ML20210J193
| ML20210J193 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 03/31/1986 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-1162, NUDOCS 8604030383 | |
| Download: ML20210J193 (477) | |
Text
{{#Wiki_filter:- NUREG-1162 o a Technical Specifications Perry Nuclear Power Plant, Unit No.1 Docket No. 50-440 Appendix "A" to License No. NPF-45 9 Issued by the U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation March 1986 o pm %,, p,, ,g 2 :. l
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NOTICE Availability of Reference Materials Cited in NRC Publications Most documents cited in NRC publications will be available from one of the following sources:
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l l l NUREG-1162 Technical Specifications Perry Nuclear Power Plant, Unit No.1 Docket No. 50-440 Appendix "A" to Ucense No. NPF-45 l l Issued by the U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation March 1906
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h V DEFINITIONS SECTION
- 1. 0 DEFINITIONS PAGE 1.1 ACTI0N....................................................... 1-1 1.2 AVERAGE PLANAR EXP05URE...................................... 1-1
- 1. 3 AVERAGE PLANAR LINEAR HEAT GENERATION RATE. . . . . . . . . . . . . . . . . . . 1-1 1.4 CHANNEL CALIBRATION.......................................... 1-l' 1.5 CHANNEL CHECK................................................ 1-1 1.6 CHANNEL FUNCTIONAL TEST...................................... 1-1 1.7' CORE ALTERATION.............................................. 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 b
x,_,/ 1.11 DRYWELL INTEGRITY............................................ 1-2 1.12 E-AVERAGE DISINTEGRATION ENERGY.............................. 1-3 1.13 EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME........... 1-3 1.14 END-0F-CYCLE RECIRCULATION PUMP. TRIP SYSTEM RESPONSE TIME.... 1-3 1.15 FRACTION OF LIMITING POWER DENSITY........................... 1-3 1.16 FRACTION OF RATED THERMAL P0WER.............................. 1-3 1.17 FREQUENCY N0TATION........................................... 1-4 1.18 FUEL HANDLING BUILDING INTEGRITY............................. 1-4 1.19 GASEOUS RADWASTE TREATMENT (OFFGAS) SYSTEM................... 1-4 1.20 IDENTIFIED LEAKAGE........................................... 1-4
- 1. 21 ISO LATION SYSTEM RESPONSE TIME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 1.22 LIMITING CONTROL R0D PATTERN................................. 1-5 s 1.23 LINEAR HEAT GENERATION RATE.................................. 1-5
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J PERRY - UNIT 1 i , Q 9+
DEFINITIONS SECTION DEFINITIONS (Continued) PAGE 1.24 LIQUID RADWASTE TREATMENT SYSTEM............................. 1-5 1.25 LOGIC SYSTEM FUNCTIONAL TEST................................. 1-5 1.26 MEMBER (S) 0F THE PUBLIC...................................... 1-5 1.27 MINIMUM CRITICAL POWER RATI0................................. 1-5
- 1. 28 0FFSITE DOSE CALCULATION MANUAL. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-5 1.29 OPERABLE - OPERABILITY....................................... 1-6 1.30 OPERATIONAL CONDITION - C0NDITION............................ 1-6 1.31 PHYSICS TESTS................................................ 1-6
- 1. 32 PRESSURE BOUNDARY LEAKAGE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-6 1.33 PRIMARY CONTAINMENT INTEGRITY................................ 1-6 1.34 PROCESS CONTROL PR0 GRAM...................................... 1-7 1.35 PURGE - PURGING.............................................. 1-7 1.36 RATED THERMAL P0WER.......................... ............... 1-7 1.37 REACTOR PROTECTION SYSTEM RESPONSE TIME...................... 1-7 1.38 REPORTABLE EVENT............................................. 1-7 1.39 R0D DENSITY....................... .......................... 1-7 1.40 SECONDARY CONTAINMENT INTEGRITY.............................. 1-7 1.41 SHUTDOWN MARGIN......................................... .... 1-8 1.42 SITE B0VNDARY.................................. ............. 1-8 1.43 SOLIDIFICATION... ........................................... 1-8 1.44 SOURCE CHECK......................... . ... .............. .. 1-8 1.45 STAGGERED TEST BASIS............................ ... ........ 1-8 1.46 THERMAL POWER.... ........................................... 1-9 PERRY - UNIT 1 ii
.~ 4 a DEFINITIONS '5 SECTION DEFINITIONS (Continued) - PAGE 1.47 TURBINE BYPASS SYSTEM RESPONSE TIME.......................... 1-9 1.48 UNIDENTIFIED LE KAGE......................................... 1-9 1.49 UNRESTRICTED AREA............................................ 1-9
; 1.50 VENTILATION EXHAUST TREATMENT. SYSTEMS........................ 1-9 1.51 VENTING...................................................... 1-9 l
, Table 1.1, Surveillance Frequency Notation........................ 1-10 i Table 1.2, Operational Conditions................................. 1-11 i i i i 1 i i i-i i 1 1 1 1 PERRY - UNIT 1 iii , g pm.r- 9m-mypf g 9 ,-,_y_, -9w7+W---97+.-7,y-4- eW- F-1+-y , a, -*w,-.-.e-veg , ,,-_,g,_, . . ,,,m.,,w q ,y,,,u , , _ ,,,y,,,y,,...-,p,,,, .,.,,,g,g_..,.m.-,gg,7.,,, p
SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION PAGE 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low Flow..................... 2-1 THERMAL. POWER, High Pressure and High Flow.................. 2-1 Reactor Ccolant System Pressure............................. 2-1 Reactor Vessel Water Level.................................. 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 Flow..................... B 2-1 THERMAL POWER, High Pressure and High Flow.................. B 2-2 Bases Table B 2.1.2-1 Uncertainties Used In The Determination Of The Fuel Cladding Safety Limit............ B 2-3 Bases Table B 2.1.2-2 Nominal Values Of Parameters Used In The Statistical Ana-lysis Of Fuel Cladding Integrity Safety Limit........ .. B 2-4 Reactor Coolant System Pressure............................. B 2-5 Reactor Vessel Water Level............ ..................... B 2-5 2.2 LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints.... ..... B 2-6 O PERRY - UNIT 1 iv
C d 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 Scram Accumulators........................... 3/4 1-8 Control Rod Drive Coupling............................... 3/4 1-10 Control Rod Position Indication.......................... 3/4 1-12 Control Rod Drive Housing Support........................ 3/4 1-14 Q 3/4.1.4 CONTROL R00 PROGRAM CONTROLS Control Rod Withdrawa1................................... 3/4 1-15 Rod Pattern Control System............................... 3/4 1-16 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM............................ 3/4 1-18 Figure 3.1.5-1 Sodium Pentaborate Solution i
Concentration / Volume Requirements........................ 3/4 1-20 3/4.2 POWER' DISTRIBUTION LIMITS l 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE............... 3/4 2-1 l Figure 3.2.1-1 Maximum Average Planar Linear Heat Generation Rate (MAPLHGR) Versus Average Planar Exposure Initial Core Fuel Types P85RB219............ 3/4 2-2 l Figure 3.2.1-2 Maximum Average Planar Linear Heat l Generation Rate (MAPLHGR) Versus Average Planar Exposure Initial Core Fuel Types,P85RB176............ 3/4 2-3 PERRY - UNIT 1 v .-
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LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE POWER DISTRIBUTION LIMITS (Continued) Figure 3.2.1-3 Maximum Average Planar Linear Heat Generation Rate (MAPLHGR) Versus Average Planar Exposure Initial Core Fuel Types P85RB071........... 3/4 2-4 3/4 2.2 APRM SETP0INTS.......................................... 3/4 2-5 3/4 2.3 MINIMUM CRITICAL POWER RATI0............................ 3/4 2-6 Figure 3.2.3-1 MCPR .............................. 3/4 2-7 f Figure 3.2.3-2 MCPRp ........................ ..... 3/4 2-8 3/4.2.4 LINEAR HEAT GENERATION RATE............................. 3/4 2-9 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 Table 4.3.1.1-1 Reactor Protection System Instrumentation Surveillance Requirements........... .......... 3/4 3-7 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION. . . . . . . . . . . . . . ...... 3/4 3-9 Table 3.3.2-1 Isolation Actuation Instrumentation..................... 3/4 3-11 Table 3.3.2-2 Isolation Actuation Instrumentation Setpoints........... 3/4 3-17 Table 3.3.2-3 Isolation System Instrumen-tation Response Time. . . . . . . . . . . . . . . . 3/4 3-21 Table 4.3.2.1-1 Isolation Actuation Instrumen-tation Surveillance Requirements...................... 3/4 3-23 0 ' PERRY - UNIT 1 vi
,m LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS (v )
SECTION PAGE 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION......................................... 3/4 3-27 Table 3.3.3-1 Emergency Core Cooling System Actuation Instrumentation........... 3/4 3-28 Table 3.3.3-2 Emergency Core Cooling System Actuation Instrumentation Setpoints........................... 3/4 3-32 Table 3.3.3-3 Emergency Core Cooling System Response Times...................... 3/4 3-35 Table 4.3.3.1-1 Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements......... 3/4 3-37 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS Recirculation Pump Trip System Instrumentation..... 3/4 3-40 [h Table 3.3.4.1-1 ATWS Recirculation Pump Trip (/ System Instrumentation............ 3/4 3-41 Table 3.3.4.1-2 ATWS Recirculation Pump Trip System Instrumentation Setpoints......................... 3/4 3-42 Table 4.3.4.1-1 ATWS Recirculation Pump Trip Instrumentation Surveillance Requirements...................... 3/4 3-43 End-of-Cycle Recirculation Pump Trip System Instrumentation......................................... 3/4 3-44 Table 3.3.4.2-1 End-of-Cycle Recirculation Pump Trip System Instrumentation....... 3/4 3-46 Table 3.3.4.2-2 End-of-Cycle Recirculation Pump Trip System Setpoints............. 3/4 3-47 Table 3.3.4.2-3 End-0f-Cycle Recirculation Pump Trip System Response Time......... 3/4 3-48 Table 4.3.4.2.1-1 End-0f-Cycle Recirculation Pump Trip System Surveillance O Requirements.. ................. 3/4 3-49 i i C/ PERRY - UNIT 1 vii ,.
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.3.5 . REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION......................................... 3/4 3-50 Table 3.3.5-1 Reactor Core Isolation Cooling System Actuation Instrumenta-tion................................ 3/4 3-51 Table 3.3.5-2 Reactor Core Isolation Cooling System Actuation Instrumentation Setpoints........................... 3/4 3-53 Table 4.3.5.1-1 Reactor Core Isolation Cooling System Actuation Instrumentation Surveillance Requirements.......... 3/4 3-54 3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION....................... 3/4 3-55 Table 3.3.6-1 Control Rod Block Instrumenta-tion................................. 3/4 3-56 Table 3.3.6-2 Control Rod Block Instrumenta-tion Setpoints....................... 3/4 3-58 Table 4.3.6-1 Control Rod Block Instrumenta-tion Surveillance Requirements....... 3/4 3-59 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation.................... 3/4 3-61 Table 3.3.7.1-1 Radiation Monitoring Instrumentation................... 3/4 3-62 Table 4.3.7.1-1 Radiation Monitoring Instrumentation Surveillance Requirements...................... 3/4 3-65 Seismic Monitoring Instrumentation.......... ........... 3/4 3-67 Table 3.3.7.'2-1 Seismic Monitoring Instrumentation.................. . 3/4 3-68 Table 4.3.7.2-1 Seismic Monitoring Instrumentation Surveillance Requirements....................... 3/4 3-69 O PERRY - UNIT 1 viii
7m V) ( LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE INSTRUMENTATION (Continued) Meteorological Monitoring Instrumentation............... 3/4 3-70 Table 3.3.~7.3-1 Meteorological Monitoring Instrumentation................... 3/4 3-71 Table 4.3.7.3-1 Meteorological Monitoring
-Instrumentation Surveillance Requirements...................... 3/4 3-72 Remote Shutdown System Instrumentation and Controls..... 3/4 3-73 Table 3.3.7.4-1 Remote Shutdown System Instrumentation and Controls...... 3/4 3-74 Table 4.3.7.4-1 _ Remote Shutdown System Instrumentation Surveillance Requirements...................... 3/4 3-76 A Accident Monitoring Instrumentation..................... 3/4 3-77 Table 3.3.7.5-1 Accident Monitoring Instrumen-tation............................ 3/4 3-78 Table 4.3.7.5-1 Accident Monitoring Instrumenta-tion Surveillance Requirements... 3/4 3-80 Source Range Monitors................................... 3/4 3-81 Traversing In-Core Probe System......................... 3/4 3-82 Loose-Part Detection System............................. 3/4 3-83 Radioactive Liquid Effluent Monitoring Instrumen-tation.................................................. 3/4 3-84 Table 3.3.7.9-1 Radioactive Liquid Effluent Monitoring Instrumentation........ 3/4 3-85 Table 4.3.7.9-1 Radioactive Liquid Effluent Monitoring Instrumentation Surveillance Requirements......... 3/4 3-87 PERRY - UNIT 1 ix v
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE INSTRUMENTATION (Continued) Radioactive Gaseous Effluent Monitoring Instrumen-tation.................................................. 3/4 3-89 Table 3.3.7.10-1 Radioactive Gaseous Effluent Monitoring Instrumentation....... 3/4 3-9C Table 4.3.7.10-1 Radioactive Gaseous Effluent Monitoring Instrumentation Surveillance Requirements...... . 3/4 3-93 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM...................... 3/4 3-96 3/4.3.9 PLANT SYSTEM ACTUATION INSTRUMENTATION.. ................ 3/4 3-98 Table 3.3.9-1 Plant Systems Actuation Instrumentation..................... 3/4 3-100 Table 3.3.9-2 Plant Systems Actuation Instrumen-tation Setpoints.................... 3/4 3-101 Table 4.3.9.1-1 Plant Systems Actuation Instrumentation Surveillance Requirements...................... 3/4 3-102 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM Recirculation Loops..................................... 3/4 4-1 Figure 3.4.1.1-1 Thermal Power versus Core F10w............................. 3/4 4-3 Jet Pumps............................................... 3/4 4-4 Recirculation Loop Flow...... .. .. . ........... .. .. 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 4-8 O PERRY - UNIT 1 x
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LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS
. SECTION PAGE 3/4 4.3 REACTOR COOLANT SYSTEM LEAKAGE ; Leakage Detection Systems............................... 3/4 4-9
) Operational Leakage..................................... 3/4 4-10 1 Table 3.4.3.2-1 Reactor Coolant System Pressure
. Isolation Valves.................. 3/4 4-12 3/4.4.4 CHEMISTRY............................................... 3/4 4-13 I Table 3.4.4-1 Reactor Coolant System Chemistry . Limits.............................. 3/4 4-15 3/4.4.5 SPECIFIC ACTIVITY....................................... 3/4 4-16 Table 4.4.5-1 Primary Coolant Specific Activity Sample and Analysis Program......... 3/4 4-18 3/4.4.6 PRESSURE / TEMPERATURE LIMITS Reactor Coolant System.................................. 3/4 4-19 i Figure 3.4.6.1-1 Minimum Reactor Pressure Vessel i Metal Temperature Vs. Reactor l
Vessel Pressure.................. 3/4 4-21 Table 4.4.6.1.3-1 Reactor Vessel Material Surveil- e ance Program - Withdrawal . Schedule........................ 3/4 4-22 i Reactor Steam Dome...................................... 3/4 4-23 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES........................ 3/4 4-24 3/4.4.8 STRUCTURAL INTEGRITY.................................... 3/4 4-25 3/4.4.9 RESIDUAL HEAT REMOVAL. Hot Shutdown............................................ 3/4 4-26 Cold Shutdown........................................... 3/4 4-27 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - 0PERATING........................................ 3/4 5-1 l 1 l PERRY - UNIT 1 xi ,
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE EMERGENCY CORE COOLING SYSTEM (Continued) 3/4.5.2 ECCS - SHUTD0WN......................................... 3/4 5-6 3/4.5.3 SUPPRESSION P00L........................................ 3/4 5-8 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity - Operating. . . . . . . . . . . . . . . 3/4 6-1 Primary Containment Integrity - Shutdown................ 3/4 6-2 Primary Contai nment Leakage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-3 Primary Containment Ai r Loc ks. . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-6 MSIV Leakage Control System............................. 3/4 6-8 Containment Structural Integrity........................ 3/4 6,9 Containment Internal Pressure........................... 3/4 6-10 Primary Containment Average Air Temperature............. 3/4 6-11
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Drywell and Containment Purge System.................... 3/4 6-12 Feedwater Leakage Control System........................ 3/4 6-14 3/4.6.2 DRYWELL D rywe l l I n t e g r i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-15 Drywell Bypass Leakage.................................. 3/4 6-16 Drywell Air Lock........................................ 3/4 6-17 Drywel l Structural Integri ty. . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-19 Drywell Internal Pressure............. ................. 3/4 6-20 l Drywell Average Air Temperature......................... 3/4 6-21 l 3/4.6.3 DEPRESSURIZATION SYSTEMS Suppression Poo1..................... .................. 3/4 6-22 l l l PERRY - UNIT 1 xii l
1 I l 1 [m V) LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE CONTAINMENT SYSTEMS (Continued) Containme'nt Spray....................................... 3/4 6-25 i Suppression Pool Cooling................................ 3/4 6-26 Suppression Pool Makeup System.......................... 3/4 6-27 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES................ 3/4 6-28 Table 3.6.4-1 Containment and Drywell Isolation Valves.............................. 3/4 6-30 3/4.6.5 VACUUM RELIEF Containment Vacuum Breakers............................. 3/4 6-42
. Containment Humidity Control............................ 3/4 6-44 Figure 3.6.5.2-1 Containment Average Temperature vs Relative Humidity................ 3/4 6-45 D rywe l l Vac uum B re a ke rs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-46 3/4.6.6 SECONDARY CONTAINMENT i
Secondary Containment Integrity. . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-47 Annulus Exhaust Gas Treatment. System.................... 3/4 6-48 3/4.6.7 ATH0 SPHERE CONTROL Containment Hydrogen Recombiner Systems................. 3/4 6-51 Combustible Gas Mixing System........................... 3/4 6-52 Containment and Drywell Hydrogen Ignition System........ 3/4 6-53 3/4.7 PLANT SYSTEMS 3/4.7.1 COOLING WATER SYSTEMS
- Emergency Service Water System (Loops A, 8, C).......... 3/4 7-1 Emergency Closed Cooling Water System................... 3/4 7-2 lV
\ PERRY - UNIT 1 xiii i
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE. PLANT SYSTEMS (Continued) 3/4.7.2 CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM. . . . . . . . . . . . . 3/4 7-3 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM................... 3/4 7-6 3/4.7.4 SNU8BERS................................................ 3/4 7-8 Figure 4.7.4-1 Sample Plan 2) For Snubber Functional Test.................... 3/4 7-13 3/4.7.5 SEALED SOURCE CONTAMINATION............................. 3/4 7-14 3/4.7.6 MAIN TURBINE BYPASS SYSTEM.............................. 3/4 7-16 3/4.7.7 FUEL HANDLING BUILDING Fuel Handling Building Ventilation System............... 3/4 7-17 Fuel Handling Building Integrity........................ 3/4 7-19 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES A.C. Sources - Operating................................ 3/4 8-1 Tatie 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 8-15 D.C. Sources - Shutdown................................. 3/4 8-16 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS Distribution - Operating................................ 3/4 8-17 Distribution - Shutdown................................. 3/4 8-19 O PERRY - UNIT 1 xiv
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Containment Penetration Conductor Overcurrent Protective 0evices.................................... 3/4 8-21 Table 3.8.4.1-1 Primary Containment Penetration Conductor Overcurrent Protective 0evices........................... 3/4 8-23 Reactor Protection System Electric Power Monitoring..... 3/4 8-25 3/4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH..................................... 3/4 9-1
~3/4.9.2 INSTRUMENTATION......................................... 3/4 9-3 3/4.9.3 CONTROL R00 P0SITION.................................... 3/4 9-5 3/4.9.4 DECAY TIME.............................................. 3/4 9-6 3/4.9.5 C0MUNICATIONS.......................................... 3/4 9-7 3/4.9.6 REFUELING PLATF0RM...................................... 3/4 9 :
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I 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE POOL, NEW FUEL STORAGE VAULTS, AND UPPER CONTAINMENT P00L...................... 3/4 9-9 3/4.9.8 WATER LEVEL - REACTOR VESSEL............................ 3/4 9-10 $ 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE AND' UPPER ! CONTAINMENT P00LS....................................... 3/4 9-11
- 3/4.9.10 CONTROL R00 REMOVAL.
Single Control Rod Remova1.............................. 3/4 9-12 Multiple Control Rod Remova1............................ 3/4 9-14 i 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION i i High Water Leve1........................................ 3/4 9-16 , Low Water Leve1......................................... 3/4 9-17 3/4.9.12 INCLINED FUEL TRANSFER SYSTEM........................... 3/4 9-18 ! PERRY - UNIT 1 xv l I
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY........................... 3/4 10-1 3/4.10.2 R0D PATTERN 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 TRAINING STARTUPS....................................... 3/4 10-5 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 Radwaste Treatment System........................ 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 Gaseous Radwaste (Offgas) Treatment..................... 3/4 11-14 Ventilation Exhaust Treatment Systems................... 3/4 11-15 Explosive Gas Mixture............................ ...... 3/4 11-16 Main Condenser.......................................... 3/4 11-17 PERRY - UNIT 1 xvi-
E g LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS
-s SECTION PAGE RADI0 ACTIVE EFFLUENTS (Continued) 3/4.11.3 SOLID RADWASTE TREATMENT................................ 3/4 11-18 3/4.11.4 TO TA L 00 S E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 11-20 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MONITORING PR0 GRAM...................................... 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 Radio-activity Concentrations In i 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 C/ 3/4.12.3 INTERLA80RATORY COMPARISON PR0 GRAM...................... 3/4 12-14 i
4 4 l l l l O PERRY - UNIT 1 xvii
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,8ASES SECTION PAGE 3/4.0 APPLICABILITY............................................ B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN...................................... 8 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES.................................. B 3/4 1-1 3/4.1.3 CO NT RO L R0 D S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3 /4 1- 2 3/4.1.4 CONTROL R0D PROGRAM CONTR0LS......................... 8 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 R AT E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 3 /4 2 - 1 Bases Table 8 3/4 2.1-1 Significant Input Para-meters to the Loss-Of-Cooling Accident Analysis................ B 3/4 2-3 3/4.2.2 APRM SETP0INTS......................... ............. 8 3/4 2-2 3/4.2.3 MINIMUM CRITICAL POWER RATI0.......................... B 3/4 2-4 Bases Figure B 3/4 2.3-1 Power to Flow Operating Map................... 8 3/4 2-6 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 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 3/4.3.6 CONTROL R00 BLOCK INSTRUMENTATION.............. .. .. 8 3/4 3-4 PERRY - UNIT 1 xviii
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- BASES I- SECTION PAGE i
INSTRUMENTATION (Continued)
- 3/4.3.7 MONITORING INSTRUMENTATION 3 Radiation Monitoring Instrumentation.................... B 3/4 3-4
? Seismic Monitoring Instrumentation...................... B 3/4 3-4
- Meteorological Monitoring Instrumentation............... B 3/4 3-4
- i Remote Shutdown System Instrumentation and Controls..... B 3/4 3-5
, Accident Monitoring Instrumentation..................... B 3/4 3-5 t ! Source Range Monitors................................... B 3/4 3-5 } Traversing In-Core Probe System......................... B 3/4 3-5 > 1 t Loose-Part Detection System............................. B 3/4 3-6 ! Radioactive Liquid Effluent Monitoring i Instrumentation......................................... B 3/4 3-6 i Radioactive Gaseous Effluent Monitoring
- Instrumentation......................................... B 3/4 3-6
i 3/4.3.8 TURBINE OVERSPEF0 PROTECTION SYSTEM..................... B 3/4 3-6 3/4.3.9 PLANT SYSTEMS ACTUATION INSTRUMENTATION................. B 3/4 3-6 ! }; Bases Figure B 3/4 3-1 Reactor Vessel Water j Leve1...................... 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 i
1 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE l l Leakage Detection Systems............................... B 3/4 4-3 i l Operational Leakage..................................... B 3/4 4-3 1 3/4.4.4 CHEMISTRY............................................... B 3/4 4-4 PERRY - UNIT 1 xix l
1 BASES SECTION PAGE REACTOR COOLANT SYSTEM (Continued) 3/4.4.5 SPECIFIC ACTIVITY....................................... 8 3/4 4-4 3/4.4.6 PRESSURE / TEMPERATURE LIMITS............................. 8 3/4 4-5 Bases Table 8 3/4 4.6-1 Reactor Vessel Toughness................. 8 3/4 4-7 Bases Figure 8 3/4 4.6-1 Fast Neutron Fluence (E>l MeV) At 1/4 T As A Function of Service Life...................... 8 3/4 4-8 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES.. ..................... 8 3/4 4-6 3/4.4.8 STRUCTU RA L INTEG R I TY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 3/4 4-6 3/4.4.9 RESIDUAL HEAT REM 0 VAL................................... 8 3/4 4-6 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTD0WN................. 8 3/4 5-1 3/4.5.3 SUPPRESSION P00L........................................ 8 3/4 5-2 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity........................... 8 3/4 6-1 Primary Containment Leakage............................. 8 3/4 6-1 Containment Air Locks............................ ...... B 3/4 6-1 MSIV Leakage Control System............................. 8 3/4 6-2 Containment Structural Integrity........................ 8 3/4 6-2 Containment Internal Pressure............... ........... 8 3/4 6-2 Containment Average Air Temperature..................... 8 3/4 6-2 Drywell and Containment Purge System.................... 8 3/4 6-2 Feedwater Leakage Control System............. ......... B 3/4 6-3 PERRY - UNIT 1 xx
BASES SECTION PAGE CONTAINMENT SYSTEMS (Continued) 3/4.6.2 DRYWELL Drywell Integrity....................................... B 3/4 6-3 Drywell Bypass Leakage.................................. B 3/4 6-3 Drywell Air Lock........................................ B 3/4 6-3 Drywell Structural Integrity............................ B 3/4 6-4 Drywell Internal Pressure............................... B 3/4 6-4 Drywell Average Ai r Temperature. . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 6-4 3/4.6.3' DEPRESSURIZATION SYSTEMS................................ B 3/4 6-4 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES................ B 3/4 6-5 3/4.6.5 VACUUM RELIEF........................................... B 3/4 6-6 {' . 3/4.6.6 SECONDARY CONTAINMENT................................... B 3/4 6-6 3/4.6.7 ATMOSPHERE CONTR0L...................................... B 3/4 6-7 3/4.7 PLANT SYSTEMS - 1 3/4.7.1 COOLING WATER SYSTEMS................................... B 3/4 7-1 3/4.7.2 CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM............. B 3/4 7-1 i ! 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM................... B 3/4 7-1 [ 3/4.7.4 SNUBBERS................................................ B 3/4 7-2 r ! 3/4.7.5 SEALED SOURCE CONTAMINATION............................. B 3/4 7-3 l 3/4.7.6 MAIN TURBINE BYPASS SYSTEM.............................. B 3/4 7-4 [ 3/4.7.7 FUEL HANDLING BUILDING.................................. B 3/4 7-4 PERRY - UNIT 1 xxi '" l
BASES SECTION PAGE 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 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 R0D P0SITION................................... B 3/4 9-1 3/4.9.4 DECAY TIME............. .......... .................... B 3/4 9-1 3/4.9.5 COMMUNICATIONS...................... ................... B 3/4 9-1 3/4.9.6 R E F U E L I NG P LAT F 0 RM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 9-1 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE POOL, NEW FUEL STORAGE VAULTS, AND UPPER CONTAINMENT 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 AND UPPER CONTAINMENT P0OLS.. 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 3/4.9.12 INCLINED FUEL TRANSFER SYSTEM........................... B 3/4 9-2 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 TRAINING STARTUPS....................................... B 3/4 10-1 O PERRY - UNIT 1 xxii
h v BASES S s SECTION PAGE 3/4.11 RADI0 ACTIVE EFFLUENTS 3/4.1L 1 LIQUID EFFLUENTS Concentration...................'..'s.s................... B 3/4 11-1 Dose....... ............................................ B 3/4 11-1 Liquid Radwaste Treatment System........................ 8 3/4 11-2 Liquid Holdup Tanks..................................... 8 3/4 11-2 3/4.11.2 GASEOUS EFFLUENTS Dose Rate............................................... B 3/4 11-3 Dose - Noble Gases...................................... 8 3/4 11-3' Dose - Iodine-131, Iodine-133, Tritium, and Radionuclides in Particulate Form....................... 8 3/4 11-4 Gaseous Radwaste Treatment (Offgas) System and-Ventilation Exhaust Treat 1mnt Systems. . . . . . . . . . . . . . . . . . . 8 3/4 11-5 Explosive Gas Mixture................................... 8 3/4 11-5 Main Condenser....................................,...... 8 3/4 11-5 3/4.11.3 SOLID RADI0 ACTIVE WASTE.................................; 8 3/4 11-6 3/4.11.4 TOTAL D0SE......................... .................... 83/411-6
- 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING ,
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- 3/4.12.1 MONITORING PR0 GRAM...................................... B 3/4 12-1
! 3/4.12.2 LAND USE CENSUS......................................... B 3/4 12-1" i , 3/4.12.3 INTERLABORATORY COMPARISON PR0 GRAM...................... B 3/4 12-2 - f i [ , ) ! 3 4 i PERRY - UNIT 1 xxiii ,, } _ .___-_L.__.._._ _.._.._ ___ ____ _ _ _ _ _ , . . ._
DESIGN FEATURES SECTION PAGE 5.1 SITE Exclusion Area, Unrestricted Area for Liquid Effluents and Si te Boundary for Gaseous Ef fluents. . . . . . . . . . . . . . . . . . . . . 5-1 Figure 5.1.1-1 Exclusion Area, Unrestricted Area for Liquid Effluents and Site Boundary for Gaseous 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............... ................ ....... 5-4 5.3 REACTOR CORE Fuel Assemblies................................ ............ 5-4 Control Rod Assemblies......................... ....... .... 5-4 5.4 REACTOR COOLANT SYSTEM Design Pressure and Temperature.................... ......... 5-4 Volume.................. ......................... ..... .... 5-5 5.5 METEOROLOGICAL TOWER LOCATION Figure 5.1.1-1 Exclusion Area, Unrestricted Area for Liquid Effluents and Site Boundary for Gaseous Effluents..................................... ......... 5-6 5.6 FUEL STORAGE Criticality.................. .............. .. ............. 5-5 Drainage...................... .................. .. ........ 5-5 Capacity............ .............. . ........ ....... .. . 5-5 5.6 COMPONENT CYCLIC OR TRANSIENT LIMIT..... .. . ............. 5-5 Table 5.6.1-1 Component Cyclic or Transient Limits.... 5-6 PERRY - UNIT 1 xxiv
m i ADMINISTRATIVE CONTROLS d SECTION PAGE i
- 6.1 RESPONSIBILITY............................................... 6-1 6.2 ORGANIZATION................................................. 6-1 6.2.1 C o rp o ra t e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Figure 6.2.1-1 Corporate Organization............. 6-3 6.2.2 Unit Staff.............................................. 6-1 Figure 6.2.2-1 Unit Organization.................. 6-4 Table 6.2.2-1 Minimum Shift Crew Composition......................... 6-6 6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP Function .............................................. 6-7 Composition............................................ 6-7
') Responsibilities....................................... 6-7 J
Records................................................ 6-7 6.2.4 SHIFT TECHNICAL ADVIS0R................................ 6-7 6.3 UNIT STAFF QUALIFICATIONS................................... 6-7 4 6.4 TRAINING.................................................... 6-8 6.5 REVIEW AND AUDIT 6.5.1 PLANT OPERATIONS REVIEW COMMITTEE (PORC) Function ....................................... ...... 6-8 1 l Composition ........................................... 6-8 Alternates.......................................... .. 6-8 Meeting Frequency ..................................... 6-8 Quorum................................................. 6-8 Responsibilities ...................................... 6-9 , ' O l Records................................................ 6-10 - PERRY - UNIT 1. xxv
ADMINISTRATIVE CONTROLS SECTION PAGE 6.5.2 NUCLEAR SAFETY REVIEW COMMITTEE (NSRC) Function .............................................. 6-10 Composition ........................................... 6-11 Alternates............................................. 6-11 Consultants............................................ 6-11 Meeting Frequency...................................... 6-11 Quorum................................................. 6-11 Review................................................. 6-12 Audits................................................. 6-12 Records............................ ................... 6-13 6.5.3 TECHNICAL REVIEW AND CONTROL ACTIVITIES................ 6-14 6.6 REPORTABLE EVENT ACTI0N..................................... 6-15 6.7 SAFETY LIMIT VIOLATION...................................... 6-15 6.8 PROCEDURES, INSTRUCTIONS AND PROGRAMS................. ..... 6-16 6.9 REPORTING REQUIREMENTS 6.9.1 ROUTINE REPORTS .................. ................ 6-17 l Startup Report......................................... 6-17 Annual Reports ........................................ 6-18 l Annual Radiological Environmental Operating Report. ... 6-18 l ! Semiannual Radioactive Effluent Release Report......... 6-19 Monthly Operating Reports........ ..................... 6-21 l 6.9.2 SPECIAL REPORTS.... .. ...... ....... ................. 6-21 l 6.10 RECORD RETENTION......... .... ......... ... ........ .... 6-21 6.11 RADIATION PROTECTION PR0 GRAM................... ........... 6-23 l PERRY - UNIT 1 xxvi l
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- ADMINISTRATIVE CONTROLS 1
Jl SECTION PAGE t 6.12 HIGH RADIATION AREA........................................ 6-23 6.13 PROCESS CONTROL PROGRAM (PCP).............................. 6-24 )
-6.14 0FFSITE DOSE CALCULATION MANUAL (0DCM)..................... 6-25 l i
3 6.15 MAJOR CHANGES TO RADIOACTIVE WASTE TREATMENT' SYSTEMS....... 6-25 l 1 l 4- f i 1 i-1 i , i f i i i t i i 4e , I 4 4 4 i i f l , t L F , t [. t
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4 SECTION 1.0 l 1 i l DEFINITIONS , l f I. a l I i ! l 1 i e I I O ! I B _--.,_v.n. . . . , _ _ , _ _ , _ _ , . . . _ , . , , _ , , , , . _ . ~ . - , _ , . . , . , , _ , _ ___
1.0 DEFINITIONS A The following 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 w I 1. 4 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the I channel 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 pos-sible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameter. l CHANNEL FUNCTIONAL TEST
- 1. 6 A CHANNEL FUNCTIONAL TEST shall be:
- a. Analog 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 - the injection of a simulated signal into the sensor to verify OPERABILITY including alarm and/or trip functions.
. O) l4b The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total channel steps such that the entire channel is tested. PERRY - UNIT 1 1-1
DEFINITIONS CORE ALTERATION 1.7 CORE ALTERATION si all 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 comple-tion of the movement of a component to a safe conservati'te position. CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY 1.8 The CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CHFLPD) shall be the 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." i DRYWELL INTEGRITY l 1.11 ORYWELL INTEGRITY shall exist when: , a. All drywell penetrations required to be closed during accident I conditions are either:
- 1. Capable of being closed by an OPERABLE automatic isolation l system, or l
- 2. Closed by at least one manual valve, blind flange, or deactivated automatic valve secured in its closed position, except as provided in Table 3.6.4-1 of Specification 3.6.4.
- b. The drywell equipment hatch is closed and sealed.
- c. The drywell head is installed and sealed.
- d. The drywell air lock is in compliance with the requirements of Specification 3.6.2.3.
- e. The drywell leakage rates are within the limits of Specification 3.6.2.2.
PERRY - UNIT 1 1-2
i DEFINITIONS ORYWELL INTEGRITY (continued)
- f. The suppression pool is in compliance with the requirements of Specification 3.6.3.1.
- g. The sealing mechanism associated with each drywell penetration; e.g.,
- welds, bellows or 0-rings, is OPERA 8LE.
i , E-AVERAGE DISINT'EGRATION ENERGY 1 ! 1.12 I 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 t non-iodine activity in the coolant. ' EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME ; 1.13 The EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME shall be that time " interval from when the monitored parameter exceeds its ECCS actuation setpoint i 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 dis-charge 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. END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME i ' 1.14 The END-OF-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:
i l a. Turbine stop valves, and i b. Turbine control valves. The response time may be measured by any series of sequential. overlapping or total steps such that the entire response t'~a is measured. FRACTION OF LIMITING POWER DENSITY l 1.15 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 j . type. 1 i FRACTION OF RATED THERMAL POWER 1.16 The FRACTION OF RATED THERMAL POWER (FRTP) shall be the measured THERMAL POWER divided by the RATED THERMAL POWER. PERRY - UNIT 1 1-3 u__ , _ _ . - _ , _ __
DEFINITIONS FREQUENCY NOTATION 1.17 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1. FUEL HANDLING BUILDING INTEGRITY 1.18 FUEL HANDLING BUILDING (FHB) INTEGRITY shall exist when:
- a. The doors in each access to the 620 foot elevation of the FHB are closed, except for normal entry and exit.
- b. The FHB railroad track door is closed.
- c. The fuel handling area floor hatches are in place.
- d. The FHB ventilation system is in compliance with Specification 3.7.9.1.
- e. The shield blocks are installed adjacent to the Shield Building.
GASEOUS RADWASTE TREATMENT (OFFGAS) SYSTEM 1.19 The GASEOUS RADWASTE TREATMENT (0FFGAS) SYSTEM is the system designed and installed to reduce radioactive gaseous effluents by collecting primary coolant system offgasses from the main condenser evacuation system and provid-ing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment. IDENTIFIED LEAKAGE 1.20 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 drywell atmosphere from sources that are both specifically located and known either not to interfere with the I operation of the leakage detection systems or not to be PRESSURE BOUNDARY LEAKAGE.
ISOLATION SYSTEM RESPONSE TIME 1.21 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. PERRY - UNIT 1 1-4
DEFINITIONS i LIMITING CONTROL ROD PATTERN l 1.22 A LIMITING CONTROL ROD 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. LINEAR HEAT GENERATION RATE , 1.23 LINEAR HEAT GENERATION RATE (LHGR) shall be the heat generation per unit , length of fuel rod. It is the integral of the heat flux over the heat transfer area associated with the unit length. LIQUID RADWASTE TREATMENT SYSTEM 1.24 The LIQUID RADWASTE TREATMENT SYSTEM is any process or control equipment used to reduce the amount or concentration of liquid radioactive materials ] prior to their discharge to UNRESTRICTED AREAS. It involves all the installed ' and available liquid radwaste management system equipment, as well as their controls, power instrumentation, and services that make the system functional. LOGIC SYSTEM FUNCTIONAL TEST 1.25 A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all logic components, i.e., all relays and contacts, all trip units, solid state logic elements, etc, of a logic circuit, from sensor through and including the actuated device, to g verify OPERABILITY. The LOGIC SYSTEM FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total system steps such that the entire i logic system is tested. MEMBER (S) 0F THE PUBLIC 1.26 MEMBER (S) 0F THE PUBLIC shall include all persons who are not occupa-tionally associated with the plant. This category does not include employees of the utility, its contractors, or vendors. Also excluded from this category
- are persons who enter the site to service equipment or to make deliveries.
This category does include persons who use portions of the. site for recreational, occupational, or other purposes not associated with the plant. MINIMUM CRITICAL POWER RATIO 1.27 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be the smallest CPR which exists in the core. , OFFSITE DOSE CALCULATION MANUAL (ODCM) 1.28 The OFFSITE DOSE CALCULATION MANUAL shall contain the methodology and parameters used in the calculation of offsite doses due to radioactive gaseous and liquid effluents, in the calculation of gaseous and liquid effluent moni -
- toring alarm / trip setpoints, and in the conduct of the radiological environmental monitoring program.
I i PERRY - UNIT 1 1-5
- -, ~~ --, ---r - - . -m- w , ,
DEFINITIONS OPERABLE - OPERABILITY 1.29 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 1.30 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 1.31 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 1.32 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 1.33 PRIMARY CONTAINMENT INTEGRITY shall exist when:
- a. All containment penetrations required to be closed during accident conditions are either:
- 1. Capable of being closed by an OPERABLE containment automatic isolation system, or
- 2. Closed by at least one manual valve, blind flange, or deacti-vated automatic valve secured in its closed position, except as provided in Table 3.6.4-1 of Specification 3.6.4.
l
- b. The containment equipment hatch is closed and sealed.
- c. Each containment air lock is in compliance with the requirements of Specification 3.6.1.3.
- d. The containment leakage rates are in compliance with the requirements of Speci fication 3. 6.1.2.
- e. The suppression pool is in compliance with the requirements of Specification 3.6.3.1.
l l PERRY - UNIT 1 1-6
DEFINITIONS
- f. The sealing mechanism associated with each primary containment penetration; e.g., welds, bellows or 0-rings, is OPERABLE.
PROCESS CONTROL PROGRAM (PCP) 1.34 The PROCESS CONTROL PROGRAM shall contain the current formulas, sampling, analyses, tests, and determinations to be made to ensure that the processing and packaging of solid radioactive wastes based on demonstrated processing of actual or simulated wet solid wastes will be accomplished in such a way as to assure compliance with 10 CFR Part 20, 10 CFR Part 61, 10 CFR Part 71 and Federal and State regulations, burial ground requirements and other requirements governing the disposal of the radioactive waste. PURGE - PURGING 1.35 PURGE or PURGING is 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 required to purify the confinement. RATED THERMAL POWER 1.36 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 3579 MWT. 1 REACTOR PROTECTION SYSTEM RESPONSE TIME 1.37 REACTOR PROTECTION SYSTEM RESPONSE TIME shall be the time interval from 'i 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 1.38 A REPORTABLE EVENT shall be any of those conditions specified in Sections 50.72 and 50.73 to 10 CFR Part 50. i R00 DENSITY l 1.39 R00 DENSITY shall be the number of control rod notches inserted as a fraction of the total number of control rod notches. All rods fully inserted is equivalent to 100% ROD DENSITY. SECONDARY CONTAINMENT INTEGRITY 1.40 SECONDARY CONTAINMENT INTEGRITY shall exist when:
- a. All penetrations terminating in the annulus and required to be closed during accident conditions are either:
N PERRY - UNIT 1 1-7 l l
DEFINITIONS
- 1. Capable of being closed by an OPERABLE containment automatic isolation system, or
- 2. Closed by at least one manual valve, blind flange, or deactivated automatic valve, as applicable secured in its closed position.
- b. The containment equipment hatch is closed and sealed and the shield blocks are installed adjacent to the Shield Building.
- c. The door in each access to the annulus is closed, except for normal entry and exit.
- d. The sealing mechanism associated with each Shield Building penetration, e.g., welds, bellows or 0-rings, is OPERABLE.
- e. The pressure within the secondary containment is less than or equal to the value required by Specification 4.6.6.1.a., except for normal entry and exit to the annulus.
- f. The Annulus Exhaust Gas Treatment System is in compliance with the requirements of Specification 3.6.6.2.
SHUTDOWN MARGIN 1.41 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 condition; cold, i.e. 68*F; and xenon free. SITE BOUNDARY 1.42 The SITE BOUNDARY shall be that line beyond which the land is neither owned, nor leased, nor otherwise controlled by the licensee. SOLIDIFICATION 1.43 SOLIDIFICATION shall be the conversion of wet wastes into a form that meets shipping and burial ground requirements. SOURCE CHECK 1.44 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 1.45 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.
PERRY - UNIT 1 1-8
DEFINITIONS
- b. The testing of one system, subsystem, train or other designated component at the beginning of each subinterval.
THERMAL POWER 1.46 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant. TURBINE BYPASS SYSTEM RESPONSE TIME 1.47 The TURBINE BYPASS SYSTEM RESPONSE TIME consists of two separate time intervals: a) time from initial ~ movement of the main turbine stop valve or control valve until 80% of 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 1.48 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE. UNRESTRICTED AREA l//~S 1.49 An UNRESTRICTED AREA shall be any area at or beyond the SITE BOUNDARY access to which is not controlled by the licensee for purposes of protection ~of l MEMBERS OF THE PUBLIC from exposure to radiation and radioactive materials, or any area within the SITE BOUNDARY used for residential quarters or for industrial, commercial, institutional, and/or recreational purposes. VENTILATION EXHAUST TREATMENT SYSTEMS 1.50 A VENTILATION EXHAUST TREATMENT SYSTEM is any system designed and , installed to reduce gaseous radioiodine or radioactive material in particulate l form in effluents by passing ventilation or vent exhaust gases through charcoal adsorbers and/or HEPA filters for the purpose of removing iodines or particulates from the gaseous exhaust stream prior to the release to 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 provided l the ESF system is not utilized to treat normal releases. 1 VENTING 1.51 VENTING is 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 l imply a VENTING process. O PERRY - UNIT 1 1-9 l
TABLE 1.1 SURVEILLANCE FREQUENCY NOTATION l NOTATION FREQUENCY S At least once per 12 hours. 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. l SA At least once per 184 days. A At least once per 366 days. i R At least once per 18 months (550 days). S/U Frior to each reactor startup. P Completed prior to each release-
-N.A. Not applicable.
I l i e PERRY - UNIT 1 1-10
TABLE 1.2 p l 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 3HUTDOWN Shutdown #'##'*** 1 200 F
- 5. REFUELING
- Shutdown or Refuel ***# 1 140 F F
(
#The reactor mode switch may be placed in the Run, Startup/ Hot Standby, or Refuel 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 Speci ficatior. 3.9.10.1.
- Fuel il the reactor vessel with the vessel head closure bolts less than fully tansioned 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 provided that the one-rod-out interlock is OPERABLE.
1 1 PERRY - UNIT 1 1-11 1
I l i l l i l I { i I SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS I I l l 1
. _ . . _ _ . . - - =_ _ -
2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure 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 reactor 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. i l 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 j 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 i
vessel steam dome, above 1375 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. b i PERRY - UNIT 1 2-1 l
- 2. 0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SAFETY LIMITS (Continued)
O REACTOR VESSEL WATER LEVEL 2.1.4 The reactor vessel water level shall be above the top of the active irradiated fuel. APPLICABILITY: OPERATIONAL CONDITIONS 3, 4 and 5 ACTION: With the reactor vessel water level at or below the top of the active ir-radiated fuel, manually initiate the ECCS to restore the water level. Depressurize the reactor vessel, as necessary for ECCS operation. Comply with the requirements of Specification 6.7.1. O O PERRY - UNIT 1 2-2
~~ 2. SAFETY 0 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 the channel inoperab h and apply the applicable 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. O PERRY - UNIT 1 2-3 i l
TABLE 2.2.1-1 m REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS E Q ALLOWABLE
, FUNCTIONAL UNIT TRIP SETPOINT VALUES b
- 1. Intermediate Range Monitor
- a. Neutron Flux-High < 120/125 divisions < 122/125 divisions
~ of full scale of full scale
- b. Inoperative NA NA
- 2. Average Power Range Monitor;
- a. Neutron Flux-High Setdown 5 15% of RATED 5 20% of RATED THERMAL POWER THERMAL POWER
- b. Flow Biased Simulated Thermal Power-High
- 1) Flow Biased 5 0.66 W+48%g, with 5 0.66 W+51%g, with a maximum of a maximum of
- 2) High Flow Clamped 5 111.0% of RATED 5 113.0% of RATED THERMAL POWER THERMAL POWER
- c. Neutron Flux-High < 118.0% of RATED < 120.0% of RATED m THERMAL POWER THERMAL POWER 1 d. Inoperative NA NA
- 3. Reactor Vessel Steam Dome Pressure - High 5 1064.7 psig 5 1079.7 psig
- 4. Reactor Vessel Water Level - Low, Level 3 1 177.7 inches above 2 177.1 inches above top of active fuel
- top of active fuel *
- 5. Reactor Vessel Water Level-High, Level 8 < 219.5 inches above 5 220.1 inches above top of active fuel
- tcp of active fuel *
- 6. Main Steam Line Isolation Valve - Closure 1 8% closed 5 12% closed
- 7. Main Steam Line Radiation - High 5 3.0 x full power 5 3.6 x full power background background
- 8. Drywell Pressure - High 5 1.68 psig 5 1.88 psig
*See Bases Figure B 3/4 3-1. #During the startup test program, the APRM trip setpoint and allowable value may be permitted to be increased to the ME00 values (trip setpoint of 5 0.66 W + 64% and allowable value of 5 0.66 W + 67%).
O O O
A O - s l TABLE 2.2.1-1 (Continued) h REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS 5 ALLOWABLE c: FUNCTIONAL UNIT TRIP SETPOINT VALUES 5 ~
-d 9. Scram Discharge Volume Water Level - High l '
- a. Level Transmitter < 37.9 inches ** ~< 38.87 inches **
j (626' 6.6" elevation) (626' 7.56" elevation)
- b. Float Switches
< 626' 9.87" elevation < 626' 11.5" elevation C11N013A C11N0138 7 626' 10.25" elevation i 626' 11.5" elevation C1]N013C 7 626' 10.87" elevation i 626' 11.5" elevation C11N0130 5626'11.18" elevation 5626'11.5" elevation
- 10. Turbine Stop Valve - Closure < 5% closed < 7% closed -
- 11. Turbine Control Valve Fast Closure, Valve Trip Oil Pressure'- Low 1 530 psig 1 465 psig
- 12. Reactor Mode Switch Shutdown Position NA NA
- 13. Manual Scram NA NA l
i l l 9 I l I l
** Level zero is 623' 4.69" elevation.
i
i 'I i ( l l l-I l s I t BASES FOR SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS i i t w -m - m -n e mw*ww ,- w - -w --w--, - - , , - - - , - - -
i l l 5 f r f i i
- t i $
i ; I f
- - ?
.i i i i , a 4 NOTE The BASES contained in succeeding pages summarize
- j. the reasons for.the specifications in Section 2.0, i but in accordance with 10 CFR 50.36 are not part of :
j these Technical Specifications. I I l l' i . f
- }.
! t l ! I 3 [ 4 i I I L f t f L 6 i t
=
i 2.1 SAFETY LIMITS BASES 1
2.0 INTRODUCTION
The fuel cladding, reactor pressure vessel and primary system piping 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 to occur if the 1.init is not violated. Because fuel damage is not directly 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 conservative 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 barrier is related to its relative freedom from perforations or cracking. Although some corrosion or use related cracking may 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 j significantly above design conditions and the Limiting Safety System Settings. I While fission product migration from cladding perforation is just as measurable ( as that from use related cracking, the thermally caused cladding perforations i signal a threshold beyond which still greater thermal stresses may cause gross i rather than incremental cladding deterioration. Therefore, the fuel cladding Safety Limit is defined with a margin to the conditions which would produce I onset of transition boiling, MCPR of 1.0. These conditions represent a significant departure from the condition intended by design for planned operation. 2.1.1 THERMAL POWER, Low Pressure or Low Flow l The use of the GEXL correlation is not valid for all critical power calculations at pressures below 785 psig or core flows less than 10% of rated i 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 flows will always be greater than 4.5 psi. Analyses show that with a bundle flow of 28 x 103 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 e at pressures.from 14.7 psia to 800 psia indicate that the fuel assembly critical 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. PERRY - UNIT 1 B 2-1
-m._ -~- _ - - --
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 tae 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 uncertainties. 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 condi-tions used in the tests of the data used to develop the correlation. The required input to the statistical model are the uncertainties listed in Bases Table 82.1.2-1 and the nominal values of the core parameters listed in Bases Table 82.1.2-2. The bases for the uncertainties in the core parameters are given in D NED0-20340 and the basis for the uncertainty in the GEXL correlation is given in NED0-10958-Aa . 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. The 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 l 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.
O PERRY - UNIT 1 B 2-2 l
l !~ s Bases Table 82.1.2-1 i (\ UNCERTAINTIES USED IN THE DETERMINATION
- OF THE FUEL CLADDING SAFETY LIMIT
- Standard i
Deviation d Quantity (% of Point) Feedwater Flow 1.76 Feedwater Temperature 0.76 Reactor Pressure 0.5 j Core Inlet Temperature 0.2 Core Total Flow 2.5 Channel Flow Area 3.0 Friction Factor Multiplier 10.0 Channel Friction Factor p Multiplier 5.0 - TIP Readings 6.3 R Factor 1.5 , Critical Power 3.6 i t i I i , The uncertainty analysis used to establish the core wide Safety Limit MCPR is l based on the assumption of quadrant power symmetry for the reactor core. PERRY - UNIT 1 8 2-3
s . Bases Table 82.1.2-2 NOMINAL VALUES OF PARAMETERS USED IN THE STATISTICAL ANALYSIS OF FUEL CLADDING INTEGRITY SAFETY LIMIT l THERMAL POWER 3323 MW ' Core Flow 108.5 M1b/hr Dome Pressure 10I0.4 psig Channel Flow Area 0.1089 ft2 R-Factor High enrichment - 1.043 Medium enrichment - 1.039 Lcw enrichment - 1.030 l 1 O PERRY - UNIT 1 8 2-4
l SAFETY LIMITS (\j BASES l l 2.1.3 REACTOR COOLANT SYSTEM PRESSURE 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 1971 Edition, including Addenda through Winter 1972, which permits a maximum pressure transient of 110%, 1375 psig, of design pressure, 1250 psig. The Safety Limit of 1325 psig, 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 is designed to the ASME Boiler and Pressure Vessel Code, 1974 Edition,' including Addenda through Winter 1975 for the reactor recircu-lation piping, which permits a maximum pressure transient of 120% of design pressure, 1500 psig. The pressure Safety Limit is selected to be the lowest transient overpressure allowed by the applicable codes. 2.1.4 REACTOR VESSEL WATER LEVEL With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the n effect of decay heat. If the water level should drop below the top of the ( active irradiated fuel during this period, the ability to remove decay heat is G) 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. l O PERRY - UNIT 1 8 2-5
- 2. 2 LIMTING SAFETY SYSTEM SETTINGS BASES 2.2.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS The Reactor Protection System instrumentation setpoints specified in 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 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. The Trip Setpoints and allowable values also contain additional margin for instrument accuracy and calibration capability.
- 1. Intermediate Range Monitor, Neutron Flux - High The IRM system consists of 8 chambcrs, 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 also ranged up. The IRM instruments provide for overlap with both the APRM and SRM systems.
For BWR 6 plants, the role of the IRM system in responding to potential Rod Withdrawal Er or (RWE) accidents is greatly diminished due to the use of a dual channel Rod Pattern Control System.
- 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 maneuvers associated with power plant startup. Effects of increasing pressure l at zero or low void content are minor and cold water from sources available i during startup is not much colder than that already in the system. Temperature coefficients are small and control rod patterns are constrained by the RPCS. Of all the possible sources of reactivity input, uniform control rod withdrawal is the most probable cause of significant power increase. 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 O PERRY - UNIT 1 B 2-6 l
LIMITING SAFETY SYSTEM SETTINGS a BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) Average Power Range Monitor (Continued) 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 sys-tem and therefore the monitors respond directly and quickly to changes due to transient operation for the case of the Neutron Flux-High setpoint; 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 trans-fer associated with the fuel. For the Flow Biased Simulated Thermal Power-High 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. tb ]j [ 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 MFLPD 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 pres-sure 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 flux, counteracting the pressure increase. The trip set-ting is slightly higher than the operating pressure to permit normal operation j 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 l 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 trips are bypassed. For a load rejection or turbine trip under these conditions, the l transient analysis indicated an adequate margin to the thermal hydraulic limit. l O(% PERRY - UNIT 1 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. Reactor Vessel Water Level-High A reactor scram from high reactor water level, approximately two feet above normal operating level, is intended to offset the addition of reactivity ef fect associated with the introduction of a significant amount of relatively cold feedwater. An excess of feedwater entering the vessel would be detected by the level increase in a timely manner. This scram feature is only effective when the reactor mode switen is in the Run position because at THERMAL POWER levels below 10% to 15% of RATED THERMAL POWER, the approximate range of power level for changing to the Run position, the safety margins are more than adequate withcut a reactor scram.
- 6. 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.
- 7. 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 l 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 l to prevent spurious trips yet low enough to promptly detect gross failures in l the fuel cladding.
O PERRY - UNIT 1 B 2-8
- , _ - . . ~ - . -. .-.
1 LIMITING SAFETY SYSTEM SETTINGS + BASES i REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) i
- 8. Drywell Pressure-High i High pressure in the drywell .could indicate a break in the primary pressure
- boundary systems. 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 ;
to the primary containment. The trip setting was selected as low as possible i without causing spurious trips. j 9. Scram Discharge Volume Water Level-High
-The scram discharge volume receives.the water displaced by 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 hindered. The reac -
i tor is therefore tripped when the water level has reached a point high enough to indicate that it is indeed filling up, but the volume is still great er.ough to accommodate the water from the movement of Oe rods at pressures below i 65 psig when they are tripped. The trip setpoint for'each scram discharge volume is equivalent to a contained volume of approximately.24 gallons of water.
- 10. 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 resul-tant increase in heat flux is such that adequate thermal margins are maintained i during the worst case transient.
- 11. Turbine Control Valve Fast Closure, Trip Oil Pressure-Low
! The turbine control valve fast closure trip anticipates the pressure, neutron flux, and heat flux increase that could result from fast closure of the , turbine control valves due to load rejection with or without coincident failure of the l 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 20 milliseconds after the start of control valve fast. closure. This is achieved by the action of the fast acting solenoid , i 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 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 a j different valve characteristic from that of the turbine stop valve, combine to j 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.
I PERRY - UNIT l' B 2-9
-LIMITING SAFETY SYSTEM SETTING BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)
- 12. Reactor Mode Switch Shutdown Position The reactor mode switch Shutdown position provides additional manual reactor trip capability.
- 13. Manual Scram The Manual Scram provides manual reactor trip capability. The manual scram function is composed of four push button switches in a one-out-of-two taken twice logic.
O O PERRY - UNIT 1 B 2-10
i SECTIONS 3.0 and 4.0 LIMITING CONDITIONS FOR OTERATION AND SURVEILLANCE REQUIREMENTS l l I l
. ._ - _. .- . - - _ . _ = . -
- 1 d
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 CONDITIONS or d other conditions specified therein; except that upon failure to meet the Limiting Conditions for Gperation, the associated ACTION requirements shall be met. 3.0.2 Noncompliance with'a Specification shall exist when the requirements of the Limiting Condition for Operation and associated ACTION requirements are i 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 initiated l- to place the unit in an OPERATIONAL CONDITION in which the Specificatio'n does
'not apply by placing it, as applicable, in:
- 1. At least STARTUP within the next 6 hours,
- 2. At least HOT SHUTDOWN within the following 6 hours, and
- 3. At least COLD SHUTDOWN within the subsequent 24 hours.
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. 1 Exceptions to these requirements are stated in the individual Specifications. N- 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 met without reliance on provisions contained in the ACTION requirements. This
- provision shall not prevent passage through or to OPERATIONAL CONDITIONS as j required to comply with ACTION requirements. Exceptions to these requirements l are stated in the individual Specifications.
l l e i PERRY - UNIT 1 3/4 0-1 e
APPLICABILITY SURVEILLANCE REQUIREMENTS 4.0.1 Surveillance Requirements shall be met during the OPERATIONAL CONDITIONS or other conditions specified for individual Limiting Conditions 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 intervals 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 Specifications. Surveillance requirements do not have to be performed on inoperable equipment. 4.0.4 Entry into an OPERATIONAL CONDITION or other specified applicable condition 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 Surveil. lance 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 CFR 50, Section 50.55a(g), except where specific written relief has been granted by the Commission pursuant to 10 CFR 50, Section 50.55a(g)
(6) (i).
- b. Surveillance intervals specified in Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda for the inservice l 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 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 Yearly or annually At least once per 366 days PERRY - UNIT 1 3/4 0-2
APPLICABILITY-O) ( ,, 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 inspection and testing activities shall be in addition to other specified Surveillance Requirements.
- e. Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any Technical Specification.
f l PERRY - UNIT 1 3/4 0-3 _ - - _ - - , _, _ _ _ _ _ . _ _ _ _ . _ . _ _ , . . _ . _ - _ _ _ _ _ _ , . _ _ _ _ _ . _ _ _ _ _ _ _ _ . _ _ . . . _ . _ . - - _ - ~ _ . . , _ . . _ _ . _ - - . -
3/4.1 REACTIVITY CONTROL SYSTEMS f
.( 3/4.1.1 SHUTDOWN MARGIN LIMITING CONDITION FOR OPERATION
~ 3.1.1 The SHUTDOWN MARGIN 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.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5. ACTION: With the SHUTDOWN MARGIN less than~specified:
- a. In OPERATIONAL CONDITION 1 or 2, reestablish the required SHUTOOWN MARGIN within 6 hours or be in at least HOT SHUTDOWN within the next
- 12 hours.
i b. In OPERATIONAL CONDITION 3 or 4, immediately verify all insertable control rods to-be inserted and suspend all activities that could reduce the SHUTDOWN MARGIN. In OPERATIONAL CONDITION 4, establish PRIMARY CONTAINMENT INTEGRITY within 8 hours. ( c. In OPERATIONAL CONDITION 5, suspend CORE ALTERATIONS and other l activities that could reduce the SHUTDOWN MARGIN and insert all insertable control rods within 1 hour. Establish PRIMARY CONTAIN-MENT INTEGRITY within 8 hours. SURVEILLANCE REQUIREMENTS < 4 4.1.1 The SHUTDOWN MARGIN shall be determined to be equal to or greater than specified at any time during the fuel cycle:
- a. By measurement, prior to or during the first startup after each refueling.
- b. By measurement, within 500 MWD /T prior to the core average exposure l at which the predicted SHUTDOWN MARGIN, including uncertainties and -
4 calculation biases, is equal to the specified limit.
- c. Within 12 hours after detection of a withdrawn control rod that is immovable, as a result of excessive friction or mechanical interference, 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.
i l
' PERRY - UNIT 1 3/4 1-1
-~ . . . . , _ . - . . - . - , - . _ . , , - - - - - . - _ . , _ - _ , , . . . - , - - , - - - , - . - - , , _ , - , . _ , - . - - . . , - -
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 ROD DENSITY and the predicted ROD 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 1000 MWD /T during POWER OPERATION.
- c. The provisions of Specification 4.0.4 are not applicable.
i l l I I l 9 l PERRY - UNIT 1 3/4 1-2
REACTIVITY CONTROL SYSTEMS O 3/4.1.3 CONTROL ROOS yl CONTROL ROD OPERABILITY LIMITING CONDITION FOR OPERATICJ 3.1.3.1 All control rods shall be OPERABLE. APPLICA8ILITY: ' 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:
l 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 ** 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.
- 2. Comply with Surveillance Requirement 4.1.1.c within 12 hours, or be in at least HOT SHUTDOWN within the next 12 hours.
- 3. Restore the inoperable withdrawn control rod to OPERABLE status 4
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 4 b) Demonstrate the insertion capability of the inoperable withdrawn l 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) Hydraulically by closing the drive water and exhaust water isolation valves.
^The. inoperable control rod may then be withdrawn to a position no further l Q withdrawn than its position when found to be inoperable.
! **May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status. PERRY - UNIT 1 3/4 1-3 f
- - - , - - . . - - - , _ , . . ~ . . . , . . . , - , . . . . . , ,
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. Otherwise, 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 at least one vent valve and one drain valve 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: l a. At least once per 31 days verifying each valve to be open,* and
- b. At least once per 92 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 RPCS, all withdrawn control rods not required to have their directional control valves disarmed electrically l 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.
j *These valves may be closed 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.
PERRY - UNIT 1 3/4 1-4 l l
1 i REACTIVITY CONTROL SYSTEMS
- SURVEILLANCE REQUIREMENTS (Continued)
- 4.1.3.1.3 All control rods shall be demonstrated OPERA 8LE by performance of -
- . Surveillance Requirements 4.1.3.2, 4.1.3.3, 4.1.3.4 and 4.1.3.5.
! 4.1.3.1.4 The scram discharge volume shall be determined OPERA 8LE by l demonstrating: l a. The scram discharge volume drain and vent valves OPERA 8LE at least i 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 i .
j 2. Open when the scram signal is reset. ' j b. Proper level sensor response by performance of a CHANNEL FUNCTIONAL ; ! TEST of the scram discharge volume scram and control rod block level : l instrumentation at least once per 31 days. l l I l I l l l I i t i I i t PERRY - UNIT 1 3/4 1-5 ! \
- l. - - - - . _ - _ - -
REACTIVITY CONTROL SYSTEMS CONTROL R00 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, based on de-energization of the scram pilot valve solenoids. as time zero, shall not exceed the following limits: Maximum Insertion Times to Notch Position (Seconds) Reactor Vessel Dome Pressure (psig)* 43 29 13 950 0.31 0.81 1.44 1050 0.32 0.86 1.57 APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With the maximum scram insertion time of one or more control rods exceeding the maximum scram insertion time limits of Specification 3.1.3.2 as determined by Specification 4.1.3.2.a or b, operation may continue provided that:
- 1. For all " slow" control rods, i.e., those which exceed the limits of Specification 3.1.3.2, the individual scram insertion times do not exceed the following limits:
Maximum Insertion Times to Notch Position (Seconds) Reactor Vessel Dome Pressure (psia)* 43 29 13 950 0.38 1.09 2.09 1050 0.39 1.14 2.22
- 2. For " fast" control rods, i.e., those which satisfy the limits of Specification 3.1.3.2, the average scram insertion times do not exceed the following limits:
Maximum Average Insertion Times to Notch Position (Seconds) Reactor Vessel Dome Pressure (psig)* 43 29 13 950 0.30 0.78 1.40 1050 0.31 0.84 1.53
- 3. The sum of " fast" control rods with individual scram insertion times in excess of the limits of ACTION a.2 and of " slow" control rods does not exceed 7.
- 4. No " slow" control rod, " fast" control rod with individual scram insertion time in excess of the limits of ACTION a.2, or other-wise inoperable control rod occupy adjacent locations in any direction, including the diagonal, to another such control rod.
Otherwise, be in at least HOT SHUTDOWN within 12 hours.
*For intermediate reactor vessel dome pressure, the scram time criteria is :
determined by linear interpolation at each notch position. l PERRY - UNIT 1 3/4 1-6 l
N REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued)
- b. With a " slow" control rod (s) not satisfying ACTION a.1, above:
- 1. Declare the " slow" control rod (s) 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 " slow" control rods declared inoperable. ! Otherwise,'be in at least HOT SHUTDOWN within 12 hours,
- c. With the maximum scram insertion time of one or more control rods exceed-ing the maximum scram insertion time limits of Specification 3.1.3.2 as determined by Specification 4.1.3.2.c, operation may continue provided that:
l 1. " Slow" control rods, i.e., those which exceed the limits of Specification 3.1.3.2, do.not make up more than 20% of the 10% sample of control rods tested.
- 2. Each of these " slow" control rods satisfies the limits of ACTION a.1.
- 3. The eight adjacent control rods surrounding each " slow" control rod are:
! a) Demonstrated through measurement within 12 hours to satisfy the maximum scram insertion time limits of Specification 3.1.3.2, and b) OPERABLE. [ 4. The total number of " slow" control rods, as determined by ' Specification 4.1.3.2.c, when added to the sum of ACTION a.3, as determined by Specification 4.1.3.2.a and b, does not exceed 7. Otherwise, be in at least HOT SHUTDOWN within 12 hours. 4
- d. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS ! 4.1.3.2 The maximum scram insertion time of th'e control rods shall be demonstrated 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 pumps isolated from the accumulators:
- a. For all control rods prior to THERMAL POWER exceeding 40% of RATED l THERMAL POWER following CORE ALTERATIONS or after a reactor j shutdown that is greater than 120 days, i 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 j c. For at least 10% of the control rods, on a rotating basis, at least once per 120 days of POWER OPERATION. t
*The provisions of Specification 4.0.4 'are not applicable for entry into OPERATIONAL CONDITION 2 provided this surveillance is completed prior to
!, entry into OPERATIONAL CONDITION 1. l PERRY - UNIT 1 3/4 1-7
--._-._--_._--_.__._-a - -
REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.1.3.3 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 accumulator is withdrawn, imediately verify that at least one control rod drive pump is operating by inserting at least one withdrawn control rod at least one notch or place the reactor mode switch in the Shutdown position. b) Insert the inoperable control rods and disarm the associated directional control valves either:
- 1) Electrically, or
- 2) Hydraulically by closing the drive water and exhaust water isolatinn 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 scram accumulator inoperable and with no control rod drive pump operating, immediately place the reactor mode switch in the Shutdown position.
I
- 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.
1 PERRY - UNIT 1 3/4 1-8
REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS s 4 4.1.3.3 Each control rod scram accumulator shall be determined OPERABLE:
- a. At least once per 7 days by verifying that the pressure is greater than or equal to 1520 psig unless the control rod is inserted and disarmed or scrammed.
- b. At least once per 18 months by performance of a:
- 1. CHANNEL FUNCTIONAL TEST of the leak detectors, and
- 2. CHANNEL CALIBRATION of the pressure detectors, and verifying an alarm setpoint of 1535 115 psig on decreasing pressure.
l t l 1 i i l I PERRY - UNIT 1 3/4 1-9 ) i
REACTIVITY CONTROL SYSTEMS CONTROL R00 DRIVE COUPLING LIMITING CONDITION FOR OPERATION 3.1.3.4 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 RPCS, insert the control rod drive mechanism 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 drive will not go to the overtravel position. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.
- 2. If recoupling is not accomplished on the first attempt or, if not permitted by the RPCS, then until permitted by the RPCS, declare the control rod inoperable, 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. 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:
- 1. Insert the control rod to accomplish recoupling and verify recoupling 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.
*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.
PERRY - UNIT 1 3/4 1-10
i i REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.3.4 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, i b. Anytime the control rod is withdrawn to the " Full out" position in subsequ6nt operation, and
- c. Following maintenance on or modification to the control rod or j control rod drive system which could have affected the control rod drive coupling integrity.
i 1 PERRY - UNIT 1 3/4 1-11
l REACTIVITY CONTROL SYSTEMS CONTROL R00 POSITION INDICATION LIMITING CONDITION FOR OPERATION 3.1.3.5 At least one control rod position indication system shall be OPERABLE.*** APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:
- a. In OPERATIONAL CONDITION 1 or 2 when the position of any OPERABLE control rod cannot be determined by at least one OPERABLE control rod position indicator, within 1 hour:
- 1. Hove the control rod to a position with an OPERABLE. position indicator, or
- 2. When THERMAL POWER is:
a) Less than or equal to the low power setpoint of the RPCS:
- 1) Declare the control rod inoperable, and
- 2) Verify the position and bypassing of control rods with inoperable " Full-in" and/or " Full-out" position indicators by a second licensed operator or other technically qualified member of the unit technical staff.
b) Greater than the low power setpoint of the RPCS, declare the centrol 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 both position indicators of a withdrawn control rod inoperable, move the control rod to a position with an OPERA 8LE position indicator or insert the control rod.
- c. The provisions of Specification 3.0.? are not applicable.
*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. ***This requirement shall be satisfied if the position of each OPERABLE control rod can be determined by at least one OPERABLE control rod position indicator.
PERRY - UNIT 1 3/4 1-12
REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.3.5 The above required 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, and
- 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.
O O PERRY - UNIT 1 3/4 1-13
REACTIVITY CONTROL SYSTEMS CONTROL ROD DRIVE HOUSING SUPPORT O LIMITING CONDITION FOR OPERATION 3.1.3.6 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 COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.1.3.6 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. O PERRY - UNIT 1 3/4 1-14
)
I
REACTIVITY CONTROL-SYSTEMS 3/4.1.4 CONTROL R00 PROGRAM CONTROLS CONTROL ROD WITH0RAWAL LIMITING CONDITION FOR OPERATION 3.1. 4.1 Control rods shall not.be withdrawn. APPLICA8ILITY: OPERATIONAL' CONDITIONS 1 and 2, when the main turbine bypass valves are not fully closed and THERMAL POWER'is greater than the low power setpoint of the rod pattern control system (RPCS). ACTION: With any control rod withdrawal when the main turbine bypass valves are not fully closed and THERMAL POWER is greater than the low power setpoint of the RPCS, immediately return the control rod (s) to the position prior to control rod withdrawal.
-SURVEILLANCE REQUIREMENTS 4.1.4.1 Control rod withdrawal shall be prevented, when the main turbine bypass valves are not fully closed and THERMAL POWER is greater than the low l power setpoint of the RPCS, and verified by a second licensed operator or l other technically qualified member of the unit technical staff.
i PERRY - UNIT 1 3/4 1-15 l. l.
REACTIVITY CONTROL SYSTEMS R00 PATTERN CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.4.2 The rod pattern control system (RPCS) shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2*#. ACTION:
- a. With the RPCS inoperatie or with the requirements of ACTION b, below, not satisfied and with:
- 1. THERMAL POWER less than or equal to the RPCS low power setpoint, control rod movement shall not be permitted, except by a scram.
- 2. THERMAL POWER greater than the RPCS low power setpoint, control rod withdrawal shall not be permitted.
- b. With an inoperable control rod (s), OPERABLE control rod movement may continue by bypassing the inoperable control rod (s) in the RPCS provided that:
- 1. With one control rod inoperable due to being immovable, as a result of excessive friction or mechanical interference, or known to be untrippable, this inoperable control rod may be bypassed in the rod gang drive system (RGDS) and/or the rod action control system (RACS) provided that the SHUTDOWN MARGIN has been determined to be equal to or greater than required by Specification 3.1.1.
- 2. With up to eight control rods inoperable for causes other than addressed in ACTION b.1, above, these inoperable control rods may be bypassed in the RACS provided that:
a) The control rod to be bypassed is inserted and the directional control valves are disarmed either:
- 1) Electrically, or
- 2) Hydraulically by closing the drive water and exhaust water isolation valves.
b) All inoperable control rods are separated from all other inoperable control rods by at least two control cells in all directions. c) There are not more than 3 inoperable control rods in any RPCS group.
- 3. The position and bypassing of an inoperable control rod (s) is verified by a second licensed operator or other technically qualified member of the unit technical staff.
*See Special Test Exception 3.10.2
- Entry into OPERATIONAL CONDITION 2 and withdrawal of selected control rods is permitted for the purpose of determining the OPERABILITY of the RPCS prior to withdrawal of control rods for the purpose of bringing the reactor to criticality.
PERRY - UNIT 1 3/4 1-16
. - . _ = . - . . _ _ - -
b REACTIVITY CONTROL SYSTEMS ; !- SURVEILLANCE REQUIREMENTS l 4 4.1.4.2 The RPCS shall be demonstrated OPERABLE by verifying the OPERABILITY
. of the-i l l a. Rod pattern controller when THERMAL POWER is less than the low power i setpoint by selecting and attempting to move an inhibited control l rod:
1 1. After withdrawal of the first insequence control rod or gang, for each reactor startup.
- 2. As soon as the rod inhibit mode is automatically initiated at the RPCS low power setpoint, during power reduction.
I 3. The first time only that a banked position, N1, N2, or N3, is , reached during startup or during power reduction below the RPCS j low power setpoint. ! b. Rod withdrawal limiter when THERMAL POWER is greater than or equal i to the low power setpoint by selecting and attempting to move a l restricted control rod in excess of the allowable distance: l 1. As power is increased above the RPCS low power setpoint and ! RPCS high power setpoint, and as power is decreased below the j RPCS high power setpoint. 1
- 2. At least once per 31 days while operation continues above the RPCS low power setpoint.
1 I i ) J l l l I PERRY - UNIT 1 3/4 1-17 i
l 1 1 l REACTIVITY CONTROL SYSTEMS ' 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1. 5 The standby liquid control system subsystems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:
- a. In OPERATIONAL CONDITION 1 or 2:
l 1. With one system subsystem inoperable, restore the inoperable l subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours.
- 2. With both standby liquid control system subsystems inoperable, restore at least one subsystem to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours.
- b. In OPERATIONAL CONDITICN 5*:
- 1. With one system subsystem inoperable, restore the inoperable 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, I
insert all insertable control rods within one hour. SURVEILLANCE REQUIREMENTS 4.1. 5 Each standby liquid control system subsystem shall be demonstrated OPERABLE:
- a. At least once per 24 hours by verifying that;
- 1. The temperature of the sodium pentaborate solution is greater than or equal to 70*F.
- 2. The available volume of sodium pentaborate solution is within the limit of Figure 3.1.5-1.
- 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.
1
*With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.
l i e PERRY - UNIT 1 3/4 1-18 I
+ , , .. - .. . . . . . . .- - . ._ - . - .
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 5236 lbs and the sodium pentaborate soluti_on concentration 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 1220 psig is met.
~
- d. At least once per 18 months during shutdown by;
- 1. Initiating both of the standby liquid control system subsystems, including an explosive valve, and verifying that a flow path r from the pumps to the reactor pressure vessel is available by I pumping demineralized water into the reactor vessel. The replacement charge for the explosive valve shall be from the l
I (vj same manufactured batch as the one fired or from another batch which has been certified by having one of that batch success- ! fully fired. i
- 2. Demonstrating that all heat traced piping between the storage tank and the reactor vessel is unblocked by pumping from the storage tank to the test tank and then draining and flushing the piping with demineralized water.**
- 3. Demonstrating that the storage tank operating heater is OPERABLE by verifying the expected temperature rise of the sodium pentaborate solution in the storage tank after the operating heater is 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.
**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, over-lapping or total flow path steps such that the entire flow path is included.
PERRY - UNIT 1 3/4 1-19
15-5
= -
I$ . LOW HIGH- OVERFLOW
=g ,4 LEVEL . ALARM LEVEL ALARn4 VOLUME Es e .li. . . .i
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z REGION OF APPROVED - _ __ VOLUME - CONCENTR ATION 1 i am - N f 5 8E N / , yo 12- 5( I.:lNIMUM REQUIRED CONCENTRATION LINE II 4260 4409 4647 5013 V - NET TANK VOLUME (GALLONS) SODIUM PENTABORATE SOLUTION CONCENTRATION / VOLUME REQUIREMENTS Figure 3.1.5.1 O O -- - O -
POWER DISTRIBUTION LIMITS 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION 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 i shown in Figures 3.2.1-1, 3.2.1-2, and 3.2.1-3. APPLICA81LITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than j 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, or 3.2.1-3, 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. 1 !O SURVEILLANCE REQUIREMENTS el __ i
; 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, and 3.2.1-3
- 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 in one hour, and
- c. Initially and at least once per 12 hours when the reactor is i operating with a LIMITING CGNTROL R0D PATTERN for APLHGR.
- d. The provisions of Specification 4.0.4 are not applicable.
t l l l l l PERRY - UNIT 1 3/4 2-1 t
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POWER DISTRIBUTION LIMITS 3/4.2.2 APRM SETPOINTS LIMITING CONDITION FOR OPERATION 3.2.2 The APRM flow biased simulated thermal power-high scram trip setpoint (S) and flow biased neutron flux-upscale control rod block trip setpoint (SRB) shall be established according to the following relationships: TRIP SETPOINT ALLOWABLE VALUE S < (0.66W + 48%*)T S< (0.66W + 51%*)T Sji(0.66W+42%*)T R S RB 1 (0.66W + 45%*)T where: S and S are in percent of RATED THERMAL POWER, DB W = Loop recirculation flow as a percentage of the loop recirculation flow which produces a rated core flow of 104.0 million 1bs/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. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With the APRM flow biased simulated thermal ~ power-high scram trip setpoint and/or the flow biased neutron flux-upscale control rod block trip setpoint less conser-vative than the value shown in the Allowable Value column for S or SRB, as above determined, initiate corrective action within 15 minutes and adjust S and/or S RB x to be consistent with the Trip Setpoint value** within 6 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. l SURVEILLANCE REQUIREMENTS 4.2.2 The FRTP and CHFLPD shall be determined, the value of T calcu-lated, and the most recent actual APRM flow biased simulated thermal power-high scram and flow biased neutron flux-upscale control rod block trip setpoints verified to be within the above limits or adjusted, as required:
- 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 in one hour, and l c. Initially and at least once per 12 hours when the reactor is operat-ing with CMFLPD greater than or equal to FRTP.
- d. The provisions of Specification 4.0.4 are not applicable.
*0uring the startup test program, the APRM trip setpoint and allowable values may be permitted to be increased to the ME00 values (S trip setpoint of
( $0.66W + 64% and allowable value of 1 0.66W + 67%, and SRB trip setpoint of
- <0.66W + 58% and allowable value of < 0.66W + 61%).
**With CMFLPD greater than the FRTP, rather than adjusting the APRM setpoints, the APRM gain may be adjusted such that the APRM scale readings are greater f than or equal to 100% times CMFLPD provided that the adjusted APRM scale read-ing does not exceed 100% of RATED THERMAL POWER, and a notice of the adjustment is posted on the reactor control panel.
PERRY - UNIT 1 3/4 2-5
POWER DISTRIBUTION LIMITS 3/4.2.3 MINIMUM CRITICAL POWER RATIO
*IMITING CONDITION FOR OPERATION 3.2.3 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be equal to or greater than both MCPR f and MCPRp limits at indicated core flow, THERMAL POWER AT* and core average exposure compared to End of Cycle Exposure (EOCE)** as shown in Figures 3.2.3-1 and 3.2.3-2.
APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With MCPR less than the applicable MCPR limit shown in Figures 3.2.3-1 and
? 2.3-2, initiate corrective action within 15 minutes and restore MCPR to w ' in the required limit within 2 hours or reduce THERMAL POWER to less than 2L o/ RATED THERMAL POWER within the next 4 hours.
SURVEILLANCE REQUIREMENTS 4.2.3 MCPR shall be determined to be equal to or greater than the 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 of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER in one hour, and
- c. Initially and at least once per 12 hours when the reactor is operating with a LIMITING CONTROL R0D PATTERN for MCPR.
- d. The provisions of Specification 4.0.4 are not applicable.
*This AT refers to the planned reduction of rated feedwater temperature from nominal. rated feedwater temperature (420*F), such as prolonged removal of feedwater heater (s) from service.
- End of Cycle Exposure (EOCE) is defined as 1) the core average exposures at which there is no longer sufficient reactivity to achieve RATED THERMAL POWER with rated core flow, all control rods withdrawn, all feedwater heaters in service and equilibrium Xenon, or 2) as specified by the fuel vendor.
O PERRY - UNIT 1 3/4 2-6 I I
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OLMCPR = 1.18 ~ t ' f ' I I l 4 1.1 i i I : i fii 40 60 80 100 120
*O 20 CORE FLOW (% OF RATED)
MCPR f Figure 3.2.3-1 b i ! PERRY - UNIT 1 3/4 2-7 4 l I. - - - - _ . _ . . -. _
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*These MCPR limits assume that the TCV/TSV scram bypass setpoint (see note (h) of Table 3 P3.1-1) and EOC-RPT bypass setpoint (see note (b) of Table 3.3.4.2-1) are consistent with corresponding steam flow. For at>0, the trip setpoint shall be conservatively reduced from <25.4% of calibrated span on increasing turbine first-stage pressure to <15%. The allowable value shall be consistently reduced from 126.9% of calibrated span to 116.5%.
MCPR p Figure 3.2.3-2 PERRY - UNIT 1 3/4 2-8
POWER DISTRIBUTION LIMIT f-"x k) 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. 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 THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours.
- SURVEILLANCE REQUIREMENTS
'N 4.2.4 LHGR's shall be determined to be equal to or less than the limit:
- 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 in one hour, and
- c. Initially and at least once per 12 hours when the reactor is operating on a LIMITING CONTROL ROD PATTERN for LHGR.
- d. The provisions of Specification 4.0.4 are not applicable.
PERRY - UNIT 1 3/4 2-9
I 3/4.3 INSTRUMENTATION 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 REACTOR PROTECTION SYSTEM RESPONSE TIME as shown in Table 3.3.1-2. 4
; APPLICA8ILITY: As shown in Table 3.3.1-1.
j 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/cr that trip system in the tripped condition
- within 1 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 1 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 i 1 i
) 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 i 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.
4.3.1.3 ine 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 3 N times 18 months where N is the total number of redundant channels in a specific j 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 inoperable channel shall be restored to OPERABLE status within 2 hours or the ACTION required by Table 3.3.1-1 f ar 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 condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition.
I v PERRY - UNIT 1 3/4 3-1
, , - , --- , , , - , , m -- ,-r- -
TABLE 3.3.1-1 A REACTOR PROTECTION SYSTEM INSTRUMENTATION E
' APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS E FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION A
~ 1. Intermediate Range Monitors:
- a. Neutron Flux - High 2 3 1 3 2 3(bi 5 3 3
- b. Inoperative 2 3 1
^
,4 3 2 5 3 3
- 2. Average Power Range Monitor (c);
- a. Neutron Flux - High, Setdown 2 3- 1 t, 3 2 3 3(b) 5 3 3
'1' b. Flow Biased Simulated Thermal N
Power - High 1 3 4
- c. Neutron Flux - High 1 3 4
- d. Inoperative 1, 2 3 1 3 3 2 5 3 3
- 3. Reactor Vesycl Steam Dome Pressure - High 1,2(d) p y
- 4. Reactor Vessel Water Level - Low, Level 3 1, 2 2 1
- 5. Reactor Vessel Water Level - High' Level 8 1(e) 2 4
- 6. Main Steam Line Isolation Valve -
Closure 1(*) 4 4
- 7. Main Steam Line Radiation -
High 1, 2(d) 2 5
- 8. Drywell Pressure - High 1, 2 ff) 2 1-0 0 0 -
1 O 3 j TABLE 3.3.1-1 (Continued) h REACTOR PROTECTION SYSTEM INSTRUMENTATION l E i e APPLICABLE MINIMUM l 5 OPERATIONAL OPERABLE CHANNELS' FUNCTIONAL UNIT CONDITIONS PER TRIP' SYSTEM (a) ACTION
]
- 9. Scram Discharge Volume Water Level - High i a. Level Transmitter 1, 2 2 1 l
! S I9) 2 3 l l b. Float Switches 1, 2 2 1 ! S I9) '2 3-i ! 10. Turbine Stop Valve - Closure 1(h) 4 6 ! w ! A 11. Turbine Control Valve Fast closure, w Valve Trip System Oil Pressure - Low 1(h) 2 6 0 t
- 12. Reactor Mode Switch Shutdown
. Position 1, 2 2 1
, 3, 4 2 7 5 2 3 i 13. Manual Scram 1, 2 2 1 l 3, 4 2 8 5 . 2 9 I e l l l i i i 1 i
TABLE 3.3.1-1 (Continued) REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION
~
I ACTION 1 - Be in at least HOT SHUTDOWN within 12 hours. ACTION 2 - Verify all insertable control rods to be inserted la 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 ecdr vitt.in 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 l within 6 hours or in at least HOT SHUTDOWN within 12 hours. l 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. 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. 1 l l
*Except replacement of LPRM strings provided SRM instrumentation is OPERABLE per Specification 3.9.2.
PERRY - UNIT 1 3/4 3-4
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. (b) Unless adequate shutdown margin has been demonstrated per Specifica-
~
tion 3.1.1 and the "one-rod-out" Refuel position interlock has been demonstrated OPERA 8LE per Specification 3.9.1, the shorting links shall be removed from the RPS circuitry prior to and during the time any control rod is withdrawn.* (c) 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. (d) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1. (e) This function shall be automatically bypassed when the reactor mode switch is not in the Run position.
.T (f) This function is not required to be OPERABLE when DRYWELL INTEGRITY is s not required.
(g) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. (h) This function is automatically bypassed when turbine first stage pressure is less than the value of turbine first stage pressure corresponding to 40% of RATED THERMAL POWER. l
*Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.
O PERRY - UNIT 1 3/4 3-5
TABLE 3.3.1-2 h REACTOR PROTECTION SYSTEM RESPONSE TIMES Q c RESPONSE TIME g FUNCTIONAL UNIT (Seconds)
-4 - 1. Intermediate Range Monitors;
- a. Neutron Flux - High NA
- b. Inoperative NA
- 2. Average Power Range Monitor *:
- a. Neutron Flux - High, Setdown NA
- b. Flow Biased Simulated Thermal Power - High < 0.09**
- c. . Neutron Flux - High < 0.09
- d. Inoperative RA
- 3. Reactor Vessel Steam Dome Pressure - High < 0.35 w 4. Reactor Vessel Water Level - Low, Level 3 D 7 1.05
- 5. Reactor Vessel Water Level - High, Level 8 7 1.05 w 6. Main Steam Line Isolation Valve - Closure 5 7 0.06
- 7. Main Steam Line Radiation - High RA
- 8. Drywell Pressure - High NA
- 9. Scram Discharge Volume Water Level - High NA
- 10. Turbine Stop Valve - Closure
- 11. -< 0.06 Turbine Control Valve Fast Closure, Valve Trip System Oil Pressure - Low < 0.07#
- 12. Reactor Mode Switch Shutdown Position NA
- 13. Manual Scram NA
- Neutron detectors are exempt from response time testing. Response time sh'll a 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
O O O TABLE 4.3.1.1-1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL i c CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH { FUNCTIONAL UNIT CHECK TEST ' CALIBRATION (a) SURVEILLANCE REQUIRED
- 1. Intermediate Range Monitors:
- a. Neutron Flux - High S/U.S,(b) S/U(c) ,W R 2 S W R 3,4,5
- b. Inoperative NA W NA 2,3,4,5
- 2. Average Power Range Monitor:(f)
- a. Neutron Flux - High, S/U,S,(b) S/UIC) ' W
, SA 2 Setdown S W SA 3, 5
- b. Flow Biased Simulated Thermal Power - High S,D(h) y y(d)(e) 34(m) R(i) I
- c. Neutron Flux - High S W W(d) , SA 1 4 d. Inoperative NA W NA 1,2,3,5
- 3. Reactor Vessel Steaki Dome Pressure - High S M R I9) 1,2(3)
- 4. Reactor Vessel Water Level -
Low, Level 3 S M R I9) 1, 2
- 5. Reactor Vessel Water Level -
High, Level 8 S H R(9) 1
- 6. Main Steam Line Isolation Valve - Closure NA M R 1
- 7. Main Steam Line Radiation -
High S M R 1,2(3)
- 8. Drywell Pressure - High S M R(9) 1, 2(I)
- 9. Scram Discharge Volume Water Level - High
- a. Level Transmitter S M R(9) 1, 2, 5(k)
- b. Float Switches NA M R 1, 2, 5(k)
TABLE 4.3.1.1-1 (Continued) y REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS w
' CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH E FUNCTIONAL UNIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
[ 10. Turbine Stop Valve - Closure NA H R 1
- 11. Turbine Control Valve Fast Closure Valve Trip System Oil Pressure - Low NA M R 1
- 12. Reactor Mode Switch Shutdown Position NA R NA 1,2,3,4,5
- 13. Manual Scram NA H 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 1/2 decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined +3 overlap for M at least 1/2 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. T
* (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 than 2% of RATED THERMAL POWER.
Any APRM channel gain adjustment made in compliance with Specification 3.2.2 shall not be included 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 MWD /T using the TIP system. (g) Calibrate trip unit setpoint at least once per 31 days. (h) Verify measured core flow (total core flow) to be greater than or equal to established ccre flow at the existing loop flow (APRM % flow). (i) This calibration shall consist of verifying the 6 1 0.6 second simulated thermal power time constant. (j) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1. (k) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. (1) This function is not required to be OPERABLE when Drywell Integrity is not required. (m) The CHANNEL CALIBRATION shall exclude the flow reference transmitters, these transmitters shall be calibrated at least once per 18 months. O O -- O
( INSTRUMENTATION m j
) 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown 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.
APPLICABILITY: As shown in Table 3.3.2-1. ACTION:
- a. With an isolation actuation instrumentation channel trip setpoint 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 OPERABLE 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 i the tripped condition
- within one hour. The provisions of Specifica-l tion 3.0.4 are not applicable.
- c. With the number of OPERABLE channels less than required by the Minimum Os 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 3.3.2-1.
*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 condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition.
O PERRY - UNIT 1 3/4 3-9
l INSTRUMENTATION 1 SURVEILLANCE REQUIREMENTS ! 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 I Ol PERRY - UNIT 1 3/4 3-10 l
O O . TABLE 3.3.2-1 ISOLATION ACTUATION INSTRUMENTATION
' VALVE GROUPS MINIMUM APPLICABLE g OPERATED BY OPERABLE CHANNELS OPERATIONAL q TRIP FUNCTION SIGNAL PER TR',' JSTEM (a) CONDITION ACTION
- 1. PRIMARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level -
i Low, Level 2 1,5,7,8 2 1, 2, 3 and # 20
- b. Drywell Pressure - High 1,2,5,8,9(b)(c) 2 1,2,3 20
- c. Containment and Drywell Purge Exhaust Plenum Radiation - High 8 2(9) 1, 2, 3 and
- 21
- d. Reactor Vessel Water Level -
Low, Level 1 2(b)(c) 2 1, 2, 3 and # 20 y e. Manual Initiation 1,2,5,7,8,9 2(k) 1, 2, 3 and
- 22 I 2. MAIN STEAM LINE ISOLATION U a. Reactor Vessel Water Level -
Low, Level 1 6 2 1,2,3 20
- b. Main Steam Line Radiation - High 6(d) 2 1, 2 23 I
- c. Main Steam Line-Pressure - Low 6 2 1 24
- d. Main Steam Line Flow - High 6 2/line 1, 2, 3 23 l e. Condenser Vacuum - Low 6 2 1, 2**, 3** 23
, f. Mai'i Stecs Line Tunnel . Temperature - High 6 2 1,.2, 3 23
- g. Main Steam Line Tunnel A Temperature - High 6 2 1,2,3 23
- h. Turbine Building Main Steam Line Temperature - High 6 2 1,2,3 23
- i. Manual Initiation 6 2 1,2,3 22
TABLE 3.3.2-1 (Continued) m ISOLATION ACTUATION INSTRUMENTATION
' VALVE GROUPS MINIMUM APPLICABLE g OPERATED BY OPERABLE CHANNELS OPERATIONAL q TRIP. FUNCTION SIGNAL PER TRIP SYSTEM (a) CONDITION ACTION ~ 3. SECONDARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level - Low, Level 2 1 -
2 1, 2, 3 and # 25
- b. Drywell Pressure - High 1(b)(c) 2 1,2,3 25
- c. Manual Initiation 1 2 1,2,3 22 1 2 . 25
- 4. REACTOR WATER CLEANUP SYSTEM ISOLATION
- a. A Flow - High 7 1 1,2,3 27 m b. A Flow Timer 7 -
1 1,2,3 27 A c. Equipment Area Temperature - w High 7 1 1,2,3 27 5 d. Equipment Area A
. Temperature - High 7 1 1,2,3 27
- e. Reactor Vessel Water Level -
Low, Level 2 7 2 1,2,3 27
- f. Main. Steam Line Tunnel Ambient Temperature - High 7 1 1,2,3 27
- g. Main Steam Line Tunnel A Temperature - High 7 1 1,2,3 27
- h. SLCS Initiation 7(*) 1 1,2,3 27
- i. Manual Initiation 7 2 1,2,3 26 l
l O O O
i O TABLE 3.3.2-1 (Contir.ued) h ISOLATION ACTUATION INSTRUMENTATION i 4
, VALVE GROUPS MINIMUM APPLICABLE l
c- OPERATED BY OPERABLE CHANNELS OPERATIONAL 5
-4 TRIP FUNCTION SIGNAL PER TRIP SYSTEM (a) CONDITION ACTION
" 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION l
- a. RCIC Steam Line Flow - High 9 1/ Area 1, 2, 3 27 i b. RCIC Steam Supply Pressure -
Low 9 1/ Area 1,2,3 27
- c. RCIC Turbine Exhaust Diaphragm Pressure - High 9 fI) 2 1,2,3 27
- d. RCIC Equipment Room Ambient Temperature - High 9 1 1,2,3 '27 m e. RCIC Equipment Room A 2 Temperature - High 9 1 1,2,3 27 Y f. Main Steam Line Tunnel 0 Ambient Temperature - High 9 1 1,2,3 27 4
- g. Main Steam Line Tunnel A Temperature - High 9 1 1,2,3 27
- h. Main Steam Line Tunnel Temperature Timer 9 1 1,2,3 27
- i. RHR Equipment Room Ambient
, Temperature - High 9 1 1,2,3 27
- j. RHR Equipment Room A
- Temperature - High 9 1 1,2,3 27 j k. RCIC Steam Line Flow High j Timer 9 1 1,2,3 27
- 1. Drywell Pressure - High 9(h) 1 1,2,3 27
- m. Manual Initiation 9 I) 1 1,2,3 26 l
TABLE 3.3.2-1 (Continued) h ISOLATION ACTUATION INSTRUMENTATION 5! i VALVE GLOUPS MINIMUM APPLICABLE c: OPERATED BY OPERABLE CHANNELS OPERATIONAL
}
TRIP FUNCTION SIGNAL PER TRIP SYSTEM (a) CONDITION ACTION
- 6. RHR SYSTEM ISOLATION
- a. RHR Equipment Area Ambient Temperature - High 3, 4 1/ Area 1,2,3 28
- b. RHR Equipment Area A Temperature - High 3, 4 1/ Area 1, 2, 3 .28
- c. RHR/RCIC S'.eam Line Flow - High 9 I3) 1 1,2,3 28 t' d. Reactor Vessel Water
- Level - Low, Level 3 3, 4 2 1,2,3 28 Y
Z e. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 4 2 1,2,3 28
- f. Drywell Pressure - High 3 2 1,2,3 28
- g. Manual Initiation 3, 4 2 1,2,3 26 O _
O O
TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION ACTION ACTIGN 20 - Be in at'least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN
- within the next 24 hours. t ACTION 21 -
Close the affected system isolation valve (s) within one hour or: 1 a. 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.
- b. In Operational Condition *, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary containment and operations with a potential for draining the reactor vessel.
I ACTION 22 - Restore the manual initiation function to OPERABLE status I within 48 hours or:
- a. In OPERATIONAL CONDITION 1, 2, or 3, be in at leest HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN
; within the following 24 hours,
- b. In OPERATIONAL CONDITION *, suspend CORE ALTERATIONS, l operations with-a potential for draining the reactor vessel, and handling of irradiated fuel in the primary containment.
ACTION 23 - Be in at least STARTUP with the associated isolation valves O closed within 6 hours or be in at~1 east HOT SHUTDOWN within d 12 hours and in COLD SHUTDOWN within the next 24 hours. ACTION 24 - Be in at least STARTUP within 6 hours. l ACTION 25 - Verify SECONDARY CONTAINMENT INTEGRITY with the annulus exhaust ! gas treatment system operating within onc hour. ACTION 26 - Restore the manual initiation function to OPERABLE status within 8 hours or close the affected system isolation valves within 1 hour and declare the affected system inoperable. ! ACTION 27 - Close the affected system isolation valves within one hour and declare the affected system inoperable.
- ACTION 28 -
Within one hour lock the affected system isolation valves closed, or verify, by remote indication, that the valve (s) is closed and
- electrically disarmed, or isolate the penetration (s) and declare the affected system inoperable.
- NOTES j
- When handling irradiated fuel in the primary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
l i ** When any turbine stop valve is greater than 90% open and/or the key locked Condenser Low Vacuum Bypass Switch is in the normal position.
# During CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
PERRY - UNIT 1 3/4 3-15 l
TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION ACTION NOTES (Continued) (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 con-dition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter. (b) Also actuates the standby subsystem of the annulus exhaust gas treatment system. (c) Also actuates the control room emergency filtration system in the recir-culation mode of operation. (d) Also trips and isolates the mechanical vacuum pumps. (e) Closes only RWCU system isolation valve (s) 1G33-F004 (SLCS Pump A) and 1G33-F001 (SLCS Pump B). (f) Manual initiation isolates 1E51-F064 and IE51-F031 only and only following manual or automatic initiation of the RC:C system. (g) Containment and Drywell Purge System inboard and outboard isolation valves each use a separate two out of two isolation logic. (h) Requires RCIC system steam supply pressure - low coincident with drywell pressure high to isolate valve'1E51-F077. (i) For this signal, one trip system has two channels which close valves 1E51-F063 and 1E51-F076 while the~other trip system has two channels which close valve 1E51-F064. (j) Isolates both RHR and RCIC. (k) There is only one (1) RCIC manual initiation channel for valve group 9. l l l l l l 9 PERRY - UNIT 1 3/4 3-16 l I
!. TABLE 3.3.2-2 ! o ISOLATION ACTUATION INSTRUMENTATION SETPOINTS ! 5! ALLOWABLE l . TRIP FUNCTION -TRIP SETPOINT VALUE E 1. PRIMARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level -
Low, level 2 1 129.8 inches
- 1 127.6 inches -
- b. Drywell Pressure - High 5 1.68 psig '$ 1.88 psig
- c. Containment and Drywell Purge Exhaust Plenum Radiation - High 5 2 mR/hr** above background 5 4 mR/hr** above backgroud
- d. Reactor Ves~sel Water Level -
Low, Level 1 1 16.5 inches
- 1 14.3 inches
- e. Manual Initiation NA NA R
- 2. MAIN'S(EAM LINE ISOLATION
- a. Reactor Vsssel Water Level - "
" Low, Level 1 1 16.5 inches
- 1 14.3 inches
- b. Main Steam Line Radiation - High 5 3.0 x full power background 5 3.6 x full power background
- c. Main Steam Line Pressure - Low 2 807.0 psig 1 795.0 psig
- d. Main Steam Line Flow - High 5 183 psid 5 191 psid
- e. Condenser Vacuum - Low 2 8.5 inches Hg. vacuum 1 7.6 inches Hg. vacuum
- f. Main Steam Line Tunnel Temperature - High 5 131.4*F $ 133.9*F
- g. Main Steam Line Tunnel A Temperature - High 5 80.65*F 5 82.4*F
- h. Turbine Building Main Steam Line Temperature - High 5 116.4 F 5 118.9*F.
- i. Manual Initiation NA. NA
TABLE 3.3.2-2 (Continued) y ISOLATION ACTUATION INSTRUMENTATION SETPOINTS
- o ALLOWABLE
[ TRIP FUNCTION TRIP SETP0lHI VALUE h 3. SECONDARY CONTAINMENT ISOLATION s a. Reactor Vessel Water Level - Low, Level 2 2 129.8 inches
- 1 127.6 inches
- b. Drywell Pressure - High 5 1.68 psig 5 1.88 psig
- c. Manual Initiation NA NA
- 4. REACTOR WATER CLEANUP SYSTEM ISOLATION
- a. A Flow - High 5 68 gpm** $ 77.1 gpm**
- b. A Flow Timer 5 45 seconds 5 47 seconds
- c. Equipment Area Temperature - High
- 1. RWCU Hx Room < 136.4*F < 138.9*F y 2. Pump Rooms, Valve Nest Room 3135.4"F 3137.9*F 5 d. . Equipment Area A Temperature - High
- 1. RWCU Hx Room < 76.65*F < 78.4*F
- 2. RWCU Pump Rooms, Valve Nest Room 328.65*F 330.4*F
- e. Reactor Vessel Water Level -
Low, Level 2 1 129.8 inches
- 1 127.6 inches
- f. Main Steam Line Tunnel Ambient Temperature - High 5 131.4*F 5 133.9 F
- g. Main Steam Line Tunnel a Temperature - High 5 80.65 F $ 82.4*F
- h. SLCS Initiation NA NA
- i. Manual Initiation NA NA O O O
f O N
~.
, TABLE 3.3.2-2 (Continued) h I_ SOLATION ACTUATION INSTRUMENTATION SETPOINTS
, ALLOWABLE c TRIP FUNCTION TRIP SETPOIE VALUE
?i H 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION e
- a. RCIC Steam Line Flow - High 5 290" H2 0** 5 298.5" H2 0**
- b. RCIC Steam Supply Pressure - Low 1 E0 psig 1 55 psig
- c. RCIC Turbine Exhaust Diaphragm Pressure - High 5 10 psig 5 20 psig
- d. RCIC Equipment Room Ambient Temperature - High 5 143.4*F 5 145.9*F w e. RCIC Equipment Room A 5 37.25*F 5 39*F
) Temperature - High
[ f. Main Steam Line Tunnel Ambient
- Temperature - High 5 131.4*F 5 133.9'F
- g. Main Steam Line Tunnel A Temperature - High 5 80.65*F 5 82.4*F
- h. Main Steam Line Tunnel Temperature Timer 5 29 minutes 5 30 minutes
- i. RHR Equipment Room Ambient Temperature - High 5 157.4*F $ 159.9*F
- j. RHR Equipment Room a Temperature - High 5 50.65*F 5 52.4*F
- k. RCIC Steam Flow High Timer 3 seconds 5 t 5 13 seconds 3 seconds 5 t 5 13 seconds
- 1. Drywell Pressure - High 5 1.68 psig 5 1.88 psig
- m. Manual Initiation NA NA
TABLE 3.3.2-2 (Continued) b ISOLATION ACTUATION INSTRUMENTATION SETPOINTS 5!
- ALLOWABLE c TRIP FUNCTION TRIP SETPOINT VALUE z
Q 6. RHR SYSTEM ISOLATION
- a. RHR Equipment Area Ambient Temperature - High 5 157.4 F $ 159.9 F
- b. RHR Equipment Area A Temperature -
High 5 50.65*F 1 52.4*F
- c. RHR/RCIC Steam Line Flow - High 5 105" H2 0** .
$ 114" H2 0**
- d. Reactor Vessel Water Level - Low, Level 3 1 177.7 inches * > 177.1 inches
$ e. Reactor Vessel (RHR Cut-in w Permissive) Pressure - High 5 135 psig 5 150 psig
- f. Drywell Pressure - High 5 1.68 psig i 1.88 psig
- g. Hanual Initiation NA NA
*See Bases Figure B 3/4 3-1.
** Initial setpoint. Final setpoint to be determined during startup test program. Any required change to this setpoint shall be submitted to the Commission within 90 days of test completion.
O O O
l TABLE 3.3.2-3 V ISOLATION SYSTEM INSTRUMEN". TION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#
- 1. PRIMARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level - Low, Level 2 NA
- b. Drywell Pressure - High NA
- c. Containment and g ell Purge Exhaust Plenum Radiation - High < 10(,)
- d. Reactor Vessel Water Level - Low, Level 1 NA
- e. Manual Initiation NA
- 2. MAIN STEAM LINE ISOLATION
- a. Reactor Vessel Water Level - Low L < 1.0*/< 10(a) ,
- b. Main Steam Line Radiation - Higb(b)evel 1 I 1.0*/7 10(a) ,
- c. Main Steam Line Pressure - Low i 1.0*/7 10((a),,
a),a
- d. Main Steam Line Flow - High 30.5*/510
- e. Condenser Vacuum - Low NA
- f. Main Steam Line Tunnel Temperature - High NA
- g. Main Steam Line Tunnel a Temperature - High NA
- h. Turbine Building Main Steam Line Temperature - High NA
- 1. Manual Initiation NA O 3. SECONDARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level - Low, Level 2 NA
- b. Drywell Pressure - High NA
- c. Manual Initiation NA
- 4. REACTOR WATER CLEANUP SYSTEM ISOLATION
- a. A Flow - High NA-
- b. A Flow Timer NA
- c. Equipment Area Tertperature - High NA
- d. Equipment Area a Temperature - High. NA
- e. Reactor Vessel Water Level - Low, Level 2 NA
- f. Main Steam Line Tunnel Ambient Temperature - High .
NA
- g. Main Steam Line Tunnel a Temperature - High NA
- h. SLCS Initiation NA
- i. Manual Initiation NA w
PERRY - UNIT 1 3/4 3-21 .
TABLE 3.3.2-3 (Continued) ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#
- 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLAlION
- a. RCIC Steam Line Flow - High NA
- b. RCIC Steam Supply Pressure - Low NA
- c. RCIC Turbine Exhaust Diaphragm Pressure - High NA
- d. RCIC Equipment Room Ambient Temperature - High NA
- e. RCIC Equipment Room A Temperature - High NA
- f. Main Steam Line Tunne. Ambient Temperature - High NA
- g. Main Steam Line Tunnel A Temperature -~High NA
- h. Main Steam Line Tunnel Temperature Timer NA
- i. RHR Equipment Room Ambient Temperature - High NA
- j. RHR Equipment Room A Temperature - High NA
- k. RCIC Steam Line Flow High Timer NA
- 1. Drywell Pressure - Hioh NA
- m. Manual Initiation NA
- 6. RHR SYSTEM ISOLATION
- a. RHR Equipment Area Ambient Temperature - High NA
- b. RHR Equipment Area a Temperature - High NA
- c. RHR/RCIC Steam Line Flow - High NA
- d. Reactor Vessel Water Level - Low, Level 3 NA
- e. Reactor Vessel (RHR Cut-in Permissive)
Pressu'.e - High NA
- f. Drywell Pressure - High NA
- g. Manual Initiation NA (a) Isolation system instrumentation response time specified includes the diesel generator starting and sequence loading delays.
(b) Radiation detectors are exempt from response time testing. Response time shall be measured from detector output or the input of the first electron component in the channel.
- Isolation system instrumentation response time for MSIVs only. No diesel-generator delays assumed.
** 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 3.6.4-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.
O PERRY - UNIT 1 3/4 3-22
O C O TABLE 4.3.2.1-1 h ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 5!
, CHANNEL OPERATIONAL c CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH 2 TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED ~ 1. PRIMARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level -
Low, Level 2 S M R 1, 2, 3 and #
- b. Drywell Pressure - High S M R 1, 2, 3
- c. Containment and Drywell Purge Exhaust Plenum Radiation -
High S M R 1, 2,'3 and *
- d. Reactor Vessel Water Level -
Low, Level 1 S M R(b) 1, 2, 3 and #
- e. Manual Initiation NA R NA 1, 2, 3 and *
- 2. MAIN STEAM LINE ISOLATION w a. Reactor Vessel Water Level -
} Low, Level 1 S M R(b) 1, 2, 3 m b. Main Steam Line Radiation -
4 High S M~ R 1, 2 w c. Main Steam Line Pressure - Low S M R(b) y
- d. Main Steam Line Flow - High S M R( ) 1, 2, 3
- e. Condenser Vacuum - Low S M R I) 1, 2**, 3**
- f. Main Steam Line Tunnel Temperature - High S M R 1,2,3
- g. Main Steam Line Tunnel a Temperature - High S M R 1,2,3
- h. Turbine Building Main Steam Line Temperature - High S M R 1, 2, 3
- i. Manual Initiation NA R NA 1, 2, 3 9
TABLE 4.3.2.1-1 (Continued) h ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E CHANNEL OPERATIONAL
' CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH g TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED Z 3. SECONDARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level - Low, Level 2 S M R 1, 2, 3 and #
- b. Drywell Pressure - High S M R 1,2,3
- c. Manual Initiation NA R NA 1, 2, 3 and *
- 4. REACTOR WATER CLEANUP SYSTEM ISOLATION
- a. A Flow - High S M R 1, 2, 3
- b. A Flow Timer NA M R 1,2,3
- c. Equipment Area Temperature -
High S M R 1,2,3 m d. Equipment Area Ventilation
} A Temperature - High S M R 1, 2, 3 m e. Reactor Vessel Water A Level - Low, Level 2 S M R(b) 1,2,3
- f. Main Steam Line Tunnel Ambient Temperature - High S M R 1,2,3
- g. Main Steam Line Tunnel a Temperature - High S R 1, 2, 3
- h. SLCS Initiation NA M(a)
M MA 1,2,3
- i. Manual Initiation NA R NA 1,2,3 9 O O
O TABLE 4.3.2.1-1 (Continued) h
- o ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS
-< CHANNEL OPERATIONAL
' CONDITIONS IN WHICH CHANNEL FUNCTIONAL CHANNEL E TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
- 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION
- a. RCIC Steam Line Flow - High S M R(b) 1,2,3
- b. RCIC Steam Supply Pressure -
Low S M R(b) 1,2,3
- c. RCIC Turbine Exhaust Diaphragm Pressure - High S M R(b) 1,2,3 '
- d. RCIC Equipment Room Ambient Temperature - High S M R 1,2,3
- e. RCIC Equipment Room A Temperature - High S M R 1, 2, 3
- f. Main Steam Line Tunnel Ambient w Temperature - High 5 M R 1,2,3 <
% g. Main Steam Line Tunnel w A Temperature - High S M' R 1, 2, 3 4
- h. Main Steam Line Tunnel Temperature Timer NA M R 1,2,3 l ,
- i. RHR Equipment Room Ambient
! Temperature - High S M R 1, 2, 3 i j. RHR Equipment Room A , i Temperature - High S M R 1,2,3 , ! k. RCIC Steam Line Flow NA M R 1,2,3 i High Timer ! 1. Drywell Pressure - High S M R(b) 1, 2, 3 l m. Manual Initiation NA R NA 1, 2, 3 l I ( l l _ - --i __
TABLE 4.3.2.1-1 (Continued) d x ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH E TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED w
- 6. RHR SYSTEM ISOLATION
- a. RHR Equipment Area Ambient Temperature - High S M R ~ 1, 2, 3
- b. RHR Equipment Area a Temperature - High S M R 1,2,3
- c. RHR/RCIC Steam Line Flow - High 5 M R(b) 1, 2, 3
- d. Reactor Vessel Water Level -
$ Low, Level 3 S M R(b) 1, 2, 3 Y e. Reactor Vessel (RHR Cut-in $ Permissive) Pressure - High S M R ID) 1, 2, 3
- f. Drywell Pressure - High S H R ID) 1, 2, 3
- g. Manual Initiation NA R NA 1, 2, 3
*When handling irradiated fuel in the primary 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 the key locked bypass switch is in the normal position.
#During CORE ALTERATION and operations with a potential for. draining the reactor vessel.
(a) Each train or logic channel shall be tested at least every other 31 days. (b) Calibrate trip unit setpoint at least once per 31 days. O O O
INSTRUMENTATION s 1 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION v 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.
- c. With either ADS trip system "A" or "B" inoperable, restore the inoperable trip system to OPERABLE status:
g ) N_/
- 1. Within 7 days, provided that the HPCS and RCIC systems are OPERABLE, or,
- 2. Within 72 hours, provided either the HPCS or the RCIC system is inoperable.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and reduce reactor steam dome pressure to less than or equal to 100 psig within the following 24 hours. 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. f O PERRY - UNIT 1 3/4 1-27
TABLE 3.3.3-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION i MINIMUM OPERABLE APPLICABLE , c- CHANNELS PER OPERATIONAL TRIP FUNCTION TRIP FUNCTION (a) CONDITIONS ACTION A. DIVISION 1 TRIP SYSTEM
- 1. RHR-A (LPCI MODE) AND LPCS SYSTEM
- a. Reactor Vessel Water Level - Low, Level 1 2 1, 2, 3, 4 * , 5* 30
- b. Drywell Pressure - High 2 1,2,3 30
- c. LPCS Pump Discharge Flow - Low (Bypass) 1 1,2,3,4*,5* 39
- d. Reactor Vessel Pressure - Low (LPCS Injection 1 1,2,3 31 Valve Permissive) .
4*, 5* 32
- e. Reactor Vessel Pressure - Low (LPCI Injection 1 1,2,3 31 Valve Permissive) 4*, 5* 32
{ f. LPCI Pump A Start Time Delay Relay 1 1,2,3,4*,5* 31
- g. LPCI Pump A Discharge Flow - Low (Bypass) 1 1,2,3,4* 5* 39 4 h. Manual Initiation 1 1,2,3,4*,5* 33
. 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"#
- a. Reactor Vessel Water Level - Low, Level 1 2(b) 1, 2, 3 30
- b. Manual Inhibit 1 1,2,3 33
- c. ADS Timer 1 1,2,3 31
- d. Reactor Vessel Water Level - Low, level 3 (Permissive) 1 1,2,3 31
- e. LPCS Pump Discharge Pressure - High (Permissive) 2 1,2,3 31
- f. LPCI Pump A Discharge Pressure - High (Permissive) 2 1,2,3 31
- g. Manual Initiation 2 1,2,3 33 O O O
O O O TABLE 3.3.3-1 (Continued) h EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION E .
. MINIMUM OPERABLE APPLICABLE c: CHANNELS PER OPERATIONAL
}
TRIP FUNCTION TRIP FUNCTION (*) CONDITIONS ACTION B. DIVISION 2 TRIP SYSTEM -
- 1. RHR B AND C (LPCI MODE)
- a. Reactor Vessel Water Level - Low, Level 1 2 1, 2, 3, 4*, 5* 30
- b. Drywell Pressure - High 2 1,2,3 30 ,
- c. Reactor Vessel Pressure - Low (LPCI Injection 1 1,2,3 31 Valve Permissive). 4*, 5* 32
- d. LPCI Pump B Start Time Delay Relay 1 1,2,3,48, 5* 31
- e. LPCI Pump Discharge Flow - Low (Bypass) 1/ pump 1,2,3,4*,5* 39
- f. Manual Initiation 1 1, 2, 3, 4* , 5* 33
- 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"#
- a. Reactor Vessel Water Level - Low, ' Level 1 2(b) 1, 2, 3 30
- b. Manual Inhibit 1 1,2,3 33
- c. ADS Timer 1 1,2,3 31
- d. Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1, 2,~3 31
- e. LPCI Pump B and C Discharge Pressure - High (Permissive) 2 1,2,3 31
- f. Manual Initiation 2 1,2,3 33
TABLE 3.3.3-1 (Continued) A EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION E MINIMUM OPERABLE APPLICABLE CHANNELS PER OPERATIONAL E TRIP FUNCTION TRIP FUNCTION (a) CONDITIONS ACTION C. DIVISION 3 TRIP SYSTEM
- 1. HPCS SYSTEM
- a. Reactor Vessel Water Level - Low, Level 2 4(b) 1, 2, 3, 4*, 5* 34
- b. Drywell Pressure - High## 4(b) 1, 2, 3 34
- c. Reactor Vessel Water Level - High, Level 8 4(c) 1, 2, 3, 4* , 5* 31
- d. Condensate Storage Tank Level - Low 2(d) 1, 2, 3, 4 * , 5* 35
- e. Suppression Pool Water Level - High 2(d) 1, 2, 3, 4*, 5* 35
- f. HPCS Pump Discharge Pressure - High (Bypass) 1 1, 2, 3, 4* , 5* 39 R' g. HPCS System Flow Rate - Low (Bypass) 1 1, 2, 3, 4 * , 5* 39 w h. Manual Initiation ## 1 1, 2, 3, 4* , 5* 36 0
o MINIMUM APPLICABLE TOTAL NO. CHANNELS OPERABLE OPERATIONAL OF CHANNELS TO TRIP CHANNELS CONDITIONS ACTION D. LOSS OF POWER
- 1. 4.16 kv Emergency Bus Undervoltage### 2/ bus 2/ bus 2/ bus 1, 2, 3, 4**, 5** 37 (Loss of Voltage) gg,
- 2. 4.16 kv Emergency Bus Undervoltage 2/ bus 2/ bus 2/ bus 1, 2, 3, 4**, 5** 38 (Degraded Voltage)
(a) A channel may be placed in an inoperable status for up to 2 hours during periods of required 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 actuates the associated division diesel generator. (c) Provides signal to close HPCS pump injection valve only. (d) Provides signal to HPCS pump suction valves only. When the system is required to be OPERABLE per Specification 3.5.2 or 3.5.3. 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 100 psig.
## The injection function of Drywell Pressure - High and Manual Initiation are not required to be OPERABLE with indicated reactor vessel water level on the wide range instrument greater than the Level 8 setpoint coincident with the reactor ssure less than 450 psig.
re common to Divisions 1, 2 and 3. O.TheLossofVoltageandDegradedVoltagefuncti
i TABLE 3.3.3-1 (Continued) s EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION
\
ACTION ACTION 30 - With the number of OPERA 8LE channels less than required by the Minimum OPERA 8LE Channels per Trip Function requirement: i
- a. With one channel inoperable, place the inoperable channel
! in the tripped condition within one hour
- or declare the
, associated system inoperable.
- b. With more than one channel inoperable, declare the associated' system inoperable.
ACTION 31 - With the number of OPERA 8LE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, i declare the associated ADS trip system or ECCS inoperable. ACTION 32 - With the number of OPERABLE channels less than the Minimum OPERA 8LE 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 ADS valve or ECCS inoperable. ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:
- a. For one trip system, place that trip system in the tripped condition within onc hour
- or declare the HPCS system inoperable.
O ACTION 35 -
- b. For both trip systems, declare the HPCS system inoperable.
With the number of OPERABLE channels less than required by the ' Minimum OPERA 8LE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within one hour *, or align the HPCS system to take suction from the suppression pool, or declare the HPCS system inoperable. i ACTION 36 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 HPCS system inoperable.
ACTION 37 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel gcnerator inoperable and take the ACTION required by. Specification 3.8.1.1 or 3.8.1.2, as appropriate. ( ACTION 38 - With the number of OPERABLE channels less than the Total Number i of Channels, place the inoperable channel in the tripped condi-tion within 1 hour *; operation may then continue until perform-ance of the next required CHANNEL FUNCTIONAL TEST. . ACTION 39 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.
I Restore the inoperable channel to OPERABLE status within 7 days j or declare the associated system inoperable.
*The provisions of Specification 3.0.4 are not appliable.
PERRY - UNIT 1 3/4 3-31 i
A TABLE 3.3.3-2 i8
-< EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS e
E ALLOWABLE
$ TRIP FUNCTION TRIP SETPOINT VALUE A. DIVISION 1 TRIP SYSTEM
- 1. RHR-A (LPCI MODE) AND LPCS SYSTEM
- a. Reactor Vessel Water Level - Low, Level 1 > 16.5 inches * > 14.3 inches
- b. Drywell Pressure - High i 1.68 psig i 1.88 psig
- c. LPCS Pump Discharge Flow - Low (Bypass) 1 1350 gpm 2 1200 gpm
- d. Reactor Vessel Pressure - Low (LPCS Injection 577.7 1 15 psig 577.7 + 30, -95 psig Valve Permissive)
- e. Reactor Vessel Pressure - Low (LPCI Injection 502.5 + 5, -10 psig 502.5 + 10, -40 psig Valve Permissive)
- f. LPCI Pump A Start Time Delay Relay 1 5 seconds i 5.25 seconds
- g. LPCI Pump A Discharge Flow - Low (Bypass) 2 1650 gpm 1 1450 gpm
- h. Manual Initiation NA NA
$ 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"
'[ a. Reactor Vessel Water Level - Low, > 16.5 inches *
> 14.3 inches N Level I
- b. Manual Inhibit NA NA -
- c. ADS Timer < 105 seconds < 117 seconds j d. Reactor Vessel Water Level - Low, Level 3 E177.7 inches * [177.1 inches (Permissive)
, e. LPCS Pump Discharge Pressure - High > 145 psig, increasing
> 125 psig, increasing
! (Permissive)
- f. LPCI Pump A Discharge Pressure - High > 125 psig, increasing > 115 psig, increasing
- (Permissive) i g. Manual Initiation NA NA l
t l O. O O
_ _ _ - _ _ . .- .-- - _ . .. _ - _- - . - . .- -_ ~ _ ..-
- O O O 4
TABLE 3.3.3-2 (Continued) y EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS 5 -
' ALLOWABLE l .
TRIP FUNCTION TRIP SETPOINT VALUE
- =
U B. DIVISI0'N 2 TRIP SYSTEM
- 1. RHR B AND C (LPCI MODE) .
- a. Reactor Vessel Water Level - Low, 1 16.5 inches * > 14.3 inches Level 1 i b. Drywell Pressure - High 5 1.68 psig i 1.88 psig
! c. Reactor Vessel Pressure - Low (LPCI Injection i i Valve Permissive) ' LPCI Pump B 508.0 + 5, -10 psig 508.0 + 10, -40 psig
; LPCI Pump C 506.6 + 5, -10 psig 506.6 + 10, -40 psig i d. LPCI Pump B Start Time Delay Relay 1 5 seconds 1 5.25 seconds j
m e. LPCI Pump Discharge Flor - Low (Bypass) 1 1650 gpm 1 1450 gpa j g f. Manual Initiation NA NA i
- 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B" i a. Reactor Vessel Water Level - Low, 1 16.5 inches
- 1 14.3 inches
- Level 1 ,
l b. Manual Inhibit NA NA l c. ADS Timer 1 105 seconds 1 117 seconds j
- d. Reactor Vessel Water Level - Low, Level 3 1 177.7 inches
- 1 177.1 inches (Permissive)
- e. LPCI Pump B and C Discharge Pressure - High > 125 psig, increasing
> 115 psig, increasing
-l (Permissive) } f. Manual Initiation NA NA j
)
i i d 1
TABLE 3.3.3-2 (Continued) A g EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS ALLOWABLE E TRIP FUNCTION TRIP SETPOINT VALUE N C. DIVISION 3 TRIP SYSTEM
- 1. HPCS SYSTEM
- a. Reactor Vessel Water Level - Low, 1 129.8 inches
- 1 127.6 inches Level 2
- b. Drywell Pressure - High 1 1.68 psig i 1.88 psig
- c. Reactor Vessel Water Level - High, Level 8 1 219.5 inches
- 1 221.7 inches
- d. Condensate Storage Tank Level - Low 1 63,300 gallons 1 59,700 gallons (624 feet 10 inches (624 feet 7 inches elevation) elevation)
- e. Suppression Pool Water Level - High < 18 feet 4.9 inches < 18 feet 6 inches T593 feet 2.9 inches T593 feet 4 inches R elevation) elevation)
- f. HPCS Pump Discharge Pressure - High (Bypass) 1 145 psig 1 120 psig y g. HPCS System Flow Rate - Low (Bypass) 1 725 gpm 2 600 gpm y h. Manual Initiation NA NA D. LOSS OF POWER
- 1. 4.16 kv Emergency Bus Undervoltage# a. 4.16 kv Basis -
(Loss of Voltage) 3010176 volts 30101151 volts
- b. 3.010.075 seconds 3.010.15 seconds time delay time delay
- 2. 4.16 kv Emergency Bus Undervoltage# a. 4.16 kv Basis -
(Degraded Voltage) 3800120 volts 3800140 volts
- b. 5.010.25 minute 5.010.5 minute time delay time delay
- c. 1510.75 second 1511.5 second
- LOCA time delay LOCA time delay 1
"See Bases Figure B 3/4 3-1.
The Loss of Voltage and Degraded Voltage functions are common to Division 1, Division 2, and Division 3. l l l O O O
TABLE 3.3.3-3 EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES
.(
ECCS RESPONSE TIME (Seconds) 1 A. DIVISION 1 TRIP SYSTEM
- 1. RHR-A (LPCI MODE) AND LPCS SYSTEM
- a. Reactor Vessel Water Level - Low, 1 37 Level 1
- b. Drywell Pressure - High 1 37
- c. LPCS Pump Discharge Flow - Low (Bypass) NA
- d. Reactor Vessel Pressure - Low (LPCS Injection NA Valve Permissive)
- e. Reactor Vessel Pressure - Low (LPCI Injection NA Valve Permissive)
- f. LPCI Pump A Start Time Delay Relay NA
- g. LPCI Pump A Discharge Flow - Low (Bypass) NA
- h. Manual Initiation NA
- 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"
- a. Reactor Vessel Water Level - Low, Level 1 NA
- b. Manual Inhibit NA
- c. ADS Timer NA
- d. Reactor Vessel Water Level - Low, NA Level 3 (Permissive)
- e. LPCS Pump Discharge Pressure - High NA
, (Permissive)
- f. LPCI Pump A Discharge Pressure - High NA (Permissive)
Manual Initiation
- g. NA B. DIVISION 2 TRIP SYSTEM
- 1. RHR B AND C (LPCI MODE)
- a. Reactor Vessel Water Level - Low, 1 37 Level 1
- b. Drywell Pressure - High 1 37
- c. Reactor Vessel Pressure - Low (LPCI NA Injection Valve Permissive)
- d. LPCI Pump B Start Time Delay Relay NA
- e. LPCI Pump Discharge Flow - Low (Bypass) NA
- f. Manual Initiation NA I+
PERRY - UNIT 1 3/4 3-35
TABLE 3.S.3-3 (Continued) EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES TRIP FUNCTION RESPONSE TIME (Seconds)
- 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"
- a. Reactor Vessel Water Level - Low, NA Level 1
- b. Manual Inhibit NA
- c. ADS Timer NA
- d. Reactor Vessel Water Level - Low, NA Level 3 (Permissive)
- e. LPCI Pump B and C Discharge NA Pressure - High (Permissive)
- f. Manual Initiation NA C. DIVISION 3 TRIP SYSTEM .
- 1. HPCS SYSTEM
- a. Reactor Vessel Water Level - Low, 1 27 Level 2
- b. Drywell Pressure - High 1 27
- c. Reactor Vessel Water Level - High, NA Level 8
- d. Condensate Storage Tank Level - Low NA
- e. Suppression Pool Water Level - High NA
- f. HPCS Pump Discharge Pressure - High NA
- g. HPCS System Flow Rate - Low NA
- h. Manual Initiation NA D. LOSS OF POWER
- 1. 4.16 kv Emergency Bus Undervoltage# NA (Loss of Voltage)
- 2. 4.16 kv Emergency Bus Undervoltage# NA (Degraded Voltage) l l
t i l l The Loss of Voltage and Degraded Voltage functions are common to Division 1, Division 2, and Division 3. PERRY - UNIT 1 3/4 3-36
0 O O TABLE 4.3.3.1-1 5 g EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL
@ CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH q TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED A. DIVISION I TRIP SYSTEM
- 1. RHR-A (LPCI MODE) AND LPCS SYSTEM
- a. Reactor Vessel Water Level -
Low, Level 1 S M 1, 2, 3, 4 * , 5*
- b. Drywell Pressure - High S M Rfa R 1, 2, 3
- c. LPCS Pump Discharge Flow - Low g (Bypass) S M 1, 2, 3, 4*, 5*
- d. Reactor Vessel Pressure - Low S M R(a)
R
) 1, 2, 3, 4*, 5*
w (LPCS Injection Valve Permissive)'
} e. Reactor Vessel Pressure - Low S M R(,) 1, 2, 3, 4* , 5*
g (LPCI Injection Valve Permissive) a f. LPCI Pump A Start Time Delay N Relay NA M Q(,) 1, 2, 3, 4*, 5*
- g. LPCI Pump A Flow - Low (Bypass) S M R 1, 2, 3, 4*, 5*
- h. Manual Initiation NA R NA 1, 2, 3, 4*, 5*
- 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"#
- a. Reactor Vessel Water Level -
Low, Level 1 S M. R(a) 1, 2, 3
- b. Manual Inhibit NA M NA 1,2,3
- c. ADS Timer NA M Q 1,2,3
- d. Reactor Vessel Water Level -
Low, Level 3 (Permissive) S M R(a) 1, 2, 3
- e. LPCS Pump Discharge Pressure - High (Permissive) S M R(a) 1, 2, 3
- f. LPCI Pump A Discharge Pressure - High (Permissive) S M R(,) 1,2,3
- g. Manual Initiation NA R NA 1, 2, 3
TABLE 4.3.3.1-1 (Continued) N g EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL E CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH Q TRIP Fl'NCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED B. DIVISION 2 TRIP SYSTEM
- 1. RHR B AND C (LPCI MODE)
- a. Reactor Vessel Water Level -
Low, Level 1 S M R 1,2,3,4*,5*
- b. Drywell Pressure - High S M 1, 2, 3
- c. Reactor Vessel Pressure - Low S M R(3)
R 1, 2, 3, 4*, 5* (LPCI Injection Valve Permissive) w d. LPCI Pump B Start Time Delay 2 Relay NA M Q 1, 2, 3, 4*, 5* w e. LPCI Pump Discharge Flow - Low a (Bypass) S M R(a) 1, 2, 3, 4*, 5*
- f. Manual Initiation NA R NA 1,2,3,4*,5*
- 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"#
l
- a. Reactor Vessel Water Level -
Low, Level 1 S M R(a) 1, 2, 3
- b. Manual Inhibit NA M NA 1,2,3 l
- c. ADS Timer NA M Q 1, 2, 3 i
- d. Reactor Vessel Water Level -
Low, Level 3 (Permissive) S M R(a) 1, 2, 3
- e. LPCI Pump B and C Discharge Pressure - High (Permissive) S M R(a) 1,2,3
- f. Manual Initiation NA R NA 1,2,3 O O O
~ _.__ _ _ _ - . _. _ _ . _ _ _. __ . O O O TABLE 4.3.3.1-1 (Continued) E EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL E CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH Z TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED C. DIVISION 3 TRIP SYSTEM
- 1. HPCS SYSTEM
- a. Reactor Vessel Water Level -
a Low, Level 2 5 M R 1, 2, 3, 4*, 5*
- b. Drywell Pressure-High,, S M R 1,2,3
- c. Reactor Vessel Water Level - High, Level 8 S M R(3) 1,2,3,4*,5*
- d. Condensate Storage Tank Level -
Low S M R(,) 1, 2, 3, 4*, 5* R e. Suppression Pool Water
- Level - High S M R(3) 1,.2, 3, 4*, 5*
y f. HPCS Pump Discharge Pressure - g High S M R((,,) 1, 2, 3, 4*, 5*
- g. HPCS System Flow Rate - Low 5 M R
) 1, 2, 3, 4*, 5*
- h. Manual Initiation ## NA R NA 1, 2, 3, 4*, 5*
D. LOSS OF POWER
- 1. 4.16 kv Emergency Bus Under- NA NA R 1, 2, 3, 4**, 5**
voltage (Loss of Voltage) .
- 2. 4.16 kv Emergency Bus Under- S M R 1, 2, 3, 4**, 5**
voltage (Degraded Voltage)
#Not required to be OPERABLE when :eactor steam dome pressure is less than or equal to 100 psig.
##The injection function of Drywell Pressure - High and Manual Initiation are not required to be OPERABLE with indicated reactor vessel water level on the wide range instrument greater than the Level 8 setpoint coincident with reactor pressure less than 450 psig.
*When the system is required to be OPERABLE per Specification 3.5.2 or 3.5.3.
** Required when ESF equipment is required to be OPERABLE.
(a) Calibrate trip unit.setpoint at least once per 31 days.
INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION 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-RPT 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 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:
- 1. If the inoperable channels consist of one reactor vessel water level channel and one reactor vessel pre:sure channel, place both inoperable channels in the tripped c ocit'on* within one hour.
- 2. If the inoperable channels include two reactor vessel water level channels or two reactor vessel pressure channel;, 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. 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.
- The inoperable channels need not be placed in the tripped condition where this would cause the Trip Function to occur. In this case, the inoperable channels shall be restored to OPERABLE status within 2 hours, or the trip system shall be declared inoperable.
PERRY - UNIT 1 3/4 3-40
)
TABLE 3.3.4.1-1 , 9] ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION x 7 MINIMUMOPERABLECHAggjLSPER c: TRIP FUNCTION TRIP SYSTEM z ! I
- 1. Reactor Vessel Water Level - 2 i Low, Level 2
- 2. Reactor Vessel Pressure - High 2 (a) One channel may be placed in an inoperable status for up to 2 hours for required surveillance u, provided the other channel is OPERABLE.
1 Y h ;
TABLE 3.3.4.1-2 ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION SETPOINTS TRIP ALLOWABLE TRIP FUNCTION SETPOINT VALUE e-.
- 1. Reactor Vessel, Water Level - 1 129.8 inches
- 1 127.6 inches
[ Low, Level 2
- 2. Reactor Vessel Pressure - High 5 1083 psig i 1098 psig l
l
*See Bases figure B 3/4 3-1.
l w 2 Y e O O O
TABLE 4.3.4.1-1 h ATWS RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION SURVEILLANCE ' AEQUIREMENTS Q
, CHANNEL CHANNEL FUNCTIONAL CHANNEL c TRIP FUNCTION CHECK . TEST CALIBRATION 5
- 1. Reactor Vessel Water Level - S M R*
- Low, Level 2
- 2. Reactor Vessel Pressure - High S M R*
- Calibrate trip unit at setpoint at least once per 31 days.
M. 0
- _ = , _ ._ _
INSTRUMENTATION END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION O LIMITING CONDITION FOR OPERATION 3.3.4.2 The end-of-cycle recirculation pump trip (E0C-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 40% 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 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:
- 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 turbine control valve channels or two turbine stop valve channels, declare the trip system 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 40% 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 40% of RATED THERMAL POWER within the next 6 hours.
O PERRY - UNIT 1 3/4 3-44
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 sha'll be performed at least once per 18 months. 4.3.4.2.3 The END-OF-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. The measured time shall be added to the most recent breaker arc suppression time and the resulting END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME shall be verified to be within its limits. 4.3.4.2.4 The time interval necessary for breaker arc suppression from energi-zation of the recirculation pump circuit breaker trip coil shall be measured-at least once per 60 months. v' lO l PERRY - UNIT 1 3/4 3-45
TABLE 3.3.4.2-1 END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION I c;; HINIMUM OPERABLECHANNE[g)
] TRIP F1NCTION PER TRIP SYSTEM
- 1. Turbine Stop Valve - Closure 2(b)
- 2. Turbine Control Valve - Fast Closure 2(D)
(a)A trip system may be placed in an inoperable status for up to 2 hours for required surveillance w provided that the other trip system is OPERABLE. 1 (b)This function is automatically bypassed when turbine first stage pressure is less than the w value of turbine first stage pressure corresponding to 40% of RATED THERMAL POWER. O O O
_ _ _ - - _ - - _ . __ _ . . . _ _ . - - . _ _ . . -._... _ . _ . .-. _. . _ . ._ _ . _ . _ . - . _ . . .m._ __ .._._ . _ _ _ _ 4 TABLE 3.3.4.2-2 -
, .s
. s.-
@ END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM SETPOINTS 4 .
i ALLOWA8LE l e TRIP FUNCTION TRIP SETPOINT VALUE i
- 1. Turbine Stop Valve - Closure -< 5% closed -< 7% closed w
- 2. Turbine Control Valve - Fast Closure > 530 psig
> 465 psig ;
U i i N A , Y 0 . e 9 (
TABLE 3.3.4.2-3 END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME
- TRIP FUNCTION RESPONSE TIME (Milliseconds)
- 1. Turbine Stop Valve - Closure i 140
- 2. Turbine Control Valve - Fast Closure i 140
/
o Y 8 O . O O- -
a i j TABLE 4.3.4.2.1-1 i 1 "O > 1 E END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM SURVEILLANCE REQUIREMENTS -l E . I e CHANNEL l i c FUNCTIONAL CHANNEL ; 5 a TRIP FUNCTION TEST CALIBRATION j 1. Turbine Stop Valve - Closure M R i. l 2. Turbine Control Valve - Fast Closure M R l' l f f R. W I i c l i l l i _ _ _ _ . _ .' _ , _ . . . _ _ _ . ~ . . . - - - _ . _ _ _ - . _ . , _ . , . - . -. _ . - . . . _ _ . - _ . _ _ . . . . _ _ ,
INSTRUMENTATION 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 instrumenta-tion channels shown in Table 3.3.5-1 shall be OPERABLE with their trip set-points 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 adjusted consistent with the Trip Setpoint value.
1 l b. With one or ore RCIC system actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.5-1. SURVEILLANCE REQUIRFMENTS t l 4.3.5.1 Each RCIC system actuation instrumentation channel shall be demon-strated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL l TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table j 4.3.5.1-1. 4.3.5.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. l
*Not required to be OPERABLE until after non-nuclear heatup following initial criticality.
PERRY - UNIT 1 3/4 3-50
w TABLE 3.3.5-1 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION s MINIMUM i c { FONCTIONAL UNITS OPERABLECHANNEL{a) PER TRIP SYSTEM ACTION
- a. Reactor Vessel Water Level - Low, Level 2 2 50
- b. Reactor Vessel Water Level - High, Level 8 2(D) 51
- c. Condensate Storage Tank Water Level - Low 2(c) 52
- d. Suppression Pool Water Level - High 2(c) 52
- e. Manual Initiation 1(d) 53
$ (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without
- w placing the trip system in the tripped condition provided at least one other OPERABLE channel in the S
same trip system is monitoring that parameter. (b) One trip system with two-out-of-two logic. (c) One trip system with one-out-of-two logic.
; (d) There is only one manual switch.
I
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 System requirement:
- a. For one trip system, place the inoperable channel (s) and/or that trip system in the tripped condition within one hour or declare the RCIC system ;., operable.
- b. For both trip systems, declare the RCIC system inoperable.
ACTION 51 - With the number of OPERABLE channels less than required by the Minimum OPERABLE channels per Trip System requirement, declare the RCIC system inoperable. ACTION 52 - With the number of OPERAELE channels less than required by the Minimum OPERABLE Channels per Trip System requirement, place at least one inoperable channel in the tripped condition within one hour, or align the RCIC system to take suction from the suppression pool, or declare the RCIC system inoperable. ACTION 53 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement, restore the inoperable channel to OPERABLE status within 8 hours or declare + ~ > 'WiC system inoperable. O PERRY - UNIT 1 3/4 3-52 I
O O . TABLE 3.3.5-2 h REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOI'NTS 4 i ALLOWABLE g FUNCTIONAL UNITS TRIP SETPOINT VALUE El Reactor Vessel Water Level - Low, Level 2
- a. > 129.8 inches * > 127.6 inches
- b. Reactor Vessel Water Level - High, Level 8 5 219.5 inches
- 1 221.7 inches
- c. Condensate Storage Tank Level - Low > 63,300 gallons > 59,700 gallons T624 feet 10 inches T624 feet 7 inches 4
elevation) elevation)
- d. Suppression Pool Water Level - High < 18 feet 4.9 inches < 18 feet 6 inches i T593 feet 2.9 inches T593. feet 4 inches elevation) elevation)
R', e. Manual Initiation NA NA a Y w
*See Bases Figure B 3/4 3-1.
I I
TABLE 4.3.5.1-1 A g REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL E CHANNEL FUNCTIONAL CHANNEL p FUNCTIONAL UNITS CHECK TEST CALIBRATION
- a. Reactor Vessel Water Level -
Low, Level 2 S M R(a)
- b. Reactor Vessel Water Level - S M RI ")
High, Level 8
- c. Condensate Storage Tank Level -
Low S M R(3)
- d. Suppression Pool Water Level -
w High S M R(3) 1 w e. Manual Initiation NA R NA
. (a) Calibrate trip unit setpoint at least once per 31 days.
1 O -- O O -
INSTRUMENTATION O V 3/4.3.6 CONTill R00 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 valua.
- b. With the number 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.
s, SUP.VEILLANCE REQUIREMENTS , t s 1 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. PERRY - UNIT 1 3/4 3-55
l TABLE 3.3.6-1 h CONTROL R0D BLOCK INSTRUMENTATION E MINIMUM APPLICABLE I ' OPERABLE CHANNELS OPERATIONAL l @ TRIP FUNCTION PER TRIP FUNCTION CONDITIONS ACTION { U 1. R00 PATTERN CONTROL SYSTEM
- a. Low Power Setpoint 2 1, 2 60
- b. RWL - High Power 2 1 60 Setpoint
- 2. APRM
- a. Flow Biased Neutron Flux -
Upscale 6 1- 61
- b. Inoperative 6 1, 2, 5 61
- c. Downscale 6 1 61
- d. Neutron Flux - Upscale, Startup 6 2, 5 61 R 3. SOURCE RANGE MONITORS
[ a. Detector not full in(a) 3 2 61 J, 2** 5 61 Upscale (b) 2 61 b. 2
- c. Inoperative (b) 3 2
- d. Downscale(c) **
- 4. INTERMEDIATE RANGE MONITORS
- a. Detector not full in 6 2, 5 61
- b. Upscale 6 2, 5 61
- c. Inoperative 6 2, 5 61
- d. Downscale(d) 6 2, 5 61
- 5. SCRAM DISCHARGE VOLUME
- a. Water Level-High 2 1, 2, 5* 62
- 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW
- a. Upscale 6 1 62 REACTOR MODE SWITCH SHUTDOWN POSITION 2 3, 4 63
TABLE 3.3.6-1 (Continued) CONTROL R00 BLOCK INSTRUMENTATION ACTION ACTION 60 - Ceclare the RPCS inoperable and take the ACTION required by Specification 3.1.4.2. ACTION 61 - With the number of OPERABLE Channels:
- 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 next hour.
- b. Two or more 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.
ACTION 62 - 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 63 - With the number of OPERABLE channels iess than required by the l O Minimum OPERABLE Channels per Trip Function requirement, initiate a rod block. NOTES
*With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.
, **0PERABLE channels must be associated with SRMs required OPERABLE per Specification 3.9.2. (a)This funct1t... 5 automatically bypassed if detector count rate is > 100 cps or the IRM channels are on range 3 or higher. (b)This function is automatically bypassed when the associated IRM channels are on range 8 or higher.
~(c)This function is automatically bypassed when the IRM channels are on range 3 or higher.
(d)This function is automatically bypassed when the IRM channels are on range 1. PERRY - UNIT 1 3/4 3-57 . I L
TABLE 3.3.6-2 CONTROL R00 BLOCK INSTRUMENTATION SETPOINT9 9
, TRIP FUNCTION TRIP SETPOINT ALLOWABLE VALUE O 1. R0D PATTERN CONTROL SYSTEM 7 a. Low Power Setpoint 20 + 15, - 0% of RATED THERMAL POWER ** 20 + 15, - 0% of RATED THERMAL POWER **
c b. RWL - High Power Setpoint 70 + 0, - 15% of RATED THERMAL POWER ** 70 + 0, - 15% of RATED THERMAL POWER **
% 2. APRM
- a. Flow Biased Neutron Flux -
Upscale 5 0.66 W . 42%*# 5 0.66 W + 45%*#
- b. Inoperative NA NA
- c. Downscale 1 4% of RATED THERMAL POWER 1 3% of RATED THERMAL POWER
- d. Neutron Flux - Upscale Startup 1 12% of RATED THERMAL POWER 5 14% of RATED THERMAL POWER
- 3. SOURCE RANGE MONITORS
- a. Detector not full in NA NA
- b. Upscale 1 1 x 105 cps 5 1.6 x 105 cps
- c. Inoperative NA gg NA gg
- d. Downscale 2 0.7 cps 1 0.5 cps
{ 4. INTERMEDIATE RANGE MONITORS w a. Detector not full in NA NA E b. Upscale < 108/125 division of full scale < 110/125 division of full scale
- c. Inoperative HA HA
- d. Downscale 1 5/125 division of full scale 1 3/125 division of full scale
- 5. SCRAM DISCHARGE VOLUME
- a. Water Level - High -< 16.6 inches *** -< 17.48 inches ***
(624' 3.3" elevation) (624' 4.17" elevation)
- 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW
- a. Upscale 5 108% of rated flow 1 110% of rated flow
- 7. REACTOR 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.
**The actual setpoints are the corresponding values of the turbine first stage pressure for these power levels.
*** Level zero is 622' 10.69" elevation; level transmitter readout.
#During the startup test program, the APRM trip setpoint and allowable value may be permitted to be increased to the ME00 values (trip setpoint of 0.66 W + 58% and allowable value of 0.66 W + 61%).
rovided signal to noise ratio 1 2.
l ' O TABLE 4.3.6-1 O CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS i
! A E
CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST CALIBRATION (a) SURVEILLANCE REQUIRED
- 1. R00 PATTERN CONTROL SYSTEM
- a. Low Power Setpoint NA S/ #
SA 1, 2
- b. RWL - High Power Setpoint NA S/U(b) g(d)
D(c) g(d) #
, SA 1
- 2. APRM
{ a. Flow Biased Neutron Flux - SAI ') Upscale NA S/U(b) W 1
- b. Inoperative NA S/U(b),W NA 1,2,5
- c. Downscale NA S/U(b),y 34 7
- d. Neutron Flux - Upscale,'Startup. NA S/U(b),W , SA 2, 5
$ 3. SOURCE' RANGE MONITORS '
- a. Detector not full in NA S/U(b) W NA 2, 5
- b. Upscale NA S/U(b), SA 2, 5
. c. Inoperative NA -S/U(b),W .NA 2, 5 j d. Downscale NA S/U(b),W ,W SA 2, 5
! 4. INTERMEDIATE RANGE MONITORS
- a. Detector not full in NA S/U ,W NA 2, 5
. b. Upscale NA S/U(b),W. SA 2, 5 l c. Inoperative NA S/U(b),W NA 2, 5
- d. Downscale NA S/U ,W SA 2, 5
- 5. SCRAM DISCHARGE VOLUME i a. Water Level - High NA M R 1, 2, 5*
- 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW
- a. Upscale NA S/U(b) g ,
gg(e) y
- 7. REACTOR MODE SWITCH SHUTDOWN POSITION NA R NA 3, 4
TABLE 4.3.6-1 (Continued) CONTROL R0D BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTES:
- a. Neutron detectors may be excluded from CHANNEL CALIBRATION.
- b. Within 24 hours prior to startup, if not performed within the previous 7 days.
- c. Within one hour prior to control rod movement, unless performed within the previous 24 hours, and as power is increased above the RPCS low power setpoint and the RPCS high power setpoint and as power is decreased below the RPCS high power setpoint for the first time during any 24 hour period during power increase or decrease.
- d. At least once per 31 days whild operation continues with power above the RPCS low power setpoint.
- e. The CHANNEL CALIBRATION shall exclude the flow reference transmitters, these transmitters shall be calibrated at least once per 18 months.
*With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. # Calibrate trip unit setpoint at least once per 31 days.
O PERRY - UNIT 1 3/4 3-60
INSTRUMENTATION 3/4.3.7 MONITORING INSTRUMENTATION 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. i , s PERRY - UNIT 1 3/4 3-61
TABLE 3.3.7.1-1 A RADIATION MONITORING INSTRUMENTATION 58
' MINIMUM CHANNELS APPLICABLE ALARM / TRIP g INSTRUMENTATION OPERABLE CONDITIONS SETPOINT ACTION Z **
g 1. Fuel Handling 1 1 1500 cpm 70 Area Vent Exhaust Radiation Monitor (Noble Gas)
- 2. Offgas 1
- 1 1.x 108 cpm (b) 71 Post-treatment Radiation Monitor
- 3. Control Room 1 All OPERATIONAL ~< 800 cpm 72 Ventilation Radiation ' CONDITIONS and ***
w Monitor (Noble Gas) 2 m 4. Offgas Pre-treatment 1 * (c) 73 a Radiation Monitor n
- 5. Area Monitors
- a. Criticality Monitors
- 1) Fuel Pre- 1 15mR/hrggg 74 paration Pool 5 20 mR/hr
- 2) Spent Fuel 1 >5mR/hrggg 74 Storage Pool 5 20 mR/hr
- 3) Upper Contain- 1 1 5mR/hrpgj 74 ment Pools < 20 mR/hr
- b. Control Room 1 At all times 1 2.5 mR/hr(a) 75 Area Radiation Monitor O O O
O TABLE 3.3.7.1-1 (Continued) A RADIATION MONITORING INSTRUMENTATION E s Si TABLE NOTATION Z w , When the offgas treatment system is operating. AA With irradiated fuel in the Fuel Handling Building. AAA . 1 When irradiated fuel is being handled in the Fuel Handling Building or primary containment.
-(a) Alarm only.
(b) Isolates the offgas system. (c) Alarm setpoint to be set in accordance with Specification 3.11.2.7. With fuel in the fuel preparation pool.
)"; ##
With fuel in the spent fuel storage pool. Y With fuel stored in the upper containment pools. l
TABLE 3.3.7.1-1 (Continued) RADIATION MONITORING INSTRUMENTATION ACTION ACTION 70 - With the required monitor inoperable, obtain and analyze at least one grab sample of the monitored parameter at least once per 24 hours. In addition, with the Unit 1 Vent noble gas monitor inoperable, restore the inoperable noble gas monitor to OPERABLE status within 24 hours or place the inoperable notie gas monitor in the tripped condition. ACTION 71 - With the required monitor inoperable, release via this pathway may continue provided grab samples are taken at least once per 8 hours and these samples are analyzed for gross activity within 24 hours. ACTION 72 - With the required monitor inoperable, assure a portable con-tinuous noble gas monitor is OPERABLE in the control room within 24 hours. Restore the inoperable monitor to OPERABLE status within 7 days, otherwise, initiate and maintain operation of the control room emergency filtration system in the isolation mode of operation within 1 hour. ACTION 73 - With the number of channels OPERABLE less than required by Minimum Channels OPERABLE requirement, release via this pathway may continue for up to 30 days provided:
- a. The offgas system is not bypassed, and
- b. The offgas post-treatment monitor is OPERABLE, and
- c. 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.
ACTION 74 - With the required monitor inoperable, assure a portable area radiation monitor with the same alarm setpoint is OPERABLE in the vicinity of the installed monitor during any fuel movement. If no fuel movement is being made, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours. ACTION 75 - With the required monitor inoperable, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours. O PERRY - UNIT 1 3/4 3-64
O 1 O TABLE 4.3.7.1-1 RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS g CHANNEL CONDITIONS IN q CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE INSTRUMENTATION CHECK TEST CALIBRATION REQUIRED
- 1. Fuel Handling Area Vent Exhaust **
Radiation Monitor S M R (Noble Gas)
- 2. Offgas Post-treatment
- Radiation Monitor S H R
- 3. Control Room Ventilation Radiation All 0PERATIONAL Monitor (Noble Gas) CONDITIONS and ***
$ S M R T 4. Offgas Pre-treatment
$ Radiation Monitor S M R
- 5. Area Monitors
- a. Criticality Monitors
- 1) Fuel Preparation y Pool S M R
- 2) Spent Fuel-Storage gy Pool S M R
- 3) Upper Containment ggy Pools S M R
- b. Control Room Area Radiation Monitor S M R At all times
TABLE 4.3.7.1-1 (Continued) m g RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS g TABLE NOTATION p H When the offgas treatment system is operating. With irradiated fuel in the Fuel Handling Building.
***When irradiated fuel is being handled in the fuel Handling Building or primary containment.
With fuel in the fuel preparation pool. With fuel in the spent fuel storage pool. With fuel stored in the upper containment pools. N. Y 6 O O O
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 O 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 0.05g shall be restored to OPERA 8LE status within 24 hours and a CHANNEL CALIBRATION performed within 30 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 Commission pursuant to Specification 6.9.2 within 10 days describing the magnitude, fre-quency spectrum and resultant effect upon unit features important to safety. l d P i PERRY - UNIT 1 3/4 3-67
TABLE 3.3.7.2-1 SEISMIC MONITORING INSTRUMENTATION MINIMUM MEASUREMENT INSTRUMENTS INSTRUMENTS AND SENSOR LOCATIONS RANGE OPERABLE
- 1. Triaxial Time-History Accelerographs
- a. 051-N101 Reactor Building 0.01 - 1.0g 1 Foundation
- b. 051-N111 Containment Vessel 0.01 - 1.0g 1
- c. 051-N100 Reactor Building 0.005 - 0.02g 1(D)
Foundation
- d. 051-N110. Reactor Building 0.005 - 0.02g 1(b)
Foundation
- 2. Triaxial Peak Accelerographs
- a. 051-R120 Reacter Recirculation 0.05 - 1.0g 1 l Pump l
- b. D51-R130 HPCS Piping in Reactor 0.05 - 1.0g 1 Building
- c. D51-R140 HPCS Pump Base Mat 0.05 - 1.0g 1 1
- 3. Triaxial Seismic Switches
- a. 'D51-N150 Reactor Building 0.025 - 0.25g 1(a)
Foundation
- 4. Triaxial Response-Spectrum Recorders
- a. 051-R160 Reactor Building 2 - 25.4 Hz 1(a)
Foundation ~
- b. 051-R170 Reactor Recirculation 2 - 25.4 Hz 1 Diping Support
- c. 051-R180 HPCS Pump Base Mat 2 - 25.4 Hz 1
- d. 051-RISO RCIC Pump Base Mat 2 - 25.4 Hz 1 (a)With control room annunciation.
(b) Seismic trigger with control room annunciation. O PERRY - UNIT 1 3/4 3-68
TABLE 4.3.7.2-1 1 A k,,/ SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL FUNCTIONAL CHANNEL INSTRUMENTS AND SENSOR LOCATIONS CHECK TEST CALIBRATION
- 1. Triaxial Time-History Accelerographs
- a. D51-N101 Reactor Building M SA R Foundation
- b. 051-N111 Containment Vessel M SA R
- c. 051-N100 Reactor Building NA SA R Foundation
- d. 051-N110 Reactor Building NA SA R Foundation
- 2. , Triaxial Peak Accelerographs
- a. D51-R120 Reactor Recircula- NA NA R tion Pump
- b. D51-R130 HPCS Piping in NA NA R Reactor Building
- c. D51-R140 HPCS Pump Base Mat NA NA R
, 3. Triaxial Seismic Switches
- a. 051-N150 Reactor Building M(a) SA R Foundation
- 4. Triaxial Response-Spectrum Recorders
- a. 051-R160 Reactor Building M NA R Foundation
- b. 051-R170 Reactor Recircula- NA NA R tion Piping Support
- c. 051-R180 HPCS Pump Base Mat NA NA R l d. 051-R190 RCIC Pump Base Mat NA NA R (a)Except seismic trigger.
i PERRY - UNIT 1 3/4 3-69
- , ----- ,- - - - ~ - --,w -,, w-- - - - - - , - - - - - - - - -
INSTRUMENTATION METE]RCLOGICAL MONITORING INSTRUMENTATION O LIMITING CONDITION FOR OPERATION 3.3.7.3 The meteorological monitoring instrumentation shown in Table 3.3.7.3-1 shall be OPERABLE. APPLICABILITY: At all times. ACTION:
- a. With one or more of the above required meteorological monitoring instruments inoperable for more than 7 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 instrumentation to OPERABLE status.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.7.3 Each of the above required meteorological monitoring instruments shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.3-1. l l l 1 l l PERRY - UNIT 1 3/4 3-70
11 TABLE 3.3.7.3-1 N METEOROLOGICAL MONITORING INSTRUMENTATION MINIMUM INSTRUMENTS INSTRUMENT OPERABLE ,
- a. Wind Speed
- 1. Elevation 10 m 1
- 2. Elevation 60 m 1
- b. Wind Direction
- 1. Elevation 10 m 1
- 2. Elevation 60 m . I
- c. Air Temperature Difference
- 1. Elevation 10/60 m 1 l
I J e h P t l l i l l i
~
t PERRY - UNIT 1 3/4 3-71
. _ ,... _ __ ____ . _ _ - . . _ _ . _ . . . . _ _ . . _ . . _ , _ _ _ . _ _ _ . _ _ _ . _ _ _ _ _ . _ - _ _ , ~ . _ _ . _ - - - _ - - - _ _ _ _ _ _ . _ - - , _
l l l TABLE 4.3.7.3-1 METEOROLOGICAL MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS l CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION
- a. Wind Speed
- 1. Elevation 10 m D SA
- 2. Elevation 60 m D SA
- b. Wind Direction
- 1. Elevation 10 m D SA
- 2. Elevation 60 m D SA
- c. Air Temperature Difference
- 1. Elevation 10/60 m D SA O
O PERRY - UNIT 1 3/4 3-72
INSTRUMENTATION \- / REMOTE SHUT 00WN SYSTEM INSTRUMENTATION AND CONTROLS LIMITING CONDITION FOR OPERATIOM 3.3.7.4 The remote shutdown system instrumentation and controls shown in Table 3.3.7.4-1 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With the number of OPERABLE remote shutdown system' 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 HGT SHUTDOWN within the next 12 hours.
- b. With the number of OPERABLE remote shutdown system controls less than required in Table 3.3.7.4-1, 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 shutdown system 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 Each of the above remote shutdown controls.shall oe demonstrated OPERABLE by verifying its capability to perform its intended function (s) at least once per 18 months. M PERRY - UNIT 1 3/4 3-73 .
TABLE 2.3.7.4-1 REMOTE SHUTDOWN SYSTEM INSTRUMENTATION MINIMUM CHANNELS OPERABLE INSTRUMENT Division 1 Division 2
- 1. Reactor Vessel Pressure 1 1
- 2. Reactor Vessel Water Level 1 1
- 3. Safety / Relief Valve Position *, 3 valves 3/"alve 1/ valve
- 4. Suppression Pool Water Level 1 1
- 5. Suppression Pool Water Temperature 1 1
- 6. Drywell Pressure 1 1
- 7. Drywell Temperature 1 1
- 8. RHR System Flow 1 1
- 9. Emergency Service Water Flow to RHR 1 1 Heat Exchanger
- 10. Emergency Service Water-Flow to 1 1 Emergency Closed Cooling Heat Exchanger
- 11. RCIC System Flow 1 NA
- 12. RCIC Turbine Speed 1 NA
- 13. Emergency Closed Cooling 1 1 System Flow
- 14. Inboard MSIV Position **, 4 valves NA 1
- Indicating lights to indicate valve solenoid energized /de-energized.
** Indicating lights to indicate valve position.
G~ PERRY - UNIT 1 3/4 3-74
TABLE 3.3.7.4-1 (Continued) REMOTE SHUTDOWN SYSTEM CONTROLS
/
h] CONTROL ESW Pump MINIMUM CHANNELS OPERABLE Division 1 1 Division 2 1 ESW Pump Discharge Valve 1 1 RHR HX's ESW Inlet / Outlet Valves 2(,) 2(,) RHR HX's Inlet / Outlet / Bypass Valves 3(a) 3(a) RHR Pump 1 1 RHR to Containment Shutoff Valve 1 1 RHR Pump Suppression Pool Suction Valve 1 1 LPCI Injection Valve 1 1 RHR A Shutdown Cooling Suction Valve 1 NA RHR Upper Pool Suction Valve 1 1 RHR Head Spray Isolation Valve 1 NA RHR HX's Dump Valve 1 1 Containment Spray First Shutoff 1 1 Shutdown Cooling to Feedwater Shutoff 1 1 RHR Test Valve to Suppression Pool 1 1 Shutdown Cooling Outboard Suction Isolation Valve 1 NA RHR A to Radwaste Second Isolation Valve 1 NA Steam Condensing Shutoff Valve to RCIC 1 1 RHR HX's Steam Shutoff Valve 1 1 RHR Pump Minimus Flow Valve 1 ] ECC Pump 1 1 RCIC Turbine Gland Seal Compressor 1 NA RHR & RCIC Steam Supply Outboard Isolation Valve 1 NA RCIC Second Test Valve to CST 1- NA RCIC Turbine Trip C RCIC Steam Shutoff Valve
. 1.
1 NA' NA RCIC First Test Valve to CST 1 NA RCIC Pump CST Suction Valve 1 NA RCIC Injection Valve- 1 NA RCIC Pump Suppression Pool Suction Isolation Valve 1 NA RCIC Turbine Trip Throttle ~ Valve 1 NA RCIC Pump Minimum Flow Valve 1 NA RCIC Turbine Exhaust Shutoff Valve 1 NA RCIC Exhaust Vacuum Breaker Outboard Isolation Valve 1 NA RCIC Pump Discharge to L.0. Cooler Valve 1 NA RCIC Exhaust Vacuum Breaker Inboard Isolation Valve NA 1* RHR 8 Shutdown Cooling Suction Valve NA 1* Shutdown Cooling Inboard Suction Isolation. Valve NA 1* RHR & RCIC Steam Supply Inboard Isolation Valve NA 1* RHR & RCIC Steam Supply Warmup Isolation Valve Ng) 1 Safety Relief Valves 3 3{3) Control Room to Shutdown Panel Transfer Switches 2* APRM Power Supply Breakers 14 1*, (b) 7
)
Inboard Main Steam Isolation Valve NA 2 Diesel Generator Room Fan 1A Temperature Controller 1 NA l (a) 1 per valve l (b) One breaker constitutes one channel for ATWS Division 1 and Division 2. l (c) One switch for Solenoid "A" per 4 valves, one switch for Solenoid "B" per 4 - l valves.
,j
- These Division 2 controls are physically located on the Division 1 panel, v ** These breakers are physically located on ATWS Distribution Panels 1R14-5014 l and 1R14-5015.
! PERRY - UNIT 1 3/4 3-75
TABLE 4.3.7.4-1 REMOTE SHUTDOWN SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION
- 1. Reactor Vessel Pressure M R
- 2. Reactor Vessel Water Level M R
- 3. Safety / Relief Valve Position M NA
- 4. Suppression Pool Water Level M R S. Suppression Pool Water Temperature M R
- 6. Drywell Pressure M R
- 7. Drywell Temperature M R
- 8. RHR System Flow M- R
- 9. Emergency Service Water Flow to RHR H R Heat Exchanger
- 10. Emergency Service Water Flow to Emergency M R Closed Cooling Heat Exchanger
- 11. RCIC System Flow M R
- 12. RCIC Turbine Speed M R
- 13. Emergency Closed Cooling System Flow M R l 14. Inboard MSIV Position M NA 1
l , O. PERRY - UNIT 1 3/4 3-76 1
\
INSTRUMENTATION ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 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. I 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. O l l PERRY - UNIT 1 3/4 3-77
TABLE 3.3.7.5-1 A g ACCIDENT MONITORING INSTRUMENTATION i E MINIMUM APPLICABLE q REQUIRED NUMBER CHANNELS OPERATIONAL g INSTRUMENT OF CHANNELS OPERABLE CONDITIONS ACTION
- 1. Reactor Vessel Pressure 2 1 1,2,3 80
- 2. Reactor Vessel Water Level 2 1 1,2,3 80
- 3. Suppression Pool Water Level 2 1 1,2,3 80
- 4. Suppression Pool Water Temperature 16, 2/ sector 8, 1/ sector 1,2,3 80
- 5. Primary Containment Pressure 2 1 1,2,3 80
- 6. Primary Containment Air Temperature 2 1 1,2,3 80
- 7. Drywell Pressure 2 1 1,2,3 80
- 8. Drywell Air Temperature 2 1 1,2,3 80
- 9. Primary Containment and Drywell Hydrogen Concentration Analyzer and Monitor 2 1 1,2,3 80 R 10. Safety / Relief Valve Position Indicators ** 2/ valve 1/ valve 1,2,3 80
- 11. Primary Containment /Drywell Area Gross Gamma Radiation Monitors ## 2* 1* 1,2,3 81 m 12. Offgas Ventilation Exhaust Monitor,*gg 1 1 1,2,3 81
- 13. Turbine Building / Heater Bay Ventilation Exhaust Monitor #'## 1 1 1,2,3 81
- 14. Unit 1 Vent Monitorgg 'gg 1 1 1,2,3 81
- 15. Unit 2 Vent Monitor *gg 1 1 1,2,3 81
- 16. Neutron Flux ##
- a. Average Power Range 2 1 1,2,3 80
- b. Intermediate Range 2 1 1,2,3 80
- c. Source Range ,,, gg 2 1 1,2,3 80
- 17. Primary Containment Isolation Valve Position '
2/ valve 1/ valve 1,2,3 82 A Each for primary containment and drywell. AA One channel consists of a pressure switch on the SRV discharge pipe, the other channel consists of a temperature sensor on the SRV discharge pipe. AAA One channel consists of the open limit switch, and the other channel consists of the closed limit switch for each automatic containment isolation valve in Table 3.6.4-1,a. High and intermediate range D19 system noble gas monitors, t required to be OPERABLE prior to exceeding 5% ATED THERMAL POWER.
l Table 3.3.7.5-1 (Continued) ACCIDENT MONITORING INSTRUMENTATIONS ACTION STATEMENTS ACTION 80 -
- a. With the numoer 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, rertare the inoperable channel (s) to OPERA 8LE status within 48 haurs or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN wit'h the following 24 hours.
ACTION 81 - With the number of OPERABLE 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.
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 alter-nate indication 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 i following 24 hours.
- b. With the number of OPERA 8LE accident monitoring instrumentation
, channels less than the Minimurc Channels OPERABLE requirements of Table 3.3.7.5-1, verify the valve (s) position by use of alter-nate indication methods; restore the inoperable channel (s) to l OPERABLE status within 7 days or be in at least HOT SHUTDOWN I within the next 12 hours and in COLD SHUIDOWN within the follow-ing 24 hours. PERRY - UNIT 1 3/4 3-79
TABLE 4.3.7.5-1 M jg ~ ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS
' APPLICABLE E CHANNEL CHANNEL OPERATIONAL M INSTRUMENT CHECK CALIBRATION CONDITIONS
- 1. Reactor Vessel Pressure M R 1,2,3
- 2. Reactor Vessel Water Level M R 1,2,3
- 3. Suporession Pool Water Level M R 1, 2, 3
- 4. Suppression Pool Water Temperature M R 1,2,3
- 5. Primary Containment Pressure M R 1,2,3
- 6. Primary Containment Air Temperature M R 1,2,3
- 7. Drywell Pressure M R 1,2,3
- 8. Drywell Air Temperature M R 1,2,3
- 9. Primary Containment and Drywell Hydrogen Concentration Analyzer and Monitor NA Q* 1,2,3
- 10. Safety / Relief Valve Position Indicators M R 1,2,3 y 11. Primary Containment /Drywell Area
[ Gross Gamma Radiation Monitors ## M R** 1,2,3
$ 12. Offgas Ventilation Exhaust Monitor #'## M R 1,2,3
- 13. Turbine Building / Heater Bay Ventilation Exhaust Monitor #'## M R 1, 2, 3
- 14. Unit 1 Vent Monitor #'## M R 1,2,3
- 15. Unit 2 Vent Monitor #'## M R 1,2,3
- 16. Neutron Flux ##
- a. Average Power Range M R 1,2,3
- b. Intermediate Range M R 1,2,3
- c. Source Range g M R 1,2,3
- 17. Primary Containment Isolation Valve Position , M R 1,2,3
*Using sample gas containing:
- a. One volume percent hydrogen, balance nitrogen.
- b. Four volume percent hydrogen, balance nitrogen.
**The 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 and intermediate range D19 system noble gas monitors.
t required to be OPERABLE prior to exceeding 5% ATED THERMAL POWER.
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 con-trol rods to be fully inserted in the core and lock the reactor mode switch in the Shutdown position within one hour.
SURVEILLANCE REQUIREMENTS b' 4.3.7.6 Each~of the above required source range monitor channels shall be demonstrated OPERABLE by:
- a. Performance of a:
- 1. CHANNEL CHECK at least once per:
i 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 I
- 2. At least once per 31 days.
- c. Verifying, prior to withdrawal of control rods, that the SRM count rate is at least 0.7 cps *** with the detector fully inserted, i
*With IRM's on range 2 or below.
** Neutron detectors may be excluded from CHANNEL CALIBRATION.
( ***Provided the signal-to-noise ratio is > 2. _ PERRY - UNIT 1 3/4 3-81 4 e-,..- - - -- , _ ,_ - -. , , _ . _ _ _ _ _ _ _ . - _.__ _ __
INSTRUMENTATION TRAVERSING IN-CORE PROBE SYSTEM LIMITING CONDITION FOR OPERATION 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, do not use 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 i 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 l to use when required for the LPRM calibration function. 1 "Only the detector (s) in the location (s) of interest are required to be C 'ABLE. O PERRY - Ut!IT 1 3/4 3-82
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 channels inoperable for
- more than 30 days, prepare aad submit a Special Report to the Com-mission 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.
- l
. b. The provisions of Specifications 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.
l . i. i l s I i' PERRY - UNIT 1 3/4 3-83 . yN-* 4 9p yy--=Tye"w+m&-mmv y g_---r--y"T==' T-> ++rr -w-- h-=&w w+r +'-w--w-----pg-yee w -e-e v-*f4- -WP-+w +-N-ww w gwwwav'-mweN et- we-es-w.NwT 'a. e-v=wW-'* = ' '-*P=w *v eu "*J"T+
INSTRUMENTATION RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 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 OFFSITE DOSE CALCULATION MANUAL (00CM). 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 inoperal.e.
- 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 OPERABLE status within the time specified in the ACTION and, if unsuccessful, explain why this inoperability was not corrected in a timely manner in the next Semiannual Radioactive Effluent Release Report.
- 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 operations at the frequencies shown in Table 4.3.7.9-1. i s D O PERRY - UNIT 1 3/4 3-84
O O O TABLE 3.3.7.9-1 A g RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION
' MINIMUM c: CHANNELS ACTION 3 INSTRUMENT OPERABLE
- 1. GROSS RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE
- a. Liquid Radwaste Discharge Radiation Monitor - 1 110 ESW Discharge 1
- 2. GROSS BETA OR GAMMA RADI0 ACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE
- a. Emergency Service Water Loop A Radiation Monitor 1 111 m b. Emergency Service Water Loop B Radiation Monitor 1 111 2
T 3. FLOW RATE MEASUREMENT DEVICES
- a. Radwaste Discharge Header l 1. Radwaste High Flow Discharge Header Flow 1 112 l 2. Radwaste Low Flow Discharge Header Flow 1 112 l -
l b. Service Water Discharge Header Flow ~ 1 113
- c. Unit 1 Emergency Service Water Flow Monitor 1 113 l
l l l 9
TABLE 3.3.7.9-1 (Continued) RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION ACTION STATEMENTS ACTION 110 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases from 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 4.11.1.1.1, and
- b. At least two technically cualified members of the Facility Staff independently verify the release rate calculations and discharge line valving; Otherwise, suspend rr. lease of radioactive effluents via this pathway.
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 (beta or gamma) at a limit of detection of at least 10 7 microcuries/ml. 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 dis-charge valve position is verified to be consistent with the flow rate provisions of the release permit at least once per 4 hours during actual releases. Prior to initiating another release, at least two technically qualified members of the Facility Staff shall independently verify tue discharge line valving and that the discharge valve position corresponds to the desired flow rate. Otherwise, suspend release of radioactive effluents via this pathway. ACTION 113 - 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. O PERRY - UNIT 1 3/4 3-86 l I l
O O O
~
TABLE 4.3.7.'9 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL c CHANNEL SOURCE CHANNEL FUNCTIONAL h INSTRUMENT CHECK CHECK CALIBRATION TEST ! 1. GROSS RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE
- a. Liquid Radwaste Discharge Radiation D P R(3) Q(1)
Monitor - ESW Discharge
- 2. GROSS BETA OR GAMMA RADI0 ACTIVITY MONITORS PROVIDIP3 ALARM BUT NOT PROVIDING AUTOMATIC TERMINAlI0N OF RELEASE
, a. Emergency Service Water Loop A Radiation D M R(3) Q(2) , g Monitor
[ b. Emergency Service Water Loop B Radiation D M R(3) Q(2) , w Monitor I 3. FLOW RATE MEASUREMENT DEVICES
- a. Radwaste Discharge Header
- 1. Radwaste High Flow Discharge Header Flow D(4) N.A. R Q 1
l '2. Radwaste Low Flow Discharge Header Flow D(4) N.A. R Q i
- b. Service Water Discharge Header Flow 0(4) N.A. R Q
! c. Unit 1 Emergency Service Water Flow 0(4) N.A. R Q l Monitor T
F l TABLE 4.3.7.9-1 (Continued) RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS TABLE NOTATION (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:
- 1. Instrument indicates measured levels above the alarm / trip setpoint.
- 2. Instrument indicates a downscale failure.
- 3. Instrument controls not set in operate mode except in high voltage position.
(2) Tr,9 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. Instrument indicates a downscale failure.
- 3. Instrument controls not set in operate mode, except in high voltage position.
(3) The initial CHANNEL CALIBRATION shall be performed using one or more of I the reference standards certified by the National Bureau of Standards or i 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 shall be used. (4) CHANNEL CHECK shall consist of verifying indication of flow during periods of release. CHANNEL CHECK shall be made at least once per 24 hours on days which continuous, periodic or batch releases are made. l l l l O PERRY - UNIT 1 3/4 3-88
g INSTRUMENTATION 4 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 e'nsure that the Ifmit of Specification 3.11.2.1* are'not exceeded. The alarm / trip setpoints of applicable channels 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, declare the channci inoperable.
- b. With less than the minimum number of radioactive gaseous effluent monitoring instrumentation channels OPERA 8LE, 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 and, if unsuccessful, explain why this inoperability was not corrected in a g timely manner in the next Semiannual Radioactive Effluent Release Report.
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.7.10 Each radioactive gaseous effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations at the frequencies shown in Tc51e 4.3.7.10-1. I r O *See Specification 3.11.2.6 for the Main Condenser Of fgas Hydrogen Monitor (1N64-N012A/8) 1imit. PERRY - UNIT 1 3/4 3-89 l i
TABLE 3.3.7.10-1 A RADI0 ACTIVE CASE 0US EFFLUENT MONITORING INSTRUMENTATION g E MINI.4UM CHANNELS
$ INSTRUMENT OPEPABLE APPLICABILITY ACTION
- 1. OFFGAS VENT RADIATION MONITOR
- a. Noble Gas Activity Monitor 1 121
- b. Iodine Sampler 1 122
- c. Particulate Sampler 1 122
- d. Effluent System Flow Rate Monitor 1 123
$ e. Sampler Flow Rate Monitor 1 123
- 2. UNIT 1 VENT RADIATION MONITOR
, a. Noble Gas Activity Monitor 1 125
- b. Iodine Sampler 1 122
- c. Particulate Sampler 1 122
- d. Effluent System Flow Rate Monitor 1 123
- e. Sampler Flow Rate Monitor 1 123 O O O
i m f U TABLE 3.3.7.10-1 (Continued) A
.RADI0 ACTIVE GASE0US EFFLUENT MONITORING INSTRUMENTATION Hj ;
1-e E MINIMUM CHANNELS
- 1 INSTRUMENT OPERABLE APPLICABILITY- ACTION r
- 3. UNIT 2 VENT RADIATION MONITOR
- a. Noble Gas Activity Monitor 1 121
- b. Iodine Sampler 1 122 i c. Particulate Sampler 1 122
! d. Effluent System Flow Rate Monitor 1 123 u, e. Sampler Flow Rate Monitor 1 123 i 3; l u, 4. HEATER BAY / TURBINE BUILDING VENT R?.91ATION MONITOR s"' * ,i a. Noble Gas Activity Monitor 1 121 1 .
*' 122 l b. Iodine Sampler _ 1 1
- c. Particulate Sampler 1 122
- d. Effluent System Flow Rate Monitor 1 123 1
- 123
) e. Sampler Flow Rate Monitor 1
- 5. MAIN CONDENSER OFF-GAS HYDROGEN MONITOR t
** 124
- a. Hydrogen Monitor 1 .
j - , 4 l 1
l TABLE 3.3.7.10-1 (Continued) RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION TABLE NOTATION
- At all times.
** During main condenser offgas treatment system operation.
ACTION 121 - With the number of channels OPERABLE less than required by the Minmum 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. 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 samples are continuously collected within 8 hours with auxiliary sampling equipment as required by Table 4.11.2.1.2-1. ACTION 123 - With the number of channels OPERA 8LE 1ess than required by the Minimum Channels OPERABLE requirement, effluent release via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 4 hours. 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 provided grab samples are collected at least once per 4 hours and analyzed within the following 4 hours. If the recombiner temperature remains constant and-THERMAL POWER has not changed, the grab sample collection frequency may be changed to at least once per 8 hours. ACTION 125 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, except as a result of a non-conservative setpoint, immediately suspend containment / drywell purge and vent. Prior to resuming containment /drywell purge and vent, ensure compliance with the requirements of Specification 3.11.2.1. If compliance with Specifica-tion 3.11.2.1 is met, containment /drywell purge and vent 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. O PERRY - UNIT 1 3/4 3-92
p k \. TABLE 4.3.7.10-1 A E RADI0 ACTIVE GASE0'IS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS E CHANNEL MODES IN WHICH l :1 CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE ,
~ INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED
, 1. OFFGAS VENT RADIATION MONITOR
- a. Noble Gas Activity Monitor D M R(2) Q(1) 1
- b. Iodine Sampler W(4) N.A. N.A. N.A.
j c. Particulate Sampler W(4) N.A. N.A. N.A. ,
- d. Effluent System Flow Rated'onitor D N.A. R Q
, u 3 e. Sampler Flow Rate Monitor D N.A. R Q
- 2. UNIT 1 VENT RADIATION MONITOR 1
j , a. Noble Gas Activity Monitor D M R(2) Q(1) , j
- b. Iodine Sampler W(4) N.A. N.A. N.A.
i c. Particulate Sampler W(4) N.A. N.A. N.A. i Effluent System Flow Rate d. Monitor D N.A. R Q
- e. Sampler Flow Rate Monitor D N.A. R Q 1
1
,i
TABLE 4.3.7.10-1 (Continued) RADI0 ACTIVE GASE0US EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS SE CHANNEL MODES IN WHICH
$ CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE' g INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED
- 3. UNIT 2 VENT RADIATION MONITOR
- a. Noble Gas Activity Monitor D M R(2) Q(1) *
- b. Iodine Sampler W(4) N.A. N.A. N.A. *
- c. Particulate Sampler W(4) N. A. N.A. N.A. *
- d. Effluent System Flow Rate Monitor D N.A. R Q
$ e. Sampler Flow Rate Monitor D N.A. R Q T $ 4. HEATER BAY / TURBINE BUILDING VENT RADIATION HONITOR
- a. Nobi- Gas Activity Monitor D M R(2) Q(1) *
- b. Iodine Sampler W(4) N.A. N.A. N.A. *
- c. Particulate Sampler W(4) N.A. N.A. N.A. *
- d. Effluent System Flow Rate Monitor D N.A. R Q
- e. Sampler Flow Rate Monitor D N.A. R Q
- 5. MAIN CONDENSER OFFGAS HYDROGEN MONITOR
- a. Hydrogen Monitor D N.A. Q(3) M **
O O O
^ ~
i TABLE 4.3.7.10-1 (Continued) i RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS . TABLE NOTATION At all times. During main condenser offgas treatment system operation. (1) The CHANNEL ~ FUNCTIONAL TEST shall also demonstrate that control room alarm annuciation occurs if any of the following conditions exists:
- 1. Instrument indicates measured levels above the alarm setpoint.
- 2. Instrument indicates a downscale failure.
- 3. Instrument controls not set in operate mode.
(2) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards i (N8S) or using standards that have been obtained from suppliers that par-
- ticipate in measurement assurance activities with N85. These standards shall permit calibrating the system over its intended energy and measure-r.ient range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.
O( ,/ (3) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:
- 1. One volume percent hydrogen, balance nitrogen, and
- 2. Four volume percent hydrogen, balance nitrogen.
(4) The iodine cartridges and particulate filters will be changed at least , once per 7 days. I I t w l PERRY - UNIT 1 3/4 3-95 . i
INSTRUMENTATION 3/4.3.8 TUR8INE OVERSPEED PROTECTION SYSTEM LIMITING CONDITION FOR OPERATION 3.3.8 At least one turbine overspeed protection system shall be OPERABLE. APPLICA8ILITY: OPERATIONAL CONDITIONS 1 and 2*. ACTION:
- a. With one turbine control valve or one turbine stop valve per high pressure turbine steam line inoperable, and/or with one turbine intercept or intermediate stop valve per low pressure turbine steam line inoperable, restore the inoperable valve (s) to OPERABLE status within 72 hours or close at least one valve in the affected steam line 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.
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 tha overspeed orotection control system;
- 1) Six low pressure turbine intercept valves, and
- 2) Four high pressure turbine control valves.
b) For the electrical overspeed trip system and the mechanical overspeed trip system;
- 1) Four high pressure turbine stop valves, and
- 2) Six low pressure turbine intermediate stop valves, and
- 3) Four high pressure turbine control valves.
- Not required to be OPERABLE prior to exceeding 1% of RATED THERMAL POWER for the first time.
PERRY - UNIT 1 3/4 3-96 : 1 1
i INSTRUMENTATION l k SURVEILLANCE REQUIREMENTS (Continued)
- b. At least once per 18 months by performance of a CHANNEL CALIBRATION of the turbine overspeed protection instrumentation.
- c. At least once per 40 months by disassembling at least one of each of i the above valves and performir.g 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, i
h l ) l < J ) 1 l l ( l PERRY - UNIT 1 3/4 3-97
- - . - . , , , . , . - , - - - - , - . , , - - , , ,n m.-
INSTRUMENTATION l 3/4.3.9 PLANT SYSTEMS ACTUATION INSTRUMENTATION l LIMITING CONDITION FOR OPERATION 3.3.9 The plant systems 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 plant 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. For the containment spray system:
- 1. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place at least one inoperable channel in the tripped condition within one hour or declare the associated system inoperable.
- 2. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, declare the associated system inoperable.
- c. For the feedwater system / main turbine trip system:
- 1. With the number of OPERABLE channels one less than required by t.he Minimum OPERABLE Channels requirement, restore the inoperable channel to OPERABLE status within 7 days or be in at least STARTUP within the next 6 hours.
- 2. 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.
O PERRY - UNIT 1 3/4 3-98
INSTRUMENTATION LIMITING CONDITION FOR OPERATION (Continued) f ACTION (Continued)
- d. For the suppression pool makeup systeai:
- 1. For the Drywell Pressure-High and the Reactor Vessel Water Level-Low, Level.1:
With the number cf 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 one hour
- or declare the associated system (s) inoperable.
b) With core than one channel inoperable, declare the asso-ciated system (s) inoperable.
- 2. For the Suppression Pool Water Level-Low, Suppression Pool Makeup Timer and the SPMU Manual Initiation:
With the number of OPERA 8LE channels less than required by the Minimum OPERABLE Channels per Trip System requirement, restore the inoperable channels to OPERABLE status within 8 hours; ! ( otherwise, declare the associated suppression pool makeup system
\ inoperable and take the action required by Specification 3.6.3.4.
SURVEILLANCE REQUIREMENTS 4.3.9.1 Each plant system actuation instrumentation channel shall be demon-strated 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 channels shall be performed at least once per 18 months. i ~
*The provisions of Specification 3.0.4 are not applicable.
} PERRY - UNIT 1 3/4 3-99
- - . . - - - - - . -n -
- - - - , , - - _ . - ,._-,,-,.,.._a-.- -, - , . _ , - - - , - - - . - - . - - - . , .- - - , . - - , , -, , . , -
TABLE 3.3.9-1 A g PLANT SYSTEMS ACTUATION INSTRUMENTATION
' MINIMUM APPLICABLE g OPERABLECHANNEg) OPERATIONAL q TRIP FUNCTION PER TRIP SYSTEM CONDITIONS
- 1. CONTAINMENT SPRAY SYSTEM
- a. Drywell Pressure - High 2 1,2,3
- b. Containment Pressure - High 2 1,2,3
- c. Reactor Vessel Water Level - Low, Level 1 2 1,2,3
- d. Timers (1) System A and B (10 minute timer) 1 1,2,3 (2) System B (1.5 minute timer) 1 1,2,3 y e. Manual Initiation 1 1,2,3 a
y 2. FEEDWATER SYSTEM / MAIN TURBINE TRIP SYSTEM
- a. Reactor Vessel Water Level - High, Level 8 3 1
- 3. SUPPRESSION POOL MAKEUP SYSTEM
- a. Drywell Pressure - High 2 1,2,3
- o. Reactor Vessel Water Level - Low, level 1 2 1,2,3
- c. Suppression Pool Water Level - Low 2 1,2,3
- d. Suppression Pool Makeup Timer 1 1,2,3
- e. SPMU Manual Initiation 1 1,2,3 (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip sytsem in the tripped condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.
O O O
{ s v. TABLE 3.3.9-2 PLANT SYSTEMS ACTUATION INSTRUMENTATION SETPOINTS i ALLOWABLE g TRIP FUNCTION TRIP SETPOINT VALUE Q g 1. CONTAINMENT SPRAY SYSTEM
- a. Drywell Pressure - High i 1.68 psig $ 1.88 psig
- b. Containment Pressure - High 5 8.35 psig i 8.85 psig
- c. Reactor Vessel Water Level - Low, Level 1 > 16.5 inches * > 14.3 inches
- d. Timers (1) System A and 8 10.85 1 0.3 minutes 10.85 1 0.6 minutes '
(2) System B 35 1 2 seconds 35 1 3. seconds
- e. Manual Initiation NA NA ,
- 2. FEEDWATER SYSTEM / MAIN TURBINE TRIP SYSTEM
- a. Reactor Vessel Water Level - High, Level 8 5 219.5 inches * $ 221.7 inches y 3. SUPPRESSION POOL MAKEUP SYSTEM g i,
- a. Drywell Pressure - High 1 1.68 psig i 1.88 psig
- b. Reactor Vessel Water Level - Low, Level 1 > 16.5 inches * > 14.3 inches '
- c. Suppression Pool Water Level - Low 5 591' 6.9" elevation 5 591' 5.64" elevation
- d. Suppression Pool Makup Timer .
529.4 minutes 530.0 minutes
- e. SPMU Manual Initiation NA NA
*See Bases figure B 3/4 3-1.
TABLE 4.3.9.1-1 m E PLANT SYSTEMS ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL E CilANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH Q TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
- 1. CONTAINMENT SPRAY SYSTEM
- a. Drywell Pressure - High S M R* 1,2,3
- b. Containment Pressure - High S M R* 1,2,3
- c. Reactor Vessel Water Level - Low Level 1 5 M R$ 1,2,3
- d. Timers (1) System A and B NA M R 1, 2, 3 (2) System B NA M R 1, 2, 3
$ e. Manual Initiation NA R NA 1,2,3
- 2. FEE 0 WATER SYSTEM / MAIN TURBINE TRIP SYSTEM .
IS
- a. Reactor Vessel Water Level - High, Level 8 5 M R* 1
- 3. SUPPRESSION POOL MAKEUP SYSTEM
- a. Drywell Pressure - High S M R$ 1,2,3
- b. Reactor Vessel Water Level -
Low, level 1 S M R* 1,2,3
- c. Suppression Pool Water Level - Low S M R* 1,2,3
- d. Suppression Pool Makeup Timer NA H Q 1,2,3
- e. SPMU Manual Initiation NA R NA 1,2,3 kalibratetripunitsetpointatleastonceper31 days.
O O O
3/4.4 REACTOR COOLANT SYSTEM (Oj 3/4.4.1 RECIRCULATION SYSTEM RECIRCULATION LOOPS LIMITING CONDITION FOR OPERATION f m 3.4.1.1 Two reactor coolant system recirculatio~n 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 systea 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
; initiate measures to place the unit in at least HOT SHUTDOWN within the next 12 hours.
- b. With no reactor coolant system recirculation loops in operation,
/ immediately initiate action to reduce THERMAL POWER to less than or I
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. i
- 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 4.4.1.1.2):
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 4
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 to less than or equal to the limit specified in Figure 3.4.1.1-1. 4
*See Special Test Exception 3.10.4.
** Detector levels A and C of one LPRM string per core octant plus detectors A j and C of one LPRM string in the center of the core should be monitored.
PERRY - UNIT 1 3/4 4-1 l l
- - - -_ . , . -,_ ., ,_.~ _ . , . ,- - , ,, - - - .-
REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.1.1.1 Each reactor coolant system recirculation loop flow control valve shall be demonstrated OPERABLE at least once per 18 months by:
- a. Verifying that the control valve fails "as is" on loss of hydraulic pressure at the hydraulic control unit, and
- b. Verifying that the average rate of control valve movement is:
- 1. Less than or equai to 11% of stroke per second opening and
- 2. Less than or equal to 11% of stroke per second closing.
4.4.1.1.2 Establish a baseline APRM and LPRM* neutron flux noise value within the regions for which monitorirrg is required (Specification 3.4.1.1, ACTION c) within 2 hours of entering the region for which monitoring is required unless baselining has previously been performed in the region since the last refueling outage. O i
- Detector levels A and C of one LPRM string per core octant plus detectors A i and C of one LPRM string in the center of the core should be monitored.
O PERRY - UNIT 1 3/4 4-2
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h ' O i ! 30 40 50 SO 70 CORE FLOW (% RATED) THERMAL POWER VERSUS CORE FLOW FIGURE 3.4.1.1-1
REACTOR COOLANT SYSTEM JET PUMPS LIMITING CONDITION FOR OPERATION 3.4.1.2 All jet pumps shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2*. ACTION: With one or more jet pumps inoperable, be in at least HOT SHUTDOWN within 12 hours. 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 that no two of the following conditions occur when the recirculation loops are operating at the same flow control valve position.
- a. The indicated recirculation loop flow differs by more than 10% from the established flow control valve position-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 individual jet pump differs from established patterns by more than 10%.
*Not required to be OPERABLE prior to nuclear heatup.
O PERRY - UNIT 1 3/4 4-4
d REACTOR COOLANT SYSTEM
\
[ A RECIRCULATION LOOP FLOW LIMITING CONDITION FOR OPERATION 3.4.1.3 Recirculation loop flow mismatch shall be maintained within:
- a. 5% of rated recirculation flow with core flow greater than or equal to 70% of rated core flow,
- b. 10% of rated recirculation flow with core flow less than 70% of rated core flow.
APPLICA8ILITY: OPERATIONAL CONDITIONS 1* and 2*#. ACTION: With recirculation loop flows different by more than the specified limits, either:
- a. Restore the recirculation loop flows to within the specified limit within 2 hours, or
' i
- b. Declare the recirculation loop with the lower flow not in operation and take the ACTION required by Specification 3.4.1.1.
SURVEILLANCE REQUIREMENTS 4.4.1.3 Recirculation loop flow mismatch shall be verified to be within the limits at least once per 24 hours.
*See Special Test Exception 3.10.4.
#Not required to be OPERA 8LE prior to nuclear heatup.
PERRY - UNIT 1 3/4 4-5 4
REACTOR COOLANT SYSTEM IDLE RECIRCULATION LOOP STARTUP O 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 100*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 recirculation loops is less than or equal to 50*F and the operating loop flow rate is less than or equal to 50% of rated loop flow.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4 with reactor steam dome pressure greater than 25 psig. 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 PERRY - UNIT 1 3/4 4-6
REACTOR COOLANT SYSTEM O 3/4.4.2 SAFETY VALVES SAFETY / RELIEF VALVES LIMITING CONDITION FOR OPERATION 3.4.2.1 Of the following safety / relief valves, the safety valve function of at least 7 valves and the relief valve function of at least 6 valves other than those satisfying the safety valve function requirement shall be OPERABLE with the specified lift settings: Number of Valves Function Setpoint* (psia) 8 Safety 1165 2 11.6 psi 6 Safety 1180 2 11.8 psi 5 Safety 1190 1 11.9 psi 1 Relief 1103 1 15 psi 9 Relief 1113 1 15 psi 9 ' Relief 1123 1 15 psi APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With the safety and/or relief valve function of one or more of the above required safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTOOWN within the next 24 hours,
- b. With one or more safety / relief valves stuck open, close the stuck open safety / relief valve (s); with suppression pool average water temperature 110*F or greater, place the reactor mode switch in the Shutdown position.
t c. With one or more safety / relief valve tail pipe pressure switches \ inoperable, restore the inoperable switch (es) to OPERABLE status within 7 days or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- d. With either relief valve function pressure actuation trip system "A" or "B" inoperable, restore the inoperable trip system to OPERABLE status within 7 days; otherwise, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTOOWN within the following 24 hours.
SURVEILLANCE REQUIREMENTS 4.4.2.1.1 The tail pipe pressure switch for each safety / relief valve shall be demonstrated OPERABLE with the setpoint verified *.o be 3015 psig by per-formance of a:
- a. CHANNEL FUNCTIONAL TEST at least once per 31 days, and a
- b. CHANNEL CALIBRATION at least once per 18 months.
4.4.2.1.2 The relief valve function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:
- a. CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at least once per 31 days.
- b. CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.
*The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.
O PERRY - UNIT 1 3/4 4-7 i l 1
REACTOR COOLANT SYSTEM 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 Relief Function Setpoint* (psig) i 15 psi Setpoint* (psia) Valve No. Open Close Open Close 1821-F051D 1033 926 1103 1 15 psi 1003 ! 20 psi 1821-F051C 1073 936 1113 2 15 psi 1013 t 20 psi 1821-F051A 1113 946 1113 1 15 psi 1013 1 20 psi 1821-F051B 1113 946 1113 1 15 psi 1013 1 20 psi 1821-F047F 1113 946 1113 1 15 psi 1013 1 20 psi 1821-F051G 1113 946 1113 1 15 psi 1013 20 psi 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 the low-low set function to OPERABLE status within 14 days or be in at least HOT SHUTOOWN 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 more than one 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.
- c. With either relief valve / low-low set function pressure actuation trip system "A" or "B" inoperable, restore the inoperable trip system to OPERABLE status within 7 days; otherwise, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the following 24 hours.
SURVEILLANCE REQUIREMENTS 4.4.2.2.1 The relief valve function ard the low-low set function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:
- a. CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at least once per 31 days.
- b. CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.
"The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.
PERRY - UNIT 1 3/4 4-8
REACTOR COOLANT 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 OPERA 8LE:
- a. The drywell atmosphere particulate or gaseous radioactivity monitoring system,
- b. The ~drywell floor drain sump and equipment drain sump flow monitoring system, and
- c. The upper drywell air coolers condensate flow rate monitoring system.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3*. ACTION: With only two of the required leakage detection systems OPERA 8LE, operation may continue for up to: '
- a. 30 days when the required gaseous and particulate radioactive monitoring system is inoperable provided grab samples of the drywell atmosphere are obtained and analyzed at least once per 24 hours, or O. b. 30 days when the drywell floor drain sump or equipment drain sump flow monitoring system is inoperable, or
- c. .30 days when the upper drywell air coolers condensate flow rate monitoring system is inoperable.
Otherwise, be in at least HOT SHUTOOWN 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 demon-strated OPERABLE by:
- a. Drywell atmosphere particulate or gaseous monitoring systems-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. Drywell floor drain and equipment drain sump flow monitoring system-performance of a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.
- c. Upper 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.
*The drywell floor drains sump and equipment drain sump flow monitoring system and the upper drywell air coolers condensate flow rate monitoring system are not required to be OPERABLE prior to nuclear heatup.
PERRY - UNIT 1 3/4 4-9
REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.3.2 Reactor coolant system leakage shall be limited to:
- a. No PRESSURE B0UNDARY 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 speci-fled in Table 3.4.3.2-1, at rated pressure.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With any PRESSURE B0UNDARY LEAKAGE, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTOOWN 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 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
- valve, or be in at least HOT SHUT 00WN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours.
Which have been verified not to exceed the allowable leakage limit at the last refueling outage or after the last time the valve was disturbed, whichever is more recent. O PERRY - UNIT 1 3/4 4-10 k
REACTOR COOLANT SYSTEM O 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 particulate or gaseous radioactiv-ity at least once per 12 hours (not a means of quantifying leakage),
- b. Monitoring the drywell floor and equipment sump flow rate at least once per 12 hours,
- c. Monitoring the drywell upper drywell air coolers condensate flow rate at least once per 12 hours, and
- d. Monitoring the reactor vessel head flange leak detection system at least once per 24 hours.
4.4.3.2.2 Each reactor coolant system oressure isolation valve specified in Table 3.4.3.2-1 shall be demonstrated OPERA 8LE 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,
- b. Prior to returning the valve to service following maintenance, repair or replacement work on the valve which could affect its leakage rate, and The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 3.
PERRY - UNIT 1 3/4 4-11
TABLE 3.4.3.2-1 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES VALVE NUMBER SYSTEM 1C41-F006 Standby Liquid Control IC41-F007 Standby Liquid Control 1E12-F008 Residual Heat Removal 1E12-F009 Residual Heat Removal 1E12-F041A Residual Heat Removal 1E12-F041B Residual Heat Removal 1E12-F041C Residual Heat Removal 1E12-F042A Residual Heat Removal 1E12-F0428 Residual Heat Removal 1E12-F042C Residual Heat Removal 1E12-F550 Residual Heat Removal 1E21-F005 Low Pressure Core Spray 1E21-F006 Low Pressure Core Spray 1E22-F004 High Pressure Core Spray 1E22-F005 High Pressure Core Spray 1E51-F065 Reactor Core Isolation Cooling 1E51-F066 Reactor Core Isolation Cooling 4 O PERRY - UNIT 1 3/4 4-12
REACTOR COOLANT SYSTEM (O v) 3/4.4.4 CHEMISTRY 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 more than 336 hours per year, be in at least STARTUP within the next g i 6 hours.
O
- 3. 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 SHUT 00WN within the next 24 hours,
- b. In OPERATIONAL CONDITION 2 and 3, with the conductivity, chloride concen-tration or pH exceeding the limit specified in Table 3.4.4-1 for more than 48 hours during one continuous time interval, be in at least 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 witnin 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 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.
v PERRY - UNIT 1 3/4 4-13
\
l 1
REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS O 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, 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.
O PERRY - UNIT 1 3/4 4-14
3
- o TABLE 3.4.4-1 7 REACTOR COOLANT SYSTEM c CHEMISTRY LIMITS fi
-4 - OPERATIONAL CONDITION CHLORIDES CONDUCTIVITY (pahos/cm @25"C) PJH 1 $ 0.2 ppa $ 1. 0 5.6 5 pH $ 8.6 2 and 3 $ 0.1 ppa 12.0 5.6 $ pH $ 8.6 At all other t.mes 5 0.5 ppm $ 10.0 5.3 $ pH $ 8.6 W
G
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 EQUIVALENT I-131, and
- b. Less than or equal to 100/E 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 SHUTOOWN 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 Ifne isolation valves closed within 12 hours.
- b. In OPERATIONAL CONDITIONS 1, 2, 3 or 4, with the specific activity of the primary coolant greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131 or greater than 100/l 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 1 hour *, or
- 2. The offgas level, at the outlet of main condenser air ejector, 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 offgas level, at the outlet of main condenser air ejectne, increased by more than 15% in one hour during steady state operation at release rates greater than 75,000 microcuries per second,
- Not applicable during the startup test program.
PERRY - UNIT 1 3/4 4-16
REACTOR COOLANT SYSTEM LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued)
' perform the sampling and analysis requirements of Item 4b of Table 4.4.5-1 until the specific activity of the primary coolant is restored to within its limit.
SURVEILLANCE REQUIREMENTS 4.4.5 The specific activity of the reactor coolant shall be demonstrated to be within the ifaits by performance of the sampling and analysis program of Table 4.4.5-1. O i l l PERRY - UNIT 1 3/4 4-17
TABLE 4.4.5-1 PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM
. OPERATIONAL CONDITIONS e TYPE OF MEASUREMENT 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 EQUIVALENT 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 activity exceeds a limit, y as required by ACTION b. i b) At least one sample, between 1#, 2# En 2 and 6 hours following the change in THERHAL POWER or offgas 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 Xc-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
REACTOR COOLANT SYSTEM
/
i i C/ 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 8 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 operations above the heatup and cooldown limit curves, and
- d. The reactor vessel flange and head flange temperature greater than p) or equal to 70*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 SHUTOOWN 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 be determined to be within the above required heatup and cooldown ilmits and to the right of the limit lines of Figure 3.4.6.1-1 curves A and A', 8 and B', or C and C', as applicable, at least once por 30 minutes. A (v PERRY - UNIT 1 3/4 4-19
REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) O 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 curves C and C' within 15 minutes prior to the withdrawal of control rods to 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. 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. 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.
O PERRY - UNIT 1 3/4 4-20 j
O _ AAs .1 aa F s 1 I t soTTO= = = f F PtsetTRATiofu
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- I I I noe I I I I I j l I CORE DELTuost AFTER SHIFT I
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- I A -INeflAL SYSTEW HYDROTEST UNIT
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$ I l h assumed 34*F CORE SELTUNE l -
400 - TEWP SHIFT PROM AM INITIAL l SHELL PLATE RTNOT Of W l J12 peg 1i g 200 i SOLTUP UMif l l / 70'P j 0 0 100 200 300 400 Soo MINIMUM RE ACTOR VESSEL METAL TEMPERATURE t'F) MINIMUM REACTOR PRESSURE VESSEL METAL TEMPERATURE VERSUS REACTOR VESSEL PRESSURE Figure 3.4.6.1-1 l PERRY - UNIT 1 3/4 4-21
T TABLE 4.4.6.1.3-1 REACTOR VESSEL MATERIAL 581RVEILLANCE PROGRAM-WITHDRAWAL SCilEDULE CAPSULE VESSEL LEAD WITHDRAWAL TIME
= NUMBER LOCATION ' FACTOR 0 1/4 I (EFPY) 131C6981G1 3 . 0.58 10 131C8981G1 177* 0.58 30 13108981G1 183 0.58 Spare w
t M O O O
REACTOR COOLANT SYSTEM REACTOR STEAM DOME LIMITING CONDITION FOR OPERATION 3.4.6.2 The pressure in the reactor steam done shall be less than or equal to 1045 psig. APPLICA8ILITY: OPERATIONAL CONDITION 1* and 2*. ACTION: With the reactor steam done pressure greater than 1045 psig, reduce the pressure to less than or equal to 1045 psig within 15 minutes or be in at , least HOT SHUTDOWN within 12 hours. SURVEILLANCE REQUIREMENTS l t 4.4.6.2 The reactcc steam dome pressure shall be verified to be less than or , equal to 1045 psig at least once per 12 hours.
"Not applicable during anticipated transients.
O PERRY - UNIT 1 3/4 4-23
REACTOR COOLANT SYSTEM 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.4.7 Two main steam line isolation valves (MSIVs) per main steam line shall be OPERABLE with stroke times in the closing direction greater than or equal to 2.5 and less than or equal to 5 seconds. The stroke time average shall be calculated using the stroke times of the fastest valve in each main steam line, and this average shall be greater than or equal to 3 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 affected 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 RE0VIREMENTS 4.4.7 Each of the above required MSIVs shall be demonstrated OPERABLE by verifying full stroke times in the closing direction between 2.5 and 5 seconds when tested pursuant to Specification 4.0.5. The stroke time average shall be calculated using the stroke times of the fastest valve in each main steam line, and this average shall be greater than or equal to 3 seconds. The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITIONS 2 or 3 provided the surveillance is performed within 12 hours after reaching a reactor steam pressure of 600 psig and prior to entry into OPERATIONAL CONDITION 1. O PERRY - UNIT 1 3/4 4-24 I
REACTOR COOLANT SYSTEM j% !. ) 3/4.4.8 STRUCTURAL INTEGRITY LJ 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 greater than 50*F above the minimum temperature required by NOT 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 to greater than 200*F.
I,__h) ( ,',, 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 requirements other than Specification 4.0.5. (D ss- ) ( PERRY - UNIT 1 3/4 4-25
REACTOR COOLANT SYSTEM 3/4.4.9 RESIDUAL HEAT REMOVAL \ HOT SHUTDOWN 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 *'## with each loop consisting of at least:
- a. One OPERABLE RHR pump, and
- b. Two OPERABLE RHR heat exchangers.
APPLICABILITY: OPERATIONAL CONDITION 3, with reactor vessel pressure less than the RHR cut-in permissive setpoint. ACTION:
- a. With less than the above required RHR shutdown cooling mode loops OPERABLE, immediately initiate corrective action to return the required loops to OPERABLE status as soon as possible. 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. Be in at least COLD SHUTDOWN within 24 hours.**
- b. With no RHR shutdown cooling mode loop or recirculation pump in operation, immediately initiate corrective action to return at least one RHR shut-down cooling mode loop or recirculation pump to operation as soon as possible. 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 Specifications 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 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 inoperable for up to 2 hours for surveillance testing provided the other loop is OPERABLE and 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 RHR shutdown cooling mode loop may be removed from operation during hydrostatic testing.
- 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.
PERRY - UNIT 1 3/4 4-26
REACTOR COOLANT SYSTEM A ( ) COLD SHUTDOWN %/ 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 at least:
- a. One OPERABLE RHR pump, and
- b. Two OPERABLE RHR heat exchangers.
APPLICABILITY: 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.
- b. With no RHR shutdown cooling mode loop or recirculation pump in operation, within one hour establish reactor coolant circulation by an alternate p, method and monitor reactor coolant temperature and pressure at least once per hour.
(O
- 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.
*The shutdown cooling pump may be removed from operation for up to 2 hours per 8 hour period provided the other loop is OPERABLE.
Q '
##The shutdown cooling mode loop may be removed from operation during hydrostatic testing. -
PERRY - UNIT 1. 3/4 4-27 y f
3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - OPERATING LIMITING CONDITION FOR OPERATION i 3.5.1 ECCS divisions 1, 2 and 3 shall be OPERABLE with:
- a. ECCS division 1 consisting of:
- 1. The OPERABLE low pressure core spray (LPCS) system with a flow path capable of taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.
- 2. The OPERABLE low pressure coolant injection (LPCI) subsystem "A" of the RHR system with a flow path capable of taking suction from -
the suppression pool and transferring the water to the reactor vessel. -
- 3. Eight OPERABLE ADS valves.
- b. ECCS division 2 consisting of:
- 1. The OPERABLE low pressure coolant injection (LPCI) subsystems "B"
} and "C" of the RHR system, each with a flow path capable of taking V suction from the suppression pool and transferring the water to the reactor vessel.
- 2. Eight OPERABLE ADS valves.
- c. ECCS division 3 consisting of the OPERABLE high pressure core spray (HPCS) system with a flow path capable of~ taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.
APPLICABILITY: OPERATIONAL CONDITION 1, 2*'# and 3*'## .
"The ADS is not required to be OPERABLE when reactor s' team dome pressure is less than or equal to 100 psig.
#See Special Test Exception 3.10.5.
##0ne LPCI subsystem of the RHR system may be aligned in the shutdown cooling !
mode when reactor' vessel pressure is less than the cut-in permissive setpoint. - x PERRY - UNIT 1 3/4 5-1
EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION:
- a. For ECCS division 1, provided that ECCS divisions 2 and 3 are OPERABLE:
- 1. With the LPCS system inoperable, restore the inoperable LPCS system to OPERABLE status within 7 days.
- 2. With LPCI subsystem "A" inoperable, restore the inoperable LPCI subsystem "A" to OPERABLE status within 7 days.
- 3. With the LPCS system inoperable and LPCI subsystem "A" inoperable, restore at least the inoperable LPCI subsystem "A" or the inoperable LPCS system to OPERABLE status within 72 hours.
- 4. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours."
- b. For ECCS division 2, provided that ECCS divisions 1 and 3 are OPERABLE:
- 1. With either LPCI subsystem "B" or "C" inoperable, restore the inoperable LPCI subsystem "B"' or "C" to OPERABLE status within 7 days.
- 2. With both LPCI subsystems "B" and "C" inoperable, restore at least the inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours.
l 3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours *.
- c. For ECCS division 3, provided that ECCS divisions 1 and 2 and the RCIC system are OPERABLE:
- 1) With ECCS division 3 inoperable, restore the inoperable division to OPERABLE status within 14 days.
- 2) Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
*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 PERRY - UNIT 1 3/4 5-2
- l
l 4 EMERGENCY CORE COOLING SYSTEMS (f LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) 4 d. For ECCS divisions 1 and 2, provided that ECCS division 3 is OPERABLE:
- 1. 'With LPCI subsystem "A" and either LPCI subsystem "B" or "C" inoperable, restore at least the inoperable LPCI subsystem "A" or inoperable LPCI subsystem "B" or "C" to OPERA 8LE status within 72 hours.
- 2. With the LPCS system inoperable and either LPCI subsystems "B"
; or "C" inoperable, restore at least the inoperable LPCS system or inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours.
- 3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours *.
- e. For ECCS divisions 1 and 2, provided that ECCS division 3 is OPERABLE and divisions 1 and 2 are otherwise OPERABLE:
l 1. With one of the above required ADS valves inoperable, restore the inoperable ADS valve to OPERA 8LE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours and reduce reactor steam done pressure to 5 100 psig within the next ON 24 hours. 1 2. With two or more of the above required ADS valves inoperable, be in at least HOT SHUTDOWN within 12 hours and reduce reactor steam done pressure to 1 100 psig within the next 24 hours.
- f. With an ECCS discharge line " keep filled" pressure alarm instrumenta-tion channel inoperable, perform surveillance 4.5.1.a.1 at least once per 24 hours.
; 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.
4 d a
*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. i PERRY - UNIT 1 3/4 5-3
EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.1 ECCS division 1, 2 and 3 shall be demonstrated 0FERABLE by:
- a. At least once per 31 days for the LPCS, LPCI and HPCS systems:
- 1. Verifying by venting at the hign 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.
- b. Verifying that, when tested pursuant to Specification 4.0.5, each:
- 1. LPCS pump develops a flow of at least 6110 gpm at a differential pressure greater than or equal to 128 psid for the system.
- 2. LPCI pump develops a flow of at least 7100 gpm at a differential pressure greater than or equal to 24 psid for the system.
- 3. HPCS pump develops a flow of at least 6110 gpm at a differential pressure greater than or equal to 200 psid for the system.
- c. For the LPCS, LPCI and HPCS systems, at least once per 18 months:
- 1. Performing a system functional test which. includes simulated automatic 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 injec-tion of coolant into the reactor vessel may be excluded from this test.
- 2. Performing a CHANNEL CALIBRATION of the ECCS discharge line
" keep filled" pressure alarm instrumentation.
- d. For the HPCS system, at least once per 18 months, verifying that the suction is automatically transferred from the condensate storage tank to the suppression pool on a condensate storage tank low water l
level signal and on a suppression pool high water level signal.
*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.
PERRY - UNIT 1 3/4 5-4 i
l l EMERGENCY CORE COOLING SYSTEMS () SURVEILLANCE REQUIREMENTS (Continued)
- e. For the ADS by:
- 1. At least once per 31 days, performing a CHANNEL FUNCTIONAL TEST
~of the safety related instrument air system low pressure alarm system.
4
- 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 done 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, or
- 3) The safety relief valve discharge pressure switch
)
(d indicates the valve is open. c) Performing a CHANNEL CALIBRATION of the safety related instrument air system low pressure alarm system and verifying an alarm setpoint of 2475 1 25 psig on decreasing pressure.
*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.
r r PERRY - UNIT 1 3/4 5-5 i i
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. The low pressure core spray (LPCS) system with a flow path capable of taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.
- b. Low pressure coolant injection (LPCI) subsystem "A" of the RHR system with a flow path capable of taking suction from the suppres-sion pool and transferring the water to the reactor vessel.
- c. Low pressure coolant injection (LPCI) subsystem "B" of the RHR system with a flow path capable of taking suction from the suppres-sion pool and transferring the water to the reactor vessel.
- d. Low pressure coola~nt injection (LPCI) subsystem "C" of the RHR system with a flow path capable of taking suction from the suppres-sion pool and transferring the water to the reactor vessel.
- e. The high pressure core spray (HPCS) system with a flow path capable of taking suction from one of the following water sources and transferring the water through the spray sparger to the reactor vessel:
- 1. From the suppression pool, or
- 2. When the suppression pool level is less than the level required by Specification 3.5.3.b, from the condensate storage tank containing at least 150,000 available gallons of water, equivalent to a level of 47% (220,000 gallons of water).
APPLICABILITY: OPERATIONAL CONDITION 4 and 5*. ACTION:
- a. With one of the above required subsystems / systems inoperable, restore at least two subsystems / systems to OPERABLE status within 4 hours or suspend all operations that have a potential for draining the reactor vessel.
- b. With both of the above required subsystems / systems inoperable, suspend CORE ALTERATIONS and all operations that have a pctential for draining the reactor vessel. Restore at least one subsystem /
system to OPERABLE status within 4 hours or establish PRIMARY CONTAINMENT INTEGRITY within the next 8 hours.
- c. With an ECCS discharge line " keep filled" pressure alarm instrumen-tation channel associated with an above required ECCS system inoper-able, perform surveillance 4.5.1.a.1 at least once per 24 hours.
~
7 e
*The ECCS is not require:1 to be OPERABLE provided that the reactor vessel head is jemoved, the cavity is flooded, the steam dryer storage / reactor well gate is removed, and water level in these upper containment pools is maintained within the limits of Specification 3.9.8 and 3.9.9.
PERRY - UNIT 1 3/4 S-6 m__. _
t EMERGENCY CORE COOLING SYSTEMS
- SURVEILLANCE REQUIREMENTS l
4.5.2.1 At least the above required ECCS shall be demonstrated OPERABLE per Surveillance Requirement 4.5.1. 4.5.2.2 The'HPCS system shall be determined OPERABLE at least once per i 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.e.
.i l i a 3 1 l 1 ' l l l PERRY - UNIT 1 3/4 5-7
--n . - . ---,m-e--------------
EMERGENCY CORE COOLING SYSTEMS 3/4.5.3 SUPPRESSION POOL LIMITING CONDITION FOR OPERATION 3.5.3 The suppression pool shall be OPERABLE:
- a. In OPERATIONAL CONDITION 1, 2 and 3, with a contained water volume of at least 115,612 ft3, equivalent to a level of 18'0".
- b. In OPERATIONAL CONDITION 4 and 5*, with a contained water volume of at least 106,508 ft3, equivalent to a level of 16'6", except that the suppression pool level may be less than the limit or may be 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 150,000 available gallons of water, equivalent to a level of 47% (220,000 gallons of water), and
. 4. The HPCS system is OPERABLE per Specification 3.5.2 with 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 pool water level 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 SHUT 00WN within the following 24 hours.
- b. In OPERATIONAL CONDITION 4 or 5*, with the suppression pool water level less than the above limit or drained and the above required conditions not satisfied, suspend CORE ALTERATIONS and all operations that have a potential for draining the reactor vessel and lock the reactor mode switch in the Shutdown position. Establish PRIMARY CONTAINMENT INTEGRITY within 8 hours.
A The suppression pool is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded, the steam dryer storage / reactor well gate is removed and the water level in these upper containment pools is maintained within~ the limits of Specification 3.9.8 and 3.9.9. O i PERRY - UNIT 1 3/4 5-8 I
EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.3.1 The suppression pool shall be determined OPERABLE by verifying the water level to be greater than or equal to:
- a. 18'0" at least once per 24 hours in OPERATIONAL CONDITIONS 1, 2, and 3.
- b. 16'6" at least once per 12 hours in OPERATIONAL CONDITIONS 4 and 5.
4.5.3.2 With the suppression pool 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.
\
)
^
The suppression pool is not required to be OPERABLE pre.*ided that the reactor vessel head is removed, the cavity is flooded, the steam oryer storage / reactor well' gate is removed and the water level in these upper containment pools is - maintained within the limits of Specification 3.9.8 and 3.9.9. PERRY - UNIT 1 3/4 5-9
3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT r.J PRIMARY CONTAINMENT INTEGRITY - OPERATING LIMITING CONDITION FOR OPERATION 3.6.1.1.1 PRIMARY CONTAINMENT INTEGRITY shall be maintained. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. ACTION: i Without PRIMARY CONTAINMENT INTEGRITY, restore PRIMARY CONTAINMENT INTEGRITY within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:
- a. After each closing of each penetration subject to Type B 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, 11.31 psig, and verifying that when the measured leakage rate for these seals is ry added to the leakage rates determined pursuant to Surveillance
('s ) Requirement 4.6.1.2.d for all other type B and C penetrations, the combined leakage rate is less than or equal to 0.60 La.
- b. At least once per 31 days by verifying that all primary containment penetrations ** not capable of being closed by OPERABLE primary con-tainment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deacti-vated automatic valves secured in position, except as provided in Table 3.6.4-1 of Specification 3.6.4.
- 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 pool is in compliance with the requirements of Specification 3.6.3.1.
*See Special Test Exception 3.10.1.
**Except valves, blind flanges, and deactivated automatic valves which are located inside the primary containment, drywell, or the steam tunnel portion of the auxiliary building, and are locked, sealed, or ntherwise secured in the closed position. These penetrations shall be verified closed during f' N each COLD SHUTDOWN except such verification need not be performed more often
( ) than once per 92 days. L./ PERRY - UNIT 1 3/4 6-1 4
3/4.6.1 PRIMARY CONTAINMENT PRIMARY CONTAINMENT INTEGRITY - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.6.1.1.2 PRIMARY CONTAINMENT INTEGRITY
- shall be maintained.
APPLICABILITY: When irradiated fuel is being handled in the primary containment, and during CORE ALTERATIONS , and operations with a potential for draining the reactor vessel. Under these conditions, the requirements of PRIMARY CONTAINMENT INTEGRITY do not apply to normal operation of the inclined fuel transfer system. ACTION: Without PRIMARY CONTAINMENT INTEGRITY, suspend handling of irradiated fuel in the primary containment, CORE ALTERATIONS, and operations with a potential for draining the reactor vessel. SURVEILLANCE REQUIREMENTS 4.6.1.1.2 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:
- a. At least once per 31 days by verifying that all primary containment penetrations not capable of being closed by OPERABLE primary contain-ment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deacti-vated automatic valves secured in position, except as provided in Table 3.6.4-1 of Specification 3.6.4.
- b. By verifying each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.
- The primary containment leakage rates in accordance with Specification 3.6.1.2 are not applicable.
- The primary containment equipment hatch is not required to be closed and sealed during initial fuel load.
PERRY - UNIT 1 3/4 6-2
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 to 0.75 L,,
0.20 percent by weight of.the primary containment air per 24 hou-s at P,, 11.31 psig.
- b. A combined leakage rate of less than or equal to 0.60 L for all penetrations and all valves, except for main steam line, isolation valves and valves which are hydrostatically leak tested per Table 3.6.4-1, subject to Type B and C tests when pressurized to P,, 11.31 psig.
- c. Less than or equal to 25 scf per hour for any one main steam line through the isolation valves when tested at P,, 11.31 psig,
- d. A combined leakage rate of less than or equal to 0.0504 L for all penetrations shown in Table 3.6.4-1 of Specification 3.6.4 as
-secondary containment bypass leakage paths when pressurized in accordance with Table 3.6.4-1.
~
- e. ' A combined leakage rate of less than or equal to 1 gpm times the total number of containment isolation valves in hydrostatically tested lines per Table 3.6.4-1 which penetrate the primary containment, when ON tested at 1.10 P,, 12.44 psig.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. 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 except for main steam line isolation valves and valves which are hydrostatically leak tested per Table 3.6.4-1, subject to Type B and C tests exceeding 0.60 L,, or
- c. The measured leakage rate exceeding 25 scf per hour for any one main steam line through the isolation valves, or
- d. The combined leakage rate for all penetrations shown in Table 3.6.4-1 as secondary containment bypass leakage paths exceeding 0.0504 L,, or
- e. The measured combined leakage rate for all containment isolation valves in hydrostatically tested lines per Table 3.6.4-1 which pene-trate the primary containment exceeding 1 gpm times the total number of such valves:
*See Special Test Exception 3.10.1.
O PERRY - UNIT 1 3/4 6-3
CONTAINMENT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued) restore:
- a. The overall integrated leakage rate (s) to less than or equal to 0.75 L,, and
- b. The combined leakage rate for all penetrations and all valves except for main steam line isolation valves and valves which are hydrostati-cally leak tested per Table 3.6.4-1, subject to Type B and C tests to less than or equal to 0.60 L,, and
- c. The leakage rate to less than 25 scf per hour for any one main steam line through the isolation valves, and
- d. The combined leakage rate for all penetrations shown in Table 3.6.4-1 as secondary containment bypass leakage paths to less than or equal to 0.0504 L , and a
- e. The combined leakage rate for all containment isclation valves in hydrostatically tested lines per Table 3.6.4-1 which penetrate the primary containment to less than or equal to 1 gpm times the total number of such valves, prior to increasing reactor coolant system temperature above 200 F.
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 cri-teria specified in Appendix J of 10 CFR Part 50 using the methods and provi-sions of ANSI N45.4-1972 and BN-TOP-1; test results shall also be reported based on the Mass Point Methodology described in ANSI /ANS N56.8-1981:
- a. Three Type A Overall Integrated Containment Leakage Rate tests shall be conducted at 40 + 10 month intervals during shutdown at P ,
11.31 psig during each 10 year service period. Thethirdte$tof each set shall be conducted during the shutdown for the 10 year plant inservice inspection.
- b. If any periodic Type A test fails to meet 0.75 L , the test schedule forsubsequentTypeAtestsshallbereviewedan8approvedbythe Commission. If two consecutive Type A tests fail to meet 0.75 L , a Type A test shall be performed at least every 18 mcnths until tw8 consecutive Type A tests meet 0.75 aL , at which time the above test schedule may be resumed.
- c. The accuracy of each Type A test shall be verified by a supplemental test which:
PERRY - UNIT 1 3/4 6-4 l
I CONTAIMENT SYSTEMS O 'SbRVEILLANCE REQUIREMENTS (Continued) l l
- 1. Confirms the accuracy of the test by verifying that the differ- i ence between the supplemental data and the Type A test data is within 0.25 L,. The formula to used is:
(La + L ,- 0.25 L,3 i La i [L, + L,, + 0.25 L,] where Lc supplemental test result; L =a superimposed leakage; L,, = measured Type A leakage.
- 2. Has duration sufficient to establish accurately the change in leakage rate between the Type A test and the supplemental test.
- 3. Requires the quantity of gas injected into the primary contain-ment or Died from the primary containment during the supple-mental test to be between 0.75 L, and 1.25 L,.
- d. Type B and C tests shall be conducted w th gas at P , 11.31 psig*,
i at intervals no greater than 24 months except for t$sts involving:
- 1. Air locks,
- 2. Main steam line isolation valves,
- 3. Valves pressurized with flula from a seal system,
- 4. All containment isolation valves in hydrostatically tested lines per Table 3.6.4-1 which penetrate the primary containment, and Os 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. Leakage from isolation valves that are sealed with fluid from a seal system may be excluded, subject to the provisions of Appendix J of 10 CFR 50 Section III.C.3, when determining the combined leakage rate provided the seal system and valves are pressurized to at least 1.10 P maintain, system 12.44 psig, and the pressure for seal system at least capacity is adequate to 30 days.
- h. All containment isolation valves in hydrostatic' ally tested lines per Table 3.6.4-1 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 4.6.1.8.3, and 4.6.1.8.4.
- j. The provisions of Specification 4.0.2 are not. applicable to 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 3.6.4-1.
PERRY - UNIT 1 3/4 6-5
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 2.5 scf per hour at P 3, 11.31 psig.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and #. 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.
- 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. Otherwise, in OPERATIONAL CONDITION #, suspend all operation involving handling of irradiated fuel in the primary containment, CORE ALTERATIONS, and operations with a potential for draining the reactor vessel.
- 5. The provisions of Specification 3.0.4 are not applicable.
- b. With the primary containment air lock inoperable in OPERATIONAL CONDI-TIONS 1, 2, or 3, except as a result of an inoperable air lock door, main-tain 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.
- c. With the primary containment air lock inoperable, in OPERATIONAL CONDI-TION #, except as a result of an inoperable air lock door, maintain at least one air lock door closed; restore the inoperable air lock to OPER-ABLE status within 24 hours or suspend all operations involving handling of irradiated fuel in the primary containment, CORE ALTERATIONS, and ope-rations with a potential for draining the reactor vessel.
- When handling irradiated fuel in the primary containment, during CORE ALTERATIONS, and operations with a potential for draining the reactor vessel.
- Except during entry to repair an inoperable inner door, for a cumulative time not to exceed 1 hour per year.
PERRY - UNIT 1 3/4 6-6
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS O i 4.6.1.3 Each primary containment air lock shall be demonstrated OPERA 8LE:
~
- a. By verifying seal leakage rate less than or equal to 2.5 scf per hour when the gap between the door seals is pressurized to Pa,11.31 psig:
within 72 hours # following each closing, except when the air lock
~
1. is bejng used for multiple entries, then at least once per 72 hours ; and
- 2. prior to establishing PRIMARY CONTAINMENT INTEGRITY when the air lock has been used and no maintenance has been performed on the airlock.*
- b. By verifying at least once per 7 days that the service and instrument air system pressure in the header to the primary containment air lock is > 90 psig.
- c. By conducting an overall air lock leakage test at P,,11.31 psig, and verifying that the overall air lock leakage rate is within its limit:
- 1. At least once per 6 months # ,
- 2. Prior to establishing PRIMARY CONTAINMENT INTEGRITY when O~ maintenance has been performed on the air lock that could affect the air lock sealing capability.*
- d. At least once per 6 months by verifying that only one door in each air lock can be opened at a time.
- e. By verifying the door inflatable seal system OPERABLE at least once per 18 months by conducting a seal pneumatic system leak test and verifying that system pressure does not decay more than 1.5 psig from 90 psig within 24 hours.
The provisions of. Specification 4.0.2 are not applicable.
- Exemption to Appendix J of 10 CFR 50.
O PERRY - UNIT 1 3/4 6-7
CONTAINMENT SYSTEMS MSIV LEAKAGE CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.4 Two independent MSIV leakage control system (LCS) subsystems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3. ACTION: With one MSIV leakage control system subsystem inoperable, restore the inoperable 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. SURVEILLANCE REQUIREMENTS 4.6.1.4 Each MSIV leakage control system subsystem shall be demonstrated OPERABLE:
- a. At least once per 31 days by verifying:
- 1. Blnwer OPERABILITY by starting the blower (s) from the control room and operating the blower (s) for at least 15 minutes.
- 2. Inboard heater OPERABILITY by demonstrating electrical continuity of the heating element circuitry by verifying the inboard heater draws 8.28 1 10% amperes per phase.
- b. During each COLD SHUTOOWN, if not performed within the previous 92 days, by cycling each motor operated valve, including the main steam stop valves, through at least one complete cycle of full travel.
- c. At least once per 18 months by:
- 1. Performance of a functional test which includes simulated actuation of the subsystem throughout its operating sequence, and verifying that each automatic valve actuates to its correct position, and the blower (s) start (s).
- 2. Verifying that the blower (s) develop (s) at least the below required vacuum at the rated capacity:
a) Inboard system,15" H 2O at > 100 scfm. b) Outboard system, 15" H2 O at > 200 scfm.
- d. By verifying the inboard flow and inboard and outboard pressure instrumentation to be OPERABLE by performance of a:
- 1. CHANNEL FUNCTIONAL TEST at least once per 31 days, and
- 2. CHANNEL CALIBRATION at least once per 18 months.
PERRY - UNIT 1 3/4 6-8 L
CONTAINMENT SYSTEMS gss (U CONTAINMENT STRUCTURAL INTEGRITY LINITING CONDITION FOR OPERATION 3.6.1.5 The structural integrity of the 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 lof the 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 containment, including the annulus fill concrete, shall be determined during the shutdown for each Type A containment leakage 7s s 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 containment structure 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 vessel and the annulus fill con-crete, the inspection procedure, the tolerances on concrete cracking, and the corrective actions taken. i 3 O PERRY - UNIT 1 3/4 6-9 i L
CONTAINMENT SYSTEMS CONTAINMENT INTERNAL PRESSURE LIMITING CONDITION FOR OPERATION
- 3. 6.1. 6 Primary containment to secondary containment differential pressure shall be maintained between -0.1 and +1.0 psid.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the primary containment to secondary containment differential pressure outside of the specified limits, restore the differential pressure to within the limits within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.6 The primary containment to secondary containment differential pressure O shall be determined to be within the limits at least once per 12 hours. I 1 O PERRY - UNIT 1 3/4 6-10
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AVERAGE AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.7 Primary containment average air temperature shall not exceed 90*F. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the primary containment average air temperature greater than 90*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 SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.7 The primary containment average air temperature shall be the arith-metical average
- of the temperatures at the following locations and shall be determined to be within the limit at least once per 24 hours:
Elevation Azimuth
- a. 720'-6" 280*
- b. 720'-6" 100*
- c. 689'-4" 40*
- d. 689'-4" 210'
- e. 647'-0" 54*
- f. 645'-6" 251*
- g. 613'-0" 69*
- h. 613'-0" 251*
*At least one reading from each elevation for an arithmetical average. However, all available instruments should be used in calculating the arithmetical O average.
PERRY - UNIT 1 3/4 6-11
CONTAINMENT SYSTEMS DRYWELL AND CONTAINMENT PURGE SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.8 The drywell and containment purge 42-inch outboard (1M14-F040, F090) supply and exhaust isolation valves and the 18-inch supply and exhaust isolation valves (1M14-F190, F195, F200, F205) shall be OPERABLE and:
- a. Each 42-inch inboard purge valve (1M14-F045, F085) shall be sealed closed.
- b. Each 42-inch outboard purge valve (1M14-F040, F090) may be open limited to an opening angle of 50* or less for purge system operation
- with such operation limited to 3000 hours ** per 365 days for reducing airborne activity and pressure control.
- c. Each 24-inch (1M14-F055A, 8 and F060A, 8) and 36-inch (1M14-FC65, F070) drywell purge valve shall be sealed closed.
- d. Each 2-inch (IM51-F090 and F110) backup hydrogen purge system iso-1ation valves may be open for controlling drywell pressure.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With a 42-inch inboard drywell and containment purge supply and/or exhaust isolation valve (s) open or not sealed closed, within 4 hours close and/or seal the 42-inch valve (s) or otherwise isolate the penetration or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- b. With a 18-inch or 42-inch outboard drywell and containment purge supply and/or exhaust isolation valves inoperable or open for more than 3000 hours per 365 days for purge system operation *, within four hours close the open 18- or 42-inch valve (s) or otherwise isolate the penetration (s) or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- c. With a 24- or 36-inch drywell purge supply and/or exhaust isolation valve (s) open or not sealed closed, within 4 hours close and/or seal close the 24- or 36-inch valve (s) or otherwise isolate the penetra-tion, or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- d. With a dryweli and containment purge supply and/or exhaust isolation valve (s) with resilient material seals having a measured leakage rate exceeding the limit of Surveillance Requirement 4.6.1.8.3 and/or
- Purge system operation shall be defined as any t'me that both 18-inch and the 42-inch outboard purge valves are open concurrently in either the supply or exhaust line.
- Applicable from initial fuel load until 3 months following the completion of the first refueling outage; otherwise, a 1000-hour per-365-day limit applies.
PERRY - UNIT 1 3/4 6-12
CONTAINMENT SYSTEMS LIMITING CONDITION FOR OPERATION ORYWELL AND CONTAINMENT PURGE SYSTEM (Continued) 4.6.1.8.4, restore the inoperable valve (s) to OPERABLE status within 24 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- e. With one or more 2-inch backup hydrogen purge system isolation valve (s) not closed except as permitted above, close the 2-inch
- valves within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- f. The provisions of specification 3.0.4 are not applicable to ACTIONS a, b, c, and e above.
SURVEILLANCE REQUIREMENTS 4.6.1.8.1 Each 42-inch inboard drywell and containment purge supply and exhaust isolation valve shall be verified to be sealed closed at least once per 31 days. 4.6.1.8.2 The cumulative time that the 18-inch and the 42-inch outboard O drywell and containment purge supply and exhaust isolation valves have been l open limited to an opening angle of 50* or less for the 42-inch valves during the past 365 days for purge system operation
- shall be determined at least once per 7 days.
4.6.1.8.3 At least once per 6 months each sealed closed 42-inch inboard con-tainment purge supply and 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, when pressurized to P,. 4.6.1.8.4 At least once per 92 days each 18-inch and the 42-inch outboard containment purge supply and exhaust isolation valves with resilient material seals shall be demonstrated OPERABLE by verifying that the measured leakage rate is less than or equal to 0.05 L, when pressurized to P,. 4.6.1.8.5 Each 24-inch and 36-inch drywell purge valve shall be verified to be sealed closed at least once per 31 days. 4.6.1.8.6 At least once per 18 months each 42-inch outboard drywell and con-tainment purge supply and exhaust isolation valve shall be verified to be limited to an opening angle of 50* or less. 4.6.1.8.7 Each 2-inch backup hydrogen purge system isolation valve shall be verified to be closed within 4 hours following each purge. -
- Purge system operation shall be defined as any time that both 18-inch and the 42-inch outboard purge valves are open concurrently in either the supply or exhaust line.
PERRY - UNIT 1 3/4 6-13
CONTAINMENT SYSTEMS FEEDWATER LEAKAGE CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.9 Two independent feedwater leakage control (FWLC) system subsystems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3. ACTION: With one FWLC system subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours or in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS .
- 4. 6.1. 9 Each FWLC system subsystem shall be demonstrated OPERABLE:
- a. At least once per 31 days by observing proper operation of the asso-ciated ECCS water leg pump.
- b. At least once per 18 months by cycling each valve in the flow path not testable during POWER OPERATION through at least one complete cycle of full travel.
O PERRY - UNIT 1 3/4 6-14
CONTAINMENT SYSTEMS 3/4.6.2 DRYWELL DRYWELL INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.2.1 DRYWELL INTEGRITY shall be maintained. ' APPLICA8ILITY: OPERAT!0NAL CONDITIONS 1, 2* and 3. , ACTION: - ) Without DRYWELL INTEGRITY, restore DRYWELL INTEGRITY within 1 hour or be in at j least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the i following 24 hours. 1 i SURVEILLANCE REQUIREMENTS i 4.6.2.1 DRYWELL INTEGRITY shall be demonstrated: a.. At least once per 31 days by verifying that all drywell penetrations ** not capable of being closed by OPERABLE drywell i automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated 3 automatic valves secured in position, except as provided in Table 3.6.4-1 of Specification 3.6.4.
- b. By verifying the drywell air lock is in compliance with the require-ments of Specification 3.6.2.3.
- c. By verifying the suppression pool is in compliance with the require-ments of Specification 3.6.3.1.
t d. 3y verifying'the drywell bypass leakage is in compliance with the ' requirements of Specification 3.6.2.2. 1 i
*See Special Test Exception 3.10.1.
- **Except valves, blind flanges, and deactivated automatic valves which are located inside the drywell or containment, and are locked, sealed or other-wise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except such verification need not be performed more often than once per 92 days.
PERRY - UNIT 1 3/4 6-15
. - - . , -_n,+--.,---~--,._.,,,,,,,_,,._,.,~n - , - - - , _ , - - , - - . , . . . . , - , , , , ,
CONTAINMENT SYSTEMS DRWELL BYPASS LEAKAGE LIMITING CONDITION FOR OPERATION 3.6.2.2 Orywell bypass leakage shall be less than or equal to 10% of the minimum acceptable A/8 design value of 1.68 ft.2 APPLICABILITY: When DRWELL INTEGRITY is required per Specification 3.6.2.1. ACTION: With the drywell bypass leakage greater than 10% of the minimum acceptable A/8 design value of 1.68 ft.2, restore the drywell bypass leakage to within the limit prior to increasing reactor coolant system temperature above 200*F. SURVEILLANCE REQUIREMENTS 4.6.2.2 The drywell bypass leakage rate test shall be conducted at least once per 18 months at an initial differential pressure of 2.5 psi and the A/8 shall be calculated from the measured leakage. One drywell air lock door shall remain open during the drywell leakage test such that each drywell door is leak tested duriag at least every other leakage rate test.
- a. If any drywell bypass leakage test fails to meet the specified limit, the schedule for subsequent tests shall be reviewed and approved by the Commission. If two consecutive tests fail to meet the limit, a test shall be performed at least every 9 months until two consecutive tests meet the limit, at which time the 18 month test schedule may be resumed.
- b. The provisions of Specification 4.0.2 are not applicable.
O PERRY - UNIT 1 3/4 6-16
CONTAINMENT SYSTEMS g DRYWELL AIR LOCK LIMITING CONDITION FOR OPERATION 3.6.2.3 The drywell 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 drywell,- then at least one air lock door shall be closed, and
- b. An overall air lock leakage rate of less than or equal to 2.5 scf per hour at 2.5 psig.
- APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3.
ACTION:
- a. With one drywell air lock door inoperable: .
e
- 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.
O) g
'd
- 2. Operation may then continue.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 SHUT 00WN within the following 24 hours.
- 4. The provisions of Specification 3.0.4 are not applicable.
- b. With the drywell 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.
s PERRY - UNIT 1 3/4 6-17 4 e
, , . n,, _ . _. ,.-, _
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.2.3 The drywell air lock shall be demonstrated OPERA 8LE:
- 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 2.5 scf per hour when the gap between the door seals is pressurized to 2.5 psig.
- b. By verifying at least once per 7 days that the service and instrument air system pressure in the header to the drywell air lock is > 60 psig.
- c. By conducting an overall air lock leakage test at 2.5 psig and veri-fying that the overall air lock leakage rate is within its limit:
- 1. Each COLD SHUTDOWN if not performed within the previous 6 months.
- 2. Prior to establishing ORYWELL INTEGRITY when maintenance has been performed on the air lock that could affect the air lock sealing capability.
- d. By verifying that only one door in the air lock can be opened at a time prior to drywell entry, if not performed in the previous 18 months.
- e. By verifying the door inflatable seal system OPERABLE at least once per 18 months by conducting a seal pneumatic system leak test and verifying that system pressure does not decay more than 3 psig from 60 psig within 24 hours.
~
O PERRY - UNIT 1 3/4 6-18
l l CONTAINMENT SYSTEMS ORYWELL STRUCTURAL INTEGRITY LIMITING CONDITION FOR OPERATION 4 3.6.2.4 The structural integrity of the drywell shall be maintained at a level consistent with the acceptance criteria in Specification 4.6.2.4.1. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the structural integrity of the drywell not conforming to the above requirements, restore the structural integrity to within the limits within 24 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.2.4.1 The structural integrity of the exposed accessible interior and - exterior surfaces of the drywell 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.
4.6.2.4.2 Reports Any abnormal degradation of- the drywell structure detected during the above required inspections shall be reported to the Commission pursuant to Specification 6.9.2 witt.in 30 days. This report shall include a description of the condition of the concrete, the inspection procedure, the tolerances on cracking, and the correct'ive actions taken. s C PERRY - UNIT 1 3/4 6-19
DRYWELL INTERNAL PRESSURE LIMITING CONDITION FOR OPERATION l l 3.6.2.5 Drywell to primary containment differential pressure shall be main-tained between -0.5 and +2.0 psid. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. I ACTION: With the drywell to primary containment differential pressure outside of the specified limits, restore the differential pressure to within the limits within 1 hour or be in at least HOT SHUTOOWN within the next 12 hours and in COLD i SHUTOOWN within the following 24 hours. 1 l l SURVEILLANCE REQUIREMENTS 4.6.2.5 The drywell to primary containment differential pressure shall be O determined to be within the limits at least once per 12 hours. l l l l i l 1 l PERRY - UNIT 1 3/4 6-20 l t
CONTAINMENT SYSTEMS )> DRYWELL AVERAGE AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.2.6 Drywell average air temperature shall not exceed 135*F. APPLICABILITY: OPERATONAL CONDITIONS 1, 2 and 3. ACTION: l 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 SHUTDOWN within the following l 24 hours. 1 SURVEILLANCE ~ REQUIREMENTS 4.6.2.6 The drywell average air temperature shall be the arithmetical average
- of the temperatures at the following locations and shall be determined to be within the limit at least once per 24 hours:
Elevation Azimuth
- a. 653'-8" 315*
- b. 653'-8" 135*
- c. 634'-0" 308*
- d. 634'-0" 145*
- e. 605'-0"# 308*
- f. 604'-6"# 150*
*At least one reading.from each elevation for an arithmetical average. However, all available instruments should be used in calculating the arithmetical average. #The instruments at e. and f. are considered to be at the same elevation.
O PERRY - UNIT 1 3/4 6-21
CONTAINMENT SYSTEMS 3/4.6.3 DEPRESSURIZATION SYSTEMS SUPPRESSION POOL LIMITING CONDITION FOR OPERATION 3.6.3.1 The surpression pool shall be OPERABLE with the pool water:
- a. Volume between 115,612 ft3 and 118,548 ft3 equivalent to a level between 18'0" and 18'6", and a
- b. Maximum average temperature of 90 F except that the maximum average temperature may be permitted to increase to:
- 1. 105 F during testing which adds heat to the suppression pool.
. 2. 110*F with THERMAL POWER less than or equal to 1% of RATED THERMAL POWER.
- 3. 120 F with the main steam line isolation valves closed following a scram.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With'the suppression pool water level outside the above limits, restore the water level to within the limits 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. With the suppression pool average water temperature greater than 90 F, restore the average temperature to less than or equal to 90 F within 24 hours 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 pool average water temperature greater than 105 F during testing which adds heat to the suppression pool, stop all testing which adds heat to the suppression pool and restore the average temperature to less than 90*F within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 2. With the suppression pool average water temperature greater than:
a) 90 F for more than 24 hours and THERMAL POWER greater than 1% of RATED THERMAL POWER, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours, b) 110 F, place the reactor mode switch in the Shutdown position and operate at least one residual heat removal loop in the suppression pool cooling mode. PERRY - UNIT 1 3/4 6-22
CONTAIPMENT SYSTEMS g v
) LIMITING CONDITION FOR OPERATION (Continued)
ACTION: (Continued) c) 120*F, depressurize the reactor pressure vessel to less than 200 psig within 12 hours.
- c. With only one suppression pool water level indicator OPERA 8LE and/or with less than eight suppression pool water temperature indicators, one in each of the eight locations OPERA 8LE, restore the inoperable indicators (s) to OPERA 8LE status within 7 days or verify suppression pool water level and/or temperature to be within the limits at least once per 12 hours.
- d. With no suppression pool water level indicators OPERA 8LE and/or with less than seven suppression pool water temperature indicators covering at least seven locations OPERABLE, restore at least one water level indicator and at least seven water temperature indicators to OPERA 8LE status within 48 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
SURVEILLANCE REQUIREMENTS 4.6.3.1 The suppression pool shall be demonstrated OPERA 8LE:
- a. By verifying the suppression pool water volume to be within the V limits at least once per 24 hours.
- b. At least once per 24 hours in OPERATIONAL CONDITION 1 or 2 by verifying the suppression pool average water temperature to be less than or equal to 90*F, except:
- 1. At least once per 5 minutes during testing which adds heat to the suppression pool, by verifying the suppression pool average water temperature less than or equal to 105*F.
- 2. At least once per hour when suppression pool average water temperature is greater than or equal to 90*F, by verifying suppression pool average water temperature to be less than or equal to 110*F, and THERMAL POWER to be less than or equal to 1%
of RATED THERMAL POWER after suppression pool. average water temperature has exceeded 90*F for more than 24 hours.
- 3. At least once per 30 minutes following a scram with suppression pool average water temperature greater than or equal to 90 F, by verifying suppression pool average water temperature less than or equal to 120*F.
O PERRY - UNIT 1 3/4 6-23
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
- c. By verifying at least 16 suppression pool water temperature instrumentation channels, at least two channels in each suppression pool sector, 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 <90*F.
O I O PERRY - UNIT 1 3/4 6-24 l .
CONTAINMENT SYSTEMS CONTAINMENT SPRAY V LIMITING CONDITION FOR OPERATION 3.6.3.2 The containment 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
- b. An OPERABLE flow path capable of recirculating water from the suppression pool through two RHR heat exchangers, and the contain-ment spray spargers.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one containment spray loop inoperable, restore the inoperable
' loop to OPERABLE status within 72 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- b. With both containment spray loops inoperable, restore at least one loop 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.
/'~' SURVEILLANCE REQUIREMENTS 4.6.3.2 The containment 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 7100 gpm on recirculation flow through the RHR heat exchangers to the suppression pool when tested pursuant to Specification 4.0.5.
- c. At least once per 18 months by performance of a system functional test which includes simulated automatic 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 spraying of coolant into the containment may be excluded from this test.
- d. By performance of an air or smoke flow test of the containment spray nozzles at least once per 5 years and verifying that. each spray nozzle is unobstructed.
*Whenever both 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.
\ PERRY - UNIT 1 3/4 6-25
CONTAINMENT SYSTEMS SUPPRESSION POOL COOLING LIMITING CONDITION FOR OPERATION 3.6.3.3 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 pool through two RHR heat exchangers.
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 suppression pool cooling loops inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN
- within the next 24 hours.
SURVEILLANCE REQUIREMENTS O 4.6.3.3 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 7,100 gpm on recirculation flow through the RHR heat exchangers to the suppression pool when tested pursuant to Specification 4.0.5.
"Whenever both 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 PERRY - UNIT 1 3/4 6-26
CONTAINMENT SYSTEMS
\ SUPPRESSION POOL MAKEUP SYSTEM
(/ LIMITING CONDITION FOR OPERATION 3.6.3.4 The suppression pool makeup system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1,. 2 and 3. ACTION:
- a. With one suppression pool makeup line inoperable, restore the inoperable makeup line 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 the upper containment pool water level less than the limit, restore the water level to within the limit within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- c. With upper containment pool water temperature greater than the limit, restore the upper containment pool water temperature to within the limit within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
/-
I SURVEILLANCE REQUIREMENTS \s_ 4.6.3.4 The suppression pool makeup system shall be demonstrated OPERABLE:
- a. At least once per 24 hours by verifying the upper containment pool water:
- 1. Level to be greater than or equal to 22'10" above the reactor pressure vessel flange, and
- 2. Temperature to be less than or equal to 100*F.
- b. At least once per 31 days by verifying that:
- 1. The steam dryer storage / reactor well pool gate is removed and the fuel transfer pool gate is in place.
- 2. Each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secure in position, is in its correct position.
- c. At least once per 18 months by performing a system functional test which includes simulated automatic 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 makeup of water to the suppression pool may be excluded from this test.
\ PERRY - UNIT 1 3/4 6-27
CONTAINMENT SYSTEMS 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.4 The containment and drywell isolation valves shown in Table 3.6.4-1 shall be OPERABLE with isolation times less than or equal to those shown in Table 3.6.4-1. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and **. ACTION:
- a. With one or more of the containment or drywell isolation valves shown in Table 3.6.4-1 inoperable, maintain at least one isolation valve OPERA 8LE 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.*
The provisions of Specification 3.0.4 are not applicable provided that 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, 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. Otherwise, in Operational Condition **, suspend all operations involving CORE ALTERATIONS, handling of irradiated fuel in the primary containment and with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.
- Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative controls.
- When handling irradiated fuel in the primary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
9 PERRY - UNIT 1 3/4 6-28
CONTAINMENT SYSTEMS ^ SURVEILLANCE REQUIREMENTS 4.6.4.1 Each isolation valve shown in Table 3.6.4-1 shall be demonstrated
- OPERA 8LE prior to returning the valve to service after maintenance, repair or replacement work is performed on the valve or its associated . actuator, control or power circuit by cycling the valve thrcugh at least one complete cycle of full travel and verifying the specified isolation time.
0 4.6.4.2 Each automatic isolation valve shown in Table 3.6.4-1 shall be demon-strated OPERA 8LE at least once per 18 months by verifying that on an isolation 1 test signal each automatic isolation valve a:tuates to its isolation position. I 4.6.4.3 The isolation time of each power operated or automatic valve shown in Table 3.6.4-1 shall be determined to be within its limit when tested pursuant to Specification 4.0.5. I 4 1 i s PERRY - UNIT 1 3/4 6-29
. - . ~ - . . . . . . , , _ _ . - . - .vm. . _ _ . _ , _ , _ , _ , . , , _ _ . , . . . , - _ . _ . . _ - _ . . , , _ . _ . . _ . . , , , _ _ . . _ , . . . . _ , . . - . . . _ - _ . _ . - ,
Table 3.6.4-1 Containment and Drywell Iaolation Valves A g a. CONTAINMENT AUTOMATIC ISOLATION VALVES s Valve Penetration Valve gc) Maximum Secondary sest 5;; Number Number Group Isolation Time Containment Pressure
$ (Seconds) Bypass Path (Psig)
(Yes/No) 1821-F016 P423 6 20 Yes 11.31 1821-F019 P423 6 20 Yes 11.31 1821-F022A P124 6 5(g) No 11.31 1821-F0228 P416 6 5(g) No 11.31 1821-F022C P122 6 5(g) No 11,31 1821-F0220 P415 6 5(g) No 11.31 1821-F028A P124 6 5(g) No 11.31 1821-F0288 P416 6 5(g) No 11.31 1821-F028C P122 6 5(g) No 11.31 1821-F0280 P415 6 5(g) No 11.31 M
^ 1821-F067A P124 6 22.5* No 11.31 1821-F0678 P416 6 22.5* No 11.31 i 1821-F067C P122 6 22.5* No 11.31 5 1821-F067D P415 6 22.5* No 11.31 ID17-F071A P201 1 3 Yes 11.31 1D17-F0718 P201 1 3 Yes 11.31 1017-F079A P201 1 3 Yes 11.31 1017-F079B P201 1 3 Yes 11.31 ID17-F081A P317 1 3 Yes 11.31 ID17-F081B P317 1 3 Yes 11.31 1017-F089A P317 1 3 Yes 11.31 1017-F0898 P317 1 3 Yes 11.31 1E12-F008 P421 4 33 No(h) 73,37 1E12-F009 P421 4 33 No 11.31 1E12-F011A P105 2 60* No (b) 1E12-F0118 P407 2 60* (b) 1E12-F021 P408 2 90 No(h)
No 11.31 1E12-F023 P123 4 90* No(h) 11.31 1E12-F024A P105 2 90 No (b) 1E12-F0248 P407 2 90 No (b) 1E12-F037A Pll3 4 180* No 11.31
-F037B P412 4 180* No 11.3
O O . O
- a. CONTAINMENT AUTOMATIC ISOLATION VALVES (Continued)
A E Valve Penetration Maximum Secondary Test Number Number Valve Group (c) Isolation Time Containment Pressure
] (Seconds) Bypass Path (Psig)
E (Yes/No) Z ~ IE12-F042A P113 4 27 No .11.31 IE12-F0428 P412 4 27 No 11.31 IE12-F064A P105 4 8 No (b) lE12-F064B P407 4 .8 No (b) lE12-F064C P408 4 8 No (b) IE21-F011 P105 17 20* No (b) IE21-F012 P105 2 180* No (b) IE22-F004 P410 16 27 No(h) 11.31 lE22-F012 P409 16 5 No(h) 11.31 w 1E22-F023 P409 1 180* No lh) yy,3y A m 1E32-F001A P124 10 20 No 11.31 J, IE32-F001E P416 10 20 No 11.31 IE32-F00lJ P122 10 20 No 11.31 IE32-F00lN P415 10 20 No 11.31 1E51-F031 III P101 9 30 No (b) IE51-F063 III P422 9 50* No 11.31 IE51-F064 III P422 9 10 No Ih) 11.31 IE51-F076 III P422 9 15* No '11.31 IE51-F077 III P106, P107 P115, P429 9 22.5* No 11.31 IG33-F001 P131 7 15 Yes 11.31 IG33-F004 P131 7 15 Yes 11.31 1G33-F028 P424 7 15 Yes 11.31 IG33-F034 P424 7 15 Ye 11.31 IG33-F039 P132 7 15 No[h) 11.31 IG33-F040 P132 7 15 No 11.31 IG33-F053 P419 7 15 Yes 11.31 IG33-F054 P419 7 15 Yes 11.31 i
- a. CONTAlflMElli AUTOMATIC ISOLATION VALVES (Continued)
A
= Valve Penetration Valve gc) Maximum Secondary Test Number Number Group Isolation Time Containment Pressure (Seconds) Bypass Path (Psig)
Ej (Yes/No) U IG41-F100 P203 1 30 Yes 11.31
~
IG41-f140 P301 1 30 Yes 11.31 IG41-f 145 P301 1 30 Yes 11.31 IG50-F272 P420 1 20* Yes 11.31 IG50-F277 P420 1 20" Yes 11.31 IG61- F 075 P417 1 22 Yes 11.31 IG61-F080 P417 1 22 Yes 11.31 IG61-fl65 P418 1 22 Yes 11.31 IG61-f l70 P418 1 22 Yes 11.31 IM14-F040 V313 8 4 Yes 11.31 m IM14-F045(j) V313 8 4 Yes 11.31
'g IM14-F085(j) V314 8 4 Yes 11.31 y, IM14-f090 V314 8 4 Yes 11.31 a
N IM14-F190 V313 8 4 Yes 11.31 IM14-F200 V314 8 4 Yes 11.31 IM14-fl95 V313 8 4 Yes 11.31 If114-f 205 V314 8 4 Yes 11.31 lill7-f 015 Pll4 5 5 Yes 11.31 IM17-f 025 P208 5 5 Yes 11.31 IMll-f 035 P428 5 5 Yes 11.31 IMll-f045 P436 5 5 Yes 11.31 IM51-fo90 P302 2 30* No 11.31 IMSI-Filo P302 2 30* No 11.31 IPil-F060 P108 1 30 ~Yes 11.31 IPll-F 080 Pill 1 30 Yes 11.31 IPll-F090 Pill 1 30 Yes 11.31 IP22-f010 P309 1 22 Yes 11.31 IP43-f 055 P310 2 30 Yes 11.31 IP43-F140 P311 2 30 Yes 11.31 IP4 3-F 215 P311 2 30 Yes 11.31 O O O
O
- a. CONTAINMENI AUTOMATIC ISOLATION VALVES (Continued)
A E Valve Penetration Valve gc) Maximum Secondary Test
- Number Group Isolation Time Number Containment Pressure (Seconds) Bypass Path (Psig)
E (Yes/No) G
,, IP50-f060 P404 1 30 Yes 11.31 1P50-f140 P405 1 30 Yes 11.31 IP50-F150 P405 1 30 Yes- 11.31 IP51-fl50 P308 1 15 Yes 11.31 IPS2-F160 P305 1 3 No 11.31 IPS2-fl10 P312 1 3 No 11.31 IPS2-f200 P306 2 30* Yes 11.31 IPS3-f010 P305 1 3 No 11.31 u, IPS3-f015 P305 1 3 No 11.31 ); IPS3-f020 P312 1 3 No 11.31 cn 1PS3-F025 P312 1 3 No 11.31 J, IP53-f070 P305 1 3 No 11.31 "* IPS3-f 075 P312 1 3 -No 11.31 IP54-F340 P210 1 20 Yes 11.31 IP86-f002 Pll7 1 30" Yes 11.31 T
1 l 1 i 1 i l
- b. CONTAltiMENT MANUAL ISOLATI0tl VALVES A
g valve Penetration Valve Maximum Secondary Test -< Number tiumbe r Group c) Isolation Time Containment Pressure (Seconds) Bypass Path (Psig) 5 (Yes/No) ,_. IB21-f06SA P121 100* Yes 11.31 1821-F0658 P414 100* Yes 11.31 IC11-f083f ") P204 12.S* Yes 11.31 IC41-FS18 P315 s'i lA NA Yes 11.31 ID23-f010AI ") P434 3 No (a) ID23-f010BI ') P320 3 tio (a) 1023-f020A(") P434 3 t!o (a) I 1023-f020B P320 3 No (a) ID23-f030AI " ")I P433 3 No (a) 1023-f030BI ") P31*J 3 No (a) R ID23-f040A " P433 3 No (a) 4 1023-f040he) P31'3 3 No (a) T ID23-f050 P425 3 No (a) I} P102 lE12-f004A I# "I 120* No (b) lE12-f004B P402 120* (b) IE12-f02/AI " Pll3 60* No(h) No 11.31 1012-f0?/BI " P412 60* tlo(h) 11.31 lE12-f028AI " P113 60 No 11.31 I P412 60 11.31 IE12-f02eB It12-f042CI " ")I P411 21 No(h) No 11.31 IE12-F0/3A(e) P11B IS* No 11.31 If12-f0/38(e) P431 IS* No 11.31 1f12-f105(e) P403 120* No (b) IE 21-F00lI "I P103 NA 120* (b) If21-f005I "I Pl12 NA 27 No(h) No 11.31 IE22-f015 P401 NA 24 No (b) O O O
O O O
- b. CONTAINHENT MANUAL ISOLATION VALVES (Continued)
A
@ Valve Penetration Valve Max imun. Secondary Test
- Group (c)
Number- tiun.ber Isolation Time Containment Pressure { (Seconds) Bypass Path (Psig) j 5 (Yes/No)
) IESI-f013 IESl-f019 l.f P123 P104 NA NA 15 5
No 11.31 11.31 IESI-f068 f ")III P106, P107 NA 60* No(h) No 33,37 PllS, P429 IE61-fS49 P317 NA NA Yes 11.31 i IE61-fSSO P317 NA NA Yes 11.31 1 lE61-f SSI P319 NA NA Yes 11.31 IE61-fSS2 P319 NA NA Yes 11.31 IG43-f050A P102 NA 3 - No (a) IG43-f050fe) P402 NA 3 No (a) m 1G43-f060 P401 NA 3 No (a) l IM17-f0SS P434 NA 3 No (a) l J, IM17-f 065 P320 NA 3 No (a) litSI-f 210A P425 NA 3 No (a) IMSI-f210B P318 NA 3 No (a) IMS I-f 220A e) P42S NA 3 No (a) IMSI-f220B(e) P318 NA 3 No (a) IMSI-f230A " P425 NA 3 No (a) I IllSI-f P318 NA 3 No (a) IMSI-f240AI " ")) 230B P425 NA 3 No (a) IM51-f2408 P318 NA 3 No (a) IMSI-f250A P425 NA 3 No (a) IMSI-f2508 e) P318 NA 3 No (a) 4 1
- b. CONTAltiMENI HAtlUAL ISOLAT10tl VALVES (Continued) el B Valve Penetration Valve Ma mum Seconday Test
- fiumber Group (c) fiumber Isolation Time Containme:;t Pressure (Seconds) Bypass Path (Psig)
E (Yes/No) Z
~ Iri27-F 751 P106, P107, NA NA Yes 11.31 PilS, P42s I P305 IPS3-F030 I ")) NA 3 No 11.31 P305 NA 3 No 11.31 IPS3-F03S I "I P312 IPS3-F040 I ")
NA 3 No 11.31 P312 NA 3 No 11.31 IPS3-FS36 fd IPS3-F04S ")/ F570 Id) P305 I} NA NA Yes 11.31 IPS3-FS41(d)/ FS/1 P312 flA fiA Yes 11.31 R IPS4-F726 P406 NA NA Yes 11.31
- IPS4-F727 P406 NA NA Yes 11.31
}
IPS7-F0lSA P304 NA 15* No 11.31
)
IPS7-F0lSB P116 NA IS* No 11.31 IP87-F037 P401 NA 3 Yes (b) IP8/-F065 P318 NA 3 Yes (a) IP8/-F071I * , P318 NA 3 Yes (a) IP87-f 0/4 P318 NA 3 Yes (a) IP87-f 0//gg) P318 NA 3 Yes (a) IP81-F049I " P413 NA 3 Yes 11.31 IP8/-F OSSI "I P413 NA 3 Yes 11.31 IPH/-f 046 P413 NA 3 Yes 11.31 I IP87-f OS2 "' P413 NA 3 Yes 11.31 IP8/-f 083I ") P106, P107 NA 3 Yes 11.31 P115, P429 IP87-F264I "I P106, P107 NA 3 Yes 11.31 P115, P429 O O O
v ~ v
~
- c. OINER CONTAINf!ENT ISOLATION VALVES m
jllj Valve Penetration Valve gc) Maximum Secondary Test i -< Number Number Group Isolation Time Containment Pressure (Seconds) Bypass Path (Psig) E (Yes/No) O [ IB21-f032A P121 NA NA fio (b) j IB21-f0328 P414 NA NA No (b) ICll-F122 III P204 NA NA Yes 11.31 1C41-f520 II) P315 NA NA Yes 11.31 Ifl2-f005 P106, P107, P115, P429 NA NA No 11.31 lE12-f025A P106, P107, P115, P429 NA NA 11.31 IE12-f0258 P106, P107, Pil5, P429 NA NA N (h) 11.31 IE12-f025C P106, P107, P115, P429 NA NA N No (h) 11.31 ICl2-f041C I#I P411 NA NA No 11.31 R IE12-F055A P106, P107, P115, P429 NA NA fio 11.31 4 IE12-f055h) P106, P107, Pil5, P429 NA NA No 11.31 m lE12-F550 P421 NA NA No 11.31 h IE12-f558Af Pil8 NA NA fio 11.31 lE12-f5588 P431 NA NA No 11.31 lE21-F006 I#I Pll2 NA NA 11.31 IE21-f 018 P106, P107, P115, P429 NA NA No(h) No 11.31 IE22-f005 II} P410 NA NA No 11.31 IE22-fu35 P409 f4A NA No 11.31 l IE51-F066 I#III) P123 NA NA No 11.31 IG41-f 522 I#I P203 NA NA Yes 11.31 IHil-f010 I#) Pll4 NA NA Yes 11.31 Itt!7-f 020 I#I P208 NA NA Yes 11.31 Ill!7-f030 I#) P428 NA NA Yes 11.31 17117-f 040 III P436 NA NA Yes 11.31
- c. 0 tiler C0f1TAlfalEtJT ISOLATI0t1 VALVES (Continued) v E Valve Penetration t-lax imum Secondary Test 7 tJumber tJumber Valve Group (c) Isolation Time Containment Pressure (Seconds) Bypass Path (Psig) c
( Yes/flo ) IN27-f %9A I} P121 f1A tJA No (b) ItJ27-f $59B I#} P414 NA NA tio (b) IPil-F545 I#) P108 flA NA Yes 11.31 IP22-f577 I#) P309 tJA tJA Yes 11.31 IP43-f721 I#) P310 NA fiA Yes 11.31 IP50-f539 I#) P404 flA NA Yes 11.31 IP51-f530I 'I P308 NA NA Yes 11.31 IPS2-f550 III P306 tJA NA Yes 11.31 m h IP54-f1098 fII P210 tJA NA Yes 11.31 IP86-F528 I Pil7 NA NA Yes 11.31 IP57-F524A(t) P304 NA NA No 11.31 IP57-F 524B( # } Pil6 tJA NA No 11.31 O O O
p [ f'N i
- d. ORYWELL ISOLATION VALVES m
E Valve Penetration Valve Maximum E Number Number Group (C} Isolation Time (Seconds) E
" IB33-F013A IIIII) PRB3049 NA NA 1833-F013B IIIII) PRB3090 NA NA
! IB33-F017A IOIII PRB3049 NA NA III) IB33-F017 PRB3090 NA NA l IB33-F019 PRB3105 11 5 l 1833-F020 II) PRB3105 11 5 IC41-F006 II)fI) PRB4031 NA NA i IC41-F00/ I#)III PRB4031 NA NA IG61-F030 II) PRB2030 1 22 IG61-F035 II) PRB2030 1 22 w IG61-F150 II) PRB2042 1 22 ! D IG61-F155 II) PRB2042 1 22 as O
- IH14-F055A(j)(i) VRB3003 8 4 IH14-F055B(j)(i) VRB3003 8- 4 IH14-F060A(j)(i) VRB3002 8 4 IH14-F060B(j)(i) VRB3002 8 4 IH14-F065(j)(i) VRB5001 8 4 IH14-F070(j)(i) VRB5001 8 4 IH16-F010A III PRB5012 13 5 I PRB50ll 13 5 IH16-F010B(II IH16-F020A }(') PRB5012 NA NA IH16-F020B I#IIII PRB50ll NA NA IH51-F010A Ii) PRB5012 12 37 IH51-F010B I} PRB50ll 12 37 IP22-F593 I#)III PRB3050 NA NA IP22-F015 II) PRB3050 1 18.8
- d. DRWE L L 150LATIOf4 VALVES (Continued)
A E Valve Penetration Valve Maximmu Group ICI flumber Number Isolation Time (Seconds) E
= '
b IP43-F355fg) PRB2039 2 10 IP43-f722 PRB2039 14A flA IP43-f400I '} PRB2038 2 10 IP43-f410I 'I PRB2038 2 10 I IP51-f653!)f5) PRB3050 t4A tJA IP51-F652I ') PRB3050 1 22.5 I IPS2-f639(III) PRB3050 f4A t1A IPS2-f646I ') PRB3050 2 30* I. IP54-F395 ') PRB2037 1 20" l D I g. s l 4 O O O .
i m o U 0 ~ ( l Table 3.6.4.1 Containment and Drywell Isolation Valves o h! NOTES: a. Isolation valve for instrument line which penetrates the containment, conforms to the requirements
- of Regulatory Guide 1.11. The In-service Inspection (ISI) program will provide assurance of the operability and integrity of the isolation provisiens. Type "C" testing will not be performed on g the instrument line isolation valves. The instrument lines will be within the boundaries of the
; Type "A" test, open to the media (containment atmosphere or suppression pool water) to which they l
,. will be exposed under postulated accident conditions. Three exceptions to the above are penetrations P401, P318, and P425. Isolation valves for these three penetrations include the H2 analyzer and Post i Accident Sampling System valves. These valves are normally closed post-LOCA, opened only inter-l mittently, and will receive Type C tests.
- b. flydrostatic leak test at > 1.10Pa.
- c. See Specification 3.3.2, Table 3.3.2-1, for isolation signal (s) associated with each valve groups 1-9. Valve groups 10-13,16 and 17 are as follows:
Valve Group 10 - MSIV Leakage Control System Valve Group 11 - Reactor Recirculation System Valve Group 12 - Combustible Gas Control System t: Valve Group 13 - Drywell Vacuum Relief System i Valve Group 16 - HPCS cp Valve Group 17 - LPCS s.
** d. Test connection valve.
- e. Remote manually controlled valve.
- f. Check valve.
- g. See Section 3/4.4.7, " Main Steam Line Isolation Valves."
- h. During Type C testing, valve stem and bonnet are checked for leaks as potential secondary containment bypass leakage paths.
- i. Not required to be OPERABLE in OPERATIONAt CONDITION **.
J. Not required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2 and 3.
" Standard closure time, based upon nominal pipe diameter, is approximately 12 inches / min for gate valves and approsisately 4 inches / min for globe valves.
3/4.6.5 VACUUM RELIEF CONTAINMENT VACUUM BREAKERS LIMITING CONDITION FOR OPERATION 3.o.5.1 All containment vacuum breakers shall be OPERABLE and the vacuum breakers shall be closed. APPLICABILITY: Whenever PRIMARY CONTAINMENT INTEGRITY is required per Specifications 3.6.1.1.1 and 3.6.1.1.2. ACTION:
- a. With one containment vacuum breaker inoperable for opening but known to be closed, operation may continue and the provisions of Specification 3.0.4 are not applicable.
- b. With two containment vacuum breakers inoperable and/or with one or two containment vacuum breakers open, within 4 hours close the motor operated isolation valve (s). Restore at least 3 vacuum breakers to OPERABLE and closed status within 72 hours or be in at least HOT SHUT 00WN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- c. With more than two containment vacuum breakers inoperable and/or open, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTCOWN within the next 24 hours, and:
- 1. Maintain an unobstructed opening (s) in the containment that equals or exceeds the flow area provided by two open vacuum breakers, or
- 2. Deactivate the containment spray by closing at least one valve in each containment spray supply header and deenergizing the power supply to its motor operator.
- d. With the position indicator of any containment vacuum breaker inoperable, restore the inoperable position indicator to OPERABLE status within 14 days or verify the vacuum breaker to be closed at least once per 24 hours by local indication. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
O PERRY - UNIT 1 3/4 6-42
p SUREVILLANCE REOUIREMENTS-h j 4.6.5.1 Each containment vacuum breaker shall be: l a. Verified closed at least once per 24 hours,
- b. Demonstrated OPERABLE:
- 1. At least once per 31 days by:
a) Cycling the vacuum breaker and isolation valve through at j least one complete cycle of full travel, b) Verifying the position indicator OPERABLE by observing expected valve movement during the cycling test.
- 2. At least once per 18 months by:
a) Verifying the pressure dif ferential required to begin to open the vacuum breaker, from the closed position, to be s 0.1 psid and to be fully open to be 1 0.2 psid (out-side containment to containment), and b) Verify.ing the position indicator OPERABLE by performance of a CHANNEL CALIBRATION .
\
- 3. By verifying the OPERABILITY of the vacuum breaker isolation valve differential pressure actuation instrumentation with the opening setpoint of greater than or equal to 0.0 psid and less than or equal to 0.112 psid (containment to outside containment) by performance of a:
I 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. r ( v PERRY - UNIT 1 3/4 6-43
CONTAINMENT HUMIDITY CONTROL LIMITING CONDITION FOR OPERATION 3.6.5.2 Containment average temperature and relative humidity shall be main-tained above the curve shown in Figure 3.6.5.2-1. APPLICABILITY: Whenever PRIMARf CONTAINMENT INTEGRITY is required for Specification 3.6.1.1.1. ACTION: With the containment average temperature / relative humidity not within the limits for acceptable operation as shown in Figure 3.6.5.2-1:
- a. In OPERATIONAL CONDITION 1, 2 or 3, restore the average temperature /
relative humidity to within the limits for acceptable operation as shown in Figure 3.6.5.2-1 within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours,
- b. At all other times, either:
- 1. Maintain an unobstructed opening (s) in the containment that equals or exceeds the ficw area provided by two open vacuum breakers, or
- 2. Deactivate the containment spray by closing at least one valve in each containment spray supply header and deenergizing the power supply to its motor operator.
SURVEILLANCE REOUIREMENTS 4.6.5.2 Containment average temperature / relative humidity shall be verified to be within the limits for acceptable operation curve shown in Figure 3.6.5.2-1:
- a. At least once every 24 hours,
- b. By verifying the temperature instrumentation 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 la months.
O PERR/ - UNIT 1 3/4 6-44
'4 4
m '
) '
v 100 ., i , i , i. ..
. t i ii I 90
- j _
- t. . p p. 4.__ _
4 : +_ _.. _._ __ .. __ . _ . . _. . . _ , - . ._. 80 '
- +- ,: -.-+ i j
-y j-! '. rb;--
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, 1 3 i ei 1< 70 . ..
,i.
., ,, i . , .
. . 1 i. , .,1 6 i 6 i . i
^
60 -+ CCEPTABLE i .at .... . .'. ...s . . .. . 1
- .-- CPERATION ,
- C ::: 50 - . .' .
. +;
', , l i l t -
3 . .
;- '.- .i-
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+
E i .. . 3 4n , s , i . . i ~, x . . . i 3
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,4 ,.
e , , , ,, 3.,., 30 ,,i i e
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* .*i ! - * . . <
e i , < +1 , - > E 20 '. I yr-- .
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OPERATION 10 , 1i _e l
..aq.:_. _ ._ a , , , ,
, 1
, , ___ - ._.. _ __. i
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>u '
' 4. '
0 120 60 70 80 90 100 110 - Temperature ( F) i CONTAINMENT AVERAGE TEMPERATURE VS RELATIVE HUMIDITY ! Figure 3.6.5.2-1 PERRY - UNIT 1 3/4 6-45
CONTAINMENT SYSTEMS ORYWELL VACUUM BREAKERS LIMITING CONDITION FOR OPERATION 3.6.5.3 All drywell vacuum breakers shall be OPERABLE and closed. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3* ACTION:
- a. With one drywell vacuum breaker 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 SHUT 00WN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours.
- b. With one drywell vacuum breaker open, restore the open vacuum breaker to the closed position within 1 hour or be in at least HOT SHUT-DOWN within the next 12 hours and in COLD SHUTOOWN withi;1 the following 24 hours,
- c. With the position indicator of an OPERABLE drywell vacuum breaker inoper-able, verify the vacuum breaker to be closed at least once per 24 hours by lecal indication. Otherwise, declare the vacuum breaker inoperable.
SURVEILLANCE RE0VIREMENTS 4.6.5.3 Each drywell vacuum breaker shall be:
- a. Verified closed at least once per 7 days.
- b. Demonstrated OPERABLE:
- 1. At least once per 31 days'by a) Cycling the vacuum breaker and associated isolation valve through at least one complete cycle of full travel.
b) Verifying the position indicators OPERABLE by observing expected valve movement during the cycling test.
- 2. At least once per 18 months by:
a) Verifying the pressure dif ferential required to open the vacuum breaker, from the closed position, to be less than or equal to 0.5 psid (containment to drywell), and b) Verifying the position indicators OPERABLE by performance of a CHANNEL CALIBRATION.
- 3. By verifying the OPERABILITY of the vacuum breaker isolation valve differential pressure actuation instrumentation with the opening setpoint 5 -0.810 inch water gauge do by performance of a:
a) CHANNEL FUNCTIONAL TEST at least once per 31 days, and b) CHANNEL CALIBRATION at least once per 18 months. "Not required to be OPERABLE until after non-nuclear heatup following initial criticality. PERRY - UNIT 1 3/4 6-46
/~' s CONTAINMENT SYSTEMS k. j 3/4.6.6 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *# . ACTION: Without SECONDARY CONTAINMENT INTEGRITY:
- a. In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours,
- b. In Operational Condition *#, suspend handling of irradiated fuel in the primary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE RE0VIREMENTS v 4.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:
- a. Verifying at least once per 24 hours that the pressure within the secondary containment is less than or equal to 0.40 inches of vacuum water gauge.
- b. Verifying at least once per 31 days that:
- 1. The primary containment equipment hatch is closed and sealed and the shield blocks are installed. adjacent to the shield building.
- 2. The door in each access- to the secondary containment is closed, except for routine entry and exit.
- 3. All penetrations terminating in the annulus not capable of being closed by OPERABLE automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in position.
*When irradiated fuel is being handled in the primary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
p #The primary containment equipment hatch is not required to be closed and S sealed and the shield blocks are not required to be installed adjacent to the {b shield building during initial fuel load. Surveillance Requirements 4.6.6.1.a and 4.6.6.1.b.1 are not required to demonstrate secondary containment integrity during initial fuel load. _ PERRY - UNIT 1 3/4 6-47
CONTAINMENT SYSTEMS ANNULUS EXHAUST GAS TREATMENT SYSTEM LIMITING CONDITION FOR OPERATION 3.6.6.2 Two independent annulus exhaust gas treatmeit subsystems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and
- ACTION:
- a. With one annulus exhaust gas treatment subsystem inoperable, restore the inoperable subsystem 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 primary 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 both annulus exhaust gas treatment subsystems inoperable in Operational Condition *, suspend handling of irradiated fuel in the primary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REOUIREMENTS 4.6.6.2 Each annulus exhaust gas treatment subsystem shall be demonstrated OPERABLE:
- a. At least once per 31 days by initiating, from the control room, flow through the HEPA filters and charcoal adsorcers and verifying that the subsystem operates for at least 10 hours with the heaters OPERABLE.
*When irradiated fuel is being handled in the primary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
O PERRY - UNIT 1 3/4 6-48
p CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
- b. 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.S.a, C;5.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 2000 scfm 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 03803; and 1
- 3. Verifying a subsystem flow rate of 2000 scfm i 10% during system operation when tested in accordance with ANSI N510-1980. The installed air flow monitor can be used to determine flow in t lieu of the pitot traverse.
- c. 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 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 03803; j
- d. At least once per 18 months by:
- 1. Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence for the LOCA.
- 2. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 6.0 inches water gauge while operating the filter train at a flow rate of_2000 scfm 10%.
- 3. 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
- b. Simulated automatic initation signal.
- 4. Verifying that the heaters dissipate 20 kw 10% when tested in accordance with ANSI N510-1980.
PERRY - UNIT 1 3/4 6-49
l l l l CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
- e. 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.5.c of Regulatory Guide 1.52 Revi-sion 2, March 1978, while operating the system at a flow rate of 2000 scfm 10%.
- f. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accord-ance with Reg ~ulatory 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 2000 scfm 10L O
O PERRY - UNIT 1 3/4 6-50
,s CONTAINMENT SYSTEMS
{, \a
\_ / 3/4.6.7 ATMOSPHERE CONTROL CONTAINMENT HYDROGEN RECOMBINER SYSTEMS LIMITING CONDITION FOR OPERATION 3.6.7.1 Two independent containment hydrogen recombiner subsystems shall be OPERABLE.
APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one containment hydrogen recombiner subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours. SURVEILLANCE REOUIREMENTS 4.6.7.1 Each containment hydrogen recombiner subsystem shall be demonstrated OPERABLE:
~s a. At least once per 6 months by verifying during a recombiner subsystem g
\- '
) functional test that the minimum heater sheath temperature increases to greater than or equal to 700 F within 90 minutes. Maintain > 700*F for at least 2 hcurs,
- b. At least once per 18 months by:
- 1. Performing a CHANNEL CALIBRATION of all control complex recombiner operating' instrumentation and control circuits.
- 2. Verifying the integrity of all heater electrical circuits by performing a resistance to ground test within 2 hours following the below required functional test. The resistance to ground for any heater phase shall be greater tnan or equal to 10,000 ohms.
- 3. Verifying during a recombiner subsystem functional test that the heater sheath temperature increases to greater than or equal to 1225 F within 5 hours and is maintained between 1225 F and 1450 F for at least 4 hours.
- 4. Verifying through a visual examination that there is no evidence of abnormal conditions within the recombiner enclosure; i.e, loose wiring or structural connections,. deposits of foreign materials, etc.
i r%l PERRY - UNIT 1 3/4 6-51
CONTAINMENT SYSTEMS COMBUSTIBLE GAS MIXING S'f STEM LIMITING CONDITION FOR OPERATION 3.6.7.2 Two independent combustible gas mixing subsystems shall be OPERABLE with each subsystem consisting of one combustible gas purge compressor. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one combustible gas mixing subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours. SURVEILLANCE REOUIREMENTS 4.6.7.2 Each combustible gas mixing subsystem shall be demonstrated OPERABLE:
- a. At least once per 92 days by:
- 1. Starting the subsystem from the control room,~ and
- 2. Verifying that the subsystem operates for at least 15 minutes.
- b. At least once per 18 months by verifying a subsystem flow rate of at least 500 scfm.
O PERRY - UNIT 1 3/4 6-52
f- x CONTAINMENT SYSTEMS t ) \s / CONTAINMENT AND DRYWELL' HYDR 0 GEN IGNITION SYSTEM LIMITING CONDITION FOR OPERATION 3.6.7.3 The containment and drywell hydrogen ignition system shall be operable consisting of two independent containment and drywell hydrogen ignition sub-systems each consisting of three circuits with no more than two igniter assem-blies inoperable per circuit and no more than five igniter assemblies inoperable per subsystem, and no adjacent igniter assemblies inoperable. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With one containment and drywell hydrogen ignition subsystem and/or circuit inoperable, restore the inoperable subsystem and/or circuit to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours.
- b. With any adjacent igniter assembly inoperable, restore all igniter assemblies adjacent to an inoperable igniter assembly to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours.
(m')
%._ J SURVEILLANCE REQUIREMENTS 4.6.7.3 The containment and drywell hydrogen ignition system shall be demonstrated OPERABLE:
- a. At least once per 6 months by energizing all the igniter assemblies and performing a current voltage measurement of each circuit.
- 1. If more than 3 igniter assemblies on either subsystem are deter-mined to be inoperable, Surveillance Requirement 4.6.7.3.a shall be performed at least once per 92 days until this condition no longer exists.
- 2. If more than 1 igniter assembly on each subs, tem are determined to be inoperable, determine if the inoperable igniter assemblies are adjacent.
- b. At least once per 18 months by energizing each igniter assembly and verifying by current measurement sufficient current / voltage draw to develop 1700 F temperature for those igniter assemblies in high radi-ation areas and verifying a surface temperature of at least 1700 F for each of the remaining igniters.
( V PERRY - UNIT 1 3/4 6-53
l r '~ 3/4.7 PLANT SYSTEMS _ I s v/ 3/4.7.1 COOLING WATER SYSTEMS EMERGENCY SERVICE WATER SYSTEM (LOOPS A, B, C) LIMITING CONDITION FOR OPERATION 3.7.1.1 The. emergency service water (ESW) loop (s) shall be OPERABLE which is associated with 'ystems s or components which are required to be OPERABLE. Each OPERABLE ESW loop shall be comprised of: -
- a. One OPERABLE ESW pump, and
- b. An OPERABLE flow path capable of taking suction from Lake Erie and transferring water through the associated systems and components heat exchanger (s) that are required to be OPERABLE.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and
- ACTION:
With an emergency service water loop (s) inoperable which is associated with system (s) or component (s) required to be OPERABLE, declare the associated system (s) or component (s) inoperable and take the ACTION required by the ,3 , applicable Specification (s). I (J' SURVEILLANCE REOUIREMENTS 4.7.1.1 The above required emergency service water system loops shall be demonstrated OPERABLE:
- a. At least once per 31 days by verifying that each valve in the flow path that is not locked. oealed or otherwise secured in position, is in its correct position.
- b. At least once per 18 months during shutdown by verifying that each automatic valve servicing safety related equipment actuates to the correct position on a LOCA. test signal.
*When handling irradiated fuel in the Fuel Handling Building or primary containment.
(~N e N..)\ PERRY - UNIT 1 3/4 7-1
3/4.7 PLANT SYSTEMS EMERGENCY CLOSED COOLING WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.1.2 The emergency closed cooling (ECC) loop (s) shall be OPERABLE which is ' associated with systems or components which are required to be OPERABLE. Each OPERABLE ECC loop shall be comprised of:
- a. One OPERABLE ECC pump, and
- b. An OPERABLE flow path capable of transferring water th ough the associated systems and components heat exchanger (s) that are required to be OPERABLE.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, and 5. ACTION: With an emergency closed cooling loop (s) inoperable which is associated with system (s) or component (s) required to be OPERABLE, declare the associated system (s) or component (s) inoperable and take the ACTION recuired by the s applicable Specification (s). SURVEILLANCE REQUIREMENTS 4.7.1.2 The above required emergency closed cooling loop (s) 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 or otherwise secured in position, is in its correct position.
- b. At least once per 18 months during shutdown by verifying that each automatic valve servicing safety related equipment actuates to the correct' position on a LOCA test signal.
O PERRY - UNIT 1 3/4 7-2
PLANT SYSTEMS U 3/4.7.2 CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency recirculation system subsystems shall be OPERABLE. APPLICABILITY: All OPERATIONAL CONDITIONS and *. ACTION:
- a. In OPERATIONAL CONDITION 1, 2 or 3, with one control room emergency recirculation 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 ih COLD SHUTOOWN within the following 24 hours.
- b. In OPERATIONAL CONDITION 4, 5 or *:
- 1. With one control room' emergency recirculation subsystem inoper able, restore the inoperable subsystem to GPERABLE status within-7 days or initiate and maintain operation of the OPERABLE subsystem in the emergency recirculation mode of operation.
m 2. With both control room emergency recirculation subsystems I inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the Fuel Handling Building and the primary containment, and operations with a potential for draining the reactor vessel.
- c. The provisions of Specificatio.n 3.0.3 are not applicable in Operational Condition *.
SURVEILLANCE REQUIREMENTS 4.7.2 Each control room emergency recirculation subsystem shall be demonstrated OPERABLE:
- a. At least once per 12 hours by verifying that' the c'ontrol room air temperature is less than or equal to 90*F.
- 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 OPERABLE.
*When irradiated fuel is being handled in the Fuel Handling Building or % primary containment.
PERRY - UNIT 1 3/4 7-3
PLANT 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 communi-cating 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.S.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 30000 scfm 1C%.
- 2. Verifying within 31 days af ter 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% 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 30000 scfm 10% during sub-system operation when tested in accordance with ANSI N510-1980.
The installed air flow monitor can be used to determine flow in lieu of a pitot traverse.
- d. Af ter 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 Posi-ton C.6.b of Regulatory ' uide 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% 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:
- 1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 4.9 inches water gauge while operating the subsystem at a flow rate of 30000 scfm 2 10%.
- 2. Verifying that on each of the below emergency recirculation mode actuation test signals, the subsystem automatically switches to the emergency recirculation mode of operation and the isolation dampers close within 10 seconds:
a) High Drywell Pressure b) Low Reactor Water Level-Level 1 c) High radiation from control room ventilation duct PERRY - UNIT 1 3/4 7-4
PLANT SYSTEMS [^3
\
SURVEILLANCE REQUIREMENTS (Continued)
' 3. Verifying that the heaters dissipate 100 Kw 10% when tested in accordance with ANSI N510-1980.
- 4. Verifying that. leakage through the outside air intake dampers (M25-F010A and M25-F0208 for one train and M25-F0108 and M25-F020A for the other train) is limited to less than 20 scfm.
- 5. Verify that leakage through the exhaust dampers M25-F130A and M25-F130B is limited to less than 20 scfm.
- f. Af ter each complete or partial replacemen't 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.5.a and C.S.c of Regulatory Guide 1.52 Revi-sion 2, March 1978, while operating the system at a flow rate of 30000 scfm 10%.
- g. After each complete or partial replacement of a charcoal adsorber back bv verifying that the charcoal adsorber bank satisfies the in-place: penetration and testing acceptance criteria of less than 0.05%
O in accordance with Regulatory Positions C.S.a and C.S.d of Regulatory Guide' 1.52 Revision 2, March 1978, . for a halogenated hydrocarbon re-frigerant test gas while operating the system at a flow rate of 30000 scfm 10%. . l 4 ssl PERRY - UNIT 1 3/4 7-5 L.
~-
PLANT SYSTEMS 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM LIMITING CONDITION FOR OPERATION 3.7.3 The reactor core isolation cooling (RCIC) system shall be OPERABLE with an OPERABLE flow path capable of automatically taking suction from the sup-pression 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 HPCS 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 doie pressure to less than or equal to 150 psig within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.7.3 The RCIC system shall be demonstrated 0PERABLE:
- a. At least cnce 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 700 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 1020 + 25 - 100 psig (steam dome pressure).*
- 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.
- Not required to be OPERABLE until after non-nuclear heatup following initial criticality. ]
l PERRY - UNIT ~1 3/4 7-6 I
l l f- s\ PLANT SYSTEMS
\
, \s_ / l SURVEILLANCE REQUIREMENTS (Continued)
- 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 i.
or equal.to 700 gpm in the test flow path when steam i,5 sup-plied to the turbine at a pressure of 150 + 15 - O psig (steam dome pressure).*
- 3. Verifying that the suction for the RCIC system is automatically i
transferred-from the condensate _ storage tank to the suppression i i pool on a condensate storage tank water level - low signal and on a suppression pool water level - high signal. c r
\
, *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 tests. 4 7 4 F O PERRY - UNIT 1 3/4 7-7 's
PLANT SYSTEMS 3/4.7.4 SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.4 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: With 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 4.7.4.g on the attached component or declare the attached system inoperable and follow the appropriate ACTION statement for that system. SURVEILLANCE RE0VIREMENTS 4.7.4 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requir.,'nts of Specification 4.0.5.
- a. Insoection Tyoes As used in this specification, type of snubber shall mean snubbers of the same design and manufacturer, 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 snall 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 inspections shall be performed in accordance with the following schedule:
O PERRY - UNIT 1 3/4 7-8
PLANT SYSTEMS
. []f \
V ~ SURVEILLANCE REQUIREMENTS (Continued) No. Inoperable Snubbers of Each Type per Subsequent Visual Inspection. Period Inspection Period *#^ 0 18 months ! 25% 1 12. months 25%
-2 6 months t 25%
3,4 124 days 25% 5,6,7 62 days 25% 8 or more 31 days 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 securo, 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 interval, providing that:
(1) the cause of the rejection is clearly established and remedied for that particular snubber and for other snubbers irrespective of type on that system that may be generically susceptible; and/or (2) the affected snubber is functionally tested in the as found condition and V[,D 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 for each of the related systems.
- 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 using at least one of the following: (1) manually induced snubber moven.ent; or (2) evaluation of in place snubber piston setting; or (3) stroking the mechanical snubber through its full range of travel.
*The inspection interval for each type of snubber shall-not be lengthened more than one' step at a time unless a generic problem has been identified and corrected; in that event the inspection interval may be lengthened one step the first time and two steps thereafter if no inoperable snubbers of that type are found.
O i #The provisions of Specification 4.0.2 are not applicable. PERRY - UNIT 1 3/4 7-9 s
PLANT SYSTEMS SURVEILLANCE RE0VIREMENTS (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 snubber. 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 4.7.4.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; or
- 2) A representative sample of each type of snubber shall be functionally tested in accordance with Figure 4.7.4-1. "C" is the total number of snubbers of a type found not meeting the acceptance requirements of Specification 4.7.4.f. The cumulative number of snubbers of a type tested is denoted by "N". At the end of each day's testing, the new values of "N" and "C" (previous day's. total plus current day's increments) shall be plotted on Figure 4.7.4-1. If at any time the point plotted falls on or above the " Reject" line all snubbers of that type shall be functionally 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 Testing" 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 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; or
- 3) An initial representative sample of 55 snubbers of each type shall be functionally tested. For each snubber type which does not meet the functional test acceptance criteria, another sample of at least 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 results from this sample plan shall be plotted using an " Accept" line which follows the equation N = 55(1 + C/2). Each snubber point should be plotted as soon as the snubber is tested. If the 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.
PERRY - UNIT 1 3/4 7-10
^
7 PLANT SYSTEMS i \. SURVEILLANCE REQUIREMENTS (Continued) The representative sample selected for the 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 various configu-rations, operating environments, range of size, a.nd capacity of snubbers of each type. Snubbers placed in the same locations as snubbers which failed the p.evious 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 testirg, additional sampling is required due to failure of only one type of snubber, tne functional 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; Snubber bleed, or release rate where required, is present in (m - 2)
V) both tension and compression, within the specified range (hydraulic snub'bers 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 methoos 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 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 (qV) in order to ensure that the component remains capable of meeting the designed service.
PERRY - UNIT 1 3/4 7-11
PLANT SYSTEMS SURVEILLANCE REOUIREMENTS (Continued) 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 4.7.4.e. for snubbers not meeting the functional test acceptance criteria.
- h. Functional Testing of Reoaired and Reolaced Snubbers Snubbers which fail the visual inspection or the functional test 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 Procram The service life of all snubbers shall be monitored to ensure that the service life is not exceeded between surveillance inspections.
The maximum expected service life for various seals, springs, and other critical parts shall be extended or shortened based on moni-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 be retained in accordance with Specification 6.10.3. l e' l PERRY - UNIT 1 3/4 7-12
g -n - 1 - - .-a _ . ., -,a - - - . - O 10 9 8 7 p REJECT [ 1 00 Q Cs -
,gso**/[
4 cr*/*/ CONTINUE i 3 -
" I' 2 - . .
ct,0 *O s + ACCEPT 0 10 20 30 40 50 60 70 80 90 100 N SAMPLE PLAN 2) FOR SNUB 8ER FUNCTIONAL TEST Figure 4.7.4-1 PERRY - UNIT 1 3/4 7-13 l
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PLANT SYSTEMS 3/4.7.5 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.5 Each sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting material or 10 microcuries of alpha emitting material shall be free of greater than or equal to 0.005 micro-curies 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 RE0VIREMENTS 4.7.5.1 Test Reouirements - 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. 4.7.5.2 Test Frecuencies - 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. Sources in use - At least once per six months for all sealed sources containing radioactive material:
- 1. With a half-life greater than 30 days, e.<cluding Hydrogen 3, and
- 2. In any form other than gas.
PERRY - UNIT 1 3/4 7-14
PLANT SYSTEMS X.) 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 moaths. 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.
4.7.5.3 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. I O l PERRY - UNIT 1 3/4 7-15
PLANT SYSTEMS 3/4.7.6 MAIN TURBINE BYPASS SYSTEM LIMITING CONDITION FOR OPERATION 3.7.6 The main turbine bypass system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITION 1 when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With the main turbine bypass system inoperable, restore the system to OPERABLE status within 1 hour or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REQUIREMENTS 4.7.6 The main turbine bypass system shall be demonstrated OPERABLE at least once per:
- a. 7 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 measured 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 seconds. b) Bypass valve opening shall start in less than or equal to 0.1 seconds. O PERRY - UNIT 1 3/4 7-16 l
,m
- PLANT SYSTEMS
[ j\ \ 3/4.7.7 FUEL HANDLING BUILDING FUEL HANDLING BUILDING VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.7.1 At least three Fuel Handling Building (FHB) ventilation exhaust subsystems shall be OPERABLE. APPLICABILITY: When irradiated fuel is being handled in the Fuel Handling Building. ACTION: With one FHB ventilation exhaust subsystem inoperable, restore the inoperable system to OPERABLE status within 7 days or suspend handling of irradiated fuel in the FHB. The provisions of Specification 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS 4.7.7.1 Each of the required FHB ventilation exhaust subsystem shall be demonstrated OPERABLE: n (V a. 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 OPERA 8LE.
- b. At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housing, 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 deceptance criteria of less than 0.05*. and uses the test procedure guidance in Regulatory Positions C.5.a, C.S.c and C.5.d of Regulatory . Guide 1.52, Revision 2, March 1978, and the system flow rate is 15000 scfm 10%.
- 2. Verifying within 31 days af ter 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% when tested at a temperature of 30 C and a relative humidity of 70%
in accordance with ASTM 03803; and fs, 3. Verifying a subsystem flow rate of 15000 scfm 10*. during 'Q system operation when test.ed in accordance with ANSI N510-1980. PERRY - UNIT 1 3/4 7-17
PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) c. After every 720 hours of charcoal ac'sorber operation by verifying within 31 days af ter removal that a laboratory analysis of a repre-sentative carbon sample obtained in a:cordance 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% when tested at a temperature of 30 C and a relative humidity of 70% in accordance with ASTM 03803. ,
- d. At least once per 18 months by:
- 1. Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence for the fuel handling accident.
- 2. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 4.9 inches water gauge while operating the filter train at a flow rate of 15000 scfm 10%.
- 3. Verifying that the filter train starts on manual initiation from the control room.
- 4. Verifying that the heaters dissipate 50 kW 10% when tested in accordance with ANSI N510-1980.
- e. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration acceptance criteria of less than 0.05% in accordance with Regulatory Positions C.5.a and C.5.c of Regulatory Guide 1.52, Revision 2, March 1978, while operating the subsystem at a flow rate of 15000 scfm 10%.
- f. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace penetration acceptance criteria of less than 0.05% in accor-dance with Regulatory Positions C.5.a and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrig-erant test gas while operating the subsystem at a flow rate of 15000 scfm i 10%.
O PERRY - UNIT 1 3/4 7-18
i
- L 4
PLANT SYSTEMS .i O FUEL HANDLING BUILDING INTEGRITY ( j LIMITING CONDITION FOR OPERATION ; i j 3.7.7.2 FUEL HANDLING BUILDING (FHB) INTEGRITY shall be maintained. APPLICABILITY: When' irradiated fuel is being handled in the Fuel Handling Building. l ACTION: Withoet FUEL HANDLING BUILDING INTEGRITY suspend handling of irradiated fuel in Fuel Handling Building. The provisions of Specification 3.0.3 are not !
-applicable.
SURVEILLANCE REQUIREMENTS j 4.7.7.2 FHB INTEGRITY shall be demonstrated by: (- j a. Verifying at least once per 24 hours that the FHB ventilation j exhaust system is operable as required by Specification 3.7.7.1. l
- b. Verifying within 24 hours prior to the start of handling of irradiated fuel in the FHB and at least once per 24 hours while handling irradiated fuel in the FHB that:
1 i 1. The doors in each access to the 620-foot elevation of the FHB
- are closed, except for normal entry and exit,
- 2. The FHB railroad track door is closed, and 3 The fuel handling area floor hatches are in place.
- 4. The shield blocks are installed adjacent to the shield building.
i t l t t PERRY - UNIT 1 3/4 7-19 ., k -
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4
- ' 'N 3/4.8 ELECTRICAL POWER SYSTEMS '
'U) 3/4.8.1- A.C. SOURCES -
A.C. SOURCES -)CPERATING' < LIMITING CONDITIOE FOR OPERATION 3.8.1.1. As a minimum, the following A.C. electrical power sources shall be OPERABEE:
- a. Two physically independent circu-its between the offsite transmission network and the onsite Class 1E distribution system, and
- b. Three separate and independent diesel generators, each with:
- 1. A separate day fuel tank containing a minimum of 225 gallons of fuel for Div 1 and Div 2 and 204' gallons of fuel for Div 3,
- 2. A separate fuel storage system containing a mir.imum of i 69,430 gallons of fuel for Div 1 and Div 2 and 34,824 gallons of fuel for Div 3, and
- 3. A separate fuel transfer pump.
q APPLICABILITY: OPERATIONALCONDITIONS1,b2,and3. ACTION: s
- 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 8 hours thereafter. If either diesel generator Div 1 or Div 2 has not been successfully tested within the past 24 hours, demonstrate its OPERABILITY by performing Surveillance Re-quirements 4.8.1.1.2.a.4 and 4.8.1.1.2.a.$ for each such diesel gen-erator, separately within 24 hours. Restore the 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 either diesel generator Div 1 or Div 2 inoperable, demonstrate the OPERABILITY of the above required A.C. offsite sources by perform-ing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least i
once per 8 hours thereaf ter. If the diesel generator became inoperable due to any cause other than preplanned prsventive maintenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE diesel gererators 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 24 hours *;
*This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY, The provisions of Specification 3.0.2 are not applicable.
PERRY - UNIT 1 3/4 8-1
ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued) restore the 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 diesel generator Div 1 or Div 2 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 thereaf ter. If a diesel generator became inoperable due to any cause other than preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE diesel generators separately for each diesel generator by performing Surveillance Requirements 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 within 8 hours
- for each diesel generator which has nct been success-fully tested within the past 24 hours. Restore at least one of the inoperable A.C. sources to OPERABLE status within 12 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. Restore at least two offsite circuits and diesel generators Div 1 and Div 2 to OPERA 8LE status with 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.
- d. With diesel generator Div 3 of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the offsite 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 the diesel generator became inoperable due to any cause other than preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE diesel generators separately by performing Surveillance Requirements 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 within 24 hours *. Restore diesel generator Div 3 to OPERABLE status within 72 hours or declare the HPCS system and the C ESW pump inoperable and take the ACTION required by Specifications 3.5.1 and 3.7.1.1.
- e. With diesel generator Div 1 or Div 2 of the above required A.C.
electrical power sources inoperable, in addition to ACTION b or c, as applicable, verify within 2 hours that all required systems, subsystems, trains, components and devices that depend on the remaining OPERABLE diesel generator as a source of emergency power are also OPERABLE; otherwise, be in at least HOT SHUTDOWN within the next 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. The provisions of Specification 3.0.2 are not applicable.
PERRY - UNIT 1 3/4 8-2 t j
-ig) ELECTRICAL POWER SYSTEMS V LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued)
- f. With both of the above required offsite circuits inoperable, demon-strate the OPERABILITY of three diesel generators by performing Sur-viellance Requirements 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 offsite 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 gener-ator OPERABILITY per Surveillance Requirements 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 a.
- g. With diesel generators Div 1 and Div 2 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 k and Surveillance Requirements 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 for diesel generator Div 3 within 8 hours *. Restore.at least one of the inoperable diesel generators Div 1 and Div 2 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 both diesel generators Div 1 and Div 2 to OPERABLE status within 72 hours from time of inidial loss or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours.
- h. With one offsite circuit of the'above required A.C. electrical power
~
sources and diesel generator Div 3 inoperable, apply the requirements of ACTION a and d specified above.
- i. With either diesel generator Div 1 or Div 2 inoperable and diesel gen-erator-Div 3 inoperable, apply the requirements of ACTION b, d and e specified above.
*This test.is required to be completed regarr ess of when the inoperable diesel (q
j
) generator is restored to OPERABILITY.
are not applicable. The provisions of Specification 3.0.2 PERRY - UNIT 1 3/4 8-3
ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between the offsite transmission network and the onsite Class lE distribution system shall be:
- a. Determined OPERABLE at least once per 7 days by verifying correct breaker alignments and indicated power availability, and
- b. Demonstrated OPERABLE at least oncc per 18 months during shutdown by transferring 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 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 day tank.
- 2. Verifying the fuel level in the fuel storage tank.
- 3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the day tank.
- 4. Verifying the diesel starts from ambient conditions and acceler-ates to at lesst 441 rpm for Div 1 and Div 2 and 882 rpm for Div 3 in less than or equal to 10 seconds
- The generator voltage and frequency shall be 4160 420 volts and 60 1.2 Hz within 10 seconds
- after the start signal for Div 1 and Div 2 and 13 seconds
- after the start signal for Div 3.
- 5. Verifying the diesel generator is synchronized, loaded to between 5600 and 5800 kw** for diesel generators Div 1 and Div 2 and loaded to greater than or equal to 2600 kw for diesel generator Div 3 in less than or equal to 60 seconds *, and operates with this load for at least 60 minutes.
- 6. Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.
*All diesel generator starts for the purpose of this Surveillance Requirement may be preceded by an engine prelube period. The diesel generator start (10 sec)/ load (60 sec) from ambient conditions shall be performed at least once per 184 days in these surveillance tests. All other engine starts for the purpose of this surveillance testing may be preceded by other warmup pro-cedures recommended by the manufacturer so that the mechanical stress and wear on the diesel engine is minimized. **This band is meant as guidance to avoid routine overloading of the engine.
Loads in excess of this band shall not invalidate the test; the loads, however, shall not be less than 5600 kw nor greater than 7000 kw. PERRY - UNIT 1 3/4 8-4
l ELECTRICAL POWER SYSTEMS V)
-SURVEILLANCE REQUIREMENTS (Continued)
- 7. Verifying the pressure in all diesel generator air start receivers to be greater than or equal to 210 psig.
- b. At least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to 1 hour by checking for and removing accumulated water from the day tank.
- c. 'At least once per 92 days by. checking for and removing accumulated water from the fuel oil storage tanks.
- d. At least once per 92 days and from new fuel oil prior to its addi-tion to the storage tanks by verifying that a sample obtained in accordance with ASTM-D270-1975 meets the following minimum require-ments in accordance with the tests specified in ASTM-0975-1977:
- 1) A water and sediment content of less than or equal to 0.05 volume percent;
- 2) A saybolt universal viscosity at 100*F of greater than or equal
~
to 32.6 sus, but less than or equal to 40.1 sus;
- 3) An API gravity as specified by the manufacturer at 60*F of greater than or equal to 26 degrees, but less than or equal to 36 degrees;
- 4) An impurity level of less than 2 mg of insolubles per 100 ml when tested in accordance with ASTM-02274-70; analysis shall be completed within 7 days after obtaining the sample but may be sampled and analyzed after the addition of new fuel oil; and
- 5) The other properties specified in Table 1 of ASTM-0975-1977 and Regulatory Guide 1.137, Revision 1, October 1979, Position 2.a., when tested in accordance with ASTM-0975-1977; analysis shall be completed within 14 day.s after obtaining the sample but may be sampled and analyzed after the addition of new fuel oil.
- e. At least once per 18 months *, during shutdown, by:
- 1. Subjecting the diesel to an inspection in accordance with instructions prepared in conjunction with its manufacturer's recommendatiens for this class of standby service.
- 2. Verifying the diesel generator capability to reject a load of greater than or equal to 1400 kw (LPCS pump) for diesel generator Div 1, greater than or equal to 725 kw (RHR B pump or RHR C pump)
V *For any start of a diesel, the diesel must be loaded in accordance with the manufacturer's recommendations PERRY - UNIT 1 3/4 8-5
ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) for diesel generator Div 2, and greater than or equal to 2200 kw (HPCS pump) for diesel generator Div 3 while maintaining speed less than nominal speed plus 75% of the difference between nominal speed and the ove'rspeed trip setpoint or 15% above nominal, whichever is less.
- 3. Verifying the diesel generator capability to reject a load of 5800 kw for diesel generators Div 1 and Div 2 and 2600 kw for diesel generator Div 3 without tripping. The generator voltage shall not exceed 4784 volts for Div 1 and Div 2 and 5000 volts for Div 3 during and following the load rejection.
- 4. Simulating a loss of offsite power by itself, and:
a) For divisions 1 and 2:
- 1) Verifying de energization of the emergency busses and load shedding from the emergency busses.
- 2) Verifying the diesel generator starts
- on the auto-start signal, energizes the emergency busses with per-manently connected loads within 10 seconds, energizes the auto connected loads through the load sequence (individual load timers) and operates for greater than or equal to 5 minutes while its generator is so loaded. After energization, the steady state voltage and frequency of the emergency busses shall be main-tained at 4160 420 volts and 60 1.2 Hz.during this test.
b) For division 3:
- 1) Verifying de-energization of the emergency bus.
- 2) Verifying the diesel generator starts
- on the auto-start signal, energizes the emergency bus with the per-manently connected loads within 13 seconds and operates for greater than or equal to 5 minutes while its gen-erator is so loaded. After energization, the steady
*All diesel generator starts for the purpose of this Surveillance Requirement may be preceded by an engine prelube period. The diesel generator start (10 sec)/ load (60 sec) from ambient conditions shall be performed at least once per 184 days in these surveillance tests. All other engine starts for the purpose of this surveillance testing may be preceded by other warmup pro-
, cedures recommended by the manufacturer so that the mechanical stress and wear on the diesel engine is minimized. PERRY - UNIT 1 3/4 8-6
T ELECTRICAL POWER SYSTEMS (O SURVEILLANCE REQUIREMENTS (Continued) state voltage and frequency of the emergency bus shall be maintained at 4160 1 420 volts and 60 1 1.2 Hz-during this test.
- 5. Verifying that on an ECCS actuation test signal, without loss {
of offsite power, the diesel generator starts
- on the auto-start l signal and operates on standby for greater than or equal to 5 minutes. The generator voltage and frequency shall be 4160.
420 volts an'd 60 1.2 Hz within 10 seconds after the auto-start signal for Div 1 and Div 2 and within 13 sec~onds after the auto-start, signal for Div 3; the steady state generator voltage and frequency 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) For divisions 1 and 2:
- 1) Verifying 'de-energization of the emergency busses and load shedding from the emergency busses.
- 2) Verifying the diesel generator ' starts' on the auto-start Q
signal, energizes the emergency busses with permanently ~ connected loads within 10 seconds, energizes the auto ~ connected emergency loads and opera'.es for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 420 volts and 60 1.2 Hz during this test. b) For division 3: 1
- 1) Verifying de-energization of the emergency bus.
- 2) Verifying the diesel generator starts
- on the auto-start signal, energizes the emergency bus with its loads and the auto-connected emergency loads within 13 seconds and operates for greater than or equal to 5 minutes while its generator is loaded with the.emer-gency loads. After energization, the steady state
*All diesel generator starts for the purpose of this Surveillance Requirement may be preceded by an engine pre 1ube period. The diesel generator start (10 sec)/ load (60 sec) from ambient conditions shall be performed at least once per 184 days in these surveillance tests. All other engine starts for p4 g
the purpose of this surveillance testing may be preceded by other warmup pro-cedures recommended by the manufacturer so that the mechanical stress and wear on the diesel engine is minimized. i PERRY - UNIT 1 3/4 8-7
ELECTRICAL POWER SYSTEMS SURVEILLANCE REOUIREMENTS (Continued) 9, voltage and frequency of the emergency bus shall be maintained at 4160 2 420 volts and 60 1.2 Hz during this test.
- 7. Verifying that all automatic diesel generator trips are auto-matically bypassed with an ECCS actuation signal except:
a) For divisions 1 and 2, engine overspeed and generator differential current. b) For division 3, engine overspeed and generator differential current.
- 8. Verifying the diesel generator operates for at least 24 hours.
During this test, the diesel generator shall be loaded to between 6800-7000 kw for the first two hours and between 5600-5800 kw** for the remaining 22 hours for diesel generator Div 1 and Div 2. The Div 3 diesel generator shall be loaded to greater than or equal to 2860 kw for the first two hours of this test and 2600 kw for the remaining 22 hours of this test. The generator voitage and frequency shall be 4160 420 volts and 60 2 1.2 Hz within 10 seconds after the start signal for Div 1 and Div 2 and within 13 seconds af ter the start signal for Div 3; the steady state generator voltage and frequency shall be maintained within these limits during this test. Within 5 minutes af ter completing this 24-hour test, perform Surveillance Requirement 4.8.1.1.2.e 4.a.2 and b. 2* or perform Surveil lance Requi rement 4. 8.1.1. 2. e. 6. a.2 and b 2.*
- 9. Verifying that the auto-connected loads to each diesel generator do not exceed 7000 kw for diesel generator Div 1 and Div 2 and 2860 kw for diesel generator Div 3.
- 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, and c) Be restored to its standby status.
- 11. Verifying that with the diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal over-rides the test mode by (1) returning the diesel generator to
*If Surveillance Requirements 4.8.1.1.2.e.4.a.2 and b.2 or 4.8.1.1.2.e.6.a.2 and b.2 are not satisfactorily completed, it is not necessary to repeat the preceding 24 hour test. Instead, the diesel generator Div 1 or Div 2 may be operated at 5600-5800 kw or diesel generator Div 3 may be operated at 2600 kw for one hour or until operating temperatures have stabilized.
^^This band is meant as guidance to avoid routine overloading of the engine. Loads in excess of this band shall not invalidate the test; the loads, however, shall not be less than 5600 kw nor greater than 7000 kw. PERRY - UNIT 1 3/4 8-8
p ELECTRICAL POWER SYSTEMS 't I SURVEILLANCE REQUIREMENTS (Continued) to standby operation, and (2) automatically energizes the emer-gency loads with offsite power.
- 12. Verifying that each fuel transfer pump transfers fuel from the fuel storage tank to the day tank of each diesel.
- 13. Verifying that the automatic load sequence timers are OPERABLE with the interval between each load block within t 10% of its design interval for diesel generators Div 1 and Div 2.
- 14. Verifying that the following diesel generator lockout features prevent diesel generator starting only when required: ,
- a. For diesel generators Div 1 and Div 2:
- 1) Control room switch in pull-to-lock (with local / remote switch in remote).
- 2) Local / remote switch in local
- 3) Barring device engaged
- 4) Inop/ Normal switch in inop fN b. For diesel generator Div 3:
( ) L' 1) Emergency run/s*.op switch in stop
- 2) Maintenance / auto / test switch in maintenance
- f. At least once per 10 years or af ter any modifications which could af-fect diesel generator interdependence by starting all three diesel generators simultaneously, during shutdown, and verifying that all three diesel generators accelerate to at least 441 rpm for diesel generators Div 1 and Div 2 and 882 rpm for diesel generator Div 3 in less than or equal to 10 seconds.
- g. 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 or equivalent solution, and
- 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 11 Article IWD-5000.
4.8.1.1.3 Reports - All diesel generator failures, valid or non valid, shall be reported to the Commission pursuant to Specification 6.9.2 within 30 days. 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. O If the number of failures in the last 100 valid tests, on a per nuclear uait ( ')
'~
basis, is greater than or equal to 7, the report shall be supplemented to in-clude the additional information recommended in Regulatory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977. PERRY - UNIT 1 3/4 8-9 _ m ,
TABLE 4.8.1.1.2-1 DIESEL GENERATOR TEST SCHEDULE Number of Failures Number of Failures in in Last 100 Valid Last 20 Valid Tests
- Tests
- Test Frequency 11 14 One per 31 days
> 2** >5
_ Cnce per 7 days O
" Criteria for determining number of f ailures 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 f requency, 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 manu-facturer g 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 tne routine Surveil lance Requi rement 4. 8.1.1. a. 4 and 4. 8.1.1. 2. a. 5, f our tes ts , in accor-dance with the 184-day testing requirement of Surveillance Requirements 4.8.1.1.2.a.4 and 4.8.1.1.a.5. If this criterion is not satistied during the first series of tests, any alternate criterion to be used to transvalue the failure count to zero requires NRC approval.
- The associated test frequency shall be maintained until seven consecutive f ailure f ree demands have been performed and the number of failures in the last 20 valid demands has been reduced to l ss than or equal to one.
PERRY - UNIT 1 3/4 8-10
4 i l l f-~s ELECTRICAL POWER SYSTEMS ( )
\s s' 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 lE distribution system, and l
- b. Diesel' generator Div 1 or Div 2, and diesel generator Div 3 when the HPCS system is required to be OPERABLE, with each diesel generator having:
- 1. A day tank containing a minimum of 225 gallons of fuel for Div 1 and Div 2 and 204 gallons of fuel for Div 3.
- 2. A fuel storage system containing a minimum of 69,430 gallons of fuel for Div 1 and Div 2 and 34,824 gallons of fuel for Div 3.
, 3. A fuel transfer pump.
APPLICABILITY: -OPERATIONAL CONDITIONS 4, 5 and *. ACTION: r
/ \
- a. With less than the offsite circuits and/or diesel generators Div 1 or Div 2 of the above required A.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handli.ng of irradiated fuel in the primary containment and Fuel Handling Building, operations with a potential for draining the reactor vessel and crane operations ove- the spent fuel storage pool when fuel assemblies are therein. In addition, when in OPERATIONAL CONDITION 5 with the water level less than 22 feet 10 inches above the reactor pressure vessel flange, immediately initiate corrective action to restore the required power sources to OPERABLE status as soon as practical.
- b. With diesel generat'or Div 3 of the above required A.C. electrical power sources inoperable, restore the inoperable diesel generator Div 3 to 0PERABLE status within 72 hours or declare the HPCS system inoper-able and take the ACTION required by Specification 3.5.2 and 3.5.3.
- c. The provisions of Specification 3.0.3 are not applicable.
i SURVEILLANCE REQUIREMENTS } 4.8.1.2 AL Teast the above required A.C. electrical power sources shall be demonstrated LPERABLE per Surveillance Requirements 4.8.1.1.1, 4.8.1.1.2 (except for the requirement of 4.8.1.1.2.a.5), and 4.8.1.1.3. f containment. PERRY - UNIT 1 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. Division 1, consisting of:
- 1. 125 volt battery 1R42-5002.
- 2. 125 volt full capacity charger 1R42-5006 or 1R42-5007.
- b. Division 2, consisting of:
- 1. 125 volt battery 1R42-5003.
- 2. 125 volt full capacity charger 1R42-5008 or 1R42-5009.
- c. Division 3, consisting of:
- 1. 125 volt battery 1E22-5005.
- 2. 125 volt full capacity charger lE22-5006 or 1R42-50ll.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With either Division 1 battery and/or both chargers or Division 2 battery and/or both chargers of the above required D.C. electrical power sources inoperable, restore the inoperable division battery 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 Division 3 battery and/or both chargers of the above required D.C. electrical power sources inoperable, declare the HPCS system in-operable and take the ACTION required by Specification 3.5.1.
SURVEILLANCE REQUIREMENTS 4.8.2.1 Each of the above required 125 volt batteries and chargers shall be demonstrated 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 is greater than or equal to 129 volts on float charge.
O PERRY - UNIT 1 3/4 8-12 _
7] ELECTRICAL POWER SYSTEMS b SURVEILLANCE REQUIREMENTS (Continued)
- b. At least once per 92 days and within 7 days after a battery discharge-with battery terminal voltage below 110 volts, or battery overcharge with battery terminal voltage above 145 volt's, by verifying that:
~1. The parameters in Table 4.8.2.1-1 meet the Category B limits,
- 2. There is no. visible corrosion -t either terminals or connectors, or the connection resistance of each cell-to-cell and terminal connection is less than or equal to 50 x 10 6 ohms for Div 1 and Div 2 batteries-and 100 x 10 6 ohms for the Div 3 battery.
- 3. The average electrolyte temperature of 10 connected cells is above 72 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 50 x 10 6. ohms for Div 1 and-Div 2 batteries and 100 x 10 6 ohms for the Di_v 3 battery.
- 4. The battery chargers 1R42-5006, -5007, -5008, and -5009 will each supply _at least'400 amperes at a minimum of 125 volts for at least 8 hours, and
- 5. The battery chargers 1E22-5006 and 1R42-5011 will each supply at least 50 amperes at a minimum of 125 volts for at least 8 hours.
- 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 tihe 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 profile while maintaining the battery terminal voltage greater than or equal to 105 volts.
~
PERRY - UNIT 1 3/4 8-13 - 3
ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) a) Division 1 2 604 amps for the first 60 seconds 1 127 amps for the next 9 minutes 1 380 amps for the next 1 minute 1127 amps for the next 108 minutes 1 326 amps for the .last 60 seconds b) Division 2 3 569 amps for the first 60 seconds 1 119 amps for the next 9 minutes 1 372 amps for the next 1 minute 2 119 amps for the next 108 minutes 3 316 amps for the last 60 seconds c) Division 3 1 95 amps for the first 60 seconds
> 16 amps for the last 119 minutes
- 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 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 indicated 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.
O PERRY - UNIT 1 3/4 8-14
$ TABLE 4.8.2.1-1 BATTERY SURVEILLANCE REQUIREMENTS s CATEGORY A(I) CATEGORY B(2) Parameter Limits for each Limits for each A110wable(3) designated pilot connected cell value for each' 7 cell connected cell
- I
'~
Electrolyte > Minimum level > Minimum level Above top of Level indication mark, indication' mark, plates, i and < b" above and < %" above and not maxiiium level maxiiiium level overflowing } indication mark indication mark Float Voltage 3 2.13 volts 1 2.13 volts (c) > 2.07 volts Specifig) > 1.200 ,, 2 1.195(b)* Not more than Gravity 3 1.195 2 1.190(b)** .020 below the
/ average of all '
l( connected cells Average of all Average of all connected cells connected cells 1 1.205(b)* 3 1.195 ,, 1 1.200(b)** > 1.190 (a) . Corrected for electrolyte temperature and level. ' (b) Or battery charging current is less than 2 amperes when on float charge. (c) May be corrected for average electrolyte temperature. (1) For any Category A parameter (s) outside the limit (s) shown, the battery i may be considered OPERABLE provided that within 24 hours all the Category 8 measurements are taken and found to be within their allowable values, and provided all Category A and 8 parameter (s) are restored to within limits within the next 6 days. (2) For any Category 8 parameter (s) outside the limit (s) shown, the battery 1 may be considered OPERABLE provided that the Category 8 parameters are within their allowable values and provided the Category 8 parameter (s) are restored to within limits within 7 days. (3) Any Category 8 parameter.not within its allowable value indicates an
- inoperable battery.
l i
- Division 1 and Division 2 battery.
,( ** Division 3 battery. PERRY - UNIT.1 3/4 8-15 i I
- , - . - . _ _ , . _ ~ - . _ . _ - _ . , _ _ _ . _ , _ , , _ _ _ _ , _ _ __ _ _ _ _ _ . _ , . . _
.__.__.-.__..._,I
ELECTRICAL POWER SYSTEMS 0.C. SOURCES - SHUTDOWN L'IMifING CONDITION FOR OPERATION 3.8.2.2 As a minimum, Division 1 or Division 2, and, whe'1 the HPCS system is required to be OPERABLE, Division 3, of the O.C. electrical power sources shall be OPERABLE with:
- a. Division 1 consisting of:
- 1. 125 volt battery 1R42-5002.
- 2. 125 volt full capacity charger 1R42-5006 or 1R42-5007.
- b. Division 2 consisting of:
- 1. 125 volt battery 1R42-5003.
- 2. 125 volt full capacity charger 1R42-5008 or 1R42-S009.
- c. Division 3 consisting of:
- 1. 125 volt battery 1E22-5005.
- 2. 125 volt full capacity charger 1E22-5006 or 1R42-5011.
APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. ACTION:
- a. With both Division 1 battery and/or both chargers and Division 2 battery and/or both chargers of the above required D.C. electrical power sources inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary containment and operations with a potential for draining the reactor vessel.
- b. With Division 3 battery and/or both chargers of the above required D.C. electrical power sources inoperable, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
- c. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.8.2.2 Each of the above required battery and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1.
"When handling irradiated fuel in the Fuel Handling Building or primary containment.
O PERRY - UNIT 1 3/4 8-16
n ELECTRICAL POWER SYSTEMS I I V 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.3.1 The following power distribution system divisions shall be energized:
- a. A.C. power distribution:
- 1. Division 1, consisting of:
a) 4160 volt A.C. bus EH11. b) 480 volt A.C. busses EF-1-A and EF-1-B. c) 480 volt A.C. MCCs EF-1-A-07, EF-1-A-08, cF-1-A-09, EF-1-A-12, EF-1-B-07, EF-1-B-08, EF-1-B-09, and EF-1-B-10/EF-1-0-10.** d) 120 volt A.C. distribution panels EB-1-Al and EK-1-Al in 480 volt MCCs EF-1-B-07 and EF-1-A-07. e) 120 volt A.C. bus EV-1-A energized f rom inverter 1R14-5012 connected to 0.C. bus E0-1-A-06. *
- 2. Division 2, consisting of:
a) 4160 volt A.C. bus EH12.
} b) 480 volt A.C. busses EF-1-C and EF-1-0.
(/ c) 480 volt A.C. MCCs EF-1-C-07, EF-1-C-08 EF-1-C-09, EF-1-C-12, EF-1-0-07, EF-1-0-08, and EF-1-0-09. d) 120 volt A.C. distribution panels EB-1-B1 and EK-1-B1 in 480 volt MCCs EF-1-0-07 and EF-1-C-07. e) 120 volt A.C. bus EV-1-B energized from inverter 1R14-5013 connected to 0.C. bus E0-1-B-08.*
- 3. Division 3, consisting of:
a) 4160 volt A.C. bus EH13. b) 480 volt A.C. MCCs EF-1-E-1 and EF-1-E-2. c) 120 volt A.C. distribution panel EK-1-C1 in 480 volt MCCs EF-1-E-1.
- b. 0.C. power distribution:
- 1. Division 1, consisting of 125 volt 0.C. distribution panels E0-1-A-06 and MCC E0-1-A-09.
*0ne inverter may be disconnected from its 0.C. source for up to 24 hours for the purpose of performing an equalizing charge on the associated battery bank provided (1) its AC bus remains uPERABLE and energized, and the AC bus associated with the other battery bank is OPERABLE and energized.
p) t
\J
**480 volt MCC EF-1-B-10/EF-1-0-10 is normally energized from Division 1.
Division 2 provides an alternate power source. PERRY - UNIT 1 3/4 8-17
ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
- 2. Division 2, consisting of 125 volt D.C. distribution panels ED-1-B-06 and ED-1-B-08, and MCC ED-1-B-09.
- 3. Division 3, consisting of 125 volt D.C. distribution panel 1R42-5037.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. For A.C. power distribution:
- 1. With either Division 1 or Division 2 of the above required A.C.
distribution system not energized, re-energize the division within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 2. With Division 3 of the above required A.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.1.
- b. For D.C. power distribution: O
- 1. With either Division 1 or Division 2 of the above required D.C.
distribution system 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.
- 2. With Division 3 of the above required D.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.1.
SURVEILLANCE REQUIREMENTS 4.8.3.1 Each of the above required power distribution system divisions shall be determined energized at least once per 7 days by verifying voltage and correct breaker alignment on the busses /MCCs/ panels. O PERRY - UNIT 1 3/4 8-18
1 i 4 ELECTRICAL POWER SYSTEMS O DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.3.2 As a minimum, the following power distribution system divisions shall
~
be energized: i
- a. For A.C. power distribution, Division 1 or Division 2, and when the HPCS system is required to be OPERABLE, Division 3, with:
- 1. Division 1 consisting of:
a) 4160 volt A.C. bus EH11. b) 480 volt A.C. busses EF-1-A and EF-1-B. c) 480 volt A.C. MCCs EF-1-A-07, EF-1-A-08, EF-1-A-09, EF-1-A-12, EF-1-8-07, EF-1-B-08, EF-1-B-09, and EF-1-B-10/EF-1-0-10.* d) 120 volt A.C. distribution panels EB-1-Al and EK-1-Al in 480 volt MCCs EF-1-B-07 and EF-1-A-07. e) 120. volt A.C. bus EV-1-A energized from inverter 1R14-5012 connected to D.C. bus ED-1-A-06, or energized from A.C. bus EF-1-B-07.
- 2. Division 2 consisting of:
O a) b) c) 4160 volt A.C. bus EH12. 480 volt A.C. busses EF-1-C and EF-1-0. 480 volt A.C. MCCs EF-1-C-07, EF-1-C-08, EF-1-C-09, EF-1-C-12, EF-1-0-07, EF-1-0-08, and EF-1-0-09. d) 120 volt A.C. distribution panels EB-1-B1 and EK-1-B1 in 480 volt MCCs EF-1-0-07 and EF-1-C-07. e) 120 volt A.C. bus EV-l'-B energized from inverter 1R14-5013 connected to D.C. bus ED-1-B-08 or. energized from A.C. bus EF-1-0-09.
- 3. Division 3 consisting of:
a) 4160 volt A.C. bus EH13. b) 480 volt A.C. MCCs EF-1-E-1 and EF-1-E-2. c) 120 volt A.C. distribution panel EK-1-C1 in 480 volt MCC EF-1-E-1.
- b. For 0.C. power distribution, Division 1 or Division 2, and when the HPCS system is required to be OPERABLE, Division 3, with:
- 1. Division 1 consisting of 125 volt D.C. distribution panels ED-1-A-06 and MCC ED-1-A-09.
- 2. Division 2 consisting of 125 volt D.C. distribution panels ED-1-B-06 and ED-1-B-08, and MCC E0-1-B-09.
*480 voit MCC EF-1-B-10/EF-1-D-10 is normally energized from Division 1.
Division 2 provides an alternate power source. PERRY - UNIT 1 3/4 8-19 _
ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
- 3. Division 3 consisting of 125 volt D.C. distribution panel 1R42-5037.
APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and
- ACTION:
- a. For A.C. power distribution:
- 1. With less than Division 1 and/or Division 2 of the above required A.C. distribuf. ion system energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the Fuel Handling Building and primary containment and operations with a potential for draining the reactor vessel.
- 2. With Division 3 of the above required A.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
- b. For D.C. power distribution:
- 1. With less than Division 1 and/or Division 2 of the above required D.C. distribution system energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the fuel Handling Building and primary containment and operations with a potential for draining the reactor vessel.
- 2. With Division 3 of the above required 0.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
- 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 divisions shall be determined energized at least once per 7 days by verifying voltage and correct breaker alignment on the busses /MCCs/ panels.
- When handling irradiated fuel in the Fuel Handling Building or primary containment.
PERRY - UNIT 1 3/4 8-20
- ELECTRICAL POWER SYSTEMS /ss CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.1 All 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 containment penetration conductor overcurrent 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 13.8 kV circuit breakers, de-energize the 13.8 kV circuit (s) by tripping the associated redundant circuit breaker (s) within 72 hours and verify the redundant circuit breaker to be tripped at least once per 7 days thereafter.
- 2. For 120- and 125-volt circuit breakers, remove the inoperable circuit breaker (s) from service by racking out the breaker within 72 hours I
V o) and verify the inoperable breaker (s) to be racked out 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 13.8 kV circuits which have their redundant circuit breakers tr pped or to 120- and 125-volt circuits which have the inoperable circuit breaker racked out.
SURVEILLANCE REQUIREMENTS 4.8.4.1 Each of the 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 the medium voltage 13.8 kV circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10*. of the circuit breakers and performing:
a) A CHANNEL CALIBRATION of the associated protective relays, 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 con-trol circuits function as designed, and PERRY - UNIT 1 3/4 8-21
ELECTRICAL POWER SYSTEMS LURVEILLANCE REOUIREMENTS (Continued) c) 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.
- 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 injecti'ng a current in excess of the breakers' nominal setpoint including the instantaneous element setpoint and measuring the response time. The measured response time shall be compared to the manufacturer's data to ensure that it is less than or equal to a value specified by the manufacturer. 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 instructions prepared in conjunction with its manufacturer's recommendations.
O PERRY - UNIT 1 3/4 6-22
TABLE 3.8.4.1-1 [ \s CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 13.8 KV LOAD OVERCURRENT PROTECTION Primary Secondary 1833-C001A L1106 1833-C0018 1R22-5012 L1205 1R22-5013 120V LOAD OR CIRCUIT 1821-B1X (Sp. Htr.) 1R25-5097-CB1 1821-B3X.(Sp. Htr.) NA* 1R25-5097-C82 NA* IB21-85X (Sp. Htr.) 1R25-5093-CB1 1821-8760X8 NA* 1R25-5043-CB20 NA* IB21-8756XB 1R25-5043-CB18 NA* 1821-8758XB 1R25-SO43-CB19 NA* IB21-8754XB 1R25-5043-CB17 NA* 1821-8752X8 1R25-5047-CB11 NA* IB33-82X (Sp. Htr.) 1R25-5093-CB7 1833-84X (Sp. Htr.) NA* 1R25-5093-CB8 NA* 1833-B6X (Sp. Htr.) 1R25-5097-CBS IB33-B8X (Sp. Htr.) NA* 1R25-5097-CB6 NA* \- 1833-810X (Sp. Htr.) 1R25-5093-CB9 1833-B12X (Sp. Htr.) NA* 1R25-5093-CB10 NA* 1833-814X (Sp. Htr.) 1R25-5097-CB7 IB33-B16X (Sp. Htr.) NA* 1R25-5097-C88 NA* 1833-B17X (Sp..Htr.) 1R25-5093-CB11 1833-B19X (Sp. Htr.) NA* 1R25-5097-CB9 NA* IB33-B21X (Sp. Htr.) 1R25-5093-C84 1833-823X (Sp. Htr.) NA* 1R25-5097-CB10 NA* 1Cll-8250X (Sp. Htr.) 1R25-SO93-C85 1C11-C1X NA* NA* 1H13-P653-CB1 1C41-B9XB (Sp. Htr) 1R25-SO43-C821 NA* 1E51-83XB 1R25-5043-CB24 NA* lE51-B1XB 1R25-5043-C823 NA* 1F42-B5X (Sp. Htr.) 1R25-5097-CB3 NA* 1G33-B1X (Sp. Htr.) 1R25-5095-C81 NA* 1G33-B3X (Sp. Htr.) 1R25-5081-C82 NA* 1G33-B5X (Sp. Htr.) 1R25-5079-C81 NA* 1G33-B7X (Sp. Htr.) 1R25-5079-CB,2 NA* 1G33-B9X (Sp. Htr.-) 1R25-5081-CB1 NA*
- Protected by fuse.
PERRY - UNIT 1 3/4 8-23
i TABLE 3.8.4.1-1 (Continued) + 120V LOAD OR CIRCUIT OVERCURRENT PROTECTION , Primary Secondary i 1G33-811X (Sp. Htr.) 1R25-5079-C83 NA* 1G33-813X (Sp. Htr.) 1R25-5079-C84 NA* 1G33-815X (Sp. Htr.) 1R25-S079-C85 NA* 1G33-817X (Sp. Htr.) 1R25-5079-CB6 NA* ! 1G41-81X 1R25-5077-C81 NA* 1R25-8516X OR25-5054-C87 NA* 1R25-8517X OR25-S054-CB13 NA* l . 1R25-8245X 1R25-5057-CB12 NA* 1P56-81060X 1R25-5053-CB34 NA* 1P57-83X8 1R25-5043-C815 NA* 1R25-8522X 1R25-5153-C813 NA* l 1R25-8515X 1R25-5053-C825 NA* 1M16-87X8 1R25-5047-C81 NA* IM16-89XB 1R25-5047-CB3 NA* 1M16-817XB 1R25-5047-C85 NA* IM16-819XB 1R25-5047-C86 NA* l 1E12-83XB 1R25-5047-CB7 NA* IE12-87X8 1R25-5047-C88 NA* 1E12-811XB 1R25-5047-C89 NA*
! 1E12-815XB 1R25-5047-CB10 NA*
i { i i l
- Protected by fuse.
PERR( - UNIT 1 3/4 8-24
ELECTRICAL POWER SYSTEMS \ REAC10R PROTECTION SYSTEM ELECTRIC POWER MONITORING LIMITING CONDITION FOR OPERATION 3.8.4.2 Two RPS electric power monitoring assemblies 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 assembly for an inservice RPS MG set or alternate power supply inoperable, restore the inoperable power monitoring assembly 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 assemblies for an inservice RPS MG set or alternatt power supply inoperable, restore at least one electric power monitoririg assembly to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service.
SURVEILLANCE REQUIREMENTS \ 4.8.4.2 The above specified RPS electric power monitoring assemblies shall be determined OPERABLE:
- a. By performance of a CHANNEL FUNCTIONAL TEST each time the unit is in COLD SHUTDOWN for a period of more then 24 hours, unless performed within the previous 6 months, and
- b. At least once per 18 months by demonstrating the OPERABILITY of over-voltage, under-voltage and under-frequency protective instru-mentation 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 < 132 VAC,
- 2. Under-voltage 1 108 VAC, and
- 3. Under-frequency 157 Hz.
v PERRY - UNIT 1 3/4 8-25 i l
.- 1
r3 3/4.9 REFUELING OPERATIONS I ' v') 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. One rod out.
- 2. Refuel platform position.
- 3. Refuel platform main hoist fuel-loaded.
APPLICABILITY: OPERATIONAL CONDITION 5* # . ACTION:
} a. With the reactor mode switch not locked in the Shutdown or Refuel s
L'j position as specified, suspend CORE ALTERATIONS and lack 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 pcsition 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 reactnr vessel with the vessel head closure bolts less than fully tensioned or with the head removed, m o PERRY - UNIT 1 3/4 9-1
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.
4.9.1.2 Each of the above required reactor mode switch Refuel position interlocks
- shall be demonstrated OPERABLE 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 PERRY - UNIT 1 3/4 9-2
l REFUELING OPERATIONS i V 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. 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 Specifi-cation 3.1.1 and the "one rod-out" Refuel position interlock has been demonstrated OPERABLE per Specification 3.9.1, the shorting links shall be removed from the RPS ci the time any control rod is withdrawn.gcuitry prior to and during APPLICABILITY: OPERATIONAL CONDITION 5. ACTION: With the requirements of the above specification not satisfied, immediately ( j suspend all operations involving CORE ALTERATIONS and insert all insertable V control rods. SURVEILLANCE RE0VIREMENTS 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 are connected to the normal SRM circuits.
#N ot required for control rods removed per Specification 3.9.10.1 and 3.9.10.2.
O PERRY - UNIT 1 3/4 9-3 y - , _ . . _ . . _ . - - _ _ _ - - r r- -.
REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS (Continued)
- b. Performance of a CHANNEL FUNCTIONAL TEST:
I 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, except that:
- 1. During fuel unloading, the required count rate may be permitted to be less than 0.7 cps *
- 2. Prior to and during fuel loading, until sufficient fuel has been loadod to maintain at least 0.7 cps *, the required count rate may be achieved by:
a) Use of portable external source, or b) loading up to 2 fuel assemblies ### ir cells containing inserted control rods around an SRM.
- d. Verifying within 8 hours prior to and at leap once per 12 hours during the time any control rod is withdrawn that the shorting links have been removed from the RPS circuitry unless adequate shutdown margin has been demonstrated per Specification 3.1.1 and the "one-rod-out" Refuel position interlock has been demonstrated OPERABLE per Specification 3.9.1.
"Provided signal to noise ratio ;2.
#"Not required for control rods removed per Speci fication 1. 9.10.1 or 3.9.10.2.
These fuel assemblies may be loauN with the SRM count-rate of less than 0.7 cps provided the signal-to-noise ratio is g2. PERRY - UNIT 1 3/4 9-4
(N ( REFUELING OPERATIONS
\s_-}
3/4.9.3 CONTROL R00 POSITION LIMITING CONDITION FOR OPERATION 3.9.3 All control rods shall be inserted.* APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS.** ACTION: With all control roos not inserted, suspend all other CORE ALTERATIONS. SURVEILLANCE REQUIREMENTS 4.9.3 All control rods shall be verified to be inserted, except as above specified:
- a. Within 2 hours prior to:
O I ) 1. The start of CORE ALTERATIONS. %J
- 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. One contral rod may be withdrawn under control of the reactor mode switch Refuel position one-rod-out interlock.
**See Special Test Exception 3.10.3.
(s. PERRY - UNIT 1 3/4 9-5
i REFUELING OPERATIONS 3/4.9.4 DECAY TIME LIMITING CONDITION FOR OPERATION 3.9.4 The reactor shall be subtritical for at least 24 hours. APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS. 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 PERRY - UNIT 1 3/4 9-6 -
l
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(T REFUELING ODERATIONS 3/4.9.5 COMMUNICATIONS l i LIMITING CONDITION FOR OPERATION l 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.* 1' l l l i l V) SURVElLLANCE RE0VIREMEN15 l t 4.9.5 Direct communication between the control room and refueling floor personnel shall be demonstrated within one hour prior to the start of and at least once per 12 hours during CORE ALTERATIONS."
*Except movement of incore instrumentation and control rods with their normal drive system.
\
V PERRY - UNIT 1 3/4 9-7 -
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. APPLICABILITY: 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 inoperable 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 REOUIREMENTS 4.9.6 Each refueling platform crane or 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 with that crane or hoist by:
- a. Demonstrating operation of the overload cutoff on the main hoist before the total cable load exceeds 1250 pounds.
- b. Demonstrating operation of both the overload cutoffs on each of the frame mounted and monorail hoists before the total cable load exceeds 550 pounds.
- c. Demonstrating operation of the uptravel stop on the main, frame mounted and monorail hoists when uptravel brings the point of attach-ment of the grapple to the control rod or fuel assembly to 8 feet 3 inches or greater below the refueling floor level.
- d. Demonstrating operation of the downtravel cutof f on the main hoist when the bottom of the grapple hook down travel reaches 4.0 2 0.5 inches below the top of the fuel assembly handle.
- e. Demonstrating operation of the slack cable cutoff on the main hoist.
- f. Demonstrating operation of the grapple loaded interlock on the main hoist bofure the total cable load exceeds 535 pounds.
- g. Demonstrating operation of the primary and redundant interlocks on the main hoist before the total cable load exceeds 600 pounds.
PERRY - UNIT 1 3/4 9-8
l
,, REFUELING OPERATIONS
/ \ ( V) 3/4.9.7 CRANE TRAVEL-SPENT FUEL STORAGE POOL, NEW FUEL STORAGE VAULTS, AND UPPER CONTAINMENT FUEL POOL LIMITING CONDITION FOR OPERATION 3.9.7 Loads which would result in excess of 400 foot pounds of impact enorcy if dropped shall be prchibited from travel over fuel assemblies in the spent fuel storage pool racks, new fuel storage vaults, or upper cuntainment fuel pool racks. APPLICABILITY: With fuel assemblies in the spent fuel storage pool racks, new fuel storage vaults, or upper containment fuel pool racks. ACTION: With the requirements of the above specification not satisfied, place the crane load in a safe condition. The provisions of Specification 3.0.3 are not applicable. ( /
%/
SURVEILLANCE REQUIREMENTS 4.9.7 Loads, other than fuel assemblies or control rods, shall be verified to result in less than or equal to 4000 foot pounds of impact energy if dropped before travel over fuel assemblies in the spent fuel storage pool racks, new fuel storage vaults, or the upper containment fuel pool racks. f () PERRY - UNIT 1 3/4 9-9 -
REFUELING OPERATIONS 3/4.9.8 WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION 3.9.8 At least 22 feet 10 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. O 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. O PERRY - UNIT 1 3/4 9-10
REFUELING OPERATIONS V 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE AND UPPER CONTAINMENT FUEL POOLS LIMITING CONDITION FOR OPERATION
~
3.9.9 At least'23 feet of wa'ert shall be maintained over the top of irradiated fuel. assemblies seated in the Fuel Handling Building spent fuel storage and upper containment fuel pool racks. APPLICABILITY: Whenever irradiated fuel assemblies are in the Fuel Handling Building spent fuel storage or upper containment fuel pools. ACTION: With'the requirements of the above specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the Fuel Handling Building spent fuel storage or upper containment fuel pool areas, as
. applicable after placing the fuel assemblies and crane load in a safe condition.
The provisions of Specification 3.0.3 are 'not applicable. m SURVEILLANCE REOUIREMENTS {- 4.9.9 The water level in the Fuel. Handling Building spent fuel storage and upper containment fuel pools shall be determined to be at least at its minimum required depth at least once per 7 days. LO PERRY - UNIT 1 3/4 9-11 .- i
REFUELING OPERATIONS 3/4.9.10 CO: TROL ROD REMOVAL SINGLE CONTROL R00 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;
- 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 cer,tered 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.
APPLICABILITY: OPERATIONAL CONDITION 4 and 5. ACTION: With the requirements of the above specification not satisfied, suspend removal of the control rod and/or associated control rod drive mechanism f rom the core and/or reactor pressure vessel and initiate action to satisfy the above requirements. O PERRY - UNIT 1 3/4 9-12 -
i l l
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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 associated 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 hydrau-lically disarmed or the four fuel assemblies surrounding the control
. /~ 's rod or control rod drive mechanism to be removed from the core . ( ) and/or reactor vessel are removed from the core cell. x- /
- e. All other control rods are inserted.
f3 PERRY - UNIT 1 3/4 9-13 _
REFUELING OPERATIONS MULTIPLE CONTROL ROD REMOVAL LIMITING CONDITION FOR OPERATION 3.9.10.2 Any number of control rods and/or control rod drive mechanisms may be removed from th'e core and/or reactor pressure vessel provided that at least the following requirements are satisfied until all control rods and control 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 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.
APPLICABILITY: OPERATIONAL CONDITION 5. ACTION: With the requirements of the above :;pecification not satisfied, suspend removal
~
of control rods and/or control rod drive mechanisms frcm the core and/or reactor pressure vessel and initiate action to satisfy the above requirements. O PERRY - UNIT 1 3/4 9-14
REFUELING OPERATIONS ('] U 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 tne core and/or reactor pressure vessel and at least once per 24 hours thereafter until all control roos 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.
- c. The SHUT 00WN 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 assemblies surrounding each control rod and/or control n rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.
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 bypassed. p (v) PERRY - UNIT 1 3/4 9-15
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 at least:
- a. One OPERABLE RHR pump, and
- b. Two OPERABLE RHR heat exchangers.
APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is greater than or equal to 22 feet 10 inches above the top of the reactor pressure vessel flange and heat losses to the ambient
- are not sufficient to maintain OPERATIONAL CONDITION 5.
ACTION: With no RHR shutdown cooling mode loop OPERABLE, within one hour and at least once per 24 hours thereafter, demonstrate the operability of at least one alter-nate method capable of decay heat removal. Otherwise, suspend all operations involving an increase in the reactor decay heat load and establish PRIMARY CONTAINMENT INTEGRITY within 4 hours. SURVEILLANCE REQUIREMENTS 4.9.11.1 At least once per 12 hours verify at least one RHR shutdown cooling mode loop is capable of taking suction from the reactor vessel and discharging back to the reactor vessel through an RHR heat exchanger with available cooling water.
- Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though COLD SHUTDOWN conditions are being maintained).
O PERRY - UNIT 1 3/4 9-16
[ . REF'UELING OPERATIONS LOW WATER LEVEL. LIMITING CONDITION FOR OPERATION J 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 l each loop consisting of at least: l
- a. One OPERABLE RHR pump, and 4
- b. Two OPERABLE RHR heat exchangers.
APPt?(ABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the. reactor vessel ~oim ' he water level is less tnan 22 feet 10 inches above the top of the reactor presst.-a vessel flange. ! ACTION:
- a. With less than the above required shutdown cooling mode loops of the RHR 4- system OPERABLE, within one hour and at least once per 24 hours-thereafter,
/"'$g demonstrate the operability of at least one alternate method capable of
( j 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.
i
- SURVEILLANCE REQUIREMENTS l
i 1 ! 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.
I 1 1 1 1 I *The shutdown cooling pump'may be removed from operation for up to 2 hours per 8-hour period. i PERRY - UNIT.1 3/4 9-17 - ~ Ww- -,m - - , - . ,y 4,,,m ., .y, .,_m,-..m.,,r ,,y 3.,. -.9 , _ _ , , ,, . . , . ,,r.,,_ _ - . . _.y_-__y-,, . , ,._.-m-c- ,- ,.,r., , ,.- - 4,-,-
REFUELING OPERATIONS 3/4.9.12 INCLINED FUEL TRANSFER SYSTEM LIMITING CONDITION FOR OPERATION 3.9.12 The inclined fuel transfer system (IFTS) may be in operation provided -that:
- a. The access door and floor plugs of all rooms through which the transfer system penetrates are closed and locked.
- b. All access interlocks and palm switches are OPERABLE.
- c. The Versa blocking valve located in the Fuel Handling Building IFTS hydraulic power unit is OPERABLE.
- d. At least one IFTS carriage position indicator is OPERABLE at each of the twelve proximity sensors and at least one liquid level sensor is OPERABLE.
- e. All keylock switches which provide IFTS access control-transfer system lockout are OPERABLE.
- f. The warning-light outside of the access door is OPERABLE.
APPLICABILITY: When the IFTS blank flange is removed. ACTION:
- a. With one or more access interlocks, warning lights, and/or palm switches inoperable, operation of the IFTS may continue provided that entry into the area is prohibited by establishing a continuous watch and conspicuously posting as a high rac Jtion area.
- b. With the requirements of the above specification not satisfied, suspend IFTS operation with the IFTS at either terminal point. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REOUIREMENTS 4.9.12.1 Within 4 hours prior to the startup of the IFTS, verify that no personnel are in areas immediately adjacent to the IFTS tube and that the access door and floor plugs to rooms through which the IFTS tube penetrates are closed and locked. O PERRY - UNIT 1 3/4 9-18
- .- -. - - . - . = -- . -... . . - . _
i i
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. I
,- s REFUELING OPERATIONS
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l , SURVEILLANCE REQUIREMENTS (Continued) d 4.9.12.2 Within 4 hours prior to the operation of IFTS and at least once per 12 hours thereaf ter, when the IFTS in in operation verify that:
- a. At least one IFTS carriage position indicator is OPERABLE at each of the twelve proximity sensors and at least one liquid level sensor is OPERABLE.
i
, b. The warning light outside of the access door is'0PERABLE.
4.9.12.3 Within 4 hours prior to the operation of IFTS and~at least once per 7 days thereafter, when the IFTS is in operation verify that: a. All access interlocks for the IFTS Valve Room are OPERABLE.
- b. !
The Versa blocking valve in the Fuel Handling Building IFTS hydraulic power unit is OPERABLE. c. All keylock switches'which provide IFTS access control-transfer system i lockout are OPERABLE.
, -ss 4.9.12.4 Within 4 hours prior to installation of the floor plugs, after they ' (N have been removed, verify that the access interlocks and palm switches. for the shield building -annulus room and/or mid-support room, as applicable, are OPERABLE.
i ss _ -) j i PERRY - UNIT 1 3/4 9-19
1 l 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY /DRYWELL INTEGRITY LIMITING CONDITION FOR OPERATION 3.10.1 The provisions of Specifications 3.6.1.1.1,-3.6.1.2, 3.6.1.3, 3.6.2.1, 3.6.2.3, 3.6.5.1, 3.6.5.2 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 drywell air lock door 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, _( j 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. 4 PERRY - UNIT 1 3/4 10-1 i
SPECIAL TEST EXCEPTIONS 3/4.10.2 RCD PATTERN CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1'O. 2 The sequence constraints imposed on control rod groups by the rod pattern control system (RPCS) per Specification 3.1.4.2 may be suspended by means of the individual rod position bypass switches for the follcwing tests:
- a. Shutdown margin demonstrations, Specification 4.1.1.
- b. Control rod scram insertion times, Specification 4.1.3.2.
- c. Control rod friction measurements.
- d. Startup Test Program with the THERMAL POWER less than the RPCS low power setpoint.
APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With the reouirements of the above specification not satisfied, verify that the RPCS is OPERABLE per Specification 3.1.4.2. SURVEILLANCE REQUIREMENTS 4.10.2 When the sequence constraints imposed on control rod groups by the RPCS are bypassed, verify:
- a. Within 8 hours prior to bypassing any sequence constraint and at least once per 12 hours while any sequence constraint is bypassed, that movement of the control rods between 75% ROD DENSITY to the RPCS low power setpoint is limited to the established control rod sequence for the specified test, and
- b. Conformance with this specification and test procedures by a second licensed operator or other technically qualified member of the unit technical staff.
O PERRY - UNIT 1 3/4 10-2
x SPECIAL TEST EXCEPTIONS , } V' 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS LIMITING CONDITION FOR OPERATION 3.10.3 The provisiens of Specification 3.9.1, Specification 3.9.3 and Table l 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 y satisfied. l l
- a. The source range monitors are OPERABLE per Specification 3.9.2 with the RPS circuitry " shorting links" removed.
- b. 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 " continuous withdrawal" 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 S, 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 REOUIREMENTS 4.10.3 Within 30 minutes prior to and at least once per 12 hours during the purformance of a shutdown margin demonstration, verify that;
- a. The source range donitors are OPERABLE per Specification 3.9.2, with the RPS circuitry " shorting links" removed.
- b. A second licensed operator or other technically qualified member of the unit technical staff is present and verifies compliance with the shutdown demonstration procedures, and
- c. No other CORE ALTERATIONS are in progress.
p ( / ( PERRY - UNIT 1 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 flow 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 requirements have 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 PERRY - UNIT 1 3/4 10-4
[ \ /
') SPECIAL TEST EXCEPTIONS 3/4.10.5 TRAINING STARTUPS LIMITING CONDITION FOR OPERATION 3.10.5 The provisions of Specification 3.5.1 may be suspended to permit one RHR subsystem to b'e 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 RE0UIREMENTS (~ k j 4.10.5 The reactor s assel 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 L j' PERRY - UNIT 1 3/4 10-5
/ ) 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 concentrations specified in 10 CFR Part 20, Appendix B, Table II, Column 2 for radionuclides 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 1iquid effluents to UNRESTRICTED AREAS exceeding the above limits, immediately restore the concentration to within the-above limits.
,x fV) SURVEILLANCE REQUIREMENTS 4.11.1.1.1 The radioactivity content of each batch of radioactive liquid waste shall be determined prior to release by sampling and analysis in accord-ance with Table 4.11.1.1.1-1. The results of pre-release analyses shall be used with the calculational methods in the 00CM to assure that the concentration at the point of release is maintained within the limits of Specification 3.11.1.1.
4.11.1.1.2 Post-release analyses of samples composited from batch releases shall be performed in accordance with Table 4.11.1.1.1-1. The results of the radioactivity analysis shall be used in accordance with the methodology and parameters in the ODCM to assure that the concentrations at the point of release are maintained within the limits of Specification 3.11.1.1.
/m\
() PERRY - UNIT l' 3/4 11-1
TABLE 4.11.1.-l.1-1 RADIOACTIVE LIQUID WASTE SAMPLING AND ANALYSIS PROGRAM Minimum Type of Lower Limit Liquid Release Sampling Analysis' Activity of Detection Type Frequency Frequency Analysis (LLD) (pCi/ml)a
~7 A. Batch Waste P P PrincipajGamma 5x10 Releage Each batch Each Batch Emitters Tanks I-131 -6 1x10 P M Dissolved and 1x10
-5 One Batch /M Entrained Gases (Gamma emitters)
P M H-3 1x10
-5 Each Batch Composite Gross Alpha 1x10' P Q b Sr-89, Sr-90 5x10'O Each Batch Composite Fe-55 1x10
-6 B. 0 W Principa 5x10
-7 Continuogs 7 b Releases Grab Sample Composite 'f Emitters} Gamma RHR Heat Exchanger I-131 1x10
-6 ESW Outlet
-5 M M Dissolved and 1x10 Grab Sample Entrained Gases (Gamma Emitters) 0 M H-3 1x10'0 Grab Sample Composite b _
Gross Alpha 1x10 ; 0 Q Sr-89, Sr-90 5x10'O b Grab Sample Composite -6 Fe-55 1x10 0 PERRY - UNIT 1 3/4 11-2 i
4 4 4 TABLE 4.11.1.1.1-1 (Continued) RADI0 ACTIVE LIQUID WASTE-SAMPLING AND ANALYSIS PROGRAM TABLE NOTATION
- a. The LLD is the smallest concentration of radioactive material in a sample that'will yield a net count (above system background) that will be detected 4
with 95% probability with only 5% probability of f.alsely concluding that' a blank observation represents a "real" signal. For a particular measurement system (which may include radiochemical separation): 4.66 s D LLD = E - V 2.22 x 106 - Y - exp(-Aat) t where [ ^ LLD is the "a priori" lower limit.of detection as defined above (as
- pCi per unit mass.or volume).
s b is the standard deviation of the background counting rate or of I the counting rate of a blank ~ sample as appropriate (as counts per minute) E is the counting eff.iciency (as counts per disintegration) V is -the sample size (in units of mass .or volume) 2.22.x 106 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 partic~ular~radionuclide (sec 1) at is the elasped time between sample coIlection (or.end of the sample collection period) and time of counting (sec)
;. . Typical values of E, V, Y and at should bs used in the calculation. j 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 a_ posteriori (after the fact) limit for a particular measurement.
5 PERRY - UNIT 1 3/4 11-3 _ , . -, - _ , _ _ . _ _ _ - . ~ _ _ _ _ _ _ - _ _ _ . . . - . _ . . _ _ . _ _ . _ . _ _ ,
TABLE 4.11.1.1.1-1 (Continued) RADI0 ACTIVE LIQUID WASTE SAMPLING AND ANALYSIS PROGRAM TABLE NOTATION (Continued)
- b. A composite sample is one in which the quantity of liquid sampled is proportional to the quantity of liquid waste discharged and in which the method of sampling employed results in a specimen which is representative of the liquids released.
- c. A batch release is the discharge of liquid wastes of a discrete volume.
Prior to sampling for analyses, each batch shall be isolated, and then thoroughly mixed to assure representative sampling.
- d. The principal gamma emitters for which the LLD specification applies exclusively are the following radionuclides: 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 5x10 6 This list does not mean that only these nuclides are to be detected and reported. Other peaks which are measurable and identifiable, together with the above nuclides, shall also be identified and reported in the Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.7 in the format outlined in Regulatory Guide 1.21, Appendix B, Revision 1, June 1974.
- e. 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. Sampling / Analysis of RHR Heat Exchanger is only applicable when there is ESW flow thru the RHR Heat Exchanger.
- f. Sampling and analysis is required of the RHR heat exchanger ESW outlet every 12 nours when the samples indicate levels greater than LLD.
O PERRY - UNIT 1 3/4 11-4
I e
~
RADI0 ACTIVE EFFLUENTS 4- DOSE l LIMITING CONDITION FOR OPERATION 3.11.1.2 The dose or dose commitment to a MEMBER OF THE PUBLIC from radioactive 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 or equal to 1.5 mrems to the total body and to less'than or equal to 5 mrems to any organ, and i
! b. During any calendar year to less than or equal to 3 mrems to the i total body and to less than or equal to 10 mrems to any organ. i APPLICABILITY: At all times. l t ACTION: ?,
- a. With the calculated dose'from the release of radioactive materials in liquid effluents exceeding any of the above limits, prepare and i submit to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special. Report which identifies the cause(s) for
- ( exceeding the limit (s)'and defines the corrective actions that have been,taken to reduce the releases and the corrective actions to be
~
! taken to ensure that future releases will be in compliance with the l above limits. j b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
- SURVEILLANCE REQUIREMENTS 4.11.1.2 Dose Calculations. Cumulative dose contributions from. liquid' effluents for the current calendar quarter and the current calendar year shall be determined in accordance with the methodology and parameters of the ODCM at.least once
~ per 31 days. 1 i 'O PERRY - ONIT 1 3/4 11-5
RADI0 ACTIVE EFFLUENTS LIQUID RADWASTE TREATMENT SYSTEM 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 release of radioactivity 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 a 31-day period. APPLICABILITY: At all times
- ACTiCa:
- a. With radioactive liquid waste being discharged without treatment 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 which 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, and
- 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 projected at least once per 31 days, in accordance with method-ology and parameters in the 00CM. 4.11.1.3.2 The installed LIQUID RADWASTE TREATMENT SYSTEM shall be demonstrated OPERABLE by meeting Specifications 3.11.1.1 and 3.11.1.2. "Not required to be OPERABLE prior to initial criticality. PERRY - UNIT 1 3/4 11-6
- .- . . . - - - -.=. ..-. - _ -_- - - - - - - .- - _ . _ .
's RADIOACTIVE EFFLUENTS
, %s - LIQUID HOLOUP TANKS LIMITING CONDITION FOR OPERATION i 3.11.1.4 The quantity of radioactive material contained in any outside tempo-rary tank, not including liners for shipping radwaste, shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained ' noble gases. APPLICABILITY: At all times. ACTION: 4 ) a. With the quantity of radioactive material in any of the above 4 specified tanks exceeding the above limit, immediate'y suspend all additions of radioactive material to the tanks and within 48 hours i d reduce the tank contents to within the limit, and desccibe the events leading to the condition in the next Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.8. 4 b. The provisions of Specifications 3.0.3 and 3.0.4 are not 4 applicable. gs SURVEILLANCE REQUIREMENTS i 4.11.1.4 The quantity of radioactive material contained in each of the above specified tanks shall be determined to be within the'above limit by analyzing a representative sample of _ the tank's contents at least once per 7 days when radioactive materials are being added to the tank. ] I I i 1 l PERRY - UNIT 1 3/4 11-7
RADI0 ACTIVE EFFLUENTS 3/4.11.2 GASEOUS EFFLUENTS DOSE RATE LIMITING CONDITION FOR OPERATION 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 mrens/yr to the skin, and
- b. For all iodine-131, iodine-133, tritium and all radionuclides in particulate form with half lives grecter 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 decrease the release rate (s) to within the above limit (s). SUREVEILLANCE_9EQUIREMENTS 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 of the ODCM. 4.11.2.1.2 The dose rate due to iodine-131, iodine-133, tritium and to radionuclides in particulate form with half lives greater than 8 days in gaseous effluents shall be determined to be within the above limits in accord-ance with the methodology and parameters of the ODCM by obtaining representa-tive samples and performing analyses in accordance with the sampling and anal-ysis program specified in Table 4.11.2.1.2-1. 1 0' PERRY - UNIT 1 3/4 11-8
. -. . _ - - - . - . . . _ - . .- ~. -~ . - . - ~ . .
.C l' (
( s t> - TABLE 4.11.2.1.2-1 g - RADI0 ACTIVE GASEOUS WASTE' SAMPLING AND ANALYSIS PROGRAM E MINIMUM LOWER LIMIT OF E SAMPLING ANALYSIS TYPE OF DETECTION (LLD)f") U GASE0US RELEASE PATH -FREQUENCY FREQUENCY ACTIVITY ANALYSIS (pCi/mL) ID) A. Drywell and Each PURGE (b) Each PURGE Primary Containment and VENI and VENT Principal Gamma EmittersI *) 1x10
~4 PURGE and VENT. Grab Sample M M 11 - 3 1x10 Grab Sample I
B. M(b) ' ~4 Offgas Vent, Unit 1 Vent, Unit 2 Vent Grab Sample M( ) Principag Emitters g 1x10 and Turbine y Building /lleater 11- 3 1x10 w Bay Vent C. All Release Paths Continuous (d) y(c) 1-131 1x10
-12
* -10 as listed in Charcoal Sample I-133 1x10 8 above Continuous (d) g(c) Principal Gamma Emittersf *) 1x10
~11 Particulate Sample i
Continuous (d) M Gross' Alpha 1x10
-11 Composite Par-i ticulate Sample Continuous (d) Sr-89, Sr-90 -11 Q 1x10 Composite Par-ticulate Sample Continuous (d) -Noble Gas Noble Gases 1x10
-6 Monitor (f) Gioss Beta or Gamma (Xe-133 equivalent) i j
t
TABLE 4.11.2.1.2-1 (Continued) RADI0 ACTIVE GASE0US WASTE SAMPLING AND ANALYSIS PROGRAM TABLE NOTATION
- a. The LLD is 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 sjstem (which may include radiochemical separation): 4.66 s b O* E - V 2.22 x 106 - Y - exp(-Aat) where LLD is the "a priori" lower limit of detection as defined above (as pCi per unit mass or volume). s is the standard deviation of tha background counting rate or of b the 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 106 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) at is the elasped time between sample collection (or end of the sample collection period) 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 not as a posteriori (af ter the fact) limit for a particular measurement. t O PERRY - UNIT 1 3/4 11-10
TABLE 4.11.2.1.2-1 (Continued) U RADI0 ACTIVE GASEOUS WASTE SAMPLING AND ANALYSIS PROGRAM TABLE NOTATION (Continued)
- b. Analyses shall also.be performed following startup, shutdown, or a THERMAL POWER change exceeding 15 percent of the RATED THERMAL POWER within a one 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 h~as not increased more than a factor of 3.
- c. 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 and analyses 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 percent of RATED THERMAL POWER in one hour. When samples collected for 24 hours are analyzed, the corresponding LLD's nay be increased by a factor of 10. 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. The ratio of the sample flow rate to the sampled stream flow rate shall Q 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.
- e. The principal gamma emitters for which the LLD specification applies 4
exclusively are the following radionuclides: Kr-87, Kr-88, . Xe-133, Xe-133m, Xe-135, and Xe-138 for. gaseous emissions and Mn-54, Fe-59, , Co-58, Co-60, Zn-65, Mo-99, I-131, Cs-134, Cs-137, Ce-141 and Ce-144 for particulate emissions. This list does not mean that only these nuclides are to be detected and reported. Other peaks which are measurable and identifiable, together with the above nuclides, shall also be identified and reported in the Semiannual Radiological Effluent Release Report pursuant to Specification 6.9.1.7 in the. format outlined in Regulatory Guide 1.21, Appendix B, Revision 1, June 1974.
- f. Sampling and analysis of gaseous release points shall be performed initially whenever a high alarm setpoint is. exceeded or whenever two or more of the alert setpoints are exceeded. If the high alarm setpoint or two or more of the alert setpoints continue to be exceeded, verify at least once per 4 hours via the radiation monitors that plant releases are below the Specification 3.11.2.1 dose rate limits and sampling and analysis shall be performed at least once per 12 hours.
!n ,m PERRY - UNIT 1 3/4 11-11
RADI0 ACTIVE 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, from the site 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 mrads 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 the radioactive noble gases in gaseous effluents exceeding any of the above limits, prepare and submit to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special Report which identifies the cause(s) for exceeding the limit (s) and defines the corrective actions to be taken to ensure that future releases will be in compliance with Specification 3.11.2.2.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REOUIREMENTS 4.11.2.2 Dose Calculations. Cumulative dose contributions for noble gases for the current calendar quarter and current calendar year shall be determined in accordance with the methodology and parameters in the ODCM at least once per 31 days. O PERRY - UNIT 1 3/4 11-12
['N, RADI0 ACTIVE 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 radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents released, from each reactor unit, from the site to
~
areas at and beyond the CITE BOUNDARY (see Figure 5.1.1-1) shall be limited to the following:
- a. During any calermar 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.
APPLICABILITY: 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
- O greater than 8 days, in gaseous effluents exceeding any of the above
\ ) limits, prepare and su' omit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special Report which identifies the cause(s) for exceeding the limit and defines the corrective actions that have been taken to reduce releases and the proposed corrective actions to be taken to ensure that future releases will be in compliance with Specification 3.11.2.3.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REOUIREMENTS 4.11.2.3 Dose Calculations. Cumulative dose contributions from iodine-131, iodine-133, tritium and radionuclides in particulate form with half-lives greater than 8 days for the current calendar quarter and current calendar year shall be determined in accordance with the methodology and parameters in the ODCM at least once per 31 days. /~N (v) PERRY - UNIT 1 3/4 11-13 i I
RADI0 ACTIVE EFFLUENTS GASEOUS RADWASTE (OFFGAS) TREATMENT LIMITING CONDITION FOR OPERATION 3.11.2.4 The GASEOUS RA0 WASTE TREATMENT (OFFGAS) SYSTEM shall be in operation. The Charcoal bypass mode shall not be used 'unless the offgas post-treatment radiation monitor is OPERABLE as specified in Table 3.3.7.1-1. APPLICABILITY: Whenever the main condenser air ejector evacuation system is in operation. ACTION:
- a. With gaseous radwaste from the main condenser air ejector system being discharged without treatment for more than 7 consecutive days, prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special Report which includes the following information:
- 1. Explanation of why gaseous radwaste was being discharged without treatment, identification of the inoperable equipment or subsystems which resulted in gaseous radwaste being discharged without treatment, and the reason for 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 REOUIREMENTS 4.11.2.4 The readings of relevant instrumentation shall be checked at least once per 12 hours when the main condenser air ejector is in use to ensure that the gaseous radwaste treatment system is. functioning. O PERRY - UNIT 1 3/4 11-14 h
RADI0 ACTIVE EFFLUENTS \ VENTILATION EXHAUST TREATMENT SYSTEMS LIMITING CONDITION FCR OPERATION 3.11.2.5 The VENTILATION EXHAUST TREATMENT SYSTEMS shall be OPERABLE and appropriate portions of the sy' stem shall be used to reduce releases of radio-activity when the projected dose due to gaseous effluent releases from each , reactor unit to areas at and beyond the SITE BOUNDARY (see Figure 5.1.1-1) in a 31 day period would exceed 0.3 mrem to any organ of a MEMBER OF THE PUBLIC. APPLICABILITY: At all times *. ACTION: .
- a. With radioactive gaseous waste being discharged without treatment and in excess of the above limits, prepare and submit to the Commis-sion within 30 days, pursuant to Specification 6.9.2, a Special Report which includes the fo.11owing information:
- 1. Explanation of why gaseous radwaste was being discharged without treatment, identification of-any inoperable equipme~t or subsystems which resulted in gaseous radwaste being discharged without treatment, 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 4.11.2.5.1 Doses due to gaseous releases from each reactor 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 00CM. 4.11.2.5.2 The installed VENTILATION EXHAUST TREATMENT SYSTEMS shall be demonstrated OPERABLE by meeti.ng Specifications 3.11.2.1 and 3.11.2.3. m
*Not required to be OPERABLE prior to initial criticality.
PERRY - UNIT 1 3/4 11-15
RADI0 ACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE LIMITING CONDITION FOR OPERATION 3.11.2.6 The concentration of hydrogen in the offgas treatment system shall be limited to less than or equal to 4% by volume. APPLICABILITY: Whenever the offgas treatment system is in operation. ACTION: a. With the concentration of hydrogen.in the offgas treatment system exceeding the limit, restore the concentration to within the limit within 48 hours. b. With the continuous monitor inoperable, utilize grab sampling procedures,
- 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 offgas treatment system shall be determined to be within the above limits by continuously monitoring the 9 waste gas in the offgas treatment system whenever the main condenser evacuation system is in operation with the hydrogen monitor OPERABLE as required by Table 3.3.7.10-1 of Specification 3.3.7.10. O PERRY - UNIT 1 3/4 11-16
RADI0 ACTIVE EFFLUENTS l \ \ / MAIN CONDENSER LIMITING CONDITION FOR OPERATION 3.11.2.7 The release rate of the sum of the activities of the noble gases Kr-85m, Kr-87, Kr-88, Xe-133, Xe-135, and Xe-138 measured at the main condenser air ejector shall be limited to less than or equal to 358 millicuries /second, after 30 minutes decay. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3* ACTION: With the release rate of the specified noble g'ases at the main condenser air ejector effluent exceeding 358 millicuries /second after 30 minutes decay, restore the release rate to within its limit within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS !, ,j 4.11.2.7.1 The release rate of noble gases at the outlet of the main condenser (/ air ejector shall be continuously monitored in accordance with Specification 3.3.7.1. 4.11.2.7.2 The release rate of the specified noble gases from the main conden-ser air ejector shall be determined to be within the limits of Specification 3.11.2.7 at the following frequencies ** by performing an isotopic analysis of a representative sample of gases taken at the discharge (prior to dilution and/or discharge) of the main condenser air ejector,
- a. At least once per 31 days.
- b. Within 4 hours following an increase, as indicated by the Offgas Pretreatment Radiation 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.
*When the main condenser air ejector is in operation.
**The provisions of Specification 4.0.4 are not applicable.
O i i xJ PERRY - UNIT 1 3/4 11-17
RADI0 ACTIVE EFFLUENTS 3/4.11.3 SOLID RA0 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 the SOLIDIFICATION or dewatering not performed in accordance with the PROCESS CONTROL PROGRAM, (1) test the improperly processed waste in each container to ensure that it meets burial ground and shipping requirements and (2) take appropriate administrative action to prevent recurrence.
- c. The provisions of Specification 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REOUIREMENTS 4.11.3.1 If the SOLIDIFICATION method is used, the PROCESS CONTROL PROGRAM shall be used to verify the SOLIDIFICATION of at least one representative test specimen from at least every tenth batch of each type of wet radioactive waste (e.g., filter sludges, spent resins, evaporator bottoms, and sodium sulfate solutions).
- a. If any test specimen fails to verify SOLIDIFICATION, the SOLIDIFICA-TION of the batch under test shall be suspended until such time as additonal test specimens can be obtained, alternative SOLIDIFICATION parameters can be determined in accordance with the PROCESS CONTROL PROGRAM, and a subsequent test verifies SOLIDIFICATION. SOLIDIFICATION of the batch may then be resumed using the alternative SOLIDIFICATION parameters determined by the PROCESS CONTROL PROGRAM.
"Not required to be OPERABLE prior to initial criticality. l PERRY - UNIT 1 3/4 11-18
RADI0 ACTIVE EFFLUENTS SURVEILLANCE REQUIREMENTS (Continued) ,
- b. If-the initial test specimen from a batch of waste fails to verify SOLIDIFICATION, the P.ROCESS CONTROL PROGRAM shall provide for-the collection and testing of representative test specimens from each consecutive batch of the same type of wet waste until at least three consecutive initial test specimens demonstrate SOLIDIFICATION. The PROCESS CONTROL PROGRAM shall be modified as required, as provided in Specification 6.13, to assure SOLIDIFICATION of subsequent batches of waste.
- c. With the installed equipment incapable of meeting Specification 3.11.3 or declared inoperable, restore the equipment to OPERABl.E status or provide the contract capability to process wastes as necessary to satisfy all applicable transportation and disposal requirements.
6 PERRY - UNIT 1 3/4 11-19
RADI0 ACTIVE EFFLUENTS 3/4.11.4 TOTAL 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 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: 4. 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 shall be made including direct radiation contributions from the reactor units and from outside storage tanks 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 and ircludes 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 (dese) to a MEMBER OF THE PUBLIC from uranium fuel cycle sources, including all effluent pathways and direct radiation, for the calendar year that in-c1udes the release (s) covered by this report. It shall also describe levels of radiation and concentrations of radioactive material in-volved, and the cause of the exposure levels or concentrations. If the estimated dose (s) exceeds the above-limits, and if the release l condition resulting in violation of 40 CFR Part 190 has not already been corrected, the Special Report shall include a request for a variance 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 REOUIREMENTS 4.11.4.1 Cumulative dose contributions from liquid and gaseous effluents 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 00CM. 1 4.11.4.2 If the cumulative dose contributions exceed the limits defined in 3.11.4, ACTION a, cumulative dose contributions from direct radiation from unit operation including outside storage tanks shall be determined in accordance with the methodology and parameters in the 00CM. PERRY - UNIT 1 3/4 11-20 J
'p 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING l
3/4.12.1 MONITORING PROGRAM LIMITING CONDITION FOR OPERATION 3.12.1 The radiologi' cal environmental monitoring program shall be conducted as specified in Table 3.12.1-1. APPLICABILITY: At all times. ACTION: i a. With the radiological environmental monitoring program not being con-ducted as specified in Table 3.12.1-1,. prepare and submit to the Com-mission, in the Annual Radiological Environmental Operating Report per i Specification 6.9.1.6, 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
- t an environmental sampling medium at a specified location exceeding the reporting levels of Table 3.12.1-2 when averaged over any calendar
- quarter, prepare and submit to the Commission within 30 days pursuant c
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 taken to reduce radioactive effluents so that the potential annual dose to a MEM8ER~ 0F 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 i of the radionuclides in Table 3.12.1-2 are detected in the sampling medium, this report shall be submitted if:
!s concentration (1) reporting level (1) concentration (2) reporting level (2) + * * * > 1.0
- 4. When radionuclides other than those in Table 3.12.1-2 are detected and are the result of plant effluents, this report shall be submitted if the potential annual dose
- to a MEMBER OF THE PUBLIC 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 required by ! Specification 6.9.1.6.
- c. With milk or broad leaf vegetation 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 l within 30 days to the Radiological Environmental Monitoring Program i given in the ODCM. The specific locations from which samples were unavailable may then be deleted from the monitoring program. Pursuant to Specification 6.14, submit in the next Semiannual Radioactive 4
Effluent Release ' Report documentation for a change in the ODCM includ- , ing a revised figure (s) and table for the 00CM reflecting the new j location (s) with supporting information identifying the cause of the , unavailability of samples and justifying the selection of the new location (s) for obtaining samples.
- d. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
i *The methodology and parameters used to estimate the potential annual dose to a . MEMBER OF THE PUBLIC shall be indicated in this report. 1 PERRY - UNIT 1 3/4 12-1 _
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l RADIOLOGICAL ENVIRONMENTAL MONITORING 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 il the table and figures 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 l i 1 9 PERRY - UNIT 1 3/4 12-2 -
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TABLE 3.12.1-1 A g RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM
- I E Number of Samples Q Exposure Pathway and Sampling and Type and frequency g and/or Sample Sample tocations (7) Collection Frequency of Analysis
- 1. Direction -Twenty-eight routine monitoring .
Quarterly. Gamma dose quarterly. Radiation (2) stations either with two or more dosimeters or with one instrument for measuring and recording dose rate continuously, placed as follows: An inner ring of stations, one in each meteorological sector, other than those sectors entirely over water (N, NNE, NNW, tN, W, WfN),
- in the general area of the SITE g BOUNDARY; w
An outer ring of stations, one in each meteorological sector, other than those sectors entirely over water (N, NE, NNE, NfN, NW, W WNW), in the 6- to 8-km range from the site; and The balance of the stations to be placed in.special interest areas such as population centers, nearby residences, schools, and in one or two areas to serve as control stations.
TABLE 3.12.1-1 (Continued) M y RADIOLOGICAL Ef4VIRONMENTAL f10NITORIf1G PROGRAft 5 Number of Samples
? Exposure Pathway and Sampling and Type and Frequency
~ and/or Sample Sample Locations (1) Collection Frequency of Analysis
- 2. Airborne Radioiodine and Samples f rom five locations: Continuous sampler Radioiodine Canister:
Particulates operation with sample I-131 analysis weekly. Ihree samples from close to collection weekly, or the three SITE BOUNDARY loca- more frequently if tions, in different sectors, of required by dust Particulate Sampler: the highest calculated annual loading. Gross beta radioactivity average Ground-level D/Q; analysis following 1,, filter change;(3) and g) g One sample from the vicinity gamma isotopic analysis
- of a community having the highest of composite (by y calculated annual average ground- location) quarterly.
level D/Q; and One sample from a control location, as for example 15 to 30 km distant and in the least prevalent wind direction.
- 3. Waterborne
- a. Surface Two samples Composite sample over Gamma isotopic analysis 1-month period.(S) m nthly. Composite for tritium analysis quarterly.
O O O
c O O TABLE 3.12.1-1 (Continued) A g RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM 5 Number of Samples y Exposure Pathway and Sampling and Type and frequency ~ and/or Sample Sample Locations (y) Collection Frequency of Analysis -
- 3. Waterborne (Continued)
- b. Drinking One sample of each of one to Composite sample I-131 analysis on each three of the nearest water over 2-week period (5) composite when the dose supplies that could be when I-131 analysis calculated from the consump-affected by its discharge. is performed; monthly tion of the water is greater composite otherwise* than 1 mrem per year.(6) Com-One sample from a control posite for gross beta and I Cd" "'
gamma' isotopic analyses I4) R o monthly. Composite for tritium analysis quarterly. h m
- c. Sediment One sample from area with Semiannually. Gamma isotopic analysis (4) from existing or potential semiannually, shoreline recreational value.
- 4. Ingestion
- a. Milk Samples from milking animals Semimonthly when Gamma isotopicI4) and I-131 in three locations within animals are on analysis semimonthly when 5 km distance having the pasture; monthly at animals are on pasture; highest dose potential. If other times. monthly at other times.
there are none, then one sample from milking animals in each of three areas between 5 to 8 km distant where doses are calculated to be greater than 1 mrem per yr.(6) One sample from milking animals at a control location 15 to 30 km distant and in the least prevalent wind direction.
TABLE 3.12.1-1 (Continued) RADIOLOGICAL Ef1VIR0t1 MENTAL F10t1ITORING PROGRAM E flumber of Samples Exposure Pathway and Sampling and Type and Frequency O gy) of Analysis and/or Sample Sample Locations Collection Frequency
~
- 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 t' plant discharge. u
- c. Food Samples of three different kinds Monthly during Gamma isotopicI4) and 1-131
[ growing season. analysis. A Products of broad leaf vegetation grown nearest each of two different offsite locations of highest predicted annual average l ground level D/Q if milk sampling
- is not performed.
t One sample of each of the simi- Monthly during Gamma isotopic (4) and 1-131 lar broad leaf vegetation grown growing season. analysis. 15 to 30 km distant in the least prevalent wind direction if milk sampling is not performed. O O O
i I l
/m, 1 TABLE 3.12.1-1 (Continued)
)
RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM TABLE NOTATIONS Sample locations are given on the figure and the table in the ODCM. (1) Specific parame.ters of distance and direction sector from the centerline of one reactor, ar.f additional description where pertinent, shall be provided for eac% and every sample location in Table 3.12-1 in a table and figure (s) *n the ODCM. Refer to NUREG-0133, " Preparation of Radio-logical Efficant Technical Specifications for Nuclear Power Plants," October 1973, and to Radiological Assessment Branch Technical Position, Revisior. 1, November 1979. Deviations are permitted from the required sampling schedule if specimens are unobtainable due to circumstances such as hazardous conditions, seasonal unavailability, and malfunction of. automatic sampling equipment. If specimens are unobtainable due to sampling equipment malfunction, effort shall be made to complete correc-tive action prior to the end of the next sampling period. All deviations from the sampling schedule shall be documented in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. It is recognized that, at times, it may not be possible or practicable to continue to obtain samples of the media of choice at the most desired location or time. In these instances suitable specific alternative media and locations may be chosen for the particular pathway in question and (n) U/ appropriate substitutions made within 30 days in the Radiological Environ-mental 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) One or more instruments, such as a pressurized ion chamber, for measuring ana recording dose rate continuously may be used in place of, or in addition to, integrating dosimeters. For the purposes of this table, a thermoluminescent dosimeter (TLD) is considered to be one phosphor; two or more phosphors in a packet are considered as two or more dosimeters. Film badges shall not be used as dosimeters for measuring direct radiation. (The 40 stations is not an absolute number. The number of direct radiation monitoring stations may be reduced according to geographical limitations; e.g., at an ocean site, some sectors will be over water so that the number of dosimeters may be reduced accordingly. The frequency of analysis or readout for TLD systems will depend upon the characteristics of the specific system used and should be selected to obtain optimum dose information with minimal fading.) (3) Airborne particulate sample filters shall be analyzed for gross beta radioactivity 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 O) i, v isotopic analysis shall be performed on the individual samples. PERRY - UNIT 1 3/4 12-7
TABLE 3.12.1-1 (Continued) TABLE NOTATIONS (Continued) (4) Gamma isotopic analysis means the identification and quantification of gamma emitting radionuclides that may be attributable to the effluents from the facility. (5)- 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 (e.g. , hourly) relative to the cornpositing period (e.g. , monthly) in order to assure obtaining a representative sample. (6) The dose shall be calculated for the maximum organ and age group, using I the methodology and parameters in the ODCM. O l l 9 PERRY - UNIT 1 3/4 12-8
TABLE 3.12.1-2 REPORTING LEVELS FOR RADI0 ACTIVITY CONCENTRATIONS IN ENVIRONMENTAL SAMPLES
.g Reporting Levels M
- Water Airborne Particulate Fish Milk Food Products Analysis (pCi/1) or Gases (pCi/m3 ) (pCi/Kg, wet) (pCi/1) (pCi/kg, wet).
4 H-3 2 x 10 NA NA NA NA Hn-54 1 x 10 3 NA 3 x 10 4 NA' NA 2 4 Fe-59 4 x 10 NA 1 x 10 NA NA 4 Co-58 1 x 10 NA' 3 x 10 NA- NA R 2 Co-60 3 x 10 4 NA 1 x 10 NA [ n NA 2 d> Zn-65 3 x 10 NA 2 x 10 4 NA NA 2 Z r-Nb-95 4 x 10 NA NA NA NA I-131 2 0.9 ~ 2 NA 3 1 x 10 Cs-134 30 10 1 x 10 60 1 x 10 3 Cs-137 50 20 2 x 10 70 2 x 10 3 2 Ba-La-140 2 x 10 NA NA 3 x 10 2 NA I j For drinking water samples. This is a 40 CFR Part 141 value. l
- . - - ..- - - - - -- -. --- .- - - ~
TABLE 4.12.1-1 A MAXIMUM VALUES FOR THE LOWER LIMITS OF DETECTION (LLD)(a), (b), (c) IN ENVIRONMENTAL SAMPLES ] b Airborne Particulate Broad Leaf Water or Gas Fish .Hilk Vegetation Sediment Analysis (pCi/1) (pCi/m3 ) (pCi/kg, wet) (pCi/1) (pCi/kg, wet) (pCi/kg, dry) Gross beta 4 1 x 10 -2 NA NA NA flA H-3 2000* NA NA NA NA NA Mn-54 15 NA 130 NA NA NA fe-59 30 NA 260 NA flA NA w Co-58,60 15 NA 130 NA NA NA D ~ In-65 30 NA 260 NA NA NA "f $; Ir-95 30 NA NA NA NA NA Hb-95 15 NA NA NA NA NA I-131 1** 7x 10
-2 NA 1 60 NA Cs-134 15 5 x 10~ 130 15 60 150 Cs-137 18 6 x 10 -2 150 18 80 180 Ba-140 60 NA NA 60 NA NA ta-140 15 NA NA 15 NA NA
*If no drinking water pathway exists, a value of 3000 pCi/l may be used.
**lt no drinking water pathway exists, a value of 15 pCi/l may be used.
\ O O O
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\ TABLE 4.12.1-1 (Continued)
MAXIMUM VALUES FOR THE LOWER LIMITS OF DETECTION (LLD) TABLE NOTATION . a Acceptable detection capabilities for thermoluminescent dosimeters used for environmental measurements are given in Regulatory Guide 4.13. b Table 4.12-1 indicates acceptable detection capabilities for radioactive
, materials in environmental samples. These detection capabilities are tabulated in terms of the lower limits of detection (LLDs). The LLD is defined, for purposes of this guide, 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):
4.66 s D LLD = E - V 2.22 - Y - exp(-Aat)
, where I )
(__./ LLD is the "a priori" lower limit of detection as defined above (as pCi per unit mass or volume). s b is the standara deviation of the background counting rate or of the 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 is the fractional radiochemical yield (when applicable) A is the radioactive decay constant for the particular radionuclide at is the elasped time between sample collection (or end of'the sample collection period) and time of counting The value of sh used in the calculation of the LLD for a particular measurement'sy5 tem should be based on the actual observed variance of the background counting rate or of the counting rate of the blank samples (as appropriate) rather than on an unverified theoretically predicated variance. [} s' PERRY - UNIT 1 3/4 12-11
TABLE 4.12.1-1 (Continued) MAXIMUM VALUES FOR THE LOWER LIMITS OF DETECTION (LLD) TABLE NOTATION (Continued) 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 not as a posteriori (af ter the fact) limit for a particular measurement. Occasionally background fluctuations, unavoidable small sample size, the presence of inter-fering nuclides, or other uncontrollable circumstances may render these LLDs unachievable. In such cases, the contributing factors should be identified and described in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. c This list does not mean that only 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 Oper-ating Report pursuant to Specification 6.9.1.6. O O PERRY - UNIT 1 3/4 12-12 l
em RADIOLOGICAL ENVIRONMENTAL MONITORING I V) 3/4.12.2 LAND USE CENSUS LIMITING CONDITION FOR OPERATION 3.12.2 A land use census shall be conducted and shall identify within a dis-tance of 8 km (5 miles) the location in each of the 16 meteorological sectors of the nearest milk animal, the nearest residence and the nearest garden
- of greater than 50 m2 (500 ft 2) producing broad leaf vegetation.
APPLICABILITY: At all times. ACTION:
- a. With a land use census identifying a location (s) which yields a calculated 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 to Specification 6.9.1.7.
- b. With a land use census identifying a location (s) which yields a calculated dose or dose commitment (via the same exposure pathway) 20 percent greater than at a location from which milk and/or broad leaf vegetation samples are currently being obtained in accordance with Specification 3.12.1, add the new location (s) to the radiological environmental monitoring program within 30 days. If no milk and/or s < broad leaf vegetation samples are identified in the new sector with the highest 0/Q value, then the next sector with the highest 0/Q value will be considered and so on until a sampling location can be established. 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 land use census was conducted.* 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 (s) for the 00CM reflecting the new location (s).
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.12.2 The land use census shall be conducted during the growing season at least once per 12 months using that information that will provide the best results, such as by a door-to-door survey, aerial survey, or by consulting local agriculture authorities. The results of the land use census shall be included in the Annual Radiological Environmental Operating Report pursuant to Speci fication 6. 9.1. 6.
" Broad leaf vegetation sampling of at least three different kinds of vegetation may be parformed at the site boundary in each of two different direction sec-tors with the highest predicted 0/Qs in lieu of the garden census. Specifica-tions for broad leaf vegetation sampling in Table 3.12.1-1 shall be followed.
(VO) including analysis of control samples. PERRY - UNIT 1 3/4 12-13
RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.3 INTERLABORATORY COMPARISON PROGRAM LIMITING CONDITION FOR OPERATION 3.12.3 Analyses shall be performed on radioactive materials that correspond to samples required by Table 3.12.1-1. These materials are supplied as part of an Interlaboratory Comparison Program which has been approved by the Commission. APPLICABILITY: At all times. ACTION:
- a. With analyses not being performed as required above, report the corrective actions taken to prevent a recurrence to the Commission in the Annual Radiological Environmental Operating Report pursuant to Speci fication 6. 9.1. 6.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE RE0UIREMENTS 4.12.3 A summary of the results obtained as part of the above required Interlaboratory Comparison Program shall be included in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. O PERRY - UNIT 1 1 12-14 l l l
t i ? l lO \ i I t i t i I BASES FOR I t SECTIONS 3.0 AND 4.0 f I LIMITING CONDITIONS FOR OPERATION i l AND SURVEILLANCE REQUIREMENTS O ! I i I I I l i l 0
i-1 . l t x !e i I t i f ! 1 i i l i I
- l i
! i l NOTE I ' The BASES contained in succeeding pages summarize ! the. reasons for the Specifications in Section 3.0 ; and 4.0, but in accordance with 10 CFR 50.36 are l not part of these Technical Specifications.
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3/4.0 APPLICABILITY
/
I \ BASES The specifications of this section provide the general ~ requirements applicable to each of the Limiting Conditions fo.r 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 con-dition and is provided to delineate specifically when each specification is. applicable. 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 to be taken for those circumstances not directly provided for in the ACTION statements and whose occurrence would violate the intent of the specification. For example, Speciff-cation 3.7.2 requires two control room emergency recirculation subsystems to be O OPERABLE and provides explici_t 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 3.6.7.1 requires two primary containment hydrogen recombiner subsystems to be OPERABLE and provides explicit ACTION requirements if one recombiner 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 and in at least HOT SHUTOOWN within the following 6 hours. 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 service 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. Exceptions to this provision have been provided for a limited number of specifications when startup with inoperable equipment would not affect plant safety. These exceptions are stated in the ACTION statements of the appropriate specifications. PERRY - UNIT 1 B 3/4 0-1 _ ____---_--_a
APPLICABILITY 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 activities 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 surveillance activities. The tolerance values, taken either individually or consecutively over 3 test intervals, are sufficiently restrictive to ensure that the reliability. associated with the surveiliance 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 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. 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 acplicable surveillance activ-ities must be performed within the stated surveillance interval prior to placing or returning the system or equipment into OPERABLE status. PERRY - UNIT 1 B 3/4 0-2 , 1
)
I [3 APPLICABILITY \
)
BASES 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 arid applicable Addends. This clarifi-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 tnis 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 "x CONDITION or other specified applicability condition takes precedence over the I., di 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. [h k v PERRY - UNIT 1 B 3/4 0-3
n 3/4.1 REACTIVITY CONTROL SYSTEMS BASES 3/4.1.1 SHUTDOWN MARGIN A sufficient SHUTOOWN MARGIN ensures that 1) the reactor can be made sub-critical 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 appropriate. 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 or 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 SHUT 00WN MARGIN. The highest worth rod may be determined analytically or by test. The SHUTDOWN
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MARGIN is demonstrated by an insequence control rod withdrawal at the beginning h 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 condi-tion assures subcriticality with the most reactive 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% 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% would not exceed the design conditions of the reactor and is on the safe side of the postulated transients.
'N PERRY - UNIT 1 B 3/4 1-1 1
REACTIVITY CONTROL SYSTEMS BASES 3/4.1.3 CONTROL RODS The specification 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 safety analyses, 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 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 SHUTOOWN MARGIN requirements. The number of control rods permitted to be inoperable could be more than 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 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 control 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 ard Specification 3.1.3.1 then applies. This presents a pattern of inoperac'e accumulators that would result in less reactivity insertion on a scram than has been analyzed even though control rods with inoperable accumulators may stil; be inserted with normal drive water pressure. Operaoility of the accumulator ensures that there is a means available to insert the control rods even under the most unfavorable depressurization of the reactor. B 3/4 1-2
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PERRY - UNIT 1
p 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 i provides the only p'ositive mechanical means of determining that a rod is l properly coupled and therefore this check must be performed prior to achieving l 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 demonstration. In order to ensure that the control rod patterns can.be followed and therefore that other parameters are within their limits, the control rod position indication system must be OPERABLE. l The control rod housing support restricts the outward movement of a control rod to less than 3 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 l 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 R00 PROGRAM CONTROLS The rod withdrawal limiter system input power signal orginatas from the first stage turbine pressure. When operating with the steam bypass valves open, this signal indicates a core power level which is less than the true core power. Consequently, near the low power setpoint and.high power setpoint of the rod pattern control sys6em, the potential exists for non-conservative control rod withdrawals. Therefore, when operating at a sufficiently high power level, there is a small probability of violating fuel Safety Limits during a licensing basis rod withdrawal error transient. To ensure that fuel Safety Limits are not violated, this specification prohibits coqtrol rod withdrawal when a biased power signal exists and core power excee.'s the specified level. Control rod withdrawal and insertion sequences are established to assure-that the maximum insequence individual control rod or control rod segments which
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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 RPCS to be OPERABLE when THERMAL POWER is less.than or equal to 20% of RATED THERMAL POWER provides adequate control. On PERRY - UNIT 1 8 3/4 1-3
REACTIVITY CONTROL SYSTEMS BASES CONTROL R00 PROGRAM CONTROLS (Continued) The RPCS prov de automatic supervision to assure that out-of-sequence rods will not be withdrewn or inserted. The analysis of the rod drop accident is presented in Section 15.4 of the FSAR and the techniques of the analysis are presented in a topical report, Reference 1, and two supplements, References 2 and 2. - The RPCS is also designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density during higher power operation. A dual channel system is provided that, above the low power setpoint, restricts the withdrawal
- distances of all control rods. This restriction is greatest at highest power levels.
3/4.1.5 STANDBY LIOUID 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. To allow for potential leakage and imperfect mixing this concentration is increased by 25%. The required concen-tration is achieved by having a minimum available quantity of 4409 gallons of sodium pentaborate solution,13.4% by weight, containing a minimum of 5236 lbs. of sodium pentaborate. This quantity of solution is the net amount above the pump suction, thus allowing for the portion that cannot be injected. The pump-ing rate of 41.2 gpm provides a negative reactivity insertion rate over the permissible sodium pentaborate solution volume range which adequately compensates for the positive reactivity effects due to temperature and xenon during shutdown. The temperature requirement for the sodium pentaborate solution 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 baron 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 thest 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 NEDO-10527, March 1972
- 2. C. J. Paone, R. C. Stirn and R. M. Young, Supplement 1 to NEDO-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 PERRY - UNIT 1 B 3/4 1-4
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! I fS 3/4.2 POWER DISTRIBUTION LIMITS BASES The specificationsoof this section assure that the peak cladding temper-ature following the postulated design basis loss-of-coolant accident will not 4
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 averag9 heat generation rate of all the rods of a fuel assembly at any axial location and is dependent only secondarily ' on the rod to rod power distribution within an assembly. The peak clad temperature is calculated assuming a LHGR 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 heatup 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 and 3.2.1-3.
-~s The calculational procedure used to establish the APLHGR shown on Figures
) 3.2.1-1, 3.2.1-2 and 3.2.1-3 is based on a loss-of-coolant accident analysis.
\
V The analysis was performed using General Electric (GE) calculational 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 presented 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. Correct heat capacity of reactor internals heat nodes.
L PERRY - UNIT 1 B 3/4 2-1
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. Incorporate 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 thermal power-high scram trip setpoint and the flow biased neutron flux-upscale control rod block functions of the APRM instruments 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 settings and rod block settings are adjusted in accordance with the for-mula in this specification when the combination of THERMAL POWER and CMFLPD indicates a peak power distribution to ensure than an LHGR transient would not be increased in degraded conditions. O PERRY - UNIT 1 B 3/4 2-2
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Bases Table B 3.2.1-1 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS Plant Parameters; Core THERMAL POWER ....... ....... ... 3729 Mwt* which corresponds to 105% of rated steam flow Vessel Steam Output ........... ..... . 16.2 x 106 lbm/hr which corresponds to 105% of rated steam flow Vessel Steam Dome Pressure.... .. ... 1060 psia Design Basis Recirculation Line Break Area for:
- a. Large Breaks 2.7 ft2 (v) b. Small Breaks 0.09 ft2, 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 P8 x 8R 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 ard subsection 6.3 of the FSAR.
*This power level meets the Appendix K reouirement 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.
, n PERRY - UNIT 1 8 3/4 2-3 7
POWER DISTRIBUTION LIMITS BASES
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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 Liniit is not exceeded during any anticipated abnormal operational transient, the most limiting tran-sients have been analyzed to determine which result in the largest reduction in CRITICAL POWER RATIO (CPR). The type of transients evaluated 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 and presented in Figure 3.2.3-1. The power-flow map of Figure 8 3/4 2.3-1 defines the analytical basis for generation of the MCPR operating limits. The evaluation of a given transient begins with the system initial parameters shown in FSAR Table 15.0-1 that are input to a GE-core dynamic behavior transient computer progrg The code used to evaluate pressurization events is described in NE00-24154(2) and the program used in non pressurization events is described in NE00-10802 The outputs of this program along with the initial MCPR form the input for further analyses of the thermally limiting bundlewithtgsinglechanneltransientthermalhydraulicTASCcodedescribed in NEDE-25149 The principal result of this evaluation is the reduction in MCPR caused by the transient. The purpose of the MCPR f and MCPR of Figures 3.2.3-1 and 3.2.3-2 is to defir,e operating limits at other than Eated core flow and power conditions. At less than 100% of rated flow and power the required MCPR is the larger value of the MCPR f and MCPR at the existing core flow and power state. The MCPR,s are establisned to proEect the core from inadvertent core flow increases such that the 99.9% MCPR limit requirement can be assured. Figure 3.2.3-2 reflects the required MCPR values resulting from the analysis performed to justify operation with the feedwater temperature ranging from 420 F to 320 F at 100% RATED THERMAL POWER steady state conditions, and also beyond the end of cycle with the feedwater temperature ranging from 420 F and 250 F. The MCPR f s were calculated such that for the maximum core flow rate and the corresponding THERMAL POWER along the 105% of rated steam flow control line, the limiting bundle's relative power was adjusted until the MCPR was slightly above the Safety Limit. Using this relative bundle power, the MCPRs were calculated at different points along the 105% of rated steam flow control line corresponding to different core flows. The calculated MCPR at a given point of core flow is defined as MCPRf. PERRY - UNIT 1 B 3/4 2-4
._- _- _- -_. ~
POWER DISTRIBUTION LIMITS G BASES MINIMUM ~ CRITICAL POWER RATIO (Continued) l The MCPR s are established to protect the core from plant transients other than core floO increases, including the localized event such as rod withdrawal , I
. error. .The MCPR s were calculated based upon the most limiting transient at the given core powerp level.
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-3 i 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 will be made at 25% of RATED THERMAL POWER level with minimum recirculation pump speed. The MCPR nargin 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 g 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, NE00-24154, October 1978.
- 4. TASC 01-A Computer Program For The Transient Analysis of a Single Channel, Technical Description, NEDE-25149, January 1980.
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BASES 3/4.3.1 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 absorbed fc11owing 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. The reactor _ protection system is made up of two independent trip systems. [m') 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 specified 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. !O PERRY - UNIT 1 B 3/4 3-1 i L
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 isol& tion of the reactor systems. When neces-sary, 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 setpoints of ather instrumentation, where only the high or low end of the setting have a direct bearing on safety, are established at a level away ' rom 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 valve is assumed; thus the signal delay (sensor response) is concurrent with the 13-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. 3f4.3.3 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. 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. PERRY - UNIT 1 8 3/4 3-2
/'N INSTRUMENTATION (v) 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 and NEDO-24222, dated December 1979, and Section 15.8 of the FSAR. The end-of-cycle recirculation pump trip (E0C-RPT) system is an essential safety supplement to the Reactor Protection System. The purpose of the EOC-RPT is to recover the loss of thermal margin which occurs at the end-of-cycle. The physical phenomenon 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 EOC-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void collapse 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. A fast closure sensor from each of two turbine control valves provides. (U) input to the E0C-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the second EOC-RPT system. Similarly, a position switch for each of two turbine stop valves provides input to one E0C-RPT system; a position switch from 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 EOC-RPT system and trip both recirculation pumps. Each EOC-RPT system may be manually bypassed by use of a keyswitch which is administratively controlled. .The manual bypasses and the automatic Operating Bypass at less than 40% of RATED THERMAL POWER are annunciated in the control room. The EOC-RPT system response time is the time assumed in the analysis between initiation of valve motion and complete suppression of the electric arc, i.e., 140 ms. Included in this time are: the time from initial valve movement to reaching the trip setpoint, the response time of the sensor, the response time of the system logic, and the time allotted for breaker arc suppression. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the f] difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drif t specifically allocated for each trip in the safety a nal~ys e s . PERRY - UNIT 1 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 isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel. Operation with a taip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the differ-ence 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. 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 differ-ence 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 INSTRUMENTATIC'N 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; (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 important 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 recommendations of Regulatory Guide 1.12 " Instrumentation for Earthquakes", April 1974. 3/4.3.7.3 METEOROLOGICAL MONITORING INSTRUMENTATION The OPERABILITY of the meteorological monitoring instrumentation ensures that sufficient meteorological data is available for estimating potential radiation doses to the public as a result of routine or accidental release of radioactive materials to the atmosphere. This capability is required to eval-uate 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. PERRY - UNIT 1 8 3/4 3-4
i INSTRUMENTATION BASES MONITORING INSTRUMENTATION (Continued)
- 3/4.3.7.4 REMOTE SHUTDOWN INSTRUMENTATION AND CONTROLS The OPERABILITY of the remote shutdown monitoring instrumentation and controls ensures that sufficient capability is available to permit shutdown and ,
maintenance room. of HOT SHUTDOWN of the unit from locations outside of the control ' 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 '
7 Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," December 1975 and NUREG-0737, " Clarification of TMI Action Plan Requirements," November 1980. 3/4.3.7.6 SOURCE RANGE MONITORS O 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 av&ilable without the SRMs and they can be retracted. The SRMs are required OPERABLE in OPERATIONAL CONDITION 2 to provide for i rod block capability, and are required OPERABLE in OPERABLE CONDITIONS 3 and 1 4 to provide monitoring capability which provides diversity of protection to the mode switch interlocks. 3/4.3.7.7 TRAVERSING IN-CORE PROBE SYSTEM i 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 gamma flux distribution of the reactor core. The TIP system OPERABILITY is demonstrated by normalizing.all probes (i.e., detectors) prior to performing an LPRM calibration function. Monitoring core thermal limits may involve utilizing individual detectors to monitor selected areas of the reactor core, thus all detectors may not be required to OPERABLE. The OPERABILITY of individual detectors to be used for monitoring is demonstrated by comparing the detector (s) output with data obtained during the previous LPRM calibrations. PERRY - UNIT 1 8 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 recommen-dations 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 LIOUID EFFLUENT MONITORING INSTRUMENTATION The radioactive liquid effluent 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 in accordance with the procedures 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 instru-mentation 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 ef fluent instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases of gaseous ef fluents. The alarm setpoints for these instruments shall be calculated in accordance with the procedures in the 00CM to ensure that the alarm will occur prior to exceeding the limits of 10 CF.'? Part 20. This instrumentation also includes provisions for monitoring the concentrations of potentially explosive gas mixtures in the GASEOUS RADWASTE TREATMENT SYSTEM. The OPERABILITY and use of this instrumen-tation is consistent with the requirements of General Design Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. 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 PLANT SYSTEMS ACTUATION INSTRUMENTATION The plant systems actuation instrumentation is provided to initiate action of the containment spray system in the event of a LOCA with high containment PERRY - UNIT 1 8 3/4 3-6
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BASES MONITORING INSTRUMENTATION (Continued) 3/4.3.9 PLANT SYSTEMS ACTUATION INSTRUMENTATION (Continued) pressure and the feedwater system / main turbine trip system in the event of a failure of the feedwater controller under maximum demand. The LPCI mode of the RHR system is automatically initiated on a high drywell pressure signal and/or a low reactor water level, level 1, signal. The containment spray system will then actuate automatically following high drywell and high con-tainment pressure signals. A 10-minute minimum and a 11.5-minute maximum time delay exists between initiation of LPCI and containment spray actuation. The suppression pool makeup system is automatical.ly initiated on a low suppres-sion pool water level signal with a concurrent LOCA signal or following a specified time delay after receipt of a LOCA signal. A high reactor water level, level 8, signal will actuate the feedwater system / main turbine trip system. v (o] %/ PERRY - UNIT 1 8 3/4 3-7 _
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f^X 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. An inoperable jet pump is not, in itself, a sufficient reason to declare 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. Jet pump failure can be detected by monitoring jet pump perfor . mance on a prescribed schedule for significant degradation. Recirculation loop flow mismatch limits are in compliance with 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 loop temperature must.also be within 50 F of the reactor pressure vessel coolant temperature to prevent thermal shock to the recirculation pump and recirculation nozzles. Since the coolant in gy 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 V difference was greater than 100 F. The objective of GE BWR plant and fuel design is to provide stable opera-tion'with margin over the normal operating domain. However, at the high power / low flow corner of the operating domain, a small probability of limit cycle neutron flux oscillations exists depending on combinations of operating condi-tions (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 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 conservative 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 Figure 3.4.1.1-1 (Reference 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 a decay ratio greater than or equal to 0.8. t ("%l
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REACTOR COOLANT SYSTEM BASES RECIRCULATION SYSTEM (Continued) Neutron flux noise limits are also established to ensure early detection of limit cycle neutron flux oscillations. 8WR 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 single and dual recirculation loop operation. Neutron flux noise levels which signifi-cantly bound these values are considered in the thermal / mechanical design of GE BWR fuel and are found to be of negligible consequence (Reference 2). In addition, stability tests at operating BWRs have demonstrated that when stabil-ity 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 sufficient 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 flow can be applied over a range of core flows. To maintain a reasonable variation between the low flow and high flow ends 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 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 operation with two recirculation loops. Baseline data should be taken near the maximum rod line at which the majority of operation will occur. However, baseline data taken at lower red lines (i.e. , lower power) will result in a conservative value since the neutron flux noise level is proportional to the power level at a given core flow. References (1) "BWR Core Thermal-Hydraulic Stability" Service Information Letter 380, Revision 1, February 1984. (2) G. A. Watford, " Compliance of the General Electric Boili,ng Water Reactor Fuel Designs to Stability Licensing Criteria," December 1982 (NEDE 22277-P). 3/4.4.2 SAFETY / RELIEF VALVES The safety valve function of the safety / relief valves (SRV) operate to prevent the reactor coolant system from being pressurized above the Safety Limit of 1325 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 upset transient. Any combination-of 6 SRVs operating in the relief mode and 7 SRVs operating in the safety made is acceptable. PERRY - UNIT 1 B 3/4 4-2
e' REACTOR COOLANT SYSTEM l ) V BASES SAFETY / RELIEF VALVES (Continued) Demonstration of the safety-relief valve lift settings will occur only during shutdown and will be performed in accordance with the provisions of Specification 4.0.5. The low-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 6 valves and lowering the opening setpoint of 2 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. 3/4 4.3 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.3.1 LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specification are provided to monitor and detect leakage from the reactor coolant pressure gs boundary. These detection systems are consistent with the recommendations of Regulatory Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection (v} 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 specified for UNIDENTIFIED 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 BOUNDARY LEAKAGE, the reactor will be shutdown to allow further investigation and corrective action. The Surveillance Requirements for RCS pressure isolation valves provide added assurance of valve integrity thereby reducing the probability of gross 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. l3 PERRY - UNIT 1 3 3/4 4-3
REACTOR COOLANT SYSTEM BASES 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 exceeding 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. 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 possible iodine spiking phenomenon which may occur following changes in THERMAL POWER. Operation with specific activity levels exceeding 0.2 microcuries per gram DOSE EQUIVALENT I-131 but less than or equal to 4.0 microcuries per gram DGSE EQUIVALENT I-131 must be restricted to no more than 800 hours per year, approximately 10 percent of the unit's yearly operating time, since these activity levels increase the 2 hour thyroid dose at the site boundary by a factor of up to 20 following a postulated steam line rupture. The reporting of cumulative operating time over 500 hours in any 6 month consecutive period with greater than 0.2. micro-curies per gram DOSE EQUIVALENT I-131 will allow sufficient time for Commission evaluation of the circumstances prior to reaching the 800 hour limit. 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 cnanges may be permissible if justified by the data obtained. PERRY - UNIT 1 B 3/4 4-4
n REACTOR COOLANT SYSTEM BASES l' SPECIFIC ACTIVITY (Continued) Closing the main steam line isolation valves prevents the release of activity i to the environs should a steam li~ne rupture occur outside containment. The sur-veillance requirements provide adequate assurance that excessive specific activity levels in the reactor coolant'will be detected in sufficient time to take corrective action. 3/4.4.6 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 transier ts, reactor trips, and startup and shutdown operations. The various categories of load cycles
' used for design purposes are provided in Section 3.9 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. t The operating limit curves of Figure 3.4.6.1-1 are derived from the frac-ture toughness requirements of 10 CFR 50 Appendix G and ASME Code Section III, Appendix G. The curves are based on the RTNOT and stress intensity factor information for the reactor vessel components. Fracture toughness limits and the basis for compliance are more-fully discussed in Chapter 5 of the FSAR.
Q The reactor vessel materials have been tested to determine their initial RTNDT. 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 RTNOT. Therefore, an adjusted reference temperature, ' 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 recommenoa-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 assumed j shift in RT NDT f r the end of life fluence. The actual shift in RTNDT f the vessel material will be established period-ically during operation by removing and evaluating, in accordance with 10 CFR 50, Appendix H, irradiated flu'x wires installed near the inside wall of the reactor vessel in the core area. The irradiated flux wires can be used with confidence in predicting reactor vessel material transition temperature shift. The operat-ing limit curves of Figure 3.4.6.1-1 shall be adjusted, as required, on the basis of the flux wires data and recommendations of Regulatory Guide 1.99, Revision 1. 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 requirements 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 Os 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 l Appendix H to 10 CFR Part 50. 1 PERRY'- UNIT 1 B 3/4 4-5
REACTOR COOLANT SYSTEM BASES PRESSURE / TEMPERATURE LIMITS (Continued) A sensitivity study was performed for a BWR Class 3 plant to investigate the ef f ects of increasing the initial reactor pressure relative to the initial value used in the overpressure protection analysis on the peak system pressure. This analysis showed that increasing the initial operating pressure results in an increase in peak system pressure that is less than half the initial pressure increase. For Perry, the Technical Specification limit on the high-reactor-pressure scram is 1064.7 psig. Therefore, since the vessel dome pressure used in the overpressurization analysis was 1045 psig, the maximum increase in the initial pressure would be limited to 50 psi, and the maximum peak system pres-sure increase during the overpressure design transient would be less than 25 psi. Recirculation pump trip has resulted in an increase of 2 to 6 psi in calcula-tions for other BWRs. These results indicate that considerable margin is avail-able to Perry before reaching the Code limit and that GDC 15 will be satisfied even if increased initial dome pressure and recirculatica pump trip are con-sidered. Since the Perry specific overpressure analysis (as well as all other transient analyses in Chapter 15 of the FSAR) were performed assuming an ini-tial dome pressure of 1045 psig, the Technical Specifications operating pres-sure limit is 1045 psig. 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 f-llowing 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 has been granted by the NRC pursuant to 10 CFR Part 50.55a(g)(6)(i). 3/4.4.9 RESIDUAL HEAT REMOVAL A single shutdown cooling mode loop provides sufficient heat removal capa-bility for removing core decay heat and mixing to assure accurate temperature 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. PERRY - UNIT 1 8 3/4 4-6 1
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l O O 10 20 30 40 Service Life (Years ) l Fast Neutron Fluence (E>l Mev) at !sT As a Function of Service Life
- l Bases Figure B 3/4 4.6-1
*At 90% of RATED THERMAL POWER and 90% availability l
l PERRY - UNIT 1 B 3/4 4-8
fh 3/4.5 EMERGENCY CORE COOLING SYSTEM BASES 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUT 00WN ECCS division 1 consists of the low pressure core spray system and low pressure coolant injection subsystem "A" of the RHR system and the automatic depressurization system (ADS) as actuated by ADS trip system "A" ECCS divi-sion 2 consists of low pressure cooiant injection subsystems "B" and "C" of the RHR system and the automatic depressurization system as actuated by ADS trip system "B". The low pressure core spray (LPCS) system and the low pressure coolant-injection (LPCI) 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 LPCS and LPCI are sources 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 LPCS and [3] x / LPCI systems will.be OPERABLE when required. testable and full flow can be. demonstrated by recirculation through a test Although all active components are loop during reactor operation, a complete functicnal 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. ECCS division 3 consists of the high pressure core spray system. The high pressure core spray (HPCS) 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 HPCS system permits the reactor to be shut down while maintaining suf ficient reactor vessel water level inventory until the vessel is depressurized. The HPCS system operates over a range of 1177 psid, differential pressure.between reactor vessel and HPCS suction source, to O psid. The capacity of the system is selected to provide the required core
- cooling. The HPCS pump is designed to deliver greater than or equal to 517/
1550/6110 gpm at differential pressures of 1177/1147/200 psid. 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. O)
\
v PERRY - UNIT 1 8 3/4 5-1 _
3/4.5 EMERGENCY CORE COOLING SYSTEM BASES ECCS-OPERATING and SHUTDOWN (Continued) With the HPCS system inoperable, adequate core. cooling is assured by the OPERABILITY of the redundant and diversified automatic depressurization system and both the LPCS and LPCI systems. In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in the safety analysis, will automatically provide makeup at reactor operati.ng pressures on a reactor low water level condition. The HPCS out-of service period of 14 days is based on the demonstrated OPERA 8ILITY of redundant and diversified low
. pressure core cooling systems.
The surveillance requirements provide adequate assurance that the HPCS system will be OPERABLE when required. Flow and total developed head values for surveillance testing include system losses to ensure design requirements are met. 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 shut-down. The pump discharge piping is maintained full to prevent water hammer damage and to provide cooling at the earliest moment. Upon failure of the HPCS system to function properly after a small break loss of-coolant accident, the automatic depressurization system (ADS) auto-matically causes selected 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 conservatively required to be OPERABLE whenever reactor vessel pressure exceeds 100 psig even though LPCS flow is 6110 gpm rated flow at 128 psid, and LPCI flow is 7100 gpm rated flow at 24 psid. ADS automatically controls eight selected safety-relief valves although the safety analysis only takes credit for seven 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 POOL The supression pool is required to be OPERABLE as part of the ECCS to ensure that a sufficient supply of water is available to the HPCS, LPCS and LPCI systems in the event of a LOCA. This limit on suppression pool minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression pool in OPERATIONAL CONDITIONS 1, 2 or 3 is required.by Specification 3.6.3.1. Repair work might require making the suppression pool 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 pool must be made inoperable, including draining, in OPERATIONAL CONDITIONS 4 or 5. In OPERATIONAL CONDITION 4 and 5 the suppression pool minimum required water volume is reduced because the reactor coolant is maintained at or below 200 F. Since pressure suppression is not required below 212 F, the minimum required water volume is based on NPSH, recirculation volume, and vortex prevention plus a safety margin for conservatism. PERRY - UNIT 1 8 3/4 5-2 t
,m 3.4.6 CONTAINMENT SYSTEMS (V)
BASES 3/4.6.1 CONTAINMENT 3/4.6.1.1 PRIMARY CONTAINMENT INTEGRITY
' PRIMARY CONTAINMENT INTEGRITY ensures that the release of radioactive
.aterials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed 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 CONTAINMENT LEAKAGE The limitations on containment leakage rates ensure that the total contain-ment leakage volume will not exceed the value assumed in the accident analyses at the peak accident pressure of 11.31 psig, P . As an added conservatism, the 3 measured overall fategrated leakage rate is further limited to less than or equal to 0.75 L, during performance of the periodic tests to account for pos-sible degradation of the containment leakage barriers between leakage tests. Overall integrated leakage rate means the leakage rate which obtains from [m') a summation of leakage through all potential leakage paths. Where a leakage
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j path contains more than one valve, fitting, or component in series, the leakage for that path will be that leakage of the worst leaking valve, fitting, or com-ponent and not the summation of the leakage of all valves, fittings, or ccm-ponents in that leakage path. 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 to 10 CFR 50 with the exception of exemptions granted for testing the airlocks after each opening. 3/4.6.1.3 CONTAINMENT AIR LOCKS The limitations on closure and leak rate for the containment. air locks are required to meet the restrictions on PRIMARY CONTAINMENT INTEGRITY and the containment leakage rate given in Specifications 3.6.1.1 and 3.6.1.2. The specification makes allowances for the fact that there may be long periods of time when the air locks will be in a closed and secured position daring reactor operation. Only one closed door in each air lock is required to maintain the integrity of the containment. The air supply to the containment air lock and seal system is the service and instruinent air system. The system consists cf two 100%. capacity air com-(p t pressors per unit and can be cross-connected. This system is redundant and ( extremely reliable and provides system pressure indication in the control room. PERRY - UNIT 1 B 3/4 6-1
CONTAINMENT SYSTEMS BASES l 3/4.6.1.4 MSIV LEAKAGE CONTROL SYSTEM Calculated doses resulting from the maximum leakage allowance for the main steam line 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 in the leak tightness of the MSIV's such that the specified leakage requirements have not always been maintained continuously. The requirement for the leakage control system will reduce the untreated leakage from the MSIV's when isolation of the primary system and containment is required. 3/4.6.1.5 CONTAINMENT 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 the containment will withstand the maximum pressure of 15 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 CONTAINMENT INTERNAL PRESSURE The limitations on primary containment to secondary containment differen-tial pressure ensure that the primary containment peak pressure of 11.31 psig does not exceed the design pressure of 15.0 psig during LOCA conditions or that the external pressure differential does not exceed the design maximum external pressure differential of +0.8 psid. The limit of -0.1 to +1.0 psid for initial positive primary containment to secondary containment pressure will limit the primary containment pressure to 11.31 psid which is less than the design pres-sure and is consistent with the safety analysis. 3/4.6.1.7 CONTAINMENT AVERAGE AIR TEMPERATURE The limitation on containment average air temperature ensures that the containment peak air temperature does not exceed the design temperature of 185 F during LOCA conditions and is consistent with the safety analysis.
- 3/4.6.1.8 DRYWELL AND CONTAINMENT PURGE SYSTEM The use of the drywell and containment purge lines is restricted to the 42-inch outboard and 18-inch purge supply and exhaust isolation valves. These valves will close during 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. The term sealed closed as used in this context means that the valve is secured in its closed position by deactivating the valve motor operator, and does not pertain to injecting seal water between the isolation valves by a seal water system.
PERRY - UNIT 1 B 3/4 6-2 < 1
~O CONTAINMENT SYSTEMS BASES ORYWELL AND CONTAINMENT PURGE SYSTEM (Continued)
Leakage integrity tests with a maximum allowable leakage rate for purge supply and exhaust isolation valves will provide early indication of resilient material seal degradation and will allow the opportunity :for repair before gross leakage failure develops. The 0.60 L leakage limit shall not be a exceeded when the leakage rates determined by the leakage integrity tests of these valves are added to the previously determined total for all valves and penetrations subject to Type B and C tests. 3/4.6.1.9 FEEDWATER LEAKAGE CONTROL SYSTEM The OPERABILITY of the feedwater leakage control system is required to meet the restrictions on overall containment leak rate assumed in the accident analyses. 3/4.6.2 ORYWELL 3/4.6.2.1 DRYWELL INTEGRITY Drywell integrity ensures that the steam released for the full spectrum
,O of drywell pipe breaks is condensed inside the primary containment either by the suppression pool or by containment spray. By utilizing the suppression l ( pool as a heat sink, energy released-to the containment is minimized and the severity of the transient is reduced.
3/4.6.2.2 DRYWELL BYPASS LEAKAGE The limitation on drywell bypass leakage rate is based on having contain-ment spray OPERABLE. It ensures that the maximum leakage which could bypass the suppression pool during an accident would not result in the containment l exceeding its design pressure of 15.0 psig. -The integrated drywell leakage value is limited to 10% of the design drywell leakage rate. The limiting case accident is a very small reactor coolant system break which will not automatically result in a reactor depressurization. The long term differential pressure created between the drywell and containment will result in a significant pressure buildup in the containment due to this' bypass leakage. 3/4.6.2.3 DRYWELL AIR LOCK The limitations on closure for the drywell air lock i.e required to meet the restrictions on DRYWELL INTEGRITY and the drywell leakage rate given in Specifications 3.6.2.1 and 3.6.2.2. The specification makes allowances for the fact that there may be long periods of time when the air lock will be in a closed and secured position during reactor operation. Only one closed door in the air lock is required to maintain the integrity of the drywell. The air supply to the drywell air lock and seal system is the service and instrument air system. This system consists of two 100% capacity air compressors per unit and can be cross-connected. This system is redundant and extremely reliable and provides system pressure indication in the control room. PERRY - UNIT 1 B 3/4 6-3 ._
CONTAINMENT SYSTEMS BASES 3/4.6.2.4 DRYWELL STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the drywell will be maintained comparable to the original design specification for the life of the unit. A visual inspection in conjunction with Type A leakage tests is sufficient to demonstrate this capability. 3/4.6.2.5 ORYWELL INTERNAL PRESSURE The limitations on drywell-to-containment differential pressure ensure that the drywell peak calculated pressure of 21.8 psig does not exceed the design pressure of 30.0 psig and that the containment peak pressure of 11.31 psig does not exceed the design pressure of 15.0 psig during LOCA conditions. The maxi-mum external drywell pressure differential i. limited to +0.5 psid, well below the 2.4 psid at which suppression pool water w '1 be forced over the wier wall and into the drywell. The limit of 2.0 psid for initial positive drywell to containment pressure will limit the drywell pressure to 21.8 psig which is less than the' design pressure and is consistent with the safety analysis. 3/4.6.2.6 DRYWELL AVERAGE AIR TEMPERATURE The limitation on drywell average air temperature ensures that peak drywell temperature does not exceed the design temperature of 330 F during LOCA condi-tions and is consistent with the safety analysis. 3/4.6.3 DEPRESSURIZATION SYSTEMS The specifications of this section ensure that the drywell and containment pressure will not exceed the design pressure of 30 psig and 15 psig, respec-tively, during primary system blowdown from full operating pressure. The suppression pool water volume must absorb the associated decay and structural sensible heat released during a reactor blowdown from 1045 psig. Using conservative parameter inputs, the maximum calculated containment pressure during and following a design basis accident is below the containment design pressure of 15 psig. Similarly the drywell pressure remains below the design pressure of 30 psig. The maximum and minimum water volumes for the suppression pool are 118,548 cubic feet and 115,612 cub _ic feet, respectively. These values include the water volume of the containment pool, horizontal vents, and weir annulus. Testing in the Mark III Pressure Suppression Test Facility and analysis have assured that the suppression pool temperature will not rise above 185 F for the full range of break sizes. Should it be necessary to make the suppression pool inoperable. this shall only be done as specified in Specification 3.5.3. Experimental data indicates that effective steam condensation without excessive load on the containment pool walls will occur with a quencher device and pool temperature below 200 F during relief valve operation. Specifications have been placed on the envelope of reactor operating conditions to assure the bulk pool temperature does not rise above 185 F in compliance with the containment structural design criteria. PERRY - UNIT 1 B 3/4 6-4
1 CONTAINMENT SYSTEMS V BASES DEPRESSURIZATION SYSTEMS (Continued) In addition to the limits on temperature of the suppression 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 al1 available means to close,the valve, (2) initiate suppression pool water cooling, and (3) if other safety-relief valves are used to depressurize the reactor, their. discharge shall be separated from that of the stuck-open safety relief valve, where possible, to assure mixing and uniformity of energy insertion to the pool.
.The containment spray system consists of two 100% capacity loops, each with three spray rings located at different elevations about the inside circum-ference of the containment. 'RHR pump A supplies one loop and RHR pump 8 sup-plies the other. RHR pump C cannot supply the spray system. Dispersion of the flow of water is effected by 345 nozzles in each loop, enhancing the condensa-tion of water vapor in the containment volume and preventing overpressurization.
Heat rejection is through the RHR heat exchangers. The turbulence caused by the spray system aids.in mixing the containment air volume to maintain a homogeneous mixture for H2 control.
. __ The suppression pool cooling function is a mode of the RHR system and
~ functions.as part of the containment heat removal system. The purpose of the system is to ensure containment integrity following a LOCA' by preventing exces-sive containment pressures and temperatures. The suppression pool cooling mode is designed to limit the long term bulk temperature of the pool to 185 F con-sidering all of the post-LOCA energy additions. The suppression pool cooling trains, being an integral part of the RHR system, are redundant, safety-related component systems that are initiated following the recovery of the reactor vessel water level by ECCS flows from the RHR system. Heat rejection to the emergency service water is accomplished in the RHR heat exchangers.
The suppression pool make-up system provides water from the upper-containment pool to the suppression pool by gravity flow through two 100% capaci?.y dump lines following a.LOCA. The quantity of water provided is sufficient to account for all conceivable post-accident entrapment volumes, ensuring the long term energy sink capabilities of the suppression pool and maintaining the water coverage over the uppermost drywell vents. During refueling, there will be administrative control to ensure the make-up dump valves will not be opened. 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES The OPERABILITY of the 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 to 10 CFR 50. Containment and drywell isolation within the time limits specified for those isolation valves designed ( to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.
. PERRY - UNIT 1 8 3/4 6-5
[ CONTAINMENT SYSTEMS (,/ BASES 3/4.6.6 SECONDARY CONTAINMENT (Continued) boundary radiation doses associated with containment leakage. The operation of this system and resultant iodine removal capacity are consistent with the j assumptions used in the LOCA analyses. Continuous operation of the system with the heaters OPERABLE for 10 hours during each 31 day period is sufficient to reduce the buildup of moisture on the absorbers and HEPA filters. 3/4.6.7 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 containment below its flammable limit during post-LOCA conditions. The containment hydrogen recombiner system 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 combustible gas mixing system is provided to ensure adequate mixing of the containment atmosphere following a LOCA. This mixing action will prevent localized accumulations of hydrogen from exceeding the flammable limit. Two 100% combustible gas mixing subsystems are the primary means of'H 2 /
) control within the drysell, purging hydrogen produced following a LOCA into the / containment volume. Hydrogen generated from the metal-water reaction and radiolysis is assumed to evolve to the drywell atmosphere and form a homogenous mixture through natural forces and mechanical turbulence (ECCS pipe break flow).
The combustible gas mixing system forces drywell atmosphere into the containment. The hydrogen control system is consistent with the recommendations of Regulatory Guide 1.7, " Control of Combustible Gas Concentrations in Containment Following a LOCA", November, 1978. The OPERABILITY of the primary containment /drywell hydrogen igniters ensures that hydrogen combustion can be accomplished in a controlled manner following a degraded core event that produces hydrogen concentrations in excess of LOCA conditions. Inaccessible areas are defined as areas that have high radiation levels during the entire refueling outage period. These areas are the heat exchanger, filter demineralizer, backwash, and holding pump rooms of the RWCU system. CN \ ) NJ PERRY - UNIT 1 B 3/4 6-7
3/4.7 PLANT SYSTEMS BASES 3/4.7.1 COOLING WATER SYSTEMS The OPERABILITY of the service water systems ensures that sufficient cooling capacity'is available for continued operation of safety related equipment during normal and accident conditions. The redundant cooling capacity of these systems, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits. 3/4.7.2 CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM The OPERABILITY cf the control room emergency recirculation 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 per-sonnel during and following all design basis accident conditions. Continuous operation of the system with the heaters OPERABLE for 10 hours during each 31 day period is sufficient to reduce the buildup of moisture on the adsorbers
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and HEPA filters. The 0PERABILITY of this system in conjunction with control room design provisions is based on limiting the radiation 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. (' 3/4.7.3 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 System equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor pressure exceeds 150 psig. This pressure is substantially below that for which the low pressure core cooling systems can provide adequate core cooling for events requiring the RCIC system. The RCIC system specifications are appliccble during OPERATIONAL CONDITIONS 1, 2 and 3 when reactor vessel pressure exceeds 150 psig because RCIC is the primary non-ECCS source of emergency core cooling when the reactor is pressurized. With the RCIC system inoperable, adequate core cooling is assured by the OPERABILITY of the HPCS system and justifies the specified 14 day out of-service period. The surveillance requirements provide 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 cooling at-the earliest possible moment. PERRY -~ UNIT 1 B 3/4 7-1
PLANT SYSTEMS BASES 3/4.7.4 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 snubbers 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 on a given system and is determined by the number of inoperable snubbers found during an inspection of each system. In order to establish the inspection frequency for each type of snubber on a safety-related 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 failure during an assumed initiating event. Inspections performed before that interval has elapsed may be used as a new reference point to determine the next inspection. However, the results of such early inspections performed before the original required time interval has elasped (nominal time less 25%) may not be used to lengthen the required inspec-tion interval. Any inspection whose results required a shorter inspection interval will override the previous schedule. The acceptance criteria are to be used in the visual inspection to I determine OPERABILITY of the snubbers. To provide assurance of snubber functional reliability one of three functional testing methods is used with the stated acceptance criteria: PERRY - UNIT 1 8 3/4 7-2 t
I 1 l /9 I t PLANT SYSTEMS
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BASES SNUB 8ERS (Continued)
- 1. Functionally test 10% of a type of snubber with an additional 10%
tested for each functional testing failure, or
- 2. Functionally test a sample size and determine sample acceptance or rejection using Figure 4.7.4-1, or
- 3. Functionally test a representative sample size and determine sample acceptance or rejection using the stated equation.
Figure 4.7.4-1 was developed using "Wald's Sequential Probability Ratio Plan" as described in " Quality Control and Industrial Statistics" by Acheson J. Duncan. Permanent or other exemptions from the surveillance program for individual snubbers may be granted by the Commission if a justifiable basis for exemption is presented and, if applicable, snubber life destructive testing was performed to qualify the snubbers for the applicable design conditions at either the com-pletion of their fabrication or at a subsequent date. Snubbers so exempted shall be lised in the list of individual snubbers indicating the extent of the /7 exemptions. \'-'] 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 area, etc.). The requirement to monitor the snubber service life is included to ensure that the snubbers periodically undergo a performance evaluation in view of their age and operating conditions. These records will provide statis-tical bases for future consideration of snubber service life. 3/4.7.5 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 materici 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 mee' qism. \ L.- ) PERRY - UNIT 1 B 3/4 7-3
l l l PLANT SYSTEMS BASES 3/4.7.6 MAIN TURBINE BYPASS SYSTEM The main turbine bypass system is required to be OPERABLE consistent with the assumptions of the feedwatt controller failure analysis in FSAR Chapter 15. 3/4.7.7 FUEL HANDLING BUILDING FUEL HANDLING BUILDING INTEGRITY ensures that the release of radioactive materials from the Fuel Handling Building following a fuel handling accident will be consistent with the accident analyses. The Fuel Handling Building Ventilation Exhaust System ensures that no significant fraction of the radioactive release from a postulated fuel handling accident could escape untreated. O l l O 1 i PERRY - UNIT 1 8 3/4 7-4
(A) V 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 DISTRIBUTION SYSTEMS The OPERABILITY of the A.C. and D.C. power sources and associated distribution systems during operation ensures that sufficient power 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 condi-tions 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 commensurate with the level of degradation. The OPERABILITY of the power sources are consistent with the initial condition assumptions of the safety analyses and are based upon maintaining at least Division 1 or 2 of the onsite A.C. and 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. Division 3 supplies the high pressure core spray (HPCS) system only.
/~N (v) 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 modified by plant specific analysis and diesel generator manufacturer recommendations. When diesel generator Division 1 or Division 2 is inoperable, there is an additional ACTION requirement to verify that all required systems, subsystems, trains, components and devices, that depend on the remaining OPER-ABLE diesel generator Division 1 or Division 2 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 func-tion of critical systems d uring the period diesel generator Division 1 or Division 2 is inoperable. The term verify as used in this context mcans to administratively 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 i (1) the facility can be maintained in the shutdown or refueling condition for extended time periods and (2) sufficient instrumentation and control capabil-:ty 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 recommendations of Regulatory Guide 1.9, " Selection of Diesel Generator Set Capacity for Standby Power Supplies," March 10, 1971, and Regulatory Guide 1.108, " Periodic Testing of O(j Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," Revision 1, August 1977 as modified by plant specific analysis and diesel generator manufacturer recommendations. l l l PERRY - UNIT 1 B 3/4 8-1
ELECTRICAL POWER SYSTEMS BASES A.C. SOURCES, D.C. SOURCES and ONSITE POWER DISTRIBUTION SYSTEMS (Continued) The surveillance requirements for demonstrating the OPERABILITY 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 Practice for Maintenance, Testing, and Replacement of Large Lead Storage Bat-teries for Generating Stations and Substations." 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 time 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 not more than .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 grav-ity, 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 con-nected 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 to 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 accept-cble 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 l l PERRY - UNIT 1 8 3/4 8-2 ,
ELECTRICAL POWER SYSTEMS J BASES 3/4.8.4 ELECTRICAL EOUIPMENT PROTECTIVE DEVICES Containment electrical penetrations and penetration conductors are protected by demonstrating the OPERABILITY of primary and backup overcurrent j protection circuit breakers by periodic surveillance. The surveillance requirements applicable to lower voltage circuit breakers provides assurance of breaker reliability by testing at least one representa- ^ a tive sample of each manufacturers brand of circuit breake~r. Each manufacturer's molded case and metal case circuit breakers are grouped into representative samples which are then 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 i groups and treat each group as a separate type of breaker for surveillance 3 purposes. d l I f t I l PERRY - UNIT 1 B 3/4 8-3 i-
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l 3/4.9 REFUELING OPERATIONS ( BASES 3/4.9.1 REACTOR MODE SWITCH Locking the-0PERABLE 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 t'o excessive radioactivity. i , 3/4.9.2 INSTRUMENTATION 1 The OPERABILITY of at least two source range monitors ensures that redundant monitoring capability is available to detect changes-in the react.ivity condition of the core. , 3/4.9.3 CONTROL R00 POSITION i The. requirement that all control rods be inserted during CORE' ALTERATIONS b ensures that fuel will not be loaded into a cell without a control rod, athough one rod may be withdrawn under the control of the reactor mode switch refuel
) position one rod-out interlock.
i
'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.
3 3/4.9.5 COMMUNICATIONS l The requirement for communications capability ensures that refueling station ! personnel can be promptly informed of significant changes in the facility status i or core reactivity condition during movement of fuel within the reactor' pressure
- ' vessel.
3/4.9.6 REFUELING PLATFORM The OPERABILITY requirements ensure that (1) the refueling platform will be used for handling control rods and fuel assemblies within the reactor pressure , vessel, (2) each crane and hoist has sufficient load capacity for handling fuel I assemblies and control rods, and (3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertently engaged during lifting operations. PERRY - UNIT 1 8 3/4 9-1 i
REFUELING OPERATIONS BASES 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE POOL, NEW FUEL STORAGE VAULTS, AND UPPER CONTAINMENT FUEL POOL The restriction on movement of loads which would result in excess of 4000 foot pounds of impact energy if dropped over fuel assemblies in the pools ensures that in the event this load is dropped 1) the activity release will be less than that assumed in the safety analysis, 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 STORAGE AND UPPER CONTAINMENT FUEL P0OLS 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 ROD 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 inadvertant 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 COOLANT CIRCULATION The requirement that at least one residual heat removal loop be OPERABLE and in operation 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) sufficient 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 wculd be 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 than 22 feet 10 inches feet of water above the reactor vessel flange ensures that a single failure of the operating loop will not result in a com-plete loss of residual heat removal capability. With the reactor vessel head removed and 22 feet 10 inches of water above the reactor 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. 3/4.9.12 INCLINED FUEL TRANSFER SYSTEM The purpose of the inclined fuel transfer system specification is to control personnel access to those potentially high radiation areas immediately adjacent to the system and to assure safe operation of the system. PERRY - UNIT 1 B 3/4 9-2
I (' 3/4.10 SPECIAL TEST EXCEPTIONS b) BASES 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY /DRYWELL INTEGRITY The requirements for PRIMARY CONTAINMENT INTEGRITY and DRYWELL INTEGRITY are not applicable during the period when open vessel tests are being performed during the low power PHYSICS TESTS. 3/4.10.2 R00 PATTERN 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 Performance of shutdown margin demonstrations with the vessel head removed requires additional restrictions in order to ensure that criticality does not A occur. These additional restrictions are specified in this LCO. I (d 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 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. r V PERRY - UNIT 1 8 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 radio-active materials released in liquid waste effluents to UNRESTRICTED AREAS will
, n be less than the conce'tration levels specified in 10 CFR Part 20, Appendix B, Table II, Column 2. This limitation provides additional assurance that the i l
levels of radioactive materials in bodies of water in UNRESTRICTED AREAS will result in exposures within (1) the Section II. A design objectives of Appendix I, 10 CFR 50, to a MEMBER OF THE PUBLIC, and (2) the limits of 10 CFR 20.106(e) to the population. The concentration Ifmit for dissolved or entrained noble gases is based upon the assumption that Xe-135 is the controlling 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. This specification applied to the release of radioactive materials in liquid effluents from all units at the site. The required detection capabilities for radioactive materals in liquid waste samples are tabulated in terms of the lower limits of detection (LLDs). ( Detailed discussion of the LLO, and other detection limits, can be found in: (1) Currie, L. A. . , " Lower Limit of Detection: Definition and Elabora-tion of a Proposed Position for Radiological Effluent and Environmental Measurements," NUREG/CR-4007 (September, 1984). (2) 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 I,10 CFR Part 50. The Limiting 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 Appendix I which assure that the releases of radioactive material in liquid effluents to UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." Also, for fresh water sites with drinking water supplies which 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 141. The dose calculations in the ODCM implement 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 equations specified in the 00CM for calculating the doses PERRY - UNIT 1 B 3/411-1 ._
RADI0 ACTIVE EFFLUENTS BASES 3/4.11.1.2 00SE (Continued) due to the actual release rates of radioactive materials in liquid effluents are consistent with the methodology provided in Regulatory Guide 1.109, " Cal-culation 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 Guic;e 1.113, " Estimating Aquatic Dis-persion of Effluent from Accidental and Routine Reactor Releases for the Purpose of Implementing Appendix I," April 1977. This specification applies to the release of liquid effluents from each reactor at the site. For units with shared radwaste treatment systems, the liquid effluerts from the shared system are proportioned among the units sharing that system. 3/4.11.1.3 LIQUID RA0 WASTE 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 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 speci-fication implements the requirements of 10 CFR Part 50.36a, 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 limit governing the use of appropriate portions of the liquid radwaste treatment system were speci-fied 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. This specification applies to the release of liquid effluents from each reactor at the site. For units with shared radwaste treatment systems, the liquid effluents from the shared system are proportioned among the units sharing the system. 3/4.11.1.4 LIQUID HOLDUP TANKS The tanks listed in this specification include all those outdoor tanks con-taining radioactive material that are not surrounded by liners, dikes, or walls capable of holding the contents and that do not have 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 limit:; 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. O PERRY - UNIT 1 B 3/4 11-2
[ \ / RADI0 ACTIVE EFFLUENTS BASES 3/4.11.2 GASEOUS EFFLUENTS 3/4.11.2.1 DOSE RATE This specification is provided to ensure that the dose any time at and beyond the SITE B0UNDARY from gaseous effluents from all units on the site will be within-the annual dose limits of 10 CFR Part 20 for UNRESTRICTED AREAS. The annual dose rate limits are those associated with the concentrations of those MPCs as described in Regulatory Guide 1.109. 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 the MEMBER OF THE PUBLIC will 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 appropriate occupancy factors, shall be given in the ODCM. 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 /G than or equal to 3000 mrems/ year to the skin. 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. This specification applies to the release of radioactive materials in gaseous effluents from all reactors at the site. The required detection capa-bilities for radioactive material in gaseous waste samples are tabulated in terms of the lower limit of detection (LLDs). Detailed discussion of the LLD and other detection limits can be found in: (1) 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). (2) 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 UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." The Surveillance Requirements implement the requirements in Section III.A of 3 Appendix I that conformance with the guides of Appendix I be shown by calcu-N / lational procedures based on models and data such that the actual exposure of PERRY - UNIT 1 8 3/4 11-3
RADIOACTIVE EFFLUENTS BASES 3/4.11.2.2 DOSE - NOBLE GASES (Continued) a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially underestimated. The dose calculations established in the 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 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," Revi-sion 1, July 1977. The ODCM equations provided for determining the air doses at and beyond the SITE BOUNDARY are made using meteorological conditions con-current with the time of release of radioactive materials in gaseous effluents or are based upon the historical average atmospheric conditions. This specification applies to the release of radioactive materials in gaseous effluents from each reactor at the site. For units with shared rad-waste treatment systems, the gaseous effluents from the shared system are proportioned among the units sharing that system. 3/4.11.2.3 DOSE - IODINE-131, IODINE-133, TRITIUM AND RADIONUCLIDES IN PARTICULATE FORM 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 assure that the releases of radioactive materials in gaseous effluents to UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." The ODCM calculational methods specified in the Surveillance Requirements imple-ment 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 ODCM calculational methods for calculating the doses due to the actual release rates of the subject materials are consietent with the methodology provided in Regu-latory 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 Ef fluents in Routine Releases from Light-Water-Cooled Reactors," Revision 1, July 1977. These equations also provide for determining the actual doses using meteorological conditions concurrent with the time of release of radio- l active materials in gaseous effluents or are based upon the historical average i atmospheric conditions. The release rate specifications for iodine-131, l iodine-133, tritium and radionuclides in particulate form are dependent on the I existing radionuclide pathway to man in the areas at and beyond the SITE l BOUNDARY. The pathways which were examined in the development of these PERRY - UNIT 1 B 3/4 11-4
[ } RADI0 ACTIVE EFFLUENTS
%./
BASES 3/4.11.2.3 DOSE - IODINE-131, 10 DINE-133, TRITIUM AND RADIONUCLIDES IN PARTICULATE FORM.(Continued) calculations were: (1) individual inhalation 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. This specification applies to the release of radioactive materials in gaseous effluents from each reactor at the site. For units with shared rad-waste treatment systems, the gaseous effluents from the shared system are proportioned among the units sharing that system. , 3/4.11.2.4 and 3/4.11.2.5 GASEOUS RADWASTE TREATMENT (0FFGAS) SYSTEM AND VENTILATION EXHAUST TREATMENT SYSTEMS The OPERABILITY of the GASEOUS RADWASTE TREATMENT (OFFGAS) SYSTEM and the VENTILATION EXHAUST TREATMENT SYSTEMS ensures that the systems will be available for use whenever gaseous effluents require treatment prior to release to the environment. The requirement that the appropriate portions of the systems be used, when specified, provides reasonable assurance that the releases of (A) k/ radioactive materials in gaseous effluents will be kept "as low as is reason-ably achievable." This specification implements the requirements of 10 CFR Part 50.36a, General Design Criterion 60 of Appendix A to 10 CFR Part 50, and the design objectives given in Section II.D 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.8 and II.C of Appendix I,10 CFR Part 50, for gaseous effluents. This specification applies to the release of radioactive materials in gaseous effluents from each reactor at the site. For units with shared rad-waste treatment systems, the gaseous effluents from the shared system are proportional among the units sharing that system. 3/4.11.2.6 EXPLOSIVE GAS MIXTURE This specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the offgas holdup system is maintained below the flammability limits of hydrogen. Maintaining the concentra-tion of hydrogen below its flammability limit provides assurance that the releases 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 a o) ( (/ MEMBER OF THE PUBLIC at and beyond the SITE BOUNDARY will not exceed a small fraction of the limits of 10 CFR Part 100 in the event this effluent is inad-l vertently discharged directly to the environment without treatment. This specification implements the requirements of General Design Criteria 60 and 64 of Appendix A to 10 CFR Part 50. PERRY - UNIT 1 B 3/4 11-5 1
RADI0 ACTIVE EFFLUENTS BASES 3/4.11.3 SOLID RADI0 ACTIVE WASTE This specification implements the requirements of 10 CFR Part 50.36a and 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, mixing and curing times. 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 when-ever the calculated doses due to releases of radioactivity and to radiation from uranium fuel cycle sources exceed 25 mrems to the whole body or any organ, except the thyroid, which shall be limited to less than or equal to 75 mrems. For sites containing up to four reactors, it is highly unlikely that the result-ant 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 units including outside stor-age tanks, etc. are kept small. The Special Report will describe a course of action that should result in the limitation of the annual dose to a MEMBER OF THE PUBLIC to within the 40 CFR Part 190 limits. For the purposes of the Spe-cial Report, it may be assumed that the dose commitment to the MEMBER OF THE PUBLIC from other uranium fuel cycle sources is negligible, with the exception that dose contributions from other nuclear fuel cycle facilities 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 conditions resulting in violation of 40 CFR Part 190 have not already been corrected), in accordance with the provisions of 40 CFR 190.11 and 10 CFR 20.405c, is con-sidered 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 requirements for dose limitation of 10 CFR Part 20, as addressed in Specifications 3.11.1.1 and 3.11.2.1. An individual is not considered a MEMBER OF THE PUBLIC during any period in which he/she is engaged in carrying out any operation that is part of the nucleaa fuel cycle. O PERRY - UNIT 1 B 3/4 11-6 1
O t I 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING
%)
BASES 3/4.12.1 MONITORING PROGRAM The Radiological Envirromental Monitoring Program required by this specifi-cation provides representative measurements of radiation and of radioactive 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 plant operation. This monitoring program implements Section IV.8.2 of Appendix I to 10 CFR Part 50 and thereby supplements the Radiological Effluent Monitoring Program by verifying that the measurable concentrations of radio-active 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 monitoring program is provided by the Radiological Assessment Branch Technical Position on Environmental Monitoring, Revision 1, November 1979. The initially specified monitoring program will be effective for at least the first 3 years of commercial operation. Following this period, pro-gram 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 are considered optimum for routine environmental measurements (a) V in industrial laboratories. It should be recognized that the LLO is defined as an a priori (before the fact) limit representing the capability of a measure-ment system and not as an a posterinri (af ter the fact) limit for a particular measurement. Detailed discussion of the LLD, and other detection limits, can be found in: (1) 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). (2) HASL Procedure Manual, HASL-300 (revised annually). 3/4.12.2 LAND USE CENSUS 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 given in the ODCM are made if required by the results of the census. The best information from door-to-door survey, visual or aerial survey or from consulting with local agricultural authorities shall be used. This census satisfies the requirements of Sec-tion IV.8.3 of Appendix I to 10 CFR Part 50. Restricting the census to gar-dens of greater than 50 m2 provides assurance tnat significant exposure path-ways via leafy vegetables will be identified and monitored since a garden of this size is the minimum required to produce the quantity (26 Ag/ year) of leafy vegetables assumed in Regulatory Guide 1.109 for consumption by a child. O) (V determine this minimum garden size, the following assumptions were made: (1) 20% of the garden was used for growing broad leaf vegetation (i.e. , simi-To lar to lettuce and cabbage), and (2) a vegetation yield of 2 kg/m2, PERRY - UNIT 1 8 3/4 12-1 -
. _ .____. _ __- . _ . _ _ . ~ _ _ . _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _
I I IO 1 (
- l l
l l i ! l i e I i f 1 I i !, SECTION 5.0 DESIGN FEATURES ; i I i i O i r s f
?
4 l l . i l i s I I e l' O ; F r i f I I a
l l
) 5.0 DESIGN FEATURES V
5.1 SITE '
, 5.1.1 EXCLUSION AREA, UNRESTRICTED AREA FOR LIQUID EFFLUENTS, AND SITE BOUNDARY FOR GASEOUS EFFLUENTS Figure 5.1.1-1 shows the PNPP site area, including the meteorological tower.
The exclusion area boundary is 2900 feet from the center line of the reactor. All land within the exclusion area is jointly owned by the CAPC0 Group Companies. CEI controls the exclusion area; controls include mineral . rights for oil, gas, and salt. In addition, the U.S. Coast Guard provides control over the Lake Erie portion of the exclusion area. A railroad spur serves the plant, heading in an east north easterly direction from the railroad company right-of-way to the plant site. CEI owns the tracks and only railroad cars consigned to the PNPP are brought onto the site over this spur. s> Figure 5.1.1-1 also shows the liquid and gaseous effluent discharge locations as well as the plant SITE BOUNDARY for gaseous releases and the UNRESTRICTED AREA for liquid effluent releases. The dose rate and doses due to radioactive materials released in gaseous effluents from the site to areas at and beyond the SITE BOUNDARY shall be limited pursuant to Specification 3.11.2.1, 3.11.2.2, and 3.11.2.3. All gaseous effluent releases at PNPP are considered to be ground-level releases. The concentrations of radioactive materials /^; released in liquid effluents to UNRESTRICTED AREAS shall be limited pursuant y) to Specification 3.11.1.1. LOW POPULATION ZONE 5.1. 2 The low population zone shall be as shown in Figure 5.1.2-1. 5.2 CONTAINMENT
\
CONFIGURATION 5.2.1 The primary containment is a steel structure composed of a vertical right cylinder and an ellipsoidal dome. Inside and at the bottom of the primary con-tainment is a reinforced concrete drywell composed of a vertical right cylinder and a steel head which contains an approximately 18'3" deep water filled sup-pression pool connected to the drywell through a series of horizontal vents. The primary containment has a minimum net free air volume of 1,160,000 cubic feet. The drywell has a minimum net free air volume of 276,500 cubic feet. DESIGN TEMPERATURE AND PRESSURE 5.2.2 The containment and drywell are designed and shall be maintained for:
- a. Maximum internal pressure:
C/ 1. 2. Drywell 30 psig. Containment 15 psig. PERRY - UNIT 1 5-1
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DESIGN FEATURES' DESIGN TEMPERATURE AND PRESSURE (Continued)
- b. Maximum internal temperature:
- 1. Drywell 330 F.
- 2. Suppression pool 185 F.
- c. Maximum external to internal differential pressure:
- 1. Drywell 21 psid.
- 2. Containment 0.8 psid.
SECONDARY CONTAINMENT 5.2.3 The secondary containment consists of the annulus between the shield building and the primary containment and has a minimum free volume of 392,548 cubic feet.
- 5. 3 REACTOR CORE FUEL ASSEMBLIES 5.3.1 The reactor core shall contain 748 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 1.9 weight percent U-235. Reload fuel shall be similar in physical design to the initial core loading. CONTROL R00 ASSEMBLIES 5.3.2 The reactor core shall contain 177 control rod assemblies, each consisting of a cruciform array of stainless steel tubes containing 143.7 inches of baron carbide, 8 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 snall be maintained:
. In accordance with the code requirements specified in Section 5.2 of the FSAR, with allowance for nc< mal degradation pursuant to the applicable Surveillance Requirements,
- b. For a pressure of:
- 1. 1250 psig on the suction side of the recirculation pump.
PERRY - UNIT 1 5-4
( DESIGN FEATURES OESIGN PRESSURE AND TEMPERATURE (Continued)
- 2. 1650 psig from the recirculation pump discharge to the outlet side of the discharge block valve.
- 3. 1550 psig from the discharge block valve to the jet pumps.
.c. For a temperature of 575*F.
VOLUME 5.4.2 The total water and steam volume of the reactor vessel and recirculation system is approximately 19,000 cubic feet at a nominal steam dome saturation temperature of 549 F. 5.5 METEOROLOGICAL TOWER LOCATION
- 5. 5.1 The meteorological tower shall be located as shown on Figure 5.1.1-1.
- 5. 6 FUEL STORAGE CRITICALITY 5.6.1. The spent fuel storage racks are designed and shall be maintained with:
/ i .\ / a. A k eff 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 of the FSAR.
- b. A nominal 6.625 inch center-to-center distance between fuel assemblies placed in the storage racks in the Fuel Handling Building.
- c. A nominal 12 inch center-to-center distance from rack to rack and a minimum fuel storage cell spacing of 7 inches center-to-center within a rack in the upper containment pool.
The storage of spent fuel in the upper containment pool is prohibited during OPERATIONAL CONDITIONS 1 and 2. DRAINAGE 5.6.2 The spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 594'6" CAPACITY 5.6.3 The spent fuel storage pool is designed and shall be maintained with a storage capacity limited to no more than 4020 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. PERRY - UNIT 1 E-5 -
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TABLE 5.7.1-1 COMPONENT CYCLIC OR TRANSIENT LIMITS E Z g CYCLIC OR DESIGN CYCLE COMP 0llENT TRANSIENT LIMIT OR TRANSIENT Reactor 120 heatup and cooldown cycles 70 F to 560 F to 70 F 80 step change cycles Loss of feedwater heaters 180 reactor trip cycles 100% to 0% of RATED THERMAL POWER 40 hydrostatic pressure or Pressurized to > 930 psig and l leak tests < 1250 psig T o, 9 O O
4 h I t I 1 i 1 i i 'I l I i, f 1 i - I 4 i l I. SECTION 6.0 i 4 r ADMINISTRATIVE CONTROLS i l .j l E I t l 4 4 5 4 i l l I I t i& lO r J l k
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/ . 6.0 ADMINISTRATIVE CONTROLS G 6.1 RESPONSIBILITY 6.1.1 The Manager, Perry Plant Operations Department, shall be responsible for overall unit operation and shall delegate in writing the succession to this responsibility during his absence. 6.1. 2 The 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 Group shall be reissued to all station personnel on an annual basis. 6.2 ORGANIZATION CORPORATE 6.2.1 The corporate organization for unit management and technical support shall be as shown en 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
('~'N, crew composition shown in Table 6.2.2-1; \ ')
- b. At least one licensed 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 Operator shall be in the control room;
- c. A Health Physics 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 Operator or licensed Senior Operator Limited to Fuel Handling who has no other concurrent responsibilities during this operation; and
*The Health Physics Technician may be less than the minimum requirements 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 positions.
p) \v PERRY - UNIT 1 6-1 .
ADMINISTRATIVE CONTROLS ( 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 Operators, licensed Operators, health physics technicians, auxiliary operators, and key maintenance personnel).
The amount of overtime worked by unit staff members performing safety-related functions shall be limited in accordance with the NRC Policy Statement on working hours (Generic Letter No. 82-12). O 1 l l l PERRY - UNIT 1 6-2
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b.af't h.*b8 881 l l i FIGURE 6.2.2-1 (Continued) l i UNIT ORGANIZATION l l
TABLE 6.2.2 1 MINIMUM SHIFT CREW COMPOSITION POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION CONDITION 1, 2, or 3 CONDITION 4 or 5 SS 1 1 SRO 1 None R0 2 1 A0 2 1 STA 1 None TABLE NOTATION SS - Shift Supervisor with a Senior Operator license on Unit 1. SR0 - Individual with a Senior Operator license on Unit 1. RO - Individual with an Operator or Senior Operator license on Unit 1. A0 - Auxiliary Operator STA - Shift Technical Advisor 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 accommo-date unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum require-ments 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. During any absence of the Shift Supervisor from the control room while the unit is in OPERAYIONAL CONDITION 1, 2 or 3, an individual with a valid Senior Opera-tor license shall be designated to assume the control room command function. During any absence of the Shift Supervisor from the control room while the unit is in OPERATIONAL CONDITION 4 or 5, an individual with a valid Senior Operator license or Operator license shall be designated to assume the control room com-mand function. O PERRY - UNIT 1 6-6
/ ADMINISTRATIVE CONTROLS .\
6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP (ISEG) FUNCTION 6.2.3.1 The ISEG shall function to examine unit operating characteristics, NRC issuances, industry advisories, Licensee Event Reports, and other sources of unit design and operating esperience information, including units of simi-lar design, which may indicate areas for improving unit safety._ The ISEG shall make detailed recommendations for revised procedures, equipment modifications, maintenance activities, operations activities, or other means of improving unit safety to the Manager, Nuclear Engineering Department. ' i. COMPOSITION 6.2.3.2 The ISEG shall be composed of at least five, dedicated, full-time i engineers or~ technically oriented individuals located onsite. Each shall hava either (1) a bachelor's degree in engineering or related science and at least 2 years professional level experience in his field, at hast 1 year of which experience shall be in the nuclear field, or (2) equivalent work experience as described in Section 4.1 of ANSI /ANS 3.1, December 1981. RESPONSIBILITIES 6.2.3.3 The ISEG shall be responsible for maintaining surveillance of unit e - activities to provide independent verification
- that these activities are per-l formed correctly and that human errors are reduced as much as practical.
- RECORDS 6.2.3.4 Records of activities performed by the ISEG shall be prepared, main-tained, and forwarded each calendar month to the Manager, Nuclear Engineering Department.
6.2.4 SHIFT TECHNICAL ADVISOR 6.2.4.1- The Shift Technical Advisor shall provide advisory technical support to the 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 engineer-ing discipline and shall have received specific training in the response and anal-ysis 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 OUALIFICATIONS 6.3.1 Each member of the unit staff shall meet or exceed tre minimum qualifica-tions of ANSI N18.1-1971 for comparable positions, except for the Senior Opera-tions Coordinator for the first cycle and the Plant Health Physicist who shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975. The licensed Operators and Senior Operators shall also meet or exceed the minimum qualifications of the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980 NRC letter to all licensees.
*Not responsible for sign-off function.
PERRY - UNIT 1 6-7
}
ADMINISTRATIVE CONTROLS 6.4 TRAINING 6.4.1 A retraining and replacement training program for the unit staff shall be maintained under the direction of the Perry Training Section General Super-visor, and shall meet or exceed the requirements and recommendations of Sec-tion 5.5 of ANSI N18.1-1971 and Appendix A of 10 CFR Part 55 and the supplemen-tal requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980 Nk'C letter to all licensees, and shall include familiarization with relevart industry operational experience. 6.5 REVIEW AND AUDIT 6.5.1 PLANT OPERATIONS REVIEW COMMITTEE (PORC) FUNCTION 6.5.1.1 The PORC shall function to advise the Managers, Perry Plant Departments, on all matters related to nuclear safety. COMPOSITION 6.5.1.2 The PORC shall be composed of the: Chairman: Manager, Perry Plant Operations Department Vice-Chairman / Member: Manager, Perry Plant Technical Department Vice-Chairman / Member: Technical Superintendent, Perry Plant Technical Department Member: General Supervisor, Operations Section Member: General Supervising Engineer, Technical Section Member: General Supervisor, Maintenance Section Member: Reactor Engineer Memoer: General Supervising Engineer, Radiation Protection Section Member: Plant Health Physicist Member: General Supervising Engineer, Instrumentation and Control Section ALTERNATES 6.5.1.3 All alternate members shall be appointed in writing by the PORC Chairman to serve on a temporary basis; however, no more tnan two alternates shall participate as voting members in PORC activities at any one time. MEETING FREQUENCY 6.5.1.4 The PORC shall meet at least once per calendar month and as convened by the PORC Chairman or his designated alternate. QUORUM 6.5.1.5 The quorum of the PORC necessary for the performance of the PORC responsibility and authority provisions of these Technical Specifications shall consist of the Chairman or his designated alternate and at least four members including alternates. PERRY - UNIT 1 6-8
~
V) l ADMINISTRATIVE CONTROLS RESPONSIBILITIES 6.5.1.6 The PORC shall be responsible for:
- a. Review of all Administrative Procedures;
- b. Review of the safety evaluations for (1) proposed procedures /
instructions, (2) changes to procedures / instructions, equipment, systems or facilities, and (3) tests or experiments performed under the provisions of 10 CFR 50.59 to verify that such actions do not constitute an unreviewed safety question;
- c. Review of proposed procedures / instructions and cnanges to procedures /
instructions, equipment, systems or facilities which involve an unreviewed safety quatt h as cerined in 10 CFR 50.59;
- d. Review of proposed tests or experiments which involve an unreviewed safety question as defined in 10 CFR 50.59;
- e. Review of proposed changes to Technical Specifications or the Ooerating License;
- f. Investigation of all violations of the Technical Specifications including the preparation and forwarding of reports covering evalua-tion and recommendations to prevent recurrence to the Vice President -
Nuclear Group and to the Nuclear Safety Review Committee;
- g. Review of al1 REPORTABLE EVENTS; (d h. Review of the plant Security Plan and Security Contingency Instruc-tions and submittal of recommended charges to the Nuclear Safety Review Committee;
- i. Review of the Emergency Plan and implementing instructions and sub-mittal of recommended changes to the Nuclear Safety Review Committee;
- j. Review of changes to the PROCESS CONTROL PROGRAM, the 0FFSITE DOSE CALCULATION MANUAL, and Radwaste Treatment Systems;
- k. Review of any accidental, unplanned or uncontrolled radioactive release 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 Managers, Perry Plant Departments, the Nuclear Safety Review Committee and the Vice President - Nuclear Group;
- 1. Review of Unit operations to detect potential har 3rds to nuclear safety;
- m. Investigations or analysis of special subjects as requested by the Chairman of the Nuclear Safety Review Committee; and
- n. Review of the Fire Protection Program and implementing procedures and submittal of recommended changes to the Nuclea- Safety Review Committee.
g3
- 6 d
PERRY - UNIT 1 6-9
ADMINISTRATIVE CONTROLS RESPONSIBILITIES (Continued)
- 6. 5.1. 7 The PORC shall:
a. Recommend in writing to the Managers, Perry Plant Departments, approval or disapproval of items considered under Specifications 6.5.1.6a. through e., h., i., J., and k., above prior to their implementation; b. Render determinations in writing with regard to whether or not each item considered under Specifications 6.5.1.6b. through e., above, constitutes an unreviewed safety question; and c. Provide written notification within 24 hours to the Vice President - Nuclear Group and the Nuclear Safety Review Committee of disagreement between the PORC and the Manager, Perry Plant Operations Department; however, the Manager, Perry Plant Operations Department, shall have responsibility for resolution of such disagreements pursuant to Specification 6.1.1 above. RECORDS
- 6. 5.1. 8 The PORC shall maintain written minutes of each PORC meeting that, at a minimum, document the results of all PORC activities performed under the responsibility provisions of these Technical Specifications. Copies shall be provided to the Vice President - Nuclear Group and the Nuclear Safety Review Committee.
6.5.2 NUCLEAR SAFETY REVIEW COMMITTEE (NSRC) FUNCTION 6.5.2.1 The NSRC 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 radiochemistry,
- d. Metallurgy,
- e. Instrumentation and control,
- f. Radiological safety,
- g. Mechanical and electrical engineering,
- h. Quality assurance practices and administrative controls, and
- i. Nondestructive testing.
The NSRC shall report to and advise the Vice President - Nuclear Group on those areas of responsibility specified in Specifications 6.5.2.7 and 6.5.2.8. PERRY - UNIT 1 6-10
b] ADMINISTRATIVE CONTROLS COMPOSITION 6.5.2.2 The membership of the NSRC shall be composed of at least eight person-nel appointed by the Vice President - Nuclear Group to provide collective ex-perience and competency in the following areas: Nuclear power plant operations
. Nuclear engineering Chemistry and radiochemistry Metallurgy Nondestructive testing Instrumentation and control Radiological safety Mechanical and electrical engineering Administrative controls and quality assurance practices The Chairman, appointed by the Vice President - Nuclear Group, shall have 10 years of power plant experience, of which 3 years shall be nuclear power plant experience.
The NSRC members shall hold a bachelors' degree in an enginee' ring or physical science field, or equivalent experience, and a minimum of 5 years of technical experience of which a minimum of 3 years shall be in one or more of the disciplines in Specification 6.5.2.1. Competent alternates may be designated in advance and consultants may be used for in-depth expertise if desire:I by the committee. ALTERNATES 6.5.2.3 All alternate members shall be appointed in writing by the NSRC Chairman to serve on a temporary basis; however, no more than two alternates shall parti-ipate as voting members in NSRC activities at any one time. CONSULTANTS 6.5.2.4 Consultants shall be utilized as determined by the NSRC Chairman to provide expert advice to the NSRC. MEETING FREQUENCY 6.5.2.5 The NSRC shall meet at least once per calendar quarter during the initial year of unit operation following fuel loading and at least once per 6 months thereafter. QUORUM 6.5.2.6 The quorum of the NSRC necessary for the performance of the NSRC review and audit functions of these Technical Specifications shall consist of the Chairman or his designated alternate and at least four but not less than one-half of the NSRC members including alternates. No more than a minority of the quorum shall have line responsibility for operation of the unit. s PERRY - UNIT 1 6-11
ADMINISTRATIVE CONTROLS REVIEW 6.5.2.7 The NSRC shall be responsible for the review of: a. The safety evaluations for (1) changes to procedures, instructions, eouipent, or systems; and (2) tests or experiments completed under the provision of 10 CFR 50.59 to verify that such actions did not constitute an unreviewed safety question; b. Changes or proposed changes to procedures, instructions, equipment, or systems which involve an unreviewed safety question as defined in 10 CFR 50.59;
- c. Tests or experiments or proposed tests or experiments which involve
- an unreviewed safety question as defined in 10 CFR 50.59;
- d. Proposed changes to Technical Specifications or this Operating License;
- e. Violations of codes, regulations, orders, Technical Specifications, license requirements, or of internal procedures or instructions having nuclear safety significance;
- f. Significant operating abnormalities or deviations from normal and expected performance of unit equipment that affect nuclear safety;
- g. All REPORTABLE EVENTS;
- h. All recognized indications of an unanticipated deficiency in some aspect of design or operation of structures, systems, or components that could affect nuclear safety; and
- i. Reports and meeting minutes of the PORC.
AUDITS 6.5.2.8 Audits of unit activities shall be performed under the cognizance of the NSRC. These audits shall encompass:
- a. The conformance of unit operation to provisions contained within the Technical Specifications and applicable license conditions at least once per 12 months;
- b. The performance, training and qualifications of the entire unit staff at least once per 12 months;
- c. The results of actions taken to correct deficiencies accecring in unit equipment, structures, systems, or method of opera'.icn that affect nuclear safety, at least once per 6 months; l
PERRY - UNIT 1 6-12 l
'l ADMINISTRATIVE CONTROLS ~Q AUDITS (Continued)
- d. The performance of activities required by the Operational Quality Assurance Program to meet the criteria of Appendix B, 10 CFR Part 50, at least once per 24 months;
- e. The fire protection programmatic controls including the implementing' procedures at least once per 24 months by qualified licensee QA personnel;
- f. The fire protection equipment and program implementation at least once per 12 months utilizing either a qualified corporate licensee fire protection engineer (s) or an outside independent fire protection consultant. An outside independent fire protection consultant shall be utilized at least every third year;
- g. The radiological environmental monitoring program and the results thereof at least once per 12 months;
- h. The OFFSITE DOSE CALCULATION MANUAL and implementing procedures at least once per 24 months;
- i. The PROCESS CONTROL PROGRAM and implementing procedures at least x once per 24 months;
\
j. The performance of activities required by the Quality Assurance Program for effluent and environmental monitoring at least once' per 12 months; and
- k. Any other area of unit operation considered appropriate by the NSRC or the Vice President - Nuclear Group.
RECORDS 6.5.2.9 Records of NSRC activities shall be prepared, approved, and distributed as indicated below:
- a. Minutes of each NSRC meeting shall be prepared, approved, and forwarded to the Vice President-- Nuclear Group within 14 days following each meeting.
- b. Reports of reviews encompassed by Specification 6.5.2.7 shall be prepared, approved, and forwarded to the Vice President - Nuclear Group within 14 days following completion of the review.
- c. Audit reports encompassed by Specification 6.5.2.8 shall be forwarded to the Vice President - Nuclear Group and to the management positions responsible for the areas audited within 30 days after completion of the audit by the auditing organization.
U PERRY - UNIT 1 6-13 -
ADMINISTRATIVE CONTROLS 6.5.3 TECHNICAL REVIEW AND CONTROL ACTIVITIES 6.5.3.1 Activities which affect nuclear safety shall be conducted as follows:
- a. Procedures / instructions required by Specification 6.8 and other procedures / instructions which affect plant nuclear safety, and changes thereto, shall be prepared, reviewed and approved. Each such procedure / instruction or procedure / instruction change shall be re-viewed by a qualified individual (s) other than the individual (s) which prepared tha procedure / instruction or procedure / instruction change, but who may be from the same section as the individual (s) which prepared the procedure / instruction or procedure / instruction change. Instructions shall be approved by appropriate management personnel as designated in writing by PORC, and approved by the appropriate managers, Perry Plant Departments. The Managers, Perry Plant Departments, shall approve Administrative Procedures. Temporary changes to procedures / instructions which do not change the intent of the approved procedures / instructions shall be approved for implemen-tation by two members of the plant management staff, at least one of whom holds a Senior Operator license. These temporary changes shall be documented. The temporary changes shall be approved by the ori-ginal approval authority within 14 days. For changes to procedures /
instructions which may involve a change in intent of the proced;res/ instructions, the original approval authority shall approve the change prior to implementation;
- b. Proposed modifications to plant structures, systems and components that affect nuclear safety shall be reviewed by individuals desig-nated by the Manager, Nuclear Engineering Department. Each such modification shall be reviewed by a qualified individual (s) other than the individual (s) which designed the modification, but who may be from the same section as the individual (s) which designed the modifications.
Proposed modifications to plant structures, systems and components that affect nuclear safety shall be reviewed by PORC and approved prior to implementation by the Managers, Perry Plant Departments;
- c. Proposed tests and experiments which affect plant nuclear safety shall be prepared, reviewed, and approved. Each such test or experi-ment shall be reviewed by a qualified individual (s) other than the individual (s) which prepared the proposed test or experiment.
Proposed tests and experiments shall be approved before implementa-tion by the Managers, Perry Plant Departments. O PERRY - UNIT 1 6-14
f ADMINISTRATIVE CONTROLS ACTIVITIES (Continued)
- d. Sections responsible for reviews, including cross-disciplinary re-views, performed in accordance with Specifications 6.5.3.la., and 6.5.3.lc.,'shall be. designated in writing by PORC and approved by the appropriate Manager, Perry Plant Department. The individual (s) per-forming the review shall meet or exceed the qualification requirements of appropriate section(s) of ANSI N18.1-1971;
- e. Each review shall include a determination pursuant'to 10 CFR 50.59 of whether or not the potential for an unreviewed safetjy question exists. If such a potential does exist, a safety evaluation per 10 CFR 50.59 to determine whether or not an unreviewed safety question is involved shall be performed. Pursuant to 10 CFR 50.59, NRC approval of items involving unreviewed safety questions shall be obtained prior to the Managers, Perry Plant Departments, approval for implementation; and
'f.
The Plant Security Plan and Emergency Plan, and implementing instruc-tions, shall be reviewed at least once per 12 months. Recommended changes to the implementing instructions shall-be approved by the Manager, Perry Plant Technical Department. . Recommended changes to the Plans shall be reviewed pursuant to the requirements of Specifi-cations 6.5.1.6 and 6.5.2.7 and approved by the Manager, Perry . Plant-Technical Department. NRC approval shall be obtained as appropriate. 6.6 REPORTABLE EVENT ACTION 6.6.1 The following actions shall be taken for REPORTABLE EVENTS:
- a. The Commission shall be notified pursuant to the requirements of Section 50.72 to 10 CFR Part 50, and a report submitted pursuant to ,
the requirements of Section 50.73 to 10 CFR Part 50, and
- b. Each REPORTABLE EVENT shall be reviewed by the PORC and the results of the review submitted to the NSRC and the Vice President - Nuclear Group.
6.7 SAFETY LIMIT VIOLATION 6.7.1 The following actions shall be taken in the event a Safety Limit is violated:
- a. The NRC Operations Center shall be notified by. telephone as soon as possible and in all cases within I hour. The Vice President - Nuclear Group and the NSRC shall be notified within 24 hours.
- b. A Safety Limit Violation Report shall be prepared. The report shall be reviewed by.the PORC. This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation upon unit components, systems, or structures, and (3) corrective action taken to prevent recurrence.
- c. The Safety Limit Violation' Report shall be submitted to the Commission, the NSRC, and the.Vice President - Nuclear Group within 14 days of the violation.
- d. Critical operation of the unit shall not be resumed until authorized by the Commission.
PERRY - UNIT 1 6-15
ADMINISTRATIVE CONTROLS 6.8 PROCEDURES / INSTRUCTIONS AND PROGRAMS 6.8.1 Written procedures / instructions shall be established, implemented, and maintained covering the activities referenced below:
- a. The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
- b. The applicable procedures required to implement the requirements of NUREG-0737 and supplements thereto.
- c. Security Plan implementation.
- d. Emergency Plan implementation.
- e. PROCESS CONTROL PROGRAM implementation.
- f. OFFSITE DOSE CALCULATION MANUAL implementation.
- g. Radiological Environmental Monitoring Program implementation.
- h. Fire Protection Program implementation.
6.8.2 Eam.; administrative procedure of Specification 6.8.1, and changes thereto, shall be reviewed by the PORC and shall be approved by the Managers, Perry Plant Departments, prior to implementation. All procedures / instructions shall be reviewed periodically as set forth in administrative procedures. 6.8.3 The following programs shall be established, implemented, and maintained:
- a. Primary Coolant Sources Outside Containment A program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as low as practical levels. The systems include the HPCS, CS, RHR, RCIC, LPCS, feedwater leakage control system, and post-accident sampling systems. The program shall include the following:
- 1. Preventive maintenance and periodic visual inspection requirements, and
- 2. Integrated leak test requirements for each system at refueling cycle intervals or less.
- b. In-Plant Radiation Monitoring A program which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions. This program shall include the following:
- 1. Training of personnel,
- 2. Procedures for monitoring, and
- 3. Provisions for maintenance of sampling and analysis equipment.
PERRY - UNIT 1 6-16
FN ADMINISTRATIVE CONTROLS s. PROCEDURES, INSTRUCTIONS AND PROGRAMS (Continued)
- c. Post-accident Sampling A program which will ensure the capability to obtain and analyze reactor coolant, radioactive iodines and particulates in plant gaseous efflu-ents, and containment atmosphere samples under accident conditions.
The program shall include the following:
- 1. Training of- personnel,
- 2. Procedures for sampling and. analysis, and ,
3. Provisions for maintenance of sampling and analysis equipment. 6.9 REPORTING REQUIREMENTS ROUTINE REPORTS 6.9.1 In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the following reports shall be submitted to the Regional Administrator of the Regional Office of the NRC unless otherwise noted. STARTUP REPORT (O) k/ 6. 9.1.1 A summary report of plant startup and power escalation testing shall be submitted following (1) receipt of an Operating License, (2) amendment to the license involving a planned increase in power level, (3) installation of fuel that has a different design or has been manufactured by a different fuel supplier, and (4) modifications that may have significantly altered the nuclear, thermal, or hydraulic performance of the unit. 6.9.1.-2 The startup report shall address each of- the tests . identified in the Final Safety Analysis Report Subsection 14.2.12.2 and shall include a descrip-tion of the measured values of the operating conditions or characteristics obtaint:d during the test program and a comparison of these values with design predictions and specifications. Any corrective actions that were required to obtain satisfactory operation shall also be described. Any additional specific details required in license conditions based on other commitments shall be included in this report. 6.9.1.3 Startup reports shall be-submit:.ed within (1) 90 days following comple-tion of the startup test program, (2) 90 days following resumption or commence-ment of commercial power operation, or (3) 9 months following initial criticality,
.whichever is earliest. If'the startup report does not cover all three events, i.e., initial criticality, completion of startup test program, and resumption or commencement of commercial operation supplementary reports shall be submitted at least every 3 months until all three events have been completed.
\ PERRY - UNIT 1 6-17 ._
ADMINISTRATIVE CONTROLS x ANNUAL REPORTS 6.9.1.4 Annual reports covering the activities of the unit as described below for the previous calendar year shall be submitted prior to March 1 of each year. The initial report shall be submitted prior to March 1 of the year following initial criticality.
- 6. 9.1. 5 Reports required on an annual basis shall include:
- a. A tabulation on an annual basis of the number of station, utility, and other personnel, including conti actors, receiving exposures greater than 100 mrem /yr and their associated man rem exposure according to work and job functions ** e.g. , reactor operations and surveillance, inservice inspection, routine maintenance, special maintenance [ describe maintenance], waste processing, and refueling.
The dose assignments to various duty functions may be estimated based on pocket dosimeter, thermoluminescent dosimeter (TLD), or film badge measurements. Small exposures totalling less than 20% of the indi-vidual total dose need not be accounted for. In the aggregate, at least 80% of the total whole-body dose received from external sources should be assigned to specific major work functions; and
- b. Documentation of all challenges to safety / relief valves.
- c. Annual reports shall also include the results of specific activity analysis in which the primary coolant exceeded the limits of Specifi-cation 3.4.5. The following information shall be included: (1) Re-actor power history starting 48 hours prior to the first sample in which the limit was exceeded; (2) Results of the last isotopic analy-sis for radiciodine performed prior to exceeding the limit, results of analysis while limit was exceeded and results of one analysis after the radiciodine activity was reduced to less than limit. Each result should include date and time of sampling and the radiciodine concentrations; (3) Clean-up system flow history starting 48 hours prior to the first sample in which the limit was exceeded; (4) Graph of the I-131 concentration and one other radioiodine isotope concen-tration in microcuries per gram as a function of time for the dura-tion of the specific activity above the steady-state level; and (5)
The time duration when the specific activity of the primary coolant exceeded the radioicdine limit. ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT
- 6. 9.1. 6 Routine radiological environmental operating reports covering the operation of the unit during the previous calendar year shall be submitted M
A single submittal may be made for a multiple unit station. The submittal i should combine those sections that are common to all units at the station. This tabulation supplements the requirements of S20.407 of 10 CFR Part 20. PERRY - UNIT 1 6-18
1 I i l l O ADMINISTRATIVE CONTROLS V ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING' REPORT (Continued) prior to May 1 of each year. The initial report shall be submitted prior-to May 1 of the year following initial criticality and shall include copies of reports of the preoperational Radiological Environmental Monitoring Program of the unit for at least two years prior to initial criticality in addition to the following. The Annual Radiological Environmental.0perating Reports shall include summaries, interpretations, and an analysis of trends of the results of the radiological environmental surveillance activities for the report period, including a com-parison with preoperational studies, operational controls (as appropriate.', and previous environmental surveillance reports and an assessment of the observed impacts of the plant operation on the environment. The reports shall also include the results of land use censuses required by Specifica-tion 3.12.2. The Annual Radiological Environmental Operating Reports shall include the results of analysis of all radiological environmental samples and of all loca-tions specified in the table and figures in the Offsite Dose Calculation Manual, as well as summarized and tabulated results of these analyses and measurements in the format of the table in the Radiological Assessment Branch Technical Position, Revision 1, November 1979. In the event.that some individual results p are not available for inclusion with the report, the report sW' be submitted noting and explaining the reasons for the missing results. The missing data shall be submitted as soon as possible in a supplementary report. The reports shall also include the following: a summary description of the Cadiological Environmental Monitoring Program; at least two legible maps
- covering all sampling locations keyed to a table giving~ distances and direc-tions from the centerline of one reactor; the results of licensee participation in the Interlaboratory Comparison Program and the corrective action taken if the specified program is not being performed as required by Specification 3.12.3; reasons for not, conducting the Radiological Environmental Monitoring Program as required by Specification 3.12.1, and discussion 'of all deviations from the sampling schedule of Table 3.12.1-1; discussion of environmental sample measure-ments that exceed the reporting levels of Table 3.12.1-2 but are not the result of plant effluents, pursuant to ACTION b of Specification 3.12.1; and discus-sion of all analyses in which the LLD required'by Table 4.12.1-1 was not achievable.
SEMIANNUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT
- 6. 9.1. 7 Routine radioactive release reports covering the operation of the unit during the previous 6 months o# operation shall be submitted within 60 days after January 1 and July 1 of each year. The period of the first report shall begin with the date of initial. criticality.
*0ne map shall cover stations near the SITE B0UNDARY; a second shall include
% the more distant stations. PERRY - UNIT 1 6-19
ADMINISTRATIVE CONTROLS SEMIANNUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT (Continued) The Semiannual Radioactive Effluent Release Reports shall include a sum-mary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit as outlined in Regulatory Guide 1.21, " Measuring, Evaleating, and Reporting Radioactivity in Solid Wastes and Releases of Radio-active Materials in Liquid and Gaseous Effluents from Light-Water-Cooled Nu-clear Power Plants," Revision 1, June 1974, with data summarized on a quarterly basis following the format of Appendix 8 thereof. For solid wastes, the format for Table 3 in Appendix 8 shall be supplemented with three additional categories: class of solid wastes (as defined by 10 CFR Part 61), type of container (e.g., LSA, Type A, Type 8, large Quantity) and SOLIDIFICATION agent or absorbent (e.g. , cement, urea formaldehyde). The Semiannual Radioactive Effluent Release Report to be submitted within 60 days after January 1 of each year shall include an annual . summa ry of hourly meteorological data collected over the previous year. This annual summary may be either in the form of an hour-by-hour listing on magnetic tape of wind speed, wind directio'n, atmospheric stability, and precipitation (if measured), or in the form of joint frequency distributions of wind speed, wind direction, and atmospheric stability.* This same report shall include an assessment of the radiation doses due to the radioactive liquid and gaseous effluents released from the unit or station during the previous calendar year. This same report shall also include an assessment of the radiation doses from radioactive liquid and gaseous effluents to MEMBERS OF THE PUBLIC due to their activities inside the SITE BOUNDARY (Figure 5.1.1-1) during the report period. All assumptions used in making these assessments, i.e., specific activity, exposure time, and location, shall be included in these reports. The meteorological conditions concurrent with the time of release of radicactive materials in gaseous effluents, as determined by sampling frequency and measurement, shall be used for determin-ing the gaseous pathway doses. The assessment of radiation doses shall be performed in accordance with the methodology and parameters in the OFFSITE DOSE CALCULATION MANUAL (ODCM). The Semiannual Radioactive Effluent Release Report to be submitted within 60 days af ter January 1 of each year shall also include an assessment of radia-tion doses to the likely most exposed MEMBER OF THE PUBLIC from reactor releases and other nearby uranium fuel cycle sources, including doses from primary effluent pathways and direct radiation, for the previous calendar year to show conformance with 40 CFR Part 190, " Environmental Radiation Protection Standards for Nuclear Power Operation." Acceptable methods for calculating the dose con-tribution from liquid and gaseous ef fluents are given in Regulatory Guide 1.109, Rev. 1, October 1977. The Semiannual Radioactive Effluent Release Reports shall include a list and description of unplanned releases from the site to UNRESTRICTED AREAS of radioactive materials in gaseous and liquid effluents made during the reporting period. "In lieu of submission with the Semiannual Radioactive Ef fluent Release Report, the licensee has the option of retaining this summary of required meteorological data on site in a file that shall be provided to the NRC upon request. PERRY - UNIT 1 6-20
p ADMINISTRATIVE CONTROLS O SEMIANNUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT (Continued) The Semiannual Radioactive Effluent Release Reports shall include any changes made during the reporting period to the PROCESS CONTROL PROGRAM (PCP) and to the OFFSITE DOSE CALCULATION MANUAL (00CM), pursuant to Specifications 6.13 and 6.14, respectively, as well as any major change to Liquid; Gaseous, or Solid Radwaste Treatment Systems pursuant to Specification 6.15. It shall also include a list-ing of new locations for' dose calculations and/or environmental monitoring iden-tified by the Land Use Census pursuant to Specification 3.12.2. The Semiannual Radioactive Effluent Release Reports shall also include the following: an explanation as to why the inoperability of liquid or gaseous-effluent monitoring instrumentation was not corrected within the time specified in Specification 3.3.7.9 or 3.3.7.10, respectively; and description of the events leading to liquid holdup tanks exceeding the limits of Specification 3.11.1.4. MONTHLY OPERATING REPORTS
- 6. 9.1. 8 Routine reports of operating statistics and shutdown experience shall be submitted on a month.ly basis to the Director, Office of Management and Program Analysis, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, with a copy to the Regional Administrator of the Regional Office no later than the 15th of each month following the calendar month covered by the report.
~SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the Regional Administrator of the Regional Office within the time period specified for each report.
6.9.3 Safety / relief <alve failures will be reported to the Regional Administrator of the Regional Office of the NRC via the Licensee Event Report system within 30 days. 6.10 RECORD RETENTION 6.10.1 In addition to the applicable record retention requirements of Title 10, Code of Federal Regulations, the following records shall be retained for at least the minimum period indicated. 6.10.2 The following records shall be retained for at least 5 years:
- a. Records and logs of unit operation covering time interval at each power level.
- b. Records and logs of principal maintenance activities, inspections, repair, and replacement of principal items of equipment related to nuclear safety.
- c. All REPORTABLE EVENTS.
J' ( d. Records of surveillance activities, inspections, and calibrations required by these Technical Specifications. PERRY - UNIT 1 6-21
ADMINISTRATIVE CONTROLS RECORD RETENTION (Continued)
- e. Records of change,s made to the procedures required by Specification
- 6. 8.1.
- f. Records of radioactive shipments,
- g. Records of sealed source and fission detector leak tests and results.
- h. Records of annual physical inventory of all sealed source material of record.
6.10.3 The following records shall be retained for the duration of the unit Operating License:
- a. . Records and drawing changes reflecting unit design modifications made to systems and equipment described in the Final Safety Analysis Report.
- b. Records of new and irradiated fuel i nvento ry , fuel transfers, and assembly burnup histories.
- c. Records of radiation exposure for all individuals entering radiation control areas.
- d. Records of gaseous and liquid radioactive material released to the environs.
~
- e. Records of transient or operational cycles for those unit components identified in Table 5.7.1-1.
- f. Records of reactor tests and experiments.
- g. Records of training and qualification for current members of the unit staff.
- h. Records of inservice inspections performed pursuant to these Technical Specifications.
- i. Records of quality assurance activities required by the Operational Quality Assurance Manual.
- j. Records of reviews performed for changes made to procedures or equip-ment or reviews of tests and experiments pursuant to 10 CFR 50.59.
- k. Records of meetings of the PORC and the NSRC.
- 1. Records of the service lives of all hydratlic and mechanical snubbers including the date at which the service life commences and associated installation and maintenance records.
PERRY - UNIT 1 6-22
/'D ADMINISTRATIVE CONTROLS J'
RECORD RETENTION (Continued)
- m. Records of analyses required by the radiological environmental moni-toring program that would permit evaluation of the accuracy of the analysis at a later date. .This would include procedures effective at the specified times and QA records showing that these procedures were followed.
l 6.11 RADIATION PROTECTION PROGRAM 6.11.1 Procedures for personnel radiation protection shall be prepared consist-ent with the requirements of 10 CFR Part 20 and shall be approved, maintained, and adhered to for all operations involving personnel radiation exposure. l* 6.12 HIGH RADIATION AREA 6.12.1 In lieu of the " control device" or " alarm signal" required by paragraph 20.203(c)(2) of 10 CFR Part 26, each high radiation area in which the intensity of radiation is greater than 100 mrem /hr** but less than 1000 mrem /hr** shall be barricaded and conspicuously posted as a high radiation area and entrance thereto shall be controlled by requiring issuance of a Radiation. Work Permit [N i (RWP)*. Any individual or group of individuals permitted to enter such areas shall be provided with or accompanied by one or more of the following:
- a. A radiation monitoring device which continuously indicates the radiation dose rate in the area.
- b. A radiation monitoring device which continuously integrates the radiation dose rate in the area and alarms when a preset integrated l l
L dose is received. Entry into such areas with this monitoring device ; may'be made after the dose rate levels in the area have been established and personnal have been made knowledgeable of them.
- c. A health physics qualified individual f.e., qualified in accordance with ANSI N18.1-1971, with a radiation dose rate monitoring device
' who is responsible for providing positive control over the activi-ties within the area and shall perform periodic radiation surveil-lance at the frequency specified by the Plant Health Physicist. l
- Health physics personnel or personnel escorted by health physics personnel
! shall'be exempt from the RWP issuance requirement during the performance of their assigned radiation protection duties, provided they are otherwise follow-l ing plant radiation protection procedures for entry into high radiation areas.
** Measurement made at 18 inches from source of radioactivity.
( PERRY - UNIT 1 6-23
ADMINISTRATIVE CONTROLS HIGH RADIATION AREA (Continued) 6.12.2 In addition to the requirements of Specification 6.12.1, areas access-ible to personnel with radiation levels such that a major portion of the body could receive in 1 hour a dose greater than 1000 mrem
- shall be provided with uniquely keyed locked doors or continuously guarded to prevent unauthorized entry, and the keys shall-be maintained under the administrative control of the Shift Supervisor or the Plant Health Physicist. Doors shall remain locked ex-cept during periods of access by personnel under 'an approved RWP. For individ-ual areas accessible to pernonnel with radiation levels such that a major por-tion of the body could receive in 1 hour a dose in excess of 1000 mrem
- that are located within large areas, such as the containment, where no enclosure exists for purposes of locking, or that cannot be continuously guarded and no enclosure
. can be reasonably constructed around the individual areas, then that area shall be roped off, conspicuously posted, and a flashing light shall be activated as a warning device. 6.12.3 In addition to the requirements of Specifications 6.12.1 and 6.12.2, for individual areas accessible to personnel such that a major portion of tha body could receive in 1 hour a dose in excess of 3000 mrem *, entry shall require an approved RWP which will specify dose rate levels in the immediate work area and the maximum allowable stay time for individuals in that area. In lieu of the stay time specification of the RWP, continuous surveillance, direct or remote, such as use of closed circuit TV cameras, may be made by personnel qual-ified in radiation protection procedures to provide positive exposure control over activities within the area. 6.13 PROCESS CONTROL PRCGRAM (PCP) 6.13.1 The PCP shall be approved by the Commission prior to implementation. 6.13.2 Licensee initiated changes to the PCP:
- 1. Shall be submitted to the Commission in the Semiannual Radioactive Effluent Release Report for the period in which the change (s) was made. This submittal shall contain:
- a. Sufficiently detailed information to totally support the rationale for the change without benefit of additional or supplemental information;
- b. A determination that the change did not reduce the overall conformance of the solidified waste product to existing criteria for solid wastes; and
- c. Documentation of the fact that the change has been reviewed and found acceptable by the PORC.
- Measurement made at 18 inches from source of radioactivity.
PERRY - UNIT 1 6-24
ADMINISTRATIVE CONTROLS PROCESS CONTROL PROGRAM (PCP) (Continued)
- 2. Shall become effective upon review and acceptance by the PORC.
6.14 0FFSITE DOSE CALCULATION MANUAL (ODCM) 6.14.1 The 00CM shall be approved by the Commission prior to implementation. 6.14.2 Licensee initiated changes to the ODCM:
- 1. Shall be submitted to the Commission in the Semiannual Radioactive Effluent Release Report for the period in which the change (s) was made. This submittal shall contain:
- a. Sufficiently detailed informaticn to totaliy. support the rationale for the change without benefit of additional or supplemental information. Information submitted should consist of a package of-those pages of the ODCM to be changed with each page numbered and provided with an approval and data box, together with appropriate analyses or evaluations justifying the change (s);
- b. A determination that the change will not reduce the accuracy or reliability of dose calculations or setpoint determinations; and i
N c. Documentation of the fact that the change has been reviewed and found acceptable by the PORC.
- 2. Shall become effective upon review and acceptance by the PORC.
6.15 MAJOR CHANGES TO RADIOACTIVE WASTE TREATMENT SYSTEMS
- 6.15.1 Licensee initiated major changes to the radioactive waste systems, liquid, gaseous and solid:
- 1. Shall be reported to the Commission in the Semiannual Radioactive Effluent Release Report for the period in which the evaluation was reviewed by the PORC The discussion of each change shall contain:
- a. A summary of the evaluation that led to the determination that the change could be made in accordance wth 10 CFR 50.59;
- b. Sufficient detailed information to totally support the reason for the change without benefit of additional or supplemental information;
- c. A detailed description of the equipment, components and processes involved and the interfaces with other plant systems; A
t \ U
- Licensee may choose to submit the information called for in this Specification as part of the annual FSAR update.
PERRY - UNIT 1 6-25
ADMINISTRATIVE CONTROLS MAJOR CHANGES TO RADI0 ACTIVE WASTE TREATMENT SYSTEMS (Continued)
- d. An evaluation of the change which shows the predicted releases of radioactive materials in liquid and gaseous effluents and/or quantity of solid waste that differ from those previously predicted in the license application and amendments thereto;
- e. An evaluation of the change which shows the expected inaximum exposures to MEMBERS OF THE PUBLIC in the UNRESTRICTED AREA and to the general population that differ from those previously estimated in the license application and amendments thereto; f.* A comparison of the predicted releases of radioactive materials, in liquid and gaseous effluents and in solid waste, to the actual releases for the period prior to when the changes are to be made;
- g. An estimate of the exposure.to plant operating personnel as a result of the change; and
- h. Documentation of the fact that the change was reviewed and found acceptable by the PORC.
- 2. Shall become effective upon review and acceptance by the PORC.
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. ec .est s Accesus sveia Technical Specifications for Perry iluclear Power Plant, Unit :lo. 1 5 0Are ...ar o v ureo vost-g..A.
f1 ARCH 1986 e Au r>.On 5# 7 O Art REpCA f '550tD MONra VEAR MARCH 1986 d PRCsECT rasm WOma uger gywegn 9 P(#5CRYtNG CmGAgita rsog Nayg AND MA' LING AOORE SS iteuar la Codes Division of BWR Licensing Office of fluclear Reactor Regulation ,a ,,, % ,... U. S. Nuclear Regulatory Commission tlashington, D. C. 20555
'1 SPON 508'NG OaG A%i2 A r'ON N AME AND M A'L'NG ADOR E SS isac%de la Codes I 2a rvPt O REPOmr Same as 8. above Technical i 2% *EM r00 COv E at 3 riace s.ve u secess March 1986
, s ..u...sr... saris Appendix "A" to License No. flPF-45 Docket flo. 50-440 a85'a ACr 100 arores or wiss The Perry Nuclear Power Plant, Unit No. 1 Technical Specifications were prepared by the U. S. riuclear Regulatory Commission to set forth limits, operating conditions, and other reouirements applicable to a nuclear reactor facility as set forth in Section 50.36 of 10 CFR Part 50 for the protection of the health and safety of the public.
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UNITED STATES sPicini ,ouaf w ct ass asti NUCLEAR REGULATORY COMMISSION NSt^tst"_Es PatD WASHINGTON, D.C. 20555 wasa o c PF RV.T non 6 A7 OFFICIAL BUSINESS PENALTY FOR PRIVATE USE. 5300 0 I I I O}}