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 Report Chapter 7 Intentionally Blank

Intentionally Blank Revision 52-09/29/2016 NAPS UFSAR 7-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 ContentsSectionTitle Page Revision 52-09/29/2016 NAPS UFSAR 7-iiChapter 7: Instrumentation and ControlTable of Contents (continued)SectionTitle Page7.2.3.4Safety 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 Af ter 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 52-09/29/2016 NAPS UFSAR 7-iiiChapter 7: Instrumentation and ControlTable of Contents (continued)SectionTitle Page7.5SAFETY-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 R oom 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 52-09/29/2016 NAPS UFSAR 7-ivChapter 7: Instrumentation and ControlTable of Contents (continued)SectionTitle Page7.7.1.13Control Room Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-187.7.1.14Anticipated Transient Without Scram (A TWS) 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 Instrumenta tion 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 52-09/29/2016 NAPS UFSAR 7-vChapter 7: Instrumentation and ControlList of TablesTableTitle PageTable7.2-1List 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 Indicat ors and/or Recorders Availableto the Operator Condition II and III Events. . . . . . . . . . . . . . . . . . . . . .7.5-5Table7.5-2Main Control Board Indicat ors and/or Recorders Availableto the Operator Condition IV Events. . . . . . . . . . . . . . . . . . . . . . . . . . .7.5-8Table7.5-3Control Room Indicators and/or Recorders Available to the Operator to Monitor Significant Plant Parameters During Normal Operation. . .7.5-13Table7.7-1Plant Control System Interlocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7-31Table7.7-2Auxiliary Shutdown Pane l Monitoring Instrumentation a . . . . . . . . . . .7.7-32Table7.9-1Inadequate Core Cooling Monitor (ICCM) System Data . . . . . . . . . . .7.9-5 Revision 52-09/29/2016 NAPS UFSAR 7-viChapter 7: Instrumentation and ControlList of Figures FigureTitle PageFigure 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 Transi ent 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 52-09/29/2016 NAPS UFSAR 7-viiChapter 7: Instrumentation and ControlList of Figures (continued)

FigureTitle PageFigure 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 52-09/29/2016 NAPS UFSAR 7-viii Intentionally Blank Revision 52-09/29/2016 NAPS UFSAR 7.1-1CHAPTER 7INSTRUMENTATION AND CONTROLS

7.1INTRODUCTION

Note: As required by the Renewe d Operating Licenses for NorthAnna Units1 and2, issuedMarch20,2003, various systems, st ructures, and components discu ssed within this chapter aresubject to aging management. The programs and activities necessary to manage the aging of these systems, structures, and components are discussed in Chapter18.

This chapter describes the various plant inst rumentation and contro l systems by presenting the functional performance requireme nts, design bases, system de scriptions, design evaluations, and tests and inspections for each.

The information provided in this chapter applies particularly to those instruments and associated equipment that constitute the protection system as defined in Institute 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 in strumentation and control syst ems is to provide automatic protection against unsafe and improper reactor ope ration during steady-state and transient power operations (American Nuclear Society (ANS) ConditionsI, II, III) and to provide initiating signals to mitigate the conse quences of faulted conditions (ANS ConditionIV). (See Chapter15 for a discussion of the ANS conditions.) Consequently, the information presented in this chapter emphasizes those instrumentation and control systems that are central to ensuring that the reactor can be operated to produc e power in a manner that ensures no undue risk to the health and safety of the public.

It is shown that the applicable criteria and codes conc erned 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 sa fety-related functions include both those which initiate a protective action, su ch as a reactor trip or a safety injection, and also those which are used tomonitor Technical Specifications or other sa fety-related parameters. Instrumentation loops include both analog and digita l instrumentation sign als that initiate protective actions that represent acceptable conditions of the physical processes. The T echnical Specification describes and limits appropriate parameters. Appropriately selected reactor protection setpoints andassociated analog instrument signal uncert ainties define the bases upon which safety is established and proved by the UFSAR Chapter15 analysis. The verification of actual allowable analog instrumentation signal uncertainties must consider various in strumentation hardwareconstraints when proving appropriate analog ch annel statistical allowances. Examples of the kinds of hardware considerations that determine the proper accuracy are as follows:*Transmitter model Revision 52-09/29/2016 NAPS UFSAR 7.1-2*Calibration tolerances, methods, and frequencies*Measurement and test equipment ranges and accuracies*Loop scaling These hardware considerations have all be en accounted for in ve rifying the allowable instrument uncertainty associated with each safety-related instrument loop.7.1.1DefinitionsThe definitions below establish the meaning of words in the cont ext of their use inChapter7.Channel -

An arrangement of components and modules as required to generate a single protective action signal when re quired 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 disconnect ed, removed as a unit, and replaced with a spare. It has defi nable performance characteristics that permit it to be tested as a unit. A module can be a card or other subassembly of a larger device, provided it meets the requirements of this definition.

Components -

Items from which the system is assemb led (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 components of 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 channe l 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 in itiation 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 associated with a particular generating st ation condition, signal processing, and the initiation and completion of the protective action at values of th e 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 variable and the number of channels that, when tri pped, will cause an automatic system trip.

Revision 52-09/29/2016 NAPS UFSAR 7.1-3 Cold-Shutdown Condition - When the reactor is subcritical by at least 1% deltak/k and T avg 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 T avg is greater than or equal to the temperature specified in the Technical Specifications.Containment Isolation PhaseA -

Closure of all nonessential pr ocess lines that penetrate containment. Initiated by the sa fety injection activation signal.Containment Isolation PhaseB -

Closure of remaining process li nes. Initiated by containment high-high-pressure signal (process lines do not in clude engineered safety features lines).Trip Accuracy -

The tolerance band of the difference between (1)the desi red trip point value of a process variable, and (2)the actual value at which a comparator trips (and thus actuates some desired result).Technically, trip accuracy describes the maximum inaccuracy or maximum uncertaintyassociated with the desired trip setpoint. Tr ip accuracy is usually expressed in percent ofinstrument span. Trip accuracy id entifies, in both the positive and negative directi ons, the furthest point from the desired trip setpoint at which trip actuation could occur. This is also referred to as the channel statistical allowance (CSA). Thus, the trip setpoint accuracy envel opes a range around the desired trip setpoint within which an actual trip must occur.

The following instrument loop error terms ar e included, as required, when determining tripaccuracy: systematic error, pr ocess 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 of these error terms are addressed in Reference6 and associated engineering standards or calculations.

Actuation Accuracy - Synonymous with trip accuracy, but us ed 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 actual value of that process variable. The tolerance band includes the inaccuracies associated with the instrument channel and the readout devices. It also includes process rack environmental effects,but does not include process effects such as fluid stratification.

Revision 52-09/29/2016 NAPS UFSAR 7.1-4Reproducibility -

This term may be substitu ted for "accuracy" in the a bove definitions for those cases where a trip value or indicated value need not be refe renced to an actual process variable value, but rather to a previously established trip or indication value; this value is determined by test.7.1.2Identification of Sa fety-Related Systems The instrumentation and control systems an d supporting systems that are required to function to achieve the system re sponses assumed in the safety ev aluations, 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 ventilati on systems for safety-relate d 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 functionally defined 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 Trip System, is containe d 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 fu nctions identified in Section 7.3, Engineered Safety 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 52-09/29/2016 NAPS UFSAR 7.1-55.Actuation devices.7.1.3Identification of Safety Criteria 7.1.3.1 Design 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 C ooled Nuclear Power Plants, Division of Reactor Standards,Atomic Energy Commission, October27,1971.3.The Institute of Electrical a nd Electronic Engineers, Inc., IEEE Standard: Criteria forProtection Systems for Nuclear Power Generating Stations, IEEE Std279-1971.4.The Institute of Electrical a nd Electronic Engineers, Inc., IEEE Standard Criteria for Class IE Electric Systems for Nuclear Power Generating Stations, IEEE Std308-1971.5.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard for Electrical Penetration 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 El ectrical and Electroni c Engineers, Inc., IEEE Trial-Use Guide for TypeTests of Continuous-Duty ClassI Motors Insta lled Inside the Containm ent of Nuclear PowerGenerating Stations, IEEE Std334-1971.8.The Institute of Electrical and Electronic Engineers, Inc., IEEE Standard: Installation,Inspection, and Testing Requirements for Inst rumentation and Electri cal 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 System The reactor trip system acts to limit the cons equences of ConditionII events (faults of moderate frequency such as loss of feedwater flow) by, at most , a shutdown of the reactor and turbine, with the plant capable of returning to operation after corrective action. The reactor trip Revision 52-09/29/2016 NAPS UFSAR 7.1-6 system features impose a limiting boundary region to plant opera tion 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 Perform ance Requirements 7.1.3.2.1.1Reactor Trips. The reactor trip system automatically initiates reactor trip as follows:1.Whenever necessary to prevent fuel damage from any an ticipated 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 protect the 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 reactor trip is initiated to prevent the reactivity inse rtion that would otherwis e 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 by operator action.

7.1.3.2.1.4 Feedwater Isolation.

The reactor trip system provides a signal whenever reactor trip is initiated (in conjunction with interlockP-4), which closes main feedwater valves on T avg below setpoint. The signal also preven ts opening main feedwater valves that were closed by safety injection or high steam generator water level.

7.1.3.2.1.5 Safety Injection.

The reactor trip system provides a signal whenever reactor trip isinitiated (in conjunction with interlockP-4), which automatically blocks the automatic re-actuation of safety injection (after safety in jection has been reset).7.1.3.2.2Design Bases The design requirements for the reactor trip system ar e derived by analyses of plant operating and fault conditions where automatic rapid control rod insertion is necessary to prevent or limit core or reacto r coolant boundary damage. The design limit s for this system are as follows:1.Minimum departure from nucleate boiling rati o (DNBR) shall not be less than the design DNBR limit as a result of an y 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 52-09/29/2016 NAPS UFSAR 7.1-74.The release of radioactive material shall not be sufficient to in terrupt or restrict public use of those 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 Standards The reactor protection instru mentation meets IEEE crite ria as set forth in IEEEStd279-1971, IEEE Standard: Criteria for Protection Systems for Nuclea r 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) pr otection channels required to operate in the postaccident enviro nment, and the required duration of operation, is included inSection3.11.In the NorthAnna Units1 and2 spaces containing Class1E equipment where Class1E redundant ventilation or air co nditioning systems are not provid ed and the temperature couldexceed that for which the Class1 E equipment is qualified, a te mperature monitoring system is provided that will meet the following requirements:1.An alarm will occur in the control room when the qualified temperature ra nge 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 emergency bus).2.Operating procedures require the control room operator to log the receipt of all alarms, the action taken, and the alarm clearing. The temp erature in the alarmed area will be recordedperiodically, either manually or automatically, during the time that th e temperature is above the alarm setpoint.

For alarms of temperature exceeding the e quipment qualification, an analysis will be provided to demonstrate that the excess temperature has not de graded the equipment below alevel acceptable for continued operations.

7.1.3.3Engineered Safety Features Actuation System The engineered safety features (ESF) system acts to limit the consequences of ConditionIII events (infrequent faults such as primary coolant spillage from a small r upture that exceed normalcharging system makeup and require the actuation of the safety injection system). The ESF Revision 52-09/29/2016 NAPS UFSAR 7.1-8 system also acts to mitigate ConditionIV events (lim iting faults, which include the potential for significant release of radioactive material). The ESF system cons ists of the ESF actuation systemas discussed in Section7.3 and the ESF-actuated devices discussed in Chapter6.7.1.3.3.1Functional Perform ance Requirements 7.1.3.3.1.1General Performance Requirements.

Signals additional to th ose 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 andIV events. These are serious abnorma l conditions in the reactor cool ant 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 disc ussed in detail inChapter6.7.1.3.3.1.2Automatic Actuation Requirements. The primary functional requirement of the ESF actuation 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 th e various components and subsyste ms comprising the ESF actuateddevices. These output signals, in conjunction with the actuated devices, ensure that the ESF system 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 for manually initiating from the c ontrol room all of the functi ons 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 actuation system by the desi gn-base objectives.

In addition to the requirements for a reactor trip for anticipated abnormal transients, the plant shall be provided with ade quate instrumentation and contro ls to sense accident situationsand initiate the operation of necessary ESF-actua ted devices. The occurrence of a limiting fault,such as a LOCA or a steam-line br eak, requires a reactor tr ip plus the actuation of one or more of the ESF actuation devices to prevent or mitigate damage to the core and reactor coolant systemcomponents and ensure containment integrity.

Revision 52-09/29/2016 NAPS UFSAR 7.1-9To accomplish these design objectives, the ESF system shall have proper and timely initiating signals supplied by the sensors, tran smitters, and logic compon ents making up the various 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 E SF power demands on the ESF buses (supplied by either 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 co ld legs of the reactor coolant system.4.Charging/safety injection pumps, and associ ated valving, which pr ovide the injection of water to the cold leg of the reactor coolant system following a LOCA.5.Low-head safety injection pumps, which star t to provide borated makeup water to the cold legs of the reactor coolant loops.6.Service water system pumps a nd valves, which provide cooli ng water to the recirculation spray heat exchangers and are thus the heat sink for containment cooling.7.Auxiliary feedwater pumps.8.Containment isolation phaseA, whose func tion is to prevent fission product release.9.Steam-line isolation, to prevent the contin uous, uncontrolled blow down of more than one steam generator and thereby uncontroll ed reactor coolant system cooldown.10.Main feedwater-line isolation, to limit the energy release in the case of a steam-line break and to limit the magnitude of the reactor coolant system cooldown.11.Emergency diesel starting, to ensure backup supply of power to emergency and supporting systems components.12.Containment depressurization system actuation, which perfor ms the following functions:a.Initiates containment quench and recirculat ion spray subsystems, which serve to reducecontainment pressure and temperature followi ng a loss-of-coolant or steam-line-break accident.b.Initiates containment isolation phaseB, which isolates the containment following aLOCA or a feedwater-line or st eam-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 52-09/29/2016 NAPS UFSAR 7.1-10 In addition, the minimum performance for each of the ESF actuati on systems specified in terms of time response, accuracy, and range is in accordance with the requirements set forth in this document.7.1.3.3.4Environmental RequirementsThe environmental design bases are given in Sections3.10 and3.11 and in IEEEStd279-1971.

7.1.3.4 Instrumentation and Control Power SupplyThe functional performance requirements for the instrumentat ion and control powersupplies are described in detail in Chapter8.

7.1.3.5 Quality Assurance The quality assurance program applied to safe ty-related instrumentation and control systemcomponents is described in Chapter17.

7.1.3.6 Safety-Related Equipment Identification There are two sets of separate process anal og racks. One set contains instrumentation furnished by the architect-engineer, the other contains instru mentation furnished by the NSSSsupplier. The separation of redundant analog cha nnels begins at the process sensors and is maintained in the fiel d wiring, containment penetrations, and analog protection racks to the redundant trains in the logic racks. Redundant analog channels are sepa rated by locating modulesin different rack sets. Since al l equipment within any analog ra ck is associated with a singleprotection set, there is no requirement for the separation of wiri ng and components within the rack. Barriers are provided in th e logic rack to separate channel inputs. A color-coded nameplate on each analog rack is used to differentiate between protective and nonprotective sets. The color coding 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 rela ys 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 Coding IRed with white lettering II White with black letteringIIIBlue with white lettering IVYellow with black lettering Revision 52-09/29/2016 NAPS UFSAR 7.1-11There are identification namepl ates on the input pa nels of the digital logic system. Fordetails of the digital logic system, see Sections7.2 and7.3.

The installation of all cable, including separati on requirements for control board wiring,complies with the criteria presented in Chapter8.

Redundant sensors, sensing li nes, and actuating devices ar e separated by either space, physical barriers, or both. The sens ing lines are normally routed to missile-protec ted areas where the transmitters are located. In areas where the potential for missi les is high and where no physical barriers are provided, sensors, sensing lines, and act uating devices are physic ally separated by aminimum distance of 4feet in any direction. Sensing lines passing through walls are also physically separated, or ea ch sensing line is protected by rigi d steel conduit when passage is made through 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 of instrumentation required by the ope rators to monitor the plant a nd environs during and followingan accident. This instrumentation consists of indicators that are a ssociated with a variety of plant safe-shutdown and balance of pl ant systems. The intent of Reg. Guide1.97 is to provide the operators with the minimum essent ial information during and following an accident so that theywill be able to mitigate and minimize the consequences of the accident. The Reg. Guide has specifically determined four of the five types of instrument ation required to ensure proper indication is available to the operators. These four types (TypeB, C, D, andE) are outlined inTable3 of the Reg. Guide along wi th their specifically assigned category, de sign and qualification requirements. The fifth type of instrumentation, Type"A" variables, are plant specific. Atype"A" variable provides the operator with essential information ne cessary to take manualactions to mitigate an accident for which no automatic actions ar e provided. These instruments are characterized by their definiti on as stated in the Reg. Gu ide. These definitions are:1.TypeA Variables: Those variables to be m onitored that provide th e primary information required to permit the control room operator to take specific ma nually controlled actions for which no automatic cont rol is provided and that are required for safety systems to accomplish their safety functions for design basis accident events. Primary information isessential for the direct accomplishment of the specified safety functi ons; it does not include those variables that are associated with con tingency actions that may also be identified in written procedures.2.TypeB Variables: Those variab les that provide information to indicate whether plant safetyfunctions are being accomplished. Plant safety functions are (1)reactivity control, (2)core Revision 52-09/29/2016 NAPS UFSAR 7.1-12cooling, (3)maintaining reactor coolant system integrity, and (4)mai ntaining containment integrity (including radioactive effluent control). Variables ar e 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 i ndicate the operation of individual safety systems and ot her systems important to safety. These variables are to help the operator make appropriate decisions in us ing the individual systems important to safety in mitigating the consequences of an accident.5.TypeE Variables: Those variables to be monitored as required for use in determining the magnitude of the release of radioactive materials and conti nually assessing such releases.To further define the variables, Reg. Guide1.97 has assigned each variable a design andqualification category. This cate gorization consists of either a category1, 2 or3 designation witha category1 having the mo st stringent requirements to category3 having the least stringent. Thevariables are examined against twelve design and qualif ication criteria. However, Category2 or3 variables may be exempt from some or all of the individual criterion's requirements. The criteria and how they are to be applied against each of the three categories are listed in Table1 Design and Qualification Criteri a for Instrumentation of Regulatory Guide1.97. The twelve category requirements 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 52-09/29/2016 NAPS UFSAR 7.1-13 In response to NUREG-0737, and Regulatory Guide1.97, Revision3, Virginia Power has developed a programmatic approach in defining the Regulatory Guide1.97 required equipment.The Virginia Power Regulatory Guide1.97 program reviews exam ined each of the required instrumentation loops against th e category design and qualification requirements. The reviews determined whether equipment upgrades to meet the Regulatory Guide requirements were required. Any required equipment upgr ades will be performed to meet the Design and Qualification Criteria for Instrumentation of the Regulatory Guide. Virginia Power has also takenexceptions to the category requirements for certain plant instrume nts. These exceptions to the Regulatory Guide have been ou tlined in correspondence between the NRC and Virginia Power.

Any further exceptions to th e Regulatory Guide will also be relayed to the NRC by correspondence for their review and approval. Virginia Power main tains a plant specific technicalreport, PE-0013, and Technical Requirements Manual SectionTR3.3.9 that provide a tabular identification 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 Steam Supply Systems, (W CID 7300 Series), WCAP-7913.2.J. B. Lipchak and R. A. Stokes, Nuclear Instrumentation System , WCAP-7380-L,January1971 (Westinghouse NE S Proprietary); and WCAP-7669, May1971 (non proprietary).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 52-09/29/2016 NAPS UFSAR 7.1-147.1REFERENCE 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 St ation Drawings are controlled by station procedure.

Drawing Number Description1.11715-LSK-27-12ATypical Loop Diagram fo r 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 Cont ainment Pressure Protection Protection6.11715-LSK-27-12FContainment Depressurization Actuation and Reset, Train B 7.11715-LSK-28-5CSafety Inject ion System, Actuated Devices 8.11715-LSK-27-12GContainment Depr essurization 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 52-09/29/2016 NAPS UFSAR 7.2-17.2REACTOR TRIP SYSTEM Electrical schematic diagrams for the reactor trip system and its supporting systems were included 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.7.2.1Description The reactor trip system uses sensors that feed analog circuitry consisting of two to four redundant channels that monitor various plant parameters. The react or trip system also contains the 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 protection channels.Each of the two trains, A and B, is capable of opening a sepa rate 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 driv e 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 control power supply cabinets. For reactor tr ip, a loss of dc voltage to th e undervoltage coil releases thetrip plunger and trips open the breaker. A shunt trip relay is in stalled in parallel with theundervoltage attachment. Upon de-energization, contacts from the relay energize the reactor trip breaker shunt trip attachment and trips open the breaker. This provides a redundant/backup means to 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 the control rods fall by gravity into the core. The rods cannot be wi thdrawn until an operator resetsthe trip breakers. The trip breake rs cannot be reset unt il the bi-stable that initiated the trip isre-energized. Bypass breakers BY A and BYB are provided to perm it 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 fuel design limits).3.Reactor coolant system overpressure creatin g stresses approaching the limits specified inChapter5.

Revision 52-09/29/2016 NAPS UFSAR 7.2-2 The following are the variables re quired to be monito red 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 spatiall y dependent. See Section7.3.1.2 for a discussion of 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 the setpoints used in the Technical Requirements Manual are conservative.

The setpoints for the various fu nctions in the reactor trip sy stem have been analyticallydetermined such that the operational limits so prescribed will pr event fuel rod clad damage andloss of integrity of the reactor coolant system as a result of any ConditionII incident (anticipated malfunction). 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 correspondi ng to fuel centerline melting.The accident analyses described in Section1

5.2 demonstrate

that the functional requirements as specified for the reactor trip system are adequate to meet the above considerations, 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 (a llowable values), is presentedin the Technical Specifications.For a discussion of energy supply and environmental variations, see Sections8.3.1.2and3.11, respectively.

Revision 52-09/29/2016 NAPS UFSAR 7.2-3The malfunctions, accidents, or other unusual events that could physi cally 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 Technical Specifications. During periodic testing as required by Technical Specifications, it is demonstrated or verified that instrument errors and time delays are equal to or less than the values assumed in the safety analyses.Maximum allowable time delays in generating the reactor tr ip 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 permit online testing of the various protec tion channels or to permit cont inued operation in the event of a subsystem instrumentation channel failure, the Technical Specifications define the operabilityrequirements for the reactor trip system. The Technical Specif ications also define the requiredrestriction to operation in the event that the channel operability cannot be met.7.2.1.1Reactor TripsThe various reactor trip circu its automatically open the reactor trip breakers whenever a condition monitored by the reactor trip system reac hes a preset level. In addition to redundantchannels and trains, the design approach provides a reactor trip system that monitors numerous system variables, that is, provides reactor trip system functional diversity. The extent of this diversity has been eval uated for a wide variety of postulated accidents and is detailed inReference1.Table7.2-1 provides a list of re actor trips, coincidence require ments, and interlocks, whichare described below.Table7.2-5 provides a list of reactor trip system instrumentation with the number of channels to trip and the minimum channels that are required operable.

Revision 52-09/29/2016 NAPS UFSAR 7.2-47.2.1.1.1Nuclear Overpower Trips The specific trip functions generated are as follows:1.Power range high-neutron-flux tr ip-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 se tting used for a high and a low setting. The high trip settin g provides protection during normal power ope ration and is always active. The low trip setting, which provides protection during startup, can be manually bypassed when two out of the four pow er range channels r ead above approximately 10% 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 re actor trip system interlocks.2.Intermediate range high-neutron-flux trip-The intermediate range high-neutron-flux trip circuit trips the reactor when one out of the two intermediate range channels exceeds the trip setpoint. This trip, which provi des protection during reactor st artup, can be manually blocked if two out of the four power range channels are above a pproximately 10% power (P-10).

Three out of the four power range channels below this value automatically reinstate the intermediate range high-neutron-flux trip.

The intermediate range channels (including detectors) are separate from the power range channels. The intermediate range channels canbe individually bypassed at the nuclear instrumentation racks to permit channel testing during plant shutdown or befo re startup. This bypass action is annunciated on the control board.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 setpoi nt. This trip, which provides protection dur ing reactor startup and plan t shutdown, can be manually bypassed when one of the tw o intermediate range channels reads above the P-6 setpoint value and is automatically reinstated when bot h intermediate range ch annels decrease below the 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 an administrative action requiring manual actuation of tw o control board mounted switches.Each switch will reinstate the trip function in one of the two protection logic trains. The source range trip point is set be tween the P-6 setpoint (source range cutoff flux level) and the maximum source range flux level. The channe ls can be individuall y bypassed at the nuclear instrumentation racks to permit channel testing during plant s hutdown or before startup. This bypassing action is annunciated on the control board.4.Power range neutron flux rate trips (PRRT)-Refer to Figure7.2-3. The functional diagram shown includes reactor trip logi c provided to trip the reac tor when an abnormal rate of increase or decrease in nuclear power occurs in two out of four power range channels.

Revision 52-09/29/2016 NAPS UFSAR 7.2-5a.Power range high positive neutron flux rate trip-The bi-stables associated with high positive flux rate trip for an abnormal rate of increase in nuclear power. The reactor is tripped when a high positive rate occurs in two out of the f our power range channels. This trip provides protection agains t rod ejection accidents of lo w worth from midpower and is always active.b.Power range high negative neutron flux rate trip-The bi-stables associated with high negative flux rate trip for an abnormal rate of decrease in nuclear power. The reactor is tripped when a high negative rate occurs in tw o out of the four power range channels. This trip provides protection agains t two or more dropped rods and is always active. Protection against one dropped rod is not required to pr event the occurrence of DNBR at full powerper the analysis in Section15.2.3.These channels of the react or trip system derive si gnals from the power range uncompensated ion chambers. In the nuclear instrumentation system, the rate sensorassembly is an operational amplifier unit that incorporates an adjustable lag network at one input and a nondelayed signal on the other. The unit compares the actual power signal with the delayed power signal received through the la g network and amplifies the difference. Thisamplified differential si gnal is delivered to two bi-stable units that trip when the level of thesignal exceeds a preset value. The bi-stable un its are the latching type to ensure that the necessary action, once initiated, will be carried to comple tion. The bi-stable outputs are provided to the solid-state protection syst em where the logic shown in Figure7.2-3 is performed to provide a reactor trip when abnormal nuclear power rates occur.

The operability of the rate trip functions as sociated with dropped rod and ejected rod protection is verified by the in troduction of a signal step change using the channel drawer test circuits. The time delay setting of the rate m odule is predetermined by analysis to correspond to 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 detailed functional 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 device but uses an additional bi-stable am plified in each protection channel.

Revision 52-09/29/2016 NAPS UFSAR 7.2-67.2.1.1.2Core Thermal Overpower Trips The specific trip functions generated are as follows:1.Overtemperature deltaT trip-This trip prot ects the core against low DNBR and trips the reactor on coincidence as listed in Table7.2-1 using one se t of temperature measurements per loop. The setpoint for this trip is continuously calculated by analog circuitry for each channel by solving the following equation:

(7.2-1)where:T setpoint = T reactor trip setpoint, °FT o = indicated T at full power (RTP), °F T avg = measured average reactor coolant temperature, °FT' = nominal average reactor coolant temperature at full power, °F P = measured pressurizer pressure, psig

K 1 = setpoint bias, dimensionless K 2 = constant based on the effect of temperature on the departure from nucleate boiling (DNB) limits, °F

-1 K 3 = constant based on the effect of pressure on the DNB limits, psig

-11 , 2 = time constants, sec s = Laplace transform variable, sec

-1 f 1 (q) = a function of the neutron flux difference between upper and lower long ionchambers, dimensionless. One power range channel separately feeds each overtemperature T trip channel. A non-zero f 1 (q) can only lead to a decrease in trip setpoint. Refer to Figure7.2-4.

The single pressurizer pressure parameter requ ired per channel is obtained from separate sensors that are connected to three pressure taps at the top of the pressurizer. This results in one 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 detailed functional description of the process equipment associated with this function is contained inReference3.2.Overpower deltaT trip-This trip protects against excessive power (fuel rod rating protection) and trips th e reactor on coincidence, as listed in Table7.2-1, with one set ofT setpointT o K 1 K 2 11 s+12 s+----------------

-T avg T'-()K 3 P 2235-()f 1q ()-+-=

Revision 52-09/29/2016 NAPS UFSAR 7.2-7 temperature measurements per l oop. The setpoint for each cha nnel is continuously calculated using the following equation:

(7.2-2)where:T setpoint = T reactor trip setpoint, °FT o = indicated T at full power (RTP), °F f 2 (q) = a function of the neutron flux diff erence between upper and lower long ion chamber section, dimensionless K 4 = a preset, manually adjustable bias, dimensionless K 5 = a constant based on the effect of rate of change of T avg on overpower T limit, °F

-1 K 6 = a constant based on the effect of Ta vg on overpower T limit, °F

-1T' = nominal average reactor coolant temperature at full power, °F

T avg = measured average reactor coolant temperature, °F3 = time constant, sec s = Laplace transform variable, sec

-1 The 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 th is 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 Trips The specific trip functions generated are as follows:1.Pressurizer low-pressure trip-T he purpose of this trip is to protect against low pressure, which could lead to a DNBR less than the de sign 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 meas urements fall below pr eset limits. This trip is blocked below P-7 to permit startup.The trip logic is shown in Figure7.2-6. A de tailed functional description of the processequipment associated with the function is contained in Reference3.2.Pressurizer high-pressure tri p-The purpose of this trip is to protect the reactor coolant system against system overpressure.T setpointT o K 4 K 53 s 13 s+----------------

-Tavg-K 6 Tavg T'-()-f 2q ()-=

Revision 52-09/29/2016 NAPS UFSAR 7.2-8The same sensors and transmitters used for the pressurizer low-pressure trip are used for the high-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. There are 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 Section3.11 for details concerning the environmental qualification of the pressurizer pressuretransmitters.3.Pressurizer high water level tr ip-This trip is provided as a backup to the high pressurizerpressure trip and serves to prevent water relief through the pressurizer safety valves. This trip is blocked below P-7 to permit startup.

The trip logic for this function is shown in Figure7.2-6. A detail ed description of the processequipment associated with this function is contained in Reference3.7.2.1.1.4Reactor Coolant System Low-Flow Trips These trips protect against a DNBR of less than the design limit in the event of a loss-of-coolant flow situation. The means of se nsing the loss-of-coolant flow are as follows:1.The parameter sensed is reactor coolant flow. Three elbow ta ps in each coolant loop are usedas a flow device that indicates the status of reactor coolant flow. The basic function of this device is to provide information as to whether or not a reducti on in flow rate has occurred.

An output signal from two out of the three bi-stables in a loop would indicate a low flow in that loop.

The detailed functional descripti on of the process equipment asso ciated with the trip functionis contained in Reference3.2.Reactor coolant pump bus undervoltage trip-Thi s 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 co nnected 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 th ese relays are time delayed to prevent spurious trips caused by short-term voltage perturbations.3.Reactor coolant pump bus underfrequency trip-Thi s trip is required to protect against lowflow resulting from bus underfrequency, fo r example, a major power grid frequency disturbance. The function of this trip is to trip the reactor for an underfrequency condition.

Revision 52-09/29/2016 NAPS UFSAR 7.2-9 There is one underfrequency sensing relay c onnected to each reactor coolant pump bus.

Signals from relays connected to any two of th e buses (time delayed to prevent spurious trips caused by short-term frequency perturbations) will directly trip the react or if the power level is above P-7.4.An additional input into this sensing system is provided by the reactor cool ant pump breakertrip-The opening of one or tw o reactor coolant pump breakers (depending on power level), which is indicative of an immine nt loss of coolant flow in that loop, or loops, will also cause a 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 fo r this function since other de-energize to trip logics providereactor trip on loss of coolant flow.Figure7.2-5 shows the logic for the react or coolant system low-flow trips.7.2.1.1.5Steam Generator Trips The 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 antici pated transient without scram(ATWS) mitigation system actuation circuitry (AMS AC). This system is operational when the C-20 permissive is satisfied by the unit being a bove 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 of tw o out of three steam generators is below the AMSA C setpoint and the C-20 permissive is satisfied, an AM SAC 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 RPS setpoint, providing certain criteria are met. The AMSAC trip is ti me delayed to allow the RPS to function prior to AMSAC action.

AMSAC trips the turb ine directly and tr ips the reactor by tripping the power feeder breakers for the rod control motor generator sets. Th is 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 Trip The turbine trip-reactor trip is actuated by either two-out-of-three logic from the low auto-stop oil pressure signals or by all closed signals from the turbine steam stop valves. A turbine trip causes a direct reactor trip above P-8. This is shown in Figure7.2-8.

Revision 52-09/29/2016 NAPS UFSAR 7.2-10In addition, an independent tu rbine trip may be actuated by the AMSAC. This system is operational when the C-20 permissive is satisfie d by the unit being above a specific power levelbased on turbine first stage pressure. When the narrow range steam generator level detected by two out of three channels on each of two out of three steam generators is below the AMSAC setpoint and the C-20 permissive is satisfied, an AMSAC trip can be generated. The AMSAC steam generator level can be the same as the RPS low-low level setpoint or may be set as much as 5% lower than the RPS setpoint, providing certain criteria are met. The AMSAC trip is time delayed to allow the RPS to f unction 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 le vel signals in two out of three channels for any steam generator will actuate a tu rbine trip, trip the main feedwater pumps, close the main and bypass feedwater control valves, and close the main feed line isolation valves. The purpose is to protect the turbine and steam piping from excessive moisture carryover caused by high-high steam generator 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 repres ented by dashed (---) lines.When the turbine is tripped, turb ine auto-stop oil pressure drops, which will be sensed by three pressure sensors. A digital output is provided from each sensor when the auto-stop oil pressure drops below a preset value. Th ese three outputs are transmitte d to two redundant two-out-of-three logic 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 of the turbine steam throttle valves. When all throttle valves are closed, a reactor trip signal will be initiated if the reactor is above P-8. This trip signal is generated by re dundant (two each) limit switches 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 actuating the 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 52-09/29/2016 NAPS UFSAR 7.2-11There 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 Times The 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 meas ured by means of any series of sequential, overlapping, or total steps so that the entire response time is m easured. In lieu of measurement, response time may be verified for selected components provide d that the components and methodology forverification have been previously reviewed and approved by the NRC.

The measured or verified cha nnel response times are compared with those used in the safetyevaluations. In accordance with Technical Specifications, the response times are required to be less than or equal to the times used in the safety analyses.7.2.1.3Reactor Trip System Interlocks7.2.1.3.1Power Escalation Permissives The overpower protection provide d by the out-of-core nuclear instrumentation consists of three discrete, but overlapping, levels. The cont inuation of startup opera tion or power increase requires 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 automatically reactivated and high voltage re stored when both intermediate range channels are below thepermissive (P-6) level. There is a manual reset switch for admini stratively reactivating the source range level trip and detector high voltage when between the permissive P-6 and P-10 level if required. Source range level trip block and high-voltage cutoff are always maintained when above the permissive P-10 level.The intermediate range level trip and power ra nge (low setpoint) trip can only be blocked after satisfactory operation and pe rmissive information are obtaine d 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 automatically reactivated when any three of the four power range channels are below the permissive (P-10) level, thus ensuring automatic activati on to more restrictive trip protection.

The development of permissi ves 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 and intermediate range channels.

Revision 52-09/29/2016 NAPS UFSAR 7.2-12See 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 appr oximately 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 undervo ltage, reactor coolant pump underfrequency, pressurizer lowpressure, or pressurizer high water level. See Figures7.2-5, 7.2-6 and7.2-8 for permissive applications. The low-power signa l is derived from three out of four power range neutron flux signals below the setpoint in co incidence with two out of two turbine impulse chamber pressure signals 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 se tpoint, the reactor will not trip with a turbine trip, or with one inactive loop. The reactor could be allowed to ope rate with one inactiveloop, provided Technical Specifica tions 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 Arrangement Three thermowell mounted resistance temperature detectors ar e installed in the hot leg of each loop near the inlet to the steam generator for reactor protection and control. One thermowell mounted resistance temperature dete ctor is installed in the cold leg of each loop at the discharge of 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 System The process analog system is described in Section7.7.1.11 and Reference3.7.2.1.7Digital Logic System The solid-state protection logic system takes binary inputs (voltage/no voltage) from the process and nuclear instrument channels corres ponding to conditions (nor mal/abnormal) of plantparameters. The system combines these signals in the required logic comb ination and generates a trip signal (no voltag e) to the undervoltage coils of the re actor trip circuit breakers when the necessary combination of signals occur. The system also provides annunciator, status light, and computer input signals, wh ich indicate the condition of bi-stabl e input signals, partial-trip and full-trip functions, and the status of the various blocking, permis sive, and actuation functions. In Revision 52-09/29/2016 NAPS UFSAR 7.2-13 addition, the system includes mean s for semi-automatic testing of the logic circ uits. A detaileddescription of this system is given in Reference4.7.2.1.8Isolation AmplifiersIn certain applications, Westinghouse consider s it advantageous to employ control signalsderived from individual protection channels th rough isolation amplifiers contained in the protection channel, as permitted by IEEE Std279-1971. In all of these cases, analog signals derived from protecti on channels for nonprotective functions are obtained through is olation amplifiers located in the analog protection racks. By definition, nonprotective functio ns include those signals used for control, remote process indication, 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 envi ronmental variations throughout which the systemwill perform are given in Section3.11.

7.2.1.10Trip Setpoints The setpoints that, when reach ed, will require trip action are given in the Technical Requirements Manual.

7.2.1.11Seismic Design The 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 wi thin a safe region bytripping the reactor whenever the limits of the region are approached. The safe operating region is defined by several considerations such as mechanical/hydraulic limitati ons on equipment and heat transfer phenomena. Therefore, the reactor trip system keeps surveillance on process variables that are directly related to equi pment mechanical limitations, such as pressure, pressurizer waterlevel (to prevent water discharge through safety valves) and also on variables that directly affect the heat transfer capability of the reactor (e.g., flow, reactor coolant temperatures). Still other parameters used in the reactor trip system are calculated from va rious process variables. In anyevent, whenever a direct process or calculated va riable exceeds a setpoint , the reactor will be shut Revision 52-09/29/2016 NAPS UFSAR 7.2-14 down to protect against either gros s 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 variable setpoints, most notably the overtemperature deltaT and overpower deltaT se tpoints. All setpoints in the reactor trip system have been selected either on the basis of applicable engineering coderequirements or engineering design studies. The capability of the r eactor trip system to prevent a loss 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 analys is (where appropriate) that uses this trip ispresented in Section7.2.2.1.2. It shoul d 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 Discussion It 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 core design can be determined as a function of the core inlet temp erature, power output, operatingpressure, and flow. Consequently, core safety limits in terms of a DNBR equa l to the limit value for 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 s hown as solid lines inFigure15.1-1 are the loci of conditions equivalent to 118% of power as a function of deltaT and T avg representing the overpower (kW/ft) limit on th e fuel. The dashed lines indicate the maximum permissible setpoint (deltaT) as a function of T avg and pressure for the overtemperature and overpower reactor trip. Ac tual setpoint constants in the equa tion representing the dashed lines are given 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 pro cess variables that determineDNB are sensed and evaluated. Small isolated changes in various process variable s may not,when considered singly, result in the violation of a core safe ty limit, whereas the individual variations, when operating together, over sufficient time, may cause the overpower or overtemperature safety limit to be exceeded. The design concept of the reactor trip system takes cognizance of this situation by pr oviding reactor trips associated wi th individual process variables in addition to the overpower/overtemperature safety limit trips. The process variable trips prevent reactor operation whenever a change in the monitored value is such that a core or system safety limit is in danger of being ex ceeded should operation continue. Basically, the high-pressure, low-pressure, and overpower/overtemperature deltaT trips provide sufficient protection for slow Revision 52-09/29/2016 NAPS UFSAR 7.2-15transients, as opposed to such trips as low flow or high flux, which will trip the reactor for rapid changes in flow or flux, respectively, that would result in fuel da mage 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 cha nge in a single variable will 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 ca use safety limits to be exceeded. Overall,the reactor trip system offers diverse and comprehensive prot ection 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 re actor trip system, and correlatesthem to the Technical Specificat ions and the appropriate accident discussed in the safety analyses in which the trip could be used.The nuclear power plant reactor trip system design employed by Westinghouse was evaluated 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 pe rformed on reactor trip syst em components and systems to determine equipment readiness for startup. This testing serves as a very re al evaluation of the system functional design.Analyses of the results of ConditionI, II, III, andIV events , including considerations of instrumentation installe d to mitigate their consequences, are presented in Chapter15. The instrumentation 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 automatically provides core protection during nonstandard operati ng configuration, that is, operation with a loop out of service. Although ope rating with a loop out of serv ice over an extended time is unlikely and is currently prohibited by the Technical Specifications , no protection system setpoints 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 de sign 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 high nuclear power reactor trip when operating with one loop not in se rvice. By first resetting thecoefficient setpoints in the overtemperature deltaT function to more restrictive values as wouldbe listed in the Technical Specifi cations, the P-8 setpoint could th en be increased to the maximum value consistent with maintaini ng DNBR above the design limit for ConditionII transients in the one-loop shutdown mode. The resetting of the deltaT overtemperature trip and P-8 would be carried out under prescribed admi nistrative procedures and only under the direction of authorized supervision.

Revision 52-09/29/2016 NAPS UFSAR 7.2-16The steam-line differential pressure signal is designed to provide a safety injection signal when the steam-line nonreturn valve closes following a ConditionIV steam-line break upstream of the nonreturn valve. If the nonr eturn valve fails to close follo wing a break upstream of it, thena high steam flow signal coincident with either low steam-line pressure or low-low Tavg would actuate safety injection, and the steam-line differential pressure signal is not required.The steam-line differential pre ssure logic will actuate safety injection if a ny 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 c ondition to provide safety injection if any one of the noniso lated loops has a steam pressure that is 100psi lower than the steam pressure in the remaini ng nonisolated loop. Therefore, the steam-line differential pressure signal possesses redundancy both with and without an isolated loop an d can accept a single failure in any channel without a loss of function.The steam-line differential pressure bi-stable status is cons tantly displayed on the main control 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 cont rol room if the proper bi-stabl es have been placed in the trip mode.

Even if the operator fails to place the proper bi-stables in the trip mode, the steam-linedifferential pressure system possesses redunda ncy unless the isolated steam generator isdepressurized.

The maximum rate of depre ssurization from natural heat losses would be less thanapproximately 12psi/hr; thus, it would be more than an hour before the depres surization couldsignificantly affect the operability of the differential pressure actuation signal. Faster depressurizations would result only following acci dent conditions in the isolated loop. The design basis does not require the consideration of an additional, nonconsequential accident in an operable loop following the first acci dent in the isolated loop.

The isolation of a primary reac tor coolant loop and the closure of the main steam stop valve in the isolated loop never cause a loss of function in the steam line differential pressure safety injection actuation system. Redundancy in this system is also maintained unless the operator permits the isolated loop steam gene rator to depressurize and fails to trip the proper bi-stables in spite of the fact that he:1.Has specific operating instructio ns 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 52-09/29/2016 NAPS UFSAR 7.2-17 In 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 Measurement The elbow taps used on each loop in the primar y coolant system are instrument devices thatindicate the status of the reactor coolant flow.

The basic function of this device is to provide information as to whether or not a reduction in flow rate has o ccurred. The correlation betweenflow rate and elbow tap signal is given by the following equation:

(7.2-3)where P o is the pressure differential at the referenced flow rate, w o , andP is the pressuredifferential at the corresponding flow rate, w. The full-flow refere nce point was established during initial plant startup. The low-flow trip point was then establis hed by extrapolating along the correlation curve.The expected absolute accuracy of the channel is within

+/-10%, and field results have shown the 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 Std279-1971 The 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 de signed to provide redundant (one out of two, two out of three, or two out of four) instrumentation chan nels for each protective function and one-out-of-two logi c train circuits. These redundant channels an d trains areelectrically isolated and physically separated. Thus, an y single failure within a channel or train will not prevent protective action at the system level when requ ired. This design meets therequirements of General Design Criterion21. A loss of input power, the most likely mode of failure, to a channel or logic train will result in a signal calling for a trip. This design also meets the requirements of General Design Criterion23.To prevent the occurrence of common-mod e failures, such a dditional measures asfunctional diversity, physical separation, and te sting, as well as admin istrative control during design, 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 Co mponents and Modules.

For a discussion of the quality of the components and modules used in the reactor trip syst em, refer to Chapter17. The quality used also meets the requirements of General Design Criterion1.PP o---------w w o------2=

Revision 52-09/29/2016 NAPS UFSAR 7.2-187.2.2.2.1.3Equipment Qualification.

For a discussion of the type tests made to verify the performance requirements, refer to Section3.11. The test results al so demonstrate that the design meets the requirements of Criterion4 of the GDC.7.2.2.2.1.4Independence.

Channel independence is carried throughout the system, extending from the sensor through to th e devices actuating the protective function. See Figure7.2-12.

Physical separation is used to achieve the separation of redundant transmitters. The separation of wiring is achieved by using sepa rate wireways, cable trays, conduit runs, a nd containment penetrations for each redundant channel. Redundant analog equi pment is separated by locatingmodules in different protection r ack sets. Each redundant channel is energize d from a separate ac power feed. This design also meets the requirements of General Design Criterion21.

The independence of the logic trains is discussed in Reference4. Two reactor trip breakers are actuated by two separate logic matrices th at interrupt power to the control rod drivemechanisms. The breaker main contacts are connec ted 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 this diversity has been evaluated for a wide variety of postulated accidents and is discussed in Reference1. Generally, two or more diverse pr otection functions would terminate an accident before intolerable consequences could occur. This design also me ets the requirements of GeneralDesign Criterion22.7.2.2.2.1.5Control and Protection System Interaction.

The protection system is designed to be independent of the control syst em. In certain applications, the control signals and other nonprotective functions are derived from indivi dual protective channels through isolation amplifiers. The isolation amplifiers are classified as part of the protection system and are located in the analog protective racks.

Nonprotective functions include those signals used for control, remote process indication, and computer monito ring. The isolation amplifiers are designed such that a short circuit, open circuit, or the application of 120Vac or 140V dc 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 never returned to the protective racks. This design also meets the requirements of General DesignCriterion24.

A detailed discussion of the de sign and testing of the isolat ion amplifiers is given inReferences5 and6. These report s include the results of appl ying various malfunction conditions on the output portion of the isolation amplifiers. The results sh ow that no significant disturbance to the isolation amplifie r input signal occurred.

Revision 52-09/29/2016 NAPS UFSAR 7.2-19 In addition to the fault tests on the isolation amplifiers, system tests on the nuclear instrumentation system (NIS), the solid state protection sy stem (SSPS), and the 7300Seriesprocess control system (7300PCS) have been conducted by Westinghouse. These tests have demonstrated that credible externally applied electrical faults or interference, which could be postulated to be propagated ba ck into redundant instrument and control prot ection cabinets, would not prevent these systems from performing their safety f unctions (or cause their spurious actuation).

The NIS and SSPS system test s 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 te sts are reported inReference9, the conclusions having been accepted by the NRC for the NorthAnna PowerStation.Where failure of a protection sy stem component can cause a pr ocess excursion that requires protective action, the prot ection system can withstand another, independent failure without loss of protective action. This design also meets the requirements of General Design Criterion24. 7.2.2.2.1.6Capability for Testing.

The reactor trip system is ca pable of being tested during power operation. When only parts of the system are tested at a ny 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 action unless a trip condition actually exists. This is because of the coincidence logic required for reactortrip. Note, however, that the source and interm ediate range high-neutron-flux trips must be bypassed during testing.The operability of the process sensors is ascertained by comparison with redundant channels 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 perf ormed at the analog instrument ation rack set by individually introducing simulated input signals into the inst rumentation channels and observing the tripping of the appropriate output bi-sta bles. Process analog output to th e logic circuitry is interrupted during individual channel test by a test switch that, when thrown, de-energizes the associated logic input and inserts a proving lamp in the bi-stable output. The interru ption of the bi-stable output to the logic circuitry for any cause (test, maintenance pur poses, or remove d from service)will cause that portion of the logic to be actuated (partial trip), accompanied by a partial trip alarm and channel status light actuation in the control room. Each channel contains those switches, testpoints, etc., necessary to te st the channel. See Reference3 for additional information.

The power range channels of the nuclear instrumentati on system may be tested by superimposing a test signal on the actual detector signal being rece ived by the channel at the time Revision 52-09/29/2016 NAPS UFSAR 7.2-20 of 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 not required.To test a power range channel, a TEST-OPERATE switch is provided to require deliberate operator action. Operat ion of the switch will initiate the CHANNEL TEST ann unciator in the control room. Bi-stable operation is tested by increasing th e 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 vali d trip signal would ca use the channel under test to trip at a lower actual reactor power level.

A reactor trip would occur wh en a second bi-stable trips. No specific provision has been made in the channel test circuit for reducing the channel signal level below 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 prevents the initiation of a reactor trip from that particular channel duri ng 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 cont rol room to indicate wh en 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 disc ussion of compliance toSafety Guide22.

The reactor coolant pump break ers cannot be tripped at power without causing a plant upsetby loss of power to a coolant pump. However, the reactor coolan t pump breaker open trip logiccan be tested at power. Ma nual trip cannot be tested at power without causing a r eactor trip since operation of either manual trip switch actuates both trainA and trainB. Initiating safety injection or opening the turbine trip br eakers 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 incl udes a check of the input relays and a logic matrix check. The following sequence is used to test the system:

1.Check of input relays

-During testing of th e process instrumentation system and nuclear instrumentation system channels , each channel bi-stable is place d in a trip mode, causing oneinput relay in trainA and one in trainB to de-energize. A cont act of each relay is connected to a universal logic printed circuit card. Th is card performs both the reactor trip and monitoring functions. The contact that creates the reactor trip also causes a status lamp and an annunciator on the control board to operate. Either the trainA or trainB input relayoperation will light the status lamp and annunciator.

Revision 52-09/29/2016 NAPS UFSAR 7.2-21 Each train contains a multiplexing test switch. At the start of a process or nuclear instrumentation system test, this switch (in either tr ain) is placed in the A + B position. The A + B position alternately allo ws information to be transmitted from the two trains to thecontrol board. Status lamps and annunciators indi cate that input relays in both trains havebeen de-energized. Contact inputs to the logi c protection system, such as reactor coolant pump bus underfre quency relays, operate input relays , which are tested by operating theremote contacts as described above and using the same type of indications as those provided for bi-stable input relays.

The actuation of the input rela ys provides the overlap betw een the testing of the logic protection system and the testi ng of those systems s upplying the inputs to the logic protectionsystem. Test indications are st atus lamps and annunciators on th e control board. Inputs to thelogic protection system are checked one channe l at a time, leaving the other channels in service. For example, a function that trips the reactor when two out of four channels trip becomes a one-out-of-three trip when one channe l is placed in the trip mode. Both trains of the logic protection system remain in service during this portion of the test.

2.Check of logic matrices

-Logic matrices are checked one trai n at a time. Input relays are not operated during this portion of the test. Reactor trips from the tr ain being tested are inhibited with the use of the i nput error inhibit switch on the semi automatic test panel in the train.Details of semiautomatic tester operation are given in Reference4. At the completion of the logic matrix tests, one bi-stable in each channel of process inst rumentation or nuclear instrumentation may be tripped to check closur e of the input error i nhibit switch contacts.

The logic test scheme uses pul se techniques to check the coin cidence logic. All possible trip and nontrip combinations are check ed. Pulses from the tester ar e applied to the inputs of the universal logic card at th e same terminals that connect to th e input relay cont acts. Thus, there is an overlap between the input relay check and the logic matr ix check. Pulses are fed backfrom the reactor trip breaker undervoltage coil to the tester. The pulse s are of such shortduration that the reactor tr ip breaker undervoltage coil armature cannot respondmechanically.

Test indications that are pr ovided are an annunciator in th e 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 ma trix test. Protection capability provided during this portion of th e test is from the train not being tested.

The general design features and details of the testability of th e logic system are described inReference4. The testing capability meets th e 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 inte rvals. Although pulse techniques are used in Revision 52-09/29/2016 NAPS UFSAR 7.2-22 protection 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 tr ip 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 to automatically trip the breakers.

An automatic shunt trip relay was installed which deenergizes ona reactor trip signal and energizes the shunt trip attach ment to trip the breaker. The automaticshunt trip relay, test pushbuttons, and test jack connectors are loca ted on a panel installed into thereactor trip breakers instrument compartment.Test jack connectors and pushbutt ons are provided to test the automatic shunt trip devicesand to verify breaker operations and response time.

Approved station procedures desc ribe the method used to test reactor trip breaker operationthrough the shunt trip relay.

Auxiliary contacts of the bypass breakers are connected into thei r respective trains such that if either train is placed in test while the bypass breaker of the othe r train is closed, both reactor trip breakers and both bypass breakers will automatically trip.

Auxiliary contacts of the bypass breakers are c onnected in such a way that if an attempt is made to close the bypass breaker in one train while the bypass breaker of the other train is already closed, both bypass breakers wi ll automatically trip.The trainA and trainB alarm systems operate separate annunciators in the control room.

The two bypass breakers also ope rate an annunciator in the control room. Bypassing of a protection train with either the bypass breaker or with the test sw itches will result in audible and visual indications.

Revision 52-09/29/2016 NAPS UFSAR 7.2-237.2.2.2.1.8Bypasses.

Where operating requirements necessitate automatic or manual bypass ofa protective function, the design is such th at the bypass is remove d automatically whenever permissive conditions are not met. Devices used to achieve au tomatic removal of the bypass of a protective function are considered part of the pr otective system and are designed in accordance with the criteria of this secti on. Indication is provided in the cont rol 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, multip le setpoints are used. When amore restrictive trip setting becomes necessary to provide adequate pr otection for a particular mode of operation or set of oper ating conditions, the protective system circuits are designed to provide positive means or administra tive control to ensure that the more restrictive trip setpoint is used. The devices used to prevent improper use of less restrictive trip settings are considered part of 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, once initiated, a protective action goes to completion. Return to norma l operation require s action by theoperator.

7.2.2.2.1.11Manual Initiation.

Switches are provided on the control board for manual initiation of protective action. Failure in the automatic syst em 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 administrativ e control of access to all setpoint adjustments, module ca libration adjustments, testpoints, and the means for manually bypassing channels or protective functions. For details refer to Reference3.7.2.2.2.1.13Information Readout.

The reactor trip system provides the operator with complete information pertinent to system status and safety. All transmitted signals (flow, pressure,temperature, etc.) that can cause a reactor trip ar e 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 are indicated and iden tified down to the channel level.

Alarms and annunciators are also used to alert the oper ator of deviations from normal operating conditions so that he may take appropriate corrective action to a void a reactor trip. The actuation of any rod stop or th e trip of any reactor trip ch annel will actuate an alarm.7.2.2.2.1.14Identification.

The identification described in Section7.1 provides immediate and unambiguous identification of the protection equipment.

Revision 52-09/29/2016 NAPS UFSAR 7.2-247.2.2.2.2Evaluation of Compliance with IEEE Std308-1971 (Reference10)See Section7.6 and Chapter8 for a discu ssion 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 equi pment is type tested to substantia te the adequacy of design. This isthe preferred method, as indicated in Reference11.Most Westinghouse-supplied elec trical equipment essential to safe shutdown was qualifiedbefore the issuance of IEEE Std323-1971. For this reason, the format of te st documentation is notas listed in Section5.2 of Reference11. The testing and documen tation 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 re ferences, 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 electrica l penetrations and co mpliance 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 disc ussion of compliance with IEEEStd336-1971.

Revision 52-09/29/2016 NAPS UFSAR 7.2-257.2.2.3Specific Control and Protection Interactions7.2.2.3.1Neutron FluxThe flux difference between th e upper and lower long ion chambe rs from three of the four power range neutron detectors is used as inputs to the overtemperature deltaT and overpowerdeltaT setpoints. The is olated neutron flux output signal from the fourth channel is used for automatic rod control.

In addition, a deviati on signal will give an alarm if any neutr on flux channel deviates significantly from any of the ot her channels. Also, the control sy stem will respond only to rapid changes in indicated ne utron flux; slow change s or drifts are compen sated by the temperaturecontrol signals. Finally, an overpower signal fro m any intermediate or power range nuclear channel will block manual and automatic rod withdr awal. The setpoint for this rod stop is below the reactor trip setpoint.7.2.2.3.2Coolant Temperature The delta-T and Tavg signals developed in the react or protection system for the overtemperature delta-T and overpow er delta-T reactor trips also pr ovide 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 pr opagating back into the protection channels.

In the control system, the delta-T and T avg signals from each of the th ree protection channels are sent to the median signal select or (MSS) auctioneeri ng circuits. The MSS is designed to preventthe failed protection system delta-T or T avg signal from precipitating an inaccurate control system response. Under normal operating conditions with no failures in a ny reactor coolant system (RCS) narrow range temperature instrument channel, the MSS will reject both the highest and the lowest of the three channels received and pass to the control system only the signal whose value falls between 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 deviation between the two is detected, at wh ich point the median signal will be passed to the control system as discussed above. If one of the three inputs should deviate si gnificantly from normal (i.e., -3°F for 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 hi gher of the remaining two valid inputs for reactor control. Th e use of the MSS circuits in the reactor control system satisfies the Control and Protection System interaction requirements of IEEE Std279-1971, and prevents aspurious low temperature signal from causing rod withdrawals.

In addition, channel deviation si gnals in the control system will give an alarm if any temperature channel deviates significantly from the auctioneered (median) value. Automatic rodwithdrawal blocks will also occur if any two of the temperature channels indicate an overtemperature or overpower condition.

Revision 52-09/29/2016 NAPS UFSAR 7.2-26Two hot leg temperature indications are available at the Auxi liary Monitoring Panel. One ofthem is installed with a specific separation from the additional temperatur e indication available in the control room. This separation meets 10CFR50 AppendixR SectionIII.G.2.7.2.2.3.3Pressurizer PressureNorthAnna uses separate transmitters for pressurizer pressure protection and control functions. There are three transmitt ers used to provide inputs to three protection channels. Thereare two additional transmitters used for reactor coolant pressure control functions. The protection channels provide high- and lo w-pressure protecti on, 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 cause decreasing pressure by the actu ation of either spray or relie f valves. Additional redundancy is provided in the low pressurizer pressure reactor trip logic and in the logic for safety injection to ensure low-pressure protection.

An additional pressurizer pressu re indication is avai lable at the Auxili ary Monitoring Panel and is installed with a specific separation from the additional pressuri zer pressure indication available 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 tr ip. Isolated signals from these channels are used for pressurizer water level control. A failure in the water level control system could 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 ambien t temperature. This temperature will vary somewhat over the le ngth of the reference leg piping under normal operating conditions but will not exceed 140°F. During a blowdow n accident, any reference legwater-flashing to steam will be confined to the condensate-steam interface in the reference leg at the top of the temperature barrier leg and will have only a small (about 1inch) effect on measured level. 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 can accumulate in the upper part of the reference leg of the pressurizer water level instruments. At reactor coolant system pressures, high concentrations of dissolved hydrogen in the water of the reference leg are possible. It ha s been hypothesized that a sudden primary system depressurizationwould cause rapid effervescence of the dissolved hydrogen in the water of the reference leg. This phenomenon could blow out the reference leg, creating a large er ror in measured pressurizer level.Accurate calculations of this effect have been difficult to obtain. Thus, the effect of a suddenprimary system depressuri zation on the pressurizer high level reactor trip is to generate a reactor trip somewhat below the actual pr essurizer high-level trip setpoint. To gene rate a high pressurizer Revision 52-09/29/2016 NAPS UFSAR 7.2-27level 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 trip or safety injection. It should be noted that the relatively large erro r caused by the rapid depressurization is of a transi ent nature due to the ongoing co ndensation process within the reference 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 th e reference leg to atmosphere w ill be immediately detectable byoff-scale indication and alarms on the control board. Small leaks are de tectable by deviations from other channels. A closed pr essurizer level instrument shutof f valve would be detectable by comparing the level indications from the redundant channels (three channels). A control room alarm is installed to indicate an error between measured pressurizer water level and the programmed pressurizer water level. There is no single instrument valve which could affect more than one of the three channels.A pressurizer water level indica tion is available at the Auxi liary Monitoring Panel and isinstalled with a specific separation from the addition pressuri zer water level indication available in the control room. This separation meets 10CFR50 AppendixR SectionIII.G.2.7.2.2.3.5Steam Generator Water Level and Feedwater Flow The basic function of the reactor protection ci rcuits associated with low steam generator water level and low feedwater flow is to preserve the steam gene rator heat sink for the removal of long-term residual heat. Should a complete loss of feedwater occur, the reactor would be tripped on low-low steam- genera tor water level. In addition, redu ndant auxiliary feedwater pumps areprovided to supply feed water to maintain residual heat re moval 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 genera tors are dry to reduce the required capacity andstarting time requirements of these auxiliary feedwater pumps and to minimize the thermal transient on the reactor coolant system and steam generators.

Therefore, the low-low steamgenerator water level reactor trip circuit is provided for each steam genera tor 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 chan nels are input to the control system and compared by the MSS. The MSS sel ects the median signal fo r use by the controlsystem. By rejecting the high and low signals, the MSS prevents the control system from acting on any single failed protection syst em instrument channel. Since no adverse control system action may now result from a single, failed protection instrument ch annel, a second random protection system failure (as would otherw ise be required by IEEE-279) ne ed not be cons idered. Signals resulting from a single failed high or low SG le vel channel will be rejected for control purposes Revision 52-09/29/2016 NAPS UFSAR 7.2-28and, therefore, will not affect the system. The MSS eliminates the cont rol and protection system interaction mechanism.

The isolation devices separating the low-low steam generator water level protection channels and the MSS of the steam generator water level co ntrol system perform the isolation function between the control and protection systems.The control room recorders used to meet Regulatory Guide1.97 requ irements described in section 7.5 for steam generator narrow range water level, st eam flow rate, and feedwater flow rate will 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 wi ll eventually trip on a low-low water level signal independent of indicated feedwater flow.A mismatch between steam flow and feedwater fl ow that results in a rising steam generatorwater level would actuate alarms to alert the operator of the situa tion in time for manual correction.

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 cause feedwater 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 incorpor ates reset action on the level error signal, such that with expected controller settings a rapid increase or decrease in the flow signal would cause only a small ch ange in level before the controller would compensate for thelevel error. A slow change in the feedwater signal would have no ef fect at all. A spurious low or high 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 is satisfied by the unit being above a specific power level based on turbine first stage pressure.

When the narrow range steam gene rator level detected by two out of three channels on each oftwo out of three steam generato rs is below the AMSA C setpoint and the C-20 permissive is satisfied, an AMSAC trip can be generated. Further desc ription of the C-20 se tpoint and its basisis provided in Section7.7.1.14. The AMSAC steam ge nerator level can be the same as the RPSlow-low level setpoint or may be set as much as 5% lower than th e RPS setpoint, providingcertain criteria are met. The AMSA C trip is time delayed to allo w the RPS to function prior to AMSAC action. AMSAC trips the turbine, trips th e reactor by tripping the power feeder breakersfor the rod control motor generator sets, isolates the sample and blowdown lines, and start all auxiliary feedwater pumps. This logic is shown in Figure7.2-13.

Revision 52-09/29/2016 NAPS UFSAR 7.2-297.2.3Tests and Inspections The reactor trip system meets the testing requirements of Reference13 with the exceptionsgiven in Section7.2.2.2.5. The test ability of the system is discussed in Section7.2.2.2.1. Test intervals are specified in the Technical Specifications.7.2.3.1Inservice Tests and Inspections Periodic surveillance of the reactor trip system is perf ormed to ensure proper protective action. This surveillance c onsists of checks, calibrations, a nd 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 Nu clear Instrumentation System Periodic 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 in accordance with the established calibration and troubleshooting procedures provided in the PlantTechnical Manual for the nuclear in strumentation system. Protection trip and permissive interlocksettings are indicated in the Te chnical Requirements Manua

l. 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 cha nnels of the protection circuits are performed as specified inthe Technical Specifications.

7.2.3.4Safety Guide22 Periodic testing of the reactor trip system actuation functions, as de scribed, complies withAEC Safety Guide22, Periodic Testing of Protection System Actuation Functions

,February1971. Under the present de sign, there are protection functi ons that are not tested atpower. These are as follows:1.Generation of a reactor trip by tri pping 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 52-09/29/2016 NAPS UFSAR 7.2-30 The 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 equipment is, and can be mainta ined, acceptably low without test ing the equipmen t during reactor operation.3.The equipment can routinely be test ed when the reactor is shut down.

Where the ability of a system to respond to a bona fide accident si gnal is intentionally bypassed for the purpose of performing a test during reactor operation, each bypass condition is automatically indicated to the r eactor operator in the main contro l room by a separate annunciatorfor the train in test. Test circuitry does not allow tw o trains to be tested at the same time, so that extension of the bypass condition to redundant systems is prevented. See Section7.2.2.2.1 for details of testing the channels and trains of the reactor trip system.

7.2REFERENCES

1.T. W. Burnett, Reactor Protection System Diversity in Westinghouse Pressurized Water Reactors, 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 Instrumentat ion Isolation Amplifier WestinghouseComputer and Instrumentation Division Nucana 7300Series , WCAP-7862,September1972.6.J. B. Lipchak and R. R. Bartholomew, Test Report Nuclear Instrume ntation System Isolation Amplifier , 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 52-09/29/2016 NAPS UFSAR 7.2-318.The Institute of Electrical a nd 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 El ectrical and Electroni c 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 El ectrical and Electroni c Engineers, Inc., IEEE Trial-Use Guide for TypeTests of Continuous-Duty ClassI Motors Insta lled Inside the Containm ent 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 Electrical Penetration 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 Anal ytical 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 52-09/29/2016 NAPS UFSAR 7.2-32Table7.2-1LIST OF REACTOR TRIPSReactor TripCoincidence LogicInterlocksComments1.High neutron flux (power range)2/4Manual block of low setting permitted by P-10 High and low settings; manual block and automatic reset of low setting by P-10.2.Intermediate range1/2Manual block permitted by P-10Manua l block and automatic reset.3.Source range neutron flux1/2M anual block permitted by P-6, interlocked with P-10 Manual 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 52-09/29/2016 NAPS UFSAR 7.2-3314.Reactor coolant pump bus under-frequency2/3Interlocked with P-7Underfre quency on two buses will cause reactor trip; reactor trip blocked below P-7.15.Low-low steam generator water level 2/3 per loop No Interlocks Blocked for a loop in which the primary coolant stop valves are closed.16.Safety injection signalCoincident with actuation of safety injection No Interlocks (See Section 7.3 for engineered safety features actuation conditions.)17.Turbine-generator trip2/3Interlo cked with P-8Blocked below P-8.a.Lowauto-stopoilpressur eb.Turbine stop valve close4/4 Interl ocked 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 delay Interlocked with C-20 Blocked 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 52-09/29/2016 NAPS UFSAR 7.2-34Table7.2-2REACTOR TRIP SYSTEM ACCURACIES AND RANGESReactor Trip SignalTrip Accuracy See 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 actuation not a pplicable - digital input from ESF17.Turbine-generator trip:a.Low auto-stop oil pressure not required(a, b)b.Turbine stop valves closed not required(a, b)18.Manual reactor trip not required(a, b)19.General warning not 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 flux 0 to 120% power2.Intermediate range high neutron flux10-11 to 10-3 amperes(a)3.Source range high neutron flux 10 0 to 10 6 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 52-09/29/2016 NAPS UFSAR 7.2-356.Overtemperature T:Trip setpoint 0 to 150% power T hot 530 to 650°F T cold 510 to 630°F T avg 530 to 630°FPressurizer pressure1700 to 2500psig F(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 Accuracy See 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 52-09/29/2016 NAPS UFSAR 7.2-36Table7.2-3REACTOR TRIP SYSTEM INTERLOCKSDesignationDerivation Function Power Escalation PermissivesP-61/2 neutron flux (intermediate range) above setpoint Allows manual block of source range reactor trip 2/2 neutron flux (i ntermediate range) below setpoint Defeats the block of source range reactor tripP-102/4 neutron flux (power range) above setpoint Allows manual block of power range (low setpoint) reactor trip Allows 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

setpoint Defeats the block of power range (low

setpoint) reactor trip Defeats 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 setpoint Blocks 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 setpoint Input to P-7 Revision 52-09/29/2016 NAPS UFSAR 7.2-37Table7.2-4TRIP CORRELATIONTrip AccidentTechnicalSpecification1.Source range, high neutron flux15.2.11)Uncontrolled RCCA bank withdrawal from a subcritical conditionYes2.Intermediate range, high neutron flux 15.2.11)Uncontrolled RCCA bank withdrawal from a subcritical conditionYes a3.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 conditionYes 15.2.22)Uncontrolled RCCA bank withdrawal at power 15.2.63)Startup of an inactive reactor coolant loop 15.2.74)Loss of external electrical load and/or turbine trip 15.2.105)Excessive heat removal due to feedwater system malfunction15.2.116)Excessive load increase 15.2.137)Accidental depressurization of the main steam system5.Power range high positive neutron flux rate 15.4.6 Rod ejectionYes a6.Power range high negative neutron flux rate 15.2.31)RCCA misalignmentYes7.Overpower delta T15.2.21)Uncontrolled RCCA bank withdrawal at powerYes 15.2.102)Excessive heat removal due to feedwater system malfunctiona.Credit not taken for trip for reasons of conservatism in the safety analyses.

Revision 52-09/29/2016 NAPS UFSAR 7.2-387.Overpower delta T (continued)15.2.113)Excessive load increase 15.2.134)Accidental depressurization of the main steam system8.Overtemperature delta T15.2.21)Uncontrolled RCCA bank withdrawal at powerYes 15.2.42)Uncontrolled boron dilution 15.2.73)Loss of external electrical load and/or turbine trip 15.2.104)Excessive heat removal due to feedwater system malfunction15.2.115)Excessive load increase 15.2.126)Accidental depressurization of the RC system 15.2.137)Accidental depressurization of the main steam system9.Low primary coolant flowa.Undervoltage 15.2.51)Partial loss of forced reactor coolant flowYesb.Underfrequencyc.Low flow or pump breaker open 1 of 3 loops 15.2.92)Loss of offsite power to the station auxiliaries (station blackout)d.Low flow or pump breaker open 2 of 3 loops 15.3.43)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 52-09/29/2016 NAPS UFSAR 7.2-3910.Pressurizer high pressure (continued) 15.2.72)Loss of external electrical load and/or turbine trip 15.4.2.23)Main feedline break11.Pressurizer high water level15.2.21)Uncontrolled RCCA bank withdrawal at powerYes 15.2.72)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 feedwaterYes 15.4.2.22)Main feedline breakTable7.2-4(continued)TRIP CORRELATIONTripAccidentTechnicalSpecificationa.Credit not taken for trip for reasons of conservatism in the safety analyses.

Revision 52-09/29/2016 NAPS UFSAR 7.2-40Table7.2-5REACTOR TRIP SYSTEM INSTRUMENTATION Functional UnitChannels to Trip Minimum Channels Operable1.Manual Reactor Trip 1 2 122.Power Range, Neutron Flux 2 33.Power Range, Neutr on Flux, High Positive Rate 234.Power Range, Neutron Flux, High Negative Rate 235.Intermediate Range, Neutron Flux 1 26.Source Range, Neutron Fluxa.Startup 1 2b.Shutdown 1 2c.Shutdown (Indication only) 0 17.Overtemperature T2 28.Overpower T2 29.Pressurizer Pressure-Low 2 210.Pressurizer Pressure-High 2 211.Pressurizer Water Level-High 2 212.Loss of Flow-(Above P-7) 2/loop in any loop >P-8 2/loop in each loop 2/loop in any 2 loops >P-713.Steam Generator Water Level-Low-Low2/loop 2/loop14.Undervoltage-Reactor Coolant Pump Busses2 215.Underfrequency-Reactor Coolant Pump Busses 2216.Turbine Tripa.Low Auto Stop Oil Pressure 2 2b.Turbine Stop Valve Closure 4 317.Safety Injection Input from ESF 1 218.Reactor Coolant Pump Breaker Position Trip Above P-71>P-8 2>P-7 1/breaker 19.a.Reactor Trip Breakers 12b.Reactor Trip Bypass Breakers 1 120.Automatic Trip Logic 1 221.Reactor Trip System Interlocks Revision 52-09/29/2016 NAPS UFSAR 7.2-41a.Intermediate Range Neutron Flux, P-6 1 2b.Low Power Reactor Trips Block, P-7 P-10 Input 2 3 or P-13 Input 1 2c.Power Range Neutron Flux, P-8 2 3d.Power Range Neutron Flux, P-10 2 3e.Turbine Impulse Chamber Pressure, P-13 1 2Table7.2-5(continued)REACTOR TRIP SYSTEM INSTRUMENTATION Functional UnitChannels to Trip Minimum Channels Operable Revision 52-09/29/2016 NAPS UFSAR 7.2-42 FIGURE 7.2-1INDEX AND SYMBOLS Revision 52-09/29/2016 NAPS UFSAR 7.2-43 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-44 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-45 FIGURE 7.2-4SETPOINT REDUCTION FUNCTION FOR OVERTEMPERATURE T TRIPS (TYPICAL)

Revision 52-09/29/2016 NAPS UFSAR 7.2-46 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-47 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-48 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-49 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-50 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-51 FIGURE 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 52-09/29/2016 NAPS UFSAR 7.2-52FIGURE 7.2-11 PRESSURIZER REFERENCE LEG LEVEL SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.2-53 FIGURE 7.2-12 DESIGN TO ACHIEVE ISOLATION BETWEEN CHANNELS Revision 52-09/29/2016 NAPS UFSAR 7.2-54 FIGURE 7.2-13ANTICIPATED TRANSIENT WITHOUT SCRAM MITIGATION SYSTEM ACTUATION CIRCUITRY (AMSAC)

Revision 52-09/29/2016 NAPS UFSAR 7.3-17.3ENGINEERED SAFETY FEATURES ACTUATION SYSTEM Electrical schematic diagrams for the engineer ed safety features (ESF) actuation system, ESF actuator circuits, and their supporting sy stems are included in reports NA-TR-1001 and NA-TR-1002, Safety Related Electrical Schematics, dated May10,1973, which were submittedto the Atomic Energy Commission (AEC) on May18,1973, as sepa rate documents. For general notes, diagram symbols, and terminology, refer to Reference Drawings1 through4.7.3.1Description The ESF actuation system senses selected pl ant parameters, determines whether or not predetermined safety limits are being exceeded and, if they are, combines the signals into logic matrices sensitive to combinations indicative of primary or secondary system boundary ruptures(ClassIII orIV faults).

Once the required logi c combination is completed, the system sendsactuation signals to those ESF actuation devices whose aggregate function best serves the requirements of the accident.

The design meets the requirements of General Design Criteria13, 20, 21, 22, 23, and24.

7.3.1.1 Functional 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 single dump, 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 52-09/29/2016 NAPS UFSAR 7.3-22.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 (T avg).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 portion consisting of redundant channels that monitor vari ous plant parameters such as the reactor coolantsystem and steam system pressures, temperatures, and flows, a nd containment pressures; and a digital portion consisting of tw o redundant logic trains that receive inputs from the analogprotection channels and perform the needed logic to actuate th e ESF actuation devices. Eachdigital train can actuate the mini mum ESF actuation devices required.

The intent is that any single failure 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. The separation of redundant analog channels begins at the pr ocess sensors and is maintained in the field wiring, containment vessel penetrations, an d analog protection racks, terminating at theredundant groups of ESF logic racks. The design meets the requirements of General DesignCriterion21.Section7.2 provides further de tails on protective instru mentation. The same design philosophy applies to both system s and meets the requirements of General Design Criteria20, 21,22, 23, and24.

Revision 52-09/29/2016 NAPS UFSAR 7.3-3The variables are sensed by the analog circ uitry as discussed in Reference1 and inSection7.2. The outputs from the analog channels are combined in to 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 and the 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 to the recirculation phase after a LOCA.7.3.1.1.2Devices Requiring Actuation The following are the actions th at the ESF actuation system initiates when it is called on to perform its function:1.Safety injection.2.Reactor trip.3.Feedwater line isolation.4.Auxiliary feedwate r 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 th at 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 measur ement is negated by taking multiple samples from the reactor coolant hot leg. The outputs from th ree hot leg resistance temperature detectors(RTDs) are summed and averaged to obtain a repr esentative hot leg temperature value for a given loop.The parameter values that will require pr otective action are given in the TechnicalSpecifications.

Revision 52-09/29/2016 NAPS UFSAR 7.3-4The malfunctions, accidents, or other unusual events that could physically damage protection system components or could cause environmental ch anges 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 reactor trip breakers and control and latching mech anisms, although the reactor trip (or ESFactuation signal) theoretically occurs before or simultaneous ly with ESF sequence initiation(see Figure7.2-9).Maximum allowable time delays in generating the actuation si gnal for accident protectionare listed in the Technical Requirements Manual.2.System accuracies (Reference12)-Accuracies required for generating the required actuation signals for loss-of-coolant protection are:a.Pressurizer pressure 16.4psi to +25.42psib.Containment pressure

+/-3.7% of full scaleAccuracies required in generating the required actuation signals for steam-line break protection are:a.Steam-line pressure

+/-11.1% of spanb.Steam flow signals

+/-20% P span over the range of 0% to 110% full steam flowc.Containment pressure signal

+/-3.7% of full scale Revision 52-09/29/2016 NAPS UFSAR 7.3-53.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-coolant protection are:a.Pressurizer pressure1700 to 2500psigb.Containment pressure0 to 65psia Ranges required in generating th e required actuation signals fo r steam-line break protection are:a.T avg 530°F to 630°Fb.Steam-line pressure0 to 1400psigc.Steam-line flow0 to 120% maximum steam flowd.Containment pressure0 to 65psia 7.3.1.3 Implementation of Functional Design7.3.1.3.1Analog Circuitry The process analog sensors and racks for the ESF actuation sy stem are covered inReference1. Discussed in this report are the parameters to be measur ed including pressures,flows, tank and vessel water levels, and temp eratures, as well as the measurement and signal transmission considerations. These latter considerations include the basic cu rrent transmission system, transmitters, orifices and flow elem ents, resistance temperature detectors, and pneumatics. Other consid erations covered are automatic cal culations, signal conditioning, and location and mounting of the devices.See Section7.7.1.11 for a discussion of el ectrical separation between safety- andnonsafety-related portions of the process analog system.

The sensors monitoring the primary system are locate d as shown on the piping flow diagrams and reference drawings in Chapter5, Reactor Cool ant System. The secondary system sensor locations are shown on the steam system flow diagrams and reference drawings given inChapter10.7.3.1.3.2Containment Pressure Narrow range containment pressure (0-65psia) is sensed by four physically separated absolute pressure transmitters mounted outside the containmen t, connected to containment atmosphere by four independent 3/8-inch stainless steel lines. Th e distance from penetration totransmitter is kept to a minimum, and separation is maintained. Wide range containment pressure(0-180psia) is sensed by two ab solute pressure transmitters mounted outside the containment.Their sensing lines are tapped off the narrow range containment pressure transmitted sensing lines.

Revision 52-09/29/2016 NAPS UFSAR 7.3-6 The 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 co ntain notes and symbolsapplicable to the logic di agrams in these sections.

7.3.1.3.2.1 Design. The four narrow range pressure tran smitters form four redundant pressure measuring channels, which provide inputs to two isolated separated actuating logic trains. The four 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 impl emented via three normally energized logicinput relays, which become de-energized on the receipt of a hi gh 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 impl emented via three normally energized logic input relays, which become de-energized on the receipt of an intermediate high-high containment pressure signal.

High-high containment pressure , on 2/4 channels, is the only condition that will initiate containment depressurization actuation and containment isolation phaseB.

Note: The inputs to the logic matr ices 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 the applicable coincidence logic is performed. The solid-state logic operates master relays in the output section, which then operate slave relays, for ESF actuation.

The slave relays are used forcontact multiplication.

Containment depressurization ac tuation signals are used in the following ESF systems:1.Quench spray pumps.2.Recirculation spray pumps.3.Refueling water chem ical addition system.4.Service water valves.

5.Diesel loading logic.

Revision 52-09/29/2016 NAPS UFSAR 7.3-7Containment isolation phase B occurs simult aneously with containment depressurization actuation, that is, as a direct result of high-high containment pressure. The wide range pressure transmitters 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 with these 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 power will not result in the initiation of safety injection, containment isolation, or main steam line isolation.

All equipment actuated by high, intermedia te high-high, and high-high containment pressure can be manually actuated from the control room as a final backup.

During normal plant operation, essentially all of the e ngineered safegu ards components, analog, logic, and actuation circuitry can be fu lly tested. The few remaining components can bepartially tested (see Section7.3.2.1.5).

7.3.1.3.2.2 Operation.

The operation of the containment pressure instrumentation system is illustrated in Reference Drawings5 through10, 28 and29.Refer to Reference Drawing6, which illustra tes the operation of high-high containment pressure protection. A high-high cont ainment pressure signal will be initiated if the containment pressure exceeds its setpoint on any 2/4 channels, provided that th e associated test switches are closed.Reference Drawing7 illustrates containment depressurization actuation, which is initiated by either of the foll owing 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 il lustrates the in itiation of high contai nment pressure. A high containment pressure signal w ill be initiated if channel pressure exceeds 17psia in any 2/3 channels or any 2/3 test switches are opened.Reference Drawing9 illustrate s intermediate high-high containment pr essure protection.

An intermediate high-high containment pressure si gnal is initiated when channel pressure exceeds its 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 52-09/29/2016 NAPS UFSAR 7.3-8Two position reset selector switches for containment spray trainsA &B exist in the control room.Reference Drawings28 and29 illustrate th e operation of the Recirculation Spray Subsystems, which are a part of the Containment Spray System. Further desc ription of the Recirculation Spray instrumentation is contained in Section7.3.2.11.7.3.1.3.3Safety InjectionFigure7.2-9 and the design and operation sections below ex plain the safety injection actuation system. The respective actuation logic is shown in Reference Drawing11.

7.3.1.3.3.1 Design. 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-line pressure or low-low T avg in two out of three loops.4.High containment pressure.

The purpose of the safety injection system is to maintain clad inte grity and thus minimize the 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 acc umulators following a LOCA. The three accumulators are self-contained and are de signed to supply borate d water as soon as th e reactor coolant systempressure drops below accumulator pressure. Addi tional 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 auxiliar y feedwater system.7.Start signals to service water pumps and repositioning of the valves.8.Turbine trip.

Revision 52-09/29/2016 NAPS UFSAR 7.3-9 7.3.1.3.3.2 Operation. Refer to Figure7.2-9, which illustrat es the makeup of safety injection actuation. A safety injection actuation signal will be initiated by any of the following conditions:1.Manual-Turning either of th e 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 T avg.b.High steam-line differential pressure.c.Low-low pressurizer pressure.d.High containment pressure.A safety injection actu ation signal may be manually re set by rotating the two position (NORM/RESET) safety injection reset selector switch to the RESET position, provided that the 1-min time delay has timed out a nd 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 or ESF actuation systems that enable additional monitoring of in-c ontainment conditions in the post-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 storage tank consists of four channels. All four cha nnels provide a remote indication at the maincontrol board and two channels provide lo w-level alarm functions. Three of the four channels provide a low level in terlock signal that is coincident with Containment High-High Pressure to start the RS pumps as described in Section7.3.2.1

1. All four cha nnels provide signals to initiate automatic ch angeover from injection mode to the recirculati on 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 pressure channel clearly shows that th e safety injection pumps are operating. This transmitter is outside 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 valv es have position indi cation on the control board to show proper positioning of the valves. Red and gree n indicator lights are located next to the manual control st ation showing open and closed positions. These lights thus enable the operator to quickly assess the status of the ESF systems. These indications are derived from contacts integral to the valve operators. In the cases of the accumulatorisolation valves, the redundancy of position indication is provided by valv e stem-mounted Revision 52-09/29/2016 NAPS UFSAR 7.3-10limit switches, which actuate annunciators on the control boa rd when the valves are notcorrectly positioned for ESF. The stem-mount ed switches are inde pendent of the limitswitches in the motor operators. See Section7.6 for additional information.5.Containment recirculati on air coolers-The air c oolers cooling water flow is indicated in the control room. The cooling water exit temperatures are provided to the plant computer. The sensors are outside the reactor containment.6.Sump instrumentation-The containment sump wide range instrumentation consists of redundant 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 the considerations and provisions for physical and electrical separati on as well as details of thecircuitry. Reference3 also covers certain aspects of on-line test provisions, provisions for test points, 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 actuat ion testing, two cabinets (one per train) are pr ovided that enable the operation of safety featur es actuation devices on a group-by-group basis until the actuation of all devices has been checked. Fina l actuation testing is discussed in detail in Section7.3.2.7.3.1.3.5Engineered Safety Feat ures Actuation Devices The outputs of the solid-state logic protection system (the slave relays) are energized to actuate, as are the switchgear an d motor control cente rs for all ESF-actuated devices. The following 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, th e ESF loads are sequenced onto the diesel generators. This loading is discussed in Chapter8. The de sign meets the requirements ofGeneral Design Criterion35.1.Figure7.3-2 is a general illustra tion of the relationship of unit trip signals. The interrelation of 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 52-09/29/2016 NAPS UFSAR 7.3-11c.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. These interfaces 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 ther e are two paths provi ded 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 emergency bus. 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 loss of reserve station service power signal for both Units1 and2. Also shown are the resultant actuation of the service water pumps, and the st art 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 less than 74%, whenever the bus voltage drops below 90% and remains there for 60seconds orlonger, or whenever a safety injection actuat ion 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 to decay below 71% nominal. These resultants are the automatic trip of specified loads.

Also illustrated is the subseq uent restoration of voltage to the emergency bus, after theemergency diesel-generator supply breaker is closed. Refer to Reference Drawing12 (containment depressurization) and Reference Drawing11 (s afety injection) for the subsequent restart of the affected ESF actuation devices.7.Figure7.3-8 illustrates the equipment that is tripped on a signal from the containment depressurization actuation (CDA) signal. This is done to rem ove 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 52-09/29/2016 NAPS UFSAR 7.3-12 Undervoltage 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-fea tures actuation mode by operato r action until the actuation signal has been reset. The protection system is designed such that on ce initiated, a protectionaction at the system level (initi ation of the final actuation device associated with a given protective function, i.e., quench spray, recirculation spray, chemical addition, safety injection, etc.) goes to comple tion. Reset capability of ESF signals is required to permit action in the postacci dent period. One example is stopping the quench spray pump when therefueling water storage tank level will no longer support continued quench spray pump operation.

The manual reset logic is design ed such that any preaccident operation of the reset controlswitch will not block a subsequent bona fide ac cident signal. It is important to note that manual control of the spray system cannot be achieved (once protective action at the system level has been initiated) by ju st resetting the associated actua tion signal. The manual reset is the first of a set of deliberate operator actions required to return the system to the non-safety-feature mode.

The circuitry for the feedwater bypass valves is provided with an admini stratively controlled keylock selector switc

h. During station operation this sw itch 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 refuelin g the switch isplaced in the "SG Wet Layup" position which al lows resetting of the feedwater bypass valves which is necessary to place th e steam generators in wet layup. In this case the ESF actuation signal being blocked (steam generator level) is not a valid core protection ESF actuation signal.Having gone to completion, that is, once breakers are closed or motor-operated valves orother actuators are operated, deliberate operator action is required to re turn a device to the Revision 52-09/29/2016 NAPS UFSAR 7.3-13non-ESF mode. Specifically, the fo llowing two actions per train are required for any device in a given train except for the feedwater bypass valves:a.Push reset for the appropriate actuation signal.b.Subsequently operate the c ontrol 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 oper ation, two operator actions ar e required to return these valves to the non-ESF actuation mode. The two actions per tr ain 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 in itiating logic andthe actuation devices required for feedwater isolation. The logic shown in ReferenceDrawing14 provides a redundant m eans of isolating feedwater in the event a main feedwater regulating valve should fail to close when required.11.Reference Drawing11, in conjunction with Figure7.3-4, illustrates automatic actuation logic for all actuation devices initiated by a containment depressurization actuation signal. Theeffect of the availability of emergency bus voltage on contai nment depressurization actuated devices is also shown. When emergency bus voltage has been restored for a specified time period, the actuated devices will start, providing the containm ent depressurization actuation signal is present.12.Figure7.3-8 shows how some devices on the emergency bus are tripped off on the initiation of a containment de pressurization signal.13.Reference Drawing11, in conjunction with Figure7.3-4, illustrates the effect that emergency bus power availability has on de vices actuated by the safety in jection actuation signal. Whenemergency bus voltage has been restored for a predetermined time, the ESF-actuated devices will operate, providing the safe ty injection signal is present.14.The diagrams in Reference Drawings15 and16 and Figures7.3-11 and7.3-13, and the design and operation sections belo w explain the containment isol ation system and its related function.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 isolati on trip valves are provided in the piping of variou s systems in accordance with th e design-basis established inSection6.2.4.

Revision 52-09/29/2016 NAPS UFSAR 7.3-14Containment isolation trip valves are air-operated valves operating on an air-to-open signal.

Compressed air is supplied to the underside of th e valve diaphragm, which compresses the spring and opens the valve. The air above the diaphragm vents to the c ontainment 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 atmos phere. The containment isol ation valves inside the containment will be ensured of operating regardless of the containment pressure.

Containment isolation valves are tripped closed as a result of containment isolation phase A or phase B, which results from safety injection and high-high containment pressure, respectively.

The valves must be manually rese t when tripped. The valve controls are designed so that a loss of electric power or air supply will also close the containment isolat ion valve. The trip signals must be removed and the electric power and air supply restored befo re the valves can be reset.

The position of each isolation trip valve and the availabili ty of power is monitored on the main control board.Certain trip valves, in addition to the normal tripping functions, are automatically opened and closed from process contro l signals as required (refer to Figures7.3-11 and7.3-12, andReference Drawing16). The trip signals will al ways override process signals. These combination operational 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 test ed in a manner similar to that described inSection7.2.2.2.1.6.

7.3.1.3.5.2 Containment Isolation System Operation.

Containment isolation si gnals that trip the isolation valves are generated as follows:

1.Phase A containment isolation-refer to Figure7.2-9. Cont ainment isolation phase A actuation will occur as a result of any of the following conditions:a.Either of two containment isolation phaseA momentary select or switches being placed inthe phaseA position. (This actuates trainsA andB.)

Revision 52-09/29/2016 NAPS UFSAR 7.3-15b.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 (placeme nt 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 isolation phase (four reset push buttons). These push buttons are provided with safety covers to prevent inadvertent operation.

Operating reset push buttons befo re an isolation signal initiati on 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 ei ther of the following:1.Manual switch actuation of containmen t isolation from the control board.2.Returning respective memory circuits to normal by the disapp earance of the (SI or high-high)signal and subsequently having them reoccur.Figure7.3-11 illustrates opera tion of a typical, normally closed trip valve, which is pneumatically operated with a solenoid-operated air pilot valve. The trip valves to which this diagram 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 process signal (providing the circuit has been reset) if no contai nment isolation signal condition exists.2.The valve will be closed if any of the following conditions occur:a.Containment isolation.b.The absence of an auto-open process signa l and the OPEN push button is not depressed.c.Depression of the CLOSE push button.Figure7.3-13 and Reference Drawing16 illustra tes the operation of a typical, normally open trip valve, which is pneumat ically operated with a solenoid-ope rated air pilot valve. The trip valves for which this diagram applies are listed in Reference Drawings17 and18, and operation is as follows:1.The valve will be opened provided there is no containment isolation (phaseA orB, asapplicable) signal and the OP EN push button is depressed.

Revision 52-09/29/2016 NAPS UFSAR 7.3-162.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 st eam generator feedwater 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 torn ado 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 ca n be manually started providing:1.Control switch is in START either at the c ontrol board or at the auxiliary shutdown panel, with the transfer switch in the appropriate position.2.No motor electrical faults are pres ent, 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 transfer switch in appropriate position.2.No electrical faults are present.3.The bus has no undervol tage 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. (This is the same setpoint used for reactor trip.)c.Loss of reserve station power.d.AMSAC initiated.

Revision 52-09/29/2016 NAPS UFSAR 7.3-17 In addition to the start demand si gnals a, b, c and d above, there is also a delayed auto start in the event a safety injection si gnal is initiated. This start is delayed 20seconds to maintain anacceptable voltage profile from the offsite source. In the event of an unde rvoltage signalconcurrent with safety injection, automatic starting will be delayed until 25se conds after the voltage 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 be stopped manually with the control switches at either the main control board or the auxiliary shutdown panel. They will stop automa tically with a motor protection trip.Figure7.3-12 and Reference Drawing19 illust rates the operation of the full-sized,turbine-driven auxiliary feedwater pump FW-P-2. Steam to the tu rbine driver can be admittedthrough either MS-TV-111A & -211A or through MS-TV-111B & -211B.MS-TV-111A & B and -211A & B can be manuall y operated using selector switches at the control board or the auxiliary s hutdown panel, provided the transfer switch is in the appropriate position.MS-TV-111A & -211A will open automatically as a result of the following trainA signals(similarly trainB signals operate MS-TV-111B & -211 B), providing the selector switch at the control board or the auxiliary shutdown panel is in the AUTO position and the transfer switch is in 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 co ntrol board or in the auxiliary shutdown panel.The discharge valve from each auxiliary steam generator feed water pump to its associated steam 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 illustrate s the operation of auxili ary feedwater controlvalve HCV-FW 100A and is typical for HCV-FW 100 B and C. The valve can be controlled from a manual loading station at the control board or from a similar station at the au xiliary shutdown panel, providing the transfer swit ch, located at the shutdown panel, is in the appropriate position.

Revision 52-09/29/2016 NAPS UFSAR 7.3-18 Auxiliary feedwater flow indica tion to each steam generator is powered from the 120V ac vital bus, which is battery-backed, and flow is displayed in the control room.

NUREG-0737 requires that the indication to be environmen tally qualified, and powered from a highly reliable, battery-backed, non-Class1E power sour ce. Although the power supply isClass1E, the power cables to the indicator are not safety-related, and the i ndicators on the control board do not have barriers for safety-related separation. The indication is environmentally qualified by virtue of being lo cated in a mild enviro nment. The power supply and equipment exceed the requirements of NUREG-0737.

Auxiliary feedwater pump discharge pressure is indicated at the contro l board and the auxiliary shutdown panel.

Auxiliary feedwater pump suction pressure is also indicated at the control 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 the following conditions exist:1.Transfer switch, located at the auxiliary s hutdown 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 the following conditions exist:1.Transfer switch, located at the auxiliary s hutdown panel, is in the appropriate position.2.OPEN/CLOSED switch for FW-MOV-100 A is held in the CLOSE position.To improve the reliability of the auxiliary feedwater system, al arms have been added in the control 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 fe edwater pump turbine thro ttle 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 main steam line outside the reactor c ontainment in a tornado-missile-protected enclosure. They are similar in design to standard swing check valves, except that they are installed counter to the normal steam flow directi on with the disk held out of the flow path by an air cylinder operator on each side.

Revision 52-09/29/2016 NAPS UFSAR 7.3-19 The purpose of these valves is to close immediately in case of a rupture in the main steam line between the valve and the turbine, thus preventing rapid blowdo wn of the shell side of the steam generator and rapid c ooling 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 Testing System, which tests for continuity through the safeguard contact and solenoid valve.Refer to Reference Drawing21. The following conditions will lead to main steam line isolation 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 temp erature (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 Sw itchgear Room for trip solenoid valvesSOV-MS101A-7, B-7, and C-7, is in the EMERG. CLOSE position.

Once the main steam-line isol ation trip valve receives a close signal (either by manual pushbutton actuation or automatic close signal), a relay contact seals the solenoids in theenergized position. This seal-i n is broken when the OPEN pu sh button is pressed and theautomatic isolation signal is reset.

When the valves are closed by one of the above, the valves can be reopene d by depressing the OPEN push button, providing none of the trip conditions exist, bot h control switch es are in the NORMAL position, and the upstream (ste am generator) pressure is less than 4psi greater than the downstream pressure.Air-operated bypass valves are provided to allow the operator to equa lize pressure on either side 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 52-09/29/2016 NAPS UFSAR 7.3-207.3.2Analysis 7.3.2.1Evaluation of Compliance With IEEE Std279-1971 (Reference2)7.3.2.1.1Single-Failure CriteriaThe discussion in Section7.2.2.2.1 is applicab le to the ESF actuation system, with the following exception.

In the engineered safety features, a loss of instrument power will call for the actuation of ESF 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, th e final bi-stables are ener gized to trip to avoid spurious actuation. In addition, manual containment spray requires simultaneous actuation of bothmanual controls. This is considered acceptable because spray actuation on high-high containment pressure signal provides automatic initiation of the system via protection channels meeting thecriteria in Reference2. Moreover, all safety-related equipment (valves, pumps, etc.) can be individually manually actua ted from the control board. Hence, a secondary mode of containment spray 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 ES F outputs from the solid-state logic protection cabinet s are redundant, and the actuations associated with each trainare energized up to and including the final actuators by the separa te ac power suppl ies that power the logic trains.7.3.2.1.4Control and Protection System Interaction The 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 appli cable to the sensors,analog circuitry, and logic trains of the ESF actuation system.

The following discussions cove r those areas in which the testing provisions differ from those for the reactor trip system.

7.3.2.1.5.1Testing of Engineered Safety Features Actuation Systems. The ESF systems are tested to provide assurance that the systems w ill operate as designed and will be available to Revision 52-09/29/2016 NAPS UFSAR 7.3-21 function properly in the unlikely event of an accident. The testing pr ogram, which meets the requirements 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 fully tested. In addition, essentially all of the ESF final actuators are fully tested, except for thecontacts of most slave relays. Th e contacts of these slave rela ys are tested functionally when the reactor is shut down for refueling.

7.3.2.1.5.2Performance Test Acceptability Standards for the "S" (Safety Injection Signal) and for the "P" (Automatic Demand Signal for Containment Spray Actuation) Actuation Signals Generation.

During reactor operation, the ba sis for ESF actuation systems acceptability is the successful completion of the ove rlapping tests performed on the reactor tripand the ESF actuation systems. Analog checks verify the operability of the sensors. Analog checks and tests verify the opera bility of the analog circuitry fr om the input of these circuits through to and including the logic i nput relays. Solid-state logic testing checks the digital signal path from and including logic input relay contact s through the logic matrices and master relays and 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 contac t portion of most slave relays.These slave relays are not actuated on-line because doing so would adversely affect the safety of the plant or disrupt reactor opera tion. The contacts of these slav e relays are pr oven operable by functionally testing them when the reactor is shut down for refueling. The final actuators are routinely tested on-line by the nor mal pump and valve surveillances.

Maintenance checks such as re sistance to ground te sting of signal ca bles are typically conducted for only the short term purpose of verifying proper in stallation following a replacement of cabling. In accordance with 10CFR50.49, qualification test data for cabling are documented for the long term purpose of establishing what constitutes an acceptable cable qualification life based on typical radiation exposures.

7.3.2.1.5.3Frequency of Performance of Engineered Safety Features Actuation Tests.

During normal reactor operation, complete system testing (excluding sensors or those devices whose operation would cause plant upset) is performed as required by the Technical Specifications.

Further testing, including the sensors and actuated devices, as required by the Technical Specifications, is performed during scheduled plant shutdowns for refueling.

Revision 52-09/29/2016 NAPS UFSAR 7.3-22 7.3.2.1.5.4Engineered Safety Features Actuation Test Description. The following sectionsdescribe the testing circuitry and procedures fo r the on-line portion of the testing program. The guidelines used in developing the circui try 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.

7.3.2.1.5.5 Descriptions of Initiation Circuitry.

Several systems comprise the total ESF system,most of which may be initiated by different pr ocess conditions and reset independently of eachother.The remaining functions are initiated by a common signa l (safety injection) (seeFigure7.3-3), which in turn may be generated by different process conditions.

In addition, the operation of all other vital a uxiliary support systems, such as auxiliaryfeedwater, component cooling, and service water, is initiated via th e ESF starting sequence actuated by the safety injection signal.Each function is actuated by a logic circuit duplicated for each of the two redundant trains of ESF initiation circuits.

The output of each of the ini tiation circuits consists of a master relay, which drives slaverelays for contact multiplication as required. The logic, master, and slave relays are mounted in the solid-state logic protection cabinets designated trainA and trainB, respectively, for the redundant counterparts. The master and slave rela y circuits operate various pump and fan circuitbreakers or starters, motor-operated valve contactors, solenoid-operated valves, emergency generator 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, proving lamps and analog test switches are provided. Administra tive control require s, during bi-stable testing, that the bi-stable output be put in a trip cond ition by placing the te st switch in the testposition. This action connects th e proving lamp to the bi-sta ble 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. Rela y logic in the process cabinets automatically blocks the test signal unless all of th e 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. An exception to this is containment depressurization, which is energi zed to actuate 2/4 and reverts to 2/3 when one channel is in test.

Revision 52-09/29/2016 NAPS UFSAR 7.3-23Refer to Reference Drawing5. Relay R-4, of cha nnel test switch cards, is operable for test purposes only when all three comp arator 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. Verifi cation 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. The verification of the bi-stabl e 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 pa nels. This step providesoverlap between the analog and logic portions of the test program. During this test, each of the logic inputs is actuated automatically in all combinations of trip and nontrip logic. Trip logic is not maintained long enough to permit master relay actuation; master relays are "pulsed" to checkcontinuity. Following the logic testing, the individual master relays are actuat ed electrically to test their mechanical operation. The actuation of the master relays during this test will apply low voltage to the slave relay coil ci rcuits to allow continuity check ing, but not slave relay actuation.

During logic testing of one trai n, 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 th e 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 rela ys 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 relay are verified operable during these tests. The PTs verify that each contact on the slave relay performs its safety function.

7.3.2.1.5.9Time Required for Testing.

It is estimated that analog te sting for most channels can be performed at a rate of several channels pe r hour provided that no ch annels are found out of calibration. Logic testing for one logic train may take as long as 2hours.

The testing of actuated components (including t hose that can only be pa rtially tested) is a f unction of control roomoperator availability. Several shif ts are required to accomplish th ese tests. During this procedure, automatic actuation circuitr y will override testing.

7.3.2.1.5.10 Safety Guide 22.

Periodic testing of the ESF actu ation functions as describedcomplies with AEC Safety Guide22, Periodic Testing of Protecti on System Actuation Functions

,February1972.Under the present design of the ESF, testing can be accom plished as described in thepreceding sections; all actuated devices and logic can be tested at power exce pt for the contacts ofmost slave relays and the follow ing protection functions: generation of a safety injection signal by Revision 52-09/29/2016 NAPS UFSAR 7.3-24use of the manual safety inject ion switch; generation of the c ontainment depressurization signal by use of the manual spray actuation switch.As required by Safety Guide22, where actuate d equipment is not tested during reactor operation it has been determined that:1.There is no practicable system design that would permit the ope ration of the actuatedequipment without adversely affecting th e safety or operability of the plant.2.The probability that the protection system will fail to initia te the operation of the actuatedequipment is, and can be maintained, acceptably low without testing the actuated equipment during 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 c ontacts of most slave relays because their actuation has been determined to adversely affect plant safety or disrupt reactor operation.

When the ability of a system to respond to a bona fide accident signal is intentionally bypassed for the purpose of performing a test during reactor operation, each bypass condition is automatically indicated to the reactor operator in the main control room by a common "ESFtesting" annunciator for the train in test. Test ci rcuitry does not allow two ESF trains to be tested at the same time so that the extension of th e bypass condition to redundant systems is prevented.7.3.2.1.5.11Summary. The procedures describe d provide the capability for checking completely from 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 ca lled on to operate for an accident conditi on. For those deviceswhose operation could adversely affect plant safety or disrupt reactor op eration, the procedureprovides for checking from the proc ess 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 veri fication of bi-stable setpoint are accomplished at process analog racks. The verification of bi-stable relay opera tion is done at the main control room status lights.2.Logic testing through the operation of the master relays and low-voltage application to slave relays is done at the logic rack test panel.3.The testing of pumps, fans, and valves is accomplished by IWV and IWP Programs. A full functional test is performed during the refuel ing cycle to ensure al l actuated equipment is operable.4.The contacts of the slave relays are verified operable during the testing mention in 3 above.

Revision 52-09/29/2016 NAPS UFSAR 7.3-25 7.3.2.1.5.12Testing During Shutdown. Emergency core cooling system tests are performed at a frequency established by the Surveillance Frequency Control Program (Tech Spec5.5.17). With the reactor coolant system pressure less than or equal to 450psi g and temperature less than orequal to 350°F, a test safety inject ion signal will be applied to in itiate 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 the Surveillance Frequency Control Program (Tech Spec5.5.17). The tests are performed with the isolation valves in the spray supply lines at the containment and spray additive tank blocked closed and are initiated by tripping the normal actuation instrumentation.

The balance of the requir ements 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 protect ion 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 the preferred 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 spra y 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 Technical Specifications to meet the intent of IEEE Std338-1971. Only t hose response times used in the accident 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 electrica l penetrations and co mpliance with IEEEStd317-1971.

Revision 52-09/29/2016 NAPS UFSAR 7.3-26 7.3.2.8Evaluation 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 di scussion of complia nce of the vital acpower system with IEEE Std336-1971.

7.3.2.9 SummaryThe effectiveness of the ESF actuation system is evaluated in Chapter15, based on the ability 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 the component performance specificatio ns, which are given by the manufacturer or verified by testfor each component. Appropriate factors to account fo r 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 signal actuating the protection function reliably and within a time consistent with the accident analysesin Chapter15.

Much longer times are associat ed with the actuation of the mechanical and fluid systemequipment associated with ESF. This include s the time required for switching, bringing pumps and other equipment to speed, and the ti me required for them to take load.

Operating procedures require that the complete ESF actuati on system normally be operable.However, the redundancy of system components is such that the system operability assumed for the 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 cont ainment high-high bi-stables are blocked (bypassed).

7.3.2.9.1Loss-of-Cool ant Protection By 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 char ging 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 cool ing system, providing additional protection as a backup to actuation on low-low pressurizer pressure. Emergency core cooling actuation can be brought about on sensing this other di rect consequence of a primary system break, that is, the prot ection system detects the leak age of the coolant into the Revision 52-09/29/2016 NAPS UFSAR 7.3-27 containment. The generation time of the actuation signal, about 1.0second after detection of the consequences of the accident, is adequate.

Containment spray will provide additional emergency cooling of the containment and also limit fission product release on sensing elevated containment pressu re (high-high) to mitigate theeffects of a LOCA.

The delay time between the de tection of the accident conditi on and the generation of the actuation signal for these systems is assumed to be about 1.0sec ond, well within the capability of the protection system equipment. However, this time is short compared to that required for the start-up of the fluid systems.The analyses in Chapter15 show that th e diverse methods of detecting the accident condition and the time for the gene ration of the signals by the protection systems are adequate to provide 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 act uated to protect against a steam-line break.About 2.0seconds elapse be tween sensing high steam-line differential pres sure or high steam-line flow and the generation of the actuation signal. The analysis of steam-line-break accidents assuming this delay for signal generation shows that the emergency core cooling system is actuated 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 th e highly borated water injected by the emergencycore cooling system.Additional protection against the effects of steam-line break is provided by feedwater isolation, 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 pr ovided by the closure of allsteam-line trip valves to prevent uncontrolled blowdown of all steam ge nerators. The generation of the protection system signal (about 2.0seconds) is again short comp ared to the time to trip the fast-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 a steam-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 the highly borated water injected by the emergency core cooling system.The analyses in Chapter15 of the steam-line-break accidents and an evaluation of the protection system instru mentation and channel design shows that the ESF act uation system iseffective in mitigating the effects of a steam-line-break accident.

Revision 52-09/29/2016 NAPS UFSAR 7.3-28 7.3.2.10Automatic Changeover From Injection Mode to Recirculation Mode After Loss of Primary Coolant The 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 by both the two-of-four refueling water storage tank (RWST) low-low-level protection logic and the safeguards 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 soli d state protection systems. Thus, when two-of-four RWST level channel bi-stables generate an RWST low-low level actuation signal it is developed in both safeguards protection cabinets. Each of the four RWST level channe l bi-stables is aligned to oneof four RWST level channels. E ach level channel is assigned to a separate vital instrument bus.The RWST level channel bi-s tables 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 (S I signal) is also required to initiate theautomatic switchover sequence. This interlock requires the capability fo r the retention of thesafeguards protection logic ac tuation signal (SI signal) by la tching relays located in thesafeguards protection cabinets. Th e retention of this signal is required since plant emergency procedures will instruct the operator to reset the master relays for the safeguards protection logic actuation signal (SI signal) signifi cantly in advance of the generation of the RWST low-low-level actuation signals. The output of thes e latching relays is retained such that when the two-of-fourRWST low-low-level actuation signals are developed, the trainA and trainB automatic switchover sequence trip signals are generated.

The automatic switchover sequence trip signal is applied to all valves except 1-862A and 1-862B that are automatically re positioned. This ensures that th e automatic switchover sequence cannot be unintentionally interr upted by the plant operator by manually repositioning the valve.

Provisions have been included in this interloc k to permit on-line te sting of the automaticswitchover sequence without aff ecting normal plant operation. The testing provisions have been developed to ensure that an open path from the RWST to the charging/safety injection pump suction does not exist at any time during the testing procedure. Test ing 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 simula te 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 52-09/29/2016 NAPS UFSAR 7.3-29 The following additional features are included in this inte rlock to prevent the unintentional remote manual operation of cert ain valves by the operator:1.The remote manual opening of a low-head safety injection pump miniflow isolation valve requires that the sump isolation valve in the same train be fully closed. This prevents the inadvertent pumping of sump water to the re fueling water storage tank after an accident.2.The remote manual opening of a sump isolat ion valve requires that one of the low-headsafety injection pump miniflow isolation valves in the same tr ain be fully closed. Again, this is to prevent inadvertent pumping of sump water to the refuel ing water storage tank after an accident.3.A RWST-to-LHSI pump isolation valve cannot be manually opened unless the sump isolation valve is fully closed. This avoids the condition where an LHSI pump would continue to take suct ion from the refueli ng water storage tank after the switchover to recirculation 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 inside recirculation spray (IRS) and outsi de recirculation spray (ORS) pum ps at appropriate times after the occurrence of a containmen t depressurization actuation (CDA). The automatic start sequenceis initiated when actuation si gnals are generated by a coinci dence of the CDA Containment Pressure 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 Hi gh-High (CDA) portion of th e RS pump start logic isdescribed in Section7.3.1.3.2 and Reference Drawings5, 6, and7. Actual pump start is not initiated until both the CDA and RWST Level-Low two-of-three l ogic is satisfied. This design ensures that the pumps will not start until enough wate r has been added to containment so thatsufficient water level is availa ble to meet sump strainer submergence and pump suction operating requirements.The RWST Level-Low portion of the RS pump start logic is desc ribed in ReferenceDrawings28 and29. The analog inputs to this logic are the same RWST leve l signals used in the Automatic 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. Separate bi-stables installed in three of the analog loops provide the RW ST 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 actuation signal, it is developed in both safeguards protec tion cabinets. Each of the three RWST Level-Low Revision 52-09/29/2016 NAPS UFSAR 7.3-30 channel bi-stables is aligned to one of three RWST level cha nnels. Each level channel is assigned to 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 logic is satisfied (Assuming that all electrical permissi ves are satisfied). The IRS pump control circuits are configured so that the pu mps start after a 120-second delay from the coincident actuation signal. This delay minimizes the impact on emergency diesel loading and allows for the ORS system to fill its piping completely, deliver spray to the containment and reach a stable flow demand on the sump before the IR S pumps start. This method of starting th e RS pumps ensuresthat a reliable mass of liquid is added to the containment to meet the sump strainer submergence requirements for the range of LOCA brea k sizes requiring the containment sump.

The Inside and Outside Recirculation Spray Pump Start Function is tested using the same methods and design features described in Section7.3.2.1.5.1.

7.3.2.12Casing Cooling Tank Isolation The Casing Cooling subsystem instrumentation provides the logic for automatic isolation of the Casing Cooling tank at the low-low level setpoint The timing of this f unction is important to prevent gas transport to the outside recircul ation pumps from the Ca sing Cooling tank due to vortexing.Automatic isolation is initiated when the Casing Cooling tank level drops below the low-low level setpoint, af ter a CDA signal. Signals are generated by each tank level monitor, and the channel bistable then automa tically closes the re spective trai n related pump low-low levelMOV.The low-flow MOV will also close automatically on low pump discharge flow as measured from dp across the recirculation path. Low recirc ulation flow would occur upon shutting down the Casing 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 a nd 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 52-09/29/2016 NAPS UFSAR 7.3-315.The Institute of Electrical a nd 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 a nd 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 a nd Electronics Engineers, Inc., IEEE Standard for Electrical Penetration 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 Requireme nts 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 St ation Drawings are controlled by station procedure.

Drawing Number Description1.11715-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 52-09/29/2016 NAPS UFSAR 7.3-325.11715-LSK-27-12ATypical Loop Diagram fo r 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 Inject ion System, Actuated Devices12.11715-LSK-27-12GContainment Depr essurization 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 Isolati on, 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: Re circulation Spray Sub Systems29.11715-LSK-27-1BLogic Diagram: Re circulation Spray Sub Systems Revision 52-09/29/2016 NAPS UFSAR 7.3-33Table7.3-1INTERLOCKS FOR ENGINEERED SAFETY FEATURES ACTUATION SYSTEM In addition to the interlocks in the Technica l Specifications, the following interlocks are installed.DesignationInput Function PerformedP-4Reactor trip Actuates turbine trip Closes main feedwater valves on T avg below setpoint Prevents opening of main feedwater valves that were closed by safety injection or high steam generator water level Allows 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

generator Closes all feedwater control valvesTrips all main feedwater pumps and closes the feed line isolation valves Actuates turbine trip Revision 52-09/29/2016 NAPS UFSAR 7.3-34Table7.3-2ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION Functional Unit Channels to Trip Minimum Channels Operable1.Safety Injectiona.Manual Initiation 1 2b.Automatic Actuation 1 2c.Containment Pressure-High 2 2d.Pressurizer Pressure-Low-Low 2 2e.Differential Pressure Between Steam Lines-High 2/steam line twice and 1/3 steam lines 2/steam linef.Steam Flow in Two Steam Lines-High1/steam line any 2 steam lines 1/steam line Coincident with either T avg-Low-Low 1 T avg any 2loops 1 T avg any 2loopsor, coincident with Steam Line Pressure-Low 1 pressure any 2lines 1 pressure any 2lines2.Containment Spraya.Manual1 set2setsb.Automatic Actuation Logic12c.Containment Pressure-High-High23d.Refueling Water Storage Tank (RWST)Level-Low Coincident with Containment Pressure High-High 223.Containment Isolationa.Phase"A" Isolation1)Manual122)From Safety Injection Automatic Actuation Logic 12c.Phase"B" Isolation1)Manual1set2 2)Automatic Actuation Logic12 3)Containment Pressure-High-High23 Revision 52-09/29/2016 NAPS UFSAR 7.3-354.Steam Line Isolationa.Manual1/steam line2/steam lineb.Automatic Actuation Logic 1 2c.Containment Pressure-Intermediate High-High2 2d.Steam Flow in Two Steam Lines-High1/steam line any 2steam lines 1/steam line Coincident with either T avg-Low-Low 1 T avg any 2loops 1 T avg any 2loopsor, coincident with Steam Line Pressure-Low 1 pressure any 2lines 1 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. 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 generator 2/steam generatord.Safety Injection (SI)See

1. 1 above (All SI initiating functions and requirements)e.Station Blackout1/bus on 2busses 1/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-Low 23Table7.3-2(continued)ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION Functional Unit Channels to Trip Minimum Channels Operable Revision 52-09/29/2016 NAPS UFSAR 7.3-368.Engineered Safety Feature Actuation System Interlocksa.Pressurizer Pressure, P-11 2 2b.Low-Low T avg , P-12 2 2c.Reactor Trip, P-4 1 29.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 INSTRUMENTATION Functional Unit Channels to Trip Minimum Channels Operable Revision 52-09/29/2016 NAPS UFSAR 7.3-37 Figure 7.3-1LOGIC DIAGRAM MOTOR DRIVEN STEAM GENERATOR AUXILIARY FEED PUMPS Revision 52-09/29/2016 NAPS UFSAR 7.3-38 Figure 7.3-2UNIT TRIP SIGNAL INTERFACES Revision 52-09/29/2016 NAPS UFSAR 7.3-39 Figure 7.3-3 ENGINEERED SAFETY FEATURES SIGNAL INTERFACES Revision 52-09/29/2016 NAPS UFSAR 7.3-40 Figure 7.3-4SIGNAL PATHS TO ESF ACTUATED DEVICES Revision 52-09/29/2016 NAPS UFSAR 7.3-41 Figure 7.3-5LOSS AND RESTORATION OF EMERGENCY BUS Revision 52-09/29/2016 NAPS UFSAR 7.3-42 Figure 7.3-6DIESEL LOAD AND SEQUENCING CONDITIONING CONCEPT Revision 52-09/29/2016 NAPS UFSAR 7.3-43 Figure 7.3-7RESERVE STATION SERVICE-UNDERVOLTAGEFigs. 7.3-1 & 7.3-12Fig 7.3-1 Revision 52-09/29/2016 NAPS UFSAR 7.3-44 Figure 7.3-8REMOVAL OF UNNECESSARY LOAD FROM EMERGENCY BUS DURING CONTAINMENT DEPRESSURIZATION7.3-5Ref. Dwg. No. 12Fig.

Revision 52-09/29/2016 NAPS UFSAR 7.3-45 Figure 7.3-9STATION SERVICE-UNDERVOLTAGE Revision 52-09/29/2016 NAPS UFSAR 7.3-46 Figure 7.3-10ENGINEERED SAFETY FEATURES BLOCKING LOGIC Revision 52-09/29/2016 NAPS UFSAR 7.3-47Figure 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 52-09/29/2016 NAPS UFSAR 7.3-48 Figure 7.3-12LOGIC DIAGRAM TURBINE DRIVEN-STEAM GENERATOR AUXILIARY FEED PUMPFIG 7.3-1FIG 7.3-1FIG 7.2-7 Revision 52-09/29/2016 NAPS UFSAR 7.3-49 Figure 7.3-13LOGIC DIAGRAM NORMALLY OPEN CONTAINMENT ISOLATION VALVESRef. Draw. 15Ref. Draw. 27REF DRAW 17 18REF DRAW 17 18REF DRAW 18REF DRAW 17 Revision 52-09/29/2016 NAPS UFSAR 7.3-50 Figure 7.3-14 ECCS LOGIC/AUTOMATIC SWITCHOVER FROMINJECTION PHASE TO RECIRCULATION PHASE Revision 52-09/29/2016 NAPS UFSAR 7.4-17.4SYSTEMS REQUIRED FOR SAFE SHUTDOWN Electrical schematic diagrams for systems required for shutdown and their supporting systems 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 channels that are associated with the major systems in both the primary and seconda ry loops of the nuclear steam supply system. These chan nels normally service a variety of operational functions, including start-up and shutdown as well as prot ective functions. There ar e no systems whose only function is safe shutdown. Prescrib ed procedures for placing and maintaining the plant in a safe condition can be instituted by appropriate alignment of select ed nuclear steam supply systems.

The discussion of these systems, together with th e applicable codes, crit eria, and guidelines, is found in other sections of this FSAR. In addition, the implementation of shutdown functions associated with the engineered safety features that are used under postulated limiting fault situations is discussed in Chapter6 and Section7.3.7.4.1Description The operator actions, instrumentation, and control features that maintain safe shutdown ofthe reactor as discussed in this section are the minimum number under nonacci dent conditions.These features will permit th e 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 necessary instrumentation and controls to achieve and ma intain a safe-shutdown condition. In the unlikely event that the main control room needs to be evacuated, an auxiliary s hutdown panel is provided.The conditions listed below include the design basis for the auxiliary shutdown panel. The identification is given for the control and monitori ng features (Section 7.4.1.2) necessary for maintaining a hot shutdown. The equipment and se rvices 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.

7.4.1.1 Design 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 th e operator trips the reactor befo re 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 52-09/29/2016 NAPS UFSAR 7.4-23.In the event the control room is inaccessibl e, the operator must br ing the plant to the hot standby condition.4.It is assumed that loss of extern al power may occur during evacuation.5.A sound-powered telephone netw ork exists between the aux iliary shutdown panel and the following 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, el ectrical as well as physical is olation exists between the main control board and auxiliary shutdown panel.7.The diesel generator will have both local-start and auto-start capability.8.No additional accident conditi ons are assumed to occur simultaneously with control roominaccessibility.9.No hardware failures are assumed to occur simultaneously with cont rol room inaccessibility; therefore, all automatic sy stems continue functioning.10.Fire in a section of the control board is considered credible. However, with the design of the control board (separation, limited combustibl es), control room evacuation should not be required following a fire in the main control board.11.A source of feedwa ter will be available for in excess of 1week. For the first 8hours, auxiliary feedwater pumps take suction from the 110,000-gall ons condensate storage tank.After 8hours, the auxiliary feedwater pumps can take suction from either the service water system 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 to separate diesels in the event of loss of outside power. The contro l is grouped with thecharging flow controls and duplicates f unctions 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 fo r 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 detailed operating instructions in conjunc tion with instrumentation and c ontrols on the panel. He will Revision 52-09/29/2016 NAPS UFSAR 7.4-3 be communicating by sound-powered telephone with other personnel to direct necessary local-manual action.15.Electric motors can be started or stopped at the switchgear.16.Motor-operated valves can be operated manually and drivers ca n be disengaged or locked out if required.17.The following processes will be available:a.Residual heat removal (reactor cool ant system natura l circulation).b.Boration capability.c.Reactor coolant sampling.d.Reactor coolant inventory control.e.Instrument air.18.The following items operate dur ing normal plant operation and wi ll continue to operate fromthe emergency diesel-generator bus should there be a loss of reserve station service power:a.Service water pumps.b.Component coo ling water pumps.c.Reactor containment fan cooler units.19.For equipment having motor controls outside the control room on the auxiliary shutdown panel (which duplicate the functi ons inside the control room), the controls will be provided with a selector switch that tran sfers the control of the switchge ar from the control room to a selected local station. Placing the local select or switch in the local operating position will give 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 to achieving and maintaining a safe shutdown, are av ailable in the event an evacuation of thecontrol room is required. These controls and instrumentation channels, together with the equipment and services identified in the fo llowing sections (7.4.1.3 and7.4.1.4), which are available for both hot and cold shutdown, identify the potential capability for cold shutdown of the reactor subsequent to a control room evacuati on through the use of suitable procedures. Therefore, the applicable requirements of General Design Criterion19 (1971 criteria) are met.

7.4.1.2 Auxiliary Shutdown Instrumentation Should it become necessary to abandon the c ontrol room, the plant can be safely brought to and maintained in the hot-shutdown condition from the auxiliary shutdow n control panels. Thiscapability, including a list of instruments and controls, is fully described in Section7.7.1.13.1.

Revision 52-09/29/2016 NAPS UFSAR 7.4-4 7.4.1.3Equipment and Services and Approximate Time Required After Incident ThatRequires Hot Shutdown1.Auxiliary feedwater pumps-required if main feedwater pumps are not operating. For blackout 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 of fan coolers.)3.Diesel generators-Initial loads begin in 10seconds. (See Chapter8 for a discussion of diesels.)4.Lighting in the areas of plant required during this condition-immediately. (See Chapter9 for 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 syst em (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 52-09/29/2016 NAPS UFSAR 7.4-5 The reactor plant design does not preclude attaining th e cold-shutdown condition from outside the control room. An as sessment of plant conditions can be made on a long-term basis (a week or more) to establish proc edures for bringing the plant to cold shutdown. During such time the plant could be safely main tained at hot-shutdown conditi on. Detailed procedures to befollowed in effecting cold shut down from outside the control room are best determined by plant personnel 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. The hot-shutdown condition can be maintained safely for an exte nded period of time. In the unlikely event that access to the control room is restricted, the plant can be safely kept at hot shutdown until the control room can be re-entered.

The evaluation of the ability to maintain a safe shutdown has included a consid eration of the accident consequences that might jeopa rdize safe-shutdown conditions. The accidentconsequences that are germane are those that w ould tend to degrade the capabilities for boration,adequate supply for auxiliary feedwater, and resi dual 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 af fected by these accidents, with the associated assumptions being that the instrumentation and controls indicated in Section7.4.1 are available to control and/or monitor shut down. These available systems will allow the maintenance of hot shutdown, even under the acc ident conditions listed above, which would tendtoward a return to critical ity or a loss of heat sink.

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

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

Revision 52-09/29/2016 NAPS UFSAR 7.4-8 Intentionally Blank Revision 52-09/29/2016 NAPS UFSAR 7.5-17.5SAFETY-RELATED DISPLAY INSTRUMENTATION7.5.1DescriptionTables7.5-1 and7.5-2 list the in formation readouts provided to the operator to enable him to perform required manual safety functions and to determine the effect of ma nual actions taken following a reactor trip due to a ConditionII, III, orIV event. Table7.5-2 also contains theminimum set of parameters classified as TypeA for ConditionIV even ts as analyzed byRegulatory Guide1.97. The tables list the information readouts require d to maintain the plant in ahot-shutdown condition or to proceed to a cold shutdown within the limits of the Technical Specifications. Reactivity control after ConditionII andIII fa ults will be maintained by administrative sampling of the reactor coolant for boron to ensu re that the concentration issufficient to maintain the reactor subcritical.Table7.5-3 lists the information available to the operator fo r monitoring conditions in thereactor, the reactor coolant syst em, the containment, and proces s systems throug hout all normal operating conditions of the plant, including anticipated operational occurrences.After the March1979 accident at Three Mile Island, the ar rangement of controls and displays on the control boards wa s reviewed. As a result, some devices were relocated on theseboards to improve operator efficiency and to minimize the chance of operator error. A lamp test system was added on the safety-related control boards in the main control room to verify system/component status. In addition, postaccident monitoring and control pa nels were installed for both units.7.5.2AnalysisFor ConditionII, III, andIV events (see Tables7.5-1 and7.5-2), sufficient duplication of information is provided to ensure that the minimum information re quired will be available. The information is part of the operational monitoring of the plant that is under operator surveillance during normal plant operation. This is functionally arranged on the control board to provide the operator with ready understandi ng and interpretation of plant conditions. Comparisons between duplicate information channels or between functiona lly related channels will enable the operatorto readily identify a malfunction in a particular channel.

Refueling water storage tank (RWST) level is indica ted by four and alarmed by twoindependent single-channel systems. Similarly, two channels of primary system pressure (widerange) are available for maintaining proper pr essure-temperature relationships following apostulated ConditionII orIII event. One channel of steam generator wate r level (wide range) is provided for each steam generato r; this duplicates level inform ation from steam generator water level (narrow range) and ensures the availability of level information to the operator.

Revision 52-09/29/2016 NAPS UFSAR 7.5-2 The remaining safety-related display instrumentation necessary for ConditionII, III, orIV events 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 and availability during and subsequent to an accident for which they are necessary. Thus, the occurrence of an accident does not render this information unavailable, and the status and reliability of the necessary in formation is known to the operato r before, during, and after an accident. 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 and annunciators. All containment isolat ion trip valves have their stat us monitored by lights on the main control board. All sa fety-related switchgear is monitore d by indicating lights in the main control room.

The design criteria used in the display system are listed below.1.Range and accuracy requirement s are determined through the analyses of ConditionII, III,orIV events, as described in Chapter15. The display system meets the following requirements:a.The range of the readouts extends over the ma ximum expected range of the variable being measured, 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 contro l board safeguards sections by more than one seismically quali fied indicator from separate channels powered by separate vital 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 52-09/29/2016 NAPS UFSAR 7.5-3g.Service water pressure.h.Safety injection accumulator level.i.Safety injection acc umulator 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 Thermocouples The following information is displayed to the operator on the main control board by more than one seismically qualified indicator, from separate channe ls powered by separate vital buses, wired by separate multiconductor cab les and including a seismic recorder:a.Steam generator level.b.Pressurizer level.c.Pressurizer pressure.d.Reactor coolant temperature (wide range).e.Condensate storage ta nk level (with alarm).

The auxiliary feedwater flow is displayed to the operator on or adjacent to the main control board by a seismically qualified indicator:

The following parameters have input to the plant computer fo r station logs and postaccidentreview. The information from one channel of each parameter will be retained by thecomputer for 1week, following a safegua rds actuation, for postaccident analysis:a.Steam generator level.b.Pressurizer level.c.Pressurizer pressure.d.Reactor coolant temperature.e.Containment building pressure.

Revision 52-09/29/2016 NAPS UFSAR 7.5-4 In response to NUREG-0578, ClassI seismically qualified pos taccident monitoring control panels for both units were installed (PAMC-1 and PAMC-2). The panels provide controls for the hydrogen analyzer inlet and outlet valves, hydrogen recombiner inle t and outlet valves,reactor coolant system venting valves, posta ccident 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, th e following information is displayed on theNIS panels by two Class1E seismically qualified indicators fr om 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 10 5 cps)In addition, in compliance with AppendixR , the single channel display at the remote monitoring panels provides for adequate info rmation display of neut ron flux information in the event of a fire in the control room, emerge ncy switchgear room, or cable vault and tunnel.

Revision 52-09/29/2016 NAPS UFSAR 7.5-5Table7.5-1MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLETO THE OPERATOR CONDITION II AND III EVENTSNumber of ChannelsAvailable Indicated Accuracy a Indicator/RecorderParameterAvailableRequiredRangePurpose1.T cold or T hot (measured, wide range)1 T hot , 1 T cold per loop 1 in any operating loop 0 to 700 oF+/- 13.5°FAll channels are recorded Ensure 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 recording Ensure 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 indicated Recorder for 1 channel Monitor containment pressure conditions to indicate the need for potential safegu ards actuation.5.Containment pressure (wide range)210 to 180psia

+/-4.9psiaBoth are indicatedMoni tor containment pressure conditions to indicate the need for

potential safegu ards 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 52-09/29/2016 NAPS UFSAR 7.5-66.Steam-line pressure3/steam line 1/steam line0 to 1400psig

+/-37.7psigAll required channels are indicated Monitor 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 recorded Ensure maintenance of reactor

heat sink.8.Steam generator water level (narrow range)3/steam generatorb0 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 indicated Ensure proper core subcooling.10.Reactor vessel level Upper range vessel level Full range vessel level Dynamic head vessel level 60 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 Accuracy a Indicator/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 52-09/29/2016 NAPS UFSAR 7.5-711.Degree of subcooling-35°F (superheat) to 200°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 computer Provide 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 Accuracy a Indicator/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 52-09/29/2016 NAPS UFSAR 7.5-8Table7.5-2 MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/Recorde rParameterAvailableRequiredRangePurpose1.Containment pressure (narrow range) b410 to 65psia

+/-1.6psiaAll 4 are indicated Monitor post-LOCA containment pressure conditions.2.Containment pressure (wide range) b210 to 180psia-7.1 to +7.5psia Both are indicated, only 1 is recorded Monitor post-LOCA containment pressure conditions.3.RWST water level420 to 100%-2.4 to +2.5%All are indicated; 2 are alarmed Ensure 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) b 3/steam generatorc0 to 100% (+7 to -5ft from nominal full-load level)-3.7 to +14.4%

d All 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 hos tile 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 ge nerator water level taps.

Revision 52-09/29/2016 NAPS UFSAR 7.5-95.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%

d All channels are recorded Detect steam generator tube

rupture; monitor steam generator water level

following a steam-line break.6.Steam-line pressure b 3/steam line 1/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 recording Indicate 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 indicated Monitor containment sump

level during and following a LOCA or steam-line break.Table7.5-2(continued)

MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR CONDITION IV EVENTS Number of ChannelsAvailable Indicated

Accuracy aIndicator/Recorde rParameterAvailableRequiredRangePurposea.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 hos tile 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 ge nerator water level taps.

Revision 52-09/29/2016 NAPS UFSAR 7.5-109.Inadequate Core Cooling Monitor21All channels indicated Monitor core conditions to help ensure proper core subcooling.9.1Reactor vessel levelUpper range vessel levelFull range vessel level Dynamic head vessel level 60 to 120%

0 to 120%0 to 120%not calculated not calculated not calculatedOne channel recorded9.2Degree of subcooling b-35°F (superheat) to 200°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 +138.6psig Loop A and C indication only, trended on PCS Monitor post-LOCA RCS pressure.Table7.5-2(continued)

MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR CONDITION IV EVENTS Number of ChannelsAvailable Indicated Accuracy aIndicator/Recorde rParameterAvailableRequiredRangePurposea.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 hos tile 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 ge nerator water level taps.

Revision 52-09/29/2016 NAPS UFSAR 7.5-1111.High head safety injection flow to cold leg (total) b210 to 1000 gpm-108.4 to +99.9gpm Indicated on control board and trended on PCS Monitor post-LOCA total safety injection flow rate to RCS cold legs.12.Containment high range radiation monitor b2110 0 to 10 7R/hr+/-2.25x10 6 R/hr All channels are recorded Monitor post-LOCA containment radi ation levels.13.Source range neutron flux (Gamma-Metrics)2110-1 to 10 5 cps+/-5810cpsTrended on PCSMonitor post-LOCA core reactivity.14.Power range neutron flux (Gamma-Metrics)2110-8 to 2x10 2% 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°F All channels are recorded Monitor 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°F All channels are recorded Monitor reactor coolant

temperature to help ensure core cooling is being accomplished.Table7.5-2(continued)

MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR CONDITION IV EVENTS Number of ChannelsAvailable Indicated Accuracy aIndicator/Recorde rParameterAvailableRequiredRangePurposea.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 hos tile 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 ge nerator water level taps.

Revision 52-09/29/2016 NAPS UFSAR 7.5-1217.Containment hydrogen analyzer210 to 10% H 2+/-1.45% H 2 Al channels are recorded Monitor 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 position 1/isolatio n valve 1/isolatio n valveOpen/Closenot calculatedIndication onlyMonitor containment integrity.Table7.5-2(continued)

MAIN CONTROL BOARD INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATOR CONDITION IV EVENTSNumber of ChannelsAvailable Indicated Accuracy aIndicator/Recorde rParameterAvailableRequiredRangePurposea.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 hos tile 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 ge nerator water level taps.

Revision 52-09/29/2016 NAPS UFSAR 7.5-13Table7.5-3CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of Channels Available RangeAvailable Indicated Accuracy aIndicator/ RecorderLocationNotesNUCLEAR INSTRUMENTATION1.Source rangea.Count rate210 0 to 10 6 counts/sec

+/-7% of the linear full-scale analog voltage b Both channels indicated; either may be selected for recording Control board One 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 b Both channels

indicated Control board2.Intermediate rangea.Flux level210-11 to 10-3 amps 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 b Both channels

indicated; either

may be selected for recording Control boardb.Start-up rate2-0.5 to 5.0 decades/min

+/-7% of the linear full-scale analog

voltage b Both channels indicated Control 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 52-09/29/2016 NAPS UFSAR 7.5-14NUCLEAR 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 indicated NIS racks in control roomb.Upper and lower ion chamber current difference4-30 to +30%

+/-3% of full power b Diagonally opposed; any 2 of the 4 channels may be selected for recording at the

same time using recorder in item 1 Control 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 b All 4 channels indicated; any 2 of the 4 channels may

be recorded using recorder in item 1 above Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-15NUCLEAR 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%

b All 4 channels recorded Control boarde.Flux difference on the top and bottom ion chambers4-30 to +30%

+/-4% b All 4 channels indicated Control boardREACTOR COOLANT SYSTEM1.T avg (measured)1/loop530° to 630°F

+/-3.64°FThe 1 channel is indicated Control board 2.T (measured)1/loop0 to 150% of full-power T+/-5.2% of full-power T The 1 channel is

indicated; one loop's channel is

selected for recording Control boarda.Tcold or T hot (measured, wide range)1-T hot and 1-T cold per loop 0 to 700°F

+/-13.5°FBoth channels recorded Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-16REACTOR COOLANT SYSTEM (continued)3.Overpower T setpoint1/loop0 to 150% of full-power T+/-5.7% of full-power T The 1 channel is indicated; one loop's channel is selected for recording Control 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 recording Control board5.Pressurizer pressure51700 to 2500psig

+/-25.4psigAll channels indicated Control board6.Pressurizer level30 to 100%

Entire distance

between taps

+/-7.12%All channels indicated; one channel is selected for recording Control 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% flow All channels

indicated Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-17REACTOR COOLANT SYSTEM (continued)8.Reactor coolant pump amperes1/loop0 to 1500Anot calculatedAll channels indicated Control boardOne channel for each

bus.9.Reactor coolant system pressure (wide range)20 to 3000psig

+/-70.1psigAll channels indicated Control board10.Pressurizer liquid temperature2100 to 700°Fnot calculatedAll channels indicated and monitored at the

computer Control boardREACTOR CONTROL SYSTEM1.Demanded rod speed10 to 76 step/min

+/-1.5 step/min b The 1 channel is indicated Control board2.Median T avg1530° to 630°F

+/-3.64°FThe 1 channel is indicated and recorded Control board The median of the

3-loop average temperatures are passed to the indicator and recorder.3.Treference1530° to 630°F

+/-4°F b The 1 channel is

indicated and recorded Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of

Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-18REACTOR CONTROL SYSTEM (continued)4.Control rod position If system not available, borate and sample accordingly.a.Number of steps of demand rod withdrawal1/group0 to 230 steps

+/-1 step b Each group is indicated during rod motion Control board These 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 position 1 for each rod 0 to 235 steps

+/-5% of full scale between 10-90%

b Each rod position is

indicated Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of

Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-19REACTOR CONTROL SYSTEM (continued)5.Control rod bank demand position 40 to 100% withdrawn (0 to 230 steps)

+/-2.5% of total bank travel b All 4 control rod bank positions are recorded along with the low-low limit alarm for each bank Control board 1. 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 SYSTEM Containment pressure (narrow range) 40 to 65psia

+/-1.6psiaAll 4 channels indicated Control boardTable7.5-3(continued)CONTROL ROOM INDICATORS AND/OR RECORDERS AVAILABLE TO THE OPERATORTO MONITOR SIGNIFICANT PLANT PARAMETERS DURING NORMAL OPERATIONParameter Number of

Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-20FEEDWATER AND STEAM SYSTEMS1.Auxiliary feedwater water flow 1/steam generator0 to 500 gpm-21 to +17gpmAll channels indicated Control board One 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 recorded Control 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 recorded Control board4.Main feedwater flow2/steam generator 0 to 5x10 6 lbm/hr+/-1.46x10 5 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 OPERATIONParameter Number of

Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-21FEEDWATER AND STEAM SYSTEMS (continued)5.Magnitude of signal controlling main and bypass feedwater control valves1/main 1/bypass 0 to 100% of valve

opening+/-1.5% b All channels

indicated Control board 1. 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 generator 0 to 5x10 6 lbm/hr+/-2.04x10 5 lbm/hrAll channels indicated; the channels used for

control are recorded Control board Accuracy is equipment capability; however, absolute accuracy

depends on applicant calibration against feedwater flow.7.Steam line pressure3/steam line0 to 1400psig

+/-37.7psigAll channels indicated Control board8.Steam dump demand signal10 to 100% maximum demand to valves

+/-1.5% b The one channel is

indicated Control board OPEN/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 OPERATIONParameter Number of

Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.5-22FEEDWATER AND STEAM SYSTEMS (continued)9.Turbine impulse chamber pressure20 to 120% full power

+/-4.2% full power b Both channels indicated Control board OPEN/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 indicated Control room Main 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 OPERATIONParameter Number of

Channels Available RangeAvailable Indicated Accuracy aIndicator/ 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 52-09/29/2016 NAPS UFSAR 7.6-17.6ALL 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 separa te documents. A logic diagram for the loop stop valves has been included in the FSAR as Figure7.6-1. Logic diagrams for the main control room ventilation duct isolation are included in report NA-TR-1001, dated May10,1973.7.6.1Instrumentation and Control Power SuppliesChapter8 provides a descriptio n and analysis of the inst rumentation and control powersupplies, consisting of the vital bus and dc power systems.7.6.2Residual Heat Removal System Inlet MOV Interlocks 7.6.2.1 DescriptionThere are two motor-operated gate valves in series in the inlet line from the reactor coolant system to the residual heat removal (RHR) system. They are nor mally closed and are only openfor residual heat removal after system pressure is reduced below approximately 450psig and system temperature has been reduced below approximately 350°F. (See Chapter5 for details ofthe RHR system.) Each of these valves is interloc ked with a pressure signal to prevent its beingopened whenever the system pressure exceeds 418psig. The upstream valv e is interlocked fromone protection channel. The other valve is interlocked from a second protection channel. Bothprotection channels use Rosemount1153 pressure transmitters which are environmentallyqualified.

7.6.2.2 Analysis Based 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 the consequences of loss of function, the requirements of IEEE Std279-1971 are applied with the following comments:1.For the purpose of applying IEEE Std279-1971, to this circuit, the fo llowing definitions are used:a.Protection System-The two valves in series in the line and al l components of their interlocking 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 52-09/29/2016 NAPS UFSAR 7.6-22.IEEE Std279-1971, Paragraph4.10: The requi rement for online test and calibration capability is applicable only to the actuation signal and not to the isolation valves, which are required to remain closed during power operation.3.IEEE Std279-1971, Paragraph4.15: This require ment does not apply be cause the setpoints are 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 Interlocks 7.6.3.1 DescriptionThe purpose of these interlocks is to ensure that an accidental start-up of an unborated and/or cold, isolated reactor coolant loop results onl y in a relatively slow re activity insertion rate.

The interlocks perform a protecti ve function. Therefore, there are:1.Two independent limit sw itches to indicate that a valve is fully opened.2.Two independent switches to indicate that a valve is fully closed.3.Two differential pressure swit ches 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 should be noted that flow through the reli ef line isolation valves indicates that (1)the valves in theline are open, (2)the line is not blocked, and (3)the pump is running.

7.6.3.2 AnalysisSection15.2.6 presents an analys is of the start-up of an in active reactor coolant loop with the loop isolation valves initially closed. The start-up of an inactive reactor coolant loop accident analysis does not credit the loop stop valve interlocks.

Based on the scope definitions presented in References1 and 2, these criteria do not apply to the reactor cool ant system loop is olation valve interlocks; however, to ensure continuous availability of the function provided by these interlocks, the requirements of IEEE Std279-1971, are applied.

Only those interlocks and alar ms relating to core protecti on are described. Those required for reactor coolant pump protecti on are not part of th e protection system and need not meet theprotection system criteria of Reference1.

In addition to the interlocks, an alarm is pr ovided 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 reactor is at a power level where all loops are required to be in service and the bypass valve is not fully closed. An alarm is used because, if the bypass valve is opened at full power, the core flow reduction is of the order of 2% to 5% and does not result in an immediate DNB problem.

Revision 52-09/29/2016 NAPS UFSAR 7.6-37.6.4Main Control Room, Relay Room, an d Emergency Switch gear Room Air Conditioning, Heating, and Ventilation System Instrumentation and Controls 7.6.4.1 Description The system design, flow diagram, and instru mentation appli cation for the main control room and relay room air conditioning, heating, and ventilation system are included inSection9.4.1. Temperature controls ar e provided to maintain the retu rn air from the main control room and relay room at a predetermined temperature, as sensed by the te mperature transmitters.

During LOCA conditions, the contro l and relay rooms are isolated from the outside atmosphere.A differential pressure indicato r mounted on the ventilation pane l, located in th e main control room, is provided to determine that the pressure in the control room is being maintained slightly above the atmospheric pres sure 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 maintained slightly above atmospheric.There are no areas other than those described above where safety-related control and electrical equipment require a cont rolled environment (temperature, humidity, and air particulate) for proper operation. Schematic drawings for equipment suppor ting the areas described were included in the Safety Related Electrical Schematics, VolumeII, Tab9, submitted to the AEC onMay18,1973.

7.6.4.2 Analysis The 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) fo r reducing the possibility of damage to the fuelduring fuel-handling operations are provided, as well as mechanical stops, which provide the primary means of preventing fuel-handling accidents. For exam ple, safety aspects of the manipulator crane fuel-handli ng operation depend on the use of electrical interlocks and mechanical stops, as discussed in Section9.1.4.4.4. The electrical in terlocks for this manipulator crane fuel-handling operation ar e not specifically designed to the require ments of IEEEStd279-1971 because of the backup provided by the mechanical stops.7.6.6Accumulator Isolation Valve Control The 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 52-09/29/2016 NAPS UFSAR 7.6-4 It is necessary with automati c opening of these valves with reactor coolant pressure to include 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 injection signal or a manual opening si gnal. Additional description is in Sections6.3.2.2.7 and6.3.5.5.1.7.6.7Pressurizer Relief Valve Flow IndicationThe NRC clarifications to NUR EG-0578 (contained in Discussion of Lessons LearnedShort-Term Requirements, Position2.1.3.a, Clarification2, October30,1979) state that control room 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 a nd meet NUREG-0578/RegulatoryGuide1.97, Post Accident Monitoring requirements, an environmentally and seismicallyqualified Valve Monitoring System (VMS) has been instal led to verify the CLOSED,NOT-CLOSED position of the safety valves during all modes of plant operation, except Mode6(Refueling). The PORVs use separa te, environmentally an d seismically qualified limit switches to monitor 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 the Control Room. They provide reli able 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 indi cation in the Control Room derived from a qualified, single channel of acoustical m onitoring, operating from a highlyreliable power supply. For each sa fety valve, an active and pass ive qualified ac celerometer has been attached to the outside of the discharge pipe and connected to preamplifiers in stalled inside a transient shield to maintain th eir environmental quali fication. Either of th ese sensors can provide indication to alert the operator wh en flow is detected through a pr essurizer safety valve. A panel,common to both Units1 and2, pr ovides Operators with Control Room indication of the safety valves 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 seismically supported and is locate d beside 1-EI-CB-08A.PORV position indication for PCV-1455C a nd 1456 have four environmentally and seismically qualified valve stem position limit sw itches, powered by dive rse power supplies, to detect OPEN/CLOSED position of each valve. The limit switches are arranged in two sets of two per valve to provide channel redundant indication position lights in the Control Room. These limitswitches have been seismically installed, external to the PORV.

Revision 52-09/29/2016 NAPS UFSAR 7.6-

57.6REFERENCES

1.The Institute of El ectrical and Electroni c 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 52-09/29/2016 NAPS UFSAR 7.6-6 Figure 7.6-1LOOP STOP VALVE INTERLOCKS Revision 52-09/29/2016 NAPS UFSAR 7.6-7 Figure 7.6-2TYPICAL REACTOR COOLANT SYSTEM LOOP WITH LOOP STOP VALVES Revision 52-09/29/2016 NAPS UFSAR 7.6-8 Figure 7.6-3FUNCTIONAL BLOCK DIAGRAM FOR OPENING ACCUMULATOR ISOLATION VALVE Revision 52-09/29/2016 NAPS UFSAR 7.7-17.7PLANT CONTROL SYSTEMS The general design objectives of the pl ant control systems are the following:1.To establish and maintain power equilibriu m between the primary and secondary systems during steady-state unit operation.2.To constrain operational transients to preclude unit trip and re-establish steady-state unit operation.3.To provide the reactor operator with monitori ng instrumentation that indicates all requiredinput and output control parameters of the systems and enables the operator to assume manual control of the systems.7.7.1Description The 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, with in the load range of 15% to 100% without reactor trip, steam dump, or pressurizer re lief actuation, subj ect to possible xenonlimitations.b.Maintains reactor coolant average temperature (T avg) within prescribed limits by creating the bank demand signals for moving groups of rod cluster control assemblies during normal operation and operational transients. The T avg control also suppl ies the signals to pressurizer level control and st eam dump control. These signal s are derived in the Reactor Protection System sent to the reactor control system via circuit isolators.

2.Rod Control Systema.Provides for reactor power modulation by manual or automa tic control of control rod banks in a preselected sequence and fo r manual operation of individual banks.b.The rod control system incl udes systems for monitoring and indicating for the following purposes: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 ex ceeds a preset limit.

3.Plant Control System Interlocks (See Table7.7-1.)Prevent further withdrawal of the control banks when signa l limits are approached that predict the approach of a DNBR limit or kilowatts per foot limit.

Revision 52-09/29/2016 NAPS UFSAR 7.7-2 4.Pressurizer Pressure ControlMaintains or restores the pressurizer pressure to the design pressure

+/-25psi (which is well within reactor trip and relief and safety valve actuation setpoints limits) following normal operational transients that induce pressure chan ges by control (man ual or automatic) of heaters and spray in the pressurizer. Also provides st eam relief by cont rolling 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 cau sed by coolant density changes induced by loading, operational, and unloading transients. Le vel changes are alsoproduced by charging flow control (manual or automatic) as well as by manual selection of 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 limits during normal operating transients.b.Provides capability to restores the steam generator water level to within predetermined limits at unit trip conditions. Regulates the feedwater flow rate such that during operational transients the heat sink for the reactor coolant system does not decrease belowa minimum. Steam generator wa ter inventory control is manual or automatic through the use 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 accommo date excess power generationin the reactor during turbine load-reduction transients.b.Ensures that stored energy a nd residual heat are re moved following a reactor trip, to bringthe plant to equilibrium no-l oad conditions without the actua tion of the steam generator safety valves.c.Maintains the plant at no-load conditions and permits manual temperature control.

8.Incore Instrumentation Provides information on the neut ron flux distribution and on the core outlet temperatures at selected core locations.

Revision 52-09/29/2016 NAPS UFSAR 7.7-3 7.7.1.1Reactor Control System The 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 or decreases of 5% per minute, within the load range of 15% to100% without reactor trip, steam dump, or pressure relief , subject to possible xenon limitation

s. The system is also capable of restoring coolant average temper ature 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 coolan t average temperature by the regulation of control rod bank position. The reactor coolant l oop average temperatures are determined from hot-leg and cold-leg measuremen ts 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 (T avg) 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 then processed through a lead-lag compensation unit) from ea ch of the reactor coolant loopsconstitutes the primary control signal, as shown in general in Figure7.7-1 and in more detail on the functional diagrams shown in Figure7.7-2. The system is capabl e of restoring coolant average temperature to the programmed value following a change in load. The programmed coolant temperature increases linearly wi th turbine load from zero power to the full-power condition. The T avg is also a signal to the pressu rizer level control, steam dump control, and rod insertion limit monitoring.

An additional control input si gnal is derived from the reac tor power versus turbine load mismatch signal. This additiona l control input signal improves sy stem performance by enhancing response.7.7.1.2Rod Control System The rod control system r eceives rod speed and direction signals from the T avg control system. 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 si gnal. The rod direction demand signal is determined by the posi tive 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 co ntrolled by the reactor control systems. A permissive interlock C-5 (see Table7.7-1) derived from me asurements of turbine impulsechamber pressure prevents automa tic withdrawal when the turbin e load is belo w 15%. In the Tavg Thot Tcold+2-------------

---

-=

Revision 52-09/29/2016 NAPS UFSAR 7.7-4AUTOMATIC mode, the rods are again withdrawn (or inserted) in a predetermined programmed sequence by the automatic pr ogramming equipment. The manual and automatic controls are further interlocked with the control interlocks.

The shutdown banks are always in the fully withdrawn position during normal operation and are moved to this position at a constant speed by manual control before criticality. A reactor trip signal causes them to fall by gravity into the core. There are two shutdown banks.

The control banks are the only r ods that can be manipulated under automatic control. Each control bank is divided into two groups to obtain smaller incremental reac tivity 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 insert small amounts of reactivity at lo w speed to accomplish fine control of reactor coolant average temperature about a small temperature deadband, as well as furnishing control at high speed. A summary 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 the following order: control bankA, control bankB, control bankC, and control bankD. The programmed 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 preset position, the second bank begins to move out simultaneously wi th the first bank. When the first bank reaches the top of the core, it stops, while the second bank continues to move toward its fully withdrawn pos ition. When the second bank re aches a preset position, the third bank begins to move out , and so on. This withdrawal se quence 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 c ontrolled between a minimum of8steps/minute and a maximum of 72steps/minute.

Revision 52-09/29/2016 NAPS UFSAR 7.7-5 7.7.1.3Plant Control Signals for Monitoring and Indicating7.7.1.3.1Monitoring Functions Provided by the Nuclear Instrumentation System The nuclear instrumentation system is described in Reference1.

The power range channels ar e important because of thei r use in monitoring power distribution in the core within specified safe limits. They are used to me asure reactor power level, axial power imbalance, and radial power imbalan ce. These channels are capable of recording overpower excursions up to 200% of full power. Suitable alarms ar e 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); these detectors 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 pow er range detector (four such signals).

Derived from these basic signals are the foll owing (including standard signal processing for calibration):1.Indicated nuclear flux (four such).2.Indicated axial flux imbalance, derived from upper-half flux minus lower-half flux (four such).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 are provided on the control board for nuclear power and fo r axial power imbalance.7.7.1.3.2Rod Position Monito ring of Control Rods The following separate systems are provided to sense and display control rod position:1.Analog system-An analog signa l is produced for each rod cl uster control assembly by alinear variable transformer.

Direct continuous readout of ev ery rod cluster control assembly position is presented to the operator by individual meter indicat ions, without the need for ope rator selection or switching to determine rod position. A rod bot tom (rod drop) alarm is provided.

Revision 52-09/29/2016 NAPS UFSAR 7.7-62.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 sepa rate systems; eachserves as backup for the other. Comparison by th e reactor operator of th e demand reading fromthe digital readout and the analog (actual) read ing from the meter indi cations verifies proper operation of the rod control syst em. 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 In sertion MonitoringWhen the reactor is crit ical, the normal indication of reactivity status in the core is the position of the control bank in relation to reactor power (as indicated by the reactor coolantsystem loop deltaT) and coolant average temperature. These para meters are used to calculate insertion limits for the control banks. The following two alarms are provided for each control bank:1.The "low" alarm alerts the operator of an approach to the rod insert ion limits requiring boron addition 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 coolant system by any one of seve ral 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 following reactor trip; provides a limit on the maximum inserted rod wort h in the unlikely event of a hypothetical rod ejection; and limits rod insertion such that accepta ble nuclear peak ing 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 be decreased (the rods must be w ithdrawn further) with increasing power. Two parameters that are proportional to power are used as inputs to the insertion monitor. These are the deltaT between the 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 control rod bank as follows:

Z LL = A(T) + B (T avg) + C(7.2-1)where: Z LL = maximum permissible insertion limit for affected control bank (T) = median/high select T of all loops (T avg) = median/high select T avg of all loops Revision 52-09/29/2016 NAPS UFSAR 7.7-7 B = 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 Z LL as follows:

If Z - Z LL D, a low alarm is actuated.

If Z - Z LL E, a low-low alarm is actuated.

Since the highest values of T avg 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 alar m 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 is reached. The value of "D" is chos en to allow the operator to follow normal boration procedures.Figure7.7-3 shows a block diagram representation of the control rod bank insertion monitor. The monitor is shown in more detail on the functi onal diagrams shown in Figure7.7-2. In addition to the rod insertion monitor for the control banks, an alarm system is provided to warn the operator if any shutdown rod cluster control assembly leaves the full y withdrawn position.

Rod insertion limits are established by the following:1.Establishing the allowed rod re activity insertion at full power consistent with the purposes given above.2.Establishing the differential reactivity worth of the contro l rods when moved in normal sequence.3.Establishing the change in reactivity with power level by rela ting power level to rod position.4.Linearizing the resultant limit curve. All key nuclear parame ters in this procedure are measured 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 indication of a change in the reactivity status of the reactor. In addition, samples are taken periodically ofcoolant boron concentration. Vari ations in concentration during core life provide an additionalcheck on the reactivity status of the reactor, including core depletion.7.7.1.3.4Rod Deviation Alarm The demanded and measured r od position signals are displa yed on the control board. They are also monitored by the plant computer, which provides a visual printout and an audible alarm Revision 52-09/29/2016 NAPS UFSAR 7.7-8whenever 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 exceedi ng 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 Alarm A rod bottom signal for the c ontrol 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 Interlocks The 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 th e designation numbers for these interlocks are preced ed by "C." The developm ent of these logic func tions 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 Stops Rod stops are provided to pr event abnormal power conditio ns that could result fromexcessive control rod withdrawal initiated by either a control system malfunction or operator violation of administrative procedures.Rod stops are the C 1 , C 2 , C 3 , C 4, andC 5 control interlocks identified in Table7.7-1. The C 3 rod stop, derived from overtemperature deltaT, and the C 4 rod stop, derived from overpowerdelta T, are also used for turbine runback, which is discussed below.7.7.1.4.2Automatic Turbine Load Runback Automatic turbine load runback is initia ted by an approach to an over-power or overtemperature condition. This will prevent high-power operation that might lead to an undesirable 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-thr ee coincidence logic is used.

A rod stop and turbine runback are initiated when:T > T rod stop & turbine runback for both the overtemperature and the overpower condition.

Revision 52-09/29/2016 NAPS UFSAR 7.7-9 For either condition in general:Trod stop & turbine runback

= T setpoint - B p (7.2-2)where: B p = 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 equa l to or less than delta Trodstop&turbinerunback. This function serves to maintain an essentially constant margin to trip.

7.7.1.5Pressurizer Pressure ControlThe reactor coolant system pres sure is controlled by using th e 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 c ontrol system transmitters is used in conjunction with a reference pressure to de velop a demand signal for a thre e mode controller providing for pressurizer proportional heater cont rol, pressurizer backup heater c ontrol, spray valve control, andcontrol of one of two PORVs.Steam condensed by the spray reduces the pre ssurizer pressure. A small continuous spray isnormally maintained to reduce thermal stresses and thermal shock and to help maintain uniform water chemistry and temperature in the pressurizer. The spray nozzl e is located on the top of thepressurizer. Spray is initiated wh en the pressure controller spra y demand signal is above a given setpoint. The spray rate increase s proportionally with increasing spray dema nd signal until it reaches a maximum value.

Pressure is raised by adding h eat to the pressurizer via the pressurizer heaters. The electrical immersion heaters are located n ear the bottom of the pressurizer. A portion of the heater group isproportionally controlled to correct small pressu re variations. These vari ations are due to heat losses, including heat losses from a small continuous spray. The remaining (backup) heaters areturned on when the pressurizer pressure controlled signal dema nds approximately 100%proportional heater power.Two pressurizer power-operated relief valves limit system pressure for large positivepressure transients. During the low temperatur e 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 react or coolant system cold legtemperature devices. The PORVs will actuate if undesirable combinations of temperature and pressure develop. During power operations, one PORV is controlled by a pressurizer pressuretransmitter and associated master controller. Actuation of this PORV is dependent on the master controller pressure setpoint and the length of time that pressurizer pressure is ab ove the setpoint.

Revision 52-09/29/2016 NAPS UFSAR 7.7-10The second PORV is controlled, during power operations, from a separate pressurizer pressuretransmitter and will actuat e 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 the density of the reactor coolant changes due to reactor coolant temperature, the steam-waterinterface moves to absorb the variations wi th relatively small pressure disturbances.

The water inventory in the reactor coolant sy stem 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 pres surizer water level is programmed as a function of cool ant average temperature, with the median temperature of the three loops average temper atures used for control.

The pressurizer water level decreases as theload is reduced from full load. This is a re sult of coolant contrac tion following programmedcoolant temperature reduction from full power to low power. The programmed level is designed to match as nearly as possible the level change s resulting from the cool ant temperature changes.

Manual control of pressurizer water level is available at all times.

A block diagram of the pressurizer water le vel control system is shown in Figure7.7-10.

7.7.1.7Steam Generator Water-Level Control Each steam generator is equippe d with a three-element feedwater flow control system that maintains a programmed water level as a function of turbine load. The three-element feedwatercontroller regulates the feedwater valve by contin uously comparing the feed water 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 follow ing a reactor trip and turbine tr ip. An override signal closes the feedwater valves when the aver age 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 Control The steam dump system is desi gned to accept a 40% loss of ne t load without tripping thereactor.The automatic steam dump system is able to accommodate this abnorma l load rejection andto reduce the effects of the transient imposed on the reactor coolant sy stem. By bypassing the main steam directly to the condenser, an artifici al load is maintained on the primary system. The Revision 52-09/29/2016 NAPS UFSAR 7.7-11 rod control system can then re duce the reactor temp erature to a new equi librium value without causing overtemperature and/or overpressure conditions. The NorthAnna plant was designed torelieve the heat equivalent to 50% of the rated load at the tim e of initial licensing (40% by the steam 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 th at the steam dump capacity could be as low as 34.7% of the steam 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 anal yses was reviewed. It wasdetermined that there was acceptable margin to all relevant reac tor trip setpoints for a 50% loadrejection from 2968 MWt NSSS power.If the difference between the reference T avg (T ref) based on turbine impulse chamberpressure and the lead/lag compensated median T avg exceeds a predetermined amount and the interlock mentioned below is sa tisfied, a demand signal will actuate the steam dump to maintain the reactor coolant syst em temperature within control rang e until a new equi librium condition is reached.To prevent the actuation of steam dump on small-load perturbations, an independent load rejection sensing circuit is provided. This circuit senses the rate of decrease in the turbine load as detected by the turbine impulse chamber pressure. It is provided to unbl ock the dump valves when the rate of load rejection excee ds a preset value corresponding to a 10% step-load decrease or a sustained 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 St eam 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 median T avg and the reference T avg based on turbine impulse chamber pressure.The Tavg signal is the same as that used in the reactor coolant system. The lead/lag compensation for the Tavg signal is to compensate for lags in the plant thermal response and in valve positioning. Following a sudden load decrease, T ref is immediately decreased and T avg tends to increase, thus generating an immediate demand signal for steam dump. Since control rods are available in this situation, st eam dump terminates as the erro r comes within the maneuvering capability of the control rods.7.7.1.8.2Turbine Trip Steam Dump Controller Following a turbine trip, as m onitored by the turbine trip signal, the load rejection steam dump 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 the lead/lag compensated median T avg and the no-load reference T avg. When the error signal exceeds Revision 52-09/29/2016 NAPS UFSAR 7.7-12a predetermined setpoint, the dump valves are tripped open in a prescribed sequence. As the error signal reduces in magnitud e, indicating that the reactor coolant system Tavg is being reduced toward the reference no-load value, the dump valv es are modulated by the plant trip controller to regulate the rate of decay heat removal and thus gradually esta blish the equilibrium hot-shutdowncondition.

The error signal determines whet her a group of valves is to be tripped open or modulated open. In either case, they are modulated when the error is below the trip-open setpoints.7.7.1.8.3Steam Header Pr essure 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 controller operates the steam dump valves to the condensers. The controlle r can automatically control thesteam dump valves to maintain the desired steam header pressure, or the dump valves can be manually controlled in this mode.

7.7.1.9Incore Instrumentation The incore instrumentation system consists of Chromel-Alumel thermo couples at fixed coreoutlet positions and movable miniature neutron detectors that can be positioned at the center of selected fuel assemblies, anywhe re along the length of the fuel as sembly vertical axis. The basic system for the insertion of these detectors is shown in Figure7.7-13. Sections1 and2 ofReference3 outline the incore inst rumentation system in more detail.

7.7.1.9.1Thermocouples The 51 Chromel-Alumel thermocouples are thr eaded into guide tubes that penetrate the reactor vessel head thr ough 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 System Miniature fission chamber detectors can be remotely posi tioned in retractable guide thimbles to provide flux mapping of the core. See Reference3 for neutron flux detectorparameters. The stainless steel dete ctor shell is welded to the leading end of helical wrap drivecable and to stainless-steel-she athed coaxial cable. The retractab le thimbles, into which the miniature detectors are driven, are pushed into the reactor core through conduits that extend from the bottom of the reactor vessel down through the concrete shield area and then up to a thimble seal table.The thimbles are closed at the leading ends, ar e dry inside, and serve as the pressure barrier between the reactor water pressure and the atmos phere. Mechanical seals between the retractable thimbles and the conduits are provided at the s eal line. During reactor operation, the retractable Revision 52-09/29/2016 NAPS UFSAR 7.7-13thimbles are stationary. They are extracted downward from the core during refueling to avoid interference within the core. A space above the s eal 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 se lector 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 miniature detectors 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 assembly consists of a gear motor that pushes a helical wrap dr ive cable and a detect or through a selectivethimble path by means of a special drive box and includes a storage device that accommodates the total 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 to isolate a thimble while a detector/drive cable is inserted into the thimble. The detector/drive cable must be retracted to a position above the isolation valve before closing the valve.

A small leak would proba bly not prevent access to the is olation valves; thus, a leaking thimble 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 Description The control and readout syst em provides means for insert ing the miniature neutron detectors into the reactor core and withdrawing the detectors while plo tting neutron flux versus detector position. The control system consists of two sections, one physically mounted with the drive units, the other contained in the control room. Li mit switches in each tr ansfer device provide feedback of path selection ope ration. Each gearbox drives an en coder for position feedback. One five-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 the detectors.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 e quipment for control, position indication, andflux recording for each detector. A dditional panels are pr ovided for such features as drive motor controls, core path selector swit ches, 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 52-09/29/2016 NAPS UFSAR 7.7-14 withdrawal of the detectors throug h the core from the top to a point below the bottom. In a similarmanner, other core locations ar e selected and plotte

d. Each detector provides axial flux distribution data along the center of a fuel assembly. Various radial positions of de tectors are then compared to obtain a flux map for a region of the core.The thimbles are distributed nearly uniformly over the core with approximately the same number of thimbles in each quadrant. The number and location of these thimbles have been chosen to permit the measurement of local to average peaking factors to an accuracy of

+/-5%(95% confidence). Measured nucl ear peaking factors will be in creased by 5% to allow for thisaccuracy. If the measured power peaking is larger than acceptab le, reduced power required byTechnical Specifications.

Operating plant experience has demonstrated the adequacy of the incore instrumentation in meeting the design bases stated.

7.7.1.10Computer System A 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 with additional information as to th e condition of the nuclear steam su pply system. It also has the capability to monitor inpu ts from the balance of plant syst ems and to alarm and log variousoff-normal conditions. There is no direct reactor control or protecti on action taken by thecomputer; therefore, the safety of the plant operation is not impaired by its loss.

In addition to the above opera tor support functions, the PCS also serves as the station'sEmergency Response Facility Co mputer 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 the PCS: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 parameters and equipment status. It provides alarms for various off-normal c onditions. It is also used for post-trip reviews, sequence of ev ents recording, sens or calibration, and converting values intoengineering units. Also included are reactor control and protection system supervision. Under this function are control rod cluste r position deviation and devia tion in redundant measurementsmonitoring. There are also calc ulations made under the nuclear steam su pply system process supervision function. These calcul ations include reactor dynamic thermal output, steam generatortotal thermal output, unit net efficiency, RCS leak rate, and onsite incore data collection.

Calculations performed by the PC S may be modified or added to the system from time to time Revision 52-09/29/2016 NAPS UFSAR 7.7-15under the control of an admin istrative procedure as operatio nal and regulatory requirements change.Emergency Response The PCS host computer receives plant sensor inputs via the Validyne multiplexing system and processes th is data for use in Emer gency Response related indi cation, alarm, trending, recording, and display functions. Users of the system access th is information from personal computer workstations that communicate with the host over the station's local area network and the 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 Res ponse 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 Instrumentation Much of the process instrument ation that has been provided is described in Section7.2, andSection7.3. The remaining portio n of the process instrumentatio n that is not safety-related is shown on the system flow diagrams included in the appropriat e sections of this report. System flow diagrams serve as piping a nd instrumentation diagrams (P&IDs) and illustrate the operations and processes of the various auxiliary systems. The inst rument application portion of each auxiliary system section describes the proce ss instrumentation provided for monitoring and automatically controlling that system.The Westinghouse test program, designed to demonstrate that adequate physical separation exists between safety-related and non-safety-rel ated portions of the 7300Series process analog system, is described in Reference4. The tests conclusively demons trate that automatic actuation of the safety systems is ensured even if called on to func tion at a time when severe abnormal electrical 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 pe rturbation of the card output due to a step change in the power supply voltage.

7.7.1.12Control Stations The control room, located in th e service building, cont ains all controls and instrumentation necessary to start up, ope rate, or shut dow n both units. All pertinent interrelated information Revision 52-09/29/2016 NAPS UFSAR 7.7-16required for the safe and reliable operation of the plant, including periods of transient and accident conditions, is presented there. If this area become s inaccessible, the reacto rs can be brought to and maintained in a hot-shut down condition at the auxiliary shutdown control panels located in the relay rooms below the main control room. The control room is shown in Figure1.2-3 andReference Drawing1.7.7.1.12.1Design Basis The main control room contains controls a nd instrumentation necessary for monitoring the operation of the reactors and turbine gene rators under normal a nd accident conditions.

Continuous surveillance under all operating conditions and the postulated design basis accident (DBA) conditions is provide d by licensed operators.

The main control room has f our independent communication sy stems. One system consists of standard commercial tele phones (PBX system) using leas ed lines. These telephones andseveral outside trunk lines service the station for outside calls.

This system may or may not beavailable under emergency c onditions. A second system, a communication and voice paging system, 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 installe

d. This additional system is located in separate fire areas from the existing system and consists of repeaters, handsets, antennas, hand held radios, and associated equi pment. The fourth system is sound powered, with telephone jacks and interconnecting wires at each majo r control point for test and maintenancepurposes. Sound-powered telephones are installed at various stations thr oughout 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 not rely on any power source, so it is available at all times. The communicati on systems are describedin detail in Section9.5.2.Sufficient shielding, distance, and structural integrity are provided to ensure that control room personnel shall not be su bjected to doses that in the aggregate would exceed suggestedlimits in 10CFR50 AppendixA, GDC19 as revised for AST. All equipment in this area has been designed to minimize the possibility of a condition that could l ead to inaccessibility or evacuation.

A supplemental supply of breathing-quality air is available for the main control room fromhigh-pressure air cylinders. With in an hour after MCR/ESGR envelope isolation, an emergencyventilation system with high-efficiency particulate air (HEPA)/charcoal filters is manually aligned to supply breathing air indefinitely.

The auxiliary shutdown control panels, also highly protected, are de signed with a minimum of simple control actions requir ed to bring and maintain the reactor in a hot-shutdown condition.See Section7.4 for details of the auxiliary shutdown control panels.

Revision 52-09/29/2016 NAPS UFSAR 7.7-177.7.1.12.2Design Description The 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 alarm indication to ensure safe and re liable operation under normal and accident conditions. Specialemphasis is given to maintaining control integrity during accident conditions.

The equipment in the main cont rol room is arranged with co nsideration given to the fact that certain systems normally require more operator at tention than do others. The main control board is the central item in the main control room. The control board for Unit1 is completelyindependent of the control board for Unit2. Comple tely 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 separati on and independence of the systems associatedwith Unit1 from those of Unit 2 in the main control room ar e the observance of a minimumphysical separation of 4ft. 0in.

for the independent systems. The shared systems are consideredas part of Unit1 and th e following criteria apply:1.The design criteria for maintaining separa tion and independence of all safety-related redundant systems, instrument s, power supplies, and cabling that share a common panel or control board are to provide a spacing of 12 inches or a physical barrier between theredundant components. Studies of the main control room and control boards were made to arrive at the optimum arrangeme nt 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 redu ndant components or physical barriers.Each control board has a benc h section and a vertical sect ion located behind the bench section. 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 bench console or vertical sections in functional gr oupings. Recorders and indicators are mounted on the vertical back panels in agreement, wherever appropriate, with the f unctional groupings of the bench sections. The engineered safeguards secti on of the control board is designed to minimize the time required for the operato r to evaluate the system perf ormance under accident conditions.Auxiliary vertical panels are provided in the main control room where their use simplifies the control of certain auxiliary sy stems or for systems that require less frequent operator attentionsuch as turbine supervisory, radiation moni toring, and liquid and ga seous waste disposal.

Illuminated window and audible al arm units are incorporated in to the control room to warn the operator if abnormal conditions are appr oached by any system.

Independent annunciator systems for each unit have their own identifying alarm horn tone

s. Indications a nd alarms are also Revision 52-09/29/2016 NAPS UFSAR 7.7-18 provided so that the control room operator is made aware of a ny deviation from normal conditions at remote control stations. Many of thes e conditions are also alarmed by the unit performance-and-alarm monitoring system. Audible alarms are initiated automa tically by theradiation monitoring system on high-radiation levels. Audible alarms also sound in appropriate areas through the station if high-radiation conditions are present.

Design specifications for the equipment in the main control room sp ecify no loss of protective function over the temperature range from 40°F to 120°F. Thus, there is a wide margin between design limits and the normal operating envi ronment for control room equipment. If only one 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 the design 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 shut down is required. As the control room latent heat is negligible, humidity is not a factor. A dou ble failure (both conditioning systems failing concurre ntly) is required to jeopardize the temperature control. In this very unlikely event, the control room w ould reach 120°F in about 45 minutes, which wouldstill provide sufficient time to shut down the reactor. Onsite testi ng proved the installed performance of the air conditioning systems.

Qualification testing has been performed on various safety systems such as process instrumentation, nuclear instrument ation, and relay racks.

This testing involve d demonstrating the operation of safety functions at elevated ambient temperatures to 120°F for control room equipment and in full postaccident environmen t for required equipment in the containment.

Detailed results of some of th ese 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 ensure continual operation of v ital unit and station instrumentation. Emergency li ghting is also provided.

7.7.1.13Control Room Availability The main control room is designed to be availa ble at all times. Safe occupancy of the main control room during an abnormal condition is provided for in the design of the service building.Two carbon dioxide monitors have been installed to ve rify carbon dioxide le vels in the control rooms are at accepted habitability limits. One monitor is installed in Unit1 control room and oneis installed in Unit2 control room. Adequate sh ielding and air conditioning are used to maintaintolerable radiation and air temperature levels in the main control room. Ventilation consists of totally contained redundant recirc ulating air conditioning systems designed to continue operationunder all normal and emergency c onditions. Fresh air intake and exhaust for normal use are from other independent systems, which are isolated as required. Outside air is automatically isolatedupon an SI signal. Makeup air, under emer gency conditions, is immediately av ailable from a Revision 52-09/29/2016 NAPS UFSAR 7.7-19compressed breathing-air bank and, on exhaustion, from emergency ventilating units supplyingair through HEPA and charcoal filt ers 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 emerge ncy ventilation with an emergency ventilatio n fan/filter operating in recirculation.Incorporated in the control r oom design are provisions to li mit the possibility and potential magnitude of a fire.

If a fire should occur in the ma in control room, it is expected to be only minor in magnitude so that it could be readily exti nguished by underfloor gas flooding or a hand fire extinguisher.

Smoke and vapors can be removed by the ventilat ion system during normal operations. If ventingis undesirable in any emergency, breathing apparatus is available for use. The main control room and auxiliary shutdown control panels are protected from outs ide fire, smoke, or airborneradioactivity by sealed penetrations, weather-stripped doors, ab sence of windows, and by the positive air pressure maintained in the area during normal and emergency operations.7.7.1.13.1Auxiliary Shutdown Control Panels The probability of the main control room becoming inaccessible as a result of fire or other causes is considered extremely small. However, if the operator must leave the main control room, operating procedures require that he trip the reactors and turb ine generators before leaving, so as to bring the station automatically to the no-load condition, thus en suring control at the auxiliary shutdown control panels. Each reactor unit can be brought to and maintained in a hot-shutdowncondition from the auxiliary shutdown control pa nels, which are provided with the following control provisions:1.Removal of core residual heat.2.Boration of the reactor coolant system.3.Maintenance of pressuri zer level and pressure.

These functions require the operation of auxiliary feedwater pumps, charging pumps, and boric acid transfer pumps. Appropri ate process instrumentation such as pressurizer pressure and level and steam generator pressure and level ar e provided on the auxili ary shutdown control panels. The auxiliary shutdown control panel instrumentation measurement range is shown inTable7.7-2. This equipment is sufficient to safe ly maintain the unit or units for an extended period of time in a hot-standby condition.

Each auxiliary shutdown control pa nel has the following equipment:1.No.2 auxiliary feedwater pump turbin e 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 52-09/29/2016 NAPS UFSAR 7.7-204.Pneumatic hand-control valves-auxiliary feed pump discharge open-cl ose 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.T avg 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 betw een auxiliary shutdown cont rol 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-MS 101-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 52-09/29/2016 NAPS UFSAR 7.7-2126.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 provide instrumentation to be used in conjunction with the auxiliary shut down control panel to safely shut down the reactor in accordance with 10CFR50 AppendixR (Section9.5.1).

Auxiliary monitoring panel 2-EI-CB-97A supplies Unit1 and2 indication of the following parameters:*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 following parameters:*Steam generator wide range level*Reactor coolant system cold leg temperature*Wide and source range excore neutron flux Redundant steam generator wide range level and reactor coolant cold leg temperature indicators are supplied to provide greater system reliability.

Power for the steam generator wide range level and the reactor coolant system cold leg temperature instrumentation for Unit1 is supplied by the Unit2 emergency power system.Conversely, the steam generator wide range level and the react or coolant system cold leg temperature instrumentation for Unit2 is supplied by the Unit1 emergency power system. This was done to ensure that power will be availabl e 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 switc hgear room isolation panel 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 de dicated shutdown capability include requirements for achievi ng cold shutdown conditions within 72hours. In order to reach cold shutdown one pump from the service water system, one pum p from the component cooling Revision 52-09/29/2016 NAPS UFSAR 7.7-22 water system, and one pump from the residual heat removal system are required for each reactor unit in operation. These pumps are normall y controlled from the control room.

In the event of a control room evacuation the capability to isolate da maged control circuitsand to operate the pumps in these systems from the emergency swit chgear room has beenincorporated by the installation of a transfer sw itch and a control switch on each pumps breakercompartment at the switchgear.7.7.1.13.4System Evaluation The main control room is desi gned to provide the operator with the controls, indication, and alarms necessary to control the stat ion during normal or abnormal conditions.

7.7.1.14Anticipated Transient Without Scram (ATWS) Mitigation System DescriptionThe ATWS Mitigation System (A MSAC) is a diverse control system which initiates turbine trip and auxiliary feedwater system flow upon detection of an ATWS type event. An ATWS event is described as a postulated operational occurrence or a transient such as a loss of feedwater, loss of condenser vacuum, or other design-basis ev ent coincident with a failure of the reactor protection system to shut down or scram the reactor. The AMSAC is diverse from the reactor protection system from field sensor output to, but not including, the actuation devices, except for the reactor trip via the motor generator set i nput breakers which is a diverse actuation device.The AMSAC initiates a reactor trip, turbine tri p, and auxiliary feedwate r flow (pumps start) upon detection of steam generator level less than its setpoint on an y two out of three level channels on any two out of thre e steam generators, with turbin e load greater than setpoint, permissive C-20 satisfied.

The AMSAC generic design specified in Reference5 calle d for AMSAC to be enabled when first stage turbine impulse pressure exceed ed 40% (nominal) turbine load. This genericsetpoint applies to all We stinghouse pressurized water re actors (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 tu rbine impulse pressure channels themselves.In some of the Reference5 discussions, turbine load and reactor power are usedinterchangeably. In reality, turbine load, as repr esented by impulse pressure , and reactor power arenot linearly related and the two values tend to deviate as power and load are reduced. The setpoint development did not specifically address this nonlinearity betwee n turbine impulse pressure andreactor power.As discussed in Reference5 and supporting documents, the power level at which AMSAC is required to maintain the peak RCS pressure below the 3200psig faulted stress limit for an Revision 52-09/29/2016 NAPS UFSAR 7.7-23ATWS 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 to values 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 event have shown that for a C-20 se tpoint corresponding to 50% rated thermal power, the voiding that would occur without AMSAC was still less than th at 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 cont rollers (PLC) located in the AMSAC 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 turbine impulse chamber pressure signa ls are wired to each PLC. Th e PLCs perform timing, logic functions, and provide ou tputs to the various loads. The outputs to safety-related circuits arewired through safety-related qualified class1E is olation relays. The AMSA C panel is located in the 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 level transmitters in any 2 out of 3 stea m generators less than or equal to setpoint of narrow range level span. The PLCs perform a time delay to allow the existing Reactor Prot ection System (RPS) to respond 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-generato r set will be provided trip signals.ATWS mitigation by AMSAC is automatica lly blocked below the setpoint power by permissive (C-20) that is derived from the First Stage Pressure (FSP) transmitters. This automatic block will be defeated for approximately 360seconds following a decrease of FSP below its setpoint. This time dela y 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 52-09/29/2016 NAPS UFSAR 7.7-24 initiated automatically if a loss of heat sink (steam generator i nventory loss) occurs within the360-second time delay.7.7.2AnalysisThe plant control systems are designed to ensure high reliability in any anticipated operational occurrences. Equipment used in these systems is desi gned and constructed to maintaina high level of reliability.Proper positioning of the co ntrol rods is monitored in the control room by bank arrangements of the indivi dual rod position indicators for each rod cluster control assembly. A rod deviation alarm alerts the operator of a deviation of one rod cluster control assembly from theother rods in that bank positio

n. There are also insertion limit mo nitors with visual and audible annunciation. A rod bottom alarm signal is provided to the control room for each full-length rodcluster control assembly. Four ex-core long ion ch ambers also detect asymmetrical flux distribution indicative of rod misalignment.

Overall reactivity control is achieved by the combination of soluble boron and rod cluster control assemblies. Long-term regulation of co re reactivity is accomplished by adjusting theconcentration of boric acid in the reactor coolan

t. Short-term reactivity control for power changes is accomplished by the plant co ntrol system that automatica lly moves rod cluster control assemblies. This system uses input signals including neutron flux, coolant temperature, and turbine load.The plant control systems will prevent an unde sirable 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 the following: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 depressu rization of the reactor coolant system.These analyses show that a reacto r trip setpoint is reached in time to protect the health and safety of the public under these postulated inci dents and that the resulting coolant temperatures Revision 52-09/29/2016 NAPS UFSAR 7.7-25 produce a DNBR well above the DNBR Design Limit.

Thus, there will be no cladding damage and no release of fission produc ts to the reactor coolant system under the assumption of thesepostulated worst-case failure mode s of the plant control system.

7.7.2.1Separation of Protection and Control Systems In some cases, it is advantageous to empl oy control signals deri ved from individualprotection channels through isolation amplifiers contained in the protection channel. As such, a failure in the control circuitry does not adversely affect the protection channel. Accordingly, this postulated 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 140Vdc on the isolated output portion of the circuit (i.e., the nonprotective side of the circuit) will notaffect the input (protectiv e) side of the circuit.

Where a single random fail ure can cause a control system ac tion that results in a generating station condition requiring protective action, and can also preven t proper action of a protection system channel designed to protect against th e condition, the remaining redundant protection channels are capable of providi ng the protective action even when degraded by a second random failure. This meets the applicable requirements of Section4.7 of IEEE Std279-1971.

The pressurizer pressure cha nnels needed to derive the control signals are physically isolated from the pressure channels used to derive protection signals.

Channels of the nuclear instrumentation that ar e used in the protective system are combinedto provide nonprotective functions such as signals to indicating or recording devices; the required

signals are derived throug h isolation amplifiers. These isolation amplifiers are designed so that open or short-circuit conditions as well as the application of 120Vac or 140V dc to the isolatedside of the circuit will have no effect on the in put or protection side of the circuit. As such, failures on the nonprotective side of the system will not affect the indivi dual protection channels.

7.7.2.2Reactivity Control Considerations Reactor shutdown with contro l rods is completely indepe ndent of the c ontrol 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 groups or unplanned dilution of soluble boron without exceeding acceptable fuel desi gn limits. Thus, the design 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 deliber ately withdraw a single rod cluster control assembly in the control bank; this feature is ne cessary in order to retr ieve a rod, should one be accidentally dropped. In the extremely unlikely ev ent of simultaneous el ectrical failures that could result in single withdrawal , rod deviation would be displayed on the plant annunciator, and Revision 52-09/29/2016 NAPS UFSAR 7.7-26 the rod position indicators would in dicate the relative positions of the rods in the bank. The withdrawal of a single rod cluster control assembly by operator action, whethe r deliberate or by a combination of errors, would result in the activation of the same alarm and the same visual indications.Each bank of control and shutdown rods in th e system is divided into two groups of four mechanisms each. The rods comprising a gr oup operate in parallel through multiplexing thyristors. The two groups in a bank move sequentia lly such that the firs t group is always within one step of the second group in th e bank. A definite schedule of ac tuation 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 driven in parallel, any single failure that could cause rod withdrawal would affect a minimum of onegroup of rod cluster control asse mblies. Mechanical failures are in the direction of insertion, orimmobility.

The identified multiple failure involving th e least number of components consists of open-circuit failure of the proper 2 out of 16 wires connected to the ga te of the lift coil thyristors.

The probability of open-wire (o r terminal) failure is 0.016 x10-6/hr by MIL-HBD-217A. These wire failures would have to be accompanied by the failure or disregard of the indications mentioned above. The probability of this occurrence is th erefore too low to ha ve any significance.To erroneously withdraw a singl e rod cluster control assembly , the operator would have toimproperly set the bank selector switch, the lift coil disconnect switches, and the in-hold-out switch. In addition, the three in dications would have to be disregarded or ineffective. Such a series of errors would require a complete lack of understanding and administrative control. A probability number cannot be assigned to a series of errors su ch as this. Such a number would be highly subjective.

The rod position indication system provides direct visual di splays of each control rodassembly position. The plant computer alarms for the deviatio n of rods from their banks. In addition, a rod insertion li mit monitor provides an audible and visual alar m to warn the operator of an approach to an abnormal condition due to dilution. The low-low insertion li mit alarm alerts the 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 will not 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 of the rods.In all analyses involving reactor trip, the single, highest-worth rod cluster control assembly is postulated to remain untri pped in its full-out position.

Revision 52-09/29/2016 NAPS UFSAR 7.7-27 One means of detecting a stuc k control rod assembly is av ailable from the actual rod position information displayed on the control boar

d. The control board position readouts, one for each full-length rod, give the plant operator the act ual position of the rod in steps. The indications are grouped by banks (e.g., control bankA, control bankB) to indicate to the operator the deviation of one rod with respect to other rods in a bank. This serv es as a means to identify rod deviation.

The plant computer monitors the actual position of all r ods. Should a rod be misaligned from the other rods in that ba nk and approach limits specified in the Technical Specifications, the rod deviation alarm is actuated.

Misaligned rod cluster control assemblies are also detected and alarmed in the control room via the nuclear instrumentation flux tilt monitoring system, which is independent of the plantcomputer.Isolated signals derived from the nuclear instrumentation system are compared with one another to determine if a preset amount of devi ation 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 operato r to a power imbalance caused by a misaligned rod.By the use of individual rod position readouts, the operator can de termine the deviating control rod and take corrective action. T hus, the design of the plant cont rol systems meets the applicable requirements of General Design Criterion25 (1971criteria).

The rod system can compensate for xenon burnout reactivity transi ents 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 bor on 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 temperature changes accompanying power level changes over the full range from full load to no load at the design 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 the cold-shutdown state irrespective of the disposition of the control rods. The overall reactivity control achieved by the combination of soluble bor on and rod cluster control assemblies meets the applicable require ments of General Design Criterion26 (1971criteria).

7.7.2.3Step-Load Changes Without Steam Dump The plant control system rest ores 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 52-09/29/2016 NAPS UFSAR 7.7-28 dump controller is not armed for load decreases less than or eq ual to 10%. A load demand greater than full power is prohibited by the turbine control load limit devices.The plant control system minimizes the reactor coolant average temperature deviation during the transient within a gi ven value and restores average temperature to the programmed setpoint. Excessive pressurizer pressure variations are prev ented by using spray, heaters, andpower relief valves in the pressurizer.

The control system will limit nu clear power overshoot to acc eptable values following a 10% increase in load to 100%.

7.7.2.4 Loading and Unloading Ramp loading and unloading of 5% per minute can be accepted over the 15% to 100%

power range under automa tic control without trip ping the plant. The func tion of the controlsystem is to maintain the coolant average temp erature as a function of turbine-generator load.

The coolant average temperature increases during loading and causes a continuous insurge to the pressurizer as a result of coolant expansion. The sprays limit the result ing pressure increase.Conversely, as the coolant aver age temperature is decreasing during unloadin g, there is acontinuous outsurge from the pressurizer resulti ng from coolant contr action. The pressurizer heaters limit the resulting system pressure decrease. The pressurizer water level is programmed such that the water level is above the setpoint for heater cut-out during the loading and unloading transients. 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 aver age temperature exceeds a predetermined amount, a signal 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 rod control system. The steam dump fl ow reduction is as fast as rod cluster control assemblies arecapable of inserting negative reactivity.

The rod control system can then reduce the re actor temperature to a new equilibrium value without causing overtemperature and/or overpressure conditions. The steam dump steam flow capacity 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 is restored to its programmed equilibrium value.

Revision 52-09/29/2016 NAPS UFSAR 7.7-29 The dump valves are modulate d by the reactor coolant aver age temperature signal. The required number of steam dump valves can be tripped quickl y 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 Trip Whenever the turbine-ge nerator unit trips at an operating power level above 30% power, thereactor also trips. The thermal capacity of the re actor coolant system is greater than that of thesecondary system, and because the full-load average temperature is greater than the no-load temperature, 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 by the combination of the controlled release of steam to the condenser and by the makeup of cold feedwater to the steam generators. The trip signal interfaces are shown in Figure7.3-2.The steam dump system is cont rolled from the reactor coolan t average temperature signal whose setpoint values are programmed as a function of turbine load. The actuation of the steam dump is rapid, to prevent the actua tion of the steam generator safety valves. With the dump valvesopen, the average coolant temperature starts to reduce quickly to the no-load setpoint. A direct feedback of temperature acts to proportionally close the valves to minimize the total amount of steam that is bypassed.Following the turbine trip, the feedwater flow is cut off when the average coolanttemperature decreases below a gi ven temperature or when the steam generator water level reaches a given high level.

Additional feedwater makeup is then controlled manually to restore and maintain steamgenerator water level while ensuring that the react or 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 c ondensers. This controller operates a portion of the same steam dump valves to the condensers that are used during the ini tial transient following turbine and reactor trip.The pressurizer pressure and water level fall rapidly during the transient because of coolant contraction. 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 c ontrol systems are designed to prevent the average coolant temperature from falling below the programmed no-load temperature follow ing the trip, to ensureadequate reactivity shutdown margin.

Revision 52-09/29/2016 NAPS UFSAR 7.7-3

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 Thermocouple s), 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 St ation Drawings are controlled by station procedure.

Drawing Number Description1.11715-FE-27BArrangement: Main Control Room, Elevation 276'- 9", Units 1 & 2 Revision 52-09/29/2016 NAPS UFSAR 7.7-31Table7.7-1 PLANT CONTROL SYSTEM INTERLOCKSDesignationDerivationFunctionC-11/2 neutron flux (intermediate range) above setpoint Blocks automatic and manual control rod withdrawalC-21/4 neutron flux (power range) above setpoint Blocks automatic and manual

control rod withdrawal C-32/3 overtemperature delta T above setpoint Blocks automatic and manual

control rod withdrawal Actuates turbine runback via load reference C-42/3 overpower delta T above setpointBlocks automatic and manual control rod withdrawal Actuates turbine runback via load reference C-51/1 turbine impulse chamber pressure below setpoint Blocks automatic control rod

withdrawalC-71/1 time derivative (absolute value) of turbine impulse chamber pressure (decrease only) above setpoint Makes steam dump valves available for either tripping or modulation C-8Turbine trip, 2/3 turbine auto stop oil pressure below setpoint Blocks steam dump control via load

rejection T avg controller or 4/4 turbine valves closed Makes 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 closed Blocks steam dump control via turbine trip T avg controllerC-9Any condenser pressure above setpoint, orThree circulation water pump breakers open Blocks steam dump to condenser C-111/1 bank D control rod position above setpoint Blocks automatic rod withdrawalC-20First stage pressure transmitterBlocks AMSAC below the first stage pressure setpoint Revision 52-09/29/2016 NAPS UFSAR 7.7-32Table7.7-2AUXILIARY SHUTDOWN PANEL MONITORING INSTRUMENTATION a Instrument Measurement Range1.Reactor Coolant Temperature-Average530-630°F2.Pressurizer Pressure1700-2500psig3.Pressurizer Level 0-100%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 Level 0-100%9.Relay Room Positive Ventilation0-0.50inches H 2 0a.Located at Elevation254 in the Emergency Switchgear and Relay Room.

Revision 52-09/29/2016 NAPS UFSAR 7.7-33 Figure 7.7-1SIMPLIFIED BLOCK DIAGRAM OF REACTOR CONTROL SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.7-34 Figure 7.7-2ROD CONTROLS AND ROD BLOCKS Revision 52-09/29/2016 NAPS UFSAR 7.7-35 Figure 7.7-3CONTROL BANK ROD INSERTION MONITOR Revision 52-09/29/2016 NAPS UFSAR 7.7-36 Figure 7.7-4ROD DEVIATION COMPARATOR Revision 52-09/29/2016 NAPS UFSAR 7.7-37 Figure 7.7-5STEAM DUMP CONTROL Revision 52-09/29/2016 NAPS UFSAR 7.7-38 Figure 7.7-6PRESSURIZER PRESSURE AND LEVEL CONTROL Revision 52-09/29/2016 NAPS UFSAR 7.7-39 Figure 7.7-7 PRESSURIZER HEATER CONTROL Revision 52-09/29/2016 NAPS UFSAR 7.7-40 Figure 7.7-8 FEEDWATER CONTROL AND ISOLATION Revision 52-09/29/2016 NAPS UFSAR 7.7-41 Figure 7.7-9BLOCK DIAGRAM OF PRESSURIZER PRESSURE CONTROL SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.7-42 Figure 7.7-10BLOCK DIAGRAM OF PRESSU RIZER LEVEL CONTROL SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.7-43Figure 7.7-11BLOCK DIAGRAM OF STEAM GENERATOR WATER LEVEL CONTROL SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.7-44 Figure 7.7-12BLOCK DIAGRAM OF STEAM DUMP CONTROL SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.7-45 Figure 7.7-13 BASIC FLUX-MAPPING SYSTEM Revision 52-09/29/2016 NAPS UFSAR 7.7-46 Intentionally Blank Revision 52-09/29/2016 NAPS UFSAR 7.8-17.8EMERGENCY RESPONSE TO ACCIDENTS In order to provide improved management of accidents, the Emergency Response Facilitieshave been installed in accordance with Supplement1 to NUREG-0737, NUREG-0696 and within the requirements set forth in NUREG-0700. The Emergency Res ponse Facilities (ERF) which have 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 the ERF 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 52-09/29/2016 NAPS UFSAR 7.8-2Activation of the Emergency Facilities is initiated by the Emergency Plan ImplementingProcedures (EPIP):

EPIP-1.01Emergency Manager Controlling Procedure EPIP-1.02 Response to Notification of Unusual Event EPIP-1.03 Response to Alert EPIP-1.04Response to Site Area Emergency EPIP-1.05Response to General Emergency The following EPIPs provide the instruction to direct personnel to set the EmergencyResponse Facilities e quipment into operation:

EPIP-3.02Activation of Technical Support Center EPIP-3.03 Activation of Operational Support CenterCPIP-3.2NorthAnna LEOF Activation Revision 52-09/29/2016 NAPS UFSAR 7.9-17.9INADEQUATE CORE COOLING MONITOR (ICCM) SYSTEMIn response to NUREG-0578 (Reference1), inst rumentation 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 and Combustion Engineering, and meet s all the requirements of Regulatory Guide1.97 (Reference2).The ICCM consists of the foll owing three redundant subsystems that share co mmon redundant calculator devices and continuous control room displays: Core Exit Thermocouple (CET) System, Core Cooling Monitor (CCM) System, and Reactor Vessel Le vel Instrumentation System(RVLIS).The system provides means for acquiring data only, and performs no operational unit control. The system readily detects and disp lays 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 piping tubing, and conduit are seismically supported. All equipment has seismically-qualified mountingsupports and the redundant electronics, in cluding the microprocessor, are housed in seismically-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 material s used in the designare consistent with original stat ion design criteria, exce pt that compression t ype fittings, besides being used for the connection at th e instruments, are also used in the RVLIS tubing connecting the reactor vessel head vent valve to the high-volu me sensors. These fittings, which meet system design pressures and temperatures, are necessary to prevent damaging the tubing when the reactor vessel head is removed during refueling.

7.9.2Design Description 7.9.2.1Core Exit Thermocouple (CET) Sy stem-Subsystem of ICCM SystemThe Core Exit Thermocouple System uses inputs from up to 50 of the 51 incore thermocouples (51st availa ble as spare) to calculate and displa y temperature of the reactor coolant as it exits the core. Refer to Figures4.4-20 (Unit1) and4.4-21 (Unit2) for the locations of thermocouples that have been abandoned in place.

Revision 52-09/29/2016 NAPS UFSAR 7.9-2The CET system consists of TypeK, ungrounded, stainless steel sheathed thermocouples.

Refer to UFSAR Section7.7.1.9.1 for description of th e quantity and design of the thermocouples.Safety-related thermocouples from each channel (25 for TrainA and 25 for TrainB) are wired 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 to calculate and to display the water level height in the reacto r vessel during all plant conditions(except mode6).RVLIS uses differential pressure (d/p) measuring devices to measure vessel level or relative void content of the circulating primary coolant sy stem fluid. The system is redundant and includes automatic compensation for potential temperature variations of the impulse lines. Essential information 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 the vessel, and from the hot legs to the top of the vessel. To do this, it is n ecessary to tap into the reactor coolant system at the re actor vessel head, seal table, and the resistance temperaturedetector bypass piping of the hot legs of two reactor coolant syst em loops. Filled, sealed capillary impulse lines are used from the reactor coolant system to the tr ansmitters. Each capillary line is sealed 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-leg temperatures and impulse line temperatures will be monitored a nd used to compensate for fluiddensity variations occurring during operating conditions.

Revision 52-09/29/2016 NAPS UFSAR 7.9-3 This 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. Th is d/p cell provides a meas urement of reactor vessel level above the hot leg pipe when the reactor coolant pump (RCP) in the loop with the hot leg connection is not operating.*Reactor Vessel-Dynamic Head Range. This d/

p cell provides an indication of reactor core and internals pressure drop for any combination of operati ng RCPs. Comparison ofthe measured pressure drop with the normal, single-phase pressure drop provides an approximate indication of the re lative void content or density of the circulating fluid. This instrument monitors coolan t conditions on a continuing basis during forced flow conditions.*Reactor Vessel-Full Range. This d/p cell provides an indica tion of reactor vessel levelfrom the bottom of the reactor vessel to the top of the reactor duri ng natural circulation conditions.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 c ontainment structure following an accident.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 containment environment (temperature, pressu re, radiation) during an accide nt. The cells are also located outside 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 du ring all plant conditions. These input parameters provide the plant operators wi th complete information on corecooling.Software algorithmus perform calculations which determine the equivalent saturated temperature (T sat) based on reactor wide range pressure. This (T sat) value is used to determine thesubcooled margin for the average of the five highest core exit ther mocouples temperature.

Revision 52-09/29/2016 NAPS UFSAR 7.9-

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 Class1 E Equipment for Nuclear PowerGenerating Stations, 1974.4.IEEE Std344-1975, Recommended Practices for Seismic Qualification of Class1EEquipment for Nuclear Power Generating Stations , 1975.

Revision 52-09/29/2016 NAPS UFSAR 7.9-5Table7.9-1 INADEQUATE CORE COOLING MO NITOR (ICCM) SYSTEM DATAI.ICCM Display1.Type/LocationFlat Plasma Graphic/Vertical Main Control Board2.Operator Interface/Location4 - Butt on Keypad/Main Control Board Benchboard3.RedundancyYes4.Information Displayed*DATA LINK FAILURE message indicates the datalink from the system micr oprocessor to the display has failed*Incore thermocouple display graphics*Core Cooling display graphics

• RVLIS display graphics5.Display Update RateEvery two secondsII.Calculator1.Type Microprocessor (16 Bit)2.LocationAnnunciator Room3.Operator Interface Local Display Panel with switch es 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 per unit/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 52-09/29/2016 NAPS UFSAR 7.9-6 III.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 30minutes showing static head (full range level) with a range of 0-120% level, dynamic head with a range of0-120% full dP, and da ta quality based on the number of sensors used in the computations*Graphics layout of complete RVLIS process,including RVLIS status, RC S wide range pressure, and hot leg temperature*Instantaneous vessel le vel conditions for dynamichead full dP, and full and upper range level in ranges between 0 and 120%*RVLIS diagnostic information.IV.Core Cooling Monitor Sy stem - 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 the saturation temperature cu rve and the over pressureand over temperature regions and current RCS coolant conditions plus trending of coolant conditions for previous 30 minutes. The P-T curvevertical axis range is 0 to 3000psig wide range pressure and the horizontal axis range is 0 to 700°Fof the average of th e five highest incore thermocouples. Also displayed digitally are theinput parameters and margin-to-saturation.4.AlarmControl board annunciati on on approach-to-saturation temperatureTable7.9-1(continued)

INADEQUATE CORE COOLING MO NITOR (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 52-09/29/2016 NAPS UFSAR 7.9-7V.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 showi ng temperature at each thermocouple location for that channel*Core map showing the maximum, minimum and average temperature for that channel for each quadrant and the subcooled temperature*Tabulation of each thermocouple for that channel by 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. Also listed are the subcooling temperature and the CET temperature based on the average of the five highest thermocouples per core*CET diagnostic information*Thermocouple range of all displays is 0-2,300°FTable7.9-1(continued)

INADEQUATE CORE COOLING MO NITOR (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 52-09/29/2016 NAPS UFSAR 7.9-8 Intentionally Blank