ML052910076
| ML052910076 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 10/06/2005 |
| From: | Susquehanna |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 028401 TSB2, Rev 1 | |
| Download: ML052910076 (98) | |
Text
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MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2005-43306 USER INFORMA TN:
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SSES MANUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Table Of Contents Issue Date:
10/05/2005 Procedure Name Rev TEXT LOES 63
Title:
LIST OF EFFECTIVE SECTIONS Issue Date 10/05/2005 Change ID Change Number TEXT TOC
Title:
TABLE OF CONTENTS 7
04/18/2005 TEXT 2.1.1 1
Title:
SAFETY LIMITS (SLS) REACTOR 10/27/2 004 CORE SLS I
j 1 j TEXT 2.1.2
Title:
SAFETY LIMITS (SLS) RI TEXT 3.0
Title:
LIMITING CONDITION FOE TEXT 3.1.1
Title:
REACTIVITY CONTROL SY' 0
EACTOR 11/18/2002 COOLANT SYSTEM SURE SL 1
1 MARGIN (SDM)
TEXT 3.1.2 0
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 2
07/06/2005
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 Pagel of 8 Report Date: 10/05/05 Page 1 of 8
Report Date: 10/05/05
-1 SSES MANUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.1.7 1
08/30/2005
Title:
REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 0
11/18/2002
Title:
REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 2
10/05/2005
Title:
POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
TEXT 3.2.2 1
03/24/2005
Title:
POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)
I[
TEXT 3.2.3
Title:
POWER DISTRIBUTION TEXT 3.2.4
Title:
POWER DISTRIBUTION TEXT 3.3.1.1 0
11/18/2002 LIMITS LINEAR HEAT GENERATION RATE (LHGR) 1 07/06/2005 LIMITS AVERAGE POWER RANGE MONITOR (APRM) GAIN AND SETPOINTS 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 TEXT 3.3.1.3
Title:
OPRM INSTRUMENTATION 0
11/22/2004 TEXT 3.3.2.1 1
02/17/2005
Title:
INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 0
11/18/2002
Title:
INSTRUMENTATION FEEDWATER -
MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 2
07/06/2005
Title:
INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION Page2 of 8 Report Date: 10/05/05 Page 2 of 8 Report Date: 10/05/05
SSES MANUAL Manual Name:
TSB2 Manual
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 1
11/09/2004
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 1
09/02/2004
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 Page3 of 8 Report Date: 10/05/05 Page 3 of 8 Report Date: 10/05/05
-1
-- "r-SSES MANUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL jf TEXT 3.4.3 0
Title:
TEXT 3.4.4 0
Title:
TEXT 3.4.5 0
Title:
TEXT 3.4.6 1
Title:
TEXT 3.4.7 1
Title:
TEXT 3.4.8 1
Title:
HOT SHUTDOWN 11/18/2 002 SAFETY/RELIEF VALVES (S/RVS) 11/18/2002 RCS OPERATIONAL LEAKAGE 11/18/2002 RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE 04/18/2005 RCS LEAKAGE DETECTION INSTRUMENTATION 04/18/2005 RCS SPECIFIC ACTIVITY 04/18/2005 RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM-`
TEXT 3.4.9
Title:
REACTOR COOLANT COLD SHUTDOWN 0
11/18/2002 SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM TEXT 3.4.10 0
11/18/2002
Title:
REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATUR.E (P/T) LIMITS TEXT 3.4.11 0
11/18/2002
Title:
REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 2
10/05/2005
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM ECCS -
OPERATING TEXT 3.5.2 0
11/18/2002
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM ECCS -
SHUTDOWN TEXT 3.5.3 1
04/18/2005
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM RCIC SYSTEM Page4 of 8 Report Date: 10/05/05 Page 4 of 8 Report Date: lo/05/05
SSES MANUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.1.1
Title:
CONTAINMENT 0
SYSTEMS PRIMARY 11/18/2002 CONTAINMENT TEXT 3.6.1.2
Title:
CONTAINMENT 0
11/18/2002 SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3
Title:
CONTAINMENT 2
08/24/2005 SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)
TEXT 3.6.1.4 0
11/18/2002
Title:
CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 1
10/05/2005
Title:
CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE TEXT 3.6.1.6 0
11/18/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS TEXT 3.6.2.1 0
11/18/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 0
11/18/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 0
11/18/2002
Title:
CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 0
11/18/2002
Title:
CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 1
04/18/2005
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT HYDROGEN RECOMBINERS TEXT 3.6.3.2 1
04/18/2005
Title:
CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM PageS of 8
Report Date: 10/05/05 Page 5 of 8 Report Date: 10/05/05
SSES MANUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL AJIi TEXT 3.6.3.3 0
11/18/2002
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 3
10/05/2005
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 2
11/09/2004
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 I
TEXT 3.7.3 0
11/18/2002
Title:
PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM TEXT 3.7.4
Title:
PLANT SYSTEMS 0
11/18/2002 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 3
10/05/2005
Title:
ELECTRICAL POWER SYSTEMS AC SOURCES -
OPERATING Page 6 of 8 Report Date: 10/05/05 Page 6 of 8 Report Date: lo/05/05
SSES MANUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.8.2
Title:
ELECTRICAL TEXT 3.8.3
Title:
ELECTRICAL TEXT 3.8.4
Title:
ELECTRICAL TEXT 3.8.5
Title:
ELECTRICAL TEXT 3.8.6
Title:
ELECTRICAL TEXT 3.8.7 l
-Title: ELECTRICAL TEXT 3.8.8
Title:
ELECTRICAL 0
11/18/2002 POWER SYSTEMS AC SOURCES -
SHUTDOWN 0
11/18/2002 POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR 0
11/18/2002 POWER SYSTEMS DC SOURCES -
OPERATING 0
11/18/2002 POWER SYSTEMS DC SOURCES -
SHUTDOWN 0
11/18/2002 POWER SYSTEMS BATTERY CELL PARAMETERS 1
10/05/2005 POWER SYSTEMS DISTRIBUTION SYSTEMS -
OPERATING
-0 11/18/2002 POWER SYSTEMS DISTRIBUTION SYSTEMS -
SHUTDOWN TEXT 3.9.1 0
11/18/2002
Title:
REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 0
11/18/2002
Title:
REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 0
11/18/2002
Title:
REFUELING OPERATIONS CONTROL ROD POSITION TEXT 3.9.4 0
11/18/2002
Title:
REFUELING OPERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0
11/18/2002
Title:
REFUELING OPERATIONS CONTROL ROD OPERABILITY -
REFUELING Page 7 of 8 Report Date: 10/05/05 Page 7 of 8 Report Date: 10/05/05
SSES MA1NUAL Manual Name:
TSB2 Manual
Title:
TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Llt TEXT 3.9.7 0
11/18/2002
Title:
REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR)
TEXT 3.9.8 0
11/18/2002
Title:
REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR)
HIGH WATER LEVEL LOW WATER LEVEL TEXT 3.10.1
Title:
SPECIAL TEXT 3.10.2
Title:
SPECIAL TEXT 3.10.3
Title:
SPECIAL TEXT 3.10.4
Title:
SPECIAL TEXT 3.10.5
Title:
SPECIAL TEXT 3.10.6
Title:
SPECIAL TEXT 3.10.7
Title:
SPECIAL TEXT 3.10.8
Title:
SPECIAL 0
11/18/2002 OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION 0
11/18/2002 OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING 0
11/18/2002 OPERATIONS SINGLE CONTROL ROD WITHDRAWAL -
HOT SHUTDOWN 0
11/18/2002 OPERATIONS SINGLE CONTROL ROD WITHDRAWAL -
COLD SHUTDOWN 0
11/18/2002 OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL -
REFUELING 0
11/18/2002 OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL -
REFUELING 1
03/24/2005 OPERATIONS CONTROL ROD TESTING -
OPERATING 1
03/24/2005 OPERATIONS SHUTDOWN MARGIN (SDM) TEST -
REFUELING
-I Page8 of 8 Report Date: 10/05/05 Page 8 of 8 Report Date: lo/05/05
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title
- Revision TOC B 2.0 Table of Contents SAFETY LIMITS BASES PageTS/B2.0-1 Page TS l B 2.0-2 Page TS / B 2.0-3 Page TS I B 2.0-4 Page TS/B2.0-5 Pages B 2.0-6 through B 2.0-8 7
2 3
4 1
0 B 3.0 B 3.1 LCO AND SR APPLICABILITY BASES Pages B 3.0-1 through B 3.0-4 Pages TS / B 3.0-5 through TS / B 3.0-7 Pages TS / B 3.0-8 through TS / B 3.0-9 Pages TS / B 3.0-10 through TS / B 3.0-12 Pages TS / B 3.0-13 through TS / B 3.0-154 Pages TS / B 3.0-16 and TS / B 3.0 A
=
.=.s s=.
f REACTIVITY CONTROL BASES Pages B 3.1-1 through B 3.1-4 Page TS / B 3.1-5 Pages TS lB 3.1-6 and TS B Pages B 3.1-8 through B,
- PageTS.B13.1-14 Pages B 3.1-15throu~FFBT Page TS I B 3.1-2 s
Pages B 3.1-24:
Page TS / B 3.1-Page TS / 3.-,9-ir Pages B"3-Ihough B 3.1-^
Page s 7534 through T' PaoeS I B.1-37 AL 27 33 S / B 3.1-36 0
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27^.1-38 Page z 3.1-39 through B 3.1-44 ge'S/B 3.1-45 Ps B 3.1-46 through B 3.1-51 B 3.2 POWER DISTRIBUTION LIMITS BASES Pages TS / B 3.2-1 and TS / B 3.2-2 Page TS I B 3.2-3 Page TS I B 3.2-4 Pages TS I B 3.2-5 and TS / B 3.2-6 Page TS I B 3.2-7 Pages TS / B 3.2-8 and TS / B 3.2-9 Pages TS I B 3.2-10 through TS / B 3.2-17 Page TS / 3.2-18 Page TS / 3.2-19 v -
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- UNIT 2 TS/BLOES-1 Revision 63 SUSQUEHANNA - UNIT 2 TS I B LOES-1 Revision 63
I 7
1 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through TS / B 3.3-4 Page TS / B 3.3-5 PageTS/B3.3-6 Page TS / B 3.3-7 Pages TS / B 3.3-8 through TS / B 3.3-11 PageTS/B3.3-12 Page TS / B 3.3-13 Page TS / B 3.3-14 Pages TS / B 3.3-15 and TS / B 3.3-16 Pages TS / B 3.3-17 and TS / B 3.3-18 Pages TS / B 3.3-19 through TS / B 3.3-27 Pages TS / B 3.3-28 through TS / B 3.3-30 Page TS / B 3.3-31 Page TS / B 3.3-32 Page Ts I B 3.3-33 Pages TS / B 3.3-34 through TS / B 3.3-43 Pages TS / B 3.3-43a though TS / B 3.3-43i Pages TS I B 3.3-44 through TS I B 3.3-54 Pages B 3.3-55 through B 3.3-63 Pages TS / B 3.3-64 and TS I B 3.3-65 Page TS / B 3.3-66 Page TS I B 3.3-67 Page TS IB 3.3-68 Pages TS I B 3.3-69 and TS I B 3.3-70 Pages TS I B 3.3-71 Pages TS I B 3.3-72 through TS I B 3.3-75 Page TS I B 3.3-75a Pages TS / B 3.3-75b and TS / B 3.3-75c Pages B 3.3-76 through TS / B 3.3-77 Page TS / B 3.3-78 Pages B 3.3-79 through B 3.3-91 Pages TS / B 3.3-92 through TS / B 3.3-103 Page TS / B 3.3-104 Pages TS / B 3.3-105 and TS / B 3.3-106 Page TS / B 3.3-107 Page TS / B 3.3-108 Page TS / B 3.3-109 Pages TS / B 3.3-110 through TS B 3.3-112 Page TS / B 3.3-113 Page TS / B 3.3-114 Page TS / B 3.3-115 Pages TS / B 3.3-116 through TS / B 3.3-118 Pages TS / B 3.3-119 through TS / B 3.3-120 Pages TS / B 3.3-121 and TS B 3.3-122 PageTS/B3.3-123 I
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- UNIT 2 TS/BLOES-2 Revision 63 SUSQUEHANNA - UNIT 2 TS /B LOES-2 Revision 63
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page TS / B 3.3-124 2
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Page TS / B 3.3-125 1
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PageTS/B3.3-127 3
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Page TS / B 3.3-132 2
Pages TS / B 3.3-133 and TS / B 3.3-134 1
Pages B 3.3-135 through B 3.3-137 0
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Pages B 3.3-139 through B 3.3-149 0
Pages TS/ B 3.3-150 through TS / B 3.3-162 1
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Pages TS / B 3.3-164 through TS B 3.3-177 1
Page TS / B 3.3-178 2
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Page TS / B 3.3-179a 2
Page TS / B 3.3-180 1
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Pages TS I B 3.3-182 through TS/ B 3.3-186 1
Pages TS / B 3.3-187 and TS I B 3.3-188 2
Pages TS I B 3.3-189 through TS I B 3.3-191 Pages B 3.3-192 through B 3.3-205 0
PageTS/B3.3-206 1
Pages B 3.3-207 through B 3.3-220 0
B 3.4 REACTOR COOLANT SYSTEM BASES Pages TS / B 3.4-1 and TS / B 3.4-2 1
Pages TS / B 3.4-3 through TS / B 3.4-9 3
Pages B 3.4-10 through B 3.4-14 0
Page TS / B 3.4-15 1
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SUSQUEHANNA
- UNIT 2 TSIBLOES-3 Revision 63 SUSQUEHANNA - UNIT 2 TS / B LOES-3 Revision 63
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Pages TS I B 3.4-54 and TS I B 3.4-55 2
Pages TS / B 3.4-56 through TS / B 3.4-60 1
B 3.5 ECCS AND RCIC BASES Pages TS I B 3.5-1 and TS / B 3.5-2 1
Pages TS / B 3.5-3 through TS / B 3.5-6 2
Pages TS / B 3.5-7 through TS J B 3.5-10 1
PageTS/B3.5-11 2
Pages TS I B 3.5-12 through TS / B 3.5-14 1
Pages TS I B 3.5-15 and TS / B.3.5-16 2
Page TS / B 3.5-17 3
Page TS / B 3.5-18 1
Pages B 3.5-19 through B 3.5-24 0
Pages TS I B 3.5-25 through TS / B 3.5-27 1
Pages B 3.5-28 through B 3.5-31 0
B 3.6 CONTAINMENT SYSTEMS BASES Page TS / B 3.6-1 2
Page TS / B 3.6-1a 3
Pages TS I B 3.6-2 through TS / B 3.6-5 2
Page TS / B 3.6-6 3
Pages TS / B 3.6-6a and TS / B 3.6-6b 2
Page TS / B 3.6-6c 0
Pages B 3.6-7 through B 3.6-14 0
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Pages TS I B.3.6-15a and TS / B 3.6-15b 0
Page TS I B 3.6-16 1
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Pages TS I B 3.6-22 and TS / B 3.6-23 2
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Page TS I B 3.6-38 1
SUSQUEHANNA
- UNIT 2 TS/BLOES-4 Revision 63 SUSQUEHANNA - UNIT 2 TS I B LOES-4 Revision 63
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page TS I B 3.6-39 4
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B 3.7 PLANT SYSTEMS BASES Pages TS / B 3.7-1 through TS / B 3.7-6 2
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SUSQUEHANNA
- UNIT 2 TSIB LOES-5 Revision 63 SUSQUEHANNA - UNIT 2 TS /B LOES-5 Revision 63
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision B 3.8 ELECTRICAL POWER SYSTEMS BASES Pages B 3.8-1 through B 3.8-4 0
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B 3.9 REFUELING OPERATIONS-BASES Pages TS/ B 3.9-1 and TS/ B 3.9-2 Page TS/ B 3.9-2a 1
Pages TS / B 3.9-3 and TS/ B 3.9-4 1
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B 3.10 SPECIAL OPERATIONS BASES PageTS/B3.10-1 1
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SUSQUEHANNA
- UNIT 2 TS/BLOES-8 Revision 63 SUSQUEHANNA - UNIT 2 TS / B LOES-6 Revision 63
PPL Rev. 2 APLHGR B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
BASES BACKGROUND The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on the APLHGR are specified to ensure that limits specified in 10 CFR 50.46 are not exceeded during the postulated design basis loss of coolant accident (LOCA).
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APPLICABLE SAFETY ANALYSES SPC performed LOCA calculations for the SPC ATRIUM-10 fuel design. The analytical methods and assumptions used in evaluating the fuel design limits from 10 CFR 50.46 are presented in References 3, 4, 5, and 6 for the SPC analysis. The analytical methods and assumptions used in evaluating Design Basis Accidents (DBAs) that determine the APLHGR Limits are presented in References 3 through 9.
I I
I LOCA analyses are performed to ensure that the APLHGR limits are adequate to meet the Peak Cladding Temperature-(PCT), maximum cladding oxidation, and maximum hydrogen generation limits of 10 CFR 50.46. The analyses are performed using calculational models that are consistent with the requirements of 10 CPR 50,;Appendix K.
A complete discussion of the analysis codes are provided in References 3, 4, 5, and 6 for the SPC analysis; The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within the assembly.
APLHGR limits are developed as a function of fuel type and exposure.
The SPC analysis is valid for full cores of ATRIUM
-10 fuel. The SPC LOCA analyses also consider several alternate operating modes in the development of the APLHGR limits (e.g. Extended Load Line Limit Analysis (ELLA), Suppression Pool Cooling Mode, and Single Loop Operation (SLO)). LOCA analyses were performed for the regions of the power/flow map bounded by the 100% rod line and the APRM rod block line (i.e., the ELLA region). The ELLA region is analyzed to determine whether an APLHGR multiplier as a function of core flow is required. The results of the analysis demonstrate the PCTs are within the 10 CFR 50.46 limit, and that APLHGR multipliers as a function of core flow are not required.
I (continued)
-USQUE--NN - UNI 2
-B 3.2-Revisi.....
on,I :...A.,g SUSQUEHANNA - UNIT 2 TS / B 3.2-1 Revision 1
PPL Rev. 2 APLHGR B 3.2.1 BASES APPLICABLE SAFETY ANALYSES (continued)
The SPC LOCA analyses consider the delay in Low Pressure Coolant Injection (LPCI) availability when the unit is operating in the Suppression Pool Cooling Mode. The delay in LPCI availability is due to the time required to realign valves from the Suppression Pool Cooling Mode to the LPCI mode. The results of the analyses demonstrate that the PCTs are within the 10 CFR 50.46 limit.
Finally, the SPC LOCA analyses were performed for Single-Loop Operation. The results of the SPC analysis for ATRIUM
-10 fuel shows that an APLHGR limit which is 0.8 times the two-loop APLHGR limit meets the 10 CFR 50.46 acceptance criteria, and that the PCT is less than the limiting two-loop PCT.
The APLHGR satisfies Criterion 2 of the NRC Policy Statement (Ref.
10).
LCO The APLHGR limits specified in the COLR are the result of the DBA analyses.
APPLICABILITY The APLHGR limits are primarily derived-from.LOCA analyses that are assumed to occur at high power levels. Design calculations and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases. At THERMAL POWER levels < 25% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.
ACTIONS A.1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a DBA occurring simultaneously with the APLHGR out of specification.
(continued)
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SUSQUEHANNA - UNIT 2 TS / B 3.2-2 Revision 1
PPL Rev. 2 APLHGR B 3.2.1 BASES ACTIONS B.1 (continued)
If the APLHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE REQUIREMENTS SR 3.2.1.1 APLHGRs are required to be initially calculated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER is Ž 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter.
Additionally, APLHGRs must be calculated prior to exceeding 50%
RTP unless performed in the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. APLHGRs are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowance after THERMAL POWER
Ž 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and beca-use the APLHGRs must be calculated prior to exceeding 50% RTP.
REFERENCES
- 1.
Not Used
- 2.
Not Used
- 3.
EMF-2361(P)(A), "EXEM BWR-2000 ECCS Evaluation Model,"
..Framatome ANP.
- 4.
EMF-2292(P)(A) Revision 0, "ATRIUM'-10:
Appendix K Spray Heat Transfer Coefficients."
- 5.
XN-CC-33(P)(A) Revision 1, "HUXY: A Generalized Multirod Heatup Code with I OCFR50 Appendix K Heatup Option Users Manual," November 1975.
t-;
(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.2-3 Revision 3
PPL Rev. 2 APLHGR B 3.2.1 BASES REFERENCES (continued)
- 6.
XN-NF-80-19(P)(A), Volumes 2, 2A, 2B, and 2C "Exxon Nuclear Methodology for Boiling Water Reactors: EXEM BWR ECCS Evaluation Model," September 1982.
- 7.
FSAR, Chapter 4.
- 8.
FSAR, Chapter 6.
- 9.
FSAR, Chapter 15.
- 10.
Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
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H SUSQUEHANNA-UNIT 2 TS / B3.2-4 Revision 1
PPL Rev. 2 ECCS-Operating B 3.5.1 B 3.5 B 3.5.1 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS-Operating BASES-BACKGROUND
- I; S.
The ECCS is designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core Spray (CS) System, the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR)
System, and the Automatic Depressurization System (ADS). The suppression pool provides the required source of water for the ECCS.
Although no credit is taken in the safety analyses for the condensate storage tank (CST), it is capable of providing a source of water for the HPCI and CS systems.
On receipt of an initiation signal, ECCS pumps automatically start; simultaneously, the system aligns and the pumps inject water, taken either from the CST or suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is overcome by the discharge pressure of the ECCS pumps. Although the system is initiated,-ADS action is delayed, allowing the-operator to interrupt the timed sequence if the system is not needed.
The HPCI pump discharge pressure quickly exceeds that of the RCS, and the pump injects coolant into the vessel to cool the core. If the break is small, the HPCI System will maintain coolant inventory as well as vessel level while the RCS is still pressurized. If HPCI fails, it is backed up by ADS in combination with LPCI and CS. In this event absent operator action, the ADS timed sequence would time out and open the selected safety/relief valves (S/RVs) depressurizing the RCS, thus allowing the LPCI and CS to overcome RCS pressure and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly and the LPCI and CS cool the core.
Water from the break returns to the suppression pool where it is used again and again. Water in the suppression pool is circulated through a heat exchanger cooled by the RHR Service Water System. Depending on the location and size of the break, portions of the ECCS may be ineffective; (continued)
SUSQUEHANNA - UNIT 2 TS I B 3.5-1 Revision 1
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES BACKGROUND however, the overall design is effective in cooling the core regardless of (continued) the size or location of the piping break. Although no credit is taken in the safety analysis for the RCIC System, it performs a similar function as HPCI, but has reduced makeup capability. Nevertheless, it will maintain inventory and cool the core while the RCS is still pressurized following a reactor pressure vessel (RPV) isolation.
All ECCS subsystems are designed to ensure that no single active component failure will prevent automatic initiation and successful operation of the minimum required ECCS equipment.
The CS System (Ref. 1) is composed of two independent subsystems.
Each subsystem consists of two motor driven pumps, a spray sparger above the core, and piping and valves to transfer water from the suppression pool to the sparger. The CS System is designed to provide cooling to the reactor core when reactor pressure is low. Upon receipt of an initiation signal, the CS pumps in both subsystems are automatically started when AC power is available. When the RPV pressure drops sufficiently, CS System flow to the RPV begins. A full flow test line is provided to route water from and to the suppression pool to allow testing of the CS System without spraying water in the RPV.
LPCI is an-independent operating mode-of the RHR System. There are two LPCI subsystems (Ref. 2), each consisting of two motor driven pumps and piping and valves to transfer water from the suppression pool to the RPV via the corresponding recirculation loop. The two LPCI subsystems can be interconnected via the RHR System cross tie valves; however, at least one of the two cross tie valves is maintained closed with its power removed to prevent loss of both LPCI subsystems during a LOCA. The LPCI subsystems are designed to provide core cooling at low RPV pressure. Upon receipt of an initiation signal, all four LPCI pumps are automatically started. RHR System valves in the LPCI flow path are automatically positioned to ensure the proper flow path for water from the suppression pool to inject into the recirculation loops. When the RPV pressure drops sufficiently, the LPCI flow to the RPV, via the corresponding recirculation loop, begins. The water then enters the reactor through the jet pumps.
(continued)
SUSQUEHANNA - UNIT 2 TS I B 3.5-2 Revision 1
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES BACKGROUND Full flow test lines are provided for each LPCI subsystem to route water (continued) from the suppression pool, to allow testing of the LPCI pumps without injecting water into the RPV. These test lines also provide suppression pool cooling capability, as described in LCO 3.6.2.3, "RHR Suppression Pool Cooling."
The HPCI System (Ref. 3) consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the feedwater system line, where the coolant is distributed within the RPV through the feedwater sparger. Suction piping for the system is provided from the CST and the suppression pool. Pump suction for HPCI is normally aligned to the CST source to minimize injection of suppression pool water into the RPV. Whenever the CST water supply is low, an automatic transfer to the suppression pool water source ensures an adequate suction head for the pump and -an uninterrupted water supply for continuous operation of the HPCI System. The steam supply to the HPCI turbine is piped from a main steam line upstream of the associated inboard main steam isolation valve.
The HPCI System is designed to provide core cooling for a wide range of reactor pressures (165 psia to 1225 psia)
Upon receipt of an initiation signal, the HPCI turbine stop valve and turbine control valve open and the turbine accelerates to a specified speed. As the HPCI flow increases, the turbine control valve is automatically adjusted to maintain design flow.
Exhaust steam from the HPCI turbine is discharged to the suppression pool. A full flow test line is provided to route water to the CST to allow testing of the HPCI System during normal operation without injecting water into the RPV.
The ECCS pumps are provided with minimum flow bypass lines, which discharge to the suppression pool. The valves in these lines automatically open to prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, all ECCS pump discharge lines are filled with water. The HPCI, LPCI and CS System discharge lines are kept full of water using a "keep fill" system that is supplied using the condensate transfer system.
(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.5-3 Revision 2
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES BACKGROUND (continued)
The ADS (Ref. 4) consists of 6 of the 16 S/RVs. It is designed to provide depressurization of the RCS during a small break LOCA if HPCI fails or is unable to maintain required water level in the RPV. ADS operation reduces the RPV pressure to within the operating pressure range of the low pressure ECCS subsystems (CS and LPCI), so that these subsystems can provide coolant inventory makeup. Each of the S/RVs used for automatic depressurization is equipped with two gas accumulators and associated inlet check valves. The accumulators provide the pneumatic power to actuate the valves.
APPLICABLE SAFETY ANALYSES The ECCS performance is evaluated for the entire spectrum of break sizes for a postulated LOCA. The accidents for which ECCS operation is required are presented in References 5, 6, and 7. The required analyses and assumptions are defined in Reference 8. The results of these analyses are also described in Reference 9.
This LCO helps to ensure that the following acceptance criteria for the ECCS, established by 10 CFR 50.46 (Ref. 10), will be met following a LOCA, assuming the worst case single active component failure in the ECCS:
- a. Maximum fuel element cladding temperature is < 22001F;
- b. Maximum cladding oxidation is < 0.1-7 times the total cladding thickness before oxidation;
< 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react;
- d. The core is maintained in a coolable geometry; and
- e. Adequate long term cooling capability is maintained.
SPC performed LOCA calculations for the SPC ATRIUM'-10 fuel design.
The limiting single failures for the SPC analyses are discussed in Reference 11. The LOCA calculations examine both recirculation pipe and non-recirculation pipe breaks. For the recirculation pipe breaks, breaks on both the discharge and suction side of the recirculation pump are performed for two geometries; double-ended guillotine break and split break. The LOCA calculations demonstrate that the most limiting (highest PCT) break is a double-ended guillotine break in the recirculation pump suction piping. The limiting single failure is the failure of the LPCI injection valve in the intact recirculation loop to open.
(continued)
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SUSQUEHANNA - UNIT 2 TS I B 3.5-4 Revision 2
PPL Rev. 2 ECCS-Operating B 3.5.1
- BASES APPLICABLE SAFETY One ADS valve failure is analyzed as a limiting single failure for events ANALYSES requiring ADS operation. The remaining OPERABLE ECCS subsystems (continued) provide the capability to adequately cool the core and prevent excessive fuel damage.
The ECCS satisfy Criterion 3 of the NRC Policy Statement (Ref. 15).
LCO Each ECCS injection/spray subsystem and six ADS valves are required to be OPERABLE. The ECCS injection/spray subsystems are defined as the two CS subsystems, the two LPCI subsystems, and one HPCI System.
The low pressure ECCS injection/spray subsystems are defined as the two CS subsystems and the two LPCI subsystems.
With less than the required number of ECCS subsystems OPERABLE, the potential exists that during a limiting design basis LOCA concurrent with the worst case single failure, the limits specified in Reference 10 could be exceeded. All ECCS subsystems must therefore be OPERABLE to satisfy the single failure criterion required by Reference 10.
LPCI subsystems may be considered OPERABLE during alignment and operation for decay heat remroval when below the actual RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. At these low pressures and decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary.
(continued)
SUSQUEHANNA - UNIT 2 TS /B 3.5-5 Revision 3
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES APPLICABILITY All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3, when there is considerable energy in the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and 3, when reactor steam dome pressure is
- 150 psig, ADS and HPCI are not required to be OPERABLE because the low pressure ECCS subsystems can provide sufficient flow below this pressure. ECCS requirements for MODES 4 and 5 are specified in LCO 3.5.2, ECCS-Shutdown."
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable HPCI subsystem and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied-in this circumstance.
A.1 If any one low pressure ECCS injection/spray subsystem is inoperable for reasons other than Condition B, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition,-the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced, because a single failure in one of the remaining OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety function. The 7 day Completion Time is based on a reliability study (Ref. 12) that evaluated the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (i.e., Completion Times).
B.1 If one LPCI pump in one or both LPCI subsystems is inoperable, the inoperable LPCI pumps must be restored to OPERABLE status within 7 days.
In this Condition, the remaining OPERABLE LPCI pumps and at least one CS subsystem provide adequate core cooling during a LOCA.
However, overall ECCS reliability is reduced, because a single failure in one of the remaining OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety function. A 7 day Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.
(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.5-6 Revision 2
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES ACTIONS C.1 and C.2 (continued)
If the inoperable low pressure ECCS subsystem or LPCI pump(s) cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply.
To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
D.1 and D.2 If the HPCI System is inoperable and the RCIC System is verified to be OPERABLE, the HPCI System must be restored to OPERABLE status within 14 days. In this Condition, adequate core cooling is ensured by the OPERABILITY of the redundant and diverse low pressure ECCS injection/spray subsystems in conjunction with ADS. Also, the RCIC System will automatically provide makeup water at most reactor operating pressures. Verification of RCIC OPERABILITY is therefore required when HPCI is inoperable. This may be performed as an administrative check by
-e examining logs or other information to determine if RCIC is out of service for maintenance or other reasons. It does not mean to perform the Surveillances needed to demonstrate the OPERABILITY-of the RCIC System. If the OPERABILITY of the RCIC System cannot be verified, however, Condition H must be immediately entered. If a single active component fails concurrent with a design basis LOCA, there is a potential, depending on the specific failure, that the minimum required ECCS equipment will not be available. A 14 day Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.
E.1 and E.2 If Condition A or Condition B exists in addition to an inoperable HPCI System, the inoperable low pressure ECCS injection/spray subsystem or the LPCI pump(s) or the HPCI System must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In this Condition, adequate core cooling is ensured by the OPERABILITY of the ADS and the remaining low pressure ECCS subsystems. However, the overall ECCS reliability is significantly reduced because a single failure in one of the remaining OPERABLE subsystems (continued)
SUSQUEHANNA - UNIT 2 TS I B 3.5-7 Revision I
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES ACTIONS E.1 and E.2 (continued) concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function. Since both a high pressure system (H PCI) and a low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is required to restore either the HPCI System or the low pressure ECCS injection/spray subsystem to OPERABLE status. This Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.
F. 1 The LCO requires six ADS valves to be OPERABLE in order to provide the ADS function. Reference 11 contains the results of an analysis that evaluated the effect of one ADS valve being out of service. Per this analysis, operation of only five ADS valves will provide the required depressurization. However, overall reliability of the ADS is reduced, because a single failure in the OPERABLE ADS valves could result in a reduction in depressurization capability. Therefore, operation is only allowed for a limited time. The 14 day Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable-through operating experience.
G.1 and G.2 If Condition A or Condition B exists in addition to one inoperable ADS valve, adequate core cooling is ensured by the OPERABILITY of HPCI and the remaining low pressure ECCS injection/spray subsystem.
However, overall ECCS reliability is reduced because a single active component failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being available. Since both a high pressure system (ADS) and a low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is required to restore either the low pressure ECCS subsystem or the ADS valve to OPERABLE status. This Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.
(continued)
SUSQUEHANNA - UNIT 2 TS / B3.5-8 Revision I
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES ACTIONS H.1 and H.2 (continued)
If any Required Action and associated Completion Time of Condition D, E, F, or G is not met, or if two or more ADS valves are inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reactor steam dome pressure reduced to < 150 psig within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
1.1 When multiple ECCS subsystems are inoperable, as stated in Condition I, LCO 3.0.3 must be entered immediately.
SURVEILLANCE REQUIREMENTS The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the HPCI System, CS System, and LPCI subsystems full of-water ensures that the ECCS will perform properly, injecting its full -capacity into the RCS upon demand.
This will also prevent a water hammer following an ECCS initiation signal.
One acceptable method of ensuring that the lines-are full is to vent at the high points. The 31 day Frequency is based on the gradual nature of void buildup in the ECCS piping, the procedural controls governing system operation, and operating experience.
SR 3.5.1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This.SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in (continued)
SUSQUEHANNA - UNIT 2 TS I B 3.5-9 Revision 1
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES SREQUIREMENTS SR 3.5.1.2 (continued) the correct position. This SR does not apply to valves-that cannot be inadvertently misaligned, such as check valves. For the HPCI System, this SR also includes the steam flow path for the turbine and the flow controller position.
The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would only affect a single subsystem. This Frequency has been shown to be acceptable through operating experience.
This SR is modified by a Note that allows LPCI subsystems to be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than the RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. This allows operation in the RHR shutdown cooling mode during MODE 3, if necessary.
SR 3.5.1':3 Verification every 31 days that ADS gas supply header pressure is 2 135 psig ensures adequate gas pressure for reliable ADS operation.
The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least one valve actuations can occur with the drywell at 70% of design pressure.
The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of 135 psig is provided by the containment instrument gas system. The 31 day Frequency takes into consideration administrative controls over operation of the gas system and alarms associated with the containment instrument gas system.
(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.5-1 0 Revision 1
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.5.1.4 Verification every 31 days that at least one RHR System cross tie valve is closed and power to its operator is disconnected ensures that each LPCI subsystem remains independent and a failure of the flow path in one subsystem will not affect the flow path of the other LPCI subsystem.
Acceptable methods of removing power to the operator include opening the breaker, or racking out the breaker, or removing the breaker. If both RHR System cross tie valves are open or power has not been removed from at least one closed valve operator, both LPCI subsystems must be considered inoperable. The 31 day Frequency has been found acceptable, considering that these valves are under strict administrative controls that will ensure the valves continue to remain closed with motive power removed.
SR 3.5.1.5 Verification every 31 days that each 480 volt AC swing bus transfers automatically from the normal source to the alternate source on loss of power while supplying its respective bus demonstrates that electrical ipower is available to ensure proper operation of the associated LPCI inboard injection and minimum flow valves and the recirculation pump discharge and bypass valves. Therefore, each 480 volt AC swing bus must be OPERABLE for the associated LPCI subsystem to be OPERABLE. The test is performed by actuating the load test switch or by disconnecting the preferred power source to the transfer switch and verifying that swing bus automatic transfer is accomplished. The 31 day Frequency has been found to be acceptable through operating experience.
SR 3.5.1.6 Cycling the recirculation pump discharge and bypass valves through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and provides assurance that the valves will close when required to ensure the proper LPCI flow path is established. Upon initiation of an automatic LPCI subsystem injection signal, these valves are required to be closed to ensure full LPCI subsystem flow injection in the reactor via the recirculation jet pumps. De-energizing the valve in the closed position will also ensure the proper flow path for the LPCI subsystem. Acceptable methods of de-energizing the valve include opening the breaker, or racking out the breaker, or removing the breaker.
(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.5-11 Revision 2
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.6 (continued)
REQUIREMENTS The specified Frequency is once during reactor startup before THERMAL POWER is > 25% RTP. However, this SR is modified by a Note that states the Surveillance is only required to be performed if the last-performance was more than 31 days ago. Therefore, implementation of this Note requires this test to be performed during reactor startup before exceeding 25% RTP. Verification during reactor startup prior to reaching
> 25% RTP is an exception to the normal Inservice Testing Program generic valve cycling Frequency of 92 days, but is considered acceptable due to the demonstrated reliability of these valves. If the valve is Ainoperable and in the open position, the associated LPCI subsystem must obe declared inoperable.
SR 3.5.1.7. SR 3.5.1.8, and SR 3.5.1.9 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CFR 50, Appendix K criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME Code, Section Xi, requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The low pressure ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 10.
The pump-flow rates are verified against a system head equivalent to the RPV pressure expected'during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during a LOCA. These values may be established during preoperational testing.
The flow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rated flow is tested at both the higher and lower operating ranges of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow. Reactor steam pressure is considered adequate when 2 920 psig to perform SR 3.5.1.8 and 2 150 psig to perform SR 3.5.1.9. However, the requirements of SR 3.5.1.9 are met by a successful performance at any pressure < 165 psig. Adequate steam flow is represented by at least 1.25 turbine bypass valves open.
Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily (continued)
SUSQUEHANNA - UNIT 2 TS / B 3.5-12 Revision 1
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7, SR 3.5.1.8, and SR 3.5.1.9 (continued)
REQUIREMENTS perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPCI is inoperable.
Therefore, SR 3.5.1.8 and SR 3.5.1.9 are modified by Notes that state the Surveillances are not required to be performed -until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the reactor steam pressure and flow are adequate to perform the test.
The Frequency for SR 3.5.1.7 and SR 3.5.1.8 is in accordance with the Inservice Testing Program requirements. The 24 month Frequency for SR 3.5.1.9 is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage.
Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.5.1.10 The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup andaactuation of all automatic valves to their required positions. This functional test includes the LPCI and CS interlocks between Unit 1 and Unit 2 and specifically requires the following:
A functional test of the interlocks associated with the LPCI and CS pump starts in response to an automatic initiation signal in Unit 1 followed by a false automatic initiation signal in Unit 2; A functional test of the interlocks associated with the LPCI and CS pump starts in response to an automatic initiation signal in Unit 2 followed by a false automatic initiation signal in Unit 1; and (continued) f 6-ft
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SUSQUEHANNA - UNIT 2 T S I B 3.5-13 Revision I
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES REQUIREMENTS SR 3.5.1.10 (continued)
A functional test of the interlocks associated with the LPCI and CS pump starts in response to simultaneous occurrences of an automatic initiation signal in both Unit 1 and Unit 2 and a loss of Offsite power condition affecting both Unit 1 and Unit 2.
The purpose of this functional test (preferred pump logic) is to assure that if a false LOCA signal were to be received on one Unit simultaneously with an actual LOCA signal on the second Unit, the preferred LPCI and CS pumps are started and the non-preferred LPCI and CS pumps are tripped for each Unit. This functional test is performed by verifying that the non-preferred LPCI and CS pumps are tripped. The verification that preferred LPCI and CS pumps start is performed under a separate surveillance test. Only one division of LPCI preferred pump logic is required to be OPERABLE for each Unit, because no additional failures needs to be postulated with a false LOCA signal. If the preferred or non-preferred pump logic for CS is inoperable, the associated CS pumps shall be declared inoperable-and the pumps should not be operated to ensure that the opposite Unit's CS pumps or 4.16 kV ESS Buses are protected.
This SR also ensures that the HPCI System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlaps this Surveillance.
This SR can be accomplished by any series of sequential overlapping or total steps such that the entire channel is tested.
The 24 month Frequency is acceptable-because operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
(continued)
SUSQUEHANNA - UNIT 2 TS /B 3.5-14
.Revision 1
PPL Rev. 2 ECCS-Operating B3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.5.1.11 The ADS designated S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e.,
solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.12 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform portions of the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note that excludes valve actuation. This prevents an RPV pressure blowdown.
SR 3.5.1.12 A manual actuation of each ADS valve is-performed to verify that the valve and solenoid are functioning properly. This is demQnstrated by one of the two methods described below. Proper operation of the valve tailpipes is ensured through the use of foreign material exclusion during maintenance.
One method is by manual actuation of ADS valve under hot conditions.
Proper functioning of the valve and solenoid is demonstrated by the response of turbine control or bypass valve or by a change in the measured flow or by any other method suitable to verify steam flow.
Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve due to seat impact during closure. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this SR. Adequate pressure at which this SR is to be performed is 150 psig.
However, the requirements of SR 3.5.1.12 are met by a successful performance at any pressure. Adequate steam flow is represented by at least 1.25 turbine bypass valves open. Reactor startup is allowed prior to performing this SR by this method because valve OPERABILITY and the setpoints for I
1.
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SUSQUEHANNA - UNIT 2 TS / B3.5-15 Revision 2
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS SR 3.5.1.12 (continued) overpressure protection are verified, per ASME requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed for manual actuation after the required pressure is reached is sufficient to achieve stable conditions and provides adequate time to complete the Surveillance.
Another method is by manual actuation of the ADS valve at atmospheric temperature and pressure during cold shutdown. When using this method, proper functioning of the valve and solenoid is demonstrated by visual observation of actuator movement. Actual disc travel is measured during valve refurbishment and testing per ASME requirements. Lifting the valve at atmospheric pressure requires controlling the actuator to set the valve disc softly on its seat to prevent valve damage. Lifting of the valves at atmospheric pressure is the preferred method because lifting the valves with steam flow increases the likelihood that the valve will leak.
The Note that modified this SR is not needed when this method is used because the SR is performed during cold shutdown.
SR 3.5.1.11 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function. The Frequency of 24 mhonths on-a STAGGERED TEST BASIS ensures that both solenoids for each ADS valve are alternately tested. The Frequency is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concJuded to be acceptable from a reliability standpoint.
SR 3.5.1.13 This SR ensures that the ECCS RESPONSE TIME for each ECCS injection/spray subsystem is less than or equal to the maximum value assumed in the accident analysis. Response Time testing acceptance criteria are included in Reference 13. This SR is modified by a Note that allows the instrumentation portion of the response time to be assumed to be based on historical response time data and therefore, is excluded from the ECCS RESPONSE TIME testing. This is allowed since the instrumentation response time is a small part of the ECCS RESPONSE TIME (e.g., sufficient margin exists in the diesel generator start time when compared to the instrumentation response time) (Ref. 14).
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SUSQUEHANNA - UNIT 2 TS IB 3.5-16 Revision 2
PPL Rev. 2 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.13 (continued)
REQUIREMENTS The 24 month Frequency is consistent with the typical industry refueling cycle and is acceptable based upon plant operating experience.
REFERENCES
- 1.
FSAR, Section 6.3.2.2.3.
- 2.
FSAR, Section 6.3.2.2.4.
- 3.
FSAR, Section 6.3.2.2.1.
- 4.
FSAR, Section 6.3.2.2.2.
- 5.
FSAR, Section 15.2.8.
- 6.
FSAR, Section 15.6.4.
- 7.
FSAR, Section 15.6.5.
- 8.
- 9.
FSAR, Section 6.3.3.
- 10.
- 11.
FSAR, Section 6.3.3.
- 12.
Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC),
"Recommended Interim Revisions to LCOs for ECCS Components,"
December 1, 1975.
- 13.
FSAR, Section 6.3.3.3.
- 14.
NEDO 32291-A, "System Analysis for the Elimination of Selected Response Time Testing Requirements, October 1995.
- 15. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 2 TS / B 3.5-17 Revision 3
PPL Rev. 2 ECCS-Operating B 3.5.1 THIS PAGE INTENTIONALLY LEFT BLANK
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SUSQUEHANNA - UNIT 2 TS / B 3.5-18 Revision I
PPL Rev. I Drywell Air Temperature B 3.6.1.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.5 Drywell Air Temperature BASES BACKGROUND The drywell contains the reactor vessel and piping, which add heat to the airspace. Drywell coolers remove heat and maintain a suitable environment. The average airspace temperature affects the calculated response to postulated Design Basis Accidents (DBAs). The limitation on the drywell average air temperature was developed as reasonable, based on operating experience. The limitation on drywell air temperature is used in the Reference 1 safety analyses.
APPLICABLE SAFETY ANALYSES Primary containment performance is evaluated for a spectrum of break sizes for postulated loss of coolant accidents (LOCAs)
(Ref. 1). Among the inputs to the design basis analysis is the initial drywell average air temperature (Ref. 1). Analyses assume an initial average drywell air temperature, which bounds the allowed drywell air temperature of 1350F. This limitation ensures that the safety analysis remains valid by maintaining the expected initial conditions and ensures that the peak LOCA drywell temperature-does not exceed the maximum allowable temperature of 3400F (Ref. 1). Exceeding this design temperature may result in the degradation of. the primary containment structure under accident loads. Equipment inside primary containment required to mitigate the effects of a DBA is designed to operate and be capable of operating under environmental conditions expected for the accident.
Drywell air temperature satisfies Criterion 2 of the NRC Policy Statement. (Ref. 2)
LCO In the event of a DBA, with an initial drywell average air temperature less than or equal to the LCO temperature limit, the resultant peak accident temperature is maintained below the drywell design temperature. As a result, the ability of primary containment to perform its design function is ensured.
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Revision I TS I B 3.6-43
PPL Rev. I Drywell Air Temperature B 3.6.1.5 BASES (continued)
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining drywell average air temperature within the limit is not required in MODE 4 or 5.
ACTIONS A.1 With drywell average air temperature not within the limit of the LCO, drywell average air temperature-must be restored within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time is acceptable, considering the sensitivity of the accident analysis to variations in this parameter, and provides sufficient time to correct minor problems.
B.1 and B.2 If the drywell average air temperature cannot be restored to within limit within the required Completion Time, the plant must be brought to a MODE in whichthe-LCO does-not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based-on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE REQUIREMENTS SR 3.6.1.5.1 Verifying that the drywell average air temperature is within the LCO limit ensures that operation remains within the limits assumed for the primary containment analyses.
Drywell air temperature is monitored in the following areas:
SUSQUEHANNA - UNIT 2E TSIB3.6-44
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Revision 1
PPL Rev. 1 Drywell Air Temperature B 3.6.1.5 BASES SURVEILLANCE REQUIREMENTS SR 3.6.1.5.1 (continued)
Temperature Substitution Areas Access at Elevation Element Nos.
Value Top 794'4" TE 25791A 150OF TE 25791 B 150OF Middle 752' 2" TE 25790A 150OF TE 25790B 150OF Bottom 719' 1" TE25798A 150OF TE25798B 150OF Pedestal 704' 0" TE 25799A 130OF TE 25799B 130OF and is the arithmetical average of all valid temperatures from the above sensors. The location of the Drywell Temperature Elements ensures the Drywell Average Temperature is obtained. In the event a sensor becomes inoperable, the "substitution value" will be-used in the calculation.
Satisfying the surveillance requirement with less than 6 of the above listed 8 sensors operable shall not be done without an engineering evaluation.
Note that inoperable sensors should also be evaluated against LCO 3.3.3.1.
The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency of the SR was developed based on operating experience related to drywell average air temperature -variations and temperature instrument drift during the applicable MODES and thea low probability of a DBA occurring between surveillances. Furthermore, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal drywell air temperature condition.
REFERENCES
- 1.
FSAR, Section 6.2.
- 2.
Final Policy Statement on Technical Specifications Improvements, July 22,1993 (58 FR 39132).
SUSQUEHANNA - UNIT 2 TS I B 3.6-45 Revision 2
PPL Rev. 3 Secondary Containment B 3.6.4.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 Secondary Containment BASES BACKGROUND The secondary containment structure completely encloses the primary containment structure such that a dual-containment design is utilized to limit the spread of radioactivity to the environment to within limits. The function of the secondary containment is to contain, dilute, and hold up fission products that may leak from primary containment into secondary containment following a Design Basis Accident (DBA). In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the secondary containment, the secondary containment is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment (Ref. 1).
The secondary. containment is a structure that completely encloses the primary containment and reactor coolant-pressure boundary components.
This structure forms a control volume that serves to hold up and dilute the fission products. It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump and motor heat load additions).
The secondary containment boundary consists of the reactor building structure and associated removable walls and panels, hatches, doors, dampers, sealed penetrations and valves. The secondary containment is divided into Zone I, Zone II and Zone IlIl, each of which must be OPERABLE depending on plant status and the alignment of the secondary containment boundary. Specifically, the Unit 1 secondary containment boundary can be modified to exclude Zone II. Similarly, the Unit 2 secondary containment boundary can be modified to exclude Zone I. Secondary containment may consist of only Zone IlIl when in MODE 4 or 5 during CORE ALTERATIONS, or during handling of irradiated fuel within the Zone IlIl secondary containment boundary.
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SUSQUEHANNA - UNIT 2 TS / B 3.6-83 Revision 3
PPL Rev. 3 Secondary Containment B 3.6.4.1 BASES BACKGROUND (continued) -- --
To prevent ground level exfiltration while allowing the secondary containment to be designed as a conventional structure, the secondary containment requires support systems to maintain the control volume pressure at less than the external pressure. Requirements for the safety related systems are specified separately in LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System." When one or more zones are excluded from secondary containment, the specific requirements for support systems will also change (e.g., required secondary containment isolation valves).
APPLICABLE SAFETY ANALYSES There are two principal accidents for which credit is taken for secondary containment OPERABILITY. These are a loss of coolant accident (LOCA)
(Ref. 2) and a fuel handling accident inside secondary containment (Ref. 3). The secondary containment performs no active function in response to either of these limiting events; however, its leak tightness is required to ensure that the release of radioactive materials from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis and that fission products entrapped within the secondary containment structure-will be treated by the SGT System prior to discharge to the environment.
Secondary containment satisfies-Criterion 3 of the NRC Policy Statement (Ref. 4).
LCO An OPERABLE secondary containment provides a control volume into which fission products that bypass or leak from primary containment, or are released from the reactor coolant pressure boundary components located in secondary containment, can be diluted and processed prior to release to the environment. For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum can be established and maintained. The leak tightness of secondary containment must also ensure that the release of radioactive materials to the environment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis. For example, secondary containment bypass leakage must be restricted to the leakage rate required by LCO 3.6.1.3. The secondary containment boundary required to be OPERABLE is dependent on the operating status of both units, as well as the configuration of walls, doors, hatches, SCIVs, and available flow paths to the SGT System.
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SUSQUEHANNA - UNIT 2 TS / B 3.6-84 Revision 2
PPL Rev. 3 Secondary Containment B 3.6.4.1 BA.
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BASES (continued)
APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, secondary containment OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.
In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES.
Therefore, maintaining secondary containment OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment.
ACTIONS A.1 If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring.dring periods where secondary containment is inoperable is minimal.
H -
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(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.6-85 Revision 2
PPL Rev. 3 Secondary Containment B 316.4.1 BASES ACTIONS B.1 and B.2 (continued)
If secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
C.1, C.2. and C.3 Movement of irradiated fuel assemblies in the secondary containment, CORE ALTERATIONS, and OPDRVs can be postulated to cause fission product release to the secondary containment. In such cases, the secondary containment is the only barrier to release of fission products to the environment. CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended if the secondary containment is inoperable.
Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release.
Actions must continue until OPDRVs are suspended.
Required Action C.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.
SURVEILLANCE SR 3.6.4.1.1 REQUIREMENTS This SR ensures that the secondary containment boundary is sufficiently leak tight to preclude exfiltration.
.(continued)
SUSQUEHANNA - UNIT 2 TS / B 3.6-86 Revision 1
PPL Rev. 3 Secondary Containment B 3:6.4.1 BASES SURVEILLANCE SR 3.6.4.1.1 (continued)
REQUIREMENTS The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency of this SR was developed based on operating experience related to secondary containment vacuum variations during the applicable MODES and the low probability of a DBA occurring between surveillances.
Furthermore, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal secondary containment vacuum condition.
SR 3.6.4.1.2 and SR 3.6.4.1.3 Verifying that secondary containment equipment hatches, removable walls and one access door in each access opening required to be closed are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur.
Verifying that all such openings are closed also provides adequate assurance that exfiltration from the secondary containment will not occur.
In this application, the term "sealed" has no connotation of leak tightness.
An access opening typically contains one-inner and-one outer door.
Maintaining secondary containment OPERABILITY requires verifying one door in each access opening to secondary containment zones is closed.
In some cases (e.g., railroad bay), secondary containment access openings are shared such that a secondary containment barrier may have multiple inner or multiple outer doors. The intent is to maintain the secondary containment barrier intact, which is achieved by maintaining the inner or outer portion of the barrier closed at-all times. However, all secondary containment access doors are normally kept closed, except when the access opening is being used for entry and exit or when maintenance is being performed on an access opening.
When the railroad bay door (No. 101) is closed; all Zone I and IlIl hatches, removable walls, dampers, and one door in each access opening connected to the railroad access bay are closed; or, only Zone I removable walls and/or doors are open to the railroad access shaft; or, only Zone Ill hatches and/or dampers are open to the railroad access shaft. When the railroad bay door (No. 101) is open; all Zone I and IlIl hatches, removable walls, dampers, and one door in each access opening l connected to the railroad access bay are closed. The truck bay hatch is closed and the truck bay door (No. 102) is closed unless Zone II is isolated from Zones I and IlIl.
(continued)
SUSQUEHANNA - UNIT 2 TS I B 3.6-87 Revision 2
PPL Rev. 3 Secondary Containment B 3.6.4.1 BASES SURVEILLANCE REQUIREMENTS SR 3.6.4.1.2 and SR 3.6.4.1.3 (continued)
When an access opening between secondary containment zones is being used for exit and entry, then at least one door (where two doors are provided) must remain closed. The access openings between secondary containment zones which are not provided with two doors are administratively controlled to maintain secondary containment integrity during exit and entry. This Surveillance is modified by a Note that allows access openings with a single door (i.e., no airlock) within the secondary containment boundary (i.e., between required secondary containment zones) to be opened for entry and exit. Opening of an access door for entry and exit allows sufficient administrative control by individual personnel making the entries and exits to assure the secondary containment function is not degraded. When one of the zones is not a zone required for secondary containment-OPERABILITY, the Note allowance would not apply.
The 31 day Frequency for these SRs has been shown to be adequate, based on operating experience, and is considered adequate in view of the other indications of door andthatch status that are available to the operator.
- i (continued)
SUSQUEHANNA - UNIT 2 TS / B 3.6-87a Revision 2
PPL Rev. 3 Secondary Containment B 3:6.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.4.1.4 and SR 3.6.4.1.5 The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. To ensure that all fission products are treated, SR 3.6.4.1.4 verifies that the SGT System will rapidly establish and maintain a pressure in the secondary containment that is less than the pressure external to the secondary containment boundary. This is confirmed by demonstrating that one SGT subsystem will draw down the secondary containment to 2 0.25 inches of vacuum water gauge in less than or equal to the maximum time allowed. This cannot be accomplished if the secondary containment boundary is not intact. SR 3.6.4.1.5 demonstrates that one SGT subsystem can maintain 2 0.25 inches of vacuum water gauge for at least 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at less than or equal to the maximum flow rate permitted for the secondary containment configuration that is operable. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> test period allows secondary containment to be in thermal equilibrium at steady state conditions. As noted, both SR 3.6.4.1.4 and SR 3.6.4.1.5 acceptance limits are dependent upon the secondary containment configuration when testing is being performed. The acceptance criteria for the SRs based on secondary containment configuration is defined as follows:
SECONDARY MAXIMUM DRAWDOWN TIME(SEC)
MAXIMUM FL-OW RATE (CFM)
CONTAINMENT (SR 3.6.4.1.4 (SR 3.6.4.1.5 TEST CONFIGURATION ACCEPTANCE CRITERIA)
ACCEPTANCE CRITERIA)
Zones I, II and lII.
< 125 Seconds
< 4000 CFM (Zones I, 11, and III)
(From Zones I, II, and III)
Zones II and Ill.
< 118 Seconds
< 2960 CFM (Zones II and III)
(From Zones II and I1I)
Only one of the above listed configurations needs to be tested to confirm secondary containment OPERABILITY.
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SUSQUEHANNA - UNIT 2 TS / B 3.6-88 Revision 3
PPL Rev. 3 Secondary Containment B 3:6.4.1 BASES SURVEILLANCE REQUIREMENTS SR 3.6.4.1.4 and SR 3.6.4.1.5 (continued)
A Note also modifies the Frequency for each SR. This Note identifies that each SR must be performed in the most limiting Secondary Containment Configuration every 60 months. The 60 month Frequency is acceptable because operating experience has shown that these components usually pass the Surveillance and all active components are tested more frequently. Therefore, these tests are used to ensure secondary containment boundary integrity.
Since these SRs are secondary containment tests, they need not be performed with each SGT subsystem. The SGT subsystems are tested on a STAGGERED TEST BASIS, however, to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform SR 3.6.4.1.4 and SR 3.6.4.1.5. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
4-
...- SoREFERENCES
- 1. FSAR, Section 6.2.3.
- 2. FSAR, Section 15.6.
- 3. FSAR, Section 15.7.4.
- 4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 2 TS I B 3.6-89 Revision 1
PPL Rev. 3 AC Sources-Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating BASES BACKGROUND The unit Class 1 E AC Electrical Power Distribution System AC sources consist of two offsite power sources (preferred power sources, normal and alternate), and the onsite standby power sources (diesel generators (DGs) A, B, C and D). A fifth diesel generator, DG E, can be used as a substitute for any one of the four DGs A, B, C or D. As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.
The Class I E AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed. Each load group has connections to two preferred offsite power supplies and a single DG.
The two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electrical Power Distribution System are supported by two independent offsite power sources. A 230 kV line from the Susquehanna T10 230 kV switching station feeds start-up transformer No. 10; and, a 230 kV tap from the 500-230 kV tie line feeds the startup transformer No. 20.
The two independent offsite power sources are supplied to and are shared by both units. These two electrically and physically separated circuits provide AC power, through startup transformers (ST) No. 10 and ST No. 20, to the four 4.16 kV Engineered Safeguards System (ESS) buses (A, B, C and D) for both Unit 1 and Unit 2. A detailed description of the offsite power network and circuits to the onsite Class I E ESS buses is found in the FSAR, Section 8.2 (Ref. 2).
An offsite circuit consists of all breakers, transformers, switches, automatic tap changers, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class I E ESS bus or buses.
(continued)
SUSQUEHANNA - UNIT 2 B 3.8-1 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES BACKGROUND ST No. 10 and ST No. 20 each provide the normal source of power to (continued) two of the four 4.16 kV ESS buses in each Unit and the alternate source of power to the remaining two 4.16 kV ESS buses in each Unit.
If any 4.16 kV ESS bus loses power, an automatic transfer from the normal to the alternate occurs after the normal supply breaker trips.
When off-site power is available to the 4.16 kV ESS Buses following a LOCA signal, the required ESS loads will be sequenced onto the 4.16 kV ESS Buses in order to compensate for voltage drops in the onsite power system when starting large ESS motors.
The onsite standby power source for 4.16 kV ESS buses A, B, C and D consists of five DGs. DGs A, B, C and D are dedicated to ESS buses A, B, C and D, respectively. DG E can be used as a substitute for any one of the four DGs (A, B, C or D) to supply the associated ESS bus. Each DG provides standby power to two 4.16 kV ESS buses-one associated with Unit 1 and one associated with Unit 2.
The four "required" DGs are those aligned to a 4.16 kV ESS bus to provide onsite standby power for both Unit 1 and Unit 2.
A DG, when aligned to an ESS bus, starts automatically on a loss of
=-
Coolant accident (LOCA)-signal (i.e., low reactor water level signal or high drywell pressure signal) or on an-ESS bus degraded voltage or undervoltage signal. After the DG has started, it-automatically ties to its respective bus after offsite power is tripped as a consequence of ESS bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the ESS bus on a LOCA signal alone.
Following the trip of offsite power, non-permanent loads are stripped from the 4.16 kV ESS Buses. When a DG is tied to the ESS Bus, loads are then sequentially connected to their respective ESS Bus by individual load timers. The individual load timers control the starting permissive signal to motor breakers to prevent overloading the associated DG.
In the event of loss of normal and alternate offsite power supplies, the 4.16 kV ESS buses will shed all loads except the 480 V load centers and the standby diesel generators will connect to the ESS busses. When a DG is tied to its respective ESS bus, loads are then sequentially connected to (continued)
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SUSQUEHANNA - UNIT 2 B 3.8-2 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued) the ESS bus by individual load timers which control the permissive and starting signals to motor breakers to prevent overloading the DG.
In the event of a loss of normal and alternate offsite power supplies, the ESS electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a LOCA.
Certain required plant loads are returned to service in a predetermined sequence in order to prevent overloading of the DGs in the process.
Within 286 seconds after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service. Ratings for the DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3).
DGs A, B, C and D have the following ratings:
- a. 4000 kW-continuous,
- b. 4700 kW-2000 hours, DG E has the following ratings:
- a. 5000 kW-continuous,
- b. 5500 kW-2000 hours.
APPLICABLE SAFETY ANALYSES The initial conditions of DBA and transient analyses in the FSAR, Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and Section 3.6, Containment Systems.
The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit and supporting safe shutdown of the other unit. This includes maintaining the onsite or offsite AC sources (continued) 4~~*
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en a9't5 SUSQUEHANNA - UNIT 2 B 3.8-3 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES APPLICABLE OPERABLE during accident conditions in the event of an assumed SAFETY ANALYSES loss of all offsite power or all onsite AC power; and a worst case single (continued) failure.
AC sources satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).
LCO Two qualified circuits between the offsite transmission network and the onsite Class 1 E Distribution System and four separate and independent DGs (A, B, C and D) ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA. DG E can be used as a substitute for any one of the four DGs A, B, C or D.
Qualified offsite circuits are those that are described in the FSAR, and are part of the licensing basis for the unit. In addition, the required automatic load timers for each ESF bus shall be OPERABLE.
The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources. Therefore, Unit 2 Technical Specifications establish requirements for the OPERABILITY of the DG(s) and qualified-offsite-circuits needed to support the Unit I onsite Class 1 E AC electrical power distribution subsystem(s) required by LCO 3.8.7, Distribution Systems-Operating.
Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESS buses. One OPERABLE offsite circuit consists of an energized ST. No. 10 transformer and the respective circuit path including energized ESS transformers 101 and 111 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses. The other OPERABLE offsite circuit consists of an energized ST. No. 20 transformer, and the respective circuit path including energized ESS transformers 201 and 211 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses. Both offsite circuits are OPERABLE provided each meets the criteria described above and provided that no 4.16 kV ESS Bus has less than one OPERABLE offsite circuit (continued)
SUSQUEHANNA - UNIT 2 B 3.8-4 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES LCO capable of supplying the required loads. If no OPERABLE offsite (continued) circuit is capable of supplying any of the 4.16 kV ESS Buses, provided that the offsite circuits otherwise meet the above requirements, one offsite source shall be declared inoperable. Unit 2 also requires Unit 1 offsite circuits to be OPERABLE.
Four of the five DGs are required to be Operable to satisfy the initial assumptions of the accident analyses. Each required DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESS bus on detection of bus undervoltage after the normal and alternate supply breakers open. This sequence must be accomplished within 10 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite power can be restored to the ESS buses. These capabilities are required to be met from a variety of initial conditions, such as DG in standby with the engine hot and DG in normal standby conditions. Normal standby conditions for a DG mean that the diesel engine oil is being continuously circulated and engine coolant is circulated as necessary to maintain temperature consistent with manufacturer recommendations. Additional DG capabilities must be demonstrated
-to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal wfiile-operatfng in parallel test mode.
Although not normally aligned as a required DG, DG E is normally maintained OPERABLE (i.e., Surveillance Testing completed) so that it can be used as a substitute for any one of the four DGs A, B, C or D.
Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.
The AC sources must be separate and independent (to the extent possible) of other AC sources. For the DGs, the separation and independence are complete. For the offsite AC sources, the separation and independence are to the extent practical. A circuit may be connected to more than one ESS bus, with automatic transfer capability to the other circuit OPERABLE, and not violate separation criteria. A circuit that is not connected to an ESS bus is required to (continued)
SUSQUEHANNA - UNIT 2 TS I B 3.8-5 Revision 1
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES LCO (continued) have OPERABLE automatic transfer interlock mechanisms to each ESS bus to support OPERABILITY of that offsite circuit.
APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:
- a.
Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
- b.
Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources-Shutdown."
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.
There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
The ACTIONS are modified by a Note which allows entry into associated Conditions and Required Actions to be delayed for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> when an OPERABLE diesel generator is placed in an inoperable status for the alignment of diesel generator E to or from the Class 1 E distribution system. Use of this allowance requires both offsite circuits to be OPERABLE. Entry into the appropriate Conditions and Required Actions shall be made immediately upon the determination that substitution of a required diesel generator will not or can not be completed.
A.1 To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met.
However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.
(continued)
SUSQUEHANNA - UNIT 2 TS I B 3.8-6 Revision 1
PPL Rev. 3 AC Sources-Operating B3.8.1 BASES ACTIONS A.2 (continued)
Required Action A.2, which only applies if one 4.16 kV ESS bus cannot be powered from any offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of critical systems. These features (e.g., system, subsystem, division, component, or device) are designed to be powered from redundant safety related 4.16 kV ESS buses. Redundant required features failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has no offsite power. The Completion Time for Required Action A.2 is intended to allow time for the operator to evaluate and repair any discovered inoperabilities.
This Completion Time also allows an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:
- a.
A 4.16 kV ESS bus has no offsite power supplying its loads; and
- b.
A redundant required feature on another 4.16 kV ESS bus is inoperable.
If, at any time during the existence ofthis Condition. (one offsite circuit inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.
Discovering no offsite power to one 4.16 kV ESS bus on the onsite Class 1 E Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other emergency bus that has offsite power, results in starting the Completion Times for the Required Action.
Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before the unit is subjected to transients associated with shutdown.
The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class I E Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 (continued)
SUSQUEHANNA - UNIT 2 B 3.8-7 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES ACTIONS A.2 (continued) hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class I E Distribution System.
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occu-rring during this period.
The second Completion Time for Required Action A.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This situation could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A (continued)
SUSQUEHANNA - UNIT 2 B 3.8-8 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES ACTIONS A.3 (continued) and B are entered concurrently. The "AND" connector between the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.
As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time that Condition A was entered.
B. I To ensure a highly reliable power source remains with one required DG inoperable, it is necessary to verify the availability of the required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit
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-inoperability, additional C-onditions must then be entered.
-B.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.e.,
single division systems are not included). Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.
(continued)
SUSQUEHANNA-UNIT 2 TS I B 3.8-9 Revision 2
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES ACTIONS B.2 (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:
- a.
An inoperable DG exists; and
- b.
A required feature powered from another diesel generator (Division 1 or 2) is inoperable.
If, at any time during the existence of this Condition (one required DG inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.
Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.-
The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System.
Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.
B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.7 does not have to be performed. If the cause of inoperability exists on other DG(s), they are declared inoperable upon discovery, and Condition E of (continued)
SUSQUEHANNA - UNIT 2 TS / B 3.8-1 0 Revision I
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES ACTIONS B.3.1 and B.3.2 (continued)
LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be determined not to exist on the remaining DG(s), performance of SR 3.8.1.7 suffices to provide assurance of continued e&=
OPERABILITY of those DGs. However, the second Completion Time for Required Action B.3.2 allows a performance of SR 3.8.1.7 completed up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to entering Condition B to be accepted as demonstration that a DG is not inoperable due to a common cause failure.
In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the plant corrective action program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> constraint imposed while in Condition B.
According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.
B.4 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In Condition B, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.
The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This situation could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to (continued) a..
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..A SUSQUEHANNA - UNIT 2 TS I B 3.8-11 Revision 1
PPL Rev. 3 AC Sources-Operating B.3.8.1 BASES ACTIONS B.4 (continued) complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.
As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered.
C.1 Required Action C.1 addresses actions to be taken in the event of concurrent inoperability of two offsite circuits. The -Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered irioperabilities.
According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AD sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.
Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable. However, two factors tend to decrease the severity of this degradation level:
- a.
The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and (continued)
SUSQUEHANNA - UNIT 2 B 3.8-12 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES ACTIONS C.1 (continued)
- b.
The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.
With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis.
Thus, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria. According to Regulatory Guide 1.93 (Ref. 7), with the available offsite AC sources two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If two offsite sources are restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, power operation continues in accordance with Condition A.
D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System Actions would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any ESS bus, Actions for LCO 3.8.7, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of the offsite circuit and one DG without regard to whether a division is de-energized. LCO 3.8.7 provides the appropriate restrictions for a de-energized bus.
According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the (continued)
SUSQUEHANNA - UNIT 2 B 3.8-1 3 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES ACTIONS D.1 and D.2 (continued) reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.
E.1 With two or more DGs inoperable and an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown could cause grid instability, which could result in a total loss
-of AC power.) Since any-inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The iritent-here is to avoid-the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.
According to Regulatory Guide 1.93 (Ref. 7), with two or more DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
F.1 and F.2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are (continued)
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SUSQUEHANNA - UNIT 2 B 3.8-14 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES i :'
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.I-I BASES ACTIONS F.1 and F.2 (continued) reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
G.1 Condition G corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.
SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 9). Periodic component tests are supplemented by extensive functional tests
-during refueling outages {under simulated accident conditions). The SRs for demonstrating the OPERAB1LITY of the DGs are in accordance with the recommendations of Regulitory-Guide 1.9 (Ref. 3), and Regulatory Guide 1.137 (Ref. 11), as addressed in the FSAR.
The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources. Therefore, Surveillance requirements are established for the Unit I onsite Class 1 E AC electrical power distribution subsystem(s) required to support Unit 2 by LCO 3.8.7, Distribution Systems-Operating. As Noted at the beginning of the SRs, SR 3.8.1.1 through SR 3.8.1.20 are applicable to the Unit 2 AC sources and SR 3.8.1.21 is applicable to the Unit 1 AC sources.
Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable. The minimum steady state output voltage of 3793 V is the value assumed in the degraded voltage analysis and is approximately 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of (continued)
SUSQUEHANNA - UNIT 2 B 3.8-15 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) 4000 V motors whose minimum operating voltage is specified as 90%
or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90% of name plate rating. The specified maximum steady state output voltage of 4400 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations found in Regulatory Guide 1.9 (Ref. 3). The lower Frequency Limit is necessary to support the LOCA analysis assumptions for low pressure ECCS pump flow rates. (Reference 12)
The Surveillance Table has been modified by a Note, to clarify the testing requirements associated with DG E. The Note is necessary to define the intent of the Surveillance Requirements associated with the integration of DG E. Specifically, the Note defines that a DG is only considered OPERABLE and required when it is aligned to the Class
- E distribution system. For example, if DG A does not meet the requirements of a specific SR, but DG E is substituted for DG A and aligned to the Class 1 E distribution system, DG E is required to be OPERABLE to satisfy the LCO requirement of 4 DGs-and DG A is not required to be OPERABLE because it is not aligned to the Class 1 E distribution system. This is acceptable because only 4 DGs are assumed in the event analysis. Furthermore, the Note identifies when the Surveillance Requirements, as modified by SR Notes, have been met and performed, DG E can be substituted for any other DG and declared OPERABLE after performance of two SRs which verify switch alignment. This is acceptable because the testing regimen defined in the Surveillance Requirement Table ensures DG E is fully capable of performing all DG requirements.
SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its (continued)
SUSQUEHANNA-UNIT 2 B 3.8-16 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.1 (continued)
REQUIREMENTS correct position to ensure that distribution buses and loads are connected to an Operable offsite power source and that appropriate independence of offsite circuits is maintained. The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.
SR 3.8.1.2 Not Used.
SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.
Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardQwn inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the Cooper Bessemer Service Bulletin 728, so that mechanical stress and wear on the diesel engine are minimized.
Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients do not invalidate the test.
(continued)
SUSQUEHANNA - UNIT 2 B 3.8-1 7 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 (continued)
REQUIREMENTS Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.
Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
Note 5 provides the allowance that DG E, when not aligned as substitute for DG A, B, C and D but being maintained available, may use the test facility to satisfy loading requirements in lieu of synchronization with an ESS bus.
Note 6 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units, with the DG synchronized to the 4.16 kV ESS bus of Unit 1 for one periodic test and synchronized to the 4.16 kV ESS bus of Unit 2 during the next periodic test. This is acceptable because the purpose of the test is to demonstrate the ability of the DG to operate at its continuous rating-(with the exception of DG E which is only required to be tested at the continuous rating of DGs A thru D) and this attribute is tested-at the required Frequency.
Each unit's circuit breakers and breaker control circuitry, which are only being tested every second test (due to the staggering of the tests),
historically have a very low failure rate. If a DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit. In addition, if the test is scheduled to be performed on the other Unit, and the other Unit's TS allowance that provides an exception to performing the test is used (i.e., the Note to SR 3.8.2.1 for the other Unit provides an exception to performing this test when the other Unit is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment),
or it is not possible to perform the test due to equipment availability, then the test shall be performed synchronized to this Unit's 4.16 kV ESS bus. The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3).
(continued)
SUSQUEHANNA - UNIT 2 B 3.8-18 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.8.1.4 This SR verifies the level of fuel oil in the engine mounted day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 55 minutes of DG A-D and 62 minutes of DG E operation at DG continuous rated load conditions.
The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and operators would be aware of any large uses of fuel oil during this period.
SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the engine mounted day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential-for water entrainment in the fuel oil during DG operation. Water may come fror' any of several sources, including condensation, ground water, rain water,-contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.
(continued)
SUSQUEHANNA - UNIT 2 TS /
3.8-19 Revision I
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. It is required to support continuous operation of standby power sources. This Surveillance provides assurance.that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.
The Frequency for this SR is 31 days because the design of the fuel transfer system requires that the transfer pumps operate automatically.
Administrative controls ensure an adequate volume of fuel oil in the day tanks. This Frequency allows this aspect of DG Operability to be demonstrated during or following routine IDG operation.
SR 3.8.1.7 This SR helps to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.
To minimize the wear on moving parts that do not get lubricated when the engine is not running, this SR has been modified by Note 1 to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the.DG's turbo charger is sufficiently prelubicated to prevent undo wear and tear).
For the purposes of this testing, the DGs are started from standby conditions. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.
(continued)
SUSQUEHANNA - UNIT 2 B 3.8-20 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.7 (continued)
REQUIREMENTS The DG starts from standby conditions and achieves the minimum required voltage and frequency within 10 seconds and maintains the required voltage and frequency when steady state conditions are reached. The ten second start requirement support the assumptions in the design bases LOCA analysis of FSAR Section 6.3 (Ref. 12)
To minimize testing of the DGs, Note 2 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to one unit.
The time for the DG to reach steady state operation is periodically monitored and the trend evaluated to identify degradation.
The 31 day Frequency is consistent with Regulatory Guide 1.9 (Ref. 3). This Frequency provides adequate assurance of DG OPERABILITY.
SR 3.8.1.8 Transfer of each 4.16 kV ESS bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads. The 24 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed on the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of the automatic transfer of unit power supply could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a (continued)
SUSQUEHANNA - UNIT 2 B 3.8-21 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)
REQUIREMENTS result, plant safety systems. The manual transfer of unit power supply should not result in any perturbation to the electrical distribution system, therefore, no mode restriction is specified. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in Unit I Technical Specifications tests the applicable logic associated with Unit 1. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1 or 2 does not have applicability to Unit 1. The NOTE only applies to Unit 2, thus the Unit 2 Surveillance shall not be performed with Unit 2 in MODE I or 2.
SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each a DG is a residual heat removal (RHR) pump (1425 kW). This Surveillance may be accomplished by:
- a.
Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or
- b.
Tripping its associated single largest post-accident load with the DG solely supplying the bus.
As recommended by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75%
of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower. For DGs A, B, C, D and E, this represents 64.5 Hz, equivalent to 75% of the (continued)
SUSQUEHANNA - UNIT 2 B 3.8-22 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)
REQUIREMENTS difference between nominal speed and the overspeed trip setpoint.
The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 4.5 seconds specified is equal to 60% of the 7.5 second load sequence interval between loading of the RHR and core spray pumps during an undervoltage on the bus concurrent with a LOCA. The 6 seconds specified is equal to 80% of that load sequence interval. The voltage and frequency specified are consistent with the design range of the equipment powered by the DG. SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c specify the steady state voltage-and frequency values to which the system must recover following load rejection.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.
To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each
'unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide DG damage protection. While the DG is not expected to experience this transient during an event, and continues to be available, this response ensures that the DG (continued)
SUSQUEHANNA - UNIT 2 TS / B 3.8-23 Revision I
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)
REQUIREMENTS is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.
SR 3.8.1.11 As required by Regulatory Guide 1.9 (Ref. 3), this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of -offsite power, including shedding of the nonessential loads and energization of the ESS buses and respective 4.16 kV loads from the DG. It further demonstrates the capability of the DG to automatically achieve and maintain the required voltage and frequency within the specified time.
The DG auto-start time of 10 seconds is derived from requirements of the licensed accident analysis for responding to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note I (continued)
SUSQUEHANNA - UNIT 2 B 3.8-24 Revision 0
PPL Rev. 3 AC Sources-Operating 8 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)
REQUIREMENTS allows all DG starts to be preceded by an engine prelube period (which for DG's A through D includes operation of he lube oil system to ensure the DGs turbo charger is sufficiently prelubricated). For the purpose of this testing, the DGs shall be started from standby conditions, that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in the Unit I Technical Specifications tests the applicable logic associated with Unit 1. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have
-applicability to Unit 1. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 -in MODES 1, 2 or 3.
This SR is also modified by Note 3. The Note -specifies when this SR is required to-be performed for the DGs and the 4.16 kV ESS Buses.
The Note is necessary because this SR involves an integrated test between the DGs and the 4.16 kV ESS Buses and the need for the testing regimen to include DG E being tested (substituted for all DGs for both units) with all 4.16 kV ESS Buses. To ensure the necessary testing is performed, the following rotational tsesting regimen has been established:
UNIT IN OUTAGE DIESEL E SUBSTITUTED FOR 2
DG E not tested I
Diesel Generator D 2
Diesel Generator A I
DG E not tested 2
Diesel Generator B I
Diesel Generator A 2
Diesel Generator C I
Diesel Generator B 2
Diesel Generator D I
Diesel Generator C (continued)
SUSQUEHANNA - UNIT 2TSB.-5RvsoI TS / B 3.8-25 Revision I
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)
REQUIREMENTS The specified rotational testing regimen can be altered to facilitate unanticipated events which render the testing regimen impractical to implement, but any alternative testing regimen must provide an equivalent level of testing.
This SR does not have to be performed with the normally aligned DG when the associated 4.16 kV ESS bus is tested using DG E and DG E does not need to be tested when not substituted or aligned to the Class 1 E distribution system. The allowances specified in the Note are acceptable because the tested attributes of each of the five DGs and each unit's four 4.16 kV ESS buses are verified at the specified Frequency (i.e., each DG and each 4.16 kV ESS bus is tested every 24 months). Specifically, when DG E is tested with a Unit 1 4.16 kV ESS bus, the attributes of the normally aligned DG, although not tested with the Unit 1 4.16 kV ESS bus, are tested with the Unit 2 4.16 kV ESS bus within the 24 month Frequency. The testing allowances do result in some circuit pathways which do not need to change state (i.e., cabling) not being tested on a 24 month Frequency. This is acceptable because these components are not required to change
-- -L-state to perform their safety function and when substituted--normal operation of DG E will ensure continuity of most-of the cabling not tested.
SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for 2 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on a LOCA signal without loss of offsite power.
The requirement to verify the connection and power supply of permanent and auto connected loads is intended to satisfactorily show the relationship of these loads to the loading logic for loading onto offsite power. In certain circumstances, many of these loads cannot actually be (continued) t a~S D
,,,8;;
- ;,A aS~f Xm SUSQUEHANNA - UNIT 2 TS I B 3.8-26 Revision 1
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)
REQUIREMENTS connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, high pressure injection systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable.
This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
SR 3.8.1.12.a through SR 3.8.1.12.d are performed with the DG running. SR 3.8.1.12.e can be performed when the DG is not running.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency is acceptable from a
-reliability standpoint.
This SR is modified by two Notes. The reason for-Note -1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelubef period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated). For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
The reason for Note 2 is to allow DG E, when not aligned as substitute for DG A, B, C or D, to use the test facility to satisfy loading requirements in lieu of aligning with the Class 1 E distribution system.
When tested in this configuration, DG E satisfies the requirements of this test by completion of SR 3.8.1.12.a, b and c only. SR 3.8.1.12.d and 3.8.1.12.e may be performed by any DG aligned with the Class 1E distribution system or by any series of sequential, (continued)
SUSQUEHANNA - UNIT 2 B 3.8-27 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)
REQUIREMENTS overlapping, or total steps so that the entire connection and loading sequence is verified.
This Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal. The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately.
The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.
The 24 month Frequency is based on engineering judgment, takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
The SR is modified by two Notes. To minimize testing of the DGs, Note 1 to SR 3.8.1.13 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to-only one unit.
Note 2 provides the allowance that DG E, when not aligned as a substitute for DG A, B, C, and D but being maintained available, may use a simulated ECCS initiation signal.
SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), requires demonstration once per 24 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s-22 hours of which is at a load equivalent to 90% to 100% of the continuous rating of the DG, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 105% to 110% of the continuous duty rating of the DG. SSES has taken exception to this (continued)
SUSQUEHANNA - UNIT 2 B 3.8-28 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)
REQUIREMENTS requirement and performs the two hour run at the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating for each DG. The requirement to perform the two hour overload test can be performed in any order provided it is performed during a single continuous time period.
The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube discussed in SR 3.8.1.7, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
A load band is provided to avoid routine overloading of the DG.
Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended~ to be consistent with expected fuel cycle lengths.
This Surveillance has been modified by four Notes...Note 1 states that momentary transients due to changing bus loads-do not invalidate this test.
To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units.
This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
Note 3 stipulates that DG E, when not aligned as substitute for DG A, B, C or D but being maintained available may use the test facility to satisfy the specified loading requirements in lieu of synchronization with an ESS bus.
SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from full load temperatures and achieve the required voltage (continued)
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SUSQUEHANNA - UNIT 2 B 3.8-29 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BAS SURVEILLANCE SR 3.8.1.15 (continued)
REQUIREMENTS and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by three Notes. Note I ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
Momentary transients due to changing bus loads do not invalidate this test.
Note 2 allows all DG starts to be preceded by.an engine prelube period (which for DGs A through D includes operation of the-lube oil system to ensure the DG's turbocharger is sufficiently prelubricated) to minimize wear and tear on the diesel during testing.
To minimize testing of the DGs, Note 3 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and that the DG can be returned to ready-to-load status when offsite power is restored. It also (continued)
SUSQUEHANNA - UNIT 2 B 3.8-30 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)
REQUIREMENTS ensures that the auto-start logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the DG controls are in isochronous and the output breaker is open.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.1 1 for the Bases of the Note.
SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions is not compromised as the result of testing. Interlocks to the LOCA sensing circuits cause the DG to a
"automatically reset to ready-to-load operation if an ECCS initiation signal is received during operation inThe-test m6de.. Ready-to-load operation is defined as the DG running at rated speed and voltage, the DG controls in isochronous, and the DG output breaker open. These provisions for automatic switchover are required by IEEE-308 (Ref. 10), paragraph 6.2.6(2).
The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirements associated with SR 3.8.1.17.b is to show that the emergency loading is not affected by the DG operation in test mode.
In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This test is performed by verifying that after the DG is tripped, the offsite source originally in parallel with the DG, remains connected to the affected 4.16 kV ESS Bus. SR 3.8.1.12 is performed separately to verify the proper offsite loading sequence.
(continued) go---:-.
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SUSQUEHANNA - UNIT 2 B 3.8-31 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 REQUIREMENTS (continued)
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.1 1 for the Bases of the Note.
Under accident conditions, loads are sequentially connected to the bus by individual load timers which control the permissive and starting signals to motor breakers to prevent overloading of the AC Sources due to high motor starting currents. The load sequence time interval tolerance ensures that sufficient time exists for the AC Source to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESS buses. A list of the required timers and the associated setpoints are included in the Bases as Table B 3.8.1-1, Unit 1 and Unit 2 Load Timners. Failure of a timer identified as an offsite power timer
-may result in both offsite -sources inoperable. Failure of any other timer may result in the associated DG being inoperable. A timer is
~considered failed for this SR if it will not ensure that the associated load will energize within the Allowable Value specified in Table B 3.8.1-
- 1. These conditions will require entry into applicable Condition of this specification. With a load timer inoperable, the load can be rendered inoperable to restore OPERABILITY to the associated AC sources. In this condition, the Conditions and Required Actions of the associated specification shall be entered for the equipment rendered inoperable.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
SR 3.8.1.18 This SR is modified by a Note that specifies that load timers associated with equipment that has automatic initiation (continued)
SUSQUEHANNA - UNIT 2 TS / B3.8-32 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASE S
~ ~
~
SURVEILLANCE SR 3.8.1.18 REQUI REMENTS (continued) capability disabled are not required to be Operable. This is acceptable because if the load does not start automatically, the adverse effects of an improper loading sequence are eliminated. Furthermore, load timers are associated with individual timers such that a single timer only affects a single load.
SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.
This Surveillance demonstrates DG operation, as discussed in the Bases for SR 3.8.1.1 1, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified-To simulate the ndn-LOCA unit 4.16 kV
-ESS Bus loads on the DG, bounding loads are energized on the tested 4.16 kV ESS Bus after all auto connected emergency loads are energized.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length.
This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated). For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil being continuously circulated and (continued)
SUSQUEHANNA - UNIT 2 TS / B 3.8-33 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)
REQUIREMENTS engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
Note 2 is necessary to accommodate the testing regimen associated with DG E. See SR 3.8.1.11 for the Bases of the Note.
The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in the Unit 1 Technical Specifications tests the applicable logic associated with Unit 1. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2 or 3 does not have applicability to Unit 1. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODE 1, 2 or 3.
SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously. The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3).
This SR is modified by two Notes. The reason for Note 1 is to minimize wear on the DG during'testing. The Note allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated.) For the purpose of this testing, the DG's must be started from standby conditions, that is, with the engine oil continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
(continued)
SUSQUEHANNA - UNIT 2 TS I 8 3.8-34 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)
REQUIREMENTS Note 2 is necessary to identify that this test does not have to be performed with DG E substituted for any DG. The allowance is acceptable based on the design of the DG E transfer switches. The transfer of control, protection, indication, and alarms is by switches at two separate locations. These switches provide a double break between DG E and the redundant system within the transfer switch panel. The transfer of power is through circuit breakers at two separate locations for each redundant system. There are four normally empty switchgear positions at DG E facility, associated with each of the four existing DGs. Only one circuit breaker is available at this location to be inserted into one of the four positions. At each of the existing DGs, there are two switchgear positions with only one circuit breaker available. This design provides two open circuits between redundant power sources. Therefore, based on the described design, it can be concluded that DG redundancy and independence is maintained regardless of whether DG E is substituted for any other DG.
SR 3.8.1.21 This Surveillance is provided to direct that the appropriate Surveillances for Unit 1 AC sources required to support Unit 2 are governed by the Unit 2 Technical Specifications. With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.1.1 through SR 3.8.1.20) are applicable to the Unit 2 AC sources only. Meeting the SR requirements of Unit 1 LCO 3.8.1 will satisfy all Unit 2 requirements for Unit 1 AC sources. However, six Unit 1 LCO 3.8.1 SRs, if not required to support Unit 1 OPERABILITY requirements, are not required when demonstrating Unit 1 sources are capable of supporting Unit 2. SR 3.8.1.8 is not required if only one Unit 1 offsite circuit is required by the Unit 2 Specification.
SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, and SR 3.8.1.19 are not required since these SRs test the Unit 2 ECCS initiation signal, which is not needed for the AC sources to be OPERABLE on Unit 2.
SR 3.8.1.20 is not required since starting independence is not required with the DG(s) not required to be OPERABLE.
The Frequency required by the applicable Unit 1 SR also governs performance of that SR for Unit 2.
(continued)
SUSQUEHANNA - UNIT 2 TS /B 3.8-35 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)
REQUIREMENTS As Noted, if Unit 1 is in MODE 4 or 5, the Note to Unit 1 SR 3.8.2.1 is applicable. This ensures that a Unit 2 SR will not require a Unit 1 SR to be performed, when the Unit 1 Technical Specifications do not require performance of a Unit 1 SR. (However, as stated in the Unit 2 SR 3.8.2.1 Note, while performance of an SR is not required, the SR still must be met).
REFERENCES
- 1.
10 CFR 50, AppendixA, GDC 17.
- 2.
FSAR, Section 8.2.
- 3.
- 4.
FSAR, Chapter 6.
- 5.
FSAR, Chapter 15.
- 6.
Final Policy Statement on Technical Specifications Improvements, July22, 1993 (58 FR 39132).
- 7.
- 8.
- 9.
10 CFR 50, Appendix A, GDC 18.
- 10.
- 11.
- 12.
FSAR, Section 6.3.
- 13. ASME Boiler and Pressure Vessel Code,Section XI.
SUSQUEHANNA - UNIT 2 TS / B 3.8-36 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 TA i*
-TA 8.1---1^
(page 1-b 2
^
UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE TAG NO.
SYSTEM LOADING TIMER LOCATION (seconds)
VALUE (seconds) 62A-20102-RHR Pump 1A 1A201 3
22.7 and* 3.6 62A-20202 RHR Pump 1 B 1A202 3
2.7 and s 3.6 62A-20302 RHR Pump IC IA203 3
2.7 and s3.6 62A-20402 RHR Pump ID 1A204 3
2Ž2.7 and* 3.6 62A-20102 RHR Pump 2A 2A201 3
2 2.7 and S 3.6 62A-20202 RHR Pump 2B 2A202 3
Ž 2.7 and *3.6 62A-20302 RHR Pump 2C 2A203 3
2Ž2.7 and S3.6 62A-20402 RHRPump 2D 2A204 3
22.7 and* 3.6 EIIA-K202B RHR Pump IC (Offsite PowerTimer) 1C618 7.0
Ž6.5 and* 7.5 E11A-K120A RHR Pump 1 C (Offsite Power Timer)
I C617 7.0
Ž6.5 and *7.5 E11A-K120B RHR Pump1 D (Offsite Power Timer) 1 C618 7.0 26.5 and S 7.5 E11 A-K202A RHR Pump iD (Offsite PowerTimer) 1 C617 7.0 26.5 and *7.5 E11 A-KI20A RHR Pump 2C (Offsite Power Timer) 2C617 7.0 2 6.5 and S 7.5 Eli1 A-K2021B RHR Pump 20 (Offsfte Power Timer) 20618 7.0
Ž:6.5 and5 *7.5 El1IA-K120B RHR Pump 2D (Offsite Power Timer) 2C618 7.0 2 6.5 and S7.5 E11A-K202A RHR Pump 2D (Offsite Power Timer) 2C617 7.0 2 6.5 and S7.5 E21 A-K106A CS Pump 1
A P
C626 10.5 9.4 and* 11.6 E21 A-K116B CS Pump 1 B 1 C627 10.5 9.4 and S 11.6 E21A-K125A CS Pump 1 C 1 C626 10.5
Ž9.4 and* 11.6 E21A-K125B CS Pump 1 D 1C627 10.5 2Ž9.4 and s 11.6 E21 A-KI 16A CS Pump 2A 2C626 10.5 k 9.4 and S 11.6 E21 A-K116B CS Pump 2A 2C627 10.5
Ž9.4 and*s 11.6 E21A-K125A CS Pump 20 2C626 10.5 29.4 and S 11.6 E21A-K125A CS Pump 2D 2C627 10.5 -
9.4 and* 11.6 E21 A-K1 6A CS Pump A (Offste Power Timer) 1 C626 15 0
14.0 and s 16.0 E21A-K16B CS Pump 1 A(Offsite Power Timer) 1 C627 15 2 14.0 and* 16.0 E21A-K25A CS Pump 10 (Offsite Power Timer) 1 C626 15
Ž 14.0 and S16.0 E21 A-K25B CS Pump 1 D (Offsite Power Timer) 1 C627 1 5 2 14.0 and
- 16.0 E21 A-K56A CS Pump 2A (Offsite Power Timer) 2C626 15 14.0 and s 16.0 E21A-K1<6A CS Pump 2A (Offsite Power Timer) 2C627 15
Ž 14.0 and *16.0 E21A-K25A CS Pump 20 (Offsite Power Timer) 2C626 15 a 14.0 and:s 16.0 E21A-K25B CS Pump 2D (Offsite Power Timer) 2C627 15
Ž14.0 and *16.0 62A-K2-2B 08 Emergency Service Water 1A201 42 -
2Ž 36 and S 144 62AX2-20208 Emergency Service Water 1A202 40 -
Ž36 and s 44 62AX2-20303 Emergency Service Water 1A203 44 39.6 and S 48.4 62AX2-20403 Emergency Service Water 1 A204 48
Ž 43.2 and
- 52.8 62X3-20404 Control Structure Chilled Water System A0877B 60 254 62X3-20304 Control Structure Chilled Water System OC877A 60
> 54 62X-20104 Emergency Switchgear Rm Cooler A & RHR OC877A 60 254 SW Pump H V Fan A__
62X-20204 Emergency Switchgear Rm Cooler B & RHR OC877B 60 2Ž54 SW Pump H&V Fan B 62X-5653A DG Room Exhaust Fan E3 OB565 60 2Ž54 62X-5652A DG Room Exhausts Fan E4 OB565 60 2Ž54 262X-20204 Emergency Switchaear Rm Cooler B OC877B 120 2 54 262X-20104 Emergency Switchgear Rm Cooler A OC877A 120 254 62X-546 DG Rm Exh Fan D 0-546 120 54 (continued)
SUSQUEHANNA - UNIT 2 TS I B 3.8-37 Revision 0
PPL Rev. 3 AC Sources-Operating B 3.8.1 TABLE B 3.8.1-1 (page 2 of 2)
UNIT I AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE TAG NO.
SYSTEM LOADING TIMER LOCATION (seconds)
VALUE (seconds) 62X-536 DG Rm Exh Fan C OB536 120 254 62X-526 DG Rm Exh Fan B OB526 120 254 62X-516 DG Rm Exh Fan A OB516 120
Ž54 CRX-5652A DG Room Supply Fans El and E2 OB565 120
Ž54 62X2-20410 Control Structure Chilled Water System OC876B 180 254 62X1-20304 Control Structure Chilled Water System 0C877A 180 254 62X2-20310 Control Structure Chilled Water System OC876A 180 254 62X1 -20404 Control Structure Chilled Water System OC877B 180
Ž54 62X2-20304 Control Structure Chilled Water System OC877A 210
Ž54 62X2-20404 Control Structure Chilled Water System OC877B 210
Ž54 62X-K11 BB Emergency Switchgear Rm Cooling 2CB250B 260 2 54 Compressor B 260 2_ 54 62X-KII1AB Emergency Switchgear Rm Cooling 2CB250A 250 Compressor A I_
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111 I: X SUSQUEHANNA - UNIT 2 TS I B 3.8-38 Revision 1
PPL Rev. 1 Distribution Systems-Operating B 3.8.7 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Distribution Systems-Operating BASES BACKGROUND The onsite Class 1 E AC and DC electrical power distribution system is divided into redundant and independent AC and DC electrical power distribution subsystems and a DG E electrical power distribution subsystem.
The primary AC distribution system consists of four 4.16 kV Engineered Safeguards System (ESS) buses each having a primary and alternate offsite source of power as well as an onsite diesel generator (DG) source that supports one 4.16 kV ESS bus in each unit. Each 4.16 kV ESS bus is normally supplied by either Startup Transformer (ST) No. 10 or ST No. 20. ST No. 10 and ST No. 20 each provide the normal source of power to two of the four 4.16 kV ESS buses in each Unit and the alternate source of power to the remaining two 4.16 kV ESS buses in each Unit. If any 4.16 kV ESS bus loses power, an automatic transfer from the normal to the alternate occurs after the normal supply breaker trips. If both offsite sources are unavailable, the onsite emergency DGs supply-power to the 4.16 kV
-ESS buses.
There are two 250 VDC electrical power distribution subsystems; four 125 VDC electrical power distribution subsystems; and, and one 125 VDC DG E electrical power distribution subsystem, all of which support the necessary power for ESF functions.
In addition, some components required by Unit 2 receive power through Unit 1 electrical power distribution subsystems, the Unit 1 AC and DC electrical power distribution subsystems needed to support the required equipment are addressed in Unit 2 LCO 3.8.7.
Required distribution subsystems are listed in LCO 3.8.7, Table 3.8.7-1.
APPLICABLE The initial conditions of Design Basis Accident (DBA) and SAFETY ANALYSES transient analyses in the FSAR, Chapter 6 (Ref. 1) and Chapter 15 (Ref. 2), assume ESF systems are OPERABLE. The AC and DC electrical power distribution systems are designed (continued)
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PPL Rev. 1 Distribution Systems-Operating B 3.8.7 BASES APPLICABLE to provide sufficient capacity, capability, redundancy, and reliability to SAFETY ANALYSES ensure the availability of necessary power to ESF systems so that the (continued) fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reabtor Coolant System (RCS); and Section 3.6 Containment Systems.
The OPERABILITY of the AC and DC electrical power distribution subsystems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining distribution systems OPERABLE during accident conditions in the event of:
- a.
An assumed loss of all offsite power or all onsite AC electrical power; and -
- b.
A worst case single failure.
The AC and DC electrical power distribution system satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).
LCO The required electrical power distribution -subsystems listed in
'Table 3.8.7-1 ensure the availability of AC and DC electrical power for the systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. The AC and DC electrical power distribution subsystems are required to be OPERABLE.
Maintaining the AC and DC electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor.
AC electrical power distribution subsystems require the associated buses and electrical circuits to be energized to their proper voltages. DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated battery or charger. The AC and DC electrical power distribution
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LCO subsystem is only considered Inoperable when the subsystem is not energized to its proper voltage.
APPLICABILITY The electrical power distribution subsystems are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:
- a.
Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AQOs or abnormal transients; and
- b.
Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
Electrical power distribution subsystem requirements for MODES 4 and 5 are covered in the Bases for LCO 3.8.8, "Distribution Systems-Shutdown."
ACTIONS A. 1 With one or more required Unit 2 ACbuses, load centers, motor
-control centers, or distribution panels inoperable but not resulting in a loss of safety function, or two Unit 1 AC electrical power distribution subsystems on one Division inoperable for performance of Unit I SR 3.8.1.19, the remaining AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The-overall reliability is reduced, however, because a single failure in the remaining power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the required AC buses, load centers, motor control centers, and distribution panels must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
The Condition A worst scenario is one division without AC power (i.e., no offsite power to the division and the associated DG inoperable). In this Condition, the unit is more vulnerable to a complete loss of AC power. It is, therefore, imperative that the unit operators' attention be focused on minimizing the potential for loss of power to the remaining division by stabilizing the unit, and on restoring power to the affected division. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time limit before
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PPL Rev. I Distribution Systems-Operating B 3.8.7 BASES (continued)
ACTIONS A.1 (continued) requiring a unit shutdown in this Condition is acceptable because:
- a.
There is a potential for decreased safety if the attention of unit operators is diverted from the evaluations and actions necessary to restore power to the affected division to the actions associated with taking the unit to shutdown within this time limit.
- b.
The potential for an event in conjunction with a single failure of a redundant component in the division with AC power. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP).")
The second Completion Time for Required Action A.1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single continuous occurrence of failing to meet LCO 3.8.7. If Condition A is entered while, for instance, a DC bus is inoperable and subsequently returned OPERABLE, this LCO may already have been not met for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This situation could lead to a total duration of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, since initial failure of the LCO, to restore the AC distribution system. At this time a DC circuit could again become inoperable, and AC distribution could be restored OPERABLE.
This could continue indefinitely.
This Completion Time allows for an exception to the normal "time zero" for-beginning the allowed outage time "clock." This results in establishing the "time zero" at the time this LCO was initially not met, instead of at the time Condition A was entered. The 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> Completion Time is an acceptable limitation on this potential to fail to meet the LCO indefinitely.
The completion time exception is not applicable to Condition E or F because Condition E and F are only applicable to DG E DC electrical power subsystem.
Condition A is modified by a Note that states that Condition A is not applicable to the DG E DC electrical power subsystem. Condition E or F is applicable to an inoperable DG E DC electrical power subsystem.
Required Action A. 1 is modified by a Note that requires the applicable Conditions and Required Actions of LCO 3.8.4 "DC Sources - Operating,"
to be entered for DC subsystems made inoperable by inoperable AC electrical power distribution subsystems. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for inoperable DC sources. Inoperability of a distribution subsystem can result in loss of charging power to batteries and eventual loss of DC power. This Note ensures that the appropriate attention is given to restoring charging power to batteries, if necessary, after loss of distribution systems.
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ACTIONS B. 1 (continued)
With one or more Unit 1 DC buses inoperable, the remaining DC electrical power distribution subsystems may be capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure.
The overall reliability is reduced, however, because a single failure in one of the remaining DC electrical power distribution subsystems could result in the minimum required ESF functions not being supported.
Therefore, the required DC buses must be restored to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> by powering the bus from the associated battery or charger.
Condition B represents one subsystem or multiple DE Buses without adequate DC power, potentially with both the battery significantly degraded and the associated charger non-functioning. In this situation the plant is significantly more vulnerable to a loss of minimally required DC power. It is, therefore, imperative that the operator's attention focus on stabilizing the plant, minimizing the potential for loss of power to the remaining divisions, and restoring power to the affected division.
This 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is more conservative than Completion Times allowed for the majority of components that would be without power. Taking exception to LCO 3.0.2 for components without adequate DC power, Which would have Required Action Completion Times shorter than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, is acceptable because of:
- a.
The potential for decreased safety when requiring a change in plant conditions (i.e., requiring a shutdown) while not allowing stable operations to continue;
- b.
The potential for decreased safety when requiring entry into numerous applicable Conditions and Required Actions for components without DC power, while not providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected division;
- c.
The potential for an event in conjunction with a single failure of a redundant component.
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ACTIONS B.1 (continued)
The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time for DC buses is consistent with Regulatory Guide 1.93 (Ref. 3).
The second Completion Time for Required Action B.1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single continuous occurrence of failing to meet the LCO. If Condition C is entered while, for instance, an AC bus is inoperable and subsequently restored OPERABLE, the LCO may already have been not met for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This situation could lead to a total duration of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, since initial failure of the LCO, to restore the DC distribution system. At this time, an AC division could again become inoperable, and DC distribution could be restored OPERABLE. This could continue indefinitely.
Condition B is modified by a Note that states that Condition B is not applicable to the DG E DC electrical power subsystem. Condition E or F is applicable to an inoperable DG E DC electrical power subsystem.
This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage timer"clock." This allowance results
-in establishing the "time zero". at the time the LCO-was initially not met, instead of at the time Condition C was entered. The 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> Completion Time is an acceptable limitation on-this potential of failing to meet the LCO indefinitely. The Completion Time exception is not applicable to Condition E and F because Condition E and F are only applicable to DG E DC electrical power subsystem.
C.1 With one Unit 1 AC electrical power subsystem that support Unit 2 inoperable, the remaining Unit I AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. However, the overall reliability is reduced because a single failure in the remaining AC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. The Completion (continued)
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ACTIONS C.1 (continued)
Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is consistent with the Completion Times associated with LCOs for the Unit 2 and common equipment potentially affected by loss of a Unit 1 AC electrical power subsystem.
D.1 and D.2 If the inoperable distribution subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
E. 1 If Diesel Generator E is not aligned to the Class 1E distribution system, the only supported safety function is for the ESW system. Therefore, under this condition, if Diesel Generator E DC power distribution subsystem is not OPERABLE, to ensure the OPERABILITY of the ESW system, actions are taken to either restore the power distribution subsystem to OPERABLE status or shutdown Diesel Generator E and close the associated ESW valves. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is consistent with the allowed time for other inoperable DC power distribution subsystems and provides sufficient time to evaluate the condition and take the corrective actions.
F. 1 If the Diesel Generator E is aligned to the class 1 E distribution system, the loss of Diesel Generator E DC power distribution subsystem will result in the loss of a on-site Class 1 E power source. Therefore, under this condition, if Diesel Generator E DC power distribution subsystem is not OPERABLE actions are taken to either restore the power distribution subsystem to OPERABLE status or declare Diesel Generator E inoperable and take Actions of LCO 3.8.1. The (continued)
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ACTIONS F. 1 (continued) 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is consistent with the allowed time for other DC sources and provides sufficient time to evaluate the condition and take the necessary corrective actions.
G.1 Condition G corresponds to a level of degradation in the electrical distribution system that causes a required safety function to be lost.
When more than one AC or DC electrical power distribution subsystem is lost, and this results in the loss of a required function, the plant is in a condition outside the accident analysis. Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown. Entry into Condition F is not required if the loss of safety function is the result of entry into Condition A in combination with the loss of safety functions governed by LCOs other than LCO 3.8.7. In this case, enter LCO 3.8.7, Condition A, and the Condition for loss of function in the LCO that governs the safety function that is lost.
H.1 With one or more Unit 1 DC electrical power subsystems inoperable, the remaining DC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. However, The overall reliability is reduced because a single failure in the remaining DC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. The Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is consistent with the Completion Times associated with a loss of one or more DC distribution subsystems and will allow sufficient time to restore power.
Completion of Required Action H.1 causes Unit 1 loads to be powered from a Unit 2 DC electrical power subsystem.
Although the corresponding Unit 2 DC electrical power subsystem is evaluated for this condition, this condition is outside the design commitment to maintain DC power separation between units. To minimize the time this (continued)
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BAS-ES-(continuedV' ACTIONS H.1 (continued) condition exists, Required Action H.2 direct power to be restored from the corresponding Unit I DC electrical power subsystem, which restores power to the common loads, or requires that the Unit I and common loads be declared inoperable. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provides sufficient time to restore power and acknowledges the fact that the condition, although not consistent with all design requirements, maintains all required safety systems available.
1.1 If Unit 1 and common loads required to support Unit 2 cannot be transferred to corresponding Unit 2 DC electrical power subsystem when Unit 1 DC sources are inoperable; or, cannot be transferred back to a Unit 1 DC source when the Unit I DC source becomes OPERABLE, the associated loads may be incapable of performing their intended function and must be declared inoperable immediately.
SURVEILLANCE SR 3.8.7.1 REQUIREMENTS
-This Surveillance verifies that the AC and DC, electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate independence of the electrical buses are maintained, and the appropriate voltage or indicated power is available to each required bus. This includes a verification that Unit 1 and common 125 VDC loads are aligned to a Unit 1 DC power distribution subsystem. The verification of voltage availability on the buses ensures that the required voltage is readily available for motive as well as control functions for critical system loads connected to these buses. The 7 day Frequency takes into account the redundant capability of the AC and DC electrical power distribution subsystems, and other indications available in the control room that alert the operator to subsystem malfunctions.
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- BASES (continued)
REFERENCES
- 1.
FSAR, Chapter 6.
- 2.
FSAR, Chapter 15.
- 3.
Regulatory Guide 1.93, December 1974.
- 4.
Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
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