ML17033B531

North Anna Power Station, Units 1 and 2 - Redacted Updated Final Safety Analysis Report Chapter 7

ML17033B531
Person / Time
Site:	North Anna
Issue date:	09/29/2016
From:	V Sreenivas Plant Licensing Branch II
To:	Heacock D A Virginia Electric & Power Co (VEPCO)
Sreenivas V, NRR/DORL/LPL2-1, 415-2597
Shared Package
ML17033B477	List: ML17033B480 ML17033B492 ML17033B500 ML17033B509 ML17033B515 ML17033B518 ML17033B525 ML17033B531 ML17033B533 ML17033B540 ML17033B545 ML17033B550 ML17033B570 ML17033B573 ML17033B575 ML17033B583 ML17033B585 ML17033B590 ML17033B591
References
Download: ML17033B531 (222)

Text

North Anna Power Station Updated Final Safety Analysis ReportChapter 7 Intentionally Blank Intentionally Blank Revision 52-09/29/2016NAPS UFSAR7-i

7.1INTRODUCTION

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-17.1.1Definitions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-27.1.2Identification of Safety-Related Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-47.1.3Identification of Safety Criteria. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-57.1.3.1Design Criteria Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-57.1.3.2Reactor Trip System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-57.1.3.3Engineered Safety Features Actuation System . . . . . . . . . . . . . . . . . . . . . . . .7.1-77.1.3.4Instrumentation and Control Power Supply . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-107.1.3.5Quality Assurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-107.1.3.6Safety-Related Equipment Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-107.1.4Regulatory Guide1.97 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-117.1References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-137.1Reference Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.1-147.2REACTOR TRIP SYSTEM. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-17.2.1Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-17.2.1.1Reactor Trips. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-37.2.1.2Reactor Trip System Accuracies and Response Times. . . . . . . . . . . . . . . . . .7.2-117.2.1.3Reactor Trip System Interlocks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-117.2.1.4Coolant Temperature Sensor Arrangement. . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-127.2.1.5Pressurizer Water Level Reference Leg Arrangement . . . . . . . . . . . . . . . . . .7.2-127.2.1.6Analog System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-12 7.2.1.7Digital Logic System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-12 7.2.1.8Isolation Amplifiers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-137.2.1.9Energy Supply and Environmental Variations . . . . . . . . . . . . . . . . . . . . . . . .7.2-137.2.1.10Trip Setpoints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-13 7.2.1.11Seismic Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-137.2.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-137.2.2.1Evaluation of Design. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-137.2.2.2Evaluation of Compliance to Applicable Codes and Standards . . . . . . . . . . .7.2-177.2.2.3Specific Control and Protection Interactions. . . . . . . . . . . . . . . . . . . . . . . . . .7.2-257.2.3Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-29 7.2.3.1Inservice Tests and Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-29 7.2.3.2Periodic Testing of the Nuclear Instrumentation System . . . . . . . . . . . . . . . .7.2-297.2.3.3Periodic Testing of the Process Analog Channels of the Protection Circuits .7.2-29Chapter 7: Instrumentation and ControlTable of ContentsSectionTitlePage Revision 52-09/29/2016NAPS UFSAR7-iiChapter 7: Instrumentation and ControlTable of Contents (continued)SectionTitlePage7.2.3.4Safety Guide22. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-297.2References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-307.3ENGINEERED SAFETY FEATURES ACTUATION SYSTEM. . . . . . . . . . . . .7.3-17.3.1Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-1 7.3.1.1Functional Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-17.3.1.2Design Bases: IEEE Std279-1971 (Reference2). . . . . . . . . . . . . . . . . . . . . .7.3-37.3.1.3Implementation of Functional Design. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-57.3.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-207.3.2.1Evaluation of Compliance With IEEE Std279-1971 (Reference2). . . . . . . .7.3-207.3.2.2Evaluation of Compliance With IEEE Std308-1969 (Reference5). . . . . . . .7.3-257.3.2.3Evaluation of Compliance With IEEE Std323-1971 (Reference6). . . . . . . .7.3-257.3.2.4Evaluation of Compliance With IEEE Std334-1971 (Reference7). . . . . . . .7.3-257.3.2.5Evaluation of Compliance With IEEE Std338-1971 (Reference8). . . . . . . .7.3-257.3.2.6Evaluation of Compliance With IEEE Std344-1971 (Reference9). . . . . . . .7.3-257.3.2.7Evaluation of Compliance With IEEE Std317-1971 (Reference10). . . . . . .7.3-257.3.2.8Evaluation of Compliance With IEEE Std336-1971 (Reference11). . . . . . .7.3-26 7.3.2.9Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-267.3.2.10Automatic Changeover From Injection Mode to Recirculation Mode After Loss of Primary Coolant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-287.3.2.11Inside and Outside Recirculation Spray Pump Start Function . . . . . . . . . . . .7.3-297.3.2.12Casing Cooling Tank Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-307.3References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-307.3Reference Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-317.4SYSTEMS REQUIRED FOR SAFE SHUTDOWN . . . . . . . . . . . . . . . . . . . . . . .7.4-17.4.1Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.4-17.4.1.1Design Considerations for the Auxiliary Shutdown Panel . . . . . . . . . . . . . . .7.4-17.4.1.2Auxiliary Shutdown Instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.4-37.4.1.3Equipment and Services and Approximate Time Required After Incident That Requires Hot Shutdown. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.4-47.4.1.4Equipment and Systems Available for Cold Shutdown . . . . . . . . . . . . . . . . .7.4-47.4.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.4-5 Revision 52-09/29/2016NAPS UFSAR7-iiiChapter 7: Instrumentation and ControlTable of Contents (continued)SectionTitlePage7.5SAFETY-RELATED DISPLAY INSTRUMENTATION. . . . . . . . . . . . . . . . . . .7.5-17.5.1Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.5-17.5.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.5-17.6ALL OTHER SYSTEMS REQUIRED FOR SAFETY. . . . . . . . . . . . . . . . . . . . .7.6-17.6.1Instrumentation and Control Power Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-17.6.2Residual Heat Removal System Inlet MOV Interlocks . . . . . . . . . . . . . . . . . . .7.6-17.6.2.1Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-1 7.6.2.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-17.6.3Reactor Coolant System Loop Isolation Valve Interlocks . . . . . . . . . . . . . . . . .7.6-27.6.3.1Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-27.6.3.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-27.6.4Main Control Room, Relay Room, and Emergency Switchgear Room Air Conditioning, Heating, and Ventilation System Instrumentation and Controls. . . . . . . . . . . . .7.6-37.6.4.1Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-3 7.6.4.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-37.6.5Refueling Interlocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-37.6.6Accumulator Isolation Valve Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-37.6.7Pressurizer Relief Valve Flow Indication. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-47.6References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-57.7PLANT CONTROL SYSTEMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-1 7.7.1Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-17.7.1.1Reactor Control System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-37.7.1.2Rod Control System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-3 7.7.1.3Plant Control Signals for Monitoring and Indicating . . . . . . . . . . . . . . . . . . .7.7-57.7.1.4Plant Control System Interlocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-8 7.7.1.5Pressurizer Pressure Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-97.7.1.6Pressurizer Water-Level Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-107.7.1.7Steam Generator Water-Level Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-10 7.7.1.8Steam Dump Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-10 7.7.1.9Incore Instrumentation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-12 7.7.1.10Computer System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-147.7.1.11Process Instrumentation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-157.7.1.12Control Stations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-15 Revision 52-09/29/2016NAPS UFSAR7-ivChapter 7: Instrumentation and ControlTable of Contents (continued)SectionTitlePage7.7.1.13Control Room Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-187.7.1.14Anticipated Transient Without Scram (ATWS) Mitigation System Description7.7-227.7.2Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-247.7.2.1Separation of Protection and Control Systems . . . . . . . . . . . . . . . . . . . . . . . .7.7-257.7.2.2Reactivity Control Considerations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-257.7.2.3Step-Load Changes Without Steam Dump . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-277.7.2.4Loading and Unloading. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-287.7.2.5Load Rejection Furnished by Steam Dump System . . . . . . . . . . . . . . . . . . . .7.7-287.7.2.6Turbine Trip with Reactor Trip. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-297.7References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-307.7Reference Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-307.8EMERGENCY RESPONSE TO ACCIDENTS. . . . . . . . . . . . . . . . . . . . . . . . . . .7.8-17.9INADEQUATE CORE COOLING MONITOR (ICCM) SYSTEM. . . . . . . . . . .7.9-17.9.1Design Bases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.9-17.9.2Design Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.9-1 7.9.2.1Core Exit Thermocouple (CET) System-Subsystem of ICCM System . . . .7.9-17.9.2.2Reactor Vessel Level Instrumentation Systems (RVLIS)-Subsystem of ICCMSystem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.9-27.9.2.3Core Cooling Monitor System-Subsystem of ICCM System. . . . . . . . . . . .7.9-37.9References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.9-4 Revision 52-09/29/2016NAPS UFSAR7-vChapter 7: Instrumentation and ControlList of TablesTableTitlePageTable7.2-1List of Reactor Trips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-32Table7.2-2Reactor Trip System Accuracies and Ranges . . . . . . . . . . . . . . . . . . . .7.2-34Table7.2-3Reactor Trip System Interlocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-36Table7.2-4Trip Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-37Table7.2-5Reactor Trip System Instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-40Table7.3-1Interlocks for Engineered Safety Features Actuation System. . . . . . . .7.3-33Table7.3-2Engineered Safety Feature Actuation System Instrumentation. . . . . . .7.3-34Table7.5-1Main Control Board Indicators and/or Recorders Availableto the Operator Condition II and III Events. . . . . . . . . . . . . . . . . . . . . .7.5-5Table7.5-2Main Control Board Indicators and/or Recorders Availableto the Operator Condition IV Events. . . . . . . . . . . . . . . . . . . . . . . . . . .7.5-8Table7.5-3Control Room Indicators and/or Recorders Available to the Operatorto Monitor Significant Plant Parameters During Normal Operation. . .7.5-13Table7.7-1Plant Control System Interlocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-31Table7.7-2Auxiliary Shutdown Panel Monitoring Instrumentationa . . . . . . . . . . .7.7-32Table7.9-1Inadequate Core Cooling Monitor (ICCM) System Data . . . . . . . . . . .7.9-5 Revision 52-09/29/2016NAPS UFSAR7-viChapter 7: Instrumentation and ControlList of FiguresFigureTitlePageFigure 7.2-1Index and Symbols. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-42Figure 7.2-2Reactor Trip Signals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-43Figure 7.2-3Nuclear Instrumentation and Trip Signals. . . . . . . . . . . . . . . . . . . . . .7.2-44Figure 7.2-4Setpoint Reduction Function for Overtemperature T Trips (Typical)7.2-45Figure 7.2-5Primary Coolant System Trip Signals . . . . . . . . . . . . . . . . . . . . . . . . .7.2-46Figure 7.2-6Pressurizer Trip Signals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-47Figure 7.2-7Steam Generator Trip Signals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-48Figure 7.2-8Turbine Trips, Runbacks, and Other Signals. . . . . . . . . . . . . . . . . . . .7.2-49Figure 7.2-9Safeguards Actuation Signals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-50 Figure 7.2-10Nuclear Instrumentation and Blocks . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-51 Figure 7.2-11Pressurizer Reference Leg Level System. . . . . . . . . . . . . . . . . . . . . . .7.2-52Figure 7.2-12Design to Achieve Isolation Between Channels . . . . . . . . . . . . . . . . .7.2-53Figure 7.2-13Anticipated Transient without Scram Mitigation System Actuation Circuitry (AMSAC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.2-54Figure 7.3-1Logic Diagram Motor Driven Steam Generator Auxiliary Feed Pumps7.3-37Figure 7.3-2Unit Trip Signal Interfaces. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-38Figure 7.3-3Engineered Safety Features Signal Interfaces . . . . . . . . . . . . . . . . . . .7.3-39Figure 7.3-4Signal Paths to ESF Actuated Devices . . . . . . . . . . . . . . . . . . . . . . . .7.3-40Figure 7.3-5Loss and Restoration of Emergency Bus. . . . . . . . . . . . . . . . . . . . . . .7.3-41Figure 7.3-6Diesel Load and Sequencing Conditioning Concept. . . . . . . . . . . . . .7.3-42Figure 7.3-7Reserve Station Service-Undervoltage . . . . . . . . . . . . . . . . . . . . . . . .7.3-43Figure 7.3-8Removal of Unnecessary Load from Emergency Bus During Containment Depressurization7.3-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-44Figure 7.3-9Station Service-Undervoltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.3-45Figure 7.3-10Engineered Safety Features Blocking Logic . . . . . . . . . . . . . . . . . . . .7.3-46Figure 7.3-11Normally Closed Containment Isolation Trip Valves . . . . . . . . . . . . .7.3-47 Figure 7.3-12Logic Diagram Turbine Driven-Steam Generator Auxiliary Feed Pump7.3-48Figure 7.3-13Logic Diagram Normally Open Containment Isolation Valves. . . . . .7.3-49Figure 7.3-14ECCS Logic/Automatic Switchover fromInjection Phase to Recirculation Phase . . . . . . . . . . . . . . . . . . . . . . . .7.3-50 Revision 52-09/29/2016NAPS UFSAR7-viiChapter 7: Instrumentation and ControlList of Figures (continued)FigureTitlePageFigure 7.4-1Switching Logic, Sheet 1, for Transfer Between Main Control Board and Auxiliary Shutdown Panel (for Switchgear (Typical)). . . . . . . . .7.4-6Figure 7.4-2Switching Logic, Sheet 2, for Transfer Between Main Control Board and Auxiliary Shutdown Panel [for Switchgear (Typical)]. . . . . . . . .7.4-7Figure 7.6-1Loop Stop Valve Interlocks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6-6Figure 7.6-2Typical Reactor Coolant System Loop With Loop Stop Valves. . . . .7.6-7Figure 7.6-3Functional Block Diagram for Opening Accumulator Isolation Valve7.6-8Figure 7.7-1Simplified Block Diagram of Reactor Control System. . . . . . . . . . . .7.7-33Figure 7.7-2Rod Controls and Rod Blocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-34Figure 7.7-3Control Bank Rod Insertion Monitor. . . . . . . . . . . . . . . . . . . . . . . . . .7.7-35Figure 7.7-4Rod Deviation Comparator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-36Figure 7.7-5Steam Dump Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-37Figure 7.7-6Pressurizer Pressure and Level Control. . . . . . . . . . . . . . . . . . . . . . . .7.7-38Figure 7.7-7Pressurizer Heater Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-39Figure 7.7-8Feedwater Control and Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-40 Figure 7.7-9Block Diagram of Pressurizer Pressure Control System. . . . . . . . . . .7.7-41Figure 7.7-10Block Diagram of Pressurizer Level Control System . . . . . . . . . . . . .7.7-42Figure 7.7-11Block Diagram of Steam Generator Water Level Control System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-43Figure 7.7-12Block Diagram of Steam Dump Control System. . . . . . . . . . . . . . . . .7.7-44Figure 7.7-13Basic Flux-Mapping System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-45 Revision 52-09/29/2016NAPS UFSAR7-viiiIntentionally Blank Revision 52-09/29/2016NAPS UFSAR7.1-1CHAPTER 7INSTRUMENTATION AND CONTROLS

7.1INTRODUCTION

Note: As required by the Renewed Operating Licenses for NorthAnna Units1 and2, issuedMarch20,2003, various systems, structures, and components discussed within this chapter aresubject to aging management. The programs and activities necessary to manage the aging of thesesystems, structures, and components are discussed in Chapter18.This chapter describes the various plant instrumentation and control systems by presentingthe functional performance requirements, design bases, system descriptions, design evaluations,and tests and inspections for each. The information provided in this chapter applies particularly tothose instruments and associated equipment that constitute the protection system as defined inInstitute of Electrical and Electronics Engineers (IEEE) IEEE Std279-1971, IEEE Standard:Criteria for Protection Systems for Nuclear Power Generating Stations.The primary purpose of the instrumentation and control systems is to provide automaticprotection against unsafe and improper reactor operation during steady-state and transient poweroperations (American Nuclear Society (ANS) ConditionsI, II, III) and to provide initiatingsignals to mitigate the consequences of faulted conditions (ANS ConditionIV). (See Chapter15for a discussion of the ANS conditions.) Consequently, the information presented in this chapteremphasizes those instrumentation and control systems that are central to ensuring that the reactorcan be operated to produce power in a manner that ensures no undue risk to the health and safetyof the public.It is shown that the applicable criteria and codes concerned with the safe generation ofnuclear power, such as the Atomic Energy Commission's (AEC) General Design Criteria andIEEE Standards, were met by these systems.Instrument loops which support safety-related functions include both those which initiate aprotective action, such as a reactor trip or a safety injection, and also those which are used tomonitor Technical Specifications or other safety-related parameters. Instrumentation loopsinclude both analog and digital instrumentation signals that initiate protective actions thatrepresent acceptable conditions of the physical processes. The Technical Specification describesand limits appropriate parameters. Appropriately selected reactor protection setpoints andassociated analog instrument signal uncertainties define the bases upon which safety isestablished and proved by the UFSAR Chapter15 analysis. The verification of actual allowableanalog instrumentation signal uncertainties must consider various instrumentation hardwareconstraints when proving appropriate analog channel statistical allowances. Examples of thekinds of hardware considerations that determine the proper accuracy are as follows:*Transmitter model Revision 52-09/29/2016NAPS UFSAR7.1-2*Calibration tolerances, methods, and frequencies*Measurement and test equipment ranges and accuracies*Loop scalingThese hardware considerations have all been accounted for in verifying the allowableinstrument uncertainty associated with each safety-related instrument loop.7.1.1DefinitionsThe definitions below establish the meaning of words in the context of their use inChapter7.Channel - An arrangement of components and modules as required to generate a singleprotective action signal when required by a generating station condition. A channel loses itsidentity where single-action signals are combined.

Module - Any assembly of interconnected components that constitutes an identifiable device,instrument, or piece of equipment. A module can be disconnected, removed as a unit, andreplaced with a spare. It has definable performance characteristics that permit it to be tested as aunit. A module can be a card or other subassembly of a larger device, provided it meets therequirements of this definition.

Components - Items from which the system is assembled (e.g., resistors, capacitors, wires,connectors, transistors, tubes, switches, springs).

Single Failure - Any single event that results in a loss of function of a component or componentsof a system. Multiple failures resulting from a single event shall be treated as a single failure.Protective Action - A protective action can be at the channel or the system level. A protectiveaction at the channel level is the initiation of a signal by a single channel when the variable sensedexceeds a limit. A protective action at the system level is the initiation of the operation of asufficient number of actuators to effect a protective function.Protective Function - A protective function is the sensing of one or more variables associatedwith a particular generating station condition, signal processing, and the initiation and completionof the protective action at values of the variable established in the design basis.Type Tests - Tests made on one or more units to verify adequacy of design.Degree of Redundancy - The difference between the number of channels monitoring a variableand the number of channels that, when tripped, will cause an automatic system trip.

Revision 52-09/29/2016NAPS UFSAR7.1-3Cold-Shutdown Condition - When the reactor is subcritical by at least 1% deltak/k and Tavg is200°F.Hot-Shutdown Condition - When the reactor is subcritical by an amount greater than or equal tothe margin specified in the Technical Specifications, and Tavg is greater than or equal to thetemperature specified in the Technical Specifications.Containment Isolation PhaseA - Closure of all nonessential process lines that penetratecontainment. Initiated by the safety injection activation signal.Containment Isolation PhaseB - Closure of remaining process lines. Initiated by containmenthigh-high-pressure signal (process lines do not include engineered safety features lines).Trip Accuracy - The tolerance band of the difference between (1)the desired trip point value of aprocess variable, and (2)the actual value at which a comparator trips (and thus actuates somedesired result).Technically, trip accuracy describes the maximum inaccuracy or maximum uncertaintyassociated with the desired trip setpoint. Trip accuracy is usually expressed in percent ofinstrument span. Trip accuracy identifies, in both the positive and negative directions, the furthestpoint from the desired trip setpoint at which trip actuation could occur. This is also referred to asthe channel statistical allowance (CSA). Thus, the trip setpoint accuracy envelopes a range aroundthe desired trip setpoint within which an actual trip must occur.The following instrument loop error terms are included, as required, when determining tripaccuracy: systematic error, process measurement accuracy, primary element accuracy, sensorcalibration accuracy, sensor measuring and test equipment, sensor drift, sensor pressure effect,sensor temperature effect, sensor power supply effect, rack calibration accuracy, rack measuringand test equipment, rack temperature effect, rack drift, and environmental allowances. The use ofthese error terms are addressed in Reference6 and associated engineering standards orcalculations.Actuation Accuracy - Synonymous with trip accuracy, but used where the word "trip" may causeambiguity.

Indicated Accuracy - The tolerance band containing the highest expected value of the differencebetween (1)the value of a process variable read on an indicator or recorder and (2)the actualvalue of that process variable. The tolerance band includes the inaccuracies associated with theinstrument channel and the readout devices. It also includes process rack environmental effects,but does not include process effects such as fluid stratification.

Revision 52-09/29/2016NAPS UFSAR7.1-4Reproducibility - This term may be substituted for "accuracy" in the above definitions for thosecases where a trip value or indicated value need not be referenced to an actual process variablevalue, but rather to a previously established trip or indication value; this value is determined bytest.7.1.2Identification of Safety-Related SystemsThe instrumentation and control systems and supporting systems that are required tofunction to achieve the system responses assumed in the safety evaluations, and to shut down theplant safely, are the following:1.Reactor trip system, discussed in Section7.2.2.Engineered safety features actuation system, discussed in Section7.3.3.Vital ac power systems, discussed in Section8.3.1.2.4.Service water system, discussed in Section9.2.1.5.Air conditioning and ventilation systems for safety-related equipment, discussed inSection9.4.6.Charging pump auxiliary lube-oil pump.

7.Component cooling pumps, discussed in Section9.2.2.8.Onsite power system, discussed in Section8.3.The reactor trip system and the engineered safety features actuation system are functionallydefined systems. The functional descriptions of these systems are in Sections7.2 and7.3respectively. The equipment that provides the trip functions identified in Section7.2, Reactor TripSystem, is contained in the following:1.Process instrumentation and control system (Reference1).2.Nuclear instrumentation system (Reference2).3.Solid-state logic protection system (Reference3).4.Reactor trip switchgear (Reference3).5.Manual actuation circuit.The equipment that provides the actuation functions identified in Section 7.3, EngineeredSafety Features Actuation System, is contained in the following:1.Process instrumentation and control system. (Reference1).2.Solid-state logic protection system (Reference3).3.Engineered safety features test cabinet (Reference4).4.Manual actuation circuits.

Revision 52-09/29/2016NAPS UFSAR7.1-55.Actuation devices.7.1.3Identification of Safety Criteria7.1.3.1Design Criteria ComplianceThe compliance of safety-related systems with the following documents is discussed in theappropriate sections of Chapter7:1.General Design Criteria for Nuclear Power Plants, AppendixA to 10CFR50, July7,1971.2.Safety Guides for Water Cooled Nuclear Power Plants, Division of Reactor Standards,Atomic Energy Commission, October27,1971.3.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard: Criteria forProtection Systems for Nuclear Power Generating Stations, IEEE Std279-1971.4.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard Criteria for ClassIE Electric Systems for Nuclear Power Generating Stations, IEEE Std308-1971.5.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard for ElectricalPenetration Assemblies in Containment Structures for Nuclear Fueled Power GeneratingStations, IEEEStd 317-1971.6.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Standard: GeneralGuide for Qualifying ClassI Electric Equipment for Nuclear Power Generating Stations,IEEE Std323-1971.7.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Guide for TypeTests of Continuous-Duty ClassI Motors Installed Inside the Containment of Nuclear PowerGenerating Stations, IEEE Std334-1971.8.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard: Installation,Inspection, and Testing Requirements for Instrumentation and Electrical Equipment Duringthe Construction of Nuclear Power Generating Stations, IEEE Std336-1971.9.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Criteria for thePeriodic Testing of Nuclear Power Generating Station Protection Systems, IEEEStd338-1971.10.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Guide for SeismicQualification of Class1 Electric Equipment for Nuclear Power Generating Stations, IEEEStd344-1971.7.1.3.2Reactor Trip SystemThe reactor trip system acts to limit the consequences of ConditionII events (faults ofmoderate frequency such as loss of feedwater flow) by, at most, a shutdown of the reactor andturbine, with the plant capable of returning to operation after corrective action. The reactor trip Revision 52-09/29/2016NAPS UFSAR7.1-6system features impose a limiting boundary region to plant operation that ensures that the reactorsafety limits are not exceeded during ConditionII events and that these events can beaccommodated without developing into more severe conditions.7.1.3.2.1Functional Performance Requirements7.1.3.2.1.1Reactor Trips. The reactor trip system automatically initiates reactor trip as follows:1.Whenever necessary to prevent fuel damage from any anticipated malfunction(ConditionII).2.To limit core damage from infrequent faults (ConditionIII).3.So that the energy generated in the core is compatible with the design provisions to protectthe reactor coolant pressure boundary from limiting faults (ConditionIV).7.1.3.2.1.2Turbine Trips. The reactor trip system initiates a turbine trip signal whenever reactortrip is initiated to prevent the reactivity insertion that would otherwise result from excessivereactor system cooldown and to avoid unnecessary actuation of the engineered safety featuresactuation system.7.1.3.2.1.3Manual Trip. The reactor trip system provides for manual initiation of reactor trip byoperator action.7.1.3.2.1.4Feedwater Isolation. The reactor trip system provides a signal whenever reactor tripis initiated (in conjunction with interlockP-4), which closes main feedwater valves on Tavg belowsetpoint. The signal also prevents opening main feedwater valves that were closed by safetyinjection or high steam generator water level.7.1.3.2.1.5Safety Injection. The reactor trip system provides a signal whenever reactor trip isinitiated (in conjunction with interlockP-4), which automatically blocks the automaticre-actuation of safety injection (after safety injection has been reset).7.1.3.2.2Design BasesThe design requirements for the reactor trip system are derived by analyses of plantoperating and fault conditions where automatic rapid control rod insertion is necessary to preventor limit core or reactor coolant boundary damage. The design limits for this system are as follows:1.Minimum departure from nucleate boiling ratio (DNBR) shall not be less than the designDNBR limit as a result of any anticipated transient or malfunction (ConditionII faults).2.Power density shall not exceed the rated linear power density for ConditionII faults. SeeChapter4 for fuel design limits.3.The stress limit of the reactor coolant system for the various conditions shall be as specifiedin Chapter5.

Revision 52-09/29/2016NAPS UFSAR7.1-74.The release of radioactive material shall not be sufficient to interrupt or restrict public use ofthose areas beyond the exclusion radius as a result of any ConditionIII fault.5.For any ConditionIV fault, the release of radioactive material shall not result in an unduerisk to public health and safety.7.1.3.2.3Codes and StandardsThe reactor protection instrumentation meets IEEE criteria as set forth in IEEEStd279-1971, IEEE Standard: Criteria for Protection Systems for Nuclear Power GeneratingStations. 7.1.3.2.4Environmental RequirementsThe environmental design bases are given in Sections3.10 and3.11 and in IEEEStd279-1971. A list of the nuclear steam supply system (NSSS) protection channels required tooperate in the postaccident environment, and the required duration of operation, is included inSection3.11.In the NorthAnna Units1 and2 spaces containing Class1E equipment where Class1Eredundant ventilation or air conditioning systems are not provided and the temperature couldexceed that for which the Class1E equipment is qualified, a temperature monitoring system isprovided that will meet the following requirements:1.An alarm will occur in the control room when the qualified temperature range is exceeded.The necessary instrumentation:a.Is of high quality.b.Has testing facilities to verify its functional capability.c.Is powered from a reliable power source (semi-vital bus originating from an emergencybus).2.Operating procedures require the control room operator to log the receipt of all alarms, theaction taken, and the alarm clearing. The temperature in the alarmed area will be recordedperiodically, either manually or automatically, during the time that the temperature is abovethe alarm setpoint.For alarms of temperature exceeding the equipment qualification, an analysis will beprovided to demonstrate that the excess temperature has not degraded the equipment below alevel acceptable for continued operations.7.1.3.3Engineered Safety Features Actuation SystemThe engineered safety features (ESF) system acts to limit the consequences of ConditionIIIevents (infrequent faults such as primary coolant spillage from a small rupture that exceed normalcharging system makeup and require the actuation of the safety injection system). The ESF Revision 52-09/29/2016NAPS UFSAR7.1-8system also acts to mitigate ConditionIV events (limiting faults, which include the potential forsignificant release of radioactive material). The ESF system consists of the ESF actuation systemas discussed in Section7.3 and the ESF-actuated devices discussed in Chapter6.7.1.3.3.1Functional Performance Requirements7.1.3.3.1.1General Performance Requirements. Signals additional to those developed by thereactor trip system are generated by the ESF actuation system to protect against the effects (andreduce the consequences) of more serious types of accidents designated as ConditionIII andIVevents. These are serious abnormal conditions in the reactor coolant system, main steam system,or containment vessel, and include a loss-of-coolant accident (LOCA) or a steam-line break.The functional performance requirements for the ESF system are discussed in detail inChapter6.7.1.3.3.1.2Automatic Actuation Requirements. The primary functional requirement of the ESFactuation system is to receive input signals (information) from the various operating processeswithin the reactor plant and containment and automatically provide, as output, timely andeffective signals to actuate the various components and subsystems comprising the ESF actuateddevices. These output signals, in conjunction with the actuated devices, ensure that the ESFsystem will meet its performance objectives as outlined in Chapter6.The logic diagrams and functional diagrams represented in Reference Drawings1through15 and Figures7.2-5, 7.2-6, 7.2-7, 7.2-9, 7.3-1, 7.3-5, 7.3-7, 7.3-8, 7.3-10, 7.3-12,and7.3-14 provide a graphic outline of the functional requirements of the actuation system and itsdevices.7.1.3.3.1.3Manual Actuation Requirements. The ESF actuation system has provisions formanually initiating from the control room all of the functions of the ESF system. Manualactuation serves as backup to the automatic initiation and provides selective control of ESFservice features.

7.1.3.3.2Design BasesThe design bases for the engineered safety features are in Chapter6.

The following is a discussion of the design requirements imposed on the ESF actuationsystem by the design-base objectives.In addition to the requirements for a reactor trip for anticipated abnormal transients, theplant shall be provided with adequate instrumentation and controls to sense accident situationsand initiate the operation of necessary ESF-actuated devices. The occurrence of a limiting fault,such as a LOCA or a steam-line break, requires a reactor trip plus the actuation of one or more ofthe ESF actuation devices to prevent or mitigate damage to the core and reactor coolant systemcomponents and ensure containment integrity.

Revision 52-09/29/2016NAPS UFSAR7.1-9To accomplish these design objectives, the ESF system shall have proper and timelyinitiating signals supplied by the sensors, transmitters, and logic components making up thevarious instrumentation channels of the ESF actuation system. The specific functions that rely onthe ESF actuation system for initiation are the following:1.A reactor trip, provided one has not already been generated by the reactor trip system.2.Proper load application sequencing of ESF power demands on the ESF buses (supplied byeither preferred or standby power supply).3.Cold-leg injection isolation valves, which are opened for the injection of borated water bycharging/safety injection pumps into the cold legs of the reactor coolant system.4.Charging/safety injection pumps, and associated valving, which provide the injection ofwater to the cold leg of the reactor coolant system following a LOCA.5.Low-head safety injection pumps, which start to provide borated makeup water to the coldlegs of the reactor coolant loops.6.Service water system pumps and valves, which provide cooling water to the recirculationspray heat exchangers and are thus the heat sink for containment cooling.7.Auxiliary feedwater pumps.8.Containment isolation phaseA, whose function is to prevent fission product release.9.Steam-line isolation, to prevent the continuous, uncontrolled blowdown of more than onesteam generator and thereby uncontrolled reactor coolant system cooldown.10.Main feedwater-line isolation, to limit the energy release in the case of a steam-line breakand to limit the magnitude of the reactor coolant system cooldown.11.Emergency diesel starting, to ensure backup supply of power to emergency and supportingsystems components.12.Containment depressurization system actuation, which performs the following functions:a.Initiates containment quench and recirculation spray subsystems, which serve to reducecontainment pressure and temperature following a loss-of-coolant or steam-line-breakaccident.b.Initiates containment isolation phaseB, which isolates the containment following aLOCA or a feedwater-line or steam-line break within containment.7.1.3.3.3Codes and StandardsThe ESF actuation system meets the criteria as set forth in IEEE Std279-1971, IEEEStandard: Criteria for Protection Systems for Nuclear Power Generating Stations.

Revision 52-09/29/2016NAPS UFSAR7.1-10In addition, the minimum performance for each of the ESF actuation systems specified interms of time response, accuracy, and range is in accordance with the requirements set forth inthis document.7.1.3.3.4Environmental RequirementsThe environmental design bases are given in Sections3.10 and3.11 and in IEEEStd279-1971.

7.1.3.4Instrumentation and Control Power SupplyThe functional performance requirements for the instrumentation and control powersupplies are described in detail in Chapter8.7.1.3.5Quality AssuranceThe quality assurance program applied to safety-related instrumentation and control systemcomponents is described in Chapter17.7.1.3.6Safety-Related Equipment IdentificationThere are two sets of separate process analog racks. One set contains instrumentationfurnished by the architect-engineer, the other contains instrumentation furnished by the NSSSsupplier. The separation of redundant analog channels begins at the process sensors and ismaintained in the field wiring, containment penetrations, and analog protection racks to theredundant trains in the logic racks. Redundant analog channels are separated by locating modulesin different rack sets. Since all equipment within any analog rack is associated with a singleprotection set, there is no requirement for the separation of wiring and components within therack. Barriers are provided in the logic rack to separate channel inputs. A color-coded nameplateon each analog rack is used to differentiate between protective and nonprotective sets. The colorcoding of the nameplates is as follows:All non-rack-mounted protective equipment and components are provided with anidentification tag or nameplate. Small electrical components such as relays have nameplates ontheir enclosures. All cable identification is discussed in Chapter8.For further details of the process analog system, see Sections7.2, 7.3 and7.7.Protection SetColor CodingIRed with white letteringIIWhite with black letteringIIIBlue with white letteringIVYellow with black lettering Revision 52-09/29/2016NAPS UFSAR7.1-11There are identification nameplates on the input panels of the digital logic system. Fordetails of the digital logic system, see Sections7.2 and7.3.The installation of all cable, including separation requirements for control board wiring,complies with the criteria presented in Chapter8.Redundant sensors, sensing lines, and actuating devices are separated by either space,physical barriers, or both. The sensing lines are normally routed to missile-protected areas wherethe transmitters are located. In areas where the potential for missiles is high and where no physicalbarriers are provided, sensors, sensing lines, and actuating devices are physically separated by aminimum distance of 4feet in any direction. Sensing lines passing through walls are alsophysically separated, or each sensing line is protected by rigid steel conduit when passage is madethrough a common opening in a wall.In areas where the potential for missiles is very low, sensors, sensing lines, and actuatingdevices are separated by at least 12inches where barriers are not used.7.1.4Regulatory Guide1.97Reg. Guide1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plants to AssessPlant and Environs Conditions during and following an Accident, contains tables ofinstrumentation required by the operators to monitor the plant and environs during and followingan accident. This instrumentation consists of indicators that are associated with a variety of plantsafe-shutdown and balance of plant systems. The intent of Reg. Guide1.97 is to provide theoperators with the minimum essential information during and following an accident so that theywill be able to mitigate and minimize the consequences of the accident. The Reg. Guide hasspecifically determined four of the five types of instrumentation required to ensure properindication is available to the operators. These four types (TypeB, C, D, andE) are outlined inTable3 of the Reg. Guide along with their specifically assigned category, design and qualificationrequirements. The fifth type of instrumentation, Type"A" variables, are plant specific. Atype"A" variable provides the operator with essential information necessary to take manualactions to mitigate an accident for which no automatic actions are provided. These instruments arecharacterized by their definition as stated in the Reg. Guide. These definitions are:1.TypeA Variables: Those variables to be monitored that provide the primary informationrequired to permit the control room operator to take specific manually controlled actions forwhich no automatic control is provided and that are required for safety systems toaccomplish their safety functions for design basis accident events. Primary information isessential for the direct accomplishment of the specified safety functions; it does not includethose variables that are associated with contingency actions that may also be identified inwritten procedures.2.TypeB Variables: Those variables that provide information to indicate whether plant safetyfunctions are being accomplished. Plant safety functions are (1)reactivity control, (2)core Revision 52-09/29/2016NAPS UFSAR7.1-12cooling, (3)maintaining reactor coolant system integrity, and (4)maintaining containmentintegrity (including radioactive effluent control). Variables are listed with designated rangesand category for design and qualification requirements. Key variables are indicated bydesign and qualification Category1.3.TypeC Variables: Those variables that provide information to indicate the potential for beingbreached or the actual breach of the barriers to fission product releases. The barriers are(1)fuel cladding, (2)primary coolant pressure boundary, and (3)containment.4.TypeD Variables: Those variables that provide information to indicate the operation ofindividual safety systems and other systems important to safety. These variables are to helpthe operator make appropriate decisions in using the individual systems important to safetyin mitigating the consequences of an accident.5.TypeE Variables: Those variables to be monitored as required for use in determining themagnitude of the release of radioactive materials and continually assessing such releases.To further define the variables, Reg. Guide1.97 has assigned each variable a design andqualification category. This categorization consists of either a category1, 2 or3 designation witha category1 having the most stringent requirements to category3 having the least stringent. Thevariables are examined against twelve design and qualification criteria. However, Category2 or3variables may be exempt from some or all of the individual criterion's requirements. The criteriaand how they are to be applied against each of the three categories are listed in Table1 Designand Qualification Criteria for Instrumentation of Regulatory Guide1.97. The twelve categoryrequirements consist of the following:1.Equipment Qualification2.Redundancy3.Power Source4.Channel Availability5.Quality Assurance 6.Display and Recording7.Range8.Equipment Identification 9.Interfaces10.Servicing, Testing and Calibration11.Human Factors12.Direct Measurement Revision 52-09/29/2016NAPS UFSAR7.1-13In response to NUREG-0737, and Regulatory Guide1.97, Revision3, Virginia Power hasdeveloped a programmatic approach in defining the Regulatory Guide1.97 required equipment.The Virginia Power Regulatory Guide1.97 program reviews examined each of the requiredinstrumentation loops against the category design and qualification requirements. The reviewsdetermined whether equipment upgrades to meet the Regulatory Guide requirements wererequired. Any required equipment upgrades will be performed to meet the Design andQualification Criteria for Instrumentation of the Regulatory Guide. Virginia Power has also takenexceptions to the category requirements for certain plant instruments. These exceptions to theRegulatory Guide have been outlined in correspondence between the NRC and Virginia Power.Any further exceptions to the Regulatory Guide will also be relayed to the NRC bycorrespondence for their review and approval. Virginia Power maintains a plant specific technicalreport, PE-0013, and Technical Requirements Manual SectionTR3.3.9 that provide a tabularidentification of Regulatory Guide1.97 associated equipment (References5 and 7).

7.1REFERENCES

1.J. A. Nay, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems,WCAP-7547-L, March1971 (Westinghouse NES Proprietary); WCAP-7671, May1971(non proprietary); and J. B. Reid, Process Instrumentation for Westinghouse Nuclear SteamSupply Systems, (W CID 7300 Series), WCAP-7913.2.J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System, WCAP-7380-L,January1971 (Westinghouse NES Proprietary); and WCAP-7669, May1971 (nonproprietary).3.D. N. Katz, Solid State Logic Protection System Description, WCAP-7488-L, March1971(Westinghouse NES Proprietary); and WCAP-7672, May1971 (non proprietary).4.J. T. Haller, Engineered Safeguards Final Device or Activator Testing, WCAP-7705.5.Technical Report PE-0013, NorthAnna Power Station Response to Regulatory Guide1.97.6.Technical Report EE-0101, Setpoint Bases Document.7.NorthAnna Technical Requirements Manual Section TR3.3.9.

Revision 52-09/29/2016NAPS UFSAR7.1-147.1REFERENCE DRAWINGSThe list of Station Drawings below is provided for information only. The referenced drawings are not part of the UFSAR. This is not intended to be a complete listing of all Station Drawings referenced from this section of the UFSAR. The contents of Station Drawings are controlled by station procedure.Drawing NumberDescription1.11715-LSK-27-12ATypical Loop Diagram for Each Channel Hi-Hi Containment Pressure Protection2.11715-LSK-27-12BHi-Hi Containment Pressure Protection and Indication, Unit13.11715-LSK-27-12CContainment Depressurization Actuation and Reset, Train A4.11715-LSK-27-12DHi Containment Pressure Protection 5.11715-LSK-27-12EIntermediate Hi-Hi Containment Pressure Protection Protection6.11715-LSK-27-12FContainment Depressurization Actuation and Reset, Train B 7.11715-LSK-28-5CSafety Injection System, Actuated Devices 8.11715-LSK-27-12GContainment Depressurization Actuated Devices9.11715-LSK-5-13ALogic Diagram: Motor Driven Steam Generator, Auxiliary Feedwater Pumps10.11715-LSK-5-8HFeedwater Isolation Trip Valves11.11715-LSK-32-1CLogic Diagram: Normally Closed Containment Isolation Trip Valves12.11715-LSK-5-13BTurbine Driven, Steam Generator, Auxiliary Feedwater Pumps 13.11715-LSK-5-13CAuxiliary Feedwater Control Valves14.11715-LSK-8-18AMain Steam Isolation Trip Valve 15.11715-LSK-8-18DMain Steam Isolation Bypass Valve Revision 52-09/29/2016NAPS UFSAR7.2-17.2REACTOR TRIP SYSTEMElectrical schematic diagrams for the reactor trip system and its supporting systems wereincluded in reports NA-TR-1001 and NA-TR-1002, Safety Related Electrical Schematics, datedMay10,1973, which were submitted to the Atomic Energy Commission (AEC) onMay18,1973, as separate documents. Figure7.2-1 shows the symbols used in the logic diagramsthat are included as appropriate throughout the chapter.7.2.1DescriptionThe reactor trip system uses sensors that feed analog circuitry consisting of two to fourredundant channels that monitor various plant parameters. The reactor trip system also containsthe digital logic circuitry necessary to automatically open the reactor trip breakers. The digitalcircuitry consists of two redundant logic trains that receive inputs from the analog protectionchannels.Each of the two trains, A and B, is capable of opening a separate and independent reactortrip breaker, RTA and RTB, respectively. The two trip breakers in series connect three-phase acpower from the rod drive motor-generator sets to the rod drive power cabinets, as shown inFigure7.2-2. During plant power operation, a dc undervoltage coil on each reactor trip breakerholds a trip plunger out against its spring, allowing the power to be available at the rod controlpower supply cabinets. For reactor trip, a loss of dc voltage to the undervoltage coil releases thetrip plunger and trips open the breaker. A shunt trip relay is installed in parallel with theundervoltage attachment. Upon de-energization, contacts from the relay energize the reactor tripbreaker shunt trip attachment and trips open the breaker. This provides a redundant/backup meansto automatically trip the breakers upon the receipt of a trip signal from the reactor trip system.When either of the trip breakers opens, power is interrupted to the rod drive power supply, and thecontrol rods fall by gravity into the core. The rods cannot be withdrawn until an operator resetsthe trip breakers. The trip breakers cannot be reset until the bi-stable that initiated the trip isre-energized. Bypass breakers BYA and BYB are provided to permit the testing of the tripbreakers, as discussed below.The following are the generating station conditions requiring reactor trip (seeSection7.1.3.2.2):1.Core approaching thermal hydraulic limits.2.Power density (kW/ft) approaching rated value for ConditionII faults (see Chapter4 for fueldesign limits).3.Reactor coolant system overpressure creating stresses approaching the limits specified inChapter5.

Revision 52-09/29/2016NAPS UFSAR7.2-2The following are the variables required to be monitored in order to provide reactor trips(see Section7.2.1.1 and Table7.2-1):1.Neutron flux.2.Reactor coolant temperature.3.Reactor coolant system pressure (pressurizer pressure).

4.Pressurizer water level.

5.Reactor coolant flow.6.Reactor coolant pump operational status (bus voltage and frequency, and breaker position).7.Steam generator feedwater flow.8.Steam generator water level.9.Turbine-generator operational status (autostop oil pressure and stop valve position).The reactor coolant temperature is spatially dependent. See Section7.3.1.2 for a discussionof this variable spatial dependence.The allowable values associated with the parameters that will require reactor trip are givenin the Technical Specifications and in Chapter15, Accident Analyses. Chapter15 proves that thesetpoints used in the Technical Requirements Manual are conservative.The setpoints for the various functions in the reactor trip system have been analyticallydetermined such that the operational limits so prescribed will prevent fuel rod clad damage andloss of integrity of the reactor coolant system as a result of any ConditionII incident (anticipatedmalfunction). As such, the reactor trip system limits the following parameters to:1.Minimum DNBR greater than the limit value.2.Maximum system pressure = 2750psia.3.Fuel rod maximum linear power less than the value corresponding to fuel centerline melting.The accident analyses described in Section15.2 demonstrate that the functionalrequirements as specified for the reactor trip system are adequate to meet the aboveconsiderations, even assuming, for conservatism, adverse combinations of instrument errors (referto Tables15.1-3 and15.1-4). A discussion of the safety limits associated with the reactor core andreactor coolant system, plus the limiting safety system setpoints (allowable values), is presentedin the Technical Specifications.For a discussion of energy supply and environmental variations, see Sections8.3.1.2and3.11, respectively.

Revision 52-09/29/2016NAPS UFSAR7.2-3The malfunctions, accidents, or other unusual events that could physically damage reactortrip system components or could cause environmental changes are as follows:1.Earthquakes, discussed in Chapters2 and3.2.Fire, discussed in Section9.5.3.Explosion (hydrogen buildup inside containment), discussed in Section6.2.4.Missiles, discussed in Section3.5.

5.Flood, discussed Chapters2 and3.6.Wind and tornados, discussed in Section3.3.The performance requirements are as follows:1.System response times:The reactor trip system response time, or total delay to trip, is defined in the TechnicalSpecifications. During periodic testing as required by Technical Specifications, it isdemonstrated or verified that instrument errors and time delays are equal to or less than thevalues assumed in the safety analyses.Maximum allowable time delays in generating the reactor trip signal are given in theTechnical Requirements Manual.2.Reactor trip accuracies and ranges are given in Table7.2-2 and Reference19.The complete reactor trip system is normally required to be in service. However, to permitonline testing of the various protection channels or to permit continued operation in the event of asubsystem instrumentation channel failure, the Technical Specifications define the operabilityrequirements for the reactor trip system. The Technical Specifications also define the requiredrestriction to operation in the event that the channel operability cannot be met.7.2.1.1Reactor TripsThe various reactor trip circuits automatically open the reactor trip breakers whenever acondition monitored by the reactor trip system reaches a preset level. In addition to redundantchannels and trains, the design approach provides a reactor trip system that monitors numeroussystem variables, that is, provides reactor trip system functional diversity. The extent of thisdiversity has been evaluated for a wide variety of postulated accidents and is detailed inReference1.Table7.2-1 provides a list of reactor trips, coincidence requirements, and interlocks, whichare described below.Table7.2-5 provides a list of reactor trip system instrumentation with the number ofchannels to trip and the minimum channels that are required operable.

Revision 52-09/29/2016NAPS UFSAR7.2-47.2.1.1.1Nuclear Overpower TripsThe specific trip functions generated are as follows:1.Power range high-neutron-flux trip-The power range high-neutron-flux trip circuit trips thereactor when two of the four power range channels exceed the trip setpoint.There are two independent bi-stables, each with its own trip setting used for a high and a lowsetting. The high trip setting provides protection during normal power operation and isalways active. The low trip setting, which provides protection during startup, can bemanually bypassed when two out of the four power range channels read above approximately10% power (P-10). Three out of the four channels below 10% automatically reinstate the tripfunction. Refer to Table7.2-3 for a listing of all reactor trip system interlocks.2.Intermediate range high-neutron-flux trip-The intermediate range high-neutron-flux tripcircuit trips the reactor when one out of the two intermediate range channels exceeds the tripsetpoint. This trip, which provides protection during reactor startup, can be manually blockedif two out of the four power range channels are above approximately 10% power (P-10).Three out of the four power range channels below this value automatically reinstate theintermediate range high-neutron-flux trip. The intermediate range channels (includingdetectors) are separate from the power range channels. The intermediate range channels canbe individually bypassed at the nuclear instrumentation racks to permit channel testingduring plant shutdown or before startup. This bypass action is annunciated on the controlboard.3.Source range high-neutron-flux trip-The source range high-neutron-flux trip circuit tripsthe reactor when one of the two source range channels exceeds the trip setpoint. This trip,which provides protection during reactor startup and plant shutdown, can be manuallybypassed when one of the two intermediate range channels reads above the P-6 setpointvalue and is automatically reinstated when both intermediate range channels decrease belowthe P-6 value. This trip is also automatically bypassed by two-out-of-four logic from thepower range interlock (P-10). This trip function can also be reinstated below P-10 by anadministrative action requiring manual actuation of two control board mounted switches.Each switch will reinstate the trip function in one of the two protection logic trains. Thesource range trip point is set between the P-6 setpoint (source range cutoff flux level) and themaximum source range flux level. The channels can be individually bypassed at the nuclearinstrumentation racks to permit channel testing during plant shutdown or before startup. Thisbypassing action is annunciated on the control board.4.Power range neutron flux rate trips (PRRT)-Refer to Figure7.2-3. The functional diagramshown includes reactor trip logic provided to trip the reactor when an abnormal rate ofincrease or decrease in nuclear power occurs in two out of four power range channels.

Revision 52-09/29/2016NAPS UFSAR7.2-5a.Power range high positive neutron flux rate trip-The bi-stables associated with highpositive flux rate trip for an abnormal rate of increase in nuclear power. The reactor istripped when a high positive rate occurs in two out of the four power range channels. Thistrip provides protection against rod ejection accidents of low worth from midpower and isalways active.b.Power range high negative neutron flux rate trip-The bi-stables associated with highnegative flux rate trip for an abnormal rate of decrease in nuclear power. The reactor istripped when a high negative rate occurs in two out of the four power range channels. Thistrip provides protection against two or more dropped rods and is always active. Protectionagainst one dropped rod is not required to prevent the occurrence of DNBR at full powerper the analysis in Section15.2.3.These channels of the reactor trip system derive signals from the power rangeuncompensated ion chambers. In the nuclear instrumentation system, the rate sensorassembly is an operational amplifier unit that incorporates an adjustable lag network at oneinput and a nondelayed signal on the other. The unit compares the actual power signal withthe delayed power signal received through the lag network and amplifies the difference. Thisamplified differential signal is delivered to two bi-stable units that trip when the level of thesignal exceeds a preset value. The bi-stable units are the latching type to ensure that thenecessary action, once initiated, will be carried to completion. The bi-stable outputs areprovided to the solid-state protection system where the logic shown in Figure7.2-3 isperformed to provide a reactor trip when abnormal nuclear power rates occur.The operability of the rate trip functions associated with dropped rod and ejected rodprotection is verified by the introduction of a signal step change using the channel drawer testcircuits. The time delay setting of the rate module is predetermined by analysis to correspondto high positive or negative power rate associated with the above events and is tested duringinitial startup testing.Figure7.2-3 shows the logic for all of the nuclear overpower and rate trips. A detailedfunctional description of the equipment associated with the negative flux rate (dropped rod)function is given in Reference2. The positive rate trip function is generated by the same devicebut uses an additional bi-stable amplified in each protection channel.

Revision 52-09/29/2016NAPS UFSAR7.2-67.2.1.1.2Core Thermal Overpower TripsThe specific trip functions generated are as follows:1.Overtemperature deltaT trip-This trip protects the core against low DNBR and trips thereactor on coincidence as listed in Table7.2-1 using one set of temperature measurementsper loop. The setpoint for this trip is continuously calculated by analog circuitry for eachchannel by solving the following equation:(7.2-1)where:Tsetpoint = T reactor trip setpoint, °FTo = indicated T at full power (RTP), °FTavg = measured average reactor coolant temperature, °FT' = nominal average reactor coolant temperature at full power, °FP = measured pressurizer pressure, psig K1 = setpoint bias, dimensionlessK2 = constant based on the effect of temperature on the departure from nucleate boiling (DNB) limits, °F-1K3 = constant based on the effect of pressure on the DNB limits, psig-11, 2 = time constants, secs = Laplace transform variable, sec-1f1(q) = a function of the neutron flux difference between upper and lower long ionchambers, dimensionless. One power range channel separately feeds each overtemperature Ttrip channel. A non-zero f1(q) can only lead to a decrease in trip setpoint. Refer to Figure7.2-4.The single pressurizer pressure parameter required per channel is obtained from separatesensors that are connected to three pressure taps at the top of the pressurizer. This results inone pressure tap per channel. Refer to Section7.2.2.3.3 for an analysis of this.Figure7.2-5 shows the logic for the overtemperature deltaT trip function. A detailedfunctional description of the process equipment associated with this function is contained inReference3.2.Overpower deltaT trip-This trip protects against excessive power (fuel rod ratingprotection) and trips the reactor on coincidence, as listed in Table7.2-1, with one set ofTsetpointToK1K211s+12s+-----------------TavgT'-()K3P2235-()f1q()-+-=

Revision 52-09/29/2016NAPS UFSAR7.2-7temperature measurements per loop. The setpoint for each channel is continuously calculatedusing the following equation:(7.2-2)where:Tsetpoint = T reactor trip setpoint, °FTo = indicated T at full power (RTP), °Ff2(q) = a function of the neutron flux difference between upper and lower long ion chamber section, dimensionlessK4 = a preset, manually adjustable bias, dimensionlessK5 = a constant based on the effect of rate of change of Tavg on overpower T limit, °F-1K6 = a constant based on the effect of Tavg on overpower T limit, °F-1T' = nominal average reactor coolant temperature at full power, °F Tavg = measured average reactor coolant temperature, °F3 = time constant, secs = Laplace transform variable, sec-1The source of temperature and flux information is identical to that of the overtemperaturedeltaT trip, and the resultant deltaT setpoint is compared to the same measured deltaT.Figure7.2-5 shows the logic for this trip function. The detailed functional description of theprocess equipment associated with this function is contained in Reference3.7.2.1.1.3Reactor Coolant System Pressurizer Pressure and Water Level TripsThe specific trip functions generated are as follows:1.Pressurizer low-pressure trip-The purpose of this trip is to protect against low pressure,which could lead to a DNBR less than the design limit and to limit the necessary range ofprotection afforded by the overtemperature deltaT trip. The parameter being sensed isreactor coolant pressure as measured in the pressurizer. Above P-7 the reactor is trippedwhen the compensated pressurizer pressure measurements fall below preset limits. This tripis blocked below P-7 to permit startup.The trip logic is shown in Figure7.2-6. A detailed functional description of the processequipment associated with the function is contained in Reference3.2.Pressurizer high-pressure trip-The purpose of this trip is to protect the reactor coolantsystem against system overpressure.TsetpointToK4K53s13s+-----------------Tavg-K6TavgT'-()-f2q()-=

Revision 52-09/29/2016NAPS UFSAR7.2-8The same sensors and transmitters used for the pressurizer low-pressure trip are used for thehigh-pressure trip except that separate bi-stables are used for the high-pressure trip. Thesebi-stables trip when uncompensated pressurizer pressure signals exceed preset limits. Thereare no interlocks or permissives associated with this trip function.The logic for this trip is shown in Figure7.2-6. The detailed functional description of theprocess equipment associated with this trip is provided in Reference3. See also Section3.11for details concerning the environmental qualification of the pressurizer pressuretransmitters.3.Pressurizer high water level trip-This trip is provided as a backup to the high pressurizerpressure trip and serves to prevent water relief through the pressurizer safety valves. This tripis blocked below P-7 to permit startup.The trip logic for this function is shown in Figure7.2-6. A detailed description of the processequipment associated with this function is contained in Reference3.7.2.1.1.4Reactor Coolant System Low-Flow TripsThese trips protect against a DNBR of less than the design limit in the event of aloss-of-coolant flow situation. The means of sensing the loss-of-coolant flow are as follows:1.The parameter sensed is reactor coolant flow. Three elbow taps in each coolant loop are usedas a flow device that indicates the status of reactor coolant flow. The basic function of thisdevice is to provide information as to whether or not a reduction in flow rate has occurred.An output signal from two out of the three bi-stables in a loop would indicate a low flow inthat loop.The detailed functional description of the process equipment associated with the trip functionis contained in Reference3.2.Reactor coolant pump bus undervoltage trip-This trip is required to protect against lowflow, which can result from a loss of voltage to more than one reactor coolant pump (e.g.,from station blackout).There are two undervoltage sensing relays connected to each reactor coolant pump bus.These relays provide an output signal when the bus voltage goes below approximately 70%of rated voltage. Signals from these relays are time delayed to prevent spurious trips causedby short-term voltage perturbations.3.Reactor coolant pump bus underfrequency trip-This trip is required to protect against lowflow resulting from bus underfrequency, for example, a major power grid frequencydisturbance. The function of this trip is to trip the reactor for an underfrequency condition.

Revision 52-09/29/2016NAPS UFSAR7.2-9There is one underfrequency sensing relay connected to each reactor coolant pump bus.Signals from relays connected to any two of the buses (time delayed to prevent spurious tripscaused by short-term frequency perturbations) will directly trip the reactor if the power levelis above P-7.4.An additional input into this sensing system is provided by the reactor coolant pump breakertrip-The opening of one or two reactor coolant pump breakers (depending on power level),which is indicative of an imminent loss of coolant flow in that loop, or loops, will also causea reactor trip.Two sets of auxiliary contacts on each pump breaker serve as the input signal to the triplogic. The logic is designed on an energize-to-trip basis. However, this is an anticipatory tripand no credit has been taken for this function since other de-energize to trip logics providereactor trip on loss of coolant flow.Figure7.2-5 shows the logic for the reactor coolant system low-flow trips.7.2.1.1.5Steam Generator TripsThe specific trip function generated is the low-low steam generator water level trip-This tripprotects the reactor from a loss of heat sink in the event of a sustained steam/feedwater flowmismatch. This trip is actuated on two out of three low-low water level signals occurring in anysteam generator, provided that the stop valves for that loop are open.The logic is shown in Figure7.2-7. A detailed functional description of the processequipment associated with this trip is provided in Reference3.In addition, an independent trip may be actuated by the anticipated transient without scram(ATWS) mitigation system actuation circuitry (AMSAC). This system is operational when theC-20 permissive is satisfied by the unit being above a specific power level based on turbine firststage pressure. When the narrow range steam generator level detected by two out of threechannels on each of two out of three steam generators is below the AMSAC setpoint and the C-20permissive is satisfied, an AMSAC trip can be generated. The AMSAC steam generator level canbe the same as the RPS low-low level setpoint or may be set as much as 5% lower than the RPSsetpoint, providing certain criteria are met. The AMSAC trip is time delayed to allow the RPS tofunction prior to AMSAC action. AMSAC trips the turbine directly and trips the reactor bytripping the power feeder breakers for the rod control motor generator sets. This logic is shown inFigure7.2-13. Further description of the C-20 permissive setpoint and its basis is provided inSection7.7.1.14.7.2.1.1.6Turbine Trip-Reactor TripThe turbine trip-reactor trip is actuated by either two-out-of-three logic from the lowauto-stop oil pressure signals or by all closed signals from the turbine steam stop valves. A turbinetrip causes a direct reactor trip above P-8. This is shown in Figure7.2-8.

Revision 52-09/29/2016NAPS UFSAR7.2-10In addition, an independent turbine trip may be actuated by the AMSAC. This system isoperational when the C-20 permissive is satisfied by the unit being above a specific power levelbased on turbine first stage pressure. When the narrow range steam generator level detected bytwo out of three channels on each of two out of three steam generators is below the AMSACsetpoint and the C-20 permissive is satisfied, an AMSAC trip can be generated. The AMSACsteam generator level can be the same as the RPS low-low level setpoint or may be set as much as5% lower than the RPS setpoint, providing certain criteria are met. The AMSAC trip is timedelayed to allow the RPS to function prior to AMSAC action. AMSAC trips the turbine directly.The logic is shown in Figure7.2-13. Further description of the C-20 permissive setpoint and itsbasis is provided in Section7.7.1.14.High-high steam generator level signals in two out of three channels for any steamgenerator will actuate a turbine trip, trip the main feedwater pumps, close the main and bypassfeedwater control valves, and close the main feed line isolation valves. The purpose is to protectthe turbine and steam piping from excessive moisture carryover caused by high-high steamgenerator water level. Other turbine trips are discussed in Chapter10.The logic for this trip is shown in Figure7.2-7.The analog portion of the trip shown in Figure7.2-8 is represented by dashed (---) lines.When the turbine is tripped, turbine auto-stop oil pressure drops, which will be sensed by threepressure sensors. A digital output is provided from each sensor when the auto-stop oil pressuredrops below a preset value. These three outputs are transmitted to two redundant two-out-of-threelogic matrices, either of which trips the reactor if above P-8.The auto-stop oil pressure signal also dumps the electro-hydraulic control oil closing all ofthe turbine steam throttle valves. When all throttle valves are closed, a reactor trip signal will beinitiated if the reactor is above P-8. This trip signal is generated by redundant (two each) limitswitches on the stop valves.

7.2.1.1.7Safety Injection Signal Actuation TripA reactor trip occurs when the safety injection system is actuated. The means of actuatingthe safety injection system are described in Section7.3. This trip protects the core during a loss ofreactor coolant or steam-line break.Figure7.2-9 shows the logic for this trip. A detailed functional description of the processequipment associated with this trip function is provided in Reference3.7.2.1.1.8Manual TripThe manual trip consists of two redundant switches with multiple outputs on each switch.One output is used to actuate the trainA trip breaker and another output actuates the trainB tripbreaker. Operating a manual trip switch removes the voltage from the undervoltage trip coil andenergizes the shunt trip coil, either of which will cause a reactor trip.

Revision 52-09/29/2016NAPS UFSAR7.2-11There are no interlocks that can block this trip. Figure7.2-3 shows the manual trip logic.7.2.1.2Reactor Trip System Accuracies and Response TimesThe system accuracies and the system response times of the instrument trip signals requiredfor plant safety are given in Tables7.2-2 and15.1-3, respectively.Periodic response time testing of the reactor trip and ESF systems has been established inthe Technical Specifications to meet the intent of IEEE Std338-1971.The response time may be measured by means of any series of sequential, overlapping, ortotal steps so that the entire response time is measured. In lieu of measurement, response timemay be verified for selected components provided that the components and methodology forverification have been previously reviewed and approved by the NRC.The measured or verified channel response times are compared with those used in the safetyevaluations. In accordance with Technical Specifications, the response times are required to beless than or equal to the times used in the safety analyses.7.2.1.3Reactor Trip System Interlocks7.2.1.3.1Power Escalation PermissivesThe overpower protection provided by the out-of-core nuclear instrumentation consists ofthree discrete, but overlapping, levels. The continuation of startup operation or power increaserequires a permissive signal from the high-range instrumentation channels before the lower rangelevel trips can be manually blocked by the operator.A one-of-two intermediate range permissive signal (P-6) is required before source rangelevel trip blocking and detector high-voltage cutoff. Source range level trips are automaticallyreactivated and high voltage restored when both intermediate range channels are below thepermissive (P-6) level. There is a manual reset switch for administratively reactivating the sourcerange level trip and detector high voltage when between the permissive P-6 and P-10 level ifrequired. Source range level trip block and high-voltage cutoff are always maintained when abovethe permissive P-10 level.The intermediate range level trip and power range (low setpoint) trip can only be blockedafter satisfactory operation and permissive information are obtained from two out of four powerrange channels. Individual blocking switches are provided so that the low-range power range tripand intermediate range trip can be independently blocked. These trips are automaticallyreactivated when any three of the four power range channels are below the permissive (P-10)level, thus ensuring automatic activation to more restrictive trip protection.The development of permissives P-6 and P-10 is shown in Figure7.2-10. All of thepermissives are digital; they are derived from analog signals in the nuclear power range andintermediate range channels.

Revision 52-09/29/2016NAPS UFSAR7.2-12See Table7.2-3 for the list of reactor trip system interlocks.7.2.1.3.2Blocks of Reactor Trips at Low PowerInterlock P-7 blocks a reactor trip at low power (below approximately 10% of full power)on a low reactor coolant flow or reactor coolant pump open breaker signal in more than one loop,reactor coolant pump undervoltage, reactor coolant pump underfrequency, pressurizer lowpressure, or pressurizer high water level. See Figures7.2-5, 7.2-6 and7.2-8 for permissiveapplications. The low-power signal is derived from three out of four power range neutron fluxsignals below the setpoint in coincidence with two out of two turbine impulse chamber pressuresignals below the setpoint (low plant load).The P-8 interlock blocks a reactor trip when the plant is below approximately 30% of fullpower, on a low reactor coolant flow in any one loop, a reactor coolant pump breaker open signalin any one loop, or turbine trip signal. Below the P-8 setpoint, the reactor will not trip with aturbine trip, or with one inactive loop. The reactor could be allowed to operate with one inactiveloop, provided Technical Specifications are amended to authorize this mode of operation. SeeFigure7.2-10 for the derivation of P-8 and Figures7.2-5 and7.2-8 for applicable logics.See Table7.2-3 for the list of protection system blocks.7.2.1.4Coolant Temperature Sensor ArrangementThree thermowell mounted resistance temperature detectors are installed in the hot leg ofeach loop near the inlet to the steam generator for reactor protection and control. One thermowellmounted resistance temperature detector is installed in the cold leg of each loop at the dischargeof the reactor coolant pump for reactor protection and control.7.2.1.5Pressurizer Water Level Reference Leg ArrangementThe design of the pressurizer water-level instrumentation includes the usual tank levelarrangement using differential pressure between an upper and a lower tap. Refer toSection7.2.2.3.4 for an analysis of this arrangement.7.2.1.6Analog SystemThe process analog system is described in Section7.7.1.11 and Reference3.7.2.1.7Digital Logic SystemThe solid-state protection logic system takes binary inputs (voltage/no voltage) from theprocess and nuclear instrument channels corresponding to conditions (normal/abnormal) of plantparameters. The system combines these signals in the required logic combination and generates atrip signal (no voltage) to the undervoltage coils of the reactor trip circuit breakers when thenecessary combination of signals occur. The system also provides annunciator, status light, andcomputer input signals, which indicate the condition of bi-stable input signals, partial-trip andfull-trip functions, and the status of the various blocking, permissive, and actuation functions. In Revision 52-09/29/2016NAPS UFSAR7.2-13addition, the system includes means for semi-automatic testing of the logic circuits. A detaileddescription of this system is given in Reference4.7.2.1.8Isolation AmplifiersIn certain applications, Westinghouse considers it advantageous to employ control signalsderived from individual protection channels through isolation amplifiers contained in theprotection channel, as permitted by IEEE Std279-1971. In all of these cases, analog signals derived from protection channels for nonprotectivefunctions are obtained through isolation amplifiers located in the analog protection racks. Bydefinition, nonprotective functions include those signals used for control, remote processindication, and computer monitoring.Isolation amplifier qualification tests are described in References5 and6.7.2.1.9Energy Supply and Environmental VariationsThe energy supply for the reactor trip system, including the voltage and frequencyvariations, is described in Section8.3. The environmental variations throughout which the systemwill perform are given in Section3.11.

7.2.1.10Trip SetpointsThe setpoints that, when reached, will require trip action are given in the TechnicalRequirements Manual.

7.2.1.11Seismic DesignThe seismic design considerations for the reactor trip system are given in Section3.10. Thisdesign meets the requirements of General Design Criterion2.7.2.2Analysis7.2.2.1Evaluation of Design7.2.2.1.1General DiscussionThe reactor trip system automatically keeps the reactor operating within a safe region bytripping the reactor whenever the limits of the region are approached. The safe operating region isdefined by several considerations such as mechanical/hydraulic limitations on equipment and heattransfer phenomena. Therefore, the reactor trip system keeps surveillance on process variablesthat are directly related to equipment mechanical limitations, such as pressure, pressurizer waterlevel (to prevent water discharge through safety valves) and also on variables that directly affectthe heat transfer capability of the reactor (e.g., flow, reactor coolant temperatures). Still otherparameters used in the reactor trip system are calculated from various process variables. In anyevent, whenever a direct process or calculated variable exceeds a setpoint, the reactor will be shut Revision 52-09/29/2016NAPS UFSAR7.2-14down to protect against either gross damage to fuel cladding or a loss of system integrity, whichcould lead to the release of radioactive fission products into the containment.While most setpoints used in the reactor protection system are fixed, there are variablesetpoints, most notably the overtemperature deltaT and overpower deltaT setpoints. All setpointsin the reactor trip system have been selected either on the basis of applicable engineering coderequirements or engineering design studies. The capability of the reactor trip system to prevent aloss of integrity of the fuel clad and/or reactor coolant system pressure boundary duringConditionII andIII transients is demonstrated in Chapter15. These safety analyses are carriedout using setpoints determined from results of the engineering design studies. The associatedallowable values are presented in the Technical Specifications. A discussion of the intent for eachof the various reactor trips and the accident analysis (where appropriate) that uses this trip ispresented in Section7.2.2.1.2. It should be noted that the selected trip setpoints all provide formargin before protection action is actually required, to allow for uncertainties and instrumenterrors. The design meets the requirements of General Design Criteria10 and20.7.2.2.1.2Trip Setpoint DiscussionIt has been pointed out that below a DNBR equal to the limit value there is likely to besignificant local fuel clad failure. The DNBR existing at any point in the core for a given coredesign can be determined as a function of the core inlet temperature, power output, operatingpressure, and flow. Consequently, core safety limits in terms of a DNBR equal to the limit valuefor the hot channel can be developed as a function of core deltaT, Tavg, and pressure for aspecified flow as illustrated by the solid lines in Figure15.1-1. Also shown as solid lines inFigure15.1-1 are the loci of conditions equivalent to 118% of power as a function of deltaT andTavg representing the overpower (kW/ft) limit on the fuel. The dashed lines indicate the maximumpermissible setpoint (deltaT) as a function of Tavg and pressure for the overtemperature andoverpower reactor trip. Actual setpoint constants in the equation representing the dashed lines aregiven in the Core Operating Limits Report (COLR). These values are conservative to allow forinstrument errors. The design meets the requirements of General Design Criteria10, 15, 20,and29.DNB is not a directly measurable quantity; however, the process variables that determineDNB are sensed and evaluated. Small isolated changes in various process variables may not,when considered singly, result in the violation of a core safety limit, whereas the individualvariations, when operating together, over sufficient time, may cause the overpower orovertemperature safety limit to be exceeded. The design concept of the reactor trip system takescognizance of this situation by providing reactor trips associated with individual process variablesin addition to the overpower/overtemperature safety limit trips. The process variable trips preventreactor operation whenever a change in the monitored value is such that a core or system safetylimit is in danger of being exceeded should operation continue. Basically, the high-pressure,low-pressure, and overpower/overtemperature deltaT trips provide sufficient protection for slow Revision 52-09/29/2016NAPS UFSAR7.2-15transients, as opposed to such trips as low flow or high flux, which will trip the reactor for rapidchanges in flow or flux, respectively, that would result in fuel damage before the actuation of theslower responding deltaT trips could be effected.Therefore, the reactor trip system has been designed to provide protection for fuel clad andreactor coolant system pressure boundary integrity where: (1)a rapid change in a single variablewill quickly result in exceeding a core or a system safety limit and (2)a slow change in one ormore variables will have an integrated effect that will cause safety limits to be exceeded. Overall,the reactor trip system offers diverse and comprehensive protection against fuel/clad failureand/or loss of reactor coolant system integrity for ConditionII andIII accidents. This isdemonstrated by Table7.2-4, which lists the various trips of the reactor trip system, and correlatesthem to the Technical Specifications and the appropriate accident discussed in the safety analysesin which the trip could be used.The nuclear power plant reactor trip system design employed by Westinghouse wasevaluated in detail with respect to common-mode failure and is presented in References1 and7.The design meets the requirements of General Design Criterion21.Preoperational testing is performed on reactor trip system components and systems todetermine equipment readiness for startup. This testing serves as a very real evaluation of thesystem functional design.Analyses of the results of ConditionI, II, III, andIV events, including considerations ofinstrumentation installed to mitigate their consequences, are presented in Chapter15. Theinstrumentation installed to mitigate the consequences of load rejection and turbine trip is given inSection7.7.7.2.2.1.2.1Nonstandard Operating Configuration. The reactor trip system automaticallyprovides core protection during nonstandard operating configuration, that is, operation with aloop out of service. Although operating with a loop out of service over an extended time isunlikely and is currently prohibited by the Technical Specifications, no protection systemsetpoints need to be reset. This is because the nominal value for the power (P-8) interlock setpointrestricts the power levels such that DNBRs smaller than the design limit will not be realizedduring any Condition II transients occurring during this mode of operation. This restricted powerlevel is considerably below the boundary of permissible values, as defined by the core safety limits for operation with a loop out of service. Thus, the P-8 interlock acts essentially as a highnuclear power reactor trip when operating with one loop not in service. By first resetting thecoefficient setpoints in the overtemperature deltaT function to more restrictive values as wouldbe listed in the Technical Specifications, the P-8 setpoint could then be increased to the maximumvalue consistent with maintaining DNBR above the design limit for ConditionII transients in theone-loop shutdown mode. The resetting of the deltaT overtemperature trip and P-8 would becarried out under prescribed administrative procedures and only under the direction of authorizedsupervision.

Revision 52-09/29/2016NAPS UFSAR7.2-16The steam-line differential pressure signal is designed to provide a safety injection signalwhen the steam-line nonreturn valve closes following a ConditionIV steam-line break upstreamof the nonreturn valve. If the nonreturn valve fails to close following a break upstream of it, thena high steam flow signal coincident with either low steam-line pressure or low-low Tavg wouldactuate safety injection, and the steam-line differential pressure signal is not required.The steam-line differential pressure logic will actuate safety injection if any one steam linehas a pressure that is 100psi lower than the pressure in the remaining steam lines.When a primary reactor coolant loop is isolated, the logic is in a condition to provide safetyinjection if any one of the nonisolated loops has a steam pressure that is 100psi lower than thesteam pressure in the remaining nonisolated loop. Therefore, the steam-line differential pressuresignal possesses redundancy both with and without an isolated loop and can accept a single failurein any channel without a loss of function.The steam-line differential pressure bi-stable status is constantly displayed on the maincontrol board by the following:1.Annunciator panels with an associated alarm when the panels are first lit.2.Trip status lights for each bi-stable.The operator can see from the control room if the proper bi-stables have been placed in thetrip mode.Even if the operator fails to place the proper bi-stables in the trip mode, the steam-linedifferential pressure system possesses redundancy unless the isolated steam generator isdepressurized.The maximum rate of depressurization from natural heat losses would be less thanapproximately 12psi/hr; thus, it would be more than an hour before the depressurization couldsignificantly affect the operability of the differential pressure actuation signal. Fasterdepressurizations would result only following accident conditions in the isolated loop. The designbasis does not require the consideration of an additional, nonconsequential accident in an operableloop following the first accident in the isolated loop.The isolation of a primary reactor coolant loop and the closure of the main steam stop valvein the isolated loop never cause a loss of function in the steam line differential pressure safetyinjection actuation system. Redundancy in this system is also maintained unless the operatorpermits the isolated loop steam generator to depressurize and fails to trip the proper bi-stables inspite of the fact that he:1.Has specific operating instructions to trip the bi-stables.2.Has a period of more than an hour to trip the bi-stables before redundancy is lost.3.Has two control board indications telling him whether or not the bi-stables have been tripped.

Revision 52-09/29/2016NAPS UFSAR7.2-17In order to defeat the protective action of the differential pressure bi-stables, the operatormust make an error, the isolated loop must be allowed to cool down significantly, and a failuremust occur in the protection system circuitry.7.2.2.1.3Reactor Coolant Flow MeasurementThe elbow taps used on each loop in the primary coolant system are instrument devices thatindicate the status of the reactor coolant flow. The basic function of this device is to provideinformation as to whether or not a reduction in flow rate has occurred. The correlation betweenflow rate and elbow tap signal is given by the following equation:(7.2-3)where Po is the pressure differential at the referenced flow rate, wo, andP is the pressuredifferential at the corresponding flow rate, w. The full-flow reference point was established duringinitial plant startup. The low-flow trip point was then established by extrapolating along thecorrelation curve.The expected absolute accuracy of the channel is within +/-10%, and field results have shownthe repeatability of the trip point to be within +/-1%.7.2.2.2Evaluation of Compliance to Applicable Codes and Standards7.2.2.2.1Evaluation of Compliance with IEEE Std279-1971The reactor trip system meets the criteria of IEEE Std279-1971 (Reference8), as indicatedbelow.

7.2.2.2.1.1Single-Failure Criterion. The protection system is designed to provide redundant(one out of two, two out of three, or two out of four) instrumentation channels for each protectivefunction and one-out-of-two logic train circuits. These redundant channels and trains areelectrically isolated and physically separated. Thus, any single failure within a channel or trainwill not prevent protective action at the system level when required. This design meets therequirements of General Design Criterion21. A loss of input power, the most likely mode offailure, to a channel or logic train will result in a signal calling for a trip. This design also meetsthe requirements of General Design Criterion23.To prevent the occurrence of common-mode failures, such additional measures asfunctional diversity, physical separation, and testing, as well as administrative control duringdesign, production, installation, and operation are employed, as discussed in Reference7. Thisdesign also meets the requirements of General Design Criteria21 and22.7.2.2.2.1.2Quality of Components and Modules. For a discussion of the quality of thecomponents and modules used in the reactor trip system, refer to Chapter17. The quality usedalso meets the requirements of General Design Criterion1.PPo---------wwo------2=

Revision 52-09/29/2016NAPS UFSAR7.2-187.2.2.2.1.3Equipment Qualification. For a discussion of the type tests made to verify theperformance requirements, refer to Section3.11. The test results also demonstrate that the designmeets the requirements of Criterion4 of the GDC.7.2.2.2.1.4Independence. Channel independence is carried throughout the system, extendingfrom the sensor through to the devices actuating the protective function. See Figure7.2-12.Physical separation is used to achieve the separation of redundant transmitters. The separation ofwiring is achieved by using separate wireways, cable trays, conduit runs, and containmentpenetrations for each redundant channel. Redundant analog equipment is separated by locatingmodules in different protection rack sets. Each redundant channel is energized from a separate acpower feed. This design also meets the requirements of General Design Criterion21.The independence of the logic trains is discussed in Reference4. Two reactor trip breakersare actuated by two separate logic matrices that interrupt power to the control rod drivemechanisms. The breaker main contacts are connected in series with the power supply so thatopening either breaker interrupts power to all full-length control rod drive mechanisms,permitting the rods to free fall into the core.The design philosophy is to make maximum use of a wide variety of measurements. Theprotection system continuously monitors numerous diverse system variables. The extent of thisdiversity has been evaluated for a wide variety of postulated accidents and is discussed in Reference1. Generally, two or more diverse protection functions would terminate an accidentbefore intolerable consequences could occur. This design also meets the requirements of GeneralDesign Criterion22.7.2.2.2.1.5Control and Protection System Interaction. The protection system is designed to beindependent of the control system. In certain applications, the control signals and othernonprotective functions are derived from individual protective channels through isolationamplifiers. The isolation amplifiers are classified as part of the protection system and are locatedin the analog protective racks. Nonprotective functions include those signals used for control,remote process indication, and computer monitoring. The isolation amplifiers are designed suchthat a short circuit, open circuit, or the application of 120Vac or 140Vdc on the isolated outputportion of the circuit (i.e., the nonprotective side of the circuit) will not affect the input(protective) side of the circuit. The signals obtained through the isolation amplifiers are neverreturned to the protective racks. This design also meets the requirements of General DesignCriterion24.A detailed discussion of the design and testing of the isolation amplifiers is given inReferences5 and6. These reports include the results of applying various malfunction conditionson the output portion of the isolation amplifiers. The results show that no significant disturbanceto the isolation amplifier input signal occurred.

Revision 52-09/29/2016NAPS UFSAR7.2-19In addition to the fault tests on the isolation amplifiers, system tests on the nuclearinstrumentation system (NIS), the solid state protection system (SSPS), and the 7300Seriesprocess control system (7300PCS) have been conducted by Westinghouse. These tests havedemonstrated that credible externally applied electrical faults or interference, which could bepostulated to be propagated back into redundant instrument and control protection cabinets,would not prevent these systems from performing their safety functions (or cause their spuriousactuation).The NIS and SSPS system tests are covered in the report Westinghouse Protection SystemNoise Tests, which was submitted and accepted by the NRC in support of the Diablo Canyonapplication (Docket Numbers50-275 and50-323). The 7300PCS tests are reported inReference9, the conclusions having been accepted by the NRC for the NorthAnna PowerStation.Where failure of a protection system component can cause a process excursion that requiresprotective action, the protection system can withstand another, independent failure without loss ofprotective action. This design also meets the requirements of General Design Criterion24. 7.2.2.2.1.6Capability for Testing. The reactor trip system is capable of being tested duringpower operation. When only parts of the system are tested at any one time, the testing sequenceprovides the necessary overlap between the parts to ensure complete system operation.The protection system is designed to permit periodic testing of the analog channel portionof the reactor trip system during reactor power operation without initiating a protective actionunless a trip condition actually exists. This is because of the coincidence logic required for reactortrip. Note, however, that the source and intermediate range high-neutron-flux trips must bebypassed during testing.The operability of the process sensors is ascertained by comparison with redundantchannels monitoring the same process variables or those with a fixed known relationship to the parameter being checked. The in-containment sensors can be calibrated during plant shutdown.Analog channel testing is performed at the analog instrumentation rack set by individuallyintroducing simulated input signals into the instrumentation channels and observing the trippingof the appropriate output bi-stables. Process analog output to the logic circuitry is interruptedduring individual channel test by a test switch that, when thrown, de-energizes the associatedlogic input and inserts a proving lamp in the bi-stable output. The interruption of the bi-stableoutput to the logic circuitry for any cause (test, maintenance purposes, or removed from service)will cause that portion of the logic to be actuated (partial trip), accompanied by a partial trip alarmand channel status light actuation in the control room. Each channel contains those switches, testpoints, etc., necessary to test the channel. See Reference3 for additional information.The power range channels of the nuclear instrumentation system may be tested bysuperimposing a test signal on the actual detector signal being received by the channel at the time Revision 52-09/29/2016NAPS UFSAR7.2-20of testing. The output of the bi-stable is not placed in a tripped condition prior to testing. Also,since the power range channel logic is two out of four, bypass of this reactor trip function is notrequired.To test a power range channel, a TEST-OPERATE switch is provided to require deliberateoperator action. Operation of the switch will initiate the CHANNEL TEST annunciator in thecontrol room. Bi-stable operation is tested by increasing the test signal level up to its trip setpointand verifying bi-stable relay operation by control board annunciator and trip status lights.It should be noted that a valid trip signal would cause the channel under test to trip at alower actual reactor power level. A reactor trip would occur when a second bi-stable trips. Nospecific provision has been made in the channel test circuit for reducing the channel signal levelbelow that signal being received from the nuclear instrumentation system detector.A nuclear instrumentation system channel that can cause a reactor trip through one-of-twoprotection logic (source or intermediate range) is provided with a bypass function, which preventsthe initiation of a reactor trip from that particular channel during the short period that it isundergoing test. These bypasses initiate an alarm in the control room.For a detailed description of the nuclear instrumentation system, see Reference2.The reactor logic trains of the reactor trip system are designed to be capable of completetesting at power. Annunciation is provided in the control room to indicate when a train is in test,when a reactor trip is bypassed, and when a reactor trip breaker is bypassed. Details of the logicsystem testing are given in Reference4. See Section7.2.3.4 for a discussion of compliance toSafety Guide22.The reactor coolant pump breakers cannot be tripped at power without causing a plant upsetby loss of power to a coolant pump. However, the reactor coolant pump breaker open trip logiccan be tested at power. Manual trip cannot be tested at power without causing a reactor trip sinceoperation of either manual trip switch actuates both trainA and trainB. Initiating safety injectionor opening the turbine trip breakers cannot be done at power without upsetting normal plantoperation. However, the logic for the associated trips is testable at power.The testing of the logic trains of the reactor trip system includes a check of the input relaysand a logic matrix check. The following sequence is used to test the system:1.Check of input relays-During testing of the process instrumentation system and nuclearinstrumentation system channels, each channel bi-stable is placed in a trip mode, causing oneinput relay in trainA and one in trainB to de-energize. A contact of each relay is connectedto a universal logic printed circuit card. This card performs both the reactor trip andmonitoring functions. The contact that creates the reactor trip also causes a status lamp andan annunciator on the control board to operate. Either the trainA or trainB input relayoperation will light the status lamp and annunciator.

Revision 52-09/29/2016NAPS UFSAR7.2-21Each train contains a multiplexing test switch. At the start of a process or nuclearinstrumentation system test, this switch (in either train) is placed in the A + B position. TheA + B position alternately allows information to be transmitted from the two trains to thecontrol board. Status lamps and annunciators indicate that input relays in both trains havebeen de-energized. Contact inputs to the logic protection system, such as reactor coolantpump bus underfrequency relays, operate input relays, which are tested by operating theremote contacts as described above and using the same type of indications as those providedfor bi-stable input relays.The actuation of the input relays provides the overlap between the testing of the logicprotection system and the testing of those systems supplying the inputs to the logic protectionsystem. Test indications are status lamps and annunciators on the control board. Inputs to thelogic protection system are checked one channel at a time, leaving the other channels inservice. For example, a function that trips the reactor when two out of four channels tripbecomes a one-out-of-three trip when one channel is placed in the trip mode. Both trains ofthe logic protection system remain in service during this portion of the test.2.Check of logic matrices-Logic matrices are checked one train at a time. Input relays are notoperated during this portion of the test. Reactor trips from the train being tested are inhibitedwith the use of the input error inhibit switch on the semiautomatic test panel in the train.Details of semiautomatic tester operation are given in Reference4. At the completion of thelogic matrix tests, one bi-stable in each channel of process instrumentation or nuclearinstrumentation may be tripped to check closure of the input error inhibit switch contacts.The logic test scheme uses pulse techniques to check the coincidence logic. All possible tripand nontrip combinations are checked. Pulses from the tester are applied to the inputs of theuniversal logic card at the same terminals that connect to the input relay contacts. Thus, thereis an overlap between the input relay check and the logic matrix check. Pulses are fed backfrom the reactor trip breaker undervoltage coil to the tester. The pulses are of such shortduration that the reactor trip breaker undervoltage coil armature cannot respondmechanically.

Test indications that are provided are an annunciator in the control room indicating thatreactor trips from the train have been blocked and that the train is being tested, and green andred lamps on the semiautomatic tester to indicate a good or bad logic matrix test. Protectioncapability provided during this portion of the test is from the train not being tested.The general design features and details of the testability of the logic system are described inReference4. The testing capability meets the requirements of General Design Criterion21.7.2.2.2.1.7Testing of Reactor Trip Breakers. Normally the reactor trip breakers 52/RTA and52/RTB are racked in and closed; and the bypass breakers are racked in and open. Testing of thetrip breakers is included in the procedure for the testing of their associated protection logic and isperformed on a per train basis at staggered intervals. Although pulse techniques are used in Revision 52-09/29/2016NAPS UFSAR7.2-22protection logic testing, which avoids the tripping of the reactor trip breakers, the associatedbypass breaker is closed providing redundancy. The following procedure illustrates the testing ofthe reactor trip breaker (RTA), the bypass breaker (BYA) and its associated protection logic:1.Close BYA. Trip BYA to verify its operation.2.Close BYA. Test Auto shunt trip block of RTA.3.Trip RTA manually via UV coil to verify its operation. Close RTA.

4.Trip RTA via Shunt Trip to verify its operation. Close RTA.5.Perform Reactor Protection and ESF logic tests.

6.Verify RTA is closed. If not, close and verify.

7.Trip BYA and leave racked in.8.Repeat the analogous steps for testing the "B" train.Modifications to the reactor trip switchgear were implemented to satisfy action items inNRC Generic Letter83-28 dated July8,1983, to improve reactor trip system reliability.The reactor trip switchgear was modified to provide a redundant/backup means toautomatically trip the breakers. An automatic shunt trip relay was installed which deenergizes ona reactor trip signal and energizes the shunt trip attachment to trip the breaker. The automaticshunt trip relay, test pushbuttons, and test jack connectors are located on a panel installed into thereactor trip breakers instrument compartment.Test jack connectors and pushbuttons are provided to test the automatic shunt trip devicesand to verify breaker operations and response time.Approved station procedures describe the method used to test reactor trip breaker operationthrough the shunt trip relay.Auxiliary contacts of the bypass breakers are connected into their respective trains such thatif either train is placed in test while the bypass breaker of the other train is closed, both reactor tripbreakers and both bypass breakers will automatically trip.Auxiliary contacts of the bypass breakers are connected in such a way that if an attempt ismade to close the bypass breaker in one train while the bypass breaker of the other train is alreadyclosed, both bypass breakers will automatically trip.The trainA and trainB alarm systems operate separate annunciators in the control room.The two bypass breakers also operate an annunciator in the control room. Bypassing of aprotection train with either the bypass breaker or with the test switches will result in audible andvisual indications.

Revision 52-09/29/2016NAPS UFSAR7.2-237.2.2.2.1.8Bypasses. Where operating requirements necessitate automatic or manual bypass ofa protective function, the design is such that the bypass is removed automatically wheneverpermissive conditions are not met. Devices used to achieve automatic removal of the bypass of aprotective function are considered part of the protective system and are designed in accordancewith the criteria of this section. Indication is provided in the control room if some part of thesystem has been administratively bypassed or taken out of service.7.2.2.2.1.9Multiple Setpoints. For monitoring neutron flux, multiple setpoints are used. When amore restrictive trip setting becomes necessary to provide adequate protection for a particularmode of operation or set of operating conditions, the protective system circuits are designed toprovide positive means or administrative control to ensure that the more restrictive trip setpoint isused. The devices used to prevent improper use of less restrictive trip settings are considered partof the protective system and are designed in accordance with the criteria of this section.7.2.2.2.1.10Completion of Protective Action. The reactor trip system is so designed that, onceinitiated, a protective action goes to completion. Return to normal operation requires action by theoperator.

7.2.2.2.1.11Manual Initiation. Switches are provided on the control board for manual initiationof protective action. Failure in the automatic system does not prevent the manual actuation of theprotective functions. Manual actuation relies on the operation of a minimum of equipment.

7.2.2.2.1.12Access. The design provides for administrative control of access to all setpointadjustments, module calibration adjustments, testpoints, and the means for manually bypassingchannels or protective functions. For details refer to Reference3.7.2.2.2.1.13Information Readout. The reactor trip system provides the operator with completeinformation pertinent to system status and safety. All transmitted signals (flow, pressure,temperature, etc.) that can cause a reactor trip are either indicated or recorded for every channel,including all neutron flux power range currents (top detector, bottom detector, algebraicdifference, and average of bottom and top detector currents).Any reactor trip will actuate an alarm and an annunciator. Such protective actions areindicated and identified down to the channel level.Alarms and annunciators are also used to alert the operator of deviations from normaloperating conditions so that he may take appropriate corrective action to avoid a reactor trip. Theactuation of any rod stop or the trip of any reactor trip channel will actuate an alarm.7.2.2.2.1.14Identification. The identification described in Section7.1 provides immediate andunambiguous identification of the protection equipment.

Revision 52-09/29/2016NAPS UFSAR7.2-247.2.2.2.2Evaluation of Compliance with IEEE Std308-1971 (Reference10)See Section7.6 and Chapter8 for a discussion of the power supply for the protectionsystem and compliance with IEEE Std308-1971.7.2.2.2.3Evaluation of Compliance with IEEE Std323-1971 (Reference11)Reactor trip system equipment is type tested to substantiate the adequacy of design. This isthe preferred method, as indicated in Reference11.Most Westinghouse-supplied electrical equipment essential to safe shutdown was qualifiedbefore the issuance of IEEE Std323-1971. For this reason, the format of test documentation is notas listed in Section5.2 of Reference11. The testing and documentation that was accomplished iscomparable to that required by IEEE Std323-1971. Test data, considered proprietary byWestinghouse or its suppliers, can be made available for audit purposes at Westinghouse or itssuppliers.

7.2.2.2.4Evaluation of Compliance with IEEE Std334-1971 (Reference12)There are no continuous duty, ClassI motors in the reactor trip system. Therefore, IEEEStd334-1971 does not apply to the reactor trip system.

7.2.2.2.5Evaluation of Compliance with IEEE Std338-1971 (Reference13)Periodic response time testing of reactor trip system response times has been established inthe Technical Specifications to meet the intent of IEEE Std338-1971.7.2.2.2.6Evaluation of Compliance with IEEE Std344-1971 (Reference14)The seismic testing, as discussed in Section3.10 and the references, conforms to theguidelines set forth in IEEE Std344-1971, with the exceptions noted in Section3.10.7.2.2.2.7Evaluation of Compliance with AEC General Design Criteria (Reference15)The reactor trip system meets the requirements of the General Design Criteria whereverappropriate. Specific cases are noted as they are discussed in Chapter7.7.2.2.2.8Evaluation of Compliance with IEEE Std317-1971 (Reference16)See Section3.8.2.1.4 for a discussion of electrical penetrations and compliance with IEEEStd317-1971.

7.2.2.2.9Evaluation of Compliance with IEEE Std336-1971 (Reference17)Instrumentation and electrical equipment was installed, inspected, and tested in accordancewith IEEE Std336-1971. See Section8.3.1.1.2.2 for a discussion of compliance with IEEEStd336-1971.

Revision 52-09/29/2016NAPS UFSAR7.2-257.2.2.3Specific Control and Protection Interactions7.2.2.3.1Neutron FluxThe flux difference between the upper and lower long ion chambers from three of the fourpower range neutron detectors is used as inputs to the overtemperature deltaT and overpowerdeltaT setpoints. The isolated neutron flux output signal from the fourth channel is used forautomatic rod control.In addition, a deviation signal will give an alarm if any neutron flux channel deviatessignificantly from any of the other channels. Also, the control system will respond only to rapidchanges in indicated neutron flux; slow changes or drifts are compensated by the temperaturecontrol signals. Finally, an overpower signal from any intermediate or power range nuclearchannel will block manual and automatic rod withdrawal. The setpoint for this rod stop is belowthe reactor trip setpoint.7.2.2.3.2Coolant TemperatureThe delta-T and Tavg signals developed in the reactor protection system for theovertemperature delta-T and overpower delta-T reactor trips also provide input to the rod control,steam dump control, and pressurizer level control systems. Circuit isolators are installed toprevent a failure in the reactor control system from propagating back into the protection channels.In the control system, the delta-T and Tavg signals from each of the three protection channels aresent to the median signal selector (MSS) auctioneering circuits. The MSS is designed to preventthe failed protection system delta-T or Tavg signal from precipitating an inaccurate control systemresponse. Under normal operating conditions with no failures in any reactor coolant system (RCS)narrow range temperature instrument channel, the MSS will reject both the highest and the lowestof the three channels received and pass to the control system only the signal whose value fallsbetween the high/low extremes (i.e., median signal). If two of the three input signals haveidentical values, the MSS will select one of the two identical signals for control until a deviationbetween the two is detected, at which point the median signal will be passed to the control systemas discussed above. If one of the three inputs should deviate significantly from normal (i.e., -3°Ffor Tavg; -3.2% delta-T power for a delta-T input at 100% power based on a 63.4°F delta-Tcondition), the MSS will transfer to a high select mode and select the higher of the remaining twovalid inputs for reactor control. The use of the MSS circuits in the reactor control system satisfiesthe Control and Protection System interaction requirements of IEEE Std279-1971, and prevents aspurious low temperature signal from causing rod withdrawals.In addition, channel deviation signals in the control system will give an alarm if anytemperature channel deviates significantly from the auctioneered (median) value. Automatic rodwithdrawal blocks will also occur if any two of the temperature channels indicate anovertemperature or overpower condition.

Revision 52-09/29/2016NAPS UFSAR7.2-26Two hot leg temperature indications are available at the Auxiliary Monitoring Panel. One ofthem is installed with a specific separation from the additional temperature indication available inthe control room. This separation meets 10CFR50 AppendixR SectionIII.G.2.7.2.2.3.3Pressurizer PressureNorthAnna uses separate transmitters for pressurizer pressure protection and controlfunctions. There are three transmitters used to provide inputs to three protection channels. Thereare two additional transmitters used for reactor coolant pressure control functions. The protectionchannels provide high- and low-pressure protection, input to the overtemperature deltaTprotection function, and indication. The indication is isolated from the protection functions.A spurious high-pressure signal from a pressurizer pressure control channel can causedecreasing pressure by the actuation of either spray or relief valves. Additional redundancy isprovided in the low pressurizer pressure reactor trip logic and in the logic for safety injection toensure low-pressure protection.An additional pressurizer pressure indication is available at the Auxiliary Monitoring Paneland is installed with a specific separation from the additional pressurizer pressure indicationavailable in the control room. This separation meets AppendixR SectionIII.G.2.7.2.2.3.4Pressurizer Water LevelThree pressurizer water level channels are used for reactor trip. Isolated signals from thesechannels are used for pressurizer water level control. A failure in the water level control systemcould fill or empty the pressurizer at a slow rate (on the order of half an hour or more).The reference leg is uninsulated and will remain near local ambient temperature. Thistemperature will vary somewhat over the length of the reference leg piping under normaloperating conditions but will not exceed 140°F. During a blowdown accident, any reference legwater-flashing to steam will be confined to the condensate-steam interface in the reference leg atthe top of the temperature barrier leg and will have only a small (about 1inch) effect on measuredlevel. Some additional error may be expected due to effervescence of hydrogen in the temperaturebarrier water.Experience has shown that during normal operating conditions hydrogen gas canaccumulate in the upper part of the reference leg of the pressurizer water level instruments. Atreactor coolant system pressures, high concentrations of dissolved hydrogen in the water of thereference leg are possible. It has been hypothesized that a sudden primary system depressurizationwould cause rapid effervescence of the dissolved hydrogen in the water of the reference leg. Thisphenomenon could blow out the reference leg, creating a large error in measured pressurizer level.Accurate calculations of this effect have been difficult to obtain. Thus, the effect of a suddenprimary system depressurization on the pressurizer high level reactor trip is to generate a reactortrip somewhat below the actual pressurizer high-level trip setpoint. To generate a high pressurizer Revision 52-09/29/2016NAPS UFSAR7.2-27level reactor trip at a lower level than the true setpoints is conservative and will not requirechanges in the plant safety analysis report. Pressurizer low level is not used for either reactor tripor safety injection. It should be noted that the relatively large error caused by the rapiddepressurization is of a transient nature due to the ongoing condensation process within thereference leg. This will correct the level error in a short period of time as the condensate fills thereference leg to its normal level.Significant leaks of the reference leg to atmosphere will be immediately detectable byoff-scale indication and alarms on the control board. Small leaks are detectable by deviationsfrom other channels. A closed pressurizer level instrument shutoff valve would be detectable bycomparing the level indications from the redundant channels (three channels). A control roomalarm is installed to indicate an error between measured pressurizer water level and theprogrammed pressurizer water level. There is no single instrument valve which could affect morethan one of the three channels.A pressurizer water level indication is available at the Auxiliary Monitoring Panel and isinstalled with a specific separation from the addition pressurizer water level indication availablein the control room. This separation meets 10CFR50 AppendixR SectionIII.G.2.7.2.2.3.5Steam Generator Water Level and Feedwater FlowThe basic function of the reactor protection circuits associated with low steam generatorwater level and low feedwater flow is to preserve the steam generator heat sink for the removal oflong-term residual heat. Should a complete loss of feedwater occur, the reactor would be trippedon low-low steam- generator water level. In addition, redundant auxiliary feedwater pumps areprovided to supply feedwater to maintain residual heat removal after trip, preventing eventualthermal expansion and discharge of the reactor coolant through the pressurizer relief valves intothe relief tank even when main feedwater pumps are incapacitated.This reactor trip acts before the steam generators are dry to reduce the required capacity andstarting time requirements of these auxiliary feedwater pumps and to minimize the thermaltransient on the reactor coolant system and steam generators. Therefore, the low-low steamgenerator water level reactor trip circuit is provided for each steam generator to ensure thatsufficient initial thermal capacity is available in the steam generator at the start of the transient.The feedwater control system includes steam generator narrow range level median signalselection (MSS) circuitry. All three SG level measurement channels are input to the controlsystem and compared by the MSS. The MSS selects the median signal for use by the controlsystem. By rejecting the high and low signals, the MSS prevents the control system from actingon any single failed protection system instrument channel. Since no adverse control system actionmay now result from a single, failed protection instrument channel, a second random protectionsystem failure (as would otherwise be required by IEEE-279) need not be considered. Signalsresulting from a single failed high or low SG level channel will be rejected for control purposes Revision 52-09/29/2016NAPS UFSAR7.2-28and, therefore, will not affect the system. The MSS eliminates the control and protection systeminteraction mechanism.The isolation devices separating the low-low steam generator water level protectionchannels and the MSS of the steam generator water level control system perform the isolationfunction between the control and protection systems.The control room recorders used to meet Regulatory Guide1.97 requirements described insection 7.5 for steam generator narrow range water level, steam flow rate, and feedwater flow ratewill also record the median steam generator level as determined by the control system.A mismatch between steam demand and feedwater flow that results in lowering steamgenerator water level will actuate alarms to alert the operator of this situation in time for manualcorrection or, if the condition is allowed to continue, the reactor will eventually trip on a low-lowwater level signal independent of indicated feedwater flow.A mismatch between steam flow and feedwater flow that results in a rising steam generatorwater level would actuate alarms to alert the operator of the situation in time for manualcorrection.If the condition is allowed to continue, a two-out-of-three high-high steam generator waterlevel signal from any steam generator, independent of the indicated feedwater flow, will causefeedwater isolation and trip the turbine. The turbine trip will result in a subsequent reactor trip ifreactor power is above the setpoint of P-8.In addition, the three-element feedwater controller incorporates reset action on the levelerror signal, such that with expected controller settings a rapid increase or decrease in the flowsignal would cause only a small change in level before the controller would compensate for thelevel error. A slow change in the feedwater signal would have no effect at all. A spurious low orhigh steam flow signal would have the same effect as high or low feedwater controller output,discussed above.In the event of an ATWS, the AMSAC would operate provided that the C-20 permissive issatisfied by the unit being above a specific power level based on turbine first stage pressure.When the narrow range steam generator level detected by two out of three channels on each oftwo out of three steam generators is below the AMSAC setpoint and the C-20 permissive issatisfied, an AMSAC trip can be generated. Further description of the C-20 setpoint and its basisis provided in Section7.7.1.14. The AMSAC steam generator level can be the same as the RPSlow-low level setpoint or may be set as much as 5% lower than the RPS setpoint, providingcertain criteria are met. The AMSAC trip is time delayed to allow the RPS to function prior toAMSAC action. AMSAC trips the turbine, trips the reactor by tripping the power feeder breakersfor the rod control motor generator sets, isolates the sample and blowdown lines, and start allauxiliary feedwater pumps. This logic is shown in Figure7.2-13.

Revision 52-09/29/2016NAPS UFSAR7.2-297.2.3Tests and InspectionsThe reactor trip system meets the testing requirements of Reference13 with the exceptionsgiven in Section7.2.2.2.5. The testability of the system is discussed in Section7.2.2.2.1. Testintervals are specified in the Technical Specifications.7.2.3.1Inservice Tests and InspectionsPeriodic surveillance of the reactor trip system is performed to ensure proper protectiveaction. This surveillance consists of checks, calibrations, and channel operational testing, whichare defined in the Technical Specifications.The minimum frequency for checks, calibration, and testing are defined in the TechnicalSpecifications.7.2.3.2Periodic Testing of the Nuclear Instrumentation SystemPeriodic tests of the nuclear instrumentation system are performed as specified in theTechnical Specifications.Any deviations noted during the performance of these tests are investigated and corrected inaccordance with the established calibration and troubleshooting procedures provided in the PlantTechnical Manual for the nuclear instrumentation system. Protection trip and permissive interlocksettings are indicated in the Technical Requirements Manual. Control settings are indicated in theNorthAnna Setpoint Document.

7.2.3.3Periodic Testing of the Process Analog Channels of the Protection CircuitsPeriodic tests of the analog channels of the protection circuits are performed as specified inthe Technical Specifications.

7.2.3.4Safety Guide22Periodic testing of the reactor trip system actuation functions, as described, complies withAEC Safety Guide22, Periodic Testing of Protection System Actuation Functions,February1971. Under the present design, there are protection functions that are not tested atpower. These are as follows:1.Generation of a reactor trip by tripping the main coolant pump breakers.2.Generation of a reactor trip by tripping the turbine.3.Generation of a reactor trip by use of the manual trip switch.4.Generation of a reactor trip by actuating the safety injection system.

Revision 52-09/29/2016NAPS UFSAR7.2-30The actuation logic for the functions listed is tested off-line. As required by SafetyGuide22, where equipment is not tested during reactor operation it has been determined that:1.There is no practicable system design that would permit operation of the equipment withoutadversely affecting the safety or operability of the plant.2.The probability that the protection system will fail to initiate the operation of the equipmentis, and can be maintained, acceptably low without testing the equipment during reactoroperation.3.The equipment can routinely be tested when the reactor is shut down.Where the ability of a system to respond to a bona fide accident signal is intentionallybypassed for the purpose of performing a test during reactor operation, each bypass condition isautomatically indicated to the reactor operator in the main control room by a separate annunciatorfor the train in test. Test circuitry does not allow two trains to be tested at the same time, so thatextension of the bypass condition to redundant systems is prevented. See Section7.2.2.2.1 fordetails of testing the channels and trains of the reactor trip system.

7.2REFERENCES

1.T. W. Burnett, Reactor Protection System Diversity in Westinghouse Pressurized WaterReactors, WCAP-7306, April1969.2.J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System, WCAP-7380-L,January1971 (Westinghouse NES Proprietary); and WCAP-7669, May1971(nonproprietary).3.J. A. Nay, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems,WCAP-7547-L, March1971 (Westinghouse NES Proprietary); WCAP-7671, May1971(nonproprietary); J. B. Reid, Process Instrumentation for Westinghouse Nuclear SteamSupply Systems (W CID 7300Series), WCAP-7913.4.D. N. Katz, Solid State Logic Protection System Description, WCAP-7488-L, March1971(Westinghouse NES Proprietary); and WCAP-7672, May1971 (nonproprietary).5.I. Garber, Isolation Tests Process Instrumentation Isolation Amplifier WestinghouseComputer and Instrumentation Division Nucana 7300Series, WCAP-7862,September1972.6.J. B. Lipchak and R. R. Bartholomew, Test Report Nuclear Instrumentation System IsolationAmplifier, WCAP-7506-L, October1970 (Westinghouse NES Proprietary); andWCAP-7819, Rev.1, January1972 (nonproprietary).7.W. C. Gangloff, An Evaluation of Anticipated Operational Transients in WestinghousePressurized Water Reactors, WCAP-7486, May1971.

Revision 52-09/29/2016NAPS UFSAR7.2-318.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard: Criteria forProtection Systems for Nuclear Power Generating Stations, IEEE Std279-1971.9.Westinghouse 7300 Series Process Control System Noise Tests, WCAP-8892-A, June1977.10.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard Criteria forClassIE Electric Systems for Nuclear Power Generating Stations, IEEE Std308-1971.11.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Standard; GeneralGuide for Qualifying ClassI Electric Equipment for Nuclear Power Generating Stations,IEEE Std323-1971.12.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Guide for TypeTests of Continuous-Duty ClassI Motors Installed Inside the Containment of Nuclear PowerGenerating Stations, IEEE Std334-1971.13.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial Use Criteria for thePeriodic Testing of Nuclear Power Generating Station Protection Systems, IEEEStd338-1971.14.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial-Use Guide for SeismicQualification of ClassI Electric Equipment for Nuclear Power Generating Stations, IEEEStd344-1971.15.General Design Criteria for Nuclear Power Plants, AppendixA to Title 10CFR50,July7,1971.16.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard for ElectricalPenetration Assemblies in Containment Structures for Nuclear Fueled Power GeneratingStations, IEEE Std317-1971.17.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard Installation,Inspection, and Testing Requirements for Instrumentation and Electric Equipment Duringthe Construction of Nuclear Power Generating Stations, IEEE Std336-1971.18.NUREG-1218, Regulatory Analysis for Resolution of USI A-47, Safety Implications ofControl Systems in LWR Nuclear Power Plants, U.S. Nuclear Regulatory Commission,July1989.19.Technical Report EE-0101, Setpoint Bases Document Analytical Limits, Setpoints andCalculations for Technical Specifications Instrumentation at NorthAnna and Surry PowerStations.20.WCAP-13632-P-A, Revision2, Elimination of Pressure Sensor Response Time TestingRequirements, January1996.21.WCAP-14036-P-A, Revision1, Elimination of Periodic Protection Channel Response TimeTests, December1995.

Revision 52-09/29/2016NAPS UFSAR7.2-32Table7.2-1LIST OF REACTOR TRIPSReactor TripCoincidence LogicInterlocksComments1.High neutron flux (power range)2/4Manual block of low setting permitted by P-10High and low settings; manual block and automatic reset of low setting by P-10.2.Intermediate range1/2Manual block permitted by P-10Manual block and automatic reset.3.Source range neutron flux1/2Manual block permitted by P-6, interlocked with P-10Manual block and automatic reset. Automatic block above P-10. Manual reset available below P-10.4.Power range high positive neutron flux rate2/4No interlocks5.Power range high negative neutron flux rate2/4No interlocks6.Overtemperature deltaT2/3No interlocks7.Overpower deltaT2/3No interlocks8.Pressurizer low pressure2/3Interlocked with P-7Blocked below P-7.

9.Pressurizer high pressure2/3No interlocks10.Pressurizer high water level2/3Interlocked with P-7Blocked below P-7.11.Low reactor coolant flow2/3 per loopInterlocked with P-7 and P-8Low flow in one loop will cause a reactor trip when above P-8 and a low flow in two loops will cause a reactor trip when above P-7 Blocked below P-7.12.Reactor coolant pump breakers open2/3Interlocked with P-7Blocked below P-7. Open breaker in 1 loop permitted below P-8.1/3Interlocked with P-8Blocked below P-813.Reactor coolant pump bus under-voltage2/3Interlocked with P-7Low voltage on all buses permitted below P-7.*AMSAC trips the reactor by tripping the power supply breakers to the rod control motor generator sets which in turn trips the unit.

Revision 52-09/29/2016NAPS UFSAR7.2-3314.Reactor coolant pump bus under-frequency2/3Interlocked with P-7Underfrequency on two buses will cause reactor trip; reactor trip blocked below P-7.15.Low-low steam generator water level2/3 per loopNo InterlocksBlocked for a loop in which the primary coolant stop valves are closed.16.Safety injection signalCoincident with actuation of safety injectionNo Interlocks(See Section7.3 for engineered safety features actuation conditions.)17.Turbine-generator trip2/3Interlocked with P-8Blocked below P-8.a.Lowauto-stopoilpressureb.Turbine stop valve close4/4Interlocked with P-8Blocked below P-8.18.ManualNo interlocks19.General warning2/2 trains (1 per train)No interlocks20.Steam generator water level (AMSAC)*2/3 per loop per 2/3 steam generators after time delayInterlocked with C-20Blocked below C-20 after time delay.Table7.2-1(continued)LIST OF REACTOR TRIPSReactor TripCoincidence LogicInterlocksComments*AMSAC trips the reactor by tripping the power supply breakers to the rod control motor generator sets which in turn trips the unit.

Revision 52-09/29/2016NAPS UFSAR7.2-34Table7.2-2REACTOR TRIP SYSTEM ACCURACIES AND RANGESReactor Trip SignalTrip AccuracySee NoteREACTOR TRIP SYSTEM TRIP SETPOINT ACCURACIES1.Power range high neutron flux+/-5.61% of span2.Intermediate range high neutron fluxnot calculated(a)3.Source range high neutron flux+/-4.412% of linear span4.Power range high positive neutron flux ratenot required(a, b)5.Power range high negative neutron flux ratenot required(a, b)6.Overtemperature T+/-7.485% of span with f(I)<0+/-4.606% of span with f(I)=0+/-6.872% of span with f(I)>07.Overpower T+/-3.68% of span8.Pressurizer low pressure+/-2.660% of span9.Pressurizer high pressure+/-2.612% of span10.Pressurizer high water level+/-6.887% of span11.Low reactor coolant flow+/-2.34% of span (Foxboro transmitters)+/-2.25% of span (Rosemount transmitters)12.Reactor coolant pump breakers opennot required(a, b)13.Reactor coolant pump bus undervoltage+/-143.5 volts(a, b)14.Reactor coolant pump bus underfrequency+/-0.30 hertz(a, b)15.Low-low steam generator water level+6.42% to +10.38% of narrow range span16.Safety injection actuationnot applicable - digital input from ESF17.Turbine-generator trip:a.Low auto-stop oil pressurenot required(a, b)b.Turbine stop valves closednot required(a, b)18.Manual reactor tripnot required(a, b)19.General warningnot required(a, b)20.AMSAC (SG water level)+/-0.23% of narrow range span(a, b)reactor trip system Process Ranges1.Power range high neutron flux0 to 120% power2.Intermediate range high neutron flux10-11 to 10-3 amperes(a)3.Source range high neutron flux100 to 106 counts/second4.Power range high positive neutron flux rate0 to 120% power(a)5.Power range high negative neutron flux rate0 to 120% power(a)a.Reactor trip signal protection is not credited in plant safety analyses.b.A safety analysis setpoint limit has not been established; calculation of setpoint accuracy is not required.c.Process input to reactor trip system is digital only; no process range exists.

Revision 52-09/29/2016NAPS UFSAR7.2-356.Overtemperature T:Trip setpoint0 to 150% powerThot530 to 650°FTcold510 to 630°FTavg530 to 630°FPressurizer pressure1700 to 2500psigF(I)0 to 150% T7.Overpower T(See Overtemperature T)8.Pressurizer low pressure1700 to 2500psig9.Pressurizer high pressure1700 to 2500psig10.Pressurizer high water level0 to 100% level11.Low reactor coolant flow0 to 120% rated flow12.Reactor coolant pump breakers opennot applicable(a, c) 13.Reactor coolant pump bus undervoltage0 to 4200 volts(a)14.Reactor coolant pump bus underfrequency55 to 59.5 hertz(a)15.Low-low steam generator water level0 to 100% narrow range level16.Safety injection actuationnot applicable(c)17.Turbine-generator trip:a.Low auto-stop oil pressure15 to 150psig(a) b.Turbine stop valves closednot applicable(a, c)18.Manual reactor tripnot applicable(a, c) 19.General warningnot applicable(a, c) 20.AMSAC0 to 100% narrow range level(a)Table7.2-2(continued)REACTOR TRIP SYSTEM ACCURACIES AND RANGESReactor Trip SignalTrip AccuracySee Notea.Reactor trip signal protection is not credited in plant safety analyses.b.A safety analysis setpoint limit has not been established; calculation of setpoint accuracy is not required.c.Process input to reactor trip system is digital only; no process range exists.

Revision 52-09/29/2016NAPS UFSAR7.2-36Table7.2-3REACTOR TRIP SYSTEM INTERLOCKSDesignationDerivationFunctionPower Escalation PermissivesP-61/2 neutron flux (intermediate range) above setpointAllows manual block of source range reactor trip2/2 neutron flux (intermediate range) below setpointDefeats the block of source range reactor tripP-102/4 neutron flux (power range) above setpointAllows manual block of power range (low setpoint) reactor tripAllows manual block of intermediate range reactor trip and intermediate range rod stops (C-1)Blocks source range reactor trip (back-up for P-6)3/4 neutron flux (power range) below setpointDefeats the block of power range (low setpoint) reactor tripDefeats the block of intermediate range reactor trip and intermediate range rod stops (C-1)Input to P-7BlocksofReactorTripsP-73/4 neutron flux (power range) below setpoint (from P-10) and 2/2 turbine impulse chamber pressure below setpoint (from P-13)Blocks reactor trip on low flow or reactor coolant pump breakers open in more than one loop, undervoltage, underfrequency, pressurizer low pressure, and pressurizer high levelP-83/4 neutron flux (power range) below setpointBlocks reactor trip on low flow or reactor coolant pump breaker open in a single loop and on turbine tripP-132/2 turbine impulse chamber pressure below setpointInput to P-7 Revision 52-09/29/2016NAPS UFSAR7.2-37Table7.2-4TRIP CORRELATIONTripAccidentTechnicalSpecification1.Source range, high neutron flux15.2.11)Uncontrolled RCCA bank withdrawal from a subcritical conditionYes2.Intermediate range, high neutron flux15.2.11)Uncontrolled RCCA bank withdrawal from a subcritical conditionYesa3.Power range, high neutron flux (low setpoint)15.2.11)Uncontrolled RCCA bank withdrawal from a subcritical conditionYes4.Power range, high neutron flux (high setpoint)15.2.11)Uncontrolled RCCA bank withdrawal from a subcritical conditionYes15.2.22)Uncontrolled RCCA bank withdrawal at power15.2.63)Startup of an inactive reactor coolant loop15.2.74)Loss of external electrical load and/or turbine trip15.2.105)Excessive heat removal due to feedwater system malfunction15.2.116)Excessive load increase15.2.137)Accidental depressurization of the main steam system5.Power range high positive neutron flux rate15.4.6Rod ejectionYes a6.Power range high negative neutron flux rate15.2.31)RCCA misalignmentYes7.Overpower delta T15.2.21)Uncontrolled RCCA bank withdrawal at powerYes15.2.102)Excessive heat removal due to feedwater system malfunctiona.Credit not taken for trip for reasons of conservatism in the safety analyses.

Revision 52-09/29/2016NAPS UFSAR7.2-387.Overpower delta T (continued)15.2.113)Excessive load increase15.2.134)Accidental depressurization of the main steam system8.Overtemperature delta T15.2.21)Uncontrolled RCCA bank withdrawal at powerYes15.2.42)Uncontrolled boron dilution15.2.73)Loss of external electrical load and/or turbine trip15.2.104)Excessive heat removal due to feedwater system malfunction15.2.115)Excessive load increase15.2.126)Accidental depressurization of the RC system15.2.137)Accidental depressurization of the main steam system9.Low primary coolant flowa.Undervoltage15.2.51)Partial loss of forced reactor coolant flowYesb.Underfrequencyc.Low flow or pump breaker open 1 of 3 loops15.2.92)Loss of offsite power to the station auxiliaries (station blackout)d.Low flow or pump breaker open 2 of 3 loops15.3.43)Complete loss of forced reactor coolant flow10.Pressurizer high pressure15.2.21)Uncontrolled RCCA bank withdrawal at powerYesTable7.2-4(continued)TRIP CORRELATIONTripAccidentTechnicalSpecificationa.Credit not taken for trip for reasons of conservatism in the safety analyses.

Revision 52-09/29/2016NAPS UFSAR7.2-3910.Pressurizer high pressure (continued)15.2.72)Loss of external electrical load and/or turbine trip15.4.2.23)Main feedline break11.Pressurizer high water level15.2.21)Uncontrolled RCCA bank withdrawal at powerYes15.2.72)Loss of external electrical load and/or turbine trip12.Pressurizer low pressure15.2.121)Accidental depressurization of the RC systemYes13.Low-low steam generator level15.2.81)Loss of normal feedwaterYes15.4.2.22)Main feedline breakTable7.2-4(continued)TRIP CORRELATIONTripAccidentTechnicalSpecificationa.Credit not taken for trip for reasons of conservatism in the safety analyses.

Revision 52-09/29/2016NAPS UFSAR7.2-40Table7.2-5REACTOR TRIP SYSTEM INSTRUMENTATIONFunctional UnitChannels to TripMinimum Channels Operable1.Manual Reactor Trip12122.Power Range, Neutron Flux233.Power Range, Neutron Flux, High Positive Rate234.Power Range, Neutron Flux, High Negative Rate235.Intermediate Range, Neutron Flux126.Source Range, Neutron Fluxa.Startup12b.Shutdown12c.Shutdown (Indication only)017.Overtemperature T228.Overpower T229.Pressurizer Pressure-Low2210.Pressurizer Pressure-High2211.Pressurizer Water Level-High2212.Loss of Flow-(Above P-7)2/loop in any loop >P-82/loop in each loop2/loop in any 2 loops >P-713.Steam Generator Water Level-Low-Low2/loop2/loop14.Undervoltage-Reactor Coolant Pump Busses2215.Underfrequency-Reactor Coolant Pump Busses2216.Turbine Tripa.Low Auto Stop Oil Pressure22b.Turbine Stop Valve Closure4317.Safety Injection Input from ESF1218.Reactor Coolant Pump Breaker Position Trip Above P-71>P-8 2>P-71/breaker19.a.Reactor Trip Breakers12b.Reactor Trip Bypass Breakers1120.Automatic Trip Logic1221.Reactor Trip System Interlocks Revision 52-09/29/2016NAPS UFSAR7.2-41a.Intermediate Range Neutron Flux, P-612b.Low Power Reactor Trips Block, P-7P-10 Input23orP-13 Input12c.Power Range Neutron Flux, P-823d.Power Range Neutron Flux, P-1023e.Turbine Impulse Chamber Pressure, P-1312Table7.2-5(continued)REACTOR TRIP SYSTEM INSTRUMENTATIONFunctional UnitChannels to TripMinimum Channels Operable Revision 52-09/29/2016NAPS UFSAR7.2-42FIGURE 7.2-1INDEX AND SYMBOLS Revision 52-09/29/2016NAPS UFSAR7.2-43FIGURE 7.2-2REACTOR TRIP SIGNALS(Fig. 7.2-9)(Fig. 7.2-8)(Fig. 7.7-8)(Fig. 7.2-9)(Fig. 7.2-8)(Fig. 7.2-8)

Revision 52-09/29/2016NAPS UFSAR7.2-44FIGURE 7.2-3NUCLEAR INSTRUMENTATION AND TRIP SIGNALSP-6(Fig. 7.2-10)P-10(Fig. 7.2-10)P-10(Fig. 7.2-10)P-10 (Fig. 7.2-10)High Neutron FluxRate Reactor Trip(Fig. 7.2-2)Reactor Trip (Fig. 7.2-2)High Neutron Flux(High Setpoint)Reactor Trip (Fig. 7.2-2)High Neutron Flux (Low Setpoint)Reactor Trip(Fig. 7.2-2)High Neutron FluxReactor Trip(Fig. 7.2-2)ToI.R. Rod Stop(Fig. 7.2-10)To I.R. Rod Stop(Fig. 7.2-10)To I.R. Rod Stop (Fig. 7.2-10)High Neutron Flux Reactor Trip (Fig. 7.2-2)

Revision 52-09/29/2016NAPS UFSAR7.2-45FIGURE 7.2-4SETPOINT REDUCTION FUNCTION FOR OVERTEMPERATURE T TRIPS (TYPICAL)

Revision 52-09/29/2016NAPS UFSAR7.2-46FIGURE 7.2-5PRIMARY COOLANT SYSTEM TRIP SIGNALSReactor Trip(Fig. 7.2-2)Reactor Trip(Fig. 7.2-2)Reactor Trip(Fig. 7.2-2)P-7(Fig. 7.2-10)Reactor Trip (Fig. 7.2-2)To Start Turbine Runback Lock Automatic and Manual Rod Withdrawal (Figs. 7.2-8 and 7.7-2)P-12Lo-Lo TavgInterlock(Fig.7.2-7and7.7-5)To Feedwater Isolation (Fig. 7.7-8)Reactor Trip(Fig. 7.2-2)Reactor Trip(Fig. 7.2-2)P-7 (Fig. 7.2-10)P-8 (Fig. 7.2-10)

Revision 52-09/29/2016NAPS UFSAR7.2-47FIGURE 7.2-6PRESSURIZER TRIP SIGNALSP7 (Fig. 7.2-10)Reactor Trip(Fig. 7.2-2)Reactor Trip (Fig. 7.2-2)P7 (Fig. 7.2-10)Reactor Trip (Fig. 7.2-2)To Safety Injection(Fig. 7.2-9)To Pressurizer Relief Block(Fig. 7.7-6)

Revision 52-09/29/2016NAPS UFSAR7.2-48FIGURE 7.2-7STEAM GENERATOR TRIP SIGNALS(Fig. 7.2-9)(Fig. 7.2-9)(Fig. 7.2-5)(Fig. 7.2-9)(Fig. 7.2-2)(Fig. 7.3-1)(Fig. 7.7-8)

Revision 52-09/29/2016NAPS UFSAR7.2-49FIGURE 7.2-8TURBINE TRIPS, RUNBACKS, AND OTHER SIGNALSP-4 Reactor TripTrain B (Fig. 7.2-2)Steam Generator Hi-Hi Level or S.I. Train B (Fig. 7.7-8)Steam Generator Hi-Hi Level or S.I. Train A (Fig. 7.7-8)P-4 Reactor TripTrain A (Fig. 7.2-2)P-13 To P-7 (Fig. 7.2-10)C-5 Block Automatic RodWithdrawal(Fig. 7.7-2)P-8 (Fig. 7.2-10)To Reactor Trip (Fig. 7.2-2)To Steam Dump Control(Fig. 7.7-5)C-3 OvertemperatureT (2/3)(Fig. 7.2-5)C-4 OverpowerT (2/3)(Fig. 7.2-5)

Revision 52-09/29/2016NAPS UFSAR7.2-50FIGURE 7.2-9SAFEGUARDS ACTUATION SIGNALSMain Steam Line Flow Coincident with Low Steam Line Pressure or Lo-Lo Tavg (Fig. 7.2-7)High Steam Line DifferentialPressure(Fig. 7.2-7)Low-Low Pressurizer Pressure (Fig. 7.2-6)Auxiliary Feedwater Pumps (Fig. 7.3-14)Reactor Trip(Fig. 7.2-2)FeedwaterIsolation(Fig. 7.7-8)P-4 Reactor Trip (Fig.

7.2-2)

Revision 52-09/29/2016NAPS UFSAR7.2-51FIGURE 7.2-10NUCLEAR INSTRUMENTATION AND BLOCKSP-13 Turbine Impulse Chamber Pressure(Fig. 7.2-8)P-7(Figs. 7.2-5, 7.2-6)P-10(Fig. 7.2-3)P-6(Fig. 7.2-3)P-8(Figs. 7.2-5 &

7.2-8)C-1:High Neutron FluxRod Stop(Block Automatic & Manual Rod Withdrawal)

(Fig. 7.7-2)C-2Overpower Rod Stop(Block Automatic & Manual Rod Withdrawal)

(Fig. 7.7-2)From I/N 56A IR Bypass(Fig. 7.2-3)From IRBlock Logic(Fig. 7.2-3)From I/N 35AIR Bypass(Fig. 7.2-3)

Revision 52-09/29/2016NAPS UFSAR7.2-52FIGURE 7.2-11PRESSURIZER REFERENCE LEG LEVEL SYSTEM Revision 52-09/29/2016NAPS UFSAR7.2-53FIGURE 7.2-12DESIGN TO ACHIEVE ISOLATION BETWEEN CHANNELS Revision 52-09/29/2016NAPS UFSAR7.2-54FIGURE 7.2-13ANTICIPATED TRANSIENT WITHOUT SCRAM MITIGATION SYSTEM ACTUATION CIRCUITRY (AMSAC)

Revision 52-09/29/2016NAPS UFSAR7.3-17.3ENGINEERED SAFETY FEATURES ACTUATION SYSTEMElectrical schematic diagrams for the engineered safety features (ESF) actuation system,ESF actuator circuits, and their supporting systems are included in reports NA-TR-1001 andNA-TR-1002, Safety Related Electrical Schematics, dated May10,1973, which were submittedto the Atomic Energy Commission (AEC) on May18,1973, as separate documents. For generalnotes, diagram symbols, and terminology, refer to Reference Drawings1 through4.7.3.1DescriptionThe ESF actuation system senses selected plant parameters, determines whether or notpredetermined safety limits are being exceeded and, if they are, combines the signals into logicmatrices sensitive to combinations indicative of primary or secondary system boundary ruptures(ClassIII orIV faults). Once the required logic combination is completed, the system sendsactuation signals to those ESF actuation devices whose aggregate function best serves therequirements of the accident.The design meets the requirements of General Design Criteria13, 20, 21, 22, 23, and24.7.3.1.1Functional DesignThe following is a summary of generating station conditions requiring protective action:1.Primary system:a.Rupture in small pipes or cracks in large pipes.b.Rupture of a reactor coolant pipe (LOCA).c.Steam generator tube rupture.2.Secondary system:a.Minor secondary system pipe breaks resulting in steam release rates equivalent to a singledump, or relief or safety valve operation.b.Rupture of a major steam pipe.The following summarizes the generating station variables required to be monitored foreach accident:1.Rupture in small pipes or cracks in large primary system pipes:a.Pressurizer pressure.b.Pressurizer water level.c.Containment pressure.

Revision 52-09/29/2016NAPS UFSAR7.3-22.Rupture of a reactor coolant pipe (LOCA):a.Pressurizer pressure.b.Pressurizer water level.c.Containment pressure.3.Steam generator tube rupture:a.Pressurizer pressure.b.Pressurizer water level.4.Minor secondary system pipe breaks:a.Pressurizer pressure.b.Pressurizer water level.c.Steam-line pressures.d.Steam-line differential pressures.e.Steam flows.f.Reactor coolant average temperatures (Tavg).g.Containment pressure.5.Rupture of a major steam pipe: Same as 4 above.7.3.1.1.1Signal ComputationThe ESF actuation system consists of two discrete portions of circuitry: an analog portionconsisting of redundant channels that monitor various plant parameters such as the reactor coolantsystem and steam system pressures, temperatures, and flows, and containment pressures; and adigital portion consisting of two redundant logic trains that receive inputs from the analogprotection channels and perform the needed logic to actuate the ESF actuation devices. Eachdigital train can actuate the minimum ESF actuation devices required. The intent is that any singlefailure within the ESF system shall not prevent system action when required.The redundant concept is applied to both the analog and logic portions of the system. Theseparation of redundant analog channels begins at the process sensors and is maintained in thefield wiring, containment vessel penetrations, and analog protection racks, terminating at theredundant groups of ESF logic racks. The design meets the requirements of General DesignCriterion21.Section7.2 provides further details on protective instrumentation. The same designphilosophy applies to both systems and meets the requirements of General Design Criteria20, 21,22, 23, and24.

Revision 52-09/29/2016NAPS UFSAR7.3-3The variables are sensed by the analog circuitry as discussed in Reference1 and inSection7.2. The outputs from the analog channels are combined into actuation logic as shown inFigures7.2-5, 7.2-6, 7.2-7, and7.2-9. The Technical Specifications give additional informationpertaining to logic and function. Table7.3-2 provides the number of channels required to trip andthe minimum channels that are required operable.The interlocks associated with the ESF actuation system are outlined in Table7.3-1, theTechnical Specifications, and the Technical Requirements Manual. These interlocks satisfy thefunctional requirements discussed in Section7.1.3.Manual reset controls on the main control board are provided to switch from the injection tothe recirculation phase after a LOCA.7.3.1.1.2Devices Requiring ActuationThe following are the actions that the ESF actuation system initiates when it is called on toperform its function:1.Safety injection.2.Reactor trip.3.Feedwater line isolation.4.Auxiliary feedwater system actuation.5.Service water (pump start and system valve operation).6.Containment depressurization system.7.Containment isolation (phaseA andB).

8.Emergency diesel start-up (and loading on loss of power).9.Main steam line isolation.7.3.1.2Design Bases: IEEE Std279-1971 (Reference2)The generating station conditions that require protective action are given in Section7.3.1.1.The generating station variables that are required to be monitored to provide protective actions arealso summarized in Section7.3.1.1.The only variable sensed by the ESF actuation system that has spatial dependence is reactorcoolant temperature. The effect on the measurement is negated by taking multiple samples fromthe reactor coolant hot leg. The outputs from three hot leg resistance temperature detectors(RTDs) are summed and averaged to obtain a representative hot leg temperature value for a givenloop.The parameter values that will require protective action are given in the TechnicalSpecifications.

Revision 52-09/29/2016NAPS UFSAR7.3-4The malfunctions, accidents, or other unusual events that could physically damageprotection system components or could cause environmental changes and for which provisionshave been made to retain the necessary protection system are as follows.1.LOCA.2.Steam-line breaks.3.Earthquakes.

4.Fire.5.Explosion (hydrogen buildup inside containment).6.Missiles.

7.Flood.Minimum performance requirements are as follows:1.System response times-The ESF actuation response time, or time delay, is defined in theTechnical Specifications. The delay time includes sensor, process (analog), and logic(digital) delay plus, for conservatism, the time delay associated with tripping open the reactortrip breakers and control and latching mechanisms, although the reactor trip (or ESFactuation signal) theoretically occurs before or simultaneously with ESF sequence initiation(see Figure7.2-9).Maximum allowable time delays in generating the actuation signal for accident protectionare listed in the Technical Requirements Manual.2.System accuracies (Reference12)-Accuracies required for generating the requiredactuation signals for loss-of-coolant protection are:a.Pressurizer pressure16.4psi to +25.42psib.Containment pressure+/-3.7% of full scaleAccuracies required in generating the required actuation signals for steam-line breakprotection are:a.Steam-line pressure+/-11.1% of spanb.Steam flow signals+/-20% P span over the range of 0% to 110% fullsteam flowc.Containment pressure signal+/-3.7% of full scale Revision 52-09/29/2016NAPS UFSAR7.3-53.Ranges of sensed variables to be accommodated until the conclusion of protective action isensured-Ranges required in generating the required actuation signals for loss-of-coolantprotection are:a.Pressurizer pressure1700 to 2500psigb.Containment pressure0 to 65psiaRanges required in generating the required actuation signals for steam-line break protectionare:a.Tavg530°F to 630°Fb.Steam-line pressure0 to 1400psigc.Steam-line flow0 to 120% maximum steam flowd.Containment pressure0 to 65psia7.3.1.3Implementation of Functional Design7.3.1.3.1Analog CircuitryThe process analog sensors and racks for the ESF actuation system are covered inReference1. Discussed in this report are the parameters to be measured including pressures,flows, tank and vessel water levels, and temperatures, as well as the measurement and signaltransmission considerations. These latter considerations include the basic current transmissionsystem, transmitters, orifices and flow elements, resistance temperature detectors, andpneumatics. Other considerations covered are automatic calculations, signal conditioning, andlocation and mounting of the devices.See Section7.7.1.11 for a discussion of electrical separation between safety- andnonsafety-related portions of the process analog system.The sensors monitoring the primary system are located as shown on the piping flowdiagrams and reference drawings in Chapter5, Reactor Coolant System. The secondary systemsensor locations are shown on the steam system flow diagrams and reference drawings given inChapter10.7.3.1.3.2Containment PressureNarrow range containment pressure (0-65psia) is sensed by four physically separatedabsolute pressure transmitters mounted outside the containment, connected to containmentatmosphere by four independent 3/8-inch stainless steel lines. The distance from penetration totransmitter is kept to a minimum, and separation is maintained. Wide range containment pressure(0-180psia) is sensed by two absolute pressure transmitters mounted outside the containment.Their sensing lines are tapped off the narrow range containment pressure transmitted sensinglines.

Revision 52-09/29/2016NAPS UFSAR7.3-6The containment pressure instrumentation system is illustrated in Reference Drawings5through10, 28 and29. The design and operation of the system are described inSections7.3.1.3.2.1 and7.3.1.3.2.2. Reference Drawings1 through4 contain notes and symbolsapplicable to the logic diagrams in these sections.7.3.1.3.2.1Design. The four narrow range pressure transmitters form four redundant pressuremeasuring channels, which provide inputs to two isolated separated actuating logic trains. Thefour channels generate initiating signals for the following three conditions:1.High containment pressure.2.Intermediate high-high containment pressure.3.High-high containment pressure.The high containment pressure signal, on 2/3 channels, is one of four conditions that willinitiate a safety injection actuation signal, which, in turn, actuates containment isolation phaseA.Note: The inputs to the logic matrices are implemented via three normally energized logicinput relays, which become de-energized on the receipt of a high containment pressure signal.The intermediate high-high containment pressure signal, on 2/3 channels, is one of twoconditions that will initiate a steam-line isolation.Note: The inputs to the logic matrices are implemented via three normally energized logicinput relays, which become de-energized on the receipt of an intermediate high-high containmentpressure signal.High-high containment pressure, on 2/4 channels, is the only condition that will initiatecontainment depressurization actuation and containment isolation phaseB.Note: The inputs to the logic matrices are implemented via four normally de-energized logicinput relays, which become energized on the receipt of a high-high containment pressure signal.Contacts of input relays enter the signal into the logic portion of the system where theapplicable coincidence logic is performed. The solid-state logic operates master relays in theoutput section, which then operate slave relays, for ESF actuation. The slave relays are used forcontact multiplication.Containment depressurization actuation signals are used in the following ESF systems:1.Quench spray pumps.2.Recirculation spray pumps.3.Refueling water chemical addition system.4.Service water valves.

5.Diesel loading logic.

Revision 52-09/29/2016NAPS UFSAR7.3-7Containment isolation phase B occurs simultaneously with containment depressurizationactuation, that is, as a direct result of high-high containment pressure. The wide range pressuretransmitters provide indication in the control room and are used to monitor containment structuralintegrity during and following an accident. No protection or control function is associated withthese transmitters.Each instrument channel of the containment pressure instrumentation can be tested andcalibrated while the plant is at full power.Since four batteries are available for emergency instrument power, a loss of station powerwill not result in the initiation of safety injection, containment isolation, or main steam lineisolation.All equipment actuated by high, intermediate high-high, and high-high containmentpressure can be manually actuated from the control room as a final backup.During normal plant operation, essentially all of the engineered safeguards components,analog, logic, and actuation circuitry can be fully tested. The few remaining components can bepartially tested (see Section7.3.2.1.5).7.3.1.3.2.2Operation. The operation of the containment pressure instrumentation system isillustrated in Reference Drawings5 through10, 28 and29.Refer to Reference Drawing6, which illustrates the operation of high-high containmentpressure protection. A high-high containment pressure signal will be initiated if the containmentpressure exceeds its setpoint on any 2/4 channels, provided that the associated test switches areclosed.Reference Drawing7 illustrates containment depressurization actuation, which is initiatedby either of the following two conditions:1.Both of the board-mounted manual spray actuation switches are turned to INITIATE.2.High-high containment pressure is present on at least two channels.Reference Drawing8 illustrates the initiation of high containment pressure. A highcontainment pressure signal will be initiated if channel pressure exceeds 17psia in any 2/3channels or any 2/3 test switches are opened.Reference Drawing9 illustrates intermediate high-high containment pressure protection.An intermediate high-high containment pressure signal is initiated when channel pressure exceedsits setpoint on any 2/3 channels, or any 2/3 test switches are opened.Reference Drawing10 illustrates the initiation of high-high containment pressure andcontainment depressurization (trainB), which previously have been described for trainA.

Revision 52-09/29/2016NAPS UFSAR7.3-8Two position reset selector switches for containment spray trainsA &B exist in the controlroom.Reference Drawings28 and29 illustrate the operation of the Recirculation SpraySubsystems, which are a part of the Containment Spray System. Further description of theRecirculation Spray instrumentation is contained in Section7.3.2.11.7.3.1.3.3Safety InjectionFigure7.2-9 and the design and operation sections below explain the safety injectionactuation system. The respective actuation logic is shown in Reference Drawing11.7.3.1.3.3.1Design. The four parameters that will initiate a safety injection signal are as follows:1.Low-low pressurizer pressure.2.High steam-line pressure differential between the steam generators.3.High steam-line flow in two out of three steam lines, coincident with either low steam-linepressure or low-low Tavg in two out of three loops.4.High containment pressure.The purpose of the safety injection system is to maintain clad integrity and thus minimizethe release of fission products from the fuel during a LOCA.The safety injection system provides for the injection of borated water into the reactorcoolant system from the accumulators following a LOCA. The three accumulators areself-contained and are designed to supply borated water as soon as the reactor coolant systempressure drops below accumulator pressure. Additional borated water to the reactor coolantsystem is provided by the charging pumps and the low-head safety injection pumps.Safety injection actuation signals initiate the following:1.Reactor trip.

2.Safety injection system operation.3.Containment isolation phaseA.

4.Emergency diesel starting.5.Main feedwater isolation.6.Start-up of auxiliary feedwater system.7.Start signals to service water pumps and repositioning of the valves.8.Turbine trip.

Revision 52-09/29/2016NAPS UFSAR7.3-97.3.1.3.3.2Operation. Refer to Figure7.2-9, which illustrates the makeup of safety injectionactuation. A safety injection actuation signal will be initiated by any of the following conditions:1.Manual-Turning either of the two board-mounted, manual safety injection switches toINITIATE.2.Auto-Any of the following:a.High steam flow with low steam-line pressure or low-low Tavg.b.High steam-line differential pressure.c.Low-low pressurizer pressure.d.High containment pressure.A safety injection actuation signal may be manually reset by rotating the two position(NORM/RESET) safety injection reset selector switch to the RESET position, provided that the1-min time delay has timed out and that the reactor trip breakers are open. One selector switch isprovided for each train, trainA and trainB.The following is a description of those process channels not included in the reactor trip orESF actuation systems that enable additional monitoring of in-containment conditions in thepost-LOCA recovery period. These channels are located outside of the containment (with theexception of sump instrumentation) and will not be affected by the accidents.1.Refueling water storage tank level-Level instrumentation on the refueling water storagetank consists of four channels. All four channels provide a remote indication at the maincontrol board and two channels provide low-level alarm functions. Three of the fourchannels provide a low level interlock signal that is coincident with Containment High-HighPressure to start the RS pumps as described in Section7.3.2.11. All four channels providesignals to initiate automatic changeover from injection mode to the recirculation mode of theemergency core cooling system (ECCS), as described in Section7.3.2.10.2.High-head safety injection pumps discharge pressure-The discharge header pressurechannel clearly shows that the safety injection pumps are operating. This transmitter isoutside the containment.3.Pump energization-Pump motor power feed breakers indicate that they have closed byenergizing indicating lights on the control board.4.Valve position-All ESF remote-operated valves have position indication on the controlboard to show proper positioning of the valves. Red and green indicator lights are locatednext to the manual control station showing open and closed positions. These lights thusenable the operator to quickly assess the status of the ESF systems. These indications arederived from contacts integral to the valve operators. In the cases of the accumulatorisolation valves, the redundancy of position indication is provided by valve stem-mounted Revision 52-09/29/2016NAPS UFSAR7.3-10limit switches, which actuate annunciators on the control board when the valves are notcorrectly positioned for ESF. The stem-mounted switches are independent of the limitswitches in the motor operators. See Section7.6 for additional information.5.Containment recirculation air coolers-The air coolers cooling water flow is indicated in thecontrol room. The cooling water exit temperatures are provided to the plant computer. Thesensors are outside the reactor containment.6.Sump instrumentation-The containment sump wide range instrumentation consists ofredundant level sensors designed to operate in a post accident environment. LT-RS151A-1,LT-RS151A-2, LT-RS151B-1, and LT-RS151B-2 sump wide range level transmitters arequalified in accordance with IEEE Std323-1974, to meet post accident conditions, includingsubmergence. The indicators are located in the control room.7.3.1.3.4Digital CircuitryThe ESF logic racks are discussed in detail in Reference3. The description includes theconsiderations and provisions for physical and electrical separation as well as details of thecircuitry. Reference3 also covers certain aspects of on-line test provisions, provisions for testpoints, considerations for the instrument power source, considerations for accomplishing physicalseparation, and provisions for ensuring instrument qualification. The outputs from the analogchannels are combined into actuation logic as shown in Figure7.2-5 (Tavg), Figure7.2-6(pressurizer pressure and water level), Figure7.2-7 (steam flow, pressure, and differentialpressure), Figure7.2-9 (ESF actuation), and Figure7.3-1 (auxiliary feedwater).To facilitate ESF actuation testing, two cabinets (one per train) are provided that enable theoperation of safety features actuation devices on a group-by-group basis until the actuation of alldevices has been checked. Final actuation testing is discussed in detail in Section7.3.2.7.3.1.3.5Engineered Safety Features Actuation DevicesThe outputs of the solid-state logic protection system (the slave relays) are energized toactuate, as are the switchgear and motor control centers for all ESF-actuated devices. Thefollowing descriptions and referenced diagrams explain and illustrate the manner in which theengineered safety features are actuated by the ESF actuation signals. Unit protection features andemergency diesel-generator start-up and loading are also described and illustrated. Should anaccident occur coincident with a station electrical blackout, the ESF loads are sequenced onto thediesel generators. This loading is discussed in Chapter8. The design meets the requirements ofGeneral Design Criterion35.1.Figure7.3-2 is a general illustration of the relationship of unit trip signals. The interrelationof tripping between the generator, turbine, and reactor is as follows:a.A generator trip will result in a turbine trip.b.A turbine trip after the generator is on line will result in a generator trip.

Revision 52-09/29/2016NAPS UFSAR7.3-11c.A turbine trip at a preset minimum power will result in a reactor trip.d.A reactor trip will result in a turbine trip.2.Figure7.3-3 illustrates the signal interfaces of ESF actuation and actuated devices. Theseinterfaces are the basis of the ESF system terminology and logic, and the actuation signalsare shown in relation to each other as well as the actuated systems.3.Figures7.3-4 and7.3-5 illustrate that there are two paths provided to actuate theESF-actuated devices: the first, when emergency bus power is not interrupted; the second,when there is a loss of emergency bus power. Should there be a loss of power, the equipmentis started sequentially.4.Figure7.3-6 illustrates the concepts used to adjust and sequence the loads on dieselgenerators. The inputs will be combined by the logic circuit as required, to initiate theappropriate sequence and loading of the diesel generator for given accident input conditions.The resultant blocks represent typical actions taken on equipment assigned to the emergencybus. Detailed logic for specific loads is shown in Reference Drawings11 and12, andFigures7.3-5, 7.3-7 and7.3-8.5.Reference Drawing13, Figure7.3-1, and Figure7.3-7 illustrate the development of the lossof reserve station service power signal for both Units1 and2. Also shown are the resultantactuation of the service water pumps, and the start of auxiliary steam generator feed pumps.6.Figures7.3-5 and7.2-9 illustrate the auto-start signals for an emergency diesel generator.The emergency diesel generator starts whenever the respective emergency bus voltage is lessthan 74%, whenever the bus voltage drops below 90% and remains there for 60seconds orlonger, or whenever a safety injection actuation signal is initiated. This is described inSection8.3.1.1.1.Also shown in Figure7.3-5 are the resultants, should the emergency bus voltage continue todecay below 71% nominal. These resultants are the automatic trip of specified loads.Also illustrated is the subsequent restoration of voltage to the emergency bus, after theemergency diesel-generator supply breaker is closed. Refer to Reference Drawing12(containment depressurization) and Reference Drawing11 (safety injection) for thesubsequent restart of the affected ESF actuation devices.7.Figure7.3-8 illustrates the equipment that is tripped on a signal from the containmentdepressurization actuation (CDA) signal. This is done to remove unnecessary loads from theemergency diesel generators.8.Figure7.3-9 is a diagram of the undervoltage signal for the normal station service buses.When voltage drops below 70% on 2/3 station service buses (1A, 1B, or 1C), the reactor istripped, providing the reactor power level is greater than P-7.

Revision 52-09/29/2016NAPS UFSAR7.3-12Undervoltage on the station service bus results in the following:a.Main feedwater pump trips.b.Reactor coolant pump trips.c.Condensate pump trips.d.Low-pressure heater drain pump trips.e.High-pressure heater drain pump trips.f.Normal supply bus breaker trips.g.Bearing cooling water pump trips.9.If an ESF-actuated device has been actuated by a safety features actuation signal, it cannot bereturned to the non-safety-features actuation mode by operator action until the actuationsignal has been reset. The protection system is designed such that once initiated, a protectionaction at the system level (initiation of the final actuation device associated with a givenprotective function, i.e., quench spray, recirculation spray, chemical addition, safetyinjection, etc.) goes to completion. Reset capability of ESF signals is required to permitaction in the postaccident period. One example is stopping the quench spray pump when therefueling water storage tank level will no longer support continued quench spray pumpoperation.The manual reset logic is designed such that any preaccident operation of the reset controlswitch will not block a subsequent bona fide accident signal. It is important to note thatmanual control of the spray system cannot be achieved (once protective action at the systemlevel has been initiated) by just resetting the associated actuation signal. The manual reset isthe first of a set of deliberate operator actions required to return the system to thenon-safety-feature mode.The circuitry for the feedwater bypass valves is provided with an administratively controlledkeylock selector switch. During station operation this switch is placed in the "Normal"position which prevents the blocking of any ESF actuation signals when depressing thefeedwater bypass valve reset pushbutton. During cold shutdown or refueling the switch isplaced in the "SG Wet Layup" position which allows resetting of the feedwater bypass valveswhich is necessary to place the steam generators in wet layup. In this case the ESF actuationsignal being blocked (steam generator level) is not a valid core protection ESF actuationsignal.Having gone to completion, that is, once breakers are closed or motor-operated valves orother actuators are operated, deliberate operator action is required to return a device to the Revision 52-09/29/2016NAPS UFSAR7.3-13non-ESF mode. Specifically, the following two actions per train are required for any device in agiven train except for the feedwater bypass valves:a.Push reset for the appropriate actuation signal.b.Subsequently operate the control switch for the device.This is illustrated in Figure7.3-10. Electrical protection trips and emergency diesel-generatorsequenced trips are, however, not affected by the blocking logic. In the case of the feedwaterbypass valves, during station operation, two operator actions are required to return thesevalves to the non-ESF actuation mode. The two actions per train which are required are asfollows:a.Push reset for the appropriate actuation signal.b.Push reset for the feedwater bypass valve.10.Reference Drawing14, in conjunction with Figure7.7-8, illustrates the initiating logic andthe actuation devices required for feedwater isolation. The logic shown in ReferenceDrawing14 provides a redundant means of isolating feedwater in the event a main feedwaterregulating valve should fail to close when required.11.Reference Drawing11, in conjunction with Figure7.3-4, illustrates automatic actuation logicfor all actuation devices initiated by a containment depressurization actuation signal. Theeffect of the availability of emergency bus voltage on containment depressurization actuateddevices is also shown. When emergency bus voltage has been restored for a specified timeperiod, the actuated devices will start, providing the containment depressurization actuationsignal is present.12.Figure7.3-8 shows how some devices on the emergency bus are tripped off on the initiationof a containment depressurization signal.13.Reference Drawing11, in conjunction with Figure7.3-4, illustrates the effect that emergencybus power availability has on devices actuated by the safety injection actuation signal. Whenemergency bus voltage has been restored for a predetermined time, the ESF-actuated deviceswill operate, providing the safety injection signal is present.14.The diagrams in Reference Drawings15 and16 and Figures7.3-11 and7.3-13, and thedesign and operation sections below explain the containment isolation system and its relatedfunction.15.Service Water spray array motor-operated valves (MOV) are aligned from either a TrainA orTrainB SI signal.7.3.1.3.5.1Containment Isolation System Description. Containment isolation trip valves areprovided in the piping of various systems in accordance with the design-basis established inSection6.2.4.

Revision 52-09/29/2016NAPS UFSAR7.3-14Containment isolation trip valves are air-operated valves operating on an air-to-open signal.Compressed air is supplied to the underside of the valve diaphragm, which compresses the springand opens the valve. The air above the diaphragm vents to the containment or auxiliary building.A containment isolation signal will de-energize the solenoid valve, blocking the compressed airsupply and venting the air from below the diaphragm. The spring will close the valve. The closingaction of the valve will be independent of the ambient pressure since both the top and bottom ofthe diaphragm will be vented to the same atmosphere. The containment isolation valves inside thecontainment will be ensured of operating regardless of the containment pressure.Containment isolation valves are tripped closed as a result of containment isolation phase Aor phase B, which results from safety injection and high-high containment pressure, respectively.The valves must be manually reset when tripped. The valve controls are designed so that a loss ofelectric power or air supply will also close the containment isolation valve. The trip signals mustbe removed and the electric power and air supply restored before the valves can be reset.The position of each isolation trip valve and the availability of power is monitored on themain control board.Certain trip valves, in addition to the normal tripping functions, are automatically openedand closed from process control signals as required (refer to Figures7.3-11 and7.3-12, andReference Drawing16). The trip signals will always override process signals. These combinationoperational and isolation valves are provided in the following systems:1.Primary drain transfer pumps.2.Containment sump pump.3.Air ejectors.4.Containment vacuum system.5.Steam generator blowdown trip valves.Containment isolation trip valves are powered from 120Vac vital bus panels or from the120Vdc panels.The containment isolation trip signals are tested in a manner similar to that described inSection7.2.2.2.1.6.7.3.1.3.5.2Containment Isolation System Operation. Containment isolation signals that trip theisolation valves are generated as follows:1.Phase A containment isolation-refer to Figure7.2-9. Containment isolation phase Aactuation will occur as a result of any of the following conditions:a.Either of two containment isolation phaseA momentary selector switches being placed inthe phaseA position. (This actuates trainsA andB.)

Revision 52-09/29/2016NAPS UFSAR7.3-15b.A safety injection actuation signal.2.Phase B containment isolation-refer to Reference Drawing10. Containment isolationphaseB actuation will occur as a result of any of the following conditions:a.Manual containment spray actuation (placement of both bench-mounted switches toINITIATE). This actuates trainsA andB.b.High-high containment pressure signal, on 2/4 channels.The resetting of containment isolation phaseA orB is accomplished by the depression ofthe bench-mounted RESET push buttons. There is one reset push button per train, per isolationphase (four reset push buttons). These push buttons are provided with safety covers to preventinadvertent operation.Operating reset push buttons before an isolation signal initiation will not block the isolationsignal. However, once the isolation signal is initiated, it can be reset at any time by the operator.Once the signal is reset, it can only be reinitiated (reset-removed) by either of the following:1.Manual switch actuation of containment isolation from the control board.2.Returning respective memory circuits to normal by the disappearance of the (SI or high-high)signal and subsequently having them reoccur.Figure7.3-11 illustrates operation of a typical, normally closed trip valve, which ispneumatically operated with a solenoid-operated air pilot valve. The trip valves to which thisdiagram applies are listed in Reference Drawings17 and18, and operation is as follows:1.The valve will be opened by depressing the OPEN push button, or an auto-open processsignal (providing the circuit has been reset) if no containment isolation signal conditionexists.2.The valve will be closed if any of the following conditions occur:a.Containment isolation.b.The absence of an auto-open process signal and the OPEN push button is not depressed.c.Depression of the CLOSE push button.Figure7.3-13 and Reference Drawing16 illustrates the operation of a typical, normallyopen trip valve, which is pneumatically operated with a solenoid-operated air pilot valve. The tripvalves for which this diagram applies are listed in Reference Drawings17 and18, and operationis as follows:1.The valve will be opened provided there is no containment isolation (phaseA orB, asapplicable) signal and the OPEN push button is depressed.

Revision 52-09/29/2016NAPS UFSAR7.3-162.The valve will be closed if any of the following conditions exist:a.A close process signal.b.Depression of the CLOSE push button.c.Containment isolation signal.Figure7.3-2 illustrates and describes the turbine and generator trips.7.3.1.3.5.3Auxiliary Feedwater System Description and Operation. Figures7.3-1, 7.3-12, andReference Drawings13, 19 and20 illustrate the operation of the auxiliary steam generatorfeedwater pumps system.A turbine-driven auxiliary feedwater pump, FW-P-2, and two motor-driven auxiliaryfeedwater pumps, FW-P-3A, 3B, receive suction from the emergency condensate storage tankCN-TK-1, which is encased in concrete for tornado missile protection.Figure7.3-1 and Reference Drawing13 illustrate the start and stop of the motor-drivenauxiliary feedwater pumps FW-P-3A & -3B. Reference Drawing19 and Figure7.3-12 illustratethe operation of the turbine-driven auxiliary feedwater pump FW-P-2.Auxiliary feed pump motors can be manually started providing:1.Control switch is in START either at the control board or at the auxiliary shutdown panel,with the transfer switch in the appropriate position.2.No motor electrical faults are present, that is, lockout relay is reset.3.No undervoltage has occurred on the bus in the previous 25seconds.Immediate automatic starting will take place if the following conditions exist:1.Control switch at the control board or the auxiliary shutdown panel is in AUTO with transferswitch in appropriate position.2.No electrical faults are present.3.The bus has no undervoltage signal present.4.No safety injection signal is present.

5.Occurrence of any of the following:a.All main feed pumps tripped.b.Low-low steam generator level on two out of three channels of any steam generator. (Thisis the same setpoint used for reactor trip.)c.Loss of reserve station power.d.AMSAC initiated.

Revision 52-09/29/2016NAPS UFSAR7.3-17In addition to the start demand signals a, b, c and d above, there is also a delayed auto startin the event a safety injection signal is initiated. This start is delayed 20seconds to maintain anacceptable voltage profile from the offsite source. In the event of an undervoltage signalconcurrent with safety injection, automatic starting will be delayed until 25seconds after thevoltage is restored, to ensure an acceptable voltage profile while starting multiple loads poweredfrom the emergency diesel generator. Control switch and electrical fault permissives also apply tothis start feature.With the transfer switch properly positioned, the auxiliary feedwater pump motors can bestopped manually with the control switches at either the main control board or the auxiliaryshutdown panel. They will stop automatically with a motor protection trip.Figure7.3-12 and Reference Drawing19 illustrates the operation of the full-sized,turbine-driven auxiliary feedwater pump FW-P-2. Steam to the turbine driver can be admittedthrough either MS-TV-111A & -211A or through MS-TV-111B & -211B.MS-TV-111A & B and -211A & B can be manually operated using selector switches at thecontrol board or the auxiliary shutdown panel, provided the transfer switch is in the appropriateposition.MS-TV-111A & -211A will open automatically as a result of the following trainA signals(similarly trainB signals operate MS-TV-111B & -211B), providing the selector switch at thecontrol board or the auxiliary shutdown panel is in the AUTO position and the transfer switch isin the appropriate position:1.Loss of preferred station power.2.Safety injection signal.3.Low-low steam generator level on two out of three channels of any steam generator.4.All main feed pumps tripped.5.AMSAC initiated.With the transfer switches properly positioned, the turbine driven auxiliary feedwater pumpcan be stopped manually using the control switches either on the main control board or in theauxiliary shutdown panel.The discharge valve from each auxiliary steam generator feedwater pump to its associatedsteam generator is normally open. The steam generator blowdown valves trip closed on signalsactuating either SOV-MS 111A or SOV-MS 111B.Refer to Reference Drawing20. This illustrates the operation of auxiliary feedwater controlvalve HCV-FW 100A and is typical for HCV-FW 100B and C. The valve can be controlled from amanual loading station at the control board or from a similar station at the auxiliary shutdownpanel, providing the transfer switch, located at the shutdown panel, is in the appropriate position.

Revision 52-09/29/2016NAPS UFSAR7.3-18Auxiliary feedwater flow indication to each steam generator is powered from the 120V ac vitalbus, which is battery-backed, and flow is displayed in the control room.NUREG-0737 requires that the indication to be environmentally qualified, and poweredfrom a highly reliable, battery-backed, non-Class1E power source. Although the power supply isClass1E, the power cables to the indicator are not safety-related, and the indicators on the controlboard do not have barriers for safety-related separation. The indication is environmentallyqualified by virtue of being located in a mild environment. The power supply and equipmentexceed the requirements of NUREG-0737.Auxiliary feedwater pump discharge pressure is indicated at the control board and theauxiliary shutdown panel. Auxiliary feedwater pump suction pressure is also indicated at thecontrol board.Reference Drawing20 also illustrates the operation of motor-operated valvesFW-MOV-100A & -200A. Operation for FW-MOV-100B & -200B, FW-MOV-100C & -200C,and FW-MOV-100D & -200D.Motor-operated valve FW-MOV-100A may be modulated open, provided both of thefollowing conditions exist:1.Transfer switch, located at the auxiliary shutdown panel, is in the appropriate position.2.OPEN/CLOSE switch for FW-MOV-100A is held in the OPEN position.Motor-operated valve FW-MOV-100A may be modulated closed, provided both of thefollowing conditions exist:1.Transfer switch, located at the auxiliary shutdown panel, is in the appropriate position.2.OPEN/CLOSED switch for FW-MOV-100A is held in the CLOSE position.To improve the reliability of the auxiliary feedwater system, alarms have been added in thecontrol room to indicate abnormal alignment of auxiliary feedwater pump discharge valvesFW-MOV-100A, B, C, & D, and -200A, B, C, & D and FW-HCV-100A, B, & C, and -200A, B,&C, and the auxiliary feedwater pump turbine throttle trip valve. Refer to Section10.4.3.5 forfurther details.7.3.1.3.5.4Main Steam Isolation Trip Valves. Reference Drawing 21, and the description below,show the operation of the main steam isolation trip valves.The three main steam isolation trip valves, TV-MS101A, B, and C, are installed in the mainsteam line outside the reactor containment in a tornado-missile-protected enclosure. They aresimilar in design to standard swing check valves, except that they are installed counter to thenormal steam flow direction with the disk held out of the flow path by an air cylinder operator oneach side.

Revision 52-09/29/2016NAPS UFSAR7.3-19The purpose of these valves is to close immediately in case of a rupture in the main steamline between the valve and the turbine, thus preventing rapid blowdown of the shell side of thesteam generator and rapid cooling of the reactor core.Provisions to test for the operability of SOV-MS-101 TrainA, TrainB, 101B TrainA,TrainB, 101C TrainA, and TrainB are provided by the Westinghouse Safeguard On-Line TestingSystem, which tests for continuity through the safeguard contact and solenoid valve.Refer to Reference Drawing21. The following conditions will lead to main steam lineisolation trip of all three valves.1.A high steam flow in two out of three steam lines, coincident witha.Low steam-line pressure in two out of three lines, orb.Low-low average reactor coolant temperature (below approximately 543°F).2.An intermediate high-high containment pressure signal.3.The CLOSE push button for either trip solenoid valve (TrainA or TrainB) is depressed inthe main control room for each of the three MSTVs.4.The control switch in the Main Control Room for trip solenoid valves SOV-MS101A-6, B-6,and C-6, is placed in the EMERG. CLOSE position and depressed.5.The control switch in the Emergency Switchgear Room for trip solenoid valvesSOV-MS101A-7, B-7, and C-7, is in the EMERG. CLOSE position.Once the main steam-line isolation trip valve receives a close signal (either by manualpushbutton actuation or automatic close signal), a relay contact seals the solenoids in theenergized position. This seal-in is broken when the OPEN push button is pressed and theautomatic isolation signal is reset.When the valves are closed by one of the above, the valves can be reopened by depressingthe OPEN push button, providing none of the trip conditions exist, both control switches are in theNORMAL position, and the upstream (steam generator) pressure is less than 4psi greater than thedownstream pressure.Air-operated bypass valves are provided to allow the operator to equalize pressure on eitherside of the main steam isolation trip valve disk during unit start-up or after spurious trip. Thesevalves are automatically de-energized to vent air to close by the same auto trip logic used to tripthe main steam line isolation valves. Refer to Reference Drawing22.

Revision 52-09/29/2016NAPS UFSAR7.3-207.3.2Analysis7.3.2.1Evaluation of Compliance With IEEE Std279-1971 (Reference2)7.3.2.1.1Single-Failure CriteriaThe discussion in Section7.2.2.2.1 is applicable to the ESF actuation system, with thefollowing exception.In the engineered safety features, a loss of instrument power will call for the actuation ofESF equipment controlled by the specific bi-stable that lost power (containment spray excepted).The actuated equipment must have power to comply. The power supply for the protection systemsis discussed in Chapter8. For containment spray, the final bi-stables are energized to trip to avoidspurious actuation. In addition, manual containment spray requires simultaneous actuation of bothmanual controls. This is considered acceptable because spray actuation on high-high containmentpressure signal provides automatic initiation of the system via protection channels meeting thecriteria in Reference2. Moreover, all safety-related equipment (valves, pumps, etc.) can beindividually manually actuated from the control board. Hence, a secondary mode of containmentspray initiation is available.The design meets the requirements of General Design Criteria21 and23.7.3.2.1.2Equipment QualificationEquipment qualification is discussed in Section3.11 and in Reference4.7.3.2.1.3Channel IndependenceThe discussion presented in Section7.2.2.2.1 is applicable. The ESF outputs from thesolid-state logic protection cabinets are redundant, and the actuations associated with each trainare energized up to and including the final actuators by the separate ac power supplies that powerthe logic trains.7.3.2.1.4Control and Protection System InteractionThe discussions presented in Sections7.2.2.2.1 and7.2.2.3.5 are applicable.7.3.2.1.5Capability for Sensor Checks and Equipment Test and CalibrationThe discussions of system testability in Section7.2.2.2.1 are applicable to the sensors,analog circuitry, and logic trains of the ESF actuation system.The following discussions cover those areas in which the testing provisions differ fromthose for the reactor trip system.

7.3.2.1.5.1Testing of Engineered Safety Features Actuation Systems. The ESF systems aretested to provide assurance that the systems will operate as designed and will be available to Revision 52-09/29/2016NAPS UFSAR7.3-21function properly in the unlikely event of an accident. The testing program, which meets therequirements of General Design Criteria21, 37, 40 and43, and Safety Guide22, is as follows:1.Prior to initial plant operations, ESF system tests were conducted.2.Subsequent to initial start-up, ESF system tests are conducted at a frequency established bythe Surveillance Frequency Control Program (Tech Spec5.5.17).3.During on-line operation of the reactor, all of the ESF analog and logic circuitry are fullytested. In addition, essentially all of the ESF final actuators are fully tested, except for thecontacts of most slave relays. The contacts of these slave relays are tested functionally whenthe reactor is shut down for refueling.7.3.2.1.5.2Performance Test Acceptability Standards for the "S" (Safety Injection Signal) andfor the "P" (Automatic Demand Signal for Containment Spray Actuation) ActuationSignals Generation. During reactor operation, the basis for ESF actuation systemsacceptability is the successful completion of the overlapping tests performed on the reactor tripand the ESF actuation systems. Analog checks verify the operability of the sensors. Analogchecks and tests verify the operability of the analog circuitry from the input of these circuitsthrough to and including the logic input relays. Solid-state logic testing checks the digital signalpath from and including logic input relay contacts through the logic matrices and master relaysand performs continuity tests on the coils of the output slave relays. The only small part of theactuation system logic which is not tested on-line is the contact portion of most slave relays.These slave relays are not actuated on-line because doing so would adversely affect the safety ofthe plant or disrupt reactor operation. The contacts of these slave relays are proven operable byfunctionally testing them when the reactor is shut down for refueling. The final actuators areroutinely tested on-line by the normal pump and valve surveillances.Maintenance checks such as resistance to ground testing of signal cables are typicallyconducted for only the short term purpose of verifying proper installation following a replacementof cabling. In accordance with 10CFR50.49, qualification test data for cabling are documentedfor the long term purpose of establishing what constitutes an acceptable cable qualification lifebased on typical radiation exposures.7.3.2.1.5.3Frequency of Performance of Engineered Safety Features Actuation Tests. Duringnormal reactor operation, complete system testing (excluding sensors or those devices whoseoperation would cause plant upset) is performed as required by the Technical Specifications.Further testing, including the sensors and actuated devices, as required by the TechnicalSpecifications, is performed during scheduled plant shutdowns for refueling.

Revision 52-09/29/2016NAPS UFSAR7.3-227.3.2.1.5.4Engineered Safety Features Actuation Test Description. The following sectionsdescribe the testing circuitry and procedures for the on-line portion of the testing program. Theguidelines used in developing the circuitry and procedures were as follows:1.The test procedures must not involve the potential for damage to any plant equipment.2.The test procedures must minimize the potential for accidental tripping.3.The provisions for on-line testing must not adversely affect the safety of the plant or disruptreactor operations.7.3.2.1.5.5Descriptions of Initiation Circuitry. Several systems comprise the total ESF system,most of which may be initiated by different process conditions and reset independently of eachother.The remaining functions are initiated by a common signal (safety injection) (seeFigure7.3-3), which in turn may be generated by different process conditions.In addition, the operation of all other vital auxiliary support systems, such as auxiliaryfeedwater, component cooling, and service water, is initiated via the ESF starting sequenceactuated by the safety injection signal.Each function is actuated by a logic circuit duplicated for each of the two redundant trainsof ESF initiation circuits.The output of each of the initiation circuits consists of a master relay, which drives slaverelays for contact multiplication as required. The logic, master, and slave relays are mounted inthe solid-state logic protection cabinets designated trainA and trainB, respectively, for theredundant counterparts. The master and slave relay circuits operate various pump and fan circuitbreakers or starters, motor-operated valve contactors, solenoid-operated valves, emergencygenerator starting, etc.7.3.2.1.5.6Analog Testing. Analog testing is identical to that used for reactor trip circuitry andis performed as specified in the Technical Specifications. Briefly, in the analog racks, provinglamps and analog test switches are provided. Administrative control requires, during bi-stabletesting, that the bi-stable output be put in a trip condition by placing the test switch in the testposition. This action connects the proving lamp to the bi-stable and disconnects and thusde-energizes (operates) the bi-stable output relays in trainA and trainB cabinets, and allows theinjection of a test signal to the channel. Relay logic in the process cabinets automatically blocksthe test signal unless all of the channel bi-stables are tripped. This, of necessity, is done onechannel at a time. Status lights and single-channel trip alarms in the main control room confirmthat the bi-stable relays have been de-energized and the bi-stable outputs are in the trip mode. Anexception to this is containment depressurization, which is energized to actuate 2/4 and reverts to2/3 when one channel is in test.

Revision 52-09/29/2016NAPS UFSAR7.3-23Refer to Reference Drawing5. Relay R-4, of channel test switch cards, is operable for testpurposes only when all three comparator trip switch cards have been placed in the appropriatepositions. Once relay R-4 has been energized, a test signal can be inserted through a test jack viachannel test switch card and monitored at the test points shown. Verification of bi-stable tripsetting can now be confronted by the proving lamps.The analog test switch is then operated and a signal is inserted through a test jack. Theverification of the bi-stable trip setting is now confirmed by the proving lamps.7.3.2.1.5.7Solid-State Logic Testing. After the individual channel analog testing is complete,the logic matrices are tested from the trainA or trainB logic rack test panels. This step providesoverlap between the analog and logic portions of the test program. During this test, each of thelogic inputs is actuated automatically in all combinations of trip and nontrip logic. Trip logic isnot maintained long enough to permit master relay actuation; master relays are "pulsed" to checkcontinuity. Following the logic testing, the individual master relays are actuated electrically to testtheir mechanical operation. The actuation of the master relays during this test will apply lowvoltage to the slave relay coil circuits to allow continuity checking, but not slave relay actuation.During logic testing of one train, the other train can initiate the required ESF function. Foradditional details, see Reference3.7.3.2.1.5.8Actuator Testing. At this point, the testing of the initiation circuits through theoperation of the master relay and its contacts to the coils of the slave relays has beenaccomplished.With few exceptions, the units are not designed to actuate the slave relays on-line; therefore,the slave relays are functionally tested during the refueling outages. Various performance tests(PTs) are performed during the refueling cycle to ensure ESF system operability. The slave relayare verified operable during these tests. The PTs verify that each contact on the slave relayperforms its safety function.

7.3.2.1.5.9Time Required for Testing. It is estimated that analog testing for most channels canbe performed at a rate of several channels per hour provided that no channels are found out ofcalibration. Logic testing for one logic train may take as long as 2hours. The testing of actuatedcomponents (including those that can only be partially tested) is a function of control roomoperator availability. Several shifts are required to accomplish these tests. During this procedure,automatic actuation circuitry will override testing.7.3.2.1.5.10Safety Guide 22. Periodic testing of the ESF actuation functions as describedcomplies with AEC Safety Guide22, Periodic Testing of Protection System Actuation Functions,February1972.Under the present design of the ESF, testing can be accomplished as described in thepreceding sections; all actuated devices and logic can be tested at power except for the contacts ofmost slave relays and the following protection functions: generation of a safety injection signal by Revision 52-09/29/2016NAPS UFSAR7.3-24use of the manual safety injection switch; generation of the containment depressurization signalby use of the manual spray actuation switch.As required by Safety Guide22, where actuated equipment is not tested during reactoroperation it has been determined that:1.There is no practicable system design that would permit the operation of the actuatedequipment without adversely affecting the safety or operability of the plant.2.The probability that the protection system will fail to initiate the operation of the actuatedequipment is, and can be maintained, acceptably low without testing the actuated equipmentduring reactor operation.3.The actuated equipment can routinely be tested when the reactor is shut down.It should be noted that the above criteria has been applied to the contacts of most slaverelays because their actuation has been determined to adversely affect plant safety or disruptreactor operation.When the ability of a system to respond to a bona fide accident signal is intentionallybypassed for the purpose of performing a test during reactor operation, each bypass condition isautomatically indicated to the reactor operator in the main control room by a common "ESFtesting" annunciator for the train in test. Test circuitry does not allow two ESF trains to be testedat the same time so that the extension of the bypass condition to redundant systems is prevented.7.3.2.1.5.11Summary. The procedures described provide the capability for checking completelyfrom the process signal to the logic cabinets and from there to the individual pump and fan circuitbreakers or starters, valve contactors, pilot solenoid valves, etc., including all field cablingactually used in the circuitry called on to operate for an accident condition. For those deviceswhose operation could adversely affect plant safety or disrupt reactor operation, the procedureprovides for checking from the process signal to the logic rack and, testing of most slave relaycontacts to the actuated equipment is performed during refueling outages.The procedures require testing at various locations, as follows:1.Analog testing and verification of bi-stable setpoint are accomplished at process analogracks. The verification of bi-stable relay operation is done at the main control room statuslights.2.Logic testing through the operation of the master relays and low-voltage application to slaverelays is done at the logic rack test panel.3.The testing of pumps, fans, and valves is accomplished by IWV and IWP Programs. A fullfunctional test is performed during the refueling cycle to ensure all actuated equipment isoperable.4.The contacts of the slave relays are verified operable during the testing mention in 3 above.

Revision 52-09/29/2016NAPS UFSAR7.3-257.3.2.1.5.12Testing During Shutdown. Emergency core cooling system tests are performed at afrequency established by the Surveillance Frequency Control Program (Tech Spec5.5.17). Withthe reactor coolant system pressure less than or equal to 450psig and temperature less than orequal to 350°F, a test safety injection signal will be applied to initiate the operation of the system.The low head safety injection and centrifugal charging pumps are made inoperable for this test.Containment spray system tests are performed at a frequency established by theSurveillance Frequency Control Program (Tech Spec5.5.17). The tests are performed with theisolation valves in the spray supply lines at the containment and spray additive tank blockedclosed and are initiated by tripping the normal actuation instrumentation.The balance of the requirements listed in IEEE Std279-1971 (Paragraphs4.11through4.22) are discussed in Section7.2.2.2.1. Paragraph4.20 receives special attention inSection7.5.7.3.2.2Evaluation of Compliance With IEEE Std308-1969 (Reference5)See Chapter8, which discusses the power supply for the protection systems, for discussionsof compliance with this criterion.

7.3.2.3Evaluation of Compliance With IEEE Std323-1971 (Reference6)The ESF instrumentation is type tested to substantiate the adequacy of design. This is thepreferred method, as indicated in Reference6. Type tests may not conform to the formatguidelines set forth in Reference6.

7.3.2.4Evaluation of Compliance With IEEE Std334-1971 (Reference7)See Section3.11.2.2 for discussion of inside recirculation spray pumps in relation to IEEEStd334-1971 compliance.

7.3.2.5Evaluation of Compliance With IEEE Std338-1971 (Reference8)Periodic response time testing of ESF systems has been established in the TechnicalSpecifications to meet the intent of IEEE Std338-1971. Only those response times used in theaccident analysis need to be included in the testing program.

7.3.2.6Evaluation of Compliance With IEEE Std344-1971 (Reference9)The seismic testing, as set forth in Section3.10 and References1, 2, and4, conforms to theguidelines set forth in Reference9.

7.3.2.7Evaluation of Compliance With IEEE Std317-1971 (Reference10)See Section3.8.2.1.4 for a discussion of electrical penetrations and compliance with IEEEStd317-1971.

Revision 52-09/29/2016NAPS UFSAR7.3-267.3.2.8Evaluation of Compliance With IEEE Std336-1971 (Reference11)Instrumentation and electrical equipment was installed, inspected, and tested in accordancewith IEEE Std336-1971. See Section8.3.1.1.2.2 for a discussion of compliance of the vital acpower system with IEEE Std336-1971.7.3.2.9SummaryThe effectiveness of the ESF actuation system is evaluated in Chapter15, based on theability of the system to contain the effects of ConditionIII andIV faults, including loss-of-coolantand steam-line-break accidents. The ESF actuation system parameters are based on thecomponent performance specifications, which are given by the manufacturer or verified by testfor each component. Appropriate factors to account for uncertainties in the data are factored intothe constants characterizing the system.The ESF actuation system must detect ConditionIII andIV faults and generate signals thatactuate the ESF. The system is designed to sense the accident condition and generate the signalactuating the protection function reliably and within a time consistent with the accident analysesin Chapter15.Much longer times are associated with the actuation of the mechanical and fluid systemequipment associated with ESF. This includes the time required for switching, bringing pumpsand other equipment to speed, and the time required for them to take load.Operating procedures require that the complete ESF actuation system normally be operable.However, the redundancy of system components is such that the system operability assumed forthe safety analyses can still be met with certain instrumentation channels out of service. Channelsthat are out of service are to be placed in the tripped mode, except the containment high-highbi-stables are blocked (bypassed).

7.3.2.9.1Loss-of-Coolant ProtectionBy the analysis of LOCA and by system tests, it has been verified that except for very smallcoolant system breaks that can be protected against by the charging pumps followed by an orderlyshutdown, the effects of various LOCAs are reliably detected by the low-low pressurizer pressuresignal; the emergency core cooling system is actuated in time to prevent or limit core damage.For large coolant system breaks, the passive accumulators inject first because of the rapidpressure drop. This protects the reactor during the unavoidable delay associated with actuating theactive emergency core cooling system phase.High containment pressure also actuates the emergency core cooling system, providingadditional protection as a backup to actuation on low-low pressurizer pressure. Emergency corecooling actuation can be brought about on sensing this other direct consequence of a primarysystem break, that is, the protection system detects the leakage of the coolant into the Revision 52-09/29/2016NAPS UFSAR7.3-27containment. The generation time of the actuation signal, about 1.0second after detection of theconsequences of the accident, is adequate.Containment spray will provide additional emergency cooling of the containment and alsolimit fission product release on sensing elevated containment pressure (high-high) to mitigate theeffects of a LOCA.The delay time between the detection of the accident condition and the generation of theactuation signal for these systems is assumed to be about 1.0second, well within the capability ofthe protection system equipment. However, this time is short compared to that required for thestart-up of the fluid systems.The analyses in Chapter15 show that the diverse methods of detecting the accidentcondition and the time for the generation of the signals by the protection systems are adequate toprovide reliable and timely protection against the effects of loss of coolant.7.3.2.9.2Steam-Line Break ProtectionThe emergency core cooling system is also actuated to protect against a steam-line break.About 2.0seconds elapse between sensing high steam-line differential pressure or high steam-lineflow and the generation of the actuation signal. The analysis of steam-line-break accidentsassuming this delay for signal generation shows that the emergency core cooling system isactuated for a steam-line break in time to limit or prevent further damage. There is a reactor trip,but the core reactivity is further reduced by the highly borated water injected by the emergencycore cooling system.Additional protection against the effects of steam-line break is provided by feedwaterisolation, which occurs on the actuation of the emergency core cooling system. Feedwater lineisolation is initiated to prevent excessive cooldown of the reactor.Additional protection against a steam-line-break accident is provided by the closure of allsteam-line trip valves to prevent uncontrolled blowdown of all steam generators. The generationof the protection system signal (about 2.0seconds) is again short compared to the time to trip thefast-acting steam-line trip valves, which are designed to close in less than approximately5seconds.In addition to the actuation of the engineered safety features, the effect of asteam-line-break accident generates a signal resulting in a reactor trip on overpower, or followingemergency core cooling system actuation. However, the core reactivity is further reduced by thehighly borated water injected by the emergency core cooling system.The analyses in Chapter15 of the steam-line-break accidents and an evaluation of theprotection system instrumentation and channel design shows that the ESF actuation system iseffective in mitigating the effects of a steam-line-break accident.

Revision 52-09/29/2016NAPS UFSAR7.3-287.3.2.10Automatic Changeover From Injection Mode to Recirculation Mode After Loss ofPrimary CoolantThe ESF actuation system also provides the logic for the automatic switchover sequencefrom the injection mode to the recirculation mode following a LOCA.The automatic switchover sequence is initiated when actuation signals are generated byboth the two-of-four refueling water storage tank (RWST) low-low-level protection logic and thesafeguards protection logic (SI signal). (See Figure7.3-14.)Each of the four RWST level channel bi-stables provides an RWST low-low level signal toboth the TrainA and TrainB solid state protection systems. Thus, when two-of-four RWST levelchannel bi-stables generate an RWST low-low level actuation signal it is developed in bothsafeguards protection cabinets. Each of the four RWST level channel bi-stables is aligned to oneof four RWST level channels. Each level channel is assigned to a separate vital instrument bus.The RWST level channel bi-stables are the following:1.Normally de-energized.2.De-energized on loss of power.3.Energized on RWST low-low level.A safeguards protection logic actuation signal (SI signal) is also required to initiate theautomatic switchover sequence. This interlock requires the capability for the retention of thesafeguards protection logic actuation signal (SI signal) by latching relays located in thesafeguards protection cabinets. The retention of this signal is required since plant emergencyprocedures will instruct the operator to reset the master relays for the safeguards protection logicactuation signal (SI signal) significantly in advance of the generation of the RWST low-low-levelactuation signals. The output of these latching relays is retained such that when the two-of-fourRWST low-low-level actuation signals are developed, the trainA and trainB automaticswitchover sequence trip signals are generated.The automatic switchover sequence trip signal is applied to all valves except 1-862A and1-862B that are automatically repositioned. This ensures that the automatic switchover sequencecannot be unintentionally interrupted by the plant operator by manually repositioning the valve.Provisions have been included in this interlock to permit on-line testing of the automaticswitchover sequence without affecting normal plant operation. The testing provisions have beendeveloped to ensure that an open path from the RWST to the charging/safety injection pumpsuction does not exist at any time during the testing procedure. Testing addressed in this interlockis restricted to valve sequence testing and does not include the testing of RWST instrumentationand safeguards protection logic. Test buttons are provided to simulate both the safeguardsprotection logic actuation signal (SI signal) to the latching relay and the two-of-four RWSTlow-level actuation signal. Each train is tested individually.

Revision 52-09/29/2016NAPS UFSAR7.3-29The following additional features are included in this interlock to prevent the unintentionalremote manual operation of certain valves by the operator:1.The remote manual opening of a low-head safety injection pump miniflow isolation valverequires that the sump isolation valve in the same train be fully closed. This prevents theinadvertent pumping of sump water to the refueling water storage tank after an accident.2.The remote manual opening of a sump isolation valve requires that one of the low-headsafety injection pump miniflow isolation valves in the same train be fully closed. Again, thisis to prevent inadvertent pumping of sump water to the refueling water storage tank after anaccident.3.A RWST-to-LHSI pump isolation valve cannot be manually opened unless the sumpisolation valve is fully closed. This avoids the condition where an LHSI pump wouldcontinue to take suction from the refueling water storage tank after the switchover torecirculation had been completed. Preferential suction from the refueling water storage tankwould drain the tank completely, which is undesirable.7.3.2.11Inside and Outside Recirculation Spray Pump Start FunctionThe ESF actuation system provides the logic for the automatic start of the insiderecirculation spray (IRS) and outside recirculation spray (ORS) pumps at appropriate times afterthe occurrence of a containment depressurization actuation (CDA). The automatic start sequenceis initiated when actuation signals are generated by a coincidence of the CDA ContainmentPressure High-High, two-of-four safeguards logic and the Refueling Water Storage Tank (RWST)Level-Low, two-of-three safeguards logic. See Reference Drawings28 and29.The Containment Pressure High-High (CDA) portion of the RS pump start logic isdescribed in Section7.3.1.3.2 and Reference Drawings5, 6, and7. Actual pump start is notinitiated until both the CDA and RWST Level-Low two-of-three logic is satisfied. This designensures that the pumps will not start until enough water has been added to containment so thatsufficient water level is available to meet sump strainer submergence and pump suction operatingrequirements.The RWST Level-Low portion of the RS pump start logic is described in ReferenceDrawings28 and29. The analog inputs to this logic are the same RWST level signals used in theAutomatic Recirculation Mode Transfer (RMT) function described in Section7.3.2.10. The RMTfunction uses bi-stables that actuate when RWST level reaches a Low-Low setpoint. Separatebi-stables installed in three of the analog loops provide the RWST Level-Low signals for the RSpump start logic. Each of these three RWST Level-Low channels bi-stables provide an RWSTLow level signal to both the TrainA and TrainB Solid State Protection Systems (SSPS). Thus,when two-of-three RWST Level-Low channel bi-stables generate an RWST Low level actuationsignal, it is developed in both safeguards protection cabinets. Each of the three RWST Level-Low Revision 52-09/29/2016NAPS UFSAR7.3-30channel bi-stables is aligned to one of three RWST level channels. Each level channel is assignedto a separate vital instrument bus.The ORS pump control circuits are configured so that the ORS pumps receive an immediatestart signal once the Containment Pressure High-High AND RWST Level-Low coincidence logicis satisfied (Assuming that all electrical permissives are satisfied). The IRS pump control circuitsare configured so that the pumps start after a 120-second delay from the coincident actuationsignal. This delay minimizes the impact on emergency diesel loading and allows for the ORSsystem to fill its piping completely, deliver spray to the containment and reach a stable flowdemand on the sump before the IRS pumps start. This method of starting the RS pumps ensuresthat a reliable mass of liquid is added to the containment to meet the sump strainer submergencerequirements for the range of LOCA break sizes requiring the containment sump.The Inside and Outside Recirculation Spray Pump Start Function is tested using the samemethods and design features described in Section7.3.2.1.5.1.7.3.2.12Casing Cooling Tank IsolationThe Casing Cooling subsystem instrumentation provides the logic for automatic isolation ofthe Casing Cooling tank at the low-low level setpoint The timing of this function is important toprevent gas transport to the outside recirculation pumps from the Casing Cooling tank due tovortexing.Automatic isolation is initiated when the Casing Cooling tank level drops below thelow-low level setpoint, after a CDA signal. Signals are generated by each tank level monitor, andthe channel bistable then automatically closes the respective train related pump low-low levelMOV.The low-flow MOV will also close automatically on low pump discharge flow as measuredfrom dp across the recirculation path. Low recirculation flow would occur upon shutting down theCasing Cooling pump or depletion of the Casing Cooling tank volume.

7.3REFERENCES

1.J. B. Reid, Process Instrumentation for Westinghouse Nuclear Steam Supply Systems,WCAP-7913.2.The Institute of Electrical and Electronics Engineers, Inc., IEEE Standard: Criteria forProtection Systems for Nuclear Power Generating Stations, IEEE Std279-1971.3.D. N. Katz, Solid State Logic Protection System Description, WCAP-7672, June1971.4.J. Locante and E. G. Igne, Environmental Testing of Engineered Safety Features RelatedEquipment (NSSS - Standard Scope), WCAP-7744, VolumeI, August1971.

Revision 52-09/29/2016NAPS UFSAR7.3-315.The Institute of Electrical and Electronics Engineers, Inc., IEEE Standard: Criteria forClass1E Electrical Systems for Nuclear Power Generating Stations, IEEE Std308-1969.6.The Institute of Electrical and Electronics Engineers, Inc., IEEE Trial Use Standard: GeneralGuide for Qualifying Class1 Electrical Equipment for Nuclear Power Generating Stations,IEEE Std323-1971.7.The Institute of Electrical and Electronics Engineers, Inc., IEEE Trial Use Guide for TypeTests of Continuous Duty Class I Motors Installed Inside the Containment of Nuclear PowerGenerating Stations, IEEE Std334-1971.8.The Institute of Electrical and Electronics Engineers, Inc., IEEE Trial Use Criteria for thePeriodic Testing of Nuclear Power Generating Station Protective Systems, IEEEStd338-1971.9.The Institute of Electrical and Electronic Engineers, Inc., IEEE Trial Use Guide for SeismicQualification of ClassI Electric Equipment for Nuclear Power Generating Stations, IEEEStd344-1971, dated August11,1971.10.The Institute of Electrical and Electronics Engineers, Inc., IEEE Standard for ElectricalPenetration Assemblies in Containment Structures for Nuclear Fueled Power GeneratingStations, IEEE Std317-1971.11.The Institute of Electrical and Electronics Engineers, Inc., IEEE Standard Installation,Inspection and Testing Requirements for Instrumentation and Electric Equipment During theConstruction of Nuclear Power Generating Stations, IEEE Std336-1971.12.Technical ReportEE-0101, Setpoint Bases Document Analytical Limits, Setpoints andCalculations for Technical Specifications Instrumentation at NorthAnna and Surry PowerStations.7.3REFERENCE DRAWINGSThe list of Station Drawings below is provided for information only. The referenced drawings are not part of the UFSAR. This is not intended to be a complete listing of all Station Drawings referenced from this section of the UFSAR. The contents of Station Drawings are controlled by station procedure.Drawing NumberDescription1.11715-LSK-0-1ALogic Diagram: Digital Symbols2.11715-LSK-0-1BLogic Diagram: Analog Symbols3.11715-LSK-0-1CLogic Diagram: Solenoids 4.11715-LSK-0-03ALogic Diagrams: General Notes Revision 52-09/29/2016NAPS UFSAR7.3-325.11715-LSK-27-12ATypical Loop Diagram for Each Channel Hi-Hi Containment Pressure Protection6.11715-LSK-27-12BHi-Hi Containment Pressure Protection and Indication, Unit17.11715-LSK-27-12CContainment Depressurization Actuation and Reset, Train A8.11715-LSK-27-12DHi Containment Pressure Protection9.11715-LSK-27-12EIntermediate Hi-Hi Containment Pressure Protection10.11715-LSK-27-12FContainment Depressurization Actuation and Reset, Train B11.11715-LSK-28-5CSafety Injection System, Actuated Devices12.11715-LSK-27-12GContainment Depressurization Actuated Devices13.11715-LSK-5-13ALogic Diagram: Motor Driven Steam Generator, Auxiliary Feedwater Pumps14.11715-LSK-5-8HFeedwater Isolation Trip Valves 15.11715-LSK-32-1BContainment Isolation, Phase B, Actuation and Reset16.11715-LSK-32-1DNormally Open Containment Isolation Trip Valves 17.11715-LSK-32-1EContainment Isolation Trip Valves, Train A 18.11715-LSK-32-1FContainment Isolation Trip Valves, Train B19.11715-LSK-5-13BTurbine Driven, Steam Generator, Auxiliary Feedwater Pumps20.11715-LSK-5-13CAuxiliary Feedwater Control Valves 21.11715-LSK-8-18AMain Steam Isolation Trip Valve22.11715-LSK-8-18DMain Steam Isolation Bypass Valve23.11715-LSK-1-2ELogic Diagram: Turbine Trips, Sheet 524.11715-LSK-5-12ALogic Diagram: Steam Generator Blowdown Trip Valves25.11715-LSK-22-12ZLogic Diagram: Undervoltage Protection, Unit126.11715-LSK-28-5ALogic Diagram: Safety Injection System27.11715-LSK-32-1ALogic Diagram: Phase A, Containment Isolation Actuation28.11715-LSK-27-1ALogic Diagram: Recirculation Spray Sub Systems29.11715-LSK-27-1BLogic Diagram: Recirculation Spray Sub Systems Revision 52-09/29/2016NAPS UFSAR7.3-33Table7.3-1INTERLOCKS FOR ENGINEERED SAFETY FEATURES ACTUATION SYSTEMIn addition to the interlocks in the Technical Specifications,the following interlocks are installed.DesignationInputFunction PerformedP-4Reactor tripActuates turbine tripCloses main feedwater valves on Tavg below setpointPrevents opening of main feedwater valves that were closed by safety injection or high steam generator water levelAllows reset of safety injection actuationReactor not trippedDefeats reset of the safety injection actuation signalP-142/3 steam generator water level above setpoint on any steam generatorCloses all feedwater control valvesTrips all main feedwater pumps and closes the feed line isolation valvesActuates turbine trip Revision 52-09/29/2016NAPS UFSAR7.3-34Table7.3-2ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATIONFunctional UnitChannels to TripMinimum Channels Operable1.Safety Injectiona.Manual Initiation12b.Automatic Actuation12c.Containment Pressure-High22d.Pressurizer Pressure-Low-Low22e.Differential Pressure Between SteamLines-High2/steam line twice and 1/3 steam lines2/steam linef.Steam Flow in Two Steam Lines-High1/steam line any 2 steam lines1/steam lineCoincident with eitherTavg-Low-Low1 Tavg any 2loops1 Tavg any 2loopsor, coincident with Steam Line Pressure-Low1 pressure any 2lines1 pressure any 2lines2.Containment Spraya.Manual1 set2setsb.Automatic Actuation Logic12c.Containment Pressure-High-High23d.Refueling Water Storage Tank (RWST)Level-Low Coincident with ContainmentPressure High-High223.Containment Isolationa.Phase"A" Isolation1)Manual122)From Safety Injection Automatic Actuation Logic12c.Phase"B" Isolation1)Manual1set2 2)Automatic Actuation Logic12 3)Containment Pressure-High-High23 Revision 52-09/29/2016NAPS UFSAR7.3-354.Steam Line Isolationa.Manual1/steam line2/steam lineb.Automatic Actuation Logic12c.Containment Pressure-Intermediate High-High22d.Steam Flow in Two Steam Lines-High1/steam line any 2steam lines1/steam lineCoincident with eitherTavg-Low-Low1 Tavg any 2loops1 Tavg any 2loopsor, coincident with Steam Line Pressure-Low1 pressure any 2lines1 pressure any 2lines5.Turbine Trip & Feedwater Isolationa.Steam Generator Water Level-High-High2/loop2/loopb.Automatic Actuation Logic and Actuation Relays12c.Safety Injection (SI)See #1 above (All SI initiating functions and requirements)6.Auxiliary Feedwater Pump Starta.Manual Initiation12b.Automatic Actuation Logic12c.Steam Generator Water Level-Low-Low2/steam generator2/steam generatord.Safety Injection (SI)See #1 above (All SI initiating functions and requirements)e.Station Blackout1/bus on 2busses1/bus on 2bussesf.Main Feed Pump Trip1/pump1/pump7.Switchover to Containment Sumpa.Automatic Actuation Logic and Actuation Relays12b.Refueling Water Storage Tank (RWST)Level-Low-Low23Table7.3-2(continued)ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATIONFunctional UnitChannels to TripMinimum Channels Operable Revision 52-09/29/2016NAPS UFSAR7.3-368.Engineered Safety Feature Actuation System Interlocksa.Pressurizer Pressure, P-1122b.Low-Low Tavg, P-1222c.Reactor Trip, P-4129.Loss of Powera.4.16Kv Emergency Bus Undervoltage (Loss of Voltage)2/bus2/busb.4.16Kv Emergency Bus Undervoltage (Grid Degraded Voltage)2/bus2/busTable7.3-2(continued)ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATIONFunctional UnitChannels to TripMinimum Channels Operable Revision 52-09/29/2016NAPS UFSAR7.3-37Figure 7.3-1LOGIC DIAGRAM MOTOR DRIVEN STEAM GENERATOR AUXILIARY FEED PUMPS Revision 52-09/29/2016NAPS UFSAR7.3-38Figure 7.3-2UNIT TRIP SIGNAL INTERFACES Revision 52-09/29/2016NAPS UFSAR7.3-39Figure 7.3-3ENGINEERED SAFETY FEATURES SIGNAL INTERFACES Revision 52-09/29/2016NAPS UFSAR7.3-40Figure 7.3-4SIGNAL PATHS TO ESF ACTUATED DEVICES Revision 52-09/29/2016NAPS UFSAR7.3-41Figure 7.3-5LOSS AND RESTORATION OF EMERGENCY BUS Revision 52-09/29/2016NAPS UFSAR7.3-42Figure 7.3-6DIESEL LOAD AND SEQUENCING CONDITIONING CONCEPT Revision 52-09/29/2016NAPS UFSAR7.3-43Figure 7.3-7RESERVE STATION SERVICE-UNDERVOLTAGEFigs. 7.3-1 & 7.3-12Fig 7.3-1 Revision 52-09/29/2016NAPS UFSAR7.3-44Figure 7.3-8REMOVAL OF UNNECESSARY LOAD FROM EMERGENCY BUS DURING CONTAINMENT DEPRESSURIZATION7.3-5Ref. Dwg. No. 12Fig.

Revision 52-09/29/2016NAPS UFSAR7.3-45Figure 7.3-9STATION SERVICE-UNDERVOLTAGE Revision 52-09/29/2016NAPS UFSAR7.3-46Figure 7.3-10ENGINEERED SAFETY FEATURES BLOCKING LOGIC Revision 52-09/29/2016NAPS UFSAR7.3-47Figure 7.3-11NORMALLY CLOSED CONTAINMENT ISOLATION TRIP VALVES(Fig. 7.2-9)Refer To LSK-32-IE and LSK-32-IF (Ref. No. 17 and 18) for normally closed valves.

Revision 52-09/29/2016NAPS UFSAR7.3-48Figure 7.3-12LOGIC DIAGRAM TURBINE DRIVEN-STEAM GENERATOR AUXILIARY FEED PUMPFIG 7.3-1FIG 7.3-1FIG 7.2-7 Revision 52-09/29/2016NAPS UFSAR7.3-49Figure 7.3-13LOGIC DIAGRAM NORMALLY OPEN CONTAINMENT ISOLATION VALVESRef. Draw. 15Ref. Draw. 27REF DRAW 1718REF DRAW 1718REF DRAW 18REF DRAW 17 Revision 52-09/29/2016NAPS UFSAR7.3-50Figure 7.3-14ECCS LOGIC/AUTOMATIC SWITCHOVER FROMINJECTION PHASE TO RECIRCULATION PHASE Revision 52-09/29/2016NAPS UFSAR7.4-17.4SYSTEMS REQUIRED FOR SAFE SHUTDOWNElectrical schematic diagrams for systems required for shutdown and their supportingsystems were included in reports NA-TR-1001 and NA-TR-1002, Safety Related ElectricalSchematics, dated May10,1973, which were submitted to the Atomic Energy Commission(AEC) on May18,1973, as separate documents.The information necessary for safe shutdown is available from instrumentation channelsthat are associated with the major systems in both the primary and secondary loops of the nuclearsteam supply system. These channels normally service a variety of operational functions,including start-up and shutdown as well as protective functions. There are no systems whose onlyfunction is safe shutdown. Prescribed procedures for placing and maintaining the plant in a safecondition can be instituted by appropriate alignment of selected nuclear steam supply systems.The discussion of these systems, together with the applicable codes, criteria, and guidelines, isfound in other sections of this FSAR. In addition, the implementation of shutdown functionsassociated with the engineered safety features that are used under postulated limiting faultsituations is discussed in Chapter6 and Section7.3.7.4.1DescriptionThe operator actions, instrumentation, and control features that maintain safe shutdown ofthe reactor as discussed in this section are the minimum number under nonaccident conditions.These features will permit the necessary operations that will:1.Prevent the reactor from achieving criticality in violation of the Technical Specifications.2.Provide an adequate heat sink such that design and safety limits are not exceeded.The plant is normally controlled from the main control room, which contains all necessaryinstrumentation and controls to achieve and maintain a safe-shutdown condition. In the unlikelyevent that the main control room needs to be evacuated, an auxiliary shutdown panel is provided.The conditions listed below include the design basis for the auxiliary shutdown panel. Theidentification is given for the control and monitoring features (Section7.4.1.2) necessary formaintaining a hot shutdown. The equipment and services and approximate time required after anincident that requires a hot shutdown are listed in Section7.4.1.3; the equipment and serviceavailable for a cold shutdown are identified in Section7.4.1.4.7.4.1.1Design Considerations for the Auxiliary Shutdown Panel1.In the event the control room must be evacuated, it is assumed the control room isinaccessible for at least a period of 10hours to 1week.2.Although it is assumed that the operator trips the reactor before leaving the control room, aturbine trip can be accomplished at the turbine as well as in the control room, and a reactortrip can be accomplished at the reactor trip switchgear as well as in the control room.

Revision 52-09/29/2016NAPS UFSAR7.4-23.In the event the control room is inaccessible, the operator must bring the plant to the hotstandby condition.4.It is assumed that loss of external power may occur during evacuation.5.A sound-powered telephone network exists between the auxiliary shutdown panel and thefollowing areas in the plant:a.Auxiliary feed pump area.b.Normal and emergency switchgear rooms.c.Diesel generators.d.Emergency boration line.e.Steam dump valves.6.For safety-related circuits, electrical as well as physical isolation exists between the maincontrol board and auxiliary shutdown panel.7.The diesel generator will have both local-start and auto-start capability.8.No additional accident conditions are assumed to occur simultaneously with control roominaccessibility.9.No hardware failures are assumed to occur simultaneously with control room inaccessibility;therefore, all automatic systems continue functioning.10.Fire in a section of the control board is considered credible. However, with the design of thecontrol board (separation, limited combustibles), control room evacuation should not berequired following a fire in the main control board.11.A source of feedwater will be available for in excess of 1week. For the first 8hours,auxiliary feedwater pumps take suction from the 110,000-gallons condensate storage tank.After 8hours, the auxiliary feedwater pumps can take suction from either the service watersystem or fire main.12.Pressurizer heater on-off control with selector switch is provided for two backup heatergroups. The heater groups are connected to separate buses, such that each is connected toseparate diesels in the event of loss of outside power. The control is grouped with thecharging flow controls and duplicates functions available in the control room.13.The condenser steam dump and atmospheric relief valves are automatically controlled.Manual control is provided locally as well as in the control room for the atmospheric reliefvalves. Steam dump to the condenser is blocked on high condenser pressure.14.It is assumed that one operator will be at the auxiliary shutdown panel, using detailedoperating instructions in conjunction with instrumentation and controls on the panel. He will Revision 52-09/29/2016NAPS UFSAR7.4-3be communicating by sound-powered telephone with other personnel to direct necessarylocal-manual action.15.Electric motors can be started or stopped at the switchgear.16.Motor-operated valves can be operated manually and drivers can be disengaged or locked outif required.17.The following processes will be available:a.Residual heat removal (reactor coolant system natural circulation).b.Boration capability.c.Reactor coolant sampling.d.Reactor coolant inventory control.e.Instrument air.18.The following items operate during normal plant operation and will continue to operate fromthe emergency diesel-generator bus should there be a loss of reserve station service power:a.Service water pumps.b.Component cooling water pumps.c.Reactor containment fan cooler units.19.For equipment having motor controls outside the control room on the auxiliary shutdownpanel (which duplicate the functions inside the control room), the controls will be providedwith a selector switch that transfers the control of the switchgear from the control room to aselected local station. Placing the local selector switch in the local operating position willgive an annunciating alarm in the control room and will turn off the motor control positionlights on the control room panel. (Refer to Figures7.4-1 and7.4-2.)20.It is noted that the instrumentation and controls listed in Section7.4.1.2, which are critical toachieving and maintaining a safe shutdown, are available in the event an evacuation of thecontrol room is required. These controls and instrumentation channels, together with theequipment and services identified in the following sections (7.4.1.3 and7.4.1.4), which areavailable for both hot and cold shutdown, identify the potential capability for cold shutdownof the reactor subsequent to a control room evacuation through the use of suitableprocedures. Therefore, the applicable requirements of General Design Criterion19 (1971criteria) are met.7.4.1.2Auxiliary Shutdown InstrumentationShould it become necessary to abandon the control room, the plant can be safely brought toand maintained in the hot-shutdown condition from the auxiliary shutdown control panels. Thiscapability, including a list of instruments and controls, is fully described in Section7.7.1.13.1.

Revision 52-09/29/2016NAPS UFSAR7.4-47.4.1.3Equipment and Services and Approximate Time Required After Incident ThatRequires Hot Shutdown1.Auxiliary feedwater pumps-required if main feedwater pumps are not operating. Forblackout condition the auxiliary feedwater pumps start automatically within 1minute. (SeeChapter10 for a discussion of pumps.)2.Reactor containment fan cooler units-within 15minutes. (See Chapter9 for a discussion offan coolers.)3.Diesel generators-Initial loads begin in 10seconds. (See Chapter8 for a discussion ofdiesels.)4.Lighting in the areas of plant required during this condition-immediately. (See Chapter9for a discussion of lighting.)5.Pressurizer heaters-within 8hours. (See Chapter5 for a discussion of heaters.)6.Communication network to be available immediately.7.4.1.4Equipment and Systems Available for Cold Shutdown1.Reactor coolant pump. (See Chapter5.)2.Auxiliary feedwater pumps. (See Chapter10.)3.Boric acid transfer pump. (See Chapter9.)4.Charging pumps. (See Chapter9.)

5.Service water pumps. (See Chapter9.)6.Containment fans. (See Chapter9.)7.Control room ventilation. (See Chapter9.)

8.Component cooling pumps. (See Chapter9.)9.Residual heat removal pumps. (See Chapter5.)10.Certain motor control center and switchgear sections.11.Controlled steam release and feedwater supply. (See Section7.7 and Chapter10.)12.Boration capability. (See Chapter9.)13.Nuclear instrumentation system (source range and intermediate range). (See Sections7.2and7.7.)14.Reactor coolant inventory control (charging and letdown). (See Chapter9.)15.Pressurizer pressure control including opening control for pressurizer relief valves (heatersand spray). (See Chapter5.)

Revision 52-09/29/2016NAPS UFSAR7.4-5The reactor plant design does not preclude attaining the cold-shutdown condition fromoutside the control room. An assessment of plant conditions can be made on a long-term basis (aweek or more) to establish procedures for bringing the plant to cold shutdown. During such timethe plant could be safely maintained at hot-shutdown condition. Detailed procedures to befollowed in effecting cold shutdown from outside the control room are best determined by plantpersonnel at the time it is decided to go to cold shutdown.7.4.2AnalysisHot shutdown is a stable plant condition, reached following a plant shutdown. Thehot-shutdown condition can be maintained safely for an extended period of time. In the unlikelyevent that access to the control room is restricted, the plant can be safely kept at hot shutdownuntil the control room can be re-entered.The evaluation of the ability to maintain a safe shutdown has included a consideration of theaccident consequences that might jeopardize safe-shutdown conditions. The accidentconsequences that are germane are those that would tend to degrade the capabilities for boration,adequate supply for auxiliary feedwater, and residual heat removal. The results of the accidentanalyses are presented in Chapter15. Of these the following produce the most severeconsequences that are pertinent:1.Uncontrolled boron dilution.2.Loss of normal feedwater.3.Loss of offsite ac power to the station auxiliaries (station blackout).It is shown by these analyses that safety is not adversely affected by these accidents, withthe associated assumptions being that the instrumentation and controls indicated in Section7.4.1are available to control and/or monitor shutdown. These available systems will allow themaintenance of hot shutdown, even under the accident conditions listed above, which would tendtoward a return to criticality or a loss of heat sink.

Revision 52-09/29/2016NAPS UFSAR7.4-6Figure 7.4-1SWITCHING LOGIC, SHEET 1, FOR TRANSFER BETWEEN MAIN CONTROL BOARD AND AUXILIARY SHUTDOWN PANEL (FOR SWITCHGEAR (TYPICAL))

Revision 52-09/29/2016NAPS UFSAR7.4-7Figure 7.4-2SWITCHING LOGIC, SHEET 2, FOR TRANSFER BETWEEN MAIN CONTROL BOARD AND AUXILIARY SHUTDOWN PANEL [FOR SWITCHGEAR (TYPICAL)]

Revision 52-09/29/2016NAPS UFSAR7.4-8Intentionally Blank Revision 52-09/29/2016NAPS UFSAR7.5-17.5SAFETY-RELATED DISPLAY INSTRUMENTATION7.5.1DescriptionTables7.5-1 and7.5-2 list the information readouts provided to the operator to enable himto perform required manual safety functions and to determine the effect of manual actions takenfollowing a reactor trip due to a ConditionII, III, orIV event. Table7.5-2 also contains theminimum set of parameters classified as TypeA for ConditionIV events as analyzed byRegulatory Guide1.97. The tables list the information readouts required to maintain the plant in ahot-shutdown condition or to proceed to a cold shutdown within the limits of the TechnicalSpecifications. Reactivity control after ConditionII andIII faults will be maintained byadministrative sampling of the reactor coolant for boron to ensure that the concentration issufficient to maintain the reactor subcritical.Table7.5-3 lists the information available to the operator for monitoring conditions in thereactor, the reactor coolant system, the containment, and process systems throughout all normaloperating conditions of the plant, including anticipated operational occurrences.After the March1979 accident at Three Mile Island, the arrangement of controls anddisplays on the control boards was reviewed. As a result, some devices were relocated on theseboards to improve operator efficiency and to minimize the chance of operator error. A lamp testsystem was added on the safety-related control boards in the main control room to verifysystem/component status. In addition, postaccident monitoring and control panels were installedfor both units.7.5.2AnalysisFor ConditionII, III, andIV events (see Tables7.5-1 and7.5-2), sufficient duplication ofinformation is provided to ensure that the minimum information required will be available. Theinformation is part of the operational monitoring of the plant that is under operator surveillanceduring normal plant operation. This is functionally arranged on the control board to provide theoperator with ready understanding and interpretation of plant conditions. Comparisons betweenduplicate information channels or between functionally related channels will enable the operatorto readily identify a malfunction in a particular channel.Refueling water storage tank (RWST) level is indicated by four and alarmed by twoindependent single-channel systems. Similarly, two channels of primary system pressure (widerange) are available for maintaining proper pressure-temperature relationships following apostulated ConditionII orIII event. One channel of steam generator water level (wide range) isprovided for each steam generator; this duplicates level information from steam generator waterlevel (narrow range) and ensures the availability of level information to the operator.

Revision 52-09/29/2016NAPS UFSAR7.5-2The remaining safety-related display instrumentation necessary for ConditionII, III, orIVevents is obtained through isolation amplifiers from the protection system. These protectionchannels are described in Section7.2.The readouts identified in the tables were selected on the basis of sufficiency andavailability during and subsequent to an accident for which they are necessary. Thus, theoccurrence of an accident does not render this information unavailable, and the status andreliability of the necessary information is known to the operator before, during, and after anaccident. No special separation is required to ensure the availability of necessary and sufficientinformation. In fact, such separation could reduce the operator's ease of interpretation of data.The status of all safety-related instrumentation bi-stables is monitored by status lights andannunciators. All containment isolation trip valves have their status monitored by lights on themain control board. All safety-related switchgear is monitored by indicating lights in the maincontrol room.The design criteria used in the display system are listed below.1.Range and accuracy requirements are determined through the analyses of ConditionII, III,orIV events, as described in Chapter15. The display system meets the followingrequirements:a.The range of the readouts extends over the maximum expected range of the variable beingmeasured, as listed in column4 of Tables7.5-1 and7.5-2.b.The combined available indicated accuracies, shown in column5 of Tables7.5-1and7.5-2, are within the errors assumed in the safety analyses.c.Power supply for the display instruments is described in Section8.3.1.2 and complieswith paragraph5.4 of IEEE Std308-1971.d.Those channels determined to provide useful information in charting the course of eventsare recorded, as shown in column6 of Tables7.5-1 and7.5-2.2.The following information is displayed on the main control board safeguards sections bymore than one seismically qualified indicator from separate channels powered by separatevital buses and wired by separate multiconductor cables:a.Containment building pressure.b.Containment sump level.c.Containment sump temperature.d.RWST level.e.RWST temperature.f.Service water reservoir level.

Revision 52-09/29/2016NAPS UFSAR7.5-3g.Service water pressure.h.Safety injection accumulator level.i.Safety injection accumulator pressure.j.Safety injection hot leg flow (total).k.Safety injection cold leg flow (total).l.Pressurizer liquid temperaturem.Reactor vessel leveln.Degree of Subcooling o.Core Exit ThermocouplesThe following information is displayed to the operator on the main control board by morethan one seismically qualified indicator, from separate channels powered by separate vitalbuses, wired by separate multiconductor cables and including a seismic recorder:a.Steam generator level.b.Pressurizer level.c.Pressurizer pressure.d.Reactor coolant temperature (wide range).e.Condensate storage tank level (with alarm).The auxiliary feedwater flow is displayed to the operator on or adjacent to the main controlboard by a seismically qualified indicator:The following parameters have input to the plant computer for station logs and postaccidentreview. The information from one channel of each parameter will be retained by thecomputer for 1week, following a safeguards actuation, for postaccident analysis:a.Steam generator level.b.Pressurizer level.c.Pressurizer pressure.d.Reactor coolant temperature.e.Containment building pressure.

Revision 52-09/29/2016NAPS UFSAR7.5-4In response to NUREG-0578, ClassI seismically qualified postaccident monitoring controlpanels for both units were installed (PAMC-1 and PAMC-2). The panels provide controls forthe hydrogen analyzer inlet and outlet valves, hydrogen recombiner inlet and outlet valves,reactor coolant system venting valves, postaccident hydrogen indication, containment sumpisolation valves, reactor vessel level, and containment pressure and water levels. The panels,including panel-mounted equipment, have been specified to IEEE Std323-1971 and IEEEStd344-1975 requirements. All devices and internal wiring meet color separationrequirements specified in Chapter8.In compliance with Regulatory Guide1.97, the following information is displayed on theNIS panels by two Class1E seismically qualified indicators from separate channels poweredby separate vital buses and wired by separate multi-conductor cables.a.Excore neutron flux - wide range (10-8 to 200% of full power)b.Excore neutron flux - source range (0.1 to 105cps)In addition, in compliance with AppendixR, the single channel display at the remotemonitoring panels provides for adequate information display of neutron flux information inthe event of a fire in the control room, emergency switchgear room, or cable vault and tunnel.

Revision 52-09/29/2016NAPS UFSAR7.5-5Table7.5-1MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION II AND III EVENTSNumber of ChannelsAvailable Indicated AccuracyaIndicator/RecorderParameterAvailableRequiredRangePurpose1.Tcold or Thot(measured, wide range)1 Thot,1 Tcold per loop1 in anyoperatingloop0 to 700oF+/- 13.5°FAll channels are recordedEnsure maintenance of proper cooldown rate and ensure maintenance of proper relationship between system pressure and temperature for nil-ductility transition temperature (NDTT) considerations.2.Pressurizer water level310 to 100% Entire distance between taps+/-7.12%All 3 channels indicated; 1 channel is selected for recordingEnsure maintenance of proper reactor coolant inventory.3.Reactor coolant system pressure (wide range)210 to 3000psig+/- 70.1psigIndicatedEnsure maintenance of proper relationship between system pressure and temperature for NDTT considerations.4.Containment pressure (narrow range)410 to 65psia+/-1.6psiaAll 4 are indicatedRecorder for 1 channelMonitor containment pressure conditions to indicate the need for potential safeguards actuation.5.Containment pressure (wide range)210 to 180psia+/-4.9psiaBoth are indicatedMonitor containment pressure conditions to indicate the need for potential safeguards actuation.a.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowances (CSA) values for a mild environment.)b.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable on at least two loops.

Revision 52-09/29/2016NAPS UFSAR7.5-66.Steam-line pressure3/steam line1/steam line0 to 1400psig+/-37.7psigAll required channels are indicatedMonitor steam generator pressure conditions during hot shutdown and cooldown, and for use in recovery from steam generator tube ruptures.7.Steam generator water level (wide range)1/steam generatorb0 to 100% (+7 to -41 ft from nominal full-load water level)-2.1 to +2.9% (cold)All channels recordedEnsure maintenance of reactor heat sink.8.Steam generator water level (narrow range)3/steamgeneratorb0 to 100% (+7 to -5ft from nominal full-load water level)-2.7% to

+11.1%All channels indicated; one channel per steam generator is recorded.Ensure maintenance of reactor heat sink.9.Inadequate Core Cooling Monitor21All channels indicatedEnsure proper core subcooling.10.Reactor vessel levelUpper range vessel levelFull range vessel levelDynamic head vessel level60 to 120%0 to 120%0 to 120%-8.2 to +3.7%-11.7 to

+5.5%-7.4 to +3.4°FOne channel recordedTable7.5-1(continued)MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION II AND III EVENTSNumber of ChannelsAvailable Indicated AccuracyaIndicator/RecorderParameterAvailableRequiredRangePurposea.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowances (CSA) values for a mild environment.)b.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable on at least two loops.

Revision 52-09/29/2016NAPS UFSAR7.5-711.Degree of subcooling-35°F (superheat) to200°F (subcooled)-24.9 to +18.6°F12.Core exit thermocouples40 to 2300°F-18.6 to +24.9°F13.Pressurizer liquid temperature21100 to 700°Fnot calculatedAll channels indicated and monitored at the computerProvide compensation temperature for pressurizer water levelTable7.5-1(continued)MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION II AND III EVENTSNumber of ChannelsAvailable Indicated AccuracyaIndicator/RecorderParameterAvailableRequiredRangePurposea.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowances (CSA) values for a mild environment.)b.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable on at least two loops.

Revision 52-09/29/2016NAPS UFSAR7.5-8Table7.5-2MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/RecorderParameterAvailableRequiredRangePurpose1.Containment pressure(narrow range) b410 to 65psia+/-1.6psiaAll 4 are indicatedMonitor post-LOCA containment pressure conditions.2.Containment pressure (wide range) b210 to 180psia-7.1 to +7.5psiaBoth are indicated, only 1 is recordedMonitor post-LOCA containment pressure conditions.3.RWST water level420 to 100%-2.4 to +2.5%All are indicated; 2 are alarmedEnsure that water is available to the safety injection system after a LOCA and determine when to shift from injection to recirculation mode.4.Steam generator water level (narrow range) b3/steam generatorc0 to 100% (+7 to -5ft from nominal full-load level)-3.7 to +14.4% dAll channels indicated; one channel per steam generator is recorded.Detect steam generator tube rupture; monitor steam generator water level following a steam-line break.a.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for Post Design-Basis Event (PDBE) environment, except RWST and ECST water level, which is not located in a harsh environment.)b.Variable analyzed by Regulatory Guide1.97 and classified as Type A for ConditionIV events.c.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable for two loops.d.For the steam break, when the water level channel is exposed to a hostile environment, the accuracy required can be relaxed. The indication need only convey to the operator that water level in the steam generator not experiencing the break is somewhere between the narrow-range steam generator water level taps.

Revision 52-09/29/2016NAPS UFSAR7.5-95.Steam generator water level (wide range)1/steam generatorc0 to 100% (+7 to -41 ft from nominal full-load level)-19.4 to +7.5% dAll channels are recordedDetect steam generator tube rupture; monitor steam generator water level following a steam-line break.6.Steam-line pressure b3/steam line1/steam line0 to 1400psig+/-96.6psigAll channels are indicatedMonitor steam-line pressures following steam generator tube rupture or steam-line break.7.Pressurizer water level b310 to 100%Entire distance between taps-14.0 to +2.1%All 3 are indicated and 1 is for recordingIndicate that water has returned to the pressurizer following cooldown after steam generator tube rupture or steam-line break.8.Containment sump level (wide range) b210 to 11ft 4in-7.2 to +8.0inBoth channels are indicatedMonitor containment sump level during and following a LOCA or steam-line break.Table7.5-2(continued)MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/RecorderParameterAvailableRequiredRangePurposea.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for Post Design-Basis Event (PDBE) environment, except RWST and ECST water level, which is not located in a harsh environment.)b.Variable analyzed by Regulatory Guide1.97 and classified as Type A for ConditionIV events.c.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable for two loops.d.For the steam break, when the water level channel is exposed to a hostile environment, the accuracy required can be relaxed. The indication need only convey to the operator that water level in the steam generator not experiencing the break is somewhere between the narrow-range steam generator water level taps.

Revision 52-09/29/2016NAPS UFSAR7.5-109.Inadequate Core Cooling Monitor21All channels indicatedMonitor core conditions to help ensure proper core subcooling.9.1Reactor vessel levelUpper range vessel levelFull range vessel level Dynamic head vessel level60 to 120%0 to 120%0 to 120%not calculatednot calculatednot calculatedOne channel recorded9.2Degree of subcooling b-35°F (superheat) to200°F (subcooled)-74.8 to +52.3°F9.3Core exit thermocouples606K 1491H16-HIV b40 to 2300°F-22.2 to +36.0°F (at 700°F)-22.8 to +44.9°F (at 1200°F)10.Reactor coolant system pressure (wide range) b210 to 3000psig-115.1 to +138.6psigLoop A and C indication only, trended on PCSMonitor post-LOCA RCS pressure.Table7.5-2(continued)MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/RecorderParameterAvailableRequiredRangePurposea.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for Post Design-Basis Event (PDBE) environment, except RWST and ECST water level, which is not located in a harsh environment.)b.Variable analyzed by Regulatory Guide1.97 and classified as Type A for ConditionIV events.c.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable for two loops.d.For the steam break, when the water level channel is exposed to a hostile environment, the accuracy required can be relaxed. The indication need only convey to the operator that water level in the steam generator not experiencing the break is somewhere between the narrow-range steam generator water level taps.

Revision 52-09/29/2016NAPS UFSAR7.5-1111.High head safety injection flow to cold leg (total) b210 to 1000 gpm-108.4 to +99.9gpmIndicated on control board and trended on PCSMonitor post-LOCA total safety injection flow rate to RCS cold legs.12.Containment high range radiation monitor b21100 to 107R/hr+/-2.25x106R/hrAll channels are recordedMonitor post-LOCA containment radiation levels.13.Source range neutron flux (Gamma-Metrics)2110-1 to 105cps+/-5810cpsTrended on PCSMonitor post-LOCA core reactivity.14.Power range neutron flux (Gamma-Metrics)2110-8 to 2x102% power+/-11.6% powerTrended on PCSMonitor post-LOCA core reactivity15.RCS hot leg temperature (wide range)310 to 700°F-6.9 to +20.1°FAll channels are recordedMonitor reactor coolant temperature to help ensure core cooling is being accomplished.16.RCS cold leg temperature (wide range)310 to 700°F-6.9 to +20.1°FAll channels are recordedMonitor reactor coolant temperature to help ensure core cooling is being accomplished.Table7.5-2(continued)MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/RecorderParameterAvailableRequiredRangePurposea.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for Post Design-Basis Event (PDBE) environment, except RWST and ECST water level, which is not located in a harsh environment.)b.Variable analyzed by Regulatory Guide1.97 and classified as Type A for ConditionIV events.c.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable for two loops.d.For the steam break, when the water level channel is exposed to a hostile environment, the accuracy required can be relaxed. The indication need only convey to the operator that water level in the steam generator not experiencing the break is somewhere between the narrow-range steam generator water level taps.

Revision 52-09/29/2016NAPS UFSAR7.5-1217.Containment hydrogen analyzer210 to 10% H2+/-1.45% H2Al channels are recordedMonitor post-LOCA containment hydrogen levels.18.Emergency condensate storage tank level210 to 100%+/-2.7%One channel recordedMonitor emergency condensate storage tank (ECST) level to help ensure adequate water supply for auxiliary feedwater.19.Containment isolation valve position1/isolationvalve1/isolationvalveOpen/Closenot calculatedIndication onlyMonitor containment integrity.Table7.5-2(continued)MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/RecorderParameterAvailableRequiredRangePurposea.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for Post Design-Basis Event (PDBE) environment, except RWST and ECST water level, which is not located in a harsh environment.)b.Variable analyzed by Regulatory Guide1.97 and classified as Type A for ConditionIV events.c.Minimum requirements: One level channel per steam generator (either wide or narrow range) with wide-range channels operable for two loops.d.For the steam break, when the water level channel is exposed to a hostile environment, the accuracy required can be relaxed. The indication need only convey to the operator that water level in the steam generator not experiencing the break is somewhere between the narrow-range steam generator water level taps.

Revision 52-09/29/2016NAPS UFSAR7.5-13Table7.5-3CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesNUCLEAR INSTRUMENTATION1.Source rangea.Count rate2100 to 106 counts/sec+/-7% of the linear full-scale analog voltage bBoth channels indicated; either may be selected for recordingControl boardOne 2-pen recorder is used to record any of the 8 nuclear channels (2 source range, 2 intermediate range, and 4 power range)b.Start-up rate2-0.5 to 5.0 decades/min+/-7% of the linear full-scale analog voltage bBoth channels indicatedControl board2.Intermediate rangea.Flux level210-11 to 10-3amps 8decades of neutron flux (corresponds to 0-to-full-scale analog voltage) overlapping the source range by 2 decades+/-7% of the linear full-scale analog voltage and +/-3% of the linear full-scale voltage in the range of 10-4 to 10-3 A bBoth channels indicated; either may be selected for recordingControl boardb.Start-up rate2-0.5 to 5.0 decades/min+/-7% of the linear full-scale analog voltage bBoth channels indicatedControl boarda.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-14NUCLEAR INSTRUMENTATION (continued)3.Power rangea.Uncalibrated ion chamber current (top and bottom uncompensated ion chambers)40 to 120% of full-power current +/-1.2% of full power currentAll 8 current signals indicatedNIS racks in controlroomb.Upper and lower ion chamber current difference4-30 to +30%+/-3% of full power bDiagonally opposed; any 2 of the 4 channels may be selected for recording at the same time using recorder in item 1Control boardc.Average flux of the top and bottom, ion chamber4 0 to 120% of full power +/-3% of full power for indication +/-2% for recording bAll 4 channels indicated; any 2 of the 4 channels may be recorded using recorder in item 1 aboveControl boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-15NUCLEAR INSTRUMENTATION (continued)d.Average flux of the top and bottom ion chambers4 0 to 200% of full power+/-2% of full power to 120% +/-6% of full power to 200% bAll 4 channels recordedControl boarde.Flux difference on the top and bottom ion chambers4-30 to +30%+/-4% bAll 4 channels indicatedControl boardREACTOR COOLANT SYSTEM1.Tavg (measured)1/loop530° to 630°F+/-3.64°FThe 1 channel is indicatedControl board2.T (measured)1/loop0 to 150% of full-power T+/-5.2% of full-power TThe 1 channel is indicated; one loop's channel is selected for recordingControl boarda.Tcold or Thot (measured, wide range)1-Thot and 1-Tcold per loop0 to 700°F+/-13.5°FBoth channels recordedControl boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-16REACTOR COOLANT SYSTEM (continued)3.Overpower T setpoint1/loop0 to 150% of full-power T+/-5.7% of full-power TThe 1 channel is indicated; one loop's channel is selected for recordingControl board4.OvertemperatureT setpoint1/loop0 to 150% of full-power T+/-11.23 (F(I)<0)+/- 6.91 (F(I)=0)+/-10.31 (F(I)>0)All channels indicated; one channel is selected for recordingControl board5.Pressurizer pressure51700 to 2500psig+/-25.4psigAll channels indicatedControl board6.Pressurizer level30 to 100%Entire distance between taps+/-7.12%All channels indicated; one channel is selected for recordingControl boardTwo-pen recorder used, second pen records reference level signal.7.Primary coolant flow3/loop0 to 120% of rated flow+/-3.5 Foxboro transmitters+/-3.5 Rosemount transmitters at 100% flowAll channels indicatedControl boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-17REACTOR COOLANT SYSTEM (continued)8.Reactor coolant pump amperes1/loop0 to 1500Anot calculatedAll channels indicatedControl boardOne channel for each bus.9.Reactor coolant system pressure (wide range)20 to 3000psig+/-70.1psigAll channels indicatedControl board10.Pressurizer liquid temperature2100 to 700°Fnot calculatedAll channels indicated and monitored at the computerControl boardREACTOR CONTROL SYSTEM1.Demanded rod speed10 to 76 step/min+/-1.5 step/min bThe 1 channel is indicatedControl board2.Median Tavg1530° to 630°F+/-3.64°FThe 1 channel is indicated and recordedControl boardThe median of the 3-loop average temperatures are passed to the indicator and recorder.3.Treference1530° to 630°F+/-4°F bThe 1 channel is indicated and recordedControl boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-18REACTOR CONTROL SYSTEM (continued)4.Control rod positionIf system not available, borate and sample accordingly.a.Number of steps of demand rod withdrawal1/group0 to 230 steps+/-1 step bEach group is indicated during rod motionControl boardThese signals are used in conjunction with the measured position signals (4c) to detect deviation of any individual rod from the demanded position. A deviation will actuate an alarm and annunciator.b.Rod measured position1 for each rod0 to 235 steps+/-5% of full scale between 10-90% bEach rod position is indicatedControl boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-19REACTOR CONTROL SYSTEM (continued)5.Control rod bank demand position 40 to 100% withdrawn (0 to 230 steps)+/-2.5% of total bank travel bAll 4 control rod bank positions are recorded along with the low-low limit alarm for each bankControl board1. One channel for each control rod.2. An alarm and annunciator are actuated when the last rod control bank to be withdrawn reaches the withdrawal limit, when any rod control bank reaches the low insertion limit, and when any rod control bank reaches the low-low insertion limit.CONTAINMENT SYSTEMContainment pressure (narrow range) 40 to 65psia+/-1.6psiaAll 4 channels indicatedControl boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-20FEEDWATER AND STEAM SYSTEMS1.Auxiliary feedwater water flow1/steam generator0 to 500 gpm-21 to +17gpmAll channels indicatedControl boardOne channel to measure the flow to each steam generator.2.Steam generator level (narrow range)3/steam generator+7 to -5 ft from nominal full-load level-0.3 to +1.3ftAll channels indicated; one channel per steam generator is recordedControl board3.Steam generator level (wide range)1/steam generator+7 to -41 ft from nominal full-load level-1.3 to +1.7 ft (cold)All channels recordedControl board4.Main feedwater flow2/steam generator0 to 5x106 lbm/hr+/-1.46x105 lbm/hrAll channels indicated; the channels used for control are recorded.Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-21FEEDWATER AND STEAM SYSTEMS (continued)5.Magnitude of signal controlling main and bypass feedwater control valves1/main1/bypass0 to 100% of valve opening+/-1.5% bAll channels indicatedControl board1. One channel for each main and bypass feed-water control valve.

2. OPEN/SHUT indication is provided in the control room for each main feed- water control valve.6.Steam flow2/steam generator0 to 5x106 lbm/hr+/-2.04x105 lbm/hrAll channels indicated; the channels used for control are recordedControl boardAccuracy is equipment capability; however, absolute accuracy depends on applicant calibration against feedwater flow.7.Steam line pressure3/steam line0 to 1400psig+/-37.7psigAll channels indicatedControl board8.Steam dump demand signal10 to 100% maximum demand to valves+/-1.5% bThe one channel is indicatedControl boardOPEN/SHUT indication is provided in the control room for each steam dump valve.Table7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.5-22FEEDWATER AND STEAM SYSTEMS (continued)9.Turbine impulse chamber pressure20 to 120% full power+/-4.2% full power bBoth channels indicatedControl boardOPEN/SHUT indication is provided in the control room for each turbine stop valve.10.Area monitoring (Aux. Building ambient temperature)180 to 200°F+/-8.5°FEach channel indicatedControl roomMain annunciator alarm on high temperature in any monitored area.Table7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameterNumber of Channels AvailableRangeAvailable IndicatedAccuracyaIndicator/ RecorderLocationNotesa.Includes channel accuracy and environmental effects. (Accuracies are based on channel statistical allowance (CSA) values for a mild environment.)b.An original Westinghouse estimation of indication accuracy - not a CSA calculation.

Revision 52-09/29/2016NAPS UFSAR7.6-17.6ALL OTHER SYSTEMS REQUIRED FOR SAFETYElectrical schematic diagrams for all other systems required for safety, as described inSection7.6.1, were included in reports NA-TR-1001 and NA-TR-1002, Safety Related ElectricalSchematics, dated May10,1973, which were submitted to the Atomic Energy Commission(AEC), on May18,1973, as separate documents. A logic diagram for the loop stop valves hasbeen included in the FSAR as Figure7.6-1. Logic diagrams for the main control room ventilationduct isolation are included in report NA-TR-1001, dated May10,1973.7.6.1Instrumentation and Control Power SuppliesChapter8 provides a description and analysis of the instrumentation and control powersupplies, consisting of the vital bus and dc power systems.7.6.2Residual Heat Removal System Inlet MOV Interlocks7.6.2.1DescriptionThere are two motor-operated gate valves in series in the inlet line from the reactor coolantsystem to the residual heat removal (RHR) system. They are normally closed and are only openfor residual heat removal after system pressure is reduced below approximately 450psig andsystem temperature has been reduced below approximately 350°F. (See Chapter5 for details ofthe RHR system.) Each of these valves is interlocked with a pressure signal to prevent its beingopened whenever the system pressure exceeds 418psig. The upstream valve is interlocked fromone protection channel. The other valve is interlocked from a second protection channel. Bothprotection channels use Rosemount1153 pressure transmitters which are environmentallyqualified.

7.6.2.2AnalysisBased on the scope definitions presented in Reference1 (IEEE Std279-1971) andReference2 (IEEE Std338-1971), these criteria do not apply to the RHR isolation valveinterlocks; however, to meet AEC requirements and because of the possible severity of theconsequences of loss of function, the requirements of IEEE Std279-1971 are applied with thefollowing comments:1.For the purpose of applying IEEE Std279-1971, to this circuit, the following definitions areused:a.Protection System-The two valves in series in the line and all components of theirinterlocking and closure circuits.b.Protective Action - The maintenance of RHR system isolation from the reactor coolantsystem at reactor coolant system pressures above RHR design pressure.

Revision 52-09/29/2016NAPS UFSAR7.6-22.IEEE Std279-1971, Paragraph4.10: The requirement for online test and calibrationcapability is applicable only to the actuation signal and not to the isolation valves, which arerequired to remain closed during power operation.3.IEEE Std279-1971, Paragraph4.15: This requirement does not apply because the setpointsare independent of the mode of operation and are not changed.Environmental qualification of the valves and wiring is discussed in Section3.11.7.6.3Reactor Coolant System Loop Isolation Valve Interlocks7.6.3.1DescriptionThe purpose of these interlocks is to ensure that an accidental start-up of an unboratedand/or cold, isolated reactor coolant loop results only in a relatively slow reactivity insertion rate.The interlocks perform a protective function. Therefore, there are:1.Two independent limit switches to indicate that a valve is fully opened.2.Two independent switches to indicate that a valve is fully closed.3.Two differential pressure switches in each line that bypasses a cold-leg loop isolation valve.This is the line that contains the relief line isolation valve (valve4 in Figure7.6-2). It shouldbe noted that flow through the relief line isolation valves indicates that (1)the valves in theline are open, (2)the line is not blocked, and (3)the pump is running.7.6.3.2AnalysisSection15.2.6 presents an analysis of the start-up of an inactive reactor coolant loop withthe loop isolation valves initially closed. The start-up of an inactive reactor coolant loop accidentanalysis does not credit the loop stop valve interlocks.Based on the scope definitions presented in References1 and2, these criteria do not applyto the reactor coolant system loop isolation valve interlocks; however, to ensure continuousavailability of the function provided by these interlocks, the requirements of IEEE Std279-1971,are applied.Only those interlocks and alarms relating to core protection are described. Those requiredfor reactor coolant pump protection are not part of the protection system and need not meet theprotection system criteria of Reference1.In addition to the interlocks, an alarm is provided to indicate that the bypass valve (valve3in Figure7.6-2) is not closed when the power is above P-8. This will alarm whenever the reactoris at a power level where all loops are required to be in service and the bypass valve is not fullyclosed. An alarm is used because, if the bypass valve is opened at full power, the core flowreduction is of the order of 2% to 5% and does not result in an immediate DNB problem.

Revision 52-09/29/2016NAPS UFSAR7.6-37.6.4Main Control Room, Relay Room, and Emergency Switchgear Room Air Conditioning, Heating, and Ventilation System Instrumentation and Controls7.6.4.1DescriptionThe system design, flow diagram, and instrumentation application for the main controlroom and relay room air conditioning, heating, and ventilation system are included inSection9.4.1. Temperature controls are provided to maintain the return air from the main controlroom and relay room at a predetermined temperature, as sensed by the temperature transmitters.During LOCA conditions, the control and relay rooms are isolated from the outside atmosphere.A differential pressure indicator mounted on the ventilation panel, located in the main controlroom, is provided to determine that the pressure in the control room is being maintained slightlyabove the atmospheric pressure following a LOCA. A separate indicator mounted at the auxiliaryshutdown panel for each unit shows that the pressure in the relay room is also being maintainedslightly above atmospheric.There are no areas other than those described above where safety-related control andelectrical equipment require a controlled environment (temperature, humidity, and air particulate)for proper operation. Schematic drawings for equipment supporting the areas described wereincluded in the Safety Related Electrical Schematics, VolumeII, Tab9, submitted to the AEC onMay18,1973.7.6.4.2AnalysisThe control room ventilation system outdoor air inlet has two dampers in series, poweredfrom the same source as the fan and controlled by switches in the control room. Similarly, the dualdampers for the switchgear room ventilation inlet are powered from the same sources as its fanand are controlled by switches at the auxiliary control panel.7.6.5Refueling InterlocksElectrical interlocks (i.e., limit switches) for reducing the possibility of damage to the fuelduring fuel-handling operations are provided, as well as mechanical stops, which provide theprimary means of preventing fuel-handling accidents. For example, safety aspects of themanipulator crane fuel-handling operation depend on the use of electrical interlocks andmechanical stops, as discussed in Section9.1.4.4.4. The electrical interlocks for this manipulatorcrane fuel-handling operation are not specifically designed to the requirements of IEEEStd279-1971 because of the backup provided by the mechanical stops.7.6.6Accumulator Isolation Valve ControlThe control diagram for the motor-operated isolation valve in the accumulator discharge isshown in Figure7.6-3. The controls of the motor-operated isolation valves include automaticopening whenever reactor coolant system pressure exceeds a specified limit consistent with theassumptions of the accident analyses.

Revision 52-09/29/2016NAPS UFSAR7.6-4It is necessary with automatic opening of these valves with reactor coolant pressure toinclude an administratively controlled manual bypass circuit that must be actuated to allow forperiodic testing of the system valves. This manual bypass will be overridden by a safety injectionsignal or a manual opening signal. Additional description is in Sections6.3.2.2.7 and6.3.5.5.1.7.6.7Pressurizer Relief Valve Flow IndicationThe NRC clarifications to NUREG-0578 (contained in Discussion of Lessons LearnedShort-Term Requirements, Position2.1.3.a, Clarification2, October30,1979) state that controlroom indication and alarm should be provided for the valve position of the Pressurizerpower-operated relief valves (PORVs) PCV-1455C and 1456 and the safety valves SV-1551A, B,and C. These valves have been included in the NorthAnna response to USNRC RegulatoryGuide1.97 - Post Accident Monitoring.In order to protect the Reactor Coolant System and meet NUREG-0578/RegulatoryGuide1.97, Post Accident Monitoring requirements, an environmentally and seismicallyqualified Valve Monitoring System (VMS) has been installed to verify the CLOSED,NOT-CLOSED position of the safety valves during all modes of plant operation, except Mode6(Refueling). The PORVs use separate, environmentally and seismically qualified limit switches tomonitor valve position in all modes of operation.The VMS monitors safety valves using accelerometers and preamplifiers located inside thereactor containment. These accelerometers provide an input to the acoustical monitors in theControl Room. They provide reliable indication and alarms in the Main Control Room wheneverany one of the three safety valves, (SV-1551A, B, and C) are not fully closed.Pressurizer safety valves SV-1551A, B, and C have valve position indication in the ControlRoom derived from a qualified, single channel of acoustical monitoring, operating from a highlyreliable power supply. For each safety valve, an active and passive qualified accelerometer hasbeen attached to the outside of the discharge pipe and connected to preamplifiers installed inside atransient shield to maintain their environmental qualification. Either of these sensors can provideindication to alert the operator when flow is detected through a pressurizer safety valve. A panel,common to both Units1 and2, provides Operators with Control Room indication of the safetyvalves position. The power supply for the panel can be fed from either unit. A voltage relayprovides automatic transfer on the loss of either unit's power supply. The panel is seismicallysupported and is located beside 1-EI-CB-08A.PORV position indication for PCV-1455C and 1456 have four environmentally andseismically qualified valve stem position limit switches, powered by diverse power supplies, todetect OPEN/CLOSED position of each valve. The limit switches are arranged in two sets of twoper valve to provide channel redundant indication position lights in the Control Room. These limitswitches have been seismically installed, external to the PORV.

Revision 52-09/29/2016NAPS UFSAR7.6-

57.6REFERENCES

1.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard Criteria forProtection Systems for Nuclear Power Generating Stations, IEEE Std279-1971.2.The Institute of Electrical and Electronics Engineers, Inc., IEEE Trial-Use Criteria for thePeriodic Testing of Nuclear Power Generating Station Protection Systems, IEEEStd338-1971.

Revision 52-09/29/2016NAPS UFSAR7.6-6Figure 7.6-1LOOP STOP VALVE INTERLOCKS Revision 52-09/29/2016NAPS UFSAR7.6-7Figure 7.6-2TYPICAL REACTOR COOLANT SYSTEM LOOP WITH LOOP STOP VALVES Revision 52-09/29/2016NAPS UFSAR7.6-8Figure 7.6-3FUNCTIONAL BLOCK DIAGRAM FOR OPENING ACCUMULATOR ISOLATION VALVE Revision 52-09/29/2016NAPS UFSAR7.7-17.7PLANT CONTROL SYSTEMSThe general design objectives of the plant control systems are the following:1.To establish and maintain power equilibrium between the primary and secondary systemsduring steady-state unit operation.2.To constrain operational transients to preclude unit trip and re-establish steady-state unitoperation.3.To provide the reactor operator with monitoring instrumentation that indicates all requiredinput and output control parameters of the systems and enables the operator to assumemanual control of the systems.7.7.1DescriptionThe plant control systems described in this section perform the following functions:1.Reactor Control Systema.Enables the nuclear plant to accept a step-load increase or decrease of 10% and a rampincrease or decrease of 5% per minute, within the load range of 15% to 100% withoutreactor trip, steam dump, or pressurizer relief actuation, subject to possible xenonlimitations.b.Maintains reactor coolant average temperature (Tavg) within prescribed limits by creatingthe bank demand signals for moving groups of rod cluster control assemblies duringnormal operation and operational transients. The Tavg control also supplies the signals topressurizer level control and steam dump control. These signals are derived in the ReactorProtection System sent to the reactor control system via circuit isolators.2.Rod Control Systema.Provides for reactor power modulation by manual or automatic control of control rodbanks in a preselected sequence and for manual operation of individual banks.b.The rod control system includes systems for monitoring and indicating for the followingpurposes:1)To provide alarms to alert the operator if the required core reactivity shutdown marginis not available because of excessive control rod insertion.2)To display the control rod position.3)To provide alarms to alert the operator if control rod deviation exceeds a preset limit.3.Plant Control System Interlocks (See Table7.7-1.)Prevent further withdrawal of the control banks when signal limits are approached thatpredict the approach of a DNBR limit or kilowatts per foot limit.

Revision 52-09/29/2016NAPS UFSAR7.7-24.Pressurizer Pressure ControlMaintains or restores the pressurizer pressure to the design pressure +/-25psi (which is wellwithin reactor trip and relief and safety valve actuation setpoints limits) following normaloperational transients that induce pressure changes by control (manual or automatic) ofheaters and spray in the pressurizer. Also provides steam relief by controlling the powerrelief valves.5.Pressurizer Water-Level Controla.Establishes, maintains, and restores pressurizer water level within specified limits as afunction of the average coolant temperature. Level changes are caused by coolant densitychanges induced by loading, operational, and unloading transients. Level changes are alsoproduced by charging flow control (manual or automatic) as well as by manual selectionof letdown orifices.b.Maintains coolant level in the pressurizer within prescribed limits by controlling thecharging system flowrate, thus providing control of the reactor coolant water inventory,and isolates the letdown on low level.6.Steam Generator Water-Level Controla.Establishes and maintains the steam generator water level to within predetermined limitsduring normal operating transients.b.Provides capability to restores the steam generator water level to within predeterminedlimits at unit trip conditions. Regulates the feedwater flow rate such that duringoperational transients the heat sink for the reactor coolant system does not decrease belowa minimum. Steam generator water inventory control is manual or automatic through theuse of feedwater control valves.7.Steam Dump Controla.Permits the nuclear plant to accept a sudden loss of load without incurring reactor trip.Steam is dumped to the condenser as necessary to accommodate excess power generationin the reactor during turbine load-reduction transients.b.Ensures that stored energy and residual heat are removed following a reactor trip, to bringthe plant to equilibrium no-load conditions without the actuation of the steam generatorsafety valves.c.Maintains the plant at no-load conditions and permits manual temperature control.8.Incore InstrumentationProvides information on the neutron flux distribution and on the core outlet temperatures atselected core locations.

Revision 52-09/29/2016NAPS UFSAR7.7-37.7.1.1Reactor Control SystemThe reactor control system enables the nuclear plant to follow load changes automatically,including the acceptance of step-load increases or decreases of 10% and ramp increases ordecreases of 5% per minute, within the load range of 15% to100% without reactor trip, steamdump, or pressure relief, subject to possible xenon limitations. The system is also capable ofrestoring coolant average temperature to within the programmed temperature deadband followinga change in load. Manual control rod operation may be performed at any time.The reactor control system controls the reactor coolant average temperature by theregulation of control rod bank position. The reactor coolant loop average temperatures aredetermined from hot-leg and cold-leg measurements in each reactor coolant loop. These signalsare derived in the reactor protection system sent to the reactor control system via circuit isolators.An average coolant temperature (Tavg) is computed for each loop, where:The error between the programmed reference temperature (based on turbine impulsechamber pressure) and the median value of the average measured temperatures (which is thenprocessed through a lead-lag compensation unit) from each of the reactor coolant loopsconstitutes the primary control signal, as shown in general in Figure7.7-1 and in more detail onthe functional diagrams shown in Figure7.7-2. The system is capable of restoring coolant averagetemperature to the programmed value following a change in load. The programmed coolanttemperature increases linearly with turbine load from zero power to the full-power condition. TheTavg is also a signal to the pressurizer level control, steam dump control, and rod insertion limitmonitoring.An additional control input signal is derived from the reactor power versus turbine loadmismatch signal. This additional control input signal improves system performance by enhancingresponse.7.7.1.2Rod Control SystemThe rod control system receives rod speed and direction signals from the Tavg controlsystem. The rod speed demand signal varies over the corresponding range of 5 to 45in/minute (8to 72steps/minute) depending on the magnitude of the error signal. The rod direction demandsignal is determined by the positive or negative value of the error signal. Manual control isprovided to move a control bank in or out at a prescribed fixed speed.When the turbine load reaches approximately 15% of rated load, the operator may select theAUTOMATIC mode, and rod motion is then controlled by the reactor control systems. Apermissive interlock C-5 (see Table7.7-1) derived from measurements of turbine impulsechamber pressure prevents automatic withdrawal when the turbine load is below 15%. In theTavgThotTcold+2-----------------------------=

Revision 52-09/29/2016NAPS UFSAR7.7-4AUTOMATIC mode, the rods are again withdrawn (or inserted) in a predetermined programmedsequence by the automatic programming equipment. The manual and automatic controls arefurther interlocked with the control interlocks.The shutdown banks are always in the fully withdrawn position during normal operationand are moved to this position at a constant speed by manual control before criticality. A reactortrip signal causes them to fall by gravity into the core. There are two shutdown banks.The control banks are the only rods that can be manipulated under automatic control. Eachcontrol bank is divided into two groups to obtain smaller incremental reactivity changes per step.All rod control cluster assemblies in a group are electrically paralleled to move simultaneously.There is individual position indication for each rod cluster control assembly.Power to rod drive mechanisms is supplied by two motor-generator sets operating from twoseparate 480V, three-phase buses. Each generator is of the synchronous type and is driven by a150-hp induction motor. The ac power is distributed to the rod control power cabinets through thetwo series connected reactor trip breakers.The variable speed rod control system rod drive programmer affords the ability to insertsmall amounts of reactivity at low speed to accomplish fine control of reactor coolant averagetemperature about a small temperature deadband, as well as furnishing control at high speed. Asummary of the rod cluster control assembly sequencing characteristics is given below.1.Two groups within the same bank are stepped such that the relative position of the groupswill not differ by more than one step.2.The control banks are programmed such that the withdrawal of the banks is sequenced in thefollowing order: control bankA, control bankB, control bankC, and control bankD. Theprogrammed insertion sequence is the opposite of the withdrawal sequence, that is, the lastcontrol bank withdrawn (bankD) is the first control bank inserted.3.The control bank withdrawals are programmed such that when the first bank reaches a presetposition, the second bank begins to move out simultaneously with the first bank. When thefirst bank reaches the top of the core, it stops, while the second bank continues to movetoward its fully withdrawn position. When the second bank reaches a preset position, thethird bank begins to move out, and so on. This withdrawal sequence continues until the unitreaches the desired power. The control bank insertion sequence is the opposite.4.Overlap between successive control banks is adjustable between 0% to 50% (0 and115steps), with an accuracy of +/-1step.5.Rod speeds for the control banks are capable of being controlled between a minimum of8steps/minute and a maximum of 72steps/minute.

Revision 52-09/29/2016NAPS UFSAR7.7-57.7.1.3Plant Control Signals for Monitoring and Indicating7.7.1.3.1Monitoring Functions Provided by the Nuclear Instrumentation SystemThe nuclear instrumentation system is described in Reference1.The power range channels are important because of their use in monitoring powerdistribution in the core within specified safe limits. They are used to measure reactor power level,axial power imbalance, and radial power imbalance. These channels are capable of recordingoverpower excursions up to 200% of full power. Suitable alarms are derived from these signals, asdescribed below.Basic power range signals are as follows:1.Total current from a power range detector (four such signals from separate detectors); thesedetectors are vertical and have an active length of 10feet.2.Current from the upper half of each power range detector (four such signals).3.Current from the lower half of each power range detector (four such signals).Derived from these basic signals are the following (including standard signal processing forcalibration):1.Indicated nuclear flux (four such).2.Indicated axial flux imbalance, derived from upper-half flux minus lower-half flux (foursuch).Alarm functions derived are as follows:1.Deviation (maximum minus minimum of four) in indicated nuclear power.2.Upper radial tilt (maximum to average of four) on upper-half currents.3.Lower radial tilt (maximum to average of four) on lower-half currents.Nuclear power and axial imbalance is selectable for recording as well. Indicators areprovided on the control board for nuclear power and for axial power imbalance.7.7.1.3.2Rod Position Monitoring of Control RodsThe following separate systems are provided to sense and display control rod position:1.Analog system-An analog signal is produced for each rod cluster control assembly by alinear variable transformer.Direct continuous readout of every rod cluster control assembly position is presented to theoperator by individual meter indications, without the need for operator selection or switchingto determine rod position. A rod bottom (rod drop) alarm is provided.

Revision 52-09/29/2016NAPS UFSAR7.7-62.Demand position system-The demand position system counts pulses generated in the roddrive control system to provide a digital readout of the demanded bank position.The demand position and analog rod position indication systems are separate systems; eachserves as backup for the other. Comparison by the reactor operator of the demand reading fromthe digital readout and the analog (actual) reading from the meter indications verifies properoperation of the rod control system. If doubt remains about the rod alignment, an incore map maybe made as described in Section7.7.1.9.3.The rod position monitoring system is described in detail in Reference2.7.7.1.3.3Control Bank Rod Insertion MonitoringWhen the reactor is critical, the normal indication of reactivity status in the core is theposition of the control bank in relation to reactor power (as indicated by the reactor coolantsystem loop deltaT) and coolant average temperature. These parameters are used to calculateinsertion limits for the control banks. The following two alarms are provided for each controlbank:1.The "low" alarm alerts the operator of an approach to the rod insertion limits requiring boronaddition by following normal procedures with the Chemical and Volume Control System.2.The "low-low" alarm alerts the operator to take action to add boron to the reactor coolantsystem by any one of several alternative methods.The purpose of the control bank rod insertion monitor is to warn the operator of excessiverod insertion. The insertion limit maintains sufficient core reactivity shutdown margin followingreactor trip; provides a limit on the maximum inserted rod worth in the unlikely event of ahypothetical rod ejection; and limits rod insertion such that acceptable nuclear peaking factors aremaintained. Since the amount of shutdown reactivity required for the design shutdown margin following a reactor trip increases with increasing power, the allowable rod insertion limits must bedecreased (the rods must be withdrawn further) with increasing power. Two parameters that areproportional to power are used as inputs to the insertion monitor. These are the deltaT betweenthe hot leg and the cold leg, which is a direct function of reactor power, and Tavg which isprogrammed as a function of power. The rod insertion monitor uses parameters for each controlrod bank as follows:ZLL = A(T) + B (Tavg) + C(7.2-1)where:ZLL = maximum permissible insertion limit for affected control bank(T) = median/high select T of all loops(Tavg) = median/high select Tavg of all loops Revision 52-09/29/2016NAPS UFSAR7.7-7B = 0, A and C are maintained and revised by Engineering in the Core Operating Limits Report for BanksC andD.The control rod bank demand position (Z) is compared to ZLL as follows:If Z - ZLL D, a low alarm is actuated.If Z - ZLL E, a low-low alarm is actuated.Since the highest values of Tavg and deltaT are chosen by the median/Hi select feature inthe event of a failure in a temperature channel, a conservatively high representation of power isused in the insertion limit calculations.The actuation of the low alarm alerts the operator of an approach to reduced shutdownreactivity. Administrative procedures require the operator to add boron through the Chemical andVolume Control System. The actuation of the low-low insertion limit alarm alerts the operator toinitiate boration to restore shutdown margin in accordance with the plant procedures. The value of"E" is chosen so that the low-low alarm would normally be actuated before the insertion limit isreached. The value of "D" is chosen to allow the operator to follow normal boration procedures.Figure7.7-3 shows a block diagram representation of the control rod bank insertion monitor. Themonitor is shown in more detail on the functional diagrams shown in Figure7.7-2. In addition tothe rod insertion monitor for the control banks, an alarm system is provided to warn the operator ifany shutdown rod cluster control assembly leaves the fully withdrawn position.Rod insertion limits are established by the following:1.Establishing the allowed rod reactivity insertion at full power consistent with the purposesgiven above.2.Establishing the differential reactivity worth of the control rods when moved in normalsequence.3.Establishing the change in reactivity with power level by relating power level to rod position.4.Linearizing the resultant limit curve. All key nuclear parameters in this procedure aremeasured as part of the initial and periodic physics testing program.Any unexpected change in the position of the control bank under automatic control, or achange in coolant temperature under manual control, provides a direct and immediate indicationof a change in the reactivity status of the reactor. In addition, samples are taken periodically ofcoolant boron concentration. Variations in concentration during core life provide an additionalcheck on the reactivity status of the reactor, including core depletion.7.7.1.3.4Rod Deviation AlarmThe demanded and measured rod position signals are displayed on the control board. Theyare also monitored by the plant computer, which provides a visual printout and an audible alarm Revision 52-09/29/2016NAPS UFSAR7.7-8whenever an individual rod position signal deviates from the other rods in the bank by a presetlimit. The alarm can be set with appropriate allowance for instrument error and within sufficientlynarrow limits to preclude exceeding core design hot-channel factors.Figure7.7-4 is a block diagram of the rod deviation comparator and alarm system.7.7.1.3.5Rod Bottom AlarmA rod bottom signal for the control rods bistable in the analog rod position system asdescribed in Reference2 is used to operate a control relay, which generates the ROD BOTTOMROD DROP alarm.7.7.1.4Plant Control System InterlocksThe listing of the plant control system interlocks, along with the description of theirderivations and functions, is presented in Table7.7-1. It is noted that the designation numbers forthese interlocks are preceded by "C." The development of these logic functions is shown in thefunctional diagrams: C-1 (Figures7.2-3 &7.2-10); C-2 (Figure7.2-10); C-3 (Figures7.2-5&7.2-8); C-4 (Figures7.2-5 &7.2-8); C-5 (Figures7.2-8 &7.7-2); C-7 (Figure7.7-5); C-8(Figures7.2-8 &7.7-5); C-9 (Figure7.7-5); C-11 (Figure7.7-2); and C-20 (Figure7.2-13).7.7.1.4.1Rod StopsRod stops are provided to prevent abnormal power conditions that could result fromexcessive control rod withdrawal initiated by either a control system malfunction or operatorviolation of administrative procedures.Rod stops are the C1, C2, C3, C4, andC5 control interlocks identified in Table7.7-1. TheC3rod stop, derived from overtemperature deltaT, and the C4rod stop, derived from overpowerdelta T, are also used for turbine runback, which is discussed below.7.7.1.4.2Automatic Turbine Load RunbackAutomatic turbine load runback is initiated by an approach to an over-power orovertemperature condition. This will prevent high-power operation that might lead to anundesirable condition that, if reached, will be protected by reactor trip.Turbine load reference reduction is initiated by either an overtemperature or overpowerdelta T signal. Two-out-of-three coincidence logic is used.A rod stop and turbine runback are initiated when:T > Trod stop & turbine runbackfor both the overtemperature and the overpower condition.

Revision 52-09/29/2016NAPS UFSAR7.7-9For either condition in general:Trod stop & turbine runback = Tsetpoint - Bp(7.2-2)where:Bp = a setpoint biaswhere deltaT setpoint refers to the overtemperature deltaT reactor trip value and theoverpower deltaT reactor trip value for the two conditions.The turbine runback is continued until deltaT is equal to or less than deltaTrodstop&turbinerunback. This function serves to maintain an essentially constant margin to trip.7.7.1.5Pressurizer Pressure ControlThe reactor coolant system pressure is controlled by using the heaters (in the water region)and the spray (in the steam region) of the pressurizer, plus steam relief for large positive pressuretransients. Pressurizer pressure from one of the control system transmitters is used in conjunctionwith a reference pressure to develop a demand signal for a three mode controller providing forpressurizer proportional heater control, pressurizer backup heater control, spray valve control, andcontrol of one of two PORVs.Steam condensed by the spray reduces the pressurizer pressure. A small continuous spray isnormally maintained to reduce thermal stresses and thermal shock and to help maintain uniformwater chemistry and temperature in the pressurizer. The spray nozzle is located on the top of thepressurizer. Spray is initiated when the pressure controller spray demand signal is above a givensetpoint. The spray rate increases proportionally with increasing spray demand signal until itreaches a maximum value.Pressure is raised by adding heat to the pressurizer via the pressurizer heaters. The electricalimmersion heaters are located near the bottom of the pressurizer. A portion of the heater group isproportionally controlled to correct small pressure variations. These variations are due to heatlosses, including heat losses from a small continuous spray. The remaining (backup) heaters areturned on when the pressurizer pressure controlled signal demands approximately 100%proportional heater power.Two pressurizer power-operated relief valves limit system pressure for large positivepressure transients. During the low temperature solid water phase of reactor coolant systempressurization both PORVs are controlled by separate wide-range pressure transmitters and anauctioneered-low temperature signal from the wide-range reactor coolant system cold legtemperature devices. The PORVs will actuate if undesirable combinations of temperature andpressure develop. During power operations, one PORV is controlled by a pressurizer pressuretransmitter and associated master controller. Actuation of this PORV is dependent on the mastercontroller pressure setpoint and the length of time that pressurizer pressure is above the setpoint.

Revision 52-09/29/2016NAPS UFSAR7.7-10The second PORV is controlled, during power operations, from a separate pressurizer pressuretransmitter and will actuate on a high-pressure signal.A block diagram of the pressurizer pressure control system is shown in Figure7.7-9.7.7.1.6Pressurizer Water-Level ControlThe pressurizer operates by maintaining a steam cushion over the reactor coolant. As thedensity of the reactor coolant changes due to reactor coolant temperature, the steam-waterinterface moves to absorb the variations with relatively small pressure disturbances.The water inventory in the reactor coolant system is maintained by the Chemical andVolume Control System. During normal plant operation, the charging flow varies to produce theflow demanded by the pressurizer water-level controller. The pressurizer water level isprogrammed as a function of coolant average temperature, with the median temperature of thethree loops average temperatures used for control. The pressurizer water level decreases as theload is reduced from full load. This is a result of coolant contraction following programmedcoolant temperature reduction from full power to low power. The programmed level is designedto match as nearly as possible the level changes resulting from the coolant temperature changes.Manual control of pressurizer water level is available at all times.A block diagram of the pressurizer water level control system is shown in Figure7.7-10.7.7.1.7Steam Generator Water-Level ControlEach steam generator is equipped with a three-element feedwater flow control system thatmaintains a programmed water level as a function of turbine load. The three-element feedwatercontroller regulates the feedwater valve by continuously comparing the feedwater flow signal, thewater-level signal, the programmed level, and the pressure-compensated steam flow signal.Continued delivery of feedwater to the steam generators is required as a sink for the heat storedand generated in the reactor following a reactor trip and turbine trip. An override signal closes thefeedwater valves when the average coolant temperature is below a given temperature and thereactor has tripped. Manual control of the feedwater control system is available at all times.A block diagram of the steam generator water-level control system is shown inFigure7.7-11.7.7.1.8Steam Dump ControlThe steam dump system is designed to accept a 40% loss of net load without tripping thereactor.The automatic steam dump system is able to accommodate this abnormal load rejection andto reduce the effects of the transient imposed on the reactor coolant system. By bypassing themain steam directly to the condenser, an artificial load is maintained on the primary system. The Revision 52-09/29/2016NAPS UFSAR7.7-11rod control system can then reduce the reactor temperature to a new equilibrium value withoutcausing overtemperature and/or overpressure conditions. The NorthAnna plant was designed torelieve the heat equivalent to 50% of the rated load at the time of initial licensing (40% by thesteam dump system and 10% by the control rods). For the measurement uncertainty recapture(MUR) power uprate, the steam dump capacity was reviewed for a bounding NSSS power of2968MWt. It was determined that the steam dump capacity could be as low as 34.7% of thesteam flow rate corresponding to 2968 MWt NSSS power. Since this result was less than the 40%design criterion, the NSSS control system margin-to-trip analyses was reviewed. It wasdetermined that there was acceptable margin to all relevant reactor trip setpoints for a 50% loadrejection from 2968 MWt NSSS power.If the difference between the reference Tavg (Tref) based on turbine impulse chamberpressure and the lead/lag compensated median Tavg exceeds a predetermined amount and theinterlock mentioned below is satisfied, a demand signal will actuate the steam dump to maintainthe reactor coolant system temperature within control range until a new equilibrium condition isreached.To prevent the actuation of steam dump on small-load perturbations, an independent loadrejection sensing circuit is provided. This circuit senses the rate of decrease in the turbine load asdetected by the turbine impulse chamber pressure. It is provided to unblock the dump valves whenthe rate of load rejection exceeds a preset value corresponding to a 10% step-load decrease or asustained ramp-load decrease of 5% per minute.A block diagram of the steam dump control system is shown in Figure7.7-12.7.7.1.8.1Load Rejection Steam Dump ControllerThis circuit prevents a large increase in reactor coolant temperature following a large,sudden load decrease. The error signal is a difference between the lead/lag compensated medianTavg and the reference Tavg based on turbine impulse chamber pressure.The Tavg signal is the same as that used in the reactor coolant system. The lead/lagcompensation for the Tavg signal is to compensate for lags in the plant thermal response and invalve positioning. Following a sudden load decrease, Tref is immediately decreased and Tavg tendsto increase, thus generating an immediate demand signal for steam dump. Since control rods areavailable in this situation, steam dump terminates as the error comes within the maneuveringcapability of the control rods.7.7.1.8.2Turbine Trip Steam Dump ControllerFollowing a turbine trip, as monitored by the turbine trip signal, the load rejection steamdump controller is defeated and the turbine trip steam dump controller becomes active. Sincecontrol rods are not available in this situation, the demand signal is the error signal between thelead/lag compensated median Tavg and the no-load reference Tavg. When the error signal exceeds Revision 52-09/29/2016NAPS UFSAR7.7-12a predetermined setpoint, the dump valves are tripped open in a prescribed sequence. As the errorsignal reduces in magnitude, indicating that the reactor coolant system Tavg is being reducedtoward the reference no-load value, the dump valves are modulated by the plant trip controller toregulate the rate of decay heat removal and thus gradually establish the equilibrium hot-shutdowncondition.The error signal determines whether a group of valves is to be tripped open or modulatedopen. In either case, they are modulated when the error is below the trip-open setpoints.7.7.1.8.3Steam Header Pressure ControllerThe main steam header pressure is maintained by the steam generator pressure controller(manually selected) that controls the amount of steam flow to the condensers. This controlleroperates the steam dump valves to the condensers. The controller can automatically control thesteam dump valves to maintain the desired steam header pressure, or the dump valves can bemanually controlled in this mode.7.7.1.9Incore InstrumentationThe incore instrumentation system consists of Chromel-Alumel thermocouples at fixed coreoutlet positions and movable miniature neutron detectors that can be positioned at the center ofselected fuel assemblies, anywhere along the length of the fuel assembly vertical axis. The basicsystem for the insertion of these detectors is shown in Figure7.7-13. Sections1 and2 ofReference3 outline the incore instrumentation system in more detail.

7.7.1.9.1ThermocouplesThe 51 Chromel-Alumel thermocouples are threaded into guide tubes that penetrate thereactor vessel head through seal assemblies and terminate at the exit flow end of the fuelassemblies. The thermocouples are provided with a compression seal from conduit to head. Thethermocouples are supported in guide tubes in the upper core support assembly.7.7.1.9.2Movable Neutron Flux Detector Drive SystemMiniature fission chamber detectors can be remotely positioned in retractable guidethimbles to provide flux mapping of the core. See Reference3 for neutron flux detectorparameters. The stainless steel detector shell is welded to the leading end of helical wrap drivecable and to stainless-steel-sheathed coaxial cable. The retractable thimbles, into which theminiature detectors are driven, are pushed into the reactor core through conduits that extend fromthe bottom of the reactor vessel down through the concrete shield area and then up to a thimbleseal table.The thimbles are closed at the leading ends, are dry inside, and serve as the pressure barrierbetween the reactor water pressure and the atmosphere. Mechanical seals between the retractablethimbles and the conduits are provided at the seal line. During reactor operation, the retractable Revision 52-09/29/2016NAPS UFSAR7.7-13thimbles are stationary. They are extracted downward from the core during refueling to avoidinterference within the core. A space above the seal table is provided for the retraction operation.The drive system for the insertion of the miniature detectors consists basically of driveassemblies, 5-path rotary transfer operation selector assemblies, and 10-path rotary transferselector assemblies, as shown in Figure7.7-13. These assemblies are described in Reference3.The drive system pushes hollow helical wrap drive cables into the core with the miniaturedetectors attached to the leading ends of the cables and small-diameter sheathed coaxial cablesthreaded through the hollow centers back to the ends of the drive cables. Each drive assemblyconsists of a gear motor that pushes a helical wrap drive cable and a detector through a selectivethimble path by means of a special drive box and includes a storage device that accommodates thetotal drive cable length.The leakage detection and gas purge provisions are discussed in Reference3.Manual isolation valves (one for each thimble) are provided for closing the thimbles. Whenclosed, the valve forms a 2500-psig barrier. The manual isolation valves are not designed toisolate a thimble while a detector/drive cable is inserted into the thimble. The detector/drive cablemust be retracted to a position above the isolation valve before closing the valve.A small leak would probably not prevent access to the isolation valves; thus, a leakingthimble could be isolated during a hot shutdown. A large leak might require cold shutdown foraccess to the isolation valve.7.7.1.9.3Control and Readout DescriptionThe control and readout system provides means for inserting the miniature neutrondetectors into the reactor core and withdrawing the detectors while plotting neutron flux versusdetector position. The control system consists of two sections, one physically mounted with thedrive units, the other contained in the control room. Limit switches in each transfer device providefeedback of path selection operation. Each gearbox drives an encoder for position feedback. Onefive-path operation selector is provided for each drive unit to insert the detector in one of fivefunctional modes of operation. A common path is provided to permit cross-calibration of thedetectors.A 10-path rotary transfer assembly is a transfer device that is used to route a detector intoany one of up to 10selectable paths.The control room contains the necessary equipment for control, position indication, andflux recording for each detector. Additional panels are provided for such features as drive motorcontrols, core path selector switches, plotting, and gain controls.A "flux-mapping" consists, briefly, of selecting (by panel switches) flux thimbles in givenfuel assemblies at various core quadrant locations. The detectors are driven to the top of the coreand stopped automatically. An x-y plot (position versus flux level) is initiated with the slow Revision 52-09/29/2016NAPS UFSAR7.7-14withdrawal of the detectors through the core from the top to a point below the bottom. In a similarmanner, other core locations are selected and plotted. Each detector provides axial fluxdistribution data along the center of a fuel assembly. Various radial positions of detectors are thencompared to obtain a flux map for a region of the core.The thimbles are distributed nearly uniformly over the core with approximately the samenumber of thimbles in each quadrant. The number and location of these thimbles have beenchosen to permit the measurement of local to average peaking factors to an accuracy of +/-5%(95% confidence). Measured nuclear peaking factors will be increased by 5% to allow for thisaccuracy. If the measured power peaking is larger than acceptable, reduced power required byTechnical Specifications.Operating plant experience has demonstrated the adequacy of the incore instrumentation inmeeting the design bases stated.7.7.1.10Computer SystemA plant computer system (PCS) is provided with each unit to assist the operator in theefficient operation of the plant. The computer's primary function is to provide the operator withadditional information as to the condition of the nuclear steam supply system. It also has thecapability to monitor inputs from the balance of plant systems and to alarm and log variousoff-normal conditions. There is no direct reactor control or protection action taken by thecomputer; therefore, the safety of the plant operation is not impaired by its loss.In addition to the above operator support functions, the PCS also serves as the station'sEmergency Response Facility Computer System, fulfilling the requirements of NUREG-0737,Supplement1 and the guidance of NUREG-0696.The following operator support and emergency response functions are performed by thePCS:Operator SupportThe PCS obtains data by scanning analog and digital sensors and processes this data toprovide the operator with graphic displays, and indications, trends and logs of plant parametersand equipment status. It provides alarms for various off-normal conditions. It is also used forpost-trip reviews, sequence of events recording, sensor calibration, and converting values intoengineering units. Also included are reactor control and protection system supervision. Under thisfunction are control rod cluster position deviation and deviation in redundant measurementsmonitoring. There are also calculations made under the nuclear steam supply system processsupervision function. These calculations include reactor dynamic thermal output, steam generatortotal thermal output, unit net efficiency, RCS leak rate, and onsite incore data collection.Calculations performed by the PCS may be modified or added to the system from time to time Revision 52-09/29/2016NAPS UFSAR7.7-15under the control of an administrative procedure as operational and regulatory requirementschange.Emergency ResponseThe PCS host computer receives plant sensor inputs via the Validyne multiplexing systemand processes this data for use in Emergency Response related indication, alarm, trending,recording, and display functions. Users of the system access this information from personalcomputer workstations that communicate with the host over the station's local area network andthe Corporate wide area network. Workstations dedicated to Emergency Response functions arelocated in the station's Main Control Room (MCR), Technical Support Center (TSC) and LocalEmergency Operations Facility (LEOF) and off-site in the Corporate Emergency OperationsFacility (CEOF) and Corporate Emergency Response Center (CERC). The PCS supports thefollowing functions related to Emergency Response:*SPDS (Safety Parameter Display System)*NRC ERDS (Emergency Response Data System)*MIDAS (Meteorological Information Dose Assessment System)

• Monitoring of certain Regulatory Guide1.97 variables7.7.1.11Process InstrumentationMuch of the process instrumentation that has been provided is described in Section7.2, andSection7.3. The remaining portion of the process instrumentation that is not safety-related isshown on the system flow diagrams included in the appropriate sections of this report. Systemflow diagrams serve as piping and instrumentation diagrams (P&IDs) and illustrate the operationsand processes of the various auxiliary systems. The instrument application portion of eachauxiliary system section describes the process instrumentation provided for monitoring andautomatically controlling that system.The Westinghouse test program, designed to demonstrate that adequate physical separationexists between safety-related and non-safety-related portions of the 7300Series process analogsystem, is described in Reference4. The tests conclusively demonstrate that automatic actuationof the safety systems is ensured even if called on to function at a time when severe abnormalelectrical conditions existed on system cabling in the balance of plant.The lead/lag amplifier cards have been retrofitted to improve performance. Thismodification was to prevent the perturbation of the card output due to a step change in the powersupply voltage.7.7.1.12Control StationsThe control room, located in the service building, contains all controls and instrumentationnecessary to start up, operate, or shut down both units. All pertinent interrelated information Revision 52-09/29/2016NAPS UFSAR7.7-16required for the safe and reliable operation of the plant, including periods of transient and accidentconditions, is presented there. If this area becomes inaccessible, the reactors can be brought to andmaintained in a hot-shutdown condition at the auxiliary shutdown control panels located in therelay rooms below the main control room. The control room is shown in Figure1.2-3 andReference Drawing1.7.7.1.12.1Design BasisThe main control room contains controls and instrumentation necessary for monitoring theoperation of the reactors and turbine generators under normal and accident conditions.Continuous surveillance under all operating conditions and the postulated design basis accident(DBA) conditions is provided by licensed operators.The main control room has four independent communication systems. One system consistsof standard commercial telephones (PBX system) using leased lines. These telephones andseveral outside trunk lines service the station for outside calls. This system may or may not beavailable under emergency conditions. A second system, a communication and voice pagingsystem, is provided that interconnects the entire station and is supplied from the vital powersystem. In order to ensure that portable radios can be used following a fire in any area of the plant, an additional emergency communications system has been installed. This additional system islocated in separate fire areas from the existing system and consists of repeaters, handsets,antennas, hand held radios, and associated equipment. The fourth system is sound powered, withtelephone jacks and interconnecting wires at each major control point for test and maintenancepurposes. Sound-powered telephones are installed at various stations throughout the plant. Thissystem is accessible so that roving operators or service personnel may have easy communication with the main control room or one another. The sound-powered communication system does notrely on any power source, so it is available at all times. The communication systems are describedin detail in Section9.5.2.Sufficient shielding, distance, and structural integrity are provided to ensure that controlroom personnel shall not be subjected to doses that in the aggregate would exceed suggestedlimits in 10CFR50 AppendixA, GDC19 as revised for AST. All equipment in this area has beendesigned to minimize the possibility of a condition that could lead to inaccessibility or evacuation.A supplemental supply of breathing-quality air is available for the main control room fromhigh-pressure air cylinders. Within an hour after MCR/ESGR envelope isolation, an emergencyventilation system with high-efficiency particulate air (HEPA)/charcoal filters is manually alignedto supply breathing air indefinitely.The auxiliary shutdown control panels, also highly protected, are designed with a minimumof simple control actions required to bring and maintain the reactor in a hot-shutdown condition.See Section7.4 for details of the auxiliary shutdown control panels.

Revision 52-09/29/2016NAPS UFSAR7.7-177.7.1.12.2Design DescriptionThe primary objectives of the main control room layout are to provide the necessarycontrols to start, operate, and shut down each unit with sufficient information display and alarmindication to ensure safe and reliable operation under normal and accident conditions. Specialemphasis is given to maintaining control integrity during accident conditions.The equipment in the main control room is arranged with consideration given to the factthat certain systems normally require more operator attention than do others. The main controlboard is the central item in the main control room. The control board for Unit1 is completelyindependent of the control board for Unit2. Completely separate systems, circuits, instruments,power supplies, cabling panels, racks, and control boards are provided for Unit2, except forcertain shared auxiliary systems.The design criteria for maintaining separation and independence of the systems associatedwith Unit1 from those of Unit2 in the main control room are the observance of a minimumphysical separation of 4ft. 0in. for the independent systems. The shared systems are consideredas part of Unit1 and the following criteria apply:1.The design criteria for maintaining separation and independence of all safety-relatedredundant systems, instruments, power supplies, and cabling that share a common panel orcontrol board are to provide a spacing of 12inches or a physical barrier between theredundant components. Studies of the main control room and control boards were made toarrive at the optimum arrangement for the operation of the station while meeting the criteriafor separation.2.All redundant systems located in separate panels, racks, or control boards in the control areaare separated by either a space of 12inches between redundant components or physicalbarriers.Each control board has a bench section and a vertical section located behind the benchsection. Most of the essential instruments and controls for power operation, and protectiveequipment which is immediately needed in cases of emergency, are either mounted on the benchconsole or vertical sections in functional groupings. Recorders and indicators are mounted on thevertical back panels in agreement, wherever appropriate, with the functional groupings of thebench sections. The engineered safeguards section of the control board is designed to minimizethe time required for the operator to evaluate the system performance under accident conditions.Auxiliary vertical panels are provided in the main control room where their use simplifiesthe control of certain auxiliary systems or for systems that require less frequent operator attentionsuch as turbine supervisory, radiation monitoring, and liquid and gaseous waste disposal.Illuminated window and audible alarm units are incorporated into the control room to warnthe operator if abnormal conditions are approached by any system. Independent annunciatorsystems for each unit have their own identifying alarm horn tones. Indications and alarms are also Revision 52-09/29/2016NAPS UFSAR7.7-18provided so that the control room operator is made aware of any deviation from normal conditionsat remote control stations. Many of these conditions are also alarmed by the unitperformance-and-alarm monitoring system. Audible alarms are initiated automatically by theradiation monitoring system on high-radiation levels. Audible alarms also sound in appropriateareas through the station if high-radiation conditions are present.Design specifications for the equipment in the main control room specify no loss ofprotective function over the temperature range from 40°F to 120°F. Thus, there is a wide marginbetween design limits and the normal operating environment for control room equipment. If onlyone of the four control room cooling units remains operable, the common control roomtemperature will level off under 90°F. The electronic equipment was tested at the factory for thedesign temperature range of 40°F to 110°F. Qualification testing has demonstrated that theinstrumentation remains operable to 120°F, as there is a possible calibration shift above this range.The 120°F limit establishes the maximum temperature at which plant shutdown is required. Asthe control room latent heat is negligible, humidity is not a factor. A double failure (bothconditioning systems failing concurrently) is required to jeopardize the temperature control. Inthis very unlikely event, the control room would reach 120°F in about 45 minutes, which wouldstill provide sufficient time to shut down the reactor. Onsite testing proved the installedperformance of the air conditioning systems.Qualification testing has been performed on various safety systems such as processinstrumentation, nuclear instrumentation, and relay racks. This testing involved demonstrating theoperation of safety functions at elevated ambient temperatures to 120°F for control roomequipment and in full postaccident environment for required equipment in the containment.Detailed results of some of these tests are proprietary to the supplier, but are on file at thesupplier and available for audit by qualified parties.A reliable source of electrical power, described in Section8.3, is provided to ensurecontinual operation of vital unit and station instrumentation. Emergency lighting is also provided.7.7.1.13Control Room AvailabilityThe main control room is designed to be available at all times. Safe occupancy of the maincontrol room during an abnormal condition is provided for in the design of the service building.Two carbon dioxide monitors have been installed to verify carbon dioxide levels in the controlrooms are at accepted habitability limits. One monitor is installed in Unit1 control room and oneis installed in Unit2 control room. Adequate shielding and air conditioning are used to maintaintolerable radiation and air temperature levels in the main control room. Ventilation consists oftotally contained redundant recirculating air conditioning systems designed to continue operationunder all normal and emergency conditions. Fresh air intake and exhaust for normal use are fromother independent systems, which are isolated as required. Outside air is automatically isolatedupon an SI signal. Makeup air, under emergency conditions, is immediately available from a Revision 52-09/29/2016NAPS UFSAR7.7-19compressed breathing-air bank and, on exhaustion, from emergency ventilating units supplyingair through HEPA and charcoal filters to remove particulates and iodine, respectively. With alloutside air makeup shut off, the quality of the air will be maintained with the compressed air bankor the filtered emergency ventilation with an emergency ventilation fan/filter operating inrecirculation.Incorporated in the control room design are provisions to limit the possibility and potentialmagnitude of a fire.If a fire should occur in the main control room, it is expected to be only minor in magnitudeso that it could be readily extinguished by underfloor gas flooding or a hand fire extinguisher.Smoke and vapors can be removed by the ventilation system during normal operations. If ventingis undesirable in any emergency, breathing apparatus is available for use. The main control roomand auxiliary shutdown control panels are protected from outside fire, smoke, or airborneradioactivity by sealed penetrations, weather-stripped doors, absence of windows, and by thepositive air pressure maintained in the area during normal and emergency operations.7.7.1.13.1Auxiliary Shutdown Control PanelsThe probability of the main control room becoming inaccessible as a result of fire or othercauses is considered extremely small. However, if the operator must leave the main control room,operating procedures require that he trip the reactors and turbine generators before leaving, so asto bring the station automatically to the no-load condition, thus ensuring control at the auxiliaryshutdown control panels. Each reactor unit can be brought to and maintained in a hot-shutdowncondition from the auxiliary shutdown control panels, which are provided with the followingcontrol provisions:1.Removal of core residual heat.2.Boration of the reactor coolant system.3.Maintenance of pressurizer level and pressure.These functions require the operation of auxiliary feedwater pumps, charging pumps, andboric acid transfer pumps. Appropriate process instrumentation such as pressurizer pressure andlevel and steam generator pressure and level are provided on the auxiliary shutdown controlpanels. The auxiliary shutdown control panel instrumentation measurement range is shown inTable7.7-2. This equipment is sufficient to safely maintain the unit or units for an extendedperiod of time in a hot-standby condition.Each auxiliary shutdown control panel has the following equipment:1.No.2 auxiliary feedwater pump turbine steam supply valve control switches.2.No.3A auxiliary feedwater pump motor start-stop control switch.3.No.3B auxiliary feedwater pump motor start-stop control switch.

Revision 52-09/29/2016NAPS UFSAR7.7-204.Pneumatic hand-control valves-auxiliary feed pump discharge open-close control stations(Reference3).5.Steam generator water-level indicators.6.No.1A charging pump motor start-stop control switch.

7.No.1B charging pump motor start-stop control switch.

8.No.1C charging pump motor start-stop control switch.9.Nos.2A and2B boric acid pump motor start-stop control switches (Unit1).10.Nos.2C and2D boric acid pump motor start-stop control switches (Unit2).11.Motor-operated valves-auxiliary feedwater pump discharge open-close control switch(Reference4).12.Transfer switches for all the above valve and pump motors.13.Status lights for all the above pump motors and valve positions.14.Charging flow indicator.15.Tavg indicator for each loop.16.Condensate storage tank level indicator.17.Pressurizer pressure indicators.18.Pressurizer level indicators.

19.Pressurizer heater control switch.20.Sound-powered telephone between auxiliary shutdown control panels and all areas,including the following:a.Switchgear room.b.Emergency switchgear room.c.Auxiliary building at the Emergency boration line motor-operated valve.d.Auxiliary feedwater pumphouse21.Power relief valves (PCV-MS101-A, B, C) (3) hand-indicating control station with transfercapability.22.Indication of pressure difference between the turbine building and the relay room.23.Charging flow manual station.

24.Controls for letdown isolation valves.

25.Steam pressure for each steam generator.

Revision 52-09/29/2016NAPS UFSAR7.7-2126.Auxiliary feedwater pump discharge pressure.27.Relay room emergency ventilation for control and damper position indication.7.7.1.13.2Auxiliary Monitoring PanelsTwo additional monitoring panels have been added in the fuel building. These provideinstrumentation to be used in conjunction with the auxiliary shutdown control panel to safely shutdown the reactor in accordance with 10CFR50 AppendixR (Section9.5.1).Auxiliary monitoring panel 2-EI-CB-97A supplies Unit1 and2 indication of the followingparameters:*Pressurizer level*Pressurizer pressure*Reactor coolant system hot leg temperatureThis panel can be powered from either the Unit1 or the Unit2 emergency power system.Auxiliary monitoring panel 1-EI-CB-203 supplies Unit1 and2 indication of the followingparameters:*Steam generator wide range level*Reactor coolant system cold leg temperature*Wide and source range excore neutron fluxRedundant steam generator wide range level and reactor coolant cold leg temperatureindicators are supplied to provide greater system reliability.Power for the steam generator wide range level and the reactor coolant system cold legtemperature instrumentation for Unit1 is supplied by the Unit2 emergency power system.Conversely, the steam generator wide range level and the reactor coolant system cold legtemperature instrumentation for Unit2 is supplied by the Unit1 emergency power system. Thiswas done to ensure that power will be available to the instrumentation of the affected unitfollowing a fire in that units emergency switchgear room, cable tunnel, or cable vault.The Unit1 excore neutron flux monitor system is normally supplied from the Unit1emergency power system. A transfer switch on the Unit2 emergency switchgear room isolationpanel is used to transfer power for one train of the system from the Unit1 to the Unit2 emergencypower system. The Unit2 excore neutron flux monitor system is powered in a similar manner.7.7.1.13.3Pump Operation at Emergency SwitchgearThe provisions of 10CFR50 AppendixR on alternative and dedicated shutdown capabilityinclude requirements for achieving cold shutdown conditions within 72hours. In order to reachcold shutdown one pump from the service water system, one pump from the component cooling Revision 52-09/29/2016NAPS UFSAR7.7-22water system, and one pump from the residual heat removal system are required for each reactorunit in operation. These pumps are normally controlled from the control room.In the event of a control room evacuation the capability to isolate damaged control circuitsand to operate the pumps in these systems from the emergency switchgear room has beenincorporated by the installation of a transfer switch and a control switch on each pumps breakercompartment at the switchgear.7.7.1.13.4System EvaluationThe main control room is designed to provide the operator with the controls, indication, andalarms necessary to control the station during normal or abnormal conditions.7.7.1.14Anticipated Transient Without Scram (ATWS) Mitigation System DescriptionThe ATWS Mitigation System (AMSAC) is a diverse control system which initiates turbinetrip and auxiliary feedwater system flow upon detection of an ATWS type event. An ATWS eventis described as a postulated operational occurrence or a transient such as a loss of feedwater, lossof condenser vacuum, or other design-basis event coincident with a failure of the reactorprotection system to shut down or scram the reactor. The AMSAC is diverse from the reactorprotection system from field sensor output to, but not including, the actuation devices, except forthe reactor trip via the motor generator set input breakers which is a diverse actuation device.The AMSAC initiates a reactor trip, turbine trip, and auxiliary feedwater flow (pumps start)upon detection of steam generator level less than its setpoint on any two out of three levelchannels on any two out of three steam generators, with turbine load greater than setpoint,permissive C-20 satisfied.The AMSAC generic design specified in Reference5 called for AMSAC to be enabledwhen first stage turbine impulse pressure exceeded 40% (nominal) turbine load. This genericsetpoint applies to all Westinghouse pressurized water reactors (PWR) and is based onrepresentative ATWS analyses which show that below 40% power an ATWS event withoutAMSAC produced only limited reactor coolant system (RCS) voiding. The Virginia PowerAMSAC design specifies a nominal permissive (C-20) setpoint based on the generic setpoint of40% turbine load minus an allowance for channel inaccuracies in the turbine impulse pressurechannels themselves.In some of the Reference5 discussions, turbine load and reactor power are usedinterchangeably. In reality, turbine load, as represented by impulse pressure, and reactor power arenot linearly related and the two values tend to deviate as power and load are reduced. The setpointdevelopment did not specifically address this nonlinearity between turbine impulse pressure andreactor power.As discussed in Reference5 and supporting documents, the power level at which AMSACis required to maintain the peak RCS pressure below the 3200psig faulted stress limit for an Revision 52-09/29/2016NAPS UFSAR7.7-23ATWS has been shown generically to be 70% rated thermal power. At power levels below 40%reactor power, an ATWS with no AMSAC would limit RCS voiding in the first 10minutes tovalues less than those obtained for the full power case with AMSAC.For power levels between 40% and 70%, voiding is not predicted to occur until well afterthe peak RCS pressure is reached. Additional studies of the loss of normal feedwater ATWS eventhave shown that for a C-20 setpoint corresponding to 50% rated thermal power, the voiding thatwould occur without AMSAC was still less than that expected for the full power case withAMSAC (Reference6).Therefore the current NorthAnna AMSAC design meets its design basis, providedAMSAC is armed at 40% turbine load (nominal) or 50% rated thermal power.The steam generator level signals are wired from isolated outputs in the Westinghouse solidstate protection racks. The steam generator level signals are from the narrow range channelsI, II,andIII of each steam generator. The turbine load signals are wired from the redundant turbineimpulse chamber pressure channelsIII andIV.The input signals are wired to three programmable logic controllers (PLC) located in theAMSAC panel. These signals are isolated with class1E qualified devices in the 7300System toprovide signals to the PLCs. One PLC is dedicated to each steam generator. The two turbineimpulse chamber pressure signals are wired to each PLC. The PLCs perform timing, logicfunctions, and provide outputs to the various loads. The outputs to safety-related circuits arewired through safety-related qualified class1E isolation relays. The AMSAC panel is located inthe Instrument Rack Room. The AMSAC panel is powered from the TSC Uninterruptible PowerSupply (UPS), using a new breaker in UPS Distribution SubpanelA.The AMSAC is initiated when the turbine load is greater than setpoint and a complete lossof feedwater is detected. Loss of feedwater is the condition of any two of the three leveltransmitters in any 2 out of 3 steam generators less than or equal to setpoint of narrow range levelspan. The PLCs perform a time delay to allow the existing Reactor Protection System (RPS) torespond first.In the event of an ATWS and the expiration of the time delay, the main turbine will betripped, all three auxiliary feedwater pumps will receive signals to start, the steam generatorblowdown isolation and sample isolation valves will receive automatic close signals, and thebreakers which supply power for each rod control motor-generator set will be provided tripsignals.ATWS mitigation by AMSAC is automatically blocked below the setpoint power bypermissive (C-20) that is derived from the First Stage Pressure (FSP) transmitters. This automaticblock will be defeated for approximately 360seconds following a decrease of FSP below itssetpoint. This time delay will be required for the instance wherein an ATWS event occurs and theturbine load reduces causing FSP to drop. The ATWS mitigating actions, AMSAC, will still be Revision 52-09/29/2016NAPS UFSAR7.7-24initiated automatically if a loss of heat sink (steam generator inventory loss) occurs within the360-second time delay.7.7.2AnalysisThe plant control systems are designed to ensure high reliability in any anticipatedoperational occurrences. Equipment used in these systems is designed and constructed to maintaina high level of reliability.Proper positioning of the control rods is monitored in the control room by bankarrangements of the individual rod position indicators for each rod cluster control assembly. A roddeviation alarm alerts the operator of a deviation of one rod cluster control assembly from theother rods in that bank position. There are also insertion limit monitors with visual and audibleannunciation. A rod bottom alarm signal is provided to the control room for each full-length rodcluster control assembly. Four ex-core long ion chambers also detect asymmetrical fluxdistribution indicative of rod misalignment.Overall reactivity control is achieved by the combination of soluble boron and rod clustercontrol assemblies. Long-term regulation of core reactivity is accomplished by adjusting theconcentration of boric acid in the reactor coolant. Short-term reactivity control for power changesis accomplished by the plant control system that automatically moves rod cluster controlassemblies. This system uses input signals including neutron flux, coolant temperature, andturbine load.The plant control systems will prevent an undesirable condition in the operation of the plantthat, if reached, will be protected by reactor trip. The description and analysis of this protection iscovered in Section7.2. Worst-case failure modes of the plant control systems are postulated in theanalysis of off-design operational transients and accidents covered in Chapter15, such as thefollowing:1.Uncontrolled rod cluster control assembly withdrawal from a subcritical condition.2.Uncontrolled rod cluster control assembly withdrawal at power.3.Rod cluster control assembly misalignment.4.Loss of external electrical load and/or turbine trip.5.Loss of all ac power to the station auxiliaries (station blackout).

6.Excessive heat removal because of feedwater system malfunctions.

7.Excessive load increase.8.Accidental depressurization of the reactor coolant system.These analyses show that a reactor trip setpoint is reached in time to protect the health andsafety of the public under these postulated incidents and that the resulting coolant temperatures Revision 52-09/29/2016NAPS UFSAR7.7-25produce a DNBR well above the DNBR Design Limit. Thus, there will be no cladding damageand no release of fission products to the reactor coolant system under the assumption of thesepostulated worst-case failure modes of the plant control system.7.7.2.1Separation of Protection and Control SystemsIn some cases, it is advantageous to employ control signals derived from individualprotection channels through isolation amplifiers contained in the protection channel. As such, afailure in the control circuitry does not adversely affect the protection channel. Accordingly, thispostulated failure mode meets the requirements of General Design Criterion24 (1971criteria).Test results have shown that a short circuit, open circuit, or the application of 120Vac or 140Vdcon the isolated output portion of the circuit (i.e., the nonprotective side of the circuit) will notaffect the input (protective) side of the circuit.Where a single random failure can cause a control system action that results in a generatingstation condition requiring protective action, and can also prevent proper action of a protectionsystem channel designed to protect against the condition, the remaining redundant protectionchannels are capable of providing the protective action even when degraded by a second randomfailure. This meets the applicable requirements of Section4.7 of IEEE Std279-1971. The pressurizer pressure channels needed to derive the control signals are physicallyisolated from the pressure channels used to derive protection signals.Channels of the nuclear instrumentation that are used in the protective system are combinedto provide nonprotective functions such as signals to indicating or recording devices; the required signals are derived through isolation amplifiers. These isolation amplifiers are designed so thatopen or short-circuit conditions as well as the application of 120Vac or 140Vdc to the isolatedside of the circuit will have no effect on the input or protection side of the circuit. As such,failures on the nonprotective side of the system will not affect the individual protection channels.7.7.2.2Reactivity Control ConsiderationsReactor shutdown with control rods is completely independent of the control functionssince the trip breakers interrupt power to the rod drive mechanisms regardless of existing controlsignals. The design is such that the system can withstand accidental withdrawal of control groupsor unplanned dilution of soluble boron without exceeding acceptable fuel design limits. Thus, thedesign meets the applicable requirements of General Design Criterion25 (1971criteria).No single electrical or mechanical failure in the rod control system could cause theaccidental withdrawal of a single rod cluster control assembly from the partially inserted bank atfull-power operation. The operator could deliberately withdraw a single rod cluster controlassembly in the control bank; this feature is necessary in order to retrieve a rod, should one beaccidentally dropped. In the extremely unlikely event of simultaneous electrical failures thatcould result in single withdrawal, rod deviation would be displayed on the plant annunciator, and Revision 52-09/29/2016NAPS UFSAR7.7-26the rod position indicators would indicate the relative positions of the rods in the bank. Thewithdrawal of a single rod cluster control assembly by operator action, whether deliberate or by acombination of errors, would result in the activation of the same alarm and the same visualindications.Each bank of control and shutdown rods in the system is divided into two groups of fourmechanisms each. The rods comprising a group operate in parallel through multiplexingthyristors. The two groups in a bank move sequentially such that the first group is always withinone step of the second group in the bank. A definite schedule of actuation or deactuation of thestationary gripper, movable gripper, and lift coils of a mechanism is required to withdraw the rodcluster control assembly attached to the mechanism. Since the four stationary gripper, movablegripper, and lift coils associated with the rod cluster control assemblies of a rod group are drivenin parallel, any single failure that could cause rod withdrawal would affect a minimum of onegroup of rod cluster control assemblies. Mechanical failures are in the direction of insertion, orimmobility.The identified multiple failure involving the least number of components consists ofopen-circuit failure of the proper 2 out of 16 wires connected to the gate of the lift coil thyristors.The probability of open-wire (or terminal) failure is 0.016x10-6/hr by MIL-HBD-217A. Thesewire failures would have to be accompanied by the failure or disregard of the indicationsmentioned above. The probability of this occurrence is therefore too low to have any significance.To erroneously withdraw a single rod cluster control assembly, the operator would have toimproperly set the bank selector switch, the lift coil disconnect switches, and the in-hold-outswitch. In addition, the three indications would have to be disregarded or ineffective. Such aseries of errors would require a complete lack of understanding and administrative control. Aprobability number cannot be assigned to a series of errors such as this. Such a number would behighly subjective.The rod position indication system provides direct visual displays of each control rodassembly position. The plant computer alarms for the deviation of rods from their banks. Inaddition, a rod insertion limit monitor provides an audible and visual alarm to warn the operatorof an approach to an abnormal condition due to dilution. The low-low insertion limit alarm alertsthe operator to initiate boration to restore shutdown margin in accordance with the plantprocedures. The facility reactivity control systems are such that acceptable fuel damage limits willnot be exceeded even in the event of a single malfunction of either system.An important feature of the control rod system is that insertion is provided by gravity fall ofthe rods.In all analyses involving reactor trip, the single, highest-worth rod cluster control assemblyis postulated to remain untripped in its full-out position.

Revision 52-09/29/2016NAPS UFSAR7.7-27One means of detecting a stuck control rod assembly is available from the actual rodposition information displayed on the control board. The control board position readouts, one foreach full-length rod, give the plant operator the actual position of the rod in steps. The indicationsare grouped by banks (e.g., control bankA, control bankB) to indicate to the operator thedeviation of one rod with respect to other rods in a bank. This serves as a means to identify roddeviation.The plant computer monitors the actual position of all rods. Should a rod be misalignedfrom the other rods in that bank and approach limits specified in the Technical Specifications, therod deviation alarm is actuated.Misaligned rod cluster control assemblies are also detected and alarmed in the control roomvia the nuclear instrumentation flux tilt monitoring system, which is independent of the plantcomputer.Isolated signals derived from the nuclear instrumentation system are compared with oneanother to determine if a preset amount of deviation of average power has occurred. Should sucha deviation occur, the comparator output will operate a bi-stable unit to actuate a control boardannunciator. This alarm will alert the operator to a power imbalance caused by a misaligned rod.By the use of individual rod position readouts, the operator can determine the deviating controlrod and take corrective action. Thus, the design of the plant control systems meets the applicablerequirements of General Design Criterion25 (1971criteria).The rod system can compensate for xenon burnout reactivity transients over the allowedrange of rod travel. Xenon burnout transients of larger magnitude must be accommodated byboration or by reactor trip (which eliminates the burnout). The boron system can compensate forall xenon burnout reactivity transients without exception.The boron system is not needed to compensate for the reactivity effects of fuel and watertemperature changes accompanying power level changes.The rod system can compensate for the reactivity effects of fuel and water temperaturechanges accompanying power level changes over the full range from full load to no load at thedesign maximum load uprate. Automatic control of the rods is, however, limited to the range ofapproximately 15% to 100% of rating for reasons unrelated to reactivity or reactor safety.The boron system (by the use of administrative measures) will maintain the reactor in thecold-shutdown state irrespective of the disposition of the control rods. The overall reactivitycontrol achieved by the combination of soluble boron and rod cluster control assemblies meets theapplicable requirements of General Design Criterion26 (1971criteria).7.7.2.3Step-Load Changes Without Steam DumpThe plant control system restores equilibrium conditions, without a trip, following a +/-10%step change in load demand, over the 15% to 100% power range for automatic control. The steam Revision 52-09/29/2016NAPS UFSAR7.7-28dump controller is not armed for load decreases less than or equal to 10%. A load demand greaterthan full power is prohibited by the turbine control load limit devices.The plant control system minimizes the reactor coolant average temperature deviationduring the transient within a given value and restores average temperature to the programmedsetpoint. Excessive pressurizer pressure variations are prevented by using spray, heaters, andpower relief valves in the pressurizer.The control system will limit nuclear power overshoot to acceptable values following a10% increase in load to 100%.7.7.2.4Loading and UnloadingRamp loading and unloading of 5% per minute can be accepted over the 15% to 100%power range under automatic control without tripping the plant. The function of the controlsystem is to maintain the coolant average temperature as a function of turbine-generator load.The coolant average temperature increases during loading and causes a continuous insurgeto the pressurizer as a result of coolant expansion. The sprays limit the resulting pressure increase.Conversely, as the coolant average temperature is decreasing during unloading, there is acontinuous outsurge from the pressurizer resulting from coolant contraction. The pressurizerheaters limit the resulting system pressure decrease. The pressurizer water level is programmedsuch that the water level is above the setpoint for heater cut-out during the loading and unloadingtransients. The primary concern during loading is to limit the overshoot in nuclear power and toprovide sufficient margin in the overtemperature deltaT setpoint.7.7.2.5Load Rejection Furnished by Steam Dump SystemWhen a load rejection occurs, if the difference between the required temperature setpoint ofthe reactor coolant system and the actual average temperature exceeds a predetermined amount, asignal will actuate the steam dump to maintain the reactor coolant system temperature within thecontrol range until a new equilibrium condition is reached.The reactor power is reduced automatically at a rate consistent with the capability of the rodcontrol system. The steam dump flow reduction is as fast as rod cluster control assemblies arecapable of inserting negative reactivity.The rod control system can then reduce the reactor temperature to a new equilibrium valuewithout causing overtemperature and/or overpressure conditions. The steam dump steam flowcapacity is 40% of full-load steam flow at full-load steam pressure.The steam dump flow reduces proportionally as the control rods act to reduce the averagecoolant temperature. The artificial load is therefore removed as the coolant average temperature isrestored to its programmed equilibrium value.

Revision 52-09/29/2016NAPS UFSAR7.7-29The dump valves are modulated by the reactor coolant average temperature signal. Therequired number of steam dump valves can be tripped quickly to stroke full open or modulate,depending upon the magnitude of the temperature error signal resulting from the loss of load.7.7.2.6Turbine Trip with Reactor TripWhenever the turbine-generator unit trips at an operating power level above 30% power, thereactor also trips. The thermal capacity of the reactor coolant system is greater than that of thesecondary system, and because the full-load average temperature is greater than the no-loadtemperature, a heat sink is required to remove heat stored in the reactor coolant to prevent theactuation of steam generator safety valves for a trip from full power. This heat sink is provided bythe combination of the controlled release of steam to the condenser and by the makeup of coldfeedwater to the steam generators. The trip signal interfaces are shown in Figure7.3-2.The steam dump system is controlled from the reactor coolant average temperature signalwhose setpoint values are programmed as a function of turbine load. The actuation of the steamdump is rapid, to prevent the actuation of the steam generator safety valves. With the dump valvesopen, the average coolant temperature starts to reduce quickly to the no-load setpoint. A directfeedback of temperature acts to proportionally close the valves to minimize the total amount ofsteam that is bypassed.Following the turbine trip, the feedwater flow is cut off when the average coolanttemperature decreases below a given temperature or when the steam generator water level reachesa given high level.Additional feedwater makeup is then controlled manually to restore and maintain steamgenerator water level while ensuring that the reactor coolant temperature is at the desired value.Residual heat removal is maintained by the steam header pressure controller (manually selected)that controls the amount of steam flow to the condensers. This controller operates a portion of thesame steam dump valves to the condensers that are used during the initial transient followingturbine and reactor trip.The pressurizer pressure and water level fall rapidly during the transient because of coolantcontraction. If heaters become uncovered following the trip, they are de-energized and theChemical and Volume Control System will provide full charging flow to restore water level in thepressurizer. Heaters are then turned on to restore pressurizer pressure to normal.The steam dump and feedwater control systems are designed to prevent the average coolanttemperature from falling below the programmed no-load temperature following the trip, to ensureadequate reactivity shutdown margin.

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07.7REFERENCES

1.J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System, WCAP-7669, 1971.2.A. E. Blanchard, Rod Position Monitoring, WCAP-7571, 1971.3.J. J. Loving, Incore Instrumentation (Flux-Mapping System and Thermocouples),WCAP-7607, 1971.4.R. M. Siroky and F. W. Marasco, Westinghouse 7300Series Process Control System NoiseTests, 1976.5.M. R. Adler, AMSAC Generic Design Package, WCAP-10858P-A, Rev.1, July1987.6.Westinghouse Technical Bulletin ESBU-TB-08, AMSAC C-20 Interlock Permissive,November26,1997.7.7REFERENCE DRAWINGSThe list of Station Drawings below is provided for information only. The referenced drawings are not part of the UFSAR. This is not intended to be a complete listing of all Station Drawings referenced from this section of the UFSAR. The contents of Station Drawings are controlled by station procedure.Drawing NumberDescription1.11715-FE-27BArrangement: Main Control Room, Elevation 276'- 9", Units 1 & 2 Revision 52-09/29/2016NAPS UFSAR7.7-31Table7.7-1PLANT CONTROL SYSTEM INTERLOCKSDesignationDerivationFunctionC-11/2 neutron flux (intermediate range) above setpointBlocks automatic and manual control rod withdrawalC-21/4 neutron flux (power range) above setpointBlocks automatic and manual control rod withdrawal C-32/3 overtemperature delta T above setpointBlocks automatic and manual control rod withdrawalActuates turbine runback via load reference C-42/3 overpower delta T above setpointBlocks automatic and manual control rod withdrawalActuates turbine runback via load reference C-51/1 turbine impulse chamber pressure below setpointBlocks automatic control rod withdrawalC-71/1 time derivative (absolute value) of turbine impulse chamber pressure (decrease only) above setpointMakes steam dump valves available for either tripping or modulation C-8Turbine trip, 2/3 turbine auto stop oil pressure below setpointBlocks steam dump control via load rejection Tavg controlleror4/4 turbine valves closedMakes steam dump valves available for either tripping or modulationNo turbine trip, 2/3 turbine auto stop oil pressure above setpoint and 1/4 turbine-inlet line stop valves not closedBlocks steam dump control via turbine trip Tavg controllerC-9Any condenser pressure above setpoint, orThree circulation water pump breakers openBlocks steam dump to condenser C-111/1 bank D control rod position above setpointBlocks automatic rod withdrawalC-20First stage pressure transmitterBlocks AMSAC below the first stage pressure setpoint Revision 52-09/29/2016NAPS UFSAR7.7-32Table7.7-2AUXILIARY SHUTDOWN PANEL MONITORING INSTRUMENTATIONaInstrumentMeasurement Range1.Reactor Coolant Temperature-Average530-630°F2.Pressurizer Pressure1700-2500psig3.Pressurizer Level0-100%4.Auxiliary Feed Pump Discharge Header Pressure500-1500psig5.Emergency Condensate Storage Tank Level0-100%

6.Charging Flow0-180gpm7.Main Steam Line Pressure0-1400psig8.Steam Generator Level0-100%9.Relay Room Positive Ventilation0-0.50inches H20a.Located at Elevation254 in the Emergency Switchgear and Relay Room.

Revision 52-09/29/2016NAPS UFSAR7.7-33Figure 7.7-1SIMPLIFIED BLOCK DIAGRAM OF REACTOR CONTROL SYSTEM Revision 52-09/29/2016NAPS UFSAR7.7-34Figure 7.7-2ROD CONTROLS AND ROD BLOCKS Revision 52-09/29/2016NAPS UFSAR7.7-35Figure 7.7-3CONTROL BANK ROD INSERTION MONITOR Revision 52-09/29/2016NAPS UFSAR7.7-36Figure 7.7-4ROD DEVIATION COMPARATOR Revision 52-09/29/2016NAPS UFSAR7.7-37Figure 7.7-5STEAM DUMP CONTROL Revision 52-09/29/2016NAPS UFSAR7.7-38Figure 7.7-6PRESSURIZER PRESSURE AND LEVEL CONTROL Revision 52-09/29/2016NAPS UFSAR7.7-39Figure 7.7-7PRESSURIZER HEATER CONTROL Revision 52-09/29/2016NAPS UFSAR7.7-40Figure 7.7-8FEEDWATER CONTROL AND ISOLATION Revision 52-09/29/2016NAPS UFSAR7.7-41Figure 7.7-9BLOCK DIAGRAM OF PRESSURIZER PRESSURE CONTROL SYSTEM Revision 52-09/29/2016NAPS UFSAR7.7-42Figure 7.7-10BLOCK DIAGRAM OF PRESSURIZER LEVEL CONTROL SYSTEM Revision 52-09/29/2016NAPS UFSAR7.7-43Figure 7.7-11BLOCK DIAGRAM OF STEAM GENERATOR WATER LEVEL CONTROL SYSTEM Revision 52-09/29/2016NAPS UFSAR7.7-44Figure 7.7-12BLOCK DIAGRAM OF STEAM DUMP CONTROL SYSTEM Revision 52-09/29/2016NAPS UFSAR7.7-45Figure 7.7-13BASIC FLUX-MAPPING SYSTEM Revision 52-09/29/2016NAPS UFSAR7.7-46Intentionally Blank Revision 52-09/29/2016NAPS UFSAR7.8-17.8EMERGENCY RESPONSE TO ACCIDENTSIn order to provide improved management of accidents, the Emergency Response Facilitieshave been installed in accordance with Supplement1 to NUREG-0737, NUREG-0696 and withinthe requirements set forth in NUREG-0700. The Emergency Response Facilities (ERF) whichhave been installed include:*Technical Support Center (TSC)*Emergency Control Center (ECC)

• Operations Support Center (OSC)*Local Emergency Operations Facility (LEOF)*Corporate Emergency Response Center (CERC)

• Center Emergency Operation Facility (CEOF)*The Safety Parameter Display System (SPDS)Although the Safety Parameter Display System is not a facility, it is an integral part of theERF and will be treated as such.The Emergency Response Facilities provide the following services:*Keep the reactor operators informed of the plant's safety status.*Relieve the reactor operators of peripheral duties not directly related to plant safety.*Provide technical assistance to the reactor operators.*Provide a coordinated response to the accident.

• Keep observers out of the control room.*Provide communications between onsite and offsite emergency response organizations.*Centralize control of recommendations for offsite actions.

• Provide relevant plant data to the NRC for analysis.Personnel assigned to staff the Emergency Response Facilities are trained to followemergency procedures in a timely manner. Emergency Planning is described in Section13.3.

Revision 52-09/29/2016NAPS UFSAR7.8-2Activation of the Emergency Facilities is initiated by the Emergency Plan ImplementingProcedures (EPIP):EPIP-1.01Emergency Manager Controlling ProcedureEPIP-1.02Response to Notification of Unusual EventEPIP-1.03Response to AlertEPIP-1.04Response to Site Area EmergencyEPIP-1.05Response to General EmergencyThe following EPIPs provide the instruction to direct personnel to set the EmergencyResponse Facilities equipment into operation:EPIP-3.02Activation of Technical Support CenterEPIP-3.03Activation of Operational Support CenterCPIP-3.2NorthAnna LEOF Activation Revision 52-09/29/2016NAPS UFSAR7.9-17.9INADEQUATE CORE COOLING MONITOR (ICCM) SYSTEMIn response to NUREG-0578 (Reference1), instrumentation to detect inadequate corecooling has been installed at NorthAnna Units1 and2.7.9.1Design BasesThe Inadequate Core Cooling Monitor (ICCM) system is designed by Westinghouse andCombustion Engineering, and meets all the requirements of Regulatory Guide1.97 (Reference2).The ICCM consists of the following three redundant subsystems that share common redundantcalculator devices and continuous control room displays: Core Exit Thermocouple (CET) System,Core Cooling Monitor (CCM) System, and Reactor Vessel Level Instrumentation System(RVLIS).The system provides means for acquiring data only, and performs no operational unitcontrol. The system readily detects and displays conditions of inadequate core cooling.The safety-grade signal inputs, calculator devices and displays are qualified to IEEEStd323-1974 (Reference3) and IEEE Std344-1975 (Reference4).The system is safety-related, Class1E. The RVLIS is a Seismic ClassI System. All pipingtubing, and conduit are seismically supported. All equipment has seismically-qualified mountingsupports and the redundant electronics, including the microprocessor, are housed inseismically-qualified equipment cabinets.System data are given in Table7.9-1.The system is designed and constructed in accordance with General Design Criteria14, 15,16, 30 and55 of AppendixA to 10CFR, Part50. All components and materials used in the designare consistent with original station design criteria, except that compression type fittings, besidesbeing used for the connection at the instruments, are also used in the RVLIS tubing connecting thereactor vessel head vent valve to the high-volume sensors. These fittings, which meet systemdesign pressures and temperatures, are necessary to prevent damaging the tubing when the reactorvessel head is removed during refueling.

7.9.2Design Description7.9.2.1Core Exit Thermocouple (CET) System-Subsystem of ICCM SystemThe Core Exit Thermocouple System uses inputs from up to 50 of the 51 incorethermocouples (51st available as spare) to calculate and display temperature of the reactor coolantas it exits the core. Refer to Figures4.4-20 (Unit1) and4.4-21 (Unit2) for the locations ofthermocouples that have been abandoned in place.

Revision 52-09/29/2016NAPS UFSAR7.9-2The CET system consists of TypeK, ungrounded, stainless steel sheathed thermocouples.Refer to UFSAR Section7.7.1.9.1 for description of the quantity and design of thethermocouples.Safety-related thermocouples from each channel (25 for TrainA and 25 for TrainB) arewired to the redundant ICCM calculators in the annunciator room via the electrical penetrationsand Station Multiplexer System.The cold junction compensation is performed internally at the remote multiplexer (MUX)installed in the cable vault area.The thermocouples measure the core exit temperature in a range of 0-2300°F.7.9.2.2Reactor Vessel Level Instrumentation Systems (RVLIS)-Subsystem ofICCMSystemThe Reactor Vessel Level Instrumentation System (RVLIS) uses various parameters tocalculate and to display the water level height in the reactor vessel during all plant conditions(except mode6).RVLIS uses differential pressure (d/p) measuring devices to measure vessel level or relativevoid content of the circulating primary coolant system fluid. The system is redundant and includesautomatic compensation for potential temperature variations of the impulse lines. Essentialinformation is displayed in the main control room in a form directly usable by the operator.The function performed by the RVLIS are as follows:*Assist in detecting the presence of a gas bubble or void in the reactor vessel.*Assist in detecting the approach to ICC.*Indicate the formation of a void in the RCS during forced flow conditions.

The RVLIS utilizes two redundant sets of three differential pressure (d/p) cell transmitters.These cells measure the pressure drop from the bottom of the reactor vessel to the top of thevessel, and from the hot legs to the top of the vessel. To do this, it is necessary to tap into thereactor coolant system at the reactor vessel head, seal table, and the resistance temperaturedetector bypass piping of the hot legs of two reactor coolant system loops. Filled, sealed capillaryimpulse lines are used from the reactor coolant system to the transmitters. Each capillary line issealed at the reactor coolant system end with a sensor bellow. A hydraulic isolator providesisolation of each sensing line outside of the containment. Reactor coolant system pressure, hot-legtemperatures and impulse line temperatures will be monitored and used to compensate for fluiddensity variations occurring during operating conditions.

Revision 52-09/29/2016NAPS UFSAR7.9-3This d/p measuring system utilizes cells of differing ranges to cover different flowbehaviors with and without reactor coolant pump operation as follows:*Reactor Vessel-Upper Range. This d/p cell provides a measurement of reactor vessellevel above the hot leg pipe when the reactor coolant pump (RCP) in the loop with the hotleg connection is not operating.*Reactor Vessel-Dynamic Head Range. This d/p cell provides an indication of reactorcore and internals pressure drop for any combination of operating RCPs. Comparison ofthe measured pressure drop with the normal, single-phase pressure drop provides anapproximate indication of the relative void content or density of the circulating fluid. Thisinstrument monitors coolant conditions on a continuing basis during forced flowconditions.*Reactor Vessel-Full Range. This d/p cell provides an indication of reactor vessel levelfrom the bottom of the reactor vessel to the top of the reactor during natural circulationconditions.Temperature measurements of the impulse lines together with the reactor coolanttemperature measurements (hot leg RTDs) and wide range RCS pressure, are employed tocompensate the d/p transmitter outputs for differences in system density and reference leg density,particularly during the change in the environment inside the containment structure following anaccident.The d/p cells are located outside of the containment to eliminate the large reduction(approximately 15%) of measurement accuracy associated with the change in the containmentenvironment (temperature, pressure, radiation) during an accident. The cells are also locatedoutside of containment so that system operation including calibration, cell replacement, referenceleg checks, and filling are made easier.7.9.2.3Core Cooling Monitor System-Subsystem of ICCM SystemThe Core Cooling or Subcooled Margin Monitor System uses various parameters tocalculate saturated temperature and subcooled margins for the primary loops during all plantconditions. These input parameters provide the plant operators with complete information on corecooling.Software algorithmus perform calculations which determine the equivalent saturatedtemperature (Tsat) based on reactor wide range pressure. This (Tsat) value is used to determine thesubcooled margin for the average of the five highest core exit thermocouples temperature.

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47.9REFERENCES

1.U.S. Nuclear Regulatory Commission, TMI-2 Lessons Learned Task Force Status Report andShort-Term Recommendations, NUREG-0578, July1979.2.U.S. Nuclear Regulatory Commission, Instrumentation for Light-Water-Cooled NuclearPower Plants to Assess Plant and Environs Conditions During and Following an Accident,Regulatory Guide1.97, December1980.3.IEEE Std323-1974, IEEE Standard for Qualifying Class1E Equipment for Nuclear PowerGenerating Stations, 1974.4.IEEE Std344-1975, Recommended Practices for Seismic Qualification of Class1EEquipment for Nuclear Power Generating Stations, 1975.

Revision 52-09/29/2016NAPS UFSAR7.9-5Table7.9-1INADEQUATE CORE COOLING MONITOR (ICCM) SYSTEM DATAI.ICCM Display1.Type/LocationFlat Plasma Graphic/Vertical Main Control Board2.Operator Interface/Location4 - Button Keypad/Main Control Board Benchboard3.RedundancyYes4.Information Displayed*DATA LINK FAILURE message indicates the datalink from the system microprocessor to the displayhas failed*Incore thermocouple display graphics*Core Cooling display graphics

• RVLIS display graphics5.Display Update RateEvery two secondsII.Calculator1.TypeMicroprocessor (16 Bit)2.LocationAnnunciator Room3.Operator InterfaceLocal Display Panel with switches or portable maintenance terminal4.RedundancyYes5.AlarmControl board annunciation on system malfunctionIII.Reactor Vessel Level Instrumentation System (RVLIS) - Subsystem of ICCM System1.RedundancyYes2.System Input Sensors(Per Channel)*3 - Reactor Coolant Pump Breaker contacts*3 - RVLIS Hydraulic Isolator contacts

• 3 - RVLIS d/p transmitter signals

• 5 to 7 - RVLIS capillary RTDs (quantity varies perunit/channel)*2 - Hot Legs RTDs

• 1 - RCS Wide Range Pressurea.Refer to Figures4.4-20 (Unit1) and4.4-21 (Unit2) for the locations of thermocouples that have been abandoned in place.

Revision 52-09/29/2016NAPS UFSAR7.9-6III.Reactor Vessel Level Instrumentation System (RVLIS) - Subsystem of ICCM System (continued)3.Display Graphics Available(Per Channel)*Reactor Coolant Status - ON/OFF

• Vessel level trending for the preceding 30minutesshowing static head (full range level) with a rangeof 0-120% level, dynamic head with a range of0-120% full dP, and data quality based on thenumber of sensors used in the computations*Graphics layout of complete RVLIS process,including RVLIS status, RCS wide range pressure,and hot leg temperature*Instantaneous vessel level conditions for dynamichead full dP, and full and upper range level inranges between 0 and 120%*RVLIS diagnostic information.IV.Core Cooling Monitor System - Subsystem of ICCM1.RedundancyYes2.System Input Sensors(per channel)*25 - Incore thermocouples a*2 - Hot leg RTDs

• 1 - RCS wide range pressure3.Display Graphics Available(per channel)*Pressure - Temperature (P-T) graph showing thesaturation temperature curve and the over pressureand over temperature regions and current RCScoolant conditions plus trending of coolantconditions for previous 30 minutes. The P-T curvevertical axis range is 0 to 3000psig wide rangepressure and the horizontal axis range is 0 to 700°Fof the average of the five highest incorethermocouples. Also displayed digitally are theinput parameters and margin-to-saturation.4.AlarmControl board annunciation on approach-to-saturation temperatureTable7.9-1(continued)INADEQUATE CORE COOLING MONITOR (ICCM) SYSTEM DATAa.Refer to Figures4.4-20 (Unit1) and4.4-21 (Unit2) for the locations of thermocouples that have been abandoned in place.

Revision 52-09/29/2016NAPS UFSAR7.9-7V.Core Exit Thermocouple (CET) Monitoring System - Subsystem of ICCM1.RedundancyYes2.System Input Sensors(per channel)*25 - Type K Core Exit thermocouples a(1 spare train B thermocouple available)3.Display Graphics Available(per channel)*Full core map showing temperature at eachthermocouple location for that channel*Core map showing the maximum, minimum andaverage temperature for that channel for eachquadrant and the subcooled temperature*Tabulation of each thermocouple for that channelby quadrant, location, and temperature*Trending curve of the average of the five highestCETs per core for past 30 minutes, including a graph of the data quality based on the number of thermocouples used in the computations. Alsolisted are the subcooling temperature and the CETtemperature based on the average of the fivehighest thermocouples per core*CET diagnostic information*Thermocouple range of all displays is 0-2,300°FTable7.9-1(continued)INADEQUATE CORE COOLING MONITOR (ICCM) SYSTEM DATAa.Refer to Figures4.4-20 (Unit1) and4.4-21 (Unit2) for the locations of thermocouples that have been abandoned in place.

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