ML20212C695

Proposed Tech Specs,Constituting Rev 2 to CPS TS Bases.Rev Consists of Pages Annotated W/Rev Numbers 2-1 Through 2-14

ML20212C695
Person / Time
Site:	Clinton
Issue date:	10/23/1997
From:	ILLINOIS POWER CO.
To:
Shared Package
ML20212C694	List: ML20212C695 U-602832, Forwards Rev 2 to CPS TS Bases,Consisting of Pages Annotated W/Rev Numbers 2-1 Through 2-14.Text Changes Identified by Rev Bars
References
NUDOCS 9710300104
Download: ML20212C695 (104)

Text

l o

l-Enclosure 1 to U-602832

, Page1 of104 f

f' Revision 2 to the CPS TechnicalSpecification Bases o .

p-i 9710300104 977023 W PDR ADOCK 05000461; P PDR ,

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TABLE OF CONTENTS

( l.0 1.1 USE AND APPLICATION Definitions 1.0-1 1.0-1 1.2 Logical Connectors . . . . . . . . . . . . . . . . . . . 1.0-8 i 1.3 Completion Times . . . . . . . . . . . . . . . . . . . . 1.0-11 l.4 Frequency ....................... 1.0-24 2.0 SAFETY LINITS (SLs) .................... 2.0-1 .

2.1 SLs . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0-1 i 2.2 2.0-1

.SL Violations ......................

B 2.0 SAFETY LIMITS (SLs) .................... B 2.0-1 '

B 2.1.1 Reactor Core SLs . . . . . . . . . . . . . . . . . . . . B 2.0-1 B 2.1.2 Reactor Coolant System (RCS) Pressure SL . . . . . . . . B 2.0-6 2

3.0 LIMITING CONDITION FOR OPERATION.(LCO) APPLICABILITY , . . . 3.0-1 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY , . . . .... 3.0-4 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY . . . . B 3.0-1 j .B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY . . . . . ... B 3.0-10 3.1 REACTIVITY CONTROL SYSTEMS . . . . . . . . . . . . . . . . . 3.1-1 3.1.1 SHUTDOWN MARGIN (SDM) . . . . . . . . . . . . . . ... 3.1-1 3.1.2 Re act i v i ty An omal i e s - . . . . . . . . . . . . . . . . . . 3.1-5 3.1.3 Control Rod OPERABILITY . . . . . . . . . . . .... 3.1-7 3.1.4 Control Rod Scram Times . . . . . . . .- . . . . .... 3.1 -

3.1.5 Control Rod Scram Accumulators . . . . . . . . . . . . . 3.1-15

('-' 3.1.6 3.1.7 Control Rod Pattern ...

Standby Liquid Control (SLC) System 3.1-18 3.1-20

! 3.1.8 Scram Discharge Volume (SDV) Vent and .

Drain Valves . . . . . . . . . . . . . . . . . . . . 3.1-24 ,

B 3.1 REACTIVITY CONTROL SYSTEMS . . . . . . . . . . . . . . . . . B 3.1-1 B 3.1.1 SHUTDOWN MARGIN (SDM) . . .. . . . . . . . . . . .... B 3.1-1 B 3.1.2 Re act i v i ty An omal i e s . . . . . . . . . . . . . . . . . . B 3.1-B B 3.1.3 Control kod OPERABILITY . . . . . . . . . . . . .... B 3.1-13 B 3.1.4 Control Rod Scram Times . . . . . . . . . . . . .... B 3.1-22 B 3.1.5 Control Rod Scr.m Accumulators . . . . . . . . . . . . . B 3.1-28 8 3.1.6 Control Rod Pattern .................. B 3.1-33 8 3.1.7 Standby Liquid Control (SLC) System .. . . . . . .... B 3.1-3B l B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves . . . . . . . . . . . . . . . . . . . . . . . B 3.1-44 3.2 POWER DISTRIBUTION LIMITS . . . . . . . . . . . . . .... 3.2-1 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGRI ........................ 3.2-1 (continued)

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CLINTON i M ision No. 2-13

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TABLE OF CONTENTS

/ 3 .1.

3.2.2 -

-POWER DISTRIBUTION LIMITS (continued) 3.2 2 MINIMUM CRITICAL POWER RATIO (MCPR) . . . . . . . . ... . .

3.2.3 LINEAR HEAT GENERATION RATE (LHGR) . . . ... . . . . . . . 3.2 l -B 3.2 -POWER DISTRIBUTION LIMITS ................. B 3.2-1 B 3.2.1 AVERACE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) . . . . . . . . . . . . . . . , . . . . . . . . B 3.2-1

B 3.2-5 B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) ............

i B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR) . . . . . . . . . . . . . B 3'.2-9

3.3 . INSTRUMENTATION ..............,....... 3.3-1 4

3.3.1.1 Reactor Protection System (RPS)' Instrumentation .... 3.3-1 3.3.1.2 ' Source Range Monitor (SRM) Instrumentation . . . . . . . 3.3-10 3.3.2.1 Control Rod Block Instrumentation ............ 3.3-)

, 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation . . . . . 3.34 ,

3.3.3.2 Remote Shutdown System . . . . . . . . . . . . . . . . . 3.3-23

3.3.4.1 EndofCycleRecirculationPumpTrip(EOC-RPT)

Instrumentation. . . . . . . . . . . . . . . . . . 3.3-25 i 3.3.4.2 Anticipated Transient Without Scram Recirculation l Pump Trip (ATWS-RPT) Instrumentation . . . . . . . . 3.3-28 3.3.5.1 Emergency Core Cooling System (ECCS) --

4: -

Instrumentation .-................. 3.3-31 j- ,

3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation .................. '

3.3-44-- -

1 3.3.6.1 Primary Containment and Drywell l- Isolation Instrumentation . . . . . .. . . . . . . . 3.3-48 (

3.3.6.2 Secondary Containment Isolution Instrumentation .... 3.3 61 lF 4' '

3.S.6.3 Residual Heat Removal (RHR) Containment Spray *

System Instrumentation . . .-.. . . . . . . . . . . . 3.3-65 j 3.3.6.4 Suppression Pool ~ Makeup (SPMU) System Instrumentation . . . . . . . .- . . . . . . . . . . . 3.3-69 i

3.3.6.5 Relief and low-low Set (LLS) Instrumentation . . . . . . 3.3-73 L

3.3.7.1 Control Room Ventilation System

~ Instrumentation .................. 3.3-75 l- :3.3.8.1 Loss of. Power (LOP) Instrumentation. . . . ... . . . . . 3.3-78

3.3.8.2 Reactor Protection System (RPS) Electric Power l- Monitoring'. . . . . . . . . . . . .

. . . . . . . . 3.3-81 i' B 3.3 INSTRUMENTATION ......-......,......... B 3.3 ; B 3.3.1.1 Reactor Protection System (RPS)-

. . Instrumentation .....-............. B 3.3-1 i B 3.3.1.2 Source Range Monitor (SRM) Instrumentation . . . . . . . B'3.3-31 B 3.3.2.1 Control Rod Block Instrumentation ........... B 3.3-40 B 3.3.3.1~ Post Accident Monitoring (PAM)-

i' Instrumentation .................. B 3.3-49 l-

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y CLINTON 11 - Revie, ion No. 2-13 i

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TABLE OF CONTENTS

{ B 3.3 INSTRUMENTATION (continued)

B 3.3.3.2 Remote Shutdown System . . . . . . . . . . . . . . . . . B 3.3-60 B 3.3.4.1 End of Cycle Recirculation Pump Trip (E0C-RPT) Instrumentation ............. B 3.3-65 B 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation .................. B 3.3-76 B 3.3.5.1 Emergency Core Cooling System (ECCS)

. Instrumentation .................. B 3.3-85

B 3.3.5.2 Reactor Core Isolation Cooling (RCIC)

System Instrumentation . . . . . . . . . . . . . . . B 3.3-123 B 3.3.6.1 Primary Containment and Drywell Isolation Instrumentation ............. B 3.3-135 6 3.3.6.2 Secondary Containment Isolation Instrumentation .................. B 3.3-174 B 3.3.6.3 Residual Heat Removal (RHR) Containment Spray System Instrumentation . . . . . . . . . . . . . . . B 3.3-186 8 3.3.6.4 Suppression Pool Makeup (SPMU) System Instrumentation .................. B 3.3-197 B 3.3.6.5 Relief and low-Low Set (LLS) Instrumentation . . . . . . B 3.3-208 8 3.3.7.1 Control Room Ventilation (CRV) System Instrumentation .................. B 3.3-215 B 3.3.8.1 Loss of Power (LOP) Instrumentation .......... B 3.3-222

• B 3.3.8.2 Reactor Protection System (RPS) Electric' '

• Power Monitoring . . . . . . . . . . . . . . . . . . B 3.3-230

{

. 3.4 REACTOR COOLANT SYSTEM (RCS) . . . . . . . . . . . . . . . . 3.4-1 '

3.4.1 Recirculation Loops Operating ............. 3.4-1 3.4.2 Flow Control Valves (FCVs) . . . . . . . . . . . . . . . 3.4-6 3.4.3 Jet Pumps ....................... 3.4-8 3.4.4 Safety / Relief Valves (S/RVs) . . . . . . . . . . . . . . 3.4-10 3.4.5 RCS Operational LEAKAGE ................ 3.4-12 3.4.6 RCS Pressure Isolation Valve (PIV) Leakage . . . . . . . 3.4-14 3.4.7 RCS Leakage Detection Instrumentation ......... 3.4-17 3.4.8 RCS Specific Activity ................. 3.4-20 3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown . . . . . . . . . . . . . . . . 3.4-22 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown ............... 3.4-25 3.4.11 RCS Pressure and Temperature (P/T) Limits . . . . . . . - 3.4-27 3.4.12 Reactor Steam Dome Pressure .............. 3.4-33

B 3.4 REACTOR COOLANT SYSTEM (RCS) . . . . . . . . . . . . . . . . B 3.4-1 B 3.4.1 Recirculation Loops Operating ............. B 3.4-1 E 3.4.2 Flow Control Valves (FCVs) . . . . . . . . . . . . . . . B 3.4-9 (continued)

CLINTON iii Revision No. 2-13

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TABLE OF CONTENTS f

B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

(

B 3.4.3 Jet Pumps ........................ B 3.4-13 8 3.4.4 Safety / Relief Valves (S/RVs) . . . . . . . . . . . . . . B 3.4-17 B 3.0.5 RCS Operational LEAKAGE ................ B 3.4-23 83.4.6 RCS Pressure Isolation Valve (PlV) Leakage . . . . . . . B 3.4-28 B 3.4. 7 RCS Leakage Detection Instrumentation ......... B 3.4-33 B 3.4.8 RCS Specific Activity ... .............. B 3.4-39 B ,s.4.9 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown . . . . . . . . . . . . . . . . B 3.4-43 8 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown ............... B 3.4-48 B 3.4.11 RCS Pressure and Temperature /! Limits ....... B 3.4-53 B 3.4.12 Reactor Steam Dome Pressure . ........... B 3.4-62 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM .............. 3.5-1 3.5.1 ECCS-Operating .................... 3.5-1 3.5.2 ECCS--Shutdown . . . . . . . . . . . . . . . . . . . . . 3.5-6 3.5.3 RCIC System ...................... 3.5-10 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE. ISOLATION COOLING (RCIC) SYSTEM . . . . . . . . . . . . B 3.5-1 B 3.5.1 ECCS-Operating ...................... B 3.5-1 B 3.5.2 EC C S - Sh u t d own . . . . . . . . . . . . . . . . . , . . . . . B 3.5-15 '

B 3.5.3 RCIC System ........................ B 3.5-;l 3.C CONTAINMENT SYSTEMS .................... 3.6-1 3.6.1.1 Primary Coritainment ,,................ 3.6-1

• 3.6.1.2 Primary Containment Air Locks ............. 3.6-3 3.6.1.3 Primary Containment Isolation Valves (PCIVs) . . . . . . 3.6-9 3.6.1.4 Primary Containment Pressure . . . . . . . . . . . . . . 3.6-20 3.6.1.5 Primary Containment Air Tenperature .......... 3.6-21 3.6.1.6 Iow-Low Set (LLS) Valves . . . . . . . . . . . . . . . . 3.6-22 3.6.1.7 kesidual Heat Renova; (RHR) Containment Spray System . . . . . . . . . . . . . . . . . . . . 3.6-24 3.6.1.8 Main Steam isolation Vcive (MSIV) Leakage Control System (LCS) . . . . . . . . . . . . . . . . . . . . 3.6-26 3.6.2.1 Suppression Pool Average Temperature . . . . . . . . . . 3.6-28 3.6.2.2 Suppression Pool Water Level . . . . . . . . . . . . . . 3.6-31 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ...................... 3.6-32 3.6.2.4 Suppression Pool Makeup (SPMU) System ......... 3.6-34 3.6.3.1 Primary Containment Hydrogen Recombiners . . . . . . . . 3.6-36 3.6.3.2 Primary Containmant and Drywell Hydrogen Igniters . . . . . . . . . . . . . . . . . . . . . . 3.6-38 (continued)

CLINTON iv -

Revision No. 2-13

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TABLE OF CONTENTS 3,6 - CONTAINMENT; SYSTEMS;-(continued):

3.6.3.3 Containment /Drywell Hydrogen Mixing Syster.s . . . . . . -3.6-41 3.6.4.1 - Secondary Containment .=.-. . . . . . .- -. . . . . . . 3.6-43 3.6.4.2 Secondary Containment Isolation Dampers-(SCIDs) .... 3.6 -

3.6.4.3- Standby Gas Treatment 3.6 51 3.6.5.1 ;Drywell . . . . . . .(SGT) -

System . . . . . . . . . . .

. . . . _ . . . . . . . . . . . - . . - . 3.6-54 3.6.5.2- Drywell Air Lock'. . . . . . . . . . . . . . . . . . . 3.6-56 3.6.5.3= Drywell- Isol ation Valves . . . . . . . . . . . . .r . ... 3.6-61 3.6.5.4 Dryvell Presstre . . . . . . . . . . . . . . . . . . . . 3.6-66 3.6.5.5 Drywell Air Temperature . . .............. 3.6-67

-3.6.5.6 . Drywell Post--LDCA Vacuum Relief System . . ._. . . . . 3.6-68 8 3.6 CONTAINMENT SYSTEMS . . . . . . . . . . . . . . . . . . . . B 3.6-1 B 3;6.1.1 Primary Containment . . . . .............. B 3.6-1 B 3.6.1.2- Primary Containeeta Air Locks . . . . . . . . . . . . . B 3.6-6~

-B 3.6.1.3 Primary Containment Isolation Valves (PCIVs) . . . . . . B'3.6-15 B 3.6.1.4 Primary Containment Pressure . . . . . . . . .-. . . . . B 3.6-25

.8 3.6.1.5 Primary Containment Air -Temperature . . . . . . . . . . B 3.6-32 B 3.6.1.6- Low-Low Set (LLS) Valves . . . . . . . . . . . . . . . - . B 3.6-35 B 3.6.1.7 Residual Heat Removal _(RHR) Containment -

Sp ray Sy s t em . . . . . . . . . . . . . . . . . . . . . .

B3.6-39 B 3.6.1.8 Main Steam Isolation Valve (MSIV) Leakage Control System (LCS) . . . . . . . . . . . .-. . . . 8 3.6-44 B 3.6.2.1 Suppression Pool Average' Temperature . / . . *. . . . , . . B 3.6-48 '

B 3.6.2.2 Suppression Poc1 Water Level . . . . . . . . . . . . . . B 3.6-53

(- B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling. . . . .J. . . . .......-....... B 3.6-56 B'3.6.2.4- Suppression Pool Makeup (SPMU) System . . . . . . . . . B 3.6-67 8 3.6.3.1 Primary Containment Hydrogen Recombiners . . . . . . . . B 3.6-66~

B 3.6.3.2 Pr.imary Containment ant! Drywell Hydrogen .

Igniters . . . . . . . . . ... . . . .-. . . . . . . B 3.6-72 B 3.6.3.3 Containment /Drywell Hydrogen Mixing System . . . . . . . B 3.6-78 B 3.6.4.1 Secondary Containment . . . . . . . . . . . . . . . -. . B 3.6-83 B 3.6.4.2 Secondary Containment Isolation

-- Dampers (SCIDs) ,. . . . . . . . . . . . . . . . . . B 3.6-89 B 3.6.4.3 Standby Gas Treatment (SGT) System . . . . . . . . . ... B 3.6-96 B 3.6.5.1 _ Drywell . .... . . ._. . . . . . . . . . . . . . . .-.

. B 3.6-102 B 3.6.5.2 Drywell Air Lock . . ... . . . . . . . . . . . . . . . . B 3.6-106

-B 3.6.5.3 ' Drywell Isolation Valves . . . . . . . . . . . . . . . . B 3.6-113 B 3.6.5.4 Drywell Pressure 1. . . . . . . . . . . . . . . . . ....

B 3.6-122-T -8 3.6.5.5 Drywell Air Temperature . . . . . . . . .-. . . . . . . B 3.6-125 B 3.6.5.6 Drywell Post-LOCA Vacuum Relief System . . . . . - . . . . B 3.6-128

.(continued) k

< CLINTON v . Revision No. 2-13

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TABLE OF CONTENTS- (continued)'

3.7 _ _ PLANT-SYSTEMS ... . . . . . . . . . . . . . . . .-. . . . .

3.7-1 3.7.1- Division 1 and 2 Shutdown Service Water (SX) Subsystems and Ultimate Heat Sink (UHS) . . . . . , . . . . . . 3.7-1 3.7.2 Division 3 Shutdown Service Water (SX).

Subsystem . . . . . . ...-. . . .-. . . . . . . . . 3.7-3 3.7.3: Control Room Ventilation System . . . . - . . . . . . . . . 3.7-4 3.7.4 - Control Room Air Conditioning (AC)-System .... .. 3.7 3.7.5 Main Condenser Offgas .................. 3.7-11

3. 7. 6 Main Turbine Bypass System . . . . . . . . . . . . . . . 3.7-13 3.7.7- Fuel Pool Water Level ................. 3.7-14 8 3.7 PLANT SYSTEMS ............-........... B 3.7-1 B 3.7.1 Division 1 and 2 Shutdown Service Water (SX)

-Subsystems-ar.d Ultimate Heat Sink (UHS) ...... B 3.7-1 B 3.7.2 _ Division 3 Shutdown Servica Water Subsystem (SX) . . . . B 3.7-7 8 3.7.3 Control Room Ventilation System . . . . . . . . . . . . B 3.7-10 B 3.7.4 Control Room Air Conditioning (AC) System ....... B 3.7-17 B 3.7.5 Main Condenser Offgas ......... ...... B 3.7-22 B 3.7.6 Main-Turbine Bypass System . . . . . . . . . . . . ._. . B 3.7-25 B 3.7.7 Fuel Pool Water Level . . . . . . . . . . . . . . . . . B 3.7-28 3.8 ELECTRICAL POWER SYSTEMS . . . . . . . . . . . . . . . . . . 3.8-1 3.8.1 AC Sources-Operating ................. -

3.8-1 i 3.8.2 AC Sout ces-Shutdown . . . . . . . . . . . . . . . . . . 3.8 -

l 3.8.3 Diesel Fuel Oil, Lube 011, and Starting Air ...... 3.8-20 3.8.4 DC Sources-Operating 3.8-24 3.8.5 DC Sources-Shutdown . . . . . . . . . . . . . . . . . . 3.8-27 (

3.8.6 -Batteiy Cell Parameters

.........,....... 3.8-30  :

3,S 7 Inverters-0)erating . . . . . . . . . . . . . . . . . . - 3.8-34 3.8.8 - Inverters-S tutdown ............... ,. 3.8-36 3.8.9- Distribution Systems-Operating ............ 3.8-39.

3.8.10 Distribution Syste'ns-Shutdown . . . . . . . . . . . . . 3.8-42 B 3.8 ELECTRICAL POWER SYSTEMS . . . . . . . .-. . . . . . . . . . B 3.8-1 B 3.8.1 AC Sources-Operating . . ............. B 3.8-1 8 3.8.2 AC Sources-Shutdown . . . . . . . . . . . . . . . . . . B 3.8-33 8 3.8.32 Diesel Fuel Oil, Lube 011, and Starting Air '

. . . . -. B 3.8 8 3.8.4 DC Sources-Operating . . _. . . _ . -........... B 3.8-49 B 3.8.5 DC Sources-Shutdown . . . . . . . . . . . . . . , . . . - B 3.8-58 B_3.8.6 Battery Cell Parameters . . . . . . . . . . . . . . . . _. B 3.8-62

-8 3.8.7 Inverters-0perating' . . . . . - , . . . . . . . . . . . . B 3.8-69 B 3.8.8 Inverters-Shutdown . . . . . . . . ... . . . . . . . . B 3.8-74 B 3.8.9 Distribution Systems-Operating ............ B 3.8-78 8 3.8.10. Distribution Systems-Shutdown . . . . . . . . . . . . . B 3.8 (continued) j CLINTON vi . Revision No. 2 .

v

TABLE OF CONTENTS (continuod)'

[ 3.9 REFUELING OPERATIONS . . . . . , . . .-. . . . . . .=. . . .- 3.9-1 3.9.1: Refueling Equipment Interlocks . .-- ' . . . . - . . . . . 3.9-1

- 3.9.2 Refuel Position One-Rod-Out Interlock ......... 3.9-2 3.9.3 Control Rod' Position . . . . . . . . . . . . . . . . . . 3.9-3

-- 3.9.4- Control Rod Position--Indication . . . . . . . . . . . . 3.9-4 3.9.5:: Control Rod OPERABILITY-Refueling . . . . . . . . . . . .

3.9-7 3.9.6 Reactor. Pressure Vessel (RPV) Water Level-Irradiated Fuel . . . -

, . . .-_ . . . . . - . ._ 3.9-8 3.9.7 -Reactor Pressure Vessel-(RPV) Water Level-New Fuel or Control Rods .......... 3.9-9 3.9.8 Residual Heat Removal (RHR)-High Water Level . . . . . 3.9-10

-3.9.9 Residual Heat Removal-(RHR)-Low Water Level . . . . . . 3.9-13 B 3.9 :- REFUELING OPERATIONS . . . . . . . . . . . . . . . .'. . . .--B 3.9-1 B 3.9.1 Refueling Equipment Interlocks . . . . . . . . . . . . . B 3.9-1 B 3.9.2  : Refuel- Position One-Rod-Out Interlock . . . . . . . . . - B 3.9-5 B 3.9.3 Control Rod Position-. . . . . . . . . . . . . . . . . . B 3.9 B 3.9.4- Control Rod Position Indication . . . . . .-.-. . . . . B 3.9-12 B 3.9.5 Control Rod OPERABILITY-Refueling . . . . . . . . = . . . B 3.9-16 r B 3.9.6 Reactor Pressure Vessel (RPV) Water Level. -

L -

-Irradiated Fuel ..,.............. B 3.9-19

! B 3.9.7 Reactor Pressure Vessel-(RPV) Water Level-New Fuel or Control Rods ............. B 3.9-22 l

B 3.9.8 Residual Heat Removal (RHR)-High Water i.evel- ..... .

-B 3.9-25 *

. B 3.9.9 Residual Heat Removal '(RHR)-Low Water Level . . . . . . B 3.9-29

(

3.10 SPECIAL OPERATIONS . . . .:. . ... . . . . . . . . . . . . . 3.10-1 3.10.1 . Inservice f.eak and Hydrostatic Testing Operation'. . . .- 3.10 3.10.2- Reactor Mode Switch Interlock Testing . . . . . . . . . 3.10-3 Single Control Rod Withdrawal-Hot Shutdown , . . . . . 3.10-6 3.10.3 3.10.4 Single Control Rod Nithdrawal-Cold Shutdown . . . . . . 3.10-9 3.10.5 -Single Control Rod Drive (CRD)

Removal-Refuel ing . - . . . . . ' . . . . . . . . . . . 3.10-13 3.10.6: Multiple Control Rod Withdrawal-Refueling . .. . . . . . 3.10-16 3.10.7- - Control Rod Testing-Operating . . . . . . . . . . . . . . 3.10-19 3.10.8~ SHUIDOWN MARGIN (SDM) Test-Refueling ......... 3.10-20 3.10.9 - Training Startups- . . . . . . . . . . . . . . . . . . . 3.10-24 3.10.10 - Single Control-_ Rod Withdrawal-Refueling . . . . . . . , 3.10-25 l

-B 3.10 SPECIAL OPERATIONS . . ... . . . . ... . . . . . . . . . . . B 3.10-1 0 3.10.1 Inservice Leak and Hydrostatic Testing .

Operation . . . . . . . . . . . . . . . . . . . . B 3.10-1 B 3.10.2 Reactor Mode Switch Interlock Testing ......... B 3.10-6 B 3.10.3 Single Control Rod Withdrawal-Hot Shutdown .-.

- . . . . B 3.10-11 8 3.10.4 Single control Rod Withdrawal--Cold Shutdown . . . . . .. B 3.10-16

-(continued)

.(

CLINTON- vit' ,

Revision No. 2-13

?

> TABLE OF, CONTENTS h B 3.10 .SPECIAL' CONDITIONS: (continued)

B 3.10.5 Single Control Rod Drive (CRD)- Removal- :

(

Refueling . . . ... . . . . . . ... . . . . . . . . B 3.10-21 B 3.10.6 - Multiple Control- Rod Withdrawal--Refueling . . . . . . . B 3.10-26 B 3.10.7- Control Rod Testing--Operating . . ' . . . . . . : . . . . . B 3.10-29 B 3.10.8 SHUTDOWN MARGIN (SDM) Test--Refueling -. . . . . . . . . B 3.10-33 B 3.10.9 Training Startups .

..........-. . . . . . . B 3.10-39

.l B 3.10.10 Single Control Rod-Withdrawal--Refueling . . . . . . . . B 3.10 42

-4.0 DESIGN FEATURES . . . . . . . . .--. . . . . . . . .-. . . . 4.0 1 4.11 Site Location . . . . . . . . . . . . . . . . . . . . . . 4.0-1 4.2 Reactor Core . . . . . . . . . . . . . . . .-. . . . . . 4.0-1 4.3 Fuel Storage . . . . . . . . . . . . . . . . . . . . . . 4.0-2 -

5.0-- ADMINISTRATIVE CONTROLS .................. 5.0-1 5.1 Responsibility . . . . . . . . . . . . . . . . . . . . . 5.0-1 5.2- - O rg an i z a t i on . . . . . . . . . . . . . . . . . . . . . . 5.0-2 5.3 Unit- Staff Qualifications - . . . . . . . . . . . . . . . 5.0-5 5.4 Procedures-. ... . . . . . . . . . . . . . . . . . . . 5.0-6 5.5 Programs and Manuals . . . . . . . . . . . . . . . . . . 5.0-7 4 5.6 - Reporting Requirements . . . . . . . . . . . . . . . . . 5.0-17 '

5.7 High Radiation Area .................. 5.0-20

(

CLINTON viij .

Revision No. 2-13 r

SR Applicability B 3.0

. BASES l.

SR 3.0.2 The 25% extension does not significantly degrade the (continued) reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the frequency does not apply. These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. Therefore, when a test interval is specified in the regulations, the test interval cannot be extended by the TS, and the TS will then include a Note stating, "SR 3.0.2 is not applicable." An example of an exception when the test interval is not specified in the regulations is the Note in the Primary Containment Leakage Rate Testing Program, "SR 3.0.2 is not applicable." This exception is provided because the program already includes extension of test intervals.-  ;

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Com)letion Time that requires performance on a "once per. . ." aasis. The 25%

extension applies to each performance after the initial performance. The initial ~ performance of the Required g Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25%

extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of SR 3_0.2 are not intended to be used repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified frequency, whichever is less, applies from the point in time that it is discovered thtt the Surveillance has not been

-performed in accordance with SR 3.0.2, and not-at the time (continued)

CLINTON- B 3.0-12 ,

Revision No. 2-5

Control Rod OPERABILil~

B 3.1.3

. BASES.-(continued)

SURVEILLANCE SR- 3.1.3.1 REQUIREMENTS.  !

The position of each control rod must be determined, to i

. ensure adequate information on control rod position is available to the operator for determining control rod OPERABILITY and controlling rod patterns. Control rod -

position may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. 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 is based on operating experience related to expected changes in control rod position and the availability of control rod position indications in the control room.

SR 3.1.3.2 and SR 3.1.3.3 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves.

The control rod may then be returned to its original position. This ensures the control rod is not stuck and is free to insert on a scram signal. These Surveillances are modified by notes identifying that the Surveillances are not-required to be performed when THERMAL POWER is less than or equal to the actual LPSP of the RPC since the notch

insertions may not be compatible with the requirements of 1

BPWS (LC0 3.1.6) and the RPC (LC0 3.3.2.1). These notes also provide a time allowance (i.e., the associated SR frequency plus the extension allowed by SR 3.0.2) such that the Surveillances are not required to be performed until-the next scheduled control rod testing for control rods of the same category (i.e., fully withdrawn or partially withdrawn). These notes provide this allowance to prevent unnecessary perturbations in reactor operation to perform this testir.g on a control rod whose surveillance category (i.e., fully withdrawn or partially withdrawn) has changed.

The 7 day Frequency of SR 3.1.3.2 is based on operating experience related to the changes in CRD performance and the ease of performing notch testing for fully withdrawn control rods. Partially withdrawn control rods are tested at a 31 day Frequency,-based on the potential power reduction required to allow the control rod movement, and considering the large testing sample of SR 3.1.3.2. Furthermore, the 31 day Frequency takes into-account operating experience related to changes in CRD performance. At any time, if a control rod is (continued)

CLINTON B 3.1-19 Revision No. 2-14

Control Rod Scram Times B 3.1.4

• ( BASES (continued)

SURVEILLANCE The four SRs of this LCO are modified by a Note stating that REQUIREMENTS during a single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated (i.e., charging valve closed), the influence of the CRD pump head does not affect the sir.gle control rod scram times. During a full core scram, the CR0 pump head would be seen by all control rods and would have a negligible effect on the scram insertion times.

SR 3.1.4.1 The scram reactivity used in DBA and transient analyses is based on assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure m 950 psig demonstrates acceptable scram times for the transients analyzed in References 3 and 4.

Scram insertion times increase with increasing reactor pressure because of the competing effects of reactor steam dome pressure and stored accumulator energy. Therefore.

demonstration of adequate scram times at reactor steam dome pressure a 950 psig ensures that the scram times will be

(, within the specified limits at higher pressures. Limits are

~

s)ecified as a function of reactor pressure to account for tie,se'nsitivity of the scram insertion times with pressure -

and to allow a range of pressures over which scram time testing .an be performed. To ensure scram time testing is performed within a reasonable time following fuel movement within the reactor pressure vessel or after a shutdown a 120 days, control rods are required to be tested before exceeding 40% RTP. In the event fuel movement is limited to selected core cells, it is the intent of this SR that only those CRDs associated with the core cells affected by the fuel movements are required to be scram time tested.

However, if the reactor remains shutdown a 120 days, all control rods are required to be scram time tested. This Frequency is acceptable, considering the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing of control rods affected by work on control rods or the CRD System.

SR 3.1.4.2 Additional testing of a sample of control rods is required to verify the continued performance of the scram Tur.ction during the cycle. A representative sample contains at least f (continuedl CLINTON B 3.1-25 Revision No. 2-13 k

l l

. N

Control Rod Scram Timts B 3.1.4 BASES [

SURVEILLANCE SR 3.1.4.2 (continued)

REQUIREMENTS 10% of the control rods. The sample remains i

" representative" if no more than 20% of the control rods in the tested sample are determined to be " slow." If more than 20% of the sample is declared to be " slow" per the critt.ria in Table 3.1.41, additional control rods are tested until this 20% criterion (i.e., 20% of the entire sample size) is satisfied, or until the total number of " slow" control rods throughout the core, from all surveillances) exceed the LC0 limit. For 11anned testing, the control rods selected for the sample siould be different for each test. Data from int.dvertent scrams should be used whenever possible to coid unnecessary testing at power, even if the control rods with data were previously tested in a sample. The 120 day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable, based on the additional Surveillances done on the CRDs at more frequent intervals in accordance with LCO 3.1.3 and LCO 3.1.5, " Control Rod Scram Accumulators."

SR 3.1.4.3

(

When work t' hat could affect the scram insertion time is perfohied on a' control rod or the CRD System, testing must

• be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram time testing must demonstrate that the affected control rod is still within acceptable limits by demonstrating an acceptable scram insertion time to notch position 13. The' scram time acceptance criteria for this alternate test shall be determined by linear interpolation between 0.95 seconds at a reactor coolant pressure of 0 psig and 1.40 seconds at 950 psig. The limits for reactor pressures < 950 psig are established based on a high probability of meeting the acceptance criteria at reactor pressures a 950 psig. Limits for a 950 psig are found in Table 3.1.4-1. If tasting demonstrates the affected control rod does not meet these limits, but is within the 7 second limit of Table 3.1.4-1 Note 2, the control rod can be declared OPERABLE and " slow."

Specific examples of work that could affect the scram times include (but are not limited to) the following: removal af (continued) k CLINTON 3 3.1-26 Revision No. 2-13 l

Control Rod Scram Times B 3.1.4

( BASES SURVEILLANCE SR 3.1.4.3 (continued)

REQUIREMENTS any CR0 for maintenan w or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator isolation valve, or check valves in the piping required for scram.

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

SR 3.1.4.4 When work that could affect the scram insertion time is performed on a control rod or CRD System, testing must be done to demonstrate each affected control rod is still I

within the limits of Table 3.1.4-1 with the reactor steam )

dome pressure 2: 950 psig. Where work has been performed at high reactor pressure, the requirements of SR 3.1.4.3 and SR 3.1.4.4 will be satisfied with one test. For a control -

rod affected by work performed while shut down, however, a

(' zero pressure and a high pressure test may be required.

This testing ensures that the control rod scram performance t i~s acc'eptable for operating reactor pressure conditions -

! prior to withdrawing the control rod for continued l . operation. Alternatively, a test during hydrostatic

! pressure testing could also satisfy both criteria.

The Frequency of once prior to exceeding 40% RTP is acceptable because of the capability of testing the control rod at the different conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.

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

2. USAR, Section 4.3.2.

3. USAR, Section 4.6.1.1.2.5.3.

4. USAR, Section 5.2.2.2.2.3.

5. USAR, Section 15.4.1.

6. 'USAR, Section 15.4.2.

7. USAR, Section 15.4.9.

CLINTON B 3.1-27 Revision No. 2-13

RPS Instrumentation

, B 3.3.1.1

~

BASES

-SURVEILLANCC SR 3.3.1.1.4 (continued)

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

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

I SR 3.3.1.1.6 and SR 3.3.1.1.7 3 l

These Surveillances are established to'onsure that no gaps in neutron flux indication exist from suberitical to power

! operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be demonstrated to ensure that rea: tor power will not be incressed into a region without adequate neutron flux indication. This is required prior to withdrawing SRMs from the fully-inserted position since indication is being transitioned from the SkMs to the IRMs.

The overlap between IRMs and APRMs is trT concern when reducing power into the IRM range. On power increases, the system design will prevent furtter increases (initiate a rod block):if adequate overlap is not taintained.

Overlap between IRMs and APRMs exists when sufficient IRMs a.)d- APRMs concurrently have onscale readings such that the transition between MODE I and MODE 2 can be made without l either an APRM downscale rod block or an IRM upscale rod block. Overlap between SRHs and IRMs similarly exists when,_

, prinr to withdrawing the SRMs from the fully inserted position, each IRM reading increases by a factor of the square foot of ten (i.e., 3.17) from its initia? "alue and has a minimum reading of 16 on the 0-125 scale betore any OPERABLE SRM reading reaches its upscale rod block setpoint.

(continued)

CLINTON B 3.3-25 Revision No. 2-11

Remote Shutdown System B 3.3.3.2 BASES-APPLICABLE SAFETY ANALYSES The criteria governing the design and the specific system requirements of the Remote Shutdown System are -located in

-(continued) 10 CFR 50, Appendix A, GDC 19 (Ref.1).

The Remote Shutdown System ts considered an important contributor to reducing the risk of accidents; as such, it has been retsined in the-Technical Specifications (TS) as indicated in the NRC Policy Statement.

i LC0 The Remote Shutdown System LC0 provides the requirements for the OPERABILITY of the instrumentation and controls necessary to place and malatain the plant in MODE 3 from a location other inan the control room. The instrumentation and controls required are listed in the Operational Requirements Manual (Ref. 2).

The controls, instrumentation, and_ transfer switches are those required for:

i Reactor pressure vessel (RPV) pressure control; .

I

• Decay heat removal; RPV inventory control; and Safety support systems for the above functions, e

including service water, component cooling water, and onsite power, including the diesel generators.

The Remote Shutdown System instruments and control circuits covered by this LCO ensure a redundant safety-grade capability to achieve and maintain hot shutdown from a location or locations remote from the control room, assuming no fire damage to any required systems and equipment and assuming no accident has occurred (Ref. 3).

The Remote Shutdown System-instruments ind control circuits covered by this LCO do not need to br. acergized to be considered OPERABLE. This LC0 is inteaded to ensure that the instruments and control circuits will be OPERABLE if plant conditions require that the Remote Shutdown System be placed in operation.

(continued)

('

CLINTON B 3.3-61 Revision No.-2-2<. l

Remote Shutdown System B 3.3.3.2 BASES

.' SURVEILtANCE SR 3.3.3.2.1 (continued)

REQUIREMENTS outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. As specified in the Surveillance, a CHANNEL CHECK is only required for those channels that are normally energized.

l The Frequency is based upon plant operating experience that '

demonstrates channel failure is rare.  ;

SR 3.3.3.2.2 1 l

SR 3.3.3.2.2 verifies each required Remote Shutdown System transfer switch and control circuit performs the intended function. This verification is performed from the remots shutdown panel and locally, as appropriate. Operation of the equipment from the remote shutdown panel is not necessary. The Surveillance can be satisfied by performance of a continuity check. This will ens'are that if the control room becomes inaccessible, the plant can be placed and maintained in MODE 3 from the remote shutdown panel and the local control stations. However, this Surveillance is not required to be performed only during a plant outage.

Operating experience demonstrates that Remote Shutdown System control channels usually pass the Surveillance when performed at the 18 month Frequency.

SR 3.3.3.2.3 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The test verifies the channel responds to measured parameter values with the necessary range and accuracy.

The 18' month Frequency is based upon operating experience and is consistent with the typical industry refueling cycle.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 19.

2. Operational Requirements Manual, Attachment 1.

3. NUREG-0853, " Safety Evaluation Report Related to the Operation of Clinton Power Station, Unit No. 1,"

Supplement No. 6, July 1986, Section 7.4.3.1.

i CLINTON B 3.3-64 Revision No. 2 c

C0C-RPT' Instrumentation B 3.3.4.1

-BASES SURVEILLANCE SR 3.3.4.1.4 -(continued).

. REQUIREMENTS inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel considered OPERABLE.

-The Frequency of 18 months has shown-that channel bypass failures between successive tests are rare. i SR 3.3.4.1.5 This SR ensures that the individual channel Wsponse times ,

are less than or equal to the maximum values usumed in the-accident analysis. The E0C-RPT SYSTEM RESPON$E TIME acceptance criteria are included in applicable plant-procedures and include an assumed RPT breaker interruption time of 80 milliseconds. This assumed RPT breaker-interruption time is. validated by the performance of periodic mechanical timing checks, contact gap measurements and high potential tests on each breaker in accordance with plant procedures at least once per 36 months. The acceptance criterion for the RPT breaker mechanical timing.

l check shall be 141 milliseconds (for. trip coil TC2).

(Although not part of the EOC-RPT- trip circuitry, an I acceptance criterion of < 34 milliseconds for trip coil TCl is imposed to provide additional assurance of_ proper breaker

'- maintenanceandoperation.)

EOC-RPT SYSTEM RESPONSE TIME tests are conducted on an

! -l. 18 month STAGGERED TEST BASIS. (The Note requires STAGGERED l TEST BASIS Freauency to be determined on a per Function

• basis. This is accomplished by testing all channels of one

~ Function every 18 months-on an alternating basis such that both Functions are tested every 36 months. This Frequency

is based on the logic interrelationships of the various-4 channels required to produce an E0C-RPT signal. Response times cannot be determined at power because operation of final actuated devices is. required. Therefore, this i

Frequency-is consistent with the . typical industry refueling

. cycle and is based upon plant operating experience, which l

shows that random failures of instrumentation components that cause serious response time degradation, but not channel failure,- are infrequent occurrences.

. I (continued)

CLINTON B 3.3-78 Revision No. 2-11 '

i

EOC-RPT Instrumentation B 3.3.4.1 BASES (continued).

l REFERENCES 1. USAR, Section 7.6.1.8.

2. USAR, Section 5.2.2.

3. USAR, Sections 15.1.1, 15.1.2, and 15.1.3.

4. USAR, Sections 15.2.2, 15.2.3, and 15.2.5.

-5. USAR, Sections 15.3.2 and 15.3.3.

6. GENE-770-06-1, " Bases for Changes To Surveillance Test Intervals And Allowed Out-0f-Service Times For Selected Instrumentation Technical Specifications,"

February 1991.

CLINTON B 3.3-75 Revision No. 2-11 l

Primary Ccntainment and-Orywell Isolation Instrumentation 4; B 3.3.6.1 B 3.3- INS'TRUMENTATION

B 3.3.6.1. Primary Containment end Drywell Isolation Instrumentation BASES e

! BACKGROUND .The primary containment and drywell isolation 2

instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs) and

, drywell isolation valves. The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following

, postulated Design Casis Accidents (DBAs). Primary containment iso ation within the time limits specified for L those isolation valves designed to close automatically l ensures that the release of radioactive material to the 4

- environment will be consistent with the assumptions used in the-analyses for a DBA. The isolation of drywell isolation ,

valves, in combinatien with other accident mitigation '

- systems, functions to ensure that steam and water releases

to the drywell are channeled to the suppression pool to-

! . maintain the pressure suppression function of. the drywell.

+

The isolation instrumentation includes the sensors, relays.-

timers, trip modules, and switches thatl are necessary to

- cause initiation of primary containment' and reactor coolant pressure boundary (RCPB) isolation.- Most channels include-electronic equipmeni, (e.g..- analog trip modules (ATMs)) that

compares measured input signals with pre-established i setpoints. When the setpoint-is-exceeded..the ATM trips, which then outputs a primary containment isolation signal to -

the isolation logic. Functional diversity is provided by

monitoring a wide range of' independent parameters. The

input parameters to-the isolation logic are_(a) reactor vessel water level, (b) ambient temperatures, (c)-main steam line (MSL) flow measurement, (d) Standby Liquid Control

-(SLC) System initiation, (e) condenser vacuum loss,- (f) main

< steam line pressure, (g) reactor core isolation cooling-l (RCIC) steam.line flow, (h) ventilation exhaust radiation,

(1) RCIC steam line-pressure,'(j) RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) 4 differential flow, (1)- reactor steam dome pressure, (m) drywell pressure, and (n)- containment pressure.

Redundant sensor input signals 'are provided from each such

isolation initiation parameter. The only exception is SLC System initiation. In addition, manual isolation of the j logics is provided.

(continued)

[ .

CLINTON B 3.3-135 Revision No.-2'-8

Primary Containment and Drywell isolation Instrumentation B 3.3 6.1

\

BASES ,

BACKGROUND The primary containment and drywell isolation (continued) instrumentation has inputs to the trip logic from the isolation functions listed below.

1. Main'SteamlineIsoiation Most Main Steam Line Isolation Functions receive inputs from four channels. The four channels input to four separate two-out-of-four logic divisions. The outputs from these logic divisions are combined into two two-out-of-two logic trip systems to isolate all main steam isolation valves (MSIVs) and MSL drain valves. Each MSL drain line has two isolation valves with one two-out-of-two logic system associated with each valve.

The exception to this arrangement is the Main Steam Line Flow-High Function. This Function uses 16 flow channels, four for each steam line. The four flow channels associated with a steam line are combined in a two-out-of-four logic

! configurati .,n. The outputs of the high steam flow logic for l each of the steam lines are combined in the two two-out-of-l two logic trip systems described above.

L Primary Containment and Drywell Isolation Each Primary Containment-Isolation and Drywell Function receives inputs from four channels. The outputs from these channels are arranged into two logic trip systems. One trip system initiates isolation of all-inboard PCIVs and drywell isolation valves, while the other trip system initiates isolation of all outboard ?CIVs and drywsil isolation valves. Each trip system logic closes one of the two valves on each penetration so that operation of either trip system isolates the penetration.-

3. Reactor Core Isolation Coolino System isolation Most Functions receive input from two channels, with each

] channel in one trip system. Each of the two trip systems is connected to one of the two valves'on each RCIC penetration so that operation of either trip system isolates the j penetration. The exception to this arrangement is the.RCIC Turbine Exhaust Diaphragm Pressure-High Function. This i

i Function receives input from four turbine exhaust diaphragm (continued) 4

^

{ CLINTON B 3.3-136 Revision No. 2-8 f . ,

4

T 4 . . . .

! Primary Containment' and Drywell- Isolation Instrumentation i' B 3.3.6.1 i

1 BASE $1 I BACKGROUND- -- 3i Reactor Core Isolation Coolina System Isolation -

-(continued) e pressure channels. The outputs from the turbine exhaust diaphragm pressure channels are connected into two two-out-of-two trip. systems, each trip system isolating two

! - RCIC valves. There is one manual isolation switch which can isolate only the outboard RCIC System contai.iment isolation

. valves.

Reactor Water Cleanun System Isolation

[

"4 . 3

[

Most' Functions receive input from two channels w'ith each -

r -

channel in one trip system using one-out-of-one logic.-

l Functions'4.c and 4.d (RWCU Heat Exchanger Room-Temperature and RWCU Pump Room Temperature) have one channel-in each- -

i- trip system in each room for a total of four channels- for

^metion 4.c and six channels for Function 4.d, but- the-

logic i

the same (one-out-of-one). Each of the two trip

systems.is connected to one of the two valves on each RWCU -

U penetration so that operation of either trip system isolates s the penetration. The exception to this arrangement is the Reactor Vessel Water Level-Low Low, _ Level 2 Function. This i

Function receive:;. input from four re: actor vessel water level channels. The outputs from the reactor. vessel water level channels are connected into two two-out-of-two trip systems, each trip system isolating one of the two' RWCU valves.

p 1:

- 5. -RHR System Isolation The RHR System Isolation Function receives input signals from instrumentation for the Reactor Vessel Water Level-Low Low Low, level 1; Reactor Vessel Water Level - Low, Level 3; P-Drywell Pressure - High; Reactor Vessel Pressure .- High; RHR Equipment Room Ambient Temperature - High; and Manual-Initiation Functions. The: Reactor Vessel Water Level-Low Low Low, level:1; Reactor Vessel Water Level-tow, level 3; Reactor Steam Dome Pressure-High; 'and Drywell Pressure-High Functions each have four channels. The outpcts from the reactor vessel water level (level 1) and drywell pressure i

i channels are connected in two one-out-of-two twice trip

_ systems. The reactor vessel water'1evel-(level 3) is i

combined with the drywell pressure channels in two one-out-i

of-two twice trip systems and with the reactor vessel ~

pressure channels in two one-out-of-two twice trip systems.

• (continued)

~

~

CLINTON B 3.3-137 Revision No. 2-8 w ~ L e- ,n. . ne-e-. ,.n .-v., - - - . , ,mr ,

Primary Containment and Drywell isolation Instrumentation B 3.3.6.1

. BASES-APPLICABLE- 2 k. Containment Pressure-Hiah (continued)

SAFETY ANALYSES, LCO, and -The Albwable Value was chosen to prevent opening of the APPLICABILITY containment _ ventilation supply and exhaust isolation bypass valvos when excessive differential pressure could result in damage to the associated ductwork.

Two channels of the Containment Pressure-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can precluot. the isolation

function.

. 2.1, Manual Initiation The Manual Initiation push button channels introduce signals into the primary containment and drywell isolation logic that are redundant to the automatic protective

• instrumentation and provide manual isolation capability.

There is no specific USAR safety analysis that ti.kes credit for this Function. It is retained for the isolation function as required bf the NRC in the plant licensing

, basis.

• E k There are two push buttons for the logic, one manual initiation push button per trip system (i.e., 1821H-S25A and

' 1821H-S25B). There is no Allowable Value for this Function since the channels are mechanically actuated based solely on th9 position of the push buttons.

Two channels of the Manual Initiation Function are available and are required to be OPERABLE. This Function is also

/ required to be OPERABLE during ~ CORE ALTERATIONS, movement of irradiated fuel assemblies-in primary or secondary containment, or OPDRVs. This Function initiates isolation of valves which isolate primary containment penetrations which bypass secondary containment. Thus, this Function is also required under those conditions in which secondary containment is required to be OPERABLE.

3. Reactor Core Isolation Coolina System Isolation l 3.a. Auxiliary Buildino RCIC Steam Line Flow-Hiah l Auxiliary Bu'ilding~ RCIC Steam Line Flow-High Function is provided to detect a break of the LCIC steam lines and-initiates closure of the steam line isolation valves. If the steam is ~ allowed to continue flowing out of the break,

. i (continued)

CLINTON B 3.3-148 Revision No.'2'-4'

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES l APPLICABLE

~3.a. Auxiliary Buildina ,RCIC Steam line Flow-Hiuh SAFETY ANALYSES, continued)

LCO, and-APPLICABILITY the reactor will depressurize Tnd core uncovery can occur.

Therefore, the-isolation is- L ,tiated on high flow to revent or minimize core damage. The isolation action, along with the scram function of the Reactor Protection System (RPS),

ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. - Specific credit for.this Function is not assumed in any USAR. accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments

. prevent the RCIC steam line break from becoming bounding.

l The Auxiliary Building RCIC Steam Line Flow-High signals are initiated from two transmitters that are~ connected to the system steam lines in the Auxiliary Building. Two-channels of Auxiliary Building RCIC Steam Line Flow-High .

Functions are available and are required to be OPERABLE to L ensure that no single instrument' failure can preclude the L

isolation function.- -

The Allowable Value. is chosen to be' low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event-as the bounding event. l 3.b. RCIC Steam line Flow-Hiah Time Delay The RCIC Steam-Line Flow-High Time Delay is provided to

. prevent-false isolations on RCIC Steam Line Flow-High during system startup transients and therefore improves system reliability. This Function is not assumed in any USAR transient or accident analyses. ,

The Allowable Value was chosen to be long enough to prevent-false isolations due to system starts but not so-long as to impact offsite dose calculations.

Two channels for RCIC Steam Line Flow-High Time Delay Functions are available and are required to be OPERABLE to ensure that no single instrument failure can~ preclude the isolation function.

3.c. RCIC Steam Supply line Pressure-Low Low RCIC steam supply line pressure indicates that'the pressure of'the steam may be-too low to continue operation of the RCIC turbine. This isolation is for equipment (continued)

CLINTON B 3.3 149 Revision No. 2-4

Primary Containment and Drywell Isolation--Instrumentation B 3.3.6.1

.l BASES -

APPLICABLE 3.c. RCIC Steam SuDDiv Line Pressure--Low (continued)

SAFETY ANALYSES -

LCO, and - protection and is not assumed in any transient or accident--

-APPLICABILITY analysis-in the USAR. !lowever, it also provides a diverse signal to indicate a possible system break. These instruments are included in the Technical-Specifications (TS) because of the pottntial for risk due to possible failure of the instruments preventing RCIC initiations.

' The RCIC Steam Supply Line Pressure-Low signals are -

initiated from two-transmitters that are connected to the i

, system steam line. Isolation of the RCIC vacuum breaker isolation valves requires RCIC Steam Supply Line Pressure-Low coincident with Drywell Pressure-High signals. Two channels of RCIC Steam Supply Line ,

Pressure-Low Functions are available and are required to.be OPERABLE to ensure that no single instrument. failure can preclude the isolation function.

The Allowable Value is selected to be high enough to prevent' damage to-the system turbine.

3.d. RCIC Turbine Exhaust Diaohraam Pressure-Hioh High turbine exhaust diaphrage' pressure indicates that the y pressure may be too high to contf aue operation of the-associated system turbine. That 14, one of two exhaust diaphrages has ruptured and pressure is reaching turbine casing-pressure limits. This 1:olation is for equipment -

protection and is not assumed in any transient or accident

^ analysis in the USAR. These instruments-are included in the TS because of the potential- for risk due' to possible failure; of the instruments preventing RCIC initiations (Ref. 3).

'The RCIC Turbine Exhaust Diaphragm Pressure-High signals are initiated from four-transmitters that are connected to the area between the rupture diaphrages on each system's turbine exhaust line. - Four channels of RCIC Turbine Exhaust-Diaphragm Pressure--High Functions are available and are required to be OPERA 9LE.to ensure that no_ single instrument failure can preclude the isolation function.

The Allowable Values are low enough to prevent damage.to the system turbine.

-(continued)

^

CLINTON" ~

.B 3.30150- Revision _No. 2-4

Primary Containment "and Drywell isolation- Instrumentation B 3.3.6.1 BASES--

l APPLICABLE 1.e. Ambient Temperature-Hiah

. SAFETY ANALYSES,

-LCO, and Ambient Temperatures are provided to detect a leal; from APPLICABILITY the. associated system steam piping. The isolation occurs when a very small leak has occurred and is diverse-to the high flow instrumentation. If the small. leak is allowed to cantinue without isolation, offsite dose limits may be reached. These function.s are not assumed in any USAR i

transient or-accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL- 1 breaks.

l t

Ambient Temperature-High signals are initiated from thermocouples that are appropriately located to protect the -

y system that is being monitored. Two instruments monitor l: =l each-area. Two channels for RCIC Ambient Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the, l isolation function.

The Allowable Values are set low enough to detect a leak ,

equivalent to 25 gpm.

3.f. Main Steam line Tunnel Ambient Temocrature-Hioh Ambient Temperature-High is provided to detect a leak in the RCPB and-provides diversity to the high flow instrumentation. The isolation occurs when a very small leak.has occurred. If the small leak is allowed to continue without isolation, offsite limits may be reached. However, credit-for these instruments is not taken in any transient or accident analysis in the USAR, since' bounding analyses are performed for large breaks such as MSLBs.

Ambient temperatuu signals are initiated from thermocouples-located in the area being monitored. Two channels of Main Steam Tunnel Temperature-High-Function are available and are requiret to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

Each Function has one temperature element.

The Allowable Values are chosen to detect a leak equivalent to 25 gp,m.

, (continued)

'y . ^

EINTON B 3.3-151

3. Revision No. 2-4

Primary Containnient and Drywell isolation instrumentation B 3.3.6.1 j BASES f

r APPLICABLE 3.0. Main Steam line Tunnel Temperature 11mg.t

. SAFETY ANALYSES, i LCO, and The Main Steam Lino Tunrel lemperature Timor is provided te

' APPLICABILITY allow all the other systems that may be leaking in the main (continued) steam tunnel (as indicated by the high temperature) to bo

! isolated before RCIC is automatically isolated. This '

ensures maximum RCIC System o)eration by preventing

, isolations due to leaks in otier systems. This function is

, not assumed in any USAR transient or accident analysis; however, maximizing RCIC availability is an important function.

Two channels for RCIC Main Steam Line Tunnel Timer Function j are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation j

function.

i The Allowable Values are based on maximizing the  ;

I availability of the RCIC Systemi that is, providing i sufficient time to isolate all other potential leakage sources in the main steam tunnel before RCIC is isolated.

, I. 3.1. Drywell RCIC Steam Une Flow-Hioh

}

l Drywell RCIC high steam line flow is provided to detect a break of_ the common steam line of RCIC and RHR and initiates closure of the isolation valves for both systcms. If the -

f steam were allowed to continue flowing out of the break, the reactor would depressurize and the' core could uncover.

b Therefore, the isolation is initiated at high flow to prevent or minimize core damage. Specific credit for this 5

/ Function is not assumed in any USAR accident or transient

/ analysis since the bounding analysis is performed for large

, breaks such as recirculation and MSL breaks. However, these l instruments prevent the Drywell RCIC steam line break from becoming bounding.

The Drywell RCIC steam line flow signals are initiated from two transmitters that are connected to the steam line in the drywell. Two channels are availabic and required to be OPERABLE to ensure that no-single instrument failure can i

preclude the ism ion function. Tha Allowable Value is 8

selected to n that the trip occurs to prevent fuel damage ara mat' ins'the MSLB'as the boundary event.

(continued' j CLINTON B 3.3-152 Revision ~No. 2-4

,,,,vve-,,.- ,.-,-me x ~ - v= ~

'~~ " " '

Primary Containment and Drywell isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.e. Reactor Vessel Pressure - Hioh SAFETY ANALYSES, LCO, and The Shutdown Cooling System Reactor Vessel Pressure-High APPLICABILITY function is provided to isolate the shutdown cooling portion (continued) of the RHR System. This interlock (RHR cut in permissive) is provided only for equipment protection to prevent an intersystem LOCA scenario and credit for the interlock is not assumed in the accident or transient analysis in the USAR.

The Reactor Vessel Pressure-High signals are initiated from four transmitters. Four channels of Reactor Vessel Pressure - High Function are available and are required to be .

OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization. Additionally, determination of the Allowable Value includes conscrvatisms to ensure closure of the RHR Shutdown Cooling System suction isolation valves '

(IE12-F008 and IE12-F00E) consistent with the requirements l

of HRC Generic Letter 89-10.

5.f. Drywell Pressure - Hiah High drywell pressure can indicate a break in the RCPB. The isolation of some of the PCIVs on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded. The Drywell Pressure-High function associated with isolation of the RHR System is not modeled in any USAR accident or transient analysis because

, other leakage paths (e.g., MSIVs) are more limiting.

High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four channels of Drywell Pressuu-High Function are available and are required to be OPERABLE for isolation of the RHR test return lines to ensure that no single instrument failure can preclude the isolation function. In addition, four channels of Drywell Pressure-High Function are available and are required to be OPERABLE for isolation of the fuel Pool Cooling Assist mocle to ensure that no single instrument failure can preclude '.he isolation function.

The Allowable Value was selected to be the same as the ECCG Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.

(continued)

CLINTON B 3.3-161 Revision No. 2-4

-i 4

h LOP instrumentation  !

B 3.3.8.1 l l

8 3.3 INSTRUMENTATION  !

a B 3.3.8.1 LossofPower(LOP) Instrumentation -

BASES BACKGROUND Successful operation of the required safety functions of-the  !

Emergsney Core Cooling Systems-(ECCS) is dependent upon the  !

availability of adequate power sources for energizing the j various components such as pump motors, motor operated valves, and the associated control components. The LOP i instrumentation monitors the 4.16 kV emergency buses, i Offsite power is the preferred source of power for the  !

4.16 kV emergency-buses. If the monitors determine that  ;

insufficient power _is available, the buses are disconnected  :

from the offsite power sources and connected to the onsite diesel generator (DG) powtr sources.  ;

Each 4.16 kV emergency bus has its own independent LOP instrumentation and associated trip logic. The voltage for i the Division 1,_2, and 3 buses is monitored at two levels, which can be considered as tuo different undervoltage functions: loss of voltage and degraded voltage. .

The LOP instrumentation causes various bus transfers and disconnects. Each Division 1 and 2 emergency bus Loss of - '

Voltage Function is monitored by two undervoltage relays on  !

, the emergency bus and two undervoltage relays on each of the  ;

two offsite power sources. The outputs of these relays are arranged in a two-nut-of-two taken three times logic configuration. Each of these relays is an inverse time l delay relay. The Division 3 emergency bus Loss of Voltage Function is monitored by four undervoltage relays whose

,' ' outputs arc arranged iri a one-out-of-two taken twice logic '

configuration. The outout of this logic inputs to a time ,

delay relay. Prior to helease for Operations (RFO) of the i

! associated plant modification [i.e., modification AF-027 for Division 1 or AP-028 for Diviston 2), each Division 1 and >

Division 2 emergency bus Degraded Voltage Function is monitored by two undervoltage relays for each emergency bus

-whose outputs are arranged in-a two out-of-two logic.

configuration. The output of this logic inputs to a time delay relay for each emergency bus (Ref.1). Prior to RF^

-of-modification AP-02g,~the Division 3-emergency bus  ;

Degraded Voltage Function is mGnitored by one undervoltage t

. relay with-three output contacts. arranged in a three-out-of- 4 (continued) h Revision'No.:till C'LINTON. 8 3.3-222 m m. ..

. . p ,

, t' . s t b

m w ar me,re--rw w+ m # cv n~~e- wsrv w-e v- ,-=~-,--=v-r<~~~

LOP instrumentation B 3.3.8.1 BASES BACKGROUND three logic configuration. The output of this logic inputs (continued) to a time delay relay. Following RF0 of the associated plant modification, each Division 1, Olvision 2, and Division 3 emergency bus Degraded Voltage Function is monitored by two undervoltage relays for each emergency bus whose outputs are arranged in a two out-of-two logic configuration. The output of this logic inputs to a time delay relay for each emergency bus.

APPLICABLE The LOP instrumentation is required for the Engineered SAFETY ANALYSES, Safety Features to function in any accident with a loss of LCO, and offsite )ower. The required channels of LOP instrumentation APPLICABILITY ensure t1at the ECCS and other assumed systems powered from

the DGs provide plant protection in the event of any of the l analyzed accidents in References 2, 3, and 4 in which a loss

! of offstte power is assumed. The initiation of the DGs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Accident analyses credit the loading of the DG based on the loss of offsite power during a loss of coolant accident (LOCA). The diesel starting and loading times have been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power.

De LOP instrumentat!on satisfies Criterion 3 of the NRC Policy Statement.

The OPERABILITY of the LOP instrumentation is dependent upon the OPERABILIfY of the individual instrumentation channel Functions specified in Table 3.3.8.1-1. Each Function must hwe a required number of OPERABLE channels per 4.16 kV emergency bus, with their setpoints within the specified Allowable hiues. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value.

The actual setpoint is calibrated consistent with applicable setpoint methodology aasumptions.

The Allowable Values are specified for each function in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpcints are selected to ensure that the setpoint does not exceed the Allowable Value (continuedl CLINTON B 3.3 223 Revision No. 2-11 s

g w

j LOP instrumentation B 3.3.8.1 ,

, BASES s

APPLle.ABLE between CHANNEL CAllBRA110NS. Operation with a trip SAFE 1/ ANALYSES, setpoint less conservative than the nominal tri i LCO, and but within the Allowable Value, is acceptable. pTrip setpoint,  !

4 APPLICABILITY setpoints are those predetermined values of output at which '

(continued) an action should take place. The setpoints are compared to i theactualprocessparameter(e.g.,busvoltage),andwhen

the measured output value of the process parameter exceeds ,

L the setpoint, the associated device (e.g., undervoltage

• relay) changes state. The analytic limits are derived from -

I the limiting values of the process parameters -obtained from

• 2 the safety analysis. The Allowable Values are derived from i

the analytic limits, corrected for calibration, process,.and i some of-the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors

! (e.g., drift . The trip set ,

! provide adequ) ate protection because points derived in this manner instrumentation uncertainties, process effects, calibration-tolerances,

instrumentdrift

andsevereenvironmenterrors(for channels that must function in harsh environments as defined j by 10 CFR 50.4g) are accounted for.

i The specific Applicable Safety Analyses LCO, and 2~

Applicability discussions are' listed below on a function by .

function basis.

! 4.16 kV Emeroency Bus Undervoltane i 1.a. 1.b. 2.a. 2.b. 4.16 kV Emeraency Bus Undervoltaae ,

4 (Loss of Voltaae) l j Loss of voltage on a 4.16 kV emergency bus indicates that

offsite power may be com>1stely lost to the respective c emergency bus and is unaale to supply sufficient power for i proper operation of the applicable aquipment. Therefore.

l the power supply to the bus is transferred from offsite

[ power to DG powar when the voltages on the bus and the two

. offsite power supplies drop below the Loss of Voltage-Function Allowable-Values (loss of. voltage with a short time

, delay). This ensures that adequate power will be available

j. =to the required equipment.

l ' The Bus Undervoltage Allowable Values are low enough to ,

prevent

inadvertent power supply transfer, but high enough to ensure power is available to the required equipment. The

Time Delay Allowable Values are long enough to provide time p for the offsite power supply to recover' to normal voltages, j but'short enough to ensure that power'is available to the

(continued)

CLINTON B 3.3-224 Ravision No. 2 ,

l_,. . , . .

g . .

_ _ _.__,a_ _ _ _ _. . _ . _ . _ _ _ _ _ . ~ . _ - . _ . _ _ .

y we5 w .,

k l

$ LOP instrumentation B 3.3.8.1 BASES APPLICABLE 1.a. 1.b. 2.a. 2.b4 4.16 kV Emeraency Bus Undervoltaag SAFETY ANALYSES, (loss of Voltaael (continued)

LCO, and I APPLICABilllY required equipment. The time delay specified for the Divisions 1 and 2 4.16 kV Emergency Bus Loss of Voltage

! Functions corresponds to a voltage at the 120-volt Basis trip setpoint of a 67 volts and s 97 volts. Lower voltage conditions will result in decreased trip times. The Division 3 4.16 kV Emergency Bus Loss of Voltage function 120-volt Basis trip setpoint is a 67 volts and s 78 volts.

Six channels of 4.16 kV Emergency Bus Undervoltage (Loss of h Voltage) Function )er associated emergency bus for Divisions 1 and 2 and four clannels for Division 3 are only required to be OPERABLE when the associated DG is required to be OPERABLE to ensure that no single instrument failuro can preclude the DG function. (Six channels input to each of the Division 1 and Division 2 DGs and four channels input to the Division 3 DG. Each of the six channels for Division 1 and six channels for Division 2 is an inverse time delay relay. Each of these time delays are considered to be separate channels. For Division 3, the Loss of Voltage Function logic inputs to a single time delay relay. Thus, only one time delay channel is associated with Division 3.) -

Refer to LC0 3.8.1, "AC Sources-Operating," and LCO 3.8.2, "AC Sources-Shutdown," for Applicability Bases for the DGs.

l 1.c. 1.d. 1.e. 2.c. 2.d. 2.e. 4.16 kV Emeraency Bus Undervoltaae (Dearaded Voltaael A reduced voltage condition on a 4.16 kV emergency bus indicates that while offsite power may not be completsly lost to the respective emergency bus, power may be insufficient for starting large motors without risking damage to the motors that could disable the ECCS function.

Therefore, power supply to the bus is transferred from offr.ite power to onsite DG power when the voltage on the bus drops below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay). This ensures that adequate power will be availat,le to the required equipment.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required l equipment. As stated above, the purpose of this (continued)

CLINTON B 3.3-225 Revision No. 2-11

-i-----. .,in.i. i

.iOP Instrumentation '

B 3.3.8.1 BASES 1.c. 1.d. l.e. 2.c. 2.d. 2.e. 4.16 kV Emeraency Bus APPLICABLE SAFETY ANALYSES. W.ndervoltaae (Dearaded Voltaae) (continued)

LCO, and APPLICABillTY instrumentation is to ensure that sufficient power will be available to sup) ort the ECCS function durtag a LOCA.

During a LOCA, tie ECCS and other safety systems will be initiated at the start of the event. This large loading of the safety buses results in a voltage transient of i sufficient magnitude to start the degraded voltage timers.

If the degraded voltage relays do not reset, which requires the voltage to be restored to a lovel above the relay reset setpoint, the bus undervoltage time delay relays will trip,

. resulting in bus transfer to the DGs. Thus, the relay reset (pick up) set)oint must be high enough to ensure adequate voltage for t1e safety-related loads.

Prior to RF0 of the corresponding plant modification (i.e.,

modification AP 027 for Division 1, AP-028 for Division 2, or AP-029 for Division 3), the Degraded Voltage function Allowable Value specified is the allowable value for the relay dropout. Following RF0 of the corresponding plant

( modification, the Degraded Voltage Function Allowable Values specified are for the relay dropout and the relay reset.

Because the dropout and reset settings are not independently adjustable for the relays utilized for the Degraded Voltage instrumentation prior to RF0 of the associated modification, only the dropout setting is applicable as explained in Table 3.3.3-1 by footnote (a).

The Allowable Values to be used after RF0 of the corresponding plant modification are as determined within IP -

Calculation 19-AN-19 (Ref. 5). The basis for the reset

, Allowable Value upper limit is the avoidance of shifting to the onsite source when the offsite source is acceptable as specified within GDC 17. The basis for the reset Allowable Value lower limit is the minimum voltage required to support the LOCA loads. The basis for the dropout Allowable Value upper limit is the practical limit of the reset Allowable Value lower limit. The basis for the dropout Allowable Value lower limit ensures adequate voltage to start plant equipment under non-LOCA loeding conditions. Because of the voltage transient experienced at the start of a LOCA, the specified Degraded Voltage drop out Allowable Value lower limit provides significant margin to the setting required to mitigate a LOCA. This value was selected based on other licensing basis events discussed in USAR, Section 8.3.1.1.2 o (Ref.1) and calculated in IP Calculation 19-AN-19.

__ _ (continued)

't CLINTON B 3.3-225a Revision No. 2-11 s

- - ,a , -- - - , . - , -

l This page intentionally left blank.

1 CLINTON B 3.3-225b Revision No. 2-11

1 LOP Instrumentation B 3.3.8.1 BASES l APPLICABLE 1.c. 1.d. 1.e. 2.c. 2.d. 2.e. 4.16 kV Emeroency Bus- l SAFETY ANALYSES, Undervoltaae (Dearaded Voltaae) (continued) l LCO, and APPLICABILITY The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.

Two channels of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function per associated emergency bus for Divisions 1, 2, and 3 (except 3 channels for Division 3 prior to RF0 of modification AP-029) are only required to be OPERABLE when the associated DG is required to be OPERABLE to ensure that no single instrument failure can preclude the DG i

function. (Two channels input to each of the Division 1, 2, and 3 DGs (except that 3 channels input to the Division 3 DG prior to RF0 of modification AP-029). The Degraded Voltage

-Function logic for each Division inputs to a single time delay relay. Thus, only one time delay channel is 1

associated with each Division.) Refer to LC0 3.8.1 and j , LCO 3.8.2 for Applicability Bases for the DGs. 4 Footnotes (a), (b -

the TS changes are),not effective until RF0 of theand (c) to Table 3.3 i corresponding plant modificat. ion. The planned modifications are: AP-027 for Division 1, AP-028 for Division 2, and AP-

, , 1 029 for Division 3.

ACTIONS A Note has been provided to modify the ACTIONS related to LOP instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, f subsequent divisions, subsystems, components, or variables i

expressed in'the Condition discovered to be inoperable or not within limits will not result in separate entry into the

-! Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Cor.:pletion Times based on initial entry into the Condition. However, the Required Actions for inoperable LOP instrumentation channels provide appropriate com)ensatory measures for separate inoperable channels. As suci, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel, e -

-(continued)

CLINTON B 3.3-226 Revision No. 2-11

, v

LOP Instrumentation B 3.3.8.1 BASES l ACTIONS A.1 and A.2

-(continued)

With one oFmore channels of a function ino)erable, the Function may not be capable of performing tie intended function. Therefore, only I hour is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.I. For loss of Voltage Functions, placing the inoperable channel in trip would conservatively compensate for the inoperability and allow operation to continue. However, for Degraded Voltage Functions, placing the inoperable channel in trip may not conservatively compensate for the inoperability. Because of the assumptions used in the setpoint calculations, the setpoint(s) for the remaining OPERABLE channel (s) may not ensure reset of the relay within the required voltage range.

As a result, operation with an inoperable Degraded Voltage

channel (s)-in trip is limited to 7 days.

Thus, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation) or if the inoperable '

l channel (s) is not restored to OPERABLE status within the allowable out of service time, Condition B must be entered and its Required Action taken.

~

The Complet1on Time is intended to allow the operator time to evaluate and repair any discovered ino)erabilities. The Completion Times are acceptable because t1ey minimize risk while allowing time for restoration or tripping of channels.

Required Action A.2 is modified by a Note which states that the Required Action is only applicable for Functions 1.c, l.d. l.e, 2.c. 2.d. and 2.e following RF0 of the corresponding plant modification (i.e., modification AP-027, AP-028, or AP-029). The 7-day limitation is imposed as a result of assumptions associated with the setpoint calculations for the modified Degraded Voltage Function instrumentation.

l l _ (continued) l CLINTON B 3.3-227 Revision No. 2-11

LOP Instrumentation B 3.3.8.1 BASES ACTIONS S.J (continued)

If any Required Action and associated Completion Time is not met, the associated Function may not be capable of performing the intended function.- Therefore, the associated DG(s) are declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of R LCO 3.8.1 and LCO 3.8.2, which provide appropriate actions for the inoperable DG(s).

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS Instrumentation Function are located in the SRs column of Table 3.3.8.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains DG initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition '

entered and Required Actions taken.

-SR 3.3.0.1.1 l- This SR has been deleted.

SR 3.3.8.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the ent. ire channel will perform the inter.ded function. For Series Functions, a separate CHANNEL FUNCTIONAL TEST is not required for each Function, provided each Function is tested.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 31 days is based on plant operating experience with regard to channel OPERABILITY that demonstrates that failure in any 31 day interval is rare.

. (continued)

CLINTON 8 3.3-228 Revision No. 2-11

i h LOP instrumentation 2 B 3.3.8.1 i BASES j,

SURVEILLANCE SR 3.3.8.1.3' l REQUIREMENTS .

(continued) A CHANNEL CAllBRATION is a complete check of the instrument  !

l loop and the sensor. This test verifies the channel  !

I responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel i ' adjusted to account for instrument drifts between successive  :

l calibrations. consistent with the plant specific setpoint  :

! methodology.

~ The Frequency is based on the assug tton of the magnitude of  :

equipment drift in the setpoint analysis.  !

i f SR 3.3.8.12 1 $

1 i- The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the .

OPERABILITY of the required actuation logic for a. specific .

channel. The syst3m functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to

• ' provide complete testing of the- ass'uned safety functions.  !

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant -

t' .

outage and the potential for an unplanned transient if the

Surveillance were performed with-the reactor at power. >

[ Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency.

W I

[ REFERENCES' 1. 'USAR, Section 8.3.1.1.2.

i. 2. - USAR, Section 5.2.2. i

3. USAR, Section 6.3.3.

4. USAR, Chapter 15.

_v

l. 5. IP Calculation 19-AN-19. .

u CLINTON B'3.3-229 -Revision No. 2-11 p.

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i FCVs B 3.4.2 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.2 Flow Control Valves (FCVs)

BASES BACKGROUND The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1,

" Recirculation loops Operating," which discusses the o>erating characteristics of the system and how this affects tie design basis transient and accident analyses. Thejet '

pumps and the FCVs are part of the Reactor Coolant 1

Recirculation System. The jet pumps are described in the Bases for LCO 3.4.3, " Jet Pumps

' The Recirculation Flow Control System consists of the electronic and hydraulic components necessary for the positioning of the two hydraulicaliy actuated FCVs. The recirculation loop flow rate can be rapidly changed within the expected flow range, in response to rapid changes in system demand. Limits on the system response are required to minimize the impact on core flow response during certain

• accidents and transients. Solid state control logic will generate an FCV " motion inhibit" signal in response to any one of several hydraulic power unit or analog control circuit failure signals. The "metion inhibit" signal causes '

hydraulic power unit shutdown and hydraulic isolation such that the FCVs fail "as is."

APPLICABLE The FCV stroke rate is hydraulically limited to s 30% per SAFETY ANALYSES - second in the opening direction and s 60% per secor.d'in the closing direction on a control signal failure of maximum demand. These stroke rates are assumptions of the analysis of the recirculation flow control failures on decreasing and increasing flow (Refs. I and 2).

In addition, the LOCA' analysis of Reference 3 assumes that the iritial core flow response is governed by the pump coastdown in the unbroken loop. Im)1icit in this assumption is that the FCV position does not c1ange, i.e., fails "as is."

Flow control valves satisfy Criterion 2 of the NRC Policy Statement.

(continued)

CLINTON B 3.4-9 Revision No. 2-3 Y d

FCVs 8 3.4.2 BASES (contir.utd)

LCO An FCV in each operating recirculation loop must be OPERABLE to ensure that the assumptions of the design basis transient and accident analyses are satisfied.

ApPLICABIL11Y In HODES 1 and 2, the FCVs are required to be OPERABLE,

! since during these conditions there is considerable energy in the reactor core, and the limiting design basis transients and accidents are assumed to occur. In MODES 3, 4, and 5, the concequences of a transient or accident are reduced important,and OPERABILITY of the flow control valves is not s

ACTIONS A Note has been provided to modify the ACTIONE related to FCVs. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, .

subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Section 1.3 also specifies Recuired Actions of the Condition continue to apply for each adcitional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for inoperable F::Vs provide appropriate compensatory measures for separate inoperable FCVs. As such, a Note has been provided that allows '

separate Condition entry for each inoperable FCV.

8.d With one or two required FCVs inopereble, the as;,umptions of the design basis transient and accident analyses may not be >

l met and each inoperable FCV must be returned to OPERABLE status or hydraulically locked within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

Closing an FCV during a design basis LOCA could affect the recirculation flow coastdown for the unbroken loop, resulting in higher peak clad temperatures. Therefore, if l an FCV is inoperable, deactivating the valve (motion inhibit) will essentially lock the valve in position, which will prohibit the FCV from adversely affecting the DBA analyses. Continued operation is allowed in this Condition.

The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is a reasonable time period to complete the Required Action, while limiting the time of

-aperation with an inoperable FCV.

(continued) i-CLINTON B 3.4-10 Revision No. 2-3

-I 7 M

4

' FCVs D 3.4.2 BASES

i ACTIONS Qd (continued) if the FCVs are not deactivated, (locked up and cannot be restored to OPERABLE status within the assoc)iated Completi Time, the unit must be brought to a NODE in which the LCO does not apply. To schieve this status, the unit must be d

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 />. This brings the unit to a condition where the flow coastdown characteristics i of the recirculation loop are not important. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience,'to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.4.2.1 REQUIREMENTS . i Hydraulic power unit pilot operated isolation valves located between the servo valves and the common "open" and "close" lines are required to close in the event of a loss of hydraulic pressure. Wuen closed, these valves inhibit FCV ,

t motion by blocking hydraulic pressure from the servo valve ,

to the common open and close lines as well as to the .

alternate subloop. This Surveillance verifies FCV lockup on 4

i a loss of hydraulic pressure as assumed in the design basis LOCA analyses.

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant 3 outage and the potential for an ur 31anned transient if the Surveillance were performed with .'.1e reactor at power.

0)erating experience has shown tht.se components usually pass tie SR when performed at the 18 m9 nth Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

~~"~

t' (continued)

CLINTON B 3.4 11 Revision No. 2-3 g .

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B 3.4.2 1 BASES (continued)

REFERENCES 1. USAR, Section 15.3.2. i l

2. USAR, Section 15.4.5. l

3. USAR, Section 6.3.3.

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4. USAR, Section 5.4.1.  ?

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'RCS Leckage Detection Instrumentation 0 3.4.7 BASES /

BACKGROUND integrated by a totalizer to give total sump influent (continued) volume. The flow rate signal is continuously recorded in the control room and is transmitted to an analog computer point. The recorder generates a main control room annunciator upon high flow rate (3.6 gpm).

The drywell floor drain sump also has level switches that start and stop the sump pumps when required. A timer starts each time the sump is )um>ed down to the low level setpoint.

If the sump fills to tie tigh level setpoint before the timer ends, an alarm sounds in the control room, indicating a LEAKAGE rate into the sump in excess of a preset limit. A second timer starts when the sump ) umps start on high level.

Should this timer run out before tie sump level reaches the

low level setpoint, an alarm is sounded in the control room indicating a LEAKAGE rate into the sump.in excess of a proset limit.

The drywell floor drain sump also has two^ additional flow monitoring systems equivalent to the weir box- system: 1) a magnetic flow meter installed on the discharge piping of the drywell floot drain pumps and a flow totalizer converter . -

installed in the vicinity of the flow element; and 2 a bubbler type level sensing system installed in the rd)ywell floor . drain sump pit. -

-(*

The flow totalizer converter provides local indication of total rump discharge flow and discharge flow rate.. It also provides a signal representing actual pump discharge flow rate to a programmable logic controller (PLC), in the main control room. The PLC calculates the average (total and actual pump discharge flow by integrating the signal)from the flow tota 61rer converter and dtyiding the result by the total timo beteen pump cycles. -When the sump in the drpell reaches e high level, one of the twn pumps start (the pumps alternate each cycle) pumping water to the drain sump collector tank. This' operation continues until the sump level reaches a low level setting. When the pum) stops, the PLC senses a "no flow' signal and resets t1e timer, performs the average flow rate calculation, and transmits the resulting signal to a recorder, an analog

. The PLC also computer pointcontrol gencrates main and aroom totalizer (counter)dicate alarms to in high flow (3.6 gpm), and large flow increase (2 gpm/24 hours). This operation is repeated every time a sump pump complutes its (continuedi CLINTON .B 3.4-34 . Revision No. 2 -

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'RCS teakage Octection instrumentation B 3.4.7

( BASES

- BACKGROUND cycle. The sump pumps can also be operated with the control (continued) switch in %anual" which automatically controls starting and stopping of both pumps within a smaller range.

The bubbler type levol sensor provides a pneumatic level signal to a differential pressure transmitter installed in the containment building. The level transmitter provides a level signal to the PLC in the main control room. The PLC calculates the total inleakage flow rate by measuring the level and calculating a rate of change once every minute.

From this signal, the PLC generates three analog output signals representing total inleakage flow rate and sump pit level. These signals are transmitted to a recorder, analog computer point, and to a digital cJunter. The PLC also generates main control room annunciators to indicate high flow rate (3.6_ gpm), and large. flow increase (2 gpin/24 hours), and produces a computer alarm for system inoperable (PLC diagnostic fault, or level signal out of range).

Because proper functioning of the drywell floor drain ' sump-monitoring instrumentation is dependent upon the ability to collect the LEAKAGE in the drywell floor drain sump, the 4 -

drywell floor drain sump inlet piping is periodically verified to be unblocked, as described-in Ref. 7.

h .

The drywell a'tmospheric monitoring systems continuously - .

monitor the drywill atmosphere for airborne particulate and gaseous radioactivity. A sudden increase of radioactivity,

' which may be attributed to RCPB steam or reactor water LEAKAGE, is annunciated in the control room. The drywell atmospheric particulate and gaseous radioactivity monitoring i systems are not capable of quantifying leakage rates, but ,

I are. sensitive enough to indicate increased LTAKAGE rates of 4

1 gpm within I hour. Larger changes in LEAKAGE rates are

detected in proportionally shorter times-(Ref. 3).  !

Condenskte from two of the four drywell cooling system' coil cabinets is routed to the drywell floor drain sump and is

! monitored by an in-line rotometer that provides alarms in the control room. This drywell air cooler condensate flow l

rate monitoring system serves as an added indicator, but not

quantifier, of RCS unidentified LEAKAGE.

(continued) i l

CLINTON 8 3.4-344 .

Revision No, 2 13 i

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RCS Leakage Detection Instrumentation  !

., B 3.4.7 l BASES (continued) g-r APPLICABLE A threat of.significant compromise to the'RCPB exists if.the ~!

SAFETY ANALYSES barrier contains a crack that is large enough to propagate -

rapidly. LEAKAGE rate limits are set lew enough to detect ,

the LEAKAGE emitted from a single crack in the RCPB (Refs. 4  :

fcontinued)  !-

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RCS teakago Detection Instrumentation

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B 3.4.7 l

(- BASES j s

APPLICARLE and5). Each of the leakage detection systems inside the

- SAFE 1Y ANALYSES drywell is destgned with the capability of detecting LEAKAGE (ennifnued) less than the established LEAKAGE rate limits.

Identification of the LEAKAGE allows.the operators to- -

evaluate the significance of the indicated LEAKAGE and, if i necessary, shut down the reactor for further investigation .

and correctivo action. The allowed LEAKAGE rates are well below the rates predicted for critical crack sizes (Ref. 6).

t Therefore, these actions provide adequate response before a  !

1 significant break in the RCPB can occur, t RCS leakage detection instrumentation satisfies Criterion 1 of the NRC Policy Statement.

l LCO The drywell floor drain sump flow monitoring system is

required to quantify the unidentified LEAKAGE from the RCS.

Thus, for the system to be considered OPERABLE, either the

sump Inlet, the sump level rate of change, or the sum) pump i

discharge flow monitoring portion of the' system must se - 4 OPERABLE. The other monitoring systems provide qualitative i-( ,

indication to the operators so closer examination of other

~

detection systems 'will be made to determine the extent of I

any co'rrective' action that may oe required. With the +

leakage detection systems inoperable, monitoring for LEAKAGE in the RCPB is degraded.

4 4 - .

1 APPLICABILITY In MODES 1,.2, and 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.5. This Applicability is consistent with that for LC0 3.4.5.

ACTIONS Ad

) With the three drywell floor drain sump flow monitoring systems inoperable, no other form of sampling can provide i the equivalent information to quantify leakage. However, l

the drywell atrospheric activity monitor and the drywell air

cooler condensate flow rate monitu will provide indications of changes in leakage.

) With the three drywell floor drain sump monitoring systems .

inoperable, but with RCS unidentified and total LEAKAGE being determined every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (SR 3.4.5.1), operation may (continued)

CLINTON B 3.4-35 , Revision No. 2-13 4 4 4

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RCS Leakage Detection Instrumentation

. B 3.4.7 BASES /

1 ACTIONS M (continued) l continue for 30 days. The 30 day Completion Time of Required Action A.1 is acceptable, based on operating experience, considering the multiple forms of leakage detection that cre still available. Renuired Action A.1 is modified by a Note that states that the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when the three drywell floor diain sump flow

, monitoring systems are inoperable. This allowance is provided because other instrumentation is available to monitor RCS leakage.

M With both gaseous and particulate drywell atmospheric monitoring channels inoperable, grab sa.nples of the drywell atmosphere shall be taken and analyzed to provide periodic

- leakage information. Provided a sample is obtained and analyzed every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the plant may continue operation since at least one other form of drywell-leaka e detection -

(i.e., air cooler condensate flow rate monitor is available. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> interval provides port dic inform.ation that is adequate to detect LEAKAGE.

f( i M

With the required drywell air cooler condensate flow rate monitoring system inoperable. SR 3.4.7.1 is performed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to provide periodic information of activity in the drywell at a more frequent interval than the routine Frequency of SR 3.4.7.1. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> interval provides periodic information that is adequate to detect LEAKAGE and recognizes that other forms of leakage detection are available. However, this Required Action is modified by a Note that-allows this action to be not applicable if the required drywell atmospheric monitoring system is inoperable. Consistent with SR 3.0.1, Surveillancer, are not required to be performed on inoperable equipment.

(continued)

CLINTON B 3.4-36 . Revision No. 2-13 k

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RCS P/T Limits B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.11 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design i assumptions and the stress limits for cyclic operation.

Figure 3.4.11-1 contains P/T limit curves for heatup, cooldown, and inservice leak and hydrostatic testing. The l P/T limit curves are valid for 12 Effective Full Power Years (EFPY) of operation. Curves B and C are based on core beltline conditions with an assumed 130*F shift from an initial weld RTm of -30'F. Curve A includes beltline adjusted reference temperatures (ARTS) of 58'F for 4 EFPY, 88'F for 8 EFPY, and 100'F for 12 EFPY, In addition, Curve A includes a separate P/T limit curve for the reactor pressure vessel bottom head to account for the fact that during leak and hydrostatic pressure testing, the bottom -

head temperature may be cooler than the higher elevations of the vessel if the recirculation pumps are either stopped or operating at low speed, and injection throuch the control rod drives is used to pressurize the vessel.

Each P/T limit curve defines an acceptable region for normal operation. The usual use of the curves is operational guidance during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region.

The LC0 establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure. Therefore, the LCO limits apply mainly to the vessel.

(continued)

CLINTON B 3.4-53 Revision No. 2-10

-- . ~ - .._ . - .

RCS P/T Limits B 3.4.11 BASES ~ (continued) i BACKGROUND 10 CFR 50, Appendix G (Ref.1, requires the establishment I

\ (continued) of P/T limits for material fr)cturea toughness requirements of the RCPB materials. Reference 1 requires an ade marqin to brittle failure during normal operation, quate anticipated operational occurrences, and system hydrostatic tests. It mandatos the use of the American Society of Mechanical Engineers (ASME) Code,Section III, Appendix G (Ref. 2).

(continued) l

.CLINTON- 'B 3.4-53a '

Revision No. 2-10 4

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" B 3.4-E3b Revision No. 2-10

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RCS P/T Limits B 3.4.11

^ >

BASES ACTIONS C.1 and C.2

_(continued)

Operation outside the P/T limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been i

verified by- stress analyses. The Required Action must be initiated without delay and continued until the limits are restored.

Besides restoring the P/T limit parameters to within limits.

.an evaluation is required to determine if.RCS operation is i allowed._ This evaluation must verify-that the RCPB l- integrity is acceptable and must be completed before approaching criticality or heating up to > 200'F. Several methods may be used including, comparison with pre-analyzed-transients, new analyses,- or inspection of the components.

l ,

ASME Section XI, Appendix E (Ref. 6), may be used to support the evaluation; however, its use is restricted to evaluation of the beltline.

- SURVEILLANCE SR 3.4.11.1 REQUIREMENTS

_' RCS temperature. conditions are determined by measuring the -

metal teeperature of the. reactor vessel flange surfaces, bottom head outside surface, bottom head inside surface (as measured by the bottom head drain temperature), and reactor recirculation loop temperature. Verification that operation

, is within limits is required every 30 minutes when RCS pressure and temperature conditions are undergoing planned k_

changes. This Frequency is considered reasonable in view of

- the control room indication available to monitor RCS status.

Also, since temperature-rate of change limits are specified in hourly increments,-30 minutes permits assessment and correction of minor deviations.

Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are' satisfied.

This SR has'been modified by a Note *. hat requires this Surveillance to be performed only.ou ing system heatup and cooldown operations and inservice leakage and hydrostatic testing.

\

(continued) 4 CLINTON B 3.4-58 Revision'No. 2-10

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i ICCS-Operating 1 ,

B 3.5.1 ,

l b BASES e SURVEILLANCE SR 3.5.1 1 (continued)

-AEQUIREMENTS manual actuation after the required >ressure and flow are

'- reached is sufficient to achieve staile conditions for testing and provides a reasonable time to complete the SR.

i Alternatively, the S/RV(s) may be manually actuated without reactor steau provided measures are taken to preclude damage

- to the S/RV upon reclosure..

l i

I' SR 3.5.1.6 and the LOGIC SYSTEM FUNCTIONAL TEST performed in .l LCO 3.3.5.1 overlap this :;urveillance to provide complete j testing of the assumed safety function.

! The Frequency of 18 months on a STAGGERED TEST BASIS ensures l

]

t'.at both solenoids for each ADS valve are> alternately j tested. The Frequency is based pn the need to perform this ,

r Surveillance under the conditions that apply just prior to .

or during a startup from-a plant outage and the >otential- r 4 for un)lanned transients. Operating experience las shown i that tiese components usually pass the SR when performed at >

the 18 month Frequency, which is based on the refueling- .-

cycle. Therefore, the Frequency was concluded to be '

[ ( acceptable from:a reliability standpoint.

3.'5.1.8 1R

! This SR ensures that the ECCS RESPONSE TIMES are within

-limits for each of the ECCS injection and-apray subsystems.

This SR is modified by a Note which identifies- that the ,

associated ECCS actuation instrumentation is not required to

} ._

be response time tested. Response time testing of the ,

remaining subsystem components is required. This is supported by Reference 15.' The response time limits (i.e., 1

$42 seconds for the LPCI subsystems, 141 seconds for the LPCS subsystem, and 127 seconds for the HPCS system) are '

F specified in applicable surveillance test procedures.

~

b ECCS RESPONSE TIME. tests are conducted every 18 months. The 18 month Frequency is based on the need to perform this  :

4 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 .-t power.

Operating experience has shown that these compcnents usually pass the.SR when performed at the 18 month Frequency, which D is based on the refueling cycle. Therefore, the Frequency-was concluded to be acceptable from a reliability standpoint.

1 (continued) l[ .

4 CLINTON B 3.5 13 Revision No. 2-13 i-

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[CCS-Operating 0 3.5.1 BASES (continued)  ;

(.

REFERENCES 1. USAR, Section 6.3.2.2.3.

2. USAR, Section 6.3.2.2.4.

3. USAR, Section 6.3.2.2.1. .

4. USAR, Section 6.3.2.2.2.  ;

5. USAR, Section 15.2.8.

6. USAR, Section 15.6.4.

7. USAR, Section 15.6.5.

- 8. 10 CFR 50, Appendix K.

9. USAR, Section 6.3.3.

10. 10 CFR 50.46.

11. USAR, Section 6.3.3.3.

1 4

12. Memorandum from R.L.' Baer (NRC) to V. .Stello, Jr. . .

(NRC), "secommended Interim Revisions to LCO's for ECCS Components," December 1, 1975. , (

, l.' . 13. USAR, Table 6.3-8. .

e- 1.4. USAR,Seition 7.3.1.1.1.4.

15. NED0-32291-A, " System Analyses for Elimination'of Selected Response Time Testing Requirements," January 1994.

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Primary Containment B 3.6.1.1 BASES BACKGROUND e. The leakage control system associated with the main (continued) steam lines is OPERABLL, except as provided in

LCO 3.6.1.8. " Main Steam Isolation Valvo (MSIV) i.eakage Control System (LCS)"; and

f. The primary containment leakage rates are within the limits of this LCO.

This Specification ensures that the performance of the primar) containment, in the event of a DBA, meets the assumptions used in the safety analyses of References 1 and 2. SR 3.6.1.1.1 leakage rate requirements are in l conformance with 10 CFR 50, Appendix J Option B (Ref. 3),

j as modified by approved exemptions.

1 1

APPLICABLE The safety design basis for the primary containment is that SAFETY ANALYSES -it must withstand the pressures and temperatures of the i

limiting DBA without exceeding the design leakage rate.

l The DBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this-accident, it is assumed that primary -

containment is OPERABLE such that- release of fission products to the environment is controlled by the rate of '

primary containment leakage.

Analytical methods and assumptions involving the primary containment are presented in Refarences 1 and 2. -The safety analyses assume a nonmechanistic fission product release following--a DBA, which forms the basis for determination of offsite doses. The fission product release-is, in turn, based on an assumed leakage rate from the primary containment. OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.

The maximum allowable leakage rate for the primary containment (L,) is 0.65% by weight of the containment and l drywell air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design basis LOCA maximum peak containment pressure (P 3 ) of 9.0 psig (Ref. 4).

Primary containment satisfies Criterion 3 of'the NRC Policy Statement.

(continued)

J CLINTON_ ,

B 3.6-2 Revision No. 2-5'

Primary Containment B'3.6.1.1

. BASES .(continued)

LC0 Primary containment OPERABILITY is maintained by limiting leakage to s 1.0 aL , except prior to the first startup after performing a required Primary Containment Leakage Rate lasting Program leakage test. At this time, a)plicable leakage limits must be met. . Compliance with t iis LC0 will cnsure a primary containment configuration, including.

equipment hatches, that is structurally sound and that will

limit leakage to those leakage rates assumed in the safety analysis. Individual leakage rates specified for the primary containment air locks are addressed in LCO 3.6.1.2.

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

Therefore, primary cuntainment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

ACTIONS A.1 4

In the event that primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. >The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem that is commensurate with the-importance of' maintaining primary containment OPERABILITY >

during MODES 1, 2, and 3. This time period also ensures that the probability of-an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.

ACTIONS .B.1 and B.2 If primary containment cannot be restored to CPERABLE 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

~

(continued)

CLINTON B 3.6-3 Revision No. 2-5

Primary Containment.

B 3.6,1.1 BASES ACTIONS- 8.1 and 8.2 (continued)

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.

I SURVEILLANCE SB.,3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate

' Testing Program. Failure to meet air lock leakage testing (SR 3.6.1.2.1 , secondary containment bypass leakage (SR 3.6.1.3.8 , resilient seal primary containment purge valve 1 akage testing (SR 3.6.1.3.5), main steam isolation valve leakage (SR 3.6.1.3.9), or hydrostatically tested valve leakage (SR 3.6.1.3.10);does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs most be evaluated against the-Type A, B, and C acceptance criteria of the Primary Containment Leakage .

Rate Testing Program. As left leakage prior to the first startup after performing a required leakage test is required l -to be s 0.6 L fora combined Type B and C leakage, und s 0.75 La for overall_ Type A leakage. At all other times between-required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of s 1.0 La. At s 1.0 L 3the off, site dose-consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

This Surveillance is modified by a Note that requires the leakage rate results of SR 3.6.1.1.2 for the Primary Containment Hydrogen Recombiner System (each loop) to be included in determining compliance with required limits.

This can be accomplished either by having the loops in service during-the'llRT, or if the loop is not in service during the ILRT, by separately measuring the leakage and including it in-the measured ILRT results. '

(continued)

CLINTON B 3.6-4 Revision No. 2-5

_ l

Primacy Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.2 REQUIREMENTS (continued) With respect to primary containment integrated leakage rate testing, the primary containment hydrogen recombiners '

(located outside the primary containment) are considered extensions of the primary containment boundary. This requires the smaller of the leakage from the PCIVs that isolate the primary containment hydrogen recombiner, or from the piping boundary outside containment, ta be included in the ILRT results. The Frequency is required by the Primary Containment Leakage Rate Testing Program..

REFERENCES 1. USAR, Section 6.2.

2. USAR, Section 15.6.5.

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

4. USAR, Section 6.2.1.

5. NEl 94-01, Revision 0, " Industry Guidelint for Implementing Performance-Based Option of 10 CFR -

Part 50, Appendix J."

-6. ANSI /ANS-56.8-1994, "American National Standard for Containment System Leakage Testing Requirement."

A CLINTON B<3.6-5 Revision No. 2-5

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4 Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS E.1. E.2 and E.3 -(continued) ,

position. Also, if applicable, action must be immediately initiated to suspend OPORVs to minimize the probability of a 4

vessel draindown and subsequent potential for fission product release. Action must continue until OPORVs are

- suspended.

i-The Required Actions of Condition E are modified by a Note indicating that LC0 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

l Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.

i SURVEILLANCE SR 3.6.1.2.1

- REQUIREMENTS Maintaining primary containment air locks OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Leakage Rate Testing Program when in MODES 1, 2, and 3. This SR reflects the leakage rate -

testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and primary containment OPERABILITY testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Contairment Leakage Rate Testing Program.

The SR has been modified by three' Notes. Note 1'provides an exception to the specific leakage requirements for the 4

primary containment air locks in other than MODES 1, 2, and

3. When not operating in MODES 1, 2, or 3, primary-4 containment pressure is not expected to significantly increase above normal, and therefore specific testing at elevated pressure-is not required. Note 2 states that an

. inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

4 This is considered reasonable since either air lock door is (continued)

CLINTON B 3.6-13 Revision No. 2-5 4 0

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7 e Primary Containment ~ Air Locks >

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{ B 3.6.1.2  :

l BASES i _ SURVEILLANCE:

.SR '3.6.1.2.1 (continued)

-REQUIREMENTS i

capable of providing a fission product barrier in the event '

of a DBA. Note 3 has been added to this SR, requiring the-results to be evaluated against the. acceptance l criteria-applicable tolSR 3.6.1.1.1,.i.e., the acceptance criteria specified in the Primary Containment Leakage Rate Testing Program. Conformance to the Primary. Containment Leakage-Rate Testing Program requires air lock leakage to be '

-included in determining the overall primary containment-leakage rate.

I SR 3.6.1.2.2 The-air lock interlock mechanism t iesigned<to prevent i

simultaneous opening of both ~ doors in the air lock. Since both the inner and outer' doors of an air lock are designed' to withstano the maximum expected post accident primary b containment pressure (Ref. 4), closure of either door ~will suppcrt )rimary containment-0PERABILITY. Thus, the j interloc ( feature supports primary containment 0PERABILITY-i while the air lock is-being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and'that_ simultaneous inner and outer door o)ening will not inadvertently occur. Due to the. nature of tiis y

interlock, and given that the interlock mechanism:is only challenged when the primary containment air lock door is:

4 opened,L this test is only required to'be performed upon 4

entering or exiting a primary containment air' lock, but is- t

-not required more frequently than once per 184 days. -The I' 184 day Frequency is based _on engineering judgment and is1 considered adequate in view of other administrative control s . .

V P- REFERENCESL 1. _USAR, Section 3.8.

! [ 2. -10 CFR 50, Appendix J, Option B.

3. .USAR,.Section 6.2.1.

O

14. USAR, Section 15.7.4.

i N

1 t-CLINTON 4 8 3.6-14 Revision No. 2-5 A

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PCIVs B 3.6.1.3 BASES ACTIONS D.I. D 2, and 0.3 (continued) closed (refer to the requirements of SR 3.6.1.3.1; if this requirement is not met, entry into Condition A and B, as appropriate, would also be required), so that a gross breach of primary containment does not exist.

In accordance with Required Action D.2, this penetration flow path must be verified to be isolated on a periodic basis. The periodic verification is necessary to ensure that primary containment penetrations required to be isolated following an accident, which are no longer capable of being automatically isolated, will be isolated should an event occur. This Required Action does not require any testing or valve manipulation. Rather, it involves verification that those isolation devices outside primary containment and potentially capable of being mispositioned are in the correct position. For the isolation devices inside primary containment, the time period specified as

" prior to entering h?DC 2 or 3, from MODE 4 if not performed within the previous 92 days" is. based on engineering judgment and is considered reasonable in . view of administrative controls that will ensure that isolation -

device misalignment is an unlikely possibility.

For a primary containtant purge valve with a resilient seal that is isolated in accordance with Required Action D.1, SR 3.6.1.3.5 must be performed at least once every 92 days.

This provides assurance that degradation of the resilient seal is detected and confirms that the leakage rate of the primary containment purge valve does not increase during the time the penetration is isolated. The normal Frequency for SR 3.6.1.3.5 is as required by the Primary Containment Leakage Rate Testina Program. Since more reliance is placed on a' single valve W.ile in this Condition, it is prudent to perform the SR more often. Therefore, a Frequency of once' per 92 days was chosen and has been shown acceptable based on operating experience.

E.1 and E.2 If any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, the plant must be brought to a MODE in which the LC0 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 (continued)

CLINTON 8 3.6-21 Revision No. 2-5 '

PCIVs l B 3.6.1.3 l 1

BASES l

SURVEILLANCE SR 3.6.1.3.1 (continued)

REQUIREMENTS capability would be required by SR 3.6.1.3.4 and SR 3.6.1.3.7).

The SR is modified by a Note (Note 2) stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that the 36-inch valves may be opened for pressure control, ALARA or air quality considerations for personnel entry, or for Surveillances or special testing on the purge system that require the valves to be open (e.g., testing of containment and drywell ventilation radiation monitors), provided the 12-inch containment purge and the drywell vent and purge lines are isolated. These primary containment purge valves are capable of closing in the environment following a LOCA.

Therefore, these valves are allowed to be open for limited periods of time. The 31 day Frequency is consistent with other PCIV requirements.

SR 3.6.1.3.2

-This SR verifies that each primary containment isolation .

manual valve and blind flange that is located outside primary containment, drywell, and steam tunnel, and is required to be closed during accident conditions, is closed.

The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the primary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather,-it involves verification that those devices outside primary containment, drywell, and steam tunnel, and capable of being mispositioned, are in the correct position. Since verification of valve position for devices outside prim.ry containment, drywell, and steam tunnel is relatively easy, the 31 day Frequency was chosen to provide added assurance that the devices are in the correct positions.

Two Notes are added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them tc be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for Alims reasons. Therefore, the probability of misalignment of (c_ontinued)

CLINTON B 3.6-22b Revision No. 2-8

s PCIVs B 3.6.1.3

= BASES

-SURVEILLANCE -SR 3.6.1.3.2 (continued) l REQUIREMENTS these devices,-once they have been verified to be ii.-the propt e position, is' low. A second Note is' included to clarify that--PCIVs- cpen under administrative- controls are not required to meet the SR during the time the PCIVs are open.-

S,B_,3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange located inside primary

-- - containment, drywell, er steam tunnel, and required to- be-closed during accident conditions, is closed. -The SR helps-

~

-to ensure that post accident leakage of radioactive fluids or-gases outside the primary containment boundary is within--

design-limits.. For devices inside primary containment, drywell, and. steam tunnel, the Frequency of " prior to-entering NODE 2 or 3 from MODE 4, if not performed within the-previns 92-days", is appropriate since these devices

~

are o>erated under: administrative controls and the probasility of their misalignment is low. .

l- Three Notes'are added to this SR. The first NoteJallows valves and blind. flanges located in high -radiation areas to be verified by use of; administrative-controls. Allowing verification by administrative controls -is considered; acceptable since access to these areas is typically restricted during MODES 1,:2, and 3.. Therefore, the probability of misalignment of'these devices, once they have been verified to be in their proper position, is low. A second Note is-included-to elarify-that PCIVs that-are open under administrative controls are not-required to-meet:the LSR:during the time that the PCIVs!are open.

A third note is added to allow removal of the inclined Fuel Transfer System _ (IFTS) blind flange when primary containment operability is required. This provides the option of operating-the IFTS system when primary containment-operability is required. - Requiring the fuel building fuel

,~

transfer. pool water level to be 2 el. 753 ft. ensures a sufficient depth-of water over,the highest point on the transfer tube outlet valve in the fuel building. fuel

. transfer. pool to prevent direct communication betwan the containment building atmosphere and the fuel building (continued)

Y=

• CLINTON 8 3.6-23 , Revision No. 2-8 '

\

q

4 4 PCIVsz

~B 3.6.1.3 i

BASES-SURVEILLANCE - SR- 3.6.1.3.3 (continued) i

' REQUIREMENTS

- atmosphere via the inclined fuel transfer tube. Since the i IFTS transfer tube drain line does not have the same water i= seal as the transfer tube, and the motor-operated drain

- valve remains open when the carriage is in the-lower pool, l administrative controls are required to ensure the drain line flow path is quickly: isolable in the event of a LOCA.

In this-instance, administrative control of the IFTS

transfer tube drain line isolation l valve (s) include stationing a dedicated individual, who is in continuous communication wit'n the control room, at the IFTS control

! panel- in the fuel building. This individual will = initiate closure of the IFTS transfer tube drain line motor-operated

. . isolation valve (1F42-F003); and the IFTS transfer tube Ldrain line manual isolation valve (lF42-F301) -if a- need for primary containment isolation is indicated. The pressure

, integrity of the IFTS transfer tube,'the seal created by

- water depth of the fuel' building fuel transfer pool, and the-

administrative control of the drain line . flow path create-an acceptable barrier to prevent the- post-accident containment building atmosphere from leaking onto the fuel building.

SR 3.6.1.3.4 r .

i- Verifying the isolation- time'of each power operated and each automatic PCIV is within limits is. required to demonstrate

' 0PERABILITY.- MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.6.

[ The isolation time test ensures that the valve will isolate (continued) l e

} __

+

CLINTON B 3.6-24 Revision No. 2-8

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.4 (continued)

REQUIREMENTS in a time period less than or equal to that assumed in the safety analysis. The isolation time and frequency of this SR are in accordance with the Inservice Testing Program.

SR 3.6.1.3.5 For primary containment purge valves with resi' lent seals, additional leakage rate testing beyond the test requirements l of the Primary Containment Leakage Rate Testing Program is required to ensure OPERABILITY. The acceptance criterion for this test is s 0.01 L when a pressurized to Pa, 9.0 psig.

Since cycling these valves may introduce additional seal degradation (beyond that which occurs to a valve that has not been opened), this SR must be performed within 92 days after opening the valve. However, operating experience has demonstrated that if a valve with a resilient seal is.not stroked during an operating cycle, significant increased leakage through the valve is not observed. Based on this observation, a normal Frequency in accordance with the Primary Containment Leakage Rate Testing Program was -

established.

The SR is modified by a Note stating that the primary containment purge valves are only required to meet leakage rate testing requirements in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, purge valve leakage .must be minimized to ensure offsite radiological release is within limits. At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are'not present and the purge valves are not required to meet any specific leakage criteria.

SR 3.6.1.3.6 Verifying that the full closure isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The full closure isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses. The Frequency of this SR is in accordance with the Inservice Testing Program.

_ (continued)

CLINTON B 3.6-25 Revision-No. 2-5

PCIVs B 3.6.1.3 BASES

\

SURVEILLANCE SR 3.6.1.3.7 .

REQUIREMENTS (continued) Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.7 overlaps this SR to provide complete testing of the safety function. The 18 month Frequency is' based on the need to perform this Surveillance under the conditions that apply during a plant outage and the poter.tial for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass this Surveillance when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.1.3.8 This SR ensures that the. leakage rate of secondary containment bypass leakage paths is less than the specified leakage rate. This provides assurance that the assumptions '

in the radiological evaluations of Referr.nces 1, 2, and 3 are met. The leakage rate of each bypass leukage path is assumed to be the maximum pathway leakage (leakage through the worse of the two isolation valves) unless the penetration is isolated by use of one closed and de-activated automatic valve, closed manual valve, or blind fl ange. In this case, the leakage rate of the isolated bypass leakage path is assumed to be the actual pathway leakage through the isolation device. If both isolation.

valves in the penetration are closed, the actual leakage rate is the lesser leakage rate of the two valves. This method of quantifying maximum pathway leakage is only to be l used for this SR.

The Frequency is consistent with the Primary Containment 4 Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria. Secondary containment bypass leakage is considered part of La-A Note is added to this SR which states that these valves are c.ily required to meet this leakage limit in MODES 1, 2 and 3. In the other con'ditions, the Reactor Coolant System (continued)

CLINTON 8 3.6-26 Revision No. 2-5

.,, c ,. y. . . c.i e . e o t we s

PCIVs B 3.6.1.3 BASES i i

SURVEILLANCE SR 3.6.1.3.8 (continued) )

REQUIREMENTS is not pressurized and specific primary containment leakage limits are not required a

3 SR 3.6.1.3.9 The analyses in References 1, 2, and 3,are based on leakage that is less than the npecified leakage rate. Leakage through each main steamline mtist be s 28 scfh when tested at P, (9.0 psig). The MSIV leakage rate must be verified to be in accordance with the assumptions of References 1, 2 and

3. A Note is added to this SR which states that these valves are only required to meet =this leal:agti limit in MODES 1, 2, and 3. In the other conditions, the Reactor Coolant System is not/ pressurized and primary containment leakage limits are not required. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR 3.6.1.3.10 Surveillance of hydrostatically tested lines provides ~

assurance that the calculation assumptions of Reference 4 are met. The combined leakage ratos (of I gpm times the total number of PCIVs when tested at 2

1.1 P must be demonstrated at the frequency of the leakage,)estt requirements of the Primary Containment Leakage Rate Testing Program.

This SR is modified by a Note that states that these valves are only required to meet the combined leakage rate in

' MODES 1, 2, and 3 since this is when the Reactor Coolant System is' pressurized and primary containment is required.

In some instances, the valves are required to be capable of

- automatically closing daring MODES other than MODES 1, 2, and 3. However, specific leakage limits are not applicable

.in these other MODES or conditions, t'

SR 3.6.1.3.11 This SR requires a demonstratica that each instrumentation line excess flow check valve (EFCV) is OPERABLE by verifying that the valve activates within the required differential (continued)

CLINTON B 3.6-27 Revision No. 2-5

PCIVs ]

B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.ll-(continued)

REQUIREMENTS l pressure or flow range. This SR provides assurance that the instrumentation line EFCVs will perform so that predicted radiological consequences will not be exceeded during the postulated instrument line break events (Ref. 7). The 18 month Frequency is-based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an un)lanned transient if the Surveillance were performed with tie reactor at power, REFERENCES 1. USAR, Chapter 15.6.5.

2. USAR, Section 15.6.4.

l

3. USAR, Section 15.7.4.

4. USAR. Section 6.2.

5. USAR, Table 6.2-47.

~6. 10 CFR 50, Appendix J, Option B. ,

7. Regulatory Guide 1.11. .

4 j

4 4

4 CLINTON B 3.6-28 Revision No. 2-11

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Secondary Containment-B 3.6.4.1 r BASEST

(

. SURVEILLANCE

' REQUIREMENTS; SR~ 3.6.4.1.4 and SR '3.6.4.1.5- (continued).  ;

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. lowest postulated' pressure external to the- secondary containment boundary. This is confirmed by demonstrating that one SGT-subsystem will draw.

down the secondary containment to a 0.25-inches of vacuum water gauge within the time required by Figure 3.6.4.1-1.

, These time limits account-for differences between testing-i-

conditions and anticipated LOCA conditions. The acceptance-

' criteria specified-in Figure _3.6.4.1-1 for the drawdown. test is based on a computer model. verified by actual performance of drawdown tests, in which the drawdown time determined for accident conditions is-adjusted to account for performance i -

l- of the test during normal plant conditions (acfm); . The acceptance criteria indicated per Figure 3.6.4.1-1 is based

- on conditions; corresponding to power operation (with the-turbine building ventilation system in operation) and wind

' speeds less than or equal to.10 mph. The acceptance - _

criteria for plant conditions other than'those assumed will-

- be adjusted as necessary to reflect < the conditions which ' . -

exist during-performane.e of'the surveillance test (e.g., via the use of separate figures-for different plant operating 1 conditions, such as for those corresponding to plant 'h p # shutd6wn with and without the turbine building ventilation

• system in operation). This ensures that 2 0.25 inches of. '

vacuum water gauge will be established in s 188 seconds

[ under LOCA conditions. This cannot be accomplished if the secondary containment boundary is not intact. SR 3.6.4.1.5

. demonstrates that each SGT-subsystem can maintain-:

. k 0.25 inches'of vacuum water gauge. for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at a' flow l- rate s 4400 acfm. The'l hour test, period allows secondary r ~ containment to.be in thermal equilibrium at steady state.

conditions. -Therefore, these two tests are used to ensure-secondary containment. boundary 1 integrity. Since these SRs

' are secondary containment tests, they need not be performed with each SGT subsystem and an inoperable SGT subsystem.does not result in this SR being not met.- The SGT subsystems are tested on a STAGGERED TEST BASIS, however, to ensure that in 3 :: addition-to the requirements _of LCO 3.6.4.3, either SGT

, subsystem will perform this test. Operating experience has

-(continued)

L 13 l-

{: CLINTON B 3.6-88' .

Revision No. 2-13 4

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Secondary Containment B 3.6.4.1

~ BASES SURVEILLANCE; SR 3.6.4.1.4 and SR 3.6.4.1.5 (continued)

REQUIREMENTS

, shown these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore. the Frequency was concluded to be acceptable from a reliability standpoint.

, REFERENCES 1. USAR,.Section 15.6.5.

2. USAR, Section 15.7.4.

4

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CLINTON B 3.6-88a' Revision No. 2-7

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s CLINTON 8 3.6-88b Revision No. 2-7

SGT System B 3.6.4.3 B 3.6 CONTAINMENT SYSTEMS-B 3.6.4.3 Standby Gas Treatment (SGT) System BASES BACKGROUND The SGT System is required by 10 CFR 50, Appendix A. GDC 41,

" Containment Atmosphere Cleanup" (Ref.1). The function of I the SGT System is to ensure that radioactive materials that, leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exl austing to the environment. ASME/ ANSI N510-1980, Testing of Nuclear Air cleaning Systems require that rates are measured with respect to design flow. For the SGT system, the design flow rates are in acfm.

The SGT System consists of two fully reduadant subsystems, each with its own set of ductwork, dampers, charcoal filter train, and controls.

- Each charcoal filter train consists of (components listed in order of the direction of the air flow): -

a. A flow control damper; t '

, h

b. A demister; *

!' c. An electric heater;

d. A prefilter; c.- A high efficiency particulate air (llEPA) filter;-

f .- A charcoal adsorber;

g. A second HEPA filter;-and

h. A centrifugal fan.

The sizing of the SGT System equipment and components is based on the results_ of an infiltration analysis, as well as an exfiltration analysis of the auxiliary building, fuel bt.;1 ding, emergency core cooling system (ECCS) pump rooms, and the gas control boundary. The internal pressure of the SG1 System boundary region is maintained at a negative pressure of at least 0.25 inch water gauge when the system is in operation, which represents the internal pressure (continued)  :

. CLINTON B 3.6-96 .

' Revision No. 2-13 s =. ,. ,k.s> a 8

.. - ce 1 g

• g s

SGT System

. B 3.6.4.3

[ BASES-

=

required to ensure zero exfiltration of ' air from the

~

BACKGROUND (continued) -building when exposed to a 20 mph wind.

The deutster is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream to less than 70% (Refs.-2 and 5). The prefilter removes large particulate matter, while the HEPA filter is provided to remove fine particulate matter and protect the charcoal from fouling. The charcoal adsorber removes gaseous elemental iodine and organic iodides,- and the f_inal HEPA filter is provided to collect any-carbon fines exhausted from the charcoal adsorber.

The SGT System automatically starts and operates in response to actuation signals indicative of conditions.or an-accident that could require operation of the system. Following L initiation, both charcoal filter train' fans start. - SGT l System flows are controlled by modulating inlet dampers i: installed on the charcoal filter train inlets.

APPLICABLE -The design basis for'the SGT System is to mitigate the

, SAFETY ANALYSES consequences of a loss of coolant accident and fuel handling

- (-

accidents (Refs. 3 and 6) -For all events analyzed,. the SGT

, System is shown- to be-automatically initiated to reduce, via filtration and adsorption, the radioactive material released

• to-the environment.

The SGT System satisfies Criterion 3 of the NRC Policy Statement.

LCO Following a DBA, a minimum of one SGT-subsystem is required to maintain the secondary containment at a negative pressure with respect to the environment and to process gaseous releases. - Meeting the LCO _ requirements for two operabb subsystems ensures operatQn of at least one' SGT subsystem in the event of a single active failure.

APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission product release to primary containment.that leaks to secondary containment. Therefore, SGT' System OPERABILITY is required during these MODES ~.

(continued)

CLINTON B 3.6-97 -

Revision No.__2-13

_ .. _ _ . _ ~ . _ _ _ _ . . _ _

SGI System

', -D 3.6.4.3 BASES

(

APPLICABILITY In MODES 4 and 5, the probability and consequences of these

'(continued) -events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT >

i System OPERABLE is not required in MODE 4 or 5, except for

-other situations under which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel-i-

(OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the primary or secondary containment.

ACTIONS Ad

' Wit $ one SGT subsystem inoperable, the inoperable subsystem mt . be restored to OPERABLE status within 7 days. In this

- Condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function. However the overall system reliability is reduced because a s, ingle failure in the OPERABLE subsystem could result in the radioactivity release control function not being adequately performed. The 7 day Completion Time -

is based on consideration of such factors as the availability of the OPERABLE redundant SGT sebsystem and the low probability of a DBA occurring during this period. ' (.

4 B.1 and B.2 i~

If the SGT subsystem cannot be. restored to OPERABLE status within the required Completion Time in MODE 1, 2, or 3, the

' plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

4 C.1. C.2.1. C.2.2. and C.2.3 During movement of irradiated fuel assemblies in the primary or secondary containment, during CORE ALTERATIONS, or during OPDRVs, when Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE SGT subsystem should be immediately placed in operation. This Required Action ensures that the remaining subsystem is OPERABLE, (continued)

(-

CLINTON B 3.6-9B .

Revision No. 2-13 l.

ex < -. _ +-

~

SGT System B 3.6 A.3

~

l j

)i l -

BASES n __

.}

ACTIONS , C.1. C.2.1. C.2.2. and C.2.3:-(continued) that no failures.that:could prevent automatic actuation have i occurred.._and that.any other failure would be readily ,

detected.

1 An alternative to Pequired Action C.1 is to immediately-

. suspend activities that represent-a potential _for releasing" radioactive material to the secondary containment, thus placing the unit in a Condition that minimizes risk. If

applicable, CORE ALTERATIONS and movement of irradiated fuel-assemblies must be immediately suspended. Suspension of

- 1 these activities shall not preclude completion of movement  ;

of a component to a safe position.- Also, .if applicable;- t

. action must be immediately initiated to suspend OPDRVs to  :

minimize the probability of a vessel draindown and

. subsequent potential for fission product release. This -

action should be chosen if the OPDRVs could be impacted:by a-i loss of offsite power. ? Action must continue until OPORVs

[

are suspended. '

~

The Required Actions-of Condition G have 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 4

'~ -( would not specify any action. If moving irradiated fuel +

assemblies while in M00E 1,. 2, or 3, the fuel movement is- -

4 independent of reactor operations. Therefore, in-either 4 case, inability to suspend movement of irradiated fuel.

!, assemblies would not be:a sufficient reason to require a reactor shutdown.

i

_ D.d If both SGT ribsystems are inoperable in'h00E 1, 2, or 3, the SGT System may not be capable of supporting the required

-radioactivity relaase control = function- Thcrefore; LCO .

3.0.3 must be entered immediately.

E.1. E.2. and'E.3 i

When two SGT subsystems are inoperable, if applicable,- CORE ALTERATIONS and move'nent of irradiated fuel essemolies in the primary and secondary containment must be immediately i suspended. Suspension of these_ activities shall not preclude completion of movement of a component to a safe (continued)_

l

(;

'CLINTON - 8 3.6-99 -

. Revision No. 2 213 g g 4

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, B 3.6.4.3 -

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j- ACTIONST ' E.1. E.2.'and E. (continued) 1~'

po s i t i on'.- Also, if applicable, actions must' be immediately -

L~ initslated to suc9end OPDRVs to minimize'.the probability of a

# vessel draindowmand subsequent potential for fission-

~

+

product release. A.ction must continue until OPDRVs are suspended.-

[ SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS

- Operating each.SGT subsystem from the main control room for F '

h 10 continuous' hours ensures that both subsystems are

', OPERABLE and that air associated controls are functioning.

properly. It also ensures that blockage, fr.n or. motor

[ failure, or excessive vibration can be detected for corrective action.c Operation with the heaters ~on.(automatic F - heater cycling tc maintain temperature) for a 10 continuous

' hours every 31 days-eliminates moisture on the adsorbers and i HEPA filters. The 31 day Frequency was developed in-

[ .

consideration of the Anom reliability of fan motors and

- controls and the. redundancy available in the systm.

5 ~SR 3.6.4.3.2 - ('s

! This SR verifies thit the required SGT filter t'esting is '

z performed in accordance with the Ventilation Filter Testing

' Program-(VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber bypass leakage and

! -- efficiency, minimum system flow rate, combined HEPA filter i , and charcoal adsorber pressure drop, and heater dissipation.

The frequencies for performing--the SGT System tilter tests are in accordance with Regulatory Guide 1.52 (Ref 4) and L include testing initially,- after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system ioperation - once per 18 months, and following painting, fire, i,

or chemical release in any ventilation zone communicating

-with the system. The laboratory test results will be-5- verified to be within limits within 31- days of removal of h *

• the sample from the system.- Additional-information is-t- discussed in-detail in the VFTP.

SR 3.6.4.3.3

'This SR requires verification that each SGT subsystem automatically starts upon receipt of an actual or simulated initiation signal.

(continuedF

- C-CLINTON- B 3.6-100 . Revision No. 2-13 t

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-SGT System-B 3.6.4.3-

[ BASES

. SURVEILLANCE  :

.SR- 3.6.4.3.3. (continued) _ l REQUIREMENTS-The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.'6.2.5 overlaps

. this SR to provide complete testing of the safety function.  ;

While this Surveillance can be performed with the reactor at power, operating experience has shown these components:

usually pass the Surveillance when performed at the 18 month-Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

l SR 3.6.4.3.4 This SR requirns verification that the SGT filter cooling-bypass damp.er can~be opened and the fan started. -This

- ensures that the ventilation mode of SGT System operation is -

available. Knile this Surveillance can be performed with the reactor at power, oper aing. experience has shown these

omponents usually pass the Surveillance when performed at the- 18 month Frequen

y, which is based on the refueling cycle. Therefore, the Frequency was concluded to be -

. . acceptable from a reliability standpoint.

• REFERENCES 1. 10 CFR 50, Appendix A, GDC 41.

2. USAR, Section 6.2.3.

3. USAR, Section 15.6.5.

4. -Re'gulatory Guide 1.52.

5. USAR,-Section 6.5.1.

6. USAR, Section 15.6.4.

- l-

7. USAR Appendix'A.

l 8. ~ ASME/ ANSI N510-1980.

CLINTON- 8 3.6-101 . Revision No. 2-13 t

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l

_ I it Drywell '

B 3.6.5.1 r

l1 :B 3.6' CONTAINMENT SYSTEMS B 3.6.5.1 Orywell -

l BASES t

BACKGROUND The drywell houses the reactor pressure vessel (RPV), the

- reactor coolant recirculating loops, and branch connections of the Reactor Coolant System (RCS), which have isolation '

i. ,

valves at the primary containment boundary. The function of the drywell is to maintain a pressure boundary that channels steam from a loss of coolant accident (LOCA) to the suppression pool, where-it is conden;ed. Air forced from.

the drywell is released into the primary containment through the suppression pool. The pressure suppression capability of the suppression pool assures that peak LOCA temperature and pressure in the primary containment are within design.

limits. The drywell also protects accessible areas of the-containment from radiation originating in the reactor core

- and RCS.

..- .To ensure. the drywell pressure suppression capability, the ,

drywell byp' ass leakage must be minimized to prevent-overpressurization of the primary containment during the (.

drywell pressurization phase of a LOCA. This requires . \-

t . ,

periodic testing of the drywell bypass leakage, confirmation, that the drywell' air lock is leak tight, OPERABILITY of the drywell isolation valves, and confirmation that the drywell vacuum relief valves are closed.

The drywell air. lock forms part of the drywell pressure

- boundary. Not maintaining air lock OPERABILITY may result ,

in degradation of'the pressure suppression capability, which is assumed to be functional in =the unit safety analyses.

The drywell' air lock does not need to meet the requirements of 10 CFR 50, Appendix J (Ref. 2), since it is not part of the primary containment leakage boundary. However, it is-prudent to specify a-leakage rate requirement' for the drywell air lock. 'A seal leakage rate limit and an air lock overall leakage rate limit have been established to assure the integrity of the seals.

The isolation devices _ for the'.drywell penetrations are a ~

- part of the drywell barrier. To maintain this barrier:

a.- The drywell air lock is OPERABLE except as provided in

.- LCO 3.6.5.2, "Drywell Air Lock";-

(continued) o CLINTON 8 3.6-l'02 Revision No. 2-6 l .

-Drywell

_ B 3. 6. 5.1 --

~

o  ; BASES:

4 BACKGROUND' __

ib. The drywell penetrations requiredJto be closed during

-. (continued) Laccident conditions are either:

1. capable of being closed by an OPERABLE automatic-drywell isolation valve, or -

I 2. closed by a manual- valve, blind flange. or

- de-activated automatic valve secured in the '

closed position except'as provided in LCO 3.6.5.3, ~ "Drywell Isolation Valves";

} c. .

All drywell equipment hatches _ are closed; i . d. The:Drywell Post-LOCA-Vacuum Relief System .is OPERABLE lexcept as provided in LCO 3.6.5.6, "Drywell Post-LOCA Vacuum Relief System";-

~

e. The suppression pool is OPERABLE, except as provided

-in LCO 3.6.2.2, " Suppression Pool-Water level"; and

f. 'The.drywell leakag'e rate is within-the-limits of this LCO.

r This Specification-is intended to ensure that thel performance of the drywell-in the event-of a DBA meets the assumptions used in-the safety analyses (Ref. 1).

APPLICABLE - Analytical- methods and assumptions involving the-drywell are

-SAFETY ANALYSES' presented in Reference-1. The safety- analyses assume. that -

for a high energy line break inside the drywell, the steam-is directed to the suppression pool- through-the horizontal vents where it is condensed. Maintaining the pressure

~

suppression capability assures that safety analyses remain valid'and that the peak LOCA temperature and pressure. in the primary containment-are within design limits.

The drywell satisfies Criteria'2' and 3'of the'NRC Policy Statement.

LC0 Maintaining the drywell OPERABLE is required to ensure that the pressure suppression design functions assumed in'the safety analyses are met. The drywell is OPERABLE if the drywell-structural integrity is intact and the bypass (continued)

) 1 i

- CLINTON , B 3.6-103 Revisi No.~2-6

-y wr- Q y-v*r- c--,-r, n--e

i Drywell j B 3.6.5.1 q

~

BASES.

LC0 leakage is within limits, except prior to the first startup (continued) after performing a required drywell bypass leakage test. At

, this time, the drywell bypass leakage must be s 10% of the drywell bypass leakage limit.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are-reduced due to the pressure and temperature limitations of these MODES. Therefore, the drywell-is not required to be OPERABLE in FDDES 4 and 5.

ACTIONS M In the event the drywell is inoperable, it must be restored Eto OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the'importance of maintaining the drywell OPERABLE during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring drywell OPERABILITY) occurring during periods when the '.

drywell is inoperable is minimtl. Also, the Completion' Time s, is-the same as that applied to;inoperability of the primary containment in LC0 3.6.1.1, " Primary Containment."

B.1 and B.2 If the drywell 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.

-l SURVEILLANCE -SR 3.6.5.1.1 ,

REQUIREMENTS This SR requires a test to be performed to verify seal leakage of the drywell air lock doors at pressures 2 3. 0 .

psig. A seal leakage rate limit of 1 2 scfh has been established to ensure the integrity of _ the seals. The-

+

(continuedl CLINTON- B 3.6-l'J4 Revis' ion No. 2-6

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w

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l Drywell '

B 3.6.5.1 BASES SURVEILLANCE SR 3.6.5.1.1 (continued)-

REQUIREMENTS Surveillance is only required to be performed once within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each closing. The Frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is based on operating experience.

SR 3.6.5.1.2 This SR requires a test to be performed to verify overall

> air lock leakage of the drywell air lock at pressures 2 3.0 psig. Prior to performance of this test, the air lock must 4 be pressurized to 19.7 psid. This differential pressure is the assumed peak drywell cressure expected from the accident ,

analysis. Since the drywell prassure. rapidly returns to a' steady state maximum differential pressure of 3.0 psid (due i to suppression pool vent clearing), the overall air lock leakage is allowed to be measured at this pressure.

An overall air lock leakage limit of 5 2 sr . . has been established'to ensure the integrity of the seals. The 24-month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant -

outage and the potential for violating the drywell boundary.

Operating experience has shown these components usually pass the Surveillance. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR has been modified by a Note indicating that an inoperable air lock door-does not invalidate the previous successful performance of an overall air lock leakage test.

This is considered reasonable, since either air lock door is capable of providing a fission product barrier in the event of a DBA.

l SR 3.C.5.1.3 The analyses in Reference 1 are based on a maximum drywell bypass leakage. This Surveillance ensures that the actual drywell bypass leakage is less than or equal 2

to the acceptable A/4 design value of 1.18 ft assumed in the-safety analysis. As left drywell bypass leakage, prior to the first startup after performing a required drywell bypass leakage test,. is required to be :s; 10% of the drywell bypass leakage limit. At all other times between required drywell (continued)

)

CLINTON 8 3.6-105 Revision No. 2-6

I Drywell

{- B 3.6.5.1 BASESI 4 .

{ SURVEILLANCE SR 3.6.5.1.3 (continued)

RE

-QUIREMENTS-_ -

F leakage rate tests, the acceptance criteria is based on the designtA M . :Atithe design A/ d the containment

' temperature and pressurization response are bounded by the assumptions of the safety. analysis. One drywell air lock door is left open during each drywell bypass -leakage test such that each drywell air lock door is leak tested during at least every other drywell bypass leakage test. ~ This

' ensures that the leakage through the drywell air lock is properly accounted for in the measured bypass-leakage and that each air lock is tested periodically.

Ihis Surveillance is performed at least once every 10 years (120 months) on a performance. based frequency. - The Frequency is consistent with the difficult the test, risk of high radiation exposure,y of- andperforming the remote possibility that sufficient component failures will occur such that~ the drywell bypass leakage limit will be exceeded.

If during the perforuance of this required Surveillance the drywell bypass-leakage is determined- to be greater than the leakage limit, the Surveillance frequency is increased to at .

least once every 48 months. - If during the performance of the subsequent consecutive Surveillance the drywell bypass leakage is determined to be -less. than or. equal t a the ,,

drywell bypass leakage limit, the 10-year Frequency may be resumed. If during the performance of the subsequent consecutive Surveillance the 'drywell bypass leakage is determined to.be greater than .the drywell bypass leakage limit, the Surveillance Frequency-is-increased to at least once every 24 months. The 24-month Frequency must be .

maintained until the drywell ' bypass leakage is determined to

'be less than or equal to the-leakage limit during the performance of two consecutive Surveillancos, at which time the 10-year Frequency may be resumed. For two.Surveillances to be considered consecutive, the Surveillances must be performed at least 12 months apart.

Since the Frequency is performance based, the Frequency was concluded to be-acceptable from a reliability standpoint.

] SR 3.6.5.1.4 i The exposed accessible drywell interior and exterior surfaces are inspected to ensure there are no apparent physical defects. that would prevent the drywell from

( cont i nued_).

CLINTON B 3.6-105a Revision No. 2-6

Drywell B 3.6.5.1 BASES =

SURVEILLANCE' .SR 3.6.5.1.4-(continued)L

= REQUIREMENTS-performing its. intended function. This SR ensures that drywell structural integrity is maintained. -The Frequency was chosen so that the interior and exterior surfaces of the drywell can be inspected in conjunction with the inspections of the primary containment required by 10 CFR 50,-Appendix J

.(Ref. 2) . Due to the passive nature of the drywell

- structure, the specified Frequency is sufficient to idcatify component degrade.cion that may affect drywell structural integrity.

-REFERENCES 1. USAR, Chapter 6 anti Chapter 15.

2. 10 CFR 50, Appendix J, Option 8.

s L

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1 l $ -

'CLINTON_ .B 3.6-105b -Revision No. 2-6

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Orywell Air Lock B 3.6.5.2 B 3.6 CONTAINMENT SYS1 EMS B 3.6.5.2 Drywel) Air Lock BASES BACKGROUND The drywell air lock forms part of the drywell boundary and proviues_a means for personnel access during MODES 2 and 3 during_ low power phase of unit startup. For this pur)ose, one double door drywell air lock has been provided, watch maintains drywell isolation during personnel entry and exit from the drywell. Under the normal unit operation, the drywell air lock is kept sealed.

The drywell air lock is designed to the same standards as the drywell boundary. Thus, the drywell air lock must withstand the pressure and temperature transients associated-l with the rupture of any primary system line inside the drywell and also the rapid reversal in pressure when the steam in the drywell-is condensed by the Emergency Core Cooling System flow following loss of coolant accident flooding of the reactor pressure vessel (RPV). It is also designed to withstand the high temperature associated with

-the break of a small steam iine in the drywell that does not

• result in rapic dept issurization of the RPV.

The air lock is nominally a right circular cylinder, 9 ft 10 inches in diameter, with coors at each end that are interlocked to prevent simultanc;us opening. During periods when the drywell is not required to be OPERABLE, the air lock interlock mechanism may be disabled, allowing both doors of the air lock to remain open for extended periods when frequent drywell entry is necessary. Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected l pressure following a Design Basis Accident (DBA). The drywell air lod. forms part of the drywell aressure boundary. Not meintaining air lock OPERABIalTY may result in degradation of the pressure suppression capability, which

_is assumed to be functional in the unit safoty analyses.

I (continued)

CLINTON' B 3.6 106 Revision No.-E 6

~. .

Drywell Air lock B 3.6.5.2 JBASES (continued)

APPLICABLE Analytical methods and assumations involving the drywell are SAFETY ANALYSES presented in Reference 2. 11e safety analyses assume that for a high energy line break inside the drywell, the steam is directed to the suppression pool through the horizontal vents where it is condensed. Since the drywell air lock is part of the drywell pressure boundary, its design and maintenance are essential to support drywell OPERABillTY, which assures that the safety analyses are met.

The drywell air lock satisfies Criterion 3 of the NRC Policy Statement.

LCO The drywell air lock forms part of the drywell pressure boundary. The air lock safety function assures that steam resulting from a' DBA is directed to the suppression pool.

Thus, the air loct's structural integrity is essential to the successful mitigation of such an event.

The air lock is roouired to be OPERABLE. For the air lock to be considered OPERABLE, the air lock interlock mechanism l must be OPERABLE, and both air lock doors must be OPERABLE.

The interlock allows only one. air lock door of an air lock .-

to be opened at ons time. This provision ensures that a gross breach of the drywell does not exist when the drywell is required to be OPERABLE, Air lock leakage is ercluded from this Specification. The air lock leakage rate is part of the drywell leakage rate and is controlled as part of OPEPABillTY of the drywell in LC0 3.6.5.1, "Drywell Closure of a single door in the air lock is necessary to support drywell OPERABILITY following postuisted events.

Nevertheless, both doors are kept closed when the air lock is not being used for entry into and exit from the drywell.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are (continued)

)

CLINTON B 3.6-107 Revision No. 2-6

Drywell Air Lock B 3.6.5.2 BASES APPLICABILITY reduced due to the pressure and temperature limitations in (continued) these MODES. Therefore, the drywell air lock is not requirad to be OPERABLE in MODES 4 and 5.

l ACTIONS The ACf!ONS are modified by a Note which allows entry and exit to perform repairs on the affectea air lock component.

if the outer door is inoperable, then it may be easily accessed to repair. If the inner door is inoperable, however, then there is a short time during which the drywell boundar door). y is not intact (during access through the outerThe ability means the drywell boundary is-temporarily not intact, is acceptable due to the low probability of an event thTt could pressurize the drywell during the short time in which the OPERABLE door is expected to be open. The OPERABLE door must be immediately closed after each entry and exit.

l A.I. A.2. and A.3 With one drywell air lock door inoperable, the OPERABLE door ,

must be verified closed (Required Action A.1). This ensures that a leak tight drywell barrier is maintained by the use ,

of an OPERABLE air lock door. This action must be completed within I hour. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is consistent l with the ACTIONS of LCO 3.6.5.1, which requires that the drywell be restored to OPERABLE status within I hour.

In addition, the air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Tir.a. The Completion Time is considered reasonable for locking the OPERABLE air lock door, considering that the OPERABLE door it being maintained closed.

_ ._ (continued)

CLINTON . Revision No. 2-6

~ ,,

. .B 3.6-108 .

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Drywell Air Lock B 3.6.5.2  !

BASES ACTIONS H2Js B.2. and B.3 (continued) 4 The Required Actions are modified by two Notes. Note 1 ansures only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. Nnte 2 allows entry and exit into the drywell under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock). In addition, Note 2 allows an OPERABLE air lock door to remain unlocked, but closed, when the door

" is under the control of a dedicated individual stationed at the air lock.

l l C.1 and C.2 i

With the air lock inoperable for reasons other than those described in Condition A or B, Required Action C.1 recuires 1 l that one door in tne drywell air lock must be verifiec to be closed. This Required Action must be completed within the ,.

j-I hour Completion Time. This s)ecified time )eriod is ,

consistent with the ACTIONS of LCO 3.6.5.1, W11ch requires that the drywell be restored to OPERABLE status within .

I hour.

j i

Additionally, the air lock must be restored to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable for restoring an inoperable air lock to OPERABLE status, considering that at least one door is maintained closed in the air lock.

(continued) i J

CLINTON- ,

B 3.6 110 Revision No. 2-6

,- w m ..r,q - e r,-,. , - . . , ,--,v,, -ge - , , -- - , , - - , ,

l Drywell Air Lock B 3.6.5.2 1

BASES i 1

ACTIONS D.1 and D.2 ,

(continued)

If the inoperable drywell air lock cannot be restored to OPERABLE status within the required Com)1etion Time, the

. plant must be brought to a MODE in whic1 the LCO does not apply. To achieve this status, the plant must be brought to at least H0DE 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.

l SVRVEILLANCE SR 3.6.5.2.1 REQUIREMENTS The air lock door interlock is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of the air lock are designed to withstand the maximum expected post accident drywell pressure, closure of either door will support drywell OPERABILITY. Thus, the door interlock feature supports drywell OPERABILITY while the air lock is being used for 3

personnel transit in and out of the drywell. Periodic -

testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening will not inadvertently occur. Due to the nature of this interlock, and given that the interlock mechanism is only challenged when a drywell air lock door is opened, this test is only required to be performed once l every 24 months. The 24 month frequency is based on the need to perform this Surveillance under the reduced reactivity conditions that apply during a plant outage and the potential for violating the drywell boundary. 0)erating experience has shown these components usually pass t1e l Surveillance. Therefore, the frequency was concluded to be acceptable from a reliability standpoint.

(continugdl

)

CLINTON B 3.6-111 ' Revision No. 2-6 4

' Drywell Air Lock B 3.6.5.2 BASES l SURVEILLANCE SR 3.6. 5. 2.1 (continued)

REQUIREMENTS The Surveillance is modified by a Note requiring the Surveillance to be performed only upon entry into the drywell. ,

.l

~

REFERENCES 1. 10 CFR 50, Appendix J, Option B. ,

2. USAR, Chapters 6 and 15.

+

a

.CLINTON B 3.6 112 Revision No. 2-6

Drywell isolation Valves

. B 3,6,$.3 BASES (C0 actuate on an automatic isolation signal. Additionally, (continued) drywell vent and purge supply valves are required io be sealed closed. While drywell post LOCA vacuum reliof system valves isolate drywell penetrations, they are excluded from this Specification. Controls on their isolation function are adequately addressed in LCO 3.6.5.6, "Drywell post-LOCA Vacuum Relief System."

The normally closed isolation valves or blind flanges are considered OPERABLE when, as applicable, manual valves are closed or opened in accordance with applicable administrative controls, automatic valves are de activated and secured in their closed position, check valves with flow through the valve secured, or blind flanges are in ) lace.

The valves covered by this LC0 are included (with t1eir associated stroke time, if applicable, for automatic valves) l in Reference 2.

Drywell isolation valve leakage is excluded from this Specification. The drywell isolation valve leakage rates are part of the drywell leakage rate and are controlled as

' part of OPERABILITY of the drywell in LCO 3.6.5.1, "Drywell . " .

For the purpose of meeting this LCO, only one drywell isolation valve or blind flange is required to be OPERABLE in each drywell penetration flow path (with the exception of drywell vent and purge valves, and Drywell Post-LOCA Vscuum Relief System valves). This single isolation is acceptable on the basis that these lines do not communicate directly with the drywell or containment atmospheres. Thus, steam bypass of the suppression pool is not possible without failure of the required isolation valve in conjunction with failures of the piping both inside the drywell and outside the drywell within the containment. Further, failure of multiple flow paths would be required to exceed the containment design limitations.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment, in MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the drywell isolation valves are not required to be OPERABLE in MODES 4 and 5.

~

(continued)

)

CLINTON B 3.6-115 Revision No. 2-6 j

, - I

- Drywell isolation Valves B 3.6.S.3 BASES (continued) l ACTIONS The ACTIONS are modified by three Notes. The first Note allows penetration flow paths, except for the drywell vent and purge supply and exhaust penetration flow paths, to be unisolated intermittently under administrative controls.

' Due to the size of the drywell vent and purge line penetrations and the fact that they communicate directly with the containment atmosphere, bypassing the suppression pool, these flow paths are not allowed to be unisolated under administrative controls. These controls consist of stationing a dedicated individual, who is in continuous communication with the control room, at the controls of the valve. In this way, the penetration can be rapidly isolated when a need for drywell isolation is indicated.

The second Note provides clarification that for the pur)ose of this LCO separate Condition entry is allowed for eac1 penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable drywell isolation valve. Complying with the Required Actions may allow for continued operation, and subsequent inoperable drywell isolation valves are governed by subsequent Condition entry and application of associated Required Actions.

The third Note requires the OPERABILITY of affected systems to be evaluated when a drywell isolation valve is inoperable. This ensures appropriate remedial actions are taken, if necessary, if the affected system (s) are rendered inoperable by an inoperable drywell isolation valve.

A.1 and A.2 With one or more penetration flow paths with one required drywell isolation valve inoperable, the affected penetration flow path must be isolated. T'e method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured, in this condition, the remaining OPERABLE drywell isolation valve is adequate to perform the isolation function for drywell vent and purge system penetrations.

(continuedl CLINTON B 3.6-116, Revision No. 2-6

Drywell isolation Volves B 3.6.5.3 L

BASES ,

ACTIONS A.1 and A.2 (continued)

'. The associated system piping is adequate to perform the

isolation function for other drywell penetrations. However, the overall reliability is reduced because a single failure i

could result in a loss of drywell isolation.- The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> d

Completion Tiw is acceptable, due to the low probability of i- the inoperable valve resulting in excessive drywell leakage

and the low probability of the limiting event for drywell j leakage occurring during this short time, in addition, the i Completion Time is reasonable, considering the time required

! to isolate the penetration and the relative importance of l supporting drywell OPERABILITY during MODES 1, 2, and 3.

L 4 For affected penetration flow paths that have been isolated in accordance with Required Action A.1, the affected i genetrations asis. This ismust be verified necessary to be that to ensure isolated drywellon a periodic i

L penetrations that are required to be isolated following an accident, and are no longer capable of being automatically isolated, will be isolated should an event occur. . This Required Action does not require any testing or valve manipulation; rather, it involves verification that those .

devices outside drywell and capable'of potentially being i mispositioned are in the correct position. Since these devices are inside primary containment, the time period-

! specified as " prior to entering MODE 2 or 3 from MODE- 4, if 4

not performed within the previous 92 days," is based on engineering judgment and is considered reasonable in view of f

the inaccessibility of the devices and other administrative controls that will ensure that misalignment is an unlikely f possibility. Also, this Completion Time is consistent with the Completion Time specified for PCIVs in LCO 3.6.1.3,

" Primary Containment Isolation Valves (PCIVs)."

Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas and allows them to be verified by use of administrative controls.

Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment, once they have been verified.to be in the proper position, is low.

(continued)

[

CLINTON B 3.6-117, Revision No. 2-6

Drywell isolation Valves B 3.6.5.3 BASES ACTIONS B.d '

(continued)

With one or more drywell vent and purge penetration flow paths with two drywell isolation valves inoperable, the  !

affected penetration flow path must be isolated. The method

• of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a

• closed and de-activated automatic valve, a closed manual-valve, a blind flange, and a check valve with flow through the valve secured. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is acceptable, due to the low probability = of the inoperable ,

-valves resulting in excessive drywell leakage and the low -

probability of the limiting event for dr.vwell leakage occurring during this si. ort time, in addition, the Completion Time is reasonable, considering the time required >

to isolate the penetration, and the probability of a DBA, which requires the drywell isolation valves to close, '

occurring during this short time is very low.

, Condition B is modified by a Note indicating this Condition is only applicable to drywell vent and-purge penetration  :

flow paths. For other penetration flow paths, only one < '

drywell isolation valve is required OPERABLE and, Condition A provides the appropriate Required Actions.

C.1 and C.2 ,

If any Required-Action and associated Completion Time cannot be met, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be brought-to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.5.3.1 ,

REQUIREMENTS Each 24-inch drywell vent and purge supply isolation valve is required.to be verified sealed closed at 31 day intervals. This Surveillance applies to drywell vent and purge supply isolation valves since they are not qualified to close under accident conditions. This SR is designed to ensure that a gross breach of drywell is not caused by an i inadvertent or spurious drywell vent and purge isolation (continued)

CLINTON B 3.6-118 Revision No. 2-6 5

- - - - - , , - , - - n a- - , , - ,, n,m-

. _ __ - _ . . _ _ _ .~ -_ .-

Control Room V:ntilation Systea

, B 3.7.3 8 3.7 PLANT SYSTEMS /

8 3.7.3 Control Room Ventilation System BASES BACKGROUND The Control Room Ventilation System provides a radiologically controlled environment from which the unit can be safely operated following a Design Basis Accident (DBA).

The safety related function of the Control Room Ventilation System used to control radiation exposure consists of-two independent and redundant high efficiency air filtration subsystems for treatment of recirculated air or outside supply air. Each subsystem contains a makeup air filter and a recirculation adsorber, a fan, and the associated ductwork and dampers. The makeup filter consists of a demister, an electric heater, a prefilter, a high efficiency particulate air (HEPA and a seco)nd HEPA filter. The filter,recirculation an activatedadsorber charcoal adsorber sectio consists of a prefilter and an activated charcoal adsorber section. Demisters remove water droplets from the

• airstream. Prefilters and HEPA filters remove particulate matter that may be radioactive. The charcoal adsorbers.

provide a holdup period for tuseous iodine, allowing tims ' (

for decay. For filter train test performed in accordance -

with ASME/ ANSI N510-1980 flow rates are measured with respect to design flow. For the Control Room Ventilation System, the design flows are in scfm.

In addition to the safety related standby emergency filtration function, parts of the Control Room Ventilation System are operated to maintain the control room environment during normal operation. Upon receipt of the initiation signal (s) (indicative of conditions that could result in radiation exposure to control room personnel , the Control Room Ventilation System automatically switche)s to the high radiation mode of operation to prevent infiltration of conteminated air into the control room (outside makeup air is routed through the makeup air filters, the recirculation adsorber is laced in service, and the locker room exhaust is isolated. .

^

The Control Room Ventilation System is designed to naintain the control room environment for a 30 day continuous occupancy after a DBA per the requirements of GDC 19.

Control Room Ventilation System operation in maintaining the control room habitability is discussed in the USAR, Sections 6.5.1 and 9.4.1 (Refs. I and 2, respectively).

(continued)

CLINTON B 3.7-10 Revision No. 2-13 1

. _ _ _ _ . , - . - . , - - , , -.- - -- .---,m%-w.m.,

Control Reon Ventilation Systeo

, 8 3.7.3

{ ,

BASES SURVE!LLANCE SR 3.7.3.1 and SR 3.7.3.2 (continued)

' -REQUIREMENTS each subsystw once every month provides an adequate check on this system. Monthly heater operation dries out any moisture ticcumulated in the charcoal from humidity in the ambient air. The Makeup Filter System must be operated from

-the main control room for a lo continuous hours with the-heaters energized. The Recirculation Filter System (without heaters) need only be operated for k 15 minutes to demonstrate the function of the system. Furthermore, the 31 day Frequency.is based on the Known reliability of the

equipment and the two subsystem redundancy available, p

jg. 3.7.3.3 l'>' This SR verifies that the required Control Room Ventilation System testing is performed in accordance with the-Ventilation Filter Testing Program (VFTP). The VFTP.

includes testing HEPA filter performance, charcoal adsorber bypass leakage and efficiency, minimum system flow rate

-l -

drop,)andheaterdissipation.(scfs , combinedforHEPA filter and charcoal ad The frequencies j- performing the Control Room Ventilation System filter tests are in accordance with Regulatory Guide 1.52 (Ref. 4) and .

include testing initially, after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system .

" operation, once per 18 months, and following painting, fire, or chemical release in any ventilation zone communicating with the system. The laboratory test results will be verified to be within limits within 31 days of removal of the sampic from the system. Additional information_is discussed in detail in the VFTP.

L-SR 3.7.3.4 1

This SR verifies that each control Room Ventilation subsystem starts and operates on an actual or simulated high w radiation initiation signal. While this Surv6111&nce can be

)erformed with the reactor at power, operating experience  !

ins shown these com>onents usually pass the Surveillance when performed at tie 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. 4 l

(continued)

O 4

CLINTON- B 3.7-15 Revision No. 2-13

. - , -. 4

Centrol Ro:a Ventilaticn Systea B 3.7.3 BASES

(-

SURVEILLANCE SR 3.7.3.5 REQUIREMENTS (continued) This SR verifies the integrity of the negative pressure portions of the Control Room Ventilation System ductwork located outside the main control room habitability boundary between fan OVC04CA(B) and isolation dampers OVC03YA(B)

E),OVC042YB(F),

,andOVC042YD(H). In ad OVC042YC(G)lation the recircu filter housing flexible con OVC03A(B) must be verified. This testing ensures the l unfiltered inleakage (scfe) into the main control room habitability boundary is within the analysis assumptions.

, Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.

SR 3.7.3.6 This SR verifies the integrity of the control room enclosure and the assumed inleakago rates of potentially contaminated - -

air. The control room positive pressure, with respect to potentially contaminated adjacent areas, is periodically (,.

tested to verify proper function of the Control Room .-

Ventilation System. During the high radiation mode of .

operation, the Control Room Ventilation System is designed to slightly pressurize the control room to a: % inches water gauge positive pressure with res)ect to adjacent areas to prevent unfiltered inleakage. Tie Control Room Ventiletion System is designed to maintain this positive pressure at a l flow rate of s 3000 scfm to the control room in the high radiation mode. The Frequency of 18 months on a STAGGERED 4

TEST BASIS is consistent with industry practice and other filtration system SRs.

REFERENCES 1. USAR, Section 6.5.1.

2. USAR, Section 9.4.1.

3. USAR, Chapter 6.

4. USAR, Chanter 15.

l S. USAR, Appendix A.

l 6. Regulatory Guide 1.52, Revision 2, March 1978.

g l 7. ASME/ ANSI H510-1980. h CLINTON B 3.7-16 Revision No. 2-13

'q*m ** Vh" 4 W vA  % -e 4 ,

AC S:urces-0peratin B 3.8.

BASES (continued)

SURVEILL/dCE The AC sources are designed to permit inspection and REQUIREMENTS testing of all important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 8). Periodic component tests are supplemented by extensive functional tests during refueling outages um'er simulated accident conditions. The SRs for demonstrating the OPERABILITY of the DGs are in accordance. ,

with the recommendations of Regulatory Guide 1.9 (Ref. 3),

Regulatory Guide 1.108 (Ref. 9), and Regulatory Guide 1.137

(Ref. 10).

Where the SRs discussed herein specify voltage and frequency tolerances, the minimum.and maximum steady state output d

voltages of 3870 V and 4580 V respectively, are equal to l

- 7% and + 10% of the nominal 4160 V output voltage. The j specified minimum and maximum frequencies of the DG is

' 58.8 Hz and 61.2 Hz, respectively, are equr.1 to i 2% of the i 60 Hz nominal frequency. The specified steady state voltage and frequency ranges are derived from the recommendations given in Regulatory Guide 1.9 (Ref 3). However, the j

minimum voltage was increased to ensure adequate voltage to aperate all safety-related loads during a DBA (Ref.14).

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred 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.

i SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.

(continued) i 4

3 CLINTON B 3.8-13 Revision No. 2-11

\ , ,

AC Sources--Operating

, B 3.8.1 BASES SURVEILLANCE Diesel Generator Test Schedule (continued)

REQUIREMENTS A test interval in excess of 7 days (or 31 days, as constitutes a failure to meet SRs and results appropriate)iated in the assoc DG being declared inoperable. It does not, however, constitute a valid test or failure of the DG, ,

and any consecutive test count is not reset. '

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.-

2. USAR, Chapter 8.

3. Regulatory Guide 1.9.

4. USAR, Chapter 6.

-5. USAR, Chapter 15.

6. Regulatory Guide 1.93.

7. Generic. Letter 84-15, July 2, 1984.

'~

8. 10 CFR 50, Appendix A, GDC 18.

9. Regulatory Guide 1.108.

10. Regulatory Guide 1.137.

. .11. ANSI C84.1, 1982,

12. NUMARC 87-00, Revision 1, August 1991.

13. IEEE Standard 308.

l 14. IP Calculation 19-AN-19.

i 1

b l CLINTON B 3.8-32 Revision No. 2-11 f

_ . . . . . - . . _ - . - . . - _~:..._.., . _ . _ ~ , . - - . . . , . _ _ _ _ _ _ _ . . , _

- Refuoling Equipment Interlocks  :

B 3.9.1 B 3.9 REFUELING OPERATIONS ,

i 8 3.g.1 Refueling Equipment Interlocks BASES ,

BACKGROUNO Refueling equipment interlocks restrict the operation of the refueling equipment or the withdrawal of control rods to -

reinforce unit procedures in preventing the reactor from achieving criticality du' ing refueling. The refueling interlock circuitry senses the conditlons of the refueling equipment and the control rods. Depending on the sensed conditions, interlocks are actuated to prevent the operation  ;

of the refueling equipment or the withdrawal of control rods.

GDC 26 of 10 CFR 50, Appendix A, requires that one of the

• two required independent reactivity control systems be capable conditions of(Ref.1.

holding)the The control reactor core rods, whensubcritical fully inserted, under cold serve as the system capable of maintaining the reactor subcritical in cold conditions during all fuel movement activities and accidents.

Two channels of instrumentation are provided. The following .

)- provide input to one or both channels: the position of the refueling platform, the loading of the refueling platform main hoist, and the full insertion of all control rods.

• With the reactor mode switch in the shutdown or refueling position, the indicated conditions are combined in logic ,

circuits to determine if all restrictions on refueling <

equipment operations and control rod insertion are satisfied.

A control rod not at its full-in position interrupts power to the refueling equipment and prevents operating the equipment over the reactor core when loa 6ed with a fuel i assembly. Conversely, the refueling' equipment located over the core and loaded with fuel inserts a control rod withdrawal block to prevent . withdrawing a control rod.

The refueling platform has two mechanical switches that open before the platform and the fuel-grapple are physically- >

located ovsr-the reactor vessel.' The main hoist has a load cell sensor that- feeds the Programmt.ble Logic Controller (PLC) that has two output ports (twitches) that open when the-hoist is loaded with fuel. The PLC setpoint for "holst loaded" is set to a load lighter than the weight of a single (continued)

) .CLINTON_ B 3.9 1 Revision No. 2 9 ri,,--. _ _ _ - . _ - - ' -

.....,--,,_~,ew~_m.,+ -

. . - , , -_ , , , - , . . - , . . . ~ _ , , - - , , -

v.-,.-_n----,~,-.m w -, ,.ny-

Refueling Equipment interlocks B 3.9.1 BASES-BACKGROUND fuel assembly in water to ensure that the interlock is' (continued) activated when the hoist is loded with fuel. The refueling interlocks use these indications to prevent operation of the refueling equipment with fuel loaded over the core whenever any control rod is withdrawn, or to prevent control rod withdrawal whenever fuel loaded refueling equipment is over the core (Ref. 2).

l APPLICABLE The refueling interlocks are explicitly assumed in the USAR SAFETY ANALYSES analysis of the control rod removal error during refueling (Ref. 3 .

i control) rod withdrawal during refueling.This analysis evaluates the conseq A prompt

! reactivity excursion during refueling could potentially result in fuel failure with subsequent release of radioactive material to the environment.

Criticality and, therefore, subsequent prompt reactivity excursions are prevented during the insertion of fuel, provided all control rods are fully inserted during the fuel insertinn.- The refueling interlocks accomplish this by preventing loading fuel into the core with any control rod withdrawn, or by preventing withdrawal of a rod from the

• core during fuel loading.

The refueling platform location switches activate at a point outside of the reactor core, such that, considering switch hysteresis and maximum platform momentum toward the core at 4

the time of power loss with a fuel assembly loaded and a control rod withdrawn, the fuel is not over the core.

Refueling equipment interlocks satisfy Criterion 3 of the NRC Policy Statement.

LCO To prevent criticality during refueling, the refueling-interlocks ensure that fuel assemblies are not loaded with any control rod withdrawn.

To prevent these conditions from developing, the all-rods-in, the refueling platform position, and the refueling platform main hoist fuel loaded inputs are required to be OPERABLE. These inputs are combined in logic circuits that provide refueling equipment or control rod blocks to prevent operations that could result in criticality during refueling operations.

(continued)

CLINTON B 3.9-2 Revision No. 2-9

. g

l l Single Control Rod Withdraral Refueling

! 4 8 3.10.10 l i

1 f 8 3.10 SPECIAL OPERATIONS #,

4 8 3.10.10 Single Control Rod Withdrawal - Refueling n

BASES i

! BACKGROUND The purpose of this Special Operations LC0 is to permit the '

withdrawal of a single control rod for testing in MODF 5 without imposing the requirements for establishing the i) -

secondary conta' nment and main control room boundaries as normally required during CORE ALTERATIONS. During refueling ,

i operations no more than one control rod is pomitted to be l

withdrawnfromacorecellcontainingoneormorefuel i assemblies. This restriction is enforced by the refuel l

position one rod-out interlock which will not allow the ,

j ' withdrawal of a second control rod.

.! In MODE 5, movement-of a control rod is defined as a CORE 4

ALTERATION. Many systems and functions are nomally 3 requir6d during CORE ALTERATIONS. These include t requirements on secondary containment OPERA 8ILITY, secondary

[

containment penetrations and associated automatic isolation l instrumentation, secondary containment bypass leakage path

! penetrations and associated automatic isolation i_ instrumentation, the Standby Gas Treatment System (SGTS), -3 ..

! and the main control room ventilation, air conditioning, and i associated automatic isolstion instrumentation. These s 9

j raquirements are provided to protect the public and the main

control room personnel from the release cf radioactive 4

e- material in the event of a fuel handling accident. In i addition, there are a number of requirements that apply in i MODE 5 with a control rod withdrawn. These include -

r requirements on shutdown margin, source range neutron .

monitoring, Reactor Protection System (RPS) instrumentation,  ;

{

RPS power monitoring, control rod OPERABILITY, and <

r OPERABILITY of the refuel position one-rod.out interlock.

1 These requirements are provided to preclude an inadvertent l criticality from the withdrawal of multiple control rods and 4

cause automatic insertion of the control rods in the event i of an inadvertent criticality event.

3 4 However, there are circumstances while in MODE 5 that

present the need to withdraw a single control rod for L .Various tests (e.g., friction tests, scram timing, drive venting ,and coupling integrity checks). These single control rod withdrawals are normally accomplished by selecting the refuel position for the reactor mode switch. ,

(continued)-

l CLINTON B 3.10-42 Revision No. 2-12 -

% w a +. .wr. -- -.=.w. -,r-=v. e vvw ==~r,,%ew,,N,,-*,-.,v,.4 _ ,, m. ..ry ,.,_e.., -,--e,c,,-,v-,r-+,,-r.,c.a.,, -

---,,-r,,--.wyrv, ,,y,+,-y,- vr..,ywrg,,,w,,.,,,,-w-w-w,=sm-

Singlo Centrol Rod Withdrawal - Refueling B 3.10.10 I .,

i BASES '

8ACKGROUND Uth the noted reactivity controls in place, the l raquirements related to controlling radioactive releases (continued) need not be luposed. This Special Operations LC0 provides d

added assurance that the appropriate controls are being met to allow a si ils control rod withdrawal in MODE 5 without innce with the requirements for the secondary  ;

requiring c i

containment and main control room boundaries. -

With the reactor mode switch in the refuel position, the APFLICABLE SAFETY ANALYSES analysee for control rod withdrawal during refueling are l

l applicable and, provided the assumptions of these a

! an accident. Explicit safety analyses in the USAR (Ref.1) i demonstrate that the functioning of the refueling interlocks .

and adequate SOM will precit.h unacceptable reactivity l

excursions.

Refueling interlocks restrict the movement of control rods l to reinforce operational procedures that prevent the reactor -

,'- from becoming critical. These interlocks prevent the Under these withdrawal of more than one control rod.

', conditions, since only one control rod can be withdrawn, the core will always be shut down even with the highest worth 4

control rod withdrawn if adequate SOM exists. ,

The control rod scram function provides backup protection in

! the event normal refueling precedures and the refueling l I.'

interlocks, together with the specified SDM, fail to prevent inadvertent criticality during refueling. '

i Because of these multiple levels of controls to ensure that ,

l an inadvertent criticality cannot occur, the requirements associated with establishing the secor.dary containment and i

a.ain control room boundaries may be relaxed.

i. As described in LC0 3.0.7, complianen with Specialand theref i

0>erations tte NRC Policy LCOs Statementis optional,ly.

app Special Operations LCOs provide flexibility to perform certain operations by A appropriately modifying requirements of other LCOs.

l discussion of the criteria satisfied for the other LCOs is l

i provided in their respective Bases.

(continued) i

) Revision No. 2-12 B 3.10-43 l CLINTON i

u - . . . _ _ . . . , ~ . _ _ _ . . . , _ . _ . _ _ _.~,_.____ _ .-_ ___._-_. __ ,-- _ -

Sing 1c Contr31 Rod Withurawal - Refueling

B 3.10.10 BASES (continued) [

LC0 As described in LC0 3.0.7, compliance with this Special _

Operations LC0 is optional. Withdrawal of a control rod in MODE 5 under the controls of the one-rod out interlock can be performed in accordance with the normal MODE 5 LCOs (e.g., LC0 3.9.2, ' Refuel Position One-Rod-Out Interlock,'LC0 3.9.3, " Control Rod Position ,' and LC0 3.9.5," Control Rod OPERABILITY - Refueling. ' etc.) without meeting this Special Operations LCO or 4s ACTIONS.

However, if a single control rod withdt awr1 is desired in MODE 5 without establishing the secorJary containment and main be must contrcl applied.room "Withdrawa boundariesI"this in this Special application Operations LCO includes the actual withdrawal of the control rod as well as maintaining the control rod in a position other than the full-in position, and reinserting the control rod. The refueling interlocks of LC0 3.9.2 will ensure that only one ,

control rod can be withdrawn at one time.  ;

this To Special backOperations up the refueling LC0 requiresinterlocksall other (LCOcontro 3.9.2),l rods to '

remain ~ fully inserted and prohibits the performance of any ,

other CORE ALTERATIONS.

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APPLICABILITY Control rod withdrawals are adequately controlled in MODE 5 by existing LCOs. .However, these controls require the o' secondary containment and main control room boundaries to be established. In MODE 5, control rod withdrawal without establishing the secondary containment and main control room boundaries is only allowed if performed in accordance with this Special Operations LC0 and is limited to one control rod at a time. For these conditions, the one-rod-out interlock (LC0 3.9.2), control rod position indication (LCO 3.9.4, " Control Rod Position Indication"), full inser' tion requirements for all other control rods, and scram

. functions (LCO 3.3.1.1, " Reaction Protection Sntem (RPS)

Instrumentation," and LCO 3.9.5, " Control Rod OPERABILITY -

Refueling") minimize the potential for reactivity excursions, precluding the need to establish the secondary containment and main control room boundsries.

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(continued) 1

l. l CLINTON B 3.10-44 Revision No. 2-12 l

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Single Centrol Rod Withdrawal - Refueling B 3.10.10 BASES (continued)

ACTIONS A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 5. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that

,Receired Actions of the Condition continue to apply for each adcitional failure, with Completion Times based on initial ur.try into the Condition. However, the Required Actions for l

.each requirement of the LC0 not met provide appropriate l compenst. tory measures for separate requirements that are not met. As such, a Note has been provided that allows separate Condition entry for each requirement of the LCO.

6 1 and M If oree or more of the requirements specified in this Special Operations LCO are not met, all CORE ALTERATIONS except

- control rod insertion, if in progress must be immediately suspended in accordance with Required' Action A.1, and .

1

-actions must be initiated immediately to fully insert all  !

control rods in accordance with Required Action A.2. This

\ will preclude potential mechanisms that could lead to- '

criticality. Suspersion of CORE ALTERATIONS shall not preclude the completi.on of movement of a component to a safe condition and actions to fully insert all insertable control

';. rods must continue until a'Il contral rods are fully inserted. l SURVEILLAMCE SR 3.10.10.1 and SB 3.10.10.2 REQUIREMENTS Verification that all the control rods, other than the control rod withdrawn for testing, are fully inserted is req 0 ired to ensure the SDM-is within limits. Verification that no otner CORE ALTERATIONS are being made is required to

- ensure the assumptions of the saf1ty analyses are satisfied.

Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is acceptable, given the administrative

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(continued)

B 3.10-45 Revision No. 2-12 l.CLINTc1

Single CCntrol Rod Withdrawal - Refueling i B 3.10.10 BASES .

SURVEILLANCE controls on control rod withdrawals, the protection afforded REQUIREMENTS by the LCOs involved, and hardware interlocks that preclude (continted) additional control rod withdrawals.

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REFERENCES 1. USAR, Section 15.4.1.1.

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5 l Cl.INTON B 3.10-46 Revision No. 2-12

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