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Technical Specifications for Hope Creek Generating Station. Docket No. 50-354.(Public Service Electric and Gas Company)
	ML20205D512
Person / Time
Site:	Hope Creek
Issue date:	07/31/1986
From:	; Office of Nuclear Reactor Regulation
To:	;
References
	NUREG-1202, NUDOCS 8608180070
	Download: ML20205D512 (515)
	v • d • e

{{#Wiki_filter:_- __ _ - NUREG-1202 O Technical Specifications , 4 Hope Creek Generating Station l Docket No. 50-354 Appendix "A" to l License No. NPF-57 l 1.O l U.S. Nuclear Regulatory l Commission Office of Nuclear Reactor Regulation July 1986 y no v, a b O 4 D ADOC g l

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NUREG-1202 d Technical SpecsTesi;cim Hope Creek Generating Station Docket No. 50-354 i' Appendix "A" to License No. NPF-57 i

U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation !

July 1986 p e= ae ,, h' l l l l

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i a 4 i INDEX

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      ,,               DEFINITIONS
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v SECTION 1.0 DEFINITIONS PAGE 1.1 ACTI0N............................................................... 1-1

1. 2 AVERAGE PLANAR EXP0SURE.............................................. 1-1 1.3 AVERAGE PLANAR LINEAR HEAT GENERATION RATE........................... 1-1 1.4 CHANNEL CALIBRATION.................................................. 1-1

1. 5 CHANNEL CHECK........................................................ 1-1 1.6 CHANNEL FUNCTIONAL TEST............................................. 1-1 1.7 C O R E A LT E R AT I O N . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 1.8 CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY...................... 1-2

, 1.9 CRITICAL POWER RATI0................................................. 1-2 1.10 DOSE EQUIVALENT I-131................................................ 1- 2 1.11 E-AVERAGE DISINTEGRATION ENERGY...................................... 1-2 1.12 EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME................... 1-2 4 1.13 END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME............ 1-3 1.14 FRACTION OF LIMITING POWER DENSITY................................... 1-3 1.15 FRACTION OF RATED THERMAL P0WER...................................... 1-3 1.16 FREQUENCY N0TATION................................................... 1-3 1.17 IDENTIFIED LEAKAGE................................................... 1-3 1.18 ISOLATION SYSTEM RESPONSE TIME....................................... 1-3 1.19 LIMITING CONTROL R00 PATTERN......................................... 1-3 1.20 LINEAR HEAT GENERATION RATE.......................................... 1-4

1.21 LOGIC SYSTEM FUNCTIONAL TEST......................................... 1-4 i

1.22 MAXIMUM FRACTION OF LIMITING POWER DENSITY........................... 1-4

'()                    1.23 MEMBER (S) 0F THE PUBLIC..............................................                                                                1-4 1.24 MINIMUM CRITICAL POWER RATI0.........................................                                                                 1-4 HOPE CREEK                                                 i

INDEX DEFINITIONS SECTION DEFINITIONS (Continued) PAGE 1.25 0FF-GAS RADWASTE TREATMENT SYSTEM.................................... 1-4 1.26 0FFSITE DOSE CALCULATION MANUAL...................................... 1-4 1.27 OPERABLE - OPERABILITY............................................... 1-5 1.28 OPERATIONAL CONDITION - C0NDITION.................................... 1-5 1.29 PPYSICS TESTS........................................................ 1-5 1.30 PRESSURE BOUNDARY LEAKAGE............................................ 1-5 1.31 PRIMARY CONTAINMENT INTEGRITY........................................ 1-5 1.32 PROCESS CONTROL PR0 GRAM.............................................. 1-6 1.33 PURGE-PURGING........................................................ 1-6 1.34 RATED THERMAL P0WER.................................................. 1-6 1.35 REACTOR PROTECTION SYSTEM RESPONSE TIME.............................. 1-6 1.36 REPORTABLE EVENT..................................................... 1-6 1.37 R00 DENSITY.......................................................... 1-6 1.38 SECONDARY CONTAINMENT INTEGRITY...................................... 1-7 1.39 SHUTDOWN MARGIN...................................................... 1-7 1.40 SITE B0VNDARY........................................................ 1-7 1.41 SOLIDIFICATION....................................................... 1-8 1.42 SOURCE CHECK......................................................... 1-8 1.43 STAGGERED TEST BASIS................................................. 1-8 1.44 THERMAL P0WER........................................................ 1-8 1.45 TURBINE BYPASS SYSTEM RESPONSE TIME.................................. 1-8 1.46 UNIDENTIFIED LEAKAGE................................................. 1-8 1.47 UNRESTRICTED AREA.................................................... 1-8 HOPE CREEK ii

_ __ . . _ _ _ _ . . . - _ _ . _ . ~ . _ _ - _ _ _ _ . _ _ . _ _ _ _ . . _ _ _ _ . _ . . _ . _ . _ _ _ _ _ _ . - . _ . ._

1. .

INDEX i i i DEFINITIONS i i l SECTION 4

DEFINITIONS (Continued) PAGE i

l 1.48 VENTILATION EXHAUST TREATMENT SYSTEM................................. 1-9 1 l 1.49 VENTING.............................................................. 1-9 TABLE 1.1, SURVEILLANCE FREQUENCY NOTATI0N................................ 1-10 t

TABLE 1.2, OPERATIONAL CONDITIONS......................................... 1-11 ,

i i i i , ! I i i , ,l i 1 , l i 4 1 i i i 1 1 I 1 l i . i 1 h t HOPE CREEK iii l

INDEX SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION PAGE 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low F10w............................. 2-1 THERMAL POWER, High Pressure and High F10w.......................... 2-1 Reacter Coolant System Pressure..................................... 2-1 Reactor Vessel Water Leve1.......................................... 2-2 2.2 LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints................. 2-3 Table 2.2.1-1 Reactor Protection System Instrumentation Setpoints........................................... 2-4 BASES 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low F10w............................. B 2-1 THERMAL POWER, High Pressure and High F10w.......................... B 2-2 Table B2.1.2-1 Uncertainties Used in the Determination of the Fuel Cladding Safety Limit..................... B 2-3 Table B2.1.2-2 Nominal Values of Parameters Used in the Statistical Analysis of Fuel Cladding Integrity Safety Limit............................. B 2-4 Reactor Coolant System Pressure..................................... B 2-5 Reactor Vessel Water Leve1.......................................... B 2-5 2.2 LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints.................. B 2-6 O HOPE CREEK iv

INDEX

/o\

h LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.0 APPLICABILITY................................................ 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN........................................... 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES...................................... 3/4 1-2 3/4.1.3 CONTROL RODS Control Rod Operability................................... 3/4 1-3 Control Rod Maximum Scram Insertion Times................. 3/4 1-6 Control Rod Average Scram Insertion Times................. 3/4 1-7 Four Control Rod Group Scram Insertion Times.............. 3/4 1-8 Control Rod Scram Accumulators........................... 3/4 1-9 Control Rod Drive Coupling................................ 3/4 1-11 Control Rod Position Indication........................... 3/4 1-13 V Control Rod Drive Housing Support......................... 3/4 1-15 3/4.1.4 CONTROL R0D PROGRAM CONTROLS Rod Worth Minimizer....................................... 3/4 1-16 Rod Sequence Control System............................... 3/4 1-17 Rod Block Monitor......................................... 3/4 1-18 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM............................. 3/4 1-19 Figure 3.1.5-1 Sodium Pentaborate Solution Volume / Concentration Requirements............... 3/4 1-21 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE................ 3/4 2-1 Maximum Average Planar Linear Heat Generation Rate (MAPHLGR) versus Average Planar Exposure Figure 3.2.1-1 Initial Core Fuel Type P8CIB071.......... 3/4 2-2 l Figure 3.2.1-2 Initial Core Fuel Type P8CIB094.......... 3/4 2-3 l k HOPE CREEK v i

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Figure 3.2.1-3 Initial Core Fuel Type P8CIB163.......... 3/4 2-4 Figure 3.2.1-4 Initial Core Fuel Type P8CIB248.......... 3/4 2-5 Figure 3.2.1-5 Initial Core Fuel Type P8CIB278.......... 3/4 2-6 3/4 2.2 APRM SETP0lNTS............................................ 3/4 2-7 3/4.2.3 MINIMUM CRITICAL POWER RATI0.............................. 3/4 2-8 Figure 3.2.3-1 Minimum Critical Power Ratio (MCPR) I versus at Rated Flow..................... 3/4 2-10 Figure 3.2.3-2 K f Factor................................ 3/4 2-11 Table 3.2.3-1 MCPR Feedwater Heating Capacity Adjustment............................... 3/4 2-12 3/4.2.4 LINEAR HEAT GENERATION RATE............................... 3/4 2-13 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION................. 3/4 3-1 Table 3.3.1-1 Reactor Protection System Instrumentation........................... 3/4 3-2 Table 3.3.1-2 Reactor Protection System Response Times..................................... 3/4 3-6 Figure 4.3.1.1-1 Reactor Protection System Surveillance Requirements........................... 3/4 3-7 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION....................... 3/4 3-9 Table 3.3.2-1 Isolation Actuation Instrume.ntation....... 3/4 3-11 Table 3.3.2-1 Isolation Actuation Instrumentation Setpoints................................. 3/4 3-22 Table 3.3.2-3 Isolation System Instrumentation Response Time...................................... 3/4 3-26 Table 4.3.2.1-1 Isolation Actuation Instrumentation Surveillance Requirements................. 3/4 3-28 O HOPE CREEK vi

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION... 3/4 3-32 Table 3.3.3-1 Emergency Core Cooling System Actuation Instrumentation........................... 3/4 3-33 Table 3.3.3-2 Emergency Core Cooling System Actuation Instrumentation Setpoints................. 3/4 3-36 Table 3.3.3-3 Emergency Core Cooling System Response Times..................................... 3/4 3-38 Table 4.3.3.1-1 Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements............................ 3/4 3-39 i 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS Recirculation Pump Trip System Instrumentation....... 3/4 3-41 I Table 3.3.4.1-1 ATWS Recirculation Pump Trip System ( Instrumentation......................... 3/4 3-42 i Table 3.3.4.1-2 ATWS Recirculation Pump Trip System Instrumentation Setpoints............... 3/4 3-43 Table 4.3.4.1-1 ATWS Recirculation Pump Trip Actuation Instrumentation Surveillance Requirements............................ 3/4 3-44 ]. End-of-Cycle Recirculation Pump Trip System 4 Instrumentation........................................... 3/4 3-45 Table 3.3.4.2-1 End-of-Cycle Recirculation Pump Trip System Instrumentation.................. 3/4 3-47 Table 3.3.4.2-2 End-of-Cycle Recirculation Pump Trip Setpoints............................... 3/4 3-48 Table 3.3.4.2-3 End-of-Cycle Recirculation Pump Trip System Response Time.................... 3/4 3-49 Table 4.3.4.2.1-1 End-of-Cycle Recirculation Pump Trip System Surveillance Requirements...... 3/4 3-50 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION........................................... 3/4 3-51 1

,              HOPE CREEK                                           vii

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Table 3.3.5-1 Reactor Core Isolation Cooling System Actuation Instrumentation................. 3/4 3-52 Table 3.3.5-2 Reactor Core Isolation Cooling System Actuation Instrumentation Setpoints....... 3/4 3-54 Table 4.3.5.1-1 Reactor Core Isolation Cooling System Actuation Instrumentation Surveillance Requirements............................ 3/4 3-55 3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION......................... 3/4 3-56 Table 3.3.6-1 Control Rod Block Instrumentation......... 3/4 3-57 Table 3.3.6-2 Control Rod Block Instrumentation Setpoints................................. 3/4 3-59 Table 4.3.6-1 Control Rod Block Instrumentation Surveillance Requirements................. 3/4 3-60 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation...................... 3/4 3-62 Table 3.3.7.1-1 Radiation Monitoring Instrumentation.... 3/4 3-63 Table 4.3.7.1-1 Radiation Monitoring Instrumentation Surveillance Requirements............... 3/4 3-66 Seismic Monitoring Instrumentation........................ 3/4 3-68 l Table 3.3.7.2-1 Seismic Monitoring Instrumentation...... 3/4 3-69 Table 4.3.7.2-1 Seismic Monitoring Instrumentation l Surveillance Requirements............... 3/4 3-70 Meteorological Monitoring Instrumentation................. 3/4 3-71 Table 3.3.7.3-1 Meteorological Monitoring Instrumentation......................... 3/4 3-72 Table 4.3.7.3-1 Meteorological Monitoring Instrumentation Surveillance Requirements............................ 3/4 3-73 Remote Shutdown Monitoring Instrumentation and Controls... 3/4 3-74 i ( i HOPE CREEK viii l I l

INDEX

( LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS , l SECTION PAGE Table 3.3.7.4-1 Remote Shutdown Monitoring Instrumentation......................... 3/4 3-75 Table 3.3.7.4-2 Reraote Shutdown Systems Controls. . . . . . . . 3/4 3-77 Table 4.3.7.4-1 Remote Shutdown Monitoring Instrumentation Surveillance Requirements............... ............ 3/4 3-82 Accident Monitoring Instrumentation....................... 3/4 3-84 Table 3.3.7.5-1 Accident Monitoring Instrumentation..... 3/4 3-85 Table 4.3.7.5-1 Accident Monitoring Instrumentation Surveillance Requirements............... 3/4 3-87 Source Range Monitors..................................... 3/4 3-88 Traversing In-Core Probe System........................... 3/4 3-89 Loose-Part Detection System............................... 3/4 3-90 Radioactive Liquid Effluent Monitoring Instrumentation.... 3/4 3-91 Table 3.3.7.9-1 Radioactive Liquid Effluent Monitoring Instrumentation.............. 3/4 3-92 Table 4.3.7.9-1 Radioactive Liquid Effluent Monitoring Instrumentation Surveillance Requirements............................ 3/4 3-94 Radioactive Gaseous Effluent Monitoring Instrumentation... 3/4 3-96 Table 3.3.7.10-1 Radioactive Gaseous Effluent Monitoring Instrumentation............. 3/4 3-97 Table 4.3.7.10-1 Radioactive Gaseous Effluent Monitoring Instrumentation Surveillance Requirements........................... 3/4 3-100 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM....................... 3/4 3-103 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION........................................... 3/4 3-105 Table 3.3.9-1 Feedwater/ Main Turbine Trip System Actuation Instrumentation................. 3/4 3-106 O i g HOPE CREEK ix

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Table 3.3.9-2 Feedwater/ Main Turbine Trip System Actuation Instrumentation Setpoints....... 3/4 3-107 Table 4.3.9.1-1 Feedwater/ Main Turbine Trip System Actuation Instrumentation Surveillance Requirement............................. 3/4 3-108 -3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM Recirculation Loops....................................... 3/4 4-1 Figure 3.4.1.1-1 % Rated Thermal Power Versus Core Flow............................. 3/4 4-3 Jet Pumps................................................. 3/4 4-4 Recirculation Pumps....................................... 3/4 4-5 Idle Recirculation Loop Startup........................... 3/4 4-6 3/4.4.2 SAFETY / RELIEF VALVES Safety / Relief Valves...................................... 3/4 4-7 Safety / Relief Valves Low-Low Set Function................. 3/4 4-9 3/4 4.3 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems................................. 3/4 4-10 Operational Leakage....................................... 3/4 4-11 Table 3.4.3.1-1 Reactor Coolant System Pressure Isolation Valves........................ 3/4 4-13 Table 3.4.3.2-2 Reactor Coolant System Interface Valves Leakage Pressure Monitors....... 3/4 4-14 3/4.4.4 CHEMISTRY................................................. 3/4 4-15 Table 3.4.4-1 Reactor Coolant System Chemistry Limits.... ............................... 3/4 4-17 3/4.4.5 SPECIFIC ACTIVITY......................................... 3/4 4-18 Table 4.4.5-1 Primary Coolant Specific Activity Sample and Analysis Program...................... 3/4 4-20 HOPE CREEK x

INDEX p) LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS V SECTION PAGE 3/4.4.6 PRESSURE / TEMPERATURE LIMITS Reactor Coolant System.................................... 3/4 4-21 Figure 3.4.6.1-1 Minimum Reactor Pressure Vessel Metal Temperature Versus Reactor Vessel Pressure............................... 3/4 4-23 Table 4.4.6.1.3-1 Reactor Vessel Material Surveillance Program Withdrawal Schedule........... 3/4 4-24 Reactor Steam Dome........................................ 3/4 4-25 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES.......................... 3/4 4-26 3/4.4.8 STRUCTURAL INTEGRITY...................................... 3/4 4-27 3/4.4.9 RESIDUAL HEAT REMOVAL Hot Shutdown.............................................. 3/4 4-28 Cold Shutdown............................................. 3/4 4-29 (O) 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - 0PERATING.......................................... 3/4 5-1 3/4.5.2 ECCS - SHUTD0WN........................................... 3/4 5-6 3/4.5.3 SUPPRESSION CHAMBER....................................... 3/4 5-8 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity............................. 3/4 6-1 Primary Containment Leakage............................... 3/4 6-2 Primary Containment Air Locks............................. 3/4 6-5 MSIV Sealing System....................................... 3/4 6-7 Primary Containment Structural Integrity.................. 3/4 6-8 Drywell and Suppression Chamber Internal Pressure......... 3/4 6-9 D J HOPE CREEK xi

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Drywell Average Air Temperature........................... 3/4 6-10 Drywell and Suppression Chamber Purge System.............. 3/4 6-11 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression Chamber....................................... 3/4 6-12 Suppression Pool Spray.................................... 3/4 6-15 Suppression Pool Cooling.................................. 3/4 6-16 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES...................... 3/4 6-17 Table 3.6.3-1 Primary Containment Isolation Valves...... 3/4 6-19 3/4.6.4 VACUUM RELIEF Suppression Chamber - Drywell Vacuum Breakers. . . . . . . . . . . . . 3/4 6-43 Reactor Building - Suppression Chamber Vacuum ! Breakers......................... ... .. ............... 3/4 6-45 3/4.6.5 SECONDARY CONTAINMENT Secondary Containment Integrity........................... 3/4 6-47 Secondary Containment Automatic Isolation Dampers......... 3/4 6-49 l Table 3.6.5.2-1 Secondary Containment Ventilation System Automatic Isolation Dampers Isolation Group No. 19.................. 3/4 6-50 Filtration, Recirculation and Ventilation System.......... 3/4 6-51 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL i l Containment Hydrogen Recombiner Systems................... 3/4 6-54 Drywell and Suppression Chamber Oxygen Concentration...... 3/4 6-55 3/4.7 PLANT SYSTEMS i 3/4.7.1 SERVICE WATER. SYSTEMS Safety Auxiliaries Cooling System......................... 3/4 7-1 Station Service Water System.............................. 3/4 7-3 Ultimate Heat Sink........................................ 3/4 7-5 l 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM.................. 3/4 7-6 HOPE CREEK xii

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.7.3 FLOOD PROTECTION.......................................... 3/4 7-9 Table 3.7.3-1 Perimeter Flood Doors..................... 3/4 7-10 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM..................... 3/4 7-11 3/4.7.5 SNUBBERS.................................................. 3/4 7-13 Figure 4.7.5-1 Sample Plan 2) for Snubber l Functional Test......................................... 3/4 7-18 3/4.7.6 SEALED SOURCE CONTAMINATION............................... 3/4 7-19 3.4.7.7 MAIN TURBINE BYPASS SYSTEM................................ 3/4 7-21 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES A.C. Sources-0perating.................................... 3/4 8-1 V Table 4.8.1.1.2-1 Diesel Generator Test Schedule........ 3/4 8-10 A.C. Sources-Shutdown..................................... 3/4 8-11 3/4.8.2 D.C. SOURCES D.C. Sources-Operating.................................... 3/4 8-12 Table 4.8.2.1-1 Battery Surveillance Requirements. . . . . . . 3/4 8-16 D.C. Sources-Shutdown..................................... 3/4 8-17 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS Distribution - Operating.................................. 3/4 8-18 Distribution - Shutdown................................... 3/4 8-21 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Primary Containment Penetration Conductor Overcurrent Protective Devices...................................... 3/4 8-24 Table 3.8.4.1-1 Primary Containment Penetration Conductor Overcurrent Protective Devices.......... 3/4 8-26 V Motor Operated Valve Thermal Overload Protection (Bypassed).............................................. 3/4 8-30 HOPE CREEK xiii

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Table 3.8.4.2-1 Motor Operated Valves-Thermal Overload Protection (Bypassed)................... 3/4 8-31 Motor Operated Valve Thermal Overload Protection (Not Bypassed).......................................... 3/4 8-38 Table 3.8.4.3-1 Motor Operated Valves-Thermal Overload Protection (Not Bypassed)............... 3/4 8-39 Reactor Protection System Electric Power Monitoring....... 3/4 8-40 Class 1E Isolation Breaker Overcurrent Protection Devices (Breaker Tripped by LOCA Signal)................ 3/4 8-41 Table 3.8.4.5-1 Class IE Isolation Breaker Overcurrent Protective Devices (Breaker Tripped by a LOCA Signal)........................... 3/4 8-42 Power Range Neutron Monitoring System Electric Power Monitoring.............................................. 3/4 8-44 3/4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH....................................... 3/4 9-1 l 3/4.9.2 INSTRUMENTATION........................................... 3/4 9-3 3/4.9.3 CONTROL R0D P0SITION...................................... 3/4 9-5 3/4.9.4 DECAY TIME................................................ 3/4 9-6 3/4.9.5 COMMUNICATIONS............................................ 3/4 9-7 l l 3/4.9.6 REFUELING PLATF0RM........................................ 3/4 9-8 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE P00L. . . . . . . . . . . . . . . . . . . . 3/4 9-10 3/4.9.8 WATER LEVEL - REACTOR VESSEL.............................. 3/4 9-11 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE P00L..................... 3/4 9-12 l l 3/4.9.10 CONTROL R0D REMOVAL Single Control Rod Removal................................ 3/4 9-13 Multiple Control Rod Removal.............................. 3/4 9-15 O HOPE CREEK xiv

p INDEX b) LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION High Water Level.......................................... 3/4 9-17 Low Water Leve1........................................... 3/4 9-18 3/4.10 SPECIAL TEST EXCEPTIONS 3/4,10.1 PRIMARY CONTAINMENT INTEGRITY............................. 3/4 10-1 3/4.10.2 R00 SEQUENCE CONTROL SYSTEM............................... 3/4 10-2 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS............................ 3/4 10-3 3/4.10.4 RECIRCULATION L00PS....................................... 3/4 10-4 3/4.10.5 0XYGEN CONCENTRATION...................................... 3/4 10-5 3/4.10.6 TRAINING STARTUPS......................................... 3/4 10-6 O 3/4.10.7 SPECIAL INSTRUMENTATION - INITIAL CORE LOADING............ 3/4 10-7 3/4.11 RADI0 ACTIVE EFFLUENTS 3/4.11.1 LIQUID EFFLUENTS Concentration............................................. 3/4 11-1 Table 4.11.1.1.1-1 Radioactive Liquid Waste Sampling and Analysis Program.... 3/4 11-2 ! Dose...................................................... 3/4 11-5 Liquid Waste Treatment.................................... 3/4 11-6 Liquid Holdup Tanks....................................... 3/4 11-7 3/4.11.2 GASE0US EFFLUENTS Dose Rate................................................. 3/4 11-8 Table 4.11.2.1.2-1 Radioactive Gaseous Waste Sampling and Analysis Program.... 3/4 11-9 Dose - Noble Gases........................................ 3/4 11-12 Dose - Iodine-131, Iodine-133, Tritium, and Radionuclides in Particulate Form....................................... 3/4 11-13 p Gaseous Radwaste Treatment................................ 3/4 11-14 V Ventilation Exhaust Treatment System...................... 3/4 11-15 HOPE CREEK xv

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Explosive Gas Mixture..................................... 3/4 11-16 Main Condenser............................................ 3/4 11-17 Venting or Purging........................................ 3/4 11-18 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT......................... 3/4 11-19 3/4.11.4 TOTAL 00SE................................................ 3/4 11-20 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MO N I TO R I NG P R0G RAM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 12-1 Table 3.12.1-1 Radiological Environmental Monitoring Program................... 3/4 12-3 Table 3.12.1-2 Reporting Levels For Radioactivity Concentrations In Environmental Samples.............................. 3/4 12-9 Table 4.12.1-1 Detection Capabilities For Environmental Sample Analysis........ 3/4 12-10 3/4.12.2 LAND USE CENSUS........................................... 3/4 12-13 3/4.12.3 INTERLABORATORY COMPARIS0N PR0 GRAM........................ 3/4 12-14 l t l l l O HOPE CREEK xvi

INDEX (a 1

s ,,/ s BASES SECTION PAGE 3/4.0 APPLICABILITY................................................ B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN...................................... B 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES................................. B 3/4 1-1 3/4.1.3 CONTROL R0DS......................................... B 3/4 1-2 3/4.1.4 CONTROL ROD PROGRAM C0KTROLS......................... B 3/4 1-3 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM........................ B 3/4 1-4 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE........... B 3/4 2-1 3/4.2.2 APRM SETP0INTS....................................... B 3/4 2-2 Table B3.2.1-1 Significant Input Parameters Os to the Loss-of-Coolant Accident Analysis..................... B 3/4 2-3 3/4.2.3 MINIMUM CRITICAL POWER RATI0.....,................... B 3/4 2-4 3/4.2.4 LINEAR HEAT GENERATION RATE..... .................... B 3/4 2-5 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION............ B 3/4 3-1 l 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION.................. B 3/4 3-2 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION...................................... B 3/4 3-2 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION.... B 3/4 3-3 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION...................................... B 3/4 3-4 1 3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION.................... B 3/4 3-4 3/4.3.7 MONITORING INSTRUMENTATION C Radiation Monitoring Instrumentation................. B 3/4 3-4 l HOPE CREEK xvii

INDEX BASES SECTION PAGE INSTRUMENTATION (Continued) Seismic Monitoring Instrumentation................... B 3/4 3-4 Meteorological Monitoring Instrumentation............ B 3/4 3-4 Remote Shutdown Monitoring Instrumentation and Controls....................................... B 3/4 3-5 Accident Monitoring Instrumentation.................. B 3/4 3-5 Source Range Monitors................................ B 3/4 3-5 Traversing In-Core Probe System...................... B 3/4 3-5 Loose-Part Detection System.......................... B 3/4 3-6 Radioactive Liquid Effluent Monitoring Instrumentation.................................... B 3/4 3-6 Radioactive Gaseous Effluent Monitoring Instrumentation.................................... B 3/4 3-6 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM.................. B 3/4 3-7 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION.................................... B 3/4 3-7 Figure B3/4 3-1 Reactor Vessel Water Level........... B 3/4 3-8 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM................................. B 3/4 4-1

3/4.4.2 SAFETY / RELIEF VALVES................................. B 3/4 4-2 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE l

Leakage Detection Systems............... ............ B 3/4 4-3 Operational Leakage.................................. B 3/4 4-3 3/4.4.4 CHEMISTRY............................................ B 3/4 4-3 3/4.4.5 SPECIFIC ACTIVITY.................................... B 3/4 4-4 3/4.4.6 PRESSURE / TEMPERATURE LIMITS..................... .... B 3/4 4-5 Table B3/4.4.6-1 Reactor Vessel Toughness............ B 3/4 4-7

                            ' Figure B3/4.4.6-1 Fast Neutron Fluence (E>1Mev) at (1/4)T as a Function of Service Life...........       B 3/4 4-8 HOPE CREEK                                           xviii

INDEX BASES SECTION PAGE 3/4.4.7 MAIN STEAM LINE ISOLATION VAI,VES..................... B 3/4 4-6 3/4.4.8 STRUCTURAL INTEGRITY................................. B 3/4 4-6 3/4.4.9 RESIDUAL HEAT REM 0 VAL................................ B 3/4 4-6 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1/2 ECCS - OPERATING and SHUTD0WN........................ B 3/4 5-1 3/4.5.3 SUPPRESSION CHAMBER.................................. B 3/4 5-2 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity........................ B 3/4 6-1 Primary Containment Leakage.......................... B 3/4 6-1

   \                    Primary Containment Air                Locks........................        B 3/4 6-1 MSIV Sealing System..................................                       B 3/4 6-1

Primary Containment Structural Integrity............. B 3/4 6-2 Drywell and Suppression Chamber Internal Pressure. . . . B 3/4 6-2 Drywell Average Air Temperature. . . . . . . . . . . . . . . . . . . . . . B 3/4 6-2 Drywell and Suppression Chamber Purge System......... B 3/4 6-2 l

t 3/4.6.2 DEPRESSURIZATION SYSTEMS............................. B 3/4 6-3 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES................. B 3/4 6-5 3/4.6.4 VACUUM RELIEF........................................ B 3/4 6-5 3/4.6.5 SECONDARY CONTAINMENT................................ B 3/4 6-5

3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTR0L............... B 3/4 6-6 l

HOPE CREEK xix l l

INDEX BASES SECTION PAGE i 3/4.7 PLANT SYSTEMS i 3/4.7.1 SERVICE WATER SYSTEMS................................ B 3/4 7-1 t 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM............. B 3/4 7-1 3/4.7.3 FLOOD PROTECTION..................................... B 3/4 7-1 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM;............... B 3/4 7-1 3/4.7.5 SNUBBERS............................................. B 3/4 7-2 3/4.7.6 SEALED SOURCE CONTAMINATION.......................... B 3/4 7-4 3/4.7.7 MAIN TURBINE BYPASS SYSTEM........................... B 3/4 7-4 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1, 3/4.8.2 and 3/4.8.3 A.C. SOURCES, D.C. SOURCES and ONSITE POWER DISTRIBUTION SYSTEMS................................. B 3/4 8-1 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES.............. B 3/4 8-3 3/4.9 REFUELING OPERATIONS l 3/4.9.1 REACTOR MODE SWITCH.................................. B 3/4 9-1 3/4.9.2 INSTRUMENTATION...................................... B 3/4 9-1 3/4.9.3 CONTROL ROD P0SITION................................. B 3/4 9-1 l l 3/4.9.4 DECAY TIME........................................... B 3/4 9-1 ( l 3/4.9.5 COMMUNICATIONS....................................... B 3/4 9-1 3/4.9.6 REFUELING PLATF0RM................................... B 3/4 9-2 l l 3/4.9.7 CRANE TRAVEL-SPENT FUEL STORAGE P00L. . . . . . . . . . . . . . . . . B 3/4 9-2 3/4.9.8 and 3/4.9.9 WATER LEVEL - REACTOR VESSEL and WATER LEVEL - SPENT FUEL STORAGE P00L............ B 3/4 9-2 3/4.9.10 CONTROL R00 REM 0 VAL.................................. B 3/4 9-2 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION........ B 3/4 9-2 HOPE CREEK xx

INDEX E 'N BASES 1 SECTION PAGE l l I 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY........................ B 3/4 10-1 3/4.10.2 R0D SEQUENCE CONTROL SYSTEM.......................... B 3/4 10-1 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS....................... B 3/4 10-1 3/4.10.4 RECIRCULATION L00PS.................................. B 3/4 10-1 3/4.10.5 OXYGEN CONCENTRATION................................. B 3/4 10-1 3/4.10.6 TRAINING STARTUPS.................................... B 3/4 10-1 3/4.10.7 SPECIAL INSTRUMENTATION - INITIAL CORE LOADING....... B 3/4 10-1 3/4.11 RADI0 ACTIVE EFFLUENTS 3/4.11.1 LIQUID EFFLUENTS Concentration............................................. B 3/4 11-1 O Dose...................................................... B 3/4 11-1 Liquid Radwaste Treatment System.......................... B 3/4 11-2 Liquid Holdup Tanks....................................... B 3/4 11-2 3/4.11.2 GASEOUS EFFLUENTS Dose Rate................................................. B 3/4 11-2 Dose - Noble Gases.............................,.......... B 3/4 11-3 Dose - Iodine-131, Iodine-133, Tritium, and . Radionuclides in Particulate Form....................... B 3/4 11-3 Gaseous Radwaste Treatment System and Ventilation Exhaust Treatment Systems................... B 3/4 11-4 Explosive Gas Mixture..................................... B 3/4 11-4 Main Condenser............................................ B 3/4 11-5 Venting or Purging........................................ B 3/4 11-5 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT......................... B 3/4 11-5 , 3/4.11.4 TOTAL D0SE................................................ B 3/4 11-5 i HOPE CREEK xxi

INDEX BASES SECTION PAGE 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MONITORING PR0 GRAM........................................ B 3/4 12-1 3/4.12.2 LAND USE CENSUS........................................... B 3/4 12-1 3/4.12.3 INTERLABORATORY COMPARIS0N PR0 GRAM........................ B 3/4 12-2 1 i O O HOPE CREEK xxii

INDEX s

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(~_-) DESIGN FEATURES SECTION PAGE 5.1 SITE Exclusion Area and Map Defining Unrestricted Area and Site Boundary for Radioactive Gaseous and Liquid Effluents.......... 5-1 Figure 5.1.1-1 Exclusion Area and Unrestricted Areas and Site Boundary for Radioactive Gaseous and Liquid Effluents.......................... 5-2 Low Population Zone............................................ 5-1 Figure 5.1.2-1 Low Population Zone....................... 5-3 5.2 CONTAINMENT Configuration.................................................. 5-1 Design Temperature and Pressure................................ 5-1 Secondary Containment.......................................... 5-1 4 ['__,\ Q 5.3 REACTOR CORE Fuel Assemblies................................................ 5-4 Control Rod Assemblies......................................... 5-4 5.4 REACTOR COOLANT SYSTEM Design Pressure and Temperature................................ 5-4 l Volume......................................................... 5-4 5.5 METEOROLOGICAL TOWER L0 CATION.................................. 5-4 5.6 FUEL STORAGE Criticality.................................................... 5-5 Drainage....................................................... 5-5 Capacity....................................................... 5-5 l t 5.7 COMPONENT CYCLIC OR TRANSIENT LIMIT............................ 5-5 s Table 5.7.1-1 Component Cyclic or Transient Limits. . . . . . . . 5-6 HOPE CREEK xxiii

ADMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESPONSIBILITY................................................. 6-1 6.2 ORGANIZATION................................................... 6-1 6.2.1 0FFSITE................................................... 6-1 6.2.2 UNIT STAFF................................................ 6-1 Figure 6.2.1-1 Offsite Organization..................... 6-3 Figure 6.2.2-1 Unit Organization........................ 6-4 Figure 6.2.2-2 Minimum Shift Crew Composition Single Unit Facility..................... 6-5 6.2.3 SHIFT TECHNICAL ADVIS0R................................... 6-6 6.3 UNIT STAFF QUALIFICATIONS...................................... 6-6 6.4 TRAINING....................................................... 6-6 6.5 REVIEW AND AUDIT............................................... 6-6 6.5.1 STATION OPERATIONS REVIEW COMMITTEE (50RC)................ 6-6 FUNCTION ................................................. 6-6 l COMPOSITION .............................................. 6-7 l l ALTERNATES................................................ 6-7 MEETING FREQUENCY ........................................ 6-7 i l QU0 RUM.................................................... 6-7 1 ! RESPONSIBILITIES ......................................... 6-7 l REVIEW PR0 CESS............................................ 6-8 l AUTH0RITY................................................. 6-9 REC 0RDS................................................... 6-9 O HOPE CREEK xxiv i 1

m INDEX I ') Q/ ADMINISTRATIVE CONTROLS SECTION PAGE

         -6.5.2      NUCLEAR SAFETY REVIEW (NSR)...............................                                            6-9 FUNCTION..................................................                                            6-9 COMPOSITION...............................................                                            6-9 f

j CONSULTANTS............................................... 6-10 OFFSITE SAFETY REVIEW (0SR)............................... 6-10

FUNCTI0N.................................................. 6-10 REVIEW.................................................... 6-10 AUDITS.................................................... 6-11 REC 0RDS................................................... 6-12 ONSITE SAFETY REVIEW GROUP (SRG).......................... 6-12 O

f RESP 0NSIBILITIES.......................................... 6-12 AUTH0RITY................................................. 6-13 6.5.3 TECHNICAL REVIEW AND CONTR0L.............................. 6-13 ACTIVITIES................................................ 6-13 PROCEDURE RELATED 00CUMENTS............................... 6-13 i I NON-PROCEDURE RELATED DOCUMENTS........................... 6-14 REC 0RDS................................................... 6-14 6.6 REPORTABLE EVENT ACTI0N........................................ 6-14 6.7 SAFETY LIMIT VIOLATION......................................... 6-14 6.8 PROCEDURES AND PR0 GRAMS........................................ 6-15 6.9 REPORTING REQUIREMENTS......................................... 6-17 6.9.1 ROUTINE REP 0RTS........................................... 6-17 STARTUP REP 0RT............................................ 6-17 i V 1 i HOPE CREEK xxv i _ , . - _ _ . _ _ _ _ _ _ . . _ _ . . . _ . _ . -_m_.__ . _ __.-, . , - , , - _ _ . . _ , _ . , _ _ _ - _ . . .

INDEX ADMINISTRATIVE CONTROLS SECTION PAGE ANNUAL REP 0RTS............................................ 6-17 l ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT........ 6-18 SEMIANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT.... 6-19 MO NTH LY OP E RATI NG R E P0RTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-20

 = 6.9.2             SPECIAL REP 0RTS...........................................                                        6-20 6.10 RECORD RETENTION..............................................                                                  6-21 l

6.11 RADIATION PROTECTION PR0 GRAM.................................. 6-22 6.12 HIGH RADIATION AREA........................................... 6-22 6.13 PROCESS CONTROL PROGRAM (PCP)................................. 6-23 6.14 0FFSITE DOSE CALCULATION MANUAL (0DCM)........................ 6-24 i 6.15 MAJOR CHANGES TO RADI0 ACTIVE LIQUID, GASEOUS, AND SOLID WASTE TREATMENT SYSTEMS................................. 6-24 l 1 l l \ HOPE CREEK xxvi

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                                                                                'f 6
                                                                                -I SECTION 1.0-                                    -l lJ;                               DEFINITIONS i

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1.0 DEFINITIONS b The follow'ng terms are defined so that uniform interpretation of these specifications may be achieved. The defined terms appear in capitalized type and shall be applicable throughout these Technical Specifications. ACTION 1.1 ACTION shall be that part of a Specification which prescribes remedial measures required under designated conditions. AVERAGE PLANAR EXPOSURE 1.2 The AVERAGE PLANAR EXPOSURE shall be applicable to a specific planar height and is equal to the sum of the exposure of all the fuel rods in the specified bundle at the specified height divided by the number of fuel rods in the fuel bundle. AVERAGE PLANAR LINEAR HEAT GENERATION RATE 1.3 The AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) shall be applicable to a specific planar height and is equal to the sum of the LINEAR HEAT GENERATION RATES for all the fuel rods in the specified bundle at the specified height divided by the number of fuel rods in the fuel bundle. CHANNEL CALIBRATION 1.4 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel s output such that it responds with the necessary range and accuracy to known values of the parameter which the channel monitors. The CHANNEL CALIBRATION shall encompass the entire channel including the sensor and alarm and/or trip functions, and shall include the CHANNEL FUNCTIONAL TEST. The CHANNEL CALIBRATION may be performed by any series of sequential, overlapping or total channel steps such that the entire channel is calibrated. CHANNEL CHECK

1. 5 A CHANNEL CHECK shall be the qualitative assessment of channel behavior during operation by observation. This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameter.

l l CHANNEL FUNCTIONAL TEST l l 1. 6 A CHANNEL FUNCTIONAL TEST shall be:

a. Snalog channels - the injection of a simulated signal into the channel as close to the sensor as practicable to verify OPERABILITY including alarm and/or trip functions and channel failure trips.

b. Bistable channels - tho injection of a simulated signal into the sensor to verify OPERABILITY including alarm and/or trip functions.

The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total channel steps such that the entire channel is tested. HOPE CREEK 1-1

DEFINITIONS CORE ALTERATION 1.7 CORE ALTERATION shall be the addition, removal, relocation or movement of fuel, sources, incore instruments or reactivity controls within the reactor pressure vessel with the vessel head removed and fuel in the vessel. Normal movement of the SRMs, IRMs, TIPS, or special movable detectors is not considered a CORE ALTERATION. Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe conservative position. CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY 1.8 The CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CMFLPD) shall be highest value of the FLPD which exists in the core. CRITICAL POWER RATIO 1.9 The CRITICAL POWER RATIO (CPR) shall be the ratio of that power in the assembly which is calculated by application of the GEXL correlation to cause some point in the assembly to experience boiling transition, divided by the actual assembly operating power. DOSE EQUIVALENT I-131 1.10 DOSE EQUIVALENT I-131 shall be that concentration of I-131, microcuries per gram, which alone would produce the same thyroid dose as the quantity and isotopic mixture of I-131, I-132, I-133, I-134, and I-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, " Calculation of Distance Factors for Power and Test Reactor Sites." E-AVERAGE DISINTEGRATION ENERGY 1.11 E shall be the average, weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling, of the sum of the average beta and gamma energies per disintegration, in MeV, ! for isotopes, with half lives greater than 15 minutes, making up at least 95% of the total non-iodine activity in the coolant. l EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME l 1.12 The EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ECCS actuation set-point at the channel sensor until the ECCS equipment is capable of performing its safety function, i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc. Times shall include diesel generator starting and sequence loading delays where applicable. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured. HOPE CREEK 1-2

[' DEFINITIONS END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME 1.13 The END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME shall be that time interval to complete suppression of the electric arc between the fully open contacts of the recirculation pump circuit breaker from initial movement of the associated:

a. Turbine stop valves, and

b. Turbine control valves.

The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured. FRACTION OF LIMITING POWER DENSITY 1.14 The FRACTION OF LIMITING POWER DENSITY (FLPD) shall be the LHGR existing at a given location divided by the specified LHGR limit for that bundle type. FRACTION OF RATED THERMAL POWER 1.15 The FRACTION OF RATED THERMAL POWER (FRTP) shall be the measured THERMAL POWER divided by the RATED THERMAL POWER. FREQUENCY NOTATION ( i 1.16 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1. IDENTIFIED LEAKAGE 1.17 IDENTIFIED LEAKAGE shall be:

a. Leakage into collection systems, such as pump seal or valve packing leaks, that is captured and conducted to a sump or collecting tank, or

b. Leakage into the containment atmosphere from sources that are both spe-cifically located and known either not to interfere with the operation of the leakage detection systems or not to be PRESSURE B0UNDARY LEAKAGE.

ISOLATION SYSTEM RESPONSE TIME 1.18 The ISOLATION SYSTEM RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its isolation actuation setpoint at the channel sensor until the isolation valves travel to their required positions. Times shall include diesel generator starting and sequence loading delays where applicable. The response time may be measured by'any series of sequential, overlapping or total steps such that the entire response time is measured. LIMITING CONTROL ROD PATTERN 1.19 A LIMITING CONTROL R0D PATTERN shall be a pattern which results in the core being on a thermal hydraulic limit, i.e., operating on a limiting value for APLHGR,.LHGR, or MCPR. lO HOPE CREEK 1-3

DEFINITIONS LINEAR HEAT GENERATION RATE 1.20 LINEAR HEAT GENERATION RATE (LHGR) shall be the heat generation per unit length of fuel rod. It it, the integral of the heat flux over the heat transfer area associated with the unit length. LOGIC SYSTEM FUNCTIONAL TEST 1.21 A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all logic components, i.e. , all relays and contacts, all trip units, solid state locic elernents, etc, of a logic circuit, fron sensor through and including tne actuated device, to verify OPERABILITY. The LOGIC SYSTEM FUNCTIONAL TEST may be performed by any series of sequentiel, overlapping or total system steps such that the entire logic system is tested. MAXIMUM FRACTION OF LIMITING POWER DENSITY 1.22 The MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD) shall be highest value of the FLPD which exists in the core. MEMBER (S) 0F THE PUBLIC 1.23 MEMBER (S) 0F THE PUBLIC shall include all persons who are not occcpationally associated with the plant. This category does not include employeas of the utility, it contrattors or vendors. Also excluded from this lategory ' are persons who enter the site to service equiptint cr to make deliveries. This category does include persons who use portions of the site for recre-ational, occupational or other purposes not associated with the plant. MINIMUM CRITICAL POWER RATIO 1.24 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be the smallest CPR which - exists in the core. 0FF-GAS RADWASTE TREATMENT SYSTEM 1.25 An 0FF-GAS RADWASTE TREATMENT SYSTEM is any system designed 6nd installed to reduce radioactive gaseous ef.fluents by collecting reactor coolant sys-tem offgases fror. the main condenser ev8cuation system and providing for delay or holdup for the purpose of reducing the total radioactivity prior ' to release to the environment. 0FFSITE DOSE CALCULATION MANUAL 1.26 The OFFSITE DOSE CALCULATION MANUAL (ODCM) shall contair the current method-ology and parameters used in the calculation of offsite dosas due to radio-active gaseous and liquid ef fluents, in the calcu% tion of gaseous and liquid effluent monitoring alarm / trip setpoints, and in the corduct of the radiological environmental monitoring program. O~ HOPE CREEK 1-4

l l l n $ DEFINITIONS OPERABLE - OPERABILITY 1.27 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function (s) and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function (s) are also capable of performing their related support function (s). OPERATIONAL CONDITION - CONDITION 1.28 An OPERATIONAL CONDITION, i.e., CONDITION, shall be any one inclusive combination of mode switch position and average reactor coolant temperature as specified in Table 1.2. PHYSICS TESTS 1.29 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission. PRESSURE BOUNDARY LEAKAGE 1.30 PRESSURE BOUNDARY LEAKAGE shall be leakage through a non-isolable fault in a reactor coolant system component body, pipe wall or vessel wall.

PRIMARY CONTAINMENT INTEGRITY 1.31 PRIMARY CONTAINMENT INTEGRITY shall exist when: a. All primary containment penetrations required to be closed during accident conditions are either:; 1. Capable of being closed by an OPERABLE primary containment automatic isolation system, or; 2. Closed by at least one manual valve, blind flange, or deactivated automatic valve secured in its closed position, except as provided in Table 3.6.3-1 of Specification 3.6.3.; b. All primary containment equipment hatches are closed and sealed.; c. Each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.; d. The primary containment leakage rates are within the limits of Specification 3.6.1.2.

r e. The suppression enamber is in ccmplianc.e with the requirements of Specification 3.6.2.1.

f. The sealing mechanism associated with each primary containment penetration; e.g. , welds, bellows or 0-rings. is OPERABLC h0PE CREEK 1-5 6

DEFINITIONS PROCESS CONTROL PROGRAM 1.32 The PROCESS CONTROL PROGRAM (PCP) shall contain the provisions to assure that the SOLIDIFICATION or dewatering and packaging of radioactive wastes results in a waste package with properties that meet the minimum and stability requirements of 10 CFR Part 61 and other requirements for trans-portation to the disposal site and receipt at the disposal site. With SOLIDIFICATION, the PCP shall identify the process parameters influencing SOLIDIFICATION such as pH, oil content, 2H O content, solids content ratio of solidification agent to waste and/or necessary additives for each type of anticipated waste, and the acceptable boundary conditions for the process parameters shall be identified for each waste type, based on laboratory scale and full scale testing or experience. With dewatering, the PCP shall include an identification of conditions that must be satisfied, based on full scale testing, to assure that dewatering of bead resins, powdered resins, and filter sludges will result in volumes of free wate", at the time of disposal, within the limits of 10 CFR Part 61 and of the low-level radioactive waste disposal site. PURGE - PURGING 1.33 PURGE or PURGING shall be the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentra-tion or other operating condition, in such manner that replacement air or gas is required to purify the confinement. RATED THERMAL POWER 1.34 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 3293 MWT. l REACTOR PROTECTION SYSTEM RESPONSE TIME 1.35 REACTOR PROTECTION SYSTEM RESPONSE TIME shall be the time interval from when the monitored parameter exceeds its trip setpoint at the channel sensor until de-energization of the scram pilot valve solenoids. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured. REPORTABLE EVENT l 1.36 A REPORTABLE EVENT shall be any of those conditions specified in Secti'on 50.73 to 10 CFR Part 50. ! R0D DENSITY 1.37 R0D DENSITY shall be the number of control rod notches inserted as a fraction of the total number of control rod notches. All rods fully l inserted is equivalent to 100% ROD DENSITY. HOPE CREEK 1-6 L

DEFINITIONS v SECONDARY CONTAINMENT INTEGRITY 1.38 SECONDARY CONTAINMENT INTEGRITY shall exist when:

a. All secondary containment penetrations required to be closed during accident conditions are either:

1. Capable of being closed by an OPERABLE secondary containment automatic isolation system, or

2. Closed by at least one manual valve, blind flange, or deactivated automatic valve or damper, as applicable secured in its closed position, except as provided in Table 3.6.5.2-1 of Specification 3.6.5.2.

b. All secondary containment hatches and blowout panels are closed and sealed.

c. The filtration, recirculation and ventilation system is in compliance with the requirements of Specification 3.6.5.3.

d. For double door arrangements, at least one door in each access to the secondary containment is closed.

e. For single door arrangements, the door in each access to the secondary containment is closed, except for normal entry and exit.

f. The sealing mechanism associated with each secondary containment penetration, e.g., welds, bellows or 0-rings, is OPERABLE.

l g. The pressure within the secondary containment is less than or equal l to the value required by Specification 4.6.5.1.a. SHUTDOWN MARGIN 1.39 SHUTDOWN MARGIN shall be the amount of reactivity by which the reactor is subcritical or would be subcritical assuming all control rods are fully inserted except for the single control rod of highest reactivity worth which is assumed to be fully withdrawn and the reactor is in the shutdown l condition; cold, i.e. 68 F; and xenon free. SITE B0UNDARY

1.40 The SITE BOUNDARY shall be that line beyond which the land is neither owned, nor leased, nor otherwise controlled, by the licensee. I HOPE CREEK 1-7 1

DEFINITIONS SOLIDIFICATION 1.41 SOLIDIFICATION shall be the immobilization of wet radioactive wastes such as evaporator bottomc, spent resins, sludges, and reverse osmosis concen-trates as a result of a process of thoroughly mixing the water type with a solidification agent (s) to form a free standing monolith with chemical and physical characteristics specified in the PROCESS CONTROL PROGRAM (PCP). SOURCE CHECK 1.42 A SOURCE CHECK shall be the qualitative assessment of channel response when the channel sensor is exposed to a source of increased radioactivity. STAGGERED TEST BASIS 1.43 A STAGGERED TEST BASIS shall consist of:

a. A test schedule for n systems, subsystems, trains or other designated components obtained by dividing the specified test interval into n equal subintervals.

b. The testing of one system, subsystem, train or other designated component at the beginning of each subinterval.

THERMAL POWER 1.44 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant. TURBINE BYPASS SYSTEM RESPONSE TIME 1.45 The TURBINE BYPASS SYSTEM RESPONSE TIME consists of two separate time inter-vals: a) time from initial movement of the main turbine stop valve or con-trol valve until 80% of the turbine bypass capacity is established, and b) the time from initial movement of the main turbine stop valve or control valve until initial movement of the turbine bypass valve. Either response time may be measured by any series of sequential, overlapping, or total steps such that the entire response time is measured. UNIDENTIFIED LEAKAGE 1.46 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE. UNRESTRICTED AREA 1.47 An UNRESTRICTED AREA shall be any area at or beyond the SITE B0UNDARY access to which is not controlled by the licensee for purposes of protec-tion of individua)s from exposure to radiation and radioactive materials, or any area within the SITE B0UNDARY used for residential quarters or for industrial, commercial, institutional, and/or recreational purposes. HOPE CREEK 1-8

k DEFINITIONS N VENTILATION EXHAUST TREATMENT SYSTEM 1.48 A VENTILATION EXHAUST TREATMENT SYSTEM shall be any system designed and installed to reduce gaseous radioiodine or radioactive material in particu- l late form in effluents by passing ventilation or vent exhaust gases through l charcoal adsorbers and/or HEPA filters for the purpose of removing iodines , or particulates from the gaseous exhaust stream prior to the release to l the environment. Such a system is not considered to have any effect on noble gas effluents. Engineered Safety Feature (ESF) atmospheric cleanup systems are not considered to be VENTILATION EXHAUST TREATMENT SYSTEM components. VENTING 1.49 VENTING shall be the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration or other operating condition, in such a manner that replacement air or gas ; is not provided or required during VENTING. Vent, used in system names, does not imply a VENTING process. l HOPE CREEK 1-9

TABLE 1.1 l SURVEILLANCE FREQUENCY NOTATION l l NOTATION FREQUENCY l 5 At least once per 12 hours. i 1 l D At least once per 24 hours.

W At least once per 7 days. M At least once per 31 days. Q At least once per 92 days. SA At least once per 184 days. A At least once per 366 days. R At least once per 18 months (550 days). S/U Prior to each reactor startup. P Prior to each radioactive release. j N.A. Not applicable. l O HOPE CREEK 1-10

[J TABLE 1.2 OPERATIONAL CONDITIONS MODE SWITCH AVERAGE REACTOR CONDITION POSITION COOLANT TEMPERATURE

1. POWER OPERATION Run Any temperature

2. STARTUP Startup/ Hot Standby Any temperature

3. HOT SHUTDOWN Shutdown #'*** > 200*F

4. COLD SHUTDOWN Shutdown #'##'*** $ 200 F

5. REFUELING

Shutdown or Refuel **'# $ 140*F 4

O

             #The reactor mode switch may be placed in the Run or Startup/ Hot Standby position to test the switch interlock functions and related instrumentation provided that the control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff.
           ##The reactor mode switch may be placed in the Refuel position while a single

! control rod drive is being removed from the reactor pressure vessel per Specification 3.9.10.1. l

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

           **See Special Test Exceptions 3.10.1 and 3.10.3.
        ***The reactor mode switch may be placed in the Refuel position while a single control rod is being recoupled or withdrawn provided that the one-rod-out interlock is OPERABLE.

v l HOPE CREEK 1-11

l

                                                                                                                                                                                                                           }
                                                                                                                                                                                                                           )

l J i NOTE ; The BASES contained in succeeding pages summarize the reasons for the Specifications in Section 2.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications. 4 l

2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.1 SAFETY LIMITS THERMAL POWER, low Pre;sure or Low Flow 2.1.1 THERMAL POWER shall not exceed 25% of RATED THERMAL POWER with the reactor vessel steam dome pressure less than 785 psig or core flow less than 10% of rated flow. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With THERMAL POWER exceeding 25% of RATED THERMAL POWER and the reacter vessel steam dome pressure less than 785 psig or core flow less than 10% of rated flow, be in at least HOT SHUTDOWN within 2 hours and comply with the requirements of Specification 6.7.1. THERMAL POWER, High Pressure and High Flow 2.1.2 The MINIMUM CRITICAL POWER RATIO (MCPR) shall not be less than 1.06 with the reactor vessel steam dome pressure greater than 785 psig and core flow greater than 10% of rated flow. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With MCPR less than 1.06 and the reactor vessel steam dome pressure greater than 785 psig and core flow greater than 10% of rated flow, be in at least HOT SHUTDOWN within 2 hours and comply with the requirements of Specification 6.7.1. REACTOR COOLANT SYSTEM PRESSURE 2.1.3 The reactor coolant system pressure, as measured in the reactor vessel steam dome, shall not exceed 1325 psig. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4. ACTION: With the reactor coolant system pressure, as measured in the reactor vessel steam dome, above 1325 psig, be in at least HOT SHUTDOWN with reactor coolant system pressure less than or equal to 1325 psig within 2 hours and comply with the requirements of Specification 6.7.1. HOPE CREEK 2-1

SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SAFETY LIMITS (Continued) REACTOR VESSEL WATER LEVEL 2.1.4 The reactor vessel water level shall be above the top of the active irradiated fuel. APPLICABILITY: OP.FRATIONAL CONDITIONS 3, 4 and 5 ACTION: With the reactor vessel water level at or below the top of the active irradiated fuel, manually initiate the ECCS to restore the water level, after depressurizing the reactor vessel, if required. Comply with the requirements of Specification 6.7.1. O O HOPE CREEK 2-2 3

O SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The reactor protection system instrumentation setpoints shall be set consistent with the Trip-Setpoint values shown in Table 2.2.1-1. APPLICABILITY: As shown in' Table 3.3.1-1. ACTION: . With a reactor protection system instrumentation setpoint less conservative ! than the value shown in the Allowable Values column of Table 2.2.1-1, declare l the channel inoperable and apply the applic'able ACTION statement requirement of Specification 3.3.1 until the channel is restored to OPERABLE status with its setpoint adjusted consistent with the Trip Setpoint value. x O m i O HOPE CREEK 2-3

TABLE 2.2.1-1 2 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS

                      "'                                                                                                                                                                                  ALLOWABLE Q                                                        FUNCTIONAL UNIT                                                                       TRIP SETPOINT                           VALUES A
                      ^                                                                   1.                 Intermediate Range Monitor, Neutron Flux-High           5 120/125 divisions            5 122/125 divisions of full scale                  of full scale

2. Average Power Range Monitor:

a. Neutron Flux-Upscale, Setdown 1 15% of RATED THERMAL POWER $ 20% of RATED THERMAL POWER

b. Flow Biased Simulated Thermal Power-Upscale

1) Flow Biased $ 0.66 W+51%, with 5 0.66 W+54%, with a maximum of a maximum of

2) High Flow Clamped 1 113.5% of RATED $ 115.5% of RATED THERMAL POWER THERMAL POWER

c. Fixed Neutron Flux-Upscale $ 118% of RATED THERMAL POWER $ 120% of RATED THERMAL POWER m

S

d. Inoperative NA NA

e. Downscale -> 4% of RATED -> 3% of RATED THERMAL POWER THERMAL POWER

3. Reactor Vessel Steam Dome Pressure - High 5 1037 psig $ 1057 psig

4. Reactor Vessel Water Level - Low, Level 3 > 12.5 inches above instrument > 11.0 inches above

                                                                                                                                                                     - zero*                           instrument zero

5. Main Steam Line Isolation Valve - Closure $ 8% closed 5 12% closed

6. Main Steam Line Radiation - High, High 5 3.0 x full power background 5 3.6 x full power background

                                                                                   *See Bases Figure B 3/4 3-1.

O O O

g TABLE 2.2.1-1 A n REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS i g (continued) E ALLOWABLE FUNCTIONAL UNIT TRIP SETPOINT VALUES

7. Drywell Pressure - High 5 1.68 psig i 1.88 psig i 8. Scram Discharge Volume Water Level - High l

a. Float Switch Elevation 110' 10.5" Elevation 111' O.5"

b. Level Transmitter / Trip Unit Elevation 110' 10.5"* Elevation 111' 4.5"--

Turbine Stop Valve - Closure

9. 1 5% closed 5 7% closed

10. Turbine Control Valve Fast Closure, ro Trip Oil Pressure - Low 1 530 psig 2 465 psig

11. Reactor Mode Switch Shutdown Position NA NA

12. Manual Scram NA NA

     *80.5" above instrument zero EL 104' 2" for Level Transmitter / Trip Unit A&B (South Header) 83.25" above instrument zero EL 103' 11.25" for Level Transmitter / Trip Unit C&D (North Header) 1

_ a BASES FOR SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 1 l

4 __ _ _ O SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS O l l l 9 i

L

           ] 2.1 SAFETY LIMITS BASES

2.0 INTRODUCTION

The fuel cladding, reactor pressure vessel and primary system piping i are the principal barriers to the release of radioactive materials to the environs. Safety Limits are established to protect the integrity of these barriers during normal plant operations and anticipated transients. The fuel cladding integrity Safety Limit is set such that no fuel damage is calculated j to occur if the limit is not violated. Because fuel damage is not directly 1 observable, a step-back approach is used to establish a Safety Limit such that

 .           the MCPR is not less than 1.06. MCPR greater than 1.06 represents a con-servative margin relative to the conditions required to maintain fuel cladding integrity.          The fuel cladding is one of the physical barriers which separate the radioactive materials from the environs. The integrity of this cladding j            barrier is related to its relative freedom from perforations or cracking.

Although some corrosion or use related cracking ciay occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses which occur from reactor operation signifi-l cantly above design conditions and the Limiting Safety System Settings. While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross i rather than incremental cladding deterioration. Therefore, the fuel cladding i Safety Limit is defined with a margin to the conditions which would produce ! onset of transition boiling, MCPR of 1.0. These conditions represent a signi-ficant departure from the condition intended try design for planned operation. 2.1.1 THERMAL POWER, Low Pressure or Low F1,ow _ The use of the GEXL correlation ic rect valid for all critical power calculations at pressures below 785 psig or r. ore flows less than 10% of rated flow. Therefore, the fuel cladding integrity Safety Limit is established by other means. This is done by establishing a limiting condition on core THERMAL POWER with the following basis. Since the pressure drop in the bypass region is essentially all elevation head, the core pressure drop at low power and Analyses show that with a bundle flowswillalwagsbegreaterthan4.5 psi. flow of 28 x 10 lbs/hr, bundle pressure drop is nearly independent of bundle power and has a value of 3.5 psi. Thus, the bundle flow with a 4.5 psi driving head will be greater than 28 x 103 lbs/hr. Full scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly criti-cal power at this flow is approximately 3.35 MWt. With the design peaking factors, this corresponds to a THERMAL POWER of more than 50% of RATED THERMAL POWER. Thus, a THERMAL POWER limit of 25% of RATED THERMAL POWER for reactor pressure below 785 psig is conservative. HOPE CREEK B 2-1

SAFETY LIMITS BASES 2.1.2 THERMAL POWER, High Pressure and High Flow The fuel cladding integrity Safety Limit is set such that no fuel damage is calculated to occur if the limit is not violated. Since the parameters which result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions resulting in a departure from nucleate boiling have been used to mark the beginning of the region where fuel damage could occur. Although it is recognized that a departure from nucleate boiling would not necessarily result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power. Therefore, the fuel cladding integrity Safety Limit is defined as the CPR in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition considering the power distribution within the core and all uncertain-ties. The Safety Limit MCPR is determined using the General Electric Thermal a Analysis Basis, GETAB , which is a statistical model that combines all of the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the General Electric Critical Quality (X) Boiling Length (L), (GEXL), correlation. The GEXL correlation is valid over the range of conditions used in the tests of the data used to develop the correlation. The required input to the statistical model are the uncertainties listed l in Bases Table B2.1.2-1 and the nominal values of the core parameters listed l in Bases Table 82.1.2-2. The bases for the uncertainties in the core parameters are given in NED0-20340 D and the basis for the uncertainty in the GEXL correlation is given a in NED0-10958-A . The power distribution is based on a typical 764 assembly core in which the rod pattern was arbitrarily chosen to produce a skewed power distribution having the greatest number of assemblies at the highest power levels. T.he worst distribution during any fuel cycle would not be as severe as the distribution used in the analysis.

a. " General Electric BWR Thermal Analysis Bases (GETAB) Data, Correlation and Design Application," NED0-10958-A.

b. General Electric " Process Computer Performance Evaluation Accuracy" NED0-20340 and Amendment 1, NEDO-20340-1 dated June 1974 and December 1974, respectively.

HOPE CREEK B 2-2

Bases Table B2.1.2-1 UNCERTAINTIES USED IN THE DETERMINATION OF THE FUEL CLADDING SAFETY LIMIT

Standard Deviation Quantity (% of Point)

Feedwater Flow 1.76 Feedwater Temperature 0.76 Reactor Pressure 0.5 Core Inlet Temperature 0.2 Core Total Flow 2.5 i Channel Flow Area 3.0 Friction Eactor Multiplier 10.0 Channel Friction Factor Multiplier 5.0 l ' TIP Readings 6.3 R Factor 1.5 i Critical Power 3.6

    " The uncertainty analysis used to establish the core wide Safety Limit MCPR is based on the assumption of quadrant power symmetry for the reactor core.

O B 2-3 ) HOPE CREEK

Bases Table 82.1.2-2 NOMINAL VALUES OF PARAMETERS USED IN THE STATISTICAL ANALYSIS OF FUEL CLADDING INTEGRITY SAFETY LIMIT THERMAL POWER 3323 MW Core Flow 108.5 Mlb/hr Dome Pressure 1010.4 psig Channel Flow Area 0.1089 ft 2 R-Factor High enrichment - 1.043 Medium enrichment - 1.039 Low enrichment - 1.030 0 0 HOPE CREEK B 2-4

l l d SAFETY LIMITS BASES l l 2.1.3 REACTOR COOLANT SYSTEM PRESSURE l The Safety Limit for the reactor coolant system pressure has been selected

such that it is at a pressure below which it can be shown that the integrity of the system is not endangered. The reactor pressure vessel is designed to Section III of the ASME Boiler and Pressure Vessel Code 1968 Edition, including Addenda through Winter 1969, which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig. The Safety Limit of 1325 psig, J

as measured by the reactor vessel steam dome pressure indicator, is equivalent to 1375 psig at the lowest elevation of the reactor coolant system. The reactor coolant system 4- designed to the USAS Nuclear Power Piping Code, Section B31.7 1969 Edition, it. suding Addenda through July 1, 1970 for the reactor recirculation piping, which permits a maximum pressure transient of 110%, 1375 psig, of design pressure, 1250 psig for suction piping and 1500 psig for discharge piping. l The pressure Safety Limit is selected to be the lowest transient overpressure l allowed by the applicable codes. l 2.1.4 REACTOR VESSEL WATER LEVEL l With fuel in the reactor vessel during periods when the reactor is shutdown, consides ation must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the r active irradiated fuel during this period, the ability to remove decay heat is i reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level became less than two-thirds of the core height. The Safety Limit has been established at the top of the active irradiated fuel to provide a point which can be monitored and also provide adequate margin for effective action. HOPE CREEK B 2-5

2.2 LIMITING SAFETY SYSTEM SETTINGS BASES 2.2.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS The Reactor Protection System instrumentation setpoints specified in i Table 2.2.1-1 are the values at which the reactor trips are set for each para-meter. The Trip Setpoints have been selected to ensure that the reactor core and reactor coolant system are prevented from exceeding their Safety Limits during normal operation and design basis anticipated operational occurrences and to assist in mitigating the consequences of accidents. Operation with a 1 trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each l Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

1. Intermediate Range Monitor, Neutron Flux - High The IRM system consists of 8 chambers, 4 in each of the reactor trip systems. The IRM is a 5 decade 10 range instrument. The trip setpoint of 120 divisions of scale is active in each of the 10 ranges. Thus as the IRM is ranged up to accommodate the increase in power level, the trip setpoint is l also ranged up. The IRM instruments provide for overlap with both the APRM and SRM systems.

The most significant source of reactivity changes during the power increase is due to control rod withdrawal. In order to ensure that the IRM provides the required protection, a range of rod withdrawal accidents have been analyzed. The results of these analyses are in Section 15.4 of the FSAR. The most severe case involves an initial condition in which THERMAL POWER is at approximately 1% of RATED THERMA 8. POWER. Additional conserva-tism was taken in this analysis by assuming the IRM channel closest to the l control rod being withdrawn is bypassed. The results of this analysis show that the reactor is shutdown and peak power is limited to 21% of RATED THERMAL POWER with the peak fuel enthalpy well below the fuel failure thres-hold of 170 cal /gm. Based on this analysis, the IRM provides protection against local control rod errors and continuous withdrawal of control rods in sequence and provides backup protection for the APRM.

2. Average Power Range Monitor l For operation at low pressure and low flow during STARTUP, the APRM scram setting of 15% of RATED THERMAL POWER provides adequate thermal margin between the setpoint and the Safety Limits. The margin accommodates the anticipated inaneuvers associated with power plant startup. Effects of increasing pressure at zero or low void content are minor and cold water from sources available during startup is not much colder than that already in the system. Tempera-ture coefficients are small and control rod patterns are constrained by the Of all the possible sources of reactivity input, uniform con-

! RSCS and RWM. trol od withdrawal is the most probable cause of significant power increase. HOPE CREEK B 2-6 L

LIMITING SAFETY SYSTEM SETTINGS v BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) Average Power Range Monitor (Continued) Because the flux distribution associated with uniform rod withdrawals does not involve high local peaks and because several rods must be moved to change power by a significant amount, the rate of power rise is very slow. Generally the heat flux is in near equilibrium with the fission rate. In an assumed uniform rod withdrawal approach to the trip level, the rate of power rise is not more than 5% of RATED THERMAL POWER per minute and the APRM system would be more than adequate to assure shutdown before the power could exceed the Safety Limit. The 15% neutron flux trip remains active until the mode switch is placed in the Run position. The APRM trip system is calibrated using heat balance data taken during steady state conditions. Fission chambers provide the basic input to the system and therefore the monitors respond directly and quickly to changes due to transient operation for the case of the Fixed Neutron Flux-Upscale set-point; i.e, for a power increase, the THERMAL POWER of the fuel will be less than that indicated by the neutron flux due to the time constants of the heat i O transfer associated with the fuel. For'the Flow Biased Simulated Thermal Power-Upscale setpoint, a time constant of 6 1 0.6 seconds is introduced into the flow biased APRM in order to simulate the fuel thermal transient characteristics. A more conservative maximum value is used for the flow biased setpoint as shown in Table 2.2.1-1. The APRM setpoints were selected to provide adequate margin for the Safety Limits and yet allow operating margin that reduces the possibility of unneces-sary shutdown. The flow referenced trip setpoint must be adjusted by the specified formula in Specification 3.2.2 in order to maintain these margins when CHFLPD is greater than or equal to FRTP.

3. Reactor Vessel Steam Dome Pressure-High High pressure in the nuclear system could cause a rupture to the nuclear system process barrier resulting in the release of fission products. A pressure increase while operating will also tend to increase the power of the reactor by compressing voids thus adding reactivity. The trip will quickly reduce the neutron fl.ux, counteracting the pressure increase. The trip setting is slightly higher than the operating pressure to permit normal operation without spurious trips. The setting provides for a wide margin to the maximum allowable design pressure and takes into account the location of the pressure measurement compared to the highest pressure that occurs in the system during a transient. This trip setpoint is effective at low power / flow conditions when the turbine control valve fast closure and turbine stop valve closure trip are bypassed. For a l load rejection or turbine trip under these conditions, the transient analysis l

d indicated an adequate margin to the thermal hydraulic limit. HOPE CREEK B 2-7

LIMITING SAFETY SYSTEM SETTINGS BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

4. Reactor Vessel Water Level-Low The reactor vessel water level trip setpoint has been used in transient analyses dealing with coolant inventory decrease. The scram setting was chosen far enough below the normal operating level to avoid spurious trips but high enough above the fuel to assure that there is adequate protection for the fuel and pressure limits.

5. Main Steam Line Isolation Valve-Closure The main steam line isolation valve closure trip was provided to limit the amount of fission product release for certain postulated events. The MSIV's are closed automatically from measured parameters such as high steam flow, high steam line radiation, low reactor water level, high steam tunnel temperature, and low steam line pressure. The MSIV's closure scram anticipates the pressure and flux transients which could follow MSIV closure and thereby protects reactor vessel pressure and fuel thermal / hydraulic Safety Limits.

6. Main Steam Line Radiation-High The main steam line radiation detectors are provided to detect a gross failure of the fuel cladding. When the high radiation is detected, a trip is initiated to reduce the continued failure of fuel cladding. At the same time the main steam line isolation valves are closed to limit the release of fission products. The trip setting is high enough above background radiation levels to prevent spurious trips yet low enough to promptly detect gross failures in the fuel cladding.

7. Drywell Pressure-High High pressure in the drywell could indicate a break in the primary pressure boundary systems or a loss of drywell cooling. The reactor is tripped in order to minimize the possibility of fuel damage and reduce the amount of energy being added to the coolant and the primary containment. The trip setting was selected as low as possible without causing spurious trips.

8. Scram _ Discharge Volume Water Level-High The scram discharge volume receives the water displaced b/ the motion of the control rod drive pistons during a reactor scram. Should this volume fill up to a point where there is insufficient volume to accept the. displaced water at pressures below 65 psig, control rod insertion would be hiMered. The reac-tor is therefore trippsd when the water level has reached a point high enough to indicate that it is indeed filling up, but the volume is still great enough to accommodate the water from the movement of the rods at pressures below 65 psig when they are tripped. The trip setpoint for each scram discharge j volume is equivalent to a contained volume of approximately 35 gallons of water. '

HOPE CREEK B 2-8 1

O l LIMITING SAFETY SYSTEM SETTING ( BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

9. Turbine Stop Valve-Closure The turbine stop valve closure trip anticipates the pressure, neutron flux, and heat flux increases that would result from closure of the stop valves. With a trip setting of 5% of valve closure from full open, the resultant increase in heat flux is such that adequate thermal margins are maintained during the worst case transient.

10. Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Tha turbine control valv; fast closure trip anticipates the pressure, neutron flux, and heat flux 'i.% rease that could result from fast closure of the turbine control valves due to load rejection with or without coincident failure of the turbine bypass valves. The Reactor Protection System initiates a trip when fast closure of the control valves is initiated by the fast acting solenoid valves and in less than 30 milliseconds after the start of control valve fast closure. This is achieved by the action of the fast acting solenoid valves in rapidly reducing hydraulic trip oil pressure at the main turbine control valve actuator disc dump valves. This loss of pressure is sensed by O pressure switches whose contacts form the one-out-of-two-twice logic input to the Reactor Protection System. This trip setting, a slower closure time, and Q a different valve characteristic from that of the turbine stop valve, combine to produce transients which are very similar to that for the stop valve.

Relevant transient analyses are discussed in Section 15.2.2 of the Final Safety Analysis Report.

11. Reactor Mode Switch Shutdown Position The reactor mode switch Shutdown position provides additional manual reactor trip capability.

12. Manual Scram The Manual Scram pushbutton switches provide a diverse means for initiat-ing a reactor shutdown (scram) to the automatic protective instrumentation j channels and provides manual reactor trip capability.

l l O HOPE CREEK B 2-9 i

O 4 SECTIONS 3.0 and 4.0

;                                                                                LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS i

l l l l

                     - .2 ._  ._ah* h.--    a      _ - ..a * - sn 4 a. . _ .m. a ___a,_m_ -_m.m...- . a m ,, - -_ , _

T O I i e I 1 1 I p I l 0

    -----n--,------.       _a-,          w,   .. ,

1 A 3/4.0 APPLICABILITY ) LIMITING CONDITION FOR OPERATION 3.0.1 Compliance with the Limiting Conditions for Operation contained in the succeeding Specifications is required during the OPERATIONAL (ONDITIONS or other conditions specified therein; except that upon failure to meet the Limiting Conditions for Operation, the associated ACTION requirements shall be met. 3.0.2 Noncompliar.ce with a Specification shall exist when the requirements of the Limiting Condition for Operation and associated ACTION requirements are not met within the specified time intervals. If the Limiting Condition for Operation is restored prior to expiration of the specified time intervals, completion of the Action requirements is not required. 3.0.3 When a Limiting Condition for Operation is not met, except as provided in the associated ACTION requirements, within one hour action shall be initi-ated to place the unit in an OPERATIONAL CONDITION in which the Specification does not apply by placing it, as applicable, in:

1. At least STARTUP within the next 6 hours,

2. At least HOT SHUTOOWN within the following 6 hours, and

3. At least COLD SHUTDOWN within the subsequent 24 hours.

O Where corrective measures are completed that permit operation under the ACTION requirements, the ACTION may be taken in accordance with the specified time limits as measured from the time of failure to meet the Limiting Condition for Operation. Exceptions to these requirements are stated in the individual Specifications. This Specification is not applicable in OPERATIONAL CONDITIONS 4 or 5. 3.0.4 Entry into an OPERATIONAL CONDITION or other specified condition shall not be made unless the conditions for the Limiting Condition for Operation are I met without reliance on provisions contained in the ACTION requirements. This provision shall not prevent passage through or to OPERATIONAL CONDITIONS as required to comply with ACTION requirements. Exceptions to these requirements are stated in the individual Specifications. O HOPE CREEK 3/4 0-1

APPLICABILITY SURVEILLANCE REQUIREMENTS 4.0.1 Surveillance Requirements shall be met during the OPERATIONAL CONDITIONS or other conditions specified for individual Limiting Conditione for Operation unless otherwise stated in an individual Surveillance Requirement. 4.0.2 Each Surveillance Requirement shall be performed within the specified time interval with:

a. A maximum allowable extension not to exceed 25% of the surveillance interval, but

b. The combined time interval for any 3 consecutive surveillance inter-vals shall not exceed 3.25 times the specified surveillance interval.

4.0.3 Failure to perform a Surveillance Requirement within the specified time interval shall constitute a failure to meet the OPERABILITY requirements for a Limiting Condition for Operation. Exceptions to these requirements are stated in the individual Specificatons. Surveillance requirements do not have to be performed on inoperable equipment. 4.0.4 Entry into an OPERATIONAL CONDITION or other specified applicable condi-tion shall not be made unless the Surveillance Requirement (s) associated with the Limiting Condition for Operation have been performed within the applicable surveillance interval or as otherwise specified. 4.0.5 Surveillance Requirements for inservice inspection and testing of ASME Code Class 1, 2, & 3 components shall be applicable as follows:

a. Inservice inspection of ASME Code Class 1, 2, and 3 components and inservice testing of ASME Code Class 1, 2, and 3 pumps and valves shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 l CFR 50, Section 50.55a(g), except where specific written relief has l been granted by the Commission pursuant to 10 CFR 50, Section 50.55a(g) l (6) (1).

l

b. Surveillance intervals specified in Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda for the inservice inspection and testing activities required by the ASME Boiler and Pressure Vessel Code and applicable Addenda shall be applicable as follows in these Technical Specifications:

ASME Boiler and Pressure Vessel Required frequencies l Code and applicable Addenda for performing inservice terminology for inservice inspection and testing inspection and testing activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days l Yearly or annually At least once per 366 days HOPE CREEK 3/4 0-2

i APPLICABILITY L SURVEILLANCE REQUIREMENTS (Continued)

c. The provisions of Specification 4.0.2 are applicable to the above required frequencies for performing inservice inspection and testing activities.

d. Performance of the above inservice inspec. tion and tecting activities ,

shall be in addition to other specified Surve111ar.ce Requirements.

e. Nothing in the ASHE Boiler and Pressure Vessel Code shall be con ~

strued to supersede the requiren,ents of any Technical Specificatien. e i f f 4 l I f a l I ! t f l HOPE CREEK 3/4 0-3

  -                          -~                                                                                                                                          . -

g4 d REAClIVily CONTROL SYSTEMS 3/4.1.1 91UTDOWN KtRGIij LIMITING CONDITIG4 F0ft OPERATION

                       ~                  -- -                       .

3.1. *t The StiUTDOWN MARCIN shall be equal to or greater than:

a. 0.38% delta k/k with the highest worth rod analytically determined, or

b. 0.28% delta k/k with the highest worth rod determined by test.

APPLILADILITY:_ ,0PERATIONAL CONDITIDNS 1, 2, 3, 4 and 5. ACTION: With the SHUT 00WN MARGIN less than specified:

a. In QPERATIONAL CONDITION 1 or 2, reestablish the required SHUTDJWN MARGIN witnin 6 hours or be in at least HOT SHUTDOWN within the next 12 h9urs..

t. In OPERAYIONAl. CONDITION 3 or 4, immediately verify all insertable

    ;                               control rods sto be inserted and suspend all activities that could

( r6duca the SHUTDOWN MARGIN. In OPERATIONAL CONDITION 4, establish SECONCARY CONTAINMENT INTEGRITY within 8 hours.

c. In OPERATIONAL CONDITION 5, suspend CORE ALTERATIONS and other activities that could reduce the SHUTDOWN MARGIN and insert all insertable control rods within 1 hour. Establish SECONDARY CONTAIN-tiENT INTEGRITY within 8 hours.

SURVEILLANCFRELOIREMENTS l 4.1.1 Tne SHUTOOWN MARGIN shall be determined to be equal to or greater than

specified at any tice during the fuel cycle

l a. By measurement., prior to or during the first startup after each refueling.

b. By measurement, within 500 MWD /T prior to the cort average exposure at which the predicted SiltJT00WN MARGIN, including uncertainties and cal.culation biases, is equal to the specified limit.

c. Within 12 hours after detection of a withdrawn control rod that is lanovaole, as' a result cf excessive friction or mechanical inter-ference, or is untrippable, except that the above required SHUTDOWN MARGIN Shall be verified acceptable with an increased allowance for

      '                             the withdrawn worth of the immovable or untrippable control rod.

l HOPE CREEK 3/4 1-1 1 _ _ - _ _ _ . . _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ ~ _ _ _ . . . _ _ . _ _ _ _ _ _ _ _ _ . . . _ _ _ . _ _ _

1 l REACTIVITY CONTROL SYSTEMS 3/4.1.2 REACTIVITY ANOMALIES LIMITING CONDITION FOR OPERATION 3.1.2 The reactivity equivalence of the difference between the actual R0D DENSITY and the predicted R0D DENSITY shall not exceed 1% delta k/k. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With the reactivity equivalence difference exceeding 1% delta k/k:

a. Within 12 hours perform an analysis to determine and explain the cause of the reactivity difference; operation may continue if the difference is explained and corrected.

b. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.

SURVEILLANCE REQUIREMENTS 4.1.2 The reactivity equivalence of the difference between the actual R0D DENSITY and the predicted R0D DENSITY shall be verified to be less than or

equal to 1% delta k/k: a. During the first startup following CORE ALTERATIONS, and; b. At least once per 31 ef fective full power days during POWER OPERATION.

i l O HOPE CREEK 3/4 1-2

REACTIVITY CONTROL SYSTEMS 3/4.1.3 CONTROL RODS CONTROL R00 OPERABILITY LIMITING CONDITION FOR OPERATION 3.1.3.1 All control rods shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With one control rod inoperable due to being immovable, as a result of excessive friction or mechanical interference, or known to be untrippable:

1. Within one hour:

a) Verify that the inoperable control rod, if withdrawn, is separated from all other inoperable control rods by at least two control cells in all directions. b) Disarm the associated directional control valves ** hydraulically by closing the drive water and exhaust water isolation valves. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.

2. Restore the inoperable control rod, if withdrawn, to OPERABLE status within 48 hours or be in at least HOT SHUTDOWN within the next 12 hours.

b. With one or more control rods trippable but inoperable for causes other than addressed in ACTION a, above:

1. If the inoperable control rod (s) is withdrawn, within one hour:

a) Verify that the inoperable withdrawn control rod (s) is separated from all other inoperable withdrawn control rods by at least two control cells in all directions, and b) Demonstrate the insertion capability of the inoperable withdrawn control rod (s) by inserting the control rod (s) at least one notch by drive water pressure within the normal operating range

Otherwise, insert the inoperable withdrawn control rod (s) and disarm the associated directional control valves ** either:

a) Electrically, or b) (lydraulically by closing the drive water and exhaust water isolation valves.

   *The inoperable control rod may then be withdrawn to a position no further withdrawn than its position when found to be inoperable.

O **May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status. HOPE CREEK 3/4 1-3

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) _ ACTION (Continued)

2. If the inoperable control rod (s) is inserted, within one hour disarm the associated directional control valves ** either:

a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves. Othemise, be in at least HOT SHUTDOWN within the next 12 hours.

3. The provisions of Specification 3.0.4 are not applicable.

c. With more than 8 control rods inoperable, be in at least HOT SHUTDOWN within 12 hours,

d. With one scram discharge volume vent valve and/or one scram discharge volume drain valve inoperable and open, restore the inoperable valve (s) to OPERABLE status within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours.

e. With any scram discharge volume vent valve (s) and/or any scram discharge volume drain valve (s) otherwise inoperable, restore the inoperable valve (s) to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours.

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The scram discharge volume drain and vent valves shall be demonstrated OPERABLE by:

a. At least cnce per 24 hours verifying each valve to be open,* and

b. At least once per 31 days cycling each valve through at least one complete cycle of full travel.

4.1.3.1.2 *When above the low power setpoint of the RWM and RSCS, all withdrawn control rods not required to have their dirrctional control valves disarmed

 *These valves may be c,losed intermittently for testing under administrative controls.
**May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.

HOPE CREEK 3/4 1-4

x REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) electrically or hydraulically shall be demonstrated OPERABLE by moving each control rod at least one notch:

a. At least once per 7 days, and

b. At least once per 24 hours when any control rod is immovable as a result of excessive friction or mechanical interference.

4.1.3.1.3 All control rods shall be demonstrated OPERABLE by performance of ! Surveillance Requirements 4.1.3.2, 4.1.3.4, 4.1.3.5, 4.1.3.6 and 4.1.3.7. 4.1.3.1.4 The scram discharge volume shall be determined OPERABLE by demonstrating:

a. The scram discharge volume drain and vent valves OPERABLE at least once per 18 months, by verifying that the drain and vent valves:

1. Close within 30 seconds after receipt of a signal for control rods to scram, and

2. Open when the scram signal is reset.

e r O HOPE CREEK 3/4 1-5

r REACTIVITY CONTROL SYSTEMS CONTROL R0D MAXIMUM SCRAM INSERTION TIMES LIMITING CONDITION FOR OPERATION 3.1.3.2 The maximum scram insertion time of each control rod from the fully withdrawn position to notch position 5, based on de-energization of the scram pilot valve solenoids as time zero, shall not exceed 7.0 seconds. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With the maximum scram insertion time of one or more control rods exceeding 7.0 seconds:

1. Declare the control rod (s) with the slow insertion time inoperable, and

2. Perform the Surveillance Requirements of Specification 4.1.3.2.c at least once per 60 days when operation is continued with three or more control rods with maximum scram insertion times in excess of 7.0 seconds.

Otherwise, be in at least HOT SHUTDOWN within 12 hours.

b. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS I 4.1.3.2 The maximum scram insertion time of the control rods shall be demon-I strated through measurement with reactor coolant pressure greater than or equal to 950 psig and, during single control rod scram time tests, the control rod drive ptmps isolated from the accumulators:

a. For all control rods prior to THERMAL POWER exceeding 40% of RATED THERMAL POWER following CORE ALTERATIONS or after a reactor shutdown that is greater than 120 days.

b. For specifically affected individual control rods following maintenance on or modification to the control rod or control rod drive system which could affect the scram insertion time of those specific control rods, and l c. For at least 10% of the control rods, on a rotating basis, at least once per 120 days of POWER OPERATION.

O HOPE CREEK 3/4 1-6

 ,~
    ) REACTIVITY CONTROL SYSTEMS J

CONTROL R00 AVERAGE SCRAM INSERTION TIMES LIMITING CONDITION FOR OPERATION 3.1.3.3 The average scram insertion time of all OPERABLE control rods from the fully withdrawn position, based on de-energization of the scram pilot valve solenoids as time zero, shall not exceed any of the following: Position Inserted From Average Scram Inser-Fully Withdrawn tion Time (Seconds) 45 0.43 39 0.86 25 1.93 05 3.49 APPLICABILITY: OPEPATIONAL CONDITIONS 1 and 2. ACTION: With the average scram insertion time exceeding any of the above limits, be in at least HOT SHUTDOWN within 12 hours. d SURVEILLANCE REQUIREMENTS 4.1.3.3 All control rods shall be demonstrated OPERABLE by scram time testing from the fully withdrawn position as required by Surveillance Requirement 4.1.3.2. , l l HOPE CREEK 3/4 1-7

REACTIVITY CONTROL SYSTEMS FOUR CONTROL R0D GROUP SCRAM INSERTION TIMES LIMITING CONDITION FOR OPERATION 3.1.3.4 The average scram insertion time, from the fully withdrawn position, for the three fastest control rods in each group of four control rods arranged in a two-by-two array, based on deenergization of the scram pilot valve solenoids as time zero, shall not exceed any of the following: Position Inserted From Average Scram Inser-Fully Withdrawn tion Time (Seconds) 45 0.45 39 0.92 25 2.05 05 3.70 APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With the average scram insertion times of control rods exceeding the above limits:

1. Declare the control rods with the slower than average scram insertion times inoperable until an analysis is performed to determine that required scram reactivity remains for the slow four control rod group, and

2. Perform the Surveillance Requirements of Specification 4.1.3.2.c at least once per 60 days when operation is continued with an average scram insertion time (s) in excess of the average scram insertion time limit.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.

b. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.1.3.4 All control rods shall be demonstrated OPERABLE by scram time testing from the fully withdrawn position as required by Surveillance Requirement 4.1.3.2. O HOPE CREEK 3/4 1-8

 /Q    REACTIVITY CONTROL SYSTEMS U     CONTROL ROD SCRAM ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.1.3.5 All control rod scram accumulators shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:

a. In OPERATIONAL CONDITIONS 1 or 2:

1. With one control rod scram accumulator inoperable, within 8 hours:

a) Restore the inoperable accumulator to OPERABLE status, or b) Declare the control rod associated with the inoperable accumulator inoperable. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.

2. With more than one control rod scram accumulator inoperable, declare the associated control rods inoperable and:

a) If the control rod associated with any inoperable scram accu-mulator is withdrawn, immediately verify that at least one control rod drive pump is operating by inserting at least one withdrawn control rod at least one notch. If no control rod drive pump is operating: 1) If reactor pressure is O, > 900 psig, restart at least one control rod drive pump within 20 minutes or place the reactor mode switch in the Shutdown position. 2) If reactor pressure is < 900 psig, place the reactor mode switch in the Shutdown position. b) Insert the inoperable control rods and disarm the associated control valves either:

1) Electrically, or

2) Hydraulically by closing the drive water and exhaust water isolation valves.

Otherwise, be in at least HOT SHUTDOWN within 12 hours,

b. In OPERATIONAL CONDITION 5*:

1. With one withdrawn control rod with its associated scram accumu-lator inoperable, insert the affected control rod and disarm the associated directional control valves within one hour, either:

a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves.

2. With more than one withdrawn control rod with the associated scrar accumulator inoperable and no control rod drive pump operating, immediately place the reactor mode switch in the Shutdown position.

c. The provisions of Specification 3.0.4 are not applicable.

      *At least the accumulator associated with each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

HOPE CREEK 3/4 1-9

l l REACTIVITY CONTROL SYSTEMS I ! SURVEILLANCE REQUIREMENTS 4.1.3.5 Each control rod scram accumulator shall be determined OPERABLE:

a. At least once per 7 days by verifying that the indicated pressure is greater than or equal to 940 psig unless the control rod is inserted and disarmed or scrammed.

b. At least once per 18 months by:

1. Performance of a:

a) CHANNEL FUNCTIONAL TEST of the leak detectors, and b) CHANNEL CALIBRATION of the pressure detectors, and verifying an alarm setpoint of 940 + 95, -0 psig on decreasing pressure. O l l l l O HOPE CREEK 3/4 1-10

( REACTIVITY CONTROL SYSTEMS CONTROL ROD DRIVE COUPLING LIMITING CONDITION FOR OPERATION 3.1.3.6 All control rods shall be coupled to their drive mechanisms. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:

a. In OPERATIONAL CONDITION 1 and 2 with one control rod not coupled to its associated drive mechanism, within 2 hours:

1. If permitted by the RWM and RSCS, insert the control rod to accomplish recoupling and verify recoupling by withdrawing the control rod, and:

a) Observing any indicated response of the nuclear instrumentation, and b) Demonstrating that the control rod will not go to the overtravel position.

2. If recoupling is not accomplished on the first attempt or, if not permitted by the RWM or RSCS, then until permitted by the RWM and RSCS, declare the control rod inoperable, insert the control rod and g disarm the associated directional control valves ** either:

a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours,

b. In OPERATIONAL CONDITION 5* with a withdrawn control rod not coupled to its associated drive mechanism, within 2 hours either:

l 1. Insert the control rod to accomplish recoupling and verify recoupling l by withdrawing the control rod and demonstrating that the control rod will not go to the overtravel position, or

2. If recoupling is not accomplished, insert the control rod and disarm the associated directional control valves ** either:

a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves.

c. The provisions of Specification 3.0.4 are not applicable.

l "At least each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

   **May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.

l HOPE CREEK 3/4 1-11

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.3.6 Each affected control rod shall be , demonstrated to be coupled to its drive mechanism by observing any indicated response of the nuclear instrumen-tation while withdrawing the control rod to the fully withdrawn position and then verifying that the control rod drive does not go to the overtravel position:

a. Prior to reactor criticality after completing CORE ALTERATIONS that could have affected the control rod drive coupling integrity,

b. Anytime the control rod is withdrawn to the " Full out" position in subsequent operation, and

c. Following maintenance on or modification to the control rod or control rod drive system which could have affected the control rod drive coupling integrity.

O I I O HOPE CREEK 3/4 1-12

() r REACTIVITY CONTROL SYSTEMS CONTROL ROD POSITION INDICATION LIMITING CONDITION FOR OPERATION 3.1.3.7 The control rod position indication system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:

a. In OPERATIONAL CONDITION 1 or 2 with one or more control rod position indicators inoperable, within 1 hour:

1. Determine the position of the centrol rod by utilizing the RSCS substitute position display within preset power level, or:

a) Moving the control rod, by single notch movement, to a position. with an OPERABLE position indicator, b) Returning the control rod, by single notch movement, to its original po:;ition, and c) Verifying no control rod drift alarm at least once per 12 hours, or i 2. Hove the control rod to a position with an OPERABLE position n/ indicator, or

3. When THERMAL POWER is:

a) Within the preset power level of the RSCS, declare the control rod inoperable. b) Greater than the preset power level of the RSCS, declare the control rod inoperable, insert the control rod and disarm the associated directional control valves ** either:

1) Electrically, or

2) Hydraulically by closing the drive water and exhaust water isolation valves.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.

b. In OPERATIONAL CONDITION 5* with a withdrawn control rod position indicator inoperable, move the control rod to a position with an OPERABLE position indicator or insert the control rod.

c. The provisions of Specification 3.0.4 are not applicable.

       *At least each withdrawn control rod. Not applicable to control rods removed Q       per Specification 3.9.10.1 or 3.9.10.2.

U **May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status. HOPE CREEK 3/4 1-13

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.3.7 The control rod position indication system shall be determined OPERABLE by verifying:

a. At least once per 24 hours that the position of each control rod is indicated,

b. That the indicated control rod position changes during the movement of the control rod drive when performing Surveillance Requirement 4.1.3.1.2, and

c. That the control rod position indicator corresponds to the control rod position indicated by the " Full Out" position indicator when performing Surveillance Requirement 4.1.3.6.b.

O O HOPE CREEK 3/4 1-14

f3 REACTIVITY CONTROL SYSTEM 5 CONTROL ROD ORIVE HOUSING SUPPORT LIMITING CONDITION FOR OPERATION _ 3.1.3.8 The control rod drive housing support shall be in place. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the control rod drive housing support not in place, be in at least HOT SHUTDOWN within 12 hours and in 0.0LD SHUTDOWN within tha following 24 hours. SURVEILLANCE REQUIREMENTS b G 4.1.3.8 The control rod drive housing support shall be verified to be in place by a visual inspection prior to startup any time it has been disassembled or when maintenance has been performed in the control rod drive housing support area. l t l w HOPE CREEK 3/4 1-15

  -pv..g-w y -,r-,-4--,       - - - - - - - - - - -      %  - - , . , ..-

REACTIVITY CONTROL SYSTEMS 3/4.1.4 CONTROL ROD PROGRAM CONTROLS ROD WORTl1 MINIMIZER LIMITING CONDITION FOR OPERATION 3.1.4.1 The rod worth minimizer (RWM) shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2*#, when THERMAL POWER is less than or equal to 20% of RATED THERMAL POWER, the minimum allowable low power setpoint. ACTION:

a. With the RWM inoperable, verify control rod movement and compliance with the prescribed control rod pattern by a second licensed operator or other technically qualified member of the unit technical staff who is present at the reactor control console. Otherwise, control rod movement may be only by actuating the manual scram or placing the reactor mode switch in the Shutdown position.

b. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.1.4.1 The RWM shall be demonstrated OPERABLE: 1

a. In OPERATIONAL CONDITION 2 within 8 hours prior to withdrawal of control rods for the purpose of making the reactor critical, and in OPERATIONAL CONDITION 1 within 8 hours prior to RWM automatic initia-tion when reducing THERMAL POWER, by verifying proper indication of the selection error of at least one out-of-sequence control rod.

b. In OPERATIONAL CONDITION 2 within 8 hours prior to withdrawal of control rods for the purpose of making the reactor critical, by verifying the rod block function by demonstrating inability to withdraw an out-of-sequence control rod.

c. In OPERATIONAL CONDITION 1 within one hour after RWM automatic initiation when reducing THERMAL POWER, by verifying the rod block i

function by demonstrating inability to withdraw an out-of-sequence control rod.

d. By verifying that the control rod patterns and sequence input to the RWM computer are correctly loaded following any loading of the program into the computer.

l

Entry into OPERATIONAL CONDITION 2 and withdrawal of selected control rods is permitted for the purpose of determining the OPERABILITY of the RWM prior to withdrawal of control rods for the purpose of bringing the reactor to criticality.

 #See Special Test Exception 3.10.2.

HOPE CREEK 3/4 1-16 l l

REACTIVITY CONTROL SYSTEMS ROD SEQUENCE CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.4.2 The rod sequence control system (RSCS) shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2*#, when THERMAL POWER is less than or equal to 20% RATED THERMAL POWER, the minimum allowable low power setpoint. ACTION:

a. With the RSCS inoperable, control rod movement shall not be permitted, except by a scram,

b. With an inoperable control rod (s), OPERABLE control rod movement may continue by bypassing the inoperable control rod (s) in the RSCS provided that:

1. The position and bypassing of inoperable control rods is verified by a second licensed operator or other technically qualified member of the unit technical staff, and

2. There are not more than 3 inoperable control rods in any RSCS f] group.

SURVEILLA.1CE REQUIREMENTS 4.1.4.2 The RSCS shall be demonstrated OPEEABLE by:

a. Performance of a system diagnostic function:

1. Within 8 hours prior to each reactor startup, and

2. Prior to movement of a control rod after rod inhibit mode automatic initiation when reducing THERMAL POWER.

b. Attempting to select and move an inhibited control rod:

1. After withdrawal of the first insequence control rod for each reactor startup, and

2. Within one hour after rod inhibit mode automatic initiation when reducing THERMAL POWER.

    *See Special Test Exception 3.10.2 l    # Entry into OPERATIONAL CONDITION 2 and withdrawal of selected control rods is permitted for the purpose of determining the OPERABILITY of the RSCS prior to withdrawal of control rods for the purpose of bringing the reactor to criticality.

HOPE CREEK 3/4 1-17 i

t REACTIVIfY CONTROL SYSTEMS R0D BLOCK MONITOR LIMITING CONDITION FOR OPERATION 3.1.4.3 Both rod block monitor (RBM) channels shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 30% of 'tATED THERMAL POWER. ACTION:

a. With one RBM channel inoperable:

1. Verify that the reactor is not operating on a LIMITING CONTROL R0D PATTERN, and

2. Restore the inoperable RBM channel to OPERABLE status within 24 hours.

Otherwise, place the inoperable rod block monitor channel in the tripped condition within the next hour.

b. With both RBM channels inoperable, place at least one inoperable rod block monitor channel in the tripped condition within one hour.

SURVEILLANCE REQUIREMENTS 4.1.4.3 Eacts of the above required RBM channels shall be demonstrated OPERABLE by performance of a:

a. CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION at the frequencies and for the OPERATIONAL CONDITIONS specified in Table 4.3.6-1.

b. CHANNEL FUNCTIONAL TEST prior to control rod withdrawal when the reactor is operating on a LIMITING CONTROL ROD PATTERN.

O HOPE CREEK 3/4 1-18

im (d ) REACTIVITY CONTROL SYSTEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.5 The standby liquid control system consists of two redundant subsystems and shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 5* ACTION:

a. In OPERATIONAL CONDITION 1 or 2:

1. With one system subsystem inoperable, restore the subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours.

2. With ooth system subsystems inoperable, restore at least one subsystem to OPERABLE status within 8 hours or be in at least H0T SHUTDOWN within the next 12 hours.

b. In OPERATIONAL CONDITION 5*:

1 1. With one system subsystem inoperable, restore subsystem to , [^ OPERABLE status within 30 days or insert all insertable control ( rods within the next hour.

2. With both standby liquid control system subsystems inoperable, insert all insertable control rods within one hour.

SURVEILLANCE REQUIREMENTS 4.1.5 The standby liquid control system shall be demonstrated OPERABLE:

a. At least once per 24 hours by verifying that;

1. The temperature of the sodium pentaborate solution in the storage tank is greater than or equal to 70*F.

l 2. The available volume of sodium pentaborate solution is within the limits of Figure 3.1.5-1. l

3. The heat tracing circuit is OPERABLE by determining the i temperature of the pump suction piping to be greater than or equal to 70 F.

       *With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

HOPE CREEN 3/4 1-19

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. At least once per 31 days by:

1. Verifying the continuity of the explosive charge.

2. Determining that the available weight of sodium pentaborate is greater than or equal to 5,760 lbs and the concentration of boron in solution is within the limits of Figure 3.1.5-1 by chemical analysis.*

3. Verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

c. Demonstrating that, when tested pursuant to Specification 4.0.5, the minimum flow requirement of 41.2 gpm, per pump, at a pressure of greater than or equal to 1255 psig is met.

d. At least once per 18 months during shutdown by:

1. Initiating one of the standby liquid control system subsystem, including an explosive valve, and verifying that a flow path from the pumps to the reactor pressure vessel is available by pumping demineralized water into the reactor vessel and verifying that the relief valve does not actuate. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of that batch successfully fired. Both injection subsystems shall be tested in 36 months.

2. ** Demonstrating that all heat traced piping between the storage tank and the injection pumps is unblocked and then draining and flushing the piping with demineralized water.

l 3. Demonstrating that the storage tank heaters are OPERABLE by I verifying the expected temperature rise of the sodium penta- ! borate solution in the storage tank after the heaters are energized.

     *This test shall also be performed anytime water or boron is added to the solution or when the solution ~ temperature drops below 70 F.

Q*This test shall also be performed whenever both heat tracing circuits have been found to be inoperable and may be performed by any series of sequential, overlapping or total flow path steps such that the entire flow path is included. HOPE CREEK 3/4 1-20

O O O g REGION OF APPROVED o CONCENTRATION V0LLME E ACCEPTABLE OPERATING E REGION - ENTIRE ZONE n LOW HIGH s LEVEL LEVEL ~ OVERFLOW ALARM ALARM LEVEL ac 14.0 - I Q. I I j l f l f

                                                           - 13.8 5

i C

EXPANSION P VOLUME I l w E N U g g MINIMUM REQUIRED CONCENTRATION LINE

 $                                                   13.0   .

l g - 12.9 o e g 4690 4850 4997 5058 E 12.5 4400 4500 4600 4700 4800 4900 5000 5100 5200 i V - NET VOLUME (GALLONS) i S0DIUM PENTABORATE SOLUTION l VOLUME / CONCENTRATION REQUIREMENTS i j Figure 3.1.5-1

3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION l 3.2.1 All AVERAGE PLANAR LINEAR HEAT GENERATION RATES (APLHGRs) for each type of fuel as a function of AVERAGE PLANAR EXPOSURE shall not exceed the limits shown in Figures 3.2.1-1, 3.2.1-2, 3.2.1-3, 3.2.1-4, and 3.2.1-5. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With an APLHGR exceeding the limits of Figure 3.2.1-1, 3.2.1-2, 3.2.1-3, 3.2.1-4, or 3.2.1-5, initiate corrective action within 15 minutes and restore APLHGR to within the required limits within 2 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. N , SURVEILLANCE REQUIREMENTS 4.2.1 All APLHGRs shall be verified to be equal to or less than the limits determined from Figures 3.2.1-1, 3.2.1-2, 3.2.1-3, 3.2.1-4 and 3.2.1-5:

a. At least once per 24 hours,

b. Within 12 hours after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER, and

c. Initially and at least once per 12 hours when the reactor is operating with a LIMITING CONTROL ROD PATTERN for APLHGR.

d. The provisions of Specification 4.0.4 are not applicable.

O HOPE CREEK 3/4 2-1

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N-- ; 4i r ,- . s 0 5 10 15 20 25 30 35 40 AVERA E W E N , GWd/st MAXIMLM AVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR) VERSUS AVERAGE PLANAR EXPOSURE INITIAL CORE FUEL TYPE P8CIB278 Figure 3.2.1-5 O --_ . O O

n

     )  POWER DISTRIBUTION LIMITS 3/4.2.2 APRM SETPOINTS LIMITING CONDITION FOR OPERATION 3.2.2 The APRM flow biased simulated thermal power-upscale scram trip setpoint (S) and flow biased neutron fiux-upscale control rod block trip setpoint (SRB) shall be established according to the following relationships:

TRIP SETPOINT ALLOWABLE VALUE S s (0.66W + 51%)T S < (0.66W + 54%)T S RB 5 (0.66W + 42%)T S RB 5 (0.66W + 45%)T where: S and S are in percent of RATED THERMAL POWER, DB W = Loo recirculation flow as a percentage of the loop recirculation flow which produces a rated core flow of 100 million lbs/hr, T = Lowest value of the ratio of FRACTION OF RATED THERMAL POWER (FRTP) divided by the CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CMFLPD). T is applied only if less than or equal to 1.0. s APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: lO v j With the APRM flow biased simulated thermal power-upscale scram trip setpoint and/or the flow biased neutron flux-upscale control rod block trip setpoint less conservative than the value shown in the Allowable Value column for S or S as above determined, initiate corrective action within 15 minutes andadhs,tSand/ ors g to be consistent with the Trip Setpoint values

within 6 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours.

SURVEILLANCE REQUIREMENTS ___ 4.2.2 The FRTP and the CMFLPD shall be determined, the value of T calculated, and the most recent actual APRM flow biased simulated theratal power-upscale scram and flow biased neutron flux-upscale control rod block trip setpoints verified to be within the above limits or adjusted, as required: l a. At least once per 24 hours, I

b. Within 12 hours after completion of a THERMAL POWER increase of at )

least 15% of RATED THERMAL POWER, and l

c. Jnitially and at least once per 12 hours when the reactor is operating with CMFLPD graater than or equal to FRTP.

d. The provisions of Specification 4.0.4 are not applicable.

l *With CMFLPD greater than the FRTP up to 90% of RATED THERMAL POWER, rather than l p adjusting the APRM setpoints, the APRM gain may be adjusted such that the APRM readings are greater than or equal to 100% times CMFLPD provided that the l \ adjusted APRM reading does not exceed 100% of RATED THERMAL POWER and a notice of adjustment is posted on the reactor control panel. HOPE CREEK 3/4 2-7 i

POWER GISTRIEUTION LIMITS 3/_4.2.3 MINIMUM CRIT _I_C_AL_ POWER RATIO LIMITINGCON91TI0HFOR]3QRAT?0N_ _ 3.2.3 The MINIMUM CPITICAL POWER RAT 10 (MCPR) shall be equal to or greater than the sum of the MCPR limit shewn in Figure 2.2.3-1 plus the feedwater heating capacity adjustment giveri in Tabla 3.2.3-1 times the Kf shown in Figure 3.2.3-2, with: _ {Iave IE) T ~I A B where: T A = 0.86 seconds, control rod average scram insertion time liniit to notch 39 per Specification 3.1.3.3, N r g= 0.688 + 1.65[ l N o.052),

                                                                    "   N.

I 1 i=1 1 I ave = i=1 "i'i , n I N. I i'l n = number of surveillance tests performed to date in cycle, th N'.

                                    = number of active control rods measured in the i surveillance test, T    9 = average scram time to notch 39 of all rods measured th surveillance test, and in the i N = total number of active rods measured in Specification 1

4.1.3.2.a. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. O HOPE CREEK 3/4 2-8

(~'N, POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO LIMITING CONDITION FOR OPERATION c ACTION: With MCPR less than the applicable MCPR limit shown in Figures 3.2.3-1 and 3.2.3-2 plus the feedwater heating capacity adjustment given in Table 3.2.3-1, initiate corrective action within 15 minutes and restore MCPR to within the required limit within 2 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REQUIREMENTS 4.2.3 HCPR, with:

a. t = 1.0 prior to performance of the initial scram time measurements for the cycle in accordance with Specification 4.1.3.2, or

b. I as defined in Specification 3.2.3 used to determine the limit

  ,,                  within 72 hours of the conclusion of each scram time surveillance test required by . Specification 4.1.3.2, (v}   shall be determined to be equal to or greater than the applicaole MCPR limit determined from Figures 3.2.3-1 and 3.2.3-2:

a. At least once per 24 hours,

b. Within 12 hours after completion cf a THERMAL POWER increase of at least 15% of RATED THERMAL POWER, and

c. Initially and .at least once per 12 hours when the reactor is ,

operating with a LIMITING CONTROL R00 PATTERN for MCPR. j

d. The provisions of Specification 4.0.4 are not applicable. l l

t i i V 1 HOPE CREEK 3/4 2-9

O 1 1.29 1.28 1.27 1.26 1.25 1.24 1.23 1.22 1.21 : a

                 $    1.20 2    j,jg                                       f EOC-E PT AND MAlli1 URBINE I-                  BYPASS OPERdBLE 1.16 1.15 1.14 1.13 1.12 1.11 1.10 0 0.2          0.4                  0.6                  0.8   1 T

I l MINIMUM CRITICAL POWER RATIO (MCPR) i l i VERSUS T AT RATED FLOW . 1 i Figure 3.2.3-1 i

      ,.>          HOPE CREEK                    3/4 2-10

O

   '^
      ,       l            1         4                5             1            i SJ                                                 '

l

                              \                           geseAYac Maur cosmtot t

j ecoor Tust PmaTt006

   . _        = "H = ::in
                 = == : =V
                                                                                   \     \

as es m a a se se me Guse ftser. 4 Of Ilsend Cass Meer K FACTOR O 7 Figure 3.2.3-2 HOPE CREEK 3/4 2-11

i i Table 3.2.3-1 MCPR FEEDWATER HEATING CAPACITY ADJUSTMENT ; Rated Power Feedwater

Temperature Capacity MCPR Adjustment

                > 400 F                                           c0
                > 320 F 0.03
                > 250 F                                           0.06 4

O O HOPE CREEK 3/4 2-12

POWER DISTRIBUTION LIMITS 3/4.2.4 LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION 3.2.4 The LINEAR HEAT GENERATION RATE (LHGR) shall not exceed 13.4 kw/ft. t

              ~ APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or Equal to 25% of RATED THERMAL POWER.

ACTION: With the LHGR of any fuel rod exceeding the limit, initiate corrective action within 15 minutes and restore the LHGR to within the limit within 2 hours or

              . reduce THERhAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours.

SURVEILLANCE REQUIREMENTS 4.2.4 LHGR's shall be deterained to be equal to or less than the limit: 4

a. At least once per 24 hours,

b. Within 12 hours after completion of a THERMAL POWER increase of at i least 15% of RATED THERMAL POWER, and

c. Initially and at least once per 12 hours when the reactor is

. operating on a LIMITING CONTROL R0D PATTERN for LHGR. l d. The provisions of Specification 4.0.4 are not applicable. l l HOPE CREEK 3/4 2-13 l

l l 3/4.3 INSTRUMENTATION l 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be OPERABLE with the CEACTOR PROTECTION SYSTEM RESPONSE TIME as shown in Table 3.3.1-2. APPLICABILITY: As shown in Table 3.3.1-1. ACTION:

a. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channel (s) and/or that trip system in the tripped condi-tion' within one hour. The provisions of Specification 3.0.4 are not applicable.

b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition within one hour and take the ACTION required by Table 3.3.1-1.

SURVEILLANCE REQUIREMENTS N 4.3.1.1 Each reactor protection system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.1.1-1. 4.3.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 1 4.3.1.3 The REACTOR PROTECTION SYSTEM RESPONSE TIME of each reactor trip functional unit shown in Table 3.3.1-2 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months whera N is the total number of redundant channels in a specific reactor trip system.

   ' An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, the inoper Wie channel shall be restored to OPERABLE status within 2 hours or the ACTION required by Table 3.3.1-1 for that Trip Function shall be taken.
   **If more channels are inoperable in one trip system than in the other, place the trip system with more inoperable channels in the tripped condition, except when this would cause the Trip Function to occur.

O d HOPE CREEK 3/4 3-1

TABLE 3.3.1-1 5 A REACTOR PROTECTION SYSTEM INSTRUMENTATION n E R APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION l

1. Intermediate Range Monitors (b)

a. Neutron Flux - High 2 3 1 3, 4(c) 2 2(d)

b. Inoperative 2 3 1 3, 4 2 5 2(d) 3 3

2. Average Power Range Monitor (*):

R a. Neutron Flux - Upscale, Setdown 2 2 1 3, 2 (c) 2(d) m

b. Flow Biased Simulated Thermal Power - Upscale 1 2 4

c. Fixed Neutron Flux - Upscale 1 2 4

d. Inoperative 1, 2 2 1 3, 2 (c) 2(d) l e. Downscale 1(9) 2 4 1

1 3. Reactor Vessal Steam Dome l Pressure - High 1,2(I) 2 1 1

4. Reactor Vessel Water Level - Low, Level 3 1, 2 2 1

5. Main Steam Line Isolation Valve -

Closure 1(9) 4 4 l l 9 O O

(% i O L] TABLE 3.3.1-1 (Continued) REACTOR PROTECTION SYSTEM INSTRUMENTATION n x A APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION

6. Main Steam Line Radiation -

High, High 1, 2(I) 2 5 i l 7. Drywell Pressure - High 1, 2(h) 2 1

8. Scram Discharge Volume Water Level - High

,       a. Float Switch                         1, 2 Cg)                      2                  1 j

R S 2 3 Y b. Level Transmitter / Trip Unit 1, 2(g) 2 1 w 5 i 2 3 4 Turbine Stop Valve - Closure 1(I) 4(k) 6

10. Turbine Control Valve Fast Closure, Valve Trip System Oil Pressure - Low 1(I) 2(k) 6

11. Reactor Mode Switch Shutdown Position 1, 2 2 1 3, 4 2 7 5 2 3

12. Manual Scram 1, 2 2 1 3, 4 2 8 5 2 9

TABLE 3.3.1-1 (Continued) REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION ACTION 1 - Be in at least HOT SHUTDOWN within 12 hours. ACTION 2 - Verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within one hour. ACTION 3 - Suspend all operations involving CORE ALTERATIONS

and insert all insertable control rods within one hour.

ACTION 4 - Be in at least STARTUP within 6 hours. ACTION 5 - Be in STARTUP with the main steam line isolation valves closed within 6 hours or in at least HOT SHUTDOWN within 12 hours. ACTION 6 - Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure to less than the automatic bypass setpoint within 2 hours.

ACTION 7 -

Verify all insertable control rods to be inserted within one hour. ACTION 8 - Lock the reactor mode switch in the Shutdown position within one hour. l ACTION 9 - Suspend all operations involving CORE ALTERATIONS *, and insert all insertable control rods and lock the reactor mode switch in the SHUTDOWN position within one hour.

 "Except replacement of LPRM strings provided SRM instrumentation is OPERABLE per Speci.fication 3.9.2.

O HOPE CREEK 3/4 3-4

i 9 TABLE 3.3.1-1 (Continued) REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter. i (b) This function shall be automatically bypassed when the reactor mode switch ! is in the Run position. (c) Unless adequate shutdown margin has been demonstrated per Specifica-~ tion 3.1.1, the " shorting links" shall be removed from the RPS circuitry prior to and during the time any control rod is withdrawn *. 4 (d) The non-coincident NMS reactor trip function logic is such that all channels go to both trip systems. Therefore, when the " shorting links" are removed, the Minimum OPERABLE Channels Per the Trip System are 4 APRMS, 6 IRMS and 2 SRMS.

     -(e) An APRM channel is inoperable if there are less than 2 LPRM inputs per level or less than 14 LPRM inputs to an APRM channel.

() (f) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1. (g) This function shall be automatically bypassed when the reactor mode switch is not in the Run position. (h) This function is not required to be OPERABLE when PRIMARY CONTAINMENT . INTEGRITY is not required. j (i) With any control rod withdrawn. Not applicable to control rods removed

per Specification 3.9.10.1 or 3.9.10.2.

l l (j) This function shall be automatically bypassed when turbine first stage pressure is < 153.3 psig** equivalent to THERMAL POWER less than 30% of RATED THERMAL POWER. To allow for instrument accuracy, calibration, and ! drift, a setpoint of < 132.4 psig** is used. (k) Also actuates the E0C-RPT system. t l l l l

        *Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.                                                                               '

l

      ** Initial setpoint.      Final setpoint to be determined during the startup test program.

HOPE CREEK 3/4 3-5

                                                   - - . , . , . - , , , ~ , - - - , - - - . - - , , , , , . , - - - , - - - - - - - . - - - , - - - - , - , - - - -

TABLE 3.3.1-2 REACTOR PROTECTION SYSTEM RESPONSE' TIMES 9 P RESPONSE TIMF. FUNCTIONAL UNIT (Seconds)

1. Intermediate Range Monitors:

a. Neutron Flux - High NA

b. Inoperative NA

2. Average Power Range Monitor *:

a. Neutron Flux - Upscale, Setdown NA

b. Flow Biased Simulated Thermal Power - Upscale < 0.09**

c. Fixed Neutron Flux - Upscale ?0.09

d. Inoperative NA

e. Downscale NA R 3. Reactor Vessel Steam Dome Pressure - High < 0.55

4. Reactor Vessel Water Level - Low, level 3 7 1.05 Y 5. Main Steam Line Isolation Valve - Closure 7 0.06
6. Main Steam Line Radiation - High, High RA

7. Drywell Pressure - High NA

8. Scram Discharge Volume Water Level - High NA

a. Float Switch NA

b. Level Transmitter / Trip Unit NA

9. Turbine Stop Valve - Closure -< 0.06

10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low < 0.08#

11. Reactor Mode Switch Shutdown Position RA

12. Manual Scram NA

Neutron detectors are exempt from respense time testing. Response time shall be measured from the detector output or from the input of the first electronic component in the channel.

  **Not including simulated thermal power time constant, 6 1 0.6 seconds.
   # Measured from start of turbine control valve fast closure.

O O O

                                                                                                                          'h TABLE 4.3.1.1-1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS O                                                         CHANNEL                               OPERATIONAL A

CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UNIT CHECK TEST CALIBRATION (a)

. SURVEILLANCE REQUIRED

1. Intermediate Range Monitors:
a. Neutron Flux - High S/UID) S

                                                       ,   S/U(c) ,W        R                     2 S         W                 R                     3, 4, 5 i

b. Inoperative NA W NA 2,3,4,5 l 2. Average Power Range Monitor (I):

l a. Neutron Flux - S/U(b) 3, 3fg(c) ,W SA 2 , Upscale, Setdown S W SA 3,4,5 }.

b. Flow Biased Simulated j

R Thermal Power - Upscale 5,D 59) S/U(c),y g(d)(e) SA,R(h)

                                                                                     ,            y l  Y

c. Fixed Neutron Flux -

i Upscale S S/U(c) ,y g(d) , SA 1 3

d. Inoperative NA W NA 1,2,3,4,5 g e. Downscale S W SA 1

3. Reactor Vessel Steam Dome Pressure - High S M R 1, 2

4. Reactor Vessel Water Level -

Low, Lev.el 3 S M R 1, 2

5. Main Steam Line Isolation Valve - Closure NA M R 1

6. Main Steam Line Radiation -

High, High S M R 1, 2(I)

7. Drywell Pressure - High S M R .1, 2

]

TABLE 4.3.1.1-1 (Ccntinued) 5 REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS m" OPERATIONAL CHANNEL n g CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH g FUNCTIONAL UNIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

8. Scram Discharge Volume Water Level - High

a. Float Switch NA M R 1, 2, 5 fI)

b. Level Transmitter / Trip Unit S M R 1,2,5j) g

9. Turbine Stop Valve - Closure NA M R I

10. Turbine Control Valve Fast Closure Valve Trip System 011 Pressure - Low NA M R 1

11. Reactor Mode Switch Shutdown Position NA R NA 1,2,3,4,5 R

12. Manual Scram NA M NA 1,2,3,4,5

[ (a) Neutron detectors may be excluded from CHANNEL CALIBRATION. (b) The IRM and SRM channels shall be determined to overlap for at least decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to overlap for at least % decades during each controlled shutdown, if not performed within the' previous 7 days. (c) Within 24 hours prior'to startup, if not performed within the previous 7 days. (d) This calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER > 25% of RATED THERMAL POWER. Adjust the APRM channel if the absolute difference is greater tiian 2% of RATED THERMAL POWER. Any APRM channel gain adjustment made in compliance with Specification 3.2.2 shall not be includeo in determining the absolute difference. (e) This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a calibrated flow signal. (f) The LPRMs shall be calibrated at least once per 1000 effective full power hours (EFPH) using the TIP system. (g) Verify measured core flow (total ccre flow) to be greater than or equal to established core flow at the existing recirculation loop flow (APRM % flow). (h) This calibration shall consist of verifying the 6 i 0.6 second simulated thermal power time constant. (i) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1. (j) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. O - - - - O O

i INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolatior. actuation instrumentation channels shown in Table 3.3.2-1 ) shall be OPERABLE with their trip setpoints set consistent with the values shown 1 in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE ! TIME as shown in Table 3.3.2-3. l APPLICABILITY: As shown in Table 3.3.2-1. ACTION:

a. With an isolation actuation instrumentation channel trip setpoint l less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel: is restored to OPERA 8LE status with its trip setpoint adjusted

! consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system,

! place the inoperable channel (s) and/or that trip system in the tripped condition

within one hour. The provisions of Specification 3.0.4

are not applicable. f c. With the number of OPERABLE channels less than required by the Minimum l ' OPERABLE Channels per Trip System requirement for both trip systems, I place at least one trip system ** in the tripped condition within one l hour and take the ACTION required by Table 3.3.2-1. ; i i

     *An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur.        In these cases, the inoperable channel shall be restored to OPERABLE status within 2 hours or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.
    **The trip system need not be placed in the tripped condition if this would cause the Trip Function to occur. When a trip system can be placed in the tripped candition witoout causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both i       systems have the same number of inoperable channels, place either trip system i       in the tripped condition.

I i HOPE CREEK 3/4 3-9 i

INSTRUMENTATION SURVEILLANCE REQUIREMENTS O 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL. CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1. 4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months, where N is the total number of redundant channels in a specific isolation trip system. O } O HOPE CREEK 3/4 3-10

TABLE 3.3.2-1 i g A ISOLATION ACTUATION INSTRUMENTATION n A VALVE ACTUA-R TION GROUPS MINIMUM APPLICABLE OPERATEkdgY OPERABLE CHANNE OPERATIONAL TRIP FUNCTION SIGNAL PERTRIPSYSTEMg) CONDITION ACTION

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low Low, Level 2 1,2,8,9, 2 1,2,3 20 12, 13, 14, 15, 17, 18

2) Low Low Low, Level 1 10, 11, 15, 16 2 1,2,3 20

b. Drywell Pressure - High 1, 8, 9, 10, 2 1,2,3 20 11, 12, 13, w 14, 15, 16, j } 17, 18 Y c. Reactor Building Exhaust 1, 8, 9, 12 Z Radiation - High 13, 14, 15, 3 1,2,3 28 17, 18

d. Manual Initiation 1, 8, 9, 10 1 1,2,3 24

11, 12, 13, 14, 15, 16, 17, 18

 !       2. SECONDARY CONTAINMENT ISOLATION i               a. Reactor Vessel Water Level -

l Low Low, level 2 19(c) 2 1, 2, 3 and

26

b. Drywell Pressure - High 19(c) 2 1,2,3 26

c. Refueling Floor Exhaust Radiation - High 19(c) 3 1, 2, 3 and

29

 .             d. Reactor Building Exhaust
 !                  Radiation - High                                    19(c)          3           1, 2, 3 and

28

e. Manual Initiation 19(C) 1 1, 2, 3 and

26

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION

k VALVE ACTUA-p TIO4 GROUPS MINIMUM APPLICABLE OPERABLE CHANNE OPERATIONAL TRIP FUNCTION OPERATEkdgY SIGNAL PERTRIPSYSTEM(g) CON 0ITION ACTION

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - 1 2 1,2,3 21 Low Low Low, Level 1

b. Main Steam Line Radiation - 1, 2(b) 2 1,2,3 21 i High, High

c. Main Steam Line Pressure - 1 2 1 22 Low

d. Main Steam Line Flow - High 1 2/line 1,2,3 20

 $         e. Condenser Vacuum - Low                                                                  1                      2          1, 2**, 3**                                                     21 y         f. Main Steam Line Tunnel                                                                  1         2/line                  1,2,3                                                           21 i g              Temperature - High l           g. Manual Initiation                                                                 1, 2, 17                     2          1,2,3                                                           25

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High 7 1/ Valve (*) 1, 2, 3 23 l

b. RWCU a Flow - High, Timer 7 1/ Valvef ') 1, 2, 3 23

c. RWCU Area Temperature - High 7 6/ Valve (*) 1, 2, 3 23 ,

d. RWCU Area Ventilation a 7 6/ Valve (*) 1, 2, 3 23 Temperature-High

e. SLC5 Initiation 7(#) 1/ ValveI *) 1, 2, 5# 23

f. Reactor Vessel Water 7 2/ Valve (*) 1, 2, 3 23 Level - Low Low, Level 2

g. Manual Initiation 7 1/ Valve (*) 1, 2, 3 25 O O O

O

TABLE 3.3.2-1 (Continued) i 5

A ISOLATION ACTUATION INSTRUMENTATION

;        n

R VALVE ACTUA-W TION GROUPS MINIMUM APPLICABLE i OPERABLE CHANNE OPERATIONAL TRIP FUNCTION OPERATEkdgY SIGNAL PERTRIPSYSTEM[g) CONDITION ACTION

) 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION 1 a. RCIC Steam Line A Pressure 6 1/ Valve (*) 1, 2, 3 23 i (Flow) - High 1

b. RCIC Steam Line A Pressure 6 1/ Valve (') 1, 2, 3 23 l

(Flow) - High, Timer

c. RCIC Steam Supply 6 2/ Valve (') 1, 2, 3 23

) w Pressure - Low

d. RCIC Turbine Exhaust 6 2/ Valve (') 1, 2, 3 23 1

4 Diaphragm Pressure - High i w

e. RCIC Pump Room 6 1/ Valve (*) 1, 2, 3 23

!, Temperature - High

f. RCIC Pump Room Ventilation Ducts 6 1/ Valve (*) 1, 2, 3 23 A Temperature - High

g. RCIC Pipe Routing Area 6 1/ Valve (*) 1, 2, 3 23 Temperature - High

h. RCIC Torus Compartment 6 3/ Valve (') 1, 2, 3 23 Temperature-High

i. Drywell Pressure - High f9) 6 2/ Valvef ') 1, 2, 3 23

j. Manual Initiation 6(h) 1/RCIC System 1, 2, 3 25 I

TABLE 3.3.2-1 (Continued) 5

 ;g                                         ISOLATION ACTUATION INSTRUMENTATION l k                                             VALVE ACTUA-f p                                             TION GROUPS         MINIMUM        APPLICABLE OPERABLE CHANNE     OPERATIONAL TRIP FUNCTION                              OPERATEkdgY SIGNAL         PERTRIPSYSTEM(g) CONDITION     ACTION

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line A Pressure 5 1/ ValveI *) 1, 2, 3 23 (Flow) - High

b. HPCI Steam Line A Pressure 5 1/ Valvef ') 1, 2, 3 23 (Flow) - High, Timer

c. HPCI Steam Supply Pressure-Low 5 2/ Valve (') 1, 2, 3 23 R d. tiPCI Turbine Exhaust Diaphragm 5 2/ Valvef ') 1, 2, 3 23

Pressure - High w

h e. HPCI Pump Room 5 1/ Valve (*) 1, 2, 3 23 Temperature - High

f. HPCI Pump Room Ventilation 5 1/ Valve (') 1, 2, 3 23 Ducts A Temperature - High

g. HPCI Pipe Routing Area 5 1/ Valve (') 1, 2, 3 23 Temperature - High

h. HPCI Torus Compartment 5 3/ ValveI *) 1, 2, 3 23 Temperature - High

i. Drywell Pressure - High(9) 5 2/ Valve (*) 1, 2, 3 23 II)

j. Manual Initiation -

S 1/HPCI system 1, 2, 3 25 O O O

I 1 i TABLE 3.3.2-1 (Continued)

5 l

p; ISOLATION ACTUATION INSTRUMENTATION ! n M' VALVE ACTUA-l 92 TION GROUPS MINIMUM APPLICABLE l OPERABLE CHANNE OPERATIONAL TRIP FUNCTION OPERATED SIGNAL (g} PER TRIP SYSTEM (g) CONDITION ACTION l i l 7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level - Low, Level 3 3 2/ Valve (') 1, 2, 3 27 i b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 3 2/ Valve (') 1, 2, 3 27 l

l c. Manual Initiation 3 1/ Valve (') 1, 2, 3 25 j ! Y ! M l 1 i l I l } l 1

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION ACTION ACTION 20 - Be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours. ACTION 21 - Be in at least STARTUP with the associated isolation valves closed within 6 hours or be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours. ACTION 22 - Be in at least STARTUP within 6 hours. ACTION 23 - Close the affected system isolation valves within one hour and declare the affected system inoperable. ACTION 24 - Restore the manual initiation function to OPERABLE status within 48 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. ACTION 25 - Restore the manual initiation function to OPERABLE status within 8 hours or close the affected system isolation valves within the next hour and declare the affected system inoperable. ACTION 26 - Establish SECONDARY CONTAINMENT INTEGRITY with the Filtration, Recirculation and Ventilation System (FRVS) operating within one hour. ACTION 27 - Lock the affected system isolation valves closed within one hour and declare the affected system inoperable. ACTION 28 - Place the inoperable channel in the tripped condition or close the affected system isolation valves within one hour and declare the affected system inoperable. ACTION 29 - Place the inoperable channel in the tripped condition nr establish SECONDARY CONTAINMENT INTEGRITY with the Filtration, Recirculation, and Ventilation System (FRVS) operating within one hour. NOTES

When handling irradiated fuel in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

   **    When any turbine stop valve is greater than 90% open and/or when the key-I         locked byptss switch is in the Norm position.

! # Refer to Specification 3.1.5 for applicability. l (a) A channel may be placed in an inoperable status for up to 2 hours for re-quired surveillance without placing the trip system in the tripped condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter. (b) Also trips and isolates the mechanical vacuum pumps. (c) Also starts the Filtration, Recirculation and Ventilation System (FRVS). (d) Refer to Table 3.3.2-1 table notation for the listing of which valves in an l actuation group are closed by a particular isolation signal. Refer to g Tables 3.6.3-1 and 3.6.5.2-1 for the listings of all valves within an actuation group. (e) Sensors arranged per valve group, not per trip system. (f) Closes only RWCU system isolation valve (s) HV-F001 and HV-F004. i (g) Requires system steam supply pressure-low coincident with drywell pressure-high to close turbine exhaust vacuura breaker valves.

(h) Manual isolation closes HV-F008 only, and only following manual or automatic j initiation of the RCIC system.

l (i) Manual isolation closes HV-F003 and HV-F042 only, and only following manual or automatic initiation of the HPCI system. HOPE CREEK 3/4 3-16

O O O TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION m TABLE NOTATION This table notatfort identifies which valves, in an actuation group, are closed by a particular trip signal. If all valves in the group are closed by the trip signal, only the valve group number will be listed. If only certain valves in the group are closed by the trip signal, the valve group number will be listed followed by, in parentheses, a listing of which valves are closed by the trip signal. TRIP FUNCTION VALVES CLOSED BY SIGNAL

1. PRIMARY CONTAINMENT ISOLATION; a. Reactor Vessel Water Level -; 1) Low Low, Level 2 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 2, 8, 9, 12,
13, 14, 15 (HV-5154, HV-5155), 17, 18 l 2) Low Low Low, Level 1 10, 11, 15(HV-5126 A&B, HV-5152 A&B, HV-5147, HV-5148, '

{ HV-5162), 16 f ! Y b. Drywell Pressure - High 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 8, 9, 10, I

O 11, 12, 13, 14, 15, 16, 17, 18: c. Reactor Building Exhaust Radiation - High 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 8, 9, 12, l 13, 14, 15, 17 (HV-5161), 18; d. Hanual Initiation 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 8, 9, 10, 11, 12, 13, 14, 15, 16, 17 (HV-5161), 18 3 2. SECONDARY CONTAINMENT ISOLATION; a. Reactor Vessel Water Level -

Low Low, Level 2 19

b. Drywell Pressure - High 19

c. Refueling Floor Exhaust Radiation - High 19 l

d. Reactor Building Exhaust Radiation - High 19

e. Manual Initiation 19 i

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION p, TABLE NOTATION m E TRIP FUNCTION VALVES CLOSED BY SIGNAL

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - 1 (HV-F022A, B, C & D, HV-F028A, B, C & D, HV-F067A, B, Low Low Low, Level 1 C & D, HV-F016, HV-F019)

b. Main Steam Line Radiation - High, High 1 (as above), 2

c. Main Steam Line Presure - Low 1 (as above)

d. Main Steam Line Flow - High 1 (as above)

R

e. Condenser Vacuum - Low 1 (as above) w h f. Main Steam Line Tunnel 1 (as above)

Temperature - High

g. Manual Initiation 1 (as above), 2, 17 (SV-J004A-1, 2, 3, 4 & 5)

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU A Flow - High 7

b. RWCU A Flow - High, Timer 7

c. RWCU Area Temperature - High 7 O O O

w TABLE 3.3.2-1 (Continued) 5 ?; ISOLATION ACTUATION INSTRUMENTATION h! TABLE NOTATION W TRIP FUNCTION VALVES CLOSED BY SIGNAL

d. RWCU Area Ventilation 7 A Temperature - High

e. SLCS Initiation 7

f. Reactor Vessel Water Level - 7 Low Low, Level 2

g. Manual Initiation 7

$$ 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line A Pressure (Flow) - High 6 (HV-F007, HV-F076, HV-F008)

b. RCIC Steam Line A Pressure (Flow) - High, Timer 6 (HV-F007, HV-F076, HV-F008)

c. RCIC Steam Supply Pressure - Low 6

d. RCIC Turbine Exhaust 6 (HV-F007, HV-F076, HV-F008)

Diaphragm Pressure - High

e. RCIC Pump Room Temperature - High 6 (HV-F007, HV-F076, HV-F008)

f. RCIC Pump Room Ventilation Ducts 6 (HV-F007, HV-F076, HV-F008)

A Temperature - High

g. RCIC Pipe Routing Area 6 (HV-F007, HV-F076, HV-F008)

Temperature - High

n. RCIC Torus Compartment Temperature - High 6 (HV-F007, HV-F076, HV-F008)

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION O TABLE NOTATION m E VALVES CLOSED BY SIGNAL TRIP FUNCTION Drywell Pressure - High 6 (HV-F062, HV-F084) i.

j. Manual Initiation 6 (HV-F008)

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION HPCI Steam Line A Pressure (Flow) - High 5 (HV-F002, HV-F100, HV-F003, HV-F042) a.

HPCI Steam Line A Pressure (Flow) - High, Timer 5 (HV-F002, HV-F100, HV-F003, HV-F042) b. x HPCI Steam Supply Pressure - Low 5 [. c. 5 (HV-F002, HV-F100, HV-F003, HV-F042) E$ d. HPCI Turbine Exhaust Diaphragm Pressure - High HPCI Pump Room Temperature - High 5 (HV-F002, HV-F100, HV-F003, HV-F042) e. HPCI Pump Room Ventilation Ducts 5 (HV-F002, HV-F100, HV-F003, HV-F042) f. A Temperature - High l HPCI Pipe Routing Area 5 (HV-F002, HV-F100, HV-F003, HV-F042) l g. Temperature - High HPCI Torus Compartment Temperature - High 5 (HV-F002, HV-F100, HV-F003, HV-F042) h. 5 (HV-F075, HV-F079)

i. Drywell Pressure - High 5 (HV-F003, HV-F042)

j. Manual Initiation O 9 9

i i l 4 TABLE 3.3.2-1 (Continued) 5 j A ISOLATION ACTUATION INSTRUMENTATION c. R m TABLE NOTATION n , TRIP FUNCTION VALVES CLOSED BY SIGNAL 1

 !                         7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION 1

j a. Reactor Vessel Water Level 3 (HV-F008, HV-F009, HV-F015A & B, HV-F022, HV-F023) j Low, Level 3

I b. Reactor Vessel (RHR Cut-in 3 (HV-F008, HV-F009, HV-F015A & B, HV-F022, HV-F023) i Permissive) Pressure - High

c. Manual Initiation 3 (HV-F008, HV-F009, Hv' F015A & B, HV-F022, HV-F023)

I w !' 1 w I 4 i 4 L 4 l

    . , . . - . - . , , . . . .       . . ~ . ,,                   .. , , , . - . , . .                . . . , . - . ..         . . . . - _ _ . .           ._.   -

TABLE 3.3.2-2 5 ISOLATION ACTUATION INSTRUMENTATION SETPOINTS A c, ALLOWABLE A TRIP FUNCTION TRIP SETPOINT VALUE E 1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low Low, Level 2 > -38.0 inches * > -45.0 inches

2) Low Low Low, Level 1 5 -129.0 inches

i -136.0 inches

b. Drywell Pressure - High 31.68psig 31.88psig

c. Reactor Building Exhaust Radiation - High 5 1x10 3pCi/cc** $ 1.2x10 3pCi/cc**

d. Manual Initiation NA NA

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

Low Low, Level 2 1 -38.0 inches

1 -45.0 inches

$ b. Drywell Pressure - High $ 1.68 psig 5 1.88 psig y c. Refueling Floor Exhaust y Radiation - High 1 2x10 3p Ci/cc** $ 2.4x10 3p ci/cc**

d. Reactor Building Exhaust Radiation - High 5 1x10 8p Ci/cc** $ 1.2x10 3pCi/cc**

e. Manual Initiation NA NA

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1 -129.0 inches

1 -136.0 inches

b. Main Steam Line $ 3.0 X full power $ 3.6 X full power Radiation - High, High background background

c. Main Steam Line Pressure - Low 1 756.0 psig 1 736.0 psig

d. Main Steam Line Flow - High 5 108.7 psid 5 111.7 psid O O O

) TABLE 3.3.2-2 (Continued) i ISOLATION ACTUATION INSTRUMENTATION SETPOINTS ALLOWABLE i 9 TRIP FUNCTION TRIP SETPOINT VALUE m MAIN STEAM LINE ISOLATION (Continued) l e. Condenser Vacuum - Low 1 8.5 inches Hg vacuus 1 7.6 inches Hg vacuum i f. Main Steam Line Tunnel i Temperature - High 5 160*F $ 172*F .i j g. Manual Initiation NA NA

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High 5 56.3 gpm 5 61.3 gpm

b. RWCU a Flow - High, Timer 45.0 seconds 5 t 5 47.0 seconds 45.0 seconds 5 t 5 47.0 seconds

c. RWCU Area Temperature - High 5 160*F, 140*F or 135"F*** 1 172*F, 152*F or 147*F***

R*

d. RWCU/ Area Ventilation a Temperature - High 5 60*F 5 70*F 4

w

e. SLCS Initiation NA NA

f. Reactor Vessel Water Level -

Low Low, Level 2 > -38.0 inches

1 -45.0 inches

g. Manual Initiation NA NA; 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION; a. RCIC Steam Line a Pressure (Flow) - High 5 609.6" H2 0** < 622.1" H2 0**; b. .RCIC Steam Line a Pressure 3.0 seconds < t < 13.0 seconds 3.0 seconds < t < 13.0 seconds j (Flow) - High, Timer
c. RCIC Steam Supply Pressure - Low 1 64.5 psig 1 56.5 psig I: d. RCIC Turbine Exhaust Diaphragm Pressure - High 5 10.0 psig 5 20.0 psig i

l l

TABLE 3.3.2-2 (Ccntinued) ISOLATION ACTUATION INSTRUMENTATION SETPOINTS z o ALLOWABLE 5 TRIP FUNCTION TRIP SETPOINT VALUE k REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued) S e. RCIC Pump Room Temperature - High 5 160*F $ 172 F

f. RCIC Pump Room Ventilation Duct a Temperature - High 5 70*F $ 80*F

g. RCIC Pipe Routing Area Temperature - High 5 160*F, $ 172*F,

h. - RCIC Torus Compartment Temperature - High 5 128*F, $ 140*F,

i. Drywell Pressure - High 5 1.68 psig 5 1.88 psig

j. Manual Initiation NA~ NA

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

                 $                                        a.                HPCI Steam Line A Pressure                                    5 1025.0 inches H2 0**         $ 1044.5 inches H2 0**

(Flow) - High

b. HPCI Steam Line A Pressure 3.0 seconds 5 t 5 13.0 seconds 3.0 seconds 5 t 5 13.0 seconds l $ (Flow) - High, Timer l

c. HPCI Steam Supply Pressure - Low 2 100.0 psig 1 90.0 psig

d. HPCI Turbine Exhaust Diaphragm Pressure - High 5 10.0 psig~ $ 20.0 psig

e. HPCI Pump Room Temperature - High 5 160*F $ 172 F

f. HPCI Pump Room Ventilation Ducts A Temperature - High 5 70*F $ 80*F

g. HPCI Pipe Routing Area Temperature - High 5 160 F,, $ 172*F,,

h. HPCI Torus Compartment -< 128*F -< 140 F Temperature - High

i. Drywell Pressure High 5 1.68 psig 5 1.88 psig .

Manual Initiation NA NA J. G G e

TABLE 3.3.2-2 (Continued) x ISOLATION ACTUATION INSTRUMENTATION SETPOINTS ALLOWABLE t 2 TRI? FUNCTION TRIP SETPOINT VALUE i

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

Low, Level 3 1 12.5 inches

1 11.0 inches

b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 5 82.0 psig < 102.0 psig

c. Manual Initiation NA NA l "See Bases Figure B 3/4 3-1.

R',

        ** Initial setpoint. Final setpoint to be determined during startup test program.
       ***These setpoints are as follows:

) i' 160*F - RWCU pipe chase room 4402

 , Ut          140 F - RWCU pump room and heat exchanger rooms i              135 F - RWCU pipe chase room 4505 i         #30 minute time delay.

I ##15 minute time delay. l ' 4 4 4 I 1 l l l

TABLE 3.3.2-3 ISOLATION SYSTEM INSTPUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low Low, Level 2 NA

2) Low Low Low, Level 1 NA

b. Drywell Pressure - High NA

c. Reactor Building Exhaust Radiation - High NA

d. Manual Initiation NA

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level-Low Low, Level 2 NA

b. Drywell Pressure - High NA

c. Refueling Floor Exhaust Radiation - -< 4.0 High(b)

d. Reactor Building Exhaust < 4.0 Radiation - High(b)

e. Manual Initiation NA

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - Low Low Low,

                                                                  < 1.0*/< 13 I
                                                                                ,),,

Level 1

b. Main Steam Line Radiation - High, High(a)(b) 7 1.0*/7 13(a),,

)**

7 1.0*/7 13I ),,

c. Main Steam Line Pressure - Low

d. Main Steam Line Flow-High 7 0.5*/7 13I

e. Condenser Vacuum - Low NA

f. Main Steam Line Tunnel Temperature - High NA

g. Manual Initiation NA

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High NA

b. RWCU a Flow - High, Timer NA

c. RWCU Area Temperature - High NA

d. RWCU Area Ventilation a Temperature - High NA

e. SLCS Initiation NA

f. Reactor Vessel Water Level - Low Low, Level 2 NA

g. Manual Initiation NA

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line a Pressure (Flow) - High NA

b. RCIC Steam Line a Pressure (Flow) - High, Timer NA

c. RCIC Steam Supply Pressure - Low NA

d. RCIC Turbine Exhaust Diaphragm Pressure - High NA O

HOPE CREEK 3/4 3-26

l l TABLE 3.3.2-3 (Continued) ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)# REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

e. RCIC Pump Room Temperature - High NA; f. RCIC Pump Room Ventilation Ducts a Temperature
- High NA: g. RCIC Pipe Routing Area Temperature - High NA; h. RCIC Torus Compartment Temperature - High NA i; 1. Drywell Pressure - High NA; j. Manual Initiation NA; 6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION; a. HPCI Steam Line a Pressure (Flow) - High NA; b. HPCI Steam Line a Pressure (Flow) - High, Timer NA I

I

c. HPCI Steam Supply Pressure - Low NA

d. HPCI Turbine Exhaust Diaphragm Pressure - High NA

,         e.           HPCI Pump Room Temperature - High                  NA 1

f. HPCI Pump Room Ventilation Ducts
a Temperature - High NA l g. HPCI Pipe Routing Area Temperature - High NA j h. HPCI Torus Compartment Temperature - High NA: 1. Drywell Pressure - High NA

, J. Manual Initiation NA

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION; 3. Reactor Vessel Water Level - Low, Level 3 NA
b. Reactor Vessel (RHR Cut-in Permissive)

! Pressure - High NA i c. Manual Initiation NA

(a) Isolation system instrumentation response time specified includes diesel j generator starting and sequence loading delays. .

i (b) Radiation detectors are exempt from response time testing. Response time ! shall be measured from detector output or the input of the first electronic component in the channel. ,

Isolation system instrumentation response time for MSIVs only. No diesel generator delays assumed for MSIVs.

      ** Isolation system instrumentation response time for associated valves except MSIVs.
       # Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time shown in Table 3.6.3-1 and 3.6.5.2-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.

HOPE CREEK 3/4 3-27

TABLE 4.3.2.1-1 5 A ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS k CHANNEL OPERATIONAL W CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

1) Low Low, Level 2 S M R 1,2,3

2) Low Low Low, Level 1 S M R 1,2,3

b. Drywell Pressure - High S M R 1,2,3

c. Reactor Building Exhaust Radiation - High S M g) R 1,2,3

d. Manual Initiation NA M NA 1,2,3

2. SECONDARY CONTAINMENT ISOLATION

 $        a. Reactor Vessel Water Level -

m Low Low, Level 2 S M R 1, 2, 3 and

4 b. Drywell Pressure - High S M R 1,2,3 m c. Refueling Floor Exhaust Radiation - High S M R 1, 2, 3 and *

d. Reactor Building Exhaust Radiation - High S R 1, 2, 3 and

i

e. Manual Initiation NA M(3)

M NA 1, 2, 3 and

l

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level -

Low Low Low, Level 1 S M R 1,2,3

b. Main Steam Line

! Radiation - High, High S M R 1,2,3

c. Main Steam Line Pressure - Low S M R 1

d. Main Steam Line Flow - High 5 M R 1, 2, 3 O O O

O O O i TABLE 4.3.2.1-1 (Continued) k ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS [ CHANNEL OPERATIONAL g CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH i p TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED MAIN STEAM LINE ISOLATION (Continued)

e. Condenser Vacuum - Low S M R 1, 2**, 3**

I

f. Main Steam Line Tunnel i Temperature - High NA M R 1,2,3

g. Manual Initiation NA M(a) NA 1,2,3

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High S M R 1,2,3

b. RWCU a Flow - High, Timer NA M R 1,2,3 l $ c. RWCU Area Temperature - High NA M R 1,2,3 i

y d. RWCU Area Ventilation a y Temperature - High NA M R 1,2,3

e. SLCS Initiation #

l NA M(b) NA 1, 2, 5 l f. Reactor Vessel Water l Level - Low Low, Level 2 S M R 1, 2, 3

g. Manual Initiation NA M(a) NA 1,2,3

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION 1

a. RCIC Steam Line a Pressure (Flow) - High NA M R 1,2,3

, b. RCIC Steam Line A Pressure (Flow) - High, Timer NA M R 1,2,3 I

c. RCIC Steam Supply Pressure -

Low NA M R 1,2,3 l ! d. RCIC Turbine Exhaust Diaphragm i Pressure - High NA M R 1,2,3 l l i 1

TABLE 4.3.2.1-1 (Continued) k ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL [ CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH M p TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued)

e. RCIC Pump Room Temperature - High NA M R 1,2,3

f. RCIC Pump Room Ventilation

          - Ducts A Temperature - High         NA            M              R                 1,2,3

g. RCIC Pipe Routing Area Temperature - High NA M R 1,2,3

h. RCIC Torus Compartment Temperature -High NA M R 1,2,3 y i. Drywell Pressure - High 5 M R 1,2,3

j. Manual Initiation NA R NA 1,2,3

$ 6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line A Pressure (Flow) - High NA M R 1,2,3

b. HPCI Steam Line A Pressure (Flow) - High, Timer NA M R 1, 2, 3

c. HPCI Steam Supply Pressure - Low NA M R 1, 2, 3

d. HPCI Turbine Exhaust Diaphragm Pressure - High NA M R 1, 2, 3

e. HPCI Pump Room Temperature - High NA M R 1, 2, 3

f. HPCI Pump Room Ventilation Ducts A Temperature - High NA M R 1, 2, 3

g. HPCI Pipe Routing Area Temperature - High NA M R 1,2,3 9 9 e

( \v ). TABLE 4.3 ?.1-1 (Continued) j 5 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS I E CHANNEL OPERATIONAL Q CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH y TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION (Continued)

h. HPCI Torus Compartment

! Temperature - High NA M R 1,2,3

i. Drywell Pressure - High NA M R 1,2,3; j. Manual Initiation NA R NA 1,2,3; 7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION
a. Reactor Vessel Water Level -

l Low, Level 3 S M R 1,2,3

5:' b. Reactor Vessel (RHR Cut-in J ^ Permissive) Pressure - High NA M R 1,2,3
$ c. Manual Initiation NA M(a) NA 1,2,3

) i

" When handling irradiated fuel in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

                 ** When any turbine stop valve is greater than 90% open and/or when the key-locked bypass switch is l                     in the Norm position.
                    # Refer to Specification 3.1.5 for applicability.

(a) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circuitry I associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as part

!                     of circuitry required to be tested for automatic system isolation.

(b) Each train or logic channel shall be tested at least every other 31 days. i

INSTRUMENTATION 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3 The emergency core cooling system (ECCS) actuation instrumentation channels shown in Table 3.3.3-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.3-2 and with EMERGENCY CORE COOLING SYSTEM RESPONSE TIME as shown in Table 3.3.3-3. APPLICABILITY: As shown in Table 3.3.3-1. ACTION:

a. With an.ECCS actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.3-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b. With one or more ECCS actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.3.1 Each ECCS actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.3.1-1. 4.3.3.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 4.3.3.3 The ECCS RESPONSE TIME of each ECCS trip function shown in Table 3.3.3-3 shall be demonstrated to be within the limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific ECCS trip system. O HOPE CREEK 3/4 3-32

p s \ s (m -v) TABLE 3.3.3-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION c MINIMUM OPERABLE CHANNELS PER APPLICABLE 4 2 TRIP OPERATIONAL 1

3 TRIP FUNCTION FUNCTION (a) CONDITIONS ACTION j 1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level - Low Low Low, level 1 1, 2, 3, 4*, 5* 30

b. Drywell Pressure - High 2((b)(e) 2 b)(e) 1, 2, 3 30

c. Reactor Vessel Pressure - Low (Permissive) 4/ division (f) 1,2,3 31 4*, 5* 32

d. Core Spray Pump Discharge Flow - Low (Bypass) 1/ subsystem 1, 2, 3, 4* , 5* 37

 !                                     e. Core Spray Pump Start Time Delay - Normal Power                1/ subsystem    1, 2, 3, 4*, 5*      31

f. Core Spray Pump Start Time Delay - Emergency Power 1/ subsystem 1, 2, 3, 4*, 5* 31

g. Manual Initiation 1/ division ID)(9) 1, 2, 3, 4* , 5* 33

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Reactor Vessel Water Level - Low Low Low, Level 1 2/ valve 1, 2, 3, 4*, 5* 30 l w b. Drywell Pressure - High 2/ valve 1,2,3 30

, d. c. Reactor Vessel Pressure - Low (Permissive) 1/ valve 1, 2, 3 31 4*, 5* 32 l l d. LPCI Pump Discharge Flow - Low (Bypass) 1/ pump (g) 1, 2, 3, 4*, 5* 37 i e. LPCI Pump Start Time Delay - Normal Power 1/ pump 1, 2, 3, 4* , 5* 31

f. Manual Initiation 1/ subsystem 1, 2, 3, 4*, 5* 33 i 3. HIGH PRESSURE COOLANT INJECTION SYSTEM I

a. Reactor Vessel Water Level - Low Low Level 2 4 1,2,3 34 j b. Drywell Pressure - High 1, 2, 3 34

c. Condensate Storage Tank Level - Low 4(c) 1, 2, 3 35

d. Suppression Pool Water Level - High 2(c) 2 1, 2, 3 35

e. Reactor Vessel Water Level - High, Level 8 4(d) 1,2,3 31

f. HPCI Pump Discharge Flow - Low (Bypass) 1 1,2,3 37 i g. Manual Initiation 1/ system 1, 2, 3 33

4. AUTOMATIC DEPRESSURIZATION SYSTEMr#

a. Reactor Vessel Water Level - Low Low Low, Level 1 4 1,2,3 30

,                                       b. Drywell Pressure - High                                       4               1,2,3                30 4

c. ADS Timer 2 1,2,3 31

d. Core Spray Pump Discharge Pressure - High (Permissive) 1/ pump 1,2,3 31

TABLE 3.3.3-1 (Cont'd) EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION r MINIMUM OPERABLE fE CHANNELS PER APPLICABLE TRIP OPERATIONAL 9 TRIP FUNCTION FUNCTION (a) CONDITIONS ACTION h 4. AUTOMATIC DEPRESSURIZATION SYSTEM

e. RHR LPCI Mode Pump Discharge Pressure - High (Permissive) 2/ pump 1,2,3 31

f. Reactor Vessel Water Level - Low, Level 3 (Permissive) 2 1,2,3 31

g. ADS Drywell Pressure Bypass Timer 4 1,2,3 31

h. ADS Manual Inhibit Switch 2 1,2,3 31

i. Manual Initiation 4 1,2,3 33 MINIMUM APPLICABLE TOTAL NO CHANNELS CHANNELS OF CHANNELS (h) TO TRIP (h) OPERABLE CONDITIONS (h) 0?ERATIONAL ACTION

5. LOSS OF POWER

1. 4.16 kv Emergency Bus Under-R voltage (Loss of Voltage) 4/ bus 2/ bus 3/ bus 1, 2, 3, 4**, 5** 36

4.16 kv Emergency Bus Under-2.

Y voltage (Degraded Voltage) 2/ source / 2/ source / 2/ source / 1. 2, 3, 4**, 5** 36

  %                                                           bus           bus           bus (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) Also actuates the associated emergency diesel generators. (c) One trip system. Provides signal to HPCI pump suction valve only. (d) Provides a signal to trip HPCI pump turbine only. (e) In divisions 1 and 2, the two sensors are associated with each pump and valve combination. In divisions 3 and 4, the two sensors are associated with each pump only. (f) Division 1 and 2 only. (g) In divisions 1 and 2, manual initiation is associated with each pump and valve combination; in divisions 3 and 4, manual initiation is associated with each pump only. (h) Each voltage detector is a channel. (i) Start time delay is applicable to LPCI Pump C and D only.

When the system is required to be OPERABLE per Specification 3.5.2.

     **    Required when ESF equipment is required to be OPERABLE.
     #     Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.
     ##    Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

O O O

f TABLE 3.3.3-1 (Continued) i d EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement: I a. With one channel inoperable, place the inoperable channel 4 in the tripped condition within one hour

or declare the associated system inoperable,

b. With more than one channel inoperable, declare the l associated system inoperable, i

ACTION 31 - With the number of OPERABLE channels less than required by the i Minimum OPERABLE Channels per Trip Function requirement, declare j the associated ECCS inoperable. ACTION 32 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place the inoperable channel in the tripped condition within one hour. ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore

the inoperable channel to OPERABLE status within 8 hours or

! declare the associated ECCS inoperable. ! 5 ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip runction requirement: l'

a. For one channel inoperable, place the inoperable channel in the tripped condition within 1 hour

or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI

. system inoperable. ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at

least one inoperable channel in the tripped condition within one hour

or declare the HPCI system inoperable.

4 ACTION 36 - With the number of OPERABLE channels one less than the Total Number of Channels, place the inoperable channel in the tripped ' condition within 1 hour;* operation may then continue until performance of the next required CHANNEL FUNCTIONAL TEST. ACITON 37 - With the number of OPERABLE channels less than required by the > Minimum OPERABLE channels per Trip Function requirement, open the minimum flow bypass valve within one hour. Restore the inoperable channel to OPERABLE status within 7 days or declare the associated ECCS inoperable.

              "The provisions of Specification 3.0.4 are not applicable.

i HOPE CREEK 3/4 3-35 l

TABLE 3.3.3-2 5 A EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS n A ALLOWABLE TRIP SETPOINT VALUE Q TRIP FUNCTION

1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level - Low Low Low, Level 1 >-129 inches * >-136 inches

b. Drywell Pressure - High 51.68psig 51.88psig

c. Reactor Vessel Pressure - Low 461 psig < 481 psig and

                                                                                                                                                                                                  > 441 psig

d. Core Spray Pump Discharge Flow - Low (Bypass) 1 775 gpm > 650 gpm

e. Core Spray Pump Start Time Delay - Normal Power 10 seconds > 9 seconds and

                                                                                                                                                                                                  < 11 seconds

f. Core Spray Pump Start Time Delay - Emergency Power 6 seconds 55secondsand

                                                                                                                                                                                                  < 7 seconds w                                                                                          g. Manual Initiation                                     NA                   5A D

w 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM di

a. Reactor Vessel Water Level - Low Low Low, Level 1 >-129 inches * >-136 inches

b. Drywell Pressure - High 51.68psig 51.88psig

c. Reactor Vessel Pressure - Low (Permissive) 450 psig < 460 psig and

                                                                                                                                                                                                  > 440 psig

d. LPCI Pump Discharge Flow - Low (Bypass) 1 1250 gpm > 1100 gpm

e. LPCI Pump Start Time Delay - Normal Power 5 seconds > 4 seconds and

                                                                                                                                                                                                  < 6 seconds

f. Manual Initiation NA NA

3. HIGH PRESSURE COOLANT INJECTION SYSTEM

a. Reactc,r Vessel Water Level - (Low Low, Level 2) >-38 inches * >-45 inches

b. Drywell Pressure - High 51.68psig 31.88psig

c. Condensate Storage Tank Level - Low 1 22,558 gallons 1 19,174 gallons

d. Suppression Pool Water Level - High < 78.5 inches < 80.3 inches

;                                                                                                                 e. Reactor Vessel Water Level - High, Level 8           < 54 inches           < 61 inches

f. HPCI Pump Discharge Flow - Low (Bypass) {550gpm 5500gpm i g. Manual Initiation NA NA l

l e o e

v TABLE 3.3.3-2 (Continued) E g EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS g ALLOWABLE g TRIP FUNCTION TRIP SETPOINT VALUE

4. AUTOMATIC DEPRESSURIZATION SYSTEM ,

a. Reactor Water Level - Low Low Low, Level 1 >-129 inches * >-136 inches 1 b. Drywell Pressure - High 31.68psig 31.88psig i c. ADS Timer < 105 seconds < 117 seconds

! d. Core Spray Pump Discharge Pressure - High I45 psig 5155psig

                                                                                                      > 125 psig

{ e. RHR LPCI Mode Pump Discharge Pressure-High 125 psig < 135 psig j

                                                                                                      > 115 psig

f. Reactor V:ssel Water Level-Low, Level 3 > 12.5 inches i 11.0 inches

g. ADS Drywell Pressure Bypass Timer < 5.0 minutes 55.5 minutes

,                   h. ADS Manual Inhibit Switch                             RA                   NA l                    i. Manual Initiation                                     MA                   NA
       ,   5.       LOSS OF POWER

! s j [ a. 4.16 kv Emergency Bus Undervoltage a. 4.16 kv Basis - (Loss of Voltage) 2975 1 30 volts 2975 1 63 volts { u b. 120 v Basis - J 85 1 0.85 volts 85 1.8 volts l b. 4.16 kv Emergency Bus Undervoltage a. 4.16 kv Basis - (Degraded Voltage)** > 3857 volts -> 3857 volts

b. 120 v Basis -

                                                                                > 110.2 volts         > 109.0 volts

c. 70 sec 9 70 + 15, - 5 sec 109.0 volts @ 109.0 volts i " See Bases Figure B 3/4 3-1.

! ** This is an inverse time delay voltage relay. The voltages shown are the maximum that will not l result in a trip. Some voltage conditions will result in decreased trip times. I I

TABLE 3.3.3-3 EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES ECCS RESPONSE TIME (Seconds)

1. CORE SPRAY SYSTEM i 27

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM 5 40

3. AUTOMATIC DEPRESSURIZATION SYSTEM NA

4. HIGH PRESSURE COOLANT INJECTION SYSTEM i 27

5. LOSS OF POWER NA O

O HOPE CREEK 3/4 3-38 )

p

TABLE 4.3.3.1-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS l 8 CHANNEL OPERATIONAL 4

        ;g                                                       CHANNEL      FUNCTIONAL         CHANNEL         CONDITIONS FOR WHICH

] n TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQi1 IRED l h x

1. CORE SPRAY SYSTEM

a. Reactor V6sel Water Level -

Low Low Low, Level 1 5 M R 1, 2, 3, 4*, 5*

b. Drywell Pressure - High S M R 1,2,3

! c. Reactor Vessel Pressure - Low S M R 1, 2, 3, 4* , 5* j d. Core Spray Pump Discharge , Flow - Low (Bypass) S M R 1, 2, 3, 4* , 5* i e. Core Spray Pump Start Time i Delay - Normal Power NA M R 1, 2, 3, 4* , 5* i f. Core Spray Pump Start Time l Delay - Eirergency Power NA M R 1, 2, 3, 4* ; 5* { g. Manual Initiation NA R NA 1, 2, 3, 4*, 5* j w 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM s

a. Reactor Vessel Water Level -

y Low Low Low, Level 1 S M R 1, 2, 3, 4*, 5* g b. Drywell Pressure - High S M R 1,2,3

c. Reactor Vessel Pressure - Low (Permissive) S M R .

1, 2, 3, 4* , 5*

d. LPCI Pump Discharge Flow -

Low (Bypass) S M R 1, 2, 3, 4* , 5*

e. LPCI Pump Start Time Delay -

Normal Power NA M R 1, 2, 3, 4*, 5*

f. Manual Initiation NA R NA 1, 2, 3, 4*, 5*

3. HIGH PRESSURE COOLANT INJECTION SYSTEM

a. Reactor Vessel Water Level -

Low Low, Level 2 S M R 1,2,3 ! b. Drywell Pressure - High S M R 1,2,3 i c. Condensate Storage Tank Level - ! Low S M R 1,2,3

d. Suppression Pool Water Level -

High S M R 1, 2, 3 j e. Reactor Vessel Water Level - i High, Level 8 S H R 1,2,3 ! f. HPCI Pump Discharge Flow - Low (Bypass) S M R 1,2,3 j g. Manual Initiation NA R NA 1,2,3

TABLE 4.3.3.1-1 (Continued) EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 2 CHANNEL OPERATIONAL A ^ CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

4. AUTOMATIC DEPRESSURIZATION SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 5 M R 1,2,3

b. Drywell Pressure - High S M R 1,2,3

c. ADS Timer NA M Q 1,2,3

d. Core Spray Pump Discharge Pressure - High S M R 1,2,3

e. RHR LPCI Mode Pump Discharge Pressure - iligh S M R 1,2,3

f. Reactor Vessel Water Level - Low, R Level 3 S M R 1,2,3

g. ADS Drywell Pressure Bypass Timer NA M 1,2,3 Q

Y h. ADS Manual Inhibit Switch NA R NA 1,2,3 8 i. Manual Initiation NA R NA 1,2,3

5. LOSS OF POWER

a. 4.16 kv Emergency Bus Under-voltage (Loss of Voltage) NA NA R 1, 2, 3, 4**, 5**

b. 4.16 kv Emergency Bus Under-voltage (Degraded Voltage) S M R 1, 2, 3, 4**, 5**

When the system is required to be OPERABLE per Specification 3.5.2.

 **    Required OPERABLE when ESF equipment is required to be OPERABLE.
 #     Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.
 ##    Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

O O O

3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION

!m\

C/ ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2. APPLICABILITY: OPERATIONAL CONDITION 1. ACTION:

a. With an ATWS recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the Minimum OPERA 6LE Channels per Trip System requirement for one or both trip systems, place the inoperable channel (s) in the tripped condition within one hour.

c. With the number of OPERABLE channels two or more less than required p) by the Minimum OPERABLE Channels per Trip System requirement for one trip system, and:

1. If the inoperable channels consist of one reactor vessel water level channel and one reactor vessel pressure channel, place both inoperable channels in the tripped condition within one hour, or if this action will initiate a pump trip, declare the trip system inoperable.

2. If the inoperable channels include two reactor vessel water level channels or two reactor vessel pressure channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours or be in at least STARTUP within the next 6 hours.

e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or be in at least STARTUP within the next 6 hours.

SURVEILLANCE REQUIREMENTS 4.3.4.1.1. Each ATWS recirculation pump trip system instrumentation channel ! shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.4.1-1. l 4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. HOPE CREEK 3/4 3-41

5 g TABLE 3.3.4.1-1 k ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER TRIP FUNCTION TRIP SYSTEM (*)

1. Reactor Vessel Water Level - 2 Low Low, level 2

2. Reactor Vessel Pressure - High 2 R

a T (a) One channel may be placed in an inoperable status for up to 2 hours for required surveillance i provided the other channel is OPERABLE. G G e

I t t 5 i A TABLE 3.3.4.1-2 n '

                "                                                  ATWS RECIRCULATION PUNP TRIP SYSTEN INSTRUENTATION SETPOINTS x

TRIP ALLOWA8LE TRIP FUNCTION SETPOINT VALUE t

1. Reactor Vessel, Water Level - -> -38 inches * -> -45 inches Low Low, Level 2 "

2. Reactor Vessel Pressure - High $ 1071 psig 5 1086 psig i

r I w 1 Y w , t i

                   "See Bases Figure 83/4 3-1.                                                                                                                                                                                          <

[ i f i

TABLE 4.3.4.1-1 ATWS RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E A CHANNEL CHANNEL FUNCTIONAL CHANNEL TRIP FUNCTION CHECK TEST CALIBRATION

1. Reactor Vessel Water *evel - 5 M R Low Low, level 2

2. Reactor Vessel Pressure - High 5 M R R.

2 O O O

1 INSTRUMENTATION END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.2 The end-of-cycle recirculation pump trip (EOC-RPT) system instrumentation channels shown in Table 3.3.4.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.4.2-2 and with the END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME as shown in Table 3.3.4.2-3. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 307,of RATED THERMAL POWER. ACTION:

a. With an end-of-cycle recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the g Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel (s) in the tripped condition within one hour,

c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and:

I

1. If the inoperable channels consist of one turbine control valve channel and one turbine stop valve channel, place both inoperable channels in the tripped condition within one hour.

2. If the inoperable channels include two tt.rbine control valve channels or two turbine stop valve channels, declare the trip y tom inoperable. l

d. With one trip system inoperable, restore the inoperable trip system '

to OPERABLE status within 72 hours or reduce THERMAL POWER to less

                  *than 30% of RATED THERMAL POWER within the next 6 hours.

e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or reduce THERMAL POWER to less than 30% of RATED THERMAL POWER within the next 6 hours.

.O

!d HOPE CREEK 3/4 3-45 l

INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.4.2.1 Each end-of-cycle recirculation pump trip system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.4.2.1-1. 4.3.4.2.2. LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 4.3.4.2.3 The END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME of each trip function shown in Table 3.3.4.2-3 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least the logic of one type of channel input, turbine control valve fast closure or turbine stop valve closure, such that both types of channel inputs are tested at least once per 36 months. 4.3.4.2.4 The time interval necessary for breaker arc suppression from energization of the recirculation pump circuit breaker trip coil shall be measured at least once per 60 months. O O HOPE CREEK 3/4 3-46

( r 4 ( (n) w-5 I A TABLE 3.3.4.2-1 1 n j g END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION R MINIMUM {

OPERA 8LECHANNEg) 1 TRIP FUNCTION PER TRIP SYSTEM

1. Turbine Stop Valve - Closure 2(b)

2. Turbine Control Valve-Fast Closure 2 ID) 1 i

I ! U

   *         (a)A trip system may be placed in an inoperable status for up to 2 hours for required surveillance provided I

y that the other trip system is OPERABLE. l 0 IIThis function shall be automatically bypassed when turbine first stage pressure is 5 153.3 psig* equivalent to THERMAL POWER less than 30% of RATED THERMAL POWER. To allow for instrument accuracy, calibration ' and drift, a setpoint of i 132.4 psig* is used. 1 ! t i i l

Initial Setpoint. Final setpoint to be determined during the startup test program.

4 1

TABLE 3.3.4.2-2 5 A END-OF-CYCLE RECIRCULATION PUMP TRIP SETPOINTS 9 m

ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE

1. Turbine Stop Valve-Closure 1 5% closed 5 7% closed

2. Turbine Control Valve-Fast Closure > 530 psig > 465 psig R

l 8 l l l l O O O

1 TABLE 3.3.4.2-3 5 i i A END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME n i

 .R    TRIP FUNCTION                                                                                                                              RESPONSE TIME (Milleseconds)'

E

1. Turbine Stop Valve-Closure < 175 i

2. Turbine Control Valve-Fast Closure < 175 :

i l i l i La.3 I 1 ! Y : 0 E i 6 1 I

i

TABLE 4.3.4.2.1-1 5 A END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM SURVEILLANCE REQUIREMENTS k CHANNEL p FUNCTIONAL CHANNEL

        ; ,IT ny 7m*:                                                                     TEST          CALIBRATION

1. Turbine Stop Valve-Closuic M R

2. Turbine Control Valve-Fast Closure M R l

l l ! T 1 E i j O O O

INSTRUMENTATION f\

%/

3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.5 The reactor core isolation cooling (RCIC) system actuation instrumentation channels shown in Table 3.3.5-1 shall be OPERABLE with their

,     trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3 with reactor steam dome pressure greater than 150 psig. ACTION:

a. With a RCIC system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.5-2, declare the channel inoperable until the channel'is restored to OPERABLE status with its trip setpoint i adjusted consistent with the Trip Setpoint value.

b. With one or more RCIC system actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.5-1.

V SURVEILLANCE REQUIREMENTS 4.3.5.1 Each RCIC system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown l in Table 4.3.5.1-1. 4.3.5.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of l all channels shall be performed at least once per 18 months. l h O' HOPE CREEK 3/4 3-51

5 A TABLE 3.3.5-1 k REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION W MINIMUM OPERABLE PER TRIP FUNCTION CHANNELS (a) ACTION TRIP FUNCTION

a. Reactor Vessel Water Level - Low Low, level 2 4(b) 50

b. Reactor Vessel Water Level - High, Level 8 4(b) 50

c. Condensate Storage Tank Water Level - Low (*) 2(c) 51

d. Manual Initiation 1(d) 52 M

= Y IG (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip system in the tripped condition provided all other channels monitoring that parameter are OPERABLE. (b) One trip system with one-out-of-two twice logic. (c) One trip system with one-out-of-two logic. (d) One trip system with one channel. (e) Initiates RCIC suction switchover from the condensate storage tank to the torus. O O O

g TABLE 3.3.5-1 (Continued) REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION 50 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place the inoperable channel in the tripped condition within 1 hour or declare the RCIC system inoperable.

b. With more than one channel inoperable, declare the RCIC system inoperable.

ACTION 51 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within one hour or declare the RCIC system inoperable. ACTION 52 - With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 8 hours or declare the RCIC system inoperable. O O HOPE CREEK 3/4 3-53

I c

l y TABLE 3.3.5-2 y REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS rn

ALLOWABLE FUNCTIONAL UNITS TRIP SETPOINT VALUE

a. Reactor Vessel Water Level - Low Low, Level 2 2 -38 inches

2 -45 inches

b. Reactor Vessel Water Level - High, Level 8 5 54 inches * $ 61 inches

c. Condensate Storage Tank Level - Low 2 22,558 gallons 1 19,174 gallons

d. Manual Initiation NA NA M

a T S:

                *See Bases Figure B 3/4 3-1.

9 O e

5 A TABLE 4.3.5.1-1 n A REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E CHANNEL CHANNEL FUNCTIONAL CHANNEL FUNCTIONAL UNITS CHECK TEST CALIBRATION 1

a. Reactor Vessel Water Level -

Low Low, Level 2 S M R

b. Reactor Vessel Water S M R Level - High, Level 8 f

c. Condensate Storage Tank

Lavel - Low NA M R 1" d. Manual Initiation NA M(a) NA w

di (a) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as part of circuitry required to be tested for automatic system actuation. 1

INSTRUMENTATION 3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.6. The control rod block instrumentation channels shown in Table 3.3.6-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.6-2. APPLICABILITY: As shown in Table 3.3.6-1. ACTION:

a. With a control rod block instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.6-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the numbsr of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, take the ACTION required by Table 3.3.6-1.

SURVEILLANCE REQUIREMENTS 4.3.6 Each of the above required control rod block trip systems and instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.6-1.

O HOPE CREEK 3/4 3-56

d-TABLE 3.3.6-1 g CONTROL ROD BLOCK INSTRUMENTATION

A MINIMUM APPLICABLE

, c, OPERABLE CHANNELS OPERATIONAL l E TRIP FUNCTION PER TRIP FUNCTION CONDITIONS ACTION i E 1. ROD BLOCK MONITOR (a)

a. Upscale 2 1* 60

! b. Inoperative 2 1* 60 l c. Downsc4Te*

2 1* 60

2. APRM

a. Flow Biased Neutron Flux -

Upscale 4 1 61

b. Inoperative 4 1,2,5 61 i: c. Downscale 4 1 61; d. Neutron Flux - Upscale, Startup 4 2, 5 61; 3. SOURCE RANGE MONITORS l a. Detector not full in(b) 3 2 61
R 2 5 61 Upscale (c) 3 2 b.

E c. Inoperative (c) 3 2 3 2 6 i d. Downscale(d)

4. INTERMEDIATE RANGE MONITORS

a. Detector not full in 6 2, 5 61

b. Upscale 6 2, 5 61

c. Inoperati 6 2, 5 61

d. Downscale{g) 6 2, 5 61

5. SCRAM DISCHARGE VOLUME j a. Water Level-High (Float Switch) 2 1, 2, 5** 62

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW

a. Upscale 2 1 62

b. Inoperative 2 1 62

c. Comparator 2 1 62

7. REACTOR MODE SWITCH SHUTDOWN POSITION 2 3, 4 63

l l l TABLE 3.3.6-1 (Continued) CONTROL R0D BLOCK INSTRUMENTATION ACTION ACTION 60 - Declare the RBM inoperable and take the ACTION required by Specification 3.1.4.3. ACTION 61 - With the number of OPERABLE. Channels: i l

a. One less than required by the Minimum OPERABLE Channels

per Trip Function requirement, restore the inoperable

! channel to OPERABLE status within 7 days or place the inoperable channel in the tripped condition within the j next hour. t

b. Two or more less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least i one inoperable channel in the tripped condition within l one hour.

The provisions of Specification 3.0.4 are not applicable. ACTION 62 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place j the inoperable channel in the tripped condition within one hour. The provisions of Specification 3.0.4 are not applicable. ACTION 63 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, initiate a rod block. NOTES With THERMAL POWER > 30% of RATED THERMAL POWER. With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

a. The RBM shall be automatically bypassed when a peripheral control rod is selected.

b. This function shall be automatically bypassed if detector count rate is

      > 100 cps or the IP.M channels are on range 3 or higher.

c. This' function shall be automatically bypassed when the associated IRM l

channels are on range 8 or higher.

d. This function shall be automatically bypassed when the IRM channels are on range 3 or higher,

e. This function shall be automatically bypassed when the IRM channels are on range 1.

l l HOPE CREEK 3/4 3-58

                                                                                      %                                                                                                        1 (O)                                                  I TABLE 3.3.6-2 CONTROL ROD BLOCK INSTRUMENTATION SETPOINTS k                  TRIP FUNCTION                                         TRIP SETPOINT                 ALLOWABLE VALUE

[ 1. R0D BLOCK MONITOR g a. Upscale < 0.66 W + 40% < 0.66 W + 43% 7 b. Inoperative NA HA

c. Downscale > 5% of RATED THERMAL POWER > 3% of RATED THERMAL POWER

2. APRM

a. Flow Biased Neutron Flux -

Upscale < 0.66 W + 42%* < 0.66 W + 45%*

b. Inoperative HA RA

c. Downscale > 4% of RATED THERMAL POWER > 3% of RATED THERMAL POWER d'. Neutron Flux - Upscale, Startup 312%ofRATEDTHERMALPOWER {14%ofRATEDTHERMALPOWER

3. SOURCE RANGE MONITORS

a. Detector not full in NA NA 5 5 i'

b. Upscale < 1.0 x 10 cps < 1.6 x 10 cps

c. Inoperative HA RA

d. Downscale > 3 cps ** > 1.8 cps

                                                              ,                   4. INTERMEDIATE RANGE MONITORS
                                                              's                       a. Detector not full in                       NA                             NA
,                                                             [                        b. Upscale                                    < 108/125 divisions of         f 110/125 divisions of i

e full scale full scale E c. Inoperative NA NA

d. Downscale > 5/125 divisions of > 3/125 divisions of

( Tull scale Tull scale

5. SCRAM DISCHARGE VOLUME

a. Water Level-High (Float Switch) 109'1" (North Volume) 109'3" (North Volume) 108'11.5" (South Volume) 109'1.5" (South Volume) j 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW Upscale < 108% of rated flow < 111% of rated flow a.

b. Inoperative NA NA

c. Comparator < 10% flow deviation < 11% flow deviation

7. E R_EACTOR MODE SWITCH SHUTDOWN POSITION NA NA "The Average Power Range Monitor rod block function is varied as a function of recirculation loop flow (W). The trip setting of this function must be maintained in accordance with Specification 3.2.2.

                                                                                  **May be reduced to 0.7 cps provided the signal-to-noise ratio is > 2.

TABLE 4.3.6-1 g CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS A n CHANNEL OPERATIONAL g CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH p TRIP FUNCTION CHECK TEST CALIBRATION (3) SURVEILLANCE REQUIRED

1. R0D BLOCK MONITOR

a. Upscale NA S/U(b)(c) (c) b)(c), (c)

SA 1*

b. Inoperative NA NA 1*

I c. Downscale NA S/U(b)(c) S/U( , (c) SA 1*

2. APRM

a. Flow Biased Neutron Flux -

! Upscale NA S/U ,M SA 1

b. Inoperative NA S/U(b),M NA 1,2,5

c. Downscale NA S/U(b),M SA 1

d. Neutron Flux - Upscale, Startup NA S/U ,M SA 2, 5 y 3. SOURCE RANGE MONITORS

a. Detector not full in NA S/U ,W NA 2, 5

[ g, b. Upscale NA SA 2, 5 o c. Inoperative NA S/U(b),W NA 2, 5

d. Downscale NA S/U(b),W S/U , SA 2, 5

4. INTERMEDIATE RANGE MONITORS

a. Detector not full in NA S/U(b)

S/U(b),W NA 2, 5

b. Upscale NA ,W SA 2, 5

c. Inoperative NA S/U ,W NA 2, 5

d. Downscale NA S/U ,W SA 2, 5

5. SCRAM DISCHARGE VOLUME

a. Water Level-High (Float Switch) NA M R 1, 2, 5**

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW

a. Upscale NA S/U(b) SA 1

b. Inoperative NA S/U(b),M NA 1

c. Comparator NA S/U(b),M

                                                                                                             ,M         SA               1

7. REACTOR MODE SWITCH SHUTDOWN POSITION NA R NA 3, 4 O O .

O

TABLE 4.3.6-1 (Continued) CONTROL R0D BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS l NOTES. 4

a. Neutron detectors may be excluded from CHANNEL CALIBRATION.

b. Within 24 hours prior to startup, if not performed within the l

previous 7 days,

c. Includes reactor manual control multiplexing system input.

With THERMAL POWER > 30% of RATED THERMAL POWER.

   **     With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

i \ l l l HOPE CREEK 3/4 3-61

INSTRUMENTATION 3/4.3.7 MONITORING INSTRUMENTATION O RADIATION MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.1 The radiation monitoring instrumentation channels shown in Table 3.3.7.1-1 shall be OPERABLE with their alarm / trip setpoints within the specified limits. APPLICABILITY: As shown in Table 3.3.7.1-1. ACTION:

a. With a radiation monitoring instrumentation channel alarm / trip setpoint exceeding the value shown in Table 3.3.7.1-1, adjust the setpoint to within the limit within 4 hours or declare the channel inoperable.

b. With one or more radiation monitoring channels inoperable, take the ACTION required by Table 3.3.7.1-1.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.1 Each of the above required radiation monitoring instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the conditions and at the frequencies shown in Table 4.3.7.1-1. O HOPE CREEK 3/4 3-62

TABLE 3.3.7.1-1

5

] A RADIATION MONITORING INSTRUMENTATION i 1 2 m l ! %' MINIMUM CHANNELS APPLICABLE ALARM / TRIP L i INSTRUMENTATION OPERABLE CONDITIONS SETPOINT ACTION i ! 1. Control Room 2/ intake 1,2,3,5 and * -< 2x10.sp C/cc** 71 1 Ventilation Radiation ) Monitor l Area Monitors 2.

a. Criticality Monitors

1) New Fuel 1 # > 5 mR/hr and 72 l Storage Vault 20 mR/hr(a) w 2) Spent Fuel 1 ## > 5 mR/hr and 72 A Storage Pool < 20 mR/hr(a)

b. Control Room Direct 1 At all times 2.5 mR/hr(a) .72 ;

i

                                     "               Radiation Monitor                                                                                                           '

I 3. Reactor Auxiliaries Cooling 1 At all times 9 x 10 s pC/cc(a) 73 Radiation Monitor

 !                                         4. Safety Auxiliaries Cooling                 1/ loop              At all times  6 x 10 5 pC/cc(a)        73 i                                              Radiation Monitor Offgas Pre-treatment                                            ***

! 5. 1 (b) 74 Radiation Monitor 1 4 d 4

TABLE 3.3.7.1-1 (Continued) RADIATION MONITORING INSTRUMENTATION E g TABLE NOTATION x

         *When irradiated fuel is being handled in the secondary containment.
        ** Activates control room emergency filtration system.
       ***When the offgas treatment system is operating.
         #With fuel in the new fuel storage vault.
        ##With fuel in the spent fuel storage pool.

(a) Alarm only. (b) Alarm setpoint to be set in accordance with Specification 3.11.2.7. R.

O O O

p TABl.E 3.3.7.1-1 (Continued) RADIATION MONITORING INSTRUMENTATION ACTION ACTION 71 -

a. With one of the required monitors inoperable, place the inoperable channel in the tripped condition within one hour; restore the inoperable channel to OPERABLE status within 7 days, or, within the next 6 hours, initiate and maintain operation of the control room emergency filtration system in the pressurization mode of operation,

b. With both of the required monitors inoperable, initiate and maintain operation of the control room emergency filtration system in the pressurization mode of operation within one hour.

;          ACTION 72     -

With the required monitor inoperable, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours. ACTION 73 - With the required monitor inoperable, obtain and analyze at least one sample of the monitored parameter at least cnce per 24 hours." ACTION 74 - With the number of channels OPERABLE less than required by i Minimum Channels OPERABLE requirement, release (s) via this pathway may continue for up to 30 days provided:

a. The offgas system is not bypassed, and

b. Grab samples are taken at least once per 8 hours and analyzed within the following 4 hours; Otherwise, be in at least HOT SHUTDOWN within 12 hours, i

lp

Radiation level readings may be taken at the Local Radiation Processor (LRP)

V at least once per 24 hours in lieu of ootaining and analyzing grab samples at least once per 24 hours prior to 120 days after initial fuel load. HOPE CREEK 3/4 3-65

TABLE 4.3.7.1-1 5 g _ RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS h OPERATIONAL p CHANNEL CONDITIONS FOR CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE INSTRUMENTATION CHECK TEST CALIBRATION REQUIRED

1. Control Room Ventilation Radiation Monitor S M R 1, 2, 3, 5 and *

2. Area Monitors

a. Criticality Monitors

1) New Fuel Storage S M R #

 ,                    Vault s

[ 2) Spent Fuel Storage S M R ## 4 Pool m

b. Control Room Direct S M R At all times Radiation Monitor

3. Reactor Auxiliaries Cooling S M R At all times Radiation Monitor

! 4. Safety Auxiliaries Cooling S M R At all times l Radiation Monitor

5. Offgas Pre-treatment S M R Radiation Monitor O O O

                                                                                                                            ~ J'
 \

TABLE 4.3.7.1-1 (Continued) 4 5 l A RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS

E i

h TABLE NOTATION

                            #With fuel in the new fuel storage vault.

4

                           ##With fuel in the spent fuel storage pool.
                            *When irradiated fuel is being handled in the secondary containment.
                           **When the offgas treatment system is operating.

i 0 i : i l i i i I 5 l i

INSTRUMENTATION SEISMIC MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.2 The seismic monitoring instrumentation shown in Table 3.3.7.2-1 shall be OPERABLE. APPLICABILITY: At all times. ACTION:

a. With one or more of the above required seismic monitoring instruments inoperable for more than 30 days, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the instrument (s) to OPERABLE status,

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.2.1 Each of the above required seismic monitoring instruments shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNC-TIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.2-1. 4.3.7.2.2 Each of the above required seismic monitoring instruments actuated during a seismic event greater than or equal to 0.01g shall be restored to OPERABLE status within 24 hours and a CHANNEL CALIBRATION performed within 5 days following the seismic event. Data shall be retrieved from actuated instruments and analyzed to determine the magnitude of the vibratory ground motion. A Special Report shall be prepared and submitted to the Co:nmission pursuant to Specification 6.9.2 within 10 days describing the magnitude, frequency spectrum and resultant effect upon unit features important to safety. O HOPE CREEK 3/4 3-68

l l TABLE 3.3.7.2-1 /~~N SEISMIC MONITORING INSTRUMENTATION MINIMUM MEASUREMENT INSTRUMENTS INSTRUMENTS AND SENSOR LOCATIONS RANGE OPERABLE

1. Triaxial Time-History Accelerographs

a. 500' From Reactor Building i 1G 1 Free Field, 60' Below Grade

b. Primary Containment Foundation, i 1G 1 Room 4101

c. Refueling Floor in Reactor i 1G 1 Building

d. Core Spray Piping in Drywell i 1G 1

e. Auxiliary Building Foundation i IG 1

2. Triaxial Peak Accelerographs

a. Reactor Support Lateral Truss i SG 1

b. Core Spray Piping in Drywell i 5G 1

c. Service Water Pump Piping i 5G 1

3. Triaxial Seismic Switches b a. Primary Containment Foundation, NA 1*

Room 4101 (Trigger)

b. Primary Containment Foundation, NA 1g)

Room 4101 (Switch)

4. Triaxial Response-Spectrum Recorders

a. Primary Containment Foundation 1.0 -32.0 Hz** 1 (north-south)

b. , Primary Containment Foundation 1.0 -32.0 Hz** 1 (east-west)

c. Primary Containment Foundation 1.0 -32.0 Hz** 1 (vertical)

(a)With reactor control room annunciation.

        *Provides trigger mechanism to activate magnetic recording tapes for the               ,

time-history accelerographs. i

      **Each recorder has 16 reeds responsive to 16 discrete frequencies from 1.0-32.0 Hz. Each recorder also contains 16 switches integrally related to the 16 reeds which provide independent control room indication when predetermined acceleration levels and design limits have been exceeded.

l O HOPE CREEK 3/4 3-69

l l TABLE 4.3.7.2-1 SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL FUNCTIONAL CHANNEL INSTRUMENTS AND SENSOR LOCATIONS CHECK TEST CALIBRATION

1. Triaxial Time-History Accelerographs

a. 500' From Reactor Building M 'SA R Free Field, 60' Below Grade

b. Primary Containment M SA R Foundation, Room 4101

c. Refueling Floor in Reactor M SA R Building

d. Core Spray Piping in Drywell M SA R

e. Auxiliary Building Foundation M SA R

2. Triaxial Peak Accelerographs

a. Re::: tar Support Lateral NA NA R Truss

b. Core Spray Piping in Drywell NA NA R

c. Service Water Pump Piping NA NA R

3. Triaxial Seismic Switches l

a. Primary Containment NA SA R Foundation, Room 4101 (Trigger)

b. Primary Containment NA SA R Foundation Room 4101 (Switch)

4. Triaxial Response-Spectrum Recorders ,

a. Primary Containment M SA R Foundation (north-south)

b. Primary Containment M SA R Foundation (east-west)

c. Primary Containment M SA R Foundation (vertical) l O

HOPE CREEK 3/4 3-70

INSTRUMENTATION ( METEOROLOGICAL MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION l 3.3.7.3 The meteorological monitoring instrumentation channels shown in Table 3.3.7.3-1 shall be OPERABLE. APPLICABILITY: At all times. ACTION:

a. With one or more of the required meteorological monitoring instrumen-tation channels inoperable for more than 7 days, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the instrumentation to OPERABLE status.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

Os SURVEILLANCE REQUIREMENTS 4.3.7.3 Each of the above required meteorological monitoring instrumentation channels shall be demcnstrated OPERABLE by the performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.3-1. i HOPE CREEK 3/4 3-71

TABLE 3.3.7.3-1 , METEOROLOGICAL MONITORING INSTRUMENTATION MINIMUM INSTRUMENTS INSTRUMENT OPERABLE

a. Wind Speed

1. Elev. 33 ft. I l

2. Elev. 150 ft. I

b. Wind Direction

1. Elev. 30 ft. 1

2. Elev. 150 ft. 1

c. Air Temperature Difference

1. Elev. 150-33 ft. 1 O

O HOPE CWEEK 3/4 3-72

N TABLE 4.3.7.3-1 j METEOROLOGICAL MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL . INSTRUMENT CHECK CALIBRATION

a. Wind Speed

. 1. Elev. 33 ft. D SA

2. Elev. 150 ft. D SA

b. Wind Direction

1. Elev. 33 ft. D SA

! 2. Elev. 150 ft. D SA i

c. Air Temperature Difference

1. Elev. 150-33 ft. D SA l

E i i l l ) e 5 i. t l l l ! i HOPE CREEK 3/4 3-73 l j !

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM INSTRUMENTATION AND CONTROLS LIMITING CONDITION FOR OPERATION 3.3.7.4 The remote shutdown system instrumentation and controls shown in Table 3.3.7.4-1 and Table 3.3.7.4-2 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With the number of OPERABLE remote shutdown monitoring instrumentation channels less than required by Table 3.3.7.4-1, restore the inoperable channel (s) to OPERABLE status within 7 days or be in at least HOT SHUTOOWN within the next 12 hours.

b. With the number of OPERABLE remote shutdown system controls less than required in Table 3.3.7.4-2, restore the inoperable control (s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours.

c. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.4.1 Each of the above required remote shetdown monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.4-1. 4.3.7.4.2 At least one of each of the above remote shutdown control switch (es) and control circuits shall be demonstrated OPERABLE by verifying its capability to perform its intended function (s) at least once per 18 months. O HOPE CREEK 3/4 3-74

l 1 TABLE 3.3.7.4-1 1 5 l g REMOTE 5HUTDOWN MONITORING INSTRUMENTATION j g m Q MINIMUM i INSTRUMENTS j INSTRUMENT OPERABLE *

1. Reactor Vessel Pressure 2 1

2. Reactor Vessel Water Level 2 i 3. Safety / Relief Valve Position, (3) valves 1/ valve l

j 4. Suppression Chamber Water Level 2 i

5. Suppression Chamber Water Temperature 2 '

         $  6. RHR System Flow                                                                                               1 4

4 7. Safety Auxiliaries Cooling System Flow 1

8. Safety Auxiliaries Cooling System Temperature 1 ,

l 9. RCIC System Flow 1 ; t

10. RCIC Turbine Speed 1 j 11. RCIC Turbine Bearing Oil Pressure Low Indication 1 1 :

12. RCIC High Pressure / Low Pressure Turbine Bearing Temperature High Indication 1 Condensate Storage Tank Level Low-Low Indication '

j 13. 1 f 14. Standby Diesel Generator 1AG400 Breaker Indication 1 i

           "Either primary location (Remote Shutdown Panel,10C399) or alternate location.

l

TABLE 3.3.7.4-1 (Continued) REMOTE SHUTDOWN MONITORING INSTRUMENTATION a 5 MINIMUM INSTRUMENTS INSTRUMENT (Continued) OPERABLE *

15. Standby Diesel Generator IBG400 Breaker Indication 1

16. Standby Diesel Generator ICG400 Breaker Indication 1

17. Standby Diesel Generator 1DG400 Breaker Indication 1

18. Switchgear Room Cooler 1AVH401 Status Indication 1

19. Switchgear Room Cooler IBVH401 Status Indication 1

{ 20. Switchgear Room Cooler ICVH401 Status Indication 1

21. Switchgear Room Cooler IDVH401 Status Indication 1

   *Either primary location (Remote Shutdown Panel 10C399) or alternate location.

9 O O

TABLE 3.3.7.4-2 O V REMOTE SHUTDOWN SYSTEMS CONTROLS CHANNEL TRANSFER SWITCHES - REMOTE SHUTDOWN PANEL (RSP)(1) ISV-HSS-4410A Control - Class IE Channel A Transfer Switch ISV-HSS-4410B Control - Class IE Channel B Transfer Switch ISV-HSS-4410C Control - Class 1E Channel C Transfer Switch ISV-HSS-4410D Control - Class IE Channel D Transfer Switch ISV-HSS-4410N Control - Non-Class IE Transfer Switch RCIC SYSTEM - RSP 1FC-HV-4282 Control - RCIC Turbine Trip / Throttle Valve 1FC-HV-F045 Control - RCIC Turbine Shutoff Valve 1FC-HV-F008 Control - RCIC Steam Supply Outboard Isolation Valve IFC-HV-F007 Centrol - RCIC Steam Supply Inboard Isolation Valve IBD-HV-F031 Control - Suppression Pool to RCIC Pump Suction Valve IBD-HV-F010 Control - Condensate Storage Tank to RCIC Pump Suction Valve 1BD-SV-F019 Control - RCIC Pump Discharge Minimum Flow Valve IBD-HV-F046 Control - RCIC Turbine Cooling Water Supply Valve m IBD-HV-F013 Control - RCIC Pump Discharge to Feedwater Line Isolation Valve [V ) 1FC-HV-F076 IBD-HV-F012( Control-Indication - RCIC Steam Line Inboard Isolation Valve RCIC Pump Discharge Valve IBD-HV-F022 C Indication - Test Return Valve to Condensate Storage Tank IFC-HV-F059(2) Indication - RCIC Turbine Exhaust to Suppression Pool Valve 1FC-HV-F060(2) Indication - RCIC Condenser Vacuum Pump Discharge Valve 1FC-HV-F062(2) Indication - RCIC Turbine Exhaust Outboard Vacuum Breaker Isolation Valve 1FC-HV-F084(2) Indication - RCIC Turbine Exhaust Inboard Vacuum Breaker Isolation Valve 1FC-HV-F025(3) Indication - RCIC Condensate Pot Drain to Main Condenser Valve 1FC-HV-F004(3) Indication - RCIC Vacuum Tank Condensate Pump Discharge to Clean Rad Waste Valve 1BD-BP228(4) Indication - ECCS (RCIC) Jockey Pump BP228

IFC-0P220 Control - RCIC Vacuum Tank Condensate Pump OP220 1FC-0P219 Control - RCIC Gland Seal Condenser Vacuum Pump

! OP219 1FC-FIC-4158 Control - RCIC System Injection Flow RHR SYSTEM - RSP Control - RHR Pump BP202 Suction From Recirc Line O IBC-HV-F006B Valve 18C-HV-F004B Control - RHR Pump BP202 Suction From Suppression Pool Valve HOPE CREEK 3/4 3-77

TABLE 3.3.7.4-2 (Continued) REMOTE SHUTOOWN SYSTEMS CONTROLS RHR SYSTEM - RSP (Cont.) IBC-HV-F0078 Control - RHR Pump BP202 Minimum Flow Valve to Suppression Pool 1BC-HV-F048B Control - RHR Loop B Heat Exchanger Bypass Valve 1BC-HV-F0158 Control - RHR Loop B Shutdown Cooling Return Valve 1BC-HV-F022 Control - RHR Reactor Head Spray Inboard Isolation Valve 1BC-HV-F023 Control - RHR Reactor Head Spray Outboard Isolation Valve 18C-HV-F009 Control - RHR Shutdown Cooling Suction From Recirc Line Inboard Isolation Valve 1BC-HV-F008 Control - RHR Shutdown Cooling Suction From Recirc Line Outboard Isolation Valve 18C-HV-F1228 Control - RHR Loop B Shutdown Cooling Injection Check Valve Bypass Valve 1BC-HV-4439 Control - RHR Discharge to Liquid Radwaste Reactor Building Isolation Valve 1BC-HV-F0248 Control - RHR Pump BP202 Test Return Valve to Suppression Pool IBC-HV-F0478 Control - RHR Loop B Heat Exchanger Shell Side Inlet Valve 1BC-HV-F0038 Control - RHR Loop B Heat Exchanger Shell Side Outlet Valve i IBC-HV-F049 Control - RHR Discharge to Liquid Radwaste Inboard Isolation Valve 1BC-HV-F040 Control - RHR Discharge to Liquid Radwaste Outboard Isolation Valve 1BC-HV-F006A(3) Indication - RHR Pump AP202 Suction From Recirc Line Valve 1BC-HV-F010B(3) Indication - RHR Pump DP202 Test Return Valve to l Suppression Pool l IBC-HV-F016B(3) Indication - RHR Loop B Containment Spray Outboard Isolation Valve 1BC-HV-F027B(3) Indication - RHR Loop B Suppression Pool Spray Line Isolation Valve 1BC-HV-F017B(3) Indication - RHR Low Pressure Coolant Injection L oP B Injection Valve 180-HV-F004D(2) Indication - RHR Pump DP202 Suction From Suppression Pool Valve 1BC-HV-F021A(3) Indication - RHR Loop A Containment Spray Inboard Isolation Valve 18C-HV-F0f1B(3) Indication - RHR Loop B Containment Spray Inboard Isolation Valve 18C-BP202 Control - RHR Pump BP202 Control - Transfer Switch For RHR Pump LP202 IBC-HSS-4g8 IBC-DP228 Indication - ECCS (RHR B) Jockey Pump DP228 HOPE CREEK 3/4 3-78 t

TABLE 3.3.7.4-2 (Continued) v REMOTE SHUTDOWN SYSTEMS CONTROLS RHR SYSTEM - REDUNDANT CONTROLS 1BC-HV-F006A Local Control - RHR Pump AP202 Suction From Recirc Line Valve 1BC-HV-F004A Local Control - RHR Pump AP202 Suction From Suppression Pool Valve 1BC-HV-F048A Local Control - RHR Loop A Heat Exchanger Bypass Valve 1BC-HV-F015A Local Control - RHR Loop A Shutdown Cooling Return Valve 1BC-HV-F024A Local Control - RHR Pump AP202 Test Return Valve to Suppression Pool 1BC-HV-F047A Local Control - RHR Loop A Heat Exchanger Shell Side Inlet Valve 1BC-HV-F003A Local Control - RHR Loop A Heat Exchanger Shell Side Outlet Valve 1BC-AP202 Local Control - RHR Pump AP202 SACS - RSP IEG-HV-2522B Control - SACS Loop B to Turbine IEG-HV-24968(5) Auxiliaries Cooling System (TACS) p) ( 1EG-HV-25220(6) IEG-HV-24960 Control - Inboard Supply and Return Valves SACS Loop B to TACS Outboard Supply and Return Valves 1EG-HV-25128 Control - RHR Loop B Heat Exchanger Tube Side Outlet Valve 1EG-HV-2491B Control - SACS Loop B Heat Exchanger B1E201, Inlet Valve IEG-HV-24948 Control - SACS Loop B Heat Exchanger B2E201, Inlet Valve 1EG-HV-2520B(7)(2) Indication - RHR Pump BP202 Seal and Motor Bearing Coolers Cooling Water Supply Valve l 1EG-BP210 Control - SACS Loop B Pump BP210 1EG-HSS-2485B Control - Transfer Switch For SACS Loop B Pump BP210 1EG-DP210 Control - SACS Loop B Pump DP210 1EG-HSS-2485D Control - Transfer Switch For SACS Loop B Pump DP210 l SACS - REDUNDANT CONTROLS [ 1EG-HV-249,6A Local Control - SACS Loop A Return From TACS Inboard l Valve ! 1EG-HV-2496C Local Control - SACS Loop A Return From TACS Outboard Valve 1EG-HV-2512A Local Control - RHR Loop A Heat Exchanger Tube Side Outlet Valve

o) l HOPE CREEK 3/4 3-79 i

t

TABLE 3.3.7.4-2 (Continued) REMOTE SHUTDOWN SYSTEMS CONTROLS SACS - REDUNDANT CONTROLS (Cont.) 1EG-AP210 Local. Control - SACS Loop A Pump AP210 1EG-CP210 Local Control - SACS Loop A Pump CP210 STATION SERVICE WATER SYSTEM (SSWS) - RSP IEA-HV-2204 Control - Reactor Auxiliaries Cooling System

                                 ,,             (RACS) Heat Exchanger Supply Valve (From SACS Loop B) 1EA-HV-2355B               Control -           SACS Loop B Heat Exchanger B2E201 Outlet Valve 1EA-HV-2371B               Control -           SACS Loop B Heat Exchanger B1E201 Outlet Valve 1EA-HV-2357B               Control -           SoCS Loop B to Cooling Tower Valve SSWS Pump BP502 Discharge valve 1EA-HV-21988         '

Control 1EA-HV-2198D Control - SSWS Pump DP502 Discharge Valve 1EA-HV-21978 Control - SSWS Strair,or BF509 Main Backwash Valve 1EA-HV-21970 -Control - SSWS Strainer DF509 Main Backwash Valve 1EA-BP502 Control - SSWS Pump BP502 1EA-HSS-2219B Control - Transfer Switch For SSWS Pump BP502 1EA-DP502 Control - SSWS Pump DP502 1EA-HSS-22190 Control - Transfer' Switch For SSWS Pump DP502 SNS - REDUNDANT CONTROLO 1EA-HV-2203 Local Control - RACS Heat Exchanger Supply Valve (From SACS Loop A) 1EA-AP502 Local Control - SSWS Pump AP502 1EA-CP502 Local Control - SSWS Pump CP502 CONTROL AREA Ch1LLED WATER SYSTEM (CACWS) - RSP I 1GJ-BK400 Control - Control Area Chiller BK400 Control -

1 1GJ-HSS-9652B Transfer Switch For Control Area Chiller BK400 1GJ-EK403~ Control - Safety-Related Panel Room Chiller

                                              '8K403 1GJ-HSS-9666B4             Control -           Transfer Switch For Safety-Related Panel Room Chiller BK403 IGJ-BP400

Control - Control Area Chilled Water l Circulatirg Pump BP400 1GJ-BP414 Control - ' Safety-Related Panel Room Chilled Water Circulating Pump BP414 i

HOPE CREEK 3/4 3-80

             ,                                  s
        *                                     \   $,.

TABLE 3.3.7.4-2 (Continued) J REMOTE SHUTDOWN SYSTEMS CONTROLS CACWS - REDUNDANT CONTROLS , IGJ-AK400 Local Control - Control Area Chiller AK400 1GJ-AK403 Local Control - Safety-Related Panel Room Chiller AK403 IGJ-AP400 Local Control - Control Area Chilled Water Circulating Pump AP400 1GJ-AP414 Local Control - Safety-Related Panel Room Chilled Water Circulating Pump AP414 REACTOR RECIRCULATION SYSTEM -RSP 1BB-HV-F031B(3) Indication - Reactor Recirculation Pump BP201 Discharge Valve SAFETY / RELIEF VALVES - RSP 1AB-PSV-F013F Control - Main Steam Line B Safety / Relief Valve 1AB-PSV-F013H Control - Main Steam Line D Safety / Relief Valve 1AB-PSV-F013M Control - Main Steam Line D Safety / Relief Valve SAFETY / RELIEF VALVES - REDUNDANT CONTROLS Local Control - Main Steam Line A Safety / Relief Valve p 1AB-PSV-F013A 1AB-PSV-F013E Local Control - Main Steam Line C Safety / Relief Valve (1) The Remote Shutdown Panel (RSP) is Panel 10C399. (2) Valve is signalled to open on RSP Takeover. (3) Valve is signalled to close on RSP Takeover. (4) Pump is signalled to run on RSP Takeover. (5) Operation of valve 1EG-HV-2496B is ganged to operation of valve IEG-HV-25228. (6) Operation of valve IEG-HV-2496D is ganged to operation of valve 1EG-HV-25220. (7) Operation of valve 1EG-HV-2520B is ganged to operation of RHR Pump BP202. 1 U l HOPE CREEK 3/4 3-81

TABLE 4.3.7.4-1 5

           ?'                                                                                    REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS O

m 92 CHANNEL CHANNEL i INSTRUMENT CHECK CALIBRATION

1. Reactor Vessel Pressure M R

2. Reactor Vessel Water Level M R

3. Safety / Relief Valve Position (Energization) M NA

4. Suppression Chamber Water Level M R ,

5. Suppression Chamber Water Temperature M R u, 6. RHR System Flow M R D

u, 7. Safety Auxiliaries Cooling System Flow M R S h) 8. Safety Auxiliaries Cooling System Temperature M R

9. RCIC System Flow M R

10. RCIC Turbine Speed M R

11. RCIC Turbine Bearing Oil Pressure Low Indication M R

12. RCIC High Pressure / Low Pressure Turbine Bearing Temperature High Indication M R O O O

f -m t

       \                                                          s                                                        k                              I s                                                         N.                                                           w/

TABLE 4.3.7.4-1 (Continued) 5 g REMOTE SHUTDOWN E NITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS E [m CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

13. Condensate Storage Tank Level Low-Low Indication M R

14. Standby Diesel Generator IAG400 Breaker

            -Indication                                             M              NA

15. Standby Diesel Generator 1BG400 Breaker Indication M NA

16. Standby Diesel Generator 1CG400

    ,       Breaker Indication                                       M             NA

, N I m 17. Standby Diesel Generator IDG400 ' 4 Greaker Indication M NA w

18. Switchgear Room Cooler 1AVH401 Status Indication M NA I

19 Switchgear Room Cooler IBVH401 Status Indication M NA

20. Switchgear Room Cooler ICVH401 i Status Indication M NA

 . 21. Switchgear Room Cooler IDVH401 l            Status Indication                                       M             NA 1

I I i l d

INSTRUMENTATION ACCIDENT MONITORING INSTRJMENTATION O LIMITING CONDITION FOR OPERATION l 3.3.7.5 The accident monitoring instrumentation channels shown in Table 3.3.7.5-1 shall be OPERABLE. APPLICABILITY: As shown in Table 3.3.7.5-1. ACTION: With one or more accident monitoring instrumentation channels inoperable, take the ACTION required by Table 3.3.7.5-1. SURVEILLANCE REQUIREMENTS 4.3.7.5 Each of the above required accident monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.5-1. Ol HOPE CREEK 3/4 3-84

O

                                                                                                                             *r t                                                                                                             U l                                                                 TABLE 3.3.7.5-1

ACCIDENT MONITORING INSTRUMENTATION l 9 MINIMUM APPLICABLE 3

A

REQUIRED NUMBER CHANNELS OPERATIONAL INSTRUMENT OF CHANNELS OPERABLE CONDITIONS ACTION i 1. Reactor Vessel Pressure 2 1 1,2,3 80 l 2. Reactor Vessel Water Level 2 1 1,2,3 80 l 3. Suppression Chamber Water Level 2 1 1,2,3 80 l 4. Suppression Chamber Water Temperature
2 2 1,2,3 80(a)

5. Suppression Chamber Pressure 2 1 1,2,3 80 j 6. Drywell Pressure 2 1 1,2,3 80 l 7. Drywell Air Temperature 2 1 1,2,3 80 i

w 8. Primary Containment Hydrogen /0xygen Concentration l 4 1 Analyzer and Monitor 2 1 1,2,3 80 l } 9. 10. Safety / Relief Valve Position Indicators Drywell Atmosphere Post-Accident Radiation Monitor 2/ valve ** 2 1/ valve ** 1,2,3 1 1,2,3 80 81

11. North Plant Vent Radiation Monitor # 1 1 1,2,3 81

12. South Plant Vent Radiation Monitor # 1 1 1,2,3 81 j 13. FRVS Vent Radiation Monitor # 1 1 1,2,3 81 l 14. PrimaryCoginmentIsolationValvePosition Indication 2/ valve 1/ valve 1,2,3 82 l

l j

           #High range noble gas monitors.

Average bulk pool temperature.

l ** Acoustic monitoring and tail pipe temperature. (a) Suppression chamber water temperature instrumentation must satisfy the availability requirements specified in Specification 3.6.2.1. 1 (b)0ne channel consists of the open limit switch, and the other channel consists of the closed limit switch. l l l

Table 3.3.7.5-1 (Continued) ACCIDENT MONITORING INSTRUMENTATION ACTION STATEMENTS ACTION 80 -

a. With the number of OPERABLE accident monitoring instrumentation channels less than the Required Number of Channels shown in Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE requirements of Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 48 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

ACTION 81 - With the number of OPERABLE accident monitoring instrumentation channels less than required by the Minimum Channels OPERABLE requirement, either restore the inoperable channel (s) to OPERABLE status within 72 hours, or:

a. Initiate the preplanned alternate method of monitoring the appropriate parameter (s), and

b. Prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

l The provisions of Specification 3.0.4 are not applicable. ACTION 82 -

a. With the number of OPERABLE accident monitoring instrumentation channels less than the Required Number of Channels shown in Table 3.3.7.5-1, verify the valve (s) position by use of alternate indica-tion methods; restore the inoperable channel (s) to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE requirements of

            . Table 3.3.7.5-1, verify the valve (s) position by use of alternate indication methods; restore the inoperable channel (s) to OPERABLE l

f status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. ; O HOPE CREEK 3/4 3-86 l

p p i j TABLE 4.3.7.5-1 i x

      !@                                           ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS APPLICABLE Q                                                                                CHANNEL              CHANNEL        OPERATIONAL g               INSTRUMENT                                                         CHECK             CALIBRATION      CONDITIONS

1. Reactor Vessel Pressure M R 1,2,3

2. Reactor Vessel Water Level M R 1,2,3 j 3. Suppression Chamber Water Level M R 1,2,3 l 4. Suppression Chamber Water Temperature M R 1,2,3 i

 !                   5. Suppression Chamber Pressure                                   M                    R              1,2,3

6. Drywell Pressure M R 1,2,3

7. Drywell Air Temperature M R 1,2,3 l 8. Primary Containment Hydrogen /0xygen Concentration

 !                          Analyzer and Monitor                                           M                    Q*             1,2,3 i      w l      }             9. Safety / Relief Valve Position Indicators                      M                    R              1,2,3 Y             10. Drywell Atmosphere Post-Accident Radiation Monitor             M                    R**            1,2,3 0             11. North Plant Vent Radiation Monitor #                           M                    R              1,2,3 i

12. South Plant Vent Radiation Monitor # M R 1,2,3 j 13. FRVS Vent Radiation Monitor # M R 1,2,3

14. Primary Containment Isolation Valve Position Indication M R 1,2,3 2

                        "Using sample gas containing:
,                        a. Five volume percent oxygen balance nitrogen (oxygen analyzer channel).

b. Five volume percent hydrogen, balance nitrogen (hydrogen analyzer channel).

                     ** CHANNEL CALIBRATION shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr and a one point calibration check of the detector below 10 R/hr with an installed or portable gamma source.
!                       #High range noble gas monitors.

l .1 1

INSTRUMENTATION SOURCE RANGE MONITORS LIMITING CONDITION FOR OPERATION 3.3.7.6 At least the following source range monitor channels shall be OPERABLE:

a. In OPERATIONAL CONDITION 2*, three.

b. In OPERATIONAL CONDITION 3 and 4, two.

APPLICABILITY: OPERATIONAL CONDITIONS 2*, 3 and 4. ACTION:

a. In OPERATIONAL CONDITION 2* with one of the above required source range monitor channels inoperable, restore at least 3 source range monitor channels to OPERABLE status within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours,

b. In OPERATIONAL CONDITION 3 or 4 with one or more of the above required source range monitor channels inoperable, verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within one hour.

SURVEILLANCE REQUIREMENTS 4.3.7.6 Each of the above required source range monitor channels shall be demonstrated OPERABLE by: O i a. Performance of a:

1. CHANNEL CHECK at least once per:

l ! a) 12 hours in CONDITION 2*, and b) 24 hours in CONDITION 3 or 4.

2. CHANNEL CALIBRATION ** at least once per 18 months.

b. Performance of a CHANNEL FUNCTIONAL TEST:

1. Within 24 hours prior to moving the reactor mode switch from the Shutdown position, if not performed within the previous 7 days, and

2. At least once per 31 days.

c. Verifying, prior to withdrawal of control rods, that the SRM count rate is at least 3 cps *** with the detector fully inserted.

   *With IRM's on range 2 or below.
  ** Neutron detectors may be excluded from CHANNEL CALIBRATION.
 ***May be reduced to 0.7 cps provided the signal-to-noise ratio is > 2.

HOPE CREEK 3/4 3-88

INSTRUMENTATION V TRAVERSING IN-CORE PROBE SYSTEM i LIMITING CONDITION FOR OPERATION 1 3.3.7.7. The traversing in-core probe system shall be OPERABLE with:

a. Five movable detectors, drives and readout equipment to map the core, and

b. Indexing equipment to allow all five detectors to be calibrated in a common location.

APPLICABILITY: When the traversing in-core probe is used for:

a. Recalibration of the LPRM detectors, and b.* Monitoring the APLHGR, LHGR, MCPR, or MFLPD.

ACTION: With the traversing in-core probe system inoperable, suspend use of the system for the above applicable monitoring or calibration functions. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 4.3.7.7 The traversing in-core probe system shall be demonstrated OPERABLE by normalizing each of the above required detector outputs within 72 hours prior to use for the LPRM calibration function.

*0nly the detector (s) in the required measurement location (s) are required to be OPERABLE.

HOPE CREEK 3/4 3-89

INSTRUMENTATION LOOSE-PART DETECTION SYSTEM LIMITING CONDITION FOR OPERATION 3.3.7.8 The loose part detection system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With one or more loose part detection system char.nels inoperable for more than 30 days, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the channel (s) to OPERABLE status,

b. The provisions of Specification 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.8 Each channel of the loose part detection system shall be demonstrated OPERABLE by performance of a:

a. CHANNEL CHECK at least once per 24 hours,

b. CHANNEL FUNCTIONAL TEST at least once per 31 days, and

c. CHANNEL CALIBRATION at least once per 18 months.

O HOPE CREEK 3/4 3-90

INSTRUMENTATION "O

  \ / RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION l

3.3.7.9 The radioactive liquid effluent monitoring instrumentation channels shown in Table 3.3.7.9-1 shall be OPERABLE with their Alarm / Trip Setpoints set to ensure that the limits of Specification 3.11.1.1 are not exceeded. The Alarm / Trip Setpoints of these channels shall be determined and adjusted in accordance with the methodology and parameters in the OFFSITE DOSE CALCULATION MANUAL (0DCM). APPLICABILITY: At all times. ACTION:

a. With a radioactive liquid effluent monitoring instrumentation channel Alarm / Trip Setpoint less conservative than required by the above specification, immediately suspend the release of radioactive liquid effluents monitored by the affected channel, or declare the channel inoperable.

b. With less than the minimum number of radioactive liquid effluent monitoring instrumentation channels OPERABLE, take the ACTION shown in Table 3.3.7.9-1. Restore the inoperable instrumentation to t OPERABLE status within the time specified in the ACTION, or explain V in the next Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.7 why this inoperability was not corrected in a timely manner.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.9 Each radioactive liquid effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST at the frequencies shown in Table 4.3.7.9-1. HOPE CREEK 3/4 3-91

TABLE 3.3.7.9-1 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION O

 ";                                                                      MINIMUM CHANNELS INSTRUMENT                                       OPERABLE ACTION

1. RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE

a. Liquid Radwaste Discharge Line to the Cooling Tower Blowdown Line 1 110

2. RADI0 ACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE

a. Cooling Tower Blowdown Effluent 1 111 R

3. FLOW RATE MEASUREMENT DEVICES T

X! a. Liquid Radwaste Discharge Line to Cooling 1 112 Tower Blowdown Line

b. Cooling Tower Blowdown Weir 1 112 I

l { l l 1 l 1 i O O O

TABLE 3.3.7.9-1 (Continued) TABLE NOTATION l ACTION 110 - With the number of channels OPERABLE less than required by the , Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided that prior to initiating a release:

a. At least two independent samples are analyzed in accordance with Specification 4.11.1.1.2, and

b. At least two technically qualified members of the Facility Staff independently verify the release rate calculations and discharge line valving; Otherwise, suspend release of radioactive effluents via this pathway.

l ACTION 111 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided that, at least once per 12 hours, grab samples are collected and analyzed for gross radioactivity at a limit of detection of at least 10 7 microcuries/ml. Otherwise, suspend release of radioactive effluents via this pathway. 1 O ACTION 112 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 4 hours during actual releases. Pump performance curves generated in place may be used to estimate flow. i 4 l I j HOPE CREEK 3/4 3-93 I

              ~ . _ _ - _ _ _ ..             - . ..-._.__ - - __ - ___                -_.. - - - . - - - .. -

TABLE 4.3.7.9-1 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMFNTATION SURVEILLANCE REQUIREMENTS 9 R CHANNEL CHANNEL SOURCE CHANNEL FUNCTIONAL INSTRUMENT CHECK CHECK CALIBRATION TEST

1. RADI0 ACTIVITY M0?lITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE

a. Liquid Radwaste Discharge Line to the Cooling Tower Blowdown Line D P R(3) Q(1)

2. RADI0 ACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE y a. Cooling Tower Blowdown Effluent D M R(3) Q(2)

Y 3. FLOW RATE MEASUREMENT DEVICES

a. Liquid Radwaste Discharge Line D(4) N.A. R Q to Cooling Tower Blowdown Line

b. Cooling Tower Blowdown Weir D(4) N.A. R Q O O O

TABLE 4.3.7.9-1 (Continued) b

 \h                                                   TABLE NOTATIONS (1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occur if any of the following conditions exists:

a. Instrument indicates measured levels above the Alarm / Trip Setpoint, or

b. Circuit failure, or

c. Instrument indicates a downscale failure.

(2) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the folluwing conditions exists:

a. Instrument indicates measured levels above the Alarm Setpoint, or

b. Circuit failure, or

c. Instrument indicates a downscale failure.

(3) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) n U or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration or are NBS traceable shall be used. (4) CHANNEL CHECK shall cunsist of verifying indication of flow during periods of release. CHANNEL CHECK shall be made at least once per 24 hours on days on which continuous, periodic, or batch releases are made. i l O HOPE CREEK 3/4 3-95

INSTRUMENTATION RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.10 The radioactive gaseous effluent monitoring instrumentation channels shown in Table 3.3.7.10-1 shall be OPERABLE with their Alarm / Trip Setpoints set to ensure that the limits of Specifications 3.11.2.1 and 3.11.2.6 are not exceeded. The Alarm / Trip Setpoints of these channels meeting Specification 3.11.2.1 shall be determined and adjusted in accordance with the methodology and parameters in the ODCM. APPLICABILITY: As shown in Table 3.3.7.10-1. ACTION:

a. With a radioactive gaseous effluent monitoring instrumentation channel Alarm / Trip Setpoint less conservative than required by the above specification, immediately suspend the release of radioactive gaseous effluents monitored by the affected channel, or declare the channel inoperable.

b. With less than the minimum number of radioactive gaseous effluent monitoring instrumentation channels OPERABLE, take the ACTION shown in Table 3.3.7.10-1. Restore the inoperable instrumentation to OPERABLE status within the time specified in the ACTION, or explain in the next Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.7 why this inoperability was not corrected in a timely manner.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

l SURVEILLANCE REQUIREMENTS l 4.3.7.10 Each radioactive gaseous effluent monitoring instrumentation channel l shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST at the frequencies shown in Table 4.3.7.10-1. l O HOPE CREEK 3/4 3-96

f . s - V TABLE 3.3.7.10-1 x i % m RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION l E E MINIMUM CHANNELS ! INSTRUMENT OPERABLE APPLICABILITY ACTION I i 1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM ! EXPLOSIVE GAS MONITORING SYSTEM 1

a. Hydrogen Monitor 1 ** 124 i

l 2. FILTRATION, RECIRCULATION AND VENTILATION l MONITORING SYSTEM 1

a. Noble Gas Activity Monitor 1

123 j b. Iodine Sampler 1
125 M

I' c. Particulate Sampler 1

125 i T I $ d. Flow Rate Monitor 1
122 1

Sampler Flow Rate Monitor

j e. 1 122 I

I l 3. SOUTH PLANT VENT MONITORING SYSTEM i i a. Noble Gas Activity Monitor 1

123

 ,                              b. Iodine Sampler                                 1                                             125 l

c. Particulate Sampler 1 125 l d. Flow Rate Monitor 1 122

e. Sampler Flow Rate Monitor 1 122 i

TABLE 3.3.7.10-1 (Continued) RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION O A MINIMUM CHANNELS

INSTRUMENT OPERABLE APPLICABILITY ACTION

4. NORTH PLANT VENT MONITORING SYSTEM

a. Noble Gas Activity Monitor 1 123

125

b. Iodine Sampler 1

125

c. Particulate Sampler 1

122

d. Flow Rate Monitor 1

e. Sampler Flow Rate Monitor 1 122 R.

E 9 O O

TABLE 3.3.7.10-1 (Continued) (]

 \   ,
  'V                                     TABLE NOTATION At all times.
       ** Ouring operation of the main condenser air ejector.

ACTION 122 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 4 hours. Otherwise, suspend release of radioactive effluents via this pathway. ACTION 123 - With the number of channels OPERABLE less than required by the Mir.imum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided grab samples are taken at least once per 12 hours and these samples are analyzed for gross activity within 24 hours. Otherwise, suspend release of radioactive effluents via this pathway. ACTION 124 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, operation of main condenser offgas treatment system may continue for up to 30 days provided grab samples are collected at least once per 4 hours and analyzed

 /^N                  within the following 4 hours. Otherwise, suspend release of y)                   radioactive effluents via this pathway.

ACTION 125 - With the nuraber of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway nay continue provided that within 8 hours samples are continuously collected witt, auxiliary sampling equipment as required in Table 4.11.2.1.2-1. 4 HOPE CREEK 3/4 3-99

TABLE 4.3.7.10-1 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS E A CHANNEL MODES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED

1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM

a. Hydrogen Monitor N.A. **

D Q(3) M

2. FILTRATION, RECIRCULATION AND VENTILATION MONITORING SYSTEM

a. Noble Gas Activity Monitor D M R(2) Q(1) *

b. Iodine Sampler W N.A. N.A. N.A. *

{ Y c. Particulate Sampler W N.A. N.A. N.A. Es

d. Flow Rate Monitor D N.A. R Q

e. Sampler Flow Rate Monitor

D N.A. R Q

3. SOUTH PLANT VENT MONITORING SYSTEM

a. Noble Gas Activity Monitor D M R(2) Q(1)

N.A. *

b. Iodine Sampler W N.A. N.A.

c. Particulate Sampler W N.A. N.A. N.A.

d. Flow Rate Monitor D N.A. R Q

e. Sampler Flow Rate Monitor N.A. R

D Q O O O

i i 1 TABLE 4.3.7.10-1 (Continued) 5 y RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 2 m m

CHANNEL M00ES IN idHICH CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED

4. NORTH PLANT VENT MONITORING SYSTEM f

! a. Noble Gas Actvity Monitor D M R(2) Q(1) * ) b. Iodine Sampler W N.A. N.A. N.A. *

c. Particulate Sampler W N.A. N.A. M.A.

t j d. Flow Rate Monitor D N.A. R Q i

1 R

e. Sampler Flow Rate Monitor D M.A. R Q E;

r i .i l i f 1 l l i

TABLE 4.3.7.10-1 (Continued) TABLE NOTATION

At all times.
- During operation of the main condense.r air ejector.

(1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exists:

1. Instrument indicates measured levels above the alarm setpoint.

2. Circuit failure.

3. Instrument indicates a downscale failure.

(2) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration or are NBS traceable shall be used. (3) The CHANNEL CALIBRATION shall include the use of standard gas samples containii.g a nominal:

1. Zero volume percent hydrogen, balance nitrogen, and

2. 1.5 volume percent hydrogen, balance nitrogen.

O HOPE CREEK 3/4 3-102

INSTRUMENTATION i n

> V     3/4.3.8 TURBINE OVERSFEED PROTECTION SYSTEM LIMITING CONDITION FOR OPERATION 3.3.8 At least one turbine overspeed protection system shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With one turbine control valve, or one main stop valve per high pressure turbine steam lead inoperable and/or with one combined intermediate valve per low pressure turbine steam lead inoperable, restore the inoperable valve (s) to OPERABLE status within 72 hours or close at least one valve in the affected steam lead (s) or isolate the turbine from the steam supply within the next 6 hours.

b. With the above required turbine overspeed protection system otherwise inoperable, within 6 hours isolate the turbine from the steam supply.

c. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.8.1 The provisions of Specification 4.0.4 are not applicable. 4.3.8.2 The above required turbine overspeed protection system shall be demonstrated OPERABLE:

a. At least once per 7 days by:

1. Cycling each of the following valves through at least one complete cycle from the running position:

a) For the overspeed protection control system;

1) Six low pressure combined intermediate valves b) For the electrical overspeed trip system and the mechanical overspeed trip system;

1) Four high pressure main stop valve:,, and

2) Six low pressure combined intermediate valves.

O v l HOPE CREEK 3/4 3-103

INSTRUMENTATION SURVEILLANCE REQUIREMENTS (Continued)

b. At least once per 31 days by:

1. Cycling each of the following valves through at least one complete cycle from the running position:

a) For the overspeed protection control system;

1) Four high pressure turbine control valves b) For the electrical overspeed trip system and the mechanical overspeed trip system;

1) Four high pressure turbine control valves.

c. At least once per 18 months by performance of a CHANNEL CALIBRATION of the turbine overspeed protection instrumentation.

d. At least once per 40 months by disassembling at least one of each of the above valves and performing a visual and surface inspection of all valve seats, disks and stems and verifying no unacceptable flaws or excessive corrosion. If unacceptable flaws or excessive corrosion are found, all other valves of that type shall be inspected.

O HOPE CREEK 3/4 3-104

INSTRUMENTATION V 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION I 1 LIMITING CONDITION FOR OPERATION 3.3.9 The feedwater/ main turbine trip system actuation instrumentation channels shown in Table 3.3.9-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.9-2. APPLICABILITY: As shown in Table 3.3.9-1. ACTION:

a. With a feedwater/ main turbine trip system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.9-2, declare the channel inoperable and either place the inoperable channel in the tripped condition until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value, or declare the associated system inoperable.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels requirement, restore the inoperable channel C to CPERABLE status within 7 days or be in at least STARTUP within the (T) next 6 hours,

c. With the number of OPERABLE channels two less than required by the Minimum OPERABLE Channels requirement, restore at least one of the inoperable channels to OPERABLE status within 72 hours or be in at least STARTUP within the next 6 hours.

SURVEILLANCE REQUIREMENTS 4.3.9.1 Each feedwater/ main turbine trip system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS

and at the frequencies shown in Table 4.3.9.1-1.

4.3.9.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all l channels shall be performed at least once per 18 months. 1 O HOPE CREEK 3/4 3-105

TABLE 3.3.9-1 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION ! O E APPLICABLE MININMUM OPERATIONAL FUNCTIONAL UNIT OPERABLE CHANNELS CONDITIONS l 1. Reactor Vessel Water Level-High, Level 8 3 1 1 l 4 a; m \ l O O O

E L s BE e AU h WL c S OA n T LV i N L I A 5 O . P 5 T 5 E S $ N O I T A T N E M . U R T S N I N T s 2 O N e I I h

    -   T      O   c 9    A      P   n U      T  i 3    T
      . C     .E S  0 3    A P  4 E    M      I 5 L    E      R B    T      T   5 A    S T    Y S

P I 8 R T l e E v N e I L B R , U h T g i N H I - A l M e

        /          v R

E e . L 1 T - A r 3 W D t a 4 E a / E W 3 F l B e s e _ s r _ T e u _ I V g _ N i U r F o L t s A c e N a s O e a I R B T C e N e U . S F 1 " 9A <. Ya~ I l l l

                                                           ~          TABLE 4.3.9.1-1 c .!        '                                  ~

m FEE 0 WATER / MAIN TURBINE TRIP SYSTEM ACTUAil0N INSTRUMENTATION SURVEILLANCE REQUIREMENTS

f , .e _,, c - 3-

  . m CHANNEL                                              ,0PERATIONAL CHANNEL             FUNCTIONAL                       CHANNEL       CON 0lTIONS FOR $ : n e                      /

TRIP FUNCTIONAL CHECK CHECK TEST CALIBRATION St1RVEILLANCE REQUIRED

1. Reactor Vessel Water Level-High, '

Level 8 S M -

                                                                                                       - ~'

R ,_ 1 - V

                                                                                                                                             /
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O O O

l m 3/4.4 REACTOR CCOLANT SYSTEM l 3/4.4.1 RECIRCULATION SYSTEM RECIRCULATION LOOPS LIMITING CONDITION FOR OPERATION 3.4.1.1 Two reactor coolant system recirculation loops shall be in operation with:

a. Total core flow greater than or equal to 45% of rated core flow, or

b. THERMAL POWER less than or equal to the limit specified in Figure 3.4.1.1-1.

APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2*. ACTION:

a. With one reactor coolant system recirculation loop not in operation, immediately initiate action to reduce THERMAL POWER to less than or equal to the limit specified in Figure 3.4.1.1-1 within 2 hours and n initiate measures to place the unit in at least HOT SHUTDOWN within

( 12 hours.

b. With no reactor coolant system recirculation loops in operation, immediately initiate action to reduce THERMAL POWER to less than or equal to the limit specified in Figure 3.4.1.1-1 within 2 hours and initiate measures to place the unit in at least STARTUP within 6 hours and in HOT SHUTDOWN within the next 6 hours.

c. With two reactor coolant system recirculation loops in operation and total core flow less than 45% of rated core flow and THERMAL POWER greater than the limit specified in Figure 3.4.1.1-1:

1. Determine the APRM and LPRM** noise levels (Surveillance 4.4.1.1.3):

a) At least once per 8 hours, and b) Within 30 minutes after the completion of a THERMAL POWER increase of at least 5% of RATED THERMAL POWER. ( 2. With the APRM or LPRM** neutron flux noise levels greater than three times their established baseline noise levels, immediately initiate corrective action to restore the noise levels to within the required limits within 2 hours by increasing core flow to greater ,than 45% of rated core flow or by reducing THERMAL POWER l to less than or equal to the limit specified in Figure 3.4.1.1-1.

        *See Special Test Exception 3.10.4.
      ** Detector levels A and C of one LPRM string per core octant plus detectors A l         and C of one LPRM string in the center of the core should be monitored.

HOPE CREEK 3/4 4-1

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.1.1.1 At least once per 12 hours verify that total core flow is greater than or equal to 45% of rated core flow and/or that THERMAL POWER is less than the limit specified in Figure 3.4.1.1-1. 4.4.1.1.2 Each pump MG set scoop tube mechanical and electrical stop shall be demonstrated OPERABLE with overspeed setpoints less than or equal to 105% and 102.5%, respectively, of rated core flow, at least once per 18 months. 4.4.1.1.3 Establish a baseline APRM and LPRM** neutron flux noise value within the regions for which monitoring is required (Specification 3.4.1.1, ACTION c) within 2 hours of entering the region for wnich monitoring is required unless baselining has previously been performed in the region since the last refueling outage. O l l

  *If not performed within the previous 31 days.
 ** Detector levels A and C of one LPRM string per core octant plus detectors A and C of one LPRM string in the center of the core should be monitored.

HOPE CREEK 3/4 4-2 l

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a N o o e o e o o o tw M3 en w n N v-031VB % 'M3M0d WWB3H13803 HOPE CREEK 3/4 4-3

l REACTOR COOLANT SYSTEM JET PUMPS LIMITING CONDITION FOR OPERATION 1 3.4.1.2 All jet pumps shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: l With one or more jet pumps inoperable, be in at least HOT SHUTDOWN within 12 hours. l l SURVEILLANCE REQUIREMENTS

4.4.1.2 Each of the above required jet pumps shall be demonstrated OPERABLE prior to THERMAL POWER exceeding 25% of RATED THERMAL POWER and at least once per 24 hours by determining recirculation loop flow, total core flow and diffuser-to-lower plenum differential pressure for each jet pump and verifying l

that no two of the following conditions occur when the recirculation pumps are t operating in accordance with Specification 3.4.1.3.

a. The indicated recirculation loop flow differs by more than 10% from the established pump speed-loop flow characteristics.

b. The indicated total core flow differs by more than 10% from the established total core flow value derived from recirculation loop flow measurements.

c. The indicated diffuser-to-lower plenum differential pressure of any i individual jet pump differs from the established patterns by more than 10%.

l l l i l *During the startup test program, data shall be recorded for the parameters j listed to provide a ba, sis for establishing the specified relationships. l Comparisons of the actual data in accordance with the criteria listed shall commence upon conclusion of the startup test program. HOPE CREEK 3/4 4-4 i _ _ _ _ _ _ _ _ _ _ _ _

REACTOR COOLANT SYSTEM RECIRC'JLATION PUMPS LIMITING CONDITION FOR OPERATION 3.4.1.3 Recirculation pump speed shall be maintained within:

a. 5% of each other with core flow greater than or equal to 70% of rated core flow.

b. 10% of each other with core flow less than 70% of rated core flow.

APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2*. ACTION: With the recirculation pusp speeds different by more than the specified limits, either:

a. Restore the recirculation pump speeds to within the specified limit within 2 hours, or; b. Declare the rceirculation loop of the pump with the slower speed not
O in operation and take the ACTION required by Specification 3.4.1.1.

SURVEILLANCE REQUIREMENTS 4.4.1.3 Recirculation pump speed shall be verified to be within the limits at least once per 24 hours "See Special Test Exception 3.10.4. m U HOPE CREEK 3/4 4-5

REACTOR COOLANT SYSTEM IDLE RECIRCULATION LOOP STARTUP LIMITING CONDITION FOR OPERATION 3.4.1.4 An idle recirculation loop shall not be started unless the temperature differential between the reactor pressure vessel steam space coolant and the bottom head drain line coolant is less than or equal to 145 F and:

a. When both loops have been idle, unless the temperature differential between the reactor coolant within the idle loop to be started up and the coolant in the reactor pressure vessel is less than or equal to 50 F, or

b. When only one loop has been idle, unless the temperature differential between the reactor coolant within the idle and operating recircula-tion loops is less than or equal to 50 F and thc operating loop flow rate is less than or equal to 50% of rated loop flow.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4. ACTION: With temperature differences and/or flow rates exceeding the above limits, suspend startup of any idle recirculation loop. SURVEILLANCE REQUIREMENTS 4.4.1.4 The temperature differentials and flow rate shall be determined to be within the limits within 15 minutes prior to startup of an idle recirculation loop. O HOPE CREEK 3/4 4-6

REACTOR COOLANT SYSTEM 3/4.4.2 SAFETY / RELIEF VALVES SAFETY / RELIEF VALVES LIMITING CONDITION FOR OPERATION 3.4.2.1 The safety valve function of at least 13 of t coolantsystemsafety/reliefvalvesshallbeOPERABLE*gefollowingreactor with the specified code safety valve function lift settings:** 4 safety-relief valves @ 1108 psig 11% 5 safety-relief valves @ 1120 psig 11% 5 safety-relief valves @ 1130 psig 11% APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With the safety valve function of two or more of the above listed fourteen safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

O.

 \    b. With one or more safety / relief valves stuck open, provided that suppression pool average water temperature is less than 110 F, close the stuck open safety relief valve (s); if unable to close the stuck open valve (s) within 2 minutes or if suppression pool average water temperature is 110*F or greater, place the reactor mode switch in the Shutdown position.

c. With one or more of the above required safety / relief valve acoustic moni-tors inoperable, restore the inoperable monitors to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

      "SRVs which perform as ADS function must also satisfy the OPERABILITY requirements of Specification 3.5.1, ECCS-Operating.
      **The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.

1 #SRVs which perform a low-low set function must also satisfy the OPERABILITY requirements of Specification 3.2.2, Safety / Relief Valves Low-Low Set

  /m\  Function.

l HOPE CREEK 3/4 4-7

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.2.1 The acoustic monitor for each safety / relief valve shall be demonstrated OPERABLE with the setpoint verified to be < 30% of full open noise level ** by performance of a:

a. CHANNEL FUNCTIONAL TEST at least once per 31 days, and a

b. CHANNEL CALIBRATION at least once per 18 months *.

4.4.2.2 At least 1/2 of the safety relief valves shall be removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored in accordance with manufacturer's recommendations at least once per 18 months, and they shall be rotated such that all 14 safety relief valves are removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored in accordance with manufacturer's recommendations at least once per 40 months.

    *The provisions of Specification 4.0.4 are not applicable provided the Surveillance is pe.lormed within 12 hours after reactor steam pressure is adequate to perform the test.

4

  ** Initial setting shall be in accordance with the manufacturer's recommendations.

Adjustment to the valve full open noise level shall be accomplished during the startup test program. O HOPE CREEK 3/4 4-8

m REACTOR COOLANT SYSTEM (v h SAFETY / RELIEF VALVES LOW-LOW SET FUNCTION LIMITING CONDITION FOR OPERATION 3.4.2.2 The relief valve function and the low-low set function of the following reactor coolant system safety / relief valves shall be OPERABLE with the following settings: Low-Low Set Function Setpoint* (psig) f2% Valve No. Open Close F013H 1017 905 F013P 1047 935 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With the relief valve function and/or the low-low set function of one of the above required reactor coolant system safety / relief valves inoperable, restore the inoperable relief valve function and low-low set function G to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With the relief valve function and/or the low-low set function of both of the above required reactor coolant system safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

SURVEILLANCE REQUIREMENTS 4.4.2.2.1 The relief valve function and the low-low set function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a: l a. CHANNEL FUNCTIONAL TEST at least once per 31 days.

b. CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system (excluding actual valve actuation) at least once per 18 months.

l

      *The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.

HOPE CREEK 3/4 4-9 l l

l REACTOR C00LART SYSTEM 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.3.1 The following reactor coolant system leakage detection systems shall be OPERABLE:

a. The drywell atmosphere gaseous radioactivity monitoring system,*

b. The drywell floor and equipment drain sump monitoring system,

c. The drywell air cooler condensate flow rate monitoring system,

d. The drywell pressure monitoring system, and

e. The drywell temperature monitoring system.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With only four of the above required leakage detection systems OPERABLE, opera-tion may continue for up to 30 days provided grab samples of the containment atmosphere are obtained and analyzed at least once per 24 hours when the re-quired drywell atmosphere gaseous radioactivity monitoring system, the drywell pressure monitoring system, the drywell temperature monitoring system and/or the drywell air cooler condensate flow rate monitoring system is inoperable; otherwise, be in at least H0T SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.4.3.1 The reactor coolant system leakage detection systems shall be demonstrated OPERABLE by:

a. Drywell atmosphere gaseous radioactivity monitoring system performance of a CHANNEL CHECK at least once per 12 hours, a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.

b. The drywell pressure shall be monitored at least once per 12 hours and the drywell temperature shall be monitored at least once per 24 hours.

c. .Drywell floor and equipment drain sump monitoring system performance of a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION TEST at least once per 18 months.

d. Drywell air coolers condensate flow rate monitoring system performance of a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.

Not required to be OPERABLE prior to 150 days after initial fuel load.

HOPE CREEK 3/4 4-10

REACTOR COOLANT SYSTEM (~~S (U) OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.3.2 Reactor coolant system leakage shall be limited to:

a. No PRESSURE BOUNDARY LEAKAGE.

b. 5 gpm UNIDENTIFIED LEAKAGE.

c. 25 gpm IDENTIFIED LEAKAGE averaged over any 24-hour period.

d. 0.5 gpm leakage per nominal inch of valve size up to a maximum of 5 gpm from any reactor coolant system pressure isolation valve specified in Table 3.4.3.2-1, at rated pressure.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With any PRESSURE BOUNDARY LEAKAGE, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

b. With any reactor coolant system leakage greater than the limits in b and/or c, above, reduce the leakage rate to within the limits within

  -               4 hours or be in at least HOT SHUTDOWN within the next 12 hours and (m  '            in COLD SHUTOOWN within the following 24 hours,

c. With any reactor coolant system pressure isolation valve leakage greater than the above limit, isolate the high pressure portion of the affected system from the low pressure portion within 4 hours by use of at least one other closed manual or deactivated automatic or check

valves, or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

d. With one or more of the high/ low pressure interface valve leakage pressure monitors shown in Table 3.4.3.2-2 inoperable, restore the inoperable monitor (s) to OPERABLE status within 7 days or verify the pressure to be less than the alarm setpoint at least once per 12 hours; ;

restore the inoperable monitor (s) to OPERABLE status within 30 days ! or be in at least HOT SHUTDOWN within the next 12 hours and in COLD l SHUTDOWN within the following 24 hours.

       *Which have been verified not to exceed the allowable leakage limit at the last refueling outage or the after last time the valve was disturbed, whichever

! is more recent. l HOPE CREEK 3/4 4-11

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.3.2.1 The reactor coolant system leakage shall be demonstrated to be within each of the above limits by:

a. Monitoring the drywell atmospheric gaseous radioactivity at least once per 12 hours (not a means of quantifying leakage),

b. Monitoring the drywell floor and equipment drain sump flow rate at least once per 12 hours, and

c. Monitoring the drywell air coolers condensate flow rate at least once per 12 hours, and

d. Monitoring the drywell pressure at least once per 12 hours (not a means of quantifying leakage), and

e. Monitoring the reactor vessel head flange leak detection system at least once per 24 hours (not a means of quantifying leakage), and

f. Monitoring the drywell temperature at least once per 24 hours (not a means of quantifying leakage).

4.4.3.2.2 Each reactor coolant system pressure isolation valve specified in Table 3.4.3.2-1 shall be demonstrated OPERABLE by leak testing pursuant to Specification 4.0.5 and verifying the leakage of each valve to be within the specified limit:

a. At least once per 18 months, and

b. Prior to returning the valve to service following maintenance, repair or replacement work on the valve which could affect its leakage rate.

The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 3. 4.4.3.2.3 The high/ low pressure interface valve leakage pressure monitors shall be demonstrated OPERABLE with alarm setpoints per Table 3.4.3.2-2 by performance of a: l

a. CHANNEL FUNCTIONAL TEST at least once per 31 days, and i

b. CHANNEL CALIBRATION at least once per 18 months.

l O HOPE CREEK 3/4 4-12

1 O O TABLE 3.4.3.2-1 5 g REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES E A IST ISOLATION 2ND ISOLATION x VALVE (S) NUMBERS (S) VALVE (S) NUMBER (S) PRESSURE INDICATION SERVICE BE-V006 BE-V007 1-BE-PISH-N654A 'A' Core Spray / BE-V071 HPCI Injection BE-V002 BE-V003 1-BE-PISH-N654B 'B' Core Spray BE-V072 Injection

j BC-V114 BC-V113 1-BC-PISH-N653A 'A' LPCI Injection j BC-V119 l BC-V017 BC-V016 1-BC-PISH-N653B 'B' LPCI Injection

BC-V120 1

] $ BC-V102 BC-V121 BC-V101 1-BC-PISH-N653C 'C' LPCI Injection U BC-V005 BC-V004 1-BC-PISH-N6530 'D' LPCI Injection BC-V122 BC-V021 BC-V020 1-BC-PISH-N653B Head Spray a BC-Vill BC-V110 1-BC-PISH-N653A 'A' Shutdown Cooling BC-V117 Return to 'A' Recirc Loop BC-V014 BC-V013 1-BC-PISH-N653B 'B' Shutdown Cooling ! BC-V118 Return to 'B' Recirc Loop BC-V071 BC-V164 1-BC-PISH-NG57 Shutdown Cooling Supply From 'B' Recirc Loop i

l TABLE 3.4.3.2-2 REACTOR COOLANT SYSTEM INTERFACE VALVES LEAKAGE PRESSURE MONITORS ALARM ALARM SETPOINT ALLOWABLE SERVICE INSTRUMENT (psig) VALUE (psig) Core Spray 1-BE-PISH-N654A 475 $500 Core Spray 1-BE-PISH-N6548 475 1500 LPCI/RHR 1-BC-PISH-N653A 380 1410 LPCI/RHR 1-BC-PISH-N653B 380 5410 LPCI/RHR 1-BC-PISH-N653C 380 5410 LPCI/RHR 1-BC-PISH-N653D 380 5410 1 RHR 1-BC-PISH-N657 130 1155 O l i l 9 HOPE CREEK 3/4 4-14

REACTOR COOLANT SYSTEM I

Q 3/4.4.4 CHEMISTRY l LIMITING CONDITION FOR OPERATION 3.4.4 The chemistry of the reactor coolant system shall be maintained within the limits specified in Table 3.4.4-1. APPLICABILITY: At all times. ACTION:

a. In OPERATIONAL CONDITION 1:

1. With the conductivity, chloride concentration or pH exceeding the limit specified in Table 3.4.4-1 for less than 72 hours during one continuous time interval and, for conductivity and chloride concen-tration, for less than 336 hours per year, but with the conductivity less than 10 pmho/cm at 25*C and with the chloride concentration less than 0.5 ppm, this need not be reported to the Commission and the provisions of Specification 3.0.4 are not applicable.

2. With the conductivity, chloride concentration or pH exceeding the limit specified in Table 3.4.4-1 for more than 72 hours during one continuous time interval or with the conductivity and chloride concentration exceeding the limit specified in Table 3.4.4-1 for g3 more than 336 hours per year, be in at least STARTUP within the next b}

3. 6 hours. With the conductivity exceeding 10 pmho/cm at 25*C or chloride concentration exceeding 0.5 ppm, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

b. In OPERATIONAL CONDITION 2 and 3 with the conductivity, chloride concentration or pH exceeding the limit specified in Table 3.4.4-1 for l more than 48 hours during one continuous time interval, be in at least I HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

c. At all other times:

1. With the:

a) Conductivity or pH exceeding the limit specified in Table 3.4.4-1, restore the conductivity and pH to within the limit within 72 hours, or b) Chloride concentration exceeding the limit specified in Table 3.4.4-1, restore the chloride concentration to within the limit within 24 hours, or perform an engineering evaluation to determine the effects of the out of-limit condition on the structural integrity of the reactor coolant system. Determine that the structural integrity of the l reactor coolant system remains acceptable for continued operation prior to proceeding to OPERATIONAL CONDITION 3.

2. The provisions of Specification 3.0.3 are not applicable.

HOPE CREEK 3/4 4-15

l REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.4 The reactor coolant shall be determined to be within the specified chemistry limit by:

a. Measurement prior to pressurizing the reactor during each startup, if not performed within the previous 72 hours,

b. Analyzing a sample of the reactor coolant for:

1. Chlorides at least once per:

a) 72 hours, and b) 8 hours whenever conductivity is greater than the limit in Table 3.4.4-1.

2. Conductivity at least once per 72 hours.

3. pH at least once per:

a) 72 hours, and b) 8 hours whenever conductivity is greater than the limit in Table 3.4.4-1.

c. Continuously recording the conductivity of the reactor coolant, or, l

when the continuous recording conductivity monitor is inoperable, obtaining an in-line conductivity measurement at least once per:

1. 4 hours in OPERATIONAL CONDITIONS 1, 2 and 3, and

2. 24 hours at all other times.

d. Performance of a CHANNEL CHECK of the continuous conductivity monitor with an in-line flow cell at least once per:

1. 7 days, and

2. 24 hours whenever conductivity is greater than the limit in Table 3.4.4-1.

l l O l HOPE CREEK 3/4 4-16 l

 !                                                                                                                                                                   T l

i

 .         2 TABLE 3.4.4-1 k                                                               REACTOR COOLANT SYSTEM
 ;         n                                                                         CHEMISTRY LIMITS I

E R OPERATIONAL CONDITION CHLORIDES CONDUCTIVITY (pehos/cm @25*C) PH i 1 5 0.2 ppm 5 1.0 5.6 5 pH $ 8.6 , 2 and 3 5 0.1 ppm 52.0 5.6 5 pH $ 8.6

i At all other times 5 0.5 ppm 5 10.0 5.3 5 pH $ 8.6 i j I t Q. O l 0 l

i -4 I i

REACTOR COOLANT SYSTEM 3/4.4.5 SPECIFIC ACTIVITY LIMITING CONDITION FOR OPERATION 3.4.5 The specific activity of the primary coolant shall be limited to:

a. Less than or equal to 0.2 microcuries per gram DOSE EQUlvn. NT I-131, and

b. Less than or equal to 1004 microcuries per gram.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4. ACTION:

a. In OPERATIONAL CONDITIONS 1, 2 or 3 with the specific activity of the primary coolant;

1. Greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131 but less than or equal to 4.0 microcuries per gram DOSE EQUIVALENT I-131 for more than 48 hours during one continuous time interval or greater than 4.0 microcuries per gram DOSE EQUIVALENT I-131, be in at least HOT SHUTDOWN with the main steam line isolation valves closed within 12 hours.

2. Greater than 100/E microcuries per gram, be in at least HOT SHUTDOWN with the main steam line isolation valves closed within 12 hours.

b. In OPERATIONAL CONDITIONS 1, 2, 3 or 4, with ;he specific activity of the primary coolant greater than 0.2 niicrocuries per gram DOSE EQUIVALENT I-131 or greater than 1004 microcuries per gram, perform the sampling and analysis requirements of Item 4a of Table 4.4.5-1 until the specific activity of the primary coolant is restored to within its limit.

c. In OPERATIONAL CONDITION 1 or 2, with:

1. THERMAL POWER changed by more than 15% of RATED THERMAL POWER in one hour *, or

2. The off gas level, at the SJAE, increased by more than 10,000 microcuries per second in one hour during steady state operation at release rates less than 75,000 microcuries per second, or

3. The off gas level, at the SJAE, increased by more than 15% in one hour during steady state operation at release rates greater than 75,000 microcuries per second, perform the sampling and analysis requirements of Item 4b of i?ble 4.4.5-1 until the specific activity of the primary coolant is restored to within its limit.

Not applicable during the startup test program. HOPE CREEK 3/4 4-18

   .            -                 - .                .                     . - . . - - - -                      .     .  . -.-         . . . . - .         _- -. . ~ . - _ -

1 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4

,                                       4.4.5. The specific activity of the reactor coolant shall be demonstrated to i                                        be within the limits by performance of the sampling and analysis program of Table 4.4.5-1.                                                                                                                       !

l l 1 I I f l , ( i I i I h i s l l l i I i l HOPE CREEK 3/4 4-19 l

TABLE 4.4.5-1 O A PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM k OPERATIONAL CONDITIONS E TYPE OF MEASUREM(NT SAMPLE AND ANALYSIS IN WHICH SAMPLE AND ANALYSIS FREQUENCY AND ANALYSIS REQUIRED

1. Gross Beta and Gamma Activity At least once per 72 hours 1, 2, 3 Determination

2. Isotopic Analysis for DOSE At least once per 31 days 1 Et}UIVALENT I-131 Concentration

3. Radiochemical for E Determination At least once per 6 months

1

4. Isotopic Analysis for Iodine a) At least once per 4 hours, 1#, 2#, 3#, 4#

whenever the specific w activity exceeds a limit, 1 as required by ACTION b. b b) At least one sample, between 1, 2 2 and 6 hours following the change in THERMAL POWER or ! off gas level, as required by ACTION c.

5. Isotopic Analysis of an Off- At least once per 31 days 1 gas Sample Including Quantitative Measurements for at least Xe-133, Xe-135 and Kr-88

Sample to be taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours or longer.

   #Until the specific activity of the primary coolant system is restored to within its limits.

O O O

l l i REACTOR COOLANT SYSTEM [sh V 3/4.4.6 PRESSURE / TEMPERATURE LIMITS REACTOR COOLANT SYSTEM LIMITING CONDITION FOR OPERATION 3.4.6.1 The reactor coolant system temperature and pressure shall be limited in accordance with the limit lines shown on Figure 3.4.6.1-1 (1) curves A and A' for hydrostatic or leak testing; (2) curves B and B' for heatup by non-nuclear means, cooldown following a nuclear shutdown and low power PHYSICS TESTS; and (3) curves C and C' for operations with a critical core other than low power PHYSICS TESTS, with:

a. A maximum heatup of 100*F in any one hour period,

b. A maximum cooldown of 100*F in any one hour period,

c. A maximum temperature change of less than or equal to 20*F in any one hour period during inservice hydrostatic and leak testing opera-tions above the heatup and cooldown limit curves, and N

d. The reactor vessel flange and head flange metal temperature shall be maintained greater than or equal to 79*F when reactor vessel head bolting studs are under tension.

APPLICABILITY: At all times. ACTION: With any of the above limits exceeded, restore the temperature and/or pressure to within the limits within 30 minutes; perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the reactor coolant system; determine that the reactor coolant system remains acceptable for continued operations or be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.4.6.1.1 *During system heatup, cooldown and inservice leak and hydrostatic testing operations, the reactor coolant system temperature and pressure shall l be determined to be within the above required heatup and cooldown limits and to ! the right of the limit lines of Figure 3.4.6.1-1 curves A and A', B and B', or l C and C' as applicable, at least once per 30 minutes.

HOPE CREEK 3/4 4-21

l o REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) 4.4.6.1.2 The reactor coolant system temperature and pressure shall be determined to be to the right of the criticality limit line of Figure 3.4.6.1-1 l curves C and C' within 15 minutes prior to the withdrawal of control rods to i bring the reactor to criticality and at least once per 30 minutes during system heatup. 4.4.6.1.3 The reactor vessel material surveillance specimens shall be removed and examined, to determine changes in reactor pressure vessel material properties, as required by 10 CFR 50, Appendix H in accordance with the schedule in Table 4.4.6.1.3-1. The results of these examinations shall be used to update the curves of Figure 3.4.6.1-1 based on the greater of the following criteria:

a. The actual shift in reference temperature for plate material from heat 5K3238-1 and weld metal 510-01205 as determined by Charpy impact test, or

b. The predicted shift in reference temperatures for plate material from heat SK3025-1 as determined by Regulatory Guide 1.99, " Radiation Damage to Reactor Vessel Materials."

4.4.6.1.4 The reactor vessel flange and head flange temperature shall be verified to be greater than or equal to 70 F:

a. In OPERATIONAL CONDITION 4 when reactor coolant system temperature is:

1. $ 100 F, at least once per 12 hours.

! 2. 1 80*F, at least once per 30 minutes.

b. Within 30 minutes prior to and at least once per 30 minutes during tensioning of the reactor vessel head bolting studs.

l l O HOPE CREEK 3/4 4-22

                                                                                                                     \
                                                                                                                     \

A* A F S C* C A- SYSTEM MYOROTEST LeedlT WITN FUE L IN VESSE L S- NOENUCLE AR NEATING CORE SELTLINE AFTER 30*F f 3 C- eeuCLE AR ICORE CR4TICALI 1300 - guepygegoy g g Lauer gA3ED ON G. E. CO. LabelTiesGP 8 SWR LICEseBleeG TOPICAL REPORT NEDO.317M A ' A*. F. C' - CORE SE LTLle6E AFTER ANAm " D30apygup I f SMIFT FROM AN INITIAL

      )                                   f PLATE RTNOTOF 19 F 8

2 1880 - v,,,E L l f CURVES ARE NOT LatelT6NG

                                                                                       .so N ,oR ,e,- AT,0N aa'vl t          0 CONT =uiTv            !=         g twit g

I / NOn: E" ~ l / Curves A.s. Aae C ARE PREDICTED TO APPLY AS

                                              /                             THE LitetTS FOR 40 YEARS (32 EFPYI OF OPER ATION E                                     &

a f O i - -

i I .,EW ,. C.R ., APPENOtX G L-imimN f i I 312 880 SOLTUP 200 - 798F

0 I I i i 1 0 too 300 300 .00 300 eNNIMUM RE ACTOR VESSE L MET AL TEesPER ATURE (*FI l l MINIMUM REACTOR PRESSURE VESSEL METAL TEMPERATURE VS. REACTOR VESSEL PRESSURE Figure 3.4.6.1-1 ( HOPE CREEK 3/4 4-23

i TABLE 4.4.6.1.3-1 5 A REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM-WITHDRAWAL SCHEDULE k CAPSULE VESSEL LEAD WITHDRAWAL TIME y NUMBER LOCATION FACTOR @ % T (EFPY) 1 30* 1.20 6 2 120* 1.20 15 3 300* 1.20 EOL i W i l l 9 9 e

         ~x                         REACTOR COOLANT SYSTEM i

REACTOR STEAM DOME LIMITING CONDITION FOR OPERATION 3.4.6.2 The pressure in the reactor steam dome shall be less than 1020 psig. APPLICABILITY: OPERATIONAL CONDITION 1* and 2*. ACTION: With the reactor steam dome pressure exceeding 1020 psig, reduce the pressure to less than 1020 psig within 15 minutes or be in at least HOT SHUTDOWN within 12 hours.

            's                     SURVEILLANCE REQUIREMENTS 1

4.4.6.2 The reactor steam dome pressure shall be verified to be less than 1020 psig at least once per 12 hours. Not applicable during anticipated transients. i l HOPE CREEK 3/4 4-25

REACTOR COOLANT SYSTEM 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.4.7 Two main steam line isolation vafves (MSIVs) per main steam line shall be OPERABLE with closing times greater than or equal to 3 and less than or equal to 5 seconds. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more MSIVs inoperable:

1. Maintain at least one MSIV OPERABLE in each affected main steam line that is open and within 8 hours, either:

a) Restore the inoperable valve (s) to OPERABLE status, or b) Isolate the affecteo main steam line by use of a deactivated MSIV in the closed position.

2. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.4.7 Each of the above required MSIVs shall be demonstrated OPERABLE by verifying full closure between 3 and 5 seconds when tested pursuant to Specification 4.0.5. O HOPE CREEK 3/4 4-26

I i REACTOR COOLANT SYSTEM 3/4.4.8 STRUCTURAL INTEGRITY LIMITING CONDITION FOR OPERATION 3.4.8 The structural integrity of ASME Code Class 1, 2 and 3 components shall be maintained in accordance with Specification 4.4.8. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5. ACTION:

a. With the structural integrity of any ASME Code Class 1 component (s) not conforming to the above requirements, restore the structural integrity of the affected component (s) to within its limit or isolate the affected component (s) prior to increasing the Reactor Coolant System temperature more than 50*F above the minimum temperature required by NDT considerations.

b. With the structural integrity of any ASME Code Class 2 component (s) not conforming to the above requirements, restore the structural integrity of the affected component (s) to within its limit or isolate the affected component (s) prior to increasing the Reactor Coolant System temperature above 200*F.

c. With the structural integrity of any ASME Code Class 3 component (s) not conforming to the above requirements, restore the structural integrity of the affected component (s) to within its limit or isolate the affected component (s) from service.

d. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.4.8 No reauirements other than Specification 4.0.5. HOPE CREEK 3/4 4-27

E REAC(0Rh00LANTSYSTEM [ 3/4.4.9 RSI?UALHEATREMOVAL HOTbh0T00WN , LIMITING, CONDITION FOR OPERATION - 3 :4. 9.1 Two# shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at least one shutdown cooling mode loop shall be in operation *'N , with each loop consisting of:

a. One OPERABLE RHR puap, and ,

b. . One OPERABLE RHR N5t' okchanger. t APPLICABILITY: OPERATIONALCONCITION.3,withreactordesselpressurelessthan the RHR cut-in permissive setpoint.

_AC_ TION: a.' With'less than the above required RHR shutdown cooling mode loops OPERABLE, immediately initiate corrective action to returt toe required loops to 5 OPERABLE status is soon as possible. . Withir.ione hour and at deast once per 24 hours thereafter, demonstrate the operability of at least one alcernate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop. Be in at least COLD SHUT 90WN within 24 hours.**

3. With no RHR shutdown cooling mode 1 cop ori:ecircylation pump in operation, imaediately initiate corrective action tc' return 'at least one loop to operation as soon as possible. Within one hour establish reactor coolant l circulation by an alternate methc,d'an& monitor ecactor coolant temperature and pressure at least once per hour.,

\ /

c. The provisions of Specification 3.0.4 are not' applicable.

1 SURVEILLANCE REQUIREMENTS l 4.4.9.1 At least one shutdown cooling mode loop _of the' residual heat removal system, one recirculation pump, or alternate method shall be determined to be in operation and circulating reactor coolant at least once per.12 hours.

    #0ne RHR shutdown cooling mode loop may be iroper ble for up to 2 hours for l      surveilknce testing provided the other 1 cop f r. OPERABLE and in operation' or at least one recirculation pump is in operation.

! *The shutdown cooling pump may be removed fro::' operation for up to 2 hours per 8 hour period provided the other loop is OPERABLE.

   ##The RHR shutdown coojing mode loop may be removed from operation during hyd.cstatic testing.                   '
   **Wheneser two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, ma'ntain reactor coolant temperature as low hs1 practical by use of alternate heat, removal methods.

HOPE CREEK 3/4 4-28

REACTOR COOLANT SYSTEM (Vh COLD SHUTOOWN LIMITING CONDITION FOR OPERATION 3.4.9.2 Two# shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at least one shutdown cooling mode loop shall be in operation *'## with each loop consisting of:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITION 4 and heat ' asses to ambient* are not sufficient to maintain OPERATIONAL CONDITION 4. ACTION:

a. With less than the above required RHR shutdown cooling mode loops OPERABLE, within one hour and at least once per 24 hours thereafter, demonstrate the operability of at least one alternate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop.

(A V) b. With no RHR shutdown cooling mode loop or recirculation pump in operation, within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature and pressure at least once per hour.

c. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.4.9.2 At least one shutdown cooling mode loop of the residual heat removal system, recirculation pump or alternate method shall be determined to be in operation and circulating reactor coolant at least once per 12 hours.

    #0ne RHR shutdown cooling mode loop may be inoperable for up to 2 hours for surveillance testing provided the other loop is OPERABLE and in operation or at least one recirculation pump is in operation.
     *The shutdown cooling pump may be removed from operation for up to 2 hours per 8 hour period provided the other loop is OPERABLE.
   ##The shutdown cooling mode loop may be removed from operation during f-    hydrostatic testing.

\ ** Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though COLD SHUTDOWN conditions are being maintained). HOPE CREEK 3/4 4-29

l 3/4.5 EMERGENCY CORE COOLING SYSTEMS V 3/4.5.1 ECCS - OPERATING LIMITING CONDITION FOR OPERATION 3.5.1 The emergency core cooling systems shall be OPERABLE with:

a. The core spray system (CSS) consisting of two subsystems with each subsystem comprised of:

1. Two OPERABLE core spray pumps, and

2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water through the spray sparger to the reactor vessel.

b. The low pressure coolant injection (LPCI) system of the residual heat removal system consisting of four subsystems with each subsystem comprised of:

1. One OPERABLE LPCI pump, and

2. An OPERABLE flow path capable of taking suction from the C suppression chamber and transferring the water to the reactor

( vessel.

c. The high pressure coolant injection (HPCI) system consisting of:

1. One OPERABLE HPCI pump, and

2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.

1 ! d. The automatic depressurization system (ADS) with five OPERABLE ADS ! valves. I l APPLICABILITY: OPERATIONAL CONDITION 1, 2*, ** #, and 3*, **, ##. A The HPCI system is not required to be OFERABLE when reactor steam dome pressure is less than or equal to 200 psig. AA The ADS is not required to be OPERABLE when reactor steam dome pressure is less than or equrl to 100 psig.

        #See Special Test Exception 3.10.G.

Two LPCI subsystems of the RHR system may be inoperable in that they are n aligned in the shutdown cooling mode when the reactor vessel pressure is l / \ less than the RHR shutdown cooling permissive setpoint. b HOPE CREEK 3/4 5-1

EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION:

a. For the Core Spray system:

1. With one core spray subsystem inoperable, provided that at least two LPCI subsystem are OPERABLE, restore the inoperable core spray subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

2. With both core spray subsystems inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

b. For the LPCI system:

1. With one LPCI subsystem inoperable, provided that at least one core spray subsystem is OPERABLE, restore the inoperable LPCI subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

2. With two LPCI subsystems inoperable, provided that at least one core spray subsystem is operable, restore at least one LPCI subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

3. With three LPCI subsystems inoperable, provided that both core spray subsystems are OPERABLE, restore at least two LPCI subsystems to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

4. With all four LPCI subsystems inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.*

c. For the HPCI system, provided the Core Spray System, the LPCI system, the ADS and the RCIC system are OPERABLE:

Whenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

O HOPE CREEK 3/4 5-2 l l l

EMERGENCY CORE COOLING SYSTEMS b LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued)

1. With the HPCI system inoperable, restore the HPCI system to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours and reduce reactor steam dome pressure to 5 200 psig within the following 24 hours.

d. For the ADS:

1. With one of the above required ADS valves inoperable, provided the HPCI system, the core spray system and the LPCI system are OPERABLE, restore the inoperable ADS valve to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours and reduce reactor steam dome pressure to < 100 psig within the next 24 hours.

2. With two or more of the above required ADS valves inoperable, be in at least H0T SHUTOOWN within 12 hours and reduce reactor steam dome pressure to 5 100 psig within the next 24 hours,

e. With a CSS and/or LPCI header AP instrumentation channel inoperable, restore the inoperable channel to OPERABLE status within 7 days or A)

(V determine the ECCS header AP locally at least once per 12 hours; otherwise, declare the associated ECCS subsystem inoperable.

f. With a LPCI and/or CCS discharge line " keep filled" alarm instru-mentation inoperable, perform Surveillance Requirement 4.5.1.a.1.a.

g. In the event an ECCS system is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and sub-mitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.

O HOPE CREEK 3/4 5-3

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.1 The emergency core cooling systems shall be demonstrated OPERABLE by:

a. At least once per 31 days:

1. For the core spray system, the LPCI system, and the HPCI system:

a) Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water, b) Verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct

position.

2. For the HPCI system, verifying that the HPCI pump flow controller is in the correct position.

b. Verifying that, when tested pursuant to Specification 4.0.5:

1. The two core spray system pumps in each subsystem together develop a flow of at least 6350 gpm against a test line pressure corresponding to a reactor vessel pressure of 2 105 psi above suppression pool pressure.

2. Each LPCI pump in each subsystem develops a flow of at least 10,000 gpm against a test line pressure corresponding to a reactor vessel to primary containment differential pressure of 2 20 psid.

3. The HPCI pump develops a flow of at least 5600 gpm against a test line pressure corresponding to a reactor vessel pressure of 1000 psig when steam is being supplied to the turbine at 1000,

                 +20, -80 psig.**

c. At least once per 18 months:

1. For the core spray system, the LPCI system, and the HPCI system, performing a system functional test which includes simulated auto-matic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. Actual injection of coolant into the reactor vessel may be excluded from this test.

*Except that an automatic valve capable of automatic return to its ECCS position when an ECCS signal is present may be in position for another mode of operation.

- The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the test.

HOPE CREEK 3/4 5-4

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

2. For the HPCI system, verifying that:

a) The system develops a flow of at least 5600 gpm against a test line pressure corresponding to a reactor vessel pressure of > 200 psig, when steam is being supplied to the turbine at 200 + 15, -0 psig.** b) The suction is automatically transferred from the condensate storage tank to the suppression chamber on a condensate storage tank water level - low signal and on a suppression chamber - water level high signal.

3. Performing a CHANNEL CALIBRATION of the CSS, and LPCI system discharge line " keep filled" alarm instrumentation.

4. Performing a CHANNEL CALIBRATION of the CSS header AP instrumenta-tion and verifying the setpoint to be 1 the allowable value of 4.4 psid.#

5. Performing a CHANNEL CALIBRATION of the LPCI header AP instrumen-tation and verifying the setpoint to be i the allowable value of 1.0 psid.#

d. For the ADS:

1. At least once per 31 days, performing a CHANNEL FUNCTIONAL TEST of the Primary Containment Instrument Gas System low-low pressure alarm system.

2. At least once per 18 months:

a) Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence, but excluding actual valve actuation. b) Manually opening each ADS valve when the reactor steam dome pressure is greater than or equal to 100 psig** and observing that either:

1) The control valve or bypass valve position responds accordingly, or

2) There is a corresponding change in the measured steam flow.

c) Performing a CHANNEL CALIBRATION of the Primary Containment Instrument Gas System low-low pressure alarm system and verifying an alarm setpoint of 85 + 2 psig on decreasing pressure.

**The provisions of Specification 4.0.4 are not applicable providad the surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the test.
 # Initial setpoint. Final setpoint to be determined during the startup test program.

HOPE CREEK 3/4 5-5

EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.5.2 At least two of the following shall be OPERABLE:

a. Core spray system subsystems with a subsystem comprised of:

1. Two OPERABLE core spray pumps, and

2. An OPERABLE flow path capable of taking suction from at least one of the following water sources and transferring the water through the spray sparger to the reactor vessel:

a) From the suppression chamber, or b) When the suppression chamber water level is less than the limit or is drained, from the condensate storage tank containing at least 135,000 available gallons of water.

b. Low pressure coolant injection (LPCI) system subsystems each with a subsystem comprised of:

1. One OPERABLE LPCI pump, and

2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.

APPLICABILITY: OPERATIONAL CONDITION 4 and 5*. ACTION: I

a. With one of the above required subsystems inoperable, restore at

( least two subsystems to OPERABLE status within 4 hours or suspend l all operations with a potential for draining the reactor vessel. l b. With both of the above required subsystems inoperable, suspend CORE ALTERATIONS and all operations with a potential for draining the reactor vessel. Restore at least one subsystem to OPERABLE status i within 4 hours or establish SECONDARY CONTAINMENT INTEGRITY within j the next 8 hours. i

 *The ECCS is not required to be OPERABLE provided that the reactor vessel head l  is removed, the cavity is flooded, the spent fuel pool gates are removed, and water level is maintained within the limits of Specification 3.9.8 and 3.9.9.

O HOPE CREEK 3/4 5-6

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2.1 At least the above required ECCS shall be demonstrated OPERABLE per I Surveillance Requirement 4.5.1. 4.5.2.2 The core spray system shall be determine OPERABLE at least once per 12 hours by verifying the condensate storage tank required volume when the condensate storage tank is required to be OPERABLE per Specification 3.5.2.a.2.b. l 1 I HOPE CREEK 3/4 5-7

EMERGENCY CORE COOLING SYSTEMS l 3/4.5.3 SUPPRESSION CHAMBER l LIMITING CONDITION FOR OPERATION l i 3.5.3 The suppression chamber shall be-0PERABLE: l a. In OPERATIONAL CONDITION 1, 2 and 3 with a contained water volume of I at least 118,000 ft 3, equivalent to an indicated level of 74.5".

b. In OPERATIONAL CONDITION 4 and 5* with a contained volume of at least 57,390 ft 3, equivalent to an indicated level of 5.0" except that the suppression charrber level may be less than the limit or may be i

drained provided that:

1. No operations are performed that have a potential for draining the reactor vessel,

2. The reactor mode switch is locked in the Shutdown or Refuel position,

3. The condensate storage tank contains at least 135,000 available i

gallons of water, and A. The core spray system is OPERABLE per Specification 3.5.2 with j an OPERABLE flow path capable of taking suction from the condensate storage tank and transferring the water through the spray sparger to the reactor vessel. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5*. ACTION:

a. In OPERATIONAL CONDITION 1, 2 or 3 with the suppression chamber water l

1evel less than the above limit, restore the water level to within the limit within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. In OPERATIONAL CONDITION 4 or 5* with the suppression chamber water level less than the above limit or drained and the above required conditions not satisfied, suspend CORE ALTERATIONS and all operations I that have a potential for draining the reactor vessel and lock the reactor mode switch in the Shutdown position. Establish SECONDARY CONTAINMENT INTEGRITY within 8 hours.

 *The suppression chamber is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded or being flooded from

! the suppression pool,'the spent fuel pool gates are removed when the cavity I is flooded, and the water level is maintained within the limits of Specification 3.9.8 and 3.9.9. HOPE CREEK 3/4 5-8

EMERGENCY CORE COOLING SYSTEMS O SURVEILLANCE REQUIREMENTS 4.5.3.1 The suppression chamber shall be determined OPERABLE by verifying the water level to be greater than or equal to:

a. 74.5" at least once per 24 hours in OPERATIONAL CONDITIONS 1, 2, and 3.

b. 5.0" at least once per 12 hours in OPERATIONAL CONDITIONS 4 and 5*.

4.5.3.2 With the suppression chamber level less than the above limit or drained in OPERATIONAL CONDITION 4 or 5*, at least once per 12 hours:

a. Verify the required conditions of Specification 3.5.3.b to be satisfied, or

b. Verify footnote conditions

to be satisfied.

HOPE CREEK 3/4 5-9 i - - - - - . - - -

i 3/4.6 CONTAINMENT SYSTEMS l O V 3/4.6.1 PRIMARY CONTAINMENT I PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION

3. 6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. t ACTION: i . Without PRIMARY CONTAINMENT INTEGRITY, restore PRIMARY CONTAINMENT INTEGRITY j within 1 hour or be in at least NOT SHUTDOWN within the next 12 hours and in j COLD SHUTDOWN within the following 24 hours. l l SURVEILLANCE REQUIREMENTS < } 2 3 4. 6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:

a. After each closing of each penetration subject to Type 8 testing, except the primary containment air locks, if opened following Type A

! or B test, by leak rate testing the seals with gas at Pa, 48.1 psig, . and verifying that when the measured leakage rate for these seals is j added to the leakage rates determined pursuant to Surveillance ! Requirement 4.6.1.2.d for all other Type 8 and C penetrations, the j combined leakage rate is less than or equal to 0.60 La. I

b. At least once per 31 days by verifying that all primary containment 4 penetrations ** not capable of being closed by OPERABLE containment automatic isolation valves and required to be closed during accident

, conditions are closed by valves, blind flanges, or deactivated l automatic valves secured in position, except as provided in Table 3.6.3-1 of Specification 3.6.3.

c. By verifying each primary containment air lock is in compliance with

!. the requirements of Specification 3.6.1.3.

d. By verifying the suppression chamber is in compliance with the requirements of Specification 3.6.2.1.
*See Special Test Exception 3.10.1
**Except valves, blind flanges, and deactivated automatic valves which are located inside the primary containment, and are' locked, sealed or otherwise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except such verification need not be performed when the i

primary containment,has not been de-inerted since the last verification or more often than once per 92 days. l i l HOPE CREEK 3/4 6-1 l 1 f

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT LEAKAGE LIMITING CONDITION FOR OPERATION 3.6.1.2 Primary containment leakage rates shall be limited to:

a. An overall integrated leakage rate of less than or equal tc L , 0.5 per-cent by weight of the containment air per 24 hours at Pa ' 40 1 psig.

b. A combined leakage rate of less than or equal to 0.60 L for all penetrationsandallvalveslistedinTable3.6.3-1,ex8eptformain steam line isolation valves *, valves which form the boundary for the long-term seal of the feedwater lines, and other valves which are hydrostatically tested per Table 3.6.3-1, subject to Type B and C tests when pressurized to Pa , 48.1 psig.

c. *Less than or equal to 46.0 scfh combined through all four main steam lines when tested at 5 psig (seal system AP).

d. A combined leakage rate of less than or equal to 10 gpm for all con-tainment isolation valves which form the boundary for the long-term seal of the feedwater lines in Table 3.6.3-1, when tested at 1.10 Pa, 52.9 psig.

e. A combined leakage rate of less than or equal to 10 gpm for all other containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment, when tested at Pa, 48.1 psig Ap.

APPLICABILITY: When PRIMARY CONTAINMENT INTEGRITY is required per Specification 3.6.1.1. ACTION: With:

a. The measured overall integrated primary containment leakage rate exceeding 0.75 L, or

b. The measured combined leakage rate for all penetrations and all valves listed in Table 3.6.3-1, except for main steam line isolation valves *, valves which form the boundary for the long-term seal of the feedwater lines, and other valves which are hydrostatically tested per Table 3.6.3-1, subject to Type B and C tests exceeding 0.60 L 3 , or

c. The measured leakage rate exceeding 46.0 scfh combined through all four main steam lines, or

d. The measured combined leakage rate for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines in Table 3.6.3-1 exceeding 10 gpm, or

e. The measured combined leakage rate for all other containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment exceeding 10 gpm, restore:

a. The overall integrated leakage rate (s) to less than or equal to 0.75 La, and

Exemption to Appendix "J" of 10 CFR 50.

HOPE CREEK 3/4 6-2

1 l CONTAINMENT SYSTEMS

; p   LIMITING CONDITION FOR OPERATION (Continued)

U ACTION (Continued)

b. The combined leakage rate for all penetrations and all valves listed !

in Table 3.6.3-1, except for main steam line isolation valves *, valves I which form the boundary for the long-term seal of the feedwater lines, and other valves which are hydrostatically tested per Table 3.6.3-1, subject ! to Type B and C tests to less than or equal to 0.60 L,, and

c. The leakage rate to less than or equal to 46.0 scfh combined through all four main steam lines, and

d. The combined leakage rate for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines in Table 3.6.3-1 to less than or equal to 10 gpm, and

e. The combined leakage rate for all other containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment to less than or equal to 10 gpm, prior to increasing reactor coolant system temperature ai,0ve 200*F.

i SURVEILLANCE REQUIREMENTS 4.6.1.2 The primary containment leakage rates shall be demonstrated at the following test schedule and shall be determined in conformance with the criteria specified in Appendix J of 10 CFR 50 using the methods and provisions of ANSI

,y    N45.4 - 1972:

a. Three Type A Overall Integrated Containment Leakage Rate tests shall be conducted at 40 + 10 month intervals during shutdown at P,,

48.1 psig, during each 10 year service period. The third test of each set shall be conducted during the shutdown for the 10 year plant inservice inspection. I b. If any periodic Type A test fails to meet 0.75 L,, the test schedule for subsequent Type A tests shall be reviewed and approved by the Commission. If two consecutive Type A tests fail to meet 0.75 L,, a Type A test shall be performed at least every 18 months until two ! consecutive Type A tests meet 0.75 L,, at which time the above test schedule may be resumed. j c. The accuracy of each Type A test shall be verified by a supplemental test which:

                      .1.        Confirms the accuracy of the test by verifying that the difference between the supplemental data and the Type A test data is within 0.25 L,.

2. Has duration cufficient to establish accurately the change in leakage rate between the Type A test and the supplemental test.

3. Require's the quantity of gas injected into the containment or '

bled from the containment during the supplemental test to be l \ between 0.75 L, and 1.25 L,.

Exemption to Appendix "J" of 10 CFR 50.

HOPE CREEK 3/4 6-3

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) The formula to be used is: [L, + L am - 0.25 L,] 5 Lc I El o +l am

0.25 L,] where L c E supplement test result; L a g superimposed leakage; and L, a measured Type A leakage.

d. Type B and C tests shall be conducted with gas at P,, 48.1 psig*,

at intervals no greater than 24 months except for tests involving:

1. Air locks,

2. Main steam line isolation valves,

3. Valves pressurized with fluid from a seal system,

4. All containment isolation valves in hydrostatically tested lines

;                                         in Table 3.6.3-1 which penetrate the primary containment, and

5. Purge supply and exhaust isolation valves with resilient material seals.

e. Air locks shall be tested and demonstrated OPERABLE per Surveillance Requirement 4.6.1.3.

f. Main steam line isolation valves shall be leak tested at least once per 18 months.

g. Containment isolation valves which form the boundary for the long-term seal of the feedwater lines in Table 3.6.3-1 shall be hydrostati-cally tested at 1.10 P,, 52.9 psig, at least once per 18 months.

h. All containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment shall be leak tested at least once per 18 months,

i. Purge supply and exhaust isolation valves with resilient material seals shall be tested and demonstrated OPERABLE per Surveillance Requirements 4.6.1.8.2 and 4.6.1.8.3.

j. The provisions of Specification 4.0.2 are not applicable to l

Specifications 4.6.1.2.a 4.6.1.2.b, 4.6.1.2.c, 4.6.1.2.d, and 4.6.1.2.e.

   *Unless a hydrostatic test is required per Table 3.6.3-1.

O HOPE CREEK 3/4 6-4

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCKS LIMITING CONDITION FOR OPERATION 3.6.1.3 Each primary containment air lock shall be OPERABLE with:

a. Both doors closed except when the air lock is being used for normal transit entry and exit through the containment, then at least one air lock door shall be closed, and

b. An overall air lock leakage rate of less than or equal to 0.05 L, at P,, 48.1 psig.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. ACTION:

a. With one primary containment air lock door inoperable:

1. Maintain at least the OPERABLE air lock door closed and either restore the inoperable air lock door to OPERABLE status within 24 hours or lock the OPERABLE air lock door closed.

t/ 2. Operation may then continue until performance of the next required overall air lock leakage test provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.

3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.; 4. The provisions of Specification 3.0.4 are not applicable.; b. With the primary containment air lock inoperable, except as a result of an inoperable air lock door, maintain at least one air lock door closed;
restore the inoperable air lock to OPERABLE status within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

    "See Special Test Exception 3.10.1.

lb HOPE CREEK 3/4 6-5

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.1.3 Each primary containment air lock shall be demonstrated OPERABLE:

a. Within 72 hours following each closing, except when the air lock is being used for multiple entries, then at least once per 72 hours, by verifying seal leakage rate less than or equal to 5 scf per hour when the gap between the door seals is pressurized to 10.0 psig.

b. By conducting an overall air lock leakage test at P , 48.1 psig, and by verifying that the overall air lock leakage fate is within its I'mit:

1. At least once per 6 months #, and

2. Prior to establishing PRIMARY CONTAINMENT INTEGRITY when maintenance has been performed on the air lock that could affect the airlock sealing capability *, and

3. Prior to establishing PRIMARY CONTAINMENT INTEGRIiY when main-tenance has not been performed on the air lock that could affect the air lock sealing capability, a seal test may be performed in lieu of the overall air lock leakage test. The acceptance criteria and test pressure shall be as specified in 4.6.1.3.a.

c. At least once per 6 months by verifying that only one door in each air lock can be opened at a time.**

l l l l l l ! The provisions of Specification 4.0.2 are not applicable.

Exemption to Appendix J of 10 CFR 50.

l

  **Except that the inner door need not be opened to verify interlock OPERABILITY

when the primary containment is inerted, provided that the inner door interlock is tested within 8 hours after the primary containment has been de-inerted.

HOPE CREEK 3/4 6-6

CONTAINMENT SYSTEMS

    )   MSIV SEALING SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.4 Two independent MSIV sealing system (MSIVSS) subsystems shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With one MSIV sealing system subsystem inoperable, restore the inoperable sub-system to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.4 Each MSIV sealing system subsystem shall be demonstrated OPERABLE:

a. At least once per 92 days by cycling each testable motor-operated valve except the Main Steam Stop Valves (MSSVs) through at least one complete cycle of full travel.

b. During each COLD SHUTDOWN, if not performed within the previous 92 days, by cycling each motor-operated valve including the Main v Steam Stop Valves (MSSVs) not testable during operation through a least one complete cycle of full travel.

, c. At least once per 18 months by performance of a functional test of the subsystem throughout its operating sequence, and verifying that each interlock and timer operates as designed and each automatic j valve actuates to its correct position.

d. By verifying the control instrumentation to be OPERABLE by performance of a:

1. CHANNEL CHECK at least once per 24 hours,

2. CHANNEL FUNCTIONAL TEST at least once per 92 days, and

3. CHANNEL CALIBRATION at least once per 18 months. f I

l HOPE CREEK 3/4 6-7 _ .-. . . _ _ _ -. _ - - . . . - _ --______.-_-.--_-___--___A

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT STRUCTURAL INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.5 The structural integrity of the primary containment shall be maintained at a level consistent with the acceptance criteria in Specification 4.6.1.5.1. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the structural integrity of the primary containment not conforming to the above requirements, restore the structural integrity to within the limits within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.5.1 The structural integrity of the exposed accessible interior and exterior surfaces of the primary containment shall be determined during the shutdown for each Type A containment leakage rate test by a visual inspection of those surfaces. This inspection shall be performed prior to the Type A containment leakage rate test to verify no apparent changes in appearance or other abnormal degradation. 4.6.1.5.2 Reports Any abnormal degradation of the primary containment struc-ture detected during the above required inspections shall be reported to the Commission pursuant to Specification 6.9.2 within 30 days. This report shall include a description of the condition of the containment, the inspection pro-cedure, and the corrective actions taken. O HOPE CREEK 3/4 6-8

l p CONTAINMENT SYSTEMS d DRYWELL AND SUPPRESSION CHAMBER INTERNAL PRESSURE l LIMITING CONDITION FOR OPERATION , l 3.6.1.6 Drywell and suppression chamber internal pressure shall be maintained i between -0.5 and +1.5 psig. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the drywell and/or suppression chamber internal pressure outside of the specified limits, restore the internal pressure to within the limit within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, b SURVEILLANCE REQUIREMENTS 4.6.1.6 The drywell and suppression chamber internal pressure shall be determined to be within the limits at least once per 12 hours. HOPE CREEK 3/4 6-9

CONTAINMENT SYSTEMS DRYWELL AVERAGE AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.7 Drywell average air temperature shall not exceed 135*F. APPLICA8ILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the drywell average air temperature greater than 135*F, reduce the average air temperature to within the limit within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.7 The drywell average air temperature shall be the volumetric average of the temperatures at the following locations and shall be determined to be within the limit at least once per 24 hours: Elevation Zone Approximate Azimuth *

a. 86'11"-112'8" 90", 225*, 90", 270*

(under vessel) 135*, 300", 100*, 190*

b. 86'11"-111'10" (outside of pedestal) i c. 111'10"-139'2" 55*, 240*, 155*, 315" l

! d. 139'2"-168'0" 45*, 215*, 0", 90*, 180*, 270* l

e. 168'0"-192'7" 95*, 130*, 300 , 355*,

t 45*, 225" i i l

   *At least one reading from each elevation zone is required for a volumetric average calculation.

I HOPE CREEK 3/4 6-10

i l l A CONTAINMENT SYSTEMS DRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.8 The 26-inch drywell purge supply and exhaust isolation valves and the 24-inch suppression chamber purge supply and exhaust isolation valves, and the 6-inch nitrogen supply valve shall be OPERABLE and sealed closed.* APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With a 26-inch drywell purge supply or exhaust isolation valve, or a 24-inch suppression chamber purge supply or exhaust isolation valve or the 6-inch nitrogen supply valve open or not sealed closed,* close or seal the valves (s) or otherwise isolate the penetration within four hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With a drywell purge supply or exhaust isolation valve, or a suppression chamber purge supply or exhaust isolation valve or the nitrogen supply valve, with resilient material seals having a measured leakage rate exceed-ing the limit of Surveillance Requirements 4.6.1.8.2 and/or 4.6.1.8.3, re-p)

V store the inoperable valve (s) to OPERABLE status within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.8.1 Each 26-inch drywell purge supply and exhaust isolation valve, and 24-inch suppression chamber purge supply and exhaust isolation valve and the 6-inch nitrogen supply valve, shall be verified to be sealed closed

at least once per 31 days.

4.6.1.8.2 At least once per 6 months on a STAGGERED TEST BASIS each sealed closed 26-inch drywell purge supply and exhaust isolation valve, and 24-inch suppression chamber purge supply and exhaust isolation valve, and the 6-inch

nitrogen supply valve, with resilient material seals shall be demonstrated l OPERABLE by verifying that the measured leakage rate is less than or equal to 0.05 L, per penetration when pressurized to P, 48.1 psig.

4.6.1.8.3 At least once per 92 days the 26-inch drywell purge inboard exhaust isolation valve with resilient material seals shall be demonstrated OPERABLE by verifying *that the measured leakage rate is less than or equal to 0.05 L, per penetration when pressurized to P, 48.1 psig. O V

    *The 26-inch drywell purge inboard exhaust valve is not required to be sealed closed and may be opened in series with the 2 inch vent line bypass valve dur-ing periods of containment pressure control.

HOPE CREEK 3/4 6-11 l

CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION SYSTEMS SUPPRESSION CHAMBER LIMITING CONDITION FOR OPERATION 3.6.2.1 The suppression chamber shall be OPERABLE with:

a. The pool water:

1. Volume between 118,0003ft and 122,000 ft3 , equivalent to an indicated level between 74.5" and 78.5" and a

2. Maximum average temperature of 95*F during OPERATIONAL CONDITION 1 or 2, except that the maximum average temperature may be permitted to increase to:

a) 105 F during testing which adds heat to the suppression chamber. b) 110 F with THERMAL POWER less than or equal to 1% of RATED THERMAL POWER.

3. Maximum average temperature of 95*F during OPERATIONAL CONDITION 3, except that the maximum average temperature may be permitted to increase to 120*F with the main steam line isolation valves closed following a scram.

b. A total leakage between the suppression chamber and drywell of less than the equivalent leakage through a 1-inch diameter orifice at a differential pressure of 0.80 psig.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: l

a. With the suppression chamber water level outside the above limits, restore the water level to within the limits within I hour or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. With the suppression chamber average water temperature greater than 95*F and THERMAL POWER greater than 1% of RATED THERMAL POWER, restore t

l the average temperature to less than or equal to 95"F within 24 hours I or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, except, as permitted above:

1. With the suppression chamber average water temperature greater than 105"F during testing which adds heat to the suppression chamber, stop all testing which adds heat to the suppression chamber and restore the average temperature to less than 95*F within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours.

2. With the suppression chamber average water temperature greater than 110*F, place the reactor mode switch in the Shutdown posi-tion and operate at least one residual heat removal loop in the suppression pool cooling mode.

HOPE CREEK 3/4 6-12

1

p. CONTAINMENT SYSTEMS l LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

3. With the suppression chamber average water temperature greater than 120*F, depressurize the reactor pressure vessel to less than 200 psig within 12 hours.

c. With one suppression pool water temperature monitoring channel inoperable, restore the inoperable channel (s) to OPERABLE status within 7 days or verify suppression pool temperature to be within the limits at least once per 12 hours.

d. With both suppression pool water temperature monitoring channels inoperable, restore at least one inoperable channel to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

,            e. With one suppression chamber water level instrumentation channel in-operable, restore the inoperable narrow range suppression chamber i                 water level channel to OPERABLE status within 7 days or verify sup-pression pool water level to be within the limits at least once per 12 hours.

f. With both suppression chamber water level instrumentation channels inoperable, restore at least one narrow range suppression chamber (O

V

     )            water level channel to OPERABLE status within 48 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

g. With the drywell-to-suppression chamber bypass leakage in excess of the limit, restore the bypass leakage to within the limit prior to increasing reactor coolant temperature above 200 F.

SURVEILLANCE REQUIREMENTS 4.6.2.1 The suppression chamber shall be demonstrated OPERABLE:

a. By verifying the suppression chamber water volume to be within the limits at least once per 24 hours,

b. At least once per 24 hours in OPERATIONAL CONDITION 1 or 2 by verifying the suppression chamber average water temperature to be less than or i equal to 95*F, except:

! 1. At least once per 5 minutes during testing which adds heat to

                  +      the suppression chamber, by verifying the suppression chamber average water temperature less than or equal to 105"F.

2. At least once per hour when suppression chamber average water temperature is greater than 95*F, by verifying:

a) Suppression chamber average water temperature to be less O/ than or equal to 110*F, and i HOPE CREEK 3/4 6-13

i l CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) b) THERMAL POWER to be less than or equal to 1% of RATED THERMAL POWER. c) At least once per 30 minutes in OPERATIONAL CONDITION 3 following a scram with suppression chamber average water temperature greater than 95 F, by verifying suppression chamber average water temperature less than or equal to 120*F.

c. By an external visual examination of the suppression chamber after safety / relief valve operation with the suppression chamber average water temperature greater than or equal to 177 F and reactor coolant system pressure greater than 100 psig,

d. At least once per 18 months by a visual inspection of the accessible interior and exterior of the suppression chamber,

e. By verifying all temperature elements used by the suppression pool water temperature monitoring system OPERABLE by performance of a:

1. CHANNEL CHECK at least once per 24 hours,

2. CHANNEL FUNCTIONAL TEST at least once per 31 days, and

3. CHANNEL CALIBRATION at least once per 18 months, with the water high temperature alarm setpoint for:

1. First setpoint < 95 F

2. Second setpoint < 105*F

3. Third setpoint < 110 F

4. Fourth setpoint < 120*F

f. By verifying both suppression chamber water level instrumentation channels OPERABLE by performance of a:

1. CHANNEL CHECK at least once per 24 hours,

2. CHANNEL FUNCTIONAL TEST at least once per 31 days, and

3. CHANNEL CALIBRATION at least once per 18 months, With the water level alarm setpoint for:

1. High water level < 78.5"

2. Low water level > 65.0"

g. 'At least once per 18 months by conducting a drywell-to-suppression chamber bypass leak test at an initial differential pressure of 0.80 psi and verifying that the differential pressure does not de-crease by more than 0.24 inch of water per minute for a period of 10 minutes. If any drywell-to-suppression chamber bypass leak test fails to meet, the specified limit, the test schedule for subsequent tests shall be reviewed and approved by the Commission. If two con-secutive tests fall to meet the specified limit, a test shall be per-formed at least every 9 months until two consecutive tests meet the specified limit, at which time the 18 month test schedule may be resumed.

HOPE CREEK 3/4 6-14

CONTAINMENT SYSTEMS V SUPPRESSION POOL SPRAY LIMITING CONDITION FOR OPERATION 3.6.2.2 The suppression pool spray mode of the residual heat removal (RHR) system shall be OPERABLE with two independent loops, each loop consisting of:

a. One OPERABLE RHR pump, and J

b. An OPERABLE flow path capable of recirculating water from the suppression chamber through an RHR heat exchanger and the suppression pool spray sparger.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one suppression pool spray loop inoperable, restore the inoper-able loop to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With both suppression pool spray loops inoperable, ru tore at least one loop to OPERABLE status within 8 hours or be in at least H0T SHUTDOWN within the next 12 hours and in COLD SHUTDOWN

within the

    \g            following 24 hours.

SURVEILLANCE REQUIREMENTS 4.6.2.2 The suppression pool spray mode of the RHR system shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position,

b. By verifying that each of the required RHR pumps develops a flow of at least 500 gpm on recirculation flow through the RHR heat exchanger and suppression pool spray sparger when tested pursuant

to Specification 4.0.5.

       "Whenever both RHR subsystems are inopeiable, if unable to attain COLD SHUTOOWN es required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

I HOPE CREEK 3/4 6-15

CONTAINMENT SYSTEMS SUPPRESSION POOL COOLING LIMITING CONDITION FOR OPERATION 3.6.2.3 The suppression pool cooling mode of the residual heat removal (RHR) system shall be OPERABLE with two independent loops, each loop consisting of:

a. One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recirculating water from the suppression chamber through an RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one suppression pool cooling loop inoperable, restore the inoperable loop to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. With both suppressien pool cooling loops inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN

within the next 24 hours.

SURVEILLANCE REQUIREMENTS 4.6.2.3 The suppression pool cooling mode of the RHR system shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.

b. By verifying that each of the required RHR pumps develops a flow of at least 10,000 gpm on recirculation flow through the RHR heat exchanger and the suppression pool when tested pursuant to Specification 4.0.5.

Whenever both RHR subsystems are iroperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods. l 9ll HOPE CREEK 3/4 6-16

CONTAINMENT SYSTEMS

         ^ 'N

[Q 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3 The primary containment isolation valves and the reactor instrumentation line excess flow check valves shown in Table 3.6.3-1 shall be OPERABLE with isolation times less than or equal to those shown in Table 3.6.3-1. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more of the primary containment isolation valves shown in Table 3.6.3-1 inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours either:

1. Restore the inoperable valve (s) to OPERABLE status, or

2. Isolate each affected penetration by use of at least one deactivated automatic valve secured in the isolated position,* or

3. Isolate each affected penetration by use of at least one closed manual valve or blind flange.*

4. The provisions of Specification 3.0.4 are not applicable provided s that within 4 hours the affected penetration is isolated in accordance with ACTION a.2. or a.3. above, and provided that the associated system, if applicable, is declared inoperable and the appropriate ACTION statements for that system are performed.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. With one or more of the reactor instrumentation line excess flow check valves shown in Table 3.6.3-1 inoperable, operation n;ay continue and the provisions of Specifications 3.0.3 and 3.0.4 are not applicable provided that within 4 hours either:

1. The inoperable valve is returned to OPERABLE status, or

2. The instrument line is isolated and the associated instrument is declared inoperable.

OtherWise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. I

              " Isolation valves closed to satisfy these requirements may be reopened en an p        intermittent basis under administrative control.

U HOPE CREEK 3/4 6-17

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.3.1 Each primary containment isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE prior to returning the valve to se.tvice after mainte-nance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time. 4.6.3.2 Each primary containment automatic isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE during COLD SHUTDOWN or REFUELING at least once per 18 months by verifying that on a containment isolation test signal each automatic isolation valve actuates to its isolation position. 4.6.3.3 The isolation time of each primary containment power operated or automatic valve shown in Table 3.6.3-1 shsH be determined to be within its limit when tested pursuant to Specification 4.0.5. 4.6.3.4 Each reactor instrumentation line excess flow check valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE at least once per 18 months by verifying that the valve checks flow. 4.6.3.5 Each traversing in-core probe system explosive isolation valve shall be demonstrated OPERABLE *:

a. At least once per 31 days by verifying the continuity of the explosive charge.

b. At least once per 18 months by removing the explosive squib from at least one explosive valve such that each explosive squib in each explosive valve will be tested at least once per 90 months, and initiating the explosive squib. The replacement charge for the exploded squib shall be from the same manufactured batch as the one fired or from another batch which has been certified by having at least one of that batch successfully fired. No squib shall remain in use beyond the expiration of its shelf-life or operating life, as applicable.

Exemption to Appendix J of 10 CFR Part 50.

HOPE CREEK 3/4 6-18

O O O TABLE 3.6.3-1 PRIMARY CONTAINMENT ISOLATION VALVES S MAXIMUM E PENETRATION

ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID A. Automatic Isolation Valves

1. Group 1 - Main Steam system (a) Main Steam Isolation Valves (MSIVs) M-41-1 Inside:

Line A HV-F022A (AB-V028) P1A 5 1 Line B HV-F022B (AB-V029) PIB 5 1 Line C HV-F022C (AB-V030) PIC 5 1 Line D HV-F022D (AB-V031) P1D 5 1 M

Outside:

Line A HV-F028A (AB-V032) PIA 5 1 T Line B HV-F0288 (AB-V033) PIB 5 1 U Line C HV-F028C (AB-V034) PIC 5 1 Line D HV-F028D (AB-V035) P1D 5 1 : (b) Main Steam Line Drain Isolation M-41-1 Inside: HV-F016 (AB-V039) P12 30 3 Outside: Line A HV-F067A (AB-V059) P1A 45 1 Line B HV-F0678 (AB-V060) PIB 45 1 Line C HV-F067C (AB-V061) Plc 45 1 Line D HV-F067D (AB-V062) P1D 45 1 HV-F019 (AB-V040) P12 30 3 ,

TABLE 3.6.3-1 (C@ntinued) O M PRIMARY CONTAINMENT ISOLATION VALVES n A MAXIMUM E PENETRATION ISOLATION TIME VALVE FUNCTION ARD NUMBER NUMBER (Seconds) NOTE (S) P&ID (c) MSIV Sealing System Isolation Valves M-72-1 Outside: Line A HV-5834A (KP-V010) P1A 45 1 Line B HV-5835A (KP-V009) PIB 45 1 Line C HV-5836A (KP-V008) Plc 45 1 Line D HV-5837A (KP-V007) P1D 45 1

2. Group 2 - Reactor Recirculation Water Sample System (a) Reactor Recirculation Water Sample Line Isolation Valves M-43-1 w

1 15 3 m Inside: BB-SV-4310 P17 Outside: P17 15 3 4 O BB-SV-4311

3. Group 3 - Residual Heat Removal (RHR) System (a) RHR Suppression Pool Cooling Water & System Test Isolation Valves M-51-1 Outside:

Loop A: P2128 180 4 HV-F024A (BC-V124) P212B 180 4 HV-F010A (BC-V125) Outside: Loop B: P212A 180 4 HV-F0248 (BC-V028) P212A 180 4 HV-F010B (BC-V027) (b) RHR to Suppression Chamber Spray Header Isolation Valves M-51-1 Outside: P2148 75 3 Loop A: HV-F027A (BC-V112) P214A 75 3 Loop B: HV-F027B (BC-V015) 6 9 9

v TABLE 3.6.3-1 (Continued) 5

g PRIMARY CONTAINMENT ISOLATION VALVES g MAXIMUM p PENETRATION ISOLATION TIME 3 VALVE FUNCTION Atl0 NUMBER NUMBER (Seconds) P&ID NOTE (S)

(c) RHR Shutdown Cooling Suction Isolation Valves M-51-1 Inside: 'HV-F009 (BC-V071) P3 45 3 Outside: HV-F008 (BC-V164) P3 45 3 i j (d) RHR Head Spray Isolation Valves M-51-1 Inside: HV-F022 (BC-V021) P10 60 3 i Outside: HV-F023 (BC-V020) P10 60 3 (e) RHR Shutdown Cooling Return Isolation Valves M-51-1 Outside: i w Loop A: HV-F015A (BC-V110) P4B 45 3 g Loop B: HV-F0158 (BC-V013) P4A 45 3 [ 4. Group 4 - Core Spray System ! Outside: (a) Core Spray Test to Suppression Pool Isolation Valves M-52-1 l Loop A: HV-F015A (BE-V025) P2178 80 4 Loop B: HV-F015B (BE-V026) P217A 80 4

5. Group 5 - High Pressure Coolant Injection (HPCI) System i

i (a) HPCI Turbine Steam Supply Isolation Valves M-55-1 Inside: HV-F002 (FD-V001) P7 NA 3 HV-F100 (FD-V051) P7 NA 3 Outside: HV-F003 (FD-V002) P7 NA 3 (b) HPCI Pump Suction Isolation Valve M-55-1 Outside: HV-F042 (BJ-V009) P202 NA 4

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES g MAXIMUM g PENETRATION ISOLATION TIME Pc VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (c) HPCI Turbine Exhaust Isolation Valve M-55-1 to Vacuum Breaker Network Outside: HV-F075 (FD-V007) P201/P204 NA 4 (d) HPCI and RCIC Vacuum Network Isolation Valve M-55-1 Outside: HV-F079 (FD-V010) P204/P201 NA 3

6. Group 6 - Reactor Core Isolation Cooling (RCIC) System (a) RCIC Turbine Steam Supply Isolation Valves M-49-1 Inside: HV-F007 (FC-V001) P11 NA 3 T P11 NA 3 g HV-F076 (FC-V048)

P11 NA 3 Outside: HV-F008 (FC-V002) (b) RCIC Turbine Exhaust Isolation Valve to M-49-1 Vacuum Breaker Network Outside: P207/P204 NA 4 HV-F062 (FC-V006) M-49-1 (c) HPCI and RCIC Vacuum Network Isolation Valve Outside: P204/P207 NA 3 HV-F084 (FC-V007)

7. Group 7 - Reactor Water Cleanup (RWCU) System (a) RWCU Supply Isolation Valves M-44-1 l

P9 45 3 Inside: HV-F001 (BG-V001) 3 Outside: HV-F004 (BG-V002) P9 45 O - - O O

N TABLE 3.6.3-1 (Continued) 5 g PRIMARY CONTAINMENT ISOLATION VALVES k m MAXIMUM

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

8. Group 8 - Torus Water Cleanup (TWC) System (a) TWC Suction Isolation Valves M-53-1 i

Outside: HV-4680 (EE-V003) P223 45 4 HV-4681 (EE-V004) P223 45 4 (b) TWC Return Isolation Valves M-53-1 Outside: HV-4652 (EE-V002) P222 45 4

  $                 HV-4679 (EE-V001)                                            P222           45                               4

[ 9. Group 9 - Drywell Sumps w (a) Drywell Floor Drain Sump Discharge Isolation Valves- M-61-1 Inside: HV-F003 (HB-V005) P25 30 3 Outside: HV-F004 (HB-V006) P25 30 3 (b) Drywell Equipment Drain Sump Discharge Isolation Valves M-61-1 Inside: HV-F019 (HB-V045) P26 30 3 Outside: HV-F020 (HB-V046) P26 30 3

10. Group 10 - Drywell Coolers (a) Chilled Water to Drywell Coolers Isolation Valves M-87-1 Inside:

Loop A: HV-9531B1 (GB-V081) P88 60 3 Loop B: HV-953183 (GB-V083) P38A 60 3 J

l TABLE 3.6.3-1 (Centinued) 5

g PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM p PENETRATION ISOLATION TIME VALVE FUNCTION AMD NUMBER NUMBER (Seconds) NOTE (S) P&ID Outside

Loop A: HV-9531A1 (GB-V048) P88 60 3 Loop B: HV-9531A3 (GB-V070) P38A 60 3 (b) Chilled Water from Drywell Coolers Isolation Valves M-87-1 Inside: Loop A: HV-953182 (GB-V082) P8A 60 3 Loop B: HV-953184 (GB-V084) P388 60 3 Outside: Loop A: HV-9531A2 (GB-V046) P8A 60 3 R

Loop B: P388 60 3 HV-9531A4 (GB-V071)

11. Group 11 - Recirculation Pump System (a) Recirculation Pump Seal Water Isolation Valves M-43-1 Outside:

Loop A: HV-3800A (BF-V098) P19 45 3 Loop B: HV-38008 (BF-V099) P20 45 3

12. Group 12 - Containment Atmosphere Control System (a) Drywell Purge Supply Isolation Valves M-57-1 Outside:

P22 15 3, 8 HV-4956 (GS-V009) P22/220 15 3, 8 HV-4979 (GS-V021) (b) Drywell Purge Exhaust Isolation Valves M-57-1 Outside: P23 15 3 HV-4951 (GS-V025) HV-4950 (GS-V026) P23 15 3, 8 P23 15 3, 8 HV-4952 (GS-V024) O O O

                                                                                                       )                                          O O

TABtE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES Q MAXIMUM A PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (c) Suppression Chamber Purge Supply Isolation Valves M-57-1 Outside: HV-4980 (GS-V020) P22/P220 15 3, 8 HV-4958 (GS-V022) P220 15 3, 8 (d) Suppression Chamber Purge Exhaust Isolation Valves M-57-1 Outside: HV-4963 (GS-V076) P219 15 3 HV-4962 (GS-V027) P219 15 3, 8 g HV-4964 (GS-V028) P219 15 3, 8

                                       ?               (e) Nitrogen Purge Isolation Valves                                                           M-57-1 E$

Outside: HV-4974 (GS-V053) J7D/J202 45 3 HV-4978 (GS-V023) P22/P220 15 3, 8

13. Group 13 - Hydrogen /0xygen (H2/02) Analyzer System (a) Drywell H2/02 Analyzer Inlet Isolation Valves M-57-1 Outside: -

Loop A: HV-4955A (GS-V045) J9E 45 3 HV-4983A (GS-V046) J9E 45 3 HV-4984A (GS-V048) J10C 45 3 HV-5019A (GS-V047) J10C 45 3 Outside: Loop B: HV-49558 (GS-V031) J3B 45 3 HV-49838 (GS-V032) J3B 45 3 HV-4984B (GS-V034) J70/J202 45 3 HV-5019B (GS-V033) J7D -45 3 l

TABLE 3.6.3-1 (Ccntinued) E

 ;g                                          PRIMARY CONTAINMENT ISOLATION VALVES Q                                                                                                    MAXIMUM Q

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (b) Suppression Chamber H2/02 Analyzer Intet Isolation Valves M-57-1 Outside: Loop A: HV-4965A (GS-V050) J212 45 3 HV-4959A (GS-V049) J212 45 3 Outside: Loop B: HV-49658 (GS-V041) J210 45 3 HV-49598 (GS-V040) J210 45 3 (c) H2/02 Analyzer Return to Suppression Chamber m Isolation Valves M-57-1 A Outside:

 ?                  Loop A:   HV-4966A (GS-V051)                                          J201          45           3 y                            HV-5022A (GS-V052)                                          J201          45           3 l                    Outside:

Loop B: HV-4966B (GS-V042) J202 45 3 l HV-50228 (GS-V043) J202/J7D 45 3

14. Group 14 - Containment Hydrogen Recombination (CHR) System (a) CHR Supply Isolation Valves M-58-1 Outside:

Loop A: HV-5050A (GS-V002) P23 45 3 HV-5052A (GS-V003) P23 45 3 Outside: Loop B: HV-50508 (GS-V004) P22 45 3 HV-50528 (GS-V005) P22 45 3 (b) CHR Return Isolation Valves M-58-1 l Outside: , Loop A: HV-5053A (GS-V008) P220 45 3 HV-5054A (GS-V010) P220 45 3 l O O O

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES 9 MAXIMUM E

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID Outside:

Loop B: HV-50538 (GS-V006) P219 45 3 M-58-1 HV-50548 (GS-V007) P219 45 3

15. Group 15 - Primary Containment Instrument Gas System (PCIGS)

(a) PCIGS Drywell Supply Header Isolation Valves M-59-1 Inside: Loop A: HV-5152A (KL-V028) P288 45 3 { Loop B: HV-51528 (KL-V026) P28A 45 3 T Outside: O Loop A: HV-5126A (KL-V027) P288 45 3 Loop B: HV-51268 (KL-V025) P28A 45 3 (b) PCIGS Drywell Suction Isolation Valves M-59-1 Inside: HV-5148 (KL-V001) P39 45 3 Outside: Loop A: HV-5147 (KL-V002) P39 45 3 Loop B: HV-5162 (KL-V049) P39 45 3 (c) PCIGS Suppression Chamber Supply Isolation Valves M-59-1 Outside: HV-5154 (KL-V018) J211 15 3 HV-5155 (KL-V019) J211 15 3

TABLE 3.6.3-1 (Continued) 5 g PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM h ISOLATION TIME g PENETRATION NUMBER (Seconds) NOTE (S) P&ID VALVE FUNCTION AND NUMBER

16. Group 16 - Reactor Auxiliaries Cooling System (RACS)

(a) RACS Supply Isolation Valves M-13-1 P29 45 3 Inside: HV-2554 (ED-V020) Outside: HV-2553 (ED-V019) P29 45 3 M-13-1 (b) RACS Return Isolation Valves P30 45 3 Inside: HV-2556 (ED-V022) P30 45 3 Outside: HV-2555 (ED-V021)

17. Group 17 - Traversing In-core Probe (TIP) System g

M-59-1

 ?                         (a) TIP Probe Guide Tube Isolation Valves E                               Outside:

P34A 15 3 SV-J004A-1 (SE-V026) 3 SV-J004A-2 (SE-V027) P34B 15 P34C 15 3 SV-J004A-3 (SE-V028) 3 P34D 15 SV-J004A-4 (SE-V029) 3 P34E 15 SV-J004A-5 (SE-V030) M-59-1 (b) TIP Purge System Isolation Valve Outside: 3 P34F 15 HV-5161 (SE-V004)

18. Group 18 - Reactor Coolant Pressure Boundary (RCPB)

Leakage Detection System (a) Drywell Leak Detection Radiation Monitoring System (DLD-RMS) M-25-1 Inlet Isolation Valves Outside: 3 J8C 45 HV-5018 (SK-V005) 3 J8C 45 HV-4953 (SK-V006) 9 9 e

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM PENETRATION ISOLATION TIME NUMBER (Seconds) NOTE (S) P&ID 5 VALVE FUNCTION AND NUMBER 7n M-25-1 n (b) DLD-RMS Return Isolation Valves h! Outside: 75 JSA 45 3 HV-4957 (SK-V008) J5A 45 3 HV-4981 (SK-V009) B. Remote Manual Isolation Valves

1. Group 21 - Feedwater System M-41-1 (a) Feedwater Isolation Valves Outside Check Valves P2A NA 2 HV-F0328 (AE-V001)

P2B NA 2 HV-F032A (AE-V005) (b) Reactor Water Cleanup System Return Outside: P2A&B NA 2 M-44-1 R8 HV-F039 (AE-V021) I, 2. Group 22 - High Pressure Coolant Injection (HPCI) System [g (a) Core Spray Discharge Valve Outside: P5B NA 3 M-55-1 HV-F006 (BJ-V001) (b) Turbine Exhaust Valve Outside: P201 NA 4 M-55-1 HV-F071 (FD-V006) (c) HPCI Minimum Return Line Valve Outside: M-55-1 P203 NA 4 HV-F012 (BJ-V016) (d) Feedwater Line Discharge Valve Outside: M-55-1 P28 NA 2 HV-8278 (BJ-V059)

3. Group 23 - Reactor Core Isolation Cooling (RCIC) System (a) RCIC Turbine Exhaust Valve Outside: 4 M-49-1 P207 NA HV-F059 (FC-V005)

TABLE 3.6.3-1 (C:ntinued) 5 y PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM g PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seccr.ds) NOTE (S)_ P&ID Outside: (b) RCIC Pump Suction Isolation Valve HV-F031 (BD-V003) P208 NA 4 M-49-1 ' Outside: (c) RCIC Minimum Return Line Isolation Valve SV-F019 P209 NA 4 M-49-1 Outside: (d) RCIC Vacuum Pump Discharge HV-F060 (FC-V011) P210 NA 4 M-49-1 (e) Feedwater Line Discharge Valve w Outside: l

                                     }                  HV-F013 (BD-V005)                                                                                  P2A                                             NA                                                                             2  M-49-1 l                                            4. Group 25 - Core Spray System (a) Core Spray injection Valves                                                                                                                                                                                                           M-52-1 l                                                        Outside:

Loop A&C HV-F005A (BE-V007) PSB NA 3 Loop B&D HV-F005B (BE-V003) PSA NA 3 (b) Core Spray Suppression Pool Suction Valves M-52-1 Outside: Loop A HV-F001A (BE-V017) P216D NA 4 Loop B HV-F0018 (BE-V019) P216A NA 4 Loop C HV-F001C (BE-V018) P216C NA 4 Loop D HV-F0010 (BE-V020) P216B NA 4 (c) Core Spray Minimum Flow Valves M-52-1 Outside: Loop A&C HV-F031A (BE-V035) P2178 NA 4 Loop B&D HV-F0318 (BE-V036) P217A NA 4 (d) Core Spray Injection Line Bypass Valves M-52-1 Inside: HV-F039A (BE-V071) PSB NA 3 HV-F0398 (BE-V072) PSA NA 3 O O O

TABLE 3.6.3-1 (Continued) 5 g PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM g PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

5. Group 26 - Residual Heat Removal System (a) Low Pressure Coolant Injection Valves M-51-1 Outside:

Loop A: HV-F017A (BC-V113) P6C NA 3 Loop B: HV-F0178 (BC-V016) P68 NA 3 Loop C: HV-F017C (BC-V101) P6D NA 3 Loop D: HV-F0170 (BC-V004) P6A NA 3 (b) RHR Containment Spray M-51-1 Outside: y Loop A: HV-F021A (BC-V116) P24B NA 3

HV-F016A (BC-V115) P24B NA 3

? Loop B: HV-F0218 (BC-V019) P24A NA 3 $ HV-F0168 (BC-V018) P24A NA 3 (c) RHR Suppression Pool Suction M-51-1 Outside: Loop A: HV-F004A (BC-V103) P211C NA 4 Loop B: HV-F004B (BC-V006) P2118 NA 4 Loop C: HV-F004C (BC-V098) P211D NA 4 Loop D: HV-F004D (BC-V001) P211A NA 4 (d) RHR Minimum Flow Isolation Valves M-51-1 Outside: Loop A: HV-F007A (BC-V128) P2128 NA 4 Loop B: HV-F0078 (BC-V031) P212A NA 4 Loop C: HV-F007C (BC-V131) P2128 NA 4 Loop D: HV-F007D (BC-V034) P212A NA 4 E

TABLE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES A 2 PENETRATION MAXIMUM ISOLATION TIME

;  { VALVE FUNCTION AND NUMBER                                   NUMBER             (Seconds)   NOTE (S) P&ID (e) Bypass Valves on LPCI Injection Lines Inside:                                                                             M-51-1 HV-F146A (BC-V119)                            P6C                NA           3 HV-F146B (BC-V120)                            P68                NA           3 HV-F146C (BC-V121)                            P6D                NA           3 HV-F146D (BC-V122)                            P6A                NA           3 (f) Bypass Valves on Shutdown Cooling Return Lines                                        M-51-1 Inside:

HV-F122A (BC-V117) P4B NA 3 HV-F1228 (BC-V118) P4A NA 3

6. Group 27 - Standby Liquid Control w Outside: M-48-1

  }                  HV-F006A (BH-V028)                            P18                NA           3 m                  HV-F006B (BH-V054)                            P18                NA          3 a

7. Group 28 - Containment Atmosphere Control System Supression Chamber Vacuum Relief Outside: M-57-1 HV-5031 (GS-V038) P220 NA 3 HV-5029 (GS-V080) P219 NA 3

8. Group 69 - TIP System Explosive Shear Valves Outside: M-59-1 SE-XV-J004B1 (SE-V021) P34A NA 7 SE-XV-J004B2 (SE-V022) P348 NA 7 SE-XV-J004B3 (SE-V023) P34C NA 7 SE-XV-J004B4 (SE-V024) P34D NA 7 SE-XV-J004B5 (SE-V025) P34E NA 7 0 9 9

O O TABLE 3.6.3-1 (Continued) 5 g PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM p PENETRATION ISOLATION TIME P&ID VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) l 9. Group 29 - HPCI System Suppression Pool Level Instrumentation Isolation M-55-1 Outside: HV-4803 (BJ-V500) J209 NA 6 HV-4804 (BJ-V501) P228 NA 6 HV-4865 (BJ-V502) J217 NA 6 HV-4866 (BJ-V503) J219 NA 6

10. Group 30 - Post-Accident Sampling System Liquid Sampling M-38-0 y

Outside:

RC-SV-0643A P227 NA 3 T w RC-SV-0643B P227 NA 3

 "                                                                                                                                                      3 RC-SV-8903A                                                                                   J50                NA RC-SV-89038                                                                                   J50                NA           3 Gas Sampling                                                                                                                             M-38-0 Outside:

RC-SV-0730A J7E NA 3 RC-SV-07308 J7E NA 3 RC-SV-0731A J10E NA 3 RC-SV-0731B J10E NA 3 RC-SV-0728A J206 NA 3 RC-SV-0728B J206 NA 3 RC-SV-0729A J221 NA 3 RC-SV-0729B J221 NA 3 RC-SV-0707A J220 NA 3 RC-SV-07078 J220 NA 3

TABLE 3.6.3-1 (Centinued) 5

  ?R                                                                                                              PRIMARY CONTAINMENT ISOLATION VALVES n

Ni MAXIMUM SQ PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID C. Primary Containment (Other Isolation Valves)

1. Group 31 - Feedwater System (a) Feedwater Isolation Valves M-41-1 Inside Check Valves AE-V003 P2A NA 3 u, AE-V007 P2B NA 3 D

m Outside Check Valves J, (Air Assisted) HV-F0748 (AE-V002) P2A NA 3 HV-F074A (AE-V006) P2B NA 3

2. Group 32 - Standby Liquid Control System Inside Check Valve M-48-1 BH-V029 P18 NA 3

3. Group 33 - Primary Containment Atmosphere Control System Containment Vacuum Breakers M-57-1 Outside:

GS-PSV-5032 P220 NA 3 GS-PSV-5030 P219 NA 3

4. Group 34 - Service Air System M-15-0 Outside KA-V038 P27 NA 3 Inside KA-V039 P27 NA 3 O O O

4 TABLE 3.6.3-1 (Continued) 5 g PRIMARY CONTAINMENT ISOLATION VALVES E MAXIMUM E PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

5. Group 35 - Breathing Air System M-15-1 Inside KG-V016 P31 NA 3 Outside KG-V034 P31 NA 3

6. Group 36 - TIP Purge System Inside:

Check Valve: SE-V006 P34F NA 3 M-59-1

7. Group 37 - HPCI System Outside:

HPCI Turbine Exhaust: FD-V004 P201 NA 4 M-55-1 { [ 8. Group 38 - RCIC System m Outside: RCIC Turbine Exhaust: FC-V003 P207 NA 4 M-49-1 Vacuum Pump Discharge: FC-V010 P210 NA 4 M-49-1

9. Group 39 - RHR System (a) Thermal Relief Valves M-51-1 Outside:

Loop A: BC-PSV-F025A P2128 NA 5 Loop B: BC-PSV-F025B P212A NA 5 Loop C: BC-PSV-F025C P2128 NA 5 Loop D: BC-PSV-F025D P212A NA 5 (b) Jockey Pump Discharge Check Valves M-51-1 Outside: Loops A & C: (BC-V206) P212B NA 4 Loops B & D: (BC-V260) P212A NA 4 (c) RHR Heat Exchanger Thermal Relief Valves M-51-1 Outside: BC-PSV-4431A P213B NA 5 BC-PSV-44318 P213A NA 5

TABLE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES

    "'                                                                                                                                                              MAXIMUM I

Q PENETRATION ISOLATION TIME I A VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (d) RHR Shutdown Cooling Suction Thermal Relief Valve M-51-1 Inside: BC-PSV-4425 P3 NA 3 (e) LPCI Injection Line Check Valves M-51-1 Inside: l HV-F041A (BC-V114) P6C NA 3 HV-F041B (BC-V017) P6B NA 3 HV-F041C (BC-V102) P6D NA 3 HV-F041D (BC-V005) P6A NA 3 l l (f) Shutdown Cooling Return Line Check Valves M-51-1 Inside: w HV-F050A (BC-V111) P4B NA 3 i HV-F050B (BC-V014) P4A NA 3 T (g) RHR Suppression Pool Return Valves M-51-1 M Outside: HV-F011A (BC-V126) P212B NA 4 HV-F0118 (BC-V026) P212A NA 4

10. Group 40 - Core Spray System (a) Thermal Relief Valves M-52-1 Outside:

Loop A&C: BE-PSV-F012A P217B NA 5 Loop B&D: BE-PSV-F012B P217A NA 5 (b) Core Spray Injection Line Check Valves Inside: M-52-1 HV-F006A (BE-V006) PSB NA 3 HV-F006B (BE-V002) PSA NA 3

11. Group 41 - Drywell Pressure Instrumentation M-42-1 Outside:

BB-V563 J6A NA 6 BB-V564 J8D NA 6 BB-V565 J7A NA 6 BB-V566 J10D NA 6 O O O

O O O TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES 2 MAXIMUM ! E

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) P&ID 1 NOTE (S)

12. Group 42 - Intergrated Leak Rate Testing System M-60-1 Inside GP-V001 J36D NA '3 Outside GP-V002 J36D NA 3 Inside GP-V120 J36C NA 3 Outside GP-V122 J36C NA 3 l Outside GP-V004 J209 NA 3 i Outside GP-V005 J209 NA 3 i

i

13. Group 43 - Suppression Chamber Pressure Instrumentation M-57-1 Outside R GS-V044 J207 NA 6

[ GS-V087 J208 NA 6 b 14. Group 44 - Chilled Water System Thermal Relief Valves M-87-1 j Inside i GB-PSV-9522A P88 NA 3 ' GB-PSV-95228 P38A NA 3 GB-PSV-9523A P8A NA 3 GB-PSV-9523B P38B NA 3 I 15. Group 45 - Recirculation Pump Seal Purge Line Check Valves M-43-1 Inside l BB-V043 P19 NA 3 BB-V047 P20 NA 3 l D. Excess Flow Check Valves 1 1. Group 46 - Nuclear Boiler M-41-1

 !                                                 Outside BB-XV-3649                                      J5C                 NA          6, 10 AB-XV-3666A                                     J25A                NA          6 l                                                   AB-XV-36668                                     J26A                NA          6
)                                                  AB-XV-3666C                                     J27A                NA          6

AB-XV-3666D J28A NA 6 i

a

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES E MAXIMUM E PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID Outside M-41-1 AB-XV-3667A J22A NA 6 AB-XV-36678 J22C NA 6 AB-XV-3667C J21A NA 6 AB-XV-3667D J21D NA 6 AB-XV-3668A J22B NA 6 AB-XV-36688 J220 NA 6 AB-XV-3668C J21E NA 6 AB-XV-3668D J21F NA 6 AB-XV-3669A J25C NA 6 AB-XV-36698 J26C NA 6 w AB-XV-3669C J27D NA 6 1 AB-XV-3669D J280 NA 6

2. Group 47 - Nuclear Boiler Vessel Instrumentation M-42-1 Outside BB-XV-3621 J3A NA 6 BB-XV-3725 J2C NA 6 BB-XV-3726A J1350 NA 6 BB-XV-3726B J1353 NA 6 BB-XV-3727A J44 NA 6 BB-XV-3727B J41 NA 6 BB-XV-3728A J1351 NA 6 BB-XV-3728B J1354 NA 6 BB-XV-3729A J51 NA 6 BB-XV-3729B J42 NA 6 BB-XV-3730A J52 NA 6 BB-XV-3730B J43 NA 6 BB-XV-3731A J1352 NA 6 J1355 NA 6 BB-XV-37318 J37A NA 6 BB-XV-3732A J11A NA 6 BB-XV-37328 J24E NA 6 BB-XV-3732C O O ..

O

,m

( TABLE 3.6.3-1 (Continued) 5

     ;8                                             PRIMARY CONTAINMENT ISOLATION VALVES k                                                                                      MAXIMUM p                                                                 PENETRATION       ISOLATION TIME VALVE FUNCTION APID NUMBER                                      NUMBER            (Seconds)   NOTE (S)  P&ID Outside                                                                                 M-42-1 BB-XV-37320                                      J11B               NA           6 BB-XV-3732E                                      J37C               NA           6 4

BB-XV-3732F J40C NA 6 BB-XV-3732G J37D NA 6 BB-XV-3732H J40E NA 6 BB-XV-3732J J37E NA 6 BB-XV-3732K J11E NA 6 BB-XV-3732L J14A NA 6 BB-XV-3732M J40F NA 6 BB-XV-3732N J14B NA 6 R* BB-XV-3732P J128 NA 6 BB-XV-3732R J14C NA 6 T BB-XV-37325 J12C NA 6

    $                     BB-XV-3732T                                      J14D               NA           6 l                         BB-XV-3732U                                      J400               NA           6 BB-XV-3732V                                      J14E               NA           6 BB-XV-3732W                                      J12E               NA           6
;                         BB-XV-3734A                                      J50                NA           6 J47 BB-XV-37348                                                         NA           6 BB-XV-3734C                                      J14F               NA           6 BB-XV-3734D                                      J12F               NA           6 1                          BB-XV-3737A                                      J38A               NA           6 BB-XV-37378                                      J16C               NA           6 BB-XV-3738A                                      J13D               NA           6 BB-XV-37388                                      J388               NA           6

3. Group 48 - Reactor Recirculation System M-43-1 Outside BB-XV-3783 J32B NA 6 BB-XV-3785 J32C NA 6 BB-XV-3787 J30C NA 6 BB-XV-3789 J30B NA 6 BB-XV-3801A J188 NA 6

TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES E m MAXIMUM m PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID Outside M-43-1 BB-XV-3801B J28B NA 6 BB-XV-3801C J16E NA 6 BB-XV-3801D J36E NA 6 BB-XV-3802A J18F NA 6 BB-XV-38028 J28F NA 6 BB-XV-3802C J16F NA 6 BB-XV-38020 J36F NA 6 BB-XV-3803A J29F NA 6 BB-XV-3803B J24A NA 6 BB-XV-3803C J38C NA 6 w BB-XV-3803D J34D NA 6 A BB-XV-3804A J29D NA 6 cn BB-XV-3804B J248 NA 6 A BB-XV-3804C J38F NA 6 BB-XV-3804D J34E NA 6

4. Group 49 - Reactor Recirculation System - Cont'd. M-43-1 Outside BB-XV-3820 J32E NA 6 BB-XV-3821 J32F NA 6 BB-XV-3826 J34B NA 6 BB-XV-3827 J23C NA 6

5. Group 50 - Reactor Water Cleanup M-44-1 Outside BG-XV-3882 J24C NA 6 BG-XV-3801A J19D NA 6 BG-XV-3884B J34A NA 6 BG-XV-3884C J19E NA 6 BG-XV-38840 J34C NA 6 O O O

O O O TABLE 3.6.3-1 (Continued) 5 A PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM Q PENETRATION ISOLATION TIME VALVE FUNCTION APID NUMBER NUMBER (Seconds) NOTE (S) P&ID

6. Group 51 - Reactor Core Isolation Cooling System M-49-1 Outside FC-XV-4150A J20A NA 6 i FC-XV-4150B J40B NA 6

) FC-XV-4150C J20B NA 6 FC-XV-4150D J40A NA 6 l 7. Group 52 - Residual Heat Removal System M-51-1 , I i Outside i R BC-XV-4411A J33A NA 6

BC-XV-4411B J23B NA 6 j T BC-XV-4411C J35A NA 6 l $ BC-XV-4411D J36B NA 6 l BC-XV-4429A J33D NA 6 i BC-XV-4429B J23A NA 6 BC-XV-4429C J35C NA 6 I BC-XV-4429D J36A NA 6

8. Croup 53 - Core Spray System M-52-1 1
Outside l BE-XV-F018A J19C NA 6 BE-XV-F018B J30F NA 6 l

1

9. Group 54 - High Pressure Coolant Injection System M-55-1 Outside I FD-XV-4800A J19A NA 6 FD-XV-48008 J29A NA 6 FD-XV-4800C J198 NA 6 FD-XV-48000 J298 NA 6 l

l TABLE 3.6.3-1 PRIMARY CONTAINMENT ISOLATION VALVES NOTES NOTATION ! 1. Main Steam Isolation Valves are sealed with a seal system that maintains a positive pressure of 5 psig above reactor pressure. Leakage is in-leakage and is not added to 0.60 La allowable leakage.*

2. Containment Isolation Valves are sealed with a water seal from the HPCI and/or RCIC system to form the long-term seal boundary of the feedwater lines. The valves are tested with water at 1.10 Pa, 52.9 psig, to ensure the seal boundary will prevent by pass leakage. Seal boundary liquid leakage will be limited to 10 gpm.

3. Containment Isolation Valve, Type C gas test at Pa, 48.1 psig. Leakage added to 0.60La allowable leakage.

4. Containment Isolation Valve, Type C water test at Pa, 48.1 psig a P.

Leakage added to 10 gpm allowable leakage.

5. Containment boundary is discharge nozzle of relief valve, leakage tested during Type A test.*

6. Drywell and suppression chamber pressure and level instrument root valves and excess flow check valves, leakage tested during Type A.*

7. Explosive shear valves (SE-V021 through SE-V025) not Type C tested.*

8. Surveillances to be performed per Specification 3.6.1.8.

9. All valve I.D. numbers are preceded by a numeral I which represents an Unit 1 valve.

10. The reactor vessel head seal leak detection line (penetration J5C) excess flow check valve (BB-XV-3649) is not subject to OPERABILITY testing. This valve will not be exposed to primary system pressure except under the unlikely conditions of a seal failure where it could be partially pressurized to reactor pressure. Any leakage path is restricted at the source; therefore, this valve need not be l OPERABILITY tested.

l

Exemption to Appendix J of 10 CFR Part 50.

l 1 O HOPE CREEK 3/4 6-42

CONTAINMENT SYSTEMS 3/4.6.4 VACUUM RELIEF SUPPRESSION CHAMBER - DRYWELL VACUUM BREAKERS LIMITING CONDITION FOR OPERATION 3.6.4.1 All suppression chamber - drywell vacuum breakers shall be OPERABLE and closed. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one of the above vacuum breakers inoperable for opening but known to be closed, restore the inoperable vacuum breaker to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. With one or more suppression chamber - drywell vacuum breaker (s) open, close the open vacuum breaker (s) within 2 hours; or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

c. With one of the position indicators of any suppression chamber -

drywell vacuum breaker inoperable:

1. Verify the other position indicator in the pair to be OPERABLE within 2 hours and at least once per 14 days thereafter, or

2. Verify the vacuum breaker (s) with the inoperable position indicator to be closed by conducting a test which demonstrates that the AP is maintained at greater than or equal to 0.5 psi for one hour without makeup within 24 hours and at least once per 14 days thereafter.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. HOPE CREEK 3/4 6-43

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS O 4.6.4.1 Each suppression chamber - drywell vacuum breaker shall be:

a. Verified closed at least once per 7 days.

b. Demonstrated OPERABLE:

1. At least once per 31 days and within 2 hours after any discharge of steam to the suppression chamber from the safety-relief valves, by cycling each vacuum breaker through at least one complete cycle of full travel.

2. At least once per 31 days by verifying both position indicators OPERABLE by observing expected valve movement during the cycling test.

3. At least once per 18 months by; a) Verifying the opening setpoint, from the closed position, to be less than or equal to 0.20 psid, and b) Verifying both position indicators OPERABLE by performance of a CHANNEL CALIBRATION.

O HOPE CREEK 3/4 6-44

CONTAINMENT SYSTEMS [m\ C/ REACTOR BUILDING - SUPPRESSION CHAMBER VACUUM BREAKERS i LIMITING CONDITION FOR OPERATION 3.6.4.2 Both reactor building - suppression chamber vacuum breaker assemblies l consisting of a vacuum breaker valve and a butterfly isolation valve shall be OPERABLE and closed. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one valve of a reactor building - suppression chamber vacuum breaker assembly inoperable for opening but known to be closed, restore the inoperable vacuum breaker assembly valve to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With one valve of a reactor building - suppression chamber vacuum breaker assembly open, verify the other vacuum breaker assembly valve in the line to be closed within 2 hours; restore the open vacuum breaker assembly valve to the closed position within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

c. With the position indicator of any reactor building - suppression chamber vacuum breaker assembly valve inoperable, restore the inoper-Q able position indicator to OPERABLE status within 14 days or verify the affected vacuum breaker assembly valve to bc closed at least or;ce per 24 hours by a visual inspection. Otherwise, declare the vacuum breaker assembly valve inoperable or l'e in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours.

SURVEILLANCE REQUIREMENTS 4.6.4.2 Both reactor building - suppression chamber vacuum breaker assemblies shall be:

a. Verified closed at least once per ' da'. .

b. Demonstrated OPERABLE:

1. At least once per 31 days by:

a) Cycling each vacuum breaker assembly valve through at least one complete cycle of full travel. b) Verifying the position indicators on each assembly valve OPERABLE l by observing expected valve movement during the cycling test. ! 2. At least once per 18 months by: a) Demonstrating that the force required to open each vacuum breaker valve does not exceed the equivalent of 0.25 psid. b) Visual inspection. , HOPE CREEK 3/4 6-45 l

CONTAINMENT SYSTEMS - SURVEILLANCE REQUIREMENTS (Continued) O c) Verifying the position indicators on each assembly valve OPERABLE by performance of a CHANNEL CALIBRATION. d) Verifying the instrument actuation rystem for the inboard isola-tion valve auto open control system OPERABLE by performance of a CHANNEL CALIBRATION. O O HOPE CREEK 3/4 6-46

i CONTAINMENT SYSTEMS (m 3/4.6.5 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. ACTION: Without SECONDARY CCNTAINMENT INTEGRITY:

a. In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. In Operational Condition * , suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:

a. Verifying at least once per 24 hours that the reactor building is at a negative pressure.

(- b. Verifying at least once per 31 days that:

1. All secondary containment equipment hatches and blowout panels are closed and sealed.

2. a. For double door arrangements, at least one door in each access to the secondary containment is closed.

b. For single door arrangements, the door in each access to the secondary containment is closed except for routine entry and exit. ,

3. All secondary containment penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers /

valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic dampers / l valves secured in position.

c. At least once per 18 months:

! 1. Verifying that four filtration recirculation and ventilation

                 ;ystem (FRVS) recirculation units and one ventilation unit of the filtration recirculation and ventilation system will draw down the secondary containment to greater than or equal to 0.25 inches of vacuum water gauge in less than or equal to 375 seconds, and
    *When irradiated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

HOPE CREEK 3/4 6-47

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

2. Operating four filtration recirculation and ventilation system (FRVS) recirculation units and one ventilation unit of the filtration recirculation and ventilation system for four hours and maintaining greater than or equal to 0.25 inches of vacuum water gauge in the secondary containment at a flow rate not exceeding 3324 CFM.

l l i l O l l l l l O HOPE CREEK 3/4 6-48

CONTAINMENT SYSTEMS n/ y SECONDARY CONTAINMENT AUTOMATIC ISOLATION DAMPERS LIMITING CONDITION FOR OPERATION 3.6.5.2 The secondary containment ventilation system (RBVS) automatic isolation dampers shown in Table 3.6.5.2-1 shall be OPERABLE with isolation times less than or equal to the times shown in Table 3.6.5.2-1. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. ACTION: With one or more of the secondary containment ventilatior. system automatic isolation dampers shown in Table 3.6.5.2-1 inoperable, maintain at least one isolation damper OPERABLE in each affected penetration that is open and within 8 hours either:

a. Restore the inoperable dampers to OPERABLE status, or

b. Isolate each affected penetration by use of at least one deactivated damper secured in the isolation position, or

c. Isolate each affected penetration by use of at least one closed manual valve or blind flange.

p Otherwise, in OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN

 'Q    within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

Otherwise, in Operational Condition *

                                                  , suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel.       The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.2 Each secondary containment ventilation system automatic isolation damper shown in Table 3.6.5.2-1 shall be demonstrated OPERABLE:

a. Prior to returning the damper to service after maintenance, repair or replacement work is performed on the damper or its associated actuator, control or power circuit by cycling the damper through at least one complete cycle of full travel and verifying the specified isolation time.

b. During COLD SHUTDOWN or REFUELING at least once per 18 months by verifying that on a containment isolation test signal each isolation damper actuates to its isolation position.

c. By verifying the isolation time to be within its limit at least once per

, 92 days. l i

    *When irradiated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

HOPE CREEK 3/4 6-49

l l TABLE 3.6.5.2-1 SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION DAMPERS ISOLATION GROUP NO. 19 MAXIMUM ISOLATION TIME DAMPER FUNCTION (Seconds)

1. Reactor Building Ventilation Supply Damper HD-9370A 10

2. Reactor Building Ventilation Supply Damper HD-93708 10

3. Reactor Building Ventilation Exhaust Damper HD-9414A 10

4. Reactor Building Ventilation Exhaust Damper HD-94148 10 0

l HOPE CREEK 3/4 6-50

CONTAINMENT SYSTEMS ps FILTRATION, RECIRCULATION AND VENTILATION SYSTEM (FRVS) LIMITING CONDITION FOR OPERATION 3.6.5.3 Five FRVS recirculation units and two FRVS ventilation units shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. ACTION:

a. With one of the above required FRVS recirculation units or one of the above required FRVS ventilation units inoperable, restore the inoper-able unit to OPERABLE status within 7 days, or:

1. In OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

2. In Operational Condition * , suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

b. With three FRVS recirculation units or both ventilation units inoper-able in Operational Condition *, suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS or operations with a potential for draining the reactor vessel. The provisions of Speci-fication 3.0.3. are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.3 Each of the six FRVS recirculation and two ventilation units shall be demonstrated OPERABLE: I a. At least once per 14 days by verifying that the water seal bucket traps have a water seal and making up any evaporative losses by fil-ling the traps to the overflow.

b. At least once per 31 days by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours with the heaters on in order to reduce the buildup of moisture on the carbon adsorbers and HEPA :

filters. l I

    "When irradiated fuel is being handled in the secondary containment and during (x  CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

l l HOPE CREEK 3/4 6-51 !

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c. At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the subsystem by:

1. Verifying that the subsystem satisfies the in place penetration test-ing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.S.a, C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rates are 30,000 cfm i 10% for each FRVS recirculation unit, and 9,000 cfm i 10%

for each FRVS ventilation unit.

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, by showing a methyl iodide penetration of less than 1.0% when tested at a temperature of 30*C and at a relative humidity of 70% in accordance with ASTM D3803; and

3. Verifying a subsystem flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm 110% for each FRVS ventilation unit during system operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, by showing a methyl iodide penetration of less than 1.0% when tested at a temperature of 30 C and at a relative humidity of 70% in accordance with ASTM D3803.

e. At least once per 18 months by:

l l 1. Verifying that the pressure drop across the combined HEPA filters and l charcoal adsorber banks is less than 8 inches Water Gauge in the recir-culation filter train and less than 5 inches Water Gauge in the ventilation unit while operating the filter train at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm i 10%

             'for each FRVS ventilation unit.

2. Verifying that the filter train starts and isolation dampers open on each of the following test signals:

a. Manual initiation from the control room, and HOPE CREEK 3/4 6-52

1 CONTAINMENT SYSTEMS U SURVEILLANCE REQUIREMENTS (Continued) :

b. Simulated automatic initiation signal.

3. Verifying that the heaters dissipate 100 1 10 kw for each recirculation unit and 32 1 3 kw for each ventilation unit when tested in accordance with ANSI N510-1980, and verifying humidity is maintained less than or equal to 70% relative humidity through the carbon adsorbers by performance of a channel calibration of the humidity control instrumentation.

f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Position C.S.a and C.5.0 of Regulatory Guide 1.52, Revi-sion 2 March 1978, while operating the system at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm i 10% for each FRVS ventilation unit.

g. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace (q penetration testing acceptance criteria of less than 0.05% in accor-dance with Regulatory Position C.S.a and C.S.d of Regulatory C) Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm i 10% for each FRVS ventilation unit.

i l O HOPE CREEK 3/4 6-53

CONTAINMENT SYSTEMS 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL CONTAINMENT HYDROGEN RECOMBINER SYSTEMS LIMITING CONDITION FOR OPERATION 3.6.6.1 Two independent containment hydrogen recombiner systems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one containment hydrogen recombiner system inoperable, restore the inoper-able system to OPERABLE status within 30 days or be in at least 110T SHUTDOWN within the next 12 hours. SURVEILLANCE REQUIREMENTS 4.6.6.1 Each containment hydrogen recombiner system shall be demonstrated OPERABLE:

a. At least once per 6 months by verifying during a recombiner system functional test that the minimum reaction chamber gas temperature increases to greater than or equal to 1150*F within 120 minutes and is maintained > 1150*F for at least 2 hours.

b. At least once per 18 months by:

1. Performing a CHANNEL CALIBRATION of all recombiner control panel instrumentation and control circuits.

2. Verifying the integrity of all heater electrical circuits by performing a resistance to ground test within 30 minutes follow-ing the ateve required functional test. The resistance to ground for any heater phase shall be greater than or equal to one megaohm.

O HOPE CREEK 3/4 6-54

A CONTAINMENT SYSTEMS DRYWELL AND SUPPRESSION CHAMBER OXYGEN CONCENTRATION LIMITING CONDITION FOR OPERATION 3.6.6.2 The drywell and suppression chamber atmosphere oxygen concentration shall be less than 4% by volume. APPLICABILITY: OPERATIONAL CONDITION 1*, during the time period:

a. Within 24 hours after THERMAL POWER is greater than 15% of RATED THERMAL POWER, following startup, to

b. Within 24 hours prior to reducing THERMAL POWER to less than 15% of RATED THERMAL POWER, preliminary to a scheduled reactor shutdown.

ACTION: With the drywell and/or suppression chamber oxygen concentration exceeding the limit, restore the oxygen concentration to within the limit within 24 hours or be in at least STARTUP within the next 8 hours. SURVEILLANCE REQUIREMENTS 4.6.6.2 The drywell and suppression chamber oxygen concentration shall be verified to be within the limit within 24 hours after THERMAL POWER is greater than 15% of RATED THERMAL POWER and at least once per 7 days thereafter.

 "See Special Test Exception 3.10.5.

O HOPE CREEK 3/4 6-55

l p 3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS SAFETY AUXILIARIES COOLING SYSTEM LIMITING CONDITION FOR OPERATION l 3.7.1.1 At least the following independernt safety auxiliaries cooling system (SACS) subsystems, with each subsystem comprised of:

a. Two OPERABLE SACS pumps, and

b. An OPERABLE flow path consisting of a closed loop through the SACS heat exchangers and SACS pumps and to associated safety related equipment shall be OPERABLE:

a. In OPERATIONAL CONDITION 1, 2 and 3, two subsystems.

b. In OPERATIONAL CONDITION 4, 5, and ** the subsystems associated with systems and components required OPERABLE by Specification 3.4.9.1, 3.4.9.2, 3.5.2, 3.8.1.2, 3.9.11.1 and 3.9.11.2.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5, and **. ACTION: O a. In OPERATIONAL CONDITION 1, 2, or 3:

1. With one SACS pump or heat exchanger inoperable, restore the inoperable pump or heat exchanger to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

l

2. With one SACS subsystem otherwise inoperable, realign the affected l diesel generators to the OPERABLE SACS subsystem within 2 hours, j and restore the inoperable subsystem to OPERABLE status with at least one OPERABLE pump and heat exchanger within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

3. With one SACS pump or heat exchanger in each subsystem inoperable, immediately initiate measures to place the unit in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

4. With both SACS subsystems otherwise inoperable, immediately initiate measures to place the unit in at least HOT SHUTDOWN

' within the next 12 hours and in COLD SHUTDOWN

in the following 24 hours.

          *Whenever both SACS subsystems are inoperable, if unable to attain COLD SHUTDOWN O'     as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
         **When handling irradiated fuel in the secondary containment.

HOPE CREEK 3/4 7-1

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued)

b. In OPERATIONAL CONDITION 3 or 4 with the SACS subsystem, which is associated with an RHR loop requim d OPERABLE by Specification 3.4.9.1 or 3.4.9.2, inoperable, declare the associated RHR loop inoperable and take the ACTION required by Specification 3.4.9.1 or 3.4.9.2, as applicable.

c. In OPERATIONAL CONDITION 4 or 5 with the SACS subsystem, which is associated with safety related equipment required OPERABLE by Speci-fication 3.5.2, inoperable, declare the associated safety related equipment inoperable and take the ACTION required by Specification 3.5.2.

d. In OPERATIONAL CONDITION 5 with the SACS subsystem, which is associated with an RHR loop required OPERABLE by Specification 3.9.11.1 or 3.9.11.2, inoperable, declare the associated RHR system inoperable and take the ACTION required by Specification 3.9.11.1 or 3.9.11.2, as applicable.

e. In OPERATIONAL CONDITION 4, 5, or **, with one SACS subsystem, which is associated with safety related equipment required OPERABLE by Specification 3.8.1.2, inoperable, realign the associated diesel generators within 2 hours to the OPERABLE SACS subsystem, or declare the associated diesel generators inoperable and take the ACTION re-quired by Specification 3.8.1.2. The provisions of Specifica-tion 3.0.3 are not applicable.

f. In OPERATIONAL CONDITION 4, 5, or **, with only one SACS pump and heat exchanger and its associated flowpath OPERABLE, restore at least two pumps and two heat exchangers and associated flowpaths to OPERABLE status within 72 hours or, declare the associated safety related equipment inoperable and take the associated ACTION requirements.

SURVEILLANCE REQUIREMENTS 4.7.1.1 At least the above required safety auxiliaries cooling system subsystems shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve in the flow

               . path that is not locked, sealed of atherwise secured in position, is in its correct position.

b. At least once per 18 months during shutdown by verifying that.: 1) Each automatic valve servicing safety related equipment actuates to its correct position on the appropriate test signal (s), and 2) Each pump starts automatically when its associated diesel generator automati-cally starts.

HOPE CREEK 3/4 7-2

l

   ^ PLANT SYSTEMS (U) STATION SERVICE 'JATER SYSTEM LIMITING CONDITION FOR OPERATION                                                       i 3.7.1.2 At least the following independent station service water system loops, with each loop comprised of:

a. Two OPERABLE station service water pumps, and

b. An OPERABLE flow path capable of taking suction from the Delaware River (ultimate heat sink) and transferring the water to the SACS heat exchangers, shall be OPERABLE:

a. In OPERATIONAL CONDITION 1, 2 and 3, two loops.

b. In OPERATIONAL CONDITION 4, 5 and *, one loop.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *. ACTION:

a. In OPERATIONAL CONDITION 1, 2, or 3:

1

1. With one station service water pump inoperable, restore the in-( operable pump to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

2. With one station service water pump in each loop inoperable, restore at least one inoperable pump to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, i 3. With one station service water system loop otherwise inoperable, restore the inoperable station service water system loop to l

OPERABLE status with at least one OPERABLE pump within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. In OPERATIONAL CONDITION 4 or 5:

With only one station service water pump and its associated flowpath OPERABLE, restore at least two pumps with at least one flow path to OPERABLE status within 72 hours or declare the associated SACS sub-System inoperable and take the ACTION required by Specification 3.7.1.1.

c. In OPERATIONAL CONDITION *:

With only one station service water pump and its associated flowpath OPERABLE, restore at least two pumps with at least one flow path to OPERABLE status within 72 hours or declare the associated SACS sub-O system inoperable and take the ACTION required by Specification 3.7.1.1. The provisions of Specification 3.0.3 are not applicable.

     *When handling irradiated fuel in the secondary containment.

HOPE CREEK 3/4 7-3

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.1.2 At least the above required station service water system loops shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve (manual, power operated or automatic), servicing safety related equipment that is not locked, sealed or otherwise secured in position, is in its correct position.

b. At least once per 18 months during shutdown, by verifying that:

1. Each automatic valve servicing non-safety related equipment actuates to its isolation position on an isolation test signal.

2. Each pump starts automatically when its associated diesel genera-tor automatically starts.

O O HOPE CREEK 3/4 7-4

i l

 ,q PLANT SYSTEMS Q  ULTIMATE HEAT SINK LIMITING CONDITION FOR OPERATION 3.7.1.3 The ultimate heat sink (Delaware River) shall be OPERABLE with:

a. A minimum river water level at or above elevation -13'O Mean Sea Level, USGS datum (76'O PSE&G datum), and

b. An average river water temperature of less than or equal to 90.5'F.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *. ACTION: With the requirements of the above specification not satisfied:

a. In OPERATIONAL CONDITIONS 1, 2 or 3, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

O b. In OPERATIONAL CONDITIONS 4 or 5, declare the SACS system and the V station service water system inoperable and take the ACTION required by Specification 3.7.1.1 and 3.7.1.2.

c. In Operational Condition *, declare the plant service water system inoperable and take the ACTION required by Specification 3.7.1.2.

The provisions of Specification 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS 4.7.1.3 The ultimate heat sink shall be determined OPERABLE: , a. By verifying the river water level to be greater than or equal to the minimum limit at least once per 24 hours.

b. By verifying river water temperature to be within its limit: ,

1-) at least once per 24 hours when the river water temperature is less than or equal to 85'F.

2) at least once per 6 hours when the river water temperature is i Greater than 85'F.

1 "When handling irradiated fuel in the secondary containment. HOPE CREEK 3/4 7-5

PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency filtration system subsystems shall be OPERABLE with each subsystem consisting of: a) One control room supply unit, b) One filter train, and c) One control room return air fan. APPLICABILITY: All OPERATIONAL CONDITIONS and *. ACTION:

a. In OPERATIONAL CONDITION 1, 2 or 3 with one control room emergency filtration subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. In OPERATIONAL CONDITION 4, 5 or *:

1. With one control room emergency filtration subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days or initiate and maintain operation of the OPERABLE subsystem in the pressurization / recirculation mode of operation.

2. With both control room emergency filtration subsystems inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

c. The provisions of Specification 3.0.3 are not applicable in Operational Condition *.

SURVEILLANCE REQUIREMENTS 4.7.2 Each control room emergency filtration subsystem shall be demonstrated OPERABLE:

a. At least once per 12 hours by verifying that the control room air temperature is less than or equal to 85'F .

b. At least once per 31 days on a STAGGERED TEST BASIS by initiating, from the control room, the control area chilled water pump, flow hen irradiated fuel is being handled in the secondary containment.

This does not require starting the non-running control emergency filtration subsystem. HOPE CREEK 3/4 7-6

PLANT SYSTEMS

   /7 i

SURVEILLANCE REQUIREMENTS (Continued) through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours with the heaters on in order to reduce the buildup of moisture on the carbon adsorbers and HEPA filters.

c. At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the subsystem by:

1. Verifying that the subsystem satisfies the in place penetration testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a. C.5.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system filter train flow rate is 4000 cfm i 10%.

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, by showing a methyl iodide penetration of less than 0.175% when tested at a temperature of 30'C and at a relative humidity of 70%

in accordance with ASTM D3803 with a 4 inch bed; and

;G

3. Verifying a subsystem filter train flow rate of 4000 cfm i 10%

during subsystem operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, by showing a methyl j iodide penetration of less than 0.175% when tested at a temperature of 30*C and at a relative humidity of 70% in accordance with ATSM D3803 with a 4 inch bed,

e. At least once per 18 months by:

1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 7.5 inches Water Gauge while operating the filter train subsystem at a flow rate of

! 4000 cfm i 10%. l

2. Verifying with the control room hand switch in the recirculation mode that on each of the below recirculation mode actuation test signals, the subsystem automatically switches to the isolation O mode of operation and the isolation dampers close within 5 seconds:

HOPE CREEK 3/4 7-7 I

PLANT SYSTEMS ^ SURVEILLANCE REQUIREMENTS (Continued) O a) High Drywell Pressure b) Reactor Vessel Water Level Low Low Low, Level 1 c) Control room ventilation radiation monitors high.

3. Verifying with the control room hand switch in the outside air mode that on each of the below pressurization mode actuation test signals, the subsystem automatically switches to the pressurization mode of operation and the control room is maintained at a positive pressure of at least 1/8 inch water gauge relative to adjacent areas during subsystem operation at a flow rate less than or equal to 1000 cfm:

a) High Drywell Pressure b) Reactor Vessel Water Level Low Low Low, Level I c) Control room ventilation radiation monitors high.

4. Verifying that the heaters dissipate 13 1 1.3 Kw when tested in

-                  accordance with ANSI N510-1980 and verifying humidity is maintained
  ~

less than or equal to 70% humidity through the carbon adsorbers by performance of a channel calibration of the humidity control instrumentation.

f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Positions C.S.a and C.S.c of Regulatory Guide 1.52, Revision 2, March 1978, while operating the system at a flow rate of 4000 cfm i 10%.

g. Af ter each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace pene-tration testing acceptance criteria of less than 0.05% in accordance with Regulatory Positions C.5.a and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 4000 cfm i 10%.

O HOPE CREEK 3/4 7-8

l PLANT SYSTEMS ~t b 3/4.7.3 FLOOD PROTECTION LIMITING CONDITION FOR OPERATION 3.7.3 Flood protection shall be provided for all safety related systems, components and structures when the water level of the Delaware River reaches 6.0 feet Mean Sea Level (MSL) USGS datum (95.0 feet PSE&G datum) at the Ser-vice Water Intake Structure. APPLICABILITY: At all times. ACTION:

a. With severe storm warnings from the National Weather Service which may impact Artificial Island in effect or with the water level at the service water intake structure above elevation 6.0 feet MSL USGS datum (95.0 feet PSE&G datum), initiate and complete:

1. The closing of all service water intake structure watertight perimeter flood doors identified in Table 3.7.3-1 within 1 hour, and I

t o 2. The closing of all power block watertight perimeter flood doors identified in Table 3.7.3-1 within 1.5 hours. Once closed, all access through the doors shall be administrative 1y controlled.

b. With the water level at the service water intake structure above elevation 10.5 fer.t MSL USGS datum (99.5 feet PSE&G datum), be in at least HOT SHUT-DOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

SURVEILLANCE REQUIREMENTS 4.7.3 The water level at the service water intake structure shall be deter-mined to be within the limit by:

a. Measurement at least once per 24 hours when the water level is below elevation 6.0 MSL USGS datum (95.0 feet PSE&G datum), and

b. Measurement at least once per 4 hours when severe storm warnings from the National Weather Service which may impact Artificial Island are l in effect. i I

c. Measurement at least once per hour when the water level is equal l to or above elevation 6.0 MSL USGS datum (95.0 feet PSE&G datum). !

b l , HOPE CREEK 3/4 7-9

l TABLE 3.7.3-1 PERIMETER FLOOD DOORS INTAKE STRUCTURE 000RS Water tight door 1 Water tight door 2 Water tight door 3 Water tight door 4 Water tight door 5 Water tight door 6 Water tight door 7 Water tight door 8 POWER BLOCK DOORS and HATCH Doors & Hatch Location Hatch Exterior 45; K

                                     "               45.5; L S-13 3340B
                                     "               44; M 3337B
                                     "               44; Md 6312
                                     "               45.4; T 6323B
                                     "               45.4; U 5315A
                                     "               29.9; X 5315C
                                     "               29; X 4323A
                                     "               13.6; U 4304
                                     "               13.6; U 3301A
                                      "              13.6; Md 3305B
                                      "              13.6; L 3315B  Interior-102'        25; H 3329A
                                      "              27; H 33318
                                      "               35; H 3209A  Interior             26; H O

HOPE CREEK 3/4 7-10

m PLANT SYSTEMS [V ) 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM LIMITING, CONDITION FOR OPERATION 3.7.4 The reactor core isolation cooling (RCIC) system shall be OPERABLE with an OPERABLE flow path capable of automatically taking suction from the suppression pool and transferring the water to the reactor pressure vessel. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3 with reactor steam dome pressure greater than 150 psig. ACTION: With the RCIC system inoperable, operation may continue provided the HPCI system is OPERABLE; restore the RCIC system to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours and reduce reactor steam dome p.ressure to less than or equal to 150 psig within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.7.4 The RCIC system shall be demonstrated OPERABLE:

a. At least once per 31 days by:

(\ 1. Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.

2. Verifying that each valve, manual, power operated or automatic in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.; 3. Verifying that the pump flow controller is in the correct position,; b. When tested pursuant to Specification 4.0.5 by verifying that the RCIC pump develops a flow of greater than or equal to 600 gpm in the
test flow path with a system head corresponding to reactor vessel operating pressure when steam is being supplied to the turbine at 1000 + 20. - 80 psig.*

        "The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours after reactor steam pressure is adequate *to perform the test.

l i HOPE CREEK 3/4 7-11 I o

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) O

c. At least once per 18 months by:

1. Performing a system functional test which includes simulated automatic actuation and restart # and verifying that each automatic valve in the flow path actuates to its correct position. Actual injection of coolant into the reactor vessel may be excluded.

2. Verifying that the system will develop a flow of greater than or equal to 600 gpm in the test flow path when steam is supplied to the turbine at a pressure of 150 + 15, - 0 psig."

3. Verifying that the suction for the RCIC system is automatically transferred from the condensate storage ta to the suppression pool on a condensate storage tank water level-low signal.

"The provisions 07 Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the tests.

Automatic restart on a low water level signal which is subsequent to a high water level trip.

O HOPE CREEK 3/4 7-12

PLANT SYSTEMS 3/4.7.5 SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.5 All snubbers shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1,2, and 3. OPERATIONAL CONDITIONS 4 and 5 for snubbers located on systems required OPERABLE in those OPERATIONAL CONDITIONS. ACTION:

'    dith one or more snubbers inoperable, within 72 hours replace or restore the inoperable snubber (s) to OPERABLE status and perform an engineering evaluation per Specification 4.7.5.g on the attached component or declare the attached system inoperable and follow the appropriate ACTION statement for that system.

SURVEILLANCE REQUIREMENTS i 4.7.5 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5. c a. Inspection Types 1 (V As used in this specification, type of snubber shall mean snubbers of the same design and manufactui ,r, irrespective of capacity.

b. Visual Inspections Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these groups (inaccessible and accessible) may be -

inspected independently according to the schedule below. The first , inservice visual inspection of each type of snubber shall be performed after 4 months but within 10 months of commencing power operation and shall include all snubbers. If all snubbers of each type are found , OPERABLE during the first inservice visual inspection, the second , inservice visual inspection shall be performed at the first refueling ! outage. Otherwise, subsequent visual insr.ections shall be performed in accordance with the following schedule: 1 O

V 1 1

HOPE CREEK 3/4 7-13

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continund) No. Inoperable Snubbers of Each Type per Subsequent Visual Inspection Period Inspection Period *# 0 18 months i 25% 1 12 months i 25% 2 6 months i 25% 3,4 124 days i 25% 5,6,7 62 days i 25% 8 or more 31 days i 25%

c. Visual Inspection Acceptance Criteria Visual inspections shall verify (1) that there are no visible indications of damage or impaired OPERABILITY, (2) attachments to the foundation or supporting structure are secure, and (3) fasteners for attachment of the snubber to the component and to the snubber anchorage are secure. Snubbers which appear inoperable as a result of visual inspections may be determined OPERABLE for the purpose of establishing the next visual inspection period, providing that:

(1) the cause of the rejection is clearly established and remedied for that particular snubber and for other snut,bers irrespective of type on that system that may be generically susceptible; or (2) the affected snubber is functionally tested in the as found condition and determined OPERABLE per Specifications 4.7.4.f. For those snubbers common to more than one system, the OPERABILITY of such snubbers shall be considered in assessing the surveillance schedule.

d. Transient Event Inspection An inspection shall be performed of all snubbers attached to sections of systems that have experienced unexpected, potentially damaging transients, as determined from a review of operational data or a visual inspection of the systems, within 72 hours for accessible systems and 6 months for inaccessible systems following this deter-mination. In addition to satisfying the visual inspection acceptance

' criteria, freedom-of-motion of mechanical snubbers shall be verified l using at least one of the following: (1) manually induced snubber j movement, or (2) evaluation of in-place snubber piston setting. I

  *The inspection interval for each type of snubber shall not be lengthened more tharf one step at a time unless a generic problem has been identified and corrected; in that event the inspection interval may be lengthened one steo l   the first time and two steps thereafter if no inoperable snubbers of that type are found.

l

  #The provisions of Specification 4.0.2 are not applicable.

O HOPE CREEK 3/4 7-14 1

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

   \  /

e. Functional Tests During the first refueling shutdown and at least once per 18 months thereafter during shutdown, a representative sample of snubbers shall be tested using one of the following sample plans for each type of s nt.bber. The sample plan shall be selected prior to the test period and cannot be changed during the test period. The NRC Regional Admin-istrator shall be notified in writing of the sample plan selected prior to the test period or the sample plan used in the prior test period shall be implemented:

1) At least 10% of the total of each type of snubber shall be functionally tested either in place or in a bench test. For each snubber of a type that does not meet the functional test acceptance criteria of Specification 4.7.5.f., an additional 10% of that type of snubber shall be functionally tested until no more failures are found or until all snubbers of that type have been functionally tested. Testing equipment failure during functional testing may invalidate that day's testing and allow that day's testing to resume anew at a later time, providing all snubbers tested with the failed equipment during the day of equipment failure are re-tested; or

2) A representative sample of each type of snubber shall be functionally tested in accordance with Figure 4.7.5-1. "C" is O the total number of snubbers of a type found not meeting the V acceptance requirements of Specification 4.7.5.f. The cumulative number of snubbers of a type tested is denoted by "N". At the end of testing "N" snubbers, the results shall be plotted on Figure 4.7.5-1. If at any time the point plotted falls on or above the " Reject" line all snubbers of that type shall be func-tionally tested. If at any time the point plotted falls on or below the " Accept" line, testing of snubbers of that type may be terminated. When the point plotted lies in the " Continue Test-4 ing" region, additional snubbers of that type shall be tested until the point falls in the " Accept" region or the " Reject" region, or all the snubbers of that type have been tested.

Testing equipment failure during functional testing may invali-date that day's testing and allow that day's testing to resume anew at a later time, providing all snubbers tested with the

,                        failed equipment during the day of equipment failure are retested; or

3) An initial representative sample of 55 snubbers of each type shall l be functionally tested. For each snubber type which does not meet

the functional test acceptance criteria, another sample of at least l one-half the size of the initial sample shall be tested until the total number tested is equal to the initial sample size multiplied by the factor, 1 + C/2, where "C" is the number of snubbers found which do not meet the functional test acceptance criteria. The l

results from this sample plan shall be plotted using an " Accept" j line which follows the equation N = 55(1 + C/2). Each snubber i s point should be pictted when "N" snubbers have been tested. If the 1 l l HOPE CREEK 3/4 7-15 l l l

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) point plotted falls on or below the " Accept" line, testing of that type of snubber may be terminated. If the point plotted falls above the " Accept" line, testing must continue until the point falls on or below the " Accept" line or all the snubbers of that type have been tested. Testing equipment failure during func-tional testing may invalidate that day's testing and allow that day's testing to resume anew at a later time, providing all snubbers tested with the failed equipment during the day of equipment failure are retested. The representative sample selected for the initial function test sample plans shall be randomly selected from the snubbers of each type and reviewed before beginning the testing. The review shall ensure as far as practical that they are representative of the var-ious configurations, operating environments, range of size, and capacity of snubbers of each type. Snubbers placed in the same locations as snubbers which failed the previous functional test shall be retested at the time of the next functional test but shall not be included in the sample plan, and failure of this functional test shall not be the sole cause for increasing the sample size under the sample plan. If during the functional testing, additional sampling is required due to failure of only one type of snubber, the func-tional testing results shall be reviewed at the time to determine if additional samples should be limited to the type of snubber which has failed the functional testing.

f. Functional Test Acceptance Criteria The snubber functional test shall verify that:

1) Activation (restraining action) is achieved within the specified range in both tension and compression;

2) Snubber bleed, or release rate where required, is present in both tension and compression, within the specified range (hydraulic snubbers only);

3) For mechanical snubbers, the force required to initiate or main-tain motion of the snubber is within the specified range in both directions of travel; and

4) For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without displacement.

           " Testing methods may be used to measure parameters indirectly or parameters other than those specified if those results can be corre-lated to the specified parameters through established methods.

g. Functional Test Failure Analysis An engineering evaluation shall be made of each failure to meet the functional test acceptance criteria to determine the cause of the failure. The results of this evaluation shall be used, if applicable, in selecting snubbers to be tested in an effort to determine the HOPE CREEK 3/4 7-16

PLANT SYSTEMS ' xs . SURVEILLANCE REQUIREMENTS (Continued) OPERABILITY of other snubbers irrespective of type which may be subject to the same failure mode. For the snubbers found inoperable, an engineering evaluation shall be performed on the components to which the inoperable snubbers are attached. The purpose of this engineering evaluation shall be to determine if the components to which the inoperable snubbers are attached were adversely affected by the inoperability of the snubbers in order to ensure that the component remains capable of meeting the designed service. If any snubber selected for functional testing either fails to lock up or fails to move, i.e., frozen-in place, the cause will be evaluated and if caused by manufacturer or design deficiency all snubbers of the same type subject to the same defect shall be functionally tested. This testing requirement shall be independent of the requirements stated in Specification 4.7.5.e. for snubbers not meeting the functional test acceptance criteria.

h. Functional Testing of Repaired and Replaced Snubbers Snubbers which fail the visual inspection or the functional test O acceptance criteria shall be repaired or replaced. Replacement snubbers and snubbers which have repairs which might affect the functional test result shall be tested to meet the functional test criteria before installation in the unit. Mechanical snubbers shall

! have met the acceptance criteria subsequent to their most recent service, and the freedom-of-motion test must have been performed ! within 12 months before being installed in the unit.

i. Snubber Service Life Replacement Program The service life of all snubbers shall be monitored to ensure that l the service life is not exceeded between surveillance inspections.

i The maximum expected service life for various seals, springs, and other critical parts shall be extended or shortened based on moni-l tored test results and failure history. Critical parts shall be replaced so that the maximum service life will not be exceeded during a period when the snubber is required to be OPERABLE. The parts replacements shall be documented and the documentation shall , he retained in accordance with Specification 6.10.3. HOPE CREEK 3/4 7-17

_u __ _ J 3 - _A _ l 10 9 8 REJECT j 8 " Oi [

c. -

o# / g 4

C/ CONTINUE

         *           /                    TESTING                 /

y / - 5

a f 49 ..C..,

0 10 20 30

                                   /40     50     SO 70    80   90 100 N

SAMPLE PLAN 2) FOR SNUBBER FUNCTIONAL TEST Figure 4.7.5-1 HOPE CREEK 3/4 7-18

EANTSYSTEMS 3/4.7.6 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.6 Each sealed source containing radioactive material either in excess of 100 microcur!es of beta and/or gamma emitting material or 5 microcuries of alpha emitting material shall be free of greater than or equal to 0.005 microcuries of removable contamination. APPLICABILITY: At all times. ACTION:

a. With a sealed source having removable contamination in excess of the above limit, withdraw the sealed source from use and either:

1. Decontaminate and repair the sealed source, or

2. Dispose of the sealed source in accordance with. Commission Regulations.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.6.1 Test Requirements - Each sealed source shall be tested for leakage and/or contamination by:

a. The licensee, or

b. Other persons specifically authorized by the Commission or an Agreement State.

The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample. 4.7.6.2 Test Frequencies - Each category of sealed sources, excluding startup sources and fission detectors previously subjected to core flux, shall be tested at the frequency described below.

a. Scurces in use - At least once per six months for all sealed sources containing radioactive material:

1. With a half-life greater than 30 days, excluding Hydrogen 3, and

2. In any form other than gas.

HOPE CREEK 3/4 7-19

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. Stored sources not in use - Each sealed source and fission detector shall be tested prior to use or transfer to another licensee unless tested within the previous six months. Sealed sources and fission detectors transferred without a certificate indicating the last test date shall be tested prior to being placed into use.

c. Startup sources and fission detectors - Each sealed startup source and fission detector shall be tested within 31 days prior to being subjected to core flux or installed in the core and following repair or maintenance to the source.

4.7.6.3 Reports - A report shall be prepared and submitted to the Commission on an annual basis if sealed source or fission detector leakage tests reveal the presence of greater than or equal to 0.005 microcuries of removable contamination. O O HOPE CREEK 3/4 7-20

PLANT SYSTEMS 3/4.7.7 MAIN TURBINE BYPASS SYSTEM LIMITING CONDITION FOR OPERATION 3.7.7 The main turbine bypass system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITION 1. ACTION: With the main turbine bypass system inoperable, restore the system to OPERABLE status within 2 hours or reduce THERMAL POWER to less than or equal to 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REQUIREMENTS 4.7.7 The main turbine bypass system shall be demonstrated OPERABLE at least once per:

a. 31 days by cycling each turbine bypass valve through at least one complete cycle of full travel, and

b. 18 months by:

1. Performing a system functional test which includes simulated automatic actuation and verifying that each automatic valve actuates to its correct position.

2. Demonstrating TURBINE BYPASS SYSTEM RESPONSE TIME meets the following requirements when me'asured from the initial movement of the main turbine stop or control valve:

a) 80% of turbine bypass system capacity shall be established in less than or equal to 0.3 second. b) Bypass valve opening shall start in less than or equal to 0.1 second. HOPE CREEK 3/4 7-21

l r~' 3/4.8 ELECTRICAL POWER SYSTEMS l f (m,,)/ 3/4.8.1 A.C. SOURCES A.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION

3. 8.1.1 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

1

a. Two physically independent circuits between the offsite transmission l network and the onsite Class lE distribution system, and i

b. Four separate and independent diesel generators, each with:

1. A separate fuel oil day tank containing a minimum of 200 gallons of fuel,

2. A separate fuel storage system consisting of two storage tanks containing a minimum of 48,800 gallons of fuel, and

3. A separate fuel transfer pump for each storage tank.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3. ACTION:

a. With one offsite circuit of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C.

sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter. If any diesel generator has not been successfully tested within the past 24 hours, ('s ' demonstrate its OPERABILITY by performing Surveillance Require-ment 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 for each such diesel generator separately within 24 hours. Restore the inoperable offsite circuit to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,

b. With one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the above required A.C. offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter. If the diesel generator became inoperable due to any cause other than preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by performing Surveillance Require-ment 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for each diesel generator within 24 hours *; restore the inoperable diesel generator to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

c. "With one offsite circuit of the above required A.C. sources and one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and "This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY.

HOPE CREEK 3/4 8-1

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) at least once per 8 hours thereafter. If a diesel generator became inoperable due to any causes other than preplanned preventive main-tenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE diesel generators separately for each diesel generator by performing Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 within 24 hours.* Restore at least two offsite circuits and all four of the above required diesel generators to OPERABLE status within 72 hours from time of the initial loss or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. A successful test (s) of diesel generator OPERABILITY per Sur-veillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 performed under this ACTION statement for the OPERABLE diesel generators satisfies the diesel generator test requirements of ACTION Statement b.

d. With both of the above required offsite circuits inoperable, demon-strate the OPERABILITY of all of the above required diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for each diesel generator within 8 hours unless the diesel generators are already operating; restore at least one of the above required offsite circuits to OPERABLE status within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours. With only one off-site circuit restored to OPERABLE status, restore at least two offsite circuits to OPERABLE status within 72 hours from time of initial loss or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. A successful test (s) of diesel generator OPERABILITY per Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 performed under this ACTION statement for the OPERABLE diesel generators satisfies the diesel generator test requirements of ACTION statement a.; e. With two diesel generators of the above required A.C. electrical power l sources inoperable, demonstrate the OPERABILITY of the above required A.C. offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter and demonstrate the OPERABILITY of the remaining diesel generators by performing Sur-l veillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for l each diesel generator within 8 hours.* Restore at least one of the l inoperable diesel generators to OPERABLE status within 2 hours or be
in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN l within the following 24 hours. Restore both of the inoperable diesel l

generators to OPERABLE status within 72 hours from time of initial loss or be in at least HOT SHUTDOWN within the next 12 hours and in i

     *This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY.

HOPE CREEK 3/4 8-2

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) l l COLD SHUTDOWN within the following 24 hours. A successful test (s) of i diesel generator OPERABILITY per Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 performed under this ACTION statement for the OPERABLE diesel generators satisfies the diesel generator test re-quirements of ACTION Statements a and b.

f. With two diesel generators of the above required A.C. electrical power sources inoperable, in addition to ACTION e., above, verify within 2 hours that all required systems, subsystems, trains, components, and devices that depend on the remaining diesel generators as a source of emergency power are also OPERABLE; otherwise, be in at least HOT SHUT-DOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

g. With one offsite circuit and two diesel generators of the above re-quired A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter and demonstrate the OPERABILITY of the remaining diesel s '

generators by performing Surveillance Requirements 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for each diesel generator within 8 hours.* Restore at least one of the above required inoperable A.C. sources to OPERABLE status within 2 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. Restore the inoperable offsite circuit and both of the inoperable diesel generators to OPERABLE status within 72 hours from time of initial loss or be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the following 24 hours.

     "This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY.

HOPE CREEK 3/4 8-3 '

l ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS O 4.8.1.1.1 Each of the above required independent circuits between the offsite transmission network and the onsite Class 1E distribution system shall be: i

a. Determined OPERABLE at least once per 7 days by verifying correct breaker alignments and indicated power availability, and i

b. Demonstrated OPERABLE at least once per 18 months during shutdown by transferring, manually and automatically, unit power supply from the normal circuit to the alternate circuit.

4.8.1.1.2 Each of the above required diesel generators shall be demonstrated l OPERABLE:

a. In accordance with the frequency specified in Table 4.8.1.1.2-1 on a STAGGERED TEST BASIS by:

1. Verifying the fuel level in the fuel oil day tank.

2. Verifying the fuel level in the fuel oil storage tank.

3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the fuel oil day tank.

4. Verifying the diesel starts from ambient conditions and accel-erates to at least 514 rpm in less than or equal to 10 seconds after receipt of the start signal.* The generator voltage and frequency shall be 4160 1 420 volts and 60 1 1.2 Hz within 10 seconds after receipt of the start signal. The diesel generator shall be started for this test by using one of the following signals:

a) Manual. b) Simulated loss of offsite poser by itself. c) Simulated loss of offsite power in conjunction with an ESF actuation test signal. d) An ESF actuation test signal by itself.

5. Verifying the diesel generator is synchronized, loaded to between 4300 and 4400** kw in less than or equal to 130 seconds,*

and operates with this load for at least 60 minutes. 1 "The diesel generator start (10 sec) and subsequent loading (130 sec) from ambient conditions shall be performed at least once per 184 days in these j surveillance tests. All other engine starts and loading for the purpose of : this surveillance testing may be preceded by an engine prelube period and/or l other warmup procedures recommended by the manufacturer so that mechanical stress and wear on the diesel engine is mini:aized.

 **This band is meant as guidance to avoid rc, dine overloading of the engine.

Loads in excess of this band shall not invalidate the test; the loads, however, shall not be less than 4300 kw nor greater than 4430 kw. HOPE CREEK 3/4 8-4

i ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

6. Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

7. Verifying the pressure in all diesel generator air start receivers to be greater than or equal to 380 psig.

8. Verifying the lube oil pressure, temperature and differential pressure across the lube oil filters to be within manufac-turer's specifications.

b. At least once per 31 days by visually examining a sample of lube oil from the diesel engine to verify absence of water.

c. At least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to I hour by checking for and removing accumulated water from the fuel oil day tank.

d. At least once per 92 days by removing accumulated water from the fuel oil storage tanks.

e. At least once per 31 days by performing a functional test on the emergency load sequencer to verify operability.

f. At least once per 92 days and from new fuel oil prior to addition to the storage tanks by obtaining a sample in accordance with ASTM-D270-1975 and by verifying that the sample meets the following minimum requirements and is tested within the specified time limits:

1. As soon as sample is taken or from new fuel prior to addition to the storage tank, as applicable, verify in accordance with the tests specified in ASTM-D975-77 that the sample has:

a) A water and sediment content of less than or equal to 0.05 volume percent. b) A kinematic viscosity @ 40 C of greater than or equal to 1.9 centistokes, but less than or equal to 4.1 centistokes or a Saybolt Second Universal (SSU) viscosity at 100 F of greater than or equal to 32 SSU but less than or equal to 40.1 SSU. c) A specific gravity as specified by the manufacturer as API gravity @ 60 F of greater than or equal to 28 degrees but less than or equal to 42 degrees.

2. Within one week after obtaining the sample, verify an impurity

(~} level of less than 2 mg of insolubles per 100 ml. when tested in accordance with ASTM-D2274-70. (O 1 HOPE CREEK 3/4 8-5

ELECTRICAL POWER SYSTEMS l l SURVEILLANCE REQUIREMENTS (Continued) O: t

3. Within 2 weeks after obtaining the sample, verify that the l other properties specified in Table 1 of ASTM-0975-77 and Regulatory Guide 1.137, Position 2.a, are met when tested in accordance with ASTM-D975-77.

g. At least once per 2 months, by verifying the buried fuel oil transfer piping's cats dic o protection system is OPERABLE and at least once per year by subjecting the cathodic protection system to a performance test.

(

h. At least once per 18 months #, during shutdown, by:

1. Subjecting the diesel to an inspection in accordance with l procedures prepared in conjunction with its manufacturer's recommendations for this class of standby service.

2. Verifying the diesel generator capability.to reject a load of greater than or equal to that of the RHR pump motor (1003 kW) for each diesel generator while maintaining voltage at 4160 1 420 volts and frequency at 60 1 1.2 Hz.

3. Verifying the diesel generator capability to reject a load of 4430 kW without tripping. The generator voltage shall not exceed 4580 volts during and following the load rejection.

4. Simulating a loss of offsite power by itself, and:

a) Verifying loss of power is detected and deenergization of the emergency busses and load shedding from the emergency busses. b) Verifying the diesel generator starts

on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds after receipt of the start signal, energizes the autoconnected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 1 420 volts and 60 1 1.2 Hz during this test.

            ~
 *This diesel generator start (10 sec) and subsequent loading (130 sec) from ambient conditions may be preceded by an engine prelube period and/or other warmup procedures recommended by the manufacturer so that mechanical stress and wear on the diesel engine is minimized.
 #For any start of a diesel generator, the diesel must be loaded in accordance with the manufacturer's recommendations.

O HOPE CREEK 3/4 8-6

i l 1 (N ELECTRICAL POWER SYSTEMS kv) SURVEILLANCE REQUIREMENTS (Continued)

5. Verifying that on an ECCS actuation test signal, without loss of offsite power, the diesel generator starts on the auto-start signal and operates on stand 5y for greater than or equal to 5 minutes. The generator voltage and frequency shall be 4160 1 420 volts and 60 1 1.2 Hz within 10 seconds after the auto-start signal; the steady state generator voltage and fre-quency shall be maintained within these limits during this test.

6. Simulating a loss of offsite power in conjunction with an ECCS actuation test signal, and:

a) Verifying loss of power is detected and deenergization of the emergency busses and load shedding from the emergency busses. b) Verifying the diesel generator starts

on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds after receipt of the start signal, energizes the autoconnected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with O the emergency loads. After energization, the steady state Q voltage and frequency of the emergency busses shall be main-tained at 4100 1 420 volts and 60 i 1.2 Hz during this test.

7. Verifying that all automatic diesel generator trips, except engine overspeed, generator differential current, generator overcurrent, bus differential current and low lube oil pressure are automatically bypassed upon loss of voltage on the emergency bus concurrent with an ECCS actuation signal.#

8. Verifying the diesel generator operates for at least 24 hours.

During the first 22 hours of this test, the diesel generator shall be loaded to between 4300 and 4400 kW** and during the remaining 2 hours of this test, the diesel generator shall be loaded to between 4800 and 4873 kW. The generator voltage and

      *This diesel generator start (10 sec) and subsequent loading (130 sec) from                              ,

ambient. conditions may be preceded by an engine prelube period and/or other i warmup procedures recommended by the manufacturer so that mechanical stress { and wear on the diesel engine is minimized. l

     **This band is meant as guidance to avoid routine overloading of the engine.                              j Loads in excess of this band shall not invalidate the test; the loads;                                  )

however, shall not be less than 4300 kW nor greater than 4873 kW. l

      # Generator differential current, generator overcurrent, and bus differential i(v p)    current is two-out-of-three logic and low lube oil pressure is two-out-of-four logic.

l HOPE CREEK 3/4 8-7 l l

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) frequency shall be 4160 420 volts and 60 1 1.2 Hz within 10 seconds after the start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test. Within 5 minutes after completing this 24-hour test, perform Surv5illance Requirement 4.8.1.1.2.h.4.b).**

9. Verifying that the auto-connected loads to each diesel generator do not exceed the continuous rating of 4430 kW.

10. Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated restoration of offsite power, b) Transfer its loads to the offsite power source, c) Be restored to its standby status, and d) Diesel generator circuit breaker is open.

11. Verifying that with the diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal overrides the test mode by (1) returning the diesel generator to standby operation, and (2) automatically energizes the emergency loads with offsite power.

12. Verifying that the fuel oil transfer pump transfers fuel oil from each fuel storage tank to the day tank of each diesel via the installed cross connection lines.

13. Verifying that the automatic load sequence timer is OPERABLE with the interval between each load block within i 10% of its design interval.

14. Verifying that the following diesel generator lockout features prevent diesel generator starting only when required:

a) Engine overspeed, generator differential, and low lube oil pressure (regular lockout relay, (1) 86R). l b) Backup generator differential and generator overcurrent l (backup lockout relay, (1) 86B) c) Generator ground and lockout relays-regular, backup and l test, energized (breaker failure lockout relay, (1) 86F)

 **If Surveillance Requirement 4.8.1.1.2.h.4.b) is not satisfactorily completed, i    it is not necessary to repeat the preceding 24 hour test. Instead, the diesel generator may be operated at between 4300 kw and 4400 kw for one hour or until operating temperature has stabilized prior to repeating Surveillance Requirement 4.8.1.1.2.h.4.b).

l HOPE CREEK 3/4 8-8

1 ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

1. At least once per 10 years or after any modifications which could i affect diesel generator interdependence by starting all diesel generators simultaneously, during shutdown, and verifying that all diesel generators accelerate to at least 514 rpm in less than

or equal to 10 seconds.

j. At least once per 10 years by:

1. Draining each fuel oil storage tank, removing the accumulated sediment and cleaning the tank using a sodium hypochlorite solution or equivalent, and i 2. Performing a pressure test of those portions of the diesel fuel oil system designed to Section III, subsection ND of the ASME Code in accordance with ASME Code Section XI Article IWD-5000.

4.8.1.1.3 Reports - All diesel generator failures, valid or non-valid, shall be reported to the Commission within 30 days pursuant to Specification 6.9.2. Reports of diesel generator failures shall include the information recommended in Regulatory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977. If the number of failures in the last 100 valid tests, on a per nuclear unit basis, is greater than or equal to 7, the report shall be supplemented to include the additional information recommended in Regulatory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977. i l l t l l l HOPE CREEK 3/4 8-9 l

l TABLE 4.8.1.1.2-1 DIESEL GEtaERATOR TEST SCHEDULE O ) Number of Failures in Nucbar of Failures in Last 20 Valid Tests

Last 106 Valid Tests
Test Frequency 11 14 Once per 31 days 2 2** 25 Once per 7 days 1
Criteria for determining number of failures and number of valid tests shall be in accordance with Regulatory Position C.2.e of Regulatory Guide 1.108, but determined on a per diesel generator basis.

For the purposes of determining the required test frequency, the previous test failure count may be reduced to zero if a complete diesel overhaul to like-new condition is completed, provided that the overhaul including appropriate post-maintenance operation and testing, is specifically approved by the manufacturer and if acceptable reliability has been demonstrated. The reliability criterion shall be the successful completion of 14 consecutive tests in a single series. Ten of these tests shall be in accordance with the routine Surveillance Require-ment 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5, four tests, in accordance with the 184-day testing requirement of Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5. If this criterion is not satisfied during the first series of tests, any alter-nate criterion to be used to transvalue the failure count to zero requires NRC approval.

 **The associated test frequency shall be maintained until seven consecutive failure free demands have been performed and the number of failures in the last 20 valid demands has been reduced to one.

O HOPE CREEK 3/4 8-10

l l ELECTRICAL POWER SYSTEMS b) A.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.1.2 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. One circuit between the offsite transmission network and the onsite Class 1E distribution system, and

b. Two diesel generators, one of which shall be diesel generator A or diesel generator B, each with:

1. A separate fuel oil day tank containing a minimum of 200 gallons of fuel.

2. A fuel storage system consisting of two storage tanks containing a minimum of 48,800 gallons of fuel.

3. A separate fuel transfer pump for each storage tank.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. V ACTION:

a. With less than the above required A.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment, operations with a potential for draining the reactor vessel and crane operations over the spent fuel storage pool when fuel assemblies are stored therein. In addition, when in OPERATIONAL CONDITION 5 with the water level less than 22'-2" above t.5e reactor pressure vessel flange, immediately initiate corrective ac fon to restore the required power sources to OPERABLE status as soon as practical.

b. The provisions of Specification 3.0.3 are not applicable. .

SURVEILLANCE REQUIREMENTS 4.8.1.2 At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1, 4.8.1.1.2, i and 4.8.1.1.3, except for the requirement of 4.8.1.1.2.a.5. (3 l

    "When handling irradiated fuel in the secondary containment.

HOPE CREEK 3/4 8-11

ELECTRICAL POWER SYSTEMS 3/4.8.2 D.C. SOURCES D.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 As a minimum, the following D.C. electrical power sources shall be OPERABLE:

a. Channel A, consisting of:

1. 125 volt battery 1AD4?.1

2. 125 volt full capacity charger 1AD413 or 1AD414

3. 250 volt battery 1.0D421;

4. 250 volt full capacity charger 10D423

b. Channel B, consisting of:

1. 125 volt battery 18D411

2. 125 volt full capacity charger 180413 or 180414

3. 250 volt battery 10b431;

4. 250 volt full capacity charger 100433

c. Channel C, consisting of:

1. 125 volt battery 1CD411

2. 125 volt full capacity charger 1C0413 or 1C0414

3. 125 volt battery ICD 447

4. 125 volt full capacity charger 1C0444

d. Channel D, consisting of:

1. 125 volt battery 10D411

2. 125 volt full capacity charger 3DD413 or IDD414

3. 125 volt battery 100447

4. 125 volt full capacity charger 100444 l

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With any 125v battery and/or all associated chargers of the above required D.C. electrical power sources inoperable, restore the inoperable channel to OPERABLE status within 2 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With any 250v battery and/or charger of the above required DC electrical power sources inoperable, declare the associated HPCI or RCIC system inoperable and take the appropriate ACTION required by the applicable Specification.

1 O HOPE CREEK 3/4 8-12

l l ( ELECTRICAL POWER SYSTEMS V] SURVEILLANCE REQUIREMENTS 4.8.2.1 Each of the above required batteries and chargers shall be demon-strated OPERABLE:

a. At least once per 7 days by verifying that:

1. The parameters in Table 4.8.2.1-1 meet the Category A limits, and

2. Total battery terminal voltage for each 125-volt battery is greater than or equal to 129 volts on float charge and for each 250-volt battery the terminal voltage is greater than or equal to 258 volts on float charge.

b. At least once per 92 days and within 7 days after a battery discharge with battery terminal voltage below 105 volts for a 125-volt battery or 210 volts for a 250-volt battery, or battery overcharge with battery terminal voltage above 140 volts for a 125-volt battery or 280 volts for a 250-volt battery, by verifying that:

1. The parameters in Table 4.8,2.1-1 meet the Category B limits,

2. There is no visible corrosion at either terminals or connectors,

    /N                             or the connection resistance of these items is less than 150 x 10 8 ohms, excluding cable intercell connections, and U)

I

3. The average electrolyte temperature of each sixth cell of connected cells is above 60 F.

c. At least once per 18 months by verifying that:

1. The cells, cell plates and battery racks show no visual

! indication of physical damage or abnormal deterioration,

2. The cell-to-cell and terminal connections are clean, tight, free of corrosion and coated with anti-corrosion material,

3. The resistance of each cell-to-cell and terminal connection is less than or equal to 150 x 10 8 ohms, excluding cable intercell connections, and

4. The battery charger will supply the current listed below at the j

voltage listed below for at least 8 hours.* CURRENT l CHARGER Minimum Voltage (AMPERES) l 200 1AD413, 1AD414 129 18D413, 180414 1CD413, 1C0414 1C0444, 10D414 100444,.10D413 O 10D423, 100433 258 50

Prior to startup following the first refueling outage, this test may be per-l formed for at least 4 hours.

HOPE CREEK 3/4 8-13

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

d. At least once per 18 months, during shutdown, by verifying that either:

1. The battery capacity is adequate to supply and maintain in OPERABLE status all of the actual emergency loads for the design duty cycle when the battery is subjected to a battery service test, or

2. The battery capacity is adequate to supply a dummy load of the following design profile while maintaining the battery terminal voltage greater than or equal to 105 volts for the 125-volt battery and 210 volts for the 250-volt battery:

Load Profile Duration in 125 Volt Battery Amperes Sequence (Minutes] 1AD411 451.1 1 330.4 1 273.0 8 270.4 50 298.1 180 180411 443.3 1 326.5 1 267.2 8 267.9 30 267.2 20 289.6 180 1CD411 419.2 1 359.2 1 272.2 58 l 299.2 180 10D411 416.3 1 356.3 1 269.3 58 294.3 180 l 125 Volt Eattery 1CD447 68 60 l 77 180 1 l 10D447 73 60 80 180 250 Volt Battery 100421 758.1 1 42.6 7 HOPE CREEK 3/4 8-14

w ELECTRICAL POWER SYSTEMS I SURVEILLANCE REQUIREMENTS (Continued) Load Profile (Continued) Duration in 250 Volt Battery Amperes Sequence (Minutes) 10D421 (Continued) 307.9 1 42.6 41 348.9 1 42.6 7 307.9 1 42.6 41 348.9 1 42.6 7 307.9 1 42.6 41 387.9 1 83.6 89 100431 197.9 1 25.3 5 66.3 1

   }                                                             25.3                              17 74.7                                1 33.7                             125 33.7                              60 56.3                                1 33.7                              29

e. At least once per 60 months during shutdown by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test. At this once per l

60 month interval, this performance discharge test may be performed in lieu of the battery service test.

f. At least once per 18 months during shutdown performance discharge tests of battery capacity shall be given to any battery that shows signs of degradation or has reached 85% of the service life expected for the application. Degradation is indicate'd when the battery capacity drops more than 10% of rated capacity from its average on

                            . previous performance tests, or is below 90% of the manufacturer's rating. At this once per 18 months interval, this performance dis-charge test may be performed in lieu of the battery service test.

HOPE CREEK 3/4 8-15

TABLE 4.8.2.1-1 BATTERY SURVEILLANCE REQUIREMENTS CATEGORY A f1) CATEGORY B(2) Parameter Limits for each Limits for each A11owable(3) designated pilot connected cell value for each cell connected cell Electrolyte > Minimum level > Minimum level Above top of Level Indication mark, indication mark, plates, and < " above and < %" above and not maximum level maximum level overficwing indication mark (d) indication mark (d) Float Voltage > 2.13 volts > 2.13 volts (c) > 2.07 volts Not more than

                                                                    .020 below the average of all
                                               > 1.195              connected cells Specifig)             > 1.200(b)                Average of all       Average of all Gravity                                          connected cells     connectg) cells
                                                > 1.205             > 1.195 (a) Corrected for electrolyte temperature and level.

(b)0r battery charging current is less than 2 amperes when on float charge. (c)May be corrected for average electrolyte temperature. (d) Electrolyte level may exceed 1/4" above maximum level indication mark if an equalizing charge is in progress or an equalizing charge has been completed within the previous 72 hours. (1)For any Category A parameter (s) outside the limit (s) shown, the battery may be considered OPERABLE provided that within 24 hours all the Category B measurements are taken and found to be within their allowable values, and provided all Category A and B parameter (s) are restored to within limits within the next 6 days. (2)For any Category B parameter (s) outside the limit (s) shown, the battery may be sonsidered OPERABLE provided that the Category B parameters are within their allowable values and provided the Category B parameter (s) are restored to within limits within 7 days. (3)Any Category B parameter not within its allowable value indicates an inoperable battery. O HOPE CREEK 3/4 8-16

ELECTRICAL POWER SYSTEMS O D.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, two of the following four channels of the D.C. electrical power sources, one of which shall be channel A or channel 8, shall be OPERABLE with: , a. Channel A, consisting of:

1. 125 volt battery 1AD411

2. 125 volt full capacity charger # 1AD413 or IAD414

b. Channel B, consisting of:

1. 125 volt battery 18D411

2. 125 volt full capacity charger # IBD413 or 18D414.

c. Channel C, consisting of:

1. 125 volt battery 1C0411

2. 125 volt full capacity charger # 1C0413 or 10D414

3. 125 volt battery 1C0447

4. 125 volt full capacity charger ICD 444

d. Channel D, consisting of:

1. 125 volt battery 1D0411

2. 125 volt full capacity charger # 1D0413 or 100414

3. 125 volt battery 1D0447

4. 125 volt full capacity charger 1DD444 APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. ,

ACTION:

a. With less than two channels of the above required D.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.2.2 At least the above required battery and charger shall be demonstrated l OPERABLE per Surveillance Requirement 4.8.2.1.

   "When handling irradiated fuel in the secondary containment.
   #Dnly one full capacity charger per battery is required for the channel to be OPERABLE.

HOPE CREEK 3/4 8-17

ELECTRICAL POWER SYSTEMS 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.3.1 The following power distribution system channels shall be energized:

a. A.C. power distribution:

1. Channel A, consisting of:

a) 4160 volt A.C. switchgear bus 10A401 b) 480 volt A.C. load centers 10B410 108450 c) 480 volt A.C. MCCs 108212 10B411 10B451 108553 d) 208/120 volt A.C. distribution panels 10Y401(source:10B411) 10Y411(source:10B451) 10YS01(source:10B553) e) 120 volt A.C. distribution panels 1AJ481 1YF401(source:1AJ481) 1AJ482

2. Channel B, consisting of:

a) 4160 volt A.C. switchgear bus 10A402 b) 480 volt A.C. load centers 108420 10B460 c) 480 volt A.C. MCCs 108222 108421 10B461 108563 d) 208/120 volt A.C. distribution panels 10Y402(source:108421) 10Y412(source:10B461) 10Y502(source:10B563) e) 120 volt A.C. distribution panels 1BJ481 1YF402(source:1BJ481) IBJ482

3. Channel C, consisting of:

s) 4160 volt A.C. switchgear bus 10A403 b) 480 volt A.C. load centers 10B430 10B470 c) 480 volt A.C. MCCs 108232 108431 10B471 10B573 d) 208/120 volt A.C. distribution panels 10Y403(source:108431) 10Y413(source:10B471) 10Y503(source:108573) HOPE CREEK 3/4 8-18

e ~s s ELECTRICAL POWER SYSTEMS ( )

 \s /      LIMITING CONDITION FOR OPERATION (Continued)
                     'e)   120 volt A.C. distribution panels          ICJ481 1YF403(source:1CJ481)

ICJ482

4. Channel D, consisting of:

a) 4160 volt A.C. switchgear bus 10A404 b) 480 volt A.C. load centers 108440 108480 c) 480 volt A.C. MCCs 10B242 108441 108481 108583 d) 208/120 volt A.C. distribution panels 10Y404(source:108441) 10Y414(source:108481) 10Y504(source:10B583) e) 120 volt A.C distribution panels 1DJ481 1YF404(source:1DJ481) 1DJ482

b. D.C. power distribution:

1. Channel A, consisting of:

a) 125 volt D.C. switchgear 10D410 Os - b) c) 125 volt D.C. fuse box 125 volt D.C. distribution panel 1AD412 1AD417 d) 250 volt D.C. switchgear 10D450 e) 250 volt D.C. fuse box 10D422

f) 250 volt D.C. MCC 10D251: 2. Channel B, consisting of:

a) 125 volt D.C. switchgear 10D420 b) 125 volt D.C. fuse box 1BD412 i c) 125 volt D.C. distribution panel 180417 ! d) 250 volt D.C. switchgear 10D460 l e) 250 volt D.C. fuse boxes 10D432 f) 250 volt D.C. MCC 10D261

3. Channel C, consisting of:

a) 125 volt D.C. switchgear 10D430

                                                                     '100436 b)   125 volt D.C. fuse box                     ICD 412
                     .                                                1CD448 c)  125 volt D.C. distribution   panel         1C0417

4. Channel D, consisting of:

a) 125 volt D.C. switchgear 10D440 10D446 , b) 125 volt D.C. fuse boxes 100412 10D448 [} v c) 125 volt D.C. distribution panel IDD417 HOPE CREEK 3/4 8-19

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one of the above required A.C. distribution system channels not energized, re-energize the channel within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With one of the above required 125 volt D.C. distribution system channels not energized, re-energize the division within 2 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

c. With any one of the above required 250 volt D.C. distribution systems not energized, declare the associated HPCI or RCIC system inoperable and apply the appropriate ACTION required by the applicable Specifications.

SURVEILLANCE REQUIREMENTS 4.8.3.1 Each of the above required power distribution system channels shall be determined energized at least once per 7 days by verifying correct breaker / switch alignment and voltage on the busses /MCCs/ panels. O HOPE CREEK 3/4 8-20

i I i

  ,/]        ELECTRICAL POWER SYSTEMS
   'G                                                                                                        l DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION                                                             I 3.8.3.2 As a minimum, 2 of the 4 channels, one of which shall be channel A or                ,

channel 8, of the power distribution system shall be energized with.

a. A.C. power distribution: ,

1. Channel A, consisting of: [

a) 4160 volt A.C. switchgear bus 10A401 b) 480 volt A.C. load centers 108410 - 108450 c) 480 volt A.C. MCCs 108212 108411 108451 108553 , d) 208/120 volt A.C. distribution panels 10Y401(source:10B411) 10Y411(source:108451) 10Y501(source:103553) e) 120 volt A.C. distribution panels 1AJ481 1YF401(source:1AJ431) ' 1AJ482 p.

  >                        2. Channel B, consisting of:                                                 :
  \

a) 4160 volt A.C. switchgear bus 10A402 ! b) 480 volt A.C. load centers 10B420 10B460 : c) 480 volt A.C. MCCs 108222 10B421 108461 , 108563 1 d) 208/120 volt A.C. distribution panels 10Y402(source:108421) 10Y412(source:108461) i 10Y502(source:108563) l e) 120 volt A.C. distribution panels IBJ481 1YF402(source:1BJ481) 1BJ482

3. Channel C, consisting of:

a) 4160 volt A.C. switchgear bus 10A403 b) 480 volt A.C. load centers 108430 1 10B470 l c) 480 volt A.C. MCCs 10B232 108431 10B471 108573 d) 208/120 volt A.C. distribution panels 10Y403(source:108431) , 10Y413(source:108471) 10Y503(source:108573) HOPE CREEK 3/4 8-21 l

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPEPATION_(Continued) e) 120 volt A.C. cistribution panels 1CJ481 l 1YF403(source:1CJ481) ICJ482 1

4. Channel D, consisting of:

a) 4160 volt A.C. switchgear bus 10A404 b) 480 volt A.C. Ioad centers 108440 108480 c) 480 volt A.C. MCCs 108242 108441 108481 108583 d) 208/120 volt A.C. distribution panels 10Y404(source:108441) 10Y414(source:108481) 10Y504(source:108583) e) 120 volt A.C. distribution panels 1DJM1 1YF404(source:1DJ481) 1DJ482

b. 0.C. power distribution:

1. Channel A, consisting of:

a) 125 volt D.C. switchgear 10D410 b) 125 volt D.C. fuse box 1AD412 c) 125 volt D.C. distribution panel 1AD417

2. Channel 8, consisting of:

a) 125 volt D.C. switchgear 10D420 l b) 125 volt D.C. fuse box 180412

c) 125 volt D.C. dittribution panel 12D417: 3. Channel C, consisting of:

l a) 125 volt D.C. switchgear 10D430 ' 100436 b) 125 volt D.C. fuse boxes 1CD412 1CD448 c) 125 volt D.C. distribution panel ICD 417

4. Channel D, consisting of:

a) 125 volt D.C. switchgear 10D440 10D446 b) 125 volt D.C. fuse box 100412 ! 1D0448 l c) 125 volt D.C. distribution panel 10D417 l l 9 HOPE CREEK 3/4 8-22

rN ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. ACTION:

a. With less than two channels of the above required A.C. distribution system energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

b. With less than two channels of the above required D.C. distribution system energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

c. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.3.2 At least the above required power distribution system channels shall be determined energized at least once per 7 days by verifying correct breaker / switch alignment and voltage on the busses /MCCs/ panels.

 'd "When handling irradiated fuel in the secondary containment.

HOPE CREEK 3/4 8-23

                                                                          .--      +

ELECTRICAL POWER SYSTEMS PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.1 All primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more of the primary containment penetration conductor over-current protective devices shown in Table 3.8.4.1-1 inoperable, declare the affected system or component inoperable and apply the appropriate ACTION statement for the affected system, and

1. For 4.16 kV circuit breakers, de-energize the 4.16 kV circuit (s) by tripping the associated redunoant circuit breaker (s) within 72 hours and verify the redundant circuit breaker to be tripped at least once per 7 days thereafter.

2. For 480 volt circuit breakers, remove the inoperable circuit breaker (s) from service by disconnecting

the breaker within 72 hours and verify the inoperable breaker (s) to be disconnected at least once per 7 days thereafter.

      - Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. The provisions of Specification 3.0.4 are not applicable to overcurrent devices in 4.16 kV circuits which have their redundant circuit breakers tripped or to 480 volt circuits which have the inoperable circuit breaker disconnected.*

SURVEILLANCE REQUIREMENTS ! 4.8.4.1 Each of the primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 shall be demonstrated OPERABLE:

a. At least once per 18 months:

1. By verifying that each of the medium voltage 4.16 kV circuit breakers are OPERABLE by performing:

a) A CHANNEL CALIBRATION of the associated protective relays, and b) An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and overcurrent control circuits function as designed. i

  *After being disconnected, these breakers shall be maintained disconnected under administrative control.

HOPE CREEK 3/4 8-24

ELECTRICAL POWER SYSTEMS (O V t SURVEILLANCE REQUIREMENTS (Continued)

2. By selecting and functionally testing a representative sample of at least 10% of each type of lower voltage circuit breakers.

Circuit breakers selected for functional testing shall be selected on a rotating basis. Testing of these circuit breakers shall consist of injecting a current with a value between 150% and ) 300% of the pickup of the long time delay trip element and verifying that the circuit breaker operates within the time delay bandwidth for that current specified by the manufacturer. The instantaneous element shall be tested by injecting a current in excess of 120% the pickup value of the element and verifying that the circuit breaker trips instantaneously with no inten-tional time delay. Molded case circuit breaker testing shall also follow this procedure except that generally no more than two trip elements, time delay and instantaneous, will be involved. Circuit breakers found inoperable during functional testing shall be restored to OPERABLE status prior to resuming operation. For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been

 /]
 \j functionally tested.

b. At least once per 60 months by subjecting each circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

V HOPE CREEK 3/4 8-25

TABLE 3.8.4.1-1 PRIMARY CONTAINMENT PENETRATION CONDUCTOR RE3_ CURRENT PROTECTIVE DEVICES

1. 4160-VOLT CIRCUIT BREAKERS CIRCUIT SYSTEMS OR BREAKER N0. LOCATION EQUIPMENT POWERED 1AN205 1AN205 Reactor Recirculation Pump 1AP201 1BN205 IBN205 Reactor Recirculation Pump 1BP201 1CN205 1CN205 Reactor Recirculation Pump 1AP201 1DN205 1DN205 Reactor Recirculation Pump 1BP201

2. 480-VOLT MOLDED CASE CIRCUIT BREAKERS Primary and backup breakers have the same device numbers cna are located in the same Motor Control Center cubicle.

CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-411065 108411 IM HFB150 RHR Head Spray Valve TM HFB150 IBC-HV-F022 52-451061 108451 IM HFB150 RHR Shutdown Cooling Suction TM HFB150 Inboard Valve 1BC-HV-F009 52-212021 108212 IM HFB150 RWCU Suction Isolation Inboard TM HFB150 Valve 1BG-HV-F001 52-212101 108212 IM HFB150 PCIGS Drywell Supply Heeder A TM HFB150 Isolation Valve 1KL-HV-5152A 52-212181 10B212 IM HFB150 Main Steam Line Drain Inboard TM HFB150 Valve 1AB-HV-F016 52-212183 108212 IM HFB150 PCIGS Drywell Suction TM HFB150 Inboard Valve 1KL-HV-5148 52-232061 108232 IM HFB150 Drywell Supply Header A TM HFB150 Isolation Valve 1KL-HV-5124A 52-232103 108232 IM HFB150 Drywell Equip. Orain Sump TM HFB150 Isolation Valve IHB-HV-F019 52-232104 108232 IM HFB150 HPCI Warmup Bypass Line Til HFB150 Isolation Valve 1FD-HV-F100 52-232181 108232 IM'HFB150 Chilled Water Loop A Supply TM HFB150 Isolation Valve 1GB-HV-9531B1 52-232182 108232 IM HFB150 Chilled Water Loop A Return TM HFB150 Isolation Valve 1GB-HV-953182 52-232183 108232 IM HFB150 Chilled Water Loop B Supply TM HFB150 Isolation Valve 1GB-HV-953183 HOPE CREEK 3/4 8-26

TABLE 3.8.4.1-1 (Continued) PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

2. 480-V0LT M0LDED CASE CIRCUIT BREAKERS (Continued)

CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-232193 108232 IM HFB150 Chilled Water Loop B Return TM HFB150 Isolation Valve IGB-HV-953184 52-232203 108232 IM HFB150 HPCI Turbine Steam Supply TM HFB150 Isolation Valve 1FD-HV-F002 52-242021 108242 IM HFB150 Drywell Floor Drain Sump TM HFB150 Isolation Valve 1HB-HV-F003 52-242061 108242 IM HFB150 Drywell Supply Header B TM HFB150 Isolation Valve 1KL-HV-51248 52-242101 10B242 IM HFB150 PCIGS Drywell Supply Header B TM HFB150 Isolation Valve 1KL-HV-51528 52-242102 10B242 IM HFB150 RCIC Turbine Steam Supply TM HFB150 Isolation Valve 1FC-HV-F007 52-242103 10B242 IM HFB150 RCIC Warmup Bypass Line TM HFB150 Isolation Valve 1FC-HV-F076 52-242172 108242 IM HFB150 Reactor Recirc Pumps Cooling TM HFB150 Supply Isolation 1ED-HV-2554 52-242173 10B242 IM HFB150 Reactor Recirc Pumps Cooling TM HFB150 Return Isolation 1ED-HV-2556 52-252021 10B252 IM HFB150 Drywell Cooler A Fan 1A1V212 TM HFB150 52-252022 10B252 IM HFB150 Drywell Cooler B Fan 181V212 TM HFB150 52-252031 10B252 IM HFB150 Drywell Cooler C Fan ICIV212 TM HFB150 52-252032 108252 IM HFB150 Drywell Cooler D Fan 101V212 l TM HFB150 52-252041 108252 IM HFB150 Drywell Cooler E Fan 1E1V212 , TM HFB150 52-252042 108252 IM HFB150 Drywell Cooler F Fan 1F1V212 TM HFB150 52-252051 108252 IM HFB150 Drywell Cooler G Fan 1GIV212 TM HFB150 52-252052 108252 IM HFB150 Drywell Cooler H Fan 1H1V212 TM HFB150 HOPE CREEK 3/4 8-27

TABLE 3.8.4.1-1 (Continued) PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

2. 480-VOLT MOLDED CASE CIRCUIT BREAKERS (Continued)

CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-252063 108252 IM HFB150 Dr,ywell Equip Drain Sump Pump TM HFB150 1AP267 52-252064 108252 IM HFB150 Drywell Floor Drain Sump Pump TM HFB150 1CP267 52-252073 108252 IM HFB150 Feedwater Inlet A Shutoff TM HFB150 1AE-HV-F011A 52-262021 108262 IM HFB150 Drywell Cooler A Fan 1A2V212 TM HFB150 52-262022 108262 IM HFB150 Drywell Cooler B Fan 182V212 TM HFB150 52-262031 10B262 IM HFB150 Drywell Cooler C Fan 1C2V212 TM HFB150 52-262032 108262 IM HFB150 Drywell Cooler D Fan 1D2V212 TM HFB150 52-262041 108262 IM HFB150 Drywell Cooler E Fan 1E2V212 TM HFB150 52-262042 108262 IM HFB150 Drywell Cooler F Fan 1F2V212 TM HFB150 52-262051 108262 IM HFB150 Drywell Cooler G Fan 1G2V212 TM HFB150 52-262052 108262 IM HFB150 Drywell Cooler H Fan 1H2V212 TM HFB150 52-262063 108262 IM HFB150 Diywell Equip Drain Sump Pump TM HFB150 1BP267 52-262064 10B262 IM HFB150 Drywell Floor Drain Sump Pump TM HFB150 1DP267 52-253012* 10B253 IM HFB150 Recirc Pump Motor Hoist 1AH201 TM HFB150 Disconnect Switch 1AS204 52-253021 10B253 IM HFB150 Recirc Pump 1BP201 Suction TM HFB150 Valve 1BB-HV-F023B 52-253031 108253 IM HFB150 Recirc Pump 1BP201 Discharge TM HFB150 Valve 1BB-HV-F031B 52-253053 10B253 IM HFB150 Reactor Vessel Head Vent TM HFB150 Inboard Isolation 1BB-HV-F001 HOPE CREEK 3/4 8-28

l l TABLE 3.8.4.1-1 (Continued) , Q). ( _,- PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

2. 480-V0LT MOLDED CASE CIRCUIT BREAKERS (Continued)

CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-253064 10B253 IM HFB150 Reactor Vessel Head Vent to TM HFB150 Steam Line 1BB-HV-F005 52-263011 10B263 IM HFB150 Reactor Vessel Head Vent TM HFB150 Outboard Isolation 1BB-HV-F002 52-263012* 10B263 IM HFB150 Recirc Pump Motor Hoist 1BH201 TM HFB150 Disconnect Switch 18S204 52-263022* 10B263 TM HFB150 CRD Equipment Handling Platform 10S270 52-263042* 10B263 IM HFB150 Main Steam Relief Valve Hoist TM HFB150 10H202 Disconnect Switch 10S207 52-263054 10B263 IM HFB150 RWCU Suction from Recirc TM HFB150 Loop A 1BG-HV-F100 52-263081 108263 IM HFB150 RWCU Suction from RPV Drain TM HFB150 Valve 1BG-HV-F101 O- 52-263082 108263 IM HFB150 RWCU Suction Valve 1BG-HV-F102 TM HFB150 52-263033 10B263 IM HFB150 RWCU Suction from Recirc Loop TM HFB150 B Valve 1BG-HV-F106 52-264053 108264 IM HFB150 Recirc Pump A Discharge Valve TM HFB150 1BB-HV-F031A 52-264062 10B264 IM HFB150 Feedwater Inlet B Shutoff TM HFB150 Valve IAE-HV-F011B 52-264071 108264 IM HFB150 Reactor Recirc Pump 1AP201 TM HFB150 Space Heater 1AS220 52-264072 10B264 IM HFB150 Reactor Recirc Pump 1BP201 TM HFB150 Space Heater 1BS220 52-264083 10B264 IM HFB150 Recirc Pump A Suction Valve TM HFB150 1BB-HV-F023A

          *These breakers shall be administrative 1y maintained open in OPERATIONAL CONDITIONS 1, 2 and 3 and are not required to be tested.

HOPE CREEK 3/4 8-29

I l ELECTRICAL POWER SYSTEP; MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED) l l LIMITING CONDITION FOR OPERATION 3.8.4.2 The thermal overload protection bypass circuit of each motor operated valve (MOV) shown in Table 3.8.4.2-1 shall be OPERABLE. l APPLICABILITY: Whenever the MOV is required to be OPERABLE. l ACTION: I With the thermal overload protection bypass circuit for one or more of the above required MOVs inoperable, restore the inoperable thermal overload pro-l tection bypass circuit (s) to OPERABLE status within 8 hours or declare the affected MOV(s) inoperable and apply the appropriate ACTION statement (J) for the affected system (s). l SURVEILLANCE REQUIREMENTS l l 4.8.4.2.1 The thermal overload protection bypass circuit for each of the above required MOVs shall be demonstrated OPERABLE:

a. At least once per 18 months by the performance of a CHANNEL FUNCTIONAL TEST f 3r:

1. Those thermal overload protection devices which are normally in force during plant operation and bypassed only under accident conditions.

2. A representative sample of at least 25% of those thermal overload protection devices which are bypassed continuously and temporarily l placed in force only when the MOVs are undergoing periodic or maintenance testing, such that the bypass circuitry for each thermal overload protection device of this type is tested at least once per 6 years.

3. A representative sample of at least 25% of those thermal over-load protection devices which are in force during normal manual (momentary push button contact) MOV operation and bypassed dur-ing remote manual (push button held depressed) MOV operation, such that the bypass circuitry for each thermal overload pro-tection device of this type is tested at least once per 6 years.

b. Following maintenance on the motor starter.

4.8.4.2.2 The thermal overload protection for the above required MOVs which are continuously bypassed and temporarily placed in force only when the MOV is under-going periodic or maintenance testing shall be verified to be continuously l bypassed following such testing. HOPE CREEK 3/4 8-30

TABLE 3.8.4.2-1 MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED) THERMAL OVERLOAD VALVE NUMBER PROTECTION STATUS SYSTEM (S) AFFECTED 1AB-HV-F016 2 Main Steam 1AB-HV-F019 2 Main Steam 1AB-HV-F067A 2 Main Steam 1AB-HV-F0678 2 Main Steam 1AB-HV-F067C 2 Main Steam 1AB-HV-F0670 2 Main Steam 1AB-HV-F071 3 Main Steam 1AB-HV-3631A 3 Main Steam 1AB-HV-3631B 3 Main Steam , 1AB-HV-3631C 3 Main Steam 1AB-HV-3631D 3 Main Steam 1AE-HV-F032A 3 Feedwater 1AE-HV-F0328 3 Feedwater 1AE-HV-F039 3 Feedwater 1AE-HV-4144 3 Feedwater 1AN-HV-2600 3 Demineralized Water 0AP-HV-2072 3 Condensate Storage & Transfer I 0AP-HV-2073 3 Condensate Storage & Transfer 1AP-HV-F011 1 Condensate Storage & Transfer 1BC-HV-F004A 3 Residual Heat Removal (RHR) IBC-HV-F004B 3 RHR 1BC-HV-F004C 3 RHR 1BC-HV-F004D 3 RHR IBC-HV-F006A 3 RHR 1BC-HV-F006B 3 RHR 18C-HV-F007A 1 RHR 1BC-HV-F007B 1 RHR 1BC-HV-F007C 1 RHR 1BC-HV-F0070 1 RHR 1BC-HV-F008 2 RHR 1BC-HV-F009 2 RHR 1BC-HV-F010A 2 RHR 1BC-HV-F010B 2 RHR 1BC-HV-F015A 2 RHR IBC-HV-F015B 2 RHR IBC-HV-F016A 3 RHR 1BC-HV-F0168 3 RHR 1BC-HV-5017A 1 RHR 1BC-HV-50178 1 RHR 1BC-HV-F017C 1 RHR 1BC-HV-F017D 1 RHR IBC-HV-F021A 3 RHR O 1BC-HV-F021B 3 RHR IBC-HV-F022 2 RHR IBC-HV-F023 2 RHR HOPE CREEK 3/4 8-31 l

TABLE 3.8.4.2-1 (Continued) MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED) lh THERMAL OVERLOAD VALVE NUMBER PROTECTION STATUS SYSTEM (S) AFFECTED 1BC-HV-F024A 2 RHR IBC-HV-F024B 2 RHR 1BC-HV-F027A 2 RHR 1BC-HV-F027B 2 RHR 1BC-HV-F040 2 RHR IBC-HV-F047A 3 RHR 18C-HV-F0478 3 RHR 1BC-HV-F048A 1 RHR IBC-HV-F0488 1 RHR ' 1BC-HV-F049 2 RHR 1BC-HV-F075 3 RHR 1BC-HV-4439 3 RHR 1BC-HV-5055A 2 Containment Atmosphere Control 1BC-HV-5055B 2 Containment Atmosphere Contrsl IBD-HV-F010 2 Reactor Core Isolation Cooling (RCIC) 1BD-HV-F012 1 RCIC IBD-HV-F013 1 RCIC 1BD-HV-F022 2 RCIC 1BD-HV-F031 1 RCIC 1BD-HV-F046 1 RCIC IBE-HV-F001A 3 Core Spray 3BE-HV-F001B 3 Core Spray 1BE-HV-F001C 3 Core Spray 1BE-HV-F001D 3 Core Spray IBE-HV-F004A 1 Core Spray 1BE-HV-F0048 1 Core Spray 1BE-HV-F005A 1 Core Spray 1BE-HV-F005B 1 Core Spray IBE-HV-F015A 2 Core Spray 1BE-HV-F015B 2 Core Spray 18E-HV-F031A 1 Core Spray 1BE-HV-F031B 1 Core Spray IBF-HV-3800A 3 Control Rod Drive IBF-HV-38008 3 Control Rod Drive IBF-HV-4005 3 Control Rod Drive 1BG-HV-F0D1 2 Reactor Water Cleanup 1BG-HV-F004 2 Reactor Water Cleanup 1BG-HV-F034 3 Reactor Water Cleanup 1BG-HV-F035 3 Reactor Water Cleanup 1BG-HV-3980 3 Reactor Water Cleanup 1BH-HV-F006A 3 Standby Liquid Control 1BH-HV-F006B 3 Standby Liquid Control HOPE CREEK 3/4 8-32

[) TABLE 3.8.4.2-1 (Continued) U MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED) , i THERMAL OVERLOAD VALVE NUMBER PROTECTION STATUS SYSTEM (S) AFFECTED 1BJ-HV-F004 1 High Pressure Coolant Injection , (HPCI) IBJ-HV-F006 1 HPCI 1BJ-HV-F007 1 HPCI 1BJ-HV-F008 2 HPCI

                       -1BJ-HV-F012.                       1               HPCI 1BJ-HV-F042                       1               HPCI 1BJ-HV-F059                       1               HPCI 1BJ-HV-4803                       3               HPCI 1BJ-HV-4804                       3               HPCI 1BJ-HV-4865                       3               HPCI 1BJ-HV-4866                       3               HPCI 1BJ-HV-8278                       1               HPCI OBN-HV-2069                       3               Refueling Water Transfer 1EA-HV-F073                       3               Station Service Water 1EA-HV-2197A                      3               Station Service Water 1EA-HV-21978                      3               Station Service Water 1EA-HV-2197C                      3               Station Service Water
   \s_                   1EA-HV-21970                      3               Station Service Water 4

1EA-HV-2198A 2 Station Service Water IEA-HV-21988 2 Station Service Water , IEA-HV-2198C 2 Station Service Water 1EA-HV-21980 2 Station Service Water 1EA-HV-2203 3 Station Service Water 1EA-HV-2204 3 Station Service Water 1EA-HV-2207 3 Station Service Water 1EA-HV-2234 3 Station Service Water 1EA-HV-2236 3 Station Service Water , IEA-HV-2238 3 Station Service Water 1EA-HV-2346 3 Station Service Water 1EA-HV-2355A 2 Station Service Water

1EA-HV-2355B 2 Station Service Water
1EA-HV-2356A 3 Station Service Water 1EA-HV-2356B 3 Station Service Water i 1EA-HV-2357A 3 Station Service Water-1EA-HV-23578 3 Station Service Water 1EA-HV-2371A 2 Station Service Water IEA-HV-23718 2 Station Service Water IEC-HV-4647 3 Fuel Pool Cooling l 1EC-HV-4648 3 Fuel Pool Cooling 1EC-HV-4689A 3 Fuel Pool Cooling IEC-HV-46898 3 Fuel Pool Cooling 1ED-HV-2553 2 Reactor Auxiliaries Cooling IED-HV-2554 2 Reactor Auxiliaries Cooling HOPE CREEK 3/4 8-33

TABLE 3.8.4.2-1 (Continued) MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED) THERMAL OVERLOAD VALVE NUMBER PROTECTION STATUS SYSTEM (S) AFFECTED 1ED-HV-2555 2 Reactor Auxiliaries Cooling 1ED-HV-2556 2 Reactor Auxiliaries Cooling 1ED-HV-2598 3 Reactor Auxiliaries Cooling IED-HV-2599 3 Reactor Auxiliaries Cooling 1EE-HV-4652 2 Torus Water Cleanup IEE-HV-4679 2 Torus Water Cleanup 1EE-HV-4680 2 Torus Water Cleanup 1EE-HV-4681 2 Torus Water Cleanup IEG-HV-2314A 3 Safety Auxiliaries Cooling 1EG-HV-23148 3 Safety Auxiliaries Cooling IEG-HV-2317A 3 Safety Auxiliaries Cooling 1EG-HV-23178 3 Safety Auxiliaries Cooling 1EG-HV-2320A 3 Safety Auxiliaries Cooling 1EG-HV-2320B 3 Safety Auxiliaries Cooling 1EG-HV-2321A 2 Safety Auxiliaries Cooling 1EG-HV-2321B 2 Safety Auxiliaries Cooling 1EG-HV-2446 3 Safety Auxiliaries Cooling IEG-HV-2447 3 Safety Auxiliaries Cooling 1EG-HV-2452A 3 Safety Auxiliaries Cooling 1EG-HV-24528 3 Safety Auxiliaries Cooling 1EG-HV-2453A 2 Safety Auxiliaries Cooling 1EG-HV-2453B 2 Safety Auxiliaries Cooling IEG-HV-2491A 3 Safety Auxiliaries Cooling IEG-HV-2491B 3 Safety Auxiliaries Cooling 1EG-HV-2494A 3 Safety Auxiliaries Cooling 1EG-HV-2494B 3 Safety Auxiliaries Cooling 1EG-HV-2496A 3 Safety Auxiliaries Cooling 1EG-HV-24968 3 Safety Auxiliaries Cooling 1EG-HV-2496C 3 Safety Auxiliaries Cooling 1EG-HV-24960 3 Safety Auxiliaries Cooling 1EG-HV-2512A 3 Safety Auxiliaries Cooling 1EG-HV-25128 3 Safety Auxiliaries Cooling i 1EG-HV-7921A 3 Safety Auxiliaries Cooling 1EG-HV-7921B 3 Safety Auxiliaries Cooling IEG-HV-7922A 3 Safety Auxiliaries Cooling 1EG-HV-7922B 3 Safety Auxiliaries Cooling 1EP-HV-2225A 3 Station Service Water 1EP-HV-22258 3 Station Service Water IEP-HV-2225C 3 Station Service Water 1EP-HV-2225D 3 Station Service-Water IFC-HV-F007 2 Reactor Core Isolation Cooling l (RCIC) IFC-HV-F008 2 RCIC l l HOPE CREEK 3/4 8-34 1 l 1 - - . __.

1 TABLE 3.8.4.2-1 (Continued) s-MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTIO * (BYPASSED) , THERMAL OVERLOAD VALVE NUMBER PROTECTION STATUS SYSTEM (S) AFFECTED I 1FC-HV-F045 2 RCIC IFC-HV-F059 3 RCIC ] 1FC-HV-F060 3 RCIC IFC-HV-F062 2 RCIC

1FC-HV-F076 2 RCIC 1FC-HV-F084 2 RCIC IFC-HV-4282 3 RCIC 1FD-HV-F001 1 High Pressure Coolant Injection (HPCI)

IFD-HV-F002 2 HPCI 1FD-HV-F003 2 HPCI j 1FD-HV-F071 3 HPCI 1FD-HV-F075 2 HPCI 1FD-HV-F079 2 HPCI l 1FD-HV-F100 2 HPCI IFD-HV-4922 2 HPCI 1GB-HV-9531A1 2 Chilled Water 1GB-HV-9531A2 2 Chilled Water 1GB-HV-9531A3 2 Chilled Water 1GB-HV-9531A4 2 Chilled Water 1GB-HV-953181 2 Chilled Water IG8-HV-9531B2 2 Chilled Water 1GB-HV-9531B3 2 Chilled Water l 1GB-HV-953184 2 Chilled Water 1GB-HV-9532-1 3 Chilled Water 1GB-HV-9532-2 3 Chilled Water , 1GH-HV-5543 3 Radwaste Area Vent ,

1GS-HV-4955A 2 Containment Atmosphere Control 1GS-HV-4955B 2 Containment Atmosphere Control 1GS-HV-4959A 2 Containment Atmosphere Control IGS-HV-4959B 2 Containment Atmosphere Control 1GS-HV-4965A 2 Containment Atmosphere Control 1GS-HV-49658 2 Containment Atmosphere Control 1GS-HV-4966A 2 Containment Atmosphere Control 1GS-HV-4966B 2 Containment Atmosphere Control 1GS-HV-4974 2 Containment Atmosphere Control il 1GS-HV-4963A 2 Containment Atmosphere Control 1GS-HV-4983B 2 Containment Atmosphere Control 1GS-HV-4984A 2 Containment Atmosphere Control 1GS-HV-49848 2 Containment Atmosphere Control 1GS-HV-5019A 2 Containment Atmosphere Control

  ,h                         1GS-HV-5019B                                    2                Containment Atmosphere Control l  \s_,/                      1GS-HV-5022A                                    2                Containment Atmosphere Control 1GS-HV-50228                                    2                Containment Atmosphere Control I

HOPE CREEK 3/4 8-35 i

TABLE 3.8.4.2-1 (Continued) MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED) THERMAL OVERLOAD VALVE NUMBER PROTECTION STATUS SYSTEM (S) AFFECTED 1GS-HV-5050A 2 Containment Atmosphere Control 1GS-HV-5050B 2 Containment Atmosphere Control 1GS-HV-5052A 2 Containment AtdIosphere Control 1GS-HV-5052B 2 Containment Atmosphere Control 1GS-HV-5053A 2 Containment Atmosphere Control 1GS-HV-5053B 2 Containment Atmosphere Control 1GS-HV-5054A 2 Containment Atmosphere Control 1GS-HV-5054B 2 Containment Atmosphere Control 1GS-HV-5057A 2 Containment Atmosphere Control 1GS-HV-5057B 2 Containment Atmosphere Control 1HB-HV-F003 2 Liquid Radwaste 1HB-HV-F004 2 Liquid Radwaste 1HB-HV-F019 2 Liquid Radwaste 1HB-HV-F020 2 Liquid Radwaste 1HB-HV-5262 3 Liquid Radwaste 1HB-HV-5275 3 Liquid Radwaste 1HC-HV-5551 3 Solid Radwaste 1KA-HV-7626 3 Service Compressed Air 1KB-HV-7629 3 Instrument Air (Backup to PCIG System) 1KL-HV-5124A 2 Primary Containment Instrument Gas (PCIG) 1KL-HV-5124B 2 PCIG 1KL-HV-5126A 2 PCIG 1KL-HV-5126B 2 PCIG 1KL-HV-5147 2 PCIG 1KL-HV-5148 2 PCIG IKL-HV-5152A 2 PCIG 1KL-HV-5152B 2 PCIG 1KL-HV-5160A 3 PCIG 1KL-HV-5160B 3 PCIG 1KL-HV-5162 2 PCIG 1KL-HV-5172A 2 PCIG l 1KL-HV-5172B 2 PCIG 1KP-HV-5829A 3 Main Steam Isolation Valve Sealing IKP-HV-58298 3 Main Steam Isolation Valve Sealing 1XP-HV-5834A 2 Main Steam Isolation Valve Sealing 1KP-HV-58348 3 Main Steam Isolation Valve Sealing 1KP-HV-5835A 2 Main Steam Isolation Valve Sealin ( 3 Main Steam Isolation Valve Sealin l IKP-HV-5835B 1KP-HV-5836A 2 Main Steam Isolation Valve Sealin 3 Main Steam Isolation Valve Sealing 1KP-HV-5836B HOPE CREEK 3/4 8-36

TABLE 3.8.4.2-1_(Continued) em ( ') MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (BYPASSED)

  \J THERMAL OVERLOAD VALVE NUMBER                           PROTECTION STATUS                SYSTEM (S) AFFECTED 1KP-HV-5837A                                  2                     Main Steam Isolation Valve Sealing 1KP-HV-5837B                                  3                     Main Steam Isolation Valve Sealing ISK-HV-4953                                   2                     Plant Leak Detection ISK-HV-4957                                   2                     Plant Leak Detection 1SK-HV-4981                                   2                     Plant Leak Detection ISK-HV-5018                                   2                     Plant Leak Detection THERMAL OVERLOAD PROTECTION STATUS CODES

1. Normally in force during plant operation and bypassed only under accident conditions.

2. Bypassed continuously and temporarily placed in force only when the MOVs are undergoing periodic or maintenance testing.

3. In force during normal remote manual (momentary push button contact) MOV operation and bypassed during remote manual (push button held depressed)

MOV operation. l , \ HOPE CREEK 3/4 8-37

ELECTRICAL POWER SYSTEMS MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (NOT BYPASSED) LIMITING CONDITION FOR OPERATION 3.8.4.3 The thermal overload protection of each motor operated valve (MOV) shown in Table 3.8.4.3-1 shall be OPERABLE. APPLICABILITY: Whenever the M0V is required to be OPERABLE. ACTION: With the thermal overload protection for one or more of the above required MOVs inoperable, restore the inoperable thermal overload (s) to OPERABLE status within 8 hours or declare the affected MOV(s) inoperable and apply the appro-priate ACTION statement (s) for the affected system (s). SURVEILLANCE REQUIREMENTS 4.8.4.3 The thermal overload protection for each of the above required MOVs shall be demonstrated OPERABLE at least once per 18 months and following main-tenance on the motor starter by the performance of a CHANNEL CALIBRATION. O O, HOPE CREEK 3/4 8-38

TABLE 3.8.4.3-1 MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (NOT BYPASSED) VALVE NUMBER SYSTEM (S) AFFECTED 4

.       IBC-HV-F003A                                  Residual Heat Removal IBC-HV-F003B                                  Residual Heat Removal                              ,

j IGS-HV-5741A Containment Atmosphere Control IGS-HV-5741B Containment Atmosphere Control l i

!       IKC-HV-3408M                                  Fire Protection i

i l 1 i i .f, , i 4 i I I l i 1 l t l l HOPE CREEK 3/4 8-39

ELECTRICAL POWER SYSTEMS REACTOR PROTECTION SYSTEM ELECTRICAL POWER MONITORING LIMITING CONDITION FOR OPERATION 3.8.4.4 Two RPS electric power monitoring channels for each inservice RPS MG set or alternate power supply shall be OPERABLE. APPLICABILITY: At all times. ACTION:

a. With one RPS electric power monitoring channel for an inservice RPS MG set or alternate power supply inoperable, restore the inoperable power monitoring channel to OPERABLE status within 72 hours or remove the associated RPS MG set or alternate power supply from service.

b. With both RPS electric power monitoring channels for an inservice RPS MG set or alternate power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service.

SURVEILLANCE REQUIREMENTS 4.8.4.4 The above specified RPS electric power monitoring channels shall be determined OPERABLE:

a. At least once per 6 months by performance of a CHANNEL FUNCTIONAL TEST, and

b. At least once per 18 months by demonstrating the OPEtiABILITY of over-voltage, under-voltage, and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints.

1. Over-voltage 5 132 VAC, (Bus A), 132 VAC (Bus B)

2. Under-voltage 1 108 VAC, (Bus A), 108 VAC (Bus B)

3. Under-frequency 1 57 Hz. (Bus A and Bus B)

O HOPE CREEK 3/4 8-40

fq ELECTRICAL POWER SYSTEMS CLASS 1E ISOLATION BREAKER OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.5 All Class 1E isolation breaker (tripped by a LOCA signal) overcurrent protective devices shown in Table 3.8.4.5-1 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more of the overcurrent protective devices shown in Table 3.8.4.5-1 inoperable, declare the affected isolation breaker inoper-able and remove the inoperable circuit breaker (s) from service within 72 hours and verify the inoperable breaker (s) to be disconnected at least once per 7 days thereafter,

b. The provisions of Specification 3.0.4 are not applicable to over-

, current devices in 480 volt circuits which have the inoperable cir-cuit breaker disconnected. i SURVEILLANCE REQUIREMENTS i 4.8.4.5 Each of the Class IE isolation breaker overcurrent protective devices i shown in Table 3.8.4.5-1 shall be demonstrated OPERABLE: 1 l a. At least once per 18 months: 1 \ By selecting and functionally testing a representative sample of at . least 10% of each type of lower voltage circuit breakers. Circuit breakers selected for functional testing shall be selected on a rotating basis. Testing of these circuit breakers shall consist of injecting a current with a value between 150% and 300% of the pickup of the long time delay trip element and a value between 150% and 250% of the pickup of the short time delay, and verifying that the l circuit breaker operates within the time delay band width for that current specified by the manufacturer. The instantaneous element shall be tested by injecting a current in excess of 120% of the pick-up value of the element and verifying that the circuit breaker trips instantaneously with no intentional time delay. Molded case circuit breaker testing shall also follow this procedure except that gener-ally no more than two trip elements, time delay and instantaneous, will be involved. For circuit breakers equipped with solid state trip devices, the func-tional testing may be performed with use of portable instruments de signed to verify the time-current character-istics and pickup calibra-tion of the trip elements. Circuit breakers found inoperable during functional testing shall be restored to OPERABLE status prior to resuming operation. For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

b. At least once per 60 months by subjecting each circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

HOPE CREEK 3/4 8-41

TABLE 3.8.4.5-1 CLASS 1E ISOLATION BREAKER OVERCURRENT PROTECTIVE DEVICES (BREAKER TRIPPED BY A LOCA SIGNAL) 480 VAC POWER CIRCUIT BREAKERS

1. TYPE AKR-5A-30 Class 1E Circuit Class IE Breaker No. Bus Non-Class 1E Load Description 52-41011 108410 Reactor Auxiliaries Cooling System Pump 1AP209 52-41014 108410 Radwaste and Service Area MCC 10B313 52-41024 10B410 Reactor Building Supply Air Handling Unit 1BVH300 52-42011 108420 Reactor Auxiliaries Cooling System Pump 1BP209 52-42014 10B420 Radwaste and Service Area MCC 108323 l Reactor Building Exhaust Fan l

52-42024 10B420 l 1BV301 l 52-43024 108430 Reactor Building Supply Air Handling Unit ICVH300 52-43014 108430 Control Rod Drive Pump 1AP207 52-44014 108440 Control Rod Drive Pump 1BP207 52-44024 108440 Reactor Building Supply Air Handling Unit 1AVH300 52-44034 108440 Radwaste Area Supply Fan OBV316 i 52-45011 108450 Reactor Area MCC 10B252 l Radwaste Area Exhaust Fan 52-45014 108450 OAV305 52-45024 108450 Emergency Instrument Air Compressor 10K100 HOPE CREEK 3/4 8-42 l 1

1 TABLE 3.8.4.5-1 (Continued) 480 VAC POWER CIRCUIT BREAKERS

1. Type AKR-5A-30 (Continued)

Class 1E

,              Circuit           Class IE Breaker No.             Bus  Non-Class 1E Load Description 52-45034          10B450     Reactor Building Exhaust Fan ICV 301 52-46011          108460     Reactor Area MCC 108262 52-46014          108460     Radwaste Area Exhaust Fan OBV305 52-47011          108470     Reactor Area MCC 10B272 52-47014          10B470     Radwaste Area Exhaust Fan OCV305 52-47024          108470     Radwaste Area Supply Fan 0AV316 52-47031          108470     Technical Support Center MCC 008474 52-48011          108480     Reactor Area MCC 108282 O

t 52-48024 108480 Reactor Building Exhaust Fan 1AV301 480 VAC MOLDED CASE CIRCUIT BREAKERS

1. Type HFB150 Class IE Circuit Class 1E Breaker No. Bus Non-Class 1E Load Description 52-441043 108441 NSSS Computer Inverter 100485 52-451023 108451 Public Address System Inverter 100496 52-471023 108471 Security System Inverter 0AD495 i

O HOPE CREEK 3/4 8-43 l l __- _ _ . _ _ .. . - . _ - ___ --__ -

ELECTRICAL POWER SYSTEM POWER RANGE NEUTRON MONITORING SYSTEM ELECTRICAL POWER MONITORING LIMITING CONDITION FOR OPERATION 3.8.4.6 The power :ange neutron monitoring system (NMS) electric power monitoring channels for each inservice power range NHS power supply shall be OPERABLE. APPLICABILITY: At all times. ACTION:

a. With one power range NMS electric power monitoring channel for an inservice power range NMS power supply inoperable, restore the in-operable power monitoring channel to OPERABLE status within 72 hours or deenergize the associated power range HMS power supply feeder circuit.

b. With both power range NHS electric power monitoring channels for an inservice power range NHS power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or deenergize the associated power range NMS power supply feeder circuit.

SURVEILLANCE REQUIREMENTS l 4.8.4.6 The above specified power range NMS electric power monitoring channels shall be determined OPERABLE:

a. At least once per 6 months by performance of a CHANNEL FUNCTIONAL TEST, and

b. At least once per 18 months by demonstrating the OPERABILITY of over-voltage, under-voltage, and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including l

simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints.

1. Over-voltage 5, 132 VAC (BUS A), 132 VAC (BUS B) l

2. Under-voltage > 108 VAC (BUS A),108 VAC (BUS B)

3. Under-frequency > 57 Hz. -0, +2%

1 O HOPE CREEK 3/4 8-44

O 3/4.9 REFUELING OPERATIONS U 3/4.9.1 REACTOR MODE SWITCH LIMITING CONDITION FOR OPERATION 3.9.1 The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel position. When the reactor mode switch is locked in the Refuel position:

a. A control rod shall not be withdrawn unless the Refuel position one-rod-out interlock is OPERABLE.

b. CORE ALTERATIONS shall not be performed using equipment associated with a Refuel position interlock unless at least the following associ-ated Refuel position interlocks are OPERABLE for such equipment.

1. All rods in.

2. Refuel platform position.

3. Refuel platform hoists fuel-loaded.

4. Service platform hoist fuel-loaded.

APPLICABILITY: OPERATIONAL CONDITION 5* # . ACTION: , ./ a. With the reactor mode switch not locked in the Shutdown or Refuel position as specified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Shutdown or Refuel position.

b. With the one-rod-out interlock inoperable, lock the reactor mode switch in the Shutdown position.

c. With any of the above required Refuel position equipment interlocks inoperable, suspend CORE ALTERATIONS with equipment associated with the inoperable Refuel position equipment interlock.

See Special Test Exceptions 3.10.1 and 3.10.3.

        # The reactor shall be maintained in OPERATIONAL CONDITION 5 whenever fuel is in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

o HOPE CREEK 3/4 9-1 l

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS 4.9.1.1 The reactor mode switch shall be verified to be locked in the Shutdown or Refuel position as specified:

a. Within 2 hours prior to:

1. Beginning CORE ALTERATIONS, and

2. Resuming CORE ALTERATIONS when the reactor mode switch has been unlocked.

b. At least once per 12 hours.

4. s. l. 2 Each of the above required reactor mode switch Refuel position interlocks

shall be demonstrated 0PERABLE by performance of a CHANNEL FUNCTIONAL TEST within 24 hours prior to the start of and at least once per 7 days during control rod withdrawal or CORE ALTERATIONS, as applicable.

4.9.1.3 Each of the above required reactor mode switch Refuel position interlocks

that is affected shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST prior to resuming control rod withdrawal or CORE ALTERATIONS, as applicable, following repair, maintenance or replacement of any component that could affect the Refuel position interlock.

The reactor mode switch may be placed in the Run or Startup/ Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff. O HOPE CREEK 3/4 9-2

r3 REFUELING OPERATIONS 3/4.9.2 INSTRUMENTATION , LIMITING CONDITION FOR OPERATION 3.9.2 At least 2 source range monitor * (SRM) channels shall be OPERABLE and inserted to the normal operating level with:##

a. Annunciation and continuous visual indication in the control room,

b. One of the required SRM detectors located in the quadrant where CORE ALTERATIONS are being performed and the other required SRM detector located in an adjacent quadrant, and

c. Unless adequate shutdown margin has been demonstrated per Specifica-tion 3.1.1,the"shortinglinks"removedfromtheRP)circuitryprior to and during the time any control rod is withdrawn APPLICABILITY: OPERATIONAL CONDITION 5.**

ACTION: With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE ALTERATIONS and insert all insertable O control rods. O SURVEILLANCE REQUIREMENTS i 4.9.2 Each of the above required SRM channels shall be demonstrated OPERABLE by:

a. At least once per 12 hours:

1. Performance of a CHANNEL CHECK,

2. Verifying the detectors are inserted to the normal operating level, and

3. During CORE ALTERATIONS, verifying that the detector of an OPERABLE SRM channel is located in the core quadrant where CORE

! ALTERATIONS are being performed and another is located in an adjacent quadrant.

      "The use of special movable detectors during CORE ALTERATIONS in place of the normal SRM nuclear detectors is permissible as long as these special detectors g are connected to the normal SRM circuits.

Not required for control rods removed per Specification 3.9.10.1 and 3.9.10.2. jjSeeSpecialTestException3.10.7. Three SRM channels shall be OPERABLE for critical shutdown margin demonstra-x tions. An SRM detector may be retracted provided a channel indication of at least 100 i:ps is maintained. HOPE CREEK 3/4 9-3

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS (Continued)

b. Performance of a CHANNEL FUNCTIONAL TEST:

1. Within 24 hours prior to the start of CORE ALTERATIONS, and

2. At least once per 7 days.

c. Verifying that the channel count rate is at least 0.7 cps:*

1. Prior to control rod withdrawal,

2. Prior to and at least once per 12 hours during CORE ALTERATIONS, and

3. At least once per 24 hours.

d. Unless adequate shutdown margin has been demonstrated per Specification 3.1.1, verifying that the RPS circuitry " shorting links" have been removed, within 8 hours prior to and at least once per 12 hours during the time any control rod is withdrawn.**

 *Provided signal-to-noise is > 2. Otherwise, 3 cps.

- Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.

O HOPE CREEK 3/4 9-4 )

REFUELING OPERATIONS (O i 3/4.9.3 CONTROL R0D POSITION LIMITING CONDITION FOR OPERATION l 3.9.3 All control rods shall be inserted.* APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS.** ACTION: With all control rods not inserted, suspend all other CORE ALTERATIONS, except that one control rod may be withdrawn under control of the reactor mode switch Refuel position one rod-out interlock. - SURVEILLANCE REQUIREMENTS 4.9.3 All control rods shall be verified to be inserted, except as above ( specified:

a. Within 2 hours prior to:

1. The start of CORE ALTERATIONS.

2. The withdrawal of one control rod under the control of the reactor mode switch Refuel position one-rod-out interlock.

b. At least once per 12 hours.

             " Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.
             **See Special Test Exception 3.10.3.

O HOPE CREEK 3/4 9-5

REFUELING OPERATIONS 3/4.9.4 DECAY TIME LIMITING C0!!DITION FOR OPERATION 3.9.4 The reactor shall be subcritical for at least 24 hours. , APPLICABILITY: OPERATIONAL CONDITION 5, during movement of irradiated fuel in the reactor pressure vessel. ACTION: With the reactor subcritical for less than 24 hours, suspend all operations involving movement of irradiated fuel in the reactor pressure vessel. SURVEILLANCE REQUIREMENTS 4.9.4 The reactor shall be determined to have been subcritical for at least 24 hours by verification of the date and time of subcriticality prior to movement of irradiated fuel in the reactor pressure vessel. O l HOPE CREEK 3/4 9-6 1 l

REFUELING OPERATIONS V 3/4.9.5 COMMUNICATIONS LIMITING CONDITION FOR OPERATION 3.9.5 Direct communication shall be maintained between the control room and refueling floor personnel. APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS. ACTION: When direct communication between the control room and refueling floor personnel cannot be maintained, immediately suspend CORE ALTERATIONS. 4 SURVEILLANCE REQUIREMENTS

 ,                    4.9.5 Direct communication between the control room and refueling floor i

personnel shall be demonstrated within one hour prior to the start of and at least once per 12 hours during CORE ALTERATIONS. i i i t i HOPE CREEK 3/4 9-7 l

   -,  --+---r----- + '      ~                                          -        - --

REFUELING OPERATIONS 3/4.9.6 REFUELING PLATFORM LIMITING CONDITION FOR OPERATION 3.9.6 The refueling platform shall be OPERABLE and used for handling fuel assemblies or control rods within the reactor pressure vessel. AFPLICABILITY: During handling of fuel assemblies or control rods within the reactor pressure vessel. ACTION: With the requirements for refueling platform OPERABILITY not satisfied, suspend use of any incperable refueling platform equipment from operations involving the handling of control rods and fuel assemblies within the reactor pressure vessel after placing the load in a safe condition. SURVEILLANCE REQUIREMENTS 4.9.6.1 The refueling platform main hoist used for handling of control rods or fuel assemblies within the reactor pressure vessel shall be demonstrated OPERABLE within 7 days prior to the start of such operations by:

a. Demonstrating operation of the overload cutoff on the main hoist when the load exceeds 1200 + 0, -50 pounds,

b. Demonstrating operation of the main hoist uptravel stops ,when uptravel brings the top of active fuel to 8 feet below the normal Water le' vel.

c. Demonstrating operation of the slack cable cutoff on the main hoist when the load is less than 50 1 10 pounds.

d. Demonstra. ting operation of the loaded rod block interlock on the nain -

hoist when the load exceeds 485 1 50 pounds.

e. Demonstrating operation of the redundant loaded interlock on the main hoist when the load exceeds 550 1 50 pounds.

HOPE CREEK 3/4 9-8

i REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS (Continued) , 4.9.6.2 The refueling platform frame-mounted auxiliary hoist used for handling of control rods within the reactor pressure vessel shall be demonstrated OPERABLE within 7 days prior to the use of such equipment by:

a. Demonstrating operation of the overload cutoff on the frame mounted hoist when the load exceeds 500 1 50 pounds.

b. Demonstrating operation of the uptravel mechanical stop on the frame mounted hoist when uptravel brings the grapple to 8 feet below the normal water level.

c. Demonstrating operation of the control rod block interlock on the frame mounted hoist when the load exceeds 400 1 50 pounds.

4.9.6.3 The refueling platform monorail mounted auxiliary hoist used for handling of control rods within the reactor pressure vessel shall be demon-strated OPERABLE within 7 days prior to the use of such equipment by:

a. Demonstrating operation of the overload cutoff on the monorail hoist when the load exceeds 500 1 50 pounds.

O V

b. Demonstrating operation of the uptravel mechanical stop on the mono-rail hoist when uptravel brings the grapple to 8 feet below the normal water level.

c. Demonstrating operation of the control rod block interlock on the monorail hoist when the load exceeds 400 1 50 pounds.

l

l HOPE CREEK 3/4 9-9 I l

I e REFUELING OPERATIONS

1 3/4.9.7 CRANE TRAVEL-SPENf FUEL STORAGE 'P00L l l , LIMITING CONDITION FOR OPERATION 3.9.7 Loads in excess of 1200 pounds shall be prohibited from travel over fuel assemblies in the spent fuel storage pool racks unless handled by a single failure prosf handling system. , APPLICABILITD With fuel assemblies in the spent fuel storage pool racks. i l ACTION: l With the requirements of the above specification not satisfied, place the polar crane load in a safe condition. The provisions of Specification 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS 4.9.7.1 Interlocks and physical stops which prevent polar crane main hoist travel over fuel assemblies in the spent fuel storage pool racks shall be demonstrated OPERABLE within 7 days prior to and at least once per 7 days during polar crane operation. 4.9.7.2 The single failure proof handling system shall be visually inspected and verified OPERABLE within 7 days prior to and et least once per 7 days during polar crane operation. l l l 9 HOPE CREEK 3/4 9-10

s' REFUELING OPERATIONS O' [ 3/4.9.8 WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION _ 3.9.8 At least 22 feet 2 inches of water shall be maintained over the top of the reactor pressure vessel flange. APPLICABILITY: During handling of fuel assemblies or control rods within the reactor pressure vessel while in OPERATIONAL CONDITION 5 when the fuel assemblies being handled are irradiated or the fuel assemblies seated within the reactor vessel are irradiated. ACTION: With the requirements of the above specification not satisfied, suspend all operations involving handling of fuel assemblies or control rods within the reactor pressure vessel after placing all fuel assemblies and control rods in a safe condition. m i SURVEILLANCE REQUIREMENTS 4.9.8 The reactor vessel water level shall be determined to be at least its minimum required depth within 2 hours prior to the start of and at least once per 24 hours during handling of fuel assemblies or control rods within the reactor pressure vessel. 1 1 l l O V HOPE CREEK 3/4 9-11

REFUELING OPERATIONS 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE POOL O LIMITING CONDITION FOR OPERATION 3.9.9 At least 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks. APPLICABILITY: Whenever irradiated fuel assemblies are in the spent fuel storage pool.

ACTION:

With the requirements of the above specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the spent fuel storage pool area after placing the fuel assemblies and crane load in a safe condition. The provisions of Specification 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS 4.9.9 The water level in the spent fuel storage pool shall be determined to be at least at its minimum required depth at least once per 7 days. O HOPE CREEK 3/4 9-12

O REFUELING OPERATIONS U 3/4.9.10 CONTROL ROD REMOVAL SINGLE CONTROL ROD REMOVAL LIMITING CONDITION FOR OPERATION 3.9.10.1 One control rod and/or the associated control rod drive mechanism may be removed from the core and/or reactor pressure vessel provided that at least the following requirements are satisfied until a control rod and associ-ated control rod drive mechanism are reinstalled and the control rod is fully inserted in the core.

a. The reactor mode switch is OPERABLE and locked in the Shutdown position or in the Refuel position per Table 1.2 and Specification 3.9.1.; b. The source range monitors (SRM) are OPERABLE per Specification 3.9.2.; c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied, except that the control rod selected to be removed; m 1. May be assumed to be the highest worth control rod required to be assumed to be fully withdrawn by the SHUTDOWN MARGIN test, and; 2. Need not be assumed to be immovable or untrippable.; d. All other control rods in a five-by-five array centered on the control
rod being removed are inserted and electrically or hydraulically disarmed or the four fuel assemblies surrounding the control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.: e. All other control rods are inserted.; f. All fuel loading operations shall be suspended. I APPLICABILITY: OPERATIONAL CONDITIONS 4 and 5.

ACTION: I With the requirements of the above specification not satisfied, suspend removal of the control rod and/or associated control rod drive mechanism from the core , and/or reactor pressure vessel and initiate action to satisfy the above requirements. O HOPE CREEK 3/4 9-13

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS 4.9.10.1 Within 4 hours prior to the start of removal of a control rod and/or the associated control rod drive mechanism from the core and/or reactor pressure vessel and at least once per 24 hours thereafter until a control rod and associ-ated control rod drive mechanism are reinstalled and the control rod is inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position with the "one rod out" Refuel position interlock OPERABLE per Specification 3.9.1.

b. The SRM channels are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied per Specification 3.9.10.1.c.

d. All other control rods in a five-by-five array centered on the control rod being removed are inserted and electrically or hydraulically disarmed or the four fuel assemblies surrounding the control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

e. All other control rods are inserted.

l

f. All fuel loading operations are suspended.

l l 9 HOPE CREEK 3/4 9-14

(^ REFUELING OPERATIONS ( MULTIPLE CONTROL R0D REMOVAL LIMITING CONDITION FOR OPERATION 3.9.10.2 Any number of control rods and/or control rod drive mechanisms may be removed from the core and/or reactor pressure vessel provided that at least i the following requirements are satisfied until all control rods and control i rod drive mechanisms are reinstalled and all control rods are inserted in the Core.

a. The reactor mode switch is OPERABLE and locked in the Shutdown position or in the Refuel position per Specification 3.9.1, except that the Refuel position "one-rod-out" interlock may be bypassed, as required, for those control rods and/or control rod drive mechanisms to be removed, after the fuel assemblies have been removed as specified below.

b. The source range monitors SRM are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

   ;       d.           All other control rods are either inserted or have the surrounding
'd                      four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

f. All fuel loading operations shall be suspended.

APPLICABILITY: OPERATIONAL CONDITION 5. ACTION: With the requirements of the above specification not satisfied, suspend removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and initiate action to satisfy the above requirements. HOPE CREEK 3/4 9-15

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS 4.9.10.2.1 Within 4 hours prior to the start of removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and at least once per 24 hours thereafter until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position per Specification 3.9.1.

b. The SRM channels are OPERABLE per Specification 3.9.2.

l

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assenblies surrounding each control rod and/or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell. I l

f. All fuel loading operations are suspended.

4.9.10.2.2 Following replacement of all control rods and/or control rod drive mechanisms removed in accordance with this specification, perform a functional test of the "one-rod-out" Refuel position interlock, if this function had been l bypassed. O HOPE CREEK 3/4 9-16

REFUELING OPERATIONS 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION HIGH WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.11.1 At least one shutdown cooling mode loop of the residual heat removal (RHR) system shall be OPERABLE and in operation

with:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger.

l APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is gre. iter than or equal to 22 feet 2 inches above the top of the reactor pressure vessel flange and heat losses to ambient ** are not sufficient to maintain OPERATIONAL CONDITION 5. ACTION:

a. With no RHR shutdown cooling mode loop OPERABLE, within one hour and at s least once per 24 hours thereafter, demonstrate the operability of at j least one alternate method capable of decay heat removal. Otherwise, suspend all operations involving an increase in the reactor decay heat load and establish SECONDARY CONTAINMENT INTEGRITY within 4 hours.

b. With no RHR shutdown cooling mode loop in operation, within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature at least once per hour.

r SURVEILLANCE REQUIREMENTS 4.9.11.1 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be verified to be in operation and circulating reactor coolant at least once per 12 hours. l l A The shutdown cooling pump may be removed from operation for up to 2 hours g per 8-hour period.

           ** Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though REFUELING conditions are being maintained).

l HOPE CREEK 3/4 9-17 l t 1

     - - .                      .---                    _                       _ _ . --                       _\

l I i REFUELING OPERATIONS LOW WATER LEVEL l LIMITING CONDITION FOR OPERATION 3.9.11.2 Two shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and at least one loop shall be in operation,* with each loop consisting of:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger. l APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor .

vessel and the water level is less than 22 feet 2 inches above the top of the reactor pressure vessel flange and heat losses to ambient ** are not sufficient to maintain OPERATIONAL CONDITION 5. ACTION:

a. With less than the above required shutdown cooling mode loops of the RHR system OPERABLE, within one hour and at least once per 24 hours there-after, demonstrate the OPERABILITY of at least one alternate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop.

b. With no RHR shutdown cooling mode loop in operation, within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature at least once per hour.

c. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.11.2 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be verified to be in operation and circulating reactor coolant at least once per 12 hours.

   "The shutdown cooling pump may be removed from operation for up to 2 hours per 8-hour period.

l

 ** Ambient losses must be such that no increase in reactor vessel water temper-     l ature will occur (even though REFUELING conditions are being maintained).

l O' HOPE CREEK 3/4 9-18

1 l l l (% C 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.10.1 The provisions of Specifications 3.6.1.1, 3.6.1.3 and 3.9.1 and Table 1.2 may be suspended to permit the reactor pressure vessel closure head and the drywell head to be removed and the primary containment air lock doors to be open when the reactor mode switch is in the Startup position during low power PHYSICS TESTS with THERMAL POWER less than 1% of RATED THERMAL POWER and reactor coolant temperature less than 200*F. APPLICABILITY: OPERATIONAL CONDITION 2, during low power PHYSICS TESTS. ACTION: With THERMAL POWER greater than or equal to 1% of RATED THERMAL POWER or with the reactor coolant temperature greater than or equal to 200*F, immediately place the reactor mode switch in the Shutdown position. d SURVEILLANCE REQUIREMENTS 4.10.1 The THERMAL POWER and reactor coolant temperature shall be verified to be within the limits at least once per hour during low power PHYSICS TESTS. l HOPE CREEK 3/4 10-1

SPECIAL TEST EXCEPTIONS 3/4.10.2 ROD SEQUENCE CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.10.2 The sequence constraints imposed on control rod groups by the rod worth minimizer (RWM) per Specification 3.1.4.1 and by the rod sequence control system (RSCS) per Specification 3.1.4.2 may be suspended by means of bypass switches for the following tests provided that control rod movement prescribed for this testing is verified by a second licensed operator or other technically qualified member of the unit technical staff present at the reactor console:

a. Shutdown margin demonstrations, Specification 4.1.1.

b. Control rod scram, Specification 4.1.3.2.

c. Control rod friction measurements.

d. Startup Test Program with the THERMAL POWER less than 20% of RATED THERMAL POWER.

A?PLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With the requirements of the above specification not satisfied, verify that the RWM and/or the RSCS is OPERABLE per Specifications 3.1.4.1 and 3.1.4.2, l respectively. SURVEILLANCE REQUIREMENTS l 4.10.2 When the sequence constraints imposed by the RSCS and/or RWM are bypassed, verify: i I

a. That movement of the control rods from 75% R0D DENSITY to the RSCS low power setpoint is limited to the approved control rod withdrawal sequence during scram and friction tests.

b. That movement of control rods during shutdown margin demonstra-tions is limited to the prescribed sequence per Specification 3.10.3.

l c. Conformance with this specification and test procedures by a second licensed operator or other technically qualified member of the unit technical staff. HOPE CREEK 3/4 10-2

'p

 's SPECIAL TEST EXCEPTIONS                                                              ,

l 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS LIMITING CONDITION FOR OPERATION 3.10.3 The provisions of Specification 3.9.1, Specification 3.9.3 and Table 1.2 may be suspended to permit the reactor mode switch to be in the Startup position and to allow more than one control rod to be withdrawn for shutdown margin demonstration, provided that at least the following requirements are satisfied.

a. The source range monitors are OPERABLE with the RPS circuitry " shorting links" removed per Specification 3.9.2.

b. The rod worth minimizer is OPERABLE per Specification 3.1.4.1 and is programmed for the shutdown margin demonstration, or conformance with the shutdown margin demonstration procedure is verified by a second licensed operator or other technically qualified member of the unit technical staff.

c. The " rod-out-notch-override" control shall not be used during out-of-sequence movement of the control rods.

d. No other CORE ALTERATIONS are in progress.

APPLICABILITY: OPERATIONAL CONDITION 5, during shutdown margin demonstrations. ACTION: With the requirements of the above specification not satisfied, immediately place the reactor mode switch in the Shutdown or Refuel position. SURVEILLANCE REQUIREMENTS 4.10.3 Within 30 minutes prior to and at least once per 12 hours during the performance of a shutdown margin demonstration, verify that;

a. The source range monitors are OPERABLE per Specification 3.9.2,

b. The rod worth minimizer is OPERABLE with the required program per Specification 3.1.4.1 or a second licensed operator or other techni-l cally qualified member of the unit technical staff is present and verifies compliance with the shutdown demonstration procedures, and l O c. No other CORE ALTERATIONS are in progress.

HOPE CREEK 3/4 10-3

SPECIAL TEST EXCEPTIONS 3/4.10.4 RECIRCULATION LOOPS LIMITING CONDITION FOR OPERATION 3.10.4 The requirements of Specifications 3.4.1.1 and 3.4.1.3 that recirculation loops be in operation with matched pump speed may be suspended for up to 24 hours for the performance of:

a. PHYSICS TESTS, provided that THERMAL POWER does not exceed 5% of RATED THERMAL POWER, or

b. The Startup Test Program.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2, during PHYSICS TESTS and the Startup Test Program. ACTION:

a. With the above specified time limit exceeded, insert all control rods.

b. With the above specified THERMAL POWER limit exceeded during PHYSICS TESTS, immediately place the reactor mode switch in the Shutdown position.

SURVEILLANCE REQUIREMENTS 4.10.4.1 The time during which the above specified requirement has been suspended shall be verified to be less than 24 hours at least once per hour during PHYSICS TESTS and the Startup Test Program. 4.10.4.2 THERMAL POWER shall be determined to be less than 5% of RATED THERMAL POWER at least once per hour during PHYSICS TESTS. O HOPE CREEK 3/4 10-4 i

             .           .            . _ _ -                                      __- _\

SPECIAL TEST EXCEPTIONS 3/4.10.5 OXYGEN CONCENTRATION LIMITING CONDITION FOR OPERATION 3.10.5 The provisions of Specification 3.6.6.2 may be suspended during the performance of the Startup Test Program until 6 months after initial criticality. APPLICABILITY: OPERATIONAL CONDITION 1. ACTION With the requirements of the above specification not satisfied, be in at least STARTUP within 6 hours. O

,   SURVEILLANCE REQUIREMENTS 4.10.5 The number of months since initial criticality shall be verified to be less than or equal to 6 months at least once per 31 days during the Startup Test Program.

f O HOPE CREEK 3/4 10-5

SPECIAL TEST EXCEPTIONS 3/4.10.6 TRAINING STARTUPS LIMITING CONDITION FOR OPERATION __ 3.10.6 The provisions of Specification 3.5.1 may be suspended to permit one RHR subsystem to be aligned in the shutdown cooling mode during training startups provided that the reactor vessel is not pressurized, THERMAL POWER is less than or equal to 1% of RATED THERMAL POWER and reactor coolant temperature is less than 200 F. APPLICABILITY: OPERATIONAL CONDITION 2, during training startups. ACTION: With the requirements of the above specification not satisfied, immediately place the reactor mode switch in the Shutdown position. SURVEILLANCE REQUIREMENTS 4.10.6 The reactor vessel shall be verified to be unpressurized and the THERMAL POWER and reactor coolant temperature shall be verified to be within the limits at least once per hour during training startups. O HOPE CREEK 3/4 10-6

[] SPECIAL TEST EXCEPTIONS 3/4.10.7 SPECIAL INSTRUMENTATION - INITIAL CORE LOADING LIMITING CONDITION FOR OPERATION 3.10.7 During initial core loading within the Startup Test Program the pro-visions of Specification 3.9.2 may be suspended provided that at least two source range monitor (SRM) channels with detectors inserted to the normal operating level are OPERABLE with:

a. One of the required SRM channels continuously indicating

in the control room,

b. One of the required SRM detectors located in the quadrant where CORE ALTERATIONS are being performed and the other required SRM detector located in an adjacent quadrant,**

c. The RPS " shorting links" shall be removed prior to and during fuel loading,

d. The reactor mode switch is OPERABLE-and locked in the REFUEL position.

APPLICABILITY: OPERATIONAL CONDITION 5 ACTION With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE ALTERATIONS and insert all insertable control rods. SURVEILLANCE REQUIREMENTS 4.10.7 Each of the above required SRM channels shall be demonstrated OPERABLE by: -

a. Within 1 hour prior to and at least once per 12 hours during CORE ALTERATIONS:

1. Performance of a CHANNEL CHECK ***

l

2. Confirming that the above required SRM detectors are at the normal operating level and located in the quadrants required by Specification 3.10.7.

          "Up to 16 fuel bundles may be loaded without a visual indication of count I

rate. 'h '\j

        **The use of special movable detectors during CORE ALTERATIONS in place of the normal SRM nuclear detectors is permissible as long as these special detectors are connected to the normal SRM circuits.
       *** Check may be performed by use of movable neutron source.

HOPE CREEK 3/4 10-7 l

SPECIAL TEST EXCEPTIONS SURVEILLANCE REQUIREMENTS (Continued) 4.10.7. (Continued)

3. The RPS " shorting links" are removed.

4. The reactor mode switch is locked in the REFUEL position.

b. Performance of a CHANNEL FUNCTIONAL TEST within 24 hours prior to the start and at least once per 7 days during CORE ALTERATIONS.

c. Verifying for at least one SRM channel that the count rate is at least 0.7 cps *:

1. Immediately following the loading of the first 16 fuel bundles.

2. At least once per 12 hours thereafter during CORE ALTERATIONS.

O

   *Provided signal-to-noise is > 2. ,

Otherwise, 3 cps. O HOPE CREEK 3/4 10-8

g- 3/4.11 RADI0 ACTIVE EFFLUENTS 3/4.11.1 LIQUID EFFLUENTS CONCENTRATION LIMITING CONDITION FOR OPERATION 3.11.1.1 The concentration of radioactive material released in liquid effluents to UNRESTRICTED AREAS (see Figure 5.1.1-1) shall be limited to the concentra-tions specified in 10 CFR Part 20, Appendix B, Table II, Column 2 for radio-nuclides other than dissolved or entrained noble gases. For dissolved or entrained noble gases, the concentration shall be limited to 2 x 10 4 microcuries/ml total activity. APPLICABILITY: At all times. ACTION: With the concentration of radioactive material released in liquid effluents to UNRESTRICTED AREAS exceeding the above limits, immediately restore the concentration to within the above limits. SURVEILLANCE REQUIREMENTS O 4 .11.1.1.1 Radioactive liquid wastes shall be sampled and analyzed according to the sampling and analysis program of Table 4.11.1.1.1-1. 4.11.1.1.2 The results of the radioactivity analyses shall be used in accordance with the methodology and parameters in the ODCM to assure that the concentrations at the point of release are maintai.1ed within the limits of Specification 3.11.1.1. i l O HOPE CREEK 3/4 11-1 l

TABLE 4.11.1.1.1-1 RADI0 ACTIVE LIQUID WASTE SAMPLING AND ANALYSIS PROGRAM Lower Limit Minimum ofDetectjon Liquid Release Sampling Analysis Type of Activity - (LLD) Type Frequency Frequency Analysis (pCi/ml) A. Batch Wgste P P Each Batch

                                                                             -7 Release         Each Batch                    Principa} Gamma    5x10 Sample                                        Emitters Tanks (3)                                                             -6 I-131              1x10 P                 M        Dissolved and      1x10
                                                                             -5 One Batch /M                  Entrained Gases (Gamma Emitters)

P M H-3 1x10 0 d Each Batch Composite Gross Alpha

                                                                             -7 1x10 l

P Sr-89, Sr-90 5x10

                                                                             -8 Q   d Each Batch    Composite Fe-55              1x10
                                                                             -6 5x10
                                                                             -7 f  B. Continuogs                             M    Principa} Gamma d

l Releases Composite Emitters Station Service NA

                                                                             -6 Water System                                I-131                1x10 (GSW) (If                                                            -5 contaminated      W                   M    Dissolved and        1x10 as indicated   Grab Sample                 Eritrained Gases by SACS                                    (Gamma Emitters) system)                                                              -5 H-3                  1x10 d                            -7 NA          Composi e    Gross Alpha          1x10 Q d  Sr-89, Sr-90         5x10 NA          Composite 1x10
                                                                             -6 Fe-55 O

HOPE CREEK 3/4 11-2

 /~N                                 TABLE 4.11.1.1.1-1 (Continued)

TABLE NOTATION a The LLD is defined, for purposes of these specifications, as the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 95% probability with only 5% probability of falsely concluding that a blank observation represents a "real" signal. For a particular measurement system, which may include radiochemical separation: 4' 8 b LLD = E V 2.22 x 108 Y exp (-Aat) Where: LLD is the "a priori" lower limit of detection as defined above, as microcuries per unit mass or volume, s is the standard deviation of the background counting rate or of t,e counting rate of a blank sample as appropriate, as counts per minute, E is the counting efficiency, as counts per disintegration, V is the sample size in units of mass or volume, 2.22 x 108 is the number of disintegrations per minute per microcurie, Y is the fractional radiochemical yield, when applicable, A is the radioactive decay constant for the particular radionuclide (sec 1), and at for plant effluents is the elapsed time between the midpoint of sample collection and time of counting (sec). Typical values of E, V, Y, and at should be used in the calculation. It should be recognized that the LLD is defined as an a priori (before the fact) limit representing the capability of a measurement system and I not as an,a posteriori (after the fact) limit for a particular measurement. b A batch release is the discharge of liquid wastes of a discrete volame. Prior to sampling for analyses, each batch shall be isolated, and then thoroughly mixed by a method described in the ODCM to assure representative sampling. G HOPE CREEK 3/4 11-3

TABLE 4.11.1.1.1-1 (Continued) TABLE NOTATION c The principal gamma emitters for which the LLD specification applies exclusively are: Mn-54, Fe-59, Co-58, Co-60, Zn-65, Mo-99, Cs-134, Cs-137, and Ce-141. Ce-144 shall also be measured, but with an LLD of 5 x 10 6 This does not mean that only these nuclides are to be considered. Other peaks that are identifiable, together with those of the aboVB nuclides, shall also be analyzed and reported in the Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.7. d A composite sample is one in which the quantity of liquid samples is proportional to the quantity of liquid waste discharged and in which the method of sampling employed results in a specimen that is representative of the liquids released.

  'A continuous release is the discharge of liquid wastes of a nondiscrete volume; e.g., from a volume of a system that has an input flow during the continuous release.

O O HOPE CREEK 3/4 11-4

RADI0 ACTIVE EFFLUENTS

  /\s_,/
     ')  DOSE LIMITING CONDITION FOR OPERATION 3.11.1.2 The dose or dose commitment to a MEMBER OF THE PUBLIC from radio-active materials in liquid effluents released, from each reactor unit, to UNRESTRICTED AREAS (see Figure 5.1.1-1) shall be limited:

a. . During any calendar quarter to less than cr equai to 1.5 mrems to the total body and to less than or equal to 5 mrems to any organ, and

, b. Durf ag any calendar year to less than or equal to 3 mrems to the total body and to less than or equal to 10 mrems to any organ. APPLICABILITY: At all times. ACTION:

a. With the calculated dose from the release of radioactive materials in liquid effluents exceeding any of the above limits, prepare and '

submit to the Comniission within 30 days, pursuant to Scecifica-tion 6.0.2, a Special G6 port that identifies the causa(s) for ' T exceeding the limit (;) and defines the corrective actions that '

   ,j               have been taken to reduce the releases and the proposed , corrective actions to be taken to assure that subse.quent r.eleases will be in compliance with the above limits.

b. The provisions of Sp6cifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS ~ l l l 4.11.1.2 Cumulative dose contributions from liquid effluents for the current

calendar quarter and the current calendar year sht11 be detsrmi.ned in :

accordance with the methodology and paras.etcrs ir, the DDCM at 16ast once per 31 days. 1 () . HOPE CREEK 3/4 11-5 t

RADI0 ACTIVE EFFLUENTS LIQUID WASTE TREATMENT LIMITING CONDITION FOR OPERATION 3.11.1.3 The liquid radwaste treatment system shall be OPERABLE and appropriate portions of the system shall be used to reduce the radioactive materials in liquid wastes prior to their discharge when the projected doses due to the liquid effluent, from each reactor unit, to UNRESTRICTED AREAS (see ; Figure 5.1.1-1) would exceed 0.06 mrem to the total body or 0.2 mrem to any organ in any 31-day period. APPLICABILITY: At all times. ACTION:

a. With radioactive liquid waste being discharged and in excess of the above limits and any portion of the liquid radwaste treatment system not in operation, prepare and submit to the Commission within 30 days pursuant to Specification 6.9.2 a Special Report that includes the following information:

1. Explanation of why liquid radwaste was being discharged without treatment, identification of any inoperable equipment or sub-systems, and the reason for the inoperability,

2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and

, 3. Summary description of action (s) taken to prevent a recurrence.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.1.3.1 Doses due to liquid releases from each reactor unit to UNRESTRICTED AREAS shall be projectcd at least once per 31 days in accordance with the methodology and parameters in the ODCM.

4. 11.1.3.2 The installed liquid radwaste treatment system shall be demonstrated OPERABLE by meuting Specifications 3.11.1.1 and 3.11.1.2.

O HOPE CREEK 3/4 11-6 l

RADIOACTIVE EFFLUENTS

~}

LIQUID HOLDUP TANKS LIMITING CONDITION FOR OPERATION 3.11.1.4 The quantity of radioactive material contained in any outside temporary tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained noble gases. APPLICABILITY: At all times. ACTION:

a. With the quantity of radioactive material in any of the above tanks exceeding the above limit, immediately suspend all cdditions of radioactive material to the tank, within 48 hours reduce the tank contents to within the limit, and describe the events leading to this condition in the next Semiannual Radioactive Effluent Release Report, pursuant to Specification 6.9.1.7.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

O SURVEILLANCE REQUIREMENTS 4.11.1.4 The quantity of radioactive material contained in each of the above tanks shall be determined to be within the above limit by analyzing a repre-sentative sample of the tank's contents at least once per 7 days when radio-active materials are being added to the tank. l i l l I l l , I I l HOPE CREEK 3/4 11-7 l

RADIOACTIVE EFFLUENTS 3/4.11.2 GASEOUS EFFLUENTS DOSE RATE LIMITING CONDITION FOR OPERATION 1 1 3.11.2.1 The dose rate due to radioactive materials released in gaseous effluents from the site to areas at and beyond the SITE BOUNDARY (see Figure 5.1.1-1) shall be limited to the following:

a. For noble gases: Less than or equal to 500 mrems/yr to the total body and less than or equal to 3000 mrems/yr to the skin, and

b. For iodine-131, iodine-133, tritium, and for all radionuclides in particulate form with half-lives greater than 8 days: Less than or equal to 1500 mrems/yr to any organ.

APPLICABILITY: At all times. ACTION: With the dose rate (s) exceeding the above limits, immediately restore the release rate to within the above limit (s). SURVEILLANCE REQUIREMENTS 4.11.2.1.1 The dose rate due to noble gases in gaseous effluents shall be determined to be within the above limits in accordance with the methodology and parameters in the ODCM. 4.11.2.1.2 The dose rate due to iodine-131, iodine-133, tritium, and all radio-l nuclides in particulate form with half-lives greater than 8 days in gaseous

effluents shall be determined to be within the above limits in accordance with the methodology and parameters in the ODCM by obtaining representative samples and performing analyses in accordance with the sampling and analysis program specified in Table 4.11.2.1.2-1.

i l O HOPE CREEK 3/4 11-8 l

TABLE 4.11.2.1.2-1 RADI0 ACTIVE GASEOUS WASTE SAMPLING AND ANALYSIS PROGRAM n g Minimum Lower Limit of p Sampling Analysis Type of Detection (LLD), Gaseous Release Type Frequency Frequency Activity Analysis (pCi/ml) P P A. Containment PURGE Each PURGE (c) Each PURGE (c) Principal Gamma Emitters (b) 1x10

                                                                                                                                                       -4 Grab Sample                                                          -6 P        H-3 (oxide)                    1x10 B. North Plant Vent                   M(c),(d)               g(c)      Principal Gamma Emitters (b)   1x10 South Plant Vent                   Grab Sample                      H-3 (oxide)                    1x10 C. All Release Types                  Continuous (*)         W CI)     I-131                          1x10
                                                                                                                                                       -12 as listed in A                                      Charcoal and B above.                                        Sample Continuous (*)         W II)     Principal Gamma Emitters (D)   1x10
                                                                                                                                                       -11 4

R 1 Particulate y Sample E Continuous (*) Q Gross Alpha 1x10

                                                                                                                                                       -11 Composite Particulate Sample Continuous (*)                   Sr-89, Sr-90                   1x10
                                                                                                                                                       -11 Q

Composite Particulate Sample Continuous (*) Noble Gas Noble Gases 1x10

                                                                                                                                                       -6 Monitor         Gross Beta or Gamma               ,

I l }

TABLE 4.11.2.1.2-1 (Continued) l TABLE NOTATION (a)The LLD is defined, for purposes of these specifications, as the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 9]i% probability with only 5% probability of falsely concluding that a blank observation represents a "real" signal. For a particular measurement system, which may include radiochemical separation: LLD = - E V 2.22 x 108 Y exp (-Aat) Where: LLD is the "a priori" lower limit of detection as defined above, as microcuries per unit mass or volume, shis the standard deviation of the background counting rate or of tne counting rate of a blank sample as appropriate, as counts per minute, E is the counting efficiency, as counts per disintegration, V is the sample size in units of mass or volume, 2.22 x 108 is the number of disintegrations per minute per microcurie, Y is the fractional radiochemical yield, when applicable, l A is the radioactive decay constant for the particular radionuclide (sec 1), and l At for plant effluents is the elapsed time between the midpoint of l sample collection and time of counting (sec). l Typical values of E, V, Y, and at should be used in the calculation. l l It should be recognized that the LLD is defined as an a priori (before the fact) limit representing the capability of a measurement system and not as an a posteriori (after the fact) limit for a particular measurement. l l e t HOPE CREEK 3/4 11-10 i

TABLE 4.11.2.1.2-1 (Continued) h TABLE NOTATIONS (b)The principal gamma emitters for which the LLD specification applies exclusively are the following radionuclides: Kr-87, Kr-88, Xe-133, Xe-133m, Xe-135, and Xe-138 in noble gas releases and Mn-54, Fe-59, Co-58, Co-60, Zn-65, Mo499, I-131, Cs-134, Cs-137, Ce-141 and Ce-144 in iodine and particulate releases. This list does not mean that only these nuclides are to be sensidered. Other gamma peaks that are identifiable, together with those of the above nuclides, shall also be analyzed and reported in the Semiannual Radioactive l 4 Effluent Release Report pursuant to Specification 6.9.1.7. ' (c) Sampling and analysis shall also be performed following shutdown, startup, or a THERMAL POWER change exceeding 15% of RATED THERMAL POWER within a 1-hour period. This requirement does not apply if (1) analysis shows that the DOSE EQUIVALENT I-131 concentration in the primary coolant has not increased more than a factor of 3; and (2) the noble gas monitor shows that effluent activity has not increased more than a factor of 3. (d) Tritium grab samples shall be taken at least once per 7 days from the ventilation exhaust from the spent fuel pool area, whenever spent fuel is in the spent fuel pool. (e)The ratio of the sample flow rate to the sampled stream flow rate shall be known for the time period covered by each dose or dose rate calculation made in accordance with Specifications 3.11.2.1, 3.11.2.2, and 3.11.2.3. (f) Samples shall be changed at least once per 7 days and analyses shall be completed within 48 hours after changing, or after removal from sampler. Sampling shall also be performed at least once per 24 hours for at least 7 days following each shutdown, startup or THERMAL POWER change exceeding 15% of RATED THERMAL POWER in 1 hour and analyses shall be completed within 48 hours of changing. When saraples collected for 24 hours are analyzed, the corresponding LLDs may be increased by a factor of 10. This requiremeat does not apply if (1) analysis shows that the DOSE EQUIVALENT I-131 concentration in the primary coolant has not increased more than a factor of 3; and (2) the noble gas monitor shows that effluent activity has not increased more than a factor of 3. l l HOPE CREEK 3/4 11-11

a. RADIOACTIVE EFFLUENTS DOSE - NOBLE GASES LIMITING CONDITION FOR OPERATION 3.11.2.2 The air dose due to noble gases released in gaseous effluents, from each reactor unit, to areas at and beyond the SITE BOUNDARY (see Figure 5.1.1-1) shall be limited to the following:

a. During any calendar quarter: Less than or equal to 5 mrads for gamma radiation and less than or equal to 10 orads for beta radiation and,

b. During any calendar year: Less than or equal to 10 mrads for gamma radiation and less than or equal to 20 mrads for beta radiation.

APPLICABILITY: At all times. ACTION

a. With the calculated air dose from radioactive noble gases in gaseous effluents exceeding any of the above limits, prepare and submit to the Commission within 30 days, pursucnt to Specification 6.9.2, a Special Report that identifies the cause(s) for exceeding the limit (s) and defines the corrective actions that have been taken to reduce the releases and the proposed corrective actions to be taken to assure that subsequent releases will be in compliance with the above limits.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2.2 Cumulative dose contributions for the current calendar quarter and current calendar year for noble gases shall be determined in accordance with the methodology and parameters in the ODCM at least once per 31 days. O l HOPE CREEK 3/4 11-12

m RADIOACTIVE EFFLUENTS l DOSE - 10 DINE-131, IODINE-133, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM LIMITING CONDITION FOR OPERATION 3.11.2.3 The dose to a MEMBER OF THE PUBLIC from iodine-131, iodine-133, tritium, and all radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents released, from each reactor unit, to areas at and beyond the SITE B0UNDARY (see Figure 5.1.1-1) shall be limited to the following:

a. During any calendar quarter: Less than or equal to 7.5 mrems to any organ and,

b. During any calendar year: Less than or equal to 15 mrems to any organ.

APPLICARILITY: At all times. ACTION:

a. With the calculated dose from the release of iodine-131, iodine-133, tritium, and radionuclides in particulate form with half lives greater than 8 days, in gaseous effluents exceeding any of the above limits, prepare and submit to the Commission within 30 days, pursuant to y Specification 6.9.2, a Special Report that identifies the cause(s) for exceeding the limit and defines the corrective actions that have been taken to reduce the releases and the proposed corrective actions to be taken to assure that subsequent releases will be in compliance with the above limits.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS ; l 4.11.2.3 Cumulative dose contributions for the current calendar quarter and current calendar year for iodine-131, iodine-133, tritium, and radionuclides in particulate form with half-lives greater than 8 days shall be determined in accordance with the methodology and parameters in the ODCM at least once ! per 31 days. ) l HOPE CREEK 3/4 11-13

RADIOACTIVE EFFLUENTS GASEOUS RADWASTE TREATMENT LIMITING CONDITION FOR OPERATION 3.11.2.4 The GASE0US RADWASTE TREATMENT SYSTEM shall be in operation. APPLICABILITY: Whenever the main condenser steam jet air ejector system is in operation. ACTION:

a. With gaseous radwaste from the main condenser air ejector system being discharged without treatment for more than 7 days, prepare and submit to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special Report that includes the following information:

1. Identification of the inoperable equipment or subsystems and the reason for the inoperability,

2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and

3. Summary description of action (s) taken to prevent a recurrence.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2.4 The readings of the relevant instruments shall be checked every 12 hours when the main condenser air ejector is in use to ensure that the gaseous radwaste treatment system is functioning. l l l l HOPE CREEK 3/4 11-14

p RADI0 ACTIVE EFFLUENTS VENTILAIION EXHAUST TREATMENT SYSTEM LIMITING CONDITION FOR OPERATION 3.11.2.5 The VENTILATION EXHAUST TREATMENT SYSTEM for the Reactor Building and the Service and Radwaste Building shall be OPERABLE and appropriate por-tions of this system shall be used to reduce release of radioactivity when the projected doses in 31 days due to gaseous effluent releases from each unit to areas at and beyond the SITE B0UNDARY (see Figure 5.1.1-1) would exceed:

a. 0.2 mrad to air from gamma radiation, or

b. 0.4 mrad to air from beta radiation, or

c. 0.3 mrem to any organ of a MEMBER OF THE PUBLIC APPLICABILITY: At all times.

ACTION:

a. With radioactive ventilation exhaust being discharged without treat-ment and in excess of the above limits, prepare and submit to the O Commission within 30 days pursuant to Specification 6.9.2 a Special V Report that includes the following information:

1. Identification of any inoperable equipment or subsystems, a:d the reason for the inoperability,

2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and

3. Summary description of action (s) taken to prevent a recurrence.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2.5.1 Doses due to gaseous releases from each unit to areas at and beyond the SITE BOUNDARY shall be projected at least once per 31 days in accordance with the methodology and parameters in the ODCM, when the VENTILATION EXHAUST TREATMENT SYSTEM is not being fully utilized. 4.11.2.5.2 The installed VENTILATION EXHAUST TREATMENT SYSTEM shall be con-sidered OPERABLE by meeting Specifications 3.11.2.1 and 3.11.2.2 and 3.11.2.3. O v , HOPE CREEK 3/4 11-15

RADI0 ACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE LIMITING CONDITION FOR OPERATION 3.11.2.6 The concentration of hydrogen in the main condenser offgas treatment system shall be limited to less than or equal to 4% by volume. APPLICABILITY: At all times. ACTION:

a. With the concentration of hydrogen in the main condenser offgas treatment system exceeding the limit, restore the concentration to within the limit within'48 hours,

b. With continuous monitors inoperable, operation of the main condenser offgas treatment system may continue for up to 30 days provided grab samples are collected at least once per 4 hours and analyzed within the following 4 hours.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2.6 The concentration of hydrogen in the main condenser offgas treatment system shall be determined to be within the above limits by continuously moni-toring the waste gases in the main condenser offgas treatment system whenever the main condenser evacuation system is in operation with the hydrogen monitors required OPERABLE by Table 3.3.7.10-1 of Specification 3.3.7.10. l l I O l HOPE CREEK 3/4 11-16

m RADI0 ACTIVE EFFLUENTS MAIN CONDENSER LIMITING CONDITION FOR OPERATION 3.11.2.7 The radioactivity rate of noble gases measured at the recombiner after-condenser discharge shall be limited to less than or equal to 330 milli-curies /sec after 30 minute decay. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3*. ACTION: With the radioactivity rate of noble gases at the recombiner after-condenser discharge exceeding 330 millicuries /sec after 30 minute decay, restore the radioactivity rate to within its limit within 72 hours or be in at least HOT STANDBY within the next 12 hours. SURVEILLANCE REQUIREMENTS 4.11.2.7.1 The radioactivity rate of noble gases at the recombiner after-condenser discharge shall be continuously monitored in accordance with Specifi-cation 3.3.7.1.

4.11.2.7.2 The radioactivity rate of noble gases from the recombiner after-condenser discharge shall be determined to be within the limits of Specifica-tion 3.11.2.7 at the following frequencies by performing an isotopic analysis of a representative sample of gases taken near the discharge of the main con-denser air ejector:

a. At least once per 31 days,

b. Within 4 hours following an increase, as indicated by the Offgas Radioactivity Monitor, of greater than 50%, after factoring out increases due to changes in THERMAL POWER level, in the nominal steady-state fission gas release from the primary coolant.

c. The provisions of Specification 4.0.4 are not applicable.

Q *When the main condenser air ejector is in operation. HOPE CREEK 3/4 11-17

4-I RADI0 ACTIVE EFFLUENTS VENTING OR PURGING LIMITING CONDITION FOR OPERATION ) i l 3.11.2.8 VENTING or PURGING of the Mark I containment drywell shall be through either the reactor building ventilation system or the filtration, recirculation , and ventilation system. APPLICABILITY: Whenever the containment is vented or purged. , l ACTION:

a. With the requirements of the above specification not satisfied, suspend all VENTING and PURGING of the drywell.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2.8 The containment shall be determined to be aligned for VENTING or PURGING through either the reactor building ventilation system or the filtration, recirculation and ventilation system within 4 hours prior to start of and at least once per 12 hours during VENTING or PURGING of the drywell. HOPE CREEK 3/4 11-18 ) 1

~ RADIOACTIVE EFFLUENTS 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT LIMITING-CONDITION FOR OPERATION 3.11.3 Radioactive wastes shall be SOLIDIFIED or dewatered in accordance with the PROCESS CONTROL PROGRAM to meet shipping and transportation requirements during transit, and disposal site requirements when received at the disposal site. APPLICABILITY: At all times. ACTION:

a. With SOLIDIFICATION or dewatering not meeting disposal site and

    <             shipping and transportation requirements, suspend shipment of the inadequately processed wastes and correct the PROCESS CONTROL PROGRAM, the procedures and/or the solid waste system as necessary to prevent recurrence,

b. With SOLIDIFICATION or dewatering not performed in accordance with the PROCESS CONTROL PROGRAM, (1) demonstrate by test or analysis that the improperly processed waste in each container meets the requirements for transportation to the disposal site and for receipt

. at the disposal site and (2) take appropriate administrative action to prevent recurrence. i c. The provisions of_ Specifications 3.0.3 and 3.0.4 are not applicable. ! d SURVEILLANCE REQUIREMENTS J 4.11.3.1 The PROCESS CONTROL PROGRAM shall be followed to verify that the pro-perties of the packaged waste meet the minimum stability requirements of 10 CFR Part 61 and other requirements for transportation to the disposal site and re-ceipt at the disposal site. 4.11.3.2 The PROCE$3 CONTROL PROGRAM shall include sufficient quality control

and assurance methods to assure the solidified waste product from any process (either in-house or contracted vendor) meets the requirements for transporta-tion and receipt at the disposal site.

HOPE CREEK 3/4 11-19

RADI0 ACTIVE EFFLUENTS 3/4.11.4 TO'AL DOSE LIMITING CONDITION FOR OPERATION 3.11.4 The annual (calendar year) dose or dose commitment to any MEMBER OF THE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources shall be limited to less than or equal to 25 mrems to the total body or any organ, except the thyroid, which shall be limited to less than or equal to 75 mrems. APPLICABILITY: At all times. ! ACTION:

a. With the calculated doses from the release of radioactive materials in liquid or gaseous effluents exceeding twice the limits of Specifi-cation 3.11.1.2a., 3.11.1.2b., 3.11.2.2a., 3.11.2.2b., 3.11.2.3a., or 3.11.2.3b., calculations should be made including direct radiation contributions from the units including outside storage tanks, etc.

to determine whether the above limits of Specification 3.11.4 have been exceeded. If such is the case, prepare and submit to the Com-mission within 30 days, pursuant to Specification 6.9.2, a Special Report that defines the corrective action to be taken to reduce sub-sequent releases to prevent recurrence of exceeding the above limits i and includes the schedule for achieving conformance with the above limits. This Special Report, as defined in 10 CFR 20.405c, shall include an analysis that estimates the radiation exposure (dose) to a MEMBER OF THE PUBLIC from uranium fuel cycle sources, including all effluent pathways and direct radiation, for the calendar year that includes the release (s) covered by this report. It shall also de-scribe levels of radiation and concentrations of radioactive material involved, and the cause of the exposure levels or concentrations. If the estimated dose (s) exceeds the above limits, and if the release ' condition resulting in violation of 40 CFR Part 190 has not already been corrected, the Special Report shall include a request for a vari-ance in accordance with the provisions of 40 CFR Part 190. Submittal of the report is considered a timely request, and a variance is granted until staff action on the request is complete.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS l 4.11.4.1 Cumulative dose contributions from liquid and gaseous eff% eats shall ' be determined in accordance with Specifications 4.11.1.2, 4.11.2.2, and 4.11.2.3, and in accordance with the methodology and parameters in the ODCM. 4.11.4.2 Cumulative dose contributions from direct radiation from the units including outside storage tanks, etc. shall be determined in accordance with the methodology and parameters in the ODCM. This requirement is applicable only under conditions set forth in Specification 3.11.4, ACTION a. HOPE CREEK 3/4 11-20

n 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING

   /             \

V 3/4.12.1 MONITORING PROGRAM LIMITING CONDITION FOR OPERATION 3.12.1 The radiological environmental monitoring program shall be conducted as specified in Table 3.12.1-1. APPLICABILITY: At all times. ACTION:

a. With the radiological environmental monitoring program not being conducted as specified in Table 3.12.1-1, prepare and submit to the Commission, in the Annual Radiological Environmental Operating Report required by Specification 6.9.1.7, a description of the reasons for not conducting the program as required and the plans for preventing a recurrence,

b. With the level of radioactivity as the result of plant effluents in an environmental sampling medium at a specified location exceeding the reporting levels of Table 3.17.1-2 when averaged over any calendar quarter, prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special Report that identifies the cause(s)

                 )             for exceeding the limit (s) and defines the corrective actions to be U                           taken to reduce radioactive effluents so that the potential annual dose

to A MEMBER OF THE PUBLIC is less than the calendar year limits of Specifications 3.11.1.2, 3.11.2.2, and 3.11.2.3. When more than one of the radionuclides in Table 3.12.1-2 are detected in the sampling medium, this report shall be submitted if:

concentration (1) , concentration (2) + ***> 1.0 reporting level (1) reporting level (2) l When radionuclides other than those in Table 3.12-2 are detected and l l are the result of plant effluer:ts, this report shall be submitted if the potential annual dose

to A MEMBER OF THE PUBLIC from all radio-nuclides is equal to or greater than the calendar year limits of Specifications 3.11.1.2, 3.11.2.2, and 3.11.2.3. This report is not required if the measured level of radioactivity was not the result of plant effluents; however, in such an event, the condition shall be reported and described in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6.

c. With milk or fresh leafy vegetable samples unavailable from one or more of the sample locations required by Table 3.12.1-1, identify specific locations for obtaining replacement samples and add them to the radiological environmental monitoring program within 30 days.

1 I l % *The methodology used to estimate the potential annual dose to a MEMBER OF THE PUBLIC shall be indicated in this report. HOPE CREEK 3/4 12-1

RADIOLOGICAL ENVIRONMENTAL MONITORING LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) The specific locations from which samples were unavailable may then be deleted from the monitoring program. Pursuant to Specifica-tion 6.9.1.8, identify the cause of the unavailability of samples and identify the new location (s) for obtaining replacement samples in the next Semiannual Radioactive Effluent Release Report pursuant to Speci-fication 6.9.1.8 and also include in the report a revised figure (s) and table for the ODCM reflecting the new location (s).

d. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.12.1 The radiological environmental monitoring samples shall be collected pursuant to Table 3.12.1-1 from the specific locations given in the table and figure (s) in the ODCM, and shall be analyzed pursuant to the requirements of Table 3.12.1-1 and the detection capabilities required by Table 4.12.1-1. O iw O HOPE CREEK 3/4 12-2

  ~ ._- ,_        _

C C O s TABLE 3.12.1-1 l 5 , A RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM

i E m

i E Number of Representative Exposure Pathway Samples and Sampling and Type and Frequency ! gy) 1 and/or Sample Sample Locations Collection Frequency of Analysis

1. DIRECT RADIATION (2) Forty-three routine monitoring Quarterly Gamma dose quarterly.

' stations either with two or j more dosimeters placed as i follows: I { An inner ring of stations, one i in each meteorological sector in the general area of the SITE BOUNDARY; R

An outer ring of stations, one l 0 in each land based meteorological i a sector in the 6- to 8-km range from j

the site; and ! The balance of the stations to be placed in special interest areas such as popula-tion centers, nearby residences, schools, and in one or two areas to serve as control stations.

                  *The number, media, frequency, and location of samples may vary from site to site. This table presents an acceptable minimum program for a site at which each entry is applicable. Local site characteristics must be examined to determine if pathways not covered by this table may significantly contribute to an j
;                      individual's dose and should be included in the sample program.

i 1 l - _ _ _ _ - _ - _ _

TABLE 3.12.1-1 (Crntinued) 5 g RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM E E

Number of Representative Exposure Pathway Samples and Sampling end Type and Frequency and/or Sample Sample locations (y) Collection Frequency of Analysis

2. AIRBORNE Radioiodine and Samples from 5 locations. Continuous sampler Radiciodine Cannister:

Particulates operation with sample I-131 analysis weekly. collection weekly, or Three samples from close to the SITE BOUNDARY locations, in more frequently if different sectors, of a high required by dust Particulate Sampler: l calculated annual average ground- loading. Gross beta radioactivity level D/Q. analysisfollogg filter change; One sample from the vicinity of a Gama isotopic analysis (4)

   $                                    community having a high calculated                           of composite (by y

y annual average groundlevel D/Q. location) quarterly, a One sample from a control location, as for example 15-30 km distant and in the least prevalent wind direction.

3. WATERBORNE

a. Surface (5) One sample upstream. Grab sample monthly. Gamma isotopic analysis (4)

One sample downstream. monthly. Composite for One sample crosstream, tritium analysis quarterly.

b. Ground Samples from one or two sources Monthly Gamma isotopic (4) and tritium only if likely to be affected(7) . analysis monthly.

O O O

A

TABLE 3.12.1-1 (Continued)

RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM e N Number of Representative , Exposure Pathway Samples and gy) Sampling 7nd Type and Frequency and/or Sample Sample Locations Collectior, aequency of Analysis

c. Drinking One sample of each of one to Composite sample I-131 analysis on each l three the nearest water sup- over 2-week period (6) composite when the dose i

plies that could be affected when I-131 analysis calculated for the consump- ! by its discharge. is performed, monthly tion of the water is g ater j composite otherwise than 1 mrem per year. Com-r One sample from a control positeforgrossbetaag) l location. gamma isotopic analyses j monthly. Composite for

tritium analysis quarterly.

! R

d. Sediment One sample from downstream area Semiannually Gamma isotopic analysis I4)

I One sample from upstream area semiannually. l y One sample from cross stream area i w

4. INGESTION

a. Milk Samples from milking animals in Sem! monthly when Gamma isotopic monthly (4) and three locations within 5 km animals are on I-131 analysis semimonthly distance having the highest dose pasture, monthly at when animals are on pasture; j potential. If there are none, other times monthly at other times.

then, I sample from milking animals in each of three areas between 5 to 8 km distant where doses are calculatef8) be greater than 1 mrem per yr. One sample from milking animals at a control location 15-30 km ! distant. 4 1 1

TABLE 3.12.1-1 (Continued) RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM e N Number of Representative Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample Sample Locations (7) Collection Frequency of Analysis

4. INGESTION (Continued)

b. Fish and One sample of each commercially Sample in season, or Gamma isotopic analysis (4)

Inverte- and recreationally important semiannually if they on edible portions. brates species in vicinity of plant are not seasonal discharge area. One sample of same species in areas not influenced by plant discharge. R c. Food One sample of each principal At time of harvest (9) Gamma isotopic analysis (4)

on edible portion.

Products class of food products from any U area that is irrigated by water E. in which liquid plant wastes have been discharged. 9 O O --

1 TABLE 3.12.1-1 (Continued) TABLE NOTATIONS (1) Specific parameters of distance and direction sector from the centerline of one reactor, and additional description where pertinent, shall be pro- . vided for each and every sample location in Table 3.12.1-1 in a table and figure (s) in the 00CM. Refer to NUREG-0133, " Preparation of Radiological Effluent Technical Specifications for Nuclear Power Plants,4-October 1978, and to Radiologicri Assessment Branch Technical Position, Revision 1, November 1979. Deviations are permitted from the required sampling schedule if specimens are unobtainable due to hazardous conditions, sea-i sonal unavailability, malfunction of automatic sampling equipment and other legitimate reasons. If specimens are unobtainable due to sampling equipment malfunction, every effort shall be made to complete corrective action prior to the end of the next sampling period. All deviations from i the sampling schedule shall be documented in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. It is 1 recognized that, at times, it may not be possible or practicable to con-tinue to obtain samples of the media of choice at the most desired loca-tion or time. In these instances suitable specific alternative media and locations may be chosen for the particular pathway in question and appro-priate substitutions made within 30 days in the Radiological Environmental l Monitoring Program given in the ODCM. Pursuant to Specification 6.14, submit in the next Semiannual Radioactive Effluent Release Report documen-tation for a change in the ODCM including a revised figure (s) and table for the ODCM reflecting the new location (s) with supporting information identifying the cause of the unavailability of samples for that pathway and justifying the selection of the new location (s) for obtaining samples. (2)0ne or more instruments, such as a pressurized ion chamber, for measuring

and recording dose rate continuously may be used in place of, or in addi-tion to, integrating dosimeters. For the purposes of this table, a thermo-luminescent dosimeter (TLD) is considered to be one phosphor; two or more
phosphors in a packet are considered as two or more dosimeters. Film i badges shall not be used as dosimeters for measuring direct radiation.

The frequency of analysis or readout for TLD systems will depend upon the i characteristics of the specific system used and should be selected to obtain optimum dose information with minimal fading. 1

(3) Airborne particulate sample filters shall be analyzed for gross beta radio-activity 24 hours or more after sampling to allow for radon and thoron ,

daughter decay. If gross beta activity in air particulate samples is greater than 10 times the yearly mean of control samples, gamma isotopic analysis shall be performed on the individual samples. (4) Gamma isotopic analysis means the identification and quantification of gamma-emitting radionuclides that may be attributable to the effluents from the facility. l (5)The " upstream sample" shall be taken at a distance beyond significant

influence of the discharge. The " downstream" sample shall be taken in an l area beyond but near the mixing zone. " Upstream" samples in an estuary l must be taken far enough upstream to be Deyond the plant influence. Salt water shall be sampled only when the receiving water is utilized for

, recreational activities. HOPE CREEK 3/4 12-7

TABLE 3.12.1-1 (Continued) TABLE NOTATION (6)A composite sample is one in which the quantity (aliquot) of liquid sampled is proportional to the quantity of flowing liquid and in which the method of sampling employed results in a specimen that is representative of the liquid flow. In this program composite sample aliquots shall be collected at time intervals that are very short relative to the compositing period in order to assure obtaining a representative sample. (7) Groundwater samples shall be taken when this source is tapped for drinking or irrigation purposes in areas where the hydraulic gradient or recharge properties are suitable for contamination. (8)The dose shall be calculated for the maximum organ and age group, using the methodology and parameters in the ODCM. (9)lf harvest occurs more tha.n once a year, sampling shall be performed during each discrete harvest. If harvest occurs continuously, sampling shall be monthly. Attention shall be paid to including samples of tuberous and root food products. O O HOPE CREEK 3/4 12-8

I N I l TABLE 3.12.1-2 k m REPORTING LEVELS FOR RADI0 ACTIVITY CONCENTRATIONS IN ENVIR0000 ENTAL SAMPLES 9 REPORTING LEVELS N n Water Airborne Particulate Fish Milk Food Products Analysis (pCi/2) or Gases (pCi/ma ) (pCi/kg, wet) (pCi/1) (pCi/kg, wet) H-3 30,000 Mn-54 1,000 30,000 Fe-59 400 10,000 Co-58 1,000 30,000 l Co-60 300 10,000 l T

Zn-65 300 20,000 U

a Zr-Nb-95 400 I-131 2 0.9 3 100 Cs-134 30 10 1,000 60 1,000 Cs-137 50 20 2,000 70 2,000 Ba-La-140 200 300 4 1 1 i i I

TABLE 4.12.1-1 DETECTION CAPABILITIES FOR ENVIRONMENTAL SAMPLE ANALYSIS (1)(2) k LOWER LIMIT OF DETECTION (LLD)(3) E Water Airborne Particulate Fish Milk Food Products Sediment Analysis (pCi/1) or Gas (pCi/m3 ) (pCi/kg, wet) (pCi/1) (pCi/kg, wet) (pCi/kg, dry) gross beta 4 0.01 H-3 3000 Mn-54 15 130 Fe-59 30 260 Co-58,60 15 130 R* 260 Zn-65 30 U 4o Z r-Nb-95 15 I-131 1 0.07 1 60 Cs-134 15 0.05 130 15 60 150 Cs-137 18 0.06 150 18 80 180 . Ba-La-140 15 15 l l l i l { l O O O

TABLE 4.12.1-1 (Continued) h TABLE NOTATIONS (1)This list does not mean that cnly these nuclides are to be considered. Other peaks that are identifiable, together with those of the above nuclides, shall also be analyzed and reported in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9J.6. (2) Required detection capabilities for thermoluminescent dosimeters used for environmental measurements shall be in accordance with the recommendations of Regulatory Guide 4.13. (3)The LLD is defined, for purposes of these specifications, as the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 95% probability with only 5% probability of falsely concluding that a blank observation

,               represents a "real" signal.

For a particular measurement system, which may include radiochemical separation: 4' 8 b LLD = E - V - 2.22 - Y - exp(-Aat) n Where: LLO is the "a priori" lower limit of detection as defined above, as picocuries per unit mass or volume, sbis the standard deviation of the background counting rate or of tne counting rate of a blank sample as appropriate, as counts per minute, E is the counting efficiency, as counts per disintegration, V is the sample size in units of mass or volume, 2.22 is the number of disintegrations per minute per picocurie, ! Y it the fractional radiochemical yield, when applicable, A is the radioactive decay constant for the particular radionuclide '

                         ,sec

( 1), and At for environmental samples is the elapsed time between sample J collection, or end of the sample collection period, and time of counting (sec) Typical valves of E, V, Y, and At should be used in the calculation. !O HOPE CREEK 3/4 12-11

TABLE 4.12.1-1 (Continued) TABLE NOTATIONS It should be recognized that the LLD is defined as an a priori (before l the fact) limit representing the capability of a measurement system and l not as an a posteriori (after the fact) limit for a particular measurement. Analyses shall be performed in such a manner that the stated LLDs will be achieved under routine conditions. Occasionally background 1'luctuations, unavoidable small sample sizes, the presence of interfering nuclides, or other uncontrollable. circumstances may render these LLDs unachievable. In such cases, the contributing factors shall be identified and described in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. O O HOPE CREEK 3/4 12-12 J

i p RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.2 LAND USE CENSUS 1 l 5 l LIMITING CONDITION FOR OPERATION l l 3.12.2 A land use census shall be conducted and shall identify within a , distance of 8 km (5 miles) the location in each of the 16 meteoroTogical sectors of the nearest milk animal, the nearest residence and the nearest garden

of greater than 50 m2 (500 fts) producing broad leaf vegetation.

APPLICABILITY: At all times. ACTION:

a. With a land use census identifying a location (s) that yields a calcu-lated dose or dose commitment greater than the values currently being calculated in Specification 4.11.2.3, identify the new location (s) in the next Semiannual Radioactive Effluent Release Report, pursuant te 4

Specification 6.9.1.7.

b. With a land use census identifying a location (s) that yields a calculated dose or dose commitment (via the same exposure pathway) 20% greater than at a location from which samples are currently being obtained in accordance with Specification 3.12.1, add the

' p] s
   - \

new location (s) to the radiological environmental monitoring program within 30 days. The sampling location (s), excluding the control station location, having the lowest calculated dose or dose commitment (s), via the same exposure pathway, may be deleted from this monitoring program after October 31 of the year in which this I land use census was conducted. Pursuant to Specification 6.9.1.8, identify the new location (s) in the next Semiannual Radioactive Effluent Release Report and also include in the report a revised figure (s) and table for the ODCM reflecting the new location (s).

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS l 4.12.2 The land use census shall be conducted during the growing season at l 1 east once per 12 months using that information that will provide the best results, such as by a door-to-door survey, visual survey, aerial survey, or by consulting local agriculture authorities. The results of the land use census sha*11 be included in the Annual Radiological Environmental Operating

Report pursuant to Specification 6.9.1.6.

l

Broad leaf vegetation sampling of at least three different kinds of vegetation

, may be performed at the SITE BOUNDARY in each of two different direction sectors with the highest predicted C/Qs in lieu of the garden census. Specifications for broad leaf vegetation sanpling in Table 3.12.1-1, Part 4.c. , shall be followed, including analysis of control samples. HOPE CREEK 3/4 12-13

    -.--,-w      ---..-- -.-.---, ,            . . - - - , . . - - - - - . - - ,      . - . - - - . - - - - - - - - - - -           , - - ----   _.-,=..w-r--w"+w     =+   en---,--,-wer-----.=-   - .----w-e-    -

 .                    .. .,                     ~,       -            _            -

RADIOLOGICAL. EWIRONHENTAL MONITORING 3/4.12.3 INTERLABORATORY COMPARISCN PROGRt.M LIMITING CONDITION FOR GPERATION _

3.12.3 Analyses shall be performe(1 on radioactive materials supplied as part of an Interlaboratory Comparison Program that has been approved by t.he Coenission. APPLICABILITY: At all times. ACTION:

a. With analyses not being performed as required above, re,oort the corrective actions taken to prevent a recurrence tc the Commission in the Annual Radiological Endronncntel Operating Report pursuant to Specification 6.9.1.6.

b. The provisions of Specificatiens 3.0.3 and 3.0.4 are not applicable. .

SURVEILLANCE REQUIREMENTS , _

4.12.3 The Interlaboratory Comparison Program shall be described in the ODCH. O A summary of the results obtained as part of the above required Ints.r . laboratory Comparison Program shall be included in the Annual Radiclogical Environmental Operating Report pursuant to Specification 6.9.'t.6. I t 140PE CREEK 3/4 12-14

w - - - BASES FOR SECTIONS 3.0 AND 4.0 LIMITING CONDITIONS FOR OPERATION ' AND SURVEILLANCE REQUIREMENTS [ t ( i l l l O

   . - - _ ~ , - _ . ~ .     . ~ . - . - . - - . _ - .     . - - . _ , . . . . . - . . .        - . . . - -   .

l O i l t NOTE The Summary statements contained in this section provide the bases for the specifications in Section 3.0 and 4.0 but in accordance with 10 CFR 50.36 are not a part of these Technical Specifications. l l 1 O O f

   \d 3/4.0 APPLICABILITY BASES The specifications of this section provide the general requirements applicable to each of the Limiting Conditions for Operation and Surveillance Requirements within Section 3/4.

3.0.1 This specification states the applicability of each specification in terms of defined OPERATIONAL CONDITION or other specified applicability condition and is provided to delineate specifically when each specification is appl.icable. 3.0.2 This specification defines those conditions necessary to constitute compliance with the terms of an individual Limiting Condition for Operation and associated ACTION requirement. 3.0.3 This specification delineates the measures te be taken for circum-stances not directly provided for in the ACTION statements and whose occurrence g would violate the intent of the specification. For example, Specification 3.7.2 ( calls for two control room emergency filtration subsystems to be OPERABLE and provides explicit ACTION requirements if one subsystem is inoperable. Under the requirements of Specification 3.0.3, if both of the required subsystems are inoperable, within one hour measures must be initiated to place the unit in at least STARTUP within the next 6 hours, in at least HOT SHUTDOWN within the following 6 hours and in COLD SHUTDOWN within the subsequent 24 hours. As a further example, Specification 3.6.6.1 requires two containment hydrogen re-combiner systems to be OPERABLE and provides explicit ACTION requirements if one recombiner system is inoperable. Under the requirements of Specification 3.0.3, if both of the required systems are inoperable, within one hour measures must be initiated to place the unit in at least STARTUP within the next 6 hours and

;     in at least HOT SHUTDOWN within the following 6 hours.

i' 3.0.4 This specification provides that entry into an OPERATIONAL CONDITION must be made with (a) the full complement of required systems, equipment or components OPERABLE and (b) all other parameters as specified in the Limiting Conditions for Operation being met without regard for allowable deviations and out of ser,vice provisions contained in the ACTION statements. The intent of this provision is to ensure that unit operation is not initiated with either required equipment or systems inoperable or other limits being exceeded. I Exceptions to this provision have been provided for a limited number of specifications when startup with inoperable equipment would nat affect plant , k safety. These exceptions are stated in the ACTION statements of the appropriate specifications. HOPE CREEK 8 3/4 0-1

APPLICABILITY BASES 4.0.1 This specification provides that surveillance activities necessary to ensure the Limiting Conditions for Operation are met and will be performed - during the OPERATIONAL CONDITIONS or other conditions for which the Limiting Conditions for Operation are applicable. Provisions-for additional surveillance activitie: to be performed without regard to the applicable OPERATIONAL CONDI-TIONS or other conditions are provided in the individual Surveillance Require-ments. Surveillance Requirements for Special Test Exceptions need only be performed when the Special Test Exception is being utilized as an exception to an individual specification. 4.0.2 The provisions of this specification provide allowable tolerances for performing surveillance activities beyond those specified in the nominal surveillance interval. These tolerances are necessary to provide operational , flexibility because of scheduling and performance considerations. The phrase "at least" associated with a surveillance frequency does not negate this allowable tolerance; instead, it permits the more frequent performance of sur-veillance activities. The tolerance values, taken either individua11.y or consecutively over 3 test intervals, are sufficiently restrictive to ensure that the reliability associated with the surveillance activity is not significantly degraded beyond that obtained from the nominal specified interval. 4.0.3 The provisions of this specification set forth the criteria for determination of compliance with the OPERABILITY requirements of the Limiting Conditions for Operation. Under this criteria, equipment, systems or components are assumed to be OPERABLE if the associated surveillance activities have been I satisfactorily performed within the specified time interval. Nothing in this provision is to be construed as defining equipment, systems or components OPERABLE, when such items are found or known to be inoperable although still meeting the Surveillance Requirements. { O HOPE CREEK B 3/4 0-2

V APPLICABILITY BASES 4.0.4 This specification ensures that surveillance activities associated with a Limiting Conditions for Operation have been performed within the specified time interval prior to entry into an applicable OPERATIONAL CONDITION or other specified applicability condition. The intent of this provision is to ensure that surveillance activities have been satisfactorily demonstrated on a current basis as required to meet the OPERABILITY requirements of the Limiting Condition for Operation. Under the terms of this specification, for example, during initial plant startup or following extended plant outage, the applicable surveillance activ-ities must be performed within the stated surveillance interval prior to placing or returning the system or equipment into OPERABLE status. 4.0.5 This specification ensures that inservice inspection of ASME Code Class 1, 2 and 3 components and inservice testing of ASME Code Class 1, 2 and 3 pumps and valves will be performed in accordance with a periodically updated version of Section XI of the ASME Boiler and Pressure Vessel Code and Addenda

 ,    as required by 10 CFR 50, Section 50.55a. Relief from any of the above require-ments has been provided in writing by the Commission and is not a part of these Technical Specifications.

This specification includes a clarification of the frequencies of perform-ing the inservice inspection and testing activities required by Section XI of , the ASME Boiler and Pressure Vessel Code and applicable Addenda. This clarifi- I cation is provided to ensure consistency in surveillance intervals throughout these Technical Specifications and to remove any ambiguities relative to the frequencies for performing the required inservice inspection and testing activ-ities. Under the terms of this specification, the more restrictive requirements of the Technical Specifications take precedence over the ASME Boiler and Pressure Vessel Code and applicable Addenda. For example, the requirements of Specifi-cation 4.0.4 to perform surveillance activities prior to entry into an OPERATIONAL CONDITION or other specified applicability condition takes precedence over the ASME Boiler and Pressure Vessel Code provision which allows pumps to be tested up to one week after return to normal operation. And for example, the Technical Specification definition of OPERABLE does not grant a grace period before a device that is not capable of performing its specified function is declared inoperable *and takes precedence over the ASME Boiler and Pressure Vessel provi-sion which allows a valve to be incapable of performing its specified function . for up to 24 hours before being declared inoperable. l l HOPE CREEK B 3/4 0-3

3/4.1 REACTIVITY CONTROL SYSTEMS I BASES I 3/4.1.1 SHUTDOWN MARGIN A sufficient SHUTDOWN MARGIN ensures that 1) the reactor can be made subcritical from all operating conditions, 2) the reactivity transients associated with postulated accident conditions are controllable within acceptable limits, and 3) the reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition. Since core reactivity values will vary through core life as a function of fuel depletion and poison burnup, the demonstration of SHUTDOWN MARGIN will be performed in the cold, xenon-free condition and shall show the core to be subcritical by at least R + 0.38% delta k/k or R + 0.28% delta k/k, as appro-priate. The value of R in units of % delta k/k is the difference between the calculated value of maximum core reactivity during the operating cycle and the calculated beginning-of-life core reactivity. The value of R must be positive cr zero and must be determined for each fuel loading cycle. Two different values are supplied in the Limiting Condition for Operation to provide for the different methods of demonstration of the SHUTDOWN MARGIN. The highest worth rod may be determined analytically or by test. The SHUTDOWN MARGIN is demonstrated by an insequence control rod withdrawal at the beginning of life fuel cycle conditions, and, if necessary, at any future time in the cycle if the first demonstration indicates that the required margin could be reduced as a function of exposure. Observation of subcriticality in this con-dition assures subcriticality with the most res:tive control rod fully withdrawn. This reactivity characteristic has been a basic assumption in the analysis of plant performance and can be best demonstrated at the time of fuel loading, but the margin must also be determined anytime a control rod is incapable of insertion. 3/4.1.2 REACTIVITY ANOMALIES Since the SHUTDOWN MARGIN requirement for the reactor is small, a careful check on actual conditions to the predicted conditions is necessary, and the changes in reactivity can be inferred from these comparisons of rod patterns. Since the , comparisons are easily done, frequent checks are not an imposition on normal operations. A 1% delta k/k change is larger than is expected for normal operation so a change of this magnitude should be thoroughly evaluated. A change as large as 1% delta k/k would not exceed the design conditions of the reactor and is on the safe side of the postulated transients. ' HOPE CREEK B 3/4 1-1

REACTIVITY CONTROL SYSTEMS BASES 3/4.1.3 CONTROL RODS The specifications of this section ensure that (1) the minimum SHUTDOWN MARGIN is maintained, (2) the control rod insertion times are consistent with those used in the accident analysis, and (3) limit the potential effects of the rod drop accident. The ACTION statements permit variations from the basic requirements but at the same time impose more restrictive criteria for continued operation. A limitation on inoperable rods is set such that the resultant effect on total rod worth and scram shape will be kept to a minimum. The requirements for the various scram time measurements ensure that any indication of systematic problems with rod drives will be investigated on a timely basis. Damage within the control rod drive mechanism could be a generic problem, therefore with a withdrawn control rod immovable because of excessive friction or mechanical interference, operation of the reactor is limited to a time period which is reasonable to determine the cause of the inoperability and at the same time prevent operation with a large number of inoperable control rods. Control rods that are inoperable for other reasons are permitted to be taken out of service provided that those in the nonfully-inserted position are consistent with the SHUTDOWN MARGIN requirements. The number of control rods permitted to be inoperable could be more than I the eight allowed by the specification, but the occurrence of eight inoperable rods could be indicative of a generic problem and the reactor must be shutdown for investigation and resolution of the problem. The control rod system is designed to bring the reactor subcritical at a rate fast enough to prevent the MCPR from becoming less than 1.06 during the l limiting power transient analyzed in Section 15.4 of the FSAR. This analysis shows that the negative reactivity rates resulting from the scram with the average response of all the drives as given in the specifications, provide the required protection and MCPR remains greater than 1.06. The occurrence of scram times longer then those specified should be viewed as an indication of a systematic problem with the rod drives and therefore the surveillance interval is reduced in order to prevent operation of the reactor for long periods of time with a potentially serious problem. The scram discharge volume is required to be OPERABLE so that it will be available when needed to accept discharge water from the centrol rods during a

reactor scram and will isolate the reactor coolant system from the containment when required. Control rods with inoperable accumulators are declared inoperable and Specification 3.1.3.1 then applies. This prevents a pattern of inoperable accumulators that would result in less reactivity insertion on a scram than has been analyzed even though control rods with inoperable accumulators may still be inserted with normal drive water pressure. Operability of the accumulator ensures that there is a means available to insert the control rods even under the most unfavorable depressurization of the reactor. HOPE CREEK B 3/4 1-2

REACTIVITY CONTROL SYSTEMS BASES CONTROL RODS (Continued) Control rod coupling integrity is required to ensure compliance with the analysis of the rod drop accident in the FSAR. The overtravel position feature provides the only positive means of determining that a rod is properly coupled and therefore this check must be performed prior to achieving criticality after completing CORE ALTERATIONS that could have affected the control rod coupling integrity. The subsequent check is performed as a backup to the initial demon-stration. In order to ensure that the control rod patterns can be followed and there-fore that other parameters are within their limits, the control rod position indication system must be OPERABLE. The control rod housing support restricts the outward movement of a control rod to less than 6 inches in the event of a housing failure. The amount of rod reactivity which could be added by this small amount of rod withdrawal is less than a normal withdrawal increment and will not contribute to any damage to the primary coolant system. The support is not required when there is no pressure to act as a driving force to rapidly eject a drive housing. The required surveillance intervals are adequate to determine that the rods are OPERABLE and not so frequent as to cause excessive wear on the system components. 3/4.1.4 CONTROL R0D PROGRAM CONTROLS Control rod withdrawal and insertion sequences are established to assure that the maximum insequence individual control rod or control rod segments which are withdrawn at any time during the fuel cycle could not be worth enough to result in a peak fuel enthalpy greater than 280 cal /gm in the event of a control rod drop accident. The specified sequences are characterized by homogeneous, scattered patterns of control rod withdrawal. When THERMAL POWER is greater than 20% of RATED THERMAL POWER, there is no possible rod worth which, if dropped at the design rate of the velocity limiter, could result in a peak enthalpy of 280 cal /gm. Thus requiring the RSCS and/or RWM to be OPERABLE when THERMAL POWER is less than or equal to 20% of RATED THERMAL POWER provides adequate control. The RSCS and RWM provide automatic supervision to assure that out-of-sequence r,ods will not be withdrawn or inserted. The analysis of the rod drop accident is presented in Section 15.4.9 of the FSAR and the techniques of the analysis are presented in a topical report, Reference 1, and two supplements, References 2 and 3. The RBM is designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density during high power operation. Two channels are provided. Tripping one of the channels will block erroneous rod withdrawal soon enough to prevent fuel damage. This system backs up the written sequence used by the operator for withdrawal of control rods. HOPE CREEK B 3/4 1-3 U-~

REACTIVITY CONTROL SYSTEMS BASES 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM The standby liquid control system provides a backup capability for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern. To meet this objective it is necessary to inject a quantity of boron which produces a concen-tration of 660 ppm in the reactor core and other piping systems connected to the reactor vessel. To allow for potential leakage and imperfect mixing, this con-centration is increased by 25L The required concentration is achieved by having a minimum available quantity of 4850 gallons of sodium pentaborate solution containing a minimum of 5760 lbs of sodium pentaborate. This quantity of solution is a net amount which is above the pump suction, thus allowing for the portion which cannot be injected. The pumping rate of 41.2 gpm per pump provides a negative reactivity insertion rate over the permissible pentaborate

 > solution volume range, which adequately compensates for the positive reactivity effects due to temperature and Xenon during shutdown. The temperature require-ment is necessary to ensure that the sodium pentaborate remains in solution.

With redundant pumps and explosive injection valves and with a highly reliable control rod scram system, operation of the reactor is permitted to continue for short periods of time with the system inoperable or for longer periods of time with one of the redundant components inoperable. Surveillance requirements are established on a frequency that assures a high reliability of the system. Once the solution is established, boron con-centration will not vary unless more boron or water is added, thus a check on the temperature and volume once each 24 hours assures that the solution is available for use. Replacement of the explosive charges in the valves at regular intervals will assure that.these valves will not fail because of deterioration of the charges.

1. C. J. Paone, R. C. Stirn and J. A. Woolley, " Rod Drop Accident Analysis for Large BWR's", G. E. Topical Report NED0-10527, March 1972 l 2. C J. Paone, R. C. Stirn and R. M. Young, Supplement 1 to NED0-10527, July 1972

3. J. M., Haun, C. J. Paone and R. C. Stirn, Addendum 2, " Exposed Cores",

Supplement 2 to NE00-10527, January 1973 O HOPE CREEK B 3/4 1-4

_ 3/4.2 POWER DISTRIBUTION LIMITS BASES The specifications of this section assure that the peak cladding temperature following the postulated design basis loss-of-coolant _ accident will not exceed the 2200 F limit specified in 10 CFR 50.46. 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE The peak cladding temperature (PCT) following a postulated loss-of-coolant accident is primarily a function of the average heat generation rate of all the rods of a fuel assembly at sny axial location and is dependent only secondarily on the rod to rod power distribution within an assembly. The peak clad temperature is calculated assuming e i.HGR for the highest powered rod which is equal to or less than the design LHGR corrected for densification. This LHGR times 1.02 is used in the neatup code along with the exposure dependent steady state gap conductance and rod-to rod local peaking factor. The Technical Specification AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) is this LHGR of the highest powered rod divided by its local peaking factor. The limiting value for APLHGR is shown in Figures 3.2.1-1, 3.2.1-2, 3.2.1-3, 3.2.1-4 and 3.2.1-5. l The calculational procedure used to establish the APLHGR shown on Figures N 3.2.1-1, 3.2.1-2, 3.2.1-3, 3.2.1-4 and 3.2.1-5 is based on a loss-of-coolant accident analysis. The analysis was performed using General Electric (GE) cal-culational models which are consistent with the requirements of Appendix K to 10 CFR 50. A complete discussion of each code employed in the analysis is pre-sented in Reference 1. Differences in this analysis compared to previous analyses can be broken down as follows.

a. Input Changes

1. Corrected Vaporization Calculation - Coefficients in the vaporization correlation used in the REFLOOD code were corrected.

2. Incorporated.more accurate bypass areas - The bypass areas in the top guide were recalculated using a more accurate technique.

3. Corrected guide tube thermal resistance.

4. Corrected heat capacity of reactor internals heat nodes.

O HOPE CREEK B 3/4 2-1

v POWER DISTRIBUTION LIMITS BASES AVERAGE PLANAR LINEAR HEAT GENERATION RATE (Continued)

b. Model Change

1. Core CCFL pressure differential - 1 psi - Incorporate the assumption that flow from the bypass to lower plenum must overcome a 1 psi pressure drop in core.

2. Incoporate NRC pressure transfer assumption - The assumption used in the SAFE-REFLOOD pressure transfer when the pressure is increasing was changed.

A few of the changes affect the accident calculation irrespective of CCFL. These changes are listed below.

a. Input Change

1. Break Areas - The DBA break area was calculated more accurately.

b. Model Change

1. Improved Radiation and Conduction Calculation - Incorporation of CHASTE 05 for heatup calculation.

A list of the significant plant input parameters to the loss-of-coolant accident analysis is presented in Bases Table B 3.2.1-1. 3/4.2.2 APRM SETPOINTS The fuel cladding integrity Safety Limits of Specification 2.1 were based on a power distribution which would yield the design LHGR at RATED THERMAL POWER. The flow biased simulated thernal power-upscale scram setting and the flow biased neutron flux-upscale control rod block trip setpoints must be adjusted to ensure that the MCPR does not become less than 1.06 or that > 1% plastic strain does not occur in the degraded situation. The scram setpoints and rod block setpoints are adjusted in accordance with the formula in Specifi-cation 3.2'.2 whenever it is known that the existing power distribution would cause the design LHGR to be exceeded at RATED THERMAL POWER. O HOPE CREEK B 3/4 2-2

Bases Table B 3.2.1-1 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS Plant Parameters: Core THERMAL POWER .................... 3430 Mwt* which corresponds to 105% of rated steam flow Vessel Steam Output ................... 14.87 x 106 lbm/hr which corresponds to 105% of rated steam flow Vessel Steam Dome Pressure............. 1055 psia Design Basis Recirculation Line Break Area for:

a. Large Breaks 4.1 ft2

b. Small Breaks 0.09 ft 2, Fuel Parameters:

PEAK TECHNICAL INITIAL SPECIFICATION DESIGN MINIMUM LINEAR HEAT AXIAL CRITICAL FUEL BUNDLE GENERATION RATE PEAKING POWER FUEL TYPE GE0 METRY (kw/ft) FACTOR RATIO Initial Core 8x8 13.4 1.4 1.20 A more detailed listing of input of each model and its source is presented in Section II of Reference 1 and subsection 6.3.3 of the FSAR.

   *This power level meets the Appendix K requirement of 102%. The core heatup calculation assumes a bundle power consistent with operation of the highest powered rod at 102% of its Technical Specification LINEAR HEAT GENERATION RATE limit.

J l HOPE CREEK B 3/4 2-3

t POWER DISTRIBUTION LIMITS BASES 3/4.2.3 MINIMUM CRITICAL POWER RATIO The required operating limit MCPRs at steady state operating _ conditions as specified in Specification 3.2.3 are derived from the established fuel cladding integrity Safety Limit MCPR of 1.06, and an analysis of abnormal operational transients. For any abnormal operating transient analysis evalua-tion with the initial condition of the reactor being at the steady state operating limit, it is required that the resulting MCPR does not decrease below the Safety Limit MCPR at any time during the transient assuming instrument trip setting given in Specification 2.2. To assure that the fuel cladding integrity Safety Limit is not exceeded during any anticipated abnormal operational transient, the most limiting tran-sients have been analyzed to determine which result in the largest re.1uction in CRITICAL POWER RATIO (CPR). The type of transients evalrated were loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest delta MCPR. When added to the Safety Limit MCPR of 1.06, the required minimum operating limit MCPR of Specification 3.2.3 is obtained. The evaluation of a given transient begins with the system initial parameters shown in FSAR Table 15.0-3 that are input to a GE-core dynamic behavior transient computer progr g The code used to evaluate pressurization events is described in NE00-24154(2) and the program used in non pressurization events is described in NED0-10802 . The outputs of this program along with the initial MCPR form the input for further analyses of the thermally limiting bundle with tgsingle channel transient thermal hydraulic TASC code described in NEDE-25149 The principal result of this evaluation is the reduction in MCPR caused by the transient. The purpose of the K, factor of Figure 3.2.3-2 is to define operating limits at other than rated core flow conditions. At less than 100% of rated factor. The K flowtherequiredMCPRistheproductoftheMCPRandtheK[edduringaflow factors assure that the Safety Limit MCPR will not be viola increase transient resulting from a motor generator speed control failure. The K factors may be applied to both manual and automatic flow control modes. 7 The Kf factors values shown in Figure 3.2.3-2 were developed generically and are applicable to all BWR/2, BWR/3 and BWR/4 reactors. The Kf factors were derived using the flow control line corresponding to RATED THERMAL POWER at rated core. flow. For the manual flow control mode, the K7 factors were calculated such that for the maximum flow rate, as limited by the pump scoop tube set point and the corresponding THERMAL POWER along the rated flow control line, the limiting bundle's relative power was adjusted until the MCPR changes with different core flows. The ratio of the MCPR calculated at a given point of core flow, divided by the operating limit MCPR, determines the Kf . HOPE CREEK B 3/4 2-4

POWER DISTRIBUTION LIMITS BASES MINIMUM CRITICAL POWER RATIO (Continued) For operation in the automatic flow control mode, the same procedure was employed except the initial power distribution was established such that the MCPR was equal to the operating limit MCPR at RATED THERMAL POWER and rated thermal flow. The K factors shown in Figure 3.2.3-2 are conservative for the General ElectricpfantoperationbecausetheoperatinglimitMCPRsofSpecification 3.2.3 is the same as the original 1.20 operating limit MCPR used for the generic derivation of K . f At THERMAL POWER levels less than or equal to 25% of RATED THERMAL POWER, the reactor will be operating at minimum recirculation pump speed and the moderator void content will be very small. For all designated control rod patterns which may be employed at this point, operating plant experience indi-cates that the resulting MCPR value is in excess of requirements by a considerable margin. During initial start up testing of the plant, a MCPR evaluation vill be made at 25% of RATED THERMAL POWER level with minimum recirculation pump speed. The MCPR margin will thus be demonstrated such that future MCPR evaluation below this power level will be shown to be unnecessary. The daily requirement for calculating MCPR when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER is sufficient since power distribution shifts are very slow when there have not been significant power or control rod changes. The require-ment for calculating MCPR when a limiting control rod pattern is approached ensures that MCPR will be known following a change in THERMAL POWER or power shape, regardless of magnitude, that could place operation at a thermal limit. 3/4.2.4 LINEAR HEAT GENERATION RATE This specification assures that the Linear Heat Generation Rate (LHGR) in any rod is less than the design linear heat generation even if fuel pellet densification is postulated.

References:

1. General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CFR 50, Appendix K, NEDE-20566, November 1975.

2. R. B. Linford, Analytical Methods of Plant Transient Evaluations for the GE BWR, NED0-10802, February 1973.

3. -Qualification of the One Dimensional Core Transient Model for Boiling Water Reactors, NED0-24154, October 1978.

4. TASC 01-A Computer Program for the Transient Analysis of a Single Channel, Technical Description, NEDE-25149, January 1980.

HOPE CREEK B 3/4 2-5

9 3/4.3 INSTRUMENTATION BASES E4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION The reactor protection system automatically initiates a reactor scram to:

a. Preserve the integrity of the fuel cladding.

b. Preserve the integrity of the reactor coolant system.

c. Minimize the energy which must be adsorbed following a loss-of-coolant accident, and

d. Prevent inadvertent criticality.

This specification provides the limiting conditions for operation necessary to preserve the ability of the system to perform its intended function even during periods when instrument channels may be out of service because of main-tenance. When necessary, one channel may be made inoperable for brief intervals to conduct required surveillance. j The reactor protection system is made up of two independent trip systems. 'd There are usually four channels to monitor each parameter with two channels in each trip system. The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems will produce a reactor scram. The system meets the intent of IEEE-279 for nuclear power plant protection systems. The bases for the trip settings of the RPS are discussed in the bases for Specification 2.2.1. The measurement of response time at the speci,fied frequencies provides assurance that the protective functions associated with each channel are com-pleted within the time limit assumed in the safety analyses. No credit was taken for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping or total channel test measurement, provided such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or (2) utilizing replacement sensors with certified response times. HOPE CREEK B 3/4 3-1

INSTRUMENTATION BASES 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip setpoints and response times for isolation of the reactor systems. When necessary, one channel may be inoperable for brief intervals to conduct required surveillance. Some of the trip settings may have tolerances explicitly stated where both the high and low values are critical and may have a substantial effect on safety. The set-points of other instrumentation, where only the high or low end of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved. Except for the MSIVs, the safety analysis does not address individual sensor response times or the response times of the logic systems to which the sensors are connected. For D.C. operated valves, a 3 second delay is assumed before the valve starts to move. For A.C. operated valves, it is assumed that the A.C. power supply is lost and is restored by startup of the emergency diesel generators. In this event, a time of 13 seconds is assumed before the valve ! starts to move. In addition to the pipe break, the failure of the D.C. operated i valve is assumed; thus the signal delay (sensor response) is concurrent with ! the 10 second diesel startup. The safety analysis considers an allowable inventory loss in each case which in turn determines the valve speed in conjunc-tion with the 13 second delay. It follows that checking the valve speeds and the 13 second time for emergency power establishment will establish the response time for the isolation functions. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses. 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION The emergency core cooling system actuation instrumentation is provided to initiate actions to mitigate the consequences of accidents that are beyond the ability of the operator to control. This specification provides the OPERABILITY requirements, trip setpoints and response times that will ensure effectiveness of the systems to provide the design protection. Although the instruments are listed by system, in some cases the same instrument may be used to send the actuation signal to more than one system at the same time. l Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between eact! Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses. HOPE CREEK B 3/4 3-2

( V INSTRUMENTATION BASES 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system provides a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NED0-10349, dated March 1971, NEDO-24222, dated December 1979, and Section 15.8 of the FSAR. The end-of-cycle recirculation pump trip (EOC-RPT) system is an essential safety supplement to the reactor trip. The purpose of the E0C-RPT is to recover the loss of thermal margin which occurs at the end-of-cycle. The physical phe-nomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity to the reactor system at a faster rate than the control rods add negative scram reactivity. Each E0C-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void col-lapse in the core during two of the most limiting pressurization events. The two events for which the EOC-RPT protective feature will function are closure of the turbine stop valves and fast closure of the turbine control valves. s A fast closure sensor from each of two turbine control valves provides input to the E0C-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the second E0C-RPT system. Similarly, a position switch for each of two turbine stop valves provides input to one E0C-RPT system; a position switch frc:a each of the other two stop valves provides input to the other E0C-RPT system. For each EOC-RPT system, the sensor relay contacts are arranged to form a 2-out-of-2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the E0C-RPT system and trip both recirculation pumps. Each EOC-RPT system may be manually bypassed by use of a keyswitch which is administrative 1y controlled. The manual bypasses and the automatic Operating Bypass at less than 30% of RATED THERMAL POWER are annunciated in the control room. ! l The E0C-RPT system response time is the time assumed in the analysis j between initiation of valve motion and complete suppression of the electric l arc, i.e. ,175 ms. Included in this time are: the response time of the sensor, I the time allotted for breaker arc suppression (135 ms @ 100% RTP), and the response time of the system logic.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the n difference between each Trip Setpoint and the Allowable Value is an allowance

( for instrument drift specifically allocated for each trip in the safety analyses. HOPE CREEK B 3/4 3-3

INSTRUMENTATION BASES 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION The reactor core isolation cooling system actuation instrumentation is provided to initiate actions to assure adequate core cooling in the event of reactor isoletion from its primary heat sink and the loss of feedwater flow to the reactor vossel. Operaticn with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses. 3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION The control rod block functions are provided consistent with the requirements of the specifications in Section 3/4.1.4, Control Rod Program Controls and Section 3/4.2 Power Distribution Limits and Section 3/4.3 Instru-mentation. The trip logic is arranged so that a trip in any one of the inputs will result in a control rod block. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses. 3/4.3.7 MONITORING INSTRUMENTATION 3/4.3.7.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring instrumentation ensures that; (1) the radiation levels are continually measured in the areas served by the individual channels, and (2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded; and (3) sufficient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with 10 CFR Part 50, Appendix A, General Design Criteria 19, 41, 60, 61, 63 and 64. 3.4.3.7.2 SEISMIC MONITORING INSTRUMENTATION The OPERABILITY of the seismic monitoring instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event and evaluate the response of those features impartant to safety. This capability is required to permit comparison of the measured response to that used in the design basis for the unit. This instrumentation is consistent with the rpcommendations of Regulatory Guide 1.12 " Instrumentation for Earthquakes," April 1974 3/4.3.7.3 METEOROLOGICAL MONITORING INSTRUMENTATION The OPERABILITY of the meteorological monitoring instronentation ensures that sufficient meteorological data is available for estimating potential radia-tion doses to the public as a result of routine or accidental release of 9 HOPE CREEK a3 3-4

INSTRUMENTATION BASES MONITORING INSTRUMENTATION (Continued) radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public. This instrumentation is consistent with the recommenda-tions of Regulatory Guide 1.23 "Onsite Meteorological Programs," February, 1972. 3/4.3.7.4 REMOTE SHUTDOWN MONITORING INSTRUMENTATION AND CONTROLS The OPERABILITY of the remote shutdown monitoring instrumentation and con-trols ensures that sufficient capability is available to permit shutdown and maintenance of HOT SHUTDOWN of the unit from locations outside of the control

, room. This capability is required in the event control room habitability is lost and is consistent with General Design Criteria 19 of 10 CFR 50.

3/4.3.7.5 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess important variables following an accident. This capability is consistent with the recommendations of Regulatory Guide 1.97, " Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," December 1980 and NUREG-0737, " Clarification of TMI Action Plan Requirements," November 1980. 3/4.3.7.6 SOURCE RANGE MONITORS The source range monitors provide the operator with information of the status of the neutron level in the core at very low power levels during startup and shutdown. At these power levels, reactivity additions shall not be made without this flux level information available to the operator. When the inter-mediate range monitors are on scale, adequate information is available without the SRMs and they can be retracted. 3/4.3.7.7 TRAVERSING IN-CORE PROBE SYSTEM The OPERABILITY of the traversing in-core probe system with. the specified minimum complement of equipment ensures that the measurements obtained from use of this equipment accurately represent the spatial neutron flux distribution of the reactor core. HOPE CREEK B 3/4 3-5

INSTRUMENTATION BASES MONITORING INSTRUMENTATION (Continued) 3/4.3.7.8 LOOSE-PART DETECTION SYSTEM The OPERABILITY of the loose part detection system ensures that sufficient capability is available to detect loose metallic parts in the primary system and avoid or mitigate damage to primary system components. The allowable out-of-service times and surveillance requirements are consistent with the recom-mendations of Regulatory Guide 1.133, " Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors," May 1981. 3/4.3.7.9 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION The radioactive liquid effluent monitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in liquid effluents during actual or potential releases of liquid effluents. The alarm / trip setpoints for these instruments shall be calculated and adjusted in accordance with the methodology and parameters in the ODCM to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20. The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. 3/4.3.7.10 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION The radioactive gaseous effluent monitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases of gaseous effluents. The alarm / trip setp:ints for these instruments shall be calculated and adjusted in accordance with the methodology and parameters in the ODCM. This will ensure the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20. This instrumentation also includes provisions for monitoring and controlling the concentrations of potentially explosive gas mixtures in the main condenser offgas treatment system. The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. l l 1 O l HOPE CREEK B 3/4 3-6

Q INSTRUMENTATION BASES l 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM This specification is provided to ensure that the turbine overspeed protection system instrumentation and the turbine speed control valves are OPERABLE and will protect the turbine from excessive overspeed. Protection from turbine excessive overspeed is required since excessive overspeed of the turbine could generate potentially damaging missiles which could impact and damage safety related components, equipment or structures. 3/4.3.9 FEE 0 WATER / MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION The feedwater/ main turbine trip system actuation instrumentation is pro-vided to initiate action of the feedwater system / main turbine trip system in the event of a high reactor vessel water level (Level 8) to mitigate potential damage to the main turbine. O O HOPE CREEK B 3/4 3-7

esOTE SCAT = =CNES Amove vEssaL zERO WATER LEVEL NOMENCLATURE MEiOHT AaOVE soo- - vEsset zERo seO. th.I SEADING (8) 581.5 +54 750- - () i 566.5 557.5

                                                                                                                  +39
                                                                                                                  +30 7*8   ""~ VESSEL
             .                                       FLANGE 7                      d )I         540.0             +12.5 700- -                                               (2)          489.5             -38 (1)          398.5             -129 850 - -

4 58. 5 MAIN STEAM \ TINE ,/

                              .Oo _ _
                                      -tal 581.5                 +6 b -                            "-
                                      -871 566 S                        '(83 + E I

E -tel 5515 171 +39 te ALARM

                                                                          #C3C '

Bottom of " ~ -13:540 W tel +30 LO ALARM Separator (31 +12. 5 REACTOR SCRAM

                                      - M7. Amsi ZERO                     M                        --

Skirt g4 - ~ PEED 4es.5 -121 489.5 WATER - 821 - 3 8 ellTIATE RCIC &

                                      -484. 5 -             y I N REClRO

, ,3 a i 416.38" 400 -= 11393.5 -(1312 9 sesTIATE RNR. CS, START DIESEL.

                                      > 3,77j 5                  .15 0<  ~            CONTRISUTE TO C                        ~

ib A.D.S., AND CLOSE 350- - MStV S pdf L 300 - - WIDE RANCE LEVEL FU L This indication is reactor

coolant temperature sensitive. I'U ~ The calibration is thus made at rated conditions. The

   "                                    ~  218.3          "

< 200 - - level error at low pressures _ , , , __ RECiRC (temperatures) is bounded by RECIRC - INLET

the safety analysis which ET+ 161. NOZZLE reflects the weight-of-coolant

            ]                                                                 above the lower tap, and not 100 f            indicated level.

2 50 0

RELATIVE TO VESSEL i i NOTE: D6 MEN 510NS WINCHES bases Figure B 3/4 3-1 REACTOR VESSEL WATER LEVEL HOPE CREEK B 3/4 3-8 l

i 3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 RECIRCULATION SYSTEM Operation with one reactor core coolant recirculation loop inoperable is prohibited until an evaluation of the performance of the ECCS during one loop operation has been performed, evaluated and determined to be acceptable. i An inoperable jet pump is not, in itself, a sufficient reason to declare i a recirculation loop inoperable, but it does, in case of a design-basis-accident, increase the blowdown area and reduce the capability of reflooding the core; thus, the requirement for shutdown of the facility with a jet pump inoperable. l Jet pump failure can be detected by monitoring jet pump performance on a prescribed schedule for significant degradation.

Recirculation pump speed mismatch limits are in compliance with the ECCS LOCA analysis design criteria. The limits will ensure an adequate core flow ,

coastdown from either recirculation loop following a LOCA. In order to prevent undue stress on the vessel nozzles and bottom head region, the recirculation loop temperatures-shall be within 50*F of each other prior to startup of an idle loop. The 1000 temperature must also be within 50*F of the reactor pressure vessel coolant temperature to prevent thermal !O '\ shock to the recirculation pump and recirculation nozzles. Since the coolant in the bottom of the vessel is at a lower temperature than the coolant in the upper regions of the core, undue stress on the vessel would result if the temperature difference was greater than 145*F. The objective of GE BWR plant and fuel design is to provide stable operation I with margin over the normal operating domain. However, at the high power / low flow corr.er of the operating domain, a small probability of limit cycle neutron flux oscillations exists depending on combinations of operating conditions (e.g., rod pattern, power shape). To provide assurance that neutron flux limit cycle oscillations are detected and suppressed, APRM and LPRM neutron flux noise levels i should be monitored while operating in this region. Stability tests at operating BWRs were reviewed to determine a generic region of the power / flow map in which surveillance of neutron flux noise levels should be performed. A conservation decay ratio of 0.6 was chosen as the bases for determining the generic region for surveillance to account for the plant to plant variability of decay ratio with core and fuel designs. This generic region has been determined to correspond to a core flow of less than or equal to 45% of rated core flow and a THERMAL POWER greater than that specified in i Figure 3.4.1.1-1. Plant specific calculations can be performed to determine an applicable region for monitoring neutron flux noise levels. In this case the degree of conservatism can be reduced since plant to plant variability would be eliminated. ; In this case, adequate. margin will be assured by monitoring the region which has l a decay ratio greater than or equal to 0.8. t HOPE CREEK B 3/4 4-1

REACTOR COOLANT SYSTEM BASES Neutron flux noise limits are also established to ensure early detection of limit cycle neutron flux oscillations. BWR cores typically operate with neutron flux noise caused by random boiling and flow noise. Typical neutron flux noise levels of 1-12% of rated power (peak-to peak) have been reported for the range of low to high recirculation loop flow during both singTe and dual recirculation loop operation. Neutron flux noise levels which significantly bound these values are considered in the thermal / mechanical design of GE BWR fuel and are found to be of negligible consequence. In addition, stability tests at operating BWRs have demonstrated that when stability related neutron flux limit cycle oscillations occur they result in peak-to peak neutron flux limit cycles of 5-10 times the typical values. Therefore, actions taken to reduce neutron flux noise levels exceeding three (3) times the typical value are suf-ficient to ensure early detection of limit cycle neutron flux oscillations. Typically, neutron flux noise levels show a gradual increase in absolute magnitude as core flow is increased (constant control rod pattern) with two reactor recirculation loops in operation. Therefore, the baseline neutron flux noise level obtained at a specific core flew can be applied over a range of core flows. To maintain a reasonable variation between the low flow and high flow end of the flow range, the range over which a specific baseline is applied should not exceed 20% of rated core flow with two recirculation loops in operation. Data j from tests and operating plants indicate that a range of 20% of rated core flow will result in approximately a 50% increase in neutron flux noise level during l operation with two recirculation loops. Baseline data should be taken near the l maximum rod line at which the majority of operation will occur. However, base-line date taken at lower rod lines (i.e. , lower power) will result in a conser-vative value since the neutron flux noise level is proportional to the power level at a given core flow. 3/4.4.2 SAFETY / RELIEF VALVES The safety valve function of the safety / relief valves operates to prevent l the reactor coolant system from being pressurized above the Safety Limit of 1375 psig in accordance with the ASME Code. A total of 13 OPERABLE safety / relief valves is required to limit reactor pressure to within ASME III allowable values for the worst case transient. Demonstration of the safety / relief valve lift settings will occur only during shutdown. The safety / relief valves will be removed and either set pres-sure tested or replaced with spares which have been previously set pressure tested and stored in accordance with manufacturer's recommendations at the specified frequency. The }ow-low set system ensures that safety / relief valve discharges are minimized for a second opening of these valves, following any overpressure tran-sient. This is achieved by automatically lowering the closing setpoint of two valves and lowering the opening setpoint of two valves following the initial opening. In this way, the frequency and magnitude of the containment blowdown duty cycle is substantially reduced. Sufficient redundancy is provided for the low-low set system such that failure of any one valve to open or close at its reduced setpoint does not violate the design basis. HOPE CREEK B 3/4 4-2

p REACTOR COOLANT SYSTEM BASES 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.3.1 LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specificat. ion are provided to monitor and detect leakage from the reactor coolant pressure boundary. These detection systems are consistent with the recommendations of Regulatory Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systems", May 1973. 3/4.4.3.2 OPERATIONAL LEAKAGE The allowable leakage rates from the reactor coolant system have been based on the predicted and experimentally observed behavior of cracks in pipes. The normally expected background leakage due to equipment design and the detection capability of the instrumentation for determining system leakage was also con-sidered. The evidence obtained from experiments suggests that for leakage ; somewhat greater than that sp'ecified for U_NIDENTIFIED LEAKAGE the probability ' is small that the imperfection or crack associated with such leakage would grow rapidly. However, in all cases, if the leakage rates exceed the values specified or the leakage is located and known to be PRESSURE B0UNDARY LEAKAGE, the reactor will be shutdown to allow further investigation and corrective action. The Surveillance Requirements for RCS pressure isolation valves provide O added assurance of valve integrity thereby reducing the probability of gross V valve failure and consequent intersystem LOCA. Leakage from the RCS pressure isolation valves is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit. 3/4.4.4 CHEMISTRY The water chemistry limits of the reactor coolant system are established to prevent damage to the reactor materials in contact with the coolant. Chloride limits are specified to prevent stress corrosion cracking of the stainless steel. The effect of chloride is not as great when the oxygen concentration in the coolant is low, thus the 0.2 ppm limit on chlorides is permitted during POWER OPERATION. During shutdown and refueling operations, the temperature necessary for stress corrosion to occur is not present so a 0.5 ppm concentration of chlorides is not considered harmful during these periods. Conductivity measurements are required on a continuous basis since changes in this parameter are an indication of abnormal conditions. When the conductivity is within limits, the pH, chlorides and other impurities affecting conductivity must also be within their acceptable limits. With the conductivity meter inoperable, additional samples must be analyzed to ensure that the chlorides are not efceeding the limits. The surveillance requirements provide adequate assurance that concentrations in excess of the limits will be detected in sufficient time to take corrective action. O V HOPE CREEK B 3/4 4-3

REACTOR COOLANT SYSTEM BASES 3/4.4.5 SPECIFIC ACTIVITY The limitations on the specific activity of the primary coolant ensure that the 2 hour thyroid and whole body doses resulting from a main steam line failure outside the containment during steady state operation will not exceed small fractions of the dose guidelines of 10 CFR 100. The values for the limits on specific activity represent interim limits based upon a parametric evaluation by the NRC of typical site locations. These values are conservative in that specific site parameters, such as site boundary location and meteorological conditions, were not considered in this evaluation. The ACTION statement permitting POWER OPERATION to continue for limited time periods with the primary coolant's specific activity greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131, but less than or equal to 4.0 micro-curies per gram DOSE EQUIVALENT I-131, accommodates po331ble iodine spiking phenomenon which may occur following changes in THERMAL POWER. Monitoring the iodine activity in the primary coolant and taking responsible actions to maintain it at a reasonably low level will aid in ensuring the accumulated time of plant operation with high iodine activity will not exceed 800 hours in a consecutive 12-month period. The results of all primary coolant specific activity analyses' which exceed the limits of Specification 3.4.5 will be documented pursuant to Specification 6.9.1.5. Information obtained on iodine spiking will be used to assess the parameters associated with spiking phenomena. A reduction in frequency of isotopic analysis following power changes may be permissible if justified by the data obtained. Closing the main steam line isolation valves prevents the release of activity to the environs should a steam line rupture occur outside containment. The surveillance requirements provide adequate assurance that excessive specific activity levels in the reactor coolant will be detected in sufficient time to take corrective action. O HOPE CREEK B 3/4 4-4

REACTOR COOLANT SYSTEM

  ,- y (V  3      BASES af4.4.6 PRESSURE / TEMPERATURE LIMITS                                                                                         ,

All components in the reactor coolant system are designed to withstand the effects of cyclic loads due to system temperature and pressure changes. These cyclic loads are introduced by normal load transients, reactor trips, and startup and shutdown operations. The various categories of load cycles used for design purposes are provided in Section (4.9) of the FSAR. During startup and shutdown, the rates of temperature and pressure changes are limited ! so that the maximum specified heatup and cooldown rates are consistent with

the design assumptions and satisfy the stress limits for cyclic operation.

                     .The operating limit curves of Figure 3.4.6.1-1 are derived from the fracture toughness requirements of 10 CFR 50 Appendix G and ASME Code Section III, Appen-dix G. The curves are based on the RT                            and stress intensity factor information NDT for the reactor vessel components. Fracture toughness limits and the basis for compliance are more fully discussed in FSAR Chapter 5, Paragraph 5.3.1.5, " Frac-ture Toughness."

The reactor vessel materials have been tested to determine their initial RT NDT. The results of these tests are shown in Table B 3/4.4.6-1. Reactor operation and resultant fast neutron, E greater than 1 MeV, irradiation will cause an increase in the RTNDT. Therefore, an adjusted reference temperature,

Q based upon the fluence, phosphorus content and copper content of the material in question, can be predicted using Bases Figure B 3/4.4.6-1 and the recommenda-tions of Regulatory Guide 1.99, Revision 1, " Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel Materials." The pressure / tempera-

!           ture limit curve, Figure 3.4.6.1-1, curves A', B' and C', includes an assumed shift in RT NDT f r the end of life fluence.

The actual shift in RT NDT of the vessel material will be established period-ically during operation by removirg and evaluating, irradiated flux wires installed near the inside wall of the reactor vessel in the core area. Since the neutron spectra at the flux wires and vessel inside radius are essentially identical, the irradiated flux wires can be used with confidence in predicting reactor vessel material transition temperature shift. The operating limit curves of Figure 3.4.6.1-1 shall be adjusted, as required, on the basis of the flux wire data and recommendations of Regulatory Guide 1.99, Revision 1. l l l O HOPE CREEK B 3/4 4-5

REACTOR COOLANT SYSTEM BASES PRESSURE / TEMPERATURE LIMITS (Continued) The pressure-temperature limit lines shown in Figures 3.4.6.1-1, curves C, and C', and A and A', for reactor criticality and for inservice leak and hydrostatic testing have been provided to assure compliance with the minimum temperature requi.'ements of Appendix G to 10 CFR Part 50 for reactor criticality and for inservice leak and hydrostatic testing. The number of reactor vessel irradiation surveillance capsules and the j frequencies for removing and testing the specimens in these capsules are pro-vided in Table 4.4.6.1.3-1 to assure compliance with the requirements of Appen-dix H to 10 CFR Part 50. 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES Double isolation valves are provided on each of the main steam lines to minimize the potential leakage paths from the containment in case of a line break. Only one valve in each line is required to maintain the integrity of the containment, however, single failure considerations require that two valves be OPERABLE. The surveillance requirements are based on the operating history of this type valve. The maximum closure time has been selected to contain fission products and to ensure the core is not uncovered following line breaks. The minimum closure time is consistent with the assumptions in the safety analyses to prevent pressure surges. 3/4.4.8 STRUCTURAL INTEGRITY The inspection programs for ASME Code Class 1, 2 and 3 components ensure that the structural integrity of these components will be maintained at an acceptable level throughout the life of the plant. Components of the reactor coolant system were designed to provide access to permit inservice inspections in accordance with Section XI of the ASME Boiler and Pressure Vessel Code 1977 Edition and Addenda through Summer 1978. The inservice inspection program for ASME Code Class 1, 2 and 3 components will be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable addenda as required by 10 CFR Part 50.55a(g) except , where specific written relief bas been granted by the NRC pursuant to 10 CFR Part 50.55a(g)(6)(1). 3/4.4.9 RESIDUAL HEAT REMOVAL A single shutdown cooling r.cde loop provides sufficient heat removal capability for removing core decay neat and mixing to assure accurate tempera- ' ture indication, however, single failure considerations require that two loops be OPERABLE or that alternate methods capable of decay heat removal be demonstrated and that an alternate method of coolant mixing be in operation. HOPE CREEK B 3/4 4-6

O ~'N w/ wY %J BASES TABLE B 3/4.4.6-1 5 r'#1 REACTOR VfSSEL TOUGHNESS kr" HEAT / SLAB HIGHEST PREDICTED UNIRRA01ATED MAX. E01

BELTLINE WELD SEAM I.D. OR UPPER SHELF RT a RT RT COMPONENT OR MAT'l TYPE HEAT / LOT CU(%) P(%) NDT(*F) NOT(*F) (FT-LSS) _,

39 Plate SA-533 GR 8 CL.1 SK3025-1 .15 .012 +19 20 76 +39 Weld Long. seams for D55040/ .08 .010 -30 .17 135 -13 shells 4&5 and girth 1125-02000 weld between 4&5 NOTE:

These values are given Only for the benefit of calculating the end-of-life (EOL) RT g .T" HEAT / SLAB HIGHEST REFERENCE NON-BELTLINE MT'L TYPE OR OP. gMPERAT'JRE COMPONENT WELD SEAM I.D. HEAT / LOT NDT (*F)

= Shell Ring Connected to SA 533, GR.B C1.1 All Heats +19 y Vessel Flange

Bottom Head Dome SA 533, GR.B, C1.1 All Heats +3G

t Bottom Head Torus SA 533, GR.6, C1.1 All Heats +30 w LPCI Nozzles SA 503, C1.2 All Heats -20 ) Top Head Torus SA 533, GR.B C1.1 All Heats +19 Top Head Flange SA 508, C1.2 All Heats +10 Vessel Flange SA 508, C1.2 All Heats +10 Feedwater Nozzle SA 508, C1.2 All Heats -20 Weld Metal All RPV Welds All Heats O Closure Studs SA 540, GR.B, 24 All Heats ' Meet 45 f t-lbs & 25 mils l' lateral expansion at +10*F The design of the Hope Creek vessel results in these nozzles experiencing a predicted E0L fl'uence at 1/4T of the vessel thickness of 1.6 x 10" n/cm2. Therefore, these nozzles are predicted to have an EOL RT NDT of -6 F. l l I

O 4 51.4 - i S

                  = 1.2     -

T 1.1 E 1 .0 - T w [ 0.8 - e .

                 " 0.6

d g

0.4 - g 0.2 - S 1 . . .

r. 0.0 - -

0 10 20 30 40 SERVICE LIFE YEAR 5* i FIG!!RE 8 3/4 4.6-1 FAST NEUTRON FLUENCE (E>l Mev) AT 1/4 T AS A FUNCTION Of SERVICE LIFE

Bases Figure B 3/4.4.6-1 l
At 90% of RKTED THERMAL POWER and 90% availability l HOPE CREEK B 3/4 4a8

3/4.5 EMERGENCY CORE COOLING SYSTEM BASES 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN The core spray system (CSS), together with the LPCI mode of the RHR system, is provided to assure that the core is adequately cooled following a loss-of-coolant accident and provides adequate core cooling capacity for all break sizes up to and including the double ended reactor recirculation line break, and for smaller breaks following depressurization by the ADS. The CSS is a primary source of emergency core cooling after the reactor vessel is depressurized and a source for flooding of the core in case of accidental draining. The surveillance requirements provide adequate assurance that the CSS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage to piping and to start cooling at the earliest moment. The low pressure coolant injection (LPCI) mode of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant accident. Four subsystems, each with one pump, provide adequate core flooding for all break sizes up to and including the double-ended reactor recirculation line break, and for small breaks following depressurization by the ADS. The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage to piping and to start cooling at the earliest moment. The high pressure coolant injection (HPCI) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressurization of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HPCI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling. The capacity of the system is selected to provide the required core cooling. The HPCI pump is designed to deliver greater than or equal to 5600 gpm at reactor pressures between 1120 and 200 psig. Initially, water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water. HOPE CREEK B 3/4 5-1 1

EMERGENCY CORE COOLING SYSTEM BASES ECCS-0PERATING and SHUTDOWN (Continued) With the HPCI system inoperable, adequate core cooling is assured by the OPERABILITY of the redundant and diversified automatic depressurization system and both the CSS and LPCI systems. In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in tee safety analysis, will automatically provide makeup at reactor operating pressures on a reactor low water level condition. The HPCI out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified icw pressure core cooling systems and the RCIC system. The surveillance requirements provide adequate assurance that the HPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor to be in H0T SHUTDOWN with vessel pressure not less than 200 psig. The pump discharge piping is maintained full to prevent water hammer damage and to provide cooling at the earliest moment. Upon failure of the HPCI system to function properly after a small break loss-of-coolant accident, the automatic depressurization system (ADS) automa-tically causes salected safety-relief valves to open, depressurizing the reactor so that flow from the low pressure core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200 F. ADS is conserva-tively required to be OPERABLE whenever reactor vessel pressure exceeds 100 psig. This pressure is substantially below that for which the low pressure core cooling systems can provide adequate core cooling for events requiring ADS. ADS automatically controls five selected safety-relief valves although the safety analysis only takes credit for four valves. It is therefore appropriate to permit one valve to be out-of-service for up to 14 days without materially reducing system reliability. 3/4.5.3 SUPPRESSION CHAMBER The suppression chamber is required to be OPERABLE as part of the ECCS to ensure that a sufficient supply of water is available to the HPCI, CSS and LPCI systems in the event of a LOCA. This limit on suppression chamber minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression chamber in OPERATIONAL CONDITIONS 1, 2 or 3 is also required by Specification 3.6.2.1. Repair work might require making the suppression chamber inoperable. This specification will permit those repairs to be made and at the same time give assurance-that the irradiated fuel has an adequate cooling water supply when the suppression chamber must be made inoperable, including draining, in OPERATIONAL CONDITION 4 or 5. In OPERATIONAL CONDITION 4 and 5 the suppression chamber minimum required < water volume is reduced because the reactor coolant is maintained at or below l 200 F. Since pressure suppression is not required below 212 F, the minimum water volume is based on NPSH, recirculation volume and vortex prevention plus ! a safety margin for conservatism. HOPE CREEK B 3/4 5-2 l I

l I l O 5 3/4.6 CONTAINMENT 3YSTEMS BASES 3/4.6.1 PRIMARY CONTAINMENT 3/4.6.1.1 PRIMARY CONTAINMENT INTEGRITY PRIMARY CONTAINMENT INTEGRITY ensures that the release of radioactive mate-rials from the containment atmosphere will be restricted to those leakage paths and associated leak rates as;umed in the accident analyses. This restriction, in conjunction with the leakage rate limitation, will limit the site boundary radiation doses to within the limits of 10 CFR Part 100 during accident conditions. 3/4.6.1.2 PRIMARY CONTAINMENT LEAKAGE The limitations on primary containment leakage rates ensure that the total containment leakage volume will not exceed the value assumed in the accident

                                                                    . As an added conserva-analyses     at the peak tism, the measured       accident overall       pressure integrated        of 48.1 leakage  ratepsig, is P,further limited to less than or equal to 0.75 L during performance of the periodic tests to account for possible degradation of,the containment leaka0e barriers between leakage tests.

Operating experience with the main steam line isolation valves has indicated that degradation has occasionally occurred in the leak tightness of

 ]   the valves; therefore the special requirement for testing these valves.

The surveillance testing for measuring leakage rates is consistent with the requirements of Appendix "J" of 10 CFR Part 50 witn the exception of exemptions granted for main steam isolation valve leak testing and testing the airlocks after each opening. 3/4.6.1.3 PRIMARY CONTAINMENT AIR LOCKS l l l The limitations on closure and leak rate for the primary containment air locks are required to meet the restrictions on PRIMARY CONTAINMENT INTEGRITY and the primary containment leakage ra h given in Specifications 3.6.1.1 and 3.6.1.2. The specification makes allcwances for the fact that there may be ! long periods of time when the air locks will be in a closed and secured l position during reactor operation. Only one closed door in each air lock l is required to maintain the integrity of the containment. 3/4.6.1.4 MSIV SEALING SYSTEM Calculated doses resulting from the maximum leakage allowance for the main steamline isolation valves in the postulated LOCA situations would be a small fraction of the 10 CFR 100 guidelines, provided the main steam line system from the isolation valves up to and including the turbine condenser remains intact. ; Operating experience has indicated that degradation has occasionally occurred l n in the leak tightness of the MSIV's such that the specified leakage requirements l

 /  have not always been maintained continuously. The sealing system will reduce V) the untreated leakage from the MSIVs when isolation of the primary system and containment is required.                                                                l l

l HOPE CREEK B 3/4 6-1

t CONTAINMENT SYSTEMS BASES 3/4.6.1.5 PRIMARY CONT,.INMENT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the-containment will be maintained comparable to the original design standards for the life of the unit. Structural integrity is required to ensure that tne containment will withstand the maximum pressure of 48.1 psig in the event of a LOCA. A visual inspection in conjunction with Type A leakage tests is sufficient to demonstrate this capability. 3/4.6.1.6 DRYWELL AND SUPPRESSION CHAMBER INTERNAL PRESSURE The limitations on drywell and suppression chamber internal pressure ensure that the containment peak. pressure of 48.1 psig does not exceed the design pressure of 62 psig during LOCA conditions or that the external pressure differential does not exceed the design maximum external pressure differential of 3 psid. The limit of -0.5 to +1.5 psig for initial positive containment pressure will limit the total pressure to 48.1 psig which is less than the design pressure and is consistent with the safety analysis. 3/4.6.1.7 DRYWELL AVERAGE AIR TEMPERATURE The limitation on drywell average air temperature ensures that the containment peak air temperature does not exceed the design temperature of 340 F during LOCA conditions and is consistent with the safety analysis. The 135*F average temperature is conducive to normal and long term operation. 3/4.6.1.8 DRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM The outboard 26-inch and outboard 24-inch drywell and suppression chamber purge supply and exhaust isolation valves are required to be sealed closed during plant operation since these valves have not been demonstrated capable of closing during a LOCA or steam line break accident. Maintaining these valves sealed closed during plant operations ensures that excessive quantities of radioactive materials will not be released via the containment purge system. To provide assurance that the 26-inch and the 24-inch valves cannot be inadvertently opened, they are sealed closed in accordance with Standard Review Plan 6.2.4, which includes mechanical devices to seal or lock the valve closed, or prevent power from being supplied to the valve cperator. O HOPE CREEK B 3/4 6-2

O) t CONTAINMENT SYSTEMS BASES DRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM (Continued) The use of the drywell and suppression chamber purge lines for pressure control is restricted with the following exception, the inboard 26-inch valve on ! the drywell purge outlet vent line when used in conjunction with the 2-inch i purge outlet vent line bypass valve since the 2-inch valves will close during l a LOCA or steam line break accident and therefore the site boundary dose guidelines of 10 CFR Part 100 would not be exceeded in the event of an accident during purging operations. In addition due to the limited flow rate through the 2-inch bypass valve, the inboard 26-inch valve is also capable of closing under these conditions. The design of the 2-inch purge supply and exhaust isolation valves meets the requirements of Branch Technical Position CSB 6-4,

      " Containment Purging During Normal Plant Operations".

Leakage integrity tests with a maximum aliowable leakage rate for purge supply and exhaust isolation valves will provide early ' indication of resilient inaterial seal degradation and will allow the opportunity for repair before gross leakage failure develops. The 0.60 L leakage limit shall not be exceeded when theleakageratesdeterminedbythel$akageintegritytestsofthesevalves are added to the previously determined total for all valves and penetrations subject to Type B and C tests. 3/4.6.2. DEPRESSURIZATION SYSTEMS

    "       The specifications of this section ensure that the primary containment pressure will not exceed the design pressure of 62 psig during primary system blowdown from full oparating pressure.

The suppression chamber water provides the heat sink for the reactor coolant system energy release following a postulated rupture of the system. The suppression chamber water volume must absorb the associated decay and structural sensible heat released during reactor coolant system blowdown from l 1020 psig. Since all of the gases in the drywell are purged into the suppression chamber air space during a loss of coolant accident, the pressure of the liquid must not exceed 62 psig, the suppression chamber maximum internal design pressure. The design volume of the suppression chamber, water and air, was obtained by considering that the total volume of reactor coolant to be i considered is discharged to the suppression chamber and that the drpeell volume l is purged to the suppression chamber. l i Using the minimum or maximum water volumes given in this specification, containment pressure during the design basis accident is approximately 48.1 psig which is below the design pressure of 62 psig. Maximum water volume of 122,000 ft 3results in a downcomer submergence of 3.33 ft and the minimum volume of 118,000 fta results in a submergence of approximately 3.0 ft. The majority of the Bodega tests were run with a submerged length of four feet and with complete condensation. Thus, with respect to the downcomer submergence, this j specification is adequate. The maximum temperature at the end of the blowdown l HOPE CREEK B 3/4 6-3

CONTAINMENT SYSTEMS BASES DEPRESSURIZATION SYSTEMS (Continued) tested during the Humboldt Bay and Bcdega Bay tests was 170*F and this is con-servatively taken to be the limit for complete condensation of the reactor coole.nt, although condensation would occur for temperatures above 170 F. Should it be necessary to make the suppression chamber inoperable, this shall only be done as specified in Specification 3.5.3. Under full power operating conditions, blowdown from an initial suppression chamber water temperature of 95*F results in a water temperature of approx-imately 135'F immediately following blowdown which is below the 200 F used for complete condensation via mitered T quencher devices. At this tempera-ture and atmospheric pressure, the available NPSH exceeds that required by both the RHR and core spray pumps, thus there is no dependency on containment over-pressure during the accident injection phase. If both RHR locps are used for containment cooling, there is no dependency on containment overpressure for post-LOCA operations. Experimental data indicates that excessive steam condensing loads can be avoided if the peak local temperature of the suppression pool is maintained below 200*F during any period of relief valve operation. Specifications have been placed on the envelope of reactor operating conditions so that the reactor can be depressurized in a timely manner to avoid the regime of potentially high suppression chamber loadings. Because of the large volume and thermal capacity of the suppression pool, the volume and temperature normally changes very slowly and monitoring these parameters daily is sufficient to establish any temperature trends. By requiring the suppression pool temperature to be frequently recorded during periods of significant heat addition, the temperature trends will be closely followed so that appropriate action can be taken. The requirement for an external visual examination following any event where potentially high loadings could occur pro-vides assurance that no significant damage was encountered. Particular atten-tion should be focused on structural discontinuities in the vicinity of the relief valve discharge since these are expected to be the points of highest stress. In addition to the limits on temperature of the suppression chamber pool water, operating procedures define the action to be taken in the event a safety-relief valve inadvertently opens or sticks open. As a minimum this action shall include: (1) use of all available means to close the valve, (2) initiate suppres-sion pool water cooling, (3) initiate reactor shutdown, and (4) if other safety-relief valves are used to depressurize the reactor, their discharge shall be separated from that of the stu-k-open safety relief valve to assure mixing and uniformity of energy insertion to the pool. In conjuction with the Mark I containment Long Term Program, a plant unique analysis was performed which demonstrated that the containment, the attached piping and internal structures meet the applicable structural and mechanical acceptance criteria for Hope Creek. The evaluation followed the design basis loads defined in the Mark I Load Definition Report, NEDO-21888, December 1978, as modifled by NRC SER NUREG 0661, July 1980 and Supplement 1, August 1982, to ensure that hydrodynamic loads, appropriate for the life of the plant, were applied. HOPE CREEK B 3/4 6-4

A i \

 'w/  CONTAINMENT SYSTEMS BASES 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES The OPERABILITY of the primary containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A of 10 CFR 50. Containment isolation within the time limits specified for those isolation valves designed to close auto-matically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.

3/4.6.4 VACUUM RELIEF Vacuum relief breakers are provided to equalize the pressure between the suppression chamber and drywell and between the Reactor Building and suppres-sion chamber. This system will maintain the structural integrity of the primary containment under conditions of large differential pressures. The vacuum breakers between the suppression chamber and the drywell must not be inoperable in the open position since this would allow bypassing of the suppression pool in case of an accident. (L 3/4.6.5 SECONDARY CONTAINMENT 5econdary containment is designed to minimize any ground level release of radioactive material which may result from an accident. The Reactor Building and associated structures provide secondary containment during normal operation when the drywell is sealed and in service. At other times the drywell may be open and, when required, secondary containment integrity is specified. Establishing and maintaining a 0.25 inch water gage vacuum in the reactor building with the filtration recirculation and ventilation system (FRVS) once per 18 months, along with the surveillance of the doors, hatches, dampers and valves, is adequate to ensure that there are no violations of the integrity of i the secondary containment. The OPERABILITY of the FRVS ensures that sufficient iodine removal capa-bility will be available in the event of a LOCA. The reduction in containment iodine inventory reduces the resulting site boundary radiation doses associated ! with containment leakage. The operation of this system and resultant iodine removal capacity are consistent with the assumptions used in the LOCA analyses and with the drawdown analysis. Continuous operation of the system with the heaters and humidity control instruments OPERABLE for 10 hours during each 31 day l period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA i filters. HOPE CREEK B 3/4 6-5

CONTAINMENT SYSTEMS BASES 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL The OPERABILITY of the systems required for the detection and control of hydrogen gas ensures that these systems will be available to maintain the hydrogen concentration within the primary containment below its flammable limit during post-LOCA conditions. Either containment hydrogen recombiner is capable of controlling the expected hydrogen generation associated with (1) zirconium-water reactions, (2) radiolytic decomposition of water and (3) corrosion of metals within containment. The hydrogen control system is consistent with the recommendations of Regulatory Guide 1.7, " Control of Combustible Gas Concen-trations in Containment Following a LOCA" November 1978. O O l HOPE CREEK B 3/4 6-6 1 L_ _ _ _ _ _ - - _ - - _ _ . _ _ _ _ . - _ - - -

3/4.7 PLANT SYSTEMS (q

  %/
     /         BASES 3/4.7.1 SERVICE WATER SYSTEMS The OPERABILITY of the station service water and the safety auxiliaries cooling systems ensures that sufficient cooling capacity is available for con-tinued operation of the SACS and its associated safety-related equipment during normal and accident conditions. The redundant cooling capacity of these sys-tems, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits.

3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM The OPERABILITY of the control room emergency filtration system ensures that 1) the ambient air temperature does not exceed the allowable temperature for continuous duty rating for the equipment and instrumentation cooled by this system and 2) the control room will remain habitable for operations personnel during and following all design basis accident conditions. Continuous operation of the system with the heaters and humidity control instruments OPERABLE for 10 hours during each 31 day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The OPERABILITY of this system in conjunction with control room design provisions is based on limiting the radia-tion exposure to personnel occupying the control room to 5 rem or less whole body, or its equivalent. This limitation is consistent with the requirements of General Design Criteria 19 of Appendix "A", 10 CFR Part 50. (j ( 3/4.7.3 FLOOD PROTECTION The requirement for flood protection ensures that facility flood protection features are in place in the event of flood conditions. The limit of elevation 10.E' Mean Sea Level is based on the elevation at which facility flood protection features provide protection to safety related equipment. 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM The reactor core isolation cooling (RCIC) system is provided to assure adequate core cooling in the event of reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel without requiring actuation of any of the Emergency Core Cooling Syste, equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor steam dome pressure exceeds 150 psig. This pressure is substantially below that for which the RCIC system can provide adequate core cooling for events requiring the RCIC system. The RCIC system specifications are applicable during OPERATIONAL CONDITIONS 1, 2 and 3 when reactor vessel steam dome pressure exceeds 150 psig because RCIC is the primary non-ECCS source of emergency core cooling when the reactor is pressurized. With the RCIC syst.em inoperable, adequate core cooling is assured by the OPERABILITY of the HPCI system and justifies the specified 14 day out-of-service period. HOPE CREEK B 3/4 7-1

PLANT SYSTEMS BASES REACTOR CORE __ ISOLATION COOLING SYSTEM (Continued) The surveillance requirements provida adequate assurance that RCIC will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage and to start cocling at the earliest possible moment. 3/4.7.5 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity of the reactor coolant system and all other safety related systems is maintained during and following a seismic or other event initiating dynamic loads. Snub-bers excluded from this inspection program are those installed on nonsafety-related systems and then only if their failure or failure of the system on which they are installed would have no adverse effect on any safety related system. Snubbers are classified and grouped by design and manufacturer but not by size. For example, mechanical snobbers utilizing the same design features of the 2-kip, 10-kip, and 100-kip capacity manufactured by Company "A" are of the . same type. The same design mechanical snubbers manufactured by Company "B" for the purposes of this Technical Specification would be of a different type, as would hydraulic snubbers from either manufacturer. A list of individual snubbers with detailed information of snubber location and size and of system affected shall be available at the plant in accordance with Section 50.71(c) of 10 CFR Part 50. The accessibility of each snubber shall be determined and approved by the Plant Operations Review Committee. The determination shall be based upon the existing radiation levels and the expected time to perform a visual inspection in each snubber location as well as other factors associated with accessibility during plant operations (e.g., temperature, atmosphere, location, etc.), and the recommendations of Regulatory Guide 8.8 and 8.10. The addition or deletion of any snubber shall be made in accordance with Section 50.59 of 10 CFR Part 50. The visual inspection frequency is based upon maintaining a constant level of snubber protection to each safety-related system. Therefore, the required inspection interval varies inversely with the observed snubber failures and is determineo by the number of inoperable snubbers found during an inspection. In order to establish the inspection frequency for each type of snubber on a safety-re}ated system, it was assumed that the frequency of snubber failures and initiating events is constant with time and that the failure of any snubber on that system could cause the system to be unprotected and to result in fail-ure during an assumed initiating event. Inspections performed before that 9 HOTE CREEK B 3/4 7-2

  . . =.                  .                  .   - - .               .-. _    -           _                  .-

PLANT SYSTEMS BASES _SN_UBBERS (Continued) ! interval has elapsed may be used as a new reference point to determine the next inspection. However, the results of such early inspections-performed I before the original required time interval has elasped (nominal time less 25%) { may not be used to lengthen the required inspection interval. Any inspection l whose results required a shorter inspection interval will override the previous ! , schedule. The acceptance criteria are to be used in the visual inspection to determine OPERABILITY of the snubbers. l To provide assurance of snubber functional reliability one of three functional testing methods is used with the stated acceptance criteria:

1. Functionally test 10% of a type of snubber with an additional 10%

j tested for each functional testing failure, or

2. Functionally test a sample size and determine sample acceptance or rejection using Figure 4.7.5-1, or 4

3. Functionally test a representative sample size and determine sample acceptance or rejection using the stated equation.

l Figure 4.7.5-1 was developed using "Wald's Sequential Probability Ratio i Plan" as described in Quality Control and Industrial Statistics" by Acheson J. Duncan. 4 Permanent or other exemptions from the surveillance program for individual I snubbers may be granted by the Commission if a justifiable basis for exemption i is presented and, if applicable, snubber life destructive testing was performed to qualify the s .ubbers for the applicable design conditions at either the com-t pletion of their fabrication or at a subsequent date. Snubbers so exempted shall be listed in the list of individual snubbers indicating the extent of the exemptions. i The service life of a snubber is evaluated via manufacturer input and information through consideration of the snubber service conditions and asso-ciated installation and maintenance records (i.e., newly installed snubber, seal replaced, spring replaced, in high radiation area, in high temperature 1 l area, etc.). The requirement to monitor the snubber service life is included , to ensure.that the snubbers periodically undergo a performance evaluation in i view of their age and operating conditions. These ruards will provide statis- i ! tical bases for future consideration of snubber service life. ) l i l HOPE CREEK B 3/4 7-3

PLANT SYSTEMS BASES 3/4.7.6 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requiring leak testing, including alpha emitters, is based on 10 CFR 70.39(c) limits for plutonium. This limitation will ensure that leakage from byproduct, source, and special nuclear material sources will not exceed allowable intake values. Sealed sources are classified into three groups according to their use, with surveillance requirements commensurate with the probability of damage to a source in that group. Those sources which are frequently handled are required to be tested more often than those which are not. Sealed sources which are continuously enclosed within a shielded mechanism, i.e., sealed sources within radiation monitoring devices, are considered to be stored and need not be tested unless they are removed from the shielded mechanism. 3/4.7.7 MAIN TURBINE BYPASS SYSTEM The main turbine bypass system is required to be OPERABLE consistent with the assumptions of the feedwater controller failure analysis for FSAR Chapter 15. O O HOPE CREEK B 3/4 7-4 LV

i 3/4.8 ELECTRICAL POWER SYSTEMS BASES 3/4.8.1, 3/4.8.2 and 3/4.8.3 A.C. SOURCES, D.C. SOURCES and ONSITE POWER j , DISTRIBUTION SYSTEMS ; The OPERABILITY of the A.C. and D.C. power sources and associated distribution systems during operation ensures that sufficient powiir will be available to supply the safety related equipment required for (1) the safe shutdown of the facility and (2) the mitigation and control of accident conditions within the facility. The minimum specified independent and redundant A.C. and D.C. power sources and distribution systems satisfy the requirements of General Design Criteria 17 of Appendix "A" to 10 CFR 50. The ACTION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation comensurate with the level of degradation. The OPERABILITY of the power sources are con-sistent with the initial condition assumptions of the safety analyses and are based upon maintaining at least one of the onsite A.C. and the corresponding D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss of offsite power and single failure of the other onsite A.C. or D.C. source. The A.C. and D.C. source allowable out-of-service times are based on Regulatory Guide 1.93, " Availability of Electrical Power Sources", December 1974 as acdiried by plant specific analysis and diesel generator manufacturer O* recomendations. When two diesel generators are inoperable, there is an addi-tional ACTION requirement to verify that all required systems, susbsystems, trains, components and devices, that depend on the remaining OPERABLE diesel generators as a source of emergency power, are also OPERABLE. This requirement is intended to provide assurance that a loss of offsite power event will not result in a complete loss of safety function of critical systems during the period two or more of the diesel generators are inoperable. The term verify as used in this context means to administrative 1y check by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons. It does not mean to perform the surveillance requirements needed to demonstrate the OPERABILITY of the component. The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that (1) the facility can be maintained in the shutdown or refueling condition for extended time periods and (2) sufficient instrumentation and control capability is available for monitoring and maintaining the unit status. The surveillance requirements for demonstrating the OPERABILITY of the diesel generators are in accordance with the recomendations of . Regulatory Guide 1.9, " Selection of Diesel Generator Set Capacity for Standby Power Supplies",' March 10, 1971, Regulatory Guide 1.108, " Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants", Revision 1, August 1977 and Regulatory Guide 1.137" Fuel-011 Systems for Standby Diesel Generators", Revision 1, October 1979 as modified by plant specific anal-ysis and diesel generator manuf acturer's recomendations. h HOPE CREEK B 3/4 8-1

ELECTRICAL POWER SYSTEMS BASES O\l l A.C. SOURCES, D.C. SOURCES and ONSITE POWER DISTRIBUTION SYSTEMS (Continued) The surveillance requirements for demonstrating the OPERABIL-ITY of the unit batteries are in accordance with the recommendations of Regulatory Guide 1.129 " Maintenance Testing and Replacement of Large Lead Storage Batteries for Nuclear Power Plants", February 1978 and IEEE Std 450-1980, "IEEE Recommended l Practice for Maintenance, Testing, and Replacement of Large Lead Storage ! Batteries for Generating Stations and Substations." j Verifying average electrolyte temperature above the minimum for which the battery was sized, total battery terminal voltage on float charge, connection resistance values and the performance of battery service and discharge tests ensures the effectiveness of the charging system, the ability to handle high discharge rates and compares the battery capacity at that +ime with the rated capacity. Table 4.8.2.1-1 specifies the normal limits for each designated pilot cell and each connected cell for electrolyte level, float voltage and specific gravity. The limits for the designated pilot cells float voltage and specific gravity, greater than 2.13 volts and .015 below the manufacturer's full charge specific gravity or a battery charger current that had stabilized at a low value, is characteristic of a charged cell with adequate capacity. The normal limits for each connected cell for float voltage and specific gravity, greater than 2.13 volts and not more than .020 below the manufacturer's full charge specific gravity with an average specific gravity of all the connected cells not more than .010 below the manufacturer's full charge specific gravity, ensures the OPERABILITY and capability of the battery. Operation with a battery cell's parameter outside the normal limit but within the allowable value specified in Table 4.8.2.1-1 is permitted for up to 7 days. During this 7 day period: (1) the allowable values for electrolyte level ensures no physical damage tc the plates with an adequate electron transfer capability; (2) the allowable value for the average specific gravity of all the cells, not more than .020 below the manufacturer's recommended full charge specific gravity ensures that the decrease in rating will be less than the safety margin provided in sizing; (3) the allowable value for an individual cell's specific gravity, ensures that an individual cell's specific gravity will not be more than .040 below the manufacturer's full charge specific gravity and that the overall capability of the battery will be maintained within an acceptable limit; and (4) the allowable value for an individual cell's float voltage, greater than 2.07 volts, ensures the battery's capability to perform its design function. O HOPE CREEK B 3/4 8-2

l ELECTRICAL POWER SYSTEMS BASES 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Primary containment electrical penetrations and penetration conductors : are protected by demonstrating the OPERABILITY of primary and backup overcurrent protection circuit breakers by periodic surveillance. The surveillance requirements applicable to lower voltage circuit breakers provides assuranc2 of breaker reliability by testing at least one representative sample of each manufacturers brand of circuit breaker. Each manufacturer's molded case and metal case circuit breakers are grouped into representative samples which are than tested on a rotating basis to ensure that all breakers are tested. If a wide variety exists within any manufacturer's brand of circuit breakers, it is necessary to divide that manufacturer's breakers into groups and treat each group as a separate type of breaker for surveillance purposes. The OPERABILITY or bypassing of the motor operated valves thermal overload protection continuously or during accident conditions by integral bypass de-vices ensures that the thermal overload protection during accident conditions will not prevent safety related valves from performing their function. The Surveillance Requirements for demonstrating the OPERABILITY or bypassing of the thermal overload protection continuously or during accident conditions are in p accordance with Regulatory Guide 1.106 " Thermal Overload Protection for Elec-g tric Motors on Motor Operated Valves", Revision 1, March 1977. f l l l l l HOPE CREEK B 3/4 8-3

3/4.9 REFUELING OPERATIONS O BASES 3/4.9.1 REACTOR MODE SWITCH Locking the OPERABLE reactor mode switch in the Shutdown or. Refuel position, as specified, ensures that the restrictions on control rod withdrawal and refueling platform movement during the refueling operations are properly activated. These conditions reinforce the refueling procedures and reduce the probability of inadvertent criticality, damage to reactor internals or fuel assemblies, and exposure of personnel to excessive radiation. 3/4.9.2 INSTRUMENTATION The OPERABILITY of at least; two source range monitors ensures that redundant monitoring capability is available to detect changes in the reactivity condition of the core. 3/4.9.3 CONTROL ROD POSITION The requirement that all control rods be inserted during other CORE ALTERA-TIONS minimizes the possibility that fuel will be loaded into a cell without a

- control rod, although one rod may be withdrawn under control of the reactor mode switch refuel position one-rod-out-interlock.

3/4.9.4 DECAY TIME The minimum requirement for reactor subcriticality prior to fuel movement ensures that sufficient time has elapsed to allow the radioactive decay of the short lived fission products. This decay time is consistent with the assump-l tions used in the accident analyses. i ( 3/4.9.5 COPNUNICATIONS The requirement for communications capability ensures that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity condition during movement of fuel within the reactor pressure vessel. i HOPE CREEK B 3/4 9-1

REFUELING OPERATIONS BASES 3/4.9.6 REFUELING PLATFORM The OPERABILITY requirements ensure that (1) the refueling platform will be u,ed for handling control rods and fuel assemblies within the reactor pressure vessel, (2) each crane and hoist has sufficient load caoacity for handling fuel assemblies and control rods, and (3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertently en-gaged during lifting operations. 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE POOL The restriction on movement of loads in excess of the nominal weight of a fuel assembly over other fuel assemblies in the storage pool ensures that in the event this load is dropped (1) the activity release will be limited to that contained in a single fuel assembly, and (2) any possible distortion of fuel in the storage racks will not result in a critical array. This assumption is consistent with the activity release assumed in the safety analyses. 3/4.9.8 and 3/4.9.9 WATER LEVEL - REACTOR VESSEL and WATER LEVEL - SPENT FUEL T70 RAGE POOL The restrictions on minimum water level ensure that sufficient water depth is available to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly. This minimum water depth is consistent with the assumptions of the accident analysis. 3/4.9.10 CONTROL R0D REMOVAL These specifications ensure that maintenance or repair of control rods or control rod drives will be performed under conditions that limit the probability of inadvertent criticality. The requirements for simultaneous removal of more than one control rod are more stringent since the SHUTDOWN MARGIN specification provides for the core to remain subcritical with only one control rod fully withdrawn. 3/4.9.11 RESIDUAL HEAT REMOVAL AND C00LdT CIRCULATION The requirement that at least one residual heat removal loop be OPERABLE or that an alternate method capable of decay heat removal be demonstrated and that an alternate method of coolant mixing be in operation ensures that (1) suf-ficient cooling capacity is available to remove decay heat and maintain the water in the reactor pressure vessel below 140 F as required during REFUELING, and (2) sufficient coolant circulation would br.: available through the reactor core to assure accurate temperature indication and to distribute and prevent stratification of the poison in the event it becomes necessary to actuate the standby liquid control system. The requirement to have two shutdown cooling mode loops OPERABLE when there is less ttian 22 feet 2 inches of water above the reactor vessel flange ensures that a single failure of the operating loop will not result in a complete loss of residual heat removal capability. With the reactor vessel head removed and 22 feet 2 inches of water above the reactnr vessel flange, a large heat sink is available for core cooling. Thus, in the event a failure of the operating RHR loop, adequate time is'provided to initiate alternate methods capable of decay heat removal or emergency procedures to cool the core. HOPE CREEK B 3/4 9-2

O t V) 3/4.10 SPECIAL TEST EXCEPTIONS BASES l 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY The requirement for PRIMARY CONTAINMENT INTEGRITY is not applicable during the period when open vessel tests are being performed during the low power PHYSICS TESTS. 3/4.10.2 R0D SEQUENCE CONTROL SYSTEM In order to perform the tests required in the technical specifications it is necessary to bypass the sequence restraints on control rod movement. The additional surveillance requirments ensure that the specifications on heat generation rates and shutdown margin requirements are not exceeded during the period when these tests are being performed and that individual rod worths do not exceed the values assumed in the safety analysis. 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS d Performance of shutdown margin demonstrations during open vessel testing requires additional restrictions in order to ensure that criticality is properly .; p) monitored and controlled. These additional restrictions are specified in this LCO.

,t    )

3/4.10.4 RECIRCULATION LOOPS This special test exception permits reactor criticality under no flow conditions and is required to perform certain startup and PHYSICS TESTS while at low THERMAL POWER levels. 3/4.10.5 OXYGEN CONCENTRATION Relief from the oxygen concentration specifications is necessary in order to provide access to the primary containment during the initial startup and testing phase of operation. Without this access the startup and test program ! could be restricted and delayed. 1 3/4.10.6 TRAINING STARTUPS This special test exception permits training startups to be performed with the reactor vessel depressurized at low THERMAL POWER and temperature while controlling RCS temperature with one RHR subsystem aligned in the shutdown cooling mode in order to minimize contaminated water discharge to the radioactive waste disposal system. 3/4.10.7 SPECIAL INSTRUMENTATION - INITIAL CORE LOADING This special test exception permits relief from the requirements for a minimum count rate while loading the first 16 fuel bundles to allow sufficient source-l ) O" to-detector coupling such that minimum count rate can Se achieved on an SRM. This is acceptable because of the significant margin to criticality while load-ing the initial 16 fuel bundles. HOPE CREEK B 3/4 10-1

3/4.11 RADIOACTIVE EFFLUENTS BASES 3/4.11.1 LIQUID EFFLUENTS 3/4.11.1.1 CONCENTRATION This specification is provided to ensure that the concentration of radioactive materials released in liquid waste effluents to UNRESTRICTED AREAS will be less than the concentration levels specified in 10 CFR Part 20, Appen-dix B, Table II, Column 2. This limitation provides additional assurance that the levels of radioactive materials in bodies of water in UNRESTRICTED AREAS will result in exposures within (1) the Section II.A design objectives of Appen-dix I, 10 CFR Part 50, to a MEMBER OF THE PUBLIC and (2) the limits of 10 CFR < Part 20.106(e) to the population. The concentration limit for dissolved or entrained noble gases is based upon the assumption that Xe-135 is the control-ling radioisotope and its MPC in air (submersion) was converted to an equivalent concentration in water using the methods described in International Commission on Radiological Protection (ICRP) Publication 2. The required detection capabilities for radioactive materials in liquid waste samples are tabulated in terms of the lower limits of detect. ion (LLDs). Detailed discussion of the LLD, and other detection limits can be found in Currie, L. A., " Lower Limit of Detection: Definition and Elaboration of a Proposed Position for Radiological Effluent and Environmental Measurements," ( NUREG/CR-4007 (September 1984), and in the HASL Procedures Manual, HASL-300 (revised annually). 3/4.11.1.2 DOSE This specification is provided to implement the requirements of Sections II.A, III.A, and IV.A of Appendix 1, 10 CFR Part 50. The Limiting j Condition for Operation implements the guides set forth in Section II.A of

Appendix I. The ACTION statements provide the required operating flexibility and at the same time implement the guides set forth in Section IV.A of Appen-dix I to assure that the releases of radioactive material in liquid effluents to UNRESTRICTED AREAS will be kep+. "as low as is reasonably achievable." Also, for fresh water sites with drinking water supplies that can be potentially affected by plant operations, there is reasonable assurance that the operation of the facility will not result in radionuclide concentrations in the finished drinking water that are in excess of the requirements of 40 CFR Part 141. The dose calculation methodology and parameters in the ODCM implement the require-ments in Section III.A of Appendix I that conformance with the guides of

! Appendix I be shown by calculational procedures based on models and data, such that the actual exposure of a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially underestimated. The equations specified in the ODCM for calculating the doses due to the actual release rates of radioactive materials in liquid effluents are consistent with the methodology provided in i Regulatory Guide 1.109, " Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with s 10 CFR Part 50, Appendix I," Revision 1, October 1977 and Regulatory Guide 1.113,

     *     " Estimating Aquatic Dispersion of Effluents from Accidental and Routine Reactor Releases for the Purpose of Implerenting Appendix I," April 1977.

HOPE CREEK B 3/4 11-1

RADI0 ACTIVE EFFLUENTS BASES 3/4.11.1.3 LIQUID RADWASTE TREATMENT SYSTEM The OPERABILITY of the liquid radwaste treatment system ensures that this system will be available for use whenever liquid effluents require treatment prior to their release to the environment. The requirement that the appropriate portions of this system be used, when specified, provides assurance that the releases of radioactive materials in liquid effluents will be kept "as low as is reasonably achievable." This specification implements the requirements of' General Design Criterion 60 of Appendix A to 10 CFR Part 50 and the design objective given in Section II.D of Appendix I to 10 CFR Part 50. The specified limits governing the use of appropriate portions of the liquid radwaste treatment system were specified as a suitable fraction of the dose design objectives set forth in Section II.A of Appendix I, 10 CFR Part 50, for liquid effluents. 3/4.11.1.4 LIQUID HOLDUP TANKS The tanks listed in this specification include all those outdoor radwaste tanks that are not surrounded by liners, dikes, or walls capable of holding the tank contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System. Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tanks' contents, the resulting concentrations would be less than the limits of 10 CFR Part 20, Appendix B, Table II, Column 2, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA. 3/4.11.2 GASEOUS EFFLUENTS 3/4.11.2.1 DOSE RATE This specification is provided to ensure that the dose at any time at and beyond the SITE BOUNDARY from gaseous effluents from all units on the site will be within the annual dose limits of 10 CFR Part 20 to UNRESTRICTED AREAS. The annual dose limits are the doses associated with the concentrations of 10 CFR Part 20, Appendix B, Table II, Column 1. These limits provide reasonable assurance that radioactive material discharged in gaseous effluents will not result in the exposure of a MEMBER OF THE PUBLIC in an UNRESTRICTED AREA, either within or outside the SITE BOUNDARY, to annual average concentrations exceeding the limits specified in Appendix B, Table II of 10 CFR Part 20 (10 CFR Part 20.106(b)). For MEMBERS OF THE PUBLIC who may at times be within the SITE BOUNDARY, the occupancy of that MEMBER OF THE PUBLIC will usually be sufficiently low to compensate for any increase in the atmospheric diffusion factor above that for the SITE BOUNDARY. Examples of calculations for such MEMBERS OF THE PUBLIC, with the appropriate occupancy factors, shall be.given in the ODCH. The specified release rate limits restrict, at all times, the corresponding gamma and beta dose rates above background to a MEMBER OF THE PUBLIC at or beyond the SITE BOUNDARY to less than or equal to 500 mrems/ year to the total body or to less than or equal to 3000 mrems/ year to the skin. HOPE CREEK B 3/4 11-2

RADI0 ACTIVE EFFLUENTS BASES DOSE RATE (Continued) i These release rate limits also restrict, at all times, the corresponding thyroid dose rate above background to a child via the inhalation pathway to less than or equal to 1500 mrems/ year. The required detection capabilities for radioactive materials in gaseous waste samples are tabulated in terms of the lower limits of detection (LLDs). Detailed discussion of the LLD, and other detection limits can be found in Currie, L. A., " Lower Limit of Detection: Definition and Elaboration of a Proposed Position for Radiological Effluent and Environmental Measurements," NUREG/CR-4007 (September 1984), and in the HASL Procedures Manual, HASL-300 (revised annually). 3/4.11.2.2 DOSE - NOBLE GASES This specification is provided to implement the requirements of Sections II.B, III.A, and IV.A of Appendix I, 10 CFR Part 50. The Limiting Condition for Operation implements the guides set forth in Section II.B of

Appendix I. The ACTION statements provide the required operating flexibility and at the same time implement the guides set forth in Section IV.A of Appendix I to assure that the releases of radioactive material in gaseous effluents to V) i
UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." The Sur-veillance Requirements implement the requirements in Section III.A of Appendix I

! that conformance with the guides of Appendix I be shown by calculational proce-dures based on models and data such that the actual exposure of a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially under-estimated. The dose calculation methodology and parameters established in the l ODCM for calculating the doses due to the actual release rates of radioactive noble gases in gaseous effluents are consistent with the methodology provided in llegulatory Guide 1.109, " Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I," Revision 1, October 1977 and Regulatory Guide 1.111,

     " Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water Cooled Reactors," Revision 1, July 1977.

The ODCM equations provided for determining the air doses at and beyond the SITE BOUNDARY are based upon the historical average atmospheric conditions. 3/4.11.2.3 DOSE - 10 DINE-131, IODINE-133, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM l This. specification is provided to implement the requirements of Sections II.C, III.A and IV.A of Appendix I, 10 CFR Part 50. The Limiting Conditions for Operation are the guides set forth in Section II.C of Appendix I. , The ACTION statements provide the required operating flexibility and at the same time implement the guides set forth in Section IV.A of Appendix I to O assure that the releasps of radioactive materials in gaseous effluents to UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." The i ODCM calculational methods specified in the Surveillance Requirements implement HOPE CREEK B 3/4 11-3

RADI0 ACTIVE EFFLUENTS BASES DOSE - 10 DINE-131, 10 DINE-133, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM (Continued) the requirements in Section III.A of Appendix I that conformance with the guides of Appendix I be shown by calculational procedures based on models and data, such that the actual exposure of a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially underestimated. The 00CM calculational methodology and parameters for calculating the doses due to the actual release rates of the subject materials are consistent with the methodology provided in Regulatory Guide 1.109, " Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I," Revision 1, October 1977 and Regulatory Guide 1.111, " Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water-Cooled Reactors," Revision 1, July 1977. These equations also provide for determining the actual doses based upon the historical average atmospheric conditions. The release rate specifications for iodine-131, iodine-133, tritium, and radionuclides in particulate form with half lives greater than 8 days are dependent upon the existing radionuclide pathways to man, in the areas at and beyond the SITE B0UNDARY. The pathways that were examined in the development of these calculations were: (1) individual inhala-tion of airborne radionuclides, (2) deposition of radionuclides onto green leafy vegetation with subsequent consumption by man, (3) deposition onto grassy areas where milk animals and meat producing animals graze with consumption of the milk and meat by man, and (4) deposition on the ground with subsequent exposure of man. 3/4.11.2.4 AND 3/4.11.2.5 GASE0US RADWASTE TREATMENT AND VENTILATION EXHAUST TREATMENT The OPERABILITY of the GASEOUS RADWASTE TREATMENT SYSTEM and the VENTILA-TION EXHAUST TREATMENT SYSTEM ensures that the system will be available for use whenever gaseous effluents require treatment prior to release to the environment. The requirement that the appropriate portions of these systems be used, when specified, provides reasonable assurance that the releases of radioactive mate-rials in gaseous effluents will be kept "as low as is reasonably achievable." This specification implements the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50, and the design objectives given in Section II.0 of Appendix I to 10 CFR Part 50. The specified limits governing the use of appropriate portions of the systems were specified as a suitable fraction of the dose design objectives set forth in Sections II.B and II.C of Appendix I, 10 CFR Part 50, for gaseous effluents. 3/4.11.2.6 EXPLOSIVE GAS MIXTURE This specification is provided to ensure that the concentration of poten-tially explosive gas mixtures contained in the GASEOUS RADWASTE TREATMENT SYSTEM main condenser offgas system is maintained below the flammability limits of hydrogen and oxygen. Automatic control features are included in the system to prevent the hydrogen and oxygen concentration from reaching these flammability HOPE CREEK B 3/4 11-4

RADIOACTIVE EFFLUENTS BASES EXPLOSIVE GAS MIXTURE (Continued) limits. These automatic control features include isolation of the source of hydrogen and/or oxygen on loss of dilution steam. Maintaining the concentra-tion of hydrogen below the flammability limit provides assurance that the re-leases of radioactive materials will be controlled in conformance with the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50. ; 3/4.11.2.7 MAIN CONDENSER Restricting the gross radioactivity rate of noble gases from the main condenser provides reasonable assurance that the total body exposure to an individual at the exclusion area boundary will not exceed a small fraction of )' the limits of 10 CFR Part 100 in the event this effluent is inadvertently discharged directly to the environment without treatment. This specification implements the requirements of General Design Criteria 60 and 64 of Appendix A l to 10 CFR Part 50. 3/4.11.2.8 VENTING OR PURGING n This specification provides reasonable assurance that releases from drywell , ( purging operations will not exceed the annual dose limits of 10 CFR Part 20 i for UNRESTRICTED AREAS. 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT This specification implements the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50. The process parameters included in establishing the PROCESS CONTROL PROGRAM may include, but are not limited to waste type, waste pH, waste / liquid / solidification agent / catalyst ratios, waste oil content, waste principal chemical constituents, and mixing and curing times. The purpose of the PROCESS CONTROL PROGRAM is to provide quality assurance that the solidified waste meets 10 CFR Part 61 requirements. 3/4.11.4 TOTAL DOSE This specification is provided to meet the dose limitations of 40 CFR Part 190 that have been incorporated into 10 CFR Part 20 by 46 FR 18525. The specification requires the preparation and submittal of a Special Report whenever the calculated doses from plant generated radioactive effluents and direct radiation exceed 25 mrems to the total body or any organ, except - the thyroid, which shall be limited to less than or equal to 75 mrems. For sites containing up to 4 reactors, it is highly unlikely that the resultant dose to a MEMBER OF THE PUBLIC will exceed the dose limits of 40 CFR Part 190 if the individual reactors remain within twice the dose design objectives of Appendix I, and if direct radiation doses from the reactor unite 'ncluding l outside storage tanks,etc. are kept small. The Special Report will describe a i course of action that should result in the limitation of the e .of, dose to a MEMBER OF THE PUBLIC to within the 40 CFR Part 190 limits. For the purposes of the Special Report, it may be assumed that the dose commitment to the MEMBER OF HOPE CREEK B 3/4 11-5

RADI0 ACTIVE EFFLUENTS BASES TOTAL DOSE (Continued) THE PUBLIC from other uranium fuel cycle sources is negligiblo, with the excep-tion that dose contributions from other nuclear fuel cycle tacilities at the same site or within a radius of 8 km must be considered. If the dose to any MEMBER OF THE PUBLIC is estimated to exceed the requirements of 40 CFR Part 190, the Special Report with a request for a variance (provided the release condi-tions resulting in violation of 40 CFR Part 190 have not already been corrected), in accordance with the provisions of 40 CFR Part 190.11 and 10 CFR Part 20.405c, is considered to be a timely request and fulfills the requirements of 40 CFR Part 190 until NRC staff action is completed. The variance only relates to the limits of 40 CFR Part 190, and does not apply in any way to the other require-ments for dose limitation of 10 CFR Part 20, as addressed in Specifica-tions 3.11.1.1 and 3.11.2.1. A.n individual is not considered a MEMBER OF THE PUBLIC during any period in which he/she is engaged in carrying out any opera-tion that is part of the nuclear fuel cycle. O l l l O HOPE CREEK B 3/4 11-6

3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING D'i t BASES 3/4.12.1 MONITORING PROGRAM The radiological environmental monitoring program required by this specification provides representative measurements of radiation and of radio-active materials in those exposure pathways and for those radionuclides that lead to the highest potential radiation exposures of MEMBERS OF THE PUBLIC resulting from the station operation. This monitoring program implements Section IV.B.2 of Appendix I to 10 CFR Part 50 and thereby supplements the radiological effluent monitoring program by verifying that the measurable concentrations of radioactive materials and levels of radiation are not higher than expected on the basis of the effluent measurements and the modeling of the environmental exposure pathways. Guidance for this :nonitoring program is provided by the Radiological Assessment Branch Technical Position on Environ-mental Monitoring, Revision 1, November 1979. The initially specified monitor-ing program will be effective for at least the first 3 years of commercial operation. Following this period, program changes may be initiated based on operational experience. The required detection capabilities for environmental sample analyses are tabulated in terms of the lower limits of detection (LLDs). The LLDs required by Table 4.12.1-1 are considered optimum for routine environmental

 ;    j measurements in industrial laboratories. It should be recognized that the V     LLD is defined as an a priori (before the fact) limit representing the capa-bility of a measurement system and not as an a posteriori (after the fact) limit for a particular measurement.

Detailed discussion of the LLD, and other detection limits, can be found in Currie, L. A. , " Lower Limit of Detection: Definition and Elaboration of a Proposed Position for Radiological Effluent and Environmental Measurements," NUREG/CR-4007 (September 1984), and in the HASL Procedures Manual, HASL-300 (revised annually). l 3/4.12.2 LAND USE CENSUS i This specification is provided to ensure that changes in the use of areas ! at and beyond the SITE BOUNDARY are identified and that modifications to the . radiological environmental monitoring program are made if required by the

results of this census. The best information from the door-to-door survey, ,

from aerial survey, from visual survey or from consulting with local agricul-l tural authorities shall be used. This census satisfies the requircaents of Section IV,.B.3 of Appendix I to 10 CFR Part 50. Restricting the census to gar- ' ! dens of greater than 50 m2 provides assurance that significant exposure pathways via leafy vegetables will be identified and monitored since a garden of this size is the minimum required to produce the quantity (26 kg/ year) of leafy vege-tables assumed in Regulatory Guide 1.109 for consumption by a child. To deter-mine this minimum garden size, the following assumptions were made: (1) 20% of p)v the garden was used fo'r growing broad leaf vegetation (i.e., similar to lettuce and cabbage), and (2) a vegetation yield of 2 kg/m2, )s , l HOPE CREEK B 3/4 12-1

3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING BASES 3/4.12.3 INTERLABORATORY COMPARISON PROGRAM The requirement for participation in an approved Interlaboratory Comparison Program is provided to ensure that independent checks on the precision and accu-racy of the measurements of radioactive material in environmental sample matrices are performed as part of the quality assurance program for environ-mental monitoring in order to demonstrate that the results are valid for the purposes of Section IV.B.2 of Appendix I to 10 CFR Part 50. O O HOPE CREEK B 3/4 12-2

l l t t i i SECTION 5.0 DESIGN FEATURES .l 4 l l l j

  . _._m_- . . ..--__ _. _ - _ - __ _ _ _ _ ._. _ _ _ _ _   - . _ _ _ _ _ . , _ , . _ _ _ _ _ . . _ _ _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _

_w - - _- l 1 s 5.0 DESIGN FEATURES C/ 5.1 SITE EXCLUSION AREA AND MAP DEFINING UNRESTRICTED AREAS AND SITE BOUNDARY FOR RADI0 ACTIVE GASEOUS AND LIQUID EFFLLENTS 5.1.1 The exclusion area shall be as shown in Figure 5.1.1-1. Information regarding radioactive gaseous and liquid effluents which will allow identifica-tion of structures and release points as well as definition of UNRESTRICTED AREAS within the SITE B0UNDARY that are accessible to MEMBERS OF THE PUBLIC, shall be as shown in Figure 5.1.1-1. LOW POPULATION ZONE 5.1.2 The low population zone shall be as shown in Figure 5.1.2-1. The circle with the five mile radius is the low population zone. 5.2 CONTAINMENT CONFIGURATION 5.2.1 The primary containment is a steel structure composed of a spherical b lower portion, a cylindrical middle portion, and a hemispherical top head which form a drywell. The drywell is attached to the suppression chamber through a series of downcomer vents. The suppression chamber is a steel pressure vessel in the shape of a torus. The drywell has a nominal free air volume of 169,000 cubic feet. The suppression chamber has an air volume of 137,000 cubic feet and a water region of 118,000 cubic feet. DESIGN TEMPERATURE AND PRESSURE 5.2.2 The primary containment is designed and shall be maintained for:

a. Maximum internal pressure 62 psig.

! b. Maximum internal temperature: drywell 340*F. suppression pool 310 F.

c. Maximum external differential pressure 3 psid.

SECONDARY CONTAINMENT 5.2.3 The secondary containment consists of the Reactor Building, and a portion of the main steam tunnel and has a free volume of 4,000,000 cubic feet. ( HOPE CREEK 5-1

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DESIGN FEATURES 5.3 REACTOR CORE FUEL ASSEMBLIES 5.3.1 The reactor core shall contain 764 fuel assemblies with each fuel assembly containing 62 fuel rods and two water rods clad with Zircaloy-2. Each fuel rod shall have a nominal active fuel length of 150 inches. The initial core loading shall have a maximum average enrichment of 1.90 weight percent U-235. Reload fuel shall be similar in physical design to the initial core loading. CONTROL ROD ASSEMBLIES 5.3.2 The reactor core shall contain 185 control rod assemblies, each consisting of a cruciform array of stainless steel tubes containing 143 inches of boron carbide, B C, 4 powder surrounded by a cruciform shaped stainless steel sheath. 5.4 REACTOR COOLANT SYSTEM DESIGN PRESSURE AND TEMPERATURE 5.4.1 The reactor coolant system is designed and shall be maintained:

a. In accordance with the code requirements specified in Section 5.2 of the FSAR, with allowance for normal degradation pursuant to the applicable Surveillance Requirements,

b. For a pressure of:

l 1. 1250 psig on the suction side of the recirculation pump.

2. 1500 psig from the recirculation pump discharge to the jet pumps.

! c. For a temperature of 575 F. l VOLUME l 5.4.2 The total water and steam volume of the reactor vessel and recirculation l system is approximately 21,970 cubic feet at a nominal steam dome saturation j temperature of 547*.F. i 5.5 METEOROLOGICAL TOWER LOCATION l 5.5.1 The meteorological tower shall be located as shown on Figure 5.1.1-1. O HOPE CREEK 5-4

DESIGN FEATURES l V 5.6 FUEL STORAGE CRITICALIH 5.6.1 The spent fuel storage racks are designed and shal.1 be maintained with:

a. A k,7f equivalent to less than or equal to 0.95 when flooded with unborated water, including all calculational uncertainties and biases as described in Section 9.1.2 of the FSAR.

b. A nominal 6.308 inch center-to-center distance between fuel assemblies placed in the storage racks.

5.6.1.2 The k,ff for new fuel for the first core loading stored dry in the spent fuel storage racks shall not exceed 0.98 when aqueous foam moderation is assumed. DRAINAGE 5.6.2 The spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 199' 4". g CAPACITY . N , i 5.6.3 The spent fuel storage pool is designed and shall be maintained with a

storage capacity limited to no more than 1108 fuel assemblies.

5.7 COMPONENT CYCLIC OR TRANSIENT LIMIT 5.7.1 The components identified in Table 5.7.1-1 are designed and shall be maintained within the cyclic or transient limits of Table 5.7.1-1. HOPE CREEK 5-5 4

5 A n TABLE 5.7.1-1 5 m COMPONENT CYCLIC OR TRANSIENT LIMITS i CYCLIC OR DESIGN CYCLE

,                                               COMPONENT                                 TRANSIENT LIMIT                       OR TRANSIENT l                                                Reactor                                 120 heatup and cooldown cycles          70*F to 546*F to 70*F 80 step change cycles                   Loss of feedwater heaters I                                                                                        180 reactor trip cycles                 100% to 0% of RATED THERMAL POWER 130 hydrostatic pressure and            Pressurized to > 930 and
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i leak tests $1250 psig l T cn l l l O O O .

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i 1 l SECTION 6.0 ADMINISTRATIVE CONTROLS 1 I l I i l i l I l

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6.0 ADMINISTRATIVE CONTROLS A 6.1 RESPONSIBILITY 6.1.1 The General Manager - Hope Creek Operations shall be responsible for overall unit operation and shall delegate in writing the succession to this responsibility during his absence. 6.1.2 The Senior Nuclear Shift Supervisor or during his absence from the control room, a designated individual shall be responsible for the control room command function. A management directive to this effect, signed by the Vice President - Nuclear shall be reissued to all station personnel on an annual basis. 6.2 ORGANIZATION OFFSITE 6.2.1 The offsite organization for unit management and technical support shall be as shown on Figure 6.2.1-1. UNIT STAFF 6.2.2 The unit organization shall be as shown on Figure 6.2.2-1 and:

a. Each on duty shift shall be composed of at least the minimum shift crew composition shown in Table 6.2.2-1;

b. At least one licensed Reactor Operator shall be in the control room when fuel is in the reactor. In addition, while the unit is in

OPERATIONAL CONDITION 1, 2 or 3, at least one licensed Senior Reactor Operator shall be in the control room;

c. A Radiation Protection Technician

shall be on site when fuel is in the reactor;

d. ALL CORE ALTERATIONS shall be observed and directly supervised by either a licensed Senior Reactor Operator or licensed Senior Reactor Operator Limited to Fuel Handling who has no other concur-rent responsibilities during this operation; and "The Radiation Protection Technician may be unavailable for a period of time not to exceed 2 hours, in order to accommodate unexpected absence, provided immediate action is taken to fill the required position.

l O l HOPE CREEK 6-1

ADMINISTRATIVE CONTROLS I l UNIT STAFF (continued) . e. Administrative procedures shall be developed and implemented to limit ! the working hours of unit staff who perform safety-related functions e.g., licensed Senior Reactor Operators, licensed Reactor Operators, i radiation protection technicians, equipment operators, and key main-tenance personnel. Adequate shift coverage shall be maintained without routine heavy use of over-time. The objective shall be to have operating personnel work a normal 8-hour day, 40-hour week while the unit is operating. However, in the event that un-foreseen problems require substantial amounts of overtime to be used, or during extended periods of shutdown for refueling, major maintenance on major unit modifications, on a temporary basis the following guidelines shall be followed:

1. An individual should not be permitted to work more than 16 hours straight, excluding shift turnover time.

2. An individual should not be permitted to work more than 16 hours in any 24-hour period, nor more than 24 hours in any 48-hour period, nor more than 72 hours in any 7 day period, all excluding shift turnover time.

3. A break of at least 8 hours should be allowed between work periods, in-cluding shift turnover time.

4. Except during extended shutdown periods, the use of overtime should be con-sidered on an individual basis and not for the entire staff on a shift.

Any deviction from the above guidelines shall be authorized by the appropriate department manager, or higher levels of management, in accordance with et, tab-lished procedures and with documentation of the basis for granting the deviation. Controls shall be included in the procedures such that individual overtime shall I be reviewed monthly by the General Manager-Hope Creek Operations or his designee to assure that excessive hours have not been assigned. Routine deviation from the above guidelines is not authorized. I O HOPE CREEK 6-2

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V TABLE 6.2.2-1

  ,                                                    MINIMUM SHIFT CREW COMPOSITION SINGLE UNIT FACILITY 4

POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION CONDITION 1, 2, or 3 CONDITION 4 or 5 SNSS* 1 1 NSS* 1 None NCO 2 1 E0 2 1 STA 1 None TABLE NOTATION j SNSS - Senior Nuclear Shift Supervisor with a Senior Reactor Operator i license on the Unit j NSS - Nuclear Shift Supervisor with a Senior Reactor Operator license on the Unit

    ;       NCO      - Nuclear Control Operator with a Reactor Operator license on the Unit

\ EO - Equipment Operator STA - Shift Technical Advisor Except for the Senior Nuclear Shift Supervisor, the shift crew composition may be one less than the minimum requirements of Table 6.2.2-1 for a period of time not to exceed 2 hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew compo-sition to within the minimum requirements of Table 6.2.2-1. This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent.

l During any absence of the Senior Nuclear Shift Supervisor from the control room

while the unit is in OPERATIONAL CONDITION 1, 2 or 3, an individual with a valid i' Senior Reactor Operator license shall be designated to assume the control room command function. During any absence of the Senior Nuclear Shift Supervisor i

rom the control room while the unit is in OPERATIONAL CONDITION 4 or 5, an individual with a valid Senior Reactor Operator license or Operator license

! shall be designated to assume the control room command function. 4 "In cares where an individual has a Senior Reactor Operator's license on the t unit, is a qualified STA, and has a Professional Engineers License by virtue of successful completion of the Professional Engineers examination or a bachelor's degree in a scientific, engineering, or engineering technology discipline from an accredited institution, the individual can serve in a dual ( role capacity as either the SNSS/STA or NSS/STA. (Note: For those individuals with a bachelor's degree in a scientific or engineering technology discipline, course work must have included physical, mathematical, or engineering science.) Otherwise, there shall be a qualified STA as well as a SNSS and NSS on-shift. HOPE CREEK 6-5 l 4._.. . .___. __ ___. _ _ _ _ _ __. .

ADMINISTRATIVE CONTROLS 6.2.3 SHIFT TECHNICAL ADVISOR 6.2.3.1 The Shift Technical Advisor shall provide advisory technical support to the Senior Nuclear Shift Supervisor in the areas of thermal hydraulics, reactor engineering, and plant analysis with regard to safe operation of the unit. The Shift Technical Advisor shall have a bachelor's degree or equivalent in a scientific or engineering discipline and shall have received specific training in the response and analysis of the unit for transients and accidents, and in unit design and layout, including the capabilities of instrumentation and controls in the control room. 6.3 UNIT STAFF QUALIFICATIONS 6.3.1 Each member of the unit staff shall meet or exceed the minimum qualifica-tions of ANSI /ANS 3.1-1981 for comparable positions, except for the Radiation Protection Manager who shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975. The licensed Reactor Operators and Senior Reactor Operators shall also meet or exceed the minimum qualifications of the supple-mental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980 NRC letter to all licensees. 6.4 TRAINING 6.4.1 A retraining and replacement training program for the unit staff shall be maintained under the direction of the Manager-Nuclear Training, shall meet or exceed the requirements and recommendations of Section 5.5 of ANSI /ANS 3.1-1981 and Appendix A of 10 CFR Part 55 and the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980 NRC letter to all licen-sees, and shall include familiarization with relevant industry operational experience. 6.4.2 A training program for the Fire Brigade shall be maintained under the direction of the Manager - Site Protection and shall meet or exceed the require-ments of the SRP (NUREG-0800) Section 13.2.2.II.6, 10 CFR 50 Appendix R and Br ach Technical Position CMEB 9.5.1, Section C.3.d. 6.5 REVIEW AND AUDIT 6.5.1 STATION OPERATIONS REVIEW COMMITTEE (SORC) i FUNCTION 6.5.1.1 The SORC shall function to advise the General Manager - Hope Creek Operations on all matters related to nuclear safety. O HOPE CREEK 6-6

  "                  ADMINISTRATIVE CONTROLS COMPOSITION 6.5.1.2 The SORC shall be composed of the:

Chairman: General Manager - Hope Creek Operations Member and Vice Chairman: Operations Manager Member and Vice Chairman: Technical Manager Member: Maintenance Manager Member: I & C Engineer Member: Systems Engineer Member: Radiation Protection / Chemistry Manager Member: Radiation Protection Engineer or Chemistry Engineer Member: Onsite Safety Review Engineer (or designee) ALTERNATES 6.5.1.3 All alternate members shall be appointed in writing by the 50.9C Chairman,

a. Vice Chairmen shall be members of Station management.

! b. No more than two alternates to members shall participate as voting d members in SORC activities at any one meeting.

c. Alternate appointees will only represent their respective department.

d. Alternates for members will not make up part of the voting quorum when the member the alternate represents is also present.

MEETING FREQUENCY 6.5.1.4 The 50RC shall meet at least once per calendar month and as convered by the SORC Chairman or his designated alternate. QUORUM , 6.5.1.5 The quorum of the 50RC necessary for the performance of the 50RC responsibility and authority provisions of these Technical Specifications shall consist of the Chairman or his designated alternate and at least four members including alternates. RESPONSIBILITIES 6.5.1.6 The 50RC shall be responsible for: I

a. Review of: (1) all Station Administrative Procedures and changes l thereto and (2) Newly created procedures or changes to existing

, o HOPE CREEK 6-7 i

ADMINISTRATIVE CONTROLS procedures that involve a significant safety issue as described in Section 6.5.3.2.d.

b. Review of all proposed tests and experiments that affect nuclear safety.

c. Review of all proposed changes to Appendix "A" Technical Specifications.

d. Review of all proposed changes or modifications to plant systems or equipment that affect nuclear safety.

e. Review of the safety evaluations that have been completed under the provisions of 10 CFR 50.59.

f. Investigation of all violations of the Technical Specifications includ-ing the preparation and forwarding of reports covering evaluations and recommendations to prevent recurrence to the Vice President -

Nuclear and to the General Manager - Nuclear Safety Review.

g. Review of all REPORTABLE EVENTS.

h. Review of facility operations to detect potential nuclear safety hazards,

i. Performance of special reviews, investigations or analyses and reports thereon as requested by the General Manager - Hope Creek Operations or General Manager - Nuclear Safety Review.

j. Review of the Facility Security Plan and implementing procedures and shall submit recommended changes to the General Manager - Nuclear Safety Review.

k. Review of the racility Emergency Plan and implementing procedures and shall submit recommended changes to the General Manager - Nuclear Safety Review.

1. Review of the Fire Protection Program and implementing procedures and shall submit recommended changes to the General Manager - Nuclear Safety Review.

m. Review of all unplanned on-site releases of radioactivity to the environs including the preparation of reports covering evaluation, recommendations, and disposition of the corrective action to prevent recurrence and the forwarding of these reports to the Vice President -

Nuclear and to the General Manager - Nuclear Safety Review.

n. Review of changes to the PROCESS CONTROL MANUAL and the OFF-SITE DOSE CALCULATION MANUAL, and the Radwaste Treatment Systems.

REVIEW PROCESS

6. 5.1. 7 A technical review and control systen utilizing qualified reviewers shall function to perform the periodic or routine review of procedures and changes thereto. Details of this technical review process are provided in Section 6.5.3.

O HOPE CREEK 6-8

l ADMINISTRATIVE CONTROLS AUTHORITY 6.5.1.8 The 50RC shall:

a. Recommend in writing to the General Manager - Hope Creek Operations approval or disapproval of items considered under Specifica-tion 6.5.1.6.a. through e. prior to their implementation.

b. Provide written notification within 24 hours to the Vice President -

Nuclear and to the General Manager - Nuclear Safety Review of dis-agreement between the 50RC and the General Manager - Hope Creek Operations; however, the General Manager - Hope Creek Operations shall have responsibility for resolution of such disagreements pursuant to Specification 6.1.1. RECORDS 6.5.1.9 The SORC shall maintain minutes of each SORC meeting, and copies shall be provided to the Vice President - Nuclear, General Manager - Nuclear Safety Review and Manager - Offsite Safety Review. 6.5.2 NUCLEAR SAFETY REVIEW G FUNCTION 6.5.2.1 The Nuclear Safety Review Depart. ment (NSR) shall function to provide the independent safety review program and audit of designated activities. COMPOSITION 6.5.2.2 NSR shall consist of the General Manager - Nuclear Safety Review, the Manager - Offsite Safety Review, who is supported by at least four dedicated, full-time engineers, and the Onsite Safety Review Group, which is managed by the Onsite Safety Review Engineer and is supported by at least three dedicated, full-time engineers located onsite. The Manager - Offsite Safety Review and staff shall meet or exceed the qualifica-tions described in Section 4.7 of ANS 3.1 - 1981 and shall be guided by the provisions for independent review described in Section 4.3 of ANSI N18.7 - 1976 (ANS 3.2). The Offsite Safety Review staff shall generally possess experience and com-petence in the areas listed in Section 6.5.2.4.1. A system of qualified re-viewers from other technical organizations shall be utilized to augment ex-pertise in the disciplines of Section 6.5.2.4.1, where appropriate. Such quslified reviewers shall meet the same qualification requirements as the Offsite Safety Review staff, and shall not have been involved with performance , of the original work. d The Onsite Safety Review Engineer and staff shall meet or exceed the qualifica-tions described in Section 4.4 of ANS 3.1 - 1981. HOPE CREEK 6-9

ADMINISTRATIVE CONTROLS CONSULTANTS 6.5.2.3 Consultants or other technical experts shall be utilized-by NSR to the extent necessary as determined by the General Manager - Nuclear Safety Review. 6.5.2.4 0FFSITE SAFETY REVIEW (OSR) FUNCTION 6.b.2.4.1 The OSR organization shall function to provide independent review and audit of designated activities in the areas of:

a. Nuclear power plant operations,

b. Nuclear engineering,

c. Chemistry and radiocnemistry,

d. Metallurgy,

e. Instrumentation and control,

f. Radiological safety,

g. Mechanical engineering,

h. Electrical engineering

i. Quality assurance

j. Nondestructive testing

k. Emergency preparedness REVIEW 6.5.2.4.2 The OSR shall review:

a. The safety evaluations fo" changes to procedures, equipment, or systems; and tests or experiments completed under the provision of 10 CFR 50.59 to verify that such actiens did not constitute an unreviewed safety question;

b. Proposed changes to procedures, equipment, or systems and tests or experiments which involve an unreviewed safety question as defined in 10 CFR 50.59;

c. Proposed changes to Technical Specifications or this Operating License;

d. yiolations of codes, regulations, orders, Technical Specifications, license requirements, or of internal procedures or instructions having nuclear safety significance;

e. Significant operating abnormalities or deviations from normal and expected performance of facility equipment that affect nuclear safety; O

HOPE CREEK 6-10

q ADMINISTRATIVE CONTROLS

f. All REPORTABLE EVENTS. -

g. All recognized indications of an unanticipated deficiency in some aspect of design or operation of structures, systems, of components that could affect nuclear safety; and

h. Reports and meeting minutes of the SORC.

AUDITS , 6.5.2.4.3 Audits of facility activities shall be performed under the cognizance of the OSR. These audits shall encompass:

a. The conformance of facility operation to provisions contained within the Technical Specifications and applicable license conditions at least once per 12 months;; b. The perforn.ance, training and qualifications of the entire facility staff at least once per 12 months;; c. The results of actions taken to correct deficiencies occurring in facility equipment, structures, systems, or method of operation that affect nuclear safety, at least once per 6 months;; d. The performance of activities required by the Operational Quality V Assurance Program to meet the criteria of Appendix B, 10 CFR Part 50, at least once per 24 months;; e. The Facility Emergency Plan and implementing procedures at least
once per 12 months;: f. The Facility Security Plan and implementing procedures at least once per 12 'nonths;; g. Any other area of facility operation considered appropriate by the General Manager - Nuclear Safety Review or the Vice President - Nuclear;; h. The facility Fire Protection Program and the implementing procedures l at least once per 24 months;; i. The fire protection and loss prevention program implementation at least once per 12 months utilizing either a qualified off-site licensee fire protection engineer (s) or an outside independent fire protection consultant. An outside independent fire protection con-sultant shall be utilized at least once per 36 months; and i; j. The radiological environmental monitoring program and the results thereof at least once per 12 months.; k. The OFFSITE DOSE CALCULATION MANUAL and implementing procedures at}}

ML20205D512: Difference between revisions

Latest revision as of 01:28, 30 December 2020

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2.0 INTRODUCTION

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ML20205D512: Difference between revisions

Latest revision as of 01:28, 30 December 2020

Text

2.0 INTRODUCTION

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