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Technical Specification Bases Unit 1 Manual Changes
	ML061210062
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Site:	Susquehanna
Issue date:	04/19/2006
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TO: GERLACH*ROSE M 04/19/2006 LOCATION: USNRC FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)

THE FOLLOWING CHANGES HAVE OCCURRED TO THE HARDCOPY OR ELECTRONIC MANUAL ASSIGNED TO YOU. HARDCOPY USERS MUST ENSURE THE DOCUMENTS PROVIDED MATCH THE INFORMATION ON THIS TRANSMITTAL. WHEN REPLACING THIS MATERIAL IN YOUR HARDCOPY MANUAL, ENSURE THE UPDATE DOCUMENT ID IS THE SAME DOCUMENT ID YOU'RE REMOVING FROM YOUR MANUAL. TOOLS FROM THE HUMAN PERFORMANCE TOOL BAG SHOULD BE UTILIZED TO ELIMINATE THE CHANCE OF ERRORS.

ATTENTION: 'REPLACE" directions do not affect the Table of Contents, Therefore no TOC will be issued with the updated material.

TSB1 - TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL REMOVE MANJUAL TABLE OF CONTENTS DATE: 04/12/2006 ADD MANUAL TABLE OF CONTENTS DATE: 04/18/2006 CATEGORY: DOCUMENTS TYPE: TSB1 0

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SSES MANUAL T Manual Name: TSBt-Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL Table Of Contents Issue Date: 04/18/2006 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 71 04/18/2006

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 9 04/18/2006

Title:

TABLE OF CONTENTS 9' TEXT 2.1.1 2 04/18/2006 "I . :

X -. a

Title:

SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 0 11/15/2002

Title:

SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEMI,(RCS) PRESSURE SL TEXT 3.0 1 04/18/2005,-

Title:

LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY TEXT 3.1.1 4.1 '04/18/2006

Title:

REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN (SDM) 46 '

TEXT 3.1.2 le" I , 0 11/15/2002

Title:

REACTIVITY CONTROL SYSTEMS REACTIVITY ANOMALIES TEXT 3.1.3 (

I - .,

I 07/06/2005

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD OPERABILITY TEXT 3.1.4 2 04/18/2006

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: 04/18/06 Page 11 Page of of 88 Report Date: 04/18/06

SSES MANUAL ,/

Manual Name: TS-BS-Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.1.7 1 08/30/2005

Title:

REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 1 10/19/2005

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 0 11/15/2002

Title:

POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE (LHGR)

TEXT 3.2.4 2 04/12/2006

Title:

POWER DISTRIBUTION LIMITS AVERAGE POWER RANGE MONITOR (APRM) GAIN AND SETPOINTS L 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 3 04/12/2006

Title:

INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 1 04/18/2005

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM I-Page 2 of 8 Report Date: 04/18/06

SSES MANUAL

Manual Name: TSB+/--

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 (AIWS-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 1 11/09/2004

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.6.2 1 11/09/2004 Ji

Title:

INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 0 11/15/2002

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 TEXT 3.4.3 1 01/16/2006

Title:

REACTOR COOLANT SYSTEM (RCS) SAFETY/RELIEF VALVES (S/RVS)

Report Date: 04/18/06 Page33 Page of 88 Report Date: 04/18/06

SSES MANUAL I Manual Name: TSBl-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 1 04/18/2005

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

Title:

REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM '

- COLD SHUTDOWN TEXT 3.4.10 0 11/15/2002

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 0 11/15/2002

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT Report Date: 04/18/06 Page44 Page of of 88 Report Date: 04/18/06

. SSES MANUAL

Manual Name: TSB+/--

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 3 12/08/2005

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

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

"'EXT 3.6.2.1 0 11/15/2002 go bTitle: 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 1 04/18/2005

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

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION Report Date: 04/18/06 PageS5 Page of of 88 Report Date: 04/18/06

SSES MANUAL rP Manual Name: TSBt-Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL K>

TEXT 3.6.4.1 5 03/16/2006

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 3 10/24/2005

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 ULTIMATE 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 0 11/15/2002

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 0 11/15/2002

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: 04/18/06 Page66 Page of of 88 Report Date: 04/18/06

SSES MANUAL i Manual Name: TSBo 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 0 11/15/2002

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 0 11/15/2002

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN TEXT 3.8.6 0 11/15/2002

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 il,l;)

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 0 11/15/2002

Title:

REFUELING COPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 0 11/15/2002

Title:

REFUELING C)PERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 0 11/15/2002

Title:

REFUELING C)PERATIONS CONTROL ROD POSITION TEXT 3.9.4 0 11/15/2002

Title:

REFUELING C)PERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0 11/15/2002

Title:

REFUELING C)PERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 0 11/15/2002

Title:

REFUELING C)PERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL Report Date: 04/18/06 Page 7 Page7 of of 88 Report Date: 04/18/06

SSES MANUAL Manual Name: TSBt-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: 04/18/06 Page88 Paige of of 88 Report Date: 04/18/06

TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)

B2.0 SAFETY LIMITS (SLs) .................................................. B2.0-l B2.1.1 Reactor Core SLs .................................................. B2.0-il B2.1.2 Reactor Coolant System (RCS) Pressure SL ............ ..................... B2.0-7 B3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY .............. B3.0- i B3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ........ .............. TS/B3.0--10 B3.1 REACTIVITY CONTROL SYSTEMS .............................................. B3.1-1l B3.1.1 Shutdown Margin (SDM) ............ .................... ............. B3.1-l B3.1.2 Reactivity Anomalies ............................ . B3.1-:3 B3.1.3 Control Rod OPERABILITY ....................

s. B3.1-13 B3.1.4 Control Rod Scram Tim es ......... ............... ....... B3.1-:22 B3.1.5 Control Rod Scram Accumulators ... ;

"TS/B3.1-29 I B3.1.6 Rod Pattern Control ........................... TS/B3.1-34 B3.1.7 Standby Liquid Control (SLC) System B3.1-:39 B3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves. B3.1-47 B3.2 POWER DISTRIBUTION LIMITS ....i TSB3.2-l B3.2.1 Average Planar Linear Heat'Generation Rate (APLHGR) ........ TS/B3.2-l B3.2.2 Minimum Critical Power Ratio (MCPR) ..................................... TSIB3.2-5 B3.2.3 Linear Heat Generation Rate (LHGR) ....................................... TS/I3.2-10 B3.2.4 Average Power Range Monitor (APRM) Gain and Setpointst ...... B3.2-14

/ -,

B3.3 INSTRUMENTATION ................ .. TS/I3.3-1 B3.3.1 .1 Reactor Protection System (RPS) Instrumentation ................... TS/B3.3-1 B3.3.1 .d Source Range Monitor (SRM) Instrumentation ......................... TS/B3.3-:35 B3.3.2.1 Control'Rod Block Instrumentation ......................................... TS/B3.3-4 B3.3.2.9 Feedwater - Main Turbine High Water Level Trip

\ Instrumentation .8................................ B3.3-55 B3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ..................... TS/13.3434 B3.3.3. Remote Shutdown System .. .................................... B3.3-76 B3.3.4.1 1End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation ..................................... B3.3-81 B3.3.4.d Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation ....... TS/B3.3-92 I B3.3.5.1 Emergency Core Cooling System (ECCS)

Instrumentation ..................................... B3.3-1 01 B3.3.5.9 Reactor Core Isolation Cooling (RCIC) System Instrumentation ...................................... 3.3-135 B3.3.6.1 Primary Containment Isolation Instrumentation ...............................B3.3-147 B3.3.6.' Secondary Containment Isolation Instrumentation ........ TS/B3.3-180 B3.3.7.1 Control Room Emergency Outside Air Supply (CREOAS)

System Instrumentation ..... B3.3-192 i%,,w ,

(contirued)

SUSQUEHANNA - UNIT 1 TS / B TOC - 1 Revision 9

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 Monitoring ....................................... B3.3-213 B3.4- REACTOR COOLANT SYSTEM (RCS) ...................................... . B3.4-1 B3.4.1 Recirculation Loops Operating ....................................... B3.4-1 B3.4.2 Jet Pumps ........................... B3.4-10 6.........

B3.4.3 Safety/Relief Valves (S/RVs) ....................................... TS/B3.4-15 B3.4.4 jRCS 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................ 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 B3.4.1l1r 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 1 CONTAINMENT SYSTEMS .TS/B3.6-1 B3.6.1. Primary Containment ....................... ! TS/B3.6-1 B3.6.1.:7 Primary Containment Air Lock ........................ B3.6-7 B3.6.1.:3 Primary Containment Isolation Valves (PCIVs) ......................... TS/B3.6-15 B3.6.1.:5 Containment Pressure. B3.6-41 B3.6.1.13 Drywell Air Temperature .TS/B3.6-44 63.6.1.1. :Suppression Chamber-to-Drywell Vacuum Breakers ....... TS/B3.6-47 B3.6.2.1 Suppression Pool Average Temperature .............................. ;.u' B3.6-53 B3.6.2.2 Suppression Pool Water Level ........................ .;.-.'.i 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 'Primary Containment Hydrogen Recombiners .................. B3.6-70 6.............

B3.6.3.2 Drywell Air Flow System.................. B3.6-76 6...

B3.6.3.3 Primary Containment Oxygen Concentration ........................ B3.6-81 6.........

B3.6.4.1 Secondary Containment .. ' . [ TS/B3.6-.84 B3.6.4.f Secondary Containment Isolation Valves (SCIVs)....... TS/B3.6-91 Standby Gas Treatment (SGT) System... TS/B3.6-101 Ir I (contin ed)

!. I SUSQlJEHANNA -UNIT 1 TS/BTOC-2 Revision 9

II

i '

TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)

B3.7 PLANT SYSTEMS ............................................ TS/B3.7-'l B3.7.1 Residual Heat Removal Service Water (RHRSW) System and the Ultimate Heat Sink (UHS) ...................................... TS/B3.7-'

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-'i2 B3.7.4 Control Room Floor Cooling System ........................................ TS/B3.7-1 9 B3.7.5 Main Condenser Offgas ............... ............................. B3.7-24 B3.7.6 Main Turbine Bypass System ............................................ TS/B3.7-27 B3.7.7 Spent Fuel Storage Pool Water Level ............................................ B3.7-31 B3.8 ELECTRICAL POWER SYSTEM ............................................. TS/B3.8-l B3.8.1 AC Sources - Operating ......................... .................... TS/B3.8-l 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 ....................... B3.8-136 8.................

B3.9 REFUELING OPERATIONS .................................. ....... TS/B3.9- I B3.9.1 Refueling Equipment Interlocks ................................... TS/B3.9-l B3.9.2 Refuel Position One-Rod-Out Interlock ................ ................... B3.9-5 B3.9.3 Control Rod Position .8............ ; 3.9-9 B3.9.4 Control Rod Position Indication ...................... :33.9-12 8..........

B3.9.5 Control Rod OPERABILITY- Refueling .... ............................ 183.9-16 B3.9.6 Reactor Pressure Vessel (RPV) Water Level ............ 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 ....I..................... 83.9-26 B3.10 SPECIAL OPERATIONS ................. . TS/B3.10-1 83.10.1

Inservice Leak and Hydrostatic Testing Operation .............. ! TS/B3.10-1 B3.10.2' Reactor Mode Switch Interlock Testing .............. B3.10-6 8............

B3.10.31 Single Control Rod Withdrawal - Hot Shutdown).9 ............... B3.1C-11 8..........

B3.10.4 Single Control Rod Withdrawal - Cold Shutdowr........ ir...-. . .......... B3.10-16 B3.10.5 Single Control Rod Drive (CRD) Removal - Refu'eling ............. B3.10-21 B3.10:61 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 8.

i TSB1 TextjTOc UQ N - U SUSQLIEHANNA'-

1 UNIT 1 TS /BTOC- 3 Revision 9

SUSQIJEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section. Title Revision TOC Table of Contents 9 B 2.0 SAFETY LIMITS BASES Page B 2.0-1 0 Page TS / B 2.0-2 3 PageTS/B2.0-3 4 Pages TS/ B 2.0-4 and TS /B 2.0-5 3 PageTS/B2.0-6 .

Pages B 2.0-7 through B 2.0-9 0 B 3.0 LCO AND SR APPLICABILITY BASES Pages B 3.0-1 through 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 Pages TS / B 3.0-10 through 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 PageTS/B3.1-5 1 Pages TS / B 3.1-6 and TS /B3.1-7 2 Pages B 3.1-8 through B 3.1-13 . 0 PageTS/B3.1-14 1 Pages B 3.1-15 through B 3.1-22 0 PageTS/B3.1-23 1 Pages B 3.1-24 through B 3.1-27 0 Page TS / B 3.1-28 2 Page TS /B3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.3-34 through TrS / B 3.3-36 1 PagesTS/B3.1-37andTS/B3.1-38 2 Pages B 3.1-39 through B 3.1-44 0 iPageTS/B3.1-45 0 PFages B3.1-46and B3.1-47) 9 1 Pages TS /B3.1-48 and TS B3.1-49 f

Page B3.1-50 : I 0 Page TS / B 3.1-51 B 3.2 POWER DISTRIBUTION LIMITS BASES PageTS/B3.2-1 l I 1 Fages TS /B 3.2-2 through TS /83.2-6 2 SUQIEHNA UITITSBLES1Reison7 SUSQUEHANNA - UNIT 1 TS / B LOES-1 Revision 71

SUSQUIEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision 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 1 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 j 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/B3.3-6 1 PageTS/B3.3-7 3 PageTS/B3.3-7a 0 Pages TS / B 3.3-8 through TS I 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 i B 3.3-17 and TS / B 3.3-18 3 Pages TS B 3.3-19 1 Pages TS / B 3.3-20 through TS I B 3.3-22 2 Page TS / B 3.3-22a 0 PagesTS / 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/B3.3-27 1 Pages TS / B 3.3-28 through TS I B 3.3-30 3 Page TS / B 3.3-30a 0 Dage TS I B 3.3-31 3 Page TS /B3.3-32 5 Pages TS I B 3.3-32a and TS / B 3.3-32b 0 Page TS / B 3.3-33 5 Page TS I/B 3.3-33a 0 Page TS / B 3.3-34 1 Pages TS / B 3.3-35 and TS I B 3.3-36 2 Pages TS / B 3.3-37 through TS I B 3.3-43 1 Page TS / B 3.3-44 3 TS/BLOES-2 Revision 71 SUSQUEHANNA - UNIT SUSQlJEHANNA -

UNIT 1 1 TS /B LOES-2 Revision 71

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Pages TS / B 3.3-45 through TS I B 3.3-49 2 Page TS / B 3.3-50 3 Page TS / 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 Pages TS / B 3.3-68 and TS I B 3.3-69 4 Pages TS / B 3.3-70 and TS B 3.3-71 3 Pages TS / 3.3-72 through TS / 3.3-75 2 Page TS / B 3.3-75a 4 Page TS / B 3.3-75b 5 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 Page 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 I 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 PageTS/B3.3-117 1 Pages B 3.3-118 through B 3.3-122 ; 0 Pages TS / B 3.3-123 andTS/B 3.3-1241 I 1 Page TS / B 3.3-124a 0 Page B 3.3-125 I[I 0 Pages TS B 3.3-126 and TS B 3.3-1271 I 1 Pages B 3.3-128 through B 3.3-130 I 0 Page TS/B3.3-131 l 1 Pages B 3.3-132 through B 3.3-137 0 IUR SUSQIJEHANNA - UNIT 1 TS I B LOES-3 Revision 71

SUSQUEHAN4NA STEAM ELECTRIC STATION LIST OF1 EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page TS / B 3.3-138 1 Pages B 3.3-139 through B 3.3-149 0 Page TS I B 3.3-150 through TS / B 3.3-162 1 Page TS / B 3.3-163 2 Pages TS / B 3.3-164 through TS / B 3.3-177 1 Pages TS /B3.3-178 and TS /B3.3-179 2 Pages TS / B 3.3-179a and TS / B 3.3-179b 2 Page TS / B 3.3-179c 0 Page TS / B 3.3-180 1

'PageTS / B 3.3-181 2 Pages TS / B 3.3-182 through TS / 83.3-186 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 Pages B 3.3-192 through 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 Page TS /B3.4-3 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 /B3.4-28 and TS/ B3.4-29 1 Pages B 3.4-30 and B 3.4-31 0 Page TS / B 3.4-32 1 Pages B 3.4-33 through B 3.4-36 0 Page TS / B 3.4-37 1 PagesB 3.4-38 through B3.4-40 1 Page TS/ B 3.4-41 Pages B 3.4-42 through B 3.4-48 0 Page TS / B 3.4-49 2 Page TS/ B 3.4-50 2 I Page TS I B 3.4-51 2 Pages TS / B 3.4-52 and TS / B 3.4-53 1

'Pages TS / B 3.4-54 and TS / B 3.4-55 2 IPageTS/ B 3.4-56 1 PageTS/B3.4-57 2 Pages TS / B 3.4-58 through TS / B 3.4-60 SUSQUEHANNA - UNIT 1 TS / B LOES-4 Revision 71

SUSQIJEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIOJS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision 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/B3.5-5 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 Page TS / B 3.5-14 and TS B3.5-15 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 CONTAINMENTSYSTEMS BASES' Page TS / B 3.6-1 2 Page TS / B 3.6-1 a 3 Pages TS / B 3.6-2 through TS I B 3.6-5 2 PageTS/B3.6-6 r 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 Pages TS / B 3.6-15a and TS I B 3.6-15b [ 0 Page B 3.6-16 0 PageTS/B3.6-17 ,

Page TS / B 3.6-17a 0 Pages TS /83.6-18 and TS B3.6-19 0 PageTS/B3.6-20 1 iPage TS / B 3.6-21 2 PageTS/B3.6-22 . [ 1 Page TS/B3.6-22a 0 Page TS / B 3.6-23 1 Pages TS I B 3.6-24 through TS / 3.625 0

'PageTS/B3.6-26 I 1 PageTS B 3.6-27 ii,; 2 PageTS B3.6-28 J 5 Pages TS / B 3.6-29 and TS /B3.6-30 1 PageTS5B 3.6-31 3 SUSQUEHANNA - UNIT 1 TS B LOES 5 Revision 71

SUSQLIEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page B 3.6-32 0 Page TS / B 3.6-33 1 PagesB 3.6-34 and B 3.6-35 0 Page TS / B 3.6-36 1 Page.B 3.6-37 0 Page TS / B 3.6-38 1 Page B 3.6-39 0 Page TS / B 3.6-40 4 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/B3.6-46 2 Pages TS / B 3.6-47 through TS / B 3.6-51 1 Page.TS /B3.6-52 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 3.6-72 0 Page TS / B 3.6-73 1 Pages B 3.6-74 through 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 PagelTS / B 3.6-86 . 3 Page'TS / B 3.6-87 1 Pages TS / B 3.6-88 and TS /B 3.6-88a 2 Page TS / B 3.6-89 3 Page TS / B3.6-90 2 PageTS/B3.6-91 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 I 2' Pages TS I B 3.6-1 01 and TS / B 3.6-102 1 Pages TS/ B 3.6-103 and TS / B 3.6-104 2 PagejTS / B 3.6-105 3 Pages TS / B 3.6-106 and TS / B 3.6-107 2 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 PagesTS/B33.7-6b and TS/B3.7-6c 0 Page TS / B 3.7-7 2 Pages TS / B 3.7-8 through TS / B 3.7-11 1 Pages TS /B3.7-12 and TS /B3.7-13 2 Pages TS i B 3.7-14 through TS I B 3.7-18 2 SUSQUEHANNA - UNIT 1 TS / B LOES-6 Revision 71

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Tile Reisio Sectin k,.) Section Title Revision Page TS / B 3.7-18a Pages TS / B 3.7-19 through TS / B 3.7-23 Pages B 3.7-24 through B 3.7-26 Pages TS / B 3.7-27 through TS / B 3.7-29 Page TS / B 3.7-30 Pages B 3.7-31 through B 3.7-33 B 3.8 ELECTRICAL POWER SYSTEMS BASES Pages TS / B 3.8-1 through TS / B 3.8-3 PageTS/B3.8-4 Pages TS / B 3.8-4a and TS I B 3.8-4b tPage TS/B3.8-5 Page TS/B3.8-6 Pages TS / B 3.8-7 through TS/B 3.8-8 PageTS/B3.8-9 Page TS / B 3.8-10 Pages TS / B 3.8-11 and TS / B 3.8-17 PageTS/B3.8-18 Pages TS / B 3.8-19 through TS / B 3.8-21 Pages TS / B 3.8-22 and TS / B 3.8-23 Pages TS / B 3.8-24 through TS / B 3.8-37 Pages B 3.8-38 through B 3.8-53 Pages TS / B 3.8-54 through TS / B 3.8-61 Page TS / B 3.8-62 and TS / B 3.8-63 Page TS / B 3.8-64 Page TS / B 3.8-65 Pages B 3.8-66 through B 3.8-80 PageTS/B3.8-81 Pages B 3.8-82 through B 3.8-90 I

i B 3.9 iI REFUELING OPERATIONS BASES

i i Pages TS / B 3.9-1 and TS / B 3.9-1a I

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Pages TS / B 3.9-2 through TS / B 3.9-4 Pages B 3.9-5 through B 3.9-30 i

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i B 3.10 SPECIAL OPERATIONS BASES I 1: .:, PageTS/B3.10-1 I i j:

Pages B 3.10-2 through B 3.10-31 0 i i:I PageTS/B3.10-32 2 I

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TSB1 text WOES 416/06 I

E UNI I S/B OES- Re isi n 7 SHUAS QNA Revisim 71 SUSQUEHANNA - UNIT 1 TS / B LOES-7 i . .

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PPL Rev. 2 Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs)

B2.1.1 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. .1.2 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 detericration.

Therefore, the fuel cladding SL is defined with a margin to the conditions i2 F That would produce nset of transition boiling (iLe.; JMCPR-1.0.1hs

,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 B 2.0-1 Revision 0

PPL. Rev. 2

. Reactor Core SLs B 2.1.1 BASES BA(CKGROUND 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 normanl SAFETY ANALYSES operation and AOOs. 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 Cladding InteQritv 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 106 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)

0lwI _UQEAN - UNT_-/B.- evso SU',QUEHANNA - UNIT 1 TS / B 2.0 Revision 3

PPL Rev. 2 I Reactor Core SLs B 2.1.1 BASES I APF'LICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES For the SPC ATRIUM-10 design, the minimum bundle flowv is

> 28 x 103 lb/hr. For the ATRIUM-10 fuel design, the coclant minimum bundle flow and maximum area are such that the mass flux is always > .25 x 106 lb/hr-ft 2. Full scale critical power

i 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 1o6 lb/hr-ft2 is approximately 3.35 MWt. At 25% RTP, a bundle power of approximately 3.35 MWt corresponds to a bundle radial peaking factor cf 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.

I i 2.1.1.2 MCPR i

l i . The MCPR SL ensures sufficient conservatism in the operating MCPR limit that, in the event of an AOO from the limiting condition of I

I 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 w

I 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.

I

I , I I ,

A: The SPCB critical power correlation is based on a significant boc'y of I practical test Idata. As long as the core pressure and flow are within the

, I I ,,

range of validity of the correlations (refer to'Section B.2.1.1.1), the assumed reactor conditions used in defining the SL introduce

., ' 'I l !l conservatism into the limit because bounding high radial power factors I', 1 ll and bounding flat local peaking distributions are used to estimate the

i :

!i number of rods in boiling transition. !These conservatismrs and the t : ' !

inherent accuracy of the SPCB correlation provide a reasonable degree I of assurance that during sustained operation at the MCPR SL thare would be no transition boiling in the Icore.

(continued) e , so N TI:S B. -

kqdo SU Q E A N I SUS)QUEHANNA - UNIT 1 TS/ B 2.0-3 Revision 4

PPL. Rev. 2 Reactor CDre SLs B 2.1.1 BASSES 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

. Icould 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)

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SU%, QUEHANNA- UNIT 1 TS / B 2.0-4 Revision 3

PPL Rev. 2 Reactor Core SLs B 2.1.1 BASES k",).

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.

SAF-ETY LIMIT Exceeding an SL may cause fuel damage and create a potential for VIOLATIONS radioactive releases in excess of 10 CFR 100, "Reactor Site Crit:eria,"

limits (Ref. 3). Therefore, it is required to insert all insertable control rods and restore compliance with the SLs within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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.

REF:ERENCES 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. 10 CFR 100.

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 Valiatio Methodology ofCSO4McrbmB for Boiling Water Reactors: cober 99 and Evaluation Validation of CASMO-4/Mi 6roburn-12,;' October 1999.

(continued) tK- SUQEAN NTITSIB205Rvso SUSQUEHANNA - UNIT 1 TS / B2.0-5 Revision 3 i

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PPL Rev. 2

. Reactor Core SLs tACIRC B 2.1.1 MAsitU Of I

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ZSU:SQUEHANNA - UNIT 1 TS / B 2.0-6 Revision 1

PPL Rev. 1 SDM B 3.1.1 K-I B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1 SHUTDOWN MARGIN (SDM)

BAS'ES BACKGROUND SDM requirements are specified to ensure:

a. The reactor can be made subcritical from all operating conditions and transients and Design Basis Events;

b. The reactivity transients associated with postulated accident conditions are controllable within acceptable limits; and

c. The reactor will be maintained sufficiently subcritical to preclude f inadvertent criticality in the shutdown condition.

These requirements are satisfied by the control rods, as described in GDC 26 (Ref. 1), which can compensate for the reactivity effects of the fuel and water temperature changes experienced during all operating i

conditions.

I APPLICABLE The control rod drop accident (CRDA) analysis (Refs. 2 and 3) assumes SAFETY the core is subcritical with the highest worth control rod withdrawn.

ANALYSES Typically, the first control rod withdrawn has a very high reactivity worth and, should the core be critical during the withdrawal of the first control rod, the consequences of a CRDA could exceed the fuel damage limits for a CRDA (see Bases for LCO 3.1.6, "Rod Pattern Control"). Also, SDM is assumed as an initial condition for the control rod removal error during refueling and fuel assembly insertion'error during refueling accidents (Ref. 4)' The analysis of these reactivity insertion events assumes the refueling interlocks are OPERABLE when the reactor is in

.., the refueling mode of operation. These interlocks prevent the withdrawal of more than one control rod from' the core during refueling.

(Special consideration and requirements formultiple c6ntrol rod withdrawal during refueling are covered in Special Operations LCO 3.10.6, "Multiple Control Rod Withdrawal-Refueiing.") The analysis assumes'this condition is acceptable since the core will be (continued)

SUSDQUEHANNA - UNIT 1 B 3.1-1 Revision 0

PPL Rev. 1 SDM B 3.1.1 BASES APPLICABLE shut down with the highest worth control rod withdrawn, if adequate SDM SAFETY has been demonstrated.

ANALYSES (continued) Prevention or mitigation of reactivity insertion events is necessary lo limit energy deposition in the fuel to prevent significant fuel damage, which could result in undue release of radioactivity. Adequate SDM ensures inadvertent criticalities and potential CRDAs involving high worth control rods (namely the first control rod withdrawn) will not cause significant fuel damage.

- SDM satisfies Criterion 2 of the NRC Policy Statement (Ref. 5).

_i LCO) The specified SDM limit accounts for the uncertainty in the demonstration of SDM by testing. Separate SDM limits are provided for testing where the highest worth control rod is determined analytically or by i measurement. This is due to the reduced uncertainty in the SDM test when the highest worth control rod is determined by measurement. When SDM is demonstrated by calculations not associated with a test (e.g., to vi IL confirm SDM during the fuel loading sequence), additional margin is included to account for uncertainties in the calculation. To ensure adequate SDM during the design process, a design margin is included to account for' uncertainties in the design calculations (Ref. 6).

APPLICABILITY In MODES 1 and 2, SDM must be provided because subcriticality with the highest worth control rod withdrawn is assumed in the CRDA analysis (Ref. 2). In MODES 3 and 4, SDM is required to ensure the reactor will be held subcritical with margin for a single withdrawn control rod. SDM is required in MODE 5 to prevent an open' vessel, inadvertent criticality during the withdrawal of a single control r6d from a core cell containing one or more fuel assemblies or a fuel assembly insertion error (Re,. 4).

1, EI I (continued)

SUSQUEHANNA - UNIT 1 B 3.1-2 Revision 0 i

PPL. Rev. 1

'- . . SDM B 3.1.1 BASES (continued)

ACTIONS A.1 With SDM not within the limits of the LCO in MODE 1 or 2, SDM must be restored within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Failure to meet the specified SDM may be caused by a control rod that cannot be inserted. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is acceptable, considering that the reactor can still be shut down, assuming no failures of additional control rods to insert, and the low probability of an event occurring during this interval.

B.1 If the SDM cannot be restored, the plant must be brought to MODE 3 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , to prevent the potential for further reductions in available SDM (e.g., additional stuck control rods). The allowed Completion Time Df 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

, C.1 With SDM not within limits in MODE 3, the operator must immediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are fully inserted. This action results in the least reactive condition for the core.

D.1, D.2, D.3, and D.4 With SDM not within limits in MODE 4,' the operator must immediately initiate action to fully insert all insertable control rods. Action must continueluntil all insertable control rods are fully inserted. This action results in the least reactive condition for the core. Action must also be initiated within, i hour to provide means for control of potential radioactive releases. This includes ensuring secondary containment is OPERABLE; at least one Standby Gas Treatment (SGT) subsystem is OPERABLE; and secondary containment isolation capability (i.e., at least one secondary containment isolation valve and associated instumehtation aare OPERABLE, or other acceptable I

(continued)

SU'SQUEHANNA - UNIT 1 B 3.1-3 Revision 0

PPL Rev. 1 L- ; . SDM B 3.1.1 tI BASES ACTIONS D.1, D.2, D.3, and D.4 (continued) administrative controls to assure isolation capability) in each secondary containment penetration flow path not isolated and required to be isolated to mitigate radioactivity releases. This may be performed as an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the surveillances needed to demonstraie the OPERABILITY of the components. If, however, 'any required component is inoperable, then it must be restored to OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.

E.1. E.2, E.3, E.4. and E.5 With SDM not within limits in MODE 5, the operator must immediately

suspend CORE ALTERATIONS that could reduce SDM (e.g., insertion of fuel in the core or the withdrawal of control rods). Suspension of these activities shall not preclude inserting control rods or removing fuel from the core to reduce the total reactivity.

Action must also be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies have been fully iniserted. Control rods in care cells containing no fuel assemblies do not affect the reactivity of the core and therefore do not have to be' iserted.

I Action must also be initiated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to provide means for cortrol potential radioactive releases. IThis'i"c'udes ensuring secondary containment is OPERABLE; at least one SGT subsystem is OPERABLE; and secondary coritainment isolation capability (i.e., at least one secondary containment isolation valve and associated I ;l ' instrumentation are O1PERABLE, ~or other la cceptable administrative!

I -l controls to assure isolation capability) in each associated penetration Flow path not isolated that is

_' __'_'___i___(continued)

SUSQUEHANNA - UNIT 1 B 3.1-4 Revision 0

PPL Rev. 1

- . .SDM B 3.1.1 BASES ;

ACTIONS E.1, E.2, E.3, E.4, and E.5 (continued) assumed to be isolated to mitigate radioactivity releases. This may be performed as an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances as needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Action must continue until all required components are OPERABLE.

SURVEILLANCE REQUIREMENTS SDM must be verified to be within limits to ensure that the reactor can be made subcritical from any initial operating condition. Adequate SDM is demonstrated by testing before or during the first startup after fuel movement, control rod replacement, or shuffling within the reactor pressure vessel. Control rod replacement refers to the decoupling and removal of a control rod from a core location, and subsequent replacement with a new control rod or a control rod from another core location. Since core reactivity will vary during the cycle as a function of fuel depletion and poison burnup, the beginning of cycle (BOC) test must also account for changes in core reactivity during the cycle. Therefore, to obtain the SDM, the initial measured value must be increased by an adder, "R", which is the difference b6tween6the calculated value of I iI maximum core reactivity during the operating cycle and the calculated BOc core reactivity. If the value of 'R'l iszero (that is,-C is the roost reactive point in the cycle), no correction to the BOC measured value is required (Ref. 6). !For the SDM demonstrations that rely solely on

, calculation of the highest worth control rod, additional margin (0.10%Ho Ak/k)

I l must be added to the SDM limit of 0.28% Ak/k to account for uncertainties in the calculation.

iThe DM may be demonstrated during an in sequence control rod withdrawal, in which the highest worth control rod is analytically determined, or during local criticals, where (continued)

- U SUSQUEHANNA -UNITI1 TS / B3.1-5 Revision 1

PPL Rev. 1 SDM B 3.1.1 BASSES SURVEILLANCE SR 3.1.1.1 (continued)

REQUIREMENTS the highest worth control rod is determined by analysis or testing.

Local critical tests require the withdrawal of control rods in a sequence that is not in conformance with BPWS. This testing would therefore require re-programming or bypassing of the rod worth minimizer to allow the withdrawal of control rods not in conformance with BPWS, and therefore additional requirements must be met (see LCO 3.10.7, "Control Rod Testing - Operating").

The Frequency of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reaching criticality is allowed to provide a reasonable amount of time to perform the required calculations and have appropriate verification.

During MODE 5, adequate SDM is required to ensure that the reactor does not reach criticality during control rod withdrawals. An evaluation of each planned in-vessel fuel movement during fuel loading (including shuffling fuel within the core) is required to ensure adequate SDM i; maintained during refueling. This evaluation ensures that the intermediate loading patterns are bounded by the safety analyses for the final core loading pattern. For example, bounding analyses that demonstrate adequate SDM for the most reactive configurations during the refueling may be performed to demonstrate acceptability of the entire fuel movement sequence. These bounding analyses include additional margins to the associated uncertainties. Spiral offload/reload sequences inherently satisfy the SR, provided the fuel assemblies are reloaded in the same configuration analyzed for the new cycle. Removing fuel from the core will always result in an increase in SDM.

I REI: 'ERENCES 1. 0 CFR 50, Appendix A, GDC 26.

2.: FSAR, Section 15.

3.: XN-NF-80-19(P)(A) Volume A and Supplements I and 2, "Exxon Nuclear Methodology for Boiling Water Reactors," Exxon Nuclear Company, March 1983.

4. FSAR, Section 15.4.1.1.

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SUSQUEHANNA - UNIT 1 TS / B 3.1-6 Revision 2 I

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PPL:Rev. 1

. SDM B 3.1.1 BASES REF ERENCES 5. Final Policy Statement on Technical Specifications Improvements, (continued) July 22, 1993 (58 FR 39132).

,6. FSAR, Section 4.3.

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i *TS / B 3.1-7 Revision 2 I

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PPL Rev. 2 Control Rod Scram Times B 3.1.4 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.4 Control Rod Scram Times BASES BACKGROUND The scram function of the Control Rod Drive (CRD) System control s reactivity changes during abnormal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). The control rods are scrammed by positive means using hydraulic pressure exerted on the CRD piston.

When a scram signal is initiated, control air is vented from the scram ivalves, allowing them to open by spring action. Opening the exhaust valve reduces the pressure above the main drive piston to atmospheric pressure,-and opening the inlet valve applies the accumulator or reactor pressure to the bottom of the piston. Since the notches in the index tube are tapered on the lower edge, the collet fingers are forced open by cam action, allowing the index tube to move upward without restriction because of the high differential pressure across the piston. As the drive moves upward and the accumulator pressure reduces below the reactor pressure, a ball check valve opens, letting the react6r pressure complete

'the scram action. If the reactor pressure is low, such as during startup, the accumulator will fully insert the control rod in the required time without assistance from reactor pressure.

APPLICABLE The analytical methods and assumptions used in evaluating the control SAI:ETY' rod scram function are presented in References 2, 3, and 4. The Design ANALYSES Basis Accident (DBA) and transient analyses assume that all of the control rods scram at a specified insertion rate., The resulting negative scram reactivity forms the basis for the determination of plarit thermal limits (e.g.,

the MCPR). Other distributions of.scram times (e.g., several control rods scramming slower than the average time with several control rods scramming faster than the average time) can also provide sufficient scram II I reactivity. Surveillance of each individual control rod s scram time ensures the scram reactivity assumed in the DBA and transierit analyses can be met.

(continued)

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II B 3.1 -22 SUSQUEHANNA - UNIT 1 Re'vision 0 II I I I .

PPL Rev. 2 Control Rod Scrarm Times B 3.1.4 BASES APPLICABLE The scram function of the CRD System protects the MCPR Safety Limit SAFETY (SL) (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, ANALYSES "MINIMUM CRITICAL POWER RATIO (MCPR)") and the 1% cladding (ccntinued) plastic strain fuel design limit (see Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)" and LCO 3.2.4, "Average Power Range Monitor (APRM) Gain and Setpoints"), which ensure that no fuel damage will occur if these limits are not exceeded. ;Above 800 psig, the scram function is designed to insert negative reactivity at a rate fast enough to prevent the actual MCPR from becoming less than the MCPR SL, diring the analyzed limiting power transient. Below 800 psig, the scram function is assumed to perform during the control rod drop accident and, therefore, also provides protection against violating fuel damage limits during reactivity insertion accidents (Ref. 5) (see Bases for LCO 3.1.6, "Rod Pattern Control"). For the reactor vessel overpressure protection analysis, the scram function, along with the safety/relief valves, ensure that the peak vessel pressure is maintained within the applicable ASME Code limits.

Control rod scram times satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).

LCC) The scram times specified in Table 3.1.4-1 (in the accompanying LCO) are required to ensure that the scram reactivity assumed in the DBA and transient analysis is met (Ref. 7). To account for single failures and "slow" scramming control rods, the scram times specified in Table 3.1.4-1 are faster than those assumed in the design basis analysis. The scram times have a margin that allows up to approximately 7% of the control rods (e.g.,

185 x 7% 13) to have scram times exceeding the specified limits (i.e.,

"slow" control rods) including a single stuck control rod (as allowed by LCO 3.1.3, "Control Rod OPERABILITY") and an additional control rod

[failing to scram per the single failure criterion. The scram times are specified as a function of reactor steam dome pressure to account for the pressure dependence of the scram times. The scram times are specified relative to measurements based on reed switch positions, which provide the control rod position indication. The reed switch closes ("pickup") when

[the index tube passes a specific location and then opens ("dropout") as the index tube travels upward. Verification of the specified scram tines in iTable 3.1.4-1 is I (continued)

SUS'QUEHANNA - UNIT I TS / B 3.1-23 Revision 1

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES LOC) accomplished through measurement of the "dropout" times. To ensure (continued) that local scram reactivity rates are maintained within acceptable limits, no more than one "slow" control rod may occupy a face or diagonally adjacent location to any other "slow" or stuck control rod.

Table 3.1.4-1 is modified by two Notes which state that control rods with scram times not within the limits of the table are considered "slow" and that control rods with scram times > 7 seconds are considered inoperable as required by SR 3.1.3.4.

This LCO applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed (LCO 3.1.3). Slow scramming control rods may be conservatively declared inoperable and not accounted for as "slow" control rods.

APPLICABILITY In MODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function of the control rods is required during these MODES. In MODES 3 and 4, the control rods are not able to be withdrawn (except as permitted ty 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 requirements for control rod scram capability during these conditions. Scram requirements in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY-Refueling."

tI;1 I1 i I When the requirements of this LCO are not met, the rate of negative Ii i

I reactivity insertion during a scram may, not be within the assumptions of Ii

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t i the safety analyses." Therefore, the plant must be brought to a MODE in which the LCO does not apply. To achieve'thisistatus, the plant must be i.I

.I i I brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of

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i 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, lbased on operating experience,'to reach MODE 3 i from full power conditions in an orderly manner and without challenging i

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plant systems.

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SUSQUEHANNA - UNIT 1 B 3.1-24 Revision 0

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BA'SES (continued)

SURVEILLANCE The four SRs of this LCO are modified by a Note stating that REQUIREMENTS during a single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated, (i.e., charging valve closed) the influence of the CRD pump head does not affect the single control rod scram times. During a full core scram, the CRD pump head would be seen by all control rods and would have a negligible effect on the scram insertion times.

SR 3.1.4.1 i, . The scram reactivity used in DBA and transient analyses is based on an assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure 2 800 psig demonstrates acceptable scram times for the transients analyzed in References 3 and 4.

Maximum scram insertion times occur at a reactor steam dome pressure of approximately 800 psig because of the competing effects of reactor steam dome pressure and stored accumulator energy. Therefore, demonstration of adequate scram times at reactor steam dome pressure 2 800 psig ensures that the measured

; lscram times will be within the specified limits at higher pressures.

Limits are specified as a function of reactor pressure to account for t ; + ;the sensitivity of the scram insertion times with pressure and to allow a range of pressures over which scram time testing can be performed. To ensure that scram time testing is performed within a reasonable time following fuel movement within the reactor pressure vessel after a shutdown 2 120 days or longer, control rods are required to be tested before exceeding 40% RTP following the

'the event fuel movement is limited to selected core i;'shutdown.

cells, it is the intent of this SR that only those' CRDs associated with

' the core cells affected by the fuel movement 'are required to be scram time tested. However, if the reactor remains shutdown 2 120 days, all control rods are required to be;scram time tested. This Frequency is acceptable considering the additional surveillances i: j -performed for control rod OPERABILITY, thelfrequent verification of d adequate accumulator pressure, land the required testing of control

,rods affected by work on control rods or the CRD System.

__ _ ](continued)

SUS'QUEHANNA - UNIT I B 3.1-25 Revision 0

PP. Rev. 2 Control Rod Scram Times B 3.1.4 K;

BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS (continued) Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains representative if no more than 20% of the control rods in the sample tested are determined to be "slow." With more than 20'/o of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 20% criterion (e.g., 20% of the entire sample size) is satisfied, or until the total number of "slow" control rods (throughout the core, from all surveillances) exceeds the LCO limit.

For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used

.1 i! whenever possible to avoid unnecessary testing at power, even if tie i

i control rods with data may have been previously tested in a sample. The 1

1 1 120 day Frequency is based on operating experience that has shown 1 !

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control rod scram times do not significantly change over an operatihg i I cycle. This Frequency is also reasonable based on the additional I

I I Surveillances done on the CRDs at more frequent intervals in accordance I

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1 with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."

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iI SR 3.1.4.3 I1 i When work that could affect the scram insertion time is performed on a i i 1 1 I control rod or the CRD System, testing must be done to demonstrate

'! I that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once

'before declaring the control rod OPERABLE. The required scram lime testing must demonstrate the affected control rod is still within acceptable limitsJ The limits for reactor pressures < 800 psig are

[!established based on a high probability of meeting the acceptance criteria at reactor' pressures 2 800 psig. Limits for 2 800 psig are found

!in Table 3.1.4-1. If testing demonstrates the affected control rod dDes not meet these limits, but is within the 7-second limit of Table 3.1.4-1, jNote 2, the control rod can be declared OPERABLE and "slow."

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PPL. Rev. 2 Control Rod Scram Times 6 3.1.4 BA'SES REQUIREMENTS SR 3.1.4.3 (continued)

SURVEILLANCE Specific examples of work that could affect the scram times are (but are not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator, isolation valve or check valve in the piping required for scram.

The Frequency of once prior to declaring the affected control rod OPERABLE is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.

SR 3.1.4.4 When work that could affect the scram insertion time is performed on a control rod or CRD System, testing must be done to demonstrate each affected control rod is still within the limits of Table 3.1.4-1 with the reactor steam dome pressure 2 800 psig. Where work has been performed at high reactor pressure, the requirements of SR 3.1.4.3 and SR 3.1.4.4 can be satisfied with one test. For a control rod affected by work performed while shut down, however, a zero pressure and high pressure test may be required. This testing ensures that, prior to withdrawing the control rod for continued operation, the control rod scram performance is acceptable for operating reactor pressure conditions. Alternatively, a control rod s ram test during hydrostatic pressure testing could also satisfy both criteria.

The Frequency of once prior to exceeding 40% RTP is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.

REFERENCES 1. 10 CFR 50,:Appendix A, GDC 10.

2. FSAR, Section 4.3.2.

3. FSAR, Sectidn 4.6.

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SUSQUEHANNA - UNIT 1 B 3.1-27 Revision 0

PPL Rev. 2 Control Rod Scrarn Times B 3.1.4

).

BASES REFERENCES 4. FSAR, Section 15.0.

(continued)

5. FSAR, Section 15.4.9. I

6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).

7. Letter from R.F. Janecek (BWROG) to R.W. Starostecki (NRC.),

"BWR Owners Group Revised Reactivity Control System Technical Specifications," BWROG-8754, September 17, 1987.

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SUSQUEHANNA - UNIT 1 TS / B3.1-28 Revision 2

PPL. Rev. 2 Rod Pattern Control B 3.1.6 k4'1 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.6 Rod Pattern Control BASES BACKGROUND Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM) (LCO 3.3.2.1, "Control Rod Block Instrumentation"), so that only specified control rod sequences and relative positions are allowed over the operating range of all control rods inserted to 10% RTP. The sequences limit the potential amount of reactivity addition that could occur in the event of a Control Rod Drop Accident (CRDA).

This Specification assures that the control rod patterns are consistent with the assumptions of the CRDA analyses of References 1 and 2.

A PFLI CAB LE The analytical methods and assumptions used in evaluating the CF:DA SAFItETY are summarized in References 1 and 2. CRDA analyses assume that the ANALYSES reactor operator follows prescribed withdrawal sequences. These i sequences define the potential initial conditions for the CRDA analysis.

The RWM (LCO 3.3.2.1) provides backup to operator control of the iI withdrawal sequences to ensure that the initial conditions of the CRDA analysis are not violated.

i Prevention or mitigation of positive reactivity insertion events is necessary to limit the energy deposition in the fuel, thereby preventing significant fuel damage which could result in the undue release of radioactivity. Since the failure consequences for U02 have been shown to be insignificant below fuel energy depositions of 300 cal/gm (Ref. 3), the fuel damage limnt of

I 280 cal/gm provides a margin of safety from significant core damace which would result in release of radioactivity (Refs. 4 and 5). Generic evaluations (Ref. 1 & 6) of a design basis CRDA have shown that tne

. : maximum reactor pressure will be less than the required ASME Code

limits (Ref.7). Theloffsite doses are calculated eachkcycle using the methodology in reference 1 to demonstrate that the calculated offs te

'doses will be well within the required limits (Ref. 5). Control rod pa tems analyzed in Reference 1 follow the banked position withdrawal sequence (BPWS). The BPWS is applicable from the conditionr of all control ods fully inserted to 10% RTP (Ref. 2). For the BPWS, the control rods are required to be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions

-u o i (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-34 Revision I

PPL. Rev. 2 Rod Pattern Control B 3.1.6 BASES APPLICABLE (e.g., between notches 08 and 12). The banked positions are established SAFETY to minimize the maximum incremental control rod worth without being ANALYSES overly restrictive during normal plant operation. For each reload cycle the (continued) CRDA is analyzed to demonstrate that the 280 cal/gm fuel damage limit will not be violated during a CRDA'while following the BPWS mode of operation for control rod patterns.' These analyses consider the effects of fully inserted inoperable and OPERABLE control rods not withdrawn in the normal sequence of BPWS, but are still in compliance with the BPWVS requirements regarding out of sequence control rods. These requirements allow a limited number (i.e., eight) and distribution of fully inserted inoperable control rods.

When performing a shutdown of the plant, an optional BPWS control rod sequence (Ref. 9) may be used provided that all withdrawn control rods have been confirmed to be coupled prior to reaching THERMAL PC)WER of <10% RTP. The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled. When using the J.t Reference 9 control rod sequence' for shutdown, the RWM may be reprogrammed to enforce the requirements of the improved BPWS control r I) rod insertion, or may be bypassed and the improved BPWS shutdown sequence implemented under LCO 3.3.2.1, Condition D controls.

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In order to use the Reference 9 BPWS shutdown process, an extra check is required in order to consider a control rod to be "confirmed" to be I

coupled. This extra check ensures that no Single Operator Error can result in an incorrect coupling check. For purposes of this shutdown process, the method for confirming that control rods are coupled varies depending on the position of the control rod in the core. Details on this coupling confirmation requiremenat are provided in Reference 9, which requires that any partially inserted c6ntrol rods, which have not been confirmed to be coupled since their last withdrawal, be fully inserted prior to reaching THERMAL POWER 6f *10% RTP. If a control rod has been checked for coupling at notch 48 and the rod has since only been moved inward, this rod is in contact with it's drive and is not required to be fully inserted prior to reaching THERMAL POWER of <10% RTP. However, if it cannot be confirmed that the control rod has been moved inward, then that rod shall be fully inserted prior to reaching the THERMAL POWER of

<10% RTP. This extra check may be performed as an administrative check, by examining logs, previ6u's -

-; (continued)

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,SUSQUEHANNA - UNIT 1 TS / B 3.1-35 I Revision I

PPL. Rev. 2

.Rod Pattern Control B 3.1.6 BASES ,__

APPLICABLE surveillance's or other information) If the requirements for use of the SAFETY BPWS control rod insertion process contained in Reference 9 are ANALYSES followed, the plant is considered to be in compliance with the BPWS, (continued) requirements, as required by LOC 3.1.6.

Rod pattern control satisfies Criterion 3 of the NRC Policy Statement (Ref. 8).

LCO Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting the initial conditions :o those consistent with the BPWS. This LCO only applies to OPERABLE control rods. For inoperable control rods required to be inserted, separate requirements are specified in LCO 3.1.3, "Control Rod OPERABILITY,"

consistent with the allowances for inoperable control rods in the BPWS.

APPLICABILITY In MODES 1 and 2, when THERMAL POWER is < 10%'RTP, the CRDA is a Design Basis Accident and, therefore, compliance with the assumptions of the safety analysis is required. When THERMAL POWER is

> 10% RTP, there is no credible control rod configuration that resul:s in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 2). In MODES 3, 4, and 5, since the reactor is shut down and only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will remain subcritical with a single control rod withdrawn.

ACFIONS A.1 and A.2 I With one or more OPERABLE control rods not in compliance with the prescribed control rod sequence, actions may be taken to either correct Ithe control rod pattern or declare the associated control rods inoperable within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . Noncompliance with the prescribed 'sequence may be the result of "double notching," drifting' from a c6ntrol rod drive cooling water transient, leaking scram valves, or'a power reduction to < 10% RTP before i establishing the correct control rod pattern. The number of OPERABLE i

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control rods not in compliance witli the prescribed sequence is limited to i eight, to prevent the operator from' attem'ptifg to correct a control rod i

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'. pattern that significantly deviates from the prescribed sequence. When the control I

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(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-36 Revision 1

PPI Rev. 2 Rod Pattern Control B 3.1.6 BASES ACTIONS A.1 and A.2 (continued) rod pattern is not in compliance with the prescribed sequence, all control rod movement should be stopped except for moves needed to correct the rod pattern, or scram if warranted.

Required Action A.1 is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be returned to their correct position. LCO 3.3.2.1 requires verification of control rod movemen: by a qualified member of the technical staff. This ensures that the control rods will be moved to the correct position. A control rod not in compliance with the prescribed sequence is not considered inoperable'except as required by Required Action A.2. OPERABILITY of control rods is determined by compliance with LCO 3.1.3, "Control Rod OPERABILITY," LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators." The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is reasonable, considering the restrictions on the number of allowed out of sequence control rods and the low probability of a CRDA occurring during the time the control rods are out of sequence.

B.1 and B.2 If nine or more OPERABLE control rods are out of sequence, the control

. rod pattern significantly deviates from the prescribed sequence. Control rod withdrawal should be suspended immediately to prevent the pctential for further deviation from the prescribed sequence. 'Control rod insertion to correctcontrol rods withdrawn beyond their allowed position is allowed since, in Igeneral,'inisertion of control rods has'less impoact on control rod worth than withdrawals have. Required Action B 1 is modified by a Note which allows the RWM to be bypassed to allow the affected control rods

.to be returned to their correct position. LCO 3.3.2.11requires verification of control rod movement by a qualified member of the' technical staff.

When nine or more OPERABLE control rods are not in compliance with BPWS, the reactor!mode switch must be placed in the shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . With the mode switch in shutdown, the reactor is shut down, anid as such, does not meet the applicability requirements of this LCO. The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability (continued)

SUSQUEHANNA - UNIT 1 ITS / B 3.1-37 REVision 2

PPL Rev. 2 Rod Pattern Control B 3.1.6 BASES ACTIONS B.1 and B.2 (continued) of a CRDA occurring with the control rods out of sequence.

SURVEILLANCE SR 3.1.6.1 REQUIREMENTS The control rod pattern is verified to be in compliance with the BPVWS at a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency to ensure the assumptions of the CRDA analyses are met. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency was developed considering that the primary check on compliance with the BPWS is performed by the RWM (LCO 3.3.2.1), which provides control rod blocks to enforce the required sequence and is required to be OPERABLE when operating at

10% RTP.

REFERENCES 1. XN-NF-80-19(P)(A) Volume 1 and Supplements 1 and 2, "Exxon Nuclear Methodology for Boiling Water Reactors," Exxon Nuclear Company, March 1983.

2. "Modifications to the Requirements for Control Rod Drop Accident Mitigating System," BWR Owners Group, July 1986.

3. NUREG-0979, Section 4.2.1.3.2, April 1983.

4. NUREG-0800, Section 15.4.9, Revision 2, July 1981.

5. 10 CFR 100.11.

i-6. NEDO-21778-A, "Transient Pressure Rises Affected Fracture

Toughness Requirements for Boiling Water Reactors,"

December 1978.

7. ASME, Boiler and Pressure Vessel Code.

8. Final Policy Statement on Technical Specifications Improvements,

July 22,1993 (58 FR 39132).

9. NEDO 33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," Aprl 2003.

I SUSDQUEHANNA - UNIT 1 TS / B 3.1-38 Revision 2 I

i

PPL Rev. 1 APLHGR B 3.2.1 B. 3.2 POWER DISTRIBUTION LIMITS .

B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

BASES BACKGROUND The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on the APLHGR are specified to ensure that limits specified in 10 CFR 50.46 are not exceeded during the postulated design basis loss of coolant accident (LOCA).

APPLICABLE SPC performed LOCA calculations for the SPC ATRIUM'-10fuel I SAFETY design. The analytical methods and assumptions used in evaluating the ANALYSES fuel design limits from 10 CFR 50.46 are presented in References 3, 4, I 5, and 6 for the SPC analysis. The analytical methods and assumptions used in evaluating Design Basis Accidents (DBAs) that determine the APLHGR Limits are presented in References 3 through 9.

LOCA analyses are performed to ensure that the APLHGR limits are adequate to meet the Peak Cladding Temperature (PCT), maximum cladding oxidation, and maximum hydrogen generation limits of 10 CFR 50.46. The analyses are performed using calculational models that are consistent with the requirements of 10.CFR 50, Appendix K. A complete discussion of'the analysis codes are provided in References 3, I 4, 5, and 6 for the SPC analysis. The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within the assembly.

APLHGR limits are developed as a function of fuel type and exposure.

The SPC LOCA analyses also consider several alternate operating I modes in the development of the APLHGRtlimits (e.g., Extended Load Line Limit Analysis (ELLA), Suppression Pool Cooling Mode, and Single Loop Operation (SLO)). LOCA analyses were performed for the regions of the power/flow map bounded by the 100% rod line and the APRM rod I' block line (i.e., the ELLA region). The ELLA region is analyzed tc determine whether an APLHGR multiplier as' a function of core flow is required. The results of the analysis demonstrate the PCTs are within the 10 CFR 50.46 limit, and that APLHGR multipliers as a function of core flown are not required.

(continued) i S

I .S U 11 I--zQUEHANNA -UNIT 1 TS / B 3.2-1 Recision I i

I II i i i II

PPL Rev. 1 AP'LHGR B 3.2.1 BASES APPLICABLE The'SPC LOCA analyses consider the delay in Low Pressure Coolant SAFETY Injection (LPCI) availability when the unit is operating in the ANALYSES Suppression Pool Cooling Mode. The delay in LPCI availability is due (continued) to the time required to realign valves from the Suppression Pool Cooling Mode to the LPCI mode. The results of the analyses demonstrate that the PCTs are within the 10 CFR 50.46 limit.

Finally, the SPC LOCA analyses were performed for Single-Loop I Operation. The results of the SPC analysis for ATRIUM -10 fuel shows that an APLHGR limit which is 0.8 times the two-loop APLHGR limit meets the 10 CFR 50.46 acceptance criteria, and that the PCT is less than the limiting two-loop PCT. I The APLHGR satisfies Criterion 2 of the NRC Policy Statement (Ref.

10).

LCCO The'APLHGR limits specified in the COLR are the result of the DBA analyses.

APPLICABILITY The'APLHGR limits are primarily derived from. LOCA analyses that are assumed to occur at high power levels. Design calculations and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases. At THERMAL POWER levels

< 25% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a DBA occurring simultaneously with the APLHGR out of specification.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.2-2 Revision 2

PPLi Rev. 1 APLHGR B 3.2.1 BA SES ACTIONS B.1 (continued)

If the APLHGR 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 must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . 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 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after

! THERMAL POWER is 2 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

Additionally, APLHGRs must be calculated prior to exceeding SOY0 RTP unless performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . APLHGRs are 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance after THERMAL POWER 2 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because the APLHGRs must be calculated pricr to exceeding 50% RTP.

REFERENCES 1. Not used.

2. Not used. I

3. EMF-2361(P)(A), "EXEM BWR-2000 ECCS Evaluation Model,"

Framatome ANP. i

4. ANF-CC-33(P)(A) Supplement 2, "HUXY: A Generalized MLItirod Heatup Code with 10CFR50 Appendix K Heatup Option,"

January 1991.

' 5. XN-CC-33(P)(A) Revision 1, "HUXY: A Generaiized Multirocd a Heatup Code with 10CFR50 Appendix K Heatup Option Users i Manual," November 1975. i (continued)

SUS'QUEHANNA - UNIT 1 TS / B 3.2-3 Revision 2

PPL Rev. 1 APLHGR B 3.2.1 BASES Ref erences 6. XN-NF-80-19(P)(A), Volumes 2, 2A, 2B, and 2C "Exxon Nuclear (continued) Methodology for Boiling Water Reactors: EXEM BWR ECCS Evaluation Model," September 1982.

7. FSAR, Chapter 4.

8. FSAR, Chapter 6.

9. FSAR, Chapter 15.

10. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).

I I' 1!

I [

S5U ZQUEHANNA -UNIT 1 TS / B 3.2-4 Revision 2 i

l

PPL Rev. 1 MCPR B 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)

BASES BACKGROUND MCPR is a ratio of the fuel assembly power that would result in th e onset of boiling transition to the actual fuel assembly power. The MCPR Safety Limit (SL) is set such that 99.9% of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2.1.1.2).

The operating limit MCPR is established to ensure that no fuel damage results during anticipated operational occurrences (AOOs). Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.

The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e., the bundle power, level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant'operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.

APFLICA'BLE' The analytical methods and assumptions used in evaluating the A0Os SAFETY to establish the operating limit MCPR are presented in References 2 ANALYSES through 10. To 'ensure that the MCPR SL is not exceeded during any I I1 !1 transient event that occurs with moderate frequency, limiting transients have been analyzed to determine th6 largest reduction in critical Flower ii ratio (CPR). The types of transients evaluated are loss of flow, increase i

i i in pressure and power, positive reactivity insertion, and coolant f temperature decrease. The limiting transient yields the largest change in 1 : CPR (ACPR). When the largest ACPR is added to the I, MCPR SL, the i I required operating lirmit MCPR is obtained.

i i I

ii The MCPR operating limits derived from the transient analysis are I : dependent on the operating core flow and power k i

~~~ ,:.

i.

1 f!

Ii I:

ii i 1 :

(continued)

SUS'QUEHANNA - UNIT 1 :I TS/ B 3.2-5 ii Revision 2

- PPL Rev. 1 MCPR B 3.2.2 BASES APPLICABLE state to ensure adherence to fuel design limits during the worst transient SAFETY that occurs with moderate frequency. These analyses may also ANALYSES consider other combinations of plant conditions (i.e., control rod scram (continued) speed, bypass valve performance, EOC-RPT, cycle exposure, etc.).

Flow dependent MCPR limits are determined by analysis of slow flow runout transients.

The MCPR satisfies Criterion 2 of the NRC Policy Statement (Ref. 11).

LCC) The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis. The operating limit MCPR is determined by the larger of the flow dependent MCPR aid power dependent MCPR limits.

APFPLICABILITY The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power levels. Below 25% RTP, the reactor is operating at a minimum recirculation pump speed and the

moderator void ratio is small. Surveillance of thermal limits below 25% RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs.

Studies of the variation of limiting transient behavior have been I performed over the range of power and flow conditions. These studies encompass the range of key actual plant parameter values important to C typically limiting transients. The results of these studies 'demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to 25% RTP. This trend is expected to i

i j -. t !,

f 7 1

. I ,

4 1

Io :i',e,

+F I - , (continued) 1 SUSQUEHANNA - UNIT 1 TS / B .2-15 ; Revision 2 I

PPL Rev. 1 MCPR B 3.2.2 BASES APPLICABILITY continue to the 5% to 15% power range when entry into MODE 2 occurs.

(continued) When in MODE 2, the intermediate range monitor provides rapid scram initiation for any significant power increase transient, which effectively eliminates any MCPR compliance concern. Therefore, at THERNIAL POWER levels < 25% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.

ACTIONS A.1 If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met.

Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable basec on the low probability of a transient or DBA occurring simultaneously with the MCPR out of specification.

B.1 If the MCPR cannot be restored to within its required limits within the o,9' 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 must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . 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 3.22.1 [

REOiUIREMENTS The MCPR is required to be initially calculated within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is Ž 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

Additionally, MCPR must be calculated prior to exceeding 50% RTP unless performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . MCPR is compared to the specified limits in the I : !I, S Ks! t i(continued)

I ~i' SUSQUEHANNA - UNIT 1 B 3.2-7 Revision 0

PPL. Rev. I MCPR B 3.2.2 BASES SURVEILLANCE SR 3.2.2.1 (continued)

REQUIREMENTS COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance after THERMAL POWER Ž25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because the MCPR must be calculated prior to exceeding 50% RTP.

SR 3.2.2.2 Because the transient analysis takes credit for conservatism in th a scram time performance, it must be demonstrated that the specific scram time is consistent with those used in the transient analysis.

SR 3.2.2.2 compares the average measured scram times to the assumed scram times documented in the COLR. The COLR contains a table of scram times based on the LCO 3.1.4 "Control Rod Scram Times" and the realistic scram times, both of which are used in the transient analysis. If the average measured scram times are greater than the realistic scram times then the MCPR operating limits corresponding to the Maximum Allowable Average Scram Inserticn Time

`(1, must be implemented. Determining MCPR operating limits based on interpolation between scram insertion times is not permitted. The average measured scram times and corresponding MCPR operating limit must be determined once within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each set of scram time tests required by SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3 and SR 3.1.4.4 because the effective scram times may change during the cycle. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is acceptable due to the relatively minor changes in average measured scram times expected during the fuel cycle.

i a REI *ERENCES 1. NUREG-0562, June 1979.

. 2. XN-NF-80-19(P)(A) Volume 1 and Supplements 1 and 2, 'Exxon

Nuclear Methodology for Boiling Water Reactors," Exxon Nuclear Company, March 1983.

(continued)

Su:,U:QUEHANNA- UNIT 1 TS /B3.2-8 Re-vision 2 II

PPL. Rev. 1

_MCPR B 3.2.2 BASES !_:

REFERENCES 3. XN-NF-80-19(P)(A)'Volume 3 Revision 2, "Exxon Nuclear (continued) Methodology for Boiling Water Reactors, THERMEX: Thermal Limits Methodology!Summary Description," Exxon Nuclear Company, January 1987.

4. ANF-913(P)(A) Volume 1:Revision 1 and Volume Supplements 2, 3, and 4, "COTRANSA2: A Computer Program for Boiling Water Reactor Transient Analyses," Advanced Nuclear Fuels Corporation, August 1990.

5. XN-NF-80-19 (P)(A), Volume 4, Revision 1, "Exxon Nuclear Methodology for Boiling Water Reactors: Application of th a ENC Methodology to BWR Reloads," Exxon Nuclear Company, June 1986.

6. NE-092-001, Revision 1, Susquehanna Steam Electric Station Units 1 & 2: Licensing Topical Report for Power Uprate with Increased Core flow," December 1992, and NRC Approval Letter:

Letter from T. E. Murley (NRC) to R. G. Byram (PP&L),

I . "Licensing Topical Report for Power Uprate With Increased Core Flow, Revision 0, Susquehanna Steam Electric Station, Units I and 2 (PLA-3788) (TAC Nos. M83426 and M83427)," November 30,1993.

7. EMF-2209(P)(A), Revision 1, "SPCB Critical Power Correlation,"

Siemens Power Corporation, July 2000.

8. XN-NF-79-71(P)(A) Revision 2, Supplements 1, 2, and 3, 'Exxon

Nuclear Plant Transient Methodology for Boiling Water Reactors,"

March 1986.

9. XN-NF-84-105(P)(A), Volume 1 and Volume 1 Supplements 1 sI and 2, "XCOBRA-T5 A Computer Code for BWR Transient:

Thermal-Hydraulic Core Analysis," February 1987.

l 10. ANF-1358(P)(A) Revision 1, "The Loss of Feedwater Heating Transient in Boiling Water Reactors," Advanced Nuclear Fujels Corporation, September 1992.

i l11. Final Policy Statement on Technical Specifications

_Improvements, Julyi22, 1993 (58 FR 39132).

SuI , _____-_UNI T - __TS__3_2_ Reviion SUCSQUEHANNA -UNIT 1 TS / B 3.2-9 Revision 2

PPL Rev. 4 AC Sources - Operating B3 3.8.1

~.ue B 3.3 ELECTRICAL POWER SYSTEMS B 3.3.1 AC Sources - Operating BASES I BACKGROUND The unit Class 1E AC Electrical Power Distribution System AC sources consist of two offsite power sources (preferred power sources, normal and alternate), and the onsite standby power sources (diesel generators (DGs) A, B, C and D). A fifth diesel generator, DG E, can be used as a substitute for any one of the four DGs A, B, C or D. As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The Class 1E AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed. Each'load group has connections to two preferred offsite power supplies and a single DG.

. The two qualified circuits between the offsite transmission netwcrk and

! the onsite Class 1E AC Electrical Power Distribution System are t

l supported by two independent offsite power sources. A 230 kV line from the Susquehanna T10 230 kV switching station feeds start-up transformer No. 10; and, a 230 kV tap from the 500-230 kV tie line

. F ; feeds the startup transformer No. 20.

l I The two independent offsite power sources are supplied to and are shared by both units. These two electrically and physically separated

! circuits provide AC power, through startup transformers (ST) No. 10 and ST No. 20, to the four 4.16 kV Engineered Safeguards System r

(ESS) buses (A, B, C and Dj for both Unit 1 arid Unit 2. A detailed I description of the offsite'power network' and circuits to the onsite I

Class 1E ESS buses is found in the FSAR,! Section :8.2 (Ref. 2).

i I

P i An offsite circuit consists of all breakers, transformers, switches, I

i automatic tap changers,'inte'rrupting devices, cabling, and controls iI L I i

required to transmit power from the offsite transmission network to the I

onsite ClassiE ESS bus or buses.

I . I

. I I

i i t

i i

I i . '!I IiL

,e I

I (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-.1 Revision 2

. i i1

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES B

BACKGROUND ST No. 10 and ST No. 20 each provide the normal source of poNer to (continued) two of the four 4.16 kV ESS buses in each Unit and the alternate source of power to the remaining two 4.16 kV ESS buses in each Unit.

If any 4.16 kV ESS bus loses power, an automatic transfer from the normal to the alternate occurs after the normal supply breaker trips.

When off-site power is available to the 4.16 kV ESS Buses following a LOCA signal, the required ESS loads will be sequenced onto the 4.16 kV ESS Buses in order to compensate for voltage drops in the cinsite power system when starting large ESS motors.

The onsite standby power source for 4.16 kV ESS buses A,' B, C and D consists of five DGs. DGs A, B, C and D are dedicated to ESS buses A, B, C and D, respectively. DG E can be used as a substitute for any one of the four DGs (A, B, C or D) to supply the associated ESS bus. Each DG provides standby power to two 4.16 kV ES'S buses-one associated with Unit 1 and one associated with Unit 2.

The four "required" DGs are those aligned to a 4.16 kV ESS bus to provide onsite standby power for both Unit 1 and Unit 2.

A DG, when aligned to an ESS bus, starts automatically on a loss of coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell;pressure signal) or on an ESS bus degraded voltage or undervoltage signal. After the DG has started, it automatically t es to its respective bus after offsite power is tripped as a consequence of ESS bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the ESS bus on a LOCA signal alone.

Following the trip of offsite power, non-permanent loads are stripped from the 4.16 kV ESS Buses. When a DG is tied to the ESS BLIS, loads are then sequentially connected to their respective ESS Bus by individual load timers. The individual load timers control the starting permissive signal to motor breakers to prevent overloading the associated DG.

In the event of loss of normal and alternate offsite power supplies, the 4.16 kV ESS buses will shed all loads except the 480 V load centers andithe standby diesel generators will connect toitheEEES busses. When a DG is tied to its respective ESS bus, loads are then sequentially connected to (continued)

SUSDQUEHANNA - UNIT 1 TS / B 3.8-2 Revision 2

PPL Rev. 4 AC Sources - Operating B 3.8.1 BASES BACKGROUND the ESS bus by individual load timers which control the permissive and (ccntinued) starting signals to motor breakers to prevent overloading the DC.

In the event of a loss of normal and alternate offsite power supplies, the ESS electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a LOCA.

4 Certain required plant loads are returned to service in a predetermined sequence in order to prevent overloading of the DGs in the process.

Within 286 seconds after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service. Ratings for the DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3).

i DGs A, B, C and D have the following ratings:

a. 4000 kW-continuous, i

b. 4700 kW-2000 hours, i

DG E has the following ratings:

a. 5000 kW-continuous, I

b. 5500 kW-2000 hours.

I I

i APFPLICABLE l The initial conditions of DBA and transient analyses in the FSAF, SAF ETY ANALYSES Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, i i Reactor Coolant System (RCS), and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for

[1i,4 I Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coclant i

System (RCS);'and Section 3.6, Containment Systems.

i II j The OPERABILITY of the AC electrical power sources is i

I 1

I I

i .: i consistent with the initial assumptions ofthe accident analyses I . i I I : and is based upon imeeting the design basis of the unit and l:,i ;;

1I i i supporting safe shutdown of the other unit. This includes 1: i : I maintaining the onsite or offsite AC sources Ii I .

i r p

I I,! -

1 i ,

(continued) j.

SU,% oQUEHANNA -UNIT 1 TS / B 3.8-3 Revision 2

PPL. Rev. 4

-AC Sources - Operating B 3.8.1 I BASES APPLICABLE OPERABLE during accident conditions in the event of an assurmed SAFETY ANALYSES loss of all offsite power or all onsite AC power; and a worst case single failure.

(continued)

AC sources satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Two qualified circuits between the offsite transmission network and the onsite Class 1E Distribution System and four separate and independent DGs (A, B, C and D) ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA: DG E can be used as a substitute for any one of the four DGs A, B, C or D.

Qualified offsite'circuits are those that are described in the FSAR, and are part of the licensing basis for the unit. In addition, the required automatic load timers for each ESF bus shall be OPERABLE.

The Safety Analysis for Unit 2 assumes the OPERABILITY of some l equipment that receives power from Unit I AC Sources. Therefore,

'Unit 2 Technical Specifications establish requirements for the OPERABILITY of the'DG(s) and qualified offsite circuits needed to support the Unit 1 onsite Class 1E AC electrical power distribution subsystem(s) required by LCO 3.8.7, Distribution Systems-Operating.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESS buses.

One OPERABLE offsite circuit exists when all of the following conditions are nmet:

1. An energized ST. No. 10 transformer with the load tap changer (LTC) in Automatic operation.

2. The respective circuit path including energized ESS transformers 101 and 111 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses.

3. Acceptable offsite grid voltage, defined as a voltage that is within the grid voltage requirements established for SSES.

The grid voltage requirements include both a minimum grid voltage and an allowable grid voltage drop during normal operationr, and for a predicted voltage for a trip of the unit.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-4 Revision 3

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES LOC) The Regional Transmission Operator (PJM), and/or the (continued) Transmission Power System Dispatcher, PPL EU, determine, monitor and report actual and/or contingency voltage Preadicted tvoltaqe) violations that occur for the SSES monitored offsite 230kV and 500kV buses.

The offsite circuit is inoperable for any actual voltage violation, or a contingency voltage violation that occurs for a trip of a

SSES unit, as reported by the transmission RTO or Transmission Power System Dispatcher.

The offsite circuit is operable for any other predicted grid event (i.e., loss of the most critical transmission line or the largest supply) that does not result from the generator trip of a SSES unit. These conditions do not represent an impact on SSES operation that has been caused by a LOCA and subsequent generator trip. The design basis does not require entry into LCOs for predicted grid conditions that can not result in a LOCA, delayed LOOP.

The other offsite circuit is Opdrable when all the following conditions are met:

1. An energized ST. No. 20 transformer with the load tap changer (LTC) in automatic operation.

2. The respective circuit path including energized ESS transformers 201 and 211 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses.

3. Acceptable offsite gridjvoltage, defined as a voltage that is within the grid voltage requirements established for SSES.

The grid voltage requirements include both a minimum grid voltage and an all6wable grid voitage drop during normal operation, and for 'a predicted voltage for a trip of the unit.

The Regional Transmission Operator (PJM), and/or the Transmission Power System Dispatcher, PPL EU, determine, monitor and report actual and/or contingency voltage (Predicted volta'e) violations that occur for the SSES monitored offsite 230kV and 500kV buses.

(continued) i SUEQUEHANNA - UNIT 1 TS / B 3.8-4a Revision O

PPL Rev. 4 AC Sources - Operating B 3.8.1 7 . I II BASES I .

i l LCO The offsite circuit is inoperable for any actual voltage (continued) violation, or a contingency voltage violation that occurs for a I

trip of a SSES unit, as reported by the transmission RTO or Transmission Power System Dispatcher.

The offsite circuit is operable for any other predicted grid event (i.e., loss of the most critical transmission line or the largest supply) that does not result from the generator trip of a SSES unit. These conditions do not represent an impact on SSES operation that has been caused by a LOCA and subsequent generator trip. The design basis does not require entry into LCOs for predicted grid conditions that can not result in a LOCA, delayed LOOP.

Both offsite circuits are OPERABLE provided each meets the criteria described above and provided that no 4.16 kV ESS Bus has less than one OPERABLE offsite circuit If Of' I

I I I

,:I II i;

I: II

I (continued) 1 SUSQUEHANNA - UNIT 1 TS / E3 3.8-4b Revision 0 i'

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES LCO capable of supplying the required loads. If no OPERABLE offsite (continued) circuit is capable of supplying any of the 4.16 kV ESS Buses, provided that the offsite circuits otherwise meet the above requirements, one offsite source shall be declared inoperable.

Four of the five DGs are required to be Operable to satisfy the initial assumptions of the accident analyses. Each required DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESS bus on detection of bus undervoltage after the normal and alternate supply breakers open. This sequence must be accomplished within 10 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite pcwer can be restored to the ESS buses. These capabilities are required to be met from a variety of initial conditions, such as DG in standby with the engine hot and DG in normal standby conditions. Normal standby conditions for a DG mean that the diesel engine oil is being continuously circulated and engine coolant is circulated as necessary to maintain temperature consistent with manufacturer recommendations. Additional DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.

Although not normally aligned as a required DG, DG E is normally maintained OPERABLE (i.e., Surveillance Testing completed) so that it can be used as a substitute for any one of the four DGs A, B, C or D.

Proper sequencing of loads, including tripping of nonessential Iciads, is a required function for DG OPERABILITY.,

The AC sources must be separate and independent (to the extent possible) of other AC sources. For the DGs, the separation and independence are complete. For the offsite'AC sources, the separation and independence are to the extent practical. A circuit may ibe connected to more than one ESS bus, with automatic transfer capability to the other circuit OPERABLE, and not violate separation criteria. A circuit'that is not connected to an ESS bus is required to

'have OPERABLE automatic transfer interlock mechanisms to each ESS bus to support OPERABILITY of that offsite circuit.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-5 Revision 4

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASSES (continued)

APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources-Shutdown."

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The ACTIONS are modified by a Note which allows entry into l associated Conditions and Required Actions to be delayed for Up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months when an OPERABLE diesel generator is placed in an inoperable status for the alignment of diesel generator E to or from the Class 1E distribution system. Use of this allowance requires both offsite circuits to be OPERABLE. Entry into the appropriate Conditions and Required Actions shall be made immediately upon the determination that substitution of a required diesel generator Wi.l not or can not be completed.

A.1 To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure ofjSR 3.8.1.1 acceptance criteria does not result in a Required Action not met.

THowever, if alsecond required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

(continued)

Su. SQUEHANNA - UNIT 1 TrS / B 3.8-6 Revision 3

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES A ACTIONS A.2 (cc ntinued)

Required Action A.2, which only applies if one 4.16 kV ESS bus cannot be powered 'from any offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of critical systems. These features (e.g:, system, subsystem, division, component, or device) are designed to be powered from redundant safety related 4.16 kV ESS buses. Redundant required features failures consist of inoperable features associated with an emergency bus redundant to the emergency bus' that has no offsite power. The Completion Time for Required Action A.2 is intended to allow time for the operator to evaluate and repair any discovered inoperabilities.

This Completion Time also allows an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. A 4.16 kV ESS bus has no offsite power supplying its loads; and

b. A redundant required feature on another 4.16 kV ESS bus is inoperable.

<,1, If, at any time during the existence of this Condition (one offsite circuit inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.

Discovering no offsite power to one 4.16 kV ESS bus on the onsite Class 1E Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other emergency bus that has offsite power, results in starting the Completion Times for1 the Required Action!. Twenty-four hours is acceptable because it minimizes riskI while! allowing time for restoration before the unit is subjected to transients associated with shutdown.

The remaining:OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24

.'(co' tinued (continued) i I SUSQUEHANNA -UNIT 1 TS / B 3.8-7 Revision 2 I .

i .

L .

PPL. Rev. 4 AC Sources - Operating B 3.8.1 BASES AC7IONS A.2 (continued) hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.

- tThe second Completion Time for Required Action A.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable, and that DG is I subsequently retumed OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This situation could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restbred OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. 'This limit is considered reasonable for l situations in which Conditions A and B are entered concurrently.

The "AND" connector between the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that !both (continued)

SUSQUEHANNA - UNIT 1 TS i B 3.8-8 Revision 2

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES AC--IONS A.3 (continued)

Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time that Condition A was entered.

B.1 To ensure a highly reliable power source remains with one requ red offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Actioh being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.

B.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.a.,

single division systems are not included). Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning t'he allowed outage time "clock." In!thi Required Action the Completion (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-9 Revision 4

PPL Rev. 4

--AC Sources - Operating B 3.8.1 BASES ACTIONS B.2 (continued)

Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A required feature powered from another diesel generator (Division 1 or 2) is inoperable.

If, at any time during the existence of this Condition (one required DG inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Corrpletion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE DGs and offsite circuits are adequaie to supply electrical power to the onsite Class I E Distribution System.

Thus, on a component basis, single failure protection for the rec uired feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable

[time for repairs, and low probability of a DBA occurring during this period.

l 'B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary

,testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.7 does not have to be performed. If the cause of inoperability exists on

, ,other DG(s), they are declared inoperable upon discovery, and Condition E of LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists,: Required Action B.3.1 is 1'satisfied. If the cause of the initial in6perable DG cannot be determined not to exist on the remaining DG(s), performance of SR 3.8.1.7 suffices to provide assurance of continued OPERAEILITY of those DGs.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-1 0 Revision 3

PPL Rev. 4

-'AC Sources - Operating B 3.8.1 BASES ACTIONS B.3.1 and B.3.2 (continued)

However, the second Completion Time for Required Action B.3.2 allows a performance of SR 3.8.1.7 completed up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to entering Condition B to be accepted as demonstration that a DG is not inoperable due to a common cause failure.

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2,' the plant corrective action program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.

B.4 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In Condition B, the remaining OPERABLE DGs. and offsite circuits are adequate to supply electrical power to the onsite Class I E Distribution iSystem. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC~sources, reasonable time for repairs, and low probability of a DBA occurring during this period.

The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. Iif Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This situation could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure of ithe LCo, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The E6day Completion Time provides a limit on the time allowed in a specified (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-11 Revision 2

PPL Rev. 4 AC Sources - ODerating B 3.8.1 BAS'ES ACTIONS B.4 (continued) condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND"!connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered.

C.1 Required Action C.1 addresses actions to be taken in the event of concurrent inoperability of two offsite circuits. The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This level of degradation means that the offsite electrical power system dDes not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, .the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.

Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other 6ombinations of two AC sources inoperable that inv'olve one or more DGs inoperable.: Howe ver, two factorsitend to decrease the severity of this degradation level:'

a. The configuration of the redundant AC electrical power system that remains bus or switching and is not susceptible to a single available failure I I, i *1 (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.8-12 Revision 2

PPL. Rev. 4 AC Sources - Operating B 3.8.1 BASES ACTIONS C. 1 (continued)

b. The time required to detect and restore an unavailable offisite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis.

Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria. According to Regulatory Guide 1.93 (Ref. 7), with the available offsite AC sources two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A.

D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System Actions would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any ESS bus, Actions for LCO 3.8.7, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of the offsite ci -cuit and one DG without regard to whether a division is de-energized. LCO 3.8.7 provides the appropria restnctions for a de-energized bus.

,i I According to Regulatory Guide 1.93 (Ref. 7), operation may

. i I: continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . InCon D, individual redundancy is lost in both the offsite electrical powerssystem and the onsite AC electrical I power system. Since power, system redundancy is provided by two diverse sources of power, however, the I.. .

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-i3 Revision 2

PPL. Rev. 4 AC Sources - Operating B 3.8.1 BASES ACTIONS D.1 and D.2 (continued) reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). T-his difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.

E.

With two or more DGs inoperable and an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Regulatory Guide 1.93 (Ref. 7), with two or more DGs inoperable, operation may continue for a period that should not exceed I l 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months F.1 and F.2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . 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 3.8-14 Revision 2

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES ACTIONS G.1 (continued)

Condition G corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE The AC sources are designed to permit inspection and testing of all REOUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 9). Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), and Regulatory Guide 1.137 (Ref. 11), as addressed in the I FSAR.

The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources. TherefDre, Surveillance requirements are established for the Unit 1 onsite Class i

1E AC electrical power distribution subsystem(s) required to support Unit 2 by LCO 3.8.7, Distribution Systems-Operating. The Unit 1 SRs required to support Unit 2 are identified in the Unit 2 Technical Specifications.

l Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable. The minimum steady state output voltage of 3793 V is the value assumed in the degradedyvoltage analysis and is approximately 90% of the nominal 4160 V,output voltage. This value allows for voltage

drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90%/ or 3600 V. It also allows

, for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90% of name plate rating. The specified maximum steady state output voltage of 4400 V is equal to the (continued)

SUSQUEHANNA -UNIT 1 TS / B 3.8-15 Revision 2 i

PPI. Rev. 4

- AC Sources - Operating B 3.8.1 BASES SURVEILLANCE maximum operating voltage specified for 4000 V motors. It ensures REQUIREMENTS that for a lightly loaded distribution system, the voltage at the terminals (continued) of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to

+ 2% of the 60 Hz nominal frequency and are derived from the recommendations found in Regulatory Guide 1.9 (Ref. 3). The lower frequency limit is necessary to support the LOCA analysis assumptions for low pressure ECCS pump flow rates. (Reference 12)

The Surveillance Table has been modified by a Note, to clarify the testing requirements associated with DG E. The Note is necessary to define the intent of the Surveillance Requirements associated with the integration of DG E. Specifically, the Note defines that a DG is only considered OPERABLE and required when it is aligned to the C~lass 1E distribution system. For example, if DG A does not meet the requirements of a specific SR, but DG E is substituted for DG A and aligned to the Class 1E distribution system, DG E is required to be OPERABLE to satisfy the LCO requirement of 4 DGs and DG A is not required to be OPERABLE because it is not aligned to the Class I E distribution system. This is acceptable because only 4 DGs are assumed in the event analysis. Furthermore., the Note identifies when the Surveillance Requirements, as modified by SR Notes, have been met and performed, DG E can be substituted for any other DG and declared OPERABLE after performance of two SRs which verify switch alignment. This is acceptable because the testing regimen defined in the Surveillance Requirement Table ensures DG E is fully capable of performing all DG requirements.

SR 3.8.1.1 . -

This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribdtion buses and loads are connected to an Operableloffsite power source and that appropriate independence of offsite circuits is maintained. The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.

(continued)

( l IQ:

SuISQUEHANNA - UNIT 1 TS / B 3.8-16 Revision 2

i. .

I,, '

PPL. Rev. 4 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 REQUIREMENTS (continued) Not Used.

SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this OR, the DG is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the Cooper Bessemer Service Bulletin 728, so that mechanical stress and wear on the diesel engine are minimized.

Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly,

¶ .momentary power factor transients do not invalidate the test.

Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory

. Iperformance.l iNote 5 provides the allowance that DG E,when not aligned as substitute forDG A, B, C and D but being maintained available, (continued)

SU3'QUEHANNA - UNIT 1 TS / B 3.8-17 Revision 2

PPI Rev. 4

- AC Sources - Operating B 3.8.1 BAS)ES SURVEILLANCE SR 3.8.1.3 REQUIREMENTS (continued) may use the test facility to satisfy loading requirements in lieu of synchronization with an ESS bus.

Note 6 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units, with the DG synchronized to the 4.16 kV ESS bus of Unit 1 for one periodic test and synchronized to the 4.16 kV;ESS bus of Unit 2 during the next periodic test. This is acceptable because the purpose of the test is to demonstrate the ability of the DG to operate at its continuous rating (with the exception of DG E which is only required to be tested at the continuous rating of DGs A through D) and this attribute is tested at the required Frequency. Each unit's circuit'breakers and breaker control circuitry, which are only being tested every second test (due to the staggering of the tests), historically have a very low failure rate. If a DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause 'of the failure can be directly related to only one unit.

In addition, if the test is scheduled to be performed on the other Unit, and the other Unit's TS allowance that provides an exception to performing the test is used (i.el., the Note to SR 3.8.2.1 for the other Unit provides an exception to performing this test when the other Unit K0 is in MODE 4 or 5, or' moving irradiated fuel assemblies in the secondary containment), or it is not possible to perform the test due to equipment availabililty, then the test shall be performed synchronized to this Unit's 4.16 kV ESS bus. The 31 day Frequency for this Surveillance is consistent with Regulatory Guide -i.9(Ref. 3).

SR 3.8.1.4 This SR verifies the level of fuel oil in the engine mounted day tank is at or above the level at which Ifuel oil is automatically added. The level is expresse s an equivalent volume in gallons, and is selected to ensure adequate fuel oil for alm'inimum of 55 minutes of DG A-D and 62 minutes of DG E operation at DG continuous rated load conditions.

iThe 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and operators would be aware of any large uses of fuel oil during this period.

(continued)

I SUSQUEHANNA 1:

-UNIT 1 1 TS / B 3.8-18 Revision 3

PPL Rev. 4 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.5 REQUIREMENTS (continued) Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the engine mounted day tanks once every 31 days eliminates the necessary environment for bacterial survival. This. is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventive maintenance., The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this I

Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer 4.I , pump operates and transfers fuel oil from its associated storage tank to its associated day tank. It is required to support continuous operation of standby power sources. This Surveillance provides I

l assurance that the fuel oil transfer pump is OPERABLE, the fuel oil

,i .

,. I piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE. i I I

i i I

I I i

1 I!

. I I 1 1 i I i

i i I i

I 1 i

1 :

I ;

i ii iI i i i

i i i i

i I1 II I ii 1 11 i

i I1 11 I

II I

I iI i iI (continued) i I

SUS DUEHANNA - UNIT 1 TS / B 3.8-19 Revision 2 I

! i 1 I 1 1 I

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 (continued)

REQUIREMENTS The Frequency for this SR is 31 days because the design of the fuel transfer system requires that the transfer pumps operate automatically.

Administrative controls ensure an adequate volume of fuel oil in the day tanks. This Frequency allows this aspect of DG Operability to be demonstrated during or following routine DG operation.

SR 3.8.1.7 This SR helps to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.

To minimize the wear on moving parts that do not get lubricated when the engine is not running, this SR has been modified by Note I to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubicated to prevent undo wear and tear).

For the purposes of this testing the DGs are.started from standby conditions. Standby conditions for a DG mean that the diesel engine oil is being continuously circulated and diesel engine coolant is being circulated as necessary to maintain temperature consistent with manufacturer recommendations. The DG starts from standby conditions and achieves the minimum required voltage and frequency within 10 seconds and maintains the required voltage and frequency when steady state conditions are reached. The 10 second start requirement supports the assumptions in the design basis LOCA analysis of FSAR, Section 6.3 (Ref. 12).

To minimize testing of the DGs, Note 2 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit).

H This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the G should be considered inoperable for both (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-20 Revision 2

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES REQUIREMENTS SR 3.8.17 (continued)

SURVEILLANCE units, unless the cause of the failure can be directly related to one unit The time for the DG to reach steady state operation is periodically monitored and the trend evaluated to identify degradation.

The 31 day Frequency is consistent with Regulatory Guide 1.9 (Ref. 3). This Frequency provides adequate assurance of DG OPERABILITY.

SR 3.8.1.8 Transfer of each 4.16 kV ESS bus !power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads. The 24 month Frequency of the Surveillance is i based on engineering judgment taking into consideration the plant

conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed on the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of the automatic transfer of the unit power supply could cause perturbations to the electrical distribution systems that could challenge continued steady state!

operation and, as a result, plant safety systems. The manual transfer of unit power supply should not result in any perturbation to the electrical distribution system, therefore, no mode restriction is specified.

This Surveillance tests the applicable logic associated with Unil 1. The comparable test specified in Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequentlyl a test must be

- performed within the specified Frequency for each unit. As the I Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE l or 2 does not have applicability to Unit 2. The NOTE (continued)

SU! UQUEHANNA - UNIT 1 TS / B 3.8-21 Revision 2

PPL. Rev. 4

--AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)

REQUIREMENTS only applies to Unit 1, thus the Unit 1 Surveillance shall not be performed with Unit 1 in MODE 1 or 2.

SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each DG is a residual heat removal (RHR) pump (1425 kW). This Surveillance may be accomplished by:

a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or

b. Tripping its associated single largest pqst-accident load with the DG solely supplying the bus.

As recommended by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75%

It ;,of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower. For DGs A, B, C, D and E, this represents 64.5 Hz, equivalent to 75% of the difference between nominal speed and the overspeed trip setpoint.

The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref.' 3) recommendations for response during load sequence intervals. The 45 seconds specified is equal to 60% of the 7.5 second load sequence interval between loading of the RHR and core spray pumps during an undervoltage on the bus concurrent with a LOCA. The 6 seconds specified is equal to 80% of that load sequence interval. The voltage and frequency specified are l ,l l ji l 1 UQUEHANA-U T ' . Rtinued)

R(co iSUSQUEHANNA - UNIT I TS /B 3.8-22 Revision 3

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)

REQUIREMENTS consistent with the design range of the equipment powered by the DG.

SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c specify the steady state voltage and frequency values to which the system must recover following load rejection.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.

To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be' considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage

limits. The DG full load rejection may occur because of a systerm fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions.

This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load., These acceptance criteria provide

,*li l 4 DG damage protection. While [the DG is not expected to experience this transient during an event, and continues to be available, this including reconnection to the bus if the trip initiator can be corre :ted or isolated.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-23 Revision 3

PPL Rev. 4

- AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)

REQUIREMENTS To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for eazh unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.

SR 318.1.11 As required by Regulatory Guide 1.9 (Ref. 3), this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the ESS buses and respective I4.16kV loads from the DG. It further demonstrates the capability of the DG to automatically achieve and maintain the required voltage and D

frequency within the specified time.

The DG auto-start time of 10 seconds is derived from requirements of the licensed accident analysis for responding to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant ccnditions required to perform the Surveillance, and is intended to be consistent I ;with expected fuel cycle lengths.

(continued)

SUSQUEHANNA - UNIT 1 TS/ B 3.8-24 Revision 2

PPL Rev. 4 AC Sources - Operating 13 3.8.1 BASES SURFVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note I allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubicated). For the purpose of this testing, the DGs shall be started from standby conditions that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.

This SR is also modified by Note 2. The Note specifies when this SR is required to be performed for the DGs and the 4.16 kV ESS Buses.

The Note is necessary because this SR involves an integrated test between the DGs and the 4.16 kV ESS Buses and the need for the testing regimen to include DG E being tested (substituted for all DGs for both Units) with all 4.16 kV ESS Buses. To ensure the necessary testing is performed, the following rotational testing regimen has been established:

UNIT IN OUTAGE DIESEL E SUBSTITUTED FOR 2 DG E not tested 1 Diesel Generator D 2 Diesel Generator A 2 DG E not tested 2 Diesel Generator B I Diesel Generator A 2 Diesel Generator C

1. iDiesel Generator B 2 , Diesel Generator D 1Diesel Generator C 7The specified rotational testing regimen can be altered to

'facilitate unanticipated events which render the testing regimen

,:impractical to implement, but any alternative (continued)

SUS;QUEHANNA -UNIT 1 TS /;B 3.8-25 Revision 2 I .

i i :

I

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BA'SES SURVEILLANCE SR 3.8.1.11 (continued)

REOUIREMENT .

testing regimen must provide an equivalent level oftesting. This SR does not have tobe performed with the normally aligned DG when the associated 4.16 kV ESS bus is tested using DG E and DG E does not need to be tested when not substituted or aligned to the Class I E distribution system. The allowances specified in the Note are acceptable because the tested attributes of each of the five DGs and each unit's four 4.16 kV ESS buses are verified at the specified Frequency (i.e., each DG and each 4.16 kV ESS bus is tested every 24 months). Specifically, when DG E is tested with a Unit 1 4.16 kV ESS bus, the attributes of the normally aligned DG, although not tested with the Unit 1 4.16 kV ESS bus, are tested with the Unit 2 4.16 kV ESS bus within the 24 month Frequency. The testing allowances do result in some circuit pathways which do not need to change state (i.e., cabling) not being tested on a 24 month Frequency. This is acceptable because these components are not required to change state to perform their safety function and when substituted-normal operation of DG E will ensure continuity of most of the cabling not tested. 1 The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed Within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 2. The Note only applies to Unit 1, thus the Unit 1 Surveillances shall not be performed with Unit 1 in MODES 1, 2 or 3.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for 2 5 minutes. The 5 minute period provides sufficient time to demonstrate (continued)

I SUSQUEHANNA -UNIT 1 : TS / B 3.8-26 Revision 2

I

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the cffsite electrical power system on a LOCA signal without loss of offsite power.

The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to the loading logic for loading onto offsite power. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, high pressure injection systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential,

-overlapping, or total steps so that the entire connection and loading sequence is verified. SR 3.8.1.12.a through SR 3.8.1.12.d are performed with the DG running. SR 3.8.1.12,e can be performed when the DG is not running.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all

,DG starts to be preceded by an engine prelube period (which for DG A through D includes operation of the lube oil system to ensure the DG's turbo-charger is sufficiently prelubicated). For the purpose of this

testing, the DGs must be started from standby conditions that is, with i the engine oil being continuously'circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.

iN UT B(continued)

! SU',QUEHANNA - UNIT 1 TS / E 3.8-27 Revision 2

PPL. Rev. 4

-.AC Sources - Operating B 3.8.1 Yj) BASES SURVEILLANCE SR 3.8.1.13 REQUIREMENTS (continued) The reason for Note 2 is to allow DG E, when not aligned as substitute for DG A, B, C or D to use the test facility to satisfy loading requirements in lieu of aligning with the Class 1E distribution system.

When tested in this configuration, DG E satisfies the requirements of this test by completion of SR 3.8.1.12.a, b and c only. SR 3.8.1.12.d and 3.8.1.12.e may be performed by any DG aligned with the Class 1E distribution system or by any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

This Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on an if ECCS initiation test signal. The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This

'alarm provides the operator with sufficient time to react appropriately.

The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The 24 month Frequency is based on engineering judgment, takes into i consideration plant conditions required to perform the Surveillance, i and is intended to be'consistent with expected fuel cycle lengths.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

The SR is modified by two Notes. To minimize testing of the D(3s, Note 1 to SR 3.8.1.13 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is acceptable j because this test is iritended to demo ntrate'attributes of the DG that I this Surveillance, are not associated with either Unit. If the DG fails unit',

theIDboth u'le h the DG should be considered inoperable for bot uns, Mess the c e of the failure can be directly related to only one unit.

I Note 2 provides the allowance that DG E, when not aligned as a substitute for DG A, B, C,' and D but being maintained available, may use a simulated ECCS initiation signal.

' I (continued)

SUSQUEHANNA - UNIT 1 TS /;B 3.8-28 Revision 2

PPL Rev. 4 AC Sources - Operating B3 3.8.1 0 BASES SURVEILLANCE SR 3.8.1.14 REQUIREMENTS (co ltinued) Regulatory Guide 1.9 (Ref. 3), requires demonstration once per i

24 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s-22 hours of which is at a load equivalent to 90% to 100% of the continuous rating cf the DG, and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent to 105% to 11 0% of the continuous duty rating of the DG. SSES has taken exception to this requirement and performs the two hour run at the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating for each DG. The requirement to perform the two hour overload test can be performed in any order provided it is performed during a single continuous time period.

The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube discussed in SR 3.8.1.7, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

A load band is provided to avoid routine overloading of the DG.

Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This Surveillance has been modified by four Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this

' test.

I To minimize testing of the DGs, Note 2 allows a single test (instead of l two tests, one for each unit) to satisfy' the requirements for both units.

This is acceptable because this test is intended to demonstrate attributes of the ODG that are not associated with either Unit. Ifthe DG I fails this Surveillance, the DG should be considered inoperable ior both units, unless the cause of the failiur can' be directly related to only one unit.

Note 3 stipulates that DG E, when not aligned as substitute for LDG A, B, C or D but being maintained available, may use (continued)

I SU';QUEHANNA -UNIT 1 TSJ B 3.8-29 Revision 2 I f

PPL Rev. 4 AC Sour.ces - Operating 13 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS the test facility to satisfy the specified loading requirements in lieu of synchronization with an ESS bus.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from full load temperatures, and achieve the required voltage and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by three Notes. Note 1 ensures that the tes: is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILIl'.

Momentary transients due to changing bus loads do not invalidate this test.

Note 2 allows all DG starts to be preceded by an engine prelube period I' T'1(which for DGs A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubricated) to minimize wear and tear on the diesel during testing.

To minimize testing of the DGs; Note 3 allows a single test to satisfy the requirements for both units!(instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that'areenot associated with either Unit. If the DG lfails this Surveillancel the DG should be considered inoperable ifor I both units, unless the cause of the failure can be directly related to only one unit.

Y - (continued)

SU';QUEHANNA - UNIT 1 TS lB 3.8-30 ' Revision 2

PPL Rev. 4

-AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 REOUIREMENTS (continued) As required by Regulatory Guide 1.9 (Ref. 3), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and that the DG can be returned to ready-to-load status when offsite power is restored. It also ensures that the auto-start logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the DG controls are in isochronous and the output breaker is open.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.11 for the Bases of the Note.

SR 3.8.1.17 1 I 4

Demonstration of the test mode override ensures that the DG availability under accident conditions is not compromised as the result i

of testing. Interlocks to the LOCA sensing circuits cause the DC; to automatically reset to ready-to-load operation if an ECCS initiation i

signal is received during operation in the test mode. Ready-to-load i

I operation is defined as the DG running at rated speed and voltage, the i DG controls in isochronous and the DG output breaker open. These i

i provisions for automatic switchover are required by IEEE-308 t

I (Ref. 10), paragraph 6.2.6(2).

1 1-i I The requirement to automatically energize the emergency loads, with i ii i offsite power is essentially identical to that of SR 3.8.1.12. The I

i I

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.I

'intent in the requirements associated with SR 3.8.1.17.b is to show i I that the emergency loading is not affected by the' DG operation in 1 i: test mode. In lieu of actual demonstration of connection and loading I-i ! of loads, testing that adequately shows the capability of the 1II iiI.

I emergency loads to perform these functions is acceptable. This test io i: is performed by verifying that after the DG is tripped, the offsite I source originally in parallel with the DG, remains connected to the i

I I; I

(continued)

SUSQUEHANNA -UNIT 1 TS / B 3.8-31 Revision 2

.i I I !

PPL. Rev. 4

- AC Sources - Operating B 3.8.1

_BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS affected 4.16 kV ESS Bus. SR 3.8.1.12 is performed separately to verify the proper offsite loading sequence.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.11 for the Bases of the Note.

SR 3.8.1.18 Under accident conditions, loads are sequentially connected to the bus by individual load timers which control the permissive and starting signals to motor breakers to prevent overloading of the AC Sou ces due to high motor starting currents. The load sequence time interval tolerance ensures that sufficient time exists for the AC Source to F restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic.

loading of ESS buses. A list of the required timers and the associated Isetpoints are included in the Bases as Table B 3.8.1-1, Unit I and Unit 2 Load Timers. Failure of a timer identified as an offsite power timer may result in both offsite sources being inoperable. Failure of any other timer may result in the associated DG being inoperable. A timer is considered failed for this SR if it will not ensure that the associated load will energize within the Allowable Value in Table B 3.8.1-1. These conditions will require entry into applicable Conditions of this specification. With a load timer inoperable, the load can be rendered i , I linoperable to restore OPERABILITY to the associated AC sources. In this condition, 'the Condition and Required Actions of the associated I specification shall be entered for the equipment rendered inoperable.

l The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent F i with expected fuel cycle lengths.

_, ;(co;tinued)

SUSQUEHANNA-UNIT1 TS/ B 3.8-32 Revision 2

PPL Rev. 4

-_AC Sources - Operating B 3.8.1

'BAS)ES SURVEILLANCE SR 3.8.1.18 (continued)

REQUIREMENTS This SR is modified by a Note that specifies that load timers associated with equipment that has automatic initiation capability disabled are not required to be Operable. This is acceptable because if the load does not start automatically, the adverse effects of an improper loading sequence are eliminated. Furthermore, load timers are associated with individual timers such that a single timer only affects a single load.

SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates DG operation, as discussed in the Bases for SR 3.8.1.1 1, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified. To simulate the non-LOCA unit 4.16 kV ESS Bus loads on the DG, bounding loads are energized on the tested 4.16 kV ESS Bus after all auto connected energizing loads are energized.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length. This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be' preceded by an engine prelube period (which for DGs A through D includes operation cf the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated.) F or the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.

(continued)

SU:3QUEHANNA - UNIT 1 TS / B 3.8-33 Revision 2

PPL Rev. 4

-AC Sources - Operating 3 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)

REQUIREMENTS Note 2 is necessary to accommodate the testing regimen associated with DG E. See SR 3.8.1.11 for the Bases of the Note.

The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2 or 3 does not have applicability to Unit 2. The Note only applies to Unit 1, thus the UJnit I Surveillances shall not be performed with Unit 1 in MODE 1, 2 o 3.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independerce has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously. The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3).

! -This SR is modified by two Notes. The reason for Note 1 is to

minimize wear on the DG during testing. The Note allows all DG starts

to be preceded by an engine prelube period (which for DGs A through

D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated). For the purpose of this testing,

,the DGs must be started from standby conditions, that is, with the

I J engine oil continuously circulated and engine coolant being circulated E Ilas necessary to maintain temperature consistent with manufacturer recommendations.

Note 2 is necessary to identify that this test does not have to be performed with DG E substituted for any DG. The allowance is l acceptable based on the design of the DG E transfer switches.

The transfer of control, protection, indication, (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-34 Revision 2

PPL Rev. 4 I -ACSources - Operating E3 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)

RECUIREMENTS and alarms is by switches at two separate locations. These switches provide a double break between DG E and the redundant system within the transfer switch panel. The transfer of power is through circuit breakers at two separate locations for each redundant system. --here are four normally empty switch gear positions at DG E facility, associated with each of the four existing' DGs. Only one circuit l reaker is available at this location to be inserted into one of the four positions.

At each of the existing DGs, there are tvwo switchgear positions with only one circuit breaker available. This design provides two open circuits between redundant power sources. Therefore, based on the described design, it can be concluded that DG redundancy and independence is I maintained regardless of whether DG E is substituted for any other DG.

R. E REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

i

2. FSAR, Section 8.2.

I i 3. Regulatory Guide 1.9.

I

4. FSAR, Chapter 6.

.i 5. FSAR, Chapter 15.

i I

6. Final Policy Statement on Technical Specifications I

i i

Improvements, July 22, 1993 (58 FR 39132).

i I

.r i ii, I

7. Regulatory Guide 1.93.

I I i ! -11

8. Generic Letter 84-15.

!I I .

i1 i . 1i

.i It9. 10 CFR 50, Appendix A, GDC IS.

I i

.ii 10. IEEE Standard 308.

l i i:j iI 11 11. Regulatory Guidel1.137.

111 i i

1 I

ii 12. FSAR, Section 6.3.

i1i1I

. iI 11 I1 ! 13. ASME Boiler and Pressure Vessel Code, Section Xl.

1 (continued)

_I 1.SUS QUEHANNA -UNIT 1 ITS/ B3.8-35 Revision 2 i, , :

a

PPL Rev. 4 AC Sources - Operating B 3.8.1

TABLE B 3.8.1-1 (page 1 of 2)

UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE \VALUE TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) (seconds) 62A-20102 RHR Pump IA 1A201 3 22.7 and s 3.6 62A-20202 RHR Pump I B 1A202 3 2Ž2.7 and S 3.6 62A-40302 ' RHR Pump IC 1A203 3 22.7 and* 3.6 62A-30402 RHR Pump 1D 1A204 3 22.7 and* 3.6 62A-,0102 RHR Pump 2A 2A201 3 2 2.7 and* 3.6 62A-0202 RHR Pump 2B . 2A202 3 2 2.7 and S3.6 62A-Z0302 RHR Pump 2C 2A203 3 2 2.7 and s3.6 62A- 0402 RHR Pump 2D 2A204 3 2 2.7 and S3.6 E11A.K202B RHR Pump IC (Offsite Power Timer) 1C618 7.0 2 6.5 and* 7.5 E11A-K120A RHR Pump J C (Offs'de Power Timer) 1C617 7.0 2 6.5 and* 7.5 E11A-K120B RHR Pump ID (Offsite Power Timer) 1C618 7.0 2 6.5 and* 7.5 E11A.K202A RHR Pump 1D (Offsite Power Timer) 1C617 7.0 2Ž6.5 and S7.5 E11 A-K1 20A RHR Pump 2C (Offsite Power Timer) 2C617 7.0 Ž 6.5 and S7.5 E11A.K202B RHR Pump 2C (Offsite Power Timer) 2C618 7.0 2Ž6.5 and S7.5 ElA-Kl20B R.HR Pump2D (Offsite PowerTimer) 2C618 7.0 Ž6.5and*7.5 E11A.K202A RHR Pump 2D (Offsite PowerTimer) 2C617 7.0 26.5ands7.5 E21A-K116A CS Pump IA 1C626 10.5 2Ž9.4 and*S1;.6 E21A.K116B CS Pump 1B 1C627 10.5 29.4 and:S 11.6 E21A-K125A CS Pump 1C 1C626 10.5 29.4 and* 11.6 E21A.K125B CS Pump 1D 1C627 10.5 29.4 and <1-1.6 E21A-K116A CS Pump 2A 2C626 10.5 2Ž9.4 andS 1-1.6 E21AK116B CS Pump 2B 2C627 10.5

29.4 andS 11.6 E21A-K125A CS Pump 2C 2C626 10.5 29.4 and S 11.6 E21A.K125B ' CS Pump 2D 2C627 10.5 29.4 and:S1 1.6 E21A-K16A CS Pump IA (Offsite Power Timer) 1C626 15 ' 14.0 and S 16.0 E21A-K16B CS Pump 1 B (Offsite Power Timer) 1C627 15 2 14.0 ands5 16.0 E21A-K25A CS Pump I C (Offsite Power Timer) 1C626 15 2Ž14.0 and *16.0 E21 A.K25B CS Pump 1D (Offsite Power Timer) 1C627 15 Ž14.0 and *16.0 E21A-K1 6A CS Pump 2A (Offsite Power Timer) 2C626 15 2 14.0 and S 16.0 E21A:K16B CS Pump 2B (Offsite FowerTimer) 2C627 15 Ž14.0 and *16.0 E21A-K25A CS Pump 2C (Offsite Power Timer) 2C626 15 Ž14.0 and *16.0 E21A-K25B CS Pump 2D (Offsite Power Timer) 2C627 15 Ž14.0 and S16.0 62AX2-20108 Emergency Service Water 1A201 40 ! Ž36 and S 44 62AX2-20208 Emergency Service Water 1A202 40 2 36 and s 4 62AX2-20303 Emergency Service Water 1A203 44 1 2 39.6 and s z8.4 62AX2-20403 Emergency Service Water 1A204 48 Ž243.2 and S E2.8 62X3.20404 Control Structure Chilled Water System OC877B 60 2Ž54 62X3-20304 Control Structure Chilled Water System OC877A 60 ; 2Ž54 I Emergency Switchgear Rm CoolerA 2 54 62X I201 04 RRS u 8 a OC877A 60 0 .Emergency Switchgear Rm Cooler B &

62X-220.~ RHR SW Puimp H&V Fan B007B6Ž5 62X-'653A DG Room Exhaust Fan E3 OB565 60 Ž 54 62X-E652A DG Room Exhausts Fan E4 OB565 60 .254 262X-20204 Emergency Switchgear Rm Cooler B OC877B 120 2Ž54 262X-20104 Emergency SwitchgearI Rm Cooler A OC877A 120

254 I (continued) t1I SULIQUEHANNA- UNIT 1 TS / B 3.8-36 R Revision 2

'PPL Rev. 4

-AC Sources - Operating 13 3.8.1 TABLE B 3.8.1-1 (page 2 of 2)

UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE VALUE TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) (seconds) 62X-546 DG Rm Exh Fan D OB546 1120 2 54 62X-536 DG Rm Exh Fan C OB536 120 2 54 62X-526 DG Rm Exh Fan B 08526 120 254 62X-516 DG Rm Exh Fan A OB516 120 254 CRX-5652A DG Room Supply Fans El and E2 08565 120 2 54 62X2-20410 Control Structure Chilled Water System OC876B , 180 2 54 62X1 -20304 Control Structure Chilled Water System OC877A 180 2 54 62X2-20310 Control Structure Chilled Water System OC876A 180 2 54 I 62X1 -20404 Control Structure Chilled Water System OC877B O180 54 62X2 20304 Control Structure Chilled Water System OC877A 210 2 54 62X2-20404 Control Structure Chilled Water System OC877B 210 . 54 62X1<1188 62X-1<.11 I BB Emergency Cmrso Compressor B Switchgear Rm Coaling 2 B 5 B2 2CB250B 2600~5 2 54 Rm Coaling 2 B5 A2 5 62X-1<62X l<I1AB 1 AB CompressorSwitchgear Emergency A 2CB250A 2602 54_=

Copeso I.

I SUSQUEHANNA - UNIT 1 TS / B 3.8-37 Re~vision 2

PPL Rev. 1 Control Rod Testing-Operating E,3.10.7 I ;

B 3.10 SPECIAL OPERATIONS I .

B 3.10.7 Control Rod Testing-Operating i BASES ,

BACKGROUND The purpose of this Special Operations LCO is to permit control rod testing, while in MODES 1 and 2, by imposing certain administrative l controls. Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM) (LCO 3.3.2.1, "Control Rod Block Instrumentation"), such that only the specified control rod sequences and relative positions required by LCO 3.1.6, "Rod6Pattem Control," are allowed over the operating range from all control rods inserted to the low power setpoint (LPSP) of the RWM.

The sequences effectively limit the potential amount and rate of reactivity increase that could 6ccur during a control rod drop accident (CRDA). During these conditions, control rod testing is sometimes required that may result in control rod patterns not in compliance with the prescribed sequences of LCO 3.1.6. These tests include SDM demonstrations, control rod scram time testing, control rod friction testing, and testing performed during the Startup Test Program (e.g.

local'cfriticality). This Special Operations LCO provides the necessary exemption to the requirements of LCO 3.1.6 and provides additional administrative controls to allow the deviations in such tests from the prescribed sequences in LCD 3.1.6.

APF 'LICABLE The analytical methods and assumptions used in evaluating the SAF ETY ANALYSES CRDA area summarized in References 1 and 2. CRDA analyses assume the reactor operator follows prescribed withdrawal sequences. These sequences define the potential initial conditions for the CRDA analyses. The RWM provides backup to operator control of the withdrawal sequences to ensure the initial conditions of the CRDA analyses are not violated. For special sequences developed for control 'rod testing, the initial control rod p~atterns assumed in the safety analysis of References 1 and 2 may not be preserved.

Therefore, special CRDA analyses are required to demonstrate

.that these special sequences will not result in unacceptable consequences, should a CRDA occur during the testing.' These (continued)

IUEHANNA- UNIT 1 B 3.10-29 Revision 0 II.

PPL Rev. 1 Control Rod Testing-Operating B 3.10.7 BASES APPLICABLE analyses, performed in accordance with an NRC approved SAFETY ANALYSES methodology, are dependent on the specific test being performed.

(continued)

As described in LCO 3.0.7, compliance with Special Operations L.COs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases.

LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Control rod testing may be performed in compliance with the prescribed sequences of LCO 3.1.6, and during these tests, no exceptions to the requirements of LCO 3.1.6 are necessary. For testing performed with a sequence not in compliance with LCO 3.1.6, the requirements of LCO 3.1.6 may be suspended, provided additional administrative controls are placed on the test to ensure that the assumptions of the special safety analysis for the test sequence are satisfied. Assurances that the test sequence is followed can be provided by either programming the test sequence into the RWM, with conformance verified as specified in SR 3.3.2.1.8 and allowing the RWM to monitor control rod withdrawal and provide appropriate control rod blocks if necessary, or by verifying conformance to the approved test sequence by a second licensed operator or other qualified member of the technical staff. These controls are consistent with those normally applied to operation in the startup range as defined in the SRs and ACTIONS of LCO 3.3.2.1, "Control Rod Block Instrumentation."

APPLICABILITY Control rod testing, while in MODES 1 and 2, with THERMAL POWER greater than the LPSP of the RWM, is adequately controlled by the existing LCOs on power distribution limits and control rod block instrumentation. Control rod movement during these conditions is not restricted to prescribed sequences and can be performed within the constraints of LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," LC0 3.2.2,'MINIMUM CRITICAL POWER RATIO (MCPR)," LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," and (continued)

SU'SQUEHANNA - UNIT 1 B 3.10-30 Revision 0

PPL Rev. 1 Control Rod Testing-Operating I B 3.10.7 BAS 11E BASES _ I 4!

APPLICABILITY LCO 3.3.2.1. With THERMAL POWER less than or equal to the LPSP (continued) of the RWM, the provisions of this Special Operations LCO are r necessary to perform special tests that are not in conformance with the I

prescribed sequences of LCO 3.1.6.1 While in MODES 3 and 4, control rod withdrawal is only allowed if performed in accordance with Special Operations LCO 3.10.3, "Single Control Rod Withdrawal-Hot Shutdown," of Special Operations LCO 3.10.4, "Single Control Rod Withdrawal-Cold Shutdown," which provide adequate controls to ensure that the assumptions of the safety analyses of Reference 1 and 2 are satisfied. During these Special Operations and while in MODE 5, the one-rod-out interlock (LCO 3.9.2,1 "Refuel Position One-Rod-Out Interlock,") and scram functions (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and LCO 3.9.5, "Control Rod OPERABILITY-Refueling"), or the added administrative controls prescribed in the applicable Special Operations LCOs, provide mitigation of potential reactive excursions.

ACTIONS A.1 With the requirements of the LCO not met (e.g., the control rod pattern

k4ooj, is not in compliance with the special test sequence, the sequence is improperly loaded in the RWM) the testing is required to be immediately ii suspended. Upon suspension of the special test, the provisions of 1, I LCO 3.1.6 are no longer expected, and appropriate actions are to be i

I 1. taken to restore the control rod sequence to the prescribed sequence of i LCO 3.1.6, or to shut down the reactor, if required by LCO 3.1.6.

I I!

iii:

1 SURVEILLANCE SR 3.10.7.1 t I REQUIREMENTS I With the special test sequence not programmed into the RWM, a I

II : I second licensed operator or other qualified member'of the technical ii staff is required to verify conformrance with the approved sequence for

.I : the test. This verification must be performed during control rod II movement to prevent deviationsfrom the specified sequence. A Note

,P I: is added to indicate that this Surv'eillance does not need to be

.! I il performed if SR 3.10.7.2 is satisfied.

, II I,1::

.!Ii

.II

-I; i I

! II I I (continued)

SU'S;QUEHANNA -UNIT 1 B 3.10-31 Revision 0 i

I

PPL Rev. I Control Rod Testing-Operating B 3.10.7 BASES SURVEILLANCE SR 3.10.7.2 REQUIREMENTS (co:ntinued) When the RWM provides conformance to the special test sequence, the test sequence must be verified to be correctly loaded into the RWM prior to control rod movement. This Surveillance demonstrates compliance with SR 3.3.2.1.8, thereby demonstrating that the RWM is OPERABLE. A Note has been added to indicate that this Surveillance does not need to be performed if SR 3.10.7.1 is satisfied.

REFERENCE 1. FSAR 15.4.9

2. XN-NF-80-19(P)(A) Volume 1 and Supplements 1 and 2, "Exxon Nuclear Methodology for Boiling Water Reactors," Exxon Nuclear Company, March 1983.

SUSQUEHANNA - UNIT I TS / B 3.10-32 Revision 2

ML061210062

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