ML072890194
| ML072890194 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 10/05/2007 |
| From: | Susquehanna |
| To: | Gerlach R Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML072890194 (173) | |
Text
Oct. 05, 2007 Page 1 of 5 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2007-34750 USER INFORMATION:
GERLACH*ROSE M EMPL#:028401 CA#: 0363 Address: NUCSA2 Phone#: 254-3194 TRANSMITTAL INFORMATION:
TO: GERLACH*ROSE M 10/05/2007 LOCATION: USNRC FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)
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SSES MAANUAL
. Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL Table Of Contents Issue Date: 10/04/2007 procedure Name Rev Issue Date Change ID Change Number TEXT LOES 85 10/04/2007
Title:
LIST OF EFFECTIVE SECTIONS TEXT TOC 13 10/04/2007
Title:
TABLE OF CONTENTS TEXT 2.1.1 3 10/04/2007
Title:
SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 1 10/04/2007
Title:
SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEM (RCS) PRESSURE S TEXT 3.0 2 10 /12/2 006
Title:
LIMITING CONDITION FOR OPER mTION (LCO) APPLICABILITY TEXT 3.1.1 1 04/18/2006
Title:
REACTIVITY CONTROL SYSTEMS 3HUTDOWN MARGIN (SDM)
TEXT 3.1.2 -0 11/15/2002
Title:
REACTIVITY. CONTROL SYSTEMS IREACTIVITY ANOMALIES TEXT 3.1.3 1 07/06/2005
Title:
REACTIVITY CONTROL SYSTEMS CONTROL ROD OPERABILITY TEXT 3.1.4 3 09/29/2006
Title:
REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3.1.5 1 07/06/2005
Title:
REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3.1.6 2 04/18/2006
Title:
REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Report Date: 10/04/07 Pagel Page I of of ~,
8 Report Date: 10/04/07
SS~E MANUJAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL 4 TEXT 3.1.7 2 10/04/2007
Title:
REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 2 10/04/2007
Title:
REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 1 04/18/2006
Title:
POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
TEXT 3.2.2 1 04/18/2006
Title:
POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)
TEXT 3.2.3 1 10/04/2007
Title:
POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE (LHGR)
TEXT .3.2.4 2 04/12/2006 0
Title:
POWER DISTRIBUTION LIMITS AVERAGE POWER RANGE MONITOR (APRM) GAIN AND SETPOINTS TEXT 3.3.1.1 3 04/12/2006
Title:
INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 1 04/12/2006
Title:
INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3.3.2.1 2 04/12/2006
Title:
INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 0 11/15/2002
Title:
INSTRUMENTATION FEEDWATER - MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 6 04/03/2007
Title:
INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 1 04/18/2005
Title:
INSTRUMENTATION REMOTE SHUTDOWN SYSTEM Report Date: 10/04/07 Page2 Page 2 of of 8
.8 Report Date: 10/04/07
SSES MANUAL
. Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.3.4.1 0 11/15/2002
Title:
INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATION TEXT 3.3.4.2 0 11/15/2002
Title:
INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3.5.1 2 07/06/2005
Title:
INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 0 11/15/2002
Title:
INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION TEXT 3.3.6.1 3 10/04/2007
Title:
INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.6.2 2 10/04/2007
Title:
INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 1 10/04/2007
Title:
INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 1 09/02/2004
Title:
INSTRUMENTATION LOSS OF POWER (LOP) INSTRUMENTATION TEXT 3.3.8.2 0 11/15/2002
Title:
INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1 3 04/12/2006
Title:
REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4.2 0 11/15/2002
Title:
REACTOR COOLANT SYSTEM (RCS) JET PUMPS S TEXT 3.4.3 1
Title:
REACTOR COOLANT SYSTEM (RCS) 01/16/2006 SAFETY/RELIEF VALVES (S/RVS)
Page 3 of8 Report Date: 10/04/07
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.4.4 0 11/15/2002
Title:
REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE TEXT 3.4.5 1 01/16/2006
Title:
REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE TEXT 3.4.6 1 04/18/2005
Title:
REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 2 10/04/2007
Title:
REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 1 04/18/2005
Title:
REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM
- HOT SHUTDOWN TEXT 3.4.9 0 11/15/2002 0
Title:
REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM
- COLD SHUTDOWN TEXT 3.4.10 2 05/10/2006
Title:
REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TEXT 3.4.11 0 11/15/2002
Title:
REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 2 01/16/2006
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM ECCS - OPERATING TEXT 3.5.2 0 11/15/2002
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM ECCS - SHUTDOWN TEXT 3.5.3 1 04/18/2005
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM RCIC SYSTEM TEXT 3.6.1.1 2 10/04/2007
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT Titloe:RprtDte 0/40 Page 1 of Report Date: 10/04/07
SSES MANUAL
. Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.1.2 0 11/15/2002
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3 7 10/04/2007
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)
LDCN 3092 TEXT 3.6.1.4 0 11/15/2002
Title:
CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 1 10/05/2005
Title:
CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE TEXT 3.6.1.6 0 11/15/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS I TEXT 3.6.2.1
Title:
0 11/15/2002 CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 0 11/15/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 1 01/16/2006
Title:
CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 0 11/15/2002
Title:
CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 2 06/13/2006
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT HYDROGEN RECOMBINERS TEXT 3.6.3.2 1 04/18/2005
Title:
CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM TEXT 3.6.3.3 0 11/15/2002 10
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION Page 5 of8 Report Date: 10/04/07
SSES MANUJAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.4.1 7 10/04/2007
Title:
CONTAINMENT SYSTEMS SECONDARY CONTAINMENT TEXT 3.6.4.2 2 01/03/2005
Title:
CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)
TEXT 3.6.4.3 4 09/21/2006
Title:
CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 0 11/15/2002
Title:
PLANT SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER (RHRSW) SYSTEM AND THE ULTIMAaTE HEAT SINK (UHS)
TEXT 3.7.2 1 11/09/2004
Title:
PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM TEXT 3.7.3 0 11/15/2002
Title:
PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM TEXT 3.7.4 0 11/15/2002
Title:
PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 1 10/04/2007
Title:
PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 1 01/17/2005
.Title: PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 1 10/04/2007
Title:
PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.8.1 4 04/18/2006
Title:
ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 0 11/15/2002
Title:
ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN Report Date: 10/04/07 Page5 Page ~ of of 8 .~
Report Date: 10/04/07
SSES MANUAL
. Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.8.3 0 11/15/2002
Title:
ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR TEXT 3.8.4 2 12/14/2006
Title:
ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 1 12/14/2006
Title:
ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN TEXT 3.8.6 1 12/14/2006
Title:
ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS TEXT 3.8.7 1 10/05/2005
Title:
ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - OPERATING TEXT 3.8.8 0 11/15/2002
Title:
ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 0 11/15/2002
Title:
REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 0 11/15/2002
Title:
REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 .0 11/15/2002
Title:
REFUELING OPERATIONS CONTROL ROD POSITION TEXT 3.9.4 0 11/15/2002
Title:
REFUELING OPERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0 11/15/2002
Title:
REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 1 10/04/2007
Title:
REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL Report Date: 10/04/07 Page77 Page of of 88 Report Date: 10/04/07
SSES MANUAL.
Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.9.7 0 11/15/2002
Title:
REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.8 0 11/15/2002
Title:
REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 0 11/15/2002
Title:
SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION TEXT 3.10.2 0 11/15/2002
Title:
SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING TEXT 3.10.3 0 11/15/2002
Title:
SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN TEXT 3.10.4 0 11/15/2002
Title:
SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - COLD SHUTDOWN TEXT 3.10.5 0 11/15/2002
Title:
SPECIAL OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL - REFUELING TEXT 3.10.6 0 11/15/2002
Title:
SPECIAL OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL - REFUELING TEXT 3.10.7 1 04/18/2006
Title:
SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING TEXT 3..10.8 1 04/12/2006
Title:
SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING Report Date: 10/04/07 Pages Page ja of of ~8 Report Date: 10/04/07
TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)
B2.0 SA FETY LIM ITS (S Ls) .................................................................................. B2.0-1 B2.1.1 Reactor C ore S Ls ........................................................................... B2.0-1 B2.1.2 Reactor Coolant System (RCS) Pressure SL ........................... TS/B2.0-7 B3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ........ TS/B3.0-1 B3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY .................. TS/B3.0-10 B3.1 REACTIVITY CONTROL SYSTEMS .................................................... B3.1-1 B3.1.1 Shutdown Margin (SDM) ................................................................ B3.1-1 B3.1.2 Reactivity Anom alies ...................................................................... B3.1-8 B3.1.3 Control Rod OPERABILITY ............................................................ B3.1-13 B3.1.4 Control Rod Scram Times ........................................................ TS/B3.1-22 B3.1.5 Control Rod Scram Accumulators ............................................ TS/B3.1-29 B3.1.6 Rod Pattern Control .................................................................. TS/B3.1-34 B3.1.7 Standby Liquid Control (SLC) System ...................................... TS/B3.1-39 B3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves .......... TS/B3.1-47 B3.2 POWER DISTRIBUTION LIMITS ................................................... TS/B3.2-1 B3.2.1 Average Planar Linear Heat Generation Rate (APLHGR) ........ TS/B3.2-1 B3.2.2 Minimum Critical Power Ratio (MCPR) ..................................... TS/B3.2-5 B3.2.3 Linear Heat Generation Rate (LHGR) ....................................... TS/B3.2-10 B3.2.4 Average Power Range Monitor (APRM) Gain and Setpoints ........................................................................... B 3.2-14 B3.3 INSTRUMENTATION ..................................................................... TS/B3.3-1 B3.3.1.1 Reactor Protection System (RPS) Instrumentation ................... TS/B3.3-1 B3.3.1.2 Source Range Monitor (SRM) Instrumentation ......................... TS/B3.3-35 B3.3.2.1 Control Rod Block Instrumentation ........................................... TS/B3.3-44 B3.3.2.2 Feedwater - Main Turbine High Water Level Trip Instrum entation ......................................................................... B3.3-55 B3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ..................... TS/B3.3-64 B3.3.3.2 Remote Shutdown System ............................................................. B3.3-76 B3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)
Instrum entation ......................................................................... B 3.3-81 B3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation .............................. TS/B3.3-92 B3.3.5.1 Emergency Core Cooling System (ECCS)
Instrum entation ......................................................................... B3.3-101 B3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrum entation ......................................................................... B3.3-135 B3.3.6.1 Primary Containment Isolation Instrumentation .............................. B3.3-147 B3.3.6.2 Secondary Containment Isolation Instrumentation ................... TS/B3.3-180 B3.3.7.1 Control Room Emergency Outside Air Supply (CREOAS)
System Instrumentation ............................................................ B3.3-192 (continued)
SUSQUEHANNA - UNIT 1 TS / B TOC - 1 Revision 13
TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)
B3.3 INSTRUMENTATION (continued)
B3.3.8.1 Loss of Power (LOP) Instrumentation ....................................... TS/B3.3-205 B3.3.8.2 Reactor Protection System (RPS) Electric Power M onitoring ................................................................................ B 3.3-2 13 B3.4 REACTOR COOLANT SYSTEM (RCS) ............................................... B3.4-1 B3.4.1 Recirculation Loops Operating ....................................................... B3.4-1 B 3.4.2 Jet P um ps .............. ;....................................................................... B 3.4-10 B3.4.3 Safety/Relief Valves (S/RVs) .................................................... TS/B3.4-15 B3.4.4 RCS Operational LEAKAGE .......................................................... B3.4-19 B3.4.5 RCS Pressure Isolation Valve (PIV) Leakage ................................. B3.4-24 B3.4.6 RCS Leakage Detection Instrumentation ........................................ B3.4-30 B3.4.7 RCS Specific Activity ................................................................ TS/B3.4-35 B3.4.8 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown ........................................................... B3.4-39 B3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown ......................................................... B3.4-44 B3.4.10 RCS Pressure and Temperature (P/T) Limits ........................... TS/B3.4-49 B3.4.11 Reactor Steam Dome Pressure ................................................ TS/B3.4-58 B3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM .................................. B3.5-1 B3.5.1 ECCS - Operating ......................................................................... B3.5-1 B3.5.2 ECCS - Shutdown ......................................................................... B3.5-19 B3.5.3 RCIC System ........................................................................... TS/B3.5-25 B3.6 CONTAINMENT SYSTEMS ........................................................... TS/B3.6-1 B3.6.1.1 Primary Containment ............................................................... TS/B3.6-1 B3.6.1.2 Primary Containment Air Lock ........................................................ B3.6-7 B3.6.1.3 Primary Containment Isolation Valves (PCIVs) ......................... TS/B3.6-15 B3.6.1.4 Containment Pressure .................................................................... B3.6-41 B3.6.1.5 Drywell Air Temperature ........................................................... TS/B3.6-44 B3.6.1.6 Suppression Chamber-to-Drywell Vacuum Breakers ................ TS/B3.6-47 B3.6.2.1 Suppression Pool Average Temperature ........................................ B3.6-53 B3.6.2.2 Suppression Pool Water Level ....................................................... B3.6-59 B3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ..................................................................................... B3 .6-62 B3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray ............... B3.6-66 B3.6.3.1 Not Used .................................................................................. TS/B3.6-70 B3.6.3.2 Drywell Air Flow System ................................................................. B3.6-76 B3.6.3.3 Primary Containment Oxygen Concentration .................................. B3.6-81 B3.6.4.1 Secondary Containment ........................................................... TS/B3.6-84 B3.6.4.2 Secondary Containment Isolation Valves (SCIVs) .................... TS/B3.6-91 B3.6.4.3 Standby Gas Treatment (SGT) System ................................... TS/B3.6-101 (continued)
SUSQUEHANNA - UNIT I TS / B TOC - 2 Revision 13
TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)
W B3.7 PLANT SYSTEMS ......................................................................... TS/B3.7-1 B3.7.1 Residual Heat Removal Service Water (RHRSW) System and the Ultimate Heat Sink (UHS) ...................................... TS/B3.7-1 B3.7.2 Emergency Service Water (ESW) System ................................ TS/B3.7-7 B3.7.3 Control Room Emergency Outside Air Supply (CREOAS) System ............................................................. TS/B3.7-12 B3.7.4 Control Room Floor Cooling System ........................................ TS/B3.7-19 B3.7.5 Main Condenser Offgas ........................................................... TS/B3.7-24 B3.7.6 Main Turbine Bypass System ................................................... TS/B3.7-27 B3.7.7 Spent Fuel Storage Pool Water Level ...................................... TS/B3.7-31 B3.8 ELECTRICAL POWER SYSTEM ................................................... TS/B3.8-1 B3.8.1 AC Sources - Operating .......................................................... TS/B3.8-1 B3.8.2 AC Sources - Shutdown ................................................................ B3.8-38 B3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air .................. B3.8-45 B3.8.4 DC Sources - Operating .......................................................... TS/B3.8-54 B3.8.5 DC Sources - Shutdown ................................................................ B3.8-66 B3.8.6 Battery Cell Parameters ................................................................. B3.8-71 B3.8.7 Distribution Systems - Operating ................................................... B3.8-78 B3.8.8 Distribution Systems - Shutdown ................................................... B3.8-86 B3.9 REFUELING OPERATIONS .......................................................... TS/B3.9-1 B3.9.1 Refueling Equipment Interlocks ................................................ TS/B3.9-1 B3.9.2 Refuel Position One-Rod-Out Interlock ........................................... B3.9-5 83.9.3 C ontrol Rod Position ...................................................................... B3.9-9 B3.9.4 Control Rod Position Indication ...................................................... B3.9-12 B3.9.5 Control Rod OPERABILITY - Refueling ......................................... B3.9-16 B3.9.6 Reactor Pressure Vessel (RPV) Water Level ........................... TS/B3.9-19 B3.9.7 Residual Heat Removal (RHR) - High Water Level ........................ B3.9-22 B3.9.8 Residual Heat Removal (RHR) - Low Water Level ......................... B3.9-26 B3.10 SPECIAL OPERATIONS ............................................................... TS/B3.10-1 B3.10.1 Inservice Leak and Hydrostatic Testing Operation ................... TS/B3.10-1 B3.10.2 Reactor Mode Switch Interlock Testing .......................................... B3.10-6 B3.10.3 Single Control Rod Withdrawal - Hot Shutdown ............................. B3.10-11 B3.10.4 Single Control Rod Withdrawal - Cold Shutdown ........................... B3.10-16 B3.10.5 Single Control Rod Drive (CRD) Removal - Refueling ................... B3.10-21 B3.10.6 Multiple Control Rod Withdrawal - Refueling ................ B3.10-26 B3.10.7 Control Rod Testing - Operating .................................................... B3.10-29 B3.10.8 SHUTDOWN MARGIN (SDM) Test- Refueling ............................. B3.10-33 TSB1 Text TOC 9/12/2007 SUSQUEHANNA - UNIT 1 TS / B TOC - 3 Revision 13
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision TOC Table of Contents 13 B 2.0 SAFETY LIMITS BASES Page B 2.0-1 0 Page TS / B 2.0-2 3 Page TS / B 2.0-3 4 Page TS / B 2.0-4 3 Page TS / B 2.0-5 4 Page TS / B 2.0-6 1 Pages TS / B 2.0-7 through TS / B 2.0-9 1 B 3.0 LCO AND SR APPLICABILITY BASES Page TS / B 3.0-1 1 Pages TS / B 3.0-2 through TS / B 3.0-4 0 Pages TS / B 3.0-5 through TS / B 3.0-7 1 Pages TS / B 3.0-8 through TS / B 3.0-9 2 Page TS / B 3.0-10 1 Page TS / B 3.0-11 2 Page TS / B 3.0-11a 0 Page TS / B 3.0-12 1 Pages TS / B 3.0-13 through TS / B 3.0-15 2 Pages TS / B 3.0-16 and TS / B 3.0-17 0 B 3.1 REACTIVITY CONTROL BASES Pages B 3.1-1 through B 3.1-4 0 Page TS / B 3.1-5 1 Pages TS / B 3.1-6 and TS / B 3.1-7 2 Pages B 3.1-8 through B 3.1-13 0 Page TS / B 3.1-14 1 Pages B 3.1-15 through B 3.1-21 0 Page TS / B 3.1-22 0 Page TS / B 3.1-23 1 Page TS / B 3.1-24 0 Page TS / B 3.1-25 1 Page TS / B 3.1-26 0 Page TS / B 3.1-27 1 Page TS / B 3.1-28 2 Page TS / B 3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.3-34 through TS / B 3.3-36 1 Pages TS / B 3.1-37 and TS / B 3.1-38 2 Pages TS / B 3.1-39 and TS / B 3.1-40 1 Page TS / B 3.1-40a 0 Pages TS / B 3.1.41 through TS / B 3.1-43 1 Page TS / B 3.1-44 0 Page TS / B 3.1-45 2 Page B 3.1-46 0 SUSQUEHANNA - UNIT I TS / B LOES-1 Revision 85
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Section Title Revision Pages TS / B 3.1-47 through TS / B 3.1-49 1 Page TS / B 3.1-50 0 Page TS / B 3.1-51 2 B 3.2 POWER DISTRIBUTION LIMITS BASES Page TS / B 3.2-1 1 Pages TS / B 3.2-2 through TS / B 3.2-6 2 Page B 3.2-7 0 Pages TS / B 3.2-8 and TS / B 3.2-9 2 Page TS / B 3.2.10 2 Page TS / B 3.2-11 2 Page B 3.2-12 0 Page TS / B 3.2-13 2 Pages B 3.2-14 and B 3.2-15 0 Page TS / B 3.2-16 2 Page B 3.2-17 0 Page TS / B 3.2-18 1 Page TS / B 3.2-19 4 B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through TS / B 3.3-4 1 Page TS / B 3.3-5 2 Page TS / B 3.3-6 1 Page TS / B 3.3-7 3 Page TS / B 3.3-7a 0 Pages TS / B 3.3-8 through TS / B 3.3-12 3 Pages TS / B 3.3-12a through TS / B 3.3-12c 0 Page TS / B 3.3-13 1 Page TS / B 3.3-14 3 Pages TS / B 3.3-15 and TS / B 3.3-16 1 Pages TS / B 3.3-17 and TS / B 3.3-18 3 Page TS / B 3.3-19 1 Pages TS / B 3.3-20 through TS / B 3.3-22 2 Page TS / B 3.3-22a 0 Pages TS / B 3.3-23 and TS / B 3.3-24 2 Pages TS / B 3.3-24a and TS / B 3.3-24b 0 Pages TS / B 3.3-25 and TS / B 3.3-26 2 Page TS / B 3.3-27 1 Pages TS / B 3.3-28 through TS / B 3.3-30 3 Page TS / B 3.3-30a 0 Page TS / B 3.3-31 3 Page TS / B 3.3-32 5 Pages TS / B 3.3-32a and TS / B 3.3-32b 0 Page TS / B 3.3-33 5 Page TS / B 3.3-33a 0 Page TS / B 3.3-34 1 Pages TS / B 3.3-35 and TS / B 3.3-36 2 SUSQUEHANNA - UNIT 1 TS / B LOES-2 Revision 85
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Section Title Revision Pages TS / B 3.3-37 through TS / B 3.3-43 1 Page TS / B 3.3-44 3 Pages TS / B 3.3-45 through TS / B 3.3-49 2 Page TS / B 3.3-50 3 Page TS I B 3.3-51 2 Pages TS / B 3.3-52 and TS / B 3.3-53 1 Page TS / B 3.3-54 3 Pages B 3.3-55 through B 3.3-63 0 Pages TS / B 3.3-64 and TS / B 3.3-65 2 Page TS / B 3.3-66 4 Page TS / B 3.3-67 3 Page TS / B 3.3-68 4 Page TS / B 3.3-69 5 Pages TS / B 3.3-70 and TS / B 3.3-71 3 Pages TS / B 3.3-72 and TS / B 3.3-73 2 Page TS / B 3.3-74 3 Page TS / B 3.3-75 2 Pages TS / B 3.3-75a and TS / B 3.3-75b 6 Page TS / B 3.3-75c 4 Pages B 3.3-76 through 3.3-77 0 Page TS / B 3.3-78 1 Pages B 3.3-79 through B 3.3-89 0 Page TS / B 3.3-90 1 Page B 3.3-91 0 Pages TS / B 3.3-92 through TS / B 3.3-100 1 Pages B 3.3-101 through B 3.3-103 0 Page TS / B 3.3-104 1 Pages B 3.3-105 and B 3.3-106 0 Page TS / B 3.3-107 1 Page B 3.3-108 0 Page TS / B 3.3-109 1 Pages B 3.3-110 and B 3.3-111 0 Pages TS / B 3.3-112 and TS / B 3.3-112a 1 Pages TS / B 3.3-113 through TS / B 3.3-115 1 Page TS / B 3.3-116 2 Page TS / B 3.3-117 1 Pages B 3.3-118 through B 3.3-122 0 Pages TS / B 3.3-123 and TS / B 3.3-124 1 Page TS / B 3.3-124a 0 Page B 3.3-125 0 Pages TS / B 3.3-126 and TS / B 3.3-127 1 Pages B 3.3-128 through B 3.3-130 0 Page TS / B 3.3-131 1 Pages B 3.3-132 through B 3.3-137 0 TS/BLOES-3 Revision 85 SUSQUEHANNA - UNIT SUSQUEHANNA - UNIT II TS / B LOES-3 Revision 85
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Section Title Revision Page TS / B 3.3-138 1 Pages B 3.3-139 through B 3.3-149 0 Pages TS / B 3.3-150 and TS / B 3.3-151 1 Page TS / B 3.3-152 2 Page TS / B 3.3-153 1 Page TS / B 3.3-154 2 Page TS / B 3.3-155 1 Pages TS / B 3.3-156 through TS / B 3.3-158 2 Pages TS / B 3.3-159 through TS / B 3.3-162 1 Page TS / B 3.3-163 2 Pages TS / B 3.3-164 and TS / B 3.3-165 1 Pages TS / B 3.3-166 and TS / B 3.3-167 2 Pages TS / B 3.3-168 and TS / B 3.3-169 1 Page TS / B 3.3-170 2 Pages TS / B 3.3-171 through TS / B 3.3-177 1 Pages TS / B 3.3-178 through TS / B 3.3-179a 2 Pages TS / B 3.3-179b and TS / B 3.3-179c 0 Page TS / B 3.3-180 1 Page TS / B 3.3-181 3 Page TS / B 3.3-182 1 Page TS / B 3.3-183 2 Page TS / B 3.3-184 1 Page TS / B 3.3-185 2 Page TS / B 3.3-186 1 Pages TS / B 3.3-187 and TS / B 3.3-188 2 Pages TS / B 3.3-189 through TS / B 3.3-191 1 Page TS / B 3.3-192 0 Page TS / B 3.3-193 1 Pages TS / B 3.3-194 and TS / B 3.3-195 0 Page TS / B 3.3-196 1 Pages; TS I B 3.3-197 through TS / B 3.3-204 0 Page TS / B 3.3-205 1 Pages B 3.3-206 through B 3.3-219 0 B 3.4 REACTOR COOLANT SYSTEM BASES Pages B 3.4-1 and B 3.4-2 0 Pages TS / B 3.4-3 and Page TS / B 3.4-4 4 Pages TS / B 3.4-5 through TS / B 3.4-9 2 Pages B 3.4-10 through B 3.4-14 0 Page TS / B 3.4-15 1 Pages TS / B 3.4-16 through TS / B 3.4-18 2 Pages B 3.4-19 through B 3.4-27 0 Pages TS / B 3.4-28 and TS / B 3.4-29 1 Pages B 3.4-30 and B 3.4-31 0 Page TS / B 3.4-32 1 Pages B 3.4-33 and B 3.4-34 0 Pages TS / B 3.4-35 and TS / B 3.4-36 1 SUSQUEHANNA - UNIT 1 TS / B LOES-4 Revision 85
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Section Title Revision Page TS / B 3.4-37 2 Page TS / B 3.4-38 1 Pages B 3.4-39 and B 3.4-40 0 Page TS / B 3.4-41 1 Pages B 3.4-42 through B 3.4-48 0 Page TS / B 3.4-49 3 Page TS / B 3.4-50 1 Page TS / B 3.4-51 3 Page TS / B 3.4-52 2 Page TS / B 3.4-53 1 Pages TS / B 3.4-54 and TS / B 3.4-55 2 Page TS / B 3.4-56 1 Page TS / B 3.4-57 3 Pages TS / B 3.4-58 through TS / B 3.4-60 1 B 3.5 ECCS AND RCIC BASES Pages B 3.5-1 and B 3.5-2 0 Page TS / B 3.5-3 2 Page TS / B 3.5-4 1 Page TS / B 3.5-5 2 Page TS / B 3.5-6 1 Pages B 3.5-7 through B 3.5-10 0 Page TS / B 3.5-11 1 Page TS / B 3.5-12 0 Page TS / B 3.5-13 1 Pages TS / B 3.5-14 and TS / B 3.5-15 0 Pages TS / B 3.5-16 through TS / B 3.5-18 1 Pages B 3.5-19 through B 3.5-24 0 Page TS / B 3.5-25 1 Pages TS / B 3.5-26 and TS / B 3.5-27 1 Pages B 3.5-28 through B 3.5-31 0 B 3.6 CONTAINMENT SYSTEMS BASES Page TS / B 3.6-1 2 Pages TS / B 3.6-1a and TS / B 3.6-2 3 Page TS / B 3.6-3 3 Page TS / B 3.6-4 4 Pages TS / B 3.6-5 and TS / B 3.6-6 3 Pages TS / B 3.6-6a and TS / B 3.6-6b 2 Page TS / B 3.6-6c 0 Pages B 3.6-7 through B 3.6-14 0 Page TS / B 3.6-15 2 Page TS / B 3.6-15a 0 Page TS / B 3.6-15b 2 Pages TS / B 3.6-16 and TS / B 3.6-17 1 Page TS / B 3.6-17a 0 Pages TS / B 3.6-18 and TS / B 3.6-19 0 SUSQUEHANNA - UNIT 1 TS / B LOES-5 Revision 85
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Section Title Revision Page TS / B 3.6-20 1 Page TS / B 3.6-21 2 Page TS / B 3.6-22 1 Page TS / B 3.6-22a 0 Page TS / B 3.6-23 1 Pages TS / B 3.6-24 and TS / B 3.6-25 0 Pages TS / B 3.6-26 and TS / B 3.6-27 2 Page TS / B 3.6-28 6 Pages TS / B 3.6-29 and TS / B 3.6-30 1 Page TS / B 3.6-31 3 Page TS / B 3.6-32 0 Page TS / B 3.6-33 1 Pages TS / B 3.6-34 and TS / B 3.6-35 0 Page TS / B 3.6-36 1 Page TS / B 3.6-37 0 Page TS / B 3.6-38 3 Page TS / B 3.6-39 2 Page TS / B 3.6-40 6 Pages B 3.6-41 through B 3.6-43 3 Pages TS / B 3.6-44 and TS / B 3.6-45 1 Page TS / B 3.6-46 2 Pages TS / B 3.6-47 through TS / B 3.6-51 1 Page TS / B 3.6-52 2 Pages B 3.6-53 through B 3.6-63 0 Pages TS / B 3.6-64 and TS / B 3.6-65 1 Pages B 3.6-66 through B 3.6-69 0 Pages TS / B 3.6-70 through TS / B 3.6-72 1 Page TS / B 3.6-73 2 Pages TS / B 3.6-74 and TS / B 3.6-75 1 Pages B 3.6-76 and B 3.6-77 0 Page TS / B 3.6-78 1 Pages B 3.6-79 through B 3.3.6-83 0 Page TS / B 3.6-84 3 Page TS / B 3.6-85 2 Page TS / B 3.6-86 4 Pages TS / B 3.6-87 through TS / B 3.6-88a 2 Page TS / B 3.6-89 4 Page TS / B 3.6-90 2 Page TS / B 3.6-91 3 Pages TS / B 3.6-92 through TS / B 3.6-96 1 Page TS / B 3.6-97 2 Pages TS / B 3.6-98 and TS / B 3.6-99 1 Page TS / B 3.6-100 2 Pages TS / B 3.6-101 and TS / B 3.6-102 1 Pages TS / B 3.6-103 and TS / B 3.6-104 2 TS/BLOES-6 Revision 85 SUSQUEHANNA-UNITI SUSQUEHANNA - UNIT 1 TS / B LOES-6 Revision 85
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page TS / B 3.6-105 3 Page TS / B 3.6-106 2 Page TS / B 3.6-107 3 B 3.7 PLANT SYSTEMS BASES Pages TS / B 3.7-1 through TS / B 3.7-6 2 Page TS / B 3.7-6a 2 Pages TS / B 3 3.7-6b and TS / B 3.7-6c 0 Page TS / B 3.7-7 2 Pages TS / B 3.7-8 through TS / B 3.7-13 1 Pages TS / B 3.7-14 through TS / B 3.7-18 2 Page TS / B 3.7-18a 0 Pages TS / B 3.7-19 through TS / B 3.7-23 1 Page TS / B 3.7-24 1 Pages TS / B 3.7-25 and TS / B 3.7-26 0 Pages TS / B 3.7-27 through TS / B 3.7-29 4 Page TS / B 3.7-30 2 Page TS / 8 3.7-31 1 Page TS / B 3.7-32 0 Page TS / B 3.7-33 1 B 3.8 ELECTRICAL POWER SYSTEMS BASES Pages TS / B 3.8-1 through TS / 8 3.8-3 2 Page TS / B 3.8-4 3 Pages TS / 8 3.8-4a and TS / 8 3.8-4b 0 Page TS / B 3.8-5 4 Page TS / B 3.8-6 3 Pages TS / B 3.8-7 through TS/B 3.8-8 2 Page TS / 8 3.8-9 4 Page TS / B 3.8-10 3 Pages TS / 8 3.8-11 and TS / B 3.8-17 2 Page TS / 8 3.8-18 3 Pages TS / B 3.8-19 through TS / 8 3.8-21 2 Pages TS / B 3.8-22 and TS / B 3.8-23 3 Pages TS / B 3.8-24 through TS / 8 3.8-37 2 Pages B 3.8-38 through B 3.8-53 0 Pages TS / B 3.8-54 through TS / B 3.8-61 2 Pages TS / B 3.8-62 and TS / B 3.8-63 4 Page TS / B 3.8-64 3 Page TS / B 3.8-65 4 Pages TS / 8 3.8-66 through TS / B 3.8-77 1 Pages TS / B 3.8-77A through TS / B 3.8-77C 0 Pages B 3.8-78 through B 3.8-80 0 Page TS / B 3.8-81 1 Pages B 3.8-82 through B 3.8-90 0 TSIBLOES-7 Revision 85 SUSQUEHANNA - UNIT SUSQUEHANNA -
UNIT 11 TS I B LOES-7 Revision 85
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision B 3.9 REFUELING OPERATIONS BASES Pages TS / B 3.9-1 and TS / B 3.9-1a 1 Pages TS / B 3.9-2 through TS / B 3.9-4 1 Pages B 3.9-5 through B 3.9-18 0 Pages TS / B 3.9-19 through TS / B 3.9-21 1 Pages B 3.9-22 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES Page TS / B 3.10-1 1 Pages B 3.10-2 through B 3.10-31 0 Page TS / B 3.10-32 2 Page B 3.10-33 0 Page TS / B 3.10-34 1 Pages B 3.10-35 and B 3.10-36 0 Page TS / B 3.10-37 1 Page TS / B 3.10-38 2 TSB1 Tex" LOES.doc 9/13/07 TSIBLOES-8 Revision 85 SUSQUEHANNA - UNIT SUSQUEHANNA -
UNIT 1 1 TS I B LOES-8 Revision 85
PPL Rev. 3 Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs)
B 2.1.1 Reactor Core SLs BASES BACKGROUND GDC 10 (Ref. 1) requires, and SLs ensure, that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and anticipated operational occurrences (AOOs).
The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in Specification 2.1.1.2 for Siemens Power Corporation fuel. MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity.
The fuel cladding is one of the physical barriers that 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 significantly above design conditions.
While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration.
Therefore, the fuel cladding SL is defined with a margin to the conditions that would produce onset of transition boiling (i.e., MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. The MCPR fuel cladding integrity SL ensures that during normal operation and during AQOs, at least 99.9% of the fuel rods in the core do not experience transition boiling.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 2.0-1 Revision 0
PPL Rev. 3 Reactor Core SLs B 2.1.1 BASES BACKGROUND Operation above the boundary of the nucleate boiling regime could (continued) result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant.
APPLICABLE The fuel cladding must not sustain damage as a result of normal SAFETY ANALYSES operation and AQOs. The reactor core SLs are established to preclude violation of the fuel design criterion that an MCPR limit is to be established, such that at least 99.9% of the fuel rods in the core would not be expected to experience the onset of transition boiling.
The Reactor Protection System setpoints (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with the other LCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR limit.
2.1.1.1 Fuel Claddina Intearitv The use of the SPCB (Reference 4) correlation is valid for critical power calculations at pressures _>571.4 psia and bundle mass fluxes
> 0.087 x 10' lb/hr-ft2 . For operation at low pressures or low flows, the fuel cladding integrity SL is established by a limiting condition on core THERMAL POWER, with the following basis:
Provided that the water level in the vessel downcomer is maintained above the top of the active fuel, natural circulation is sufficient to ensure a minimum bundle flow for all fuel assemblies that have a relatively high power and potentially can approach a critical heat flux condition.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 2.0-2 Revision 3
PPL Rev. 3 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)
SAFETY ANALYSES For the SPC ATRIUM-10 design, the minimum bundle flow is
> 28 x 103 lb/hr. For the ATRIUM-10 fuel design, the coolant minimum bundle flow and maximum area are such that the mass flux is always> .25 x 106 lb/hr-ft2 . Full scale critical power test data taken from various SPC and GE fuel designs at pressures from 14.7 psia to 1400 psia indicate the fuel assembly critical power at 0.25 x 106 Ib/hr-ft 2 is approximately 3.35 MWt. At 25% RTP, a bundle power of approximately 3.35 MWt corresponds to a bundle radial peaking factor of approximately 3.0, which is significantly higher than the expected peaking factor. Thus, a THERMAL POWER limit of 25% RTP for reactor pressures < 785 psig is conservative.
2.1.1.2 MCPR The MCPR SL ensures sufficient conservatism in the operating MCPR limit that, in the event of an AOO from the limiting condition of operation, at least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The margin between calculated boiling transition (i.e., MCPR = 1.00) and the MCPR SL is based on a detailed statistical procedure that considers the uncertainties in monitoring the core operating state. One specific uncertainty included in the SL is the uncertainty in the critical power correlation. References 2, 4, and 5 describe the methodology used in determining the MCPR SL.
The SPCB critical power correlation is based on a significant body of practical test data. As long as the core pressure and flow are within the range of validity of the correlations (refer to Section B.2.1.1.1), the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and bounding flat local peaking distributions are used to estimate the number of rods in boiling transition. These conservatisms and the inherent accuracy of the SPCB correlation provide a reasonable degree of assurance that during sustained operation at the MCPR SL there would be no transition boiling in the core.
(continued)
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PPL Rev. 3 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.2 MCPR (continued)
SAFETY ANALYSES If boiling transition were to occur, there is reason to believe that the integrity of the fuel would not be compromised.
Significant test data accumulated by the NRC and private organizations indicate that the use of a boiling transition limitation to protect against cladding failure is a very conservative approach. Much of the data indicate that BWR fuel can survive for an extended period of time in an environment of boiling transition.
SPC Atrium -10 fuel is monitored using the SPCB Critical Power Correlation. The effects of channel bow on MCPR are explicitly included in the calculation of the MCPR SL. Explicit treatment of channel bow in the MCPR SL addresses the concerns of NRC Bulletin No. 90-02 entitled "Loss of Thermal Margin Caused by Channel Box Bow."
Monitoring required for compliance with the MCPR SL is specified in LCO 3.2.2, Minimum Critical Power Ratio.
2.1.1.3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability.
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 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 reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes < 2/3 of the core height.
The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be (continued)
SUSQUEHANNA - UNIT 1 TS / B 2.0-4 Revision 3
PPL Rev. 3 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.3 Reactor Vessel Water Level (continued)
SAFETY ANALYSES monitored and to also provide adequate margin for effective action.
SAFETY LIMITS The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of radioactive materials to the environs.
SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria. SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.
APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.
SAFETY LIMIT Exceeding an SL may cause fuel damage and create a potential for VIOLATIONS radioactive releases in excess of regulatory limits. Therefore, it is required to insert all insertable control rods and restore compliance with the SLs within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.
REFERENCES 1. 10 CFR 50, Appendix A, GDC 10.
- 2. ANF 524 (P)(A), Revision 2, "Critical Power Methodology for Boiling Water Reactors," Supplement 1 Revision 2 and Supplement 2, November 1990.
- 3. Deleted. I
- 4. EMF-2209(P)(A), Revision 1, "SPCB Critical Power Correlation," Siemens Power Corporation, July 2000.
- 5. EMF-2158(P)(A), Revision 0, "Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASMO-4/Microbum-B2," October 1999.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 2.0-5 Revision 4
PPL Rev. 3 Reactor Core SLs B 2.1.1 BASES THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 1 TS / B 2.0-6 Revision 1
PPL Rev. 1 RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs)
B 2.1.2 Reactor Coolant System (RCS) Pressure SL BASES BACKGROUND The SL on reactor steam dome pressure protects the RCS against overpressunzation. In the event of fuel cladding failure, fission products are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere.
Establishing an upper limit on reactor steam dome pressure ensures continued RCS integrity. According to 10 CFR 50, Appendix A, GDC 14, "Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) shall be designed with sufficient margin to ensure that the design conditions are not exceeded during normal operation and anticipated operational occurrences (AOOs).
During normal operation and AQOs, RCS pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code (Ref. 2). To ensure system integrity, all RCS components are hydrostatically tested at 125% of design pressure, in accordance with ASME Code requirements, prior to initial operation when there is no fuel in the core. Any further hydrostatic testing with fuel in the core may be done under LCO 3.10.1, "Inservice Leak and Hydrostatic Testing Operation." Following inception of unit operation, RCS components shall be pressure tested in accordance with the requirements of ASME Code,Section XI (Ref. 3).
Overpressurization of the RCS could result in a breach of the RCPB, reducing the number of protective barriers designed to prevent radioactive releases from exceeding regulatory limits. If this occurred in conjunction I with a fuel cladding failure, fission products could enter the containment atmosphere.
APPLICABLE The RCS safety/relief valves and the Reactor Protection System Reactor SAFETY High Flux and Vessel Steam Dome Pressure-High Function have settings ANALYSES established to ensure that the RCS pressure SL will not be exceeded.
(continued)
SUSQUEHANNA- UNIT 1 TS / B 2.0-7 Revision 1
PPL Rev. 1 RCS Pressure SL B 2.1.2 BASES APPLICABLE The RCS pressure SL has been selected such that it is at a pressure SAFETY ANALYSES below which it can be shown that the integrity of the system is not (continued) endangered. The reactor pressure vessel is designed to Section Ili of the ASME, Boiler and Pressure Vessel Code, 1968 Edition, including Addenda through the summer of 1970 (Ref. 5), which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig. The SL of 1325 psig, as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS.
The RCS inside containment is designed to the ASME Boiler and Pressure Vessel Code,Section III, 1971 Edition with Addenda through summer of 1972 (Ref. 6), for the reactor recirculation piping, which permits a maximum pressure transient of 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes.
SAFETY LIMITS The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code,Section III, is 110% of design pressure. The maximum transient pressure allowable in the RCS piping, valves, and fittings is 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The most limiting of these allowances is the 110% of the suction piping design pressures; therefore, the SL on maximum allowable RCS pressure is established at 1325 psig as measured at the reactor steam dome.
APPLICABILITY SL 2.1.2 applies in all MODES.
SAFETY LIMIT Exceeding the RCS pressure SL may cause immediate RCS failure VIOLATIONS and create a potential for radioactive releases in excess of regulatory limits. Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an accident occurring during this period is minimal.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 2.0-8 Revision 1
PPL Rev. 1 RCS Pressure SL B 2.1.2 BASES (continued)
REFERENCES 1. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28.
- 2. ASME, Boiler and Pressure Vessel Code,Section III, Article NB-7000.
- 3. ASME, Boiler and Pressure Vessel Code,Section XI, Article IW-5000.
- 4. Deleted.
- 5. ASME, Boiler and Pressure Vessel Code,Section III, 1968 Edition, Addenda summer of 1970.
- 6. ASME, Boiler and Pressure Vessel Code,Section III, 1971 Edition, Addenda summer of 1972.
SUSQUEHANNA - UNIT I TS / B 2.0-9 Revision 1
PPL Rev. 2 SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement Additionally, the SLC System is designed to provide sufficient buffering agent to maintain the suppression pool pH at or above 7.0 following a DBA LOCA involving fuel damage. Maintaining the suppression pool pH at or above 7.0 will mitigate the re-evolution of iodine from the suppression pool water following a DBA LOCA. The SLC system satisfies the requirements of 10 CFR 50.62 (Ref. 1) for anticipated transient without scram.
The SLC System consists of a sodium pentaborate solution storage tank, two positive displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to transfer borated water from the storage tank to the reactor pressure vessel (RPV).
The borated solution is discharged near the bottom of the core shroud, where it then mixes with the cooling water rising through the core. A smaller tank containing demineralized water is provided for testing purposes.
APPLICABLE The SLC System is manually initiated from the main control room, as SAFETY directed by the emergency operating procedures, if the operator believes the ANALYSES reactor cannot be shut down, or kept shut down, with the control rods or if fuel damage occurs post-LOCA. The SLC System is used in the event that enough control rods cannot be inserted to accomplish shutdown and iI cooldown in the normal manner or if fuel damage occurs post-LOCA. The SLC System injects borated water into the reactor core to add negative reactivity to compensate for all of the various reactivity effects that could occur during plant operations. To meet this objective, it is necessary to inject a quantity of boron, which produces a concentration of 660 ppm of natural boron, in the reactor coolant at 680 F. To allow for potential leakage and imperfect mixing in the reactor system, an amount of boron equal to 25% of the amount cited above is added (Ref. 2). The volume versus concentration limits in Figure 3.1.7-1 and the temperature versus concentration limits in Figure 3.1.7-2 are calculated such that the required concentration is achieved accounting for dilution in the RPV with normal water level and including the water volume in (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-39 Revision 1
PPL Rev. 2 SLC System B 3.1.7 BASES APPLICABLE the residual heat removal shutdown cooling piping and in the recirculation SAFETY loop piping. This quantity of borated solution is the amount that is above ANALYSES the pump suction shutoff level in the boron solution storage tank. No credit (continued) is taken for the portion of the tank volume that cannot be injected. The minimum concentration of 13.6 weight percent ensures compliance with the requirements of 10 CFR 50.62 (Ref. 1).
The SLC System is also used to control Suppression Pool pH in the event of a DBA LOCA by injecting sodium pentaborate into the reactor vessel. The sodium pentaborate is then transported to the suppression pool and mixed by ECCS flow recirculation through the reactor, out of the break and into the suppression chamber. The amount of sodium pentaborate solution that must be available for injection following a DBA LOCA is determined as part of the DBA LOCA radiological analysis. This quantity is maintained in the storage tank as specified in the Technical Specification.
The SLC System satisfies the requirements of the NRC Policy Statement (Ref. 3) because operating experience and probabilistic risk assessments have shown the SLC System to be important to public health and safety.
Thus, it is retained in the Technical Specifications.
LCO The OPERABILITY of the SLC System provides backup capability for reactivity control independent of normal reactivity control provisions provided by the control rods and provides sufficient buffering agent to maintain the suppression pool pH at or above 7.0 following a DBA LOCA involving fuel damage. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves. Two SLC subsystems are required to be OPERABLE; each contains an OPERABLE pump, an explosive valve, and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.
APPLICABILITY In MODES 1 and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn (except as permitted by LCO 3.10.3 and LCO 3.10.4) since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure that the reactor remains subcritical. In MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Demonstration of adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") ensures that the reactor will not become critical. Therefore, the SLC System is not required to be OPERABLE when only a single control rod can be withdrawn.
(continued)
SUSQUEHANNA- UNIT 1 TS / B 3.1-40 Revision I
PPL Rev. 2 SLC System B 3.1.7 BASES APPLICABILITY A DBA LOCA that results in the release of radioactive material is possible in (continued) MODES 1, 2 and 3; therefore, capability to buffer the suppression pool pH is required. In MODES 4 and 5, a DBA LOCA with a radioactive release need not be postulated.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-40a Revision 0
PPL Rev. 2 SLC System B 3.1.7 BASES ACTIONS A.1 If the boron solution concentration is less than the required limits for compliance with 10 CFR 50.62 (Ref. 1) (> 13.6 weight percent) but greater than the concentration required for cold shutdown (original licensing basis) and suppression pool pH control, the concentration must be restored to within limits > 13.6 weight percent in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. It is not necessary under these conditions to enter Condition C for both SLC subsystems inoperable since they are capable of performing their original design basis functions.
Because of the low probability of an event and the fact that the SLC System capability still exists for vessel injection under these conditions, the allowed Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is acceptable and provides adequate time to restore concentration to within limits.
The second Completion Time for Required Action A.1 establishes a limit on the maximum time allowed for any combination of concentration out of limits or inoperable SLC subsystems during any single continuous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, an SLC subsystem is inoperable and that subsystem is subsequently returned to OPERABLE, the LCO may already have been not met for up to 7 days. This situation could lead to a total duration of 10 days (7 days in Condition B, followed by 3 days in Condition A), since initial failure of the LCO, to restore the SLC System. Then an SLC subsystem could be found inoperable again, and concentration could be restored to within limits. This could continue indefinitely.
This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock," resulting in establishing the "time zero" at the time the LCO was initially not met instead of at the time Condition A was entered. The 10 day Completion Time is an acceptable limitation on this potential to fail to meet the LCO indefinitely.
B. 1 If one SLC subsystem is inoperable for reasons other than Condition A, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining OPERABLE subsystem is adequate to perform the (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-41 Revision 1
PPL Rev. 2 SLC System B 3.1.7 BASES ACTIONS B.1 (continued) shutdown function and provide adequate buffering agent to the suppression pool. However, the overall reliability is reduced because a single failure in the remaining OPERABLE subsystem could result in reduced SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System functions and the low probability of an event occurring requiring SLC injection.
The second Completion Time for Required Action B.1 establishes a limit on the maximum time allowed for any combination of concentration out of limits or inoperable SLC subsystems during any single continuous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, concentration is out of limits, and is subsequently returned to within limits; the LCO may already have been not met for up to 3 days. This situation could lead to a total duration of 10 days (3 days in Condition A, followed by 7 days in Condition B), since initial failure of the LCO, to restore the SLC System. Then concentration could be found out of limits again, and the SLC subsystem could be restored to OPERABLE. This could continue indefinitely.
This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock," resulting in establishing the "time zero" at the time the LCO was initially not met instead of at the time Condition B was entered. The 10 day Completion Time is an acceptable limitation on this potential to fail to meet the LCO indefinitely.
C.1 If both SLC subsystems are inoperable for reasons other than Condition A, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The allowed Completion Time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is considered acceptable given the low probability of an event occurring requiring SLC injection.
(continued)
SUSQUEHANNA - UNIT 1 TS I B 3.1-42 Revision 1
PPL Rev. 2 SLC System B 3.1.7 BASES ACTIONS D.1 (continued)
If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 are 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Surveillances verifying certain characteristics of the SLC System (e.g., the volume and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution volume and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in ensuring that the sodium pentaborate remains in solution and does not precipitate out in the storage tank or in the pump suction piping.
The temperature versus concentration curve of Figure 3.1.7-2 ensures that a 10OF margin will be maintained above the saturation temperature. An alternate method of performing SR 3.1.7.3 is to verify the OPERABILITY of the SLC heat trace system. This verifies the continuity of the heat trace lines and ensures proper heat trace operation, which ensure that the SLC suction piping temperature is maintained. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience and has shown there are relatively slow variations in the measured parameters of volume and temperature.
SR 3.1.7.4 and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on (continued)
SUSQUEHANNA- UNIT 1 TS / B 3.1-43 Revision 1
PPL Rev. 2 SLC System B 3.1.7 BASES SURVEILLANCE SURVEQIR NENS SR 3.1.7.4 and SR 3.1.7.6 (continued)
REQUIREMENTS operating experience and has demonstrated the reliability of the explosive charge continuity.
SR 3.1.7.6 verifies that each valve in the system is in its correct position, but does not apply to the squib (i.e., explosive) valves. Verifying the correct alignment for manual and power operated valves in the SLC System flow path provides assurance that the proper flow paths will exist for system operation. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position from the control room, or locally by a dedicated operator at the valve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance also does not apply to valves that are locked, sealed, or otherwise secured in position since they are verified to be in the correct position prior to locking, sealing, or securing.
This verification of valve alignment does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation that ensures correct valve positions.
SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of sodium pentaborate exists in the storage tank. SR 3.1.7.5 must be performed anytime sodium pentaborate or water is added to the storage tank solution to determine that the sodium pentaborate solution concentration is within the specified limits. SR 3.1.7.5 must also be performed anytime the temperature is restored to within the limits of Figure 3.1.7-2, to ensure that no significant sodium pentaborate precipitation occurred. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of sodium pentaborate concentration between surveillances.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-44 Revision 0
PPL Rev. 2 SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.7 REQUIREMENTS (continued) Demonstrating that each SLC System pump develops a flow rate _Ž 41.2 gpm at a discharge pressure >_1395 psig without actuating the pump's relief valve ensures that pump performance has not degraded during the fuel cycle.
Testing at 1395 psig assures that the functional capability of the SLC system meets the ATWS Rule (10 CFR 50.62) (Ref. 1) requirements. This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. Additionally, the minimum pump flow rate requirement ensures that adequate buffering agent will reach the suppression pool to maintain pH above 7.0. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.
SR 3.1.7.8 and SR 3.1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 48 months at alternating 24 month intervals. The Surveillance may be performed in separate steps to prevent injecting solution into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
Demonstrating that all heat traced piping between the boron solution storage tank and the suction inlet to the injection (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-45 Revision 2
PPL Rev. 2 SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.8 and SR 3.1.7.9 (continued)
REQUIREMENTS pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to pump from the storage tank to the test tank. This test can be performed by any series of overlapping or total flow path test so that the entire flow path is included.
The 24 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping. This is especially true in light of the temperature verification of this piping required by SR 3.1.7.3. However, if, in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum or the heat trace was not properly energized and building temperature was below the temperature at which the SLC solution would precipitate out, SR 3.1.7.9 must be performed once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the piping temperature is restored to within the limits of Figure 3.1.7-2.
REFERENCES 1. 10 CFR 50.62.
- 2. FSAR, Section 9.3.5.
- 3. Final Policy Statement on Technical Specifications Improvements, July 22,1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.1-46 Revision 0
PPL Rev. 2 SDV Vent and Drain Valves B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves BASES BACKGROUND The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that sufficient volume is available at all times to allow a complete scram. During a scram, the SDV vent and drain valves close to contain reactor water. The SDV is a volume of header piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume. There are two SDVs (headers) and two instrument volumes, each receiving approximately one half of the control rod drive (CRD) discharges. The two instrument volumes are connected to a common drain line with two valves in series. Each header is connected to a common vent line with two valves in series. The header piping is sized to receive and contain all the water discharged by the CRDs during a scram. The design and functions of the SDV are described in Reference 1.
APPLICABLE The Design Basis Accident and transient analyses assume all of the SAFETY control rods are capable of scramming. The acceptance criteria for the ANALYSES SDV vent and drain valves are that they operate automatically to:
- a. Close during scram to limit the amount of reactor coolant discharged so that adequate core cooling is maintained and offsite and control room doses remain within regulatory limits; and I
- b. Open on scram reset to maintain the SDV vent and drain path open so that there is sufficient volume to accept the reactor coolant discharged during a scram.
Isolation of the SDV can also be accomplished by manual closure of the SDV valves. Additionally, the discharge of reactor coolant to the SDV can be terminated by scram reset or closure of the HCU manual isolation valves. For a bounding leakage case, the offsite and control room doses are well within regulatory limits, and adequate core cooling is maintained (Ref. 3). The SDV vent and drain valves allow continuous drainage of the SDV during normal plant operation (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-47 Revision I
PPL Rev. 2 SDV Vent and Drain Valves B 3.1.8 BASES APPLICABLE to ensure that the SDV has sufficient capacity to contain the reactor SAFETY coolant discharge during a full core scram. To automatically ensure this ANALYSES capacity, a reactor scram (LCO 3.3.1.1, "Reactor Protection System (RPS)
(continued) Instrumentation") is initiated if the SDV water level in the instrument volume exceeds a specified setpoint. The setpoint is chosen so that all control rods are inserted before the SDV has insufficient volume to accept a full scram.
SDV vent and drain valves satisfy Criterion 3 of the NRC Policy Statement (Ref. 4).
LCO The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain valves will close during a scram to contain reactor water discharged to the SDV piping. The SDV vent and drain valves are required to be open to ensure the SDV is drained. Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system. Additionally, the valves are required to open on scram reset to ensure that a path is available for the SDV piping to drain freely at other times.
APPLICABILITY In MODES 1 and 2, scram may be required; therefore, the SDV vent and drain valves must be OPERABLE. In MODES 3 and 4, control rods are not able to be withdrawn (except as permitted by LCO 3.10.3 and LCO 3.10.4) since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure that only a single control rod can be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies.
Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram.
ACTIONS The ACTIONS table is modified by Note 1 indicating that a separate Condition entry is allowed for the SDV vent line and the SDV drain line. This is acceptable, since the (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-48 Revision 1
PPL Rev. 2 SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS Required Actions for each Condition provide appropriate compensatory (continued) actions for each inoperable SDV line. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions.
The ACTIONS table is modified by a second note stating that a isolated line may be unisolated under administrative control to allow draining and venting of the SDV. When a line is isolated, the potential for an inadvertent scram due to high SDV level is increased. During these periods, the line may be unisolated under administrative control. This allows any accumulated water in the line to be drained, to preclude a reactor scram on high SDV level. This is acceptable since administrative controls ensure the valve can be closed quickly, if a scram occurs with the valve open.
A.1 When one SDV vent or drain valve is inoperable in one or more lines, the associated line must be isolated to contain the reactor coolant during a scram. The 7 day Completion Time is reasonable, given the level of redundancy in the lines and the low probability of a scram occurring while the valve(s) are inoperable and the line is not isolated. The SDV is still isolable since the redundant valve in the affected line is OPERABLE.
During these periods, the single failure criterion is not preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.
B. 1 If both valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram.
The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time to isolate the line is based on the low probability of a scram occurring while the line is not isolated and unlikelihood of significant CRD seal leakage.
C.1 If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-49 Revision 1
PPL Rev. 2 SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS C.1 (continued) does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2) to allow for drainage of the SDV piping. Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended functions during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verification that the valves are in the correct position.
The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation, which ensure correct valve positions.
SR 3.1.8.2 During a scram, the SDV vent and drain-valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through its complete range of motion (closed and opený ensures that the valve will function properly during a scram. The 92 day Frequency is based on operating experience and takes into account the level of redundancy in the system design.
SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-50 Revision 0
PPL Rev. 2 SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE URVEQUIR NENS SR 3.1.8.3 (continued)
REQUIREMENTS 30 seconds after receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis based on the requirements of Reference 2. Similarly, after receipt of a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.1.3 overlap this Surveillance to provide complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES 1. FSAR, Section 4.6.
- 2. Deleted.
- 3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping," August 1981.
- 4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
- 5. TSTF-404-A, Rev. 0.
SUSQUEHANNA - UNIT 1 TS / B 3.1-51 Revision 2
PPL Rev. 1 LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)
BASES BACKGROUND The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation. Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials.
Fuel design limits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the normal operations identified in Reference 1.
APPLICABLE The analytical methods and assumptions used in evaluating the fuel SAFETY system design are presented in References 1, 2, 3, and 4. The fuel ANALYSES assembly is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in excess of regulatory limits. The mechanisms I that could cause fuel damage during operational transients and that are considered in fuel evaluations are:
- a. Rupture of the fuel rod cladding caused by strain from the relative expansion of the U0 2 pellet; and
- b. Severe overheating of the fuel rod cladding caused by inadequate cooling.
A value of 1% plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 3).
Fuel design evaluations have been performed and demonstrate that the 1% fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the operating limit specified in the COLR. A separate evaluation was performed to determine the limits of LHGR during anticipated operational occurrences. This limit, (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.2-10 Revision 2
PPL Rev. 1 LHGR B 3.2.3 BASES APPLICABLE Protection Against Power Transients (PAPT), defined in Reference 4 SAFETY provides the acceptance criteria for LHGRs calculated in evaluation of ANALYSES the AQOs.
(continued)
The LHGR satisfies Criterion 2 of the NRC Policy Statement (Ref. 7).
LCO The LHGR is a basic assumption in the fuel design analysis. The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to cause a 1% fuel cladding plastic strain. The operating limit to accomplish this objective is specified in the COLR.
APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels < 25% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at Ž 25% RTP.
ACTIONS A.1 If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.2-11 Revision 2
PPL Rev. 1 LHGR B 3.2.3 BASES ACTIONS A._1 (continued) restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.
B.1I If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER is reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.2.3.1 REQUIREMENTS The LHGR is required to be initially calculated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER is >_25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter.
Additionally, LHGRs must be calculated prior to exceeding 50% RTP unless performed in the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The LHGR is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slow changes in power distribution during normal operation. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowance after THERMAL POWER >_25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels and because the LHGRs must be calculated prior to exceeding 50% RTP.
REFERENCES 1. FSAR, Section 4.
- 2. FSAR, Section 5.
- 3. NUREG-0800,Section II.A.2(g), Revision 2, July 1981.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.2-12 Revision 0
PPL Rev. 1 LHGR B 3.2.3 BASES REFERENCES 4. ANF-89-98(P)(A) Revision 1 and Revision 1 Supplement 1, (continued) "Generic Mechanical Design Criteria for BWR Fuel Designs,"
Advanced Nuclear Fuels Corporation, May 1995.
- 5. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.2-13 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3 INSTRUMENTATION B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs). The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs). Primary containment 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 DBA.
The isolation instrumentation includes the sensors, relays, and instruments that are necessary to cause initiation of primary containment and reactor coolant pressure boundary (RCPB) isolation. When the setpoint is reached, the sensor actuates, which then outputs an isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logics are (a) reactor vessel water level, (b) area ambient and emergency cooler temperatures, (c) main steam line (MSL) flow measurement, (d) Standby Liquid Control (SLC) System initiation, (e) condenser vacuum, (f) main steam line pressure, (g) high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) steam line A pressure, (h) SGTS Exhaust radiation, (i) HPCI and RCIC steam line pressure, (j) HPCI and RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) differential flow and high flow, (I) reactor steam dome pressure, and (m) drywell pressure. Redundant sensor input signals from each parameter are provided for initiation of isolation. The only exception is SLC System initiation. In addition, manual isolation of the logics is provided.
Primary containment isolation instrumentation has inputs to the trip logic of the isolation functions listed below.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.3-147 Revision 0
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 1. Main Steam Line Isolation (continued)
Most MSL Isolation Functions receive inputs from four channels. The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of all main steam isolation valves (MSIVs).
The outputs from the same channels are arranged into two two-out-of-two logic trip systems to isolate all MSL drain valves. The MSL drain line has two isolation valves with one two-out-of-two logic system associated with each valve.
The exceptions to this arrangement are the Main Steam Line Flow-High Function. The Main Steam Line Flow-High Function uses 16 flow channels, four for each steam line. One channel from each steam line inputs to one of the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an MSL isolation. Each trip string has four inputs (one per MSL), any one of which will trip the trip string. The trip strings are arranged in a one-out-of-two taken twice logic. This is effectively a one-out-of-eight taken twice logic arrangement to initiate isolation of the MSIVs. Similarly, the 16 flow channels are connected into two two-out-of-two logic trip systems (effectively, two one-out-of-four twice logic), with each trip system isolating one of the two MSL drain valves.
- 2. Primary Containment Isolation Most Primary Containment Isolation Functions receive inputs from four channels. The outputs from these channels are arranged into two two-out-of-two logic trip systems. One trip system initiates isolation of all inboard primary containment isolation valves, while the other trip system initiates isolation of all outboard primary containment isolation valves.
Each logic closes one of the two valves on each penetration, so that operation of either logic isolates the penetration.
The exceptions to this arrangement are as follows. Hydrogen and Oxygen Analyzers which isolate Division I Analyzer on a Division I isolation signal, and Division II Analyzer on a Division II isolation signal.
This is to ensure monitoring capability is not lost. Chilled Water to recirculation pumps and Liquid Radwaste Collection System isolation valves (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-148 Revision 0
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 2. Primary Containment Isolation (continued) where both inboard and outboard valves will isolate on either division providing the isolation signal. Traversing incore probe ball valves and the instrument gas to the drywell to suppression chamber vacuum breakers only have one isolation valve and receives a signal from only one division.
3., 4. High Pressure Coolant Iniection System Isolation and Reactor Core Isolation Cooling System Isolation Most Functions that isolate HPCI and RCIC receive input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems in each isolation group is connected to one of the two valves on each associated penetration.
The exceptions are the HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High and Steam Supply Line Pressure-Low Functions.
These Functions receive inputs from four turbine exhaust diaphragm pressure and four steam supply pressure channels for each system.
The outputs from the turbine exhaust diaphragm pressure and steam supply pressure channels are each connected to two two-out-of-two trip systems. Each trip system isolates one valve per associated penetration.
- 5. Reactor Water Cleanup System Isolation The Reactor Vessel Water Level-Low Low, Level 2 Isolation Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected into two two-out-of-two trip systems. The Differential Flow-High, Flow-High, and SLC System Initiation Functions receive input from two channels, with each channel in one trip system using a one-out-of-one logic. The temperature isolations are divided into three Functions. These Functions are Pump Area, Penetration Area, and Heat Exchanger Area.
Each area is monitored by two temperature monitors, one for each trip system. These are configured so that any one input will trip the associated trip system. Each of the two trip systems is connected to one of the two valves on each RWCU penetration.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-149 Revision 0
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 6. Shutdown Cooling System Isolation (continued)
The Reactor Vessel Water Level-Low, Level 3 Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected to two two-out-of-two trip systems. The Reactor Vessel Pressure-High Function receives input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems is connected to one of the two valves on each shutdown cooling penetration.
- 7. Traversing Incore Probe System Isolation The Reactor Vessel Water Level-Low, Level 3 Isolation Function receives input from two reactor vessel water level channels. The Drywell Pressure-High Isolation Function receives input from two drywell pressure channels. The outputs from the reactor vessel water level channels and drywell pressure channels are connected into one two-out-of-two logic trip system.
When either Isolation Function actuates, the TIP drive mechanisms will withdraw the TIPs, if inserted, and close the inboard TIP System isolation ball valves when the proximity probe senses the TIPs are withdrawn into the shield. The TIP System isolation ball valves are only open when the TIP System is in use. The outboard TIP System isolation valves are manual shear valves.
APPLICABLE The isolation signals generated by the primary containment isolation SAFETY instrumentation are implicitly assumed in the safety analyses of ANALYSES, References 1 and 2 to initiate closure of valves to limit offsite doses.
LCO, and Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"
APPLICABILITY Applicable Safety Analyses Bases for more detail of the safety analyses.
Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 8) Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-150 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE The OPERABILITY of the primary containment instrumentation is SAFETY dependent on the OPERABILITY of the individual instrumentation ANALYSES, channel Functions specified in Table 3.3.6.1-1. Each Function must LCO, and have a required number of OPERABLE channels, with their setpoints APPLICABILITY within the specified Allowable Values, where appropriate. A channel is (continued) inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time, where appropriate.
Allowable Values are specified for each Primary Containment Isolation Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
In general, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCO 3.6.1.1, "Primary Containment." Functions that have different Applicabilities are discussed below in the individual Functions discussion.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-151 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE The penetrations which are isolated by the below listed functions can be SAFETY determined by referring to the PCIV Table found in the Bases of LCO ANALYSES, 3.6.1.3, "Primary Containment Isolation Valves."
LCO, and APPLICABILITY Main Steam Line Isolation (continued) 1.a. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of the MSIVs and other interfaces with the reactor vessel occurs to prevent offsite dose limits from being exceeded. The Reactor Vessel Water Level-Low Low Low, Level 1 Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The Reactor Vessel Water Level-Low Low Low, Level 1 Function associated with isolation is assumed in the analysis of the recirculation line break (Ref. 1). The isolation of the MSLs on Level 1 supports actions to ensure that offsite dose limits are not exceeded for a DBA.
Reactor vessel water level signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite and control room doses from exceeding regulatory limits.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.3-152 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.b. Main Steam Line Pressure-Low SAFETY ANALYSES, Low MSL pressure indicates that there may be a problem with the LCO, and turbine pressure regulation, which could result in a low reactor vessel APPLICABILITY water level condition and the RPV cooling down more than 100°F/hr if (continued) the pressure loss is allowed to continue. The Main Steam Line Pressure-Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2). For this event, the closure of the MSIVs ensures that the RPV temperature change limit (IOO0 F/hr) is not reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded. (This Function closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus reducing reactor power to < 25% RTP.)
The MSL low pressure signals are initiated from four instruments that are connected to the MSL header. The instruments are arranged such that, even though physically separated from each other, each instrument is able to detect low MSL pressure. Four channels of Main Steam Line Pressure-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Main Steam Line Pressure-Low trip will only occur after a 500 milli-second time delay to prevent any spurious isolations.
The Allowable Value was selected to be high enough to prevent excessive RPV depressurization. The Main Steam Line Pressure-Low Function is only required to be OPERABLE in MODE I since this is when the assumed transient can occur (Ref. 2).
1.c. Main Steam Line Flow-High Main Steam Line Flow-High is provided to detect a break of the MSL and to initiate closure of the MSIVs. If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Main Steam Line Flow-High Function is (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-153 Revision I
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.c. Main Steam Line Flow-High (continued)
SAFETY ANALYSES, directly assumed in the analysis of the main steam line break (MSLB)
LCO, and (Ref. 1). The isolation action, along with the scram function of the APPLICABILITY Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and offsite and control room doses do not exceed regulatory limits.
The MSL flow signals are initiated from 16 instruments that are connected to the four MSLs. The instruments are arranged such that, even though physically separated from each other, all four connected to one MSL would be able to detect the high flow. Four channels of Main Steam Line Flow-High Function for each unisolated MSL (two channels per trip system) are available and are required to be OPERABLE so that no single instrument failure will preclude detecting a break in any individual MSL.
1.d. Condenser Vacuum-Low The Allowable Value is chosen to ensure that offsite dose limits are not exceeded due to the break.
The Condenser Vacuum-Low Function is provided to prevent overpressurization of the main condenser in the event of a loss of the main condenser vacuum. Since the integrity of the condenser is an assumption in offsite dose calculations, the Condenser Vacuum-Low Function is assumed to be OPERABLE and capable of initiating closure of the MSIVs. The closure of the MSIVs is initiated to prevent the addition of steam that would lead to additional condenser pressurization and possible rupture of the diaphragm installed to protect the turbine exhaust hood, thereby preventing a potential radiation leakage path following an accident.
Condenser vacuum pressure signals are derived from four pressure instruments that sense the pressure in the condenser. Four channels of Condenser Vacuum-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-154 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.d. Condenser Vacuum-Low (continued)
SAFETY ANALYSES, The Allowable Value is chosen to prevent damage to the condenser due LCO, and to pressurization, thereby ensuring its integrity for offsite dose analysis.
APPLICABILITY As noted (footnote (a) to Table 3.3.6.1-1), the channels are not required to be OPERABLE in MODES 2 and 3 when all main turbine stop valves (TSVs) are closed, since the potential for condenser overpressurization is minimized. Switches are provided to manually bypass the channels when all TSVs are closed.
1.e. Reactor BuildinQ Main Steam Tunnel Temperature-High Reactor Building Main Steam Tunnel temperature is provided to detect a leak in the RCPB and provides diversity to the high flow instrumentation.
The isolation occurs when a very small leak has occurred. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. However, credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks, such as MSLBs.
Area temperature signals are initiated from thermocouples located in the area being monitored. Four channels of Reactor Building Main Steam Tunnel Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The reactor building main steam tunnel temperature trip will only occur after a one second time delay.
The temperature monitoring Allowable Value is chosen to detect a leak equivalent to approximately 25 gpm of water.
1.f. Manual Initiation The Manual Initiation push button channels introduce signals into the MSL isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for the overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-155 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.f. Manual Initiation (continued)
SAFETY ANALYSES, There are four push buttons for the logic, two manual initiation push LCO, and button per trip system. There is no Allowable Value for this Function APPLICABILITY since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the MSL isolation automatic Functions are required to be OPERABLE.
Primary Containment Isolation 2.a. Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.
The isolation of the primary containment on Level 3 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Reactor Vessel Water Level-Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.
Reactor Vessel Water Level-Low, Level 3 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-156 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.b. Reactor Vessel Water Level-Low Low. Level 2 SAFETY ANALYSES, Low RPV water level indicates that the capability to cool the fuel may be LCO, and threatened. The valves whose penetrations communicate with the APPLICABILITY primary containment are isolated to limit the release of fission products.
(continued) The isolation of the primary containment on Level 2 supports actions to ensure that offsite and control room dose regulatory limits are not I exceeded. The Reactor Vessel Water Level-Low Low, Level 2 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.
Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Level 2 Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA.
2.c. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products. The isolation of the primary containment on Level 1 supports actions to ensure the offsite and control room dose regulatory limits are not exceeded. The Reactor Vessel Water Level - Low Low Low, Level 1 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.3-157 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.c. Reactor Vessel Water Level-Low Low Low, Level 1 (continued)
SAFETY ANALYSES, Reactor vessel water level signals are initiated from four level LCO, and instruments that sense the difference between the pressure due to a APPLICABILITY constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the associated penetrations isolate on a potential loss of coolant accident (LOCA) to prevent offsite and control room doses from exceeding regulatory limits.
2.d. Drvwell Pressure-Hiah High drywell pressure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Drywell Pressure-High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.
High drywell pressure signals are initiated from pressure instruments that sense the pressure in the drywell. Four channels of Drywell Pressure-High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-158 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.e. SGTS Exhaust Radiation-High SAFETY ANALYSES, High SGTS Exhaust radiation indicates possible gross failure of the fuel LCO, and cladding. Therefore, when SGTS Exhaust Radiation High is detected, APPLICABILITY an isolation is initiated to limit the release of fission products. However, (continued) this Function is not assumed in any accident or transient analysis in the FSAR because other leakage paths (e.g., MSIVs) are more limiting.
The SGTS Exhaust radiation signals are initiated from radiation detectors that are located in the SGTS Exhaust. Two channels of SGTS Exhaust Radiation-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value is low enough to promptly detect gross failures in the fuel cladding.
2.f. Manual Initiation The Manual Initiation push button channels introduce signals into the primary containment isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability.
There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the Primary Containment Isolation automatic Functions are required to be OPERABLE.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-159 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE High Pressure Coolant Iniection and Reactor Core Isolation SAFETY Cooling Systems Isolation
- ANALYSES, LCO, and 3.a., 4.a. HPCI and RCIC Steam Line A Pressure-High APPLICABILITY (continued) Steam Line A Pressure High Functions are provided to detect a break of the RCIC or HPCI steam lines and initiate closure of the steam line isolation valves of the appropriate system. If the steam is allowed to continue flowing out of the break, the reactor will depressurize and the core can uncover. Therefore, the isolations are initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit for these Functions is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC or HPCI steam line breaks from becoming bounding.
The HPCI and RCIC Steam Line A Pressure - High signals are initiated from instruments (two for HPCI and two for RCIC) that are connected to the system steam lines. Two channels of both HPCI and RCIC Steam Line A pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The steam line A Pressure - High will only occur after a 3 second time delay to prevent any spurious isolations.
The Allowable Values are chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event, and high enough to be above the maximum transient steam flow during system startup.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.3-160 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.b., 4.b. HPCI and RCIC Steam Supply Line A Pressure-Low SAFETY ANALYSES, Low MSL pressure indicates that the pressure of the steam in the HPCI LCO, and or RCIC turbine may be too low to continue operation of the associated APPLICABILITY system's turbine. These isolations are for equipment protection and are (continued) not assumed in any transient or accident analysis in the FSAR.
However, they also provide a diverse signal to indicate a possible system break. These instruments are included in Technical Specifications (TS) because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).
The HPCI and RCIC Steam Supply Line Pressure-Low signals are initiated from instruments (four for HPCI and four for RCIC) that are connected to the system steam line. Four channels of both HPCI and RCIC Steam Supply Line Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are selected to be high enough to prevent damage to the system's turbine.
3.c.. 4.c. HPCI and RCIC Turbine Exhaust Diaohraam Pressure-Hiah High turbine exhaust diaphragm pressure indicates that a release of steam into the associated compartment is possible. That is, one of two exhaust diaphragms has ruptured. These isolations are to prevent steam from entering the associated compartment and are not assumed in any transient or accident analysis in the FSAR. These instruments are included in the TS because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).
The HPCI and RCIC Turbine Exhaust Diaphram Pressure-High signals and initiated from instruments (four for HPCI and four for RCIC) that are connected to the area between the rupture diaphragms on each system's turbine exhaust line. Four channels of both HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-161 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.c., 4.c. HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High SAFETY (continued)
- ANALYSES, LCO, and The Allowable Values is low enough to identify a high turbine exhaust APPLICABILITY pressure condition resulting from a diaphragm rupture, or a leak in the diaphragm adjacent to the exhaust line and high enough to prevent inadvertent system isolation.
3.d.. 4.d. Drvwell Pressure-Hiah High drywell pressure can indicate a break in the RCPB. The HPCI and RCIC isolation of the turbine exhaust vacuum breaker line is provided to prevent communication with the wetwell when high drywell pressure exists. A potential leakage path exists via the turbine exhaust. The isolation is delayed until the system becomes unavailable for injection (i.e., low steam supply line pressure). The isolation of the HPCI and RCIC turbine exhaust vacuum breaker line by Drywell Pressure-High is indirectly assumed in the FSAR accident analysis because the turbine exhaust vacuum breaker line leakage path is not assumed to contribute to offsite doses and is provided for long term containment isolation.
High drywell pressure signals are initiated from pressure instruments that sense the pressure in the drywell. Four channels of both HPCI and RCIC Drywell Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this is indicative of a LOCA inside primary containment.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-162 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.e., 3.f., 3.q., 4.e., 4.f., 4.q., HPCI and RCIC Area and Emergency SAFETY Cooler Temperature-High
- ANALYSES, LCO, and HPCI and RCIC Area and Emergency Cooler temperatures are provided APPLICABILITY to detect a leak from the associated system steam piping. The isolation (continued) occurs when a small leak has occurred and is diverse to the high flow instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.
Area and Emergency Cooler Temperature-High signals are initiated from thermocouples that are appropriately located to protect the system that is being monitored. Two Instruments monitor each area. Two channels for each HPCI and RCIC Area and Emergency Cooler Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The HPCI and RCIC Pipe Routing area temperature trips will only occur after a 15 minute time delay to prevent any spurious temperature isolations due to short temperature increases and allows operators sufficient time to determine which system is leaking. The other ambient temperature trips will only occur after a one second time delay to prevent any spurious temperature isolations.
The Allowable Values are set low enough to detect a leak equivalent to 25 gpm, and high enough to avoid trips at expected operating temperature.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-163 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.h.. 4.h. Manual Initiation SAFETY ANALYSES, The Manual Initiation push button channels introduce signals into the LCO, and HPCI and RCIC systems' isolation logics that are redundant to the APPLICABILITY automatic protective instrumentation and provide manual isolation (continued) capability. There is no specific FSAR safety analysis that takes credit for these Functions. They are retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis There is one manual initiation push button for each of the HPCI and RCIC systems. One isolation pushbutton per system will introduce an isolation to one of the two trip systems. There is no Allowable Value for these Functions, since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of both HPCI and RCIC Manual Initiation Functions are available and are required to be OPERABLE in MODES 1, 2, and 3 Since these are the MODES in which the HPCI and RCIC systems' Isolation automatic Functions are required to be OPERABLE.
Reactor Water Cleanuo System Isolation 5.a. RWCU Differential Flow-High The high differential flow signal is provided to detect a break in the RWCU System. This will detect leaks in the RWCU System when area temperature would not provide detection (i.e., a cold leg break). Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high differential flow is sensed to prevent exceeding offsite doses.
A 45 second time delay is provided to prevent spurious trips during most RWCU operational transients. This Function is not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.
(continued)
SUSQUEHANNA-UNIT 1 TS / B 3.3-164 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.a. RWCU Differential Flow-High (continued)
SAFETY ANALYSES, The high differential flow signals are initiated from instruments that are LCO, and connected to the inlet (from the recirculation suction) and outlets (to APPLICABILITY condenser and feedwater) of the RWCU System. Two channels of Differential Flow-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Differential Flow-High Allowable Value ensures that a break of the RWCU piping is detected.
5.b, 5.c. 5.d RWCU Area TemDeratures-Hiah RWCU area temperatures are provided to detect a leak from the RWCU System. The isolation occurs even when small leaks have occurred and is diverse to the high differential flow instrumentation for the hot portions of the RWCU System. If the small leak continues without isolation, offsite dose limits may be reached. Credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.
Area temperature signals are initiated from temperature elements that are located in the area that is being monitored. Six thermocouples provide input to the Area Temperature-High Function (two per area).
Six channels are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The area temperature trip will only occur after a one second time to prevent any spurious temperature isolations.
The Area Temperature-High Allowable Values are set low enough to detect a leak equivalent to 25 gpm.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-165 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.e. SLC System Initiation SAFETY ANALYSES, The isolation of the RWCU System is required when the SLC System LCO, and has been initiated to prevent dilution and removal of the boron solution APPLICABILITY by the RWCU System (Ref. 4). SLC System initiation signals are (continued) initiated from the two SLC pump start signals.
There is no Allowable Value associated with this Function since the channels are mechanically actuated based solely on the position of the SLC System initiation switch.
Two channels (one from each pump) of the SLC System Initiation Function are available and are required to be OPERABLE only in MODES 1, 2, and 3 which is consistent with the Applicability for the SLC System (LCO 3.1.7).
As noted (footnote (b) to Table 3.3.6.1-1), this Function is only required to close the outboard RWCU isolation valve trip systems.
5.f. Reactor Vessel Water Level-Low Low, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. The isolation of the RWCU System on Level 2 supports actions to ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
The Reactor Vessel Water Level-Low Low, Level 2 Function associated with RWCU isolation is not directly assumed in the FSAR safety analyses because the RWCU System line break is bounded by breaks of larger systems (recirculation and MSL breaks are more limiting).
Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-166 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.f. Reactor Vessel Water Level-Low Low, Level 2 (continued)
SAFETY ANALYSES, Reactor Vessel Water Level-Low Low, Level 2 Function are available LCO, and and are required to be OPERABLE to ensure that no single instrument APPLICABILITY failure can preclude the isolation function.
The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.
5.q. RWCU Flow- High RWCU Flow-High Function is provided to detect a break of the RWCU System. Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation is initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Specific credit for this Function is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks.
The RWCU Flow-High signals are initiated from two instruments. Two channels of RWCU Flow-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The RWCU flow trip will only occur after a 5 second time delay to prevent spurious trips.
The Allowable Value is chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event.
5.h. Manual Initiation The Manual Initiation push button channels introduce signals into the RWCU System isolation logic that are redundant to (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-167 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.h. Manual Initiation (continued)
SAFETY ANALYSES, the automatic protective instrumentation and provide manual isolation LCO, and capability. There is no specific FSAR safety analysis that takes credit APPLICABILITY for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3 since these are the MODES in which the RWCU System Isolation automatic Functions are required to be OPERABLE.
Shutdown Cooling System Isolation 6.a. Reactor Steam Dome Pressure-High The Reactor Steam Dome Pressure-High Function is provided to isolate the shutdown cooling portion of the Residual Heat Removal (RHR) System. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario, and credit for the interlock is not assumed in the accident or transient analysis in the FSAR.
The Reactor Steam Dome Pressure-High signals are initiated from two instruments. Two channels of Reactor Steam Dome Pressure-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Function is only required to be OPERABLE in MODES 1, 2, and 3, since these are the only MODES in which the reactor can be pressurized with the exception of Special Operations LCO 3.10.1; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-168 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. Reactor Vessel Water Level-Low. Level 3 SAFETY ANALYSES, Low RPV water level indicates that the capability to cool the fuel may be LCO, and threatened. Should RPV water level decrease too far, fuel damage APPLICABILITY could result. Therefore, isolation of some reactor vessel interfaces occurs to (continued) begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low, Level 3 Function associated with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by breaks of the recirculation and MSL.
The RHR Shutdown Cooling System isolation on Level 3 supports actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.
Reactor Vessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. As noted (footnote (c) to Table 3.3.6.1-1), only two channels of the Reactor Vessel Water Level-Low, Level 3 Function are required to be OPERABLE in MODES 4 and 5 (and must input into the same trip system), provided the RHR Shutdown Cooling System integrity is maintained. System integrity is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system.
The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low, Level 3 Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened.
The Reactor Vessel Water Level-Low, Level 3 Function is only required to be OPERABLE in MODES 3, 4, and 5 to prevent this potential flow path from lowering the reactor vessel level to the top of the fuel.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-169 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. Reactor Vessel Water Level-Low, Level 3 (continued)
SAFETY ANALYSES, In MODES 1 and 2, another isolation (i.e., Reactor Steam Dome LCO, and Pressure-High) and administrative controls ensure that this flow path APPLICABILITY remains isolated to prevent unexpected loss of inventory via this flow path.
6.c Manual Initiation The Manual Initiation push button channels introduce signals to RHR Shutdown Cooling System isolation logic that is redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 3, 4, and 5, since these are the MODES in which the RHR Shutdown Cooling System Isolation automatic Function are required to be OPERABLE.
Traversing Incore Probe System Isolation 7.a Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.
The isolation of the primary containment on Level 3 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Reactor Vessel Water Level - Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-170 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 7.a Reactor Vessel Water Level - Low, Level 3 (continued)
SAFETY ANALYSES, Reactor Vessel Water Level - Low, Level 3 signals are initiated from LCO, and level transmitters that sense the difference between the pressure due to APPLICABILITY a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Two channels of Reactor Vessel Water Level - Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent isolation actuation. The isolation function is ensured by the manual shear valve in each penetration.
The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.
7.b. Drvwell Pressure - Hiah High drywell pressure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Drywell Pressure - High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Two channels of Drywell Pressure - High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation. The isolation function is ensured by the manual shear valve in each penetration.
The Allowable Value was selected to be the same as the ECCS Drywell Pressure - High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-171 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS The ACTIONS are modified by two Notes. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls.
These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room.
In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable primary containment isolation instrumentation channel.
A.1 Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Functions 2.a, 2.d, 6.b, 7.a, and 7.b and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Functions 2.a, 2.d, 6.b, 7.a, and 7.b has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B. 1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue with no further restrictions. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its Required Action taken.
(continued)
SUSQUEHANNA- UNIT 1 TS / B 3.3-172 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS B.1 and B.2 (continued)
Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path(s). The MSL Isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function. For Functions 1.a,1.b, 1.d, and .1.e, this would require both trip systems to have one channel OPERABLE or in trip. For Function 1.c, this would require both trip systems to have one channel, associated with each MSL, OPERABLE or in trip. Therefore, this would require both trip systems to have one channel per location OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, 3.b, 3.c, 3.d, 4.b, 4.c, 4.d, 5.f, and 6.b, this would require one trip system to have two channels, each OPERABLE or in trip. For Functions 2.e, 3.a, 3.e, 3.f, 3.g, 4.a, 4.e, 4.f, 4.g, 5.a, 5.b, 5.c, 5.d, 5.e, 5.g, and 6.a, this would require one trip system to have one channel OPERABLE or in trip. The Condition does not include the Manual Initiation Functions (Functions 1.f, 2.f, 3.h, 4.h, 5.h, and 6.c), since they are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (as allowed by Required Action A. 1) is allowed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-173 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS C.1 (continued)
Required Action C.1 directs entry into the appropriate Condition referenced in Table 3.3.6.1-1. The applicable Condition specified in Table 3.3.6.1-1 is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action of Condition A or B and the associated Completion Time has expired, Condition C will be entered for that channel and provides for transfer to the appropriate subsequent Condition.
D.1, D.2.1, and D.2.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.
This is done by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (Required Actions D.2.1 and D.2.2).
Alternately, the associated MSLs may be isolated (Required Action D.1),
and, if allowed (i.e., plant safety analysis allows operation with an MSL isolated), operation with that MSL isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel. The Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
E. 1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.
This is done by placing the plant in at least MODE 2 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 2 from full power conditions in an orderly manner and without challenging plant systems.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-174 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS F.1 (continued)
If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels.
If it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram), Condition H must be entered and its Required Actions taken.
The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing sufficient time for plant operations personnel to isolate the affected penetration flow path(s).
G._1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is acceptable due to the fact that these Functions are either not assumed in any accident or transient analysis in the FSAR (Manual Initiation) or, in the case of the TIP System isolation, the TIP System penetration is a small bore (0.280 inch), its isolation in a design basis event (with loss of offsite powerý would be via the manually operated shear valves, and the ability to manually isolate by either the normal isolation valve or the shear valve is unaffected by the inoperable instrumentation., It should be noted, however, that the TIP System is powered from an auxiliary instrumentation bus which has an uninterruptible power supply and hence, the TIP drive mechanisms and ball valve control will still function in the event of a loss of offsite power. Alternately, if it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram),
Condition H must be entered and its Required Actions taken.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-175 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS H. and H.2 (continued)
If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, or any Required Action of Condition F or G is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
1.1 and 1.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated SLC subsystem(s) is declared inoperable or the RWCU System is isolated. Since this Function is required to ensure that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystems inoperable or isolating the RWCU System.
The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.
J.1 and J.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated).
Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling System is isolated.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-176 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Primary REQUIREMENTS Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 5 and 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.
SR 3.3.6.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.
The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with the channels required by the LCO.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-177 Revision 1
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.
The 92 day Frequency of SR 3.3.6.1.2 is based on the reliability analysis described in References 5 and 6.
This SR is modified by two Notes. Note 1 provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relays which input into the combinational logic. (Reference 11) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.1.5. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.
Note 2 provides a second specific exception to the definition of CHANNEL FUNCTIONAL TEST. For Functions 2.e, 3.a, and 4.a, certain channel relays are not included in the performance of the CHANNEL FUNCTIONAL TEST. These exceptions are necessary because the circuit design does not facilitate functional testing of the entire channel through to the coil of the relay which enters the combinational logic. (Reference 11) Specifically, testing of all required relays would require rendering the affected system (i.e., HPCI or RCIC) inoperable, or require lifting of leads and inserting test equipment which could lead to unplanned transients. Therefore, for these circuits, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the actuation of circuit devices up to the point where further testing could result in an unplanned transient. (References 10 and 12)
The required relays not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.1.5. This exception (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-178 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.2 (continued)
REQUIREMENTS is acceptable because operating experience shows that the devices not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.
SR 3.3.6.1.3 and SR 3.3.6.1.4 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
The Frequency of SR 3.3.6.1.3 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.6.1.4 is based on the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
It should be noted that some of the primary containment High Drywell pressure instruments, although only required to be calibrated on a 24 month Frequency, are calibrated quarterly based on other TS requirements.
SR 3.3.6.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional'testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function. The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating
.experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-179 Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 REQUIREMENTS (continued) This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
Testing is performed only on channels where the guidance given in Reference 9 could not be met, which identified that degradation of response time can usually be detected by other surveillance tests.
As stated in Note 1, the response time of the sensors for Functions 1.b, is excluded from ISOLATION SYSTEM RESPONSE TIME testing.
Because the vendor does not provide a design instrument response time, a penalty value to account for the sensor response time is included in determining total channel response time. The penalty value is based on the historical performance of the sensor. (Reference 13) This allowance is supported by Reference 9 which determined that significant degradation of the sensor channel response time can be detected during performance of other Technical Specification SRs and that the sensor response time is a small part of the overall ISOLATION RESPONSE TIME testing.
Function 1.a and 1 .c channel sensors and logic components are excluded from response time testing in accordance with the provisions of References 14 and 15.
As stated in Note 2, response time testing of isolating relays is not required for Function 5.a. This allowance is supported by Reference 9.
These relays isolate their respective isolation valve after a nominal 45 second time delay in the circuitry. No penalty value is included in the response time calculation of this function. This is due to the historical response time testing results of relays of the same manufacturer and model number being less than 100 milliseconds, which is well within the expected accuracy of the 45 second time delay relay.
ISOLATION SYSTEM RESPONSE TIME acceptance criteria are included in Reference 7. This test may be performed in one measurement, or in overlapping segments, with verification that all components are tested.
ISOLATION SYSTEM RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience that shows that random failures of instrumentation (continued)
SUSQUEHANNA-UNIT 1 TS / B 3.3-179a Revision 2
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 (continued)
REQUIREMENTS components causing serious response time degradation, but not channel failure, are infrequent occurrences.
REFERENCES 1. FSAR, Section 6.3.
- 2. FSAR, Chapter 15.
- 3. NEDO-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.
- 4. FSAR, Section 4.2.3.4.3.
- 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.
- 6. NEDC-30851P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
- 7. FSAR, Table 7.3-29.
- 8. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
- 9. NEDO-32291-A "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.
- 10. PPL Letter to NRC, PLA-2618, Response to NRC INSPECTION REPORTS 50-387/85-28 AND 50-388/85-23, dated April 22, 1986.
- 11. NRC Inspection and Enforcement Manual, Part 9900:
Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.
- 12. Susquehanna Steam Electric Station NRC REGION I COMBINED INSPECTION 50-387/90-20; 50-388/90-20, File R41-2, dated March 5, 1986.
- 13. NRC Safety Evaluation Report related to Amendment No. 171 for License No. NPF-14 and Amendment No. 144 for License No. NPF-22.
- 14. NEDO 32291-A, Supplement 1, "System Analyses for the Elimination of Selected Response Time Testing Requirements,"
October 1999.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-179b Revision 0
PPL Rev. 3 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES REFERENCES 15. NEDO 32291, Supplement 1, Addendum 2, "System Analyses for (continued) the Elimination of Selected Response Time Testing Requirements,"
September 5, 2003.
SUSQUEHANNA - UNIT 1 TS / B 3.3-179c Revision 0
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation and establishment of vacuum with the SGT System within the assumed time limits ensures that fission products that leak from primary containment following a DBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits.
The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of secondary containment isolation.
When the setpoint is reached, the channel sensor actuates, which then outputs a secondary containment isolation signal to the isolation logic.
Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, (2) drywell pressure, (3) refuel floor high exhaust duct radiation - high, (4) refuel floor wall exhaust duct radiation - high, and (5) railroad access shaft exhaust duct radiation - high. Only appropriate ventilation zones are isolated for different isolation signals. Isolation signals for drywell pressure and vessel water level will isolate the affected Unit's zone (Zone I for Unit 1 and Zone 11for Unit 2) and Zone Ill.
Redundant sensor input signals from each parameter are provided for initiation of isolation. In addition, manual initiation of the logic is provided.
The Functions are arranged as follows for each trip system. The Reactor Vessel Water Level - Low Low, Level 2 and DryweH Pressure - High are each arranged in a two-out-of-two logic. The Refuel Floor High Exhaust Duct Radiation - High, Refuel Floor Wall Exhaust Duct Radiation - High and the Railroad Access Shaft Exhaust Duct Radiation - High are arranged into one-out-of-one trip systems. One trip (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-180 Revision 1
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES BACKGROUND system initiates isolation of one automatic isolation valve (damper) and (continued) starts one SGT subsystem (including its associated reactor building recirculation subsystem) while the other trip system initiates isolation of the other automatic isolation valve in the penetration and starts the other SGT subsystem (including its associated reactor building recirculation subsystem). Each logic closes one of the two valves on each penetration and starts one SGT subsystem, so that operation of either logic isolates the secondary containment and provides for the necessary filtration of fission products.
APPLICABLE The isolation signals generated by the secondary containment isolation SAFETY instrumentation are implicitly assumed in the safety analyses of ANALYSES, References I and 2 to initiate closure of valves and start the SGT System LCO, and to limit offsite and control room doses.
APPLICABILITY Refer to LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs),"
and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," Applicable Safety Analyses Bases for more detail of the safety analyses.
The secondary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 7) Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
The OPERABILITY of the secondary containment isolation instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have the required number of OPERABLE channels with their setpoints set within the specified Allowable Values, as shown in Table 3.3.6.2-1. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. Each channel must also respond within its assumed response time, where appropriate.
Allowable Values are specified for each Function specified in the Table.
Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-181 Revision 3
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE Trip setpoints are those predetermined values of output at which an action SAFETY should take place. The setpoints are compared to the actual process ANALYSES, parameter (e.g., reactor vessel water level), and when the measured LCO, and output value of the process parameter reaches the setpoint, the APPLICABILITY associated device changes state. The analytic limits are derived from the (continued) limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip SAFETY ANALYSES, setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions when SCIVs and the SGT System are required.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
- 1. Reactor Vessel Water Level-Low Low. Level 2 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. An isolation of the secondary containment and actuation of the SGT System are initiated in order to minimize the potential of an offsite dose release. The Reactor Vessel Water Level-Low Low, Level 2 Function is one of the Functions assumed to be OPERABLE and capable of providing isolation and initiation signals. The isolation and initiation systems on Reactor Vessel Water Level-Low Low, Level 2 support actions to ensure that any offsite releases are within the limits calculated in the safety analysis.
Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-182 Revision 1
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 1. Reactor Vessel Water Level-Low Low, Level 2 (continued)
SAFETY ANALYSES, level (variable leg) in the vessel. Four channels of Reactor Vessel Water LCO, and Level--Low Low, Level 2 Function are available and are required to be APPLICABILITY OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the High Pressure Coolant Injection/Reactor Core Isolation Cooling (HPCI/RCIC) Reactor Vessel Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1 and LCO 3.3.5.2), since this could indicate that the capability to cool the fuel is being threatened.
The Reactor Vessel Water Level-Low Low, Level 2 Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the Reactor Coolant System (RCS); thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas.
In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, this Function is not required. In addition, the Function is also required to be OPERABLE during operations with a potential for draining the reactor vessel (OPDRVs) because the capability of isolating potential sources of leakage must be provided to ensure that offsite and control room dose limits are not exceeded if core damage occurs.
Reactor Vessel Water Level--Low Low, Level 2 will isolate the affected Unit's zone (i.e., Zone I for Unit 1 and Zone II for Unit 2) and Zone Ill.
- 2. Drywell Pressure-High High drywell pressure can indicate a break in the reactor coolant pressure boundary (RCPB). An isolation of the secondary containment and actuation of the SGT System are initiated in order to minimize the potential of an offsite dose release. The isolation on high drywell pressure supports actions to ensure that any offsite releases are within the limits calculated in the safety analysis. However, the Drywell Pressure-High Function associated with (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-183 Revision 2
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 2. Drywell Pressure - High (continued)
SAFETY ANALYSES, isolation is not assumed in any FSAR accident or transient analyses. It is LCO, and retained for the overall redundancy and diversity of the secondary APPLICABILITY containment isolation instrumentation as required by the NRC approved licensing basis.
High drywell pressure signals are initiated from pressure instruments that sense the pressure in the drywell. Four channels of Drywell Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude performance of the isolation function.
The Allowable Value was chosen to be the same as the ECCS Drywell Pressure-High Function Allowable Value (LCO 3.3.5.1) since this is indicative of a loss of coolant accident (LOCA).
The Drywell Pressure-High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. This Function is not required in MODES 4 and 5 because the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES.
Drywell Pressure - High will isolate the affected Unit's zone (i.e., Zone I for Unit 1 and Zone II for Unit 2) and Zone Ill.
3, 4, 5, 6, 7 Refuel Floor High Exhaust Duct, Refuel Floor Wall Exhaust Duct, and Railroad Access Shaft Exhaust Duct Radiation-High High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding due to a fuel handling accident. When Exhaust Radiation-High is detected, secondary containment isolation and actuation of the SGT System are initiated to limit the release of fission products as assumed in the FSAR safety analyses (Ref. 4).
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-184 Revision I
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 3, 4, 5, 6, 7 Refuel Floor High Exhaust Duct, Refuel Floor Wall Exhaust SAFETY Duct, and Railroad Access Shaft Exhaust Duct Radiation-High ANALYSES, (continued)
LCO, and APPLICABILITY The Exhaust Radiation-High signals are initiated from radiation detectors that are located on the ventilation exhaust ductwork coming from the refueling floor zones and the Railroad Access Shaft. The signal from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Eight channels of Refuel Floor High Exhaust Duct and Wall Exhaust Duct Radiation-High Function (four from Unit 1 and four from Unit 2) and two channels of Railroad Access Shaft Exhaust Duct Radiation - High Function (both from Unit 1) are available to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are chosen to promptly detect gross failure of the fuel cladding.
The Refuel Floor Exhaust Radiation-High Functions are required to be OPERABLE during CORE ALTERATIONS, OPDRVs, and movement of irradiated fuel assemblies in the secondary containment, because the capability of detecting radiation releases due to fuel failures (due to a fuel handling accident) must be provided to ensure that offsite and control room dose limits are not exceeded.
The Railroad Access Shaft Exhaust Duct Radiation - High Function is only required to be OPERABLE during handling of irradiated fuel within the Railroad Access Shaft, and above the Railroad Access Shaft with the Railroad Access Shaft Equipment Hatch open. This provides the capability of detecting radiation releases due to fuel failures resulting from dropped fuel assemblies which ensures that offsite and control room dose I limits are not exceeded.
Refuel Floor High and Wall Exhaust Duct and Railroad Access Shaft Exhaust Duct Radiation - High Functions will isolate Zone III of secondary containment.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-185 Revision 2
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 8. Manual Initiation SAFETY ANALYSES, A Manual Initiation can be performed for secondary containment isolation LCO, and by initiating a Primary Containment Isolation. There is no specific FSAR APPLICABILITY safety analysis that takes credit for this Function. It is retained for the (continued) overall redundancy and diversity of the secondary containment isolation instrumentation as required by the NRC approved licensing basis.
There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, and during CORE ALTERATIONS, OPDRVs, and movement of irradiated fuel assemblies in the secondary containment. These are the MODES and other specified conditions in which the Secondary Containment Isolation automatic Functions are required to be OPERABLE.
ACTIONS A Note has been provided to modify the ACTIONS related to secondary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable secondary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable secondary containment isolation instrumentation channel.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-186 Revision 1
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES ACTIONS (continued) A.
Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Function 2, and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Function 2, has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its Required Actions taken.
B..1 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic isolation capability for the associated penetration flow path(s) or a complete loss of automatic initiation capability for the SGT System. A Function is considered to be maintaining secondary containment isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two SCIVs in the associated penetration flow path and one SGT subsystem (including its associated reactor building recirculation subsystem) can be initiated on an isolation signal from the given Function.
For the Functions with two logic trip systems (Functions 1, 2, 3, 4, 5, 6 and 7), this would require one trip system to have the required channel(s)
OPERABLE or in trip. The Condition does not include the Manual Initiation Function (Function 8), since it is not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (as allowed by Required Action A.1) is allowed.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-187 Revision 2
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES ACTIONS B.1 (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
C.1, C.2.1, and C.2.2 If any Required Action and associated Completion Time of Condition A or B are not met, the ability to isolate the secondary containment and start the SGT System cannot be ensured. Therefore, further actions must be performed to ensure the ability to maintain the secondary containment function. Isolating the associated zone (closing the ventilation supply and exhaust automatic isolation dampers) and starting the associated SGT subsystem (including its associated reactor building recirculation subsystem) in emergency mode (Required Action C.1) performs the intended function of the instrumentation and allows operation to continue.
Alternately, declaring the associated SCIVs and SGT subsystem(s)
(including its associated reactor building recirculation. subsystem) inoperable (Required Actions C.2.1 and C.2.2) is also acceptable since the Required Actions of the respective LCOs (LCO 3.6.4.2 and LCO 3.6.4.3) provide appropriate actions for the inoperable components.
One hour is sufficient for plant operations personnel to establish required plant conditions or to declare the associated components inoperable without unnecessarily challenging plant systems.
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Secondary REQUIREMENTS Containment Isolation instrumentation Function are located in the SRs column of Table 3.3.6.2-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains secondary containment isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-188 Revision 2
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE channel must be returned to OPERABLE status or the applicable REQUIREMENTS Condition entered and Required Actions -taken. This Note is based on the (continued) reliability analysis (Refs. 5 and 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the SCIVs will isolate the associated penetration flow paths and that the SGT System will initiate when necessary.
SR 3.3.6.2.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.
The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channel status during normal operational use of the displays associated with channels required by the LCO.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.3-189 Revision 1
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.
This SR is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference 8) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.2.5. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.
The Frequency of 92 days is based on the reliability analysis of References 5 and 6.
SR 3.3.6.2.3 and SR 3.3.6.2.4 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
The Frequencies of SR 3.3.6.2.3 and SR 3.3.6.2.4 are based on the assumption of a 92 day and an 24 month calibration interval, respectively, in the determination of the magnitude of equipment drift in the setpoint analysis.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-190 Revision 1
PPL Rev. 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.5 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on SCIVs and the SGT System in LCO 3.6.4.2 and LCO 3.6.4.3, respectively, overlaps this Surveillance to provide complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.
REFERENCES 1. FSAR, Section 6.3.
- 2. FSAR, Chapter 15
- 3. FSAR, Section 15.2.
- 4. FSAR, Sections 15.7.
- 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation", July 1990.
- 6. NEDC-30851 P-A Supplement 2, 'Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
- 7. Final Policy Statement on Technical Specifications Improvements, July 22, 1993. (58 FR 32193)
- 8. NRC Inspection and Enforcement Manual, Part 9900:
Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.
SUSQUEHANNA - UNIT 1 TS / B 3.3-191 Revision 1
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 B 3.3 INSTRUMENTATION B 3.3.7.1 Control Room Emergency Outside Air Supply (CREOAS) System Instrumentation BASES BACKGROUND The CREOAS System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. Two independent CREOAS subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the CREOAS System automatically initiate action to pressurize the main control room to minimize the consequences of radioactive material in the control room environment.
In the event of a loss of coolant accident (LOCA) signal (Reactor Vessel Water Level-Low Low, Level 2 or Drywell Pressure-High), Refuel Floor High Exhaust Duct Radiation-High, Refuel Floor Wall Exhaust Duct Radiation-High, Railroad Access Shaft Exhaust Duct Radiation-High or Main Control Room Outside Air Intake Radiation-High signal, the CREOAS System is automatically started in the pressurization/filtration mode.
The CREOAS System instrumentation has two trip systems. Each trip system receives input from each of the Functions listed above and initiates associated subsystem. The Functions are arranged for each trip system as follows: the Reactor Vessel Water Level-Low Low, Level 2 and Drywell Pressure-High are each arranged in a two-out-of-two logic. The Refuel Floor High Exhaust Duct Radiation -
High, Refuel Floor Wall Exhaust Duct Radiation - High, the Main Control Room Outside Air Intake Radiation - High and the Railroad Access Shaft Exhaust Duct Radiation - High are arranged in a one-out-of-one logic.
With the exception of the Main Control Room Outside Air Intake Radiation - High all the instruments also initiate a secondary containment isolation. When the setpoint is reached, the sensor actuates, which then outputs a CREOAS System initiation signal to the initiation logic.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-192 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES (continued)
APPLICABLE The ability of the CREOAS System to maintain the habitability of the SAFETY main control room is explicitly assumed for certain accidents as ANALYSES, discussed in the FSAR safety analyses (Refs. 1 and 2). CREOAS LCO, and System operation ensures that the radiation exposure of control room APPLICABILITY personnel, through the duration of any one of the postulated accidents, does not exceed regulatory limits.
CREOAS System instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 5)
The OPERABILITY of the CREOAS System instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.7.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each CREOAS System Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with- a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-193 Revision 1
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES APPLICABLE function in harsh environments as defined by 10 CFR 50.49) are SAFETY accounted for.
- ANALYSES, LCO, and The specific Applicable Safety Analyses, LCO, and Applicability APPLICABILITY discussions are listed below on a Function by Function basis.
(continued)
- 1. Reactor Vessel Water Level-Low Low, Level 2 Low reactor pressure vessel (RPV) water level indicates that the capability of cooling the fuel may be threatened. A low reactor vessel water level could indicate a LOCA and will automatically initiate the CREQAS System, since this could be a precursor to a potential radiation release and subsequent radiation exposure to control room personnel.
Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are available (two channels per trip system) and are required to be OPERABLE to ensure that no single instrument failure can preclude a CREOAS System initiation. The Reactor Vessel Water Level- Low Low, Level 2 Allowable Value was chosen to be the same as the HPCI and RCIC Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value (LCO 3.3.5.1, "ECCS Instrumentation and LCO 3.3.5.2 "RCIC Instrumentation").
The Reactor Vessel Water Leveli-LowLow, Level 2 Function is required to be OPERABLE in MODES 1, 2, and 3, and during operations with a potential for draining the reactor vessel (OPDRVs) to ensure that the control room personnel are protected during a LOCA. In MODES 4 and 5 at times other than OPDRVs, the probability of a vessel draindown event resulting in a release of radioactive material into the environment is minimal. In addition, adequate protection is performed by the Control Room Air Inlet Radiation-High Function. Therefore, this Function is not required in other MODES and specified conditions.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-194 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES APPLICABLE 2. Drywell Pressure-High SAFETY ANALYSES, High pressure in the drywell could indicate a break in the reactor coolant LCO, and pressure boundary. A high drywell pressure signal could indicate a APPLICABILITY LOCA and will automatically initiate the CREOAS System, since this (continued) could be a precursor to a potential radiation release and subsequent radiation exposure to control room personnel.
Drywell Pressure-High signals are initiated from four pressure instruments that sense drywell pressure. Four channels of Drywell Pressure-High Function are available (two channels per trip system) and are required to be OPERABLE to ensure that no single instrument failure can preclude CREOAS System initiation. The Drywell Pressure-High Allowable Value was chosen to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1).
The Drywell Pressure-High Function is required to be OPERABLE in MODES 1, 2, and 3 to ensure that control room personnel are protected in the event of a LOCA. In MODES 4 and 5, the Drywell Pressure-High Function is not required since there is insufficient energy in the reactor to pressurize the drywell to the Drywell Pressure-High setpoint.
3, 4, 5, 6, 7 Refuel Floor High Exhaust Duct, Refuel Floor Wall Exhaust Duct and Railroad Access Shaft Exhaust Duct Radiation-High High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding. The release may have originated from the refueling floor due to a fuel handling accident.
When Exhaust Radiation-High is detected CREOAS is initiated to maintain the habitability of the main control room.
The Exhaust Radiation-High signals are initiated from radiation detectors that are located on the ventilation exhaust ducting coming from the refueling floor zone and the Railroad Access Shaft. The signal from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Eight total channels Refuel Floor High Exhaust Duct and Wall Exhaust (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-195 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES APPLICABLE 3, 4, 5, 6, 7 Refuel Floor High Exhaust Duct, Refuel Floor Wall Exhaust SAFETY Duct and Railroad Access Shaft Exhaust Duct Radiation-High ANALYSES, (continued)
LCO, and APPLICABILITY Duct Radiation-High Function (four from Unit 1 and four from Unit 2),
and two channels of the Railroad Access Shaft Exhaust Radiation - High Function (both from Unit 1) are available and are required to be OPERABLE when the associated Refuel Floor Exhaust System is in operation to ensure that no single instrument failure can preclude the initiation function.
The Allowable Values are chosen to promptly detect gross failure of the fuel cladding. The Refuel Floor Exhaust Duct and Wall Exhaust Duct Radiation-High are required to be OPERABLE during CORE ALTERATIONS, OPDRVs, and movement of irradiated fuel assemblies in the secondary containment, because the capability of detecting radiation releases due to fuel failures (due to fuel uncovery or dropped fuel assemblies) must be provided to ensure that offsite and control room dose limits are not exceeded.
The Railroad Access Shaft Exhaust Duct Radiation - High Function is only required to be OPERABLE during handling of irradiated fuel within the Railroad Access Shaft, and above the Railroad Access Shaft with the Railroad Access Shaft Equipment Hatch open, because the capability of detecting radiation releases due to fuel failures (dropped fuel assemblies) must be provided to ensure that offsite and control room dose limits are not exceeded.
- 8. Main Control Room Outside Air Intake Radiation-High The main control room outside air intake radiation monitors measure radiation levels at the control structure outside air intake duct. A high radiation level may pose a threat to main control room personnel; thus, automatically initiating the CREOAS System. The Control Room Air Inlet Radiation-High Function consists of two independent monitors. Two channels of Control Room Air Inlet Radiation-High are available and are required to be OPERABLE to ensure that no single instrument failure can preclude CREOAS System initiation. The Allowable Value was selected to ensure protection of the control room personnel.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-196 Revision I
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES APPLICABLE 8. Main Control Room Outside Air Intake Radiation-High (continued)
SAFETY ANALYSES, The Control Room Air Inlet Radiation-High Function is required to be LCO, and OPERABLE in MODES 1, 2, and 3 and during CORE ALTERATIONS, APPLICABILITY OPDRVs, and movement of irradiated fuel assemblies in the secondary containment, to ensure that control room personnel are protected during a LOCA, fuel handling event, or vessel draindown event. During MODES 4 and 5, when these specified conditions are not in progress (e.g., CORE ALTERATIONS), the probability of a LOCA or fuel damage is low; thus, the Function is not required.
- 9. Manual Initiation A Manual Initiation can be performed for CREOAS isolation by initiating a Primary Containment Isolation. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for the overall redundancy and diversity of the secondary containment isolation instrumentation as required by the NRC approved licensing basis.
There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, and during CORE ALTERATIONS, OPDRVs, and movement of irradiated fuel assemblies in the secondary containment. These are the MODES and other specified conditions in which the Secondary Containment Isolation automatic Functions are required to be OPERABLE.
ACTIONS A Note has been provided to modify the ACTIONS related to CREOAS System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-197 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES ACTIONS entry into the Condition. Section 1.3 also specifies that Required (continued) Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.
However, the Required Actions for inoperable CREOAS System instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable CREOAS System instrumentation channel.
A._1 Required Action A. 1 directs entry into the appropriate Condition referenced in Table 3.3.7.1-1. The applicable Condition specified in the Table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
B.1.1, B.1.2, B.2.1, and B.2.2 Because of the diversity of sensors available to provide initiation signals and the redundancy of the CREOAS System design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Function 2 and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for all other Functions has been shown to be acceptable (Refs. 3 and 4) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function is still maintaining CREOAS System initiation capability. A Function is considered to be maintaining CREOAS System initiation capability when sufficient channels are OPERABLE or in trip such that one trip system will generate an initiation signal from the given Function on a valid signal. For Functions 1 and 2, this would require one trip system to have two channels per logic string OPERABLE or in trip. For Functions 3, 4, 5, 6 and 7, this would require one trip system to have one channel OPERABLE.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-198 Revision 0
PPL Rev. I CREOAS System Instrumentation B 3.3.7.1 BASES ACTIONS B.1.1, B.1.2, B.2.1, and B.2.2 (continued)
Required Action B.1.2 is provided to allow the associated CREOAS subsystem(s) to be placed in the pressurization/filtration mode of operation within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. This is acceptable because placing the associated CREOAS subsystem(s) in the pressurization/filtration mode performs the safety function of the affected instrumentation. The method used to place the CREOAS subsystem(s) in operation must provide for automatically re-initiating the subsystem(s) upon restoration of power following a loss of power to the CREOAS subsystem(s).
The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time (B. 1.1, B. 1.2) is acceptable because it minimizes risk while allowing time for restoring, tripping of channels or placing in operation.
If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.2.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
Required Action B.2.2 is provided to allow the associated CREOAS subsystem(s) to be placed in the pressurization/filtration mode of operation. This is acceptable because placing the associated CREOAS subsystem(s) in the pressurization/filtration mode performs the safety function of the affected instrumentation. The method used to place the CREOAS subsystem(s) in operation must provide for automatically re-initiating the subsystem(s) upon restoration of power following a loss of power to the CREOAS subsystem(s).
C.1.1. C.1.2 and C.2 Because of the diversity of sensors available to provide initiation signals and the redundancy of the CREOAS System design, an allowable out of service time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is provided to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function is still maintaining CREOAS System initiation capability. A Function (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-199 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES ACTIONS C.1.1, C.1.2 and C.2 (continued) is considered to be maintaining CREOAS System initiation capability when sufficient channels are OPERABLE or in trip such that one trip system will generate an initiation signal from the given Function on a valid signal. For Function 8, this would require one trip system to have one channel OPERABLE or in trip. For loss of CREOAS System initiation capability, the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance of Required Action C.2 is not appropriate. If the Function is not maintaining CREOAS System initiation capability, the CREOAS System must be declared inoperable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of discovery of the loss of CREOAS System initiation capability in both trip systems.
Required Action C.1.2 is provided to allow the associated CREOAS subsystem(s) to be placed in pressurization/filtration mode of operation within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. This is acceptable because placing the associated CREOAS subsystem(s) in the pressurization/filtration mode performs the safety function of the affected instrumentation. The method used to place the CREOAS subsystem(s) in operation must provide for automatically re-initiating the subsystem(s) upon restoration of power following a loss of power to the CREOAS subsystem(s).
The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time (C. 1.1 and C. 1.2) is acceptable because it minimizes risk while allowing time for restoring or tripping of channels.
If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action C.2. Placing the inoperable channel in trip performs the intended function of the channel (starts the lead CREOAS subsystems in the pressurization/filtration mode).
Alternately, if it is not desired to place the channel in trip (e.g., as in the case where it is not desired to start the subsystem), Condition D must be entered and its Required Action taken. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time is based on the consideration that this Function provides the primary signal to start the CREOAS System; thus, ensuring that the design basis of the CREOAS System is met.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-200 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES ACTIONS D.1 (continued)
With any Required Action and associated Completion Time not met, the associated CREOAS subsystem must be declared inoperable immediately per Required Action D.1 to ensure that control room personnel will be protected in the event of a Design Basis Accident.
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each CREOAS REQUIREMENTS System instrumentation Function are located in the SRs column of Table 3.3.7.1-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, provided the associated Function maintains CREOAS System initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be retumed to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 3 and 4) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the CREOAS System will initiate when necessary.
SR 3.3.7.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious.
A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-201 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.1 (continued)
REQUIREMENTS Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.
The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channel status during normal operational use of the displays associated with channels required by the LCO.
SR 3.3.7.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.
The Frequency of 92 days is based on the reliability analyses of References 3 and 4.
This SR is modified by two Notes. Note 1 provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relays which input into the combinational logic. (Reference 6) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.7.1.5. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.3-202 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.2 REQUIREMENTS (continued) Note 2 provides a second specific exception to the definition of CHANNEL FUNCTIONAL TEST. For Function 8, certain channel relays are not included in the performance of the CHANNEL FUNCTIONAL TEST. These exceptions are necessary because the circuit design does not facilitate functional testing of the entire channel through to the coil of the relay which enters the combinational logic. (Reference 6)
Specifically, testing of all required relays would require lifting of leads and inserting test equipment which could lead to unplanned transients.
Therefore, for these circuits, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the actuation of circuit devices up to the point where further testing would result in an unplanned transient.
(References 7 and 8) The required relays not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.7.1.5. This is acceptable because operating experience shows that the devices not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.
SR 3.3.7.1.3 and SR 3.3.7.1.4 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
The Frequencies of SR 3.3.7.1.3 and SR 3.3.7.1.4 are based upon the assumption of a 92 day and a 24 month calibration interval respectively, in the determination of the magnitude of equipment drift in the setpoint analysis.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.3-203 Revision 0
PPL Rev. 1 CREOAS System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.5 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.7.3, "Control Room Emergency Outside Air Supply (CREOAS) System," overlaps this Surveillance to provide complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
REFERENCES 1. FSAR, Section 6.4.1.
- 2. FSAR, Table 15.2.
- 3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
- 4. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.
- 5. Final Policy Statement on Technical Specification Improvements, July 22, 1993 (58 FR 32193).
- 6. NRC Inspection and Enforcement Manual, Part 9900:
Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.
- 7. PPL Letter to NRC, PLA-2618, Response to NRC INSPECTION REPORTS 50-387/85-28 and 50-388/85-23, dated April 22, 1986.
- 8. Susquehanna Steam Electric Station NRC REGION I COMBINED INSPECTION 50-387/90-20; 50-388/90-20, File R41-2, dated March 5, 1986.
SUSQUEHANNA - UNIT 1 TS / B 3.3-204 Revision 0
PPL Rev. 2 RCS Specific Activity B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.7 RCS Specific Activity BASES BACKGROUND During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks into the reactor coolant and activation of corrosion products in the reactor coolant. These radioactive materials in the reactor coolant can plate out in the RCS, and, at times, an accumulation will break away to spike the normal level of radioactivity.
The release of coolant during a Design Basis Accident (DBA) could send radioactive materials into the environment.
Limits on the maximum allowable level of radioactivity in the reactor coolant are established to ensure that in the event of a release of any radioactive material to the environment during a DBA, radiation doses are maintained within regulatory limits.
This LCO contains iodine specific activity limits. The iodine isotopic activities per gram of reactor coolant are expressed in terms of a DOSE EQUIVALENT 1-131. The allowable levels are intended to limit the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> radiation dose to an individual at the site boundary regulatory limits.
APPLICABLE Analytical methods and assumptions involving radioactive material in the SAFETY primary coolant are presented in the FSAR (Ref. 2). The specific activity ANALYSES in the reactor coolant (the source term) is an initial condition for evaluation of the consequences of an accident due to a main steam line break (MSLB) outside containment. No fuel damage is postulated in the MSLB accident, and the release of radioactive material to the environment is assumed to end when the main steam isolation valves (MSIVs) close completely.
This MSLB release forms the basis for determining offsite and control room doses (Ref. 2). The limits on the specific activity of the primary coolant ensure that the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> dose at the site boundary, resulting from an MSLB outside containment during steady state operation, will not exceed regulatory limits.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.4-35 Revision 1
PPL Rev. 2 RCS Specific Activity B 3.4.7 BASES APPLICABLE The limits on specific activity are values from a parametric evaluation of SAFETY typical site locations. These limits are conservative because the ANALYSES evaluation considered more restrictive parameters than for a specific site, (continued) such as the location of the site boundary and the meteorological conditions of the site.
RCS specific activity satisfies Criterion 2 of the NRC Policy Statement (Ref. 3).
LCO The specific iodine activity is limited to
- 0.2 pLCi/gm DOSE EQUIVALENT 1-131. This limit ensures the source term assumed in the safety analysis for the MSLB is not exceeded, so any release of radioactivity to the environment during an MSLB will not exceed regulatory limits. I APPLICABILITY In MODE 1, and MODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are applicable since there is an escape path for release of radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary containment In MODES 2 and 3 with the main steam lines isolated, such limits do not apply since an escape path does not exist. In MODES 4 and 5, no limits are required since the reactor is not pressurized and the potential for leakage is reduced.
ACTIONS A.1 and A.2 When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT 1-131 limit, but is
- 4.0 pCi/gm, samples must be analyzed for DOSE EQUIVALENT 1-131 at least once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. In addition, the specific activity must be restored to the LCO limit within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The Completion Time of once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on the time needed to take and analyze a sample. The 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> Completion Time to restore the activity level provides a reasonable time for temporary coolant activity increases (iodine spikes or crud bursts) to be cleaned up with the normal processing systems.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.4-36 Revision 1
PPL Rev. 2 RCS Specific Activity B 3.4.7 BASES ACTIONS A.1 and A.2 (continued)
A Note permits the use of the provisions of LCO 3.0.4.c. This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS.
This allowance is acceptable due to the significant conservatism incorporated into the specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds to power operation.
B.1, B.2.1, B.2.2.1, and B.2.2.2 If the DOSE EQUIVALENT 1-131 cannot be restored to
- 0.2 j+/-Ci/gm within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, or if at any time it is > 4.0 4+/-Ci/gm, it must be determined at least once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and all the main steam lines must be isolated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Isolating the main steam lines precludes the possibility of exceeding regulatory dose limits during a postulated MSLB accident.
Alternatively, the plant can be placed in MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This option is provided for those instances when isolation of main steam lines is not desired (e.g., due to the decay heat loads). In MODE 4, the requirements of the LCO are no longer applicable.
The Completion Time of once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is the time needed to take and analyze a sample. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is reasonable, based on operating experience, to isolate the main steam lines in an orderly manner and without challenging plant systems. Also, the allowed Completion Times for Required Actions B.2.2.1 and B.2.2.2 for placing the unit in MODES 3 and 4 are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.4-37 Revision 2
PPL Rev. 2 RCS Specific Activity B 3.4.7 BASES (continued)
SURVEILLANCE SR 3.4.7.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains within limit during normal operation. The 7 day Frequency is adequate to trend changes in the iodine activity level.
This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less.
REFERENCES 1. Deleted. I
- 2. FSAR, Section 15.6.4.
- 3. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.4-38 Revision 1
PPL Rev. 2 Primary Containment B 3.6.1.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a Design Basis Loss of Coolant Accident and to confine the postulated release of radioactive material. The primary containment consists of a steel lined, reinforced concrete vessel, which surrounds the Reactor Primary System and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment.
The isolation devices for the penetrations in the primary containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:
- a. All penetrations required to be closed during accident conditions are either:
- 1. capable of being closed by an OPERABLE automatic containment isolation system, or
- 2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as provided in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs);"
- b. The primary containment air lock is OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air Lock;"
and
- c. All equipment hatches are closed.
Several instruments connect to the primary containment atmosphere and are considered extensions of the primary containment. The leak rate tested instrument isolation valves identified in the Leakage Rate Test Program should be used as the primary containment boundary when the instruments are isolated and/or vented. Table B 3.6.1.1-1 contains the listing of the instruments and isolation valves.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-1 Revision 2
PPL Rev. 2 Primary Containment B 3.6.1.1 BASES BACKGROUND (continued) The H20 2 Analyzer lines beyond the PCIVs, up to and including the components within the H 2 0 2 Analyzer panels, are extensions of primary containment (i.e., closed system), and are required to be leak rate tested in accordance with the Leakage Rate Test Program. The H 2 0 2 Analyzer closed system boundary is identified in the Leakage Rate Test Program, and consists of components, piping, tubing, fittings, and valves, which meet the design guidance of Reference 7. Within the H 2 0 2 Analyzer panels, the boundary ends at the first normally closed valve. The closed system boundary between PASS and the H 2 0 2 Analyzer system ends at the Seismic Category I boundary between the two systems. This boundary occurs at the process sampling solenoid operated isolation valves (SV-12361, SV-12365, SV-12366, SV-12368, and SV-12369). These solenoid operated isolation valves do not fully meet the guidance of Reference 7 for closed system boundary valves in that they are not powered from a Class 1 E power source. Based upon a risk determination, operating these valves as closed system boundary valves is not risk significant.
These normally closed valves are required to be leakage rate tested in accordance with the Leakage Rate Test Program, since they form part of the closed system boundary for the H 2 0 2 Analyzers. These valves are "closed system boundary valves" and may be opened under administrative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.
When the H 20 2 Analyzer panels are isolated and/or vented, the panel isolation valves identified in the Leakage Rate Test Program should be used as the boundary of the extension of primary containment. Table B 3.6.1.1-2 contains a listing of the affected H 2 0 2 Analyzer penetrations and panel isolation valves.
This Specification ensures that the performance of the primary containment, in the event of a Design Basis Accident (DBA),
meets the assumptions used in the safety analyses of References 1 and 2. SR 3.6.1.1.1 leakage rate requirements are in conformance with 10 CFR 50, Appendix J, Option B and supporting documents (Ref. 3, 4 and 5), as modified by approved exemptions.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-1 a Revision 3
PPL Rev. 2 Primary Containment B 3.6.1.1 BASES (continued)
APPLICABLE The safety design basis for the primary containment is that SAFETY ANALYSES it must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.
The DBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage.
Analytical methods and assumptions involving the primary containment are presented in References 1 and 2. The safety analyses assume a nonmechanistic fission product release following a DBA, which forms the basis for determination of offsite and control room doses. The fission product release is, in turn, based on an assumed leakage rate from the primary containment.
OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.
The maximum allowable leakage rate for the primary containment (La) is 1.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design basis LOCA maximum peak containment pressure (Pa) of 45 psig.
Primary containment satisfies Criterion 3 of the NRC Policy Statement. (Ref. 6)
LCO Primary containment OPERABILITY is maintained by limiting leakage to < 1.0 La, except prior to each startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met.
Compliance with this LCO will ensure a primary containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analyses.
Individual leakage rates specified for the primary containment air lock are addressed in LCO 3.6.1.2.
Leakage requirements for MSIVs and Secondary containment bypass are addressed in LCO 3.6.1.3.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.6-2 Revision 3
PPL Rev. 2 Primary Containment B 3.6.1.1 BASES (continued)
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.
Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.
ACTIONS A.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1, 2, and 3.
This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.
B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. The primary containment concrete visual examinations may be.performed during either power operation, e.g., performed concurrently with other primary containment inspection-related activities, or during a maintenance or refueling outage. The visual examinations of the steel liner plate inside primary containment are performed during maintenance or refueling outages since this is the only time the liner plate is fully accessible.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.6-3 Revision 3
PPL Rev. 2 Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.1 (continued)
REQUIREMENTS Failure to meet air lock leakage testing (SR 3.6.1.2.1) or resilient seal primary containment purge valve leakage testing (SR 3.6.1.3.6) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. As left leakage prior to each startup after performing a required leakage test is required to be < 0.6 La for combined Type B and C leakage, and <0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of
< 1.0 La. At < 1.0 La the offsite and control room dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.
SR Frequencies are as required by the Primary Containment Leakage Rate Testing Program. These periodic testing requirements verify that the primary containment leakage rate does not exceed the leakage rate assumed in the safety analysis.
As noted in table B 3.6.1.3-1, an exemption to Appendix J is provided that isolation barriers which remain water filled or a water seal remains in the line post-LOCA are tested with water and the leakage is not included in the Type B and C 0.60 La total.
SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR measures drywell to suppression chamber leakage to ensure that the leakage paths that would bypass the suppression pool are within allowable limits. The allowable limit is 10% of the acceptable SSES Ahlk design valve. For SSES, the A/-4k design value is
.0535 ft2 .
Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and determining the leakage. The leakage test is performed when the 10 CFR 50, Appendix J, Type A test is performed in accordance with the Primary Containment Leakage Rate Testing Program. This testing Frequency was developed considering this test is performed in conjunction with the Integrated Leak rate test (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-4 Revision 4
PPL Rev. 2 Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)
REQUIREMENTS and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 24 months is required until the situation is remedied as evidenced by passing two consecutive tests.
SR 3.6.1.1.3 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through downcomers into the suppression pool. This SR measures suppression chamber-to-drywell vacuum breaker leakage to ensure the leakage paths that would bypass the suppression pool are within allowable limits. The total allowable leakage limit is 30% of the SR 3.6.1.1.2 limit. The allowable leakage per set is 12% of the SR 3.6.1.1.2 limit.
The leakage is determined by establishing a 4.3 psi differential pressure across the drywell-to-suppression chamber vacuum breakers and verifying the leakage. The leakage test is performed every 24 months. The 24 month Frequency was developed considering the surveillance must be performed during a unit outage. A Note is provided which allows this Surveillance not to be performed when SR 3.6.1.1.2 is performed. This is acceptable because SR 3.6.1.1.2 ensures the OPERABILITY of the pressure suppression function including the suppression chamber-to-drywell vacuum breakers.
REFERENCES 1. FSAR, Section 6.2.
- 2. FSAR, Section 15.
- 3. 10 CFR 50, Appendix J, Option B.
- 4. Nuclear Energy Institute, 94-01 (continued)
SUSQUEHANNA- UNIT 1 TS / B 3.6-5 Revision 3
PPL Rev. 2 Primary Containment B 3.6.1.1 BASES REFERENCES (continued) 5. ANSI/ANS 56.8-1994
- 6. Final Policy Statement on Technical Specifications Improvements July 22, 1993 (58 FR 39132)
- 7. Standard Review Plan 6.2.4, Rev. 1, September 1975 I SUSQUEHANNA - UNIT 1 TS / B 3.6-6 Revision 3
PPL Rev. 2 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 1 of 2)
PENETRATION INSTRUMENT INSTRUMENT ISOLATION NUMBER VALVE X-3B PSH-C72-1N002A IC-PSH-1N002A PSH L C72-1N004 IC-PSHL-1N004 PS-E11-1NO10A IC-PS-1NO10A PS-Ell-1NO11A IC-PS-1N011A PSH-C72-1 N002B IC-PSH-1 N002B PS-E11-1NO10C IC-PS-1N010C PS-El-N011C IC-PS-1 N011 C PSH-15120C IC-PSH-15120C X-32A PSH-C72-1 N002D IC-PSH- 1NO02D PS-El1-1NO10B IC-PS-1 N01 OB PS-E11-IN011B IC-PS-1N011B PSH-C72-1 N002C IC-PSH-1 N002C PS-E11-1NO10D IC-PS-1NO10D PS-El1-INO11D IC-PS-1 N01 1D PSH-15120D IC-PSH-15120D X-39A FT-15120A IC-FT-15120A HIGH and IC-FT-15120A LOW X-39B FT-15120B IC-FT-15120B HIGH and IC-FT-15120B LOW X-90A PT-1 5709A IC-PT-1 5709A PT-15710A IC-PT-15710A PT- 15728A IC-PT-1 5728A X-90D PT-15709B IC-PT-1 5709B PT-15710B IC-PT-15710B PT-1 5728B IC-PT-15728B SUSQUEHANNA - UNIT 1 TS/B 3.6-6a Revision 2
PPL Rev. 2 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 2 of 2)
X-204A/205A FT-15121A IC-FT-15121A HIGH and IC-FT-15121A LOW X-204B/205B FT-15121B IC-FT-15121B HIGH and IC-FT-15121B LOW X-219A LT-15775A IC-LT-15775A REF and IC-LT-15775A VAR LSH-E41-1NO15A 155027 and 155031 LSH-E41-1N015B 155029 and 155033 X-223A PT-1 5702 IC-PT- 15702 X-232A LT-15776A IC-LT-15776A REF and IC-LT-15776A VAR PT-1 5729A IC-PT-15729A LI-15776A2 IC-LT-15776A2 REF and IC-LT-15776A2 VAR X234A LT-15775B IC-LT-15775B REF and IC-LT-15775B VAR X-235A LT-15776B IC-LT-15776B REF and IC-LT-1 5776B VAR PT-1 5729B IC-PT-15729B SUSQUEHANNA - UNIT 1 TS/B 3.6-6b Revision 2
PPL Rev. 2 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-2 H20 2 ANALYZER PANEL ISOLATION VALVES PENETRATION NUMBER PANEL ISOLATION VALVE(a)
X-60A, X-88B, X-221A, X-238A 157138 157139 157140 157141 157142 X-80C, X-233, X-238B 157149 157150 157151 157152 157153 (a) Only those valves listed in this table with current leak rate test results, as identified in the Leakage Rate Test Program, may be used as isolation valves.
SUSQUEHANNA - UNIT 1 TS/B 3-6-6c Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)
BASES BACKGROUND The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment 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 DBA.
The OPERABILITY requirements for PCIVs help ensure that an adequate prmary containment boundary is maintained during and after an accident by minimizing potential paths to the environment.
Therefore, the OPERABILITY requirements provide assurance that primary containment function assumed in the safety analyses will be maintained. For PCIVs, the primary containment isolation function is that the valve must be able to close (automatically or manually) and/or remain closed, and maintain leakage within that assumed in the DBA LOCA Dose Analysis. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices. The OPERABILITY requirements for closed systems are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.
For each division of H2 0 2 Analyzers, the lines, up to and including the first normally closed valves within the H 2 0 2 Analyzer panels, are extensions of primary containment (i.e.,
closed system), and are required to be leak rate tested in (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-15 Revision 2
PPL Rev. 7 PCIVs B 3.6.1.3 BASES BACKGROUND accordance with the Leakage Rate Test Program. The H20 2 (continued) Analyzer closed system boundary is identified in the Leakage Rate Test Program. The closed system boundary consists of those components, piping, tubing, fittings, and valves, which meet the guidance of Reference 6. The closed system provides a secondary barrier in the event of a single failure of the PCIVs, as described below. The closed system boundary between PASS and the H 2 0 2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-12361, SV-12365, SV-12366, SV-12368, and SV-12369). These solenoid operated isolation valves do not fully meet the guidance of Reference 6 for closed system boundary valves in that they are not powered from a Class 1 E power source. However, based upon a risk determination, operating these valves as closed system boundary valves is not risk significant. These valves also form the end of the Seismic Category I boundary between the systems. These process sampling solenoid operated isolation valves are normally closed and are required to be leak rate tested in accordance with the Leakage Rate Test Program as part of the closed system for the H20 2 Analyzer system. These valves are "closed system boundary valves" and may be opened under administrative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1,2, and 3 is permitted in accordance with TRO 3.6.4.
Each H20 2 Analyzer Sampling line penetrating primary containment has two PCIVs, located just outside primary containment. While two PCIVs are provided on each line, a single active failure of a relay in the control circuitry for these valves, could result in both valves failing to close or failing to remain closed. Furthermore, a single failure (a hot short in the common raceway to all the valves) could simultaneously affect all of the PCIVs within a H20 2 Analyzer division. Therefore, the containment isolation barriers for these penetrations consist of two PCIVs and a closed system. For situations where one or both PCIVs are inoperable, the ACTIONS to be taken are similar to the ACTIONS for a single PCIV backed by a closed system.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-15a Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 BASES BACKGROUND The drywell vent and purge lines are 24 inches in diameter;,
(continued) the suppression chamber vent and purge lines are 18 inches in diameter. The containment purge valves are normally maintained closed in MODES 1, 2, and 3 to ensure the primary containment boundary is maintained. The outboard isolation valves have 2 inch bypass lines around them for use during normal reactor operation.
The RHR Shutdown Cooling return line containment penetrations
{X-13A(B)}are provided with a normally closed gate valve
{HV-151F015A(B)} and a normally open globe valve
{HV-151F017A(B)} outside containment and a testable check valve {HV-1 51 F050A(B)} with a normally closed parallel air operated globe valve {HV-151 F122A(B)} inside containment.
The gate valve is manually opened and automatically isolates upon a containment isolation signal from the Nuclear Steam Supply Shutoff System or RPV low level 3 when the RHR System is operated in the Shutdown Cooling Mode only. The LPCI subsystem is an operational mode of the RHR System and uses the same injection lines to the RPV as the Shutdown Cooling Mode.
The design of these containment penetrations is unique in that some valves are containment isolation valves while others perform the function of pressure isolation valves. In order to meet the 10 CFR 50 Appendix J leakage testing requirements, the HV-1 51 F01 5A(B) and the closed system outside containment are the only barriers tested in accordance with the Leakage Rate Test Program. Since these containment penetrations {X-13A and X-13B} include a containment isolation valve outside containment that is tested in accordance with 10 CFR 50 Appendix J require-ments and a closed system outside containment that meets the requirements of USNRC Standard Review Plan 6.2.4 (September 1975), paragraph 11.3.e, the containment isolation provisions for these penetrations provide an acceptable alternative to the explicit requirements of 10 CFR 50, Appendix A, GDC 55.
Containment penetrations X-13A(B) are also high/low pressure system interfaces. In order to meet the requirements to have two (2) isolation valves between the high pressure and low pressure systems, the HV-151 F050A(B), HV-151F122A(B), and HV-1 51 F01 5A(B) valves are used to meet this requirement and are tested in accordance with the pressure test program.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-15b Revision 2
PPL Rev. 7 PCIVs B 3.6.1.3 BASES APPLICABLE The PCIVs LCO was derived from the assumptions related SAFETY ANALYSES to minimizing the loss of reactor coolant inventory, and establishing the primary containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment.
Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO.
The DBAs that result in a release of radioactive material within primary containment are a LOCA and a main steam line break (MSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) are minimized. The closure time of the main steam isolation valves (MSIVs) for a MSLB outside primary containment is a significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds since the 5 second closure time is assumed in the analysis. The safety analyses assume that the purge valves were closed at event initiation. Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled.
The DBA analysis assumes that within the required isolation time leakage is terminated, except for the maximum allowable leakage rate, L,.
The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary containment purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.
The primary containment purge valves may be unable to close in the environment following a LOCA. Therefore, each of the purge valves is required to remain closed during MODES 1, 2, and 3 except as permitted under Note 2 of SR 3.6.1.3.1. In this case, the single failure criterion remains applicable to the primary containment purge valve (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-16 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 BASES APPLICABLE due to failure in the control circuit associated with each SAFETY ANALYSES valve. The primary containment purge valve design (continued) precludes a single failure from compromising the primary containment boundary as long as the system is operated in accordance with this LCO.
Both H2 0 2 Analyzer PCIVs may not be able to close given a single failure in the control circuitry of the valves. The single failure is caused by a "hot short" in the cables/raceway to the PCIVs that causes both PCIVs for a given penetration to remain open or to open when required to be closed. This failure is required to be considered in accordance with IEEE-279 as discussed in FSAR Section 7.3.2a. However, the single failure criterion for containment isolation of the H 2 0 2 Analyzer penetrations is satisfied by virtue of the combination of the associated PCIVs and the closed system formed by the H20 2 Analyzer piping system as discussed in the BACKGROUND section above.
The closed system boundary between PASS and the H20 2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-12361, SV-12365, SV-12366, SV-12368, and SV-12369). The closed system is not fully qualified to the guidance of Reference 6 in that the closed system boundary valves between the H 2 0 2 system and PASS are not powered from a Class 1 E power source. However, based upon a risk determination, the use of these valves is considered to have no risk significance. This exemption to the requirement of Reference 6 for the closed system boundary is documented in License Amendment No. 195.
PCIVs satisfy Criterion 3 of the NRC Policy Statement. (Ref. 2)
LCO PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a DBA.
The power operated, automatic isolation valves are required to have isolation times within limits and actuate on an automatic isolation signal. The valves covered by this LCO are listed in Table B 3.6.1.3-1.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-17 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 BASES LCO The normally closed PCIVs are considered OPERABLE (continued) when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves and devices are those listed in Table B 3.6.1.3-1.
Purge valves with resilient seals, secondary containment bypass valves, MSIVs, and hydrostatically tested valves must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment," as Type B or C testing.
This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.
Therefore, most PCIVs are not required to be (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-17a Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 BASES APPLICABILITY OPERABLE and the primary containment purge valves are (continued) not required to be closed in MODES 4 and 5. Certain valves, however, are required to be OPERABLE to prevent inadvertent reactor vessel draindown. These valves are'those whose associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation."
(This does not include the valves that isolate the associated instrumentation.)
ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.
A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.
The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions are not required even when the associated LCO is not met. Therefore, Notes 3 and 4 are added to require the proper actions be taken.
A.1 and A.2 With one or more penetration flow paths with one PCIV inoperable except for purge valve leakage not within limit, (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-18 Revision 0
PPL. Rev. 7 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued) the affected penetration flow paths must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available valve to the primary containment. The Required Action must be completed within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for main steam lines). The Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time is allowed. The Completion Time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for the main steam lines allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown.
For affected penetrations that have been isolated in accordance with Required Action A. 1, the affected penetration flow path(s) must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no longer capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-19 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 BASES.
ACTIONS A.1 and A.2 (continued)
Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two PCIVs except for the H20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H 2 0 2 Analyzer Penetrations, Condition D provides the appropriate Required Actions.
Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas, and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices, once they have been verified to be in the proper position, is low.
B.1 With one or more penetration flow paths with two PCIVs inoperable except for purge valve leakage not within limit, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de--activated automatic valve, a closed manual valve, and a blind flange. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is consistent with the ACTIONS of LCO 3.6.1.1.
Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two PCIVs except for the H20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H20 2 Analyzer Penetrations, Condition D provides the appropriate Required Actions.
C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to. OPERABLE status or the affected penetration flow path (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-20 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued) must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action C.1 must be completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The closed system must meet the requirements of Reference 6. For conditions where the PCIV and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply. For the Excess Flow Check Valves (EFCV), the Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. In the event the affected penetration flow path is isolated in accordance with Required Action C. 1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.
Condition C is modified by a Note indicating that this Condition is only applicable to penetration flow paths with only one PCIV. For penetration flow paths with two PCIVs and the H20 2 Analyzer Penetration. Conditions A, B and D provide the appropriate Required Actions.
Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these valves, once they have been verified to be in the proper position, is low.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-21 Revision 2
PPL Rev. 7 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)
With one or more H 2 0 2 Analyzer penetrations with one or both PCIVs inoperable, the inoperable valve(s) must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action D.1 must be completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the unique design of the H20 2 Analyzer penetrations. The containment isolation barriers for these penetrations consist of two PCIVs and a closed system. In addition, the Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. In the event the affected penetration flow path is isolated in accordance with Required Action D.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.
When an H20 2 Analyzer penetration PCIV is to be closed and deactivated in accordance with Condition D, this must be accomplished by pulling the fuse for the power supply, and either determinating the power cables at the solenoid valve, or jumpering of the power side of the solenoid to ground.
The OPERABILITY requirements for the closed system are discussed in Technical Requirements Manual (TRM) Bases 3.6.4.
In the event that either one or both of the PCIVs and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply.
(continued)
SUSQUEHANNA-UNIT 1 TS / B 3.6-22 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)
Condition D is modified by a Note indicating that this Condition is only applicable to the H20 2 Analyzer penetrations.
E. 1 With the secondary containment bypass leakage rate not within limit, the assumptions of the safety analysis may not be met.
Therefore, the leakage must be restored to within limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and de-activated automatic valve, closed manual valve, or blind flange. When a penetration is isolated, the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is reasonable considering the time required to restore the leakage by isolating the penetration and the relative importance of secondary containment bypass leakage to the overall containment function.
F.1 In the event one or more containment purge valves are not within the purge valve leakage limits, purge valve leakage must be restored to within limits. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable, considering that one containment purge valve remains closed, except as controlled by SR 3.6.1.3.1 so that a gross breach of containment does not exist.
G.1 and G.2 If any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-22a Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 BASES ACTIONS H.1 and H.2 (continued)
If any Required Action and associated Completion Time cannot be met, the unit must be placed in a condition in which the LCO does not apply. If applicable, action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended or valve(s) are restored to OPERABLE status. If suspending an OPDRV would result in closing the residual heat removal (RHR) shutdown cooling isolation valves, an alternative Required Action is provided to immediately initiate action to restore the valve(s) to OPERABLE status. This allows RHR to remain in service while actions are being taken to restore the valve.
SURVEILLANCE SR 3.6.1.3.1 REQUIREMENTS This SR ensures that the primary containment purge valves are closed as required or, if open, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. The SR is also modified by Note 1, stating that primary containment purge valves are only required to be closed in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves, or the release of radioactive material will exceed limits prior to the purge valves closing. At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are allowed to be open. The SR is modified by Note 2 stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The vent and purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-23 Revision I
PPL Rev. 7 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.1 (continued)
REQUIREMENTS limited periods of time. The 31 day Frequency is consistent with other PCIV requirements discussed in SR 3.6.1.3.2.
SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.
This SR does not require any testing or valve manipulation.
Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are in the correct position. Since verification of valve position for PCIVs outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the PCIVs are in the correct positions.
Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.
SR 3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-24 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)
REQU IREMENTS secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing. Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.
SR 3.6.1.3.4 The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.
SR 3.6.1.3.5 Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-25 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 (continued)
REQUIREMENTS full closure isolation time is demonstrated by SR 3.6.1.3.7. The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed in the Final Safety Analyses Report. The isolation time and Frequency of this SR are in accordance with the requirements of the Inservice Testing Program.
SR 3.6.1.3.6 For primary containment purge valves with resilient seals, the Appendix J Leakage Rate Test Interval of 24 months is sufficient.
The acceptance criteria for these valves is defined in the Primary Containment Leakage Rate Testing Program, 5.5.12.
The SR is modified by a Note stating that the primary containment purge valves are only required to meet leakage rate testing requirements in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, purge valve leakage must be minimized to ensure offsite radiological release is within limits.
At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are not required to meet any specific leakage criteria.
SR 3.6.1.3.7 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses. This ensures that the calculated radiological consequences of these events remain within regulatory limits. The Frequency of this SR is in accordance I with the requirements of the Inservice Testing Program.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-26 Revision 2
PPL Rev. 7 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.8 REQUIREMENTS (continued) Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.5 ovedaps this SR to provide complete testing of the safety function. The 24 month Frequency was developed considering it is prudent that some of these Surveillances be performed only during a unit outage since isolation of penetrations could eliminate cooling water flow and disrupt the normal operation of some critical components. Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.6.1.3.9 This SR requires a demonstration that a representative sample of reactor instrumentation line excess flow check valves (EFCV) are OPERABLE by verifying that the valve actuates to check flow on a simulated instrument line break. As defined in FSAR Section 6.2.4.3.5 (Reference 4), the conditions under which an EFCV will isolate, simulated instrument line break, are at flow rates which develop a differential pressure of between 3 psid and 10 psid.
This SR provides assurance that the instrumentation line EFCVs will perform its design function to check flow. No specific valve leakage limits are specified because no specific leakage limits are defined in the FSAR. The 24 month Frequency is based on the need to perform some of these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The representative sample consists of an approximate equal number of EFCVs such that each EFCV is tested at least once every 10 years (nominal). The nominal 10 year interval is based on other performance-based testing programs, such as Inservice Testing (snubbers) and Option B to 10 CFR 50, Appendix J. In addition, the EFCVs in the sample are representative of the various plant configurations, models, sizes and operating environments. This ensures that any potential common problems with a specific type or application of EFCV is detected at the earliest possible time. EFCV failures will be evaluated to determine if additional testing in that test interval is warranted to ensure overall reliability and that failures to isolate are very infrequent. Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint (Reference 7).
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-27 Revision 2
PPL Rev. 7 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.10 REQUIREMENTS (continued) The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Frequency of 24 months on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4).
SR 3.6.1.3.11 This SR ensures that the leakage rate of secondary containment bypass leakage paths is less than the specified leakage rate. This provides assurance that the assumptions in the radiological evaluations of Reference 4 are met. The secondary containment leakage pathways and Frequency are defined by the Primary Containment Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria.
A note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other MODES, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required.
SR 3.6.1.3.12 The analyses in References 1 and 4 are based on the specified leakage rate. Leakage through each MSIV must be < 100 scfh for any one MSIV or
- 300 scfh for total leakage through. the MSIVs combined with the Main Steam Line Drain Isolation Valve, HPCI Steam Supply Isolation Valve and the RCIC Steam Supply Isolation Valve. The MSIVs can be tested at either > Pt (22.5 psig) or P, (45 psig). Main Steam Line Drain Isolation, HPCI and RCIC Steam Supply Line Isolation Valves, are tested at P, (45 psig). A note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other conditions, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required. The Frequency is required by the Primary Containment Leakage Rate Testing Program. I (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-28 Revision 6
PPL Rev. 7 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.13 REQUIREMENTS (continued) Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 2 are met. The acceptance criteria for the combined leakage of all hydrostatically tested lines is 3.3 gpm when tested at 1.1 Pa, (49.5 psig). The combined leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by the Primary Containment Leakage Testing Program.
As noted in Table B 3.6.1.3-1, PCIVs associated with this SR are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water level in the Suppression Chamber. These valves are tested in accordance with the IST Program. Therefore, these valves leakage is not included as containment leakage.
This SR has been modified by a Note that states that these valves are only required to meet the combined leakage rate in MODES 1, 2, and 3, since this is when the Reactor Coolant System is pressurized and primary containment is required. In some instances, the valves are required to be capable of automatically closing during MODES other than MODES 1, 2, and 3. However, specific leakage limits are not applicable in these other MODES or conditions.
REFERENCES 1. FSAR, Chapter 15.
- 2. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
- 3. 10 CFR 50, Appendix J, Option B.
- 4. FSAR, Section 6.2.
- 5. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"
March 1988.
- 6. Standard Review Plan 6.2.4, Rev. 1, September 1975
- 7. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000.
SUSQUEHANNA - UNIT 1 TS / B 3.6-29 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 1 of 11)
Isolation Signal CO 3.3.6.1 Function No.
LType Plant System Valve Number Vatve Description T of Valve (Maximum Isolation Time (Seconds))
Containment 1-57-193 (d) ILRT Manual N/A Atmospheric 1-57-194 (d) ILRT Manual N/A Control HV-15703 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-1 5704 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15705 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15711 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-1 5713 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15714 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-1 5721 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15722 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15723 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15724 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15725 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)
HV-15766 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)
HV-1 5768 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)
SV-1 57100 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57100 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157101 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157101 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57102 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57102 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57103 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157103 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57104 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57105 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157106 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57107 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-15734 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15734 B (e> Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15736 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15736 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d
_ _ _ ISV-1 5737 jNitogen Makeup Automatic Valve 2.b, 2.d, 2.e SUSQUEHANNA - UNIT 1 TS / B 3.6-30 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 2 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Valve Number Valve Description Type of Valve (MLaximum Isolation Plant System Time (Seconds))
Containment SV-15738 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Atmospheric SV-15740 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d Control SV-15740 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d (continued) SV-15742 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15742 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5750 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15750 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5752 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5752 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15767 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SV-15774 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15774 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15776 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15776 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15780 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15780 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5782 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15782 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5789 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Containment 1-26-072 (d) Containment Instrument Gas Manual Check N/A Instrument Gas 1-26-074 (d) Containment Instrument Gas Manual Check N/A 1-26-152 (d) Containment Instrument Gas Manual Check N/A 1-26-154 (d) Containment Instrument Gas Manual Check N/A 1-26-164 (d) Containment Instrument Gas Manual Check N/A HV-12603 Containment Instrument Gas Automatic Valve 2.c, 2.d (20)
SV-12605 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-12651 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-1 2654 A Containment Instrument Gas Power Operated N/A SV-12654 B Containment Instrument Gas Power Operated N/A SV-12661 Containment Instrument Gas Automatic Valve 2.b, 2.d SV-12671 Containment Instrument Gas Automatic Valve 2.b, 2.d Core Spray HV-1 52F001 A (b)(c) CS Suction Valve Power Operated N/A HV-1 52F001 B (b)(c) CS Suction Valve Power Operated N/A HV-1 52F005 A CS Injection Power Operated N/A HV-152F005 B CS Injection Valve Power Operated N/A HV-152F006 A CS Injection Valve Air Operated Check N/A Valve HV-152F006 B CS Injection Valve Air Operated Check N/A Valve HV-1 52F01 5 A (b)(c) CS Test Valve Automatic Valve 2.c, 2.d (80) 1 HV-1 52F01 5 B (b)(c) CS Test Valve Automatic Valve 2.c, 2.d (80)
SUSQUEHANNA - UNIT 1 TS / B 3.6-31 Revision 3
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 3 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))
Core Spray HV-152F031 A (b)(c) CS Minimum Recirculation Flow Power Operated N/A (continued) HV-152F031 B (b)(c) CS Minimum Recirculation Flow Power Operated N/A HV-152F037 A CS Injection Power Operated N/A (Air)
HV-152F037 B CS Injection Power Operated NIA (Air_
XV-152F018 A Core Spray Excess Flow Check N/A I _Valve XV-152F018 B Core Spray Excess Flow Check N/A Valve HPCI 1-55-038 (d) HPCI Injection Valve Manual N/A 155F046 (b)(c)(d) HPCI Minimum Flow Check Valve Manual Check N/A 155F049 (a)(d) HPCI Turbine Exhaust Valve Manual Check N/A HV-155F002 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (50>
HV-155F003 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (50)
HV-155F006 HPCI Injection Valve Power Operated N/A HV-155F012 (b)(c) HPCI Minimum Flow Valve Power Operated N/A HV-155F042 (b)(c) HPCI Suction Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (90)
HV-155F066 (a) HPCI Turbine Exhaust Valve Power Operated N/A HV-155F075 HPCI Vacuum Breaker Isolation Automatic Valve 3.b, 3.d (15)
Valve HV-155F079 HPCI Vacuum Breaker Isolation Automatic Valve 3.b, 3.d (15)
Valve HV-155F100 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (6)
XV-155F024 A HPCI Valve Excess Flow Check N/A Valve XV-155F024 B HPCI Valve Excess Flow Check N/A Valve XV-155F024 C HPCI Valve Excess Flow Check N/A
,Valve YV-155F024 D HPCI Valve Excess Flow Check N/A Valve Liquid Radwaste HV-16108 Al Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)
Collection HV-16108 A2 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)
HV-16116 Al Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)
HV-16116 A2 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)
Demin Water 1-41-017 (d) Demineralized Water Manual N/A 1-41-018 (d) Demineralized Water Manual N/A Nuclear Boiler 141 F010 A (d) Feedwater Isolation Valve Manual Check N/A
.141 F010 B (d) Feedwater Isolation Valve Manual Check N/A SUSQUEHANNA - UNIT 1 TS / B 3.6-32 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 4 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Plant System Valve Number Valve Description Type of Valve (Maximumstion (Maximum Isolation Time (Seconds))
Nuclear Boiler 141 F039 A (d) Feedwater Isolation Valve Manual Check N/A (continued) 141 F039 B (d) Feedwater Isolation Valve Manual Check NIA 141818 A (d) Feedwater Isolation Valve Manual Check N/A 141818 B (d) Feedwater Isolation Valve Manual Check NIA HV-141 F016 MSL Drain Isolation Valve Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (10)
HV-141 FO19 MSL Drain Isolation Valve Automatic Valve 1.a, 1.b, 1.c, 1.d, i.e (15)
HV-141F022 A MSIV Automatic Valve l.a, l.b, 1.c, 1.d, i.e (5)
HV-141 F022 B MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, i.e (5)
HV-141 F022 C MSIV Automatic Valve 1.a, 1.b, 1.c, 1d, 1.e (5)
HV-141 F022 D MSIV Automatic Valve 1.a, 1.b, 1.c, 1d, 1.e (5)
HV-141F028 A MSIV Automatic Valve l.a, l.b, 1.c, 1.d, 1.e (5)
HV-141 F028 B MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)
HV-141 F028 C MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)
HV-141 F028 D MSIV Automatic Valve l.a, 1.b, i.c, 1.d, 1.e (5)
HV-1 41 F032 A Feedwater Isolation Valve Power Operated N/A Check HV-141 F032 B Feedwater Isolation Valve Power Operated NIA Check XV-141F009 Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F070 A Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F070 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141F070 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F070 D Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-1 41 F071 A Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F071 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141F071 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F071 D Nuclear Boiler EFCV Excess Flow Check N/A Valve SUSQUEHANNA - UNIT 1 TS / B 3.6-33 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 5 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))
Nuclear Boiler XV-141 F072 A Nuclear Boiler EFCV Excess Flow Check N/A (continued) Valve XV-141 F072 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F072 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F072 D Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F073 A Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F073 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F073 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141F073 D Nuclear Boiler EFCV Excess Flow Check N/A Valve Nuclear Boiler XV-1 4201 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Vessel Valve Instrumentation XV-14202 Nuclear Boiler Vessel Instrument Excess FlowCheck N/A Valve XV-142F041 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F043 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F043 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F045 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F045 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F047 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F047 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 C Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 D Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F053 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F053 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A
_Valve SUSQUEHANNA - UNIT I TS / B 3.6-34 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 6 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Time (Seconds))
Nuclear Boiler XV-142F053 C Nuclear Boiler Vessel Instrument Excess Flow Check N/A Vessel Valve Instrumentation XV-142F053 D Nuclear Boiler Vessel Instrument Excess Flow Check N/A (continued) Valve XV-142F055 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F057 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F059 C Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 D Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 E Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 F Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 G Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 H Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 L Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 M Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 N Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 P Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F059 R Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 S Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 T Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 U Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F061 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve RBCCW HV-11313 RBCCW Automatic Valve 2.c, 2.d (30)
HV-11314 RBCCW Automatic Valve 2.c, 2.d (30)
HV-1 1345 RBCCW Automatic Valve 2.c, 2.d (30)
HV-11346 RBCCW Automatic Valve 2.c, 2.d (30)
SUSQUEHANNA - UNIT 1 TS / B 3.6-35 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 7 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Valve Number Valve Description Type of Valve LO3.61unotion Plant System (Maximum Isolation Time (Seconds))
RCIC 1-49-020 (d) RCIC INJECTION Manual N/A 149F021 (b)(cXd) RCIC Minimum Recirculation Flow Manual Check N/A 149F028 (a)(d) RCIC Vacuum Pump Discharge Manual Check N/A 149F040 (a)(d) RCIC Turbine Exhaust Manual Check N/A FV-149F019 (b)(c) RCIC Minimum Recirculation Flow Power Operated N/A HV-149F007 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)
HV-149F008 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)
HV-149F013 RCIC Injection Power Operated N/A HV-149F031 (b)(c) RCIC Suction Power Operated N/A HV-149F059 (a) RCIC Turbine Exhaust Power Operated N/A HV-149F060 (a) RCIC Vacuum Pump Discharge Power Operated N/A HV-149F062 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)
HV-149F084 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)
HV-149F088 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (12)
XV-149F044 A RCIC Excess Flow Check N/A Valve XV-149F044 B RCIC Excess Flow Check N/A Valve XV-149F044 C RCIC Excess Flow Check N/A Valve XV-149F044 D RCIC Excess Flow Check N/A Valve RB Chilled HV-18781 Al RB Chilled Water Automatic Valve 2.c, 2.d (40)
Water System HV-18781 A2 RB Chilled Water Automatic Valve 2.c, 2.d (40)
HV-18781 B1 RB Chilled Water Automatic Valve 2.c, 2.d (40)
HV-18781 B2 RB Chilled Water Automatic Valve 2.c, 2.d (40)
HV-18782 Al RB Chilled Water Automatic Valve 2.c, 2.d (12)
HV-1 8782 A2 RB Chilled Water Automatic Valve 2.c, 2.d (12)
HV-18782 B1 RB Chilled Water Automatic Valve 2.c, 2.d (12)
HV-18782 B2 RB Chilled Water Automatic Valve 2.c, 2.d (12)
HV-18791 Al RB Chilled Water Automatic Valve 2.b, 2.d (15)
HV-18791 A2 RB Chilled Water Automatic Valve 2.b, 2d (15)
HV-18791 B1 RB Chilled Water Automatic Valve 2.b, 2.d (15)
HV-1 8791 B2 RB Chilled Water Automatic Valve 2.b, 2.d (15)
HV-1 8792 Al RB Chilled Water Automatic Valve 2.b, 2.d (8)
HV-18792 A2 RB Chilled Water Automatic Valve 2.b, 2.d (8)
HV-1 8792 B1 RB Chilled Water Automatic Valve 2.b, 2.d (8)
HV-1 8792 B2 RB Chilled Water Automatic Valve 2.b, 2.d (8)
Reactor 143F013 A (d) Recirculation Pump Seal Water Manual Check N/A Recirculation 143F01 3 B (d) Recirculation Pump Seal Water Manual Check N/A SUSQUEHANNA-UNIT 1 TS / B 3.6-36 Revision 1
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 8 of 11)
Plant System Plant__Syste__
Valve Number Vav_ u bra__ecrpinTp VleDsrpinTp
_Valve__
fVle
{LT(Maximum Isolation Signal LO3361Fnto o CO 3.3.6.1 Function of____________ IsolationNo.
Time (Seconds))
Reactor )(V-143F003 A Reactor Recirculation Excess Flow Check N/A Recirculation Valve (continued) K(V-143FO03 B Reactor Recirculation Excess Flow Check N/A Valve KV-143F004 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F004 B Reactor Recirculation Excess Flow Check N/A Valve KV-143F009 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F009 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F009 C Reactor Recirculation Excess Flow Check NIA Valve XV-143F009 D Reactor Recirculation Excess Flow Check N/A Valve XV-143F010 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F010 B Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F01 0 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F010 D Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F01 1 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F011 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F011 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F011 D Reactor Recirculation Excess Flow Check N/A Valve XV-143F012A Reactor Recirculation Excess Flow Check N/A Valve XV-143F012 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F012 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F012 D Reactor Recirculation Excess Flow Check N/A Valve XV-143FO17 A Recirculation Pump Seal Water Excess Flow Check N/A Valve XV-143F017 B Recirculation Pump Seat Water Excess Flow Check N/A Valve
)(V-1 43F040 A Reactor Recirculation Excess Flow Check N/A Valve SUSQUEHANNA - UNIT I TS / B 3.6-37 Revision 0
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 9 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Plant System Valve Number Valve Description Type of Valve (Maximumstion (Maximum Isolation Time (Seconds))
Reactor XV-143F040 B Reactor Recirculation Excess Flow Check N/A Recirculation Valve (continued) XV-143F040 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F040 D Reactor Recirculation Excess Flow Check N/A Valve XV-143F057 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F057 B Reactor Recirculation Excess Flow Check N/A Valve HV-143F019 Reactor Coolant Sample Automatic Valve 2.b (9)
HV-143F020 Reactor Coolant Sample Automatic Valve 2.b (2)
Residual Heat HV-151 F004 A (b)(c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-151F004 B (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-151 F004 C (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-151 F004 D (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-151 F007 A (b)(c) RHR-Minimum Recirculation Flow Power Operated N/A HV-151 F007 B (b)(c) RHR-Minimum Recirculation Flow Power Operated N/A HV-151 F008 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)
HV-151 F009 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)
HV-151 F011 A (b)(d) RHR-Suppression Pool Manual N/A Cooling/Spray HV-151 F011 B (b)(d) RHR-Suppression Pool Manual N/A Cooling/Spray HV-151 FO15 A (f) RHR - Shutdown Cooling Power Operated N/A Retum/LPCI Injection HV-151 F015 B (f) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection HV-151F016 A (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)
HV-151F016 B (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)
HV-151 F022 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (30)
HV-151 F023 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (20)
HV-151 F028 A (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)
Cooling/Spray HV-151 F028 B (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)
Cooling/Spray HV-151 F050 A (g) RHR - Shutdown Cooling Air Operated. Check N/A Return/LPCI Injection Valve Valve HV-151F050 B (g) RHR - Shutdown Cooling Air Operated Check N/A RetumrLPCI Injection Valve Valve HV-151 F103 A (b) RHR Heat Exchanger Vent Power Operated N/A HV-151 F103 B (b) RHR Heat Exchanger Vent Power Operated N/A SUSQUEHANNA - UNIT 1 TS / B 3.6-38 Revision 3
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)
Primary Containment Isolation Valve (Page 10 of 11)
Isolation Signal LCO 3.3.6.1 Function No.
Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))
Residual Heat HV-151 F122 A (g) RHR - Shutdown Cooling Power Operated N/A Removal Return/LPCI Injection Valve (Air)
(continued) HV-151 F122 B (g) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection Valve (Air)
PSV-1 5106 A (b)(d) RHR - Relief Valve Discharge Relief Valve N/A PSV-15106 B (b)(d) RHR - Relief Valve Discharge Relief Valve N/A PSV-1 51 F126 (d) RHR - Shutdown Cooling Suction Relief Valve N/A
/V-15109 A RHR Excess Flow Check N/A Valve XV-1 5109 B RHR Excess Flow Check N/A Valve XV-1 5109 C RHR Excess Flow Check N/A Valve XV-1 5109 D RHR Excess Flow Check N/A Valve RWCU HV-144F001 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5f, 5.g (30)
HV-144F004 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.e, 5.f, 5.g (30)
XV-14411 A RWCU Excess Flow Check N/A Valve XV-14411 B RWCU Excess Flow Check N/A Valve XV-14411 C RWCU Excess Flow Check N/A Valve AV-14411 D RWCU Excess Flow Check N/A Valve XV-144F046 RWCU Excess Flow Check N/A Valve HV-14182 A RWCU Return Isolation Valve Power Operated N/A HV-14182 B RWCU Return Isolation Valve Power Operated N/A SLCS 148F007 (a)(d) SLCS Manual Check N/A HV-148F006 (a) SLCS Power Operated N/A Check Valve TIP System C51-J004 A (Shear TIP Shear Valves Squib Valves N/A Valve)
C51-J004 B (Shear TIP Shear Valves Squib Valves N/A Valve)
C51-J004 C (Shear TIP Shear Valves Squib Valves N/A Valve)
C51-J004 D (Shear TIP Shear Valves Squib Valves N/A Valve)
C51-J004 E (Shear TIP Shear Valves Squib Valves N/A Valve) I I SUSQUEHANNA- UNIT 1 TS / B 3.6-39 Revision 2
PPL Rev. 7 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 11 of 11)
Isolation Signal LCO 3.3.6.1 3..1 Function FuIstion No.
Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))
TIP System C51-J004 A (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)
(continued) Valve)
C51-J004 B (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)
Valve)
C51-J004 C (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)
Valve)
C51-J004 D (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5y Valve) I C51 -J004 E (Ball IP Ball Valves Automatic Valve 7.a, 7.b (5)
Valve)
(a) Isolation barrier remains water filled or a water seal remains in the line post-LOCA, isolation valve is tested with water. Isolation valve leakage is not included in 0.60 La total Type B and C tests.
(b) Redundant isolation boundary for this valve is provided by the closed system whose integrity is verified by the Leakage Rate Test Program. This footnote does not apply to valve 155F046 (HPCI) when the associated PCIV, HV1 55F01 2 is closed and deactivated. Similarly, this footnote does not apply to valve 149F021 (RCIC) when it's associated PCIV, FV149F019 is closed and deactivated.
(c) Containment Isolation Valves are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water level in the Suppression Chamber. Refer to the IST Program.
(d) LCO 3.3.3.1, "PAM Instrumentation," Table 3.3.3.1-1, Function 6, does not apply since these are relief valves, check valves, manual valves or deactivated and closed.
(e) The containment isolation barriers for the penetration associated with this valve consists of two PCIVs and a closed system. The closed system provides a redundant isolation boundary for both PCIVs, and its integrity is required to be verified by the Leakage Rate Test Program.
(f) Redundant isolation boundary for this valve is provided by the closed system whose integrity is verified by the Leakage Rate Test Program.
(g) These valves are not required to be 10 CFR 50, Appendix J tested since the HV-151 F015A(B) valves and a closed system form the 10 CFR 50, Appendix J boundary. These valves form a high/low pressure interface and are pressure tested in accordance with the pressure test program.
SUSQUEHANNA - UNIT 1 TS / B 3.6-40 Revision 6
PPL Rev. 7 Secondary Containment B 3.6.4.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 Secondary Containment BASES BACKGROUND The secondary containment structure completely encloses the primary containment structure such that a dual-containment design is utilized to limit the spread of radioactivity to the environment to within limits. The function of the secondary containment is to contain, dilute, and hold up fission products that may leak from primary containment into secondary containment following a Design Basis Accident (DBA). In conjunction with I
operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the secondary containment, the secondary containment is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment (Ref. 1).
The secondary containment is a structure that completely encloses the primary containment and reactor coolant pressure boundary components.
This structure forms a control volume that serves to hold up and dilute the fission products. It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump and motor heat load additions).
The secondary containment boundary consists of the reactor building structure and associated removable walls and panels, hatches, doors, dampers, sealed penetrations and valves. The secondary containment is divided into Zone I, Zone II and Zone III, each of which must be OPERABLE depending on plant status and the alignment of the secondary containment boundary. Specifically, the Unit 1 secondary containment boundary can be modified to, exclude Zone II. Similarly, the Unit 2 secondary containment boundary can be modified to exclude Zone I. Secondary containment may consist of only Zone III when in MODE 4 or 5 during CORE ALTERATIONS, or during handling of irradiated fuel within the Zone III secondary containment boundary.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-84 Revision 3
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES BACKGROUND To prevent ground level exfiltration while allowing the secondary (continued) containment to be designed as a conventional structure, the secondary containment requires support systems to maintain the control volume pressure at less than the external pressure. Requirements for the safety related systems are specified separately in LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System." When one or more zones are excluded from secondary containment, the specific requirements for support systems will also change (e.g., required secondary containment isolation valves).
APPLICABLE There are two principal accidents for which credit is taken for secondary SAFETY containment OPERABILITY. These are a loss of coolant accident (LOCA)
ANALYSES (Ref. 2) and a fuel handling accident inside secondary containment (Ref. 3). The secondary containment performs no active function in response to either of these limiting events; however, its leak tightness is required to ensure that the release of radioactive materials from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis and that fission products entrapped within the secondary containment structure will be treated by the SGT System prior to discharge to the environment.
Secondary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).
LCO An OPERABLE secondary containment provides a control volume into which fission products that bypass or leak from primary containment, or are released from the reactor coolant pressure boundary components located in secondary containment, can be diluted and processed prior to release to the environment. For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum can be established and maintained. The leak tightness of secondary containment must also ensure that the release of radioactive materials to the environment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis. For example, secondary containment bypass leakage must be restricted to the leakage rate required by LCO 3.6.1.3. The secondary containment boundary required to be OPERABLE is dependent on the operating status of both units, as well as the configuration of walls, doors, hatches, SCIVs, and available flow paths to the SGT System.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-85 Revision 2
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES (continued)
APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, secondary containment OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.
In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES.
Therefore, maintaining secondary containment OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment.
ACTIONS A. 1 If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring during periods where secondary containment is inoperable is minimal.
A temporary (one-time) Completion Time is connected to the Completion Time Requirements above (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) with an "OR" connector. The Temporary Completion Time is 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> and applies to the replacement of the Reactor Building Recirculating Fan Damper Motors. The Temporary Completion Time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> may only be used once, and expires on December 31, 2005.
B.1 and B.2 If secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-86 Revision 4
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES ACTIONS C.1, C.2, and C.3 (continued)
Movement of irradiated fuel assemblies in the secondary containment, CORE ALTERATIONS, and OPDRVs can be postulated to cause fission product release to the secondary containment. In such cases, the secondary containment is the only barrier to release of fission products to the environment. CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended if the secondary containment is inoperable.
Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release.
Actions must continue until OPDRVs are suspended.
Required Action C.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.
SURVEILLANCE SR 3.6.4.1.1 REQUIREMENTS This SR ensures that the secondary containment boundary is sufficiently leak tight to preclude exfiltration under expected wind conditions. Expected wind conditions are defined as sustained wind speeds of less than or equal to 16 mph at the 60m meteorological tower or less than or equal to 11 mph at the 10m meteorological tower if the 60m tower wind speed is not available. Changes in indicated reactor building differential pressure observed during periods of short-term wind speed gusts above these sustained speeds do not by themselves impact secondary containment integrity. However, if secondary containment integrity is known to be compromised, the LCO must be entered regardless of wind speed.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-87 Revision 2
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.1 (continued)
REQUIREMENTS The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency of this SR was developed based on operating experience related to secondary containment vacuum variations during the applicable MODES and the low probability of a DBA occurring between surveillances.
Furthermore, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal secondary containment vacuum condition.
SR 3.6.4.1.2 and SR 3.6.4.1.3 Verifying that secondary containment equipment hatches, removable walls and one access door in each access opening required to be closed are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur.
Verifying that all such openings are closed also provides adequate assurance that exfiltration from the secondary containment will not occur.
In this application, the term "sealed" has no connotation of leak tightness.
An access opening typically contains one inner and one outer door.
Maintaining secondary containment OPERABILITY requires verifying one door in each access opening to secondary containment zones is closed.
In some cases (e.g., railroad bay), secondary containment access openings are shared such that a secondary containment barrier may have multiple inner or multiple outer doors. The intent is to maintain the secondary containment barrier intact, which is achieved by maintaining the inner or outer portion of the barrier closed at all times. However, all secondary containment access doors are normally kept closed, except when the access opening is being used for entry and exit or when maintenance is being performed on an access opening.
When the railroad bay door (No. 101) is closed; all Zone I and III hatches, removable walls, dampers, and one door in each access opening connected to the railroad access bay are closed; or, only Zone I removable walls and/or doors are open to the railroad access shaft; or, only Zone III hatches and/or dampers are open to the railroad access shaft. When the railroad bay door (No. 101) is open; all Zone I and Ill hatches, removable walls, dampers, and one door in each access opening connected to the railroad access bay are closed. The truck bay hatch is closed and the truck bay door (No. 102) is closed unless Zone II is isolated from Zones I and Ill.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-88 Revision 2
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.2 and SR 3.6.4.1.3 (continued)
REQUIREMENTS When an access opening between required secondary containment zones is being used for exit and entry, then at least one door (where two doors are provided) must remain closed. The access openings between secondary containment zones which are not provided with two doors are administratively controlled to maintain secondary containment integrity during exit and entry. This Surveillance is modified by a Note that allows access openings with a single door (i.e., no airlock) within the secondary containment boundary (i.e., between required secondary containment zones) to be opened for entry and exit. Opening of an access door for entry and exit allows sufficient administrative control by individual personnel making the entries and exits to assure the secondary containment function is not degraded. When one of the zones is not a zone required for secondary containment OPERABILITY, the Note allowance would not apply.
The 31 day Frequency for these SRs has been shown to be adequate, based on operating experience, and is considered adequate in view of the other indications of door and hatch status that are available to the operator.
(continued)
SUSQUEHANNA - UNIT I TS / B 3.6-88a Revision 2
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.4 and SR 3.6.4.1.5 REQUIREMENTS (continued) The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. To ensure that all fission products are treated, SR 3.6.4.1.4 verifies that the SGT System will rapidly establish and maintain a pressure in the secondary containment that is less than the pressure external to the secondary containment boundary. This is confirmed by demonstrating that one SGT subsystem will draw down the secondary containment to > 0.25 inches of vacuum water gauge in less than or equal to the maximum time allowed. This cannot be accomplished if the secondary containment boundary is not intact. SR 3.6.4.1.5 demonstrates that one SGT subsystem can maintain
>_ 0.25 inches of vacuum water gauge for at least 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at less than or equal to the maximum flow rate permitted for the secondary containment configuration that is operable. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> test period allows secondary containment to be in thermal equilibrium at steady state conditions. As noted, both SR 3.6.4.1.4 and SR 3.6.4.1.5 acceptance limits are dependent upon the secondary containment configuration when testing is being performed. The acceptance criteria for the SRs based on secondary containment configuration is defined as follows:
SECONDARY MAXIMUM DRAWDOWN TIME(SEC) MAXIMUM FLOW RATE (CFM)
CONTAINMENT (SR 3.6.4.1.4 (SR 3.6.4.1.5 TEST CONFIGURATION ACCEPTANCE CRITERIA) ACCEPTANCE CRITERIA>
Zones 1,11and II1. < 300 Seconds < 4000 CFM (Zones I, II, and I11) (From Zones I, II, and III)
Zones I and Il1. < 300 Seconds < 2885 CFM (Zones I and III) (From Zones I and III)
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.6-89 Revision 4
PPL Rev. 7 Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.4 and SR 3.6.4.1.5 (continued)
REQUIREMENTS Only one of the above listed configurations needs to be tested to confirm secondary containment OPERABILITY.
A Note also modifies the Frequency for each SR. This Note identifies that each configuration is to be tested every 60 months. Testing each configuration every 60 months assures that the most limiting configuration is tested every 60 months. The 60 month Frequency is acceptable because operating experience has shown that these components usually pass the Surveillance and all active components are tested more frequently. Therefore, these tests are used to ensure secondary containment boundary integrity.
Since these SRs are secondary containment tests, they need not be performed with each SGT subsystem. The SGT subsystems are tested on a STAGGERED TEST BASIS, however, to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform SR 3.6.4.1.4 and SR 3.6.4.1.5. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES 1. FSAR, Section 6.2.3.
- 2. FSAR, Section 15.6.
- 3. FSAR, Section 15.7.4.
- 4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.6-90 Revision 2
PPL Rev. 1 Main Condenser Offgas B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Main Condenser Offgas BASES BACKGROUND During unit operation, steam from the low pressure turbine is exhausted directly into the condenser. Air and noncondensible gases are collected in the condenser, then exhausted through the steam jet air ejectors (SJAEs) to the Main Condenser Offgas System. The offgas from the main condenser normally includes radioactive gases.
The Main Condenser Offgas System has been incorporated into the unit design to reduce the gaseous radwaste emission. This system uses a catalytic recombiner to recombine radiolytically dissociated hydrogen and oxygen. The gaseous mixture is cooled by the offgas condenser; the water and condensibles are stripped out by the offgas condenser and moisture separator. The radioactivity of the remaining gaseous mixture (i.e., the offgas recombiner effluent) is monitored downstream of the moisture separator prior to entering the holdup line.
APPLICABLE The main condenser offgas radioactivity rate is an initial condition of the SAFETY Main Condenser Offgas System failure event, discussed in the FSAR, ANALYSES Section 15.7.1 (Ref. 1). The analysis assumes a gross failure in the Main Condenser Offgas System that results in the rupture of the Main Condenser Offgas System pressure boundary. The radioactivity rate of the specified noble gases (Xe-133, Xe-135, Xe-138, Kr-85m, Kr-87, and Kr-88) is controlled to ensure that, during the event, the calculated offsite doses will be well within regulatory limits-or the NRC staff approved licensing basis.
The main condenser offgas limits satisfy Criterion 2 of the NRC Policy Statement. (Ref. 3)
LCO To ensure compliance with the assumptions of the Main Condenser Offgas System failure event (Ref.1), the fission product release rate should be consistent with a specified noble gas release to the reactor coolant of (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-24 Revision 1
PPL Rev. 1 Main Condenser Offgas B 3.7.5 BASES LCO 100 p.Ci/MWt-second. The LCO is established consistent with this (continued) requirement (3293 MWt x 100 p.Ci/MWt-second =330 mCi/second), and is based on the original licensed rated thermal power.
APPLICABILITY The LCO is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being processed via the Main Condenser Offgas System. This occurs during MODE 1, and during MODES 2 and 3 with any main steam line not isolated. In MODES 4 and 5, steam is not being exhausted to the main condenser and the requirements are not applicable.
ACTIONS A._1 If the offgas radioactivity rate limit is exceeded, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is allowed to restore the radioactivity rate to within the limit. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is reasonable, based on engineering judgment, the time required to complete the Required Action, the large margins associated with permissible dose and exposure limits, and the low probability of a Main Condenser Offgas System rupture.
B.1, B.2.1, and B.2.2 If the radioactivity rate is not restored to within the limits in the associated Completion Time, all main steam lines must be isolated. This isolates the Main Condenser Offgas System from the source of the radioactive steam.
The main steam lines are considered isolated if at least one main steam isolation valve in each main steam line is closed, and at least one main steam line drain valve is closed. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is reasonable, based on operating experience, to perform the actions from full power conditions in an orderly manner and without challenging unit systems.
An alternative to Required Action B.1 is to place the unit in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-25 Revision 0
PPL Rev. 1 Main Condenser Offgas B 3.7.5 BASES ACTIONS B.1, B.2.1, and B.2.2 (continued)
Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SURVEILLANCE SR 3.7.5.1 REQUIREMENTS This SR, on a 31 day Frequency, requires that the radioactivity rate be determined, which is an isotopic analysis of an offgas sample to ensure that the required limits are satisfied. The specified noble gases to be sampled are Xe-133, Xe-135, Xe-138, Kr-85m, Kr-87, and Kr-88. If the nominal steady state fission gas release as indicated by the condenser offgas pretreatment radioactivity monitor increases significantly (by > 50%
after correcting for expected increases due to changes in THERMAL P OWER), an isotopic analysis is also performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the increase is noted, to ensure that the increase is not indicative of a sustained increase in the radioactivity rate. The 31 day Frequency is adequate in view of other instrumentation that continuously monitor the offgas, and is acceptable, based on operating experience.
This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated. During this period it is improbable that radioactive gases will be in the main condenser offgas system at significant rates and any potential problem will be detected by the condenser offgas pretreatment radioactivity monitor.
REFERENCES 1. FSAR, Section 15.7.1.
- 2. 10 CFR 100.
- 3. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.7-26 Revision 0
PPL Rev. 1 Spent Fuel Storage Pool Water Level B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Spent Fuel Storage Pool Water Level BASES BACKGROUND The minimum water level in the spent fuel storage pool meets the assumptions of iodine decontamination factors following a fuel handling accident.
A general description of the spent fuel storage pool design is found in the FSAR, Section 9.1 (Ref. 1). The assumptions of the fuel handling accident are found in the FSAR, Section 15.7.4 (Ref. 2).
APPLICABLE The water level above the irradiated fuel assemblies is an explicit SAFETY assumption of the fuel handling accident. A fuel handling accident is ANALYSES evaluated to ensure that the radiological consequences (calculated doses at the exclusion area and low population zone boundaries) are within the regulatory limits of 10 CFR 50.67 (Ref. 4). A fuel handling accident could release a fraction of the fission product inventory by breaching the fuel rod cladding as discussed in the Regulatory Guide 1.183 (Ref. 5).
The fuel handling accident is evaluated for the dropping of an irradiated fuel assembly onto the reactor core. With an assumed minimum water level of 21 ft and a minimum decay time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to fuel handling, the analysis and test programs demonstrate that the iodine release due to a postulated fuel handling accident is adequately captured by the water and that offsite and control room doses are maintained within allowable limits (Ref. 2). The consequences of a fuel handling accident over the spent fuel storage pool are no more severe than those of the fuel handling accident over the reactor core, as discussed in the FSAR, Section 15.7.4 (Ref. 2). The water level in the spent fuel storage pool provides for absorption of water soluble fission product gases and transport delays of soluble and insoluble gases that must pass through the water before being released to the secondary containment atmosphere. This absorption and transport delay reduces the potential radioactivity of the release during a fuel handling accident.
The spent fuel storage pool water level satisfies Criteria 2 and 3 of the NRC Policy Statement (Ref. 6).
(continued)
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PPL Rev. 1 Spent Fuel Storage Pool Water Level B 3.7.7 BASES (continued)
LCO The specified water level preserves the assumptions of the fuel handling accident analysis (Ref. 2). As such, it is the minimum required for fuel movement within the spent fuel storage pool.
APPLICABILITY This LCO applies during movement of irradiated fuel assemblies in the spent fuel storage pool since the potential for a release of fission products exists.
ACTIONS A..1 Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not a sufficient reason to require a reactor shutdown.
When the initial conditions for an accident cannot be met, action must be taken to preclude the accident from occurring. If the spent fuel storage pool level is less than required, the movement of irradiated fuel assemblies in the spent fuel storage pool is suspended immediately.
Suspension of this activity shall not preclude completion of movement of an irradiated fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring.
SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR verifies that sufficient water is available in the event of a fuel handling accident. The water level in the spent fuel storage pool must be checked periodically. The 7 day Frequency is acceptable, based on operating experience, considering that the water volume in the pool is normally stable, and all water level changes are controlled by unit procedures.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-32 Revision 0
PPL Rev. 1 Spent Fuel Storage Pool Water Level B 3.7.7 BASES (continued)
REFERENCES 1. FSAR, Section 9.1.
- 2. FSAR, Section 15.7.4.
- 3. Deleted.
- 4. 10 CFR 50.67.
- 5. Regulatory Guide 1.183, July 2000.
- 6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.7-33 Revision I
PPL Rev. 1 RPV Water Level B 3.9.6 B3.9 REFUELING OPERATIONS B 3.9.6 Reactor Pressure Vessel (RPV) Water Level BASES BACKGROUND The movement of fuel assemblies or handling of control rods within the RPV requires a minimum water level of 22 ft above the top of the RPV flange. During refueling, this maintains a sufficient water level in the reactor vessel cavity and spent fuel pool. Sufficient water is necessary to retain iodine fission product activity in the water in the event of a fuel handling accident (Refs. 1 and 2). Sufficient iodine activity would be retained to limit offsite doses from the accident to *25% of 10 CFR 50.67 limits, as provided by the guidance of Reference 1. I APPLICABLE During movement of fuel assemblies or handling of control rods, the water SAFETY ANALYSES level in the RPV is an initial condition design parameter in the analysis of a fuel handling accident in containment postulated by Regulatory Guide 1.183 (Ref. 1). A decontamination factor of 138 is used in the accident analysis for iodine. This relates to the assumption that 99% of the total iodine released from the pellet to cladding gap of all the dropped fuel assembly rods is retained by the water. The fuel pellet to cladding gap is assumed to contain 8% of the total fuel rod 1-131 inventory and 5%
of the total fuel rod 1-132,1-133,1-134, and 1-135 inventory (Ref. 1).
Analysis of the fuel handling accident inside containment is described in Reference 2. With an assumed minimum water level of 21 ft and a minimum decay time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to fuel handling, the analysis and test programs demonstrate that the iodine release due to a postulated fuel handling accident is adequately captured by the water and that offsite and control room doses are maintained within allowable limits (Ref. 2).
While the worst case assumptions include the dropping of the irradiated fuel assembly being handled onto the reactor core, the possibility exists of the dropped assembly striking the RPV flange and releasing fission products. Therefore, the minimum depth for water coverage to ensure (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.9-19 Revision 1
PPL Rev. 1 RPV Water Level B 3.9.6 BASES APPLICABLE acceptable radiological consequences is specified from the RPV flange.
SAFETY ANALYSES Since the worst case event results in failed fuel assemblies seated in the (continued) core, as well as the dropped assembly, dropping an assembly on the RPV flange will result in reduced releases of fission gases.
RPV water level satisfies Criterion 2 of the NRC Policy Statement (Ref. 5).
LCO A minimum water level of 22 ft above the top of the RPV flange is required to ensure that the radiological consequences of a postulated fuel handling accident are within acceptable limits, as provided by the guidance of Reference 1.
APPLICABILITY LCO 3.9.6 is applicable when moving fuel assemblies or handling control rods (i.e., movement with other than the normal control rod drive) within the RPV. The LCO minimizes the possibility of a fuel handling accident in containment that is beyond the assumptions of the safety analysis.
Requirements for fuel handling accidents in the spent fuel storage pool are covered by LCO 3.7.7, "Spent Fuel Storage Pool Water Level."
ACTIONS A.1 If the water level is < 22 ft above the top of the RPV flange, all operations involving movement of fuel assemblies and handling control rods within the RPV shall be suspended immediately-to ensure that a fuel handling accident cannot occur. The suspension of fuel movement and handling control rods shall not preclude completion of movement of a component to a safe position.
SURVEILLANCE REQUIREMENTS Verification of a minimum water level of 22 ft above the top of the RPV flange ensures that the design basis for the (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.9-20 Revision 1
PPL Rev. 1 RPV Water Level B 3.9.6 BASES SURVEILLANCE REQUIREMENTS SR 3.9.6.1 (continued) postulated fuel handling accident analysis during refueling operations is met Water at the required level limits the consequences of damaged fuel rods, which are postulated to result from a fuel handling accident in containment (Ref. 2).
The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls on valve positions, which make significant unplanned level changes unlikely.
REFERENCES 1. Regulatory Guide 1.183, July 2000. I
- 2. FSAR, Section 15.7.4.
- 3. Deleted. I I
- 4. 10 CFR 50.67.
- 5. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA- UNIT 1 TS / B 3.9-21 Revision 1