ML18053A741
| ML18053A741 | |
| Person / Time | |
|---|---|
| Site: | Lee  |
| Issue date: | 12/19/2017 |
| From: | Donahue J Duke Energy Carolinas |
| To: | Office of New Reactors |
| Hughes B | |
| References | |
| DUKE, DUKE.SUBMISSION.15, LEE.NP, LEE.NP.1 | |
| Download: ML18053A741 (637) | |
Text
UFSAR Table of Contents 1 Introduction and General Description of the Plant 2 Site Characteristics 3 Design of Structures, Components, Equipment and Systems 4 Reactor 5 Reactor Coolant System and Connected Systems 6 Engineered Safety Features 7 Instrumentation and Controls 8 Electric Power 9 Auxiliary Systems 10 Steam and Power Conversion 11 Radioactive Waste Management 12 Radiation Protection 13 Conduct of Operation 14 Initial Test Program 15 Accident Analyses 16 Technical Specifications 17 Quality Assurance 18 Human Factors Engineering 19 Probabilistic Risk Assessment UFSAR Formatting Legend Description Original Westinghouse AP1000 DCD Revision 19 content Departures from AP1000 DCD Revision 19 content Standard FSAR content Site-specific FSAR content Linked cross-references (chapters, appendices, sections, subsections, tables, figures, and references)
15.0.1 Classification of Plant Conditions ............................................... 15.0-1 15.0.1.1 Condition I: Normal Operation and Operational Transients .................................................................. 15.0-1 15.0.1.2 Condition II: Faults of Moderate Frequency............... 15.0-2 15.0.1.3 Condition III: Infrequent Faults................................... 15.0-3 15.0.1.4 Condition IV: Limiting Faults ...................................... 15.0-3 15.0.2 Optimization of Control Systems ................................................ 15.0-4 15.0.3 Plant Characteristics and Initial Conditions Assumed in the Accident Analyses ...................................................................... 15.0-4 15.0.3.1 Design Plant Conditions............................................. 15.0-4 15.0.3.2 Initial Conditions......................................................... 15.0-4 15.0.3.3 Power Distribution...................................................... 15.0-5 15.0.4 Reactivity Coefficients Assumed in the Accident Analysis ......... 15.0-6 15.0.5 Rod Cluster Control Assembly Insertion Characteristics ............ 15.0-6 15.0.6 Protection and Safety Monitoring System Setpoints and Time Delays to Trip Assumed in Accident Analyses ........................... 15.0-7 15.0.7 Instrumentation Drift and Calorimetric Errors, Power Range Neutron Flux ............................................................................... 15.0-7 15.0.8 Plant Systems and Components Available for Mitigation of Accident Effects .......................................................................... 15.0-8 15.0.9 Fission Product Inventories ........................................................ 15.0-8 15.0.10 Residual Decay Heat .................................................................. 15.0-8 15.0.10.1 Total Residual Heat ................................................... 15.0-8 15.0.10.2 Distribution of Decay Heat Following a Loss-of-Coolant Accident........................................... 15.0-8 15.0.11 Computer Codes Used ............................................................... 15.0-9 15.0.11.1 FACTRAN Computer Code........................................ 15.0-9 15.0.11.2 LOFTRAN Computer Code........................................ 15.0-9 15.0.11.3 TWINKLE Computer Code....................................... 15.0-10 15.0.11.4 VIPRE-01 Computer Code....................................... 15.0-10 15.0.11.5 COAST Computer Program ..................................... 15.0-10 15.0.11.6 ANC Computer Code ............................................... 15.0-11 15.0.12 Component Failures ................................................................. 15.0-11 15.0.12.1 Active Failures ......................................................... 15.0-11 15.0.12.2 Passive Failures....................................................... 15.0-11 15.0.12.3 Limiting Single Failures............................................ 15.0-12 15.0.13 Operator Actions....................................................................... 15.0-12 15.0.14 Loss of Offsite ac Power........................................................... 15.0-12 15.0.15 Combined License Information ................................................. 15.0-13 15.0.16 References ............................................................................... 15.0-13 15.1 Increase in Heat Removal From the Primary System ................................. 15.1-1 15.1.1 Feedwater System Malfunctions that Result in a Decrease in Feedwater Temperature ............................................................. 15.1-1 15.1.1.1 Identification of Causes and Accident Description..... 15.1-1 15.1.1.2 Analysis of Effects and Consequences...................... 15.1-2 15.1.1.3 Conclusions ............................................................... 15.1-2 15-i Revision 1
Feedwater Flow .......................................................................... 15.1-2 15.1.2.1 Identification of Causes and Accident Description..... 15.1-2 15.1.2.2 Analysis of Effects and Consequences...................... 15.1-3 15.1.2.3 Conclusions ............................................................... 15.1-5 15.1.3 Excessive Increase in Secondary Steam Flow........................... 15.1-5 15.1.3.1 Identification of Causes and Accident Description..... 15.1-5 15.1.3.2 Analysis of Effects and Consequences...................... 15.1-6 15.1.3.3 Conclusions ............................................................... 15.1-7 15.1.4 Inadvertent Opening of a Steam Generator Relief or Safety Valve........................................................................................... 15.1-8 15.1.4.1 Identification of Causes and Accident Description..... 15.1-8 15.1.4.2 Analysis of Effects and Consequences...................... 15.1-9 15.1.4.3 Margin to Critical Heat Flux...................................... 15.1-10 15.1.4.4 Conclusions ............................................................. 15.1-10 15.1.5 Steam System Piping Failure .................................................. 15.1-11 15.1.5.1 Identification of Causes and Accident Description... 15.1-11 15.1.5.2 Analysis of Effects and Consequences.................... 15.1-12 15.1.5.3 Conclusions ............................................................. 15.1-16 15.1.5.4 Radiological Consequences .................................... 15.1-16 15.1.6 Inadvertent Operation of the PRHR Heat Exchanger ............... 15.1-18 15.1.6.1 Identification of Causes and Accident Description... 15.1-18 15.1.6.2 Analysis of Effects and Consequences.................... 15.1-19 15.1.6.3 Conclusions ............................................................. 15.1-19 15.1.7 Combined License Information ................................................. 15.1-19 15.1.8 References ............................................................................... 15.1-19 15.2 Decrease in Heat Removal by the Secondary System ............................... 15.2-1 15.2.1 Steam Pressure Regulator Malfunction or Failure that Results in Decreasing Steam Flow.......................................................... 15.2-1 15.2.2 Loss of External Electrical Load ................................................. 15.2-1 15.2.2.1 Identification of Causes and Accident Description..... 15.2-1 15.2.2.2 Analysis of Effects and Consequences...................... 15.2-3 15.2.2.3 Conclusions ............................................................... 15.2-3 15.2.3 Turbine Trip ................................................................................ 15.2-3 15.2.3.1 Identification of Causes and Accident Description..... 15.2-3 15.2.3.2 Analysis of Effects and Consequences...................... 15.2-4 15.2.3.3 Conclusions ............................................................... 15.2-7 15.2.4 Inadvertent Closure of Main Steam Isolation Valves .................. 15.2-7 15.2.5 Loss of Condenser Vacuum and Other Events Resulting in Turbine Trip ................................................................................ 15.2-7 15.2.6 Loss of ac Power to the Plant Auxiliaries ................................... 15.2-8 15.2.6.1 Identification of Causes and Accident Description..... 15.2-8 15.2.6.2 Analysis of Effects and Consequences...................... 15.2-9 15.2.6.3 Conclusions ............................................................. 15.2-11 15.2.7 Loss of Normal Feedwater Flow ............................................... 15.2-11 15.2.7.1 Identification of Causes and Accident Description... 15.2-11 15.2.7.2 Analysis of Effects and Consequences.................... 15.2-12 15.2.7.3 Conclusions ............................................................. 15.2-14 15-ii Revision 1
15.2.8.1 Identification of Causes and Accident Description... 15.2-14 15.2.8.2 Analysis of Effects and Consequences.................... 15.2-15 15.2.8.3 Conclusions ............................................................. 15.2-18 15.2.9 Combined License Information ................................................. 15.2-18 15.2.10 References ............................................................................... 15.2-18 15.3 Decrease in Reactor Coolant System Flow Rate ........................................ 15.3-1 15.3.1 Partial Loss of Forced Reactor Coolant Flow ............................. 15.3-1 15.3.1.1 Identification of Causes and Accident Description..... 15.3-1 15.3.1.2 Analysis of Effects and Consequences...................... 15.3-1 15.3.1.3 Conclusions ............................................................... 15.3-3 15.3.2 Complete Loss of Forced Reactor Coolant Flow ........................ 15.3-3 15.3.2.1 Identification of Causes and Accident Description..... 15.3-3 15.3.2.2 Analysis of Effects and Consequences...................... 15.3-4 15.3.2.3 Conclusions ............................................................... 15.3-4 15.3.3 Reactor Coolant Pump Shaft Seizure (Locked Rotor) ................ 15.3-4 15.3.3.1 Identification of Causes and Accident Description..... 15.3-4 15.3.3.2 Analysis of Effects and Consequences...................... 15.3-5 15.3.3.3 Radiological Consequences ...................................... 15.3-7 15.3.4 Reactor Coolant Pump Shaft Break ........................................... 15.3-9 15.3.4.1 Identification of Causes and Accident Description..... 15.3-9 15.3.4.2 Conclusion ................................................................. 15.3-9 15.3.5 Combined License Information ................................................... 15.3-9 15.3.6 References ................................................................................. 15.3-9 15.4 Reactivity and Power Distribution Anomalies .............................................. 15.4-1 15.4.1 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal from a Subcritical or Low-Power Startup Condition .................... 15.4-1 15.4.1.1 Identification of Causes and Accident Description..... 15.4-1 15.4.1.2 Analysis of Effects and Consequences...................... 15.4-3 15.4.1.3 Conclusions ............................................................... 15.4-4 15.4.2 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power ..................................................................................... 15.4-4 15.4.2.1 Identification of Causes and Accident Description..... 15.4-4 15.4.2.2 Analysis of Effects and Consequences...................... 15.4-6 15.4.2.3 Conclusions ............................................................... 15.4-9 15.4.3 Rod Cluster Control Assembly Misalignment (System Malfunction or Operator Error).................................................... 15.4-9 15.4.3.1 Identification of Causes and Accident Description..... 15.4-9 15.4.3.2 Analysis of Effects and Consequences.................... 15.4-11 15.4.3.3 Conclusions ............................................................. 15.4-14 15.4.4 Startup of an Inactive Reactor Coolant Pump at an Incorrect Temperature ............................................................................. 15.4-14 15.4.5 A Malfunction or Failure of the Flow Controller in a Boiling Water Reactor Loop that Results in an Increased Reactor Coolant Flow Rate .................................................................... 15.4-14 15-iii Revision 1
Results in a Decrease in the Boron Concentration in the Reactor Coolant........................................................................ 15.4-14 15.4.6.1 Identification of Causes and Accident Description... 15.4-14 15.4.6.2 Analysis of Effects and Consequences.................... 15.4-15 15.4.6.3 Conclusions ............................................................. 15.4-20 15.4.7 Inadvertent Loading and Operation of a Fuel Assembly in an Improper Position ..................................................................... 15.4-20 15.4.7.1 Identification of Causes and Accident Description... 15.4-20 15.4.7.2 Analysis of Effects and Consequences.................... 15.4-21 15.4.7.3 Conclusions ............................................................. 15.4-22 15.4.8 Spectrum of Rod Cluster Control Assembly Ejection Accidents .................................................................................. 15.4-22 15.4.8.1 Identification of Causes and Accident Description... 15.4-22 15.4.8.2 Analysis of Effects and Consequences.................... 15.4-25 15.4.8.3 Radiological Consequences .................................... 15.4-28 15.4.9 Combined License Information ................................................. 15.4-30 15.4.10 References ............................................................................... 15.4-31 15.5 Increase in Reactor Coolant Inventory ........................................................ 15.5-1 15.5.1 Inadvertent Operation of the Core Makeup Tanks During Power Operation......................................................................... 15.5-1 15.5.1.1 Identification of the Causes and Accident Description ................................................................. 15.5-1 15.5.1.2 Analysis of Effects and Consequences...................... 15.5-2 15.5.1.3 Results ....................................................................... 15.5-3 15.5.1.4 Conclusions ............................................................... 15.5-4 15.5.2 Chemical and Volume Control System Malfunction That Increases Reactor Coolant Inventory ......................................... 15.5-4 15.5.2.1 Identification of Causes and Accident Description..... 15.5-4 15.5.2.2 Analysis of Effects and Consequences...................... 15.5-6 15.5.2.3 Results ....................................................................... 15.5-7 15.5.2.4 Conclusions ............................................................... 15.5-8 15.5.3 Boiling Water Reactor Transients ............................................... 15.5-8 15.5.4 Combined License Information ................................................... 15.5-8 15.5.5 References ................................................................................. 15.5-8 15.6 Decrease in Reactor Coolant Inventory ...................................................... 15.6-1 15.6.1 Inadvertent Opening of a Pressurizer Safety Valve or Inadvertent Operation of the ADS .............................................. 15.6-1 15.6.1.1 Identification of Causes and Accident Description..... 15.6-1 15.6.1.2 Analysis of Effects and Consequences...................... 15.6-2 15.6.1.3 Conclusion ................................................................. 15.6-4 15.6.2 Failure of Small Lines Carrying Primary Coolant Outside Containment ............................................................................... 15.6-4 15.6.2.1 Source Term .............................................................. 15.6-4 15.6.2.2 Release Pathway ....................................................... 15.6-4 15.6.2.3 Dose Calculation Models ........................................... 15.6-5 15.6.2.4 Analytical Assumptions and Parameters ................... 15.6-5 15-iv Revision 1
15.6.2.6 Doses......................................................................... 15.6-5 15.6.3 Steam Generator Tube Rupture ................................................. 15.6-5 15.6.3.1 Identification of Cause and Accident Description....... 15.6-5 15.6.3.2 Analysis of Effects and Consequences...................... 15.6-8 15.6.3.3 Radiological Consequences .................................... 15.6-12 15.6.3.4 Conclusions ............................................................. 15.6-13 15.6.4 Spectrum of Boiling Water Reactor Steam System Piping Failures Outside of Containment .............................................. 15.6-14 15.6.5 Loss-of-Coolant Accidents Resulting from a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary ................................................................... 15.6-14 15.6.5.1 Identification of Causes and Frequency Classification............................................................ 15.6-14 15.6.5.2 Basis and Methodology for LOCA Analyses ............ 15.6-15 15.6.5.3 Radiological Consequences .................................... 15.6-16 15.6.5.4 Core and System Performance................................ 15.6-21 15.6.5.4A Large-Break LOCA Analysis Methodology and Results .................................................................... 15.6-21 15.6.5.4B Small-Break LOCA Analyses .................................. 15.6-26 15.6.5.4C Post-LOCA Long-Term Cooling .............................. 15.6-40 15.6.6 References ............................................................................... 15.6-46 15.7 Radioactive Release from a Subsystem or Component ............................. 15.7-1 15.7.1 Gas Waste Management System Leak or Failure ...................... 15.7-1 15.7.2 Liquid Waste Management System Leak or Failure (Atmospheric Release) ............................................................... 15.7-1 15.7.3 Release of Radioactivity to the Environment Due to a Liquid Tank Failure................................................................................ 15.7-1 15.7.4 Fuel Handling Accident............................................................... 15.7-1 15.7.4.1 Source Term .............................................................. 15.7-2 15.7.4.2 Release Pathways ..................................................... 15.7-2 15.7.4.3 Dose Calculation Models ........................................... 15.7-3 15.7.4.4 Identification of Conservatisms .................................. 15.7-3 15.7.4.5 Offsite Doses ............................................................. 15.7-4 15.7.5 Spent Fuel Cask Drop Accident ................................................. 15.7-4 15.7.6 Combined License Information ................................................... 15.7-4 15.7.7 References ................................................................................. 15.7-4 15.8 Anticipated Transients Without Scram ........................................................ 15.8-1 15.8.1 General Background................................................................... 15.8-1 15.8.2 Anticipated Transients Without Scram in the AP1000 ................ 15.8-1 15.8.3 Conclusion .................................................................................. 15.8-1 15.8.4 Combined License Information ................................................... 15.8-1 15.8.5 References ................................................................................. 15.8-1 15-v Revision 1
RADIOLOGICAL CONSEQUENCES OF ACCIDENTS ..........................15A-1 15A.1 Offsite Dose Calculation Models .................................................................. 15A-1 15A.1.1 Immersion Dose (Effective Dose Equivalent) .............................. 15A-1 15A.1.2 Inhalation Dose (Committed Effective Dose Equivalent) ............. 15A-1 15A.1.3 Total Dose (Total Effective Dose Equivalent) .............................. 15A-2 15A.2 Main Control Room Dose Models ................................................................ 15A-2 15A.2.1 Immersion Dose Models .............................................................. 15A-2 15A.2.2 Inhalation Dose............................................................................ 15A-2 15A.2.3 Total Dose (Total Effective Dose Equivalent) .............................. 15A-3 15A.3 General Analysis Parameters ...................................................................... 15A-3 15A.3.1 Source Terms .............................................................................. 15A-3 15A.3.1.1 Primary Coolant Source Term ...................................15A-3 15A.3.1.2 Secondary Coolant Source Term ...............................15A-3 15A.3.1.3 Core Source Term .....................................................15A-4 15A.3.2 Nuclide Parameters ..................................................................... 15A-4 15A.3.3 Atmospheric Dispersion Factors.................................................. 15A-4 15A.4 References................................................................................................... 15A-4 PENDIX 15B REMOVAL OF AIRBORNE ACTIVITY FROM THE CONTAINMENT ATMOSPHERE FOLLOWING A LOCA ..................................................15B-1 15B.1 Elemental Iodine Removal ........................................................................... 15B-1 15B.2 Aerosol Removal.......................................................................................... 15B-1 15B.2.1 Mathematical Models................................................................... 15B-2 15B.2.1.1 Sedimentation ............................................................15B-2 15B.2.1.2 Diffusiophoresis .........................................................15B-4 15B.2.1.3 Thermophoresis .........................................................15B-4 15B.2.2 Other Removal Mechanisms ....................................................... 15B-5 15B.2.3 Validation of Removal Mechanisms ............................................ 15B-5 15B.2.4 Parameters and Assumptions for Calculating Aerosol Removal Coefficients ..................................................................................15B-6 15B.2.4.1 Containment Geometry ..............................................15B-6 15B.2.4.2 Source Size Distribution .............................................15B-6 15B.2.4.3 Aerosol Void Fraction .................................................15B-6 15B.2.4.4 Fission Product Release Fractions ............................15B-7 15B.2.4.5 Inert Aerosol Species .................................................15B-7 15B.2.4.6 Aerosol Release Timing and Rates ...........................15B-7 15B.2.4.7 Containment Thermal-Hydraulic Data ........................15B-7 15B.2.5 Aerosol Removal Coefficients ..................................................... 15B-7 15B.3 References................................................................................................... 15B-8 15-vi Revision 1
0-2 Summary of Initial Conditions and Computer Codes Used ........................ 15.0-16 0-3 Nominal Values of Pertinent Plant Parameters Used in Accident Analyses ..................................................................................................... 15.0-20 0-4a Protection and Safety Monitoring System Setpoints and Time Delay Assumed in Accident Analyses .................................................................. 15.0-21 0-4b Limiting Delay Times for Equipment Assumed in Accident Analyses ........ 15.0-23 0-5 Determination of Maximum Power Range Neutron Flux Channel Trip Setpoint, Based on Nominal Setpoint and Inherent Typical Instrumentation Uncertainties .............................................................................................. 15.0-24 0-6 Plant Systems and Equipment Available for Transient and Accident Conditions .................................................................................................. 15.0-25 0-7 Single Failures Assumed in Accident Analyses ......................................... 15.0-29 0-8 Nonsafety-Related System and Equipment Used for Mitigation of Accidents .................................................................................................... 15.0-31 1.2-1 Time Sequence of Events for Incidents That Result in an Increase in Heat Removal From the Primary System................................................... 15.1-20 1.5-1 Parameters Used in Evaluating the Radiological Consequences of a Main Steam Line Break .............................................................................. 15.1-22 2-1 Time Sequence of Events for Incidents Which Result in a Decrease in Heat Removal By the Secondary System .................................................. 15.2-20 3-1 Time Sequence of Events for Incidents That Result in a Decrease In Reactor Coolant System Flow Rate ........................................................... 15.3-11 3-2 Summary of Results for Locked Rotor Transients (Four Reactor Coolant Pumps Operating Initially) .......................................................................... 15.3-12 3-3 Parameters Used in Evaluating the Radiological Consequences of a Locked Rotor Accident ............................................................................... 15.3-13 4-1 Time Sequence of Events for Incidents Which Result in Reactivity and Power Distribution Anomalies .................................................................... 15.4-33 4-2 Parameters................................................................................................. 15.4-35 4-3 Deleted ....................................................................................................... 15.4-36 4-4 Parameters Used in Evaluating the Radiological Consequences of a Rod Ejection Accident ................................................................................ 15.4-37 4-201 Not Used ..................................................................................................... 15.4-39 4-202 Not Used ..................................................................................................... 15.4-40 4-203 Not Used...................................................................................................... 15.4-41 5-1 Time Sequence of Events For Incidents Which Result in an Increase in Reactor Coolant Inventory ............................................................................ 15.5-9 6.1-1 Time Sequence of Events for Incidents That Cause a Decrease in Reactor Coolant Inventory.......................................................................... 15.6-49 6.2-1 Parameters Used in Evaluating the Radiological Consequences of a Small Line Break Outside Containment ..................................................... 15.6-50 6.3-1 Steam Generator Tube Rupture Sequence of Events................................ 15.6-51 6.3-2 Steam Generator Tube Rupture Mass Release Results ............................ 15.6-52 6.3-3 Parameters Used in Evaluating the Radiological Consequences of a Steam Generator Tube Rupture ................................................................. 15.6-53 15-vii Revision 1
6.5-2 Assumptions and Parameters Used in Calculating Radiological Consequences of a Loss-of-Coolant Accident ........................................... 15.6-55 6.5-3 Radiological Consequences of a Loss-of-Coolant Accident With Core Melt ............................................................................................................. 15.6-57 6.5-4 Major Plant Parameter Assumptions Used in the Best-Estimate Large-Break LOCA Analysis ...................................................................... 15.6-58 6.5-5 AP1000 LOCA Chronology ........................................................................ 15.6-59 6.5-6 Best-Estimate Large-Break Sequence of Events for the Limiting PCT/MLO Case .......................................................................................... 15.6-60 6.5-7 Not Used .................................................................................................... 15.6-61 6.5-8 Best-Estimate Large-Break LOCA Results ................................................ 15.6-62 6.5-9 Initial Conditions for AP1000 Small-Break LOCA Analysis ........................ 15.6-63 6.5-10 AP1000 ADS Parameters........................................................................... 15.6-64 6.5-11 Inadvertent ADS Depressurization Sequence of Events............................ 15.6-65 6.5-12 2-Inch Cold Leg Break in CLBL Line Sequence of Events......................... 15.6-66 6.5-13 Double-Ended Injection Line Break Sequence of Events - 20 psi ............. 15.6-67 6.5-13A Double-Ended Injection Line Break Sequence of Events - 14.7 psi .......... 15.6-68 6.5-14 10-inch Cold Leg Break in Sequence of Events......................................... 15.6-69 6.5-15 Double-Ended Injection Line Break Sequence of Events (Entrainment Sensitivity) .................................................................................................. 15.6-70 7-1 Assumptions Used to Determine Fuel Handling Accident Radiological Consequences ............................................................................................. 15.7-5
-1 Reactor Coolant Iodine Concentrations for Maximum Iodine Spike of 60 Ci/g Dose Equivalent I-131 ....................................................................15A-6
-2 Iodine Appearance Rates in the Reactor Coolant ......................................... 15A-6
-3 Reactor Core Source Term ........................................................................... 15A-7
-4 Nuclide Parameters....................................................................................... 15A-9
-5 Offsite Atmospheric Dispersion Factors (/Q) for Accident Dose Analysis .......................................................................................................15A-12
-6 Control Room Atmospheric Dispersion Factors (/Q) for Accident Dose Analysis .......................................................................................................15A-13
-7 Control Room Source/Receptor Data for Determination Of Atmospheric Dispersion Factors ......................................................................................15A-14
-1 Aerosol Removal Coefficients in the AP1000 Containment Following a Design Basis LOCA With Core Melt .............................................................15.B-9 15-viii Revision 1
0.3-2 AP1000 Loop Layout ................................................................................. 15.0-33 0.4-1 Doppler Power Coefficient used in Accident Analysis ............................... 15.0-34 0.5-1 RCCA Position Versus Time to Dashpot ................................................... 15.0-35 0.5-2 Normalized Rod Worth Versus Position .................................................... 15.0-36 0.5-3 Normalized RCCA Bank Reactivity Worth Versus Drop Time .................. 15.0-37 1.2-1 Feedwater Control Valve Malfunction Nuclear Power ............................... 15.1-23 1.2-2 Feedwater Control Valve Malfunction Loop T ......................................... 15.1-24 1.2-3 Feedwater Control Valve Malfunction Core Coolant Mass Flow ............... 15.1-25 1.3-1 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback ........ 15.1-26 1.3-2 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback ................. 15.1-27 1.3-3 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback ................. 15.1-28 1.3-4 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback ................. 15.1-29 1.3-5 DNBR Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback .......................................................... 15.1-30 1.3-6 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback ....... 15.1-31 1.3-7 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback ................ 15.1-32 1.3-8 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback ................ 15.1-33 1.3-9 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback ................ 15.1-34 1.3-10 DNBR Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback ......................................................... 15.1-35 1.3-11 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback .... 15.1-36 1.3-12 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback ............. 15.1-37 1.3-13 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback ............. 15.1-38 1.3-14 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback ............. 15.1-39 1.3-15 DNBR Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback .............................................. 15.1-40 1.3-16 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback ... 15.1-41 1.3-17 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback ............ 15.1-42 1.3-18 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback ............ 15.1-43 15-ix Revision 1
Increase, Automatic Control and Maximum Moderator Feedback ............ 15.1-44 1.3-20 DNBR Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback ............................................. 15.1-45 1.4-1 Keff Versus Core Inlet Temperature Steam Line Break Events ................. 15.1-46 1.4-2 Nuclear Power Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve ................................................................................ 15.1-47 1.4-3 Core Heat Flux Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve ................................................................................ 15.1-48 1.4-4 Loop 1 Reactor Coolant Temperatures Inadvertent Opening of a Steam Generator Relief or Safety Valve .............................................................. 15.1-49 1.4-5 Loop 2 (Faulted Loop) Reactor Coolant Temperatures Inadvertent Opening of a Steam Generator Relief or Safety Valve ............................. 15.1-50 1.4-6 Reactor Coolant System Pressure Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve ................................................... 15.1-51 1.4-7 Pressurizer Water Volume Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve .............................................................. 15.1-52 1.4-8 Core Flow Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve .......................................................................................... 15.1-53 1.4-9 Feedwater Flow Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve ................................................................................ 15.1-54 1.4-10 Core Boron Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve .......................................................................................... 15.1-55 1.4-11 Steam Pressure Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve ................................................................................ 15.1-56 1.4-12 Steam Flow Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve .......................................................................................... 15.1-57 1.5-1 Nuclear Power Transient Steam System Piping Feature .......................... 15.1-58 1.5-2 Core Heat Flux Transient Steam System Piping Failure ........................... 15.1-59 1.5-3 Loop 1 Reactor Coolant Temperatures Steam System Piping Failure ..... 15.1-60 1.5-4 Loop 2 Reactor Coolant Temperatures Steam System Piping Failure ..... 15.1-61 1.5-5 Reactor Coolant System Pressure Transient Steam System Piping Failure ....................................................................................................... 15.1-62 1.5-6 Pressurizer Water Volume Transient Steam System Piping Failure ......... 15.1-63 1.5-7 Core Flow Transient Steam System Piping Failure .................................. 15.1-64 1.5-8 Feedwater Flow Transient Steam System Piping Failure ......................... 15.1-65 1.5-9 Core Boron Transient Steam System Piping Failure ................................ 15.1-66 1.5-10 Steam Pressure Transient Steam System Piping Failure ......................... 15.1-67 1.5-11 Steam Flow Transient Steam System Piping Failure ................................ 15.1-68 1.5-12 Core Makeup Tank Injection Flow Steam System Piping Failure ............. 15.1-69 1.5-13 Core Makeup Tank Water Volume Steam System Piping Failure ............ 15.1-70 1.6-1 Not Used. .................................................................................................. 15.1-71 1.6-2 Not Used. .................................................................................................. 15.1-71 1.6-3 Not Used. .................................................................................................. 15.1-71 1.6-4 Not Used. .................................................................................................. 15.1-71 1.6-5 Not Used. .................................................................................................. 15.1-71 1.6-6 Not Used. .................................................................................................. 15.1-71 15-x Revision 1
1.6-8 Not Used. .................................................................................................. 15.1-71 2.3-1 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ....... 15.2-27 2.3-2 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ............................. 15.2-28 2.3-3 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ..................... 15.2-29 2.3-4 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ............................. 15.2-30 2.3-5 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ..................... 15.2-31 2.3-6 DNBR versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ................................................................. 15.2-32 2.3-7 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback ....... 15.2-33 2.3-8 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback ...... 15.2-34 2.3-9 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback ............................ 15.2-35 2.3-10 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback .................... 15.2-36 2.3-11 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback ............................ 15.2-37 2.3-12 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback .................... 15.2-38 2.3-13 DNBR versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback ................................................................ 15.2-39 2.3-14 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback ...... 15.2-40 2.3-15 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback .................................................................................................. 15.2-41 2.3-16 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback ................ 15.2-42 2.3-17 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback ................ 15.2-43 2.3-18 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback ................ 15.2-44 2.3-19 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback ................ 15.2-45 2.3-20 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback .................................................................................................. 15.2-46 2.3-21 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback ............... 15.2-47 2.3-22 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback ............... 15.2-48 15-xi Revision 1
Without Pressurizer Spray and Maximum Moderator Feedback ............... 15.2-49 2.3-24 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback ............... 15.2-50 2.3-25 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback ............... 15.2-51 2.3-26 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback .................................................................................................. 15.2-52 2.6-1 Nuclear Power Transient for Loss of ac Power to the Plant Auxiliaries .... 15.2-53 2.6-2 Core Heat Flux Transient for Loss of ac Power to the Plant Auxiliaries .... 15.2-54 2.6-3 Pressurizer Pressure Transient for Loss of ac Power to the Plant Auxiliaries .................................................................................................. 15.2-55 2.6-4 Pressurizer Water Volume Transient for Loss of ac Power to the Plant Auxiliaries .................................................................................................. 15.2-56 2.6-5 Reactor Coolant System Temperature Transients in Loop Containing the PRHR for Loss of ac Power to the Plant Auxiliaries .................................. 15.2-57 2.6-6 Reactor Coolant System Temperature Transients in Loop Not Containing the PRHR for Loss of ac Power to the Plant Auxiliaries ............................ 15.2-58 2.6-7 Steam Generator Pressure Transient for Loss of ac Power to the Plant Auxiliaries .................................................................................................. 15.2-59 2.6-8 PRHR Flow Rate Transient for Loss of ac Power to the Plant Auxiliaries .................................................................................................. 15.2-60 2.6-9 PRHR Heat Flux Transient for Loss of ac Power to the Plant Auxiliaries .................................................................................................. 15.2-61 2.6-10 Reactor Coolant Volumetric Flow Rate Transient for Loss of ac Power to the Plant Auxiliaries ............................................................................... 15.2-62 2.6-11 Steam Generator Inventory Transient for Loss of ac Power to the Plant Auxiliaries .................................................................................................. 15.2-63 2.6-12 DNB Ratio Transient for Loss of ac Power to the Plant Auxiliaries ........... 15.2-64 2.7-1 Nuclear Power Transient for Loss of Normal Feedwater Flow .................. 15.2-65 2.7-2 Reactor Coolant System Volumetric Flow Transient for Loss of Normal Feedwater Flow ......................................................................................... 15.2-66 2.7-3 Reactor Coolant System Temperature Transients in Loop Containing the PRHR for Loss Normal Feedwater Flow ................................................... 15.2-67 2.7-4 Reactor Coolant System Temperature Transients in Loop Not Containing the PRHR for Loss of Normal Feedwater Flow ......................................... 15.2-68 2.7-5 Pressurizer Pressure Transient for Loss of Normal Feedwater Flow ........ 15.2-69 2.7-6 Pressurizer Water Volume Transient for Loss of Normal Feedwater Flow ........................................................................................................... 15.2-70 2.7-7 Steam Generator Pressure Transient for Loss of Normal Feedwater Flow ........................................................................................................... 15.2-71 2.7-8 Steam Generator Inventory Transient for Loss of Normal Feedwater Flow ........................................................................................................... 15.2-72 2.7-9 PRHR Heat Flux Transient for Loss of Normal Feedwater Flow ............... 15.2-73 2.7-10 CMT Injection Flow Rate Transient for Loss of Normal Feedwater Flow ........................................................................................................... 15.2-74 15-xii Revision 1
2.8-2 Core Heat Flux Transient for Main Feedwater Line Rupture .................... 15.2-76 2.8-3 Faulted Loop Reactor Coolant System Temperature Transients for Main Feedwater Line Rupture ................................................................... 15.2-77 2.8-4 Intact Loop Reactor Coolant System Temperature Transients for Main Feedwater Line Rupture ............................................................................ 15.2-78 2.8-5 Pressurizer Pressure Transient for Main Feedwater Line Rupture ........... 15.2-79 2.8-6 Pressurizer Water Volume Transient for Main Feedwater Line Rupture ... 15.2-80 2.8-7 Steam Generator Pressure Transient for Main Feedwater Line Rupture ..................................................................................................... 15.2-81 2.8-8 PRHR Flow Rate Transient for Main Feedwater Line Rupture ................. 15.2-82 2.8-9 PRHR Heat Flux Transient for Main Feedwater Line Rupture .................. 15.2-83 2.8-10 CMT Injection Flow Rate Transient for Main Feedwater Line Rupture ..... 15.2-84 3.1-1 Core Mass Flow Transient for Four Cold Legs in Operation, Two Pumps Coasting Down .......................................................................................... 15.3-14 3.1-2 Nuclear Power Transient for Four Cold Legs in Operation, Two Pumps Coasting Down .......................................................................................... 15.3-15 3.1-3 Pressurizer Pressure Transient for Four Cold Legs in Operation, Two Pumps Coasting Down .............................................................................. 15.3-16 3.1-4 Average Channel Heat Flux Transient for Four Cold Legs in Operation, Two Pumps Coasting Down ...................................................................... 15.3-17 3.1-5 Hot Channel Heat Flux Transient for Four Cold Legs in Operation, Two Pumps Coasting Down .............................................................................. 15.3-18 3.1-6 DNB Transient for Four Cold Legs in Operation, Two Pumps Coasting Down ......................................................................................................... 15.3-19 3.2-1 Flow Transient for Four Cold Legs in Operation, Four Pumps Coasting Down ......................................................................................................... 15.3-20 3.2-2 Nuclear Power Transient for Four Cold Legs in Operation, Four Pumps Coasting Down .......................................................................................... 15.3-21 3.2-3 Pressurizer Pressure Transient for Four Cold Legs in Operation, Four Pumps Coasting Down .............................................................................. 15.3-22 3.2-4 Average Channel Heat Flux Transient for Four Cold Legs in Operation, Four Pumps Coasting Down ..................................................................... 15.3-23 3.2-5 Hot Channel Heat Flux Transient for Four Cold Legs in Operation, Four Pumps Coasting Down .............................................................................. 15.3-24 3.2-6 DNBR Transient for Four Cold Legs in Operation, Four Pumps Coasting Down .......................................................................................... 15.3-25 3.3-1 Core Mass Flow Transient for Four Cold Legs in Operation, One Locked Rotor ............................................................................................. 15.3-26 3.3-2 Faulted Loop Volumetric Flow Transient for Four Cold Legs in Operation, One Locked Rotor ..................................................................................... 15.3-27 3.3-3 Peak Reactor Coolant Pressure for Four Cold Legs in Operation, One Locked Rotor ............................................................................................. 15.3-28 3.3-4 Average Channel Heat Flux Transient for Four Cold Legs in Operation, One Locked Rotor ..................................................................................... 15.3-29 3.3-5 Hot Channel Heat Flux Transient for Four Cold Legs in Operation, One Locked Rotor ..................................................................................... 15.3-30 15-xiii Revision 1
Rotor ......................................................................................................... 15.3-31 3.3-7 Cladding Inside Temperature Transient for Four Cold Legs in Operation, One Locked Rotor ..................................................................................... 15.3-32 4.1-1 RCCA Withdrawal from Subcritical Nuclear Power ................................... 15.4-42 4.1-2 RCCA Withdrawal from Subcritical Average Channel Core Heat Flux ..... 15.4-43 4.1-3 RCCA Withdrawal from Subcritical Hot Spot Fuel Average Temperature (Sheet 1 of 2) ............................................................................................ 15.4-44 4.1-3 RCCA Withdrawal from Subcritical Hot Spot Cladding Inner Temperature (Sheet 2 of 2) ............................................................................................ 15.4-45 4.2-1 Nuclear Power Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) ............. 15.4-46 4.2-2 Thermal Flux Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) ............. 15.4-47 4.2-3 Pressurizer Pressure Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) ................................................................................................. 15.4-48 4.2-4 Pressurizer Water Volume Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) ................................................................................................. 15.4-49 4.2-5 Core Coolant Average Temperature Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) ................................................................................ 15.4-50 4.2-6 DNBR Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) ............................ 15.4-51 4.2-7 Nuclear Power Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) ............... 15.4-52 4.2-8 Thermal Flux Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) ....................... 15.4-53 4.2-9 Pressurizer Pressure Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) ................................................................................................... 15.4-54 4.2-10 Pressurizer Water Volume Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) ................................................................................................... 15.4-55 4.2-11 Core Coolant Average Temperature Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) .................................................................................. 15.4-56 4.2-12 DNBR Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) .............................. 15.4-57 4.2-13 Minimum DNBR Versus Reactivity Insertion Rate for Rod Withdrawal at 100-percent Power ................................................................................ 15.4-58 4.2-14 Minimum DNBR Versus Reactivity Insertion Rate for Rod Withdrawal at 60-percent Power .................................................................................. 15.4-59 4.2-15 Minimum DNBR Versus Reactivity Insertion Rate for Rod Withdrawal at 10-percent Power ................................................................................. 15.4-60 4.2-16 Not Used. .................................................................................................. 15.4-61 4.2-17 Not Used. .................................................................................................. 15.4-61 15-xiv Revision 1
4.3-2 Core Heat Flux Transient for Dropped RCCA ........................................... 15.4-63 4.3-3 Pressurizer Pressure Transient for Dropped RCCA ................................. 15.4-64 4.3-4 RCS Average Temperature Transient for Dropped RCCA ....................... 15.4-65 4.7-1 Representative Percent Change in Local Assembly Average Power for Interchange Between Region 1 and Region 3 Assembly .......................... 15.4-66 4.7-2 Representative Percent Change in Local Assembly Average Power for Interchange Between Region 1 and Region 2 Assembly with the BP Rods Transferred to Region 1 Assembly .................................................. 15.4-67 4.7-3 Representative Percent Change in Local Assembly Average Power for Enrichment Error (Region 2 Assembly Loaded into Core Central Position) .................................................................................................... 15.4-68 4.7-4 Representative Percent Change in Local Assembly Average Power for Loading Region 2 Assembly into Region 1 Position Near Core Periphery ................................................................................................... 15.4-69 4.8-1 Nuclear Power Transient Versus Time for the PCMI Rod Ejection Accident .................................................................................................... 15.4-70 4.8-2 Nuclear Power Transient Versus Time for the High Cladding Temperature Rod Ejection Accident ......................................................... 15.4-71 4.8-3 Nuclear Power Transient Versus Time for the Peak Enthalpy and Fuel Centerline Temperature Rod Ejection Accident ........................................ 15.4-72 4.8-4 Not Used. .................................................................................................. 15.4-73 5.1-1 Core Nuclear Power Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ....................................................... 15.5-11 5.1-2 RCS Temperature Transient in Loop Containing the PRHR for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ............... 15.5-12 5.1-3 RCS Temperature Transient in Loop Not Containing the PRHR for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ............... 15.5-13 5.1-4 Pressurizer Pressure Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ....................................................... 15.5-14 5.1-5 Pressurizer Water Volume Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ....................................................... 15.5-15 5.1-6 DNBR Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ...................................................................................... 15.5-16 5.1-7 Steam Generator Pressure Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ....................................................... 15.5-17 5.1-8 Inadvertent Actuated CMT Flow Rate Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves .............................. 15.5-18 15-xv Revision 1
Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ....................................................... 15.5-19 5.1-10 PRHR and Core Heat Flux Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ....................................................... 15.5-20 5.1-11 PRHR Flow Rate Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves ............................................................................. 15.5-21 5.2-1 Core Nuclear Power Transient for Chemical and Volume Control System Malfunction ................................................................................... 15.5-22 5.2-2 RCS Temperature Transient in Loop Containing the PRHR for Chemical and Volume Control System Malfunction .................................. 15.5-23 5.2-3 RCS Temperature Transient in Loop Not Containing the PRHR for Chemical and Volume Control System Malfunction .................................. 15.5-24 5.2-4 Pressurizer Pressure Transient for Chemical and Volume Control System Malfunction ................................................................................... 15.5-25 5.2-5 Pressurizer Water Volume Transient for Chemical and Volume Control System Malfunction ................................................................................... 15.5-26 5.2-6 DNBR Transient for Chemical and Volume Control System Malfunction ................................................................................................ 15.5-27 5.2-7 CVS Flow Rate Transient for Chemical and Volume Control System Malfunction ................................................................................................ 15.5-28 5.2-8 Steam Generator Pressure Transient for Chemical and Volume Control System Malfunction ................................................................................... 15.5-29 5.2-9 CMT Injection Line and Balance Line Flow Transient for Chemical and Volume Control System Malfunction ......................................................... 15.5-30 5.2-10 PRHR and Core Heat Flux Transient for Chemical and Volume Control System Malfunction ................................................................................... 15.5-31 5.2-11 PRHR Flow Rate Transient for Chemical and Volume Control System Malfunction ................................................................................................ 15.5-32 6.1-1 Nuclear Power Transient Inadvertent Opening of a Pressurizer Safety Valve ......................................................................................................... 15.6-71 6.1-2 DNBR Transient Inadvertent Opening of a Pressurizer Safety Valve ....... 15.6-72 6.1-3 Pressurizer Pressure Transient Inadvertent Opening of a Pressurizer Safety Valve .............................................................................................. 15.6-73 6.1-4 Vessel Average Temperature Inadvertent Opening of a Pressurizer Safety Valve .............................................................................................. 15.6-74 6.1-5 Core Mass Flow Rate Inadvertent Opening of a Pressurizer Safety Valve ......................................................................................................... 15.6-75 6.1-6 Nuclear Power Transient Inadvertent Opening of Two ADS Stage 1 Trains ........................................................................................................ 15.6-76 6.1-7 DNBR Transient Inadvertent Opening of Two ADS Stage 1 Trains .......... 15.6-77 6.1-8 Nuclear Power Transient Inadvertent Opening of Two ADS Stage 1 Trains ........................................................................................................ 15.6-78 15-xvi Revision 1
Trains ........................................................................................................ 15.6-79 6.1-10 Core Mass Flow Rate Inadvertent Opening of Two ADS Stage 1 Trains ........................................................................................................ 15.6-80 6.3-1 Pressurizer Level for SGTR ...................................................................... 15.6-81 6.3-2 Reactor Coolant System Pressure for SGTR ............................................ 15.6-82 6.3-3 Secondary Pressure for SGTR ................................................................. 15.6-83 6.3-4 Intact Loop Hot and Cold Leg Reactor Coolant System Temperature for SGTR ........................................................................................................ 15.6-84 6.3-5 Primary-to-Secondary Break Flow Rate for SGTR ................................... 15.6-85 6.3-6 Ruptured Steam Generator Water Volume for SGTR ............................... 15.6-86 6.3-7 Ruptured Steam Generator Mass Release Rate to the Atmosphere for SGTR ........................................................................................................ 15.6-87 6.3-8 Intact Steam Generator Mass Release Rate to the Atmosphere for SGTR ........................................................................................................ 15.6-88 6.3-9 Ruptured Loop Chemical and Volume Control System and Core Makeup Tank Injection Flow for SGTR ..................................................... 15.6-89 6.3-10 Integrated Flashed Break Flow for SGTR ................................................. 15.6-90 6.5.4A-1 WCOBRA/TRAC Peak Cladding Temperature for All Five Rod Groups for 95th Percentile Estimator PCT/MLO Case .......................................... 15.6-91 6.5.4A-2 HOTSPOT Cladding Temperature Transient at Limiting Elevation for 95th Percentile Estimator PCT/MLO Case ................................................ 15.6-92 6.5.4A-3 Total Mass Flow at Top of Hot Assembly Channel for 95th Percentile Estimator PCT/MLO Case ......................................................................... 15.6-93 6.5.4A-4 Pressurizer Pressure for 95th Percentile Estimator PCT/MLO Case ........ 15.6-94 6.5.4A-5 Accumulator Injection Flow for 95th Percentile Estimator PCT/MLO Case .......................................................................................................... 15.6-95 6.5.4A-6 Core Makeup Tank Injection Flow for 95th Percentile Estimator PCT/MLO Case ......................................................................................... 15.6-96 6.5.4A-7 Total Mass Flow at Top of Peripheral Assemblies Channel for 95th Percentile Estimator PCT/MLO Case ................................................ 15.6-97 6.5.4A-8 Total Mass Flow at Top of Guide Tube Assemblies Channel for 95th Percentile Estimator PCT/MLO Case ................................................ 15.6-98 6.5.4A-9 Total Mass Flow at Top of Support Column/Open Hole Assemblies Channel for 95th Percentile Estimator PCT/MLO Case ............................ 15.6-99 6.5.4A-10 Break Mass Flow for 95th Percentile Estimator PCT/MLO Case ............ 15.6-100 6.5.4A-11 Core Channel Collapsed Liquid Levels for 95th Percentile Estimator PCT/MLO Case ....................................................................................... 15.6-101 6.5.4A-12 Downcomer Channel Collapsed Liquid Levels for 95th Percentile Estimator PCT/MLO Case ....................................................................... 15.6-102 6.5.4A-13 PBOT/PMID Box Supported by AP1000 ASTRUM Analysis .................. 15.6-103 6.5.4B-1 Inadvertent ADS - RCS Pressure ........................................................... 15.6-104 6.5.4B-2 Inadvertent ADS - Pressurizer Mixture Level ......................................... 15.6-105 6.5.4B-3 Inadvertent ADS - ADS 1-3 Liquid Discharge ........................................ 15.6-106 6.5.4B-4 Inadvertent ADS - ADS 1-3 Vapor Discharge ........................................ 15.6-107 6.5.4B-5 Inadvertent ADS - CMT-1 Injection Rate ................................................ 15.6-108 6.5.4B-6 Inadvertent ADS - CMT-2 Injection Rate ................................................ 15.6-109 6.5.4B-7 Inadvertent ADS - CMT-1 Mixture Level ................................................ 15.6-110 15-xvii Revision 1
6.5.4B-9 Inadvertent ADS - Downcomer Mixture Level ........................................ 15.6-112 6.5.4B-10 Inadvertent ADS - Accumulator-1 Injection Rate .................................... 15.6-113 6.5.4B-11 Inadvertent ADS - Accumulator-2 Injection Rate .................................... 15.6-114 6.5.4B-12 Inadvertent ADS - ADS-4 Integrated Discharge ..................................... 15.6-115 6.5.4B-13 Inadvertent ADS - IRWST-1 Injection Rate ............................................ 15.6-116 6.5.4B-14 Inadvertent ADS - IRWST-2 Injection Rate ............................................ 15.6-117 6.5.4B-15 Inadvertent ADS - RCS System Inventory ............................................. 15.6-118 6.5.4B-16 Inadvertent ADS - Core/Upper Plenum Mixture Level ............................ 15.6-119 6.5.4B-17 2-inch Cold Leg Break - RCS Pressure .................................................. 15.6-120 6.5.4B-18 2-inch Cold Leg Break - Pressurizer Mixture Level ................................ 15.6-121 6.5.4B-19 2-inch Cold Leg Break - CMT-1 Mixture Level ....................................... 15.6-122 6.5.4B-20 2-inch Cold Leg Break - CMT-2 Mixture Level ....................................... 15.6-123 6.5.4B-21 2-inch Cold Leg Break - Downcomer Mixture Level ............................... 15.6-124 6.5.4B-22 2-inch Cold Leg Break - CMT-1 Injection Rate ....................................... 15.6-125 6.5.4B-23 2-inch Cold Leg Break - CMT-2 Injection Rate ....................................... 15.6-126 6.5.4B-24 2-inch Cold Leg Break - Accumulator-1 Injection Rate .......................... 15.6-127 6.5.4B-25 2-inch Cold Leg Break - Accumulator-2 Injection Rate .......................... 15.6-128 6.5.4B-26 2-inch Cold Leg Break - IRWST-1 Injection Rate ................................... 15.6-129 6.5.4B-27 2-inch Cold Leg Break - IRWST-2 Injection Rate ................................... 15.6-130 6.5.4B-28 2-inch Cold Leg Break - ADS-4 Liquid Discharge .................................. 15.6-131 6.5.4B-29 2-inch Cold Leg Break - RCS System Inventory .................................... 15.6-132 6.5.4B-30 2-inch Cold Leg Break - Core/Upper Plenum Mixture Level .................. 15.6-133 6.5.4B-31 2-inch Cold Leg Break - ADS-4 Integrated Discharge ............................ 15.6-134 6.5.4B-32 2-inch Cold Leg Break - Liquid Break Discharge ................................... 15.6-135 6.5.4B-33 2-inch Cold Leg Break - Vapor Break Discharge ................................... 15.6-136 6.5.4B-34 2-inch Cold Leg Break - PRHR Heat Removal Rate .............................. 15.6-137 6.5.4B-35 2-inch Cold Leg Break - Integrated PRHR Heat Removal ..................... 15.6-138 6.5.4B-36 DEDVI - Vessel Side Liquid Break Discharge - 20 psi .......................... 15.6-139 6.5.4B-37 DEDVI - Vessel Side Vapor Break Discharge - 20 psi .......................... 15.6-140 6.5.4B-38 DEDVI - RCS Pressure - 20 psi ............................................................. 15.6-141 6.5.4B-39 DEDVI - Broken CMT Injection Rate - 20 psi ........................................ 15.6-142 6.5.4B-40 DEDVI - Intact CMT Injection Rate - 20 psi ........................................... 15.6-143 6.5.4B-41 DEDVI - Core/Upper Plenum Mixture Level - 20 psi ............................. 15.6-144 6.5.4B-42 DEDVI - Downcomer Mixture Level - 20 psi .......................................... 15.6-145 6.5.4B-43 DEDVI - ADS 1-3 Vapor Discharge - 20 psi .......................................... 15.6-146 6.5.4B-44 DEDVI - Core Exit Void Fraction - 20 psi ............................................... 15.6-147 6.5.4B-45 DEDVI - Core Exit Liquid Flow Rate - 20 psi ......................................... 15.6-148 6.5.4B-46 DEDVI - Core Exit Vapor Flow Rate - 20 psi ......................................... 15.6-149 6.5.4B-47 DEDVI - Lower Plenum to Core Flow Rate - 20 psi ............................... 15.6-150 6.5.4B-48 DEDVI - ADS-4 Liquid Discharge - 20 psi ............................................. 15.6-151 6.5.4B-49 DEDVI - ADS-4 Integrated Discharge - 20 psi ....................................... 15.6-152 6.5.4B-50 DEDVI - Intact Accumulator Flow Rate - 20 psi ..................................... 15.6-153 6.5.4B-51 DEDVI - Intact IRWST Injection Rate - 20 psi ....................................... 15.6-154 6.5.4B-52 DEDVI - Intact CMT Mixture Level - 20 psi ............................................ 15.6-155 6.5.4B-53 DEDVI - RCS System Inventory - 20 psi ............................................... 15.6-156 6.5.4B-54 DEDVI - PRHR Heat Removal Rate - 20 psi ......................................... 15.6-157 6.5.4B-55 DEDVI - Integrated PRHR Heat Removal - 20 psi ................................ 15.6-158 15-xviii Revision 1
6.5.4B-37A DEDVI - Vessel Side Vapor Break Discharge - 14.7 psi ....................... 15.6-160 6.5.4B-38A DEDVI - RCS Pressure - 14.7 psi .......................................................... 15.6-161 6.5.4B-39A DEDVI - Broken CMT Injection Rate - 14.7 psi ..................................... 15.6-162 6.5.4B-40A DEDVI - Intact CMT Injection Rate - 14.7 psi ........................................ 15.6-163 6.5.4B-41A DEDVI - Core/Upper Plenum Mixture Level - 14.7 psi .......................... 15.6-164 6.5.4B-42A DEDVI - Downcomer Mixture Level - 14.7 psi ....................................... 15.6-165 6.5.4B-43A DEDVI - ADS 1-3 Vapor Discharge - 14.7 psi ....................................... 15.6-166 6.5.4B-44A DEDVI - Core Exit Void Fraction - 14.7 psi ............................................ 15.6-167 6.5.4B-45A DEDVI - Core Exit Liquid Flow Rate - 14.7 psi ...................................... 15.6-168 6.5.4B-46A DEDVI - Core Exit Vapor Flow Rate - 14.7 psi ...................................... 15.6-169 6.5.4B-47A DEDVI - Lower Plenum to Core Flow Rate - 14.7 psi ............................ 15.6-170 6.5.4B-48A DEDVI - ADS-4 Liquid Discharge - 14.7 psi .......................................... 15.6-171 6.5.4B-49A DEDVI - ADS-4 Integrated Discharge - 14.7 psi .................................... 15.6-172 6.5.4B-50A DEDVI - Intact Accumulator Flow Rate - 14.7 psi .................................. 15.6-173 6.5.4B-51A DEDVI - Intact IRWST Injection Rate - 14.7 psi .................................... 15.6-174 6.5.4B-52A DEDVI - Intact CMT Mixture Level - 14.7 psi ......................................... 15.6-175 6.5.4B-53A DEDVI - RCS System Inventory - 14.7 psi ............................................ 15.6-176 6.5.4B-54A DEDVI - PRHR Heat Removal Rate - 14.7 psi ...................................... 15.6-177 6.5.4B-55A DEDVI - Integrated PRHR Heat Removal - 14.7 psi ............................. 15.6-178 6.5.4B-56 10-inch Cold Leg Break - RCS Pressure ................................................ 15.6-179 6.5.4B-57 10-inch Cold Leg Break - Pressurizer Mixture Level .............................. 15.6-180 6.5.4B-58 10-inch Cold Leg Break - CMT-1 Mixture Level ..................................... 15.6-181 6.5.4B-59 10-inch Cold Leg Break - CMT-2 Mixture Level ..................................... 15.6-182 6.5.4B-60 10-inch Cold Leg Break - Downcomer Mixture Level ............................. 15.6-183 6.5.4B-61 10-inch Cold Leg Break - CMT-1 Injection Rate ..................................... 15.6-184 6.5.4B-62 10-inch Cold Leg Break - CMT-2 Injection Rate ..................................... 15.6-185 6.5.4B-63 10-inch Cold Leg Break - Accumulator-1 Injection Rate ........................ 15.6-186 6.5.4B-64 10-inch Cold Leg Break - Accumulator-2 Injection Rate ........................ 15.6-187 6.5.4B-65 10-inch Cold Leg Break - IRWST-1 Injection Rate ................................. 15.6-188 6.5.4B-66 10-inch Cold Leg Break - IRWST-2 Injection Rate ................................. 15.6-189 6.5.4B-67 10-inch Cold Leg Break - ADS-4 Liquid Discharge ................................ 15.6-190 6.5.4B-68 10-inch Cold Leg Break - RCS System Inventory .................................. 15.6-191 6.5.4B-69 10-inch Cold Leg Break - Core/Upper Plenum Mixture Level ................ 15.6-192 6.5.4B-70 10-inch Cold Leg Break - Composite Core Mixture Level ...................... 15.6-193 6.5.4B-71 10-inch Cold Leg Break - Core Exit Liquid Flow ..................................... 15.6-194 6.5.4B-72 10-inch Cold Leg Break - Core Exit Vapor Flow ..................................... 15.6-195 6.5.4B-73 10-inch Cold Leg Break - Core Exit Void Fraction .................................. 15.6-196 6.5.4B-74 10-inch Cold Leg Break - ADS-4 Integrated Discharge .......................... 15.6-197 6.5.4B-75 10-inch Cold Leg Break - Liquid Break Discharge ................................. 15.6-198 6.5.4B-76 10-inch Cold Leg Break - Vapor Break Discharge ................................. 15.6-199 6.5.4B-77 10-inch Cold Leg Break - PRHR Heat Removal Rate ............................ 15.6-200 6.5.4B-78 10-inch Cold Leg Break - Integrated PRHR Heat Removal ................... 15.6-201 6.5.4B-79 DEDVI - Downcomer Pressure Comparison .......................................... 15.6-202 6.5.4B-80 DEDVI - Intact IRWST Injection Flow ..................................................... 15.6-203 6.5.4B-81 DEDVI - Intact DVI Line Injection Flow ................................................... 15.6-204 6.5.4B-82 DEDVI - ADS-4 Integrated Liquid Discharge Comparison ..................... 15.6-205 6.5.4B-83 DEDVI - Upper Plenum Mixture Mass Comparison ............................... 15.6-206 15-xix Revision 1
6.5.4B-85 DEDVI - Downcomer Region Mass Comparison .................................... 15.6-208 6.5.4B-86 DEDVI - Core Region Mass Comparison ............................................... 15.6-209 6.5.4B-87 DEDVI - Vessel Mixture Mass Comparison ............................................ 15.6-210 6.5.4B-88 DEDVI - Core/Upper Plenum Mixture Level Comparison ....................... 15.6-211 6.5.4B-89 DEDVI - Core Collapsed Liquid Level Comparison ................................ 15.6-212 6.5.4B-90 DEDVI - Pressurizer Mixture Level Comparison .................................... 15.6-213 6.5.4C-1 Collapsed Level of Liquid in the Downcomer (DEDVI Case) .................. 15.6-214 6.5.4C-2 Collapsed Level of Liquid over the Heated Length of the Fuel (DEDVI Case) ......................................................................................... 15.6-215 6.5.4C-3 Void Fraction in Core Hot Assembly Top Cell (DEDVI Case) ................. 15.6-216 6.5.4C-4 Void Fraction in Core Hot Assembly Second from Top Cell (DEDVI Case) ......................................................................................... 15.6-217 6.5.4C-5 Collapsed Liquid Level in the Hot Leg of Pressurizer Loop (DEDVI Case) ......................................................................................... 15.6-218 6.5.4C-6 Vapor Rate out of the Core (DEDVI Case) ............................................. 15.6-219 6.5.4C-7 Liquid Flow Rate out of the Core (DEDVI Case) ..................................... 15.6-220 6.5.4C-8 Collapsed Liquid Level in the Upper Plenum (DEDVI Case) .................. 15.6-221 6.5.4C-9 Mixture Flow Rate Through ADS Stage 4A Valves (DEDVI Case) ......... 15.6-222 6.5.4C-10 Mixture Flow Rate Through ADS Stage 4B Valves (DEDVI Case) ......... 15.6-223 6.5.4C-11 Upper Plenum Pressure (DEDVI Case) .................................................. 15.6-224 6.5.4C-12 Peak Cladding Temperature (DEDVI Case) ........................................... 15.6-225 6.5.4C-13 DVI-A Mixture Flow Rate (DEDVI Case) ................................................ 15.6-226 6.5.4C-14 DVI-B Mixture Flow Rate (DEDVI Case) ................................................ 15.6-227 6.5.4C-1A Collapsed Level of Liquid in the Downcomer (DEDVI Case) -
14.7 psi .................................................................................................... 15.6-228 6.5.4C-2A Collapsed Level of Liquid over the Heated Length of the Fuel (DEDVI Case) - 14.7 psi ......................................................................... 15.6-229 6.5.4C-3A Void Fraction in Core Hot Assembly Top Cell (DEDVI Case) -
14.7 psi .................................................................................................... 15.6-230 6.5.4C-4A Void Fraction in Core Hot Assembly Second from Top Cell (DEDVI Case) - 14.7 psi ......................................................................... 15.6-231 6.5.4C-5A Collapsed Liquid Level in the Hot Leg of Pressurizer Loop (DEDVI Case) - 14.7 psi ......................................................................... 15.6-232 6.5.4C-6A Vapor Rate out of the Core (DEDVI Case) - 14.7 psi ............................. 15.6-233 6.5.4C-7A Liquid Flow Rate out of the Core (DEDVI Case) - 14.7 psi .................... 15.6-234 6.5.4C-8A Collapsed Liquid Level in the Upper Plenum (DEDVI Case) -
14.7 psi .................................................................................................... 15.6-235 6.5.4C-9A Mixture Flow Rate Through ADS Stage 4A Valves (DEDVI Case) -
14.7 psi .................................................................................................... 15.6-236 6.5.4C-10A Mixture Flow Rate Through ADS Stage 4B Valves (DEDVI Case) -
14.7 psi .................................................................................................... 15.6-237 6.5.4C-11A Upper Plenum Pressure (DEDVI Case) - 14.7 psi ................................. 15.6-238 6.5.4C-12A Peak Cladding Temperature (DEDVI Case) - 14.7 psi ........................... 15.6-239 6.5.4C-13A DVI-A Mixture Flow Rate (DEDVI Case) - 14.7 psi ............................... 15.6-240 6.5.4C-14A DVI-B Mixture Flow Rate (DEDVI Case) - 14.7 psi ............................... 15.6-241 6.5.4C-15 Collapsed Level of Liquid in the Downcomer (Wall-to-Wall Floodup Case) - 14.7 psi ...................................................................................... 15.6-242 15-xx Revision 1
(Wall-to-Wall Floodup Case) - 14.7 psi .................................................. 15.6-243 6.5.4C-17 Void Fraction in Core Hot Assembly Top Cell (Wall-to-Wall Floodup Case) - 14.7 psi ...................................................................................... 15.6-244 6.5.4C-18 Void Fraction in Core Hot Assembly Second from Top Cell (Wall-to-Wall Floodup Case) - 14.7 psi .................................................. 15.6-245 6.5.4C-19 Collapsed Liquid Level in the Hot Leg of Pressurizer Loop (Wall-to-Wall Floodup Case) - 14.7 psi .................................................. 15.6-246 6.5.4C-20 Vapor Rate out of the Core (Wall-to-Wall Floodup Case) - 14.7 psi ...... 15.6-247 6.5.4C-21 Liquid Flow Rate out of the Core (Wall-to-Wall Floodup Case) -
14.7 psi .................................................................................................... 15.6-248 6.5.4C-22 Collapsed Liquid Level in the Upper Plenum (Wall-to-Wall Floodup Case) - 14.7 psi ...................................................................................... 15.6-249 6.5.4C-23 Mixture Flow Rate Through ADS Stage 4A Valves (Wall-to-Wall Floodup Case) - 14.7 psi ........................................................................ 15.6-250 6.5.4C-24 Mixture Flow Rate Through ADS Stage 4B Valves (Wall-to-Wall Floodup Case) - 14.7 psi ........................................................................ 15.6-251 6.5.4C-25 Upper Plenum Pressure (Wall-to-Wall Floodup Case) - 14.7 psi ........... 15.6-252 6.5.4C-26 Hot Rod Cladding Temperature Near Top of Core (Wall-to-Wall Floodup Case) - 14.7 psi ........................................................................ 15.6-253 6.5.4C-27 DVI-A Mixture Flow Rate (Wall-to-Wall Floodup Case) - 14.7 psi .......... 15.6-254 6.5.4C-28 DVI-B Mixture Flow Rate (Wall-to-Wall Floodup Case) - 14.7 psi .......... 15.6-255
-1 Site Plan with Release and Intake Locations ............................................15.A-15 15-xxi Revision 1
ANSI 18.2 (Reference 1) classification divides plant conditions into four categories according to cipated frequency of occurrence and potential radiological consequences to the public. The four gories are as follows:
Condition I: Normal operation and operational transients Condition II: Faults of moderate frequency Condition III: Infrequent faults Condition IV: Limiting faults basic principle applied in relating design requirements to each of the conditions is that the most bable occurrences should yield the least radiological risk, and those extreme situations having the ntial for the greatest risk should be those least likely to occur. Where applicable, reactor trip and ineered safeguards functioning are assumed to the extent allowed by considerations such as the le failure criterion in fulfilling this principle.
0.1.1 Condition I: Normal Operation and Operational Transients dition I occurrences are those that are expected to occur frequently or regularly in the course of er operation, refueling, maintenance, or maneuvering of the plant. As such, Condition I urrences are accommodated with margin between a plant parameter and the value of that ameter requiring either automatic or manual protective action.
ause Condition I events occur frequently, they must be considered from the point of view of their ct on the consequences of fault conditions (Conditions II, III, and IV). In this regard, analysis of h fault condition described is generally based on a conservative set of initial conditions esponding to adverse conditions that can occur during Condition I operation.
pical list of Condition I events follows.
ady-State and Shutdown Operations Table 1.1-1 of Chapter 16.
eration with Permissible Deviations ous deviations that occur during continued operation as permitted by the plant Technical cifications are considered in conjunction with other operational modes. These deviations include following:
Operation with components or systems out of service (such as an inoperable rod cluster control assembly [RCCA])
Leakage from fuel with limited cladding defects Excessive radioactivity in the reactor coolant:
- Fission products
- Corrosion products
- Tritium Operation with steam generator tube leaks Testing 15.0-1 Revision 1
Ramp load changes (up to 5 percent/minute)
Load rejection up to and including design full-load rejection transient 0.1.2 Condition II: Faults of Moderate Frequency se faults, at worst, result in a reactor trip with the plant being capable of returning to operation. By nition, these faults (or events) do not propagate to cause a more serious fault (Condition III or IV nts). In addition, Condition II events are not expected to result in fuel rod failures, reactor coolant em failures, or secondary system overpressurization. The following faults are included in this gory:
Feedwater system malfunctions that result in a decrease in feedwater temperature (see Subsection 15.1.1)
Feedwater system malfunctions that result in an increase in feedwater flow (see Subsection 15.1.2)
Excessive increase in secondary steam flow (see Subsection 15.1.3)
Inadvertent opening of a steam generator relief or safety valve (see Subsection 15.1.4)
Inadvertent operation of the passive residual heat removal heat exchanger (see Subsection 15.1.6)
Loss of external electrical load (see Subsection 15.2.2)
Turbine trip (see Subsection 15.2.3)
Inadvertent closure of main steam isolation valves (see Subsection 15.2.4)
Loss of condenser vacuum and other events resulting in turbine trip (see Subsection 15.2.5)
Loss of ac power to the station auxiliaries (see Subsection 15.2.6)
Loss of normal feedwater flow (see Subsection 15.2.7)
Partial loss of forced reactor coolant flow (see Subsection 15.3.1)
Uncontrolled RCCA bank withdrawal from a subcritical or low-power startup condition (see Subsection 15.4.1)
Uncontrolled RCCA bank withdrawal at power (see Subsection 15.4.2)
RCCA misalignment (dropped full-length assembly, dropped full-length assembly bank, or statically misaligned assembly) (see Subsection 15.4.3)
Startup of an inactive reactor coolant pump at an incorrect temperature (see Subsection 15.4.4)
Chemical and volume control system malfunction that results in a decrease in the boron concentration in the reactor coolant (see Subsection 15.4.6) 15.0-2 Revision 1
Chemical and volume control system malfunction that increased reactor coolant inventory (see Subsection 15.5.2)
Inadvertent opening of a pressurizer safety valve (see Subsection 15.6.1)
Break in instrument line or other lines from the reactor coolant pressure boundary that penetrate containment (see Subsection 15.6.2) 0.1.3 Condition III: Infrequent Faults dition III events are faults that may occur infrequently during the life of the plant. They may result e failure of only a small fraction of the fuel rods. The release of radioactivity is not sufficient to rrupt or restrict public use of those areas beyond the exclusion area boundary, in accordance with guidelines of 10 CFR 50.34. By definition, a Condition III event alone does not generate a dition IV event or result in a consequential loss of function of the reactor coolant system or tainment barriers. The following faults are included in this category:
Steam system piping failure (minor) (see Subsection 15.1.5)
Complete loss of forced reactor coolant flow (see Subsection 15.3.2)
RCCA misalignment (single RCCA withdrawal at full power) (see Subsection 15.4.3)
Inadvertent loading and operation of a fuel assembly in an improper position (see Subsection 15.4.7)
Inadvertent operation of automatic depressurization system (see Subsection 15.6.1)
Loss-of-coolant accidents (LOCAs) resulting from a spectrum of postulated piping breaks within the reactor coolant pressure boundary (small break) (see Subsection 15.6.5)
Gas waste management system leak or failure (see Subsection 15.7.1)
Liquid waste management system leak or failure (see Subsection 15.7.2)
Release of radioactivity to the environment due to a liquid tank failure (see Subsection 15.7.3)
Spent fuel cask drop accidents (see Subsection 15.7.5) 0.1.4 Condition IV: Limiting Faults dition IV events are faults that are not expected to take place, but are postulated because their sequences include the potential of the release of significant amounts of radioactive material. They the faults that must be designed against, and they represent limiting design cases. Condition IV ts are not to cause a fission product release to the environment resulting in doses in excess of the eline values of 10 CFR 50.34. A single Condition IV event is not to cause a consequential loss of uired functions of systems needed to cope with the fault, including those of the emergency core ling system and the containment. The following faults are classified in this category:
15.0-3 Revision 1
Reactor coolant pump shaft seizure (locked rotor) (see Subsection 15.3.3)
Reactor coolant pump shaft break (see Subsection 15.3.4)
Spectrum of RCCA ejection accidents (see Subsection 15.4.8)
Steam generator tube rupture (see Subsection 15.6.3)
LOCAs resulting from a spectrum of postulated piping breaks within the reactor coolant pressure boundary (large break) (see Subsection 15.6.5)
Design basis fuel handling accidents (see Subsection 15.7.4) 0.2 Optimization of Control Systems ntrol system setpoint study is performed prior to plant operation to simulate performance of the ary plant control systems and overall plant performance. In this study, emphasis is placed on the elopment of the overall plant control systems that automatically maintain conditions in the plant in the allowed operating window and with optimum control system response and stability over the re range of anticipated plant operating conditions. The control system setpoints are developed g the nominal protection and safety monitoring system setpoints implemented in the plant. Where ropriate (such as in margin to reactor trip analyses), instrumentation errors are considered and applied in an adverse direction with respect to maintaining system stability and transient ormance. The accident analysis and plant control system setpoint study in combination show that plant can be operated and meet both safety and operability requirements throughout the core life for various levels of power operation.
plant control system setpoint study is comprised of analyses of the following control systems:
t control, axial offset control, rapid power reduction, steam dump (turbine bypass), steam erator level, pressurizer pressure, and pressurizer level.
0.3 Plant Characteristics and Initial Conditions Assumed in the Accident Analyses 0.3.1 Design Plant Conditions le 15.0-1 lists the principal power rating values assumed in the analyses performed. The thermal er output includes the effective thermal power generated by the reactor coolant pumps. Selected 000 loop layout elevations are shown in Figure 15.0.3-2 to aid in interpreting plots shown in other pter 15 subsections.
values of other pertinent plant parameters used in the accident analyses are given in le 15.0-3.
0.3.2 Initial Conditions most accidents that are departure from nucleate boiling (DNB) limited, nominal values of initial ditions are assumed. The allowances on power, temperature, and pressure are determined on a istical basis and are included in the departure from nucleate boiling ratio (DNBR) design limit es (see Section 4.4), as described in WCAP-11397-P-A (Reference 2). This procedure is known he Revised Thermal Design Procedure (RTDP) and is discussed more fully in Section 4.4.
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re power + 2 percent allowance for calorimetric error. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
erage reactor coolant +6.5 or -7.0°F allowance for controller deadband and measurement tem temperature errors ssurizer pressure + 50 psi allowance for steady-state fluctuations and measurement errors al values for core power, average reactor coolant system temperature, and pressurizer pressure selected to minimize the initial DNBR unless otherwise stated in the sections describing the cific accidents. Table 15.0-2 summarizes the initial conditions and computer codes used in the dent analyses.
plant operating instrumentation selected for feedwater flow measurement is a Caldon [Cameron]
M CheckPlus System (Reference 201), which will be calibrated (in a certified laboratory using a ng configuration representative of the plant piping design) prior to installation and will be tested r installation in the plant in accordance with the LEFM CheckPlus commissioning procedure. This cted plant operating instrumentation has documented instrumentation uncertainties to calculate a er calorimetric uncertainty that confirms the 1% uncertainty assumed for the initial reactor power e safety analysis bounds the calculated calorimetric power uncertainty values. The calculated rimetric is done in accordance with a previously accepted Westinghouse methodology ference 202). Administrative controls implement maintenance and contingency activities related e power calorimetric instrumentation.
0.3.3 Power Distribution transient response of the reactor system is dependent on the initial power distribution. The lear design of the reactor core minimizes adverse power distribution through the placement of assemblies and control rods. Power distribution may be characterized by the nuclear enthalpy hot channel factor (FH) and the total peaking factor (Fq). Unless specifically noted otherwise, peaking factors used in the accident analyses are those presented in Chapter 4.
transients that may be DNB limited, the radial peaking factor is important. The radial peaking or increases with decreasing power level due to control rod insertion. This increase in FH is uded in the core limits illustrated in Figure 15.0.3-1. Transients that may be departure from leate boiling limited are assumed to begin with an FH, consistent with the initial power level ned in the Technical Specifications.
axial power shape used in the DNB calculation is a chopped cosine, as discussed in Section 4.4, ransients analyzed at full power and the most limiting power shape calculated or allowed for dents initiated at nonfull power or asymmetric RCCA conditions.
radial and axial power distributions just described are input to the VIPRE-01 code as described ection 4.4.
transients that may be overpower-limited, the total peaking factor (Fq) is important. Transients may be overpower-limited are assumed to begin with plant conditions, including power ributions, which are consistent with reactor operation as defined in the Technical Specifications.
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m flow) and that may reach equilibrium without causing a reactor trip, the fuel rod thermal luations are performed as discussed in Section 4.4.
overpower transients that are fast with respect to the fuel rod thermal time constant (for example, uncontrolled RCCA bank withdrawal from subcritical or lower power startup and RCCA ejection dent, both of which result in a large power rise over a few seconds), a detailed fuel transient heat sfer calculation is performed.
0.4 Reactivity Coefficients Assumed in the Accident Analysis transient response of the reactor system is dependent on reactivity feedback effects, in icular, the moderator temperature coefficient and the Doppler power coefficient. These reactivity fficients are discussed in Subsection 4.3.2.3.
e analysis of certain events, conservatism requires the use of large reactivity coefficient values.
values used are given in Figure 15.0.4-1, which shows the upper and lower bound Doppler er coefficients as a function of power, used in the transient analysis. The justification for use of servatively large versus small reactivity coefficient values is treated on an event-by-event basis.
ome cases, conservative combinations of parameters are used to bound the effects of core life, ough these combinations may not represent possible realistic situations.
0.5 Rod Cluster Control Assembly Insertion Characteristics negative reactivity insertion following a reactor trip is a function of the acceleration of the RCCAs function of time and the variation in rod worth as a function of rod position. For accident lyses, the critical parameter is the time of insertion up to the dashpot entry, or approximately ercent of the rod cluster travel. In analyses where all of the reactor coolant pumps are coasting n prior to, or simultaneous, with RCCA insertion, a time of 2.09 seconds is used for insertion time ashpot entry.
igure 15.0.5-1, the curve labeled complete loss of flow transients shows the RCCA position us time normalized to 2.09 seconds assumed in accident analyses where all reactor coolant ps are coasting down. In analyses where some or all of the reactor coolant pumps are running, RCCA insertion time to dashpot is conservatively taken as 2.47 seconds. The RCCA position us time normalized to 2.47 seconds is also shown in Figure 15.0.5-1.
use of such a long insertion time provides conservative results for accidents and is intended to ly to all types of RCCAs, which may be used throughout plant life. Drop time testing requirements specified in the Technical Specifications.
re 15.0.5-2 shows the fraction of total negative reactivity insertion versus normalized rod position a core where the axial distribution is skewed to the lower region of the core. An axial distribution wed to the lower region of the core can arise from an unbalanced xenon distribution. This curve is d to compute the negative reactivity insertion versus time following a reactor trip, which is input to point kinetics core models used in transient analyses. The bottom-skewed power distribution f is not an input into the point kinetics core model.
re is inherent conservatism in the use of Figure 15.0.5-2 in that it is based on a skewed flux ribution, which would exist relatively infrequently. For cases other than those associated with alanced xenon distributions, significantly more negative reactivity is inserted than that shown in curve, due to the more favorable axial distribution existing prior to trip.
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cifically noted otherwise. This assumption is conservative with respect to the calculated trip tivity worth available as shown in Table 4.3-3.
normalized RCCA negative reactivity insertion versus time curve for an axial power distribution wed to the bottom (Figure 15.0.5-3) is used in those transient analyses for which a point kinetics model is used. Where special analyses require use of three-dimensional or axial one-ensional core models, the negative reactivity insertion resulting from the reactor trip is calculated ctly by the reactor kinetics code and is not separable from the other reactivity feedback effects. In case, the RCCA position versus time of Figure 15.0.5-1 is used as code input.
0.6 Protection and Safety Monitoring System Setpoints and Time Delays to Trip Assumed in Accident Analyses actor trip signal acts to open two trip breaker sets connected in series, feeding power to the trol rod drive mechanisms. The loss of power to the mechanism coils causes the mechanisms to ase the RCCAs, which then fall by gravity into the core. There are various instrumentation delays ociated with each trip function including delays in signal actuation, in opening the trip breakers, in the release of the rods by the mechanisms. The total delay to trip is defined as the time delay the time that trip conditions are reached to the time the rods are free and begin to fall. Limiting setpoints assumed in accident analyses and the time delay assumed for each trip function are n in Table 15.0-4a. Reference is made in that table to overtemperature and overpower T trip wn in Figure 15.0.3-1.
le 15.0-4a also summarizes the setpoints and the instrumentation delay for engineered safety ures (ESF) functions used in accident analyses. Time delays associated with equipment actuated h as valve stroke times) by ESF functions are summarized in Table 15.0-4b.
difference between the limiting setpoint assumed for the analysis and the nominal setpoint esents an allowance for instrumentation channel error and setpoint error. Nominal setpoints are cified in the plant Technical Specifications. During plant startup tests, it is demonstrated that al instrument time delays are equal to or less than the assumed values. Additionally, protection em channels are calibrated and instrument response times are determined periodically in ordance with the plant Technical Specifications.
0.7 Instrumentation Drift and Calorimetric Errors, Power Range Neutron Flux mples of the instrumentation uncertainties and calorimetric uncertainties used in establishing the er range high neutron flux setpoint are presented in Table 15.0-5.
calorimetric uncertainty is the uncertainty assumed in the determination of core thermal power as ined from secondary plant measurements. The total ion chamber current (sum of the top and om sections) is calibrated (set equal) to this measured power on a daily basis.
secondary power is obtained from measurement of feedwater flow, feedwater inlet temperature e steam generators, and steam pressure. Installed plant instrumentation is used for these surements.
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tulated environmental conditions, and dynamic effects of the postulated accidents. In addition, the ign incorporates features that minimize the probability and effects of fires and explosions.
pter 17 discusses the quality assurance program that is implemented to provide confidence that plant systems satisfactorily perform their assigned safety functions. The incorporation of these ures in the plant, coupled with the reliability of the design, provides confidence that the normally rating systems and components listed in Table 15.0-6 are available for mitigation of the events ussed in Chapter 15.
etermining which systems are necessary to mitigate the effects of these postulated events, the sification system of ANSI N18.2-1973 (Reference 1) is used. The design of safety-related ems (including protection systems) is consistent with IEEE Standard 379-2000 and Regulatory de 1.53 in the application of the single-failure criterion. Conformance to Regulatory Guide 1.53 is marized in Subsection 1.9.1.
le 15.0-8 summarizes the nonsafety-related systems assumed in the analyses to mitigate the sequences of events. Except for the cases listed in Table 15.0-8, control system action is not d for mitigation of accidents.
0.9 Fission Product Inventories sources of radioactivity for release are dependent on the specific accident. Activity may be ased from the primary coolant, from the secondary coolant, and from the reactor core if the dent involves fuel damage. The radiological consequences analyses use the conservative design is source terms identified in Appendix 15A.
0.10 Residual Decay Heat 0.10.1 Total Residual Heat idual heat in a subcritical core is calculated for the LOCA according to the requirements of CFR 50.46, as described in WCAP-10054-P-A and WCAP-12945-P (References 3 and 4). The e-break LOCA methodology considers uncertainty in the decay power level. The small-break A events and post-LOCA long-term cooling analyses use 10 CFR 50, Appendix K, decay heat, ch assumes infinite irradiation time before the core goes subcritical to determine fission product ay energy. For all other accidents, the same models are used, except that fission product decay rgy is based on core average exposure at the end of an equilibrium cycle.
0.10.2 Distribution of Decay Heat Following a Loss-of-Coolant Accident ing a LOCA, the core is rapidly shut down by void formation, RCCA insertion, or both, and a large tion of the heat generation considered comes from fission product decay gamma rays. This heat ot distributed in the same manner as steady-state fission power. Local peaking effects, which are ortant for the neutron-dependent part of the heat generation, do not apply to the gamma ray tribution. The steady-state factor, which represents the fraction of heat generated within the ding and pellet, drops to 95 percent or less for the hot rod in a LOCA.
example, consider the transient resulting from the postulated double-ended break of the largest tor coolant system pipe; one-half second after the rupture, about 30 percent of the heat erated in the fuel rods is from gamma ray absorption. The gamma power shape is less peaked the steady-state fission power shape, reducing the energy deposited in the hot rod at the 15.0-8 Revision 1
rods; the remaining 2 percent is absorbed by water, thimbles, sleeves, and grids. Combining the rcent total heat reduction from gamma redistribution with this 2 percent absorption produce as net effect a factor of 0.95, which exceeds the actual heat production in the hot rod. The actual hot heat generation is computed during the AP1000 large-break LOCA transient as a function of core conditions.
0.11 Computer Codes Used maries of some of the principal computer codes used in transient analyses are given as follows.
er codes - in particular, specialized codes in which the modeling has been developed to simulate given accident, such as those used in the analysis of the reactor coolant system pipe rupture Subsection 15.6.5) - are summarized in their respective accident analyses sections. The codes d in the analyses of each transient are listed in Table 15.0-2. WCAP-15644 (Reference 11) ides the basis for use of analysis codes.
0.11.1 FACTRAN Computer Code TRAN (Reference 5) calculates the transient temperature distribution in a cross section of a al-clad UO2 fuel rod and the transient heat flux at the surface of the cladding using as input the lear power and the time-dependent coolant parameters (pressure, flow, temperature, and sity). The code uses a fuel model which simultaneously exhibits the following features:
A sufficiently large number of radial space increments to handle fast transients Material properties which are functions of temperature and a sophisticated fuel-to-clad gap heat transfer calculation The necessary calculations to handle post-DNB transients: film boiling heat transfer correlations, zircaloy-water reaction, and partial melting of the materials TRAN is further discussed in WCAP-7908-A (Reference 5).
0.11.2 LOFTRAN Computer Code LOFTRAN (Reference 6) program is used for studies of transient response of a pressurized er reactor system to specified perturbations in process parameters. LOFTRAN simulates a tiloop system by a model containing reactor vessel, hot and cold leg piping, steam generator e and shell sides), and pressurizer. The pressurizer heaters, spray, and safety valves are also sidered in the program. Point model neutron kinetics, and reactivity effects of the moderator, fuel, on, and rods are included. The secondary side of the steam generator uses a homogeneous, rated mixture for the thermal transients and a water level correlation for indication and control.
protection and safety monitoring system is simulated to include reactor trips on high neutron flux, rtemperature T, high and low pressure, low flow, and high pressurizer level. Control systems are simulated, including rod control, steam dump, feedwater control, and pressurizer level and sure control. The emergency core cooling system, including the accumulators, is also modeled.
TRAN is a versatile program suited to both accident evaluation and control studies as well as ameter sizing.
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LOFTRAN code is modified to allow the simulation of the passive residual heat removal (PRHR) t exchanger, core makeup tanks, and associated protection and safety monitoring system ation logic. A discussion of these models and additional validation is presented in WCAP-14234 ference 10).
TTR2 (Reference 8) is a modified version of LOFTRAN with a more realistic break flow model, a
-region steam generator secondary side, and an improved capability to simulate operator actions ng a steam generator tube rupture (SGTR) event.
LOFTTR2 code is modified to allow the simulation of the PRHR heat exchanger, core makeup s, and associated protection system actuation logic. The modifications are identical to those e to the LOFTRAN code. A discussion of these models is presented in WCAP-14234 ference 10).
0.11.3 TWINKLE Computer Code TWINKLE (Reference 7) program is a multidimensional spatial neutron kinetics code, which is erned after steady-state codes currently used for reactor core design. The code uses an implicit e-difference method to solve the two-group transient neutron diffusion equations in one, two, and e dimensions. The code uses six delayed neutron groups and contains a detailed multiregion
-clad-coolant heat transfer model for calculating pointwise Doppler and moderator feedback cts. The code handles up to 2000 spatial points and performs its own steady-state initialization.
e from basic cross-section data and thermal-hydraulic parameters, the code accepts as input ic driving functions, such as inlet temperature, pressure, flow, boron concentration, control rod ion, and others. Various edits are provided (for example, channelwise power, axial offset, alpy, volumetric surge, point-wise power, and fuel temperatures).
TWINKLE code is used to predict the kinetic behavior of a reactor for transients that cause a or perturbation in the spatial neutron flux distribution.
0.11.4 VIPRE-01 Computer Code VIPRE-01 code is described in Subsection 4.4.4.5.2.
0.11.5 COAST Computer Program COAST computer program is used to calculate the reactor coolant flow coastdown transient for combination of active and inactive pumps and forward or reverse flow in the hot or cold legs. The gram is described in Reference 13 and was referenced in Reference 12. The program was roved in Reference 14.
equations of conservation of momentum are written for each of the flow paths of the COAST el assuming unsteady one-dimensional flow of an incompressible fluid. The equation of servation of mass is written for the appropriate nodal points. Pressure losses due to friction, and metric losses are assumed proportional to the flow velocity squared. Pump dynamics are eled using a head-flow curve for a pump at full speed and using four-quadrant curves, which are ametric diagrams of pump head and torque on coordinates of speed versus flow, for a pump at r than full speed.
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ensions. ANC can also solve the three-dimensional kinetics equations for six delayed neutron ups.
0.12 Component Failures 0.12.1 Active Failures Y-77-439 (Reference 9) provides a description of active failures. An active failure results in the ility of a component to perform its intended function.
active failure is defined differently for different components. For valves, an active failure is the re of a component to mechanically complete the movement required to perform its function. This udes the failure of a remotely operated valve to change position on demand. The spurious, tended movement of the valve is also considered as an active failure. Failure of a manual valve hange position under local operator action is included.
ng-loaded safety or relief valves that are designed for and operate under single-phase fluid ditions are not considered for active failures to close when pressure is reduced below the valve point. However, when valves designed for single-phase flow are challenged with two-phase flow, h as a steam generator or pressurizer safety valve, the failure to reseat is considered as an active re.
other active equipment - such as pumps, fans, and rotating mechanical components - an active re is the failure of the component to start or to remain operating.
electrical equipment, the loss of power, such as the loss of offsite power or the loss of a diesel erator, is considered as a single failure. In addition, the failure to generate an actuation signal, er for a single component actuation or for a system-level actuation, is also considered as an ve failure.
rious actuation of an active component is considered as an active failure for active components in ty-related passive systems. An exception is made for active components if specific design ures or operating restrictions are provided that can preclude such failures (such as power out, confirmatory open signals, or continuous position alarms).
ngle incorrect or omitted operator action in response to an initiating event is also considered as ctive failure; the error is limited to manipulation of safety-related equipment and does not include ght-process errors or similar errors that could potentially lead to common cause or multiple rs.
0.12.2 Passive Failures Y-77-439 also provides a description of passive failures. A passive failure is the structural failure static component that limits the effectiveness of the component in carrying out its design tion. A passive failure is applied to fluid systems and consists of a breach in the fluid system ndary. Examples include cracking of pipes, sprung flanges, or valve packing leaks.
sive failures are not assumed to occur until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the start of the event. Consequential cts of a pipe leak - such as flooding, jet impingement, and failure of a valve with a packing leak -
t be considered.
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0.12.3 Limiting Single Failures most limiting single active failure (where one exists), as described in Section 3.1, of safety-ted equipment, is identified in each analysis description. The consequences of this failure are cribed therein. In some instances, because of redundancy in protection equipment, no single re that could adversely affect the consequences of the transient is identified. The failure umed in each analysis is listed in Table 15.0-7.
0.13 Operator Actions events where the PRHR heat exchanger is actuated, the plant automatically cools down to a
, stable shutdown condition. Where a stabilized condition is reached automatically following a tor trip, it is expected that the operator may, following event recognition, take manual control and eed with orderly shutdown of the reactor in accordance with the normal, abnormal, or emergency rating procedures. The exact actions taken and the time at which these actions occur depend on t systems are available and the plans for further plant operation.
ever, for these events, operator actions are not required to maintain the plant in a safe and stable dition for at least 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Operator actions typical of normal operation are credited for the vertent actuations of equipment in response to a Condition II event.
0.14 Loss of Offsite ac Power equired in GDC 17 of 10 CFR Part 50, Appendix A, anticipated operational occurrences and tulated accidents are analyzed assuming a loss of offsite ac power. The loss of offsite power is considered as a single failure, and the analysis is performed without changing the event category.
e analyses, the loss of offsite ac power is considered to be a potential consequence of the event.
ss of offsite ac power will be considered a consequence of an event due to disruption of the grid wing a turbine trip during the event. Event analyses that do not result in a possible consequential uption of offsite ac power do not assume offsite power is lost.
those events where offsite ac power is lost, an appropriate time delay between turbine trip and postulated loss of offsite ac power is assumed in the analyses. A time delay of 3 seconds is used.
time delay is based on the inherent stability of the offsite power grid as discussed in Section 8.2.
owing the time delay, the effect of the loss of offsite ac power on plant auxiliary equipment - such eactor coolant pumps, main feedwater pumps, condenser, startup feedwater pumps, and CAs - is considered in the analyses. Turbine trip occurs 5 seconds following a reactor trip dition being reached. This delay is part of the AP1000 reactor trip system.
ign basis LOCA analyses are governed by the GDC-17 requirement to consider the loss of offsite er. For the AP1000 design, in which all the safety-related systems are passive, the availability of te power is significant only regarding reactor coolant pump operation for LOCA events. A sitivity study for AP1000 has shown that for large-break LOCAs, assuming the loss of offsite er coincident with the inception of the LOCA event is nonlimiting relative to assuming continued tor coolant pump operation until the automatic reactor coolant pump trip occurs following an signal less than 10 seconds into the transient. For small-break LOCA events, the AP1000 matic reactor coolant pump trip feature prevents continued operation of the reactor coolant ps from mixing the liquid and vapor present within a two-phase reactor coolant system inventory crease the liquid break flow and deplete the reactor coolant system mass inventory rapidly. The 15.0-12 Revision 1
occurring either at time zero or as a result of the S signal. Whether a loss of offsite power is tulated at the inception of the LOCA event or occurs automatically later on is unimportant in the section 15.6.5.4C long-term cooling analyses because with either assumption, the reactor lant pumps are tripped long before the long-term cooling timeframe.
AP1000 protection and safety monitoring system and passive safeguards systems are not endent on offsite power or on any backup diesel generators. Following a loss of ac power, the ection and safety monitoring system and passive safeguards are able to perform the safety tions and there are no additional time delays for these functions to be completed.
0.15 Combined License Information 0.15.1 Following selection of the actual plant operating instrumentation, calculation of the primary power calorimetric uncertainty is addressed in Subsection 15.0.3.2.
0.16 References American National Standards Institute N18.2, Nuclear Safety Criteria for the Design of Stationary PWR Plants, 1973.
Friedland, A. J., and Ray, S., Revised Thermal Design Procedure, WCAP-11397-P-A (Proprietary) and WCAP-11397-A (Non-Proprietary), April 1989.
Lee, N., Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code, WCAP-10054-P-A (Proprietary) and WCAP-10081 (Non-Proprietary), August 1985.
Bajorek, S. M., et al., Code Qualification Document for Best-Estimate LOCA Analysis, WCAP-12945-P-A, Volume 1, Revision 2, and Volumes 2 through 5, Revision 1, (Proprietary) and WCAP-14747 (Non-Proprietary), 1998.
Hargrove, H. G., FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908-A, December 1989.
Burnett, T. W. T., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Non-Proprietary), April 1984.
Risher, D. H., Jr., and Barry, R. F., TWINKLE - A Multi-Dimensional Neutron Kinetics Computer Code, WCAP-7979-P-A (Proprietary) and WCAP-8028-A (Non-Proprietary),
January 1975.
Lewis, R. N., SGTR Analysis Methodology to Determine the Margin to Steam Generator Overfill, WCAP-10698-P-A (Proprietary) and WCAP-10750-A (Non-Proprietary), August 1987.
Case, E. G., Single Failure Criterion, SECY-77-439, August 17, 1977.
Bachrach, U., Carlin, E. L., LOFTRAN and LOFTTR2 AP600 Code Applicability Document, WCAP-14234, Revision 1 (Proprietary) and WCAP-14235, Revision 1 (Non-Proprietary), August 1997.
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Combustion Engineering Standard Safety Analysis Report, CESSAR Docket No. STN-50-470, December 1975.
COAST Code Description, CENPD-98-A, April 1973, Proprietary Information.
CENPD-98-A, COAST Code Description, April 1973 (NRC Approval Letter dated December 4, 1974).
. Final Safety Evaluation for Cameron Measurement Systems Engineering Report ER-157P, Revision 8, Caldon Ultrasonics Engineering Report ER-157P, Supplement to Topical Report ER-80P: Basis for a Power Uprate with the LEFM Check or CheckplusTM System, (TAC No. ME1321). August 16, 2010. ADAMS Accession No. ML102160694.
. Final Safety Evaluation for Beaver Valley Power Station, Unit Nos. 1 and 2 (BVPS-1 and 2) -
Issuance of Amendment re: 1.4-Percent Power Uprate and Revised BVPS-2 Heatup and Cooldown Curves. September 24, 2001, ADAMS Accession No. ML012490569.
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ermal power output (MWt) 3415 ective thermal power generated by the reactor coolant pumps (MWt) 15 re thermal power (MWt) 3400 15.0-15 Revision 1
Summary of Initial Conditions and Computer Codes Used Reactivity Coefficients Assumed Computer Moderator Moderator Initial Thermal Codes Density Temperature Power Output ction Faults Used (k/gm/cm3) (pcm/°F) Doppler Assumed (MWt) 5.1 Increase in heat removal from the primary system Feedwater system malfunctions Bounded by excessive - - - -
causing a reduction in feedwater increase in secondary temperature steam flow Feedwater system malfunctions LOFTRAN, 0.470 - Upper curve of 0 and 3415 that result in an increase in FACTRAN, Figure 15.0.4-1 feedwater flow VIPRE-01 Excessive increase in secondary LOFTRAN, 0.0 and 0.470 - Upper and lower 3415 steam flow FACTRAN, curves of VIPRE-01 Figure 15.0.4-1 Inadvertent opening of a steam LOFTRAN, Function of - See 0 (subcritical) generator relief or safety valve VIPRE-01 moderator density Subsection 15.1.4.
(see Figure 15.1.4-1)
Steam system piping failure LOFTRAN, Function of - See 0 (subcritical)
VIPRE-01 moderator density Subsection 15.1.5 (see Figure 15.1.4-1)
Inadvertent operation of the N/A N/A - N/A 3415 PRHR heat exchanger 15.0-16 Revision 1
Reactivity Coefficients Assumed Computer Moderator Moderator Initial Thermal Codes Density Temperature Power Output ction Faults Used (k/gm/cm3) (pcm/°F) Doppler Assumed (MWt) 5.2 Decrease in heat removal by the secondary system Loss of external electrical load LOFTRAN, 0.0 and 0.470 - Lower and upper 3415 and and/or turbine trip FACTRAN, curves of 3483.3 (a)
VIPRE-01 Figure 15.0.4-1 Inadvertent closure of main steam Bounded by turbine - - - -
isolation valves trip event Loss of condenser vacuum and Bounded by turbine - - - -
other events resulting in turbine trip event trip Loss of nonemergency ac power LOFTRAN 0.0 - Lower curve of 3483.3 (a) to the plant auxiliaries Figure 15.0.4-1 Loss of normal feedwater flow LOFTRAN 0.0 - Lower curve of 3483.3 (a)
Figure 15.0.4-1 Feedwater system pipe break LOFTRAN 0.0 - Lower curve of 3483.3 (a)
Figure 15.0.4-1 5.3 Decrease in reactor coolant system flow rate Partial and complete loss of LOFTRAN, 0.0 - Lower curve of 3415 forced reactor coolant flow FACTRAN, COAST, Figure 15.0.4-1 VIPRE-01 Reactor coolant pump shaft LOFTRAN, 0.0 - Lower curve of 3483.3 (a) seizure (locked rotor) and reactor FACTRAN, COAST, Figure 15.0.4-1 coolant pump shaft break VIPRE-01 15.0-17 Revision 1
Reactivity Coefficients Assumed Computer Moderator Moderator Initial Thermal Codes Density Temperature Power Output ction Faults Used (k/gm/cm3) (pcm/°F) Doppler Assumed (MWt) 5.4 Reactivity and power distribution anomalies Uncontrolled RCCA bank TWINKLE, FACTRAN, - 0.0 Coefficient is 0 withdrawal from a subcritical or VIPRE-01 consistent with a low power startup condition Doppler defect of
-0.67%k Uncontrolled RCCA bank LOFTRAN, 0.0 and 0.470 - Upper and lower 10%, 60%, and withdrawal at power FACTRAN, curves of 100% of 3415 VIPRE-01 Figure 15.0.4-1 RCCA misalignment LOFTRAN, NA - NA 3415 VIPRE-01 Startup of an inactive reactor NA NA - NA NA coolant pump at an incorrect temperature Chemical and volume control NA NA - NA 0 and 3415 system malfunction that results in a decrease in the boron concentration in the reactor coolant Inadvertent loading and operation ANC NA - NA 3415 of a fuel assembly in an improper position Spectrum of RCCA ejection ANC, VIPRE Refer to Refer to Refer to Refer to accidents Subsection 15.4.8 Subsection 15.4.8 Subsection 15.4.8 Subsection 15.4.8 15.0-18 Revision 1
Reactivity Coefficients Assumed Computer Moderator Moderator Initial Thermal Codes Density Temperature Power Output ction Faults Used (k/gm/cm3) (pcm/°F) Doppler Assumed (MWt) 5.5 Increase in reactor coolant inventory Inadvertent operation of the LOFTRAN 0.0 - Upper curve of 3483.3 (a) emergency core cooling system Figure 15.0.4-1 during power operation Chemical and volume control LOFTRAN 0.0 - Upper curve of 3483.3 (a) system malfunction that increases Figure 15.0.4-1 reactor coolant inventory 5.6 Decrease in reactor coolant inventory Inadvertent opening of a LOFTRAN, 0.0 - Lower curve of 3415 pressurizer safety valve and FACTRAN, Figure 15.0.4-1 inadvertent operation of ADS VIPRE-01 Steam generator tube failure LOFTTR2 0.0 - Lower curve of 3483.3 (a)
Figure 15.0.4-1 A break in an instrument line or NA NA - NA NA other lines from the reactor coolant pressure boundary that penetrate containment LOCAs resulting from the NOTRUMP See Subsection 15.6.5 - See Subsection 15.6.5 3468.0 (SBLOCA) spectrum of postulated piping WCOBRA/ references references 3434.0 (LBLOCA) breaks within the reactor coolant TRAC pressure boundary HOTSPOT s:
102% of rated thermal power - The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
BOC - Beginning of core cycle EOC - End of core cycle 15.0-19 Revision 1
Parameters Used in Accident Analyses Without RTDP(a)
RTDP With 10% Without Steam With 10% Steam Steam Generator Generator Tube Generator Tube Tube Plugging Plugging Plugging ermal output of NSSS (MWt) 3415 3415 3415 re inlet temperature (°F) 535.8 535.5 535.0 ssel average temperature (°F) 573.6 573.6 573.6 actor coolant system 2250.0 2250.0 2250.0 ssure (psia) actor coolant flow per loop (gpm) 15.08 E+04 14.99 E+04 14.8 E+04 am flow from NSSS (lbm/hr) 14.96 E+06 14.96 E+06 14.95 E+06 am pressure at steam generator 802.2 814.0 796.0 let (psia) sumed feedwater temperature at 440.0 440.0 440.0 am generator inlet (°F) erage core heat flux (Btu/-hr-ft2) 1.99 E+05 1.99 E+05 1.99 E+05 Steady-state errors discussed in Subsection 15.0.3 are added to these values to obtain initial conditions for most transient analyses.
15.0-20 Revision 1
Setpoints and Time Delay Assumed in Accident Analyses Limiting Setpoint Time Delays Function Assumed in Analyses (seconds) ctor trip on power range high neutron flux, 118% 0.9 h setting ctor trip on power range high neutron flux, 35% 0.9 setting ctor trip on source range neutron flux Not applicable 0.9 ctor trip rtemperature T Variable (see Figure 15.0.3-1) 2.0 rpower T Variable (see Figure 15.0.3-1) 2.0 ctor trip on high pressurizer pressure 2460 psia 2.0 ctor trip on low pressurizer pressure 1800 psia 2.0 ctor trip on low reactor coolant flow in either 87% loop flow 1.45 leg ctor trip on reactor coolant pump under 90% 0.767 ed ctor trip on low steam generator narrow 95,000 lbm 2.0 ge level h steam generator narrow range level 85% of narrow range level span 2.0 (startup feedwater cident with reactor trip (P-4) isolation) 2.0 (chemical and volume control system makeup isolation) h-2 steam generator level 95% of 2.0 (reactor trip) narrow range level span 0.0 (turbine trip) 2.0 (feedwater isolation) ctor trip on high-3 pressurizer water level 76% of span 2.0 HR actuation on low steam generator wide 55,000 lbm 2.0 ge level signal and steam line isolation on low Tcold 500°F 2.0 15.0-21 Revision 1
Limiting Setpoint Time Delays Function Assumed in Analyses (seconds) signal and steam line isolation on low steam 405 psia (with an adverse 2.0 pressure environment assumed) 535 psia (without an adverse environment assumed) signal on low pressurizer pressure 1700 psia 2.0 ctor trip on PRHR discharge valves not Valve not closed 1.25 ed signal on high-2 containment pressure 8 psig 2.0 2.2 (LBLOCA) ctor coolant pump trip following S - 15.0 4.0 (LBLOCA)
HR actuation of high-3 pressurizer water 76% of span 2.0 l (plus 15.0-second timer delay) mical and volume control system isolation 63% of span 2.0 high-2 pressurizer water level mical and volume control system isolation 28% of span 2.0 high-1 pressurizer water level coincident with signal on dilution block on source range flux 3 over 50 minutes 80.0 bling S Stage 1 actuation on core makeup tank 67.5% of tank volume 32.0 seconds for control level signal(1) valve to begin to open S Stage 4 actuation on core makeup tank 20% of tank volume 2.0 seconds for squib
-low level signal(1) valve to begin to open T actuation on pressurizer low-2 water level 0% of span 2.0 e:
The delay times reflect the design basis of the AP1000. The applicable Chapter 15 accidents were evaluated for the design basis delay times. The results of this evaluation have shown that there is a small impact on the analysis and the conclusions remain valid. The output provided for the analyses is representative of the transient phenomenon.
15.0-22 Revision 1
Equipment Assumed in Accident Analyses Time Delays Component (seconds) dwater isolation valve closure, feedwater control valve 10 (maximum value for non-LOCA) ure, or feedwater pump trip 5 (maximum value for mass/energy) am line isolation valve closure 5 e makeup tank discharge valve opening time 15 (maximum) 10 (nominal value for best-estimate LOCA) mical and volume control system isolation valve closure(1) 30 HR discharge valve opening time 15 (maximum) 10 (nominal value for best-estimate LOCA) 1.0 second (small-break LOCA value: follows a 15-second interval of no valve movement) mineralized water transfer and storage system isolation valve 20 ure time am generator power-operated relief valve block valve closure 44 (1) See Table 15.6.5-10.
omatic depressurization system (ADS) valve opening times e:
The valve stroke times reflect the design basis of the AP1000. The applicable Chapter 15 accidents were evaluated for the design basis valve stroke times. The results of this evaluation have shown that there is a small impact on the analysis and the conclusions remain valid. The output provided for the analyses is representative of the transient phenomenon.
15.0-23 Revision 1
Neutron Flux Channel Trip Setpoint, Based on Nominal Setpoint and Inherent Typical Instrumentation Uncertainties minal setpoint (% of rated power) 109 lorimetric errors in the measurement of secondary system thermal power:
Effect on Accuracy of Thermal Power Measurement Determination Variable of Variable (% of Rated Power) edwater temperature +3°F eam pressure (small correction on enthalpy) +6 psi edwater flow +0.5% P instrument span (two channels per steam generator) sumed calorimetric error 2.0 (a)*
The main feedwater flow measurement supports a 1% power uncertainty; use of a 2% power uncertainty is conservative.
dial power distribution effects on total ion chamber 7.8 (b)*
rrent owed mismatch between power range neutron flux 2.0 (c)*
annel and calorimetric measurement trumentation channel drift and setpoint reproducibility 0.4% of instrument span 0.84(d)*
(120% power span) trumentation channel temperature effects 0.48(e)*
otal assumed error in setpoint +8.4
% of rated power): [(a)2 + (b)2 + (c)2 + (d)2 + (e)2]1/2 ximum power range neutron flux trip setpoint 118 suming a statistical combination of individual certainties (% of rated power) 15.0-24 Revision 1
Available for Transient and Accident Conditions Reactor ESF Trip Actuation ESF and Incident Functions Functions Other Equipment tion 15.1 ease in heat removal m the primary system dwater system High-2 Steam Generator High-2 steam generator Feedwater isolation functions that result in an Level, Power range high flux, level produced feedwater valves ease in feedwater flow overtemperature isolation and turbine trip essive increase in Power range high flux, - -
ondary steam flow overtemperature T, overpower T, manual dvertent opening of a Power range high flux, Low pressurizer pressure, Core makeup tank, am generator safety valve overtemperature T, low compensated steam feedwater isolation overpower T, Low line pressure, low Tcold, valves, main steam pressurizer pressure, S, low-2 pressurizer level isolation valves (MSIVs),
manual startup feedwater isolation, accumulators am system piping failure Power range high flux, Low pressurizer pressure, Core makeup tank, overtemperature T, low compensated steam feedwater isolation overpower T, Low line pressure, high-2 valves, main steam line pressurizer pressure, S, containment pressure, isolation valves (MSIVs),
manual low Tcold, manual accumulators, startup feedwater isolation dvertent operation of the PRHR discharge valve Low pressurizer pressure, Core makeup tank HR position low Tcold, low-2 pressurizer level 15.0-25 Revision 1
Reactor ESF Trip Actuation ESF and Incident Functions Functions Other Equipment tion 15.2 rease in heat removal by secondary system s of external load/turbine High pressurizer pressure, - Pressurizer safety high pressurizer water level, valves, steam generator overtemperature T, safety valves overpower T, Steam generator low narrow range level, low RCP speed, manual s of nonemergency Steam generator low narrow Steam generator low PRHR, steam generator power to the station range level, high pressurizer narrow range level safety valves, iliaries pressure, high pressurizer coincident with low pressurizer safety valves level, manual startup water flow, steam generator low wide range level s of normal feedwater Steam generator low narrow Steam generator low PRHR, steam generator range level, high pressurizer narrow range level safety valves, pressure, high pressurizer coincident with low pressurizer safety valves level, manual startup water flow, steam generator low wide range level dwater system pipe Steam generator low narrow Steam generator low PRHR, core makeup ak range level, high pressurizer narrow range level tank, MSIVs, feedline pressure, high pressurizer coincident with low isolation, pressurizer level, manual startup feedwater flow, safety valves, steam Steam generator low wide generator safety valves range level, low steam line pressure, high-2 containment pressure tion 15.3 rease in reactor coolant tem flow rate tial and complete loss of Low flow, underspeed, - Steam generator safety ed reactor coolant flow manual valves, pressurizer safety valves actor coolant pump shaft Low flow, high pressurizer - Pressurizer safety ure (locked rotor) pressure, manual valves, steam generator safety valves 15.0-26 Revision 1
Reactor ESF Trip Actuation ESF and Incident Functions Functions Other Equipment tion 15.4 activity and power ribution anomalies ontrolled RCCA bank Source range high neutron - -
drawal from a subcritical flux, intermediate range high ow power startup neutron flux, power range dition high neutron flux (low setting), power range high neutron flux (high setting),
high nuclear flux rate, manual ontrolled RCCA bank Power range high neutron - Pressurizer safety drawal at power flux, high power range valves, steam generator positive neutron flux rate, safety valves overtemperature T, over-power T, high pressurizer pressure, high pressurizer water level, manual CA misalignment Overtemperature T, manual - -
rtup of an inactive reactor Power range high flux, low - -
lant pump at an incorrect flow (P-10 interlock), manual perature emical and volume control Source range high flux, Source range flux CVS to RCS isolation tem malfunction that power range high flux, doubling valves, makeup pump ults in a decrease in overtemperature T, manual suction isolation valves, on concentration in the from the demineralized ctor coolant water transfer and storage system ctrum of RCCA ejection Power range high flux, high - Pressurizer safety valves idents positive flux rate, manual tion 15.5 ease in reactor coolant entory dvertent operation of the High pressurizer pressure, High pressurizer level, Core makeup tank, T during power operation manual, safeguards trip, low Tcold pressurizer safety high pressurizer level valves, chemical and volume control system isolation, PRHR, steam generator safety valves emical and volume control High pressurizer pressure, High pressurizer level, Core makeup tank, tem malfunction that safeguards trip, high low Tcold, low steam line pressurizer safety eases reactor coolant pressurizer level, manual pressure valves, chemical and entory volume control system isolation, PRHR 15.0-27 Revision 1
Reactor ESF Trip Actuation ESF and Incident Functions Functions Other Equipment tion 15.6 rease in reactor coolant entory dvertent opening of a Low pressurizer pressure, Low pressurizer pressure Core makeup tank, ADS, ssurizer safety valve or overtemperature T, manual accumulator S path ure of small lines carrying - Manual isolation of the Sample System isolation ary coolant outside Sample System or CVS valves, Chemical and tainment discharge lines volume control system discharge line isolation valves am generator tube Low pressurizer pressure, Low pressurizer pressure, Core makeup tank, ture overtemperature T, high-2 steam generator PRHR, steam generator safeguards (S), manual water level, high steam safety and/or relief generator level coincident valves, MSIVs, radiation with reactor trip (P-4), low monitors (air removal, steam line pressure, low steam line, and steam pressurizer level generator blowdown),
startup feedwater isolation, chemical and volume control system pump isolation, pressurizer heater isolation, steam generator power-operated relief valve isolation CAs resulting from the Low pressurizer pressure, High-2 containment Core makeup tank, ctrum of postulated safeguards (S), manual pressure, low pressurizer accumulator, ADS, ng breaks within the pressure steam generator safety ctor coolant pressure and/or relief valves, ndary PRHR, in-containment water storage tank (IRWST) 15.0-28 Revision 1
Event Description Failure (a) -
dwater temperature reduction essive feedwater flow One protection division essive steam flow One protection division dvertent secondary depressurization One core makeup tank discharge valve am system piping failure One core makeup tank discharge valve dvertent operation of the PRHR One protection division am pressure regulator malfunction(b) -
s of external load One protection division bine trip One protection division dvertent closure of main steam isolation valve One protection division s of condenser vacuum One protection division s of ac power One PRHR discharge valve s of normal feedwater One PRHR discharge valve dwater system pipe break One PRHR discharge valve tial loss of forced reactor coolant flow One protection division mplete loss of forced reactor coolant flow One protection division actor coolant pump locked rotor One protection division actor coolant pump shaft break One protection division CA bank withdrawal from subcritical One protection division CA bank withdrawal at power One protection division pped RCCA, dropped RCCA bank One protection division (c) -
tically misaligned RCCA gle RCCA withdrawal One protection division es:
No protection action required Not applicable to AP1000 No transient analysis 15.0-29 Revision 1
Event Description Failure w controller malfunction(b) -
controlled boron dilution One protection division roper fuel loading(c) -
CA ejection One protection division dvertent CMT operation at power One PRHR discharge valve ease in reactor coolant system inventory One PRHR discharge valve dvertent reactor coolant system One protection division ressurization ure of small lines carrying primary coolant -
side containment(c) am generator tube rupture Faulted steam generator power-operated relief valve fails open ectrum of LOCA mall breaks One ADS Stage 4 valve arge breaks One CMT valve g-term cooling One ADS Stage 4 valve es:
No protection action required Not applicable to AP1000 No transient analysis 15.0-30 Revision 1
Equipment Used for Mitigation of Accidents Event Nonsafety-related System and Equipment 1.5 Feedwater system malfunctions that result in an Main feedwater pump trip increase in feedwater flow 1.4 Inadvertent opening of a steam generator relief MSIV backup valves1 or safety valve Main steam branch isolation valves 1.5 Steam system piping failure MSIV backup valves1 Main steam branch isolation valves 2.7 Loss of normal feedwater Pressurizer heater block 5.1 Inadvertent operation of the core makeup tanks Pressurizer heater block during power operation 5.2 Chemical and volume control system Pressurizer heater block malfunction that increases reactor coolant inventory 6.2 Failure of small lines carrying primary coolant Sample line isolation valves outside containment 6.3 Steam generator tube rupture Pressurizer heater block MSIV backup valves(1)
Main steam branch isolation valves 6.5 Small-break LOCA Pressurizer heater block These include the turbine stop or control valves, the turbine bypass valves, and the moisture separator reheater 2nd stage steam isolation valves.
15.0-31 Revision 1
Figure 15.0.3-1 Overpower and Overtemperature T Protection 15.0-32 Revision 1
Figure 15.0.3-2 AP1000 Loop Layout 15.0-33 Revision 1
-5 Least Negative Doppler Only Power Defect = -0.843% Delta K (0 to 100% Power)
-10
-15 Most Negative Doppler Only Power Defect = -1.60% Delta K
-20 (0 to 100% Power)
-25 0 10 20 30 40 50 60 70 80 90 100
% Power Figure 15.0.4-1 Doppler Power Coefficient used in Accident Analysis 15.0-34 Revision 1
1 0.9 0.8 0.7 Normalized RCCA Position 0.6 All or Some Reactor 0.5 Coolant Pumps Running (Normailzed to 2.47 Sec.)
(Distance Dropped / Distance to Top of Dashpot) 0.4 Complete Loss of Flow Transients (Normalized to 2.09 Sec.)
0.3 0.2 0.1 0
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Normalized Drop Time (Time After Drop Begins / Drop Time to Top of Dashpot)
Figure 15.0.5-1 RCCA Position Versus Time to Dashpot 15.0-35 Revision 1
0.9 0.8 0.7 Normalized Reactivity Worth 0.6 0.5 0.4 0.3 0.2 0.1 0.0 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Rod Position (Fraction Inserted)
Figure 15.0.5-2 Normalized Rod Worth Versus Position 15.0-36 Revision 1
0.9 0.8 0.7 Normalized RCCA Reactivity Worth 0.6 0.5 0.4 Complete Loss of Flow Transients 0.3 All or some Reactor Coolant Pumps Running 0.2 0.1 0
0 0.5 1 1.5 2 2.5 3 3.5 Time After Drop Begins (Sec.)
Figure 15.0.5-3 Normalized RCCA Bank Reactivity Worth Versus Drop Time 15.0-37 Revision 1
postulated. Detailed analyses are presented for the events that have been identified as limiting es.
ussions of the following reactor coolant system cooldown events are presented in this section:
Feedwater system malfunctions causing a reduction in feedwater temperature Feedwater system malfunctions causing an increase in feedwater flow Excessive increase in secondary steam flow Inadvertent opening of a steam generator relief or safety valve Steam system piping failure Inadvertent operation of the passive residual heat removal (PRHR) heat exchanger preceding events are Condition II events, with the exception of small steam system piping res, which are considered to be Condition III, and large steam system piping failure Condition IV nts. Subsection 15.0.1 contains a discussion of classifications and applicable criteria.
accidents in this section are analyzed. The most severe radiological consequences result from main steam line break accident discussed in Subsection 15.1.5. The radiological consequences reported only for that limiting case.
1.1 Feedwater System Malfunctions that Result in a Decrease in Feedwater Temperature 1.1.1 Identification of Causes and Accident Description uctions in feedwater temperature cause an increase in core power by decreasing reactor coolant perature. Such transients are attenuated by the thermal capacity of the secondary plant and of reactor coolant system. The overpower/overtemperature protection (neutron overpower, rtemperature, and overpower T trips) prevents a power increase that could lead to a departure nucleate boiling ratio (DNBR) that is less than the design limit values.
duction in feedwater temperature may be caused by a low-pressure heater train or a high-sure heater train out of service or bypassed. At power, this increased subcooling creates an eased load demand on the reactor coolant system.
h the plant at no-load conditions, the addition of cold feedwater may cause a decrease in reactor lant system temperature and a reactivity insertion due to the effects of the negative moderator fficient of reactivity. However, the rate of energy change is reduced as load and feedwater flows rease, so the no-load transient is less severe than the full-power case. The net effect on the tor coolant system due to a reduction in feedwater temperature is similar to the effect of easing secondary steam flow; that is, the reactor reaches a new equilibrium condition at a power l corresponding to the new steam generator T.
ecrease in normal feedwater temperature is classified as a Condition II event, an incident of erate frequency.
protection available to mitigate the consequences of a decrease in feedwater temperature is the e as that for an excessive steam flow increase, as discussed in Subsection 15.0.8 and listed in le 15.0-6.
15.1-1 Revision 1
transient is analyzed by calculating conditions at the feedwater pump inlet following the removal low-pressure feedwater heater train from service. These feedwater conditions are then used to lculate a heat balance through the high-pressure heaters. This heat balance gives the new water conditions at the steam generator inlet.
following assumptions are made:
Initial plant power level corresponding to 100-percent nuclear steam supply system thermal output.
The worst single failure in the pre-heating section of the Main Feedwater System, resulting in the maximum reduction in feedwater temperature, occurs.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3.
1.1.2.2 Results ult in the feedwater heaters section of the Feedwater System causes a reduction in feedwater perature that increases the thermal load on the primary system. The maximum reduction in water temperature, due to a single failure in the feedwater system, is lower than 71.5°F. This uction results in an increase in heat load on the primary system of less than 10-percent full power.
1.1.3 Conclusions decrease in feedwater temperature transient is less severe than the increase in feedwater flow nt or the increase in secondary steam flow event (see Subsections 15.1.2 and 15.1.3). Based on results presented in Subsections 15.1.2 and 15.1.3, the applicable Standard Review Plan section 15.1.1 evaluation criteria for the decrease in feedwater temperature event are met.
1.2 Feedwater System Malfunctions that Result in an Increase in Feedwater Flow 1.2.1 Identification of Causes and Accident Description ition of excessive feedwater causes an increase in core power by decreasing reactor coolant perature. Such transients are attenuated by the thermal capacity of the secondary plant and the tor coolant system. The overpower/overtemperature protection (neutron overpower, rtemperature, and overpower T trips) prevents a power increase that leads to a DNBR less than safety analysis limit value.
example of excessive feedwater flow is a full opening of a feedwater control valve due to a water control system malfunction or an operator error. At power, this excess flow causes an eased load demand on the reactor coolant system due to increased subcooling in the steam erator.
h the plant at no-load conditions, the addition of cold feedwater may cause a decrease in reactor lant system temperature and a reactivity insertion due to the effects of the negative moderator fficient of reactivity.
15.1-2 Revision 1
ncrease in normal feedwater flow is classified as a Condition II event, fault of moderate uency.
nt systems and equipment available to mitigate the effects of the accident are discussed in section 15.0.8 and listed in Table 15.0-6.
eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, a loss of offsite power is umed to occur as a consequence of the turbine trip for the excessive feedwater flow case initiated full-power conditions. As discussed in Subsection 15.0.14, an excessive feedwater flow sient initiated with the plant at no-load conditions need not consider a consequential loss of te power. With the plant initially at zero-load, the turbine would not have been connected to the
, so any subsequent reactor or turbine trip would not disrupt the grid and produce a consequential of offsite ac power.
1.2.2 Analysis of Effects and Consequences 1.2.2.1 Method of Analysis excessive heat removal due to a feedwater system malfunction transient primarily is analyzed by g the LOFTRAN computer code (Reference 1). LOFTRAN simulates a multiloop system, neutron tics, pressurizer, pressurizer safety valves, pressurizer spray, steam generator, and steam erator safety valves. The code computes pertinent plant variables, including temperatures, sures, and power level.
that portion of the feedwater malfunction transient that includes a primary coolant flow coastdown sed by the consequential loss of offsite power, a combination of three computer codes is used to orm the DNBR analysis. First the LOFTRAN code is used to predict the nuclear power transient, flow coastdown, the primary system pressure transient, and the primary coolant temperature sient. The FACTRAN code (Reference 5) is then used to calculate the heat flux based on the lear power and flow from LOFTRAN. Finally, the VIPRE-01 code (see Section 4.4) is used to ulate the DNBR during the transient, using the heat flux from FACTRAN and the flow from TRAN.
transient is analyzed to demonstrate plant behavior if excessive feedwater addition occurs ause of system malfunction or operator error that allows a feedwater control valve to open fully.
following two cases are analyzed assuming a conservatively large negative moderator perature coefficient:
Accidental opening of one feedwater control valve with the reactor just critical at zero load conditions.
Accidental opening of one feedwater control valve with the reactor in automatic control at full power.
reactivity insertion rate following a feedwater system malfunction is calculated with the following umptions:
For the feedwater control valve accident at full power, one feedwater control valve is assumed to malfunction resulting in a step increase to 120 percent of nominal feedwater flow to one steam generator.
15.1-3 Revision 1
For the zero-load condition, feedwater temperature is at a conservatively low value of 40°F.
No credit is taken for the heat capacity of the reactor coolant system and steam generator thick metal in attenuating the resulting plant cooldown.
The feedwater flow resulting from a fully open control valve is terminated by a steam generator high-2 level trip signal, which closes feedwater control and isolation valves and trips the main feedwater pumps, the turbine, and the reactor.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3.
mal reactor control systems are not required to function. The protection and safety monitoring em may function to trip the reactor because of overpower or high-2 steam generator water level ditions. No single active failure prevents operation of the protection and safety monitoring system.
scussion of anticipated transients without trip considerations is presented in Section 15.8.
analysis assumes that the turbine trip during the case initiated from full power results in a sequential loss of offsite power that produces the coastdown of the reactor coolant pumps. As cribed in Subsection 15.0.14, the loss of offsite power is modeled to occur 3.0 seconds after the ine trip. The excessive feedwater flow analysis conservatively delays the start of rod insertion l 2.0 seconds after the reactor trip signal is generated, while assuming that the turbine trip occurs a zero time delay following the generation of the turbine trip signal. The interaction of these umptions produces maximum core power with minimum core coolant flow during the period of tor coolant pump coastdown and thereby minimizes the predicted DNBRs.
1.2.2.2 Results e case of an accidental full opening of one feedwater control valve with the reactor at zero power the preceding assumptions, the maximum reactivity insertion rate is less than the maximum tivity insertion rate analyzed in Subsection 15.4.1 for an uncontrolled rod cluster control embly (RCCA) bank withdrawal from a subcritical or low-power startup condition. Therefore, the lts of the analysis are not presented here. If the incident occurs with the unit just critical at oad, the reactor may be tripped by the power range high neutron flux trip (low setting) set at roximately 25-percent nominal full power.
full-power case (maximum reactivity feedback coefficients, automatic rod control) results in the atest power increase. Assuming the rod control system to be in the manual control mode results slightly less severe transient.
en the steam generator water level in the faulted loop reaches the high-2 level setpoint, the water control valves and feedwater isolation valves are automatically closed and the main water pumps are tripped. This prevents continuous addition of the feedwater. In addition, a ine trip and a reactor trip are initiated.
nsient results show the increase in nuclear power and T associated with the increased thermal on the reactor (see Figures 15.1.2-1 and 15.1.2-2). A new equilibrium condition is reached and he plant parameters, except for the SG water level, remain almost constant. Following the turbine the consequential loss of offsite power produces the reactor coolant system flow coastdown wn in Figure 15.1.2-3. The minimum DNBR is predicted to occur before the reactor trip and the tor coolant pump coastdown caused by the loss of offsite power. The minimum DNBR predicted 15.1-4 Revision 1
ause the power level rises by a maximum of about 12 percent above nominal during the essive feedwater flow incident, the fuel temperature also rises until after reactor trip occurs. The heat flux lags behind the neutron flux response because of the fuel rod thermal time constant.
refore, the peak value does not exceed 118 percent of its nominal value (the assumed high tron flux trip setpoint). The peak fuel temperature thus remains well below the fuel melting perature.
transient results show that departure from nucleate boiling (DNB) does not occur at any time ng the excessive feedwater flow incident. Thus, the capability of the primary coolant to remove t from the fuel rods is not reduced and the fuel cladding temperature does not rise significantly ve its initial value during the transient.
calculated sequence of events for this accident is shown in Table 15.1.2-1.
1.2.3 Conclusions results of the analysis show that the minimum DNBR encountered for an excessive feedwater ition at power is above the design limit value. The DNBR design basis is described in Section 4.4.
itionally, the reactivity insertion rate that occurs at no-load conditions following excessive water addition is less than the maximum value considered in the analysis of the rod withdrawal subcritical condition analysis (see Subsection 15.4.1).
1.3 Excessive Increase in Secondary Steam Flow 1.3.1 Identification of Causes and Accident Description excessive increase in secondary system steam flow (excessive load increase incident) results in wer mismatch between the reactor core power and the steam generator load demand. The plant trol system is designed to accommodate a 10-percent step load increase or a 5-percent-per-ute ramp load increase in the range of 25- to 100-percent full power. Any loading rate in excess of e values may cause a reactor trip actuated by the protection and safety monitoring system.
am flow increases greater than 10 percent are analyzed in Subsections 15.1.4 and 15.1.5.
accident could result from either an administrative violation such as excessive loading by the rator or an equipment malfunction in the steam dump control or turbine speed control.
ing power operation, turbine bypass to the condenser is controlled by reactor coolant condition als. A high reactor coolant temperature indicates a need for turbine bypass. A single controller function does not cause turbine bypass. An interlock blocks the opening of the valves unless a e turbine load decrease or a turbine trip has occurred.
ection against an excessive load increase accident is provided by the following protection and ty monitoring system signals:
Overpower T Overtemperature T Power range high neutron flux 15.1-5 Revision 1
eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, an analysis has been ormed to evaluate the effects produced by a possible consequential loss of offsite power during excessive load increase event. As discussed in Subsection 15.0.14, the loss of offsite power d be considered only as a direct consequence of a turbine trip occurring while the plant is rating at power. For the four excessive load increase cases presented, reactor and turbine trips not predicted to occur. However, to address the loss of offsite power issue, analysis has been ormed that conservatively assumes a reactor trip and an associated turbine trip occur at the time eak power. Consistent with the discussion in Subsection 15.0.14, the analysis then models a loss ffsite power occurring 3.0 seconds after the turbine trip. The primary effect of the loss of offsite er is to cause the reactor coolant pumps to coast down.
1.3.2 Analysis of Effects and Consequences 1.3.2.1 Method of Analysis accident is primarily analyzed using the LOFTRAN computer code (Reference 1). LOFTRAN ulates the neutron kinetics, reactor coolant system, pressurizer, pressurizer safety valves, surizer spray, steam generator, steam generator safety valves, and feedwater system. The code putes pertinent plant variables including temperatures, pressures, and power level.
the excessive load increase analysis that includes a primary coolant flow coastdown caused by consequential loss of offsite power, a combination of three computer codes is used to perform the BR analysis. First the LOFTRAN code is used to predict the nuclear power transient, the flow stdown, the primary system pressure transient, and the primary coolant temperature transient.
FACTRAN code (Reference 5) is then used to calculate the heat flux based on the nuclear er and flow from LOFTRAN. Finally, the VIPRE-01 code (see Section 4.4) is used to calculate the BR during the transient, using the heat flux from FACTRAN and the flow from LOFTRAN.
r cases are analyzed to demonstrate plant behavior following a 10-percent step load increase rated load. These cases are as follows:
Reactor control in manual with minimum moderator reactivity feedback Reactor control in manual with maximum moderator reactivity feedback Reactor control in automatic with minimum moderator reactivity feedback Reactor control in automatic with maximum moderator reactivity feedback the minimum moderator feedback cases, the core has the least negative moderator temperature fficient of reactivity; therefore, reductions in coolant temperature have the least impact on core er. For the maximum moderator feedback cases, the moderator temperature coefficient of tivity has its highest absolute value. This results in the largest amount of reactivity feedback due hanges in coolant temperature. For all the cases analyzed both with and without automatic rod trol, no credit is taken for T trips on overtemperature or overpower in order to demonstrate the rent transient capability of the plant. Under actual operating conditions, such a trip may occur, r which the plant quickly stabilizes.
0-percent step increase in steam demand is assumed, and each case is analyzed without credit g taken for pressurizer heaters. At initial reactor power, reactor coolant system pressure and perature are assumed to be at their full power values. Uncertainties in initial conditions are uded in the limit DNBR as described in WCAP-11397-P-A (Reference 2). Plant characteristics initial conditions are further discussed in Subsection 15.0.3.
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tor trip with a coincident turbine trip followed by a loss of offsite power 3.0 seconds later, as ussed in Subsection 15.0.14. The primary effect of the loss of offsite power is to cause the tor coolant pumps to coast down.
mal reactor control systems and engineered safety systems are not required to function.
1.3.2.2 Results res 15.1.3-1 through 15.1.3-10 show the transient with the reactor in the manual control mode no reactor trip signals occur. For the minimum moderator feedback case, there is a slight power ease and the average core temperature shows a large decrease. This results in a DNBR that eases above its initial value. For the maximum moderator feedback manually controlled case, e is a much faster increase in reactor power due to the moderator feedback. A reduction in the BR occurs, but the DNBR remains above the design limit (see Section 4.4).
res 15.1.3-11 through 15.1.3-20 show the transient assuming the reactor is in the automatic trol mode. A reactor trip signal setpoint is reached but, conservatively, reactor trip is not credited.
h the minimum and maximum moderator feedback cases show that core power increases and eby reduces the rate of decrease in coolant average temperature and pressurizer pressure. For of these cases, the minimum DNBR remains above the design limit (see Section 4.4).
the cases with no reactor trip signal, the plant power stabilizes at an increased power level.
mal plant operating procedures are followed to reduce power. Because of the measurement rs assumed in the setpoints, it is possible that reactor trip could actually occur for the automatic trol and maximum feedback cases. The plant reaches a stabilized condition following the trip.
the analysis performed modeling a loss of offsite power and the subsequent reactor coolant p coastdown, the results show that the minimum DNBRs predicted during the excessive load ease cases occur prior to the time the flow coastdown begins. Therefore, the DNB ratio results ided in Figures 15.1.3-5, 15.1.3-10, 15.1.3-15, and 15.1.3-20 are bounding, and the minimum BR during the flow coastdown remains well above the design limit defined in Section 4.4. Since loss of offsite power is delayed for 3.0 seconds after the turbine trip, the RCCAs are inserted well the core before the reactor coolant system flow coastdown begins. The resulting power reduction pensates for the reduced flow encountered once power to the reactor coolant pumps is lost.
excessive load increase incident is an overpower transient for which the fuel temperature rises.
ctor trip may not occur for some of the cases analyzed, and the plant reaches a new equilibrium dition at a higher power level corresponding to the increase in steam flow.
ause DNB does not occur during the excessive load increase transients, the capability of the ary coolant to remove heat from the fuel rod is not reduced. Thus, the fuel cladding temperature s not rise significantly above its initial value during the transient.
calculated sequence of events for the excessive load increase cases with no reactor trip are wn in Table 15.1.2-1.
1.3.3 Conclusions analysis presented in this subsection demonstrates that for a 10-percent step load increase, the BR remains above the design limit. The design basis for DNB is described in Section 4.4. The t rapidly reaches a stabilized condition following the load increase.
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most severe core conditions resulting from an accidental depressurization of the main steam em are associated with an inadvertent opening of a single steam dump, relief, or safety valve.
analyses performed assuming a rupture of a main steam line are given in Subsection 15.1.5.
steam release, as a consequence of this accident, results in an initial increase in steam flow ch decreases during the accident as the steam pressure falls. The energy removal from the tor coolant system causes a reduction of coolant temperature and pressure. In the presence of a ative moderator temperature coefficient, the cooldown results in an insertion of positive reactivity.
analysis is performed to demonstrate that the following Standard Review Plan Subsection 15.1.4 luation criterion is satisfied.
uming the most reactive stuck RCCA, with offsite power available, and assuming a single failure e engineered safety features system, there will be no consequential damage to the fuel or tor coolant system after reactor trip for a steam release equivalent to the spurious opening, with re to close, of the largest of any single steam dump, relief, or safety valve. This criterion is met by wing the DNB design basis is not exceeded.
idental depressurization of the secondary system is classified as a Condition II event as cribed in Section 15.1.
following systems provide the necessary protection against an accidental depressurization of the n steam system:
Core makeup tank actuation from one of the following signals:
- Safeguards (S) signal z Two out of four low pressurizer pressure signals z Two out of four high-2 containment pressure signals z Two out of four low Tcold signals in any one loop z Two out of four low steam line pressure signals in any one loop
- Two out of four low-2 pressurizer level signals The overpower reactor trips (neutron flux and T) and the reactor trip occurring in conjunction with receipt of the S signal Redundant isolation of the main feedwater lines Sustained high feedwater flow causes additional cooldown. Therefore, in addition to the normal control action that closes the main feedwater valves following reactor trip, an S signal rapidly closes the feedwater control valves and feedwater isolation valves, and trips the main feedwater pumps.
Redundant isolation of the startup feedwater system Sustained high startup feedwater flow causes additional cooldown. Therefore, the low Tcold signal closes the startup feedwater control and isolation valves.
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- Two out of four low steam line pressure signals in any one loop (above permissive P-11)
- Two out of four high negative steam pressure rates in any loop (below permissive P-11)
- Two out of four low Tcold signals in any one loop
- Two out of four high-2 containment pressure signals Plant systems and equipment available to mitigate the effects of the accident are discussed in Subsection 15.0.8 and listed in Table 15.0-6.
1.4.2 Analysis of Effects and Consequences 1.4.2.1 Method of Analysis following analyses of a secondary system steam release are performed:
A full plant digital computer simulation using the LOFTRAN code (Reference 1) to determine reactor coolant system temperature and pressure during cooldown, and the effect of core makeup tank injection Analyses to determine that there is no damage to the fuel or reactor coolant system following conditions are assumed to exist at the time of a secondary steam system release:
End-of-life shutdown margin at no-load, equilibrium xenon conditions, and with the most reactive RCCA stuck in its fully withdrawn position. Operation of RCCA mechanical shim and axial offset banks during core burnup is restricted by the insertion limits so that shutdown margin requirements are satisfied.
The most negative moderator coefficient corresponding to the end-of-life rodded core with the most reactive RCCA in the fully withdrawn position. The variation of the coefficient with temperature is included. The keff (considering moderator temperature and density effects) versus temperature corresponding to the negative moderator temperature coefficient used is shown in Figure 15.1.4-1. The core power is modeled as a function of core mass flow, core boron concentration, and core inlet temperature.
Minimum capability for injection of boric acid solution corresponding to the most restrictive single failure in the passive core cooling system. Low-concentration boric acid must be swept from the core makeup tank lines downstream of isolation valves before delivery of boric acid (3400 ppm) to the reactor coolant loops. This effect has been accounted for in the analysis.
The case studied is a steam flow of 520 pounds per second at 1200 psia with offsite power available. This conservatively models the maximum capacity of any single steam dump, relief, or safety valve. Initial hot shutdown conditions at time zero are assumed because this represents the most conservative initial conditions.
uld the reactor be just critical or operating at power at the time of a steam release, the reactor is ed by the normal overpower protection when power level reaches a trip point. Following a trip at er, the reactor coolant system contains more stored energy than at no-load. This is because the rage coolant temperature is higher than at no-load, and there is appreciable energy stored in the
. The additional stored energy is removed via the cooldown caused by the steam release before no-load conditions of the reactor coolant system temperature and shutdown margin assumed in analyses are reached.
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tor coolant system cooldown are less for steam line release occurring at power:
In computing the steam flow, the Moody Curve (Reference 3) for f(L/D) = 0 is used.
Perfect moisture separation occurs in the steam generator.
Offsite power is available, because this maximizes the cooldown.
Maximum cold startup feedwater flow is assumed.
Four reactor coolant pumps are initially operating.
Manual actuation of the PRHR system at time zero is conservatively assumed to maximize the cooldown.
1.4.2.2 Results results presented conservatively indicate the events that would occur assuming a secondary em steam release because it is postulated that the conditions just described occur ultaneously.
res 15.1.4-2 through 15.1.4-12 show the transient results for a steam flow of 520 pounds per ond at 1200 psia.
assumed steam release is typical of the capacity of any single steam dump, relief, or safety
- e. Core makeup tank injection and the associated tripping of the reactor coolant pumps are ated automatically by the low Tcold S signal. Boron solution at 3400 ppm enters the reactor lant system, providing enough negative reactivity to prevent a significant return to power and core age. Later in the transient, as the reactor coolant pressure continues to fall, the accumulators ate and inject boron solution at 2600 ppm.
transient is conservative with respect to cooldown, because no credit is taken for the energy ed in the system metal other than that of the fuel elements and steam generator tubes, and the HR system is assumed to be actuated at time zero. Because the limiting portion of the transient urs over a period of about 5 minutes, the neglected stored energy is likely to have a significant ct in slowing the cooldown.
calculated time sequence of events for this accident is listed in Table 15.1.2-1.
1.4.3 Margin to Critical Heat Flux analysis demonstrates that the DNB design basis, as described in Section 4.4, is met for the vertent opening of a steam generator relief or safety valve. As shown in Figure 15.1.4-2, no ificant return to power occurs and, therefore, DNB does not occur. The minimum DNBR is servatively calculated and is above the 95/95 limit.
1.4.4 Conclusions analysis shows that the criterion stated in this subsection is satisfied. For an inadvertent opening ny single steam dump or a steam generator relief or safety valve, the DNB design basis is met.
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steam release arising from a rupture of a main steam line results in an initial increase in steam
, which decreases during the accident as the steam pressure falls. The energy removal from the tor coolant system causes a reduction of coolant temperature and pressure. In the presence of a ative moderator temperature coefficient, the cooldown results in an insertion of positive reactivity.
e most reactive RCCA is assumed stuck in its fully withdrawn position after reactor trip, there is ncreased possibility that the core becomes critical and returns to power. A return to power wing a steam line rupture is a potential problem mainly because of the existing high-power king factors, assuming the most reactive RCCA to be stuck in its fully withdrawn position. The is ultimately shut down by the boric acid solution delivered by the passive core cooling system.
analysis of a main steam line rupture is performed to demonstrate that the following Standard iew Plan Subsection 15.1.5 evaluation criterion is satisfied.
uming the most reactive stuck RCCA with or without offsite power and assuming a single failure e engineered safety features system, the core cooling capability is maintained. As shown in section 15.1.5.4, radiation doses are within the guidelines.
B and possible cladding perforation following a steam pipe rupture are not necessarily cceptable. The following analysis shows that the DNB design basis is not exceeded for any mline rupture, assuming the most reactive assembly stuck in its fully withdrawn position.
ajor steam line rupture is classified as a Condition IV event.
cts of minor secondary system pipe breaks are bounded by the analysis presented in this ion. Minor secondary system pipe breaks are classified as Condition III events, as described in section 15.0.1.3.
major rupture of a steam line is the most limiting cooldown transient and is analyzed at zero er with no decay heat. Decay heat retards the cooldown and thereby reduces the likelihood that reactor returns to power. A detailed analysis of this transient with the most limiting break size, a ble-ended rupture, is presented here.
tain assumptions used in this analysis are discussed in WCAP-9226 (Reference 4). WCAP-9226 contains a discussion of the spectrum of break sizes and power levels analyzed.
following functions provide the protection for a steam line rupture (see Subsection 7.2.1.1.2):
Core makeup tank actuation from any of the following:
- Two out of four low pressurizer pressure signals
- Two out of four high-2 containment pressure signals
- Two out of four low steam line pressure signals in any loop
- Two out of four low Tcold signals in any one loop
- Two out of four low-2 pressurizer level signals The overpower reactor trips (neutron flux and T) and the reactor trip occurring in conjunction with receipt of the S signal 15.1-11 Revision 1
control action that closes the main feedwater control valves, the S signal rapidly closes the feedwater control valves and feedwater isolation valves, and trips the main feedwater pumps.
Redundant isolation of the startup feedwater system Sustained high startup feedwater flow causes additional cooldown. Therefore, the low Tcold signal closes the startup feedwater control and isolation valves.
Fast-acting main steam line isolation valves (assumed to close in less than 10 seconds) on any of the following:
- Two out of four high-2 containment pressure
- Two out of the four low steam line pressure signals in any one loop (above permissive P-11)
- Two out of four high negative steam pressure rates in any one loop (below permissive P-11)
- Two out of four low Tcold signals in any one loop st-acting main steam isolation valve is provided in each steam line. These valves are assumed to close within 10 seconds of actuation following a large break in the steam line. For breaks nstream of the main steam line isolation valves, closure of at least one valve in each line inates the blowdown.
any break in any location, no more than one steam generator would experience an uncontrolled down even if one of the main steam line isolation valves fails to close. A description of steam line ation is included in Chapter 10.
w restrictors are installed in the steam generator outlet nozzle, as an integral part of the steam erator. The effective throat area of the nozzles is 1.4 ft2, which is considerably less than the main m pipe area; thus, the flow restrictors serve to limit the maximum steam flow for a break at any tion.
ign criteria and methods of protection of safety-related equipment from the dynamic effects of tulated piping ruptures are provided in Section 3.6.
1.5.2 Analysis of Effects and Consequences 1.5.2.1 Method of Analysis analysis of the steam pipe rupture is performed to determine the following:
The core heat flux and reactor coolant system temperature and pressure resulting from the cooldown following the steam line break. The LOFTRAN code (Reference 1) is used to model the system transient.
The thermal-hydraulic behavior of the core following a steam line break. A detailed thermal-hydraulic digital computer code, VIPRE-01, is used to determine if DNB occurs for the core transient conditions computed by the LOFTRAN code.
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reactive rod control assembly stuck in its fully withdrawn position. Operation of the control rod mechanical shim and axial offset banks during core burnup is restricted by the insertion limits so that shutdown margin requirements are satisfied.
A negative moderator coefficient corresponding to the end-of-life rodded core with the most reactive RCCA in the fully withdrawn position. The variation of the coefficient with temperature is included. The keff (considering moderator temperature and density effects) versus temperature corresponding to the negative moderator temperature coefficient used is shown in Figure 15.1.4-1. The core power is modeled as a function of core mass flow, core boron concentration, and core inlet temperature.
core properties used in the LOFTRAN mode for feedback calculations are generated by bining those in the sector nearest the affected steam generator with those associated with the aining sector. The resultant properties reflect a combination process that accounts for inlet um fluid mixing and a conservative weighing of the fluid properties from the coldest core sector.
erifying the conservatism of this method, the power predictions of the LOFTRAN modeling are firmed by comparison with detailed core analysis for the limiting conditions of the cases sidered. This core analysis conservatively models the hypothetical core configuration (that is, k RCCA, nonuniform inlet temperatures, pressure, flow, and boron concentration) and directly luates the total reactivity feedback including power, boron, and density redistribution in an integral ion. The effect of void formation is also included.
parison of the results from the detailed core analysis with the LOFTRAN predictions verify the rall conservatism of the methodology. That is, the specific power, temperature, and flow ditions used to perform the DNB analysis are conservative.
The core makeup tanks and the accumulators are the portions of the passive core cooling system used in mitigating a steam line rupture. There are no single failures that prevent core makeup tank injection. In modeling the core makeup tanks and the accumulators, conservative assumptions are used that minimize the capability to add borated water.
Specifically, the core makeup tank injection line characteristics modeled reflect the failure of one core makeup tank discharge valve.
The maximum overall fuel-to-coolant heat transfer coefficient is used to maximize the rate of cooldown.
Because the steam generators are provided with integral flow restrictors with a 1.4-ft2 throat area, any rupture in a steam line with a break area greater than 1.4 ft2, regardless of location, has the same effect on the primary plant as the 1.4-ft2 double-ended rupture. The limiting case considered in determining the core power and reactor coolant system transient is the complete severance of a pipe, with the plant initially at no-load conditions and full reactor coolant flow with offsite power available. The results of this case bound the loss of offsite power case for the following reasons:
- Loss of offsite power results in an immediate reactor coolant pump coastdown at the initiation of the transient. This reduces the severity of the reactor coolant system cooldown by reducing primary-to-secondary heat transfer. The lessening of the cooldown, in turn, reduces the magnitude of the return to power.
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continued reactor coolant pump operation reduces the rate of boron injection into the core and is conservative.
- The protection system automatically provides a safety-related signal that initiates the coastdown of the reactor coolant pumps in parallel with core makeup tank actuation.
Because this reactor coolant pump trip function is actuated early during the steam line break event (right after core makeup tank actuation), there is very little difference in the predicted DNBR between cases with and without offsite power.
- Because of the passive nature of the safety injection system, the loss of offsite power does not delay the actuation of the safety injection system.
Power peaking factors corresponding to one stuck RCCA are determined at the end of core life. The coldest core inlet temperatures are assumed to occur in the sector with the stuck rod. The power peaking factors account for the effect of the local void in the region of the stuck RCCA during the return to power phase following the steam line break. This void in conjunction with the large negative moderator coefficient partially offsets the effect of the stuck assembly. The power peaking factors depend upon the core power, temperature, pressure, and flow and, therefore, may differ for each case studied.
analysis assumes initial hot standby conditions at time zero in order to present a representative e which will yield limiting post-trip DNBR results for this transient. If the reactor is just critical or rating at power at the time of a steam line break, the reactor is tripped by the overpower ection system when power level reaches a trip point.
owing a trip at power, the reactor coolant system contains more stored energy than at no-load ause the average coolant temperature is higher than at no-load, and there is energy stored in the
. The additional stored energy reduces the cooldown caused by the steam line break before the oad conditions of reactor coolant system temperature and shutdown margin assumed in the lyses are reached.
r the additional stored energy has been removed, the cooldown and reactivity insertions proceed e same manner as in the analysis that assumes a no-load condition at time zero.
In computing the steam flow during a steam line break, the Moody Curve (Reference 3) for f(L/D) = 0 is used.
Perfect moisture separation occurs in the steam generator.
Maximum cold startup feedwater flow plus nominal 100 percent main feedwater flow is assumed.
Four reactor coolant pumps are initially operating.
Manual actuation of the PRHR system at time zero is conservatively assumed to maximize the cooldown.
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ented conservatively indicate the events that would occur assuming a steam line rupture ause it is postulated that the conditions described occur simultaneously.
1.5.2.3 Core Power and Reactor Coolant System Transient res 15.1.5-1 through 15.1.3-13 show the reactor coolant system transient and core heat flux wing a main steam line rupture (complete severance of a pipe) at initial no-load condition.
ite power is assumed available so that, initially, full reactor coolant flow exists. During the course e event, the reactor protection system initiates a trip of the reactor coolant pumps in conjunction actuation of the core makeup tanks. The transient shown assumes an uncontrolled steam ase from only one steam generator. Steam release from more than one steam generator is ented by automatic trip of the main steam isolation valves in the steam lines by high containment sure signals or by low steam line pressure signals. Even with the failure of one valve, release is ed to approximately 10 seconds for the other steam generator while the one generator blows
- n. The main steam isolation valves fully close in less than 10 seconds from receipt of a closure al.
hown in Figure 15.1.5-1, the core attains criticality with the RCCAs inserted (with the design tdown assuming the most reactive RCCA stuck) before boron solution at 3400 ppm (from core eup tanks) or 2600 ppm (from accumulators) enters the reactor coolant system. A peak core er significantly lower than the nominal full-power value is attained.
calculation assumes that the boric acid is mixed with and diluted by the water flowing in the tor coolant system before entering the reactor core. The concentration after mixing depends n the relative flow rates in the reactor coolant system and from the core makeup tanks or umulators (or both). The variation of mass flow rate in the reactor coolant system due to water sity changes is included in the calculation. The variation of flow rate from the core makeup tanks ccumulators (or both) due to changes in the reactor coolant system pressure and temperature the pressurizer level is also included. The reactor coolant system and passive injection flow ulations include line losses.
o time during the analyzed steam line break event does the core makeup tank level approach the oint for actuation of the automatic depressurization system. During non-LOCA events, the core eup tanks remain filled with water. The volume of injection flow leaving the core makeup tank is et by an equal volume of recirculation flow that enters the core makeup tanks via the reactor lant system cold leg balance lines.
PRHR system provides a passive, long-term means of removing the core decay and stored heat ransferring the energy via the PRHR heat exchanger to the in-containment refueling water age tank (IRWST). The PRHR heat exchanger is normally actuated automatically when the m generator level falls below the low wide-range level. For the main steam line rupture case lyzed, the PRHR exchanger is conservatively actuated at time zero to maximize the cooldown.
1.5.2.4 Margin to Critical Heat Flux case presented in Subsection 15.1.5.2.2 conservatively models the expected behavior of the t during a steam system piping failure. This includes the tripping of the reactor coolant pumps cident with core makeup tank actuation. A DNB analysis is performed using limiting assumptions bound those of Subsection 15.1.5.2.2.
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1.5.3 Conclusions analysis shows that the DNB design basis is met for the steam system piping failure event. DNB possible cladding perforation following a steam pipe rupture are not precluded by the criteria.
preceding analysis shows that no DNB occurs for the main steam line rupture assuming the t reactive RCCA stuck in its fully withdrawn position.
1.5.4 Radiological Consequences evaluation of the radiological consequences of a postulated main steam line break outside tainment assumes that the reactor has been operating with the design basis fuel defect level 5 percent of power produced by fuel rods containing cladding defects) and that leaking steam erator tubes have resulted in a buildup of activity in the secondary coolant.
owing the rupture, startup feedwater to the faulted loop is isolated and the steam generator is wed to steam dry. Any radioiodines carried from the primary coolant into the faulted steam erator via leaking tubes are assumed to be released directly to the environment. It is servatively assumed that the reactor is cooled by steaming from the intact loop.
1.5.4.1 Source Term only significant radionuclide releases due to the main steam line break are the iodines and alkali als that become airborne and are released to the environment as a result of the accident. Noble es are also released to the environment. Their impact is secondary because any noble gases ring the secondary side during normal operation are rapidly released to the environment.
analysis considers two different reactor coolant iodine source terms, both of which consider the ne spiking phenomenon. In one case, the initial iodine concentrations are assumed to be those ociated with equilibrium operating limits for primary coolant iodine activity. The iodine spike is umed to be initiated by the accident with the spike causing an increasing level of iodine in the tor coolant.
second case assumes that the iodine spike occurs prior to the accident and that the maximum lting reactor coolant iodine concentration exists at the time the accident occurs.
reactor coolant noble gas concentrations are assumed to be those associated with the ilibrium operating limits for primary coolant noble gas activity. The reactor coolant alkali metal centrations are based on those associated with the design basis fuel defect level.
secondary coolant is assumed to have an iodine source term of 0.01 Ci/g dose ivalent I-131. This is 1 percent of the maximum primary coolant activity at equilibrium operating ditions. The secondary coolant alkali metal concentration is also assumed to be 1 percent of the ary concentration.
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The secondary coolant in the steam generator of the faulted loop is assumed to be released out the break as steam. Any iodine and alkali metal activity contained in the coolant is assumed to be released.
The reactor coolant leaking into the steam generator of the faulted loop is assumed to be released to the environment without any credit for partitioning or plateout onto the interior of the steam generator.
The reactor coolant leaking into the steam generator of the intact loop would mix with the secondary coolant and thus raise the activity concentrations in the secondary water. While the steam release from the intact loop would have partitioning of non-gaseous activity, this analysis conservatively assumes that any activity entering the secondary side is released.
dit is taken for decay of radionuclides until release to the environment. After release to the ironment, no consideration is given to radioactive decay or to cloud depletion by ground osition during transport offsite.
1.5.4.3 Dose Calculation Models models used to calculate doses are provided in Appendix 15A.
1.5.4.4 Analytical Assumptions and Parameters assumptions and parameters used in the analysis are listed in Table 15.1.5-1.
1.5.4.5 Identification of Conservatisms assumptions and parameters used in the analysis contain a number of significant conservatisms:
The reactor coolant activities are based on a fuel defect level of 0.25 percent. The expected fuel defect level is far less than this (see Section 11.1).
The assumed leakage of 150 gallons of reactor coolant per day into each steam generator is conservative. The leakage is expected to be a small fraction of this during normal operation.
The conservatively selected meteorological conditions are present only rarely.
1.5.4.6 Doses ng the assumptions from Table 15.1.5-1, the calculated total effective dose equivalent (TEDE) es for the case with accident-initiated iodine spike are determined to be less than 0.6 rem at the boundary for the limiting 2-hour interval (4.8 to 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) and 1.1 rem at the low population zone r boundary. These doses are small fractions of the dose guideline of 25 rem TEDE identified in CFR Part 50.34. A small fraction is defined, consistent with the Standard Review Plan, as being ercent or less. The TEDE doses for the case with pre-existing iodine spike are determined to be than 0.5 rem at the site boundary for the limiting 2-hour interval (0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) and 0.4 rem at the population zone outer boundary. These doses are within the dose guidelines of 10 CFR 50.34.
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n evaluated for a duration of 30 days. The 30-day contribution to the dose at the site boundary the low population zone boundary is less than 0.01 rem TEDE. When this is added to the dose ulated for the main steam line break, the resulting total dose remains less than the values orted above.
1.6 Inadvertent Operation of the PRHR Heat Exchanger 1.6.1 Identification of Causes and Accident Description inadvertent actuation of the PRHR heat exchanger causes an injection of relatively cold water the reactor coolant system. This produces a reactivity insertion in the presence of a negative erator temperature coefficient. To prevent this reactivity increase from causing reactor power ease, a reactor trip is initiated when either PRHR discharge valve comes off of its fully shut seat.
inadvertent actuation of the PRHR heat exchanger could be caused by operator error or a false ation signal, or by malfunction of a discharge valve. Actuation of the PRHR heat exchanger lves opening one of the isolation valves, which establishes a flow path from one reactor coolant em hot leg, through the PRHR heat exchanger, and back into its associated steam generator cold plenum.
PRHR heat exchanger is located above the core to promote natural circulation flow when the tor coolant pumps are not operating. With the reactor coolant pumps in operation, flow through PRHR heat exchanger is enhanced. The heat sink for the PRHR heat exchanger is provided by IRWST, in which the PRHR heat exchanger is submerged. Because the fluid in the heat hanger is in thermal equilibrium with water in the tank, the initial flow out of the PRHR heat hanger is significantly colder than the reactor coolant system fluid. Following this initial insurge, reduction in cold leg temperature is limited by the cooling capability of the PRHR heat exchanger.
ause the PRHR heat exchanger is connected to only one reactor coolant system loop, the ldown resulting from its actuation is asymmetric with respect to the core.
response of the plant to an inadvertent PRHR heat exchanger actuation with the plant at no-load ditions is bounded by the analyses performed for the inadvertent opening of a steam generator f or safety valve event (Subsection 15.1.4) and the steam system piping failure event bsection 15.1.5). Both of these events are conservatively analyzed assuming PRHR heat hanger actuation coincident with the steam line depressurization. Therefore, only the response of plant to an inadvertent PRHR initiation with the core at power is considered.
eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, the effects of a possible sequential loss of ac power during an inadvertent PRHR heat exchanger actuation event have n evaluated to not adversely impact the analysis results. This conclusion is based on a review of time sequence associated with a consequential loss of ac power in comparison to the reactor tdown time for an inadvertent PRHR heat exchanger actuation event. The primary effect of the of ac power is to cause the reactor coolant pumps (RCPs) to coast down. The protection and ty monitoring system includes a 5-second minimum delay between the reactor trip and the ine trip. In addition, a 3-second delay between the turbine trip and the loss of offsite ac power is umed, consistent with Section 15.1.3 of NUREG-1793. Considering these delays between the of the reactor trip and RCP coastdown due to the loss of ac power, it is clear that the plant tdown sequence will have passed the critical point and the control rods will have been completely rted before the RCPs begin to coast down. Therefore, the consequential loss of ac power does adversely impact this inadvertent PRHR heat exchanger actuation analysis because the plant will hut down well before the RCPs begin to coast down.
15.1-18 Revision 1
em functions are available to provide protection in the event of an inadvertent PRHR heat hanger actuation:
PRHR discharge valve not closed Overpower/overtemperature reactor trips (neutron flux and T)
Two out of four low pressurizer pressure signals Due to the potential consequences as a result of the reactivity excursion, a reactor trip has been designed so that upon an inadvertent PRHR actuation, a reactor trip will occur. This reactor trip is generated when either of the discharge valves is not closed. This ensures that the reactor will be tripped prior to a power increase due to the cold water injection.
1.6.2 Analysis of Effects and Consequences e a reactor trip is initiated as soon as the PRHR discharge valves are not fully closed, this event ssentially a reactor trip from the initial condition and requires no separate transient analysis.
1.6.3 Conclusions vertent actuation of the PRHR does not result in violation of the core thermal design limits (DNB linear power generation) or RCS overpressure.
1.7 Combined License Information section contained no requirement for additional information.
1.8 References Burnett, T. W. T., et al., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary),
and WCAP-7907-A (Nonproprietary), April 1984.
Friedland, A. J., and Ray, S., Revised Thermal Design Procedure, WCAP-11397-P-A (Proprietary) and WCAP-11397-A (Nonproprietary), April 1989.
Moody, F. S., Transactions of the ASME, Journal of Heat Transfer, Figure 3, page 134, February 1965.
Wood, D. C., and Hollingsworth, S. D., Reactor Core Response to Excessive Secondary Steam Releases, WCAP-9226 (Proprietary) and WCAP-9227 (Nonproprietary), January 1978.
Hargrove, H. G., FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908-A, December 1989.
AP1000 Code Applicability Report, WCAP-15644-P (Proprietary) and WCAP-15644-NP (Nonproprietary), Revision 2, March 2004.
15.1-19 Revision 1
Result in an Increase in Heat Removal From the Primary System Time Accident Event (seconds) cessive increase in secondary steam w
Manual reactor control (minimum 10-percent step load increase 0.0 moderator feedback) Equilibrium conditions reached (approximate 250.0 time only)
Manual reactor control (maximum 10-percent step load increase 0.0 moderator feedback) Equilibrium conditions reached (approximate 70.0 time only)
Automatic reactor control (minimum 10-percent step load increase 0.0 moderator feedback) Equilibrium conditions reached (approximate 125.0 time only)
Automatic reactor control (maximum 10-percent step load increase 0.0 moderator feedback) Equilibrium conditions reached (approximate 50.0 time only) edwater system malfunctions that One main feedwater control valve fails fully open 0.0 ult in an increase in feedwater flow Turbine trip/feedwater isolation and reactor trip 201.9 on high steam generator level Rod motion begins 203.9 Loss of offsite power occurs 204.9 Minimum DNBR occurs 205.8 dvertent operation of the PRHR PRHR discharge valves go fully open 0.0 Reactor trip setpoint reached 0.0 Rod motion begins 1.25 Rods fully inserted 3.95 15.1-20 Revision 1
Time Accident Event (seconds) dvertent opening of a steam generator Inadvertent opening of one main steam safety or 0.0 ef or safety valve relief valve S actuation signal on safeguards low Tcold 120.3 Core makeup tank actuation 137.3 Boron reaches core 152.6 am system piping failure Steam line ruptures 0.0 S actuation signal on safeguards low steam line 1.4 pressure Criticality attained 28.0 Boron reaches core 33.2 Pressurizer empty 58.2 15.1-21 Revision 1
Consequences of a Main Steam Line Break ctor coolant iodine activity Accident-initiated spike Initial activity equal to the equilibrium operating limit for reactor coolant activity of 1.0 Ci/g dose equivalent I-131 with an assumed iodine spike that increases the rate of iodine release from fuel into the coolant by a factor of 500 (see Appendix 15A). Duration of spike is 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
Preaccident spike An assumed iodine spike that has resulted in an increase in the reactor coolant activity to 60 Ci/g of dose equivalent I-131 (see Appendix 15A) ctor coolant noble gas activity Equal to the operating limit for reactor coolant activity of 280 Ci/g dose equivalent Xe-133 ctor coolant alkali metal activity Design basis activity (see Table 11.1-2) ondary coolant initial iodine and alkali 1% of reactor coolant concentrations at maximum equilibrium al activity conditions ation of accident (hr) 72 ospheric dispersion (/Q) factors See Table 15A-5 in Appendix 15A am generator in faulted loop nitial water mass (lb) 3.32 E+05 Primary to secondary leak rate (lb/hr) 52.25(a) odine partition coefficient 1.0 Steam released (lb)
- 2 hr 3.321E+05
- 72 hr 3.66 E+03 am generator in intact loop Primary to secondary leak rate (lb/hr) 52.25(a) odine partition coefficient 1.0 Steam released (lb)
- 2 hr 3.321E+05
- 72 hr 3.66 E+03 lide data See Table 15A-4 Equivalent to 150 gpd cooled liquid at 62.4 lb/ft3.
15.1-22 Revision 1
Figure 15.1.2-1 Feedwater Control Valve Malfunction Nuclear Power 15.1-23 Revision 1
Figure 15.1.2-2 Feedwater Control Valve Malfunction Loop T 15.1-24 Revision 1
Figure 15.1.2-3 Feedwater Control Valve Malfunction Core Coolant Mass Flow 15.1-25 Revision 1
Figure 15.1.3-1 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback 15.1-26 Revision 1
Figure 15.1.3-2 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback 15.1-27 Revision 1
Figure 15.1.3-3 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback 15.1-28 Revision 1
Figure 15.1.3-4 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback 15.1-29 Revision 1
Figure 15.1.3-5 DNBR Versus Time for 10-percent Step Load Increase, Manual Control and Minimum Moderator Feedback 15.1-30 Revision 1
Figure 15.1.3-6 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback 15.1-31 Revision 1
Figure 15.1.3-7 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback 15.1-32 Revision 1
Figure 15.1.3-8 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback 15.1-33 Revision 1
Figure 15.1.3-9 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback 15.1-34 Revision 1
Figure 15.1.3-10 DNBR Versus Time for 10-percent Step Load Increase, Manual Control and Maximum Moderator Feedback 15.1-35 Revision 1
Figure 15.1.3-11 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback 15.1-36 Revision 1
Figure 15.1.3-12 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback 15.1-37 Revision 1
Figure 15.1.3-13 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback 15.1-38 Revision 1
Figure 15.1.3-14 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback 15.1-39 Revision 1
Figure 15.1.3-15 DNBR Versus Time for 10-percent Step Load Increase, Automatic Control and Minimum Moderator Feedback 15.1-40 Revision 1
Figure 15.1.3-16 Nuclear Power (Fraction of Nominal) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback 15.1-41 Revision 1
Figure 15.1.3-17 Pressurizer Pressure (psia) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback 15.1-42 Revision 1
Figure 15.1.3-18 Pressurizer Water Volume (ft3) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback 15.1-43 Revision 1
Figure 15.1.3-19 Core Average Temperature (°F) Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback 15.1-44 Revision 1
Figure 15.1.3-20 DNBR Versus Time for 10-percent Step Load Increase, Automatic Control and Maximum Moderator Feedback 15.1-45 Revision 1
1.02 1.01 Keff 1 0.99 0.98 0.97 400 420 440 460 480 500 520 540 560 Core Inlet Temperature (Degrees F)
Figure 15.1.4-1 Keff Versus Core Inlet Temperature Steam Line Break Events 15.1-46 Revision 1
Figure 15.1.4-2 Nuclear Power Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-47 Revision 1
Figure 15.1.4-3 Core Heat Flux Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-48 Revision 1
Figure 15.1.4-4 Loop 1 Reactor Coolant Temperatures Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-49 Revision 1
Figure 15.1.4-5 Loop 2 (Faulted Loop) Reactor Coolant Temperatures Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-50 Revision 1
Figure 15.1.4-6 Reactor Coolant System Pressure Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-51 Revision 1
Figure 15.1.4-7 Pressurizer Water Volume Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-52 Revision 1
Figure 15.1.4-8 Core Flow Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-53 Revision 1
Figure 15.1.4-9 Feedwater Flow Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-54 Revision 1
Figure 15.1.4-10 Core Boron Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-55 Revision 1
Figure 15.1.4-11 Steam Pressure Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-56 Revision 1
Figure 15.1.4-12 Steam Flow Transient Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.1-57 Revision 1
Figure 15.1.5-1 Nuclear Power Transient Steam System Piping Feature 15.1-58 Revision 1
Figure 15.1.5-2 Core Heat Flux Transient Steam System Piping Failure 15.1-59 Revision 1
Figure 15.1.5-3 Loop 1 Reactor Coolant Temperatures Steam System Piping Failure 15.1-60 Revision 1
Figure 15.1.5-4 Loop 2 Reactor Coolant Temperatures Steam System Piping Failure 15.1-61 Revision 1
Figure 15.1.5-5 Reactor Coolant System Pressure Transient Steam System Piping Failure 15.1-62 Revision 1
Figure 15.1.5-6 Pressurizer Water Volume Transient Steam System Piping Failure 15.1-63 Revision 1
Figure 15.1.5-7 Core Flow Transient Steam System Piping Failure 15.1-64 Revision 1
Figure 15.1.5-8 Feedwater Flow Transient Steam System Piping Failure 15.1-65 Revision 1
Figure 15.1.5-9 Core Boron Transient Steam System Piping Failure 15.1-66 Revision 1
Figure 15.1.5-10 Steam Pressure Transient Steam System Piping Failure 15.1-67 Revision 1
Figure 15.1.5-11 Steam Flow Transient Steam System Piping Failure 15.1-68 Revision 1
Figure 15.1.5-12 Core Makeup Tank Injection Flow Steam System Piping Failure 15.1-69 Revision 1
Figure 15.1.5-13 Core Makeup Tank Water Volume Steam System Piping Failure 15.1-70 Revision 1
Figure 15.1.6-2 Not Used.
Figure 15.1.6-3 Not Used.
Figure 15.1.6-4 Not Used.
Figure 15.1.6-5 Not Used.
Figure 15.1.6-6 Not Used.
Figure 15.1.6-7 Not Used.
Figure 15.1.6-8 Not Used.
15.1-71 Revision 1
em to remove heat generated in the reactor coolant system are postulated. Analyses are ented in this section for the following events that are identified as more limiting than the others:
Steam pressure regulator malfunction or failure that results in decreasing steam flow Loss of external electrical load Turbine trip Inadvertent closure of main steam isolation valves Loss of condenser vacuum and other events resulting in turbine trip Loss of ac power to the station auxiliaries Loss of normal feedwater flow Feedwater system pipe break above items are considered to be Condition II events, with the exception of a feedwater system break, which is considered to be a Condition IV event.
events in this section where PRHR HX actuation occurs, transients are presented until the HR HX heat removal matches decay heat generation. After that point in time, PRHR HX ormance is driven by the performance of the passive containment cooling systems to control tainment pressure and the ability of the condensate collection features to return condensate he in-containment refueling water storage tank. The performance of these systems, for nded decay heat removal, is described in Subsection 6.3.1.1.1.
radiological consequences of the accidents in this section are bounded by the radiological sequences of a main steam line break (see Subsection 15.1.5).
2.1 Steam Pressure Regulator Malfunction or Failure that Results in Decreasing Steam Flow re are no steam pressure regulators in the AP1000 whose failure or malfunction causes a steam transient.
2.2 Loss of External Electrical Load 2.2.1 Identification of Causes and Accident Description ajor load loss on the plant can result from loss of electrical load due to an electrical system urbance. The ac power remains available to operate plant components such as the reactor lant pumps; as a result, the standby onsite diesel generators do not function for this event.
owing the loss of generator load, an immediate fast closure of the turbine control valves occurs.
automatic turbine bypass system accommodates the excess steam generation. Reactor coolant peratures and pressure do not significantly increase if the turbine bypass system and pressurizer sure control system function properly. If the condenser is not available, the excess steam eration is relieved to the atmosphere. Additionally, main feedwater flow is lost if the condenser is available. For this transient, feedwater flow is maintained by the startup feedwater system.
a loss of electrical load without subsequent turbine trip, no direct reactor trip signal is generated.
plant trips from the protection and safety monitoring system if a safety limit is approached. A tinued steam load of approximately 5 percent exists after total loss of external electrical load ause of the steam demand of plant auxiliaries.
15.2-1 Revision 1
rnal electrical load, the maximum turbine overspeed is not expected to affect the voltage and uency sensors. Any increased frequency to the reactor coolant pump motors results in a slightly eased flow rate and subsequent additional margin to safety limits. For postulated loss of load and sequent turbine-generator overspeed, an overfrequency condition is not seen by the protection safety monitoring system equipment or other safety-related loads. Safety-related loads and the ection and safety monitoring system equipment are supplied from the 120-Vac instrument power ply system, which in turn is supplied from the inverters. The inverters are supplied from a dc bus rgized from batteries or by a regulated ac voltage.
e steam dump valves fail to open following a large loss of load, the steam generator safety valves lift and the reactor may be tripped by the high pressurizer pressure signal, the high pressurizer er level signal, or the overtemperature T signal. This would cause steam generator shell side sure and reactor coolant temperature to increase rapidly. However, the pressurizer safety valves steam generator safety valves are sized to protect the reactor coolant system and steam erator against overpressure for load losses, without assuming the operation of the turbine bypass em, pressurizer spray, or automatic rod cluster control assembly control.
steam generator safety valve capacity is sized to remove the steam flow at the nuclear steam ply system thermal rating from the steam generator, without exceeding 110 percent of the steam em design pressure. The pressurizer safety valve capacity is sized to accommodate a complete of heat sink, with the plant initially operating at the maximum turbine load, along with operation of steam generator safety valves. The pressurizer safety valves can then relieve sufficient steam to ntain the reactor coolant system pressure within 110 percent of the reactor coolant system design sure.
scussion of overpressure protection can be found in WCAP-7769, Revision 1 (Reference 1) and AP-16779 (Reference 8).
ss-of-external-load event is classified as a Condition II event, fault of moderate frequency.
ss-of-external-load event results in a plant transient that is bounded by the turbine trip event lyzed in Subsection 15.2.3. Therefore, a detailed transient analysis is not presented for the loss-xternal-load event.
primary side transient is caused by a decrease in heat transfer capability, from primary to ondary, due to a rapid termination of steam flow to the turbine, accompanied by an automatic uction of feedwater flow (should feedwater flow not be reduced, a larger heat sink is available and transient is less severe). Reduction of steam flow to the turbine following a loss-of-external load nt occurs due to automatic fast closure of the turbine control valves. Following a turbine trip nt, termination of steam flow occurs via turbine stop valve closure, which occurs in approximately seconds. The transient in primary pressure, temperature, and water volume is less severe for loss-of-external-load event than for the turbine trip due to a slightly slower loss of heat transfer ability.
protection available to mitigate the consequences of a loss-of-external-load event is the same as for a turbine trip, as listed in Table 15.0-6.
15.2-2 Revision 1
uping of events. The results of the turbine trip event analysis bound those expected for the loss-xternal-load event, as discussed in Subsection 15.2.2.1.
nt systems and equipment that may be required to function in order to mitigate the effects of a plete loss of load are discussed in Subsection 15.0.8 and listed in Table 15.0-6.
protection and safety monitoring system may be required to terminate core heat input and to ent departure from nucleate boiling (DNB). Depending on the magnitude of the load loss, surizer safety valves and/or steam generator safety valves may open to maintain system sures below allowable limits. No single active failure prevents operation of any system required nction. Normal plant control systems and engineered safety systems are not required to function.
passive residual heat removal (PRHR) system may be automatically actuated following a loss of n feedwater, further mitigating the effects of the transient.
2.2.3 Conclusions ed on results obtained for the turbine trip event and considerations described in section 15.2.2.1, the applicable Standard Review Plan, Subsection 15.2.1, evaluation criteria for ss-of-external-load event, are met (see Subsection 15.2.3).
2.3 Turbine Trip 2.3.1 Identification of Causes and Accident Description turbine stop valves close rapidly (about 0.15 seconds) on loss of trip fluid pressure actuated by of a number of possible turbine trip signals. Turbine trip initiation signals include:
Generator trip Low condenser vacuum Loss of lubricating oil Turbine thrust bearing failure Turbine overspeed Manual trip Reactor trip n initiation of stop valve closure, steam flow to the turbine stops abruptly. Sensors on the stop es detect the turbine trip and initiate turbine bypass. The loss of steam flow results in a rapid ease in secondary system temperature and pressure, with a resultant primary system transient, cribed in Subsection 15.2.2.1, for the loss-of-external-load event. A slightly more severe transient urs for the turbine trip event due to the rapid loss of steam flow caused by the abrupt valve ure.
automatic turbine bypass system accommodates up to 40 percent of rated steam flow. Reactor lant temperatures and pressure do not increase significantly if the turbine bypass system and surizer pressure control system are functioning properly. If the condenser is not available, the ess steam generation is relieved to the atmosphere and main feedwater flow is lost. For this ation, feedwater flow is maintained by the startup feedwater system to provide adequate residual decay heat removal capability. Should the turbine bypass system fail to operate, the steam erator safety valves may lift to provide pressure control. See Subsection 15.2.2.1 for a further ussion of the transient.
15.2-3 Revision 1
r events which result in a turbine trip. As such, this event is analyzed and presented in section 15.2.3.2.
2.3.2 Analysis of Effects and Consequences 2.3.2.1 Method of Analysis is analysis, the behavior of the unit is evaluated for a complete loss of steam load from percent of full power, without rapid power reduction, primarily to show the adequacy of the sure-relieving devices, and to demonstrate core protection margins. The turbine is assumed to without actuating the rapid power reduction system. This assumption delays reactor trip until ditions in the reactor coolant system result in a trip due to other signals. Thus, the analysis umes a bounding transient. In addition, no credit is taken for the turbine bypass system. Main water flow is terminated at the time of turbine trip, with no credit taken for startup feedwater or PRHR heat exchanger (except for long-term recovery) to mitigate the consequences of the sient.
eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, analyses are performed to luate the effects produced by a possible consequential loss of offsite power during a complete of steam load. As discussed in Subsection 15.0.14, the loss of offsite power is considered as a ct consequence of a turbine trip occurring while the plant is operating at power. The primary effect e loss of offsite power is to cause the reactor coolant pumps to coast down.
turbine trip transients are analyzed by using the computer program LOFTRAN (Reference 2).
program simulates the neutron kinetics, reactor coolant system, pressurizer, pressurizer safety es, pressurizer spray, steam generator, and steam generator safety valves. The program putes pertinent plant variables, including temperatures, pressures, and power level.
e turbine trip analyses, that include a primary coolant flow coastdown caused by a consequential of offsite power, a combination of three computer codes is used to perform the departure from leate boiling ratio (DNBR) analyses. First, the LOFTRAN code (References 2 and 6) is used to ulate the plant system transient. The FACTRAN code (Reference 7) is then used to calculate the heat flux based on nuclear power and reactor coolant flow from LOFTRAN. Finally, the RE-01 code (see Section 4.4) is used to calculate the DNBR using heat flux from FACTRAN and from LOFTRAN.
major assumptions used in the analysis are summarized below.
al Operating Conditions sets of initial operating conditions are used. Cases performed to evaluate the minimum DNBR ined are analyzed using the revised thermal design procedure. Initial core power, reactor coolant perature, and pressure are assumed to be at their nominal values consistent with steady-state power operation. Uncertainties in initial conditions are included in the DNBR limit as described in AP-11397-P-A (Reference 5).
es performed to evaluate the maximum calculated RCS pressure include uncertainties on the al conditions. Initial core power, reactor coolant temperature, and pressure are assumed to be at nominal full-power values plus or minus uncertainties. The direction of the uncertainties is chosen aximize the RCS pressure.
15.2-4 Revision 1
Minimum reactivity feedback - A least-negative moderator temperature coefficient and a least-negative Doppler-only power coefficient are assumed (see Figure 15.0.4-1).
Maximum reactivity feedback - A conservatively large negative moderator temperature coefficient and a most-negative Doppler-only power coefficient are assumed (see Figure 15.0.4-1).
ctor Control m the standpoint of the maximum pressures attained, it is conservative to assume that the reactor manual control. If the reactor is in automatic control, the control rod banks move prior to trip and uce the severity of the transient.
am Release credit is taken for the operation of the turbine bypass system or steam generator power-operated f valves. The steam generator pressure rises to the safety valve setpoint where steam release ugh safety valves limits secondary steam pressure at the setpoint value.
ssurizer Spray cases for both the minimum and maximum reactivity feedback cases are analyzed:
Full credit is taken for the effect of pressurizer spray in reducing or limiting the coolant pressure. Safety valves are also available.
No credit is taken for the effect of pressurizer spray in reducing or limiting the coolant pressure. Safety valves are operable.
dwater Flow n feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No it is taken for startup feedwater flow or the PRHR heat exchanger, because a stabilized plant dition is reached before initiation of the startup feedwater or the PRHR heat exchanger is mally assumed to occur. The startup feedwater flow or PRHR heat exchanger remove core decay t following plant stabilization.
ctor Trip ctor trip is actuated by the first reactor trip setpoint reached, with no credit taken for the rapid er reduction on the turbine trip. Trip signals are expected due to high pressurizer pressure, rtemperature T, low RCP speed, high pressurizer water level, and low steam generator water l.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3. Plant systems equipment that may be required to function in order to mitigate the effects of a turbine trip event discussed in Subsection 15.0.8 and listed in Table 15.0-6.
protection and safety monitoring system may be required to function following a turbine trip.
ssurizer safety valves and/or steam generator safety valves may be required to open to maintain em pressures below allowable limits. No single active failure prevents operation of systems uired to function. Cases are analyzed, both with and without the operation of pressurizer spray, to rmine the worst case for presentation.
15.2-5 Revision 1
trical grid following a turbine trip during the event. The grid is assumed to remain stable for conds following the turbine trip. In the analysis for the complete loss of steam load, the event is ated by a turbine trip. Therefore, offsite power is assumed to be lost 3 seconds after the start of event. For the loss of steam load analysis, the primary impact of the loss of offsite power is a stdown of the reactor coolant pumps.
2.3.2.2 Results transient responses for a turbine trip from 100 percent of full-power operation are shown for eight es. The eight analysis cases are performed assuming minimum and maximum reactivity back, with and without credit for pressurizer spray, and with and without offsite power available.
results of the analyses are shown in Figures 15.2.3-1 through 15.2.3-26. The calculated uence of events for the accident is shown in Table 15.2-1.
imum Reactivity Feedback, Without Pressurizer Spray, With and Without Offsite Power ilable results for these cases are shown in Figures 15.2.3-15 through 15.2.3-20. In the case with offsite er available, the reactor is tripped by the high pressurizer pressure trip function. The pressure ty valves are actuated in this case and maintain the reactor coolant system pressure below percent of the design value. The DNB design basis defined in Section 4.4 is met for this case.
fsite power is lost, the reactor is tripped by the low reactor coolant pump speed reactor trip tion. Offsite power is assumed to be lost 3 seconds after turbine trip. This causes a reduction in tor coolant system flow, which is illustrated in Figure 15.2.3-20. The DNB transient is similar to, bounded by, the minimum reactivity feedback case with pressurizer spray and without offsite er. The DNB design basis defined in Section 4.4 is met for this case. The pressurizer safety es actuate in this case and maintain the reactor coolant system pressure below 110 percent of design value. Pressurizer pressure for this case is shown in Figure 15.2.3-16. Note that the with without offsite power cases have different assumptions regarding initial pressure. The initial sure assumptions were based upon sensitivities that were run. With respect to maximum reactor lant system pressure, this case is the most limiting for complete loss of steam load cases.
imum Reactivity Feedback, With Pressurizer Spray, With and Without Offsite Power ilable res 15.2.3-1 through 15.2.3-7 show the transient responses with and without offsite power ilable. In the case with offsite power available, the reactor is tripped by the high pressurizer sure trip function. Pressurizer pressure is shown in Figure 15.2.3-2, and the pressure within the tor coolant system is maintained below 110 percent of the design value. The DNBR for the case offsite power is shown in Figure 15.2.3-6, and the DNB design basis defined in Section 4.4 is case without offsite power is tripped by the low reactor coolant pump speed trip function. The B design basis defined in Section 4.4 is met. This case is the most limiting case with respect to B margin of the loss of steam load cases. The pressurizer pressure is shown in Figure 15.2.3-2, the pressure within the reactor coolant system is maintained below 110 percent of the design e.
15.2-6 Revision 1
ilable. In the case with offsite power available, the reactor is tripped by the high pressurizer sure trip function. The pressure safety valves are actuated in this case and maintain the reactor lant system pressure below 110 percent of the design value. Pressurizer pressure is shown in re 15.2.3-9. The transient DNBR for the case with offsite power available is shown in re 15.2.3-13. The DNB design basis defined in Section 4.4 is met for this case.
case without offsite power is tripped by the low reactor coolant pump speed trip function. The B transient is similar to, and bounded by, the minimum feedback case with pressurizer spray and out offsite power. The DNB design basis defined in Section 4.4 is met. The pressurizer pressure hown in Figure 15.2.3-9, and the pressure within the reactor coolant system is maintained below percent of the design value.
ximum Reactivity Feedback, Without Pressurizer Spray, With and Without Offsite wer Available res 15.2.3-21 through 15.2.3-26 show the transient responses with and without offsite power ilable. In the case with offsite power available, the reactor is tripped by the high pressurizer sure function.
ssurizer pressure is shown in Figure 15.2.3-22, and the pressure within the reactor coolant em is maintained below 110 percent of the design value. Note that the with and without power es have different assumptions regarding initial pressure. The initial pressure assumptions were ed upon sensitivities that were run. The DNB design basis defined in Section 4.4 is met for this e.
case without offsite power is tripped by the low reactor coolant pump speed trip function. The B transient is similar to, and bounded by, the minimum feedback case with pressurizer spray and out offsite power. The DNB design basis defined in Section 4.4 is met. The pressurizer pressure hown in Figure 15.2.3-22, and the pressure within the reactor coolant system is maintained below percent of the design value.
2.3.3 Conclusions ults of the analyses show that a turbine trip presents no challenge to the integrity of the reactor lant system or the main steam system. Pressure-relieving devices incorporated in the two ems are adequate to limit the maximum pressures to within the design limits.
analyses show that the predicted DNBR is greater than the design limit at any time during the sient. Thus, the departure from nucleate boiling design basis, as described in Section 4.4, is met.
2.4 Inadvertent Closure of Main Steam Isolation Valves vertent closure of the main steam isolation valves results in a turbine trip with no credit taken for turbine bypass system. Turbine trips are discussed in Subsection 15.2.3.
2.5 Loss of Condenser Vacuum and Other Events Resulting in Turbine Trip s of condenser vacuum is one of the events that can cause a turbine trip. Turbine trip initiating nts are described in Subsection 15.2.3. A loss of condenser vacuum prevents the use of steam p to the condenser. Because steam dump is assumed to be unavailable in the turbine trip lysis, no additional adverse effects result if the turbine trip is caused by loss of condenser 15.2-7 Revision 1
turbine overspeed condition, are discussed in Subsection 15.2.2.1 and are not a concern for this of event.
2.6 Loss of ac Power to the Plant Auxiliaries 2.6.1 Identification of Causes and Accident Description loss of power to the plant auxiliaries is caused by a complete loss of the offsite grid accompanied turbine-generator trip. The onsite standby ac power system remains available but is not credited itigate the accident.
m the decay heat removal point of view, in the long term this transient is more severe than the ine trip event analyzed in Subsection 15.2.3 because, for this case, the decrease in heat removal he secondary system is accompanied by a reactor coolant flow coastdown, which further reduces capacity of the primary coolant to remove heat from the core. The reactor will trip:
Upon reaching one of the trip setpoints in the primary or secondary systems as a result of the flow coastdown and decrease in secondary heat removal.
Due to the loss of power to the control rod drive mechanisms as a result of the loss of power to the plant.
owing a loss of ac power with turbine and reactor trips, the sequence described below occurs:
Plant vital instruments are supplied from the Class 1E and uninterruptable power supply.
As the steam system pressure rises following the trip, the steam generator power-operated relief valves may be automatically opened to the atmosphere. The condenser is assumed not to be available for turbine bypass. If the steam flow rate through the power-operated relief valves is not available, the steam generator safety valves may lift to dissipate the sensible heat of the fuel and coolant plus the residual decay heat produced in the reactor.
The onsite standby power system, if available, supplies ac power to the selected plant non-safety loads.
As the no-load temperature is approached, the steam generator power-operated relief valves (or safety valves, if the power-operated relief valves are not available) are used to dissipate the residual decay heat and to maintain the plant at the hot shutdown condition if the startup feedwater is available to supply water to the steam generators.
If startup feedwater is not available, the PRHR heat exchanger is actuated.
ing a plant transient, core decay heat removal is normally accomplished by the startup feedwater em if available, which is started automatically when low levels occur in either steam generator. If system is not available, emergency core decay heat removal is provided by the PRHR heat hanger. The PRHR heat exchanger is a C-tube heat exchanger connected, through inlet and et headers, to the reactor coolant system. The inlet to the heat exchanger is from the reactor lant system hot leg, and the return is to the steam generator outlet plenum. The heat exchanger is ted above the core to provide natural circulation flow when the reactor coolant pumps are not rating. The IRWST provides the heat sink for the heat exchanger. The PRHR heat exchanger, in junction with the passive containment cooling system, provides core cooling and maintains 15.2-8 Revision 1
em) returns to the IRWST, maintaining fluid level for the PRHR heat exchanger heat sink. The lysis shows that the natural circulation flow in the reactor coolant system following a loss of ower event is sufficient to remove residual heat from the core.
n the loss of power to the reactor coolant pumps, coolant flow necessary for core cooling and the oval of residual heat is maintained by natural circulation in the reactor coolant and PRHR loops.
ss of ac power to the plant auxiliaries is a Condition II event, a fault of moderate frequency. This nt is more limiting with respect to long-term heat removal than the turbine trip initiated decrease in ondary heat removal without loss of ac power, which is discussed in Subsection 15.2.3. A loss of te power to the plant auxiliaries will also result in a loss of normal feedwater.
plant systems and equipment available to mitigate the consequences of a loss of ac power event discussed in Subsection 15.0.8 and listed in Table 15.0-6.
2.6.2 Analysis of Effects and Consequences 2.6.2.1 Method of Analysis analysis is performed to demonstrate the adequacy of the protection and safety monitoring em, the PRHR heat exchanger, and the reactor coolant system natural circulation capability in oving long-term (approximately 36,000 seconds) decay heat. This analysis also demonstrates adequacy of these systems in preventing excessive heatup of the reactor coolant system with sible reactor coolant system overpressurization or loss of reactor coolant system water.
odified version of the LOFTRAN code (Reference 2), described in WCAP-15644 (Reference 6),
sed to simulate the system transient following a plant loss of offsite power. The simulation cribes the plant neutron kinetics and reactor coolant system, including the natural circulation, surizer, and steam generator system responses. The digital program computes pertinent ables, including the steam generator level, pressurizer water level, and reactor coolant average perature.
assumptions used in this analysis minimize the energy removal capability of the PRHR heat hanger and maximize the coolant system expansion.
transient response of the plant following a loss of ac power to plant auxiliaries is similar to the of normal feedwater flow accident (see Subsection 15.2.7), except that power is assumed to be to the reactor coolant pumps at the time of the reactor trip.
assumptions used in the analysis are as follows:
The plant is initially operating at 102 percent of the design power rating with initial reactor coolant temperature 7°F below the nominal value and the pressurizer pressure 50 psi above the nominal value. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
Core residual heat generation is based on ANSI 5.1 (Reference 3). ANSI 5.1 is a conservative representation of the decay energy release rates.
Reactor trip occurs on steam generator low level (narrow range). Offsite power is assumed to be lost at the time of reactor trip. This is more conservative than the case in which offsite 15.2-9 Revision 1
A heat transfer coefficient is assumed in the steam generator associated with reactor coolant system natural circulation flow conditions following the reactor coolant pump coastdown.
The PRHR heat exchanger is actuated by the low steam generator water level (narrow range coincident with low start up feed water flow).
For the loss of ac power to the station auxiliaries, the only safety function required is core decay heat removal. That is accomplished by the PRHR heat exchanger. One of two parallel valves in the PRHR outlet line is assumed to fail to open. This is the worst single failure.
Secondary system steam relief is achieved through the steam generator safety valves.
The pressurizer safety valves are assumed to function.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3.
nt systems and equipment necessary to mitigate the effects of a loss of ac power to the station iliaries are discussed in Subsection 15.0.8 and listed in Table 15.0-6. Normal reactor control ems are not required to function. The protection and safety monitoring system is required to tion following a loss of ac power. The PRHR heat exchanger is required to function with a imum heat transfer capability. No single active failure prevents operation of any system required nction.
DNB analysis is not specifically addressed for this event since, from the point of view of DNBR sient, the loss of ac power to auxiliaries is similar and bounded by the Turbine Trip event lyzed in Subsection 15.2.3. In fact, the Turbine Trip is analyzed assuming that, following the ine trip, a loss of ac power occurs with three seconds delay. This results in the coastdown of tor coolant pumps, but, in the analysis, reactor trip on the loss of power is not assumed. The tor trip is assumed to occur on an RCP Underspeed set point and rods begin to drop with more one second delay from the pumps coastdown.
loss of ac power occurs as an initiating event, the first result would be the immediate reactor trip the concomitant coastdown of the reactor coolant pumps. The calculated DNBR for such an nt would be the same or higher than predicted for the Complete Loss of Reactor Coolant System as presented in 15.3.2.
2.6.2.2 Results transient response of the reactor coolant system following a loss of ac power to the plant iliaries is shown in Figures 15.2.6-1 through 15.2.6-12. The calculated sequence of events for this nt is listed in Table 15.2-1.
LOFTRAN code results show that the natural circulation flow and the PRHR system are cient to provide adequate core decay heat removal following reactor trip and reactor coolant p coastdown.
ediately following the reactor trip, the heat transfer capability of the PRHR heat exchanger and steam generator heat extraction rate are sufficient to slowly cool down the plant. The cooldown tinues until a low Tcold S signal is reached. The S signal actuates the core makeup tanks.
ing this transient, the core makeup tanks operate in water recirculation mode. The cold borated er injected by the core makeup tanks accelerates the cooldown of the plant. The core makeup 15.2-10 Revision 1
he plant cools down, the heat removal capacity of the PRHR heat exchanger is lowered. When heat removal rate from the reactor coolant system, due to the core makeup tank injection and the HR heat exchanger, decreases below the core decay heat produced, the reactor coolant system ins heating up again. As the reactor coolant system temperature is elevated, the heat removal acity of the PRHR heat exchanger increases. The reactor coolant system temperature slowly eases until the heat removal rate of the PRHR heat exchanger matches the core decay heat duced.
ssurizer safety valves open to discharge steam to containment and reclose later in the transient n the heat removal rate of the PRHR heat exchanger exceeds the decay heat production rate.
capacity of the PRHR heat exchanger is sufficient to avoid water relief through the pressurizer ty valves.
calculated sequence of events for this accident is listed in Table 15.2-1. As shown in res 15.2.6-5 and 15.2.6-6, in the long-term the plant starts a slow cooldown driven by the PRHR t exchanger. Plant procedures may be followed to further cool down the plant.
2.6.3 Conclusions ults of the analysis show that for the loss of ac power to plant auxiliaries event, all safety criteria met. PRHR heat exchanger capacity is sufficient to prevent water relief through the pressurizer ty valves.
analysis demonstrates that sufficient long-term reactor coolant system heat removal capability ts, via natural circulation and the PRHR heat exchanger, following reactor coolant pump stdown to prevent fuel or cladding damage and reactor coolant system overpressure.
2.7 Loss of Normal Feedwater Flow 2.7.1 Identification of Causes and Accident Description ss of normal feedwater (from pump failures, valve malfunctions, or loss of ac power sources) lts in a reduction in the capability of the secondary system to remove the heat generated in the tor core. If startup feedwater is not available, the safety-related PRHR heat exchanger is matically aligned by the protection and safety monitoring system to remove decay heat.
mall secondary system break can affect normal feedwater flow control, causing low steam erator levels prior to protective actions for the break. This scenario is addressed by the umptions made for the feedwater system pipe break (see Subsection 15.2.8).
following occurs upon loss of normal feedwater (assuming main feedwater pump fails or valve functions):
The steam generator water inventory decreases as a consequence of the continuous steam supply to the turbine. The mismatch between the steam flow to the turbine and the feedwater flow leads to the reactor trip on a low steam generator water level signal. The same signal also actuates the startup feedwater system (see Subsection 15.2.6.1).
As the steam system pressure rises following the trip, the steam generator power-operated relief valves are automatically opened to the atmosphere. The condenser is assumed to be 15.2-11 Revision 1
As the no-load temperature is approached, the steam generator power-operated relief valves (or safety valves, if the power-operated relief valves are not available) are used to dissipate the decay heat and to maintain the plant at the hot shutdown condition, if the startup feedwater is used to supply water to the steam generator.
If startup feedwater is not available, the PRHR heat exchanger is actuated on either a low steam generator water level (narrow range), coincident with a low startup feedwater flow rate signal or a low steam generator water level (wide range) signal. The PRHR heat exchanger transfers the core decay heat and sensible heat to the IRWST so that core heat removal is uninterrupted following a loss of normal and startup feedwater (see Subsection 15.2.6).
ss-of-normal-feedwater event is classified as a Condition II event, a fault of moderate frequency.
2.7.2 Analysis of Effects and Consequences analysis of the system transient is presented below to show that, following a loss of normal water, the PRHR heat exchanger is capable of removing the stored and decay heat to prevent er overpressurization of the reactor coolant system or loss of water from the reactor coolant em.
2.7.2.1 Method of Analysis analysis using a modified version of the LOFTRAN code (Reference 2), described in AP-15644 (Reference 6), is performed to obtain the plant transient following a loss of normal water. The simulation describes the neutron kinetics, reactor coolant system (including the ral circulation), pressurizer, and steam generators. The program computes pertinent variables, uding the steam generator level, pressurizer water level, and reactor coolant average perature.
assumptions used in the analysis are as follows:
The plant is initially operating at 102 percent of the design power rating. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
Reactor trip occurs on steam generator low (narrow range) level.
The only safety function required is the core decay heat removal that is carried by the PRHR heat exchanger; therefore, the worst single failure is assumed to occur in the PRHR heat exchanger. The actuation of the PRHR heat exchanger requires the opening of one of the two fail-open valves arranged in parallel at the PRHR heat exchanger discharge. Because no single failure can be assumed that impairs the opening of both valves, the failure of a single valve is assumed.
The PRHR heat exchanger is actuated by the low steam generator water level narrow range signal, coincident with low start up feedwater flow.
Secondary system steam relief is achieved through the steam generator safety valves.
15.2-12 Revision 1
loss of normal feedwater analysis is performed to demonstrate the adequacy of the protection safety monitoring system and the PRHR heat exchanger in removing long-term decay heat and enting excessive heatup of the reactor coolant system with possible resultant reactor coolant em overpressurization or loss of reactor coolant system water. The assumptions used in this lysis minimize the energy removal capability of the system, and maximize the coolant system ansion.
the loss of normal feedwater transient, the reactor coolant volumetric flow remains at its normal e and the reactor trips via the low steam generator narrow range level trip. The reactor coolant ps continue to run until automatically tripped when the core makeup tanks are actuated.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3.
nt systems and equipment necessary to mitigate the effects of a loss of normal feedwater dent are discussed in Subsection 15.0.8 and listed in Table 15.0-6. Normal reactor control ems are not required to function. The protection and safety monitoring system is required to tion following a loss of normal feedwater. The PRHR heat exchanger is required to function with inimum heat transfer capability. No single active failure prevents operation of any system to orm its required function. A discussion of anticipated transients without scram considerations is ented in Section 15.8.
2.7.2.2 Results res 15.2.7-1 through 15.2.7-10 show the significant plant parameters following a loss of normal water.
r to reactor trip and the insertion of the rods into the core, the loss of normal feedwater transient e same as the transient response presented in Subsection 15.2.6 for the loss of ac power to plant iliaries. The DNB results, presented in Figure 15.2.6-12 for the loss of ac power to plant iliaries, are also applicable for a loss of normal feedwater and demonstrate that the DNB design is is met.
owing the reactor and turbine trip from full load, the water level in the steam generators falls due e reduction of steam generator void fraction. Steam flow through the safety valves continues to ipate the stored and core decay heat.
capacity of the PRHR heat exchanger, when the reactor coolant pumps are operating, is much er than the decay heat, and in the first part of the transient, the reactor coolant system is cooled n and the pressure decreases.
cooldown continues until a low Tcold S signal is eventually reached. The S signal actuates the makeup tanks. During this transient, the core makeup tanks operate in water recirculation mode.
cold borated water injected by the core makeup tanks accelerates the cooldown of the plant. The makeup tank flow slowly decreases as the core makeup tank fluid temperature increases due to er recirculation.
he plant cools down, the heat removal capacity of the passive residual heat exchanger is ered. The heat removal rate from the reactor coolant system, due to the core makeup tank ction and the PRHR heat exchanger, then decreases below the core decay heat produced. The tor coolant system then begins heating up again. As the reactor coolant system temperature is ated, the heat removal capacity of the PRHR heat exchanger increases again. The reactor 15.2-13 Revision 1
capacity of the PRHR heat exchanger is sufficient to avoid water relief through the pressurizer ty valves.
calculated sequence of events for this accident is listed in Table 15.2-1. As shown in res 15.2.7-3 and 15.2.7-4, the plant starts a slow cooldown driven by the PRHR heat exchanger.
nt procedures may be followed to further cool down the plant.
2.7.3 Conclusions ults of the analysis show that a loss of normal feedwater does not adversely affect the core, the tor coolant system, or the steam system. The heat removal capacity of the PRHR heat hanger is such that reactor coolant water is not relieved from the pressurizer safety valves. DNBR ays remains above the design limit values, and reactor coolant system and steam generator sures remain below 110 percent of their design values.
2.8 Feedwater System Pipe Break 2.8.1 Identification of Causes and Accident Description ajor feedwater line rupture is a break in a feedwater line large enough to prevent the addition of cient feedwater to the steam generators in order to maintain shell-side fluid inventory in the m generators. If the break is postulated in a feedwater line between the check valve and the m generator, fluid from the steam generator may also be discharged through the break. (A break tream of the feedwater line check valve would affect the plant only as a loss of feedwater. This e is covered by the evaluation in Subsections 15.2.6 and 15.2.7.)
ending upon the size of the break and the plant operating conditions at the time of the break, the ak could cause either a reactor coolant system cooldown (by excessive energy discharge through break) or a reactor coolant system heatup. Potential reactor coolant system cooldown resulting a secondary pipe rupture is evaluated in Subsection 15.1.5. Therefore, only the reactor coolant em heatup effects are evaluated for a feedwater line rupture in this subsection.
feedwater line rupture reduces the ability to remove heat generated by the core from the reactor lant system for the following reasons:
Feedwater flow to the steam generators is reduced. Because feedwater is subcooled, its loss may cause reactor coolant temperatures to increase prior to reactor trip.
Fluid in the steam generator may be discharged through the break and would not be available for decay heat removal after trip.
The break may be large enough to prevent the addition of main feedwater after trip.
ajor feedwater line rupture is classified as a Condition IV event.
severity of the feedwater line rupture transient depends on a number of system parameters, uding the break size, initial reactor power, and the functioning of various control and safety-ted systems. Sensitivity studies presented in WCAP-9230 (Reference 4) illustrate that the most ing feedwater line rupture is a double-ended rupture of the largest feedwater line. At the inning of the transient, the main feedwater control system is assumed to malfunction due to an erse environment. Interactions between the break and the main feedwater control system result 15.2-14 Revision 1
ure of the feedwater line is assumed such that the faulted steam generator blows down through break and no main feedwater is delivered to the intact steam generator. These assumptions servatively bound the most limiting feedwater line rupture that can occur. Analysis is performed at power assuming the loss of offsite power at the time of the reactor trip. This is more conservative the case where power is lost at the initiation of the event. The case with offsite power available ot presented because, due to the fast core makeup tanks actuation (on an S signal generated by low steam line pressure), the reactor coolant pumps are tripped by the protection and safety itoring system a few seconds after the reactor trip. The only difference between the cases with without offsite power available is the operating status of the reactor coolant pumps.
following provides the protection for a main feedwater line rupture:
A reactor trip on any of the following four conditions:
- High pressurizer pressure
- Overtemperature T
- High-3 pressurizer water level
- Low steam generator water level in either steam generator
- S signals from either of the following:
z Two out of four low steam line pressure in either steam generator z Two out of four high containment pressure (high-2) er to Sections 7.1 and 7.2 for a description of the actuation system.
PRHR heat exchanger functions to:
Provide a passive method for decay heat removal. The heat exchanger is a C-tube type, located inside the IRWST. The heat exchanger is above the reactor coolant system to provide natural circulation of the reactor coolant. Operation of the PRHR heat exchanger is initiated by the opening of one of the two parallel power-operated valves at the PRHR heat exchanger cold leg.
Prevent substantial overpressurization of the reactor coolant system (less than 110 percent of design pressures).
Maintain sufficient liquid in the reactor coolant system so that the core remains in place, and geometrically intact, with no loss of core cooling capability.
er to Subsection 6.3.2.2.5 for a description of the PRHR heat exchanger.
2.8.2 Analysis of Effects and Consequences 2.8.2.1 Method of Analysis analysis using a modified version, described in WCAP-15644 (Reference 6), of the LOFTRAN e (Reference 2) is performed to determine the plant transient following a feedwater line rupture.
code describes the reactor thermal kinetics, reactor coolant system (including natural ulation), pressurizer, steam generators, and feedwater system responses and computes pertinent ables, including the pressurizer pressure, pressurizer water level, and reactor coolant average perature.
15.2-15 Revision 1
The plant is initially operating at 102 percent of the design plant rating. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
Initial reactor coolant average temperature is 6.5°F above the nominal value, and the initial pressurizer pressure is 50 psi below its nominal value.
The pressurizer spray is turned on.
Initial pressurizer level is at a conservative maximum value and a conservative initial steam generator water level is assumed in both steam generators.
No credit is taken for the high pressurizer pressure reactor trip.
At the start of the transient, interaction between the break in the feedline and the main feedwater control system is assumed to result in a complete loss of feedwater flow to both steam generators. No feedwater flow is delivered to or lost through the steam generator nozzles.
Reactor trip is assumed to be initiated when the low steam generator narrow range level setpoint is reached on the ruptured steam generator.
After reactor trip, the faulted steam generator blows down through a double-ended break area of 1.755 ft2. A saturated liquid discharge is assumed until all the water inventory is discharged from the faulted steam generator. This minimizes the heat removal capability of the faulted steam generator and maximizes the resultant heatup of the reactor coolant. No feedwater flow is assumed to be delivered to the intact steam generator.
The PRHR heat exchanger is actuated by the low steam generator water level (wide range) signal. A 15-second delay is assumed following the low level signal to allow time for the alignment of PRHR heat exchanger valves.
Credit is taken for heat energy deposited in reactor coolant system metal during the reactor coolant system heatup.
No credit is taken for charging or letdown.
Pressurizer safety valve setpoint is assumed to be at its minimum value.
Steam generator heat transfer area is assumed to decrease as the shell-side liquid inventory decreases. The heat transfer remains approximately 100 percent in the faulted steam generator until the liquid mass reaches about 11 percent. The heat transfer is then reduced to 0 percent with the liquid inventory.
Conservative core residual heat generation is assumed based upon long-term operation at the initial power level preceding the trip (Reference 3).
15.2-16 Revision 1
- High pressurizer pressure
- Overtemperature T
- High pressurizer level
- High containment pressure PRHR heat exchanger is initiated if the steam generator water level drops to the low steam erator level (wide range). Similarly, receipt of a low steam line pressure signal in at least one m line initiates a steam line isolation signal that closes all main steam line and feed line isolation es. This signal also gives an S signal that initiates flow of cold borated water from the core eup tanks to the reactor coolant system.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3.
plant control system is not assumed to function in order to mitigate the consequences of the nt. The protection and safety monitoring system is required to function following a feedwater line ure as analyzed here. No single active failure prevents operation of this system.
engineered safety features assumed to function are the PRHR heat exchanger, core makeup
, and steam line isolation valves. The single failure assumed is the failure of one of the two allel discharge valves in the PRHR outlet line (see Table 15.0-7).
the case without offsite power, there is a flow coastdown until flow in the loops reaches the ral circulation value. The natural circulation capability of the reactor coolant system is shown Subsection 15.2.6) to be sufficient to remove core decay heat following reactor trip for the loss c power transient. Pump coastdown characteristics are demonstrated in Subsections 15.3.1 and
.2 for single and multiple reactor coolant pump trips, respectively.
escription and analysis of the core makeup tank is provided in Subsection 6.3.2.2.1. The PRHR t exchanger is described in Subsection 6.3.2.2.5.
2.8.2.2 Results culated plant parameters following a major feedwater line rupture are shown in Figures 15.2.8-1 ugh 15.2.8-10. The calculated sequence of events for the case analyzed is listed in Table 15.2-1.
results presented in Figures 15.2.8-5 and 15.2.8-7 show that pressures in the reactor coolant em and main steam system remain below 110 percent of the respective design pressure.
ssurizer pressure decreases after reactor trip on the low steam generator water level 3 seconds) due to the loss of heat input.
e first part of the transient, due to the conservative analysis assumptions, the system response wing the feedwater line rupture is similar to the loss of ac power to the station auxiliaries bsection 15.2.6). The DNB results, presented in Figure 15.2.6-12 for the loss of ac power to plant iliaries, are also applicable to a feedwater system pipe break and demonstrate that the DNB ign basis is met.
r the trip, the core makeup tanks are actuated (95 seconds) on low steam line pressure in the ured loop while the PRHR heat exchanger is actuated on a low steam generator water level wide ge (90.1 seconds).
15.2-17 Revision 1
ssurizer safety valves open due to the mismatch between decay heat and the heat transfer ability of the PRHR heat exchanger. In the first part of the transient, there is a cooling effect due to core makeup tanks that inject cold water into the reactor coolant system and receive hot water the cold leg. This effect decreases due to the heatup of the core makeup tanks from rculation flow. Also, the injection driving head is lowered as the core makeup tanks heat up.
ctor coolant system temperatures are low (approximately 510°F at about 2,500 seconds) and, in condition, the PRHR heat exchanger cannot remove the entire decay heat load. Reactor coolant em temperatures increase until an equilibrium between decay heat power and heat absorbed by PRHR heat exchanger is reached. After about 11,300 seconds, the heat transfer capability of the HR heat exchanger exceeds the decay heat power and the reactor coolant system temperatures, sure, and pressurizer water volumes start to steadily decrease. Core cooling capability is ntained throughout the transient because reactor coolant system inventory is increasing due to makeup tank injection.
2.8.3 Conclusions ults of the analyses show that for the postulated feedwater line rupture, the capacity of the PRHR t exchanger is adequate to remove decay heat, to prevent overpressurizing the reactor coolant em, and to maintain the core cooling capability. Radioactivity doses from ruptures of the tulated feedwater lines are less than those presented for the postulated main steam line break.
Standard Review Plan, Subsection 15.2.8, evaluation criteria are therefore met.
2.9 Combined License Information section contained no requirement for additional information.
2.10 References Cooper, L., Miselis, V., and Starek, R. M., Overpressure Protection for Westinghouse Pressurized Water Reactors, WCAP-7769, Revision 1, June 1972. (Also letter NS-CE-622, C. Eicheldinger (Westinghouse) to D. B. Vassallo (NRC), additional information on WCAP-7769, Revision 1, April 16, 1975).
Burnett, T. W. T., et al., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984.
American National Standard for Decay Heat Power in Light Water Reactors, ANSI/
ANS-5.1-1979, August 1979.
Lang, G. E., and Cunningham, J. P., Report on the Consequences of a Postulated Main Feedline Rupture, WCAP-9230 (Proprietary) and WCAP-9231 (Nonproprietary), January 1978.
Friedland, A. J., and Ray, S., Revised Thermal Design Procedure, WCAP-11397-P-A (Proprietary) and WCAP-11397-A (Nonproprietary), April 1989.
AP1000 Code Applicability Report, WCAP-15644-P (Proprietary) and WCAP-15644-NP (Nonproprietary), Revision 2, March 2004.
15.2-18 Revision 1
Matthys, C., Overpressure Protection Report for AP1000 Nuclear Power Plant, WCAP-16779-NP, April 2007.
15.2-19 Revision 1
Result in a Decrease in Heat Removal By the Secondary System Time Accident Event (seconds)
Turbine trip With pressurizer control, minimum Turbine trip; loss of main feedwater 0.0 reactivity feedback, with offsite power available Minimum DNBR occurs 0.0 High pressurizer pressure reactor trip point reached 6.2 Rods begin to drop 8.2 Peak RCS pressure occurs 10.0 Initiation of steam release from steam generator safety 12.4 valves With pressurizer control, minimum Turbine trip; loss of main feedwater 0.0 reactivity feedback, without offsite power available Offsite power lost, reactor coolant pumps begin coasting 3.0 down Low reactor coolant pump speed reactor trip setpoint 3.47 reached Rods begin to drop 4.24 Minimum DNBR (1.57) occurs 6.0 Peak RCS pressure occurs 6.3 Initiation of steam release from steam generator safety 18.7 valves 15.2-20 Revision 1
Time Accident Event (seconds)
With pressurizer control, Turbine trip; loss of main feedwater flow 0.0 maximum reactivity feedback, with offsite power available Minimum DNBR occurs 0.0 High pressurizer pressure reactor trip setpoint reached 6.6 Rods begin to drop 8.6 Peak RCS pressure occurs 9.6 Initiation of steam release from steam generator safety 13.0 valves With pressurizer control, Turbine trip; loss of main feedwater 0.0 maximum reactivity feedback, without offsite power available Offsite power lost, reactor coolant pumps begin coasting 3.0 down Low reactor coolant pump speed reactor trip setpoint 3.47 reached Rods begin to drop 4.24 Minimum DNBR (2.44) occurs 4.4 Peak RCS pressure occurs 7.7 Initiation of steam release from steam generator safety 24.9 valves 15.2-21 Revision 1
Time Accident Event (seconds)
Without pressurizer control, Turbine trip; loss of main feedwater flow 0.0 minimum reactivity feedback, with offsite power available High pressurizer pressure reactor trip point reached 5.9 Rods begin to drop 7.9 Peak RCS pressure occurs 9.5 Initiation of steam release from steam generator safety 10.5 valves Without pressurizer control, Turbine trip; loss of main feedwater 0.0 minimum reactivity feedback, without offsite power available Offsite power lost, reactor coolant pumps begin coasting 3.0 down Low reactor coolant pump speed reactor trip setpoint 3.47 reached Rods begin to drop 4.24 Peak RCS pressure occurs 6.3 Initiation of steam release from steam generator safety 14.0 valves 15.2-22 Revision 1
Time Accident Event (seconds)
Without pressurizer control, Turbine trip; loss of main feedwater flow 0.0 maximum reactivity feedback, with offsite power available High pressurizer pressure reactor trip 6.0 Rods begin to drop 8.0 Peak RCS pressure occurs 8.4 Initiation of steam release from steam generator safety 10.7 valves Without pressurizer control, Turbine trip; loss of main feedwater 0.0 maximum reactivity feedback, without offsite power available Offsite power lost, reactor coolant pumps begin coasting 3.0 down Low reactor coolant pump speed reactor trip setpoint 3.47 reached Rods begin to drop 4.24 Peak RCS pressure occurs 5.9 Initiation of steam release from steam generator safety 15.6 valves 15.2-23 Revision 1
Time Accident Event (seconds)
Loss of ac power to the plant Feedwater is lost 10.0 auxiliaries Low steam generator water level reactor trip set point is 70.4 reached Rods begin to drop, ac power is lost, reactor coolant 72.4 pumps start to coastdown Pressurizer safety valves open 76.5 Maximum pressurizer pressure reached 77.0 Steam generator safety valves open 87.0 PRHR heat exchanger actuation on low steam generator 132.4 water level (narrow range coincident with low start up flow rate)
Maximum pressurizer water volume reached 139.0 Pressurizer safety valves reclose 142.0 Steam generator 1 safety valves close 2,326 Core makeup tank actuation on low Tcold S signal 4,753 Steam line isolation on low Tcold S signal 4,765 Steam generator 2 safety valves close 7,006 Pressurizer safety valves open 8,056 Pressurizer safety valves reclose 16,944 PRHR heat exchanger extracted heat matches decay ~ 19,100 heat Second pressurizer water volume peak is reached 22,152 15.2-24 Revision 1
Time Accident Event (seconds)
Loss of normal feedwater flow Feedwater is lost 10.0 Low steam generator water level (narrow range) reactor 70.4 trip reached Rods begin to drop 72.4 Steam generator safety valves open 80.0 PRHR heat exchanger actuation on low steam generator 132.4 water level (narrow range coincident with low start up feeedwater flow rate)
Steam generator safety valves reclose 144 Cold leg temperature reaches low Tcold setpoint 1,154.6 Reactor coolant pump trip on low Tcold S signal 1,160.6 Steam line isolation on low Tcold S signal 1,166.6 Core makeup tank actuation on low Tcold S signal 1,171.6 Pressurizer safety valves open 3,500 Pressurizer safety valves reclose 17,702 Passive residual heat removal heat exchanger extracted ~ 17,620 heat matches decay heat Maximum pressurizer water volume reached 19,548 15.2-25 Revision 1
Time Accident Event (seconds)
Feedwater system pipe break Main feedwater flow to both steam generators stops due 10.0 to interaction between the break and the main feedwater control system Low steam generator water level (narrow range) setpoint 70.3 reached Reverse flow from the faulted steam generator through a 70.3 full double-ended rupture starts Rods begin to drop 72.3 Loss of offsite power occurs 72.3 Low steam generator water level (wide range) set point 73.1 reached Pressurizer safety valves open 74.5 Low steam line pressure set point reached 78.0 Pressurizer safety valves close 80.0 All steam and feedline isolation valves close 90.0 PRHR heat exchanger actuation on low steam generator 90.1 water level (wide range)
Core makeup tank valves fully opened 95.0 Faulted steam generator empties 100.0 Intact steam generator safety valves open 180 Intact steam generator safety valves close 425 Pressurizer safety valves open 1,848 PRHR heat exchanger extracted heat matches decay ~ 11,300 heat Pressurizer safety valves close ~ 11,300 15.2-26 Revision 1
Figure 15.2.3-1 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-27 Revision 1
Figure 15.2.3-2 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-28 Revision 1
Figure 15.2.3-3 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-29 Revision 1
Figure 15.2.3-4 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-30 Revision 1
Figure 15.2.3-5 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-31 Revision 1
Figure 15.2.3-6 DNBR versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-32 Revision 1
Figure 15.2.3-7 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident with Pressurizer Spray and Minimum Moderator Feedback 15.2-33 Revision 1
Figure 15.2.3-8 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-34 Revision 1
Figure 15.2.3-9 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-35 Revision 1
Figure 15.2.3-10 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-36 Revision 1
Figure 15.2.3-11 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-37 Revision 1
Figure 15.2.3-12 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-38 Revision 1
Figure 15.2.3-13 DNBR versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-39 Revision 1
Figure 15.2.3-14 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident with Pressurizer Spray and Maximum Moderator Feedback 15.2-40 Revision 1
Figure 15.2.3-15 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback 15.2-41 Revision 1
Figure 15.2.3-16 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback 15.2-42 Revision 1
Figure 15.2.3-17 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback 15.2-43 Revision 1
Figure 15.2.3-18 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback 15.2-44 Revision 1
Figure 15.2.3-19 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback 15.2-45 Revision 1
Figure 15.2.3-20 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident Without Pressurizer Spray and Minimum Moderator Feedback 15.2-46 Revision 1
Figure 15.2.3-21 Nuclear Power (Fraction of Nominal) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback 15.2-47 Revision 1
Figure 15.2.3-22 Pressurizer Pressure (psia) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback 15.2-48 Revision 1
Figure 15.2.3-23 Pressurizer Water Volume (ft3) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback 15.2-49 Revision 1
Figure 15.2.3-24 Vessel Inlet Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback 15.2-50 Revision 1
Figure 15.2.3-25 Vessel Average Temperature (°F) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback 15.2-51 Revision 1
Figure 15.2.3-26 Core Mass Flow Rate (Fraction of Initial) versus Time for Turbine Trip Accident Without Pressurizer Spray and Maximum Moderator Feedback 15.2-52 Revision 1
Figure 15.2.6-1 Nuclear Power Transient for Loss of ac Power to the Plant Auxiliaries 15.2-53 Revision 1
Figure 15.2.6-2 Core Heat Flux Transient for Loss of ac Power to the Plant Auxiliaries 15.2-54 Revision 1
Figure 15.2.6-3 Pressurizer Pressure Transient for Loss of ac Power to the Plant Auxiliaries 15.2-55 Revision 1
Figure 15.2.6-4 Pressurizer Water Volume Transient for Loss of ac Power to the Plant Auxiliaries 15.2-56 Revision 1
Figure 15.2.6-5 Reactor Coolant System Temperature Transients in Loop Containing the PRHR for Loss of ac Power to the Plant Auxiliaries 15.2-57 Revision 1
Figure 15.2.6-6 Reactor Coolant System Temperature Transients in Loop Not Containing the PRHR for Loss of ac Power to the Plant Auxiliaries 15.2-58 Revision 1
Figure 15.2.6-7 Steam Generator Pressure Transient for Loss of ac Power to the Plant Auxiliaries 15.2-59 Revision 1
Figure 15.2.6-8 PRHR Flow Rate Transient for Loss of ac Power to the Plant Auxiliaries 15.2-60 Revision 1
Figure 15.2.6-9 PRHR Heat Flux Transient for Loss of ac Power to the Plant Auxiliaries 15.2-61 Revision 1
Figure 15.2.6-10 Reactor Coolant Volumetric Flow Rate Transient for Loss of ac Power to the Plant Auxiliaries 15.2-62 Revision 1
Figure 15.2.6-11 Steam Generator Inventory Transient for Loss of ac Power to the Plant Auxiliaries 15.2-63 Revision 1
Figure 15.2.6-12 DNB Ratio Transient for Loss of ac Power to the Plant Auxiliaries 15.2-64 Revision 1
Figure 15.2.7-1 Nuclear Power Transient for Loss of Normal Feedwater Flow 15.2-65 Revision 1
Figure 15.2.7-2 Reactor Coolant System Volumetric Flow Transient for Loss of Normal Feedwater Flow 15.2-66 Revision 1
Figure 15.2.7-3 Reactor Coolant System Temperature Transients in Loop Containing the PRHR for Loss Normal Feedwater Flow 15.2-67 Revision 1
Figure 15.2.7-4 Reactor Coolant System Temperature Transients in Loop Not Containing the PRHR for Loss of Normal Feedwater Flow 15.2-68 Revision 1
Figure 15.2.7-5 Pressurizer Pressure Transient for Loss of Normal Feedwater Flow 15.2-69 Revision 1
Figure 15.2.7-6 Pressurizer Water Volume Transient for Loss of Normal Feedwater Flow 15.2-70 Revision 1
Figure 15.2.7-7 Steam Generator Pressure Transient for Loss of Normal Feedwater Flow 15.2-71 Revision 1
Figure 15.2.7-8 Steam Generator Inventory Transient for Loss of Normal Feedwater Flow 15.2-72 Revision 1
Figure 15.2.7-9 PRHR Heat Flux Transient for Loss of Normal Feedwater Flow 15.2-73 Revision 1
Figure 15.2.7-10 CMT Injection Flow Rate Transient for Loss of Normal Feedwater Flow 15.2-74 Revision 1
Figure 15.2.8-1 Nuclear Power Transient for Main Feedwater Line Rupture 15.2-75 Revision 1
Figure 15.2.8-2 Core Heat Flux Transient for Main Feedwater Line Rupture 15.2-76 Revision 1
Figure 15.2.8-3 Faulted Loop Reactor Coolant System Temperature Transients for Main Feedwater Line Rupture 15.2-77 Revision 1
Figure 15.2.8-4 Intact Loop Reactor Coolant System Temperature Transients for Main Feedwater Line Rupture 15.2-78 Revision 1
Figure 15.2.8-5 Pressurizer Pressure Transient for Main Feedwater Line Rupture 15.2-79 Revision 1
Figure 15.2.8-6 Pressurizer Water Volume Transient for Main Feedwater Line Rupture 15.2-80 Revision 1
Figure 15.2.8-7 Steam Generator Pressure Transient for Main Feedwater Line Rupture 15.2-81 Revision 1
Figure 15.2.8-8 PRHR Flow Rate Transient for Main Feedwater Line Rupture 15.2-82 Revision 1
Figure 15.2.8-9 PRHR Heat Flux Transient for Main Feedwater Line Rupture 15.2-83 Revision 1
Figure 15.2.8-10 CMT Injection Flow Rate Transient for Main Feedwater Line Rupture 15.2-84 Revision 1
tulated. These events are discussed in this section. Detailed analyses are presented for the most ing of the following reactor coolant system flow decrease events:
Partial loss of forced reactor coolant flow Complete loss of forced reactor coolant flow Reactor coolant pump shaft seizure (locked rotor)
Reactor coolant pump shaft break first event is a Condition II event, the second is a Condition III event, and the last two are dition IV events.
four limiting flow rate decrease events described above are analyzed in this section. The most ere radiological consequences result from the reactor coolant pump shaft seizure accident ussed in Subsection 15.3.3. Doses are reported only for that case.
3.1 Partial Loss of Forced Reactor Coolant Flow 3.1.1 Identification of Causes and Accident Description rtial loss of coolant flow accident can result from a mechanical or an electrical failure of a reactor lant pump or from a fault in the power supply to the pump or pumps. If the reactor is at power at time of the event, the immediate effect of the loss of coolant flow is a rapid increase in the coolant perature.
mal power for the pumps is supplied through four buses connected to the generator. When a erator trip occurs, the buses are supplied from offsite power. The pumps continue to operate.
rtial loss of coolant flow is classified as a Condition II incident (a fault of moderate frequency), as ned in Subsection 15.0.1.
ection against this event is provided by the low primary coolant flow reactor trip signal, which is ated by two-out-of-four low-flow signals. Above permissive P-10, low flow in either hot leg ates a reactor trip (see Section 7.2).
pecified in GDC 17 of 10 CFR Part 50, Appendix A, the effects of a loss of offsite power are sidered in evaluating partial loss of forced reactor coolant flow transients. As discussed in section 15.0.14, the loss of offsite power is considered to be a potential consequence of the nt due to disruption of the electrical grid following a turbine trip during the event. A delay of conds is assumed between the turbine trip and the loss of offsite power. In addition, turbine trip urs 5.0 seconds following a reactor trip condition being reached. This delay on turbine trip is a ure of the AP1000 reactor trip system. The primary effect of the loss of offsite power is to cause remaining operating reactor coolant pumps to coast down.
3.1.2 Analysis of Effects and Consequences 3.1.2.1 Method of Analysis transient is analyzed using three computer codes. First, the LOFTRAN code (Reference 1) is d to calculate the core flow during the transient based on the input loop flows, the nuclear power sient, and the primary system pressure and temperature transients as predicted from the loss of reactor coolant pumps. The FACTRAN code (Reference 2) is then used to calculate the heat flux 15.3-1 Revision 1
ented represent the minimum of the typical cell or the thimble cell.
3.1.2.2 Initial Conditions al reactor power, pressure, and reactor coolant system temperature are assumed to be at their inal values. Uncertainties in initial conditions are included in the DNBR limit, as described in AP-11397-P-A (Reference 5).
nt characteristics and initial conditions assumed in this analysis are further discussed in section 15.0.3.
3.1.2.3 Reactivity Coefficients nservatively large absolute value of the Doppler-only power coefficient is used (see re 15.0.4-1). This is equivalent to a total integrated Doppler reactivity from 0- to 100-percent er of 0.0160 k.
least-negative moderator temperature coefficient is assumed because this results in the imum core power during the initial part of the transient, when the minimum DNBR is reached.
these analyses, a curve of trip reactivity versus time based on a 2.5-second rod cluster control embly insertion time to the dashpot is used (see Subsection 15.0.5).
3.1.2.4 Flow Coastdowns servative flow coastdowns are used to simulate the transient. The flow coastdowns are ulated externally to the LOFTRAN code using the COAST computer code which is described in section 15.0.11.
nt systems and equipment necessary to mitigate the effects of the accident are discussed in section 15.0.8 and listed in Table 15.0-6. No single active failure in any of these systems or ipment adversely affects the consequences of the accident.
3.1.2.5 Results res 15.3.1-1 through 15.3.1-6 show the transient response for the loss of two reactor coolant ps with offsite power available. Figure 15.3.1-6 shows the DNBR to be always greater than the ign limit value as defined in Section 4.4.
plant is tripped by the low-flow trip rapidly enough so that the capability of the reactor coolant to ove heat from the fuel rods is not greatly reduced. The average fuel and cladding temperatures ot increase significantly above their initial values.
calculated sequence of events for the case analyzed is shown in Table 15.3-1. The affected tor coolant pumps continue to coast down, and the core flow reaches a new equilibrium value.
h the reactor tripped, a stable plant condition is attained. Normal plant shutdown may then eed.
15.3-2 Revision 1
he time when the remaining two operating reactor coolant pumps start coasting down, reactor trip already been initiated, core heat flux has started decreasing, and DNBR is increasing. DNBR tinues to increase as the remaining two reactor coolant pumps coast down because the core heat has decreased and is continuing to decrease rapidly. The minimum DNB ratio occurs at the same for cases with and without offsite power available.
3.1.3 Conclusions analysis shows that, for the partial loss of reactor coolant flow, the DNBR does not decrease w the design basis value at any time during the transient. The DNBR design basis is described in tion 4.4. The applicable Standard Review Plan, Subsection 15.3.1 (Reference 4), evaluation ria are met.
3.2 Complete Loss of Forced Reactor Coolant Flow 3.2.1 Identification of Causes and Accident Description mplete loss of flow accident may result from a simultaneous loss of electrical supplies to the tor coolant pumps. If the reactor is at power at the time of the accident, the immediate effect of a of coolant flow is a rapid increase in the coolant temperature.
tric power for the reactor coolant pumps is supplied through buses, connected to the generator ugh the unit auxiliary transformers. When a generator trip occurs, the buses receive power from rnal power lines and the pumps continue to supply coolant flow to the core.
mplete loss of flow accident is a Condition III event (an infrequent fault), as defined in section 15.0.1. The following signals provide protection against this event:
Reactor coolant pump underspeed Low reactor coolant loop flow reactor trip on reactor coolant pump underspeed protects against conditions that can cause a of voltage to the reactor coolant pumps. This function is blocked below approximately 10-percent er (permissive P-10).
reactor trip on reactor coolant pump underspeed is also provided to trip the reactor for an erfrequency condition resulting from frequency disturbances on the power grid. If the maximum frequency decay rate is less than approximately 5 hertz per second, this trip protects the core underfrequency events. WCAP-8424, Revision 1 (Reference 3), provides analyses of grid uency disturbances and the resulting protection requirements that are applicable to the AP1000.
reactor trip on low primary coolant loop flow is provided to protect against loss of flow conditions affect only one or two reactor coolant loop cold legs. This function is generated by two-out-of-low-flow signals per reactor coolant loop hot leg. Above permissive P-10, low flow in either hot actuates a reactor trip. If the maximum grid frequency decay rate is less than approximately hertz per second, this trip function also protects the core from this underfrequency event. This ct is described in WCAP-8424, Revision 1 (Reference 3).
15.3-3 Revision 1
complete loss of flow transient is analyzed for a loss of power to four reactor coolant pumps.
the case analyzed with a complete loss of voltage, followed by the reactor coolant pumps sting down, the method of analysis and the assumptions made regarding initial operating ditions and reactivity coefficients are identical to those discussed in Subsection 15.3.1, with one eption. Following the loss of power supply to all pumps at power, a reactor trip is actuated by the tor coolant pump underspeed trip.
ss of forced primary coolant flow can result from a reduction in the reactor coolant pump motor ply frequency. The results of the complete loss of voltage, followed by the reactor coolant pump sting down, bound the complete loss of flow initiated by a frequency decay of up to 5 hertz per ond. Therefore, only the results of the complete loss of voltage case are presented in section 15.3.2.2.2.
3.2.2.2 Results res 15.3.2-1 through 15.3.2-6 show the transient response for the complete loss of voltage to all reactor coolant pumps. The reactor is assumed to trip on the reactor coolant pump underspeed al. Figure 15.3.2-6 shows that the DNBR is always greater than the design limit value defined in tion 4.4.
calculated sequences of events for the cases analyzed are shown in Table 15.3-1. The reactor lant pumps continue to coast down, and natural circulation flow is established, as demonstrated in section 15.2.6. With the reactor tripped, a stable plant condition is attained. Normal plant tdown may then proceed.
3.2.3 Conclusions analysis demonstrates that, for the complete loss of forced reactor coolant flow, the DNBR does decrease below the design basis limit value at any time during the transient. The design basis for DNBR is described in Section 4.4. The applicable Standard Review Plan, Subsection 15.3.1 ference 4), evaluation criteria are met.
3.3 Reactor Coolant Pump Shaft Seizure (Locked Rotor) 3.3.1 Identification of Causes and Accident Description accident postulated is an instantaneous seizure of a reactor coolant pump rotor, as discussed in tion 5.4. Flow through the affected reactor coolant loop is rapidly reduced, leading to a reactor trip low-flow signal.
owing the reactor trip, heat stored in the fuel rods continues to be transferred to the coolant, sing the coolant temperature to increase and expand. At the same time, heat transfer to the shell of the steam generator in the faulted loop is reduced because: 1) the reduced flow results in a reased tube-side film coefficient, and 2) the reactor coolant in the tubes cools down while the ll-side temperature increases. (Turbine steam flow is reduced to 0 upon plant trip.) The rapid ansion of the coolant in the reactor core, combined with reduced heat transfer in the steam erators, causes an insurge into the pressurizer and a pressure increase throughout the reactor lant system. The insurge into the pressurizer compresses the steam volume, actuates the 15.3-4 Revision 1
event is classified as a Condition IV incident (a limiting fault), as defined in Subsection 15.0.1.
3.3.2 Analysis of Effects and Consequences 3.3.2.1 Method of Analysis digital computer codes are used to analyze this transient. The LOFTRAN code (Reference 1) ulates the resulting core flow transient following the pump seizure and the nuclear power wing reactor trip. This code is also used to determine the peak pressure. The thermal behavior of fuel located at the core hot spot is investigated by using the FACTRAN code (Reference 2). This e uses the core flow and the nuclear power calculated by LOFTRAN. The FACTRAN code udes a film-boiling heat transfer coefficient.
he beginning of the postulated locked rotor accident (at the time the shaft in one of the reactor lant pumps is assumed to seize), the plant is assumed to be in operation under the most adverse dy-state operating conditions, that is, maximum steady-state thermal power, maximum steady-e pressure, and maximum steady-state coolant average temperature. Plant characteristics and al conditions are further discussed in Subsection 15.0.3. The accident is evaluated for both cases and without offsite power available. For the case without offsite power available, power is lost to unaffected pumps at 3.0 seconds following turbine/generator trip. Turbine trip occurs 5.0 seconds wing a reactor trip condition being reached. This delay on turbine trip is a feature of the AP1000 tor trip system.
the peak pressure evaluation, the initial pressure is conservatively estimated as 50 psi above inal pressure (2250 psia), which allows for errors in the pressurizer pressure measurement and trol channels. This is done to obtain the highest possible rise in the coolant pressure during the sient. To obtain the maximum pressure in the primary side, conservatively high loop pressure ps are added to the calculated pressurizer pressure.
3.3.2.2 Evaluation of the Pressure Transient r pump seizure, the neutron flux is rapidly reduced by control rod insertion. Rod motion is umed to begin 1.45 seconds after the flow in the affected loop reaches the reactor trip setpoint.
credit is taken for the pressure-reducing effect of the pressurizer spray, steam dump, or controlled water flow after plant trip. Although these operations are expected to result in a lower peak tor coolant system pressure, an additional conservatism is provided by ignoring their effect.
pressurizer safety valves are fully open at 2575 psia. Their capacity for steam relief is described ection 5.4.
3.3.2.3 Evaluation of Departure from Nucleate Boiling in the Core During the Accident this accident, an evaluation of the consequences with respect to fuel rod thermal transients is ormed. Results obtained from analysis of this hot spot condition represent the upper limit with ect to cladding temperature and zirconium-water reaction.
e evaluation, the rod power at the hot spot is conservatively assumed to be 2.6 times the rage rod power (that is, FQ = 2.6) at the initial core power level.
15.3-5 Revision 1
dberg-Tong film-boiling correlation. The fluid properties are evaluated at film temperature rage between wall and bulk temperatures). The program calculates the film coefficient at every step, based upon the actual heat transfer conditions at the time. The nuclear power, system sure, bulk density, and mass flow rate as a function of time are used as program input.
this analysis, the initial values of the pressure and the bulk density are used throughout the sient because they are the most conservative with respect to cladding temperature response. For servatism, DNB is assumed to start at the beginning of the accident.
3.3.2.5 Fuel Cladding Gap Coefficient magnitude and time dependence of the heat transfer coefficient between fuel and cladding (gap fficient) have a pronounced influence on the thermal results. The larger the value of the gap fficient, the more heat is transferred between the pellet and the cladding. Based on investigations he effect of the gap coefficient upon the maximum cladding temperature during the transient, the coefficient is assumed to increase from a steady-state value consistent with initial fuel perature to 10,000 Btu/h-ft2-°F at the initiation of the transient. Thus, the large amount of energy ed in the fuel because of the small initial value of the gap coefficient is released to the cladding at initiation of the transient.
3.3.2.6 Zirconium-Steam Reaction zirconium-steam reaction can become significant above a cladding temperature of 1800°F. The er-Just parabolic rate equation is used to define the rate of the zirconium-steam reaction:
d ( w 2) 45,500
= 33.3 x 106 exp -
dt 1.986 T re:
= amount reacted (mg/cm2)
= time (s)
= temperature (Kelvin) reaction heat is 1510 cal/g.
effect of the zirconium-steam reaction is included in the calculation of the hot spot cladding perature transient.
nt systems and equipment available to mitigate the effects of the accident are discussed in section 15.0.8 and listed in Table 15.0-6. No single active failure in any of these systems or ipment adversely affects the consequences of the accident.
3.3.2.7 Results res 15.3.3-1 through 15.3.3-7 show the transient results for one locked rotor with four reactor lant pumps in operation with and without offsite power available. The without-offsite-power case 15.3-6 Revision 1
e,Section III. Also, the peak cladding surface temperature is considerably less than 2700°F. The ding temperature is conservatively calculated, assuming that DNB occurs at the initiation of the sient. These results represent the most limiting conditions with respect to the locked rotor event he pump shaft break.
calculated sequence of events for the case analyzed is shown in Table 15.3-1. With the reactor ed, a stable plant condition is eventually attained. Normal plant shutdown may then proceed.
3.3.3 Radiological Consequences evaluation of the radiological consequences of a postulated locked reactor coolant pump rotor dent assumes that the reactor has been operating with the design basis fuel defect level 5 percent of power produced by fuel rods containing cladding defects) and that leaking steam erator tubes have resulted in a buildup of activity in the secondary coolant.
a result of the accident, it is determined that no fuel rods are damaged such that the activity tained in the fuel-cladding gap is released to the reactor coolant. However, a conservative lysis has been performed assuming 10 percent of the rods are damaged. Activity carried over to secondary side because of primary-to-secondary leakage is available for release to the ironment via the steam line safety valves or the power-operated relief valves.
3.3.3.1 Source Term significant radionuclide releases due to the locked rotor accident are the iodines, alkali metals iums, rubidiums) and noble gases. The reactor coolant iodine source term assumes a existing iodine spike. The initial reactor coolant noble gas and alkali metal concentrations are umed to be those associated with the design basis fuel defect level. These initial reactor coolant vities are of secondary importance compared to the release of the gap inventory of fission ducts from the portion of the core assumed to fail because of the accident.
ed on NUREG-1465 (Reference 6), the fission product gap fraction is 3 percent of fuel inventory.
this analysis, the gap fraction is increased to 8 percent of the inventory for I-131, 10 percent for 5, 5 percent for other iodines and noble gases and 12 percent for alkali metals. Also, to address fact that the failed fuel rods may have been operating at power levels above the core average, source term is increased by the lead rod radial peaking factor.
initial secondary coolant activity is assumed to be 1 percent of the maximum equilibrium primary lant activity for iodines and alkali metals.
3.3.3.2 Release Pathways re are two components to the accident releases:
The activity initially in the secondary coolant is available for release as long as steam releases continue.
The reactor coolant leaking into the steam generators is assumed to mix with the secondary coolant. The activity from the primary coolant mixes with the secondary coolant. As steam is released, a portion of the iodine and alkali metal activity in the coolant is released. The fraction of activity released is defined by the assumed flashing fraction and the partition coefficient assumed for the steam generator. The noble gas activity entering the secondary 15.3-7 Revision 1
dit is taken for the decay of radionuclides until release to the environment. After release to the ironment, no consideration is given to radioactive decay or to cloud depletion by ground osition during transport offsite.
3.3.3.3 Dose Calculation Models models used to calculate offsite doses are provided in Appendix 15A.
3.3.3.4 Analytical Assumptions and Parameters assumptions and parameters used in the analysis are listed in Table 15.3-3.
separate accident scenarios are addressed. In the first scenario, it is assumed that the non-ty grade startup feedwater system is not available to provide feedwater to the steam generators.
is event, the water level in the steam generators drops, resulting in tube uncovery and there is hing of a portion of the primary coolant assumed to be leaking into the secondary side of the m generators. Also, the period of steaming is terminated at 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> when the capacity of the sive residual heat removal system exceeds the decay heat generation rate.
e second scenario, it is assumed that the startup feedwater system is available to maintain water l in the steam generators such that the tubes remain covered. In this scenario, direct release of hed primary coolant is not considered. Also, the passive residual heat removal system does not ate, resulting in a longer period of steaming releases.
3.3.3.5 Identification of Conservatisms assumptions used in the analysis contain a number of significant conservatisms:
Although fuel damage is assumed to occur as a result of the accident, no fuel damage is anticipated.
The reactor coolant activities are based on a fuel defect level of 0.25 percent; whereas, the expected fuel defect level is far less than this (see Section 11.1).
The leakage of reactor coolant into the secondary system, at 300 gallons per day, is conservative. The leakage is normally a small fraction of this.
It is unlikely that the conservatively selected meteorological conditions are present at the time of the accident.
3.3.3.6 Doses ng the assumptions from Table 15.3-3, the calculated total effective dose equivalent (TEDE) es are determined to be less than 0.5 rem at the exclusion area boundary for the limiting 2-hour rval (0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) and less than 0.2 rem at the low population zone outer boundary for the nario in which there is no feedwater available to maintain water level in the steam generators. The es for the scenario in which it is assumed that water level in the steam generators is maintained 0.4 rem at the exclusion area boundary for the limiting 2-hour interval of 6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 0.4 rem e low population zone outer boundary. These doses are a small fraction of the dose guideline of em TEDE identified in 10 CFR Part 50.34. A small fraction is identified as 10 percent or less sistent with the Standard Review Plan (Reference 4).
15.3-8 Revision 1
l cooling has been evaluated for a duration of 30 days. There is no contribution to the 2-hour site ndary dose because the pool boiling would not occur until after the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 30-day tribution to the dose at the low population zone boundary is less than 0.01 rem TEDE, and when is added to the dose calculated for the locked rotor event, the resulting total dose remains less the value reported above.
3.4 Reactor Coolant Pump Shaft Break 3.4.1 Identification of Causes and Accident Description accident is postulated as an instantaneous failure of a reactor coolant pump shaft. Flow through affected reactor coolant loop is rapidly reduced, though the initial rate of reduction of coolant flow eater for the reactor coolant pump rotor seizure event. Reactor trip occurs on a low-flow signal in affected loop.
owing the reactor trip, heat stored in the fuel rods continues to be transferred to the coolant, sing the coolant to expand. At the same time, heat transfer to the shell side of the steam erator in the faulted loop is reduced because: 1) the reduced flow results in a decreased tube-film coefficient, and 2) the reactor coolant in the tubes cools down while the shell-side perature increases. (Turbine steam flow is reduced to 0 upon plant trip.) The rapid expansion of coolant in the reactor core, combined with reduced heat transfer in the steam generators, causes nsurge into the pressurizer and a pressure increase throughout the reactor coolant system. The rge into the pressurizer compresses the steam volume, actuates the automatic spray system, opens the pressurizer safety valves, in that sequence. For conservatism, the pressure-reducing ct of the spray is not included in the analysis.
event is classified as a Condition IV incident (limiting fault), as defined in Subsection 15.0.1.
3.4.2 Conclusion h a failed shaft, the impeller could be free to spin in a reverse direction as opposed to being fixed osition as is the case when a locked rotor occurs. This results in a decrease in the end point ady-state) core flow. For both the shaft break and locked rotor incidents, reactor trip occurs very y in the transient. In addition, the locked rotor analysis conservatively assumes that DNB occurs e beginning of the transient. The calculated results presented for the locked rotor analysis bound reactor coolant pump shaft break event.
3.5 Combined License Information section contained no requirement for additional information.
3.6 References Burnett, T. W. T., et al., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984.
Hargrove, H. G., FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908-A, December 1989.
Baldwin, M. S., et al., An Evaluation of Loss of Flow Accidents Caused by Power System Frequency Transients in Westinghouse PWRs, WCAP-8424, Revision 1, May 1975.
15.3-9 Revision 1
Friedland, A. J., and Ray, S., Revised Thermal Design Procedure, WCAP-11397-P-A (Proprietary) and WCAP-11397-A (Nonproprietary), April 1989.
Soffer, L., et al., Accident Source Terms for Light-Water Nuclear Power Plants, NUREG-1465, February 1995.
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That Result in a Decrease In Reactor Coolant System Flow Rate Time Accident Event (seconds) tial loss of forced reactor coolant Loss of two pumps with four Coastdown begins 0.00 pumps running Low-flow reactor trip 1.61 Rods begin to drop 3.06 Minimum DNBR occurs 4.90 mplete loss of forced reactor lant Loss of four pumps with four Operating pumps lose power and begin coasting down 0.00 pumps running Reactor coolant pump underspeed trip point reached 0.47 Rods begin to drop 1.24 Minimum DNBR occurs 3.0 ctor coolant pump shaft seizure ked rotor)
One locked rotor with four pumps Rotor on one pump locks 0.00 unning with offsite power Low-flow trip point reached 0.10 available Rods begin to drop 1.55 Maximum reactor coolant system pressure occurs 2.30 Maximum cladding temperature occurs 3.90 One locked rotor with four pumps Rotor on one pump locks 0.00 unning without offsite power Low-flow trip point reached 0.10 available Rods begin to drop 1.55 Maximum reactor coolant system pressure occurs 2.30 Maximum cladding temperature occurs 3.90 15.3-11 Revision 1
(Four Reactor Coolant Pumps Operating Initially)
Without Offsite Power Available ximum reactor coolant system pressure (psia) 2703 ximum cladding temperature, core hot spot (°F) 1819 H2O reaction, core hot spot (percentage by weight) 0.30 15.3-12 Revision 1
Consequences of a Locked Rotor Accident al reactor coolant iodine activity An assumed iodine spike that has resulted in an increase in the reactor coolant activity to 60 Ci/gm of dose equivalent I-131 (see Appendix 15A)(a) actor coolant noble gas activity Equal to the operating limit for reactor coolant activity of 280 Ci/gm dose equivalent Xe-133 actor coolant alkali metal activity Design basis activity (see Table 11.1-2) ondary coolant initial iodine and alkali metal 1% of design basis reactor coolant concentrations at maximum vity equilibrium conditions ction of fuel rods assumed to fail 0.10 e activity See Table 15A-3 ial peaking factor (for determination of 1.75 vity in failed fuel rods) sion product gap fractions
-131 0.08 r-85 0.10 Other iodines and noble gases 0.05 lkali metals 0.12 actor coolant mass (lb) 3.7 E+05 ondary coolant mass (lb) 6.04 E+05 ndenser Not available ospheric dispersion factors See Table 15A-5 mary to secondary leak rate (lb/hr) 104.5(b) tition coefficient in steam generators odine 0.01 lkali metals 0.0035 ident scenario in which startup feedwater ot available Duration of accident (hr) 1.5 hr team released (lb)
-1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />(c) 6.48 E+05 eak flashing fraction(d)
-60 minutes 0.04 60 minutes 0 ident scenario in which startup feedwater vailable Duration of accident (hr) 8.0 hr team release rate (lb/sec) 60 eak flashing fraction Not applicable es:
The assumption of a pre-existing iodine spike is a conservative assumption for the initial reactor coolant activity. However, compared to the activity released to the coolant from the assumed fuel failures, it is not significant.
Equivalent to 300 gpd cooled liquid at 62.4 lb/ft3.
Heat removal is achieved by steaming and by passive core cooling system operation in the limiting case where the startup feedwater system is not available. When heat removal by the passive core cooling system exceeds the decay heat load, steam releases are terminated.
No credit for iodine partitioning is taken for flashed leakage. Credit is taken for a partition coefficient of 0.10 for alkali metals. Flashing is terminated by the passive core cooling system operation reducing the RCS below the saturation temperature of the secondary.
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Figure 15.3.1-1 Core Mass Flow Transient for Four Cold Legs in Operation, Two Pumps Coasting Down 15.3-14 Revision 1
Figure 15.3.1-2 Nuclear Power Transient for Four Cold Legs in Operation, Two Pumps Coasting Down 15.3-15 Revision 1
Figure 15.3.1-3 Pressurizer Pressure Transient for Four Cold Legs in Operation, Two Pumps Coasting Down 15.3-16 Revision 1
Figure 15.3.1-4 Average Channel Heat Flux Transient for Four Cold Legs in Operation, Two Pumps Coasting Down 15.3-17 Revision 1
Figure 15.3.1-5 Hot Channel Heat Flux Transient for Four Cold Legs in Operation, Two Pumps Coasting Down 15.3-18 Revision 1
Figure 15.3.1-6 DNB Transient for Four Cold Legs in Operation, Two Pumps Coasting Down 15.3-19 Revision 1
Figure 15.3.2-1 Flow Transient for Four Cold Legs in Operation, Four Pumps Coasting Down 15.3-20 Revision 1
Figure 15.3.2-2 Nuclear Power Transient for Four Cold Legs in Operation, Four Pumps Coasting Down 15.3-21 Revision 1
Figure 15.3.2-3 Pressurizer Pressure Transient for Four Cold Legs in Operation, Four Pumps Coasting Down 15.3-22 Revision 1
Figure 15.3.2-4 Average Channel Heat Flux Transient for Four Cold Legs in Operation, Four Pumps Coasting Down 15.3-23 Revision 1
Figure 15.3.2-5 Hot Channel Heat Flux Transient for Four Cold Legs in Operation, Four Pumps Coasting Down 15.3-24 Revision 1
Figure 15.3.2-6 DNBR Transient for Four Cold Legs in Operation, Four Pumps Coasting Down 15.3-25 Revision 1
Figure 15.3.3-1 Core Mass Flow Transient for Four Cold Legs in Operation, One Locked Rotor 15.3-26 Revision 1
Figure 15.3.3-2 Faulted Loop Volumetric Flow Transient for Four Cold Legs in Operation, One Locked Rotor 15.3-27 Revision 1
Figure 15.3.3-3 Peak Reactor Coolant Pressure for Four Cold Legs in Operation, One Locked Rotor 15.3-28 Revision 1
Figure 15.3.3-4 Average Channel Heat Flux Transient for Four Cold Legs in Operation, One Locked Rotor 15.3-29 Revision 1
Figure 15.3.3-5 Hot Channel Heat Flux Transient for Four Cold Legs in Operation, One Locked Rotor 15.3-30 Revision 1
Figure 15.3.3-6 Nuclear Power Transient for Four Cold Legs in Operation, One Locked Rotor 15.3-31 Revision 1
Figure 15.3.3-7 Cladding Inside Temperature Transient for Four Cold Legs in Operation, One Locked Rotor 15.3-32 Revision 1
nges could be caused by control rod motion or ejection, boron concentration changes, or addition old water to the reactor coolant system. Power distribution changes could be caused by control motion, misalignment, or ejection, or by static means such as fuel assembly mislocation. These nts are discussed in this section. Analyses are presented for the most limiting of these events.
following incidents are discussed in this section:
Uncontrolled rod cluster control assembly (RCCA) bank withdrawal from a subcritical or low-power startup condition Uncontrolled RCCA bank withdrawal at power RCCA misalignment Startup of an inactive reactor coolant pump at an incorrect temperature A malfunction or failure of the flow controller in a boiling water reactor recirculation loop that results in an increased reactor coolant flow rate (not applicable to AP1000)
Chemical and volume control system malfunction that results in a decrease in the boron concentration in the reactor coolant Inadvertent loading and operation of a fuel assembly in an improper position Spectrum of RCCA ejection accidents s A, B, D, and F above are Condition II events, item G is a Condition III event, and item H is a dition IV event. Item C includes both Conditions II and III events.
applicable transients in this section have been analyzed. It has been determined that the most ere radiological consequences result from the complete rupture of a control rod drive mechanism sing as discussed in Subsection 15.4.8.
iological consequences are reported only for the limiting case.
4.1 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal from a Subcritical or Low-Power Startup Condition 4.1.1 Identification of Causes and Accident Description RCCA withdrawal accident is an uncontrolled addition of reactivity to the reactor core caused by withdrawal of RCCAs which results in a power excursion. Such a transient can be caused by a function of the reactor control or rod control systems. This can occur with the reactor subcritical, ot zero power, or at power. The at-power case is discussed in Subsection 15.4.2.
ough the reactor is normally brought to power from a subcritical condition by RCCA withdrawal, al startup procedures with a clean core use boron dilution. The maximum rate of reactivity ease in the case of boron dilution is less than that assumed in this analysis (see section 15.4.6).
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in their proper withdrawal sequence. The RCCA drive mechanisms are the magnetic latch type, coil actuation is sequenced to provide variable speed travel. The maximum reactivity insertion analyzed is that occurring with the simultaneous withdrawal of the combination of two sequential CA banks having the maximum combined worth at maximum speed.
event is a Condition II event (a fault of moderate frequency) as defined in Subsection 15.0.1.
neutron flux response to a continuous reactivity insertion is characterized by a fast rise inated by the reactivity feedback effect of the negative Doppler coefficient. This self-limitation of power excursion limits the power during the delay time for protective action. Should a continuous CA withdrawal accident occur, the transient is terminated by the following automatic features of protection and safety monitoring system:
Source range high neutron flux reactor trip This trip function is actuated when two out of four independent source range channels indicate a neutron flux level above a preselected, manually adjustable setpoint. It may be manually bypassed only after an intermediate range flux channel indicates a flux level above a specified level. It is automatically reinstated when the coincident two out of four intermediate range channels indicate a flux level below a specified level.
Intermediate range high neutron flux reactor trip This trip function is actuated when two out of four independent, intermediate range channels indicate a flux level above a preselected, manually adjustable setpoint. It may be manually bypassed only after two out of four power range channels are reading above approximately 10 percent of full power. It is automatically reinstated when the coincident two out of four channels indicate a power level below this value.
Power range high neutron flux reactor trip (low setting)
This trip function is actuated when two out of four power range channels indicate a power level above approximately 25 percent of full power. It may be manually bypassed when two out of four power range channels indicate a power level above approximately 10 percent of full power. It is automatically reinstated when the coincident two out of four channels indicate a power level below this value.
Power range high neutron flux reactor trip (high setting)
This trip function is actuated when two out of four power range channels indicate a power level above a preset setpoint. It is always active.
High nuclear flux rate reactor trip This trip function is actuated when the positive rate of change of neutron flux on two out of four nuclear power range channels indicate a rate above a preset setpoint.
In addition, control rod stops on high intermediate range flux level (one out of two) and high power range flux level (one out of four) serve to discontinue rod withdrawal and prevent the need to actuate the intermediate range flux level trip and the power range flux level trip, respectively.
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analysis of the uncontrolled RCCA bank withdrawal from subcritical accident is performed in e stages: first, an average core nuclear power transient calculation; then, an average core heat sfer calculation; and finally, the departure from nucleate boiling ratio (DNBR) calculation. In the stage, the average core nuclear calculation is performed using spatial neutron kinetics methods, g the code TWINKLE (Reference 1), to determine the average power generation with time, uding the various total core feedback effects (Doppler reactivity and moderator reactivity).
e second stage, the average heat flux and temperature transients are determined by performing el rod transient heat transfer calculation in FACTRAN (Reference 2). In the final stage, the rage heat flux is used in VIPRE-01 (described in Section 4.4) for the transient DNBR calculation.
nt characteristics and initial conditions are discussed in Subsection 15.0.3. The following umptions are made to give conservative results for a startup accident:
Because the magnitude of the power peak reached during the initial part of the transient for any given rate of reactivity insertion is strongly dependent on the Doppler coefficient, conservatively low values, as a function of power, are used (see Table 15.0-2).
Contribution of the moderator reactivity coefficient is negligible during the initial part of the transient because the heat transfer time between the fuel and the moderator is much longer than the neutron flux response time. After the initial neutron flux peak, the succeeding rate of power increase is affected by the moderator reactivity coefficient. A conservative value is used in the analysis to yield the maximum peak heat flux (see Table 15.0-2).
The reactor is assumed to be at hot zero power. This assumption is more conservative than that of a lower initial system temperature. The higher initial system temperature yields a larger fuel-water heat transfer coefficient, larger specific heats, and a less negative (smaller absolute magnitude) Doppler coefficient, all of which tend to reduce the Doppler feedback effect and thereby increase the neutron flux peak. The initial effective multiplication factor (keff) is assumed to be 1.0 because this results in the worst nuclear power transient.
Reactor trip is assumed to be initiated by the power range high neutron flux (low setting). The most adverse combination of instrument and setpoint errors, as well as delays for trip signal actuation and RCCA release, is taken into account. A 10-percent uncertainty increase is assumed for the power range flux trip setpoint, raising it to 35 percent from the nominal value of 25 percent.
Because the rise in the neutron flux is so rapid, the effect of errors in the trip setpoint on the actual time at which the rods are released is negligible. In addition, the reactor trip insertion characteristic is based on the assumption that the highest worth RCCA is stuck in its fully withdrawn position. See Subsection 15.0.5 for RCCA insertion characteristics.
The maximum positive reactivity insertion rate assumed is greater than that for the simultaneous withdrawal of the combination of the two sequential RCCA banks having the greatest combined worth at maximum speed (45 inches per minute). Control rod drive mechanism design is discussed in Section 4.6.
The most limiting axial and radial power shapes, associated with having the two highest combined worth banks in their high-worth position, are assumed in the departure from nucleate boiling (DNB) analysis.
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Four reactor coolant pumps are assumed to be in operation.
Pressurizer pressure is assumed to be 50 psi below nominal for steady-state fluctuations and measurement uncertainties.
nt systems and equipment available to mitigate the effects of the accident are discussed in section 15.0.8 and listed in Table 15.0-6. No single active failure in any of these systems or ponents adversely affects the consequences of the accident. A loss of offsite power as a sequence of a turbine trip disrupting the grid is not considered because the accident is initiated a subcritical condition where the plant is not providing power to the grid.
4.1.2.2 Results res 15.4.1-1 through 15.4.1-3 show the transient behavior for the uncontrolled RCCA bank drawal from subcritical incident. The accident is terminated by reactor trip at 35 percent of inal power. The reactivity insertion rate used is greater than that calculated for the two highest-th sequential rod cluster control banks, both assumed to be in their highest incremental worth on.
re 15.4.1-1 shows the average neutron flux transient. The energy release and the fuel perature increases are relatively small. The heat flux response (of interest for DNB siderations) is also shown in Figure 15.4.1-2. The beneficial effect of the inherent thermal lag in fuel is evidenced by a peak heat flux much less than the full-power nominal value. There is gin to DNB during the transient because the rod surface heat flux remains below the critical heat value, and there is a high degree of subcooling at all times in the core. Figure 15.4.1-3 shows the onse of the average fuel and cladding temperatures. The minimum DNBR at all times remains ve the design limit value (see Section 4.4).
calculated sequence of events for this accident is shown in Table 15.4-1. With the reactor ed, the plant returns to a stable condition. Subsequently, the plant may be cooled down further ollowing normal plant shutdown procedures.
4.1.3 Conclusions e event of an RCCA withdrawal accident from the subcritical condition, the core and the reactor lant system are not adversely affected because the combination of thermal power and the coolant perature results in a DNBR greater than the safety analysis limit value. Thus, no fuel or cladding age is predicted as a result of DNB.
4.2 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power 4.2.1 Identification of Causes and Accident Description ontrolled RCCA bank withdrawal at power results in an increase in the core heat flux. Because heat extraction from the steam generator lags behind the core power generation until the steam erator pressure reaches the relief or safety valve setpoint, there is a net increase in the reactor lant temperature. Unless terminated by manual or automatic action, the power mismatch and ltant coolant temperature rise could eventually result in DNB. Therefore, to avert damage to the 15.4-4 Revision 1
event is a Condition II incident (a fault of moderate frequency) as defined in Subsection 15.0.1.
automatic features of the PMS that prevent core damage following the postulated accident ude the following:
Power range neutron flux instrumentation actuates a reactor trip if two out of four divisions exceed an overpower setpoint. In particular, the power range neutron flux instrumentation provides the following reactor trip functions:
- 1. Reactor trip on high power range neutron flux (high setpoint)
- 2. Reactor trip on high power range positive neutron flux rate The latter trip protects the core when a sudden abnormal increase in power is detected in the power range neutron flux channel in two out of four PMS divisions. It provides protection against reactivity insertion rates accidents at mid and low power, and it is always active.
Reactor trip is actuated if any two out of four T power divisions exceed an overtemperature T setpoint. This setpoint is automatically varied with axial power imbalance, coolant temperature, and pressure to protect against DNB.
Reactor trip is actuated if any two out of four T power divisions exceed an overpower T setpoint. This setpoint is automatically varied with axial power imbalance to prevent the allowable linear heat generation rate (kW/ft) from being exceeded.
A high pressurizer pressure reactor trip is actuated from any two out of four pressure divisions when a set pressure is exceeded. This set pressure is less than the set pressure for the pressurizer safety valves.
A high pressurizer water level reactor trip is actuated from any two out of four level divisions that exceed the setpoint when the reactor power is above approximately 10 percent (permissive P-10).
ddition to the preceding reactor trips, there are the following RCCA withdrawal blocks:
High neutron flux (two out of four power range)
Overpower T (two out of four)
Overtemperature T (two out of four) manner in which the combination of overpower and overtemperature T trips provide protection r the full range of reactor coolant system conditions is described in Chapter 7 and Reference 13.
re 15.0.3-1 presents allowable reactor coolant loop average temperature and T for the design er distribution and flow as a function of primary coolant pressure. The boundaries of operation ned by the overpower T trip and the overtemperature T trip are represented as protection s on this diagram. The protection lines are drawn to include adverse instrumentation and setpoint ertainties so that under nominal conditions, a trip occurs well within the area bounded by these s.
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High neutron flux (fixed setpoint)
High pressurizer pressure (fixed setpoint)
Low pressurizer pressure (fixed setpoint)
Overpower and overtemperature T (variable setpoints) eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, the effects of a possible sequential loss of offsite power during the RCCA bank withdrawal at-power event have been luated to not adversely impact the analysis results. This conclusion is based on a review of the sequence associated with a consequential loss of offsite power in comparison to the reactor tdown time for an uncontrolled RCCA bank withdrawal at-power event. The primary effect of the of offsite power is to cause the reactor coolant pumps (RCPs) to coast down. The PMS includes 0 second minimum delay between the reactor trip and the turbine trip. In addition, a 3.0 second y between the turbine trip and the loss of offsite power is assumed, consistent with tion 15.1.3 of NUREG-1793. Considering these delays between the time of the reactor trip and P coastdown due to the loss of offsite power, it is clear that the plant shutdown sequence will have sed the critical point and the control rods will have been completely inserted before the RCPs in to coast down. Therefore, the consequential loss of offsite power does not adversely impact uncontrolled RCCA bank withdrawal at-power analysis because the plant will be shut down well re the RCPs begin to coast down.
4.2.2 Analysis of Effects and Consequences 4.2.2.1 Method of Analysis transient is analyzed using the LOFTRAN (References 3 and 11) code. This code simulates the tron kinetics, reactor coolant system, pressurizer, pressurizer safety valves, pressurizer spray, m generators, and steam generator safety valves. The code computes pertinent plant variables uding temperatures, pressures, and power level. The core limits as illustrated in Figure 15.0.3-1 used to define the inputs to LOFTRAN that determine the minimum DNBR during the transient.
nt characteristics and initial conditions are discussed in Subsection 15.0.3. In performing a servative analysis for an uncontrolled RCCA bank withdrawal at-power accident, the following umptions are made:
The nominal initial conditions are assumed in accordance with the revised thermal design procedure. Uncertainties in the initial conditions are included in the DNBR limit as described in WCAP-11397-P-A (Reference 9).
Two sets of reactivity coefficients are considered:
Minimum reactivity feedback A least-negative moderator temperature coefficient of reactivity is assumed, corresponding to the beginning of core life. A variable Doppler power coefficient with core power is used in the analysis. A conservatively small (in absolute magnitude) value is assumed (see Figure 15.0.4-1).
Maximum reactivity feedback A conservatively large positive moderator density coefficient and a large (in absolute magnitude) negative Doppler power coefficient are assumed (see Figure 15.0.4-1).
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The RCCA trip insertion characteristic is based on the assumption that the highest-worth assembly is stuck in its fully withdrawn position.
A range of reactivity insertion rates is examined. The maximum positive reactivity insertion rate is greater than that for the simultaneous withdrawal of the combination of the two control banks having the maximum combined worth at maximum speed.
effect of RCCA movement on the axial core power distribution is accounted for by causing a rease in overtemperature T trip setpoint proportional to a decrease in margin to DNB.
nt systems and equipment available to mitigate the effects of the accident are discussed in section 15.0.8 and listed in Table 15.0-6. No single active failure in these systems or equipment ersely affects the consequences of the accident. A discussion of anticipated transients without m considerations is presented in Section 15.8.
4.2.2.2 Results res 15.4.2-1 through 15.4.2-6 show the transient response for a representative rapid RCCA drawal incident starting from full power with offsite power lost as a consequence of turbine trip.
ctor trip on high neutron flux occurs shortly after the start of the accident. Because this is rapid respect to the thermal time constants of the plant, small changes in temperature and pressure lt, and the DNB design basis described in Section 4.4 is met.
transient response for a representative slow RCCA withdrawal from full power, with offsite power as a consequence of turbine trip, is shown in Figures 15.4.2-7 through 15.4.2-12. Reactor trip on rtemperature T occurs after a longer period. The rise in temperature and pressure is sequently larger than for rapid RCCA withdrawal. The DNB design basis described in Section 4.4 et.
re 15.4.2-13 shows the minimum DNBR as a function of reactivity insertion rate from initial power operation for minimum and maximum reactivity feedback. Minimum DNBR, occurs ediately after rod motion. Two reactor trip functions provide protection over the whole range of tivity insertion rates. These are the high neutron flux and overtemperature T functions. The B design basis described in Section 4.4 is met.
res 15.4.2-14 and 15.4.2-15 show the minimum DNBR as a function of reactivity insertion rate RCCA bank withdrawal incidents for minimum and maximum reactivity feedback, starting at percent and 10-percent power, respectively. Minimum DNBR occurs immediately after rod motion before the loss of offsite power. The results are similar to the 100-percent power case, except as initial power is decreased, the range over which the overtemperature T trip is effective is eased and for the maximum feedback cases the transient is always terminated by the rtemperature T reactor trip. The DNB design basis described in Section 4.4 is met.
shape of the curves of minimum DNBR versus reactivity insertion rate in the referenced figures ue both to reactor core and coolant system transient response and to PMS action in initiating a tor trip.
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For high reactivity insertion rates above 14 pcm/s, reactor trip is initiated by the high neutron flux trip for the minimum reactivity feedback cases. Reactor trip is initiated by overtemperature T for the whole range of reactivity insertion rates for the maximum reactivity feedback cases. For minimum reactivity feedback cases, the neutron flux level in the core rises rapidly for the higher reactivity insertion rates while core heat flux and coolant system temperature lag behind due to the thermal capacity of the fuel and coolant system fluid. Thus, the reactor is tripped prior to a significant increase in heat flux or water temperature with resultant high minimum DNBRs during the transient. As reactivity insertion rate decreases, core heat flux and coolant temperatures remain more nearly in equilibrium with the neutron flux. Thus, minimum DNBR during the transient decreases with decreasing insertion rate.
The overtemperature T reactor trip circuit initiates a reactor trip when two out of four T power divisions exceed an overtemperature T setpoint. This trip circuit is described in Chapter 7 and Reference 13. The TCOLD and THOT signals, which are inputs to the overtemperature T setpoint calculation, are lead-lag compensated to account for the inherent thermal and transport delays in the reactor coolant system in response to power increases.
For reactivity insertion rates less than approximately 40 pcm/s for the minimum feedback cases, the rise in reactor coolant system pressure is sufficiently high that the pressurizer safety valve setpoint is reached prior to reactor trip. Opening of this valve limits the rise in reactor coolant pressure as the temperature continues to rise. Because the overtemperature T reactor trip setpoint is based on both temperature and pressure, limiting the reactor coolant pressure by opening the pressurizer safety valve brings about the overtemperature T earlier than if the valve remains closed. For this reason, the overtemperature T setpoint initiates reactor trip at reactivity insertion rates of approximately 14 pcm/s and below for the minimum feedback cases. For the maximum feedback case, the pressurizer safety valves open prior to reactor trip for reactivity insertion rates as high as 110 pcm/s.
For the minimum feedback case, at reactivity insertion rates less than approximately 14 pcm/s the overtemperature T trip predominates and the effectiveness of the overtemperature T trip increases (in terms of increased minimum DNB) because for these lower reactivity insertion rates, the power increase is slower, the rate of rise of average coolant temperature is slower, and the system lags and delays become less significant.
For reactivity insertion rates less than approximately 3 pcm/s for the minimum feedback cases and less than approximately 70 pcm/s for maximum feedback cases, the rise in the reactor coolant temperature is sufficiently high so that the steam generator safety valve setpoint is reached prior to trip. Opening of these valves, which act as an additional heat load on the reactor coolant system, sharply decreases the rate of increase of reactor coolant system average temperature. This decrease in the rate of increase of the average coolant system temperature during the transient is accentuated by the lead-lag compensation. This causes the overtemperature T setpoint to be reached later, with resulting lower minimum DNBRs.
described in item D above, at lower reactivity insertion rates the overtemperature T trip dominates and the effectiveness of the overtemperature T trip increases (in terms of increased imum DNBR) because for these lower reactivity insertion rates, the power increase is slower, the of rise of average coolant temperature is slower, and the system lags and delays become less ificant.
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back cases, the local minimum in the DNBR curve due to the steam generator safety valves ning is not present.
res 15.4.2-13, 15.4.2-14, and 15.4.2-15 illustrate minimum DNBR calculated for minimum and imum reactivity feedback.
ause the RCCA bank withdrawal at-power incident is an overpower transient, the fuel peratures rise during the transient until after reactor trip occurs. For high reactivity insertion rates, overpower transient is fast with respect to the fuel rod thermal time constant and the core heat lags behind the neutron flux response. Taking into account the effect of the RCCA withdrawal on axial core power distribution, the peak fuel temperature still remains below the fuel melting perature.
slow reactivity insertion rates, the core heat flux remains more nearly in equilibrium with the tron flux. The overpower transient is terminated by the overtemperature T reactor trip before B occurs. Taking into account the effect of the RCCA withdrawal on the axial core power ribution, the peak centerline temperature remains below the fuel melting temperature.
reactor is tripped fast enough during the RCCA bank withdrawal at-power transient that the ty of the primary coolant to remove heat from the fuel rods is not reduced. Thus, the fuel cladding perature does not rise significantly above its initial value during the transient.
calculated sequence of events for this accident, with offsite power available, is shown in le 15.4-1. With the reactor tripped, the plant returns to a stable condition. The plant may be led down further by following normal plant shutdown procedures.
discussed previously in Subsection 15.4.2.1, even if a consequential loss of offsite power and the sequent RCP coastdown were to be explicitly modeled, the minimum DNBR would be predicted ccur during the time period of the RCCA bank withdrawal at-power event prior to the time the flow stdown begins. Therefore, the minimum DNBRs calculated in the analysis are bounding.
4.2.3 Conclusions power range neutron flux instrumentation and overtemperature T trip functions provide quate protection over the entire range of possible reactivity insertion rates. The DNB design is, as defined in Section 4.4, is met for all cases.
4.3 Rod Cluster Control Assembly Misalignment (System Malfunction or Operator Error) 4.3.1 Identification of Causes and Accident Description CA misoperation accidents include:
One or more dropped RCCAs within the same group Statically misaligned RCCA Withdrawal of a single RCCA h RCCA has a position indicator channel which displays the position of the assembly. The lays of assembly positions are grouped for the operators convenience. Fully inserted assemblies 15.4-9 Revision 1
CAs are moved in preselected banks, and the banks are moved in a preselected sequence. Each k of RCCAs is divided into one or two groups of four or five RCCAs each. The rods comprising a up operate in parallel. The two groups in a bank move sequentially such that the first group is ays within one step of the second group in the bank. A definite schedule of actuation (or ctuation) of the stationary gripper, movable gripper, and lift coils of a mechanism is required to draw the RCCA attached to the mechanism. Because the stationary gripper, movable gripper, lift coils associated with the RCCAs of a rod group are driven in parallel, any single failure which ses rod withdrawal affects the entire group. A single electrical or mechanical failure in the plant trol system could, at most, result in dropping one or more RCCAs within the same group.
hanical failures can cause either RCCA insertion or immobility, but not RCCA withdrawal.
dropped RCCAs, dropped RCCA bank, and statically misaligned RCCA events are Condition II dents (incidents of moderate frequency) as defined in Subsection 15.0.1. The single RCCA drawal event is a Condition III incident, as discussed below.
single electrical or mechanical failure in the rod control system could cause the accidental drawal of a single RCCA from the inserted bank at full-power operation. The operator could draw a single RCCA in the control bank because this feature is necessary to retrieve an embly should one be accidentally dropped. The event analyzed results from multiple wiring res or multiple significant operator errors and subsequent and repeated operator disregard of nt indication. The probability of such a combination of conditions is considered low such that the ing consequences may include slight fuel damage.
event is classified as a Condition III incident consistent with the philosophy and format of erican National Standards Institute, ANSI N18.2. By definition, Condition III occurrences include dents, any one of which may occur during the lifetime of a particular plant, and shall not cause e than a small fraction of fuel elements in the reactor to be damaged . . . (Reference 10).
selection of criterion is in accordance with General Design Criterion 25, which states, The ection system shall be designed to assure that specified acceptable fuel design limits are not eeded for any single malfunction of the reactivity control systems, such as accidental withdrawal ejection or dropout) of control rods. (Emphases have been added.) It has been shown that le failures resulting in RCCA bank withdrawals do not violate specified fuel design limits.
eover, no single malfunction can result in the withdrawal of a single RCCA. Thus, it is concluded criterion established for the single rod withdrawal at power is appropriate and in accordance with eral Design Criterion 25.
opped RCCA or RCCA bank may be detected by one or more of the following:
Sudden drop in the core power level as seen by the nuclear instrumentation system Asymmetric power distribution as seen by the incore or excore neutron detectors or core exit thermocouples, through online core monitoring Rod at bottom signal Rod deviation alarm Rod position indication 15.4-10 Revision 1
thermocouples, through online core monitoring Rod deviation alarm Rod position indicators resolution of the rod position indicator channel is +/-5 percent span (+/-7.5 inches). A deviation of RCCA from its group by twice this distance (10 percent of span or 15 inches) does not cause er distributions worse than the design limits. The deviation alarm alerts the operator to rod iation with respect to the group position in excess of 5 percent of span.
e or more of the rod position indicator channels is out of service, operating instructions are wed to verify the alignment of the nonindicated RCCAs. The operator also takes action as uired by the Technical Specifications.
e extremely unlikely event of multiple electrical failures that result in single RCCA withdrawal, rod iation and rod control urgent failure are both displayed to the operator, and the rod position cators indicate the relative positions of the assemblies in the bank. The urgent failure alarm also bits automatic rod motion in the group in which it occurs. Withdrawal of a single RCCA by rator action, whether deliberate or by a combination of errors, results in activation of the same m and the same visual indication. Withdrawal of a single RCCA results in both positive reactivity rtion tending to increase core power and an increase in local power density in the core area ociated with the RCCA. Automatic protection for this event is provided by the overtemperature eactor trip. The Condition III Standard Review Plan Section 15.4.3 evaluation criteria are met; ever, due to the increase in local power density, the limits in Figure 15.0.3-1 may be exceeded.
nt systems and equipment available to mitigate the effects of the various control rod operations are discussed in Subsection 15.0.8 and listed in Table 15.0-6. No single active failure ny of these systems or equipment adversely affects the consequences of the accident.
4.3.2 Analysis of Effects and Consequences 4.3.2.1 Dropped RCCAs, Dropped RCCA Bank, and Statically Misaligned RCCA 4.3.2.1.1 Method of Analysis One or more dropped RCCAs from the same group A drop of one or more RCCAs from the same group results in an initial reduction in the core power and a perturbation in the core radial power distribution. Depending on the worth and position of the dropped rods, this may cause the allowable design power peaking factors to be exceeded. Following the drop, the reduced core power and continued steam demand to the turbine causes the reactor coolant temperature to decrease. In the manual control mode, the plant will establish a new equilibrium condition. The new equilibrium condition is reached through reactivity feedback. In the presence of a negative moderator temperature coefficient, the reactor power rises monotonically back to the initial power level at a reduced inlet temperature with no power overshoot. The absence of any power overshoot establishes the automatic operating mode as a limiting case. If the reactor coolant system temperature reduction is very large, the turbine power may not be able to be maintained due to the reduction in the secondary-side steam pressure and the volumetric flow limit of the turbine system. In this case, the equilibrium power level is less than the initial power. In the automatic control mode, the plant control system detects 15.4-11 Revision 1
characteristics, core reactivity coefficients, the dropped rod worth, and the available control bank worth.
For evaluation of the dropped RCCA event, the transient system response is calculated using the LOFTRAN code (References 3 and 11). The code simulates the neutron kinetics, reactor coolant system, pressurizer, pressurizer safety valves, pressurizer spray, steam generator and steam generator safety valves. The code computes pertinent plant variables, including temperatures, pressures and power level.
Steady-state nuclear models using the computer codes described in Table 4.1-2 are used to obtain a hot channel factor consistent with the primary system transient conditions and reactor power. By combining the transient primary conditions with the hot channel factor from the nuclear analysis, the departure from nucleate boiling design basis is shown to be met using the VIPRE-01 code.
Statically misaligned RCCA Steady-state power distributions are analyzed using the computer codes as described in Table 4.1-2. The peaking factors are then used as input to the VIPRE-01 code to calculate the DNBR.
4.3.2.1.2 Results One or more dropped RCCAs Figures 15.4.3-1 through 15.4.3-4 show the transient response of the reactor to a dropped rod (or rods) in automatic control. The nuclear power and heat flux drop to a minimum value and recover under the influence of both rod withdrawal and thermal feedback. The prompt decrease in power is governed by the dropped rod worth because the plant control system does not respond during the short rod drop time period. The plant control system detects the reduction in core power and initiates control bank withdrawal to restore the primary side power. Power overshoot occurs after which the core power is restored to the initial power level.
The primary system conditions are combined with the hot channel factors from the nuclear analysis for the DNB evaluation. Uncertainties in the initial conditions are included in the DNB evaluation as discussed in Subsection 15.0.3.2. The calculated minimum DNBR for the limiting case for any single or multiple rod drop from the same group is greater than the design limit value described in Section 4.4. The sequence of events for a representative case is shown in Table 15.4-1.
The analysis described previously includes consideration of drops of the RCCA groups which can be selected for insertion as part of the rapid power reduction system. This system is provided to allow the reactor to ride out a complete loss of load from full power without a reactor trip and is described in Subsection 7.7.1.10. If these RCCAs are inadvertently dropped (in the absence of a loss-of-load signal), the transient behavior is the same as for the RCCA drop described. The evaluation showed that the DNBR remains above the design limit value as a result of the inadvertent actuation of the rapid power reduction system.
The consequential loss of offsite power described in Subsection 15.0.14 is not limiting for the dropped RCCA event. Due to the delay from reactor trip until turbine trip and the rapid power 15.4-12 Revision 1
Statically misaligned RCCA The most severe misalignment situations with respect to DNBR arise from cases in which one RCCA is fully inserted, or where the mechanical shim or axial offset rod banks are inserted up to their insertion limit with one RCCA fully withdrawn while the reactor is at full power. Multiple independent alarms, including a bank insertion limit or rod deviation alarm, alert the operator well before the postulated conditions are approached.
For RCCA misalignments in which the mechanical shim or axial offset banks are inserted to their respective insertion limits, with any one RCCA fully withdrawn, the DNBR remains above the safety analysis limit value. This case is analyzed assuming the initial reactor power, pressure, and reactor coolant system temperature are at their nominal values, but with the increased radial peaking factor associated with the misaligned RCCA. Uncertainties in the initial conditions are included in the DNB evaluation as described in Subsection 15.0.3.2.
DNB does not occur for the RCCA misalignment incident, and thus the ability of the primary coolant to remove heat from the fuel rod is not reduced. The peak fuel temperature is that corresponding to a linear heat generation rate based on the radial peaking factor penalty associated with the misaligned RCCA and the design axial power distribution. The resulting linear heat generation is well below that which causes fuel melting.
Following the identification of an RCCA group misalignment condition by the operator, the operator takes action as required by the plant Technical Specifications and operating instructions.
4.3.2.2 Single Rod Cluster Control Assembly Withdrawal 4.3.2.2.1 Method of Analysis er distributions within the core are calculated using the computer codes described in Table 4.1-2.
peaking factors are then used by VIPRE-01 to calculate the DNBR for the event. The case of the st rod withdrawn from the mechanical shim or axial offset bank inserted at the insertion limit, with reactor initially at full power, is analyzed. This incident is assumed to occur at beginning of life ause this results in the minimum value of moderator temperature coefficient. This assumption imizes the power rise and minimizes the tendency of increased moderator temperature to flatten power distribution.
4.3.2.2.2 Results the single rod withdrawal event, two cases are considered as follows:
If the reactor is in the manual control mode, continuous withdrawal of a single RCCA results in both an increase in core power and coolant temperature and an increase in the local hot channel factor in the area of the withdrawing RCCA. In the overall system response, this case is similar to those presented in Subsection 15.4.2. The increased local power peaking in the area of the withdrawn RCCA results in lower minimum DNBRs than for the withdrawn bank cases. Depending on initial bank insertion and location of the withdrawn RCCA, automatic reactor trip may not occur sufficiently fast to prevent the minimum DNBR from falling below the safety analysis limit value. Evaluation of this case at the power and coolant conditions at which the overtemperature T trip is expected to trip the plant shows that an upper limit for the number of rods with a DNBR less than the safety analysis limit value is 5 percent.
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For such cases, a reactor trip ultimately occurs although not sufficiently fast in all cases to prevent a minimum DNBR in the core of less than the safety analysis limit value. Following reactor trip, normal shutdown procedures are followed.
The consequential loss of offsite power described in Subsection 15.0.14 is not limiting for the single RCCA withdrawal event. Due to the delay from reactor trip until turbine trip and the rapid power reduction produced by the reactor trip, the minimum DNBR, for rods where the DNBR did not fall below the design limit value (see Section 4.4) in the cases described, occurs before the reactor coolant pumps begin to coast down.
4.3.3 Conclusions cases of dropped RCCAs or dropped banks, including inadvertent drops of the RCCAs in those ups selected to be inserted as part of the rapid power reduction system, it is shown that the DNBR ains greater than the safety analysis limit value and, therefore, the DNB design basis is met.
cases of any one RCCA fully inserted, or the mechanical shim or axial offset banks inserted to r rod insertion limits with any single RCCA in one of those banks fully withdrawn (static alignment), the DNBR remains greater than the safety analysis limit value (see Section 4.4).
the case of the accidental withdrawal of a single RCCA, with the reactor in the automatic or ual control mode and initially operating at full power with the mechanical shim or axial offset ks at their insertion limits, an upper bound of the number of fuel rods experiencing DNB is rcent of the total fuel rods in the core.
4.4 Startup of an Inactive Reactor Coolant Pump at an Incorrect Temperature Technical Specifications (3.4.4) require all RCPs to be operating while in Modes 1 and 2. The imum initial core power level for the startup of an inactive loop transient is approximately zero
- t. Furthermore, the reactor will initially be subcritical by the Technical Specification requirement.
re will be no increase in core power, and no automatic or manual protective action is required.
4.5 A Malfunction or Failure of the Flow Controller in a Boiling Water Reactor Loop that Results in an Increased Reactor Coolant Flow Rate subsection is not applicable to the AP1000.
4.6 Chemical and Volume Control System Malfunction that Results in a Decrease in the Boron Concentration in the Reactor Coolant 4.6.1 Identification of Causes and Accident Description er than control rod withdrawal, the principal means of positive reactivity insertion to the core is the ition of unborated, primary-grade water from the demineralized water transfer and storage em into the reactor coolant system through the reactor makeup portion of the chemical and me control system. Normal boron dilution with these systems is manually initiated under strict inistrative controls requiring close operator surveillance. Procedures limit the rate and duration of dilution. A boric acid blend system is available to allow the operator to match the makeup water on concentration to that of the reactor coolant system during normal charging.
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igned to limit, even under various postulated failure modes, the potential rate of dilution to values
, with indication by alarms and instrumentation, allowing sufficient time for automatic or operator onse to terminate the dilution.
nadvertent dilution from the demineralized water transfer and storage system through the mical and volume control system may be terminated by isolating the makeup flow to the reactor lant system, by isolating the makeup pump suction line to the demineralized water transfer and age system storage tank, or by tripping the makeup pumps. Lost shutdown margin may be ained by adding borated water (greater than 4000 ppm) to the reactor coolant system from the c acid tank.
erally, to dilute, the operator performs two actions:
Switch control of the makeup from the automatic makeup mode to the dilute mode.
Start the chemical and volume control system makeup pumps.
ure to carry out either of those actions prevents initiation of dilution. Because the AP1000 mical and volume control system makeup pumps do not run continuously (they are expected to perated once per day to make up for reactor coolant system leakage), a makeup pump is started n the volume control system is placed into dilute mode.
status of the reactor coolant system makeup is available to the operator by the following:
Indication of the boric acid and blended flow rates Chemical and volume control system makeup pumps status Deviation alarms, if the boric acid or blended flow rates deviate by more than the specified tolerance from the preset values When reactor is subcritical
- High flux at shutdown alarm
- Indicated source range neutron flux count rates
- Audible source range neutron flux count rate
- Source range neutron flux-multiplication alarm When the reactor is critical
- Axial flux difference alarm (reactor power 50 percent rated thermal power)
- Control rod insertion limit low and low-low alarms
- Overtemperature T alarm (at power)
- Overtemperature T reactor trip
- Power range neutron flux-high, both high and low setpoint reactor trips.
event is a Condition II incident (a fault of moderate frequency), as defined in Subsection 15.0.1.
4.6.2 Analysis of Effects and Consequences on dilutions during refueling, cold shutdown, hot shutdown, hot standby, startup, and power es of operation are considered in this analysis. Conservative values for necessary parameters 15.4-15 Revision 1
em response after detection of a dilution transient in progress.
eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, a loss of offsite power is sidered for the boron dilution case initiated from the power mode of operation (Mode 1) with the tor in manual control. This is the analyzed Mode 1 boron dilution case that produces a reactor turbine trip (Subsection 15.4.6.2.6). The loss of offsite power is assumed to occur as a direct lt of a turbine trip that would disrupt the grid and produce a consequential loss of offsite ower. As discussed in Subsection 15.0.14, that scenario can occur only with the plant at power connected to the grid. Therefore, only a boron dilution case initiated from full power will address consequential loss of offsite power.
4.6.2.1 Dilution During Refueling (Mode 6) uncontrolled boron dilution transient cannot occur during this mode of operation. Inadvertent ion is prevented by administrative controls, which isolate the reactor coolant system from the ntial source of unborated water by locking closed specified valves in the chemical and volume trol system during refueling operations. These valves block the flow paths that allow unborated eup water to reach the reactor coolant system. Makeup which is required during refueling uses er supplied from the boric acid tank (which contains borated water).
4.6.2.2 Dilution During Cold Shutdown (Mode 5) following conditions are assumed for inadvertent boron dilution while in this operating mode:
A dilution flow of 175 gpm of unborated water exists.
A volume of 2592.2 ft3 is a conservative estimate of the minimum active reactor coolant system volume corresponding to the water level at mid-loop in the vessel while on normal residual heat removal. The assumed active volume does not include the volume of the reactor vessel upper head region.
Control rods are fully inserted, which is the normal condition in cold shutdown and a critical boron concentration of 1483 ppm. This is a conservative boron concentration with control rods inserted and allows for the most reactive rod to be stuck in the fully withdrawn position.
The shutdown margin is equal to 1.6-percent k/k, the minimum value identified by the core operating limit report (COLR) for the cold shutdown mode. Combined with the preceding, this gives a shutdown boron concentration of 1675 ppm.
At least one reactor coolant pump will be normally operating during plant operation in Mode 5. It may be possible under some conditions, however, to operate the plant in Mode 5 with no reactor coolant pumps operating. For this reason, the mixing volume assumed for the analysis in Mode 5 will include the reactor coolant loop and normal residual heat removal system volumes that are being actively mixed by the residual heat removal system pumps.
e event of an inadvertent boron dilution transient during cold shutdown, the source range nuclear rumentation detects an increase in the neutron flux by comparing the current source range flux to of about 50 minutes earlier. Upon detecting a sufficiently large flux increase, an alarm is sounded he operator, and valves are actuated to terminate the dilution automatically.
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ed for equipment protection only. This function is not credited in the safety analysis.
automatic protective actions initiate about 11 minutes after the start of dilution. These automatic ons minimize the approach to criticality and maintain the plant in a subcritical condition. After the matic protection functions take place, the operator may take action to restore the Technical cification shutdown margin.
4.6.2.3 Dilution During Safe Shutdown (Mode 4) following conditions are assumed for an inadvertent boron dilution while in this mode:
A dilution flow of 175 gpm of unborated water exists.
Reactor coolant system water volume is 7539.8 ft3. This is a conservative estimate of the minimum active volume of the reactor coolant system while on normal residual heat removal.
All control rods are fully inserted, except the most reactive rod which is assumed stuck in the fully withdrawn position, and a conservative critical boron concentration of 1449 ppm.
The shutdown margin is equal to 1.6-percent k/k, the minimum value required by the core operating limit report (COLR) for the hot shutdown mode. This gives a shutdown boron concentration of 1649 ppm.
The reactor coolant system dilution volume is considered well-mixed. The Technical Specifications require that when in Mode 4, at least one reactor coolant pump shall be operable, which provides sufficient flow through the system to maintain the system well-mixed. If a reactor coolant pump is not operating, the demineralized water isolation valves are closed and an uncontrolled boron dilution transient cannot occur, as discussed in Subsection 15.4.6.2.1.
e event of an inadvertent boron dilution transient during safe shutdown, the source range nuclear rumentation detects a sufficiently large increase in the neutron flux, automatically initiates valve ement to terminate the dilution, and sounds an alarm.
n the actuation of a source range flux doubling signal, the makeup flow to the reactor coolant em and the makeup pump suction line to the demineralized water transfer and storage system age tank are isolated. This thereby terminates the dilution. In addition, the makeup pumps are ed for equipment protection only. This function is not credited in the safety analysis.
protective actions initiate about 28 minutes after the start of the dilution. No operator action is uired to terminate this transient.
4.6.2.4 Dilution During Hot Standby (Mode 3) following conditions are assumed for an inadvertent boron dilution while in this mode:
A dilution flow of 175 gpm of unborated water exists.
The reactor coolant system volume is 7539.8 ft3. This is a conservative estimate of the minimum active volume of the reactor coolant system with the reactor coolant system filled and vented and one reactor coolant pump running.
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The shutdown margin is equal to 1.6-percent k/k, the minimum value required by the core operating limit report (COLR) for the hot standby mode. This gives a shutdown boron concentration of 1509 ppm.
The reactor coolant system dilution volume is considered well-mixed. The Technical Specifications require that when in Mode 3, at least one reactor coolant pump shall be operable, which provides sufficient flow through the system to maintain the system well mixed. If a reactor coolant pump is not operating, the demineralized water isolation valves are closed and an uncontrolled boron dilution transient cannot occur, as discussed in Subsection 15.4.6.2.1.
e event of an inadvertent boron dilution transient in hot standby, the source range nuclear rumentation detects a sufficiently large increase in the neutron flux, automatically initiates valve ement to terminate the dilution, and sounds an alarm. Upon the actuation of a source range flux bling signal, the makeup flow to the reactor coolant system and the makeup pump suction line to demineralized water transfer and storage system storage tank are isolated. This thereby inates the dilution. In addition, the makeup pumps are tripped for equipment protection only. This tion is not credited in the safety analysis.
ective actions initiate about 32 minutes after start of dilution. No operator action is required to inate this transient.
4.6.2.5 Dilution During Startup (Mode 2) plant is in the startup mode only for startup testing at the beginning of each cycle. During this e of operation, rod control is in manual. Normal actions taken to change power level, either up or n, require operator actuation. The Technical Specifications require an available shutdown margin
.6-percent k/k and four reactor coolant pumps operating. Other conditions assumed are the wing:
There is a dilution flow of 200 gpm of unborated water.
Minimum reactor coolant system water volume is 8126 ft3. This is a very conservative estimate of the active reactor coolant system volume, minus the pressurizer volume.
An initial maximum critical boron concentration, corresponding to the rods inserted to the insertion limits, is 1327 ppm. The minimum change in boron concentration from this initial condition to a hot zero power critical condition with all rods inserted is 1088 ppm. Full rod insertion, minus the most reactive stuck rod, occurs because of reactor trip.
mode of operation is a transitory operational mode in which the operator intentionally dilutes and draws control rods to take the plant critical. During this mode, the plant is in manual control. For a mal approach to criticality, the operator manually withdraws control rods and dilutes the reactor lant with unborated water at controlled rates until criticality is achieved. Once critical, the power alation is slow enough to allow the operator to manually block the source range reactor trip after iving the P-6 permissive signal from the intermediate range detectors (nominally at 105 cps). Too a power escalation (due to an unknown dilution) would result in reaching P-6 unexpectedly, ing insufficient time to manually block the source range reactor trip. Failure to perform this ual action results in a reactor trip and immediate shutdown of the reactor.
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itionally, the suction lines for the chemical and volume control system pumps are automatically igned to draw borated water from the chemical and volume control system boric acid tank.
r reactor trip, the dilution would have to continue for approximately 383 minutes to overcome the ilable shutdown margin. Even assuming that the non-safety-related boration operation does not ur, the unborated water that may remain in the purge volume of the chemical and volume control em is not sufficient to return the reactor to criticality. Therefore, the automatic termination of the ion flow from the demineralized water transfer and storage system prevents a post-trip return to cality.
4.6.2.6 Dilution During Full Power Operation (Mode 1) plant may be operated at power two ways: automatic Tavg/rod control and under operator control.
COLR and Technical Specifications require an available shutdown margin of 1.6-percent k/k four reactor coolant pumps operating. With the plant at power and the reactor coolant system at sure, the dilution rate is limited by the capacity of the chemical and volume control system eup pumps. The analysis is performed assuming two chemical and volume control system ps are in operation, even though normal operation is with one pump. Conditions assumed for a ion in this mode are the following:
There is a dilution flow of 200 gpm of unborated water.
Minimum reactor coolant system water volume is 8126 ft3. This is a very conservative estimate of the active reactor coolant system volume, minus the pressurizer volume.
An initial maximum critical boron concentration, corresponding to the rods inserted to the insertion limits, is 1080 ppm. The minimum change in boron concentration from this initial condition to a hot zero power critical condition with all rods inserted is 841 ppm. Full rod insertion, minus the most reactive stuck rod, occurs due to reactor trip.
h the reactor in manual control and no operator action taken to terminate the transient, the power temperature rise causes the reactor to reach the overtemperature T trip setpoint resulting in a tor trip. Upon any reactor trip signal, a safety-related function automatically isolates the orated water from the demineralized water transfer and storage system and thereby terminates dilution. Additionally, the suction lines for the chemical and volume control system pumps are matically realigned to draw borated water from the chemical and volume control system boric tank.
ause the realignment of the suction for the chemical and volume control system pumps to the c acid tank is a non-safety-related operation, the only consideration given to the reboration phase e event in the safety analysis is the unborated purge volume.
r reactor trip, the dilution would have to continue for at least 325 minutes to overcome the ilable shutdown margin. The unborated water that may remain in the purge volume of the mical and volume control system does not return the reactor to criticality. Therefore, the automatic ination of the dilution flow from the demineralized water transfer and storage system precludes a t-trip return to criticality.
uld a consequential loss of offsite power occur after reactor and turbine trip, it does not alter the that the dilution event has been terminated by automatic protection features. As indicated iously, the reactor trip signal that occurs in parallel with the turbine trip will actuate a 15.4-19 Revision 1
trol system flow be restored, the unborated water that may remain in the purge volume of the mical and volume control system will still not return the reactor to criticality.
boron dilution transient in this case is essentially the equivalent to an uncontrolled rod withdrawal ower (see Subsection 15.4.2). The maximum reactivity insertion rate for a boron dilution transient onservatively estimated to be in the range of 0.5 to 0.8 pcm per second and is within the range of rtion rates analyzed for uncontrolled rod withdrawal at power. Before reaching the rtemperature T reactor trip, the operator receives an alarm on overtemperature T and an rtemperature T turbine runback.
h the reactor in automatic rod control, the pressurizer level controller limits the dilution flow rate to maximum letdown rate. If a dilution rate in excess of the letdown rate is present, the pressurizer l controller throttles charging flow down to match letdown rate. For the safety analysis, a servative dilution flow rate of 200 gpm is assumed. With the reactor in automatic rod control, a on dilution results in a power and temperature increase in such a way that the rod controller mpts to compensate by slow insertion of the control rods. This action by the controller results in at t three alarms to the operator:
Rod insertion limit - low level alarm Rod insertion limit - low-low level alarm if insertion continues Axial flux difference alarm (I outside of the target band) en the many alarms, indications, and the inherent slow process of dilution at power, the operator sufficient time for action. The operator has at least 328 minutes from the rod insertion limit low-alarm until shutdown margin is lost at beginning of cycle. The time is significantly longer at end of e because of the low initial boron concentration.
ause the analysis for the boron dilution event with the reactor in automatic rod control does not dict a reactor and turbine trip, considering the consequential loss of offsite power for this case is needed.
preceding results demonstrate that in all modes of operation, an inadvertent boron dilution is ented or responded to by automatic functions, or sufficient time is available for operator action to inate the transient. Following termination of the dilution flow and initiation of boration, the reactor a stable condition.
4.6.3 Conclusions vertent boron dilution events are prevented during refueling and automatically terminated during shutdown, safe shutdown, and hot standby modes. Inadvertent boron dilution events during tup or power operation, if not detected and terminated by the operators, result in an automatic tor trip. Following reactor trip, automatic termination of the dilution occurs and post-trip return to cality is prevented.
4.7 Inadvertent Loading and Operation of a Fuel Assembly in an Improper Position 4.7.1 Identification of Causes and Accident Description l and core loading errors can inadvertently occur, such as those arising from the inadvertent ing of one or more fuel assemblies into improper positions, having a fuel rod with one or more ets of the wrong enrichment, or having a full fuel assembly with pellets of the wrong enrichment.
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error in enrichment, beyond the normal manufacturing tolerances, can cause power shapes more ked than those calculated with the correct enrichments. A 5-percent uncertainty margin is uded in the design value of power peaking factor assumed in the analysis of Condition I and dition II transients. The online core monitoring system is used to verify power shapes at the start e and is capable of revealing fuel assembly enrichment errors or loading errors that cause power pes to be peaked in excess of the design value. Power-distribution-related measurements are rporated into the evaluation of calculated power distribution information using the incore rumentation processing algorithms contained within the online monitoring system. The processing rithms contained within the online monitoring system are functionally identical to those orically used for the evaluation of power distributions measurements in Westinghouse surized water reactors.
h fuel assembly is marked with an identification number and loaded in accordance with a core-ing diagram to reduce the probability of core loading errors. During core loading, the tification number is checked before each assembly is moved into the core. Serial numbers read ng fuel movement are subsequently recorded on the loading diagram as a further check on per placement after the loading is completed.
power distortion due to a combination of misplaced fuel assemblies could significantly increase king factors and is readily observable with the online core monitoring system. The fixed incore rumentation within the instrumented fuel assembly locations is augmented with core exit mocouples. There is a high probability that these thermocouples would also indicate any ormally high coolant temperature rise. Incore flux measurements are taken during the startup sequent to every refueling operation.
event is a Condition III incident (an infrequent fault) as defined in Subsection 15.0.1.
4.7.2 Analysis of Effects and Consequences 4.7.2.1 Method of Analysis ady-state power distributions in the x-y plane of the core are calculated at 30-percent rated mal power using the three-dimensional nodal code ANC (Reference 7). Representative power ributions in the x-y plane for a correctly loaded core are described in Chapter 4.
each core loading error case analyzed, the percent deviations from detector readings for a mally loaded core are shown in the incore detector locations. (See Figures 15.4.7-1 through
.7-4.)
4.7.2.2 Results following core loading error cases are analyzed:
e A:
e in which a Region 1 assembly is interchanged with a Region 3 assembly. The particular case sidered is the interchange of two assemblies near the periphery of the core (see Figure 15.4.7-1).
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particular case considered, the interchange is assumed to take place close to the core center and burnable poison rods located in the correct Region 2 position, but in a Region 1 assembly akenly loaded in the Region 2 position (see Figure 15.4.7-2).
e C:
chment error - Case in which a Region 2 fuel assembly is loaded in the core central position (see re 15.4.7-3).
e D:
e in which a Region 2 fuel assembly instead of a Region 1 assembly is loaded near the core phery (see Figure 15.4.7-4).
4.7.3 Conclusions l assembly enrichment errors are prevented by administrative procedures implemented in ication.
e event that a single pin or pellet has a higher enrichment than the nominal value, the sequences in terms of reduced DNBR and increased fuel and cladding temperatures are limited e incorrectly loaded pin or pins and perhaps the immediately adjacent pins.
l assembly loading errors are prevented by administrative procedures implemented during core ing. In the unlikely event that a loading error occurs, analyses in this section confirm that lting power distribution effects are either readily detected by the online core monitoring system or se a sufficiently small perturbation to be acceptable within the uncertainties allowed between inal and design power shapes.
4.8 Spectrum of Rod Cluster Control Assembly Ejection Accidents 4.8.1 Identification of Causes and Accident Description accident is defined as the mechanical failure of a control rod mechanism pressure housing, lting in the ejection of an RCCA and drive shaft. The consequence of this mechanical failure is a d positive reactivity insertion together with an adverse core power distribution, possibly leading to lized fuel rod damage.
4.8.1.1 Design Precautions and Protection 4.8.1.1.1 Mechanical Design mechanical design is discussed in Section 4.6. Mechanical design and quality control edures intended to prevent the possibility of an RCCA drive mechanism housing failure are listed w:
Each control rod drive mechanism housing is completely assembled and shop tested at 4100 psi.
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Stress levels in the mechanism are not affected by anticipated system transients at power or by the thermal movement of the coolant loops. Moments induced by the safe shutdown earthquake can be accepted within the allowable primary working stress range specified by the ASME Code,Section III, for Class 1 components.
The latch mechanism housing and rod travel housing are each a single length of forged stainless steel. This material exhibits excellent notch toughness at temperatures that are encountered.
gnificant margin of strength in the elastic range together with the large energy absorption ability in the plastic range gives additional confidence that gross failure of the housing does not ur. The joints between the latch mechanism housing and head adapter, and between the latch hanism housing and rod travel housing, are threaded joints reinforced by canopy-type rod welds, ch are subject to periodic inspections.
4.8.1.1.2 Nuclear Design rupture of an RCCA drive mechanism housing is postulated, the operation using chemical shim is h that the severity of an ejected RCCA is inherently limited. In general, the reactor is operated the power control (or mechanical shim) RCCAs inserted only far enough to permit load follow.
axial offset RCCAs are positioned so that the targeted axial offset can be met throughout core Reactivity changes caused by core depletion and xenon transients are normally compensated for oron changes and the mechanical shim banks, respectively. Further, the location and grouping of power control and axial offset RCCAs are selected with consideration for an RCCA ejection dent. Therefore, should an RCCA be ejected from its normal position during full-power operation, ss severe reactivity excursion than analyzed is expected.
ay occasionally be desirable to operate with larger than normal insertions. For this reason, a er control and axial offset rod insertion limit is defined as a function of power level. Operation with RCCAs above this limit provides adequate shutdown capability and an acceptable power ribution. The position of the RCCAs is continuously indicated in the main control room. An alarm urs if a bank of RCCAs approaches its insertion limit or if one RCCA deviates from its bank.
rating instructions require boration at the low level alarm and emergency boration at the low-low l alarm.
4.8.1.1.3 Reactor Protection reactor protection in the event of a rod ejection accident is described in WCAP-15806-P-A, ference 4). The protection for this accident is provided by the high neutron flux trip (high and low ing) and the high rate of neutron flux increase trip. These protection functions are described in tion 7.2.
4.8.1.1.4 Effects on Adjacent Housings ures of an RCCA mechanism housing, due to either longitudinal or circumferential cracking, does cause damage to adjacent housings. The control rod drive mechanism is described in section 3.9.4.1.1.
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4.8.1.1.7 Consequences probability of damage to an adjacent housing is considered remote. If damage is postulated, it is expected to lead to a more severe transient because RCCAs are inserted in the core in metric patterns and control rods immediately adjacent to worst ejected rods are not in the core n the reactor is critical. Damage to an adjacent housing could, at worst, cause that RCCA not to on receiving a trip signal. This is already taken into account in the analysis by assuming a stuck adjacent to the ejected rod.
4.8.1.1.8 Summary ure of a control rod housing does not cause damage to adjacent housings that increase the erity of the initial accident.
4.8.1.2 Limiting Criteria event is a Condition IV incident (ANSI N18.2). See Subsection 15.0.1 for a discussion of ANS sification. Because of the extremely low probability of an RCCA ejection accident, some fuel age is considered an acceptable consequence.
REG-0800 Standard Review Plan (SRP) 4.2, Revision 3 (Reference 24), interim criteria licable to new plant design certification are applied to provide confidence that there is little or no sibility of fuel dispersal in the coolant, gross lattice distortion, or severe shock waves. These ria are the following:
The pellet clad mechanical interaction (PCMI) failure criteria is a change in radial average fuel enthalpy greater than the corrosion-dependent limit depicted in Figure B-1 of SRP 4.2, Revision 3, Appendix B.
The high cladding temperature failure criteria for zero-power conditions is a peak radial average fuel enthalpy greater than 170 cal/g for fuel rods with an internal rod pressure at or below system pressure and 150 cal/g for fuel rods with an internal rod pressure exceeding system pressure.
For intermediate (greater than 5-percent rated thermal power) and full-power conditions, fuel cladding is presumed to fail if local heat flux exceeds thermal design limits (e.g., DNBR).
For core coolability, it is conservatively assumed that the average fuel pellet enthalpy at the hot spot remains below 200 cal/g (360 Btu/lb) for irradiated fuel. This bounds non-irradiated fuel, which has a slightly higher enthalpy limit.
For core coolability, the peak fuel temperature must remain below incipient fuel melting conditions.
Mechanical energy generated as a result of (1) non-molten fuel-to-coolant interaction and (2) fuel rod burst that must be addressed with respect to reactor pressure boundary, reactor internals, and fuel assembly structural integrity.
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Peak reactor coolant system pressure is less than that which could cause stresses to exceed the Service Limit C as defined in the ASME code.
4.8.2 Analysis of Effects and Consequences hod of Analysis calculation of the RCCA ejection transients is performed in two stages: first, an average core ulation and then, a hot rod calculation. The average core calculation is performed using spatial tron kinetics methods to determine the average power generation with time, including the various l core feedback effects (Doppler reactivity and moderator reactivity). Enthalpy, fuel temperature, DNB transients are then determined by performing a conservative fuel rod transient heat transfer ulation.
scussion of the method of analysis appears in WCAP-15806-P-A (Reference 4).
rage Core Analysis three-dimensional nodal code ANC (References 14, 15, 16, 17, 21, 22, and 27) is used for the rage core transient analysis. This code solves the two-group neutron diffusion theory kinetic ation in three spatial dimensions (rectangular coordinates) for six delayed neutron groups. The moderator and fuel temperature feedbacks are based on the NRC approved Westinghouse ion of the VIPRE-01 code and methods (References 18 and 19).
Rod Analysis hot fuel rod models are based on the Westinghouse VIPRE models described in AP-15806-P-A (Reference 4). The hot rod model represents the hottest fuel rod from any channel e core. VIPRE performs the hot rod transients for fuel enthalpy, temperature, and DNBR using as t the time dependent nuclear core power and power distribution from the core average analysis.
escription of the VIPRE code is provided in Reference 18.
tem Overpressure Analysis e fuel coolability limits are not exceeded, the fuel dispersal into the coolant or a sudden pressure ease from thermal to kinetic energy conversion is not needed to be considered in the rpressure analysis. Therefore, the overpressure condition may be calculated on the basis of ventional fuel rod to coolant heat transfer and the prompt heat generation in the coolant. The em overpressure analysis is conducted by first performing the core power response analysis to in the nuclear power transient (versus time) data. The nuclear power data is then used as input plant transient computer code to calculate the peak reactor coolant system pressure.
code calculates the pressure transient, taking into account fluid transport in the reactor coolant em and heat transfer to the steam generators. For conservatism, no credit is taken for the sible pressure reduction caused by the assumed failure of the control rod pressure housing.
4.8.2.1 Calculation of Basic Parameters t parameters for the analysis are conservatively selected as described in Reference 4.
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ic methods. Standard nuclear design codes are used in the analysis.The calculation is performed he maximum allowed bank insertion at a given power level, as determined by the rod insertion
- s. Adverse xenon distributions are considered in the calculation.
ropriate safety analysis allowances are added to the ejected rod worth and hot channel factors to ount for calculational uncertainties, including an allowance for nuclear peaking due to sification as discussed in Reference 4.
4.8.2.1.2 Not Used 4.8.2.1.3 Moderator and Doppler Coefficients critical boron concentration is adjusted in the nuclear code to obtain a moderator temperature fficient that is conservative compared to actual design conditions for the plant consistent with erence 4. The fuel temperature feedback in the neutronics code is reduced consistent with erence 4 requirements.
4.8.2.1.4 Delayed Neutron Fraction, eff culations of the effective delayed neutron fraction (eff) typically yield values no less than percent at end of cycle. The accident is sensitive to eff if the ejected rod worth is equal to or ater than eff . To allow for future cycles, a pessimistic estimate of eff of 0.44 percent is used in analysis.
4.8.2.1.5 Trip Reactivity Insertion trip reactivity insertion accounts for the effect of the ejected rod and one adjacent stuck rod. The reactivity is simulated by dropping a limited set of rods of the required worth into the core. The t of rod motion occurs 0.9 second after the high neutron flux trip setpoint is reached. This delay is umed to consist of 0.583 second for the instrument channel to produce a signal, 0.167 second for trip breakers to open, and 0.15 second for the coil to release the rods. A curve of trip rod insertion us time is used, which assumes that insertion to the dashpot does not occur until 2.47 seconds r the start of fall. The choice of such a conservative insertion rate means that there is over cond after the trip setpoint is reached before significant shutdown reactivity is inserted into the
. This conservatism is important for the hot full power accidents.
minimum design shutdown margin available at hot zero power may be reached only at end of life e equilibrium cycle. This value includes an allowance for the worst stuck rod, adverse xenon ribution, conservative Doppler and moderator defects, and an allowance for calculational ertainties. Calculations show that the effect of two stuck RCCAs (one of which is the worst ejected is to reduce the shutdown by about an additional 1-percent k. Therefore, following a reactor trip lting from an RCCA ejection accident, the reactor is subcritical when the core returns to hot zero er.
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tron flux trip (high and low setting) and the high rate of neutron flux increase trip. These protection tions are part of the protection and safety monitoring system. No single failure of the protection safety monitoring system negates the protection functions required for the rod ejection accident dversely affects the consequences of the accident.
4.8.2.1.7 Results all cases, the core is preconditioned by assuming a fuel cycle depletion with control rod insertion is conservative relative to expected baseload operation. All cases assume that the mechanical and axial offset control RCCAs are inserted to their insertion limits before the event and xenon kewed to yield a conservative initial axial power shape. The limiting RCCA ejection cases for a cal cycle are summarized following the criteria outlined in Subsection 15.4.8.1.2.
PCMI and high cladding temperature (hot zero power)
The resulting maximum fuel average enthalpy rise and maximum fuel average enthalpy are less than the criteria given in Subsection 15.4.8.1.2.
High cladding temperature (5% rated thermal power)
The fraction of the core calculated to have a DNBR less than the safety analysis limit is less than the amount of failed fuel assumed in the dose analysis described in Subsection 15.4.8.3.
Core coolability The resulting maximum fuel average enthalpy is less than the criterion given in Subsection 15.4.8.1.2. Fuel melting is not predicted to occur at the hot spot.
re are no fuel failures due to the fuel enthalpy deposition, i.e., both fuel and cladding enthalpy s were met. Additionally, the coolability criteria for peak fuel enthalpy and the fuel melting criteria e met. Therefore, the fuel dispersal into the coolant, a sudden pressure increase from thermal to tic energy conversion, gross lattice distortion, or severe shock waves are precluded.
nuclear power and fuel transients for the limiting cases are presented in Figures 15.4.8-1 ugh 15.4.8-3.
calculated sequence of events for the limiting cases is presented in Table 15.4-1. Reactor trip urs early in the transients, after which the nuclear power excursion is terminated.
ejection of an RCCA constitutes a break in the reactor coolant system, located in the reactor sure vessel head. The effects and consequences of loss-of-coolant accidents (LOCAs) are ussed in Subsection 15.6.5. Following the RCCA ejection, the plant response is the same as a A.
consequential loss of offsite power described in Subsection 15.0.14 is not limiting for the alpy and temperature transients resulting from an RCCA ejection accident. Due to the delay from tor trip until turbine trip and the rapid power reduction produced by the reactor trip, the peak fuel cladding temperatures occur before the reactor coolant pumps begin to coast down.
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sidered, less than 10 percent of the rods are assumed to enter DNB based on a detailed three-ensional kinetics and hot rod analysis. The maximum fuel average enthalpy rise of rods predicted nter DNB will be less than 60 cal/g. Fuel melting does not occur at the hot spot.
consequential loss of offsite power described in Subsection 15.0.14 is not limiting for the ulation of the number of rods assumed to enter DNB for the RCCA ejection accident. Due to the y from reactor trip until turbine trip and the rapid power reduction produced by the reactor trip, the imum DNBR, for rods where the DNBR did not fall below the design limit (see Section 4.4) in the es described, occurs before the reactor coolant pumps begin to coast down.
4.8.2.1.9 Peak Reactor Coolant System Pressure culations of the peak reactor coolant system pressure demonstrate that the peak pressure does exceed that which would cause the stress to exceed the Service Level C Limit as described in the ME Code,Section III. Therefore, the accident for this plant does not result in an excessive sure rise or further damage to the reactor coolant system.
consequential loss of offsite power described in Subsection 15.0.14 is not limiting for the sure surge transient resulting from an RCCA ejection accident. Due to the delay from reactor trip l turbine trip and the rapid power reduction produced by the reactor trip, the peak system sure occurs before the reactor coolant pumps begin to coast down.
4.8.2.1.10 Lattice Deformations rge temperature gradient exists in the region of the hot spot. Because the fuel rods are free to e in the vertical direction, differential expansion between separate rods cannot produce ortion. However, the temperature gradients across individual rods may produce a differential ansion, tending to bow the midpoint of the rods toward the hotter side of the rod.
culations indicate that this bowing results in a negative reactivity effect at the hot spot because the is undermoderated, and bowing tends to increase the undermoderation at the hot spot. In tice, no significant bowing is anticipated because the structural rigidity of the core is sufficient to stand the forces produced.
ing in the hot spot region would produce a net flow away from that region. However, the heat from fuel is released to the water relatively slowly, and it is considered inconceivable that crossflow is cient to produce lattice deformation. Even if massive and rapid boiling, sufficient to distort the ces, is hypothetically postulated, the large void fraction in the hot spot region produces a uction in the total core moderator to fuel ratio and a large reduction in this ratio at the hot spot.
net effect is therefore a negative feedback.
onclusion, no credible mechanism exists for a net positive feedback resulting from lattice rmation. In fact, a small negative feedback may result. The effect is conservatively ignored in the lysis.
4.8.3 Radiological Consequences evaluation of the radiological consequences of a postulated rod ejection accident assumes the reactor is operating with a limited number of fuel rods containing cladding defects and that ing steam generator tubes result in a buildup of activity in the secondary coolant. See section 15.4.8.3.1 and Table 15.4-4.
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section 15.4.8.2.1.8).
vity released to the containment via the spill from the reactor vessel head is assumed to be ilable for release to the environment because of containment leakage. Activity carried over to the ondary side due to primary-to-secondary leakage is available for release to the environment ugh the steam line safety or power-operated relief valves.
4.8.3.1 Source Term significant radionuclide releases due to the rod ejection accident are the iodines, alkali metals, noble gases. The reactor coolant iodine source term assumes a pre-existing iodine spike. The tor coolant noble gas concentrations are assumed to be those associated with equilibrium rating limits for primary coolant noble gas activity. The initial reactor coolant alkali metal centrations are assumed to be those associated with the design fuel defect level.These initial tor coolant activities are of secondary importance compared to the release of fission products the portion of the core assumed to fail.
ed on NUREG-1465 (Reference 12), the fission product gap fraction is 3 percent of fuel ntory. For this analysis, the gap fractions are modified following the guidance of Draft Guide 1199 ference 25), which incorporates the effects of enthalpy rise in the fuel following the reactivity rtion, consistent with Appendix B of SRP 4.2, Revision 3 (Reference 24). Draft Guide 1199 uded expanded guidance for determining nuclide gap fractions available for release following a ejection. Reference 26 was issued as a clarification to the gap fraction guidance in Draft de 1199. An enthalpy rise of 60 cal/gm is used to calculate the gap fractions (see section 15.4.8.2.1.8). Also, to address the fact that the failed fuel rods may have been rating at power levels above the core average, the source term is increased by the lead rod al peaking factor. No fuel melt is calculated to occur as a result of the rod ejection (see section 15.4.8.2.1.8).
4.8.3.2 Release Pathways re are three components to the accident releases:
The activity initially in the secondary coolant is available for release as long as steam releases continue.
The reactor coolant leaking into the steam generators is assumed to mix with the secondary coolant. The activity from the primary coolant mixes with the secondary coolant and, as steam is released, a portion of the iodine and alkali metal in the coolant is released. The fraction of activity released is defined by the assumed flashing fraction and the partition coefficient assumed for the steam generator. The noble gas activity entering the secondary side is released to the environment. These releases are terminated when the steam releases stop.
The activity from the reactor coolant system and the core is released to the containment atmosphere and is available for leakage to the environment through the assumed design basis containment leakage.
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4.8.3.3 Dose Calculation Models models used to calculate doses are provided in Appendix 15A.
4.8.3.4 Analytical Assumptions and Parameters assumptions and parameters used in the analysis are listed in Table 15.4-4.
4.8.3.5 Identification of Conservatisms assumptions used in the analysis contain a number of conservatisms:
Although fuel damage is assumed to occur as a result of the accident, no fuel damage is anticipated.
The reactor coolant activities are based on conservative assumptions (refer to Table 15.4-4);
whereas, the activities based on the expected fuel defect level are far less (see Section 11.1).
The leakage of reactor coolant into the secondary system, at 300 gallons per day, is conservative. The leakage is normally a small fraction of this.
It is unlikely that the conservatively selected meteorological conditions are present at the time of the accident.
The leakage from containment is assumed to continue for a full 30 days. It is expected that containment pressure is reduced to the point that leakage is negligible before this time.
4.8.3.6 Doses ng the assumptions from Table 15.4-4, the calculated total effective dose equivalent (TEDE) es are determined to be 4.0 rem at the site boundary for the limiting 2-hour interval (0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) 5.9 rem at the low population zone outer boundary. These doses are well within the dose eline of 25 rem TEDE identified in 10 CFR Part 50.34. The phrase well within is taken as being ercent or less.
he time the rod ejection accident occurs, the potential exists for a coincident loss of spent fuel l cooling with the result that the pool could reach boiling and a portion of the radioactive iodine in spent fuel pool could be released to the environment. The loss of spent fuel pool cooling has n evaluated for a duration of 30 days. There is no contribution to the 2-hour site boundary dose ause the pool boiling would not occur until after the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 30-day contribution to the e at the low population zone boundary is less than 0.01 rem TEDE, and when this is added to the e calculated for the rod ejection accident, the resulting total dose remains less than the value orted above.
4.9 Combined License Information section contained no requirement for additional information.
15.4-30 Revision 1
Computer Code, WCAP-7979-P-A (Proprietary) and WCAP-8028-A (Nonproprietary),
January 1975.
Hargrove, H. G., FACTRAN--A FORTRAN-IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908-A, December 1989.
Burnett. T. W. T., et al., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984.
Beard, C. L. et al., Westinghouse Control Rod Ejection Accident Analysis Methodology Using Multi-Dimensional Kinetics, WCAP-15806-P-A (Proprietary) and WCAP-15807-NP-A (Nonproprietary), November 2003.
Taxelius, T. G., ed, Annual Report-SPERT Project, October 1968, September 1969, Idaho Nuclear Corporation, IN-1370, June 1970.
Liimataninen, R. C., and Testa, F. J., Studies in TREAT of Zircaloy-2-Clad, UO2-Core Simulated Fuel Elements, ANL-7225, January-June 1966, p 177, November 1966.
Liu, Y. S., et al., ANC - A Westinghouse Advanced Nodal Computer Code, WCAP-10965-P-A (Proprietary) and WCAP-10966-A (Nonproprietary), September 1986.
Not Used.
Friedland, A. J., and Ray, S., Revised Thermal Design Procedure, WCAP-11397-P-A (Proprietary) and WCAP-11397-A (Nonproprietary), April 1989.
American National Standards Institute N18.2, Nuclear Safety Criteria for the Design of Stationary PWR Plants, 1973.
AP1000 Code Applicability Report, WCAP-15644-P (Proprietary) and WCAP-15644-NP (Nonproprietary), Revision 2, March 2004.
Soffer, L. et al., Accident Source Terms for Light-Water Nuclear Power Plants, NUREG-1465, February 1995.
Not Used Nguyen, T. Q., et al., Qualifications of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, WCAP-11596-P-A (Proprietary) and WCAP-11597-A (Nonproprietary), June 1988.
Ouisloumen, M., et al., Qualification of the Two-Dimensional Transport Code PARAGON, WCAP-16045-P-A (Proprietary) and WCAP-16045-NP-A (Nonproprietary), August 2004.
Liu, Y. S., ANC - A Westinghouse Advanced Nodal Computer Code; Enhancements to ANC Rod Power Recovery, WCAP-10965-P-A, Addendum 1 (Proprietary) and WCAP-10966-A Addendum 1 (Nonproprietary), April 1989.
15.4-31 Revision 1
Sung, Y. X., Schueren, P., and Meliksetian, A., VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCA Thermal-Hydraulic Safety Analysis, WCAP-14565-P-A (Proprietary) and WCAP-15306-NP-A (Nonproprietary), October 1999.
Stewart, C. W., et al., VIPRE-01: A Thermal/Hydraulic Code for Reactor Cores, Volumes 1, 2, 3 (Revision 3, August 1989), and Volume 4 (April 1987), NP-2511-CCM-A, Electric Power Research Institute, Palo Alto, California.
Foster, J. P. and Sidener, S., Westinghouse Improved Performance Analysis and Design Model (PAD 4.0), WCAP-15063-P-A, Revision 1 with Errata (Proprietary) and WCAP-15064-NP-A (Nonproprietary), July 2000.
Zhang, B., et al., Qualification of the NEXUS Nuclear Data Methodology, WCAP-16045-P-A, Addendum 1-A (Proprietary) and WCAP-16045-NP-A, Addendum 1-A (Nonproprietary),
August 2007.
Zhang, B., et al., Qualification of the New Pin Power Recovery Methodology, WCAP-10965-P-A, Addendum 2-A (Proprietary), September 2010.
Smith, L. D , et al., Modified WRB-2 Correlation, WRB-2M, for Predicting Critical Heat Flux in 17x17 Rod Bundles with Modified LPD Mixing Vane Grids, WCAP-15025-P-A (Proprietary) and WCAP-15026-NP-A (Nonproprietary), April 1999.
NUREG-0800, Standard Review Plan, Section 4.2, Revision 3, Fuel System Design, Appendix B, Interim Acceptance Criteria and Guidance for the Reactivity Initiated Accidents, March 2007.
Draft Regulatory Guide DG-1199, Proposed Revision 1 of Regulatory Guide 1.183; Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors, October 2009. NRC ADAMS Accession Number: ML090960464.
NRC Memorandum from Anthony Mendiola to Travis Tate, Technical Basis for Revised Regulatory Guide 1.183 (DG-1199) Fission Product Fuel-to-Cladding Gap Inventory, July 2011. NRC ADAMS Accession Number: ML111890397.
Letter from Liparulo, N. J. (Westinghouse) to Jones, R. C. (NRC), Process Improvement to the Westinghouse Neutronics Code System, NSD-NRC-96-4679, March 29, 1996.
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Reactivity and Power Distribution Anomalies Time Accident Event (seconds) ontrolled RCCA bank withdrawal Initiation of uncontrolled rod withdrawal from 10-9 of nominal 0.0 a subcritical or low-power power tup condition Power range high neutron flux (low setting) setpoint reached 10.4 Peak nuclear power occurs 10.6 Rods begin to fall into core 11.3 Peak heat flux occurs 12.7 Minimum DNBR occurs 12.7 Peak average clad temperature occurs 13.3 Peak average fuel temperature occurs 13.4 or more dropped RCCAs Rods drop 0.0 Control system initiates control bank withdrawal 0.4 Peak nuclear power occurs 21.7 Peak core heat flux occurs 24.2 ontrolled RCCA bank withdrawal ower Case A Initiation of uncontrolled RCCA withdrawal at a high-reactivity 0.0 insertion rate (75 pcm/s)
Power range high neutron flux high trip point reached 6.6 Rods begin to fall into core 7.5 Minimum DNBR occurs 7.7 Loss of ac power occurs 15.2 Case B Initiation of uncontrolled RCCA withdrawal at a small reactivity 0.0 insertion rate (3 pcm/s)
Overtemperature T setpoint reached 524.4 Rods begin to fall into core 526.4 Minimum DNBR occurs 526.7 Loss of ac power occurs 534.1 15.4-33 Revision 1
Time Accident Event (seconds) mical and volume control em malfunction that results in a ease in the boron concentration e rector coolant Dilution during startup Power range - low setpoint reactor trip due to dilution 0.0 Dilution automatically terminated by demineralized water 215.0 transfer and storage system isolation Dilution during full-power Operation
- a. Automatic reactor control Operator receives low-low rod insertion limit alarm due to 0.0 dilution Shutdown margin lost 19,680
- b. Manual reactor control Initiate dilution 0.0 Reactor trip on overtemperature T due to dilution 180.0 Dilution automatically terminated by demineralized water 395.0 transfer and storage system isolation CA ejection accident PCMI limiting event Initiation of rod ejection 0.00 Peak nuclear power occurs 0.14 Reactor trip setpoint reached <0.30 Peak cladding temperature occurs 0.36 Peak enthalpy deposition occurs 0.44 Rods begin to fall into core 1.20 Peak cladding temperature Initiation of rod ejection 0.00 limiting event Power range high neutron flux (low setting) setpoint reached 0.37 Peak nuclear power occurs 0.08 Minimum DNBR occurs 0.11 Peak cladding temperature occurs 0.11 Reactor trip setpoint reached <0.30 Rods begin to fall into core 1.20 Peak enthalpy/peak fuel Initiation of rod ejection 0.00 centerline temperature event Peak nuclear power occurs 0.06 Reactor trip setpoint reached <0.30 Rods begin to fall into core 1.20 Peak fuel center temperature occurs 2.50 Peak cladding temperature occurs 2.80 15.4-34 Revision 1
Assumed Dilution Flow Rates Mode Flow Rate (gal/min) 3 through 5 175 1 through 2 200 Volume Mode Volume (ft3) Volume (gal) 1 and 2 8126 60,786 3 7539.8 56,401 4 7539.8 56,401 5 2592.2 19,391 15.4-35 Revision 1
15.4-36 Revision 1 Consequences of a Rod Ejection Accident al reactor coolant iodine activity An assumed iodine spike that has resulted in an increase in the reactor coolant activity to 60 Ci/g (2.22E+06Bq/g) of dose equivalent I-131 (see Appendix 15A)(a) ctor coolant noble gas activity Equal to the operating limit for reactor coolant activity of 280 Ci/g (1.036E+07 Bq/g) dose equivalent Xe-133 ctor coolant alkali metal activity Design basis activity (see Table 11.1-2) ondary coolant initial iodine and 1% of reactor coolant concentrations at maximum equilibrium conditions li metal activity ial peaking factor (for determination of 1.75 vity in damaged fuel) l cladding failure Fraction of fuel rods assumed to fail 0.1 Fuel enthalpy increase (cal/gm) 60 Fission product gap fractions Iodine 131 0.1238 Iodine 132 0.1338 Krypton 85 0.5120 Other noble gases 0.1238 Other halogens 0.0938 Alkali metals 0.6860 ne chemical form (%)
Elemental 4.85 Organic 0.15 Particulate 95.0 e activity See Table 15A-3 lide data See Table 15A-4 ctor coolant mass (lb) 3.7 E+05 (1.68E+05 kg) e:
The assumption of a pre-existing iodine spike is a conservative assumption for the initial reactor coolant activity. However, compared to the activity assumed to be released from damaged fuel, it is not significant.
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denser Not available ation of accident (days) 30 ospheric dispersion (/Q) factors See Table 15A-5 ondary system release path Primary to secondary leak rate (lb/hr) 104.5(a) (47.4 kg/hr)
Leak flashing fraction 0.04(b)
Secondary coolant mass (lb) 6.06 E+05 (2.75E+05 kg)
Duration of steam release from 1800 secondary system (sec)
Steam released from secondary 1.08 E+05 (4.90E+04 kg) system (lb)
Partition coefficient in steam generators
- Iodine 0.01
- Alkali metals 0.0035 tainment leakage release path Containment leak rate (% per day)
- 0-24 hr 0.10
- >24 hr 0.05 Airborne activity removal coefficients (hr-1)
- Elemental iodine 1.9(c)
- Organic iodine 0
- Particulate iodine or alkali metals 0.1 Decontamination factor limit for 200 elemental iodine removal Time to reach the decontamination 2.78 factor limit for elemental iodine (hr) es:
Equivalent to 300 gpd (1.14 m3/day) cooled liquid at 62.4 lb/ft3 (999.6 kg/m3).
No credit for iodine partitioning is taken for flashed leakage.
From Appendix 15B.
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15.4-39 Revision 1 15.4-40 Revision 1 DCD Table 15.43-3 Not Used 15.4-41 Revision 1
Figure 15.4.1-1 RCCA Withdrawal from Subcritical Nuclear Power 15.4-42 Revision 1
Figure 15.4.1-2 RCCA Withdrawal from Subcritical Average Channel Core Heat Flux 15.4-43 Revision 1
Figure 15.4.1-3 (Sheet 1 of 2)
RCCA Withdrawal from Subcritical Hot Spot Fuel Average Temperature 15.4-44 Revision 1
Figure 15.4.1-3 (Sheet 2 of 2)
RCCA Withdrawal from Subcritical Hot Spot Cladding Inner Temperature 15.4-45 Revision 1
Figure 15.4.2-1 Nuclear Power Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) 15.4-46 Revision 1
Figure 15.4.2-2 Thermal Flux Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) 15.4-47 Revision 1
Figure 15.4.2-3 Pressurizer Pressure Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) 15.4-48 Revision 1
Figure 15.4.2-4 Pressurizer Water Volume Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) 15.4-49 Revision 1
Figure 15.4.2-5 Core Coolant Average Temperature Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) 15.4-50 Revision 1
Figure 15.4.2-6 DNBR Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (75 pcm/s) 15.4-51 Revision 1
Figure 15.4.2-7 Nuclear Power Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) 15.4-52 Revision 1
Figure 15.4.2-8 Thermal Flux Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) 15.4-53 Revision 1
Figure 15.4.2-9 Pressurizer Pressure Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) 15.4-54 Revision 1
Figure 15.4.2-10 Pressurizer Water Volume Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) 15.4-55 Revision 1
Figure 15.4.2-11 Core Coolant Average Temperature Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) 15.4-56 Revision 1
Figure 15.4.2-12 DNBR Transient for an Uncontrolled RCCA Bank Withdrawal from Full Power With Maximum Reactivity Feedback (3 pcm/s) 15.4-57 Revision 1
Figure 15.4.2-13 Minimum DNBR Versus Reactivity Insertion Rate for Rod Withdrawal at 100-percent Power 15.4-58 Revision 1
Figure 15.4.2-14 Minimum DNBR Versus Reactivity Insertion Rate for Rod Withdrawal at 60-percent Power 15.4-59 Revision 1
Figure 15.4.2-15 Minimum DNBR Versus Reactivity Insertion Rate for Rod Withdrawal at 10-percent Power 15.4-60 Revision 1
Figure 15.4.2-17 Not Used.
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Figure 15.4.3-1 Nuclear Power Transient for Dropped RCCA 15.4-62 Revision 1
Figure 15.4.3-2 Core Heat Flux Transient for Dropped RCCA 15.4-63 Revision 1
Figure 15.4.3-3 Pressurizer Pressure Transient for Dropped RCCA 15.4-64 Revision 1
Figure 15.4.3-4 RCS Average Temperature Transient for Dropped RCCA 15.4-65 Revision 1
Figure 15.4.7-1 Representative Percent Change in Local Assembly Average Power for Interchange Between Region 1 and Region 3 Assembly 15.4-66 Revision 1
Figure 15.4.7-2 Representative Percent Change in Local Assembly Average Power for Interchange Between Region 1 and Region 2 Assembly with the BP Rods Transferred to Region 1 Assembly 15.4-67 Revision 1
Figure 15.4.7-3 Representative Percent Change in Local Assembly Average Power for Enrichment Error (Region 2 Assembly Loaded into Core Central Position) 15.4-68 Revision 1
Figure 15.4.7-4 Representative Percent Change in Local Assembly Average Power for Loading Region 2 Assembly into Region 1 Position Near Core Periphery 15.4-69 Revision 1
Figure 15.4.8-1 Nuclear Power Transient Versus Time for the PCMI Rod Ejection Accident 15.4-70 Revision 1
Figure 15.4.8-2 Nuclear Power Transient Versus Time for the High Cladding Temperature Rod Ejection Accident 15.4-71 Revision 1
Figure 15.4.8-3 Nuclear Power Transient Versus Time for the Peak Enthalpy and Fuel Centerline Temperature Rod Ejection Accident 15.4-72 Revision 1
15.4-73 Revision 1 Inadvertent operation of the core makeup tanks during power operation Chemical and volume control system malfunction that increases reactor coolant inventory se Condition II events cause an increase in reactor coolant inventory.
5.1 Inadvertent Operation of the Core Makeup Tanks During Power Operation 5.1.1 Identification of the Causes and Accident Description rious core makeup tank operation at power could be caused by an operator error, a false trical actuation signal, or a valve malfunction. A spurious signal may originate from any of the guards (S) actuation channels as described in Section 7.3. The AP1000 protection logic is such a single failure cannot actuate both core makeup tanks without also actuating the passive dual heat removal (PRHR) heat exchanger. A scenario such as this is the spurious S signal nt. However, if one core makeup tank is inadvertently actuated by a single failure, the event may gress with the plant at power until a reactor trip is reached. For the plant under automatic rod trol, a reactor trip on high-3 pressurizer water level reactor trip is expected to occur followed by PRHR actuation and eventually by an S signal, which would then actuate the second core eup tank. When a consequential loss of offsite power is assumed, this event is more servative than the spurious S signal event.
inadvertent opening of the core makeup tank discharge valves, due to operator error or valve re, results in significant core makeup tank injection flow leading to a boration similar to that lting from a chemical and volume control system malfunction event. If the automatic rod control em is operable, it will begin to withdraw rods from the core to counteract the reactivity effects of boration. As a result, the core makeup tank will continue injection and slowly raise the pressurizer l until the high-3 pressurizer level trip setpoint is reached. In meeting the requirements of GDC 17 0 CFR Part 50, Appendix A, a loss of offsite power is assumed to occur as a consequence of tor trip. The primary effect of this assumption is the coastdown of the reactor coolant pumps. The makeup tank injection will increase as the steam generator outlet temperature increases lting in a lower density in the CMT balance line. This event will then proceed similarly to a rious S signal or chemical and volume control system malfunction event. However, this event is e limiting primarily due to the higher pressurizer level at the time of reactor trip and to the ificant heat up of the injected fluid during the pre-trip phase of the accident. Thus, the inadvertent makeup tank actuation event with a consequential loss of offsite power is analyzed here.
n receipt of the high-3 pressurizer level reactor trip signal, the reactor is tripped; then the turbine mediately tripped, and after a 3-second delay, a consequential loss of offsite power is assumed.
basis for the 3-second delay is described in Subsection 15.0.14. The high-3 pressurizer level al also actuates the PRHR heat exchanger and blocks the pressurizer heaters, but a 15-second y is built in to prevent unnecessary actuation of the PRHR heat exchanger if offsite power is ntained.
owing reactor trip, the reactor power drops and the average reactor coolant system temperature reases with subsequent coolant shrinkage. However, due to the assumed loss of offsite power, reactor coolant cold leg temperature, in the loop without PRHR, increases and the core makeup starts injecting cold water into the reactor coolant system at a much higher rate. The primary lant system shrinkage is counteracted by the core makeup tank injection, and the pressurizer er volume starts to increase because of the heatup of the cold injected fluid by the decay heat.
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ntually, the core makeup tank heats up and the gravity-driven recirculation is significantly uced. The PRHR heat exchanger continues to extract heat from the reactor coolant system, and pressurizer water volume starts to decrease. Ultimately, the core makeup tank stops recirculating, PRHR heat removal matches decay heat and the reactor coolant system cooldown begins ntually leading to a S signal on a Low Tcold setpoint.
cold injection flow from the second CMT initially results in a fast decrease in temperature and nkage of the reactor coolant. However, as the temperature decreases, the PRHR heat removal ability diminishes and a moderate heat up occurs followed by the increase of pressurizer water
- l. The second CMT injection rate is much lower than that experienced during the first part of the sient from the first CMT. Due to the colder cold leg temperatures, the density in balance line is h higher than during the first part of the transient, resulting in a reduction of the total buoyancy ing head. Ultimately, the PRHR heat removal once again matches the decay heat and the final tor coolant system cooldown begins.
event is a Condition II incident (a fault of moderate frequency) as defined in Subsection 15.0.1.
5.1.2 Analysis of Effects and Consequences plant response to an inadvertent core makeup tank actuation is analyzed by using a modified ion of the computer program LOFTRAN described in Subsection 15.0.11.2. The code simulates neutron kinetics, reactor coolant system, pressurizer, pressurizer safety valves, pressurizer y, steam generator, steam generator safety valves, PRHR heat exchanger, and core makeup
. The program computes pertinent plant variables, including temperatures, pressures, and power l.
ctor power and average temperature drop immediately following the trip, and the operating ditions never approach the core limits. The PRHR heat exchanger removes the long-term decay t and prevents possible reactor coolant system overpressurization or loss of reactor coolant em water.
e makeup tank and PRHR system performance is conservatively simulated. Core makeup tank alpies have been maximized. This is conservative because it minimizes the cooling provided by core makeup tanks as flow recirculates and thereby increases the peak pressurizer water volume ng the transient. Core makeup tank injection and balance lines pressure drop is minimized. This imizes the core makeup tank flow injected in the primary system. During this event, the core eup tanks remain filled with water. The volume of injection flow leaving the core makeup tanks is et by an equal volume of recirculation flow that enters the core makeup tanks via the balance
- s. PRHR heat transfer capability has been minimized.
nt characteristics and initial conditions are further discussed in Subsection 15.0.3.
limiting case presented here bounds cases that model explicit operator action 60 minutes after tor trip. The assumptions for this case are as follows:
Initial operating conditions The initial reactor power is assumed to be 102 percent of nominal. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative. The initial pressurizer pressure is assumed to be 50 psi below nominal. The initial reactor coolant system average temperature is assumed to be 7°F below nominal.
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operate. The pressurizer heaters are automatically blocked on a high-3 pressurizer level signal, so they cannot add heat to the system during the period of thermal expansion that produces the peak pressurizer water volume. Thus, the pressurizer heaters are assumed to be inoperable during this event. Other control systems are conservatively not assumed to function during the transient. Cases with the turbine bypass (steam dump) and feedwater control systems working result in lower secondary and primary temperatures and in greater margin to overfilling.
Moderator and Doppler coefficients of reactivity A least-negative moderator temperature coefficient, a Low (absolute value) Doppler power coefficient, and a maximum boron worth are assumed. With these minimum feedback parameters and the operability of the pressurizer spray system and automatic rod control system assumed, the reactivity effects of the boron injection from the core makeup tanks is counteracted.
As a result, the high-3 pressurizer signal is the first reactor trip signal generated during the transient.
Boron injection The transient is initiated by an inadvertent opening of the discharge valves of one of the two core makeup tanks. The core makeup tank injects 3400 ppm borated water.
Protection and safety monitoring system actuations Reactor trip is initiated by the high-3 pressurizer level signal.
The core decay heat is removed by the PRHR heat exchanger. The worst single failure is assumed to occur in the outlet line of the PRHR heat exchanger. One of the two parallel isolation valves is assumed to fail to open.
nt systems and equipment available to mitigate the effect of the accident are discussed in section 15.0.8 and listed in Table 15.0-6.
5.1.3 Results res 15.5.1-1 through 15.5.1-11 show the transient response to the inadvertent operation of one e two core makeup tanks during power operation. The inadvertent opening of the core makeup discharge valves occurs at 10 seconds. As the core makeup tank continues to add inventory to primary system, the pressurizer level begins to increase until the high-3 pressurizer level reactor setpoint is reached at about 520.7 seconds. After a 2-second delay, the neutron flux starts reasing due to the reactor trip, which is immediately followed by the turbine trip. Following reactor the reactor power drops and the average reactor coolant system temperature decreases with sequent coolant shrinkage. However, due to the assumed loss of offsite power, the reactor lant pumps trip at about 525.4 seconds. The cold leg temperature increases and the core makeup starts injecting cold water into the reactor coolant system at a much higher rate due to the eased driving head resulting from the density decreases in balance line. The primary coolant em shrinkage is counteracted by the core makeup tank injection, and the pressurizer water me starts to increase because of the heatup of the cold injected fluid by the decay heat. The
-3 pressurizer level setpoint is once again reached at about 541.9 seconds, and after a econd delay, the signal is sent to actuate the PRHR heat exchanger and block the pressurizer ters. Following a conservative 17-second delay, the valves are assumed to open to actuate the HR heat exchanger at about 573.9 seconds.
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ks in recirculation mode, meaning it is always filled with water because cold borated water cted through the injection line is replaced by hot water coming from the cold leg (balance lines). At roximately 5,000 seconds, the PRHR heat flux matches the core decay heat. However, the surizer level continues to slowly increase until the core makeup tank recirculation is decreased ciently to significantly limit the mass addition to the RCS.
,880 seconds, the pressurizer safety valves close. At about 6,600 seconds, the pressurizer water me stops increasing. At about 12,354 seconds, the Low Tcold S setpoint is reached and the ond CMT is actuated. The pressurizer level initially shrinks due to the addition of cold borated er. As the core makeup tank continues to add inventory to the primary system, the pressurizer l begins to increase. At approximately 13,300 seconds, the first core makeup tank essentially s recirculating. The PRHR heat flux decreases below decay heat and a moderate heat up is erienced by the plant. Finally, at 21,800 seconds, the PRHR heat transfer matches the decay t and the final cooldown commences.
re 15.5.1-6 shows the departure from nucleate boiling ratio (DNBR) until the time of reactor lant trip and subsequent flow coastdown due to the loss of offsite power. At this time, core power heat flux have diminished sufficiently, due to the reactor trip, that DNBR is well above the design value defined in Section 4.4.
calculated sequence of events is shown in Table 15.5-1.
limiting case presented here bounds all cases that model explicit operator action 60 minutes r reactor trip. For such events, the operator would take action to reduce the increase in coolant ntory. As the pressurizer water level would increase above the high pressurizer water level that mally isolates chemical and volume control system makeup, the normal letdown line could be ed into service to reduce the increase in coolant inventory. If letdown could not be placed into ice, the operator could use the safety related reactor vessel head vent valves to reduce the ease in coolant inventory. For these events, following the procedures outlined in the Emergency ponse Guidelines AFR-I.1, there is sufficient time for the operator to mitigate the consequences is event, and the results of such an event have a greater margin to pressurizer overfill than that ented in this analysis.
5.1.4 Conclusions results of this analysis show that inadvertent operation of the core makeup tanks during power ration does not adversely affect the core, the reactor coolant system, or the steam system. The HR heat removal capacity is such that reactor coolant water is not relieved from the pressurizer ty valves. DNBR always remains above the design limit values, and reactor coolant system and m generator pressures remain below 110 percent of their design values.
5.2 Chemical and Volume Control System Malfunction That Increases Reactor Coolant Inventory 5.2.1 Identification of Causes and Accident Description ncrease of reactor coolant inventory, which results from addition of cold unborated water to the tor coolant system, is analyzed in Subsection 15.4.6.
is Subsection 15.5.2, the increase of reactor coolant system inventory due to the addition of ated water is analyzed.
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em, the reactor experiences a negative reactivity excursion due to the injected boron, causing a rease in reactor power and subsequent coolant shrinkage. The load decreases due to the effect educed steam pressure after the turbine control valve fully opens.
igh chemical and volume control system boron concentration, low reactivity feedback conditions, reactor in manual rod control, an S signal will be generated by either the low Tcold or low steam pressure setpoints before the chemical and volume control system can inject a significant unt of water into the reactor coolant system. In this case, the chemical and volume control em malfunction event proceeds similarly to, and is only slightly more limiting than, a spurious signal event. If the automatic rod control is modeled and the pressurizer spray functions properly revent a high pressure reactor trip signal, no S signals are generated and this specific event is inated by automatic isolation of the chemical and volume control system on the safety-related
-2 pressurizer level setpoint.
er typical operating conditions for the AP1000, the boron concentration of the injected chemical volume control system water is equal to that of the reactor coolant system. If the chemical and me control system is functioning in this manner and the pressurizer spray system functions perly to prevent a high pressure reactor trip signal, no S signals are generated and this specific nt is also terminated by automatic isolation of the chemical and volume control system on the ty-related high-2 pressurizer level setpoint.
le these scenarios are the most probable outcomes of a chemical and volume control system function, several combinations of boron concentration, feedback conditions, and plant system ractions have been identified which can result in more limiting scenarios with respect to surizer overfill. The key factors that make this event more limiting than a spurious S signal nt are that the reactor coolant system is at a lower average temperature, higher pressure, and a er pressurizer level at the time an S signal is generated. These factors produce a greater me of higher density water and, thus, a larger reactor coolant system mass at the time of the signal. In addition, at lower reactor coolant system average temperature, the PRHR is less ctive in removing decay heat, which results in greater expansion of the cold water injected by the makeup tanks.
limiting analysis scenario minimizes reactor coolant system average temperature, maximizes tor coolant system mass, and maximizes pressurizer water volume at the time of an S signal.
scenario is as follows:
Both of the chemical and volume control system pumps spuriously begin delivering flow at a boron concentration slightly higher than that of the reactor coolant system. (Assuming that a chemical and volume control system malfunction results in both chemical and volume control system pumps delivering flow is a conservative assumption. One chemical and volume control system pump is automatically controlled and one is manually controlled.)
The non-safety-related pressurizer spray is assumed to be available, so that a high pressurizer pressure reactor trip is prevented.
to the boron addition in the core, the plant cools down until an S signal is generated on low cold temperature. On the S signal, the reactor is tripped, the reactor coolant pumps are tripped, the surizer heaters are blocked, and the main feedwater lines, steam lines, and chemical and me control system are isolated. After a conservative 17-second delay, the PRHR heat exchanger ctuated and the core makeup tank discharge valves are opened.
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stdown of the reactor coolant pumps. Immediately following reactor trip, the turbine is tripped, and r a 3-second delay, a consequential loss of offsite power is assumed. The basis for the 3-second y is described in Subsection 15.0.14. As a result, the reactor coolant pumps are conservatively umed to trip about 10 seconds before they would otherwise trip due to the S signal.
event is a Condition II incident (a fault of moderate frequency) as defined in Subsection 15.0.1.
5.2.2 Analysis of Effects and Consequences malfunction of the chemical and volume control system is analyzed by using a modified version e computer program LOFTRAN (Reference 1). The code simulates the neutron kinetics, reactor lant system, pressurizer, pressurizer safety valves, pressurizer spray, steam generator, steam erator safety valves, PRHR heat exchanger, and core makeup tank. The program computes inent plant variables including temperatures, pressures, and power level.
ause of the power and temperature reduction during the transient, operating conditions do not roach the core limits. The PRHR heat exchanger removes the long-term decay heat to prevent sible reactor coolant system overpressurization or loss of reactor coolant system water.
ng an iterative analysis process, the boron concentration is chosen such that this limiting case nds the cases that model explicit operator action 30 minutes after the reactor trip.
assumptions are as follows:
Initial operating conditions The initial reactor power is assumed to be 102 percent of nominal. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative. The initial pressurizer pressure is assumed to be 50 psi above nominal. The initial reactor coolant system average temperature is assumed to be 6.5°F above nominal.
Moderator and Doppler coefficients of reactivity A least-negative moderator temperature coefficient, a low (absolute value) Doppler power coefficient, and a maximum boron worth are assumed. For a different set of reactivity feedback parameters, a different chemical and volume control system boron concentration can result in an identical transient.
Reactor control Rod control is not modeled.
Pressurizer heaters The pressurizer heaters are automatically blocked on an S signal, and do not add heat to the system during the period of fluid thermal expansion that produces the peak pressurizer water volume. Thus, the pressurizer heaters are assumed to be inoperable during this event.
Pressurizer spray The spray system controls the pressurizer pressure so that a high pressurizer pressure reactor trip is prevented.
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borated water, which is slightly above the reactor coolant system boron concentration. Upon receipt of an S signal, the chemical and volume control system pumps are isolated and the core makeup tanks begin injecting 3400 ppm borated water.
Turbine load The turbine load is assumed constant until the turbine D-EHC drives the control valve wide open.
Then the turbine load drops as steam pressure drops.
Protection and safety monitoring system actuations If the automatic rod control system is modeled and the pressurizer spray system functions properly, no reactor trip signal is expected to occur. Instead, the event is terminated by automatic isolation of the chemical and volume control system on the safety grade high-2 pressurizer level setpoint. If the automatic rod control system is not active and the pressurizer spray system is assumed to be available, reactor trip may be initiated on either low Tcold S or a low steam line pressure S signal.
The core decay heat is removed by the PRHR heat exchanger. The worst single failure is assumed to occur in the outlet line of the PRHR heat exchanger. One of the two parallel isolation valves is assumed to fail to open.
Plant systems and equipment available to mitigate the effect of the accident are discussed in Subsection 15.0.8 and listed in Table 15.0-6.
5.2.3 Results res 15.5.2-1 through 15.5.2-11 show the transient response to a chemical and volume control em malfunction that results in an increase of reactor coolant system inventory. Neutron flux ly decreases due to boron injection, but steam flow does not decrease until later in the transient n the turbine control valves are wide open.
he chemical and volume control system injection flow increases reactor coolant system inventory, surizer water volume begins increasing while the primary system is cooling down. At about 0 seconds, the low Tcold setpoint is reached, the reactor trips, and the control rods start moving the core.
ediately following reactor trip, the turbine is tripped and after a 3-second delay, a consequential of offsite power is assumed and the reactor coolant pumps trip. The basis for the 3-second delay escribed in Subsection 15.0.14. Soon after reactor trip, the pressurizer heaters are blocked and main feedwater lines, steam lines, and chemical and volume control system are isolated. After a servative 17-second delay, the PRHR heat exchanger is actuated and the core makeup tank harge valves are opened. The core makeup tanks work in recirculation mode, meaning they are ays filled with water because cold borated water injected through the injection lines is replaced by water coming from the cold leg balance lines.
operation of the PRHR heat exchanger and the core makeup tanks cools down the plant. Due to swelling of the core makeup tank water, the pressurizer level is still increasing. As the reactor lant system average temperature goes below 490°F, the cooling effect due to the core makeup s is decreasing. In this condition, the PRHR heat exchanger cannot remove the entire decay 15.5-7 Revision 1
en the PRHR heat flux matches the core decay heat, the pressurizer water volume stops easing, and the pressurizer safety valves close. Then the core makeup tanks essentially stop cting.
re 15.5.2-6 shows the DNBR until the time of reactor coolant pump trip and subsequent flow stdown due to the loss of offsite power. At this time, core power and heat flux have diminished ciently, due to the reactor trip, that DNBR is well above the design limit value defined in tion 4.4.
calculated sequence of events is shown in Table 15.5-1.
limiting case presented here bounds all cases that model explicit operator action 30 minutes r reactor trip. For such events, the operator could take action to reduce the increase in coolant ntory. As the pressurizer water level would increase above the high pressurizer water level that mally isolates chemical and volume control system makeup, the normal letdown line could be ed into service to reduce the increase in coolant inventory. If letdown could not be placed into ice, the operator would use the safety-related reactor vessel head vent valves to reduce the ease in coolant inventory. For these events, following the procedures outlined in the AP1000 ergency Response Guidelines AFR-I.1, there is sufficient time for the operator to mitigate the sequences of this event, and the results of such an event have a greater margin to pressurizer rfill than that presented in this analysis.
5.2.4 Conclusions results of this analysis show that a chemical and volume control system malfunction does not ersely affect the core, the reactor coolant system, or the steam system. The PRHR heat removal acity is such that reactor coolant water is not relieved from the pressurizer safety valves. DNBR ains above the design limit values, and reactor coolant system and steam generator pressures ain below 110 percent of their design values.
e automatic rod control system and the pressurizer spray systems are assumed to function, no tor trip signal is expected to occur. Instead, the event is terminated by automatic isolation of the mical and volume control system on the safety grade high pressurizer level setpoint. If manual control is assumed and the pressurizer spray system is assumed to be unavailable, reactor trip be initiated on either a high pressurizer pressure, low Tcold S, or a low steam line pressure signal.
5.3 Boiling Water Reactor Transients subsection is not applicable to the AP1000.
5.4 Combined License Information subsection contained no requirement for additional information.
5.5 References Burnett, T. W. T., et al., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984.
15.5-8 Revision 1
Increase in Reactor Coolant Inventory Time Accident Event (seconds) advertent operation of the core makeup Core makeup tank discharge valves open 10 nks during power operation High-3 pressurizer level setpoint reached 520.7 Rod motion begins 522.7 Loss of offsite power 525.4 Reactor coolant pumps trip 525.4 High-3 pressurizer level setpoint reached 541.9 PRHR heat exchanger actuated 573.9 Pressurizer safety valves open 574.0 Pressurizer safety valves close 594.0 Pressurizer safety valves open 1,312 Pressurizer safety valves close 5,880 Low Tcold S setpoint is reached 12,354 Second CMT starts recirculating 12,361 First Core makeup tank stops recirculating 13,300 Main steam and feed lines are isolated 12,366 Pressurizer safety valves open 14,960 Pressurizer safety valves close 20,140 Peak pressurizer water volume occurs 20,480 PRHR matches decay heat 21,800 Second Core makeup tank stops recirculating 30,900 15.5-9 Revision 1
Time Accident Event (seconds) hemical and volume control system Chemical and volume control system charging 10 alfunction that increases reactor coolant pumps start ventory Low Tcold S signal is reached 1,088 Rod motion begins 1,090 Loss of offsite power 1,093 Reactor coolant pumps trip 1,093 Main steam and feed lines are isolated 1,100 Chemical and volume control system charging 1,100 pumps are isolated Core makeup tank discharge valves open 1,100 PRHR heat exchanger actuated 1,105 Pressurizer safety valves open 1,424 PRHR matches decay heat 14,720 Pressurizer safety valves close 15,088 Peak pressurizer water volume occurs 15,262 Core makeup tanks stop recirculating 20,200 15.5-10 Revision 1
Figure 15.5.1-1 Core Nuclear Power Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-11 Revision 1
Figure 15.5.1-2 RCS Temperature Transient in Loop Containing the PRHR for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-12 Revision 1
Figure 15.5.1-3 RCS Temperature Transient in Loop Not Containing the PRHR for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-13 Revision 1
Figure 15.5.1-4 Pressurizer Pressure Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-14 Revision 1
Figure 15.5.1-5 Pressurizer Water Volume Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-15 Revision 1
Figure 15.5.1-6 DNBR Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-16 Revision 1
Figure 15.5.1-7 Steam Generator Pressure Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-17 Revision 1
Figure 15.5.1-8 Inadvertent Actuated CMT Flow Rate Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-18 Revision 1
Figure 15.5.1-9 Intact CMT Flow Rate Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-19 Revision 1
Figure 15.5.1-10 PRHR and Core Heat Flux Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-20 Revision 1
Figure 15.5.1-11 PRHR Flow Rate Transient for Inadvertent Operation of the Emergency Core Cooling System Due to a Spurious Opening of the Core Makeup Tank Discharge Valves 15.5-21 Revision 1
Figure 15.5.2-1 Core Nuclear Power Transient for Chemical and Volume Control System Malfunction 15.5-22 Revision 1
Figure 15.5.2-2 RCS Temperature Transient in Loop Containing the PRHR for Chemical and Volume Control System Malfunction 15.5-23 Revision 1
Figure 15.5.2-3 RCS Temperature Transient in Loop Not Containing the PRHR for Chemical and Volume Control System Malfunction 15.5-24 Revision 1
Figure 15.5.2-4 Pressurizer Pressure Transient for Chemical and Volume Control System Malfunction 15.5-25 Revision 1
Figure 15.5.2-5 Pressurizer Water Volume Transient for Chemical and Volume Control System Malfunction 15.5-26 Revision 1
Figure 15.5.2-6 DNBR Transient for Chemical and Volume Control System Malfunction 15.5-27 Revision 1
Figure 15.5.2-7 CVS Flow Rate Transient for Chemical and Volume Control System Malfunction 15.5-28 Revision 1
Figure 15.5.2-8 Steam Generator Pressure Transient for Chemical and Volume Control System Malfunction 15.5-29 Revision 1
Figure 15.5.2-9 CMT Injection Line and Balance Line Flow Transient for Chemical and Volume Control System Malfunction 15.5-30 Revision 1
Figure 15.5.2-10 PRHR and Core Heat Flux Transient for Chemical and Volume Control System Malfunction 15.5-31 Revision 1
Figure 15.5.2-11 PRHR Flow Rate Transient for Chemical and Volume Control System Malfunction 15.5-32 Revision 1
An inadvertent opening of a pressurizer safety valve or inadvertent operation of the automatic depressurization system (ADS)
A break in an instrument line or other lines from the reactor coolant pressure boundary that penetrate the containment A steam generator tube failure A loss-of-coolant accident (LOCA) resulting from a spectrum of postulated piping breaks within the reactor coolant pressure boundary applicable accidents in this category have been analyzed. It has been determined that the most ere radiological consequences result from the major LOCA described in Subsection 15.6.5. The A, chemical and volume control system letdown line break outside the containment and the m generator tube rupture (SGTR) accident are analyzed for radiological consequences. Other dents described in this section are bounded by these accidents.
6.1 Inadvertent Opening of a Pressurizer Safety Valve or Inadvertent Operation of the ADS 6.1.1 Identification of Causes and Accident Description types of inadvertent depressurization are discussed in this section. One covers all inadvertent ration of ADS valves. The other covers inadvertent opening of a pressurizer safety valve.
nadvertent depressurization of the reactor coolant system can occur as a result of an inadvertent ning of a pressurizer safety valve or ADS valves. Initially, the event results in a rapidly decreasing tor coolant system pressure. The pressure decrease causes a decrease in power via the erator density feedback. The average coolant temperature decreases slowly, but the pressurizer l increases until reactor trip.
reactor may be tripped by the following reactor protection system signals:
Overtemperature T Pressurizer low pressure ADS is designed such that inadvertent operation of the ADS is classified as a Condition III event, nfrequent fault.
nadvertent opening of a pressurizer safety valve is a Condition II event, a fault of moderate uency.
ADS system consists of four stages of depressurization valves. The ADS stages are interlocked; example, Stage 1 is initiated first and subsequent stages are not actuated until previous stages e been actuated. Each stage includes two redundant parallel valve paths such that no single re prevents operation of the ADS stage when it is called upon to actuate and the spurious ning of a single ADS valve does not initiate ADS flow. To actuate the ADS manually from the main trol room, the operators actuate two separate controls positioned at some distance apart on the n control board. Therefore, one unintended operator action does not cause ADS actuation.
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valve stroke times shown in Chapter 15 tables (input/assumptions) reflect the design basis of the 000. The accidents addressed in this section were evaluated for these design basis valve stroke
- s. The results of this evaluation have shown that there is a small impact on the analysis and the clusions remain valid. The output provided in this section for the analyses is representative of the sient phenomenon.
ach ADS path are two valves in series such that no mechanical failure could result in an vertent operation of an ADS stage. The ADS Stage 4 squib valves cannot be opened while the tor coolant system is at nominal operating pressure.
this analysis, multiple failures and or errors are assumed which actuate both Stage 1 ADS paths.
ough ADS Stages 2 and 3 have larger depressurization valves, the opening time of the Stage 1 ressurization valves is faster. This results in the most severe reactor coolant system ressurization due to ADS operation with the reactor at power.
vertent opening of a pressurizer safety valve can only be postulated due to a mechanical failure.
ough a pressurizer safety valve is smaller than the combined two Stage 1 ADS valves, the surizer safety valve is postulated to open in a short time.
refore, analyses are presented in this section for the inadvertent opening of a pressurizer safety e and the inadvertent opening of two paths of Stage 1 of the ADS. These analyses are performed emonstrate that the departure from nucleate boiling ratio (DNBR) does not decrease below the ign limit values (see Section 4.4) while the reactor is at power.
eeting the requirements of GDC 17 of 10 CFR Part 50, Appendix A, analyses have been ormed to evaluate the effects produced by a possible consequential loss of offsite power during vertent reactor coolant system depressurization events. As discussed in Subsection 15.0.14, the of offsite power is considered as a direct consequence of a turbine trip occurring while the plant perating at power. The primary effect of the loss of offsite power is to cause the reactor coolant ps to coast down.
6.1.2 Analysis of Effects and Consequences 6.1.2.1 Method of Analysis accidental depressurization transient is analyzed by using the computer code LOFTRAN ferences 14 and 15). The code simulates the neutron kinetics, reactor coolant system, surizer, pressurizer safety valves, main steam isolation valves, pressurizer spray, steam erator, and steam generator safety valves. The code computes pertinent plant variables including peratures, pressures, and power level.
reactor coolant system depressurization analyses that include a primary coolant flow coastdown sed by a consequential loss of offsite power, a combination of three computer codes is used to orm the DNBR analyses. First the LOFTRAN code is used to perform the plant system transient.
FACTRAN code (Reference 18) is then used to calculate the core heat flux based on nuclear er and reactor coolant flow from LOFTRAN. Finally, the VIPRE-01 code (see Section 4.4) is used alculate the DNBR using heat flux from FACTRAN and flow from LOFTRAN.
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Initial conditions are discussed in Subsection 15.0.3. Uncertainties in initial conditions are included in the DNBR limit as discussed in WCAP-11397-P-A (Reference 16).
A least negative moderator temperature coefficient is assumed. The spatial effect of voids resulting from local or subcooled boiling is not considered in the analysis with respect to reactivity feedback or core power shape.
A large (absolute value) Doppler coefficient of reactivity is used such that the resulting amount of positive feedback is conservatively high to retard any power decrease.
nt systems and equipment necessary to mitigate the effects of reactor coolant system ressurization are discussed in Subsection 15.0.8 and are listed in Table 15.0-6.
mal reactor control systems are not required to function. The rod control system is assumed to be e automatic mode to maintain the core at full power until the reactor trip protection function is hed. This is a worst case assumption. The reactor protection system functions to trip the reactor he appropriate signal. No single active failure prevents the reactor protection system from tioning properly.
6.1.2.2 Results system response to an inadvertent opening of a pressurizer safety valve is shown in res 15.6.1-1 through 15.6.1-5. The figures show the results for cases with and without offsite er available. The calculated sequence of events for both inadvertent opening of a pressurizer ty valve scenarios are shown in Table 15.6.1-1.
essurizer safety valve is assumed to step open at the start of the event. The reactor coolant em then depressurizes until the overtemperature T reactor trip setpoint is reached.
re 15.6.1-3 shows the pressurizer pressure transient.
e case where offsite power is lost, ac power is assumed to be lost 3 seconds after a turbine trip al occurs. At this time, the reactor coolant pumps are assumed to start coasting down and reactor lant system flow begins decreasing (Figure 15.6.1-5). The availability of offsite power has minimal act on the pressure transient during the period of interest.
r to tripping of the reactor, the core power remains relatively constant (Figure 15.6.1-1). The imum DNBR during the event occurs shortly after the rods begin to be inserted into the core ure 15.6.1-2). In the case where offsite power is lost, reactor trip has already been initiated and heat flux has started decreasing when the reactor coolant system flow reduction starts. The BR continues to increase when reactor coolant system flow begins to decrease due to the loss of te power. Therefore, the minimum DNBR occurs at the same time for cases with and without te power available. The DNBR remains above the design limit values as discussed in Section 4.4 ughout the transient.
system response for inadvertent operation of the ADS is shown in Figures 15.6.1-6 through
.1-10. The figures show the results for cases with and without offsite power available. The uences of events are provided in Table 15.6.1-1. The responses for inadvertent operation of the S are very similar to those obtained for inadvertent opening of a pressurizer safety valve.
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ides adequate protection against the reactor coolant system depressurization events. The ulated DNBR remains above the design limit defined in Section 4.4. The long-term plant onses due to a stuck-open ADS valve or pressurizer safety valve, which cannot be isolated, is nded by the small-break LOCA analysis.
6.2 Failure of Small Lines Carrying Primary Coolant Outside Containment small lines carrying primary coolant outside containment are the reactor coolant system sample and the discharge line from the chemical and volume control system to the liquid radwaste em. These lines are used only periodically. No instrument lines carry primary coolant outside the tainment.
en excess primary coolant is generated because of boron dilution operations, the chemical and me control system purification flow is diverted out of containment to the liquid radwaste system.
ore passing outside containment, the flow stream passes through the chemical and volume trol system heat exchangers and mixed bed demineralizer. The flow leaving the containment is at mperature of less than 140°F and has been cleaned by the demineralizer. The flow out a tulated break in this line is limited to the chemical and volume control system purification flow rate 00 gpm. Considering the low temperature of the flow and the reduced iodine activity because of ineralization, this event is not analyzed. The postulated sample line break is more limiting.
sample line isolation valves inside and outside containment are open only when sampling. The re of the sample line is postulated to occur between the isolation valve outside the containment the sample panel. Because the isolation valves are open only when sampling, the loss of sample provides indication of the break to plant personnel. In addition, a break in a sample line results in vity release and a resulting actuation of area and air radiation monitors. The loss of coolant uces the pressurizer level and creates a demand for makeup to the reactor coolant system. Upon cation of a sample line break, the operator would take action to isolate the break.
sample line includes a flow restrictor at the point of sample to limit the break flow to less than gpm. The liquid sampling lines are 1/4 inch tubing which further restricts the break flow of a pling line outside containment. Offsite doses are based on a conservative break flow of 130 gpm isolation after 30 minutes.
6.2.1 Source Term only significant radionuclide releases are the iodines and the noble gases. The analysis umes that the reactor coolant iodine is at the maximum Technical Specification level for tinuous operation. In addition, it is assumed that an iodine spike occurs at the time of the dent. The reactor coolant noble gas activities are assumed to be those associated with the ign basis fuel defect level.
6.2.2 Release Pathway reactor coolant that is spilled from the break is assumed to be at high temperature and pressure.
rge portion of the flow flashes to steam, and the iodine in the flashed liquid is assumed to become orne.
iodine and noble gases are assumed to be released directly to the environment with no credit for letion, although a large fraction of the airborne iodine is expected to deposit on building surfaces.
credit is assumed for radioactive decay after release.
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6.2.4 Analytical Assumptions and Parameters assumptions and parameters used in the analysis are listed in Table 15.6.2-1.
6.2.5 Identification of Conservatisms assumptions used contain the following significant conservatisms:
The reactor coolant activities are based on a fuel defect level of 0.25 percent; whereas, the expected fuel defect level is far less than this (see Section 11.1).
It is unlikely that the conservatively selected meteorological conditions would be present at the time of the accident.
6.2.6 Doses ng the assumptions from Table 15.6.2-1, the calculated total effective dose equivalent (TEDE) es are determined to be 1.3 rem at the exclusion area boundary and 0.6 rem at the low population e outer boundary. These doses are a small fraction of the dose guideline of 25 rem TEDE tified in 10 CFR Part 50.34. The phrase a small fraction is taken as being ten percent or less.
he time the accident occurs, there is the potential for a coincident loss of spent fuel pool cooling the result that the pool could reach boiling and a portion of the radioactive iodine in the spent fuel l could be released to the environment. The loss of spent fuel pool cooling has been evaluated for ration of 30 days. There is no contribution to the 2-hour site boundary dose because pool boiling ld not occur until after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 30-day contribution to the dose at the low population zone ndary is less than 0.01 rem TEDE and, when this is added to the dose calculated for the small break outside containment, the resulting total dose remains less than the value reported above.
6.3 Steam Generator Tube Rupture 6.3.1 Identification of Cause and Accident Description 6.3.1.1 Introduction accident examined is the complete severance of a single steam generator tube. The accident is umed to take place at power with the reactor coolant contaminated with fission products esponding to continuous operation with a limited number of defective fuel rods within the wance of the Technical Specifications. The accident leads to an increase in contamination of the ondary system due to leakage of radioactive coolant from the reactor coolant system. In the event coincident loss of offsite power, or a failure of the condenser steam dump, discharge of oactivity to the atmosphere takes place via the steam generator power-operated relief valves or safety valves.
assumption of a complete tube severance is conservative because the steam generator tube erial (Alloy 690) is a corrosion-resistant and ductile material. The more probable mode of tube re is one or more smaller leaks of undetermined origin. Activity in the secondary side is subject to tinual surveillance, and an accumulation of such leaks, which exceeds the limits established in Technical Specifications, is not permitted during operation.
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ation of chemical and volume control system flow and startup feedwater flow on high-2 steam erator level or high steam generator level coincident with reactor trip (P-4). These protective ons result in automatic cooldown and depressurization of the reactor coolant system, termination e break flow and release of steam to the atmosphere, and long-term maintenance of stable ditions in the reactor coolant system. These protection systems serve to prevent steam generator rfill (see discussion in Subsections 15.6.3.1.2 and 15.6.3.1.3) and to maintain offsite radiation es within the allowable guideline values for a design basis SGTR. The operator may take actions would provide a more rapid mitigation of the consequences of an SGTR.
ause of the series of alarms described next, the operator can readily determine when an SGTR urs, identify and isolate the ruptured steam generator, and complete the required recovery actions tabilize the plant and terminate the primary-to-secondary break flow. The recovery procedures completed on a time scale that terminates break flow to the secondary system before steam erator overfill occurs and limits the offsite doses to acceptable levels without actuation of the S. Indications and controls are provided to enable the operator to carry out these functions.
6.3.1.2 Sequence of Events for a Steam Generator Tube Rupture following sequence of events occur following an SGTR:
Pressurizer low pressure and low level alarms are actuated and chemical and volume control system makeup flow and pressurizer heater heat addition starts or increases in an attempt to maintain pressurizer level and pressure. On the secondary side, main feedwater flow to the affected steam generator is reduced because the primary-to-secondary break flow increases steam generator level.
The condenser air removal discharge radiation monitor, steam generator blowdown radiation monitor, and/or main steam line radiation monitor alarm indicate an increase in radioactivity in the secondary system.
Continued loss of reactor coolant inventory leads to a reactor trip generated by a low pressurizer pressure or over-temperature T signal. Following reactor trip, the SGTR leads to a decrease in reactor coolant pressure and pressurizer level, counteracted by chemical and volume control system flow and pressurizer heater operation. A safeguards (S) signal that provides core makeup tank and PRHR heat exchanger actuation is initiated by low pressurizer pressure or low-2 pressurizer level. The S signal automatically terminates the normal feedwater supply and trips the reactor coolant pumps. The power to the pressurizer heaters is also terminated. Startup feedwater flow is initiated on a low steam generator narrow range level signal and controls the steam generator levels to the programmed level.
The reactor trip automatically trips the turbine, and if offsite power is available, the steam dump valves open permitting steam dump to the condenser. In the event of a loss of offsite power or loss of the condenser, the steam dump valves automatically close to protect the condenser. The steam generator pressure rapidly increases resulting in steam discharge to the atmosphere through the steam generator power-operated relief valves and/or the safety valves.
Following reactor trip and core makeup tank and PRHR actuation, the PRHR heat exchanger operation - combined with startup feedwater flow, borated core makeup tank flow, and chemical and volume control system flow - provides a heat sink that absorbs the decay heat.
This reduces the amount of steam generated in the steam generators and steam bypass to 15.6-6 Revision 1
Injection of the chemical and volume control system and core makeup tank flow stabilizes reactor coolant system pressure and pressurizer water level, and the reactor coolant system pressure trends toward an equilibrium value, where the total injected flow rate equals the break flow rate.
6.3.1.3 Steam Generator Tube Rupture Automatic Recovery Actions AP1000 incorporates several protection system and passive design features that automatically inate a steam generator tube leak and stabilize the reactor coolant system, in the highly unlikely nt that the operators do not perform recovery actions. Following an SGTR, the injecting chemical volume control system flow (and pressurizer heater heat addition if the pressure control system perating) maintains the primary-to-secondary break flow and the ruptured steam generator ondary level increases as break flow accumulates in the steam generator. Eventually, the ured steam generator secondary level reaches the high and high-2 steam generator narrow ge level setpoint, which is near the top of the narrow range level span.
AP1000 protection system automatically provides several safety-related actions to cool down depressurize the reactor coolant system, terminate the break flow and steam release to the osphere, and stabilize the reactor coolant system in a safe condition. The safety-related actions ude initiation of the PRHR system heat exchanger, isolation of the chemical and volume control em pumps and pressurizer heaters, and isolation of the startup feedwater pumps. In addition, the ection and safety monitoring system provides a safety-related signal to trip the redundant, safety related pressurizer heater breakers.
uating the PRHR heat exchanger transfers core decay heat to the in-containment reactor water age tank (IRWST) and initiates a cooldown (and a consequential depressurization) of the reactor lant system.
ation of the chemical and volume control system pumps and pressurizer heaters minimizes the essurization of the primary system. This allows primary pressure to equilibrate with the ondary pressure, which effectively terminates the primary-to-secondary break flow. Because the makeup tank continues to inject when needed to provide boration following isolation of the mical and volume control system pumps, isolating the chemical and volume control system ps does not present a safety concern.
ation of the startup feedwater provides protection against a failure of the startup feedwater control em, which could potentially result in the ruptured steam generator being overfilled.
h decay heat removal by the PRHR heat exchanger, steam generator steaming through the er-operated relief valves ceases and steam generator secondary level is maintained.
6.3.1.4 Steam Generator Tube Rupture Assuming Operator Recovery Actions e event of an SGTR, the operators can diagnose the accident and perform recovery actions to ilize the plant, terminate the primary-to-secondary leakage, and proceed with orderly shutdown e reactor before actuation of the automatic protection systems. The operator actions for SGTR very are provided in the plant emergency operating procedures. The major operator actions ude the following:
Identify the ruptured steam generator - The ruptured steam generator can be identified by an unexpected increase in steam generator narrow range level or a high radiation indication 15.6-7 Revision 1
Isolate the ruptured steam generator - Once the steam generator with the ruptured tube is identified, recovery actions begin by isolating steam flow from and stopping feedwater flow to the ruptured steam generator.
Cooldown of the reactor coolant system using the intact steam generator or the PRHR system - After isolation of the ruptured steam generator, the reactor coolant system is cooled as rapidly as possible to less than the saturation temperature corresponding to the ruptured steam generator pressure. This provides adequate subcooling in the reactor coolant system after depressurization of the reactor coolant system to the ruptured steam generator pressure in subsequent actions.
Depressurize the reactor coolant system to restore reactor coolant inventory - When the cooldown is completed, the chemical and volume control system and core makeup tank injection flow increases the reactor coolant system pressure until break flow matches the total injection flow. Consequently, these flows must be terminated or controlled to stop primary-to-secondary leakage. However, adequate reactor coolant inventory must first be provided. This includes both sufficient reactor coolant subcooling and pressurizer inventory to maintain a reliable pressurizer level indication after the injection flow is stopped.
ause leakage from the primary side continues after the injection flow is stopped, until reactor lant system and ruptured steam generator pressures equalize, the reactor coolant system is ressurized to provide sufficient inventory to verify that the pressurizer level remains on span after pressures equalize.
Termination of the injection flow to stop primary to secondary leakage - The previous actions establish adequate reactor coolant system subcooling, a secondary side heat sink, and sufficient reactor coolant inventory to verify that injection flow is no longer needed. When these actions are completed, core makeup tank and chemical and volume control system flow is stopped to terminate primary-to-secondary leakage. Primary-to-secondary leakage continues after the injection flow is stopped until the reactor coolant system and ruptured steam generator pressures equalize. Chemical and volume control system makeup flow, letdown, pressurizer heaters, and decay heat removal via the intact steam generator or the PRHR heat exchanger are then controlled to prevent repressurization of the reactor coolant system and reinitiation of leakage into the ruptured steam generator.
owing the injection flow termination, the plant conditions stabilize and the primary-to-secondary ak flow terminates. At this time, a series of operator actions is performed to prepare the plant for ldown to cold shutdown conditions. The actions taken depend on the available plant systems and plan for further plant repair and operation.
6.3.2 Analysis of Effects and Consequences SGTR results in the leakage of contaminated reactor coolant into the secondary system and sequent release of a portion of the activity to the atmosphere. An analysis is performed to onstrate that the offsite radiological consequences resulting from an SGTR are within the wable guidelines.
of the concerns for an SGTR is the possibility of steam generator overfill because this can ntially result in a significant increase in the offsite radiological consequences. Automatic ection and passive design features are incorporated into the AP1000 design to automatically inate the break flow to prevent overfill during an SGTR. These features include actuation of the 15.6-8 Revision 1
analysis is performed, without modeling expected operator actions to isolate the ruptured steam erator and cool down and depressurize the reactor coolant system, to demonstrate the role that AP1000 design features have in preventing steam generator overfill. The limiting single failure for overfill analysis is assumed to be the failure of the startup feedwater control valve to throttle flow n nominal steam generator level is reached. Other conservative assumptions that maximize m generator secondary volume (such as high initial steam generator level, minimum initial tor coolant system pressure, loss of offsite power, maximum chemical and volume control em injection flow, maximum pressurizer heater addition, maximum startup feedwater flow, and imum startup feedwater delay time) are also assumed.
results of this analysis demonstrate the effectiveness of the AP1000 protection system and sive system design features and support the conclusion that an SGTR event would not result in m generator overfill.
determining the offsite radiological consequences, an SGTR analysis is performed assuming the ing single failure and limiting initial conditions relative to offsite doses. Because steam generator rfill is prevented for the AP1000, the results of this analysis represent the limiting radiological sequences for an SGTR.
ermal-hydraulic analysis is performed to determine the plant response for a design basis SGTR, integrated primary-to-secondary break flow, and the mass releases from the ruptured and intact m generators to the condenser and to the atmosphere. This information is then used to calculate radioactivity release to the environment and the resulting radiological consequences.
6.3.2.1 Method of Analysis 6.3.2.1.1 Computer Program plant response following an SGTR until the primary-to-secondary break flow is terminated is lyzed with the LOFTTR2 program (Reference 21). The LOFTTR2 program is modified to model PRHR system, core makeup tanks, and protection system actions appropriate for the AP1000.
se modifications to LOFTTR2 are described in WCAP-14234, Revision 1 (Reference 14).
6.3.2.1.2 Analysis Assumptions accident modeled is a double-ended break of one steam generator tube located at the top of the sheet on the outlet (cold leg) side of the steam generator. The location of the break on the cold side of the steam generator results in higher initial primary-to-secondary leakage than a break on hot side of the steam generator.
reactor is assumed to be operating at full power at the time of the accident, and the initial ondary mass is assumed to correspond to operation at nominal steam generator mass minus an wance for uncertainties. Offsite power is assumed to be lost and the rods are assumed to be rted at the start of the event because continued operation of the reactor coolant pumps has been rmined to reduce flashing of primary-to-secondary break flow and, consequently, lower offsite ological doses. Maximum chemical and volume control system flows and pressurizer heater heat ition are assumed immediately (even though offsite power is not available) to conservatively imize primary-to-secondary leakage. The steam dump system is assumed to be inoperable, sistent with the loss of offsite power assumption, because this results in steam release from the m generator power-operated relief valves to the atmosphere following reactor trip. The chemical volume control system and pressurizer heater modeling is conservatively chosen to delay the 15.6-9 Revision 1
limiting single failure is assumed to be the failure of the ruptured steam generator er-operated relief valve. Failure of this valve in the open position causes an uncontrolled ressurization of the ruptured steam generator, which increases primary-to-secondary leakage the mass release to the atmosphere.
assumed that the ruptured steam generator power-operated relief valve fails open when the 2 pressurizer level signal is generated. This results in the maximum integrated flashed primary-econdary break flow.
valve is subsequently isolated when the associated block valve is automatically closed on a low m line pressure protection system signal.
operator actions are modeled in this limiting analysis, and the plant protection system provides protection for the plant. Not modeling operator actions is conservative because the operators are ected to have sufficient time to recover from the accident and supplement the automatic ection system. In particular, the operator would take action to reduce the primary pressure before high steam generator level coincident with reactor trip (P-4) chemical and volume control and tup feedwater system shutoff signals are generated. It is also expected that the operator can e the block valve to the ruptured steam generator power-operated relief valve in much shorter than the automatic protection signal. The operators can quickly diagnose a power-operated f valve failure based on the rapid depressurization of the steam generator and increase in steam
. They can then close the block valve from the control panel.
sistent with the assumed loss of offsite power, the main feedwater pumps coast down and no tup feedwater is assumed to conservatively minimize steam generator secondary inventory and maximize secondary activity concentration and steam release.
6.3.2.1.3 Results sequence of events for this transient is presented in Table 15.6.3-1. The system responses to SGTR accident are shown in Figures 15.6.3-1 to 15.6.3-10.
ite power is lost concurrent with the rupture of the tube. The reactor trips due to the loss of offsite er. The main feedwater pumps are assumed to coast down following reactor trip. The startup water pumps are conservatively assumed not to start. Following the tube rupture, reactor coolant s from the primary into the secondary side of the ruptured steam generator. In response to this of reactor coolant, pressurizer level and reactor coolant system pressure decreases as shown in res 15.6.3-1 and 15.6.3-2. As a result of the decreasing pressurizer level and pressure, two mical and volume control system pumps are automatically initiated to provide makeup flow and pressurizer heaters turn on.
r reactor trip, core power rapidly decreases to decay heat levels and the core inlet to outlet perature differential decreases. The turbine stop valves close, and steam flow to the turbine is inated. The steam dump system is conservatively assumed to be inoperable. The secondary pressure increases rapidly after reactor trip until the steam generator power-operated relief es (and safety valves, if their setpoints are reached) lift to dissipate the energy, as shown in re 15.6.3-3.
imum heat addition to the pressurizer from the pressurizer heaters increases the primary sure.
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m generator power-operated relief valve is assumed to fail open at this time.
failure causes the intact and ruptured steam generators to rapidly depressurize ure 15.6.3-3). This results in an initial increase in primary-to-secondary leakage and a decrease e reactor coolant system temperatures. Both the intact and ruptured steam generators ressurize because the steam generators communicate through the open steam line isolation es.
decrease in the reactor coolant system temperature results in a decrease in the pressurizer level reactor coolant system pressure (Figures 15.6.3-1 and 15.6.3-2). Depressurization of the ary and secondary systems continues until the low steam line pressure setpoint is reached. As a lt, the steam line isolation valves and intact and ruptured steam generator power-operated relief k valves are closed.
owing closure of the block valves, the primary and secondary pressures and the ruptured steam erator secondary water volume and mass increase as break flow accumulates. This increase tinues until the steam generator secondary level reaches the high narrow range level when the mical and volume control and startup feedwater systems are isolated.
h continued reactor coolant system cooldown, depressurization provided by the PRHR heat hanger, and with the chemical and volume control system isolated, primary system pressure ntually falls to match the secondary pressure. The break flow terminates as shown in re 15.6.3-5, and the system is stabilized in a safe condition. As shown in Figure 15.6.3-8, steam ase through the intact loop, unfaulted power-operated relief valve does not occur following PRHR ation because the PRHR is capable of removing the core decay heat.
hown in Figure 15.6.3-9, the core makeup tank flow trends toward zero because the gravity head inishes as the core makeup tank temperature approaches the reactor coolant system perature due to the continued balance line flow. The core makeup tank remains full, and ADS ation does not occur.
ruptured steam generator water volume is shown in Figure 15.6.3-6. The water volume in the ured steam generator when the break flow is terminated is significantly less than the total steam erator volume of greater than 8868 ft3.
design basis SGTR event does not result in fuel failures. In the event of an SGTR, the reactor lant system depressurizes due to the primary-to-secondary leakage through the ruptured steam erator tube. This depressurization reduces the calculated DNBR. The depressurization prior to tor trip for the SGTR has been compared to the depressurization for the reactor coolant system ressurization accidents analyzed in Subsection 15.6.1. The rate of depressurization is much er for the SGTR than for the reactor coolant system depressurization accidents. Following tor trip, the DNBR increases rapidly. Thus, the conclusion of Subsection 15.6.1, that the ulated DNBR remains above the limit, is extended to the SGTR analysis, justifying the umption of no failed fuel.
6.3.2.1.4 Mass Releases mass release of an SGTR event is determined for use in evaluating the exclusion area boundary low population zone radiation exposure. The steam releases from the ruptured and intact steam erators and the primary-to-secondary leakage into the ruptured steam generator are determined 15.6-11 Revision 1
owing reactor trip, the releases to the atmosphere are through the steam generator er-operated relief valves (and steam generator safety valves for a short period). Steam relief ugh the power-operated relief valves continues until RNS conditions are met. The mass releases he SGTR event are presented in Table 15.6.3-2.
6.3.3 Radiological Consequences evaluation of the radiological consequences of the postulated SGTR assumes that the reactor is rating with the design basis fuel defect level (0.25 percent of power produced by fuel rods taining cladding defects) and that leaking steam generator tubes result in a buildup of activity in secondary coolant.
owing the rupture, any noble gases carried from the primary coolant into the ruptured steam erator via the break flow are released directly to the environment. The iodine and alkali metal vity entering the secondary side is also available for release, with the amount of release endent on the flashing fraction of the reactor coolant and on the partition coefficient in the steam erator. In addition to the activity released through the ruptured loop, there is also a small amount ctivity released through the intact loop.
6.3.3.1 Source Term significant radionuclide releases from the SGTR are the noble gases, alkali metals and the nes that become airborne and are released to the environment as a result of the accident.
analysis considers two different reactor coolant iodine source terms, both of which consider the ne spiking phenomenon. In one case, the initial iodine concentrations are assumed to be those ociated with the equilibrium operating limits for primary coolant iodine activity. The iodine spike is umed to be initiated by the accident with the spike causing an increasing level of iodine in the tor coolant.
second case assumes that the iodine spike occurs before the accident and that the maximum tor coolant iodine concentration exists at the time the accident occurs.
reactor coolant noble gas and alkali metal concentrations are assumed to be those associated the design fuel defect level.
secondary coolant iodine and alkali metal activity is assumed to be 1 percent of the maximum ilibrium primary coolant activity.
6.3.3.2 Release Pathways noble gas activity contained in the reactor coolant that leaks into the intact steam generator and rs the ruptured steam generator through the break is assumed to be released immediately as as a pathway to the environment exists. There are three components to the modeling of iodine alkali metal releases:
Intact loop steaming, with credit for partitioning of iodines and alkali metals (includes continued primary-to-secondary leakage at the maximum rate allowable by the Technical Specifications) 15.6-12 Revision 1
Release of flashed reactor coolant through the ruptured loop, with no credit for scrubbing (this conservatively assumes that break location is at the top of the tube bundle) dit is taken for decay of radionuclides until release to the environment. After release to the ironment, no consideration is given to radioactive decay or to cloud depletion of iodines by ground osition during transport offsite.
6.3.3.3 Dose Calculation Models models used to calculate doses are provided in Appendix 15A.
6.3.3.4 Analytical Assumptions and Parameters assumptions and parameters used in the analysis are listed in Table 15.6.3-3.
6.3.3.5 Identification of Conservatisms assumptions used in the analysis contain a number of significant conservatisms, such as:
The reactor coolant activities are based on a fuel defect level of 0.25 percent; whereas, the expected fuel defect level is far less (see Section 11.1).
It is unlikely that the conservatively selected meteorological conditions are present at the time of the accident.
6.3.3.6 Doses ng the assumptions from Table 15.6.3-3, the calculated TEDE doses for the case in which the ne spike is assumed to be initiated by the accident are determined to be 0.7 rem at the exclusion a boundary for the limiting 2-hour interval (0-2 hours) and 0.5 rem at the low population zone r boundary. These doses are a small fraction of the dose guideline of 25 rem TEDE identified in CFR Part 50.34. A small fraction is defined, consistent with the Standard Review Plan, as being percent or less.
the case in which the SGTR is assumed to occur coincident with a pre-existing iodine spike, the E doses are determined to be 1.4 rem at the exclusion area boundary for the limiting 2-hour rval (0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) and 0.7 rem at the low population zone outer boundary. These doses are within dose guideline of 25 rem TEDE identified in 10 CFR Part 50.34.
he time the accident occurs, there is the potential for a coincident loss of spent fuel pool cooling the result that the pool could reach boiling and a portion of the radioactive iodine in the spent fuel l could be released to the environment. The loss of spent fuel pool cooling has been evaluated for ration of 30 days. There is no contribution to the 2-hour exclusion area boundary dose because l boiling would not occur until after 2.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />. The 30-day contribution to the dose at the low ulation zone boundary is less than 0.01 rem TEDE and, when this is added to the doses ulated for the steam generator tube rupture, the resulting total doses remain as reported above.
6.3.4 Conclusions results of the SGTR analysis show that the overfill protection logic and the passive system ign features provide protection to prevent steam generator overfill. Following an SGTR accident, 15.6-13 Revision 1
n when no operator actions are assumed, the AP1000 protection system and passive design ures initiate automatic actions that can terminate a steam generator tube leak and stabilize the tor coolant system in a safe condition while preventing steam generator overfill and ADS ation.
resulting offsite radiological doses for the limiting case analyzed are within the dose acceptance s.
6.4 Spectrum of Boiling Water Reactor Steam System Piping Failures Outside of Containment section is not applicable to the AP1000.
6.5 Loss-of-Coolant Accidents Resulting from a Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary 6.5.1 Identification of Causes and Frequency Classification OCA is the result of a pipe rupture of the reactor coolant system pressure boundary. For the lyses reported here, a major pipe break (large break) is defined as a rupture with a total cross-ional area equal to or greater than 1.0 ft2. This event is considered a Condition IV event (a ing fault) because it is not expected to occur during the lifetime of the plant but is postulated as a servative design basis (see Subsection 15.0.1).
inor pipe break (small break), as considered in this subsection, is defined as a rupture of the tor coolant pressure boundary (Section 5.2) with a total cross-sectional area less than 1.0 ft2 in ch the normally operating charging system flow is not sufficient to sustain pressurizer level and sure. This is considered a Condition III event because it is an infrequent fault that may occur ng the life of the plant.
acceptance criteria for the LOCA are described in 10 CFR 50.46 (Reference 1) as follows:
The calculated maximum fuel element cladding temperature shall not exceed 2200°F.
Localized cladding oxidation shall not exceed 17 percent of the total cladding thickness before oxidation.
The amount of hydrogen generated from fuel element cladding reacting chemically with water or steam shall not exceed 1 percent of the total amount if all metal cladding were to react.
The core remains amenable to cooling for any calculated change in core geometry.
The core temperature is maintained at a low value, and decay heat is removed for the extended period of time required by the long-lived radioactivity remaining in the core.
se criteria are established to provide significant margin in emergency core cooling system ormance following a LOCA.
the AP1000, the small breaks (less than 1.0 ft2) yield results with more margin than large breaks.
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rease in the pressurizer. The reactor trip signal subsequently occurs when the pressurizer pressure trip setpoint is reached. A safeguards actuation (S) signal is generated when the ropriate setpoint is reached. These measures limit the consequences of the accident in two ways:
Reactor trip and borated water injection complement void formation in causing rapid reduction of power to a residual level corresponding to fission product decay heat. Insertion of control rods to shut down the reactor is neglected in the large-break analysis.
Injection of borated water provides core cooling and prevents excessive cladding temperatures.
acceptability of the computer codes approved for AP600 LOCA analyses for the AP1000 lication is documented in Reference 24. The acceptability of additional computer codes for the 000 Best-Estimate Large-Break LOCA analysis is documented in Reference 34.
6.5.2.1 Description of Large-Break LOCA Transient ore the break occurs, the unit is in an equilibrium condition in which the heat generated in the core eing removed via the secondary system. During blowdown, heat from fission product decay ed energy in the fuel, hot internals, and vessel continues to be transferred to the reactor coolant.
he beginning of the blowdown phase, the entire reactor coolant system contains subcooled liquid, ch transfers heat from the core by forced convection with some fully developed nucleate boiling.
r the break, the core heat transfer is based upon local fluid conditions. Transition boiling and ersed flow film boiling are the major heat transfer mechanisms.
heat transfer between the reactor coolant system and the secondary system may be in either ction, depending upon the relative temperatures. In the case of continued heat addition to the ondary system, secondary system pressure increases and the main steam safety valves may lift mit the pressure. The safety injection signal actuates a feedwater isolation signal, which isolates mal feedwater flow by closing the main feedwater isolation valves.
reactor coolant pumps trip automatically during the accident following an S signal. The effects ump coastdown are included in the blowdown. The blowdown phase of the transient ends when reactor coolant system pressure (initially assumed at 2250 psia) falls to a value approaching that e containment atmosphere.
en the S signal occurs, the core makeup tank isolation valves are opened. The core makeup begins to inject subcooled borated water into the reactor vessel through the direct vessel ction lines.
section 15.6.5.4C presents calculations that show the effective post-LOCA long-term cooling of AP1000 by passive means.
6.5.2.2 Description of Small-Break LOCA Transient AP1000 includes passive safety features to prevent or minimize core uncovery during small-ak LOCAs. The passive safety design approach of the AP1000 is to depressurize the reactor lant system if the break or leak is greater than the makeup capability of the charging system. By ressurizing the reactor system, large volumes of borated water in the accumulators and in the ST become available for cooling the core. This analysis demonstrates that, with a single failure, 15.6-15 Revision 1
ing a small-break LOCA, the AP1000 reactor coolant system depressurizes to the pressurizer pressure setpoint, actuating a reactor trip signal. The passive core cooling system is aligned for very following the generation of an S signal when the pressurizer low-pressure setpoint is hed. The passive core cooling system includes two core makeup tanks, two accumulators, a e IRWST, and the PRHR heat exchanger.
core makeup tanks operate at reactor coolant system pressure. They provide high-pressure ty injection in the event of a small-break LOCA. The core makeup tanks share a common harge line with the accumulators and IRWST; they are filled with borated water to provide core tdown margin. The injection of the core makeup tanks is provided by gravity head of the colder er in the core makeup tanks. The core makeup tanks are located above the reactor coolant loops, each is equipped with a pressure balancing line from a cold leg to the top of the tank.
pressurized accumulators provide additional borated water to the reactor coolant system in the nt of a LOCA. Nominally, these 2000-ft3 tanks are filled with 1700 ft3 of water and 300 ft3 of gen at an initial pressure of 700 psig. Once sufficient reactor coolant system depressurization urs, either as a result of a LOCA or the actuation of the ADS, accumulator injection commences.
IRWST provides an additional source of water for long-term core cooling. To attain injection from IRWST, the reactor coolant system pressure must be lowered to approximately 13 psi above tainment pressure. For this pressure to be achieved during a small-break LOCA, the ADS system itiated.
ADS consists of a series of valves, connected to the pressurizer and hot legs, which provide a sed depressurization of the reactor coolant system. As the reactor system loses inventory ugh the break, the core makeup tanks provide flow to the reactor vessel. When the level in the makeup tank drops to the 67.5-percent level, the ADS valves open to accelerate the reactor lant system depressurization rate. The ADS Stage 1 4-inch valves open at the 67.5-percent level; 8-inch Stage 2 and the 8-inch Stage 3 valves open in a timed sequence thereafter. The flow from first three stages of the ADS is discharged into the IRWST through a sparger system. The fourth es of the ADS are connected to the reactor coolant system hot legs and discharge to tainment atmosphere. The ADS Stage 4 valves are activated when the core makeup tank level hes the 20-percent level.
he reactor coolant system depressurizes and mass is lost out the break, mass is added to the tor vessel from the core makeup tanks and the accumulators. When the system is depressurized w the IRWST delivery pressure, flow from the IRWST continues to maintain the core in a lable state. Calculations described in Subsection 15.6.5.4B indicate that acceptable core cooling rovided for the small-break LOCA transients. Subsection 15.6.5.4C calculations show that ctive post-LOCA core cooling is provided in the long term by passive means.
6.5.3 Radiological Consequences ough the analysis of the core response during a LOCA (see Subsection 15.6.5.4) shows that core grity is maintained, for the evaluation of the radiological consequences of the accident, it is umed that major core degradation and melting occur.
dose calculations take into account the release of activity by way of the containment purge line r to its isolation near the beginning of the accident and the release of activity resulting from tainment leakage. Purge of the containment for hydrogen control is not an intended mode of ration and is not considered in the dose analysis. While the normal residual heat removal system 15.6-16 Revision 1
sive core cooling system, which does not pass coolant outside of containment. Thus, there is no rculation leakage release path to be modeled.
6.5.3.1 Source Term release of activity to the containment consists of two parts. The initial release is the activity tained in the reactor coolant system. This is followed by the release of core activity.
6.5.3.1.1 Primary Coolant Release reactor coolant is assumed to have activity levels consistent with operation at the Technical cification limits of 280 Ci/gm dose equivalent Xe-133 and 1.0 Ci/gm dose equivalent I-131.
ed on NUREG-1465 (Reference 19), for a plant using leak-before-break methodology, the ase of coolant into the containment can be assumed to last for 10 minutes. The AP1000 is a leak-re-break plant, and the water in the reactor coolant system is assumed to blow down into the tainment over a period of 10 minutes. The flow rate is assumed to be constant over the 10-minute od. As the reactor coolant enters the containment, the noble gases and half of the iodine activity assumed to be released into the containment atmosphere.
6.5.3.1.2 Core Release release of activity from the fuel takes place in two stages as summarized in Table 15.6.5-1. First e gap release which is assumed to occur at the end of the primary coolant release phase (i.e., at minutes into the accident) and continue over a period of half an hour. The second stage is that of in-vessel core melt in which the bulk of the activity releases associated with the accident occur.
source term model is based on NUREG-1465 and Regulatory Guide 1.183 (Reference 20).
core fission product inventory at the time of the accident is based on operation near the end of a cycle at 102-percent power and is provided in Table 15A-3 of Appendix 15A. The main feedwater measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is servative. Consistent with NUREG-1465, there are three groups of nuclides considered in the gap vity releases: noble gases, iodines, and alkali metals (cesium and rubidium). For the core melt se, there are five additional nuclide groups for a total of eight. The five additional nuclide groups the tellurium group, the noble metals group, the cerium group, the lanthanide group, and barium strontium. The specific nuclides included in the source term are as shown in Table 15A-3.
p Activity Release sistent with NUREG-1465 guidance for a plant using leak-before-break methodology, the gap ase phase begins after the primary coolant release phase ends at ten minutes and has a duration
.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
essel Core Release r the gap activity release phase, there is an in-vessel release phase which lasts for 1.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and ch releases activity to the containment due to core melting. The fractions of the core activity ased to the containment atmosphere during this phase are from NUREG-1465:
Noble gases 0.95 Iodines 0.35 Alkali metals 0.25 15.6-17 Revision 1
Cerium group 0.0005 Lanthanide group 0.0002 sistent with NUREG-1465, the releases are assumed to occur at a constant rate over the hour phase duration.
6.5.3.1.3 Iodine Form iodine form is consistent with the NUREG-1465 model. The model shows the iodine to be dominantly in the form of nonvolatile cesium iodide with a small fraction existing as elemental ne. Additionally, the model assumes that a portion of the elemental iodine reacts with organic erials in the containment to form organic iodine compounds. The resulting iodine species split is ollows:
Particulate 0.95 Elemental 0.0485 Organic 0.0015 e post-LOCA cooling solution has a pH of less than 6.0, part of the cesium iodide may be verted to the elemental iodine form. The passive core cooling system provides sufficient trisodium sphate to the post-LOCA cooling solution to maintain the solution pH at 7.0 or greater following a A (see Subsection 6.3.2.1.4).
6.5.3.2 In-containment Activity Removal Processes AP1000 does not include active systems for the removal of activity from the containment osphere. The containment atmosphere is depleted of elemental iodine and of particulates as a lt of natural processes within the containment.
mental iodine is removed by deposition onto surfaces. Particulates are removed by imentation, diffusiophoresis (deposition driven by steam condensation), and thermophoresis position driven by heat transfer). No removal of organic iodine is assumed. Appendix 15B ides a discussion of the models and assumptions used in calculating the removal coefficients.
iculates removed from the containment atmosphere to the containment shell are assumed to be hed off the shell by the flow of water resulting from condensing steam (i.e. condensate flow). The iculates may be either washed into the sump, which is controlled to a pH 7 post-accident or into IRWST, which is not pH controlled post-accident. Due to the conditions in the IRWST, a portion of particulate iodine washed into the IRWST may chemically convert to an elemental form and volve, subject to partitioning, as airborne. A water-steam partition factor of 10 for elemental iodine pplied. This value bounds the time-dependent partition factors calculated using the NUREG/
5950 (Reference 35) models and the calculated IRWST water temperature and pH as a function me.
IRWST is a closed tank with weighted louvers, and without boiling, there would be no motive e for the release of re-evolved gaseous iodine from the IRWST gas space to the containment.
s, the assumption of boiling in the IRWST liquid is imposed to force the release of the re-evolved ne to the containment atmosphere. A portion (3%) of the re-evolved elemental iodine is assumed onvert to an organic form upon its release to containment.
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assumed to be ground level releases.
ing the initial part of the accident, before the containment is isolated, it is assumed that tainment purge is in operation and that activity is released through this pathway until the purge es are closed. No credit is taken for the filters in the purge exhaust line.
majority of the releases due to the LOCA are the result of containment leakage. The containment ssumed to leak at its design leak rate for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and at half that rate for the remainder e analysis period.
6.5.3.4 Offsite Dose Calculation Models offsite dose calculation models are provided in Appendix 15A. The models address the rmination of the TEDE doses from the combined acute doses and the committed effective dose ivalent doses.
exclusion area boundary dose is calculated for the 2-hour period over which the highest doses ld be accrued by an individual located at the exclusion area boundary. Because of the delays ociated with the core damage for this accident, the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the accident are not the worst our interval for accumulating a dose.
low population zone boundary dose is calculated for the nominal 30-day duration of the accident.
both the exclusion area boundary and low population zone dose determinations, the calculated es are compared to the dose guideline of 25 rem TEDE from 10 CFR Part 50.34.
6.5.3.5 Main Control Room Dose Model re are two approaches used for modeling the activity entering the main control room. If power is ilable, the normal heating, ventilation, and air-conditioning (HVAC) system will switch over to a plemental filtration mode (Section 9.4). The normal HVAC system is not a safety-class system but ides defense in depth.
rnatively, if the normal HVAC is inoperable or, if operable, the supplemental filtration train does function properly resulting in increasing levels of airborne iodine in the main control room, the rgency habitability system (Section 6.4) would be actuated when High-2 iodine or particulate vity is detected. The emergency habitability system provides passive pressurization of the main trol room from a bottled air supply to prevent inleakage of contaminated air to the main control
- m. The bottled air also induces flow through the passive air filtration system which filters taminated air in the main control room. There is a 72-hour supply of air in the emergency itability system. After this time, the main control room is assumed to be opened and unfiltered air rawn into the main control room by way of an ancillary fan. After 7 days, offsite support is umed to be available to reestablish operability of the control room habitability system by enishing the compressed air supply. As a defense-in-depth measure, the nonsafety-related mal control room HVAC would be brought back into operation with the supplemental filtration train wer is available.
main control room is accessed by a vestibule entrance, which restricts the volume of taminated air that can enter the main control room from ingress and egress. The design of the rgency habitability system (VES) provides 65 scfm +/-5 scfm to the control room and maintains it pressurized state. The path for the purge flow out of the main control room is through the 15.6-19 Revision 1
ess/egress is 5 cfm. An additional 10 cfm of unfiltered inleakage is conservatively assumed from r sources.
vity entering the main control room is assumed to be uniformly dispersed. With the VES in ration, airborne activity is removed from the main control room atmosphere via the passive rculation filtration portion of the VES.
main control room dose calculation models are provided in Appendix 15A for the determination oses resulting from activity which enters the main control room envelope.
6.5.3.6 Analytical Assumptions and Parameters analytical assumptions and parameters used in the radiological consequences analysis are d in Table 15.6.5-2.
6.5.3.7 Identification of Conservatisms LOCA radiological consequences analysis assumptions include a number of conservatisms.
e of these conservatisms are discussed in the following subsections.
6.5.3.7.1 Primary Coolant Source Term source term is based on operation with the design fuel defect level of 0.25 percent; whereas, the ected fuel defect level is far less.
6.5.3.7.2 Core Release Source Term assumed core melt is a major conservatism associated with the analysis. In the event of a tulated LOCA, no major core damage is expected. Release of activity from the core is limited to a tion of the core gap activity.
6.5.3.7.3 Atmospheric Dispersion Factors atmospheric dispersion factors assumed to be present during the course of the accident are servatively selected. Actual meteorological conditions are expected to result in significantly higher ersion of the released activity.
-specific /Q values provided in Subsection 2.3.4 are bounded by the values given in les 15A-5 and 15A-6.
6.5.3.8 LOCA Doses 6.5.3.8.1 Offsite Doses doses calculated for the exclusion area boundary and the low population zone boundary are d in Table 15.6.5-3. The doses are within the 10 CFR 50.34 dose guideline of 25 rem TEDE.
reported exclusion area boundary doses are for the time period of 1.3 to 3.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. This is the our interval that has the highest calculated doses. The dose that would be incurred over the first urs of the accident is well below the reported dose.
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ration of 30 days. There is no contribution to the 2-hour site boundary dose because pool boiling ld not occur until after the limiting 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 30-day contribution to the dose at the low ulation zone boundary is less than 0.01 rem TEDE and, when this is added to the dose calculated he LOCA, the resulting total dose remains less than that reported in Table 15.6.5-3.
6.5.3.8.2 Doses to Operators in the Main Control Room doses calculated for the main control room personnel due to airborne activity entering the main trol room are listed in Table 15.6.5-3. Also listed on Table 15.6.5-3 are the doses due to direct e from the activity in the adjacent buildings, shine from radioactivity accumulated on the VES or filters, and sky-shine from the radiation that streams out the top of the containment shield ding and is reflected back down by air-scattering. The total of these dose paths is within the dose ria of 5 rem TEDE as defined in GDC 19.
iscussed above for the offsite doses, there is the potential for a dose to the operators in the main trol room due to iodine releases from postulated spent fuel boiling. The calculated dose from this rce is less than 0.01 rem TEDE and is reported in Table 15.6.3-3.
6.5.4 Core and System Performance section 15.6.5.4A describes the large-break LOCA analysis methodology and results.
sections 15.6.5.4B.1.0 through 15.6.5.4B.4.0 describe the small-break LOCA analysis hodology and results.
6.5.4A Large-Break LOCA Analysis Methodology and Results stinghouse applies the WCOBRA/TRAC computer code to perform best-estimate large-break A analyses in compliance with 10 CFR 50 (Reference 5). WCOBRA/TRAC is a thermal-raulic computer code that calculates realistic fluid conditions in a PWR during the blowdown and od of a postulated large-break LOCA. The methodology used for the AP1000 analysis is umented in WCAP-12945-P-A, WCAP-14171, Revision 2, and WCAP-16009-P-A ferences 10, 11, and 32).
NRC staff has reviewed and approved the best-estimate LOCA methodology (ASTRUM hodology), as documented in the SER attached in front of Reference 32, for estimating the percentile PCT for two-loop, three-loop and four-loop Westinghouse PWRs and the AP600. In erence 3, the NRC staff has reviewed and approved a best-estimate LOCA methodology, as umented in Reference 11, for estimating the 95th percentile PCT for the AP600. In the erence 32 and Reference 11 methodologies, the WCOBRA/TRAC code is used to calculate the cts of initial conditions, power distributions, and global models, and the HOTSPOT code is used alculate the effects of local models.
e ASTRUM uncertainty methodology (Reference 32), as used in the AP1000 LB LOCA analysis, al models and initial-condition, power-distribution, and local uncertainties are sampled pendently for each of 124 runs over the same ranges of uncertainty and distributions as in erences 10, 32, and 33, as described in Reference 34. The sampled global models, initial ditions, and power-distribution uncertainties become inputs to each of the 124 WCOBRA/TRAC ulations. The thermal-hydraulic boundary conditions for the hot rod are input to the local ertainties calculation performed by the HOTSPOT code.
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perature (PCT), is a conservative estimate of the 95th percentile with 95 percent confidence. The ing PCT, limiting MLO, and CWO may come from the same case or as many as three different es because each parameter is assumed to be independent of the other two. The assumption of pendence of the calculated licensing parameters is a conservative assumption because there is pendence of MLO and CWO on cladding temperature.
the AP1000 large-break LOCA analysis, the best-estimate LOCA analysis methodology is lied as described in Reference 34. The best-estimate large-break LOCA analysis complies with stipulated applicability limits in the Reference 32 approval.
post-LOCA long-term core cooling and core boron concentration analyses discussed in section 15.6.5.4C are applicable to the large-break LOCA transient.
6.5.4A.1 General Description of WCOBRA/TRAC Modeling OBRA/TRAC is the best-estimate thermal-hydraulic computer code used to calculate realistic conditions in the PWR during blowdown and reflood of a postulated large-break LOCA.
WCOBRA/TRAC Code Qualification Document (Reference 10) contains a complete description e code models and justifies their applicability to PWR large-break LOCA analysis.
le 15.6.5-4 lists the AP1000-specific parameters identified for use in the large-break LOCA lysis. WCOBRA/TRAC studies were performed for AP1000 to establish sensitivities to parameter ations. These studies included effects of ranging steam generator tube plugging, ranging the tive power in the low-power assemblies, loss of offsite power coincident with the break initiation, break location. The calculated results were used to identify bounding conditions, which are then d in the AP1000 uncertainty calculations.
WCOBRA/TRAC vessel nodalization is developed from plant design drawings to divide the sel into 10 vertical sections. The bottom of section 1 is the inside vessel bottom, and the top of ion 10 is the inside top of the vessel upper head. In addition to the major downcomer and core paths, the modeled bypass flow paths are the upper head cooling spray, guide thimbles, and bypass. After defining the elevations for each section, a noding scheme is defined for the OBRA/TRAC model as shown in Reference 34. WCOBRA/TRAC assumes a vertical flow path for ically stacked channels, unless specified otherwise in the input. Positive flow for the vertically nected channels (and cells) is upward. Several of the 10 sections are divided vertically into 2 or e levels; these levels are referred to as cells within a channel.
WCOBRA/TRAC loop model represents the major primary, secondary, and passive safety ems components. Both loops are explicitly modeled, including the hot leg, the steam generator, the two cold legs and associated pumps. The loop designated 1 has the pressurizer and the HR system connections, and loop 2 cold legs have the core makeup tank pressure balance line nections. The reactor coolant pump models contain the AP1000 homologous curves together appropriate two-phase head and torque multipliers and degradation data. AP1000 values for p coastdown characteristics are also applied. The passive safety features are modeled using ign data for elevations, liquid volumes, and line losses. Because the ADS is not actuated until after the time of PCT in large-break LOCA events, it is not modeled in detail.
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ers, and pressures are at their approximate steady-state values before the postulated break urs. Steady-state WCOBRA/TRAC calculations are run for a brief time period to verify that the ulated conditions are steady and that the desired reactor conditions are achieved.
values used to set the steady-state plant conditions reflect the AP1000 parameters for reactor lant pump flows, core power, and steam generator tube plugging levels. The fuel parameters ide the steady-state fuel temperatures, pressures, and gap conductances as a function of fuel nup and linear power. The calculated fuel temperatures from WCOBRA/TRAC are adjusted to ch the specified fuel data by adjusting the gap heat transfer coefficient between the pellet and the ding. Once the vessel fluid temperatures, flows, pressures, loop pressure drop, and core ameters are in agreement with the desired values and are steady, a suitable initial condition is ieved.
6.5.4A.3 Signal Logic for Large-Break LOCA reactor trip signal occurs due to compensated pressurizer pressure within the first second of the e-break transient. Because control rod insertion is not modeled in WCOBRA/TRAC, no effects on tivity ensue. A safeguards S signal occurs due to containment high pressure at 2.2 seconds of e-break LOCA transients.
a consequence of this signal, after appropriate delays, the PRHR and core makeup tank isolation es open and containment isolation occurs. The rapid depressurization of the primary system ng a large-break LOCA leads to the initiation of accumulator injection early in the large-break sient. The accumulator flow diminishes core makeup tank delivery to such an extent that the core eup tank level does not approach the ADS Stage 1 valve actuation point until after the umulator tank is empty. The accumulator empties long after the blowdown portion of the large-ak LOCA transient is complete. Actuation of the ADS on CMT water level does not occur until long r the AP1000 PCT is calculated to occur.
6.5.4A.4 Transient Calculation e the steady-state calculation is found to be acceptable, the transient calculation is initiated. The i-implicit pipe break model is added to the desired break location. Cold-leg breaks are analyzed ause the hot-leg break location is nonlimiting in the large-break LOCA best-estimate hodology. The break size and type are sampled consistent with the WCAP-16009-P-A ference 32) methodology. The containment backpressure is specified consistent with AP-16009-P-A (Reference 32) methodology. The steady-state calculation is restarted with the ve changes to begin the transient.
calculation is continued until the fuel rods are quenched.
le 15.6.5-5 shows a general sequence of events following a large cold-leg break LOCA and the tionship of these events to the blowdown and reflood portion of the transient.
6.5.4A.5 Large-Break LOCA Analysis Results the AP1000 large-break LOCA analysis, the best-estimate LOCA analysis methodology umented in Reference 34 is applied. The AP1000 large-break LOCA analysis complies with the rictions in Reference 32. AP1000 sensitivity calculations evaluated the sensitivity to the modeling e CMT and PRHR relative to the reference transient configuration. A case in which the CMT was ated from the rest of the AP1000 was analyzed, and the calculated PCT was lower than the PCT 15.6-23 Revision 1
alculations, and the final 95 percent uncertainty calculations have been performed for AP1000.
al and core-wide cladding oxidation values have been determined using the methodology roved in Reference 32.
e AP1000 ASTRUM analysis, the same uncertainty calculation was the limiting PCT and imum local oxidation (MLO) case. The limiting PCT/MLO case in the AP1000 ASTRUM analysis a split break. Figures 15.6.5.4A-1 through 15.6.5.4A-12 present the parameters of principal rest for the limiting PCT/MLO case. Values of the following parameters are presented:
Highest calculated cladding temperature at any elevation for the five fuel rods modeled Hot rod cladding temperature transient at the limiting elevation for PCT Core fluid mass flows at the top of the core for the fuel assemblies modeled in WCOBRA/TRAC Pressurizer pressure Break flow rates Core and downcomer collapsed liquid levels Accumulator water flow rates Core makeup tank flow rates 6.5.4A.6 Description of AP1000 Large-Break LOCA Transient escription of the limiting PCT/MLO case from the AP1000 ASTRUM analysis follows. The limiting
/MLO case is a split break. The sequence of events is presented in Table 15.6.5-6. The break modeled to occur in one of the cold legs in the loop containing the core makeup tanks. After the ak opens, the vessel rapidly depressurizes and the core flow quickly reverses. The hot assembly rods dry out and begin to heat up (Figures 15.6.5.4A-1 and 15.6.5.4A-2) after the initial flow rsal (Figure 15.6.5.4A-3).
igure 15.6.5.4A-1, Hot Rod refers to the hot rod at the maximum linear heat rate for the run, t Assembly refers to the average rod in the hot assembly that contains the hot rod, Support umn/Open Hole refers to the support column/open hole assembly average rod, Guide Tubes rs to the guide tube assembly average rod, and Low Power refers to the peripheral fuel embly rod.
steam generator secondaries are assumed to be isolated immediately at the inception of the ak to maximize their stored energy. The massive size of the break causes an immediate, rapid surization of the containment. At 2.2 seconds, credit is taken for receipt of an S signal due to h-2 containment pressure. Applying the pertinent signal processing delay means that the valves ating the core makeup tanks from the direct vessel injection line and the PRHR begin to open at seconds into the transient. The reactor coolant pumps automatically trip after a 4 second delay the actuation of the core makeup tank isolation valves at 8.2 seconds into the transient. Core tdown occurs due to voiding; no credit is taken for the control rod insertion effect.
system depressurizes rapidly (Figure 15.6.5.4A-4) as the initial mass inventory is depleted due reak flow. The pressurizer drains completely approximately 30 seconds into the transient, and umulator injection commences 18 seconds into the transient (Figure 15.6.5.4A-5). Accumulator ation shuts off core makeup tank flow (Figure 15.6.5.4A-6), which has been occurring since the ation valve opened. The CMT liquid level remains well above the ADS Stage 1 actuation setpoint ughout the AP1000 LBLOCA cladding temperature excursion, even though CMT injection begins in around 150 seconds.
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rior assemblies (the corresponding figure for the hot assembly is Figure 15.6.5.4A-3).
res 15.6.5.4A-8 and 15.6.5.4A-9 illustrate the impact of upper head drain through the guide s and upper core plate holes, respectively, on the core flow. While liquid remains in the upper d above the top of the guide tubes, the guide tubes (Figure 15.6.5.4A-8) are the preferred path for ning liquid into the upper plenum. Once the upper head begins to flash, liquid drains directly down guide tubes and that fraction that is able to penetrate into the core does so, at a maximum flow exceeding 1000 lbm/sec of total liquid flow between 11 and 24 seconds. At that point, the flow ring the guide tubes in the upper head is largely steam; residual liquid is supplied to the guide fuel assemblies at a constant or decreasing rate out to 30 seconds.
re 15.6.5.4A-9 presents the open hole/support column assembly top of core flow behavior. The ng of the initial downflow into the open hole/support column assemblies is similar to that of the nflow into the guide tube fuel assemblies, beginning at 13 seconds. Between 19 and 24 seconds, combined flow of continuous and entrained liquid is 300 to 1000 lbm/sec; the entrained liquid flow tinues to be significant until 40 seconds.
id downflow is delayed into the hot assembly. By 19 seconds into the transient, liquid that has up in the global region above the hot assembly begins to flow into the hot assembly ure 15.6.5.4A-3). Significant flow of continuous liquid into the hot assembly exists between 19 to econds. The liquid flow is not enough to quench the hot rod and hot assembly rod at all ations (Figure 15.6.5.4A-1) although effective cooling is achieved.
re 15.6.5.4A-7 demonstrates that liquid downflow exists through the top of the peripheral core emblies from 8 seconds to 13 seconds and again from 16 seconds to 21 seconds in the percentile estimator PCT/MLO case. The power of the fuel in this region is significantly lower that of the fuel in the open hole and guide tube locations (Table 15.6.5-4), so liquid downflow urs earlier than in the average power assemblies.
r 18 seconds into the transient, the accumulator begins to inject water into the upper downcomer on, most of which is initially bypassed to the break. The break flow rate diminishes as the sient progresses (Figure 15.6.5.4A-10). At 34.5 seconds, the accumulator injection begins to refill lower plenum. At approximately 54.0 seconds, the lower plenum fills to the point that water ins to reflood the core from below. The void fraction at the core bottom begins to decrease, and ime passes, core cooling increases substantially. Figure 15.6.5.4A-11 presents the collapsed d levels in the core; Figure 15.6.5.4A-12 presents the collapsed liquid levels in the downcomer.
cladding temperature begins to decrease once the core water level has risen high enough in the 6.5.4A.7 Global Model Sensitivity Studies and Uncertainty Evaluation section 15.6.5.4A discusses the treatment of the global model parameters and the uncertainty luation in the ASTRUM methodology.
6.5.4A.8 Large-Break LOCA Conclusions ccordance with 10 CFR 50.46, the conclusions of the best-estimate large-break LOCA analysis that there is a high level probability that the following criteria are met.
- 1. The calculated maximum fuel element cladding temperature (i.e., peak cladding temperature (PCT)) will not exceed 2200°F.
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- 3. The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam (i.e., maximum hydrogen generation) will not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react.
- 4. The calculated changes in core geometry are such that the core remains amenable to cooling.
Note that criterion 4 has historically been satisfied by adherence to criteria 1 and 2, and by assuring that fuel deformation due to combined LOCA and seismic loads is specifically addressed. Criteria 1 and 2 are satisfied for best-estimate large-break LOCA applications.
The approved methodology specifies that effects of LOCA and seismic loads on core geometry do not need to be considered unless grid crushing extends beyond the assemblies in the low power channel as defined in the WCOBRA/TRAC model. This situation has not been calculated to occur for the AP1000. Therefore, acceptance criterion 4 is satisfied.
- 5. After successful initial operation of the emergency core cooling system (ECCS), the core temperature will be maintained at an acceptably low value and decay heat will be removed for the extended period of time required by the long-lived radioactivity remaining in the core.
Criterion 5 is satisfied if a coolable core geometry is maintained and the core is cooled continuously following the LOCA. The AP1000 passive core cooling system provides effective core cooling following a large-break LOCA event, even assuming the limiting single failure of a core makeup tank delivery line isolation valve. The large-break LOCA transient has been extended beyond fuel rod quench until 1400 seconds, a time at which the CMT liquid level has decreased to the low-2 setpoint that actuates the fourth-stage ADS valves and IRWST injection. A significant increase in safety injection flow rate occurs when the IRWST becomes active. The analysis performed demonstrates that CMT injection is sufficient to maintain the mass inventory in the core and downcomer, from the period of fuel rod quench until IRWST injection. The AP1000 passive core cooling system provides effective post-LOCA long-term core cooling.
le 15.6.5-8 presents the calculated 95th percentile PCT, maximum cladding oxidation, maximum rogen generation, and core cooling results.
ed on the analysis, the Westinghouse Best-Estimate Large-Break LOCA methodology has shown the acceptance criteria of 10 CFR 50.46 are satisfied for AP1000.
6.5.4B Small-Break LOCA Analyses uld a small break LOCA occur, depressurization of the reactor coolant system results in a sure decrease in the pressurizer. The reactor trip signal occurs when the pressurizer low-sure trip setpoint is reached. An S signal is generated when the appropriate setpoint is hed. These measures limit the consequences of the accident in two ways:
Reactor trip leads to a rapid reduction of power to a residual level corresponding to fission product decay heat by the insertion of control rods to shut down the reactor.
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6.5.4B.1 Description of Small-Break LOCA Transient AP1000 plant design includes passive safety features to prevent or minimize core uncovery ng small-break LOCAs. The passive safety design approach of the AP1000 is to depressurize the tor coolant system if the break or leak is greater than the capability of the makeup system or if nonsafety makeup system fails to perform. By depressurizing the reactor system, large volumes orated water in the accumulators and in the IRWST become available for cooling the core. This lysis demonstrates that, with a single failure, the passive systems are capable of depressurizing reactor coolant system while maintaining acceptable core conditions and establishing stable very of cooling water from the IRWST.
ing a small-break LOCA, the AP1000 reactor coolant system depressurizes to the pressurizer pressure setpoint, actuating a reactor trip signal. The passive core cooling system is aligned for very following the generation of an S signal when the pressurizer low-pressure setpoint is hed. The passive core cooling system includes two core makeup tanks, two accumulators, a e IRWST, and the PRHR heat exchanger.
core makeup tanks operate at reactor coolant system pressure. They provide high-pressure ty injection in the event of a small-break LOCA. The core makeup tanks share a common harge line with the accumulators and IRWST; they are filled with borated water to provide core tdown margin. Gravity head of the colder water in the core makeup tanks provides the injection of core makeup tanks. The core makeup tanks are located above the reactor coolant loops, and h is equipped with a pressure balancing line from a cold leg to the top of the tank.
pressurized accumulators provide additional borated water to the reactor coolant system in the nt of a LOCA. Nominally, these 2000-ft3 tanks are filled with 1700 ft3 of water and 300 ft3 of gen at an initial pressure of 700 psig. Once sufficient reactor coolant system depressurization urs, either as a result of a LOCA or the actuation of the ADS, accumulator injection begins.
IRWST at a minimum provides an additional 73,900 ft3 of water for long-term core cooling. To in injection from the IRWST, the reactor coolant system pressure must be lowered to roximately 13 psi above containment pressure. For this pressure to be achieved during a small-ak LOCA, the actuation of the ADS valves is required.
ADS consists of a series of valves, connected to the pressurizer and hot legs, which provide a sed depressurization of the reactor coolant system. As the reactor system loses inventory ugh the break, the core makeup tanks provide flow to the reactor vessel. When the level in the makeup tank drops to the 67.5-percent level, the ADS valves open to accelerate the reactor lant system depressurization rate. The ADS Stage 1 4-inch valves open at the 67.5-percent level; 8-inch Stage 2 and the 8-inch Stage 3 valves open in a timed sequence thereafter. The flow from first three stages of the ADS is discharged into the IRWST through a sparger system. The th stages of the ADS are connected to the reactor coolant system hot legs and discharge to tainment atmosphere. The ADS Stage 4 valves are activated when the core makeup tank level hes the 20-percent level.
he reactor system depressurizes and mass is lost out the break, mass is added to the reactor sel from the core makeup tanks and the accumulators. When the system is depressurized below IRWST delivery pressure, flow from the IRWST continues to maintain the core in a coolable state.
culations described in this section indicate that acceptable core cooling is provided for the small-ak LOCA transients.
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CFR 50 Appendix K. The elements of the AP1000 small-break LOCA evaluation model are the wing:
NOTRUMP computer code NOTRUMP homogeneous sensitivity model Critical heat flux assessment during accumulator injection 6.5.4B.2.1 NOTRUMP Computer Code NOTRUMP computer code is used in the analysis of LOCAs due to small-breaks in the reactor lant system. The NOTRUMP computer code is a one-dimensional, general network code, which udes a number of advanced features. Among these features are the calculation of thermal non-ilibrium in all fluid volumes, flow regime-dependent drift flux calculations with counter-current ding limitations, mixture level tracking logic in multiple-stacked fluid nodes, and regime-endent heat transfer correlations. The version of NOTRUMP used in AP1000 small-break LOCA ulations has been validated against applicable passive plant test data (Reference 22). The code limited capability in modeling upper plenum and hot leg entrainment and did not predict the core apsed level during the accumulator injection phase adequately. The NOTRUMP homogeneous sitivity model (discussed in Subsection 15.6.5.4B.2.2) and the critical heat flux assessment during accumulator injection phase (discussed in Subsection 15.6.5.4B.2.3) supplement the base TRUMP analysis to demonstrate the adequacy of the design.
OTRUMP, the reactor coolant system is nodalized into volumes interconnected by flow paths.
transient behavior of the system is determined from the governing conservation equations of s, energy, and momentum applied throughout the system. A description of NOTRUMP is given in erences 12 and 13. The AP600 modeling approach, described in Reference 17, is also used to elop the AP1000 model; NOTRUMPs applicability to AP1000 is documented in Reference 24.
use of NOTRUMP in the analysis involves the representation of the reactor core as heated trol volumes with an associated bubble rise model to permit a transient mixture height calculation.
multi-node capability of the program enables an explicit and detailed spatial representation of ous system components. Table 15.6.5-9 lists important input parameters and initial conditions of analysis.
eady-state input deck for the AP1000 was set up to comply, where appropriate, with the standard ll-break LOCA Evaluation Model methodology. Major features of the modeling of the AP1000 w:
Accumulators are modeled at an initial pressure of 715 psia.
The flow through the ADS links is modeled using the Henry-Fauske, the homogeneous equilibrium (HEM), and the Murdock/Baumann critical flow models. The Henry-Fauske correlation is used for low-quality two-phrase flow, and the HEM model, for high-quality flow, with a transition between the two beginning at 10-percent static quality. The Murdock-Bauman model is used if the ADS flow path is venting superheated steam.
Isolation and check valves used in the passive safety systems are modeled.
The IRWST is modeled as two connected fluid nodes. The lower node is connected to the direct vessel injection line and is the source of injection water to the DVI lines driven by gravity head. The upper node acts as a sink for the ADS flow from the pressurizer and as a 15.6-28 Revision 1
simulations, a conservative 20 psia containment pressure was used based on containment pressurization calculations performed with the WGOTHIC containment model.
The PRHR system is modeled in accordance with the guidance provided in References 22 and 24. The PRHR isolation valve is modeled as opening with the maximum delay after the generation of an S signal to conservatively deny the cooling capability of the heat exchanger to the reactor coolant system for an extended period.
The core power is initially set to 102 percent of the nominal core power. The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative. The reactor trip signal occurs when the pressurizer pressure falls below 1800 psia. A conservative delay time is modeled between the reactor trip signal and reactor trip. Decay heat is modeled according to the ANS-1971 (Reference 2) standard, with 20-percent uncertainty added.
The S signal is generated when the pressurizer pressure falls below 1700 psia. The isolation valves on the core makeup tank injection lines begin to open after the signal setpoint is reached; the valves are then assumed to open linearly. The main feedwater isolation valves are ramped closed between 2 and 7 seconds after the S signal. The reactor coolant pumps are tripped 6.0 seconds after the S signal.
The ADS actuation signals are generated on low core makeup tank levels and the ADS timer delays. A list of the ADS parameters is given in Table 15.6.5-10 for AP1000. ADS Stages 1, 2, and 3 are modeled as discharging through spargers submerged in the IRWST at the appropriate depth.
The pressure in the boundary node modeling of the containment is 14.7 psia in all NOTRUMP cases except the DEDVI line break, which used 20.0 psia.
The steam generator secondary is isolated 6 seconds after the reactor trip signal, due to closure of the turbine stop valves. The main steam safety valves actuate and remove energy from the steam generator secondary when pressure reaches 1235 psia.
ve single failures of the passive safeguards systems are considered. The limiting failure is judged e one out of four ADS Stage 4 valves failing to open on demand, the failure that most severely acts depressurization capability. The safety design approach of the AP1000 is to depressurize the tor coolant system to the containment pressure in an orderly fashion such that the large reservoir ater stored in the IRWST is available for core cooling. The mass inventory plots provided for the aks show the minimum inventory condition generally occurs at the start of IRWST injection.
alizing the depressurization is the most conservative approach in postulating the single failure for h breaks.
small-break LOCA spectrum analyzed for AP1000 includes a break that exhibits a minimum tor vessel inventory early in the transient, before the accumulators become active: the 10-inch leg break. In this transient, the early mass inventory decrease is terminated by injection flow the accumulators, and depressurization through the break enables accumulator injection to in with no contribution from the actuation of ADS Stages 1, 2, and 3. For consistency, the servative failure of one of the ADS Stage 4 valves located off the PRHR inlet pipe, which ersely affects the depressurization necessary to achieve IRWST injection in small-break LOCAs, ssumed in all cases. Sensitivity analysis shows that assuming failure of one ADS Stage 4 valve he non-PRHR loop does not significantly impact core cooling.
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eloped in the same fashion with modifications to the AP600 model introduced as follows. A ification performed for AP1000 was the addition of two core nodes one foot each in length to ct the added active fuel length of this design. The ADS-4 flow path resistances were increased to ommodate shortcomings in NOTRUMP identified during the integral test facility simulations, ely, the lack of a detailed momentum flux model in the ADS-4 discharge paths. A detailed ulation of the energy and momentum equations is performed for the ADS-4 piping over a range of and pressure conditions to provide a benchmark for the NOTRUMP ADS-4 flow path resistance.
methodology used to determine the resistance increase is described in Reference 24. By easing the ADS-4 resistances, the onset of IRWST injection is more appropriately calculated.
methodology directly addresses the effect of momentum flux in ADS-4. The ADS-4 resistance ease utilized is computed for the NOTRUMP analyses in this section to be a 70 percent ADS-4 path resistance increase.
6.5.4B.2.1.2 Plant Initial Conditions/Steady-State eady-state calculation is performed prior to initiating the transient portion of the calculation.
le 15.6.5-9 contains the most important initial conditions for the transient calculations. The aviors of the primary pressure and pressurizer level, steam generator pressures, and the core rate are stable at the end of the 100-second steady-state calculation.
6.5.4B.2.2 NOTRUMP Homogeneous Sensitivity Model rder to address the uncertainties associated with entrainment in the upper plenum and hot leg wing ADS-4 operation, a sensitivity study is performed with the limiting break with respect to e phenomena, effectively maximizing the amount of entrainment downstream of the core. This hodology is described and the results are presented for the double-ended direct vessel injection DVI) line break in detail in Reference 24.
rder to maximize the entrainment downstream of the core for the limiting break with respect to ainment, NOTRUMP is run with the regions of the upper plenum, hot leg, and ADS-4 lines in a ogeneous fluid condition, with slip = 1, to demonstrate that even with maximum entrainment, the CFR 50.46 criteria are met.]*
6.5.4B.2.3 Critical Heat Flux Assessment During Accumulator Injection assessment is performed of the peak core heat flux with respect to the critical heat flux during the r ADS depressurization time period for a double-ended rupture of the direct vessel injection line.
time period corresponds to the accumulator injection phase of the transient. The predicted rage mass flux at the core inlet and the reactor pressure from the NOTRUMP computer code e model analysis are used as input parameters to critical heat flux correlation as described in erence 30. The requirements of 10 CFR 50.46 are met provided the maximum heat flux is less the critical heat flux calculated by the correlation.]* NOTRUMP has been shown (Reference 24) dequately predict mass flux and pressure for integral systems tests.
predicted mass flux at the core inlet is on the average constant and corresponds to lbm ft-2 s-1 (~35 kg m-2 s-1). The key thermal-hydraulic parameters at different times during the S depressurization time period are summarized in following table.
Staff approval is required prior to implementing a change in this information.
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500 655 95 35 19.1 570 345 50 35 18.5 600 276 40 35 18.2 the critical heat flux assessment, the peak core heat flux is applied to simulate the hot assembly dition in a conservative manner. No credit is taken for increased flow in the hot assembly that is wn to occur in rod bundles.
correlation applied for this assessment is from vertical tube data (Reference 30) and recognizes regimes depending on the mass flux. The main difference between the two is the mass flux endence. They are as follows:
( )
q *CL = q *CF + 0.01351 D
- 0.473 (L / D )0.533 G
- 1.45 for low G*
( )
q *CH = q *CF + 0.05664 D
- 0.247 (L / D )0.501 G
- 0.77 for high G*
first term of above correlations is, q *CF = 1.61 A
( )
D*
0.5 2
Ah 0.25 1 + g l
re A is the flow area and Ah is the heated area.
dimensionless CHF is calculated as, q *CHF = min(q *CL , q *CH )
ensionless CHF, G, and D are defined as, q 'CHF q *CHF =
h fg g g 15.6-31 Revision 1
g g D
D* =
re is the length scale of the Taylor instability:
=
g servative application of this correlation with the AP1000 parameters indicates that the peak 000 heat flux during this period is at least 40 percent below the predicted critical heat flux.
CHF assessment addresses core cooling during a time period where the NOTRUMP computer e may not conservatively predict the core average void fraction. The requirements of CFR 50.46 are met during this period since this CHF assessment indicates peak core heat flux is than critical heat flux. Cladding temperatures will remain near the coolant saturation perature, well below the 10 CFR 50.46 peak cladding temperature limit.
6.5.4B.3 Small-Break LOCA Analysis Results eral small-break LOCA transients are analyzed using NOTRUMP, and the results of these ulations are presented. The results demonstrate that the minimum reactor coolant system mass ntory condition occurs for the relatively large system pipe breaks. Smaller breaks exhibit a ater margin-to-core uncovery.
6.5.4B.3.1 Introduction small-break LOCA safety design approach for AP1000 is to provide for a controlled ressurization of the primary system if the break cannot be terminated, or if the nonsafety-related rging system is postulated to be lost or cannot maintain acceptable plant conditions. Nonsafety-ted systems are not modeled in this design basis analysis; the testing conducted in the SPES-2 ity has indicated that the mass inventory condition during small LOCAs is significantly improved n these nonsafety-related systems operate. The core makeup tank level activates primary em depressurization. The core makeup tank provides makeup to help compensate for the tulated break in the reactor coolant system. As the core makeup tank level drops, Stages 1 ugh 4 of the ADS valves are ramped open in sequence. The ADS valve descriptions for the 000 plant design are presented in Table 15.6.5-10. The reactor coolant system depressurizes to the break and the ADS valves, while subcooled water from the core makeup tanks and umulators enters the reactor vessel downcomer to maintain system inventory and keep the core ered. Design basis maximum values of passive core cooling system resistances are applied to in a conservative prediction of system behavior during the small LOCA events.
ing controlled depressurization via the ADS, the accumulators and core makeup tanks maintain em inventory for small-break LOCAs. Once the reactor coolant system depressurizes, injection the IRWST maintains long-term core cooling. For continued injection from the IRWST, the 15.6-32 Revision 1
ries of small-break LOCA calculations are performed to assess the AP1000 passive safety em design performance. In these calculations, the decay heat used is the ANS-1971 ference 2) plus 20 percent for uncertainty as specified in 10 CFR 50, Appendix K (Reference 1).
maximizes the core steam generation to be vented. The breaks analyzed in this document ude the following:
dvertent ADS Actuation o-break small-break LOCA calculation that uses an inadvertent opening of the 4-inch nominal ADS Stage 1 valves is a situation that minimizes the venting capability of the reactor coolant em. Only the ADS valve vent area is available; no additional vent area exists due to a break. This e examines whether sufficient vent area is available to completely depressurize the reactor lant system and achieve injection from the IRWST without core uncovery. The worst single failure his situation is a failure of one of four ADS Stage 4 valves connected to either of the two hot legs.
ADS Stage 4 valve is the largest ADS valve, and it vents directly to the containment with no itional backpressure from the spargers being submerged in the IRWST.
ch Break in a Cold Leg with Core Makeup Tank Balance Line Connections small size of the break leads to a long period of recirculatory flow from the cold leg into the core eup tank. This delays the formation of a vapor space in the core makeup tank and therefore the ation of the ADS.
uble-Ended Rupture of the Direct Vessel Injection Line injection line break evaluates the ability of the plant to recover from a moderately sized break only half of the total emergency core cooling system capacity available. The vessel side of the ak of the DEDVI line break is 4 inches in equivalent diameter. The double-ended nature of this ak means that there are effectively two breaks modeled:
Downcomer to containment. The direct vessel injection nozzle includes a venturi, which limits the available break area.
Direct vessel injection line into containment from the cold leg balance line and the broken loop core makeup tank.
containment pressure was conservatively assumed to pressurize to 20 psia. This pressure was cted based on iterative execution of the NOTRUMP and WGOTHIC codes. The NOTRUMP code ides the mass and energy releases from the AP1000 DEDVI break to the AP1000 WGOTHIC tainment model while the WGOTHIC code calculates the containment pressure response. The tainment pressure assumed in the NOTRUMP simulations was conservatively selected from the erated pressure history curves obtained from the WGOTHIC runs.
peak core heat flux during the accumulator injection period is assessed relative to the predicted cal heat flux as discussed in Subsection 15.6.5.4B.2.3.
additional injection line break case is analyzed assuming containment pressure is at 14.7 psia.
uble-Ended Rupture of the Direct Vessel Injection Line Entrainment Sensitivity sensitivity case is performed to assess the effect of higher than expected entrainment in the er plenum and hot legs on the overall system response and core cooling.
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6.5.4B.3.2 Transient Results transient results are presented in tables and figures for the key AP1000 parameters of interest in following sections.
6.5.4B.3.3 Inadvertent Actuation of Automatic Depressurization System nadvertent ADS signal is spuriously generated and the 4-inch ADS valves open. The plant, which perating at 102-percent power, is depressurized via the ADS alone. The main feedwater flow surement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is servative. Only safety-related systems are assumed to operate in this and other small-break A cases. Additional ADS valves open; after a 70-second delay, the ADS Stage 2 8-inch valves n, and after an additional 120 seconds, the ADS Stage 3 valves open. At the 20-percent core eup tank level, the ADS Stage 4A valve, which is connected to the hot leg, receives a signal to
- n. After a 60-second delay, both Stage 4B valves (one connected to the hot leg and the other nected to the PRHR inlet pipe) open. The path that fails to open as the assumed single active re is the Stage 4A valve off the PRHR inlet pipe. The reactor steady-state initial conditions umed can be found in Table 15.6.5-9. The sequence of events for the transient is given in le 15.6.5-11.
transient is initiated by the opening of the two ADS Stage 1 paths. Reactor trip, reactor coolant p trip, and safety injection signals are generated via pressurizer low-pressure signals with ropriate delays. After generation of the reactor trip signal, the turbine stop valves begin to close.
main feedwater isolation valves begin to close 2 seconds after the S signal pressure setpoint is hed. The opening of the ADS valves and the reduction in core power due to reactor trip causes primary pressure to fall rapidly (Figure 15.6.5.4B-1). Flow of fluid toward the open ADS paths ses the pressurizer to fill rapidly (Figure 15.6.5.4B-2), and the ADS flow becomes two-phase ures 15.6.5.4B-3 and 15.6.5.4B-4). The safety injection signal opens the valves isolating the core eup tanks and circulation of cold water begins (Figures 15.6.5.4B-5 and 15.6.5.4B-6). The ure level (Figures 15.6.5.4B-7 and 15.6.5.4B-8) in the core makeup tanks is relatively constant l the accumulators inject (Figures 15.6.5.4B-10 and 15.6.5.4B-11). The reactor coolant pumps in to coast down due to an automatic trip signal following a 6.0-second delay.
tinued mass flow through the ADS Stage 1, 2, and 3 valves drains the upper parts of the circuit.
steam generator tube cold leg sides start to drain, followed by the drop in mixture levels in the leg sides. As the ADS Stage 2 and 3 paths begin to open, increased ADS flow causes the primary sure to fall rapidly (Figure 15.6.5.4B-1). Following the emptying of the steam generator tube cold sides, the cold legs have drained and a mixture level forms in the downcomer ure 15.6.5.4B-9).
primary pressure falls below the pressure in the accumulators thus causing the accumulator ck valves to open and accumulator delivery to begin (Figures 15.6.5.4B-10 and res 15.6.5.4B-11). The accumulators, and then the core makeup tanks inject until they empty.
ADS flow falls off as the primary pressure decreases. The flow from the accumulators raise the ure levels in the upper plenum and downcomer (Figures 15.6.5.4B-16 and 15.6.5.4B-9).
he levels in the core makeup tanks reach the ADS Stage 4 setpoint, one out of two paths is ned from the top of the hot leg (loop 1) and begin discharging fluid. After 30 seconds, the second in loop one opens, as does a loop 2 Stage 4 path. Activating the Stage 4 paths leads to reduced through ADS Stages 1, 2, and 3. The reduced flow allows the pressurizer level to fall, and these es begin to discharge only steam. Once the core makeup tanks are empty, delivery ceases 15.6-34 Revision 1
plete; IRWST delivery exceeds the ADS flows (which are removing the decay heat), and the tor coolant system inventory is slowly rising (Figure 15.6.5.4B-15). Core uncovery does not ur and the upper plenum mixture level remains well above the core elevation throughout ure 15.6.5.4B-16).
inadvertent opening of the ADS Stage 1 transient confirms the minimum venting area capability epressurize the reactor coolant system to the IRWST pressure. The analysis indicates that the S sizing is sufficient to depressurize the reactor coolant system assuming the worst single failure he failure of a Stage 4 ADS path to open and decay heat equal to the 10 CFR 50 Appendix K ference 1) value of the ANS-1971 Standard (Reference 2) plus 20 percent, which over estimates core steam generation rate. Even under these limiting conditions, IRWST injection is obtained, the core remains covered such that no cladding heatup occurs.
6.5.4B.3.4 2-inch Cold Leg Break in the Core Makeup Tank Loop case models a 2-inch break occurring in the bottom of cold leg connected to the balance line of T-1. The reactor steady-state initial conditions assumed for this transient can be found in le 15.6.5-9. The event times for this transient are given in Table 15.6.5-12.
break opens at time zero, and the pressurizer pressure begins to fall as shown in re 15.6.5.4B-17 as mass is lost out the break. The pressurizer mixture level initially decreases as n in Figure 15.6.5.4B-18. The break fluid flow is shown in Figures 15.6.5.4B-32 and
.5.4B-33. The pressurizer pressure falls below the reactor trip set point, causing the reactor to (after the appropriate time delay) and causing isolation of the steam generator steam lines. The makeup tank isolation valves on both delivery lines and the PRHR delivery line isolation valve n after an S signal occurs (with appropriate delays); the reactor coolant pumps trip after an S a 6.0-second delay. The reactor coolant system is cooled by natural circulation with the steam erators removing the energy through their safety valves (as well as by the break) and via the HR. Once the core makeup tank isolation valves open, the core makeup tanks begin to inject ated water into the reactor coolant system as shown in Figures 15.6.5.4B-22 and 15.6.5.4B-23.
ime proceeds, the loops drain to the reactor vessel. The mixture level in the downcomer begins to p as seen in Figure 15.6.5.4B-30, and the core remains completely covered. The core makeup reaches the 67.5-percent level, and after an appropriate delay, the ADS Stage 1 valves open.
en the ADS is actuated, the mixture level increases in the pressurizer (Figure 15.6.5.4B-18) ause an opening has been created at the top of the pressurizer. After these valves open, a more d depressurization occurs as seen in Figure 15.6.5.4B-17; the accumulator setpoint is reached the accumulators begin to inject. The injection flow from the core makeup tanks are shown in res 15.6.5.4B-22 and 15.6.5.4B-23, and from the accumulators, in Figures 15.6.5.4B-24 and
.5.4B-25.
Figures 15.6.5.4B-22 and 15.6.5.4B-23 indicate, when the accumulators begin to inject, the flow both core makeup tanks is reduced, and the flow is temporarily stopped due to the surization of the core makeup tanks injection lines by the accumulators.
ADS Stage 2 valves, maintaining the depressurization rate as shown in Figure 15.6.5.4B-17.
S Stage 3 valves open, thereby increasing the system venting capability. The ADS Stage 4 valves n when the core makeup tank water level is reduced to 20 percent. Figures 15.6.5.4B-28 and
.5.4B-31 indicate the instantaneous liquid and integrated total mass discharged from the ADS ge 4 valves. After the ADS Stage 4 path opens, the pressurizer begins to drain mixture into the hot as seen in Figure 15.6.5.4B-18. The Figure 15.6.5.4B-29 mass inventory plot considers the 15.6-35 Revision 1
mixture level in the reactor vessel is approximately at the hot leg elevation as shown in re 15.6.5.4B-30 throughout this transient; the core never uncovers, and the peak cladding perature occurs for this transient at the inception of the event. The 2-inch break cases exhibit e margin-to-core uncovery.
6.5.4B.3.5 Direct Vessel Injection Line Break case models the double-ended rupture of the DVI line at the nozzle into the downcomer. The en loop injection system (consisting of an accumulator, a core makeup tank, and an IRWST very line) is modeled to spill completely out the DVI side of the break. The steady-state reactor lant system conditions for this transient are shown in Table 15.6.5-9. Design maximum stances are applied to the inlet and outlet lines of that core makeup tank to conservatively imize intact loop core makeup tank delivery through the time of minimum reactor coolant system s inventory. Minimum resistances are applied to the broken loop IRWST injection line to imize the spill to containment, thus minimizing the reactor coolant system mass inventory. This e uses a containment backpressure defined to be a constant 20 psia. While not exactly reflecting containment pressure history that occurs as a result of the DVI line break, it represents a servatively low estimate of the expected containment pressure response during a DEDVI sient. The containment pressurizes for a DEDVI break as a result of the break mass and energy ases in addition to the ADS-4 discharge paths that vent directly to the containment atmosphere.
containment pressurization was calculated using the mass and energy releases from the TRUMP small-break LOCA code in the WGOTHIC containment model. Mass and energy ases from both sides of the DVI break (both vessel side and DVI side) and ADS-4 valve harges were provided in a tabular form to the WGOTHIC AP1000 model used to compute tainment pressurization for the long-term cooling analysis.
event times for this transient are shown in Table 15.6.5-13. The break is assumed to open antaneously at 0 seconds. The accumulator on the broken loop starts to discharge via the DVI to the containment. Figure 15.6.5.4B-36 shows the subcooled discharge from the downcomer zle, which causes a rapid reactor coolant system (RCS) depressurization (Figure 15.6.5.4B-38).
actor trip signal is generated, followed by generation of the S signal. Following a delay, the ation valves on the core makeup tank and PRHR delivery lines begin to open. The S signal also ses closure of the main feedwater isolation valves after a 2-second delay and trips the reactor lant pumps after a 6-second delay. The opening of the core makeup tank isolation valves allows broken loop core makeup tank to discharge directly to the containment (Figure 15.6.5.4B-39),
a small circulatory flow develops through the intact loop core makeup tank (Figure 15.6.5.4B-40).
he pressure falls, the reactor coolant system fluid saturates, and a mixture level forms in the er plenum and then falls to the hot leg elevation (Figure 15.6.5.4B-41). The upper parts of the tor coolant system start to drain, and a mixture level forms in the downcomer ure 15.6.5.4B-42) and falls below the elevation of the break. Two-phase discharge, then vapor occurs from the downcomer side of the break (Figure 15.6.5.4B-37).
e core makeup tank connected to the broken loop, a level forms and starts to fall. The ADS ge 1 setpoint is reached, and the ADS Stage 1 valves open after the signal delay time elapses.
ensuing steam discharge from the top of the pressurizer (Figure 15.6.5.4B-43) increases the tor coolant system depressurization rate. The depressurization rate is also increased due to the m discharge from the downcomer to the containment (Figure 15.6.5.4B-37) as the downcomer ure level falls below the DVI nozzle (Figure 15.6.5.4B-42).
15.6-36 Revision 1
core (Figure 15.6.5.4B-47) and insufficient liquid remains in the core and upper plenum to sustain mixture level. The mixture level therefore starts to decrease (Figure 15.6.5.4B-41). The mixture l falls to a minimum and then starts to recover, as flow re-enters the core from the downcomer ure 15.6.5.4B-41 compared to 15.6.5.4B-47).
ADS Stage 2 valves open after the appropriate time delay between the actuation of the first two es of the ADS. The intact loop accumulator starts to inject into the downcomer ure 15.6.5.4B-50) causing the mixture level in the downcomer to slowly rise ure 15.6.5.4B-42). The mixture level also increases within the upper plenum.
ADS Stage 3 valves open upon completion of the time delay of 120 seconds between the ation of Stages 2 and 3 of the ADS. The broken loop core makeup tank level reaches the ADS ge 4 setpoint, but the ADS Stage 4 valves do not open until the minimum time delay between the ation of ADS Stages 3 and 4 occurs. Two-phase discharge ensues through three of the four ge 4 paths (Figures 15.6.5.4B-48 and 15.6.5.4B-49). The broken loop core makeup tank and umulator empty rapidly.
fluid level at the top of the intact loop core makeup tank starts to decrease slowly ure 15.6.5.4B-52) because injection from the tank has begun (Figure 15.6.5.4B-40). The intact accumulator has emptied (Figure 15.6.5.4B-50) and the reduced pressure in the injection line ws the core makeup tank to inject continuously.
ing the period of accumulator injection, the downcomer mixture level rises slowly ure 15.6.5.4B-42). Figure 15.6.5.4B-53 presents the RCS mass inventory. With only intact loop makeup tank injection available for a period of time, the downcomer level once again falls and boil-off increases the rate of reactor coolant system inventory depletion until sufficient CMT/
ST injection flow can be introduced. However, the level in the upper plenum is maintained near hot leg elevation (Figure 15.6.5.4B-41) throughout the remainder of the transient.
e the pressure in the broken DVI line falls below that in the IRWST, the water from the tank is ed to the containment.
ble, but decreasing, injection continues from the intact loop core makeup tank as the reactor lant system pressure declines slowly. The reactor coolant system pressure continues to fall until it ps below that of the IRWST and injection begins (Figure 15.6.5.4B-51). With the reduced initial S inventory recovery from the accumulators and only a single intact injection path available for the DVI line break, the minimum inventory occurs near the initiation of IRWST injection flow. After ction flow greater than the sum of the break and ADS flows exists, a slow rise in the reactor lant system inventory (Figure 15.6.5.4B-53) occurs. Since no core uncovery is predicted for this nario, no cladding heatup occurs.
critical heat flux assessment described in Subsection 15.6.5.4B.2.3 addresses core cooling ng a time period where the NOTRUMP computer code may not conservatively predict the core rage void fraction. The requirements of 10 CFR 50.46 are met during this period since this CHF essment indicates peak core heat flux is less than critical heat flux. Cladding temperatures will ain near the coolant saturation temperature, well below the 10 CFR 50.46 peak cladding perature limit.
ther DEDVI line break analysis is performed that is the same as the case discussed above ept that containment pressure is assumed to be at 14.7 psia. Table 15.6.5-13A provides the time uence of events for this analysis. Figures 15.6.5.4B-36A through 15.6.5.4B-55A provide the 15.6-37 Revision 1
6.5.4B.3.6 10-inch Cold Leg Break case models a 10-inch break occurring in the bottom of a cold leg connected to the balance line MT-1. The reactor steady-state initial conditions assumed for this transient are found in le 15.6.5-9. The event times for this transient are given in Table 15.6.5-14.
break opens at time zero, and the pressurizer pressure begins to fall, as shown in re 15.6.5.4B-56, as mass is lost out the break. The pressurizer mixture level initially decreases iven in Figure 15.6.5.4B-57. The break fluid flow is shown in Figures 15.6.5.4B-75 and
.5.4B-76 for the liquid and vapor components respectively. The pressurizer pressure falls below reactor trip set point. This causes the reactor to trip (after the appropriate time delay) and ation of the steam generator steam lines. The core makeup tank isolation valves on both delivery s and the PRHR delivery line isolation valve open after an S signal occurs (with appropriate ys); the reactor coolant pumps trip after an S with a 6.0-second delay. The reactor coolant em is cooled by natural circulation with energy being removed by the steam generator safety es, the core makeup tanks, and the PRHR heat exchanger. Once the core makeup tank isolation es open, the core makeup tanks begin to inject borated water into the reactor coolant system as wn in Figures 15.6.5.4B-61 and 15.6.5.4B-62.
ime proceeds, the loops drain to the reactor vessel. The mixture level in the downcomer begins to p as seen in Figure 15.6.5.4B-60, and the core remains completely covered. Due to the size and tion of the break involved, the accumulator setpoint is reached prior to the core makeup tanks sitioning from recirculation to injection mode. The flows from the core makeup tanks are shown in res 15.6.5.4B-61 and 15.6.5.4B-62, and from the accumulators, in Figures 15.6.5.4B-63 and
.5.4B-64. The response of core makeup tank 1 is offset compared to that of core makeup tank 2 result of the break size/location being modeled. Core makeup tank 2 reaches the 67.5-percent l first, and after an appropriate delay, the ADS Stage 1 valves open. When the ADS is actuated, mixture level increases in the pressurizer (Figure 15.6.5.4B-57) because an opening has been ted at the top of the pressurizer. After these valves open, a more rapid depressurization occurs een in Figure 15.6.5.4B-56.
ing the initial portion of the 10-inch break, both liquid and steam flow out the top of the core ures 15.6.5.4B-71 and 15.6.5.4B-72) as the void fraction in the core increases ure 15.6.5.4B-73). The break in the cold leg draws fluid from the bottom of the core, and fficient liquid remains in the core and upper plenum to sustain the mixture level. The mixture l, therefore, starts to decrease (Figure 15.6.5.4B-69). The mixture level falls to a minimum and starts to recover as accumulator flows enter the downcomer (Figures 15.6.5.4B-63 and
.5.4B-64). During this time period (~75-125 seconds), a portion of the core exhibits the potential ore dryout to occur without the prediction of a traditional core uncovery period (for example, core
-phase mixture level dropping into the active fuel region). To conservatively account for this ntial core dryout period, a composite core mixture level was created which collapses to the imum of the actual core/upper plenum two-phase mixture level and the bottom of the lowest core e that exceeds the core dryout onset conditions. A 90-percent quality limit was chosen as the cator of the onset of core dryout indicative of the critical heat flux (as predicted by Griffiths ification of the Zuber equation, in References 28 and 29); dryout is assumed at core qualities ve this value. The resulting composite core mixture level resulting from this approach can be n in Figure 15.6.5.4B-70. To conservatively estimate the effects of this dryout period, an adiabatic t-up calculation was performed, and the resulting peak cladding temperature is determined to be roximately 1370°F. Even under these conservative adiabatic heat-up assumptions, the AP1000 t design exhibits large margins to the 10 CFR 50.46 Appendix-K limits for the 10-inch break.
15.6-38 Revision 1
es maintains the depressurization rate as shown in Figure 15.6.5.4B-56. ADS Stage 3 valves sequently open. This increases the system venting capability. The ADS Stage 4 valves open n the core makeup tank water level is reduced to 20 percent. Figures 15.6.5.4B-67 and
.5.4B-74 indicate the instantaneous liquid and integrated total mass discharged from the ADS ge 4 valves. After the ADS Stage 4 path opens, the pressurizer begins to drain mixture into the hot as seen in Figure 15.6.5.4B-57. The Figure 15.6.5.4B-68 mass inventory plot considers the ary inventory to be the reactor coolant system proper, including the pressurizer; the mass ent in the passive safety system components is not included. Once the downcomer pressure ps below the IRWST injection pressure, flow enters the reactor vessel from the IRWST. The ure level in the reactor vessel is approximately at the hot leg elevation as shown in re 15.6.5.4B-69 throughout this transient; the core never uncovers, even though the period of ntial core dryout was predicted to occur during the initial blowdown period. Even when the core ut is conservatively accounted for, large margins to the 10 CFR 50.46 Appendix-K limits of 0°F exist.
6.5.4B.3.7 Direct Vessel Injection Line Break (Entrainment Sensitivity) rder to assess the potential impact of higher than expected entrainment in the upper plenum and legs on the overall system response and core cooling, an AP1000 plant sensitivity run was ormed. The sensitivity case was performed with the DEDVI line break simulation as described in following. The simulation utilizes the same initial conditions as the base DEDVI line simulation ented in Subsection 15.6.5.4B.3.5. The transient response is essentially identical until ADS-4 ation, at which time the higher than expected entrainment is included in the analysis by assuming ogenous conditions in the regions downstream of the core. In addition, since homogenous tment of these regions will eliminate the pressure drop effect of the accumulated mass stored in upper plenum, the NOTRUMP model was conservatively adjusted to account for this effect wing the transition of the ADS-4 flow paths to noncritical conditions.
re 15.6.5.4B-79 presents a comparison of the upper downcomer pressure between the base and sitivity cases. The sensitivity case results in higher upper downcomer pressure and subsequently lts in delayed IRWST injection (Figure 15.6.5.4B-80). This can also be observed in the intact DVI flow, which comprises all intact injection flow components (that is, accumulator, CMT, and ST) per Figure 15.6.5.4B-81, and the pressurizer mixture level response (Figure 15.6.5.4B-90),
ch follows the change in pressure response. As expected, the initial ADS-4 liquid discharge is h higher (Figure 15.6.5.4B-82) until the inventory, which resided in the upper plenum and hot leg ons, depletes (Figure 15.6.5.4B-83). The net effect is a decrease in the ADS-4 vapor discharge (Figure 15.6.5.4B-84) and subsequently higher RCS pressures.
to the elimination of the inventory stored in the upper plenum, the downcomer mass is also uced (Figure 15.6.5.4B-85). Since the static head that existed in the upper plenum is eliminated n the model is made homogenous, the downcomer mixture is subsequently driven into the core he static heads equilibrate. This results in the core region mass increasing initially due to the duction of cold downcomer fluid to the core region (Figure 15.6.5.4B-86). The net effect of the sitivity case is that the vessel inventory is substantially decreased over the base model simulation ure 15.6.5.4B-87); however, this inventory is sufficient to provide adequate core cooling because ADS-4 continually draws liquid flow through the core (Figure 15.6.5.4B-82). Even though there is iquid storage in the upper plenum for the homogenous case (Figure 15.6.5.4B-88), the core apsed liquid level (Figure 15.6.5.4B-89) is not impacted significantly.
sensitivity demonstrates that the AP1000 plant response is relatively insensitive to upper um and hot leg entrainment. Even with the assumption of homogenous fluid nodes above the 15.6-39 Revision 1
6.5.4B.4 Conclusions small-break LOCA analyses performed show that the performance of the AP1000 plant design to ll-break LOCA scenarios is excellent and that the passive safeguards systems in the AP1000 are cient to mitigate LOCAs. Specifically, it is concluded that:
The primary side can be depressurized by the ADS to allow stable injection into the core.
Injection from the core makeup tanks, accumulators, and IRWST prevents excessive cladding heatup for small-break LOCAs analyzed, including double-ended ruptures in the passive safeguards system lines. The peak AP1000 heat flux during the accumulator injection period is below the predicted critical heat flux.
The effect of increasing upper plenum/hot leg entrainment does not significantly affect plant safety margins.
analyses performed demonstrate that the 10 CFR 50.46 Acceptance Criteria are met by the 000. Summarizing the small-break LOCA spectrum:
AP1000 Minimum RCS Inventory Peak Cladding Break Location/Diameter (lbm) Temperature Inadvertent ADS 105,800 (1) 2-inch cold leg break 106,620 (1) 10-inch cold leg break 78,160 <1370°F DEDVI 113,710 (1)
DEDVI (Entrainment Study) ~82,000 (1)
(1) There is no core heatup as a result of this transient. PCT occurs at transient initiation 10-inch cold leg break exhibits the limiting minimum inventory condition that occurs during the al blowdown period and is terminated by accumulator injection. The AP1000 design is such that minimum inventory occurs just prior to IRWST injection for all breaks except the 10-inch cold leg ak. All breaks simulated in the break spectrum produce results that demonstrate significant gin to peak cladding temperature regulatory limits.
6.5.4C Post-LOCA Long-Term Cooling 6.5.4C.1 Long-Term Cooling Analysis Methodology AP1000 safety-related systems are designed to provide adequate cooling of the reactor finitely. Initially, this is achieved by discharging water from the IRWST into the vessel. When the 3 level setpoint is reached in the IRWST, the containment recirculation subsystem isolation es open and water from the containment reactor coolant system (RCS) compartment can flow the vessel through the PXS piping. The water in containment rises in temperature toward the ration temperature. Long-term heat removal from the reactor and containment is by heat transfer ugh the containment shell to atmosphere.
purpose of the long-term cooling analysis is to demonstrate that the passive systems provide quate emergency core cooling system performance during the IRWST injection/containment 15.6-40 Revision 1
AP1000 long-term cooling analysis is supported by the series of tests at the Oregon State versity AP600 APEX Test Facility. This test facility is designed to represent the AP600 reactor ty-related systems and nonsafety-related systems at quarter-scale during long-term cooling. The obtained during testing at this facility has been shown to apply to the AP1000 (Reference 25).
se tests were modeled using WCOBRA/TRAC with an equivalent noding scheme to that used for 00 (Reference 17) in order to validate the code for long-term cooling analysis.
erence 24 provides details of the AP1000 WCOBRA/TRAC modeling. The coarse reactor vessel eling used for AP600 has been replaced with a detailed noding like that applied in the large-ak LOCA analyses described in Subsection 15.6.5.4A. The reactor vessel noding used in the 000 long-term cooling analyses in core and upper plenum regions is equivalent to that used in scale test simulations (see Reference 24).
EDVI line break is analyzed because it is the most limiting long-term cooling case in the tionship between decay power and available liquid driving head. Because the IRWST spills ctly onto the containment floor in a DEDVI break, this event has the highest core decay power n the transfer to sump injection is initiated. In postulated DEDVI break cases, the compartment er level exceeds the elevation at which the DVI line enters the reactor vessel, so water can flow the containment into the reactor vessel through the broken DVI line; this in-flow of water through broken DVI line assists in the heat removal from the core. The steam produced by boiling in the vents to the containment through the ADS valves and condenses on the inner surface of the l containment vessel. The condensate is collected and drains to the IRWST to become available njection into the reactor coolant system. The WCOBRA/TRAC analysis presented analyzes the DVI small-break LOCA event from a time (3000 seconds) at which IRWST injection is fully blished to beyond the time of containment recirculation. During this time, the head of water to e the flow into the vessel for IRWST injection decreases from the initial level to its lowest value at containment recirculation switchover time. PXS Room B is the location of the break in the DVI At this break location, liquid level in containment at the time of recirculation is a minimum.
ntinuous analysis of the post-LOCA long term cooling is provided from the time of stable IRWST ction through the time of sump recirculation for the DEDVI break. Maximum design resistances applied in WCOBRA/TRAC for both the ADS Stage 4 flow paths and the IRWST injection and tainment recirculation flow paths.
break modeled is a double-ended guillotine rupture of one of the direct vessel injection lines. The
-term cooling phase begins after the simultaneous opening of the isolation valves in the IRWST lines and the opening of ADS Stage 4 squib valves, when flow injection from the IRWST has n fully established. Initial conditions are taken from the NOTRUMP DEDVI case at 20 psia tainment pressure reported in Subsection 15.6.5.4B.
6.5.4C.2 DEDVI Line Break with ADS Stage 4 Single Failure, Passive Core Cooling System Only Case; Continuous Case subsection presents the results of a DEDVI line break analysis during IRWST injection phase tinuing into sump recirculation. Initial conditions at the start of the case are prescribed based on NOTRUMP DEDVI break results to allow a calculation to begin shortly after IRWST injection ins in the small break long-term cooling transient. The WCOBRA/TRAC calculation is then wed to proceed until a quasi-steady-state is achieved. At this time, the predicted results are pendent of the assumed initial conditions. This calculation uses boundary conditions taken from GOTHIC analysis of this event. During the calculation, which is carried out for 10,000 seconds 15.6-41 Revision 1
e analysis, one of the two ADS Stage 4 valves in the PRHR loop is assumed to have failed. The al reactor coolant system liquid inventory and temperatures are determined from the NOTRUMP ulation. The core makeup tanks do not contribute to the DVI injection during this phase of the sient. Steam generator secondary side conditions are taken from the NOTRUMP calculation (at beginning of long-term cooling). The reactor coolant pumps are tripped and not rotating.
levels and temperatures of the liquid in the containment sump and the containment pressure are ed on WGOTHIC calculations of the conservative minimum pressure during this long-term ling transient, including operation of the containment fan coolers. Small changes in the RCS partment level do not have a major effect on the predicted core collapsed liquid level or on the dicted flow rate through the core. The minimum compartment floodup level for this break scenario 07.8 feet or greater.
is transient, the IRWST provides a hydraulic head sufficient to drive water into the downcomer ugh the intact DVI nozzle. Also, water flows into the downcomer from the broken DVI line once liquid level in the compartment with the broken line is adequate to support flow. The water flows n the downcomer and up through the core, into the upper plenum. Steam produced in the core liquid flow out of the reactor coolant system via the ADS Stage 4 valves. There is little flow out of S Stages 1, 2, and 3 even when the IRWST liquid level falls below the sparger elevation, so they not modeled in this calculation. The venting provided by the ADS-4 paths enables the liquid flow ugh the core to maintain core cooling.
roximately 500 seconds of WCOBRA/TRAC calculation are required to establish the quasi-dy-state condition associated with IRWST injection at the start of long-term cooling and so are red in the following discussion. The hot leg levels are such that during the IRWST injection phase quality of the ADS Stage 4 mass flows varies as water is carried out of the hot legs. This odically increases the pressure drop across the ADS Stage 4 valves and the upper plenum sure. The higher pressure in the upper plenum reduces the injection flow. This cycle of pressure ations due to changing void fractions in the flow through ADS Stage 4 is consistent with test ervations and is expected to recur often during long-term cooling.
head of water in the IRWST causes a flow of subcooled water into the downcomer at an roximate rate of 170 lbm/s through the intact DVI nozzle at the start of long-term cooling. The ncomer level at the end of the code initiation (the start of long-term cooling) is about 18.0 feet ure 15.6.5.4C-1). Note that the time scale of this and other figures in Subsection 15.6.5.4C.2 is et by 2500 seconds; that is, a time of 500 seconds on the Figure 15.6.5.4C-1 axis equals 0 seconds transient time for the DEDVI break. All of the injection water flows down the ncomer and up through the core. The accumulators have been fully discharged before the start e time window and do not contribute to the DVI flow.
ing in the core produces steam and a two-phase mixture, which flows into the upper plenum. The is 14 feet high, and the core average collapsed liquid level (Figure 15.6.5.4C-2) is shown from start of long-term cooling. The boiling process causes a variable rate of steam production and lting pressure changes, which in turn causes oscillations in the liquid flow rate at the bottom of core and also variations in the core collapsed level and the flow rates of liquid and vapor out of top of the core. In the WCOBRA/TRAC noding, the core is divided both axially and radially as cribed in Reference 24. The void fractions in the top two cells of the hot assembly are shown as res 15.6.5.4C-3 and 15.6.5.4C-4. The average void fraction of these upper core cells is about 0.8 ng long-term cooling, during IRWST injection, and into the containment recirculation period.
re is a continuous flow of two-phase fluid into the hot legs, and mainly vapor flow toward the ADS ge 4 valve occurs at the top of the pipe. The collapsed liquid level in the hot leg varies between 15.6-42 Revision 1
S stage 4 mass flowrates.
pressure in the upper plenum is shown in Figure 15.6.5.4C-11. The upper plenum pressure uation that occurs is due to the ADS Stage 4 water discharge. The PCT of the hot rod follows ration temperature (Figure 15.6.5.4C-12), which demonstrates that no uncovery and no cladding perature excursion occurs. A small pressure drop is calculated across the reactor vessel, and ction rates through the DVI lines into the vessel are presented in Figures 15.6.5.4C-13 and
.5.4C-14. Figure 15.6.5.4C-14 shows the flow is outward through the broken DVI line at the start e long-term cooling period, and it increases to a maximum average value of about 52 lbm/s after compartment water level has increased above the nozzle elevation to permit liquid injection into reactor vessel. In contrast, the intact DVI line flow falls from 170 lbm/s with a full IRWST to about bm/s flow from the containment at the end of the calculation. The recirculation core liquid ughput is more than adequate to preclude any boron buildup on the fuel.
res 15.6.5.4C-1A through 15.6.5.4C-14A present the sensitivity of long-term cooling ormance to a bounding containment pressure of 14.7 psia. The DEDVI break in the PXS Room case is restarted at 6500 seconds to assess in a window mode calculation the effect of this uced containment pressure at the most limiting time in the transient, the switchover to tainment recirculation. The initial 700 seconds of the window establish the reactor vessel sure condition that is consistent with the 14.7 psia containment pressure. After 7200 seconds, WCOBRA/TRAC calculation provides the transient behavior of the AP1000 at the reduced tainment pressure.
6.5.4C.3 DEDVI Break and Wall-to-Wall Floodup; Containment Recirculation subsection presents a DEDVI line break analysis with wall-to-wall flooding due to leakage ween compartments, using the window mode methodology. All containment free volume beneath level of the liquid is assumed filled in this calculation to generate the minimum water level dition during containment recirculation. The time identified for this calculation is 14 days into the nt, and the core power is calculated accordingly. The initial conditions at the start of the window consistent with the analysis described in Subsection 15.6.5.4C.2. Containment recirculation is ulated during the time window. The calculation is carried out over a time period long enough to blish a quasi-steady-state solution; after 400 seconds of problem time, the flow dynamics are si-steady-state and the predicted results are independent of the assumed initial conditions. The d level is simulated constant at 28.2 feet above the bottom inside surface of the reactor vessel er to Figure 15.0.3-2 for AP1000 reference plant elevations) during the time window, and the d temperatures in the containment sump and the PXS B room are 196°F and 182°F, ectively. The containment pressure is conservatively assumed to be 14.7 psia. The single failure n ADS Stage 4 flow path is assumed as in the Subsection 15.6.5.4C.2 case.
using on the post 400-second time interval of this case, the containment liquid provides a raulic head sufficient to drive water into the downcomer through the DVI nozzles. The water duced into the downcomer flows down the downcomer and up through the core, into the upper um. Steam produced in the core entrains liquid and flows out of the reactor coolant system via ADS Stage 4 valves. The DVI flow and the venting provided by the ADS paths provide a liquid through the core that enables the core to remain cool.
downcomer collapsed liquid level (Figure 15.6.5.4C-15) varies between 23 and 25 feet during analysis. Pressure spikes produced by boiling in the core can cause the mass flow of the DVI flow s shown in Figures 15.6.5.4C-27 and 15.6.5.4C-28 into the vessel to fluctuate upward and nward.
15.6-43 Revision 1
ch in turn, cause variations in the core collapsed level and the flow rates of liquid and vapor out of top of the core. In the WCOBRA/TRAC analysis, the core is nodalized as described in erence 24. The void fraction in the top cell is shown in Figure 15.6.5.4C-17 for the core hot embly, and Figure 15.6.5.4C-18 shows the void fraction that exists one cell further down in the hot embly. The PCT does not rise appreciably above the saturation temperature ure 15.6.5.4C.3-26). The flow through the core and out of the reactor coolant system is more than cient to provide adequate flushing to preclude concentration of the boric acid solution. Liquid ects above the upper core plate in the upper plenum, where the average collapsed liquid level is ut 3.6 feet (Figure 15.6.5.4C-22). There is no significant flow through the cold legs into either the en or the intact loops, and there is no significant quantity of liquid residing in any of the cold legs.
pressure in the upper plenum is shown in Figure 15.6.5.4C-25. The upper plenum surization, which occurs periodically, is due to the ADS Stage 4 water discharge. The collapsed d level in the hot leg of the pressurizer loop varies between 1.0 feet and 2.1 feet, as shown in re 15.6.5.4C-19. Injection rates through the DVI lines into the vessel are presented in res 15.6.5.4C-27 and 15.6.5.4C-28.
6.5.4C.4 Post Accident Core Boron Concentration evaluation has been performed of the potential for the boron concentration to build up in the core wing a cold leg LOCA. The evaluation methodology, simplified calculations, and their results are ussed in Reference 24. This evaluation considers both short-term operations, before ADS is ated, and long-term operations, after ADS is actuated. These evaluations and their results are ussed in the follow paragraphs.
rt-term - Prior to ADS actuation, it is not likely for boron to build up significantly in the core.
mally, water circulation mixes boron in the RCS and prevents buildup in the core. In order for on to start to build up in the core region, water circulation through the steam generators and HR HX has to stop. In addition, significant injection of borated water is needed from the CMTs and CVS. For this situation to happen, the hot legs need to void sufficiently to allow the steam erator tubes to drain. Once the steam generator tubes void, the cold legs will also void since they located higher than the hot legs. When the top of the cold legs void, the CMTs will begin to drain.
en the CMTs drain to the ADS stage 1 setpoint, ADS is actuated.
rt-term Results - As shown in Subsection 15.6.5.4B.3.4, a 2-inch LOCA requires less than minutes from the time that the hot legs void significantly until ADS is actuated. For larger LOCAs, time difference is shorter, as seen for the 10-inch cold leg LOCA (Subsection 15.6.5.4B.3.6). The boron concentration will not build up significantly in this short time. If the break is smaller than ches, voiding of the hot legs will occur at a later time. With maximum operation of CVS makeup, it s more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> for the core boron concentration to build up significantly. In addition, the me of the boric acid tank limits the maximum buildup of boron in the core.
owing a small LOCA where ADS is not actuated, the operators are guided to sample the RCS on concentration and to initiate a post-LOCA cooldown and depressurization. The cooldown and ressurization of the RCS reduces the leak rate and facilitates recovery of the pressurizer level.
overy of the pressurizer level allows for re-establishment of water flow through the RCS loops, ch mixes the boron. The operators are guided to take an RCS boron sample within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of the dent and several more during the plant cooldown. The purpose of the boron samples is to assess there is adequate shutdown margin and that the RCS boron concentration has not built up to essive levels. The maximum calculated core boron concentration 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after a LOCA without S actuation is less than 16,000 ppm. Operator action within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> maintains the maximum core 15.6-44 Revision 1
g-term - Once ADS is actuated, water carryover out the ADS Stage 4 lines limits the potential boron concentration buildup following a cold leg LOCA. The design of the AP1000 facilitates er discharge from the hot legs as follows:
PXS recirculation flow capability tends to fill the hot legs and bring the water level up to the ADS Stage 4 inlet.
ADS Stage 4 lines discharge at an elevation 3 to 4 feet above the containment water level.
h water carried out ADS Stage 4, the core boron concentration increases until the boron added to core in the safety injection flow equals the boron removed in the water leaving the RCS through ADS Stage 4 flow. The lower the ADS Stage 4 vent quality, the lower the core boron concentration dup.
g-term Results - Analyses have been performed (Reference 24) to bound the maximum core on concentration buildup. These analyses demonstrate that highest ADS Stage 4 vent qualities lt from the following:
Highest decay heat levels Lowest PXS injection/ADS 4 vent flows, including high line resistances and low containment water levels long-term cooling analysis discussed in Subsection 15.6.5.4C.2 is consistent with these umptions. The ADS Stage 4 vent quality resulting from this analysis is less than 40 percent at the inning of IRWST injection and reaches a maximum of less than 50 percent around the initiation of rculation. It decreases after this peak, dropping to a value less than 8 percent at 14 days.
h the maximum ADS Stage 4 vent qualities, the maximum core boron concentration peaks at a e of about 7400 ppm at the time of recirculation initiation. After this time, the core boron centration decreases as the ADS Stage 4 vent quality decreases, reaching 5000 ppm about urs after the accident. The core boron solubility temperature reaches a maximum of 58°F (at 0 ppm) and quickly drops to 40°F (at 5000 ppm). With these low core boron solubility peratures, there is no concern with cold PXS injection water causing boron precipitation in the
. With the IRWST located inside containment, its water temperature is normally expected to be ve these solubility temperatures. The minimum core inlet temperature is greater than the bility temperature considering heatup of the injection by steam condensation in the downcomer pickup of sensible heat from the reactor vessel, core barrel, and lower support plate.
boron concentration water in the containment is initially about 2980 ppm. As the core boron centration increases, the containment concentration decreases slightly. The minimum boron centration in containment is greater than 2950 ppm. The solubility temperature of the containment er at its maximum boron concentration is 32°F.
h high decay heat values, the ADS Stage 4 vent flows and velocities are high. These high vent cities result in flow regimes that are annular for more than 30 days. The annular flow regime es water up and out the ADS Stage 4 lines. This flow regime is based on the Taitel-Dukler vertical regime map. Lower decay heat levels can be postulated later in time or just after a refueling ge. Significantly lower decay heat levels result in lower ADS Stage 4 vent qualities. They also lt in ADS Stage 4 vent flows/velocities that are lower. Even with low ADS Stage 4 vent flow cities, the AP1000 plant will move water out the ADS Stage 4 operating as a manometer. Small 15.6-45 Revision 1
he time recirculation begins, the containment level will be about 109.3 feet (for a non-DVI LOCA) will be about 108.0 feet (for a DVI LOCA). Over a period of weeks after a LOCA, water may ly leak from the flooded areas in containment to other areas inside containment that did not ally flood. As a result, the minimum containment water could decrease to 103.5 feet. During rculation operation following a LOCA and ADS actuation, the operators are guided to maintain the tainment water level above the 107-foot elevation by adding borated water to the containment. In ition, if the plant continues to operate in the recirculation mode, the operators are guided to ease the level to 109 feet within 30 days of the accident. These actions provide additional margin ater flow through the ADS Stage 4 line. The operators are also guided to sample the hot leg on concentration prior to initiating recovery actions that might introduce low temperature water to reactor.
6.5.4C.5 Conclusions culations of AP1000 long-term cooling performance have been performed using the WCOBRA/
C model developed for AP1000 and described in Reference 24. The DEDVI case was chosen ause it reaches sump recirculation at the earliest time (and highest decay heat). A window mode e at the minimum containment water level postulated to occur 2 weeks into long-term cooling was performed.
DEDVI small-break LOCA exhibits no core uncovery due to its adequate reactor coolant system s inventory condition during the long-term cooling phase from initiation into containment rculation. Adequate flow through the core is provided to maintain a low cladding temperature and revent any buildup of boric acid on the fuel rods. The wall-to-wall floodup case using the window e technique demonstrates that effective core cooling is also provided at the minimum tainment water level. The results of these cases demonstrate the capability of the AP1000 sive systems to provide long-term cooling for a limiting LOCA event.
6.6 References 10 CFR 50.46, Acceptance Criteria for Emergency Core Cooling Systems for Light Water Cooled Nuclear Power Reactors, and Appendix K to 10 CFR 50, ECCS Evaluation Models.
American Nuclear Society Proposed Standard, ANS 5.1 Decay Energy Release Rates Following Shutdown of Uranium-Cooled Thermal Reactors, October (1971), Revised October (1973).
Final Safety Evaluation Report Related to Certification of the AP600 Standard Design, NUREG-1512, September 1998.
Not used.
Emergency Core Cooling Systems; Revision to Acceptance Criteria, Federal Register, Vol. 53, No. 180, September 16, 1988.
Not used.
AP600 Design Control Document, Revision 3, December 1999.
15.6-46 Revision 1
Not used.
Bajorek, S. M., et al., Code Qualification Document for Best-Estimate LOCA Analysis, WCAP-12945-P-A, Volume 1, Revision 2, and Volumes 2 through 5, Revision 1, and WCAP-14747 (Non-Proprietary), 1998.
Hochreiter, L. E., et al., WCOBRA/TRAC Applicability to AP600 Large-Break Loss-of-Coolant Accident, WCAP-14171, Revision 2 (Proprietary) and WCAP-14172, Revision 2 (Nonproprietary), March 1998.
Meyer, P. E., NOTRUMP - A Nodal Transient Small-Break and General Network Code, WCAP-10079-P-A (Proprietary) and WCAP-10080-A (Nonproprietary), August 1985.
Lee, N., Rupprecht, S. D., Schwarz, W. R., and Tauche, W. D., Westinghouse Small-Break ECCS Evaluation Model Using the NOTRUMP Code, WCAP-10054-P-A (Proprietary) and WCAP-10081-A (Nonproprietary), August 1985.
Carlin, E. L., Bachrach, U., LOFTRAN & LOFTTR2 AP600 Code Applicability Document, WCAP-14234, Revision 1 (Proprietary) and WCAP-14235, Revision 1 (Nonproprietary), August 1997.
Burnett, T. W. T., et al., LOFTRAN Code Description, WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984.
Friedland, A. J., Ray S., Revised Thermal Design Procedure, WCAP-11397-P-A (Proprietary) and WCAP-11397-A (Nonproprietary), April 1989.
Kemper, R. M., AP600 Accident Analyses B Evaluation Models, WCAP-14601, Revision 2 (Proprietary) and WCAP-15062, Revision 2 (Nonproprietary), May 1998.
Hargrove, H. G., FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO2 Fuel Rod, WCAP-7908-A, December 1989.
Soffer, L., et al., NUREG-1465, Accident source Terms for Light-Water Nuclear Power Plants, February 1995.
Regulatory Guide 1.183, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors, July 2000.
Lewis, R. N., et al., SGTR Analysis Methodology to Determine the Margin to Steam Generator Overfill, WCAP-10698-P-A (Proprietary) and WCAP-10750-A (Nonproprietary), August 1987.
NOTRUMP Final Validation Report for AP600, WCAP-14807, Revision 5 (Proprietary) and WCAP-14808, Revision 2 (Nonproprietary), August 1998.
Garner, D. C., et al., WCOBRA/TRAC OSU Long-Term Cooling Final Validation Report, WCAP-14776, Revision 4 (Proprietary) and WCAP-14777, Revision 4 (Nonproprietary),
April 1998.
15.6-47 Revision 1
AP1000 PIRT and Scaling Assessment, WCAP-15613 (Proprietary) and WCAP-15706 (Nonproprietary), February 2001.
Kemper, R. M., Applicability of the NOTRUMP Computer Code to AP600 SSAR Small-Break LOCA Analyses, WCAP-14206 (Proprietary) and WCAP-14207 (Nonproprietary),
November 1994.
Not used.
Zuber, et al., The Hydrodynamic Crisis in Pool Boiling of Saturated and Subcooled Liquids, Part II, No. 27, International Developments in Heat Transfer, 1961.
Griffith, et al., PWR Blowdown Heat Transfer, Thermal and Hydraulic Aspects of Nuclear Reactor Safety, ASME, New York, Volume 1, 1977.
Chang, S. H. et al. A study of critical heat flux for low flow of water in vertical round tubes under low pressure, Nuclear Engineering and Design, 132, 225-237, 1991.
Not used.
Nissley, M. E., et al., 2005, Realistic Large Break LOCA Evaluation Methodology Using the Automated Statistical Treatment of Uncertainty Method (ASTRUM),
WCAP-16009-P-A and WCAP-16009-NP-A (Non-proprietary).
Dederer, S. I., et al., 1999, Application of Best Estimate Large Break LOCA Methodology to Westinghouse PWRs with Upper Plenum Injection, WCAP-14449-P-A, Revision 1 and WCAP-14450 (Non-proprietary).
APP-GW-GLE-026, Change to ASTRUM Methodology for Best Estimate Large Break Loss of Coolant Accident Analysis, Westinghouse Electric Company LLC.
Beahm, E. C. et al., NUREG/CR-5950, Iodine Evolution and pH Control, December 1992.
15.6-48 Revision 1
Decrease in Reactor Coolant Inventory Time Accident Event (seconds) vertent opening of a Pressurizer safety valve opens fully 0.0 ssurizer safety valve with offsite Overtemperature T reactor trip setpoint reached 18.55 er available Rods begin to drop 20.55 Minimum DNBR occurs 21.3 vertent opening of a Pressurizer safety valve opens fully 0.0 ssurizer safety valve without Overtemperature T reactor trip setpoint reached 18.55 ite power available Turbine trip signal 20.23 Rods begin to drop 20.55 Minimum DNBR occurs 21.3 ac power lost, reactor coolant pumps begin 23.23 coasting down vertent opening of two ADS ADS valves begin to open 0.0 ge 1 trains with offsite power Overtemperature T reactor trip setpoint reached 18.40 ilable Rods begin to drop 20.40 Minimum DNBR occurs 21.30 ADS valves fully open 25.0 vertent opening of two ADS ADS valves begin to open 0.0 ge 1 trains without offsite power Overtemperature T reactor trip setpoint reached 18.40 ilable Turbine trip signal 20.1 Rods begin to drop 20.40 Minimum DNBR occurs 21.3 ac power lost, reactor coolant pumps begin 23.1 coasting down ADS valves fully open 25.0 15.6-49 Revision 1
Consequences of a Small Line Break Outside Containment actor coolant iodine activity Initial activity equal to the design basis reactor coolant activity of 1.0 Ci/g dose equivalent I-131 with an assumed iodine spike that increases the rate of iodine release from fuel into the coolant by a factor of 500 (see Table 15A-2 in Appendix 15A)(a) actor coolant noble gas activity 280 Ci/g dose equivalent Xe-133 ak flow rate (gpm) 130(b) ction of reactor coolant flashing 0.47 ration of accident (hr) 0.5 ospheric dispersion (/Q) factors See Table 15A-5 clide data See Table 15A-4 s:
Use of accident-initiated iodine spike is consistent with the guidance in the Standard Review Plan.
At density of 62.4 lb/ft3.
15.6-50 Revision 1
Time Events (seconds) ouble-ended steam generator tube rupture 0 ss of offsite power 0 eactor trip 0 eactor coolant pumps and main feedwater pumps assumed to trip and 0 gin to coastdown wo chemical and volume control pumps actuated and pressurizer heaters 0 rned on w-2 pressurizer level signal generated 2,498 uptured steam generator power-operated relief valve fails open 2,498 ore makeup tank injection and PRHR operation begins (following 2,515 aximum delay) uptured steam generator power-operated relief valve block valve closes 2,979 low steam line pressure signal hemical and volume control system isolated on high-2 steam generator 12,541 rrow range level setpoint eak flow terminated 24,100 15.6-51 Revision 1
Total Mass Flow from Initiation of Event to Cooldown to RNS(1) Conditions Start of Event to Break Flow Termination Break Flow Termination to Cut-in of RHR (Pounds Mass) (Pounds Mass) ptured steam generator Atmosphere 238,600 93,200 act steam generator Atmosphere 183,400 1,234,900 eak flow 385,000 0 RNS = normal residual heat removal 15.6-52 Revision 1
Consequences of a Steam Generator Tube Rupture ctor coolant iodine activity ccident initiated spike Initial activity equal to the equilibrium operating limit for reactor coolant activity of 1.0 Ci/g dose equivalent I-131 with an assumed iodine spike that increases the rate of iodine release from fuel into the coolant by a factor of 335 (see Appendix 15A). Duration of spike is 8.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />.
reaccident spike An assumed iodine spike that results in an increase in the reactor coolant activity to 60 Ci/g of dose equivalent I-131 (see Appendix 15A) ctor coolant noble gas activity 280 Ci/g dose equivalent Xe-133 ctor coolant alkali metal activity Design basis activity (see Table 11.1-2) ondary coolant initial iodine and alkali metal 1% of reactor coolant concentrations at maximum equilibrium conditions ctor coolant mass (lb) 3.7 E+05 ite power Lost on reactor trip denser Lost on reactor trip e of reactor trip Beginning of the accident ation of steam releases (hr) 15.94 ospheric dispersion factors See Appendix 15A lide data See Appendix 15A am generator in ruptured loop nitial secondary coolant mass (lb) 1.16 E+05 rimary-to-secondary break flow See Figure 15.6.3-5 ntegrated flashed break flow (lb) See Figure 15.6.3-10 team released (lb) See Table 15.6.3-2 odine partition coefficient 1.0 E-02(a) lkali metals partition coefficient 3.5 E-03(a) am generator in intact loop nitial secondary coolant mass (lb) 2.30 E+04 rimary-to-secondary leak rate (lb/hr) 52.16(b) team released (lb) See Table 15.6.3-2 odine partition coefficient 1.0 E-02(a) lkali metals partition coefficient 3.5 E-03(a) s:
Iodine partition coefficient does not apply to flashed break flow.
Equivalent to 150 gpd at psia cooled liquid at 62.4 lb/ft3.
15.6-53 Revision 1
Gap Release Core Melt Released over 0.5 hr. In-vessel Release Nuclide (0.167 - 0.667 hr)(1) (0.667 - 1.967 hr)(1)
Noble gases 0.05 0.95 Iodines 0.05 0.35 Alkali metals 0.05 0.25 Tellurium group - 0.05 Strontium and barium - 0.02 Noble metals group - 0.0025 Cerium group - 0.0005 Lanthanide group - 0.0002 s:
Releases are stated as fractions of the original core fission product inventory.
Dash (-) indicates not applicable.
15.6-54 Revision 1
Radiological Consequences of a Loss-of-Coolant Accident ary coolant source data Noble gas concentration 280 Ci/g dose equivalent Xe-133 Iodine concentration 1.0 Ci/g dose equivalent I-131 Primary coolant mass (lb) 4.39 E+05 tainment purge release data Containment purge flow rate (cfm) 16000 Time to isolate purge line (seconds) 30 Time to blow down the primary coolant system (minutes) 10 Fraction of primary coolant iodine that becomes airborne 1.0 e source data Core activity at shutdown See Table 15A-3 Release of core activity to containment atmosphere (timing and fractions) See Table 15.6.5-1 Iodine species distribution (%)
- Elemental 4.85
- Organic 0.15
- Particulate 95 tainment leakage release data Containment volume (ft3) 2.06 E+06 Containment leak rate, 0-24 hr (% per day) 0.10 Containment leak rate, > 24 hr (% per day) 0.05
-1) 1.9 Elemental iodine deposition removal coefficient (hr Decontamination factor limit for elemental iodine removal 200 Removal coefficient for particulates (hr-1) See Appendix 15B control room model Main control room volume (ft3) 3.89 E+04 Volume of HVAC, including main control room and control support area (ft3) 1.2 E+05 Normal HVAC operation (prior to switchover to an emergency mode)
- Air intake flow (cfm) 1650
- Filter efficiency Not applicable Atmospheric dispersion factors (sec/m3) See Table 15A-6 Occupancy 0 -24 hr 1.0 24-96 hr 0.6 96-720 hr 0.4 3/sec) 3.5 E-04 Breathing rate (m 15.6-55 Revision 1
trol room with emergency habitability system credited (VES Credited)
Main control room activity level at which the emergency habitability system 2.0 E-07 actuation is actuated (Ci/m3 of dose equivalent I-131)
Response time to actuate VES based on radiation monitor response time and 200 VBS isolation (sec)
Interval with operation of the emergency habitability system Flow from compressed air bottles of the emergency habitability system (cfm) 60 Unfiltered inleakage via ingress/egress (scfm) 5 Unfiltered inleakage from other sources (scfm) 10 Recirculation flow through filters (scfm) 600 Filter efficiency (%)
Elemental iodine 90 Organic iodine 90 Particulates 99 Time at which the compressed air supply of the emergency habitability system 72 is depleted (hr)
After depletion of emergency habitability system bottled air supply (>72 hr)
Air intake flow (cfm) 1900 Intake flow filter efficiency (%) Not applicable Recirculation flow (cfm) Not applicable Time at which the compressed air supply is restored and emergency 168 habitability system returns to operation (hr) trol room with credit for continued operation of HVAC (VBS plemental Filtration Mode Credited)
Time to switch from normal operation to the supplemental air filtration mode 265 (sec)
Unfiltered air inleakage (cfm) 25 Filtered air intake flow (cfm) 860 Filtered air recirculation flow (cfm) 2740 Filter efficiency (%)
Elemental iodine 90 Organic iodine 90 Particulates 99 ellaneous assumptions and parameters Offsite power Not applicable Atmospheric dispersion factors (offsite) See Table 15A-5 Nuclide dose conversion factors See Table 15A-4 Nuclide decay constants See Table 15A-4 3/sec)
Offsite breathing rate (m 0-8 hr 3.5 E-04 8-24 hr 1.8 E-04 24-720 hr 2.3 E-04 15.6-56 Revision 1
Loss-of-Coolant Accident With Core Melt TEDE Dose (rem)
(1) 23.5 lusion zone boundary dose (1.3 - 3.3 hr) population zone boundary dose (0 - 30 days) 22.2 n control room dose (emergency habitability system in operation)
Airborne activity entering the main control room 3.70 Direct radiation from adjacent structures, including sky shine 0.30 Filter shine 0.32 Spent fuel pooling boiling 0.01 Total 4.33 n control room dose (normal HVAC operating in the supplemental filtration mode)
Airborne activity entering the main control room 4.50 Direct radiation from adjacent structures, including sky shine 0.30 Filter shine 0.03 Spent fuel pooling boiling 0.01 Total 4.84 This is the 2-hour period having the highest dose.
15.6-57 Revision 1
Used in the Best-Estimate Large-Break LOCA Analysis Parameter Value t Physical Configuration m generator tube plugging level 10%
(10% tube plugging bounds 0%)
assembly location Under support column (Bounds under open hole or guide tube) surizer location In intact loop (Bounds location in broken loop) al Operating Conditions ctor power Core power < 1.01*3400 MWt k linear heat rate FQ 2.6 rod assembly power FH 1.75 assembly power PHA 1.683 (1) See Figure 15.6.5.4A-13 l power distribution pheral assembly power 0.2 PLOW 0.8 d Conditions ctor coolant system average temperature 573.6 - 7.5°F TAVG 573.6 + 7.5°F surizer pressure 2250 +/- 50 psia surizer level (water volume) 1000 ft3 (nominal) mulator temperature 50°F TACC 120°F mulator pressure 651.7 psia PACC 783.7 psia mulator water volume 1667 ft3 VACC 1732 ft3 ctor Coolant System Boundary Conditions le failure assumption Failure of one CMT isolation valve to open te power availability Available (Bounds loss of offsite power at time zero) ctor coolant pump automatic trip delay time after 4s iving S-signal tainment pressure Bounded (minimum)
Treatment of axial power distribution consistent with WCAP-16009-P-A (Reference 32) methodology.
15.6-58 Revision 1
15.6-59 Revision 1 Time Event (seconds) ak initiation 0.0 eguards signal 2.2 T isolation valves begin to open 4.2 ctor coolant pumps trip 8.2 umulator injection begins 18 of blowdown 34.5 om of core recovery 54.0 culated PCT occurs ~65 e quench occurs ~115 T injection resumes ~150 of transient 231 15.6-60 Revision 1
Not Used 15.6-61 Revision 1
10 CFR 50.46 Requirement Value Criteria th lculated 95 percentile PCT (°F) 1837 2200 ximum local cladding oxidation (%) 2.25 17 ximum core-wide cladding oxidation (%) 0.2 1 olable geometry Core remains coolable Core remains coolable ng-term cooling Core remains cool in long Core remains cool in long term term 15.6-62 Revision 1
Nominal Condition Calculation Steady-state essurizer pressure (psia) 2303.1 2300 ssel inlet temperature (°F) 534.03 534.3 ssel outlet temperature (°F) 612.83 612.9 ssel flow rate (lb/sec) 31086 31089 am generator pressure (psia) 806.5 788.5 15.6-63 Revision 1
Minimum Actuation Signal Valve Flow Valve (percentage of core makeup Actuation Time Area (for each Number of Opening Time tank level) (seconds) path, in2) Paths (seconds) ge 1 Control 67.5 32 after 4.6 2 out of 2 40 Low 1 CMT-Low 1 ge 2 Control 48 after Stage 1 21 2 out of 2 100 ge 3 Control 120 after Stage 2 21 2 out of 2 100 (2) 67 1 out of 2 4(3) ge 4A 20 128 after Stage 3 ge 4B 60 after Stage 4A 67 2 out of 2 4(3) es:
The valve stroke times reflect the design basis of the AP1000. The applicable Chapter 15 accidents were evaluated for the design basis valve stroke times. The results of this evaluation have shown that there is a small impact on the analysis and the conclusions remain valid. The output provided for the analyses is representative of the transient phenomenon.
The interlock requires coincidence of CMT Low-2 level as well as 128 seconds after the Stage 3 actuation signal is generated.
This includes arm-fire processing delay and the assumed valve opening time.
15.6-64 Revision 1
AP1000 Time Event (seconds) advertent opening of ADS valves 0.0 eactor trip signal 37.8 eam turbine stop valves close 43.8 signal 44.1 ain feed isolation valves begin to close 49.1 eactor coolant pumps start to coast down 50.1 DS Stage 2 70.0 DS Stage 3 190.0 cumulator injection starts 268 cumulator empties 693 DS Stage 4 1746 ore makeup tank empty 2112 WST injection starts 2663 15.6-65 Revision 1
AP1000 Time Event (seconds) eak opens 0.0 actor trip signal 54.7 eam turbine stop valves close 60.7 signal 61.9 ain feed isolation valves begin to close 63.9 actor coolant pumps start to coast down 67.9 S Stage 1 1334.1 S Stage 2 1404.1 cumulator injection starts 1405 S Stage 3 1524.1 cumulator empties 1940.2 S Stage 4 2418.6 re makeup tank empty 2895 WST injection starts 3280 15.6-66 Revision 1
AP1000 Time Event (seconds) ak opens 0.0 actor trip signal 13.1 am turbine stop valves close 19.1 signal 18.6 in feed isolation valves begin to close 20.6 actor coolant pumps start to coast down 24.6 S Stage 1 182.5 S Stage 2 252.5 ct accumulator injection starts 254 S Stage 3 372.5 S Stage 4 492.5 ct accumulator empties 600.0 ct loop IRWST injection starts* 1470 ct loop core makeup tank empties 2123 Continuous injection period 15.6-67 Revision 1
AP1000 Time Event (seconds) ak opens 0.0 actor trip signal 13.1 am turbine stop valves close 19.1 signal 18.5 in feed isolation valves begin to close 20.5 actor coolant pumps start to coast down 24.5 S Stage 1 182.7 ct accumulator injection starts 251 S Stage 2 252.7 S Stage 3 372.7 S Stage 4 492.7 ct accumulator empties 598.4 ct loop core makeup tank empties 2006 ct loop IRWST injection starts* 2076 Continuous injection period 15.6-68 Revision 1
AP1000 Time Event (seconds) eak opens 0.0 actor trip signal 5.2 signal 6.4 in feed isolation valves begin to close 8.4 eam turbine stop valves close 11.2 actor coolant pumps start to coast down 12.4 cumulator injection starts 85.
cumulator 1 empties 418.2 cumulator 2 empties 425.5 S Stage 1 750.0 S Stage 2 820.
S Stage 3 940.
S Stage 4 1491.
re makeup tank 2 empty 1800.*
WST injection starts ~1800 re makeup tank 1 empty 1900.*
The CMTs never truly empty although they cease to discharge at these times.
15.6-69 Revision 1
(Entrainment Sensitivity)
AP1000 Time Event (seconds) ak opens 0.0 actor trip signal 13.1 am turbine stop valves close 19.1 signal 18.6 in feed isolation valves begin to close 20.6 actor coolant pumps start to coast down 24.6 S Stage 1 182.8 S Stage 2 252.8 ct accumulator injection starts 255 S Stage 3 372.8 S Stage 4 492.8 ct accumulator empties 608.9 ct loop IRWST injection starts* 1711 ct loop core makeup tank empties 2095 Continuous injection period 15.6-70 Revision 1
Figure 15.6.1-1 Nuclear Power Transient Inadvertent Opening of a Pressurizer Safety Valve 15.6-71 Revision 1
Figure 15.6.1-2 DNBR Transient Inadvertent Opening of a Pressurizer Safety Valve 15.6-72 Revision 1
Figure 15.6.1-3 Pressurizer Pressure Transient Inadvertent Opening of a Pressurizer Safety Valve 15.6-73 Revision 1
Figure 15.6.1-4 Vessel Average Temperature Inadvertent Opening of a Pressurizer Safety Valve 15.6-74 Revision 1
Figure 15.6.1-5 Core Mass Flow Rate Inadvertent Opening of a Pressurizer Safety Valve 15.6-75 Revision 1
Figure 15.6.1-6 Nuclear Power Transient Inadvertent Opening of Two ADS Stage 1 Trains 15.6-76 Revision 1
Figure 15.6.1-7 DNBR Transient Inadvertent Opening of Two ADS Stage 1 Trains 15.6-77 Revision 1
Figure 15.6.1-8 Nuclear Power Transient Inadvertent Opening of Two ADS Stage 1 Trains 15.6-78 Revision 1
Figure 15.6.1-9 Nuclear Power Transient Inadvertent Opening of Two ADS Stage 1 Trains 15.6-79 Revision 1
Figure 15.6.1-10 Core Mass Flow Rate Inadvertent Opening of Two ADS Stage 1 Trains 15.6-80 Revision 1
Figure 15.6.3-1 Pressurizer Level for SGTR 15.6-81 Revision 1
Figure 15.6.3-2 Reactor Coolant System Pressure for SGTR 15.6-82 Revision 1
Figure 15.6.3-3 Secondary Pressure for SGTR 15.6-83 Revision 1
Figure 15.6.3-4 Intact Loop Hot and Cold Leg Reactor Coolant System Temperature for SGTR 15.6-84 Revision 1
Figure 15.6.3-5 Primary-to-Secondary Break Flow Rate for SGTR 15.6-85 Revision 1
Figure 15.6.3-6 Ruptured Steam Generator Water Volume for SGTR 15.6-86 Revision 1
Figure 15.6.3-7 Ruptured Steam Generator Mass Release Rate to the Atmosphere for SGTR 15.6-87 Revision 1
Figure 15.6.3-8 Intact Steam Generator Mass Release Rate to the Atmosphere for SGTR 15.6-88 Revision 1
Figure 15.6.3-9 Ruptured Loop Chemical and Volume Control System and Core Makeup Tank Injection Flow for SGTR 15.6-89 Revision 1
Figure 15.6.3-10 Integrated Flashed Break Flow for SGTR 15.6-90 Revision 1
Rods Figure 15.6.5.4A-1 WCOBRA/TRAC Peak Cladding Temperature for All Five Rod Groups for 95th Percentile Estimator PCT/MLO Case 15.6-91 Revision 1
Figure 15.6.5.4A-2 HOTSPOT Cladding Temperature Transient at Limiting Elevation for 95th Percentile Estimator PCT/MLO Case 15.6-92 Revision 1
Figure 15.6.5.4A-3 Total Mass Flow at Top of Hot Assembly Channel for 95th Percentile Estimator PCT/MLO Case 15.6-93 Revision 1
Figure 15.6.5.4A-4 Pressurizer Pressure for 95th Percentile Estimator PCT/MLO Case 15.6-94 Revision 1
Figure 15.6.5.4A-5 Accumulator Injection Flow for 95th Percentile Estimator PCT/MLO Case 15.6-95 Revision 1
Figure 15.6.5.4A-6 Core Makeup Tank Injection Flow for 95th Percentile Estimator PCT/MLO Case 15.6-96 Revision 1
Figure 15.6.5.4A-7 Total Mass Flow at Top of Peripheral Assemblies Channel for 95th Percentile Estimator PCT/MLO Case 15.6-97 Revision 1
Figure 15.6.5.4A-8 Total Mass Flow at Top of Guide Tube Assemblies Channel for 95th Percentile Estimator PCT/MLO Case 15.6-98 Revision 1
Figure 15.6.5.4A-9 Total Mass Flow at Top of Support Column/Open Hole Assemblies Channel for 95th Percentile Estimator PCT/MLO Case 15.6-99 Revision 1
Figure 15.6.5.4A-10 Break Mass Flow for 95th Percentile Estimator PCT/MLO Case 15.6-100 Revision 1
Figure 15.6.5.4A-11 Core Channel Collapsed Liquid Levels for 95th Percentile Estimator PCT/MLO Case 15.6-101 Revision 1
Figure 15.6.5.4A-12 Downcomer Channel Collapsed Liquid Levels for 95th Percentile Estimator PCT/MLO Case 15.6-102 Revision 1
0.32, 0.56 0.37, 0.56 0.55 0.50 0.25, 0.5 Normalized Power Integral in Bottom 1/3 of Core (PBOT) 0.45 0.49, 0.435 0.40 0.35 0.30 0.49, 0.29 0.255, 0.275 0.25 0.20 0.43, 0.185 0.38, 0.185 0.15 0.10 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 Normalized Power Integral in Middle 1/3 of Core (PMID)
Figure 15.6.5.4A-13 PBOT/PMID Box Supported by AP1000 ASTRUM Analysis 15.6-103 Revision 1
Figure 15.6.5.4B-1 Inadvertent ADS - RCS Pressure 15.6-104 Revision 1
Figure 15.6.5.4B-2 Inadvertent ADS - Pressurizer Mixture Level 15.6-105 Revision 1
Figure 15.6.5.4B-3 Inadvertent ADS - ADS 1-3 Liquid Discharge 15.6-106 Revision 1
Figure 15.6.5.4B-4 Inadvertent ADS - ADS 1-3 Vapor Discharge 15.6-107 Revision 1
Figure 15.6.5.4B-5 Inadvertent ADS - CMT-1 Injection Rate 15.6-108 Revision 1
Figure 15.6.5.4B-6 Inadvertent ADS - CMT-2 Injection Rate 15.6-109 Revision 1
Figure 15.6.5.4B-7 Inadvertent ADS - CMT-1 Mixture Level 15.6-110 Revision 1
Figure 15.6.5.4B-8 Inadvertent ADS - CMT-2 Mixture Level 15.6-111 Revision 1
Figure 15.6.5.4B-9 Inadvertent ADS - Downcomer Mixture Level 15.6-112 Revision 1
Figure 15.6.5.4B-10 Inadvertent ADS - Accumulator-1 Injection Rate 15.6-113 Revision 1
Figure 15.6.5.4B-11 Inadvertent ADS - Accumulator-2 Injection Rate 15.6-114 Revision 1
Figure 15.6.5.4B-12 Inadvertent ADS - ADS-4 Integrated Discharge 15.6-115 Revision 1
Figure 15.6.5.4B-13 Inadvertent ADS - IRWST-1 Injection Rate 15.6-116 Revision 1
Figure 15.6.5.4B-14 Inadvertent ADS - IRWST-2 Injection Rate 15.6-117 Revision 1
Figure 15.6.5.4B-15 Inadvertent ADS - RCS System Inventory 15.6-118 Revision 1
Figure 15.6.5.4B-16 Inadvertent ADS - Core/Upper Plenum Mixture Level 15.6-119 Revision 1
Figure 15.6.5.4B-17 2-inch Cold Leg Break - RCS Pressure 15.6-120 Revision 1
Figure 15.6.5.4B-18 2-inch Cold Leg Break - Pressurizer Mixture Level 15.6-121 Revision 1
Figure 15.6.5.4B-19 2-inch Cold Leg Break - CMT-1 Mixture Level 15.6-122 Revision 1
Figure 15.6.5.4B-20 2-inch Cold Leg Break - CMT-2 Mixture Level 15.6-123 Revision 1
Figure 15.6.5.4B-21 2-inch Cold Leg Break - Downcomer Mixture Level 15.6-124 Revision 1
Figure 15.6.5.4B-22 2-inch Cold Leg Break - CMT-1 Injection Rate 15.6-125 Revision 1
Figure 15.6.5.4B-23 2-inch Cold Leg Break - CMT-2 Injection Rate 15.6-126 Revision 1
Figure 15.6.5.4B-24 2-inch Cold Leg Break - Accumulator-1 Injection Rate 15.6-127 Revision 1
Figure 15.6.5.4B-25 2-inch Cold Leg Break - Accumulator-2 Injection Rate 15.6-128 Revision 1
Figure 15.6.5.4B-26 2-inch Cold Leg Break - IRWST-1 Injection Rate 15.6-129 Revision 1
Figure 15.6.5.4B-27 2-inch Cold Leg Break - IRWST-2 Injection Rate 15.6-130 Revision 1
Figure 15.6.5.4B-28 2-inch Cold Leg Break - ADS-4 Liquid Discharge 15.6-131 Revision 1
Figure 15.6.5.4B-29 2-inch Cold Leg Break - RCS System Inventory 15.6-132 Revision 1
Figure 15.6.5.4B-30 2-inch Cold Leg Break - Core/Upper Plenum Mixture Level 15.6-133 Revision 1
Figure 15.6.5.4B-31 2-inch Cold Leg Break - ADS-4 Integrated Discharge 15.6-134 Revision 1
Figure 15.6.5.4B-32 2-inch Cold Leg Break - Liquid Break Discharge 15.6-135 Revision 1
Figure 15.6.5.4B-33 2-inch Cold Leg Break - Vapor Break Discharge 15.6-136 Revision 1
Figure 15.6.5.4B-34 2-inch Cold Leg Break - PRHR Heat Removal Rate 15.6-137 Revision 1
Figure 15.6.5.4B-35 2-inch Cold Leg Break - Integrated PRHR Heat Removal 15.6-138 Revision 1
Figure 15.6.5.4B-36 DEDVI - Vessel Side Liquid Break Discharge - 20 psi 15.6-139 Revision 1
Figure 15.6.5.4B-37 DEDVI - Vessel Side Vapor Break Discharge - 20 psi 15.6-140 Revision 1
Figure 15.6.5.4B-38 DEDVI - RCS Pressure - 20 psi 15.6-141 Revision 1
Figure 15.6.5.4B-39 DEDVI - Broken CMT Injection Rate - 20 psi 15.6-142 Revision 1
Figure 15.6.5.4B-40 DEDVI - Intact CMT Injection Rate - 20 psi 15.6-143 Revision 1
Figure 15.6.5.4B-41 DEDVI - Core/Upper Plenum Mixture Level - 20 psi 15.6-144 Revision 1
Figure 15.6.5.4B-42 DEDVI - Downcomer Mixture Level - 20 psi 15.6-145 Revision 1
Figure 15.6.5.4B-43 DEDVI - ADS 1-3 Vapor Discharge - 20 psi 15.6-146 Revision 1
Figure 15.6.5.4B-44 DEDVI - Core Exit Void Fraction - 20 psi 15.6-147 Revision 1
Figure 15.6.5.4B-45 DEDVI - Core Exit Liquid Flow Rate - 20 psi 15.6-148 Revision 1
Figure 15.6.5.4B-46 DEDVI - Core Exit Vapor Flow Rate - 20 psi 15.6-149 Revision 1
Figure 15.6.5.4B-47 DEDVI - Lower Plenum to Core Flow Rate - 20 psi 15.6-150 Revision 1
Figure 15.6.5.4B-48 DEDVI - ADS-4 Liquid Discharge - 20 psi 15.6-151 Revision 1
Figure 15.6.5.4B-49 DEDVI - ADS-4 Integrated Discharge - 20 psi 15.6-152 Revision 1
Figure 15.6.5.4B-50 DEDVI - Intact Accumulator Flow Rate - 20 psi 15.6-153 Revision 1
Figure 15.6.5.4B-51 DEDVI - Intact IRWST Injection Rate - 20 psi 15.6-154 Revision 1
Figure 15.6.5.4B-52 DEDVI - Intact CMT Mixture Level - 20 psi 15.6-155 Revision 1
Figure 15.6.5.4B-53 DEDVI - RCS System Inventory - 20 psi 15.6-156 Revision 1
Figure 15.6.5.4B-54 DEDVI - PRHR Heat Removal Rate - 20 psi 15.6-157 Revision 1
Figure 15.6.5.4B-55 DEDVI - Integrated PRHR Heat Removal - 20 psi 15.6-158 Revision 1
Figure 15.6.5.4B-36A DEDVI - Vessel Side Liquid Break Discharge - 14.7 psi 15.6-159 Revision 1
Figure 15.6.5.4B-37A DEDVI - Vessel Side Vapor Break Discharge - 14.7 psi 15.6-160 Revision 1
Figure 15.6.5.4B-38A DEDVI - RCS Pressure - 14.7 psi 15.6-161 Revision 1
Figure 15.6.5.4B-39A DEDVI - Broken CMT Injection Rate - 14.7 psi 15.6-162 Revision 1
Figure 15.6.5.4B-40A DEDVI - Intact CMT Injection Rate - 14.7 psi 15.6-163 Revision 1
Figure 15.6.5.4B-41A DEDVI - Core/Upper Plenum Mixture Level - 14.7 psi 15.6-164 Revision 1
Figure 15.6.5.4B-42A DEDVI - Downcomer Mixture Level - 14.7 psi 15.6-165 Revision 1
Figure 15.6.5.4B-43A DEDVI - ADS 1-3 Vapor Discharge - 14.7 psi 15.6-166 Revision 1
Figure 15.6.5.4B-44A DEDVI - Core Exit Void Fraction - 14.7 psi 15.6-167 Revision 1
Figure 15.6.5.4B-45A DEDVI - Core Exit Liquid Flow Rate - 14.7 psi 15.6-168 Revision 1
Figure 15.6.5.4B-46A DEDVI - Core Exit Vapor Flow Rate - 14.7 psi 15.6-169 Revision 1
Figure 15.6.5.4B-47A DEDVI - Lower Plenum to Core Flow Rate - 14.7 psi 15.6-170 Revision 1
Figure 15.6.5.4B-48A DEDVI - ADS-4 Liquid Discharge - 14.7 psi 15.6-171 Revision 1
Figure 15.6.5.4B-49A DEDVI - ADS-4 Integrated Discharge - 14.7 psi 15.6-172 Revision 1
Figure 15.6.5.4B-50A DEDVI - Intact Accumulator Flow Rate - 14.7 psi 15.6-173 Revision 1
Figure 15.6.5.4B-51A DEDVI - Intact IRWST Injection Rate - 14.7 psi 15.6-174 Revision 1
Figure 15.6.5.4B-52A DEDVI - Intact CMT Mixture Level - 14.7 psi 15.6-175 Revision 1
Figure 15.6.5.4B-53A DEDVI - RCS System Inventory - 14.7 psi 15.6-176 Revision 1
Figure 15.6.5.4B-54A DEDVI - PRHR Heat Removal Rate - 14.7 psi 15.6-177 Revision 1
Figure 15.6.5.4B-55A DEDVI - Integrated PRHR Heat Removal - 14.7 psi 15.6-178 Revision 1
Figure 15.6.5.4B-56 10-inch Cold Leg Break - RCS Pressure 15.6-179 Revision 1
Figure 15.6.5.4B-57 10-inch Cold Leg Break - Pressurizer Mixture Level 15.6-180 Revision 1
Figure 15.6.5.4B-58 10-inch Cold Leg Break - CMT-1 Mixture Level 15.6-181 Revision 1
Figure 15.6.5.4B-59 10-inch Cold Leg Break - CMT-2 Mixture Level 15.6-182 Revision 1
Figure 15.6.5.4B-60 10-inch Cold Leg Break - Downcomer Mixture Level 15.6-183 Revision 1
Figure 15.6.5.4B-61 10-inch Cold Leg Break - CMT-1 Injection Rate 15.6-184 Revision 1
Figure 15.6.5.4B-62 10-inch Cold Leg Break - CMT-2 Injection Rate 15.6-185 Revision 1
Figure 15.6.5.4B-63 10-inch Cold Leg Break - Accumulator-1 Injection Rate 15.6-186 Revision 1
Figure 15.6.5.4B-64 10-inch Cold Leg Break - Accumulator-2 Injection Rate 15.6-187 Revision 1
Figure 15.6.5.4B-65 10-inch Cold Leg Break - IRWST-1 Injection Rate 15.6-188 Revision 1
Figure 15.6.5.4B-66 10-inch Cold Leg Break - IRWST-2 Injection Rate 15.6-189 Revision 1
Figure 15.6.5.4B-67 10-inch Cold Leg Break - ADS-4 Liquid Discharge 15.6-190 Revision 1
Figure 15.6.5.4B-68 10-inch Cold Leg Break - RCS System Inventory 15.6-191 Revision 1
Figure 15.6.5.4B-69 10-inch Cold Leg Break - Core/Upper Plenum Mixture Level 15.6-192 Revision 1
Figure 15.6.5.4B-70 10-inch Cold Leg Break - Composite Core Mixture Level 15.6-193 Revision 1
Figure 15.6.5.4B-71 10-inch Cold Leg Break - Core Exit Liquid Flow 15.6-194 Revision 1
Figure 15.6.5.4B-72 10-inch Cold Leg Break - Core Exit Vapor Flow 15.6-195 Revision 1
Figure 15.6.5.4B-73 10-inch Cold Leg Break - Core Exit Void Fraction 15.6-196 Revision 1
Figure 15.6.5.4B-74 10-inch Cold Leg Break - ADS-4 Integrated Discharge 15.6-197 Revision 1
Figure 15.6.5.4B-75 10-inch Cold Leg Break - Liquid Break Discharge 15.6-198 Revision 1
Figure 15.6.5.4B-76 10-inch Cold Leg Break - Vapor Break Discharge 15.6-199 Revision 1
Figure 15.6.5.4B-77 10-inch Cold Leg Break - PRHR Heat Removal Rate 15.6-200 Revision 1
Figure 15.6.5.4B-78 10-inch Cold Leg Break - Integrated PRHR Heat Removal 15.6-201 Revision 1
Figure 15.6.5.4B-79 DEDVI - Downcomer Pressure Comparison 15.6-202 Revision 1
Figure 15.6.5.4B-80 DEDVI - Intact IRWST Injection Flow 15.6-203 Revision 1
Figure 15.6.5.4B-81 DEDVI - Intact DVI Line Injection Flow 15.6-204 Revision 1
Figure 15.6.5.4B-82 DEDVI - ADS-4 Integrated Liquid Discharge Comparison 15.6-205 Revision 1
Figure 15.6.5.4B-83 DEDVI - Upper Plenum Mixture Mass Comparison 15.6-206 Revision 1
Figure 15.6.5.4B-84 DEDVI - ADS-4 Integrated Vapor Discharge Comparison 15.6-207 Revision 1
Figure 15.6.5.4B-85 DEDVI - Downcomer Region Mass Comparison 15.6-208 Revision 1
Figure 15.6.5.4B-86 DEDVI - Core Region Mass Comparison 15.6-209 Revision 1
Figure 15.6.5.4B-87 DEDVI - Vessel Mixture Mass Comparison 15.6-210 Revision 1
Figure 15.6.5.4B-88 DEDVI - Core/Upper Plenum Mixture Level Comparison 15.6-211 Revision 1
Figure 15.6.5.4B-89 DEDVI - Core Collapsed Liquid Level Comparison 15.6-212 Revision 1
Figure 15.6.5.4B-90 DEDVI - Pressurizer Mixture Level Comparison 15.6-213 Revision 1
Figure 15.6.5.4C-1 Collapsed Level of Liquid in the Downcomer (DEDVI Case) 15.6-214 Revision 1
Figure 15.6.5.4C-2 Collapsed Level of Liquid over the Heated Length of the Fuel (DEDVI Case) 15.6-215 Revision 1
Figure 15.6.5.4C-3 Void Fraction in Core Hot Assembly Top Cell (DEDVI Case) 15.6-216 Revision 1
Figure 15.6.5.4C-4 Void Fraction in Core Hot Assembly Second from Top Cell (DEDVI Case) 15.6-217 Revision 1
Figure 15.6.5.4C-5 Collapsed Liquid Level in the Hot Leg of Pressurizer Loop (DEDVI Case) 15.6-218 Revision 1
Figure 15.6.5.4C-6 Vapor Rate out of the Core (DEDVI Case) 15.6-219 Revision 1
Figure 15.6.5.4C-7 Liquid Flow Rate out of the Core (DEDVI Case) 15.6-220 Revision 1
Figure 15.6.5.4C-8 Collapsed Liquid Level in the Upper Plenum (DEDVI Case) 15.6-221 Revision 1
Figure 15.6.5.4C-9 Mixture Flow Rate Through ADS Stage 4A Valves (DEDVI Case) 15.6-222 Revision 1
Figure 15.6.5.4C-10 Mixture Flow Rate Through ADS Stage 4B Valves (DEDVI Case) 15.6-223 Revision 1
Figure 15.6.5.4C-11 Upper Plenum Pressure (DEDVI Case) 15.6-224 Revision 1
Figure 15.6.5.4C-12 Peak Cladding Temperature (DEDVI Case) 15.6-225 Revision 1
Figure 15.6.5.4C-13 DVI-A Mixture Flow Rate (DEDVI Case) 15.6-226 Revision 1
Figure 15.6.5.4C-14 DVI-B Mixture Flow Rate (DEDVI Case) 15.6-227 Revision 1
Figure 15.6.5.4C-1A Collapsed Level of Liquid in the Downcomer (DEDVI Case) - 14.7 psi 15.6-228 Revision 1
Figure 15.6.5.4C-2A Collapsed Level of Liquid over the Heated Length of the Fuel (DEDVI Case) - 14.7 psi 15.6-229 Revision 1
Figure 15.6.5.4C-3A Void Fraction in Core Hot Assembly Top Cell (DEDVI Case) - 14.7 psi 15.6-230 Revision 1
Figure 15.6.5.4C-4A Void Fraction in Core Hot Assembly Second from Top Cell (DEDVI Case) - 14.7 psi 15.6-231 Revision 1
Figure 15.6.5.4C-5A Collapsed Liquid Level in the Hot Leg of Pressurizer Loop (DEDVI Case) - 14.7 psi 15.6-232 Revision 1
Figure 15.6.5.4C-6A Vapor Rate out of the Core (DEDVI Case) - 14.7 psi 15.6-233 Revision 1
Figure 15.6.5.4C-7A Liquid Flow Rate out of the Core (DEDVI Case) - 14.7 psi 15.6-234 Revision 1
Figure 15.6.5.4C-8A Collapsed Liquid Level in the Upper Plenum (DEDVI Case) - 14.7 psi 15.6-235 Revision 1
Figure 15.6.5.4C-9A Mixture Flow Rate Through ADS Stage 4A Valves (DEDVI Case) - 14.7 psi 15.6-236 Revision 1
Figure 15.6.5.4C-10A Mixture Flow Rate Through ADS Stage 4B Valves (DEDVI Case) - 14.7 psi 15.6-237 Revision 1
Figure 15.6.5.4C-11A Upper Plenum Pressure (DEDVI Case) - 14.7 psi 15.6-238 Revision 1
Figure 15.6.5.4C-12A Peak Cladding Temperature (DEDVI Case) - 14.7 psi 15.6-239 Revision 1
Figure 15.6.5.4C-13A DVI-A Mixture Flow Rate (DEDVI Case) - 14.7 psi 15.6-240 Revision 1
Figure 15.6.5.4C-14A DVI-B Mixture Flow Rate (DEDVI Case) - 14.7 psi 15.6-241 Revision 1
Figure 15.6.5.4C-15 Collapsed Level of Liquid in the Downcomer (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-242 Revision 1
Figure 15.6.5.4C-16 Collapsed Level of Liquid Over the Heated Length of the Fuel (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-243 Revision 1
Figure 15.6.5.4C-17 Void Fraction in Core Hot Assembly Top Cell (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-244 Revision 1
Figure 15.6.5.4C-18 Void Fraction in Core Hot Assembly Second from Top Cell (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-245 Revision 1
Figure 15.6.5.4C-19 Collapsed Liquid Level in the Hot Leg of Pressurizer Loop (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-246 Revision 1
Figure 15.6.5.4C-20 Vapor Rate out of the Core (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-247 Revision 1
Figure 15.6.5.4C-21 Liquid Flow Rate out of the Core (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-248 Revision 1
Figure 15.6.5.4C-22 Collapsed Liquid Level in the Upper Plenum (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-249 Revision 1
Figure 15.6.5.4C-23 Mixture Flow Rate Through ADS Stage 4A Valves (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-250 Revision 1
Figure 15.6.5.4C-24 Mixture Flow Rate Through ADS Stage 4B Valves (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-251 Revision 1
Figure 15.6.5.4C-25 Upper Plenum Pressure (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-252 Revision 1
Figure 15.6.5.4C-26 Hot Rod Cladding Temperature Near Top of Core (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-253 Revision 1
Figure 15.6.5.4C-27 DVI-A Mixture Flow Rate (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-254 Revision 1
Figure 15.6.5.4C-28 DVI-B Mixture Flow Rate (Wall-to-Wall Floodup Case) - 14.7 psi 15.6-255 Revision 1
Gas waste management system leak or failure Liquid waste management system leak or failure (atmospheric release)
Release of radioactivity to the environment via liquid pathways Fuel handling accident Spent fuel cask drop accident 7.1 Gas Waste Management System Leak or Failure AP1000 gaseous radwaste system is a low-pressure, low-flow charcoal delay process. Failure of gaseous radwaste system results in a minor release of activity that is not significant. The ndard Review Plan no longer includes this event as part of the review. Therefore, no analysis is ided.
7.2 Liquid Waste Management System Leak or Failure (Atmospheric Release)
AP1000 liquid radwaste system tanks do not contain significant levels of gaseous activity ause liquids expected to contain gaseous radioactivity are processed by a gas stripper before g directed to storage. The tanks are open to the atmosphere so that any evolution of gaseous vity is continually released through the monitored plant vent. The Standard Review Plan no longer udes this event as part of the review. Therefore, no analysis is provided.
7.3 Release of Radioactivity to the Environment Due to a Liquid Tank Failure ks containing radioactive fluids are located inside plant structures.
e event of a tank failure, the liquid would be drained by the floor drains to the auxiliary building
- p. From the sump, the water would be directed to the waste holdup tank. The basemat of the iliary building is 6-feet thick, the exterior walls are 3-feet thick, and the building is seismic egory I. The exterior walls are sealed to prevent leakage. Thus, it is assumed that there is no ase of the spilled liquid waste to the environment. However, the Standard Review Plan states that it cannot be taken for liquid retention by unlined building foundations. Analysis of the impact of event is performed as discussed in Subsection 2.4.13. This analysis includes consideration of liquid level, processing and decay of tank contents, potential paths of spilled waste to the ironment, as well as other pertinent factors.
7.4 Fuel Handling Accident el handling accident can be postulated to occur either inside the containment or in the fuel dling area inside the auxiliary building. The fuel handling accident is defined as the dropping of a nt fuel assembly such that every rod in the dropped assembly has its cladding breached so that activity in the fuel/cladding gap is released.
possibility of a fuel handling accident is remote because of the many administrative controls and equipment operating limits that are incorporated in the fuel handling operations (see section 9.1.4). Only one spent fuel assembly is lifted at a time, and the fuel is moved at low eds, exercising caution that the fuel assembly not strike anything during movement. The tainment, auxiliary building, refueling pool, and spent fuel pool are designed to seismic Category I uirements to thus provide their integrity in the event of a safe shutdown earthquake. The spent storage racks are located to prevent a credible external missile from reaching the stored fuel emblies. The fuel handling equipment is designed to prevent the handling equipment from falling 15.7-1 Revision 1
7.4.1 Source Term inventory of fission products available for release at the time of the accident is dependent on a ber of factors, such as the power history of the fuel assembly, the time delay between reactor tdown and the beginning of fuel handling operations, and the volatility of the nuclides.
fuel handling accident source term is derived from the core source term detailed in endix 15A by taking into account the factors below. The assumptions used to define the fuel dling accident initial airborne release source term are provided in Table 15.7-1 along with the ved source term.
7.4.1.1 Fission Product Gap Fraction ing power operation, a portion of the fission products generated in the fuel pellet matrix diffuses the fuel/cladding gap. The fraction of the assembly fission products found in the gap depends on rate of diffusion for the nuclide in question as well as the rate of radioactive decay. In the event of el handling accident, the gaseous and volatile radionuclides contained in the fuel/cladding gap free to escape from the fuel assembly. The radionuclides of concern are the noble gases ptons and xenons) and iodines. Based on NUREG-1465 (Reference 1), the fission product gap tion is 3-percent of fuel inventory. For this analysis, the gap fractions are increased to be sistent with the guidance of Regulatory Guide 1.183 (Reference 2). The gap fractions are listed in le 15.7-1.
7.4.1.2 Iodine Chemical Form sistent with NUREG-1465 guidance, the iodine released from the damaged fuel rods is assumed e 95-percent cesium iodide, 4.85-percent elemental iodine, and 0.15-percent organic iodine.
ium iodide is nonvolatile, and the iodine in this form dissolves in water but does not readily ome airborne. However, consistent with the guidance in Regulatory Guide 1.183, it is assumed the cesium iodide is instantaneously converted to the elemental form when released from the into the low pH water pool.
7.4.1.3 Assembly Power Level uel assemblies are assumed to be handled inside the containment during the core shuffle so a k power assembly is considered for the accident. Any fuel assembly can be transferred to the nt fuel pool; during a core off-load, all fuel assemblies are discharged to the spent fuel pool. To in a bounding condition for the fuel handling accident analysis, it is assumed that the accident lves a fuel assembly that operated at the maximum rated fuel rod peaking factor. This is servative because the entire fuel assembly does not operate at this level.
7.4.1.4 Radiological Decay fission product decay time experienced prior to the fuel handling accident is at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
7.4.2 Release Pathways spent fuel handling operations take place underwater. Thus, activity releases are first scrubbed he column of water 23 feet in depth. This has no effect on the releases of noble gases or organic 15.7-2 Revision 1
r the activity escapes from the water pool, it is assumed that it is released directly to the ironment within a 2-hour period without credit for any additional iodine removal process.
e fuel handling accident occurs in the containment, the release of activity can be terminated by ure of the containment purge lines on detection of high radioactivity. No credit is taken for this in analysis. Additionally, no credit is taken for removal of airborne iodine by the filters in the tainment purge lines.
the fuel handling accident postulated to occur in the spent fuel pool, there is assumed to be no tion in the release pathway. Activity released from the pool is assumed to pass directly to the ironment with no credit for holdup or delay of release in the building.
7.4.3 Dose Calculation Models models used to calculate doses are provided in Appendix 15A.
le 15.7-1 lists the assumptions used in the analysis. The guidance of Regulatory Guide 1.183 is cted in the analysis assumptions.
7.4.4 Identification of Conservatisms fuel handling accident dose analysis assumptions contain a number of conservatisms. Some of e conservatisms are described in the following subsections.
7.4.4.1 Fuel Assembly Power Level source term is based on the assumption that all of the fuel rods in the damaged assembly have n operating at the maximum fuel rod radial peaking factor. In actuality, this is true for only a small tion of the fuel rods in any assembly. The overall assembly power level is less than the maximum al peaking factor.
7.4.4.2 Fission Product Gap Fraction assumption of Regulatory Guide 1.183 gap fractions for the short-lived nuclides is conservative factor of 2 or more, depending on the nuclide.
7.4.4.3 Amount of Fuel Damage assumed that all fuel rods in a fuel assembly are damaged so as to release the fission product ntory in the fuel/cladding gap. In an actual fuel handling accident, it is expected that there would ew rods damaged to this extent.
7.4.4.4 Iodine Plateout on Fuel Cladding ough it is expected that virtually all elemental iodine plates out on the fuel cladding and is vailable for atmospheric release, no credit is taken for plateout.
15.7-3 Revision 1
oval in the water pool), there would be no organic iodine in the fuel rods. Any formation of organic ne would occur gradually and would not contribute to early releases of activity.
7.4.4.6 Conversion of Cesium Iodide to Form Elemental Iodine analysis assumes that all of the cesium iodide converts immediately to the elemental iodine form r release to the water pool and is treated in the same manner as the iodine initially in the mental form. While the low pH solution does support conversion to the elemental form, the version would not occur unless the cesium iodide was dissolved in the water. The elemental ne that is formed would thus be in the water solution and not in the bubbles of gas released from damaged fuel. Additionally, conversion of cesium iodide would occur slowly and the elemental ne formed would not be immediately available for release.
7.4.4.7 Meteorology unlikely that the conservatively selected meteorological conditions are present at the time of the dent.
7.4.4.8 Time Available for Radioactive Decay dose analysis assumes that the fuel handling accident involves one of the first fuel assemblies dled. If it were one of the later fuel handling operations, there is additional decay and a reduction e source term.
dose evaluation was performed assuming 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> decay.
7.4.5 Offsite Doses ng the assumptions from Table 15.7-1, the calculated doses from the initial releases are rmined to be 2.8 rem TEDE at the site boundary and 1.2 rem TEDE at the low population zone r boundary. These doses are well within the dose guideline of 25 rem TEDE identified in 10 CFR 50.34. The phrase "well within" is taken as meaning 25 percent or less.
7.5 Spent Fuel Cask Drop Accident spent fuel cask handling crane is prevented from travelling over the spent fuel. No radiological sequences analysis is necessary for the dropped cask event.
7.6 Combined License Information analysis of the consequences of potential release of radioactivity to the environment due to a d tank failure is addressed in Subsection 2.4.13.
7.7 References Sofer, L., et al., "Accident Source Terms for Light-Water Nuclear Power Plants,"
NUREG-1465, February 1995.
U. S. NRC Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors, " July 2000.
15.7-4 Revision 1
Fuel Handling Accident Radiological Consequences rce term assumptions
- Core power (MWt) 3434(1)
- Decay time (hr) 48 e source term after 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> decay (Ci) 130 1.28 E+05 131 8.18 E+07 132 9.10 E+07 133 4.06 E+07 135 1.17 E+06 r-85m 1.52 E+04 r-85 1.07 E+06 r-88 5.45 E+02 e-131m 1.02 E+06 e-133m 4.47 E+06 e-133 1.70 E+08 e-135m 1.91 E+05 e-135 1.04 E+07 mber of fuel assemblies in core 157 ount of fuel damage One assembly imum rod radial peaking factor 1.75 centage of fission products in gap 131 8 ther iodines 5 r-85 10 ther noble gases 5 l decontamination factor for iodine 200 vity release period (hr) 2 ospheric dispersion factors See Table 15A-5 in Appendix 15A 3/sec) 3.5 E-4 athing rates (m lide data See Appendix 15A The main feedwater flow measurement supports a 1-percent power uncertainty.
15.7-5 Revision 1
anticipated transient without scram (ATWS) is an anticipated operational occurrence during which utomatic reactor scram is required but fails to occur due to a common mode fault in the reactor ection system. Under certain circumstances, failure to execute a required scram during an cipated operational occurrence could transform a relatively minor transient into a more severe dent. ATWS events are not considered to be in the design basis for Westinghouse plants.
8.2 Anticipated Transients Without Scram in the AP1000 Westinghouse plants, the ATWS rule (10 CFR 50.62) requires the installation of equipment that is rse from the reactor protection system to automatically trip the turbine and initiate decay heat oval. This equipment must be designed to perform its function in a reliable manner and be pendent from sensor output to final actuation device from the existing reactor protection system.
basis for the ATWS rule requirements, as outlined in SECY-83-293 (Reference 1), is to reduce risk of core damage because of ATWS to less than 10-5 per reactor year.
AP1000 includes a diverse actuation system, which provides the AMSAC protection features dated for Westinghouse plants by 10 CFR 50.62, plus a diverse reactor scram (see Section 7.7).
s, the ATWS rule is met.
8.3 Conclusion AP1000 is equipped with a diverse actuation system, which provides the functions required by ATWS rule (10 CFR 50.62). The ATWS core damage frequency for the AP1000 is well below the Y-83-293 goal of 10-5 per reactor year. The AP1000 ATWS core damage frequency is discussed hapter 33 of the Probabilistic Risk Assessment (PRA). The AP1000 design meets the ATWS rule CFR 50.62) and its ATWS core damage frequency safety goal basis.
8.4 Combined License Information section contained no requirement for additional information.
8.5 References Dircks, W. J., "Amendments to 10 CFR 50 Related to Anticipated Transients Without Scram (ATWS) Events," SECY-83-293, U.S. NRC, July 19, 1983.
15.8-1 Revision 1
appendix contains the parameters and models that form the basis of the radiological sequences analyses for the various postulated accidents.
.1 Offsite Dose Calculation Models iological consequences analyses are performed to determine the total effective dose equivalent DE) doses associated with the postulated accident. The determination of TEDE doses takes into ount the committed effective dose equivalent (CEDE) dose resulting from the inhalation of orne activity (that is, the long-term dose accumulation in the various organs) as well as the ctive dose equivalent (EDE) dose resulting from immersion in the cloud of activity.
.1.1 Immersion Dose (Effective Dose Equivalent) uming a semi-infinite cloud, the immersion doses are calculated using the equation:
Dim = DCFi R ij ( /Q ) j i j re:
= Immersion (EDE) dose (rem)
Fi = EDE dose conversion factor for isotope i (rem-m3/Ci-s)
= Amount of isotope i released during time period j (Ci)
)j = Atmospheric dispersion factor during time period j (s/m3)
.1.2 Inhalation Dose (Committed Effective Dose Equivalent)
CEDE doses are calculated using the equation:
DCEDE = DCFi R ij (BR ) j ( /Q ) j i j re:
Fi = CEDE dose conversion factor (rem per curie inhaled) for isotope i
= Amount of isotope i released during time period j (Ci)
)j = Breathing rate during time period j (m3/s)
)j = Atmospheric dispersion factor during time period j (s/m3) 15A-1 Revision 1
.2 Main Control Room Dose Models iological consequences analyses are performed to determine the TEDE doses associated with postulated accident. The determination of TEDE doses takes into account the CEDE dose lting from the inhalation of airborne activity (that is, the long-term dose accumulation in the ous organs) as well as the EDE dose resulting from immersion in the cloud of activity.
.2.1 Immersion Dose Models to the finite volume of air contained in the main control room, the immersion dose for an operator upying the main control room is substantially less than it is for the case in which a semi-infinite d is assumed. The finite cloud doses are calculated using the geometry correction factor from phy and Campe (Reference 1).
equation is:
1 Dim =
GF i DCFi (IAR )ij O j j
re:
= Immersion (EDE) dose (rem)
= Main control room geometry factor
= 1173/V0.338
= Volume of the main control room (ft3)
Fi = EDE dose conversion factor for isotope i (rem-m3/Ci-s)
)ij = Integrated activity for isotope i in the main control room during time period j (Ci-s/m3)
= Fraction of time period j that the operator is assumed to be present
.2.2 Inhalation Dose CEDE doses are calculated using the equation:
DCEDE = DCFi (IAR )ij (BR ) j O j i j re:
Fi = CEDE dose conversion factor (rem per curie inhaled) for isotope i
)ij = Integrated activity for isotope i in the main control room during time period j (Ci-s/m3)
)j = Breathing rate during time period j (m3/s)
= Fraction of time period j that the operator is assumed to be present 15A-2 Revision 1
.3 General Analysis Parameters
.3.1 Source Terms sources of radioactivity for release are dependent on the specific accident. Activity may be ased from the primary coolant, from the secondary coolant, and from the core if the accident lves fuel failures. The radiological consequences analyses use conservative design basis source s.
.3.1.1 Primary Coolant Source Term design basis primary coolant source terms are listed in Table 11.1-2. These source terms are ed on continuous plant operation with 0.25-percent fuel defects. The remaining assumptions d in determining the primary coolant source terms are listed in Table 11.1-1.
accident dose analyses take into account increases in the primary coolant source terms for nes and noble gases above those listed in Table 11.1-2, consistent with the Tech Spec limits of Ci/g dose equivalent I-131 for the iodines and 280 Ci/g dose equivalent Xe-133 for the noble es.
radiological consequences analyses for certain accidents also take into account the nomenon of iodine spiking, which causes the concentration of radioactive iodines in the primary lant to increase significantly. Table 15A-1 lists the concentrations of iodine isotopes associated a pre-existing iodine spike. This is an iodine spike that occurs prior to the accident and for which peak primary coolant activity is reached at the time the accident is assumed to occur. These opic concentrations are also defined as 60 Ci/g dose equivalent I-131. The probability of this erse timing of the iodine spike and accident is small.
ough it is unlikely for an accident to occur at the same time that an iodine spike is at its maximum tor coolant concentration, for many accidents it is expected that an iodine spike would be ated by the accident or by the reactor trip associated with the accident. Table 15A-2 lists the ne appearance rates (rates at which the various iodine isotopes are transferred from the core to primary coolant by way of the assumed cladding defects) for normal operation. The iodine spike earance rates are assumed to be as much as 500 times the normal appearance rates.
.3.1.2 Secondary Coolant Source Term secondary coolant source term used in the radiological consequences analyses is servatively assumed to be 1 percent of the primary coolant equilibrium source term. This is more servative than using the design basis secondary coolant source terms listed in Table 11.1-5.
ause the iodine spiking phenomenon is short-lived and there is a high level of conservatism for assumed secondary coolant iodine concentrations, the effect of iodine spiking on the secondary lant iodine source terms is not modeled.
re is assumed to be no secondary coolant noble gas source term because the noble gases ring the secondary side due to primary-to-secondary leakage enter the steam phase and are harged via the condenser air removal system.
15A-3 Revision 1
of life after continuous operation at 2 percent above full core thermal power. The main feedwater measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is servative. In addition to iodines and noble gases, the source terms listed include nuclides that are tified as potentially significant dose contributors in the event of a degraded core accident. The ign basis loss-of-coolant accident analysis is not expected to result in significant core damage, the radiological consequences analysis assumes severe core degradation.
.3.2 Nuclide Parameters radiological consequence analyses consider radioactive decay of the subject nuclides prior to r release, but no additional decay is assumed after the activity is released to the environment.
le 15A-4 lists the decay constants for the nuclides of concern.
le 15A-4 also lists the dose conversion factors for calculation of the CEDE doses due to inhalation dines and other nuclides and EDE dose conversion factors for calculation of the dose due to ersion in a cloud of activity. The CEDE dose conversion factors are from EPA Federal Guidance ort No. 11 (Reference 2) and the EDE dose conversion factors are from EPA Federal Guidance ort No. 12 (Reference 3).
.3.3 Atmospheric Dispersion Factors section 2.3.4 lists the off-site short-term atmospheric dispersion factors (/Q) for the reference Table 15A-5 (Sheet 1 of 2) reiterates these /Q values.
atmospheric dispersion factors (/Q) to be applied to air entering the main control room following sign basis accident are specified at the HVAC intake and at the annex building entrance (which ld be the air pathway to the main control room due to ingress/egress). A set of /Q values is tified for each potential activity release location that has been identified and the two control room ptor locations. These /Q values are listed in Table 15A-6 and are provided in Table 2.0-201.
-specific /Q values provided in Subsection 2.3.4 are bounded by the values given in les 15A-5 and 15A-6.
le 15A-7 identifies the AP1000 source and receptor data to be used when determining the site-cific control room /Q values using the ARCON96 code (References 4 and 5).
main control room /Q values do not incorporate occupancy factors.
locations of the potential release points and their relationship to the main control room air intake the annex building access door are shown in Figure 15A-1.
.4 References Murphy, K. G., Campe, K. M., "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Criterion 19," paper presented at the 13th AEC Air Cleaning Conference.
EPA Federal Guidance Report No. 11, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion,"
EPA-520/1-88-020, September 1988.
15A-4 Revision 1
NUREG/CR-6331, Ramsdell, J. V. and Simonen, C. A., "Atmospheric Relative Concentrations in Building Wakes," Revision 1, May 1997.
Regulatory Guide 1.194, Atmospheric Relative Concentrations for Control Room Radiological Habitability Assessments at Nuclear Power Plants, June 2003.
15A-5 Revision 1
Maximum Iodine Spike of 60 Ci/g Dose Equivalent I-131 Nuclide Ci/g I-130 0.66 I-131 43.4 I-132 57.5 I-133 78.8 I-134 13.4 I-135 47.8 Table 15A-2 Iodine Appearance Rates in the Reactor Coolant Equilibrium Appearance Rate Nuclide (Ci/min)
I-130 7.03x10-3 I-131 3.39x10-1 I-132 1.38 I-133 7.42x10-1 I-134 6.81x10-1 I-135 6.37x10-1 15A-6 Revision 1
Nuclide Inventory (Ci) Nuclide Inventory (Ci) nes I-130 3.66x106 Noble Gases Kr-85m 2.63x107 I-131 9.63x107 Kr-85 1.06x106 I-132 1.40x108 Kr-87 5.07x107 I-133 1.99x108 Kr-88 7.14x107 I-134 2.18x108 Xe-131m 1.06x106 8
I-135 1.86x10 Xe-133m 5.84x106 Group Cs-134 1.94x107 Xe-133 1.90x108 Cs-136 5.53x106 Xe-135m 3.87x107 Cs-137 1.13x107 Xe-135 4.84x107 Cs-138 1.82x108 Xe-138 1.65x108 Rb-86 2.29x105 Sr & Ba Sr-89 9.66x107 Group Te-127m 1.32x106 Sr-90 8.31x106 Te-127 1.02x107 Sr-91 1.20x108 Te-129m 4.50x106 Sr-92 1.29x108 Te-129 3.04x107 Ba-139 1.78x108 Te-131m 1.40x107 Ba-140 1.71x108 Te-132 1.38x108 Ce Group Ce-141 1.63x108 Sb-127 1.03x107 Ce-143 1.52x108 Sb-129 3.10x107 Ce-144 1.23x108 Group Ru-103 1.45x108 Pu-238 3.83x105 Ru-105 9.83x107 Pu-239 3.37x104 Ru-106 4.77x107 Pu-240 4.94x104 Rh-105 9.00x107 Pu-241 1.11x107 Mo-99 1.84x108 Np-239 1.93x109 Tc-99m 1.61x108 The following assumptions apply:
- Core thermal power of 3468 MWt (2 percent above the design core power of 3400 MWt). The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
- Three-region equilibrium cycle core at end of life 15A-7 Revision 1
Nuclide Inventory (Ci)
Group Y-90 8.66x106 Y-91 1.24x108 Y-92 1.30x108 Y-93 1.49x108 Nb-95 1.67x108 Zr-95 1.66x108 Zr-97 1.64x108 La-140 1.82x108 La-141 1.62x108 La-142 1.57x108 Pr-143 1.46x108 Nd-147 6.48x107 Am-241 1.25x104 Cm-242 2.95x106 Cm-244 3.62x105 The following assumptions apply:
Core thermal power of 3468 MWt (2 percent above the design core power of 3400 MWt). The main feedwater flow measurement supports a 1-percent power uncertainty; use of a 2-percent power uncertainty is conservative.
Three-region equilibrium cycle core at end of life 15A-8 Revision 1
ALOGENS EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Isotope (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
I-130 5.61x10-2 1.04x10-13 7.14x10-10 I-131 3.59x10-3 1.82x10-14 8.89x10-9 I-132 3.01x10-1 1.12x10-13 1.03x10-10 I-133 3.33x10-2 2.94x10-14 1.58x10-9 I-134 7.91x10-1 1.30x10-13 3.55x10-11 I-135 1.05x10-1 7.98x10-14 3.32x10-10 OBLE GASES EDE Dose Decay Constant Conversion Factor Isotope (hr-1) (Sv-m3/Bq-s)
Kr-85m 1.55x10-1 7.48x10-15 Kr-85 7.38x10-6 1.19x10-16 Kr-87 5.45x10-1 4.12x10-14 Kr-88 2.44x10-1 1.02x10-13 Xe-131m 2.43x10-3 3.89x10-16 Xe-133m 1.32x10-2 1.37x10-15 Xe-133 5.51x10-3 1.56x10-15 Xe-135m 2.72 2.04x10-14 Xe-135 7.63x10-2 1.19x10-14 Xe-138 2.93 5.77x10-14 15A-9 Revision 1
LKALI METALS EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Nuclide (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
Cs-134 3.84x10-5 7.57x10-14 1.25x10-8 Cs-136 2.2x10-3 1.06x10-13 1.98x10-9 Cs-137(1) 2.64x10-6 2.88x10-14 8.63x10-9 Cs-138 1.29 1.21x10-13 2.74x10-11 Rb-86 1.55x10-3 4.81x10-15 1.79x10-9 ELLURIUM GROUP EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Nuclide (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
Te-127m 2.65x10-4 1.47x10-16 5.81x10-9 Te-127 7.41x10-2 2.42x10-16 8.60x10-11 Te-129m 8.6x10-4 1.55x10-15 6.47x10-9 Te-129 5.98x10-1 2.75x10-15 2.42x10-11 Te-131m 2.31x10-2 7.01x10-14 1.73x10-9 Te-132 8.86x10-3 1.03x10-14 2.55x10-9 Sb-127 7.5x10-3 3.33x10-14 1.63x10-9 Sb-129 1.6x10-1 7.14x10-14 1.74x10-10 TRONTIUM AND BARIUM EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Nuclide (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
Sr-89 5.72x10-4 7.73x10-17 1.12x10-8 Sr-90 2.72x10-6 7.53x10-18 3.51x10-7 Sr-91 7.3x10-2 3.45x10-14 4.49x10-10 Sr-92 2.56x10-1 6.79x10-14 2.18x10-10 Ba-139 5.02x10-1 2.17x10-15 4.64x10-11 Ba-140 2.27x10-3 8.58x10-15 1.01x10-9 e:
The listed average gamma disintegration energy for Cs-137 is due to the production and decay of Ba-137m.
15A-10 Revision 1
OBLE METALS EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Nuclide (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
Ru-103 7.35x10-4 2.25x10-14 2.42x10-9 Ru-105 1.56x10-1 3.81x10-14 1.23x10-10 Ru-106 7.84x10-5 0.0 1.29x10-7 Rh-105 1.96x10-2 3.72x10-15 2.58x10-10 Mo-99 1.05x10-2 7.28x10-15 1.07x10-9 Tc-99m 1.15x10-1 5.89x10-15 8.80x10-12 CERIUM GROUP EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Nuclide (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
Ce-141 8.89x10-4 3.43x10-15 2.42x10-9 Ce-143 2.1x10-2 1.29x10-14 9.16x10-10 Ce-144 1.02x10-4 8.53x10-16 1.01x10-7 Pu-238 9.02x10-7 4.88x10-18 1.06x10-4 Pu-239 3.29x10-9 4.24x10-18 1.16x10-4 Pu-240 1.21x10-8 4.75x10-18 1.16x10-4 Pu-241 5.5x10-6 7.25x10-20 2.23x10-6 Np-239 1.23x10-2 7.69x10-15 6.78x10-10 ANTHANIDE GROUP EDE Dose CEDE Dose Decay Constant Conversion Factor Conversion Factor Nuclide (hr-1) (Sv-m3/Bq-s) (Sv/Bq)
Y-90 1.08x10-2 1.90x10-16 2.28x10-9 Y-91 4.94x10-4 2.60x10-16 1.32x10-8 Y-92 1.96x10-1 1.30x10-14 2.11x10-10 Y-93 6.86x10-2 4.80x10-15 5.82x10-10 Nb-95 8.22x10-4 3.74x10-14 1.57x10-9 Zr-95 4.51x10-4 3.60x10-14 6.39x10-9 Zr-97 4.1x10-2 9.02x10-15 1.17x10-9 La-140 1.72x10-2 1.17x10-13 1.31x10-9 La-141 1.76x10-1 2.39x10-15 1.57x10-10 La-142 4.5x10-1 1.44x10-13 6.84x10-11 Nd-147 2.63x10-3 6.19x10-15 1.85x10-9 Pr-143 2.13x10-3 2.10x10-17 2.19x10-9 Am-241 1.83x10-7 8.18x10-16 1.20x10-4 Cm-242 1.77x10-4 5.69x10-18 4.67x10-6 Cm-244 4.37x10-6 4.91x10-18 6.70x10-5 15A-11 Revision 1
for Accident Dose Analysis boundary /Q (s/m3)
-2 hours(1) 5.1x10-4 population zone /Q (s/m3)
-8 hours 2.2x10-4
-24 hours 1.6x10-4 4-96 hours 1.0x10-4 6-720 hours 8.0x10-5 s:
Nominally defined as the 0- to 2-hour interval, but is applied to the 2-hour interval having the highest activity releases in order to address 10 CFR Part 50.34 requirements 15A-12 Revision 1
for Accident Dose Analysis
/Q (s/m3) at HVAC Intake for the Identified Release Points(1)
Ground Level Plant Vent or Containment PORV and Steam Line Fuel Condenser PCS Air Release Safety Valve Break Handling Air Removal Diffuser(3) Points(4) Releases(5) Releases Area(6) Stack(7) 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 3.0E-3 6.0E-3 2.0E-2 2.4E-2 6.0E-3 6.0E-3 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 2.5E-3 3.6E-3 1.8E-2 2.0E-2 4.0E-3 4.0E-3 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 1.0E-3 1.4E-3 7.0E-3 7.5E-3 2.0E-3 2.0E-3 4 days 8.0E-4 1.8E-3 5.0E-3 5.5E-3 1.5E-3 1.5E-3 30 days 6.0E-4 1.5E-3 4.5E-3 5.0E-3 1.0E-3 1.0E-3
/Q (s/m3) at Annex Building Door for the Identified Release Points(2)
Ground Level Plant Vent or Containment PORV and Steam Line Fuel Condenser PCS Air Release Safety Valve Break Handling Air Removal Diffuser(3) Points(4) Releases(5) Releases Area(6) Stack(7) 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 1.0E-3 1.0E-3 4.0E-3 4.0E-3 6.0E-3 2.0E-2 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 7.5E-4 7.5E-4 3.2E-3 3.2E-3 4.0E-3 1.8E-2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 3.5E-4 3.5E-4 1.2E-3 1.2E-3 2.0E-3 7.0E-3 4 days 2.8E-4 2.8E-4 1.0E-3 1.0E-3 1.5E-3 5.0E-3 30 days 2.5E-4 2.5E-4 8.0E-4 8.0E-4 1.0E-3 4.5E-3 es:
These dispersion factors are to be used 1) for the time period preceding the isolation of the main control room and actuation of the emergency habitability system, 2) for the time after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> when the compressed air supply in the emergency habitability system would be exhausted and outside air would be drawn into the main control room, and 3) for the determination of control room doses when the non-safety ventilation system is assumed to remain operable such that the emergency habitability system is not actuated.
These dispersion factors are to be used when the emergency habitability system is in operation and the only path for outside air to enter the main control room is that due to ingress/egress.
These dispersion factors are used for analysis of the doses due to a postulated small line break outside of containment. The plant vent and PCS air diffuser are potential release paths for other postulated events (loss-of-coolant accident, rod ejection accident, and fuel handling accident inside the containment); however, the values are bounded by the dispersion factors for ground level releases.
The listed values represent modeling the containment shell as a diffuse area source, and are used for evaluating the doses in the main control room for a loss-of-coolant accident, for the containment leakage of activity following a rod ejection accident, and for a fuel handling accident occurring inside the containment.
The listed values bound the dispersion factors for releases from the steam line safety & power-operated relief valves. These dispersion factors would be used for evaluating the doses in the main control room for a steam generator tube rupture, a main steam line break, a locked reactor coolant pump rotor, and for the secondary side release from a rod ejection accident.
The listed values bound the dispersion factors for releases from the fuel storage and handling area. The listed values also bound the dispersion factors for releases from the fuel storage area in the event that spent fuel boiling occurs and the fuel building relief panel opens on high temperature. These dispersion factors are used for the fuel handling accident occurring outside containment and for evaluating the impact of releases associated with spent fuel pool boiling.
This release point is included for information only as a potential activity release point. None of the design basis accident radiological consequences analyses model release from this point.
15A-13 Revision 1
Horizontal Straight-Line Distance To Receptor Release Control Room Annex Building Elevation HVAC Intake Access Source Note 1 (Elevation 19.9 m) (Elevation 1.5 m)
Description (m) (1) (2) Comment t Vent ( 1) 55.7 147.2 ft 379.3 ft (44.9 m) (115.6 m)
Air Diffuser ( 2) 69.8 118.1 ft 343.2 ft (36.0 m) (104.6 m)
Building ( 3) 17.4 203.2 ft 427.4 ft Note 3 out Panel (61.9 m) (130.3 m) waste Building ( 4) 1.5 218.5 ft 433.5 ft Note 3 k Staging (66.6 m) (132.1 m)
Door m Vent ( 5) 17.1 61.5 ft 261.6 ft (18.8 m) (79.7 m)
V/Safety ( 6) 19.2 66.9 ft 255.4 ft es (20.4 m) (77.8 m) denser Air ( 7) 38.4 198.3 ft 58.3 ft Note 3 oval Stack (60.4 m) (17.8 m) ainment Shell ( 8) Same as 42.0 ft 272.3 ft Note 2 use Area Receptor (12.8 m) (83.0 m) ce) Elevation (19.9 m or 1.5 m) s:
All elevations relative to grade at 0.0 m.
For calculating distance, the source is defined as the point on the containment shell closest to receptor.
Vertical distance traveled is conservatively neglected.
- Refer to Symbols on Figure 15A-1.
- Refer to Symbols on Figure 15A-1.
15A-14 Revision 1
Figure 15A-1 Site Plan with Release and Intake Locations 15A-15 Revision 1
AP1000 design does not depend on active systems to remove airborne particulates or elemental ne from the containment atmosphere following a postulated loss-of-coolant accident (LOCA) with melt. Naturally occurring passive removal processes provide significant removal capability such airborne elemental iodine is reduced to very low levels within a few hours and the airborne iculates are reduced to extremely low levels within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
.1 Elemental Iodine Removal mental iodine is removed by deposition onto the structural surfaces inside the containment. The oval of elemental iodine is modeled using the equation from the Standard Review Plan ference 1):
KwA d =
V re:
= first order removal coefficient by surface deposition
= mass transfer coefficient (specified in Reference 1 as 4.9 m/hr)
= surface area available for deposition
= containment building volume available deposition surface is 251,000 ft2, and the containment building net free volume is x 106 ft3. From these inputs, the elemental iodine removal coefficient is 1.9 hr-1.
sistent with the guidance of Reference 1, credit for elemental iodine removal is assumed to tinue until a decontamination factor (DF) of 200 is reached in the containment atmosphere.
ause the source term for the LOCA (defined in Subsection 15.6.5.3) is modeled as a gradual ase of activity into the containment, the determination of the time at which the DF of 200 is hed needs to be based on the amount of elemental iodine that enters the containment osphere over the duration of core activity release.
.2 Aerosol Removal deposition removal of aerosols from the containment atmosphere is accomplished by a number rocesses including sedimentation, diffusiophoresis, and thermophoresis. All three of the osition processes are significant contributors to the overall removal process in the AP1000. The e contributions from diffusiophoresis and thermophoresis to the total removal are a direct sequence of the high heat transfer rates from the containment atmosphere to the containment that characterize the passive containment cooling system.
ause of the AP1000 passive containment cooling system design, there are high sensible heat sfer rates (resulting in higher thermophoretic removal of aerosols) when condensational heat sfer is low (and the aerosol removal by diffusiophoresis is also low). The reverse is also true.
s, there is an appreciable deposition removal throughout the accident from either diffusiophoresis hermophoresis, in addition to the removal by sedimentation.
15B-1 Revision 1
.2.1.1 Sedimentation vitational sedimentation is a major mechanism of aerosol removal in a containment. A standard el (Stokes equation with the Cunningham slip correction factor) for this process is used. The kes equation (Reference 2) is:
2 p g r 2 Cn s =
9 re:
= settling velocity of an aerosol particle
= material density of the particle
= gravitational acceleration
= particle radius
= gas viscosity
= Cunningham slip correction factor, a function of the Knudsen number (Kn) which is the gas molecular mean free path divided by the particle radius ever, the Stokes equation makes the simplifying assumption that the particles are spherical. The icles are expected to be nonspherical, and it is conventional to address this by introducing a amic shape factor" (Reference 2) in the denominator of the Stokes equation, such that the ling velocity for the nonspherical particle is the same as for a spherical particle of equal volume.
value of the dynamic shape factor () thus depends on the shape of the particle and, in general, t be experimentally determined.
concept of dynamic shape factor can also be applied to a spherical particle consisting of two ponents, one of which has the density of the particle material, while the other component has a rent density (Reference 9). In this manner, the impact of the void fraction in the particle can be eled. Thus, the revised Stokes equation is:
2 p g r 2 Cn s =
9 derivation of follows.
two-component particle is considered to have a density av and an effective radius of re.
uming that the second component of the particle is the void volume and letting the void fraction
, then the average density of the particle is:
15B-2 Revision 1
= density of the void material (0.0 for gas filled, 1.0 for water filled)
= void fraction
= material density (solid particle with no voids) definition of is obtained from the Stokes equation and the equation for mass of a sphere:
2 p gr 2 Cn 2 av gre2 Cn
=
9 9 ch reduces to:
p r 2 = av re2 4 p r03 4 av re3
=
3 3 ch reduces to:
p r03 = av re3 n:
p r 2
=
av re2 1 / 3 re = r av p
15B-3 Revision 1
1 / 3
= av p
.2.1.2 Diffusiophoresis usiophoresis is the process whereby particles are swept to a surface (for example, containment
) by the flow set up by a condensing vapor (Stefan flow). The deposition rate is independent of particle size and is proportional to the steam condensation rate on the surface. The standard ation for this phenomenon is due to Waldmann and Schmitt (Reference 3):
Mv W d =
M v + a/v M a v re:
= diffusiophoretic deposition velocity
= ratio of mole fraction of air to mole fraction of steam in the containment atmosphere
= molecular weight of steam
= molecular weight of air
= steam condensation rate on the wall
= mass density of steam in the containment atmosphere ause of the design of the passive containment cooling system, steam condensation rates are at certain times in the design basis LOCA; thus at these times, diffusiophoretic deposition rates significant.
.2.1.3 Thermophoresis rmophoresis is the process whereby particles drift toward a surface (for example, the tainment wall) under the influence of a temperature gradient in the containment atmosphere at surface. The effect arises because the gas molecules on the hot side of the particles undergo e collisions with the particle than do those on the cold side. Therefore, there is a net momentum sfer to the particle in the hot-to-cold direction. There are several models in the literature for this ct; the one used is the Brock equation in a form due to Talbot et al. (Reference 4). As indicated w, this model is in agreement with experimental data. The thermophoretic deposition rate is ewhat dependent on particle size and is proportional to the temperature gradient at the wall, or ivalently, the sensible heat transfer rate to the wall. The Talbot equation is:
15B-4 Revision 1
[1 + 2( + CT Kn)][1 + 3 CM Kn] T dy re:
= thermophoretic deposition velocity
= kg/kp which is the ratio of the thermal conductivities of the gas (evaluated at the gas temperature at each time step) and the aerosol particle (kp is set equal to the thermal conductivity of water - the results are not sensitive to kp or .)
= Knudsen number (equal to the gas molecular mean free path divided by the particle radius)
= Cunningham slip correction factor, a function of the Knudsen number
= gas viscosity
= gas density
= slip accommodation coefficient (Reference 4 gives the best value as 1.17.)
= thermal accommodation coefficient (Reference 4 gives the best value as 2.18.)
= momentum accommodation coefficient (Reference 4 gives the best value as 1.14.)
temperature gradient at the wall, dT/dy, can be evaluated as dT s
=
dy k g re s is the sensible heat flux to the wall, and kg is the thermal conductivity of the gas. The sible heat flux used in the analysis is the convective heat transfer calculated as discussed in section 15B.2.4.7.
.2.2 Other Removal Mechanisms ddition to the above mechanisms, there are others that were not considered, including turbulent sion and turbulent agglomeration. The neglect of these mechanisms adds further conservatism e calculation.
.2.3 Validation of Removal Mechanisms aerosol processes are well established and have been confirmed in many separate effects eriments, which are discussed in standard references (References 2 through 4). The Stokes ula for sedimentation velocity has been well confirmed for particles whose diameters are less about 50 m. In the present calculations, these make up basically all of the aerosol.
15B-5 Revision 1
siophoresis is taken into account. If it is neglected, the predicted plated mass is about two orders agnitude too small, compared to the observed plated mass.
Talbot equation for the thermophoretic effect has been experimentally confirmed to within about o 50 percent over a wide range of particle sizes (Reference 4). The temperature gradient at the
, which drives this phenomenon, can be approximated by the temperature difference between the gas and the wall divided by an appropriate length scale obtained from heat transfer correlations.
rnatively, because sensible heat transfer rates to the wall are available, it is easier and more urate to use these rates directly to infer the temperature gradient.
.2.4 Parameters and Assumptions for Calculating Aerosol Removal Coefficients parameters and assumptions were selected to conservatively model the environment that would xpected to exist as a result of a LOCA with concurrent core melt.
.2.4.1 Containment Geometry containment is assumed to be a cylinder with a volume of 55,481 m3 (1.959 x 106 ft3). This me includes those portions of the containment volume that would be participating in the aerosol sport and mixing; this excludes dead-ended volumes and flooded compartments. The horizontal ace area available for aerosol deposition by sedimentation is 2900 m2 (31,200 ft2). This includes ecting areas such as decks in addition to the floor area and excludes areas in dead-ended mes and areas that would be flooded post-LOCA. The surface area for Brownian diffusive eout of aerosols is 8008 m2 (86,166 ft2).
.2.4.2 Source Size Distribution aerosol source size distribution is assumed to be lognormal, with a geometric mean radius of m and a geometric standard deviation equal to 1.81. These values are derived from an luation of a large number of aerosol distributions measured in a variety of degraded-fuel tests and eriments. The sensitivity of aerosol removal coefficient calculations to these values is small.
.2.4.3 Aerosol Void Fraction iew of scanning electron microscope photographs of deposited aerosol particles from actual core t and fission product vaporization and aerosolization experiments (the Argonne STEP-4 test and INEL Power Burst Facility SFD 1-4 test) indicates that the deposited particles are relatively se, supporting a void fraction of 0.2.
above-mentioned test results indicate that a void fraction of 0.2 is appropriate for modeling the osols resulting from a core melt. As part of the sensitivity study that was performed for the AP600 ect, a case was run with a void fraction of 0.9. That analysis showed that the high void fraction lted in an integrated release of aerosols over a 24-hour period that was less than 14 percent ater than that calculated when using the void fraction of 0.2. Thus, it is clear that the removal of osols from the containment atmosphere is not highly sensitive to the value selected for the void tion. This is largely due to the fact that, while the selected value for void fraction has a significant act on the calculated sedimentation removal, the impact on thermophoresis and diffusiophoresis oval is slight or none. The impact for AP1000 of using the higher value for void fraction would be than was determined for the AP600 since sedimentation removal comprises a smaller fraction of total removal calculated for the AP1000.
15B-6 Revision 1
.2.4.4 Fission Product Release Fractions e inventories of fission products are from ORIGEN calculations for the AP1000 at end of the fuel
- e. Fractional releases to the containment of the fission products are those specified in section 15.6.5.3.
.2.4.5 Inert Aerosol Species inert species include SnO2, UO2, Cd, Ag, and Zr. These act as surrogates for all inert materials ing aerosols. The ratio of the total mass of inert species to fission product species was assumed e 1.5:1. This value and the partitioning of the total inert mass among its constituents are sistent with results from degraded fuel experiments (Reference 6).
.2.4.6 Aerosol Release Timing and Rates osol release timing is in accordance with the source term defined in Subsection 15.6.5.3. Aerosol ase takes place in two main phases: a gap release lasting for 0.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, followed by an early essel release of 1.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> duration. During each phase, the aerosols are assumed to be released constant rate. These rates were obtained for each species by combining its core inventory, ase fraction, and times of release.
y cesium and iodine are released during the gap release phase. During the in-vessel release se, the other fission product and inert species are released as well.
.2.4.7 Containment Thermal-Hydraulic Data thermal-hydraulic parameters used in the aerosol removal calculation are the containment gas perature, the containment pressure, the steam condensation rate on the wall, the steam mole tion, and the convective heat transfer rate, all as functions of time. The AP1000-specific ameters were obtained using MAAP4 (Reference 7) for the 3BE-1 severe accident sequence dium LOCA with failure to inject water from the refueling water storage tank into the reactor sel). The thermal-hydraulic data are thus consistent with a core melt sequence.
.2.5 Aerosol Removal Coefficients aerosol removal coefficients are provided in Table 15B-1 starting at the onset of core damage ugh 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The removal coefficients for times beyond 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are not of concern because e would be so little aerosol remaining airborne at that time. The values range between 0.29 hr-1 1.1 hr-1 during the time between the onset of core damage (0.167 hour0.00193 days <br />0.0464 hours <br />2.761243e-4 weeks <br />6.35435e-5 months <br />) and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
se removal coefficients conservatively neglect steam condensation on the airborne particles, ulent diffusion, and turbulent agglomeration. Additionally, the assumed source aerosol size is servatively small being at the low end of the mass mean aerosol size range of 1.5 to 5.5 m used UREG/CR-5966 (Reference 8). Selection of smaller aerosol size would underestimate imentation.
ke the case for the elemental iodine removal, there is no limit assumed on the removal of osols from the containment atmosphere.
15B-7 Revision 1
Cleanup System."
Fuchs, N. A., The Mechanics of Aerosols, Pergamon Press, Oxford, 1964.
Waldmann, L., and Schmitt, K. H., "Thermophoresis and Diffusiophoresis of Aerosols,"
Aerosol Science, C. N. Davies, ed., Academic Press, 1966.
Talbot, L., Chang, R. K., Schefer, R. W., and Willis, D. R., "Thermophoresis of Particles in a Heated Boundary Layer," J. Fluid Mech. 101, 737-758 (1980).
Rahn, F. J., "The LWR Aerosol Containment Experiments (LACE) Project," Summary Report, EPRI-NP-6094D, Electric Power Research Institute, Palo Alto, Nov. 1988.
Petti, D. A., Hobbins, R. R., and Hagrman, D. L., "The Composition of Aerosols Generated during a Severe Reactor Accident: Experimental Results from the Power Burst Facility Severe Fuel Damage Test 1-4," Nucl. Tech. 105, p.334 (1994).
MAAP4 - Modular Accident Analysis Program for LWR Power Plants, Computer Code Manual, May 1994.
Powers D. A., and Burson, S. B., "A Simplified Model of Aerosol Removal by Containment Sprays," NUREG/CR-5966, June 1993.
Powers, D. A., "Monte Carlo Uncertainty Analysis of Aerosol Behavior in the AP600 Reactor Containment under Conditions of a Specific Design-Basis Accident, Part 1,"
Technical Evaluation Report, Sandia National Laboratories, June 1995.
15B-8 Revision 1
Following a Design Basis LOCA With Core Melt Time Interval (hours) Removal Coefficient (hr-1) 0.167 - 0.179 1.141 0.179 - 0.200 1.013 0.200 - 0.251 0.944 0.251 - 0.292 0.882 0.292 - 0.433 0.842 0.433 - 0.631 0.901 0.631 - 0.684 0.821 0.684 - 0.801 0.781 0.801 - 0.893 0.735 0.893 - 1.033 0.699 1.033 - 1.171 0.662 1.171 - 1.233 0.627 1.233 - 1.331 0.594 1.331 - 1.395 0.562 1.395 - 1.429 0.551 1.429 - 1.475 0.576 1.475 - 1.519 0.537 1.519 - 1.579 0.510 1.579 - 1.653 0.483 1.653 - 1.776 0.458 1.776 - 1.903 0.430 1.903 - 1.991 0.462 1.991 - 2.067 0.429 2.067 - 2.176 0.396 2.176 - 2.371 0.380 2.371 - 2.621 0.337 2.621 - 2.822 0.320 2.822 - 2.872 0.357 2.872 - 2.973 0.327 2.973 - 3.176 0.302 3.176 - 3.684 0.287 3.684 - 3.737 0.328 3.737 - 3.839 0.304 3.839 - 3.990 0.298 3.990 - 4.090 0.317 15B-9 Revision 1
Time Interval (hours) Removal Coefficient (hr-1) 4.090 - 4.438 0.346 4.438 - 4.684 0.369 4.684 - 4.880 0.396 4.880 - 4.928 0.449 4.928 - 5.362 0.435 5.362 - 5.460 0.459 5.460 - 5.511 0.518 5.511 - 5.608 0.487 5.608 - 6.040 0.479 6.040 - 6.090 0.537 6.090 - 6.615 0.506 6.615 - 6.753 0.567 6.753 - 7.194 0.513 7.194 - 7.285 0.594 7.285 - 7.814 0.518 7.814 - 7.904 0.581 7.904 - 8.431 0.528 8.431 - 8.521 0.589 8.521 - 9.387 0.529 9.387 - 9.553 0.568 9.553 - 11.189 0.530 11.189 - 14.937 0.516 14.937 - 17.610 0.506 17.610 - 24 0.492 15B-10 Revision 1