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Millstone Power Station Unit 2 Safety Analysis Report

Chapter 14: Safety Analysis

Revision 38—06/30/20 MPS-2 FSAR 14-i

CHAPTER 14—SAFETY ANALYSIS

Table of Contents

Section Title Page

14.0 GENERAL......................................................................................................... 14.0-114.0.1 Classification of Plant Conditions ............................................................ 14.0-1

14.0.1.1 Acceptance Criteria................................................................................... 14.0-2

14.0.1.2 Classification of Accident Events by Category ........................................ 14.0-3

14.0.2 Plant Characteristics and Initial Conditions.............................................. 14.0-3

14.0.3 Power Distribution.................................................................................... 14.0-4

14.0.4 Range of Plant Operating Parameters and States..................................... 14.0-4

14.0.5 Reactivity Coefficients Used In The Safety Analysis .............................. 14.0-4

14.0.6 Scram Insertion Characteristics ................................................................ 14.0-4

14.0.7 Trip Setpoint Verification ......................................................................... 14.0-4

14.0.7.1 Reactor Protection System........................................................................ 14.0-5

14.0.7.2 Specified Acceptable Fuel Design Limits ................................................ 14.0-5

14.0.7.3 Limiting Safety System Settings............................................................... 14.0-6

14.0.7.3.1 Local Power Density................................................................................. 14.0-6

14.0.7.3.2 Thermal Margin/Low Pressure ................................................................. 14.0-6

14.0.7.3.3 Additional Trip Functions......................................................................... 14.0-6

14.0.7.4 Limiting Conditions for Operation ........................................................... 14.0-6

14.0.7.4.1 Departure From Nucleate Boiling............................................................. 14.0-6

14.0.7.4.2 Linear Heat Rate ....................................................................................... 14.0-7

14.0.7.5 Setpoint Analysis ...................................................................................... 14.0-7

14.0.7.5.1 Limiting Safety System Settings............................................................... 14.0-7

14.0.7.5.2 Limiting Conditions for Operation ........................................................... 14.0-8

14.0.8 Component Capacities and Setpoints ....................................................... 14.0-8

14.0.9 Plant Systems and Components Available For Mitigation of Accident Effects........................................................................................ 14.0-8

14.0.10 Effects of Mixed Assembly Types and Fuel Rod Bowing ....................... 14.0-9

14.0.11 Plant Licensing Basis and Single Failure Criteria .................................... 14.0-9

14.0.12 Plot Variable Nomenclature.................................................................... 14.0-10

14.0.13 References............................................................................................... 14.0-10

14.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM......... 14.1-1

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CHAPTER 14—SAFETY ANALYSISTable of Contents (Continued)

Section Title Page

14.1.1 Decrease in Feedwater Temperature......................................................... 14.1-1

14.1.1.1 Event Initiator ........................................................................................... 14.1-1

14.1.1.2 Event Description ..................................................................................... 14.1-1

14.1.1.3 Reactor Protection..................................................................................... 14.1-1

14.1.1.4 Disposition and Justification..................................................................... 14.1-1

14.1.2 Increase in Feedwater Flow ...................................................................... 14.1-2

14.1.2.1 Event Initiator ........................................................................................... 14.1-2




14.1.3 Increase in Steam Flow............................................................................. 14.1-3

14.1.3.1 Event Initiator ........................................................................................... 14.1-3




14.1.3.5 Definition of Events Analyzed ................................................................. 14.1-5

14.1.3.6 Analysis Results........................................................................................ 14.1-5

14.1.3.7 Conclusion ................................................................................................ 14.1-6

14.1.4 Inadvertent Opening of a Steam Generator Relief or Safety Valve.......... 14.1-6

14.1.4.1 Event Initiator ........................................................................................... 14.1-6




14.1.5 Steam System Piping Failures Inside and Outside of Containment ......... 14.1-6

14.1.5.1 Pre-Scram Analysis................................................................................... 14.1-7

14.1.5.1.1 Event Initiator ........................................................................................... 14.1-7

14.1.5.1.2 Event Description ..................................................................................... 14.1-7

14.1.5.1.3 Reactor Protection..................................................................................... 14.1-7

14.1.5.1.4 Disposition and Justification..................................................................... 14.1-7

14.1.5.1.5 Definition of Events Analyzed ................................................................. 14.1-8

14.1.5.1.6 Analysis Results...................................................................................... 14.1-13

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Section Title Page

14.1.5.1.7 Conclusions............................................................................................. 14.1-15

14.1.5.2 Post-Scram Analysis ............................................................................... 14.1-15

14.1.5.2.1 Event Initiator ......................................................................................... 14.1-15

14.1.5.2.2 Event Description ................................................................................... 14.1-15

14.1.5.2.3 Reactor Protection................................................................................... 14.1-16

14.1.5.2.4 Disposition and Justification................................................................... 14.1-16

14.1.5.2.5 Definition of Events Analyzed ............................................................... 14.1-17


14.1.5.2.7 Conclusions............................................................................................. 14.1-25

14.1.5.3 Radiological Consequences of a Main Steam Line Break...................... 14.1-26

14.1.6 References............................................................................................... 14.1-27

14.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM........ 14.2-114.2.1 Loss of External Load............................................................................... 14.2-1

14.2.1.1 Event Initiator ........................................................................................... 14.2-1






14.2.1.7 Conclusion ................................................................................................ 14.2-3

14.2.2 Turbine Trip .............................................................................................. 14.2-3

14.2.2.1 Event Initiator ........................................................................................... 14.2-3




14.2.3 Loss of Condenser Vacuum...................................................................... 14.2-4

14.2.4 Closure of the Main Steam Isolation Valves ............................................ 14.2-4

14.2.4.1 Event Initiator ........................................................................................... 14.2-4



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Section Title Page




14.2.4.7 Conclusion ................................................................................................ 14.2-8

14.2.5 Steam Pressure Regulator Failure............................................................. 14.2-8

14.2.6 Loss of Nonemergency AC Power to the Station Auxiliaries .................. 14.2-8

14.2.7 Loss of Normal Feedwater Flow .............................................................. 14.2-8

14.2.7.1 Event Initiator ........................................................................................... 14.2-8




14.2.7.5 Definition of Events Analyzed ............................................................... 14.2-10


14.2.7.6 Conclusions............................................................................................. 14.2-11

14.2.8 Feedwater System Pipe Breaks Inside and Outside Containment .......... 14.2-11

14.2.9 References............................................................................................... 14.2-11

14.3 DECREASE IN REACTOR COOLANT SYSTEM FLOW............................. 14.3-114.3.1 Loss of Forced Reactor Coolant Flow ...................................................... 14.3-1

14.3.1.1 Event Initiator ........................................................................................... 14.3-1






14.3.1.7 Conclusion ................................................................................................ 14.3-3

14.3.2 Flow Controller Malfunction .................................................................... 14.3-3

14.3.3 Reactor Coolant Pump Rotor Seizure ....................................................... 14.3-3

14.3.3.1 Event Initiator ........................................................................................... 14.3-3



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Section Title Page




14.3.3.7 Conclusion ................................................................................................ 14.3-4

14.3.4 Reactor Coolant Pump Shaft Break .......................................................... 14.3-4

14.3.5 References................................................................................................. 14.3-4

14.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES ..................... 14.4-114.4.1 Uncontrolled Control Rod/Bank Withdrawal From A Subcritical or Low-Power

Startup Condition...................................................................................... 14.4-1

14.4.1.1 Event Initiator ........................................................................................... 14.4-1






14.4.1.7 Conclusion ................................................................................................ 14.4-3

14.4.2 Uncontrolled Control Rod/Bank Withdrawal At Power........................... 14.4-3

14.4.2.1 Event Initiator ........................................................................................... 14.4-3






14.4.2.7 Conclusion ................................................................................................ 14.4-4

14.4.3 Control Rod Misoperation ........................................................................ 14.4-5

14.4.3.1 Dropped Control Rod/Bank ...................................................................... 14.4-5

14.4.3.1.1 Event Initiator ........................................................................................... 14.4-5





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Section Title Page

14.4.3.1.6 Analysis Results........................................................................................ 14.4-6

14.4.3.1.7 Conclusion ................................................................................................ 14.4-7

14.4.3.2 Dropped Part-Length Control Rod ........................................................... 14.4-7

14.4.3.3 Malpositioning of the Part-Length Control Rod Group............................ 14.4-7

14.4.3.4 Statically Misaligned Control Rod/Bank.................................................. 14.4-7

14.4.3.5 Single Control Rod Withdrawal ............................................................... 14.4-7

14.4.3.5.1 Event Initiator ........................................................................................... 14.4-7





14.4.3.5.6 Analysis Results........................................................................................ 14.4-9

14.4.3.5.7 Conclusion ................................................................................................ 14.4-9

14.4.3.6 Reactivity Control Device Removal Error During Refueling .................. 14.4-9

14.4.3.7 Variations in Reactivity Load to be Compensated by Burnup or On-Line Refueling................................................................................................... 14.4-9

14.4.4 Startup of an Inactive Loop .................................................................... 14.4-10

14.4.4.1 Event Initiator ......................................................................................... 14.4-10

14.4.4.2 Event Description ................................................................................... 14.4-10

14.4.4.3 Reactor Protection................................................................................... 14.4-10

14.4.4.4 Disposition and Justification................................................................... 14.4-10

14.4.5 Flow Controller Malfunction .................................................................. 14.4-10

14.4.6 Chemical and Volume Control System Malfunction That Results in a Decrease In The Boron Concentration in the Reactor Coolant .............................. 14.4-11

14.4.6.1 Event Initiator ......................................................................................... 14.4-11





14.4.6.6 Analysis Results...................................................................................... 14.4-13

14.4.6.7 Conclusions............................................................................................. 14.4-13

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Section Title Page

14.4.7 Inadvertent Loading and Operation of a Fuel Assembly in an Improper Position ................................................................................... 14.4-13

14.4.8 Spectrum of Control Rod Ejection Accidents......................................... 14.4-13

14.4.8.1 Event Initiator ......................................................................................... 14.4-13





14.4.8.6 Analysis Results...................................................................................... 14.4-15

14.4.8.7 Conclusion .............................................................................................. 14.4-16

14.4.8.8 Radiological Consequences .................................................................... 14.4-16

14.4.9 Spectrum of Rod Drop Accidents (Boiling Water Reactor) ................... 14.4-17

14.4.10 References............................................................................................... 14.4-17

14.5 INCREASES IN REACTOR COOLANT SYSTEM INVENTORY................ 14.5-114.5.1 Inadvertent Operation of the Emergency Core Cooling System That Increases

Reactor Coolant Inventory........................................................................ 14.5-1

14.5.2 Chemical Volume and Control System Malfunction That Increases Reactor Coolant Inventory ..................................................................................... 14.5-1

14.6 DECREASES IN REACTOR COOLANT INVENTORY ............................... 14.6-114.6.1 Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief

Valve ......................................................................................................... 14.6-1

14.6.1.1 Event Initiator ........................................................................................... 14.6-1






14.6.1.7 Conclusions............................................................................................... 14.6-2

14.6.2 Radiological Consequences of the Failure of Small Lines Carrying Primary Coolant Outside of Containment .............................................................. 14.6-3

14.6.3 Radiological Consequences of Steam Generator Tube Failure ................ 14.6-3

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Section Title Page

14.6.3.1 Event Initiator ........................................................................................... 14.6-3






14.6.3.6.1 Thermal-Hydraulic Calculation ................................................................ 14.6-7

14.6.3.6.2 Radiological Calculation........................................................................... 14.6-8

14.6.3.7 Conclusion ................................................................................................ 14.6-9

14.6.4 Radiological Consequences of a Main Steam Line Failure Outside Containment ................................................................................ 14.6-9

14.6.5 Loss of Coolant Accidents Resulting From a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary........................... 14.6-9

14.6.5.1 Large Break Loss of Coolant Accidents for M5 Clad Fuel .................... 14.6-10

14.6.5.1.1 Event Initiator ......................................................................................... 14.6-10





14.6.5.1.6 Summary of Results................................................................................ 14.6-15

14.6.5.1.7 Post Analysis of Record Evaluations...................................................... 14.6-15

14.6.5.1.8 Conclusions............................................................................................. 14.6-16

14.6.5.2 Small Break Loss of Coolant Accident................................................... 14.6-16

14.6.5.2.1 Event Initiator ......................................................................................... 14.6-16







14.6.5.2.8 Conclusions............................................................................................. 14.6-24

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Section Title Page

14.6.5.3 Post-LOCA Long Term Cooling ............................................................ 14.6-24

14.6.5.3.1 The Post-LOCA Long Term Cooling Plan ............................................. 14.6-24

14.6.5.3.2 Post-LOCA Long Term Cooling Equipment and Operator Actions ...... 14.6-25

14.6.5.3.3 Assumptions Used in the Long Term Cooling Analysis ........................ 14.6-26

14.6.5.3.4 Method of Analysis................................................................................. 14.6-26

14.6.5.3.5 Parameters Used in the Long Term Cooling Analysis ........................... 14.6-27

14.6.5.3.6 Results of the Long Term Cooling Analysis .......................................... 14.6-27

14.6.5.3.7 Conclusions of the Long Term Cooling Analysis .................................. 14.6-28

14.6.5.4 Large Break Loss of Coolant Accidents for Zircaloy-4 Clad Fuel......... 14.6-28

14.6.5.4.1 Event Initiator ......................................................................................... 14.6-28





14.6.5.4.6 Summary of Results................................................................................ 14.6-33


14.6.5.4.8 Conclusions............................................................................................. 14.6-34

14.6.6 References............................................................................................... 14.6-34

14.7 RADIOACTIVE RELEASES FROM A SUBSYSTEM OR COMPONENT .. 14.7-114.7.1 Waste Gas System Failure ........................................................................ 14.7-1

14.7.2 Radioactive Liquid Waste System Leak or Failure (Release to Atmosphere)........................................................................... 14.7-1

14.7.3 Postulated Radioactive Releases Due To Liquid Containing Tank Failures ............................................................................................ 14.7-1

14.7.4 Radiological Consequences Of Fuel Handling Accident ......................... 14.7-1

14.7.4.1 General...................................................................................................... 14.7-1

14.7.4.2 Method of Analysis................................................................................... 14.7-2

14.7.4.2.1 Fuel Handling Accident in the Spent Fuel Pool ....................................... 14.7-3

14.7.4.2.2 Fuel Handling Accident in Containment .................................................. 14.7-3

14.7.4.3 Results of Analysis ................................................................................... 14.7-3

14.7.4.3.1 Fuel Handling Accident in the Spent Fuel Pool ....................................... 14.7-3

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Section Title Page

14.7.4.3.2 Fuel Handling Accident in Containment .................................................. 14.7-4

14.7.4.4 Conclusions............................................................................................... 14.7-4

14.7.5 Spent fuel cask drop accidents.................................................................. 14.7-4

14.7.5.1 Spent Fuel Cask Tip Accident .................................................................. 14.7-4

14.7.5.2 Method of Analysis................................................................................... 14.7-4

14.7.5.3 Results of Analysis ................................................................................... 14.7-5

14.7.5.4 Conclusions............................................................................................... 14.7-6

14.8 MILLSTONE UNIT 2 FSAR EVENTS NOT CONTAINED IN THE STANDARD REVIEW PLAN ................................................................................................ 14.8-1

14.8.1 Failures of Equipment Which Provides Joint Control/Safety Functions .. 14.8-1

14.8.2 Containment Analysis............................................................................... 14.8-1

14.8.2.1 Main Steam Line Break Analysis ............................................................. 14.8-1

14.8.2.1.1 Event Initiator ........................................................................................... 14.8-1

14.8.2.1.2 Protective Systems.................................................................................... 14.8-1

14.8.2.1.3 Method of Analysis................................................................................... 14.8-2

14.8.2.1.4 Major Assumptions................................................................................... 14.8-2

14.8.2.1.5 Initial Conditions and Input Data.............................................................. 14.8-4

14.8.2.1.6 Results....................................................................................................... 14.8-4

14.8.2.1.7 Conclusions............................................................................................... 14.8-6

14.8.2.2 Loss of Coolant Accident Analysis .......................................................... 14.8-7

14.8.2.2.1 Events Analyzed ....................................................................................... 14.8-7

14.8.2.2.2 Method of Analysis................................................................................... 14.8-7

14.8.2.2.3 Input and Assumptions ............................................................................. 14.8-7

14.8.2.2.4 Results....................................................................................................... 14.8-8

14.8.2.2.5 Conclusion ................................................................................................ 14.8-8

14.8.3 Deleted ...................................................................................................... 14.8-8

14.8.4 Radiological Consequences of the Design Basis Accident ...................... 14.8-8

14.8.4.1 General...................................................................................................... 14.8-8

14.8.4.2 Release Pathways...................................................................................... 14.8-9

14.8.4.3 Control Room Habitability ..................................................................... 14.8-10

14.8.4.4 Offsite Dose Computation ...................................................................... 14.8-10

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Section Title Page

14.8.4.5 Conclusion .............................................................................................. 14.8-10

14.8.5 References............................................................................................... 14.8-11

Revision 38—06/30/20 MPS-2 FSAR 14-xii


List of Tables

Number Title

14.0-1 Reactor Operating Modes For Millstone Unit 2

14.0-2 Disposition of Events Summary

14.0.1-1 Accident Category Used For Each Analyzed Event

14.0.2-1 Plant Operating Conditions

14.0.2-2 Nominal Fuel Design Parameters

14.0.3-1 Core Power Distribution (Table Deleted)

14.0.4-1 Range of Key Initial Condition Operating Parameters

14.0.5-1 Reactivity Parameters (Table Deleted)

14.0.7-1 Analytical Trip Setpoints

14.0.7-2 Uncertainties Applied at HFP Condition in Local Power Density Limiting Safety System Settings Calculations

14.0.7-3 Uncertainties Applied at HFP Condition in the Thermal Margin/Low Pressure Limiting Safety System Settings Calculations

14.0.7-4 Uncertainties Applied at HFP Condition in the Local Power Density Limiting Condition for Operation Calculations

14.0.7-5 Uncertainties Applied in Departure from Nucleate Boiling Limiting Condition for Operation Calculations

14.0.8-1 Component Capacities and Setpoints

14.0.9-1 Overview of Plant Systems and Equipment Available for Transient and Accident Conditions

14.0.12-1 Nomenclature Used in Plotted Results

14.1.1-1 Available Reactor Protection for the Decrease in Feedwater Temperature Event

14.1.1-2 Disposition of Events for the Decrease in Feedwater Temperature Event

14.1.2-1 Available Reactor Protection for the Increase in Feedwater Flow Event

14.1.2-2 Disposition of Events for the Increase in Feedwater Flow Event

14.1.3-1 Available Reactor Protection for the Increase in Steam Flow Event

14.1.3-2 Disposition of Events for the Increase in Steam Flow Event

14.1.3-3 Initial Conditions for the Increase in Steam Flow Event

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CHAPTER 14-SAFETY ANALYSISList of Tables (Continued)

Number Title

14.1.3-4 Event Summary for the Increase in Steam Flow Event

14.1.3-5 Peak Reactor Power Levels for Increase in Steam Flow Event

14.1.4-1 Available Reactor Protection for the Inadvertent Opening of a Steam Generator Relief or Safety Valves

14.1.4-2 Disposition of Events for the Inadvertent Opening of a Steam Generator Relief or Safety Valve Event

14.1.5.1-1 Available Reactor Protection for Steam System Piping Failures Inside and Outside of Containment

14.1.5.1-2 Disposition of Events for Steam System Piping Failures Inside and Outside Containment

14.1.5.1-3 S-RELAP5 Thermal-Hydraulic Input (Pre-Scram Steam Line Break)

14.1.5.1-4 Actuation Signals and Delays (Pre-Scram Steam Line Break)

14.1.5.1-5 S-RELAP5 Neutronics Input and Assumptions (Pre-Scram Steam Line Break)

14.1.5.1-6 MDNBR and Peak Reactor Power Level Summary (Pre-Scram Steam Line Break)

14.1.5.1-7 LHGR-Limiting Pre-Scram Steam Line Break Sequence of Events: HFP 0.20ft2 Asymmetric Break Inside Containment with Offsite Power Available

14.1.5.1-8 MDNBR-Limiting Pre-Scram Steam Line Break Sequence of Events: HFP 3.51ft2 Asymmetric Break Inside Containment with Loss of Offsite Power

14.1.5.2-1 Available Reactor Protection for Steam System Piping Failures Inside and Outside of Containment, Post-Scram Analysis

14.1.5.2-2 Disposition of Events for Steam System Piping Failures Inside and Outside of Containment, Post-Scram Analysis

14.1.5.2-3 SRELAP5 -Thermal-Hydraulic Input (Post-Scram Steam Line Break)

14.1.5.2-4 Actuation Signals and Delays (Post-Scram Steam Line Break)

14.1.5.2-5 S-RELAP5 Neutronics Input and Assumptions (Post-Scram Steam Line Break)

14.1.5.2-6 Post-Scram Steam Line Break Analysis Summary

14.1.5.2-7 LHGR-Limiting Sequence of Events - HZP Offsite Power Available

14.1.5.2-8 MDNBR-Limiting Post-Scram Steam Line Break Analysis Summary

14.1.5.3-1 Assumptions Used in Main Steam Line Break Analysis

14.1.5.3-2 Summary of Millstone 2 MSLB Accident Doses

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Number Title

14.1.5.3-3 Deleted by FSARCR PKG FSC 07-MP2-006

14.2.1-1 Available Reactor for the Loss of External Load Event

14.2.1-2 Disposition of Events for the Loss of External Load Event

14.2.1-3 Event Summary for the Loss of External Load Event (Primary Overpressurization Case)

14.2.1-4 Event Summary for the Loss of External Load Event (Secondary Overpressurization Case)

14.2.1-5 Event Summary for the Loss of External Load Event (Minimum Departure from Nucleate Boiling Ratio Case)

14.2.2-1 Available Reactor Protection for the Turbine Trip Event

14.2.2-2 Disposition of Events for the Turbine Trip Event

14.2.4-1 Available Reactor Protection for the Closure of the Main Steam Isolation Valves Events

14.2.4-2 Disposition of Events for the Closure of the Main Steam Isolation Valves Events

14.2.4-3 Event Summary for the Main Steam Isolation Valve Closure Event (Lower Steam Flow Case)

14.2.7-1 Available Reactor Protection for the Loss of Normal Feedwater Flow Event

14.2.7-2 Disposition of Events for the Loss of Normal Feedwater Flow Event

14.2.7-3 Sequence of Events for Minimum Steam Generator Inventory Case: One Motor-Driven AFW Pump Fails to Start with Offsite Power and Steam Dumps

14.2.7-4 Sequence of Events for Maximum Pressurizer Level Case: Loss of Offsite Power, One Motor-Driven AFW Pump Fails to Start

14.3.1-1 Available Reactor Protection for the Loss of Forced Reactor Coolant Flow Event

14.3.1-2 Disposition of Events for the Loss of Forced Reactor Coolant Flow Event

14.3.1-3 Event Summary for the Loss of Forced Reactor Coolant Flow

14.3.3-1 Available Reactor Protection for the Reactor Coolant Pump Rotor Seizure Event

14.3.3-2 Disposition of Events for the Reactor Coolant Pump Rotor Seizure Event

14.3.3-3 Event Summary for the Reactor Coolant Pump Rotor Seizure

14.4.1-1 Available Reactor Protection for the Uncontrolled Control Rod/Bank Withdrawal from a Subcritical or Low-Power Startup Condition Event

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Number Title

14.4.1-2 Disposition of Events for the Uncontrolled Control Rod/Bank Withdrawal from a Subcritical or Low-Power Startup Condition Event

14.4.1-3 Event Summary for the Uncontrolled Bank Withdrawal from Low-Power Event

14.4.2-1 Available Reactor Protection for the Uncontrolled Control Rod/Bank Withdrawal at Power Event

14.4.2-2 Disposition of Events for the Uncontrolled Control Rod/Bank Withdrawal at Power Event

14.4.2-3 Event Summary for the Uncontrolled Rod/Bank Withdrawal Event for the Limiting 100% Power Case

14.4.3.1-1 Available Reactor Protection for the Dropped Control Rod/Bank Event

14.4.3.1-2 Disposition of Events for the Dropped Control Rod/Bank Event

14.4.3.1-3 Event Summary for the Limiting Dropped Control Rod/Bank Case

14.4.3.5-1 Available Reactor Protection for the Single Control Rod Withdrawal Event

14.4.3.5-2 Disposition of Events for the Single Control Rod Withdrawal Event

14.4.4-1 Available Reactor Protection

14.4.4-2 Disposition of Events for the Startup of an Inactive Loop Event

14.4.6-1 Available Reactor Protection for Chemical and Volume Control System Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant Event

14.4.6-2 Disposition of Events for the Chemical and Volume Control System Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant Event

14.4.6-3 Summary of Results for the Boron Dilution Event Asymmetric Dilution Front Model

14.4.6-4 Summary of Results for the Boron Dilution Event Instantaneous Mixing Mode

14.4.8-1 Available Reactor Protection for the Spectrum of Control Rod Ejection Accidents

14.4.8-2 Disposition of Events for the Spectrum of Control Rod Ejection Accidents

14.4.8-3 Event Summary for a Control Rod Ejection (Maximum Pressurization Case)

14.4.8-4 Event Summary for a Control Rod Ejection Minimum Departure from Nucleate Boiling Ratio Case

14.4.8-5 dnBounding Beginning of Cycle/End of Cycle Ejected Rod Analysis

14.4.8-6 CREA Radiological Analysis Assumptions

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Number Title

14.4.8-7 Radiological Consequences of a CREA

14.6.1-1 Available Reactor Protection for the Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve Event

14.6.1-2 Disposition of Events for the Inadvertent Opening of a Pressurized Water Reactor Pressurizer Relief Valve Event

14.6.1-3 Event Summary for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve

14.6.3-1 Available Reactor Protection for the Radiological Consequences of Steam Generator Tube Rupture Event

14.6.3-2 Disposition of Events for the Radiological Consequences of Steam Generator Tube Rupture Event

14.6.3-3 Sequence of Events for the Steam Generator Tube Rupture Event

14.6.3-4 Mass Releases for the Steam Generator Tube Rupture Accident

14.6.3-5 Assumptions for the Radiological Evaluation for the Steam Generator Tube Rupture Event

14.6.3-6 Summary - Radiological Consequences of the Steam Generator Tube Rupture Event

14.6.5.1-1 Available Reactor Protection for the Large Break Loss of Coolant Accident

14.6.5.1-2 Disposition of Events for the Large Break Loss of Coolant Accident

14.6.5.1-3 Millstone Unit 2 Realistic Large Break Loss of Coolant Accident Analysis - Plant Parameter Values and Ranges

14.6.5.1-4 Millstone Unit 2 Large Break Loss of Coolant Accident Analysis - Statistical Distribution Used for Process Parameters

14.6.5.1-5 Millstone Unit 2 Large Break Loss of Coolant Accident Analysis - Passive Heat Sinks and Material Properties In Containment Geometry

14.6.5.1-6 Millstone Unit 2 Large Break Loss of Coolant Accident Analysis - Compliance with 10 CFR 50.46(b)

14.6.5.1-7 Millstone Unit 2 Large Break Loss of Coolant Accident Analysis - Summary of Major Parameters for the Demonstration Case

14.6.5.1-8 Millstone Unit 2 Large Break Loss of Coolant Accident Analysis - Calculated Event Times for the Demonstration Case*

14.6.5.2-1 Available Reactor Protection for the Small Break Loss of Coolant Accident

Revision 38—06/30/20 MPS-2 FSAR 14-xvii


Number Title

14.6.5.2-2 Disposition of Events for the Small Break Loss of Coolant Accident

14.6.5.2-3 Millstone Unit 2 Small Break Loss of Coolant Accident System Analysis Parameters

14.6.5.2-4 Deleted by FSCR MPS-UCR-2016-016

14.6.5.2-5 Calculated Event Times for Small Break Loss-of-Coolant Accident

14.6.5.2-6 Analysis Results for Small Break Loss-of-Coolant Accident

14.6.5.2-7 Peak Clad Temperature Including All Penalties and Benefits - Small Break LOCA

14.6.5.3-1 Core and System Parameters Used in the LTC Analysis

14.6.5.4-1 Available Reactor Protection for the Large Break Loss of Coolant Accident

14.6.5.4-2 Disposition of Events for the Large Break Loss of Coolant Accident

14.6.5.4-3 Millstone Unit 2 System Analysis Parameters (Large Break Loss of Coolant Accident Analysis)

14.6.5.4-4 Millstone Unit 2 Large Break Loss of Coolant Accident Analysis

14.6.5.4-5 Millstone Unit 2 Large Break LOCA Analysis

14.6.5.4-6 Millstone Unit 2 Large Break LOCA Analysis

14.6.5.4-7 Peak Clad Temperature Including All Penalties and Benefits - Large Break LOCA

14.7.1-1 Deleted by FSARCR PKG FSC 07-MP2-006

14.7.4-1 Assumption for Fuel Handling Accident in the Spent Fuel Pool

14.7.4-2 Assumption for Fuel Handling Accident in Containment

14.7.4-3 Deleted by FSARCR 02-MP2-015

14.7.5-1 Assumptions for Spent Fuel Cask Tip Accident

14.8.2-1 Containment Design Parameters

14.8.2-2 Initial Conditions for Pressure Analyses

14.8.2-3 Minimum Containment Heat Sink Data

14.8.2-4 Sequence of Events, MP2-MSLB: Loss of Offsite Power and the Failure of Vital Bus VA-10 or VA-20 from 102% Power

14.8.2-5 Engineered Safety Features Performance for MSLB Containment Analysis

Revision 38—06/30/20 MPS-2 FSAR 14-xviii


Number Title

14.8.4-1 Loss of Coolant Accident (Off site Assumptions)

14.8.4-2 Summary of Doses for Loss of Coolant Accident

14.8.4-3 Loss of Coolant Accident (Control Room Assumptions)

14.8.4-4 Atmospheric Dispersion Data for Millstone Unit 2 Control Room

14.8.4-5 Dose to Millstone Unit 2 Control Room Operators

Revision 38—06/30/20 MPS-2 FSAR 14-xix

NOTE: REFER TO THE CONTROLLED PLANT DRAWING FOR THE LATEST REVISION.


List of Figures

Number Title

14.0.4-1 RCS Cold Leg Temperature as a Function of Power

14.0.4-2 Not Used

14.0.4-3 Not Used

14.0.4-4 Not Used

14.0.4-5 Not Used

14.0.4-6 Not Used

14.0.4-7 Linear Heat Rate Limiting Condition for Operation used in Local Power Density Limiting Condition for Operation Verification

14.0.7–1 Verification of Local Power Density Limiting Safety System Setting

14.0.7–2 Thermal Margin/Low Pressure Trip Function A1

14.0.7–3 Thermal Margin/Low Pressure Trip Function QR1

14.0.7–4 Not Used

14.0.7–5 Verification of the Departure from Nucleate Boiling Limiting Condition for Operation

14.0.7–6 Verification of Local Power Density Limiting Condition for Operation

14.0.7–7 Linear Heat Rate Limiting Condition of Operation Used in Local Power Density Limiting Condition of Operation Verification

14.1.3–1 Normalized Power and Heat Flux for the Increase in Steam Flow Event

14.1.3–2 Reactivity Feedback for the Increase in Steam Flow Event

14.1.3–3 Reactor Coolant Temperatures for Increase in Steam Flow Event

14.1.3–4 Core Inlet Mass Flow Rate for the Increase in Steam Flow Event

14.1.3–5 Pressurizer Pressure for the Increase in Steam Flow Event

14.1.3–6 Steam Generator Pressures for the Increase in Steam Flow Event

14.1.3–7 Steam Mass Flow Rates for the Increase in Steam Flow Event

14.1.3–8 Main Feedwater Flow for the Increase in Steam Flow Event

14.1.3–9 Main Feedwater Temperature for the Increase in Steam Flow Event

14.1.5.1–1 Normalized Core Power (0.20 ft2 Asymmetric Break Inside Containment)

Revision 38—06/30/20 MPS-2 FSAR 14-xx


CHAPTER 14-SAFETY ANALYSISList of Figures (Continued)

Number Title

14.1.5.1–2 Core Inlet Temperatures (0.20 ft2 Asymmetric Break Inside Containment)

14.1.5.1–3 Reactivity Feedback (0.20 ft2 Asymmetric Break Inside Containment)

14.1.5.1–4 Pressurizer Pressure (0.20 ft2 Asymmetric Break Inside Containment)

14.1.5.1–5 Steam Generator Pressures (0.20 ft2 Asymmetric Break Inside Containment)

14.1.5.1–6 Steam Mass Flow Rates (0.20 ft2 Asymmetric Break Inside Containment)

14.1.5.1–7 Normalized Power and Heat Flux (Asymmetric 3.51 ft2 Break Inside Containment with Loss of Offsite Power)

14.1.5.1–8 Reactor Coolant Temperatures (Asymmetric 3.51 ft2 Break Inside Containment with Loss of Offsite Power)

14.1.5.1–9 Normalized Reactor Coolant System Flow Rate (Asymmetric 3.51 ft2 Break Inside Containment with Loss of Offsite Power)

14.1.5.1–10 Pressurizer Pressure (Asymmetric 3.51 ft2 Break Inside Containment with Loss of Offsite Power)

14.1.5.1–11 Steam Generator Pressures (Asymmetric 3.51 ft2 Break Inside Containment with Loss of Offsite Power)

14.1.5.2–1 One Pump High Pressure Safety Injection System Delivery vs. Primary Pressure (Post-Scram Steam Line Break)

14.1.5.2–2 Steam Generator Break Flow (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–3 Steam Generators' Secondary Pressures (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–4 Core Inlet Temperatures (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–5 Pressurizer Pressure (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–6 Pressurizer Level (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–7 Steam Generators' Secondary Mass (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–8 Reactivity Components (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

Revision 38—06/30/20 MPS-2 FSAR 14-xxi



Number Title

14.1.5.2–9 Reactor Power (HZP Post-Scram Steam Line Outside Containment Break with Offsite Power Available)

14.1.5.2–10 Steam Generator Break Flow (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.1.5.2–11 Steam Generators' Secondary Pressures (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.1.5.2–12 Core Inlet Temperatures (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.1.5.2–13 Pressurizer Pressure (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.1.5.2–14 Pressurizer Level (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.1.5.2–15 Reactivity Components (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.1.5.2–16 Reactor Power (HZP Post-Scram Steam Line Outside Containment Break with Loss of Offsite Power)

14.2.1–1 Reactor Power Level for Loss of External Load (Primary Overpressurization Case)

14.2.1–2 Core Average Heat Flux for Loss of External Load (Primary Overpressurization Case)

14.2.1–3 Reactor Coolant System Temperatures for Loss of External Load (Primary Overpressurization Case)

14.2.1–4 Primary System Pressures for Loss of External Load (Primary Overpressurization Case)

14.2.1–5 Total Reactivity for Loss of External Load (Primary Overpressurization Case)

14.2.1–6 Reactor Power Level for Loss of External Load (Secondary Overpressurization Case)

14.2.1–7 Core Average Hot Flux for Loss of External Load (Secondary Overpressurization Case)

14.2.1–8 Reactor Coolant System Temperatures for Loss of External Load (Secondary Overpressurization Case)

14.2.1–9 Pressurizer Pressure for Loss of External Load (Secondary Overpressurization Case)

Revision 38—06/30/20 MPS-2 FSAR 14-xxii



Number Title

14.2.1–10 Total Reactivity for Loss of External Load (Secondary Overpressurization Case)

14.2.1–11 Maximum Secondary System Pressures for Loss of External Load (Secondary Overpressurization Case)

14.2.1–12 Reactor Power Level for Loss of External Load (MDNBR Case)

14.2.1–13 Normalized Heat Flux for Loss of External Load (MDNBR Case)

14.2.1–14 Reactor Coolant System Temperature for Loss of External Load (MDNBR Case)

14.2.1–15 Pressurizer Pressure for Loss of External Load (MDNBR Case)

14.2.1–16 Total Reactivity for Loss of External Load (MDNBR Case)

14.2.1–17 Maximum Secondary System Pressure for Loss of External Load (MDNBR Case)

14.2.4–1 Reactor Power Level for MSIV Closure (Lower Steam Flow Case)

14.2.4–2 Reactor Coolant System Temperatures for MSIV Closure (Lower Steam Flow Case)

14.2.4–3 Pressurizer Pressure for MSIV Closure (Lower Steam Flow Case)

14.2.4–4 Isolated Steam Generator Pressure at Bottom of Boiler Region for MSIV Closure (Lower Steam Flow Case))

14.2.4–5 Open MSIV Steam Generator Steam Dome Pressure for MSIV Closure (Lower Steam Flow Case))

14.2.7–1 Reactor Coolant System Loop Temperatures for Minimum Steam Generator Inventory Case: Offsite Power Available, “B” Motor-Driven AFW Pump Fails to Start

14.2.7–2 Steam Generator Dome Pressure for Minimum Steam Generator Inventory Case: Offsite Power Available, “B” Motor-Driven AFW Pump Fails to Start

14.2.7–3 Pressurizer Level for Minimum Steam Generator Inventory Case: Offsite Power Available, “B” Motor-Driven AFW Pump Fails to Start

14.2.7–4 Steam Generator for Liquid Mass Inventory for Minimum Steam Generator Inventory Case: Offsite to Power Available, “B” Motor-Driven AFW Pump Fails to Start

14.2.7–5 Steam Generator Collapsed Liquid Level for Minimum Steam Generator Inventory Case: Offsite to Power Available, “B” Motor-Driven AFW Pump Fails to Start

Revision 38—06/30/20 MPS-2 FSAR 14-xxiii



Number Title

14.2.7–6 Reactor Coolant System Loop Temperatures for Maximum Pressurizer Level Case: Loss of Offsite Power, One Motor-Driven AFW Pump Fails to Start

14.2.7–7 Steam Generator Dome Pressure for Maximum Pressurizer Level Case: Loss of Offsite Power, One Motor-Driven AFW Pump Fails to Start

14.2.7–8 Pressurizer Level for Maximum Pressurizer Level Case: Loss of Offsite Power, One Motor-Driven AFW Pump Fails to Start

14.2.7–9 Steam Generator Liquid Mass Inventory for Maximum Pressurizer Level Case: Loss of Offsite Power, One Motor-Driven AFW Pump Fails to Start

14.2.7–10 Steam Generator Collapsed Liquid Level for Maximum Pressurizer Level Case: Loss of Offsite Power, One Motor-Driven AFW Pump Fails to Start

14.3.1–1 Reactor Power Level for Loss of Forced Reactor Coolant Flow

14.3.1–2 Core Average Heat Flux for Loss of Forced Reactor Coolant Flow

14.3.1–3 Reactor Coolant System Temperature for Loss of Forced Reactor Coolant Flow

14.3.1–4 Pressurizer Pressure for Loss of Forced Reactor Coolant Flow

14.3.1–5 Reactivities for Loss of Forced Reactor Coolant Flow

14.3.1–6 Primary Coolant Flow Rate for Loss of Forced Reactor Coolant Flow

14.3.1–7 Secondary Pressure for Loss of Forced Reactor Coolant Flow

14.3-3–1 Reactor Power Level for Reactor Coolant Pump Rotor Seizure

14.3-3–2 Core Average Heat Flux for Reactor Coolant Pump Rotor Seizure

14.3-3–3 Reactor Coolant System Temperatures for Reactor Coolant Pump Rotor Seizure

14.3-3–4 Pressurizer Pressure for Reactor Coolant Pump Rotor Seizure

14.3-3–5 Reactivities for Reactor Coolant Pump Rotor Seizure

14.3-3–6 Primary Coolant Flow Rate for Reactor Coolant Pump Rotor Seizure

14.3-3–7 Secondary Pressure for Reactor Coolant Pump Rotor Seizure

14.4.1–1 Reactor Power Level for Low Power Bank Withdrawal

14.4.1–2 Core Average Heat Flux for Low Power Bank Withdrawal

14.4.1–3 Reactor Coolant Temperatures for Low Power Bank Withdrawal

14.4.1–4 Pressurizer Pressure for Low Power Bank Withdrawal

14.4.1–5 Reactivities for Low Power Bank Withdrawal

Revision 38—06/30/20 MPS-2 FSAR 14-xxiv



Number Title

14.4.2–1 Reactor Core Power for an Uncontrolled Bank Withdrawal at Power

14.4.2–2 Core Average Heat Flux for an Uncontrolled Bank Withdrawal at Power

14.4.2–3 Reactor Coolant System Temperatures for an Uncontrolled Bank Withdrawal at Power

14.4.2–4 Pressurizer Pressure for an Uncontrolled Bank Withdrawal at Power

14.4.2–5 Reactivities for an Uncontrolled Bank Withdrawal at Power

14.4.2–6 Secondary Pressure for an Uncontrolled Bank Withdrawal at Power

14.4.3.1–1 Reactor Power Level for the Limiting Dropped Control Rod/Bank Case

14.4.3.1–2 Reactor Coolant System Temperatures for the Limiting Dropped Control Rod/Bank Case

14.4.3.1–3 Pressurizer Pressure for the Limiting Dropped Control Rod/Bank Case

14.4.3.1–4 Secondary Pressure for the Limiting Dropped Control Rod/Bank Case

14.4.8–1 Core Power for a CEA Ejection (Minimum Departure for Nucleate Boiling Ratio Case)

14.4.8–2 Core Average Heat Flux for a CEA Ejection (Minimum Departure for Nucleate Boiling Ratio Case)

14.4.8–3 Reactor Coolant System Temperatures for a CEA Ejection (Minimum Departure for Nucleate Boiling Ratio Case)

14.4.8–4 Pressurizer Pressure for a CEA Ejection (Minimum Departure for Nucleate Boiling Ratio Case)

14.4.8–5 Reactivities for a CEA Ejection (Minimum Departure for Nucleate Boiling Ratio Case)

14.4.8–6 Secondary Pressure for a CEA Ejection (Minimum Departure for Nucleate Boiling Ratio Case)

14.4.8–7 Core Power for a CEA Ejection (Overpressure)

14.4.8–8 Core Average Heat Flux for a CEA Ejection (Overpressure)

14.4.8–9 Primary System Temperatures for a CEA Ejection (Overpressure)

14.4.8–10 Pressurizer Pressure for a CEA Ejection (Overpressure)

14.4.8–11 Reactivities for a CEA Ejection (Overpressure)

14.4.8–12 Secondary Pressure for a CEA Ejection (Overpressure)

Revision 38—06/30/20 MPS-2 FSAR 14-xxv



Number Title

14.6.1–1 Reactor Power Level for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve (Rated Power)

14.6.1–2 Core Average Heat Flux for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve (Rated Power)

14.6.1–3 Reactor Coolant System Temperatures for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve (Rated Power)

14.6.1–4 Pressurizer Pressure for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve (Rated Power)

14.6.1–5 Reactivities for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve (Rated Power)

14.6.1–6 Secondary Pressure for an Inadvertent Opening of a Pressurized Water Reactor Pressurizer Pressure Relief Valve (Rated Power)

14.6.3–1 Steam Generator Tube Rupture with the Loss of Offsite Power RCS Temperature Versus Time

14.6.3–2 Steam Generator Tube Rupture with the Loss of Offsite Power Pressurizer Level Versus Time

14.6.3–3 Steam Generator Tube Rupture with the Loss of Offsite Power Pressurizer Pressure Versus Time

14.6.3–4 Steam Generator Tube Rupture with the Loss of Offsite Power Steam Generator Pressure Versus Time

14.6.3–5 Steam Generator Tube Rupture with the Loss of Offsite Power Total Break Flow Rate Versus Time

14.6.3–6 Steam Generator Tube Rupture with the Loss of Offsite Power Flashed Break Flow Rate Versus Time

14.6.3–7 Steam Generator Tube Rupture with the Loss of Offsite Power Atmospheric Dump Valve Flow Rate per Steam Generator Versus Time

14.6.3–8 Steam Generator Tube Rupture with the Loss of Offsite Power Main Steam Safety Valve Flow Rates per Steam Generator Versus Time

14.6.3–9 Steam Generator Tube Rupture with the Loss of Offsite Power Auxiliary Feedwater Flow Versus Time

14.6.5.1–1 Scatter Plot Operational Parameters

14.6.5.1–2 PCT Versus PCT Time Scatter Plot

14.6.5.1–3 PCT Versus PCT Time Scatter Plot

Revision 38—06/30/20 MPS-2 FSAR 14-xxvi



Number Title

14.6.5.1–4 Maximum Local Oxidation Versus PCT Scatter Plot

14.6.5.1–5 Total Core Wide Oxidation Versus PCT Scatter Plot

14.6.5.1–6 Peak Cladding Temperature (Independent of Elevation) for the Demonstration Case

14.6.5.1–7 Break Flow for the Demonstration Case

14.6.5.1–8 Core Inlet Mass Flux for the Demonstration Case

14.6.5.1–9 Core Outlet Mass Flux for the Demonstration Case

14.6.5.1–10 Void Fraction at RCS Pumps for the Demonstration Case

14.6.5.1–11 ECCS Flows (Includes SIT, HPSI and LPSI) for the Demonstration Case

14.6.5.1–12 Upper Plenum Pressure for the Demonstration Case

14.6.5.1–13 Collapsed Liquid Level in the Downcomer for the Demonstration Case

14.6.5.1–14 Collapsed Liquid Level in the Lower Plenum for the Demonstration Case

14.6.5.1–15 Collapsed Liquid Level in the Core for the Demonstration Case

14.6.5.1–16 Containment and Loop Pressures for the Demonstration Case

14.6.5.1–17 Pressure Differences between Upper Plenum and Downcomer for the Demonstration Case

14.6.5.2–1 Peak Cladding Temperature Versus Break Size (SBLOCA Break Spectrum)

14.6.5.2–2 Reactor Power - 3.78-Inch Break

14.6.5.2–3 Primary and Secondary System Pressures - 3.78-Inch Break

14.6.5.2–4 Break Mass Flow Rate - 3.78-Inch Break

14.6.5.2–5 Break Vapor Void Fraction - 3.78-Inch Break

14.6.5.2–6 Loop Seal Void Fraction - 3.78-Inch Break

14.6.5.2–7 Total Core Inlet Mass Flow Rate - 3.78-Inch Break

14.6.5.2–8 Downcomer Collapsed Liquid Level - 3.78-Inch Break

14.6.5.2–9 Inner and Outer Core Collapsed Liquid Level - 3.78-Inch Break

14.6.5.2–10 Reactor Vessel Mass - 3.78-Inch Break

14.6.5.2–11 RCS Loop Mass Flow Rates - 3.78-Inch Break

14.6.5.2–12 Steam Generator Main Feedwater Mass Flow Rates - 3.78-Inch Break

14.6.5.2–13 Steam Generator Auxiliary Feedwater Mass Flow Rates - 3.78-Inch Break

Revision 38—06/30/20 MPS-2 FSAR 14-xxvii



Number Title

14.6.5.2–14 Steam Generator Total Mass - 3.78-Inch Break

14.6.5.2–15 Steam Generator Narrow Range Level % - 3.78-Inch Break

14.6.5.2–16 High Pressure Safety Injection Mass Flow Rates - 3.78-Inch Break

14.6.5.2–17 Low Pressure Safety Injection Mass Flow Rates - 3.78-Inch Break

14.6.5.2–18 Safety Injection Tank Mass Flow Rates - 3.78-Inch Break

14.6.5.2–19 Integrated Break Flow And ECCS Flow - 3.78-Inch Break

14.6.5.2–20 Hot Assembly Collapsed Liquid Level - 3.78-Inch Break

14.6.5.2–21 Hot Assembly Mixture Level - 3.78-Inch Break

14.6.5.2–22 Peak Cladding Temperature At Pct Location (11.02 Ft) - 3.78-Inch Break

14.6.5.2–23 (DELETED by FSARCR 00-MP2-023)

14.6.5.2–24 (DELETED by FSARCR 00-MP2-023)

14.6.5.3–1 Long Term Cooling Plan

14.6.5.3–2 Reactor Coolant System Refill Time vs. Break Area

14.6.5.3–3 Core Flush by Hot Side Injection for a Double-Ended Guillotine Cold Leg Break

14.6.5.3–4 Inner Vessel Boric Acid Concentration vs. Time for a Double-Ended Guillotine Cold Leg Break

14.6.5.4–1 Normalized Power (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–2 Safety Injection Tank (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–3 High Pressure Safety Injection Flow Rates (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–4 Low Pressure Safety Injection Flow Rates (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–5 Upper Plenum Pressure During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–6 Total Break Flow Rate During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–7 Average Core Inlet Flow Rate During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–8 Hot Channel Inlet Flow Rate During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–9 Peak Cladding Temperature Node Fluid Quality During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–10 Peak Cladding Temperature Node Fuel (Average), Cladding and Fluid Temperatures During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

Revision 38—06/30/20 MPS-2 FSAR 14-xxviii



Number Title

14.6.5.4–11 Peak Cladding Temperature Node Heat Transfer Coefficient During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–12 Peak Cladding Temperature Node Heat Flux During Blowdown (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–13 Containment Pressure (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–14 Upper Plenum Pressure (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–15 Downcomer Mixture Level (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–16 Core Effective Flooding Rate (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–17 Core Mixture Level (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–18 Core Quench Level (1.0 DECLG EOC Loss-of-Diesel)

14.6.5.4–19 Peak Cladding Temperature Node and Ruptured Node Cladding Temperatures (1.0 DECLG EOC Loss-of-Diesel)

14.8.2–1 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Containment Pressure vs. Time

14.8.2–2 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Containment Temperature vs. Time

14.8.2–3 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Mass Flow Rate vs. Time

14.8.2–4 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Energy Release Rate vs. Time

14.8.2–5 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Integrated Mass Flow vs. Time

14.8.2–6 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Integrated Energy Release vs. Time

14.8.2–7 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Affected Steam Generator Pressure vs. Time

14.8.2–8 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Unaffected Steam Generator Pressure vs. Time

14.8.2–9 Main Steam Line Break Analysis - 102% Power with Loss of Offsite Power and Failure of Vital Bus Cabinet VA-10 or VA-20 - Affected Steam Generator Liquid Mass vs. Time

Revision 38—06/30/20 MPS-2 FSAR 14-xxix



Number Title

14.8.3–1 Deleted by FSARCR 04-MP2-018






Revision 38—06/30/20 MPS-2 FSAR 14.0-1

CHAPTER 14 – SAFETY ANALYSIS

14.0 GENERAL

Preceding sections of this report describe and evaluate the reliability of major systems and components of the plant. The purpose of this section is to assume that certain accidents occur notwithstanding the precautions taken to prevent their occurrence and to evaluate the capability of the installed safety equipment to mitigate the potential consequences of such accidents. The analyses show that the health and safety of the public are assured in the event of even the most severe of the hypothetical accidents analyzed.

All events described in the Standard Review Plan (SRP) (Reference 14.0-1) have been reviewed and placed (dispositioned) into one of the following four categories:

1. The event needs to be analyzed.

2. The event is bounded by another event which is analyzed.

3. The event is not in the licensing basis for the plant.

4. The event is not applicable to Millstone Unit 2.

In the event disposition, all of the reactor operating conditions allowed by the plant Technical Specifications (Reference 14.0-2) are examined to ensure that the bounding subevents are identified for each SRP event category. This ensures that the safety analysis will support the complete range of allowable operating conditions. Events which are not bounded by other events or by existing accepted analyses, and are in the plant licensing basis, are dispositioned to be analyzed. In the event disposition process, the event initiator is identified for each event. The magnitude of the initiator for each event is calculated and compared to the magnitude of the initiator for other events. The comparison basis includes all the plant operating conditions. This allows, in several cases, a ranking of the event initiators as to severity, allowing the lesser events to be dispositioned as bounded by the greater event. Similar logic is applied in determination of the applicability and bounding nature for existing accepted analyses.

The reactor operating modes allowed for Millstone Unit 2 by the plant Technical Specifications are listed in Table 14.0-1. Table 14.0-2 presents a summary of results of the event disposition. This chapter presents the basis and justification for the disposition of events, and analysis of those events dispositioned as requiring analysis.

14.0.1 CLASSIFICATION OF PLANT CONDITIONS

Plant operations are placed in one of four categories. The categories are:

1. Normal Operations and Operational Transients - Events which are expected to occur frequently in the course of power operation, refueling, maintenance, or plant maneuvering.


2. Faults of Moderate Frequency - Events which may occur once per year during plant operation.

3. Infrequent Faults - Events which may occur once during the lifetime of the plant.

4. Limiting Faults - Events which are not expected to occur but which are evaluated to demonstrate the adequacy of the design.

14.0.1.1 Acceptance Criteria

The acceptance criteria for the four categories of events are as given below:

1. Operational Events

This condition describes the normal operational modes of the reactor. As such, occurrences in this category must maintain margin between operating conditions and the plant setpoints. The setpoints are established to assure maintenance of margin to design limits. The set of operating conditions, together with conservative allowances for uncertainties, establish the set of initial conditions for the other event categories.

2. Moderate Frequency Events

a. The pressures in reactor coolant and main steam systems should be less than 110% of design values.

b. The fuel cladding integrity should be maintained by ensuring that fuel design limits are not exceeded. That is, the minimum calculated departure from nucleate boiling ratio (DNBR) is not less than the applicable limits of the DNBR correlation being used.

c. The radiological consequences should be less than 10 CFR 20, Sections 105 and 106 and Appendix B (version prior to January 1, 1994).

d. The event should not generate a more serious plant condition without other faults occurring independently.

3. Infrequent Faults

a. The pressures in reactor coolant and main steam systems should be less than 110% of design values.

b. A small fraction of fuel failures may occur, but these failures should not hinder the capability of the core to be cooled.


c. The radiological consequences should be within the guidelines of 10 CFR 50.67 and Regulatory Guide 1.183.

d. The event should not generate a limiting fault or result in the consequential loss of the reactor coolant or containment barriers.

4. Limiting Fault Events

a. Radiological consequences should be within the guidelines of 10 CFR 50.67 and Regulatory Guide 1.183.

b. The event should not cause a consequential loss of the required functions of systems needed to cope with the reactor coolant and containment systems transients.

c. Additional criteria to be satisfied by specific events are:

1. Loss-of-Coolant Accident (LOCA) - 10 CFR 50.46 and Appendix K.

2. Rod Ejection - Radially averaged fuel enthalpy deposition < 280 cal/gm.

14.0.1.2 Classification of Accident Events by Category

Table 14.0.1-1 lists the accident category used for each event analyzed in this report. This classification is used in evaluating the acceptability of the results obtained from the analysis.

14.0.2 PLANT CHARACTERISTICS AND INITIAL CONDITIONS

Six operational modes have been considered in the analysis and are shown in Table 14.0-1. These operational modes have been considered in establishing the subevents associated with each event initiator. A set of initial conditions is established for the events analyzed that is consistent with the conditions for each mode of operation.

The nominal plant rated operating conditions are presented in Table 14.0.2-1 and principal fuel design characteristics in Table 14.0.2-2. The uncertainties used in the accident analysis applicable to the operating conditions are:

(1) Core Power, HFP Calorimetric ± 2%

(2) Primary Coolant Cold Leg Temperature ± 2.25°F

(3) Primary Coolant Pressure +25/-14 psi

(4) Primary Coolant Flow ± 4%


14.0.3 POWER DISTRIBUTION

The Technical Specification (Reference 14.0-2) power peaking factors are used in the accident analysis. The Technical Specification Limiting Conditions of Operation (LCO) assure that the power distribution is maintained within these limits during normal operation.

14.0.4 RANGE OF PLANT OPERATING PARAMETERS AND STATES

Table 14.0.4-1 presents the range of key plant operating parameters considered in the analysis. A broader range of power, core inlet temperature, and primary pressure is considered in establishing the trip setpoints verified by the analysis results presented in this document.

The range of operating states of the reactor is also considered in the analysis. The effect of exposure on fuel thermal performance and neutronics parameters is considered. State values are selected for the event analyzed to provide the greatest challenge to the acceptance criteria for that event. Several calculations may be required to bound the range of the state variable. For example, a range of neutronic parameters is used in the analysis of rod withdrawal events in order to verify the range of protection of the challenged trip setpoints.

The range of initiating events is also considered in formulating the analysis conditions for an event. The initiating conditions are examined to identify a set which conservatively challenges the acceptance criteria. Where not obvious, sensitivity studies are performed. For example, analyses are performed for uncontrolled rod withdrawal events throughout the range of reactivity insertion rate possible from boron dilution to maximum withdrawal rate of the highest worth control banks.

14.0.5 REACTIVITY COEFFICIENTS USED IN THE SAFETY ANALYSIS

The reactivity coefficients used in the analysis are consistent with the AREVA approved methodology and the Technical Specification limits. The set of parameters used in each analysis is listed in the appropriate section for that event.

14.0.6 SCRAM INSERTION CHARACTERISTICS

Scram reactivity insertion as a function of axial shape index (ASI) was used in the analysis for reactor trip. The insertion worth includes the most reactive rod stuck out. The shutdown margin of 3.6% delta rho and a control rod drop time of 2.75 seconds (to 90% insertion) have been supported by the transient analysis.

14.0.7 TRIP SETPOINT VERIFICATION

Operating limits for the Millstone Unit 2 nuclear plant are summarized below. Methods of analysis for determining or verifying the operating limits are detailed in Section 14.0.7.5 and Reference 14.0-4. Axial power distributions and other core neutronics related parameters used in the setpoint verification analyses were generated with AREVA approved core simulator code PRISM (Reference 14.0-5). This data was generated on a three-dimensional core basis, as described in Reference 14.0-4. With this methodology, the values of FQ used in the setpoint


verification are calculated directly with a three-dimensional model and since operation within the

Technical Specification on FrT limits FQ, the need for an Fxy

T limit is eliminated.

Results of the analyses indicate that operating limits established for Millstone Unit 2 are acceptable.

14.0.7.1 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 (SAFDL) during steady state and anticipated operational occurrences (AOO). The safe operation of the reactor is also maintained by restricting reactor operation to conform with the LCOs, which are administratively applied at the reactor plant. The LSSS and LCO parametric values are presented in the following sections.

14.0.7.2 Specified Acceptable Fuel Design Limits

The SAFDLs are limits on the fuel and cladding established in order to preclude fuel failure. 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:

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

2. The minimum departure from nucleate boiling ratio (MDNBR) corresponding to the accepted criterion which protects against the occurrence of departure from nucleate boiling (DNB).

The minimum power level required to produce centerline melt in zirconium alloy clad uranium fuel rods is defined as the Fuel Centerline Melt Linear Heat Rate (FCMLHR) limit and is expressed in KW/ft. This FCMLHR is determined using the methodology of Reference 14.0-4. The LPD limit for Millstone Unit 2 is the FCMLHR limit. It is noted that reload fuel may contain gadolinia-bearing fuel rods which, for a given LPD, will operate with a higher fuel temperature and will consequently have a lower LPD limit. The methodology used to determine the limit considers both uranium fuel rods and gadolinia-bearing fuel rods in establishing the FCMLHR limit.

The High Thermal Performance (HTP) critical heat flux correlation (Reference 14.0-8) is used in the thermal margin analysis with statistical parameters to support the upper 95/95 limit. Observance of the LCO will protect against DNB with 95% probability at a 95% confidence level during an AOO.


14.0.7.3 Limiting Safety System Settings

14.0.7.3.1 Local Power Density

The LPD trip limit is the locus of the limiting values of core power level versus ASI that will produce a reactor trip to prevent exceeding the FCMLHR limit. The correlation between allowed core power level and peripheral ASI was determined using methods which take into account the total calculated nuclear peaking and the measurement and calculational uncertainties associated with power peaking. The LPD barn for operation at 2700 MWt is shown in Figure 14.0.7–1 as a locus of power and ASI pairs which conservatively bounds the calculated power and ASI pairs. ASI is defined as the difference between the core power in the bottom half of the core and the top half divided by the sum of the top and bottom halves.

14.0.7.3.2 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 primary system pressure, core inlet temperature, core power and ASI. A reactor trip occurs when primary system pressure falls below the computed limiting core pressure, Pvar. A statistical setpoint methodology (Reference 14.0-4) 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 is given by:

Pvar = 2215 x A1 (ASI) x QR1 (Q) + 14.28 x Tin - 8240 [psia],

where Q is the higher of the thermal power and the nuclear flux power, Tin is the inlet temperature in °F and A1 and QR1 are shown in Figures 14.0.7–2 and 14.0.7–3, respectively.

14.0.7.3.3 Additional Trip Functions

In addition to the LPD and TM/LP trip functions, other reactor system trips have been determined to provide adherence to reactor system design criteria. The analytical setpoints for these trips are shown in Table 14.0.7-1.

14.0.7.4 Limiting Conditions for Operation

14.0.7.4.1 Departure From Nucleate Boiling

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 loss-of-flow operational occurrence. The statistical analysis accounted for the effects of uncertainties associated with core operating parameters, the HTP critical heat flux correlation, and power peaking. The allowed core power as a function of ASI for the existing LCO is shown to conservatively bound the present analysis in Figure 14.0.7–5.


14.0.7.4.2 Linear Heat Rate

In the event that the in-core detector system is not in operation, the linear heat rate (LHR) will be limited 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 LSSS (Section 14.0.7.3.1). The verification plot is shown in Figure 14.0.7–6. The LPD LCO limits core power so that the LHR LCO based on LOCA considerations is not exceeded. The LHR LCO protected by the LPD LCO is depicted in Figure 14.0.7–7.

14.0.7.5 Setpoint Analysis

14.0.7.5.1 Limiting Safety System Settings

14.0.7.5.1.1 Local Power Density

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 distribution cases typical of the cycle were examined to establish bounding values of total power peaking, FQ, versus ASI. These cases were generated in a manner consistent with that discussed in Reference 14.0-4. Statistical methods were then employed to account for the uncertainties in the parameters that are given in Table 14.0.7-2.

The peak LHR in the core occurs at the position of the maximum total peaking factor, FQ, which is the ratio of the maximum linear heat generation rate (LHGR) in the core to the average LHGR in the core.

The allowed power for each ASI was calculated statistically by incorporating the uncertainties listed in Table 14.0.7-2 as described in Reference 14.0-4. The results in Figure 14.0.7–1 are bounded by the existing Millstone Unit 2 LPD trip and thus verify the adequacy of the existing trip function.

14.0.7.5.1.2 Thermal Margin/Low Pressure Limiting Safety System Settings

The 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. This analysis uses the HTP critical heat flux correlation and the core thermal-hydraulic methodology described in References 14.0-8 and 14.0-11. The analysis methodology is consistent with the NRC's SRP in requiring DNB to be avoided with 95% probability at a 95% confidence level.

The uncertainties shown in Tables 14.0.7-2 and 14.0.7-3 are included in the verification of the TM/LP trip as described in Reference 14.0-4. An excess margin of protection is provided by the trip.


14.0.7.5.2 Limiting Conditions for Operation

14.0.7.5.2.1 Departure from Nucleate Boiling

The TM/LP trip system does not directly monitor reactor coolant flow. Thus, the TM/LP trip generally does not provide DNB protection for the four pump coastdown AOO. The analysis of this transient is given in Section 14.3.1. The LCO presented here administratively protects the DNB SAFDL for this transient.

The method used to establish the DNB LCO involved simulations of the loss-of-flow transient using the core thermal hydraulic code XCOBRA-IIIC (Reference 14.0-11) to determine the initial power, as a function of ASI, which provides protection from DNB with 95% probability. The uncertainties listed in Tables 14.0.7-4 and 14.0.7-5 are applied using the methodology described in Reference 14.0-4. The results of the statistical analysis for the loss-of-flow transient are summarized by the points in Figure 14.0.7–5. The points are bounded by the existing DNB LCO and, thus, verify the adequacy of the existing DNB LCO for Millstone Unit 2, which is shown in this same figure by the straight line segments.

14.0.7.5.2.2 Local Power Density

The plant Technical Specifications allow plant operations for limited periods of time with the in-core detectors out of service. In this situation, the LPD 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:

1. The peak LPD limit is reduced, and

2. The uncertainties listed in Table 14.0.7-4 are used, as opposed to the values in Table 14.0.7-2.

The allowed power versus ASI was statistically analyzed to account for the appropriate uncertainties. The points in Figure 14.0.7–6 represent the statistical calculation of the 15.1 kw/ft LHR curve depicted in Figure 14.0.7–7. The LCO curve is shown by the straight line segments in Figure 14.0.7–6, and conservatively bounds the calculated verification points.

14.0.8 COMPONENT CAPACITIES AND SETPOINTS

Table 14.0.8-1 presents the component setpoints and capacities used in the analysis.

14.0.9 PLANT SYSTEMS AND COMPONENTS AVAILABLE FOR MITIGATION OF ACCIDENT EFFECTS

Table 14.0.9-1 is a summary of trip functions, engineered safety features (ESF), and other equipment available for mitigation of accident effects. These are listed for all SRP Chapter 15 events. A more detailed listing of available reactor protection for each event in each operating mode is given in the individual event descriptions.


14.0.10 EFFECTS OF MIXED ASSEMBLY TYPES AND FUEL ROD BOWING

In accordance with AREVA rod bow methodology (Reference 14.0-12), the magnitude of rod bow for the AREVA assemblies has been estimated. The calculations indicate that 50% closure of the rod-to-rod gap occurs at an assembly exposure in excess of the licensed burnup limit for the AREVA 14 x 14 design. Significant impact to MDNBR due to rod bow does not occur until the gap closures exceed 50%. Since the maximum design exposure for AREVA reload fuel in Millstone Unit 2 is significantly less than that at which 50% closure occurs, rod bow does not significantly impact the MDNBR for AREVA fuel. Also, total peaking is not significantly impacted.

14.0.11 PLANT LICENSING BASIS AND SINGLE FAILURE CRITERIA

All event scenarios considered in the safety analysis depend on the following single failure criteria in the RPS:

The RPS is designed with redundancy and independence to assure that no single failure or removal from service of any component or channel of a system will result in the loss of the protection function. For each event, the reactor trips occur at the specified setpoint within the specified delay time assuming a worst single active failure.

Except for the steam generator tube rupture, design basis accident (limiting fault event) scenarios considered in the Millstone 2 safety analysis depend on one of the following additional single failure criteria:

1. Each ESF is designed to perform its intended safety function assuming a failure of a single active component. For these events, the ESFs required to function in an event are assumed to suffer a worst single failure of an active component.

2. The onsite power system and the offsite power system are designed such that each shall independently be capable of providing power for the ESF assuming a failure of a single active component in either power system.

The assumptions for concurrent loss of offsite power are as follows:

1. The following postulated accidents are considered assuming a concurrent loss of offsite power: main steam line break, control rod ejection, steam generator tube rupture, and LOCA.

2. The loss of normal feedwater, an anticipated operational occurrence, is analyzed assuming a concurrent loss of offsite power.

The requirements of 10 CFR 50, Appendix A, Criteria 10, 20, 25 and 29 require that the design and operation of the plant and the RPS assure that the SAFDLs not be exceeded during AOOs. As per the definition of AOO in 10 CFR 50, Appendix A, “Anticipated Operational Occurrences mean those conditions of normal operation which are expected to occur one or more times during


the life of the nuclear power unit and include but are not limited to loss of power to all recirculation pumps, tripping of the turbine generator set, isolation of the main condenser, and loss of all offsite power.” The SAFDLs are that: 1) the fuel shall not experience centerline melt; and 2) the DNBR shall have a minimum allowable limit such that there is a 95% probability with a 95% confidence interval that DNB has not occurred.

14.0.12 PLOT VARIABLE NOMENCLATURE

Some of the plotted results presented in Sections 14.1 through 14.6, use PTSPWR2 (Reference 14.0-13) output variable nomenclature. Specific variables plotted are listed and defined in Table 14.0.12-1.

14.0.13 REFERENCES

14.0-1 “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants,” NUREG-0800, U.S. Nuclear Regulatory Commission, July 1981.

14.0-2 Technical Specifications for Millstone Unit 2, Docket Number 50-336.

14.0-3 Deleted.

14.0-4 “Statistical Setpoint/Transient Methodology for Combustion Engineering Type Reactors,” EMF-1961(P)(A), Revision 0, Siemens Power Corporation, July 2000.

14.0-5 “Reactor Analysis Systems for PWRs, Volume 1 - Methodology Description, Volume 2 - Benchmarking Results,” EMF-96-029-(P)(A), Siemens Power Corporation, January 1997.

14.0-6 Deleted.

14.0-7 Deleted.

14.0-8 “HTP: Departure from Nucleate Boiling Correlation for High Thermal Performance Fuel,” EMF-92-153(P)(A), Revision 1, Siemens Power Corporation, January 2005.

14.0-9 Deleted.

14.0-10 Deleted.

14.0-11 “XCOBRA-IIIC: A Computer Code to Determine the Distribution of Coolant During Steady-State and Transient Core Operation,” XN-NF-75-21(A), Revision 2, Exxon Nuclear Company, January 1986.

14.0-12 “Computational Procedure for Evaluating Fuel Rod Bowing,” XN-NF-75-32(A), Supps. 1, 2, 3 & 4, Exxon Nuclear Company, Richland, WA 99352, October 1983.


14.0-13 “Description of the Exxon Nuclear Plant Transient Simulation Model for Pressurized Water Reactors (PTS-PWR),” XN-NF-74-5(A), Rev. 2 and Supplements 3-6, Exxon Nuclear Company, Richland, WA 99352, October 1986.


* Excluding decay heat.

** Fuel in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

TABLE 14.0-1 REACTOR OPERATING MODES FOR MILLSTONE UNIT 2

Mode Reactivity

Condition, Keff

% Rated Thermal Power *

Average Coolant Temperature

1. Power Operation ≥ 0.99 > 5% ≥ 300°F

2. Startup ≥ 0.99 ≤ 5% ≥ 300°F

3. Hot Standby < 0.99 0 ≥ 300°F

4. Hot Shutdown < 0.99 0 300°F > Tavg > 200°F

5. Cold Shutdown < 0.98 0 ≤ 200°F

6. Refueling ** ≤ 0.95 0 ≤ 140°F


TABLE 14.0-2 DISPOSITION OF EVENTS SUMMARY

SRP Event Designation Name Disposition

Bounding Event

15.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM

15.1.1 Decrease in Feedwater Temperature Bounded 15.1.3

15.1.2 Increase in Feedwater Flow

1) Power Bounded 15.1.3

2) Startup Bounded 15.1.3

15.1.3 Increase in Steam Flow Analyze

15.1.4 Inadvertent Opening of a Steam Generator Relief or Safety Valve

Bounded 15.1.3

15.1.5 Steam System Piping Failures Inside and Outside of Containment

Analyze

15.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM

15.2.1 Loss of External Load Analyze

15.2.2 Turbine Trip Bounded 15.2.1

15.2.3 Loss of Condenser Vacuum Not in Licensing Basis

15.2.4 Closure of the Main Steam Isolation Valves Analyze

15.2.5 Steam Pressure Regulator Failure Not applicable; BWR Event

15.2.6 Loss of Nonemergency AC Power to the Station Auxiliaries

Not in Licensing Basis

15.2.7 Loss of Normal Feedwater Flow Analyze

15.2.8 Feedwater System Pipe Breaks Inside and Outside Containment


15.3 DECREASE IN REACTOR COOLANT SYSTEM FLOW

15.3.1 Loss of Forced Reactor Coolant Flow Analyze

15.3.2 Flow Controller Malfunction Not Applicable

15.3.3 Reactor Coolant Pump Rotor Seizure Analyze

15.3.4 Reactor Coolant Pump Shaft Break Not in Licensing Basis

15.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES


15.4.1 Uncontrolled Control Rod/Bank Withdrawal from a Subcritical or Low-Power Condition

Analyze

15.4.2 Uncontrolled Control Rod/Bank Withdrawal at Power

Analyze

15.4.3 Control Rod Misoperation

1) Dropped Control Rod/Bank Analyze

2) Dropped Part-Length Control Rod Not Applicable

3) Malpositioning of the Part-Length Control Rod Group

Not Applicable

4) Statically Misaligned Control Rod/Bank Not in Licensing Basis

5) Single Control Rod Withdrawal Analyze

6) Reactivity Control Device Removal Error During Refueling

Not Applicable

7) Variations in Reactivity Load to be Compensated by Burnup or On Line Refueling

Not Applicable

15.4.4 Startup of an Inactive Loop Not Applicable (Tech Specs Preclude Significant Consequences)

15.4.5 Flow Controller Malfunction Not applicable; No Flow Controller

15.4.6 Chemical and Volume Control System (CVCS) Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant

Analyze, Modes 1-6

15.4.7 Inadvertent Loading and Operation of a Fuel Assembly in an Improper Position


15.4.8 Spectrum of Control Rod Ejection Accidents Analyze

15.4.9 Spectrum of Rod Drop Accidents (BWR)

Not applicable; BWR Event

15.5 INCREASES IN REACTOR COOLANT INVENTORY

15.5.1 Inadvertent Operation of the Emergency Core Cooling System that Increases Reactor Coolant Inventory


TABLE 14.0-2 DISPOSITION OF EVENTS SUMMARY (CONTINUED)


Bounding Event


15.5.2 CVCS Malfunction that Increases Reactor Coolant Inventory


15.6 DECREASES IN REACTOR COOLANT INVENTORY

15.6.1 Inadvertent Opening of a PWR Pressurizer Pressure Relief Valve

Analyze

15.6.2 Radiological Consequences of the Failure of Small Lines Carrying Primary Coolant Outside of Containment

Not Applicable

15.6.3 Radiological Consequences of Steam Generator Tube Failure

Analyze

15.6.4 Radiological Consequences of a Main Steamline Failure Outside Containment

Not applicable; BWR Event

15.6.5 Loss-of-Coolant Accidents Resulting from a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary

Analyze

15.7 RADIOACTIVE RELEASE FROM A SUBSYSTEM OR COMPONENT

15.7.1 Waste Gas System Failure Analyze

15.7.2 Radioactive Liquid Waste System Leak or Failure (Release to Atmosphere)


15.7.3 Postulated Radioactive Releases due to Liquid Containing Tank Failures


15.7.4 Radiological Consequences of Fuel Handling Accidents

Analyze

15.7.5 Spent Fuel Cask Drop Accidents Analyze

FSAR EVENTS NOT CONTAINED IN THE STANDARD REVIEW PLAN

(1) Failures of Equipment Which Provide Joint Control/Safety Functions

Not Applicable

(2) Containment Pressure Analysis Analyze

(3) Deleted

(4) Radiological Consequences of the Design Basis Accident

Analyze

TABLE 14.0-2 DISPOSITION OF EVENTS SUMMARY (CONTINUED)


Bounding Event


TABLE 14.0.1-1 ACCIDENT CATEGORY USED FOR EACH ANALYZED EVENT

Event Accident Category

14.1.3 Increase in Steam Flow Moderate

14.1.5 Steam System Piping Failures Inside and Outside of Containment Limiting Fault

14.2.1 Loss of External Load Moderate

14.2.4 Single Main Steam Isolation Valve Closure Moderate

14.2.7 Loss of Normal Feedwater Flow Moderate

14.3.1 Loss of Forced Reactor Coolant Flow Moderate

14.3.3 Reactor Coolant Pump Rotor Seizure Limiting Fault

14.4.1 Uncontrolled Bank Withdrawal at Subcritical or Low Power Moderate

14.4.2 Uncontrolled Bank Withdrawal at Power Moderate

14.4.3 Control Rod Misoperation

1) Dropped Control Rod/Bank Moderate

5) Single Control Rod Withdrawal Infrequent

14.4.6 Chemical and Volume Control System Malfunction Resulting in Decreased Boron Concentration

Moderate

14.4.8 Control Rod Ejection Limiting Fault

14.6.1 Inadvertent Opening of a Pressurizer Pressure Relief Valve Moderate

14.6.3 Radiological Consequences of Steam Generator Tube Failure Limiting Fault

14.6.5 Loss-of-Coolant Accidents Limiting Fault

14.7.1 Waste Gas System Failure

14.7.4 Radiological Consequences of Fuel Handling Accidents

14.7.5 Spent Fuel Cask Drop Accidents

14.8.2 Containment Analysis

14.8.4 Radiological Consequences of the Design Basis Accident


TABLE 14.0.2-1 PLANT OPERATING CONDITIONS

Core Thermal Power 2700 MWt

Pump Thermal Power (Total) 17.1 MWt

System Pressure 2225-2280 psia

Reactor Coolant System Flow Rate (Minimum) 360,000 gpm *

Core Inlet Coolant Temperature at full power 541.0-549.0°F **

* Flow reductions to 349,200 gpm are compensated for by reductions in the FrT and linear

heat rate limits.

** A full power coastdown to an indicated RCS cold leg temperature of 537°F at EOC is supported.


TABLE 14.0.2-2 NOMINAL FUEL DESIGN PARAMETERS

Total Number of Fuel Assemblies 217

Fuel Assembly Design Type 14 x 14

Assembly Pitch 8.180 inches

Fuel Rods per Assembly 176

Guide Tubes per Assembly 4

Instrument Tubes per Assembly 1

Rod Pitch 0.580 inches

Clad Outside Diameter 0.440 inches

Guide and Instrument Tube OD 1.115 inches

Active Fuel Length 136.70 inches

Fuel Rod Length 146.25 inches

Number of Spacers 9


TABLE 14.0.3-1 CORE POWER DISTRIBUTION (TABLE DELETED)


TABLE 14.0.4-1 RANGE OF KEY INITIAL CONDITION OPERATING PARAMETERS

Core thermal power Subcritical to 2754 MWt (1)

Core inlet temperature (power operation) Figure 14.0.4-1

Reactor coolant system pressure 2225-2280 psia +14/-25 psi

Pressurizer Water Level Programmed ± 7.5 inches

Feedwater flow and temperature Range consistent with power level

(1) 102% of 2700 MWt

Revision 38—

06/30/20M

PS

-2 FS

AR

14.0-21

F POWER
FIGURE 14.0.4-1 RCS COLD LEG TEMPERATURE AS A FUNCTION O


FIGURE 14.0.4-2 NOT USED

Revision 38—

06/30/20M

PS

-2 FS

AR

14.0-27

FIG LOCAL POWER DENSITY
URE 14.0.4-7 LINEAR HEAT RATE LIMITING CONDITION FOR OPERATION USED INLIMITING CONDITION FOR OPERATION VERIFICATION


TABLE 14.0.5-1 REACTIVITY PARAMETERS (TABLE DELETED)


TABLE 14.0.7-1 ANALYTICAL TRIP SETPOINTS

Parameter Setpoint

Low steam generator pressure 658 psia

Low steam generator water level 43%

Variable high power 111.6% ceiling on nuclear indicated power; 114% ceiling on thermal power 27.22% - Floor

Low reactor coolant flow 89.7% of Tech Spec minimum

High pressurizer pressure 2422 psia

High containment pressure 5.83 psig


a Two-sided 95% tolerance.

b The nuclear power measurement uncertainty used in the setpoints analyses account for calorimetric and flux signal uncertainties.

c The thermal power measurement uncertainty used in the setpoints analyses account for calorimetric and thermal power signal uncertainties. Included in this power measurement uncertainty are 2σ uncertainties on the RCS hot and cold leg temperature signals of 2.2°F and 1.725°F.

d One-sided 95% tolerance.

e Not treated statistically, treated as an event specific bias. Events where this trip is credited include the inadvertent opening of a pressurized water reactor pressurizer pressure relief valve, the uncontrolled rod/bank withdrawal at power, and the increase in steam flow transients.

f. An additional ASI bias for the INPAX-II / shape annealing factor ASI measurement uncertainty was applied.

TABLE 14.0.7-2 UNCERTAINTIES APPLIED AT HFP CONDITION IN LOCAL POWER DENSITY LIMITING SAFETY SYSTEM SETTINGS CALCULATIONS

Parameter Value

Engineering tolerance ± 3% a

Nuclear flux power measurement uncertainty at full power ± 2.34% a, b

Thermal Power measurement uncertainty at full power ±4.19% a, c

Peaking uncertainty ≤ 7% d

Local power density trip transient offset e

ASI uncertainty ± 0.039 a, f


a Two-sided 95% tolerance.

b Includes both pressure measurement and trip processing uncertainties.

c A 7.5 psi pressure measurement bias is applied along with an event specific set of transient biases on power, pressurizer pressure and RCS hot and cold leg temperatures. The events where this trip is credited include the inadvertent opening of a pressurized water reactor pressurizer pressure relief valve, the uncontrolled rod/bank withdrawal at power, and the increase in steam flow transients.

d One-sided 95% tolerance. Stated tolerance is percentage of design volumetric flow of 324,800 gpm.

e One-sided 95% tolerance.

TABLE 14.0.7-3 UNCERTAINTIES APPLIED AT HFP CONDITION IN THE THERMAL MARGIN/LOW PRESSURE LIMITING SAFETY SYSTEM SETTINGS

CALCULATIONS

Parameter Value

TM/LP trip uncertainty ± 90.30 psi a, b

TM/LP trip bias c

Inlet coolant temperature ± 2.25°F a

Flow measurement uncertainty + 4% d

Fr uncertainty ± 6% e


a. Two-sided 95% tolerance.

b. The nuclear power measurement uncertainty used in the setpoints analyses account for calorimetric and flux signal uncertainties.

c. One-sided 95% tolerance.

d. An additional ASI bias for the INPAX-II / shape annealing factor ASI measurement uncertainty was applied.

e. Uncertainty is ASI-dependent; this is the maximum value applied over the range of ASI values considered.

TABLE 14.0.7-4 UNCERTAINTIES APPLIED AT HFP CONDITION IN THE LOCAL POWER DENSITY LIMITING CONDITION FOR OPERATION CALCULATIONS

Parameter Value

Engineering tolerance ± 3% a

Power measurement uncertainty at full power ± 2.34% a, b

Peaking uncertainty ≤ 7% c

ASI uncertainty ± 0.043 a, d, e


a. Two-sided 95% tolerance.

b. One-sided 95% tolerance. Stated value is percentage of design volumetric flow of 324,800 gpm.

c. The nuclear power measurement uncertainty used in the setpoints analyses account for calorimetric and flux signal uncertainties.

d. An additional ASI bias for the INPAX-II / shape annealing factor ASI measurement uncertainty was applied.

TABLE 14.0.7-5 UNCERTAINTIES APPLIED IN DEPARTURE FROM NUCLEATE BOILING LIMITING CONDITION FOR OPERATION CALCULATIONS

Parameter Value

Pressure measurement uncertainty ± 17.9 psi a

Inlet coolant temperature ± 2.25 °F a

Flow measurement uncertainty ± 4% b

ASI uncertainty ± 0.053 a, d

Power measurement uncertainty (at full power) ± 2.34% a, c


FIGURE 14.0.7–1 VERIFICATION OF LOCAL POWER DENSITY LIMITING SAFETY SYSTEM SETTING


FIGURE 14.0.7–2 THERMAL MARGIN/LOW PRESSURE TRIP FUNCTION A1

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FIGURE 14.0.7–3 THERMAL MARGIN/LOW PRESSURE TRIP FUNCTI


FIGURE 14.0.7–4 NOT USED


FIGURE 14.0.7–5 VERIFICATION OF THE DEPARTURE FROM NUCLEATE BOILING LIMITING CONDITION FOR OPERATION


FIGURE 14.0.7–6 VERIFICATION OF LOCAL POWER DENSITY LIMITING CONDITION FOR OPERATION

1) The center point on the LPD LCO barn is shown at (0.0, 101.0); however, that point is used only for setting plant instrumentation. Operation is not permitted above 100% of rated power. The analysis was actually performed with that point at (0.0, 100.0).

2) The analyzed barn, which includes additional bias for the INPAX-II/shape annealing factor ASI measurement uncertainty, is represented by the dashed line. The analyzed barn is not meant for direct use in the plant.

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FI LOCAL POWER DENSITY
GURE 14.0.7–7 LINEAR HEAT RATE LIMITING CONDITION OF OPERATION USED INLIMITING CONDITION OF OPERATION VERIFICATION

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S

Capacity

T 110% of flow at rated conditions

T NA

M NA

F 120% of flow at rated conditions

P 294,000 lbm/hr/valve

S 794,060 lbm/hr/valve

A , 14.6.3 300 gpm/MDAFP

and 600 gpm for TDAFP

P 153,000 lbm/hr/valve

TABLE 14.0.8-1 COMPONENT CAPACITIES AND SETPOINT

Component Setpoint Response Time

urbine main throttle valve NA NA

urbine stop valve NA 0.020 sec

ain steam line isolation valves NA 6.0 sec

eedwater flow regulating valves NA 14 sec

ressurizer safety valves 2500 psia ± 3% NA

team line safety valves 2 at 1000 psia ± 3% NA

2 at 1005 psia ± 3%

2 at 1015 psia ± 3%

2 at 1025 psia ± 3%

2 at 1035 psia ± 3%

2 at 1045 psia ± 3%

4 at 1050 psia ± 3%

uxiliary feedwater pumps NA 240 sec for Events 14.2.7and 14.6.5.2

180 sec for Events 14.8.214.1.5

ressurizer relief valves 2397 psia (+)14 (-)25 psi 2.0 sec

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P 375 gpm

P 320 kW (may be less due to heater unavailability)

P 1280 kW (may be less due to heater unavailability)

TINUED)

Capacity

ressurizer sprays Off - 2300 psia (+)14 (-)25 psi NA

Full On - 2350 psia (+)14 (-)25 psi

ressurizer proportional heaters Off - 2275 psia (+)14 (-)25 psi NA

Full On - 2225 psia (+)14 (-)25 psi

ressurizer backup heaters Off - 2225 psia (+)14 (-)25 psi NA

On - 2200 psia (+)14 (-)25 psi

TABLE 14.0.8-1 COMPONENT CAPACITIES AND SETPOINTS (CON

Component Setpoint Response Time

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T TRANSIENT AND ACCIDENT

ignals and Equipment *

1

F ater Level Signals

n Valves

olation Valves

eactor Trip

In ater Level Signals

olation Valves

eactor Trip

m Dump Controller

ondenser Controller

ter System

InG

ater Level Signals

olation Valves

eactor Trip

m Dump Controller

ondenser Controller

ter System

ABLE 14.0.9-1 OVERVIEW OF PLANT SYSTEMS AND EQUIPMENT AVAILABLE FOR CONDITIONS

Event Reactor Trip Functions Other S

4.1, Increase in Heat Removal By the Secondary System

eedwater System Malfunctions High Power Trip Steam Generator W

Thermal Margin / Low Pressure Trip Feedwater Isolatio

Low Steam Generator Pressure Trip Main Steamline Is

Safety Injection Actuation Signal Turbine Trip on R

crease in Steam Flow Low Steam Generator Pressure Trip Steam Generator W

Thermal Margin / Low Pressure Trip Main Steamline Is

High Power Trip Turbine Trip on R

Safety Injection Actuation Signal Atmospheric Stea

Steam Bypass to C

Auxiliary Feedwa

advertent Opening of a Steam enerator Relief or Safety Valve

Low Steam Generator Pressure Trip Steam Generator W




Steam Bypass to C

Auxiliary Feedwa

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S ater Level Signals

olation Valves

eactor Trip

m Dump Controller

ondenser Controller

ter System

y

tion

oolers

n

1

LL

ater Level Signals

eactor Trip

m Dump Controller

ondenser Controller

afety Valves

Valves



team System Piping Failure Low Steam Generator Pressure Trip Steam Generator W




High Containment Pressure Trip Steam Bypass to C

Low Reactor Coolant Flow Trip Auxiliary Feedwa

Containment Spra

Containment Isola

Containment Air C

Feedwater Isolatio

4.2, Decrease in Heat Removal by the Secondary System

oss of External Load / Turbine Trip /oss of Condenser Vacuum

High Pressurizer Pressure Trip Steam Generator W


Thermal Margin / Low-Pressure Trip Atmospheric Stea

Low Steam Generator Water Level Trip Steam Bypass to C

Steam Generator S

Pressurizer Safety

Pressurizer Sprays

ABLE 14.0.9-1 OVERVIEW OF PLANT SYSTEMS AND EQUIPMENT AVAILABLE FOR CONDITIONS (CONTINUED)


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CV

m Dump Controller

ondenser Controller

afety Valves

Valves

Lth

ater Level Signals

afety Valves

Valves

ter System

L ater Level Signals

afety Valves

Valves

ter System

and Level Control

F ater Level Signals

afety Valves

Valves

ter System

and Level Control

1



losure of the Main Steam Isolation alves

Low Steam Generator Pressure Trip Atmospheric Stea

Low Steam Generator Water Level Trip Steam Bypass to C

High Power Trip Steam Generator S

Thermal Margin / Low Pressure Trip Pressurizer Safety

High Pressurizer Pressure Trip Pressurizer Sprays

oss of Nonemergency AC Power to e Station Auxiliaries

Low Reactor Coolant Flow Trip Steam Generator W

High Pressurizer Pressure Trip Steam Generator S

Thermal Margin / Low Pressure Trip Pressurizer Safety

Low Steam Generator Water Level Trip Auxiliary Feedwa

oss of Normal Feedwater Flow Low Steam Generator Water Level Trip Steam Generator W


Thermal Margin/Low-Pressure Trip Pressurizer Safety

Auxiliary Feedwa

Pressurizer Sprays

eedwater System Pipe Break High Pressurizer Pressure Trip Steam Generator W

Thermal Margin / Low Pressure Trip Steam Generator S

Low Steam Generator Water Level Trip Pressurizer Safety

Low Steam Generator Pressure Trip Auxiliary Feedwa

Pressurizer Sprays

4.3, Decrease in Reactor Coolant System Flow



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L m Dump Controller

ondenser Controller

afety Valves

Valves

RS

m Dump Controller

ondenser Controller

afety Valves

Valves

1

UWP

rohibit Action on Pretrip Alarms

is Maintained as Required by ations for Modes 2-6

UWC

Valves

afety Valves

and Level Control

ank Deviation Alarms which rawal Prohibit

rohibit on Pretrip Alarms



oss of Forced Reactor Coolant Flow Low Reactor Coolant Flow Trip Atmospheric Stea

Thermal Margin / Low Pressure Trip Steam Bypass to C


Pressurizer Safety

eactor Coolant Pump Rotor Seizure/haft Break

Low Reactor Coolant Flow Trip Atmospheric Stea

High Pressurizer Pressure Trip Steam Bypass to C


Pressurizer Safety

4.4, Reactivity and Power Distribution Anomalies

ncontrolled Control Rod Bank ithdrawal from a Subcritical or Low-

ower Startup Condition

Thermal Margin / Low Pressure Trip Rod Withdrawal P

High-Power Trip Shutdown MarginTechnical Specific

High Pressurizer Pressure Trip

ncontrolled Control Rod Bank ithdrawal at Power Operation

onditions

High-Power Trip Pressurizer Safety


High Pressurizer Pressure Trip Pressurizer Spray

Control Rod and BInitiate Rod Withd

Rod Withdrawal P



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C Valves

afety Valves

and Level Control

ank Deviation Alarms

S ocedures for Start up of an Idle

ith Less than All Four Primary Controlled by Technical

C(CDth

ocedures

r Response Time

InF

SA

1



ontrol Rod Misoperation High Power Trip Pressurizer Safety


Low Steam Generator Water Level Trip Pressurizer Spray

Safety Injection Actuation Signal Control Rod and B

tart up of an Inactive Loop High Power Trip Administrative PrPump

Thermal Margin / Low-Pressure Trip Plant Operation wCoolant Pumps is Specifications

hemical and Volume Control System VCS) Malfunction that Results in a

ecrease in the Boron Concentration in e Reactor Coolant

High Power Trip Administrative Pr

Thermal Margin / Low Pressure Trip Sufficient Operato


advertent Loading and Operation of a uel Assembly in an Improper Position

(Technical Specification Measurement Requirement and Administrative Procedures Preclude Occurrence)

pectrum of Control Rod Ejection ccidents

High Power Trip


Thermal Margin / Low Pressure Trip

Long Term, Safety Injection Actuation Signal

4.5, Increases in Reactor Coolant System Inventory



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InadveCVCS Reacto

es

gation System

14.6, D

InadvePressur

jection System

Steam Valves

n Valves

mp Controller

nser Controller

stem

Small-BResultiPostulaReacto

g System

stem

Air Cooler

TABL SIENT AND ACCIDENT

and Equipment *

rtent Operation of the ECCS /Malfunction that Increases r Coolant Inventory

High Power Trip Pressurizer Safety Valv

Thermal Margin / Low Pressure Trip Overpressurization Miti


ecreases in Reactor Coolant Inventory

rtent Opening of a PWR izer Pressure Relief Valve

High Power Trip High Pressure Safety In

Thermal Margin / Low Pressure Trip Pressurizer Heaters

Generator Tube Failure Thermal Margin/Low Pressure Trip Steam Generator Safety

Safety Injection Actuation Signal Main Steamline Isolatio

Atmospheric Steam Du

Steam Bypass to Conde

Auxiliary Feedwater Sy

reak Loss-of-Coolant Accidents ng from a Spectrum of ted Piping Breaks within the r Coolant Pressure Boundary

Thermal Margin/Low Pressure Trip Emergency Core Coolin

Safety Injection Actuation Signal Auxiliary Feedwater Sy

Low Reactor Coolant Flow Trip Containment Isolation

Containment Spray and

E 14.0.9-1 OVERVIEW OF PLANT SYSTEMS AND EQUIPMENT AVAILABLE FOR TRANCONDITIONS (CONTINUED)

Event Reactor Trip Functions Other Signals

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* vent consequences. However, the afety valves). In addition, the event onsequences (such as condenser

LRPR

ooling System

ter System

tion

y and Air Cooler



All of the systems and equipment listed for an event would normally be available to mitigate the eevent analysis only takes credit for those systems and equipment which are safety-grade (such as sanalysis assumes that any non safety-grade systems or equipment which would worsen the event csteam dump, for certain events) are available.

arge-Break Loss-of-Coolant Accidents esulting from a Spectrum of ostulated Piping Breaks within the eactor Coolant Pressure Boundary

No Credit taken for a Reactor Trip by the Reactor Protection System due to the Rapid Depletion of the Moderator which Shuts Down the Reactor Core Almost Immediately, Followed by ECCS Injection Which Contains Sufficient Boron to Maintain the Reactor Core in a Subcritical Configuration

Emergency Core C

Auxiliary Feedwa

Containment Isola

Containment Spra




TABLE 14.0.12-1 NOMENCLATURE USED IN PLOTTED RESULTS

Variable Number Definition

DCLEVA1 Steam Generator Downcomer Level, Loop 1

DK Total Reactivity

DKDOP Doppler Reactivity

DKMOD Moderator Temperature Reactivity

PD01 Steam Generator Dome Pressure, Loop 1

PL Core Power Level

PPR Pressurizer Pressure

PSGSA1 Steam Generator Pressure, Loop 1

QOA Core Average Heat Flux

TAVEC Core Average Coolant Temperature

TAVG1 Average Coolant Temperature, Loop 1

TCIO Core Inlet Coolant Temperature

TCL1 Cold Leg Temperature, Loop 1

THL1 Hot Leg Temperature, Loop 1

VWPR Pressurizer Liquid Volume

WDOSLT Total Steamline Steam Flow Rate

WFWT Total Feedwater Flow Rate

WLPCR Vessel Flow Rate


14.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM

14.1.1 DECREASE IN FEEDWATER TEMPERATURE

14.1.1.1 Event Initiator

A decrease in feedwater temperature may be caused by loss of one or more feedwater heaters. The loss could be due to the interruption of steam extraction flow or to an accidental opening of a feedwater heater bypass line. The worst loss of feedwater heaters incident would occur if all of the low pressure heaters were bypassed. The effects of any decrease in the feedwater temperature due to flow increases (Main or Auxiliary Feedwater (AF)) are discussed in Section 14.1.2.

14.1.1.2 Event Description

Due to a malfunction in the feedwater heater system, the enthalpy of the feedwater being injected into the steam generators is reduced. The increased subcooling of the feedwater reduces the secondary system average fluid enthalpy and increases the energy removal rate from the primary system. The increase in primary to secondary heat transfer causes the reactor coolant temperature at the outlet of the steam generator to decrease. This causes a corresponding decrease in the core inlet coolant temperature. With a negative moderator temperature coefficient (MTC), the reactor core power will begin to increase as the cooler moderator fluid reaches the core.

14.1.1.3 Reactor Protection

Reactor protection is provided by the variable overpower, thermal margin/low-pressure (TM/LP), local power density (LPD), and low steam generator pressure trips. Reactor protection for the decrease in feedwater temperature event is summarized in Table 14.1.1-1.

14.1.1.4 Disposition and Justification

For operating Modes 1-3, the response of the nuclear steam supply system (NSSS) is governed by the magnitude of the overcooling introduced by the initiating event. There is no extraction to the feedwater heaters for operating Modes 4-6. As such, there is not a credible event for these reactor operating conditions.

The most limiting case for Mode 1 is from rated power conditions because the feedwater flow rate and heater duty decrease with load. Also, at rated power conditions, the initial Departure from Nucleate Boiling Ratio (DNBR) margin is minimized. The consequences of the event in Modes 2 and 3 are bounded by those of Mode 1 because the magnitude of the initiating event in Modes 2 or 3 is much smaller than in Mode 1.

This cooldown rate due to bypassing the feedwater heaters is bounded by that of the maximum cooldown event postulated in Section 14.1.3. As such, the consequences of the Increase in Steam Flow (Event 14.1.3) bound the consequences for the Decrease in Feedwater Temperature event discussed in this section. The disposition of events for the Decrease in Feedwater Temperature event is summarized in Table 14.1.1-2.


14.1.2 INCREASE IN FEEDWATER FLOW


This event is initiated by a failure in the feedwater system which causes an increase in the feedwater flow to the steam generators. The initiators considered are complete opening of the feedwater control valves, overspeed of the feedwater pumps, inadvertent start of a second feedwater pump at low power, startup of the auxiliary feedwater system (AFWS), and inadvertent opening of the feedwater control valve bypass lines.


The increased flow to the steam generators causes an increase in the energy removal capability of the steam generators by reducing the average fluid enthalpy in the steam generators. The increased energy removal from the primary system causes the reactor coolant temperature at the outlet of the steam generator to decrease. The core inlet temperature will correspondingly be reduced, which will cause the core power to increase if the moderator temperature coefficient (MTC) is negative.

Because this event is characterized as a primary system overcooling event, the primary system pressure initially decreases along with the core inlet temperature. There is also a possibility for a core power increase in the presence of a negative moderator reactivity feedback coefficient. Increased reactor power reduces the core Departure from Nucleate Boiling (DNB) margin. A potential exists that the net effect of these three factors will represent a challenge to the core DNB margin.


Reactor protection for the rated power and power operation conditions (Mode 1) is provided by the variable overpower trip, LPD trip, TM/LP trip, low steam generator pressure trip and by the safety injection actuation signal (SIAS) on low pressurizer pressure. Additional protection is provided by the control grade reactor trip on turbine trip due to high steam generator water level.

For Modes 2 and 3, protection is provided by the low steam generator pressure trip, safety injection actuation signal (SIAS), and the variable overpower trip. Reactor protection for the Increase in Feedwater Flow event is summarized in Table 14.1.2-1.


The event consequences at rated power operating conditions will bound the consequences from all other power operating conditions. At rated power operating conditions, the initial thermal margin (DNBR) is minimized. Maximizing the increase in feedwater flow maximizes the load demand. This results in the maximum rate of moderator cooldown which, in the presence of a negative MTC, results in the maximum challenge to the specified acceptable fuel design limits (SAFDLs). Therefore, the limiting consequences of the increase in feedwater flow will occur at the full load rated power conditions and will bound all other power operating conditions due to


the initial steam generator inventory and initial margin to DNB. The greatest cooldown which can be postulated due to feedwater addition at full power is the overspeed of the feedwater pumps. This cooldown is larger than that due to inadvertent startup of the three AFW pumps but less than that calculated for Event 14.1.3, Increased Steam Flow.

The main feedwater system is off-line in Modes 4-6 but may be on-line in Mode 3. For Mode 3 operating conditions, the potential cooldown in conjunction with a negative MTC may result in a return to power at reduced primary pressure, elevated all-rods-in peaking, and less than four reactor coolant pump (RCP) conditions. This case may pose a greater challenge to the SAFDLs than the full power case, and would bound zero power operation in Mode 2 if the cooldown provides sufficient reactivity insertion to overcome the shutdown margin. This is due to the potential for prompt criticality in Mode 3. The greatest increase in feed flow would result from the startup of an idle pump with both control valves full open. The cooldown rate is less than the rate computed for Event 14.1.3 in Mode 3, and consequently Event 14.1.2 in Modes 2 and 3 is bounded by Event 14.1.3 initiated from Mode 3.

In Modes 4-6, the only increased feed flow event initiator is inadvertent startup of one or more AF pumps since the main feedwater system is off-line. The startup of all three AF pumps results in an increased energy removal rate, less than the maximum possible for the Increase in Steam Flow (Event 14.1.3) for Modes 4-6.

The disposition of events for the Increase in Feedwater Flow event is summarized in Table 14.1.2-2.

14.1.3 INCREASE IN STEAM FLOW


This event is initiated by a failure or misoperation in the main steam system which results in an increase in steam flow from the steam generators. This event could be caused by the rapid opening of the turbine control valves (TCVs), the atmospheric steam dump valves (ADVs), the turbine bypass valves (TBVs), the steam dump to condenser valves (SDVs), a safety relief valve (SRV), or the turbine feed pump control valves.


The increased steam flow resulting from the failure creates a mismatch between the heat being generated in the core and that being extracted by the steam generators. As a result of this power mismatch, the primary-to-secondary heat transfer increases and the primary system cools down. If the MTC is negative, the cooldown of the primary system coolant would cause an insertion of positive reactivity and the potential erosion of thermal margin.


The main steam system is designed to accommodate a 10% increase in load (step increase). Reactor protection against a main steam flow increase greater than a 10% step is provided by the


following trip signals: variable overpower trip, TM/LP trip, LPD trip, low steam generator water level trip, and low secondary pressure trip. In Modes 1, 2, and 3, protection is also provided by the Safety Injection Actuation Signal (SIAS) on low pressurizer pressure. Reactor protection for the Increase in Steam Flow event is summarized in Table 14.1.3-1.


This event is predominantly a cooldown event characterized by a primary pressure and temperature drop with a power rise. Therefore, the most limiting event for power operation is one which results in the highest power, the highest core inlet temperature, and the lowest primary pressure. Core flow remains essentially unchanged. The magnitude of the pressure drop for a given increase in steam flow is about the same regardless of the initial power level. The core inlet temperature will be maximized at HFP. The margin to DNB is the smallest at full power since the product of reactor power and peaking factor decreases as power drops. Additionally, the Variable Overpower trip setpoint will decrease as power decreases, thus providing greater margin to the SAFDLs at lower powers. Therefore, for Mode 1 and for nonzero power operation in Mode 2, the bounding event is one initiated from HFP.

The maximum possible steam release results from the simultaneous opening of the steam dump to condenser valves, the atmospheric dump valves and the turbine bypass valves. Furthermore, simulating the turbine control valves as operating in the “automatic” mode, rather than the “manual” mode, is limiting. Therefore, a spectrum of HFP cases, with steam releases ranging up to that for the steam dump to condenser valves and turbine bypass valves fully open with the turbine control valves operating in the “automatic” mode, were analyze. For Cycle 18, the additional opening of the atmospheric dump valves was evaluated and determined to be bounded by the cases previously analyzed and discussed in Section 14.1.3.5. The effects of power decalibration were also included in the analysis.

The ADVs are sized to accommodate 15% of steam flow at 2700 MWt. The SDVs and the TBV are sized to accommodate 40.5% of steam flow at 2700 MWt. Each SRV will pass 6.75% of steam flow at 2700 MWt. The TCVs are sized to accommodate 111.3% of steam flow at 2700 MWt. The capacities of the control valves for the main feedwater and AF pump turbines are significantly less.

To bound the allowable plant operation with the TCVs in automatic control mode, the TCVs were opened fully, simultaneous with the SDVs and the TBV opening. This energy removal rate bounds those of the rated power operating conditions for Events 14.1.1 to 14.1.2, and 14.1.4. Therefore, this event is analyzed as part of the plant transient analysis for Millstone Unit 2. The consequences of this event for all other operating conditions are bounded by the rated power operating condition due to the increased margin to DNB at the other power operating conditions.

The disposition of events for the Increase in Steam Flow event is summarized in Table 14.1.3-2.


14.1.3.5 Definition of Events Analyzed

A spectrum of HFP cases were analyzed, with steam flows ranging from approximately 11% excess steam flow (turbine control valves fully open) to the excess steam flow associated with the steam dump to condenser valves, turbine bypass valve, and turbine control valves fully opening. The effects of power decalibration were also included in the analysis.

The end-of-cycle (EOC) Doppler feedback coefficient was selected to maximize the challenge to the specified fuel design limits. The consequences of this event are bounded at EOC conditions when the MTC is at its maximum negative value. Therefore, the core operating limits report most negative MTC limit (-32 pcm/°F) was used.

Only full power cooldown and low power events which credit power-dependent reactor trips have the potential to be adversely affected by power decalibration. Power decalibration is caused by density induced changes in the reactor vessel downcomer shadowing the power-range ex-core detectors during heatup or cooldown transients. The nuclear power levels indicated by those instruments are lower than the actual reactor power levels when the coolant entering the reactor vessel is cooler than the normal temperature for full power operation. The Variable Overpower trip, the TM/LP trip function, and the LPD trip all depend on the indicated nuclear power level. The power decalibration effect was included in the modeling of any power-dependent reactor trips credited in this analysis.

The initial conditions for the Increase in Steam Flow event is summarized in Table 14.1.3-3.

14.1.3.6 Analysis Results

The transient for the limiting case (approximately 11% excess steam flow) is initiated by a failure which causes the turbine control valves to open fully at initiation. The responses of key system variables are given in Figures 14.1.3–1 to 14.1.3–9. The sequence of events is given in Table 14.1.3-4. The peak reactor power level calculated for each of the Increase in Steam Flow cases analyzed are listed in Table 14.1.3-5.The increased steam flow (see Figure 14.1.3–7) creates a mismatch between the core heat generation rate and the steam generator heat removal rate. This power mismatch causes the primary-to-secondary heat transfer rate to increase, which in turn causes the primary system to cool down (see Figure 14.1.3–3). With a negative MTC (see Figure 14.1.3–2), the primary system cooldown causes the reactor power level to increase (see Figure 14.1.3–1. However, due to power decalibration, the indicated nuclear power level does not increase along with the reactor power level. Eventually, the indicated thermal power level reaches the Variable Overpower reactor trip ceiling, and the reactor is tripped. This terminates the power excursion.

The minimum DNBR for the limiting Increase in Steam Flow case (with approximately 11% excess steam flow) is bounded by the Section 14.3.1 four RCP loss of flow event, and is above the 95/95 DNBR safety limit. Moreover, the TM/LP trip is designed to protect DNB limits for this event. The LPD LSSS trip ensures that the maximum linear heat rate is below the FCMLHR limit. These results demonstrate that fuel failures do not occur for the Increase in Steam Flow event and that the event acceptance criteria are satisfied.


14.1.3.7 Conclusion

The results of the analysis demonstrate that the event acceptance criteria are met since the minimum DNBR predicted for the full power case is greater than the safety limit. The correlation limit assures that with 95% probability and 95% confidence, DNB is not expected to occur; therefore, no fuel is expected to fail. The FCMLHR limit is not violated during this event.

14.1.4 INADVERTENT OPENING OF A STEAM GENERATOR RELIEF OR SAFETY VALVE


This event is initiated by an increase in steam flow caused by the inadvertent opening of a secondary side safety or relief valve.


The resulting mismatch in energy generation and removal rates results in an overcooling of the primary system. If the MTC is negative, the reactor power will increase.


Reactor protection is provided by the variable overpower trip, LPD trip, TM/LP trip, low secondary pressure trip, and low steam generator water level trip. In Modes 1, 2, and 3, protection is also provided by the safety injection actuation signal (SIAS) on low pressurizer pressure. Reactor protection for the Inadvertent Opening of a Steam Generator Relief or Safety Valve event is summarized in Table 14.1.4-1.


The inadvertent opening of a steam generator safety valve would result in an increased steam flow of approximately 6.75% of full rated steam flow. Each dump (relief) valve is sized for approximately 7.50% steam flow with the reactor at full rated power. As such, the consequences of any of these occurrences will be bounded by the events in Section 14.1.3. The disposition of events for the Inadvertent Opening of a Steam Generator Relief or Safety Valve event is summarized in Table 14.1.4-2.

14.1.5 STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT

Two separate analyses have been performed for the Steam Line Break (SLB) event. Section 14.1.5.1 describes the pre-scram analysis performed to determine Departure from Nucleate Boiling Ratio (DNBR) and Linear Heat Generation Rate (LHGR) up to and including reactor trip. This time period represents the highest reactor power condition and the assumptions have been selected to minimize DNBR and maximize LHGR during this time frame. Section 14.1.5.2 describes the post-scram analyses performed to determine MDNBR and LHGR during the return to power caused by the overcooling. A different set of assumptions and single


failure were determined to minimize MDNBR and maximize LHGR for the return to power time frame.

14.1.5.1 Pre-Scram Analysis

14.1.5.1.1 Event Initiator

The pre-scram SLB analysis is initiated by a rupture in the main steam piping which results in an uncontrolled steam release from the secondary system.

14.1.5.1.2 Event Description

The increase in energy removal through the secondary system results in a severe overcooling of the primary system. With a negative MTC, the primary system cooldown causes the reactor power level to increase. If the break is not large enough to trip the reactor on a Low Steam Generator Pressure signal, the cooldown will continue until the reactor is tripped on a Variable Overpower or TM/LP signal (for breaks outside containment) or a High Containment Pressure signal (for breaks inside containment) or until the reactor reaches a new steady-state condition at an elevated power level.

Although the SLB calculation is typically a cooldown event, for the pre-scram analysis the cooldown event is not significant for the limiting pre-scram case. The case with a loss of off site power, also known as a “pumps off” case, credits the low reactor coolant flow trip for harsh conditions. In this case, the Reactor Coolant Pumps (RCPs) are tripped shortly after the initiation of the transient. The sharp reduction in reactor coolant flow causes the pre-scram pumps off calculation to become a heat up transient very similar to a Loss of Coolant Flow (LOCF). Therefore, the conditions for this case are biased as if it were a LOCF (i.e. BOC neutronics). This case becomes a combination of an MSLB and an LOCF event.

14.1.5.1.3 Reactor Protection

Reactor protection is provided by the low steam generator pressure and water level trips, variable overpower trip, LPD trip, TM/LP trip, high containment pressure trip, low reactor coolant flow, and SIAS. Reactor protection for the Steam System Piping Failures Inside and Outside of Containment event is summarized in Table 14.1.5.1-1.

14.1.5.1.4 Disposition and Justification

HFP initial conditions are limiting for the pre-scram SLB cases since this is the highest power condition.

The outside containment breaks do not cause harsh conditions inside containment, and therefore, do not cause the Low Reactor Coolant Flow trip to be degraded. If a loss of off site power were concurrent with an outside containment break, the primary coolant flow rate would coastdown similar to an LOCF event, without the Low Reactor Coolant Flow trip being degraded. The


outside containment break case with loss of off site power is therefore bounded by the LOCF event.

The inside containment breaks do cause harsh conditions inside containment, and therefore, an increased allowance for instrument uncertainty was applied for the Low Reactor Coolant Flow trip. Therefore, only the inside containment breaks will be analyzed with a loss of off site power.

The following pre-scram HFP Steam Line Break cases were analyzed for a range of MTCs (up to the most negative core operating limits report limit) and for break sizes ranging up to a double-ended guillotine break in a main steam line. The effects of power decalibration and harsh containment conditions (where applicable) were included in the analysis:

1. Breaks outside containment and downstream of the check valves (symmetric cases)

2. Breaks outside containment and upstream of a check valve (asymmetric cases)

3. Breaks inside containment with RCPs on (asymmetric cases)

4. Breaks inside containment with RCPs off (asymmetric cases)

The event is analyzed to support a range of MTCs up to the most negative core operating limits report limit. This event must be analyzed both with and without a coincident loss of off site power.

The single failure assumed in this analysis is the loss of one channel of Nuclear Instrumentation (NI) which provides power indication to the RPS. If one channel is out of service, the three remaining NI safety channels will be in a 2-out-of-3 coincidence mode. With the assumption of a failure in one of these channels, both of the remaining channels are required for a trip, relying on the lowest power indication for the safety function.

The disposition of events for the Steam System Piping Failures Inside and Outside of Containment event is summarized in Table 14.1.5.1-2.

14.1.5.1.5 Definition of Events Analyzed

The pre-scram SLB event is initiated by a rupture in the main steam piping. The break location is downstream of the steam generator integral flow restrictor and either:

1. outside containment and upstream of the main steam line check valves (asymmetric break), or

2. outside containment and downstream of the main steam line check valves (symmetric break), or


3. inside containment and upstream of the main steam check valves (asymmetric break).

Steam released through a break located downstream of the main steam line check valves flows to the break from both steam generators and, therefore, results in a symmetric transient. However, steam released through a break located upstream of one of the check valves flows to the break from the upstream steam generator only (because the check valve precludes backflow to the break from the other steam generator) and, therefore, results in an asymmetric transient.

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

Harsh containment conditions can be caused by the release of steam within the reactor containment. Under such conditions, only those trips which have been qualified for harsh environments are credited, and increased uncertainties are included in the setpoints of all environmentally qualified trips which are credited.

As outlined in Reference 14.1-1, three computerized calculations are required prior to the final calculation of the Minimum Departure From Nucleate Boiling Ratio (MDNBR) values and the maximum Linear Heat Generation Rate (LHGR) values utilized in the determination of fuel failure. The NSSS response of the pre-scram SLB with AC power available is computed using the AREVA S-RELAP5 code (Reference 14.1-1), the detailed core and hot assembly power distributions are calculated using the PRISM code (Reference 14.1-3), and the detailed core and hot assembly flow and enthalpy distributions are calculated using the XCOBRA-IIIC code (Reference 14.1-4). The HTP correlation (Reference 14.1-5) was utilized to calculate MDNBR. The previous pre-scram SLB case with the concurrent loss of off site power analyzed using the ANF RELAP (Reference 14.1-2) code was determined to remain bounding. The results of this case are described in Section 14.1.5.1.6.2.

14.1.5.1.5.1 Analysis of Results

The S-RELAP5 analysis provides the NSSS boundary conditions for the PRISM and the XCOBRA-IIIC calculations. This section presents a description of the treatment of factors which can have a significant impact on NSSS response and resultant MDNBR and LHGR values. The plant specific parameters used in this analysis are listed in Tables 14.1.5.1-3 to 14.1.5.1-5. Conservatisms are included in parameters or factors known to have significant effects on the NSSS performance and resulting MDNBR and LHGR values.


14.1.5.1.5.1.1 Break Location, Size, and Flow Model

The pre-scram SLB event analyzes breaks outside containment both downstream (symmetric cases) and upstream (asymmetric cases) of the main steam line check valves and breaks inside containment (asymmetric cases). A full range of break sizes, up to the double-ended guillotine break of a main steam line, were considered.

The S-RELAP5 break mass flow rate is computed using the Moody critical flow model modified such that only steam flows out the break.

14.1.5.1.5.1.2 Power Decalibration

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

14.1.5.1.5.1.3 Harsh Containment Conditions

Harsh containment conditions can be caused by the release of steam within the reactor containment. Under such conditions, only those trips which have been qualified for harsh environments are credited, and increased uncertainties are included in the setpoints of all environmentally qualified trips which are credited.

14.1.5.1.5.1.4 Boron Injection

Boron injection into the primary system acts to mitigate the return to power. Injection of boron is modeled from the HPSI system. The HPSI system is conservatively modeled to take suction from the Refueling Water Storage Tank (RWST) at 35°F with a boron concentration of 1720 ppm. Initially, the line volume between the check valves isolating the system pumps and the cold leg injection location is assumed to be filled with unborated water. The time required to flush this unborated water from the safety injection lines is included as an integral part of the S-RELAP5 NSSS calculation. In the pre-scram SLB event, the analysis is terminated shortly after reactor trip, therefore injection of borated water is not a factor in the analysis.

14.1.5.1.5.1.5 Single Failure Assumption

In order to simulate the asymmetric thermal-hydraulic and reactivity feedback effects that occur during the pre-scram SLB event, the core is divided into an affected sector (one-half of the core) and an unaffected sector (one-half of the core). The single failure assumed in this analysis is the loss of one channel of Nuclear Instrumentation (NI) which provides power indication to the


Reactor Protection System (RPS). If one channel is out of service, the three remaining NI safety channels will be in a 2-out-of-3 coincidence mode to cause a reactor trip. The excore detectors are placed around the reactor vessel in positions that result in one detector seeing the flux only from the affected region, one seeing the flux only from the unaffected region, and two detectors seeing nearly equal flux from both regions. If one of these latter two is out of service, and the other is assumed to be a single failure, the remaining two channels will be required to cause an RPS trip (high power or TM/LP). Since the power in the affected region will always be higher than in the unaffected region, it is sufficient to model the NI channel reading the unaffected region only.

14.1.5.1.5.1.6 Feedwater

For breaks smaller than 0.4 square feet, the Main Feed Water (MFW) control valves are assumed to modulate to match MFW flow to steam flow. For larger breaks, the MFW valves are conservatively assumed to open fully at the initiation of the event and remain open. The MFW pumps are assumed to be operating at rated speed. The MFW flow increases as the secondary pressure decreases at the lowest possible fluid temperature until the feedwater regulator valve closes. Fluid temperature is determined by assuming heating of the feedwater ceases at the same time the break is initiated. The MFW flow is terminated 14 seconds after receiving the isolation signal.

14.1.5.1.5.1.7 Trips and Delays

Actuation signals and delays are given in Table 14.1.5.1-4. Biases to account for uncertainties are included in the trip setpoints as shown. In the pre-scram SLB event, the analysis is terminated shortly after reactor trip, therefore injection of borated water is not a factor in the analysis.

14.1.5.1.5.1.8 Neutronics

The core kinetics input for this calculation consisted of the minimum required control rod shutdown worth at EOC, and EOC values associated with the reactivity feedback curves, delayed neutron fraction, delayed neutron fraction distribution and related time constants, and prompt neutron generation time. The S-RELAP5 default fission product and actinide decay constants were utilized for this calculation.

The core reactivity is derived from input of several functions. These include effects from control rod worth, moderator density changes, boron concentration, and Doppler effects. The reactivity is weighted between the core sectors. The S-RELAP5 analyses for cases with off site power available were performed with an MTC ranging from -8 pcm/°F to -32 pcm/°F. In all cases, the most limiting scenarios were those performed with an MTC of -32 pcm/°F. The analyses for cases with a loss of off site power were performed with an MTC of +4.0 pcm/°F. A summary of the nuclear input and assumptions is given in Table 14.1.5.1-5.

14.1.5.1.5.1.9 Decay Heat

The presence of radioisotope decay heat at the initiation of the SLB event will reduce the rate and the extent of cooldown of the primary system. The initial decay heat is calculated on the basis of


infinite irradiation time at a power of 2754 MW prior to transient initiation. This treatment of decay heat serves to maximize the stored energy and provide limiting stored energy conditions for the SLB cases.

14.1.5.1.5.1.10 Nodalization

The NSSS transient calculations presented in this report utilized the nodalization model described in Reference 14.1-1. The nodalization treats all major NSSS components and subcomponents as discrete elements, with the exception of the secondary side of the steam generators. In addition, all components with long axial dimensions are divided into subcells adequate to minimize numerical diffusion and smearing of gradients.

In order to simulate the asymmetric thermal-hydraulic and reactivity feedback effects that occur during the pre-scram SLB event, the core is divided into an affected sector (one-half of the core) and an unaffected sector (one-half of the core).

14.1.5.1.5.1.11 Interloop Mixing

During an actual SLB transient, some mixing between the parallel channels within the reactor pressure vessel will occur in the downcomer, the lower plenum, the core, and the upper plenum due to lateral momentum imbalances, and turbulence or eddy mixing. The mixing will act to reduce the positive reactivity feedback effects due to a reduced rate and magnitude of cooldown of the affected loop and associated core sector.

In this analysis, no credit is taken for turbulent or eddy mixing of coolant between loops or the parallel flow channels within the reactor pressure vessel. However, interloop mixing is calculated to occur due to flow in interloop junctions in the upper and lower plenums. Mixing in the lower plenum was effectively reduced to zero by using an extremely high loss coefficient between the affected and intact sectors.

14.1.5.1.5.2 Minimum Departure From Nucleate Boiling and Linear Heat Generation Rate Analysis

The PRISM (Reference 14.1-3) core neutronics code is used to calculate the core radial power distributions for XCOBRA-IIIC (Reference 14.1-4) during the asymmetric transients with off site power available only. The PRISM model is a three-dimensional representation of the entire core, with four radial nodes and 24 axial nodes for each fuel assembly.

Based on the overall core conditions calculated by S-RELAP5 for the symmetric cases (or S-RELAP5 and PRISM for the asymmetric cases with off site power available) at the peak heat flux time-point, the XCOBRA-IIIC fuel assembly thermal-hydraulic code is used to calculate the flow and enthalpy distributions for the entire core and the DNB performance for the DNB-limiting assembly. The XCOBRA-IIIC model consists of a thermal-hydraulic model of the core (representing each assembly by a single “channel”) linked to a detailed thermal-hydraulic model of the limiting assembly (representing each subchannel by a single “channel”). The limiting assembly DNBR calculations are performed using the HTP DNB correlation (Reference 14.1-5).


For the asymmetric transients, the radial power peaking is augmented above the Technical Specification limit to account for the increase in radial power peaking which occurs during the transient. The increase in peaking is determined by PRISM.

14.1.5.1.6 Analysis Results

A summary of the calculated peak reactor power is presented in Table 14.1.5.1-6 for the limiting MDNBR and LHGR cases. The MDNBR values for the limiting cases are also in this Table. For cases where off site power was available for operation of the primary coolant system pumps, the MDNBR and the maximum LHGR occurred at the time of the maximum power condition. For cases where off site power is lost and the primary system pumps coast down, the maximum LHGR and the MDNBR occur when the worst combination of core power, flow, inlet temperature, and pressure are present.

The scenario which resulted in the highest power level and the largest LHGR is the HFP 0.20 ft2 asymmetric break inside containment with off site power available for operation of the primary coolant pumps. This case is presented in detail.

The scenario which resulted in the limiting MDNBR is the HFP case with a loss of off site power and is also presented in detail.

14.1.5.1.6.1 Hot Full Power 0.20 ft2 Break Inside Containment Upstream of a Check Valve with Off site Power Available

The S-RELAP5 simulation of the NSSS during the HFP asymmetric break transient with off site power available is illustrated in Figures 14.1.5.1–1 through 14.1.5.1–6. A tabulation of the sequence of events is presented in Table 14.1.5.1-7. The S-RELAP5 computation was terminated well beyond the time of MDNBR or peak LHGR. The general response of the reactor was the same for all the asymmetric break sizes but the sequence of events was quicker as the break size increased.

14.1.5.1.6.1.1 Secondary System Parameters

Upon break initiation the break flow increased sharply and then began to decline in response to falling secondary side pressure. When the turbine trip occurred, the break flow increased due to a local pressure increase. The main steam line flow rate from each generator initially increased (see Figure 14.1.5.1–6) in response to the break and the assumed instantaneous full opening of the turbine control valves. The increased steam flow creates a mismatch between the core heat generation rate and the steam generator heat removal rate. This power mismatch causes the primary-to-secondary heat transfer rate to increase, which in turn causes the primary system to cool down (see Figure 14.1.5.1–2). When the reactor scram occurred, the turbine valves closed and steam flow declined sharply.


14.1.5.1.6.1.2 Primary System Parameters

Approximately five seconds after the break occurred, the core inlet temperature began to decline. With a negative MTC (see Figure 14.1.5.1–3), the primary system cooldown caused the reactor power level to increase. The core power continues to increase until reactor scram on high containment pressure occurs. This terminated the power excursion. The pressurizer pressure and level began to decline as the volume of water in the primary system shrank. The core inlet mass flow rate increased due to the increasing density of the primary system fluid while the reactor coolant pumps’ speed remained constant.

14.1.5.1.6.1.3 Departure From Nucleate Boiling Ratio and Linear Heat Generation Rate Results

The MDNBR value for this scenario was calculated and compared to the 95/95 HTP correlation limit. The amount of failed fuel is determined by comparing the core power distribution to the power at which DNB occurs. The scenario results in no more than a predicted failure of 3.7% of the fuel rods in the core.

The peak LHR for the LHR-limiting case (0.20 ft2 break inside containment and upstream of a check valve) is calculated to be less than the FCMLHR limit. Therefore, it is apparent that centerline melt is not predicted to occur. Thus, no fuel failures are predicted to occur due to violation of the centerline melt criteria.

14.1.5.1.6.2 Hot Full Power 3.51 ft2 Inside Containment Asymmetric Break Concurrent with a Loss of Off site Power

The ANF-RELAP NSSS simulation of the most limiting pre-scram SLB scenario from an

MDNBR standpoint (i.e., HFP 3.51 ft2 inside containment asymmetric break concurrent with a loss of off site power) is illustrated in Figures 14.1.5.1–7 through 14.1.5.1–11. A tabulation of the sequence of events is presented in Table 14.1.5.1-8. The ANF-RELAP computation was terminated 60 seconds after break initiation. This is well beyond the time of MDNBR or peak LHGR.

The transient is initiated by the opening of the break. The RCPs tripped shortly after transient initiation. The sharp reduction in the reactor coolant flow causes this pre-trip pumps off calculation to become a heat up transient very similar to a Loss of Coolant Flow event. Typically, the Steam Line Break calculation is a cooldown event. Because this case is a heat up event the most positive BOC neutronics conditions are used, and the maximum inside containment asymmetric break size is used. The maximum break size causes the biggest decrease in primary pressure. Maximizing the primary system pressure decrease causes the maximum decrease in moderator density and the maximum positive moderator feedback. The RCP trip causes the RCS flow to decrease rapidly throughout this transient. The decreasing RCS flow causes the transient time of the fluid in the core to increase and the fluid temperature begins to rise. The increasing fluid temperature causes positive moderator feedback, which in turn causes an increase in core power. However, the decreasing RCS flow causes the heat transfer to the fluid to decrease. The increase in core power is offset by the decrease in heat transfer from the fuel rods, such that, the


fuel rod heat flux decreases slightly until reactor scram. The reactor scrams on the low reactor coolant flow trip signal.


The MDNBR value for the pre-scram 3.51 ft2 asymmetric break inside containment with a loss of off site power was calculated to be below the 95/95 HTP correlation limit. The number of failed assemblies is determined by comparing the core power distribution to the assembly power where DNB occurs. This results in a predicted failure of 3.7% of the fuel rods in the core.

The peak LHR for this case is bounded by the 0.20 ft2 inside containment asymmetric break. Therefore, the LHGR for this case is below the FCMLHR limit and no fuel failures are predicted to occur due to violation of the centerline melt criteria.

14.1.5.1.7 Conclusions

The HFP 0.20 ft2 break inside containment and upstream of a check valve (asymmetric break) with off site power available was determined to be the most limiting in this analysis from an LHGR standpoint. In no scenario evaluated, however, was fuel failure calculated to occur as a result of violating the FCMLHR limit.

Both the HFP 0.20 ft2 asymmetric break inside containment with off site power available and the

HFP 3.51 ft2 asymmetric break inside containment coincident with a loss of off site power were determined to be the most limiting in this analysis from the standpoint of MDNBR. Predicted fuel failures due to MDNBR are limited to no more than 3.7% of the fuel rods in the core. However, for any outside containment main steam line break scenario, no fuel failure due to violation of the DNBR limit was predicted to occur.

14.1.5.2 Post-Scram Analysis


This event is initiated by a rupture in the main steam piping downstream of the integral steam generator flow restrictors and upstream of the MSIVs which results in an uncontrolled steam release from the secondary system.


The increase in energy removal through the secondary system results in a severe overcooling of the primary system. In the presence of a negative MTC, this cooldown causes a decrease in the shutdown margin (following reactor scram) such that a return to power might be possible following a steam line rupture. This is a potential problem because of the high power peaking factors which exist, assuming the most reactive control rod to be stuck in its fully withdrawn position.



Reactor protection is provided by the low steam generator pressure and water level trips, LPD trip, TM/LP trip, high containment pressure trip, and SIAS. Reactor protection for the Steam System Piping Failures Inside and Outside of Containment event is summarized in Table 14.1.5.2-1.


At rated power conditions, the stored energy in the primary coolant is maximized, the available thermal margin is minimized, and the pre-trip power level is maximized. These conditions result in the greatest potential for cooldown and provide the greatest challenge to the SAFDLS. Initiating this event from rated power also results in the highest post-trip power since it maximizes the concentration of delayed neutrons providing for the greatest power rise for a given positive reactivity insertion. Thus, this event initiated from rated power conditions will bound all other cases initiated from at power operation modes.

For the zero power and subcritical plant states (Modes 2-6), there is a potential for a return to power at reduced pressure conditions. The most limiting steam line break (SLB) event at zero power is one which is initiated at the highest temperature, thereby providing the greatest capacity for cooldown. This occurs in Modes 2 and 3. Thus, the event initiated from Modes 2 and 3 will bound those initiated from Modes 4-6. Further, the limiting initial conditions will occur when the core is just critical. These conditions will maximize the available positive reactivity and produce the quickest and largest return to power. Thus, the SLB initiated from critical conditions in Mode 2 will bound the results of the event initiated form subcritical Mode 3 conditions.

The Technical Specifications only require a minimum of one RCP to be operating in Mode 3. One pump operation provides the limiting minimum initial core flow case. Minimizing core flow minimizes the clad to coolant heat transfer coefficient and degrades the ability to remove heat generated within the fuel pins. Conversely, however, a maximum loop flow will maximize the primary to secondary heat transfer coefficient, thus providing for the greatest cooldown. Higher loop flow will sweep the cooler fluid into the core faster, maximizing the rate of positive reactivity addition and the peak power level.

The worst combination of conditions is achieved for the four-pump loss of off site power case. In this situation, the initial loop flow is maximized resulting in the greatest initial cooldown, while the final loop flow is minimized providing the greatest challenge to the DNB SAFDL. Since the natural circulation flow which is established at the end of the transient will be the same regardless of whether one or four pumps were initially operating the results of the four-pump loss of off site power case will bound those of the one-pump case. Thus, only four-pump operation need be analyzed for the Mode 2 case.

The event is analyzed to support the Technical Specification EOC MTC limit. This event must be analyzed both with and without a coincident loss of off site power. Typically there are two single failures which are considered for the off site power available case. The first is failure of a High Pressure Safety Injection (HPSI) pump to start. The second is failure of an MSIV to close,


resulting in a continued uncontrolled cooldown. However, Millstone 2 has combination MSIV/swing disc check valves. A double valve failure would thus be required for steam from the intact steam generator to reach the break. This is not deemed credible. Thus, the single failure to be considered with off site power available is failure of a HPSI pump to start. For the loss-of-off site power case, the limiting single failure is the failure of a diesel generator to start. This is assumed to result in the loss of one HPSI pump. The disposition of events for the Steam System Piping Failures Inside and Outside of Containment event is summarized in Table 14.1.5.2-2.


The post-scram SLB is initiated by a rupture in the main steam piping downstream of the integral steam generator flow restrictors and upstream of the MSIVs which results in an uncontrolled steam release from the secondary system. The effects of harsh containment conditions (where applicable) are included in the following analyses:

1. HFP and HZP breaks outside containment with off site power available

2. HFP and HZP breaks outside containment with a loss of off site power

3. HFP and HZP breaks inside containment with off site power available

4. HFP and HZP breaks inside containment with a loss of off site power

The event is analyzed to support the Technical Specification EOC MTC limit. This event must be analyzed both with and without a coincident loss of off site power.

The single failure assumed in this analysis results in the disabling of one of the two HPSI pumps required to be in service during normal operation. In addition to the single failure, there is no credit taken for the charging pump system. This assumption results in an additional delay in the time required for boron to reach the core. The delay is amplified when combined with the assumption of a stagnant upper head which serves to maintain the primary system pressure due to flashing of the hot fluid in the upper head.

The increase in energy removal through the secondary system results in a severe overcooling of the primary system. In the presence of a negative MTC, this cooldown results in a large decrease in the shutdown margin and a return to power. This return to power is exacerbated because of the high power peaking factors which exist, with the most reactive control rod stuck in its full withdrawn position.

As outlined in Reference 14.1-1, three computerized calculations are required prior to the final calculation of the Minimum Departure From Nucleate Boiling Ratio (MDNBR) values and the maximum Linear Heat Generation Rate (LHGR) values utilized in the determination of fuel failure. The NSSS response is computed using the AREVA S-RELAP5 code (Reference 14.1-1), the detailed core and hot assembly power distributions and the reactivity at the time of peak post-scram power are calculated using the PRISM code (Reference 14.1-3), and the detailed core and hot assembly flow and enthalpy distributions are calculated using the XCOBRA-IIIC code


(Reference 14.1-4). The modified Barnett correlation was utilized to calculate MDNBR due to the reduced pressures occurring during the SLB event.

14.1.5.2.5.1 Analysis of Results

The S-RELAP5 analysis provides the NSSS boundary conditions for the PRISM and the XCOBRA-IIIC calculations. This section presents a description of the treatment of factors which can have a significant impact on NSSS response and resultant MDNBR and LHGR values. The plant specific parameters used in this analysis are listed in Tables 14.1.5.2-3 to 14.1.5.2-5. Conservatisms are included in parameters or factors known to have significant effects on the NSSS performance and resulting MDNBR and LHGR values.

14.1.5.2.5.1.1 Break Location, Size, and Flow Model

The post-scram SLB event is initiated by a double-ended guillotine break of a main steam line downstream of the integral steam generator flow restrictors and upstream of the MSIVs. The flow

is choked at the integral steam generator flow restrictor, which has an area of 3.51 ft2. On the steam generator side of the break, steam flows out of the break throughout the entire transient. On the MSIV side of the break, break flow terminates after the MSIVs are fully closed. As an added conservatism, the main steam check valves are not credited in the analysis. The event occurs concurrent with the most reactive control rod stuck out of the core. The break flow areas for the affected and intact steam generators are listed in Table 14.1.5.2-3.

The S-RELAP5 break mass flow rate is computed using the Moody critical flow model modified such that only steam flows out the break.

14.1.5.2.5.1.2 Boron Injection

Boron injection into the primary system acts to mitigate the return to power. Injection of boron is modeled from the HPSI system. The HPSI system is conservatively modeled to take suction from the Refueling Water Storage Tank (RWST) at 35°F with a boron concentration of 1720 ppm. Initially, the line volume between the check valves isolating the system pumps and the cold leg injection location is assumed to be filled with unborated water. The time required to flush this unborated water from the safety injection lines is included as an integral part of the S-RELAP5 NSSS calculation. The characteristics of the HPSI system are listed in Table 14.1.5.2-3. The delivery curve for the HPSI system used in this analysis is given in Figure 14.1.5.2–1.

14.1.5.2.5.1.3 Single Failure Assumption

The single failure assumed in the engineered safeguards system results in the disabling of one of the two HPSI pumps required to be in service during normal operation. In addition to the single failure, there is no credit taken for the charging pump system. This assumption results in an additional delay in the time required for boron to reach the reactor core. The delay is further amplified when combined with the assumption of a stagnant upper head which serves to maintain the primary system pressure due to flashing of the hot fluid in the upper head.


14.1.5.2.5.1.4 Feedwater

For the HFP scenarios, normal MFW flow is assumed to be delivered to both Steam Generators. The MFW flow increases as the secondary pressure decreases at the lowest possible fluid temperature until the feedwater regulating valve closes. Fluid temperature is determined by assuming heating of the feedwater ceases at the same time the break is initiated. The MFW flow is terminated 14 seconds after receiving the isolation signal. In addition, a sensitivity study was performed on the effect of MFW on the post-scram SLB results. The study concluded that the post-scram SLB results are insensitive to the MFW flow.

For the HFP scenarios, the AFW flow is assumed to be zero at break initiation. After 180 seconds, AFW is delivered at the maximum capacity of the AFW system with flow restrictors installed on the AFW delivery lines. For the HZP scenarios, the AFW flow is increased to the maximum capacity immediately at break initiation. For all HZP and HFP cases, the maximum AFW flow deliverable due to presence of cavitating venturis (660 gpm) is delivered to both the affected and unaffected steam generator. AFW flow to the steam generators is continued until S-RELAP5 computation was terminated 600 seconds after break initiation. By 600 seconds, core power is decreasing. After this point in time, the operators will terminate AFW flow to the affected steam generator, which will cause the primary system temperatures to increase, further decreasing the core power. The timing of the isolation of AFW to the affected steam generator is not a critical parameter.

14.1.5.2.5.1.5 Trips and Delays

Trips for the HPSI, main feedwater valves, and MSIVs are given in Table 14.1.5.2-4. Biases to account for uncertainties are included in the trip setpoints as shown. For the steam and feedwater valves, the delay times given are between the time the trip setpoint is reached and the time full valve closure is reached. For the HPSI system, the delay time given is from the time the setpoint is reached until the pumps have accelerated to rated speed. Additional delay time required to sweep the lines of unborated water is accounted for by setting the boron concentration of the injected flow to zero until the volume of the injection lines has been cleared.

14.1.5.2.5.1.6 Neutronics

The core kinetics input for this calculation consisted of the minimum required control rod shutdown worth at the EOC, and EOC values associated with the reactivity feedback curves, delayed neutron fraction, delayed neutron fraction distribution and related time constants, and prompt neutron generation time. The S-RELAP5 default fission product and actinide decay constants were utilized for this calculation.

The core reactivity is derived from input of several functions. These include effects from control rod worth, moderator density changes, boron concentration, and Doppler effects. The reactivity is weighted between the core sectors. Different reactivity functions were utilized where necessary for the HZP and the HFP cases. The HZP and HFP cases were performed with an MTC of -30 pcm/°F. A summary of the nuclear input and assumptions is given in Table 14.1.5.2-5.


14.1.5.2.5.1.7 Decay Heat

The presence of radioisotope decay heat at the initiation of the SLB event will reduce the rate and the extent of cooldown of the primary system. For the HFP scenarios, the initial decay heat is calculated on the basis of infinite irradiation time at a power of 2700 MW prior to transient initiation. For the HZP scenarios, the initial decay heat is calculated on the basis of infinite irradiation time at a power of 1 W prior to transient initiation. For both scenarios, decay heat generated from return to power is calculated. This treatment of decay heat serves to maximize the stored energy in the HFP cases and to minimize it in the HZP cases. This treatment provides limiting stored energy conditions for the SLB cases.

14.1.5.2.5.1.8 Nodalization

The NSSS transient calculations utilized the nodalization model described in Reference 14.1-1. The nodalization treats all major NSSS components and subcomponents as discrete elements, with the exception of the secondary side of the steam generators. In addition, all components with long axial dimensions are divided into subcells adequate to minimize numerical diffusion and smearing of gradients.

In order to simulate the asymmetric thermal hydraulic and reactivity feedback effects that occur during an SLB transient, the core is nodalized into three radial sectors. One sector corresponds to the region immediately surrounding the assembly where the most reactive control rod is assumed stuck out of the core. This sector is termed the 'stuck rod' sector. The remainder of the region of the core which is directly affected by the loop containing the break is the second sector and is termed the 'affected' sector. The remainder of the core and the other loop is termed either the 'unaffected' or the 'intact' sector or loop.

14.1.5.2.5.1.9 Interloop Mixing

During an actual SLB transient, some mixing between the parallel channels within the reactor pressure vessel will occur in the downcomer, the lower plenum, the core, and the upper plenum due to lateral momentum imbalances, and turbulence or eddy mixing. The mixing will act to reduce the positive reactivity feedback effects due to a reduced rate and magnitude of cooldown of the affected loop and associated core sector.

In this analysis, no credit is taken for turbulent or eddy mixing of coolant between loops or the parallel flow channels within the reactor pressure vessel (RPV). However, interloop mixing is calculated to occur due to flow in interloop junctions in the upper and lower plenums. Mixing in the lower plenum was reduced to a minimum by using an extremely high loss coefficient between the affected and intact sectors.

14.1.5.2.5.1.10 Harsh Containment Conditions

Harsh containment conditions can be caused by the release of steam within the reactor containment. Under such conditions, only those trips which have been qualified for harsh


environments are credited, and increased uncertainties are included in the setpoints of all environmentally qualified trips which are credited.

14.1.5.2.5.2 Minimum Departure From Nucleate Boiling and Linear Heat Generation Rate Analysis

MDNBR calculations require determination of the power, enthalpy, and flow distributions within the highest power assembly of the stuck rod core sector. Similarly, determination of the maximum LHGR also requires characterization of the power distribution. The power distribution within the core, including the highest powered assembly within the stuck rod core sector, is calculated with PRISM (Reference 14.1-3). Flow and enthalpy distributions within the core, including the highest powered assembly within the stuck rod core sector, are calculated with XCOBRA-IIIC (Reference 14.1-4). In order to obtain compatible flows, moderator densities, and powers within the high power assemblies, iteration between PRISM and XCOBRA-IIIC is conducted.

For this calculation, the modified Barnett correlation was found to be suitable for the MDNBR calculation. The modified Barnett correlation is based upon closed channels and primarily uniform power distribution data. The correlation is based on assembly inlet (or upstream) fluid conditions rather than on local fluid conditions as is the case with subchannel based correlations.


A summary of calculated results important to this analysis is presented in Table 14.1.5.2-6 for the limiting MDNBR and LHGR scenarios. The MDNBR values are listed together with the corresponding core power values at the time of MDNBR which corresponds to the maximum post-scram power level. The outside containment cases, regardless of whether or not off site power was or was not available, were found to be the most limiting. For cases where off site power was available for operation of the primary coolant system pumps, the MDNBR and the maximum LHGR occurred at the time of the maximum power condition. For cases where off site power is lost and the primary system pumps coast down, the maximum LHGR and the MDNBR occur when the worst combination of core power, flow, inlet temperature, and pressure are present. These conditions occurred at the time of peak power in this analysis.

The scenario which resulted in the highest post-scram power level and the largest LHGR is that initiated from HZP with the break occurring outside containment and with off site power available for operation of the primary coolant pumps. This case is presented in detail.

The NSSS responses for the scenarios with loss of off site power for operation of the primary system coolant pumps are different from those scenarios where off site power is available throughout the transient due to the pump coastdown and subsequent natural circulation of the primary coolant. Post-scram maximum power levels attained during the transient are significantly lower. Lower power levels result from lower positive moderator feedback. The positive moderator feedback is reduced due to the coolant density reductions that occur axially upwards in the core at low core flow rates, even for low core power levels. Lower power levels cause MDNBR values to increase, but lowering flow rates cause MDNBR values to decrease. Overall,


the combination of factors results in lower MDNBR values for the reduced flow condition than for the full flow condition.

Of the two loss-of-off site-power scenarios analyzed, the HZP break occurring outside containment case resulted in lower MDNBR values. The general response of the HFP and HZP cases with loss of off site power is comparable. Because the two scenarios are quite similar in terms of their general response, only the limiting MDNBR case (i.e., HZP break outside containment and without off site power) is presented in detail.

14.1.5.2.6.1 Hot Zero Power Outside Containment with Off site Power Available

The S-RELAP5 simulation of the NSSS during the HZP transient with off site power available is illustrated in Figures 14.1.5.2–2 through 14.1.5.2–9. A tabulation of the sequence of events is presented in Table 14.1.5.2-7. The S-RELAP5 computation was terminated 600 seconds after break initiation. This is well beyond the time of MDNBR or peak LHGR.

14.1.5.2.6.1.1 Secondary System Thermal Hydraulic Parameters

Steam flow out the break is the source of the NSSS cooldown. Break flow for the steam generators is plotted in Figure 14.1.5.2–2. Secondary pressure for the steam generators is plotted in Figure 14.1.5.2–3. After break initiation, the pressure in the affected steam generator decreased immediately and then stabilized around 180 seconds. The mass inventory in the affected steam generator decreased rapidly for the first 100 seconds of the transient and slowly thereafter. The unaffected steam generator mass inventory increased following the initial drop once the MSIV closed due to the addition of AFW.

The intact steam generator blows down for a short period until the MSIVs completely close approximately 15 seconds after the break is initiated. The pressure recovers following MSIV closure. The unaffected steam generator pressure begins to decrease again as cold AFW fills the steam generator.

14.1.5.2.6.1.2 Primary System Thermal Hydraulic Parameters

The primary system coolant temperature and pressurizer pressure and level responses resulting from the break flow are illustrated in Figures 14.1.5.2–4 through 14.1.5.2–6. The primary system pressure decays rapidly as the coolant contracts due to cooldown and the pressurizer empties. The MSIVs close at 15 seconds, ending the blowdown of the intact steam generators and reducing the rate of energy removal from the primary fluid. The pressurizer emptied at approximately 40 seconds. After the rapid decrease in system pressure caused by the overcooling resulting from the break, the system pressure stabilized and followed the pressure established by the saturation temperature of the primary coolant in the upper head of the reactor vessel.

14.1.5.2.6.1.3 Reactivity and Core Power

The reactivity transient calculated by S-RELAP5 is illustrated in Figure 14.1.5.2–8. Initially, the core is assumed to be at zero power. All control rods, except the most reactive one, are assumed to


be inserted into the core following the reactor trip signal. The reactivity transient then proceeds. The total core reactivity, initially at 0.00$ decreased initially due to reactor scram worth, then steadily increased due to moderator and Doppler feedback associated with the primary system cooldown. The reactor was approaching a quasi steady-state with the Doppler and the moderator reactivities balancing the scram reactivity, when boron began entering the core, causing the power to decrease.

HPSI flow to the RCS began 41 seconds after break initiation and 25 seconds after the HPSI actuation signal. Twenty-five seconds was the assumed time for the HPSI pumps to reach rated speed.

Figure 14.1.5.2–9 shows the transient reactor power. The reactor power initially declined due to insertion of the control rods. The severe cooldown resulted in power increasing after 80 seconds. A maximum power level of 281 MW or ~10.5% of rated power occurred at 333 seconds.

14.1.5.2.6.1.4 PRISM and XCOBRA-IIIC Results

The PRISM calculation is made initially on the basis of S-RELAP5 input. Each assembly within the three channels is assumed to have a uniform flow corresponding to the sector flows calculated with S-RELAP5. Due to high power peaking in the region of the stuck control rod, large moderator density reductions are calculated to occur in the top portions of several assemblies in this region of the core in the PRISM calculation and are responsible for the significant reduction in reactivity observed when PRISM is compared to S-RELAP5. An XCOBRA-IIIC analysis is also conducted to define the flow and enthalpy distribution within the high power assembly.

A comparison of the overall change in reactivity from the event initiation to the time of maximum LHGR between S-RELAP5 and PRISM shows the S-RELAP5 power calculation is conservative.


For the MDNBR portion of the calculation, the radial power distribution was modified to conservatively account for local rod power distribution effects within the hot assembly. This was done by raising the power of the hot assembly to bound the peak rod power.

On the bases of these conservative assumptions, the MDNBR value was calculated to be greater than the modified Barnett 95/95 DNBR correlation limit. Therefore, no fuel rods would be expected to fail during this transient scenario from an MDNBR stand point.

The analysis of the peak LHGR also comes from the PRISM and XCOBRA-IIIC analysis. The peak LHGR is calculated from the S-RELAP5 total core power and the PRISM radial and axial peaking. The peak LHGR was calculated to be less than the FCMLHR limit for the HZP outside containment break with off site power available event. As such, no fuel pins are predicted to fail due to the violation of the FCMLHR limit.


14.1.5.2.6.2 Hot Zero Power Outside Containment with Loss of Off Site Power

The S-RELAP5 NSSS simulation of the most limiting SLB scenario from an MDNBR standpoint (i.e., HZP outside containment break with a loss of off site power) is illustrated in Figures 14.1.5.2–10 through 14.1.5.2–16. A tabulation of the sequence of events is presented in Table 14.1.5.2-8. Termination of the AFW by manual operator action was assumed to occur 600 seconds after initiation of the break. The S-RELAP5 computation was terminated 600 seconds after break initiation. This is well beyond the time of MDNBR and maximum LHGR.

14.1.5.2.6.2.1 Secondary System Thermal Hydraulic Parameters

Steam flow out the break is the source of the NSSS cooldown. Steam flow for the affected steam generator is plotted in Figure 14.1.5.2–10. Secondary pressure for the steam generators is plotted in Figure 14.1.5.2–11. The affected steam generator blows down through the break throughout the transient. The pressure and mass flow rate dropped rapidly at first and then proceeded downward at a slower decay rate until natural circulation flow was established by approximately 250 seconds.

The intact steam generators blow down for a short period until the MSIVs completely close approximately 14 seconds after the break is initiated. The pressure recovers as the intact steam generator equilibrates with the primary system. Subsequently, the intact steam generator pressure steadily decreases as cold AFW fills the steam generator.

14.1.5.2.6.2.2 Primary System Thermal Hydraulic Parameters

The primary system core coolant temperature and pressurizer pressure and level responses resulting from the break flow are illustrated in Figures 14.1.5.2–12 through 14.1.5.2–14. The primary system pressure decays rapidly as the coolant contracts due to the cooldown and the pressurizer empties. Continued pressure reduction in the primary system causes the relatively hot stagnant liquid in the head of the RPV vessel to flash. The flashing in the upper head, coupled with near equilibration of other NSSS parameters, retards the pressure decay from that point forward.

A comparison of intact and affected core sector inlet temperatures throughout the transient indicates significant differences due to the limited cross flow allowed between loops. The core sector flows all show the same trend due to the coastdown of the primary coolant pumps. That is, all flows decrease rapidly until natural circulation conditions are achieved in the two flow loops.

14.1.5.2.6.2.3 Reactivity and Core Power

The reactivity transient calculated by S-RELAP5 is illustrated in Figure 14.1.5.2–15. Initially, the core is assumed to be at zero power. The total core reactivity, initially at 0.00$ decreased initially due to reactor scram worth, then steadily increased due to moderator and Doppler feedback associated with the primary system cooldown. The rise in reactor power was arrested when boron began entering the core at 332 seconds. Power then declined slowly due to an increasing boron concentration in the primary system.


The HPSI actuation signal was received at 21 seconds. After a 25 second delay, during which the HPSI pumps reached rated speed, HPSI flow to the RCS began, at 46 seconds.

The transient experienced by the core power is illustrated in Figure 14.1.5.2–16. The core power, initially at 1 Watt, increased rapidly at 120 seconds and reached a peak power level of 5.9% of rated power (159 MW) at 352 seconds.

14.1.5.2.6.2.4 PRISM and XCOBRA-IIIC Results

The PRISM calculation is initially made on the basis of S-RELAP5 predicted core power, flow, pressure, and inlet temperatures. The PRISM calculations provide the radial and axial power distributions for use in the XCOBRA-IIIC code. Due to the high power peaking in the region of the stuck control rod, and the low core average natural circulation flow rates, large moderator density decreases are calculated in several assemblies in this region in the PRISM calculation and are responsible for the significant reduction in reactivity observed when PRISM is compared to S-RELAP5. An XCOBRA-IIIC analysis is also conducted to define the flow and enthalpy distribution within the high power assembly.

A comparison of the overall change in reactivity from the event initiation to the time of minimum DNBR between S-RELAP5 and PRISM shows the S-RELAP5 power calculation is conservative.


The MDNBR of the hot fuel assembly is calculated to be greater than the modified Barnett 95/95 DNBR correlation limit. Therefore, no fuel rods are expected to fail from an MDNBR standpoint.

As before, the analysis of the peak LHGR comes from the PRISM and the XCOBRA-IIIC analysis. The peak LHGR was less than the FCMLHR limit. Therefore, it is apparent that centerline melt is not predicted to occur. Thus, no fuel failures are predicted to occur due to violation of the centerline melt criteria.


The HFP and HZP scenarios, with off site power maintained for operation of the primary coolant pumps, resulted in a return to higher power levels than the scenarios where off site power is lost. However, these scenarios provide substantially greater margin to the MDNBR limit because of the higher coolant flow rate. In no scenario evaluated, however, was fuel failure calculated to occur as a result of penetration of the MDNBR safety limit. Even though the scenarios with off site power available have substantially greater margin to the MDNBR limit because of a higher coolant flow rate, the higher power levels in combination with the highly skewed power distribution due to the assumed stuck rod cluster resulted in them having the least margin to the fuel centerline melt limit.

The HZP outside containment break scenario concurrent with a loss of off site power was determined to be the most limiting in this analysis from an MDNBR standpoint. The MDNBR of


the hot fuel assembly is calculated to be above the modified Barnett 95/95 DNBR correlation limit. Therefore, no fuel rods are expected to fail from an MDNBR standpoint.

The HZP outside containment break scenario with off site power available was determined to be the most limiting in this analysis from the standpoint of centerline melt. This scenario results in the highest return to power and highest calculated LHGR. No fuel pins are calculated to fail due to the violation of the FCMLHR limit.

14.1.5.3 Radiological Consequences of a Main Steam Line Break

The main steam line break is postulated to occur in a main steam line outside the containment. The radiological consequences of a main steam line break inside containment is bounded by the main steam line break outside containment. The plant is assumed to be operating with Technical Specification coolant concentrations. A 150 gpd primary to secondary leak is assumed to occur in each steam generator.

The main steam line break (MSLB) accident begins with a break in one of the main steam lines leading from a steam generator (affected generator) to the turbine coincident with a loss of off site power. As a result, the condenser is unavailable and cool down of the primary system is through the release of steam to the environment from the intact generator. In order to maximize doses, break scenarios are assessed in the following structures: 1) Turbine Building, 2) Containment and 3) Enclosure Building. The analysis for the MSLB in Containment assumes 3.7% fuel failure. The analyses for the MSLB in the Turbine Building and Enclosure Building assume no fuel failure but address the pre-accident (60μCi/gm Dose Equivalent (DEQ) I-131) and concurrent iodine (500 times the iodine appearance rates at 1μCi/gm DEQ I-131) spike scenarios as well as Technical Specification levels of activity consistent with Dose Equivalent I-131 and Xe-133 limits.

An operator action is credited in the event of MSLB in the Enclosure or Turbine Building. There is insufficient radioactivity in the release to alarm control room radiation monitors with subsequent isolation of the control room. This action requires an operator to isolate the control room within 4 hours of MSLB and align Control Room Emergency Ventilation for filtered recirculation within an additional 1 hour.

The noble gases and iodines in the primary coolant that leak into the faulted steam generator during the transient are released directly to the environment without holdup or decontamination except for MSLB in containment. For the MSLB in containment, releases from the faulted steam generator are released to the environment at Technical Specification containment leak rates. An iodine partition factor of 0.01 is used for the releases from the unaffected steam generator. Off-site power is assumed to be lost, thus making the condenser unavailable. The steam releases from the main steam line break are from the turbine building blowout panels as the atmospheric dispersion factor is greater for this release point than the enclosure building blowout panels. The steam releases from the intact steam generator are from the MSSVs/ADVs.

The radiological consequences of a main steam line break to the EAB, LPZ and Millstone 2 Control Room are reported in Table 14.1.5.3-2. The assumptions used to perform this evaluation are summarized in Table 14.1.5.3-1.


The resulting doses to the EAB, LPZ and Control Room do not exceed the guidelines provided in 10 CFR 50.67 and Regulatory Guide 1.183.

14.1.6 REFERENCES

14.1-1 “SRP Chapter 15 Non-LOCA Methodology for Pressurized Water Reactors,” EMF-2310(P)(A), Revision 1, Framatome-ANP, May 2004.

14.1-2 “ANF-RELAP Methodology for Pressurized Water Reactors: Analysis of Non-LOCA Chapter 15 Events,” ANF-89-151(P)(A), Advanced Nuclear Fuels Corporation, May 1992.

14.1-3 “Reactor Analysis Systems for PWRs, Volume 1 - Methodology Description, Volume 2 - Benchmarking Results,” EMF-96-029(P)(A), Siemens Power Corporation, January 1997.

14.1-4 “XCOBRA-IIIC: A Computer Code to Determine the Distribution of Coolant During Steady-State and Transient Core Operation,” XN-NF-75-21(A), Revision 2, Exxon Nuclear Company, January 1986.



TABLE 14.1.1-1 AVAILABLE REACTOR PROTECTION FOR THE DECREASE IN FEEDWATER TEMPERATURE EVENT

Reactor Operational Modes Reactor Protection

1 Variable Overpower Trip Thermal Margin/Low Pressure Trip Local Power Density Trip Low Steam Generator Pressure Trip

2 Variable Overpower Trip Low Steam Generator Pressure Trip

3 Variable Overpower Trip

4-6 Not a credible event for these reactor operating conditions since there is no extraction steam to the feedwater heaters


TABLE 14.1.1-2 DISPOSITION OF EVENTS FOR THE DECREASE IN FEEDWATER TEMPERATURE EVENT

Reactor Operational Modes Disposition

1 Bounded by Event 14.1.3, Increase in Steam Flow Event

2, 3 Bounded by the above

4-6 No analysis required; not a credible event


* Additional protection is provided by this control-grade reactor trip.

** Provides defense in depth.

TABLE 14.1.2-1 AVAILABLE REACTOR PROTECTION FOR THE INCREASE IN FEEDWATER FLOW EVENT


1 Variable Overpower Trip Local Power Density Trip Thermal Margin/Low Pressure Trip Low Steam Generator Pressure Trip Safety Injection Actuation Signal Reactor Trip on Turbine Trip due to High Steam Generator

Water Level *

2 Low Steam Generator Pressure Trip Variable Overpower Trip Safety Injection Actuation Signal

3 Variable Overpower Trip Safety Injection Actuation Signal

4 Technical Specification Requirements on Shutdown Margin Inherent Negative Doppler Feedback **

5, 6 No analysis required; no significant consequences


TABLE 14.1.2-2 DISPOSITION OF EVENTS FOR THE INCREASE IN FEEDWATER FLOW EVENT


1 Bounded by Event 14.1.3 (Increase in Steam Flow)

2 Bounded by the Mode 3 Case

3-6 Bounded by Event 14.1.3


* Provides defense in depth.

TABLE 14.1.3-1 AVAILABLE REACTOR PROTECTION FOR THE INCREASE IN STEAM FLOW EVENT


1 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Thermal Margin/Low Pressure Trip Local Power Density Trip Variable Overpower Trip Safety Injection Actuation Signal

2 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Variable Overpower Trip Safety Injection Actuation Signal

3 Variable Overpower Trip Safety Injection Actuation Signal

4 Technical Specification Requirements on Shutdown Margin Inherent Negative Doppler Feedback

5, 6 No Analysis Required; No Significant Consequences


TABLE 14.1.3-2 DISPOSITION OF EVENTS FOR THE INCREASE IN STEAM FLOW EVENT


1 Analyze

2, 3, 4 Bounded by the above

5, 6 No analysis required; no significant consequences


TABLE 14.1.3-3 INITIAL CONDITIONS FOR THE INCREASE IN STEAM FLOW EVENT

Parameter Initial Value

Reactor power 2754 MWt (102% of rated)

Cold leg temperature 549°F

Total RCS flow rate 360,000 gpm

Pressurizer pressure 2250 psia

Pressurizer level 65% of span

Steam generator pressure 875 psia

Steam generator fluid mass (feedwater and steam) 167,237 lbm per steam generator


TABLE 14.1.3-4 EVENT SUMMARY FOR THE INCREASE IN STEAM FLOW EVENT

EventTime

(seconds)

Steam dump to condenser valves and turbine bypass valves open fully 0.0

Turbine control valves open fully 0.0

Indicated thermal power reaches Variable Overpower trip ceiling (111.7%) 22.1

Turbine trips on reactor scram signal 23.0

Reactor power reaches maximum value 23.5

Scram CEA insertion begins 23.5

MDNBR occurs 23.7


TABLE 14.1.3-5 PEAK REACTOR POWER LEVELS FOR INCREASE IN STEAM FLOW EVENT

Case Amount of Steam ReleasePeak Reactor Power

(% of Rated)

Turbine control valves fully open ~11% excess 117.8%

Intermediate case ~20% excess 117.8%

Steam dump to condenser valves, turbine bypass valves, and turbine control valves fully open

~41% excess 117.7%


FIGURE 14.1.3–1 NORMALIZED POWER AND HEAT FLUX FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–2 REACTIVITY FEEDBACK FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–3 REACTOR COOLANT TEMPERATURES FOR INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–4 CORE INLET MASS FLOW RATE FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–5 PRESSURIZER PRESSURE FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–6 STEAM GENERATOR PRESSURES FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–7 STEAM MASS FLOW RATES FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–8 MAIN FEEDWATER FLOW FOR THE INCREASE IN STEAM FLOW EVENT


FIGURE 14.1.3–9 MAIN FEEDWATER TEMPERATURE FOR THE INCREASE IN STEAM FLOW EVENT


* Provides defense in depth.

TABLE 14.1.4-1 AVAILABLE REACTOR PROTECTION FOR THE INADVERTENT OPENING OF A STEAM GENERATOR RELIEF OR SAFETY VALVES


1 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Variable Overpower Trip Local Power Density Trip Thermal Margin/Low Pressure Trip Safety Injection Actuation Signal

2 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Variable Overpower Trip Safety Injection Actuation Signal

3, 4 Technical Specification Requirements on Shutdown

Margin, Inherent Negative Doppler Feedback *

5, 6 No Analysis Required; Not a Credible Event


TABLE 14.1.4-2 DISPOSITION OF EVENTS FOR THE INADVERTENT OPENING OF A STEAM GENERATOR RELIEF OR SAFETY VALVE EVENT


1-4 Bounded by analyses presented for Event 14.1.3

5, 6 Not a credible event; no analysis required


TABLE 14.1.5.1-1 AVAILABLE REACTOR PROTECTION FOR STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT

PRE-SCRAM ANALYSIS

Reactor Operating Conditions Reactor Protection

1 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Low Reactor Coolant Flow Variable Overpower Trip Local Power Density Trip Thermal Margin/Low Pressure Trip High Containment Pressure Trip Safety Injection Actuation Signal

2 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Low Reactor Coolant Flow Variable Overpower Trip High Containment Pressure Trip Safety Injection Actuation Signal

3-6 Technical Specification Requirements on Shutdown Margin, Inherent Negative Doppler Feedback


TABLE 14.1.5.1-2 DISPOSITION OF EVENTS FOR STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE CONTAINMENT

PRE-SCRAM ANALYSIS

Reactor Operating Conditions Disposition

1 Analyze

2 Analyze

3-6 Bounded by the above


TABLE 14.1.5.1-3 S-RELAP5 THERMAL-HYDRAULIC INPUT (PRE-SCRAM STEAM LINE BREAK)

Initial Condition Thermal-Hydraulic Input HFP

Reactor Power (MW) 2754

Pressurizer Pressure (psia) 2250

Pressurizer Level (%) 65

Cold Leg Coolant Temperature (°F) 549

Total Primary Flow Rate (lbm/sec) 37,640

Secondary Pressure (psia) 876

Core Bypass Flow Rate (lbm/sec) per Loop 724

Main Feedwater Temperature (°F) 432

Steam Generator Mass Inventory (lbm) 167,237


TABLE 14.1.5.1-4 ACTUATION SIGNALS AND DELAYS (PRE-SCRAM STEAM LINE BREAK)

Reactor TripNon-Harsh Containment

Condition SetpointHarsh Containment Condition Setpoint Delay

Variable Overpower (ceiling) 111.6% of rated (NI power); 114% of rated (thermal power)

Not credited 0.9 s

Low Reactor Coolant Flow Credited 85% flow 0.65 s

High Containment Pressure Not applicable 5.83 psig 0.9 s

Low Steam Generator Pressure 658 psia 550 psia 0.9 s

TM/LP (floor) 1728 psia 1700 psia 0.9 s

TM/LP (function) Evaluated from function given in Technical Specification

Not credited 0.9 s


Fission Product and Actinide Decay Constants

Default values in ANF-RELAP utilized

*An MTC of -30 pcm/°F is used for the inside containment offsite power available cases.

TABLE 14.1.5.1-5 S-RELAP5 NEUTRONICS INPUT AND ASSUMPTIONS (PRE-SCRAM STEAM LINE BREAK)

Point Kinetics Input Value

Effective Delayed Neutron Fraction 0.005245

Moderator Temperature Coefficient (pcm/°F)

Off Site Power Available (Technical Specification most negative limit)

-8 to -32/-30*

Loss of Off Site Power (Technical Specification most positive limit above 70% RTP)

+4

HFP Scram Worth (pcm) 6425

Shutdown Margin Requirement (pcm) 3600

Doppler Coefficient

Off Site Power Available Nominal EOC

Loss of Off Site Power 0.80 x least negative value at BOC


* The peak LHRs for all pre-scram breaks are bounded by the peak LHR for the 0.20 ft2 break inside containment and upstream of a check valve.

** The MDNBRs for these pre-scram breaks are bounded by the MDNBR for the 3.51 ft2 break inside containment, upstream of a check valve with the loss of off site power.

** Inside containment, upstream of check valve offsite power available cases analyzed with

-30 pcm/°F except for 0.05 ft2 case analyzed with MTC of -32 pcm/°F.

TABLE 14.1.5.1-6 MDNBR AND PEAK REACTOR POWER LEVEL SUMMARY (PRE-SCRAM STEAM LINE BREAK)

Location of BreakType of

CooldownSize of Break MDNBR

Peak Reactor Power (% of rated)

Outside containment, downstream of check valves

Symmetric 3.25 ft2 ** 129.83%

3.50 ft2 ** 130.84%

3.75 ft2 ** 128.19%

Outside containment, upstream of check valve

Asymmetric 1.80 ft2 ** 124.62%

2.00 ft2 ** 126.05%

2.20 ft2 ** 126.94%

2.40 ft2 ** 122.46%

Inside containment, upstream of check valve

Asymmetric 0.05 ft2 ** 134.38%***

0.10 ft2 ** 135.22%

0.20 ft2 ** 137.68% *

0.40 ft2 ** 125.03%

Inside containment, upstream of check valve with loss of off site power

Asymmetric 3.51 ft2 0.88 106.86%


TABLE 14.1.5.1-7 LHGR-LIMITING PRE-SCRAM STEAM LINE BREAK SEQUENCE

OF EVENTS: HFP 0.20FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT WITH OFFSITE POWER AVAILABLE

Time (sec.) Event

0.0 Break upstream of main steam line check valves opens

0.0 Turbine control valves open fully

115.8 High containment pressure trip setpoint reached

117.0 Scram signal

117.0 Turbine trips on reactor scram signal

117.3 Reactor power reaches maximum value

117.3 MDNBR occurs


TABLE 14.1.5.1-8 MDNBR-LIMITING PRE-SCRAM STEAM LINE BREAK

SEQUENCE OF EVENTS: HFP 3.51FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER

Time (seconds) Event

0 Break occurs

0 RCPs trip

0 Peak LHGR (kW/ft)

2 Scram signal on low flow trip

3 Scram CEA Insertion begins

3 Maximum Power (Fraction of RTP)

4 MDNBR


FIGURE 14.1.5.1–1 NORMALIZED CORE POWER (0.20 FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT)


FIGURE 14.1.5.1–2 CORE INLET TEMPERATURES (0.20 FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT)


FIGURE 14.1.5.1–3 REACTIVITY FEEDBACK (0.20 FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT)


FIGURE 14.1.5.1–4 PRESSURIZER PRESSURE (0.20 FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT)


FIGURE 14.1.5.1–5 STEAM GENERATOR PRESSURES (0.20 FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT)


FIGURE 14.1.5.1–6 STEAM MASS FLOW RATES (0.20 FT2 ASYMMETRIC BREAK INSIDE CONTAINMENT)


FIGURE 14.1.5.1–7 NORMALIZED POWER AND HEAT FLUX (ASYMMETRIC

3.51 FT2 BREAK INSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.1–8 REACTOR COOLANT TEMPERATURES (ASYMMETRIC 3.51 FT2 BREAK INSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.1–9 NORMALIZED REACTOR COOLANT SYSTEM FLOW RATE

(ASYMMETRIC 3.51 FT2 BREAK INSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.1–10 PRESSURIZER PRESSURE (ASYMMETRIC 3.51 FT2 BREAK INSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.1–11 STEAM GENERATOR PRESSURES (ASYMMETRIC 3.51 FT2 BREAK INSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER)


TABLE 14.1.5.2-1 AVAILABLE REACTOR PROTECTION FOR STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT, POST-SCRAM

ANALYSIS


1 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip Local Power Density Trip Thermal Margin/Low Pressure Trip High Containment Pressure Trip Safety Injection Actuation Signal

2 Low Steam Generator Pressure Trip Low Steam Generator Water Level Trip High Containment Pressure Trip Safety Injection Actuation Signal

3-6 Technical Specification Requirements on Shutdown Margin, Inherent Negative Doppler Feedback


TABLE 14.1.5.2-2 DISPOSITION OF EVENTS FOR STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE OF CONTAINMENT, POST-SCRAM ANALYSIS


1 Analyze

2 Analyze



TABLE 14.1.5.2-3 SRELAP5 -THERMAL-HYDRAULIC INPUT (POST-SCRAM STEAM LINE BREAK)

Break Characteristics

Minimum Flow Area

Affected Steam Generator (ft2) 3.51

Unaffected Steam Generator (ft2) 3.51

Location of Pipe Break Downstream of steam generator integral flow restrictor and upstream of MSIV

Initial Condition Thermal-Hydraulic Input HFP HZP

Core Power (MW) 2700 1E-6

Primary Pressure (psia) 2250 2250

Pressurizer Level (%) 65 40

Cold Leg Temperature (°F) 549 532

Primary Flow Rate per Loop (lbm/sec) 18,820 19,241

Secondary Pressure (psia) 881 892

Steam Generator Mass Inventory (lbm) 167,237 253,989

Total Steam Flow (lbm/sec) per Steam Generator 1634 4

Injection Systems HFP HZP

Total HPSI Pumps 3 3

Active HPSI Pumps 2 2

Single Failure (No credit for mounted spare) 1 HPSI pump 1 HPSI pump

Active Charging Pumps 0 0

Refueling Water Storage Tank Boron Concentration (ppm)

1720 1720

HPSI Delivery Curve Figure 14.1.5.2–1 Figure 14.1.5.2–1


MSIV Closure

Required Actuation Signal (3) Above

Delay - 6.9 seconds

HPSI Actuation


Delay - 25.0 seconds

Main Feedwater Valve Closure


Delay - 14.0 seconds

Reactor Scram


Delay - 0.9 second instrument delay, 3.0 second insertion time

TABLE 14.1.5.2-4 ACTUATION SIGNALS AND DELAYS (POST-SCRAM STEAM LINE BREAK)

Parameter Setpoints Inside Containment Outside Containment

1. Low Steam Generator Pressure Trip 550 psia 658 psia

2. Low Pressurizer Pressure SIAS 1500 psia 1576 psia

3. Low Steam Generator Pressure MSI 370 psia 478 psia


Stuck Rod Location

Within half-core section cooled by affected loop.

Fission Product and Actinide Decay Constants

Default values in S-RELAP5 utilized.

TABLE 14.1.5.2-5 S-RELAP5 NEUTRONICS INPUT AND ASSUMPTIONS (POST-SCRAM STEAM LINE BREAK)

Point Kinetics Input Value

Effective Delayed Neutron Fraction 0.005245

Moderator Temperature Coefficient (pcm/°F) -30

HFP Scram Worth (pcm) 6425.0

Shutdown Margin Requirement (pcm) 3600.0


TABLE 14.1.5.2-6 POST-SCRAM STEAM LINE BREAK ANALYSIS SUMMARY

Initial Power Level

Offsite Power

AvailableBreak

Location

Maximum Post-Scram Return to

Power (MW) MDNBR

Maximum LHGR (kW/ft)

Fuel Failure (% of Core)

HFP No outside containment

158 2.160 14.05 0.0

HFP Yes outside containment

259 2.629 21.55 0.0

HZP No outside containment

159 2.132 14.12 0.0

HZP Yes outside containment

281 2.547 21.98 0.0


TABLE 14.1.5.2-7 LHGR-LIMITING SEQUENCE OF EVENTS - HZP OFFSITE POWER AVAILABLE

Time (s) Event

0. Reactor at HZP

0.+ Double-ended guillotine break. Shutdown reactivity inserted. AFW increased to maximum flow, with 660 gpm to each steam generator.

7.7 MSIV closure trip signal

14.6 MSIVs closed

17.2 SI signal

42.2 SI pumps at rated speed (25 s delay)

331.7 SI lines cleared. Boron begins to enter primary system

333.3 Peak post-scram power reached (281 MW)

600. Calculation terminated; power decreasing


TABLE 14.1.5.2-8 MDNBR-LIMITING POST-SCRAM STEAM LINE BREAK ANALYSIS SUMMARY

Time (s) Event

0. Reactor at HZP

0.+ Double-ended guillotine break. Loss of offsite power. Shutdown reactivity inserted. Full AFW flow started, with 660 gpm to each steam generator.

7.3 MSIV closure trip signal

14.3 MSIVs closed

21.4 SI signal

46.4 SI pumps at rated speed (25 s delay)

332.6 SI lines cleared. Boron begins to enter primary system

352. Peak post-scram power reached (159.1 MW)

600. Calculation terminated. Power decreasing.


FIGURE 14.1.5.2–1 ONE PUMP HIGH PRESSURE SAFETY INJECTION SYSTEM DELIVERY VS. PRIMARY PRESSURE (POST-SCRAM STEAM LINE BREAK)


FIGURE 14.1.5.2–2 STEAM GENERATOR BREAK FLOW (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–3 STEAM GENERATORS' SECONDARY PRESSURES (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH

OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–4 CORE INLET TEMPERATURES (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–5 PRESSURIZER PRESSURE (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–6 PRESSURIZER LEVEL (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–7 STEAM GENERATORS' SECONDARY MASS (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER

AVAILABLE)


FIGURE 14.1.5.2–8 REACTIVITY COMPONENTS (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–9 REACTOR POWER (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH OFFSITE POWER AVAILABLE)


FIGURE 14.1.5.2–10 STEAM GENERATOR BREAK FLOW (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.2–11 STEAM GENERATORS' SECONDARY PRESSURES (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE

POWER)


FIGURE 14.1.5.2–12 CORE INLET TEMPERATURES (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.2–13 PRESSURIZER PRESSURE (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.2–14 PRESSURIZER LEVEL (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.2–15 REACTIVITY COMPONENTS (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE POWER)


FIGURE 14.1.5.2–16 REACTOR POWER (HZP POST-SCRAM STEAM LINE OUTSIDE CONTAINMENT BREAK WITH LOSS OF OFFSITE POWER)


TABLE 14.1.5.3-1 ASSUMPTIONS USED IN MAIN STEAM LINE BREAK ANALYSIS

Core Power Level (MWt) 2754

Primary to Secondary Leak Rate per Steam Generator 150 gpd

Primary Coolant Iodine Concentration 1 μCi/gpm DE I-131

Secondary Coolant Iodine Concentration 0.1 μCi/gm DE I-131

Primary Coolant Noble Gas Concentration 1100 μCi/gm DE Xe-133

Pre-accident Spike Iodine Concentration 60 μCi/gm DE I-131

Failed Fuel Percentage (Containment release only) 3.7%

Peaking Factor 1.69

Reactor Coolant Mass 428,400 lbm

Intact Steam Generator Minimum Mass 91,092 lbm

Site Boundary Breathing Rate (m3/sec)

0 - 8 hour 3.5E-04

8 - 24 hour .8E-04

24 - 720 hour 2.3E-04

Site Boundary Dispersion Factors (sec/m3)

EAB: 0 - 2 hour 3.66E-04

LPZ: 0 - 4 hour 4.80E-05

4 - 8 hour 2.31E-05

8 - 24 hour 1.60E-05

24 - 96 hour 7.25E-06

96 - 720 hour 2.32E-06

Control Room Breathing Rate 3.5E-04 m3/sec

Control Room Isolation Time - 4 hours

MSLB outside containment (Operator action in the event the break is small enough to not automatically isolate the control room.


TABLE 14.1.5.3-1 ASSUMPTIONS USED IN MAIN STEAM LINE BREAK ANALYSIS (CONTINUED)

Control Room Isolation Time - MSLB Inside Containment 140 seconds

Control Room Intake Prior to Isolation 800 cfm

Control Room Inleakage After Isolation 200 cfm

Control Room Emergency Filtered Recirculation Rate 2,250 cfm

(t = 1 hour after isolation)

Control Room Intake Dispersion Factors (sec/m3)

Containment Enclosure Building - Ground Release

0 - 2 hour 3.00E-03

2 - 8 hour 1.87E-03

8 - 24 hour 6.64E-04

24 - 96 hour 5.83E-04

96 - 720 hour 4.97E-04

Atmospheric Dump Valves (ADVs) & Enclosure Building Blowout Panels

0 - 2 hour 7.40E-03

2 - 8 hour 5.71E-03

8 - 24 hour 2.13E-03

24 - 96 hour 1.74E-03

96 - 720 hour 1.43E-03

Turbine Building Blowout Panels

0 - 2 hour 1.22E-02

2 - 8 hour 8.67E-03

8 - 24 hour 3.77E-03

24 - 96 hour 2.92E-03

96 - 720 hour 2.23E-03


TABLE 14.1.5.3-1 ASSUMPTIONS USED IN MAIN STEAM LINE BREAK ANALYSIS (CONTINUED)

Main Steam Safety Valves (MSSVs)

0 - 2 hour 3.03E-03

2 - 8 hour 2.30E-03

8 - 24 hour 8.46E-04

24 - 96 hour 6.73E-04

96 - 720 hour 5.49E-04

Control Room Free Volume 35,650 ft3

Control Room Filter Efficiency (particulate/elemental/organic) 90 / 90 / 70 % (1)

Dose Conversion Factors Federal Guidance Reports 11 and 12

(1) 70% is a conservative analysis assumption for some iodine species. Technical Specifications can support assumptions for filter efficiencies of 90% for all iodine species.


TABLE 14.1.5.3-2 SUMMARY OF MILLSTONE 2 MSLB ACCIDENT DOSES

MSLBEAB,

rem - TEDELPZ,

rem - TEDEControl Room,

rem - TEDE

MSLB in Enclosure Building

pre-accident spike 9.1E-02 2.8E-02 2.6E+00

concurrent spike 1.6E-01 5.4E-02 3.8E+00

MSLB in Turbine Building

pre-accident spike 9.1E-02 2.9E-02 4.0E+00

concurrent spike 1.6E-01 5.4E-02 4.7E+00

MSLB in Containment

3.7% fuel failure 1.4E-01 4.2E-02 2.0E+00


TABLE 14.1.5.3-3 DELETED BY FSARCR PKG FSC 07-MP2-006


14.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM

14.2.1 LOSS OF EXTERNAL LOAD


A major loss of load can be initiated as the result of a loss of external electrical load or a turbine trip. Turbine stop valve closure is assumed as the initiator of this event because this is the fastest load rejection which can be postulated which will challenge the plant overpressure and Specified Acceptable Fuel Design Limits (SAFDL) protection features. The assumed fast valve closure time (0.02 sec.) and the assumed unavailability of the steam dump system allow this event to bound the effects of Event 14.2.2 (Turbine Trip — Steam dump system available) and the simultaneous closure of both Main Steam Isolation Valves (MSIV) case of Event 14.2.4 (Closure of the MSIVs — Valve closure time > 0.02 seconds).


For a full load reduction at power, the primary to secondary heat transfer would be severely diminished because of the increase in secondary side temperature. Initially, in response to the load reduction and diminished energy removal through the secondary system, the primary system temperatures begin to increase. The increasing primary system average temperature causes an insurge into the pressurizer due to the expanding primary fluid. The primary system pressure increases as the pressurizer steam space is compressed by the insurging liquid. Primary system overpressure protection is afforded by the pressurizer power-operated relief valves (PORV) and the primary safety valves. Eventually, the secondary system pressure reaches the opening setpoint of the secondary side safety valves and steam discharge occurs to limit the secondary side pressure rise. Energy removal through the steam generator and pressurizer safety valves mitigates the consequences of the load reduction. However, in analyzing the overpressurization aspects of this event, no credit is taken for the PORVs on the primary system or the turbine bypass system and steam dump system on the secondary system.


Reactor protection is provided by the high pressurizer pressure, variable overpower, thermal margin/low pressure (TM/LP), and low steam generator water level trips. If the turbine is tripped at the initiation of this event, a direct reactor trip signal would be generated and the effects of this event would be mitigated. However, no credit is taken for a direct reactor trip on turbine trip. Additionally, reactor protection is provided by the primary and secondary safety valves. Because of the potential for increasing the primary system temperatures, with small increases in pressure, this event can challenge the SAFDLs as well as the overpressure criteria mentioned above. Reactor protection for the Loss of External Load event is summarized in Table 14.2.1-1.


This event is only credible for rated power and power operating conditions because there is no load on the turbine at other reactor conditions. The consequences of this event for rated power


operation bound the consequences for other reactor conditions because of the maximum stored energy in the primary coolant, minimum initial thermal margin and maximum power to load mismatch which occurs upon loss of load.

Three separate cases of this event are analyzed for Millstone Unit 2 from rated power conditions. Two cases maximize the primary and secondary system overpressurization criteria, respectively, and the third case addresses the fuel design limits. There is no single failure considered which could worsen the results. The disposition of events for the Loss of External Load event is summarized in Table 14.2.1-2.


The objectives in analyzing this event are to demonstrate that: the primary pressure relief capacity is sufficient to limit the pressure to less than 110% (2750 psia) of the design pressure, the secondary side pressure relief capacity is capable of limiting the pressure to less than 110% (1100 psia) of design pressure and the minimum Departure From Nucleate Boiling Ratio (DNBR) remains above the safety limit. No credit is taken for direct reactor trip on turbine trip, the turbine bypass system or the steam dump system.

Three cases are analyzed for this event: Two cases addressing the primary and secondary system overpressurization criteria, respectively, and one case addressing the fuel design limits. In the primary overpressurization and fuel design limits cases the input parameters are biased to maximize the increase in reactor power during the transient. The secondary overpressurization case minimizes the increase in reactor power to reduce the pressurizer insurge and delay the reactor trip. For the system overpressurization cases, the parameters and equipment operational states which significantly affect the results of the analysis are selected to maximize the system overpressure, while for the fuel design limit case the parameters and equipment states are selected to reduce the system pressurization and thereby provide a conservative estimate of the minimum DNBR during the transient.


This analysis was performed with AREVA Non-LOCA methodology, Reference 14.2-7, which uses the ANF-RELAP code to calculate the system response, and the XCOBRA-IIIC code to calculate the minimum DNBR.

All cases are initiated with a ramp closure of the turbine control valve in 0.02 seconds. The pressurization of the secondary side results in decreased primary-to-secondary heat transfer, and a substantial rise in primary system temperature. This results in an insurge into the pressurizer, compressing the steam space and pressurizing the primary system. The reactor trips on high pressure. The primary and secondary system safety valve setpoints were modeled with a ± 3% drift allowance, and the flow characteristics were modeled with a 3% allowance for accumulation.

In the primary system overpressurization case, the capacity of the pressurizer safety valves limit the pressurizer pressure to a maximum of 2576 psia. The maximum Reactor Coolant System pressure at the bottom of the reactor vessel is 2717 psia.


For the secondary system overpressurization and the minimum DNBR cases, the transient proceeds in a similar fashion with the primary side pressure being limited by the pressurizer PORV setpoint. The peak secondary system pressure is 1086 psia. The minimum DNBR for this event is bounded by the minimum DNBR of the Section 14.3.1 loss of forced reactor coolant flow event. Because of this, the DNB SAFDL is not violated. This event does not challenge the FCMLHR limit. Therefore, LHR is not evaluated.

The responses of key system variables are given in Figures 14.2.1–1 to 14.2.1–5 for the primary system overpressurization case, Figures 14.2.1–6 to 14.2.1–11 for the secondary system overpressurization case, and Figures 14.2.1–12 to 14.2.1–17 for the minimum DNBR case. The sequence of events for each of these cases is given in Tables 14.2.1-3, 14.2.1-4 and 14.2.1-5, respectively.

The primary and secondary side pressure relief valves have sufficient capacity to limit the respective system pressure to less than 110% (2750 and 1100 psia) of their design pressure.

In the event that one or more of the main steam safety valves are inoperable, analyses have demonstrated that the design pressure limits are met provided thermal power is limited to the values given in Technical Specification 3.7.1.1.

14.2.1.7 Conclusion

The calculated minimum DNBR for the Loss of Load event is above the heat flux correlation safety limit, so the Departure From Nucleate Boiling (DNB) SAFDL is not exceeded in this event. The peak pellet LHR is less than the FCMLHR limit. The maximum primary and secondary system pressures remain below 110% of design pressure. Thus, the Loss of External Load event has been demonstrated to meet all required acceptance criteria.

14.2.2 TURBINE TRIP


This event is initiated by a turbine trip which results in closure of the turbine stop valves and a rapid reduction in energy removal through the steam generators.


The reactor protection system is designed to generate a reactor trip signal automatically when the turbine is tripped. Following reactor trip, there would be a rapid decrease in the energy being generated in the primary system. This would mitigate the consequences of the turbine trip event. Primary and secondary system overpressurization protection is provided by the code safety valves on both the primary and secondary systems and the secondary atmospheric dump valves. Also, if the condenser was available, the steam bypass system would be activated to reduce the secondary system pressure.



Reactor protection is provided by the high pressurizer pressure trip, variable overpower trip, TM/LP trip, low steam generator water level trip, and a nonsafety grade reactor trip on turbine trip. Additional protection is also provided by the primary and secondary side safety valves. Reactor protection for the Turbine Trip event is summarized in Table 14.2.2-1.


This event is only credible for rated power and power operating conditions since the turbine will either be in tripped condition or there will be no load on the steam generators for other reactor operation conditions. The consequences of this event for rated power operation bound the event consequences for other operating conditions because of the higher initial stored energy in the primary system, maximum power to load mismatch potential, and the reduced SAFDL margin for rated power operation. Because of the limiting assumptions used in the analysis of the consequences of the Loss of External Load (Event 14.2.1), the consequences of the Turbine Trip event are bounded by the consequences of Event 14.2.1, which is analyzed for Millstone Unit 2. The major assumptions used in Event 14.2.1 are the conservatively rapid turbine stop valve closure time, the failure to trip the reactor on turbine trip, and the assumed unavailability of the atmospheric steam dump system. The disposition of events for the Turbine Trip event is summarized in Table 14.2.2-2.

14.2.3 LOSS OF CONDENSER VACUUM

This event is not in the current licensing basis for Millstone Unit 2 and therefore is not analyzed.

14.2.4 CLOSURE OF THE MAIN STEAM ISOLATION VALVES


The event postulated is the loss of control air to the MSIV operator. Either one or both MSIVs may inadvertently close. The valves are swinging disc-type check valves, installed in a reversed position and held open against steam flow by a pneumatically operating cylinder assembly. The valves are spring-loaded to the closed position.


The inadvertent MSIV closure is primarily of concern in boiling water reactors as indicated in the Standard Review Plan (Reference 14.2-1), but closure of the MSIVs in a pressurized water reactor would cause a drastic reduction in the load on the reactor. As such, the consequences of a dual MSIV closure are similar to the consequences of Event 14.2.1. Although the valve closure time for the MSIVs is less than 6 seconds, this is much longer than the turbine stop valve closure time assumed in Event 14.2.1 (0.02 seconds); as such, the transient events will proceed somewhat slower and be less severe than in the case of Event 14.2.1.


A single MSIV closure will result in an asymmetric primary temperature distribution. Upon cessation of steam flow, the pressure in the affected steam generator will increase to the opening setpoint of the steam line safety valves. The primary to secondary heat transfer will be diminished, resulting in a heatup of the associated primary side loop. In response to the drop in steam flow through the turbine control valves, the steam flow out of the unisolated steam generator will increase. Depressurization of the steam generator will result, causing an increase in heat removal from the primary. The associated primary side loop will thus experience a cooldown. The side of the core subjected to the cooldown will experience a power rise in the presence of a negative moderator temperature coefficient (MTC).


Reactor protection for the dual MSIV closure is provided by the high pressurizer pressure trip, variable overpower trip, TM/LP trip, and low steam generator water level trip. Additional protection is provided by the primary and secondary side safety valves.

Reactor protection for the single MSIV closure is provided by the low steam generator level and low steam generator pressure trips. Due to the location of the excore detectors and the asymmetries associated with this event, the variable overpower and TM/LP trip may not get the required 2 out of 4 channels tripped. Further, since one loop will be cooling down and one will be heating up, the pressure may be either increasing or decreasing. Thus, this event cannot take credit for the variable high power, TM/LP or high pressure trips. Additional protection continues to be provided by the primary and secondary side safety valves. Reactor Protection for these events are summarized in Table 14.2.4-1.


For simultaneous closure of both MSIVs, the event will progress very similarly to Event 14.2.1. As such, the limiting case is obtained when the event is initiated from rated full power conditions. Due to the decreased heat load and steam flow rates in Modes 2-4 the consequences of the event are bounded by the Mode 1 analysis. The absence of any secondary side heat removal in Modes 5 and 6 eliminates the need to consider the event in these Modes. The turbine stop valve closure time employed in Section 14.2.1 analysis (0.02 sec) is much smaller than the MSIV closure time. Thus, the consequences of Event 14.2.1 will bound those of the dual MSIV closure event.

The asymmetric conditions resulting from the closure of only one of the two MSIVs are similar to that predicted for a steam line break (SLB). That is, the primary coolant loop associated with the closed MSIV experiences a heatup due to the loss of heat sink and the primary coolant loop associated with the open MSIV experiences a cooldown due to the perceived load increase. The temperature increase seen by the hot loop will be limited by the actuation of the steam generator safety valves. The temperature decrease seen by the cooling loop will continue until such time as a reactor trip is generated.

Since the loop experiencing the cooldown will see the larger temperature change, the limiting conditions for the event are at end of cycle (EOC). The EOC MTC is larger in absolute magnitude than the beginning of cycle (BOC) MTC. When the larger MTC is coupled with the larger


temperature change in the cooling loop, a larger overall increase in core power will be predicted. This larger increase in core power will produce the limiting DNB conditions for the event.

Since the asymmetries associated with the event preclude taking credit for the high pressure or variable overpower trip, the single MSIV closure cannot be bounded without analysis by the loss of load, Event 14.2.1.

The limiting single MSIV closure case is that which is initiated from rated power in Mode 1. As for the simultaneous closure of both MSIVs, the reduced heat load and steam flow rates reduce the consequences in all other Modes. For the single MSIV closure case there is also no potential for a post-trip return to power since the remaining MSIV and the turbine stop valves provide redundant means for terminating the remaining steam flow from the unaffected steam generator. Therefore, there is no possibility of a sustained cooldown, thus preventing the addition of sufficient reactivity to the core to return to criticality after reactor trip. There is no single failure considered which could worsen the results. The disposition of events for the Closure of the MSIVs events is summarized in Table 14.2.4-2.


As discussed above, the limiting case is obtained when the event is initiated from rated full-power conditions. For simultaneous closure of both MSIVs, the event will progress very similar to Event 14.2.1. The turbine stop valve closure time employed in the Event 14.2.1 analysis (0.02 seconds) is much smaller than the MSIV closure time. Thus, the consequences of Event 14.2.1 will bound those of the dual MSIV closure event.

The objective in analyzing this event is to demonstrate that: the secondary side safety relief capacity is capable of limiting the pressure to less than 110% (1100 psia) of the design pressure, that the minimum DNBR remains above the safety limit, and that the peak LHR is below the centerline melt limit.

The asymmetric conditions resulting from the closure of only one of the two MSIVs is similar to that predicted for an SLB. That is, the primary coolant loop associated with the closed MSIV experiences a heatup due to the loss of heat sink and the primary coolant loop associated with the open MSIV experiences a cooldown due to the perceived load increase. The temperature increase seen by the hot loop will be limited by the actuation of the steam generator safety valves. The temperature decrease seen by the cooling loop will continue until such time as a reactor trip is generated.

Since the loop experiencing the cooldown will see the larger temperature change, the limiting conditions for the event are at EOC. The EOC MTC is larger in absolute magnitude than the BOC MTC. When the larger MTC is coupled with the larger temperature change in the cooling loop, a larger overall increase in core power will be predicted. This larger increase in core power will produce the limiting DNB conditions for the event.



The analysis used EOC initial conditions and assumed that one of the two MSIVs close thereby initiating a heatup on the side of the core associated with the closed MSIV. The side of the core associated with the open MSIV experiences a cooldown corresponding to an approximate doubling of the steam flow. This is because the entire steam demand is shifted to a single steam generator. As the pressure in the steam generator drops, the amount of steam which is supplied by the steam generator is also modeled to decrease. Two sensitivity cases were analyzed. In the first case, at transient initiation, the flow area of the steam control valve was set to a constant value equal to the steady state flow area, thereby simulating the manual mode of operation of the turbine control valves. In this case, the steam flow from a single steam generator with the open MSIV rapidly increases following the initiation of the transient to pick up the load from the isolated steam generator, nearly doubling the initial steam flow through the single MSIV. In the second case, steam flow is modeled as a function of steam generator pressure based on EOC coastdown data. This case simulates the automatic mode of operation of the turbine control valves. The manual mode case, having constant turbine control valve flow area, yielded lower steam flow rates through the transient.

The non-LOCA methodology (Reference 14.2-2) is used to analyze the MSIV closure event. Due to the event asymmetry and the fact that the event proceeds much like a Steam Line Break (SLB) event prior to reactor trip, portions of the pre-scram SLB methodology (Reference 14.2-2) and SLB S-RELAP5 input deck were used to perform this analysis. The input deck was modified to add the MSSV inlet piping and individual MSSVs to the steam line having the closed MSIV. For the single MSIV closure event, the neutronics input required to predict the radial power distribution between the cold and the hot side of the core was, however, redeveloped based on event specific PRISM (Reference 14.2-3) calculations. Core radial power distributions from full-power EOC PRISM cases with differences between the hot-region inlet temperature and the cold-region inlet temperature are used to determine the power split between the halves of the core as a function of the difference in inlet temperatures. Since the temperature differences used in the PRISM cases meets or exceeds the inlet temperature difference calculated by S-RELAP5 during the transient calculation, the power splits used in S-RELAP5 are bounding. The PRISM calculations for the single MSIV closure event are similar to those used in the pre-scram SLB event. The pre-scram SLB and single MSIV closure event analyses both require power distribution data assuming that an all rods out power distribution is appropriate.

The limiting results were obtained from the manual mode turbine control valve case which has lower steam flow rates. The results of the limiting EOC analysis are given in the event summary, Table 14.2.4-3, and in Figures 14.2.4–1 through 14.2.4–5. As indicated in the event summary table the secondary safety valves open early in the transient limiting the temperature rise on the hot side of the core associated with the closed MSIV. The reactor trips on low steam generator pressure which terminates the power rise.

The peak LHR and Minimum Departure from Nucleate Boiling Ratio (MDNBR) are predicted to occur on the cold side of the core. The peak LHR occurs at the time of the reactor trip, and the MDNBR occurs at the time of the peak heat flux. The peak LHR is less than the FCMLHR limit. The minimum DNBR for this event is bounded by the minimum DNBR of the Section 14.3.1 loss


of forced reactor coolant flow event. Thus it is concluded that the DNB limits will not be violated and that fuel failures are precluded during the single MSIV closure event.

The secondary side safety valve setpoints were modeled assuming a +3% tolerance on the opening set pressures, and that the valves would relieve the rated flow at an inlet pressure of 1098 psia. The calculated maximum secondary side pressure is 1093 psia, which is less than 110% (1100 psia) of design pressure.

14.2.4.7 Conclusion

The calculated minimum DNBR for the single MSIV closure event is above the HTP critical heat flux correlation safety limit, so the DNB SAFDL is not exceeded in this event. The peak LHR is less than the FCMLHR limit. The maximum secondary side pressure is below 110% of design pressure. Thus, the single MSIV closure event has been demonstrated to meet all required acceptance criteria.

14.2.5 STEAM PRESSURE REGULATOR FAILURE

Millstone Unit 2 does not have any steam line pressure regulators, so this event is not credible for this plant. No analysis needs to be considered for this event.

14.2.6 LOSS OF NONEMERGENCY AC POWER TO THE STATION AUXILIARIES


14.2.7 LOSS OF NORMAL FEEDWATER FLOW


The Loss of Normal Feedwater Flow transient is initiated by a trip of the main feedwater pumps or a malfunction in the feedwater control valves.


The loss of main feedwater flow will increase the secondary-side temperature and reduce the steam generator heat removal capability because the main feedwater system is supplying subcooled water to the steam generators. The rise in the secondary-side temperature leads to a rise in the primary system coolant temperature. As the primary system temperatures increase, the coolant expands into the pressurizer which increases the pressure by compressing the steam volume.

The temperatures of the secondary sides and primary loops are controlled by the opening and closing of the main steam safety valves and/or the steam dump valves. The long term cooling of the primary system is assured by the secondary-side water inventory supplied by the Auxiliary Feedwater System (AFWS). Two motor-driven auxiliary feedwater (AF) pumps are automatically started upon a steam generator low liquid level signal. If a loss of offsite power occurs, the motor-


driven AF pumps are powered by the emergency diesels. In addition, a turbine-driven AF pump can be manually actuated.


System overpressure protection is provided by the primary and secondary system safety valves. A reactor trip occurs on low steam generator level with additional reactor protection provided by the high pressurizer pressure trip, variable overpower trip, and the TM/LP trip. Reactor protection for the Loss of Normal Feedwater Flow event is summarized in Table 14.2.7-1.


This event is only credible for rated power and power operating conditions because the main feedwater system is not required to provide feedwater to the steam generators for other reactor operating conditions. The consequences of this event for rated power operation bound the consequences for other conditions because of the higher initial stored energy in the primary system, the minimum steam generator inventory, and the greater impact of the loss of feedwater flow on the secondary system.

The near-term pressurization and DNB aspects of this event are bounded by those Events 14.2.1 and 14.3.1, respectively. In Event 14.2.1, reactor trip is delayed until a high pressurizer pressure signal is received. This results in a higher power level at trip, greater pressurization and greater challenge to the SAFDLs than in Event 14.2.7. Long-term pressurization, if it occurs, is very gradual and is arrested by opening of the pressurizer code safety valves.

In Event 14.3.1, the RCPs are tripped as the initiating event. Reactor trip occurs on low coolant flow, and the core flow rate at the time of trip is significantly lower than in the Loss of Normal Feedwater Flow event where the RCPs are tripped coincident with the reactor trip. The core power to flow ratio is much higher for Event 14.3.1, thereby producing a more limiting minimum DNBR.

The Loss of Normal Feedwater event is analyzed to assess the maximum expected pressurizer level swell and the long-term adequacy of the AFWS to restore and maintain steam generator inventory and prevent steam generator dryout. The maximum level swell is examined to assure that the pressurizer does not become water solid. Each case was analyzed using 102% power, maximum allowed positive reactivity feedback, and maximum permitted pressurizer level. The full power initial condition maximizes the core decay heat that must be removed in the post-scram period. A primary concern in simulating this event is to demonstrate adequate long-term cooling capability. The single active failure assumptions reduce heat removal capacity by significantly limiting the amount of AFW flow supplied to the steam generators.

Two single failures considered in the Loss of Normal Feedwater Flow event are the failure of a motor-driven AFW pump to start and the failure of the steam-driven AFW pump to start. Also considered is a loss of offsite power coincident with reactor trip (Reference 14.2-7). The disposition of events for the Loss of Normal Feedwater Flow event is summarized in Table 14.2.7-2.



The Millstone Unit 2 AFW system consists of two independent motor-driven pumps which are assumed to start automatically within 240 seconds of AFW system actuation on low-low steam generator level. There is also a steam-driven AFW pump which may be started by operator action. (The operator action is credited 10 minutes following reactor trip in the safety analysis.) The piping configuration allows each pump to supply both steam generators simultaneously. There are two potential single active failures in this configuration: One is the failure of the steam-driven AFW pump to start, and the other is the failure of one of the two motor-driven AFW pumps to start. Because of the differences in pump capacity and actuation times, it is not immediately obvious which single active failure is the most limiting.

Another uncertainty when analyzing the Loss of Normal Feedwater Flow event is the effect of the RCP trip. If the RCPs remain on, the pump heat imposes a significant heat load on the system. If the RCPs are tripped, primary to secondary heat removal capability is degraded due to sole reliance on natural circulation.

The loss of offsite power option (RCP trip), combined with the two single active failure possibilities produces a total of four base cases. The four cases collectively demonstrate compliance with both the pressurizer overfill criterion and the steam generator secondary water inventory criterion when the MSSVs are the sole secondary steam release path. The biases and initial conditions for the cases are identical and are selected to maximize pressurizer level increase and to minimize steam generator level recovery. A fifth case considers the effects of steam dump system operation and determines whether the SG inventory boiloff required to cool the RCS to no load temperature is offset by increased AFW flow at lower SG pressures.

The initiating event for each case is an instantaneous loss of main feedwater.

The analysis is performed with the ANF-RELAP code (Reference 14.2-6). The ANF-RELAP code includes relevant aspects of the mass and energy balance of the primary and secondary systems.

Additional conservative conditions are applied for analysis of each case to present the greatest challenge to the event acceptance criteria. In accordance with AREVA methodology, symmetric tube plugging is modeled for the four base cases utilizing the MSSVs as the sole secondary steam release path. No steam generator tube plugging is applied for the fifth case. This conservatively minimizes post-trip steam generator liquid inventories by producing slightly higher steam generator pressures and consequently lower AFW flows when steam generator pressure is controlled by the steam dumps instead of by the MSSVs.


The Loss of Normal Feedwater Flow event is initiated from 102% power with each steam generator at nominal liquid levels. A total instantaneous loss of all Main Feedwater flow initiates the event. When loss of offsite power assumptions are applied, the loss of offsite power and reactor coolant pump trip is assumed to occur at scram. The reactor trips on the steam generator


low water level signal. The turbine trips one second after the reactor trips. Cases one through four were evaluated assuming an analytical low SG level reactor trip setpoint of 34%. Case five was evaluated with an analytical low level trip setpoint of 43%.

The cases where off site power is available and the RCPs maintain forced coolant flow through the primary system produce the lowest steam generator inventories. The loss of one of the two motor-driven AFW pumps combined with post-trip RCS temperature control using the steam dumps resulted in a minimum steam generator liquid mass inventory of 5,540 lbs per steam generator at 654 seconds. The steam generator level steadily recovers from this minimum level, thus ensuring continued heat removal. An event summary is presented in Table 14.2.7-3. The transient responses are presented in Figures 14.2.7–1 through 14.2.7–6. The transient execution time was 1800 seconds.

The cases where offsite power is assumed to be lost coincident with the reactor trip, and primary to secondary heat transfer is achieved via natural circulation, generated the highest pressurizer levels. The loss of one of the two motor-driven AFW pumps produced the maximum pressurizer level of 76.3% at 43 seconds. Sufficient steam volume remains to preclude the expulsion of liquid from the pressurizer safety valves. An event summary is presented in Table 14.2.7-4. The transient responses are presented in Figures 14.2.7–6 through 14.2.7–10. The transient execution time was 2400 seconds.

14.2.7.6 Conclusions

A loss of normal feedwater event does not result in the violation of SAFDLs, peak pressurizer pressure does not exceed 110% of the design rating and primary liquid is not expelled through the pressurizer safety valves. Adequate cooling water is supplied by the AFWS to allow a safe and orderly plant shutdown and to prevent steam generator dryout. Thus, the loss of normal feedwater event has been demonstrated to meet all required acceptance criteria.

14.2.8 FEEDWATER SYSTEM PIPE BREAKS INSIDE AND OUTSIDE CONTAINMENT

This event is not in the current licensing basis for Millstone Unit 2 and, therefore, is not analyzed.

14.2.9 REFERENCES


14.2-2 “SRP Chapter 15 Non-LOCA Methodology for Pressurized Water Reactors,” EMF-2310(P)(A), Revision 1, Framatome-ANP, May 2004.

14.2-3 “Reactor Analysis Systems for PWRs, Volume 1 - Methodology Description, Volume 2 - Benchmarking Results,” EMF-96-029 (P)(A), Siemens Power Corporation, January 1997.



14.2-5 “Advanced Nuclear Fuels Methodology for Pressurized Water Reactors - Analysis of Chapter 15 Events,” ANF-84-73(P)(A), Rev. 5, Advanced Nuclear Fuels Corp., October 1990.

14.2-6 “ANF-RELAP Methodology for Pressurized Water Reactors: Analysis of Non-LOCA Chapter 15 Events,” ANF-89-151(P)(A), Siemens Power Corporation, May 1992.

14.2-7 “Millstone Unit No. 2 Loss of Normal Feedwater Flow Transient with Reduced Auxiliary Feedwater Flow,” EMF-98-015, Rev. 1, Siemens Power Corporation, December 1998.



TABLE 14.2.1-1 AVAILABLE REACTOR FOR THE LOSS OF EXTERNAL LOAD EVENT

Reactor Operational Mode Reactor Protection

1 High Pressurizer Pressure Trip Variable Overpower Trip Thermal Margin/Low Pressure Trip Low Steam Generator Water Level Trip

2 High Pressurizer Pressure Trip Variable Overpower Trip Low Steam Generator Water Level Trip

3-6 No Analysis Required; Not a Credible Event


TABLE 14.2.1-2 DISPOSITION OF EVENTS FOR THE LOSS OF EXTERNAL LOAD EVENT


1 Analyze

2 Bounded by the above, no analysis required



TABLE 14.2.1-3 EVENT SUMMARY FOR THE LOSS OF EXTERNAL LOAD EVENT (PRIMARY OVERPRESSURIZATION CASE)

Event Time (seconds)

Turbine Trip 0.0

First MSSV opens 4.3

Primary pressure reaches high pressure trip setpoint 4.9

Reactor scrams 6.3

Pressurizer safety valves open 7.4

Peak pressurizer pressure 7.4

Primary system peak pressure 7.9

Last MSSV opens 9.5

End of calculation 20.0


TABLE 14.2.1-4 EVENT SUMMARY FOR THE LOSS OF EXTERNAL LOAD EVENT (SECONDARY OVERPRESSURIZATION CASE)


Turbine Trip 0.0


Pressurizer spray begins 3.2

Pressurizer PORV opens 4.9

Primary pressure reaches high-pressure trip setpoint 4.9

Pressurizer safety valves open 5.0


Reactor scrams 6.3

Last MSSV opens 10.1

Steam Generator secondary peak pressure 10.2



TABLE 14.2.1-5 EVENT SUMMARY FOR THE LOSS OF EXTERNAL LOAD EVENT (MINIMUM DEPARTURE FROM NUCLEATE BOILING RATIO CASE)


Turbine Trip 0.0

Pressurizer spray on 3.4


Primary pressure reaches high pressure trip setpoint 4.9

Pressurizer PORVs open 4.9

Primary safety valves open 4.9


Reactor scrams 6.3


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L LOAD
FIGURE 14.2.1–1 REACTOR POWER LEVEL FOR LOSS OF EXTERNA(PRIMARY OVERPRESSURIZATION CASE)

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14.2-19

AL LOAD
FIGURE 14.2.1–2 CORE AVERAGE HEAT FLUX FOR LOSS OF EXTERN(PRIMARY OVERPRESSURIZATION CASE)

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14.2-20

EXTERNAL LOAD
FIGURE 14.2.1–3 REACTOR COOLANT SYSTEM TEMPERATURES FOR LOSS OF(PRIMARY OVERPRESSURIZATION CASE)

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14.2-21

AL LOAD
FIGURE 14.2.1–4 PRIMARY SYSTEM PRESSURES FOR LOSS OF EXTERN(PRIMARY OVERPRESSURIZATION CASE)

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14.2-22

FI RPRESSURIZATION CASE)
GURE 14.2.1–5 TOTAL REACTIVITY FOR LOSS OF EXTERNAL LOAD (PRIMARY OVE

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14.2-23

L LOAD
FIGURE 14.2.1–6 REACTOR POWER LEVEL FOR LOSS OF EXTERNA(SECONDARY OVERPRESSURIZATION CASE)

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L LOAD
FIGURE 14.2.1–7 CORE AVERAGE HOT FLUX FOR LOSS OF EXTERNA(SECONDARY OVERPRESSURIZATION CASE)

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EXTERNAL LOAD
FIGURE 14.2.1–8 REACTOR COOLANT SYSTEM TEMPERATURES FOR LOSS OF(SECONDARY OVERPRESSURIZATION CASE)

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LOAD
FIGURE 14.2.1–9 PRESSURIZER PRESSURE FOR LOSS OF EXTERNAL(SECONDARY OVERPRESSURIZATION CASE)

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OAD
FIGURE 14.2.1–10 TOTAL REACTIVITY FOR LOSS OF EXTERNAL L(SECONDARY OVERPRESSURIZATION CASE)

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EXTERNAL LOAD
FIGURE 14.2.1–11 MAXIMUM SECONDARY SYSTEM PRESSURES FOR LOSS OF(SECONDARY OVERPRESSURIZATION CASE)

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(MDNBR CASE)
FIGURE 14.2.1–12 REACTOR POWER LEVEL FOR LOSS OF EXTERNAL LOAD

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FIGURE 14.2.1–13 NORMALIZED HEAT FLUX FOR LOSS OF EXTERNAL LOAD

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FI NAL LOAD (MDNBR CASE)
GURE 14.2.1–14 REACTOR COOLANT SYSTEM TEMPERATURE FOR LOSS OF EXTER

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FIGURE 14.2.1–15 PRESSURIZER PRESSURE FOR LOSS OF EXTERNAL LOAD

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14.2-33

DNBR CASE)
FIGURE 14.2.1–16 TOTAL REACTIVITY FOR LOSS OF EXTERNAL LOAD (M

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F AL LOAD (MDNBR CASE)
IGURE 14.2.1–17 MAXIMUM SECONDARY SYSTEM PRESSURE FOR LOSS OF EXTERN


TABLE 14.2.2-1 AVAILABLE REACTOR PROTECTION FOR THE TURBINE TRIP EVENT


1 High Pressurizer Pressure Trip Nonsafety Grade Reactor Trip on Turbine Trip Variable Overpower Trip Thermal Margin/Low Pressure Trip Low Steam Generator Water Level Trip




TABLE 14.2.2-2 DISPOSITION OF EVENTS FOR THE TURBINE TRIP EVENT

Reactor Operational Mode Disposition

1 Bounded by Event 14.2.1 for the rated power operating condition (number 1).

2 Same as above.

3-6 No Analysis Required; Not a Credible Event.


TABLE 14.2.4-1 AVAILABLE REACTOR PROTECTION FOR THE CLOSURE OF THE MAIN STEAM ISOLATION VALVES EVENTS


1 High Pressurizer Pressure Trip Variable Overpower Trip Thermal Margin/Low Pressure Trip Low Steam Generator Water Level Trip Low Steam Generator Pressure

2 High Pressurizer Pressure Trip Variable Overpower Trip Low Steam Generator Water Level Trip Low Steam Generator Pressure


4-6 No Analysis Required


TABLE 14.2.4-2 DISPOSITION OF EVENTS FOR THE CLOSURE OF THE MAIN STEAM ISOLATION VALVES EVENTS


1 Dual MSIV closure; Bounded by Event 14.2.1 Single MSIV Closure; Analyze

2-6 Bounded by Mode 1


TABLE 14.2.4-3 EVENT SUMMARY FOR THE MAIN STEAM ISOLATION VALVE CLOSURE EVENT (LOWER STEAM FLOW CASE)


Reactor at full power 0.0

One MSIV closes instantaneously, flow though other MSIV increases 0.0



Peak Steam Generator secondary pressure 12.5

Last MSSV opens 12.6

Steam Generator pressure reaches low-pressure trip setpoint 23.8

Reactor scrams (beginning of CEA insertion) 25.2

Peak reactor power 25.3



FIGURE 14.2.4–1 REACTOR POWER LEVEL FOR MSIV CLOSURE (LOWER STEAM FLOW CASE)


FIGURE 14.2.4–2 REACTOR COOLANT SYSTEM TEMPERATURES FOR MSIV CLOSURE (LOWER STEAM FLOW CASE)


FIGURE 14.2.4–3 PRESSURIZER PRESSURE FOR MSIV CLOSURE (LOWER STEAM FLOW CASE)


FIGURE 14.2.4–4 ISOLATED STEAM GENERATOR PRESSURE AT BOTTOM OF BOILER REGION FOR MSIV CLOSURE (LOWER STEAM FLOW CASE))


FIGURE 14.2.4–5 OPEN MSIV STEAM GENERATOR STEAM DOME PRESSURE FOR MSIV CLOSURE (LOWER STEAM FLOW CASE))


TABLE 14.2.7-1 AVAILABLE REACTOR PROTECTION FOR THE LOSS OF NORMAL FEEDWATER FLOW EVENT


1 Low Steam Generator Water Level Trip High Pressurizer Pressure Trip Thermal Margin/Low Pressure Trip Variable Overpower Trip





TABLE 14.2.7-2 DISPOSITION OF EVENTS FOR THE LOSS OF NORMAL FEEDWATER FLOW EVENT


1 Analyze to assess maximum pressurizer level swell and long term adequacy of AFW. Pressurization and DNB aspects bounded by Event 14.2.1.

2, 3 Bounded by the above, no analysis required.



TABLE 14.2.7-3 SEQUENCE OF EVENTS FOR MINIMUM STEAM GENERATOR INVENTORY CASE: ONE MOTOR-DRIVEN AFW PUMP FAILS TO START WITH

OFFSITE POWER AND STEAM DUMPS


0 Total loss of main feedwater

20 Pressurizer spray actuates

27.9 Reactor trip signal on low steam generator water level

28.8 Control rods begin to drop

29.9 Main turbine trip

32 Maximum pressurizer level, 73%

38 Peak steam generator pressure (993 psia)

48 AFW actuation signal on low-low Steam Generator water level

53 Charging flow initiated in response to pressurizer level program

58 Steam generator blowdown isolated

288 Train “A” motor-driven AFW pump starts

628 Steam-driven AFW pump starts

654 Minimum Steam generator liquid inventory occurs

1800 End of calculation


TABLE 14.2.7-4 SEQUENCE OF EVENTS FOR MAXIMUM PRESSURIZER LEVEL CASE: LOSS OF OFFSITE POWER, ONE MOTOR-DRIVEN AFW PUMP FAILS TO

START


0 Total loss of main feedwater

34.1 Reactor trip signal on low steam generator water level

35.1 Control rods begin to drop; RCPs tripped

36.1 Main turbine trip

39 Pressurizer PORV cycles open/closed

41 AFW actuation signal on low-low steam generator water level signal

43 Maximum pressurizer level, 76%

46 Peak steam generator pressure (1055 psia)

51 steam generator blowdown isolated

73 Charging flow on (pressurizer level below program)

170 Charging flow off (pressurizer level at program setpoint)

281 Train “A” motor-driven AFW pump starts

635 Steam-driven AFW pump starts

730 Minimum steam generator liquid inventory occurs

757 Maximum post-trip RCS average temperature (571°F)

2400 End of calculation


FIGURE 14.2.7–1 REACTOR COOLANT SYSTEM LOOP TEMPERATURES FOR MINIMUM STEAM GENERATOR INVENTORY CASE: OFFSITE POWER

AVAILABLE, “B” MOTOR-DRIVEN AFW PUMP FAILS TO START


FIGURE 14.2.7–2 STEAM GENERATOR DOME PRESSURE FOR MINIMUM STEAM GENERATOR INVENTORY CASE: OFFSITE POWER AVAILABLE, “B” MOTOR-

DRIVEN AFW PUMP FAILS TO START


FIGURE 14.2.7–3 PRESSURIZER LEVEL FOR MINIMUM STEAM GENERATOR INVENTORY CASE: OFFSITE POWER AVAILABLE, “B” MOTOR-DRIVEN AFW

PUMP FAILS TO START


FIGURE 14.2.7–4 STEAM GENERATOR FOR LIQUID MASS INVENTORY FOR MINIMUM STEAM GENERATOR INVENTORY CASE: OFFSITE TO POWER



FIGURE 14.2.7–5 STEAM GENERATOR COLLAPSED LIQUID LEVEL FOR MINIMUM STEAM GENERATOR INVENTORY CASE: OFFSITE TO POWER



FIGURE 14.2.7–6 REACTOR COOLANT SYSTEM LOOP TEMPERATURES FOR MAXIMUM PRESSURIZER LEVEL CASE: LOSS OF OFFSITE POWER, ONE

MOTOR-DRIVEN AFW PUMP FAILS TO START


FIGURE 14.2.7–7 STEAM GENERATOR DOME PRESSURE FOR MAXIMUM PRESSURIZER LEVEL CASE: LOSS OF OFFSITE POWER, ONE MOTOR-DRIVEN

AFW PUMP FAILS TO START


FIGURE 14.2.7–8 PRESSURIZER LEVEL FOR MAXIMUM PRESSURIZER LEVEL CASE: LOSS OF OFFSITE POWER, ONE MOTOR-DRIVEN AFW PUMP FAILS TO

START


FIGURE 14.2.7–9 STEAM GENERATOR LIQUID MASS INVENTORY FOR MAXIMUM PRESSURIZER LEVEL CASE: LOSS OF OFFSITE POWER, ONE



FIGURE 14.2.7–10 STEAM GENERATOR COLLAPSED LIQUID LEVEL FOR MAXIMUM PRESSURIZER LEVEL CASE: LOSS OF OFFSITE POWER, ONE



14.3 DECREASE IN REACTOR COOLANT SYSTEM FLOW

14.3.1 LOSS OF FORCED REACTOR COOLANT FLOW


The loss of forced reactor coolant flow in the primary system may result from a mechanical or electrical failure in a main reactor coolant pump (RCP) or in the power supply to these pumps. Forced coolant flow may be completely or partially lost. The limiting event initiator is that which results in the trip of all four RCPs.


The Loss of Forced Reactor Coolant Flow transient is initiated by a loss of the electrical power supplied to or a mechanical failure in a reactor coolant system (RCS) pump. These failures may result in a complete or partial loss of forced coolant flow. The immediate result of the loss of forced coolant flow is an increase in the coolant temperature as it flows through the reactor core. Prior to reactor trip, the combination of decreased flow and increased temperature poses a challenge to Departure From Nucleate Boiling (DNB) limits.


Reactor protection is provided by the following reactor trips:

1. Low reactor coolant flow;

2. Thermal margin/low pressure (TM/LP); and

3. High pressurizer pressure trip.

Reactor protection for the Loss of Forced Reactor Coolant Flow event is summarized in Table 14.3.1-1.


The power sources for the main RCPs are the most likely initiator for a loss of flow event involving more than one pump. A mechanical or electrical fault in one of the pumps will only result in a single pump loss of forced coolant flow transient. The normal power supplies for the pumps are from two buses which receive power from the main generator. Two pumps, in opposite loops, are powered from each bus. If there is a generator trip, the pumps are automatically transferred to a bus supplied from the external power lines. A generator trip with the failure of this transfer could result in a loss of power to all four pumps.

In the case of four pump operation, two situations must be considered: two pump coastdown and a total loss of forced coolant flow. Considering first the total loss of flow cases, the consequences of this postulated event are bounded by rated power operation.


The rated power case is bounding because of the reduced DNB margin for this initial state combined with the highest power to flow ratio during coastdown.

For the two pump loss of flow cases, the magnitude of the coastdown is less severe than the four pump coastdown, and the consequences of this event are bounded by the four pump loss of flow event. For the two pump flow coastdown cases, there is always some degree of forced reactor coolant flow. These events are, therefore, not as challenging as the four pump coastdown events. A comparison of the governing parameters indicates that these events are bounded by the four pump loss of flow event from full rated power conditions.

In summary, the four pump loss of flow event is the bounding event for the 14.3.1 events in all modes of operation. The only active system challenged is the reactor protection system (RPS) which is redundant and single failure proof.

The disposition of events for the Loss of Forced Reactor Coolant Flow event is summarized in Table 14.3.1-2.


This event is analyzed from full-power initial conditions. The core thermal margins are minimized at full power conditions resulting in this being the bounding mode of operation for this event. One case is analyzed for this event to assess the challenge to the DNB Specified Acceptable Fuel Design Limit (SAFDL).

The loss of coolant flow immediately results in a loss of system heat rejection capacity. This causes the primary system coolant temperature to increase. The objective of selecting input and biasing is to minimize Departure From Nucleate Boiling Ratio (DNBR). The event analysis is, therefore, biased to minimize pressure which minimizes DNBR. The steam bypass and the atmospheric dump valves are both assumed not to operate, which again most challenges the DNB SAFDL.


The transient is initiated by tripping all four primary coolant pumps. As the pumps coast down, the core flow is reduced, causing a reactor scram on low flow. No credit was taken for the RCP under speed trip. As the flow coasts down, primary temperatures increase. This increase in temperature causes a subsequent power rise due to moderator reactivity feedback. The primary challenge to DNB is from the decreasing flow rate and resulting increase in coolant temperatures.

The deterministic Minimum Departure from Nucleate Boiling Ratio (MDNBR) may violate the fuel design limit for this event. Because of this, the DNBR consequences of this event were evaluated using AREVA statistical setpoint methodology (Reference 14.3-1). The event Minimum Departure From Nucleate Boiling Ratio (MDNBR) was shown to be greater than thermal margin limits. This event does not challenge the FCMLHR limit. Therefore, LHR is not evaluated


The responses of key system variables for the deterministic case are given in Figures 14.3.1–1 to 14.3.1–7. The sequence of events is given in Table 14.3.1-3.

14.3.1.7 Conclusion

The statistical setpoint analysis demonstrates that the MDNBR limit is not penetrated by the Loss of Forced Reactor Coolant Flow event. Maximum peak pellet LHR for this event is below the FCMLHR limit.

14.3.2 FLOW CONTROLLER MALFUNCTION

There are no flow control devices on the primary RCS of Millstone Unit 2. This event is therefore not credible and need not be analyzed.

14.3.3 REACTOR COOLANT PUMP ROTOR SEIZURE


This event is initiated by an instantaneous seizure of an RCP rotor.


The RCP seizure causes an immediate reduction in RCS flow rate. As in the Loss of Forced Coolant Flow event (Event 14.3.1), the impact of losing an RCS pump is a decrease in the active flow rate in the reactor core and an increase in core temperatures. Prior to reactor trip, the combination of decreased flow and increased temperature poses a challenge to DNB limits. A pressurization of the primary system will also occur due to the heatup of the primary coolant which causes a rapid insurge into the pressurizer.


Reactor protection for the RCP rotor seizure event is provided by the low reactor coolant flow trip, TM/LP trip, and the high pressurizer pressure trip.

Reactor protection for the Reactor Coolant Pump Rotor Seizure event is summarized in Table 14.3.3-1.


This event is a concern for only rated power and power operating conditions because for other reactor operating conditions there is sufficient thermal margin so there will not be a challenge to the fuel design limits. The core heat flux to flow ratio is an excellent indicator of the potential DNB challenge for a loss of flow event. The highest ratios for this event are predicted to occur during the first few seconds of the transient from full-power rated operating conditions. The consequences of this event will therefore be bounded by a pump rotor seizure event initiated from full-power rated conditions. There is no single failure considered which could worsen the results.


The disposition of events for the Reactor Coolant Pump Rotor Seizure event is summarized in Table 14.3.3-2.


One case is analyzed for this event to maximize the challenge to the DNB limit. The bounding operating mode for this event is full-power initial conditions.


The locked rotor analysis assumes the locked pump loss coefficient given by the homologous pump curves at zero pump speed. The sequence of events is given in Table 14.3.3-3 and the responses of key system variables are given in Figures 14.3-3–1 to 14.3-3–7 for the deterministic case. This event does not challenge the FCMLHR limit. Therefore, LHR is not evaluated.

The DNBR consequences of the Loss of Flow event (14.3.1) were evaluated using AREVA statistical setpoint methodology (Reference 14.3-1), and the MDNBR was shown to be greater than thermal design limits. Because the Rotor Seizure event (14.3.3) is inherently similar to and has a deterministic MDNBR greater than the Loss of Flow event, penetration of thermal design limits is precluded for the Rotor Seizure event, as well.

14.3.3.7 Conclusion

The MDNBR limits are not exceeded by this event. The peak LHR is less than the FCMLHR limit.

14.3.4 REACTOR COOLANT PUMP SHAFT BREAK

This event is not in the current licensing basis for Millstone Unit 2 and is, therefore, not analyzed.

14.3.5 REFERENCES

14.3-1 “Statistical Setpoint/Transient Methodology for Combustion Engineering Type Reactors,” EMF-1961(P)(A), Revision 0, Siemens Power Corporation, July 2000.


TABLE 14.3.1-1 AVAILABLE REACTOR PROTECTION FOR THE LOSS OF FORCED REACTOR COOLANT FLOW EVENT


1 (4 pump operation) Low Reactor Coolant Flow Trip Thermal Margin/Low Pressure Trip High Pressurizer Pressure Trip

2 (4 pump operation) High Pressurizer Pressure Trip Technical Specification requirements on number of operating pumps

3-6 (less than 4 pump operation)

High Pressurizer Pressure Trip Technical Specification requirements on number of operating pumps


TABLE 14.3.1-2 DISPOSITION OF EVENTS FOR THE LOSS OF FORCED REACTOR COOLANT FLOW EVENT


1 Analyze

2-6 Bounded by the above, no analysis required


TABLE 14.3.1-3 EVENT SUMMARY FOR THE LOSS OF FORCED REACTOR COOLANT FLOW


Initiate Four Pump Coastdown 0.00

Letdown Flow Valve Open 0.00

Reactor Scram Signal 1.29

Rod Insertion Begins 2.44

Peak Power 2.45

MDNBR 3.7

Peak Core Average Temperature 4.10

Peak Pressurizer Pressure 5.53

Steam Line Safety Valves Open 7.35

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14.3-8

COOLANT FLOW
FIGURE 14.3.1–1 REACTOR POWER LEVEL FOR LOSS OF FORCED REACTOR

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14.3-9

R COOLANT FLOW
FIGURE 14.3.1–2 CORE AVERAGE HEAT FLUX FOR LOSS OF FORCED REACTO

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14.3-10

FIG EACTOR COOLANT FLOW
URE 14.3.1–3 REACTOR COOLANT SYSTEM TEMPERATURE FOR LOSS OF FORCED R

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14.3-11

COOLANT FLOW
FIGURE 14.3.1–4 PRESSURIZER PRESSURE FOR LOSS OF FORCED REACTOR

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14.3-12

ANT FLOW
FIGURE 14.3.1–5 REACTIVITIES FOR LOSS OF FORCED REACTOR COOL

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14.3-13

OR COOLANT FLOW
FIGURE 14.3.1–6 PRIMARY COOLANT FLOW RATE FOR LOSS OF FORCED REACT

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14.3-14

OOLANT FLOW
FIGURE 14.3.1–7 SECONDARY PRESSURE FOR LOSS OF FORCED REACTOR C


* Defense In Depth

TABLE 14.3.3-1 AVAILABLE REACTOR PROTECTION FOR THE REACTOR COOLANT PUMP ROTOR SEIZURE EVENT


1 Low Reactor Coolant Flow Trip Thermal Margin/Low Pressure Trip High Pressurizer Pressure Trip

2 High Pressurizer Pressure Trip Available Thermal Margin (1)

3-6 Available Thermal Margin (1)


TABLE 14.3.3-2 DISPOSITION OF EVENTS FOR THE REACTOR COOLANT PUMP ROTOR SEIZURE EVENT


1 Analyze

2 Bounded by the above

3-6 No analysis required


TABLE 14.3.3-3 EVENT SUMMARY FOR THE REACTOR COOLANT PUMP ROTOR SEIZURE


Reactor Coolant Pump Rotor Seizes 0.00


Rod Insertion Begins 1.23

Peak Power 1.23

MDNBR 1.7




Peak Steam Dome Pressure 6.35

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14.3-18

ROTOR SEIZURE
FIGURE 14.3-3–1 REACTOR POWER LEVEL FOR REACTOR COOLANT PUMP

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14.3-19

ROTOR SEIZURE
FIGURE 14.3-3–2 CORE AVERAGE HEAT FLUX FOR REACTOR COOLANT PUMP

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FIG NT PUMP ROTOR SEIZURE
URE 14.3-3–3 REACTOR COOLANT SYSTEM TEMPERATURES FOR REACTOR COOLA

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14.3-21

OTOR SEIZURE
FIGURE 14.3-3–4 PRESSURIZER PRESSURE FOR REACTOR COOLANT PUMP R

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14.3-22

R SEIZURE
FIGURE 14.3-3–5 REACTIVITIES FOR REACTOR COOLANT PUMP ROTO

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14.3-23

MP ROTOR SEIZURE
FIGURE 14.3-3–6 PRIMARY COOLANT FLOW RATE FOR REACTOR COOLANT PU

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14.3-24

OTOR SEIZURE
FIGURE 14.3-3–7 SECONDARY PRESSURE FOR REACTOR COOLANT PUMP R


14.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES

14.4.1 UNCONTROLLED CONTROL ROD/BANK WITHDRAWAL FROM A SUBCRITICAL OR LOW-POWER STARTUP CONDITION


Initiated by the uncontrolled withdrawal of the control rod/banks in sequence, this event results in the insertion of positive reactivity and consequently a power excursion. This event could be caused by a malfunction in the reactor control or rod control systems. The consequences of the bank withdrawal from operating Modes 2-6 are considered in this event category; the consequences at rated power and power operating initial conditions are considered in Event 14.4.2.

The control rods are wired together into preselected bank configurations. These circuits prevent the control rods from being withdrawn in other than their respective banks. Power is supplied to the banks in such a way that no more than two banks can be withdrawn at the same time and in their proper withdrawal sequence.


This event is initiated by the uncontrolled withdrawal of control rod banks in sequence. This withdrawal adds positive reactivity to the core which leads to a power excursion. As the control banks are withdrawn, the positive reactivity insertion causes a significant core power increase as the reactor approaches prompt criticality. Low coolant flow rates in the core, combined with a rapid surge of power and pronounced radial and axial power peaking, represent a challenge both to the Departure from Nucleate Boiling (DNB) and fuel centerline melt acceptance criteria. The DNB acceptance criteria may also be challenged by the reduced Reactor Coolant System (RCS) pressure for a Mode 3 initial condition. Doppler reactivity feedback from the negative Doppler coefficient limit the power excursion until the transient can be terminated by the Reactor Protection System (RPS).


The power transient is eventually terminated (as well as the control rod withdrawal) by the RPS on one of the following signals:

1. Variable overpower trip or


Reactor protection for the Uncontrolled Control Rod Bank Withdrawal from a Subcritical or Low Power Startup Condition event is summarized in Table 14.4.1-1.



The Technical Specifications (Reference 14.4-1) for Millstone Unit 2 require that the control rod drives be deenergized in Modes 4-6 whenever the RCS boron concentration is less than the refueling requirement. A rod withdrawal from these modes is therefore not considered a credible event.

During Mode 3 operations, the control rod drive mechanism may be energized provided the Technical Specification requirements that 4 RCPs are operating, the RCS temperature is greater than 500°F, the RCS pressure is greater than 2000 psia, and the variable overpower trip is operable are met. Consequently, a rod withdrawal from these operating conditions within this mode is possible. The greatest power rise for this event is obtained when it is initiated from the lowest power.

Therefore, the event initiated from a Mode 3 condition at 2000 psia will bound all other low-power or subcritical cases. The only active system challenged in this event is the RPS, which is redundant and single failure proof.

The disposition of events for the Uncontrolled Control Rod/Bank Withdrawal from a Subcritical or Low-Power Startup Condition event is summarized in Table 14.4.1-2.


As discussed in Section 14.4.1.4, the event was analyzed from a Mode 3 initial condition at 2000 psia. These conditions will bound all other low power or subcritical cases. Axial and radial power distributions for various control rod configurations, ranging from the critical configurations to all control rods fully withdrawn, were considered. Conservative system conditions were used in the analysis to bound potential initial conditions for the transient. Four coolant pumps were considered to be in operation, consistent with the Technical Specification minimum for Mode 3 operation with Control Element Assembly (CEA) drives energized and shutdown requirements met. Credit is taken only for the variable overpower trip and high pressurizer pressure trips; other trips are not modeled. The variable overpower trip setpoint was conservatively set to the zero-power initial condition of 14.6% of rated thermal power plus 12.62% to account for uncertainties in the variable overpower trip minimum setpoint, power calibration, calorimetric power, and for power decalibration allowance. The variable overpower trip delay was set to a conservatively large value of 0.7 seconds. Biased beginning-of-cycle (BOC) kinetics values were assumed to maximize the reactor power during the transient.


The event is initiated from Mode 3 with both shutdown CEA banks fully withdrawn and all regulating CEA banks fully inserted. The resultant power excursion results in a fuel temperature increase and negative Doppler reactivity feedback which limits the peak power. The transient is terminated when control rods are inserted upon a variable high power trip. The responses of key system parameters are plotted in Figures 14.4.1–1 to 14.4.1–5. The sequence of events is given in Table 14.4.1-3.


The Minimum Departure from Nucleate Boiling Ratio (MDNBR) is evaluated for conditions at the time of peak clad surface heat flux and accounts for elevated zero-power peaking. The calculated MDNBR was well above the 95/95 acceptance criterion for the HTP DNB correlation limit. This ensures that, with 95% probability and 95% confidence, DNB is not expected to occur. The peak fuel centerline temperature is calculated to be well below the melting point. Thus, no fuel failures are predicted to occur.

14.4.1.7 Conclusion

No fuel failures are predicted for this event. Therefore, the event meets the applicable acceptance criteria.

14.4.2 UNCONTROLLED CONTROL ROD/BANK WITHDRAWAL AT POWER


This event is initiated by an uncontrolled control rod/bank withdrawal from power operating conditions.


This event is initiated by an uncontrolled withdrawal of a control bank, causing a positive reactivity addition to the reactor core. This positive reactivity addition causes an increase in the core power and primary coolant system temperatures. Due to the increasing power and temperatures, the DNB limits are challenged.


The challenge to the fuel design limits is terminated by the automatic action of the RPS which terminates the bank withdrawal and inserts negative reactivity to terminate the power transient. The automatic action of the RPS is initiated as the result of one of the following signals:

1. Variable overpower trip;

2. Local power density (LPD) trip;

3. Thermal margin/low pressure (TM/LP) trip; or


Reactor protection for the Uncontrolled Control Rod/Bank Withdrawal at Power event is summarized in Table 14.4.2-1.



This event is designed to address the safety challenge posed by an uncontrolled control rod/bank withdrawal transient from power conditions. This event addresses all the power operating conditions and the rated power operating conditions. It is performed to test the adequacy of the variable overpower and TM/LP trip setpoints in mitigating the challenge to the Specified Acceptable Fuel Design Limits (SAFDL).

A rod withdrawal initiated from lower powers will provide less of a challenge to the SAFDLs due to increased initial thermal margin, a lesser amount of setpoint overshoot, and a decreased variable overpower trip setpoint resulting in a greater thermal margin at trip. The event initiated from full power will then bound those initiated from lower power conditions. This event will therefore be analyzed at full power for conditions ranging from BOC to end of cycle (EOC) for a spectrum of reactivity insertion rates. The only active system challenged by this event is the RPS, which is redundant and single failure proof.

The disposition of events for the Uncontrolled Control Rod/Bank Withdrawal at Power event is summarized in Table 14.4.2-2.


The analysis evaluates the consequences of an uncontrolled control rod bank withdrawal from rated power. A spectrum of reactivity insertion rates were evaluated in order to bound events ranging from a slow dilution of the primary system boron concentration to the fastest allowed control bank withdrawals. Specifically, the analysis encompasses reactivity insertion rates from 4

x 10 -6 to 4 x 10 -4 delta rho/sec.


The uncontrolled control bank withdrawal transients were analyzed for full-power conditions (100% of rated). The limiting uncontrolled control rod bank withdrawal at 100% power occurred

with EOC kinetics at an insertion rate of 4 x 10 -6 delta rho/sec. The MDNBR was calculated to be above the CHF correlation limit. This transient tripped on a TM/LP signal. The maximum peak pellet linear heat rate (LHR) occurs in a 100% power case which uses BOC kinetics. The variable high power and LPD trips ensure the maximum peak pellet LHR is less than the FCMLHR limit.

The sequence of events for the Uncontrolled Bank Withdrawal transient is given in Table 14.4.2-3. The transient response of key system variables are given in Figures 14.4.2–1 to 14.4.2–6.

14.4.2.7 Conclusion

Reactivity insertion transient calculations demonstrate that the DNBR limit will not be penetrated during any credible reactivity insertion transient at full power. The maximum peak pellet linear heat generation rate for this event is less than the FCMLHR limit. Applicable acceptance criteria are therefore met, and the adequate functioning of the TM/LP trip is demonstrated.


14.4.3 CONTROL ROD MISOPERATION

The control rod misoperation event encompasses a number of transients resulting from different event initiators. The specific events addressed under this event category include the following:

1. Dropped control rod or control rod bank;

2. Dropped part-length control rod;

3. Malpositioning of the part-length control rod group;

4. Statically misaligned control rod/control rod bank;

5. Single control rod withdrawal;

6. Reactivity control device removal error during refueling; and

7. Variations in reactivity load to be compensated by burnup or on-line refueling.

14.4.3.1 Dropped Control Rod/Bank


The Dropped Control Rod/Bank event is initiated by a de-energized control rod drive mechanism or by a malfunction associated with a control rod bank.


A Dropped Control Rod/Bank event is initiated by a deenergized control element drive mechanism (CEDM) or another failure in the control rod system. The reactor power initially drops in response to the insertion of negative reactivity. However, the local peaking increases due to the local effect on the power distribution. The reactor core will attempt to return to a new equilibrium at the original power level as a result of moderator and Doppler reactivity feedback. Because of the increased peaking and the potential return to the initial power level, the Dropped Control Rod/Bank event poses a challenge to the DNB margin.


If the amount of reactivity is large enough to cause a significant reduction in core power, a reactor trip could be generated by the variable overpower trip prior to returning to full power. Reactor protection for the Dropped Control Rod/Bank event is summarized in Table 14.4.3.1-1.



Since the control rod drive mechanisms are deenergized in Modes 4-6 and reactor power is limited to zero percent with keff < 0.99 in Mode 3, there will be no consequences of this event for these modes.

Ultimately, the consequences of this event are a return to power at elevated peaking conditions. Thus, the worst case is obtained when the combination of final power level, increased peaking, and core inlet temperature are maximized. This occurs for cases initiated from full-power. The full-power case thus bounds all other power operation conditions.

For a single dropped control rod, a reactor trip is not expected. Thus, a DNB evaluation assuming a return to full-power at maximum dropped rod peaking will be performed to demonstrate that the SAFDLs are not violated.

The return to power for a dropped control bank is limited by the capacity of the turbine control valve. In response to a decrease in the secondary side steam flow resulting from a drop in core power, the turbine valve will throttle open in an attempt to maintain a constant load demand. If the reactivity worth of the dropped control bank is sufficiently large, the turbine valve will not have enough excess capacity for the reactor to return to full power. The lower power level could be offset by the higher peaking factor associated with a dropped control bank. It should be noted that the operator will have multiple indications that a dropped rod/bank has occurred via CEA deviation alarms and rod bottoming signals. The only active system challenged in this event is the RPS, which is redundant and single failure proof.

The disposition of events for the Control Rod Misoperation (Dropped Control Rod/Bank) event is summarized in Table 14.4.3.1-2.


The analysis evaluates the consequences of this event from rated power conditions. A spectrum of dropped control rod/bank cases were analyzed at full power with increased radial peaking and Technical Specifications minimum primary coolant flow. Radial peaking augmentation factors for the Dropped Control Rod/Bank event are calculated at full power for different exposure conditions. Bounding radial peaking augmentation factors were used in the analysis. In addition, bounding values of control rod and bank worth were used.


The sequence of events for the limiting dropped control rod/bank case is given in Table 14.4.3.1-3. The transient response or key system parameters are given in Figures 14.4.3.1–1 to 14.4.3.1–4. The limiting case, both from the standpoint of MDNBR and peak LHR, was with a 1079.8 pcm dropped control bank.

Upon transient initiation, the core power decreased in response to the negative reactivity insertion resulting from the dropped control bank. The primary coolant and fuel temperatures decreased in


response to the falling power. Positive moderator and Doppler reactivity feedback resulted in the return to a new steady state power level. The initial decrease in the primary coolant temperatures resulted in the VHP trip being reset to a power level of 89.3% of RTP. The measured DT power exceeded the VHP trip setpoint at 88.3 seconds. Throughout the transient, the core inlet mass flow rate increased and the primary-side pressure decreased due to changes in the moderator density resulting from the primary-side cooldown.

The peak pellet LHR is calculated to be less than the FCMLHR limit. The minimum DNBR for this event is bounded by the minimum DNBR of the Section 14.3.1 loss of forced reactor coolant flow event, which is greater than thermal margin limits.

14.4.3.1.7 Conclusion

All of the cases analyzed were above the HTP 95/95 DNB safety limit and below the peak LHGR limit. Therefore, no fuel failure is predicted to occur. Applicable acceptance criteria for the Dropped Control Rod/Bank event are therefore met for Millstone Unit 2.

14.4.3.2 Dropped Part-Length Control Rod

All part-length control rods have been removed from the Millstone Unit 2 core. Therefore, this event is not applicable.

14.4.3.3 Malpositioning of the Part-Length Control Rod Group

All part-length control rods have been removed from the Millstone Unit 2 core. Therefore, this event is not applicable.

14.4.3.4 Statically Misaligned Control Rod/Bank


14.4.3.5 Single Control Rod Withdrawal


This event is initiated by the inadvertent withdrawal of a single CEA from the core. No single electrical or mechanical failure in the Rod Control System could cause the accidental withdrawal of a single CEA from the inserted CEA bank during full power operation. Procedures are available to permit the operator to withdraw a single CEA in the control bank since this feature is necessary in order to retrieve an assembly should one be accidentally dropped. The event can occur only as the result of multiple wiring failures or multiple operator actions in disregard of available event indication.

In the extremely unlikely event of simultaneous electrical failures which could result in single CEA withdrawal, the rod position indicators and deviation alarms would indicate the relative positions of the assemblies in the bank. Withdrawal of a single CEA by operator action, whether


deliberate or by a combination of errors, would similarly result in the same visual indications. The CEA Motion Inhibit prevents further rod control motion upon detection of CEA malpositioning.


The withdrawal of a single full-length CEA is initiated by the inadvertent withdrawal of a single control rod. The ensuing reactivity insertion causes core power to increase. In the event that the secondary steam dump control system does not respond to the increased power production, secondary system temperature and pressure will increase, causing a corresponding increase in primary coolant temperature. This increase in primary coolant temperature occurs slowly enough that the pressurizer pressure control system, if available, is capable of suppressing the primary pressure increase. The degradation of coolant conditions coupled with the power increase is essentially the same as expected for slow CEA bank withdrawals at power and may approach DNB conditions in the hot channel.

The single CEA withdrawal is distinguished from the withdrawal of a CEA bank by a severe radial power redistribution. High radial power peaking is localized in the region of the single withdrawn CEA and may, in severe cases, surpass the design limits. Thus, assemblies in the immediate vicinity of the withdrawn CEA may experience boiling transition for a short time period. Some fuel damage might occur.


The challenge to the fuel design limits is terminated by the automatic action of the RPS which terminates the CEA withdrawal and inserts negative reactivity to terminate the power transient. The automatic action of the RPS is initiated as the result of one of the following signals:

1. Variable overpower trip;

2. LPD trip;

3. TM/LP trip; or


Reactor protection for the Single Control Rod Withdrawal event is summarized in Table 14.4.3.5-1.


The overall system response to the withdrawal of a single CEA will be identical to the response to a slow withdrawal of a CEA bank. The only difference will be that the core will experience localized peaking in the vicinity of the withdrawn CEA that is not present if an entire bank is withdrawn. Therefore, the disposition of the single CEA withdrawal will be identical to that of the CEA bank withdrawal.


The disposition of the low to zero power bank withdrawal is addressed in Event 14.4.1. The disposition of the bank withdrawal from power operating conditions is addressed in Event 14.4.2. The disposition of events for the Single Control Rod Withdrawal event is summarized in Table 14.4.3.5-2.


This event was analyzed at rated power conditions. Radial peaking augmentation factors to account for localized peaking redistribution were utilized in the assessment of the challenge to MDNBR limits.


Radial peaking augmentation factors for single control rod withdrawal events are calculated at full power for different exposure conditions. Bounding radial peaking augmentation factors were used in the analysis. In addition, bounding value of control rod worth was used.

The deterministic MDNBR for the single rod withdrawal event is greater than the HTP correlation limit. The peak pellet LHR is calculated to be less than the FCMLHR limit. Therefore, no fuel failure is predicted to occur.


The maximum peak LHR for the single rod withdrawal event is such that fuel centerline melt is not expected. In addition, the minimum DNBR is greater than the limit. Thus, no fuel failure is predicted to occur.

14.4.3.6 Reactivity Control Device Removal Error During Refueling

Millstone Unit 2 has no reactivity control devices which are used during refueling and could inadvertently be removed. Boron dilution during refueling is considered in Event 14.4.6. Therefore, this event is not applicable.

14.4.3.7 Variations in Reactivity Load to be Compensated by Burnup or On-Line Refueling

This event considered the anticipated variations in the reactivity load of the reactor, to be compensated by means of action such as buildup and burnup of xenon poisoning, fuel burnup, on-line refueling, fuel followers, temperature moderator and void coefficients.

Provisions for xenon changes and fuel burnup are described in Chapter 3. On line refueling will not be performed on Millstone Unit 2. The core design does not include fuel followers. The safety analyses are based upon the most adverse combination of temperature, moderator and void coefficients. Therefore, this event has no significant consequences and is not analyzed.


14.4.4 STARTUP OF AN INACTIVE LOOP


This event is initiated by the startup of an inactive reactor coolant pump (RCP).


Each primary coolant loop is equipped with two single-suction centrifugal pumps, one per cold leg, which are located between the steam generator outlet and the reactor vessel inlet nozzles. A nonreversing mechanism is provided to prevent reverse rotation of the pump rotor. This feature also limits backflow through the pump under nonoperating conditions. Note that there is no backflow in the hot leg (or steam generator) associated with the side of the plant that has the inactive RCP. The inadvertent actuation of an inactive pump would therefore lead to a decrease in moderator temperature and, with a negative moderator coefficient, an increase in core reactivity with a potential increase in core power level.


Reactor protection for this event is afforded by Technical Specification requirements on shutdown margin and RCP operation. Reactor protection for the Startup of an Inactive Loop event is summarized in Table 14.4.4-1.


This event is not credible in operating Modes 1 and 2 because Technical Specifications require all four RCPs to be operating. It is not credible in Mode 6 due to administrative procedures requiring that the pumps be prevented from starting.

Technical specification requirements on shutdown margin in Modes 3-5 are such that any reactivity insertion due to an inactive loop start is not great enough to reach criticality. Thus, the consequences of this event in Modes 3-5 are minimal and no analysis is required. The disposition of events for the Startup of an Inactive Loop event is summarized in Table 14.4.4-2.

14.4.5 FLOW CONTROLLER MALFUNCTION

Millstone Unit 2 does not have any flow control devices on the primary reactor coolant loops so this event is not credible and does not need to be analyzed.


14.4.6 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION THAT RESULTS IN A DECREASE IN THE BORON CONCENTRATION IN THE REACTOR COOLANT


A dilution of the primary system boron concentration can occur as a result of adding primary grade water into the RCS via the Chemical and Volume Control System (CVCS). The greatest dilution rate occurs for operation of the CVCS charging pumps. The three available charging pumps can inject water into the primary system at a maximum rate of 147 gpm. For Modes 4, 5, and 6, only two charging pumps are to be operable for a maximum rate of 98 gpm.


A boron dilution event can occur when demineralized water is added to the primary coolant system via the CVCS resulting in decreasing boron concentration in the primary system coolant. This dilution of the primary system coolant boron concentration results in the addition of positive reactivity to the core. This event can lead to an erosion of shutdown margin for subcritical initial conditions, or a slow power excursion for at-power conditions. A boron dilution at rated or power operating conditions behaves in a manner similar to a slow uncontrolled rod withdrawal transient (Event 14.4.2).


Reactor protection for the boron dilution event during operating Modes 3-6 is provided by Technical Specification shutdown margin requirements, administrative procedures, and sufficient time for the operator to take the appropriate action in the unlikely event that a boron dilution should occur. Reactor protection for the reactor critical, power operation, and rated power operating conditions is provided by various trips and operator response time. Reactor protection for the CVCS Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant event is summarized in Table 14.4.6-1.


For boron dilutions in reactor Modes 1-6, the challenge to the SAFDLs is very similar to that of slow control rod withdrawals and can be bounded by the consequences of control rod withdrawal events as analyzed for events 14.4.2 and 14.4.1. A spectrum of control rod withdrawal reactivity addition rates is considered for Events 14.4.2 and 14.4.1, so the range of reactivity addition rates will be established to encompass the predicted reactivity addition rates for boron dilution events in Modes 1-6.

There must be 15 minutes (modes 3, 4, and 5) or 30 minutes (mode 6) from the onset of the dilution prior to a complete erosion of shutdown margin. The disposition of events for the CVCS Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant event is summarized in Table 14.4.6-2.



The boron dilution analysis evaluates the time to criticality caused by the dilution of the primary system boron and the subsequent loss of shutdown margin. This analysis determines the shutdown cooling system flow rate needed to meet the time criteria for Refueling (Mode 6), Cold Shutdown (Mode 5), and Hot Shutdown (Mode 4). The systems that would be involved in the boron dilution event, depending upon the mode of operation are the RCS, the shutdown cooling system and the CVCS.

The major differences between the operating modes are the system parameters which affect the rate at which boron dilution occurs and the boron mixing model used once the demineralized water is injected into the lower plenum of the reactor vessel. Parameters such as charging pump capacity and primary system water volume affect the dilution rate. The mixing model used depends on whether the RCPs are operating and whether the shutdown cooling system discharge is to both cold legs when the dilution is postulated to occur.

For the six modes of operation, two mixing models are used: (1) instantaneous mixing and (2) dilution front. The use of the instantaneous mixing and dilution front models is consistent with EMF-2310(P)(A) (Reference 14.4-4).In the instantaneous mixing mode, the diluting water is assumed to uniformly mix with the entire RCS volume immediately upon injection into the primary system. Instantaneous mixing is assumed to occur if one or more RCPs are in operation.

A dilution front model is used to simulate operation of the shutdown cooling system when the main RCPs are not running. It is conservatively assumed that the diluted water from the shutdown cooling system discharged to the lower plenum will not immediately mix with the entire reactor coolant due to the relatively low flow rate. Rather, the boron dilution occurs locally at the charging/shutdown cooling mixing location. The diluted mixture then flows through the RCS system until it reaches the mixing location where further dilution occurs. Thus, the RCS boron concentration can be viewed as a series of dilution fronts traveling through the RCS.

Symmetric and asymmetric variations of the dilution front model are considered. In the symmetric flow variation, diluting water is assumed to be injected into two or more cold legs located on opposite loops of the RCS. In the asymmetric flow variation, diluting water is assumed to be injected into only one cold leg. The asymmetric flow variation is more limiting than the symmetric flow variation. In either case, the time to criticality is reduced if the shutdown cooling system flow is reduced.

The boron dilution analysis also included calculations to determine the maximum and minimum reactivity insertion rates during Full Power Operation (Mode 1). Reference 14.4-4 indicates that in the event of an unplanned Boron dilution during power escalation while in Startup (Mode 2), the plant status is such that minimal impact will result. The plant will slowly escalate in power and will activate a power-related trip. Boron dilution analysis does not need to include calculations to determine the maximum and minimum reactivity insertion rates during Startup (Mode 2) under this methodology. These values are used to confirm that the reactivity insertion rates used for the uncontrolled rod withdrawal analysis remain bounding of the boron dilution event.



Table 14.4.6-3 presents the minimum shutdown cooling flow for Modes 4 through 6 required to avoid complete erosion of shutdown margin within the required time. These results are based on the asymmetric dilution front model. For Modes 4 to 6, the reactor vessel is filled to the mid-plane of the coolant loop nozzles. This is the minimum expected RCS volume during shutdown cooling operations. For these modes, only two charging pumps were considered to be operable. A reactivity shutdown margin of 3.6% was used for all operating modes except Mode 6. For Mode 6, a Keff of 0.95 was used. The results indicate that as long as the shutdown cooling system flow remains above the flowrates provided in Table 14.4.6-3, the operator response time criteria will be satisfied.

Table 14.4.6-4 presents the results of the calculated time to loss of shutdown margin for Modes 1 through 5 based on the use of the instantaneous mixing assumption. The erosion of shutdown margin following trip in Mode 1 is bounded by the Mode 2 Boron Dilution analysis, as indicated in Reference 14.4-4. For Modes 2 and 3, three charging pumps were assumed to be operable and only two charging pumps were considered to be operable for Modes 4 and 5. The results indicate that the time to loss of shutdown margin criteria is satisfied for all cases in which an RCS pump is in operation.

For Mode 1, the Reactivity Insertion Rate associated with a Boron dilution event is bounded by the rates of reactivity insertion from a rod withdrawal event.


The results of the boron dilution analysis show that there is not a complete erosion of shutdown margin within 15 minutes for modes 1 through 5 and 30 minutes in mode 6. The operator can initiate reboration to recover the shutdown margin. For all modes there is adequate time for the operator to manually terminate the source of dilution flow.

14.4.7 INADVERTENT LOADING AND OPERATION OF A FUEL ASSEMBLY IN AN IMPROPER POSITION


14.4.8 SPECTRUM OF CONTROL ROD EJECTION ACCIDENTS


This accident is initiated by a failure in the control rod drive pressure housing which could result in the rapid ejection of a control rod.


This event is initiated by a failure in the CEDM pressure housing causing a rapid ejection of the affected control rod. This results in a rapid loss of negative reactivity causing a nuclear power


transient. In addition to the power transient, the ejected rod results in a highly perturbed power distribution which, coupled with the power transient, could possibly lead to localized fuel damage. Also, the rapid nuclear power excursion can result in a significant short-term heatup of the coolant with a resultant RCS pressure increase, although on the long-term the RCS will depressurize due to the break in the reactor coolant pressure boundary.


Reactor protection for the Spectrum of Control Rod Ejection Accidents is summarized in Table 14.4.8-1. Doppler feedback inherent in the fuel also limits the nuclear power excursion.


This event is not a concern in Modes 4-6 as all control rods are required to be fully inserted per Technical Specifications and no one CEA possesses enough reactivity worth to overcome the minimum allowed shutdown margin. The fuel energy content is maximized by starting from rated power initial conditions, so the consequences of this event are bounding for power operating initial conditions. However, because of the complex interaction of the ejected rod worth and ejected peaking factor (which are maximized at hot zero power (HZP) operating conditions, and Doppler feedback effects, it is difficult to bound the consequences of the event for either rated power or HZP operating conditions without additional analysis. Therefore, the consequences of this event are analyzed for both rated power and HZP operating conditions. Separate evaluations are performed for deposited enthalpy, DNBR, and RCS pressurization for each of these initial operating conditions.

In addition to the rod ejection, this event is characterized by a small-break loss-of-coolant accident (SBLOCA) as the failure of the pressure housing is assumed to result in a breach of the primary coolant pressure boundary. The short-term aspects of the event are dominated by the rod ejection, while the long-term aspects are dominated by the SBLOCA. The limiting SBLOCA is evaluated in Event 14.6.5 and is typically a cold leg break. In the rod ejection, the break is more characteristic of a hot leg break and therefore will be bounded by the SBLOCA. Also in the rod ejection, a much earlier reactor trip occurs, resulting in lower powers and temperatures than in Event 14.6.5. It is concluded that the long-term aspects of the rod ejection are bounded by those of Event 14.6.5 for small breaks. Thus, only the short-term rod ejection consequences need be evaluated. Note also that the limiting 14.6.5 event occurs for rated power operating conditions.

The disposition of events for the Spectrum of Control Rod Ejection Accidents is summarized in Table 14.4.8-2.


Due to the complex interaction of the ejected rod worth, ejected peaking factor and Doppler feedback effects, it is difficult to bound the consequences of the event for either rated power or HZP operating conditions without analysis. Therefore, each of these conditions were evaluated at both BOC and EOC for deposited enthalpy, DNBR and pressurization concerns.


For the evaluation of the DNBR and pressurization consequences, concurrent loss of offsite power is assumed. No credit is taken for the variable overpower trip in the analysis of the pressurization consequences of a control rod ejection.


The hot full-power (HFP) control rod ejection event was determined to deposit more energy into the primary system than the event initiated from HZP. Therefore, in terms of the event acceptance criteria, the HFP event poses a greater challenge than the HZP event. For this analysis, the event was assumed to initiate from HFP at 102% of rated full power.

To assess the acceptability of the outcome of an HFP rod ejection event, two cases were examined. The first case determines the maximum pressurization potential of the primary system during this event. The second case evaluates the MDNBR. For both the maximum pressurization and minimum DNB case, BOC and EOC kinetics were employed to establish the respective limiting cases.

The limiting minimum DNB case is calculated to occur for BOC kinetics. Core boundary conditions used to evaluate the DNBR conservatively account for depressurization due to the postulated breach in the CEDM housing. As a consequence of this event, less than 11.5% of the fuel rods are calculated to fail due to penetration of DNBR limits. The responses of key system parameters are shown in Figures 14.4.8–1 to 14.4.8–6.

The maximum pressurization case occurs for EOC kinetics. The peak RCS pressure at the bottom of the reactor vessel remains below 110% of the pressure vessel design limit. The peak RCS pressure is conservatively calculated to be 2748 psia. Key system parameters for the overpressure case are plotted in Figures 14.4.8–7 to 14.4.8–12.

The sequence of events for the Control Rod Ejection transient is given in Tables 14.4.8-3 and 14.4.8-4.

The deposited enthalpy portion of the rod ejection accident has been evaluated with the procedures developed in the Generic Rod Ejection Analysis (Reference 14.4-3). The ejected rod worths and hot pellet peaking factors were calculated using the PRISM code. No credit was taken for the power flattening effects of Doppler or moderator feedback in the calculation of ejected rod worths or resultant peaking factors. The calculations performed used a full-core three-dimensional PRISM model. The pellet energy deposition resulting from an ejected rod was conservatively evaluated explicitly for BOC and EOC conditions. The rod ejection accident was found to result in an energy deposition of less than the 280 cal/g limit as stated in Regulatory Guide 1.77. The significant parameters for the analyses, along with the results, are summarized in Table 14.4.8-5.


14.4.8.7 Conclusion

The maximum RCS pressure does not exceed 110% of the design pressure. Less than 11.5% of the core will experience fuel failure due to penetration of DNBR limits. Deposited enthalpy is less than the limit of 280 cal/g.

14.4.8.8 Radiological Consequences

Two release paths are considered independently for the rod ejection accident. Each release path is considered independently as the only one available. The actual doses for the accident would be a composite of doses resulting from portions of the release going out the two different pathways.

Scenario 1: A postulated CREA that releases the failed fuel activity into the RCS, which is released in its entirety, into containment via the ruptured control rod drive mechanism housing, is mixed in the free volume of the containment and then released at containment Technical Specification leak rate. Releases occur via the Millstone stack and the Unit 2 containment.

Scenario 2: A postulated CREA that releases the failed fuel activity into the RCS which is then transmitted to the secondary side via steam generator tube leakage. The condenser is assumed to be unavailable due to a loss of offsite power. Releases occur from both steam generators via the MSSVs and the ADVs.

Scenario 1: Containment Release

Subsequent to a CREA, the following activity is assumed to be instantaneously released and to homogeneously mix in the free volume of containment.

• 11.5% of the core gap activity and consideration of a peaking factor of 1.69

The activity transport model assumes full enclosure building bypass until the enclosure building has achieved drawdown to negative pressure. After the drawdown time, 1.4% of the activity that leaks from the containment completely bypasses the enclosure building for the first 24 hours of the accident, after which it is reduced by 50% for the duration of the accident.

Scenario 2: Release via the MSSVs/ADVs

Following a CREA, the activity available for release via the secondary system consists of:

• Steam Generator tube leakage containing 11.5% of the core activity and consideration of a peaking factor of 1.69

It is assumed that offsite power is lost, therefore the main condenser is not available and releases are via the MSSVs/ADVs from both steam generators. The releases from both steam generators continue for about 16 hours until shutdown cooling commences. During this 16 hour period, reactor coolant is assumed to leak into the steam generators at a maximum leak rate of 150 gpd


per steam generator. The noble gases that enter the steam generators are released directly to the environment without holdup while the iodine activity is released from the steam generators in proportion to the steaming rate and the partition factor.

The assumptions used for the radiological consequences of a CREA are listed in Table 14.4.8-6. The radiological consequences of a CREA are presented in Table 14.4.8-7 and are within the guidelines of 10 CFR 50.67 and Regulatory Guide 1.183.

14.4.9 SPECTRUM OF ROD DROP ACCIDENTS (BOILING WATER REACTOR)

Millstone Unit 2 is not a Boiling Water Reactor and as such this event is not applicable.

14.4.10 REFERENCES



14.4-3 “A Generic Analysis of the Control Rod Ejection Transient for Pressurized Water Reactors,” XN-NF-78-44(A), Exxon Nuclear Company, October 1983.

14.4-4 SRP Chapter 15 Non-LOCA Methodology for Pressurized Water Reactors,” EMF-2310(P)(A), Revision 1, Framatome ANP Inc., June 2004.


(1) Control grade. Provides defense in depth. Not credited in any safety analysis event.

TABLE 14.4.1-1 AVAILABLE REACTOR PROTECTION FOR THE UNCONTROLLED CONTROL ROD/BANK WITHDRAWAL FROM A SUBCRITICAL OR LOW-POWER

STARTUP CONDITION EVENT


1 Considered as FSAR Event 14.4.2



Rod Withdrawal Prohibit on Variable Overpower Pretrip

Alarm (1)


Rod Withdrawal Prohibit on Variable Overpower Pretrip

Alarm (1)

4-6 Not a Credible Event; No Analysis Required


TABLE 14.4.1-2 DISPOSITION OF EVENTS FOR THE UNCONTROLLED CONTROL ROD/BANK WITHDRAWAL FROM A SUBCRITICAL OR LOW-POWER STARTUP

CONDITION EVENT


1 Considered as FSAR Event 14.4.2

2 Bounded by Mode 3

3 Analyze at 2,000 psia



TABLE 14.4.1-3 EVENT SUMMARY FOR THE UNCONTROLLED BANK WITHDRAWAL FROM LOW-POWER EVENT


Bank Withdrawal Begins 0.00

Variable Overpower Trip Setpoint Reached 37.6

Scram Reactivity Insertion Begins 38.8

Peak Nuclear Power (155.7% of rated) 39.0

Peak Core Heat Flux (58.0% of rated) 40.0

Peak Reactor Vessel Upper Plenum Coolant Temperature

41.2


FIGURE 14.4.1–1 REACTOR POWER LEVEL FOR LOW POWER BANK WITHDRAWAL


FIGURE 14.4.1–2 CORE AVERAGE HEAT FLUX FOR LOW POWER BANK WITHDRAWAL


FIGURE 14.4.1–3 REACTOR COOLANT TEMPERATURES FOR LOW POWER BANK WITHDRAWAL


FIGURE 14.4.1–4 PRESSURIZER PRESSURE FOR LOW POWER BANK WITHDRAWAL


FIGURE 14.4.1–5 REACTIVITIES FOR LOW POWER BANK WITHDRAWAL



TABLE 14.4.2-1 AVAILABLE REACTOR PROTECTION FOR THE UNCONTROLLED CONTROL ROD/BANK WITHDRAWAL AT POWER EVENT



Local Power Density Trip

Thermal Margin/Low Pressure Trip


Rod Withdrawal Prohibit Action on Variable Overpower or

TM/LP Pretrip Alarm (1)

2-6 Not considered in this section


TABLE 14.4.2-2 DISPOSITION OF EVENTS FOR THE UNCONTROLLED CONTROL ROD/BANK WITHDRAWAL AT POWER EVENT


1 Analyze at rated power

2-6 No analysis required; not considered in this section


TABLE 14.4.2-3 EVENT SUMMARY FOR THE UNCONTROLLED ROD/BANK WITHDRAWAL EVENT FOR THE LIMITING 100% POWER CASE


Start Rod Withdrawal 0.00

Letdown Flow Valve Open 0.00

TM/LP Trip Signal 511.96

Turbine Stop Valve Closed 512.88

Peak Power Level 513.32

MDNBR 513.36




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FIGURE 14.4.2–1 REACTOR CORE POWER FOR AN UNCONTROLLED BANK WITH

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FIGURE 14.4.2–4 PRESSURIZER PRESSURE FOR AN UNCONTROLLED BANK WITH

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FIGURE 14.4.2–5 REACTIVITIES FOR AN UNCONTROLLED BANK WITHDRAW

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DRAWAL AT POWER
FIGURE 14.4.2–6 SECONDARY PRESSURE FOR AN UNCONTROLLED BANK WITH


(1) Provides defense in depth

TABLE 14.4.3.1-1 AVAILABLE REACTOR PROTECTION FOR THE DROPPED CONTROL ROD/BANK EVENT



Thermal Margin/Low Pressure Trip

Local Power Density Trip

Available Thermal Margin (1)


Available Thermal Margin (1)

3-6 No Significant Consequences for these Reactor Operational Modes


(1) Provides defense in depth.

TABLE 14.4.3.1-2 DISPOSITION OF EVENTS FOR THE DROPPED CONTROL ROD/BANK EVENT



2 Bounded by the above; no analysis required

Available Thermal (1)



TABLE 14.4.3.1-3 EVENT SUMMARY FOR THE LIMITING DROPPED CONTROL ROD/BANK CASE


Minimum Worth Control Rod Drops into Core 0.0

DT Power Exceeds VHP Trip Setpoint 88.3

MDNBR and Peak LHGR occur 89.5

Analysis Terminated 100.0


FIGURE 14.4.3.1–1 REACTOR POWER LEVEL FOR THE LIMITING DROPPED CONTROL ROD/BANK CASE


FIGURE 14.4.3.1–2 REACTOR COOLANT SYSTEM TEMPERATURES FOR THE LIMITING DROPPED CONTROL ROD/BANK CASE


FIGURE 14.4.3.1–3 PRESSURIZER PRESSURE FOR THE LIMITING DROPPED CONTROL ROD/BANK CASE


FIGURE 14.4.3.1–4 SECONDARY PRESSURE FOR THE LIMITING DROPPED CONTROL ROD/BANK CASE



TABLE 14.4.3.5-1 AVAILABLE REACTOR PROTECTION FOR THE SINGLE CONTROL ROD WITHDRAWAL EVENT


1 Variable Overpower Trip Local Power Density Trip Thermal Margin/Low Pressure Trip High Pressurizer Pressure Trip Rod Withdrawal Prohibit Action on Variable Overpower

or TM/LP Pretrip Alarm (1)

2 Variable Overpower Trip High Pressurizer Pressure Trip Rod Withdrawal Prohibit on Variable Overpower Pretrip

Alarm (1)

3 Variable Overpower Trip Rod Withdrawal Prohibit on Variable Overpower Pretrip

Alarm (1)



(1) Mode 2 operation is dispositioned as bounded by Mode 1 operation because the MDNBR for an Uncontrolled Bank Withdrawal from Startup (Event 14.4.1) was found to be bounded by the MDNBR for an Uncontrolled Bank Withdrawal at Power (Event 14.4.2).

TABLE 14.4.3.5-2 DISPOSITION OF EVENTS FOR THE SINGLE CONTROL ROD WITHDRAWAL EVENT



2 Bounded by Mode 1 (1)

3 Bounded by the above



TABLE 14.4.4-1 AVAILABLE REACTOR PROTECTION


1, 2, 6 Not Applicable

3-5 Technical Specification Requirements on Shutdown Margin and Reactor Coolant Pump Operation


TABLE 14.4.4-2 DISPOSITION OF EVENTS FOR THE STARTUP OF AN INACTIVE LOOP EVENT


1, 2, 6 Not Applicable

3-5 No analysis required; minimal consequences


TABLE 14.4.6-1 AVAILABLE REACTOR PROTECTION FOR CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION THAT RESULTS IN A DECREASE IN

THE BORON CONCENTRATION IN THE REACTOR COOLANT EVENT


1 Local Power Density Trip

Variable Overpower Trip





3-6 Technical Specification Shutdown Margin Requirements

Administrative Procedures

Operator Response Time


TABLE 14.4.6-2 DISPOSITION OF EVENTS FOR THE CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION THAT RESULTS IN A DECREASE IN THE

BORON CONCENTRATION IN THE REACTOR COOLANT EVENT


1-6 Analyze for loss of shutdown margin


(1) The required flows do not include SDC flow measurement uncertainties. Plant procedures maintain the SDC flowrate at a higher value to account for instrument uncertainty.

TABLE 14.4.6-3 SUMMARY OF RESULTS FOR THE BORON DILUTION EVENT ASYMMETRIC DILUTION FRONT MODEL

Reactor Operational Mode

Minimum Analytical Required SDC Flow to Satisfy

Licensing Criteria for Operator Response Time

(gpm) (1)

Licensing Criteria for Operator Response Time

(minutes)

Mode 6 600 30

Mode 5 600 15

Mode 4 600 15


TABLE 14.4.6-4 SUMMARY OF RESULTS FOR THE BORON DILUTION EVENT INSTANTANEOUS MIXING MODE

Reactor Operational ModeCalculated Time to Loss of

Shutdown Margin (minutes)

Licensing Criteria for Time to Loss of Shutdown Margin

(minutes)

Mode 5 62 15

Mode 4 77 15

Mode 3 62 15

Mode 2 62 15


TABLE 14.4.8-1 AVAILABLE REACTOR PROTECTION FOR THE SPECTRUM OF CONTROL ROD EJECTION ACCIDENTS








4-6 No Reactor Protection Required; Ejected Rod Worth Less than the Technical Specification Minimum Shutdown Margin. No Significant Consequence for this Operating Condition.


TABLE 14.4.8-2 DISPOSITION OF EVENTS FOR THE SPECTRUM OF CONTROL ROD EJECTION ACCIDENTS


1 Analyze for short-term response. Long-term bounded by Event 14.6.5

2, 3 Analyze



TABLE 14.4.8-3 EVENT SUMMARY FOR A CONTROL ROD EJECTION (MAXIMUM PRESSURIZATION CASE)


Control Rod Ejects 0.00

Charging Pumps On 0.00

Pressurizer Heaters On 0.00


Peak Power 5.61

Pressurizer Safety Valves Open 5.94






TABLE 14.4.8-4 EVENT SUMMARY FOR A CONTROL ROD EJECTION MINIMUM DEPARTURE FROM NUCLEATE BOILING RATIO CASE


Control Rod Ejects 0.00

Letdown Valve Open 0.00


Peak Power 4.10

Peak Core Average Heat Flux 4.22

MDNBR 4.22





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(a) The contribution to the total pellet energy deposition is a function of initial fuel enthalpy, maximum control rod worth, Doppler coefficient, and delayed neutron fraction. The energy deposition contribution values and factors are derived from data calculated in the generic analysis of the control rod ejection transient document XN-NF-78-44.

(b) Total pellet energy deposition (cal/g) is calculated by the equation: Total (cal/g) = (C+D) * (E) * (F).

TABLE 14.4.8-5 DNBOUNDING BEGINNING OF CYCLE/END OF CYCLE EJECTED ROD ANALYSIS

HFP HZP

ValueContribution(a) to Energy

Deposition ValueContribution (a) to Energy

Deposition

A. 103.4 cal/g --- 18.0 cal/g ---

B. Generic Initial Fuel Enthalpy

40.8 cal/g --- 16.7 cal/g ---

C. Delta Initial Fuel Enthalpy

62.6 cal/g 62.6 cal/g 1.3 cal/g 1.3 cal/g

D. Maximum Control Rod Worth

200 pcm 131.4 cal/g 800 pcm 109.1 cal/g

E. Doppler Coefficient -0.8 pcm/°F 1.17 -0.8 pcm/°F 1.31

F. Delayed Neutron Fraction 0.0045 1.06 0.0045 1.28

G. Power Peaking Factor 6.0 --- 14.0 ---

Total Fuel Enthalpy 240.6 cal/g (b) 185.1 cal/g (b)


TABLE 14.4.8-6 CREA RADIOLOGICAL ANALYSIS ASSUMPTIONS

Core Power Level 2754 Mwt

Failed Fuel Percentage 11.5%

Peaking Factor 1.69

Percentage of Core Activity in Gap 10% Noble Gas

10% Halogens

Composition of Iodine in the Core Gap (particulate/elemental/organic)

95 / 4.85 / 0.15 % - containment

0 / 97 / 3 % - secondary side

Reactor Coolant Mass 430,000 lbs

Steam Generator Minimum Mass 100,000 lbs/SG

Containment Free Volume 1.899E6 ft3

Containment Leak Rate 0-1 day: 0.5% vol per day

1-30 days: 0.25% vol per day

Enclosure Building Bypass Fraction 1.4%

Time Before Enclosure Building Filtration System (EBFS) is Fully Functional

170 seconds

Enclosure Building Filter Efficiency 70 / 70 / 70% (1)

(particulate/elemental/organic)

Site Boundary Meteorology X/Q’s

Ground Level Release

EAB: 0 - 2 hr 3.66E-04

LPZ: 0 - 4 hr 4.80E-05

4 - 8 hr 2.31E-05


(1) 70% is a conservative analysis assumption for some iodine species. Technical Specifications can support assumptions for filter efficiencies of 90% for all iodine species.

8 - 24 hr 1.60E-05

24 - 96 hr 7.25E-06

96 - 720 hr 2.32E-06

Millstone Stack Release (includes fumigation):

EAB: 0 - 2 hr 1.00E-04

LPZ: 0- 4 hr 2.69E-05

4 - 8 hr 1.07E-05

8 - 24 hr 6.72E-06

24 - 96 hr 2.46E-06

96 - 720 hr 5.83E-07

Control Room Breathing Rate 3.5E-04 m3/sec

Control Room Isolation Time post-accident 105 seconds


Control Room Inleakage During Isolation 200 cfm

Control Room Emergency Filtered Recirculation Rate (from 1 hour after isolation)

2,250 cfm


Ground Millstone Stack ADV

0 - 2 hr 3.00E-3 2.51E-4 7.40E-3

2 - 4 hr 1.87E-3 2.51E-4 5.71E-3

4 - 8 hr 1.87E-3 1.96E-5 5.71E-3

8 - 24 hr 6.64E-4 5.46E-6 2.13E-3

24 - 96 hr 5.83E-4 3.43E-7 1.74E-3

96 - 720 hr 4.97E-4 6.44E-9 1.43E-3


Control Room Filter Efficiency (particulate/elemental/organic) 70 / 70 / 70 %(1)

Dose Conversion Factors Federal Guideline Reports 11 and 12

TABLE 14.4.8-6 CREA RADIOLOGICAL ANALYSIS ASSUMPTIONS (CONTINUED)


TABLE 14.4.8-7 RADIOLOGICAL CONSEQUENCES OF A CREA

CREAEAB,

rem-TEDELPZ,

rem-TEDEControl Room,

rem-TEDE

Containment Release 5.4 E -01 4.7 E -01 1.6E+00

Secondary Side Release 7.9 E -01 1.8 E -01 3.9E+00

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E 14.4.8–1 CORE POWER FOR A CEA EJECTION (MINIMUM DEPARTURE FOR NUCL

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E 14.4.8–2 CORE AVERAGE HEAT FLUX FOR A CEA EJECTION (MINIMUM DEPARTURATIO CASE)

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FIGU MINIMUM DEPARTURE FOR
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FIGU E FOR NUCLEATE BOILING
RE 14.4.8–4 PRESSURIZER PRESSURE FOR A CEA EJECTION (MINIMUM DEPARTURRATIO CASE)

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FIGUR EATE BOILING RATIO CASE)
E 14.4.8–5 REACTIVITIES FOR A CEA EJECTION (MINIMUM DEPARTURE FOR NUCL

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URE 14.4.8–6 SECONDARY PRESSURE FOR A CEA EJECTION (MINIMUM DEPARTURRATIO CASE)

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SURE)
FIGURE 14.4.8–7 CORE POWER FOR A CEA EJECTION (OVERPRES

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RPRESSURE)
FIGURE 14.4.8–8 CORE AVERAGE HEAT FLUX FOR A CEA EJECTION (OVE

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OVERPRESSURE)
FIGURE 14.4.8–9 PRIMARY SYSTEM TEMPERATURES FOR A CEA EJECTION (

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PRESSURE)
FIGURE 14.4.8–10 PRESSURIZER PRESSURE FOR A CEA EJECTION (OVER

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FIGURE 14.4.8–11 REACTIVITIES FOR A CEA EJECTION (OVERPRE

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PRESSURE)
FIGURE 14.4.8–12 SECONDARY PRESSURE FOR A CEA EJECTION (OVER


14.5 INCREASES IN REACTOR COOLANT SYSTEM INVENTORY

14.5.1 INADVERTENT OPERATION OF THE EMERGENCY CORE COOLING SYSTEM THAT INCREASES REACTOR COOLANT INVENTORY


14.5.2 CHEMICAL VOLUME AND CONTROL SYSTEM MALFUNCTION THAT INCREASES REACTOR COOLANT INVENTORY

This event is not in the current licensing basis for Millstone Unit 2 and therefore is not analyzed. The potential consequences of diluting the primary system boron concentration are addressed in Event 14.4.6.


14.6 DECREASES IN REACTOR COOLANT INVENTORY

14.6.1 INADVERTENT OPENING OF A PRESSURIZED WATER REACTOR PRESSURIZER PRESSURE RELIEF VALVE


The event is postulated to occur as a result of the inadvertent opening of one or more pressurizer pressure relief or safety valves due to an electrical or mechanical failure. The limiting event is obtained by assuming the inadvertent opening of a pressurizer safety valve which bounds the capacity of two pressurizer power-operated relief valves (PORVs).


The opening of the pressurizer pressure relief valve or safety valve results in a blowdown of primary coolant as steam through the faulted valves. Primary system pressure drops rapidly until the pressurizer liquid is depleted, and then quite rapidly to a pressure determined by the saturation curve at the temperature of the coolant in the upper vessel head. Reactor scram will occur on thermal margin/low pressure (TM/LP) before the pressurizer liquid is depleted, terminating the challenge to Specified Acceptable Fuel Design Limits (SAFDLs). In this initial stage, pressurizer heaters would actuate in an attempt to maintain pressure, but would be turned off on a low-level signal before the heater elements were uncovered.


The TM/LP trip provides initial protection against loss of thermal margin and possible fuel damage. Reactor protection for the Inadvertent Opening of a Pressurized Water Reactor (PWR) Pressurizer Pressure Relief Valve event is summarized in Table 14.6.1-1.


The event proceeds as a depressurization of the primary coolant system with a loss of inventory. The core power and primary loop temperatures are relatively unaffected by the pressure drop. Thus, a short term challenge to the SAFDLs exists due to the depressurization prior to scram. There is also a long term concern in that if primary inventory cannot be restored and maintained, core uncovery may result.

The greatest challenge to core uncovery exists at rated power conditions when the core power and primary coolant stored energy are maximized. The greatest challenge to the SAFDLs occurs for the event initiated at rated power where the margin to Departure from Nucleate Boiling (DNB) is minimized.

An evaluation of the SAFDL challenge is also made for 5% power operating conditions in Mode 2 when the TM/LP trip may be bypassed. In this mode, the primary system may depressurize below the TM/LP setpoint pressure without an automatic reactor trip occurring. The Safety


Injection System (SIS) will, however, be available to inject boron and provide for inventory makeup.

The disposition of events for the Inadvertent Opening of a PWR Pressurizer Pressure Relief Valve event is summarized in Table 14.6.1-2.


As discussed above, this event is analyzed for Minimum Departure from Nucleate Boiling Ratio (MDNBR) for both Modes 1 (full power), and 2 (startup). The startup power case is analyzed because the TM/LP trip can be manually bypassed below 5% power.

The system response for the full power case was evaluated by using PTSPWR2 (Reference 14.6-1). The full power event MDNBR was calculated using XCOBRA-IIIC (Reference 14.6-2).

The system response for the startup case was determined by conservative problem constraints. The maximum power was limited to 7% of the rated power. Above this power the assumed TM/LP trip bypass is automatically removed. The system pressure is conservatively assumed to be at the core inlet saturation pressure. The core inlet temperature is assumed to be at a level consistent with a maximum power rise of 7% and a conservative time delay before the SIS terminates the event. XCOBRA-IIIC was used with these system responses to predict the hot channel mass flux required for the critical heat flux calculation. The thermal margin was conservatively determined by the Modified Barnett critical heat flux correlation (Reference 14.6-3), with the system pressure reduced to the 725 psia upper limit of the Modified Barnett correlation.


The sequence of events for the full power analysis are given in Table 14.6.1-3. Figures 14.6.1–1 to 14.6.1–6 show the transient response for key system variables. The MDNBR for this event initiated from full power is above the CHF correlation limit. This event does not challenge the FCMLHR limit. Therefore, LHR is not evaluated.

The startup mode case resulted in a minimum critical heat flux ratio of above 10, as calculated by the Modified Barnett correlation. The peak pellet LHR is less than the full power value. Thus, the startup mode is bounded by the full power mode.

The High Pressure Safety Injection (HPSI) system has been shown to have sufficient capacity to compensate for the loss of primary coolant mass through the inadvertent opening of the pressurizer pressure relief valves. Analysis has shown that core uncovery does not occur during this event.


The results of the analysis demonstrate that the event acceptance criteria are met since the MDNBR predicted for the full power case is greater than the DNBR safety limit and the minimum Critical Heat Flux Ratio (CHFR) predicted for the startup mode case is greater than the Modified


Barnett Critical Heat Flux (CHF) limit. The correlation limits assure with 95% probability and 95% confidence, that DNB is not expected to occur; therefore, no fuel is expected to fail. The FCMLHR limit is not violated in this event.

14.6.2 RADIOLOGICAL CONSEQUENCES OF THE FAILURE OF SMALL LINES CARRYING PRIMARY COOLANT OUTSIDE OF CONTAINMENT

Millstone Unit 2 does not have any instrument lines connected to the reactor coolant system (RCS) which penetrate the containment. A break in either the letdown line or a RCS sample line is not in the current licensing basis for Millstone Unit 2. Therefore, this event is not analyzed.

14.6.3 RADIOLOGICAL CONSEQUENCES OF STEAM GENERATOR TUBE FAILURE


The event is initiated by a loss of integrity in a single tube in a steam generator, resulting in a flow of primary side reactor coolant water into the secondary side.


Experience with nuclear steam generators indicates that the probability of complete severance of a tube is small. The more probable modes of failure are those involving the occurrence of pinholes or small cracks in the tubes, and of cracks in the seal welds between the tubes and tube sheet.

A leaking steam generator tube would allow transport of primary coolant into the main steam system. Radioactivity contained in the primary coolant would mix with shell side water in the affected steam generator. Some of this radioactivity would be transported by steam to the turbine and then to the condenser. Noncondensible radioactive materials would then be passed to the atmosphere through the condenser air ejector discharge via the Plant stack. The vent path is via the Millstone stack until actuation of an Enclosure Building Filtration Actuation Signal (EBFAS). Actuation of EBFAS automatically isolates the vent path to the Millstone stack after which the Operators manually align the vent path to the Unit 2 stack.

The radioactive products would be sensed by the condenser air ejector radiation monitor or the stack radiation monitor. These monitors have audible alarms that will be annunciated in the control room to alert the operator to abnormal activity levels so that corrective action could be taken.

The behavior of the systems will vary depending upon the size of the steam generator tube failure. For small leaks the chemical and volume control charging pumps will be able to maintain the necessary primary coolant inventory and an automatic reactor trip will not occur. The gaseous fission products will be released from the main steam system at the air ejector discharge and will be discharged via the Plant stack. Nonvolatile fission products will tend to concentrate in the water of the steam generators.


For leaks larger than the capacity of the charging pumps, the pressurizer water level and pressure will decrease and a reactor trip will occur. Upon reactor trip, the turbine will trip and the steam system atmospheric dump valves, steam generator safety valves and the turbine bypass valves will open. In this case it is possible that in addition to the noble fission gases a substantial amount of the radioiodines contained in the secondary system may also be released to the atmosphere through the steam generator safety valves and atmospheric dump valves.

The amount of radioactivity released increases with break size. For this analysis, a double-ended break of one tube was assumed. The selection of one double-ended break as an upper limit is conservatively based upon the experience obtained with other steam generators.


The leak rate through the double-ended rupture of one tube is greater than the maximum flow available from the charging pumps. Therefore, the Primary Coolant system pressure will decrease and a low pressurizer pressure trip or TM/LP trip will occur. The thermal margin trip has a low pressure floor below which trip will always occur. Following the reactor trip the Primary Coolant System is cooled by exhausting steam through the atmospheric dump valves, steam generator safety valves, and turbine bypass valves. The radioactivity exhausted through the atmospheric dump valves and steam generator safety valves passes directly to the atmosphere. The radioactivity exhausted through the turbine bypass valves flows to the condenser where the gaseous products remaining are vented to the atmosphere through the condenser air ejector and Plant stack. Due to loss of offsite power, a release pathway via the condenser is not credited.

Reactor protection for the Radiological Consequences of Steam Generator Tube Failure event is summarized in Table 14.6.3-1.


The radiological consequences of a steam generator tube rupture (SGTR) accident are maximized at rated power operation due to the stored energy in the primary coolant which must be removed by the steam generators in order to bring the primary and secondary systems into pressure equilibrium, thereby terminating the primary to secondary leak.

The challenge to the SAFDLs exists due to the depressurization prior to scram. As such, this challenge is very similar to that which exists due to the inadvertent opening of a pressurizer relief valve (Event 14.6.1). Since the depressurization rates associated with Event 14.6.1 are substantially larger than those encountered for this event, the corresponding pressure undershoot will also be greater. Event 14.6.1 will thus be characterized by lower pressures at the time of MDNBR than those obtained for this event. Therefore, the DNB aspects of this event will be bounded by those of Event 14.6.1.

The disposition of events for the Radiological Consequences of Steam Generator Tube Failure event is summarized in Table 14.6.3-2.



The analysis of the SGTR event was performed with assumptions regarding system operation that were chosen to maximize the radiological doses. The analysis assumed that a loss of offsite power and a reactor trip occur at the initiation of a double ended rupture of a steam generator tube. This causes a loss of forced circulation which results in a higher hotleg temperature and a larger portion of the break flow flashing. The loss of offsite power also results in the loss of the ability to steam via the condenser. Plant cooldown occurs via atmospheric dump valves or main steam safety valves, which is the release pathway for primary and secondary activity. This results in a slower cooldown and RCS depressurization, and a reduced capability to cool down the plant via the unaffected steam generator. All of these effects result in higher doses.

The plant simulation includes modeling of the RCS, the steam generators, the main steam and feedwater systems, the charging and letdown systems, and the HPSI System. The pressurizer was modeled as a non-equilibrium volume. Single failure is not postulated in conjunction with the SGTR event. The following assumptions are made to ensure a conservative estimate of the radiological consequences:

1. The initial core power is 2754 MWt;

2. The initial reactor pressure is 2300 psia including instrument uncertainty;

3. The initial main steam pressure is 933 psia including instrument uncertainty;

4. The initial inlet temperature is 551.25°F including instrument uncertainty;

5. A double-ended rupture of one steam generator tube occurs instantaneously;

6. On reactor trip and turbine trip, loss of offsite power is assumed along with loss of instrument air and the condenser. The ADVs may be operated by local manual action due to loss of instrument air;

7. Following the reactor trip, the MSSVs lift for removal of decay heat from the RCS;

8. The analysis assumed the lowest allowed opening setpoint (-3% drift) for the ruptured steam generator MSSVs and the highest allowed opening setpoint (+3% drift) for the intact steam generator MSSVs;

9. The reseat pressure of the MSSVs on the ruptured steam generator is 12% below the opening pressure, Reference 14.6-5, while the reseat pressure of the MSSVs on the intact steam generator is nominal 6% below the opening pressure. This maximizes the releases to the atmosphere from the ruptured steam generator;

10. All three charging pumps are assumed to be operable, which will lead to a larger primary to secondary break flow. Letdown is conservatively isolated at the time of tube rupture;


11. SIAS is initiated on low pressurizer pressure which starts two HPSI pumps to deliver maximum flow;

12. AFW auto-initiates, accounting for system delay, and delivers a minimum flow.

The operator actions assumed in this analysis are consistent with the EOPs. The major post-trip analysis assumptions regarding operator actions are:

1. Commence Cooldown to Hotleg Temperature Less Than 515°F

Once the event is diagnosed, the operators will cool the RCS at a maximum controllable rate until the hotleg temperature of both loops reaches 515°F, for ruptured steam generator isolation. This temperature assumed in the analysis conservatively includes instrument uncertainties to delay the time till the ruptured steam generator can be isolated. The analysis assumes a loss of offsite power leading to a loss of the condenser. Therefore, the cooldown is performed using the ADVs. Since the analysis assumes a loss of offsite power, a loss of instrument air is postulated, requiring a local manual control of the ADVs for this cooldown. The analysis assumes that, to account for local manual operator action, the cooldown starts 30 minutes from the time of reactor trip.

2. Reduce and Control RCS Pressure

The analysis conservatively does not depressurize the RCS till after the hotleg temperature is less than 515°F and the ruptured steam generator is isolated. In the EOPs, the RCS depressurization begins just after the cooldown to 515°F commences. It is more conservative for dose consequences to delay the RCS depressurization since this will provide a larger primary to secondary break flow rate.

3. Determine and Isolate the Most Affected Steam Generator

The operator isolates the most affected steam generator once the hotleg temperature of the loops have reached the isolation temperature of hotleg less than 515°F.

4. Cooldown and Depressurize RCS to SDC Entry Condition

Cooldown and depressurization to SDC entry would minimize the primary to secondary break flow. The analysis assumes that cooldown to SDC entry is achieved by steaming just the intact steam generator per the EOPs. This is performed for 16 hours from the time of the tube rupture. The analysis conservatively assumes that the hotleg temperatures of the two loops fail to stay coupled, impeding the depressurization to SDC condition. There are five options available in the EOPs to cool and depressurize the isolated steam generator: 1) if RCPs are operating, use at least one RCP and perform a backflow into the RCS; 2)


if time permits, allow ambient cooling; 3) if the condenser is available, steam to the condenser; 4) feed and bleed via steam generator blowdown; 5) steam to the atmosphere using ADV and feeding. Since the last option would lead to a larger offsite dose, it is the method modeled. Given a loss of offsite power/loss of instrument air condition, the feed and bleed via the steam generator blowdown or ambient cooling may be chosen to limit the offsite dose as well as dose to the operator for performing a local manual operation of the ruptured steam generator ADV.

5. Maintain Isolated Steam Generator Level Less Than 90%

The EOPs prevent the ruptured steam generator from overfill by maintaining the pressurizer pressure within 50 psi of the isolated steam generator pressure or backflow into the RCS, in order to minimize the primary to secondary break flow. Alternatively, the steam generator blowdown may be used to restore level less than 90% narrow range level. For offsite dose purposes, this is not explicitly modeled. However, the model assumes primary side depressurization, facilitated by steaming of the isolated steam generator. Therefore, the pressurizer pressure can be maintained within 50 psi of the isolated steam generator, avoiding ruptured steam generator overfill.


14.6.3.6.1 Thermal-Hydraulic Calculation

The portion of the SGTR analysis, till the time the hotleg temperatures reach less than 515°F, was performed using RETRAN-02 MOD 3 (Reference 14.6-4) computer code. The sequence of results for this transient is presented in Table 14.6.3-3. Figures 14.6.3–1 through 14.6.3–9 present the dynamic behavior of important NSSS parameters during this event.

Following a double-ended break of a steam generator tube rupture, reactor coolant flows from the primary side into the secondary side of the ruptured steam generator (see Figure 14.6.3–5). A portion of this break flow is released as flashed steam (see Figure 14.6.3–6). The model has the reactor tripping at the time of tube break. This is conservative, since any pre-trip mass releases would be via the condenser air ejector where a partition factor would greatly reduce the iodine releases (this is further discussed in Section 14.6.3.6.2). Therefore, to conservatively maximize the direct atmospheric releases, the earliest possible trip is limiting. A loss of offsite power at the time of trip leads to a loss of forced flow and a momentary spike in the coldleg temperature as shown in Figure 14.6.3–1. The pressurizer level decreases as the reactor coolant shrinks post-trip. Also, the break flow is greater than the capacity of the charging pumps. As a result, the pressurizer level decreases as shown in Figure 14.6.3–2. The pressurizer pressure also drops as shown in Figure 14.6.3–3. While all three charging pumps and pressurizer heaters attempt to maintain level and pressure, letdown is conservatively isolated at the time of tube break. The pressurizer heaters are turned off as the pressurizer level decreases towards heater uncovery.


As the steam bypass to the condenser is assumed to be unavailable, the post-trip steaming is accomplished via the ADVs and the MSSVs. However, the ADVs require instrument air, which is postulated to be lost with the loss of offsite power. Therefore, no releases from the ADVs are modeled till 1,800 seconds from trip, when local manual operator action can be credited (see Figure 14.6.3–7). Hence, the post-trip steaming to remove decay heat is accomplished, during the initial 30 minutes, by the MSSVs (see Figure 14.6.3–8). The turbine valve closure, due to reactor trip, causes the steam generator pressure to rise, as shown in Figure 14.6.3–4, till the MSSV lift pressure is reached. The main feedwater flow is terminated at the time of trip and the AFW initiates on low steam generator level at 277 seconds accounting for system response time. As the colder AFW is delivered, a hotter volume of feedwater is swept in first. Two AFW pumps deliver a minimum flow rate (see Figure 14.6.3–9).

The pressurizer level and pressure continue to decrease as the energy transfer to the secondary side shrinks the reactor coolant and the tube break flow continues to deplete the primary inventory. The decrease in pressure results in actuation of SIAS at 496 seconds. Once RCS pressure decreases below the HPSI shutoff head pressure, two HPSI pumps deliver maximum flow to slow the decrease in pressurizer pressure. The pressurizer pressure approaches an equilibrium pressure as the combined HPSI and charging flow rate matches the break flow rate. The hotleg temperature of 515°F is reached in 3,637 seconds post-trip.

Specific analyses of the potential for fuel failure is not performed for the steam generator tube accident. The potential for fuel failure is bounded by the analysis for the inadvertent opening of the pressurizer relief valve (Event 14.6.1). The analyses for Event 14.6.1 show that fuel failure does not occur for that event, therefore, fuel failure does not occur following a steam generator tube rupture.

14.6.3.6.2 Radiological Calculation

The intent of this radiological consequences analysis is to verify that offsite and control room doses do not exceed the guidelines of 10 CFR 50.67 and Regulatory Guide 1.183.

The mass releases following a SGTR were determined for use in evaluating the offsite and control room radiation exposure. Figures 14.6.3–5 through 14.6.3–8 show the break mass flow rate and the steam mass flow rate predicted by the thermal hydraulic analysis. This includes the flashing of the break flow as it enters the secondary side of the steam generator. Table 14.6.3-4 summarizes the mass releases for the SGTR event. This includes 92,000 lbm additional mass releases from the ruptured steam generator after it is identified and isolated associated with facilitating cooldown and depressurization for SDC entry, as well as 2,719,000 lbm released from the intact steam generator for cooldown to SDC entry.

The SGTR accident is a penetration of the barrier between the RCS and the main steam system. The integrity of this barrier is significant from the standpoint of radiological safety in that a leaking steam generator tube allows the transfer of reactor coolant into the main steam system. Radioactivity contained in the reactor coolant is transported directly to the atmosphere via the ADVs and MSSVs.


The effects of iodine spiking were accounted for in the analysis. Two different spiking models were evaluated. The first assumes that the primary coolant concentration of I-131 (DEQ) is at the Technical Specification limit of 1.0 μCi/gm and the resulting tube rupture causes the iodine appearance rate to increase by a factor of 335 over the equilibrium appearance rate corresponding to the 1.0 μCi/gm (DEQ) I-131 coolant concentration. The duration of the spike is assumed to be 8 hours. The second spiking model assumes that a pre-accident iodine spike causes the primary coolant to reach an I-131 (DEQ) concentration of 60 μCi/gm at the time of the tube rupture. This concentration is assumed to last for the duration of the accident.

The RADTRAD-NAI computer program is used to calculate the TEDE dose due to RCS and secondary side activity. RADTRAD-NAI is a multiple compartment activity transport code with the dose model consistent with the Regulatory Guideline 1.183 model.

The offsite and control room doses calculated are presented in Table 14.6.3-6. The results are bounding for the assumptions on Table 14.6.3-5 and the thermal-hydraulic results presented in Table 14.6.3-4.

14.6.3.7 Conclusion

The radiological release criterion for this analysis, as well as the calculated results, are presented in Table 14.6.3-6. The calculated results are less than the NRC criteria for both the cases evaluated.

14.6.4 RADIOLOGICAL CONSEQUENCES OF A MAIN STEAM LINE FAILURE OUTSIDE CONTAINMENT

This event is only applicable to Boiling Water Reactors (BWR). As such, this event is not applicable to Millstone Unit 2.

14.6.5 LOSS OF COOLANT ACCIDENTS RESULTING FROM A SPECTRUM OF POSTULATED PIPING BREAKS WITHIN THE REACTOR COOLANT PRESSURE BOUNDARY

This event is initiated by a breach in the primary coolant system pressure boundary. Basically, a range of break sizes from small leaks up to a complete double-ended severance of a primary coolant system pipe must be considered. Typically, these breaks are classified as large breaks or small breaks. Large-break loss-of-coolant accidents (LBLOCA) are discussed in Section 14.6.5.1 for the AREVA Standard CE14 HTP fuel with M5 clad fuel rods. Large-break loss-of-coolant (LBLOCA) are discussed in Section 14.6.5.4 for the CE14 HTP fuel with Zircaloy-4 clad fuel rods. Small-break loss-of-coolant accidents (SBLOCA) are discussed in Section 14.6.5.2.


14.6.5.1 Large Break Loss of Coolant Accidents for M5 Clad Fuel


This event is initiated by a large break in the primary coolant system pressure boundary. The size

of breaks typically considered to be large breaks are from 0.5 ft2 up to a double-ended severance of a primary coolant system pipe.


The LBLOCA events are characterized by four sequential phases. They are:

1. blowdown

2. refill

3. reflood

4. long term cooling

The blowdown phase immediately follows the initiation of a large break. Primary system water is discharged through the break into containment. The system pressure decreases rapidly during the initial subcooled blowdown. As the saturation pressure is approached, local boiling and flashing takes place in the core and the reactor goes subcritical via the negative moderator reactivity feedback. The blowdown flow becomes a water-vapor mixture. The depressurization rate is reduced when core pressure falls below the saturation pressure. The water level continues to decrease until a large amount of water from the safety injection tanks reaches the lower plenum.

The refill phase starts when the safety injection tank water begins to fill the lower plenum. At this time, the core is uncovered by water and the fuel rods are cooled primarily by thermal radiation.

The reflood phase begins when the water level reaches the bottom of the core.

The long term cooling phase starts after the core has quenched to the point where the metal - water reaction is suppressed, or the water level covers the active fuel. During this phase, the water inventory is controlled by the safety injection pumps. The continuous operation of these pumps ensures the long term dissipation of the decay heat.


No credit is taken for a reactor trip by the reactor protection system (RPS) in the RLBLOCA analysis. The RPS is not necessary due to the rapid depletion of the moderator which shuts down the reactor core almost immediately, followed by ECCS injection which contains sufficient boron to maintain the reactor core in a subcritical configuration. Technical specification limits on hot rod power serve to limit the peak cladding temperature (PCT).


Available Reactor Protection for the Large Break Loss of Coolant Accidents is summarized in Table 14.6.5.1-1.


Section 15.6.5 of Reference 14.6-11 indicates that the primary acceptance criteria for this event are to limit offsite doses, to limit fuel clad oxidation, and to keep PCT below 2200°F. Offsite doses are maximized in the RLBLOCA analysis by assuming full-power operation and conservative treatment of peaking factors and decay heat. The RLBLOCA analysis initiates the event at full power conditions and core peaking factors (i.e., axial power, radial peaking, LHGR) that are set or ranged over plant technical specifications or plant limiting values. In addition, the decay heat calculations for each case in the sample set are based on the ANSI/ANS 5.1-1979 standard, which assures conservative treatment. Fuel pin cladding temperatures and oxidation rates are highly influenced by these effects, which are maximized at full power conditions. Thus, the most limiting results for this event are obtained with the plant operating at full power in Mode 1. These results bound those from Modes 2-6.

Disposition of Events for the Large Break Loss of Coolant Accidents is summarized in Table 14.6.5.1-2.


The purpose of the analysis is to verify the adequacy of the Emergency Core Cooling System (ECCS) by demonstrating compliance with the following 10 CFR 50.46(b) criteria:

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.

The NRC staff imposed a limitation on the Realistic Large Break LOCA Methodology (Reference 14.6-17) specifying that the equivalent cladding reacted (ECR) results calculated using the Cathcart-Pawel correlation are considered acceptable in conformance with 10 CFR 50.46(b)(2) if the ECR value is less than 13%.

14.6.5.1.5.1 Description of Large Break Loss of Coolant Accident Transient

A LBLOCA is initiated by a postulated rupture of the Reactor Coolant System (RCS) primary piping. The most challenging break location is in the cold leg piping between the reactor coolant


pump and the reactor vessel for the RCS loop. The plant is assumed to be operating normally at full power prior to the accident and the break is assumed to open instantaneously. A worst case single-failure is also assumed to occur during the accident. The limiting single-failure for this analysis is the loss of one ECCS pumped injection train without the loss of containment spray.

The LBLOCA event is typically described in the short-term by three phases: blowdown, refill, and reflood. Following the initiation of the break, the blowdown phase is characterized by a sudden depressurization from operating pressure down to the saturation pressure of the hot leg fluid. For larger cold leg breaks, an immediate flow reversal and stagnation occurs in the core due to flow out the break, which causes the fuel rods to pass through critical heat flux (CHF), usually within 1 second following the break. Following this initial rapid depressurization, the RCS depressurizes at a more gradual rate. Reactor trip and emergency injection signals occur when either the low pressure setpoint or the containment high-pressure setpoint are reached. However, for LBLOCA, reactor trip and scram are essentially inconsequential, as reactor shutdown is accomplished by moderator feedback. During blowdown, core cooling is supported by the natural evolution of the RCS flow pattern as driven by the break flow.

When the system pressure falls below the Safety Injection Tanks (SIT) pressure, flow from the SIT is injected into the cold legs ending the blowdown period and initiating the refill period. Once the system pressure falls below the respective shutoff heads of the safety injection systems and the system startup time delays are met, flow from the safety injection systems is injected into the RCS. While some of the ECCS flow bypasses the core and goes directly out of the break, the downcomer and lower plenum gradually refill until the mixture in the lower head and lower plenum regions reaches the bottom of the active core and the reflood period begins. Core cooling is supported by the natural evolution of the RCS flow pattern as driven by the break flow and condensation on the emergency coolant being injected. Towards the end of the refill period, heat transfer from the fuel rods is relatively low, steam cooling and rod-to-rod radiation being the primary mechanisms.

Once the lower plenum is refilled to the bottom of the fuel rod heated length, refill ends and the reflood phase begins. Substantial ECCS fluid is retained in the downcomer during refill. This provides the driving head to move coolant into the core. As the mixture level moves up the core, steam is generated and liquid is entrained, providing cooling in the upper core regions. The two-phase mixture expands into the upper plenum and some liquid may de-entrain and flow downward back into the cooler core regions. The remaining entrained liquid passes into the steam generators where it vaporizes, adding to the steam that must be discharged through the break and out of the system. The difficulty of venting steam is, in general, referred to as steam binding. It acts to impede core reflood rates. With the initiation of reflood, a quench front starts to progress up the core. With the advancement of the quench front, the cooling in the upper regions of the core increases, eventually arresting the rise in fuel rod surface temperatures. Later the core is quenched and a core cooling process is established that can maintain the cladding temperature near saturation, so long as the ECCS makes up for the core boil off.


14.6.5.1.5.2 Description of Analytical Models

The RLBLOCA methodology is documented in EMF-2103 Realistic Large Break LOCA Methodology for Pressurized Water Reactors (Reference 14.6-17). The RLBLOCA methodology uses a non-parametric statistical approach to determine that the first three criteria of 10 CFR 50.46 are met with a probability higher than 95 percent with 95 percent confidence.

The methodology follows the Code Scaling, Applicability and Uncertainty (CSAU) evaluation methodology (Reference 14.6-18) and the requirements of the Evaluation Model Development and Assessment Process (EMDAP) documented in Reference 14.6-19. The CSAU 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:

• COPERNIC for computation of the initial fuel stored energy, fission gas release, and the transient fuel cladding gap conductance.

• S-RELAP5 for the thermal-hydraulic system calculations (includes ICECON for containment response).

The governing two-fluid (plus non-condensable) 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 heat. 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 Reactor Coolant Pumps (RCPs) or the steam generator (SG) separators. All geometries are modeled at the resolution necessary to best resolve the flow field and the phenomena being modeled within practical computational limitations.

The analysis considers blockage effects due to clad swelling and rupture as well as increased heat load due to fuel relocation in the ballooned region of the cladding in the prediction of the hot fuel rod PCT.

A typical calculation using S-RELAP5 begins with the establishment of a steady-state initial condition 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. Additionally, the COPERNIC code provides initial conditions for the S-RELAP5 fuel model.


Following the establishment of an acceptable steady-state condition, the transient calculation is initiated by introducing a break into one of the loops. The evolution of the transient through blowdown, refill, and reflood is computed continuously using S-RELAP5. Containment pressure is calculated by the ICECON module within S-RELAP5.

14.6.5.1.5.3 Plant Description and Summary of Analysis Parameters

The plant analyzed is the Millstone Unit 2, CE designed PWR, which has 2x4-loop arrangement. There are two hot legs each with an U-tube steam generator and four cold legs each with a RCP. The RCS includes one Pressurizer connected to a hot leg. The ECCS comprises four SITs, one per loop/cold leg, and one full train of Low Pressure Safety Injection (LPSI) and High Pressure Safety Injection (HPSI) (after applying the single failure assumption). The HPSI and LPSI feed into common headers (cross connected) that are connected to the SIT lines. The RLBLOCA transients are of sufficiently short duration that the switchover to sump cooling water for ECCS pumped injection does not need to be considered.

The S-RELAP5 model explicitly describes the RCS, reactor vessel, pressurizer, and ECCS. The ECCS includes a SIT path and a LPSI/HPSI 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. This model also describes the secondary-side steam generator that is instantaneously isolated (closed main steam isolation valve and feedwater trip) at the time of the break. The analysis includes AREVA fuel with M5 cladding and utilizes the COPERNIC code for fuel calculations within S-RELAP5.

As described in the AREVA RLBLOCA methodology, many parameters associated with LBLOCA phenomenological uncertainties and plant operation ranges are sampled. The values for process or operational parameters, including ranges of sampled process parameters, and fuel design parameters used in this analysis are given in Table 14.6.5.1-3. The uncertainties used in the analysis are summarized in Table 14.6.5.1-4. Two parameters (refueling water storage tank temperature and diesel start time) are set at conservative bounding values for all calculations. The passive heat sinks and material properties used in the containment input model are provided in Table 14.6.5.1-5.

14.6.5.1.5.4 Base Calculations

The application of the AREVA RLBLOCA methodology involves developing input decks, executing the simulations that comprise the uncertainty analysis, retrieving PCT, maximum local oxidation, and core-wide oxidation information and determining the simultaneous Upper Tolerance Limit (UTL) results for the criteria. The analysis assumes full-power operation at 2754 MWt (includes power calorimetric uncertainty), a tube plugging level of 5.87 percent per steam generator, a peak linear heat generation rate (LHGR) of 15.1 kW/ft, and a radial peaking factor of 1.854 (includes uncertainty). The analysis supports operation of a full core of AREVA Standard CE14 HTP fuel design with M5 cladding of fresh and once-burned fuel assemblies. Blockage effects due to clad swelling and rupture are also considered.


The analysis also addresses typical operational ranges or technical specification limits (whichever is applicable) with regard to pressurizer pressure and level; safety injection tank (SIT) pressure, temperature (containment temperature), and level; core inlet temperature; core flow; containment pressure and temperature; and refueling water storage tank temperature.

The UTL results are provided in Table 14.6.5.1-6. For a simultaneous coverage/confidence level of 95/95, the UTL results are shown in Section 14.6.5.1.6. The fraction of total hydrogen generated was not directly calculated; however, it is conservatively bounded by the calculated total core wide percent oxidation, which is well below the 1 percent limit. Table 14.6.5.1-7 provides a summary of the major input parameters for the demonstration case. The sequence of event times for the demonstration case is provided in Table 14.6.5.1-8. The analysis plots for the case set are shown in Figure 14.6.5.1–1 through Figure 14.6.5.1–5. Figure 14.6.5.1–1 shows linear scatter plots of the key parameters sampled for all cases. Parameter labels appear to the left of each individual plot. Figure 14.6.5.1–2 and Figure 14.6.5.1–3 show PCT scatter plots versus the time of PCT and versus break size, respectively. The scatter plots for the maximum local oxidation and total core-wide oxidation are shown in Figure 14.6.5.1–4 and Figure 14.6.5.1–5, respectively.

Figure 14.6.5.1–6 through Figure 14.6.5.1–17 show key results from the S-RELAP5 calculations for the demonstration case.

14.6.5.1.5.5 Reduced Primary Temperature Operation at End of Cycle

An assessment to support an end of cycle full power coastdown to an indicated RCS cold leg temperature of 537°F has been performed. The result of the assessment confirmed that the RLBLOCA analysis bounds operation during an end of cycle full power coastdown to an indicated RCS cold leg temperature of 537°F.

14.6.5.1.6 Summary of Results

The UTL results providing 95/95 simultaneous coverage from this evaluation meet the 10 CFR 50.46(b) criteria with a PCT of 1615°F, a maximum local oxidation of 2.01 percent and a total core-wide oxidation of 0.025 percent. The maximum local oxidation UTL is less than 13% limit imposed by the NRC on the RLBLOCA EM (Reference 14.6-17).

14.6.5.1.7 Post Analysis of Record Evaluations

In addition to the analyses presented in this section, evaluations and reanalysis may be performed as needed to address ECCS Evaluation Model errors and emergent issues, or to support plant changes. The issues or changes are evaluated, and the impact on the peak cladding temperature (PCT) is determined. The resultant increases or decreases in PCT are applied to the analysis of record PCT.

There are no PCT penalties associated with the RLBLOCA analyses presented in this section.



The UTL results providing a 95/95 simultaneous coverage/confidence level from this evaluation meet the 10 CFR 50.46(b) criteria as seen in Section 14.6.5.1.6. The analysis also shows that the maximum local oxidation UTL is less than the 13% oxidation limit imposed by the NRC on the RLBLOCA EM (Reference 14.6-17). The results of the analysis demonstrate the adequacy of the ECCS to support the 10 CFR 50.46(b) (1-3) criteria (Reference 14.6-14) given in Section 14.6.5.1.5.

14.6.5.2 Small Break Loss of Coolant Accident

The following subsections present the ECCS Small Break Loss of Coolant Accidents (SBLOCA) performance analysis supporting AREVA Standard CE14 HTP Fuel Assembly with M5® fuel rod cladding. AREVA fuel with Zirc 4 cladding is evaluated as discussed in FSAR Section 14.6.5.2.7.


This event is initiated by a small break in the primary coolant system pressure boundary. The size of breaks typically considered to be small breaks are from a leak exceeding the makeup capacity

of the charging system up to approximately 0.5 ft2. The most limiting break location is in the RCS cold leg pipe on the discharge side of the reactor coolant pump.


The principal PWR design feature for mitigating the consequences of an SBLOCA is the Emergency Core Cooling System (ECCS) which maintains the water inventory. Its major subsystems for restoring water inventory are the HPSI system, and the LPSI system and the safety injection tanks.

An SBLOCA is characterized by slow RCS depressurization rates and mass transfer rates within the RCS relative to similar parameters calculated for LBLOCA. If the break area is large enough that the charging pumps cannot maintain the reactor coolant inventory and allow RCS pressure control, the RCS will depressurize. The depressurization produces a low pressurizer pressure (TM/LP) reactor trip and an SIAS. The rate of RCS depressurization following SIAS depends on the break area and the HPSI shutoff head. With a combination of a very small break and a sufficiently high HPSI shutoff head, the depressurization may be arrested.

If the break area is sufficiently large to allow continued depressurization and net loss of coolant inventory even with the HPSI pumps in operation, the coolant level in the reactor vessel may recede below the top of the reactor core. If sufficient steam is produced in the RCS, natural circulation (the RCPs will have been tripped by this time to reduce coolant loss out the break) around the RCS loops will cease. Eventually, loss of reactor coolant inventory is arrested by ECCS flow exceeding flow out the break. In either case, the coolant level within the reactor vessel will rise, and the RCS will eventually be refilled (although leaking) to the cold leg elevation.



Primary reactor protection for this event is provided by the low pressurizer pressure (TM/LP) trip and the SIAS on a low pressurizer pressure signal.

Available Reactor Protection for the Small Break Loss of Coolant Accidents resulting from a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary event is summarized in Table 14.6.5.2-1.


Section 15.6.5 of Reference 14.6-11 indicates that the primary acceptance criteria for this event are to limit offsite doses, to limit fuel clad oxidation, and to keep PCT below 2200°F. Offsite doses are maximized by assuming the highest concentration of radionuclides contained within the fuel pins at event initiation. This is accomplished by assuming steady state radionuclide concentrations characteristic of long term operation of the plant at full power. Fuel pin cladding temperatures and oxidation rates are maximized by initiating the event with the highest cladding temperatures and LHGR. Thus, the most limiting results for this event are obtained with the plant operating at full power in Mode 1. These results will bound those from Modes 2-6.

Disposition of Events for the Small Break Loss of Coolant Accidents Resulting from a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary event is summarized in Table 14.6.5.2-2.


The purpose of the SBLOCA analysis is to demonstrate that the criteria stated in 10 CFR 50.46(b) are met. The criteria are:

1. The calculated maximum fuel element cladding temperature shall not exceed 2200°F.

2. The calculated total local oxidation of the cladding shall not 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 core temperature is reduced and decay heat is removed for an extended period of time, as required by the long-lived radioactivity remaining in the core.


14.6.5.2.5.1 Description of Small Break Loss of Coolant Accident Transient

The SBLOCA is generally defined as a break in the PWR pressure boundary which has an area of

0.5 ft2 (approximately 10% of cold leg pipe area) or less. This range of break areas encompasses small lines which penetrate the primary pressure boundary. Small breaks could involve pressurizer relief and safety valves, charging and letdown lines, drain lines, and instrumentation lines. The limiting break size is generally in the neighborhood of 2% of the cold leg pipe area. The most limiting break location is in the cold leg pipe at the discharge side of the pumps, particularly with primary pumps tripped early to conservatively model a possible loss-of-offsite power on reactor trip. This break location results in the largest amount of inventory loss and the largest fraction of ECCS fluid ejected out the break. This produces the greatest degree of core uncovery and the longest fuel rod heatup time.

The SBLOCA transient is characterized by a slow depressurization of the primary system with a reactor trip occurring at a low primary pressure of 1700 psia (conservatively bounding the actual value of 1865 psia) in the Millstone Unit 2 plant. The SIAS occurs when the system has depressurized to 1500 psia. The capacity and shutoff head of the HPSI pumps are important parameters in the SBLOCA transient. The single failure criterion is satisfied by the loss of one diesel generator. In the Millstone Unit 2 SBLOCA analysis, only one train of safety injection is available.

The SBLOCA transient can be categorized into three ranges of break sizes. The scenario is different for each range of break sizes. Very small breaks are characterized by inventory losses that are less than the makeup capacity of the HPSI pumps such that core uncovery is limited. The core level is eventually recovered and hot rod heatup is limited. Breaks with a large flow area are characterized by a sufficiently large primary system depressurization rate such that the safety injection tank pressure is reached in sufficient time to limit the core uncovery and hot rod heatup. The HPSI pumps have limited influence on those transients. Breaks with a flow area between the two extremes are generally the most limiting. In those transients, the rate of inventory loss from the primary system is large enough that the HPSI pumps cannot preclude significant core uncovery. The primary system depressurization rate is very slow, extending the time required to reach the safety injection tank pressure. This tends to maximize the heatup time of the hot rod and produces the maximum PCT. It also results in the longest time-at-temperature, which maximizes the local cladding oxidation. The limiting break is usually one with a large enough break area that there is a prolonged period of core uncovery.

The time allowed for the operators to manually trip the primary coolant pumps following the SIAS is an important parameter. Allowing the pumps to continue to operate during an SBLOCA would delay break uncovery (transition to mostly steam flow), resulting in additional inventory loss from the system. Subsequent loss of the primary pumps (due to cavitation or an eventual manual trip) would result in more core uncovery, and higher PCTs. The base calculations for this analysis tripped the primary coolant pumps at the reactor scram signal, when a loss of offsite power is assumed to occur. A sensitivity study was also performed to determine an acceptable primary coolant pump trip delay time (Section 14.6.5.2.5.5).


14.6.5.2.5.2 Analytical Models

The approved AREVA SBLOCA evaluation model (References 14.6-12 and 14.6-13) consists of two computer codes. The appropriate conservatisms prescribed by Appendix K of 10 CFR 50 are incorporated.

1. The RODEX2-2A code was used to determine the burnup dependent initial fuel conditions for the system calculations.

2. The S-RELAP5 code was used to model the transient thermal-hydraulic response of the reactor coolant and main steam systems. The S-RELAP5 code also models the thermal-hydraulic response of the hot rod during the transient. The governing conservation equations for mass, energy, and momentum transfer are used along with appropriate correlations consistent with Appendix K of 10 CFR 50.


The Millstone Unit 2 nuclear power plant is a CE designed PWR which has two hot leg pipes, two U-tube steam generators, and four cold leg pipes with one RCP in each cold leg. The plant utilizes a large dry containment. The RCS is nodalized in the S-RELAP5 model into control volumes representing reasonably homogeneous regions, interconnected by flow paths or “junctions.” Each of the cold legs is modeled separately. The model considers four safety injection tanks, a pressurizer, and two steam generators with both primary and secondary sides of the steam generators modeled. The HPSI pumps were modeled as sources injecting directly into all RCS cold legs, with conservative flows given as a function of system backpressure. The LPSI pumps were modeled as sources injecting directly into two of the RCS cold legs, with conservative flows given as a function of system backpressure. The pumped ECCS flow rates as a function of cold leg pressure are based on a detailed Safety Injection System flow calculation which includes pump degradation. No charging pump flow was credited in the analysis.

The primary coolant pump performance curves are characteristic of the Millstone Unit 2 pumps. Symmetrical steam generator tube plugging of 500 tubes per steam generator was assumed.

The analysis assumed loss of offsite power concurrent with reactor scram. The single failure criterion required by Appendix K was satisfied by assuming the loss of one Emergency Diesel Generator (EDG), which resulted in the disabling of one HPSI pump, one LPSI pump and one motor-driven auxiliary feedwater (AFW) pump. The swing HPSI pump was not credited, leaving only a single HPSI pump in operation. Initiation of the HPSI and LPSI systems were delayed by 25 and 25 seconds, respectively, beyond the time of SIAS representing the maximum Technical Specification delay time required for EDG startup, switching, and pump startup. The disabling of a motor-driven AFW pump would leave one motor-driven pump and the turbine-driven pump available. The initiation of the motor-driven pump was delayed 240 seconds beyond the time of the Auxiliary Feedwater Actuation Signal (AFAS) indicating low steam generator level (0% narrow range). The operator startup of the turbine-driven AFW pump was not credited in the analysis. The analysis assumes a constant minimum AFW flow rate of 72 gpm per SG. The sweep


out of fluid at the main feedwater temperature in the piping between the AFW injection location and the steam generators is also accounted for.

The analysis supports a total unrodded integrated radial peaking factor (FrT) of 1.854 (1.69 plus

uncertainties), and a maximum Linear Heat Rate (LHR) of 15.1 kW/ft.

All four RCPs were assumed to trip coincident with reactor scram, consistent with a loss of offsite power at the time of trip.

Values for system parameters used in the analysis are given in Table 14.6.5.2-3.

14.6.5.2.5.4 Break Spectrum

The Millstone Nuclear Plant Unit 2 break spectrum analysis for SBLOCA includes breaks of varying diameter up to 10% of the flow area for the cold leg. The spectrum includes a wide enough range of break sizes from 2.0 inch diameter to 9.49 inch diameters to establish a PCT trend. Additional break sizes are performed with a smaller break interval fine enough to identify the limiting break size and to capture different recovery phenomena. The limiting break size was determined to be 3.78-inch diameter (0.07793 ft2), resulting in a PCT of 1707°F. The PCT results for the break spectrum are presented in Table 14.6.5.2-6. Figure 14.6.5.2–1 shows the calculated PCTs for the break spectrum. The predicted event times for the break spectrum are provided in Table 14.6.5.2-5. For the break spectrum analysis, RCP trip is assumed to occur on reactor trip.

The break opens at 0 seconds and initiates a subcooled depressurization of the primary system. The low pressurizer pressure trip setpoint is reached at 19 seconds and within 2 seconds the reactor is tripped. Offsite power is lost, coincident with the turbine trip, RCP trip, and MFW pump trip (Figure 14.6.5.2–2, Figure 14.6.5.2–11, Figure 14.6.5.2–12 and Table 14.6.5.2-5). The SIAS is issued at 27 seconds on low pressurizer pressure. As MFW to the SGs is ramped down, the pressure in the SGs increase for approximately 30 seconds until the MSSV inlet reaches the lowest opening pressure setpoint. This provides core heat removal in the early stages of the transient.

The primary system depressurization continues at a relatively fast rate for the first 125 seconds as fluid rushes out of the break (Figure 14.6.5.2–3). The broken leg loop seal clears at 356 seconds (Figure 14.6.5.2–6), as demonstrated in the horizontal loop seals and break void fractions in Figure 14.6.5.2–6 and Figure 14.6.5.2–5, respectively.

Prior to loop seal clearing in the broken leg, the core uncovers about 4 feet below the top of the active fuel (Figure 14.6.5.2–9, Figure 14.6.5.2–20 and Figure 14.6.5.2–21). As there is no loop flow, a large amount of steam is generated and accumulated in the core by the decay heat until enough pressure is built to blow the upflow leg of the loop seal in the broken leg around 356 seconds into the transient. This causes an abrupt level drop in the downcomer region (Figure 14.6.5.2–8) with a simultaneous core recovery (Figure 14.6.5.2–9). As the broken leg clears, the plant then enters a fairly slow boil-off phase where mass is lost out the break, and the primary system continues to empty. All intact loops remained plugged for the duration of the transient.


As liquid drains out of the loop piping, the break flow transitions from liquid to two phase flow, and then to steam. The break flow becomes primarily steam around 366 seconds resulting in a reduced mass flow rate out of the break (Figure 14.6.5.2–4) and an increase in the depressurization rate of the primary system (Figure 14.6.5.2–3). The liquid level in the reactor vessel continues to drop until the reactor vessel reaches a minimum level at 1386 seconds (Figure 14.6.5.2–10).

Although HPSI flow to the primary system cold legs began at approximately 62 seconds into the transient (Figure 14.6.5.2–16), it does not provide sufficient inventory at this time to offset the large amounts lost out the break at this time. As effective cooling is lost in the core, the fuel rods begin to heat up at approximately 800 seconds (Figure 14.6.5.2–22). The fuel continues to heat up until the maximum PCT of 1707°F is reached at 1824 seconds. Fuel rod rupture does occur for the hot rod, the calculated blockage factor indicates that the channel around the hot rod is not completely blocked and that all other channels in the core are also not completely blocked. Therefore, the hot rod and all other channels in the core are amenable to cooling.

For this break size, the HPSI flow is eventually sufficient to compensate for the rate of inventory loss out of the break. At the time of the PCT, the primary system has de pressurized to a pressure slightly above the SIT pressure and the LPSI shut-off head. SIT injection begins at 4580 seconds (Figure 14.6.5.2–18), followed by LPSI injection 56 seconds later (Figure 14.6.5.2–17), resulting in no influence on PCT turnaround.

The downcomer level (Figure 14.6.5.2–8) and the reactor vessel inventory (Figure 14.6.5.2–10) start slowly increasing at approximately 1400 seconds. The onset of SIT and LPSI injection helps the reactor vessel levels to step up, ensuring core recovery and long term core cooling.

In conclusion, the limiting PCT break spectrum case is a 3.78-inch diameter cold leg break. The PCT of this case is 1707°F. The transient maximum local oxidation (MLO) is 3.6% and the maximum corewide oxidation (CWO) is less than 0.04%. The total maximum local oxidation is less than 6%, including a pre-transient oxidation of 2.3%. The hot rod resulted in rupture, but remained amenable to cooling. The results of the analysis demonstrate the adequacy of the ECCS to support the 10 CFR 50.46(b) (1-4) criteria (Reference 14.6-14).

14.6.5.2.5.5 Pump Trip Delay Results

For plants such as Millstone Nuclear Plant Unit 2 that do not have an automatic RCP trip, a delayed RCP trip can potentially result in a more limiting condition than tripping the RCPs at reactor trip. Continued operation of the RCPs may result in earlier loop seal clearing with associated two-phase flow out the break, which would result in less inventory loss out the break early in the transient, but in the longer term could result in more overall inventory loss out the break. It has been postulated that tripping the pumps when the minimum RCS inventory occurs could cause a collapse of voids in the core, thus depressing the core level and provoking a deeper core uncovery, and a potentially higher PCT. Therefore, an RCP trip sensitivity for both the cold and hot leg breaks was performed with a delay time following the loss of subcooling margin in the cold leg to demonstrate 10 CFR 50.46(b)(1-4) criteria. This manual RCP trip study was performed consistent with the Combustion Engineering Owners Group guidelines described in


Generic Letter 86-06 (Reference 14.6-10) where compliance with 10 CFR 50.46 is demonstrated when operator action to trip the RCPs is taken within 2 minutes after the RCP trip criterion is reached using the 10 CFR 50 Appendix K method.

Also, consistent with Generic Letter 86-06, additional delayed RCP trip sensitivity studies were performed to determine the maximum delay time for operator action under a more realistic scenario. Best-estimate assumptions were applied using the same model as the Appendix K RCP analysis with relaxation in two areas: decay heat multiplier reduction from 1.2 to 1.0 and critical break flow model change from Moody to the Homogeneous Equilibrium Model. A range of RCP trip delay times was examined for both hot and cold leg break locations.

The results of the delayed RCP trip sensitivity, with Appendix K assumptions demonstrated that all four RCPs can be tripped by the operator within 2 minutes after subcooling margin is lost in the cold leg pump suction in order to meet the 10 CFR 50.46(b)(1-4) criteria. In addition, relaxation of Appendix K assumptions demonstrated that longer delay times of up to 10 minutes could be accommodated and still meet the 10 CFR 50.46(b)(1-4) criteria.

14.6.5.2.5.6 Asymmetric Steam Generator Tube Plugging

Small break LOCA analyses have no significant sensitivity to steam generator tube plugging. The analysis was performed using the maximum allowed total tube plugging of 1000 tubes applied symmetrically (500 tubes per steam generator), and supports the maximum allowed asymmetry between the generators of 500 tubes. By applying the maximum allowed tube plugging, the analysis is conservative because the initial primary system mass inventory is minimized.

14.6.5.2.5.7 Reduced Primary Temperature Operation

An assessment to support an end of cycle full power coastdown to an indicated RCS cold leg temperature of 537°F has been performed. The result of the assessment confirmed that break spectrum analysis bounds operation during an end of cycle full power coastdown to an indicated RCS cold leg temperature of 537°F.

14.6.5.2.5.8 Attached Piping Break Sensitivity Study

Although breaks in the attached piping are not typically PCT limiting, they do result in reduced ECCS flows available to mitigate the event. Therefore, an analysis of the limiting break size and location in attached piping was performed. For Millstone Nuclear Plant Unit 2, the limiting break location and size for an attached piping break is a double-ended guillotine break of a SIT line. The break is located in the SIT line connected to Loop 2B.

For the double-ended guillotine break in the SIT line, the calculated PCT is 1239°F, which is bounded by the limiting PCT of the RCS break spectrum. The minimal HPSI and LPSI flow rates modeled were sufficient to prevent a subsequent heatup after the initial quench from the SIT discharge.


14.6.5.2.5.9 Safety Injection Low Fluid Temperature Sensitivity Study

A sensitivity study was performed on which SIT and safety injection (SI) fluid temperatures were reduced to approximate nominal temperatures as opposed to the maximum temperatures used in the spectrum analysis. The result of the sensitivity study confirmed that the SIT and SI fluid temperatures used in the break spectrum are conservative.


The limiting PCT break spectrum case is a 3.78-inch diameter cold leg break. The PCT of this case is 1707°F. The transient maximum local oxidation (MLO) is 3.6% and the maximum core-wide oxidation (CWO) is less than 0.04%. The total maximum local oxidation is less than 6%, including a pretransient oxidation of 2.3%. The hot rod resulted in rupture, but remained amenable to cooling. The results of the analysis demonstrate the adequacy of the ECCS to support the 10 CFR 50.46(b) (1-4) criteria (Reference 14.6-14).

The results of the delayed RCP trip sensitivity with Appendix K assumptions demonstrated that all four RCPs can be tripped by the operator within 2 minutes after subcooling margin is lost in the cold leg pump suction in order to meet the 10 CFR 50.46(b)(1-4) criteria. In addition, relaxation of Appendix K assumptions demonstrated that longer delay times of up to 10 minutes could be accommodated and still meet the 10 CFR 50.46(b)(1-4) criteria.

The attached pipe break and the ECCS temperature sensitivity results are bounded by the RCS break spectrum. The sensitivity studies justify the applicability of the break spectrum as the licensing basis.

Margin between the calculated PCT and the 2200°F limit of 10 CFR 50.46 is available to accommodate other permanent adjustments due to 10 CFR 50.59 Safety Evaluations and LOCA model assessments. These adjustments are summarized in the 30 day and annual 10 CFR 50.46 reporting of PCT Margin Utilization. The reporting process and attention to PCT margin assure that the PCT remains below the 2200°F limit of 10 CFR 50.46.

The analysis supports full power operation at 2754 MWt (2700 MWt plus 2% uncertainty). A maximum LHR of 15.1 kW/ft and a radial peaking factor of 1.69 are supported by this analysis. The analysis demonstrates that the 10 CFR 50.46(b) criteria are satisfied for the Millstone Unit 2 reactor.


In addition to the analyses presented in this section, evaluations and reanalysis may be performed as needed to address ECCS Evaluation Model errors and emergent issues, or to support plant changes. The issues or changes are evaluated, and the impact on the peak cladding temperature (PCT) is determined. The resultant increases or decreases in PCT are applied to the analysis of record PCT.


A separate study applying Zirc-4 fuel and the model updates in Supplement 1 (Reference 14.6-13) of the methodology was performed, which resulted in a +4 °F increase in PCT relative to M5®. This assessment was performed to support operation utilizing AREVA fuel with Zirc-4 cladding. This increase in PCT is treated as a penalty to the Analysis of Record under the provisions of 10 CFR 50.46. The PCT, including this penalty, is presented in Table 14.6.5.2-7 for the Small Break LOCA. The current PCT is demonstrated to be less than the 10 CFR 50.46(b) requirement of 2200°F.


The limiting PCT break spectrum case is a 3.78-inch diameter cold leg break. The PCT of this case is 1707°F. The transient maximum local oxidation (MLO) is 3.6% and the maximum core-wide oxidation (CWO) is less than 0.04%. The total maximum local oxidation is less than 6%, including a pretransient oxidation of 2.3%. The hot rod resulted in rupture, but remained amenable to cooling. The results of the analysis demonstrate the adequacy of the ECCS to support the 10 CFR 50.46(b) (1-4) criteria (Reference 14.6-14) given in Section 14.6.5.2.5.

14.6.5.3 Post-LOCA Long Term Cooling

Following the short term mitigation actions for a large or small break LOCA (as discussed in Sections 14.6.5.4 and 14.6.5.2, respectively), long term cooling will continue to maintain the core at an acceptably low temperature. LOCA mitigation in the long term will be accomplished by the methods referred to as the Long Term Cooling (LTC) Plan. The LTC Plan (shown in Figure 14.6.5.3–1) consists of the events and actions that will assure acceptable long term core cooling and prevention of boric acid precipitation in the core region. The Post-LOCA Long Term Cooling Analysis, demonstrates that Post-LOCA Long Term core cooling and boric acid precipitation prevention can be accomplished for all LOCAs.

14.6.5.3.1 The Post-LOCA Long Term Cooling Plan

Figure 14.6.5.3–1 shows the basic sequence of events for the initial automatic actions and the subsequent operator actions of the LTC Plan. The operator’s first action is to initiate a plant cooldown within 1 hour post-LOCA by releasing steam from the steam generators. The steam is released either through the turbine bypass system, if it is available, or through the atmospheric dump valves (ADVs).

When pressurizer pressure is less than 600 psia and stable with a controlled cooldown in progress, the Safety Injection Tanks (SITs) are isolated to avoid injecting nitrogen, a non-condensable gas, into the reactor coolant system (RCS).

At 8 to 10 hours post-LOCA, the operator will determine if the RCS is filled. If the RCS is filled, then natural circulation will prevent boric acid precipitation and simultaneous hot and cold leg injection will not be necessary. The operators will attempt to establish shutdown cooling (SDC) if entry conditions exist or can be established. If SDC cannot be established (whether due to single failure, SDC pressure/temperature limits unsatisfied, or RCS activity beyond appropriate limits), then steam generator (SG) cooling will be continued.


If the RCS is not filled at 8 to 10 hours post-LOCA, then simultaneous hot and cold leg injection will be established to provide core flushing. The preferred method of simultaneous hot and cold leg injection is low pressure safety injection (LPSI) to the hot side (one LPSI pump to the SDC warm up line to the SDC suction line to a hot leg.) Cold side injection will be via a high pressure safety injection (HPSI) pump and the running LPSI pump. If the preferred method cannot be established, then the alternative method of simultaneous hot and cold leg injection, which is HPSI injection to the hot side (1 HPSI pump to a charging line to the pressurizer auxiliary spray line to a hot leg), will be established. Cold side injection will be via a LPSI pump. Either of these simultaneous hot and cold leg injection methods will provide flow that is adequate to cool the core and prevent boric acid precipitation.

14.6.5.3.2 Post-LOCA Long Term Cooling Equipment and Operator Actions

The following discussion elaborates on equipment and operator actions that support the Long Term Cooling Plan.

As stated above, simultaneous hot and cold leg injection will be required if the RCS is not filled at 8 to 10 hours post-LOCA.

If simultaneous hot and cold leg injection is required, then either the preferred method (LPSI hot leg injection) or the alternative method (HPSI hot leg injection) can be established and operated despite various single failures to simultaneous hot and cold leg injection equipment. Either simultaneous hot and cold leg injection configuration will provide adequate delivery flows while ensuring acceptable HPSI and LPSI pump operation. Operator actions outside the control room will be required to realign manually operated valves. Additional operator actions outside the control room will be required in the event of either a facility Z1 or Z2 loss of power (when offsite power is unavailable). These additional operator actions are described as follows.

For a failure of Facility Z1, the position of the LPSI injection valves 2-SI-615, 2-SI-625 must be known, whereas a failure of Facility Z2 requires the position of LPSI injection valves 2-SI-635 and 2-SI-645 to be known. This is required to correctly align for simultaneous hot and cold leg injection. These positions would be determined by operator actions outside the control room.

For the failure of the emergency Facility Z1 AC power to the safety injection system (SIS), the operator actions to establish LPSI hot leg injection would include aligning an alternate power source to SDC suction line valve 2-SI-651. This manual aligning would require operator action outside the control room.

For the failure of the emergency Facility Z2 DC power for the SIS train 2, the operator actions to establish HPSI hot leg injection would include aligning an alternate power source to charging valves 2-CH-517 and 2-CH-519. This manual aligning would require operator action outside the control room.

In addition to the above operator actions directly concerned with the simultaneous hot and cold leg injection realignment and operation, the following operator actions outside the control room may be required to support the Long Term Cooling Plan.


If the condenser is unavailable, the auxiliary feedwater (AFW) system and the ADVs will be used to cooldown the RCS. The cooldown will be initiated within 1 hour after the start of the LOCA. If, when initiating the cooldown, the ADVs are in a closed position, then they will be manually opened by operator action outside the control room. If the primary source of AFW to the steam generator—the condensate storage tank (CST)—becomes depleted beyond the capability of the Ecolochem system to replenish, then operator action outside the control room will be required to manually realign the Fire Protection System to supply AFW.

14.6.5.3.3 Assumptions Used in the Long Term Cooling Analysis

The major assumptions used in performing the Long Term Cooling analysis are listed below:

1. No offsite power is available.

2. The worst single failure is the failure of an emergency diesel generator. As a consequence of the failure, one ECCS train, one containment spray pump and one motor-driven auxiliary feedwater pump are unavailable.

3. Plant cooldown begins at two hours post-LOCA. (The EOPs conservatively initiate the cooldown within one hour post-LOCA.)

4. The analysis assumes that a cooldown rate of 40°F/hr is maintained until the ADVs are fully open (i.e., until flow limiting of the ADVs causes the cooldown rate to decrease from 40°F/hr).

5. The SITs are isolated prior to establishing shutdown cooling.

6. The pressurizer is included in the mass that is cooled down in establishing shutdown cooling entry conditions.

7. A continuous supply of auxiliary feedwater is available for the duration of steam generator cooling. One turbine-driven and one motor-driven auxiliary feedwater pump are assumed to be in operation.

8. Initial boric acid concentrations and inventories and pump flow rates used in the boric acid precipitation analysis are selected to maximize the boric acid concentration in the core.

9. A boric acid precipitation limit of 27.6 wt% is used in the large break LOCA boric acid precipitation analysis. This is the precipitation limit in saturated water at 14.7 psia.

14.6.5.3.4 Method of Analysis

The objective of the post-LOCA Long Term Cooling analysis is to demonstrate that the Long Term Cooling Plan provides conformance to 10 CFR 50.46 Criterion 5, Long Term Cooling, of


the ECCS acceptance criteria (Reference 14.6-14). Conformance is demonstrated by showing that under the Long Term Cooling Plan the calculated core temperature is maintained at an acceptably low value and that the boric acid concentration in the core is maintained below its solubility limit.

The Millstone 2 post-LOCA Long Term Cooling analysis was performed using the NRC accepted computer codes described in Reference 14.6-15. As described in Reference 14.6-15, the CELDA computer code is used to analyze the post-LOCA thermal-hydraulic response of the RCS for a spectrum of break sizes. The NATFLOW computer code is used to calculate RCS temperatures for the purpose of determining when the shutdown cooling entry temperature is achieved. The steam generator cooldown transient that is used as a boundary condition in CELDA and NATFLOW is calculated using the CEPAC computer code. The BORON computer code is used to calculate the boric acid concentration in the core following the LOCA.

The Millstone 2 post-LOCA Long Term Cooling Plan was developed using the NRC accepted methods described in Reference 14.6-15 with the following modification. In Reference 14.6-15, RCS pressure is used as the basis for determining whether to branch to shut down cooling (or continue steam generator cooling if SDC is inoperable) or to branch to simultaneous hot and cold side injection. In the Millstone 2 Long Term Cooling Plan, RCS status (i.e., the RCS is or is not filled) is used as the basis. This approach is consistent with the ABB CE emergency procedure guidelines (Reference 14.6-16).

14.6.5.3.5 Parameters Used in the Long Term Cooling Analysis

Significant core and system parameters used in the Long Term Cooling analysis are presented in Table 14.6.5.3-1.

14.6.5.3.6 Results of the Long Term Cooling Analysis

Figure 14.6.5.3–1 shows the Millstone 2 Long Term Cooling Plan. At 8 to 10 hours post-LOCA, the operator determines whether or not the RCS is filled. Eight to 10 hours is used as the decision time because it provides the operator with ample time to initiate simultaneous hot and cold side injection prior to the earliest time that boric acid precipitation would occur.

The left branch of the Long Term Cooling Plan applies to those break sizes for which the RCS is filled at 8 to 10 hours. For these breaks, SDC operation or continued steam generator cooling will provide heat removal and natural circulation will prevent further boric acid buildup in the core.

The right branch of the Long Term Cooling Plan applies to those break sizes for which the RCS is not filled at 8 to 10 hours. For those break sizes, simultaneous hot and cold side injection is used to maintain core cooling and to provide for boric acid precipitation control.

A double-ended guillotine break in the cold leg is the limiting break for boric acid precipitation control. A double-ended guillotine break is limiting because the low RCS pressure associated with such a large break minimizes the boric acid solubility limit in the core. The cold leg is the limiting break location because it requires the initiation of hot side injection in order to create a


core flushing flow to control boric acid precipitation. For a cold leg break, the core flushing flow is the difference between the hot side injection flow rate and the core boiloff flow rate.

As shown in Figure 14.6.5.3–3, the initiation of a hot side injection flow rate of at least 180 gpm at 13 hours post-LOCA provides a substantial and time-increasing core flushing. Figure 14.6.5.3–4 shows that with no core flushing flow, boric acid would begin to precipitate at approximately 15 hours post-LOCA. However, with a hot side injection flow rate of 180 gpm, initiated at 13 hours post-LOCA, the maximum boric acid concentration in the core is 25.4 wt% as compared to the precipitation limit of 27.6 wt%. The margin provided for the prevention of boric acid precipitation by a constant core flushing flow of 20 gpm is also shown in Figure 14.6.5.3–4.

The time by which the entrainment of hot side injection by the steam flowing in the hot leg would cease was calculated to be less than 2 hours post-LOCA. Therefore, the initiation of hot side injection at 13 hours is well after the potential for the entrainment of the hot side injection has ended.

In order for the most limiting configuration of simultaneous hot and cold leg injection to provide the required hot side injection flow rate of 180 gpm, the RCS pressure must be 86 psia or less. As shown in Figure 14.6.5.3–2, the RCS will not be filled at 8 hours for a break area as small as 0.01

ft2. Consequently, this is the smallest break for which simultaneous hot and cold side injection

would be required. The 0.01 ft2 break was calculated to achieve a RCS pressure of 86 psia prior to 13 hours post-LOCA. Larger breaks will also reach 86 psia prior to 13 hours post-LOCA. This demonstrates that the simultaneous hot and cold leg injection configurations will provide sufficient hot side injection for all breaks for which it may be required.

14.6.5.3.7 Conclusions of the Long Term Cooling Analysis

The Millstone 2 post-LOCA Long Term Cooling analysis demonstrates conformance to 10 CFR 50.46 Criterion 5 of the ECCS acceptance criteria (Reference 14.6-14) for a complete spectrum of break sizes and locations. For breaks that are small enough for the RCS to refill at 8 to 10 hours post-LOCA, shutdown cooling or steam generator cooling provides core cooling and boric acid precipitation control. For breaks that are too large for the RCS to refill at 8 to 10 hours, initiating simultaneous hot and cold side injection provides core cooling and boric acid precipitation control. A simultaneous hot and cold side injection flow rate of 180 gpm (i.e., a flow rate of 180 gpm to both the hot side and cold side of the RCS) initiated by 13 hours post-LOCA maintains the boric acid concentration in the core below the solubility limit.

14.6.5.4 Large Break Loss of Coolant Accidents for Zircaloy-4 Clad Fuel


This event is initiated by a large break in the primary coolant system pressure boundary. The size

of breaks typically considered to be large breaks are from 0.5 ft2 up to a double-ended severance of a primary coolant system pipe.



The LBLOCA events are characterized by four sequential phases. They are:

1. blowdown

2. refill

3. reflood

4. long term cooling

The blowdown phase immediately follows the initiation of a large break. Primary system water is discharged through the break into containment. The system pressure decreases rapidly during the initial subcooled blowdown. As the saturation pressure is approached, local boiling and flashing takes place in the core and the reactor goes subcritical via the negative moderator reactivity feedback. The blowdown flow becomes a water-vapor mixture. The depressurization rate is reduced when core pressure falls below the saturation pressure. The water level continues to decrease until a large amount of water from the safety injection tanks reaches the lower plenum.

The refill phase starts when the safety injection tank water begins to fill the lower plenum. At this time, the core is uncovered by water and the fuel rods are cooled primarily by thermal radiation.

The reflood phase begins when the water level reaches the bottom of the core.

The long term cooling phase starts after the core has quenched to the point where the zircaloy-water reaction is suppressed, or the water level covers the active fuel. During this phase, the water inventory is controlled by the safety injection pumps. The continuous operation of these pumps ensures the long term dissipation of the decay heat.


No credit is taken for a reactor trip by the reactor protection system (RPS). The RPS is not necessary due to the rapid depletion of the moderator which shuts down the reactor core almost immediately, followed by ECCS injection which contains sufficient boron to maintain the reactor core in a subcritical configuration. Technical specification limits on hot rod power serve to limit the peak cladding temperature (PCT).

Available Reactor Protection for the Large Break Loss of Coolant Accidents is summarized in Table 14.6.5.4-1.


Section 15.6.5 of Reference 14.6-7 indicates that the primary acceptance criteria for this event are to limit offsite doses, to limit fuel clad oxidation, and to keep PCTs below 2200°F. Offsite doses are maximized by assuming the highest concentration of radionuclides contained within the fuel


pins at event initiation. This is accomplished by assuming steady state radionuclide concentrations characteristic of long term operation of the plant at full power. Fuel pin cladding temperatures and oxidation rates are maximized by initiating the event with the highest cladding temperatures and linear heat generation rates (LHGR). Thus, the most limiting results for this event are obtained with the plant operating at full power in Mode 1. These results will bound those from Modes 2-6.

Disposition of Events for the Large Break Loss of Coolant Accidents is summarized in Table 14.6.5.4-2.


The purpose of the LBLOCA analysis is to demonstrate that the criteria stated in 10 CFR 50.46(b) are met. The criteria are:

1. The calculated peak fuel element cladding temperature does not exceed the 2200°F limit.

2. The amount of fuel element cladding which reacts chemically with water or steam does not exceed 1% of the total amount of zircaloy in the core.

3. The cladding temperature transient is terminated at a time when the core geometry is still amenable to cooling. The hot fuel rod cladding oxidation limit of 17% is not exceeded during or after quenching.

4. The core temperature is reduced and decay heat is removed for an extended period of time, as required by the long-lived radioactivity remaining in the core.

14.6.5.4.5.1 Description of Large Break Loss of Coolant Accident Transient

A LBLOCA is defined as the rupture of the RCS primary piping from 0.5 ft2 in area up to and including a double-ended guillotine break. The limiting break occurs on the pump discharge side of a cold leg pipe. Loss of offsite power is assumed to occur coincident with the LBLOCA. Primary coolant pump coastdown occurs coincident with the loss of offsite power. Following the break, depressurization of the RCS, including the pressurizer, occurs. A reactor trip signal occurs when the pressurizer low pressure trip setpoint is reached. Reactor trip and scram are conservatively neglected in the LBLOCA analysis. Early in the blowdown, the reactor core experiences flow reversal and stagnation which causes the fuel rods to pass through CHF. Following CHF, the fuel rods dissipate heat through the transition and film boiling modes of heat transfer. Rewet is precluded during blowdown by Appendix K of 10 CFR 50.

An SIS signal is actuated when the appropriate setpoint (high containment pressure) is reached. Due to loss of offsite power, a time delay for startup of diesel generators and SIS pumps is assumed. Once the time delay criteria is met and the system pressure falls below the shutoff head of the HPSI pumps or Low Pressure Safety Injection (LPSI) pumps, SIS flow is injected into the cold legs. The single failure criterion is met by assuming that either one diesel or one LPSI pump


fails. Loss of diesel results in the loss of one HPSI pump, one LPSI pump, one containment spray train and two CAR fans. The Loss-of-LPSI pump case assumes only the loss of one LPSI pump. When the system pressure falls below the safety injection tank pressure, flow from the safety injection tanks is injected into the cold legs. Flow from the ECCS is assumed to bypass the core and flow to the break until the end of bypass (EOBY) is predicted to occur (sustained downflow in the downcomer). Following EOBY, ECCS flow fills the downcomer and lower plenum until the liquid level reaches the bottom of the core (beginning of core recovery, or BOCREC time). During the refill period, heat is transferred from the fuel rods by radiation heat transfer.

The reflood period begins at BOCREC time. ECCS fluid fills the downcomer and provides the driving head to move coolant through the core. As the mixture level moves up the core, steam is generated. Steam binding occurs as the steam flows through the intact and broken loop steam generators and pumps. The pumps are assumed to have a locked rotor (per Appendix K of 10 CFR 50) which tends to reduce the reflood rate. The fuel rods are eventually cooled and quenched by radiation and convective heat transfer as the quench front moves up the core. The reflood heat transfer rate is predicted through experimentally determined heat transfer and carry-over rate fraction correlations.

14.6.5.4.5.2 Description of Analytical Models

The AREVA EXEM/PWR evaluation model (Reference 14.6-8 as modified by Reference 14.6-9) was used to perform the analysis. This evaluation model consists of the following computer codes:

1. RODEX2 for computation of initial fuel stored energy, fission gas release, and gap conductance;

2. RELAP4-EM for the system blowdown and accumulator/SIS flow split calculations;

3. CONTEMPT/LT-22 as modified in accordance with NRC Branch Technical Position CSB 6-1 for computation of containment back pressure;

4. REFLEX for computation of system reflood; and

5. TOODEE2 for the calculation of fuel rod heatup during the refill and reflood portions of the LOCA transient.

The quench time, quench velocity, and carryover rate fraction correlations in REFLEX, and the heat transfer correlations in TOODEE2 are based on AREVA’s Fuel Cooling Test Facility data.

The governing conservation equations for mass, energy, and momentum transfer are used along with appropriate correlations consistent with Appendix K of 10 CFR 50. The reactor core in RELAP4 is modeled with heat generation rates determined from reactor kinetics equations with reactivity feedback, and with actinide and decay heating as required by Appendix K. Appropriate conservatisms specified by Appendix K of 10 CFR 50 are incorporated in all of the models.



The Millstone Unit 2 nuclear power plant is a Combustion Engineering (CE) designed PWR which has two hot leg pipes, two U-tube steam generators, and four cold leg pipes with one RCP in each cold leg. The plant utilizes a large dry containment. The RCS is nodalized into control volumes representing reasonably homogeneous regions, interconnected by flow paths or “junctions.” The two cold legs connected to the intact loop steam generator were assumed to be symmetrical and were modeled as one intact cold leg with appropriately scaled input. The model considers four safety injection tanks, a pressurizer, and two steam generators with both primary and secondary sides of the steam generators modeled. The HPSI and LPSI pumps were modeled as fill junctions at the safety injection tank lines, with conservative flows given as a function of system back pressure. The pump performance curves were characteristic of pumps typically used in CE plants. The reactor core was modeled radially with an average core and a hot assembly as parallel flow channels, each with three axial nodes. A total steam generator tube plugging level of 500 tubes per steam generator (symmetric) was assumed.

Values for system parameters used in the analysis are given in Table 14.6.5.4-3.

14.6.5.4.5.4 Base Calculations

Calculations were performed for all combinations of the following parameters:

• 0.4, 0.6, 0.8, 1.0 DECLG and 0.8 and 1.0 SECLS breaks

• Beginning-of-cycle (BOC), middle-of-cycle (MOC), and end-of-cycle (EOC) axial power shapes

• Loss-of-diesel and loss-of-LPSI single failures

Thus, this analysis comprised a total of 36 complete (blowdown, refill, and reflood) calculations to determine the limiting break and plant scenario. All calculations were performed at a peak LHR of 15.1 kW/ft. The BOC, MOC, and EOC axial shapes were peaked at a relative core height of 0.5, 0.77, and 0.85, respectively. BOC stored energy (where maximum densification occurs) was conservatively used in all of the BOC and MOC axial shape calculations. MOC stored energy was used in the EOC axial shape calculations.

PCT results for each break and limiting single failure are shown in Table 14.6.5.4-4. The table shows that the 1.0 DECLG, EOC axial shape, and loss-of-diesel single failure produced the highest PCT, 1814°F. Additional calculated results for the limiting case are shown in Table 14.6.5.4-5. The sequence of events for the overall limiting case is shown in Table 14.6.5.4-6. Graphical results of parameters depicting the 1.0 DECLG, EOC axial shape, and loss-of-diesel single failure are shown in Figures 14.6.5.4–1 through 14.6.5.4–19.


14.6.5.4.5.5 Exposure Study

The calculations described in Section 14.6.5.4.5.4 support exposures out to EOC. Additional evaluation is required to consider exposures out to end of life (EOL) with a maximum assembly average exposure of 56,000 MWd/MTU. The AREVA methodology predicts maximum fuel stored energy to occur near BOC where maximum densification occurs. Closure of the fuel-cladding gap at higher exposures significantly reduces the fuel stored energy. Beyond exposures of about 30,000 MWd/MTU, the stored energy begins to increase due to fission gas release to the gap, but is still significantly less than the stored energy at MOC. In addition, the power level of rods at EOL is significantly lower than the peak powered rod, resulting in a significantly lower stored energy than the peak powered rod. The reduced stored energy at high exposures outweighs any adverse effects of higher rod internal pressure. Thus, the peak cladding temperature is lower at high exposures than the limiting case reported for the base calculations in Section 14.6.5.4.5.4. This was confirmed in a separate EOL calculation, with 1.0 DECLG and loss-of-diesel single failure, which resulted in a PCT of 1362°F. Therefore, a peak LHR of 15.1 kW/ft is supported for assembly average exposures up to 56,000 MWd/MTU.

14.6.5.4.5.6 Reduced Reactor Coolant System Temperature Operation

End-of-cycle full power primary coolant temperature (Tave) coastdown with a maximum reduction in primary coolant temperature of 12°F was evaluated. From the base calculations, the EOC axial shape combined with MOC stored energy resulted in a PCT of 1814°F. At EOC conditions, the hot rod stored energy will be considerably less than at MOC due to closure of the gap from fuel swelling and clad creep effects. This difference in stored energy is considered to more than offset any adverse effects on PCT of a 12°F Tave reduction. This was confirmed in a separate Tave coastdown calculation. In that a calculation which was performed using the 1.0 DECLG break and loss-of-diesel single failure, the PCT was 1758°F. Thus, this analysis bounds operation at EOC with up to a 12°F Tave coastdown. A full power coastdown to an indicated cold leg temperature of 537°F at EOC is bounded by this evaluation.

14.6.5.4.6 Summary of Results

The analysis identified a double-ended cold leg guillotine break with a discharge coefficient of 1.0 (1.0 DECLG) as the limiting break size. The initial reactor conditions for the limiting break corresponded to an MOC stored energy combined with an EOC axial power shape peaked at a relative core height of 0.85. The limiting scenario also included the loss of one diesel generator as a single failure. The PCT for the limiting case was calculated to be 1814°F. The transient response for this limiting case is shown in Figures 14.6.5.4–1 through 14.6.5.4–19. The summary of results is given in Table 14.6.5.4-5.

Margin between the calculated PCT and the 2200°F limit of 10 CFR 50.46 is available to accommodate other permanent adjustments due to 10 CFR 50.59 Safety Evaluations and LOCA model assessments. These adjustments are summarized in the 30-day and annual 10 CFR 50.46 reporting of PCT Margin Utilization. The reporting process and attention to PCT margin assure that the PCT remains below the 2200°F limit of 10 CFR 50.46.


The analysis supports full power operation at 2754 MWt (2700 MWt plus 2% uncertainty) with a total steam generator tube plugging of up to 500 tubes per steam generator. The analysis supports assembly average exposures of up to 56,000 MWd/MTU. The analysis also supports operation at full power, with an indicated RCS cold leg temperature of 537°F at EOC. The analysis demonstrates that the 10 CFR 50.46(b) criteria are satisfied for the Millstone Unit 2 reactor with an axial and exposure independent LHR of 15.1 kw/ft.


In addition to the analyses presented in this section, evaluations and reanalyses may be performed as need to address ECCS Evaluation Model errors and emergent issues, or to support plant changes. The issues or changes are evaluated, and the impact on the peak cladding temperature (PCT) is determined. The resultant increases or decreases in PCT are applied to the analysis of record PCT. The PCT, including all penalties and benefits, is presented in Table 14.6.5.4-7 for the large break LOCA. The current PCT is demonstrated to be less than the 10 CFR 50.46(b) requirement of 2200°F.


The results of the LBLOCA analysis for Millstone Unit 2 showed the 1.0 DECLG break size to be the limiting break with current EXEM/PWR as modified by SEM/PWR models. The analysis supports operation of Millstone Unit 2 at a power level of 2700 MWt and a total steam generator tube plugging of up to 500 tubes per steam generator. The analysis supports a peak LHR of 15.1 kW/ft with an axial and exposure independent power peaking limit. The analysis supports assembly average exposures of up to 56,000 MWd/MTU. The analysis supports full power operation with an indicated RCS cold leg temperature of 537°F at EOC. A reduction in RCS cold leg temperature to less than 537°F is acceptable as long as there is a corresponding decrease in power level.

Operation of Millstone Unit 2 with AREVA 14x14 fuel at or below the LHR limit assures that the NRC acceptance criteria (10 CFR 50.46(b)) for LOCA pipe breaks up to and including the double-ended severance of a reactor coolant pipe will be met with the ECCS for Millstone Unit 2.

14.6.6 REFERENCES

14.6-1 “Description of the Exxon Nuclear Plant Transient Simulation Model for Pressurized Water Reactors (PTS-PWR), XN-NF-74-5(A), Rev. 2 and Supplements 3-6, Exxon Nuclear Company, Richland, WA 99352, October 1986.

14.6-2 “XCOBRA-IIIC: A Computer Code to Determine the Distribution of Coolant During Steady-State and Transient Core Operation,” XN-NF-75-21(A), Revision 2, Exxon Nuclear Company.

14.6-3 E. Daniel Hughes, “A Correlation of Rod Bundle Critical Heat Flux for Water in the Pressure Range 150 to 725 psia,” IN-1412 (TID-4500), Idaho Nuclear Corporation, July 1970.


14.6-4 “RETRAN-02 A Program For Transient Thermal Hydraulic Analysis of Complex Fluid Flow Systems,” EPRI NP-1850-CNN, dated October 1984.

14.6-5 W. G. Counsil letter to J. R. Miller, Docket No. 50-336, dated December 12, 1983.

14.6-6 Technical Specifications for Millstone Unit 2, Docket No. 50-336, Updated through Amendment Number 116.

14.6-7 Letter, Dennis M. Crutchfield (USNRC Asst. Director division of PWR Licensing-B) to Gary M. Ward (ENC Manager, Reload Licensing), “Safety Evaluation of Exxon Nuclear Company's Large Break ECCS Evaluation Model EXEM/PWR and Acceptance for Referencing of Related Licensing Topical Reports,” dated July 8, 1986.

14.6-8 EXEM PWR LBLOCA Evaluation Model as defined by the following references:

a. XN-NF-82-20(A), Revision 1, and Supplements 1 through 4, “Exxon Nuclear Company Evaluation Model EXEM/PWR ECCS Model Updates,” Exxon Nuclear Company, Inc., Richland, WA 99352. Revision 1 dated January 1990, Supplements 1 to 4 dated January 1990.

b. XN-NF-82-07(A), Revision 1, “Exxon Nuclear Company ECCS Cladding Swelling and Rupture Model,” Exxon Nuclear Company, Richland, WA 99352, November 1982.

c. XN-NF-81-58(A) Revision 2, and Supplements 1 through 4, “RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model,” Exxon Nuclear Company, Richland, WA 99352. Revision 2 and Supplement 2 dated March 1984, Revision 2, Supplements 3 and 4 dated June 1990.

d. XN-NF-85-16(A), Volume 1 through Supplement 3; Volume 2, Revision 1 and Supplement 1, “PWR 17x17 Fuel Cooling Test Program,” Exxon Nuclear Company, Inc., Richland, WA 99352, February 1990.

e. XN-NF-85-105(A), Revision 0 and Supplement 1, “Scaling of FCTF-Based Reflood Heat Transfer Correlation for Other Bundle Designs,” Exxon Nuclear Company, Inc., Richland, WA 99352, January 1990.

14.6-9 EMF-2087(P), Revision 0, “SEM/PWR-98: ECCS Evaluation Model for PWR LBLOCA Applications”, Siemens Power Corporation, August 1998.

14.6-10 Nuclear Regulatory Commission Generic Letter 86-06, “Subject: Implementation of TMI Action Item II.K.3.5, 'Automatic Trip of Reactor Coolant Pumps,' (Generic Letter No. 86-06),” May 29, 1986



14.6-12 EMF-2328(P)(A), Rev. 0, “PWR Small Break LOCA Evaluation Model, S-RELAP5 Based”, March 2001.

14.6-13 EMF-2328(P)(A), Rev. 0, Supplement 1 (P)(A), Rev. 0, “PWR Small Break LOCA Evaluation Model, S-RELAP5 Based,” September 2015.

14.6-14 Code of Federal Regulations, Title 10, Part 50, Section 50.46, “Acceptance Criteria for Emergency Core Cooling Systems for Light Water Nuclear Power Reactors”.

14.6-15 CENPD-254-P-A, “Post-LOCA Long Term Cooling Evaluation Model”, June 1980, (Proprietary).

14.6-16 CEN-152, Rev. 04, “Combustion Engineering Emergency Procedure Guidelines”, October, 1996.

14.6-17 EMF-2103(P)(A), Revision 3, “Realistic Large Break LOCA Methodology for Pressurized Water Reactors,” June 2016.

14.6-18 NUREG/CR-5249, “Quantifying Reactor Safety Margins, Application of Code Scaling, Applicability, and Uncertainty Evaluation Methodology to a Large Break, Loss-of-Coolant Accident,” U.S. NRC, December 1989.

14.6-19 Regulatory Guide 1.203, “Transient and Accident Analysis Methods” U.S. NRC, December 2005.


* Defense in depth

TABLE 14.6.1-1 AVAILABLE REACTOR PROTECTION FOR THE INADVERTENT OPENING OF A PRESSURIZED WATER REACTOR PRESSURIZER PRESSURE

RELIEF VALVE EVENT


1 Thermal Margin/Low Pressure Trip Safety Injection Actuation Signal

2, 3 Safety Injection Actuation Signal Available Thermal Margin *

4 Available Thermal Margin *

5, 6 No Significant Consequences for these Reactor Operating Conditions


TABLE 14.6.1-2 DISPOSITION OF EVENTS FOR THE INADVERTENT OPENING OF A PRESSURIZED WATER REACTOR PRESSURIZER RELIEF VALVE EVENT


1, 2 Analyze for DNBR



TABLE 14.6.1-3 EVENT SUMMARY FOR AN INADVERTENT OPENING OF A PRESSURIZED WATER REACTOR PRESSURIZER PRESSURE RELIEF VALVE


Letdown Valve Open 0.00

Pressurizer Relief Valve Opens 0.01


Turbine Stop Valve Closed 9.13

Peak Power 9.58

MDNBR 9.69




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A PRESSURIZED WATER WER)

FIGURE 14.6.1–1 REACTOR POWER LEVEL FOR AN INADVERTENT OPENING OF REACTOR PRESSURIZER PRESSURE RELIEF VALVE (RATED PO

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FIGUR SSURIZED WATER REACTOR
E 14.6.1–2 CORE AVERAGE HEAT FLUX FOR AN INADVERTENT OPENING OF A PREPRESSURIZER PRESSURE RELIEF VALVE (RATED POWER)

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FIGUR OPENING OF A PRESSURIZED POWER)

E 14.6.1–3 REACTOR COOLANT SYSTEM TEMPERATURES FOR AN INADVERTENT WATER REACTOR PRESSURIZER PRESSURE RELIEF VALVE (RATED

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FIGU SURIZED WATER REACTOR
RE 14.6.1–4 PRESSURIZER PRESSURE FOR AN INADVERTENT OPENING OF A PRESPRESSURIZER PRESSURE RELIEF VALVE (RATED POWER)

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FIGUR TER REACTOR PRESSURIZER
E 14.6.1–5 REACTIVITIES FOR AN INADVERTENT OPENING OF A PRESSURIZED WAPRESSURE RELIEF VALVE (RATED POWER)

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FIG URIZED WATER REACTOR
URE 14.6.1–6 SECONDARY PRESSURE FOR AN INADVERTENT OPENING OF A PRESSPRESSURIZER PRESSURE RELIEF VALVE (RATED POWER)


TABLE 14.6.3-1 AVAILABLE REACTOR PROTECTION FOR THE RADIOLOGICAL CONSEQUENCES OF STEAM GENERATOR TUBE RUPTURE EVENT


1 Thermal Margin/Low Pressure Trip

Safety Injection Actuation Signal

2, 3 Safety Injection Actuation Signal

4-6 No Significant Consequences for These Reactor Operational Modes


TABLE 14.6.3-2 DISPOSITION OF EVENTS FOR THE RADIOLOGICAL CONSEQUENCES OF STEAM GENERATOR TUBE RUPTURE EVENT


1 Analyze radiological consequences

Fuel performance bounded by Event 14.6.1



1. Time values are rounded to the nearest second.

2. This is an assumed analytical time and is not a required operator action time.

TABLE 14.6.3-3 SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE EVENT

TIME 1 (seconds) EVENT

SETPOINT OR VALUE

0 Tube Rupture Occurs

0 Reactor Trip

0 Concurrent Loss of Offsite Power; Loss of Forced Circulation

0 Loss of Instrument Air; Loss of ADV Auto-Actuation

1 Ruptured SG MSSVs Begin to Lift (MSSVs Cycle - See Figure 14.6.3–8)

970 psia

3 Intact SG MSSVs Begin to Lift (MSSVs Cycle - See Figure 14.6.3–8)

1030 psia

9 Maximum SG Pressure Reached

- Ruptured SG 1054 psia

- Intact SG 1054 psia

37 AFW Actuation Condition Reached on Low SG Level 10% Narrow Range

277 AFW Delivery Starts

530 Pressurizer Empties

1200 Intact SG MSSVs Close for Final Time 940 psia

1220 SI Flow Begins to Enter RCS

1548 Ruptured SG MSSVs Close for Final Time 880 psia

1800 2 RCS Cooldown to Thot < 515°F Initiated Using ADVs (Manual Local Action)

3090 Pressurizer Begins to Refill

3637 Thot < 515°F Achieved; Ruptured Steam Generator Isolated


(1) until RCS is on shutdown cooling - release stops

TABLE 14.6.3-4 MASS RELEASES FOR THE STEAM GENERATOR TUBE RUPTURE ACCIDENT

Affected Steam Generator - Break Flow

Time Period, hours Total Break Flow Flashed Break Flow Liquid Break Flow

From To lbm lbm lbm

0 1 150,000 5,000 145,000

After 1 hour (1) 51,600 1,200 50,400

Affected Steam Generator - Total Steam Flow Through MSSVs and ADVs

Time Period, hours Mass Flow

From To lbm

0 1 1.700E+05

1 (1) 9.200E+04

Intact Steam Generator - Total Steam Flow Through MSSVs and ADVs

Time Period, hours Steam Flow Rate, lbm/minute

Steam Flow, lbm

From To

0.00 1.00 2.000E+03 1.20E+05

1.00 1.11 7.330E+03 4.84E+04

1.11 1.71 5.147E+03 1.85E+05

1.71 2.33 4.200E+03 1.56E+05

2.33 2.74 3.840E+03 9.45E+04

2.74 3.18 3.810E+03 1.01E+05

3.18 3.72 3.780E+03 1.22E+05

3.72 6.50 2.743E+03 4.58E+05

6.50 17.61 2.151E+03 1.43E+06


TABLE 14.6.3-5 ASSUMPTIONS FOR THE RADIOLOGICAL EVALUATION FOR THE STEAM GENERATOR TUBE RUPTURE EVENT

Primary to Secondary Leak Rate for Intact Steam Generator 150 gpd

Primary Coolant Iodine Concentration 1μCi/gm DEQ I-131

Secondary Coolant Iodine Concentration 0.1 μCi/gm DEQ I-131

Primary Coolant Noble Gas Concentration 1100 μCi/gm DE Xe-133

Pre-accident Spike Iodine Concentration 60 μCi/gm DEQ I-131

Concurrent Iodine Spike equivalent to 335 times iodine appearance rate at 1 μCi/gm DEQ I-131

Loss of Offsite Power is assumed at time of tube rupture.

Steam Generator Partition Factors

Iodine 0.01

Noble Gases 1

Particulates Note 1 0.004

Reactor Coolant Minimum Mass 423,00 lbm

Steam Generator Minimum / Maximum Mass 80,000 / 280,000 lbm

Site Boundary Breathing Rate (m3/sec)

0 - 8 hours 3.5 E -04

8 - 24 hours 1.8 E -04

24 - 720 hours 2.3 E -04

Site Boundary Dispersion Factors (sec/m3)

EAB: 0 - 2 hours 3.66 E -04

LPZ: 4 - 8 hours 4.80 E -05

4 - 8 hours 2.31 E -05

8 - 24 hours 1.06 E -05

24 - 96 hours 7.25 E -06

96 - 720 hours 2.32 E -06

Control Room Breathing Rate 3.5 E -04 m3/sec

Note 1: This constant value for Steam Generator Partition Factor for Particulates is a conservative representation of the moisture carryover anticipated during the event.


TABLE 14.6.3-5 ASSUMPTIONS FOR THE RADIOLOGICAL EVALUATION FOR THE STEAM GENERATOR TUBE RUPTURE EVENT (CONTINUED)

Control Room Isolation Time after Event Initiation

pre-accident spike - 20 seconds

(includes time for damper closure and radiation monitor response)

concurrent spike - 620 seconds

(includes time for damper closure and radiation monitor response)


Control Room Inleakage During Isolation 200 cfm

Control Room Filtered Recirculation Rate (t=1 hour, 20 sec) 2,250 cfm


Control Room Filter Efficiency (particulate/elemental/organic) 90 / 90 / 70 % (1)

Dose Conversion Factors Federal Guidance Reports 11 and 12

(1) 70% is a conservative analysis assumption for some iodine species. Technical Specifications can support assumptions for control room filter efficiencies of 90% for all iodine species.


MSSV ADV

0 - 2 hours 3.03 E -3 7.40 E -3

2 - 4 hours 2.30 E -3 5.71 E -3

4 - 8 hours 2.30 E -3 5.71 E -3

8 - 24 hours 8.46 E -4 2.13 E -3

24 - 96 hours 6.73 E -4 1.74 E -3

96 - 720 hours 5.49 E -4 1.43 E -3


TABLE 14.6.3-6 SUMMARY - RADIOLOGICAL CONSEQUENCES OF THE STEAM GENERATOR TUBE RUPTURE EVENT

SGTR EAB, rem-TEDE LPZ, rem-TEDE Control Room, rem-TEDE

concurrent spike 1.2E+00 1.6 E -01 4.5E+00

pre-accident spike 1.4E+00 1.8 E -01 4.5E+00


FIGURE 14.6.3–1 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POWER RCS TEMPERATURE VERSUS TIME

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FIG WER PRESSURIZER LEVEL
URE 14.6.3–2 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POVERSUS TIME

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FIGU ER PRESSURIZER PRESSURE
RE 14.6.3–3 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POWVERSUS TIME

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FIG WER STEAM GENERATOR
URE 14.6.3–4 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POPRESSURE VERSUS TIME

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FIGUR R TOTAL BREAK FLOW RATE
E 14.6.3–5 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POWEVERSUS TIME

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FIGU ER FLASHED BREAK FLOW
RE 14.6.3–6 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POWRATE VERSUS TIME

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FIG WER ATMOSPHERIC DUMP
URE 14.6.3–7 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POVALVE FLOW RATE PER STEAM GENERATOR VERSUS TIME

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FIG WER MAIN STEAM SAFETY E

URE 14.6.3–8 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POVALVE FLOW RATES PER STEAM GENERATOR VERSUS TIM

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FIGU ER AUXILIARY FEEDWATER
RE 14.6.3–9 STEAM GENERATOR TUBE RUPTURE WITH THE LOSS OF OFFSITE POWFLOW VERSUS TIME


TABLE 14.6.5.1-1 AVAILABLE REACTOR PROTECTION FOR THE LARGE BREAK LOSS OF COOLANT ACCIDENT


1, 2 No credit taken for reactor trip by the Reactor Protection System (RPS)

ECCS - short and long-term cooling

3-6 No significant consequences for these reactor operating conditions


TABLE 14.6.5.1-2 DISPOSITION OF EVENTS FOR THE LARGE BREAK LOSS OF COOLANT ACCIDENT


1 Analyze

2-6 Bounded by the event initiated from Mode 1


TABLE 14.6.5.1-3 MILLSTONE UNIT 2 REALISTIC LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS - PLANT PARAMETER VALUES AND RANGES

Plant Parameter Parameter Value

1.0 Plant Physical Description

1.1 Fuel

a) Cladding outside diameter 0.440 in.

b) Cladding inside diameter 0.387 in.

c) Cladding thickness 0.0265 in.

d) Pellet outside diameter 0.3805 in.

e) Initial Pellet density 96 percent of theoretical

f) Active fuel length 136.7 in.

g) Gd2O3 concentrations 2, 4, 6, 8 w/o

1.2 RCS

a) Flow resistance Analysis

b) Pressurizer location -

c) Hot assembly location Anywhere in core

d) Hot assembly type 14 x 14

e) SG tube plugging 5.87 percent

2.0 2.0 Plant Initial Operating Conditions

2.1 Reactor Power

a) Analyzed reactor power 2754 MWt

b) FQ 2.3851,2

c) Fr 1.8542

2.2 Fluid Conditions

a) Loop flow 132.2 Mlbm/hr < M < 160.0 Mlbm/hr

b) RCS cold leg temperature 536°F < T < 554°F

1. The value used for FQ is derived from the LHGR Technical Specification value2. Includes measurement uncertainty.3. Upper head temperature will change based on sampling of RCS temperature.


c) Upper head temperature ~Thot Temperature3

d) Pressurizer pressure 2190 psia < P < 2310 psia

e) Pressurizer level 35 percent < L< 75 percent

f) SIT pressure 195 psia < P < 280 psia

g) SIT liquid volume 1015 ft3< V < 1255 ft3

h) SIT temperature 60°F < T < 125°F (coupled with containmenttemperature)

i) SIT resistance fL/D As-built piping configuration

j) SIT boron 1720 ppm

3.0 Accident Boundary Conditions

a) Break location Cold leg pump discharge

b) Break type Double-ended guillotine or split

c) Break size (each side, relative to cold leg pipe area)

0.05 < A < 1.0 full pipe area (split)0.05 < A < 1.0 full pipe area (guillotine)

d) ECCS pumped injection temperature 140°F

e) HPSI pump delay 10 s (No-LOOP) 25 s (LOOP)

f) LPSI pump delay 30 s (No-LOOP) 45 s (LOOP)

g) Initial containment pressure 14.27 psia

h) Initial containment temperature 60°F < T < 125°F

i) Containment sprays delay 0 s

j) Containment spray water temperature 35°F





k) LPSI Flow

l) HPSI Flow




RCS Cold Leg Pressure (psia)

Broken Loop Flow 1A (gpm)

Intact Loop Flow 1B (gpm)

Intact Loop Flow 2A (gpm)


14.7 1369 1314 0 050 1214 1164 0 0

100 945 904 0 0150 546 519 0 0200 0 0 0 0300 0 0 0 0500 0 0 0 0700 0 0 0 0900 0 0 0 01000 0 0 0 01050 0 0 0 01100 0 0 0 0

1144.34 0 0 0 0


Broken Loop Flow 1A (gpm)


Intact Loop Flow 2A (gpm)


14.7 138 140 139 14050 136 138 137 138

100 133 135 134 135150 131 131 131 131200 128 128 128 128300 121 121 121 122500 106 106 106 106700 89 89 89 89900 68 68 68 681000 54 54 54 541050 43 43 43 431100 30 30 30 30

1144.34 0 00 0 0


TABLE 14.6.5.1-4 MILLSTONE UNIT 2 LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS - STATISTICAL DISTRIBUTION USED FOR PROCESS

PARAMETERS

Parameter

Operational Uncertainty Distribution

Parameter Range

Measurement Uncertainty Distribution

Standard Deviation

Pressurizer Pressure (psia) Uniform 2190 - 2310 Normal 0

Pressurizer Level (%) Uniform 35 - 75 Normal 0

SIT Volume (ft3) Uniform 1015 - 1255 N/A N/A

SIT Pressure (psia) Uniform 195 - 280 N/A N/A

Containment/SIT Temperature (°F) Uniform 60 - 125 N/A N/A

Containment Volume (x106 ft3) Uniform 1.899 - 2.125 N/A N/A

Initial Flow Rate (Mlbm/hr) Uniform 132.2 – 160.0 N/A N/A

Initial Operating Temperature (°F) Uniform 536 - 554 N/A N/A


TABLE 14.6.5.1-5 MILLSTONE UNIT 2 LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS - PASSIVE HEAT SINKS AND MATERIAL PROPERTIES IN

CONTAINMENT GEOMETRY

Heat SinkSurface Area,

ft2 Thickness, ft Material

Containment Shell and Dome 718700.02083 Carbon Steel3.02083 Concrete

Unlined Concrete 62800 2.0 Concrete

Galvanized Steel 1201000.0003 Galvanized Steel0.01697 Carbon Steel

Painted Thin Steel 61850 0.01667 Carbon SteelPainted Steel 32600 0.021667 Carbon SteelPainted Steel 25425 0.071667 Carbon SteelPainted Thick Steel 4630 0.245 Carbon Steel

Containment Penetration 30000.0625 Carbon Steel3.8125 Concrete

Stainless Lined Concrete 83400.020833 Stainless Steel2.020833 Concrete

Base Slab 11130 8.0 ConcreteNeutron Shield 16270 0.0154 Stainless SteelCEDM Cable Support 1380 0.1094 Stainless SteelPainted Steel 2891 0.031327 Carbon SteelPainted Steel 1856 0.02083 Carbon SteelPainted Steel 624.4 0.0374 Carbon SteelNon Galvanized Carbon Steel

23564 0.02167 Carbon Steel

Galvanized Carbon Steel 5423.40.003 Galvanized Steel

0.0112 Carbon Steel0.0115 Galvanized Steel

Stainless Steel 6948 0.02167 Stainless SteelAluminum 2300 0.01333 AluminumLead 7100 0.0325 Lead

Heat Sink MaterialThermal Conductivity

Btu/hr-ft-°FVolumetric Heat Capacity

Btu/ft3-°FConcrete 0.92 22.62Carbon Steel 27.00 58.80Stainless Steel 8.47 58.60Galvanized Steel 65.0 41.00Aluminum 118 35.2Lead 19.6 21.2


TABLE 14.6.5.1-6 MILLSTONE UNIT 2 LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS - COMPLIANCE WITH 10 CFR 50.46(B)

UTL for 95/95 Simultaneous Coverage/Confidence

Parameter Value Case Number

PCT, °F 1615 123

Maximum local oxidation, % 2.01 174

Core-wide oxidation, % 0.025 96

Characteristics of Case Setting the PCT UTL

PCT, °F 1615

PCT Rod Type Fresh 4% Gad Rod

Time of PCT, s 7.44

Elevation within Core, ft 9.36

Maximum Local Oxidation, % 1.98

Total Core-Wide Oxidation, % 0.006

PCT Rod Rupture Time, s No rod rupture

Rod Rupture Elevation within Core, ft No rod rupture


TABLE 14.6.5.1-7 MILLSTONE UNIT 2 LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS - SUMMARY OF MAJOR PARAMETERS FOR THE

DEMONSTRATION CASE

Parameter Value

Core Power (MWt) 2754

Time in Cycle (hrs) 11619

Limiting Rod Assembly Burnup (GWd/mtU) 18.4

Limiting Rod LHGR (kW/ft) 13.25

Limiting Rod Equivalent FQ 2.09

Limiting Rod Radial Peak, Fr 1.71

Limiting Rod Axial Shape Index -0.076

Break Type Split

Break Size (ft2/side) 3.6942

Offsite Power Availability LOOP


TABLE 14.6.5.1-8 MILLSTONE UNIT 2 LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS - CALCULATED EVENT TIMES FOR THE

DEMONSTRATION CASE*

* Loops 1, 2, 3 and 4 correspond to the plant Loops 1A, 1B, 2A and 2B, respectively.

Event Time (sec)

Break Opens 0.0

RCP Trip 0.0

SIAS Issued 0.7

PCT Occurred 7.4

Start of Broken Loop SIT Injection 16.6

Start of Intact Loop SIT Injection (Loop 2,3 and 4 respectively)

17.3, 17.3 and 17.3

HPSI Available 25.7

Broken Loop HPSI Delivery Began 25.7

Intact Loops HPSI Delivery Began (Loop 2, 3 and 4 respectively)

25.7, 25.7 and 25.7

Beginning of Core Recovery (Beginning of Reflood) 26.8

LPSI Available 45.7

Broken Loop LPSI Delivery Began 45.7

Intact Loops LPSI Delivery Began 45.7, N/A and N/A

Intact Loop SIT Emptied(Loop 2, 3 and 4 respectively)

62.0, 62.1 and 61.5

Broken Loop SIT Emptied 63.3

Transient Calculation Terminated 900.0


FIGURE 14.6.5.1–1 SCATTER PLOT OPERATIONAL PARAMETERS


FIGURE 14.6.5.1–2 PCT VERSUS PCT TIME SCATTER PLOT


FIGURE 14.6.5.1–3 PCT VERSUS PCT TIME SCATTER PLOT


FIGURE 14.6.5.1–4 MAXIMUM LOCAL OXIDATION VERSUS PCT SCATTER PLOT


FIGURE 14.6.5.1–5 TOTAL CORE WIDE OXIDATION VERSUS PCT SCATTER PLOT


FIGURE 14.6.5.1–6 PEAK CLADDING TEMPERATURE (INDEPENDENT OF ELEVATION) FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–7 BREAK FLOW FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–8 CORE INLET MASS FLUX FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–9 CORE OUTLET MASS FLUX FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–10 VOID FRACTION AT RCS PUMPS FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–11 ECCS FLOWS (INCLUDES SIT, HPSI AND LPSI) FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–12 UPPER PLENUM PRESSURE FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–13 COLLAPSED LIQUID LEVEL IN THE DOWNCOMER FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–14 COLLAPSED LIQUID LEVEL IN THE LOWER PLENUM FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–15 COLLAPSED LIQUID LEVEL IN THE CORE FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–16 CONTAINMENT AND LOOP PRESSURES FOR THE DEMONSTRATION CASE


FIGURE 14.6.5.1–17 PRESSURE DIFFERENCES BETWEEN UPPER PLENUM AND DOWNCOMER FOR THE DEMONSTRATION CASE


TABLE 14.6.5.2-1 AVAILABLE REACTOR PROTECTION FOR THE SMALL BREAK LOSS OF COOLANT ACCIDENT


1 Thermal Margin/Low Pressure Trip

Low Reactor Coolant Flow Trip

Safety Injection Actuation Signal

2 Safety Injection Actuation Signal

3-6 No Significant Consequences for These Reactor Operating Conditions


TABLE 14.6.5.2-2 DISPOSITION OF EVENTS FOR THE SMALL BREAK LOSS OF COOLANT ACCIDENT


1 Analyze

2-6 Bounded by the Event Initiated from Mode 1


TABLE 14.6.5.2-3 MILLSTONE UNIT 2 SMALL BREAK LOSS OF COOLANT ACCIDENT SYSTEM ANALYSIS PARAMETERS

Reactor Power, MWt 2754

Axial Power Shape -

Peak LHR, kW/ft 15.1

Radial Peaking Factor (1.69 plus uncertainties) 1.854

RCS Flow Rate, gpm 360,000

Pressurizer Pressure, psia 2250

Core Inlet Coolant Temperature, °F 549

SIT Pressure, psia 214.7

SIT Fluid Temperature, °F 120

SIT Water Volume, ft3 1135

Maximum SG Tube Plugging Level per SG, % 5.87

SG Secondary Pressure, psia 880

MFW Temperature, °F 435

AFW Flow Rate per SG, gpm 72

AFW Temperature, °F 70

Low-Low SG Level Setpoint, % Narrow Range Span 0

AFW Delay, sec 240

HPSI and LPSI Fluid Temperature, °F 140

Pressurizer Pressure - Low Reactor Trip Setpoint (RPS), psia 1700

Reactor Trip Delay Time on Low Pressurizer Pressure, sec 0.9

CEA Holding Coil Release Delay Time, sec 0.5

SIAS Activation Pressurizer Pressure Setpoint (Harsh Environment Conditions), psia

1500

HPSI Pump Delay Time on SIAS, sec 25

LPSI Pump Delay Time on SIAS, sec 45

MSSV Lift Pressure and Tolerance Nominal+ 3%


TABLE 14.6.5.2-3 MILLSTONE UNIT 2 SMALL BREAK LOSS OF COOLANT ACCIDENT SYSTEM ANALYSIS PARAMETERS (CONTINUED)

High Pressure Safety Injection Flow Rate for Cold Leg Breaks

RCS Cold Leg Pressure (psia) Loop 1A (gpm) Loop 1B (gpm) Loop 2A (gpm) Loop 2B (gpm)

14.7 143 142 145 145

50 141 140 142 142

100 138 138 139 139

150 135 135 135 135

200 132 132 132 132

300 125 125 125 125

500 109 109 109 109

700 92 92 92 92

900 71 71 71 71

1000 59 59 59 59

1050 52 52 52 52

1100 43 43 43 43

1150 30 30 30 30

1190 15 15 15 15

1204 0 0 0 0


TABLE 14.6.5.2-3 MILLSTONE UNIT 2 SMALL BREAK LOSS OF COOLANT ACCIDENT SYSTEM ANALYSIS PARAMETERS (CONTINUED)

Low Pressure Safety Injection Flow Rates for Cold Leg Breaks


Intact Loop 1A (gpm)

Intact Loop 1B (gpm)

Intact Loop 2A (gpm)

Intact Loop 2B (gpm)

14.7 1314 0 0 1369

50 1164 0 0 1214

100 904 0 0 945

150 519 0 0 546

200 0 0 0 0


TABLE 14.6.5.2-4 DELETED BY FSCR MPS-UCR-2016-016

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TABLE 14.6.5.2-5 CALCULATED EVENT TIMES FOR SMALL BREAK LOSS-OF-COOLANT ACCIDENT

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2.00 1135 0 66 67 79 90 104 124 242 -- 516 -- -- -- 1088 1100 -- 4116 -- 4330 3030 --3.00 1384 0 29 30 38 54 63 83 98 -- 418 -- -- -- 512 552 -- 2082 -- 2451 280 --3.60 1472 0 20 22 29 46 54 74 68 -- 414 -- -- -- 384 394 5700 1638 -- 2008 208 --3.70 1501 0 19 21 27 46 52 72 64 -- 412 -- -- -- 364 374 5102 1572 -- 1978 200 --3.75 1599 0 19 20 27 46 52 72 64 -- 422 -- -- -- 360 370 4660 1458 1772 1892 190 --3.76 1651 0 19 20 27 46 52 72 62 -- 420 -- -- -- 358 368 4638 1428 1654 1857 188 --3.78 1707 0 19 20 27 44 52 72 62 -- 408 -- -- -- 356 366 4580 1386 1563 1824 186 --3.785 1690 0 19 20 27 44 52 72 62 -- 408 -- -- -- 356 366 4534 1396 1591 1852 186 --3.79 1476 0 18 20 26 44 51 71 62 -- 408 944 -- 1950 1330 374 -- 1680 -- 2035 186 --3.90 1606 0 18 19 25 44 50 70 58 -- 434 -- 366 2340 1176 350 1944 1598 1852 1954 192 --4.02 1596 0 17 18 24 42 49 69 56 -- 430 700 -- 1250 1278 340 1738 1452 1684 1746 184 --4.40 1581 0 14 16 22 40 47 67 48 -- 442 600 -- 1230 954 292 1278 1230 1270 1284 154 --4.60 1621 0 13 15 20 40 45 65 46 -- 514 250 250 -- 478 272 1068 1072 1047 1076 144 --4.80 1637 0 13 14 19 40 44 64 46 956 -- -- 480 -- 574 260 934 936 907 939 136 --5.00 1615 0 12 13 19 38 44 64 44 848 -- -- 430 710 506 260 824 830 814 832 128 --5.30 1591 0 11 13 18 38 43 63 44 714 -- -- 290 250 224 232 692 698 691 699 118 --5.50 1398 0 11 12 17 38 42 62 42 692 -- 436 204 270 190 212 670 674 -- 674 112 --6.00 1535 0 10 12 16 38 41 61 42 514 -- -- 186 180 180 188 496 500 -- 501 102 --7.00 1510 0 9 11 14 38 39 59 40 360 -- 258 264 180 112 146 350 352 -- 353 74 --8.00 1540 0 9 10 13 218 38 58 40 264 -- -- 98 116 86 114 254 256 -- 258 56 --9.00 1399 0 9 10 13 -- 38 58 38 206 -- 70 86 66 102 84 198 202 -- 202 46 2889.49 1437 0 9 10 12 -- 37 57 38 184 -- 74 76 60 84 78 178 180 -- 180 42 --


TABLE 14.6.5.2-6 ANALYSIS RESULTS FOR SMALL BREAK LOSS-OF-COOLANT ACCIDENT

Break diameter (in) 2.00 3.00 3.60 3.70 3.75 3.76

Break Area (ft2) 0.02182 0.04909 0.07069 0.07467 0.07670 0.07711

Peak Clad Temperature (°F)

1135 1384 1472 1501 1599 1651

Time of PCT (sec) 4330 2451 2008 1978 1892 1857Time of Rupture (sec) -- -- -- -- 1772 1654Transient MLO (%) 0.0864 0.4249 0.6647 0.7543 1.9966 2.6718Total MLO (%) 2.337 2.676 2.915 3.005 4.247 4.922Core Wide Oxidation (%) 0.0042 0.0111 0.0124 0.0139 0.0254 0.0314PCT Elevation (ft) 10.52 10.52 10.77 10.77 11.02 11.02


Break Area (ft2) 0.07793 0.07814 0.07834 0.08296 0.08814 0.10559


1707 1690 1476 1606 1596 1581

Time of PCT (sec) 1824 1852 2035 1954 1746 1284Time of Rupture (sec) 1563 1591 -- 1852 1684 1270Transient MLO (%) 3.5273 3.2474 0.6689 1.3276 1.1046 0.6721Total MLO (%) 5.778 5.498 2.920 3.578 3.355 2.923Core Wide Oxidation (%) 0.0396 0.0368 0.0119 0.0175 0.0162 0.0110PCT Elevation (ft) 11.02 11.02 10.77 11.02 11.02 10.52


Break Area (ft2) 0.11541 0.12566 0.13635 0.15321 0.16499 0.19635


1621 1637 1615 1591 1398 1535

Time of PCT (sec) 1076 939 832 699 674 501Time of Rupture (sec) 1047 907 814 691 -- --Transient MLO (%) 0.7874 0.8477 0.6456 0.5072 0.1142 0.2316Total MLO (%) 3.038 3.098 2.896 2.758 2.365 2.482Core Wide Oxidation (%) 0.0108 0.0111 0.0091 0.0075 0.0020 0.0051PCT Elevation (ft) 10.77 10.77 10.52 10.52 10.27 10. 27


TABLE 14.6.5.2-6 ANALYSIS RESULTS FOR SMALL BREAK LOSS-OF-COOLANT ACCIDENT (CONTINUED)

Break diameter (in) 7.00 8.00 9.00 9.49

Break Area (ft2) 0.26725 0.34907 0.44179 0.49120

Peak Clad Temperature (°F) 1510 1540 1399 1437Time of PCT (sec) 353 258 202 180Time of Rupture (sec) -- -- -- --Transient MLO (%) 0.2133 0.2247 0.1097 0.1367Total MLO (%) 2.464 2.475 2.360 2.387Core Wide Oxidation (%) 0.0049 0.0046 0.0018 0.0024PCT Elevation (ft) 10. 27 10. 27 10.02 10.02


TABLE 14.6.5.2-7 PEAK CLAD TEMPERATURE INCLUDING ALL PENALTIES AND BENEFITS - SMALL BREAK LOCA

LICENSING BASIS PCT (°F)Delta PCT

(°F)

Analysis of Record Peak Clad Temperature (PCT) 1707

PCT ASSESSMENTS (Delta PCT)

1. Zirc-4 Cladding Assessment 4

2. Error in the S-RELAP5 Oxidation Calculation 3

LICENSING BASES PCT including all PCT ASSESSMENTS = 1714°F


FIGURE 14.6.5.2–1 PEAK CLADDING TEMPERATURE VERSUS BREAK SIZE (SBLOCA BREAK SPECTRUM)


FIGURE 14.6.5.2–2 REACTOR POWER - 3.78-INCH BREAK


FIGURE 14.6.5.2–3 PRIMARY AND SECONDARY SYSTEM PRESSURES - 3.78-INCH BREAK


FIGURE 14.6.5.2–4 BREAK MASS FLOW RATE - 3.78-INCH BREAK


FIGURE 14.6.5.2–5 BREAK VAPOR VOID FRACTION - 3.78-INCH BREAK


FIGURE 14.6.5.2–6 LOOP SEAL VOID FRACTION - 3.78-INCH BREAK


FIGURE 14.6.5.2–7 TOTAL CORE INLET MASS FLOW RATE - 3.78-INCH BREAK


FIGURE 14.6.5.2–8 DOWNCOMER COLLAPSED LIQUID LEVEL - 3.78-INCH BREAK


FIGURE 14.6.5.2–9 INNER AND OUTER CORE COLLAPSED LIQUID LEVEL - 3.78-INCH BREAK


FIGURE 14.6.5.2–10 REACTOR VESSEL MASS - 3.78-INCH BREAK


FIGURE 14.6.5.2–11 RCS LOOP MASS FLOW RATES - 3.78-INCH BREAK


FIGURE 14.6.5.2–12 STEAM GENERATOR MAIN FEEDWATER MASS FLOW RATES - 3.78-INCH BREAK


FIGURE 14.6.5.2–13 STEAM GENERATOR AUXILIARY FEEDWATER MASS FLOW RATES - 3.78-INCH BREAK


FIGURE 14.6.5.2–14 STEAM GENERATOR TOTAL MASS - 3.78-INCH BREAK


FIGURE 14.6.5.2–15 STEAM GENERATOR NARROW RANGE LEVEL % - 3.78-INCH BREAK


FIGURE 14.6.5.2–16 HIGH PRESSURE SAFETY INJECTION MASS FLOW RATES - 3.78-INCH BREAK


FIGURE 14.6.5.2–17 LOW PRESSURE SAFETY INJECTION MASS FLOW RATES - 3.78-INCH BREAK


FIGURE 14.6.5.2–18 SAFETY INJECTION TANK MASS FLOW RATES - 3.78-INCH BREAK


FIGURE 14.6.5.2–19 INTEGRATED BREAK FLOW AND ECCS FLOW - 3.78-INCH BREAK


FIGURE 14.6.5.2–20 HOT ASSEMBLY COLLAPSED LIQUID LEVEL - 3.78-INCH BREAK


FIGURE 14.6.5.2–21 HOT ASSEMBLY MIXTURE LEVEL - 3.78-INCH BREAK


FIGURE 14.6.5.2–22 PEAK CLADDING TEMPERATURE AT PCT LOCATION (11.02 FT) - 3.78-INCH BREAK


FIGURE 14.6.5.2–23 (DELETED BY FSARCR 00-MP2-023)


FIGURE 14.6.5.2–24 (DELETED BY FSARCR 00-MP2-023)


TABLE 14.6.5.3-1 CORE AND SYSTEM PARAMETERS USED IN THE LTC ANALYSIS

Parameter Value

Reactor power level, MWt (102% of nominal) 2754

Number of plugged tubes per SG 1000

SG / RCS cooldown rate, °F/hr (maximum) 40

Atmospheric dump valve capacity at 1000 psia, lbm/hr/valve (minimum) 879,028

Boric acid concentration, ppm (maximum)

Reactor coolant system 2640

Refueling water tank 2640

Safety injection tanks 2640

Boric acid storage tanks 6139

Initial inventory (maximum)

Reactor coolant system, lbm 543,710

Refueling water tank, gal 448,520

Safety injection tanks, ft3/tank 1190

Boric acid storage tank, ft3/tank 865.7


FIGURE 14.6.5.3–1 LONG TERM COOLING PLAN


FIGURE 14.6.5.3–2 REACTOR COOLANT SYSTEM REFILL TIME VS. BREAK AREA


FIGURE 14.6.5.3–3 CORE FLUSH BY HOT SIDE INJECTION FOR A DOUBLE-ENDED GUILLOTINE COLD LEG BREAK


FIGURE 14.6.5.3–4 INNER VESSEL BORIC ACID CONCENTRATION VS. TIME FOR A DOUBLE-ENDED GUILLOTINE COLD LEG BREAK


TABLE 14.6.5.4-1 AVAILABLE REACTOR PROTECTION FOR THE LARGE BREAK LOSS OF COOLANT ACCIDENT


1, 2 No credit taken for reactor trip by the Reactor Protection System (RPS)

ECCS - short and long-term cooling

3-6 No significant consequences for these reactor operating conditions


TABLE 14.6.5.4-2 DISPOSITION OF EVENTS FOR THE LARGE BREAK LOSS OF COOLANT ACCIDENT


1 Analyze

2-6 Bounded by the event initiated from Mode 1


TABLE 14.6.5.4-3 MILLSTONE UNIT 2 SYSTEM ANALYSIS PARAMETERS (LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS)

Primary Heat Output, MWt 2700 *

Primary Coolant Flow Rate, lbm/hr 1.36 x 108 (360,000 gpm)

Primary Coolant System Volume, ft3 11,000 **

Operating Pressure, psia 2250

Inlet Coolant Temperature, °F 549

Reactor Vessel Volume, ft3 4538

Pressurizer Total Volume, ft3 1500

Pressurizer Liquid Total, ft3 800

SIT Total Volume, ft3 (one of four) 2019

SIT Liquid Volume, ft3 1150.5

SIT Pressure, psia 238.5

SIT Fluid Temperature, °F 106.8

Total Number of Tubes per Steam Generator 8523

Steam Generator Tube Plugging 5.9%

Number of Tubes Plugged (Broken Loop) 500

Number of Tubes Plugged (Double Intact Loop) 500

Steam Generator Secondary Side Heat Transfer Area (Broken Loop), ft2

87,130

Steam Generator Secondary Side Heat Transfer Area, (Intact Loop), ft2

87,130

Steam Generator Secondary Flow Rate lbm/hr 6.04 x 106

Steam Generator Secondary Pressure (broken loop), psia 878.4

Steam Generator Secondary Pressure (intact loop), psia 878.4

Steam Generator Feedwater Temperature, °F 435

Reactor Coolant Pump Rated Head, feet 271.8

Reactor Coolant Pump Head, feet (DIL) 230.38 ***

Reactor Coolant Pump Head, feet (SIL,BL) 233.00 ***


* Primary Heat Output used in RELAP4-EM Model - 1.02 x 2700 = 2754 MWt.

** Includes pressurizer total volume and 5.9% SGTP

*** Values used in RELAP4 for initialization.

Reactor Coolant Pump Rated Torque, ft-lbf 31,560

Reactor Coolant Pump Rated Speed, rpm 892

Initial Reactor Coolant Pump Speed, rpm 866.8 ***

Reactor Coolant Pump Moment of Inertia, lbm-ft2 100,000

Maximum Containment Net Free Volume, ft3 1.938 x 106

Containment Temperature, °F 101.6

SIS Fluid Temperature, °F 72.8

HPSI Delay Time, sec 25.0

LPSI Delay Time, sec 45.0

TABLE 14.6.5.4-3 MILLSTONE UNIT 2 SYSTEM ANALYSIS PARAMETERS (LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS) (CONTINUED)


**** SIS delivery to specific loops was chosen to ensure conservative results and thus does not reflect the actual plant cold leg/SIS train arrangement. For example, the larger of the two LPSI flows under loss-of-diesel conditions was directed to the broken loop. The model is insensitive to intact loop/SIS train assignments. Analysis delivery curves shown above differ from the latest calculated values. An evaluation has shown that the analysis values are bounding.

TABLE 14.6.5.4-3 MILLSTONE UNIT 2 SYSTEM ANALYSIS PARAMETERS (LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS (CONTINUED)

SIS Delivery Curves for Loss-of-Diesel Single Failure ****

RCS Pressure

(psia)DIL HPSI

(gpm)SIL HPSI

(gpm)BL HPSI

(gpm)

DIL LPSI (gpm)

SIL LPSI (gpm)

BL LPSI (gpm)

1144.34 0.00 0.00 0.00 0.00 0.00 0.00

1100.00 61.38 30.69 30.69 0.00 0.00 0.00

1050.00 87.75 43.88 43.88 0.00 0.00 0.00

1000.00 108.65 54.33 54.33 0.00 0.00 0.00

900.00 137.89 68.95 68.95 0.00 0.00 0.00

700.00 178.35 89.18 89.18 0.00 0.00 0.00

500.00 213.13 106.57 106.57 0.00 0.00 0.00

300.00 243.43 121.22 121.22 0.00 0.00 0.00

200.00 256.67 128.34 128.34 0.00 0.00 0.00

150.00 263.57 131.31 131.59 0.00 498.35 605.38

100.00 270.04 133.80 134.54 0.00 881.92 1039.03

50.00 276.41 136.26 137.44 0.00 1156.35 1349.84

14.70 280.83 138.01 139.47 0.00 1310.58 1524.66

0.00 280.83 138.01 139.47 0.00 1310.58 1524.66


***** SIS delivery to specific loops was chosen to ensure conservative results and thus does not reflect the actual plant cold leg/SIS train arrangement. For example, the largest of the LPSI flows under loss-of-LPSI conditions was directed to the broken loop. The model is insensitive to intact loop/SIS train assignments

TABLE 14.6.5.4-3 MILLSTONE UNIT 2 SYSTEM ANALYSIS PARAMETERS (LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS (CONTINUED)

SIS Delivery Curves for Loss-of-LPSI Single Failure *****

RCS Pressure

(psia)DIL HPSI

(gpm)SIL HPSI

(gpm)BL HPSI

(gpm)DIL LPSI

(gpm)SIL LPSI

(gpm)BL LPSI

(gpm)

1144.34 0.00 0.00 0.00 0.00 0.00 0.00

1100.00 122.57 61.13 61.32 0.00 0.00 0.00

1050.00 175.22 87.38 87.65 0.00 0.00 0.00

1000.00 216.94 108.18 108.52 0.00 0.00 0.00

900.00 275.49 137.38 137.81 0.00 0.00 0.00

700.00 356.28 177.66 178.22 0.00 0.00 0.00

500.00 425.78 212.31 212.98 0.00 0.00 0.00

300.00 484.25 241.46 242.23 0.00 0.00 0.00

200.00 512.67 255.64 256.45 0.00 0.00 0.00

150.00 525.61 262.00 263.11 653.94 274.77 398.76

100.00 537.51 267.76 269.33 1155.32 512.61 664.06

50.00 549.31 273.50 275.44 1475.25 663.50 834.75

14.70 557.54 277.50 279.70 1669.90 755.14 938.85

0.00 557.54 277.50 279.70 1669.90 755.14 938.85


* NOLPSI denotes single failure of one LPSI pump, and NODIESEL denotes single failure of one diesel generator.

TABLE 14.6.5.4-4 MILLSTONE UNIT 2 LARGE BREAK LOSS OF COOLANT ACCIDENT ANALYSIS

Summary of PCT Results

Break ConfigurationBreak Cd or

Size Axial Shape

Limiting Single

Failure * PCT (°F)

BOC NOLPSI 1662

0.4 MOC NOLPSI 1711

EOC NOLPSI 1722

BOC NOLPSI 1664

0.6 MOC NOLPSI 1759

DECLG EOC NOLPSI 1770

BOC NOLPSI 1694

0.8 MOC NOLPSI 1784

EOC NOLPSI 1806

BOC NOLPSI 1688

1.0 MOC NOLPSI 1786

EOC NODIESEL 1814

BOC NOLPSI 1606

0.8 MOC NOLPSI 1669

SECLS EOC NODIESEL 1713

BOC NODIESEL 1630

1.0 MOC NODIESEL 1732

EOC NODIESEL 1759


* At 450 seconds

TABLE 14.6.5.4-5 MILLSTONE UNIT 2 LARGE BREAK LOCA ANALYSIS

Summary of Results for the Limiting Cases

1.0 DECLEG EOC Loss-of-Diesel

Hot Rod Rupture

Time (seconds) 43.002

Node Elevation (feet) 9.766

Flow Area Reduction (%) 46.37

Peak Cladding Temperature

Temperature (°F) 1814

Time (seconds) 135.784

Elevation (feet) 10.516

Metal-Water Reaction *

Local Maximum (%) 2.364

Elevation of Local Maximum (feet) 10.516

Hot Rod Total (%) 0.390

Core Maximum (%) < 1


TABLE 14.6.5.4-6 MILLSTONE UNIT 2 LARGE BREAK LOCA ANALYSIS

Sequence of Events for the Overall Limiting Case (1.0 DECLG EOC Loss-of-Diesel)

Event Time (s)

Analysis began 0.00

Break opened 0.05

SIAS issued 0.7

Broken loop SIT injection began 9.5

Double intact loop SIT injection began 14.9

Single intact loop SIT injection began 14.9

Refill began (EOBY) 18.1

Reflood began (BOCREC) 31.3

Fuel rupture occurred 43.0

Broken loop SIT emptied 48.1

Double intact loop SIT emptied 51.3

Single intact loop SIT emptied 51.9

PCT occurred 135.8


TABLE 14.6.5.4-7 PEAK CLAD TEMPERATURE INCLUDING ALL PENALTIES AND BENEFITS - LARGE BREAK LOCA

LICENSING BASISPCT(°F)

Delta PCT (°F)

Analysis of Record Peak Clad Temperature (PCT) 1814

PCT ASSESSMENTS (Delta PCT)

1. Corrected Corrosion Enhancement Factor -1

2. ICECON Coding Errors 0

3. Setting RFPAC Fuel Temperature at Start of Reflood -2

4. SISPNCH/ujun98 Code Error 0

5. Error in Flow Blockage Model in TOODEE2 0

6. Change in TOODEE2-Calculation of OMAX 0

7. Change in Gadolinia Modeling 0

8. PWR LBLOCA Split Break Modeling 0

9. TEOBY Calculation Error 0

10. Inappropriate Heat Transfer in TOODEE2 0

11. End-of-Bypass Prediction by TEOBY 0

12. R4SS Overwrite of Junction Inertia 0

13. Incorrect Junction Inertia Multipliers 1

14. Errors Discovered During RODEX2 V&V 0

15. Error in Broken Loop Steam Generator Tube Exit Junction Inertia

0

16. RFPAC Refill and Reflood Calculation Code Errors 16

17. Incorrect Pump Junction Area Used in RELA4 0

18. Error in TOODEE2 Clad Thermal Expansion -1

19. Accumulator Line Loss Error -1

20. Inconsistent Loss Coefficients Used for Robinson LBLOCA 0

21. Pump Head Adjustment for Pressure Balance Initialization -3

22. ICECON Code Errors 0

23. Containment Sump Modification and Replacement PZR 2

24. Non-Conservative RODEX Fuel Pellet Temperature 20

25. Array Index Issues in the RELAP4 Code 0

LICENSING BASES PCT including all PCT ASSESSMENTS = 1845°F


FIGURE 14.6.5.4–1 NORMALIZED POWER (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–2 SAFETY INJECTION TANK (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–3 HIGH PRESSURE SAFETY INJECTION FLOW RATES (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–4 LOW PRESSURE SAFETY INJECTION FLOW RATES (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–5 UPPER PLENUM PRESSURE DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–6 TOTAL BREAK FLOW RATE DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–7 AVERAGE CORE INLET FLOW RATE DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–8 HOT CHANNEL INLET FLOW RATE DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–9 PEAK CLADDING TEMPERATURE NODE FLUID QUALITY DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–10 PEAK CLADDING TEMPERATURE NODE FUEL (AVERAGE), CLADDING AND FLUID TEMPERATURES DURING BLOWDOWN (1.0 DECLG EOC

LOSS-OF-DIESEL)


FIGURE 14.6.5.4–11 PEAK CLADDING TEMPERATURE NODE HEAT TRANSFER COEFFICIENT DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–12 PEAK CLADDING TEMPERATURE NODE HEAT FLUX DURING BLOWDOWN (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–13 CONTAINMENT PRESSURE (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–14 UPPER PLENUM PRESSURE (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–15 DOWNCOMER MIXTURE LEVEL (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–16 CORE EFFECTIVE FLOODING RATE (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–17 CORE MIXTURE LEVEL (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–18 CORE QUENCH LEVEL (1.0 DECLG EOC LOSS-OF-DIESEL)


FIGURE 14.6.5.4–19 PEAK CLADDING TEMPERATURE NODE AND RUPTURED NODE CLADDING TEMPERATURES (1.0 DECLG EOC LOSS-OF-DIESEL)


14.7 RADIOACTIVE RELEASES FROM A SUBSYSTEM OR COMPONENT

14.7.1 WASTE GAS SYSTEM FAILURE

This section has been moved to Section 11.1.4.4.

14.7.2 RADIOACTIVE LIQUID WASTE SYSTEM LEAK OR FAILURE (RELEASE TO ATMOSPHERE)


14.7.3 POSTULATED RADIOACTIVE RELEASES DUE TO LIQUID CONTAINING TANK FAILURES


14.7.4 RADIOLOGICAL CONSEQUENCES OF FUEL HANDLING ACCIDENT

14.7.4.1 General

The likelihood of a fuel handling accident is minimized by administrative controls and physical limitations imposed upon fuel handling operations. All refueling operations are conducted in accordance with prescribed procedures under direct surveillance of a qualified supervisor. Also, before any refueling operations begin, verification of complete control element assembly (CEA) insertion is obtained by tripping each CEA individually to obtain indication of assembly drop and disengagement from the drive shaft. Boron concentration in the coolant is raised to the refueling concentration of 1720 ppm boron, or more per Technical Specifications and is verified by chemical analysis. At the required boron concentration, the core will be more than 5 percent 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 use of encoders and limit switches in the fuel handling hoists and manipulators to ensure that the minimum depth of water above the active fuel required for shielding is always present. This constraint applies in fuel handling areas inside containment and in the spent fuel pool area. 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 or fuel pool. Fuel pool structural integrity is assured by designing the pool and the spent fuel storage racks as Seismic Class I structures.

The design of the spent fuel storage racks and handling facilities in both the containment and fuel storage area is such that fuel will always be in a subcritical geometrical array. The spent fuel pool contains a minimum of 2100 ppm of boron, and the refueling pool water contains a minimum of


1720 ppm of boron. 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 the spent fuel removed from the water.

Fuel failure during refueling as a result of inadvertent criticality or overheating is not possible. The possibility of damage to a fuel assembly as a consequence of mishandling is minimized by extensive personnel training, detailed procedures, and equipment design. Equipment design and administrative controls preclude the handling of heavy objects such as shipping casks over the spent fuel storage racks with the exception of the consolidated fuel storage box or any object bounded by the consolidated fuel storage box drop analysis and any single failure proof lift by the spent fuel cask crane in accordance with the guidelines of NUREG-0612. Inadvertent disengagement of a fuel assembly or consolidated fuel storage box from the fuel handling machine is prevented by mechanical interlocks. Consequently, the possibility of dropping either one and damaging of a fuel assembly is remote.

Should a fuel assembly be dropped or otherwise damaged during handling, radioactive release could occur in either the containment or the auxiliary building. If ventilation is available and boundary integrity is set the ventilation exhaust air from both of these areas is monitored before release to the atmosphere (see Section 7.5.6.3). The radiation monitors immediately indicate the increased activity level and alarm. The affected area would then be evacuated.

Forced ventilation is not required while handling irradiated fuel in containment or in the fuel building, nor is containment or fuel handling area boundary integrity required. This allows any penetration to the containment (including the equipment hatch and personnel access door) or fuel handling area boundaries (e.g., including roll-up doors) to be open during fuel movement. Suitable radiological monitoring is recommended per the Millstone Effluent Control Program when boundary integrity is not set to ensure releases to the environment are monitored.

There is no requirement for automatic isolation of containment purge to mitigate a release through the containment purge system during fuel movement.

14.7.4.2 Method of Analysis

For the purpose of defining the upper limit on fuel damage as the result of a fuel handling accident, it is assumed that the fuel assembly or consolidated fuel storage box is dropped during handling by the spent fuel platform crane. Interlocks, procedural and administrative controls make such events unlikely. However, if assemblies are damaged to the extent that a number of fuel rods fail, the accumulated fission gases and iodines in the fuel element gap could be released to the surrounding water. Release of the particulate fission products is considered negligible due to the surrounding water.

The fuel assemblies and consolidated fuel storage box are stored within the spent fuel rack at the bottom of the spent fuel pool. The top of the rack extends above the top of the stored fuel. A dropped fuel assembly or consolidated fuel storage box could not strike more than one fuel assembly in the storage rack. Impact can occur only between the ends of the involved


components, the bottom end fitting of the dropped components impacting against the top end fitting of the stored fuel assembly. The results of an analysis on the energy absorption capability of a fuel assembly indicate that a fuel assembly in the storage rack is capable of absorbing the kinetic energy of the fuel assembly, heavy dummy fuel assembly, or consolidated fuel storage box drop with no fuel rod failures. The worst fuel handling incident that could occur in the spent fuel pool is the dropping of a fuel assembly to the fuel pool floor. It is assumed all of the fuel rods within one fuel assembly will fail as a result of a fuel handling incident within containment or the spent fuel pool area.

All X/Q values have been chosen in the following manner: Site meteorological data has been examined for the years 1974 - 1981 for off site X/Qs and 1997 - 2001 for control room X/Qs. For each release point and dose calculation time period in question, the year with the largest (most conservative) 95% maximum off site X/Q value has been chosen. Control room X/Qs are developed consistent with Regulatory Guide 1.194 except for those from the Millstone Stack, based on Regulatory Guide 1.145.

For each accident, the results indicate that the radiological consequences are within the criteria identified by Regulatory Guide 1.183 and 10 CFR 50.67. The limiting criteria are 6.3 rem TEDE for EAB and LPZ and 5 rem TEDE for the control room.

14.7.4.2.1 Fuel Handling Accident in the Spent Fuel Pool

This accident has been re-analyzed using the methods and assumptions contained in Regulatory Guide 1.183. A complete list of assumptions is provided in Table 14.7.4-1. The results of this analysis are within the limits as defined by 10 CFR 50.67 and within the criteria identified in Regulatory Guide 1.183. This analysis does not require automatic initiation, isolation or re-alignment of main exhaust or AES ventilation system from radiation monitor response, nor does it require fuel handling area integrity.

14.7.4.2.2 Fuel Handling Accident in Containment

This accident has been re-analyzed using the methods and assumptions contained in Regulatory Guide 1.183. A complete list of assumptions is provided in Table 14.7.4-2. The results of this analysis are within the limits as defined by 10 CFR 50.67 and within the criteria identified in Regulatory Guide 1.183. This analysis does not require automatic isolation of purge from radiation monitor response, nor does it require containment integrity because it is assumed that containment penetrations such as the equipment hatch are open.

14.7.4.3 Results of Analysis

14.7.4.3.1 Fuel Handling Accident in the Spent Fuel Pool

TEDE, rem

EAB 1.5E+00

LPZ 2.0 E -01


Control Room 3.1E+00

14.7.4.3.2 Fuel Handling Accident in Containment

TEDE, rem

EAB 1.5E+00

LPZ 2.0 E -01

Control Room 3.1E+00


Doses at the exclusion area boundary (EAB), low population zone (LPZ) and the control room are within the requirements of 10 CFR 50.67 and within the guidelines identified in Regulatory Guide 1.183. Therefore, a fuel handling accident in the containment or spent fuel buildings will not present any undue hazard to the health and safety of the public, nor will it compromise control room operations.

14.7.5 SPENT FUEL CASK DROP ACCIDENTS

The spent fuel cask crane is designed with special features to the structure that will ensure a single failure does not result in the loss of the capability of the system to safely retain the load. The upgraded spent fuel cask crane is designed to meet the single failure proof requirements of NUREG-0554 and NUREG-0612. When a spent fuel cask is rigged to the crane and handled in accordance with single failure criteria, a cask drop is not credible and need not be postulated. Therefore, there will be no radiological consequences.

However, the cask drop accident that is postulated to have radiological consequences involves the unlikely scenario where the spent fuel cask is disengaged from the crane in the cask laydown area and tips over into the spent fuel pool damaging impacted fuel assemblies. This postulated cask drop accident is referred to as a cask tip accident to avoid confusion.

14.7.5.1 Spent Fuel Cask Tip Accident

The spent fuel cask is assumed to initially be in the cask laydown area, where it is postulated to tip into the spent fuel pool. All the fuel assemblies in the spent fuel pool that are within the distance L of the center of the spent fuel cask laydown area are assumed to fail, where the distance L is the major dimension of the spent fuel cask. As described below, fuel assemblies in the spent fuel pool within this distance L are assumed to have decayed for the minimum period specified in Technical Specification 3.9.16.

14.7.5.2 Method of Analysis

The spent fuel cask tip accident is based upon the assumptions listed in Table 14.7.5-1.


The analysis considered a full core discharge of 217 individual fuel assemblies decayed for 90 days and 1,376 fuel assemblies consolidated to 688 consolidated fuel canisters or fuel storage boxes. Each consolidated fuel canister or storage box contains the inventory of two individual fuel assemblies. The analysis conservatively included the inventory of 33 more fuel assemblies than actually fit in the potential impact area.

All X/Q values have been chosen in the following manner: Site meteorological data has been examined for years 1974 – 1981 for offsite X/Qs and 1997 – 2001 for control room X/Qs. For each release point and dose calculation time period in question, the year with the largest (i.e., most conservative) 95% maximum offsite X/Q value has been chosen. Control room X/Qs are developed consistent with Regulatory Guide 1.194 except for those from the Millstone Stack, based on Regulatory Guide 1.145.

The analysis considered two scenarios, an unisolated control room and an isolated control room:

• For an unisolated control room, the control room unfiltered ventilation flow consists of 800 cfm normal intake and 200 cfm inleakage for the entire accident.

• For an isolated control room, isolation occurs at 20 seconds, including radiation monitor and damper closure response times:

0-20 seconds Prior to isolation, the control room unfiltered ventilation flow of 1,000 cfm, which consists of 800 cfm normal intake and 200 cfm inleakage.

20 seconds – 1 hour 20 seconds During isolation but prior to recirculation, there is only 200 cfm unfiltered inleakage.

1 hour 20 seconds – 720 hours During isolation and recirculation, 200 cfm unfiltered inleakage and 2,250 cfm filtered recirculation continue for the remainder of the accident.

The unisolated control room provides the limiting dose consequences.

14.7.5.3 Results of Analysis

TEDE, rem

EAB 5.0E-01

LPZ 1.0E-01

Control Room 8.0E-01

The results indicate, that the radiological consequences are within the criteria identified by Regulatory Guide 1.183 and 10 CFR 50.67. The limiting criteria are 6.3 rem TEDE for EAB and LPZ, and 5 rem TEDE for the control room.



The spent fuel cask tip accident has been analyzed using the methods and assumptions contained in Regulatory Guide 1.183. The dose consequences at the exclusion area boundary (EAB), low population zone (LPZ), and the control room are within the limits as defined by 10 CFR 50.67 and are within the criteria identified in Regulatory Guide 1.183. Therefore, a cask tip accident in the spent fuel pool will not present any undue hazard to the health and safety of the public, nor will it compromise control room operations.


TABLE 14.7.1-1 DELETED BY FSARCR PKG FSC 07-MP2-006


TABLE 14.7.4-1 ASSUMPTION FOR FUEL HANDLING ACCIDENT IN THE SPENT FUEL POOL

1) Reactor Core Power Level: 2754 Mwt

2) Iodine Pool Decontamination Factor: 200

3) Activity Released from Rods

a) Iodines: 10%

b) Noble Gases (Except Kr-85): 10%

c) Kr-85: 30%

c) I-131: 12%

4) Chemical Form of Iodines Above Pool

a) organic: 43%

b) elemental: 57%

5) 1 Assembly Assumed to Rupture

6) Peaking Factor: 1.83

7) Decay time: 100 hours

8) Duration of Release: 2 hours

9) All Activity Bypasses EBFS Filters and is Released at Ground Level Using Worst Case X/Q’s:

10 Ground Level X/Q’s (sec/m3)

a) EAB: 3.66 E -04

b) LPZ: 4.80 E -05

c) Control Room: 3.00 E -03

11) Dose Conversion Factors Federal Guidance Report 11 & 12

12) Breathing Rate (m3/sec): 3.5 E -04

13) Control Room Breathing Rate 3.5 E -04 m3/sec

14) Control Room Isolation Time post-accident (includes radiation monitor and damper closure response times)

20 seconds

15) Control Room Intake Prior to Isolation 800 cfm

16) Control Room Inleakage During Isolation 200 cfm



17) Control Room Emergency Filtered Recirculation Rate (from 1 hour after isolation)

2,250 cfm

18) Control Room Free Volume 35,656 ft3

19) Control Room Filter Efficiency (particulate/elemental/organic) 90 / 90 / 70 % (1)

20) Dose Conversion Factors Federal Guidance Reports 11 and 12

TABLE 14.7.4-1 ASSUMPTION FOR FUEL HANDLING ACCIDENT IN THE SPENT FUEL POOL (CONTINUED)


TABLE 14.7.4-2 ASSUMPTION FOR FUEL HANDLING ACCIDENT IN CONTAINMENT

1 Reactor Core Power Level: 2754 MWt

2 Iodine Pool Decontamination Factor: 200

3 Activity Released from Rods

a) Iodines: 10%

b) Noble Gases (except Kr-85): 10%

c) Kr-85: 30%

d) I-131: 12%

4 Chemical Form of Iodines Above Pool

a) organic: 43%

b) elemental: 57%

5 1 Assembly Assumed to Rupture

6 Peaking Factor: 1.83

7 Decay Time: 100 hours

8 Duration of Release 2 hours

9 All Activity Bypasses EBFS Filters and is Released at Ground Level Using Worst Case X/Q’s:

10 Ground Level X/Q’s (sec/m3)

a) EAB: 3.66 E -04

b) LPZ: 4.80 E -05

c) Control Room: 3.00 E -03

11 Dose Conversion Factors Federal Guidance Report 11 & 12

12 Breathing Rate (m3/sec): 3.5 E -04

13 Control Room Breathing Rate 3.5 E -04 m3/sec

14 Control Room Isolation Time post-accident (includes radiation monitor and damper closure response times)

20 seconds

15 Control Room Intake Prior to Isolation 800 cfm

16 Control Room Inleakage During Isolation 200 cfm



17 Control Room Emergency Filtered Recirculation Rate (from 1 hour after isolation)

2,250 cfm

18 Control Room Free Volume 35,656 ft3

19 Control Room Filter Efficiency (particulate/elemental/organic) 90 / 90 / 70 % (1)

20 Dose Conversion Factors Federal Guidance Reports 11 and 12

TABLE 14.7.4-2 ASSUMPTION FOR FUEL HANDLING ACCIDENT IN CONTAINMENT (CONTINUED)


TABLE 14.7.4-3 DELETED BY FSARCR 02-MP2-015

Table deleted by FSARCR 02-MP2-015


TABLE 14.7.5-1 ASSUMPTIONS FOR SPENT FUEL CASK TIP ACCIDENT

PARAMETER VALUE

Reactor Core Power Level 2,754 Mwt

Iodine Pool Decontamination Factor 200

Fraction of Activity Released from Rods

Iodines (Except I-131) 10%

I-131 12%

Noble Gases (Except Kr-85) 10%

Kr-85 30%

Chemical Form of Iodines Above Pool

Organic 43%

Elemental 57%

Ruptured Assemblies & Decay Time 217 assemblies with 90 days decay and 1,376 assemblies with 5 years decay

Peaking Factor 1

Duration of Release 2 hours

Ground Level X/Q’s

EAB 3.66E-04 sec/m3

LPZ 4.80E-05 sec/m3

Control Room 3.00E-03 sec/m3

Dose Conversion Factors Federal Guidance Reports 11 & 12

Breathing Rates

EAB & LPZ (0-8 hours) 3.5E-04 m3/sec

Control Room ((0-720 hours) 3.5E-04 m3/sec

Control Room Isolation Time post-accident (includes radiation monitor and damper closure response times)

20 seconds

Control Room Unfiltered Normal Intake 800 cfm

Control Room Unfiltered Inleakage 200 cfm


Control Room Emergency Filtered Recirculation Rate (from 1 hour after isolation)

2250 cfm


Control Room Filter Efficiency (Particulate/Elemental/Organic)

90% / 90% / 70% (1)


TABLE 14.7.5-1 ASSUMPTIONS FOR SPENT FUEL CASK TIP ACCIDENT (CONTINUED)

PARAMETER VALUE


14.8 MILLSTONE UNIT 2 FSAR EVENTS NOT CONTAINED IN THE STANDARD REVIEW PLAN

14.8.1 FAILURES OF EQUIPMENT WHICH PROVIDES JOINT CONTROL/SAFETY FUNCTIONS

Millstone Unit 2 has no instrumentation which serves a combined function of process control and of initiation of emergency safety systems.

14.8.2 CONTAINMENT ANALYSIS

14.8.2.1 Main Steam Line Break Analysis


In the event of a Main Steam Line Break (MSLB), the release of steam into containment will result in a rise in both temperature and pressure. The break is assumed to occur in the piping between the steam generator and the containment wall penetration. Mass and energy releases are limited by the flow restrictor in the steam generator outlet nozzle.

14.8.2.1.2 Protective Systems

Engineered Safety Features (ESF) systems which will operate to terminate the mass and energy release to containment and suppress containment atmosphere temperature and pressure are the Main Steam Isolation Signal (MSIS), Safety Injection Actuation Signal (SIAS), and Containment Spray Actuation Signal (CSAS).

A MSIS will actuate on receipt of a containment high pressure signal to shut the following valves and trip the main feedwater pumps:

1. Steam Generator 1 & 2 Isolation Valves

(HV-4217 & HV-4221 or MS-64A&B)

2. Steam Generator 1&2 Isolation Valves Bypass

(HV-4218 & HV-4222 or MS-65A&B)

3. Steam Generator 1 & 2 Feedwater Isolation Valves

(HV-5419 & HV-5420 or FW-5A&B)

4. Steam Generator 1 & 2 Feedwater Regulating Valves

(FV-5268 & FV-5269 or FW-51A&B)

5. Main Steam Leg Low PT. Drains

(HV-4193 & HV-4209 or MS-265B & MS-266B)


6. Steam Generator 1 & 2 Feedwater Regulating Bypass Valves

(FV-5215 & FV-5216 or FW-41A&B)

7. Feedwater Block Valve to Steam Generators 1 & 2

(HV-5263 & HV-5264 or FW-42A&B)

8. Steam Generator 1 & 2 Feed Pump Discharge Valves

(HV-5245 & HV-5247 or FW-38A&B)

A SIAS will activate the Containment Air Recirculation (CAR) fans and give a start signal to the emergency diesel generators (EDGs).


A complete MSLB spectrum study has been performed to determine the limiting cases for peak containment pressure. The NRC approved methodology (References 14.8-2 and 14.8-3) associated with the Westinghouse SGN-III computer program was used to determine the mass and energy releases to containment. Using these mass and energy releases, the NRC approved Dominion GOTHIC methodology (Reference 14.8-4) was used to determine the containment pressure-temperature consequences of the MSLB. This methodology includes consideration for the following: (a) inclusion of the steam line and feed line volumes into the overall determination of blowdown volume available; (b) determination of temperature/pressure expansion factor for the SGs and RCS to maximize the volume available for blowdown; (c) increase in feedwater flow to the affected SG due to the increasing pressure imbalance between the affected and intact SG; (d) inclusion of SG shell metal heat transfer as part of the energy release; and lastly, (e) a complete determination of the effects of different component single failures during the accident.

14.8.2.1.4 Major Assumptions

The major assumptions are as follows:

1. Offsite power is assumed to be available for most of the cases. This increases the primary to secondary heat transfer since the reactor coolant pumps (RCPs) are operating. To verify this assumption, loss of offsite power cases were included as part of the single failure analysis.

2. For determination of peak containment pressure, the initial containment pressure/temperature is conservatively assumed to be at the Technical Specification maximum of 15.7 psia and 120°F.

3. Consistent with the NRC Standard Review Plan (SRP) Section 6.2.1.4, break spectrum studies were used to address moisture carryover.


4. Preferential addition of feedwater to the affected SG is accounted for by conservatively doubling the initial feedwater flowrate as long as the MFW system is operating.

5. Credit is taken for the main steam non-return valves to prevent blowdown of the unaffected SG into the containment.

6. The maximum RCS flow rate was conservatively assumed to maximize the heat transfer from the primary to secondary side.

7. Cases initiated from 0% power assumed auxiliary feedwater (AFW) is the sole source of steam generator inventory control and AFW flow to the affected steam generator is maximized from the beginning (time = 0) of the analysis. All other cases initiate AFW at a conservative minimum time of 180 seconds.

8. Reactor coolant pump heat was included.

9. All actuation signals are redundant and safety grade. In some cases credit is taken for actuation of nonsafety grade components initiated by the safety grade signals.

10. Relative humidity is assumed at 25 percent.

11. A 0.75" auxiliary steam line located between the two steam generators remains unisolated during the events. This causes the intact steam generator to continue to blowdown even after the MSIS.

12. A cavitating venturi installed in each AFW discharge line will limit AFW flow to a steam generator to 550 gpm.

13. Operator action to isolate the AFW is assumed to occur no greater than 30 minutes following MSIS.

14. The feedwater flow rate for the cases that initiate with the main feedwater system operating conservatively account the following:

• Feedwater flow increases as the affected steam generator pressure decreases.

• Upon receipt of a MSIS, the feedwater pumps are assumed to coast down at a rate based on plant operating experience.

• If the ruptured steam generator pressure decreases to the discharge pressure of the still running condensate and heater drain pumps, flow will again begin to increase.

• Flow is eventually stopped after the containment high pressure signal actuates the MSIS and the main feedwater is isolated.


14.8.2.1.5 Initial Conditions and Input Data

Initial conditions and input data are given in Tables 14.8.2-1, 14.8.2-2 and 14.8.2-5. Table 14.8.2-3 gives an accounting of the amounts of steel assumed to be inside of containment. Since this material acts as a heat sink to reduce containment temperature and pressure, minimum amounts are used.

14.8.2.1.6 Results

In order to determine the limiting conditions, four different spectrum studies were performed. These are as follows:

1. Power level and break size.

2. Feed system single failures.

3. Containment heat removal systems single failures.

4. Spectrum study for peak containment temperature.

14.8.2.1.6.1 Power Level and Break Size

A comprehensive sensitivity study was performed to determine the limiting break size for each power level. A sensitivity study was needed because of the interaction of power level with SG inventory and moisture carryover. The limiting break size at a given power level is the largest break size that would result in a pure steam blowdown, since a pure steam blowdown results in the greatest amount of energy being transferred to the containment atmosphere in a short period of

time. The limiting results for each power level show that a maximum break size of 3.51 ft2 is limiting for 25 percent, 50 percent, 75 percent, and 100 percent power. At 0 percent power the

limiting size break is 1.89 ft2.

14.8.2.1.6.2 Feed System Single Failures

A comprehensive feedwater system isolation single failure study was performed. For each single failure, a range of steady state initial power levels was analyzed, using the insights from the Power Level/Break Size sensitivity study.

1. Feed Pump Failure to Trip - The failure of a feed pump to trip on MSIS results in additional feed water being pumped preferentially into the affected SG until the Feedwater Regulating Valves (FRV) and isolation valves shut. For 25 percent and 50 percent power levels, only one feedwater pump was assumed to be running when the accident commences. This event was not applicable to 0% cases (see assumption 7 of Section 14.8.2.1.4).


2. Inadvertent Initiation of AFW Feedwater to Affected Steam Generator - Maximum AFW flow was assumed to be inadvertently initiated at the start of the event for cases initiated from greater than 0% power.

3. Feedwater Bypass Valve Fails Open - This failure is only credible when the FW bypass valve is initially open (cases initiated from 25% power and below). The failed open feedwater bypass results in additional feedwater being pumped preferentially into the affected SG until the FW pump discharge valves shut. In addition, even with the feed pump discharge valves shut, flashing in the feedwater lines continues to add energy into the affected steam generator. This effect has been taken into account.

4. Failure of Vital Bus Cabinet VA-10 or VA-20 - This failure could prevent closure of the FRVs and results in the loss of one train of the Containment Heat Removal Systems. Feedwater addition to the affected SG will continue until closure of the main feed pump discharge valves.

14.8.2.1.6.3 Containment Heat Removal Systems Single Failures

A comprehensive containment heat removal systems single failure study was performed. For each single failure, a range of steady state initial power levels was analyzed, using the insights from the Power Level/Break Size sensitivity study.

1. Failure of Two CAR fans to start - This failure is bounded by Section 14.8.2.1.6.2, item 4 described above.

2. Failure of one spray train to start - This failure is bounded by Section 14.8.2.1.6.2, item 4 described above.

3. Failure of the Vital Bus Transfer Mechanism - This failure results in a loss of the normal off-site power supply for the vital buses. Thus initiation of the containment sprays and CAR fans is delayed until the EDGs are powering the vital buses and auto sequencing has occurred. Since the FRVs have a backup DC power source, they are unaffected by this failure and will isolate the affected SG. The RCPs and certain other nonvital loads are also unaffected by this failure, which contributes to the severity of this accident by providing more rapid heat transfer from the primary to the affected SG.

4. Loss of Offsite Power with a Loss of One EDG - A loss of offsite power will result in loss of power to the RCPs, the condensate pumps and feedwater heater drain pumps. While only one train of containment heat removal systems is available, the loss of power to these pumps results in a greatly degraded heat transfer in the affected SG and less limiting results. Feedwater isolation will be unaffected since the FRVs are powered by DC backup power supplies.


5. Loss of Offsite Power with a Loss of VA-10/20 - This case is similar to item 4 (the preceding paragraph), with the exception of the effect on feedwater isolation to the affected SG. With this failure, there is the potential for failure of the FRV and the other isolation valves to close. However, with the loss of the condensate and feedwater heater drain pumps, feedwater addition to the affected SG is terminated. The effect of continued energy addition to the affected SG from flashing in the feedwater lines has been taken into account.

14.8.2.1.6.4 Maximum Containment Temperature Spectrum Study

The limiting peak pressure cases were re-run with the following modified assumptions to maximize resultant containment temperature.

1. The initial containment pressure was reduced to 14.27 psia. This results in the maximum delay in containment spray actuation.

2. The relative humidity was increased to 100 percent.

3. The MSLB mass and energy releases model the Steam Generator steam super heating as it passes the uncovered portion of the Steam Generator tubes before exiting the break to address IE Information Notice 84-90. The containment wall re-evaporation is modeled using the GOTHIC built-in models for calculating the vaporization of the liquid in containment as described in Reference 14.8-4.


The results of a MSLB initiated from 102 percent reactor power with coincident loss of offsite power and the failure of the Vital Bus Cabinet VA-10 or VA-20 produces the limiting containment peak pressure of 53.8 psig. The peak containment atmospheric temperature for this case is 325.1°F. With the loss of offsite power and this single failure, the condensate and feedwater heater drain pumps are lost, and pumped feedwater addition to the affected steam generator is quickly terminated. However, since the FRV and the other feedwater isolation valves fail to close on the MSIS, a significant volume of feedwater system remains connected to the affected steam generator. As the affected steam generator depressurizes, feedwater in this system flashes and adds significant mass and energy to the affected steam generator. The portion of the feedwater that flashes to steam is conservatively assumed to be directly added to the containment atmosphere separate from the mass and energy releases from the steam generator. The portion of the feedwater liquid that reaches the affected steam generator as it depressurizes increases the affected steam generator liquid mass, which increases the steam generator mass and energy releases to containment. The plant response for the limiting peak pressure case is shown in Figures 14.8.2–1 through 14.8.2–9 and the sequence of events is given in Table 14.8.2-4.

The results of MSLB initiated from 102 percent reactor power with offsite power available and the failure of Vital Bus Cabinet VA-10 or VA-20produces the limiting containment peak atmospheric temperature of 360.9°F.


The containment pressure remains below the design pressure of 54 psig. Although peak containment atmospheric temperature exceeds the 289°F design temperature, it is only for a short period of time and does not raise the containment structure above 289°F.

14.8.2.2 Loss of Coolant Accident Analysis

14.8.2.2.1 Events Analyzed

Twenty four separate cases of Loss of Coolant Accidents (LOCAs) were analyzed with variations for break locations, break sizes, single failures and availability of offsite power. Break locations analyzed are the reactor coolant pump suction leg, pump discharge leg and hot leg. Break sizes include double-ended guillotine and slot breaks (9.82 sq. ft. area for the reactor coolant pump suction and discharge leg breaks, 19.24 sq. ft. area for a hot leg break) and smaller break sizes for hot leg breaks (10 sq. ft. and 2 sq. ft.) and reactor coolant pump suction and discharge leg breaks (5 sq. ft. and 2 sq. ft.). Single failures considered are failure of an emergency diesel generator (EDG) (for a loss of power (LOP) case) which fails 1 train of containment heat removal systems or (for no LOP), failure of either 1 spray system or 2 CAR fans. With an LOP 1 train of ECCS will operate, with no LOP both trains will operate.


The NRC approved, Westinghouse containment analysis methodology was used for the development of the short term mass and energy releases following a LOCA (Reference 14.8-3). Mass and energy input are provided through the End-of-Blowdown (EOB) from CEFLASH-4A, and from the EOB to End-of-Post Reflood (EOPR) from FLOOD3. The long term boil-off phase mass and energy input was calculated using the Dominion GOTHIC code (Reference 14.8-4). The containment pressure and temperature response for the entire LOCA transient was calculated using the Dominion GOTHIC computer code.

14.8.2.2.3 Input and Assumptions

a. Containment input data, such as: heat sink area, spray flow rate, CAR fan cooler heat removal rate, spray water temperature, containment volume and initial containment temperature are the same as, or more conservative than, that used for the MSLB in Section 14.8.2.1.

b. Initial containment pressure is 15.7 psia for the peak pressure case and 14.27 psia for the peak temperature case.

c. Initial containment humidity is assumed to be 25 percent as in the MSLB for the peak pressure case and 100 percent for the peak temperature case.

d. The minimum usable Refueling Water Storage Tank (RWST) volume assumed for calculation of the time of Sump Recirculation Actuation Signal (SRAS) is 370,000 gallons.


e. Both the HPSI and the LPSI pumps operate prior to SRAS. Following SRAS, the LPSI are automatically stopped.

f. The Reactor Building Closed Cooling Water (RBCCW) is modeled with assumed flows before and after SRAS. The RBCCW is cooled by Service Water at 80°F.

g. The heat removal from the CAR fan cooler is modeled in the Dominion GOTHIC Code using a fan cooler model benchmarked to the post-LOCA specification data. The specification identifies that one CAR fan is capable of removing a minimum of 80 million BTU/hr based on a containment air inlet temperature of 289°F and a fan flowrate of 34,800 cfm, along with a cooling water inlet temperature of 130°F and a flowrate of 2000 gpm.

h. A minimum spray flow of 1300 gpm is credited prior to SRAS, and 1350 gpm following SRAS.

14.8.2.2.4 Results

The limiting LOCA with respect to maximum containment pressure was determined to be the 5 square foot discharge leg break with the LOP, the failure of two CAR fans and one spray train, and minimum ECCS. The maximum calculated containment pressure for this case is 52.5 psig. This pressure is rounded up to 53 psig to establish the Pa value stated in the containment leakage rate testing program Technical Specification. The limiting LOCA with respect to maximum containment temperature was determined to be the 10 square foot hot leg break with the LOP, the failure of two CAR fans and one spray train and minimum ECCS. The maximum calculated containment temperature for this case is 279.2°F. The maximum containment pressure and temperature of these limiting LOCAs are bounded by the MSLB results provided in Section 14.8.2.1.


The maximum containment pressure and temperature of the LOCA are less than the containment design pressure and temperature of 54 psig and 289°F.

14.8.3 DELETED

14.8.4 RADIOLOGICAL CONSEQUENCES OF THE DESIGN BASIS ACCIDENT

14.8.4.1 General

A LOCA would increase the pressure in the containment resulting in a containment isolation and initiation of the ECCS and containment spray systems. A SIAS signal automatically starts the Enclosure Building Filtration System (EBFS) which maintains a negative pressure within the enclosure building during accident conditions. The nuclide inventory assumed to be initially available for release is consistent with the requirements of Regulatory Guide 1.183 (Reference 14.8-5). A SIAS also isolates the control room by closing the fresh air dampers within


20 seconds. Within 1 hour after control room isolation, the control room emergency ventilation (CREV) is properly aligned. CREV recirculates air within the control room through a charcoal filter at 2,500 cfm (±10%) to remove iodines from the control room envelope.

The radiological consequences of a Design Basis LOCA at Millstone 2 were previously analyzed for a low and high wind speed condition based on guidance from Regulatory Guide 1.4 (Reference 14.8-6) and SRP 6.5.3 (Reference 14.8-7). The low wind speed case was found to bound the high wind speed case. Therefore, the low wind speed case is the design basis for a LOCA and the high wind speed case is no longer analyzed.

14.8.4.2 Release Pathways

The release pathways to the environment subsequent to a LOCA are leakages from containment and the enclosure building, which are collected and processed by EBFS and leakages from containment and the RWST which bypass EBFS.

Containment Leakage

The containment is assumed to leak at the design leak rate for 24 hours after the accident. After 24 hours, since the pressure has been decreased significantly, Regulatory Guide 1.183 allows for the leak rate to be reduced to one-half the design leakage rate.

All containment leakage for the first 110 seconds is assumed to bypass EBFS and is released directly out the MP-2 containment. This is due to the fact that it takes 110 seconds for EBFS to achieve the required negative pressure in the enclosure building, thereby ensuring that leakage will be into the enclosure building rather than out.

EBFS collects most of the containment leakage and processes it through HEPA and charcoal filters and releases it up the Millstone stack. All containment leakage is collected and filtered by EBFS except for the small amount that is assumed to bypass EBFS and is released directly out the MP-2 containment.

Credit is taken for iodine removal due to containment sprays. The sprays are effective after 75 seconds post-LOCA. The effectiveness of the sprays in removing elemental iodine ends at 3.03 hours and in removing particulate iodine at 3.23 hours. Credit is taken for iodine retention in the containment sump based on post-LOCA sump pH ≥ 7.0 as discussed in Section 6.2.4.1.

ESF System Leakage Pathway

Post-accident radioactive releases from the ESF system are derived from fluid leakages assumed during recirculation of the containment sump water through systems located outside containment. The nuclide inventory assumed to be available for release from this pathway consists of 40% of the core iodines. The quantity of leakage is based on the assumption that the ESF equipment leaks at twice the maximum expected operational leak rate and that 10 percent of the iodine nuclides contained in the leakage fluid become airborne in the enclosure building. The nuclides which become airborne are collected and released to the environment through EBFS to the Millstone stack.


RWST Backleakage Pathway

Post-accident radioactive releases from the ECCS system are a result of ECCS subsystems containing recirculated sump fluid backleaking to the RWST. The backflow rate to the RWST, as a result of isolation valve leakage, is predefined and time dependent. Due to this time dependency, the contaminated sump fluid from backleakage does not enter into the RWST until 6.45 hours post-LOCA. Since the RWST is vented to atmosphere, the release is a result of the breathing rate of the RWST due to solar heating.

14.8.4.3 Control Room Habitability

The radiation design objective of the control room is to limit the dose to personnel inside the control room to 5 rem TEDE, during a DBA. The potential radiation dose to a control room operator is evaluated for the LOCA. The analysis is based on the assumptions and meteorological parameters (X/Q values) given in a Tables 14.8.4-3 and 14.8.4-4.

The control room is designed to be continuously occupied for the duration of the accident, 30 days. Two basic sources of radiation have been evaluated: leakage of airborne activity into the control room from sources described in Section 14.8.2 and direct dose from sources outside the control room. The control room shielding serves to protect the operators from direct radiation due to the passing cloud of radioactive effluent assumed to have leaked from containment, enclosure building and the RWST. The control room walls also provide shielding protection for radiation emanating from the CREV filters and containment shine.

A SIAS from Millstone 2 initiates control room isolation within 20 seconds by securing the fresh air intake dampers. Within 1 hour, CREV is in operation recirculating air in the control room envelope through charcoal filters to remove radioactive iodines from the atmosphere. The calculated TEDE dose from a Millstone 2 LOCA is presented in Table 14.8.4-5 and is below the General Design Criteria 19 and 10 CFR 50.67 limits.

The calculated TEDE dose from a Millstone 3 LOCA to the Millstone 2 control room is below the General Design Criteria 19 limits and bounded by the dose consequences from the Millstone 2 LOCA. No credit has been taken for control room isolation or CREV operation.

14.8.4.4 Offsite Dose Computation

The radiological offsite dose consequences resulting from a postulated Millstone 2 LOCA are reported in Table 14.8.4-2. The offsite dose analysis shows that the consequences to the EAB (highest 2 hour) and LPZ (0-30 day) are less than the limit of 25 rem TEDE as specified in 10 CFR 50.67. The assumptions used to perform the radiological analysis are summarized in Table 14.8.4-1.

14.8.4.5 Conclusion

Analysis shows that the offsite and control room radiological consequences are within 10 CFR 50.67 criteria.


14.8.5 REFERENCES

14.8-1 Deleted.

14.8-2 Preliminary Safety Analysis Report (PSAR) to CESSAR, Appendix 6B, “Description of the SGN-111 Digital Computer Code Used In Developing Main Steam Line Break Mass/Energy Release Data For Containment Analysis.”

14.8-3 NRC Safety Evaluation Report - Standard Reference System CESSAR System 80, Combustion Engineering, Inc., December 1975.

14.8-4 Dominion Topical Report DOM-NAF-3, Revision 0.0-P-A, “GOTHIC Methodology For Analyzing the Response to Postulated Pipe Ruptures Inside Containment,” September 2006.

14.8-5 Regulatory Guide 1.183, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors, July 2000.

14.8-6 Regulatory Guide 1.4, Assumptions used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors Rev. 2, June 1974.

14.8-7 SRP 6.5.3, Fission Product Control Systems and Structures.


TABLE 14.8.2-1 CONTAINMENT DESIGN PARAMETERS

Internal dimensions (feet)

Cylinder wall diameter 130.0

Cylinder wall height 132.4

Curved dome height 43.3

Net free internal volume 1,899,000 cubic feet


TABLE 14.8.2-2 INITIAL CONDITIONS FOR PRESSURE ANALYSES

* No heat transfer credited from containment structure to outside environment.

Reactor Coolant System

Core thermal power level (MWt/% of rated power) 2754/102

Reactor coolant Pump heat (MWt) 17.1

Coolant pressure (psig) 2300

Inlet coolant temperature (°F) 551.25

Internal coolant volume (cubic feet) (excludes the pressurizer) 10,104.4

Containment System

Pressure (psia) 15.7

Relative humidity (%) 25

Inside temperature (°F) 120

Outside temperature (°F) N/A *

Service Water Inlet temperature (°F) 80

Refueling Water Storage Tank (RWST) water temperature (°F) 100

Safety Injection Tank (SIT) water temperature (°F) 120


TABLE 14.8.2-3 MINIMUM CONTAINMENT HEAT SINK DATA

Heat Sink Exposed Surface Area (sq ft)

1. Containment Cylinder and Dome

Cylinder 52,800

Dome 19,070

71,870

2. Unlined Concrete

Steam Generator Compartment Walls 26,114

Miscellaneous Slabs 4,488

Elevator Foundation 643

Pressurizer Wall and Roof 2,159

Refueling Canal (Outside) 10,043

Steam Generator Pedestals 2,860

Steam Generator Buttresses 3,840

Fuel Canal Buttresses 3,273

53,420

3. Reactor Support

Concrete (3 inches, exposed on one side to the containment atmosphere and on the other to a 150°F source to account for the higher reactor cavity operating temperature)

3,486

4. Galvanized Steel 116,497

5. Painted Steel Less than 0.12 in. Thick 5,605

6. Painted Steel 0.12 to 0.16 in. Thick 16,863










15. Painted Steel Greater than 1.5 in. Thick 1,031

16. Unpainted Stainless Steel 18,464

17. Containment Floor 8,102

18. Safety Injection Tanks 2,541

TABLE 14.8.2-3 MINIMUM CONTAINMENT HEAT SINK DATA (CONTINUED)

Heat Sink Exposed Surface Area (sq ft)


(1) The minimum containment spray flows used in this analysis are provided in Table 14.8.2-5.

TABLE 14.8.2-4 SEQUENCE OF EVENTS, MP2-MSLB: LOSS OF OFFSITE POWER AND THE FAILURE OF VITAL BUS VA-10 OR VA-20 FROM 102% POWER

TIME (seconds) EVENT SETPOINT/VALUE

0.0 MSLB occurs from 102% power, break size is

3.51 ft2.

0.0 Loss of offsite power.

1.29 Low RCS flow reactor trip condition reached. 89.7% of initial RCS flow

1.94 Low RCS flow reactor trip signal generated. 0.65 second delay

2.50 Containment High Pressure Signal (CHPS) condition is reached. (Due to the assumed loss of offsite power and failure of VA-10 or VA-20, the affected steam generator FRV and main feedwater isolation valves do not close.)

5.83 psig with uncertainty

3.40 High Containment Pressure MSIS generated. 0.9 second delay

6.15 Containment High-High Pressure Signal (CHHPS) condition reached.

11.08 psig with uncertainty

28.5 Containment cooling fans energize. Time based on CHPS + 26 second delay.

37.1 Peak Containment Pressure reached. 326.5°F

74.76 Containment spray flow commences. Time based on CHHPS + 68.6 seconds for pump start, valve stroke time, and header fill time.

See Note 1

180 Maximum AFW Flow to the Affected Steam Generator.

550 gpm, 100°F

552.1 Peak Containment Pressure reached. 53.8 psig

1000 Simulation ended.


TABLE 14.8.2-5 ENGINEERED SAFETY FEATURES PERFORMANCE FOR MSLB CONTAINMENT ANALYSIS

Safety Features Value Notes

1. Containment spray

- water temperature 100°F

- CSAS setpoint 11.08 psig TS value plus uncertainty

- minimum flow rate 1361 gpm at 54 psig 1375 gpm at 51 psig 1394 gpm at 47 psig 1428 gpm at 40 psig

Values based on a minimum RWST level of 30 feet above tank bottom.

- delay time with normal AC power available

49 seconds Includes 33 seconds for header fill time and 16 seconds for signal generation, pump start and valve stroke.

- delay time with the loss of normal AC power

68.6 seconds Includes 33 seconds for header fill time and 35.6 seconds for signal generation, pump start and valve stroke.

2. Containment Air Recirculation (CAR) Cooling Fans

- number of fans 4 2 for certain single failure cases

- activation setpoint 5.83 psig TS value plus uncertainty

- delay time with normal AC power available

15 seconds

- delay time with loss of normal AC power

26 seconds

- heat removal capability of one CAR Fan

80 million BTU/hr based on air inlet temperature of 289°F and a fan flow rate of 34,800 cfm, along with a cooling water inlet temperature of 130°F and flow rate of 2000 gpm.

A GOTHIC Fan Cooler Model is used. This model is benchmarked to the cited specification data.

3. Safety Injection None Assumed.

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FIGUR ITE POWER AND FAILURE OF S. TIME

E 14.8.2–1 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - CONTAINMENT PRESSURE V

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FIGUR ITE POWER AND FAILURE OF E VS. TIME

E 14.8.2–2 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - CONTAINMENT TEMPERATUR

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FIGUR ITE POWER AND FAILURE OF IME

E 14.8.2–3 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - MASS FLOW RATE VS. T

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FIGUR ITE POWER AND FAILURE OF . TIME

E 14.8.2–4 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - ENERGY RELEASE RATE VS

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FIGUR ITE POWER AND FAILURE OF S. TIME

E 14.8.2–5 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - INTEGRATED MASS FLOW V

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FIGUR ITE POWER AND FAILURE OF E VS. TIME

E 14.8.2–6 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - INTEGRATED ENERGY RELEAS

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FIGUR ITE POWER AND FAILURE OF SSURE VS. TIME

E 14.8.2–7 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - AFFECTED STEAM GENERATOR PRE

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FIGUR ITE POWER AND FAILURE OF ESSURE VS. TIME

E 14.8.2–8 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - UNAFFECTED STEAM GENERATOR PR

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FIGUR ITE POWER AND FAILURE OF ID MASS VS. TIME

E 14.8.2–9 MAIN STEAM LINE BREAK ANALYSIS - 102% POWER WITH LOSS OF OFFSVITAL BUS CABINET VA-10 OR VA-20 - AFFECTED STEAM GENERATOR LIQU


FIGURE 14.8.3–1 DELETED BY FSARCR 04-MP2-018


TABLE 14.8.4-1 LOSS OF COOLANT ACCIDENT (OFF SITE ASSUMPTIONS)

Assumption

(1) Core power level = 2754 MWt

(2) Core released fractions: Consistent with Table 2 of Regulatory Guide 1.183

(3) Iodine composition: Containment Sump

Particulate 95% 0%

Elemental 4.85% 97%

Organic 0.15% 3%

(4) Containment leak rate: 0.5%/day ≤ 24 hrs.

0.25%/day > 24 hrs.

(5) Enclosure Building Filtration System (EBFS) charcoal filter efficiencies:

particulate/elemental/organic 90 / 90 / 70% (1)

(6) Time Before Enclosure Building Filtration System (EBFS) is Fully Functional

110 seconds

(7) EBFS Bypass Leakage

(% by Weight of Containment Air per Day)

0 - 110 sec: 0.5%

110 sec - 24 hours: 0.007%

24 - 720 hours: 0.0035%

NOTE: Prior to EBFS draw down at 110 seconds, bypass leakage is the full containment leak rate of 0.5%. After 110 seconds, bypass leakage is based on 1.4% of containment leak rate and half that at 24 hours.

(8) X/Qs:

Location Time Period Elevated Ground Release

EAB (0-2) hrs. 1.00 E-04 3.66 E-04

LPZ (0-4) hrs 2.69 E-05 4.80 E-05

(4-8) hrs. 1.07E-05 2.31 E-05

(8-24) hrs. 6.72E-06 1.60 E-05

(24-96) hrs. 2.46E-06 7.25 E-06

(96-720) hrs. 5.83E-07 2.32 E-06


(1) 70% is a conservative analysis assumption for the organic iodine. Technical Specifications can support assumptions for efficiencies of 90% for all iodine species.

(9) Dose Conversion Factors Federal Guidance Reports 11 and 12

(10) Containment Free Air Volume = 1.899 x 106 ft3

(11) Breathing Rates

(0 -8) hr. = 3.5 x 10-4 m3/sec

(8-24) hr. = 1.8 x 10-4 m3/sec

(24-720) hr. = 2.3 x 10-4 m3/sec

(12) Release Points:Filtered - Millstone Stack

Bypass - MP-2 Containment

(13) Containment Sprayed Volume: 35.4%

(14) Containment Spray Removal Coefficients: elemental = 20 per hour

particulate = 6.42 per hour

(15) Containment Spray Effectiveness Time: elemental: 75 seconds - 3.03 hours

particulate: 75 seconds - 3.23 hours

(16) ESF Leakage: 24 gallons per hour

(17) ESF Leakage begins at 27.5 minutes post LOCA

(18) Sump Volume: 3.773E+04 ft3

(19) RWST Back leakage begins at 6.45 hours

(20) RWST Back leakage amount: 0.05 - 0.70 gpm

(21) Iodine DF: 100

(22) Sump pH ≥ 7.0

TABLE 14.8.4-1 LOSS OF COOLANT ACCIDENT (OFF SITE ASSUMPTIONS) (CONTINUED)

Assumption


TABLE 14.8.4-2 SUMMARY OF DOSES FOR LOSS OF COOLANT ACCIDENT

DOSE (rems)

TEDE

EAB 2.9E+00

LPZ 1.7E+00


TABLE 14.8.4-3 LOSS OF COOLANT ACCIDENT (CONTROL ROOM ASSUMPTIONS)

1. Control Room Volume = 3.565 E+04 ft3.

2. Control Room Unfiltered Inleakage in Recirculation Mode200 cfm

3. Control Room Normal Makeup Air Flowrate 800 cfm

4. Time from MP-2 LOCA Initiation to Time when Control Room Intake Dampers Close20 seconds

5. Time when Control Room Emergency Ventilation (Filtration) System Operating at Full Capacity

1 hour

6. Control Room Emergency Ventilation (Filtration) System Flowrate 2,250 cfm

7. CREV Filter Efficiency

70% (1)

8. Control Room Shielding:

North Wall: 2' concrete.

West Wall: 1.5 feet concrete except 8 foot section which is 2 feet concrete.

South Wall: 24.5 feet of 1 foot concrete except glass wall 86.75 feet long.

East Wall: 2 feet concrete.

Roof: 2 feet concrete.

Floor: 2 foot concrete.

(1) 70% is a conservative analysis assumption for particulate, elemental and organic iodine. Technical Specifications can support assumptions for control room filter efficiencies of 90% for all iodine species.


TABLE 14.8.4-4 ATMOSPHERIC DISPERSION DATA FOR MILLSTONE UNIT 2 CONTROL ROOM

Release Point

Ground X/Q, sec/m3 RWST X/Q, sec/m3 Stack X/Q, sec/m3

0 - 2 hr 3.00 E-03 9.54 E-04 2.51 E-04

2 - 4 hr 1.87 E-03 7.56 E-04 2.51 E-04

4 - 8 hr 1.87 E-03 7.56 E-04 1.96 E-05

8 - 24 hr 6.64 E-04 2.72 E-04 5.46 E-06

24 - 96 hr 5.83 E-04 2.17 E-04 3.43 E-07

96 - 720 hr 4.97 E-04 1.51E-04 6.44 E-09


Notes:

(1) Dose through wall and ceiling from external sources included.

TABLE 14.8.4-5 DOSE TO MILLSTONE UNIT 2 CONTROL ROOM OPERATORS

Release TEDE (1)

Millstone 2 (LOCA) 3.0E+00

millstone power station unit 2, revision 38 to updated ... · revision 38—06/30/20 mps-2 fsar...

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