Text

Revisions to Technical Specifications Bases Unit 2 Manual
	ML071090068
Person / Time
Site:	Susquehanna
Issue date:	04/04/2007
From:	Gerlach R; Susquehanna
To:	; Document Control Desk, NRC/NRR/ADRO
References
	Download: ML071090068 (111)
	v • d • e

Apr. 04, 2007 Page 1 of 3 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2007-13483 USER INFORMATION:

GERLACH*ROSE M EMPL#:028401 CA#: 0363 Address: NUCSA2 Phone#: 254-3194 TPANT\IMTTTAT, TNTOPMATTNT-TO: GERLACH*ROSE M 04/04/2007 LOCATION: USNRC FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)

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

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

TSB2 - TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL REMOVE MANUAL TABLE OF CONTENTS DATE: 04/01/2007 ADD MANUAL TABLE OF CONTENTS DATE: 04/03/2007 CATEGORY: DOCUMENTS TYPE: TSB2

, Coo

Apr. 04, 2007 Page 2 of 3 ID: TEXT 2.1.1 REMOVE: REV:I ADD: REV: 2 REPLACE: REV:2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.1.7 REMOVE: REV:I ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.2.2 REMOVE: REV:1 ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.3.6.1 REMOVE: REV:I ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.6.1.1 REMOVE: REV:0 ADD: REV: 1 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.6.1.3

Apr. 04, 2007 Page 3 of 3 REMOVE: REV:4 ADD: REV: 5 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT LOES REMOVE: REV:79 ADD: REV: 80 REMOVE: REV:80 ADD: REV: 81 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: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Table Of Contents Issue Date: 04/03/2007 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 81 04/03/2007

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 10 10/12/2006

Title:

TABLE OF CONTENTS TEXT 2.1.1 2 04/03/2007 /

Title:

SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 0 11/18/20S0S2-

Title:

SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEM /(RCS) PRESSURE SL TEXT 3.0 2 10/12/20096

Title:

LIMITING CONDITION FOR OPERATIONý (LCO-)/APPLICABILITY TEXT 3.1.1 '1i S D M03/24/2005 SYSTEMS SHUTDOWN MARGIN (SDM)

Title:

REACTIVITY CONTROL TEXT 3.1.2 11/18/2002

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 03/24/2005

Title:

REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Report Date: 04/03/07 Pagel1 Page of of 88 Report Date: 04/03/07

SSES MANUAL SManual Manual Name: TSB2

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.1.7 2 04/03/2007

Title:

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

Title:

REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN.VALVES TEXT 3.2.1 2 10/05/2005 POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

Title:

TEXT 3.2.2 2 04/03/2007

Title:

POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)

TEXT 3.2.3 0 11/18/2002

Title:

POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE LHGR TEXT 3.2.4 1 07/06/2005

Title:

POWER DISTRIBUTION LIMITS AVERAGE POWER RANGE MONITOR (APRM) GAIN AND SETPOINTS TEXT 3.3.1.1 2 07/06/2005

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 0 11/18/2002

Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION 0 11/22/2004 TEXT 3.3.1.3

Title:

OPRM INSTRUMENTATION TEXT 3.3.2.1 1 02/17/2005

Title:

INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 0 11/18/2002 INSTRUMENTATION

Title:

INSTRUMENTATION FEEDWATER - MAIN TURBINE HIGH WATER LEVEL TRIP TEXT 3.3.3.1 3 06/13/2006

Title:

INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION Report Date: 04/03/07 of 8 Report Date: 04/03/07 Page 2

SSES MANUAL

'Manual Manual Name: TSB2

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.3.3.2 1 04/18/2005

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 0 11/18/2002

Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATION TEXT 3.3.4.2 0 11/18/2002

Title:

INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3.5.1 3 07/06/2005

Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 0 11/18/2002

Title:

INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION TEXT 3.3.6.1 2 04/03/2007

Title:

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

Title:

INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 0 11/18/2002

Title:

INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 2 03/31/2006

Title:

INSTRUMENTATION LOSS OF POWER (LOP) INSTRUMENTATION TEXT 3.3.8.2 0 11/18/2002

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1 2 11/22/2004

Title:

REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4.2 0 11/18/2002

Title:

REACTOR COOLANT SYSTEM (RCS) JET PUMPS Page 3 of8 Report Date: 04/03/07

SSES MANUAL Manual Name: TSB2 BASES UNIT 2 MANUAL Manual

Title:

TECHNICAL SPECIFICATIONS 01/16/2006 TEXT 3.4.3 (RCS) SAFETY/RELIEF VALVES (S/RVS)

Title:

REACTOR COOLANT SYSTEM 0 11/18/2002 TEXT 3.4.4

Title:

REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE 1 01/16/2006 TEXT 3.4.5 (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE

Title:

REACTOR COOLANT SYSTEM 1 04/18/2005 TEXT 3.4.6 (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION

Title:

REACTOR COOLANT SYSTEM 04/18/2005 TEXT 3.4.7 1 SYSTEM (RCS) RCS SPECIFIC ACTIVITY

Title:

REACTOR COOLANT 1 04/18/2005 TEXT 3.4.8 SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM

Title:

REACTOR COOLANT

- HOT SHUTDOWN 0 11/18/2002 TEXT 3.4.9 SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM

Title:

REACTOR COOLANT

- COLD SHUTDOWN 2 05/10/2006 TEXT, 3.4.10 (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS

Title:

REACTOR COOLANT SYSTEM 0 11/18/2002 TEXT 3.4.11 SYSTEM (RCS) REACTOR STEAM DOME PRESSURE

Title:

REACTOR COOLANT 3 01/16/2006 TEXT 35. 1 (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)

Title:

EMERGENCY CORE COOLING SYSTEMS SYSTEM ECCS - OPERATING 0 11/18/2002 TEXT 3.5.2 COOLING (RCIC)

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION SYSTEM ECCS - SHUTDOWN 1 04/18/2005 (RCIC)

TEXT 3.5.3 COOLING

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION SYSTEM RCIC SYSTEM Report Date: U~IUj/UI Report Date: uq/U-5/ut Page 4 of 8

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL 1 04/03/2007 TEXT 3.6.1.1

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT 0 11/18/2002 TEXT 3.6.1.2 AIR LOCK

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT 5 04/03/2007 TEXT 3.6.1.3 CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

.Title:

0 11/18/2002 TEXT 3.6.1.4

Title:

CONTAINMENT SYSTEMS CONTAINMENT PRESSURE 1 10/05/2005 TEXT 3.6.1.5

Title:

CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE 0 11/18/2002 TEXT 3.6.1..6

Title:

CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS 0 11/18/2002 TEXT 3.6.2.1

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE 0 11/18/2002 TEXT 3.6.2.2

Title:

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

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING 0 11/18/2002 TEXT 3.6.2.4

Title:

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

Title:

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

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM Report Date: 04/03/07 Report Date: 04/03/07 Page 5 of .8

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.3.3 0 11/18/2002

Title:

CONTAINMENT.SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 6 08/08/2006

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT TEXT 3.6.4.2 2 01/03/2005

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT 3.6.4.3 4 09/21/2006

Title:

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 0 11/18/2002

Title:

PLANT SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER (RHRSW) SYSTEM AND THE ULTIMATE HEAT SINK (UHS)

TEXT 3.7.2 1 11/09/2004

Title:

PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM 0 11/18/2002 TEXT 3.7.3

Title:

PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM 0 11/18/2002 TEXT' 3.7.4

Title:

PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 0 11/18/2002

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 1 01/17/2005

Title:

PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 0 11/18/2002

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.8.1 4 04/18/2006

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING Report Date: 04/03/07 of 8-8 Report Date: 04/03/07 Page6 Page .~ of

SSES MANUAL

'Manual Manual Name: TSB2

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL 0 11/18/2002 TEXT 3.8.2

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN 0 11/18/2002 TEXT 3.8.3 LUBE OIL, AND STARTING AIR

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, 2 12/14/2006 TEXT 3.8.4

- OPERATING

Title:

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

Title:

1 12/14/2006 TEXT 3.8.6 CELL PARAMETERS

Title:

ELECTRICAL POWER SYSTEMS BATTERY 3 03/31/2006 TEXT 3.8.7 SYSTEMS DISTRIBUTION SYSTEMS - OPERATING

Title:

ELECTRICAL POWER 0 11/18/2002 TEXT 3.8.8 DISTRIBUTION SYSTEMS - SHUTDOWN

Title:

ELECTRICAL POWER SYST EMS 0 11/18/2002 TEXT 3.9.1

Title:

REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS 0 11/18/2002 TEXT 3.9.2 REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK

Title:

0 11/18/2002 TEXT 3.9.3 ROD POSITION

Title:

REFUELING OPERATIONS CONTROL 0 11/18/2002 TEXT 3.9.4 ROD POSITION INDICATION

Title:

REFUELING OPERATIONS CONTROL 0 11/18/2002 TEXT 3.9.5 ROD OPERABILITY - REFUELING

Title:

REFUELING OPERATIONS CONTROL Report Date: 04/03/U!

Report Date: 04/03/07 Page I of 8.

SSES MANUAL

'Manual Manual Name: TSB2

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.9.6 0 11/18/2002

Title:

REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL TEXT 3.9.7 0 11/18/2002

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.8 0 11/18/2002

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL 0 11/18/2002 TEXT 3.10.1 OPERATION

Title:

SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING 0 11/18/2002 TEXT 3.10.2

Title:

SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING 0 11/18/2002 TEXT 3.10.3

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN 0 11/18/2002 TEXT 3.10.4 SHUTDOWN

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - COLD 0ý 11/18/2002 TEXT 3.10.5

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL - REFUELING 0 11/18/2002 TEXT 3.10.6 REFUELING SPECIAL OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL

Title:

1 03/24/2005 TEXT 3.10.7

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING 1 03/24/2005 TEXT 3.10.8

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING of ~

Report Date: 04/03/07 Page ~

PageR of 8

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVESECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision TOC Table of Contents 10 B 2.0 SAFETY LIMITS BASES Page TS / B 2.0-1 1 Page TS / B 2.0-2 3 Page TS / B2.0-3 4 Page TS I B 2.0-4 5 Page TS I B 2.0-5 1 Pages B 2.0-6 through B 2.0-8 0 B 3.0 LCO AND SR APPLICABILITY BASES Page TS / B 3.0-1 1 Pages TS / B 3.0-2 through TS I B 3.0-4 0 Pages TS I B 3.0-5 through TS / B 3.0-7 01 Pages TS / B 3.0-8 through TS / B 3.0-9 2 Page TS I B 3.0-10 1 Page TS / B 3.0-11 1 2 Page TS, B 3.0-11 a 0 Page TS I B 3.0-12 21 Pages TS / B 3.0-13 through TS I B_3.0-15 2 Pages TS I B 3.0-16 and TS/B- :0-17 ,\ 0 B 3.1 REACTIVITY CONTROL BASES(

Pages B 3.1-1 through B-.1-4 0 PageTS/B3.1-5 <- , \. 1 Pages TS / B 3.1-6 Ednd TS I B 3.1-7 2 Pages B 3.1-8 thr6ugh B 3.i-13 0 Page TS / B 3d-t , 1 Pages B 3.1-151hrough B 3.1-21 0 Page TS A31-22 0 PageT11iBf3, 1-23 1 Pagq[TS/i 3.1-24 0 Pag4, TS / p3.1-25 1 fPage SIB3.1-26 0 Pag6TS / B 3.1-27 1

\pag6 TS I B 3.1-28 2 Page TS / 3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.1.34 through TS I B 3.1-36 1 Pages TS I B 3.1-37 and TS I B 3.1-38 2 Pages TS / B 3.1-39 through TS I B 3.1-42 1 Pages TS / B 3.1-43 and TS / B 3.1-44 0 Page TS I B 3.1-45 2 Page TS I B 3.1-46 0 Page B 3.1-47 0 Revision 81 TS I B LOES-1 SUSQUEHANNA - UNIT SUSQUEHANNA -

UNIT 2 2 TS / B LOES-1 Revision 81

SUSQUEHANNA STEAM ELECTRIC STATION UST OFEFFECTIVESECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Pages TS I B 3.1-48 and TS i B 3.1-49 1 Page B 3.1-50 0 Page TS / B 3.1-51 1 B 3.2 POWER DISTRIBUTION LIMITS BASES Pages TS I B 3.2-1 and TS I B 3.2-2 1 Page TS I B 3.2-3 3 Page TS I B 3.2-4 1 Pages TS / B 3.2-5 and TS I B 3.2-6 3 Page TS I B 3.2-7 2 Pages TS I B 3.2-8 and TS / B3.2-9 4 Pages TS / B 3.2-10 through TS I B 3.2-17 1 Page TS /3.2-18 2 Page TS /3.2-19 1 B 3.3 INSTRUMENTATION Pages TS I B 3.3-1 through TS / B 3.3-4 1 Page TS.I B 3.3-5 2 Page TS/ B 3.3-6 1 Pages TS / B*3.3-7 through TS / B 3.3-12 2 Page TS / B 3.3-13 1 Page TS I B 3.3-14 2 Pages TS I B 3.3-15 and TS I B 3.3-16 1 Pages TS I B 3.3-17 and TS / B 3.3-18 2 Pages TS I B 3.3-19 through TS / B 3.3-27 1 Pages TS / B 3.3-28 through TS I B 3.3-30 2 Page TS I B 3.3-31 1 Page TS I B 3.3-32 3 Page TS I B 3.3-33 2 Pages TS I B 3.3-34 through TS / B 3.3-43 1 Pages TS I B 3.3-43a though TS I B 3.3-43i 0 Pages TS I B 3.3-44 through TS I B 3.3-54 2 Pages B 3.3-55 through B 3.3-63 0 Pages TS I B 3.3-64 and TS I B 3.3-65 2 Page TS I B 3.3-66 4 Page TS I B 3.3-67 3 Pages TS I B 3.3-68 and TS I B 3.3.69 4 Pages TS I B 3.3-70 and TS / B 3.3-71 3 Pages TS / B 3.3-72 and TS / B 3.3-73 2 Page TS I B 3.3-74 3 Page TS I B 3.3-75 2 Pages B 3.3-75a through TS I B 3.3-75c 4 Pages B 3.3-76 and TS / B 3.3-77 0 Revision 81 LOES-2 SUSQUEHANNA - UNIT SUSQUEHANNA- UNIT 22 TS I/ B TS B LOES-2 Revision 81

SUSQUEHANNA STEAM ELECTRIC STATION BASES)

UST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS Revision Section Title 1

Page TS / B 3.3-78 0 Pages B 3.3-79 through B 3.3-91 1 Pages TS / B 3.3-92 through TS I B 3.3-103 2 Page TS / B 3.3-104 1 Pages TS I B 3.3-105 and TS I B 3.3-106. 2 Page TS I B 3.3-107 1 Page TS I B 3.3-108 2 Page TS I B 3.3-109 1 Pages TS / B 3.3-110 through TS I B 3.3-112 2 Page TS I B 3.3-113 1 Page TS I B 3.3-114 3 3 2 Page TS / B 3.3-115 through TS / B . -118 1 Pages TS I B 3.3-119 through TS /B 3.3-120 2 Pages TS I B 3.3-121 and TS / B 3.3-122 1 Page TS I B 3.3-123 2 Page TS / B 3.3-124 0 Page TS / B 3.3-124a 1 Page TS I B 3.3-125 2 Page TS I B 3.3-126 3 Page TS I B 3.3-127 2 Page TS /IB3.3-128 1 Pages TS / B 3.3-129 through TS I B 3.3-131 2 Page TS I B 3.3-132 1 Pages TS / B 3.3-133 and TS I B 3.3-134 0 Pages B 3.3-135 through B 3.3-137 1 Page TS I B 3.3-138 0 Pages B 3.3-139 through B 3.3-149 1 Pages TS/ B 3.3-150 through TS I B 3.3-162 2 Page TS / B 3.3-163 1 Pages TS I B 3.3-164 and TS I B 3.3-165 2 Page TS / B 3.3-166 1 Pages TS I B 3.3-167 through TS I B 3.3-177 2 Page TS / B 3.3-178 3 Page TS I B 3.3-179 2 Page TS I B 3.3-179a 1 Page TS / B 3.3-180 2 Page TS I B 3.3-181 1 Pages TS I B 3.3-182 through TS I B 3.3-186 2 Pages TS I B 3.3-187 and TS / B 3.3-188 1 Pages TS I B 3.3-189 through TS I B 3.3-191 0 Pages B 3.3-192 through B 3.3-205 1 Page TS I B 3.3-206 0 Pages B 3.3-207 through B 3.3-209 1 Pages TS I B 3.3-210 through TS I B 3.3-213 0 Pages B 3.3-214 through B 3.3-220 TS I B LOES-3 Revision 81 SUSQUEHANNA - UNIT 2

SUSQUEHANNA STEAM ELECTRIC STATION BASES)

LIST OFEFFECTIVESECTIONS (TECHNICAL SPECIFICATIONS Revision Section Title B 3.4 REACTOR COOLANT SYSTEM BASES 1 Pages TS I B 3.4-1 and TS I B 3.4-2 3 Pages TS / B 3.4-3 through TS I B 3.4-9 0 Pages B 3.4-10 through B 3.4-14 1 Page TS / B3.4-15 2 Pages TS / B 3.4-16 through TS / B 3.4-18 0 Pages B 3.4-19 through B 3.4-27 1 Pages TS I B 3.4-28 and TS / B 3.4-29 0 Pages B 3.4-30 through B 3.3-31 1 Page TS I B 3.4-32 0 Pages B 3.4-33 through B 3.4-36 1 Page TS I B 3.4-37 0 Pages B 3.4-38 through B 3.4-40 1 Page TS I B 3.4-41 0 Pages B 3.4-42 through B 3.4-48 3 Page TS / B 3.4-49 2' Pages TS I B 3.4-50 through TS I B 3.4-52 1 Page TS / B 3.4-53 2 Pages TS I B 3.4-54 and TS / B 3.4-55 1 Page TS / B 3.4-56 2 Page TS I B 3.4-57 1 Pages TS I B 3.4-58 through TS I B 3.4-60 B 3.5 ECCS AND RCIC BASES 1 Pages TS I B 3.5-1 and TS / B3.5-2 2 Pages TS I B 3.5-3 through TS / B 3.5-6 1 Pages TS I B 3.5-7 through TS / B 3.5-10 2 Pages TS / B 3.5-11 and TS / B 3.5-12 1 Pages TS I B 3.6-13 and TS / B 3.5-14 2 Pages TS / B 3.5-15 and TS / B.3.5-16 3 Page TS / B 3.5-17 1 Page TS I B 3.5-18 0 Pages B 3.5-19 through B 3.5-24 1 Pages TS / B 3.5-25 through TS / B 3.5-27 0 Pages B 3.5-28 through B 3.5-31 B 3.6 CONTAINMENT SYSTEMS BASES 2 Page TS B 3.6-1 3 Page TS B 3.6-1a 2 Page TS B 3.6-2 3 Pages TS / B 3.6-3 through TS / B 3.6-5 4 Page TS / B 3.6-6 2 Pages TS I B 3.6-6a and TS / B 3.6-6b 0 Page TS I B 3.6-6c Revision 81 SUSQUEHANNA - UNIT 2 TS B LOES-4 TS I/ B LOES-4 Revision 81

SUSQUEHANNA STEAM ELECTRIC STATION LIST OFEFFECTIVESECTIONS (TECHNICAL SPECIFICATIONS BASES)

Title Revision Section Pages B 3.6-7 through B 3.6-14 0 Page TS I B 3.6-15 3 Page TS I B 3.6-15a 0 Page TS I B 3.6-15b 2 Page TS / B 3.6-16 1 Page TS / B 3.6-17 2 Page TS I B 3.6-17a 0 Pages TS I B 3.6-18 and TS I B 3.6-19 1 Page TS I B 3.6-20 2 Page TS / B 3.6-21 3 Pages TS I B 3.6-21a and TS / B 3.6-21b 0 Pages TS I B 3.6-22 and TS / B 3.6-23 2 Pages TS I B 3.6-24 and TS I B3.6-25 1 Page TS I B 3.6-26 2 Page TS I B 3.6-27 3 Page TS I B 3.6-28 6 Page TS I B 3.6-29 3 Page TS I B 3.6-29a 0 Page TS I B 3.6-30 2 Page TS I B 3.6-31 3 Page TS / B 3.6-32 1 Page TS I B 3.6-33 2 Page TS I B 3.6-34 1 Pages TS / B 3.6-35 through TS I B 3.6-37 2 Page TS I B 3.6-38 3 Page TS I B 3.6-39 7 Pages B 3.6-40 through B 3.6-42 0 Pages TS I B 3.6-43 and TS / B 3.6-44 1 Page TS I B 3.6-45 2 Pages TS I B 3.6-46 through TS I B 3.6-50 1 Page TS / B 3.6-51 2 Pages B 3.6-52 through B 3.6-62 0 Pages TS / B 3.6-63 and TS I B 3.6-64 1 Pages B 3.6-65 through B 3.6-68 0 Pages B 3.6-69 through B 3.6-71 1 Page TS I B 3.6-72 2 Pages TS I B 3.6-73 through TS / B 3.6-74 1 Pages B 3.6-75 and B 3.6-76 0 Page TS I B 3.6-77 1 Pages B 3.6-78 through B 3.6-82 0 Page TS I B 3.6-83 3 Page TS I B 3.6-84 2 Page TS I B 3.6-85 4 Page TS I B 3.6-86 through TS / B 3.6-87a 2 TS / B LOES-5 Revision 81 SUSQUEHANNA - UNIT 2

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

Title Revision Section Page TS / B 3.6-88 3 Page TS I B 3.6-89 2 Page TS I B 3.6-90 3 Pages TS I B 3.6-91 through TS / B 3.6-95 1 Page TS I B 3.6-96 2 Pages TS I B 3.6-97 and TS / B 3.6-98 1 Page TS I B 3.6-99 2 Page TS I B 3.6-99a 0 Pages TS I B 3.6-100 and TS / B 3.6-101 1 Pages TS I B 3.6-102 and TS I B 3.6-103 2 Page TS / B 3.6-104 3 Page TS I B 3.6-105 2 Page TS I B 3.6-106 3 B 3.7 PLANT SYSTEMS BASES 2 Pages TS I B 3.7-1 through TS I B 3.7-6 Page TS / B 3.7-6a 2 Pages TS I B 3.7-6b and TS I B 3.7-6c 0, Page TS I B 3.7-7 2 Page TS I B 3.7-8 1 Pages B 3.7-9 through B 3.7-11 0 Pages TS / B 3.7-12 and TS I B 3.7-13 1 Pages TS / B 3.7-14 through TS / B 3.7-18 2 Page TS I B 3.7-18a 0 Pages TS I B 3.7-19 through TS I B 3.7-26 1 Pages B 3.7-24 through B 3.7-26 0 Pages TS I B 3.7-27 through TS I B 3.7-29 2 Page TS / B 3.7-30 1 Pages B 3.7-31 through B 3.7-33 0 B 3.8 ELECTRICAL POWER SYSTEMS BASES 0 Pages B 3.8-1 through B 3.8-3 1 Page TS i B 3.8-4 0 Pages TS I B 3.8-4a and TS I B 3.8-4b Pages TS I B 3.8-5 and Page TS I B 3.8-6 1 Pages B 3.8-7 and B 3.8-8 0 Page TS I B 3.8-9 2 Pages TS / B 3.8-10 and TS I B 3.8-1.1 1 Pages B 3.8-12 through B 3.8-18 0 Page TS / B 3.8-19 1 Pages B 3.8-20 through B 3.8-22 0 Page TS I B 3.8-23 1 Page B3.8-24 0 TS / B LOES-6 Revision 81 SUSQUEHANNA - UNIT 2

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

Section Title Revision Pages TS I B 3.8-25 and TS I B 3.8-26 1 Pages B 3.8-27 through B 3.8-37 0 Page TS I B 3.8-38 1 Pages TS I B 3.8-39 through TS / B 3.8-55 0 Pages TS / B 3.8-56 through TS I B 3.8-64 2 Page TS I B 3.8-65 3 Page TS / B 3.8-66 4 Pages TS / B 3.8-67 and TS I B 3.8-68 3 Page TS / B 3.8-69 4 Pages TS I B 3.8-70 through TS I B 3.8-83 1 Pages TS / B 3.8-83A through TS / B 3.8-83D 0 Pages B 3.8-84 through B 3.8-85 0 Page TS I B 3.8-86 1 Page TS I B 3.8-87 2 Pages TS / B 3.8-88 through TS / B 3.8-93 1 Pages B 3.8-94 through B 3.8-99 0 B 3.9 REFUELING OPERATIONS BASES Pages TS I B 3.9-1 and TS / B3.9-2 1 Page TS I B 3.9-2a 1 Pages TS I B 3.9-3 and TS I B 3.9-4 1 Pages B 3.9-5 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES Page TS i B 3.10-1 1 Pages B 3.10-2 through B 3.10-32 0 Page TS / B 3.10-33 2 Pages B 3.10-34 through B 3.10-38 0 Page TS I B 3.10-39 2 TSB2 Text LOES-doc 3/21/07 SUSQUEHANNA-UNIT2 .TS / B LOES-7 Revision 81

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

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

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

The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking.

Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor operation significantly above design conditions.

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

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

Operation above the boundary of the nucleate boiling regime could 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.

(continued)

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

PPL Rev. 2 Reactor Core SLs B 2.11 BASES operation APPLICABLE The fuel cladding must not sustain damage as a result of normal violation of SAFETY and AOOs. The reactor core SLs are established to preclude such that ANALYSES the fuel design criterion that an MCPR limit is to be established, 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 are -

System (RPS) Instrumentation"), in combination with the other LCOs, of transient conditions for' designed to prevent any anticipated combination Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR limit.

2.1.1.1 Fuel Cladding Integrity 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 SPCB. For operation at low pressures or low 2

on flows, the fuel cladding integrity SL is established by a limiting condition 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. For the SPC Atrium 10 design, the minimum bundle flow is > 28 x 10 3 lb/hr. For 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-ft . Full scale critical power test data taken 2

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-ft is approximately 3.35 MWt. At 25% RTP, a bundle power of approximately 3.35 MWt corresponds to a bundle radial peaking factor of approximately 3.0, which is significantly higher than the expected peaking factor. Thus, a THERMAL POWER limit of 25% RTP for reactor pressures < 785 psig is conservative.

2.1.1.2 MCPR limit The MCPR SL ensures sufficient cqnservatism in the operating MCPR of operation, at that, in the event of an AOO from the limiting condition least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The margin between calculated boiling transition (i.e.,

MCPR = 1.00) and the MCPR SL is based on a detailed statistical procedure (continued)

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

PPL Rev. 2 Reactor Core SLs B 2.1t1 BASES APPLICABLE 2.1.1.2 MCPR (continued)

SAFETY One ANALYSES that considers the uncertainties in monitoring the core operating state.

specific uncertainty included in the SL is the uncertainty in the critical power correlation. References 2, 4 and 5 describe the methodology used in determining the MCPR SL.

The SPCB critical power correlation is based on a significant body of practical test data. As long as the core pressure and flow are within the range of validity of the correlation (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.

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 in Correlation. The effects of channel bow on MCPR are explicitly included the calculation of the MCPR SL. Explicit treatment of channel bow in the MCPR SL addresses the concerns of the NRC Bulletin No. 90-02 entitled "Loss of Thermal Margin Caused by Channel Box Bow."

Monitoring required for compliance with the MCPR SL is specified in LCO 3.2.2, Minimum Critical Power Ratio.

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

(continued)

TS / B 2.0-3 Revision 4 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Reactor Core SLs B 2.1.1 BASES 2.1.1.3 Reactor Vessel Water Level (continued)

APPLICABLE SAFETY at the top of the ANALYSES The reactor vessel water level SL has been established and to also active irradiated fuel to provide a point that can be monitored provide adequate margin for effective action.

of the fuel clad SAFETY LIMITS The reactor core SLs are established to protect the integrity to the environs. SL 2.1.1.1 barrier to the release of radioactive materials the fuel design criteria.

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

for SAFETY LIMIT Exceeding an SL may cause fuel damage and create a potential Site Criteria," limits VIOLATIONS radioactive releases in excess of 10 CFR 100, "Reactor control rods and (Ref. 3). Therefore, it is required to insert all insertable 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 restore compliance with the SLs within remedial action and also Time ensures that the operators take prompt this period is ensures that the probability of an accident occurring during minimal.

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

for

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

3. 10 CFR 100.

4. EMF-2209(P)(A), Revision 2, "SPCB Critical Power Correlation,"

Siemens Power Corporation, September 2003.

Methodology

5. EMF-2158(P)(A), Rev. 0, "Siemens Power Corporation Evaluation and Validation of for Boiling Water Reactors:

CASMO-4 / MICROBURN-B2," October 1999.

Revision 5 SUSQUEHANNA - UNIT 2 TS / B 2.0-4

PPL Rev. 2 Reactor Core SLs B 2.1.1 THIS PAGE INTENTIONALLY LEFT BLANK Revision 1 SUSQUEHANNA - UNIT 2 TS / B 2.0-5

PPL Rev. 5 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 DBA LOCA Dose Analysis. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices. The OPERABILITY requirements for closed systems are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.

For each division of H 2 0 2 Analyzers, the lines, up to and including the first normally closed valves within the H 2 0 2 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-15 Revision 3

PPL Rev. 5 PCIVs B 3.6.1.3 BASES BACKGROUND Analyzer panels, are extensions of primary containment (continued) (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. 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 H2 0 2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-22361, SV-22365, SV-22366, SV-22368, and SV-22369).

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 H2 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 H20 2 Analyzer Sampling line penetrating primary containment has two PCIVs, located just outside primary containment. While two PCIVs are provided on each line, a single active failure of a relay in the control circuitry for these valves, could result in both valves failing to close or failing to remain closed. Furthermore, a single failure (a hot short in the common raceway to all the valves) could simultaneously affect all of the PCIVs within a H20 2 Analyzer division. Therefore, the containment isolation barriers for these penetrations consist of two PCIVs and a closed system. For situations where one or both PCIVs are inoperable, the ACTIONS to be taken are similar to the ACTIONS for a single PCIV backed by a closed system.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-15a Revision 0

PPL Rev. 5 PCIVs B 3.6.1.3 BASES (continued)

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-251F015A(B)} and a normally open globe valve

{HV-251 F017A(B)} outside containment and a testable check valve {HV-251 F050A(B)} with a normally closed parallel air operated globe valve {HV-251F122A(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-251 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-251F05,OA(B), HV-251F122A(B), and HV-251 F01 5A(B) valves are used to meet this requirement and are tested in accordance with the pressure test program.

(continued)

TS / B 3.6-15b Revision 2 SUSQUEHANNA - UNIT 2

PPL Rev. 5 PCIVs B 3.6.1.3 BASES (continued)

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. Of the events analyzed in Reference 1, the MSLB is the most limiting event due to radiological consequences. The closure time of the main steam isolation valves (MSIVs) 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 2 TS / B 3.6-16 Revision 1

PPL Rev. 5 PCIVs B 3.6.1.3 BASES APPLICABLE due to failure in the control circuit associated with each SAFEETY ANALYSIS valve. The primary containment purge valve design precludes (continued) 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 H2 0 2 Analyzer penetrations is satisfied by virtue of the combination of the associated PCIVs and the closed system formed by the H20 2 Analyzer piping system as discussed in the BACKGROUND section above.

The closed system boundary between PASS and the H20 2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-22361, SV-22365, SV-22366, SV-22368, and SV-22369). The closed system is not fully qualified to the guidance of Reference 6 in that the closed system boundary valves between the H 2 0 2 system and PASS are not powered from a Class 1 E power source. However, based upon a risk determination, the use of these valves is considered to have no risk significance. This exemption to the requirement of Reference 6 for the closed system boundary is documented in License Amendment No. 170.

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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-17 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 BASES LCO automatic isolation signal. The valves covered by this (continued) LCO are listed in Table B 3.6.1.3-1.

The normally closed PCIVs are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are in their closed position, blind flanges are in place, and closed systems are intact.

These passive isolation valves and devices are those listed in Table B 3.6.1.3-1.

Purge valves with resilient seals, secondary containment bypass valves, MSIVs, and hydrostatically tested valves must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment," as Type B or C testing.

This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.

Therefore, most PCIVs are not required to be (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-17a Revision 0

PPL Rev. 5 PCIVs B 3.6.1.3 BASES APPLICABILITY OPERABLE and the primary containment purge valves are (continued) not required to be closed in MODES 4 and 5. Certain valves, however, are required to be OPERABLE to prevent inadvertent reactor vessel draindown. These valves are those whose associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation."

(This does not include the valves that isolate the associated instrumentation.)

ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions are not required even when the associated LCO is not met. Therefore, Notes 3 and 4 are added to require the proper actions be taken.

A. 1 and A.2 With one or more penetration flow paths with one PCIV inoperable except for purge valve leakage not within limit, (continued)

SUSQUEHANNA- UNIT 2 TS / B 3.6-18 Revision 1

PPL Rev. 5 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 capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-19 Revision 1

PPL Rev. 5 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued)

Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two PCIVs except for the H20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the 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 H 2 0 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H 2 0 2 Analyzer penetrations, Condition D provides the appropriate Required Actions.

C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-20 Revision 2

PPL Rev. 5 PCIVs B 3.6,1.3 BASES ACTIONS C.1 and C.2 (continued)

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 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 H 2 0 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 (continued)

OI I CJtA*l Ir-AIKIA INIlT , Tq I E 3 6-921 Revision 3 QUO

PPL Rev. 5 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued) restricted. Therefore, the probability of misalignment of these valves, once they have been verified to be in the proper position, is low.

D.1 and D.2 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 H 2 0 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 penetration flow path is isolated in accordance with Required Action D.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

When an H 2 0 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.

(continued)

SUSQUEHANNA- UNIT 2 TS / B 3.6-21 a Revision 0

PPL Rev. 5 PCIVs B 3.6.1.3 BASES ACTIONS AD. and D.2 (continued}

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.

Condition D is modified by a Note indicating that this Condition is only applicable to the H 2 0 2 Analyzer penetrations.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-21 b Revision 0

PPL Rev. 5 PCIVs B 3.6,1.3 BASES ACTIONS E. 1 (continued)

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 more containment purge valves are not within the purge valve leakage limits, purge valve leakage must be restored to within limits. The 24 hour2.777778e-4 days 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 2 TS / B 3.6-22 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 BASES ACTIONS H.1 and H.2 (continued)

If any Required Action and associated Completion Time cannot be met, the unit must be placed in a condition in which the LCO does not apply. If applicable, action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended or valve(s) are restored to OPERABLE status. If suspending an OPDRV would result in closing the residual heat removal (RHR) shutdown cooling isolation valves, an alternative Required Action is provided to immediately initiate action to restore the valve(s) to OPERABLE status. This allows RHR to remain in service while actions are being taken to restore the valve.

SURVEILLANCE SR 3.6.1.3.1 REQUIREMENTS This SR ensures that the primary containment purge valves are closed as required or, if open, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. The SR is also modified by Note 1, stating that primary containment purge valves are only required to be closed in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves, or the release of radioactive material will exceed limits prior to the purge valves closing. At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are allowed to be open. The SR is modified by Note 2 stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The vent and purge valves are capable of closing in the environment following (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-23 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.1 (continued)

REQUIREMENTS a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The 31 day Frequency is consistent with other PCIV requirements discussed in SR'3.6.1.3.2.

SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.

This SR does not require any testing or valve manipulation.

Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are in the correct position. Since verification of valve position for PCIVs outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the PCIVs are in the correct positions.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

SR 3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-24 Revision 1

PPL Rev. 5 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS 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. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing. Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

SR 3.6.1.3.4 The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.

SR 3.6.1.3.5 Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-25 Revision 1

PPL Rev. 5 PCIVs B 3.6,1.3 BASES SURVEILLANCE SR 3.6.1.3.5 (continued)

REQUIREMENTS OPERABILITY. MSIVs may be excluded from this SR since MSIV 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 10 CFR 100 limits.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-26 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.7 REQUIREMENTS (continued) The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.8 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 simulated instrument line break. As defined in FSAR Section 6.2.4.3.5 (Reference 4), the conditions under which an EFCV will isolate, simulated instrument line breaks 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 problem with a specific type or application of EFCV is (continued)

TS / B 3.6-27 Revision 3 SUSQUEHANNA - UNIT 2

PPL Rev. 5 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.9 (continued)

REQUIREMENTS detected af 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).

SR 3.6.1.3.10 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 anyone MSIV or < 300 scfh for total leakage through the MSIVs combined with the Main Steam Line Drain Isolation Valve, HPCI Steam Supply Isolation Valve and the RCIC Steam Supply Isolation Valve. The MSIVs can be tested at either > Pt (22.5 psig) or Pa (45 psig). Main Steam Line Drain Isolation, HPCI and RCIC Steam Supply Line Isolation Valves, are tested at Pa (45 psig). A note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-28 Revision 6

PPL Rev. 5 PCIVs B 3.6,1.3 BASES SURVEILLANCE SR 3.6.1.3.12 (continued)

REQUIREMENTS 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. If leakage from the MSIVs requires internal work on any MSIV, the leakage will be reduced for the affected MSIV to < 11.5 scfh.

SR 3.6.1.3.13 Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 2 are met. The acceptance criteria for the combined leakage of all hydrostatically tested lines is 3.3 gpm when tested at 1.1 Pa, (49.5 psig). The combined leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by the Primary Containment Leakage Testing Program.

As noted in Table B 3.6.1.3-1, PCIVs associated with this SR are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water level in the suppression chamber. These valves are tested in accordance with the IST Program. Therefore, these valves leakage is not included as containment leakage.

This SR has been modified by a Note that states that these valves are only required to meet the combined leakage rate in MODES 1, 2, and 3, since this is when the Reactor Coolant System is pressurized and primary containment is required. In some instances, the valves are required to be capable of automatically closing during MODES other than MODES 1, 2, and 3. However, specific leakage limits are not applicable in these other MODES or conditions.

REFERENCES 1. FSAR, Chapter 15.

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

3. 10 CFR 50, Appendix J, Option B.

4. FSAR, Section 6.2.

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

March 1988.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-29 Revision 3

PPL Rev. 5 PCIVs B 3.6.1.3 BASES REFERENCES (continued) 6. Standard Review Plan 6.2.4, Rev. 1, September 1975

7. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000 continued)

Revision 0 SUSQUEHANNA - UNIT 2 TS B 3.6-29a

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 1 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Containment 2-57-199 (d) ILRT Manual N/A Atmospheric 2-57-200 (d) ILRT Manual N/A Control HV-25703 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25704 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25705 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25711 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25713 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25714 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25721 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25722 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25723 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25724 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25725 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25766 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (35)

HV-25768 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)

SV-257100 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257100 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-2571 01 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2f Syst SV-2571 01 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257102 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257102 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257103 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257103 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257104 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257105 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257106 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257107 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-25734 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25734 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25736 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25736 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25737 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SUSQUEHANNA - UNIT 2 TS / B 3.6-30 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paqe 2 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Valve Number Valve Description Type of Valve (Maximumstion Plant System (Maximum Isolation Time (Seconds))

Containment SV-25738 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Atmospheric SV-25740 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d Control SV-25740 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d (continued) SV-25742 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25742 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25750 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25750 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25752 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25752 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25767 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SV-25774 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25774 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25776 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25776 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25780 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25780 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25782 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25782 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25789 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Containment 2-26-072 (d) Containment Instrument Gas Manual Check N/A Instrument Gas 2-26-074 (d) Containment Instrument Gas Manual Check N/A 2-26-152 (d) Containment Instrument Gas Manual Check N/A 2-26-154 (d) Containment Instrument Gas Manual Check N/A 2-26-164 (d) Containment Instrument Gas Manual Check N/A HV-22603 Containment Instrument Gas Automatic Valve 2.c, 2.d (20)

SV-22605 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-22651 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-22654 A Containment Instrument Gas Power Operated N/A SV-22654 B Containment Instrument Gas Power Operated N/A SV-22661 Containment Instrument Gas Automatic Valve 2.b, 2.d SV-22671 Containment Instrument Gas Automatic Valve 2.b, 2.d Core Spray HV-252F001 A (b)(c) CS Suction Power Operated N/A HV-252F001 B (b)(c) CS Suction Power Operated N/A HV-252F005 A CS Injection Power Operated N/A HV-252F005 B CS Injection Power Operated N/A HV-252F006 A CS Injection Air Operated N/A HV-252F006__A CS__InjectionCheck Valve HV-252F006 B CS Injection Air Operated N/A Check Valve HV-252F01 5 A (b)(c) CS Test Automatic Valve 2.c, 2.d (80)

HV-252F015 B (b)(c) CS Test Automatic Valve 2.c, 2.d (80)

HV-252F031 A (b)(c) CS Minimum Recirculation Flow Power Operated N/A HV-252F031 B (b)(c) CS Minimum Recirculation Flow Power Operated N/A SUSQUEHANNA - UNIT 2 TS / B 3.6-31 Revision 3

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 3 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Valve Number Valve Description Type of Valve (Max1mumstion Plant System (Maximum Isolation Time (Seconds))

Core Spray HV-252F037 A CS Injection Power Operated N/A (continued) (Air)

HV-252F037 B CS Injection Power Operated N/A (Air)

XV-252F018 A Core Spray Excess Flow N/A Check Valve XV-252F018 B Core Spray Excess Flow N/A Check Valve Demin Water 2-41-017 (d) Demineralized Water Manual N/A 2-41-018 (d) Demineralized Water Manual N/A HPCI 2-55-038 (d) HPCI Injection Manual N/A 255F046 (b) (c) (d) HPCI Minimum Recirculation Flow Manual Check N/A 255F049 (a) (d) HPCI Manual Check N/A HV-255F002 HPCI Steam Supply Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3g, (50)

HV-255F003 HPCI Steam Supply Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (50)

HV-255F006 HPCI Injection Power Operated N/A HV-255F012 (b) (c) HPCI Minimum Recirculation Flow Power Operated N/A HV-255F042 (b) (c) HPCI Suction Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (90)

HV-255F066 (a) HPCI Turbine Exhaust Power Operated N/A HV-255F075 HPCI Vacuum Breaker Automatic Valve 3.b, 3.d, (15)

HV-255F079 HPCI Vacuum Breaker Automatic Valve 3.b, 3.d, (15)

HV-255F100 HPCI Steam Supply Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (6)

XV-255F024 A HPCI Excess Flow N/A Check Valve XV-255F024 B HPCI Excess Flow N/A Check Valve XV-255F024 C HPCI Excess Flow N/A Check Valve XV-255F024 D HPCI Excess Flow N/A Check Valve Liquid Radwaste HV-261 08 Al Liquid Radwaste Automatic Valve 2.b, 2.d (15)

Collection HV-26108 A2 Liquid Radwaste Automatic Valve 2.b, 2.d (15)

HV-26116 Al Liquid Radwaste Automatic Valve 2.b, 2.d (15)

HV-26116 A2 Liquid Radwaste Automatic Valve 2.b, 2.d (15)

Nuclear Boiler 241F010 A (d) Feedwater Manual Check N/A 241 F010 B (d) Feedwater Manual Check N/A 241 F039 A (d) Feedwater Isolation Valve Manual Check N/A 241 F039 B (d) Feedwater Isolation Valve Manual Check N/A 241818 A (d) Feedwater Isolation Valve Manual Check N/A 241818 B (d) Feedwater Isolation Valve Manual Check N/A SUSQUEHANNA - UNIT 2 TS / B 3.6-32 Revision 1

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 4 of 10)

Isolation Signal LCO Plant System Valve Number Valve Description Type of Valve 3.3.6.1 Function No.

(Maximum Isolation Time (Seconds))

Nuclear Boiler HV-241 F016 MSL Drain Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (continued) (10)

HV-241 F019 MSL Drain Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (15)

HV-241 F022 A MSIV Automatic Valve 1.a, 1.b, 1.c, 1d, 1.e (5)

HV-241 F022 B MSIV Automatic Valve i.a, 1.b, 1.c, 1.d, 1.e (5)

HV-241F022 C MSIV Automatic Valve i.a, 1.b, 1.c, 1.d, i.e (5)

HV-241 F022 D MSIV Automatic Valve 1.a, 1 .b, 1.c, 1d, 1.e (5)

HV-241 F028 A MSIV Automatic Valve 1.a, i.b, 1.c, i.d, i.e (5)

HV-241 F028 B MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, i.e (5)

HV-241 F028 C MSIV Automatic Valve i.a, 1.b, 1.c, i.d, i.e (5)

HV-241 F028 D MSIV Automatic Valve 1.a, 1 .b, 1.c, 1.d, 1.e (5)

HV-241 F032 A Feedwater Isolation Valve Power Operated N/A Check Valves HV-241 F032 B Feedwater Isolation Valve Power Operated N/A Check Valves XV-241 F009 Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F070 A Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F070 B Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F070 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F070 D Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 A Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 B Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 D Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 A Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 B Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 D Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F073 A Nuclear Boiler EFCV Excess Flow N/A Check Valve SUSQUEHANNA - UNIT 2 TS / B 3.6-33 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paoe 5 of 10)

Isolation Signal LCO Plant System Valve Number Valve Description Type of Valve 3.3.6.1 Function No.

(Maximum Isolation Time (Seconds))

Nuclear Boiler XV-241 F073 B Nuclear Boiler EFCV Excess Flow N/A (continued) Check Valve XV-241 F073 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F073 D Nuclear Boiler EFCV Excess Flow N/A Check Valve Nuclear Boiler XV-242U1 Nuclear Boiler Vessel Instrument Excess Flow N/A Vessel Check V/alve Instrumentation XV-24202 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F041 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F043 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F043 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F045 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F045 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F047 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242FO47B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F051 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F051 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F051 C Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F051 D Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 C Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 D Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F055 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F057 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242FO59 B Nuclear Boiler Vessel Instrument Excess Flow N/A Chec~k \/lvu_

Chec LValve__ __

SUSQUEHANNA - UNIT 2 TS / B 3.6-34 Revision 1

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 6 of 10)

I Isolation Signal LCO 3.3.6.1 Function No.

Valve Description Type of Valve (Maximum Isolation Plant System Valve Number Time (Seconds))

____________________ 4- +/- -excess ~I-low r Nuclear Boiler XV-242F059 C Nuclear Boiler Vessel Instrument Excess Check Valve Vlow I 1141M Vessel .. .. . . . . - . . . I I. . I KIIA Instrumentation XV-242F059 D Nuclear Boiler Vessel Instrument EChec alvW Check Valve (continued)

XV-242F059 E Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 F Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 G Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 H Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 L Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 M Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 N Nuclear Boiler Vessel Instrument Excess Flow NIA Check Valve XV-242F059 P Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 R Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 S Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 T Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve

xc s I-lo.... /l XV-242F059 U Nuclear Boiler Vessel Instrument E"xcess Flow Check Valve 11/-m Nuclear ie r v s sumIA Io XV-242F061 Nuclear Boiler Vessel Instrument Check Valve Ifl 170 AI ai ~v AP(hir-iktr~to RB Chilled Water

'704")

-/

Al 1:;)13. ('*hill*t'l W*tAr Automatic valve Z.U, Z-.U k U)

HV-28781 A2 RB Chilled Water Automatic Valve 2.c, 2.c, 2.d 2.d (40)

(40)

System HV-28781 A1 RB Chilled Water Automatic Valve B2 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-28781 Al RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 A2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 B1 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 B2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 Al RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28791 A2 RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28791 HV-28791 BA RB Chilled Water Automatic Valve 2.c, 2.d (15)

B2 RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28791 Al RB Chilled Water Automatic Valve 2.c, 2.d (8)

HV-28792 H-89Al RB Chilled Water A~utomatic Vaive 2c . 8 I\/-R7*9 A2 RB Chilled Water Automatic Valve Z.c, Z. d(8'l HV-28792 A2 RB Chilled Water

[*[.] Ir'l-tlll*/d *,pl*1"*r -1 I - }[ I [JLI

______ rv-.eoI 1__H ZD I I j- eiV'.i-III - A (8)

Revision 2 SUSQUEHANNA - UNIT 2 TS / B 3.6-35

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Pane 7 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

RB Chilled Water HV-28792 B2 RB Chilled Water Automatic Valve 2.b, 2.d (8)

System (continued)

RBCCW HV-21313 RBCCW Automatic Valve 2.c, 2.d (30)

HV-21314 RBCCW Automatic Valve 2.c, 2.d (30)

HV-21345 RBCCW Automatic Valve 2.c, 2.d (30)

HV-21346 RBCCW Automatic Valve 2.c, 2.d (30)

RCIC 2-49-020 (d) RCIC Injection Manual N/A 249F021 (b) (c) (d) RCIC Minimum Recirculation Flow Manual Check N/A 249F028 (a) (d) RCIC Vacuum Pump Discharge Manual N/A 249F040 (a) (d) RCIC.Turbine Exhaust Manual N/A FV-249F019 (b) (c) RCIC Minimum Recirculation Flow Power Operated N/A HV-249F007 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-249F008 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-249F013 RCIC Injection Power Operated N/A HV-249F031 (b) (c) RCIC Suction Power Operated N/A HV-249F059 (a) RCIC Turbine Exhaust Power Operated N/A HV-249F060 (a) RCIC Vacuum Pump Discharge Power Operated N/A HV-249F062 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-249F084 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-249F088 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (12)

XV-249F044 A RCIC Excess Flow N/A Check Valve XV-249F044 B RCIC Excess Flow N/A Check Valve XV-249F044 C RCIC Excess Flow N/A Check Valve XV-249F044 D RCIC Excess Flow N/A Check Valve Reactor 243F01 3 A (d) Recirculation Pump Seal Water Manual Check N/A Recirculation 243F013 B (d) Recirculation Pump Seal Water Manual Check N/A HV-243F019 Reactor Coolant Sample Automatic Valve 2.b (9)

HV-243F020 Reactor Coolant Sample Automatic Valve 2.b (2)

XV-243F003 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F003 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F004 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F004 B Reactor Recirculation Excess Flow N/A Check Valve SUSQUEHANNA- UNIT 2 TS / B 3.6-36 Revision 2.

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve Isolation Signal LCO 3.3.6.1 Func~tion No.

Valve Number Valve Description Type of Valve (Maximumstion Plant System (Maximum Isolation Time (Seconds))

Reactor XV-243F009 A Reactor Recirculation Excess Flow N/A Recirculation Check Valve (continued) XV-243F009 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F009 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F009 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F010 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 0 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 0 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F010 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 2 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F012 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F012 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F012 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 7 A Recirculation Pump Seal Water Excess Flow N/A Check Valve XV-243F017 B Recirculation Pump Seal Water Excess Flow N/A Check Valve XV-243F040 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F040 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F040 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F040 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F057 A Reactor Recirculation Excess Flow N/A Check Valve XV-243FO57 B Reactor Recirculation Excess Flow N/A Check Valve Residual Heat HV-251 F004 A (b) (c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-251 F004 B (b) (c) RHR - Suppression Pool Suction Power Operated N/A I HV-251 F004 C (b) (c) RHR - Suppression Pool Suction Power Operated N/A SUSQUEHANNA - UNIT 2 TS / B 3.6-37 Revision 2

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 PrimaryContainment Isolation Valve (Page 9 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Residual Heat HV-251F004 D(b) (c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-251 F007 A (b) (c) RHR - Minimum Recirculation Power Operated N/A (continued) HV-251 F007 B (b) (c) RHR - Minimum Recirculation Power Operated N/A HV-251F008 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)

HV-251 F009 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)

HV-251 F01 1 A (b) (d) RHR - Suppression Pool Cooling Manual N/A HV-251 F01 1 B (b) (d) RHR - Suppression Pool Cooling Manual N/A HV-251 F01 5 A (f) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection HV-251 F015 B (f) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection HV-251 F01 6 A (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)

HV-251 F016 B (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)

HV-251 F022 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (30)

HV-251 F023 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (20)

HV-251 F028 A (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-251 F028 B (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-251 F050 A (g) RHR - Shutdown Cooling Air Operated N/A Return/LPCI Injection Check Valve HV-251F050 B (g) RHR - Shutdown Cooling Air Operated N/A Return/LPCI Injection Check Valve HV-251 F103 A (b) RHR Heat Exchanger Vent Power Operated N/A HV-251 F1 03 B (b) RHR Heat Exchanger Vent Power Operated N/A HV-251 F1 22 A (g) RHR - Shutdown Cooling Power Operated N/A Retum/LPCI Injection (Air)

HV-251 F1 22 B (g) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection (Air)

PSV-25106 A (b) (d) RHR- Relief Valve Discharge Relief Valve N/A PSV-25106 B (b) (d) RHR- Relief Valve Discharge Relief Valve N/A PSV-251 F126 (d) RHR- Shutdown Cooling Suction Relief Valve N/A XV-25109 A RHR Excess Flow N/A Check Valve XV-25109 B RHR Excess Flow N/A Check Valve XV-25109 C RHR Excess Flow N/A Check Valve XV-25109 D RHR Excess Flow N/A Check Valve RWCU HV-244F001 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.f, 5.g (30)

HV-244F004 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.e, 5.f, 5.g (30)

XV-24411 A RWCU Excess Flow N/A Check Valve XV-24411 B RWCU Excess Flow N/A Check Valve SUSQUEHANNA - UNIT 2 TS / B 3.6-38 Revision 3

PPL Rev. 5 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 10 of 10)

Isolation Signal LCO Plant System Valve Number Valve Description Type of Valve 3.3.6.1 Function No.

(Maximum Isolation Time (Seconds))

RWCU XV-24411 C RWCU Excess Flow N/A (continued) Check Valve XV-24411 D RWCU Excess Flow N/A Check Valve XV-244F046 RWCU Excess Flow N/A Check Valve HV-24182 A RWCU Return Power Operated N/A HV-24182 B RWCU Return Power Operated N/A SLCS 248F007 (a) (d) SLCS Manual Check N/A HV-248F006 (a) SLCS Power Operated N/A Check Valve TIP System C51-J004 A (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

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)

TIP System C51-JO04 A (Shear TIP Shear Valves Squib Valve N/A (continued) Valve)

C51-J004 B (Shear TIP Shear Valves Squib Valve N/A Valve)

C51-J004 C (Shear TIP Shear Valves Squib Valve N/A Valve)

C51-J004 D (Shear TIP Shear Valves Squib Valve N/A Valve)

C51-J004 E (Shear TIP Shear Valves Squib Valve N/A Valve)

(a) Isolation barrier remains 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 255F046 (HPCI) when the associated PCIV, HV255F012 is closed and deactivated. Similarly, this footnote does not apply to valve 249F021 (RCIC) when its associated PCIV, FV249F019 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, (PCIV Position) 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-251 F015A(B) valves and a closed system form the 10 CFR 50, Appendix J boundary. These valves form a high/low pressure interface and are pressure tested in accordance with the pressure test program.

SUSQUEHANNA- UNIT 2 TS / B 3.6-39 Revision 7

PPL Rev. 2 SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement.

The SLC system satisfies the requirements of 10 CFR 50.62 (Ref. 1) for anticipated transient without scram.

The SLC System consists of a sodium pentaborate solution storage tank, two positive displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to transfer borated water from the storage tank to the reactor pressure vessel (RPV). The borated solution is discharged near the bottom of the core shroud, where it then mixes with the cooling water rising through the core. A smaller tank containing demineralized water is provided for testing purposes.

APPLICABLE The SLC System is manually initiated from the main control room, as SAFETY directed by the emergency operating procedures, if the operator believes ANALYSES the reactor cannot be shut down, or kept shut down, with the control rods.

The SLC System is used in the event that enough control rods cannot be inserted to accomplish shutdown and cooldown in the normal manner.

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 68 0 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 2 TS / B 3.1-39 Revision 1

PPL Rev. 2 SLC System B 3.1.7 IBASES 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 satisfies the requirements of the NRC Policy Statement (Ref. 3) because operating experience and probabilistic risk assessments have shown the SLC System to be important to public health and safety.

Thus, it is retained in the Technical Specifications.

LCO The OPERABILITY of the SLC System provides backup capability for reactivity control independent of normal reactivity control provisions provided by the control rods. 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 2 TS / B 3.1-40 Revision 1

PPL Rev. 2 SLC System B 3.1.7 BASES (continued)

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 (continued)

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

PPL Rev. 2 SLC System B 3.1.7 BASES ACTIONS B.1 (continued) shutdown function. 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 function and the low probability of an event occurring concurrent with the failure of the Control Rod Drive (CRD)

System to shut down the plant.

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 concurrent with the failure of the control rods to shut down the reactor.

(continued)

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

PPL Rev. 2 SLC System B 3.1.7 BASES ACTIONS D. 1 (continued) If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The '

allowed 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 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 characteristics of the SLC System (e.g., the volume and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution volume and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in ensuring that the sodium pentaborate remains in solution and does not precipitate out in the storage tank or in the pump suction piping.

The temperature versus concentration curve of Figure 3.1.7-2 ensures that a 10OF margin will be maintained above the saturation temperature. An alternate method of performing SR 3.1.7.3 is to verify the OPERABILITY of the SLC heat trace system. This verifies the continuity of the heat trace lines and ensures proper heat trace operation, which ensure that the SLC suction piping temperature is maintained. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience and has shown there are relatively slow variations in the measured parameters of volume and temperature.

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

SUSQUEHANNA - UNIT 2 TS / 8 3.1-43 Revision 0

PPL Rev. 2 SLC System B 3.1.7 BASES SURVEILLANCE 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-UNIT2 TS / B 3.1-44 Revision 0

PPL Rev. 2 SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.7 REQUIREMENTS (continued) Demonstrating that each SLC System pump develops a flow rate

> 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. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.

SR 3.1.7.8 and SR 3.1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 48 months at alternating 24 month intervals. The Surveillance may be performed in separate steps to prevent injecting solution into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from aI reliability standpoint.

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

TS / B 3.1-45 Revision 2 SUSQUEHANNA - UNIT 2

PPL Rev. 2 SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.8 and SR 3.1.7.9 (continued)

REQUIREMENT S

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 pentaborate solution is made 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 2 TS / B 3.1-46 Revision 1

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 ifthe limit is not violated (refer to the Bases for SL 2.1.1.2). The operating limit MCPR is established to ensure that no fuel damage results during anticipated operational occurrences (AOOs). Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.

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

APPLICABLE The analytical methods and assumptions used in evaluating the AOOs SAFETY ANALYSES to establish the operating limit MCPR are presented in References 2 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 pressure 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 state to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency These ,analyses may also consider other (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-5 Revision 3

PPL Rev. 2 MCPR B 3.2.2 BASES APPLICABLE combinations of plant conditions (i.e., control rod scram speed, SAFETY ANALYSES bypass valve performance, EOC-RPT, cycle exposure, etc.). Flow (continued) 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 25% RTP, the reactor is operating at a minimum recirculation pump speed and the moderator void ratio is small. Surveillance of thermal limits below 25% RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs. Studies of the variation of limiting transient behavior have been 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 25%,RTP. This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs. 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

< 25% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.

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

Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-6 Revision 3

PPL Rev. 2 MCPR B 3.2.2 BASES ACTIONS A.1 (continued) 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 < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.2.1 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 > 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

Additionally, MCPR must be calculated prior to exceeding 50% RTP unless performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . MCPR is compared to the specified limits in the 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 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because the MCPR must be calculated prior to exceeding 50% RTP.

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

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

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-7 Revision 2

PPL Rev. 2 MCPR B 3.2.2 BASES SURVEILLANCE SR 3.2.2.2 (continued)

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

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.

3. XN-NF-80-19(P)(A) Volume 3, Revision 2, "Exxon Nuclear 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 1 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),

"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 2, "SPCB Critical Power Correlation," Siemens Power Corporation, September 2003.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-8 Revision 4

PPL Rev. 2 MCPR B 3.2.2 BASES Reference 8. XN-NF-79-71(P)(A) Revision 2, Supplements 1, 2, and 3, (continued) "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 3, "The Loss of Feedwater Heating Transient in Boiling Water Reactors," Advanced Nuclear Fuels Corporation, September 2005.

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

SUSQUEHANNA - UNIT 2 TS / B 3.2-9 Revision 4

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs). The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs). Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.

The isolation instrumentation includes the sensors, relays, and instruments that are necessary to cause initiation of primary containment and reactor coolant pressure boundary (RCPB) isolation.

When the setpoint is reached, the sensor actuates, which then outputs an isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logics are (a) reactor vessel water level, (b) area ambient and emergency cooler temperatures, (c) main steam line (MSL) flow measurement, (d) Standby Liquid Control (SLC)

System initiation, (e) condenser vacuum, (f) main steam line pressure, (g) high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) steam line A pressure, (h) SGTS Exhaust radiation, (i) HPCI and RCIC steam line pressure, (j) HPCI and RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) differential flow and high flow, (I) reactor steam dome pressure, and (m) drywell pressure. Redundant sensor input signals from each parameter are provided for initiation of isolation. The only exception is SLC System initiation. In addition, manual isolation of the logics is provided.

Primary containment isolation instrumentation has inputs to the trip logic of the isolation functions listed below.

(continued)

SUSQUEHANNA - UNIT 2 B 3.3-147 Revision 0

PPL Rev. 2 Primary Containment Isolation Instrumentation B 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 IIAnalyzer 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 where both inboard and outboard valves will isolate on either (continued)

SUSQUEHANNA - UNIT 2 B 3.3-148 Revision 0

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 2. Primary Containment Isolation (continued) 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. Higqh Pressure Coolant Iniection System Isolation and Reactor Core Isolation Coolingq System Isolation Most Functions that isolate HPCI and RCIC receive input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems in each isolation group is connected to one of the two valves on each associated penetration.

The exceptions are the HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High and Steam Supply Line Pressure-Low Functions.

These Functions receive inputs from four turbine exhaust diaphragm pressure and four steam supply pressure channels for each system.

The outputs from the turbine exhaust diaphragm pressure and steam supply pressure channels are each connected to two two-out-of-two trip systems. Each trip system isolates one valve per associated penetration.

5. Reactor Water Cleanup System Isolation The Reactor Vessel Water Level-Low Low, Level 2 Isolation Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected into two two-out-of-two trip systems. The Differential Flow-High, Flow- High, and SLC System Initiation Functions receive input from two channels, with each channel in one trip system using a one-out-of-one logic. The temperature isolations are divided into three Functions.

These Functions are Pump Area, Penetration Area, and Heat Exchanger Area. Each area is monitored by two temperature monitors, one for each trip system. These are configured so that any one input will trip the associated trip system. Each of the two trip systems is connected to one of the two valves on each RWCU penetration.

(continued)

SUSQUEHANNA - UNIT 2 B 3.3-149 Revision 0

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND 6. Shutdown Cooling System Isolation (continued)

The Reactor Vessel Water Level-Low, Level 3 Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected to two two-out-of-two trip systems. The Reactor Vessel Pressure-High Function receives input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems is connected to one of the two valves on each shutdown cooling penetration.

7. Traversing Incore Probe System Isolation The Reactor Vessel Water Level-Low, Level 3 Isolation Function receives input from two reactor vessel water level channels. The Drywell Pressure-High Isolation Function receives input from two drywell pressure channels. The outputs from the reactor vessel water level channels and drywell pressure channels are connected into one two-out-of-two logic trip system.

When either Isolation Function actuates, the TIP drive mechanisms will withdraw the TIPs, if inserted , and close the inboard TIP System isolation ball valves when the proximity probe senses the TIPs are withdrawn into the shield. The TIP System isolation ball valves are only open when the TIP System is in use. The outboard TIP System isolation valves are manual shear valves.

APPLICABLE The isolation signals generated by the primary containment isolation SAFETY instrumentation are implicitly assumed in the safety analyses of ANALYSES, References 1 and 2 to initiate closure of valves to limit offsite doses.

LCO, and Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"

APPLICABILITY Applicable Safety Analyses Bases for more detail of the safety analyses.

Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 8) Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-150 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES is APPLICABLE The OPERABILITY of the primary containment instrumentation individual instrumentation SAFETY dependent on the OPERABILITY of the Function must ANALYSES, channel Functions specified in Table 3.3.6.1-1. Each with their setpoints LCO, and have a required number of OPERABLE channels, containment instrumentation is APPLICABILITY The OPERABILITY of the primary individual instrumentation (continued) dependent on the OPERABILITY of the Function must channel Functions specified in Table 3.3.6.1-1. Each with their setpoints have a required number of OPERABLE channels, A channel is within the specified Allowable Values, where appropriate.

not within its required Allowable inoperable if its actual trip setpoint is with applicable Value. The actual setpoint is calibrated consistent must also respond setpoint methodology assumptions. Each channel within its assumed response time, where appropriate.

Isolation Allowable Values are specified for each Primary Containment are specified in Function specified in the Table. Nominal trip setpoints selected to the setpoint calculations. The nominal setpoints are the Allowable Value between ensure that the setpoints do not exceed CHANNEL conservative than CALIBRATIONS. Operation with a trip setpoint less is acceptable.

the nominal trip setpoint, but within its Allowable Value, values of output at which an Trip setpoints are those predetermined compared to the actual action should take place. The setpoints are and when the process parameter (e.g., reactor vessel water level),

the setpoint, measured output value of the process parameter reaches state. The analytic limits are derived the associated device changes parameters obtained from the from the limiting values of the process from the analytic safety analysis. The Allowable Values are derived the instrument limits, corrected for calibration, process, and some of for the errors. The trip setpoints are then determined accounting The trip setpoints derived in remaining instrument errors (e.g., drift).

instrumentation this manner provide adequate protection because drift, uncertainties, process effects, calibration tolerances, instrument function in and severe environment errors (for channels that must by 10 CFR 50.49) are accounted for.

harsh environments as defined OPERABLE in In general, the individual Functions are required to be 3.6.1.1, MODES 1, 2, and 3 consistent with the Applicability for LCO Applicabilities "Primary Containment." Functions that have different are discussed below in the individual Functions discussion.

(continued)

TS / B 3.3-151 Revision 1 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE The specific Applicable Safety Analyses, LCO, and Applicability SAFETY discussions are listed below on a Function by Function basis.

ANALYSES, LCO, and The penetrations which are isolated by the below listed functions can APPLICABILITY be determined by referring to the PCIV Table found in the Bases of (continued) LCO 3.6.1.3, "Primary Containment Isolation Valves."

Main Steam Line Isolation 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 doses from exceeding 10 CFR 100 limits.

(continued)

TS / B 3.3-152 Revision 1 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE l.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 if APPLICABILITY water level condition and the RPV cooling down more than 100°F/hr the pressure loss is allowed to continue. The Main Steam Line (continued)

Pressure-Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2). For this event, the closure of the not MSIVs ensures that the RPV temperature change limit (100°F/hr) is reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded. (This Function closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus reducing reactor power to < 25% RTP.)

The MSL low pressure signals are initiated from four instruments that are connected to the MSL header. The instruments are arranged such that, even though physically separated from each other, each instrument is able to detect low MSL pressure. Four channels of Main to Steam Line Pressure-Low Function are available and are required 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-High Main Steam Line Flow-High is provided to detect a break of the MSL and to initiate closure of the MSIVs. If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Main Steam Line Flow-High Function is directly assumed in the analysis of the main steam line break (MSLB) (Ref. 1). The isolation action, along with the scram function of the Reactor Protection System (RPS), ensures that the fuel peak (continued)

TS / B 3.3-153 Revision 1 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.c. Main Steam Line Flow-High (continued)

SAFETY ANALYSES, LCO, cladding temperature remains below the limits of 10 CFR 50.46 and and offsite doses do not exceed the 10 CFR 100 limits.

APPLICABILITY 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.

The Allowable Value is chosen to prevent damage to the condenser due to pressurization, thereby ensuring its integrity for offsite dose analysis. 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.

(continued)

SUSQUEHANNA- UNIT 2 TS / B 3.3-154 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.e. Reactor Building Main Steam Tunnel Temperature-High SAFETY ANALYSES, LCO, Reactor Building Main Steam Tunnel temperature is provided to detect and APPLICABILITY a leak in the RCPB and provides diversity to the high flow (continued) 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.

There are four push buttons for the logic, two manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the MSL isolation automatic Functions are required to be OPERABLE.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-155 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE Primary Containment Isolation SAFETY

ANALYSES, LCO, and 2.a. Reactor Vessel Water Level - Low, Level 3 APPLICABILITY (continued) 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 dose limits of 10 CFR 100 are not exceeded. The Reactor Vessel Water Level-Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.

Reactor Vessel Water Level-Low, Level 3 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.

2.b. Reactor Vessel Water Level-Low Low, Level 2 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 2 supports actions to ensure that offsite dose limits of 10 CFR 100 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.

2 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 (continued)

TS / B 3.3-156 Revision 1 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.b. Reactor Vessel Water Level - Low Low, Level 2 (continued)

SAFETY ANALYSES, LCO, are required to be OPERABLE to ensure that no single instrument and failure can preclude the isolation function.

APPLICABILITY The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Level 2 Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA.

2.c. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products. The isolation of the primary containment on Level 1 supports actions to ensure the offsite dose limits of 10 CFR 100 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.

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 associated penetrations isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 100 limits.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-157 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.d. Drywell Pressure-High SAFETY

ANALYSES, LCO, and High drywell pressure can indicate a break in the RCPB inside the APPLICABILITY primary containment. The isolation of some of the primary (continued) containment isolation valves on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 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.

2.e. SGTS Exhaust Radiation-High High SGTS Exhaust radiation indicates possible gross failure of the fuel cladding. Therefore, when SGTS Exhaust Radiation High is detected, an isolation is initiated to limit the release of fission products.

However, 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.

(continued)

UNIT 2 TS / B 3.3-158 Revision 1 SUSQUEHANNA -

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.f. Manual Initiation SAFETY

ANALYSES, LCO, and The Manual Initiation push button channels introduce signals into the APPLICABILITY primary containment isolation logic that are redundant to the automatic (continued) 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.

Hiqh Pressure Coolant Iniection and Reactor Core Isolation Coolinq Systems Isolation 3.a., 4.a. HPCI and RCIC Steam Line A Pressure-Hiqh 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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-159 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.a., 4.a. HPCI and RCIC Steam Line A Pressure-Hiqh (continued)

SAFETY ANALYSES, LCO, to the system steam lines. Two channels of both HPCI and RCIC and Steam Line A pressure-High Functions are available and are required APPLICABILITY 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.

3.b., 4.b. HPCI and RCIC Steam Supply Line Pressure-Low Low MSL pressure indicates that the pressure of the steam in the HPCI or RCIC turbine may be too low to continue operation of the associated system's turbine. These isolations are for equipment protection and are not assumed in any transient or accident analysis in the FSAR. However, they also provide a diverse signal to indicate a possible system break. These instruments are included in Technical Specifications (TS) because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).

The HPCI and RCIC Steam Supply Line Pressure-Low signals are initiated from instruments (four for HPCI and four for RCIC) that are connected to the system steam line. Four channels of both HPCI and RCIC Steam Supply Line Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Values are selected to be high enough to prevent damage to the system's turbine.

(continued)

TS / B 3.3-160 Revision 1 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.c., 4.c. HPCI and RCIC Turbine Exhaust Diaphraqm SAFETY Pressure-High ANALYSES, LCO, and APPLICABILITY High turbine exhaust diaphragm pressure indicates that a release of (continued) 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 Diaphragm Pressure-High signals are 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.

The Allowable Values is low enough to identify a high turbine exhaust 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. Drywell Pressure-Hiqh 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-161 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.d., 4.d. Drywell Pressure-High (continued)

SAFETY ANALYSES, LCO, and High drywell pressure signals are initiated from pressure instruments APPLICABILITY 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.

3.e., 3.f., 3.q., 4.e., 4.f., 4.g., HPCI and RCIC Area and Emergency Cooler Temperature-High HPCI and RCIC Area and Emergency Cooler temperatures are provided to detect a leak from the associated system steam piping.

The isolation occurs when a small leak has occurred and is diverse to the high flow instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.

Area and Emergency Cooler Temperature-High signals are initiated from thermocouples that are appropriately located to protect the system that is being monitored. Two instruments monitor each area.

Two channels for each HPCI and RCIC Area and Emergency Cooler Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The HPCI and RCIC Pipe Routing area temperature trips will only occur after a 15 minute time delay to prevent any spurious temperature isolations due to short temperature increases and allows operators sufficient time to determine which system is leaking. The other ambient temperature trips will only occur after a one second time delay to prevent any spurious temperature isolations.

(continued)

SUSQUEHANNA- UNIT 2 TS / B 3.3-162 Revision 1

PPL Rev. 2 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 SAFETY Emergency Cooler Temperature-High (continued)

ANALYSES, LCO, and APPLICABILITY 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.

3.h., 4.h. Manual Initiation The Manual Initiation push button channels introduce signals into the HPCI and RCIC systems' isolation logics that are redundant to the automatic protective instrumentation and provide manual isolation 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. RWCU Differential Flow-High The high differential flow signal is provided to detect a break in the RWCU System. This will detect leaks in the RWCU System when area temperature would not provide detection (i.e., a cold leg break).

Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high differential flow is sensed to prevent exceeding offsite doses. A 45 second time delay is provided to prevent spurious trips during most RWCU operational transients. This Function is not assumed in any (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-163 Revision 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.a. RWCU Differential Flow-High (continued)

SAFETY

ANALYSES, LCO, and FSAR transient or accident analysis, since bounding analyses are APPLICABILITY performed for large breaks such as MSLBs.

The high differential flow signals are initiated from instruments that are connected to the inlet (from the recirculation suction) and outlets (to 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 the FSAR, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.

Area temperature signals are initiated from temperature elements that are located in the area that is being monitored. Six thermocouples provide input to the Area Temperature-High Function (two per area).

Six channels are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The area temperature trip will only occur after a one second time to prevent any spurious temperature isolations.

The Area Temperature-High Allowable Values are set low enough to detect a leak equivalent to 25 gpm.

(continued)

TS / B 3.3-164 Revision 1 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.e. SLC System Initiation SAFETY

ANALYSES, LCO, and The isolation of the RWCU System is required when the SLC System APPLICABILITY has been initiated to prevent dilution and removal of the boron solution (continued) by the RWCU System (Ref. 4). SLC System initiation signals are 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 and 2, since these are the only MODES where the reactor can be critical, with the exception of Special Operations LCO 3.10.8, and these MODES are consistent with the Applicability for the SLC System (LCO 3.1.7).

As noted (footnote (b) to Table 3.3.6.1-1), this Function is only required to close the outboard RWCU isolation valve trip systems.

5.f. Reactor Vessel Water Level-Low Low, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. The isolation of the RWCU System on Level 2 supports actions to ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Vessel Water Level-Low Low, Level 2 Function associated with RWCU isolation is not directly assumed in the FSAR safety analyses because the RWCU System line break is bounded by breaks of larger systems (recirculation and MSL breaks are more limiting).

Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-165 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.f. Reactor Vessel Water Level-Low Low, Level 2 (continued)

SAFETY

ANALYSES, LCO, and Reactor Vessel Water Level-Low Low, Level 2 Function are available APPLICABILITY 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 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- Hi+/-qh RWCU Flow-High Function is provided to detect a break of the RWCU System. Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation is initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit for this Function is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks.

The RWCU Flow-High signals are initiated from two instruments. Two channels of RWCU Flow-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The RWCU flow trip will only occur after a 5 second time delay to prevent spurious trips.

The Allowable Value is chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event.

(continued)

TS / B 3.3-166 Revision 2 SUSQUEHANNA - UNIT 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.h. Manual Initiation SAFETY

ANALYSES, LCO, and The Manual Initiation push button channels introduce signals into the APPLICABILITY RWCU System isolation logic that are redundant to the automatic (continued) 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 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 2 TS / B 3.3-167 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASESI APPLICABLE 6.b. Reactor Vessel Water Level-Low, Level 3 SAFETY

ANALYSES, LCO, and Low RPV water level indicates that the capability to cool the fuel may APPLICABILITY be threatened. Should RPV water level decrease too far, fuel damage (continued) could result. Therefore, isolation of some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low, Level 3 Function associated with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by breaks of the recirculation and MSL.

The RHR Shutdown Cooling System isolation on Level 3 supports actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.

Reactor Vessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. As noted (footnote (c) to Table 3.3.6.1-1), only two channels of the Reactor Vessel Water Level-Low, Level 3 Function are required to be OPERABLE in MODES 4 and 5 (and must input into the same trip system), provided the RHR Shutdown Cooling System integrity is maintained. System integrity is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low, Level 3 Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level-Low, Level 3 Function is only required to be OPERABLE in MODES 3, 4, and 5 to prevent this potential flow path from lowering the reactor vessel level to the top of the fuel.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-168 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. Reactor Vessel Water Level-Low, Level 3 (continued)

SAFETY

ANALYSES, LCO, and In MODES 1 and 2, another isolation (i.e., Reactor Steam Dome APPLICABILITY Pressure-High) and administrative controls ensure that this flow path remains isolated to prevent unexpected loss of inventory via this flow path.

6.c Manual Initiation The Manual Initiation push button channels introduce signals to RHR Shutdown Cooling System isolation logic that is redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.

There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 3, 4, and 5, since these are the MODES in which the RHR Shutdown Cooling System Isolation automatic Function are required to be OPERABLE.

Traversing Incore Probe System Isolation 7.a Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products. The isolation of the primary containment on Level 3 supports actions to ensure that offsite dose limits of 10 CFR 100 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 2 TS / B 3.3-169 Revision 1

PPL Rev. 2 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 APPLICABILITY to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Two channels of Reactor Vessel Water Level - Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent isolation actuation. The isolation function is ensured by the manual shear valve in each penetration.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.

7-b. Drvwell Pressure - Hiah High drywell pressure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 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 2 TS / B 3.3-170 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS The ACTIONS are modified by two Notes. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable primary containment isolation instrumentation channel.

A.1 Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours1.388889e-4 days 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 2 TS / B 3.3-171 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS B.1 and B.2 (continued)

Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path(s). The MSL Isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function. For Functions 1.a, 1.b, 1.d, and 1.e, this would require both trip systems to have one channel OPERABLE or in trip. For Function 1.c, this would require both trip systems to have one channel, associated with each MSL, OPERABLE or in trip. Therefore, this would require both trip systems to have one channel per location OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, 3.b, 3.c, 3.d, 4.b, 4.c, 4.d, 5.f, and 6.b, this would require one trip system to have two channels, each OPERABLE or in trip. For Functions 2.e, 3.a, 3.e, 3.f, 3.g, 4.a, 4.e, 4.f, 4.g, 5.a, 5.b, 5.c, 5.d, 5.e, 5.g, and 6.a, this would require one trip system to have one channel OPERABLE or in trip.

The Condition does not include the Manual Initiation Functions (Functions 1.f, 2.f, 3.h, 4.h, 5.h, and 6.c), since they are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days 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.

C.1 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-172 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS D.1, D.2.1, and D.2.2 (continued)

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.

F. 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.

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).

(continued)

SUSQUEHANNA- UNIT 2 TS / B 3.3-173 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS G. 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. 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.

H.1 and H.2 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-174 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS 1.1 and 1.2 (continued 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.

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 comparison of the parameter indicated on one (continued)

SUSQUEHANNA- UNIT 2 TS / B 3.3-175 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.1 (continued)

REQUIREMENTS 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.

SR 3.3.6.1.2 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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-176 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.2 (continued)

REQUIREMENTS 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 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-177 Revision 1

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3,6.1 BASES SURVEILLANCE SR 3.3.6.1.3 and SR 3.3.6.1.4 (continued)

REQUIREMENTS It should be noted that some of the Primary Containment High Drywell pressure instruments, although only required to be calibrated as a 24 month Frequency, are calibrated quarterly based on the 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.

SR 3.3.6.1.6 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 Function 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.

(continued)

SUSQUEHANNA- UNIT 2 TS / B 3.3-178 Revision 2

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 (continued)

REQUIREMENTS Function l.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 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-179 Revision 3

PPL Rev. 2 Primary Containment Isolation Instrumentation B 3.3,6.1 BASES REFERENCES 6. NEDC-30851P-A Supplement 2, "Technical Specifications (continued) 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 P-A "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.

10. PPL Letter to NRC, PLA-2618, Response to NRC INSPECTION REPORTS 50-387/85-28 AND 50-388/85-23, dated April 22, 1986.

11. NRC Inspection and Enforcement Manual, Part 9900:

Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.

12. Susquehanna Steam Electric Station NRC REGION I COMBINED INSPECTION 50-387/90-20; 50-388/90-20, File R41-2, dated March 5, 1986.

13. NRC Safety Evaluation Report related to Amendment No. 171 for License No. NPF-14 and Amendment No. 144 for License No. NPF-22.

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

October 1999.

15. NEDO 32291, Supplement 1, Addendum 2, "System Analyses for the Elimination of Selected Response Time Testing Requirements," September 5, 2003.

SUSQUEHANNA - UNIT 2 TS / B 3.3-179a Revision 2

PPL Rev. 1 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 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 2 TS / B 3.6-1 Revision 2

PPL Rev. 1 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 H20 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-22361, SV-22365, SV-22366, SV-22368, and SV-22369). These solenoid operated isolation valves do not fully meet the guidance of Reference 7 for closed system boundary valves in that they are not powered from a Class 1 E power source. Based upon a risk determination, operating these valves as closed system boundary valves is not risk significant.

These normally closed valves are required to be leakage rate tested in accordance with the Leakage Rate Test Program, since they form part of the closed system boundary for the H20 2 Analyzers. These valves are Aclosed system boundary valves@

and may be opened under administrative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

When the H 2 0 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 2 TS / B 3.6-1 a Revision 3

PPL Rev. 1 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 doses. The fission product release is, in turn, based on an assumed leakage rate from the primary containment.

OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.

The maximum allowable leakage rate for the primary containment (La) is 1.0% by weight of the containment air per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the design basis LOCA maximum peak containment pressure (Pa) of 45 psig.

Primary containment satisfies Criterion 3 of the NRC Policy Statement. (Ref. 6)

LCO Primary containment OPERABILITY is maintained by limiting leakage to *1.0 L, 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 2 TS /B 3.6-2 Revision 2

PPL Rev. 1 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 refuel outage.

(continued)

SUSQUEHANNA-UNIT2 TS /B 3.6-3 Revision 3

PPL Rev. 1 Primary Containment B 3.6,.11 BASES SURVEILLANCE SR 3.6.1.1.1 (continued)

REQUIREMENTS 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.

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 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 filled or a water seal remains in the line post-LOCA are tested with water and the leakage is not included in the Type B and C 0.60 La test.

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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-4 Revision 3

PPL Rev. 1 Primary Containment B 3.6.1.1 BASES SURVEILLANCE REQUIREMENTS SR 3.6.1.1.2 (continued)

The allowable limit is 10% of the acceptable SSES Afqk design value. 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 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-5 Revision 3

PPL Rev. 1 Primary Containment B 3.6.1.1 BASES SURVEILLANCE REQUIREMENTS SR 3.6.1.1.3 (continued)

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

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 2 TS / B 3.6-6 Revision 4

PPL Rev. 1 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 1 of 2)

PENETRATION INSTRUMENT INSTRUMENT ISOLATION NUMBER VALVE X-3B PSH-C72-2NO02A IC-PSH-2N002A PSH L C72-2N004 IC-PSHL-2N004 PS-E11-2NO10A IC-PS-2N010A PS-E11-2NO11A IC-PS-21N011A PSH-C72-2N002B IC-PSH-2N002B PS-El1-2NO10C IC-PS-2NO10C PS-E11-2NO11C IC-PS-2NO11C PSH-25120C IC-PSH-25120C X-32A PSH-C72-2N002D IC-PSH-2N002D PS-El1-2NO10B IC-PS-21N010B PS-El1-2N01 1B IC-PS-2N011 B PSH-C72-2N002C IC-PSH-2N002C PS-Ell-2NO10D IC-PS-2NO10D PS-E11-2N01 1D IC-PS-2N01 1D PSH-25120D IC-PSH-25120D X-39A FT-25120A IC-FT-25120A HIGH and IC-FT-25120A LOW X-39B FT-25120B IC-FT-25120B HIGH and IC-FT-25120B LOW X-90A PT-25709A IC-PT-25709A PT-25710A IC-PT-25710A PT-25728A1 IC-PT-25728A1 X-90D PT-25709B IC-PT-25709B PT-25710B IC-PT-25710B PT-25728A IC-PT-25728A SUSQUEHANNA - UNIT 2 TS / B] 3.6-6a Revision 2

PPL Rev. 1 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 2 of 2)

PENETRATION INSTRUMENT INSTRUMENT ISOLATION NUMBER VALVE X-204A/205A FT-25121A IC-FT-25121A HIGH and IC-FT-25121A LOW X-204B/205B FT-25121B IC-FT-25121A HIGH and IC-FT-25121A LOW X-219A LT-25775A IC-LT-25775A REF and IC-LT-25775A VAR LSH-E41-2N015A 255027 and 255031 LSH-E41-2N015B 255029 and 255033 X-223A PT-25702 IC-PT-25702 X-232A LT-25776A IC-LT-25776A REF and IC-LT-25776A VAR PT-25729A IC-PT-25729A X234A LT-25775B IC-LT-25775B REF and IC-LT-25775B VAR X-235A LT-25776B IC-LT-25776B REF and IC-LT-25776B VAR PT-25729B IC-PT-25729B LI-25776B2 IC-LT-25776B2 REF and IC-LT-25776B2 VAR SUSQUEHANNA - UNIT 2 TS / B 3.6-6b Revision 2

PPL Rev. 1 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 257138 257139 257140 257141 257142 X-80C, X-221B, X-238B 257149 257150 257151 257152 257153 (a) Only those valves listed in this table with current leak rate test results, as identified in the Leakage Rate Test Program, may be used as isolation valves.

SUSQUEHANNA - UNIT 2 TS / B 3.6-6c Revision 0

ML071090068

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: