerline temperature 3.0

15.4.5-4a Amendment No. 26 (11/13)

MDNBR (% fuel failure) 2.496 (0%) 2.516 (0%) 2.067 (0%) 3.792 (0%) MDNBR limit 1.164 1.164 1.164 1.164 Peak fuel centerline temperature, °F (% fuel failure) 3878 (0%) 3977 (0%) 4594 (0%) 4011 (0%) Fuel centerline melt temperature limit, °F 4908 4623 4908 4623 Total deposited fuel enthalpy, cal/g m 111.3 137.2 140.1 129.4 Total deposited fuel enthalpy limit, cal/g m 200 200 200 200 Peak radial average fuel enthalpy rise, cal/gm < 100 < 100 < 100 < 100 Peak radial average fuel enthalpy rise Limit, cal/gm 150 for lower burned fuel 150 for lower burned fuel 150 for lower burned fuel 150 for lower burned fuel

15.4.5-4b Amendment No. 26 (11/13)

Table 15.4.5-3 Control Element Assembly (CEA) Ejection Inputs and Assumptions Input/Assumption Value Core Power Level 3030 MW th (3020 + 0.3%) Core Average Fuel Burnup 4 9 ,00 0 MWD/MTU Fuel Enrichment 1.5 - 5.0 w/o Maximum Radial Peaking Factor 1.6 5 Percent of Fuel Rods in DNB 9.5% Percent of Fuel Rods with Centerline Melt 0.5% Core Fission Product Inventory Table 15.4.1

-1e Initial RCS Equilibrium Activity 1.0 Ci/gm DE I

-131 and 518.9 Ci/gm DE Xe-133 gross activity (Table 15.4.1

-9) Initial Secondary Side Equilibrium Iodine Activity 0.1 Ci/gm DE I

-131 (Table 15.4.6

-8) Release Fraction from DNB Fuel Failures Section 1 of Appendix H to RG 1.183 Release Fraction from Centerline Melt Fuel Failures Section 1 of Appendix H to RG 1.183 Steam Generator Tube Leakage 0.5 gpm (Table 15.4.5

-5) Time to Terminate SG Tube Leakage 12.4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> s Secondary Side Mass Releases to Environment Table 15.4.5

-4 SG Tube Uncovery Following Reactor Trip Time to tube recovery Flashing Fraction 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 5 % Steam Generator Secondary Side Partition Coefficient Flashed tube flow none Non-flashed tube flow 100 Time to Reach 212 oF and Terminate Steam Release 1 2.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> RCS Mass minimum 406,71 5 lb m Minimum mass used for fuel failure dose contribution to maximum SG tube leakage activity SG Secondary Side Mass minimum 120,72 4 lb m (per SG) maximum 2 26,800 lb m (per SG) Minimum used for primary

-to-secondary leakage to maximize secondary nuclide concentration. Maximum used for initial secondary inventory release to maximize secondary side dose contribution.

Chemical Form of Iodine Released to Containment Particulate 95% Elemental 4.85% Organic 0.15% Chemical Form of Iodine Released from SGs Particulate 0% Elemental 97% Organic 3%

15.4.5-5 Amendment No. 26 (11/13)

Table 15.4.5-3 Control Element Assembly (CEA) Ejection Inputs and Assumptions Atmospheric Dispersion Factors Offsite Onsite Appendix 2I Table 15.4.5

-6 and Appendix 2J Control Room Ventilation System Time of Control Room Ventilation System Isolation Time of Control Room Filtered Makeup Flow Control Room Unfiltered Inleakage 50 seconds 1.5 ho urs 460 cfm Breathing Rates RG 1.183 Sections 4.1.3 and 4.2.6 Control Room Occupancy Factor RG 1.183 Section 4.2.6 Containment Volume Containment Leakage Rate 0 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 2.506E+06 ft 3 0.5% (by volume)/day 0.25% (by volume)/day Secondary Containment Filter Efficiency Particulate 99% Elemental 95% Organic 95% Secondary Containment Drawdown Time 310 seconds Secondary Containment Bypass Fraction 9.6% Containment Natural Deposition Coefficients Aerosols 0.1 hr-1 Elemental Iodine 2.89 hr-1 Organic Iodine None

15.4.5-6 Amendment No. 26 (11/13)

Time (h r) SG Steam Release Rat e (lb m/min) 0 5486.1 5 0.50 2820.8 6 2.00 2846.3 6 12.40 0.0 0

Time (h r) SG Tube Leakage (lb m/min) 0 3.103 0.50 3.361 0.75 3.428 1.00 3.536 1.39 3.565 2.00 3.657 4.00 3.756 8.00 3.945 10.50 4.012 12.40 0.000

15.4.5-7 Amendment No. 26 (11/13)

Time (hours)

/Q (sec/m 3) 0 6.30E-03 0.013889 2.84E-03 1.5 1.62E-03 2 1.32E-03 8 5.06E-04 24 3.88E-04 96 3.30 E-0 4 720 3.30E-04

TABLE 15.4.5-7 CEA EJECTION DOSE CONSEQUENCES Case EAB Dose (1) (REM TEDE) LPZ Dose (2) (REM TEDE) Control Roo M Dose (2) (REM TEDE) CEA Ejection Containment Release 0.29 0.71 3.26 CEA Ejection Secondary Release 0.28 0.55 3.30 Acceptance Criteria 6.3 6.3 5 (1) Worst 2-hour dose

(2) Integrated 30-day dose

15.4.5-8 Amendment No. 26 (11/13)

15.6

SUMMARY

OF OPERATING LIMITS Operating limits for the St. Lucie Unit 1 nuclear plant are summarized below. Methods of analysis for determining or verifying the operating limits are detailed in Subsection 15.6.5 and Reference 1.

15.6.1 REACTOR PROTECTION SYSTEM

The reactor protection system (RPS) is designed to assure that the reactor is operated in a safe and conservative manner. The input parameters for the RPS are denoted as limiting safety system settings (LSSS). The values or functional representation of the LSSSs are calculated to ensure adherence to the specified acceptable fuel design limits (SAFDLS) during steady state and anticipated operational occurrences (AOOs). The safe operation of the reactor is also maintained by restricting reactor operation to be in conformance with the limiting conditions for operation (LCOS) which are administratively applied at the reactor plant. The LSSS and LCO parametric values are presented in the following sections.

15.6.2 SPECIFIED ACCEPTABLE FUEL DESIGN LIMITS The SAFDLs are experimentally or analytically based limits on the fuel and cladding which preclude fuel damage. These limits may not be exceeded during steady-state operation or during AOOs. The SAFDLs are used to establish the reactor setpoints to ensure safe operation of the reactor. The specific SAFDLs used to establish the setpoints are:

- The local power density (LPD) which coincides with fuel centerline melt.

- The MDNBR corresponding to the accepted criterion which protects against the occurrence of DNB.

The setpoint verification analysis for the current cycle is performed with a LPD limit corresponding to the maximum LHR that can occur in a fuel rod without the occurrence of fuel centerline melt. It is noted that reload fuel contains gadolinia-bearing fuel rods which, for a given LPD, will operate with a higher fuel temperature and will consequently have a lower LPD limit. These rods are modeled in the centerline melt calculations to ensure that, with a standard fuel rod at the maximum LPD limit, the maximum LPD of the gadolinia-bearing rods will remain far enough below the UO 2 melt limit to prevent centerline melt.

Due to the increased thermal performance of HTP assemblies, as seen in Reference 3, and the fact that the maximum power of the limiting bi-metallic assembly is much less than the peak assembly power, a HTP assembly will be limiting from the standpoint of DNBR.

The HTP critical heat flux correlation was used in the thermal margin analysis with statistical parameters corresponding to an upper 95/95 DNBR limit with an allowance for mixed core penalty. Observance of the limiting conditions for operation will protect against DNB with 95% probability at a 95% confidence level during an AOO.

15.6-1 Amendment No. 26 (11/13) 15.6.3 LIMITING SAFETY SYSTEM SETTINGS 15.6.3.1 Local Power Distribution Control The local power distribution (LPD) trip limit is the locus of the limiting values of core power level versus axial shape index that will produce a reactor trip to prevent exceeding the fuel centerline melt limit. The correlation between allowed core power level and peripheral axial shape index (ASI) was determin ed using methods which take into account the total calculated nuclear peaking and the measurement and calculational uncertainties associated with power peaking.

15.6.3.2 Thermal Margin/Low Pressure The thermal margin/low pressure (TM/LP) trip protects against the occurrence of DNB during steady state operations and for many, but not all, AOOs. This reactor trip system monitors the primary system pressure, core inlet temperature, core power and ASI and a reactor trip occurs when primary system pressure falls below the computed limiting core pressure, Pvar. As with the LPD trip, a statistical setpoint methodology (Reference 1) is used to verify the adequacy of the existing TM/LP trip. The methodology for the TM/LP trip accounts for uncertainties in core operating conditions, HTP DNB correlation uncertainties, and uncertainties in power peaking. The existing TM/LP trip function for EPU operation at 3020 MWt is given by:

P var = 2061 x A1(ASI) x QR1(Q)+15.85 x T in-8950, where Q is the higher of the thermal power and the nuclear flux power, T in is the inlet temperature in O F and A1 and QR1 are shown in Figures 15.6-2 and 15.6-3, respectively.

15.6.3.3 Additional Trip Functions

In addition to the LPD and TM/LP trip functions, other reactor system trips have been determined to provide input to the setpoint verification. The setpoints and uncertainties for these trips are shown in Table 15.6-

4.

15.6.4 LIMITING CONDITIONS FOR OPERATION 15.6.4.1 DNB Monitoring The validity of the existing LCO for allowable core power as a function of ASI was verified to ensure adherence to the SAFDL on DNB during a postulated CEA drop and loss-of-flow operational occurrences. The statistical analysis accounted for the effects of uncertainties associated in core operating parameters, the HTP critical heat flux correlation, and power peaking. The allowed core power as a function of ASI for

the LCO is provided for the current cycle in the Technical Specifications/COLR.

15.6-2 Amendment No. 26 (11/13) 15.6.4.2 Linear Heat Rate Monitoring In the event that the incore detector system is not in operation for an extended period of time, the line ar heat rate will be monitored through the use of an LPD LCO. The verification of this LCO was performed in a fashion similar to that used in verifying the LPD limiting safety system setting (Section 15.6.3.1). The LPD LCO limits core power so that the linear heat rate LCO based on loss of coolant accident (LOCA) considerations is not exceeded. The LHR heat rate LCO protected by the LPD LCO is depicted in Figure 15.6-7.

15.6.5 SETPOINT ANALYSIS 15.6.5.1 Limiting Safety System Settings

Local Power Distribution

The LPD trip monitors core power and ASI in order to initiate a reactor scram which precludes exceeding fuel centerline melt conditions. In the analysis for this trip function a large number of axial power distributions were examined to establish bounding values of total power peaking, F Q versus ASI. Axial power distributions and other core neutronics related parameters used in the setpoint verification analyses were generated. Statistical methods were then employed to account for the uncertainties in the parameters that are given in Table 15.6-

1. The allowed power for each ASI was calculated statistically incorporating the uncertainties listed in Table

15.6-1 as described in Reference 1. The results of this calculation verify the adequacy of the LPD LSSS trip function shown in the Technical Specifications/COLR for St. Lucie Unit 1.

Thermal Margin/Low Pressure LSSS

The thermal margin/low pressure (TM/LP) trip is designed to shut the reactor down should the reactor conditions (ASI, inlet temperature, core power and pressure) approach the point where DNB might occur during either normal operation or an AOO. The present analysis uses the HTP critical heat flux correlation and the statistical setpoint methodology described in Reference 1 and is consistent with the NRC's Standard Review Plan in requiring DNB to be avoided with 95% probability at a 95% confidence level.

15.6-3 Amendment No. 26 (11/13)

The uncertainties shown in Tables 15.6-2 and 15.6

-4, and the transient biases in Table 15.6-3 are included in the verification of the TM/LP trip as described in Reference 1. Axial power profiles and scram curves for the current cycle were included in this analysis. An excess margin of protection is provided by the existing trip for the current cycle.

15.6.5.2 Limiting Conditions for Operation

DNB Monitoring

The TM/LP trip system does not monitor reactor coolant flow and does not consider changes in power peaking which do not significantly change ASI. Thus, the TM/LP trip generally does not provide DNB protection for the four-pump coastdown and CEA drop AOOs.

The LCO presented here administratively protects the DNB SAFDL for these transients.

The method used to establish the DNB LCO involved simulations of the CEA drop and the loss-of-flow transients using the core thermal hydraulic code XCOBRA-IIIC(10), to determine the initial power, as a function of ASI, which provides protection from DNB with 95% probability. The uncertainties listed in Tables 15.6-5, 15.6-6 and 15.6-7 are applied using the methodology described in Reference 1 and neutronics data. The statistical analysis accounted for the effects of uncertainties associated with incore operating parameters, the HTP critical heat flux correlation, and power peaking. Axial power profiles and scram curves for the EPU were included in the analysis. This analysis verifies the adequacy of the DNB LCO tent.

Linear Heat Rate Monitoring

The plant Technical Specifications allow plant operations for limited periods of time with the incore detectors out of service. In this situation, the LPD LCO barn provides protection in steady-state operation against penetration of the LPD limit established by LOCA considerations. The statistical methodology for the LPD LCO is essentially the same as that for LPD LSSS except the uncertainties listed in Table 15.6-5 were used, as opposed to the values in Table 15.6-

1.

The allowed power versus ASI was statistically analyzed to account for the appropriate uncertainties.

This analysis demonstrates the adequacy of the LPD LCO tent. The LHR protected by the LPD LCO is depicted in Figure 15.6-

7.

15.6-4 Amendment No. 26 (11/13)

15.

6.6 REFERENCES

FOR SECTION 15.6

1. EMF-1961(P)(A) Revision 0, Statistical Setpoint/Transient Methodology for Combustion Engineering Type Reactors,Siemens Power Corporation, July 2000.

2. XN-NF-75-21(P) (A), Revision 2, XCOBRA-IIIC: A Computer Code to Determine the Distribution of Coolant During Steady-State and Transient Core Operation, Exxon Nuclear Company, January 1986. 3. EMF-92-153(P)(A), Revision 1, Siemens Power Corporation, January 2005.

15.6-5 Amendment No. 26 (11/13)

DELETED

15.6-5a Amendment No. 26 (11/13)

TABLE 15.6-1 Uncertainties Applied in LPD LSSS Calculations Parameter Value a Engineering tolerance

+ 3% Peaking uncertainty 7%b Power measurement uncertainty See Figure 15.6

-8 Thermal power uncertainty

+/- 9.308% (of rated) c LPD trip overshoot uncertainty 0.0% LPD trip transient offset

+/- 9.42% ASI uncertainty

+ 6% _______________

a Unless otherwise noted the distributions are treated as normal, two-sided, and the uncertainty range represents 95% bound ( 1.96 ) b Treated as normal, one-sided distribution at 95% probability (1.645 )

c The thermal power uncertainty includes the effects of calorimetric uncertainty, thermal power instrumentation channel uncertainty, and measurement uncertainties.

d Not treated statistically; treated as a bias.

15.6-6 Amendment No. 26 (11/13)

TABLE 15.6-2 Uncertainties Applied in TM/LP LSSS Calculations Parameter Value (a) Engineering tolerance

+/- 3% Peaking (F r T) 6.0%(b) Power measurement uncertainty See Figure 15.6

-8 PZR Pressure uncertainty

+/- 40 psi TM/LP trip uncertainty

+/- 155 psi Trip biases Table 15.6

-4 Inlet coolant temperature

+/- 3.0°F HTP correlation See Reference 3 Flow measurement uncertainty

+/- 15,000 gpm ASI uncertainty

+/- 6% _______________

a Unless otherwise noted the distributions are treated as normal, two-sided, and the uncertainty range represents 95% bound ( 1.96). b Treated as normal, one-sided distribution at 95/95 probability (1.645).

15.6-7 Amendment No.26 (11/13)

TABLE 15.6-3 Transient Biases Applied in the TM/LP LSSS Calculation Parameter Stuck-Open PORV UCRW at Power Excess Load Power (% of Rated) 0.19 -0.16 22.22 Pressure (psi) 4.70 25.20 -3.00 Cold Leg Temperature

(°F) 0.06 -1.65 3.40 Hot Leg Temperature

(°F) 1.13 3.92 0.43

(These biases account for differences between the measured parameter and actual core conditions during each transient.)

15.6-8 Amendment No. 26 (11/13)

TABLE 15.6-4 Additional Trip Functions (Only Those Used in Setpoint Verification)

Parameter (Database Keys)

Value Setpoint Uncertainty (a) Low reactor coolant flow 95.0% 4% High pressurizer pressure 2400 psia 40 psi (b) VHPT 9.61% of rated (offset) 107% of rated (ceiling)

See Footnote (c) _______________

a The distributions are treated as normal, and the uncertainty range represents a two-sided 95% bound

( 1.96). b The high pressurizer pressure trip uncertainty applied for Setpoint verification is conservative bounding of the required 35 psi uncertainty.

c A combination of various uncertainties are applied to the VHPT setpoint for the LPD LSSS and LPD LCO setpoint verifications.

15.6-9 Amendment No. 26 (11/13)

TABLE 15.6-5 General Uncertainties Applied in the LCO Calculations Paramete r Uncertainty Value (a) Engineering tolerance

+ 3% Peaking uncertainty (F r T) 6.0%(b) Flow measurement 15,000 gpm Pressure measurement

+ 40 psi Tinlet + 3.0 °F Power measurement See Figure 15.6

-8 ASI + 6% HTP correlation See Reference 3

______________

a Unless otherwise noted, the distributions are treated as normal, two-sided, and the uncertainty range represents 95% bound ( 1.96 ). b Treated as normal, one-sided distribution at 95/95 probability (1.645 ).

15.6-10 Amendment No. 26 (11/13)

TABLE 15.6-6 Additional Uncertainties Applied in DNB LCO CEAD Calculations Parameter Uncertainty Value (a) CEAD Tinlet +/- 0.0°F CEAD Pressure

+/- 0.0 psid

_______________

a Unless otherwise noted the distributions are treated as normal, two-sided, and the uncertainty range represents 95% bound ( 1.96 ).

15.6-10a Amendment No. 26 (11/13)

TABLE 15.6-7 Additional Uncertainties Applied in DNB LCO LOCF Calculation Parameter Uncertainty Value (a) Total peaking 7%(b) CEA holding coil delay 0.0 s (c) LOCF trip 0.040000 of rated (b) Pump coastdown coefficient 0.007469 1/

s (b) Scram-speed scale factor 0.0 (c) Scram worth

+/-0.0% (k/k)(d) ______________

a Unless otherwise noted, the distributions are treated as normal, two-sided, and the uncertainty range represents 95% bound ( 1.96 ). b Treated as normal, one-sided distribution at 95/95 probability (1.645 ). c A deterministic approach is conservatively being used for the EPU due to the age of the supporting surveillance test data. The uncertainty in the rod drop and clutch coil delays are being treated deterministically which drives this uncertainty to zero.

d Bounding value includes 10% uncertainty allowance.

15.6-10b Amendment No. 26 (11/13)

Florida Power & Light CompanySt. Lucie Plant Unit 1Figure 15.6-1Amendment No. 21 (12/05)

• -....... -< ....,.; z .o ..... E-t u 1.36 z ::> 1.30 z 0 ..... E-t 1.26 u 1.20 0 u 0.. ..... 1.15 0:: E-t 0.. 1.10 ....:! ......... E-t 1.05

• 1.00 -0.6 -0.5 -0.4 -0.3 -0.2 * -0.1 0.0 0.1 AXIAL SHAPE 0.2 0.3 0.4 0.5 0.6 INDEX AMENDMENT NO. 7 (7/88) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 ST. LUCIE UNIT 1, TM/LP TRIP FUNCTION A1 FIGURE 15.6-2

• " ...... 0 '--"' z 0 ....... E-i u z p 11. z 0 ....... E-i u rxl 0 u 0.. ....... 0:: E-i 0.. H ...........

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• 1.2 1.0 0.8 0.6 0.4 0.2 0 10 20 30 40 60 60 70 80 90 POWER (PERCENT OF RATED) 100 uo 120 AMENDMENT NO. 7 (7188) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 ST. LUCIE UNIT 1, TM/LP TRIP FUNCTION QR1 FIGURE 15.6*3 Florida Power & Light CompanySt. Lucie Plant Unit 1Figure 15.6-4Amendment No. 21 (12/05)

Florida Power & Light CompanySt. Lucie Plant Unit 1Figure 15.6-5Amendment No. 21 (12/05)

Florida Power & Light CompanySt. Lucie Plant Unit 1Figure 15.6-6Amendment No. 21 (12/05)