Text

Revisions to Technical Specification Bases Unit 1 Manual
	ML081270181
Person / Time
Site:	Susquehanna
Issue date:	04/24/2008
From:	Gerlach R; Susquehanna
To:	Gerlach R; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML081270181 (279)
	v • d • e

Apr. 24, 2008 Page 1 of 6 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2008-22295 USER INFORMATION:

GERLACH*ROSE M EMPL#:028401 CA#: 0363 Address: NUCSA2 Phone#: 254-3194 TRANqMTTTAT, TNFnRMATTCN:

TO: GERLACH*ROSE M 04/24/2008 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, UPDATE DOCUMENT ID IS THE SAME DOCUMENT ID YOU'RE REMOVING FROM YOUR MANUAL.

ENSURE THE FROM THE HUMAN PERFORMANCE TOOL BAG SHOULD BE UTILIZED TO ELIMINATE THE CHANCE OF TOOLS ERRORS.

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

TSBI - TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL REMOVE MANUAL TABLE OF CONTENTS DATE: 04/14/2008 ADD MANUAL TABLE OF CONTENTS DATE: 04/23/2008 CATEGORY: DOCUMENTS TYPE: TSBI

/4o/

Apr. 24, 2008 Page 2 of 6 ID: TEXT 2.1.1 REMOVE: REV:3 ADD: REV: 4 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.1.7 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.2.1 ADD: REV: 2 REMOVE: REV:I CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.2.2 REMOVE: REV:1 ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.2.3 ADD: REV: 2 REMOVE: REV:1 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.2.4 ADD: REV: 3

Apr. 24, 2008 Page 3 of 6 REMOVE: REV:3 REMOVE: REV:2 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.3.1.1 ADD: REV: 4 REMOVE: REV:3 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.3.2.1 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.3.2.2 REMOVE: REV:0 ADD: REV: 1 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.3.3.1 ADD: REV: 7 REMOVE: REV:6 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.3.4.1 REMOVE: REV:0 ADD: REV: 1

Apr. 24, 2008 Page 4 of 6 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.3.6.1' ADD: REV: 4 REMOVE: REV:3 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.4.10 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSBI ID: TEXT 3.4.2 ADD: REV: 1 REMOVE: REV:0 CATEGORY: DOCUMENTS TYPE: TSBI ID: TEXT 3.4.3 ADD: REV: 2 REMOVE: REV:1 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.6.1.1 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSBI ID: TEXT 3.6.1.2

Apr. 24, 2008 Page 5 of 6 0

ADD: REV: 1 REMOVE: REV:0 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.6.1.3 REMOVE: REV:7 ADD: REV: 8 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.6.1.4 ADD: REV: 1 REMOVE: REV:0 CATEGORY: DOCUMENTS TYPE: TSBI

. ID: TEXT 3.6.2.1 REMOVE: REV:1 ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.7.6 ADD: REV: 2 REMOVE: REV:1 CATEGORY: DOCUMENTS TYPE: TSBI ID: TEXT 3.7.8

ADD: REV: 0 CATEGORY: DOCUMENTS TYPE: TSB1

Apr. 24, 2008 Page 6 of 6 ID: TEXT 3.8.3 REMOVE: REV:0 ADD: REV: 1 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT LOES ADD: REV: 88 REMOVE: REV:87 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT TOC REMOVE: REV:14 ADD: REV: 15 ANY DISCREPANCIES WITH THE MATERIAL PROVIDED, CONTACT DCS @ X3107 OR X3136 FOR ASSISTANCE.. UPDATES FOR HARDCOPY MANUALS WILL BE DISTRIBUTED WITHIN 3 DAYS IN ACCORDANCE WITH DEPARTMENT PROCEDURES. PLEASE MAKE ALL CHANGES AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX UPON COMPLETION OF UPDATES. FOR ELECTRONIC MANUAL USERS, ELECTRONICALLY REVIEW THE APPROPRIATE DOCUMENTS AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX.

SSES MANUAL Manual Name: TSBI Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL Table Of Contents Issue Date: 04/23/2008 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 88 04/23/2008

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 15 04/23/2008

Title:

TABLE OF CONTENTS TEXT 2.1.1 4 04/23/2008

Title:

SAFETY LIMITS (SLS) REACTOR CORE SLS, TEXT 2.1.2 1 10/04/2007

Title:

SAFETY LIMITS-(SLS) REACTOR COOLANT SYSTEM (RCS) PRESSURE S TEXT 3.0 2 ' 1,0/12/2006

Title:

LIMITING CONDITION FOR-OPERATION- (LCO) APPLICABILITY TEXT 3.1.1 ", 1 <'04/18/2006

Title:

REACTIVITY CONTROL SYSTEMS SHUTDOWN-MARGIN (SDM)

TEXT 3.1.2 0 11/15/2002

Title:

REACTIVITY 'CONTROL SYSTEMS REACTIVITY ANOMALIES TEXT 3.1.3 1 07/06/2005

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD OPERABILITY TEXT 3.1.4 3 09/29/2006

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3.1.5 1 07/06/2005

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3.1.6 2 04/18/2006

Title:

REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Report Date: 04/23/08 Page I1 of of .8 8 Report Date: 04/23/08

SSES MANUAL Manual Name:

Manual

Title:

TSB1 TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL 0

TEXT 3.1.7 3 04/23/2008

Title:

REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 2 10/04/2007

Title:

REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 2 04/23/2008

Title:

POWER DISTRIBUTION LIMITS AVERAGE PLANAR.LINEAR HEAT GENERATION RATE (APLHGR)

TEXT 3.2.2 2 04/23/2008

Title:

POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)

TEXT 3.2.3 2 04/23/2008

Title:

POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE (LHGR)

TEXT 3.3.1.1 4 04/a3/2008

Title:

INSTRUMENTATION REACTOR-PROTECTION SYSTEM (RPS) INSTRUMENTATION LDCN 3924 TEXT 3.3.1.2 1 04/12/2006

Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3.3.2.1 3 04/23/2008

Title:

INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 1 04/23/2008

Title:

INSTRUMENTATION FEEDWATER MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 7 04/23/2008

Title:

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

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 1 04/23/2008 " ..

Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATION Pag e 2 of 8. .,Report:Date: 04/23/08

SSES MANUAL

.* Manual Name:

Manual

Title:

TSB1 TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.3.4.2 0 11/15/2002

Title:

INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3.5.1 2 07/06/2005

Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 0 11/15/2002

Title:

INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION TEXT 3.3.6.1 4 04/23/2008

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.6.2 2 10/04/2007

Title:

INSTRUMENTATION-SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 1 10/Q4/2007

Title:

INSTRUMENTATION CONTROLROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 2 12/17/2007

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 1 04/23/2008

Title:

REACTOR COOLANT SYSTEM (RCS) JET PUMPS TEXT 3.4.3 2 04/23/2008

Title:

REACTOR COOLANT SYSTEM RCS SAFETY RELIEF VALVES S/RVS TEXT 3.4.4 0 11/15/2002

Title:

REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE Page 3 of 8 Report Date: 04/23/08

SSES MANJAL Manual Name: TSB1 Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.4.5 1 01/16/2006

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE TEXT 3.4.6 1 04/18/2005

Title:

REACTOR COOLANT SYSTEM (RCS). RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 2 10/04/2007

Title:

REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 1 04/18/2005

Title:

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

- HOT SHUTDOWN TEXT 3.4.9 0 11/15/2002

Title:

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

- COLD SHUTDOWN TEXT 3.4.10 3 04/2-3/2008

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 3 04/23/2008

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT TEXT 3.6.1.2 1 04/23/2008

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK Report Date: 04/23/08 Page Page44 of of 88 Report Date: 04/23/08

SSES MANUAL Manual Name: TSBI Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.1.3 8 04/23/2008

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

LDCN 3092 TEXT 3.6.1.4 1 04/23/2008

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 TEXT 3.6.2.1 2 04/23/2008

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE LDCN 3924 TEXT 3.6.2.2 0 11/1-5/2002

Title:

CONTAINMENT SYSTEMS SURPRESSION POOL WATER LEVEL TEXT 3.6.2.3 1 01/16/2006

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 0 11/15/2002

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 2 06/13/2006

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT HYDROGEN RECOMBINERS TEXT 3.6.3.2 1 04/18/2005

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM TEXT 3.6.3.3 0 11/15/2002

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 7 10/04/2007

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT Report Date: 04/23/08 PageS Page 5 of of8 *~

Report Date: 04/23'/08-

SSES MANUAL Manual Name: TSB1 Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.4.2 2 01/03/2005

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT 3.6.4.3 4 09/21/2006

Title:

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 1 12/17/2007

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 11/1-5/2002

Title:

PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 1 10/04/2007

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 2 04/23/2008

Title:

PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 1 10/04/2007

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.7.8 0 04/23/2008

Title:

PLANT SYSTEMS TEXT 3.8.1 5 12/17/2007

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 0 11/15/2002

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN Report Date: 04/23/08 Page66 Page of 8 of8 Report Date: 04/23/08

SSES MANUAL Manual Name: TSB1 Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.8.3 1 04/23/2008

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR TEXT 3.8.4 2 12/14/2006

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 1 12/14/2006

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN TEXT 3.8.6 1 12/14/2006

Title:

ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS TEXT 3.8.7 1 10/05/2005

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - OPERATING TEXT 3.8.8 0 11/15/2002

Title:

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

Title:

REFUELING )PERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9 .2 0 11/15/2002

Title:

REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 0 11/15/2002

Title:

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

Title:

REFUELING OPERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0 11/15/2002

Title:

REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 1 10/04/2007

Title:

REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL Report Date: 04/23/08 Page Page77 of 8 of3 Report Date: 04/23/08

SSES MANUJAL Manual Name: TSB1 Manual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.9.7 0 11/15/2002

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.8 0 11/15/2002

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 1 01/23/2008

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/L5/2002

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: 04/23/08 Page Page~8 of 8 of8 Report Date: 04/23/08

TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)

B2.0 SA FETY LIM ITS (S Ls) .................................................................................. B2.0-1 B2.1.1 R eactor C ore S Ls ........................................................................... B2.0-1 B2.1.2 Reactor Coolant System (RCS) Pressure SL ........................... TS/B2.0-7 B3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ....... TS/B3.0-1 B3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ...................... TS/B3.0-10 B3.1 REACTIVITY CONTROL SYSTEMS .................................................... B3.1-1 B3.1.1 Shutdow n M argin (SDM ) ................................................................ B3.1-1 B3.1.2 R eactivity A nom alies ...................................................................... B3.1-8 B3.1.3 Control Rod OPERABILITY ........................... B3.1-13 B3.1.4 Control Rod Scram Times ........................................... *.......... TS/B3.1-22 B3.1.5 Control Rod Scram Accumulators .................... TS/B3.1-29 B3.1.6 Rod Pattern Control .................................................................. TS/B3.1-34 B3.1.7 Standby Liquid Control (SLC) System ...................................... TS/B3.1-39 B3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves .......... TS/B3.1-47 B3.2 POWER DISTRIBUTION LIMITS ................................................... TS/B3.2-1 B3.2.1 Average Planar Linear Heat Generation Rate (APLHGR). ....... TS/B3.2-1 B3.2.2 Minimum Critical Power Ratio (MCPR) ..................................... TS/B3.2-5 B3.2.3 Linear Heat Generation Rate (LHGR) .................. TS/B3.2-10 B3.3 INSTRUMENTATION ..................................................... TS/B3.3-1 B3.3.1.1 Reactor Protection System (RPS). Instrumentation ................... TS/B3.3-1 B3.3.1.2 Source Range Monitor (SRM) Instrumentation ......................... TS/B3.3-35 B3.3.2.1 Control Rod Block Instrumentation .......................................... TS/B3.3-44 B3.3.2.2 Feedwater - Main Turbine High Water Level Trip Instrum entation ......................................................................... B3.3-55 B3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ..................... TS/B3.3-64 B3.3.3.2 Remote Shutdown System ............................................................. B3.3-76 B3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrum entation ......................................................................... B3.3-8 1 B3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation .............................. TS/B3.3-92 B3.3.5.1 Emergency Core Cooling System (ECCS)

Instrum entation ......................................................................... B 3.3-10 1 B3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrum entation ......................................................................... B3.3-135 B3.3.6.1 Primary Containment Isolation Instrumentation .............................. B3.3-147 B3.3.6.2 Secondary Containment Isolation Instrumentation ................... TS/B3.3-180 B3.3.7.1 Control Room Emergency Outside Air Supply (CREOAS)

System Instrum entation ............................................................ B3.3-192 (continued)

SUSQUEHANNA - UNIT 1 TS / B TOC - 1 Revision 15

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 Mo nito ring ................................................................................ B3 .3-2 13 B3.4 REACTOR COOLANT SYSTEM (RCS) ............................................... B3.4-1 B3.4.1 Recirculation Loops Operating ....................................................... B3.4-1 33.4 .2 Jet P um ps ...................................................................................... B 3.4-1 0 B3.4.3 Safety/Relief Valves (S/RVs) .................................................... TS/13.4-15 B3.4.4 RCS Operational LEAKAGE .......................................................... B3.4-19 B3.4.5 RCS Pressure 'Isolation Valve (PIV) Leakage ................................. B3.4-24 B3.4.6 RCS Leakage Detection Instrumentation ........................................ B3.4-30 B3.4.7 RCS Specific Activity ................................................................ TS/B3.4-35 B3.4.8 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown .............................................................. B3.4-39 B3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown ......................................................... B3.4-44 B3.4.10 RCS Pressure land Temperature (P/T) Limits ........................... TS/B3.4-49 B3.4.11 Reactor Steam Dome Pressure ................................................ TS/B3.4-58 63.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM.................... B3.5-1 63.5.1 ECCS - Operating ......................................................................... B3.5 B3.5.2 ECCS - Shutdown........... : ........................................................... B3.5-19 B3.5.3 RCIC System ........................................................................... TS/B3.5-25 B3.6 CONTAINMENT SYSTEMS .......................................................... TS/B3.6-1 B3.6.1.1 Primary Containment ................................................................ TS/B3.6-1 B3.6.1.2 Primary Containment Air Lock ........................................................ B3.6-7 B3.6.1.3 Primary Containment Isolation Valves (PCIVs) ......................... TS/B3.6-15 B3.6.1.4 Containment Pressure ................................................................... B3.6-41 B3.6.1.5 Drywell Air Temperature ........................................................... TS/B3.6-44 B3.6.1.6 Suppression Chamber-to-Drywell Vacuum Breakers ................ TS/B3.6-47 B3.6.2.1 Suppression Pool Average Temperature .................................. TS/B3.6-53 B3.6.2.2 Suppression Pool Water Level ....................................................... B3.6-59 B3.6.2.3 Residual Heat Removal (RHR) Suppression Pool C o o ling ..................................................................................... B 3 .6 -62 B3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray ................ B3.6-66 B 3.6.3.1 Not Used ................................................................................. T S/B3.6-70 B3.6.3.2 Drywell Air Flow System ................................................................. B3.6-76 B3.6.3.3 Primary Containment Oxygen Concentration .................................. B3.6-81 B3.6.4.1 Secondary Containment ........................................................... TS/B3.6-84 B3.6.4.2 Secondary Containment Isolation Valves (SCIVs) ......... TS/B3.6-91 B3.6.4.3 Standby Gas Treatment (SGT) System ................................... TS/B3.6-101 (continued)

SUSQUEHANNA - UNIT 1 TS / B TOC - 2 Revision 15

TABLE OF CONTENTS (TECHNICAL SPECIFICATIONS BASES)

B3.7 PLANT SYSTEM S ....................................................................... TS/B3.7-1 B3.7.1 Residual Heat Removal Service Water (RHRSW) System and the Ultimate Heat Sink (UHS) ...................................... TS/B3.7-1 B3.7.2 Emergency Service Water (ESW) System ................................ TS/B3.7-7 B3.7.3 Control Room Emergency Outside Air Supply (C REOAS) System ............................................................. TS/B3.7-12 B3.7.4 Control Room Floor Cooling System ........................................ TS/B3.7-19 B3.7.5 Main Condenser Offgas ........................................................... TS/B3.7-24 B3.7.6 Main Turbine Bypass System ................................................... TS/B3.7-27 B3.7.7 Spent Fuel Storage 0

Pool Water Level ...................................... TS/B3.7-31 B3.8 ELECTRICAL POWER SYSTEM ................................................... TS/B3.8-1 B3.8.1 AC Sources - Operating .......................................................... TS/B3.8-1 B3.8.2 AC Sources - Shutdown ............................ ......... B3.8-38 B3.8.3 Diesel Fuel Oil!. Lube Oil, and Starting Air ...................................... B3.8-45 B3.8.4 DC Sources - Operating .......................................................... TS/B3.8-54 B3.8.5 DC Sources - Shutdown ................................................................ B3.8-66 B3.8.6 Battery Cell Param eters ................................................................ B3.8-71 B3.8.7 Distribution Systems - Operating ................................................... B3.8-78 B3.8.8 Distribution Systems - Shutdown ........................ I .... B3.8-86 B3.9 REFUELING OPERATIONS ................... TS/B3.9-1 B3.9.1 Refueling Equipment Interlocks .................................................. TS/B3.9-1 B3.9.2 Refuel Position One-Rod-Out Interlock .......................................... B3.9-5 B3.9.3 C ontrol Rod Position ...................................................................... B3.9-9 B3.9.4 Control Rod Position Indication ......................... 3.9-12 B3.9.5 Control Rod OPERABILITY- Refueling ......................................... B3.9-16 B3.9.6 Reactor Pressure Vessel (RPV) Water Level ........................... TS/B3.9-19 B3.9.7 Residual Heat Removal (RHR) - High Water Level ........... B3.9-22 B3.9.8 Residual Heat Removal (RHR) - Low Water Level ......................... B3.9-26 B3.10 SPECIAL OPERATIONS ............................................................... TS/B3.10-1 B3.10.1 Inservice Leak and Hydrostatic Testing Operation ................... TS/B3.10-1 B3.10.2 Reactor Mode Switch Interlock Testing .......................................... B3.10-6 B3.10.3 Single Control Rod Withdrawal - Hot Shutdown ............................. B3.10-11 B3.10.4 Single Control Rod Withdrawal - Cold Shutdown ........................... B3.10-16 B3.10.5 Single Control Rod Drive (CRD) Removal - Refueling ................... B3.10-21 B3.10.6 Multiple Control Rod Withdrawal - Refueling .................................. B3.10-26 B3.10.7 Control Rod Testing - Operating .................................................... B3.10-29 B3.10.8 SHUTDOWN MARGIN (SDM) Test - Refueling .............. B3.10-33 TSB1 Text TOC 4/10/08 SUSQUEHANNA - UNIT 1 TS I B TOC -3 Revision 15

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

Section Title Revision TOC Table of Contents 15 B 2.0 SAFETY LIMITS BASES Page B 2.0-1 0 Page TS / B 2.0-2 3 Page TS / B 2.0-3 5 Page TS / B 2.0-4 3 Page TS / B 2.0-5 4 Page TS / B 2.0-6 1 Pages TS / B 2.0-7 through TS / B 2.0-9 1 B 3.0 LCO AND SR APPLICABILITY BASES Page TS / B 3.0-1 1 Pages TS / B 3.0-2 through TS / B 3.0-4 0 Pages TS / B 3.0-5 through TS / B 3.0-7 1 Pages TS / B 3.0-8 through TS / B 3.0-9 2 Page TS / B 3.0-10 1 Page TS / B 3.0-11 2 Page TS / B 3.0-1 la 0 Page TS/ B 3.0-12 1 Pages TS I B 3.0-13 through TS / B 3.0-15 2 Pages TS / B 3.0-16 and TS / B 3.0 0 B 3.1 REACTIVITY CONTROL BASES-Pages B 3.1-1 through B 3.1-4 0 Page TS / B 3.1-5 1 Pages TS / B 3.1-6 and TS / B 3.1-7 2 Pages B 3.1-8 through B 3.1-13 0 Page TS / B 3.1-14 1 1 Pages B 3.1-15 through B 3.1-21 0 Page TS /-B 3.1-22 0 Page TS / B 3.1-23'! 1 Page TS / B 3.1-24 0 Page TS / B 3.1-25 1 Page TS / B 3.1-26 0 Page TS / B 3.1-27 1 Page TS / B 3.1-28 2 Page TS / B 3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.3-34. through TS / B 3.3-36 1 Pages TS / B 3.1-37 and TS / B 3.1-38 2 Page TS / B 3.1-39 and TS / B 3.1-40 2 Page TS / B 3.1.40c- 0 Pages TS / B 3.1.41 and TS / B 3.1-42 2 Page TS / B 3.1.43 1 Page TS / B 3.1-44' 0 LOES-1 Revision 88 SUSQUEHANNA -UNIT SUSQUEHANNA - UNIT 11 TS /I B TS B LOES-1 Revision 88

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

Section Title Revision Page TS / B 3.1-45 3 Pages TS / B 3.1-46 through TS / B 3.1-49 1 Page TS / B 3.1-50 0 Page TS / B 3.1-51 2 B 3.2 POWER DISTRIBUTION LIMITS BASES Page TS / B 3.2-1 2 Pages TS / B 3.2-2 and TS / B 3.2-3 3 Pages TS / B 3.2-4 and TS / B 3.2-5 2 Page TS / B 3.2-6 3 Page B 3.2-7 1 Page TS / B 3.2-8 3 Pages TS / B 3.2-9 and TS / B 3.2.10 2 Page TS / B 3.2-11 3 Page TS / B 3.2-12 1 Page TS / B 3.2-13 2 B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through-TS / B 3.3-4 1 Page TS / B 3.3-5 2 Page TS / B 3.3-6 1 Page TS /B 3.3-7 3 Page TS /B 3.3-7a 1 Page TS / B 3.3-8 - 4 Pages TS / B 3.3-9 through TS / B 3.3-12 3 Pages TS / B 3.3-12a 1 Pages TS / B 3.3-12b and TS / B 3.3-12c 0 Page TS / B 3.3-13 1" Page TS / B 3.3-14 3 Pages TS / B 3.3-15 and TS / B 3.3-16 1 Pages TS / B 3.3-17 and TS / B 3.3-18 4 Page TS / B 3.3-19 1 Pages TS /B 3.3-20 through TS / B 3.3-22 2 Page TS / B 3.3-22a 0 Pages TS / B 3.3-23 and TS / B 3.3-24 2 Pages TS / B 3.3-24a and TS / B 3.3-24b 0 Page TS / B 3.3-25 3 Page TS / B 3.3-26 2 Page TS / B 3.3-27 1 Pages TS / B 3.3-28 through TS / B 3.3-30 3 Page TS / B 3.3-30a 0 LOES-2 Revision 88 SUSQUEHANNA - UNIT SUSQUEHANNA -

UNIT 1 1 TS I/ B TS B LOES-2 Revision 88

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

Section Title Revision Page TS / B 3.3-31 4 Page TS / B 3.3-32 5 Pages TS / B 3.3-32a 0 Page TS /B 3.3-32b 1 Page TS / B 3.3-33 5 Page TS /'B 3.3-33a 0 Page TS / B 3.3-34 1 Pages TS / B 3.3-35 and TS / B 3.3-36 2 Pages TS / B 3.3-37 through TS / B 3.3-43 1 Page TS / B 3.3-44 4 Pages TS / B 3.3-44a and TS / B 3.3-44b 0 Page TS / B 3.3-45 3 Pages TS / B 3.3-45a and TS / B 3.3-45b 0 Page TS / B 3.3-46 3 Pages TS / B 3.3-47 . 2 Pages TS / B 3.3-48 through TS / B 3.3-51 3 Pages TS / B 3.3-52 and TS / B 3.3-53 2 Page TS / B 3-3-53a, 0 Page TS / B 3.3-54 4 Page B 3.3-55 1 Page B 3.3-56 0 Page B 3.3-57 - . 1 Page B 3.3-58 0 Page B 3.3-59 1 Pages B 3.3-60 through B 3.3-63 0 Pages TS / B 3.3-64 and TS / B 3.3-65 2 Page'TS / B 3.3-66 4 Page TS/ B 3.3-67 3 Page TS / B 3.3-68 4 Page TS / B 3.3-69 5 Pages TS / B 3.3-70 4 Page TS / B 3.3-71 3 Pages TS / B 3.3-72 and TS / B 3.3-73 2 Page TS / B 3.3-74 3 Page TS / B 3.3-75 2 Pages TS / B 3.3-75a and TS / B 3.3-75b 6 Page TS / B 3.3-75c 5 Pages B 3.3-76 through 3.3-77 0 Page TS / B 3.3-78 1 Pages B 3.3-79 through B 3.3-81 0 Page B 3.3-82 1 Page B 3.3-83 0 Pages B 3.3-84 and B 3.3-85 1 Page B 3.3-86 0 Page B 3.3-87 1 SUSQUEHANNA - UNIT 1 TS / B LOES-3 Revision 88

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

Section Title Revision Page B 3.3-88 0 Page B 3.3-89 1 Page TS / B 3.3-90 1 Page B.3.3-91 0.

Pages TS / B 3.3-92 through TS / B 3.3-100 1 Pages B 3.3-101 through B 3.3-103 0 Page TS / B 3.3-104 1 Pages B 3.3-105 and B 3.3-106 0 Page TS / B 3.3-107 1 Page B 3.3-108 0 Page TS / B 3.3-109 1 Pages B 3'.3-110 and B 3.3-111 0 Pages TS / B 3.3-112 and TS / B 3.3-112a 1 Pages TS / B 3.3-113 through TS / B 3.3-115 1 Page TS / B 3.3-116 2 Page TS / B 3.3-117 1 Pages B 3.3-118 through B 3.3-122 0 Pages TS / B 3.3-123 and TS / B 3.3-124 1 Page TS B 3.3-124a 0 Page B 3.3-125 0 Pages TS iB 3.3-126 and TS/ B 3.3-127 1 Pages B 3.3-128 throughl B 3.3-130 - 0 Page TS/B 3.3-131, . 1 Pages B 3.3-132 through B 3.3-137 - 0 Page TS /'B 3.3-138- 1 Pages B 3.3-139 through B 3.3-149 0 Pages TS / B 3.3-150 and TS / B 3.3-151 1 Pages TS / B 3.3-152 through TS / B 3.3-154 2 Page TS / B 3.3-155 1 Pages TS / B 3.3-156 through TS / B 3.3-158 2 Pages TS / B 3.3-159 through TS / B 3.3-162 1 Page TS / B 3.3-163 2 Pages TS / B 3.3-164 and TS / B 3.3-165 1 Pages TS /B 3.3-166 and TS / B 3.3-167 2 Pages TS!/ B 3.3-168 and TS / B 3.3-169 1 Page TS / B 3.3-170" 2 Pages TS / B 3.3-171 through TS / B 3.3-177 1 Pages TS,/ B 3.3-178 through TS / B 3.3-179a 2 Pages TS / B 3.3-179b and TS / B 3.3-179c 0 Page TS / B 3.3-180 1 Page TS / B 3.3-181 3 Page TS / B 3.3-182 1 Page TS / B 3.3-183 2 Page TS / B 3.3-184 1 Page TS / B 3.3-185,, 2 Revision 88 SUSQUEHANNA SUSQUEHANNA -UNIT- UNIT 11 TS B LOES-4 TS // B LOES-4 Revision 88

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

Section Title Revision Page TS / B 3.3-186 1 Pages TS / B 3.3-187 and TS / B 3.3-188 2 Pages TS / B 3.3-189 through TS / B 3.3-191 1 Page TS / B 3.3-192 0 Page TS / B 3.3-193 1 Pages TS / B 3.3-194 and TS / B 3.3-195 0 Page TS / B 3.3-196 1 Pages TS / B 3.3-197 through TS / B 3.3-204 0 Page TS / B 3.3-205 1 Pages B 3.3-206 thri ugh B 3.3-209 0 Page TS / B 3.3-210 1 Pages B 3.3-211 through B 3.3-219 0 B 3.4 REACTOR COOLANT SYSTEM BASES Pages B 3.4-1 and Bq 3.4-2 0 Pages TS / B 3.4-3 and Page TS / B 3.4-4 4 Pages TS / B 3.4-5 through TS / B 3.4-9 2 Pages B 3.4-10 through B 3.4-12 0 Page B 3.4-13 1 Page B 3.4-14 ,,0 Page TS / B 3.4-15 2 Pages TS / B 3.4-16-and-TS / B 3.4-17 3 Page TS / B 3.4-18 2 Pages B 3.4-19 through B 3.4-27 0 Pages TS / B 3.4-28 and TS / B 3.4-29 1 Pages B 3.4-30 and B 3.4-31 0 Page TS / B 3.4-32 1 Pages B 3.4-33 and B 3.4-34 0 Pages TS / B 3.4-35 and TS / B 3.4-36 1 Page TS /.B 3.4-37 2 Page TS / B 3.4-38 1 Pages B 3.4-39 and B 3.4-40 0 Page TS / B 3.4-41 1 Pages B 3.4-42 through B 3.4-48 0 Page TS / B 3.4-49 3 Page TS / B 3.4-50 1 Page TS / B 3.4-51 3 Page TS / B 3.4-52 2 Page TS /1B 3.4-53 1 Pages TS / B 3.4-54,through TS / B 3.4-56 2 Page TS / B 3.4-57 3 Pages TS / B 3.4-58 through TS / B 3.4-60 1 Revision 88 SUSQUEHANNA - UN!IT 1~

SUSQUEHANNA~UNIT 1' /B TS /

TS B LOES-5 LOES-5 Revision 88

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (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/B3.5-4 1 Page TS / B 3.5-5 2 Page TS / B 3.5-6 1 Pages B 3.5-7 through B 3.5-10 0 Page TS / B 3.5-11 1 Page TS / B 3.5-12 0 Page TS / B 3.5-13 1 Pages TS / B 3.5-14 and TS / B 3.5-15 0 Pages TS / B 3.5-16 through TS / B 3.5-18 1 Pages B 3.5-19 through B 3.5-24 0 Page TS / B 3.5-25 1 Pages TS / B 3.5-26 and TS / B 3.5-27 1 Pages B 3.5-28 through B 3.5-31 0 B 3.6 CONTAINMENT SYSTEMS BASES Page TS / B 3.6-1 2 Page TS-/B 3.6-1a 3 Page TS / B 3.6-2 4 Page TS / B 3.6-3 3 Page TS / B 3.6-4 - 4 Pages TS / B 3.6-5 and TS /B 3.6 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 0 Page B 3.6-8 1 Pages B 3.6-9 through B 3.6-14 0 Page TS /B 3.6-15 2 Page TS / B 3.6-15a 0 Page TS / B 3.6-15b 2 Pages TS / B 3.6-16 and TS / B 3.6-17 1 Page TS / B 3.6-17a 0 Pages TS / B 3.6-18 and TS / B 3.6-19 0 Page TS / B 3.6-20 1 Page TS / B 3.6-21 2 Page TS / B 3.6-22 1 Page TS / B 3.6-22a 0 Page TS / B 3.6-23 1 Pages TS / B 3.6-24 and TS / B 3.6-25 0 Pages TS / B 3.6-26 and TS / B 3.6-27 2 Page TS / B 3.6-28 7 Page TS / B 3.6-29 2 Page TS / B 3.6-30 1 TS/BLOES-6 Revision 88 SUSQUEHANNA-UNITi SUSQUEHANNA - UNIT 1 1, TS / B LOES-6 Revision 88

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

Section Title Revision Page TS / B 3.6-31 3 Page TS / B 3.6-32 0 Page TS /:B 3.6-33 1 Pages TS / B 3.6-34 and TS / B 3.6-35 0 Page TS / B 3.6-36 1 Page TS lIB 3.6-37 0 Page TS/ 1B 3.6-38 3 Page TS [B 3.6-39 2 Page TS/:B 3.6-40 6 Page B 3.6-41 1 Pages B 3.6-42 and 13 3.6-43 3 Pages TS / B 3.6-44 "and TS / B 3.6-45 1 Page TS / B 3.6-46 2 Pages TS / B 3.6-47,through TS / B 3.6-51 1 Page TS /!B 3.6-52 2 Pages TS 1/B 3.6-53 through TS / B 3.6-56 0 Page TS / B 3.6-57 1 Page TS /:3.6-58 2 Pages B 3.6-59 throuigh B 3.6-63 0 Pages TS IIB 3.6-649and TS / B 3.6-65 1 Pages B 3.6-66 through B 3.6-69 0 Pages TS / B 3.6-70,through TS / B 3.6-72 1 Page TS B 3.6-73 2 Pages TS /1B 3.6-74 and TS / B 3.6 1 Pages B 3.6-76 and-B 3.6-77 0 Page TS / B 3.6-78 1 Pages B 3.6-79 through B 3.3.6-83, - 0 Page TS/ fB 3.6-84 3 Page TS /I B 3.6-85 2 Page TS /t 3.6-86 4 Pages TS / B 3.6-87"through TS / B 3.6-88a 2 Page TS / B 3.6-89 4 Page TS / B 3.6-90 l 2 Page TS /B 3.6-91 3 Pages TS'/ B 3.6-92,,through TS / B 3.6-96 1 Page TS / B 3.6-97 2 Pages TS1/ B 3.6-98 and TS / B 3.6-99 1 Page TS/ B 3.6-100, 2 Pages TSJ/ B 3.6-101 and TS / B 3.6-102 1 Pages TS / B 3.6-10:3 and TS / B 3.6-104 2 Page TS [] 3.6-105 3 Page TS /B 3.6-106, 2 Page TS/ B 3.6-107 3 Revision 88 SUSQUEHANNA - UNIT SUSQUEHANNA -

UNIT 11 TS /I B TS LOES-7 B LOES-7 Revision 88

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

Section Title Revision B 3.7 PLANT SYSTEMS BASES Pages TS / B 3.7-1 3 Page TS / B 3.7-2 4 Pages TS / B 3.7-3 through TS / B 3.7-5 3 Page TS / B 3.7-5a 0 Pages TS / B 3.7-6 and TS / B 3.7-6a 2 Pages TS / B 3.7-6b and TS / B 3.7-6c 1 Page TS / B 3.7-7 3 Page TS / B 3.7-8 2 Pages TS / B 3.7-9 through TS / B 3.7-13 1 Pages TS / B 3.7-14 through TS / B 3.7-18 2 Page TS / B 3.7-18a 0 Pages TS / B 3.7-19 through TS / B 3.7-23 1 Page TS / B 3.7-24 1 Pages TS: / B 3.7-251 and TS / B 3.7-26 0 Pages TS' / B 3.7-27 through TS / B 3.7-29 5 Page TS / B 3.7-30 2 Page TS-/ B 3.7-31 1 Page TS l B 3.7-32 0 Page TS /B 3.7-33 1 Pages TS / B 3.7-34 through TS./ B 3.7-37 .0 B 3.8 ELECTRICAL POWER SYSTEMS BASES-*

Pages TS / B 3.8-1 through TS / B 3.8-3 2 Page TS / B 3.8-4 3 Pages TS / B 3.8-4a and TS I B 3.8-4b 0 Page TS / B 3.8-5 5 Page TS / B 3.8-6 3 Pages TS / B 3.8-7 through TS/B 3.8-8 2 Page TS / B 3.8-9 4 Page TS / B 3.8-10 3 Pages TS / B 3.8-11land TS / B 3.8-17 2 Page TS / B 3.8-18 3 Pages TS / B 3.8-19 through TS / B 3.8-21 2 Pages TS / B 3.8-22 and TS / B 3.8-23 3 Pages TS / B 3.8-24. through TS / B 3.8-37 2 Pages B 3.8-38 through B 3.8-44 0 Page TS / B 3.8-45 1 Pages TS / B 3.8-46 through B 3.8-48 0 Page TS / B 3.8-49 1, Pages B 3.8-50 through B 3.8-53 0 Pages TS / B 3.8-54. through TS / B 3.8-61 2 Pages TS / B 3.8-62 and TS / B 3.8-63 4 Page TS / B 3.8-64 3 SUSQUEHANNA - UNIT 1ISBOS8 TS / B LOES-8 eiin8 88 Revision

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

Section Title Revision Page TS / B 3.8-65 4 Pages TS / B 3.8-66 through TS / B 3.8-77 1 Pages TS / B 3.8-77A through TS / B 3.8-77C 0 Pages B 3.8-78 through B 3.8-80 0 Page TS / B 3.8-81 1 Pages B 3.8-82 through B 3.8-90 0 B 3.9 REFUELING OPERATIONS BASES Pages TS / B 3.9-1 and TS / B 3.9-1a 1 Pages TS / B 3.9-2 through TS / B 3.9-4 1 Pages B 3.9-5 through B 3.9-18 0 Pages TS / B 3.9-19 through TS / B 3.9-21 1 Pages B 3.9-22 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES Page TS /B 3.10-1 I 2 Pages TS / B 3.10-2 through TS / B 3.10-5 1 Pages B 3.10-6 through B 3.10-31 0 Page TS/ B 3.10-32 2 Page B 3.10-33 0 Page TS / B 3.10 1 Pages B 3.10-35 and B 3.10-36 0 Page TS / B 3.10-37' 1 Page TS / B 3.10-38 -, 2 TSB1 Text LOES.doc 4/10/08 TS/BLOES-9 Revision 88 SUSQUEHANNA - UNIT SUSQUEHANNA -

UNIT 11 TS / B LOES-9 Revision 88

PPL Rev. 4 Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs)

B 2.1.1 Reactor Core SLs BASES BACKGROUND GDC 10 (Ref. 1) requires, and SLs ensure, that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and anticipated operational occurrences (AOOs).

The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in Specification 2.1.1.2 for Siemens Power Corporation fuel. MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity.

The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related t6 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 therrial stresses, which occur from reactor operation significantly above design conditions.

While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration. -

Therefore, the fuel cladding SL is defined with a margin to the conditions that would produce onset of transition boiling (i.e., MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. The MCPR fuel cladding integrity SL ensures that during normal operation and during AOOs, at least 99.9% of the fuel rods in the core do not experience transition boiling.

(continued)

'-SUSQUEHANNA-INIT'1 .. TS7"B'2T0-1 Revision.0.

Revision 0 -

PPL Rev. 4 Reactor Core SLs B 2.1.1 BASES BACKGROUND Operation above the boundary of the nucleate boiling regime could (continued) result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant.

APPLICABLE The fuel cladding must not sustain damage as a result of normal SAFETY ANALYSES operation and 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 Claddina Intearitv The use of the SPCB (Reference 4) correlation is valid for critical power calculations at pressures - 571.4 psia and bundle mass fluxes

> 0.087; x 106 lb/hr-ft. For operation at low pressures or low flows, the fuel cladding integrity SL is established by a limiting condition on core THERMAL POWER, with the following basis:

Provided that the water level in the vessel downcomer is maintained above the top of the active fuel, natural circulation is sufficient to ensure a minimum bundle flow for all fuel assemblies that have a relatively high power and potentially can approach a critical heat flux condition.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 2.0-2 Revision 3

PPL Rev. 4 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES For the FANP ATRIUM-10 design, the minimum bundle flow is > 28 x 103 Ib/hr. For the ATRIUM-10 fuel design, the coolant minimum bundle flow and maximum area are such that the mass flux is always > .25 x 106 lb/hr-7ft. Full scale critical power test data taken from various SPC and GE fuel designs at pressures from 14.7 psia to 1400 psia indicate the fuel assembly critical power at 0.25 x 106 lb/hr-ft2 is approximately 3.35 MWt. At 23% RTP, a bundle power of approximately 3.35 MWt corresponds to a bundle radial peaking factor of approximately 2.8, which is significantly higher than the expected peaking factor. Thus, a THERMAL POWER limit of 23% RTP for reactor pressures < 785 psig is conservative and for conditions of lesser power would remain conservative.

2.1.1.2 MCPR The MCPR SL ensures sufficient conservatism in the operating MCPR limit that, in theevent of an AOO from the limiting condition of operation, at least 99.9% of -the fuel rods in tlhe core would be expected--

to avoid-boilihg transition. The margin between calculated boiling transition (i.e., MCPR = 1.00) and the-MCPR SL is based on a detailed statistical procedure that considers the uncertainties in monitoring the core operating state. One specific uncertainty included in the SL is the uncertainty in the critica[ power correlation. References 2, 4, and 5 describe the methodology used in determining the MCPR SL.

The SPCB critical power correlation is based on a significant body of practical test data. As long as the core pressure and flow are within the range of validity of the correlations (refer to Section B.2.1.1.1), the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and bounding flat local peaking distributions are used to estimate the number of rods in boiling transition. These conservatisms and the inherent accuracy of the SPCB correlation provide a reasonable degree of assurance that during sustained operation at the MCPR SL there would be no transition boiling in the core.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 2.0-3 Revision 5

PPL Rev. 4 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.2 MCPR (continued)

SAFETY ANALYSES If boiling transition were to occur, there is reason to believe that the integrity of the fuel would not be compromised.

Significant test data accumulated by the NRC and private organizations indicate that the use of a boiling transition limitation to protect against cladding failure is a very conservative approach. Much of the data indicate that BWR fuel can survive for an extended period of time in an environment of boiling transition.

SPC Atrium -10 fuel is monitored using the SPCB Critical Power Correlation. The effects of channel bow on MCPR are explicitly included in the calculation of the MCPR SL. Explicit treatment of channel bow in the MCPR SL addresses the concerns of NRC Bulletin No. 90-02 entitled "Loss of Thermal Margin Caused by Channel Box Bow."

Monitoring required for compliance with the MCPR SL is specified in '"

LCO 3.2.2, Mirhimum Critical Power Ratio.

2.1.1.3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability..

With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes < 2/3 of the core height.

The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be (continued)

SUSQUEHANNA - UNIT 1 TS / B 2.0-4 Revision 3

PPL Rev. 4 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.3 Reactor Vessel Water Level (continued)

SAFETY ANALYSES monitored and to also provide adequate margin for effective action.

SAFETY LIMITS The rea'ctor core SLsoare established to protect the integrity of the fuel clad barrier to the release of radioactive materials to the environs.

SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria. SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.

APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.

SAFETY LIMIT Exceeding an SL may cause fuel damage and create a potential for VIOLATIONS radioactive releases in excess of regulatory limits. Therefore, it is required to insert all insertable control rods and restore compliance

- .with the SLs within 2 hours2.314815e-5 days 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.

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

2. ANF 524 (P)(A), Revision 2, "Critical Power Methodology for Boiling Water Reactors," Supplement 1 Revision 2 and Supplement 2, November 1990.

3. Deleted.

4. EMF-2209(P)(A), Revision 1, "SPCB Critical Power Correlation," Siemens Power Corporation, July 2000.

5. EMF-2158(P)(A), Revision 0, "Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASMO-4/Microburn-B2," October 1999.

(continued)

SUSQEHANA -UNIT1 T/B2.-5 evison SUSQUEHANNA - UNIT 1 TS / B 2.0-5 Revision 4

PPL Rev. 4 Reactor Core SLs B 2.1.1 BASES THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 1 TS / B 2.0-6 Revision 1

PPL Rev. 3 SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BAS ES BACKGROUND The SLC System is designed to provide the capability of bringing the reactor, at "anytime in a fuel cycle, from full power and minimum control rod inventory to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement.

Additionally, the SLC System is designed to provide sufficient buffering agent to maintain the suppression pool pH at or above 7.0 following a DBA LOCA involving fuel damage. Maintaining the suppression pool pH at or above 7.0 will mitigate the re-evolution of iodine from the suppression pool water following a DBA LOCA. The SLC system satisfies the requirements of 10 CFR 50.62 (Ref. 1) for anticipated transient without scram.

The SLC System consists of a sodium pentaborate solution storage tank, two positive displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to

-transfer borated water from the storage tank to the reactor pressure vessel (RPV). The borated solution is discharged near the bottom of the-core shroud, where it then mixes with the eooling water rising through the -

core. A smaller tank containing demineralized water is provided for testing purposes.,

APPLICABLE The SLC System is manually initiated from the main control room, as SAFETY directed by the emergency operating procedures, if the operator believes ANALYSES the reactor cannot be shut down, or kept shut down, with the control rods or if fuel damage occurs post-LOCA. The SLC System is used in the event that enough control rods cannot be inserted to accomplish shutdown and cooldown in the normal manner or if fuel damage occurs post-LOCA. The SLC System injects borated water into the reactor core to add negative reactivity to compensate for all of the various reactivity effects that could occur during plant operations. To meet this objective, it is necessary to inject a quantity of enriched sodium pentaborate, which produces a concentration equivalent to 660 ppm of natural boron, in the reactor coolant at 680 F. To allow for potential leakage and imperfect mixing in the reactor system, an amount of boron equal to 25% of the amount cited above is added (Ref. 2). The volume versus concentration limits in Figure 3.1.7-1 and the temperature versus concentration limits in Figure 3.1.7-2 are calculated such that the required concentration is achieved accounting for dilution in the RPV with normal water level and including the water volume in (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-39 Revision 2

PPL Rev. 3 SLC System B 3.1.7 BASES APPLICABLE the residual heat removal shutdown cooling piping and in the recirculation SAFETY loop piping. This quantity of borated solution is the amount that is above ANALYSES the pump suction shutoff level in the boron solution storage tank. No (continued) credit is taken for the portion of the tank volume that cannot be injected.

The minimum concentration ensures compliance with the requirements of 10 CFR 50.62 (Ref. 1).

The SLC System is also used to control Suppression Pool pH in the event of a DBA LOCA by injecting sodium pentaborate into the reactor vessel.

The sodium pentaborate is then transported to the suppression pool and mixed by ECCS flow recirculation through the reactor, out of the break and into the suppression chamber. The amount of sodium pentaborate solution that must be available for injection following a DBA LOCA is determined as part of the DBA LOCA radiological analysis. This quantity is maintained in the storage tank as specified in the Technical Specification.

The SLC System satisfies the requirements of the NRC Policy Statement (Ref. 3) because operating experience and probabilistic risk assessments have shown the SLC System to be important to public health and safety.

-Thus, it is retained in the Technical Specifications.

LCO The OPERABILIITY of-the SLC System provides backup capability for reactivity control independent of normal reactivity control provisions provided by the control rods and provides sufficient buffering agent to maintain the suppression pool pH at or above 7.0 following a DBA LOCA involving fuel damage. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves. Two SLC subsystems are required to be OPERABLE; each contains an OPERABLE pump, an explosive valve, and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.

APPLICABILITY In MODES 1 and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn (except as permitted by LCO 3.10.3 and LCO 3.10.4) since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure that the reactor remains subcritical. In MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies.

Demonstration of adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") ensures that the reactor will not become critical. Therefore, the SLC System is not required to be OPERABLE when only a single control rod can be withdrawn.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-40 Revision 2

PPL Rev. 3 SLC System B 3.1.7 BASES APPLICABILITY A DBA LOCA that results in the release of radioactive material is possible (continued) in MODES 1, 2 and 3; therefore, capability to buffer the suppression pool pH is required. In MODES 4 and 5, a DBA LOCA with radioactive release need not be postulated.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-40a Revision 0

PPL Rev. 3 SLC System B 3.1.7 BASES ACTIONS A.1 If the boron solution concentration is not within the limits in Figure 3.1.7-1, the operability of both SLC subsystems is impacted and the concentration must be restored to within limits within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is considered acceptable given the low probability of an event occurring concurrent with the failure of the control rods to shut down the reactor.

If the boron solution concentration is >12 weight-percent with the tank volume > 1350 gallons, both SLC subsystems are operable as long as the temperature for the boron solution concentration is within the acceptable region of Figure 3.1.7-2. If the temperature requirements are not met, operability of both SLC subsystems is impacted and the concentration or solution temperature must be restored within limits within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

B.1 If one SLC subsystem is inoperable for reasons other than Condition A, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining OPERABLE subsystem is adequate to perform the I (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-41 Revision 2

PPL Rev. 3 SLC System B 3.1.7 BASES ACTIONS B.1 (continued) shutdown function and provide adequate buffering agent to the suppression pool. However, the overall reliability is reduced because a single failure in the remaining OPERABLE subsystem could result in reduced SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System functions and the low probability of an event occurring requiring SLC injection.

C.1 If-both SLC subsystems are inoperable for reasons other than Condition A, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is considered acceptable given the low probability of an event occurring requiring SLC injection.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-42 Revision 2

PPL Rev. 3 SLC System B 3.1.7 BASES ACTIONS D.1 (continued)

If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and 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.

SURVEILLANCE SR 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 are 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Surveillances verifying certain characterislfics of the SLC System (e.g., the volume and temperature of the borated, solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These

-Surveillances ensure that the proper borated solution volume and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in _ensuring that the sodium pentaborate remains in solution and does not precipitate out in the storage tank or in the pump suction piping. The temperature versus concentration curve of Figure 3.1.7-2 ensures that a 10OF margin will be maintained above the saturation temperature. An alternate method of performing SR 3.1.7.3 is to verify the OPERABILITY of the SLC heat trace system. This verifies the continuity of the heat trace lines and ensures proper heat trace operation, which ensure that the SLC suction piping temperature is maintained. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience and has shbwn there are relatively slow variations in the measured parameters of volume and temperature.

SR 3.1.7.4 and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-43 Revision 1

PPL Rev. 3 SLC System B 3.1.7 BASES SURVEILLANCE URVEQUIR NENS SR 3.1.7.4'and SR 3.1.7.6 (continued)

REQUIREMENTS operating experience and has demonstrated the reliability of the explosive charge continuity.

SR 3.1.7.6,verifies that each valve in the system is in its correct position, but does not apply to the squib (i.e., explosive) valves. Verifying the correct alignment for manual and power operated valves in the SLC System flow path provides assurance that the proper flow paths will exist for system operation. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position from the control room, or locally by a dedicated operator at the valve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance also does not apply to valves that are locked, sealed, or otherwise secured in position since they are verified to be in the correct position prior to locking, sealing, or securing. This verification of valve alignment does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are

-in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is based on engineering judgment and is consistent with the procedural.

controls governing valve operation -that ensures correct valve positions.

SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of sodium pentaborate exists in the storage tank.

SR 3.1.7.5 must be performed anytime sodium pentaborate or water is added to the storage tank solution to determine that the sodium pentaborate solution concentration is within the specified limits.

SR 3.1.7.5 must also be performed anytime the temperature is restored to within the limits of Figure 3.1.7-2, to ensure that no significant sodium pentaborate precipitation occurred. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of sodium pentaborate concentration between surveillances.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.1-44 Revision 0

PPL Rev. 3 SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.7, REQUIREMENTS (continued) Demonstrating that each SLC System pump develops a flow rate

> 40.0 gpm at a discharge pressure > 1250 psig without actuating the pump's relief valve ensures that pump performance has not degraded during the fuel cycle. Testing at 1250 psig assures that the functional capability of the SLC system meets the ATWS Rule (10 CFR 50.62) (Ref.

1) requirements. This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. Additionally, the minimum pump flow rate requirement ensures that adequate buffering agent will reach the suppression pool to maintain pH above 7.0. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect

-incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.

SR 3.1.7.8 and SR 3:1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or frQm another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 48 months at alternating 24 month intervals.

The Surveillance may be performed in separate steps to prevent injecting solution into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

Demonstrating that all heat traced piping between the boron solution storage tank and the suction inlet to the injection (continued)

. SUSQUEHANNA - UNIT 1 TS / B 3.1-45 Revision 3

PPL Rev. 3 SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.8 and SR 3.1.7.9 (continued)

REQUIREMENTS pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to pump from the storage tank to the test tank. This test can be performed by any series of overlapping or total flow path test so that the entire flow path is included.

The 24 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping. This is especially true in light of the temperature verification of this piping required by SR 3.1.7.3.

However, if, in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum or the heat trace was not properly energized and building temperature was below the temperature at which the SLC solution would precipitate out, SR 3.1.7.9 must be performed once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the piping temperature is restored to within the limits of Figure 3.1.7-2.

-SR 3.1.7.10 Enriched sodium pentaboratesolution is rmiade by mixing granular, enriched sodium.pentaborate with water. Verification of the actual B-10 enrichment must be performed prior to addition to the SLC tank in order to ensure that the proper B-10 atom percentage is being used. This verification may be based on independent isotopic analysis or a manufacturer certificate of.compliance.

REFERENCES 1. 10 CFR 50.62.

2. FSAR, Section 9.3.5.

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

SUSQUEHANNA - UNIT 1 TS / B 3.1-46 Revision 1

PPL Rev. 2 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 ATRIUMTM-10 fuel 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, 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, 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 modes in the development of the APLHGR limits (e.g., Maximum Extended Load Line Limit Analysis (MELLLA), Suppression Pool Cooling Mode, and Single Loop Operation (SLO)). LOCA analyses were performed for the regions of the power/flow map bounded by the rod line that runs through 100% RTP and maximum core flow and the upper boundary of the MELLLA region. The MELLLA region is analyzed to 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 flow are not required.

(continued)

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

PPL Rev. 2 APLHGR 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 Operation. The results of the SPC analysis for ATRIUMTM-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.

The APLHGR satisfies Criterion 2 of the NRC Policy Statement (Ref.

10).

LCO 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

< 23% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

ACTIONS A.1 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 3.272 Revision 3

PPL Rev. 2 APLHGR B 3.2.1 BASES 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 < 23% 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 < 23% 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 Ž>23% 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 44% 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 Ž_23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because the APLHGRs must be calculated prior to exceeding 44% RTP.

REFERENCES 1. Not used.

2. Not used.

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

Frarnatome ANP.

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

January 1991.

5. XN-CC-33(P)(A) Revision 1, "HUXY: A Generalized Multirod Heatup Code with 10CFR50 Appendix K Heatup Option Users Manual," November 1975.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.2-3 Revision 3

PPL Rev. 2 APLHGR B 3.2.1 BASES References 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).

SUSQUEHANNA - UNIT 1 TS / B 3.2-4 Revision 2

PPL Rev. 2 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 the 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 theBases 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.

APPLICABLE The analytical methods and assumptions used in evaluating the AOOs 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 transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of transients evaluated are loss of flow, increase in pressur'e and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change in CPR (ACPR). When the largest ACPR is added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.2-5 Revision 2

PPL Rev. 2 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).

LCO 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 and power dependent MCPR limits.

APPLICABILITY The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power levels. Below 23% RTP, the -

reactor is operating at a minimum recirculation pump speed and the

-moderator void ratio is small.. Surveillance of thermal limits below 23% RTP is unnecessary due to the large inherent margin that ensures- -

that the MCPR.SL isnot exceeded even if a limiting transient occurs.

Studies Of the variation of limiting transient behavior have been performed over the range of power and flow conditions. These studies encompass the range of key actual plant parameter values important to 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 23% RTP. This trend is expected to (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.2-6 Revision 3

PPL Rev. 2 MCPR B 3.2.2 BAS ES 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 THERMAL POWER levels < 23% 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 based 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 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 < 23% RTP within-4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.2.1 REQUIREMENTS 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 23% 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 44% 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 (continued)

SUSQUEHANNA - UNIT 1 B 3.2-7 Revision 1

PPL Rev. 2 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 _>23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because ethe MCPR must be calculated prior to exceeding 44% RTP.

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

SIR 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 Insertion Time 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 i1hour Completion Time is acceptable due to the relatively minor changes in average measured scram times expected during the fuel cycle.

REFERENCES 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)

SUSQUEHANNA - UNIT 1 TS / B 3.2-8 Revision 3

PPL Rev. 2 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 the 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),

S - ~ "Licensing Topical Report for Power Uprate With Increased Core Flow, Revision 0, Susquehanna Steam-Electric Station, Units 1 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 and 2, "XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis," February 1987.

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

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

SUSQUEHANNA - UNIT 1 TS / B 3.2-9 Revision 2

PPL Rev. 2 LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)

BASES BACKGROUND The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation. Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials.

Fuel design limits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the normal operations identified in Reference 1.

APPLICABLE The analytical methods and assumptions used in evaluating the fuel SAFETY system design are presented in References 1, 2, 3, and 4. The fuel ANALYSES assembly is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in excess of regulatory limits. The mechanisms that could cause fuel damage during operation-al transients and that are.

considered in fuel evaluations are:

a. RFupture of the fuel rod-cladding caused by strain from the relative expansion of the U0 2 pellet; and

b. Severe overheating of the fuel rod cladding caused by inadequate cooling.

I'A value of 1% plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 3).

Fuel design evaluations have been performed and demonstrate that the 1% fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the operating limit specified in the COLR. A separate evaluation was performed to determine the limits of LHGR during anticipated operational occurrences. This limit, (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.2-10 Revision 2

PPL Rev. 2 LHGR B 3.2.3 BASES APPLICABLE Protection Against Power Transients (PAPT), defined in Reference 4 SAFETY provides -the acceptance criteria for LHGRs calculated in evaluation of ANALYSES the AQOs.

(continued)

The LHGR satisfies Criterion 2 of the NRC Policy Statement (Ref. 7).

LCO The LHGR is a basic assumption in the fuel design analysis. The fuel has been, designed to operate at rated core power with sufficient design margin td the LHGR calculated to cause a 1% fuel cladding plastic strain. The operating limit to accomplish this objective is specified in the COLR.

APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels < 23% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore,; the Specification is only required when the reactor is operating at _>23%IRTP. -4 ACTIONS A.1 If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to 0J (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.2-11 Revision 3

PPL Rev. 2 LHGR B 3.2.3 BASES ACTIONS A.1 (continued) restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.

B.1 If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER is reduced to < 23% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . I The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE !-SR 3.2.3.1 REQUIREMENTS The LHGR is required to.be initially calculated within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is > 23% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

Additionally, LHGRs .must be calculated prior to exceeding 44% RTP unless performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The LHGR is compared to' the specified limits in the. COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slow changes in power distribution during normal operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

,. allowance after THERMAL POWER > 23% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels and because the LHGRs must be calculated prior to exceeding 44% RTP.

REFERENCES 1. FSAR, Section 4.

ýi2. FSAR, Section 5.

3. NUREG-0800,Section II.A.2(g), Revision 2, July 1981.

(continued)

SUSQUEHANNA - UNIT 1 UN- TS / B 3.2-12 Revision 1

PPL Rev. 2 LHGR B 3.2.3 BASES REFERENCES 4. ANF-89-98(P)(A) Revision 1 and Revision 1 Supplement 1, (continued) "Generic Mechanical Design Criteria for BWR Fuel Designs,"

Advanced Nuclear Fuels Corporation, May 1995.

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

II SUSQUEHANNA - UNIT 1 TS / B 3.2-13 Revision 2 IP 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) and minimize the energy that must be absorbed following a loss of coolant accident (LOCA).

This can be accomplished either automatically or manually.

The protection and monitoring functions of the RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters and equipment performance. The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold for protective system action to prevent

-exceeding acceptable limits, including Safety Limits (SLs) during Design '

Basis Accidents (DBAs). -

The RPS, as shown in-the FSAR, Figure 7.2-1 (Ref. 1), includes sensors, relays, bypass circuits, and-switches that are necessary to cause initiation of a reactor-scram. Functional diversity is provided by monitoring a wide range of dependent and independent parameters. The input parameters to the scram logic are from. instrumentation that monitors reactor vessel water level, reactor vessel pressure, neutron flux, main steam line isolation valve position, turbine control valve (TCV) fast closure trip oil pressure, turbine stop valve (TSV) position, drywell pressure, and scram discharge Volume (SDV) water level, as well as reactor mode switch in shutdown position and manual scram signals. There are at least four redundant sensor input signals from each of these parameters (with the exception of the reactor mode switch in shutdown scram signal). When the setpoint is reached, the channel sensor actuates, which then outputs an RPS trip signal to the trip logic. Table B 3.3.1.1-1 summarizes the diversity of sensors capable of initiating scrams during anticipated operating transients typically analyzed.

The RPS is comprised of two independent trip systems (A and B) with two logic channels in each trip system (logic (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-1 Revision R 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES BACKGROUND channels Al and A2, Bi and B2) as shown in Reference 1. The outputs (continued) of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as a one-out-of-two taken twice logic. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received. This 10 second delay on reset ensures that the scram function will be completed.

Two AC powered scram pilot solenoids are located in the hydraulic control unit for each control rod drive (CRD). Each scram pilot valve is operated with the solenoids normally energized. The scram pilot valves control the air supply to the scram inlet and outlet valves for the associated CRD.

When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram. The scram valves

-control the supply and discharge paths for the CRD water during a scram.

One of the scram pilot valve solenoids for each CRD is controlled by trip system A, and the other solenoid is controlled by trip system B. Any trip of trip system A inconjunction with any trip in trip system B results in de-energizi ng both solenoids, air bleeding off, scram valves opening, and control rod "scram.

The DC powered backup scram valves, which energize on a scram signal to depressurize the scram air header, are also controlled by the RPS.

Additionally, the RPS System controls the SDV vent and drain valves such that when both trip systems trip, the SDV vent and drain valves close to isolate the SDV.

APPLICABLE The actions of the RPS are assumed in the safety analyses of SAFETY References 3, 4, 5 and 6. The RPS initiates a reactor scram before the ANALYSES, monitored parameter values reach the Allowable Values, specified by the LCO, and setpoint methodology and listed in Table 3.3.1.1-1 to preserve the integrity APPLICABILITY of the fuel cladding, the reactor coolant pressure boundary (RCPB), and (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-2 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE the containment by minimizing the energy that must be absorbed following SAFETY a LOCA.

ANALYSES, LCO, and RPS instrumentation satisfies Criterion 3 of the NRC Policy Statement.

APPLICABILITY (Ref. 2)

(continued)

Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.1.1-1.

Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints within the specified Allowable Value, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time.

Allowable Values are specified for each RPS Function specified in the Table. Nominal trip setpoints are specified-in the. setpoint calculations.

The nominal setpoints-are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation witlh a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-3 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE instrument 'drift and severe environment errors (for channels that must SAFETY function in harsh environments as defined by 10 CFR 50.49) are ANALYSES, accounted for.

LCO, and APPLICABILITY The OPERABILITY of scram pilot valves and associated solenoids, (continued) backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO.

I The individ'ual Functions are required to be OPERABLE in the MODES specified in the table, which may require an RPS trip to mitigate the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to provide primary and diverse initiation signals.

The RPS is required to be OPERABLE in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.

Control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram. Provided all other control rods remain inserted, the RPS function is not required. In this condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS Will occur. During normal operation in MODES 3 and 4, all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control rod to be withdrawn. Under these conditions, the RPS function is not required to be OPERABLE. The exception to this is Special Operations (LCO 3.10.3 and LCO 3.10.4) which ensure compliance with appropriate requirements.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

Intermediate Range Monitor (IRM) 1.a. Intermediate Range Monitor Neutron Flux-High The IRMs monitor neutron flux levels from the upper range of the source range monitor (SRM) to the lower range of the average power range monitors (APRMs). The IRMs are capable of generating trip signals that can be used to prevent fuel (continued)

'-SUSQUEHANNA - UNIT 1 TS / B 3.3-4 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 1.a. Intermediate Range Monitor Neutron Flux-High (continued)

SAFETY ANALYSES, damage resulting from abnormal operating transients in the intermediate LCO, and power range. In this power range, the most significant source of reactivity APPLICABILITY change is clue to control rod withdrawal. The IRM provides diverse protection for the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low power. The RWM prevents the withdrawalof an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion (Ref. 5). The IRM provides mitigation of the neutron flux excursion. To demonstrate the capability of the IRM System to mitigate control rod withdrawal events, generic analyses have been performed (Ref. 3) to evaluate the consequences of control rod withdrawal events during startup that are mitigated only by the IRM. This analysis, which assumes that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local control rod withdrawal errors and results in peak fuel energy depositions below the 170 cal/gm fuel failure threshold

-criterion.

The IRMs are also capable of -limiting other reactivity excursions during startup, such as cold water injection events, although no credit is specifically- assumed. -

The IRM System is divided into two trip systems, with four IRM channels..

inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for IRM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This trip is active in each of the 10 ranges of the IRM, which must be selected by the operator to maintain the neutron flux within the monitored level of an IRM range.

The analysis of Reference 3 has adequate conservatism to permit an IRM Allowable Value of 122 divisions of a 125 division scale.

The Intermediate Range Monitor Neutron Flux-High Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential fodr criticality exists. In (continued)

SUSQUEHANNA - UlNIT 1 TS / B 3.3-5 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE l.a. Intermediate Range Monitor Neutron Flux-High (continued)

SAFETY ANALYSES, MODE 5, when a cell with fuel has its control rod withdrawn, the IRMs LCO, and provide monitoring for and protection against unexpected reactivity APPLICABILITY excursions. In MODE 1, the APRM System and the RWM provide protection against control rod withdrawal error events and the IRMs are not required. In addition, the Function is automatically bypassed when the Reactor Mode Switch is in the Run position.

1.b. Intermediate Range Monitor-Inop This trip signal provides assurance that a minimum number of IRMs are OPERABLE. Anytime an IRM mode switch is moved to any position other than "Operate," the detector voltage drops below a preset level, or when a module is riot plugged in, an inoperative trip signal will be received by the RPS unless the IRM is bypassed. Since only one IRM in each trip system may be bypassed, only one IRM in each RPS trip system may be

-inoperable without resulting in an RPS trip signal.

This Function was not specifically credited-in the accident analysis but it is-retained for the overall.redundancy and diversity of the RPS as required -

by the NRC approvedlicen~sing basis.

Six channels of Intermediate Range Monitor-Inop with three channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.

Since this Function is not assumed in the safety analysis, there is no Allowable Value for this Function.

This Function is required to be OPERABLE when the Intermediate Range Monitor Neutron Flux-High Function is required.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-6 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE Average Power Range Monitor (APRM)

SAFETY ANALYSES, The APRM channels provide the primary indication of neutron flux within LCO, and the core and respond almost instantaneously to neutron flux increases.

APPLICABILITY The APRM channels receive input signals from the local power range (continued) monitors (LPRMs) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. Each APRM channel also includes an Oscillation Power Range Monitor (OPRM) Upscale Function which monitors small groups of LPRM signals to detect thermal-hydraulic instabilities.

The APRM trip System is divided into four APRM channels and four 2-out-of-4 Voter channels. Each APRM channel provides inputs to each of the four voter channels. The four voter channels are divided into two groups of two each with each group of two providing inputs to one RPS trip system. The system is designed to allow one APRM channel, but no voter channels, to be bypassed. A trip from any one unbypassed APRM will result in a "half-trip" in all four of the voter channels, but no trip inputs to either RPS trip system..

APRM trip Functions 2.a, 2.b, 2.c, and 2.d are voted independently from OPRM Trip Function 2.f. Therefore, any Function 2.a, 2.b, 2.c, or 2.d trip.

from any two unbypassed APRM channels will result in a full trip in each of the four voter channels, which in turn results in two trip inputs into each RPS trip system logic channel (Al, A2, B1, and B2), thus resulting in a full scram signal. Similarly, a Function 2.f trip from any two unbypassed APRM channels will result in a full trip from each of the four voter channels.

Three of the four APRM channels and all four of the voter channels are required to be OPERABLE to ensure that no single failure will preclude a scram on a valid signal. In addition, to provide adequate coverage of the entire core consistent with the design bases for the APRM Functions 2.a, 2.b, and 2.c, at least [20] LPRM inputs with at least three LPRM inputs from each of the four axial levels at which the LPRMs are located must be OPERABLE for each APRM channel, with no more than [9], LPRM detectors declared inoperable since the most recent APRM gain calibration. Per Reference 23, the minimum input requirement for an APRM channel with 43 LPRM inputs is determined given that the total number of LPRM outputs used as inputs to an APRM channel that may be bypassed shall not exceed twenty-three (23). Hence, (20) LPRM inputs (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-7 Revision 3

PPL Rev. 4

.RPS Instrumentation B 3.3.1.1 BASES APPLICABLE Average Power Range Monitor (APRM) (continued)

SAFETY ANALYSES, needed to be operable. For the OPRM Trip Function 2.f, each LPRM in LCO, and an APRM channel is further associated in a pattern of OPRM "cells," as APPLICABILITY described in References 17 and 18. Each OPRM cell is capable of producing a channel trip signal.

2.a. Averaae Power Rancie Monitor Neutron Flux-Hiah (Setdown)

For operation at low power (i.e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High (Setdown) Function will provide a secondary scram to the Intermediate Range Monitor Neutron Flux-High Function because of the relative setpoints. With the IRMs at Range 9 or' 10, it is possible that the Average Power Range Monitor

-Neutron Flux -High (Setdown) Function will provide the primary trip signal'-

for a corewide increase in power.

The Average Power Range Monitor Neutron Flux - High (Setdown)

F,unction together with-the IRM - High Function provide mitigation for the control rod withdrawal event duriing startup (Section 15.4.1 of Ref. 5).

Also, the Fiunction indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 23% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow.

Therefore; it indirectly prevents fuel damage during significant reactivity increases with-THERMAL POWER < 23% RTP.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-7a Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux-High (Setdown)

SAFETY (continued)

ANALYSES, LCO, and The Allowable Value is based on preventing significant increases in power APPLICABILITY when THERMAL POWER is< 23% RTP.

The Average Power Range Monitor Neutron Flux - High (Setdown)

Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux - High Function provides protection against reactivity transients and the RWM protects against control rod withdrawal error events.

2.b. Average Power Range Monitor Simulated Thermal Power - High The Average Power Range Monitor Simulated Thermal Power - High Function monitors neutron flux to approximate the THERMAL POWER

-being transferred to the reactor coolant. The APRM neutron flux is electronically filtered with.a time constant representative of the fuel heat transfer dynamics to generate a signal proportional to the THERMAL POWER in' the reactor. The trip level is varied as a function of recirculation drive flow (i.e., at lower core flows, the setpoint is reduced proportional to the reduction in power experienced as core flow is reduced with a fixed control rod pattern) but is clamped at an upper limit that is -

always lower than the Average Power Range Monitor Neutron Flux - High Function Allowable Value. The Average Power Range Monitor Simulated Thermal Power - High Function is not credited in any plant Safety Analyses. The Average Power Range Monitor Simulated Thermal Power

- High Function is set above the APRM Rod Block to provide defense in "

depth to the APRM Neutron Flux - High for transients where THERMAL POWER inIcreases slowly (such as loss of feedwater heating event).

During these events, the THERMAL POWER increase does not significantly lag the neutron flux response and, because of a lower trip setpoint, will initiate a scram before the high neutron flux scram. For rapid neutron flux increase events, the THERMAL POWER lags the neutron flux and the Average Power Range Monitor Neutron Flux - High Function will provide a scram signal before the Average (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-8 Revision 4

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.b. Average Power Range Monitor Simulated Thermal Power - Higqh SAFETY (continued)

ANALYSES, LCO, and Power Range Monitor Simulated Thermal Power - High Function setpoint APPLICABILITY is exceeded.

The Average Power Range Monitor Simulated Thermal Power - High Function uses a trip level generated based on recirculation loop drive flow (W) representative of total core flow. Each APRM channel uses one total recirculation drive flow signal. The total recirculation drive flow signal is generated by the flow processing logic, part of the APRM channel, by summing the flow calculated from two flow transmitter signal inputs, one from each of the two recirculation drive flow loops. The flow processing logic OPERABILITY is part of the APRM channel OPERABILITY requirements for this Function.

The adequacy of drive flow as a representation of core flow is ensured ithrough drive flow alignment, accomplished by SR 3.3.1.1.20.

A note is included, applicable When the plant is in single recirculation loop operation per LCO 3.4.1, which requires reducing by AW the recirculation flow value used in the -APRM Simulated Thermal Power - High Allowable Value equation. The Average Power Range Monitor Scram Function varies as a function of recirculation loop drive flow (W). AW is defined as the difference in indicated drive flow (in percent of drive flow, which produces rated core flow) between two-loop and single-loop operation at the same core flow. The value of AW is established to conservatively bound the inaccuracy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculation loop.

This adjusted Allowable Value thus maintains thermal margins essentially unchanged from those for two-loop operation.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-9 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.b. Average Power Range Monitor Simulated Thermal Power - High SAFETY (continued)

ANALYSES, LCO, and The THERMAL POWER time constant of < 7 seconds is based on the fuel APPLICABILITY heat transfer dynamics and provides a signal proportional to the THERMAL POWER. The simulated thermal time constant is part of filtering logic in the APRM that simulates the relationship between neutron flux and core thermal power.

The Average Power Range Monitor Simulated Thermal Power - High Function is required to be OPERABLE in MODE 1 when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL)'. During MODES 2 and 5, other IRM and APIRM Functions provide protection for fuel cladding integrity.

2.c. Average Power Ranae Monitor Neutron Flux - Hiah The Average Power Range Monitor Neutron Flux - High Function is I-capable of generating a trip signal to prevent fuel damage or excessive RCS pressure. -For the, overpressurization protection analysis of Reference "4,the Average Power Range Monitor Neutron Flux-High Function is-assumed to terminate the main steam isolation valve (MSIV) closure event and, along with the safety/relief valves (S/RVs), limit the peak reactor pressure vessel (RPV) pressure to less than the ASME Code limits. The control rod drop accident (CRDA) analysis (Ref. 5) takes credit for the Average Power Range Monitor Neutron Flux - High Function to terminate the CRDA.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-10 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.c. Average Power Range Monitor Neutron Flux - High (continued)

SAFETY ANALYSES, The CRDA analysis assumes that reactor scram occurs on Average Power LCO, and Range Monitor Neutron Flux - High Function.

APPLICABILITY The Average Power Range Monitor Neutron Flux - High Function is required to be OPERABLE in MODE 1 where the potential consequences of the analyzed transients could result in the SLs (e.g., MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Neutron Flux -High Function is assumed in the CRDA analysis, which is applicable in MODE 2, the Average Power Range Monitor Neutron Flux -

High (Setdown) Function conservatively bounds the assumed trip and, together with the assumed IRM trips, provides adequate protection.

Therefore, the Average Power Range Monitor Neutron Flux -High Function is not required in MODE 2.

2.d. Averaqe Power Rangqe Monitor - Inop Three of the four APRM channels are required to be OPERABLE for each of the APRM Functions. This Function (Inop) provides assurance that the -

minimum niumber of APRM channels are OPERABLE.

For any APRM channel, any time its mode switch is not in the "Operate" position, an APRM module required to issue a trip is unplugged, or the automatic self-test system detects a critical fault with the APRM channel, an Inop trip is sent to all four voter channels. Inop trips from two or more unbypassed APRM channels result in a trip output from each of the four voter channels to its associated trip system.

This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-11 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.d. Averagle Power Rangqe Monitor-lnop (continued)

SAFETY ANALYSES, There is no Allowable Value for this Function.

LCO, and APPLICABILITY This Function is required to be OPERABLE in the MODES where the APRM Functions are required.

2.e. 2-out-of-4 Voter The 2-out-of-4 Voter Function provides the interface between the APRM Functions, including the OPRM Trip Function, and the final RPS trip system logic. As such, it is required to be OPERABLE in the MODES where the APRM Functions are required and is necessary to support the safety analysis applicable to each of those Functions. Therefore, the 2-out-of-4 Voter Function is required-to be OPERABLE in MODES 1 and 2.

All four voter channels are required to be OPERABLE. Each voter channel includes self-diagnostic functions. If any voter channel detects a critical fault in its 6wn processing, a trip is issued from that voter channel to the associated RPS trip system.

I The Two-out-of-Four Logic-Module includes both the 2-out-of-4 Voter hardware and the APRM Interface hardware. The 2-out-of-4 Voter Function 2-.e votes APRM Functions 2.a, 2.b, 2.c, and 2.d independently- of Function 2.f. This voting is accomplished by the 2-out-of-4 Voter hardware in the Two-out-of-Four Logic Module. The voter includes separate outputs to RPS for -the two independently voted sets of Functions, each of which is redundant (four total outputs). The analysis in Reference 15 took credit for this redundancy in the justification of the 12-hour Completion Time for -

Condition A, so the voter Function 2.e must be declared inoperable if any of its functionality is inoperable. The voter Function 2.e does not need to be declared inoperable due to any failure affecting only the APRM Interface hardware portion of the Two-out-of-Four Logic Module.

There is no Allowable Value for this Function.

2.f. Oscillation Power Range Monitor (OPRM) Trip The OPRM Trip Function provides compliance with GDC 10, "Reactor Design," and GDC 12, "Suppression of Reactor Power Oscillations" thereby providing protection from exceeding the fuel MCPR safety limit (SL) due to anticipated thermal-hydraulic power oscillations.

(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-12 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Trip (continued)

SAFETY ANALYSES, References 17, 18 and 19 describe three algorithms for detecting thermal-LCO, hydraulic instability related neutron flux oscillations:' the period based and detection algorithm (confirmation count and cell amplitude), the amplitude APPLICABILITY based algorithm, and the growth rate algorithm. All three are implemented in the OPRM Trip Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations". OPRM Trip Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Trip Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation by the OPRM algorithms. Each channel is capable of detecting thermal-hydraulic instabilities, by detecting the related neutron

-flux oscillations, and issuing a trip signal before the MCPR SL is exceeded. Three of the four channels are required to be OPERABLE.

The OPRM Trip is automatically enabled (bypass removed) when THERMAL-POWER is-> 25% RTP, as indicated by the APRM Simulated Thermal Power, and reactor core flow is < the value defined in the COLR, as indicated by APRM measured recirculation drive flow. This is the -

operating region where actual thermal-hydraulic instability and related neutron flux oscillations are expected to occur. Reference 21 includes additional discussion of OPRM Trip enable region limits.

These setpoints, which are sometimes referred to as the "auto-bypass" setpoints, establish the boundaries of the OPRM Trip enabled region. The APRM Simulated Thermal Power auto-enable setpoint has 1% deadband while the drive flow setpoint has a 2% deadband. The deadband for these setpoints is established so that it increases the enabled region once the region is entered.

The OPRM Trip Function is required to be OPERABLE when the plant is at > 23% RTP. The 23% RTP level is selected to provide margin in the unlikely event that a reactor power increase transient occurring without operator action while the plant is operating below 25% RTP causes a power increase to or beyond the 25% APRM Simulated Thermal Power OPRM Trip auto-enable setpoint. This OPERABILITY requirement assures that the OPRM Trip auto-enable function will be OPERABLE when required.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-12a Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Trip (continued)

SAFETY ANALYSES, An APRM channel is also required to have a minimum number of OPRM LCO, and cells OPERABLE for the Upscale Function 2.f to be OPERABLE. The APPLICABILITY OPRM cell operability requirements are documented in the Technical Requirements Manual, TRO 3.3.9, and are established as necessary to support the trip setpoint calculations performed in accordance with methodologies in Reference 19.

An OPRM Trip is issued from an APRM channel when the period based detection algorithm in that channel detects oscillatory changes in the neutron flux, indicated by the combined signals of the LPRM detectors in a cell, with period confirmations and relative cell amplitude exceeding specified setpoints. One or more cells in a channel exceeding the trip conditions will result in a channel OPRM Trip from that channel. An OPRM Trip is also issued from the channel if either the growth rate or amplitude-based algorithms detect oscillatory changes in the neutron flux

-for one or more cells in that channel. (Note: To facilitate placing the O.PRM Trip Function 2.f in one APRM channel in a "tripped" state, if necessary to satisfy a Required Action, the APRM equipment is conservatively designed to force an OPRM Trip output from the APRM -

channel if an APRM Inop condition occurs, such as when the APRM chassis keylock switch is placed in the Inop position.)

There are three "sets" of OPRM related setpoints or adjustment parameters: a) OPRM Trip auto-enable region setpoints for STP and drive flow; b) period based detection algorithm (PBDA) confirmation count and amplitude setpoints; and c) period based detection algorithm tuning parameters.

The first set, the OPRM Trip auto-enable setpoints, as discussed in the SR 3.3.1.1.19 Bases, are treated as nominal setpoints with no additional margins added. The settings are defined in the Technical Requirements Manual, TRO 3.3.9, and confirmed by SR 3.3.1.1.19. The second set, the OPRM PBDA trip setpoints, are established in accordance with methodologies defined in Reference 19, and are documented in the COLR. There are no allowable values for these setpoints. The third set, the OPRM PBDA "tuning" parameters, are established or adjusted in accordance with and controlled by requirements in the Technical Requirements Manual, TRO 3.3.9.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-12b ' Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 3. Reactor Vessel Steam Dome Pressure-Hiah SAFETY ANALYSES, An increase in the RPV pressure during reactor operation compresses the LCO, and steam voids and results in a positive reactivity insertion. This causes the APPLICABILITY neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. This trip Function is assumed in the low power generator load rejection without bypass and the recirculation flow controller failure (increasing) event. However, the Reactor Vessel Steam Dome Pressure-High Function initiates a scram for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core power. For the overpressurization protection analysis of Reference 4, reactor scram (the analyses conservatively assume a scram from either the Average Power Range Monitor Neutron Flux-High signal, or the Reactor Vessel Steam Dome Pressure-High signal), along with the S/RVs, limits the peak RPV pressure to less than the ASME Section III Code limits" High reactor pressure signals are initiated from four pressure instruments that sense reactor pressure. The Reactor-Vessel Steam Dome Pressure-High Allowable Value is chosen to provide a sufficient margin -

to the ASME Section I11Code limits during the event.

Four chani-els of Reactor Vessel Steam Dome Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-12c Revision 0 I,

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 3. Reactor Vessel Steam Dome Pressure-Hiqh (continued)

SAFETY ANALYSES, required to be OPERABLE in MODES 1 and 2 when the RCS is LCO, and pressurized and the potential for pressure increase exists.

APPLICABILITY

4. Reactor: Vessel Water Level-Low, Level 3 Low RPV water level indicates the capability to cool the fuel may be threatened'. Should RPV water level decrease too far, fuel damage could result. Therefore, a reactor scram is initiated at Level 3 to substantially reduce the heat generated in the fuel from fission. The Reactor Vessel Water Level-Low, Level 3 Function is assumed in the analysis of the recirculation line break (Ref. 6). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

-ReactorVessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a -

constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in -the vessel.

Four channels of Reactor Vessel Water Level-Low, Level 3 Function, with two channels in each trip system arranged in a one-out-of-two logic,-

are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from -this Function on a valid signal.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value is selected to ensure that during normal operation the separator skirts are not uncovered (this protects available recirculation pump net positive suction head (NPSH) from significant carryunder) and, for transients involving loss of all normal feedwater flow, initiation of the low pressure ECCS subsystems at Reactor Vessel Water-Low Low Low, Level 1 will not be required.

The Function is required in MODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting transients and accidents. ECCS initiations at Reactor Vessel Water Level-Low Low, Level 2 and Low Low Low, (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-13 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 4. Reactor Vessel Water Level-Low, Level 3 (continued)

SAFETY ANALYSES, Level 1 provide sufficient protection for level transients in all other LCO, and MODES.

APPLICABILITY

5. Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressurization transient. However, for the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Neutron Flux-High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits. That is, the direct scram on position switches for MSIV closure events is not

-assumed in the overpressurization analysis. Additionally, MSIV closure is assumed in the transients analyzed in Reference 5 (e.g., low steam line pressure, manual closure of MSIVs, high steam line flow). The reactor scram reduces the amount of-energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B. Thus, each RPS trip system receives an input from eight Main Steam Isolation Valve-Closure channels, each consisting of one position switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines must close in order for a scram to occur.

The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-14 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 5. Main Steam Isolation Valve-Closure (continued)

SAFETY ANALYSES, Sixteen channels (arranged in pairs) of the Main Steam Isolation Valve-LCO, and Closure Function, with eight channels in each trip system, are required to APPLICABILITY be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE 1 since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs close. In addition, the Function is automatically bypassed when the Reactor Mode Switch is not in the Run position. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.

6. Drvwell Pressure-Hiqh High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant and the drywell. The Drywell Pressure-High Function is assumed in the analysis of the recirculation line break (Ref. 6). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of Emergency --

Core Cooling Sy/stems_(ECCS), ensures that the fuel peak cladding temperatur~e remains below the limits of 10 CFR 50.46.

High drywall pressure signals are initiated from four pressure instruments.

that sense drywell pressure. The Allowable Value was selected to be as low as possible and indicative of a LOCA inside primary containment.

Four channels of Drywell Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required in MODES 1 and 2 where considerable energy exists in the RCS, resulting in the limiting transients and accidents.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-15 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES

'APPLICABLE 7.a, 7.b. Scram Discharae Volume Water Level - Hiah SAFETY ANALYSES, The SDV receives the water displaced by the motion of the CRD pistons LCO, and during a reactor scram. Should this volume fill to a point where there is APPLICABILITY insufficient volume to accept the displaced water, control rod insertion (continued) would be hindered. Therefore, a reactor scram is initiated while the remaining free volume is still sufficient to accommodate the water from a full core scram. The two types of Scram Discharge Volume Water Level -

High Functions are an input to the RPS logic. No credit is taken for a scram initiated from these Functions for any of the design basis accidents or transients analyzed in the FSAR. However, they are retained to ensure the scram function remains OPERABLE.

SDV water level is measured by two diverse methods. The level in each of the two SDVs is measured by two float type level switches and two level transmitters with trip units for a total of eight level signals. The outputs of these devices are arranged so that there is a signal from a level switch and a level,',transmitter with trip unit to each RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference '8. -

The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram.

Four channels of each type of Scram Discharge Volume Water Level-High Function, with two channels of each type in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.

8. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited.

Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-16 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 8. Turbine Stop Valve-Closure (continued)

SAFETY ANALYSES, the transients that would result from the closure of these valves. The LCO, and Turbine Stop Valve-Closure Function is the primary scram signal for the APPLICABILITY turbine trip event analyzed in Reference 5. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the End of Cycle Recirculation Pump Trip (EOC-RPT)

System, ensures that the MCPR SL is not exceeded. Turbine Stop Valve-Closure sigjnals are initiated from position switches located on each of the four TSVs. Two independent position switches are associated with each stop valve., One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an input from four Turbine Stop Valve-Closure channels, each consisting of one position switch. The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs must be closed to produce a scram. This Function must be enabled at THERMAL POWER

> 26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure. Because an increase in the main turbine bypass flow can affect this function non-conservatively, THERMAL' POWER is derived from first stage pressure. The main turbine bypass valves must not cause the trip Function to be bypassed when THERMAL POWER is" 26% RTP.

The Turbihe Stop Valve-Closure Allowable Value is selected to be high.

enough to 'detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.

Eight channels (arranged in pairs) of Turbine Stop Valve-Closure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is > 26% RTP. This Function is not required when THERMAL POWER is < 26% RTP since the Reactor Vessel Steam Dome Pressure-High' and the Average Power Range Monitor Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-17 Revision 4

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 9. Turbine Control Valve Fast Closure, Trip Oil Pressure-Low SAFETY ANALYSES, Fast closure of the TCVs results in the loss of a heat sink that produces LCO, and reactor pressure, neutron flux, and heat flux transients that must be APPLICABILITY limited. Therefore, a reactor scram is initiated on TCV fast closure in (continued) anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function is:the primary scram signal for the generator load rejection event analyzed in Reference 5. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the EOC-RPT System, ensures that the MCPR SL is not exceeded.

Turbine Control Valve Fast Closure, Trip, Oil Pressure-Low signals are initiated by..the electrohydraulic control (EHC) fluid pressure at each control valve. One pressure instrument is associated with each control valve, and the signal from each transmitter is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER

Ž26% RTP. This is accomplished automatically by pressure instruments 'j sensing turbine first stage pressure. Because an increase in the main turbine bypass flow can affect this function non-conservatively, THERMAL POWER isderiVed from first stage pressure. The main turbine bypass valves must not cause the trip Function to be bypassed when THERMAL POWER is,> 26% RTP.

The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. Thi,'3 Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is Ž 26% RTP. This Function is not required when THERMAL POWER is < 26% RTP, since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-18 Revision 4

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 10. Reactor Mode Switch-Shutdown Position SAFETY ANALYSES, The Reactor Mode Switch-Shutdown Position Function provides signals, LCO, and via the manual scram logic channels, to each of the four RPS logic APPLICABILITY channels, which are redundant to the automatic protective instrumentation (continued) channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

The reactor mode switch is a single switch with four channels, each of which provides input into one of the RPS logic channels.

I There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on reactor mode switch position.

Four chanrnels of Reactor Mode Switch-Shutdown Position. Function,

-with two channels in each trip system, are available and required to be OPERABLE. TheReactor. Mode Switch-Shutdown Position Function is-required to be OPERABLE in MODES 1 and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdraWn.

11. Manual Scram The Manual Scram push button channels provide signals, via the manual scram logic channels, to each of the four RPS logic channels, which are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

There is one Manual Scram push button channel for each of the four RPS logic channels. In order to cause a scram it is necessary that at least one channel in each trip system be actuated.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-19 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 11. Manual Scram (continued)

SAFETY ANALYSES, There is no Allowable Value for this Function since the channels are LCO, and mechanically actuated based solely on the position of the push buttons.

APPLICABILITY Four channels of Manual Scram with two channels in each trip system arranged in a one-out-of-two logic are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

ACTIONS A Note has. been provided to modify the ACTIONS related to RPS instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be

-inoperable or not within limits, will not result in separate entry into the Condition. ,Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based orn initial entry into the Condition. However, the Required Actions for',!inoperable-RPS instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable'RPS instrumentation channel.

A.1 and A.2 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months has been shown to be acceptable (Refs. 9, 15 and 16) to permit restoration ,,of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B. 1, B.2, and C. 1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-20 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES ACTIONS A.1 and A.2 (continued)

.condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram),

Condition D must be entered and its Required Action taken.

As noted, Action A.2 is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. 'Inoperability of one required APRM channel affects both trip systems. For that condition, Required Action A.1 must be satisfied, and is the only action (other than restoring OPERABILITY) that will restore capability to accommodate a single failure. Inoperability of more than one required APRM channel of the same trip function results in loss of trip capability and entry into Condition C, as well as entry into Condition A for each channel.

B.1 and B.2 Condition B exists when, for any one or mere Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a tingle failure in either trip system.

Required Actions B.1 and B.2 limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arrangement for a typical four channel Function). The reduced reliability of this logic arrangement was not evaluated in Reference 9, 15 or 16 for the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time. [

Within the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the associated Function will have all required channels OPERABLE or in trip (or any combination) in one trip system.

Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in Reference 9, 15 and 16, which justified a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowable out of service time as presented in Condition A. The trip system in the more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision of which trip system is in the more degraded state should be based on prudent judgment and take into account current plant conditions (i.e., what MODE the plant is in).

I(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-21 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES ACTIONS B.1 and B.2 (continued)

If this action would result in a scram, it is permissible to place the other trip system or its inoperable channels in trip.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 'Completion Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram.

Alternately,, if it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing the inoperable channel or associated trip system in trip would result in a scram), Condition D must be entered and its Required Action taken.

As noted, Condition B is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of an APRM channel affects both trip systems and '

isnot associated ývith a specific trip system as are the APRM 2-out-of-4 Voter (Function 2.e) and other non-APRM-channels for which Condition B -

applies. For anr inoperable APRM-channel, Required Action A. 1 must be-satisfied, and is the only action (other than restoring OPERABILITY) that will restore capability to accom-modate a single failure. Inoperability of a Function irn more than one required APRM channel results in loss of trip.

capability for that Function and entry into Condition C, as well as entry into Condition A for each channel. Because Conditions A and C provide Required Actions that are appropriate for the inoperability of APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f, and because these Functions are not associated with specific trip systems as are the APRM 2-out-of-4 Voter and other non-APRM channels, Condition B does not apply.

C.___

Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Function on a valid signal. For the typical Function with one-out-of-two taken twice logic, this would require both trip sIystems to ,have one channel OPERABLE or in trip (or the associated trip system in trip). For Function 5 (Main Steam (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-22 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES ACTIONS C.1 (continued)

Isolation Valve-Closure), this would require both trip systems to have each channel associated with the MSIVs in three main steam lines (not necessarily the same main steam lines for both trip systems) OPERABLE or in trip (or the associated trip system in trip).

For Function 8 (Turbine Stop Valve-Closure), this would require both trip systems to have three channels, each OPERABLE or in trip (or the associated trip system in trip).

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-22a Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES ACTIONS C.1 (continued) 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

D.1 Required Action D.1 directs entry into the appropriate Condition referencedin Table 3.3.1.1-1. The applicable Condition specified in the Table is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed.

Each time an inoperable channel has not met any Required Action of Condition A, B, or C and the associated Completion Time has expired, Condition ') will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.1, F.1, G.1, and J.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or-the associated trip system placed in trip) within the allowed Completion Time, the plant-must be placed in a MODE or other specified condition in which the LCO does not apply. The allowed Completion Times are reasonable,, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Required Actions E.1 and J.1 are consistent with the Completion Time provided in LCO 3.2.2,""MINIMUM CRITICAL POWER RATIO (MCPR)."

H.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-23 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES ACTIONS H.1 (continued) the reactivity of the core and are, therefore, not required to be inserted.

Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.

lI1 and 1.2 Required Actions 1.1 and 1.2 are intended to ensure that appropriate actions are taken if more than two inoperable or bypassed OPRM channels result in not maintaining OPRM trip capability.

In the 4-OPRM channel configuration, any 'two' of the OPRM channels out of the total of four and one 2-out-of-4 voter channels in each RPS trip system areorequired to function for the OPRM safety trip function to be accomplished. Therefore, three OPRM channels, assures at least two OPRM channels can provide trip inputs to the 2-out-of-4 voter channels

-even in the event of a single OPRM channel failure, and the minimum of two 2-out-of-4 voter channels per RPS trip system assures at least one voter channel will be operable-per RPS trip system even in the event of a single voter channel failure.

References. 15 and 16 justified use of alternate methods to detect and suppress oscillations under limited conditions. The alternate methods are consistent with the guidelines identified in Reference 20. The alternate-methods procedures require increased operator awareness and monitoring for neutron flux oscillations when operating in the region where oscillations are possible. If operator observes indications of oscillation, as described in Reference 20, the operator will take the actions described by-procedures, which include manual scram of the reactor. The power/flow map regions where oscillations are possible are developed based on the methodology in Reference 22. The applicable regions are contained in the COLR. ",

The alternate methods would adequately address detection and mitigation in the even't of thermal hydraulic instability oscillations. Based on industry operating experience with actual instability oscillations, the operator would be able to recognize instabilities during this time and take action to suppress them through a manual scram. In addition, the OPRM system may still be available to provide alarms to the operator if the onset of oscillations were to occur.

The 12-hoLur allowed Completion Time for Required Action 1.1 is based on engineering judgment to allow orderly transition to the alternate methods (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-24 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES ACTIONS Lil and 1.2 (continued) while limiting the period of time during which no automatic or alternate detect and suppress trip capability is formally in place. Based on the small probability ,of an instability event occurring at all, the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is judged to be reasonable.

The 120-day allowed Completion Time, the time that was evaluated in References 15 and 16, is considered adequate because with operation minimized in regions where oscillations may occur and implementation of the alternate methods, the likelihood of an instability event that could not be adequately handled by the alternate methods during this 120-day period was negligibly small.

The primary purpose of Required Actions 1.1 and 1.2 is to allow an orderly completion, without undue impact on plant operation, of design and verification activities required to correct unanticipated equipment design or

-functional problems that cause OPRM Trip Function INOPERABILITY in all APRM channels that cannot reasonably be corrected by normal maintenance or repair actions; These Required Actions are not intended "

and were not evaluated as a routine alternative to returning failed or inoperable-,equipment-to OPERABLE status.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 9, 15 and 16) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-24a Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 and SR 3.3.1.1.2 REQUIREMENTS Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-24b Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 and SR 3.3.1.1.2 (continued)

REQUIREMENTS !

Agreement. criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.

The Frequency of once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for SR 3.3.1.1.1 is based upon operating experience that demonstrates that channel failure is rare. The Frequency of once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for SR 3.3.1.1.2 is based upon operating experience that demonstrates that channel failure is rare and the evaluation in References 15 and 16. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with the channels required by the LCO.

11 SR 3.3.1.1".3 To ensure that the APRMs are-accurately -indicating the true core average power, the 'APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, vWhich could affect the APRM reading between performances of SR 3.3.1.1.8.

A restriction to satisfying this SR when < 23% RTP is provided that requires the SR to be met only at > 23% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 23% RTP. At low power levels, a -

high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, LHGR and APLHGR). At >_23% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 23% if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months afterlreaching or exceeding 23% RTP. Twelve hours is based on operating experience and in (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-25 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.3 (continued)

REQUIREMENTS consideration of providing a reasonable time in which to complete the SR.

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-26 Revision 2

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.4 (continued)

REQUIREMENTS performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Reef. 9).

SR 3.3.1.1.5 A, CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A Frequency 'of 7 days provides an acceptable level of system average availability over the Frequency and is based on the reliability analysis of Reference 9. (The Manual Scram Function's CHANNEL FUNCTIONAL

-TEST Frequency was credited in the analysis to extend many automatic scram Functions' Frequencies.)

SR 3.3.1.1.6 and SR -3.3.1.1.7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. The overlap is demonstrated prior to fully withdrawing the SRMs from the core. Demonstrating the overlap prior to fully withdrawing the SRMs from the core is required to ensure the SRMs are on-scale for the overlap demonstration.

The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained. Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block, or IRM upscale rod block. Overlap (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-27 Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)

REQUIREMENTS between SRMs and IRMs similarly exists when, prior to fully withdrawing the SRMs from the core, IRMs are above mid-scale on range 1 before SRMs have reached the upscale rod block.

As noted, SR 3.3.1.1.7 is only required to be met during entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).

If overlap for a group of channels is not demonstrated (e.g., IRM/APRM overlap), the reason for the failure of the Surveillance should be determined and the appropriate channel(s) declared inoperable. Only those appropriate channels that are required in the current MODE or condition should be declared inoperable.

A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs.

SR 3.3.1.1.8 LPRM gain settings are deterniined from the local flux profiles that are either measured by the Traversing Incore Probe (TIP) System at all functional locations or calculated for TIP locations that are not functional.

The methodology used to develop the power distribution limits considers the uncertainty for both measured and calculated local flux profiles. This methodology assumes that all the TIP locations are functional for the first LPRM calibration following a refueling outage, and a minimum of 25 functional TIP locations for subsequent LPRM calibrations. The calibrated LPRMs establish the relative local flux profile for appropriate representative input to the APRM System. The 1000 MWD/MT Frequency is based on operating experience with LPRM sensitivity changes.

SR 3.3.1.1.9 and SR 3.3.1.1.14 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the (continued)

SUSQUEHANNA - UNIT 1 B 3.3-28 TS / B Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.9 and SR 3.3.1.1.14 (continued)

REQUIREMENTS intended function. The 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of Reference 9.

SR 3.3.1.1.9 is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference 10) Performance of such a test could result in a plant transient or, place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNELFUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.1.1.15. This is acceptable because operating experience shows that the contacts, not tested during the

-CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients. -

The 24 month Frequency of SR 3.3.1.1.14 is based on the need to perform this Surveillance under-the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.10, SR 3.3.1.1.11, SR 3.3.1.1.13, and SR 3.3.1.1.18 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

Note 1 for SR 3.3.1.1.18 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal.

Changes in neutron detector sensitivity are compensated for by performing the 7 day calorimetric calibration (SR 3.3.1.1.3) and the 2000 MWD/MT LPRM (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-29 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.10, SR 3.3.1.1.11, SR 3.3.1.1.13 and SR 3.3.1.1.18 REQUIREMENTS (continued) calibration against the TIPs (SR 3.3.1.1.8).

A Note is provided for SR 3.3.1.1.11 that requires the IRM SRs to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

A second note is provided for SR 3.3.1.1.18 that requires that the recirculation flow (drive flow) transmitters, which supply the flow signal to the APRMs, be included in the SR for Functions 2.b and 2.f. The APRM Simulated Thermal Power-High Function (Function 2.b) and the OPRM Trip Function (Function 2.f) both require a valid drive flow signal. The

-APRM Simulated Thermal Power-High Function uses drive flow to-vary the.-

trip setpoint. The OPRM Trip Function uses drive flow to automatically enable or I6ypass the OPRM Trip output t0the RPS. A CHANNEL CALIBRATION of the APRM drive-flow signal requires both calibrating the drive flow tb-ansmitters-and the processing hardware in the APRM equipment.-- SR 3.3.1.1.20 establishes a valid drive flow / core flow relationship. Changes throughout the cycle in the drive flow / core flow relationship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to establish the setpoints for the APRM Simulated Thermal Power-High Function and the OPRM Trip Function.

The Frequency of 184 days for SR 3.3.1.1.11, 92 days for SR 3.3.1.1.12 and 24 months for SR 3.3.1.1.13 and SR 3.3.1.1.18 is based upon the assumptions in the determination of the magnitude of equipment drift in the setpoint analysis.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-30 Revision 3

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.12 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. For the APRM Functions, this test supplements the automatic self-test functions that operate continuously in the APRM and voter channels. The scope of the APRM CHANNEL FUNCTIONAL TEST is that which is necessary to test the hardware. Software controlled functions are tested as part of the initial verification and validation and are only incidentally tested as part of the surveillance testing. Automatic self-test functions check the E'PROMs in which the software-controlled logic is defined.

Changes in the EPROMs will be detected by the self-test function and alarmed via the APRM trouble alarm. SR 3.3.1.1 .1 for the APRM functions includes a step to confirm that the automatic self-test function is still operating.

The APRM CHANNEL FUNCTIONAL TEST covers the APRM channels (including recirculation flow processing -- applicable to Function 2.b and

-the auto-enable portion of Function 2.f only), the 2-out-of-4 Voter channels, and the interface connections into the RPS trip systems from I

the voter channels.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The 184-day Frequency of SR 3.3.1.1.12 is based on the reliability analyses of References 15 and

16. (NOTE: The actual voting logic of the 2-out-of-4 Voter Function is tested as part of SR 3.3.1.1.15. The auto-enable setpoints for the OPRM Trip are confirmed by SR 3.3.1.1.19.)

A Note is provided for Function 2.a that requires this SR to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM Function cannot be performed in MODE 1 without utilizing jumpers or lifted leads. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2.

A second Note is provided for Functions 2.b and 2.f that clarifies that the CHANNEL FUNCTIONAL TEST for Functions 2.b and 2.f includes testing of the recirculation flow processing electronics, excluding the flow transmitters.

SR 3.3.1.1.15 The LOGIC; SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3), and SDV vent (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-30a Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.15 (continued)

REQUIREMENTS !

and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function.

The LOGIC SYSTEM FUNCTIONAL TEST for APRM Function 2.e simulates APRM and OPRM trip conditions at the 2-out-of-4 Voter channel inputs to check all combinations of two tripped inputs to the 2-out-of-4 logic in the voter channels and APRM-related redundant RPS relays.

The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.1.16 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is-

> 26% RTP. This is performed by a Functional check that ensures the scram feature is not bypassed-at > 26% RTP. Because main turbine bypass flow can affect-this function nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the opening of the main turbine bypass valves must not cause the trip Function to be bypassed when Thermal Power is > 26% RTP.

If.any bypass channel's trip function is nonconservative (i.e., the Functions.

are bypassed at > 26% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypasscondition, this SR is met and the channel is considered OPERABLE.

The Frequency of 24 months is based on engineering judgment and reliability of the components.

SR 3.3.1.11.17 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. This test may be performed in one (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-31 Revision 4

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.17 (continued)

REQUIREMENTS measurement or in overlapping segments, with verification that all components are tested. The RPS RESPONSE TIME acceptance criteria are included in Reference 11.

RPS RESPONSE TIME for the APRM 2-out-of-4 Voter Function (2.e) includes the APRM Flux Trip output relays and the OPRM Trip output relays of the voter and the associated RPS relays and contactors.

(Note: The digital portion of the APRM, OPRM and 2-out-of-4 Voter channels are excluded from RPS RESPONSE TIME testing because self-testing and calibration checks the time base of the digital electronics.

Confirmation of the time base is adequate to assure required response times are met. Neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. See References 12 and 13).

RPS RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. Note 3 requires STAGGERED TEST BASIS-Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Closure Function because channels are arranged in pairs.

This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

SR 3.3.1.1.17 for Function 2.e confirms the response time of that function, and also confirms the response time of components to Function 2.e and other RPS functions. (Reference 14)

Note 3 allows the STAGGERED TEST BASIS Frequency for Function 2.e to be determined based on 8 channels rather than the 4 actual 2-out-of-4 Voter channels. The redundant outputs from the 2-out-of-4 Voter channel (2 for APRM trips and 2 for OPRM trips) are considered part of the same channel, but the OPRM and APRM outputs are considered to be separate channels for application of SR 3.3.1.1.17, so N = 8. The note further requires that testing of OPRM and APRM outputs from a 2-out-of-4 Voter be alternated. In addition to these commitments, References 15 and 16 require that the testing of inputs to each RPS Trip System alternate.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-32 Revision 5

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.17 (continued)

REQUIREMENTS Combining these frequency requirements, an acceptable test sequence is one that:

a. Tests each RPS Trip System interface every other cycle,

b. Alternates the testing of APRM and OPRM outputs from any specific 2-out-of-4 Voter Channel

c. Alternates between divisions at least every other test cycle.

The testing sequence shown in the table below is one sequence that satisfies these requirements.

Function 2.e Testing Sequence for SR 3.3.1.1.17 "Staggering" 24- Voter Month Output Noter Al Voter A2 Voter B1 Voter RPS Trip Cycle Tested Output- Output Output B2 System Division Output 1 St OPRM Al OPRM A 1--

2 nd APRM B1 APRM B 1 3rd OPRM A2 OPRM A 2 4th APRM B2 APRM B 2 5 th APRM Al APRM A 1 6 OPRM B1 OPRM B 1 APRM A2 APRM A 2 7th 8 OPRM 820OPRM B 2 I After 8 cycles, the sequence repeats.

Each test of an OPRM or APRM output tests each of the redundant outputs from the 2-out-of-4 Voter channel for that Function and each of the corresponding relays in the RPS. Consequently, each of the RPS relays is tested every fourth cycle. The RPS relay testing frequency is twice the frequency justified by References 15 and 16.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-32a Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.19 REQUIREMENTS This surveillance involves confirming the OPRM Trip auto-enable setpoints. The auto-enable setpoint values are considered to be nominal values as discussed in Reference 21. This surveillance ensures that the OPRM Trip is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation drive flow properly correlate with THERMAL POWER (SR 3.3.1.1.2) and core flow (SR 3.3.1.1.20), respectively.

If any auto-enable setpoint is nonconservative (i.e., the OPRM Trip is bypassed when APRM Simulated Thermal Power > 25% and recirculation drive flow < value equivalent to the core flow value defined in the COLR, then the affected channel is considered inoperable for the OPRM Trip Function. Alternatively, the OPRM Trip auto-enable setpoint(s) may be adjusted to place the channel in a conservative condition (not bypassed).

If the OPRM Trip is placed in the not-bypassed condition, this SR is met, and the channel is considered OPERABLE.

For purposes of this surveillance, consistent with Reference 21, the conversion- from core flow values defined in the COLR to drive flow values used for this SR can be consetv~atively determined by a linear scaling assuming that 100% drive flow corresponds to 100 Mlb/hr core flow, with no adjustment made for expected deviations between core flow and drive flow below 100%.

The Frequency of 24 months is based on engineering judgment and reliability of the components.

SR 3.3.1.1.20 The APRM Simulated Thermal Power-High Function (Function 2.b) uses drive flow to vary the trip setpoint. The OPRM Trip Function (Function 2.f) uses drive flow to automatically enable or bypass the OPRM Trip output to RPS. Both of these Functions use drive flow as a representation of reactor core flow. SR 3.3.1.1.18 ensures that the drive flow transmitters and processing electronics are calibrated. This SR adjusts the recirculation drive flow scaling factors in each APRM channel to provide the appropriate drive flow/core flow alignment.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-32b Revision 1

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.20 REQUIREMENTS The Frequency of 24 months considers that any change in the core flow to drive flow functional relationship during power operation would be gradual and the maintenance of the Recirculation System and core components that may impact the relationship is expected to be performed during refueling outages. This frequency also considers the period after reaching plant equilibrium conditions necessary to perform the test, engineering judgment of the time required to collect and analyze the necessary flow data, and engineering judgment of the time required to enter and check the applicable scaling factors in each of the APRM channels. This timeframe is acceptable based on the relatively small alignment errors expected, and the margins already included in the APRM Simulated Thermal Power - High and OPRM Trip Function trip - enable setpoints.

REFERENCES 1. FSAR, Figure 7.2-1.

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

3. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.

4. FSAR, Section 5.2.2.

5. FSAR, Chapter 15.

6. FSAR, Section 6.3.3.

(continued)

SUSQUEHANNA - UNIT 1 TS /B 3.3-32c Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES REFERENCES 7. Not used.

(continued)

8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.

9. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System," March 1988.

10. NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification 1.0 Definitions, Issue date 12/08/86.

11. FSAR, Table 7.3-28.

12. NEDO-32291A "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.

13. NRC Safety Evaluation Report related to Amendment No. 171 for

- License No. NPF 14 and Amendment No. 144 for License No. NPF 22.

14. NEDO-32291-A Supplement 1 "System Analyses for the Elimination of Selected Response TiMe Testing Requirements," October 1999.

15. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995.

16. NEDC-32410P-A Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," November 1997.

17. NEDO-31960-A, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

18. NEDO-31960-A, Supplement 1, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

19. NEDO-32465-A, "BWR Owners' Group Long-Term Stability Detect and Suppress Solutions Licensing Basis Methodology and Reload Applications," August 1996.

SUSQUEHANNA - UNIT 1 TS / B 3.3-33 Revision 5

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 BASES REFERENCES 20. BWROG Letter BWROG 9479, L. A. England (BWROG) to (continued) M. J. Virgilio, "BWR Owners' Group Guidelines for Stability Interim Corrective Action," June 6, 1994.

21. BWROG Letter BWROG 96113, K. P. Donovan (BWROG) to L. E. Phillips (NRC), "Guidelines for Stability Option III

'Enable Region' (TAC M92882)," September 17, 1996.

22. EMF-CC-074(P)(A), Volume 4, "BWR Stability Analysis:

Assessment of STAIF with Input from MICROBURN-B2."

23. GE Letter to PPL, GE-2005-EMC426, "Susquehanna 1 & 2 Minimum LPRM Input Requirement for NUMAC APRM 4-Channel Design,"

April 26, 2005.

SUSQUEHANNA - UNIT 1 TS / B 3.3-33a Revision 0

PPL Rev. 4 RPS Instrumentation B 3.3.1.1 Table B 3.3.1.1-1 (page 1 of 1)

RPS Instrumentation Sensor Diversity Scram Sensors for Initiating Events RPV Variables Anticipatory Fuel Initiation Events (a) (b) (c) (d) (e) (f) (g)

MSIV Closure X X X X Turbine Trip (w/bypass) X X X X Generator Trip (w/bypass) X X X Pressure Regulator Failure (primary X X X X X pressure decrease) (MSIV closure trip)

Pressure Regulator Failure (primary X X X pressure decrease) (Level 8 trip)

Pressure Regulator Failure (primary X X pressure increase)

Feedwater Controller Failure (high X X X X reactor water level)

Feedwater Controller Failure (low X X X reactor water level)

Loss of Condenser Vacuum X X X X Loss of AC Power (loss of transformer) X X X X Loss of AC Power (loss of grid X X X X X X connections)

(a) Reactor Vessel Steam Dome Pressure-High (b) Reactor Vessel Water Level-High, Level 8 (c) Reactor Vessel Water Level-Low, Level 3 (d) Turbine Control Valve Fast Closure (e) Turbine Stop Valve-Closure (f) Main Steam Isolation Valve-Closure (g) Average Power Range Monitor Neutron Flux-High SUSQUEHANNA - UNIT 1 TS / B 3.3-34 Revision 1

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 B 3.3 INSTRUMENTATION B 3.3.2.1 Control Rod Block Instrumentation BASES BACKGROUND Control rods provide the primary means for control of reactivity changes.

Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays that are designed to ensure that specified fuel design limits are not exceeded for postulated transients and accidents. During high power operation, the rod block monitor (RBM) provides protection for control rod withdrawal error events. During low power operations, control rod blocks from the rod worth minimizer (RWM) enforce specific control rod sequences designed to mitigate the consequences of the control rod drop accident (CRDA). During shutdown conditions, control rod blocks from the Reactor Mode Switch-Shutdown Position Function ensure that all control rods remain inserted to prevent inadvertent criticalities.

The Nominal Trip Setpoint (NTSP) is a predetermined setting for a protective device chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the.

Safety Limit (SL) would not be exceeded._ The NTSP accounts for various uncertainties. As such, the NTSP meets the definition of a Limiting Safety System Setting (LSSS) because the protective instrument channel actuates to protect a-reactor core or RCS pressure boundary Safety Limit. Rod Block Monitor functions Ia, lb and lc are LSSSs.

,Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility. OPERABLE is defined in Technical Specifications as "...being capable of performing its specified safety function(s)." For automatic protective devices related to SLs, the required safety function is to ensure that a SL is not exceeded and therefore the NTSP is the LSSS, as defined by 10 CFR 50.36.

However, use of the NTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as-found" value during a Surveillance.

This would result in Technical Specification compliance problems, as well as reports and corrective actions required by the rule which are not necessary to ensure safety.

Use of the NTSP to define "as-found" OPERABILITY under the expected circumstances described above would result in actions required by both the rule and Technical Specifications that are not warranted. However, there is also some point beyond which the device would have not been able to perform its function due, for example, to greater than expected drift. This (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-44 Revision 4

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND value needs to be specified in the Technical Specifications in order to (continued) define OPERABILITY of the devices and is designated as the Allowable Value which, is the least conservative value of the as-found setpoint that a channel can have during testing.

The Allowable Value specified in SR 3.3.2.1.7 is the least conservative value of the as-found setpoint that a channel can have when tested, such that a channel is OPERABLE if the setpoint is found conservative with respect to the Allowable Value during the CHANNEL CALIBRATION.

The purpose of the RBM is to limit control rod withdrawal if localized neutron flux exceeds a predetermined setpoint during control rod manipulations. It is assumed to function to block further control rod withdrawal to preclude a MCPR Safety Limit violation. The RBM supplies a trip signal to the Reactor Manual Control System (RMCS) to appropriately inhibit control rod withdrawal during power operation above the low power range setpoint. The RBM has two channels, either of which can initiate a control rod block when the channel output exceeds the control rod block setpoint. One RBM channel inputs into one RMCS rod block circuit and the other RBM channel inputs into the second RMCS rod block circuit. The.RBM channel signal is generated by averaging a set of local power range monitor (LPRM) signals at various core heights surrounding the control rod being withdrawn. A simulated thermal power signal from one of the four redundant average power range monitor -

(APRM) channels supplies a reference signal for one of the RBM channels and a simulated thermal power signal from anbother of the APRM channels supplies the reference signal to the second RBM channel. This reference signal is used to determine which RBM range setpoint (low, intermediate, or high) is enabled. If the APRM simulated thermal power is indicating less than the low power range setpoint, the RBM is automatically bypassed. The RBM is also automatically bypassed if a peripheral control rod is selected (Ref. 2).

The purpose of the RWM is to control rod patterns during startup, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 10% RTP. The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA. Prescribed control rod sequences are stored in the RWM, which will initiate control rod withdrawal and insert blocks when the actual sequence deviates beyond allowances from the stored sequence. The RWM determines the actual sequence based position indication for each control rod.

The RWM also uses (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-44a Revision 0

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND steam flow signals to determine when. the reactor power is above the (continued) preset power level at which the RWM is automatically bypassed (Ref. 1).

The RWM is a single channel system that provides input into RMCS rod block channel 2.

The function of the individual rod sequence steps (banking steps) is to minimize the potential reactivity increase from postulated CRDA at low power levels. However, if the possibility for a control rod to drop can be eliminated, then banking steps at low power levels are not needed to ensure the applicable event limits can not be exceeded. 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.

To eliminate the possibility of a CRDA, administrative controls require that any partially inserted control rods, which have not been confirmed to be coupled since their last withdrawal, be fully inserted prior to reaching the THERMAL POWER of <10% RTP. If a control rod has been checked for coupling at notch 48 and the rod has not been moved inward, this rod is in contact with it's drive and is not required to be fully inserted prior to reaching the 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.

The remaining control rods may then be inserted without the need to stop at intermediate positions since the possibility of a CRDA has been eliminated.

With the reactor mode switch in the shutdown position, a control rod withdrawal block is applied to all control rods to ensure that the shutdown-condition is maintained. This Function prevents inadvertent criticality as the result of a control rod withdrawal during MODE 3 or 4, or during MODE 5 when the reactor mode switch is required to be in the shutdown position. The reactor mode switch has two channels, each inputting into a separate RMCS rod block circuit. A rod block in either RMCS circuit will provide a control rod block to all control rods.

APPLICABLE Allowable Values are specified for each applicable Rod Block Function SAFETY listed in Table 3.3.2.1-1. The NTSPs (actual trip setpoints) are selected ANALYSES, to ensure that the setpoints are conservative with respect to the LCO, and Allowable Value. A channel is inoperable if its actual trip setpoint is non-APPLICABILITY conservative with respect to its required Allowable Value.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-44b Revision 0

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE NTSPs are those predetermined values of output at which an action SAFETY should take place. The setpoints are compared to the actual process ANALYSES, parameter (e.g., reactor power), and when the measured output value of LCO, and the process parameter exceeds the setpoint, the associated device (e.g.,

APPLICABILITY trip unit) changes state. The Analytical Limits are derived from the (continued) limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the Analytical Limits, corrected for calibration, process, and some of the instrument errors. The NTSPs are then determined, accounting for the remaining channel-uncertainties. The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, and drift are accounted for.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

1. Rod Block Monitor The RBM is designed to.prevent violation of the MCPRSL and the cladding 1% strain Fuel design limit that may result from a single control -

rod withdrawal[(RWE) event:

The RBM is designed to limit bontrol rod withdrawal if localized neutron flux exceeds a predetermined setpoint. The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference 14. The fuel thermal performance as a function of RBM Allowable Value is determined from the analysis. The NTSP and Allowable Values are chosen as a function of power level. NTSP operating limits are established based on the specified Allowable Values.-

The RBM function satisfies Criterion 3 of the NRC Policy Statement (Ref. 7).

Two channels of the RBM are required to be OPERABLE, with their setpoints within the appropriate Allowable Value for the associated power range, to ensure that no single instrument failure can preclude a rod block for this Function. The actual setpoints are calibrated consistent with applicable setpoint methodology.

Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Values between successive CHANNEL CALIBRATIONS.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-45 Revision 3

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE Nominal trip setpoints are those predetermined values of output at which SAFETY an action should take place. The trip setpoints are compared to the ANALYSES, actual process parameter, the calculated RBM flux (RBM channel signal).

LCO, and When the normalized RBM flux value exceeds the applicable trip APPLICABILITY setpoint, the RBM provides a trip output.

(continued)

The analytic limits are derived from the limiting values of the process parameters. Using the GE setpoint methodology, based on ISA RP 67.04, Part II "Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation" setpoint calculation Method 2, the RBM Allowable Values are determined from the analytical limits using the statistical combination of the RBM input signal calibration error, process measurement error, primary element accuracy and instrument accuracy under trip conditions. Accounting for these errors assures that a setpoint found during calibration at the Allowable Value has adequate margin to protect the analytical limit thereby protecting the Safety Limit.

For the digital RBM, there is a normalization process initiated upon rod selection, so that only RBM input signal drift over the interval from the rod-selection to rod movement needs to be considered in determining the nominal trip setpoints: The RBM has.no drift characteristic with no as-left or as-found tolerances since it only performs digital calculations on the digitized input signals.provided-by the APRMs.

The RBM Allowable Value demonstrates that the analytical limit would not be exceeded, thereby protecting the safety limit. The Nominal trip setpoints and Allowable Values determined in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and environment errors are accounted for and appropriately applied for the RBM. There are no margins applied to the RBM nominal trip setpoint calculations which could mask RBM degradation.

The RBM will function when operating greater than or equal to 28% RTP.

Below this power level, the RBM is not required to be OPERABLE.

The RBM selects one of three different RBM flux trip setpoints to be applied based on the current value of THERMAL POWER. THERMAL POWER is indicated to each RBM channel by a simulated thermal power (STP) reference signal input from an associated reference APRM channel. The OPERABLE range is divided into three "power ranges," a "low power -

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-45a Revision 0

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE range," an "intermediate power range," and a "high power range." The SAFETY RBM flux trip setpoint applied within each of these three power ranges is, ANALYSES, respectively, the "low trip setpoint," the "intermediate trip setpoint," and LCO, and the "high trip setpoint" (Allowable Values for which are defined in the APPLICABILITY COLR). To determine the current power range, each RBM channel (continued) compares its current STP input value to three power setpoints, the "low power setpoint", (28%), the "intermediate power setpoint" (current value defined in the COLR), and the "high power setpoint" (current value defined in the COLR), which define, respectively, the lower limit of the low power range, the lower limit of the intermediate power range, and the lower limit of the high power range. The trip setpoint applicable for each power range is more restrictive than the corresponding setpoint for the lower power range(s). When STP is below the low power setpoint, the RBM flux trip outputs are automatically bypassed but the low trip setpoint continues to be applied to indicate the RBM flux setpoint on the NUMAC RBM displays.

The calculated setpoints and applicable power ranges are bounding values. In the eqtuipment implementation, it is necessary to apply a "deadband" to each setpoint.--The deadband is-applied to the RBM trip -

setpoint selection logic and the RBM trip automatic bypass logic such that the setpoint being applied'is always equal to or more conservative than the required setpoint. Since the RBM flux trip setpoint applicable to the higher power ranges are more conservative than the corresponding trip-setpoints for lower power ranges, the trip setpoint applicable to the higher power range (high power range or intermediate power range) continues to be applied when STP decreases below the lower limit of that range until STP is below the power range setpoint by a value exceeding the deadband. Similarly, when STP decreases below the low power setpoint, the automatic bypass of RBM flux trip outputs will not be applied until STP decreases below the trip setpoint a value exceeding the deadband.

The RBM channel uses THERMAL POWER, as represented by the STP input value from its reference APRM channel, to automatically enable RBM flux trip outputs (remove the automatic bypass) and to select the RBM flux trip setpoint to be applied. However, the RBM Upscale function is only required to be OPERABLE when the MCPR values are less than the values defined in the COLR, depending on the THERMAL POWER level. Therefore, even though the RBM Upscale Function is implemented in each RBM channel as a single trip function with a selected trip setpoint, it is characterized in Table 3.3.2.1-1 as three Functions, the Low Power (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-45b Revision 0

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE Range - Upscale Function, the Intermediate Power Range - Upscale SAFETY Function, and the High Power Range - Upscale Function, to facilitate ANALYSES, correct definition of the OPERABILITY requirements for the Functions.

LCO, and Each Function corresponds to one of the RBM power ranges. Due to the APPLICABILITY deadband effects on the determination of the current power range, the (continued) transition between these three Functions will occur at slightly different THERMAL POWER levels for increasing power versus decreasing power.

2. Rod Worth Minimizer The RWM enforces the banked position withdrawal sequence (BPWS) to ensure that the initial conditions of the CRDA analysis are not violated.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-46 Revision 3

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE The analytical methods and assumptions used in evaluating the CRDA SAFETY are summarized in References 2, 3, 4, and 5. The BPWS requires that ANALYSES, control rods be moved in groups, with all control rods assigned to a LCO, and specific group required to be within specified banked positions.

APPLICABILITY Requirements that the control rod sequence is in compliance with the (continued) BPWS are specified in LCO 3.1.6, "Rod Pattern Control."

When performing a shutdown of the plant, an optional BPWS control rod sequence (Ref. 7) may be used if the coupling of each withdrawn control rod has been confirmed. The rods may be inserted without the need to stop at intermediate positions. When using the Reference 11 control rod insertion sequence for shutdown, the rod worth minimizer may be reprogrammed to enforce the requirements of the improved BPWS control rod insertion, or may be bypassed and the improved BPWS shutdown sequence implemented under the controls in Condition D.

The RWM Function satisfies Criterion 3 of the NRC Policy Statement.

(Ref. 7)

Since the RWM is designed to act as a backup to operator control of the -

rod sequences, only one channel of the RWM is available and required to be OPERABLE (Ref. 6). Special circumstances provided for in the Required Action of LCO 3.1.3ý, "Control Rod OPERABILITY," and LCO 3.1.6 may necessitate bypassing the RWM to allow continued -

operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the BPWS. The RWM may be bypassed as required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO followed.

Compliance with the BPWS, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is < 10% RTP.

When THERMAL POWER is > 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Refs. 4 and 6). In MODES 3 and 4, all control rods are required to be inserted into the core (except as provided in 3.10 "Special Operations"); therefore, a CRDA cannot occur. In MODE 5, since 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 be subcritical.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-47 Revision 2

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE 3. Reactor Mode Switch-Shutdown Position SAFETY ANALYSES During MODES 3 and 4, and during MODE 5 when the reactor mode LCO, and switch is required to be in the shutdown position, the core is assumed to APPLICABILITY be subcritical; therefore, no positive reactivity insertion events are (continued) analyzed. The Reactor Mode Switch-Shutdown Position control rod withdrawal block ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety analysis.

The Reactor Mode Switch-Shutdown Position Function satisfies Criterion 3 of the NRC Policy Statement. (Ref. 7)

Two channels are required to be OPERABLE to ensure that no single channel failure, will preclude a rod block when required. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on reactor mode switch position.

During shutdown conditions (MODE 3, 4, or 5), no positive reactivity insertion events are analyzedbecause assumptions are that control rod withdrawal blocks are provided to prevent criticality. Therefore, when the reactor mode switch is in the shutdown position, the control rod withdrawal.block is required t6 be OPERABLE. During MODE 5 with the reactor mode switch in the refueling position, the refuel position -

one-rod-out interlock (LCO 3.9.2) provides the required control rod withdrawal blocks.

ACTIONS A.1 With one RBM channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod block function; however, overall reliability is reduced because a single failure in the remaining OPERABLE channel can result in no control rod block capability for the RBM. For this reason, Required Action A.1 requires restoration of the inoperable channel to OPERABLE status. The Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on the low probability of an event occurring coincident with a failure in the remaining OPERABLE channel.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-48 Revision 3

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS B.1 (continued)

If Required Action A.1 is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

If both RBM channels are inoperable, the RBM is not capable of performing its intended function; thus, one channel must also be placed in trip. This initiates a control rod withdrawal block, thereby ensuring that the RBM function is met.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities and is acceptable because it minimizes risk while allowing time for restoration or tripping of inoperable channels.

C.1, C.2.1.1, C.2.1.2, and C.2.2 With the RWM inoperable during a reactor startup, the operator is still

- capable of enforcing the prescribed control rod sequence. However, the overall reliability is reduced because a single operator error can result in -

violating the control rod sequence. Therefore, control rod movement must be immediately suspended except by scram. Alternatively, startup-may continue if at least 12 control rods have already been withdrawn, or a reactor startup with an inoper'able RWM was not performed in the last calendar year, i.e., the last 12 months. Required Actions C.2.1.1 and C.2.1.2 require verification of these conditions by review of plant logs and control room indications. A reactor startup with an inoperable RWM is defined as rod withdrawal during startup when the RWM is required to be OPERABLE. Once Required Action C.2.1.1 or C.2.1.2 is satisfactorily completed, control rod withdrawal may proceed in accordance with the restrictions imposed by Required Action C.2.2. Required Action C.2.2 allows for the RWM Function to be performed manually and requires a

'double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow continued operations!. In addition, Required Actions of LCO 3.1.3 and LCO 3.1.6 may require bypassing the RWM, during which time the RWM must be considered inoperable with Condition C entered and its Required Actions taken.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-49 Revision 3

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS D. 1 (continued)

With the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence. Required Action D.1 allows for the RWM Function to be performed manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow the reactor shutdown to continue.

E.1 and E.2 With one Reactor Mode Switch-Shutdown Position control rod withdrawal block channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal block function.

However, since the Required Actions are consistent with the normal action of an OPERABLE Reactor Mode Switch-Shutdown Position Function (i.e., maintaining all control rods inserted), there is no distinction -

between having one or two channels inoperable.

In both cases (one or both channels inoperable), suspending all control -

rod withdrawal and initiating action to fully insert all insertable Control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritical with adequate SDM ensured by LCO 3.1.1. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Control Rod REQUIREMENTS Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1.

The Surveillances are modified by a Note to indicate that when an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains control rod block capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 9, 12 and 13).

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-50 Revision 3

PPL Rev. 3 Control Rod Block Instrumentation 3.3.2.1 BASES SURVEILLANCE assumption of the average time required to perform channel Surveillance.

REQUIREMENTS That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not (continued) significantly reduce the probability that a control rod block will be initiated when necessary.

SR 3.3.2.1.1 A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended function. It includes the Reactor Manual Control Multiplexing System input. The Frequency of 184 days is based on reliability analyses (Refs. 8, 12 and 13).

SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function. The CHANNEL FUNCTIONAL TEST for the RWM is performed by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs and by verifying proper indication of the selection error of at least one out-of-sequence control rod. As noted "

in the SRs, SR 313.2.1.2. is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after-any control rod is withdrawn in MODE 2. --As noted, SR 3.3.2.1.3 is not required to beperformed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after THERMAL POWER is

< 10% RTP in MODE-1. This allows entry into MODE 2 for SR 3.3.2.1.2, and entry into MODE 1 whenTHERMAL POWER is < 10% RTP for SR 3.3.2.1.3,to perform the required Surveillance if the 92 day Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Frequencies are based on reliability analysis (Ref. 8).

SR 3.3.2.1.4 The RBM setpoints are automatically varied as a function of Simulated Thermal Power. Three control rod block Allowable Values are specified in Table 3.3.2.1-1, each within a specific power range. The power at which the control rod block Allowable Values automatically change are based on the APRM signal's input to each RBM channel. Below the minimum power setpoint, the RBM is automatically bypassed. These control rod block NTSPs must be verified periodically to be less than or equal to the specified Allowable Values. If any power range setpoint is non-conservative, then the affected RBM channel is considered inoperable. As noted, neutron detectors are excluded from the Surveillance because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.3 and SR 3.3.1.1.8. The 24 month Frequency is based on the actual trip setpoint methodology utilized for these channels.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-51 Revision 3

PPL Rev. 3 Control Rod Block Instrumentation 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS SR 3.3.2.1.5 (continued)

The RWM is automatically bypassed when power is above a specified value. The power level is determined from steam flow signals. The automatic bypass setpoint must be verified periodically to be not bypassed < 10% RTP. This is performed by a Functional check. If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable. Alternately, the low power setpoint channel can be placed in the conservative condition (nonbypass). If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Frequency is based on the need to perform the Surveillance during a plant start-up.

SR 3.3.2.1.6 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch-Shutdown Position Function to ensure that the entire channel will perform the intended function. The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch-Shutdown Position Function is performed by-attempting to withdraw any control rod with the reactor mode switch in the.

shutdown position and verifying a control rod block occurs.

As noted in the SR, the Surveillance is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-52 Revision 2

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.6 (continued)

REQUIREMENTS links. This allows entry into MODES 3 and 4 if the 24 month Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.

The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.2.1.7 CHANNEL CALIBRATION is a test that verifies the channel responds to

- the measured parameter with the necessary range and accuracy..

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibration consistent with the plant -

specific setpoint methodology.

As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8.

The Frequency is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.2.1.7 for the RBM Functions is modified by two Notes as identified in Table 3.3.2.1-1. The RBM Functions are Functions that are LSSSs for reactor core Safety Limits. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is not the NTSP but is conservative with respect to the Allowable Value. For digital channel components, no as-found tolerance or as-left tolerance can be specified. Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions. The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. These channels will also be identified in the Corrective Action Program.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-53 Revision 2

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE Entry into the Corrective Action Program will ensure required review and REQUIREMENTS documentation of the condition for continued OPERABILITY. The second (continued) Note requires that the as-left setting for the instrument be returned to the NTSP. If the as-left instrument setting cannot be returned to the NTSP, then the instrument channel shall be declared inoperable. The second Note also requires that the NTSP and NTSP methodology are to be contained in a document controlled by 10 CFR 50.59.

SR 3.3.2.1.8 The RWM will only enforce the proper control rod sequence if the rod sequence is properly input into the RWM computer. This SR ensures that the proper sequence is loaded into the RWM so that it can perform its intended function. The Surveillance is performed once prior to declaring" RWM OPERABLE following loading of sequence into RWM, since this is when rod sequence input errors are possible.

(continued)

SUSQUEHANNA - UNIT 1 TS /B 3.3-53a Revision 0

PPL Rev. 3 Control Rod Block Instrumentation B 3.3.2.1 BASES (continued)

REFERENCES 1. FSAR, Section 7.7.1.2.8.

2. FSAR, Section 7.6.1.a.5.7

3. NEDE-24011-P-A-9-US, "General Electrical Standard Application for Reload Fuel," Supplement for United States, Section S 2.2.3.1, September 1988.

4. "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners' Group, July 1986.

5. NEDO-21231, "Banked Position Withdrawal Sequence,"

January 1977.

6. NRC SER, "Acceptance of Referencing of Licensing Topical Report NEDE-2401 1-P-A," "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987.

7. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 32193)

8. NEDC-30851-P-A, "Technical Specificatiorn Improvement Analysis for BWR Control Rod.Block Instrumentation," October 1988.

9. GENE-770-06-1, "Addendum to Bases for changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation, Technical Specifications," February 1991.

10. FSAR, Section 15.4.2.

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

12. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995.

13. NEDC-32410P-A Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," November 1997.

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

SUSQUEHANNA - UNIT 1 TS / B 3.3-54 Revision 4

PPL Rev. 1 Feedwater- Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 B 3.3 INSTRUMENTATION B 3.3.2.2 Feedwater- Main Turbine High Water Level Trip Instrumentation BASES BACKGROUND The feedwater - main turbine high water level trip instrumentation is designed to detect a potential failure of the Feedwater Level Control System that causes excessive feedwater flow.

With excessive feedwater flow, the water level in the reactor vessel rises toward the high water level, Level 8 reference point, causing the trip of the three feedwater pump turbines and the main turbine.

Reactor Vessel Water Level-High, Level 8 signals are provided by level sensors that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level in the reactor vessel (variable leg). Three channels of Reactor Vessel Water Level-High, Level 8 instrumentation. are provided as input to a two-out-of-three initiation logic that trips the three feedwater pump turbines and the main-turbine. When the setpoint is exceeded, the channel sensor actuates, which then outputs a main-feedwater and turbine trip signal to the trip logic.

A trip of the feedwater pump turbines limits further increase in reactor vessel water level by limiting further addition of feedwater to the reactor vessel. A trip of the main turbine and closure of the stop valves protects the turbine from damage due to water entering the turbine.

APPLICABLE The feedwater - main turbine high water level trip instrumentation is SAFETY ANALYSES assumed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The Level 8 trip indirectly initiates a reactor scram from the main turbine trip (above 26% RTP) and trips the feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-55 Revision 1

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES APPLICABLE Feedwater - main turbine high water level trip instrumentation satisfies SAFETY ANALYSES Criterion 3 of the NRC Policy Statement. (Ref. 3)

(continued)

LCO The LCO requires three channels of the Reactor Vessel Water Level-High, Level 8 trip instrumentation to be OPERABLE to ensure that no single instrument failure will prevent the feedwater pump turbines and main turbine trip on a valid Level 8 signal. Two of the three channels are needed to provide trip signals in order for the feedwater - main turbine trips to occur. Each channel must have its setpoint set within the specified Allowable Value of SR 3.3.2.2.3. The Allowable Value is set to ensure that the thermal limits are not exceeded during the event.

The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumptions. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but-within its Allowable Value,- is acceptable.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value-of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-56 Revision 0

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES (continued)

APPLICABILITY The feedwater - main turbine high water level trip instrumentation is required to be OPERABLE at > 23% RTP to ensure that the fuel cladding integrity Safety Limit is not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases of LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR),"

sufficient margin to these limits exists below 23% RTP; therefore, the requirements are only necessary when operating at or above this power level.

ACTIONS A Note has been provided to modify the ACTIONS related to feedwater - main turbine high water level trip instrumentation channels.

Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition- However, the Required Actions-for inoperable feedwater - main turbine high water level trip instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable feedwater -

main turbine high water level trip instrumentation channel.

A.1 With one channel inoperable, the remaining two OPERABLE channels can provide the required trip signal. However, overall instrumentation reliability is reduced because a single failure in one of the remaining channels concurrent with feedwater controller failure, maximum demand event, may result in the instrumentation not being able to perform its intended function. Therefore, continued operation is only allowed for a limited time with one channel inoperable. If the inoperable channel cannot be restored to OPERABLE status within the Completion Time, the channel must be placed in the tripped condition per Required Action A.1. Placing the (continued)

SUSQUEHANNA - UNIT 1 B 3.3-57 Revision 1

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES ACTIONS A.1 (continued) inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue with no further restrictions. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in a feedwater or main turbine trip), Condition C must be entered and its Required Action taken.

If the failure only effects the trip function of a single component, such as a main feed pump, an option is always available to remove the affected component from service and restore OPERABILITY. This is acceptable because removing the component from service performs the safety function.

The Completion Time of 7 days is based on the low probability of the event occurring coincident with a single failure in a remaining OPERABLE channel.

B.1 With two or more channels inoperable, the feedwater - main turbine high water level trip instrumentation cannot perform its design function (feedwater - main turbine high water level trip capability is not maintained). Therefore, continued operation is only permitted for a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period, during which feedwater - main turbine high water level trip capability must be restored. The trip capability is considered maintained when sufficient channels are OPERABLE or in trip such that the feedwater - main turbine high water level trip logic will generate a trip signal on a valid signal. This requires two channels to each be OPERABLE or in trip. If the required channels cannot be restored to OPERABLE status or placed in trip, Condition C must be entered and its Required Action taken.

If the failure only affects the trip function of a single main feed pump, an option is always available to remove the affected component from service and restore OPERABILITY. This is acceptable because removing the component from service performs the safety function.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-58 Revision 0

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES ACTIONS B.1 .(continued)

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of feedwater - main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time provided in LCO 3.2.2 for Required Action A. 1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not restored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to < 23% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . As discussed in the Applicability section of the Bases, operation below 23% RTP results in sufficient margin to the required limits, and the-feedwater - main turbine high water level trip instrumentation is not required to protect fuel integrity during the

.1.

feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is based on operating experience to reduce THERMAL POWER to < 23% RTP from full power conditions in an orderly manner and without challenging plant systems.

If the failure only affects the trip function of a single main feed pump, an option is always available to remove the affected component from service and restore OPERABILITY. This is acceptable because removing the component from service performs the safety function.

SURVEILLANCE The Surveillances are modified by a Note to indicate that when a REQUIREMENTS channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains feedwater - main turbine high water level trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status (continued)

SUSQUEHANNA - UNIT 1 B 3.3-59 Revision 1

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE or the applicable Condition entered and Required Actions taken. This REQUIREMENTS Note is based on the reliability analysis (Ref. 2) assumption that (continued) 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is the average time required to perform channel Surveillance.

That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the feedwater pump turbines and main turbine will trip when necessary.

SR 3.3.2.2.1 Performance of the CHANNEL CHECK once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels, or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it-is key to verifying the instrumentation continues to operate properly between each CHANNEL-CALIBRATION.

Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channel status during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.2.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-60 Revision 0

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.2 (continued)

REQUIREMENTS The Frequency of 92 days is based on reliability analysis (Ref. 2).

This SR is modified by two Notes. Note 1 provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relays which input into the combinational logic. (Reference 4) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic.

The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.2.2.4. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass-the LOGIC SYSTEM FUNCTIONAL TEST, and-the testing methodology minimizes the risk -

of unplanned- transients.

Note 2- provides a second specific exception to the definition of CHANNEL FUNCTIONAL TEST. For the Feedwater - Main Turbine High Water Level Trip Function, certain required channel relays are not included in the performance of the CHANNEL FUNCTIONAL TEST.

These exceptions are necessary because the circuit design does not facilitate functional testing of the entire channel through to the coil of the relay which enters the combinational logic. (Reference 4)

Specifically, testing of all required relays Would require lifting of leads and inserting test equipment which could lead to unplanned transients.

Therefore, for this circuit, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the actuation of circuit devices up to the point where further testing could result in an unplanned transient.

(References 5 and 6) The required relays not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.2.2.4. This exception is acceptable because operating experience shows that the devices not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-61 Revision 0

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.3 REQUIREMENTS (continued) CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.2.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the feedwater - main turbine valves is included as part of this Surveillance and overlaps the LOGIC SYSTEM -

FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a valve is incapable of operating, the associated instrumentation would also be inoperable. The 24 month Frequency is based on -theneed to perform this Surveillance under the conditions that apply during'a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. FSAR, Section 15.1.2.

2. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.

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

(continued)

,SUSQUEHANNA - UNIT 1 B 3.3-62 Revision 0

PPL Rev. 1 Feedwater - Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES REFERENCES 4. NRC Inspection and Enforcement Manual, Part 9900: Technical (continued) Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.

5. PLA-2618: NRC Inspection Reports 50-387/85-28 and 50-388/85-23.

6. NRC Region I Combined Inspection 50-387/90-20;50-388/90-20.

SUSQUEHANNA - UNIT 1 B 3.3-63 Revision 0

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 B 3.3 INSTRUMENTATION B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The primary purpose of the PAM instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Events. The instruments that monitor these variables are designated as Type A, Category I, and non-Type A, Category I, in accordance with Regulatory Guide 1.97 (Ref. 1).

The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected plant parameters

-to monitor and assess plant status and behavior following an accident.

This capability is consistent with the recommendations of Reference 1.

APPLICABLE The PAM instrumentation LCQ ensures the OPERABILITY of Regulatory SAFETY Guide 1.97, Type A variables so that the control room operating staff can:

ANALYSES Perform the diagnosis specified in the Emergency Operating Procedures (EOPs). These variables are restricted to preplanned actions for the primary success path of Design Basis Accidents (DBAs), (e:g., loss of coolant accident (LOCA)), and

Take the specified, preplanned, manually controlled actions for which no automatic control is provided, which are required for safety systems to accomplish their safety function.

The PAM instrumentation LCO also ensures OPERABILITY of Category I, non-Type A, variables so that the control room operating staff can:

Determine whether systems important to safety are performing their intended functions; (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-64 Revision 2

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES APPLICABLE

Determine the potential for causing a gross breach of the barriers to SAFETY radioactivity release; ANALYSES (continued)

Determine whether a gross breach of a barrier has occurred; and

° Initiate action necessary to protect the public and for an estimate of the magnitude of any impending threat.

The plant specific Regulatory Guide 1.97 Analysis (Ref. 2 and 3) documents the process that identified Type A and Category I, non-Type A, variables.

Accident monitoring instrumentation that satisfies the definition of Type A in Regulatory Guide 1.97 meets Criterion 3 of the NRC Policy Statement.

(Ref. 4) Category I, non-Type A, instrumentation is retained in Technical Specifications (TS) because they are intended to assist operators in

-minimizing the consequences of accidents. Therefore, these Category I variables are important for reducing public risk.

LCO LCO 3.3.3.1 requires two OPERABLE channels for all but one Function to ensure that no single failure prevents the operators from being presented with the information necessary to determine the status of the -

plant and to bring the plant to, and maintain it in, a safe condition following that accident.

Furthermore, provision of two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.

The exception to the two channel requirement is primary containment isolation valve (PCIV) position. In this case, the important information is the status of the primary containment penetrations. The LCO requires one position indicator for each active PCIV. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status of the active valve and prior knowledge of passive valve or via system boundary (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-65 Revision 2

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES LCO status. If a normally active PCIV is known to be closed and deactivated, (continued) position indication is not needed to determine status. Therefore, the position indication for valves in this state is not required to be OPERABLE.

The following list is a discussion of the specified instrument Functions listed in Table 3.3.3.1-1 in the accompanying LCO. Table B 3.3.3.1-1 provides a listing of the instruments that are used to meet the operability requirements for the specific functions.

1. Reactor Steam Dome Pressure Reactor steam dome pressure is a Type A, Category 1, variable provided to support monitoring of Reactor Coolant System (RCS) integrity and to verify operation of the Emergency Core Cooling Systems (ECCS). Two independent pressure channels, consisting of three wide range control room indicators and one wide range control room recorder per channel

-with a range of 0 psig to 1500 psig, monitor pressure. The wide range recorders are the primary method of indication available for use by the operators during an accident, therefore, the PAM Specification deals specifically with this portion of the instrument channel.

2. Reactor Vessel Water Level Reactor vessel water level is a Type A, Category 1, variable provided to support monitoring of core cooling and to verify operation of the ECCS.

A combination of three different level instrument ranges, with two independent channels each, monitor Reactor Vessel Water Level. The extended range instrumentation measures from -150 inches to 180 inches and outputs to three control room level indicators per channel.

The wide range instrumentation measures from -150 inches to 60 inches and outputs to one control room recorder and three control room indicators per channel. The fuel zone range instrumentation measures from -310 inches to -110 inches and outputs to a control room recorder (one channel) and a control room indicator (one channel). These three ranges of instruments combine to provide level indication from the bottom of the Core to above the main steam line. The wide range level recorders, the fuel zone level indicator and level recorder, and one inner ring extended range level indicator per channel are the primary method of indication available for use by the operator during an accident, therefore the PAM (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-66 Revision 4

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES LCO 2. Reactor Vessel Water Level (continued)

Specification deals specifically with this portion of the instrument channel.

3. Suppression Chamber Water Level Suppression chamber water level is a Type A, Category 1, variable provided to detect a breach in the reactor coolant pressure boundary (RCPB). This variable is also used to verify and provide long term surveillance of ECCS function. A combination of two different level instrument ranges, with two independent channels each, monitor Suppression chamber water level. The wide range instrumentation measures from the ECCS suction lines to approximately the top of the chamber and outputs to one control room recorder per channel. The wide range recorders are the primary method of indication available for use by the operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel.

4: Primary Containment Pressure Primary Containment pressure is a Type A, Category 1, variable provided to detect a-breach of the RCPB and to verify ECCS functions that operate to maintain-RCS integrity. A combination of two different pressure instrument ranges, with two independent channels each, monitor primary containment pressure. The LOCA range measures from -15 psig to 65 psig and outputs to one control room recorder per channel. The accident range measures from 0 psig to'250 psig and outputs to one control room recorder per channel (same recorders as the LOCA range). The recorders (both ranges) are the primary method of indication available for use by the operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel.

5. Primary Containment High Radiation Primary containment area radiation (high range) is provided to monitor the potential of significant radiation releases (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-67 Revision 3

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES LCO 5. Primary Containment High Radiation (continued) and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Two independent channels, which output to one control room recorder per channel with a range of 100 to 1X108 R/hr, monitor radiation. The PAM Specification deals specifically with this portion of the instrument channel.

6. Primary Containment Isolation Valve (PCIV) Position PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the isolation status of the containment penetration. The LCO requires a channel of valve position indication in the control room to be OPERABLE for an active PCIV in a containment penetration flow path, i.e., two total channels of PCIV position indication for a penetration flow path with two active valves.

For containment penetrations with only one active PCIV having control

-room indication, Note (b) requires a single channel of valve position-indication to be OPERABLE. This is sufficient to redundantly verify the isolation status.of each isolable penetratidh via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary states. If a penetration flow path is isolated, position indication for the PCIV.(s) in the .associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE.

These valves which require position indication are specified in Table B 3.6.1.3-1. Furthermore, the loss of position indication does not necessarily result in the PCIV being inoperable.

The PCIV position PAM instrumentation consists of position switches unique to PCIVs, associated wiring and control room indicating lamps (not necessarily unique to a PCIV) for active PCIVs (check valves and manual valves are not required to have position indication). Therefore, the PAM Specification deals specifically with these instrument channels.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-68 Revision 4

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES LCO

7. Neutron Flux (continued)

Wide range neutron flux is a Category I variable provided to verify reactor shutdown. The Neutron Monitoring System Average Power Range Monitors (APRM) provides reliable neutron flux measurement from 0% to 125% of full power. The APRM consists of four channels each with their own chassis powered with redundant power supplies. The APRM sends signals to the analog isolator module which in turn sends individual APRM signals to the recorders used for post accident monitoring. The PAM function for neutron flux is satisfied by having any 2 channels of APRM provided for post accident monitoring. The PAM Specification deals specifically with this portion of the instrument channel.

The Neutron Monitoring System (NMS) was evaluated against the criteria established in General Electric NEDO-31558A to ensure its acceptability for post-accident monitoring. NEDO-31558A provides alternate criteria

-for the NMS to meet the post-accident monitoring guidance of Regulatory Guide 1.97. Based on the evaluation, the NMS was found to meet the criteria established in NEDO-31558A. The APRM sub-function of the NMS is used to provide the Neutron Flux monitoring identified in TS 3.3.3.1 (Ref. 5 and 6). - .

8. Not Used (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-69 Revision 5

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES LCO (co 9. Drywell Atmosphere Temperature (continued)

Drywell atmosphere temperature is a Category I variable provided to verify RCS and containment integrity and to verify the effectiveness of ECCS actions taken to prevent containment breach. Two independent temperature channels, consisting of two control room recorders per channel with a range of 40 to 440 degrees F, monitor temperature. The PAM Specification deals specifically with the inner ring temperature recorder portion of the instrument channel.

10. Suppression Chamber Water Temperature Suppression Chamber water temperature is a Type A, Category 1, variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression chamber water

-temperature instrumentation allows operators to detect trends in suppression chamber water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Two channels are required to be OPERABLE. Each channel consists of eight sensors of-which a minimum of four sensors (one sensor in each quadrant) must be OPERABLE to consider a channel OPERABLE. The outputs for the temperature sensors are displayed on two independent indicators in the control room and recorded on the monitoring units located on control room panel 1C601. The temperature indicators are the primary method of indication available for use by the operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1 and 2. These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5, plant conditions are such that the likelihood of an event that would require PAM instrumentation is extremely low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-70 Revision 4

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES (continued)

ACTIONS A note has been provided to modify the ACTIONS related to PAM instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable PAM instrumentation channels provide appropriate compensatory measures for separate Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable PAM Function.

A.1 When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restored to

-OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channels, the passive nature-of the-instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval.

B.1 If a channel has not been restored to OPERABLE status in 30 days, this Required Action specifies initiation of action in accordance with Specification 5.6.7, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative actions.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-71 Revision 3

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES ACTIONS B.1 (continued)

This action is appropriate in lieu of a shutdown requirement because alternative actions are identified before the written report is submitted to the NRC, and given the likelihood of plant conditions that would require information provided by this instrumentation.

C.1 When one or more Functions have two required channels that are inoperable (i.e., two channels inoperable in the same Function), one channel in the Function should be restored to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information.

Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification, requirements applied to the PAM instrumentation. Therefore, requiring restoration -of one inoperable channel of the Function limits-the risk that the PAM Function will be in a degraded condition should an accident occur.

D. 1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met any Required Action of Condition C, as applicable, and the associated Completion Time has expired, Condition D is entered for that channel and provides for transfer to the appropriate subsequent Condition.

E. 1 For the majority of Functions in Table 3.3.3.1-1, if any Required Action and associated Completion Time of Condition C are not met, the plant must be brought to a MODE in which the LCO not apply. To achieve this status, the plant 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 .

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-72 Revision 2

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES ACTIONS E.1 (continued) from full power conditions in an orderly manner and without challenging plant systems.

F. 1 Since alternate means of monitoring primary containment area radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.7. These alternate means will be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

SURVEILLANCE The following SRs apply to each PAM instrumentation Function in REQUIREMENTS Table 3.3.3.1-1..

SR 3.3.31.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious.

A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-73 Revision 2

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 (continued)

REQUIREMENTS parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit and does necessarily indicate the channel is Inoperable.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of those displays associated with the required channels of this LCO.

SR 3.3.3.1.2 and SR 3.3.3.1.3 A CHANNEL CALIBRATION is performed every 24 months except for the -

PCIV Position Function. The PCIV Position Function is adequately demonstrated by the Remote Position Indication performed in accordance with 5.5.6, ;Inservice Testing Program". CHANNEL CALIBRATION verifies that the channel responds to measured parameter with the necessary range and accuracy, and does not include alarms.

The CHANNEL CALIBRATION for the Containment High Radiation instruments shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr and a one point calibration check of the detector below 10 R/hr with an installed or portable gamma source.

The Frequency is based on operating experience and for the 24 month Frequency consistency with the industry refueling cycles.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-74 Revision 3

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 BASES REFERENCES 1. Regulatory Guide 1.97 Rev. 2, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," February 6, 1985

2. Nuclear Regulatory Commission Letter A. Schwencer to N. Curtis, Emergency Response Capability, Conformance to R.G. 1.97, Rev. 2, dated February 6, 1985.

3. PP&L Letter (PLA-2222), N. Curtis to A. Schwencer, dated May 31, 1984.

4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 32193)

5. NEDO-31558A, BWROG Topical Report, Position on NRC Reg.

Guide 1.97, Revision 3 Requirements for Post Accident Neutron Monitoring System (NMS).

6: Nuclear Regulatory Commission Letter from C. Poslusny to R.G.

Byram-dated July 3,.1996.'

SUSQUEHANNA - UNIT 1 TS / B 3.3-75 Revision 2

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 1 of 3)

Instrument/Variable Elemen t Transmitter Recorder Indicator

1. Reactor Steam UR-14201A PI-14202A Dome Pressure N/A PT-14201A (red)* PI-14202A1 (red)*_ PI-14204A PI-14202B (left side)

N/A PT-14201B (red)* PI-14202B1 (left side)

(red)* PI-14204B (left side)

2. Reactor Vessel LT-14201A UR-14201A LI-14201A (left side)

Water Level N/A T42AUi21A LI-14201A1 LI-14203A (left side)

(left side)

(Wide Range) (blue)*

LI-14203A (left side)

LT-14201B UR-14201B LI-14201B (left side)

N/A LI-14201B1 (left side)

" (Wide Range)

-LI-14203B (blue)*LI123 (efsi)

(left side)

A LT-1420A LI-14201A (right side)"(1)

N/A ExTend0d R N/A LI-14201A1 (right side)

(ExtndeRage)LI-14203A (right side)

N/A LT-14203B LI-14201B (right side)"C1 (Extended Range) N/A LI-14201B1 LI-14203B (right side) o (right side)

LT-14202A NA (Fuel Zone UbRo140n A N/

Range) (brown)*________

A LT-14202B UR-14201B N/A (Fuel Zone (brown)* N/A Range) I-

3. Suppression N/A LT-15776A UR-15776A N/A Chamber Water Level (Wide Range) (red)*

N/A LT-15776B UR-15776B N/A (Wide Range) (red)*

N/A LT-15775A UR-15776A LI-i5775A (Narrow Range) (blue)

N/A LT-15775B UR-15776B LI-15775B (Narrow Range) (blue)

TS-Prop/3.3/SA33031A.1i B SUSQUEHANNA - UNIT 1 TS / B 3.3-75a Revision 6

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 2 of 3)

Instrument/Variable Element Transmitter Recorder Indicator

4. Primary N/A PT-UR-15701A (Dark Blue)* N/A Containment (0 to 250 psig)

Pressure PT-1 5709B N/A (0 to 250 psig) UR-15701B (Dark Blue)* N/A PT-i15710OA N/A (-15 to 65 psig) UR-15701A (Red)* N/A PT-15710B N/A (-15 to 65 psig) UR-1 5701 B (Red)* N/A

5. Primary RE-1 5720A RITS-15720A UR-15776A (Green)* N/A Containment High RE-1 5720B RITS-15720B UR-15776B (Green)* N/A RadiationI1 See Technical Specification Bases Table B 3.6.1.3-1 for PCIV that require position indication to be'OPERABLE

7. Neutron Flux N/A APRM1 NR-C51-1R60A N/A (red pen)*

N/A APRM-2 N/A (red pen)*

N/A APRM-3 NR-C51-1 R603C NR-C51-1R603C N/A (red pen)*

N/A APRM-4 ( red N/A (red pen)*

8. Containment AE-15745A UR-15701A (Blue Violet)*

Oxygen and AH-15745A AIT-1 5745A UR-15701A (Violet)* N/A Hydrogen Analyzer (Hydrogen)

AE-15745B AIT-15745B UR-15701B (Blue Violet)* N/A (Hydrogen) UR-15701B (Violet)*

AE-1 5746A AIT-1 5746A UR-15701 A (Orange)* N/A (Oxygen)

AE-1 5746B Oye)

- -AlT-i15746B UR-15701 B (Orange)* N/A SUSQUEHANNA - UNIT 1 TS / B 3.3-75b Revision 6

PPL Rev. 7 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 3 of 3)

Instrument/Variable Element Transmitter Recorder Indicator

9. Drywell Atmosphere TE-15790A TT-15790A UR-15701A (Brown)* N/A Temperature TR-1 5790A (point # 1)

TE-1 5790B TT-1 5790B UR-15701B (Brown)* N/A TR-1 5790B (point # 1)

10. Suppression TE-15753 TX-15751 TIAH,15751* TI-15751 Chamber Water TE-15755 Temperature TE-1 5757 TE-1 5759 TE-15763 TE-15765 TE-15767 TE-1 5769 TE-15752 TX-15752 TIAH-15752* TI-1 5752 I.

TE-1 5754 TE-1 5758 TE-1 5760 TE-15762 TE-15766 TE-15768 TE-1 5770

Indicates that the instrument (and associated components in the instrument channel) is considered as instrument channel surveillance acceptance criteria.

(1) In the case of the inner ring indicators for extended range level, it is recommended that LI-14201A and LI-14201B be used as acceptance criteria, however LI-14201Al, LI-14201B1, LI-14203A, or LI-14203B may be used in their place provided that surveillance requirements are satisfied. Only one set of these instruments needs to be OPERABLE.

SUSQUEHANNA - UNIT 1 TS /B 3.3-75c Revision 5

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 B 3.3 INSTRUMENTATION B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation BASES BACKGROUND The EOC-RPT instrumentation initiates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients to provide additional margin to core thermal MCPR Safety Limits (SLs).

The need for the additional negative reactivity in excess of that normally inserted on a scram reflects end of cycle reactivity considerations. Flux shapes at the end of cycle are such that the control rods may not be able to ensure that thermal limits are maintained by inserting sufficient negative reactivity during the first few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure-Low or Turbine Stop Valve (TSV)-Closure. The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity at a -faster rate than the control rods can add negative reactivity. -

The EOC-RPT instrumentation, as shown in Reference 1, is composed of sensors that detect initiation of closure of the TSVs or fast closure of the TCVs, combined with relays, logic circuits, and fast acting circuit breakers that interrupt power from the recirculation pump motor generator (MG) set generators to each of the recirculation pump motors. When the setpoint is reached, the channel output relay actuates, which then outputs an EOC-RPT signal to the trip logic. When the RPT breakers trip open, the recirculation pumps coast down under their own inertia. The EOC-RPT -

has two identical trip systems, either of which can actuate an RPT.

Each EOC-RPT trip system is a two-out-of-two logic for each Function; thus, either two TSV-Closure or two TCV Fast Closure, Trip Oil Pressure-Low signals are required for a trip system to actuate. The Turbine Stop Valve - Closure functions such that:

(1) The closing of one Turbine Stop Valve will not cause an RPT trip.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-81 Revision 0

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES BACKGROUND (2) The closing of two Turbine Stop Valves may or may not cause an (continued) RPT trip depending on which stop valves are closed.

(3) The closing of three or more Turbine Stop Valves will always yield an RPT trip.

If either trip system actuates, both recirculation pumps will trip. There are two RPT breakers in series per recirculation pump. One trip system trips one of the two RPT breakers for each recirculation pump, and the second trip system trips the other RPT breaker for each recirculation pump.

APPLICABLE The TSV-Closure and the TCV Fast Closure, Trip Oil Pressure-Low SAFETY Functions are designed to trip the recirculation pumps in the event of a ANALYSES, turbine trip or generator load rejection to mitigate the neutron flux,.heat LCO, and flux, and pressuretransients, and to increase the margin to the MCPR SL-APPLICABILITY The analytical methods and assumptions-used in evaluating the turbine -

trip and geherator load.rejection, as well as other safety analyses that take credit-for EOC-RPT, are summarized in References 2 and 3.

To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of closure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a scram alone, resulting in an increased margin to the MCPR SL. Alternatively, MCPR limits for an inoperable EOC-RPT, as specified in the COLR, are sufficient to mitigate pressurization transient effects. The EOC-RPT function is automatically disabled when turbine first stage pressure is < 26% RTP.

EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 4)

The OPERABILITY of theoEOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4.1.2. The actual setpoint is calibrated consistent with applicable (continued)

SUSQUEHANNA - UNIT 1 B 3.3-82 Revision 1

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE setpoint methodology assumptions. Channel OPERABILITY also includes SAFETY the associated RPT breakers. Each channel (including the associated ANALYSES, RPT breakers) must also respond within its assumed response time.

LCO, and APPLICABILITY Allowable Values are specified for each EOC-RPT Function specified in (continued) the LCO. Nominal trip setpoints are specified in the setpoint calculations.

A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Each Allowable Value specified is more conservative than the analytical limit assumed in the transient and accident analysis in order to account for instrument uncertainties appropriate to the Function. Trip setpoints are those predetermined values of output at which an action should take place: The setpoints are compared to the actual process parameter (e.g., TSV position), and when the measured output value of -

the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for-the remaining instrument errors (e.g., drift).

The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

Alternatively, since this instrumentation protects against a MCPR SL violation, with the instrumentation inoperable, modifications to the MCPR limits (LCO 3.2.2) may be applied to allow this LCO to be met. The MCPR penalty for the EOC-RPT inoperable condition is specified in the COLR.

The specific Applicable Safety Analysis, LCO, and Applicability discussions are listed below on a Function by Function basis.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-83 Revision 0

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE Turbine Stop Valve-Closure SAFETY ANALYSES, Closure of the TSVs and a main turbine trip result in the loss of a heat LCO, and sink that produces reactor pressure, neutron flux, and heat flux transients APPLICABILITY that must be limited. Therefore, an RPT is initiated on TSV-Closure in (continued) anticipation of the transients that would result from closure of these valves. EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL is not exceeded during the worst case transient. Closure of the TSVs is determined by measuring the position of each valve. There are two separate position switches associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV-Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER Ž_26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure.-

- Because an increase in the main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from first stage pressure), the main turbine bypass valves must hot cause the trip Functions to be bypassed when thermal power is > 26% RTP. Four channels of TSV-Closure; with two channels in each trip system, are available and required-to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TSV-Closure Allowable Value is selected to detect imminent TSV closure.

This protection is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is Ž 26% RTP. Below 26% RTP, the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor (APRM) Fixed Neutron Flux-High Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary safety margins.

turbine Control Valve Fast Closure, Trip Oil Pressure-Low Fast closure of the TCVs during a generator load rejection results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TCV Fast Closure, Trip Oil Pressure-Low in anticipation of the transients that would result from the closure of these valves. The EOC-RPT decreases reactor power and aids the (continued)

SUSQUEHANNA - UNIT 1 B 3.3-84 Revision 1

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure-Low (continued)

SAFETY ANALYSES, reactor scram in ensuring that the MCPR SL is not exceeded during the LCO, and worst case transient.

APPLICABILITY Fast closure of the TCVs is determined by measuring the electrohydraulic control fluid pressure at each control valve. There is .one pressure instrument associated with each control valve, and the signal from each instrument is assigned to a separate trip channel. The logic for the TCV Fast Closure, Trip Oil Pressure-Low Function is such that two or more TCVs must be closed (pressure instrument trips) to produce an EOC-RPT.

This Function must be enabled at THERMAL POWER Ž 26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure. Because an increase in the main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived -

-from first stage pressure) the main turbine bypass valves must not cause the trip Functions to be bypassed when thermal power is >_26% RTP.

Four channels of TCV Fast Closure, Trip Oil Pressure-Low, with two channels in each-trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

This protection is required consistent with the safety analysis whenever THERMAL POWER is -> 26% RTP. Below 26% RTP, the Reactor Vessel.

Steam Dome Pressure-High and the APRM Fixed Neutron Flux-High Functions of the RPS are adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for (continued)

SUSQUEHANNA - UNIT 1 B 3.3-85 Revision 1

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS inoperable EOC-RPT instrumentation channels provide appropriate (continued) compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable EOC-RPT instrumentation channel.

A.1, A.2, and A.3 With one or more channels inoperable, but with EOC-RPT trip capability maintained (refer to Required Actions B.1 and B.2 Bases), the EOC-RPT System is capable of performing the intended function. However, the reliability and redundancy of the EOC-RPT instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function.

Therefore, only a limited time is allowed to restore compliance with the LCO. Because of the diversity of sensors available to provide trip signals,

-the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low. probability of an event requiring the initiation of-an EOC-RPT, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is provided to restore the inoperable -

channels (Required Action A. 1). Alternately, the inoperable channels may be placed in trip (Required Action A.2) or Required Action A.3 MCPR Limits for inoperable EOC-RPT can be applied since these would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. As noted, placing the channel in trip with no further restrictions is not allowed if the inoperable channel is the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the breaker may be inoperable such that it will not open). If it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an RPT, or if the inoperable channel is the result of an inoperable breaker), Condition C must be entered and its Required Actions taken.

B.1 and B.2 Required Actions B. 1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining EOC-RPT trip capability. A Function is considered to be maintaining EOC-RPT trip (continued)

SUSQUEHANNA - UNIT 1 B 3.3-86 Revision 0

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS B.1 and B.2 (continued) capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal from the given Function on a valid signal and both recirculation pumps can be tripped. This requires two channels of the Function in the same trip system, to each be OPERABLE or in trip, and the associated RPT breakers to be OPERABLE or in trip. Alternately, Required Action B.2 requires the MCPR limit for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to MCPR assumed in the safety analysis.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient time for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It is also consistent with the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time provided in LCO 3.2.2

-for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 and C.2 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 26% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Alternately, the associated recirculation pump may be removed from service, since this performs the intended function of the instrumentation.

The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on operating experience, to reduce THERMAL POWER to < 26% RTP from .1I full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that when a channel REQUIREMENTS is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains EOC-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 4) assumption of the average (continued)

SUSQUEHANNA - UNIT 1 B 3.3-87 Revision 1

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE time required to perform channel Surveillance. That analysis REQUIREMENTS demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly (continued) reduce the probability that the recirculation pumps will trip when necessary.

SR 3.3.4.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

This SR is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference 7) Performance of such a test could result in a plant

-transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which ihputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.4.1.3. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

The Frequency of 92 'days is based on reliability analysis of Reference 5.

SR 3.3.4.1.2 CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-88 Revision 0

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SURVEQIR NENS SR 3.3.4.1.2 (continued)

REQUIREMENTS The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.4.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is included as a part of this test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would also be inoperable.

The 24 month Frequency is based on the need to perform portions of this.

Surveillance under the conditions that apply during a plant outage and the potential for an unplan~ned -transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.4.1.4 This SR ensures that an EOC-RPT initiated from the TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is Ž 26% RTP. This is performed by a Functional check that ensures the EOC-RPT Function is not bypassed. Because increasing the main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from first stage pressure) the main turbine bypass valves must not cause the trip Functions to be bypassed when thermal power is Ž_26% RTP. If any functions are bypassed at >_26% RTP, either due to open main turbine bypass valves or other reasons, the affected TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable.

Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met with the channel considered OPERABLE.

(continued)

SUSQUEHANNA - UNIT 1 B 3.3-89 Revision 1

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.4 (continued)

REQUIREMENTS The Frequency of 24 months has shown that channel bypass failures between successive tests are rare.

SR 3.3.4.1.5 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The EOC-RPT SYSTEM RESPONSE TIME acceptance criteria are included in Reference 5.

A Note to the Surveillance states that breaker interruption time may be assumed from the most recent performance of SR 3.3.4.1.6. This is allowed since the time to open the contacts after energization of the trip coil and the arc suppression time are short and do not appreciably' change, due to the design of the breaker opening device and the fact that.

the breaker is not routinely cycled...

EOC-RPT SYSTEM RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. For this SR, STAGGERED TEST BASIS means that each 24 month test shall include at least the logic of one type of channel input, turbine control valve fast closure or turbine stop valve closure such that both types of channel inputs are tested at least one per 48 months. Response times cannot be determined at power because operation of final actuated devices is required. Therefore, the 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components that cause serious response time degradation, but not channel failure, are infrequent occurrences.

SR 3.3.4.1.6 This SR ensures that the RPT breaker interruption time (arc suppression time plus time to open the contacts) is provided to the EOC-RPT SYSTEM RESPONSE TIME test. The 60 month Frequency of the testing is based on the difficulty of performing the test and the reliability of the circuit breakers.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-90 Revision 1

PPL Rev. 1 EOC-RPT Instrumentation B 3.3.4.1 BASES REFERENCES 1. FSAR, Figure 7.2-1-4 (EOC-RPT logic diagram).

2. FSAR, Sections 15.2 and 15.3.

3. FSAR, Sections 7.1 and 7.6.

4. GENE-770-06-1, "Bases For Changes To Surveillance Test Intervals And Allowed Out-Of-Service Times For Selected Instrumentation Technical Specifications," February 1991.

5. FSAR Table 7.6-10.

6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 32193).

7. NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.

SUSQUEHANNA - UNIT 1 B 3.3-91 Revision 0

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3 INSTRUMENTATION B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs). The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs). Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.

The isolation instrumentation includes the sensors, relays, and instruments that are necessary to cause initiation of primary containment and reactor coolant pressure boundary (RCPB) isolation. When the

.setpoint is reached, the sensor actuates, which then outputs an isolation signal to the isolation logic. Functional diversity is provided by monitoring-a wide range of independent parameters. -The input parameters to the isolation logics are (a) -reactor vessel water level, (b) area ambient and emergency cooler termperatures, (c) main steam line (MSL) flow measurement, (d) Standby Liquid Control (SLC) System initiation, (e) condenser vacuum, (f) main steam line pressure, (g) high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) steam line A pressure, (h) SGTS Exhaust radiation, (i) HPCI and RCIC steam line pressure, (j) HPCI and RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) differential flow and high flow, (I) reactor steam dome pressure, and (m) drywell pressure. Redundant sensor input signals from each parameter are provided for initiation of isolation. The only exception is SLC System initiation. In addition, manual isolation of the logics is provided.

Primary containment isolation instrumentation has inputs to the trip logic of the isolation functions listed below.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-147 Revision 0

PPL Rev. 4 Primary Containment Isolation Instrumentation pB 3.3.6.1 BASES BACKGROUND 1. Main Steam Line Isolation (continued)

Most MSL Isolation Functions receive inputs from four channels. The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of all main steam isolation valves (MSIVs).

The outputs from the same channels are arranged into two two-out-of-two logic trip systems to isolate all MSL drain valves. The MSL drain line has two isolation valves with one two-out-of-two logic system associated with each valve.

The exceptions to this arrangement are the Main Steam Line Flow-High Function. The Main Steam Line Flow-High Function uses 16 flow channels, four for each steam line. One channel from each steam line inputs to one of the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an MSL isolation. Each trip string has four inputs (one per MSL), any one of which will trip the trip string. The trip strings are arranged in a one-out-of-two taken twice logic. This is effectively a one-out-of-eight taken twice logic arrangement to initiate isolation of the MSIVs. Similarly, the 16 flow channels are connected into two two-out-of-two logic trip systems (effectively, two one-out-of-four twice logic), with each trip system isolating one of the two MSL drain valves.

2. Primary Containment Isolation Most Primary Containment Isolation Functions receive inputs from four channels. The outputs from these channels are arranged into two two-out-of-two logic trip systems. One trip system initiates isolation of all inboard primary containment isolation valves, while the other trip system initiates isolation of all outboard primary containment isolation valves.

Each logic closes one of the two valves on each penetration, so that operation of either logic isolates the penetration.

The exceptions to this arrangement are as follows. Hydrogen and Oxygen Analyzers which isolate Division I Analyzer on a Division I isolation signal, and Division II Analyzer on a Division II isolation signal.

This is to ensure monitoring capability is not lost. Chilled Water to recirculation pumps and Liquid Radwaste Collection System isolation valves (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-148 Revision 0

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 2. Primary Containment Isolation (continued) where both inboard and outboard valves will isolate on either division providing the isolation signal. Traversing incore probe ball valves and the instrument gas to the drywell to suppression chamber vacuum breakers only have one isolation valve and receives a signal from only one division.

3., 4. High Pressure Coolant Iniection System Isolation and Reactor Core Isolation Cooling System Isolation Most Functions that isolate HPCI and RCIC receive input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems in each isolation group is connected to one of the two valves on each associated penetration.

The exceptions are the HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High and Steam Supply Line Pressure-Low Functions.

These Functions receive inputs from four turbine exhaust diaphragm pressure and four steam supply pressure channels for each system.

The outputs from the turbinre exhaust diaphragm pressure and steam supply pressure channels are each connected to two two-out-of-two trip systems. each trip system isolates one valve per associated penetration.

5. Reactor Water Cleanup System Isolation The Reactor Vessel Water Level-Low Low, Level 2 Isolation Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected into two two-out-of-two trip systems. The Differential Flow-High, Flow-High, and SLC System Initiation Functions receive input from two channels, with each channel in one trip system using a one-out-of-one logic. The temperature isolations are divided into three Functions. These Functions are Pump Area, Penetration Area, and Heat Exchanger Area.

Each area is monitored by two temperature monitors, one for each trip system. These are configured so that any one input will trip the associated trip system. Each of the two trip systems is connected to one of the two valves on each RWCU penetration.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-149 Revision 0

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 6. Shutdown Coolinq System Isolation (continued)

The Reactor Vessel Water Level-Low, Level 3 Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected to two two-out-of-two trip systems. The Reactor Vessel Pressure-High Function receives input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems is connected to one of the two valves on each shutdown cooling penetration.

7. Traversing Incore Probe System Isolation The Reactor Vessel Water Level-Low, Level 3 Isolation Function receives input from two reactor vessel water level channels. The Drywell Pressure-High Isolation Function receives input from two drywell pressure channels. The outputs from the reactor vessel water level channels and drywell pressure channels are connected into one two-out-

-of-two logic trip system.

When either Isolation Function actuates, the TIP- drive mechanisms will withdraw the TIPs, if inserted, and close the inboard TIP System isolation ball valves when the proximity probe senses the TIPs are withdrawn into the shield. The-TIP System isolation ball valves are only open when the TIP System is in use. The outboard TIP System isolation valves are manual shear valves.

APPLICABLE The isolation signals generated by the primary containment isolation SAFETY instrumentation are implicitly assumed in the safety analyses of ANALYSES, References I and 2 to initiate closure of valves to limit offsite doses.

LCO, and Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"

APPLICABILITY Applicable Safety Analyses Bases for more detail of the safety analyses.

Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 8) Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-150 Revision I

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE The OPERABILITY of the primary containment instrumentation is SAFETY dependent on the OPERABILITY of the individual instrumentation ANALYSES, channel Functions specified in Table 3.3.6.1-1. Each Function must LCO, and have a required number of OPERABLE channels, with their setpoints APPLICABILITY within the specified Allowable Values, where appropriate. A channel is (continued) inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time, where appropriate.

Allowable Values are specified for each Primary Containment Isolation Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

-Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value. of the-process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the processparameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

In general, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCO 3.6.1.1, "Primary Containment." Functions that have different Applicabilities are discussed below in the individual Functions discussion.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-151 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE The penetrations which are isolated by the below listed functions can be SAFETY determined by referring to the PCIV Table found in the Bases of LCO ANALYSES, 3.6.1.3, "Primary Containment Isolation Valves."

LCO, and APPLICABILITY Main Steam Line Isolation (continued) 1.a. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of the MSIVs and other interfaces with the reactor vessel occurs to prevent offsite dose limits from being exceeded. The Reactor Vessel Water Level-Low Low Low, Level 1 Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The Reactor Vessel Water Level-Low Low Low, Level 1 Function associated with

-isolation is assumed in the analysis of the recirculation line break (Ref. 1). The isolation of the MSLs on Level 1 supports actions to ensure that offsite dose limits -are not exceeded for a DBA.

Reactor vessel water level signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite and control room doses from exceeding regulatory limits.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-152 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.b. Main'Steam Line Pressure-Low SAFETY ANALYSES, Low MSL pressure indicates that there may be a problem with the LCO, and turbine pressure regulation, which could result in a low reactor vessel APPLICABILITY water level condition and the RPV cooling down more than 100°F/hr if (continued) the pressure loss is allowed to continue. The Main Steam Line Pressure-Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2). For this event, the closure of the MSIVs ensures that the RPV temperature change limit (100°F/hr) is not reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded. (This Function closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus reducing reactor power to < 23% RTP.)

The MSL low pressure signals are initiated from four instruments that are connected to the MSL header. The instruments are arranged such that, even though physically separated from each other, each instrument

-is able to detect low MSL pressure. Four channels of Main Steam Line Pressure-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure-can preclude the isolation function.

The Main Steam Line Pressure--Low trip will only occur after a 500 milli-second time delay to prevent any spurious isolations.

The Allowable Value was selected to be high enough to prevent excessive RPV depressurization. The Main Steam Line Pressure-Low Function is only required to be OPERABLE in MODE 1 since this is when the assumed transient can occur (Ref. 2).

1.c. Main Steam Line Flow-Hiqh Main Steam Line Flow-High is provided to detect a break of the MSL and to initiate closure of the MSIVs. If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Main Steam Line Flow-High Function is (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-153 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.c. Main Steam Line Flow-High (continued)

SAFETY ANALYSES, directly assumed in the analysis of the main steam line break (MSLB)

LCO, and (Ref. 1). The isolation action, along with the scram function of the APPLICABILITY Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and offsite and control room doses do not exceed regulatory limits.

The MSL flow signals are initiated from 16 instruments that are connected to the four MSLs. The instruments are arranged such that, even though physically separated from each other, all four connected to one MSL would be able to detect the high flow. Four channels of Main Steam Line Flow-High Function for each unisolated MSL (two channels per trip system) are available and are required to be OPERABLE so that no single instrument failure will preclude detecting a break in any individual MSL:

-1.d. Condenser Vacuum-Low The Allowable Value is chosen to ensure that offsite dose limits are not exceeded due to the break.

The Condenser Vacuum-Low Function is provided to prevent overpressurization of the main condenser in the event of a loss of the main condenser vacuum. Since the integrity of the condenser is an assumption in offsite dose calculations, the Condenser Vacuum-Low Function is assumed to be OPERABLE and capable of initiating closure of the MSIVs. The closure of the MSIVs is initiated to prevent the addition of steam that would lead to additional condenser pressurization and possible rupture of the diaphragm installed to protect the turbine exhaust hood, thereby preventing a potential radiation leakage path following an accident.

Condenser vacuum pressure signals are derived from four pressure instruments that sense the pressure in the condenser. Four channels of Condenser Vacuum-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-154 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.d. Condenser Vacuum-Low (continued)

SAFETY ANALYSES, The Allowable Value is chosen to prevent damage to the condenser due LCO, and to pressurization, thereby ensuring its integrity for offsite dose analysis.

APPLICABILITY As noted (footnote (a) to Table 3.3.6.1-1), the channels are not required to be OPERABLE in MODES 2 and 3 when all main turbine stop valves (TSVs) are closed, since the potential for condenser overpressurization° is minimized. Switches are provided to manually bypass the channels when all TSVs are closed.

i.e. Reactor Buildina Main Steam Tunnel TemDerature-Hiah Reactor Building Main Steam Tunnel temperature is provided to detect a leak in the RCPB and provides diversity to the high flow instrumentation.

The isolation occurs when a very small leak has occurred. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. However, credit for these instruments is not taken in any

-transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks, such as MSLBs.

Area temperature signals are-initiated from thermocouples located in the area being monitored.- Four channels of Reactor Building Main Steam Tunnel Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the-isolation function.

The reactor building main steam tunnel temperature trip will only occur after a one second time delay.

The temperature monitoring Allowable Value is chosen to detect a leak equivalent to approximately 25 gpm of water.

1.f. Manual Initiation The Manual Initiation push button channels introduce signals into the MSL isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for the overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-155 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.f. Manual Initiation (continued)

SAFETY ANALYSES, There are four push buttons for the logic, two manual initiation push LCO, and button per trip system. There is no Allowable Value for this Function APPLICABILITY since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the MSL isolation automatic Functions are required to be OPERABLE.

Primary Containment Isolation 2.a. Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be

-threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.

The isolation of the primary containment on Level 3 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded.- The Reactor Vessel Water Level-Low, Level 3 Function associated-with isolation is imlplijcitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.

Reactor Vessel Water Level-Low, Level 3 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-156 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.b. Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, Low RPV water level indicates that the capability to cool the fuel may be LCO, and threatened. The valves whose penetrations communicate with the APPLICABILITY primary containment are isolated to limit the release of fission products.

(continued) The isolation of the primary containment on Level 2 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Reactor Vessel Water Level-Low Low, Level 2 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.

Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Low-, Level 2 Allowable Value was chosen to be the same as the- ECCS Level 2 Allowable Value (LCO 3.3.51), since this may be indicative of a LOCA.

2.c. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products. The isolation of the primary containment on Level 1 supports actions to ensure the offsite and control room dose regulatory limits are not exceeded. The Reactor Vessel Water Level - Low Low Low, Level 1 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-157 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.c. Reactor Vessel Water Level-Low Low Low, Level 1 (continued)

SAFETY ANALYSES, Reactor vessel water level signals are initiated from four level LCO, and instruments that sense the difference between the pressure due to a APPLICABILITY constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel., Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the associated penetrations isolate on a potential loss of coolant accident (LOCA) to prevent offsite and control room doses from exceeding regulatory limits.

2.d. Drvwell Pressure-Hiqh High drywell pressure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment -

isolation valves on high drywell pressure supports actions to ensure that offsite -

and control room dose regulatory limits are not exceeded. The Drywell Pressure-High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.

High drywell pressure signals are initiated from pressure instruments that sense the pressure in the drywell. Four channels of Drywell Pressure-High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.

(continued)

SUSQUEHANNA - UNIT I TS / B 3.3-158 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.e. SGTS Exhaust Radiation-Hiah SAFETY ANALYSES, High SGTS Exhaust radiation indicates possible gross failure of the fuel LCO, and cladding. Therefore, when SGTS Exhaust Radiation High is detected, APPLICABILITY an isolation is initiated to limit the release of fission products. However, (continued) this Function is not assumed in any accident or transient analysis in the FSAR because other leakage paths (e.g., MSIVs) are more limiting.

The SGTS Exhaust radiation signals are initiated from radiation detectors that are located in the SGTS Exhaust. Two channels of SGTS Exhaust Radiation-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value is low enough to promptly detect gross failures in the fuel cladding.

2.f. Manual Initiation The Manual Initiation push button channels introduce signals into the primary containment isolation-logic that are redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no- specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.

There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the Primary Containment Isolation automatic Functions are required to be OPERABLE.

(continued)

SUSQUEHANNA - UNIT 1 TS /B 3.3-159 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE High Pressure Coolant Iniection and Reactor Core Isolation SAFETY Cooling Systems Isolation

ANALYSES, LCO, and 3.a., 4.a. HPCI and RCIC Steam Line A Pressure-High APPLICABILITY (continued) Steam Line A Pressure High Functions are provided to detect a break of the RCIC or HPCI steam lines and initiate closure of the steam line isolation valves of the appropriate system. If the steam is allowed to continue flowing out of the break, the reactor will depressurize and the core can uncover. Therefore, the isolations are initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit for these Functions is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC or HPCI steam line breaks from becoming bounding.

The HPCI and RCIC Steam Line A Pressure - High signals are initiated from instruments (two for HPCi and two for RCIC) that are connected to -

the system steam lines. Two-channels of both HPCI and RCIC Steam Line A pressure-High- Functions are available and are required to be OPERABLE to ensure.that no single instrument failure can preclude the isolation function.

The steam line A Pressure - High will only occur after a 3 second time delay to prevent any spurious isolations.

The Allowable Values are chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event, and high enough to be above the maximum transient steam flow during system startup.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-160 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.b.. 4.b. HPCI and RCIC Steam SuDIv Line A Pressure-Low SAFETY ANALYSES, Low MSL pressure indicates that the pressure of the steam in the HPCI LCO, and or RCIC turbine may be too low to continue operation of the associated APPLICABILITY system's turbine. These isolations are for equipment protection and are (continued) not assumed in any transient or accident analysis in the FSAR.

However, they also provide a diverse signal to indicate a possible system break. These instruments are included in Technical Specifications (TS) because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).

The HPCI and RCIC Steam Supply Line Pressure-Low signals are initiated from instruments (four for HPCI and four for RCIC) that are connected to the system steam line. Four channels of both HPCI and RCIC Steam Supply Line Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Vaiues are selected to be high enough to prevent damage to the system's turbine.

3.c., 4.c. HPCI and RCIC Turbine Exhaust Diaphragqm Pressure-High High turbine exhaust diaphragm pressure indicates that a release of steam into the associated compartment is possible. That is, one of two exhaust diaphragms has ruptured. These isolations are to prevent steam from entering the associated compartment and are not assumed in any transient or accident analysis in the FSAR. These instruments are included in the TS because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).

The HPCI and RCIC Turbine Exhaust Diaphram Pressure-High signals and initiated from instruments (four for HPCI and four for RCIC) that are connected to the area between the rupture diaphragms on each system's turbine exhaust line. Four channels of both HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-161 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.c., 4.c. HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High SAFETY (continued)

ANALYSES, LCO, and The Allowable Values is low enough to identify a high turbine exhaust APPLICABILITY pressure condition resulting from a diaphragm rupture, or a leak in the diaphragm adjacent to the exhaust line and high enough to prevent inadvertent system isolation.

3.d.. 4.d. Drvwell Pressure-High High drywell pressure can indicate a break in the RCPB. The HPCI and RCIC isolation of the turbine exhaust vacuum breaker line is provided to prevent communication with the wetwell when high drywell pressure exists. A potential leakage path exists via the turbine exhaust. The isolation is delayed until the system becomes unavailable for injection (i.e., low steam supply line pressure). The isolation of the HPCI and RCIC turbine exhaust vacuum breaker line by Drywell Pressure-High is

-indirectly assumed in the FSAR accident analysis because the turbine exhaust vacuum breaker line leakage path is not assumed to contribute to offsite doses and is provided for long term containment isolation.

High drywell pressure signals'are initiated from pressure instruments that sense the pressure in the drywell. Four channels of both HPCI and RCIC Drywell Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this is indicative of a LOCA inside primary containment.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-162 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.e., 3.f., 3.q., 4.e., 4.f., 4.q., HPCI and RCIC Area and Emerqency SAFETY Cooler Temperature-Hiqh

ANALYSES, LCO, and HPCI and RCIC Area and Emergency Cooler temperatures are provided APPLICABILITY to detect a leak from the associated system steam piping. The isolation (continued) occurs when a small leak has occurred and is diverse to the high flow instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.

Area and Emergency Cooler Temperature-High signals are initiated from thermocouples that are appropriately located to protect the system that is being monitored. Two Instruments monitor each area. Two channels for each HPCI and RCIC Area and Emergency Cooler Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The HPCI and RCIC Pipe Routing area temperature trips will only occur after a 15 minute time delay to prevent any spurious temperature isolations due to short.temperature increases and allows operators sufficient time to'determine which system is leaking. The other ambient temperature trips will only 0cc&r after a one second time delay to prevent arny spurious temperature isolations.

The Allowable Values are set low enough to detect a leak equivalent to 25 gpm, and high enough to avoid trips at expected operating temperature.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-163 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.h.. 4.h. Manual Initiation SAFETY ANALYSES, The Manual Initiation push button channels introduce signals into the LCO, and HPCI and RCIC systems' isolation logics that are redundant to the APPLICABILITY automatic protective instrumentation and provide manual isolation (continued) capability. There is no specific FSAR safety analysis that takes credit for these Functions. They are retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis There is one manual initiation push button for each of the HPCI and RCIC systems. One isolation pushbutton per system will introduce an isolation to one of the two trip systems. There is no Allowable Value for these Functions, since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of both HPCI and RCIC Manual Initiation Functions are available and are required to be OPERABLE in MODES 1, 2, and 3 since these are the MODES in which the HPCI and RCIC systems' Isolation automatic Functions are required-to be OPERABLE.

Reactor Water Cleanup System Isolation 5.a. RWCýU Differential Flow-HiQh The high differential flow signal is provided to detect a break in the RWCU System. This will detect leaks in the RWCU System when area temperature would not provide detection (i.e., a cold leg break). Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high differential flow is sensed to prevent exceeding offsite doses.

A 45 second time delay is provided to prevent spurious trips during most RWCU operational transients. This Function is not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-164 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.a. RWCU Differential Flow-High (continued)

SAFETY ANALYSES, The high differential flow signals are initiated from instruments that are LCO, and connected to the inlet (from the recirculation suction) and outlets (to APPLICABILITY condenser and feedwater) of the RWCU System. Two channels of Differential Flow-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Differential Flow-High Allowable Value ensures that a break of the RWCU piping is detected.

5.b, 5.c, 5.d RWCU Area Temperatures-High RWCU area temperatures are provided to detect a leak from the RWCU System. The isolation occurs even when small leaks have occurred and is diverse to the high differential flow instrumentation for the hot' portions

-of the RWCU System. If the small leak continues without isolation.,

offsite dose limits may be reached. Credit for these instruments is not taken in any transient or accident analysis-in theFSAR, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.

Area temperature signals are initiated from temperature elements that are located in the area that is being monitored. Six thermocouples provide input to the Area Temperature-High Function (two per area).

Six channels are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The area temperature trip will only occur after a one second time to prevent any spurious temperature isolations.

The Area Temperature-High Allowable Values are set low enough to detect a leak equivalent to 25 gpm.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-165 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.e. SLC System Initiation SAFETY ANALYSES, The isolation of the RWCU System is required when the SLC System LCO, and has been initiated to prevent dilution and removal of the boron solution APPLICABILITY by the RWCU System (Ref. 4). SLC System initiation signals are (continued) initiated from the two SLC pump start signals.

There is no Allowable Value associated with this Function since the channels are mechanically actuated based solely on the position of the SLC System initiation switch.

Two channels (one from each pump) of the SLC System Initiation Function are available and are required to be OPERABLE only in MODES 1, 2, and 3 which is consistent with the Applicability for the SLC System (LCO 3.1.7).

As noted (footnote (b) to Table 3.3.6.1-1), this Function is only required to close the outboard RWCU isolation valve trip systems.

5.f. Reactor Vessel Water Level-Low Lowv, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened.. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. The isolation of the RWCU System on Level 2 supports actions to ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

The Reactor Vessel Water Level-Low Low, Level 2 Function associated with RWCU isolation is not directly assumed in the FSAR safety analyses because the RWCU System line break is bounded by breaks of larger systems (recirculation and MSL breaks are more limiting).

Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of Water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of (continued)

SUSQUEHANNA - UNIT 1' TS / B 3.3-166 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.f. Reactor Vessel Water Level-Low Low, Level 2 (continued)

SAFETY ANALYSES, Reactor Vessel Water Level-Low Low, Level 2 Function are available LCO, and and are required to be OPERABLE to ensure that no single instrument APPLICABILITY failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.

5.q. RWCU Flow - High RWCU Flow-High Function is provided to detect a break of the RWCU System. Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation is initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Specific credit for this Functionr is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such -

as recirculation and MSL breaks.

The RWCU Flow-High signals are initiated from two instruments. Two.

channels of RWCU Flow-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The RWCU flow trip will only occur after a 5 second time delay to prevent spurious trips.

The Allowable Value is chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event.

5.h. Manual Initiation The Manual Initiation push button channels introduce signals into the RWCU System isolation logic that are redundant to (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-167 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.h. Manual Initiation (continued)

SAFETY ANALYSES, the automatic protective instrumentation and provide manual isolation LCO, and capability. There is no specific FSAR safety analysis that takes credit APPLICABILITY for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the.plant licensing basis.

There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3 since these are the MODES in which the RWCU System Isolation automatic Functions are required to be OPERABLE.

Shutdown Cooling System Isolation 6.a. Reactor Steam Dome Pressure-High The Reactor Steam Dome Pressure--High Function is provided to isolate the shutdown cooling portion of the Residual Heat Removal (RHR) System. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario, and credit for the interlock is not assumed in the accident or transient analysis in the FSAR.

The Reactor Steam Dome Pressure-High signals are initiated from two instruments. Two channels of Reactor Steam Dome Pressure-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Function is only required to be OPERABLE in MODES 1, 2, and 3, since these are the only MODES in which the reactor can be pressurized with the exception of Special Operations LCO 3.10.1; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.

(continued)

SUSQUEHANNA - UNIT I TS / B 3.3-168 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. Reactor Vessel Water Level-Low. Level 3 SAFETY ANALYSES, Low RPV water level indicates that the capability to cool the fuel may be LCO, and threatened. Should RPV water level decrease too far, fuel damage APPLICABILITY could result. Therefore, isolation of some reactor vessel interfaces occurs to (continued) begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low, Level 3 Function associated with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by breaks of the recirculation and MSL.

The RHR Shutdown Cooling System isolation on Level 3 supports actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.

Reactor Vessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Level-Low, Level 3 Fu~nction are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. As noted (footnote (c) to Table 3.3.6.1-1), only two channels of the Reactor Vessel Water Level-Low, Level 3 Function are required to be OPERABLE in MODES 4 and 5 (and must input into the same trip system), provided the RHR Shutdown Cooling System integrity is maintained. System integrity is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low, Level 3 Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water, Level-Low, Level 3 Function is only required to be OPERABLE in MODES 3, 4, and 5 to prevent this potential flow path from lowering the reactor vessel level to the top of the fuel.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-169 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. Reactor Vessel Water Level-Low, Level 3 (continued)

SAFETY ANALYSES, In MODES 1 and 2, another isolation (i.e., Reactor Steam Dome LCO, and Pressure-High) and administrative controls ensure that this flow path APPLICABILITY remains isolated to prevent unexpected loss of inventory via this flow path.

6.c Manual Initiation The Manual Initiation push button channels introduce signals to RHR Shutdown Cooling System isolation logic that is redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.

There are two push buttons for the logic, one manual initiation push

-button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of the Manual Initiation Function are available and are required to-be OPERABLE in MODES 3, 4, and 5, since these are the MODES in- which the RHR Shutdown Cooling System Isolation automatic Function are required to be OPERABLE.

Traversinq Incore Probe System Isolation 7.a Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.

The isolation of the primary containment on Level 3 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Reactor Vessel Water Level - Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-170 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 7.a Reactor Vessel Water Level - Low, Level 3 (continued)

SAFETY ANALYSES, Reactor Vessel Water Level - Low, Level 3 signals are initiated from LCO, and level transmitters that sense the difference between the pressure due to APPLICABILITY a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Two channels of Reactor Vessel Water Level - Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent isolation actuation. The isolation function is ensured by the manual shear valve in each penetration.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.

7.b. Drywell Pressure - High High drywell pressure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment isolation valves-on high. drywell pressure supports actions to ensure that offsite and control room dose regulatory limits are not exceeded. The Drywell Pressure - High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.

High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Two channels of Drywell Pressure - High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation. The isolation function is ensured by the manual shear valve in each penetration.

The Allowable Value was selected to be the same as the ECCS Drywell Pressure - High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-171 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS The ACTIONS are modified by two Notes. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls.

These controls consist of stationing a dedicated operator at the controls of the val, e, who is in continuous communication with the control room.

In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable primary containment.

isolation instrumentation channel.

A.11 Because of the diversity of sernsors available to provide isolation signals and the redundancy ofthe isolation design, an allowable out of service time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for Functions 2.a, 2.d, 6.b, 7.a, and 7.b and 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for Functions other than Functions 2.a, 2.d, 6.b, 7.a, and 7.b has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue with no further restrictions. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its Required Action taken.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-172 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS B.1 and B.2 (continued)

Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path(s). The MSL Isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function. For Functions 1.a,1.b, 1.d, and 1.e, this would require both trip systems to have one channel OPERABLE or in trip. For Function 1.c, this would require both trip systems to have one channel,

-associated with each MSL, OPERABLE or in trip. Therefore, this would require both trip sstems to have one channel per location OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, -3.b, 3.c, 3.d, 4.b, 4.c, 4.d, 5.f, and 6.b, this would require one trip system to have two channels, each OPERABLE or in trip. -For Functions 2.e, 3.a, 3.e, 3.f, 3.g, 4.a, 4.e, 4.f, 4.g, 5.a, 5.b., 5.c, 5.d, 5.e, 5.g,-and 6.a, this would require one trip system to have one channel OPERABLE or in trip. The Condition does not include the Manual Initiation Functions (Functions 1.f, 2.f, 3.h, 4.h, 5.h, and 6.c), since they are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action A.1) is allowed.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

(continued)

SUSQUEHANNA - UNIT 1 TS I B 3.3-173 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS C.1 (continued)

Required Action C. 1 directs entry into the appropriate Condition referenced in Table 3.3.6.1-1. The applicable Condition specified in Table 3.3.6.1-1 is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action of Condition A or B and the associated Completion Time has expired, Condition C will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

D.1, D.2.1, and D.2.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.

This is done by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Actions D.2.1 and D.2.2).

Alternately, the associated MSLs may be isolated (Required Action D.1),

and, if allowed (i.e., plant safety analysis allows operation with an MSL isolated), operation with that MSL -isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel. The Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

E.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.

This is done by placing the plant in at least MODE 2 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 2 from full power conditions in an orderly manner and without challenging plant systems.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-174 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS F.1 (continued)

If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels.

If it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram), Condition H must be entered and its Required Actions taken.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing sufficient time for plant operations personnel to isolate the affected penetration flow path(s).

G.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion. Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is acceptable due to the fact that these Functions are either not assumed in any accident or transient analysis in the FSAR (Manual Initiation) or, in the case of the TIP System isolation, the TIP System penetration is a small bore (0.280 inch), its isolation in a design basis event (with loss of offsite power) would be via the manually operated shear valves, and the ability to manually isolate by either the normal isolation valve or the shear valve is unaffected by the inoperable instrumentation. It should be noted, however, that the TIP System is powered from an auxiliary instrumentation bus which has an uninterruptible power supply and hence, the TIP drive mechanisms and ball valve control will still function in the event of a loss of offsite power.. Alternately, if it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram),

Condition H must be entered and its Required Actions taken.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-175 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS H.1 and H.2 (continued)

If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, or any Required Action of Condition F or G is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in 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.

1.1 and 1.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated SLC subsystem(s) is declared inoperable or the. RWCU System is isolated. Since this Function is required to ensure-that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystems inoperable or isolating the RWCU System.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.

J.1 and J.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated).

Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling System is isolated.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-176 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Primary REQUIREMENTS Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 5 and 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.

SR 3.3.6.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a compariso.n of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately-the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with the channels required by the LCO:

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-177 Revision 1

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

The 92 day Frequency of SR 3.3.6.1.2 is based on the reliability analysis described in References 5 and 6.

This SR is modified by two Notes. Note 1 provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relays which input into the combinational logic. (Reference 11) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay

-which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.1.5. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

Note 2 provides a second specific exception to the definition of CHANNEL FUNCTIONAL TEST. For Functions 2.e, 3.a, and 4.a, certain channel relays are not included in the performance of the CHANNEL FUNCTIONAL TEST. These exceptions are necessary because the circuit design does not facilitate functional testing of the entire channel through to the coil of the relay which enters the combinational logic. (Reference 11) Specifically, testing of all required relays would require rendering the affected system (i.e., HPCI or RCIC) inoperable, or require lifting of leads and inserting test equipment which could lead to unplanned transients. Therefore, for these circuits, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the actuation of circuit devices up to the point where further testing could result in an unplanned transient. (References 10 and 12)

The required relays not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.1.5. This exception (continued)

SUSQUEHANNA - UNIT 1 T .- 8Rvso TS / B 3.3-178 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS SR 3.3.6.1.2 (continued) is acceptable because operating experience shows that the devices not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

SR 3.3.6.1.3 and SR 3.3.6.1.4 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.3.6.1.3 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.6.1.4 is based on the assumption of an 24 month calibration interval in the determination -

of the magnitude of equipment drift in the -setpoint analysis.

It should be noted that some of the primary containment High Drywell pressure instruments, although only required to be calibrated on a 24 month Frequency, are calibrated quarterly based on other TS requirements.

SR 3.3.6.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function. The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-179 Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 REQUIREMENTS (continued) This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.

Testing is performed only on channels where the guidance given in Reference 9 could not be met, which identified that degradation of response time can usually be detected by other surveillance tests.

As stated in Note 1, the response time of the sensors for Functions 1.b, is excluded from ISOLATION SYSTEM RESPONSE TIME testing.

Because the vendor does not provide a design instrument response time, a penalty value to account for the sensor response time is included in determining total channel response time. The penalty value is based on the historical performance of the sensor. (Reference 13) This allowance is supported by Reference 9 which determined that significant degradation of the sensor channel response time can be detected during performance of other Technical Specification SRs and that the sensor response time is a small part of the overall ISOLATION RESPONSE TIME testing.

Function 1.a and 1 .c channel sensors and logic components are excluded from response time testing in accordance with the provisions of References 14 and 15.

As stated in Note 2, response time testing of isolating relays is not required for Function 5.a. This allowance is supported by Reference 9.

These relays isolate their respective isolation valve after a nominal 45 second time delay in the circuitry. No penalty value is included in the response time calculation of this function. This is due to the historical response time testing results of relays of the same manufacturer and model number being less than 100 milliseconds, which is well within the expected accuracy of the 45 second time delay relay.

ISOLATION SYSTEM RESPONSE TIME acceptance criteria are included in Reference 7. This test may be performed in one measurement, or in overlapping segments, with verification that all components are tested.

ISOLATION SYSTEM RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience that shows that random failures of instrumentation (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-179a Revision 2

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 (continued)

REQUIREMENTS components causing serious response time degradation, but not channel failure, are infrequent occurrences.

REFERENCES 1. FSAR, Section 6.3.

2. FSAR, Chapter 15.

3. NEDO-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.

4. FSAR, Section 4.2.3.4.3.

5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.

6. N EDC-30851 P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.

7. FSAR, Table 7.3-29.

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

9. NEDO-32291-A "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.

10. PPL Letter to NRC, PLA-2618, Response to NRC INSPECTION REPORTS 50-387/85-28 AND 50-388/85-23, dated April 22, 1986.

1.1. NRC Inspection and Enforcement Manual, Part 9900:

Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.

12. Susquehanna Steam Electric Station NRC REGION I COMBINED INSPECTION 50-387/90-20; 50-388/90-20, File R41-2, dated March 5, 1986.

13. NRC Safety Evaluation Report related to Amendment No. 171 for License No. NPF-14 and Amendment No. 144 for License No. NPF-22.

14. NEDO 32291-A, Supplement 1, "System Analyses for the Elimination of Selected Response Time Testing Requirements,"

October 1999.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.3-179b ' Revision 0

PPL Rev. 4 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES REFERENCES 15. NEDO 32291, Supplement 1, Addendum 2, "System Analyses for (continued) the Elimination of Selected Response Time Testing Requirements,"

September 5, 2003.

SUSQUEHANNA - UNIT 1 TS / B 3.3-179c Revision 0

PPL Rev. 1 Jet Pumps B 3.4.2 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.2 Jet Pumps BASES BACKGROUND The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating,"

which discusses the operating characteristics of the system and how these characteristics affect the Design Basis Accident (DBA) analyses.

The jet pumps are part of the Reactor Coolant Recirculation System and are designed to provide forced circulation through the core to remove heat from the fuel. The jet pumps are located in the annular region between the core shroud and the vessel inner wall. Because the jet pump suction elevation is at two-thirds core height, the vessel can be reflooded and coolant level maintained at two-thirds core height even with the complete break of the recirculation loop pipe that is located below the jet pump suction elevation.

Each reactor coolant recirculation loop contains ten jet pumps.

Recirculated coolant passes down the annulus between the reactor vessel wall and the core-shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the drive flow. The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuser section into the area below the core (lower plenum), gaining sufficient head in the process to drive the required flow upward through the core.

APPLICABLE Jet pump OPERABILITY is an explicit assumption in the design basis loss SAFETY of coolant accident (LOCA) analysis evaluated in Reference 1.

ANALYSES (continued)

SUSQUEHANNA - UNIT 1 B 3.4-10 Revision 0

PPL Rev. 1 Jet Pumps B 3.4.2 BASES APPLICABLE The capability of reflooding the core to two-thirds core height is dependent SAFETY upon the structural integrity of the jet pumps. If the structural system, ANALYSES including the beam holding a jet pump in place, fails, jet pump (continued) displacement and performance degradation could occur, resulting in an increased flow area through the jet pump and a lower core flooding elevation. This could adversely affect the water level in the core during the reflood phase of a LOCA as well as the assumed blowdown flow during a LOCA.

Jet pumps satisfy Criterion 2 of the NRC Policy Statement (Ref. 4).

LCO The structural failure of any of the jet pumps could cause significant degradation in the ability of the jet pumps to allow reflooding to two-thirds core height during a LOCA. OPERABILITY of all jet pumps is required to ensure that operation of the Reactor Coolant Recirculation System will be

-consistent with the assumptions used in the licensing basis analysis (Ref. 1).

APPLICABILITY In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactor core and since the limiting DBAs are assumed to occur in these MODES. This is consistent with the requirements for operation-of the Reactor Coolant Recirculation System (LCO 3.4.1).

In MODES 3, 4, and 5, the Reactor Coolant Recirculation System is not required to be in operation, and when not in operation, sufficient flow is not available to evaluate jet pump OPERABILITY.

ACTIONS A.1 An inoperable jet pump can increase the blowdown area and reduce the capability of reflooding during a design basis LOCA. If one or more of the jet pumps are inoperable, the (continued)

SUSQUEHANNA - UNIT 1 B 3.4-1 1 Revision 0

PPL Rev. 1 Jet Pumps B 3.4.2 BASES ACTIONS A.1 (continued) plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The Completion Time of 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.

SURVEILLANCE REQUIREMENTS This SR is designed to detect significant degradation in jet pump performance that precedes jet pump failure (Ref. 2). This SR is required to be performed only when the loop has forced recirculation flow since surveillance checks and measurements can only be performed during jet pump operation. With no forced recirculation flow, stresses on jet pump ._

-assemblies are significantly reduced. The jet pump failure of concern is a complete mixer displacement due to jet pump beam failure. Jet pump plugging is-also of concern since it adds flow resistance to the recirculation loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. The allowable deviations from the established patterns have been developed based on the variations experienced at plants during normal operation and with jet pump assembly failures (Refs. 2 and 3). Each recirculation loop must satisfy two of the performance criteria provided. Since refueling activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or core plate bypass flow) can affect the relationship between core flow, jet pump flow, and recirculation loop flow, these relationships may need to be re-established each cycle. Similarly, initial entry into extended single loop operation may also require establishment of these relationships. During the initial weeks of operation under such conditions, while base-lining new "established patterns", engineering judgement of the daily surveillance results is used to detect significant abnormalities which could indicate a jet pump failure.

The recirculation pump speed operating characteristics (loop (continued)

SUSQUEHANNA -. UNIT 1 B 3.4-12 Revision 0

PPL Rev. 1 Jet Pumps B 3.4.2 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS drive flow versus pump speed) are determined by the flow resistance from the loop suction through the jet pump nozzles. A change in the relationship indicates a plug, flow restriction, loss in pump hydraulic performance, leakage, or new flow path between the recirculation pump discharge and jet pump nozzle. For this criterion, loop drive flow versus pump speed relationship must be verified.

Individual jet pumps in a recirculation loop normally do not have the same flow. The unequal flow is due to the drive flow manifold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow

-for a jet pump that has experienced beam cracks.

The deviations from normal are considered indicative of a potential problem in the recirculation- drive flow or jet pump system (Ref. 2). Normal flow ranges and estab[ished jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown by operating experience to be timely for detecting jet pump degradation and is consistent with the Surveillance Frequency for recirculation loop OPERABILITY verification.

This SR is modified by two Notes. If this SR has not been performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the time an idle recirculation loop is restored to service, Note 1 allows 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the idle recirculation loop is in operation before the SR must be completed because these checks can only be performed during jet pump operation. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is an acceptable time to establish conditions and complete data collection and evaluation.

Note 2 allows deferring completion of this SR until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is greater than 23% of RTP. During low flow conditions, jet pump noise approaches the threshold (continued)

SUSQUEHANNA - UNIT 1 B 3.4-13 Revision I

PPL Rev. 1 Jet Pumps B 3.4.2 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data.

REFERENCES 1. FSAR, Section 6.3.

2. GE Service Information Letter No. 330, June 9, 1990.

3. NUREG/CR-3052, November 1984.

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

SUSQUEHANNA - UNIT 1 B 3.4-14 Revision 0

PPL Rev. 2 S/RVs B 3.4.3 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.3 Safety/Relief Valves (S/RVs)

BASES BACKGROUND The ASME Boiler and Pressure Vessel Code requires the reactor pressure vessel be protected from overpressure during upset conditions by self-actuated safety valves. As part of the nuclear pressure relief system, the size and number of S/RVs are selected such that peak pressure in the nuclear system will not exceed the ASME Code limits for the reactor coolant pressure boundary (RCPB).

The S/RVs are located on the main steam lines between the reactor vessel and the first isolation valve within the drywell. There are a total of 16 S/RVs of which any 14 are required to be OPERABLE. The S/RVs can actuate by either of two modes: the safety mode or the relief mode. In the safety mode (or spring mode of operation), the valve opens when steam pressure at the valve inlet overcomes the spring force holding the valve closed. This satisfies the Code requirement.

Each S/RV-discharges steam-through a discharge line to a point below the minimum water level in the-suppression pool. Six S/RVs also serve as the Automatic Depressurization System (ADS) valves. The ADS requirements are specified in LCO 3:5.1, "ECCS-Operating."

APPLICABLE The overpressure protection system must accommodate the most severe SAFETY pressurization transient. Evaluations have determined that the most ANALYSES severe transient is the closure of all main steam isolation valves (MSIVs),

followed by reactor scram on high neutron flux (i.e., failure of the direct scram associated with MSIV position) (Ref. 1). For the purpose of the analyses, 14 of the 16 S/RVs are assumed to operate in the safety mode.

The analysis results demonstrate that the design S/RV capacity is capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig = 1375 psig). This LCO helps to ensure that the acceptance limit of 1375 psig is met during the Design Basis Event.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-15 Revision 2

PPL Rev. 2 S/RVs B 3.4.3 BASES APPLICABLE From an overpressure standpoint, the design basis events are bounded SAFETY by the MSIV closure with flux scram event described above. Reference 2 ANALYSES discusses additional events that are expected to actuate the S/RVs.

(continued)

S/RVs satisfy Criterion 3 of the NRC Policy Statement (Ref. 4).

LCO The safety function of 14 of the 16 S/RVs are required to be OPERABLE to satisfy the assumptions of the safety analysis (Refs., 1 and 2). The requirements of this LCO are applicable only to the capability of the S/RVs to mechanically open to relieve excess pressure when the lift setpoint is exceeded (safety function).

The S/RV setpoints are established to ensure that the ASME Code limit on peak reactor pressure is satisfied. The ASME Code specifications require the lowest safety valve setpoint to be at or below vessel design ._

pressure (1250 psig) and the highest safety valve to be set so that the total accumulated pressure does not exceed 110% of the design pressure.

for overpressurization conditions. The transient evaluations in the FSAR _

are based on these setpoints,- but also include the additional uncertainty of +/- 3% of the nominal setpoint to provide an added degree of conservatism.

Operation with fewer valves OPERABLE than specified, or with setpoints outside the ASME limits, could result in a more severe reactor response to a transient than predicted, possibly resulting in the ASME Code limit on reactor pressure being exceeded.

APPLICABILITY In MODES 1, 2, and 3, all required S/RVs must be OPERABLE, since considerable energy may be in the reactor core and the limiting design basis transients are assumed to occur in these MODES. The S/RVs may be required to provide pressure relief to discharge energy from the core until such time that the Residual Heat Removal (RHR) System is capable of dissipating the core heat.

In MODE 4 reactor pressure is low enough that the overpressure limit is unlikely to be approached by assumed (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-16 Revision 3

PPL Rev. 2 S/RVs B 3.4.3 BASES APPLICABILITY operational transients or accidents. In MODE 5, the reactor vessel head is (continued) unbolted or removed and the reactor is at atmospheric pressure. The S/RV function is not needed during these conditions.

ACTIONS A.1 and A.2 With less than the minimum number of required S/RVs OPERABLE, a transient may result in the violation of the ASME Code limit on reactor pressure. If the safety function of one or more required S/RVs is inoperable, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 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 required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENT S The Surveillance requires that-the required S/RVs will open at the pressures-assumed in -the safety analysis of Reference 1. The demonstration of the S/RV safe lift settings must be performed during shutdown, since this is a bench test, to be done in accordance with the Inservice Testing Program. The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures. The S/RV setpoint is +/-3% of the nominal setpoint for OPERABILITY. Requirements for accelerated testing are established in accordance with the Inservice Test Program. Any of the 16 S/RVs, identified in this Surveillance Requirement, with their associated setpoints, can be designated as the 14 required S/RVs. This maintains the assumptions in the overpressure analysis.

A Note is provided to allow up to two of the required 14 S/RVs to be physically replaced with S/RVs with lower setpoints until the next refueling outage. This provides operational flexibility which maintains the assumptions in the over-pressure analysis.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-17 Revision 3

PPL Rev. 2 S/RVs B 3.4.3 BASES SURVEILLANCE SR 3.4.3.1 (continued)

REQUIREMENTS The Frequency of this Surveillance is established in accordance with the Inservice Testing Program.

REFERENCES 1. FSAR, Section 5.2.2.1.4.

2. FSAR, Section 15.

3. ASME Operation and Maintenance Code.

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

SUSQUEHANNA - UNIT 1 TS / B 3.4-18 Revision 2

PPL Rev. 3 RCS P/T Limits B 3.4.10 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.10 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.

This Specification contains P/T limit curves for heatup, cooldown, and inservice leakage and hydrostatic testing, and limits for the maximum rate of change of reactor coolant temperature. The heatup curve provides limits for both heatup and criticality.

Each P/T limit curve defines an acceptable region for normal operation.

The usual use of the curves is operational guidance during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region.

The LCO establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping.of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure.

Therefore, the LCO limits apply mainly to the vessel.

10 CFR 50, Appendix G (Ref. 1), requires the establishment of P/T limits for material fracture toughness requirements of the RCPB materials.

Reference 1 requires an adequate margin to brittle failure during normal operation, anticipated operational occurrences, and system hydrostatic tests. It mandates the use of the ASME Code, Section Xl, Appendix G (Ref. 2).

The actual shift in the RTNDT of the vessel material will be established periodically by removing and evaluating the irradiatedreactor vessel material specimens, in accordance with ASTM E 185 (Ref. 3) and Appendix H of 10 CFR 50 (Ref. 4). The operating P/T limit curves will be adjusted, as necessary, based on the evaluation findings and the recommendations of RG 1.99, "Radiation Embrittlement of Reactor Vessel Materials" (Ref. 5). The calculations to determine neutron fluence will be developed using the BWRVIP RAMA code methodology, which is NRC approved and meets the intent of RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence" (Ref. 11).

See FSAR Section 4.1.4.5 for determining fluence (Ref. 12).

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-49 Revision 3

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES BACKGROUND The P/T limit curves are composite curves established by superimposing (continued) limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive regions.

The heatup curve used to develop the P/T limit curve composite represents a different set of restrictions than the cooldown curve used to develop the P/T limit curve composite because the directions of the thermal gradients through the vessel wall are reversed. The thermal gradient reversal alters the location of the tensile stress between the outer and inner walls.

The criticality limits include the Reference 1 requirement that they be at least 40°F above the heatup curve or the cooldown curve and not lower than the minimum permissible temperature for the inservice leakage and hydrostatic testing.

.The consequence of violating-the LCO limits is that the RCS has been operated under conditions that can result in brittle failure of the RCPB, possibly leading to a nonisolable leak or loss of coolant accident. In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the RCPB components.

ASME Code, Section Xl, Appendix E (Ref. 6), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits.

APPLICABLE The P/T limits are not derived from Design Basis Accident (DBA)

SAFETY analyses. They are prescribed during normal operation to avoid ANALYSES encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the RCPB, a condition that is unanalyzed.

Reference 7 establishes the methodology for determining the P/T limits.

Since the P/T limits are not derived from any DBA, there are no acceptance limits related to the P/T limits. Rather, the P/T limits are acceptance limits themselves since they preclude operation in an unanalyzed condition.

RCS P/T limits satisfy Criterion 2 of the NRC Policy Statement (Ref. 8).

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-50 Revision 1

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES APPLICABLE The Effective Full Power Years (EFPY) shown on the curves are SAFETY approximations of the ratio of the energy that has been and is anticipated ANALYSES to be generated in a year to the energy that could have been generated if (continued) the unit ran at original thermal power rating of 3293 MWT for the entire year. These values are based on fluence limits that are not to be exceeded.

LCO The elements of this LCO are:

a. RCS pressure and temperature are to the right of the applicable curves specified in Figures 3.4.10-1 through 3.4.10-3 and within the applicable heat-up or cool down rate specified in SR 3.4.10.1 during RCS heatup, cooldown, and inservice leak and hydrostatic testing;

b. The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel (RPV) coolant is < 145 0 F during recirculation pump startup, and during increases in THERMAL POWER or loop flow while operating at low THERMAL POWER or loop flow;

-c. The temperature difference between the reactor coolant in the respective recirculation loop and in the reactor vessel is _< 50OF during -

recirculation pump startup; and during increases in THERMAL POWER or loop flow while operating at low THERMAL POWER or loop flow;

d. RCS pressure and temperature are to the right of the criticality limits.

specified in Figure 3.4.10-3 prior to achieving criticality; and

e. The reactor vessel flange and the head flange temperatures are>

70OF when tensioning the reactor vessel head bolting studs.

These limits define allowable operating regions and permit a large number" of operating cycles while also providing a wide margin to nonductile failure.

The P/T limit composite curves are calculated using the worst case of material properties, stresses, and temperature change rates anticipated under all heatup and cooldown conditions. The design calculations account for the reactor coolant fluid temperature impact on the inner wall of the vessel and the temperature gradients through the vessel wall.

Because these fluid temperatures drive the vessel wall temperature gradient, monitoring reactor coolant temperature provides. a conservative method of ensuring the P/T limits are not exceeded. Proper monitoring of vessel temperatures to assure compliance with brittle fracture temperature limits and vessel thermal stress limits during normal heatup and cooldown, and during inservice leakage and hydrostatic testing, is established in PPL Calculation EC-062-0573 (Ref. 9). For P/T curves A, B, and C, the bottom head drain line coolant temperature should be monitored and maintained to the right of the most limiting curve.

(continued)

SUSQUEHANNA- UNIT 1 TS / B 3.4-51 Revision 3

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES LCO Curve A must be used for any ASME Section III Design Hydrostatic Tests (continued) performed at unsaturated reactor conditions. Curve A may also be used for ASME Section XI inservice leakage and hydrostatic testing when heatup and cooldown rates can be limited to 20°F in a one-hour period.

Curve A is based on pressure stresses only. Thermal stresses are assumed to be insignificant. Therefore, heatup and cooldown rates are limited to 20°F in a one-hour period when using Curve A to ensure minimal thermal stresses. The recirculation loop suction line temperatures should-be monitored to determine the temperature change rate.

Curves B and C are to be used for non-nuclear and nuclear heatup and cooldown, respectively. In addition, Curve B may be used for ASME Section Xl inservice leakage and hydrostatic testing, but not for ASME Section III Design Hydrostatic Tests performed at unsaturated reactor conditions. Heatup and cooldown rates are limited to 100OF in a one-hour period when using Curves B and C. This limits the thermal gradient through the vessel wall, which is used to calculate the thermal stresses in the vessel wall. Thus, the LCO for the rate of coolant temperature change limits the thermal stresses and ensures the validity of the P/T curves. The

-vessel beltline fracture analysis assumes a 100°F/hr coolant heatup or cooldown rate in the beltline area. The 100OF limit in a one-hour period applies to the coolant in the beltline region, and takes into account the thermal inertia of.the vessel wall. Steam dome saturation temperature (TsAT), as derived from steam dome pressure, should be monitored to determine-the beltline temperature change rate at temperatures above 212 0 F. At temperatures below 212 0 F, the recirculation loop suction line temperatures should be monitored.

Violation of the limits places the reactor vessel outside of the bounds of the stress analyses and can increase stresses in other RCS components.

The consequences depend on several factors, as follows:

a. The severity of the departure from the allowable operating pressure temperature regime or the severity of the rate of change of temperature;

b. The length of time the limits were violated (longer violations allow the temperature gradient in the thick vessel walls to become more pronounced); and

c. The existences, sizes, and orientations of flaws in the vessel material.

APPLICABILITY The potential for violating a P/T limit exists at all times. For example, P/T limit violations could result from ambient temperature conditions that result in the reactor vessel metal temperature being less than the minimum allowed temperature for boltup. Therefore, this LCO is applicable even when fuel is not loaded in the core.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-52 Revision 2

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES (continued)

ACTIONS A.1 and A.2 Operation outside the P/T limits while in MODES 1, 2, and 3 must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses.

The 30 minute Completion Time reflects the urgency of restoring the parameters to within the analyzed range. Most violations will not be severe, and the activity can be accomplished in this time in a controlled manner.

Besides restoring operation within limits, an evaluation is required to determine if RCS operation can continue. The evaluation must verify the RCPB integrity remains acceptable and must be completed if continued operation is desired. Several methods may be used, including comparison with pre-analyzed transients in the stress analyses, new analyses, or inspection of the components.

ASME Code,Section XI, Appendix E (Ref. 6), may be used to support the evaluation. However, its use is restricted to evaluation of the vessel beltline.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable to accomplish the evaluation-of a mild violation. More severe violations may require special, event specific stre ss analyses or inspections. A favorable evaluation must be completed-if continued operation is desired.

Condition A is modified by a Note requiring Required Action A.2 be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action A.1 is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity.

B.1 and B.2 If a Required Action and associated Completion Time of Condition A are not met, the plant must be placed in a lower MODE because either the RCS remained in an unacceptable P/T region for an extended period of increased stress, or a sufficiently severe event caused entry into an unacceptable region. Either possibility indicates a need for more careful examination of the event, best accomplished with the RCS at reduced pressure and temperature. With the reduced pressure and temperature conditions, the possibility of propagation of undetected flaws is decreased.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-53 Revision 1

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES ACTIONS B.1 and B.2 (continued)

Pressure and temperature are reduced by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in 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.

C.1 and C.2 Operation outside the P/T limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Action must be initiated without delay and continued until the limits are restored.

Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed. This evaluation must

-verify that the RC.PB integrity is acceptable and must be completed before approaching criticality or heating up to > 200 0 F. Several methods may be used, including .comparison with pre-analyzed transients, new analyses, qr inspection of the componentsl ASME Code,Section XI, Appendix E (Ref. 6), may be used to support the evaluation; however, its use is restricted to- evaluation, of the beltline.

SURVEILLANCE SR 3.4.10.1 REQUIREMENTS Verification that operation is within limits (i.e., to the right of the applicable curves in Figures 3.4.10-1 through 3.4.10-3) is required every 30 minutes when RCS pressure and temperature conditions are undergoing planned changes. This Frequency is considered reasonable in view of the control room indication available to monitor RCS status. Also, since temperature rate of change limits are specified in hourly increments, 30 minutes permits a reasonable time for assessment and correction of minor deviations.

Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are satisfied.

This SR has been modified with a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing.

(continued)

SUSQUEHANNA - UNIT 1 TS / B] 3.4-54 Revision 2

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES SURVEILLANCE SURVEQIR NENS SR 3.4.10.1 (continued)

REQUIREMENTS Notes to the acceptance criteria for heatup and cooldown rates ensure that more restrictive limits are applicable when the P/T limits associated with hydrostatic and inservice testing are being applied.

SR 3.4.10.2 A separate limit is used when the reactor is approaching criticality.

Consequently, the RCS pressure and temperature must be verified within the appropriate limits (i.e., to the right of the criticality curve in Figure 3.4.10-3) before withdrawing control rods that will make the reactor critical.

Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of reactor criticality. Although no Surveillance Frequency is specified, the requirements-of SR-3.4.10.2 must be met at.

all times when the reactor is critical.

SR 3.4.1.0.3 and SR .3.4.10.4-Differential temperatures within the applicable limits ensure that thermal stresses resulting from the startup of an idle recirculation pump will not exceed design allowances. In addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 10) are satisfied.

Performing the Surveillance within 15 minutes before starting the idle recirculation pump provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump start.

An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.10.4 is to compare the temperatures of the operating recirculation loop and the idle loop. If both loops are idle, compare the temperature difference between the reactor coolant within the idle loop to be started and coolant in the reactor vessel.

(continued)

. SUSQUEHANNA - UNIT 1 TS / B 3.4-55 Revision 2

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES SURVEILLANCE REQUIREMENTS SR 3.4.10.3 and SR 3.4.10.4 (continued)

SR 3.4.10.3 has been modified by a Note that requires the Surveillance to be performed only in MODES 1, 2, 3, and 4. In MODE 5, the overall stress on limiting components is lower. Therefore, AT limits are not required. The Note also states the SR is only required to be met during a recirculation pump start-up, because this is when the stresses occur.

SR 3.4.10.5 and SR 3.4.10.6 Differential temperatures within the applicable limits ensure that thermal stresses resulting from increases in THERMAL POWER or recirculation loop flow during single recirculation loop operation will not exceed design allowances. Performing the Surveillance within 15 minutes before beginning such an increase in power or flow rate provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and-the time of the change in operation.

An acceptable means of demonstrating compliance with the temperature differential requireme-nt in.SR 3.4.10.6 is to compare the temperatures of the operating recirculation-loop and the idle loop.

Plant specific startup test data has determined that the bottom head is not subject to temperature stratification at power levels > 27% of RTP and with single loop flow rate >_ 21,320 gpm (50% of rated loop flow).

Therefore, SR 3.4.10.5 and SR 3.4.10.6 have been modified by a Note that requires the Surveillance to be met only under these conditions. The Note for SR 3.4.10.6 further limits the requirement for this Surveillance to exclude comparison of the idle loop temperature if the idle loop is isolated from the RPV since the water in the loop cannot be introduced into the remainder of the Reactor Coolant System.

SR 3.4.10.7, SR 3.4.10.8, and SR 3.4.10.9 Limits on the reactor vessel flange and head flange temperatures are generally bounded by the other P/T limits during system heatup and cooldown. However, operations approaching MODE 4 from MODE 5 and in MODE 4 with RCS temperature less than or equal to certain specified values require assurance that these temperatures meet the LCO limits.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.4-56 Revision 2

PPL Rev. 3 RCS P/T Limits B 3.4.10 BASES SURVEILLANCE REQUIREMENTS SR 3.4.10.7, SR 3.4.10.8, and SR 3.4.10.9 (continued)

The flange temperatures must be verified to be above the limits 30 minutes before and while tensioning the vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. When in MODE 4 with RCS temperature < 80 0 F, 30 minute checks of the flange temperatures are required because of the reduced margin to the limits.

When in MODE 4 with RCS temperature < 100 0 F, monitoring of the flange temperature is required every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to ensure the temperature is within the specified limits.

The 30 minute Frequency reflects the urgency of maintaining the temperatures within limits, and also limits the time that the temperature limits could be exceeded. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable based on the rate of temperature change possible at these temperatures.

REFERENCES - 1. 10 CFR 50, Appendix G.

2. ASME, Boiler and Pressure Vessel C-de,Section XI, Appendix G.

3. ASTME 185-73.

4. 10 CFR 50, Appendix H.

5. Regulatory Guide 1.99, Revision 2, May 1988.

6. ASME, Boiler and Pressure Vessel Code, Section Xl, Appendix E.

7. NEDO-21778-A, December 1978.

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

9. PPL Calculation EC-062-0573, "Study to Support the Bases Section of Technical Specification 3.4.10."

10. FSAR, Section 15.4.4.

11. Regulatory Guide 1.190, March 2001.

12. FSAR, Section 4.1.4.5.

SUSQUEHANNA - UNIT 1 TS / B 3.4-57 Revision 3

PPL Rev. 3 Primary Containment B 3.6.1.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a Design Basis Loss of Coolant Accident and to confine the postulated release of radioactive material. The primary containment consists of a steel lined, reinforced concrete vessel, which surrounds the Reactor Primary System and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment.

The isolation devices for the penetrations in the primary containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:

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

1- capable of being closed by an OPERABLE automatic containment isolation system, or

2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their

- .closed positions, except as provided in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs);"'

b. The primary containment air lock is OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air Lock;"

and

c. All equipment hatches are closed.

Several instruments connect to the primary containment atmosphere and are considered extensions of the primary containment. The leak rate tested instrument isolation valves identified in the Leakage Rate Test Program should be used as the primary containment boundary when the instruments are isolated and/or vented. Table B 3.6.1.1-1 contains the listing of the instruments and isolation valves.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-1 Revision 2

PPL Rev. 3 Primary Containment B 3.6.1.1 BASES BACKGROUND (continued) The H20 2 Analyzer lines beyond the PCIVs, up to and including the components within the H20 2 Analyzer panels, are extensions of primary containment (i.e., closed system), and are required to be leak rate tested in accordance with the Leakage Rate Test Program. The H20 2 Analyzer closed system boundary is identified in the Leakage Rate Test Program, and consists of components, piping, tubing, fittings, and valves, which meet the design guidance of Reference 7. Within the H 2 0 2 Analyzer panels, the boundary ends at the first normally closed valve. The closed system boundary between PASS and the H20 2 Analyzer system ends at the Seismic Category I boundary between the two systems. This boundary occurs at the process sampling solenoid operated isolation valves (SV-12361, SV-12365, SV-12366, SV-12368, and SV-12369). These solenoid operated isolation valves do not fully meet the guidance of Reference 7 for closed system boundary valves in that they are not powered from a Class 1E power source. Based upon a risk determination, operating these valves as closed system boundary valves is not risk significant.

These normally closed valves are required to be leakage rate tested in accordance with the Leakage Rate Test Program, since-they form part of the closed system boundary for the H20 2 Analyzers. These valves-are "closed system boundary valves" -

and may be opened under administrative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

When the H20 2 Analyzer panels are isolated and/or vented, the panel isolation valves identified in the Leakage Rate Test Program should be used as the boundary of the extension of primary containment. Table B 3.6.1.1-2 contains a listing of the affected H20 2 Analyzer penetrations and panel isolation valves.

This Specification ensures that the performance of the primary containment, in the event of a Design Basis Accident (DBA),

meets the assumptions used in the safety analyses of References 1 and 2. SR 3.6.1.1.1 leakage rate requirements are in conformance with 10 CFR 50, Appendix J, Option B and supporting documents (Ref. 3, 4 and 5), as modified by approved exemptions.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-1 a Revision 3

PPL Rev. 3 Primary Containment B 3.6.1.1 BASES (continued)

APPLICABLE The safety design basis for the primary containment is that SAFETY ANALYSES it must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.

The DBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage.

Analytical methods and assumptions involving the primary containment are presented in References 1 and 2. The safety analyses assume a nonmechanistic fission product release following a DBA, which forms the basis for determination of offsite

'based on an assumed leakage rate from the primary containment. OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.

The maximum allowable leakage rate for the primary containment (La) is 1.0% by weightof the containment air per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the -

design- basis LOCA maximum peak containment pressure (Pa) of 48.6 psig. -

Primary containment satisfies Criterion 3 of the NRC Policy Statement. (Ref. 6)

LCO Primary containment OPERABILITY is maintained by limiting leakage to _<1.0 La, except prior to each startup after performing a.

required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met.

Compliance with this LCO will ensure a primary containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specified for the primary containment air lock are addressed in LCO 3.6.1.2.

Leakage requirements for MSIVs and Secondary containment bypass are addressed in LCO 3.6.1.3.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-2 Revision 4

PPL Rev. 3 Primary Containment B 3.6.1.1 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.

Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

ACTIONS A.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1, 2, and 3.

This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.

B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a-MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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.

SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. The primary containment concrete visual examinations may be performed during either power operation, e.g., performed concurrently with other primary containment inspection-related activities, or during a maintenance or refueling outage. The visual examinations of the steel liner plate inside primary containment are performed during maintenance or refueling outages since this is the only time the liner plate is fully accessible.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-3 Revision 3

PPL Rev. 3 Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.1 (continued)

REQU IREMENTS Failure to meet air lock leakage testing (SR 3.6.1.2.1) or resilient seal primary containment purge valve leakage testing (SR 3.6.1.3.6) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. As left leakage prior to each startup after performing a required leakage test is required to be < 0.6 La for combined Type B and C leakage, and < 0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of

< 1.0 La. At < 1.0 La the offsite and control room dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR Frequencies are as required by the Primary Containment Leakage Rate Testing Program. These periodic testing requirements verify that the primary containment leakage rate does-not exceed the leakage rate assumed in the safety analysis.

As noted in table B 3.6.1,3-1, an exemption to Appendix J is -

provided that isolation barriers which remain water filled or a water seal remains in the line- post-LOCA are tested with water and the leakage is not includedin the Type B and C 0.60 La total.

SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR measures drywell to suppression chamber leakage to ensure that the leakage paths that would bypass the suppression pool are within allowable limits. The allowable limit is 10% of the acceptable SSES A//k design valve. For SSES, the A/,k design value is

.0535 ft2 .

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and determining the leakage. The leakage test is performed when the 10 CFR 50, Appendix J, Type A test is performed in accordance with the Primary Containment Leakage Rate Testing Program. This testing Frequency was developed considering this test is performed in conjunction with the Integrated Leak rate test (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-4 Revision 4

PPL Rev. 3 Primary Containment B 3.6:1.1 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 24 months is required until the situation is remedied as evidenced by passing two consecutive tests.

SR 3.6.1.1.3 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through downcomers into the suppression pool. This SR measures suppression chamber-to-drywell vacuum breaker leakage to ensure the leakage paths that would bypass the suppression pool are within allowable limits. The total allowable leakage limit is 30% of the SR 3.6.1.1.2 limit. The allowable leakage per set is 12% of the SR 3.6.1.1-.2 limit. _

The leakage is determined by establishing a 4.3 psi differential pressure across the drywell-to-suppression chamber vacuum breakers and verifying the leakage. The leakage test is performed every 24 months. The 24 month Frequency was developed considering the surveillance must be performed during a unit outage. A Note is provided which allows this Surveillance not to be performed when SR 3.6.1.1.2 is performed. This is acceptable because SR 3.6.1.1.2 ensures the OPERABILITY of the pressure.

suppression function including the suppression chamber-to-drywell vacuum breakers.

REFERENCES 1. FSAR, Section 6.2.

2. FSAR, Section 15.

3. 10 CFR 50, Appendix J, Option B.

4. Nuclear Energy Institute, 94-01 (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-5 Revision 3

PPL Rev. 3 Primary Containment B 3.6.1.1 BASES REFERENCES (continued) 5. ANSI/ANS 56.8-1994

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

7. Standard Review Plan 6.2.4, Rev. 1, September 1975 SUSQUEHANNA - UNIT 1 TS /B 3.6-6 Revision 3

PPL Rev. 3 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 1 of 2)

PENETRATION INSTRUMENT ISOLATION NUMBER VALVE X-3B PSH-C72-1 N002A IC-PSH-1 N002A PSH L C72-1N004 IC-PSHL-1N004 PS-E11-1NO10A IC-PS-1NO10A PS-E11-1NO11A IC-PS-1 N01 1A PSH-C72-1 N002B IC-PSH-1 NOO2B PS-E11-1NO10C IC-PS-1NO10C PS-Eli-iNO11C IC-PS-iNO11C PSH-15120C IC-PSH-15120C X-32A PSH-C72-1 N002D -IC-PSH-1 N002D PS-Ell-1N010Bl IC-PS-1NO10B PS-El-1N011iB IC-PS-1N011B PSH-C72-1 N002C IC-PSH-1 N002C PS-Ell-1NO10D IC-PS-1NO10D PS-Ell-iNO11D IC-PS-1N011D PSH-15120D IC-PSH-15120D X-39A FT-15120A IC-FT-15120A HIGH and IC-FT-15120A LOW X-39B FT-15120B IC-FT-15120B HIGH and IC-FT-15120B LOW X-90A PT-15709A IC-PT-15709A PT-15710A IC-PT-15710A PT-15728A IC-PT-1 5728A X-90D PT-15709B IC-PT- 15709B PT-15710B IC-PT-15710B PT-15728B IC-PT-15728B SUSQUEHANNA - UNIT 1 TS/B 3.6-6a Revision 2

PPL Rev. 3 Primary Containment B 3.6.1 1 B 3.6.1.1-1 TABLE TABLE B 3.6. 1.1 -1 INSTRUMENT ISOLATION VALVES (Page 2 of 2)

X-204A/205A FT-15121A IC-FT-15121A HIGH and IC-FT-15121A LOW X-204B1/205B FT-15121B IC-FT-15121B HIGH and IC-FT-15121B LOW X-219A LT-15775A IC-LT-15775A REF and IC-LT-15775A VAR LSH-E41-1NO15A 155027 and 155031 LSH-E41-1N015B 155029 and 155033 X-223A PT- 15702 IC-PT- 15702 X-232A LT-15776A /C-LT-15776A I REF and IC-LT-15776A VAR PT-15729A IC-PT-15729A LI-1I5776A2 IC-LT-15776A2 REF and IC-LT-15776A2 VAR X234A LT-15775B IC-LT-15775B REF and IC-LT-15775B VAR X-235A LT-15776B. IC-LT-15776B REF and IC-LT-15776B VAR PT-15729B IC-PT-15729B SUSQUEHANNA- UNIT 1 TS/B 3.6-6b Revision 2

PPL Rev. 3 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-2 H20 2 ANALYZER PANEL ISOLATION VALVES PENETRATION NUMBER PANEL ISOLATION VALVE(a)

X-60A, X-88B, X-221A, X-238A 157138 157139 157140 157141 157142 X-80C, X-233, X-238B 157149 157150 157151 157152 157153 (a) Only those valves listedcin this table with current leak rate test results, as identified in the Leakage Rate Test Program, may be used as isolation valves.

SUSQUEHANNA - UNIT 1 TS/B3 3.6-6c Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.2 Primary Containment Air Lock BASES BACKGROUND One double door primary containment air lock has been built into the primary containment to provide personnel access to the drywell and to provide primary containment isolation during the process of personnel entering and exiting the drywell. The air lock is designed to withstand the same loads, temperatures, and peak design internal and external pressures as the primary containment (Ref. 1). As part of the primary containment, the air lock limits the release of radioactive material to the environment during normal unit operation and through a range of transients and accidents up to and including postulated Design Basis Accidents (DBAs).

Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a DBA in primary containment. Each of the doors contains double _gasketed seals and local leakage rate testing capability to ensure pressure integrity.- To effect a leak tight seal, the air lock design-uses pressure seated doors (i.e., an increase in primary containment internal pressure results in increased sealing force on each door).

The air lock is an 8 ft 7 inch inside diameter cylindrical pressure vessel with doors at each end that are interlocked to prevent simultaneous opening. During periods when primary containment is not required to be OPERABLE, the air lock interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent primary containment entry is necessary. Under some conditions as allowed by this LCO, the primary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms part of the primary containment pressure boundary. As such, air lock integrity and leak tightness are essential for maintaining primary containment leakage rate to within limits in the event of a DBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in the unit safety analysis.

(continued)

SUSQUEHANNA - UNIT 1 B. 3.6-7 Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES (continued)

APPLICABLE The DBA that postulates the maximum release of radioactive material SAFETY ANALYSES within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE, such that release of fission products to the environment is controlled by the rate of primary containment leakage. The primary containment is designed with a maximum allowable leakage rate (La) of 1.0% by weight of the containment air per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the calculated maximum peak containment pressure (Pa) of 48.6 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock.

Primary containment air lock OPERABILITY is also required to minimize the amount of fission product gases that may escape primary containment through the air lock and contaminate and pressurize the secondary containment.

The primary containment air lock satisfies Criterion 3 of the NRC Policy Statement. (Ref. 4)

LCO As part of the primary containment pressure boundary, the air lock's -

safety function is related to control of containment leakage rates following a DBA. Thus, the- air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.

The primary containment air lock is required to be OPERABLE. For the air lock to be considered OPERABLE, the air lock interlock mechanism must be OPERABLE, the air lock must be in compliance with the Type B air lock leakage test, and both air lock doors must be OPERABLE. The interlock allows only one air lock door to be opened at a time. This provision ensures that a gross breach of primary containment does not exist when primary containment is required to be OPERABLE. Closure of a single door in each air lock is sufficient to provide a leak tight barrier following postulated events.

Nevertheless, both doors are kept closed when the air lock is not being used for normal entry or exit from primary containment.

(continued)

SUSQUEHANNA - UNIT 1 B., 3.6-8 Revision 1

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the primary containment air lock is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

ACTIONS The ACTIONS are modified by Note 1, which allows entry and exit to perform repairs of the affected air lock component. If the outer door is inoperable, then it may be easily accessed to repair. If the inner door is the one that is inoperable, however, then a short time exists when the containment boundary is not intact (during access through the outer door). The ability to open the OPERABLE door, even if it means the primary containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the primary containment during the short time in which the OPERABLE door is expected to be open. The OPERABLE door must--

be immediately closed after each entry and exit.

The ACTIONS are modified by a second Note, which ensures appropriate remedial measures are taken when necessary. This is an exception to LCO3.0.6 which would not require action, even if primary containment is exceeding its leakage limit. Therefore, the Note is added to require ACTIONS for LCO 3.6.1.1, "Primary Containment," to be taken in this event.

A.1, A.2, and A.3 With one primary containment air lock door inoperable, the OPERABLE door must be verified closed (Required Action A.1) in the air lock. This ensures that a leak tight primary containment barrier is maintained by the use of an OPERABLE air lock door. This action must be completed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

In addition, the air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (continued)

- SUSQUEHANNA - UNIT 1 B. 3.6-9 Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES ACTIONS A.1, A.2, and A.3 (continued)

Completion Time. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is considered reasonable for locking the OPERABLE air lock door, considering that the OPERABLE door is being maintained closed.

Required Action A.3 ensures that the air lock with an inoperable door has been isolated by the use of a locked closed OPERABLE air lock door. This ensures that an acceptable primary containment leakage boundary is maintained. The Completion Time of once per 31 days is based on engineering judgment and is considered adequate in view of the low likelihood of a locked door being mispositioned and other administrative controls. Required Action A.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas with limited access due to inerting and allows these doors to be verified locked closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability-of misalignment of the door, once it has been verified to be in the proper position, is small. -

The Required Actions-have been modified by two Notes. Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. With both doors in the air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. The exception of Note 1 does not affect tracking the Completion Time from the initial entry into Condition A; only the requirement to comply with the Required Actions. Note 2 allows use of the air lock for entry and exit for 7 days under administrative controls. This 7 day limit is an accumulated limit that applies to the total combined time for all entries and exits.

Primary containment entry may be required to perform Technical Specifications (TS) Surveillances and Required Actions, as well as other activities on equipment inside primary containment that are required by TS or activities on equipment that support TS-required equipment. This Note is not intended to preclude performing other activities (i.e., non-TS-related activities) if the primary containment was entered, using the inoperable air lock, to perform an (continued)

SUSQUEHANNA - UNIT 1 B. 3.6-10 Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES ACTIONS A.1, A.2, and A.3 (continued) allowed activity listed above. This allowance is acceptable due to the low probability of an event that could pressurize the primary containment during the short time that the OPERABLE door is expected to be open.

B.1, B.2, and B.3 With an air lock interlock mechanism inoperable, the Required Actions and associated Completion Times are consistent with those specified in Condition A.

The Required Actions have been modified by two Notes. Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. With both doors in the air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. Note 2 allows entry into--

and exit from the primary. containment under the control of a dedicated individual stationed at the air lock to ensure that only one -

door is opened ata time (i.e., the individual performs the function of the interlock).

Required Action B.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas with limited access due to inerting and that allows these doors to be verified locked closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.

C.1, C.2, and C.3 If the air lock is inoperable for reasons other than those described, in Condition A or B, Required Action C.1 requires action to be immediately initiated to evaluate containment overall leakage rates using current air lock leakage test results. An evaluation is acceptable since it is overly conservative to immediately declare the primary containment inoperable if both doors in an air lock have failed a seal (continued)

SUSQUEHANNA - UNIT 1 B. 3.6-11 Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES ACTIONS C.1, C.2, and C.3 (continued) test or if the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door has failed), primary containment remains OPERABLE, yet only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (according to LCO 3.6.1.1) would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits.

Required Action C.2 requires that one door in the primary containment air lock must be verified closed. This action must be completed within the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.1.1, which require that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Additionally, the air lock must be restored to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable for restoring an inoperable air lock to OPERABLEstatus considering that at least -

one door is maintained closed in the air lock.

D.1 and D.2 If the inoperable primary containment air lock cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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.

SURVEILLANCE SR 3.6.1.2.1 REQUIREMENTS Maintaining primary containment air locks OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. This SR reflects the leakage rate testing requirements with respect to air lock leakage (Type B leakage tests). The acceptance (continued)

SUSQUEHANNA - UNIT 1 B. 3.6-12 Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES SURVEILLANCE SR 3.6.1.2.1 (continued)

REQUIREMENTS criteria were established based on engineering judgement and industry operating experience. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

The SR has been modified by two Notes, Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a DBA. Note 2 requires the results of airlock leakage tests be evaluated against the acceptance criteria of the Primary Containment Leakage Testing Program, 5.5.12. This ensures that the airlock leakage is properly accounted for in determining the combined Type B and C primary containment.

leakage.

SR 3.6.1.2.2 The air-lock interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident primary containment pressure, closure of either door will support primary containment OPERABILITY. Thus, the interlock feature supports primary containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening will not inadvertently occur. Due to the purely mechanical nature of this interlock, and given that the interlock mechanism is not normally challenged when primary containment is used for entry and exit (procedures require strict adherence to single door openings), this test is only required to be performed every 24 months. The 24 month frequency is based on the need to perform this surveillance under conditions that apply during a plant outage, and the potential for loss of primary containment OPERABILITY, if the surveillance were performed with the reactor at power. The 24 month frequency for the interlock is justified based on generic operating (continued)

SUSQUEHANNA - UNIT 1 T B. 3.6,13 Revision 0

PPL Rev. 1 Primary Containment Air Lock B 3.6.1.2 BASES SURVEILLANCE SR 3.6.1.2.2 (continued)

REQUIREMENTS experience. The 24 month Frequency is based on engineering judgment and is considered adequate given the interlock is not challenged during the use of the air lock.

REFERENCES 1. FSAR, Section 3.8.2.1.2.

(continued)

2. 10 CFR 50, Appendix J, Option B.

3. FSAR, Section 6.2.

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

SUSQUEHANNA - UNIT 1 B. 3.6-14 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

BASES BACKGROUND The function-of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.

The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment.

Therefore, the OPERABILITY requirements provide assurance that primary containment function assumed in the safety analyses will be maintained. For PCIVs, the primary containment isolation function is that the valve must be able to close (automatically or manually) and/or remain closed, and maintain leakage within that -.

assumed in the DBALOCA Dose Analysis. These isolation devices are either passiveor active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valveswith flow through the valve secured), blind flanges, and closed systems are considered passive devices. The OPERABILITY requirements for closed systems are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.

For each division of H20 2 Analyzers, the lines, up to and including the first normally closed valves within the H202 Analyzer panels, are extensions of primary containment (i.e.,

closed system), and are required to be leak rate tested in (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-15 Revision 2

PPL Rev. 8 PCIVs B 3.6.1.3 BASES BACKGROUND accordance with the Leakage Rate Test Program. The H 2 0 2 (continued) Analyzer closed system boundary is identified in the Leakage Rate Test Program. The closed system boundary consists of those components, piping, tubing, fittings, and valves, which meet the guidance of Reference 6. The closed system provides a secondary barrier in the event of a single failure of the PCIVs, as described below. The closed system boundary between PASS and the H 2 0 2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-12361, SV-12365, SV-12366, SV-12368, and SV-12369). These solenoid operated isolation valves do not fully meet the guidance of Reference 6 for closed system boundary valves in that they are not powered from a Class 1 E power source. However, based upon a risk determination, operating these valves as closed system boundary valves is not risk significant. These valves also form the end of the Seismic Category I boundary between the systems. These process sampling solenoid operated isolation valves are normally closed and are required to be leak rate tested in accordance with the Leakage Rate Test Program as part of the closed system for the H 2 0 2 Analyzer system. These valves are "closed system boundary valves" and may be opened under administrative control; as delineated in Technical Requirements Manual (TRM).Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

Each H2 0 2 Analyzer Sampling line penetrating primary containment has two PCIVs, located just outside primary containment. While two PCIVs are provided on each line, a single active failure of a relay in the control circuitry for these valves, could result in both valves failing to close or failing to remain closed. Furthermore, a single failure (a hot short in the common raceway to all the valves) could simultaneously affect all of the PCIVs within a H20 2 Analyzer division. Therefore, the containment isolation barriers for these penetrations consist of two PCIVs and a closed system. For situations where one or both PCIVs are inoperable, the ACTIONS to be taken are similar to the ACTIONS for a single PCIV backed by a closed system.

(continued)

SUSQUEHANNA - UNIT 1 TS /B 3.6-15a Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES BACKGROUND The drywell vent and purge lines are 24 inches in diameter; (continued) the suppression chamber vent and purge lines are 18 inches in diameter. The containment purge valves are normally maintained closed in MODES 1, 2, and 3 to ensure the primary containment boundary is maintained. The outboard isolation valves have 2 inch bypass lines around them for use during normal reactor operation.

The RHR Shutdown Cooling return line containment penetrations

{X-13A(B)}are provided with a normally closed gate valve

{HV-151F015A(B)} and a normally open globe valve

{HV-151F017A(B)} outside containment and a testable check valve {HV-151F050A(B)} with a normally closed parallel air operated globe valve {HV-1 51 F1 22A(B)} inside containment.

The gate valve is manually opened and automatically isolates upon a containment isolation signal from the Nuclear Steam Supply Shutoff System or RPV low level 3 when the RHR System is operated in the Shutdown Cooling Mode only. The LPCI subsystem is an operational mode of the RHR System and uses the same injection lines to the RPV as the Shutdown Cooling Mode.

The design of these containment penetrations is unique in that "

some valves are containment isolation valves while others perform the function of pressure isolation valves. In order to meet the 10 CFR 50 Appendix J leakage testing requirements, the HV-1 51 F01 5A(B) and the closed system outside containment are the only barriers tested in accordance with the Leakage Rate Test Program. Since these containment penetrations {X-13A and X-13B} include a containment isolation valve outside containment that is tested in accordance with 10 CFR 50 Appendix J require-ments and a closed system outside containment that meets the requirements of USNRC Standard Review Plan 6.2.4 (September 1975), paragraph 11.3.e, the containment isolation provisions for these penetrations provide an acceptable alternative to the explicit requirements of 10 CFR 50, Appendix A, GDC 55.

Containment penetrations X-13A(B) are also high/low pressure system interfaces. In order to meet the requirements to have two (2) isolation valves between the high pressure and low pressure systems, the HV-151F050A(B), HV-151F122A(B), and HV-1 51 F01 5A(B) valves are used to meet this requirement and are tested in accordance with the pressure test program.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-15b Revisioni 2

PPL Rev. 8 PCIVs B 3.6.1.3 BASES APPLICABLE The PCIVs LCO was derived from the assumptions related SAFETY ANALYSES to minimizing the loss of reactor coolant inventory, and establishing the primary containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment.

Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO.

The DBAs that result in a release of radioactive material within primary containment are a LOCA and a main steam line break (MSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) are minimized. The closure time of the main steam isolation valves (MSIVs) for a MSLB outside primary containment is a significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds since the 5 second closure time is assumed in the analysis. The safety analyses assume that the purge valves were closed at event initiation. Likewise, it is assumed that the primary containment is isolated such that release of fission:

products to the environment is controlled.

The DBA analysis -assumes that within the required isolation time leakage is terminated; except for the maximum allowable leakage rate, La.

The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary containment purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.

The primary containment purge valves may be unable to close in the environment following a LOCA. Therefore, each of the purge valves is required to remain closed during MODES 1, 2, and 3 except as permitted under Note 2 of SR 3.6.1.3.1. In this case, the single failure criterion remains applicable to the primary containment purge valve (continued)

SUSQUEHANNA - UNIT 1 TS /B 3.6-16 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 BASES APPLICABLE due to failure in the control circuit associated with each SAFETY ANALYSES valve. The primary containment purge valve design (continued) precludes a single failure from compromising the primary containment boundary as long as the system is operated in accordance with this LCO.

Both H20 2 Analyzer PCIVs may not be able to close given a single failure in the control circuitry of the valves. The single failure is caused by a "hot short" in the cables/raceway to the PCIVs that causes both PCIVs for a given penetration to remain open or to open when required to be closed. This failure is required to be considered in accordance with IEEE-279 as discussed in FSAR Section 7.3.2a. However, the single failure criterion for containment isolation of the H20 2 Analyzer penetrations is satisfied by virtue of the combination of the associated PCIVs and the closed system formed by the H 2 0 2 Analyzer piping system as discussed in the BACKGROUND section above.

The closed system boundary between PASS and the H20 2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-12361, SV-12365, SV-12366, SV-12368,- and SV-12369). The closed system is not fully qtialified to the guidance of Reference 6 in that the closed system boundary valves between the H20 2 system and PASS are nQt powered from a Class 1 E power source. However, based upon a risk determination, the use of these valves is considered .to have no risk significance. This exemption to the requirement of Reference 6 for the closed system boundary is documented in License Amendment No. 195.

PCIVs satisfy Criterion 3 of the NRC Policy Statement. (Ref. 2)

LCO PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a DBA.

The power operated, automatic isolation valves are required to have isolation times within limits and actuate on an automatic isolation signal. The valves covered by this LCO are listed in Table B 3.6.1.3-1.

(continued)

SUSQUEHANNA - UNIT 1R TS / B 3.6-17 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 BASES LCO The normally closed PCIVs are considered OPERABLE (continued) when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves and devices are those listed in Table B 3.6.1.3-1.

Purge valves with resilient seals, secondary containment bypass valves, MSIVs, and hydrostatically tested valves must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment," as Type B or C testing.

This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences-of these events are reduced due tothe pressure and temperature limitations of these MODES.

Therefore, most PCIVs are not required to be (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-17a Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES APPLICABILITY OPERABLE and the primary containment purge valves are (continued) not required to be closed in MODES 4 and 5. Certain valves, however, are required to be OPERABLE to prevent inadvertent reactor vessel draindown. These valves are those whose associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation."

(This does not include the valves that isolate the associated instrumentation.)

ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

A second Note has been added to provide clarification .that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory -

actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are-governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test retum valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions are not required even when the associated LCO is not met. Therefore, Notes 3 and 4 are added to require the proper actions be taken.

A.1 and A.2 With one or more penetration flow paths with one PCIV inoperable except for purge valve leakage not within limit, (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-18 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued) the affected penetration flow paths must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available valve to the primary containment. The Required Action must be completed within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time (8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for main steam lines). The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is allowed. The Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for the main steam lines allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown.

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration flow path(s) must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no longer capab!e of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside

.primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility.

(continued)

SUSQUEHANNA - UNIT 1 TS B 3.6-19 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued)

Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two PCIVs except for the H 20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H20 2 Analyzer Penetrations, Condition D provides the appropriate Required Actions.

Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas, and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices, once they have been verified to be in the proper position, is low.

B.1 With one or more penetration flow paths with two PCIVs inoperable except for purge valve leakage not within limit, either -

the inoperable PCIVs-must be restored to OPERABLE status or -

the affected penetration flow path must be isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de--activated automatic valve, a closed manual valve, and a blind flange. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1.

Condition B is modified by a Note indicating this Condition is only.

applicable to penetration flow paths with two PCIVs except for the H20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H20 2 Analyzer Penetrations, Condition D provides the appropriate Required Actions.

C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path (continued)

SUSQUEHANNA -. UNIT 1 TS / B 3.6-20 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued) must be isolated. The method of isolation must include thl use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action C.1 must be completed within the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The closed system must meet the requirements of Reference 6. For conditions where the PCIV and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply. For the Excess Flow Check Valves (EFCV), the Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. In the event the affected penetration flow -

path is isolated in accordance with Required Action C. 1, the affected penetration must be verified to be isolated on a periodic -

basis. This is necessary to ensure that primary containment penetrations required-to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying.

each affected penetration is isolated is appropriate because the valves are operated under administrative controls .and the probability of their misalignment is low.

Condition C is modified by a Note indicating that this Condition is only applicable to penetration flow paths with only one PCIV. For penetration flow paths with two PCIVs and the H20 2 Analyzer Penetration. Conditions A, B and D provide the appropriate Required Actions.

Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these valves, once they have been verified to be

-in the proper position, is low.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-21 -Revision 2

PPL Rev. 8 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)

With one or more H20 2 Analyzer penetrations with one or both PCIVs inoperable, the inoperable valve(s) must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action D.1 must be completed within the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is reasonable considering the unique design of the H20 2 Analyzer penetrations. The containment isolation barriers for these penetrations consist of two PCIVs and a closed system. In addition, the Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. In the event the affected ipenetration flow path is isolated in accordance with Required Action D.1 ,the affected-penetration must be verified to -

be isolated on a periodic basis. This is necessary to ensure that -

primarycontainment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

When an H20 2 Analyzer penetration PCIV is to be closed and deactivated in accordance with Condition D, this must be accomplished by pulling the fuse for the power supply, and either determinating the power cables at the solenoid valve, or jumpering of the power side of the solenoid to ground.

The OPERABILITY requirements for the closed system are discussed in Technical Requirements Manual (TRM) Bases 3.6.4.

In the event that either one or both of the PCIVs and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-22 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)

Condition D is modified by a Note indicating that this Condition is only applicable to the H 2 0 2 Analyzer penetrations.

E.1 With the secondary containment bypass leakage rate not within limit, the assumptions of the safety analysis may not be met.

Therefore, the leakage must be restored to within limit within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and de-activated automatic valve, closed manual valve, or blind flange. When a penetration is isolated, the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable considering the time required to restore the leakage by isolating the penetration and the relative importance of secondary containment bypass leakage to the overall containment function. --

F.1 In the event one or mor'e containment purge valves are not within the purge valve leakage limits, purge valve leakage must be restored to within limits. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable, considering that one containment purge valve remains closed, except as controlled by SR 3.6.1.3.1 so that a gross breach of containment does not exist.

G.1 and G.2 If any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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 3.6-22a Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES ACTIONS H.1 and H.2 (continued)

If any Required Action and associated Completion Time cannot be met, the unit must be placed in a condition in which the LCO does not apply. If applicable, action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended or valve(s) are restored to OPERABLE status. If suspending an OPDRV would result in closing the residual heat removal (RHR) shutdown cooling isolation valves, an alternative Required Action is provided to immediately initiate action to restore the valve(s) to OPERABLE status. This allows RHR to remain in service while actions are being taken to restore the valve.

SURVEILLANCE SR 3.6.1.3.1 REQUIREMENTS This SR ensures that the primary containment purge valves are closed as required or, if open, open for an allowable reason. If a-purge valve is open in violation of-this SR, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of lirrfits. The SR is also modified by Note 1, stating that primary containment purge valves are only required to be closed in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves, or the release of radioactive material will exceed limits prior to the purge valves closing. At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are allowed to be open. The SR is modified by Note 2 stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The vent and purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-23 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.1 (continued)

REQUIREMENTS limited periods of time. The 31 day Frequency is consistent with other PCIV requirements discussed in SR 3.6.1.3.2.

SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.

This SR does not require any testing or valve manipulation.

Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are in the correct position. Since verification of valve position for PCIVs outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the PCIVs are in the correct positions.

Twvo Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

SR 3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-24 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary. containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing. Two Notes have been added to this SR. The first Note allows valves and blind flanges, located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during 2, and 3 for ALARA reasons. Therefore, the probability1, of MODES misalignment of these PCIVs, once they have been-verified to be in their proper position, is low. A second Note has -

been included.to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

SR 3.6.1.3.4 The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating, experience that has demonstrated the reliability of the explosive charge continuity.

SR 3.6.1.3.5 Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-25 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 (continued)

REQUIREMENTS full closure isolation time is demonstrated by SR 3.6.1.3.7. The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed in the Final Safety Analyses Report. The isolation time and Frequency of this SR are in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.6 For primary containment purge valves with resilient seals, the Appendix J Leakage Rate Test Interval of 24 months is sufficient.

The acceptance criteria for these valves is defined in the Primary Containment Leakage Rate Testing Program, 5.5.12.

The SR is modified by a Note stating that the primary containment purge valves are only required to meet leakage rate testing requirements in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, purge valve leakage must be minimized to ensure offsite radiological release is within limits.-

At other times when the purge valves are required to be capable -

of closing (e.g., during handling of irradiated fuel), pressurization-concerns are-not present and the purge valves are not required to meet any specific leakage criteria.

SR 3.6.1.3.7 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The isolation time test ensures that the MSIV will isolate in a time period that does not, exceed the times assumed in the DBA analyses. This ensures that the calculated radiological consequences of these events remain within regulatory limits. The Frequency of this SRis in accordance I with the requirements of the Inservice Testing Program.

(continued)

SUSQUEHANNA - UNIT 1 TS /B 3.6-26 Revision 2

PPL Rev. 8 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.8 REQUIREMENTS (continued) Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.5 overlaps this SR to provide complete testing of the safety function. The 24 month Frequency was developed considering it is prudent that some of these Surveillances be performed only during a unit outage since isolation of penetrations could eliminate cooling water flow and disrupt the normal operation of some critical components. Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.1.3.9 This SR requires a demonstration that a representative sample of reactor instrumentation line excess flow check valves (EFCV) are-OPERABLE by verifying that the valve actuates to check flow on a-simuilated instrument line break. As defined in FSAR Section 6.2.4.3.5 (Reference 4), the conditions under which an EFCV will isolate, simulated instrument line break, are at flow rates which develop a differential pressure of between 3 psid and 10 psid.

This SR provides assurance that the instrumentation line EFCVs will perform its design function to check flow. No specific valve leakage limits are specified because no specific leakage limits are defined in the FSAR. The 24 month Frequency is based on the need to perform some of these Surveillances under the conditions.

that apply during a plant outage and the potential for an unplanned transient-if the Surveillance were performed with the reactor at power. The representative sample consists of an approximate equal number of EFCVs such that each EFCV is tested at least once every 10 years (nominal). The nominal 10 year interval is based on other performance-based testing programs, such as Inservice Testing (snubbers) and Option B to 10 CFR 50, Appendix J. In addition, the EFCVs in the sample are representative of the'various plant configurations, models, sizes and operating environments. This ensures that any potential common problems with a specific type or application of EFCV is detected at the earliest possible time. EFCV failures will be evaluated to determine if additional testing in that test interval is warranted to ensure overall reliability and that failures to isolate are very infrequent. Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint (Reference 7).

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-27 Revision 2

PPL Rev. 8 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.10 REQUIREMENTS (continued) The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Frequency of 24 months on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4).

SR 3.6.1.3.11 This SR ensures that the leakage rate of secondary containment bypass leakage paths is less than the specified leakage rate. This provides assurance that the assumptions in the radiological evaluations of Reference 4 are met. The secondary containment leakage pathways and Frequency are defined by the Primary Containment Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria.

A note is added-to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other MODES,-the Reactor Coolant System is not pressurized and specific primary containment-leakage limits are not required.

SR 3.6.1.3.12 The analyses in References 1 and 4 are based on the specified leakage rate. Leakage through each MSIV must be < 100 scfh for any one MSIV and < 300 scfh for total leakage through the MSIVs combined with the Main Steam Line Drain Isolation Valve, HPCI Steam Supply Isolation Valve and the RCIC Steam Supply Isolation Valve. The MSIVs can be tested at either > Pt (24.3 psig) or Pa (48.6 psig). Main Steam Line Drain Isolation, HPCI and RCIC Steam Supply Line Isolation Valves, are tested at Pa (48.6 psig). A note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3.

In the other conditions, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-28 Revision 7

PPL Rev. 8 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.13 REQUIREMENTS (continued) Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 2 are met. The acceptance criteria for the combined leakage of all hydrostatically tested lines is 3.3 gpm when tested at 1.1 Pa, (53.46 psig). The combined leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by the Primary Containment Leakage Testing Program.

As noted in Table B 3.6.1.3-1, PCIVs associated with this SR are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water level in the Suppression Chamber. These valves are tested in accordance with the IST Program. Therefore, these valves leakage is not included as containment leakage.

This SR has been modified by a Note that states that these valves are only required to meet the combined leakage rate in MODES 1, 2, and 3, since this is when the Reactor Coolant System is pressurized and primary containment is required. In some instances, the valves are required to be-capable of automatically -.

clbsing during. MODES other than MODES 1, 2, and 3. However, specificleakage limits are not applicable in these other MODES or conditions.

REFERENCES 1. FSAR, Chapter 15.

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

3. 10 CFR 50, Appendix J, Option B.

4. FSAR, Section 6.2.

5. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"

March 1988.

6. Standard Review Plan 6.2.4, Rev. 1, September 1975

7. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000.

SUSQUEHANNA - UNIT 1 TS / 8 3.6-29 Revision 2

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 1 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Containment 1-57-193 (d) ILRT Manual N/A A.tmospheric 1-57-194 (d) ILRT Manual N/A Control HV-1 5703 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15704 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15705 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15711 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15713 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15714 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15721 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15722 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15723 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15724 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15725 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15766 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)

HV-1 5768 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)

SV-1 57100 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57100 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst -

SV-157101 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157101 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57102 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157102 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57103 A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157103 B Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157104 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57105 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157106 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-1 57107 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-15734 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5734 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15736 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15736 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d

______SV-15737 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SUSQUEHANNA - UNIT 1 TS / B 3.6-30 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 2 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Containment SV-15738 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Atmospheric SV-1 5740 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d Control SV-1 5740 B (e) Containment Atmosphere Sample, Automatic Valve 2.b, 2.d (continued) SV-1 5742 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15742 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15750 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5750 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15752 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15752 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5767 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SV-1 5774 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15774 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15776 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5776 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5780 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15780 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5782 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-1 5782 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15789 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Containment 1-26-072 (d) Containment-Instrurment Gas Manual Check N/A Instrument Gas 1-26-074 (d) Containment Instrument Gas Manual Check N/A 1-26-152 (d) Containment Instrument Gas Manual Check N/A 1-26-154 (d) Containment Instrument Gas Manual Check N/A 1-26-164 (d) Containment Instrument Gas Manual Check N/A HV-12603 Containment Instrument Gas Automatic Valve 2.c, 2.d (20)

SV-12605 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-1265.1 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-1 2654 A Containment Instrument Gas Power Operated N/A SV-12654 B Containment Instrument Gas Power Operated N/A SV-12661 Containment Instrument Gas Automatic Valve 2.b, 2.d SV-12671 Containment Instrument Gas Automatic Valve 2.b, 2.d Core Spray HV-152F001 A (b)(c) CS Suction Valve Power Operated N/A HV-152F001 B (b)(c) CS Suction Valve Power Operated N/A HV-152F005 A CS Injection Power Operated N/A HV-152F005 B CS Injection Valve Power Operated N/A HV-152F006 A CS Injection Valve Air Operated Check N/A Valve HV-152F006 B CS Injection Valve Air Operated Check N/A Valve -

HV-152F01 5 A (b)(c) CS Test Valve Automatic Valve 2.c, 2.d (80)

HV-1 52F01 5 B (b)(c) CS Test Valve Automatic Valve .2.c, 2.d (80)

SUSQUEHANNA - UNIT 1 TS / B 3.6-31 Revision 3

PPL Rev. 8 PCIVs B3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 3 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Core Spray HV-152FO31 A (b)(c) CS Minimum Recirculation Flow Power Operated N/A (continued) HV-152F031 B (b)(c) CS Minimum Recirculation Flow Power Operated N/A HV-152F037A CS Injection Power Operated N/A (Air)

HV-152F037 B CS Injection Power Operated N/A (Air)

)(V-1 52F01 8 A Core Spray Excess Flow Check N/A Valve K(V-152F018 B Core Spray Excess Flow Check N/A Valve HPCI 1-55-038 (d) HPCI Injection Valve Manual N/A 155F046 (b)(c)(d) HPCI Minimum Flow Check Valve Manual Check N/A 155F049 (a)(d) HPCl Turbine Exhaust Valve Manual Check N/A HV-155F002 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (50)

HV-155F003 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f,-

3.g (50)

HV-155F006 HPCI Injection Valve Power Operated N/A.

HV-155F012 (b)(c) HPCI.Minimum Flow Valve Power Operated N/A HV-155F042 (b)(c) HPCI Suction Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (90)

HV-155F066 (a) HPCI Turbine Exhaust Valve Power Operated N/A HV-155F075 HPCI Vacuum Breaker Isolation Automatic Valve 3.b, 3.d (15)

Valve HV-155F079 HPCI Vacuum Breaker Isolation Automatic Valve 3.b, 3.d (15)

Valve HV-155F100 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (6)

XV-155F024 A HPCI Valve Excess Flow Check N/A Valve XV-155F024 B HPCI Valve Excess Flow Check N/A Valve XV-155FO24 C HPCI Valve Excess Flow Check N/A Valve XV-155F024 D HPCI Valve Excess Flow Check N/A Valve Liquid Radwaste HV-1 6108 Al Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

Collection HV-1 6108 A2 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

HV-16116 Al Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

HV-1 6116 A2 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

Demin Water 1-41-017 (d) Demineralized Water Manual N/A 1-41 -018 (d) Demineralized Water Manual N/A Nuclear Boiler 141F010 A (d) Feedwater Isolation Valve Manual Check N/A 141 F010 B (d) Feedwater Isolation Valve Manual Check N/A SUSQUEHANNA - UNIT 1 TS / B 3.6-32 Revision 0

PPL Rev. 8 PCI Vs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 4 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Nuclear Boiler 141 F039 A (d) Feedwater Isolation Valve Manual Check N/A

,continued) 141 F039 B (d) Feedwater Isolation Valve Manual Check N/A 141818 A (d) Feedwater Isolation Valve Manual Check N/A 141818 B (d) Feedwater Isolation Valve Manual Check N/A HV-141F016 MSL Drain Isolation Valve Automatic Valve 1.a, 1.b, 1.c, 1id, i.e (10)

HV-1 41 F01 9 MSL Drain Isolation Valve Automatic Valve 1.a, 1.b, (15) 1.c, 1.d, 1.e HV-141F022 A MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, i.e (5)

HV-141 F022 B MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141 F022 C MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141 F022 D MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141 F028 A MSIV . Automatic Valve 1.a, 1.b, 1.c, i.d, i.e (5),

HV-141 F028 B MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e-(5) "

HV-141F028 C MSIV Automatic Valve 1.a, l.b, 1.c, i.d, i.e (5)

HV-141 F028 D - MSIV Automatic Valve i.a, 1.b, 1.c, 1.d, 1.e (5)

HV-1 41 F032 A Feedwater Isolation Valve Power Operated N/A Check HV-141 F032 B Feedwater Isolation Valve Power Operated N/A Check XV-141 F009 Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 FF070 A Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F070 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F070 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-1 41 F070 D Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F071 A Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F071 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F071 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F071 D Nuclear Boiler EFCV Excess Flow Check N/A Valve SUSQUEHANNA - UNIT 1 TS / B 3.6-33 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 5 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Nuclear Boiler XV-141 F072 A Nuclear Boiler EFCV Excess Flow Check N/A (continued) Valve XV-141 F072 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F072 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F072 D Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-1 41 F073 A Nuclear Boiler EF.CV Excess Flow Check N/A Valve XV-141 F073 B Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F073 C Nuclear Boiler EFCV Excess Flow Check N/A Valve XV-141 F073 D Nuclear Boiler EFCV Excess Flow Check N/A Valve Nuclear Boiler XV-14201 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Vessel Valve Instrumentation XV-14202 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F041 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F043 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve, XV-142F043 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F045 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F045 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F047 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F047 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 C Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F051 D Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F053 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F053 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve S.

SUSQUEHANNA - UNIT 1 TS / B 3.6-34 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 6 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Nuclear Boiler (V-142F053 C Nuclear Boiler Vessel Instrument Excess Flow Check N/A Vessel Valve Instrumentation XV-142F053 D Nuclear Boiler Vessel Instrument Excess Flow Check N/A (continued) Valve KV-142FO55 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F057 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F059 A Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve KV-142F059 B Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F059 C Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 D Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 E Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F059 F Nuclear Boiler Vessel Instrument -Excess Flow Check N/A Valve XV-1 42F059 G Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 H Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-1 42F059 L Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 M Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 N Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 P Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 R Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 S Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve Nuclear Boiler Vessel Instrument Excess Flow Check N/AI XV-142F059 T Valve XV-1 42F059 U Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F061 Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve RBCCW

HV-1 1313 RBCCW Automatic Valve 2.c, 2.d (30)

HV-11314 RBCCW Automatic Valve 2.c, 2.d (30)

HV-11345 RBCCW Automatic Valve 2.c, 2.d (30)

HV-1 1346 RBCCW Automatic Valve 2.c, 2.d (30)

SUSQUEHANNA - UNIT 1 TS / B 3.'6-35 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 7 of 11)

Isolation Signal Plant System Valve Number Valve Description Type of Valve LCO 3.3.6.1 Function No.

(Maximum Isolation Time (Seconds))

RCIC 1-49-020 (d) RCIC INJECTION Manual N/A 149F021 (b)(c)(d) RCIC Minimum Recirculation Flow Manual Check N/A 149F028 (a)(d) RCIC Vacuum Pump Discharge Manual Check N/A 149F040 (a)(d) RCIC Turbine Exhaust Manual Check N/A FV-149F019 (b)(c) RCIC Minimum Recirculation Flow Power Operated N/A HV-149F007 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-149F008 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-149F013 RCIC Injection Power Operated N/A HV-149F031 (b)(c) RCIC Suction Power Operated N/A HV-149F059 (a) RCIC Turbine Exhaust Power Operated N/A HV-149F060 (a) RCIC Vacuum Pump Discharge Power Operated N/A HV-149F062 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-149F084 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-149F088 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (12)

XV-149F044 A RCIC Excess Flow Check N/A Valve XV-149F044 B RCIC- Excess Flow Check N/A Valve XV-149F044 C RCIC Excess Flow Check N/A Valve XV-149F044 D RCIC Excess Flow Check N/A Valve RB Chilled HV-18781 Al RB Chilled Water Automatic Valve 2.c, 2.d (40)

Water System HV-18781 A2 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-18781 B1 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-18781 B2 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-1 8782 Al RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-18782 A2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-18782 B1 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-18782 B2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-18791 Al RB Chilled Water Automatic Valve 2.b, 2.d (15)

HV-18791 A2 RB Chilled Water Automatic Valve 2.b, 2.d (15)

HV-18791 B1 RB Chilled Water Automatic Valve 2.b, 2.d (15)

HV-18791 B2 RB Chilled Water Automatic Valve 2.b, 2.d (15)

HV-18792 Al RB Chilled Water Automatic Valve 2.b, 2.d (8)

HV-18792 A2 RB Chilled Water Automatic Valve 2.b, 2.d (8)

HV-18792 B1 RB Chilled Water Automatic Valve 2.b, 2.d (8)

HV-18792 B2 RB Chilled Water Automatic Valve 2.b, 2.d (8)

Reactor 143F013 A (d) Recirculation Pump Seal Water Manual Check N/A Recirculation 143F013 B (d) Recirculation Pump Seal Water Manual Check N/A SUSQUEHANNA - UNIT 1 TS / B 3.6-36 Revision 1

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 8 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation

_ _Time (Seconds))

Reactor XV-143F003 A Reactor Recirculation Excess Flow Check N/A Recirculation Valve (continued) XV-143F003 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F004 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F004 B Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F009 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F009 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F009 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F009 D Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F01 0 A Reactor Recirculation Excess Flow Check N/A Valve XV-143F010 B Reactor Recirculation - Excess Flow Check N/A Valve XV-143F010 C Reactor Recirculation. Excess Flow Check N/A Valve XV-143F01 0 D -_ Reactor Recirculation Excess Flow Check N/A Valve XV-143F01 I A Reactor Recirculation Excess Flow Check N/A Valve XV-143F01 1 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F01 1 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F011 D Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F01 2 A Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F01 2 B Reactor Recirculation Excess Flow Check N/A Valve XV-143F012 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F012 D Reactor Recirculation Excess Flow Check N/A Valve XV-143F017 A Recirculation Pump Seal Water Excess Flow Check N/A Valve XV-143F017 B Recirculation Pump Seal Water Excess Flow Check N/A I Valve XV-143F040 A Reactor Recirculation Excess Flow Check N/A Valve SUSQUEHANNA - UNIT 1 TS / B 3.6-37 Revision 0

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 9 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Reactor XV-1 43F040 B Reactor Recirculation Excess Flow Check N/A Recirculation Valve (continued) XV-143F040 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F040 D Reactor Recirculation Excess Flow Check N/A Valve XV-143F057 A Reactor Recirculation Excess Flow Check N/A Valve XV-1 43F057 B Reactor Recirculation Excess Flow Check N/A Valve HV-143F019 Reactor Coolant Sample Automatic Valve 2.b (9)

HV-143F020 Reactor Coolant Sample Automatic Valve 2.b (2)

Residual'Heat HV-151 F004 A (b)(c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-151 F004 B (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-151 F004 C (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-151 F004 D (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-1 51_F_07 A (b)(c) RHR-Minimum Recirculation Flow Power Operated N/A HV-151 F007 A (b)(c) RHR-Minimum Recirculation Flow Power Operated N/A HV-151F008 RHR - Shutdown Cooling Suction Putomatic Valve 6.a, 6.b, 6.c (52)

HV-151 F009 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)

HV-151 F011 A (b)(d)_. RHR-Suppression Pool- Manual N/A Cooling/Spray HV-151 F011 B (b)(d) RHR-Suppression Pool Manual N/A Cooling/Spray HV-151 F015 A (f) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection HV-151F015 B (f) RHR - Shutdown Cooling Power Operated - N/A Return/LPCI Injection HV-151 F016 A (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)

HV-151 F016 B (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)

HV-151 F022 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (30)

HV-151 F023 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (20)

HV-151 F028 A (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-151 F028 B (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-151 F050 A (g) RHR - Shutdown Cooling Air Operated Check N/A Return/LPCI Injection Valve Valve HV-151F050 B (g) RHR - Shutdown Cooling Air Operated Check N/A Return/LPCI Injection Valve Valve HV-151 F103 A (b) RHR Heat Exchanger Vent Power Operated N/A HV-151 F103 B (b) RHR Heat Exchanger Vent Power Operated N/A SUSQUEHANNA - UNIT 1 TS / B 3.6-38 Revision 3

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 10 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Valve Number Valve Description Type of Valve (Max6mum stion Plant System (Maximum Isolation Time (Seconds))

Residual Heat HV-151 F122 A (g) RHR - Shutdown Cooling Power Operated N/A Removal Return/LPCl Injection Valve (Air)

(continued) HV-151 F122 B (g) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection Valve (Air)

PiSV-1 5106 A (b)(d) RHR - Relief Valve Discharge Relief Valve N/A PSV-1 5106 B (b)(d) RHR - Relief Valve Discharge Relief Valve N/A PSV-1 51 F126 (d) RHR - Shutdown Cooling Suction Relief Valve N/A XV-15109 A RHR Excess Flow Check N/A Valve XV-15109 B RHR Excess Flow Check N/A Valve XV-15109 C RHR Excess Flow Check N/A Valve XV-15109 D RHR Excess Flow Check N/A Valve RWCU HV-144F001 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.f, 5.g-(30)

HV-144FO04 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.e, 5.f, 5.g (30)

XV-14411 A - RWCU - Excess Flow Check N/A Valve XV-14411 B RWCU Excess Flow Check N/A Valve XV-14411 C RWCU Excess Flow Check N/A Valve XV-14411 D RWCU Excess Flow Check N/A Valve XV-144F046 RWCU Excess Flow Check N/A Valve HV-1 4182 A RWCU Return Isolation Valve Power Operated N/A HV-14182 B RWCU Return Isolation Valve Power Operated N/A SLCS 148F007 (a)(d) SLCS Manual Check N/A HV-148F006 (a) SLCS Power Operated N/A Check Valve TIP System C51-J004 A (Shear TIP Shear Valves Squib Valves N/A Valve)

C51-J004 B (Shear TIP Shear Valves Squib Valves N/A Valve)

C51-J004 C (Shear TIP Shear Valves Squib Valves N/A Valve)

C51-J004 D (Shear TIP Shear Valves Squib Valves N/A Valve)

C51-J004 E (Shear TIP Shear Valves Squib Valves N/A Valve)

SUSQUEHANNA - UNIT 1 TS /B 3.6-39 Revision 2

PPL Rev. 8 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 11 of 11)

Isolation Signal I LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximumstion (Maximum Isolation Time (Seconds))

TIP System C51-J004 A (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

(continued) Valve)

C51-J004 B (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve)

C51-J004 C (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve)

C51-J004 D (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve)

C51-J004 E (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve) _ _II (a) Isolation barrier remains water filled or a water seal remains in the line post-LOCA, isolation valve is tested with water. Isolation valve leakage is not included in 0.60 La total Type B and C tests.

(b) Redundant isolation boundary for this valve is provided by the closed system whose integrity is verified by the Leakage Rate Test Program. This footnote does not apply to valve 155F046 (HPCI) when the associated PCIV, HV1 55F01 2 is closed and deactivated. Similarly, this footnote does not apply to valve 149F021 (RCIC) when it's --

associated PCIV, FV149F019 is closed and deactivated.

(c) Containment Isolation Valves are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water-level in the Suppression Chamber. Refer to the IST Program.

(d) LCO 3.3.3.1,."PAM Instrumentation," Table 3.3.3.1-1, Function 6, does not apply since these are relief valves, check valves, manual valves or deactivated and closed. -

(e) The containment isolation barriers for the penetration associated with this valve consists of two PCIVs and a closed system. The closed system provides a redundant isolation boundary for both PCIVs, and its integrity is required to be verified by the Leakage Rate Test Program.

(f) Redundant isolation boundary for this valve is provided by the closed system whose integrity is verified by the Leakage Rate Test Program.

(g) These valves are not required to be 10 CFR 50, Appendix J tested since the HV-151 F01 5A(B) valves and a closed system form the 10 CFR 50, Appendix J boundary. These valves form a high/low pressure interface and are pressure tested in accordance with the pressure test program.

SUSQUEHANNA - UNIT 1 TS / B 3.6-40 Revision 6

PPL Rev. 1 Containment Pressure B 3.6.1.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.4 Containment Pressure BASES BACKGROUND The containment pressure is limited during normal operations to preserve the initial conditions assumed in the accident analysis for a Design Basis Accident (DBA) or loss of coolant accident (LOCA).

APPLICABLE Primary containment performance is evaluated for the entire spectrum of SAFETY break sizes for postulated LOCAs (Ref. 1). Among the inputs to the DBA ANALYSES is the initial primary containment internal pressure (Ref. 1). Analyses assume an initial containment pressure of -1.0 to 2.0 psig. This limitation ensures that the safety analysis remains valid by maintaining the expected initial conditions and ensures that the peak LOCA containment internal pressure does not exceed the maximum allowable.

The maximum calculated containment pressure occurs during the reactor -

blowdown phase of the DBA,_which assumes an instantaneous recirculation line break. The calculated peak containment pressure for this limiting event is 48.6 psig (Ref. 1).

The minimum containment pressure occurs during an inadvertent spray actuation. The calculated minimum drywell pressure for this limiting event is -4.72 psig. (Ref. 1)

Containment pressure satisfies Criterion 2 of the NRC Policy Statement.

(Ref. 2)

LCO In the event of a DBA, with an initial containment pressure -1.0 to 2.0 psig, the resultant peak containment accident pressure will be maintained below the containment design pressure. The containment pressure is defined to include both the drywell pressure and the suppression chamber pressure. (Ref. 1)

(continued)

SUSQUEHANNA - UNIT 1 B 3.6-41 Revision 1

PPL Rev. 1 Containment Pressure B 3.6.1.4 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining containment pressure within limits is not required in MODE 4 or 5.

ACTIONS A.1 With containment pressure not within the limit of the LCO, containment pressure must be restored within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

B.1 and B.2 If containment pressure cannot be restored to within limit within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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.

SURVEILLANCE REQUIREMENTS SR 3.6.1.4.1 Verifying that containment pressure is within limit ensures that unit operation remains within the limit assumed. in the primary containment analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed, based on operating experience related to trending of containment pressure variations during the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition.

(continued)

SUSQUEHANNA - UNIT 1 B 3.6-42 Revision 0

PPL Rev. 1 Containment Pressure B 3.6.1.4 BASES (continued )

REFERENCES 1. FSAR, Section 6.2.

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

SUSQUEHANNA - UNIT 1 B 3.6-43 Revision 0

PPL Rev. 2 Suppression Pool Average Temperature B 3.6.2.1 B 3.6 CONTAINMENT SYSTEMS B 3.612.1 Suppression Pool Average Temperature BASES BACKGROUND The primary containment utilizes a Mark II over/under pressure suppression configuration consisting of a drywell and suppression chamber. The drywell is a steel-lined concrete truncated cone located above the steel-lined concrete cylindrical pressure suppression chamber containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay heat and sensible energy released during a reactor blowdown from safety/relief valve discharges or from Design Basis Accidents (DBAs). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment that ensures that the peak containment pressure is maintained below the maximum allowable pressure for containment (53 psig) (Ref. 1). The suppression pool must also condense steam from steam exhaustlines in the turbine driven systems (i.e., the High Pressure Coolant Injection System and Reactor Core Isolation Cooling System). Suppression pool average temperature (along with LCO 3.6.2.2, "Suppression Pool Water Level") is a key indicationf-of the capacity of the'suppression pool to fulfill these requirements.

The technical concerns that lead to the development of suppression Pool average temperature limits are as follows:

a. Complete steam condensation;

b. Primary containment peak pressure and temperature;

c. Condensation oscillation loads; and

d. Chugging loads.

APPLICABLE The postulated DBA against which the primary containment performance SAFETY is evaluated is the entire spectrum of postulated pipe breaks within the ANALYSES primary containment. Inputs to the safety analyses include initial suppression pool water volume and suppression pool temperature (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-53 Revision 0

PPL Rev. 2 Suppression Pool Average Temperature B 3.6.2.1 BASES APPLICABLE (Reference 1 for LOCAs and Reference 2 for the pool temperature SAFETY analyses required by Reference 3). An initial pool temperature of 90°F is ANALYSES assumed for the Reference 1 and Reference 2 analyses. Reactor (continued) shutdown at a pool temperature of 1 10°F and vessel depressurization at a pool temperature of 120OF are assumed for the Reference 2 analyses.

The limit of 105 0 F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during unit testing.

Suppression pool average temperature satisfies Criteria 2 and 3 of the NRC Policy Statement. (Ref. 4) -

LCO A limitation on the suppression pool average temperature is required to provide assurance that the containment conditions assumed for the safety analyses are met. This limitation subsequently ensures that peak primary

-containment pressures and temperatures do not exceed maximum allowable values during a postulated DBA or any transient resulting in heatup of the suppression pool. The LCO- requirements are:

a. Average temperature <-900F when any OPERABLE intermediate range monitor (IRM) channel is > 25/40 divisions of full scale on Range 7 with IRMs fully inserted and no testing that adds heat to the suppression pool is being performed. This requirement ensures that licensing bases initial conditions are met.

b. Average temperature < 105 0 F when any OPERABLE IRM channel is

> 25/40 divisions of full scale on Range 7 with IRMs fully inserted and testing that adds heat to the suppression pool is being performed.

This required value ensures that the unit has testing flexibility, and was selected to provide margin below the 1 10°F limit at which reactor shutdown is required. When testing ends, temperature must be restored to _<90°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months according to Required Action A.2.

Therefore, the time period that the temperature is > 90°F is short enough not to cause a significant increase in unit risk.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-54 Revision 0

PPL Rev. 2 Suppression Pool Average Temperature B 3.6.2.1 BASES LCO

c. Average temperature < 110 0 F when all OPERABLE IRM channels are (continued)

< 25/40 divisions of full scale on Range 7 with IRMs fully inserted. This requirement ensures that the unit will be shut down at > 1 10°F. The pool is designed to absorb decay heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down.

Note that 25/40 divisions of full scale on IRM Range 7 is a convenient measure of when the reactor is producing power essentially equivalent to 1% RTP. At this power level, heat input is approximately equal to normal system heat losses.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause significant heatup of the

-suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining suppression pool average tempeirature within limits is not required in MODE 4 or 5.

ACTIONS A.1 and A.2 With the suppression pool average temperature above the specified limit when not performing testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the conditions assumed for the References 1 and 2 analyses. However, primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above those assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is adequate to allow the suppression pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is > 90 0 F, increased monitoring of the suppression pool temperature is required to ensure that it remains < 1 100 F. The once per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing that adds heat to the suppression pool is being performed.

Furthermore, the once per hour Completion Time is considered (continued)

SUSQUEHANNA - UNIT B 3.6-55 TS / B Revision 0

PPL Rev. 2 Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS A.1 and A.2 (continued) adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

B. 1 If the suppression pool average temperature cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the power must be reduced to < 25/40 divisions of full scale on Range 7 for all OPERABLE IRMs within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to reduce power from full power conditions in an orderly manner and without challenging plant

- systems. -

C.1 Suppression pool average temperature is allowed to be > 90°F when any OPERABLE IRM channel is > 25/40 divisions of full scale on Range 7, and when testing that adds heat to the suppression pool is being performed. However, if temperature is > 105 0 F, all testing must be immediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable. -

D.1, D.2 and D.3 Suppression pool average temperature > 1 10°F requires that the reactor be shut down immediately. .This is accomplished by placing the reactor mode switch in the shutdown position. Further cooldown to Mode 4 is required at normal cooldown rates (provided pool temperature remains _ 120°F). Additionally, when suppression pool temperature is > 11 0°F, increased monitoring of pool temperature is required to ensure that it remains _ 1201F. The once per 30 minute Completion Time is adequate, based on operating experience. Given the high suppression pool average temperature in this (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-56 Revision 0

PPL Rev. 2 Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS D.1, D02 and D.3 (continued)

Condition, the monitoring Frequency is increased to twice that of Condition A. Furthermore, the 30 minute Completion Time is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

E. 1 If suppression pool average temperature cannot be maintained at

< 120 0 F, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the reactor pressure must be reduced to

< 200 psig within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and the plant must be brought to at least MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months from the time the plant entered Condition D. 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 addition of heat to the suppression pool with suppression pool temperature > 120OF could result in exceeding the design basis maximum allowable-values for primary containment temperature or pressure.

Furthermore, if a blowdown were to occur when the temperature was

> 120 0 F, the maximum allowable bulk and local temperatures could be exceeded very quickly.

SURVEILLANCE SR 3.6.2.1.1 REQUIREMENTS Three averages of suppression pool temperature are calculated; SPOTMOS average temperature, bottom average temperature, and bulk pool temperature. SPOTMOS average temperature is a simple average of the eight upper-level RTDs. This average is valid if at least six of the eight upper-level RTDs are OPERABLE with at least one sensor in each quadrant. Bottom average temperature is a simple average of the four bottom-level RTDs. This average is valid if at least three of the four bottom-level RTDs are OPERABLE. Bulk pool temperature is a weighted average of the SPOTMOS average temperature and the bottom average temperature. Bulk pool temperature is valid when both (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.6-57 Revision 1

PPL Rev. 2 Suppression Pool Average Temperature B 3.6.2.1 BASES SURVEILLANCE SR 3.6.2.1.1 (continued)

REQUIREMENTS SPOTMOS average temperature and bottom average temperature are valid. Additionally, the SPOTMOS electronic units send bulk pool temperature to PICSY for display.

For the purpose of monitoring Suppression Pool Average Temperature, both SPOTMOS average temperature and bulk pool temperature, displayed by the SPOTMOS electronic units or PICSY, are acceptable.

However, bulk pool temperature should be the primary indicator, when available, since it provides a more accurate representation of Suppression Pool Average Temperature and reduces the frequency of suppression pool cooling operation. The bottom sensors are not qualified for service following a LOCA or seismic event, and as a result, neither the bottom sensors nor the bulk pool temperature should be used following a LOCA or seismic event. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months frequency has been shown to be

-acceptable basedon operating experience. However, when heat is being added to the suppression pool by testing, more frequent monitoring of suppression pool temperature is necessary. The five minute frequency during testing is justified by the rates at which testing will heat up the suppression pool, hasbeen shown to be acceptable based on operating experience,- and provides assurance that allowable pool temperatures are not exceeded. The frequencies are further justified in view of other indications available in thecontrol room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

REFERENCES 1. FSAR, Section 6.2.

2. FSAR, Section 15.2.

3. NUREG-0783.

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

SUSQUEHANNA - UNIT 1 TS / B 3.6-58 Revision 2

PPL Rev. 2 Main Turbine Bypass System B 3.7.6 B 3.7 PLANT SYSTEMS B 3.7.6 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the condenser without going through the turbine.

The full bypass capacity of the system is approximately 22% of the Nuclear Steam Supply System rated steam flow. Sudden load reductions within the capacity of the steam bypass can be accommodated without reactor scram. The Main Turbine Bypass System consists of five valves connected to the main steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these five valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Turbine Electro Hydraulic Control System, as discussed in the FSAR, Section 7.7.1.5 (Ref. 1). The bypass valves are normally closed, and the pressure

-regulator controls-the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam flows fromthe bypass chest, through connecting piping, to the pressure breakdown assemblies, where a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

APPLICABLE The Main Turbine Bypass System has two modes of operation. A fast SAFETY opening mode is assumed to function during the turbine generator load ANALYSES rejection, turbine trip, and feedwater controller failure transients as discussed in FSAR Sections 15.2.2, 15.2.3, and 15.1.2 (Refs. 2, 3, and 4). A pressure regulation mode is assumed to function during the control rod withdrawal error and recirculation flow controller failure transients as discussed in FSAR Sections 15.4.2 and 15.4.5 (Refs. 5 and 6). Both modes of operation are assumed to function for all bypass valves assumed in the applicable safety analyses. Opening the bypass valves during the above transients mitigates the increase in reactor vessel pressure, which affects both MCPR and LHGR during the event. An inoperable Main Turbine Bypass System may result in a MCPR and / or LHGR penalty.

The Main Turbine Bypass System satisfies Criterion 3 of the NRC Policy Statement. (Ref. 7)

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.7-27 Revision 5

PPL Rev. 2 Main Turbine Bypass System B 3.7.6 BASES (continued)

LCO The Main Turbine Bypass System fast opening and pressure regulation modes are required to be OPERABLE to limit the pressure increase in the main steam lines and reactor pressure vessel during transients that cause a pressurization so that the Safety Limit MCPR and LHGR are not exceeded.

With the Main Turbine Bypass System inoperable, modifications to the MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)")

and LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)")

may be applied to allow this LCO to be met. The MCPR and LHGR limits for the inoperable Main Turbine Bypass System are specified in the COLR. An OPERABLE Main Turbine Bypass System requires the bypass valves to open in response to increasing main steam line pressure. Licensing analyses credit an OPERABLE Main Turbine Bypass System as having both the bypass valve fast opening mode and pressure regulation mode. The fast opening mode is required for transients initiated by a turbine control valve or turbine stop valve closure. The pressure regulation mode is required for transients where the power increase exceeds the capability of the turbine control valves.

The cycle specific safety analyses assume a certain number of OPERABLE main turbine bypass valves as an input (i.e., one through five). Therefore, the Main Turbine Bypass System is considered bOPERABLE when the number of OPERABLE bypass valves is greater than or equal to the number assumed in the safety analyses.- The number of bypass valves assumed in the safety analyses is specified in the COLR. This response is within the assumptions of the applicable analysis (Refs. 2 - 6).

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at

! 23% RTP to ensure that the fuel cladding integrity Safety Limit is not violated during all applicable transients. As discussed in the Bases for LCOs 3.2.2 and 3.2.3, sufficient margin to these limits exists at < 23% RTP.

Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1, If the Main Turbine Bypass System is inoperable and the MCPR and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not applied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the Main Turbine Bypass System to OPERABLE status or adjust the MCPR and LHGR limits accordingly. The 2-hour Completion Time is reasonable, based on the time to complete the Required Action and (continued)

SUSQUEHANNA - UNIT 1 TS / B 3.7-28 Revision 5

PPL Rev. 2 Main Turbine Bypass System B 3.7.6 BASES ACTIONS A.1 (continued) the low probability of an event occurring during this period requiring the Main Turbine Bypass System.

B.1 If the Main Turbine Bypass System cannot be restored to OPERABLE status or the MCPR and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to

< 23% RTP. As discussed in the Applicability section, operation at

-<23% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the applicable transients.

The 4-hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS Cycling each requiredlmain turbine bypass valve through one complete cycle of full travel (including the fast opening feature) demonstrates that the valves are mechanically OPERABLE and will function when required.

The 31-day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions. Operating experience has shown that these components usually pass the SR when performed at the 31-day Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.6.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required system initiation signals (simulate automatic actuation), the valves will actuate to their required position. The 24-month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown the 24-month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.7-29 Revision 5

PPL Rev. 2 Main Turbine Bypass System B 3.7.6 BASES SURVEILLANCE SR 3.7.6.3 REQUIREMENTS (continued) This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analysis. The response time limits are specified in unit specific documentation. The 24-month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown the 24-month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Section 7.7.1.5.

2. FSAR, Section 15.2.2.

3* FSAR, Section 15.2.3' -I

4. FSAR, Section 15:11.2

5. FSAR,-Section 15.4.2

6. FSAR, Section 15.4.5

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

SUSQUEHANNA - UNIT 1 TS / B 3.7-30 Revision 2

PPL Rev. 0 Main Turbine Pressure Regulation System B 3.7.8 B 3.7 PLANT SYSTEMS B 3.7.8 Main Turbine Pressure Regulation System

.BASES BACKGROUND The Main Turbine Pressure Regulation System is designed to control main steam pressure. The Main Turbine Pressure Regulation System contains two pressure regulators which are provided to maintain primary system pressure control. They independently sense pressure just upstream of the main turbine stop valves and compare it to two separate setpoints to create proportional error signals that produce each regulator's output. The outputs of both regulators feed into a high value gate. The regulator with the highest output controls the main turbine control valves. The lowest pressure setpoint gives the largest pressure error and thereby the largest regulator output. The backup regulator is nominally set 3 psi higher giving a slightly smaller error and a slightly smaller effective output of the controller. The main turbine pressure regulation function of the Turbine Electro Hydraulic Control System is discussed in the FSAR, Sections 7.7.1.5 (Ref. 1) and 15.2.1 (Ref. 2).

APPLICABLE A downscale failure of the primary or controlling pressure regulator as SAFETY discussed in FSAR, Section .15.2.1 (Ref. 2) will cause the turbine control ANALYSES- valves to begin to close momentarily. The pressure will increase, because the reactor is still generating the initial steam flow. The backup regulator will reposition the valves and re-establish steady-state operation above the initial pressure equal to the setpoint difference which is nominally 3 psi. Provided that the backup regulator takes control, the disturbance is mild, similar to a pressure setpoint change and no significant reduction in fuel thermal margins occur.

Failure of the backup pressure regulator is also discussed in FSAR, Section 15.2.1. If the backup pressure regulator fails downscale or is out of service when the primary regulator fails downscale, the turbine control valves (TCVs) will close in the servo or normal operating mode. Since the TCV closure is not a fast closure, there is no loss of EHC pressure to provide an anticipatory scram. The reactor pressure will increase to the point that a high neutron flux or a high reactor pressure scram is initiated to shut down the reactor. The increase in flux and pressure affects both MCPR and LHGR duririg the event. An inoperable Main Turbine Pressure Regulation System may result in a MCPR and/or LHGR penalty.

The Main Turbine Pressure Regulation System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.7-34 Revision 0

PPL Rev. 0 Main Turbine Pressure Regulation System B 3.7.8 BASES (continued)

LCO Both Main Turbine Pressure Regulators are required to be OPERABLE to limit the pressure increase in the main steam lines and reactor pressure vessel during a postulated failure of the controlling pressure regulator so that the Safety Limit MCPR and LHGR are not exceeded. With one Main Turbine.

Pressure Regulator inoperable, modifications to the MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)") may be applied to allow this LCO to be met. The MCPR and LHGR limits for the inoperable Main Turbine Pressure Regulation System are specified in the COLR. An OPERABLE Main Turbine Pressure Regulation System requires that both Main Turbine Pressure Regulators be available so that if the controlling regulator fails downscale (i.e., in the direction of reduced control valve demand) a backup regulator is available to, regain pressure control before fuel thermal margins can be significantly affected. An OPERABLE Main Turbine Pressure Regulation System causes the event where the controlling regulator fails downscale to be a non-limiting event from a thermal margin standpoint.

APPLICABILITY The Main Turbine Pressure Regulation System is required to be OPERABLE.

at > 23% RTP-to ensure that the fuel cladding integrity Safety Limit is not violated during all applicable transients. As discussed in the Bases for LCOs 3.2.2 and 3.2.3, sufficient margin to these limits exists at < 23% RTP.

Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1 If one Main Turbine Pressure Regulator is inoperable and the MCPR and LHGR limits for an inoperable Main Turbine Pressure Regulation System, as specified in the COLR, are not applied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the Main Turbine Pressure Regulation System to OPERABLE status or adjust the MCPR and LHGR to be within the applicable limits accordingly. The 2-hour Completion Time is reasonable, based on the time to complete the Required Action and the low probability of a downscale failure of a Main Turbine Pressure Regulator.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.7-35 Revision 0

PPL Rev. 0 Main Turbine Pressure Regulation System B 3.7.8 BASES ACTIONS B._1 If the Main Turbine Pressure Regulation System cannot be restored to OPERABLE status or the MCPR and LHGR limits for an inoperable Main Turbine Pressure Regulation System are not applied, THERMAL POWER must be reduced to < 23% RTP. As discussed in the Applicability section, operation at < 23% RTP results in sufficient margin to the required limits, and the Main Turbine Pressure Regulation System is not required to protect fuel integrity during the applicable transients.

The 4-hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.8.1 REQUIREMENTS Verifying that both Main Turbine Pressure Regulators can be

-independently used to control pressure demonstrates that the Main Turbine Pressure Regulation System is OPERABLE and will function as required. The 92-day Frequency is based on engineering.judgment, -is consistent with the procedural controls governing pressure regulator operation, and ensures proper control of main turbine pressure.

Operating-experience has shown that these components usually pass the SR when performed at the 92-day Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.8.2 The Main Turbine Pressure Regulators are designed so that a downscale failure of the controlling regulator will result in the backup regulator automatically assuming control. This SR demonstrates that, with the failure of the controlling pressure regulator, the backup pressure regulator will assume control. The 24-month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage or unit start-up and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown the 24-month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.7-36 Revision 0

PPL Rev. 0 Main Turbine Pressure Regulation System B 3.7.8 BASES REFERENCES 1. FSAR, Section 7.7.1.5.

2. FSAR, Section 15.2.1.

SUSQUEHANNA - UNIT 1 TS / B 3.7-37 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air BASES BACKGROUND Each diesel generator (DG) is provided with a storage tank having a fuel oil capacity sufficient to operate that DG for a period of 7 days while the DG is supplying maximum post loss of coolant accident (LOCA) load demand discussed in FSAR, Section 9.5.4 (Ref. 1). The maximum load demand is calculated using the assumption that at least three DGs are available. This onsite fuel oil capacity is sufficient to operate the DGs for longer than the time to replenish the onsite supply from outside sources.

Fuel oil is transferred from storage tank to day tank by a transfer pump associated with each storage tank. Independent pumps and piping preclude the failure of one pump, or the rupture of any pipe, valve, or tank to result in the loss of more than one DG. All outside tanks, pumps, and piping are located underground.

For proper operation of the standby DGs, it is necessary to ensure the proper quality of the fuel oil. Regulatory Guide 1.137 (Ref. 2) addresses -

the recommended fuel oil practices as supplemented by ANSI N195 (Ref. 3). The fuel oil properties governed by these SRs are the water and sediment content, the kinematic viscosity, specific gravity (or API gravity) and impurity level.

The DG lubrication system is designed to provide sufficient lubrication to permit proper operation of its associated DG under all loading conditions.

The system is required to circulate the lube oil to the diesel engine working surfaces and to remove excess heat generated by friction during operation. Each engine oil sump contains an inventory capable of supporting a minimum of 7 days of operation. This supply is sufficient to allow the operator to replenish lube oil from outside sources.

Each DG has an air start system with two air receivers (DG E has four air receivers) and each DG air start system provides adequate capacity for five successive start cycles on the DG without recharging the air start receivers. Each bank of two air receivers for DG E has adequate capacity for a minimum of five successive start cycles.

(continued)

.SUSQUEHANNA-UNIT 1 TS / B 3.8-45 Revision 1

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES (continued)

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient SAFETY ANALYSES analyses in FSAR, Chapter 6 (Ref. 4), and Chapter 15 (Ref. 5), assume Engineered Safety Feature (ESF) systems are OPERABLE. The DGs are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and Section 3.6, Containment Systems.

Since diesel fuel oil, lube oil, and starting air subsystem support the operation of the standby AC power sources, they satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Stored diesel fuel oil is required to have sufficient supply for 7 days of full load operation. It is also required to meet specific standards for quality.

Additionally, sufficient lube oil supply must be available to ensure the capability to operate at full load for 7 days. This requirement, in conjunction with an ability to obtain replacement supplies within 7 days, -

supports the availability of DGs required to shut down the reactor and to maintain it in a safe condition for an anticipated operational occurrence (AOO)-or a postulated DBA With loss of offsite power. DG day tank fuel oil requirements, as well as transfer capability from the storage tank to the day tank, are addressed in LCO 3.8.1, "AC Sources--Operating," and LCO 3.8.2, "AC Sources-Shutdown."

The starting air system is required to have a minimum capacity for five successive DG start attempts without recharging the air start receivers.

APPLICABILITY The AC sources (LCO 3.8.1 and LCO 3.8.2) are required to ensure the availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA.

Because stored diesel fuel oil, lube oil, and starting air subsystem support LCO 3.8.1 and LCO 3.8.2, stored diesel fuel oil, lube oil, (continued)

SUSQUEHANNA - UNIT 1 B 3.8-46 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES APPLICABILITY and starting air are required to be within limits when the associated DG is (continued) required to be OPERABLE.

ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DG. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem. Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) governed by separate Condition entry and application of associated Required Actions.

A.1 In this Condition, the 7 day fuel oil supply for a DG is not available.

However, the Condition is restricted to fuel oil level reductions that maintain at least a 6 day supply. These circumstances may be caused by events such as: _

a. Full load operation required for an inadvertent start while at minimum required level; or

b. Feed and bleed operations that may be necessitated by increasing particulate levels or any number of other oil quality degradations.

This restriction allows sufficient time for obtaining the requisite replacement volume and performing the analyses required prior to addition of the fuel oil to the tank. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required level prior to declaring the DG inoperable. This period is acceptable based on the remaining capacity (> 6 days), the fact that action will be initiated to obtain replenishment, the availability of fuel oil in the storage tank of the fifth diesel generator that is not required to be OPERABLE, and the low probability of an event during this brief period.

(continued)

SUSQUEHANNA - UNIT 1 B 3.8-47 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS B.1 (continued)

With lube oil sump level not visible in the sight glass, sufficient lube oil to support 7 days of continuous DG operation at full load conditions may not be available. Therefore, the DG is declared inoperable immediately.

C.1 This Condition is entered as a result of a failure to meet the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to correct high particulate levels prior to reaching the limit of acceptability. Poor sample procedures (bottom sampling), contaminated sampling equipment, and errors in laboratory analysis can produce failures that do not follow a trend. Since the presence of particulates does not mean failure of the fuel oil to bum properly in the diesel engine, since particulate concentration is unlikely to change significantly between Surveillance Frequency intervals, and since proper engine performance -

has been recently demonstrated (within 31 days), it is prudent to allow a -

brief period prior to declaring the associated DG inoperable. The 7 day -

Completion Time allows for further evaluation, resampling, and re-analysis of the DG fuel oil.

D.1 With the new fuel oil properties defined in the Bases for SR 3.8.3.3 not within the required limits, a period of 30 days is allowed for restoring the stored fuel oil properties. This period provides sufficient time to test the stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains acceptable, or to restore the stored fuel oil properties. This restoration may involve feed and bleed procedures, filtering, or combination of these procedures. Even if a DG start and load was required during this time interval and the fuel oil properties were outside limits, there is high likelihood that the DG would still be capable of performing its intended function.

(continued)

SUSQUEHANNA-UNIT 1 B 3.8-48 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS E.1 (continued)

With starting air receiver pressure < 240 psig in one or more air receivers, sufficient capacity for five successive DG start attempts can not be provided by the air start system. However, as long as all receiver pressures are > 180 psig, there is adequate capacity for at least one start attempt, and the DG can be considered OPERABLE while the air receiver pressure is restored to the required limit. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration to the required pressure prior to declaring the DG ir)operable. This period is acceptable based on the remaining air start capacity, the fact that most DG starts are accomplished on the first attempt, and the low probability of an event during this brief period. Entry into Condition E is not required when air receiver pressure is less than required limits following a successful start while the DG is operating.

F.11 With a Required Action and associated Completion Time of A through E.-

not met, or the stored diesel fuel -oil, lube oil, or starting air not within SR' limits for reasons other than-addressed by Conditions A, B, C, D or E, the associated DG may be incapable of performing its intended function and must be immediately declared inoperable.

SURVEILLANCE SR 3.8.3.1 REQUIREMENTS This SR provides verification that there is an adequate inventory of fuel oil in the storage tanks to support each DG's operation for 7 days at the maximum post accident load demand. The 7 day period is sufficient time to place the unit in'a safe shutdown condition and to bring in replenishment fuel from an offsite location.

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

(continued)

SUSQUEHANNA - UNIT 1 TS / B 3.8-49 Revision 1

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.2 REQUIREMENTS (continued) This Surveillance ensures that sufficient lubricating oil inventory is available to support at least 7 days of full load operation for each DG. The sump level requirement is based on the DG manufacturer's consumption values. The acceptance criteria of maintaining a visible level in the sight glass ensures adequate inventory for 7 days of full load operation without the level reaching the manufacturer's recommended minimum level.

A 31 day Frequency is adequate to ensure that a sufficient lube oil supply is onsite, since DG starts and run time are closely monitored by the plant staff.

SR 3.8.3.3 The tests listed below are a means of determining whether new fuel oil is -

of the appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion: If results from these tests are within acceptable limits, the fuel oil may be added to-the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s), but in no case is the time between receipt of new fuel and conducting the tests to exceed 31 days. The tests, limits, and applicable ASTM Standards are as follows:

a. Sample the new fuel oil following the guidelines of ASTM D4057-88.

(Ref. 7);

b. Verify following the guidelines of the tests specified in ASTM D975-93 (Ref. 7) that the sample has a density at 150C of Ž_0.816 kg/L and < 0.876 kg/L or an API gravity of >_300 and _< 420, a kinematic viscosity at 400C of > 1.9 centistokes and

4.1 centistokes, and a flash point of _> 520 C; and

c. Verify that the new fuel oil has a clear and bright appearance when tested following the guidelines of ASTM D4176-91 procedure (Ref. 7), or has < 0.05% (vol) Water and sediment when tested following the guidelines of ASTM D1796-83 (1990) (Ref. 7).

(continued)

SUSQUEHANNA - UNIT 1 B 3.8-50 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.3 (continued)

REQUIREMENT Failure to meet any of the limits for key properties of new fuel oil prior to addition to the storage tank is cause for rejecting the new fuel oil, but does not represent a failure to meet the LCO concern since the fuel oil is not added to the storage tanks.

Within 31 days following the initial new fuel oil sample, the fuel oil is analyzed to establish that the other properties specified in Specification 5.5.9 and Reference 7 are met for new fuel oil when tested following the guidelines of ASTM D975-93 (Ref. 7). The 31 day period is acceptable because the fuel oil properties of interest, even if they were not within stated limits, would not have an immediate effect on DG operation. This Surveillance ensures the availability of high quality fuel oil for the DGs.

Fuel oil degradation during long term storage shows up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that the fuel oil will not bum properly in a diesel engine. The particulate can cause fouling of filters and fuel oil injection equipment, however, which can cause engine failure.

Particulate concentrations should be determined following the guidelines of AST-M D2276-89(Ref. 7), appropriately modified to increase the range to > 10 mg/l. This method involves a gravimetric determination of total particulate concentration in the fuel oil. This limit is 10 mg/l. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing. The Frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentration is unlikely to change significantly between Frequency intervals.

SR 3.8.3.4 This Surveillance ensures that, without the aid of the refill compressor, sufficient air start capacity for each DG is available. The system design requirements provide for a minimum of five engine start cycles without recharging.

(continued)

SUSQUEHANNA - UNIT 1 B 3.8-51 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.4 (continued)

REQUIREMENTS The pressure specified in this SR is intended to reflect the lowest value at which the five starts can be accomplished. The air starting system capacity for each start cycle is calculated based on the following:

1. each cranking cycle duration should be approximately three seconds, or

2. consist of two to three engine revolutions, or

3. air start requirements per engine start provided by the engine manufacturer, whichever air start requirement is larger.

The Surveillance is modified by a Note which does not require the SR to be met when the associated DG is running. This is acceptable because once the DG is started' the .safety function of the air start system is performed.

The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and other indications available in the control room, including alarms, to alert the operator to below normal air start pressure.

SR 3.8.3.5 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 fuel storage 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 from breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and (continued)

SUSQUEHANNA - UNIT 1 B 3.8-52 Revision 0

PPL Rev. 1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.5 (continued)

REQUIREMENTS provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 2). This SR is for preventive maintenance. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during performance of the Surveillance.

REFERENCES 1. FSAR, Section 9.5.4.

2. Regulatory Guide 1.137.

3. ANSI N195, 1976.

4. FSAR, Chapter 6.

5. FSAR, Chapter 15.

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

7. ASTM Standard: D4057-88; D975-93; D4176-91; D1552-90; D2622-87; D4294-90; and D2276-89.

SUSQUEHANNA - UNIT 1 B 3.8-53 Revision 0

ML081270181

Text

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title:

Title: